• Oil & Gas Exploration & Production
  • Energy
Occidental Petroleum Corporation logo
Occidental Petroleum Corporation
OXY · US · NYSE
60.18
USD
-0.36
(0.60%)
Executives
Name Title Pay
Mr. Robert L. Peterson Executive Vice President of Essential Chemistry 2.07M
Mr. Richard A. Jackson Senior Vice President and President of Operations - U.S. Onshore Resources & Carbon Management 2.23M
Mr. Kenneth Dillon Senior Vice President and President of International Oil & Gas Operations 2.31M
Mr. Jeff F. Simmons Senior Vice President of Technical & Operations Support and CPTO 2.32M
Mr. Ioannis A. Charalambous Chief Information Officer & Vice President --
Mr. Jordan Tanner Vice President of Investor Relations --
Ms. Nicole E. Clark Vice President, Deputy General Counsel, Corporate Secretary & Chief Compliance Officer --
Mr. Christopher O. Champion Vice President, Chief Accounting Officer & Controller 1.57M
Mr. Sunil Mathew Senior Vice President & Chief Financial Officer 1.98M
Ms. Vicki A. Hollub President, Chief Executive Officer & Director 5.53M
Insider Transactions
Date Name Title Acquisition Or Disposition Stock / Options # of Shares Price
2024-06-17 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 334461 59.7491
2024-06-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1060653 59.5893
2024-06-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1552497 59.7679
2024-06-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 765899 60.2771
2024-06-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 399859 60.4253
2024-06-10 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 584550 60.2562
2024-06-07 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1386844 59.6687
2024-06-06 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 654293 59.9342
2024-06-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 524340 59.7452
2024-05-20 GUTIERREZ CARLOS M director A - X-InTheMoney Common Stock 7207 22
2024-05-20 GUTIERREZ CARLOS M director D - X-InTheMoney Warrants (Right to buy) 7207 22
2024-05-03 BAILEY VICKY A director A - A-Award Common Stock 3495 0
2024-05-03 BAILEY VICKY A director D - F-InKind Common Stock 1145 64.39
2024-05-03 Robinson Kenneth B. director A - A-Award Common Stock 3495 0
2024-05-03 Robinson Kenneth B. director D - F-InKind Common Stock 769 64.39
2024-05-03 ONeill Claire director A - A-Award Common Stock 3495 0
2024-05-03 Shearer Bob director A - A-Award Common Stock 3883 0
2024-05-03 MOORE JACK B director A - A-Award Common Stock 6679 0
2024-05-03 MOORE JACK B director D - F-InKind Common Stock 1470 64.39
2024-05-03 GUTIERREZ CARLOS M director A - A-Award Common Stock 3495 0
2024-05-03 POLADIAN AVEDICK BARUYR director A - A-Award Common Stock 3883 0
2024-05-03 GOULD ANDREW director A - A-Award Common Stock 3883 0
2024-05-03 GOULD ANDREW director D - F-InKind Common Stock 1165 64.39
2024-05-03 KLESSE WILLIAM R director A - A-Award Common Stock 3883 0
2024-05-03 KLESSE WILLIAM R director D - F-InKind Common Stock 855 64.39
2024-03-19 GUTIERREZ CARLOS M director A - X-InTheMoney Common Stock 625 22
2024-03-19 GUTIERREZ CARLOS M director D - X-InTheMoney Warrants (Right to buy) 625 22
2024-03-01 Dillon Kenneth Senior Vice President A - A-Award Common Stock 23469 0
2024-02-28 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 6481 60.26
2024-02-29 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 3076 60.61
2024-03-01 Kerrigan Sylvia J SVP & Chief Legal Officer A - A-Award Common Stock 42373 0
2024-02-29 Kerrigan Sylvia J SVP & Chief Legal Officer D - F-InKind Common Stock 5756 60.61
2024-03-01 Mathew Sunil SVP & CFO A - A-Award Common Stock 20861 0
2024-02-28 Mathew Sunil SVP & CFO D - F-InKind Common Stock 10884 60.26
2024-02-29 Mathew Sunil SVP & CFO D - F-InKind Common Stock 3405 60.61
2024-03-01 Simmons Jeff F Senior Vice President A - A-Award Common Stock 20209 0
2024-02-28 Simmons Jeff F Senior Vice President D - F-InKind Common Stock 11036 60.26
2024-02-29 Simmons Jeff F Senior Vice President D - F-InKind Common Stock 3296 60.61
2024-03-01 Hollub Vicki A. President and CEO A - A-Award Common Stock 76924 0
2024-02-28 Hollub Vicki A. President and CEO D - F-InKind Common Stock 16932 60.26
2024-02-29 Hollub Vicki A. President and CEO D - F-InKind Common Stock 9886 60.61
2024-03-01 Bennett Peter J. Vice President A - A-Award Common Stock 17927 0
2024-02-28 Bennett Peter J. Vice President D - F-InKind Common Stock 3787 60.26
2024-02-29 Bennett Peter J. Vice President D - F-InKind Common Stock 2285 60.61
2024-03-01 Peterson Robert L Senior Vice President A - A-Award Common Stock 20861 0
2024-02-28 Peterson Robert L Senior Vice President D - F-InKind Common Stock 6059 60.26
2024-02-29 Peterson Robert L Senior Vice President D - F-InKind Common Stock 2812 60.61
2024-03-01 Jackson Richard A. Senior Vice President A - A-Award Common Stock 23469 0
2024-02-28 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 6059 60.26
2024-02-29 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 3076 60.61
2024-03-01 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 11409 0
2024-02-28 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 3597 60.26
2024-02-29 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 1538 60.61
2024-02-22 GUTIERREZ CARLOS M director A - G-Gift Common Stock 2023 0
2024-02-07 Peterson Robert L Senior Vice President A - A-Award Common Stock 34283 0
2024-02-07 Peterson Robert L Senior Vice President A - A-Award Common Stock 55140 0
2024-02-07 Peterson Robert L Senior Vice President D - F-InKind Common Stock 35256 57.62
2024-02-07 Mathew Sunil SVP & CFO A - A-Award Common Stock 61218 0
2024-02-07 Mathew Sunil SVP & CFO D - F-InKind Common Stock 24150 57.62
2024-02-07 Simmons Jeff F Senior Vice President A - A-Award Common Stock 61218 0
2024-02-07 Simmons Jeff F Senior Vice President D - F-InKind Common Stock 24152 57.62
2024-02-07 Jackson Richard A. Senior Vice President A - A-Award Common Stock 34283 0
2024-02-07 Jackson Richard A. Senior Vice President A - A-Award Common Stock 55140 0
2024-02-07 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 35253 57.62
2024-02-07 Hollub Vicki A. President and CEO A - A-Award Common Stock 89990 0
2024-02-07 Hollub Vicki A. President and CEO A - A-Award Common Stock 144744 0
2024-02-07 Hollub Vicki A. President and CEO D - F-InKind Common Stock 92368 57.62
2024-02-07 Dillon Kenneth Senior Vice President A - A-Award Common Stock 36119 0
2024-02-07 Dillon Kenneth Senior Vice President A - A-Award Common Stock 58094 0
2024-02-07 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 37135 57.62
2024-02-07 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 21428 0
2024-02-07 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 34464 0
2024-02-07 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 22081 57.62
2024-02-07 Bennett Peter J. Vice President A - A-Award Common Stock 21428 0
2024-02-07 Bennett Peter J. Vice President A - A-Award Common Stock 34464 0
2024-02-07 Bennett Peter J. Vice President D - F-InKind Common Stock 22068 57.62
2024-02-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 164838 57.2024
2024-02-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1240989 56.7546
2024-02-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1246920 57.1428
2024-02-01 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 164232 57.9832
2024-02-01 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1485345 57.3898
2023-12-21 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1743124 60.2631
2023-12-20 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1812508 60.504
2023-12-19 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 879122 60.1638
2023-12-19 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 747861 59.4917
2023-12-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1524893 57.0453
2023-12-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1675906 56.1027
2023-12-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 105557 56.4657
2023-12-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 5026004 55.5822
2023-12-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2149802 56.9107
2023-10-25 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1040067 63.0483
2023-10-24 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1195400 62.6863
2023-10-23 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1686368 62.7969
2023-10-02 Kerrigan Sylvia J SVP & Chief Legal Officer D - F-InKind Common Stock 3595 62.3
2023-06-28 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 260769 57.02
2023-06-27 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1239180 57.1694
2023-06-26 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 638301 57.0143
2023-05-30 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2203753 58.3026
2023-05-26 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1500306 58.8545
2023-05-25 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 956750 58.753
2023-05-18 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1217945 58.1144
2023-05-17 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 614020 58.6597
2023-05-16 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1625257 58.2203
2023-05-05 Simmons Jeff F Senior Vice President D - Common Stock 0 0
2023-05-05 Simmons Jeff F Senior Vice President I - Common Stock 0 0
2020-08-31 Simmons Jeff F Senior Vice President D - Warrants (Right to buy) 18048 22
2023-05-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 993494 58.4611
2023-05-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 370062 57.9383
2023-05-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 645247 57.8209
2023-05-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 156989 56.7976
2023-05-05 Simmons Jeff F Senior Vice President D - Common Stock 0 0
2023-05-05 Simmons Jeff F Senior Vice President I - Common Stock 0 0
2020-08-31 Simmons Jeff F Senior Vice President D - Warrants (Right to buy) 7091 22
2023-05-05 Ackerman Neil R Vice President D - Common Stock 0 0
2023-05-05 Ackerman Neil R Vice President I - Common Stock 0 0
2020-08-31 Ackerman Neil R Vice President D - Warrants (Right to buy) 1312 22
2023-05-05 Mathew Sunil Vice President D - Common Stock 0 0
2023-05-05 Mathew Sunil Vice President I - Common Stock 0 0
2020-08-31 Mathew Sunil Vice President D - Warrants (Right to buy) 4491 22
2023-05-08 MOORE JACK B director A - A-Award Common Stock 5682 0
2023-05-08 MOORE JACK B director D - F-InKind Common Stock 1251 58.96
2023-05-08 POLADIAN AVEDICK BARUYR director A - A-Award Common Stock 3817 0
2023-05-08 ONeill Claire director A - A-Award Common Stock 3393 0
2023-05-08 ONeill Claire director D - F-InKind Common Stock 1018 58.96
2023-05-08 GOULD ANDREW director A - A-Award Common Stock 3817 0
2023-05-08 GOULD ANDREW director D - F-InKind Common Stock 840 58.96
2023-05-08 GUTIERREZ CARLOS M director A - A-Award Common Stock 3393 0
2023-05-08 BAILEY VICKY A director A - A-Award Common Stock 3393 0
2023-05-08 BAILEY VICKY A director D - F-InKind Common Stock 1112 58.96
2023-05-08 Robinson Kenneth B. director A - A-Award Common Stock 3393 0
2023-05-08 KLESSE WILLIAM R director A - A-Award Common Stock 3817 0
2023-05-08 KLESSE WILLIAM R director D - F-InKind Common Stock 840 58.96
2023-05-08 Shearer Bob director A - A-Award Common Stock 3817 0
2023-03-27 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1242725 59.6262
2023-03-27 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 546804 58.6139
2023-03-23 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 778066 59.162
2023-03-23 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1099119 58.2862
2023-03-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 110216 57.1536
2023-03-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1407785 56.6641
2023-03-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 461341 61.2856
2023-03-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1915948 60.3835
2023-03-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 845778 59.6998
2023-03-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1344479 59.6017
2023-03-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1542594 59.0346
2023-03-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 258823 57.7662
2023-03-07 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 40687 61.5605
2023-03-07 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1719999 60.9996
2023-03-06 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 109504 61.9042
2023-03-06 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1568513 61.5315
2023-03-03 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 501135 61.4739
2023-03-03 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1409522 60.9525
2023-03-03 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 452431 59.8482
2023-03-01 Peterson Robert L SVP & CFO A - A-Award Common Stock 21437 0
2023-02-28 Peterson Robert L SVP & CFO D - F-InKind Common Stock 9370 58.56
2023-03-01 Kerrigan Sylvia J SVP & Chief Legal Officer A - A-Award Common Stock 43544 0
2023-03-01 Jackson Richard A. Senior Vice President A - A-Award Common Stock 23447 0
2023-02-28 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 9528 58.56
2023-03-01 Hollub Vicki A. President and CEO A - A-Award Common Stock 75365 0
2023-02-28 Hollub Vicki A. President and CEO D - F-InKind Common Stock 33191 58.56
2023-03-01 Dillon Kenneth Senior Vice President A - A-Award Common Stock 23447 0
2023-02-28 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 8807 58.56
2023-03-01 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 11724 0
2023-02-28 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 4977 58.56
2023-03-01 Bennett Peter J. Vice President A - A-Award Common Stock 17418 0
2023-02-28 Bennett Peter J. Vice President D - F-InKind Common Stock 6546 58.56
2023-02-17 Robinson Kenneth B. director A - A-Award Common Stock 549 0
2023-02-16 Robinson Kenneth B. director D - No Securities Beneficially Owned 0 0
2023-02-15 Peterson Robert L SVP & CFO A - A-Award Common Stock 29206 0
2023-02-15 Peterson Robert L SVP & CFO D - F-InKind Common Stock 11539 62.9
2023-02-15 Peterson Robert L SVP & CFO A - A-Award Warrants (Right to buy) 2994 22
2023-02-15 Peterson Robert L SVP & CFO D - F-InKind Warrants (Right to buy) 1179 22
2023-02-15 Jackson Richard A. Senior Vice President A - A-Award Common Stock 30598 0
2023-02-15 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 12093 62.9
2023-02-15 Jackson Richard A. Senior Vice President A - A-Award Warrants (Right to buy) 3136 22
2023-02-15 Jackson Richard A. Senior Vice President D - F-InKind Warrants (Right to buy) 1235 22
2023-02-15 Hollub Vicki A. President and CEO A - A-Award Common Stock 126202 0
2023-02-15 Hollub Vicki A. President and CEO D - F-InKind Common Stock 76063 62.9
2023-02-15 Hollub Vicki A. President and CEO A - A-Award Common Stock 73015 0
2023-02-15 Hollub Vicki A. President and CEO A - A-Award Warrants (Right to buy) 7888 22
2023-02-15 Hollub Vicki A. President and CEO D - F-InKind Warrants (Right to buy) 6049 22
2023-02-15 Hollub Vicki A. President and CEO A - A-Award Warrants (Right to buy) 7483 22
2023-02-15 Dillon Kenneth Senior Vice President A - A-Award Common Stock 35458 0
2023-02-15 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 22071 62.9
2023-02-15 Dillon Kenneth Senior Vice President A - A-Award Common Stock 20515 0
2023-02-15 Dillon Kenneth Senior Vice President A - A-Award Warrants (Right to buy) 2217 22
2023-02-15 Dillon Kenneth Senior Vice President D - F-InKind Warrants (Right to buy) 1701 22
2023-02-15 Dillon Kenneth Senior Vice President A - A-Award Warrants (Right to buy) 2103 22
2023-02-15 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 21034 0
2023-02-15 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 13139 62.9
2023-02-15 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 12171 0
2023-02-15 Champion Christopher O VP, CAO and Controller A - A-Award Warrants (Right to buy) 1315 22
2023-02-15 Champion Christopher O VP, CAO and Controller D - F-InKind Warrants (Right to buy) 1010 22
2023-02-15 Champion Christopher O VP, CAO and Controller A - A-Award Warrants (Right to buy) 1248 22
2023-02-15 Bennett Peter J. Vice President A - A-Award Common Stock 24340 0
2023-02-15 Bennett Peter J. Vice President D - F-InKind Common Stock 9641 62.9
2023-02-15 Bennett Peter J. Vice President A - A-Award Warrants (Right to buy) 2495 22
2023-02-15 Bennett Peter J. Vice President D - F-InKind Warrants (Right to buy) 982 22
2023-01-18 ONeill Claire director A - A-Award Common Stock 1035 0
2023-01-18 ONeill Claire director D - F-InKind Common Stock 311 64.42
2023-01-17 ONeill Claire director D - No Securities Beneficially Owned 0 0
2022-11-02 MOORE JACK B director A - A-Award Common Stock 422 0
2022-11-02 MOORE JACK B director D - F-InKind Common Stock 93 71.1
2022-10-03 Kerrigan Sylvia J SVP & Chief Legal Officer A - A-Award Common Stock 40587 0
2022-10-03 Kerrigan Sylvia J SVP & Chief Legal Officer D - No Securities Beneficially Owned 0 0
2022-09-28 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1191917 61.3765
2022-09-28 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 49114 59.9743
2022-09-28 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 496285 59.1951
2022-09-27 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2705798 58.2857
2022-09-26 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1542076 57.9116
2022-08-04 BUFFETT WARREN E A - P-Purchase Common Stock 385469 60.0162
2022-08-08 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 385469 60.0162
2022-08-04 BUFFETT WARREN E A - P-Purchase Common Stock 152551 58.8123
2022-08-08 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 152551 58.8123
2022-08-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1116751 59.0869
2022-08-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 436862 58.5066
2022-08-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 114661 57.326
2022-08-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2243809 58.6078
2022-08-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2231566 57.8028
2022-07-18 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 242241 59.6733
2022-07-16 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 242241 59.6733
2022-07-14 BUFFETT WARREN E A - P-Purchase Common Stock 242241 59.6733
2022-07-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2400 58.595
2022-07-14 BUFFETT WARREN E A - P-Purchase Common Stock 1145881 58.0387
2022-07-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1145881 58.0387
2022-07-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 552378 56.1425
2022-07-11 BUFFETT WARREN E A - P-Purchase Common Stock 65199 56.9406
2022-07-13 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 65199 56.9406
2022-07-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1581841 57.3737
2022-07-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 872717 56.8462
2022-07-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 17976 59.8491
2022-07-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1766413 59.2652
2022-07-11 BUFFETT WARREN E A - P-Purchase Common Stock 1766413 59.2652
2022-07-06 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 530514 58.8554
2022-07-06 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2072101 58.1333
2022-07-05 BUFFETT WARREN E A - P-Purchase Common Stock 2072101 58.1333
2022-07-05 BUFFETT WARREN E A - P-Purchase Common Stock 2072101 58.1333
2022-07-06 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1265627 57.2623
2022-07-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1410353 59.0455
2022-07-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 3482614 58.0966
2022-07-05 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 3281261 57.3013
2022-07-01 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1071334 60.3732
2022-06-29 BUFFETT WARREN E A - P-Purchase Common Stock 1137994 59.6234
2022-07-01 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1137994 59.6234
2022-07-01 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1447320 58.6248
2022-07-01 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1188898 57.6672
2022-06-30 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2000 59.515
2022-06-30 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1991167 58.8152
2022-06-30 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 913062 58.1769
2022-06-29 BUFFETT WARREN E A - P-Purchase Common Stock 913062 58.1769
2022-06-29 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2135265 59.0841
2022-06-23 BUFFETT WARREN E A - P-Purchase Common Stock 900 56.09
2022-06-23 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 900 56.09
2022-06-23 BUFFETT WARREN E A - P-Purchase Common Stock 793489 55.3895
2022-06-23 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 793489 55.3895
2022-06-22 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2583094 55.7514
2022-06-22 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1295164 54.9825
2022-06-17 BUFFETT WARREN E A - P-Purchase Common Stock 119515 56.4195
2022-06-17 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 119515 56.4195
2022-06-17 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1928737 55.7788
2022-06-17 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 3624944 54.9633
2022-06-17 BUFFETT WARREN E A - P-Purchase Common Stock 3624944 54.9633
2022-06-01 Champion Christopher O VP, CAO and Controller A - M-Exempt Common Stock 11465 25.39
2022-06-01 Champion Christopher O VP, CAO and Controller A - M-Exempt Common Stock 95129 40.03
2022-06-01 Champion Christopher O VP, CAO and Controller D - M-Exempt Stock Option (Right to buy) 95129 40.03
2022-06-01 Champion Christopher O VP, CAO and Controller D - S-Sale Common Stock 106594 70.44
2022-06-01 Champion Christopher O VP, CAO and Controller D - S-Sale Common Stock 5000 70.37
2022-06-01 Champion Christopher O VP, CAO and Controller D - G-Gift Common Stock 5396 0
2022-06-01 Champion Christopher O VP, CAO and Controller D - M-Exempt Stock Option (Right to buy) 11465 0
2022-06-01 Champion Christopher O VP, CAO and Controller D - M-Exempt Stock Option (Right to buy) 11465 25.39
2022-06-01 Champion Christopher O VP, CAO and Controller D - S-Sale Warrants (Right to buy) 2097 22
2022-06-01 Champion Christopher O VP, CAO and Controller D - S-Sale Warrants (Right to buy) 2097 47.27
2022-05-26 GUTIERREZ CARLOS M A - G-Gift Common Stock 1961 0
2022-05-10 BUFFETT WARREN E A - P-Purchase Common Stock 185419 57.3386
2022-05-10 BUFFETT WARREN E A - P-Purchase Common Stock 185419 57.3386
2022-05-12 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 185419 57.3386
2022-05-10 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 716355 57.3161
2022-05-09 Shearer Bob A - A-Award Common Stock 3891 0
2022-05-09 POLADIAN AVEDICK BARUYR A - A-Award Common Stock 3891 0
2022-05-09 MOORE JACK B A - A-Award Common Stock 4755 0
2022-05-09 MOORE JACK B D - F-InKind Common Stock 1047 57.84
2022-05-09 KLESSE WILLIAM R A - A-Award Common Stock 3891 0
2022-05-09 KLESSE WILLIAM R D - F-InKind Common Stock 857 57.84
2022-05-09 GUTIERREZ CARLOS M A - A-Award Common Stock 3458 0
2022-05-09 GOULD ANDREW A - A-Award Common Stock 3891 0
2022-05-09 GOULD ANDREW D - F-InKind Common Stock 857 57.84
2022-05-09 CHAZEN STEPHEN I A - A-Award Common Stock 5360 0
2022-05-09 CHAZEN STEPHEN I D - F-InKind Common Stock 1180 57.84
2022-05-09 BAILEY VICKY A A - A-Award Common Stock 3458 0
2022-05-03 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 20500 57.7843
2022-05-02 BUFFETT WARREN E A - P-Purchase Common Stock 20500 57.7843
2022-05-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 701626 58.3745
2022-05-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1918019 57.562
2022-05-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2510957 56.7255
2022-05-02 BUFFETT WARREN E A - P-Purchase Common Stock 2510957 56.7255
2022-05-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 736516 55.9957
2022-03-28 Hollub Vicki A. President and CEO A - P-Purchase Common Stock 14191 56.24
2022-03-23 BAILEY VICKY A A - A-Award Common Stock 558 0
2022-03-22 BAILEY VICKY A director D - No Securities Beneficially Owned 0 0
2022-03-16 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1720363 54.3729
2022-03-16 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 3366227 53.7151
2022-03-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1769805 54.5188
2022-03-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1938641 53.7413
2022-03-15 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2029931 52.9899
2022-03-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 5376500 55.3815
2022-03-14 BUFFETT WARREN E A - P-Purchase Common Stock 5376500 55.3815
2022-03-14 BUFFETT WARREN E A - P-Purchase Common Stock 1901149 55.0216
2022-03-14 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1901149 55.0216
2022-03-11 POLADIAN AVEDICK BARUYR D - S-Sale Common Stock 20000 57.23
2022-03-09 BUFFETT WARREN E A - P-Purchase Common Stock 1179234 57.8943
2022-03-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1179234 57.8943
2022-03-11 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1126783 57.5122
2022-03-10 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 123042 58.4456
2022-03-10 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 542256 57.5353
2022-03-09 BUFFETT WARREN E A - P-Purchase Common Stock 345332 58.2713
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 345332 58.2713
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 9753917 57.3758
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 7304139 56.4579
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 4968927 55.7463
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 436419 54.783
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 991165 52.8325
2022-03-09 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 336175 51.4374
2022-03-02 BUFFETT WARREN E A - P-Purchase Common Stock 838411 56.2845
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 838411 56.2845
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 10110321 55.777
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2102782 54.6441
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 2714566 53.7681
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1500236 52.5247
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 8778617 51.643
2022-03-02 BUFFETT WARREN E A - P-Purchase Common Stock 4996615 50.8964
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 4996615 50.8964
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1390394 49.6269
2022-03-04 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1565923 48.842
2022-03-03 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 3715944 48.3028
2022-03-03 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 8649722 47.7712
2022-03-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 1586349 49.1264
2022-03-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 9210407 48.5948
2022-03-02 BERKSHIRE HATHAWAY INC 10 percent owner A - P-Purchase Common Stock 4191531 47.6222
2022-03-01 BERKSHIRE HATHAWAY INC 10 percent owner I - Common Stock 0 0
2022-03-01 BERKSHIRE HATHAWAY INC 10 percent owner I - Series A Preferred Stock 0 0
2022-03-01 BERKSHIRE HATHAWAY INC 10 percent owner I - Warrants to Purchase Shares of Common Stock 83858848.81 59.624
2022-02-28 Peterson Robert L SVP & CFO D - F-InKind Common Stock 8978 43.73
2022-02-28 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 9234 43.73
2022-02-28 Hollub Vicki A. President and CEO D - F-InKind Common Stock 31902 43.73
2022-02-28 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 9017 43.73
2022-02-28 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 3641 43.73
2022-02-28 Bennett Peter J. Vice President D - F-InKind Common Stock 6485 43.73
2022-02-28 Backus Marcia E. SVP, GC & CCO D - F-InKind Common Stock 8876 43.73
2022-02-11 Peterson Robert L SVP & CFO A - A-Award Common Stock 18614 0
2022-02-11 Peterson Robert L SVP & CFO A - A-Award Stock Option (Right to buy) 34204 42.98
2022-02-11 Jackson Richard A. Senior Vice President A - A-Award Common Stock 18614 0
2022-02-11 Jackson Richard A. Senior Vice President A - A-Award Stock Option (Right to buy) 34204 42.98
2022-02-11 Hollub Vicki A. President and CEO A - A-Award Common Stock 56713 0
2022-02-11 Hollub Vicki A. President and CEO A - A-Award Stock Option (Right to buy) 104213 42.98
2022-02-11 Dillon Kenneth Senior Vice President A - A-Award Common Stock 20359 0
2022-02-11 Dillon Kenneth Senior Vice President A - A-Award Stock Option (Right to buy) 37410 42.98
2022-02-11 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 10180 0
2022-02-11 Champion Christopher O VP, CAO and Controller A - A-Award Stock Option (Right to buy) 18705 42.98
2022-02-11 Bennett Peter J. Vice President A - A-Award Common Stock 11634 0
2022-02-11 Bennett Peter J. Vice President A - A-Award Stock Option (Right to buy) 21377 42.98
2022-02-11 Backus Marcia E. SVP, GC & CCO A - A-Award Common Stock 19777 0
2022-02-11 Backus Marcia E. SVP, GC & CCO A - A-Award Stock Option (Right to buy) 36341 42.98
2022-01-31 Peterson Robert L SVP & CFO A - M-Exempt Common Stock 44337 0
2022-01-31 Peterson Robert L SVP & CFO D - D-Return Common Stock 44337 37.67
2022-01-31 Peterson Robert L SVP & CFO D - M-Exempt Phantom Stock Units 44337 0
2022-01-31 Jackson Richard A. Senior Vice President A - M-Exempt Common Stock 29558 0
2022-01-31 Jackson Richard A. Senior Vice President D - D-Return Common Stock 29558 37.67
2022-01-31 Jackson Richard A. Senior Vice President D - M-Exempt Phantom Stock Units 29558 0
2022-01-31 Bennett Peter J. Vice President A - M-Exempt Common Stock 37243 0
2022-01-31 Bennett Peter J. Vice President D - D-Return Common Stock 37243 37.67
2022-01-31 Bennett Peter J. Vice President D - M-Exempt Phantom Stock Units 37243 0
2022-01-26 GUTIERREZ CARLOS M director A - G-Gift Common Stock 3108 0
2021-07-28 Peterson Robert L SVP & CFO D - D-Return Common Stock 4652 0
2021-11-15 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 78 0
2021-11-15 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 340 31.98
2021-08-09 CHAZEN STEPHEN I director A - P-Purchase Common Stock 20000 25.76
2021-07-28 CHAZEN STEPHEN I director D - D-Return Common Stock 41346 0
2021-05-19 GUTIERREZ CARLOS M director D - G-Gift Common Stock 30625 0
2021-05-10 Shearer Bob director A - A-Award Common Stock 8450 0
2021-05-10 POLADIAN AVEDICK BARUYR director A - A-Award Common Stock 8450 0
2021-05-10 Palau Hernandez Margarita director A - A-Award Common Stock 7511 0
2021-05-10 MOORE JACK B director A - A-Award Common Stock 10327 0
2021-05-10 MOORE JACK B director D - F-InKind Common Stock 2272 26.63
2021-05-10 LANGHAM ANDREW director A - A-Award Common Stock 7511 0
2021-05-10 KLESSE WILLIAM R director A - A-Award Common Stock 7511 0
2021-05-10 KLESSE WILLIAM R director D - F-InKind Common Stock 1653 26.63
2021-05-10 Hu Gaoxiang director A - A-Award Common Stock 7511 0
2021-05-10 GUTIERREZ CARLOS M director A - A-Award Common Stock 8450 0
2021-05-10 GOULD ANDREW director A - A-Award Common Stock 8450 0
2021-05-10 CHAZEN STEPHEN I director A - A-Award Common Stock 12580 0
2021-05-10 CHAZEN STEPHEN I director D - F-InKind Common Stock 2768 26.63
2021-04-05 ICAHN CARL C 10 percent owner D - S-Sale Common Stock 3500000 25.6
2021-04-06 ICAHN CARL C 10 percent owner D - S-Sale Common Stock 3500000 25.7
2021-03-31 ICAHN CARL C 10 percent owner D - S-Sale Common Stock 2600000 26.88
2021-04-01 ICAHN CARL C 10 percent owner D - S-Sale Common Stock 5400000 27.28
2021-02-28 Peterson Robert L SVP & CFO D - F-InKind Common Stock 7239 26.61
2021-02-28 Jackson Richard A. Senior Vice President D - F-InKind Common Stock 6744 26.61
2021-02-28 Hollub Vicki A. President and CEO D - F-InKind Common Stock 27760 26.61
2021-02-28 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 7178 26.61
2021-02-28 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 1380 26.61
2021-02-28 Bennett Peter J. Vice President D - F-InKind Common Stock 3312 26.61
2021-02-28 Backus Marcia E. SVP, GC & CCO D - F-InKind Common Stock 7536 26.61
2021-02-12 Bennett Peter J. Vice President A - A-Award Common Stock 17232 0
2021-02-12 Bennett Peter J. Vice President A - A-Award Stock Option (Right to buy) 34394 25.39
2021-02-12 Jackson Richard A. Senior Vice President A - A-Award Common Stock 27570 0
2021-02-12 Jackson Richard A. Senior Vice President A - A-Award Stock Option (Right to buy) 55030 25.39
2021-02-12 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 17232 0
2021-02-12 Champion Christopher O VP, CAO and Controller A - A-Award Stock Option (Right to buy) 34394 25.39
2021-02-12 Dillon Kenneth Senior Vice President A - A-Award Common Stock 29047 0
2021-02-12 Dillon Kenneth Senior Vice President A - A-Award Stock Option (Right to buy) 57978 25.39
2021-02-12 Backus Marcia E. SVP, GC & CCO A - A-Award Common Stock 29540 0
2021-02-12 Backus Marcia E. SVP, GC & CCO A - A-Award Stock Option (Right to buy) 58961 25.39
2021-02-12 Peterson Robert L SVP & CFO A - A-Award Common Stock 27570 0
2021-02-12 Peterson Robert L SVP & CFO A - A-Award Stock Option (Right to buy) 55030 25.39
2021-02-12 Hollub Vicki A. President and CEO A - A-Award Common Stock 72372 0
2021-02-12 Hollub Vicki A. President and CEO A - A-Award Stock Option (Right to buy) 144454 25.39
2021-02-10 Hu Gaoxiang director A - A-Award Common Stock 2051 0
2021-02-09 Hu Gaoxiang director D - No Securities Beneficially Owned 0 0
2020-08-31 CHAZEN STEPHEN I director D - F-InKind Warrant 405 22
2020-11-14 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 82 0
2020-11-14 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 363 11.8
2020-11-15 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 77 0
2020-11-15 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 340 11.8
2020-11-10 Champion Christopher O VP, CAO and Controller A - A-Award Common Stock 481 0
2020-11-10 Champion Christopher O VP, CAO and Controller D - F-InKind Common Stock 2120 12.38
2020-09-30 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 432060 22
2020-09-29 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 1153378 22
2020-09-28 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 90469 22
2020-09-25 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 422996 22
2020-09-24 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 248551 22
2020-09-23 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 187894 22
2020-09-22 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 99109 22
2020-09-18 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 356118 22
2020-09-17 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 317635 22
2020-09-21 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 428132 22
2020-09-16 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 439565 22
2020-09-15 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 445913 22
2020-09-14 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 732066 22
2020-09-11 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 569739 22
2020-09-10 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 652282 22
2020-09-09 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 450000 22
2020-08-31 Peterson Robert L SVP & CFO D - F-InKind Warrant 4402 22
2020-08-31 Jackson Richard A. Vice President D - F-InKind Warrant 3434 22
2020-08-31 Hollub Vicki A. President and CEO D - F-InKind Warrants 8991 22
2020-08-31 Hebert Burnis J. Vice President D - F-InKind Warrant 1276 22
2020-08-31 Dillon Kenneth Senior Vice President D - F-InKind Warrant 1841 22
2020-08-31 Champion Christopher O VP, CAO and Controller D - F-InKind Warrant 914 22
2020-08-31 Bennett Peter J. Vice President D - F-InKind Warrant 3376 22
2020-08-31 Backus Marcia E. SVP, GC & CCO D - F-InKind Warrant 2170 22
2020-08-25 KLESSE WILLIAM R director A - P-Purchase Common Stock 10000 13.43
2020-08-25 KLESSE WILLIAM R director A - P-Purchase Warrant 10000 22
2020-08-21 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 200600 22
2020-08-20 ICAHN CARL C 10 percent owner A - P-Purchase Warrant 1000000 22
2020-08-03 ICAHN CARL C 10 percent owner I - Common Stock $0.20 par value per share 0 0
2020-08-03 ICAHN CARL C 10 percent owner I - Warrants 11078406 22
2020-07-30 CHAZEN STEPHEN I director D - D-Return Common Stock 59018 0
2020-05-29 Jackson Richard A. Vice President D - Common Stock 0 0
2020-05-29 Jackson Richard A. Vice President I - Common Stock 0 0
2020-05-29 Jackson Richard A. Vice President D - Employee Stock Options (right to buy) 15000 79.98
2020-05-29 Jackson Richard A. Vice President D - Phantom Stock Units 29558 0
2020-05-29 Hebert Burnis J. Vice President D - Common Stock 0 0
2020-05-29 Hebert Burnis J. Vice President I - Common Stock 0 0
2020-05-29 Hebert Burnis J. Vice President D - Employee Stock Options (right to buy) 5000 79.98
2020-05-29 Bennett Peter J. Vice President D - Common Stock 0 0
2020-05-29 Bennett Peter J. Vice President I - Common Stock 0 0
2020-05-29 Bennett Peter J. Vice President D - Phantom Stock Units 37243 0
2020-06-05 Brown Oscar K Former Senior Vice President D - S-Sale Common Stock 52066 19.42
2020-06-08 Brown Oscar K Former Senior Vice President D - S-Sale Common Stock 11839 23.97
2020-06-01 Shearer Bob director A - A-Award Common Stock 12672 0
2020-06-01 POLADIAN AVEDICK BARUYR director A - A-Award Common Stock 13940 0
2020-06-01 Palau Hernandez Margarita director A - A-Award Common Stock 11405 0
2020-06-01 MOORE JACK B director A - A-Award Common Stock 15207 0
2020-06-01 MOORE JACK B director D - F-InKind Common Stock 3346 13.81
2020-06-01 LANGHAM ANDREW director A - A-Award Common Stock 11405 0
2020-06-01 KLESSE WILLIAM R director A - A-Award Common Stock 11405 0
2020-06-01 KLESSE WILLIAM R director D - F-InKind Common Stock 2510 13.81
2020-06-01 GUTIERREZ CARLOS M director A - A-Award Common Stock 12672 0
2020-06-01 Graziano Nick director A - A-Award Common Stock 11405 0
2020-06-01 GOULD ANDREW director A - A-Award Common Stock 12672 0
2020-06-01 CHAZEN STEPHEN I director A - A-Award Common Stock 18248 0
2020-05-08 Brown Oscar K Former Senior Vice President D - S-Sale Common Stock 30000 14.85
2020-04-03 Peterson Robert L SVP & CFO D - Common Stock 0 0
2020-04-03 Peterson Robert L SVP & CFO I - Common Stock 0 0
2020-04-03 Peterson Robert L SVP & CFO D - Employee Stock Options (right to buy) 15000 79.98
2020-04-03 Peterson Robert L SVP & CFO D - Phantom Stock Units 44337 0
2020-03-18 CHAZEN STEPHEN I director D - Common Stock 0 0
2020-03-26 Palau Hernandez Margarita director A - A-Award Common Stock 2485 0
2020-03-25 Palau Hernandez Margarita director D - No Securities Beneficially Owned 0 0
2020-03-26 LANGHAM ANDREW director A - A-Award Common Stock 2485 0
2020-03-25 LANGHAM ANDREW director D - No Securities Beneficially Owned 0 0
2020-03-26 Graziano Nick director A - A-Award Common Stock 2485 0
2020-03-25 Graziano Nick director D - No Securities Beneficially Owned 0 0
2020-03-26 Dillon Kenneth Senior Vice President A - P-Purchase Common Stock 10000 13.42
2020-03-19 CHAZEN STEPHEN I director A - A-Award Common Stock 4383 0
2020-03-18 CHAZEN STEPHEN I director D - Common Stock 0 0
2020-03-13 KLESSE WILLIAM R director A - P-Purchase Common Stock 20000 11.81
2020-03-06 Brown Oscar K Senior Vice President A - P-Purchase Common Stock 5000 27.44
2020-03-04 Walter Elisse B. director A - P-Purchase Common Stock 3758 33.21
2020-03-02 GOULD ANDREW director A - A-Award Common Stock 1139 0
2020-02-28 Vangolen Glenn M. SVP - Business Support D - F-InKind Common Stock 7375 32.74
2020-02-28 Palmer Robert Senior Vice President D - F-InKind Common Stock 3019 32.74
2020-02-28 Lowe Edward A. Executive Vice President D - F-InKind Common Stock 9106 32.74
2020-02-28 Hollub Vicki A. President and CEO D - F-InKind Common Stock 16478 32.74
2020-02-28 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 6804 32.74
2020-02-28 BURGHER CEDRIC W. SVP & CFO D - F-InKind Common Stock 5523 32.74
2020-02-28 Brown Oscar K Senior Vice President D - F-InKind Common Stock 6069 32.74
2020-02-28 Backus Marcia E. SVP, GC & CCO D - F-InKind Common Stock 7806 32.74
2020-03-01 GOULD ANDREW director D - Common Stock 0 0
2020-02-14 Vangolen Glenn M. SVP - Business Support A - A-Award Stock Option (Right to buy) 235364 41.6
2020-02-14 Vangolen Glenn M. SVP - Business Support A - A-Award Common Stock 18029 0
2020-02-14 Vangolen Glenn M. SVP - Business Support A - A-Award Common Stock 9856 0
2020-02-14 Vangolen Glenn M. SVP - Business Support D - F-InKind Common Stock 3875 41.6
2020-02-14 Palmer Robert Senior Vice President A - A-Award Stock Option (Right to buy) 164755 41.6
2020-02-14 Palmer Robert Senior Vice President A - A-Award Common Stock 12621 0
2020-02-14 Hollub Vicki A. President and CEO A - A-Award Stock Option (Right to buy) 576641 41.6
2020-02-14 Hollub Vicki A. President and CEO A - A-Award Common Stock 60848 0
2020-02-14 Hollub Vicki A. President and CEO A - A-Award Common Stock 63101 0
2020-02-14 Hollub Vicki A. President and CEO A - A-Award Common Stock 42670 0
2020-02-14 Hollub Vicki A. President and CEO D - F-InKind Common Stock 16791 41.6
2020-02-14 Hollub Vicki A. President and CEO A - A-Award Stock Appreciation Right 247132 41.6
2020-02-14 Lowe Edward A. Executive Vice President A - A-Award Stock Option (Right to buy) 274591 41.6
2020-02-14 Lowe Edward A. Executive Vice President A - A-Award Common Stock 21034 0
2020-02-14 Lowe Edward A. Executive Vice President A - A-Award Common Stock 12334 0
2020-02-14 Lowe Edward A. Executive Vice President D - F-InKind Common Stock 4842 41.6
2020-02-14 Dillon Kenneth Senior Vice President A - A-Award Stock Option (Right to buy) 231441 41.6
2020-02-14 Dillon Kenneth Senior Vice President A - A-Award Common Stock 17729 0
2020-02-14 Champion Christopher O VP and Chief Acct. Officer A - A-Award Stock Option (Right to buy) 137296 41.6
2020-02-14 Champion Christopher O VP and Chief Acct. Officer A - A-Award Common Stock 10517 0
2020-02-14 BURGHER CEDRIC W. SVP & CFO A - A-Award Stock Option (Right to buy) 266746 41.6
2020-02-14 BURGHER CEDRIC W. SVP & CFO A - A-Award Common Stock 18029 0
2020-02-14 BURGHER CEDRIC W. SVP & CFO A - A-Award Common Stock 20433 0
2020-02-14 BURGHER CEDRIC W. SVP & CFO A - A-Award Common Stock 10836 0
2020-02-14 BURGHER CEDRIC W. SVP & CFO D - F-InKind Common Stock 4253 41.6
2020-02-14 Brown Oscar K Senior Vice President A - A-Award Stock Option (Right to buy) 203982 41.6
2020-02-14 Brown Oscar K Senior Vice President A - A-Award Common Stock 21635 0
2020-02-14 Brown Oscar K Senior Vice President A - A-Award Common Stock 15625 0
2020-02-14 Backus Marcia E. SVP, GC & CCO A - A-Award Stock Option (Right to buy) 235364 41.6
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2019-11-15 Champion Christopher O VP and Chief Acct. Officer A - A-Award Common Stock 15 0
2019-11-15 Champion Christopher O VP and Chief Acct. Officer D - F-InKind Common Stock 316 38.95
2019-11-10 Champion Christopher O VP and Chief Acct. Officer A - A-Award Common Stock 12 0
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2019-07-11 Palmer Robert Senior Vice President I - Common Stock 0 0
2019-07-11 Palmer Robert Senior Vice President D - Employee Stock Options (right to buy) 10000 79.98
2019-07-12 Vangolen Glenn M. SVP - Business Support D - F-InKind Common Stock 2113 51.72
2019-07-12 Lowe Edward A. Executive Vice President D - F-InKind Common Stock 2689 51.72
2019-07-12 Kirk Jennifer M VP and Principal Acct. Officer D - F-InKind Common Stock 692 51.72
2019-07-12 Hollub Vicki A. President and CEO D - F-InKind Common Stock 4098 51.72
2019-07-12 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 1452 51.72
2019-07-12 Backus Marcia E. SVP, GC & CCO D - F-InKind Common Stock 2305 51.72
2019-07-11 Shearer Bob director A - A-Award Common Stock 3718 0
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2019-07-10 Lowe Edward A. Executive Vice President A - A-Award Common Stock 6892 0
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2019-07-10 Hollub Vicki A. President and CEO A - A-Award Common Stock 8616 0
2019-07-10 Hollub Vicki A. President and CEO D - F-InKind Common Stock 3391 50.24
2019-07-10 Backus Marcia E. SVP, GC & CCO A - A-Award Common Stock 3791 0
2019-07-10 Backus Marcia E. SVP, GC & CCO D - F-InKind Common Stock 1492 50.24
2019-07-10 Shearer Bob director D - Common Stock 0 0
2019-07-07 Kirk Jennifer M VP and Principal Acct. Officer D - F-InKind Common Stock 651 49.28
2019-07-07 Dillon Kenneth Senior Vice President D - F-InKind Common Stock 950 49.28
2019-06-12 POLADIAN AVEDICK BARUYR director A - P-Purchase Common Stock 5000 48.77
2019-06-13 BURGHER CEDRIC W. SVP & CFO A - P-Purchase Common Stock 4100 49.61
2019-06-12 Brown Oscar K Senior Vice President A - P-Purchase Common Stock 6000 48.51
2019-06-11 Brown Oscar K Senior Vice President A - P-Purchase Common Stock 4000 48.46
2019-06-10 Brown Oscar K Senior Vice President A - P-Purchase Common Stock 5000 47.86
2019-06-11 Vangolen Glenn M. SVP - Business Support A - P-Purchase Common Stock 5000 48.53
2019-06-10 Batchelder Eugene L. director A - P-Purchase Common Stock 4000 48.12
Transcripts
Operator:
Good afternoon and welcome to Occidental's First Quarter 2024 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.
Jordan Tanner:
Thank you, Drew. Good afternoon, everyone and thank you for participating in Occidental's First Quarter 2024 Earnings Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Sunil Mathew, Senior Vice President and Chief Financial Officer; Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management and Ken Dillon, Senior Vice President and President, International Oil and Gas Operations.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki.
Vicki Hollub:
Thank you, Jordan and good afternoon, everyone. I'm pleased to report on a strong start to 2024, driven by our persistent focus on operational execution. As we will detail in today's call, our oil and gas business delivered robust production results essentially offsetting an extended third-party outage, while our Midstream and OxyChem businesses outperformed our first quarter guidance.
Today, I'll start by discussing our first quarter performance, including highlighting our Delaware appraisal success and its contribution to Permian's development runway. Then I'll discuss what's on the horizon for Oxy and how these initiatives are expected to generate significant value for our shareholders. Operational excellence is fundamental to everything we do at Oxy and our capabilities were evident during the first quarter as our teams generated over $2.4 billion in operating cash flow before working capital. Though the third-party outage in the Eastern Gulf of Mexico made it a challenging start to the year, our teams delivered excellent performance in all areas of our portfolio. We concluded the first quarter by approximating the midpoint of our production guidance and we restarted production from our Gulf of Mexico platforms affected by the outage in mid-April. Taking a closer look at our production results, the first quarter benefited from strong new well performance in the Permian Basin and the Rockies, overcoming the impact of winter weather early in the year. In the Permian, we exceeded the midpoint of our production guidance due in part to better-than-expected secondary bench performance in the Delaware Basin. Our Delaware teams are achieving impressive performance by results -- performance results by applying the same proprietary subsurface workflows that have generated remarkable success in our primary benches and applying that to secondary benches. Through utilization of fit-for-purpose well design and reservoir characterization expertise, performance in our secondary benches is nearly matching Oxy's record-setting 2023 program average. Not only that, first year cumulative production from Oxy's 2023 secondary wells exceeds the Delaware industry average for all horizontal wells for the same period by more than 30%. We are driving financial returns for our shareholders by improving our ability to high grade our near-term inventory and by extending our runway of Tier 1 locations. Meanwhile, use of our existing infrastructure yields meaningful capital efficiencies. We expect these efficiency benefits to become more impactful as secondary benches become a more substantial part of our development program. Our Rockies assets outperformed the high end of our first quarter production guidance, partly driven by strong new well performance in the DJ Basin, better production uptime, higher-than-expected outside operating volumes. And then internationally, we achieved record gross daily production in Oman North, driven by new well performance and production uptime. Our teams continue to improve capital efficiency through a combination of innovative well design, exceptional execution, proactive supply chain and management practices. In the DJ and Powder River Basins, our teams optimized casing and cementing plans, completion stage design and profit utilization. These fit-for-purpose well design enhancements resulted in tangible first quarter well cost reductions of between $700,000 and $1 million per well compared to the first half of last year. We're also starting to see cost reduction progress in the Delaware Basin. Our continuous drive for improvement not only leads to innovations that increased operational efficiencies but in many instances, we're also able to reduce emissions and advanced progress toward our net zero goals. I'm proud of our team's involvement in another oil and gas industry first, the deployment of a fully electric well service rig. Oxy and Axis Energy Services deployed the first of its kind rig into our Permian Basin operations. Expanding electrification is integral to Oxy's strategy because it increases operational efficiency, generates cost savings, improves safety and helps reduce our emissions. Our Midstream business significantly outperformed at the high end of our guidance for the first quarter. Outperformance was partly driven by gas marketing optimization across our portfolio where our teams captured value in regional pricing disparities. Warmer than expected weather, combined with various third-party midstream infrastructure maintenance resulted in disjointed prices in some regions. Midstream's first quarter performance demonstrates how our teams realized value from these pricing abnormalities by leveraging Oxy's rich market intelligence along with our product storage and transportation portfolio. Looking back over multiple quarters, our marketing teams have frequently demonstrated the ability to outperform, with our transportation optimization capabilities playing a major role. Over the longer term, we anticipate similar marketing opportunities but we generally exclude those opportunities from our guidance because of the difficulty in predicting events occurrence. Not only does our Midstream business provide us with flow assurance for our marketed products, it also offers great diversification during periods of commodity price volatility as we saw in early 2024. Along with being one of the top performers for the products is manufactures, OxyChem is a consistent cash flow diversifier within our business, due in part to its renowned focus on operational efficiency. During the first quarter, OxyChem benefited from improved demand from our marketed products, including PVC and vinyl chloride as well as lower ethylene cost. This performance demonstrates how our diversified asset portfolio is well positioned to deliver financial results for our shareholders throughout the commodity cycle. In prior calls, we have reiterated our drive to increase value for our investors on an absolute and per share basis through cash flow and earnings growth. Today, I'd like to provide an update on the specific projects that we mentioned in our last quarterly call. Some aspects of the OxyChem plant enhancement projects are complete but there is more to be done, including the Battleground project where the team held a groundbreaking ceremony on April 4, to kickoff the site work. Employees, contractors, community partners, city leaders and elected officials attended in support of the project. The completion of the OxyChem projects and reductions in crude oil and transportation rates from the Permian to the Gulf Coast are expected to deliver incremental cash flow of approximately $725 million per year. In our Midstream business, we expect that our ownership stake in Western Midstream or West, will also enhance our financial results. In February, West announced an increase of over 50% to their distribution. Based on the current distribution, we anticipate that West will contribute over $240 million of additional cash flow per year to Oxy. Additionally, we intend to increase free cash flow by repaying debt as it matures. Repayment of existing debt maturities through 2026 will result in approximately $180 million of annualized incremental cash flow from interest savings that can then be applied to further strengthen our balance sheet. Overall, we expect more than $1 billion of cash flow improvements that are independent of commodities' cycles. That figure does not include our oil and gas business, which is also poised for continued financial success. As most of you know, at the end of last year, we entered into an agreement to strategically enhance our Midland Basin portfolio with the acquisition of CrownRock. The free cash flow accretion and portfolio high grading to be enabled by the CrownRock acquisition are expected to provide the potential for equity appreciation and acceleration of our shareholder return priorities. In our low carbon ventures businesses, we expect to generate cash flow detached from oil and gas price volatility and further strengthen Oxy's cash flow resiliency. Construction of our first direct air capture plant, STRATOS, is advancing on schedule. And during the first quarter, we were pleased to announce a multitude of carbon dioxide removal credit agreements with customers across a variety of sectors. Throughout Oxy's portfolio, we are focused on expanding resilient cash flow and enhancing shareholder value for decades to come. I will now hand the call over to Sunil, who will cover our financial results and guidance.
Sunil Mathew:
Thank you, Vicki. In the first quarter of 2024, we generated an adjusted profit of $0.63 per diluted share and a reported profit of $0.75 per diluted share. The difference between adjusted and reported profit was primarily driven by our litigation settlement gain related to the Andes arbitration and gains on sales included in equity income, partially offset by derivative losses.
We exited the first quarter with nearly $1.3 billion of unrestricted cash. We had a negative working capital change, which is typical for the first quarter and is largely due to semiannual interest payments on our debt, annual property tax payments and payments under our compensation plans. During the first quarter, we delivered over $700 million of free cash flow before working capital despite third-party outage impacts to portions of our oily high-margin production in the Gulf of Mexico. First quarter free cash flow was underpinned by outperformance in our onshore domestic portfolio and our Midstream and OxyChem segments. Looking ahead to the second quarter, total company production is expected to increase to a range of 1.23 million to 1.27 million BOE per day compared to the first quarter annual low of 1.17 million BOE per day. The midpoint of second quarter production guidance will be the highest quarterly production in over 3 years. The production increase is mainly due to U.S. onshore activity levels, the completion of annual plant maintenance at Dolphin and the return of production in mid-April from the Gulf of Mexico outage. Our second quarter Gulf of Mexico production guidance includes third-party outage impacts in April as well as plant maintenance in the Central Gulf of Mexico. Though we revised full year Gulf of Mexico production guidance down, as a result of the extended outage, it is fully offset by outperformance in the Rockies and we are maintaining our total company production guidance for the year. The modified production mix is expected to impact annual total company oil cut. We had a strong start to 2024 in our chemicals business and anticipate modest price improvements during the second quarter, combined with higher volumes as we exit the usual period of seasonal subdued demand. Though lower gas prices are unfavorable elsewhere in our portfolio, OxyChem benefits from reduced energy costs and our midstream teams are well positioned to capitalize on the gas marketing opportunities that Vicki highlighted. Solid outperformance has enabled us to raise Midstream's full year guidance range by $110 million. Oxy's first quarter performance demonstrates the benefits of our differentiated portfolio. Our diversified assets and distinguished operational capabilities offer our shareholders' cash flow resiliency throughout the commodities cycle. In terms of capital spending, our first quarter results were in alignment with the 2024 business plan and the capital program that is weighted towards the first half of the year. On the last earnings call, we stated that approximately 40% of Rockies capital for the year is associated with drilled and uncompleted wells, or DUCs, carried in from 2023. We intend to continue -- completing these wells and reduce DUC inventory through the first half of the year. Similarly, Permian capital is weighted towards the first half of the year due to working interest variability and the desire to high grade rigs and increased utilization rates into the second half of the year. This U.S. onshore capital profile, combined with Battleground ramp-up, is expected to result in second quarter being the highest quarterly capital for the year. I would like to close today by touching on the CrownRock acquisition. Our teams are working constructively with the FTC and we anticipate that the transaction will close in the third quarter of this year. As a reminder, Oxy will benefit from CrownRock's activity between the transaction's January 1, 2024, effective date and close, subject to customary purchase price adjustments. Concurrent with the CrownRock acquisition, we announced a $4.5 billion to $6 billion divestiture program to be completed within 18 months of the transactions close. The high-quality assets within our portfolio have garnered much interest and our teams have commenced the early stages of the divestiture process. Sales proceeds will be applied to deleveraging until we reduce our principal debt to $15 billion or below. The near-term cash flow enhancements that Vicki highlighted are expected to deliver significant free cash flow growth per diluted share for our common shareholders and to enable us to accelerate the achievement of our debt target. After our debt target is met, we intend to resume our share repurchase program and provide even greater value per common share. As we have discussed on today's call, we are well positioned to build on a strong first quarter of 2024 and deliver a differentiated long-term value proposition to our shareholders. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Sunil. Before we move to Q&A, I want to tell you about a milestone our team celebrated last quarter. Oxy began trading on the New York Stock Exchange on March 3, 1964. On that day, our operations consisted of 252 oil and gas wells in 6 states. Today, we're an international energy, chemicals and carbon management company with the best portfolio in our history. But I believe that Oxy's employees are a true differentiator. Their expertise and drive to outperform continue to stretch the limits of what is achievable in our industry. Our employees are hard at work executing our strategy through superior operations and best-in-class assets. Their efforts result in long-term shareholder value and I look forward to showcasing more of their achievements on future calls.
With that, we'll now open the call for questions. And as a reminder, as Jordan mentioned, Richard Jackson and Ken Dillon are with us today for the Q&A session.
Operator:
[Operator Instructions] The first question comes from Roger Read with Wells Fargo.
Roger Read:
Yes. Thank you and good afternoon. I'd like to -- if we could maybe just dig in a little bit more on the Permian outlook here, probably including the Rockies, maybe let's just call it the Lower 48. If we look at the CapEx and then we look at the forecast for the full year, I'm just a little curious why you didn't get a little more optimistic about total volumes? And I recognize that within the year-over-year changes, we're looking at a little more EOR, maybe a little less shale wells. And I was wondering if that's part of the difference we're seeing or maybe why we don't see production raised as well?
Vicki Hollub:
Richard?
Richard Jackson:
Yes. Thanks, Roger. Appreciate the question. I mean clearly, very pleased with our first quarter results coming out of the -- both the Rockies and the Permian. Both had [indiscernible] on the quarter, with Permian looking good on several fronts. I'll focus there first. I guess, a couple of things just to kind of anchor the year on. As we think about going from first quarter to the second quarter, which Sunil mentioned, quite a big step up in terms of production but even looking at first half versus second half in the Permian, the implied increase is about 18,000 barrels a day first half to second half and we're doing that while reducing rigs for -- in the Permian.
So we're getting more with less in terms of how we think about activity. Some of that plays through on the capital, as you mentioned, as we're a bit front-load heavy, both on rigs but also facilities as we're front-loading the facilities in the first half of the year to take on that production increase starting next quarter. The good news is, things are performing well. And so when you look at the year and you think about the trajectory we're going on with things that are meaningful to our business, we highlight the new well production, not only the primary zones, which we've highlighted over the last couple of years but now, especially this quarter, we really wanted to highlight the success of the secondary benches that play a meaningful role in our portfolio for the year. The other thing that we don't talk enough about is base decline. And so if you look at our Permian resources this year, we're improving. Our base declined from last year about 4% to 5%. That's around 15,000 barrels a day. And so that's really come through not only better wells but a lot better operations. Our uptime is improving 1% to 2% in places like the Delaware. And so I think, as we thought about full year guidance, we certainly appreciated the results in the first quarter but we wanted to see how this plays out over the steep production increase over the next couple of quarters but look forward to updating our milestones and progress through that. The last thing I would just say is, behind that, as you think about capital, we are seeing capital efficiency. So we highlighted some of the well cost improvements, both in the Rockies and the Permian. I'm very pleased with our team's progress there. That's being done through strong approaches with our service companies but also through well design changes, which we noted. And so as we put that together, we look at this total year production versus capital, our capital intensity this year has improved over last year, which is the goal. So what we're spending, dollars, millions of dollars per production added -- has improved year-on-year and we'll stay focused on that. So look forward to more updates as we go through this year to kind of help put that piece together for our total year outlook.
Roger Read:
Okay, appreciate that. I guess the other question I had just -- you talked about it on the intro there, Vicki but the performance of the midstream, how much of that is something that we ought to think about as we're going to go forward over the next 1.5 years, 2 years? We'll have another period where we're probably constrained on being able to move oil and gas out of the basin just maybe a way to think about other opportunities coming forward for you all to capture a little bit better?
Vicki Hollub:
Well, for us, it's not really -- we don't have an issue moving oil or gas out of the Permian Basin. And in fact, some of the things, the positive impacts for our midstream performance are due to the fact that, from a gas perspective, we have capacity elsewhere so that we can move molecules around too and trade molecules. And we have ways to get gas to California and to other markets. So from a gas marketing perspective, we're in really good shape and take away capacity in good shape there.
Oil, we're also in good shape. We have overcapacity now to get barrels out of the Permian. So when we talk about fluctuations in the Midstream business with respect to crude marketing, normally that -- some of that's associated with picking up the third-party barrels that are associated with the capacity that we need to fill with incremental barrels above and beyond our current production. So that's the volatility mostly in the Midstream business, that, along with the gas marketing, does cause volatility. But normally, that volatility is [indiscernible] the upside for us because of the fact that, as I just mentioned, we have the capability to move things around and to take advantage of situations that -- where others are disadvantaged. So while with Waha and the situation that it's in now, our upstream realizations are lower but our Midstream business is able to capture opportunity to offset that.
Operator:
The next question comes from Paul Cheng with Scotiabank.
Paul Cheng:
Vicki, or maybe, this is for Rich, in there you were -- you're talking about the secondary branches, I think there's the Bone Spring. Is it -- why spread too far your entire operation or specifically in certain countries? Is there any kind of characteristic that you can see in terms of the pattern that will lead to this very strong performance wells from those branches for that -- those area? So we're trying to understand that, I mean how important it is to your overall operation or your overall inventory level?
And secondly, that your DJ has been performing really well, has been, I think, beating your own guidance for a number of quarters actually, I mean, at least for, say, 7 or 8 quarters already. So from that standpoint, is your current estimate maybe a little bit conservative that for the remaining of the year in the DJ? And also that, I mean, what are the primary reasons for the outperformance there?
Richard Jackson:
Yes. Thanks, Paul. I'll start in the Permian and get to the Rockies. I think what -- the way we describe sort of our approach to primary benches and then it's turned into our secondary benches is really unique by area. And so we spend a lot of time and we've talked about it in the past, really focused on the subsurface aspects, both from a geologic perspective and then as you think about it over time, from a reservoir perspective. And so I think as we've continued to delineate and be more broad in terms of the zones that we put together in areas, we focus on how do we put these wells in space together in the subsurface to optimize that recovery.
And, of course, your stimulation design and these other factors play an important role. So I don't think it's unique by area. I think it's the same approach that we've delivered in terms of the Midland Basin with the success we've had in the Barnett, what we're doing in the Delaware Basin, whether it's upper Bone Springs or deeper Wolfcamp. And I think, as we think about the Rockies, the same sort of approach there. In terms of the Rockies, they've had great performance over the last really year plus. And a lot of that started with the subsurface approach where we really spent time thinking about how do we approach lateral length spacing, stimulation intensity and I think a lot of the early gains we were seeing there. I think what we're seeing today is a lot more operational. We talk about how do we draw these wells down. So early time flow back and then longer term. And what we're seeing is really improvements in both. So in the early time performance, it's really having the facilities and the emissions handling to do that, not only at a correct rate but to handle the emissions. And then long term, we've talked about the base recovery with things like our plunger lift assist, kind of AI. And so these types of things are really what delivered the overperformance. I wish I could say it was conservative. I just think they've improved so much. When you're improving better than 20% year-on-year, that's sometimes tough to outlook. But I think they've gotten more mature in terms of some of these advancements over the last year and I think we've done a lot better job sort of narrowing the uncertainty of those outlooks. But all the teams are still on the hook to outperform this year. We're optimistic, like I answered earlier, in terms of what we're doing in the Permian as well. So I appreciate the question and hopefully, that helps.
Operator:
The next question comes from Neil Mehta with Goldman Sachs.
Neil Mehta:
My first question is just around noncore asset sales, recognizing we still have some time before the deal closes. But I would imagine you continue to have conversations around the divestments. And so just curious what your perspective is on the market right now and your confidence in the achievability of up to the $6 billion of noncore asset sales that many have anchored to?
Vicki Hollub:
Yes. It's -- there's a lot of incoming interest. Once we announced that we were going to divest between $4.5 billion and $6 billion, Sunil started getting a lot of phone calls and letters. And so the interest is there and it's very high interest. And what we're hoping and expecting is that, that high level of interest translates into appropriate levels of offers for the things that we might consider selling. But it all comes down to valuation and that's going to make the difference for us because we do have options and as you know, lots of acreage. So we're going to make the best value decision that we can. But we don't see that there would be any impediments barring something that we haven't foreseen that would cause us to have issues with our divestitures.
Neil Mehta:
And the follow-up is just your perspective on -- sorry, please Sunil.
Vicki Hollub:
Yes. What we were going to do is just for those that haven't heard, Sunil is going to go through the kind of what we think about with respect to divestitures, just to give those who might be listening get an idea of what we're looking at.
Sunil Mathew:
Yes. So as we have said previously, we are evaluating our portfolio, the high-graded portfolio and identifying what are the assets that does not fit in our development plan -- in our near-term development plan and -- but that could be attractive to other companies. So what is the strategic fit of that asset in this high-graded portfolio? And like Vicki mentioned, what is the value that we can get? And can we potentially accelerate the value by monetizing this asset? So like Vicki said, we're getting a lot of inbounds even before the announcement and a lot more after the announcement but this is the criteria that we're using to evaluate, is this an asset that we want to potentially monetize?
And going back to your question about $4.5 billion to $6 billion, yes, we are fully committed to achieving the target within 18 months of closing. And between the proceeds from asset sales and organic cash flow we want to get to the $15 billion of principal debt that we have outlined.
Neil Mehta:
That's great perspective. And then the follow-up is just on Battleground. I'd just love your perspective on both the chlorine and caustic soda markets. And how do you think about the outlook there? And once the expansion comes online, do you think that changes the supply-demand dynamics for any of these products?
Vicki Hollub:
Just to go back and look at what OxyChem has been able to do in the last few years. When we think about pricing of PVC and caustic soda this year, we've just come out of an incredible super cycle where, in 2022, we achieved our highest annual earnings ever, our second best earnings in 2021 and our third best in 2023. Now that we're into 2024, prices don't seem to be quite at the bottom. And as we were going through the first quarter, we started to see some strengthening and -- of caustic soda and PVC a little bit. But the reality is that inflation in the United States, along with very weak demand out of China because they're basically overbuilt right now in both commercial and residential housing and buildings, so we don't see China demand getting better anytime soon. But we do believe that beyond this year, getting past our inflationary environment that there was -- there's some certainty around some reduction in inflation.
We think the housing market is already primed for growth again. And so if we could get to an inflation level that is conducive for that, we'll certainly see -- start seeing recovery in prices here in the United States. The international market and we do export, so the international market impacts us. And so we'll continue to see some pricing challenges in that market. But ultimately, getting beyond this year and the next 18 months, I do believe that driven by India and other places that we'll see growth in demand again and that we'll start seeing prices going back up. So we're feeling like we're probably at a bottom right now.
Operator:
The next question comes from John Royall with JPMorgan.
John Royall:
So just thinking about the $400 million from midstream contract roll-offs. How much of the better terms baked into those numbers are you modeling that's locked in today versus what you're just kind of expecting? And to the extent [indiscernible], what's your level of confidence in terms of going the other way as we get closer to the roll-offs?
Vicki Hollub:
I'm sorry, could you repeat that question a little bit. We had some disturbance.
Operator:
Mr. Royall, could you pick up, if you're on a speaker phone, pick up the handset by any chance?
John Royall:
Is this better? Can you hear me now?
Operator:
I think that is better. Go ahead Sir, please repeat your question.
John Royall:
Okay, apologies for that, Vicki. So just thinking about the $400 million from midstream contract roll-offs. How much of the better terms baked into those numbers if locked in today versus kind of what you're expecting? And what's your level of confidence that, to the extent if not locked in, that it might not go the other way before you have to renegotiate?
Vicki Hollub:
I have high confidence that we'll achieve the $400 million and some of that we're already seeing today. And I do believe that we wouldn't, trust me, we wouldn't say it if we weren't pretty confident that we'll get it.
Sunil Mathew:
And John, it's this confidence that actually helped us increase our cash flow -- incremental cash flow from $350 million to $400 million.
Vicki Hollub:
Yes.
John Royall:
Fair enough. And then apologies if I missed anything on this but I was hoping you could get into the 2Q OpEx guide a little bit, which is somewhat flattish with 1Q despite higher production with the GoM back up. So it looks like a numerator issue and not a denominator issue. Just maybe any color there on the OpEx guide.
Vicki Hollub:
I think the OpEx guide was driven mostly by the impact of the Gulf of Mexico production and the production coming back on. It's -- I don't see any differential there. Do you?
Sunil Mathew:
No, I think that's right. That's -- yes, we're seeing improvement with Gulf of Mexico production coming back. But again, like I mentioned in my prepared remarks, the second quarter does include some impact from the pipeline outage and we also have a planned shutdown in Central Gulf of Mexico. So by the time you get to the third and fourth quarter, you should see an improvement in the operating cost.
Richard Jackson:
Yes, John, just to add to that trajectory. Q1 actuals were at $10.31 for U.S. LOE and we're outlooking $10.10 in the second quarter.
Operator:
The next question comes from Neal Dingmann with Truist.
Neal Dingmann:
I think my question is on the -- your Permian D&C plans, particularly around Slide 24, I like what you're showing there. You all suggest, I guess, running about 21 rigs this year on average. This is kind of something you talked about after running -- I think it shows what -- is it 24 in the first quarter? And I'm just wondering trying to get a sense of the cadence, would it just be a sort of typical ramp down. And I'm also wondering if your operational efficiencies continue to be as good as they've been, would you let some rigs go and continue kind of with that production plan? Or would you maybe just ultimately end up producing more?
Richard Jackson:
Yes. Perfect. Yes, I appreciate the question. Like I mentioned earlier, the plan is to ramp down just sequentially kind of as we go into the second half of the year. And really, that's been the plan since we boarded and came out. So we are seeing good operational efficiencies. I'd say time to market really in every area is slightly improved. So we'll consider that as we go into the year to just kind of understand how that may accelerate any capital and how we want to respond to that.
I would say 1 thing that has played out well, we noted these cost improvements and a couple of things to note. Beyond just operational efficiencies, we are seeing some good outcomes as we work with our service providers like [indiscernible]. And so we've been able to, kind of as we relook and hit that more level wise, let's say, balance and activity in the second half of the year, our utilization is going up about 10% on our frac core. So that's more pumping hours per year and that's both good for us but also good for our frac providers in terms of how they manage their business. And so those types of things are delivering these savings which we think will pace well even with some acceleration in our operational efficiencies. So as the cadence goes this year, we're heavy on D&C to start the year and facilities as well, like I mentioned. And really in that back half of the year, you'll see that capital drop and you'll see the production increase. And so looking forward to that. And then that should set us up at a much more level loaded and optimized pace going into 2025. And so obviously, we'll have options depending on where Vicki wants to take us with our capital program but that's sort of the thinking going into this year and into next.
Neal Dingmann:
That's what I was looking for, Richard. And then Richard, quick follow-up on the Permian for my second. How do you view the typical these days, you're doing great on bulk but your typical Delaware versus Midland well economics? Why I ask is, just looking at the curves you all show on Slides 25 and 29, which is again, I think [indiscernible]. I think you're showing around 450,000 BOE in the Del after a year versus around 250,000 BOE in the Midland, which again, knowing that they're cheaper wells, just wondering maybe in broad strokes, how you think about the difference in the economics?
Richard Jackson:
Yes. I mean, you're saying it right. I mean, I think -- and it's the same way we think about these primary and secondary benches, even in the Delaware, the cost matters. And it's not only the drilling and completion costs, you can look at a little bit shallower, a little bit different drilling in the Midland Basin leading to lower drilling and completion costs. Same for the secondary benches in the Delaware to get a little shallower into the Bone Springs, they're cheaper. And so it's certainly, you see it play through on the D&C. But the way the team's put together their development areas, they think about the impacts on facility costs. So one of the examples, I know we had reviewed here recently, we had some shallower Bone Spring wells that came on, I think, about 3 years after we drilled the Wolfcamp wells. And the returns for those secondary wells, even with lower production, was about double the primary. And that was because we were able to reutilize these production facilities.
And so that timing of how you put that production together can make a tremendous impact on the improvement of the economics. And so as you think about it in basins, we do the same thing. The advantages of being more balanced in the Midland Basin allows us to optimize all these facility costs, maintenance costs, all these things to make sure we're getting the most production per dollar spent, not just capital but even OpEx. So appreciate the question and that's absolutely how we look at balancing the capital, looking for that full cycle return forward.
Operator:
The next question comes from Scott Gruber with Citigroup.
Scott Gruber:
Staying on the topic of the Permian. Can you provide some color on what's included in the Permian unconventional inventory count when it comes to the secondary benches in the Bone Springs? And how does your success potentially push the inventory count higher?
Richard Jackson:
Yes. I'll just, maybe give you some perspective on how we're thinking about our inventory in general in terms of how that's going and I can address some of the Bone Spring. So the last couple of years, we've been able to more than replace the wells drilled with improvements in inventory, which come in 2 buckets. One is appraisal activity, which I'll give you a little color on in terms of Bone Spring to your question but also production improvement and cost reduction. So both of those things, not only add inventory but they move it, we call it to the left, that gets us to less than $60, less than $50 and then ultimately what we're going for less than $40 breakeven inventory.
And so as we think about, this year in the unconventional, we had a target of around adding 450 wells in the unconventional less than $50 breakeven. A bulk of that will come from -- we highlighted, one of the highlights we had was this third Bone Spring target that we had on the slide highlighting the 4 wells with greater than 780 MBOE or MBO. Those will add a bulk of our improvement this year in terms of that promotion of inventory. And so when I look at, even in the first quarter, just to give you some color, so we're aiming for this 450, in the first quarter we had 90 adds less than $50 breakeven. That came, about half of that, from the Bone Spring wells that I mentioned but we're also getting things out of New Mexico and some of the shallower Bone Spring there. And so it's not only what we're drilling today, which is going up in terms of secondary benches as a percentage of our total drilled wells in the year but it's really adding that low-cost inventory in the future. And so a lot of times, we'll get the so what of this inventory and that's really it. It's being able to extend this low-cost capital intensity as we prosecute our plan over the next few years.
Scott Gruber:
Got it. And then how do you think about potentially codeveloping some of the Bone Springs, along with the core Wolfcamp? Or you're mainly looking at coming back and hitting those zones, leveraging the installed infrastructure as you mentioned?
Richard Jackson:
Yes. I think -- I mean that's a big part of, I'd say the next few years, is really optimizing how we put that together. Obviously, in the Midland, we do a lot more what we call co-development where you're doing these zones at the same time. One of the benefits in the Delaware is being able to sequence them, have a little bit more precision because of the frac barriers. So we don't have to think about more of the [ cube ] or co-development opportunities, which gives us a great opportunity to really maximize the savings we get from reusing these facilities, like I described.
So last year, I think we were around 20% secondary benches in the Delaware. This year, we're north of 30%. So you can see that sort of opportunity becoming more prominent in terms of our development plans.
Operator:
The next question comes from Nitin Kumar with Mizuho.
Nitin Kumar:
I just want to start on CrownRock quickly. You mentioned that you're still on track to close the deal in the third quarter. When we announced the deal, you had talked about 170,000 BOE per day of production from CrownRock. Just wanted to see if you could revisit that and see how things are trending there as you are getting closer to the close?
Vicki Hollub:
We don't really have any update on the -- either the production or any of the other metrics from CrownRock, just what we've provided previously. We'll probably provide -- we'll definitely provide an update when we have our next quarterly meeting. Because by that time, I believe, we will have closed, maybe not but it's going to be certainly sometime in the third quarter.
Nitin Kumar:
Great. I thought I'd take a shot. And just -- there's been some movement in Colorado around SB24, which requires a production fee on producers. Want to see what that would look like for Oxy? You're a big producer in the state and sort of what your thoughts are around that initiative?
Vicki Hollub:
Yes. I think that the agreement that was reached in Colorado was a win-win for both the people of Colorado and the investments -- the investors in Colorado. So we feel that paying the fee and along with paying the fee to have taken away some bills and some potential ballot measures that would have severely restricted what the oil and gas industry could do that when you take that together, all together, it provides a scenario for the governor and the government of Colorado to do something positive with the fees that will be collected. So we view this to be not overly burdensome for our operations. We think it's actually going to be a doable scenario for us as we work towards some of the other things that will come along with this, which is working more on doing things that impact and help to reduce the impact on the ozone layer, as well as doing some things that will help from an environmental justice standpoint.
So it's a full package deal. It's not just a fee. And putting all that together, it's a good deal.
Operator:
The next question comes from David Deckelbaum with TD Cowen.
David Deckelbaum:
I wanted to ask for a little bit more color just on the guide just so I'm clear on how numbers are progressing this year. The impact from the Gulf of Mexico, is that exclusively what's contributing to the 100-basis point reduction in oil cut this year? Are you seeing some contribution from some gassier zones and some other of your core assets or perhaps the impact of the PSE in areas like Algeria?
Vicki Hollub:
No, it was almost entirely due to the Gulf of Mexico shutdown. There's really nothing else trending differently that we have in our portfolio.
David Deckelbaum:
Appreciate that. And then maybe just a follow-up on the discussion around deleveraging and noncore asset sales. It sounds like on this call, you might be emphasizing more the cash flow returns that you would be otherwise receiving from some of these assets that maybe the market has flagged as divestiture candidates. Is that the intention here in signaling that you intend to delever more organically in that noncore asset sales either theoretically would be higher in dollar value to reflect that cash flow contribution or might take longer to materialize?
Vicki Hollub:
I don't think that's what we intended to say. That was not the message we intended to give. When we talk about the fact that we will evaluate everything from a value perspective, what we want to do is just ensure that we're making the right decisions and divestitures of noncore areas is something that we want to do. And we believe that based on the interest that we're seeing that we should be able to achieve.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I'd just like to thank you all for your questions and for joining our call. Have a great rest of your day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to the Occidental's Fourth Quarter 2023 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.
Jordan Tanner:
Thank you, Gary. Good afternoon, everyone, and thank you for participating in Occidental's Fourth Quarter 2023 earnings conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Sunil Mathew, Senior Vice President and Chief Financial Officer; Richard Jackson, President, Operations, U.S. Onshore Resources and carbon management; and Ken Dillon, Senior Vice President and President, International Oil and Gas Operations.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules for our earnings release and on our website. I'll now turn the call over to Vicki.
Vicki Hollub:
Thank you, Jordan, and good afternoon, everyone. 2023 was a great year for us, thanks to the performance of all of our teams in Oxy. I'm going to start by discussing our financial performance, operational excellence and our strategic advancements in 2023, then I'll review our capital plans for 2024. [indiscernible] continue to position us to deliver sustainable and growing returns for our shareholders through our premier asset portfolio, advanced technology and robust commercial runway. First, I'll begin by reviewing our financial performance in 2023.
Last year, our talented and committed teams across the company applied advanced technical expertise, operating skills, leading-edge technologies and innovation to our exceptional portfolio, and they delivered results, $5.5 billion in free cash flow, which enabled us to pay $600 million of common dividend, repurchased $1.8 billion of common shares and redeemed $1.5 billion of preferred shares, while also investing $6.2 billion back into the business. Next, I'll comment on our operational excellence in 2023. Last year, our production in our global oil and gas business exceeded the midpoint of our original full year production guidance by 43,000 BOE per day. This was driven by record new well productivity rates across our domestic assets in the Delaware, Midland and DJ Basins, and internationally by record production from Block 9 in Oman, and in addition, we safely completed the expansion of the Al Hosn plant in the UAE, which also delivered record annual production. Despite negative price revisions, well performance across our portfolio enabled us to achieve an all-in reserves replacement ratio of 137% in 2023, and a 3-year average ratio of 183%. Our track record from prior years of consistently replacing produced barrels continues and added F&D cost that is below our current DD&A rate. At these year-end 2023 worldwide proved reserves increased to 4.0 billion BOE from 3.8 billion BOE in 2022. OxyChem performed exceptionally well in 2023. It exceeded guidance and achieved $1.5 billion in pretax income for the third time in its history, due largely to lower energy cost and an efficient planned turnaround at our Ingleside plant, even as product markets soften compared to 2022. In addition, construction on STRATOS, our first direct air capture facility, is progressing on schedule to be commercially operational in mid-2025. The fourth quarter of 2023 was an exciting way to conclude a successful year. In oil and gas, we delivered our highest quarterly production in over 3 years, and outperformed the midpoint of our production guidance despite a third-party interruption in the Gulf of Mexico. Our Rockies business outperformed in the fourth quarter, that's consistent with its year-long trends. Innovative artificial lift technology continued to maximize base production. Well design optimization in the DJ Basin that we presented in our second quarter earnings call contributed to a 32% productivity improvement from 2022. We also continued to deliver robust well performance in the Permian Basin, where our Delaware teams drove results to the high end of the Permian's fourth quarter production guidance. Our top spot well, which we also discussed in our second quarter earnings call, continued its strong performance trajectory and delivered the highest 6-month cumulative production of any horizontal well ever in the New Mexico Delaware Basin. In fact, Oxy has drilled 8 of the top 10 horizontal wells of all time across the entire Delaware based on this production metric, and 3 of those wells came online last year. Since mid-2022, our teams outperformed the Delaware Basin industry average 12-month cumulative oil production by nearly 50%. Our team aims to extend our leadership in the New Mexico Delaware Basin this year. A significant portion of the 2024 Delaware program will develop the same horizon as the record top spot well. Further south in the Texas Delaware Basin, our teams continue to deliver success with a couple of notable appraisal wells in the 2nd Bone Spring and 3rd Bone Spring line. These wells drove incredibly early time volumes, and accordingly, we secured additional capital in our 2024 Delaware program. Our appraisal programs are positioning us for success by adding horizons in the Delaware Basin and moving Tier 2 and Tier 3 wells to Tier 1. But we're also improving our current Tier 1 intervals, for example, with our top spot well. Outside the Delaware Basin, we're also making strides in some of the basins that we expect will begin to play a more consequential role. In the Midland Basin, technical excellence, including the basin-leading Barnett wells, drove a 1-year cumulative improvement in well productivity of over 30% compared to the prior year. In the Powder River Basin, Oxy set Wyoming state initial production and early cumulative production pad record of 1.5 million barrels of oil produced in only about 7 months. As we highlighted, our unconventional technical teams continue to expand and improve inventory across all of U.S. onshore basins. While our subsurface modeling, innovative well designs and enhanced artificial lift technology have driven improvements in well recovery, new well designs have also resulted in record drilling times for both 2- and 3-mile Texas Delaware Basin laterals. Similarly, in the Powder River Basin, our teams drilled an average 1,650 feet per day, and we drilled a 10,000-foot well in only 11 days, both achieving Oxy basin records. Our successes are not limited to our onshore U.S. portfolio. In the deepwater Gulf of Mexico, we are continuing to leverage technology to drive even stronger production results. In our subsea pumping system on the K2 field achieved first lift 4 months ahead of schedule. This is Oxy's first deployment of this technology in deepwater. We expect to unlock future production enhancement opportunities and longer distance subsea tiebacks. Next, I'll shift to discussing how we advanced our strategy last year. In 2023, we high-graded our oil and gas portfolio, launched the expansion of our OxyChem Battleground facility and announced strategic commercial transactions that we expect will deliver sustainable multiyear value to our shareholders. These steps strengthened our portfolio and make it unique in our industry. We have high-quality, short-cycle, high-return oil and gas shale development in the U.S. along with conventional lower decline oil and gas development in Permian EOR, [ Nigam ], Oman, Algeria and Abu Dhabi. These developments are complemented by our strong and stable cash flow from our chemicals business and the cash flow and carbon reduction we expect our low carbon ventures to provide in the future. In addition to high grading our oil and gas portfolio through organic development and appraisal work last year, we also announced the strategic acquisition of CrownRock, which will add high-margin, low-breakeven inventory, while increasing free cash flow per diluted share. The incremental cash flow will support our cash flow priority of delivering a sustainable and growing dividend, along with deleveraging and share repurchases after reducing the principal debt to $15 billion. We are working constructively with the FTC in its review of the transaction and expect to receive regulatory approval and close in the second half of this year. The capital plan we will review in a moment excludes CrownRock because we'll continue to operate as to 2 separate companies until we obtain regulatory approval and close the acquisition. In our LCV business, we completed many pivotal transactions that provided technology advancement, third-party capital, revenue certainty and commercial optionality. We closed the acquisition of direct air capture technology innovative Carbon Engineering last quarter. This was a landmark achievement in our direct air capture development path. We're excited also about our STRATOS joint venture with BlackRock, which we believe demonstrates the DAC is becoming an investable asset for world-class financial institutions. In addition, our teams signed on several more flagship carbon dioxide renewable credit customers. Now I'd like to reiterate our cash flow priorities and discuss our capital plans for 2024. On our December call, we discussed how we will focus on our cash flow and shareholder return priorities in 2024 on dividend growth, debt reduction and the capital allocation program that generates strong free cash flow throughout the commodity cycle. As we discussed regarding CrownRock, we intend to complete at least $4.5 billion in debt repayments for both pro forma cash flow and proceeds from the divestiture program. We intend to prioritize debt reduction until we achieve a principal debt balance of $15 billion or below, including repaying debt as it matures. As a result of the acquisition, we expect to strengthen our balance sheet, improve our resilience and lower commodity price environments and free up cash from interest payments to support future sustainable dividend growth and share repurchases. Every year, we designed our capital plan to support our strategic initiatives via projects that maximize our returns and best position Oxy to deliver long-term and resilient returns to our shareholders. Our 2024 capital plan continues a bifurcated investment approach that balances short-cycle, high-margin investments with measured longer-cycle cash flow growth investments. In 2024, we plan to invest $5.8 billion to $6 billion in our energy and chemicals businesses, resulting in slightly less capital for our unconventional assets this year. However, we expect our unconventional assets to return more cash to the business, and we continue to expect year-over-year production growth and continued success across our premier unconventional portfolio, including some of the emerging horizons. We intend to complement our unconventional exposure with increases to our mid-cycle investments, including lower decline conventional reservoirs, which are expected to drive longer cycle cash flow resiliency. Our 2024 mid-cycle capital investments will position us to continue the exciting projects that we started last year. Investments in OxyChem are expected to increase this year as progress continues on the battleground expansion and the plant enhancement project. We also added a second drillship in the Gulf of Mexico to support what we believe could become a future growth asset for Oxy. Lower decline oil production from our enhanced oil recovery, or EOR, is an important part of our long-term strategy. This year, we're investing in gas processing expansions for our Permian EOR business that supports longer-term growth in many of our core CO2 [indiscernible]. Our EOR business will continue to be a key part of our future oil and gas development as we believe that carbon dioxide captured by direct air capture facilities is a sustainable way to develop the 2 billion barrels of potentially recoverable oil remaining in our Permian EOR operations. In our emerging low-carbon businesses, much of Oxy's planned $600 million 2024 investment will be directed to STRATOS. We have also allocated capital to continue preparations for a second direct air capture and sequestration held in South Texas, along with subsurface and well permitting investments needed at our Gulf Coast sequestration hubs. Capital received from financial partners for our LCV businesses will add to our $600 million investment. This includes capital contributions from our joint venture partner, BlackRock, for STRATOS. BlackRock investment totaled $100 million in 2023, and we expect that figure will increase in 2024. We're making great progress towards advancing our net zero pathway as we develop direct air capture and other exciting technologies. We see tremendous potential in LCV to increase Oxy's cash flow resilience and generate solid long-term returns for our shareholders. I'll now turn the call over to Sunil for a review of our fourth quarter financial results and 2021 guidance.
Sunil Mathew:
Thank you, Vicki. I will begin today by reviewing our fourth quarter results. We announced an adjusted profit of $0.74 per diluted share, and a reported profit of $1.08 per diluted share, with the difference between adjusted and reported profit primarily driven by the after-tax fair value gain related to the acquisition of Carbon Engineering.
Our teams exceeded the midpoint of guidance across all 3 business segments during the fourth quarter, and we delivered outstanding operational performance. Higher-than-expected production in our domestic onshore and international assets enabled us to overcome production losses caused by an unplanned third-party outage in the Eastern Gulf of Mexico. This outage led to a lower-than-expected company-wide oil cut and a higher-than-anticipated domestic operating cost per BOE. It is also expected to impact production into early next month and is reflected in the guidance that I will soon cover. We had a positive working capital change, primarily due to receipt of the environmental remediation settlement, timing of semiannual interest payments on debt and decreases in commodity prices. We exited the quarter with over $1.4 billion of unrestricted cash. Turning now to guidance. Last month, Oxy and CrownRock each received a request from the FTC for additional information related to the acquisition. The FTC's request for additional information will impact the timing of closing, which we expect to occur in the second half of the year. Oxy will receive the benefit of CrownRock's activity between the January 1, 2024 transaction effective date and close, subject to customary purchase price adjustments. Additionally, the issuance of senior unsecured notes, funding of the fully committed 4.7 billion term loans and termination of the existing bridge loan facility are expected to be aligned with the transactions closing. In 2024, we expect full year production to average 1.25 million BOE per day, representing low single-digit growth from 2023, with the Rockies and Al Hosn driving production growth. As Vicki mentioned, well design and operational expertise drove production outperformance in the Rockies last year. We anticipate that these results will continue in 2024 with a steadier run rate of wells coming online compared to the first quarter of last year when we have recently ramped up rig activity. Permian production is expected to remain largely flat, with Permian unconventional capital decreasing by approximately 10% compared to the prior year. Internationally, we anticipate continued higher production at Al Hosn following last year's plant expansion. Total company production guidance in the first quarter reflects a low point for 2024, with a significant step-up expected in the remainder of the year. The expected first quarter decrease in production is primarily driven by the relatively lower activity levels and working interest in the Permian Basin in last year's fourth quarter. January winter storm impacts of approximately 8,000 BOE per day in our domestic onshore assets, annual plant maintenance at Dolphin and the Gulf of Mexico unplanned downtime event. Domestic operating costs on a BOE basis in 2024 are expected to decrease due to reduced maintenance in the Gulf of Mexico and improved lifting costs in the DJ Basin. Moving on to chemicals. In 2023, OxyChem generated pretax income nearly matching its second highest year ever. This year, we are guiding to a midpoint of $1.1 billion of pretax income. This year's full year guidance is close to the fourth best year ever for the chemicals segment despite potential challenging market conditions. We expect that our first quarter OxyChem results will be largely flat from the prior quarter. Our guidance for Q1 reflects the combination of PVC price erosion, largely associated with contract adjustments in Q4. Typical seasonal subdued demand in both PVC and caustic and export pricing pressure on caustic from China. Our guidance assumes that in Q1, we have reached the bottom of the cycle with more stabilized prices. I would like to close today by looking beyond 2024 to highlight several catalysts that we expect will enhance our financial trajectory in the coming years. Our midstream business is well positioned to benefit from a reduction in crude oil and transportation rates from the Permian to the Gulf Coast by the end of the third quarter of 2025. We expect annualized savings from these rate reductions of $300 million to $400 million, with approximately 40% of the savings starting in 2025, and the full annual savings anticipated in 2026. The OxyChem Battleground and plant enhancement projects are expected to generate incremental benefits to EBITDA of $300 million to $400 million per year once complete. In combination, these improvements to midstream and chemicals are expected to deliver an incremental annualized run rate EBITDA of $600 million to $800 million. As Vicki discussed, we also expect the planned mid-cycle investments in our conventional Gulf of Mexico and Permian EOR assets to provide cash flow resiliency through lower decline conventional production. As we continue to execute on high grading our premier portfolio, we are committed to meeting our deleveraging targets that I outlined in December. We believe that our strengthened balance sheet and Oxy's premium portfolio will enable future increases to our common dividend and rebalance enterprise value in favor of our common shareholders. Our teams are focused on extending Oxy's track record of operational excellence and solid execution on our path to delivering, growing and sustainable shareholder returns over the long term. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Sunil. 2023 was a significant year for Oxy on both operational and commercial fronts. Our teams skillfully navigated through the dynamics, and I want to recognize our employee's ingenuity and hard work, their efforts generated the exciting achievements we covered today as well as the great progress that is underway to position us for a successful 2024.
With that, we'd like to open the call for questions. Jordan mentioned earlier that Richard Jackson and Ken Dillon are also on the call, and they will participate in the Q&A session. We'll now take your calls.
Operator:
[Operator Instructions] The first question is from Neil Mehta with Goldman Sachs.
Neil Mehta:
My question is just really around deleveraging. And so you talked about this in the opening comments, but just talk about the path to getting the balance sheet to where you want to be post the CrownRock acquisition, and how are you seeing the asset sale market playing out here and enabling you to get that debt lower?
Vicki Hollub:
Well, as you noted, by virtue of all the M&A that's happening, there's a lot of appetite for companies to try to get into the Permian. And we do have properties in the Permian that are not core to us, but could be core to others, and some of it is where they're placed in the Permian geographically and how they're not as cored up as some of our key areas. So the divestitures, I believe, will go well. What we won't do though is we've decided not to make any divestitures until we close the CrownRock acquisition. And then we'll start a proactive process more aggressively at that point.
Neil Mehta:
That's great, Vicki. And then on the Gulf of Mexico, the Q1 guide of $107 million to $115 million, but the balance of the year, $133 million to $141 million. I'm guessing a lot of that's around the pipeline outage. Can you just give us a sense of what are the gating factors to get that asset back online, and how we should be thinking about the cadence of production over the course of the year?
Vicki Hollub:
Yes. We're leaving the updates on that to the operator. And so we're not making any comments on that because we're giving them room to get their business done. With respect to the rest of the year, we expect the rest of the year to continue on as normal. And we expect that when we're back up and running, we may get a little bit of flush production from that. And we'll have, hopefully, our target date for getting back up online is pretty close to what we've said. Do you have anything to add?
Kenneth Dillon:
It's Ken here. Maybe I can add a couple of things. So we feeling pretty good about the date. And for example, we're sending our specialist start-up crews offshore tomorrow to finish lining out the facilities for full operations. I think that gives you a feel for where we are in the process. The plants are in great shape. Our operations crews in parallel with the outage carried out our full 2024 turnarounds and also completed our enhancement projects for the year as well. So avoiding outages in 2024 gives us a really good shot. So we're looking forward to it.
Vicki Hollub:
Thank you. Appreciate it, Neil. That was timed very well spent. They made use of all the time that they had to do things that we needed to do.
Operator:
The next question is from Doug Leggate with Bank of America.
Douglas Leggate:
I guess the number of Scotts are shrinking, Ken. It's great to hear you on the call after Conoco's latest retirement. So thanks, Vicki, for getting on as well. So I have a couple of questions, if I may. I guess the first one is, I hate to do it, but I want to come back on the disposal question. I realize you don't want to give a lot of detail, but I want to frame it like this. When you had bought Anadarko and you were trying to delever, I seem to recall you had about 25 different packages that were for sale. And of course, you ended up not having to do hardly any of those. I think it was about a dozen or something like that. So it seems to me that you've got a lot of things that you've already scrubbed. So my question is, can you give us some color as to whether there is significant cash flow that would come along with the range of $4.5 billion to $6 billion, without being specific on assets, what's the associated free cash flow number?
Vicki Hollub:
Well, depending on what actually is divested, we can't really give you an estimate of what that is today. Some things are changing in terms of what we're looking at. So I think that it would be very difficult to put the number out there at this point.
Douglas Leggate:
Is it significant? Would you consider it material, Vicki?
Vicki Hollub:
Anything that's material, we wouldn't likely do. We're trying to minimize the cash flow sold to ensure that we can maintain our cash flow. With that said, there will be some cash flow going because it's hard to sell any assets out here that we haven't already at least done appraisal work on to generate some cash flow.
Douglas Leggate:
Okay. My follow-up is on sustaining capital. You've stepped up a little bit to $3.9 billion. But the way we -- what we're trying to figure out is this year's growth is about 2%. You're spending $6.5 billion, of which $1 billion is Battleground and DAC, which gets you to about $5.5 billion. So what I'm trying to figure out is the growth rate of 2% seems to correlate with growth spending of about $1.5 billion. It seems -- the ratio just seems a bit off. Can you help me understand how I should think about that?
Vicki Hollub:
So if you look at our -- what we've said we'll spend in oil and gas is $4.8 billion to $5 billion in 2024. That -- part of that will be spent on, as we mentioned, some of the mid-cycle projects that generate oil production at a later date. That's for example, the Permian EOR, investing in that would generate the oil and gas production from that is about the third year after we started. So that will be a bit delayed. Gulf of Mexico, some of those are also preparing us for the future.
So the mid-cycle investments will not impact this year's production. Potentially 2.2% increase will be based on the spending of the [ 4.9 ] if you use the mid-cycle price, less that [ 480 ]. And then when you look at what's being spent in our oil and gas operations minus that amount, you still have some of that going forward facilities. So I think it speaks well to what the teams have done with respect to productivity and getting more out of the wells that we can actually spend what's really less than half that $1 billion that you mentioned on oil and gas activities and then some of that will be for facilities. So we're actually getting a 2% growth rate from some of what we've developed in 2023 flowing over to 2024 and then the high productivity that we're getting out of our developments.
Douglas Leggate:
It's a great answer, Vicki, still the most capital efficient portfolio by miles.
Vicki Hollub:
I know it's really exciting what the teams have done, and thank you for the question.
Operator:
Next question is from John Royall with JPMorgan.
John Royall:
So my first question is on midstream. I think one area that surprised us a bit was the full year midstream guide, you gave some good color on the slides kind of bridging from 4Q to 1Q. But just thinking about bridging the full year. How would you characterize the moving pieces from full year '23 to full year '24? And then maybe what do you think the midstream business can do structurally kind of under mid-cycle conditions, excess $300 million to $400 million savings you've spoken about?
Sunil Mathew:
Yes. So one of the main drivers for the relatively lower guidance for this year is an assumption on the spread for the gas transportation contracts. So last year, we captured several gas transportation capacity optimization opportunities. For example, when the cold weather event occurred in the West Coast in the first quarter. So obviously, we cannot predict this event. So our guidance assumes compressed gas transportation spreads. But when the market does present itself, we are well positioned to capture these opportunities. So that is one of the main factors.
The other one is in Al Hosn. We have assumed a lower sulfur pricing for '24 compared to last year. Now sulfur prices are at a near-term low of around $70 per tonne, and that is primarily due to weak Asian fertilizer demand and also sale of built-up sulfur inventories by major regional producers. But based on the market trends, we think -- we see a potential improvement in prices during the second half from demand pickup and also unwinding of the sulfur inventory. And the last thing I would say is, we think this is sort of the low point in terms of the midstream income. We have assumed a narrow spread for the gas transportation for this year. And starting next year, we are also going to start getting the benefit of the 2 crude transportation contracts expiring, like I mentioned in my prepared remarks. So looking forward, the next 3 or 4 years, you should see a significant uplift in our midstream income.
John Royall:
Great. And then maybe just hoping for a little bit of detail on the 700 million BOE of additions to reserves. It's a pretty big number, especially when considering you're adding an acquisition this year. So maybe just some color on the sources of those additions and where they're coming from?
Vicki Hollub:
I think the bulk of the addition is from our Permian Resources business, I think the -- I think just essentially most of it was. We had some revisions from productivity improvements in other areas, but the bulk was from Permian EOR, where I think, Richard, if you look at your reserve replacement ratio, just for onshore, that was pretty significant.
Richard Jackson:
Yes. I mean just to add to that. I mean, obviously, the focus, while near term, some of these highlights that we're putting in on the primary benches that we've been developing driving the outperformance on production. But some of the highlights we've been trying to put in the call or some of these secondary benches that are becoming more prevalent in our program. If you look at some of those highlights at a 2nd Bone Spring or the Bone Spring line, you look at that Delaware chart that we've got on [indiscernible] production, highlighting the year-on-year performance in the Delaware, those secondary benches are outperforming our 2023 average. And so those -- as we delineate and develop more of those, that's really driving that reserves in the unconventional.
EOR continues to do well. Talk in more detail if there's interest, but some of the projects they have going on there to increase capacity in some of our gas processing facilities like in the Seminole, which I think we highlighted, these are also giving us near-term, we call it, operability or it's really the reliability of that production. So some of that incremental investment this year is driving, say, a couple of thousand barrels a day of improved base production, but that's also providing capacity to develop some of those low development cost barrels that Vicki noted as we're able to bring on the CO2 for the future. So that's sort of how we're thinking about the reserve story, and it plays out in near-term outperformance, but the long term is picking it up on reserves as well.
Vicki Hollub:
And I would add the other place where we did add significant reserves is Algeria as a result of the team's work to get all the 18 contracts merged into 1 and then extended. So that was great work done by the Algeria team to add reserves there. But the thing I'm most proud of is, while the bulk of the reserves came from those 2 sources of the Permian and Algeria, and a little bit from the DJ, every business unit we have increased reserves except for Al Hosn where we had already booked quite a bit of reserves because of the modeling [indiscernible] to get that estimate more refined.
Operator:
The next question is from David Deckelbaum with TD Cowen.
David Deckelbaum:
I just wanted to follow up a little just on the prior conversation around EOR. I guess this is being built out in conjunction with some of the anticipated volumes coming from STRATOS. Can you give us a sense what sort of capacity in terms of production relative to where you're at today, you're intending to build out? Or I guess, thought another way, how large do you anticipate the growth rate to be out of the EOR production base over the next 5 to 10 years?
Vicki Hollub:
I would tell you that, over the next 5 to 10 years, it's going to be a significant part of our portfolio development. We have 2 billion barrels of resources remaining to be developed. And we believe that as a result of our direct air capture facilities that we ultimately will build to get CO2 out of the atmosphere, it's going to be the most sustainable barrels in the world. It's going to be a resource that the world needs to get -- to leave 30% or 40% of oil in conventional reservoirs and 90% of oil and shale reservoirs is just not acceptable.
And for the United States, to continue our energy independence, EOR is going to have to be a part of the equation ultimately. We're getting way ahead of the game here to be sure that we're ready because we do believe that the climate transition would not be affordable for the world without EOR being able to produce net zero carbon barrels of oil. So this is a huge part of our strategy and important, not only to our shareholders. It will add value, but to the U.S. and ultimately to other parts of the world. And for the near term, a forecast on what we can do. Richard has some data on that.
Richard Jackson:
Yes, perfect. I'll tie that. I mean one of the attributes we really like around the EOR production that we talk about a lot is the lower decline. And so as we came through the last several years with -- especially to the downturn with lower commodity prices, being able to have that flat, flatter decline, less than 5%, was able to help us maintain a lot of free cash flow. We really started restoration of some of that development last year.
And this year, as we go forward, we'll have about 60 wells that we'll bring online, which will add about 4,000 barrels a day of new well production. But the benefit of this EOR and when we talk about mid-cycle, that double next year and triples in the third year. So you really hit your peak production of around 12,000 barrels a day based on that investment today 3 years from now. The other thing I mentioned shortly, but just provide a little more color, the Seminole gas plant expansion, that's about 85 million a day that will add in terms of capacity for about $40 million Again, this year, we'll expect a couple of thousand barrels a day that we'll add in our base production. So if you think about kind of a cash investment intensity, or capital intensity, that's a competitive business we've got in the portfolio. But what it does, to Vicki's point, is we're able to bring on our CO2, anthropogenic CO2 for the future, these are very good return projects. They'll be very competitive in our portfolio, especially given the lower decline. And so when we look at just that Seminole, as we look '24 to '28, that's, say, another 15,000 to 20,000 barrels a day type opportunity for minimal capital. And so within sort of the range of capital that we're spending this year in EOR, we're building those sort of wedges with great opportunity to do more as we bring on more CO2. So hopefully, that helps tie the short and long.
David Deckelbaum:
I appreciate the details, Richard. Maybe just sticking with the theme as a follow-up, just -- I think you talked a little bit about some spending is in the budget this year for the second DAC facility, I guess, in Kleberg. Is any part of that sort of progression still contingent on conversations with the DOE? And is -- are you expecting a resolution around finality of funding and grants this year?
Vicki Hollub:
The discussions with the DOE are continuing and going quite well that where we -- the timing of the start of the front-end engineering and design will be dependent on the completion of some of those discussions. And then the discussions will continue beyond that on getting prepared for the start of construction, but there is a time line there that we're working through.
Richard Jackson:
Maybe just a couple of details I'll add since you asked the question on that. A lot of that spend is continuing to build out the subsurface capability for that CO2. Obviously, direct air capture is an anchor for the King Ranch area, but we continue to work on our other Gulf Coast hubs. We've submitted 8 Class 6 and are expected to submit another 10 this year. So just kind of giving you scale of what those -- that type of work has been going there. So going really well. I'm really pleased with the development work on that end and then obviously Carbon Engineering, we've been getting to work more and more with and really happy with the progress that is going through R&D to project work with Ken that will fulfill that development work.
Operator:
The next question is from Roger Read with Wells Fargo Securities.
Roger Read:
I'd like to come back 2 things, please, Vicki. First one on the CrownRock, if there's anything you can kind of offer us on what the FTC is asking you for a second request. And I'll just sort of preface with I understand were some of the more integrated companies, the concern of concentration. I'm a little more surprised in a more upstream-oriented company. So anything you can help us with there?
Vicki Hollub:
Well, some of our teams felt like they'd asked for everything. But I can tell you, our teams are working diligently to work with the team at the FTC to get them all the answers that they need. So it's -- we're progressing and hope to, as we said, be able to close in the second half of this year.
Roger Read:
So they ask for the moon and everything else?
Vicki Hollub:
I did -- well, I didn't see the moon on there, but we're not done yet.
Roger Read:
Fair enough. All right. The other question I had in terms of the capital efficiencies are obviously coming through in the Permian. The regular, let's call it, still modest growth there, but you're increasing the growth rate during 2024 for the Rockies and other part of it. When we had the follow-up calls yesterday, you said part of it was built in some mid-cycle businesses, maybe somewhat lower decline businesses. I was just wondering from a corporate structure, how you make the decision on where to allocate the growth capital here? Like why lean more into the Rockies and the EOR rather than the Permian when we're -- kind of all conditions to thinking of the Permian is among the best returns in the business and, obviously, the performance you've been delivering at the wellhead kind of says, well, why not more capital in the Permian rather than these other opportunities?
Vicki Hollub:
So when you look at it on a corporate level, what we're really trying to do is balance our investments over time so that we can have a sustainable growing dividend. And it -- and we've got this unique balance that I think makes it for us, different than many other companies, and we want to take full advantage of it. And I want to let Richard and Sunil chime in on their views on it because this is a critical part of what differentiates us.
Richard Jackson:
Yes. No, Roger, I appreciate the opportunity. I mean, obviously, we're putting together short term with long term in mind, and the CrownRock acquisition provides a lot of growth, and we've talked about the positive attributes of that being a more mature unconventional development with high margin, 35% decline. It immediately adds, you can think about it from a growth standpoint, a really nice growth wedge this year, both from a free cash flow basis, but also a decline basis.
The Rockies, I'll just pick on 1 point there. About 40% of that capital on the Rockies this year has to do with drilled uncompleted wells that carried in from last year. The sort of the cadence of that activity levels we had resumed activity last year, got ahead on the drilling. And then this year really beginning to complete a lot of those wells. So from a capital intensity standpoint, that's very, very low when you look at what we're spending for the amount of production that we're able to add there. Obviously, that's -- we have high margins in the Rockies. We have royalties. There's other things that drive very competitive returns there. And so that DAC count, just as a data point, we'll kind of go from say, mid-60s kind of the fourth quarter last year to more like mid-30s as we balance, and that's allowing us to then actually pull back about half of a net rig in the Rockies to more of a sustainable activity level. So just a little color on the Rockies, so we don't read too much into just 1 year. But maybe Sunil can then pick that up and talk kind of across the company.
Sunil Mathew:
Yes. So when we think about capital allocation in the oil and gas segment, what you're trying to do is we're trying to balance between margin, base decline and capital flexibility. So if you start with cash margin, we start with the U.S. unconventional with high margin, high returns. And based on everything you've heard so far, it's getting better each year.
And then you have Gulf of Mexico, which has one of the highest cash margin in our portfolio. And if you look on an incremental basis, it's even higher because a large part of the operating cost is fixed. And then you have international assets, which are mostly production share [indiscernible] where we get a higher share of production at lower prices, and this helps mitigate some of the commodity price risk and protect the overall cash margin. So that is from a margin point of view. I mean when you think about base decline, so today, our production, approximately 60% of our production is unconventional. And with Crown Rock, it's going to get to around 65%. So what we are trying to do is balance between the short cycle, high-end decline unconventional, and then the mid-cycle shallower decline conventional investments. And Permian EOR, like Richard said, is one of the lowest base decline in our portfolio. So if you look at a typical Permian EOR project, we get to the peak production by the third year, and the peak production is almost 3x the first year of production. And then after that, it is a shallow decline. So what this does is it helps manage our overall corporate decline, which helps with the sustaining capital, and which ultimately helps with the breakeven. And the third part of it is capital flexibility. So if you look at our CapEx even for this year, around 75% of upstream CapEx is U.S. onshore, where we have flexibility to change activity depending on the macro conditions. So like if you look back in 2020, in U.S. onshore, we had around 30% of the rigs that we plan to operate this year. So we were able to ramp up quickly and efficiently, and we can do this if the macro demands that. So these are the 3 attributes that we look at when we look at oil and gas capital allocation. So to summarize what I would say is we have a diverse portfolio of both conventional and unconventional assets that helps manage our base decline, while also maximizing our returns and also providing the flexibility to respond to different macro conditions.
Operator:
The next question is from Neal Dingmann with Truist Securities.
Neal Dingmann:
My first question, Vicki, is on the DJ. I'm just wondering, could you remind me where you all sit, I think, in good shape. I'm just wondering where you all sit on total permits pertaining to your DJ D&C plan? And then while early, are you all concerned about the -- I saw some latest potential proponents Colorado bills?
Vicki Hollub:
Yes. I'll pass that to Richard.
Richard Jackson:
Yes. I think just from a permit standpoint, it's been very productive over the last couple of years. So we stand today about a little over a rig year -- or 1.5x kind of our current activity. But in the last 6 months, we've gotten [ 155 ] through. In the next 12 months, we expect another [ 169 ]. So there are some big ones that we've been working through kind of from a larger package standpoint that have gone really well.
That team there -- and I hope this helps kind of the second part of your question. We continue to drop things that are important to the communities and the state around emissions. Our safety programs are very good. We've worked on consolidating facilities and doing things around transportation to make it easier. And so a lot of those things have been really the positive things we've been able to add into these permit or development plans around the permits that we've received very positive comments on. So we're continuing on. Again, we're sort of hitting more stable, sustainable activity up there, and we feel like we're in as good a position as we have been in a long time in terms of permit outlook.
Neal Dingmann:
Very helpful, Richard. And then just a follow-up on shareholder return on M&A. I'm just wondering, I assume [indiscernible] the preferred redemptions would now not incur until late '25. So is it fair to assume that when you were looking at the CrownRock acquisition that the fact you factored in that any -- the CrownRock incremental production or free cash flow would more than offset any mitigated payments now for another year or so?
Vicki Hollub:
Yes. That's what we [indiscernible] on that. But the CrownRock does -- that acquisition, once we get our debt back down to $15 billion, that's going to be a key part of helping us then to start the resumption of a more robust share repurchase program of both the common and ultimately, the preferred.
Operator:
The next question is from Josh Silverstein with UBS.
Joshua Silverstein:
I was going to ask on kind of similar topic there now that the asset sales are pushed out, and you don't have the term loan coming into just yet. Is the shareholder return profile, just the base dividend this year and that kind of supports you get into that $15 billion debt number a bit faster?
Vicki Hollub:
No, actually, we would -- we're going to accumulate cash flow as we continue to work toward closing the CrownRock deal because part of cash flow will be used to help pay down both the term loan and our debt maturities that are coming. So cash flow would not be used for share repurchases until we get to the point where we've achieved those goals.
Joshua Silverstein:
Got it. And then I saw that the Battleground project was pushed out to 2026. If you could just go through any sort of the drivers of the extra time that was needed and what the status of the other plant enhancement projects look like? And maybe what the split of that $350 million EBITDA uplift was like kind of between Battleground and the other projects?
Vicki Hollub:
I think there's -- the projects there were pushed out a bit just like many other things because of supply chain issues and also dealing a little bit with inflation. But those projects, we started those and those are in progress and going well at this point. So I'd like to say that though the importance of when those cash flows come on from the plant enhancement projects, we're already starting to see cash flow from those projects. The actual cash flow that we'll see from the Battleground expansion won't be until the second half of 2026.
But the exciting thing about all of this is that, when you add the OxyChem projects, which will deliver the $300 billion to $400 billion the full uplift by the second half of '26, that's both the plant enhancement projects and the expansion, so we've got that, and you combine that with what Sunil had talked about earlier, where we have a $400 million reduction in our mid-cycle contract prices in 2025, we'll see the full uplift of that in 2026 as well. And so when you combine those along with the $1 billion that we expect, assuming in a WTI price of $70, that puts us in 2026 with $1.7 billion incremental cash at least and potentially more than that. So to be able to get to a point where in just a little over 2 years, where we have -- through these projects and cost reduction, we are $1.7 billion better in terms of cash flow, that's pretty significant for us and something that we're really looking forward to and excited about.
Operator:
The next question is from Michael Scialla with Stephens.
Michael Scialla:
I appreciate all the detail you gave on the decision to direct more capital this year to mid-cycle investments. I wanted to ask specifically about the Gulf of Mexico, which is part of that. Back in December, you were planning on just the 2 drill ships. So wanted to see what changed your thinking there to add a third drillship, and especially given that services there seem to be tighter than they are onshore, was it just part of this whole mid-cycle investment thesis? Or is there something else? And can you talk about specifically what you're seeing there that third drillship will be targeting?
Kenneth Dillon:
And in terms of drillships, we're only planning on 2 drillships this year. In terms of GoM overall, [indiscernible] plays into the portfolio, last time I mentioned our GoM 2.0 project. Based on that, we're counting out detailed [indiscernible] characterization work we can see significant upside potential in the GoM assets. I mentioned waterflood, stimulation, horizontals, artificial lift and subsea pumping, which is already operational for us.
If I talk a little bit about water injection, when you already operate fields with original oil in place numbers of billions of barrels, adding water injection is a really economical way of increasing recovery factors on high-margin, low-development cost barrels. Typical improvements in recovery in appropriate reservoirs can be between 10% and 16%, while also significantly reducing decline. So it plays into the things that Richard was talking about in EOR. Scale of these developments and the very low development costs lead to good returns. Analogs have been highly successful in GoM. As you know, we're world leaders in these technologies. We do them in every country that we operate in, and domestic is the foundation of who we are. I'd also like to highlight the OBN seismic activity that we've done since 2020. That's really helped define these targets, scale up them and it's assisting in the well planning and well locations that we're working on at the moment. I think we see GoM as a portfolio with great optionality to grow using the existing infrastructure that we have in place, but also the technology skills that we have across the entire company. I hope that answers your question.
Michael Scialla:
Yes, it does. Appreciate that, Ken. And on the -- on your CrownRock acquisition call. You mentioned -- I think Richard mentioned your pilot that you've been working on the Midland Basin for a couple of years. I just wonder if there's any plans to expand EOR in the Midland in the near term? And did that have any bearing on your decision with the CrownRock acquisition?
Vicki Hollub:
The Crown Rock acquisition stood on its own in terms of quality and how it fit within our portfolio in the Midland Basin and made that asset stronger. But the 4 pilots that we conducted in the Midland Basin were on the South Curtis Ranch, which is not too far from some of those asset. So we do believe that the Midland Basin is going to be one of the areas that we would target in a big way with an enhanced oil recovery development that's using anthropogenic or atmospheric. But we're also doing the same thing in the Delaware Basin now. We have a pilot going on there. That will help us to potentially look at that as another place to develop ultimately. So we have both options.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Just like to say thank you all for participating in our call today. Have a good day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to the Occidental's Third Quarter 2023 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.
Neil Backhouse:
Thank you, Anthony. Good afternoon, everyone, and thank you for participating in Occidental's Third Quarter 2023 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management; Rob Peterson, Executive Vice President, Essential Chemistry; Ken Dillon, Senior Vice President and President, International Oil and Gas Operations; and Mike Avery, President and General Manager of 1PointFive.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Neil, and good afternoon, everyone. The team and I would like to discuss 2 key topics today. First, how our portfolio of assets managed by excellent teams once again drove record performance this quarter, which flowed to the bottom line.
And second, as we promised an update on 1PointFive and Direct Air Capture, which we expect to play an increasingly important role in our portfolio over time. One important note before we begin, Rob Peterson, Executive VP of Essential Chemistry will cover our financial results and guidance today. Senior VP and Chief Financial Officer, Sunil Matthew, is unfortunately attending to a family emergency. We send our thoughts and prayers to Sunil and his family. I'll begin by reviewing our third quarter performance. Our teams again performed exceptionally well with our assets this quarter and delivered strongest earnings and cash flow from operations that we've had to date this year. This positioned us to further advance our shareholder return framework and established a strong trajectory for the fourth quarter. Let's follow the molecules from producing oil and gas to moving and marketing it to where it is most valued to our African team making the products that the world needs to improve lives. And finally, returning the molecules back underground as we capture emissions and sequester them forever. First, let's review the exceptional results in oil and gas. Strong third quarter operational performance in oil and gas production exceeded the midpoint of our guidance by 34,000 BOE per day, enabling us to increase full year production guidance by 11,000 BOE per day. Our third production guidance increased this year. Production outperformance was driven by strong new well performance in the DJ and Delaware basins as well as higher uptime due to favorable operating conditions in the Gulf of Mexico. In the Permian and Rockies, our high-quality inventory, combined with our team's subsurface expertise, continue to drive record cumulative well performance improvements. This exceptional well performance and our activity plans for the remainder of the year drove our full year production guidance increase. In the third quarter, our Delaware operations team set a record with a continuous pumping time of over 88 hours, doubling the previous and at that time, audacious record in the second quarter. Our teams are hyper-focused and diligent. Their advancements are continuing to drive high performance. Additionally, during the third quarter in the DJ Basin, we began deploying a new and innovative natural gas hybrid frac pump with Liberty Energy. We believe that deploying this forward-looking technology, which is an e-frac alternative will reduce completion costs over time as well as emissions. Our midstream business performed better than expected due to the timing of cargo sales amidst rising commodity prices. And finally, to OxyChem, which exceeded earnings guidance for the quarter, largely due to improved PVC and caustic soda export demand. I can't say it enough, OxyChem provides so much synergy and cash flow generation to our portfolio. And as you'll hear, plays a large role in our Direct Air Capture story. During the third quarter, we repurchased $600 million of common shares and have now completed 60% of our $3 billion share repurchase program. Share repurchases and our dividend enabled additional redemptions of the preferred equity. We have now redeemed over 15% of the preferred equity outstanding. Now I'd like to turn to the second big topic for our call, an update on the progress that our subsidiary, 1PointFive is experiencing with Director Air Capture or DAC. The DAC technology we are using leverages the skills and expertise of our chemicals business and our enhanced ore recovery business. Our team's achievements in DAC will drive benefits to Oxy in 3 ways. First, we will advance DAC for commercial use. Second, it will increase Oxy's low resilience and generate solid returns to our shareholders over the long term. And third, it will broaden our pathway to carbon neutrality and help others to achieve the same. Some of the team's recent achievements include the agreement we announced last night with BlackRock as a partner in our first stack plant, STRATOS. This is a huge signal to the marketplace that we are attracting capital as well as customers to this exciting technology. We are very happy to have BlackRock as our partner. Our team also reached a memorandum of understanding with our long-standing partner ADNOC to explore opportunities with DAC and carbon dioxide sequestration hubs in the U.S. and the UAE. And in just 8 weeks, we announced our first initiative together, a preliminary engineering study with ADNOC for a magneto scale, DAC facility in the UAE. And shortly after the second quarter earnings call, the U.S. Department of Energy announced that it has selected 1PointFive to receive a grant for development of our South Texas DAC Hub. And just this morning, Oxy Oman announced an agreement with OQ Gas Networks, the sole transporter of natural gas in Oman to jointly study potential carbon capture utilization and sequestration projects in the ultimate. I'll now turn the call over to Richard who will delve deeper into the momentum and progression of the carbon dioxide removal market and our DAC development plans.
Richard Jackson:
Thank you, Vicki. Today, I'm glad to provide a business update focused on Direct Air Capture and the carbon dioxide removal credit market. I also want to reiterate Vicki's comments on how thankful we are to welcome BlackRock as our initial investment partner for STRATOS, our first DAC facility.
This is the most recent milestone in our DAC development strategy and is aligned with our execution approach, which we will discuss today. Across the Oxy, we are determined to solve challenges to both improve our business and provide essential resources for the world. Our low carbon business is an expansion of that strategy, and it's positioned to be a key value differentiator for Oxy in emerging markets. I will begin by highlighting several of our key DAC related accomplishments. As we advanced our low carbon business strategy, Direct Air Capture was recognized as both a necessary and valuable technology. Removing CO2 from the atmosphere provides a required solution for businesses across hard-to-abate emission sectors. Near term, we believe our DAC technology can provide carbon dioxide removal credits or CDRs at a lower cost and at larger scale than other product solutions, especially for businesses in the heavy-duty transportation sector that are working to hit decarbonization targets this decade. Longer term, cost-effective access to atmospheric CO2 to create innovative new fuels or other products can provide a pathway to lower carbon materials and commodities for many industries. From strategy to development, our team has been forward-thinking and deliberate with a road map to advance technology, partnerships and markets. We continue to view technology to commercial product with the lens of capability, scale and systems thinking. In the case of DAC, we believe carbon engineering created a unique and innovative large-scale carbon removal process that has a strong fit to our OxyChem capabilities. This process uses equipment and materials that are ready to deploy at scale. Additionally, capturing large volumes of cost-effective CO2 improves Oxy's larger integrated oil and gas, CCUS and low-carbon businesses for today and tomorrow. Early team work with carbon engineering led to a more advanced innovation center at CE and U.S. development partnership with an exclusive license for Oxy. The formation of 1PointFive followed to allow more partnerships focused on market development for CDRs. Carbon removals reached critical momentum, both their early voluntary market leaders like Airbus purchasing CDRs and through new policy support measures like the U.S. Infrastructure Investment and Jobs Act, strategic catalyze early commercial development for technologies, including DAC. This progress was recognized worldwide and enabled new global development and CDR demand scenarios for 1PointFive to begin to take shape. Meanwhile, measurable project progress was being made with CE process innovations, the groundbreaking for STRATOS, our DAC 1 plant and with key 0 emission power and emissions measurement actions to support a durable and a well-defined CDR product. Our DAC development took another step forward through the partnership with the King Ranch that enables a 30 megaton hub in South Texas, both to improve future DAC costs and to provide a more certain supply of CDRs for an increasing demand. In 2022, the U.S. Department of Energy announced a $3.5 billion regional Direct Air Capture hubs program. In August of this year, we were notified that 1PointFive was selected by the DOE for a program grant to develop our second DAC in the South Texas Hub. This follows strong policy momentum over the last several years for CCUS through U.S. 45Q tax credit enhancements, including specific recognition for the role of carbon removals in the recent inflation Reduction Act. Recently, we've seen major project momentum with ADNOC support for the UAE DAC development and especially BlackRock's key investment in STRATOS, which bolsters our ability both to build and capitalize our plans. Further support comes from recent CDR purchase agreements with ANA, a key aviation partner with Amazon, which purchased 250,000 metric tons of carbon removals and with TD Bank Group with one of the largest purchases of CDRs by financial institution. These further showcase the growing appreciation for the necessity of CDRs from leaders in core industry sectors and the need to scale them in the near term. Finally, the acquisition of carbon engineering comes at a time where the need to accelerate DAC innovation is critical. We were excited to fully support CE as they advance DAC technology while also rapidly integrating next generation of innovations into our DAC plant builds. This helps make sure we maximize value across our partnerships and supports our ability to meet this growing CDR demand. Our DAC strategy has been visionary and deliberate, aligning investment with advancements with technology, partnerships, policy and CDR markets. This approach has enabled Oxy to deploy capital responsibly, while establishing leadership in this critical technology and growing CDR market. Our accomplishments to date have positioned us as a DAC technology and market leader. The next phase of our DAC strategy is focused on growth through accelerating cost reduction and expanding partnerships. With full ownership of carbon engineering technology now in-house, we expect to supplement and support the highly talented carbon engineering team to accelerate the innovations that ultimately reduce the cost to capture years earlier than initially anticipated. By pairing the strengths of carbon engineering, Oxy major projects and OxyChem, we will continue to reduce cost for the life of the plant. Early innovations that could reduce the cost of DAC include improvements to air contactor geometry, where we believe we can materially reduce the number of air contactors per facility. We are also designing air contactor fan motors that consume less power. Additionally, our teams are leveraging OxyChem's electrochemical and chlor-alkali expertise to evaluate advanced sorbents and improvements to chemical reaction rates that could increase DAC efficiency. Oxy has a proven track record of innovation, improving operational efficiencies and large-scale project development. The application of these core competencies will be key in the successful deployment of large-scale debt. Both the CDR demand and global development opportunities continue to increase. By accelerating the cost reduction of DAC, we aim to provide a low-cost, large-scale supply of CDRs that we believe we can provide a cost-effective solution to help businesses achieve their climate targets and improve the value proposition for DAC developers. We believe that DAC generated CDRs will play a significant role in corporate emissions reduction strategies and specifically for several hard-to-abate sectors like aviation and marine, and markets like low carbon fuels. Future regulatory and compliance frameworks that cap emissions growth are driving companies in certain sectors to purchase measurable and durable CVR credits like DAC CDRs. As we reduce the cost of DAC, we expect companies will increase the share of DAC CDRs in their portfolio of solutions. We have included 3 market demand scenarios in our earnings presentation to illustrate how the DAC CDR market may grow rapidly through the end of this decade as the cost of capture is reduced. Reducing costs will enable us to offer CDRs to an expanding market at lower price points. In a scenario where the cost of capture remains at $450 per ton, we still expect the market for DAC generated CDRs to be significantly undersupplied. Demand for CDR credits from the aviation industry is expected to reach an inflection point in 2027 when the International Civil Aviation Organization begins requiring airlines to reduce or offset their annual emissions through the carbon offsetting and reduction scheme for international aviation, also known as CORSIA. Operational improvements by airlines present limited opportunities for emissions reductions. We expect that emissions reductions from sustainable aviation fuel, or SAF, will also be constrained as SAF demand is anticipated to exceed supply once CORSIA and other SAF mandates come into effect. While we recognize the importance of SAF and aviation's pathway to decarbonization, SAF remains a partial solution that is currently unable to reduce emissions to true net 0. Already DAC CDRs can be priced lower than SAF while also having the ability to scale, meet demand and deliver a true net zero solution. We expect DAC CDRs will be an essential cost-effective solution for several [indiscernible] industries to achieve their targets within these compliance markets. The pace at which we will develop DAC facilities will be driven by market demand and our ability to reduce cost. If the CDR market developed slower than expected, we will have the flexibility to refocus our efforts on R&D with the goal of bringing costs down faster. If the CDR market develops in line with the medium or high cases we've laid out, then we intend to continue executing on our cost down plan and to be positioned to secure development partners for capital. This capital flexibility becomes the most valuable at the CDR market grows in line with our high demand forecast. A high demand for DAC CDRs would likely shift our focus towards licensing DAC technology with other developers to increase CDR supply more rapidly. The CE acquisition helps unlock this development optionality as we can integrate our learnings into a DAC technology license. Regional development partners can then support the build-out with local knowledge, technical and operational resources and capital, while Oxy can support through a technical heavy but capital-light development approach. Based on our current plan, we anticipate that the LCV program capital, excluding third-party funding, will be up to $600 million per year through 2026. Moving on to the DAC 1 and 2 developments. We are again excited to announce BlackRock will invest $550 million in STRATOS, our first DAC facility through a fund managed by its diversified infrastructure business. BlackRock's investment demonstrates that DAC is becoming an investable asset class for world-class financial institutions. STRATOS Construction is progressing well, and it's approximately 30% complete. Additionally, the ongoing work at the Carbon Engineering Innovation Center has already identified several promising opportunities to lower costs on future debt. We expect several of these ideas can be implemented into STRATOS to help demonstrate the improvements at scale and to be ready for future DAC builds. To accommodate these process improvements, we are optimizing the construction schedule for the 2 process trains. This ensures STRATOS remains on schedule to be commercially operational in mid 2025 while also ensuring we are implementing the latest technical advancements earlier than previously planned. This may face some capacity into 2026, but optimize our development plan and future costs. Our South Texas DAC Hub has commenced front-end engineering design and stratigraphic well testing is in progress. We are very appreciative of our recent selection for a grant from the U.S. Department of Energy and the meaningful work we are doing through that process. Though the timing and the amount of the DOE grant are not yet known, we look forward to the final agreement and announcement of additional details. We have continued to work within a framework of DAC investment principles that will enable us to advance development while delivering returns for our shareholders and value to our customers and partners. We are focused on accelerating reductions in the cost to capture, which is expected to increase market demand for CDRs and in turn, attract additional development partners. These factors will drive future development pace of DAC, including a final investment decision of DAC 2. We will also continue to advance collaboration with companies like BlackRock, ADNOC and Oman's OQ gas networks who share our long-term vision for Direct Air Capture and our broader low-carbon product ecosystem. Across it all, we appreciate these partnerships that are enabling this business for Oxy, and we are focused on delivery of this solution that can supply essential lower carbon products for the world. I will now turn the call over to Rob for our financial discussion.
Robert Peterson:
Thank you, Richard. We posted an adjusted profit of $1.18 per diluted share and a reported profit of $1.20 per diluted share. The difference between adjusted and reported earnings was primarily driven by gains on sales of noncore affluent assets, partially offset by derivative losses in the premium paid on preferred equity redemptions. During the third quarter, strong operational execution enabled us to generate over $1.7 billion of free cash flow before working capital, and we concluded the third quarter with over $600 million of unrestricted cash.
We experienced a modest negative working capital change during the period, partially driven by an increase in commodity prices. In October, we received $341 million in cash in the environmental remediation settlement we mentioned in the last earnings call. As Vicki highlighted, each of our domestic assets exceeded the midpoint of third quarter production guidance, including in the Gulf of Mexico, where favorable weather contributed to production exceeding the high end of guidance and a higher-than-expected company-wide oil cut. Oxy's outperformance, coupled with a portion of Gulf of Mexico planned maintenance moving into the fourth quarter, resulting in better-than-expected domestic operating expenses of $10.20 per BOE for the third quarter. Capital spending in the third quarter was approximately $1.6 billion, representing a slight decrease from the second quarter. We further advanced our shareholder return framework during the third quarter through the repurchase of $600 million of common shares, including $175 million, which settled at the start of the fourth quarter. Additionally, we have now redeemed over 15% of deferred equity with $342 million deferred equity redemptions triggered and redeemed during the third quarter. As of November 7, rolling 12-month common shareholder distributions totaled $3.12, falling below the $4 preferred equity reduction trigger. It is unlikely that cumulative distributions to common shareholders will be above the $4 per share trigger again this year, primarily due to the concentration of share repurchases in the second half of 2022. However, we remain committed to the per share earnings and cash flow accretion benefits derived from our share repurchase program, and we intend to continue repurchasing shares at a pace that is largely driven by commodity prices. As Vicki mentioned, we are raising our full year production guidance through the outperformance in the third quarter. We are guiding to 1.226 million BOE per day in the fourth quarter, our highest quarterly production for the year despite hailstorms in Delaware Basin that caused power interruptions early in October. Property damage for these Permian storms and Gulf of Mexico maintenance are expected to result in fourth quarter domestic operating costs of approximately $10.50 per BOE. Fourth quarter OxyChem guidance reflects typical seasonality as well as the impact of a planned turnaround at our Ingleside [indiscernible] and DCM plant. This turnaround was the first ever of the ethylene crakcer and the first total plant outage in the Ingleside complex in over a decade. We are beginning to see early indications that PVC and caustic soda prices may have bottomed. However, may not have full clarity on the fundamentals of the growth of the upcoming business cycle until early next year as challenges remain, including global macroeconomic uncertainty and demand impacts from rising interest rates. Our performance across our domestic businesses resulted in lower-than-anticipated corporate adjusted effective tax rate during the third quarter, which we expect a rebound of approximately 30% in the fourth quarter as a proportion of international to domestic income increases during the period. Moving on to capital. Third quarter Permian capital spending was elevated as a result of program mix and activity optimization. In certain areas, we developed higher working interest projects than originally planned as we sought to balance OBO or operated by other production. Company-wide capital spending to date and planned spending in the fourth quarter are likely to result in full year spending at the higher end of our guidance range. Our teams are finalizing our 2024 capital plan, which we look forward to announcing in our next call following Board approval. Today, I would like to revisit several points from previous calls regarding our expected 2024 capital plan. In the Upstream business, we expect similar domestic onshore activity levels to add on average to 2023. We all anticipate no material change in spending for our international assets. Additionally, we expect to run 2 drillships in the Gulf of Mexico next year as part of our mid-cycle investment program. OxyChem commenced work on the modernization expansion of Battleground plant this year. As construction advances, we anticipate an incremental $100 million of capital spending starting in 2024 compared to 2023 guidance. Incremental spending in the battleground expect to continue through 2025. To summarize, the third quarter of 2023 represented a strong operational and financial quarter for Oxy. As we are near the conclusion of this year, we are preparing for 2024 with a continued focus on operational excellence and delivering on our shareholder term framework. We are pleased with the progress of the framework to date and in addition to retiring the debt that matures in 2024, we intend to continue prioritizing share repurchases in our use of cash flow. The timing of when we may exceed the 4 of our preferred equity instant trigger again, will be determined by the pace of our share repurchase program, which were largely driven by the macro environment. I look forward to next quarter's call where we expect to report on completing another strong year for Oxy. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. As Richard explained earlier, we expect DAC to play a more important role in our premier and diverse portfolio of assets. We believe tremendous additional potential exists there.
Joining us today for the Q&A session, as Neil had mentioned earlier, will be Ken Dillon, who is Senior VP and President of International Oil and Gas operations but also manages our major projects part of the -- of our business -- the major projects group. So he can answer questions with respect to the construction of the DAC. And Mike Avery, President, General Manager of 1PointFive, as was mentioned earlier. He will answer questions about the business aspects of how we're running and we'll run the DAC and some of the other projects surrounding 1PointFive. So with that, I'll now turn the call over to the moderator for questions.
Operator:
[Operator Instructions] Our first question will come from Nitin Kumar with Mizuho.
Nitin Kumar:
I want to start, Vicki, with the topic to your and the industry M&A. I know Oxy has a deep bench of inventory that you highlighted. But obviously, with some deals out there recently, there's been a focus on consolidation. So just wanted to get your thoughts on how you see Oxy fitting into that trend going forward.
Vicki Hollub:
Well, Nitin, I do want to reiterate that we were early consolidators in our industry with the Anadarko acquisition. And we did that because we saw significant synergies there. And those were obvious to us, and they were in the acreage was in an area that made it possible for us to understand the subsurface and to gain those synergies.
Now that we've done that, and we more than doubled our production with that acquisition. We've more than achieve the $2 billion of synergies that we had forecast. And now it's considerably strengthened where we are today. But the good thing is we don't have to do acquisitions. Therefore, while our BD group keeps up with and is aware of what's happening in our industry, we see -- we feel no need to have to do anything or be a part of it.
Nitin Kumar:
That's very helpful. Vicki, I want to go back. I know the focus is on LCV today, but last quarter, you talked about the strong performance in your Permian well productivity. There's been some talk around improving technology and really focusing on improving recovery rates in the basin, you do as much technical work as anybody else. So just curious if you have any technology if you are deploying or seeing being deployed that could lead to a step change in recovery factors?
Vicki Hollub:
I think I really feel like we've already had a step change in our recovery factors. And if you go back and look as far back as 2014 and '15, the improvements that we've seen have been dramatic but most of those improvements have been around understanding the subsurface better and being able to better design frac jobs and also our wellbore configuration so that we can not only get the most out of the subsurface from a modeling perspective for the design, but also from an operating standpoint.
We have an operations team that is doing a lot on the surface and with artificial lift to take advantage of AI and other things to ensure that we get the most out of the wells from an operating perspective. And then we continue to access that by using artificial intelligence, lowering our bottom hole pressures and making sure that we're the best we can be on the subsurface with respect to efficiencies. Now, Richard and others would chomp at the bit to be able to talk to you about all the technical work we're doing, but I consider that to be proprietary. And I really feel like we've disclosed a considerable amount in the past and that's enabled some others to follow some of what we're doing. So to be honest, I'd just rather keep the proprietary stuff to ourselves for now. And from a technology perspective, we have mentioned some things that we're doing internationally to recover more out of our wells in Oman. But I'll just leave it at that. Richard really want to do just a couple of minutes. And probably what you're going to say is you also have to be careful with the definition of recovery, right?
Richard Jackson:
Yes, that's right. I'll stay on point. The thing I wanted to highlight is just obviously, recovery factor is core to what we're doing. We're really proud of the slides that we keep in our appendix, which shows year-on-year the improving performance for our wells and not over a few days. We look at it on our 1-year [indiscernible]. And it's not only in the Permian, it's in the Rockies. And as Vicki alluded to, we were talking earlier, Ken had some great advancements in the Middle East as well.
The other thing I wanted to say was our appraisal success. So highlight this quarter on the Wolfcamp B well that came through the record well. The ability to go engineer and do those technical things for these new benches is core to what we believe is important as we go forward. And so really proud of that appraisal success. The appraisal wells that we drilled this year, we've already replenished the planned drill wells for this year. So and they're doing it at very low breakeven in terms of adding inventory. So I just wanted to add those 2 things to give recognition to our team and the progress they're making.
Vicki Hollub:
I thought I was going to have to cut them off there for a second but he did good.
Nitin Kumar:
And I was just hoping that you wouldn't, Ricky, but great job, guys.
Operator:
Our next question will come from Neil Mehta with Goldman Sachs.
Neil Mehta:
Yes. It's really helpful update around LCV. I wanted to take you up Vicki, on that offer to talk about construction and how that DAC plant is building towards the mid-2025 start? What are the biggest gating items to get it to completion? And how do you feel about your ability to mitigate those risks?
Vicki Hollub:
Okay. We'll pass that to Ken then.
Kenneth Dillon:
So far, I'd say construction is going very well. While we are performing extremely well in engineering, procurement and construction phase of the project is basically -- we're moving through the [indiscernible] phase where we've got around 550 people at site into the different trades and we'll move up to about 1,200 people at site by the end of Q1. So far, we've had no issues of paying labor on the field in terms of procurement. We're meeting construction needs at the moment, and we've committed around 90% of the material value that we need. So prices are locked in at the moment. So things are going very well.
I think Worley's engineering capabilities are such that we saved quite a bit of money in construction and also, we designed the system so that we can replicate that based on the engineering that we're carrying out today. We're building a digital twin and we're using AI going forward. On supply chain, I'd like to highlight the visionary vendors. We talked about that early on. We're basically working with companies who have aligned CEOs who are truly supportive and that's made a huge difference for us. As you know, over the last couple of years, there's been huge pressure on electrical and instrumentation equipment. I'd like to highlight Siemens Industries in the U.S. have really helped us out. They've really been committed to this project. And what it means Technip Energies are also very supportive all the way to the CEO. And we've received many suggestions from the visionary vendors on how to reduce the cost of their packages going forward right down to very detailed specifications. I don't know if I can give one example, but one vendor that we visited to assembly lines, one for bespoke equipment and one for standard equipment and they do our attention to, we change one thing in our specification, we could save an awful lot of money. The experience is you don't gain any extra reliability for doing that. Safety performance has been exceptional, so. We're now through 1.2 million man-hours. So overall, things are going as well as expected and in terms of materials that are out with the required on-site dates, we don't really have any. So generally working well together with vendors, broadly fabricators, we have built materials of sites. We built piping racks. We did this as a pilot to reduce fabrication, labor at site. That's worked very well. We'll definitely do that on future decks and that takes you into the mode of, can you get the point where you build a dactyere or you can generate piping materials, air contactor frames without doing all the work at site. So overall, project doing well and getting a lot of help from vendors.
Vicki Hollub:
I'd just like to build on what Ken was saying about the visionary vendors. What's been very helpful for us is that as we went through and interviewed the various vendors selected those that we felt like were more visionary. We also found that these more visionary companies also were very committed to making this work because what they realize and what's important to them is to do something that benefits the world. And if you look at the CO2 going into the atmosphere today, it's about 35 gigatons and of that 35 gigatons going into the atmosphere, 8 from stroam and that's 23% comes from transportation and that's what Richard was getting at earlier.
It's really hard to do anything to decarbonize transportation unless it's a sustainable aviation fluids, SAF, like you mentioned, which is not completely emission-free or using our carbon reduction credits. And when you look at 8 gigatons, that means thousands of these Direct Air Capture facilities must be built and no matter what model you look at, that's credible around the globe with respect to climate transition and climate change. There's no model that would show that you can cap global warming to 1.5 or 2 degrees without dealing with getting more CO2 out of the atmosphere, both for transport and just because there's too much in the atmosphere today. So that makes us a necessary technology and one that's important, as I said, for the world. And it's important to distinguish between the CO2 that goes into the atmosphere from power generation. Power generation can be addressed by wind and solar to some degree and ultimately, fully if we can -- if a battery or some sort of industrial battery can be design and build to aid it. But this Direct Air Capture is not a replacement for wind or solar. That's for a totally different type of CO2 emission. So with that, just now Neil, move to your second question?
Neil Mehta:
That was great, Vicki. And the follow-up is just around '24 capital considerations. I won't get it on the fourth quarter call, I recognize, but can you just talk about the range from '23 to '24 and last quarter, you annualized it looks like a $6.4 billion of CapEx. Is it crazy to say that's a good starting point? And any thoughts on that would be great.
Vicki Hollub:
No, it wouldn't be crazy to say that. I'll go back to what Rob said in his script, and that is that our upstream oil and gas, especially in the U.S. will have the same activity level next year that it's had this year. In addition to that, we'll have $100 million for incremental for Battleground in 2024, and we'll run those 2 drillships in the Gulf of Mexico. So I think that gets you to work to that or above as you go in total all of that. And we'll have more guidance on that, hopefully, the first part of next year.
Operator:
Next question will come from Paul Cheng with Scotiabank.
Paul Cheng:
Two questions on -- maybe this is for Richard. Have you seen any meaningful inflation rate in the construction side? And also, does the higher interest rate impact your growth plan and the business model? That's the first question.
Richard Jackson:
Sure. I'm going to start -- I'm assuming the inflation is oil and gas. But if I -- we need to go more broadly we can help with that.
We -- I'd say a few things, and maybe this goes back a little bit to the prior question as well. As we sort of hit the end of this year, a couple of things that we've been doing and seeing success is really optimizing our resources specifically rigs and frac if you'll kind of follow our trajectory over the last 2 quarters, we're down 2 rigs and 2 to 3Q and then down another 2. And that's really allowed us to optimize with our contractors, the right rigs, the right crews and seeing some early returns for that with quite a bit better foot per day in both the Rockies and the Delaware. I think as we hit the kind of the fourth quarter, we're not ready to project anything into next year. But we are seeing some areas of improvement, I'd say, across our rigs, also things like oil country tubular goods, sand, fuel these things are leading to a little bit of softening, which we hope can play forward. But our focus really has been on that optimization on efficiency. So -- maybe I'll stop there and make sure you we answer that question.
Paul Cheng:
Yes. And can we also expand not just on the oil and gas, but also to the low carbon business that are we seeing the inflation rate very different and is actually hitting up that does look like a lot of people is moving in that direction.
And also that the high inflation also want to look at is on the low carbon ventures and how that impact on that business model? And that may as well ask my second question, which is you have signed some deals with financial institute that bind the CDR, can an you share that what kind of term is it offtake and you say fixed price and even it is fixed price, what kind of pricing that we may be referring to right now?
Richard Jackson:
Great. I'm going to -- I think the way we'll do this, maybe you can start a little bit on inflation as it relates to DAC and then certainly, I want to have Mike talk about the market and what we're seeing with offtake. I think that's an important part of our message.
Kenneth Dillon:
It's Ken. Yes, we did see increases in the STRATOS cost estimate, mainly related to general industry inflation, so not specifically because of the back but we also increased cost as a result of incorporating learnings from the CEIC. And I would say it was probably 50-50 in terms of impact of moderate inflation on DAC and it's just general industry inflation, steel prices, materials, et cetera.
We're now at the point of the project where we basically locked in pricing. So we feel pretty good and the optimizations were designed to give us improved efficiency for the DAC long term, included heat recovery systems, solid handling upgrades, filtration systems upgrades and electrical upgrades also. so a number of things of not only inflation, I would say, and not -- definitely not specific to DAC.
Michael Avery:
Paul, this is Mike Avery here. So I'll give an update on the sales process and progress that we've made for STRATOS. And so what we're getting here is a lot of momentum building in the market with a strong sort of pipeline of buyers that are growing now.
We attribute this to the market beginning to realize the importance of how Direct Air Capture is going to fit within their portfolios. I think there's also a growing recognition that Direct Air Capture is not sitting out in the future. It's a technology that's ready to go now at commercial scale. And that is actually more affordable than people think when placed next to some of the other alternatives out there. I think the market has also been moving towards these higher integrity solutions as the carbon markets have been maturing. And so to date, we've announced deals with Airbus, Amazon, ANA, TD Bank, NextGen, the Houston Astros and the Texans. There's a range of terms on the CDR sales. They range from 1 year to 10 years. They are fixed price agreements. And so if we look at the deals that we've announced to date, and we couple that together with the mature negotiations where we have got price volume and term agreed, STRATOS net capacity is sold out to about 65% to 70% to 2030. And then there's a strong pipeline behind that of earlier stage negotiations that's also growing that takes us up to about 85% net capacity sold out to 2030.
Operator:
Our next question will come from Doug Leggate with Bank of America.
Douglas Leggate:
Vicki, I wonder if I could ask you about the business plan or the strategy for that going forward. Clearly, you've given up some working interest now, which I think you'd signaled before. But I think -- I don't want to misquote Richard here, but I think you said our first partner in STRATOS, where do you see your working interest? How do you see it in DAC 2? And where does license revenue fit into the capital efficiency of the DAC strategy? And I've got a follow-up, please.
Vicki Hollub:
Well, we have a lot of confidence in this technology and a lot of confidence that it fits very well with our strategy on a go-forward basis. Not only are we going to benefit from the sale of carbon reduction credits as a part of this technology and our strategy. Ultimately, we also -- while we're continuing to provide sequestration and sailing reservoirs for our customers. We also want to provide CO2 as a product to customers to convert to sustainable aviation fluids. So that's another part of the revenue -- potential revenue stream.
And the other thing that we want to do with the CO2 that we extract out of the air is used it in our enhanced oil recovery reservoirs because that's the truest form of emission-free on a net basis oil that can then deliver the fuels that maritime and aviation need. Sustainable aviation fluids, as Richard said, is a necessary thing that we have to develop, the world needs it, and we're going to support developing it by providing products and then potentially doing it through one of our investments that we've made. So that's important. But it's really the thing that's going to change the whole cost curve or the climate transition is for people to ultimately understand that you can use CO2 to generate net zero oil. The way that happens is you inject more CO2 into the reservoir than the incremental oil created or produced by that CO2 will limit when use. That's critically important because that generates a net zero oil that then can be converted to jet fuel and maritime fuels. The thing that's so important about that is not only is it emission negative or on a net basis or emission equal. What it does is that of itself is a lower impact also on the supply chain perspective because you're getting more oil out of reservoirs that exist today. So you're using existing infrastructure, which also reduces the emissions that are associated with the upstream part of the supply chain. Then the other part of that is that -- and using existing infrastructure, that's a lower cost. So that's -- it's what the world needs to use the highest intensity fuel at the lowest cost and the lowest emission level is the way that the world ultimately will need to solve this climate transition. Otherwise, the world cannot afford to cap global warming at 1.5 or 2 degrees. So this is very much needed. So when you look at all of those options, we can -- the revenue streams that we will be bringing into our business will come from all of those options. So having partners in the beginning is critically important for us to move further down the road faster to get this technology to a point where we are comfortable that not only we could build it, but we could license the building to others as well. And once we get to that point, then we're these -- instead of expecting to build 100 of these then we can start to get into the hundreds of them and potentially the thousands that are going to be needed to be built. But we would benefit from all of that. And it's -- sometimes we get criticized for the fact that we're building a business. But without making this commercial, it's not sustainable. And if it's not sustainable, then the world has no other better solution. And again, the world cannot afford the plans as they've been laid out by the UN and others right now. And so we think we have the best solution to move forward, the best kind of business model to make it happen and it will create significant value for our shareholders. We're just going to build the partnerships to make this happen at a pace that's much faster than what we could do just ourselves.
Douglas Leggate:
Yes. Vicki, just to clarify, so these obviously very ambitious growth plans going forward. It doesn't require that it's Oxy capital, I guess, was my point. Am I right in thinking that outsourcing the capital once the technology is proven has potential to be a revenue stream as a -- like a license revenue. That's what I was really getting at?
Vicki Hollub:
Yes. That's incredibly important to us. There's absolutely no way that we would have the capability to provide all of the capital. We can't do it. We're going to continue to be an oil and gas business because oil and gas is also important for the world. We'll continue our investments in oil and gas and grow our oil over time because our oil will be carbon neutral or carbon negative ultimately. And so that's to me the last barrel of oil produced in the world should come from an enhanced oil recovery reservoir using CO2 from the atmosphere. So we will be doing that.
But you're right, Doug, in that we will be licensing a lot of this out. And we've talked about regional concepts, having partners around the world that can manage and drive their own construction of these facilities as we go. And what would come back to us would be those licensing fees.
Operator:
Our next question will come from Neal Dingmann with Truist Securities.
Neal Dingmann:
My first question is on your Permian plan, specifically. Just wondering, will you all turn to more co-development in the Dell or maybe just discuss your future broader completion plans there?
Vicki Hollub:
[indiscernible]?
Richard Jackson:
Yes. I'd answer that a couple of ways, I think. I think one that's been really important to us, and we've tried to highlight is again back to some of the secondary benches in the way we think about those developments. We've been pretty precise in terms of how we put together our DSUs with those in mind. I would say this year, we have increased our -- I'll generalize completion intensity, but it's really frac intensity. And some of that was some of the capital that we put back into the Permian that delivered increasing cash flow for us this year. So I'd say a good portion of that capital increase was due to our increased completion intensity.
So as we think about playing it forward, I think over the next several years, we're going to continue to be methodical in the way we develop those secondary benches. They'll ultimately become a bigger part of our portfolio. But we've seen with these positive surprises, the ability to optimize really the next kind of 3- to 5-year type programs some of the success, I would say, even in the Midland Basin that we've seen in the secondary benches, as we looked into this year, I think we changed about half of our development plan due to improvements in our appraisal activity there last year. So I think we'll continue to do what we do, which is really focused on the subsurface. We want to make through our recovery is outstanding, and we want to really DSU across multiple benches to be fit for purpose for the geology for that area.
Neal Dingmann:
And then second also on the Permian. The second largest earthquake in the Perm was reported this morning. I'm just wonder is probably too early to know if you had any direct impact? I'm just wondering, could you all discuss the continued disposal process and if that has changed in recent years?
Vicki Hollub:
I'm sorry, Neal, I didn't get that -- the first part of that question.
Neal Dingmann:
This morning, there was announced the second largest earthquake. Hit the -- it looks like it hit the...
Vicki Hollub:
Earthquake.
Neal Dingmann:
And I'm just wondering -- I'm not asking for the impact too early there, but just wondering maybe if you could discuss -- I know you had changed some disposal process and things in the past. If you could maybe just hit that quickly.
Richard Jackson:
Yes. Our plans continue to leverage really the work we've done around water recycling, just in general, I'd say, independent of any of the hazards. We just believe that responsible use of water is a big part of what we should do. we actually had a trip here recently to the Permian, got to revisit the large recycling facility that we put together with our partner there in the Midland Basin.
And that continues to be helpful not only for Oxy but actually some of our offset peers. So we're expanding that into the Delaware. It's actually a very nice link as you think about other carbon capture projects that we have. Responsible use of industrial water is a technology that we really think is important for the future. So aware of some of what -- you're asking about in some of the hazards that's been identified. But again, we're trying to get out in front of that just in general and recycle more water in all areas of our operations.
Operator:
Our next question will come from Matt Portillo with TPH.
Matthew Portillo:
I wanted to start out on the Gulf of Mexico. You mentioned you'll be running 2 drillships there next year. Just curious if you could just give an idea of key projects you're progressing in 2024? And maybe expand a little bit on the depth of the tie-in opportunities and potential, I think, Vicki, you commented last quarter for possible growth out of the asset in the second half of the decade.
Vicki Hollub:
Yes. I would just reiterate, we're really excited about not just what we're doing from a capital perspective and the new development, but also what we're doing with the development that we have and Ken has some really good things to share with you about that.
Kenneth Dillon:
If I start off with the first part of your question, as part of the development initiatives, we plan to drill and complete 5 wells includes proximity to our facilities tied back to existing subsea manifolds with available capacity. We also do test on 2 promising exploration opportunities in the Eastern [indiscernible] probably have a working interest of around 40%, that aligns to our sort of approach of more shots on goal through partnering.
If I can maybe give some context to Vicki's comments on the last call, we basically see gone through 3 portfolio lenses. One is primary production with base optimization and drilling, including horizontals and stimulation; second aspect is secondary recovery, which is one of Oxy's strengths as a company worldwide with water flooding and artificial lift, including subsea pumping and ESPs. On these assets, very little has been done on water flooding in the past for our reservoirs, and we see significant upside including reservoirs that already have direct analogs nearby. And that's been part of the success of some of the majors in Gulf of Mexico in terms of adding long-term low decline production and reserves to the base. And an exploration, we've now built a new portfolio with a significant new partner base, as you saw in the recent announcement that came from [indiscernible] that looks like a successful approach going forward, and that could be easily tied back quickly to Lucius. So we see this as a way of moving capital between these 3 legs of the stool going forward and we see tremendous upside on the secondary recovery option.
Operator:
And that concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Thank you all for your questions and for joining our call today. Very much appreciate it. Have a great day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to Occidental's Second Quarter 2023 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.
I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.
Neil Backhouse:
Thank you, Drew. Good afternoon, everyone, and thank you for participating in Occidental's Second Quarter 2023 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Neil, and good afternoon, everyone. There are 3 things I'd like to drive home today. First, our portfolio of assets continue to set the table for record results. Second, our teams outperformed last quarter's and last year's excellent operational metrics. And I want to make sure our investors see how that flows to the bottom line. Third, our strategic and operational improvements continue to support our ability to take actions to drive even better shareholder returns.
I'll begin with the portfolio. We had the highest quality and most complementary assets that Oxy's ever had. They are a unique blend of short-cycle, high-return shale assets in the Permian and the Rockies along with lower decline, solid return conventional reservoirs in the Permian, GoM and our international assets. 60% of our oil and gas production is from shale reservoirs and 40% from conventional. More than 80% of our production is in the United States. The international oil and gas assets that we operate are in only 3 countries, Oman, Abu Dhabi and Algeria. Our worldwide full year 2023 production mix is expected to be approximately 53% oil, 22% NGLs and 25% gas and 70% of the gas is in the United States. Our conventional oil and gas assets, along with OxyChem provides support during low price cycles while the shale assets provide the opportunity for growth during moderate and high price cycles, and the flexibility to adjust activity levels quickly if needed. This combination of assets has generated record cash flows for Oxy over the last couple of years versus the cash flow generated by the portfolio that we previously had in a similar price environment from 2011 to 2014. The midstream business provides flow assurance and has done so with exceptional performance during catastrophes and emergencies. The low carbon ventures business will help Oxy and others decarbonize at scale in a way that provides incremental value to our shareholders. To summarize, we have a deep and diverse portfolio, providing the cash flow resilience and sustainability necessary to support our shareholder return framework throughout the commodity cycles. Let's shift now to operational excellence. Strong second quarter operational performance exceeded the midpoint of our production guidance by 42,000 BOE per day, enabling us to again raise full year production guidance. In the Rockies, outperformance was driven by improved base production and new well performance, along with higher-than-expected nonoperated volumes and the receipt of accumulated royalties. Our Rockies teams drilled 32% faster on a foot per day basis than they did in the first quarter. The team's diligent work set several new Oxy records, including company-wide record of drilling over 10,400 feet of lateral in only 24 hours. Just 10 years ago, it took the industry an average of 15 days to drill 10,400 feet. Our Permian production delivered higher operability and better-than-expected new well performance, particularly in our 2 new drilling space units in New Mexico, top spot and precious. Our Delaware completions team shattered Oxy's previous record for continuous frac pumping time by nearly 12 hours for a total of 40 hours and 49 minutes. Four years ago, the same job would have taken about 84 hours. 40 hours back then was unthinkable, but our teams have made this a reality. We expect that the efficiencies generated by advancements in drilling and completions pumping will result in lower cost and reduce time to market. Offshore in the Gulf of Mexico, we safely completed seasonal maintenance activities focused on asset integrity and longevity. Excluding the impact of this planned maintenance, we delivered higher base production and benefited from improved uptime performance across multiple platforms. Internationally, our teams continued to deliver strong results. The Al Hosn expansion came online 2 months earlier than planned, as a result of great teamwork with our partner, ADNOC. This means that together, we have now successfully expanded the plan in stages from 1 Bcf a day to 1.45 Bcf a day or a very small incremental capital investment. In Oman Block 65, we drilled a near-field exploration well, which delivered 6,000 BOE per day and a 24-hour initial production test, and it is now on production to sales in less than a month from completion. This was our highest Oman initial production test in the decade, and we continue to show the benefits of our subsurface characterization techniques worldwide. We were awarded the block in 2019 and in collaboration with the Ministry of Energy, we are positive about opportunities in the country where we are the largest independent producer. OxyChem also outperformed during the second quarter due to greater-than-expected resilience in the price of caustic soda and reductions in feedstock prices. OxyChem is one of our valuable differentiators. It provides rich diversification to our high-quality asset portfolio by consistently generating quarterly free cash flow which provides a balance of our oil and gas business throughout the commodity cycle. Now I'd like to talk about how our focus on operational excellence is enhancing our portfolio and extending our sustainability to maximize near- and long-term shareholder returns. Oxy's wells are getting stronger and are supported by our deep inventory, which continues to get better. In the Permian, we have improved well productivity in 7 of the last 8 years. And with the application of our proprietary subsurface modeling, we're starting to see the same results in the DJ Basin, where improved well designs have delivered reserves at roughly 20% less cost. The improved well design has resulted in about 25% improvement in single well 12-month cumulative volumes over the last 5 years. And we are on pace to significantly exceed that rate in 2023. In addition, our teams are continuing to advance our modeling expertise, which has led to upgrades of secondary benches to top-tier performers. This was the key for our -- sorry, 212% U.S. organic reserves replacement ratio last year. Let me try to make that point again. Last year, because of these upgrades to our secondary benches to our top-tier benches, we were actually able to replace our production by 212% with reserve adds. Secondary bench upgrades are progressing in 2023. Overall, in 10 of the last 12 years, we have replaced 150% to 230% of our annual production. The only exceptions being in 2015 with a price downturn in 2020 with a pandemic. Converting lower-tier benches to top tier will further extend our ability to achieve high production replacement ratios. Not only are we adding more reserves than we are producing each year, we're adding the reserves at a finding and development cost that is lower than our current DD&A rate, which will drive DD&A down and earnings up. Our differentiated portfolio and the strong results delivered by our teams provided support for execution of our 2023 shareholder return framework. During the second quarter, we generated significant free cash flow, repurchased $425 million of common shares and have now completed approximately 40% of our $3 billion share repurchase program. Common share repurchases, along with our dividend enabled additional redemptions of the preferred equity. To date, we've redeemed approximately $1.2 billion of preferred equity. I'll now turn the call over to Rob.
Robert Peterson:
Thank you, Vicki, and good afternoon, everyone. During the second quarter, we posted an adjusted profit of $0.68 per diluted share on a reported profit of $0.63 per diluted share. Difference between our adjusted and reported profit was primarily driven by impairments for undeveloped noncore acreage and deferred tax impacts from the Algeria production sharing contract or PSC renewal, partially offset by an environmental remediation settlement.
In the second quarter, strong operational execution enables over $1 billion of free cash flow for working capital despite planned maintenance activities across several of our oil and gas businesses. Following nearly $1 billion of preferred equity redemptions and premiums, $445 million of settled common share repurchases and approximately $350 million related to LCVs investment in net power, we concluded the second quarter with approximately $500 million of unrestricted cash. We experienced a positive working capital change during the second quarter primarily driven by reductions in commodity prices and fewer barrels in shipment over quarter-end. Interest payments on debt are generally paid semiannually in the first and third quarters, which also contributes to a positive second quarter working capital change. During the second quarter, we made our first U.S. federal cash tax payment this year of $210 million and state taxes of $64 million, which were netted out of working capital. We anticipate a similar federal cash taxes we made in subsequent quarters this year, those state taxes are paid annually. Our second quarter effective tax rate increased from the prior quarter due to a modest change in our income jurisdictional mix. The proportion of international income, which is subject to a higher statutory tax rate grew during the second quarter. We are therefore guiding to a minimum adjusted effective tax rate of 31% for the third quarter as we expect our effective tax rate going forward will be more closely aligned with the second quarter rate. I will now turn to our third quarter and full year guidance. As Vicki just discussed, our technical and operational excellence continues to drive outperformance across our oil and gas businesses. This enables us to raise our full year production guidance midpoint to just over 1.2 million BOE per day in anticipation of a strong exit to the year. Rockies outperformance serves the largest catalyst to our full year production guidance raised and is also a primary driver of the slight change to our full year oil mix guidance. Reported production in Rockies is expected to reduce to its lowest point this year in the third quarter before beginning to grow in the fourth quarter. In the Gulf of Mexico, we were guiding slightly lower production in the third quarter compared to the second quarter due to a contingency for seasonal weather. The third quarter weather contingency as well as planned maintenance opportunities brought forward to reduce overall downtime are expected to result in our highest domestic operating costs on a BOE basis this year when normalizing to less than $9.50 per BOE in the fourth quarter. Internationally, we expect higher production compared to the first half of 2023 due to plant turnaround and expansion project timing ? Al Hosn as well as impacts from various international production sharing contracts. As we have previously mentioned, the increased international production will be slightly offset by the new Algeria PSC, which decreased reported production, but the reduction in imported barrels is not expected to have a material impact on operating cash flow. Overall, the first half of 2023 was characterized by strong production in Gulf of Mexico, Permian and Rockies, with latter 2 businesses also benefiting from nonrecurring production events. We have better anticipated wells and time-to-market momentum year-to-date, which we expect it to be benefiting from in the second half of the year, the third quarter will be the only quarter in the year where production average is below 1.2 million BOE per day. Reduced production is mainly driven by the previously mentioned weather contingency implies to the Gulf of Mexico. The decrease in third quarter production will likely result in total company production and is lower in the second half of the year when compared to the first. However, the change in expected production does not represent a shift in our volume trajectory. We anticipate fourth quarter production will be similar to the first 2 quarters of 2023, and we expect to enter 2024 with a strong production cadence. Furthermore, our full year guidance implies our fourth quarter output of approximately 53%, largely due to improved GoM production [Indiscernible] weather contingency. Shifting now to OxyChem. As anticipated in original guidance, we continue to see weakening in the PVC and caustic soda pricing during the second quarter. However, our full year guidance remains unchanged at a pretax income midpoint of $1.5 billion which will represent our third highest pretax income ever in another strong year for OxyChem. We also expect our chemicals business to return to a more normalized seasonality compared to recent years, meaning that the fourth quarter will represent the lowest earnings for the year. As we have mentioned on previous calls, the fourth quarter is typically not a reliable roll forward for the year ahead through the inherent seasonality in the business. We revised our full year guidance from midstream and marketing due to expected market changes over the second half of this year. The margins generated by shipping crude from Midland to the U.S. Gulf Coast are expected to compress further following the annual FERC tariff revision, which has increased our pipe cost approximately $2.55 a barrel. Over the same period, the price we market long-haul capacity is expected to decrease. Additionally, we anticipate fewer gas market opportunities as spreads across multiple basins have continued to narrow and find opportunities generated in the first quarter. Also, pricing for sulfur produced at Al Hosn is expected to soften in the second half of the year. Capital spending during the quarter was approximately $1.6 billion. We expect capital to decrease slightly in the third quarter with a more pronounced reduction in the fourth quarter. The expected decrease was primarily driven by reduced working interest and gross activity in the Permian, which is in alignment with our original business plan. We anticipate receiving $350 million during the fourth quarter associated with the second quarter [Indiscernible] settlement. While this settlement will drive our -- report it overhead down, our full year guidance to overhead expense on an adjusted basis remains unchanged. Turning now to shareholder returns. As Vicki mentioned, we further advanced our shareholder return framework during the second quarter through the repurchase of $425 million of common shares, which enabled additional preferred equity redemptions. After a strong start in the first quarter, we triggered the redemption of over $520 million of preferred equity in the second quarter. Year-to-date, we've been approximately $1.2 billion or 12% of preferred equity that was outstanding at the beginning of the year with 10% premium payments to the preferred equity holder of approximately $117 million. Preferred equity redemptions to date have resulted in elimination of over $93 million of annual preferred dividends. As of August 2, rolling 12-month common shareholder distributions totaled $4.08 per share. Due primarily to the concentration of share repurchase in the third quarter of 2022, coupled with the current commodity price curve, it is likely that the cumulative distributions will fall below the $4 per common share during the third quarter. If we drop below the $4 redemption trigger, our ability to begin redeeming the preferred equity, again, will heavily be influenced by commodity prices. The EPI prices would likely need to be higher than what the forward curve presently indicates for us to remain above the trigger for the remainder of 2023. Even if we aren't able to continue redeeming the preferred equity for a period of time, we remain committed to our shareholder term program, including our $3 billion share purchase program. Our basic common share count is at the lowest since the third quarter of 2019, resulting in per share earnings and cash flow accretion to our common shareholders. Sustained efforts to significantly deleverage over the past several years have improved our credit profile, culminating a return to investment-grade status when the Fitch ratings upgraded Oxy in May. We believe that our investment grade credit range reflect our exceptional operations, diversify the high-quality asset portfolio and our commitment to pay down debt as it matures. Our second quarter results and our full year guidance demonstrates solid progression towards another strong year for Oxy. We look forward to reporting on additional progress as the year advances. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. Before closing today, we'd like to briefly mention 2 low carbon ventures announcements that we made this week. We were glad to announce that Japan's ANA Airlines became the first airline in the world to sign a carbon dioxide removal credit purchase agreement from our subsidiary, 1.5. We're excited about that and happy to work with them. We're also pleased to announce a first-of-its-kind agreement with our long-standing partners, ADNOC, to evaluate investment opportunities in direct air capture and carbon dioxide sequestration hubs in the U.S. and the UAE. With this agreement, we intend to develop a carbon management platform that will accelerate our shared net zero goals. We have many exciting developments taking place in LCV, and we look forward to providing you a more comprehensive update towards the end of this year.
With that, we will now open the call for questions.
Operator:
[Operator Instructions] The first question comes from Doug Leggate with Bank of America.
Douglas Leggate:
Vicki, I wonder if I could focus on productivity which your latest slide deck is showing -- you refer to it as the wedge wells with a quite frankly, stunning step-up in performance relative to prior years. My question, I guess, is the repeatability of that and the impact on how you think about your strategy? Because to summarize, you've suggested you would not seek to grow production meaningfully, if I'm interpreting that correctly. But this productivity would suggest that either you're going to grow production as you did with your step-up in guidance or you're going to cut your capital budget to hold the production at a flatter level. So I'm curious, are you prepared to take the production? Or is it going to get more capital efficient with lower CapEx?
Vicki Hollub:
Well, we intend to keep our capital plan as we had it or at least the activity plan as we had it. I can tell you, Doug, I'm incredibly impressed with what our teams have done. I've been in this industry for a very long time, and I've seen a lot of extensive work done to model conventional reservoirs over the years. And when we started our shale development, some thought it was more of a statistical play where you just go drill a 100 wells and maybe 25% of them would be really good, and 75% would be okay. But we took the time in 2014 to step back and say that we were going to put together a team that could do the kind of work that needs to be done in shale. It's much more complex than conventional. So we really focused on trying to make sure that we put together a team that could do the most sophisticated work on the subsurface possible, and they've done incredibly well.
And I would say, in the past 2 to 3 years, I was thinking that we were getting close to plateauing on our learnings and what we can do. But the teams continue to surprise me, continue to go beyond what I thought we would ever be able to do in this industry with respect to not only understanding the subsurface as well as we do, but also being able to understand how to get the most oil out of it. And -- so where we are today is, I've now asked the teams to stop talking about it. We for years, we're sharing things that we were doing, and we've shared some things on the slides in the slide deck, but they had prepared a lot more to share with you today, to highlight and map out the pathway that we're using to get to where we are. But it's just too important to our company, it's -- and to our shareholders to keep that proprietary because this is something that's pretty phenomenal, I think. And now we're taking this, and we're going to apply it to the Permian -- I mean to the Powder River Basin. We're using it. They've done incredibly well in the Permian. We've also taken learnings from the team in the DJ and moved those through the Permian. So we're sharing ideas across business units. The next one will be the Powder River basin, where while we did take an impairment on some noncore areas, we are excited about the Powder River. And I think Richard will say a little bit more about that later. But the Southern Powder River is, we're seeing good results there. And our appraisal team is beginning to work in the northern part of the Powder River. And we're going to take it also the same sort of concept about how to do it, we want to take to other areas within Oxy. And we think that by using a similar methodology with what our phenomenal team in the Gulf of Mexico has been able to do, they've done amazing things in terms of being able to see below-the-salt and to improve our success rate there. But I think you put this subsurface team for our shale development, but the approach they take, the methodology that they use with the ideas that our GoM team has generated and start really exploring the various strengths, I think we take this and apply it to conventional reservoirs and applying this to conventional with the expertise that we have working those conventional reservoirs today, I think that there would be even more cross flow of learnings from conventional to shale and shale and conventional. I think it's beyond what anybody in the industry that I've seen or heard about it is doing today. So with that said, to get back to your question on capital and production, we're going to execute our program, looks like it is going to result in a production increase, and we're happy with that. We never said that we didn't want to grow. We just don't want growth to be the target. But the target is value creation. And that value creation comes from doing the developments when we're ready to do them at the pace that generates the most net present value. And our teams are doing that, and they're doing it incredibly well. So we'll take what we're getting here.
Douglas Leggate:
I've got a very quick follow-up, and it's kind of hard that -- something we've talked about before, which is the legacy Anadarko portfolio. We know it dips in the second and perhaps the third quarter. My question is, when you rebound out of the fourth quarter as is ordinarily the case in that profile, have you lost any production capacity? Do you -- what do you think the production capacity is today? And presumably, those are the highest margin assets in your portfolio. I just wonder if you could confirm that so we can anticipate what happens to earnings and cash flow in Q4?
Vicki Hollub:
Yes. The legacy Anadarko assets in the Texas, Delaware are really, really top tier. We had -- when we were working to do the acquisition, we knew that they were really good. We thought they would come in and be almost equal to our Southeast New Mexico, and I'm going to get myself in trouble here. I think they were, I thought, for a while better than Southeast New Mexico. I think I happen to say that in the hallway one day, and the Southeast New Mexico team decided they would prove me wrong on that. So I would say that Southeast New Mexico and Texas Delaware are both incredibly important to us. They are very high quality, and they're both a part of our program going forward. Richard, you had something to add?
Richard Jackson:
Yes. Maybe just to help add on to that when we talk about assets in the portfolio and even legacy Anadarko. I think the Rockies trajectory, while very strong in the first half of the year, I think what's impressive, we talked about knowing we would decline kind of through the first half of the year and then grow. And I think if you see our guide for 3Q and then implied guide for 4Q, that not only was the first half better, but the second half was better as well. And while the new wells are certainly core, how do we think about deploying capital and creating the efficiency, I'd like to also recognize all the team that works on our base production.
I think the Rockies is a great example of being able to rethink our surface infrastructure, they've been able to kind of lead the industry, I think, in some of these tankless designs, but they've migrated to more efficient bulk and test. They've been able to think about artificial lift earlier, things like gas lift earlier in the cycle of the well. And a lot of that beyond creating the most EUR per dollar spent is really helping our production. And so when you look year-on-year, that base production is another one that I think we're really proud of from the teams.
Vicki Hollub:
No doubt, it's the Permian and the Rockies and the Rockies actually applying artificial intelligence to their pumps up there, which has been very, very impressive as well as the management of the gas lift in the Permian, Texas and New Mexico. So these are exciting things for us, and we're -- we have to definitely gets kudos to the teams. They've gone above and beyond expectations.
Operator:
The next question comes from Neil Mehta with Goldman Sachs.
Neil Mehta:
Yes. [Indiscernible] to start off on the return of capital. Just curious on your thoughts on the commodity price level or the oil price level at which you believe you can get back to taking out the preferred. And just in the absence of that, how aggressive can you be around buying back stock?
Vicki Hollub:
Well, certainly, we have the capability at almost any price environment. There's a lower limit to where we would probably not do much share repurchases at $60. But at $70, we could continue a common share purchase program. And certainly, at $75 and above, we've got the cash to do both. But what we feel like with our current shareholder framework is that share repurchases are a big part of that because our -- in common share repurchases because what we're really trying to do is we're trying to create value per share for our investors. And to create value per share, it not only means that we need to grow production a bit. Again, that's with the cash flow is the main thing we're trying to grow when we're growing production, and that's an outcome of our capital program.
So this year, we will get incremental earnings growth from our incremental volumes, but also developing our reserves at the lower cost, like we've talked about and like I talked about in the script and like we've been talking about here, what the teams are doing that's so important is to develop reserves, replace our production every year by at least 130% to [150%] And again, we've seen years up to 230%, where the DD&A or the funding and development cost is $6 or less in some cases. And we were able to do that with the DD&A rate of what we have today versus that, that's creating value for our shareholders, creating earnings. And then the last thing is to couple with the cash flow growth and income growth from the volume creation and the reduced cost of those binding and development reserves is to buy back shares. And especially given the fact that we feel we're very undervalued right now. So share repurchases, whether or not it triggers the preferred is really important to us. But in the near term, what we'll do is we will probably wait a little period of time here to watch what's going to happen with the macro. And if the macro plays out the way we expect, we should be able to do both to buy common and to get back at some point within the next few months to doing both buying not only common, but triggering the preferred, it could take into next year before we're able to get a program going. But we do believe that we can at $75 or above, have a program that will do that.
Robert Peterson:
I'll just add that part of the challenge that we have is that our program last year was very back-end weighted. We did $2.4 billion of share repurchases concentrated across the second half of the year of $1.8 billion of that just in the third quarter alone. And so it's the pace at which we were able to retire shares last year, matched up against the commodity prices that we have this year, that's really making it difficult to stay with the 4 consistently. So if you look back to last year, gas pricing, we realized over $7 in Q3, oil prices were over $95 realized in Q3. And so that's the big change year-over-year that we're seeing.
Neil Mehta:
And then the follow-up is congrats on getting the Al Hosn gas expansion on this year. Just would love any perspective or thoughts on your Middle East business and how we should think about the incremental cash flow associated with the asset that just came online?
Vicki Hollub:
The Al Hosn project getting to the 1.45 Bcf a day had very little capital, is definitely a good project for us. And with -- just having gotten that back on, we expect that the certainly, the production looking good towards the rest of this year from Al Hosn and also the fact that we were in Oman, able to get an exploration well that was record setting for us online and to production in less than a month was another good sign for healthy production coming out of the Middle East. We do have incremental opportunities in Oman for additional wells that are similar to that in Block 65. So -- and this year, this past year, in Safah field on the north Oman.
We've set the production records there, and that's a field that's been in operation for over 40 years. So we're still finding new things to do there. And also, when I talk about innovation and subsurface modeling and with -- and Richard brought up the guys that are working really hard base maintenance, on base production. I want to mention, too, that there's been quite a bit of innovation coming out of Oman as well, one being a process called Oxy jetting, where we go into -- you can do it in new wells or existing wells to go in and jet through the formation and with proprietary process we use there and get incremental production, and that's part of the reason that we were able to achieve record production from that area this year. So a lot of good things happening in our Middle East operations, and we're as I mentioned in my script, focused on 3 countries, and we feel like it is best not to be spread over a lot of countries, but to -- we like the fact that we are here in the U.S. and 3 countries internationally, and we'll focus on being the best we could be in those areas and eliminate or minimize distractions from anything else.
Operator:
The next question comes from Neal Dingmann with Truist.
Neal Dingmann:
My question is on the Gulf of Mexico. Your production and incremental operations at GoM continue to look quite solid. I was just wondering how would you classify just current opportunities today in the Gulf? And could we see any notable change in activity there in the coming quarters?
Vicki Hollub:
I would say that I have -- my thoughts about the Gulf of Mexico have actually changed a bit over the past year. Originally, when we made the acquisition, our plan was just to keep production flat and use the cash flow to invest elsewhere. I do believe now, again, based on the technical excellence of our teams working at and the fact that artificial intelligence, I believe, is going to be -- advanced data analytics, I believe, is going to be a game changer for the Gulf of Mexico. And I believe our team has the capability and expertise to optimize the use of those tools. So I think that not this year or next year, but I do believe that looking forward in the next 3 to 5 years, the Gulf of Mexico could become more of a growth area for us rather than just a cash generator.
Neal Dingmann:
I agree. I like the opportunities there. And then secondly, just -- you talked around this already, but maybe just a little more detail on your slide now on the DJ, maybe about just well spacing and completion design there. I'm just wondering, have your thoughts -- you guys have been ramping that up. And I'm just wondering, as you have been ramping up, have the thoughts on space or completion design has changed going forward? I think like in recent months, I believe gas and other pads are, what about 12-well spacing. So I'm just wondering if there's any thoughts to change any of that?
Richard Jackson:
Yes. Great. This is Richard. I'll try to take a few pieces of that. I mean very excited about the DJ, like I described, but the new well performance in the base. But I would say consistent with really what we've done across our reservoir positions and especially in the unconventional. It really starts with the challenge on the subsurface in terms of all the things you described, spacing, how many wells per DSU. And I think the teams continue to look at those opportunities. And as we noted, really thinking about less, I think moving from 18 to 8 to 12 wells per section allows us to deliver the same EUR for less cost. And I think just like we've done in the Permian, that's the right recipe. We have been able to use completions and really frac intensity to kind of turn up the lever to help capture those reserves without having to drill additional wells.
So we've gone up to 1,500 pounds per foot, which is up about 30%, I think from our prior designs. As we think about spacing and inventory, the thing I would say is not every drill spacing unit is the same. So the geology changes, the development sequencing changes. And so there'll be areas where that may be different. I think just to kind of contrast a little bit, we highlighted the performing DSUs in the Delaware Basin, those are actually opportunities where we added wells per section. And we were able to do that again by looking at the unique kind of attributes of that drill spacing unit against the reservoir. And we're cautious with that, but we've been able to have real success, both horizontally and vertically adding those wells where it's warranted. But just the last maybe a couple of points in the DJ, again. It's sort of a holistic design that the operation's team's put together. They have done a lot to reduce time to peak production. So eliminating those surface constraints where they can really allow those wells to optimally flow. And then as Vicki described, longer term, these wells go from gas lift to plunger lift and being able to use analytics to not only be quicker in terms of our optimization, but actually predict failure mechanism so that we can deploy operations teams quicker. These are the type of things that just really excite us about how our teams approach really adding production at the right cost.
Operator:
The next question comes from Michael Scialla with Stephens.
Michael Scialla:
You talked pretty extensively about the improving well productivity, and I know a lot of companies have been talking about service costs softening here. Looks like 2024 consensus estimates right now, anticipate you're going to spend about 4% more next year than you did this year to keep production flat with the current level. So I know it's too early to give guidance for '24, but just want to get your view on that outlook.
Vicki Hollub:
What we're seeing is we're seeing some things start to plateau in terms of cost. We're seeing labor being still a bit tight. But there's also around labor though, we're not seeing as many people wanting to change jobs. It's just a matter of getting the skills that we need in the field, and that's where the big challenge is, to get truckers to drive trucks, and people to do the welding and those kinds of field jobs are so important to us. But I would think that what -- we're not -- while we're not seeing any reduction -- much reduction in service company costs, we don't expect that. But I don't think we've settled on expecting any kind of increase next year.
Richard Jackson:
And I can add maybe just a few. I agree with Vicki. I mean, we're, one, really pleased with the efficiency of our operations. That's always our focus. And so really, the rigs we've added over the last 1.5 years, we've highlighted some of the kind of individual goals, but we're seeing productivity just from reducing nonproductive time, improved kind of efficiency of the operations continue. But as we think about going into next year, OCTG, seeing some relief, but that generally lags, sand kind of similar, and fuel, obviously is a component, which has been lower for us. So we're seeing those types of things come in a little bit lower. But we've got really, the opportunity to continue to work with the fleet we have.
We're a pretty steady operational pace at this point, which is very different to where we've been in the last couple of years. And so for us, it's really an opportunity to kind of utilize the resources we have and really get that optimization down. So if we look next year, that's going to continue to be the challenge. We hope there's some pricing that can benefit both operator and service company as we look at longer term, but we're really anxious to keep working on the efficiency.
Neil Backhouse:
And Michael, this is Neil. I just wanted to add. We'll always encourage our coverage group not to rely too much on consensus for whatever time period. As you know, the further out it goes, the more sale data that can be in there. So just continue to have the conversations with us, and we'll guide at the appropriate time.
Michael Scialla:
Got you. I guess just summing all that up, though, I guess based on those numbers that would suggest you'd need to spend more to keep production flat. Is it fair to say that feels conservative based on what you know today?
Vicki Hollub:
I would say we don't know that because we're continuing to get more barrels. I mean just look at the graphs where our teams are getting more production from the wells for either the same or lower cost. We're doing both. We're increasing efficiencies of execution while also getting more recovery out of the wells. So I don't think I'd be prepared to say that we'd have to spend more capital just to stay flat. We'll look at that. And again, the efficiencies that are being gained, I think we have to take all that into account. And we'll -- we're starting to look at some of that now, but I'm a bit impressed with what we've been able to do with the dollar to spend because I think that we still have for our wedge production, the lowest capital intensity on a per barrel basis in the industry, I believe, at least the last time we checked it. Now we haven't done that number in a couple of months. So we probably need to check that again to know for sure.
Michael Scialla:
Appreciate the detail on that. The one to follow up on your agreement with ADNOC. Does that cover Stratos? And do you have any sense for what kind of capital the company is looking to spend with you at this point?
Vicki Hollub:
It doesn't cover Stratos, but it does cover other things, and it could cover things that we currently have today, not -- probably not the first deck at the King Ranch. But what we had done is we put together a work group that worked with ADNOC to talk about what the possibilities are for direct air capture and sequestration here in the United States versus Abu Dhabi. And the big focus was to try to help each of us to achieve the goals that we've set out. And ADNOC just set another goal for themselves to get to net zero, I think, by 2045. So they're on a mission. They have a goal, and we also do and we -- given the fact that we collaborated on making and building the what is now the largest -- and what was it, even at the time, the largest ultra-sour gas processing plant in the world. There were several companies that walked away from that they didn't want to try to attempt that.
So we have a track record of working with ADNOC to do difficult things or to do things that are different. The sulfur recovery units in Al Hosn are serial numbers 1 through 4. So that's -- that was a bold step for us. And now we're taking this bold step to go into looking to help each other, and also to help our shareholders because the way we're doing this is in a way that it's not going to be a cost for us over time. It's going to be -- it's going to deliver returns and ADNOC is focused on that as well. So we have a very similar objectives around all of how we're doing this. And so the work team now will continue and start looking at sites here in the U.S. and the UAE and pick the one that gives us the best chance to ensure that right out of the gate, we're starting with a good project.
Operator:
The next question comes from Roger Read with Wells Fargo.
Roger Read:
I guess I'd like to follow up on some of the carbon capture. We saw a transaction occur, I guess, now about a month ago, on conventional sort of CO2 EOR. And I was wondering, as you look at your own operations there, anything you can look at or examining along those lines? Or have you had any inquiries from others about trying to expand the opportunity there?
Vicki Hollub:
I can't comment too much on what's happened. But I will say that there's probably not any carbon capture or CO2 EOR things that are happening in the U.S. or even worldwide that we don't follow very closely, one of which we had followed probably for a few decades or at least a couple of decades. But when we look at it, we -- and Richard can build on this. So we have now structured what we're doing so that we can focus on the things that we do best. And the things, as we've talked about in this call, the things that we do best are
And since we have used CO2 for EOR for almost 50 years, what we're doing now is just a different way, a different kind of reservoir to put the CO2 into. So a different type of modeling, but all the same work goes into it and all the same the same techniques and approach go into looking at how we handle the CO2 and how we get it sequestered, whether it's in an EOR reservoir in the Permian or elsewhere or whether it's in a saline reservoir. So that part of it is our expertise. We don't really feel the need to own pipelines because pipeline returns are generally not the kind of returns that we can get with our dollars invested in either the upstream business or shale business or conventional. So what we want to do is make sure that our capital dollars are going to the things that we do best. We've partnered with midstream companies in the sequestration hubs that we've developed. And again -- but we do have as you mentioned and referred to significant infrastructure. We do have 2,500 miles of CO2 pipeline in the Permian. We're operating there 13 CO2 processing plants. And so we have the basis to do a lot of work and a lot of sequestration in the Permian, where I think the Permian as a whole, I think the capacity is estimated to be large enough to sequester all of the emissions from the United States for 28 years, and we have a big footprint in the Permian. There are multiple zones we can not only implement CO2 for EOR, but for a straight sequestration. So we're doing partnerships that give us the best return in collaborating because there's going to be a lot of capital required for these projects over time, and we don't want all of that capital coming from Oxy. Obviously, we want other companies doing what they do best to. Richard, do you want to comment on some of the sequestration hubs?
Richard Jackson:
Sure. I mean -- yes, just build a minute. I think even especially in our Permian EOR or Permian position, we continue to work many carbon capture opportunities. We continue to think because of that legacy position we have, especially in the subsurface that that's going to present economic and real opportunity for us and emitters in terms of being able to capture and retire the CO2. In terms of the Gulf Coast, I know we talked about it before, but I want to reiterate, like Vicki said, be very focused on the sequestration of the subsurface piece of that. That's really as we learned where we could best add value, it's around that position, and we have our hubs that are going in the Gulf Coast.
We've got several of our Class 6 wells that are permitted and moving well through the process, may have up to 6 by the end of the year. We're drilling strat wells really in every hub continuing to be prepared as we think these capture projects are going to be put together and come online over the next few years. So we really think we're positioned to be the low-cost kind of sequestration, certainly providing security around the CO2 because of our history. So great partnerships with midstream companies we've announced before, and they're an important piece, but we're really focused on that, both in the Permian and in the Gulf Coast around really developing that subsurface for sequestration.
Operator:
The next question comes from Paul Cheng with Scotiabank.
Paul Cheng:
Vicki and the team, with the improvement that you're seeing in DJ, what should we expect from the activity and the production trajectory for the next several years? I mean, in the past that I think with the limitation on the inventory or there maybe concern about regulatory, that production for you has been on the decline. Should we assume that the decline will continue, but at a slower pace or that you think you may be able to do better than that? That's the first question.
Vicki Hollub:
Okay. I'll turn that over to Richard. Richard's been actually looking at that more closely.
Richard Jackson:
Sure. Yes. Let me just kind of walk you through where we were this year. Obviously, we were significantly underinvested in the last couple of years coming out of the downturn, really focusing capital on the shortest cycle. We really restored capital back to the Rockies this year back to more sustaining levels, but the teams continued to outperform. And so what really has happened this year is a shallower decline in the first half of the year. We had expected growth in the second half of the year, but the growth is actually a bit better. So if you look at kind of where we're at first half to second half, I think we're growing about 6,000 barrels a day. So the -- in terms of rigs, we're running capable -- been running 2, capable for 3. And we continue to work on these well improvements to see really how that asset and that production competes for capital in our portfolio going into next year. But I think really the -- sort of the capital that you're seeing deployed in the Rockies this year takes us from a decline into really a flat to moderate -- low-end growth.
Paul Cheng:
Rich, can we assume that that's the minimum that you will be able to do for the next several years that led to maybe modest growth?
Richard Jackson:
Look, the teams have continued -- we challenge everybody, but I think the Rockies team has really done a great job on this. Getting upfront in terms of land development, permits, really getting the midstream position in place to be able to do more. But again, it needs to fit our capital allocation. So they do high returns even at lower gas prices. These are very competitive returns. I would call them a bit longer cycle than the, say, the Delaware in Texas, but they also have a bit lower decline. And so for us, they fit really well. We'll have capability to do more, but it really needs to fit the sort of cash flow outcome that the company needs as we put capital together for next year. But we can do more as that fits.
Operator:
The next question comes from Devin McDermott from Morgan Stanley.
Devin McDermott:
So I wanted to go back to Stratos, the first DAC plant in Texas. You've made some progress in contracting some of the offtake there. I was wondering if you could just talk at a higher level on the demand that you're seeing for offtake from that DAC facility? And then I think signing offtake was one of the key factors driving some of the ranges in capital spending for lower carbon ventures this year. Could you just talk about where we're trending within that range as well?
Richard Jackson:
Yes, great. I'll start with the CDR sales. I think as we've continue to talk about, we really believe in the market and believe that really the formation and sales are following kind of our expectations. I mean, clearly pleased with strategic, strong strategic customers like A&A that recognize really the fit of our product, which is a CDR into a larger aviation decarbonization. So while there -- we think about broadly sustainable aviation fuels, we feel like CDRs fit well into that market.
So if you look at some of the equivalents on probably a better marked market in terms of sustainable aviation fuels, those may range $800 to $1,000 a ton we believe we're going to settle into that market well. Really, the key for us, though, as we continue to talk, is driving the innovation and cost down in DAC. And so we remain focused not only the construction parts going on in Permian with Stratos, but also in our King Ranch development, but very pleased with the progress carbon engineering makes with their innovation center. So I didn't want to talk about just the market because we do believe that cost down is important for us to make this affordable long term. The other mark I'll give you, just in terms of thinking about kind of sales and how the CDRs fit on the price ranges, I think in April European Parliament put together some things around requiring 2% SAF mix starting in 2025 and some of those penalties are $550 per ton of CO2. So when you look at how we can compete directly offset that at a lower cost. We think that's another mark that really helps us think about how we can be competitive.
Devin McDermott:
Great. And then just on the lower carbon spending in your plan this year, I think the offtake and the ability to finance off balance sheet was one of the swing factors. Can you just give us an update on that process as well?
Richard Jackson:
Yes. No, I think -- look, we remain optimistic that we're going to have good partners as we think about financing this long term. We've been strong in our ability to be able to carry the near term, but we understand longer term that we need financial partners that come into this with us, and we continue to make progress. Just to talk about the capital, we've stayed with the range $200 million to $600 million for the year. And really, that reflects that room to bring in that capital partnership by the end of the year.
Vicki Hollub:
Yes. And I would say, Devin, I appreciate your interest and we will have a bit more of an update in November. I want to give anybody to thinking it's some sort of major announcement, it's not. It's just an update just like what Richard gave now because things are continuing to change with respect to demand for CDRs and that sort of thing. So we'll give you a little more of that in November.
Richard Jackson:
Yes. I think construction progress, I should say, we're about 23%, I think, to date. So we'll have more construction progress. We think we can point more to the market. And just kind of follow-up on that deep dive we had last year kind of giving some updates on how these pieces come together.
Operator:
[Operator Instructions] The next comes from Scott Gruber with Citigroup.
Scott Gruber:
Yes. Just had one question, just following up on that last point. The ADNOC MOU is quite encouraging. But whether it's ADNOC or another partner? In terms of just thinking about making that equity investment in DAC, do the partners that you're talking with, do they want to see the learnings from Stratos manifest into lower capital and operating costs, DAC 2 or DAC 3 to pull the trigger on an investment? Or do you sense that just showcasing progress in constructing Stratos and getting it up and running would be sufficient to attract equity funding into the program?
Vicki Hollub:
I would say with ADNOC, they know our track record of building major projects and they know Ken Dillon well, who's actually manages our major projects. So they've seen us and how we not only -- we're innovative in how we built Al Hosn, but we were also innovative in this just recent expansion to expand the plant by almost 50% with probably spend way under 10% is -- was phenomenal. And so I think that ADNOC will be prepared to move forward with us sooner than waiting on what happens with Stratos. I think they all understand that technologies go through a cost down. There's never been a technology that's worked and been adopted in large way without having gone through the same kind of thing that we'll go through with our direct air capture.
Richard Jackson:
Yes. And the only thing I would add, I mean, there definitely is different capital, I think as we're able to move down that cost down over the next decade. We really like to partner with strategics like ADNOC or others that can be a part of not only the near term, but the long term. But obviously, we want to get the right value and set up the right economics for both parties as we bring them in. And so I think, of course, long term, as we bring costs down, the market forms, we expect that to open really capital, and that's a big part of our ability to scale development. And so to answer your question, yes, I do think that changes -- presents more opportunities over time.
Vicki Hollub:
Yes. One final comment on it is, partnering with ADNOC, we know their capabilities and expertise, too. So we know what they bring to the table. And so that's the other exciting aspect of this is having their knowledge and their experience, their expertise combined with ours, to do whichever we do or a combination of both the CCUS and the direct air capture.
Operator:
The next question comes from David Deckelbaum with TD Cowen.
David Deckelbaum:
I'm going to try to ask one perfect question. I was curious, you mentioned before, obviously, with the curve where it is now, you need to see it a bit higher to start prosecuting more preferred redemptions. Does the cash flow priority change given the fact that it's harder to achieve that milestone in the coming quarters? Or should we expect sort of a similar pace or distribution or free cash via buybacks sort of irrespective of where the curve is in the back half of this year? And does it change how you think about capital allocation, perhaps into next year relative to sustaining capital versus growth capital?
Vicki Hollub:
I would say that we're not going to execute a large growth program in our upstream oil and gas business. So -- but I will say that our intent is to keep a moderate capital spend, what we consider to be something similar to the activity level that we have on a whole year basis, not the second half, take the second half of this year and project it into next year is what our oil and gas activity level would be. But what we want to do is we just want a program that delivers the best returns at present value. So that doesn't mean that we're going to take our capital framework right now and dramatically change it. Share repurchases is a part of that.
And that's -- it's an important part of that. And what we do will depend on the macro. But from the -- what -- I would say what we see with the macro now, I wouldn't discount our ability to do both, to repurchase common shares whilst also being able to redeem some of the preferred next year because I do see a better price environment, I believe, than what some realize it's going to be. So I think there are a lot of reasons pointing to a pretty good environment. So I wouldn't discount it yet. I do believe that we'll have the opportunity to do both, but share repurchases will always be a part of our framework.
Robert Peterson:
The other thing I'll add, David, too, is in 2023, because our share repurchase program is thus far, far more ratable in our concentration and purchases last year. We're creating a foundation for 2024. We don't have as many slugs to overcome with us that necessitate spikes in oil prices or whatever to get there. So we are laying the groundwork for next year even as we continue to buy share repurchases this year, whether or not we're retiring preferred along with it or not.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I would just like to say thank you all for joining us, and have a great day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to Occidental's First Quarter 2023 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.
Neil Backhouse:
Thank you, Jason. Good afternoon, everyone, and thank you for participating in Occidental's First Quarter 2023 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Robert Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Neil, and good afternoon, everyone. The operational and financial successes we achieved last year continued into 2023 as I will detail in our first quarter call. Our operational excellence and disciplined approach to capital spending enabled us to meaningfully progress our shareholder return framework. Our continued efforts to strengthen our balance sheet culminated in regaining an investment-grade credit rating from Moody's.
This afternoon, I will begin by covering our first quarter performance, followed by an update on several accomplishments in our oil and gas business. In light of recent market volatility, I will then go over the cash flow priorities established during our last call and highlight the progress made in transferring enterprise value to our common shareholders. Then, Rob will detail the commencement and status of the preferred equity redemption before covering our financial results and guidance, including an increase to full year oil and gas production and on OxyChem pretax earnings. Our operational success even in the first quarter's lower commodity price environment enabled us to generate approximately $1.7 billion of free cash flow before working capital. Excess cash was primarily allocated towards approximately $750 million of common share repurchases in the quarter, accounting for over 25% of our $3 billion share repurchase program and triggering the redemption of nearly $650 million of preferred equity. Operationally, we exceeded our production guidance midpoint by approximately 40,000 BOE per day, following a prolific first quarter across our premier asset portfolio. In the Gulf of Mexico, we achieved our highest quarterly production in over a decade. This outperformance was partially driven by higher uptime in Horn Mountain and the outperformance following the successful Caesar-Tonga subsea system expansion project, which was completed in December. Our Permian production benefited from strong new well performance and higher operability primarily in the Texas Delaware. In the Rockies, strong base and new well performance and higher operated-by-other volumes in the DJ Basin resulted in higher-than-expected production. Internationally, our businesses performed well. Most notably, the Al Hosn gas expansion project is ahead of schedule because of the team's ability to integrate expansion work with annual turnarounds. The production ramp-up has commenced earlier than anticipated and has already led to a daily production record. These achievements demonstrate how our high-quality assets and talented teams provide the strongest foundation for free cash flow generation in Oxy's history. Our global oil and gas teams continue to perform exceptionally well in the first quarter, achieving several milestones and accomplishments. Domestically, in our onshore unconventional businesses, we delivered strong well performance and established new operational records in the Rockies and Permian. Our Rockies team drilled the industry's longest DJ Basin well ever at over 25,000 feet in just 8 days. This well also set a new lateral length record for Oxy at over 18,000 feet. In addition, we delivered a single well production record in the DJ Basin by utilizing a new well design. We plan to roll out this enhanced design as we further develop our inventory across the DJ Basin. In the Permian, our Delaware subsurface teams continued to optimize and unlock inventory, as demonstrated by success in the deeper Wolfcamp horizon, with a single well generating 30-day initial production rate of 6,500 BOE per day and an Oxy record for this interval. Our Delaware completions team also achieved a continuous pumping time of approximately 28 hours on another set of wells, far exceeding our previous record of about 22.5 hours. We expect that increasing efficiencies such as faster completions pumping will contribute to lower cost and a faster time to market. Though certain products and services utilized in our operations will likely incur price increases this year compared to 2022, we are seeing some early signs of tempered inflation. Our teams are working towards partially offsetting inflation impacts through various operational efficiencies and supply chain competencies. For example, in the Delaware Basin, we've optimized frac designs to reduce assets and water utilization for an average savings of around $240,000 per well. Our Rockies team has successfully integrated artificial intelligence into our plunger lift program, helping to maximize base production and reduce operating costs. On a broader scale, our supply chain team is continuously pursuing opportunities to manage pricing across our business portfolio through partnerships that thoughtfully balance contractual flexibility with cost management. These capabilities are more important than ever in the current inflationary environment as we strive to continuously deliver value to our shareholders. With these points in mind, I will now review our 2023 cash flow priorities. As we discussed last quarter, our 2023 cash flow priorities incorporate a disciplined capital strategy largely agnostic to the short-term volatility exhibited in commodity prices this year. Our 2023 capital plan remains on track and focused on sustaining our high-quality portfolio of assets, while securing our long-term cash flow resilience. We continuously monitor the macroeconomic landscape and intend to maintain our capital plan in the current environment. Should a sustained downturn in commodity prices occur, we possess the flexibility to rapidly reduce activity levels through our short-cycle, low-breakeven projects. We demonstrated our nimble approach during the last global downturn, and we are prepared to do so again should market conditions dictate. If oil prices follow an upward trajectory, we do not expect notable changes to our cash flow priorities, though the pace of our share repurchase program and the preferred equity redemption may be accelerated. We have previously spoken about how potential future production growth is expected to be in the low single digits. However, we have many opportunities to grow cash flow outside of production growth. We anticipate that the mid-cycle investments we are making this year will result in meaningful contributions to our future cash flow. For example, our new OxyChem projects are expected to contribute $300 million to $400 million in incremental annual EBITDA, with benefits expected to start in late 2023 and full project benefits expected in early 2026. Additionally, near-term investments in our low-carbon debentures businesses are expected to enable the commercialization of exciting decarbonization technologies with the potential to generate cash flow detached from oil and gas price volatility. We believe that the combination of our low cash flow breakeven, high-return assets and emerging low-carbon businesses uniquely position us at the forefront of our industry to create value for our shareholders. Value creation for our common shareholders governs our cash flow priorities. The allocation of excess cash toward debt reduction over the past 2 years was key in positioning us to initiate the next phase of our shareholder return framework. Our balance sheet improvement efforts reduced interest and financing costs, which contributed to an increase in our sustainable and growing dividend and the completion of last year's share repurchase program. Building on this success, we've already completed over 1/4 of our current share repurchase program, enabling us to trigger the redemption of approximately $650 million of preferred equity in the first quarter. As dictated by our 2023 cash flow priorities, we intend to continue allocating excess free cash flow towards share repurchases, which, in turn, may trigger additional preferred equity redemptions. We expect that these measures will be accretive to cash flow on a per share basis. In combination, we believe that these actions will further our goal of continued enterprise value rebalancing for our common shareholders and serve as a catalyst for future common equity appreciation. I'll now turn the call over to Rob.
Robert Peterson:
Thank you, Vicki, and good afternoon, everyone. I want to begin the day by highlighting our March credit rating upgrade and positive outlook for Moody's Investor Service. Gaining the Moody's investment grade rating is a significant milestone that acknowledges Oxy's recent financial transformation. Continued redemption of preferred equity, combined with opportunistic debt reduction, points to a compelling deleveraging story that we hope will facilitate future upgrades. The execution of our cash flow priorities over the last several quarters enabled us to begin redeeming the preferred equity. We have redeemed or have given notice redeem approximately $647 million of preferred equity so far this year at a cost of approximately $712 million, including a 10% premium payment of close to $65 million.
To date, we have eliminated approximately $52 million of annual preferred dividend, while also transfer enterprise value to our common shareholders. During last quarter's call, we reviewed how the mandatory redemption of preferred equity is triggered when rolling 12-month common shareholder distributions reached a cumulative $4 per share. The preferred stock agreement requires at least a 30-day notice for each redemption. By the end of this week, all $647 million of preferred equity triggered for addition during the first quarter will be fully redeemed. As of May 9, we have distributed $4.57 per share to common shareholders over the rolling 12-month period. We intend to continue repurchasing common shares in part to remain above the $4 trigger per share for as long as we are able. We recognize that staying above the $4 trigger will become more challenging in the latter half of this year due to the timing and pace of our prior share repurchase program. Our ability to remain above the $4 trigger will be heavily influenced by commodity prices. But even if we fall below the trigger, we plan to continue repurchasing common shares so that the distribution is required to surpass the trigger in future quarters are more evenly spread throughout the year. During a period where we may be below the $4 trigger, we may also seek to retire debt opportunistically, which would achieve a similar result of transferred enterprise value to common shareholders and further enhancing our credit profile. Turning now to our first quarter results. We posted an adjusted profit of $1.09 per diluted share and a reported profit of $1 per diluted share. The difference between our adjusted and reported profit for the quarter was primarily driven by the premium paid to redeem the preferred equity. We concluded the first quarter with nearly $1.2 billion of unrestricted cash, but had not yet made payments to preferred equity holder as of March 31 due to the 30-day redemption notice requirement. However, the first quarter call on the preferred equity is reflected in our balance sheet as an accrued liability and will be captured in future cash flow statements as payments to the preferred equity holder made. During the first quarter, we generated approximately $1.7 billion of free cash flow before working capital, which was accomplished despite a lower commodity price environment as compared to prior quarter, lower domestic realizations as compared to WTI, lower sales and production due to the quarter-end timing of cargo lifting in Algeria. We experienced a modestly negative working capital change during the period, which is typical for the first quarter, and was primarily driven by a semiannual interest payments on our debt, annual property tax payments and payments under compensation and pension plans. These items, which are largely classified as accounts payable and accrued liabilities were partially offset by a net decrease in receivables, driven by lower commodity prices. We see the potential for working capital partly reverse in the second quarter since many of these payments are made annually in the first quarter, but accrued throughout the year. As discussed in the last call, we expect to be a full U.S. federal cash taxpayer in 2023, which is reflected in our financials by the reduced deferred income tax provision and our cash flow statement compared to prior quarters. We are pleased to update our full year guidance for oil and gas in OxyChem as a result of excellent first quarter performance in both businesses. Vicki reviewed many of the highlights in our oil and gas business that contributed to our production outperformance across our high-quality assets portfolio. These factors enabled us to surpass our first quarter guidance and some are expected to continue having positive impact on production throughout the year. Specifically, the acceleration of the Al Hosn gas expansion project and new well performance in our domestic onshore businesses are expected to yield higher production than originally planned. These positive results provided us with the confidence to increase our full year production guidance midpoint to 1.195 million BOE per day. Looking ahead, we anticipate that the second quarter production will be in the lowest of the year, primarily driven by the timing of domestic onshore activity and optimization of our maintenance schedule to reduce planned downtime in the Gulf of Mexico. As discussed on our last call, we expected that the first quarter of 2023, will have the fewest wells come online in our U.S. onshore business all year. This proved to be the case as the Rockies and Permian unconventional businesses turned 6 and 53 wells to production, respectively, in the first quarter. In the second quarter, we expect to turn significantly higher number of wells on production the benefits of which will be fully realized in the second half of the year. Quarterly timing fluctuations in bringing wells online and the resulting production impact are typically and primarily driven by the optimization of resources and pad development timing. Internationally, we expect production compared to prior first quarter -- we expect higher production compared to the first quarter as our annual scheduled turnarounds were completed and production at Al Hosn is ramping up. Increased international production will be slightly offset by the just finalized Algeria production sharing contract, which decreases reported production but is not expected to have a material impact on operating cash flow. We anticipate that our second quarter oil mix will reduce to approximately 52%. The lower oil production in the Gulf of Mexico and Algeria, compounded by increased gas production at Al Hosn. While our oil mix will be lower in the second quarter, we expect that it will rebound in the second half of the year and be more in line with our full year guidance once maintenance in the Gulf of Mexico is complete. Maintenance work and the associated lower volumes in the second quarter will also contribute to a domestic price operating cost increase of $9.85 per BOE before receding on a BOE basis in the latter half of the year. In summary, our impressive first quarter production and activity plans for the remainder of the year provide us with the confidence to raise full year production guidance despite anticipated reduced production levels in the second quarter. OxyChem approximated guidance in the first quarter. Due to the seasonality of customers' chlorovinyl inventory orders, we anticipate the first half of the year reflects stronger results in the latter half of 2023. Despite macroeconomic uncertainty, margins for OxyChem's chlorovinyl products remain robust and lead us to expect another year of strong results, providing us with the confidence to raise OxyChem's 2023 pretax income guidance midpoint to $1.5 billion. Midstream and marketing generated pretax income of $35 million in the first quarter, falling within our guidance range. First quarter results were primarily impacted by the timing of crude oil sales as well as favorable gas margins due to transportation capacity; optimization in the marketing business. These items were partially offset by lower equity method investment from income from WES. Capital spending in the quarter approximated $1.5 billion and close to 25% of our 2023 capital plan, which remains at $5.4 billion to $6.2 billion. We expect higher capital spending in the second quarter compared to the first due to development timing in Rockies and Permian and advancement of the OxyChem Battleground modernization and expansion project. We also anticipate that capital spending in the third and fourth quarters will be below the second quarter and in line with full year guidance. Overall, the first quarter represents an excellent start to 2023. As we look ahead to the rest of the year, we are favorably positioned to execute on our cash flow priorities and advance our shareholder return framework. We aim to continue shifting our capital structure in favor of our common shareholders in the near and long-term. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. We're now ready for your questions.
Operator:
[Operator Instructions] Our first question comes from Neal Dingmann from Truist Securities.
Neal Dingmann:
My question is it seems like certainly in the Permian and other areas, you're having very nice and remarkable efficiencies, and then there's a potential for OFS potential softness we've heard about. I'm just wondering if you get the benefits of both those things. Would you continue with the plan you have -- basically with those savings, would you just take those free cash flow and call that back into the buybacks at all? Or would you continue with maybe more growth?
Vicki Hollub:
No, we would -- any incremental cash flow that we can generate from whatever sources would go to share repurchases, and hopefully -- and beyond that, the redemption of the preferred along with it.
Neal Dingmann:
Okay. Great to hear. And then just secondly, DJ activity, it sounds like you're going to be really -- you didn't have as many in the first quarter as expected, and that's really going to take off. Maybe could you just comment on as far as well pads, and just I guess the 2 questions I had in the DJ. On permitting, I think you're fine there I just wanted to double check that. And then secondly, just on pad size at all, expectations are you doing anything different there on the completion side.
Vicki Hollub:
Yes. I'll pass this to Richard.
Richard Jackson:
Neil, appreciate it. Yes, a really good quarter and out looking well for our Rockies team. So I appreciate really the good pieces that they're putting together, maybe just connect a couple of things. I think 1 thing we saw in the first quarter that is playing through all year is very strong base production performance. A lot of that is really strong wells that they brought on at the end of last year that were new wells or wedge that are now turned into base. But in addition to that, they've been able to continue to optimize their production system. The most meaningful thing they've done, they've introduced gas lift earlier in a lot of these wells and even on some of the legacy base performance, which has really gave us a boost. We did quite a few of those in the first quarter. We'll do less in the second quarter. So we won't see quite as much of that bump. But that's been helpful on the base side.
On the new well performance side, I mean, obviously, we're happy to see we included this peak 24-hour record for this [ Nio C ] well. And I'd say that's fundamentally a good thing to see out of our new well performance in the Rockies. We've been able to continue to down space in certain areas, similar to how we do our development in the Permian. So in many areas where there might have been 18 wells per section, we're down to 12. We've been able to increase our profit concentration to couple with that down spacing, and have been able to increase that about 30%. And then just the efficiency of really the frac and then turning that online, we're continuing to reduce, not only the time to market as we traditionally talk about it, but 1 that the team there has been very focused on, which is a time to peak production. And so being very thoughtful about how we're building this operational ramp in for the rest of the year. But I guess, last couple of points, as you said, we had 6 wells delivered in the first quarter, that was per plan. Really, the second quarter through the end of the year, we anticipate 20 to 30 wells per quarter kind of fit that total year outlook. So definitely, picking back up on that in terms of well delivery. So bottom line, if you look at the first half and the second half, as we communicated on the last call, we expected some decline just through really the cycle of underinvestment as we picked up activity in the second half of last year. That we'll be able to then turn to growth for the second half of the year, and both of those are looking better than original plan. So very pleased with the team there.
Operator:
Our next question comes from Neil Mehta from Goldman Sachs.
Neil Mehta:
The first question is more of a short-term question and then the second is around low carbon. I just -- in the quarter, it looked like price realizations were a little bit soft. And so some of that, it sounds like, was just around turnarounds on the refining side. But can you just talk about that and clarify as it did drive some delta versus consensus?
Robert Peterson:
Well, Neil, I think there were 3 key components of that. First of all, looking at the calendar month average roll in terms of the NYMEX price, we've seen the market switch really from backwardation to contango at the end of March, impacted realizations by about $1.50 per barrel. So starting there across the domestic portfolio.
Following that, in terms of the Gulf of Mexico, it had an amazing quarter. But at the same time, there were refineries on the Gulf Coast that had turnarounds going on. And so moving from the fourth quarter to the first quarter, realizations dropped against WTI by about $3.50 per barrel. Additionally, there was an outage in the DJ Basin as well, third-party outage, which caused realizations there to drop by about $1 a barrel. So with those components altogether, that really impacted oil realizations.
Neil Mehta:
That's really helpful. And then if you could give an update on the low-carbon business as you progress towards DAC-1. What is -- what's the latest in terms of the development? And then your thoughts on the voluntary market as well as that can help to bring the project closer to the money?
Vicki Hollub:
I'll start with we had a very exciting groundbreaking -- official groundbreaking finally on the low-carbon venture business, DAC-1, that we'll be building in the Permian Basin. It's already under construction. The work started at the end of the last quarter. We had an official naming at the groundbreaking. It's now called Stratos. And currently moving along very well, and we're really excited about it and excited about where the teams are headed with it. Do you want to talk about the carbon market?
Richard Jackson:
Yes, sure. And maybe just to add broadly on a couple of other updates on kind of the low-carbon progress. Like Vicki said, obviously, moving with DAC-1 in the Permian, but then continue to progress our sequestration hubs in the Gulf Coast, continue to move forward kind of with the subsurface understanding or the work that we're doing there.
Really, the big piece of that, we've submitted 2 more Class 6 wells in our hubs there and then 2 more for -- to support our Permian operations so to continue to do that. In the King Ranch area, we're making plans to drill what we call 3 stratigraphic kind of test wells that'll go in front of the Class 6 submissions there. So continue to do really that upfront work to kind of prepare for development, both from the point source side and the DAC side in both those areas. In terms of the market, continue to see the voluntary market strong or growing for our CDR sales. I think we'll anticipate having some updates on that over the next few months, getting close to some meaningful things there. But I think a lot of that is really turning to the compliance market as well as really globally as we've talked about, things around heavy-duty transportation and specifically airlines have continued to sort of form up, I'd say, sustainable aviation fuels especially in Europe, have continued to recognize kind of these carbon removals as part of that portfolio of solution. So we're seeing some policy form in addition to what we see in the U.S. with the IRA to kind of help support that. So the voluntary market is in front of that. We appreciate working with some strong partners there that understand the role of carbon removals, understand the emergence of these compliance markets. And so they're really doing their part to help us catalyze this technology, bring this cost down, while we fit that long-term compliance market need. So more updates, I think, we hope to give later this year as that makes more progress, but certainly fitting within the ranges and the expectations we have on the revenue side for our DAC projects.
Operator:
Our next question comes from Doug Leggate from Bank of America.
Douglas Leggate:
I guess I've got a couple of follow-ups because this -- I mean watching your share price reaction last night to the earnings, the market obviously saw something it didn't like. And it struck me at least that a lot of the people who cover you didn't cover Anadarko and perhaps don't remember the seasonality of Gulf of Mexico maintenance. So I wonder if you could just take a minute to explain how you're running that business as it relates to the seasonality of production?
Vicki Hollub:
Yes. Thank you, Doug, for bringing that up. And yes, you're right. I think that, that's not very well understood. What's happened with us now in terms of our forecast for Gulf of Mexico is, I want to make sure everybody realizes. This is pretty typical. What's different for this year is that we had such an incredible first quarter. And the reason that we had such an incredible first quarter is because, first of all, we had the lowest downtime that we've had in a while. It was a very, very, very good performance, operating performance by the teams in the first quarter in Gulf of Mexico. Secondly, we had the Caesar-Tonga subsea system excellence -- or expansion system come online. So from Caesar-Tonga, we had an incremental increase of a gross 15,000 barrel per day from that project. So our Q1 was really propped up by some good performance, lower downtime and the transfer of what would have been the Horn Mountain maintenance in first quarter to second quarter.
The reason we moved that from first quarter to second quarter was just some supply chain issues in getting the materials we needed from the supplier. So this would have looked like any normal year if we had our -- been able to do the maintenance as we had planned to do. Now I think what's gotten people concerned is going from 171 to such a lower number in the second quarter. But Horn Mountain is one of the biggest producers that we have offshore. So doing that maintenance in a given quarter is impactful. And along with that, we have another couple of maintenance projects on the schedule along with some well work that we want to do. So the full year still looks really good. We were at 144,000 barrels a day. So that hasn't changed. It's just the timing and how it looks much, much lumpier than we're used to and that others are used to. And again, it's because of the bigger maintenance that wasn't done in Q1 that will be done in Q2, along with much higher production than we -- than people are used to seeing. So thanks for the question. And...
Douglas Leggate:
Yes. I appreciate the clarification, Vicki, because it remarkable that, that would seem to be the primary focus of discussions after the result last night, and I just thought it'd be worth reminding everyone that legacy Anadarko that was entirely normal. So thank you for the clarification. My follow-up is really, I guess, it's a Rob question. But you mentioned inflation, Rob, or at least I think Vicki did in her remarks that things might be rolling over a little bit. But your CapEx guidance is still quite wide. So I wonder if you could just give us a tip of the hat as to where you see the trend going?
Should we be starting to think that you've got a chance of coming in towards the lower end of that range? Or is that more activity led? Or was it more -- had you already baked in a reasonable amount of inflation that might not now happen?
Robert Peterson:
I think as a discussion in Vicki's comments, and I heard also from Richard, is that we are seeing things sort of plateauing at this point. Some pieces are rolling over. There's still a fair amount of wage inflation pressures in the Permian that we are still seeing. So I wouldn't say we're ready to committed to the fact that things are going to roll over and decline for the balance of the year so we've maintained that guidance. As Vicki commented on the earlier question that if we are fortunate enough to have things fall off, and it allows us to continue the same level of activity for a lower cost, we would roll that back into additional share repurchases in the balance of the year. And then Richard probably has some additional comments.
Richard Jackson:
Yes. I would -- that's perfect, Rob. I just was going to add one. I'd say the other element we factor in is continued efficiency improvement. So Doug, ramping up last year, getting started this year kind of hitting steady state with our rigs and our frac cores. We do expect continued efficiencies. I mean we highlighted on the singular wells of these records, but it's really in total, we're anticipating some improvement in the second half of the year. So we leave a little bit of room on that. where the burn rate just gets a little faster as we gain in efficiency.
Operator:
Our next question comes from John Royall from JPMorgan.
John Royall:
So my first question is on chemicals. You were in line in 1Q, but you raised your full year guide. So you're seeing something that's giving you more confidence in the remainder of the year, but it does feel like there should still be some challenges to the housing market. So just looking for some color on the guidance raised in chems so early in the year and what appears to be an uncertain environment?
Robert Peterson:
Yes, John, I think you've characterized it actually pretty well in your question. So if you look at domestic PVC demand through the first quarter compared to last year, it's down about 18% year-over-year. However, what we've seen is the export business has picked up that slack in the first quarter as it's up almost 80% year-over-year. So we end up with a combined demand for PVC that's up about 2.5%, 2.7% for the country versus last year. And that driving on that softness in domestic demand, as we discussed on prior calls, is really being driven by housing construction sector. We still believe that inventories remain low for many PVC buyers as we're entering sort of the heart of construction season. But no doubt, there's encouraging macro conditions between inflation, mortgage rates and regional bank issues have converters a little more reluctant to build what would be typical inventories for this time of the year for construction.
So our guidance reflects that continued uncertainty and the trajectory of the global business and the domestic business. We still firmly believe there's a lot of pent-up demand for construction, but they're just cautious with the macro conditions. I would say, however, that the lower energy prices in terms of gas prices resulting in lower ethylene prices also does create the opportunity for some margin in the business that might still be present and stickier even at these lower demand levels. That's part of the raise. I would say on the caustic side of the business, we're seeing this sort of balanced along type conditions. General manufacturing is certainly off from prior year, particularly automotive remains subdued. So domestic demand is similar to last year, but availability is certainly higher than it was before. And so we're seeing that result in some price erosion continually in the caustic side of the business. So we're still assuming that the unwinding of inventories in Europe take the balance into the middle of the year and then the Chinese economy continues to open slowly. If either one of those happen more rapidly, that would certainly be favorable to the business. So that increase in guidance really reflects some optimism around things kind of reaching a stability point at least next quarter or so and then preserving some of the margins with the lower feedstock costs.
John Royall:
Great. And then my next question is on the paydown of the preferred. You gave some color on the downside case and if you end up going below $4 a share LTM. Is there a commodity price where you think you might expect to pull back on the buyback and go below that $4 a share? And just assuming we stay above it, is that $700 million-ish run rate, including the premium, a good go-forward click to think about?
Vicki Hollub:
I would say it's just based on the cash available. We're going to use the free cash that we have to continue to buy shares and to trigger the preferred as we can do that. But -- and we're monitoring that. We have an outlook on that. So we're being pretty thoughtful around what the rest of the year might look like.
Robert Peterson:
Yes, it's certainly because of the concentration of share program last year, this year is lumpier, and it makes it more challenging in Q3. I think we've talked on an annualized basis we would probably want oil prices in the $75 range to be able to continually stay above the trigger point. But as Vicki made her comments earlier, our intention would be is even as we fall below the $4, that as part of our shareholder return program is continuing to buyback stock. And so even if we fall below the $4, our intention is to continue to return value to shareholders through buybacks.
Operator:
Our next question comes from Paul Cheng from Scotiabank.
Paul Cheng:
Rob, just want to go back into the budget. What's the underlying inflation that you included in your regional budget? And have you -- I suppose that you didn't really build in into any deflationary in the second half? And how much is your service and raw material for this year will be subject to the spot prices if we do see deflationary? That's the first question.
And second question is that, I think, in the prepared remarks, talk about on the DJ Basin that for the remaining of the year. The well come on stream will be pretty variable each quarter. How about in the Permian?
Richard Jackson:
Paul, let me -- I'll try to start on both of those. In terms of really inflation, when we look year-on-year, we are around 15%. This is domestic in the U.S. Of course, internationally, we didn't see near that. But in the U.S., looking at around 15%. We had plans that were embedded in our budget to offset about 5 of that through operational efficiencies. So we're generally on target for both. Let me deconstruct kind of the second half and then a few of the bigger components. So the second half of the year, we are seeing some things soften. When you think about OCTG, obviously, power costs and fuel, some of the labor components, those are types of things that we see as potential.
We also have quite a few of our rigs and frac cores that are up, and so we'll be exposed a little bit either way there, though, like we talk about, we have longer-term relationships and we're able to balance kind of that long-term with short-term pricing with our service partners on that front. So the big areas we're looking for is continuing to kind of watch the OCTG market. We'll see what rigs and fracs do this year. Obviously, we're steady, but we'll see what the rest of the market has to do. And then probably the other point that we would watch or that would impact us is sand. We're using more regional sand even in the Rockies. There's some different sand choices, but our primary supplier there continues to be in front in the Permian, and so we're seeing some opportunity on that. So at this point, we're not looking to change our outlook or kind of change the way we're thinking about the budget, but we did want to note those are the key variables that we're watching that will impact us. And then in terms of the Permian, similar sort of well count type change, not quite as drastic as what we're seeing in the DJ. But we had 56 wells online in the first quarter. We'll see that kind of hit more steady state of around 100, 110. And really, what happened, just to give a little bit more color, as Rob kind of said in his prepared remarks, a lot around development sequencing. So if you think about the ramp-up and then going into the fourth quarter, where you're exposed to weather, we had pads with smaller well count. And so we did that to really derisk kind of the production in the fourth quarter, and really it was production in the first quarter. As we started in the first quarter, many of our well pads, Midland Basin, Delaware Basin, they've gone north of 10 kind of wells per pad. So you have a lot more SIMOPS that's better from a value standpoint, but it does change kind of that sequencing of production online. But we do see -- while the well count was low and the kind of residual DUC count grew for us in the first quarter, we expect to hit steady state really on both of those as we go into the second quarter and definitely in the second half of the year. So hopefully, that helps a little bit there.
Operator:
Our next question comes from Leo Mariani from ROTH MKM.
Leo Mariani:
I just wanted to follow up a little bit more on the low carbon venture business here. I guess recently, it came out that you guys invested kind of more money into NET Power here. And I just wanted to maybe get some color around kind of what the sort of confidence is in that business? And why putting the incremental money there?
And then sticking on low carbon ventures, I just wanted to see if there was any maybe update on sort of funding for the DACs here at this point in time. Are you all having really detailed conversations out there? Or do you think there could be something that gets done here in '23 in the funding?
Vicki Hollub:
I'll start with NET Power. We started looking at NET Power about over 2 years ago, almost 3 years ago. The reason we like it is because the physics and the technical aspect of how it works is impressive. And as we've -- I know mentioned on this call before, it's really the only source of emission-free power technology that uses hydrocarbon gases. And with hydrocarbon gases being so plentiful in the United States and in other areas of the world, we felt that a technology that actually can continue to use gas, hydrocarbon gas for the generation of power is going to be incredibly transformative for the power industry, not just here in the United States, but internationally as well.
And when you look at it, it combines hydrocarbon gases -- combust hydrocarbon gases with oxygen instead of air. So you have no volatile organics. And the CO2 which is created drives the turbine, and then it's captured on the -- as part of the process. So it does all the things that we needed to do and that other companies will need as well. And you look at the Appalachia, all the gas there, the gas of the Haynesville, the gas in the Permian and the DJ, it creates a lot of opportunity to build a lot of these things. Our confidence was bolstered also by the fact that we have now Baker as an equity owner in this process, and they are redesigning the turbines to make it more efficient. So when we are able to start building this, which should be in the 2026 time frame or maybe a little bit before, we expect that the cost of this will be less than what a traditional power plant would be if you put carbon capture on it. So it's a very flexible technology. We will be building the first one of those in the Permian Basin to provide power for our oil and gas operations, and then in the future, it will be one of the emission-free power sources that we use for our direct air capture units.
Richard Jackson:
Yes. The only thing I would add on NET Power, like Vicki said, we've started FEED on that first plant with the NET Power team, and getting that 2026 time frame lines up very well to not only what we need for direct air capture, but it's a great fit for oil and gas operations to help decarbonize the power, obviously, that we have. But the other offtake of that is CO2. So as we look to really transition and be able to use more anthropogenic CO2, it's a great fit.
So the -- on the DAC, and Vicki can help with this, too, I think we continue to think about funding not only for DAC-1 but especially for DAC-2 and beyond. To reiterate, that is absolutely our plan. We know that with commercial development success as we go beyond Plant 1, we really will need that financial support to be able to develop as we see the market growing for us to fit into. So I think we want to continue to progress this year. Obviously, we'll give updates on any of that as it comes forward. But meaningfully, as I answered earlier, kind of the market or the CDR sales caused progress on the project and then kind of how we think about the capitalization as we go forward. We want to be prepared as we go late this year and into next year to be able to give meaningful updates as that project continues.
Vicki Hollub:
And I guess what I would like to add that too...
Leo Mariani:
Okay. That's clear enough.
Vicki Hollub:
Sorry, Leo. One thing I'd like to add to that is that as we look at what the cost of this is going to be for us and what funds we will have to provide out of our free cash flow basically, it would be in the $500 million to $600 million range. It wouldn't be a lot more than that over the next 2 to 3 years. So I want everybody to understand that, looking forward, our capital program for our oil and gas development, chemicals, midstream, the corporation's capital is going to be invested in a way that, that fits with the priorities that we've established, one of which, and as important as any of the others, is investing in ourselves. That is the repurchase of shares. That's a big part of our cash flow priorities. And I want to make sure that people don't think that we're going to, in the future, have capital spending so much that we can't accomplish that.
For example, last year, we -- out of the $17.5 billion of cash that we had available to those 3 buckets, the debt reduction, share repurchases and capital programs, 57% went to debt reduction, 17% to share repurchases and 26% to our capital programs. If we had a similar situation with that kind of cash, 40% would go to capital programs, but 55% would go to share repurchases, and potentially up to 5% for debt reduction. So this is something that we're very committed to is not to let our capital grow to a point where it's not a -- we're not able to buyback shares at the level that we really need to do.
Leo Mariani:
Okay. Very thorough answer. Very much appreciate that, guys. And then just a follow-up on your comment on sort of chemicals. EBITDA on the expansion over time kind of eventually kind of getting to this $300 million to $400 million as we get towards '26. You mentioned in the prepared comments that you could start seeing some as soon as late '23. Can that number kind of start to be significant even as early as 2024? Could we get something even like 1/3 of that potential EBITDA next year? Just trying to get a sense of how that would ramp over time.
Robert Peterson:
Yes. Leo, the early days contribution from that is going to be from the smaller expansion project. It's in the $50 million EBITDA range. The $250 million to $350 million number we've given for the battleground project that's out beyond the project in 2026.
Operator:
The next question comes from Roger Read from Wells Fargo Securities.
Roger Read:
Yes. Maybe just 1 quick 1 to clarify off your comment, Vicki, to Leo's question about the CapEx, the $500 million to $600 million per year. That's inclusive of NET Power and DAC or just 1 or the other? I was just want to make sure I understood that.
Vicki Hollub:
That's all of our low carbon ventures capital. And that is assuming that we don't bring in a partner. And we are having some really good conversations with -- in fact, with -- 1 with a preferred partner that could materialize maybe sometime this year or if not this year or next year. So we do expect to get some funding. But what we want to make sure we relate to you guys is that, if we don't, that's the maximum of spend that we would have. Otherwise, we're looking at potentially having a lower spend than that with a partner.
Roger Read:
Okay. I appreciate the clarification. And then my other question, and this ties into the goal of maintaining the $4 of common repurchase on an annual trailing basis. None of us know what commodity price is going to be. You've got -- as pointed out in the presentation, right, 1 of the largest acreage holdings in the U.S. We've seen some of the other upstream companies trimming back a little bit or identifying some things as, I guess, we could call it noncore or something they simply won't be drilling and completing anytime soon.
So is there any acreage or other type of asset sales proceeds could be used to sort of plug those gaps if they arise or to offset the lumpiness that's coming forward? Just anything you can offer on that front would be appreciated.
Vicki Hollub:
Well, one of the things we do is we're always looking at how do we make the best value decisions? And when you -- when we think about divestitures, being a source for funding to continue the repurchase and the redemption of the preferred, that's certainly an option that we would consider. We -- the reality of where we are today though is that our position is large. And when you do the relative valuations of divesting versus for the continuation of this program, you have to make sure that you're making the right decision there. And I would say there's smaller things that would be optional for us to potentially do, whether it would be large enough scale to continue it is the question at this point. But we are considering other options that I doubt would mature and soon enough to be able to meet the cliff that we're facing right now.
Operator:
[Operator Instructions] There are no more questions in the queue. This concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I just talked to say in closing that I know there's been a lot of concerns among investors in the -- in our industry, particularly with respect to asset quality, execution, performance. And as Doug had pointed out, I wonder if that's part of the reason for the reaction to what we're seeing today. But looking at our asset quality, I think there's nobody that could question the quality of our assets. And you look at our past performance, I also think that our continuing improvement in well productivity in the Permian and some data that we'll show next earnings call about our performance in the Rockies, will clearly show that we're not losing any capabilities. We're not losing any performance. And in fact, looking at what our teams are doing technically today, they continue to innovate, continue to optimize. And with the mention of a new technique in the DJ, there are also new ways of doing things that we're trying in the Permian as well as in our Oman operations, Gulf of Mexico with the subsea pumping and systems installations, starting to look at our seismic differently.
I think that for our company, we have not seen degradation in the quality or performance of our teams. And I want to thank our teams for that because they continue to push the envelope and every year get better and better. And so I don't think there should be any concern about where we are today and what we're doing is it's just a kind of a strange scenario where, in second quarter, it happens to be the lowest of the year, but our production and productivity is continuing to get better. So with that, I want to thank you all for participating in the call today.
Operator:
Conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to Occidental's Fourth Quarter 2022 Earnings Conference Call. [Operator Instructions] Please note today's event is being recorded. I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.
Neil Backhouse:
Thank you, Rocco. Good afternoon, everyone, and thank you for participating in Occidental's Fourth Quarter 2022 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Neil, and good afternoon, everyone. On today's call, I'll begin with highlights of our 2022 achievements, including an oil and gas update followed by our fourth quarter performance. Next, I'll discuss our 2023 cash flow priorities, our enhanced shareholder return framework and our 2023 capital plan. Rob will then provide an update on the status and mechanics of Oxy's preferred equity redemption before reviewing our fourth quarter financial results and 2023 guidance.
In 2022, our record net income of $12.5 billion, generated a return on capital employed of 28%, which is the highest return we have achieved since before 2005. We also delivered record free cash flow before working capital of $13.6 billion, which enabled us to retire more than $10.5 billion of debt and to repurchase $3 billion of common shares. Our return on capital employed was enhanced by exceptional performance as our team set multiple operational and productivity records across our U.S. onshore, Gulf of Mexico and International businesses. OxyChem generated record earnings and our Midstream business approximated guidance. Also in 2022, our high-return Permian production grew by 90,000 BOE per day, propelled by outstanding well results. We delivered our best year ever in Delaware new well productivity, making 2022, the seventh year in a row that we were able to increase our average well productivity, as shown in our presentation's appendix on Slide 29. Our teams accomplished this by applying our proprietary service modeling and completion designs to our high-quality reservoirs. Well performance, along with our Oxy drilling dynamics and logistics efficiencies, enabled us to achieve reserves replacement ratio driven by our capital programs of over 140% at a cost of $6.50 per BOE, which was less than half of our current DD&A per barrel. With price revisions included, the total reserves replacement ratio was 172%, which increased our year-end 2022 reserves to approximately 3.8 billion BOE. Except for the years of the price collapse in 2015 and the pandemic in 2020, we have replaced more than 100% of our production for at least the last 20 years. With the depth and quality of our shale well inventory and 2 billion barrels of remaining potential in our Permian enhanced oil recovery business, we have the scale to continue our history of reserves replacement. A deep inventory, along with our unique portfolio of short-cycle, high-return unconventional assets paired with low decline conventional assets, OxyChem and our Midstream businesses, we have the capability for long-term sustainability and the flexibility to allocate capital to maximize returns for our shareholders. In 2022, we also made significant progress in developing the capabilities and assets needed to secure a low-carbon future, which is the other key to our sustainability. We started site preparation on our first direct air capture plant and executed several exciting agreements to sell carbon dioxide removal credits to prospective purchasers in the industry -- diverse industry sectors. We also secured over quarter million acres of land or approximately 400 square miles to develop carbon sequestration hubs. The fourth quarter of 2022 was a fitting way to wrap up a year of continued operational and financial success. We generated over $2.6 billion of free cash flow, which supported nearly $1.6 billion of balance sheet improvements. We also repurchased $562 million of common shares in the quarter, completing our 2022 share repurchase program. In our business segments, Oil & Gas approximated the midpoint of guidance, despite winter storm Elliott impact. Outperformance from the Gulf of Mexico and Al Hosn partially offset storm impacts experienced in the Permian and Rockies. OxyChem exceeded guidance, driven by stronger-than-expected market dynamics, while Midstream and marketing earnings were within guidance. In December, Oxy participated in the recapitalization of NET Power. This is a technology that generates emission-free power generation and has the potential to accelerate emissions reduction efforts in our existing operations and to supply electricity to our direct air capture plants and sequestration hubs. Ultimately, NET Power could be an important emission-free power generator anywhere that has access to natural gas. Among the record set in 2022 were lateral lengths in the Delaware Basin, DJ Basin, Oman and most notably in the Midland Basin where our well Lulu 3641 DP exceeded 18,000 feet to become our longest lateral on record. Remarkably, this well was drilled in slightly over 12 days. Milestones like this showcase our team's focus on safely and efficiently expanding the boundaries of drilling technology. Our teams also achieved an Oxy Delaware Basin record for wedge productivity, averaging a 30-day initial production rate of over 3,000 BOE per day from all wells that came online in 2022. We believe that 2 of our wells in the First Bone Spring in New Mexico and 6 of our wells in the Barnett formation of the Midland Basin achieved initial 30-day production records amongst all operators in their respective formations. In addition, we are continuing to consolidate acreage via trade that enable more capital-efficient, longer laterals, which help to optimize the required infrastructure. The longer laterals, exceptional well productivity and optimized infrastructure, partially offset inflation impacts in 2022, and we expect similar benefits as we progress through 2023. After highlighting 2 of our Gulf of Mexico assets, Horn Mountain and Caesar-Tonga on previous earnings calls, I'm pleased to announce another Oxy production record in our offshore operations. Our Lucius platform surpassed 150 million BOE of gross production in less than 8 years from first oil, becoming the fastest Oxy developed Gulf of Mexico platform to reach this milestone. Internationally, we, along with our partner, ADNOC, achieved record quarterly production at Al Hosn with 85,500 BOE per day net to Oxy. The Al Hosn expansion project is progressing well and remains on track for mid-2023 completion. We expect Oxy's Al Hosn net production to ultimately reach approximately 94,000 BOE per day. We are pleased with the total value we've created for shareholders in 2022, including the debt reduction of $10.5 billion and the $3 billion of share repurchases, along with a successful capital program of $4.5 billion. With our debt from outstanding bonds down to less than $18 billion and consistent with our shareholder framework, we will shift our focus to share repurchases, dividend growth and a capital program that further strengthens our sustainability. Over the long term, we intend to repay maturities and opportunistically retire debt to further reduce our cost structure and strengthen our balance sheet. In future years, we will seek to grow our cash flow and earnings to support increases of our dividend and the continuation of our share repurchase program. While we do intend to grow the absolute value of the company, as part of our value proposition, we also want to increase value per share for our shareholders through dividend growth and the reduction of outstanding shares. Accordingly, our Board of Directors authorized an over 38% increase in our common dividend and a new $3 billion share repurchase authorization, which will trigger a redemption of a portion of the preferred equity. Future cash and earnings growth opportunities could come from our shale and conventional oil & gas assets as well as our chemicals business and ultimately, our Low Carbon ventures business. Turning now to 2023. Our business plan is designed to maximize return on capital and return of capital to our shareholders while also strengthening our future sustainability by prioritizing asset-enhancing investments to support the resilience of Oxy's future cash flows. These investments include $500 million for low decline mid-cycle projects, including the previously announced modernization and expansion of OxyChem's Battleground chlor-alkali plant and a new OxyChem plant enhancement along with Permian EOR in the Gulf of Mexico. Of the $500 million that I just mentioned, we plan to spend $350 million on OxyChem projects, which upon completion, we expect will generate a combined annual EBITDA of $300 million to $400 million. We expect the Battleground project to be online in early 2026. The other OxyChem plant enhancement will deliver higher production volumes, enhanced operational efficiency and improved logistics costs. We look forward to providing more detail about this project on a future call. The remainder of the $500 million will be spent in EOR in the Gulf of Mexico. EOR remains a core component of Oxy's asset portfolio and will be essential for our future strategy, so we are glad to return to sustaining capital investment levels this year. In the Gulf of Mexico, infrastructure projects, including subsea pumping initiatives to increase the tieback radius and productivity of the existing platforms, will drive higher capital spending compared to recent years. We're also focused on our high-return short-cycle businesses. Our return to a 2-rig program in the DJ Basin late last year requires additional investment but should begin to moderate production decline by the middle of 2023. In our Permian unconventional business, we intend to run an activity program similar to the second half of last year. Our Permian unconventional assets are best placed to deliver production growth to offset marginal declines elsewhere in our portfolio. Overall, 2023 Permian unconventional capital is expected to decline slightly from 2022 due to the initial capital inflow from the Delaware Basin JV. We anticipate that inflation will continue to be a challenge for our industry this year. In 2023, we expect approximately 15% inflation impact on our domestic Oil & Gas business compared to 2022. As always, we will continue our efforts to reduce and offset inflation by leveraging our supply chain competencies and focusing on continued capital efficiency. Another important aspect of sustainability is the carbon intensity of our operations and what we're doing to address it. We focus on reducing emissions every day as we progress our pathway to net zero, and we've made significant progress over the past few years. Since 2020, our emissions reductions projects have focused on capturing methane and reducing venting and flaring. These projects resulted in a 33% decrease in our estimated company-wide methane emissions from 2020 to 2021 and a 24% decrease in methane emissions intensity of our marketed gas production. We were the first U.S. oil & gas company to endorse the World Bank's Zero Routine Flaring by 2030 initiative, and I'm pleased to announce that our U.S. Oil & Gas operations achieved Zero Routine Flaring 8 years ahead of that target. That was a major achievement. Our international operations have implemented projects to significantly reduce routine flaring, and we're on track to meet the World Bank's target well ahead of 2030. In 2023, we also intend to invest in several unique and compelling Low Carbon business opportunities to advance our net zero pathway. Ongoing construction of our direct air capture facility in the Permian and the development of our large Gulf Coast sequestration hubs, including pore space certification, will be among our expected investments. We anticipate that our first direct air capture, or DAC, plant will complete commissioning and begin to capture carbon in late 2024 and be commercially operational in mid-2025. This timing is a few months later than our original target as we navigate the current supply chain environment and focus on construction sequencing to support faster optimization and the application of new technologies and innovation. Our 2023 capital investment in these Low Carbon businesses is expected to total $200 million to $600 million, subject to third-party funding optionality for the DAC and the timing of projects. We mentioned on our prior call that our net zero ambitions will require funding outside of Oxy's historical capital allocation program. However, we are prepared to fund our first stack ourselves if utilizing our capital preserves the most value for our shareholders. Our capital plan includes investments in our carbon sequestration business, both through the development of the Gulf Coast hubs we previously announced and through drilling appraisal wells. Investments in other projects that reduce Oxy Scope 1 and 2 emissions will also continue. As part of our strategy to develop Gulf Coast sequestration hubs, we're pleased to announce that we will be working with energy transfer low-carbon development to build a pipeline network from point source emitters in the Lake Charles area through our Magnolia sequestration site in Allen Parish, Louisiana. This pipeline will support our point source carbon capture and sequestration business, which we intend to develop, along with our DACs, to help meet medium- and long-term greenhouse gas emission reduction goals for Oxy and our customers. Before turning it over to Rob, I want to reiterate that our 2023 capital plan focuses on projects that best position Oxy for long-term success. As in past years, we retained a high degree of flexibility, which allows us to adapt to commodity price fluctuations and reduce spending if necessary. Now I'll turn the call over to Rob.
Robert Peterson:
Thank you, Vicki, and good afternoon, everyone. Last year, we repaid over $10.5 billion of debt and retired all remaining interest rate swaps breaking on our balance sheet and improving our credit metrics as we seek to regain investment-grade ratings. The completion of our $3 billion share repurchase program moved us closer to returning over $4 per share to our common shareholders, which will begin to trigger a redemption of the preferred equity.
Our vastly improved financial position, even compared to 1 year ago, enables us to begin allocating a greater proportion of excess free cash flow to our shareholders in 2023. Today, I'll begin by explaining where we are in terms of partially redeeming preferred equity. I'll then detail our redemption mechanics in a scenario where the $4 trigger is met. The mandatory redemption of preferred equity is triggered with a rolling 12-month common shareholder distributions, which accumulate at $4 per share. This trigger is evaluated daily based on shares outstanding on the day capital is returned. As of today, we have distributed $3.70 per share, so additional $0.22 per share is required to reach the $4 trigger. In our presentation, we have included an illustrative example of a $100 million distribution to common shareholders after the $4 share trigger is reached. In conjunction with the common distribution, a $100 million mandatory matching distribution Berkshire Hathaway will be made, of which $91 million will redeem preferred equity principal with a $9 million or 10% premium. In this example, Oxy would incur a $200 million total cash outlay. This process of mandatory redemption repeats as long as the trailing -- per share trailing 12-month distribution to common shareholders is greater than $4. There is no limit to exceeding the $4 per share trigger through additional distribution to common shareholders. Consequently, even if the trailing 12-month distribution decline, additional distribution to common shareholders will still trigger partial preferred equity redemption. We expect our refreshed share repurchase program to combine with our $0.18 per share quarterly dividend to enable us to exceed the $4 per share trigger to begin redeeming the preferred equity. While the magnitude and pace of the partial preferred redemption and resulting enterprise value balancing will ultimately be driven by commodity prices, we expect our shareholders to benefit in a similar way to the value created in 2022 through debt reduction. I'll now turn to our fourth quarter results. We posted an adjusted profit of $1.61 per diluted share and a reported profit of $1.74 per diluted share. Difference between adjusted and reported profit was already driven by a noncash tax benefit related to reorganization of legal entities. As Vicki mentioned, our Board recently authorized a new $3 billion share repurchase program following the repurchase of approximately 47.7 million shares last year for a weighted average cost of below $63 per share. We exited the quarter with approximately $1 billion of unrestricted cash after paying $1.1 billion of debt and retiring $450 million in notional interest rate swaps. For the year, we completed over $10.5 billion of debt repayment, which eliminated 37% of outstanding principal and resulted in a sizable reduction in interest rate -- interest burden. We estimate that the balance sheet improvements executed in 2022 will reduce interest and financing costs by over $400 million per year. Our proactive debt reduction efforts leveled the company's profile of future maturities, so that we now -- so we have less than $2 billion of debt maturing in any single year for the remainder of this decade. Going forward, we intend to repay debt as it matures and may also reduce debt opportunistically. We repaid approximately $22 million in January and do not have additional maturities until the third quarter of 2024, providing us with a clear runway to focus on returning cash to shareholders and partially redeeming the preferred. In the fourth quarter, we generated approximately $2.6 billion of free cash flow, even with inflation continuing to pressure costs and capital spending. Domestic operating expenses were higher than expected, primarily due to the impact of winter storm Elliott, equipment upgrades and platform life extension work in the Gulf of Mexico and inflation. Overhead increased as a result of higher accruals related to compensation and annual environmental remediation. Capital spending in the quarter was higher than expected due to inflationary impacts, investments in attractive OBO projects, scheduled changes leading to activity in higher working interest areas and rig starts for our Delaware JV. We further improved our liquidity position as [indiscernible] Oxy became the first company ever to securitize offshore oil & gas receivables and an amendment that increased our accounts receivable facility by 50% to $600 million. In 2022, we paid U.S. federal cash taxes of approximately $940 million, in line with our previous estimate. As we move into 2023, we expect to be full U.S. federal cash taxpayer as we've utilized all our NOLs and U.S. general business carryforward credits. We expect our full year production to average 1.18 million BOE per day in 2023. As it was the case last year, production in the first quarter is expected to be lower than the preceding quarter due to scheduled maintenance turnarounds, primarily in our international operations. We'll have fewer wells come online in our U.S. onshore business in the fourth quarter, with only about 15% of our Permian wells and 6% of our Rocky wells for the year turning over to production. That said, our overall production trajectory is expected to be smoother in 2023 than in the prior year. Throughout 2022, we worked with Colorado regulators and local communities to successfully navigate the permitting process. Our work positioned us to add back 2 rigs in the DJ by the end of 2022. Given the reduced activity levels over the last few years, our Rockies production is likely to be lower in 2023 than last year. Production is expected to stabilize in the second half of 2023 once the benefits from the additional rig picked up in the fourth quarter of last year fully materialize. Setback rules in Colorado typically lead to a pad development approach with a linear time-to-market cycle as compared to simultaneous operations in other shale plays. This operating environment creates negligible additional costs for our development, but this year is expected to have a noticeable impact on time-to-market as our activity ramps up. The DJ Basin remains an exceptionally high return asset for Oxy, and we welcome the return of sustaining capital levels to that business, which was predicated by the regulatory certainty and permitting efficiency we are now experiencing in Colorado. The production sharing contract we announced last year with Algeria is expected to take effect in March. Once the agreement is in place, net barrels to Oxy will decrease by approximately 15,000 BOE per day, which is reflected in our 2023 guidance. We do not expect a material change in operating cash flow because the tax rates were also reset under the new PSC. Operating costs across our Oil & Gas business are expected to approximate the second half of 2022 as inflationary pressures remain in our lower-cost DJ Basin production declines. In the Gulf of Mexico, maintenance work to further reduce plan time -- planned downtime and extend platform lives will impact operating costs. We are also increasing EOR downhole maintenance work and CO2 purchases. On a BOE basis, operating costs may increase internationally due to lower reported barrels of the new Algeria contract. 2022 was an exceptional year for OxyChem as the business exceeded $2.5 billion in income. We expect 2023 to be another strong year by historical standards, that was unlikely to match 2022. Caustic soda prices reached all-time highs in the fourth quarter of 2022, but we are now making downward pricing pressures as the macroeconomic environment remains uncertain. PVC pricing fell sharply in the second half of 2022, but has begun to stabilize. As I've mentioned before, OxyChem's integration across multiple chlorine derivatives enables us to optimize our production mix to what the market demands. We remain optimistic about the business, and our capital investments will further strengthen our margins and competitive position. Looking forward to the rest of 2023 and beyond, we remain dedicated to extending the success of 2022 and advancing our enhanced shareholder return framework. I will now turn the call back over to Vicki.
Vicki Hollub:
We're now ready to take your questions.
Operator:
[Operator Instructions] And today's first question comes from Raphaël DuBois with Societe General.
Raphaël DuBois:
The first one is about the DAC 1 timing, which seems to have slipped a little bit with operating status now to be reached mid-2025 instead of end 2024. And I was wondering if we should consider that it's -- it means that other DACs, the ones that follow could also be delayed. That will be my first question, please.
Vicki Hollub:
No, we don't expect delays in the other DACs. The delay came because of the supply chain situation that we're experiencing today. We expect that since those are further out, we'll have more time to prepare and to address some of the supply chain challenges that we have today. So we don't expect the schedule to change.
Raphaël DuBois:
Great. And my follow-up is on the $200 million to $600 million CapEx for the Low Carbon. Can you maybe help us better understand why it's dedicated for that one? And what is left for other projects?
Vicki Hollub:
We haven't broken out the -- that $200 million to $600 million at this point. Richard, do you have anything?
Richard Jackson:
Yes. I was just going to add, I mean, to kind of help give you some color on the program. I mean, certainly, some of that is allocated as we started construction for DAC 1 this year and obviously continue on the next couple of years with our construction pace. We do continue to develop our CCUS hubs around the Gulf Coast that we've previously disclosed and we announced with the Midstream partnership today.
And then the other piece, and I think it partially answers your first question is continuing to look at our DAC Pre-FEED and FEED work as we go into the South Texas Hub. We think that's meaningful. And so while we're progressing and optimizing the schedule for DAC 1, in parallel, we're working with the same innovations and learnings and applying that to our South Texas Hub, which we think we'll be able to keep us on pace for that development as well.
Operator:
And ladies and gentlemen, our next question today comes from David Deckelbaum with Cowen.
David Deckelbaum:
I wanted to dig in a little bit more. You talked a bit about reaching this $4 per share return on capital threshold and now looking at the preferreds has this trigger as a priority. How do we think about your view on the returns of capital on retiring preferred versus, say, supplementing that with asset sales as we work through the year, especially as you get beyond the second quarter of '23 and that trailing 12 months $4 a share benefit kind of rolls off, especially from that notable lump in the second quarter of '22?
How do you think about navigating that? And should we expect you to kind of pull forward other sources of cash to try to stay above that threshold?
Vicki Hollub:
Hitting the threshold has been really not a target, but an outcome of a plan that we wanted to execute anyway. Share repurchases is such a critical part of our value proposition that this is the way it has evolved. We're not really sure what the macro is going to do towards the end of this year. So in terms of what, if any, asset sales we would do to keep the pace, that really is dependent on the value -- what value we see in doing that and what we have available.
But I would say right now, we don't have anything on the list to sell. Of course, anything we have is for sale if it's for the right price. But there's nothing that we're actively marketing right now. And we believe that the second half of the year could potentially bring a macro environment that allows us to continue without engaging in any additional asset sales.
David Deckelbaum:
That's helpful. Maybe if I could switch just to the second quickly around Low Carbon ventures and DAC. There's obviously some funding that's been made available under the Bipartisan Infrastructure Law. It seemed like you alluded to some flexibility in the budgeting around DAC for potentially other sources of funding.
Can you walk us through maybe the application process and the timeline for how we might think about any potential loans that would be coming through or when we might have some more information around other sources of funding?
Richard Jackson:
David, this is Richard. I'll try to answer a piece of that. Really, two pieces, as you described. I mean we continue to have good discussions with capital partners, not only for DAC 1, but as we look at capitalization over the life of our development plan. And so that's an important part that we want to stay fresh with.
The second part is, as you mentioned, some of the grant programs that are directly associated with CCUS and DAC specifically. We're not in a position to talk in detail on that today, but we are -- and have communicated before, we think our projects fit very well the intent of that program. We think the -- really the advanced design and really state that we're in as we go into DAC 1 and then into the South Texas Hub puts us in a really good position for that type of program. I think the South Texas Hub, as you look at that, in particular, is just a unique opportunity to look at sort of the large-scale build-out when we've contemplated the 30 DACs for that area. So to directly answer your question on updates, I think we'll have more as we go this year, but we'll leave it at that for now.
Operator:
And our next question today comes from Jeanine Wai with Barclays.
Jeanine Wai:
I have two questions, I guess, around the Permian, if we could. The first one, maybe on inventory. The second one on sustaining CapEx. On inventory, we compared your updated slide versus the prior version. And after adjusting for wells to sales in '22, it looks like the location count for the wells that break even for under $60. It really isn't all that different, which implies about a 16-year inventory at the current pace.
So just wondering if you can talk about any of the differences in assumptions between the old and the new inventory calculations, whether it's on cost or on development strategy? For example, we saw in the footnote there that your updated inventory uses the '22 budgeted well cost. And how different would that look if you used current costs?
Richard Jackson:
Great. Jeanine, this is Richard. I'll try to help answer a few of those. I mean very proud of our inventory, obviously good acreage position that we have and have accumulated, but very pleased with the team's ability to continue to advance that. So as you noted, especially in Permian resources, strong less than $60 breakeven with long activity. I'd say some of the changes that have occurred, we tried to highlight one even in that slide is really thinking about longer laterals. So able to continue to core up acreage where we're at, be patient in development areas to allow that to happen and really sequence our developments to accomplish the longer laterals.
So as we were able to do that, obviously, that may go down one, but we've made a much more valuable single well inventory. The other thing I would say is just really the environment over the last couple of years. As we restated capital or began to put capital back into the program since 2020, that's allowed us to really develop some new areas and zones. So for example, the First Bone Springs wells that we noted, very proud of those. What happened during that underinvestment cycle, we continue to work the technology and the development plans to really advance those zones. And so those type advancements in areas and zones like that also are adding to our inventory. But that restoration in capital, we believe this year especially will allow us to further advance our inventory. For example, we have 40 target wells in 2023 that we believe will fully replenish the wells we drill this year. And so we're pretty thoughtful in terms of how we're expanding that and approaching that inventory. And so hopefully, as we go, that will continue to grow in the Permian. But even in areas like the Powder River Basin, we're resuming some activity this year.
Jeanine Wai:
Okay. Great. Moving to the sustaining CapEx. In the $3.5 billion sustaining CapEx estimate, how much of that is allocated to the Permian? And does that keep Permian production flat versus '23 levels? We know Oxy has got a ton of different operating areas, and there's a lot of different ways to keep production flat there?
Vicki Hollub:
Yes. When we think about sustaining capital levels, it's really how do we maximize the return on capital employed for each of the assets that we have, while ensuring that we could do that for -- on a multiyear basis. And for example, when you talk about the Permian, there's the resources part of the business and the EOR part. The EOR part, the way we've been able to maximize return on capital employed for it is to actually keep the facilities fully loaded all of the time.
So we're not -- we don't have unused capacity and keeping those facilities fully loaded requires a certain level of capital. We certainly have the potential to continue to grow the EOR business beyond that. But up to this point, that's what we've been able to do to get the most value out of it. The Resources business, combined with the EOR business, would require about $1.8 billion for sustaining capital. And this year, we did increase the EOR and that's part of the reason to do that is that the lower decline of our EOR business, the lower decline of the chemicals business and our gas flow assets in the Middle East, those are critically important to us. And as you know, we're expanding Al Hosn, which will not very -- not by very much will that increase the sustaining capital there, but will provide us additional low decline cash flow from that asset as well. And that's what we most like about our portfolio is that this diversity of having the lower decline assets combined with the higher decline, but higher cash flow generating assets at least initially is very complementary. So we have the best of all worlds, I think, in the diverse portfolio that we have.
Operator:
And our next question today comes from Matt Portillo with TPH.
Matthew Portillo:
Just maybe to start out, I was hoping to see if you could give us an update maybe how things have progressed since the LCV Day on the point source business, maybe some of the conversations you're having with the IRA Bill coming out? And any color that we may be able to look through on when the first project might start up and how you guys are thinking about kind of the total volumes you've secured so far for sequestration on point source.
Vicki Hollub:
Okay. Thank you for the question. I'll pass that to Richard. .
Richard Jackson:
Yes. Great. Matt, I think things for many of us in CCUS and certainly in the U.S. are progressing well post IRA. I think lots of work going on with emitters to transport to sequestration. Our focus really has been sort of similar to oil & gas, really working to secure the best sequestration sites and develop those in a way to be both large scale, so we can get the economies of scale, but also be able to provide that certainty as these deals are putting together.
So we have really 5 hubs that we're working that we've talked about. We've got several Class VI wells in progress as well as characterization of these sites. The Midstream providers are very important. And so being able to secure those partnerships early, I think, aligns really the downstream from the capture site to be able to do that. So as we think about sort of how this plays out over the next couple of years, we're hopeful that as we go this year more projects will be able to combine that capture to transport the sequestration and really hit FID and then begin construction over the next couple of years. I think our work even going back to some of the work that we've done in the Permian over the last several years around some of the capture projects there really helped inform us, hopefully, as a good partner about how do you manage that kind of across the value chain. And so our focus is, again, really on that sequestration. That really puts us in a good position to take together the synergies with DAC as we develop that. And so we're playing that role and having good conversations towards those projects. And again, expect this year to have more updates.
Matthew Portillo:
Great. And then as my follow-up, just around OxyChem, a strong start to the year with the Q1 guide. Just curious how you all are feeling about the outlook for caustic and PVC and maybe what's baked into the guidance expectations as we progress through 2023?
Robert Peterson:
Yes, sure, Matt. So we -- and the theme for the year was domestic PVC demand was actually down about 6.8% in '22 relative to '21. But what we did was we saw as an industry that export demand ended up being about 46% higher, so the total PVC demand actually grew about almost 7% year-over-year in '22. And so when looking into what's going on and what's in our guidance is we saw that softness in PVC through the fourth quarter, but it appears that bottomed out late 2022, early 2023.
So all PVC buyer adjustments we believe were largely completed as prices were falling. And we believe, as we sit here today, that many buyers inventories are low as we enter the construction season. We've also seen PVC export prices not only bottomed but are actually starting to trend upward most recently. And in the domestic market, all the producers have independently announced price increases in the domestic market for PVC. So thinking about the guidance in PVC, it reflects the uncertainty of the trajectory of the domestic and global economy that's going to drive that business. And so while there's still this huge pent-up demand we see in construction and the low inventories, there's still headwinds from the impact of the higher interest rates, which now may not peak as early or begin to subside as quickly as anticipated. And of course, the pace of economic activity increases in China is just going to continue to be an impact to the PVC business globally impacting trade flows for PVC. So that's what's factored into this kind of murky outlook for PVC. The caustic soda business, we saw export prices, I discussed in my early comments in export are declining, not just from the impact of the global economy from the China taking, again, longer to restart, but also European markets stocked up significantly on caustic soda as we went into winter. That certainly has started to loosen now. We've gone from tight market conditions to looser market conditions with operating costs come down dramatically in Europe as energy prices have fallen. Our guidance on the caustic side of the business, this assumes it's going to take time for this unwinding of European inventories and a gradual opening of the Chinese economy. So -- but again, I would say, as we've talked in the past, our chemical business is so heavy weighted in domestic construction and global GDP. We're going to know a lot more about the total trajectory of the year than we do and -- sitting here in February than we will, maybe in May or June at that time. We've got a couple more months to look at it. So Overall, that guidance for the year just reflects that uncertainty around both sides of the business at this point.
Operator:
And our next question today comes from Doug Leggate with Bank of America.
Douglas Leggate:
First of all, apologies. I was a little late getting on, so I hope my questions haven't been asked already, but a lot going on today. Vicki, I want to ask you about the Gulf of Mexico trajectory and the cash operating cost. It seems to me at least that this is an area where we've always had a little bit of -- it's been a bit murky to understand just what the decline in the development backlog looks like from the legacy Anadarko portfolio.
But it seems that you are doing a lot better on the production guide and the trade-off maybe is a little bit higher OpEx. Can you give us your latest thoughts on what you see as the trajectory longer term for the Gulf?
Vicki Hollub:
Our plan for the Gulf of Mexico is to continue to keep it at around the production rate that it's at right now. It's, as you know, a significant cash flow generator for us. So we have the inventory, and we have the plan laid out to ensure that we can -- we have the development ready to maintain the current level of production where it is. We don't intend to significantly grow production. That could be part of the outcome of what some of the exploration and development will lead to.
But it's our intent and it will be lumpy. As we've said before, capital there will depend on our exploration successes, how those go and timing. But on the average, our production level should be about where it is today.
Douglas Leggate:
For what period?
Vicki Hollub:
I would say that we just picked up some leases, as you know. We're now doing the preliminary work on those leases. I would say that our trajectory is certainly between -- somewhere between 5 and 10 years of potential inventory to maintain what we have today.
Douglas Leggate:
That's helpful. My follow-up is a favorite question mine though I hate to be predictable. But I want to ask you about your breakeven, but new onset a little bit. Obviously, we've had some inflation, your breakeven capital. What you've recognized today? And I guess, what I'm really trying to understand is how you think about dividend capacity as part of that breakeven, let's say, it's $40. Has that become like a ceiling for your dividend thoughts? And I guess the clarification point, if I may, Vicki, there's been a lot of questions today about DAC, obviously. When you think about that breakeven, are you including the capital or sustaining capital for the DAC business as well?
Vicki Hollub:
Well, certainly, I would say that we are not including the capital for the DAC as a part of our breakeven or sustaining capital. If we were in a scenario where we were down in a $40 environment, unless we had significant capital inflow from somewhere else, we would significantly cut back our development on the DACs unless that development was supported by others.
So I would say that when you think about the breakeven for us and I kind of wish we had never brought that term up because it's so misleading to people. We -- I would say the difference in where we are today and where maybe we've been in prior times is that we keep a model of what it's going to take to support our dividend at various oil price levels. And what we've said is still true that we want to ensure that we're close to a $40 breakeven or less so that if we're in that environment that we can still sustain the dividend. I never want to go through a scenario where we would have to cut it again. But what that breakeven really is, is what would the price and the world look like at $40. So you can't take our numbers right now and back in to what it would be and expect it to be $40. We've obviously elevated our capital investment higher than what it would be, what the calculation would show the breakeven is today. So breakeven for us means that if you're in a $40 environment, then the supply chain, the services and materials, all of those things would be adjusted to that kind of environment, to that cost. And in that environment, our cost would then be less than it is today on OpEx and even labor cost, services materials. So in that environment, we look at what would it take to ensure that we could sustain our dividend growth. And that's how we would calculate that. So -- and that -- and sustaining capital is different. As I explained earlier, sustaining capital is where you have every asset with the investment level at the point where you're generating the best returns that you can generate from the infrastructure and facilities that you have and the resources that you have. So with what we're doing today, as we continue to reduce our cost structure, as we continue to lower our interest from our debt reduction, and we've -- as we will buy back some of the preferred, we'll lower that cost as well. We use those two measures as the primary way we can calculate how much we can grow our dividend. So as we're continuing to reduce interest, as we're continuing to reduce the preferred dividend, that will be the capacity available for the growth of the dividend. And to further get it to increase it on a per share basis, our share repurchase program is intended to help with that as well. So it's an absolute number cap that we have as well as a share repurchase program that allows that dividend per share to continue to increase over time.
Operator:
And our next question today comes from Paul Cheng with Scotiabank.
Paul Cheng:
Two questions, please. If -- I have to apologize. I want to go back into the inventory. That number, how that will change for those that is -- for less than $50 WTI and we changed the Henry Hub gas price to 2 50 and the internal way of return to, say, 15%, 20% and also for the cost, I mean how that is going to get changed? That's the first question.
And the second question that I think a lot of your peers that -- or at least some of them have signed the LNG supply agreement and one of your largest peers actually make an investment -- equity investment in the LNG plan. Want to see if Oxy think that, that will be a suitable investment for you? And what is the game plan there?
Vicki Hollub:
I'll take the LNG question first as Richard is pondering the other question. The LNG question, one of the things that we've always tried to do is make sure that we do things that are within our core competence. And so our core competence is getting the most out of oil & gas reservoirs and handling CO2. So LNG is not something that we would want to be a builder of. And if it's something that we don't want to be a builder of or use as a part of our strategy in our oil & gas development and our Low Carbon, if it's not a part of that, that's not something that we would put our investment dollars in. We're not going to go too far from what we know how to do the best.
Richard Jackson:
Paul, this is Richard. I can try to answer your question on the inventory. I mean, as you think about sort of a discount rate against that inventory, obviously, if it's higher, that would change the numbers a bit, but we are still very strong in that inventory. For example, in the DJ, as we think about that program and we look at gas price fluctuations, we look at plus 50% type program returns even at a lower gas price than what we show there. So it will impact things.
But I think in terms of the strong returns that we have well exceed sort of our expectations on return on capital. And we continue to manage that inventory to drive really what we develop into those lower breakeven categories. Probably the other thing to say on that, basically, the inventory this year with the wells that we drill are all less than $40 breakeven. So we've been able to high grade ahead of time to make sure that we have sustainability of those returns. And as I mentioned earlier, the wells that we targeted to replenish 100% of our drilled wells this year, we'll expect to carry that same result.
Operator:
And our next question today comes from Roger Read with Wells Fargo.
Roger Read:
I'd like to follow up really, I guess, on the Gulf of Mexico, maybe secondarily, on the EOR side. Relative capital discipline or maybe even aggressive capital discipline over the last couple of years for the obvious reasons. Just wonder how you're comfortable in terms of the outlook for the Gulf and also for EOR, just that whatever your base declines are now, any sort of catch-up capital maybe to maintenance or anything like that, but that sets you up for flat in the Gulf and maybe flat-to-growing in the EOR over the next couple of years. Just what you did to get comfortable with that outlook?
Vicki Hollub:
I think just starting to restore the capital to both of those assets has been helpful. And it was basically all that we needed to do. One of the things that we never stopped doing was investing and making each of those operations better. And that's why a little bit of the increase in OpEx is making in the EOR business getting some of the wells that had gone down during the pandemic, putting those wells back online, which increased our well maintenance budget, but those are very inexpensive and high-return barrels.
So starting to do that. And we didn't shut down any kind of maintenance around the infrastructure, and no kind of decreases in capital around the maintenance of our equipment. So really, it was more from the standpoint of just getting wells back online for EOR. And in the Gulf of Mexico, we've taken the opportunity to work on the -- not only the surface to ensure that we could increase our run time there with reduced capital and not being as aggressive with drilling wells out there, we were still improving productivity by spending dollars on improving run time and also putting in subsurface pumping equipment to expand the radius of our spars and to also increase productivity and extend our reserve lives out there. So the work that we've done in the Gulf of Mexico has really kept us prepared to get back to sustaining levels, both in the Gulf and EOR, without any sort of issues beyond the next year or 2.
Roger Read:
Okay. And just as a quick follow-up. Any issues with permitting anywhere on federal lands or in federal waters?
Vicki Hollub:
I'm sorry, what was that? Permitting...
Roger Read:
Yes, permitting since you're not so much federal onshore, but federal offshore.
Vicki Hollub:
Federal offshore, we've had -- not had issues permitting thus far. Even when the permitting moratorium came out, we were able to still get things done and get things approved. And so I don't see the permitting point to be an issue for us offshore at this point.
Operator:
And our next question today comes from John Royall with JPMorgan.
John Royall:
So just looking at your guidance for domestic OpEx per barrel in 2023. It looks like it's up about 6.5% from last year. And more in line with the 2H of '22, which I think Rob said in the prepared comments. Just comparing that with the 15% inflation on the capital side, can you talk about the gap there on why the OpEx inflation rate is so much better than the CapEx inflation rate?
Vicki Hollub:
Yes. I'll just reiterate the comments I made about the GoM and then Richard's got some information on onshore. But for the Gulf of Mexico, as I was saying, some of the work that we did was just to prove up our ability to increase our run time there. And that in and of itself is going to increase your OpEx a little bit this year and a little bit for next year, but it's delivering in terms of barrels because, as you've seen, the Gulf of Mexico has helped to offset some of the declines from other areas and some of the storms. So we're better prepared offshore now for higher productivity. Richard, do you have some on the permits?
Richard Jackson:
Yes. Maybe just a little bit on onshore OpEx. I mean, one major difference when you look at capital and that 15% and then kind of what we're seeing in OpEx is OCTG. While we have some exposure to that in our kind of maintenance activities, it's far less pronounced, and that was the single biggest category really last year for us.
So really, OpEx, it's been a couple of things. We break it down into inflation and then scope. And scope would be some of the maintenance activities like Vicki's describing for the GoM. So really 2022 from an OpEx perspective, U.S. onshore, most of it was really WTI or kind of price indexed inflation, things like power, CO2 price ruts which were a little unique there, gas processing, things like that. And really scope was pretty well managed. We -- our maintenance activities picked up a bit at the end of the year, mainly downhole maintenance and EOR. As Vicki said, as you go into 2023, it's much more balanced. If you see the increase, there is a little bit of kind of inflation carryover in terms of processing and CO2 volumes are up a bit this year for EOR as we've resumed activity there, but it's a lot more scope. So as we begin to resume production activities, water management, compression, these type of things show up. But by and large, we've been able to hold that cost structure for OpEx pretty well. We go back really to kind of first quarter '20 and look at those type of run rates, and we've been very good holding our cost structure since that. Probably the last thing I'd say kind of to the maintenance activity similar to the GoM, for us, in U.S. onshore, it's a lot about uptime improvement. So continuing to work with a third-party gathering and processing companies and then within our fields to be able to be resilient through weather and just sort of manage this production in a good way. So adding that uptime adds significant value to the year. And so some of our OpEx-related activities have been focused there as well.
John Royall:
Great. And then next one is just on the quarterly progression of production. And apologies if I missed something here, but I see that the midpoint of production guidance stays the same in 1Q versus the full year. But you do have the Permian ramping and you have the Al Hosn project starting later in the year. So what are some of the moving pieces there that are kind of pulling things the other way? And then how do you expect production to progress throughout the year?
Richard Jackson:
Maybe I'll start just kind of a U.S. onshore perspective. Permian being able to ramp up to the end of last year and really secure the resources by the end of the year puts us in a much better position for sort of steady-state growth. However, the first quarter, as we noted, is a little lumpy. We had about 40% less wells online versus kind of other quarters in the year or even against fourth quarter. It's a little lumpy on the Permian.
And then really the moving part is the Rockies. We've been underinvested from sustaining capital over the last several years. And so as we talk, we're resuming some activity there. We have about fourth quarter '22 to first quarter '23 about a 15,000 barrel a day decline and that sort of steadies out into the second quarter. And then we actually start growing in the Rockies in the second half of the year. And so that, from an onshore perspective, is a big part of that moving part. And then the other one is really our GoM weather assumption. So I think that's the other piece to consider when you look at the trajectory on total.
Vicki Hollub:
Yes. In total, as Richard mentioned, GoM will be down a little bit, international up a little bit as Al Hosn comes on and comes on stronger towards the end of the year.
Operator:
And ladies and gentlemen, in the interest of time, this concludes our question-and-answer session. I'd like to turn the conference back over to Vicki Hollub for any closing remarks. .
Vicki Hollub:
Thank you. I'll first by expressing my gratitude to our amazing teams for their diligent focus and pioneering work that contributed to so many advancements in our core cash generating and emerging Low Carbon businesses . So much appreciate all that you do and for always going above and beyond. Thank you all to the rest of you for joining our call today and for your questions. Have a good afternoon.
Operator:
Thank you. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.
Operator:
Good afternoon, and welcome to Occidental's Third Quarter 2022 Earnings Conference Call. [Operator Instructions] Please note, today's event is being recorded.
I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead, sir.
Jeff Alvarez:
Thank you, Rocco. Good afternoon, everyone, and thank you for participating in Occidental's Third Quarter 2022 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good afternoon, everyone. We delivered another strong quarter operationally and financially, enabling us to further advance our shareholder return framework as we made meaningfully -- meaningful progress toward completing our $3 billion share repurchase program. We achieved our goal of reducing the face value of our debt to the high teens and plan to continue repaying debt through the remainder of this year before allocating a higher percentage of cash flow to shareholder returns next year.
The excellent operational performance of our businesses was a key driver of our strong financial results, including generating the cash flow required to advance our shareholder return framework and further strengthen our balance sheet. OxyChem delivered strong earnings following a record second quarter, while our Gulf of Mexico, International, Rockies and Permian teams set new operational records. This afternoon, I will cover our third quarter operational performance and the exciting progress our Low Carbon business has made since our investor update in March. Rob will cover our financial results as well as our updated guidance, which includes an increase in full year guidance for all 3 of our business segments. Our businesses all performed well in the third quarter, enabling us to generate $3.6 billion of free cash flow before working capital, with total company-wide capital spend of approximately $1.1 billion. Our oil and gas business delivered production of nearly 1.2 million BOE per day, exceeding the midpoint of guidance by approximately 25,000 BOE per day. Outperformance from the Rockies and Gulf of Mexico were key drivers of our production exceeding third quarter guidance. The Rockies' success was driven by better-than-expected base production and higher NGL recoveries. In the Gulf of Mexico, we benefited from unseasonably calm weather during most of the third quarter and better-than-expected performance from Horn Mountain West. Our ability to generate substantial free cash flow, even as oil prices declined compared to the previous quarter, positioned us to complete approximately $2.6 billion of our $3 billion share repurchase program through November 7. Over the last 12 months, we have returned approximately $3.21 per share to common shareholders moving us closer to potentially being able to begin redeeming the preferred equity in 2023. We also repaid approximately $1.5 billion of debt in the third quarter and in the period ending November 7. Providing commodity prices remain supportive, we intend to reduce the face value of our debt approximately $18 billion by the end of this year, meaning that we will have repaid over $10 billion of debt in 2022. As we enter 2023, we expect that our free cash flow allocation will shift significantly towards shareholder returns. We intend to reward shareholders with a sustainable dividend supported by an active repurchase program, continued rebalancing of our enterprise value in favor of common shareholders, and a reduction in our cost of capital as the preferred equity is partially redeemed. Turning to OxyChem and Midstream. Both businesses benefited from supportive market conditions during the third quarter. OxyChem exceeded its guidance since chlor-alkali prices continued to strengthen and the expected softening in the PVC markets did not materialize to the extent that we had forecast. We continue to be highly encouraged by well performance across our portfolio. In the Delaware Basin, we delivered our best quarter to date for early well performance with the 46 wells online averaging peak 30-day rates of over 3,600 BOE per day, demonstrating the superior quality of our inventory and subsurface expertise. And in the Texas Delaware, we recently brought online a new Silvertip well with the highest initial oil production of any horizontal well previously drilled in the lower 48. The Python 13H well posted a 3-stream IP of almost 20,000 BOE per day and averaged over 11,000 BOEs per day over its first 30 days online, which we believe to be the strongest performance ever for a Permian well. Overall, the Python development has outperformed expectations, and we're looking forward to developing the offsetting areas over the next few months. We're beginning to see additional progress in Colorado's new permit approval process. In August, we received approval from the Colorado Oil & Gas Conservation Commission for the state's first comprehensive area plan under the recently implemented regulations. This plan has paved the way for us to complete more than 200 new wells in Wells County over the next few years. Also, several drilling permit applications that had been pending for a period of time were recently approved, allowing us to add back a rig in the DJ Basin after reallocating 1 earlier this year. With the permits we have in hand and our expectations for future approvals, we have enhanced our flexibility as we formulate our activity for next year. Last quarter, we celebrated first oil from our new discovery field in the Gulf of Mexico, Horn Mountain West. While it's exciting to realize production from new discoveries, our existing fields have abundant potential that we continue to unlock with innovative technical solutions like subsea expansions. For example, our Caesar-Tonga field recently reached a production milestone of 150 barrels of cumulative oil production since the start-up 10 years ago. Caesar-Tonga is a subsea tieback to the Constitution spar and is one of the largest fields in the Outer Continental Shelf. This impressive achievement is the result of the collaboration and hard work across Oxy's Gulf of Mexico business unit including the asset development teams and offshore personnel, who focus on delivering safe and efficient barrels every day. In the years ahead, we plan to continue maximizing production capacity through projects like this one. The Caesar-Tonga subsea expansion, which is scheduled for start-up in the first quarter of next year, will address facility bottlenecks and maximize production capacity from the field, while signaling a transition into the next phase of field development. In the second quarter, I highlighted new production records at Al Hosn in the UAE and Block 9 in Oman. I'd like to congratulate our Al Hosn and Oman teams again this quarter for breaking those recently set records. We're beginning to benefit from incremental production from Al Hosn and are pleased the expansion project is on track for completion in the middle of 2023. Turning to our Low Carbon business, I'm pleased to share that we broke ground on the world's largest direct air capture plant in Ector County, Texas. The first stage of construction, which includes site preparation and road work began in September. Plant start-up is expected in late 2024. During our March LCV Investor Update, we provided an overview of the expected revenues and costs for both direct air capture and point source capture projects. Just then, we had experienced progress on legislative and commercial fronts. Congress passed the Inflation Reduction Act, which contains several enhancements to the 45Q tax credit that will incentivize the development of carbon capture projects. Additionally, strong interest from potential customers has provided us with a clearer picture of the market for carbon dioxide removal credits or CDRs, and net zero oil in addition to other products. We believe our low carbon strategy, combined with the ability to leverage direct air capture or DAC, for the benefit of ourselves and others, uniquely positions us to lead the market in supplying CDRs to the thousands of businesses that have established net zero ambitions. We are encouraged by the passage of the IRA and previously highlighted the potential for the 45Q enhancements to accelerate our low carbon strategy. We expect the 45Q enhancements to jump start the voluntary market for CDRs, which gives us confidence to increase the number of DACs in our current development scenario from 70 online by 2035 to approximately 100. Equally as important, we expect the accelerated development of direct air capture will enable us to reduce plant capital and operating costs at a faster pace. In March, we provided a capital cost for the first DAC plant of $800 million to $1 billion. Given the inflationary pressures felt across the economy, especially for construction materials and labor, we now expect the first plant to cost approximately $1.1 billion. The current inflationary environment will not last forever, and we will leverage our supply chain and major projects expertise wherever possible, to lower the cost of our first direct air capture as well as the ones to follow. The U.S. has taken a leadership role in moving towards net zero making it more accessible for companies to meet their net zero commitments through the utilization of CDRs. Our long-term view on the potential of direct air capture has not changed, but to reach the net zero development scenario of 135 DACs described in our March update, the rest of the world will need to rise to the challenge in the form of global policy support. We're already seeing evidence of this, such as the PACE program recently announced in the UAE, which will catalyze $100 billion in financing and investment. The Permian location of our first direct air capture will provide us multiple options to maximize the value of captured CO2. We have the ability to inject the CO2 into a saline reservoir producing CDRs or to utilize the captured CO2 to produce net zero oil from our enhanced oil recovery assets. Our conversations with many corporate partners and potential clients have highlighted the significant demand for CDRs generated through CO2 sequestration. To meet this demand and advance our own net zero ambition, we plan to develop several hubs along the U.S. Gulf Coast, where we will have the option to develop direct air capture, provide point source capture and sequestration for industrial emissions or offer both solutions. To advance our ability to provide sequestration services and generate CDRs, we have filed applications for 2 Class VI sequestration permits and plan to file applications in the near future. We recently secured 2 new locations for the large-scale development of sequestration hubs. The first location covers 65,000 acres in Southeast Texas with up to 1.3 billion tons of CO2 sequestration capacity that could support up to 20 DACs. We also reached a lease agreement with King Ranch, the largest privately held ranch in the U.S., to build up to 30 DACs and develop point source capture infrastructure. Our agreement covers approximately 106,000 acres, which is about 166 square miles with the capability to safely and permanently sequester approximately 3 billion tons of CO2. We expect to develop our second DAC at King Ranch and plan to start the pre-feed before year-end. These 2 new locations are in addition to the 3 hubs focused on point source capture that we're also developing. We have secured almost 100,000 acres in Southeast Texas and Louisiana capable of safely and permanently sequestering approximately 1.9 billion tons of CO2. In total, we have secured over 260,000 acres capable of sequestering almost 6 billion tons of CO2 compared to the target we communicated in March of securing approximately 100,000 acres by the end of the year. NET Power recently announced a plan to develop and build the world's first utility-scale natural gas-fired power plant with near zero atmospheric emissions. The plant will be located close to Oxy's operations in the Permian and will supply our operations with clean, low-cost on-demand power. CO2 generated by the power plant will be used -- will be captured and permanently sequestered underground using our existing CO2 infrastructure. This plant will accelerate Oxy's plans to reduce carbon emissions to help us achieve our net zero ambitions. This first utility scale plant will enable both Oxy and NET Power to develop best practices that use NET Power's technology to provide emission-free power for our Permian operations and future direct air capture sites. I'll now turn the call over to Rob, who will walk you through our third quarter results and guidance.
Robert Peterson:
Thank you, Vicki, and good afternoon. In the third quarter, our profitability remained strong as we posted an adjusted profit of $2.44 per diluted share and a reported profit of $2.52 per diluted share, even as commodity prices declined from the recent high set in the second quarter. The difference between adjusted and reported earnings was primarily driven by a gain on sale and a tax benefit related to foreign restructuring, partially offset by early debt extinguishment cost and mark-to-market adjustments.
As Vicki mentioned, we made substantial progress towards completing our $3 billion share repurchase program in the third quarter. We have repurchased almost 42 million shares through November 7 for approximately $2.6 billion with a weighted average price below $62 per share. We intend to complete the share repurchase program by year-end and allocate any additional cash flow this year to reducing debt further. During the quarter, approximately 7.4 million publicly traded warrants were exercised, bringing the total number exercise as of September 30 to almost 12 million with approximately 104 million remaining outstanding. The warrants were a cash exercise instrument, meaning that Oxy received a cash payment from the warrant holder upon exercise, which provides them with an additional source of cash to purchase shares and reduce debt. We are very pleased to have completed our near-term debt reduction goal of lowering debt to the high teens. In addition to having repaid approximately $9.6 billion of debt year-to-date, we also retired $275 million of notional interest rate swaps in the third quarter for approximately $100 million in cash. We exited the third quarter with approximately $1.2 billion of unrestricted cash on the balance sheet and as of November 7 have reduced the face value of our debt below $19 billion. We have provided notice that the $340 million note due in February will be called on November 15, meaning that we will have less than $23 million of debt due next year. We also intend to retire the remaining $450 million of notional interest rate swaps this year, which we expect to require approximately $150 million in cash at the current interest rate curve. As I mentioned on the previous call, we believe reducing the face value of our debt to high teens will accelerate our return to investment grade. We have made outstanding progress over the past 2 years to meet this objective, but understand that we cannot determine the timing of any potential ratings change. The combined impact of improving our balance sheet and reducing debt this year alone is estimated to result in a total annual interest and financing cost savings of over $350 million on a go-forward basis. Debt reduction will remain a priority, but we intend to notably redirect our cash flow priorities next year from proactively reducing debt to returning additional excess cash flow to shareholders. Over time, we intend to reduce gross debt below $15 billion. As Vicki mentioned, we are raising our full year guidance across all 3 business segments due to outperformance in the third quarter and improved expectations for the remainder of the year. Starting with oil and gas, we have raised our full year production guidance by 5,000 BOE per day to 1.16 million BOE per day for 2022, while our full year capital guidance remains unchanged. But we continue to expect to finish the year on the high end of our capital range. Our production has increased steadily each quarter of this year, which has always been expected outcome of our 2022 plan, in part due to ramp up activity in scheduled turnarounds in the first quarter. We expect this trajectory will continue in the fourth quarter with production exceeding 1.2 million BOE per day. Our Permian operations were impacted by higher-than-expected third-party downtime and lower OBO volumes during the quarter. Our strong well performance continues to exceed our expectations, but due to third-party issues in the quarter, our Permian production came at the low end of our guidance range. We have revised our fourth quarter Permian guidance down slightly from the implied guidance we provided last quarter, as our third quarter exit rate was lower than anticipated. We expect strong performance in the Gulf of Mexico and Rockies that more than offset the updated Permian projection. As our 2022 plan anticipated an increase in activity throughout the year, our fourth quarter capital spend is expected to be higher than prior quarters this year. The activity that was added in the second half of this year will place us in a strong position for 2023 as our Permian production will grow by over 100,000 BOE per day in the first quarter. Our fourth quarter production is expected to grow approximately 18% from the fourth quarter of last year. OxyChem continues to perform well, and we've raised our full year guidance to reflect third quarter results as well as an improvement in our expectations for the fourth quarter. Fundamentals in the caustic soda market continue to be supportive, while softening in the PVC market has occurred at a slower pace than previously expected. We expect the fourth quarter to reflect seasonal trends that are typical for this business, but did not materialize in 2020 or 2021. The seasonal slowdown in construction activity towards the end of the year typically reduces demand for chlorovinyl products, which we have reflected in our guidance. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. As we said during our March investor update, achieving our net zero ambitions will require funding outside of Oxy's historical capital allocation program. As the construction phase and technology of our first stack project advances, we will continue to consider strategic capital partnerships and structures to address financing. While we are prepared to fund the first stack plant ourselves, if necessary, we are working to derisk the construction phase and commercialize the technology to attract financing structures that will retain the most value for our shareholders.
Finally, we understand that there's a high level of interest in our 2023 capital and activity plans, which we will communicate on our next call once our plans are finalized and approved by the Board. As we formulate our plans for 2023, we will focus on retaining a high degree of flexibility in our capital and spending plans, allowing us to adapt and maximize opportunities in a changing macro environment as we do each year. Before we go to our Q&A, I'd like to thank Jeff Alvarez for his leadership with our Investor Relations. I'm sure you would all agree, he's done a tremendous job to not only share our story and to help you all understand our strategy and results, he's also provided critical support to our leadership team. We appreciate what Jeff has done with Investor Relations and what he will do for us in his new role that he's recently accepted. That role is to become President and General Manager of [ Sequest ]. In this role, Jeff will lead the efforts to build our CO2 sequestration business. As you've heard in my script, this is a growing and important part of our low-carbon strategy. Jeff's 30 years of engineering and leadership experience working in domestic and Middle East operations and his proven track record of creating value will be needed for this emerging business. I'm happy to announce that Neil Backhouse will replace Jeff as Vice President of Investor Relations, reporting to Rob. And you all know, Neil, in addition to Investor Relations, his diverse expertise includes experience in treasury, finance and banking. Prior to joining Oxy, Neil worked as a corporate banker focused on oil and gas clients for 2 high-profile international banks. He holds BS from Colorado State University, a post graduate degree of Financial Services and a master's degree in International Business, both from the University of Manchester. I give tremendous thanks to Jeff Alvarez for his highly favorable contributions he's made to the finance organization, and please join me in extending your support to Neil and wishing him success as he transitions to his new role. We'll now open the call for your questions.
Operator:
[Operator Instructions] Today's first question comes from Doug Leggate with Bank of America.
Douglas Leggate:
I appreciate all the commentary. Vicki, I know you don't want to give too much away on the capital program for next year, but I wonder if you could help us with the starting point. We ask you often, I guess, maybe you get a little tired of the question, but on what your sustaining capital is for your upstream business. But obviously, there's a lot of moving parts, particularly inflation and then, of course, your higher productivity that you showed with the pipeline well this quarter. So as a starting point, where do you see your sustaining capital going as you look into 2023?
Vicki Hollub:
The challenge with that, Doug, is that we really don't know what 2023 is going to look like from an inflation standpoint. And we can talk a little bit later about what we expect the inflation to be if people are interested in that. But the way you should think about our capital, all we can tell you is kind of what we see from an activity standpoint.
And that would be and we've mentioned before that we're not going to try to grow our oil and gas production from 2022 to 2023. We're going to hold that flat. We've -- for the past couple of years, there have been a couple of business units where we weren't at their sustaining capital. So we're going to return to the sustaining capital of Permian EOR and the Gulf of Mexico. And I think you've heard that number for Gulf of Mexico before is around $500 million. And that means $500 million on an annual basis. And for EOR, it's $400 million on an annual basis at least, it could be closer to $450 million. So those are 2 assets that will need to increase more in 2023. In addition, you will see higher than sustaining capital with a couple of projects that we find very interesting for next year, one being a membrane conversion project at the Battleground plant, because, as you know, we talked about it last quarter, it increases the capacity of Battleground by 80% and delivers about $250 million to $350 million incremental EBITDA, while generating a strong return, and we have the expansion of Al Hosn to 1.45 in 2023. So adding those projects also will impact our sustaining capital to some degree on a go-forward basis. But both of those projects generate pretty good returns. But if you add the final thing, the inflation part of it, that's where for us, it gets very murky, because we're really not sure what inflation is going to be next year. And not knowing that, it's really hard to now give out what a sustaining capital would be until we get closer to that.
Douglas Leggate:
Okay. I understand it's a tough one, but thanks for framing it for us. My second -- my follow-up question is, and I guess it would appropriate to thank Jeff also for all the field trips we had over the years at Permian. But I do want to reference a couple of slides in your deck. One on Slide 23 and one Slide 25. And what I'm trying to understand is, I mean, it's a remarkable continued improvement in productivity of your well portfolio, but should we think of what we're seeing in Slide 23 as kind of the new normal that's consistent with the inventory depth on Slide 25? I'm just trying to reconcile those 2 on how to get there.
Vicki Hollub:
Okay. I'll pass that to Richard.
Richard Jackson:
Thanks, Doug. This is Richard. I'll try to answer that and kind of start, like you said, with the well performance and then translate that into the inventory, which we wanted to bring back up. I think in total, this year has been a good year. I think we noted in prepared remarks, the growth trajectory of near 100,000 barrels a day from Q1 to Q4 and certainly, the second half of this year has been pronounced. But the best part of that has been the well performance.
And so both from a total year basis, that represents 200 wells in the Delaware that's really been drilled across our acreage from North Loving up into New Mexico into the multiple development areas there. And then even the third quarter results that we showed, that was across, I think, around 45 wells across Southeast New Mexico and Loving. And so I say that -- really to say that the consistency we do believe is becoming the new normal as we continue to improve. And I think the Python well is exciting to disclose, but it's really, what's interesting about that is that entire North Loving development area has been consistently good. And even that DSU, where we had that record well, it had offset wells that had been drilled in a similar formation. And so being able to come back where we can develop a DSU with offsets that are child wells, if you like, and be able to have this sort of record performance, I think, is a real testament to the way we do our sort of subsurface development. From an inventory perspective, I mean, I think the slide speaks for itself, we've got a lot of inventory that we've accumulated across a good acreage position. The only thing I would add to that is, we continue to have strong, what we would consider, secondary bench. They're not really secondary, because some of these are performing as well as the primary. So I'd point you to some Second Bone Spring in the Delaware Basin and then even the Barnett appraisal that we noted in the highlight. Both of those have moved themselves up to really top tier in our development plans. We have optionality in terms of when we develop that and co-develop it, but it's good to see those secondary benches add to that inventory.
Operator:
And our next question today comes from Neil Mehta at Goldman Sachs.
Neil Mehta:
I guess the first question is around the production profile. And as you talked about the plan for now as you think about '23 is to keep volumes on the oil side relatively flat. What would you look for in order to change that viewpoint and actually grow volumes? Is it price signal from the market? Or is it a view on where you want your balance sheet to be?
Vicki Hollub:
It's mostly around creating shareholder value and doing it in a way that ensures that it's sustainable over time. And part of our value proposition is to provide a growing dividend, which we, as you know, had the impact, and we're trying to now resume.
So what we really want to do is make the best decisions around how to allocate capital. We don't feel like we necessarily need to grow cash flow at this point, because we have significant cash flow at almost all price ranges. We're breakeven below $40. So currently, the way that we see to increase shareholder value the most and in a sure way that's sustainable and it also enables us to grow the dividend is to buy back shares in addition to enabling us to grow the dividend over time, but we do believe that at this point, we're significantly undervalued. So that's the best value decision and the best use of our capital dollars there.
Neil Mehta:
And that's the follow-up, Vicki, which is just around the authorization. You guys did a great job in the third quarter and knocking off a decent part of that share buyback authorization. Do you need to come back into the market? And how should we think about timing and sizing there?
Vicki Hollub:
Well, we'll finish the $3 billion for this year and then any cash that's left available this year will go to further debt reduction. Starting next year is when we'll be significant -- have significantly more capital available to buy back shares. So essentially, any free cash flow that's available next year will be allocated mostly to share buybacks.
And we really want people to understand that this is not something that we're doing on a temporary basis. We do believe that share buybacks where we are today and where our capital needs are and our cash flow potential, share buybacks is a part of our value proposition as is a growing dividend. And the two work so well together as a combined value proposition. So that's what we're essentially trying to do. We will occasionally, in the near term, do some projects that are not oil and gas but do increase value. So we are increasing value in cash flow and earnings with the membrane development at Battleground and also with Al Hosn expansion. So when we see projects that are kind of opportunistic, we'll take advantage of that to increase cash flow, but we think the better value is to buy back shares and increase shareholder value that way.
Operator:
And our next question today comes from Paul Cheng at Scotiabank.
Paul Cheng:
Maybe this is for Rob. Rob, with the rising interest rate and potentially for the next several years it's going to be much higher than what we've seen in the past 10 years. How that change the LCV business model, if any, given the project financing, the economic return may not be as good as before?
And also in your chart, when you're showing from 2022 to '24, the revenue and cost seems to match. So does that means that currently, before we see further improvement that the EBITDA will be 0 for that business? That's the first question. The second question is, can you tell us the mechanics of the preferred redemption, look like next year you will start to have parcel redemption. How that work? And also that the warrant related buffer, the preferred, how those is going to get exercised?
Vicki Hollub:
We'll start with the LCV question. And first, I'll just say that we really don't know yet what the inflationary environment is going to be. We don't expect or at least at this point expect that it would be a long-term inflationary period. We know the Federal Reserve is doing all they can to manage that. So what we'll do is we have to continue our business.
And on the first direct air capture, it's really important for us to build it and to operate it, before we can understand how to optimize it. And so as we go forward, we'll always keep in mind what our costs are with respect to what the potential returns are, and we'll make decisions on that. But based on what we think we can do with it, it's more prudent to continue to invest at this point, preferably with other people's dollars, but with ours if need be, to ensure that we can get the technology tested up and running and improved. You have more to add, Richard?
Richard Jackson:
Yes, maybe just a few things. I kind of -- I think what Vicki says is exactly the way we're thinking about it, important to derisk what we can control, which is really innovation and cost. And so we have our innovation center that we continue to progress. Obviously, getting started on these projects, especially if we have line of sight to multiple projects, will help our costs down as we improve our engineering and/or construction. And so that will be important.
The pace of development, very supported by the policy, really gives us an accelerate. I think we're well positioned for some DOE grants that we talked about, I think, with you in the past. So when you think about near-term capitalization, those are options. Longer term, we want to get the cost in the market in place to really support the sustainable business. And at that point, capitalization options are wide open. And so that's sort of how we have thought about that, but very focused on getting really the cost down. On this first plant, really advancing the innovation pathway that we see to really move this development forward.
Robert Peterson:
I'll take the other part of your questions. So the -- within the preferred redemption mechanics, so we cannot voluntarily redeem the preferred shares before August 29. After August 29, we can voluntarily redeem those preferred shares at a price of $1.05 for a 5% premium at par.
However, the agreement includes a mandatory redemption provision that obligates us to redeem deferred at a 10% premium or 110% on a dollar-for-dollar basis for every dollar we distribute to common shareholders above $4 on a trailing 12-month basis. And so building off of Vicki's script today, if you -- at the end of the day, we would take all the cash spent on share repurchases, dividend, all distributed to shareholders from November 10 of last year through November 9 of this year, and add that up on a previous day's share count and get a total for that. And so as she mentioned in her opening remarks, that will be $3.21 today. If that number added up to over $4 and everything that we distribute to shareholders above that would go on a dollar per dollar basis to shareholders and equivalent would be redeemed on the preferred on a 50-50 basis. So if it had been $4.10, we would take $0.10 on the current outstanding shares to the dollar amount and applied that towards the redemption of the preferred at 110%. And so we're going to continue that. Once you are above that, you continue with that every day, and if you distribute more value to shareholders, so if we buy more shares back or pay a dividend, an equivalent amount will be applied towards the Berkshire preferred as long as we're above that threshold. You fall below the threshold, you discontinue it until you come back above the threshold and you do it again. And that's the mechanics of how the Berkshire redemption would work. In the case of the warrants, so the warrants could be exercised at any time. And so when you get the warrants exercise to us, the warrant holder pays us $22 per share in exchange for a warrant or a stock being issued in their place. And so we'll take the cash in on that. Warrant holders do not participate in dividends. And so any dividend growth, as Vicki outlined in her earlier remarks and question discussion, they would be not included in that. And so if that -- if the dividend were increased, et cetera, that could drive additional warrants to be exercised. As we mentioned, we've had about $12 million of the $116 million roughly exercised to us.
Operator:
And our next question today comes from Raphael DuBois from with Societe Generale.
Raphaël DuBois:
I have a couple of questions on OLCV. The first one is on the financing of the first stack. I understood that you might benefit from the Infrastructure Act. Could you maybe give us an update on whether we can expect you to benefit from those subsidies? And then I will have a follow-up question.
Vicki Hollub:
So the plant will be operational in 2024 and then the ability to claim the CDRs would be available at that time.
Richard Jackson:
And maybe I'll just add to that. I mean, in addition, obviously, 45Q in addition to the offtake with the carbon dioxide removals, which are sold to businesses that are looking to reduce their emissions, but also, as I mentioned briefly, well positioned for some potential grant for direct air capture that is available from that Infrastructure Act. So we want to put a competitive program together and show how those can really catalyze our business, which will allow us to reach commerciality quicker, and then we'll become self-sustaining as a business to go forward.
Vicki Hollub:
And as a reminder, what we said in the past that we do have a contract for 100,000 tons per year of CDRs from that first plant.
Raphaël DuBois:
And speaking about CDRs, it's a little bit opaque, the value of those CDRs. Can you maybe refer us to some transactions that would have been closed already at the sort of price levels that we can guess from what you show on your Slide #8?
Richard Jackson:
Yes. Perfect. I want to quickly just frame the market a little bit. I think what's happening as this market takes shape, carbon dioxide removals, which are uniquely capable to reduce atmospheric CO2, are becoming very appreciated. And so being able to have an engineered solution like direct air capture that monitors the capture of that atmospheric CO2 and then places it safely and securely underground, that's a unique part of this evolving carbon reduction market. And so I want to say that first.
Our position in that is really to be large-scale and we think we can be competitive on cost. When you look at all the alternatives to reduce emissions, we think we could be quite competitive given those 2 things. And so while we're not in a position to disclose some of the contracts that we've been working around that, there are some that get publicized. Those are generally smaller volumes and higher costs than what we show on our revenue slide. But we think -- in the way this works from a revenue standpoint, in addition to the 45Q or a policy like that, that gives you support on revenue, we're able to then attach the environmental attribute, which is the carbon removal on top of that, which gives you a total revenue against the cost that we showed in that slide. And so we're pleased with the market acceptance. We're working with some great partners that realize this is a very cost-effective way for many industries and many businesses to reduce their emissions as we look out over the next 10 to 20 years.
Operator:
And our next question today comes from Neal Dingmann with Truist Securities.
Neal Dingmann:
First question is around your 23 traditional activity. I'm just wondering specifically, do you anticipate continuing to run, I don't know, I guess it's around 23, 25 rigs next year. Could we see maybe a bit of efficiencies allowing for less? And if that's around the number, do you anticipate those rigs running in kind of approximately the same area as this year?
Richard Jackson:
I can start, and then Vicki can add any context that she needs to. But I think that rough number is about right in terms of where our activity is. We made note of the rig that we picked up in the Rockies. I think the success that we've had with our permitting have given us a strong runway on those very competitive projects in our portfolio. We also have a rig that we picked up in the second half of this year and enhanced oil recovery, which is a great add to our business as we had low decline production to kind of add to the mix. So those are the 2 I would point to.
We do have flexibility in the program. We have staggered terms in terms of contracts, so we can adjust to the macro where Oxy needs us to. We can adjust with flexibility. And then the final 2 variables I'd give you is obviously working interest. We fluctuate between 90% to even 50%, 60% in terms of working interest in a business like the Delaware. And so where we have rigs and frac core, sometimes that can look a little lumpy from a capital perspective, but it's simply working interest. And the same could be said really for OBO. And maybe the last thing to note is just our JV. So we're able to extend our EcoPetrol JV into the Delaware, which is a great opportunity for us to accelerate this high-quality inventory, brings a great partner along with us. And so that is another lever that will not be transparent when you're just trying to look at activity versus capital.
Neal Dingmann:
Got it. And then just a second question, maybe, Richard, just staying with you is around that strong pipeline well. Just wondering, could you comment as to magnitude of future locations you all see in that area and any plans near term or maybe even next year to obviously, given the success there, maybe boost activity in that area?
Richard Jackson:
Yes. What's great about them is they're certainly in a very rich geologic area for us, but that area in total is North Loving. And for those of you who know that our position in sort of the Texas Delaware, that's quite a large acreage position. And so near some of the Silvertip wells, which had some of the records in the past, but in the near term, we have 2 or 3 DSUs that will be coming online over the next couple of quarters.
But in total, that's a large acreage position that we've picked up, and just excited about prosecuting that. Again, not to challenge our team too hard, but we do continue to find ways to improve. And so whether it's the primary benches like the Wolfcamp Y, which as well was in our secondary in the Bone Spring, I'm looking forward to seeing what our teams can do.
Operator:
And ladies and gentlemen, our next question today will come from John Royall with JPMorgan.
John Royall:
On Chemicals, can you talk a little more about the drivers of the better-than-expected results in both 3Q and I think, 4Q? And how does 2023 set up relative to the run rate in 2H? I know the housing market is likely to become kind of more and more challenged with rates where they are, but that business does seem to continue to do well.
Robert Peterson:
Sure, John. I would say that as we kind of described in the opening comments and we've talked about before is, the macroeconomic conditions continue to drive the demand in our vinyls business. And so interest rates, housing starts are trending unfavorably. So at the end of the fourth quarter, what we're seeing is continued softness in the PVC domestic market. Due to the housing sector slowdown, PVC buyers are also adjusting inventories due to pricing changes. And we're also seeing a fair amount of imports from Asia now into the market due to continued COVID lockdowns in China. So you're seeing a displacement regionally of where PVC typically is.
But what's slowing that pace of decline is partially responsible for the beat in Q3 and our improved guidance for the fourth quarter is, first of all, there's still a tremendous cost advantage for U.S.-based chemical production versus Europe and certainly Asia. So the export business that has ramped up, we have a much better competing position from the U.S. And if you look at U.S. exports, they're actually up 28% year-to-date [indiscernible] to September versus prior year. In addition, I would say also despite the headwinds from interest rates, there still is a pretty significant pent-up demand on construction overall in the U.S. It's still pulling through a fair amount. The other key factor I would say is that we're slowing demand in PVC, we'll see the flip side, and we've seen this many times historically is, is when the chlorine side of the molecule slows down to the PVC chain, it naturally makes caustic soda availability much more difficult to come by and tightened up the marketplace. So we've seen steadily increases in caustic soda values, much greater value than we originally anticipated. And so those 2 collectively are the 2 main drivers of our improved performance in the third quarter and our higher guidance for the fourth quarter. Certainly, when we factor in the macro conditions and then look at the fact that we're in a seasonally slow period, that's the reason why you see fourth quarter sequentially down versus the third quarter. We really don't have a window yet to 2023 yet. I mean the very key factors are going to drive that, it would be the length of the impact of housing starts, from interest rates, to how long is COVID shutdowns in China going to persist, because once China reopens similar to the oil and gas market, it's going to draw a lot of that demand that we're seeing or competition we're seeing from Asian produced products to go right back into China as it has historically. And then just this period of time typically is a low demand period, as once we go through winter. So really, we don't have a really good viewpoint on what's going to happen in chemicals until that February-March time frame when we start looking at the construction season. So not a lot of guidance on '24 -- on '23 at this point, but that's certainly, those are going to be the key drivers of what's going to really impact us in '23 and beyond is going to be sort of that PVC demand, construction sector, general kind of durables and construction, coupled with also what happens in China in terms of when they reopen their economy.
John Royall:
Okay. That's really helpful. And then on the King Ranch deal, obviously, it's a very large amount of facility that you can put on top of it. Can you just talk to the pros and cons of building units on that site versus where you're developing DAC 1 in the Permian and maybe some of the other acreage you've secured? And then is there an incremental spend number we should be thinking about over the next couple of years to develop these sites?
Richard Jackson:
Yes. Let me start. Really excited about the King Ranch and thanks to the King Ranch for working with us on really a different way of looking at a great asset. Really, the unique things for us in that position, it's obviously a very large contiguous acreage position.
So that's -- like oil and gas, that contiguous position allows us to be very smart with the way that we develop, but really, the uniqueness, great geology in South Texas, lots of pore space per acreage position, access to water being on the Gulf Coast with our aqueous fluid design for direct air capture, the ability to grow zero emission power to support this larger build-out of direct air capture. And then proximity to point source emissions. One of the things we talk about, while this is a great place to capture and build direct air capture, proximity to the Gulf Coast to be able to also think about point source submissions and bring that gives us some economies of scale to share that cost. So advantages versus the Permian, they're just different. I think Permian has the proximity to our CO2 infrastructure, has the ability to both do sequestration and net zero oil to enhanced oil recovery process. And so depending on where the customer's preferences are for sequestration or net zero oil, we have the ability to do both. And I think on that point, we get asked a lot, how do we think about that? And I think our ability is they both reduce emissions. As you think about net zero oil or CDRs, you're lowering the atmospheric CO2 and so start there. But the other thing is the ability to grow a market for both allows us to deploy more of this technology and bring the cost down, making it very competitive when you look at other cost -- of cost abatement for emissions. So that's how we think about it. I think, again, pace, I would point you back in terms of how we should think about incremental capital. That will be a function of getting our costs down and improving innovation, how fast the CDR market grows and we anticipate it will and actually value will over the next 10 years. And then in the early time, support from something like the DOE grant could really help catalyze and allow us to move more in parallel. And then again, once we get a sustainable commercial business, capitalization options are wide open.
Vicki Hollub:
And I would just add to that, that we have quite a bit of interest in partnerships and even people investing in the project itself or directly in our Low Carbon business. So there's no lack of interest. There's -- for us, it's a matter of choosing the right partners as we begin this process. And really, it's just about, as Richard said, starting the process, making the technology better and less expensive over time, improving it up, that's when we'll have even more options about how to finance.
Operator:
And our next question today comes from David Deckelbaum with Cowen.
David Deckelbaum:
I wanted to follow up a bit on just the direct air capture plan and some of the incentives around the IRA. Just given the increase are between sequestering CO2 versus utilizing it, has this changed the way that you think about the amount of debt that would be used for EOR or just the EOR business in general? And I guess when we think about the acceleration, I presume that this would all be towards sequestration oriented projects?
Richard Jackson:
I think I can start. I think the markets are evolving. Again, I think our view is that both products, whether that be net zero oil or sequestration or valuable products of the future. And so when you look at that orb it's hard to determine exactly where that's going to land. The good news is we think it's commercial for both. And certainly, when you take into account our ability to produce a low decline, now very low carbon barrel of oil, that's a tremendous potential market for the future.
And so I think we'll let the markets determine where we go. The good news is we've got options for both. And again, the challenge is we want to deploy this technology to get the cost down. And so were commerciality is supported, this will allow us to do it across both products.
Vicki Hollub:
And I would add that my view is that the world cannot afford a climate transition without -- by cutting out completely oil and gas production. Oil production is going to be needed from decades -- for decades to come and using CO2 in enhanced oil recovery is a way to produce a net zero emission oil. And to have that as the fuel source, it's low cost, lower cost than other options, it would help with the transition, it would help to fund the transition. So I think that oil is needed for us, for our company, in particular, we have 2 billion barrels of resources available for further development in our enhanced oil recovery assets.
And we'd like to use either anthropogenic or atmospheric CO2 for the -- to develop those resources. In addition, we do know that we can technically use CO2 in the shale reservoir, so we can increase the 10% recovery that we have today to something much higher than that. So it's -- there is a use for CO2 in enhanced oil recovery. It's not as well recognized yet. But when the world realizes how much the transition will cost, I do believe that this will become the preferred option to ensure that we can continue the production of low-carbon fuel for those that need it.
Operator:
And our next question today comes from Leo Mariani with MKM Partners.
Leo Mariani:
I wanted to follow up a little bit on the thought around production here. You guys talked about not really trying to grow the oil and gas production next year. I certainly appreciate that. But I just wanted to kind of clarify on that point. You obviously have pretty significant growth on oil and gas production during the course of the year in '22. So as you think about potential growth in '23, are you more talking kind of exit to exit, so sort of fourth quarter '22 to fourth quarter '23 where there won't be much growth? Because obviously, if you were flat year-over-year, I guess, that would imply your volumes would start dropping here in '23?
Vicki Hollub:
No, we were thinking that probably it would be year-over-year. And I'm not saying that there wouldn't be some growth. We don't intend to grow it. If growth is an outcome, and it would probably be somewhere in the neighborhood of 1% or less. So it's not our intention to grow it. But if we have more wells like Richard just talked about, there will be growth from our assets, but it's not our desire to grow it in 3% to 5%. It's not -- the growth is not the target. It's to develop the best wells in the best possible ways. And if that delivers growth than that's good.
Operator:
And ladies and gentlemen, in the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I would just like to thank you all for your participation today, and thanks again to Jeff as he makes this his final call. So thank you.
Operator:
Thank you, ma'am. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.
Operator:
Good afternoon, and welcome to Occidental's Second Quarter 2022 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Jason. Good afternoon, everyone, and thank you for participating in Occidental's Second Quarter 2022 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good morning or good afternoon, everyone. We achieved a significant milestone in the second quarter as we completed our near-term debt reduction goal and activated our share repurchase program. At the beginning of this year, we established a near-term goal of repaying an additional $5 billion of debt, before further increasing the amount of cash allocated to shareholder returns. The debt we completed in May brought the total debt repaid this year to over $8 billion, surpassing our target at a quicker pace than we had originally anticipated. With our near-term debt reduction goal accomplished, we initiated our $3 billion share repurchase program in the second quarter and have already repurchased more than $1.1 billion of shares.
The additional allocation of cash to shareholders marks a meaningful progression of our cash flow priorities as we have primarily allocated free cash flow to debt reduction over the last few years. Our efforts to improve the balance sheet remain ongoing, but our deleveraging process has reached a stage where our focus is expanding to go to additional cash flow priorities. This afternoon, I'll cover the next phase of our shareholder return framework and second quarter operational performance. Rob will cover our financial results as well as our updated guidance, which includes an increase in our full year guidance for OxyChem. Starting with our shareholder return framework. Our ability to consistently deliver outstanding operational results, combined with our focus to improve our balance sheet, have positioned us to increase the amount of capital returned to shareholders. Considering current commodity prices expectations, we expect to repurchase a total of $3 billion of shares and reduce gross debt to the high teens by the end of this year. Once we have completed the $3 billion share repurchase program and reduced our debt to the high teens, we intend to continue returning capital to shareholders in 2023 through a common dividend that is sustainable at $40 WTI as well as through an active share repurchase program. The progress we are making in lowering interest payments through debt reduction, combined with managing the number of shares outstanding, will enhance the sustainability of our dividend and position us to increase our common dividend at the appropriate time. While we expect future dividend increases to be gradual and meaningful, we do not anticipate the dividend returning to its prior peak. Given our focus on returning capital to shareholders, it is possible that we may reach a point next year [ return ] to over $4 per share to common shareholders over a trailing 12-month period. Reaching and maintaining returns to common shareholders above this threshold will require us to begin redeeming their preferred equity concurrently with returning additional cash to common shareholders. I want to be clear about 2 things. First, reaching the $4 per share threshold is the potential outcome of our shareholder return framework, not a specific target. Second, if we begin redeeming the preferred equity, this does not mean there is a cap on returns to common shareholders as cash would continue to be returned to common shareholders above $4 per share. In the second quarter, we generated $4.2 billion of free cash flow before working capital, our highest quarterly free cash flow to date. Our business has all performed well, and we delivered production from continuing operations of approximately 1.1 million BOE per day, in line with the midpoint of our guidance and with total company-wide spending of capital of $972 million. OxyChem reported record earnings for the fourth consecutive quarter with EBIT of $800 million, as the business continued to benefit from robust pricing and demand in the caustic, chlorine and PVC markets. Last quarter, we highlighted the Responsible Care and Facility Safety Awards that OxyChem received from the American Chemistry Council. OxyChem's accomplishments continue to be acknowledged. In May, the U.S. Department of Energy honored OxyChem as a Better Practice Award winner, which recognizes companies for innovative and industry-leading accomplishments in energy management. OxyChem received the recognition for incorporating an engineering, training and development program that led to process changes, resulting in energy savings that reduced CO2 emissions by 7,000 metric tons annually. It's achievements like this that make me so proud to announce the modernization and expansion of one of OxyChem's key plants, which we'll detail in just a minute. Turning to oil and gas. I'd like to congratulate the Gulf of Mexico team in celebrating first oil from the new discovery field, Horn Mountain West. The new field was successfully tied back to the Horn Mountain spar using a 3.5-mile dual flow line. The project came in on budget and more than 3 months ahead of schedule. The Horn Mountain West tieback is expected to eventually add approximately 30,000 barrels of oil production per day and is an excellent example of our ability to leverage our assets and technical expertise to bring new production online in a capital-efficient manner. I'd also like to congratulate our Al Hosn and Oman teams. Al Hosn achieved a recent production record following the first full plant shutdown as a part of a planned turnaround in the first quarter. Oxy's Oman team celebrated a record high daily production at Oman North Block 9, which has been operated by Oxy since 1984. Even after almost 40 years, Block 9 is still breaking records with strong base production and new development ledge performance, supported by a successful exploration program. We have also been active in capturing opportunities to leverage our deep inventory of U.S. onshore assets. When we announced our Midland Basin JV with EcoPetrol in 2019, I mentioned how excited we were to be working with one of our strongest and longest-standing strategic partners. The JV has worked exceptionally well for both partners, with Oxy benefiting from incremental production and cash flow from the Midland Basin with minimal investment. We are fortunate to collaborate with a partner who has extensive expertise and with whom we share a long-term vision. This is why I'm equally excited this morning to announce that Oxy and EcoPetrol have agreed to enhance our JV in the Midland Basin and expand our partnership to cover approximately 20,000 net acres in the Delaware Basin. This includes 17,000 acres in the Texas Delaware that we'll utilize with infrastructure. And in the Midland Basin, Oxy will benefit from the opportunity to continue development with an extension to the capital carry through the end of this agreement in the first quarter of 2025. In the Delaware Basin, we have the opportunity to bring forward the development of high-quality acreage that was further out in our development plans, while benefiting from an additional capital carry of up to 75%. In exchange for the carried capital, EcoPetrol will earn a percentage of the working interest in the JV asset. Last month, we reached an agreement with Sonatrach in Algeria to enter into a new 25-year production-sharing agreement that will roll Oxy's existing licenses into a single agreement. The new production-sharing agreement renews and deepens our partnership with Sonatrach, while providing Oxy with the opportunity to add reserves and continue developing a low-decline cash-generating asset with long-standing partners. Even with 2022 expected to be a record year for OxyChem, we see a unique opportunity to expand OxyChem's future earnings and cash flow generating capabilities by investing in high-return project. On our fourth quarter call, we mentioned the FEED study to explore the modernization of certain Gulf Coast chlor-alkali assets and diaphragm to membrane technology. I'm pleased to announce our Battleground plant, which is adjacent to Houston Ship Channel in Deer Park, Texas as one of the sites that we will modernize. Battleground is Oxy's largest chlorine and caustic soda production facility with ready access to both domestic and international markets. The project is being undertaken in part to respond to customer demand for chlorine, chlorine derivatives and certain grades of caustic soda that we can produce with newer technology. It will also result in increased capacities for both products. The project is expected to increase cash flow through improved margins and higher product volumes, while lowering the energy intensity of the products produced. The modernization and expansion project will commence in 2023, with a capital investment of up to $1.1 billion, spread over 3 years. During construction, existing operations are expected to continue as normal, with the improvements expected to be realized in 2026. The expansion is not a prospective build as we have structurally advanced contracts and internal derivative production to consume the incremental chlorine volume, while caustic volumes will be contracted by the time the new capacity comes online. The Battleground project represents the first sizable investment we've made in OxyChem since the construction and completion of the 4CPe plant, an ethylene cracker that were completed in 2017. This high-return project is just one of several opportunities we have to grow OxyChem's cash flow over the next few years. We are conducting similar FEED studies for additional chlor-alkali assets and plan to communicate the results when complete. I'll now turn the call over to Rob, who will walk you through our second quarter results and guidance.
Robert Peterson:
Thank you, Vicki, and good afternoon. In the second quarter, our profitability remained strong, and we generated a record level of free cash flow. We announced an adjusted profit of $3.16 per diluted share and a reported profit of $3.47 per diluted share, with the difference between the 2 numbers primarily driven by gains in early debt extinguishment and positive mark-to-market adjustments. We were pleased to be able to allocate cash to share repurchases in the second quarter. To date, we have purchased over 18 million shares as of Monday, August 1, for approximately $1.1 billion for a weighted average price below $60 per share.
Also, during the quarter, approximately 3.1 million publicly traded warrants were exercised, bringing the total number exercised to almost 4.4 million with 11.5 million -- 111.5 million remaining outstanding. As we said, when the warrants were issued in 2020, the cash proceeds received will be applied towards share repurchases to mitigate potential dilution to common shareholders. As Vicki mentioned, we are excited to enhance and expand our relationship with EcoPetrol in the Permian Basin. JV amendment closed in the second quarter with an effective date of January 1, 2022. To maximize this opportunity, we intended to add an additional rig late in the year to support the JV development activity in the Delaware Basin. The additional activity is not expected to add any production until 2023, as the first Delaware JV wells will not come online until next year. Similarly, the JV amendment is not expected to have any meaningful impact on our capital budget this year. We expect the Delaware JV and the enhanced Midland JV and to allow us to maintain or even lower industry-leading capital intensity in the Permian in 2023 onwards. We will provide further details when we provide 2023 production guidance. Given that January 1, '22 effective date and related working interest transferred to our JV partner in the Midland Basin, we have adjusted our full year Permian production guidance down slightly. Separately, we are reallocating a portion of the capital we earmarked for the OBO spending this year to our operated Permian assets. Reallocating capital operating activity will provide more certainty in our West delivery for the second half of 2022 and the start of 2023, while also delivering superior returns given our inventory quality and cost control. While the timing of this change has a slight impact on our 2022 production due to activity relocation in the second half of the year, the benefit of developing resources that we operate is expected to result in even stronger financial performance going forward. The updated activity slide in the earnings presentation appendix reflects this change. The shift in OBO capital, combined with the JV working interest transfer as well as various short-term operability matters all contributed to a slightly lowering our full year Permian production guidance. The operability impacts are primarily related to third-party issues, such as downstream gas processing interruptions on our EOR assets and other unplanned disruptions at third parties. For 2022, company-wide full year production guidance remains unchanged, as the Permian adjustment is fully offset by high production in the Rockies and the Gulf of Mexico. Finally, we note that our Permian production delivery remains very strong, with a growth of approximately 100,000 BOE per day when comparing the fourth quarter of 2021 through our implied production guidance for the fourth quarter of 2022. We expect production in the second half of 2022 to average approximately 1.2 million BOE per day, which is notably higher than the first half of the year. Higher production in the second half of the year has always been an expected outcome of our 2022 plan, in part due to ramp-up activities and scheduled turnarounds in the first quarter. Company-wide third quarter production guidance includes continued growth in the Permian, but considers the potential for tropical weather impacts in the Gulf of Mexico, combined with third-party downtime and production decline in Rockies given our lower activity set as a result of relocating a rig to the Permian. Our full year capital budget remains unchanged. But as I mentioned in our previous call, we expect capital spending to come in near the high end of our range of $3.9 billion to $4.3 billion. Certain areas that we operate in, especially the Permian, continue to experience higher inflationary pressures than others. To support activity into 2023 and address the regional impact of inflation, we are reallocating $200 million of capital to the Permian. We believe our company-wide capital budget is sized appropriately to execute our 2022 plan, as the additional capital for the Permian will be reallocated from other assets that have been able to generate higher-than-expected capital savings. We are raising our full year domestic operating expense guidance to $8.50 per BOE, which accounts for higher-than-expected labor and energy costs, primarily in the Permian, as well as continued upward pricing pressure on our WTI index CO2 purchase contracts in the EOR business. OxyChem continues to perform well, and we have raised our full year guidance to reflect the exceptional second quarter performance as well as a slightly better than previously expected second half of the year. We still see the potential for market conditions to dampen from where we are today due to inflationary pressures, though the long-term fundamentals continue to remain supportive, and we expect third and fourth quarters to be strong by historical standards. Turning back to financial items. In September, we intend to settle $275 million of notional interest rate swaps. The net liability or cash outflow required to sell these swaps will be around $100 million of the current interest rate curve. Last quarter, I mentioned that as WTI averages $90 per barrel in 2022, we would expect to pay approximately $600 million in U.S. federal cash taxes. Oil prices continue to remain strong, increasing the possibility that WTI may average even higher price for the year. If WTI average $100 in 2022, we would expect to pay approximately $1.2 billion in U.S. federal cash taxes. As Vicki mentioned, year-to-date, we repaid approximately $8.1 billion of debt, including $4.8 billion in the second quarter, exceeding our near-term goals of paying $5 billion in principal this year. We have also made meaningful progress towards our medium-term goal of reducing gross debt to the high teens. We began repurchasing shares in the second quarter, further advancing our shareholder return framework as part of our commitment to return more cash to shareholders. We intend to continue allocating free cash flow towards the share repurchases until we complete our current $3 billion program. During this period, we will continue to view debt retirement opportunistically and we'll likely retire debt concurrently with share repurchases. Once our initial share repurchase program is complete, we intend to allocate free cash flow towards reducing the face value of debt to the high teens, which we believe will accelerate our return to investment grade. When we reach this stage, we intend to reduce the impetus of our allocation of free cash flow from primarily reducing debt by including initial items in our cash flow priorities. We continue to make incremental progress towards achieving our goal of returning to investment grade. Since our last earnings call, Fitch has signed a positive outlook to our credit ratings. All 3 of the major credit rating agencies rate our debt as 1 notch below investment grade, with Moody's and Fitch having assigned positive outlooks. Over time, we intend to maintain mid cycle levered at approximately 1x debt-to-EBITDA or below $15 billion. We believe this level of leverage will be appropriate for our capital structure as we will enhance our equity returns, while strengthening our ability to return capital to shareholders throughout the commodity cycle. I'll now turn the call back over to Vicki.
Vicki Hollub:
We're now prepared to take your calls.
Operator:
[Operator Instructions] The first question comes from John Royall from JPMorgan.
John Royall:
So can you talk about the various moving pieces in the CapEx guidance? I know that you raised the Permian number, but kept the total the same. So what are the areas that were the source of funds for that raise? And then any early look into some of the moving pieces for next year with this new FID for Chems and then the change in structure with EcoPetrol? Just anything you can give us on kind of the puts and takes going into next year would be helpful.
Vicki Hollub:
I'll let Richard cover the changes in the CapEx, and then I'll follow up with the additional part of that question.
Richard Jackson:
John, this is Richard. Yes, so a few moving pieces as we look across the U.S. onshore. And as we look at it, a couple of things occurred during the year. I think, first, from an OBO perspective, we had a wedge assumed in our production plan. And early in the year, that became a bit slower in terms of delivery. And so we went ahead and made the move to reallocate some of that capital into our operated, which did a few things.
One, it secured that production wedge for us, but it also added resources for the back half of the year to give us some continuity on the back half of the year. We like that we did that. As Rob mentioned in his comments, these are high-return projects that are very good. So that was a good move. And then securing some of those resources early in the year in terms of rigs and frac core has played out well in terms of our timing to manage inflation and improve performance as we hit this ramp-up for the back half of the year. The other piece of that, so step 2 is really reallocation from Oxy. And so part of that is coming from LCV. We can talk in more detail on that if we need to. But that's really -- as we hit the back half of the year, we look to be coming in closer to midpoint for low carbon ventures. That's really just more certainty around the direct air capture development in some of the CCUS hub work that we've got in place. And so that, plus, I think, some other savings around the rest of Oxy, really contributed to that balance. So if you think about that extra [ 200 ], I'd say 50% of that is really around activity adds. So we were a bit front-end loaded in our plan for the year. That allows us to take that capital and keep continuity, especially across drilling rigs, which will give us optionality as we go into 2023. And then the other piece is really around inflation. We've seen that pressure on that. We've been able to mitigate a large piece of that. But we've outlooked an additional 7% to 10% sort of outlook compared to plan on the year. We've been able to again make up an incremental 4% of that in operation savings. So pleased with the progress against that. But we did start to see some inflationary pressures come up. And so that capital helps address that uncertainty, I would call it, for the rest of the year.
Vicki Hollub:
I would say, on capital for 2023, it's still way too early for us to determine what that would be. But the EcoPetrol JV would fit into the resources allocation, and we'll compete with the capital within that program.
John Royall:
Okay. Great. And then switching over to chemicals. If you guys could just talk a little bit about the fundamentals in that business. Coming off a very strong 2Q, but a big step down in guidance for the second half. So if you could just give some color on the source of the strength in 2Q and what you see changing in the second half?
Robert Peterson:
Sure, John. I would say conditions in both the vinyls and caustic soda business that are largely the ones that determine how we perform overall. In Chemicals, they were obviously very favorable in the second quarter. And when we see both conditions -- both businesses and favorable points, you have the significant earnings impact leading to the record performance we had in the second quarter.
If you go into the third quarter, I would say, the extreme tightness that we've been experiencing for quite some time in the Vinyls business has become more manageable. And that's really from improved supply and some softening in the domestic market, while conditions in the caustic soda business remain very strong and continue to improve. I would say the macroeconomic conditions are still indicative that when you look at interest rates, housing starts, GDP, they're kind of trading unfavorably, which is why we talked about a softer second half relative to the first half. But we're also entering a very unpredictable time of the year being the latter part of the third quarter here in terms of weather, which can certainly upset supply or demand either way. And so this is -- it's very difficult to look out very far as we enter the very beginning of the hurricane season or the peak of hurricane season. And the other thing I would say that has impacted the business a bit that we're trying to incorporate into the outlook is the Chinese shutdowns related to COVID, sort of the no COVID tolerance policies is backing up their demand in terms of needs for chemicals and pushing other Asian chemicals into other parts of the world, including impacting exports from the U.S. And so there's a bit of a softening there effect. But again, these are all things that can be modified relatively in a short basis if something were to change in either of those. But because of that, macroeconomic trends and our normal seasonal declines you would see in the fourth quarter in the business, we are projecting a softer second half of the year onto the first half of the year. But again, what we're projecting is quite strong by historical standards. Even the guidance for the third quarter as it is now would have been historically a decent year in many years for the Chemicals business, let alone a quarter. Overall, when we look at business on PVC, we're still seeing growth year-over-year. Domestic demand is up almost 6% through June. And PVC demand, including exports from the U.S., total demand is up about 4.5%. The chlorine side of the business, we're still seeing growth of 3% to 4% this year. All the market sectors remain strong. There's still a lot of pent-up demand, as you can imagine, coming off of the last 2 years. But those are all areas in durable goods, et cetera, where we can see impact from interest rates, inflation, disposable income, et cetera. So again, part of it is just trying to forecast what that might look like, doing the same anybody else is doing right now, trying to gauge the depth of a potential recession and the impact on demand. But overall, still a very favorable conditions in the business, but just not as favorable as they were in the second quarter.
Operator:
The next question is from Raphaël DuBois from Societe Generale.
Raphaël DuBois:
The first one is related to Algeria. Now that you have signed this 25-year contract extension, I was wondering if you could maybe give us some better color on what is the production potential for Algeria and whether there is a change in the mix between liquids and gas that we should be expecting?
Vicki Hollub:
Currently, under the agreement that we signed, we're still -- we'll be producing basically oil production with associated gas. And primarily from the fields, we've already been developing just expanding those out. So I'd say that from the standpoint of our production outlook currently, it's going to be -- look a little bit lower next year than it looks this year because of the structure of the contract. But our cash flow is going to be approximately the same. So it's just based on the terms. And we have a lot of potential, we believe, in the existing fields to continue to develop those out. So the remaining reserves that we'll be able to add as a result of just the contract extension will be about 100 million barrels.
Other than that, there's a lot of potential for further evaluation. So we've included the 3D seismic survey as a part of the evaluation, so that we can start to better increase our recoveries from those conventional sales because they're all relatively low decline and supported with gas injection and potentially ultimately some CO2 injection. Gas is not a part of what we're developing over there yet, but could be in the future, should there be an opportunity for us to find it commercially competitive with the other projects that we have internally.
Raphaël DuBois:
Great. And my follow-on question would be about chemicals. This Battleground CapEx project that you have announced, you said earlier that you would have more plans that you will consider for modernization. When could we hear about the next one to be modernized? And could you maybe remind us of the capacity of Battleground so that we can have a feel for the CapEx intensity of such project and what we could be expecting going forward for other projects.
Robert Peterson:
Sure, Raphael. So we have talked about potential conversions beyond the Battleground project. So at this point, we've made the decision to move forward with the Battleground conversion. As indicated in the remarks, we will continue to operate the facility throughout the construction process. There may be some short periods where we'd take very short outages for important connections between existing infrastructure in the facility. We're confident, throughout that process, we can build inventory and continue to build product with no impact on our customers. And so as you think about the Battleground process, you should not assume any loss of sales or margin during the actual project itself.
So when you look at the other facilities, once we convert the Battleground facility, we already have membrane technology and polyramics, which is a non-asbestos type diaphragm technology, at our Wichita and Geismar facilities. And we're in the process right now of making a conversion change at our [ Wichita ] facility to polyramics. So the announced project, that will not only convert Battleground but increase its capacity by 8%, we'll only leave our Convent Ingleside facilities utilizing asbestos diaphragms. And we'll begin the conversion studies on those as we get further underway with the actual Battleground conversion. We'll do them sort of in series together. We won't wait for one to be completed to make a decision on the other, but we'll sort of stagger them together. But obviously, what we're going to do with those facilities isn't as pertinent as to moving forward the Battleground project right now. And so from a capital intensity standpoint, we don't provide individual capacities of our facilities. But what I would say though is that the amount -- cost of $1.1 billion that we've included in the slide deck, I would not use that as a proxy necessarily that -- for the other 2 facilities. The facilities are all individually unique, not only from different sizes and capacities in the facilities, but they all have different equipment associated inside and outside, battery limits. They have different conversions that will go along with them. In addition that, at this stage, as we mentioned, the Battleground facility expansion is determined also with existing contractual obligations we've secured for the chlorine side of the business, the derivative side of the business moving into the project. We're not expanding the project, hoping to get additional demand for those molecules are already sold in the future. At this time, we don't have needs to expand either our Convent facility or Ingleside facility. So at this stage, if we were to proceed with an FID decision on one of those, it would simply be a conversion of process change. And so it would be difficult to take that and certainly wouldn't multiply that number times 3 and come up with a number for those other 2 projects to be included in that. And so as we get further along with the Battleground project, we'll start sharing ideas on subsequent changes in the future. But this time, the only decision we made is to actually move forward with Battleground 1.
Jeff Alvarez:
Raphael, this is Jeff. I'd add one thing to what Rob said. The EBITDA number we've provided would be, the way I'd look at that is more of a mid-cycle EBITDA, not at current pricing or current marketing conditions. So you can use that for your estimates.
Operator:
The next question comes from Devin McDermott from Morgan Stanley.
Devin McDermott:
So I wanted to ask on low carbon ventures. One of the moving pieces in the cap guidance this year was LCV spend coming in toward the midpoint. I was wondering if you could just talk a little bit more broadly about the progress you've been making towards some of the milestones that you set forth earlier this year. And as part of that, the Inflation Reduction Act that's recently been introduced has some supportive language in there for carbon capture and also direct air capture. So can you talk about if that were to move forward, how that might impact the cadence of investment over the next few years?
Vicki Hollub:
Devin, I'll start, and then pass it over to Richard. And while we're on the Inflation Reduction Act, I just want to cover a little bit more about what's in there. There's a lot of things in there, ranges from alternative fuels to renewable energy, EVs, hydrogen, methane, emission reduction and carbon capture use and sequestration. But some of the things that impact us are the -- on federal land, oil and gas royalty rates increasing, increased minimum bid rates for leases, increases in annual rental rates, but not excessively, and increasing bond requirements, also offshore royalty rate increases. And one of the good things is that it does require oil and gas lease sales ahead of granting right of ways to wind and solar. It requires royalties in oil and gas produced, whatever it's used for, unless it's played for safety reasons or used for the benefit of the lease.
But one of the interesting things about the act is that it reinstates the Lease Sale 257 from the Gulf of Mexico, in which we had gotten some key leases. And so that's really important for us as a company. The other thing is that it requires the resumption of the scheduled lease sales for the GoM from 2017 to 2022. And with respect to carbon capture, which is probably the most impactful to us, is there are a lot of things around the enhancement to 45Q. And when you look at the Gulf of Mexico benefit to us and you look at the requirements for the methane emissions and emission reductions and that sort of thing, which are things we already were doing, this is turning into for us a net very positive bill should it get passed. So I'll turn it over to Richard, so he can give you a little more color on what the CCUS enhancements are.
Richard Jackson:
Yes. Devin, let me start with just a few kind of progress points on both our direct air capture and CCUS, and then get a couple of specifics on, like Vicki said, how this can potentially help our development plans.
I think from direct air capture, the critical pieces are continuing to move well. I think from a technology and engineering standpoint, we were able to finish FEED. We're on track and plan to begin construction by the end of this year. And we're really taking that feed and working hard on putting together specific bid packages and being very thoughtful about the supply chain behind that as we go into the end of the year. So we're spending time with that. From a market support, continue to have very strong support from the carbon dioxide removals in terms of the sequestered CO2 offtakes. And so continue to see good movement on that. Obviously, the policy support couples with that to help really backstop our development plan. And then in terms of capitalization, as we continue to derisk, we are thoughtful on how to think about capitalization not only for Plant One but beyond and continue to see and know that those partnerships will be meaningful. And so really, on that piece, for the end of the year, again, looking to start construction, finish detailed engineering and then work our innovation work streams. We've got our innovation center with carbon engineering going, seeing really good progress there, lots of pieces in learning, again, for Plant One. But I think one of the things we picked up in that facility is really thinking about how do you continue to reduce the cost to capture for the life of a plant. And so it provides lots of opportunity for that. Just briefly on the CCUS hubs, we continue on our 3 really focused areas on the Gulf Coast. We've been able to secure now over 100,000-acre target for space development. Very pleased with that. Lots of great engagement with emitters. And then we had the announcements, I think we picked up on the last quarter with our midstream partnerships to be able to retrofit or think about moving that CO2 efficiently within those hubs. So that goes well, expect more updates on both of those as we go into the year. Lots of dynamics, I'd say, over the last quarter. And so we'll put that into plans for 2023 and beyond that we'll communicate. So just lastly on the -- in terms of some of the policy that plays our way. I think for us, we think about that, we communicated it in our LCV update. It's really an acceleration capability for us. It gives certainty in some of the revenue to allow us to build this development, which is good because the important part of making this business work is really on us. We've got to improve the technology. We've got to lower the cost, and we've got to develop our manufacturing and project development success. And so having certainty to be able to accelerate that development plan, we believe, allows us to reduce those costs quicker and it creates a sustainable business sooner. And so when you look at both a business and emissions reduction over the next several years, we think this could be complete very meaningful. Longer runway to be able to develop that scale is contemplated in the language. Obviously, increased value support, that aligns with a lot of CCUS work done collectively around the world to kind of pick what needs to happen to create this catalyst. And so very thoughtful alignment there. And then the final thing is, I think, importantly, recognition for all sources. So point source from industrial or power sector emissions, but carbon removals and direct air capture specifically recognized. And then for the collective CCUS community, recognition of small and large sources, I think, is important. And so they were very inclusive to capture both the small and large. And that's good for us and what we're doing, but that's good for other developers. And so I think it really does create the economies of scale that we hope and plan for to make this commercially successful.
Vicki Hollub:
And just to conclude on that, I'd say that the federal leasing, onshore, offshore, the methane emission reductions in carbon capture, while we talked about what it does for Oxy, this is very good for our industry. Lots of companies will benefit from this. It will provide jobs and it will help the country meet the goals that the President has set out for emission reduction.
Devin McDermott:
A lot of positives to look forward to there. My second question is just on inflation. You mentioned in the prepared remarks that you've been able to take some steps to offset inflationary pressure. I was wondering if you could talk a little bit more on the underlying inflationary trends and also the offset initiatives that you have in place?
Vicki Hollub:
Yes. We had originally assumed $250 million for our 2020 -- based on our 2020 actuals, that incremental of $250 million this year. Our current assessment is $350 million to $450 million. And unfortunately, for Richard, it's all falling in his area. But they're dealing with it very well. I'll pass it to him to give you the details.
Richard Jackson:
Yes. Perfect. Thanks, Vicki. Yes, just to walk through that, I mean, a couple of things. Certainly, we have seen that 7% to 10% incrementally for us this year. But in our base plan, we had assumed a 2% offset, and we're now up to 6%. And so part of our strategy, and I'll talk through a couple of pieces on this whole thing, was securing quality resources.
If we get into the production cadence for the second half of the year, that delivery schedule and performance is very important. And so working with the right vendors to secure that has been important for us. But let me just rattle off a few. Like most people, OCTG has seen some of the highest sort of inflationary pressures. We work with 1 key supplier and 1 distributor for that. And so when we think about sort of inflation, you think about what is the supply security and then what is the pricing. In the supply security, we feel good out a year and really have worked that hard over this year. Developing in core areas like we do gives us a lot of ability to do that. And in pricing, we secure out about 6 months. And so we feel good going into the end of the year and then into 2023, that we're timing that fairly well in terms of how that looks. Rigs and frac core, as I mentioned earlier, securing some of those operated resources. Shifting the OBO dollars allowed us to get in front of that and get, again, the right rigs and frac cores for that. We're contracted with a little over 50% of our rigs through the first part of next year. And our frac core's similar as we look out. And so feel good about that, but we've really narrowed again to the core frac and rig providers that we feel like can secure performance. And then finally saying, again, we've worked a lot on that. I think, one, we've gone to more integrated frac providers, and they continue to help us on logistics and sand supply. But then our sand supplier, our logistics facility in Aventine has allowed us to get ahead on that. And so we feel like supply is secured, and most of our price is secured through the second half of the year. So those have been the big areas that have moved up for us. It has definitely been drilling and completion focused facilities has seen a lot less, 5% OpEx, a lot less as well. So hopefully, that provides some detail in terms of what we've been doing.
Operator:
The next question comes from Doug Leggate from Bank of America.
Douglas Leggate:
Vicki or Rob, I wonder if I could go back to the discussion around potentially being a bit more aggressive than a $4 cash return in 2023? And I guess my question is, where do you see the, I guess, the flexibility regarding trying to pay down the preference burden, I guess, the $10 billion, versus continuing to pay down debt? What's the trade-off between those 2, if you could try and frame it for us? I guess I'm trying to understand how much more than $4 per share you'd be prepared to go?
Vicki Hollub:
Doug, it really depends on the macro. Right now, we're really trying to -- we can't even forecast from 1 hour to the next or even 1 minute to the next what prices are going to be. So a lot of our strategy around the preferred would depend on the macro because of -- as you know, the terms of the deal are challenging if not planned out in a way that enables you to take advantage of the trigger point. So currently, we're really trying to assess what the macro will look like, and we're going to be prepared to make the best value decision, whether that's continued debt reduction along with preferred and along with common.
But right now, the reality is that from our capital framework, we have always had a priority to reduce debt. We'll continue to do that. And we'll do that at a faster pace than the maturities. We just don't know how fast we'll do it. And with respect to the preferred, it really depends on what we see getting through the end of this year and looking into next year what the macro will be, whether the recession, if there is one, will be short or long or deep, and what the other opportunities may look like from a debt perspective, and that could depend on what inflation does.
Douglas Leggate:
I appreciate the answer, Vicki. And I'm going to stay with you, if I may, as a quick follow-up. So before things got crazy over the last couple of years, you had talked about low single-digit growth in production. And of course, the priorities all changed with the balance sheet. So as you kind of get line of sight to the balance sheet and back to perhaps where you want it to be, what are you thinking now in terms of what happens to the growth element of prioritizing in terms of where you relatively prioritize capital? And I'll leave it there.
Vicki Hollub:
Well, the good thing is what we see that we have today is a great opportunity, and that is that we don't have to grow our cash flow right now. And we have an opportunity because of the valuation of our stock right now to continue to make that a key part of our value proposition going forward. We'll do a little bit of dividend increase. We'll certainly mature our debt faster than what the current schedule is in terms of maturities because we want to accelerate that. But we'll also buy back a significant volume of shares, or at least we hope to over the next few years. And we don't feel the need to grow production until we get beyond that point because we feel like one of the best values right now is investment in our own stock.
Operator:
The next question comes from Neal Dingmann from Truist.
Neal Dingmann:
Vicki, maybe just to follow on that last one. On M&A, are you saying that sort of given the current upstream, midstream OxyChem, you'll likely stand pat with either you don't really obviously need to divest anything and still the best spend on the money is in livestock, would it be fair to say the biggest M&A might be coming from the low carbon area?
Vicki Hollub:
Yes, I think that the only M&A that we see that would make sense for us is what we have been doing, and that's just to get bigger in the areas that we are. So increasing our working interest and/or trading acres for bolt-ons to where we are right now in the resources business and in the EOR business. So we have opportunities to do that. We picked up a little bit offshore. So that's -- those are the kind of M&A.
So we're not talking big M&A here. That's not something that we feel like we need to do. But with respect to low carbon ventures, that is a bit of a different story because we're growing a business there. And the -- what we're doing there is looking for technologies that fit within our strategy and that support our strategy. We're not going to take the shotgun approach, where we're putting dollars into 100 different little small tech companies. We're looking for technologies that make our strategy better. And where we find those, we're going to make equity investments when we feel it's a part of what we want to build ultimately. I think the team has spent with just about $200 million, they have gotten us into 2 technologies I really think are revolutionary. One is NetPower, which generates electricity at a fairly low cost, lower than a traditional gas plant with carbon capture. So this -- NetPower technology generates electricity, but also captures the emissions. So there are no emissions and no volatile organics or anything like that. So NetPower is really important for us. And then direct air capture. Back to NetPower, it's going to be revolutionary, I believe, for the electric power generation industry around the world. So that's the technology that's critically important. Direct air capture is, too. And we're looking at some other technologies. There are a few things that we're putting money into that we believe has a real chance to improve our business. And those are -- that's the way we kind of look at investments and low carbon opportunities.
Neal Dingmann:
Okay. And then one last for either Robert or Jeff maybe. Just on the preferred, has there been any conversation about maybe just direct repurchase of those given obviously the same firm mind. Obviously, a lot of equity in the company. I'm just wondering, is there -- or is that just going to be sort of, I guess, buying back as you would your debt and all?
Vicki Hollub:
It's really going to be a part of a more comprehensive evaluation as we go forward. So we'll look at that as time passes, and we'll certainly keep you guys updated. But what we intend to do is make the best value decision and proceed with the capital framework that we've laid out.
Operator:
The next question comes from Jeanine Wai from Barclays.
Jeanine Wai:
Our first question, I guess, maybe heading back on cash returns and a follow-up to a couple of the other questions. The plan for 2023-plus now is to retire debt maturities as they come due. We're looking at your debt schedule, and there's really nothing more than like $2 billion coming due in any one year, so super manageable until 2030. You've got cash building on our model to, call it, like $12 billion on strip by the end of the year. So lots of options. You had some helpful comments on the macro governors on how you're going to allocate capital over the next year or 2. Do you have an updated view on your reserve cash level? We realize there's a lot of reasons to hold cash above that, but that's always a helpful number for us.
Vicki Hollub:
Yes. Before I pass that to Rob for the answer to that question, I just want to say that you're right about our debt maturities. So we expect this year to be able to lower our debt based on what we see from the macro by another $2 billion to $2.5 billion, which would get us close to $18 billion. Then to get us down to the $15 billion that Rob mentioned in his script is that we would have -- those maturities would come due, all of them, before August, end of August of 2025. We don't want to wait 3 years to get our debt down to $15 billion. So we would expect to, assuming the macro allows, to cut that considerably. We do want to get to the $15 billion sooner rather than later. So we'll fit that in. And that is still a priority for us. I'll pass it to Rob now for the other question.
Robert Peterson:
Yes, Jeanine. And so certainly based on what Vicki just said and the fact we'll target, we should be able to do well beyond $1.9 billion that we have for the balance of the year on the share repurchase program, assuming the macro is consistent or relatively consistent to the strip prices right now. And part of targeting that will be some of the maturities you listed off. So -- but we've been able to opportunistically balance between short- and long-term debt maturities. As we move on year-to-date, it's about 45%. In the current decade, about 55% later in the [ date ] [indiscernible]. And so we continue to be opportunistic between knocking out near-term maturities, including ones that are higher interest rate coupon ones now because of the way they've come down with interest rates, but also achieving discount on longer-dated bonds. So you can expect that mix to stay together.
As far as cash reserves, certainly with a very manageable debt maturity profile, we've been holding higher cash levels historically. We ended last year about $2.5 billion. I think we'd be comfortable with something closer to $1.5 billion by the end of this year, providing another certainly $1 billion of cash to work with this year just from the reduction on reserves.
Jeanine Wai:
Okay. Great. That's very helpful. Maybe if we could turn to operations and the Permian. You probably provided some really helpful color on the Q3 Permian guide in your prepared remarks. And the implied 4Q Permian guidance calls for, I think we calculated 12% increase quarter-on-quarter to hit the midpoint. And it sounds like from your comments, there are some third-party stuff that's going on that may come back online in Q4, which will help. But any comments that you have around kind of how you try to stack the deck in your favor on execution in Q4 in the Permian, that would be really helpful just because I think a lot of people are looking at the Permian at the end of the year and trying to figure out implications for next year.
Richard Jackson:
Yes. I appreciate it. Well, there are a few pieces. You're exactly right was we thought about sort of this building security in our production delivery for the year. There are several pieces that were important to us. If I go back even to where we started and entered the year from a rig count perspective, we've added -- if you go back to second half of '21, we went from about 11.5 rigs to the first half of this year over 15, to second half of the year at 19. And so being able to secure those operated rigs early to get the performance was really important to us.
So same thing in the back half of this year. If I look at first half versus second half, we look to add about 78 more wells online compared to the first half. So a tremendous step-up in activity. We're able to utilize our frac cores more efficiently with the development plans that we've put together. We're adding 1 additional in the second half of this year, but we're really creating much more smooth operations with what we've done and transition with that OBO capital. And I guess the pieces I'd point to, what's been important to us operationally is, again, back to performance. Most of the capital for the second half of the year and the production deliveries in the Delaware, we have about 80% of those wells that are coming online are Third Bone Springs to Wolfcamp A. So it derisks a lot in terms of that production delivery. We've added lateral length. We're 1,000-foot longer compared to last year to when we look at the second half of this year. Our 24-hour IP is about 14% better than the first half of last year. And so all of that has added in terms of derisking the second half of the year. Drilling completion efficiencies improved. Our feet per day is up quarter-to-quarter about 10%. Our nonproductive time is reduced about 7% in the Delaware. And so what we've seen as we've added these rigs, we've been able to work as an operational team, the performance continues to improve. And we're looking at the second half of the year expecting about a 10% time-to-market improvement with those operations. So put a lot of pieces in place in the first half of this year, now we just need to go execute. But really, the plan has been built to achieve that production growth you noted, and we're well on our way.
Operator:
The final question comes from Neil Mehta from Goldman Sachs.
Neil Mehta:
The first question is just the path to investment grade. Can you provide any color in terms of the milestones that you're getting to in order to achieve that? How are -- how should the investment community think about timing recognizing it's out of your control? And what would getting to investment grade mean to your business?
Robert Peterson:
Yes, Neil. Sure. So year-to-date, as we mentioned, we paid $8.1 billion of debt, certainly far beyond the $5 billion initial target we established for the year. And included in that, in the second quarter, we knocked out [ 60% ] of what I would call the annual risk associated with our 0 coupon bonds. That was occurring every October. If you look back to July of last year -- or June of last year, we retired almost $15 billion of debt. So very meaningful progress on the debt reduction side of it.
But in addition to the debt reduction, all 3 agencies have their own other metrics. I'll call them, the [ return IG ]. And so they're all sitting, as we discussed, 1 notch below. Our forecast that we have internally have us exceeding the majority of these criteria before the end of the year or, in many cases, we're actually ahead of now on the last 12-month basis. But the conversation we've been having with the agencies would suggest, I just want you to get more comfortable, that in a different oil price environment, and all of the agencies have long-term oil prices well below current oil prices, that they would be comfortable that we would not slip back into being a high-yield type credit. But again, like I said, take something like Moody's, for example, they want to look at retained cash flow to adjusted debt to be greater than 40% and essentially the retained cash flow exclusive preferred dividends. But the adjusted debt does include half of the Berkshire. So the Berkshire does factor into that. And so we're well ahead of that forecast. And even we're adjusting for Moody's price forecast relative to ours. And in the case of Fitch, I'll give you an example. They also look at our sort of mid-cycle funds flow from operation it just covered [ supposed ] 5.5x. The preferred is excluded from the funds flow, but it's included in interest expense. We're going to be well over 5.5x certainly this year by year-end. And so I think on a lot of these statistics, we are passing through these very rapidly, probably much more -- certainly rapidly than we suspected or the agencies suspected. We're having very constructive conversations with them and making sure that the decisions we're making are contributing towards that. As you said, we don't have ultimate control over when that occurs, but comfortably looking at all of the various metrics that they've thrown at us relative to our financial policy and metrics. I feel confident that we would be in good stead with all those toward the end of the year. We have a gap with S&P's expectations on reported debt, but that's really the only one that we're going to have a significant gap in right now. But certainly with Fitch and Moody's, I'm confidence on those 2 agencies that what they've laid out for us explicitly on terms of metrics, that we can meet this before the end of the year.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Just want to thank you all for your participation in our call today, and have a good day. Thanks.
Operator:
Conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to Occidental's First Quarter 2022 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Drew. Good afternoon, everyone, and thank you for participating in Occidental's First Quarter 2022 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President of Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. I will now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good afternoon, everyone. We're especially proud of our results this quarter as our strong operational and financial performance enabled us to generate our highest reported and adjusted earnings in over a decade, resulting in an annualized return on capital employed of 21% when calculated with adjusted earnings. We also reported a record level of free cash flow for the fifth consecutive quarter. The increase in free cash flow compared to last quarter was achieved as we began executing on our 2022 capital plan to support our cash flow longevity.
As we will detail in a few minutes, we made meaningful progress towards our near-term goal of retiring $5 billion of debt. We remain focused on reducing debt this year as we advance our shareholder return framework. We repaid over $3.6 billion of debt as a part of the near-term goals we announced last quarter to repay an additional $5 billion of principal and lower net debt to $20 billion. Once the $5 billion target has been achieved, we -- our focus will expand to the $3 billion share repurchase program. When this first phase of our shareholder return framework is complete, we will continue to focus on debt reduction until we have achieved the face value of our debt to the high teens. When we have line of sight on reaching this milestone, we will detail the next phase of our shareholder return framework. During our most recent earnings call, we spoke about the importance of lowering our interest expense to support a dividend that can sustainably grow throughout the cycle. Continuing to lower debt, combined with managing the number of shares outstanding, will enhance the sustainability of our dividend while positioning us to increase it at the appropriate time. This morning, I will cover our first quarter operational performance and Rob will cover our financial results as well as our updated guidance, which includes an increase in guidance for OxyChem and midstream's 2022 earnings. Our first quarter results are a great example of how Oxy's operational excellence and asset portfolio position our shareholders to benefit from a high commodity price environment. In the first quarter, we generated $3.3 billion of free cash flow. This is more than twice what we generated in the first quarter of 2021, which at that time was our highest level of free cash flow in over a decade. Our strong financial results were driven by our business delivering exceptional performance while practicing disciplined capital allocation and cost control, combined with the benefits of an improved financial position and higher commodity prices. Switching to operational performance. We delivered first quarter production from continuing operations of approximately 1.1 million BOE per day, in line with the midpoint of our guidance and with total company-wide spending -- capital spending of $858 million. Our international operations successfully completed their scheduled turnarounds in the quarter and production has returned to normalized levels. Compared to the first quarter, we expect international production to increase accordingly in the second quarter. While higher prices are expected to lower our full year international guidance under our production sharing contracts, we expect the impact to be fully offset by outperformance in our Rockies and Gulf of Mexico businesses. As I mentioned during our last call, we expect company-wide production to grow from the second quarter through the end of the year as our targeted capital investments sustain 2022 average production in line with the previous year. OxyChem's performance continued to exceed expectations as the business benefited from robust pricing in the caustic, chlorine and PVC markets. OxyChem delivered record earnings this quarter, which we expect to contribute to 2022 being another record year for the business. Following several consecutive record quarters, we see the potential for market conditions to dampen slightly in the second half of the year, though the long-term fundamentals continue to remain supportive. I'm very proud of OxyChem's workforce who recently received 13 Responsible Care and 15 facility safety awards from the American Chemistry Council for their 2021 performance. Midstream and marketing's outperformance compared to guidance in the first quarter was primarily driven by higher margins from gas processing and sulfur sales and our ability to optimize gas transportation in the Permian and Rockies and the timing of export sales. While short-term opportunities in the commodity markets are difficult to predict, our midstream team excels at finding and taking full advantage of such opportunities when they arise. I'm pleased to say that our first quarter results continue to demonstrate how the quality of the assets, the talent of our teams and our improved financial position serve as catalysts for strong financial results and provide a solid foundation for free cash flow generation. Our teams did an excellent job of managing the planned turnarounds and maintenance projects this quarter. We completed turnarounds in Algeria, Al Hosn and Dolphin and a series of maintenance projects in the Gulf of Mexico. Completing these planned projects increase the reliability and efficiency of our assets. The Al Hosn turnaround involved the first full plant shutdown, during which time we safely completed over 500 tie-ins related to the expansion project. The expansion is progressing as planned with the capacity increase expected to be online towards the middle of next year. Our Rockies team brought online their largest pad ever with 23 wells and drilled their longest lateral to date at over 15,000 feet. That business continues to perform well, with strong well productivity and higher-than-expected NGL yields driving first quarter performance. Our team in the Midland Basin had similar success bringing online the 12-well 15,000-foot development we mentioned on our most recent earnings call. And in Algeria, we drilled and completed Oxy's first development well in 2022 with time to market for the completion and hookup significantly exceeding prior performance. These are just a few of the many operational achievements our teams continue to deliver each quarter. In addition to focusing on operational improvements, we continue to pursue new and resourceful ways to reduce emissions. For example, in the DJ and Permian Basins, we successfully trialed a new in-house methane detection system that will help us on our net 0 pathway. We also plan to build on the success of our water recycling partnership by developing similar systems and additional locations this year. I'll now turn the call over to Rob, who will walk you through our first quarter results and guidance.
Robert Peterson:
Thank you, Vicki, and good afternoon. Our cash flow priorities continue to direct free cash flow allocation in the first quarter as we repaid an additional debt in April and paid the first distribution of our increased common dividend. On our last call, we detailed our near-term debt reduction targets, including repaying $5 billion of debt and reducing net debt to $20 billion. Our progress towards meeting these targets advanced significantly in the first quarter.
We repaid approximately $3.3 billion of debt and ended the quarter with net debt of $23.3 billion, reflecting the face value of our debt of $25.2 billion and the unrestricted cash balance of $1.9 billion. Repaying $3.3 billion of debt in the first quarter was accomplished through a combination of a $2.9 billion tender offer, exercising the call provision on a note and open market repurchases. Following quarter end, we retired approximately $300 million in additional debt using open-market repurchases, lowering gross debt to approximately $24.9 billion, which is the balance today. It is reasonable to expect that we could meet our near-term debt targets and then initiate our share repurchase program during the second quarter. Once we complete our near-term debt reduction target and repurchased $3 billion of shares, we will continue to allocate free cash flow to repaying debt as we lower gross debt to the high teens in billions. We believe reducing debt to this level will speed our return to investment grade and better position us to sustain a greater dividend at lower prices. When we reach this stage, we intend to transition from proactively reducing debt to primarily addressing maturities as they come due. Our debt reduction efforts continue to receive positive recognition. Since our last earnings call, Moody's upgraded our credit rating to Ba1 with a positive outlook. All 3 of the major credit rating agencies now rate our debt as 1 notch below investment grade, which we view as recognition of the pronounced and ongoing improvement in our credit profile. Our consistently strong operational results in combination with the current commodity price environment are driving improved profitability on top of our already robust free cash flow generation. In the first quarter, we announced an adjusted profit of $2.12 per diluted share, our highest adjusted core EPS in over a decade; and reported profit of $4.65 per diluted share. The difference between our adjusted and reported profit for the quarter was mainly driven by the legal entity reorganization described in our most recent 10-K and 10-Q filings. Following the completion of our large-scale post-acquisition divestiture program, a portion of the existing tax basis was reallocated to operating assets, thus reducing our deferred tax liabilities by approximately $2.6 billion, which was recognized in our reported earnings for the quarter. We resumed paying U.S. federal cash taxes in the quarter, ahead of our earlier expectation. This was due in part to the strong earnings generated in the first quarter, combined with our expectations for commodity prices and earnings over the remainder of the year. Given current commodity price expectations, we now expect to exhaust our U.S. net operating losses and most of our general business credit carryforwards this year. However, the NOLs and credits that we currently have remaining are expected to limit the amount of cash taxes paid this year. For example, we would expect to pay approximately $600 million in U.S. federal cash taxes if WTI averaged $90 per barrel in 2022. The increase in commodity prices certainly benefited us during the quarter, as demonstrated by our strong earnings and free cash flow generation. The commodity price environment improvement compared to the previous quarter also resulted in higher accounts receivable balances, which contributed to a negative working capital change. Negative working capital change was also driven by typical first quarter payments such as semi-annual interest payments, annual property tax payments and payments on our compensation plan. As was the case in 2021, we see the potential for the working capital change to partially reverse over the remainder of the year if commodity prices are stable and due to payments accrued during the year being made in subsequent first quarter. We are pleased to be able to update our full year guidance for midstream and OxyChem, reflecting strong first quarter performance and improved market conditions. Our revised full year guidance for OxyChem now includes the expectation of a fourth consecutive record for quarterly earnings in the second quarter. We recognize the possibility of softer product prices later in the year but still expect the third and fourth quarters to be exceptionally strong by historical standards. As Vicki mentioned, our Rockies business continues to perform well. Our expectation of continued strong well performance over the remainder of the year provides us with confidence to raise full year guidance for the Rockies by 5,000 BOE per day. On previous calls, we've discussed how we've been working closely with Colorado communities and regulators in implementing the state's new permitting process. Our drilling permits we have in hand are sufficient to run a single rig for the remainder of 2022. It is no longer feasible for us to run a multi-rig program for Colorado this year given the current pace of state approvals. As a result, we plan to reallocate activity from the Rockies to the Permian in the second half of the year. This activity change will not impact our 2022 production and is included in domestic onshore activity slide in the appendix to our earnings presentation. We plan to submit development plans in the coming months that will cover over 1,100 rig days. We are hopeful that as Colorado's new permitting process matures, it will continue to become more efficient. Regulatory certainty early on in the process would provide us with the option to add activity back in the Rockies in future years given oil and gas development plans we expect to submit for this year. While our company-wide full year guidance is unchanged, as Vicki mentioned, we have included a 6,000 BOE per day downward adjustment to our full year international guidance, reflecting the impact of higher oil prices in our production sharing contracts. Our original budget included a forecast of $73 for Brent while our revised guidance reflects a Brent average price of $95 for 2022. Inclusive of these activity changes, our 2022 capital guidance remains at $3.9 billion to $4.3 billion. We mentioned on our last call that our 2022 capital guidance incorporates approximately $250 million of inflation compared to 2021. Cost of materials and services necessary for operations, especially onshore in the United States, has continued to increase. We are working to offset inflationary pressures through additional efficiency. But if price increases continue, we may spin near the top end of our capital guidance this year. Certain pricing pressures such as labor and our WTI index CO2 purchase contracts in the EOR business have become pressing, leading to a slight upward adjustment in our full year guidance for domestic OpEx. We are pleased with our strong start to 2022. With one full quarter behind us, we have completed scheduled turnarounds, continued to pay down debt, established a shareholder return framework, provided a comprehensive update on our low-carbon strategy and set new quarterly records for earnings and cash flow. We will continue to focus on delivering value for shareholders this year and beyond. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. I would like to thank our shareholders for voting with the Board at our recent Annual Meeting and defeating a proposal that if approved, would have been counterproductive as we work towards achieving our net 0 ambition. Our quantitative short-, medium- and long-term goals for Scope 1, 2 and 3 emissions are directly aligned with the goals of the Paris Agreement, our competitive strengths as a carbon management leader and our strategy to achieve net 0 before 2050.
With our journey towards net 0 fully underway, we presented a market update in March on our low-carbon business strategy. We provided details of the market opportunity and our plans to deliver climate and business solutions that leverage our assets and capabilities in carbon management, including CCUS. We are advancing the technological solutions that can deliver large scale and rapid emission reduction throughout our value chain. Additionally, our low-carbon strategy creates value for our existing businesses while, at the same time, helping to accelerate the path to net 0 for ourselves and other leading companies in multiple industries. We'll now open the call for your questions.
Operator:
[Operator Instructions] The first question comes from Michael Scialla with Stifel.
Michael Scialla:
Rob, you mentioned that you could potentially commence the buyback this quarter. I wanted to see -- as you look beyond this year, based on where the strip prices are right now, can you give any indication of what you're thinking in terms of free cash flow priorities for the longer term?
Robert Peterson:
Yes, Michael. Thanks for the question. So we haven't provided any guidance for 2023 and beyond at this point. I think what we've indicated in the notes was that as we complete the $5 billion and the $3 billion this year and then apply the balance of any additional cash to the balance sheet, driving that gross debt down into the high teens, that we would anticipate translating -- less of the debt reductions being the priority and more attack the debt on a -- as it comes to maturity basis. And so that would imply, in the 2023 and beyond, a re-shifting of our priorities such that shareholder returns and other priorities will move towards the higher end of the scale.
Michael Scialla:
Okay. Understood. And I know your hedges have rolled off at this point. Do you see any need to protect any of the debt reduction targets or the buyback program? Or I guess over the longer term, if you -- the dividend becomes part of the free cash flow, return to shareholders, any need to reinstitute a hedging program to protect any of those things?
Robert Peterson:
No. So Michael, our history as a company has been fairly hedge adverse. Our belief is that our shareholders will ultimately receive and the company will receive the best value for the commodities we produce and sell if we just move with the cycle throughout the entire cycle. We did deviate from that because -- in 2020 due to the amount of maturities we had coming due at the time. Since then, the combination of the trough driving out, the moving out of certain maturities, the paying off and certain reduction of debt that we've talked about and the combination of creating a sustainable business at a much lower price has removed some of that.
And also, I would say that there's other pieces to it with our chemical business, our midstream business, international business that operate a little differently in some of those price environments, creates other built-in hedges towards that. And so I don't see us going towards hedging to try and attempt to mitigate any of those risks. I mean we have a pretty manageable debt profile now, particularly for the balance of the decade. With the work that we did in the first quarter, we only have 2 years, '25 and '26, that have any maturity towers that exceed $2 billion, and that will certainly be a focus as we move forward. So I don't really see the need for hedges to mitigate any of the risks moving forward. And as Vicki outlined on our last call, the dividend approach is meant to be sustainable at low prices. The share repurchases will make that dividend that much cheaper at low prices for us. So I think we're doing the right things to protect from low price environments the business without having to artificially try and protect with hedges.
Operator:
The next question comes from Jeanine Wai with Barclays.
Jeanine Wai:
So maybe we can just start back with -- either Rob or Vicki, on your prepared remarks about what's going on next. So we just wanted to clarify the sequencing of further debt reduction and incremental shareholder returns. It sounds like from your commentary that further gross debt reduction beyond the first $5 billion, that, that will be ahead of additional cash returns beyond the $3 billion buyback and not in parallel. And so I guess reducing gross debt versus net debt, that's pretty different logistically. That's pretty easy given your free cash flow. So do you have any color on how long you think it will take to achieve the high-teens gross debt target given what you see in the market for tenders and what you see in the market for open purchases?
Robert Peterson:
Yes. It's a good question, Jeanine. I think that the -- as we laid out last quarter and what I've tried to convey in my remarks is we would complete the $5 billion of debt reduction and then initiate share purchases. I think that based on being at 3.6 where we are today, and as we've demonstrated, we have a combination of the open-market repurchases, tenders, make-whole provisions, et cetera. All that are attractive in the current environment simply because of the rise in treasuries, that achieving that is not going to be a heavy lift in the quarter. And we anticipate that proceeding with share repurchases during the quarter is reasonable to expect during Q2.
And so the timing of how long it takes to complete the share repurchases is going to be really dictated by the pace at which we're able to retire and bring those shares in. The stock is obviously very liquid. We have at our disposal lots of different mechanisms to actually acquire the shares. We're going to do it in a way that is most constructive and bring most value to the shareholders in the process. And then, we do have cash available beyond that, which the current pricing environment would certainly suggest we would have cash well above those 2 pieces of -- $8 billion between those 2 programs. We would resume applying that back to the balance sheet in the process for the balance of the year. And then...
Jeanine Wai:
Okay. My apologies. I was referring to getting to the high-teens gross debt, but we can take it offline. That's okay.
Our second question, maybe just on growth. How are you thinking about production growth beyond 2022 given the medium-term gross debt reduction target? Is it kind of like an either/or on growth and paying down debt? Or is -- the price environment, is it constructive enough and the balance sheet is improved enough that you can do both?
Vicki Hollub:
Well, I think that by the time we get to 2023, certainly, our balance sheet, we believe, is going to be very, very healthy versus where we started. So as Rob has mentioned, we expect to have the cash to be able to go beyond the $8 billion this year and every dollar above the $5 billion. That's the $3 billion of -- including the $3 billion of share repurchases in that $8 billion. So any free dollar above that would go to debt reduction. So we do expect to make significant progress with that this year.
With respect to production increases for 2023, we are going to increase throughout the rest of this year. And going into 2023, the production that we have is always a result of the programs that we put in place. And so it's going to determine the development programs that are in place by the end of this year, heading into 2023 and what we see as the appropriate pace to deliver the most net present value. And we've said before that, that could be between no growth and 5%. But as we look at the macro towards the end of the year and lay the uncertainties that we see today, we'll be able to finalize that and as you -- as we always do, let you know towards the beginning of next year.
Operator:
The next question comes from David Deckelbaum with Cowen.
David Deckelbaum:
Appreciate the time. I wanted to ask an additional question around growth into next year, specifically to the Permian. Your guide obviously implies that you'd be ramping towards almost 600,000 barrel equivalent a day there by the end of '22. Should we think about 16 gross rigs being sufficient to continue growing that profile into 2023?
Richard Jackson:
David, this is Richard. Let me start with that. I think the way I'll try to answer that is kind of talk through the cadence of how we entered the year and maybe how that translates to second quarter into the second half of the year. So very pleased with really where we landed in the first quarter. We had a beat for the onshore U.S. and specifically part the Rockies, but also part the Permian. And really, that was on a bit of uncertainty at the time we provided that guidance around final recovery of the weather event and then certainly contemplating some of the supply chain challenges that the industry saw.
And so we are very pleased where we landed in the first quarter. From an activity ramp-up plan, we're able to add the rigs that we started in the fourth quarter into the first quarter. So really, we're at near activity level for the rest of the year. We're at about 17 rigs and 5 frac cores in the first quarter. I think importantly, as we think about this, the time to market was on pace. And so we actually finished 2 wells online better in the first quarter and increased our total year outlook by 10. And so that was very important for us to continue to deliver that time to market on pace. But as you think about sort of this inflection of growth going into the second quarter and then the back half of the year, March was 24,000 barrels a day better than February. And I think below that, 62% of the first quarter wells were online in March and really late March. So again, very pleased with that sort of ramp-up and then transition. If you go back into last year, it was really -- I think we talked about on the last call a lot of transition from DUCs in the Rockies, which carried a lot of production into what I would consider a much more steady-state drilling and completion cadence really in the second quarter of this year and to the back half of the next year. So we expect to really benefit from that. And so when we think about really the second quarter, we hit this -- add a couple of rigs, as you mentioned, in the Permian, to hit the 16 and really 18 overall or net rigs. Really not a big change because our net rigs stay about the same with the drop of the Rockies in the back half of the year. But you can start looking at the Delaware. It's a really important area for us to deliver this growth. We have 30 wells that were online in the first quarter. Really, the second quarter, that goes to about 40. And then the back half of the year, that increases to about 50 per quarter. And so feel good about that delivery schedule in the Delaware. Again, going back to last year, we had about 7.5 rigs in the second half of last year in the Delaware. In the first half of this year, we'll be at 12. And so again, as we went from DUCs to drilling, that was really the next stage of the steady-state recovery. And then we'll enter into the full sort of completion, online schedule for the back half of the year. And so the good news is those wells are coming online very well. I think of all the wells -- and I pulled out this morning the Texas Delaware. I think we had 23 wells online in the first quarter that averaged -- they all average over 4,000 barrels a day on a 24-hour IP. So time to market is in line. Production's in line. And then the final thing I would say as we think about the back half of the year is really protecting that base. And I think part of the Rockies beat, we were real pleased with -- they're about 2% better on base than what we had in the plan. And so being able to protect that base production makes it a lot better. So when you look at time to market, you look at well performance and then you look at sort of our takeaway position and flexibility in the portfolio, we feel really good, continue to work with WES on strong uptime and sort of operability, been able to look beyond 2022. And so that final component of really derisking what we're trying to do is very important. So I think we -- to kind of land on where you ended your question, I think, we feel really good about where we are this year. I think we've got flexibility in the back half of the year, as Vicki said, to adjust activities and really hit what is the right capital and development program for next year to hit really what the plan needs to be given the macro conditions and what we're trying to do as a company.
David Deckelbaum:
I got my value's worth with that question. Appreciate it. Robert, just my follow-up would be -- and I'm sorry to belabor the point, but I want to ask another question around the timing of return of capital and debt paydown. If we understand the sequence correct, once you get to another tranche beyond the buybacks where you're looking to get debt down to the teens, would that then preclude any incremental return of capital via buybacks and dividends? Or should we think about it as once you get through that next tranche of debt pay down and get that into the mid-teens, would you be agnostic as long as you're sort of delivering, call it, like 50% of free cash back to shareholders on how quickly you might be triggering a paydown of the preferred notes?
Robert Peterson:
Yes. So the preferred -- so obviously, the preferred -- if you look at the $3 billion of share repurchases and add into that the dividend of $0.13, assuming that those are flat for the course of 4 consecutive quarters -- or 3 consecutive quarters, et cetera, you're still not going to quite be at the level of triggering the $4 per share Berkshire trigger. And so as we've indicated, once we go beyond the $8 billion we've laid out for debt and share repurchases, we would intend to continue reducing debt, again, with the goal being to get that gross debt down into the high teens, where, based on our conversations with the 3 rating agencies, is one of the key waypoints we need to do to achieve investment grade.
There are several other metrics they provide to us that we're doing very well on relative to. We certainly know that they're going to -- that a lot of these metrics are in place today based on commodity prices. And so continuing to make that progress will help those metrics further to be constructive even in a more moderate price environment. So that's the reason why we're talking about going back to the debt beyond the share repurchase. We do think it's very important for us to achieve that investment-grade status or get to those investment-grade type metrics. And so I would look at the Berkshire as more -- the potential of Berkshire as more a product of the strategy we're moving this year as a potential, more than being a driver of the strategy this year. And so if we find ourselves in a constructive commodity price environment, we've achieved those debt targets we've talked about, we've got those investment-grade type metrics and we're having constructive discussions with those agencies about being investment grade, then I think you are in a position, as both Vicki and I laid out in our comments, that you could see a transition for us away from being -- debt being the predominant consumer of cash that we're generating beyond spending for the business and end up being something more targeted towards shareholder returns. And for us, as we discussed, we laid it out before, that the favorite way of returning value to shareholders beyond the dividend is through share repurchases because it does increase the sustainability of the dividend in lower price environments. We also have outstanding warrants. We know that those are sources of dilution. We also issued common shares as part of the acquisition. So it's a prime way for us to reduce it. And if we do make a nominal increase in share repurchases in that 12-month period, it will automatically trigger the provision of targeting the Berkshire. So it's not a choice of do you want to trigger the Berkshire. If we cross that $4 threshold, we will begin the process of the common return and the return -- and the reduction of Berkshire preferred. And so sitting here today in May, 8 months away from January of 2023, we're not in a position to forecast where our cash flow is going to be in the first quarter or where it's going to be at. But if we can accomplish these goals, it puts us in a position where we have the optionality, similar to the optionality Richard described and discussed about production exiting the year, of being able to be in a position where through additional shareholder returns, we would trigger Berkshire and begin reducing the principal of the Berkshire in the process of doing that. And so we have some ground to hoe to get there. The commodity price environment is very constructive for us right now. The current -- certainly, the strip prices suggest this is very achievable, and we're doing the right things in the business in terms of driving cost out and keeping costs down in the process. So the combination of that, the chemicals business performance, our portfolio are all setting us up to be successful in that. We're not very big on forecasting our cash flow in subsequent quarters or what we're going to do quarters away from this. But I think we've provided you with what our expectations are to do with cash for the balance of the year. And if all those things happen, it puts us in a position where to increase share returns, we would be going after the principal on the Berkshire at that point.
Operator:
The next question comes from Matt Portillo with TPH.
Matthew Portillo:
Maybe just to start out on the DJ. I was hoping you might be able to provide a little bit more context around the permitting process and maybe some of the delays you're seeing. And then I was curious, if you hold 1 rig into 2023, what that might mean from a well count perspective for you all.
Vicki Hollub:
Yes, Matt. I'll let Richard take that.
Richard Jackson:
Matt, so thinking about the DJ this year and then into next year, we feel good about the progress we're actually making with our permits. I think the decision to move the rig to -- allocation to the Delaware is really allowing us to get our development plans in place for 2023. We've got -- I think we mentioned in the prepared comments we've got permits approved to take that 1 rig into next year. We've got another 50 sort of wells that are across a couple of pads that are in the various stages of approval but we feel good about where they're at. And then we have another 200 that are part of a larger sort of program that we're working through the system.
I would say we've got a lot of engagement obviously over the last year thinking about this. We've got a lot of improvements in technology and some things that I think will really fit well into the permitting expectations, both locally and at the state level. So really, as we go into next year, we would be capable of really getting to -- back to that 2-rig level and perhaps even more. And so from a well count perspective, it could look very similar to where we started this year for the DJ in terms of count. But the challenge for us is to obviously develop responsibly, work with the local communities, work with the states, put together the best plan we can. But when we do that, we want to be prepared to develop because those are some very good wells for us within our portfolio.
Matthew Portillo:
Perfect. And then a follow-up operational question. Just wanted to see if you might be able to spend a little bit of time talking about the Gulf of Mexico development plans from a tie-in and development perspective over the next couple of years and what that might mean for production. It's obviously a great free cash flow generative asset for the company. So I just was hoping to get a little bit more context around how you're feeling on that front moving forward.
Vicki Hollub:
Yes. We still feel really good about what we're doing in the Gulf of Mexico for the next few years. As you know, we've talked recently about the full-field development look at all the structures and the opportunities and high-graded. And then we've already started now working on a subsea -- or subsurface pumping system that will enable us to increase production.
Also, we're doing some additional work around rescheduling some of our development opportunities based on the exploration success that we've had and that we see. So I think certainly, we have the assets, we have the permitting capability there to continue to maintain that cash flow over the next few years. Beyond that depends on some of the success of the exploration that we will be executing this year and early next year.
Operator:
The next question comes from Neil Mehta with Goldman Sachs.
Neil Mehta:
I had a couple of questions here around supply chain. And Vicki, in early March, you had made the comment that, I guess, caught some press, that the supply chains in the U.S. were relatively in dire shape as it relates to U.S. producers and that would be a constraint on U.S. growth. And a lot of that has proven out, especially around pressure pumping. So can you just talk about your latest views around constraints as it relates to U.S. shale and how you see this evolving from here and tie that into your view of the oil macro?
Vicki Hollub:
Yes. And my comment on that was definitely related to those who don't already have their plans in place and didn't already have their materials lined up to purchase. So anybody trying to increase activity at this point, not only in the Permian but also worldwide, would have a very difficult time being able to do that.
And with respect to the macro, I really don't think there's been a time since I've been in our industry where inventories and spare capacity are both very low. And then you couple that with the supply chain challenge. So I think that there are a lot of headwinds to increasing production worldwide. And there's never been a time, I don't think either, that companies have been trying as hard as they can to increase production. But we can't destroy value, and it's almost value destruction if you try to accelerate anything now. And some of the longer-term projects just can't get started because of the costs involved. Now for those of us that had plans in place -- and there are other companies that have done this too. But for those of us that had plans in place and had these plans in place early enough, we've been able to mitigate some of the impact of the inflation. And I'll let Richard detail some of that.
Richard Jackson:
Sure. I'll just give you a few details from the U.S. onshore perspective, where we had factored this into our plans, like Vicki said. If you remember -- if you go back, really our first quarter message, we had up to 10% contemplated in our upstream capital budget. And we've certainly seen that. We feel good still with our capital outlook because of those plans and sort of what we had factored in for uncertainty within that range.
But I'd say a couple of things. One, I'll speak quickly on inflation mitigation. But importantly, for us -- most importantly for us, maintaining those operational efficiencies and that time to market, wells online schedule was very critical. And so you'll continue to hear us talk a lot about what we're trying to do to work with our service partners to protect that.
But from an inflation perspective, I mean, the 2 big ones:
oil country tubular goods. We knew going into the year, see that. And we have -- we've had some tubulars over 100%, and that's meaningful. It's about 7% of our capital, and so that has been meaningful.
The one that had a little bit more dynamics, I think from an industry perspective in the U.S. and the Permian, was really sand. But felt good. We've worked through that well in the first quarter and good where we're at today. We think about sort of where is price and where is supply and we feel good about our supply situation. We didn't have any disruptions in the first quarter that impacted that wells online schedules. We're able to maintain schedule there. Part of that is design. We've been able to work with our development teams to be able to manage really both white and regional sand into our designs based on that supply. The other is our primary sand supplier and the use of Aventine. So again, that facility became very helpful for us in terms of storage and last-mile logistics in terms of what we're doing. And so that was really good. The last thing around sand that I think played well for us, and we appreciate, again, our service partners with this, we moved back to a bit more of an integrated strategy with our frac providers. And so that included sand -- being able to supply sand, but it also included trucking and fuel. And so both from a trucking perspective in terms of moving sand to that last mile logistics, we were able to get some help from our frac providers; and then from a use of our Tier 4 dual-fuel perspective, that fuel supply. And so that played out very well for us. We feel like we're in a good position. We feel like we're mostly locked in on price for the rest of the year. But that sort of decision and work we did with our service partner played out very well.
Neil Mehta:
And the follow-up is just around the chem side of the business. Nice to see the guidance bump here in terms of pretax income guidance. Can you just talk a little bit about how you see the trajectory of profitability through the year? It sounds like, if I understood the comment, still a strong year, but there might be some downward pressure on pricing as we think about the year playing out. So any color around that would be great.
Robert Peterson:
Yes. Sure, Neil. I guess let me answer your question by relaying where we are today. So as you indicated from our comments, the conditions are still very strong in our vinyls and in our caustic soda business. We don't -- from our, first of all, sales, the Russian-Ukraine impact is really the escalation of prices in Europe and in Asia, which is impacting their chlor-alkali operations and chlorine derivative production and leading them to not only reduce operating rates but also increase prices accordingly. That's benefiting both sides of the business because of that.
And so -- but not only that, domestically, the business remains very strong on the vinyl side of the business. And so we would estimate year-to-date March -- operating rates through March, these lag a bit but were reported by industry at 81.6% year-to-date, which is not as high as you might think it might be. But there's been a lot of controls in that due to the outages that occurred in the industry during the first quarter, which is pretty typical. But domestic demand in the first quarter was up about 10% versus last year. And in fact, domestic demand in March for the U.S. was the highest single month for domestic demand in over a decade, just reflecting that pent-up demand for construction. And despite what is relatively, based on historical value, high prices for PVC, the demand is still there, and it's being pulled right through the building products. So that's great for the business. Exports are about 7.5% higher than they were this time last -- through March last year, reflecting the fact that there's opportunities to sell PVC internationally. In some ways, the PVC is exporting U.S. gas and ethylene overseas and the places that are being impacted by the higher prices or availability. So that's all -- it's very constructive for the business. And then we see that demand being very resilient certainly through the first half of the year, a favorable housing sector, et cetera, and the export business being open for as long as it's available simply because of the U.S. advantage on gas, ethylene and energy, et cetera, versus rest of the world. So PVC feels constructive. Obviously, interest rates raising can impact housing starts, et cetera, and demand on that business. And so that's one of those uncertainties. We're not seeing anything that would suggest it's falling off, bringing fractures in the strength of PVC. We're sitting here in the month of May and watching the news, like everyone else is, regarding the Fed getting more hawkish towards interest rates can have a corollary impact on housing starts and demand at some point. And so we're just a little bit less clear on the trajectory in the second half of the year. So you see a little more cautious outlook for the business on that side. On the caustic side of things, it's been a -- we don't get operating rates anymore as an industry because of the amount of people that participate in it, and so -- but we would estimate rates are somewhere in the low 80s. But all producers had scheduled and unscheduled downtime, the majors, during the first part of the year so far. There's been several downstream consumers that have had issues and production issues. And we're obviously dealing with some railroad logistics issues as an industry and other industries right now. And so -- but the core sectors, just like home construction, durable goods, transport, et cetera, they're all very strong right now. The improvement in travel and customer spending is still there. And obviously, just like in the PVC business, we're taking advantage of the fact that with the energy advantage in the U.S. versus the rest of the world right now from a pricing standpoint, despite being high here, it's nowhere near as high as it is in Europe and Asia, which opens up opportunities and will lead some consumers of our products to produce products here versus overseas and then export those products. And so again, similar to the PVC business, the caustic business in the second half of the year -- I think it's very strong through the first half of the year. It's just a little less clear trajectory in the second half of the year only because of those overhanging potential impacts to the economy and associated GDP, which typically drives a big part of the business. And so I wouldn't say that we're pessimistic towards the second half of the year. If you look at the guidance range we gave and look at what we're doing for the second quarter and look at Slide 33, which had a historical view of chemicals performance, the second quarter guidance alone would have been a great year by many standards for many years prior to '21 and '22. And then if we look at the second half of the year, even if we reach our guidance midyear, you're talking ranges, it will also be close to $1 billion on the high end of our range. Certainly, if things are more constructive, we're on the high end of the range. And I think that's the feeling that we have right now. We'll get more clarity. We're really in the zone right now where we're trying to understand what might be the impacts of rising interest rates in the business. But all the demand factors today are still very constructive for supply/demand. And the longer that supply/demand balance remains tight on the 2 sides of the business, the higher we're going to go towards the high end of that guidance, and we'll potentially revise that guidance at some point midyear obviously, once we see how the second quarter turns out. But our guidance that we provided for the year beyond the Q2 guidance just takes into consideration that uncertainty we have in the second half of the year just because of what's going on not only in the U.S. but globally in the economy.
Operator:
The next question comes from Doug Leggate with Bank of America.
Douglas Leggate:
Appreciate you taking my questions, everybody. Rob, I hate to do this, but I'm going to go back to the capital structure of the company. And I want to ask 2 questions related to the preferred shares. I want to nibble on them some, just a little bit, if I may.
So my first question is you talked about absolute net debt targets. You don't talk about the capital structure, including the prefs. So if I include the prefs as debt, for example, one could argue that once you get back to investment grade, your cost of debt is going to be a substantial potential offset to the premium you need to pay for the prefs, if you chose to raise debt by the prefs. See what I mean? 8% money on the prefs, let's say 4% or 5% money on the debt. Even with a 10% premium, that would make sense. Why would you not do that?
Robert Peterson:
Why would we not retire the pref? Is that what you're saying, Doug? I didn't catch the middle.
Douglas Leggate:
Yes. Sorry, yes. Why is that not an option? Because it seems to me that the premium is worth paying if you can reduce the cost of overall money, which is what you would do at 4% or 5% debt.
Robert Peterson:
Oh, go out and borrow to actually fund the retirement of the Berkshire.
Douglas Leggate:
Once you get -- once you hit investment grade, yes.
Robert Peterson:
Yes. The challenge with it is, is this is not just the premium. It's also the return to the shareholders, too. And so it's not just considering the premium on the Berkshire of the 10% through 2029. It's also that there's got to be an equivalent value returned to the shareholders at the same time. And so versus retiring the debt, like what we're going to do the balance of this year, where every dollar that goes to debt reduces our gross debt, going into -- when we retire the Berkshire, it will reduce shares by an equivalent amount but will also reduce -- possibly split -- bifurcate it into the 2. And so $1, half of it goes towards shareholders and half of it goes towards the Berkshire.
And so I think once we achieve the ability -- if we start retiring the Berkshire, we're certainly going to want to deviate and put -- whatever cash we're applying to debt reduction will be going towards the Berkshire, which, the way that our maturity is laid out today, is not very difficult for us to do. I mean we don't have any maturities of any meaningful size until the second half of 2024 at this point. Even that isn't very large in scale. And so we have the ability to allocate all the cash that we have available to us, if we want to, towards shareholders and Berkshire return, if we're doing that at that point, without having to retire the debt because we don't have any maturities over that period of time.
Douglas Leggate:
Okay. Well, I apologize for asking. I just wanted to understand if it was a crazy idea or if it was something you would actually consider.
My second question is even nuttier, if you don't mind me going down this route. Berkshire obviously has now a vested interest in a better share price for all these reasons. They've built up a very large position in your stock. And 8% money on the prefs is obviously still pretty expensive. Is there any consideration, likelihood discussion or anything else you might want to share with us that could ultimately see you swap out of the prefs on favorable terms for ordinary equity with Berkshire given that they have already built a very large position? Just curious if that was a consideration.
Vicki Hollub:
Doug, we don't share the discussions that we have with other shareholders, as you know. But I can tell you that we always consider ways to add value to our shareholders, and we'll continue to do that. So we really can't disclose any private conversations with other shareholders.
Operator:
The next question comes from Phil Gresh with JPMorgan.
Phil M. Gresh:
With respect to capital spending, in the past, you've talked about sustaining CapEx of $3.2 billion at $40 WTI. And obviously, we're in a much higher environment and probably for longer. So I'm curious if you'd have another way to think about that in particular, the CapEx you think would be required to sustain this 2022 exit rate you're talking about that should be somewhere around 1.2 million barrels a day. And I'm looking at this in the context of your CapEx guide for the year would seem to imply we're exit rating maybe in the high 4s on CapEx, but would just be interested in any color there.
Vicki Hollub:
Yes. This year, we did have some things that we needed to catch up on. As you know, we were at $2.9 billion last year, and that didn't sustain some of our lower-decline assets. So we are -- that's part of the reason that we have a little more OpEx in Permian, that is to restore some CO2 to some of our CO2 floods and also to do some workovers to get some wells back online.
So as we're going toward -- forward and looking at what's the optimum level of capital for the -- these assets to deliver the most value, we are taking into consideration what should we do, where should we allocate capital, so even the assets that in a sustainability scenario would be lower capital. It's just that the lower-decline assets take a little longer to catch up, but then they don't decline as quickly. So if I'm understanding your question, to get us to where we would continually be at a higher rate, which should happen going into next year, I think that we'll be where we need to be to have every -- the capital into every asset that we have optimized.
Phil M. Gresh:
So just to clarify, if we're exit rating, call it, at $4.8 billion or something like that in the fourth quarter on CapEx, would you be saying then that there's maybe still some catch-up spend that was embedded in that? Or is that actually the sustaining capital rate?
Vicki Hollub:
I would say that, that is probably a little higher than the sustaining rate. But it's the rate that we feel is appropriate on a go-forward basis to optimize the development within each of those portfolios. Our sustaining capital is still at that $3.2 billion in a $40 environment. So we have the increase in prices that comes with not being in the $40 environment, I should say.
We have -- on the waterfall, we show you a little deflation as costs go back down to a cycle that looks more like $40 than where we are today. So there's an uplift in costs associated with that. And then there's the $250 million that we put into the CapEx for this year that's more related to inflation, albeit we're just trying to offset $50 million of that. But that's also dollars that are not going into delivering incremental oil. It's just to pay the costs due to inflation. So it is at the rate that -- going into next year, would be at a rate that should deliver year-over-year a little bit of an increase in production.
Operator:
And the last questioner will be Paul Cheng with Scotiabank.
Paul Cheng:
Maybe first one is for Rob. I know that it's too early, that you guys haven't designed what is your program going to look like for next year. But can you tell us roughly what percent of your work may already have some kind of fixed price contract for 2023? And maybe some give and take then on how you see that program like in higher inflation or if inflation will continue pushing higher. Some kind of -- maybe any insight can help.
And second question is we're quite -- the midstream full year guidance seems to suggest second half, you're going to, say, go back to a loss. Is that just being conservative or there's some identified items to make you believe the second half of the result is going to be much worse than what we've seen in the second quarter or what you are guiding to?
Richard Jackson:
Paul, this is Richard. Maybe I'll start with just a little bit of the sort of U.S. contract and talk around it in terms of inflation. We can start there to kind of give you a view of how it's going into the back half of this year and into 2023.
I think from -- some of the critical components like rigs and frac core, we have flexibility going into the back half of the year we have some contracts that do not extend into 2023. So again, as we sort of land on what the final 2023 plan is, we've got some flexibility there. We also want to make sure we've got the highest performing crews and rigs that we can. Again, from an OCTG and sort of sand supply, I think one of the real advantages we have beyond what I mentioned earlier is that we're operating most of our activity within 5 core development plans. So we've got this year about 80% to 90% of our activity within 5 areas and would expect that to continue into next year. And that -- those designs being locked in gives us the advantage of being able to schedule out things like sand delivery and tubular. So both of those we'll order out 6 months in advance. We'll be able to secure the pricing that we can. And those represent really the biggest uncertainties in terms of inflation going into next year. The rest, we obviously work contracts globally. So work with Ken, whether it's Gulf of Mexico or internationally, to be able to work with our service providers as best we can to sort of do that global view in terms of our need. So we feel good, again, where we stand this year in terms of supply and price, and we'll be looking in the back half of this year to get that firmed up into next year.
Vicki Hollub:
I would say, Paul, on the midstream business, because of all the uncertainties in the world and there are a lot of those, we've taken a very conservative approach on our forecast for pricing of sulfur and NGLs mainly. And with that, I want to say I very much appreciate all the calls today, and I want to thank our employees for their commitment and their exceptional performance that's been able to help us resume our delivery of return on capital employed and of capital to shareholders. So have a good day. Thank you.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to Occidental's Fourth Quarter 2021 Earnings Conference Call. [Operator Instructions] Please note that this event is being recorded.
I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Rocco. Good afternoon, everyone, and thank you for participating in Occidental's Fourth Quarter 2021 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; Ken Dillon, President, International Oil and Gas Operations; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. I'll now turn the call over to Vicki. Vicki, Please go ahead.
Vicki Hollub:
Thank you, Jeff, and good afternoon, everyone. The fourth quarter of 2021 was a fitting year -- a fitting way to end the year where Oxy's operational and financial performance advanced from strong to stronger.
Our focus on consistently delivering outstanding operational results, combined with our steadfast dedication and patience in improving our balance sheet, has positioned us to begin increasing the amount of capital returned to shareholders. Our new shareholder return framework, which we will detail today, includes a dividend that is sustainable in a low price environment. We are pleased to implement this new framework, beginning with an increase in the quarterly common dividend to $0.13 per share. The position of strength that we are in today stems from our team's hard work and accomplishments last year. Throughout 2021, we strived tirelessly to improve our already exceptional operational performance. We capitalized on efficiency improvements by embedding innovative techniques across our operations. Our focus on learning, implementing change, where needed, and maximizing opportunities for improvement enabled us to accelerate time to market for our products while generating notable capital saving. We will continue to maximize operational efficiencies in 2022 by executing on the capital plan that invest in our highest-return assets to generate long-term sustainable free cash flow. This afternoon, I will begin by covering our fourth quarter and full year 2021 highlights and achievements, before detailing our 2022 capital budget. Rob and I will then discuss our shareholder return framework, and Rob will provide guidance for the first quarter and year ahead. Before turning to Q&A at the end, I will provide a preview of the Low Carbon Ventures investor update that we have planned for next month. Now to talk about delivering cash flow priorities. Those who have followed us at Oxy's journey over the past several quarters know that our cash flow priorities have centered around derisking our balance sheet and reducing debt. We diligently delivered on these cash flow priorities throughout 2021, including the repayment of approximately $6.7 billion of debt. We now expect that our net debt will be below $25 billion by the end of the first quarter of 2022, which will mark a change in how excess cash flow will be allocated going forward. Before I detail our updated cash flow priorities and shareholder return framework, I would like to first touch on a few of the many operational and financial successes that enabled us to reach this significant turning point. 2021 was a year of continuous operational improvements, which drove record free cash flow generation, rapid debt reduction and a return to profitability. One of Oxy's core strengths is our ability to develop assets in a way that efficiently maximizes production and recovery while generating significant cash flow, and that is just what we did in 2021. Multiple drilling and completion records were set across our domestic and international businesses as our production for the year averaged 1.167 million BOE per day. That's 27,000 BOE per day higher than our initial guidance. 2021 was also a more conventional year in terms of commodity prices, operations and planning, all of which was helpful in providing a reserve update that reflects a more normalized price environment. Our reserves for year-end 2021 increased to 3.5 billion BOE, representing a reserve replacement ratio of 241%. Our reserves position means that we have a vast supply of low-breakeven projects and inventory available. We have included updated inventory information for our U.S. onshore operations in the appendix to this presentation. Over the last year, we significantly advanced our commitments toward a low-carbon future. We are proud to be one of only a few oil and gas companies with net-zero goals that are aligned with the Paris Agreement's 1.5 degree Celsius pathway. In December, Oxy became the first U.S. upstream oil and gas company to enter into a sustainability-linked revolving credit facility, which includes absolute reductions in our combined Scopes 1 and 2 CO2 equivalent emissions as the key performance indicator. We set additional interim emission targets to further refine our net-zero pathway, including a short-term target to reduce our CO2 equivalent emissions to approximately 3.7 million metric tons per year below our 2021 level and to accomplish that by 2024. We set a medium-term target to facilitate the geologic storage or use of 25 million metric tons per year of CO2 in Oxy's value chain by 2032. We also endorsed the Methane Guiding Principles and Oil and Gas Methane Partnership 2.0, a climate and clean air coalition initiative led by the United Nations Environment program. This is consistent with our commitment to enhance methane emissions reporting and reducing those emissions. Our journey towards net zero is underway, and we look forward to discussing in greater detail at our Low Carbon Ventures Investor Day next month. Now the fourth quarter highlights. The strong operational and financial performance that we delivered throughout last year continued in the fourth quarter. We set a fourth consecutive record for quarterly free cash flow generation before working capital, which contributed to generating our highest-ever annual level of free cash flow in 2021. We continue to apply free cash flow towards reducing debt and strengthening our balance sheet, repaying an additional $2.2 billion of debt in the fourth quarter. Operationally, all 3 business segments excelled in driving our robust financial performance. OxyChem delivered record earnings for the second consecutive quarter as performance throughout the year culminated in 2021 being OxyChem's strongest in over 30 years. The fourth quarter, which is typically lower due to seasonality, even exceeded the record third quarter. And in our oil and gas segment, our Permian, Rockies and Oman teams set new operational records and efficiency benchmarks in the fourth quarter, further improving on their third quarter record. Our midstream business outperformed by maximizing gas margins during the fourth quarter. While short-term opportunities in the commodity markets are difficult to predict, our midstream team exceed at finding and taking full advantage of such opportunities when they arise. Now I'm pleased to say that our fourth quarter results continued to demonstrate the commitment of all of our employees, no matter their position or location, to find ways to further create value by lowering costs, improving efficiencies and maximizing recoveries. They truly are driving our strong financial results and providing a solid foundation for free cash flow generation. Now on to 2021 oil and gas operational excellence. On each of our last several calls, I've enjoyed highlighting the many operational achievements our teams continuously deliver. The magnitude of these achievements is striking when viewed on a combined basis over the last year. We established record drilling cycle times in the Gulf of Mexico, the Permian, Rockies and in Oman, and set new efficiency benchmarks across our portfolio in 2021. We intend to maintain our focus on continuous improvement in the year ahead as we work to maximize the value our portfolio can generate for shareholders. Now our 2022 capital plan. Our 2022 capital plan invests in cash flow longevity while building on the capital intensity leadership we demonstrated in 2021. We have sized our capital plan to sustain production in 2022 at 1.155 million BOE per day while investing in high-return projects that will provide cash flow stability throughout the cycle. We have also incorporated an expectation for inflation and a capital range to reflect the potential for fluctuations in our third-party-operated assets and our low-carbon opportunities during the year. Our sustaining capital, which we define as the capital required to sustain production in the $40 WTI environment over a multiyear period, remains industry-leading. Our multiyear sustaining capital is expected to increase from our 2021 capital budget of $2.9 billion, the reduced inventory of drilling uncompleted wells and additional investment in our Gulf of Mexico and EOR assets, to optimize the long-term productivity of our reservoirs and facilities. If the macro environment requires spending below our multiyear sustaining capital, we have the ability to reduce it further and hold production flat for shorter periods of time, as we've demonstrated. We're also investing in attractive mid-cycle projects that will provide cash flow stability through the cycle in future years. For example, these projects include the Al Hosn expansion, which began last year. And OxyChem is in the process of completing a FEED study to modernize certain Gulf Coast chlor-alkali assets from diaphram to membrane technology. Our capital plan also includes investments to advance our net zero pathway, including reducing emissions, improving energy efficiency and developing our carbon sequestration initiative. We're allocating capital in the budget to 1PointFive to begin construction on the first direct air capture facility. We continue to make progress on both the engineering and commercial needs for direct air capture development. We're improving both of these aspects and believe Oxy's capital helps retain value for our shareholders. As the construction phase and technology of this new project advance, we will continue to consider strategic capital partnerships and structures to address financing. We'll provide more comprehensive update on 1PointFive and direct air capture at our March 23 LCV investor update. We benefited greatly from commodity price rebound last year and appreciate how swiftly the price environment can change. The optionality that our scale and asset base provide enables us to retain a high degree of flexibility in our capital and spending plans. The majority of our capital program is comprised of short-cycle investments, meaning that we have the ability to quickly adapt to changes in the macro environment. Within 6 months or less, if necessary, we can reduce capital spending to sustaining levels. And if oil prices remain supportive this year, our intent is to follow our cash flow priorities and capital framework that we will share with you today. We have no need and no intent to invest in production growth this year. Having a flexible capital budget that includes investment and cash flow longevity provides us and puts us in a strong position to implement shareholder return framework that will benefit shareholders over the long term. With respect to cash flow priorities, our priorities for 2022 remain largely unchanged, with a continuing emphasis on reducing debt while maintaining our asset base integrity and sustainability.
The objective of strengthening our financial position remains the same:
Enable us to confidently increase the amount of capital that we may sustainably return to shareholders throughout the cycle. As we expect net debt to fall below $25 billion by the end of the first quarter, our focus has expanded to returning capital to shareholders, beginning with the increase in our common dividend to $0.13 per share and the reactivation and expansion of our share repurchase program. The increase in the dividend to $0.13 per share is consistent with our intention to initially increase the dividend to a level that approximates the yield of the S&P 500.
We believe establishing framework for returning capital to shareholders through a sustainable common dividend, combined with an active share repurchase program and continued debt reduction, creates an attractive value proposition for shareholders while also improving the company's long-term financial position. For the first phase of our shareholder return framework initiated, we have the options in future years to invest in cash flow growth. We have the ability to grow oil and gas cash flow through higher production, but also have multiple investment opportunities across our other businesses. As evidenced by our guidance for 2022, we do not intend to grow production in 2022. At the point where it is appropriate to invest in future cash flow growth, we will only do so if supported by long-term demand. Any future production growth will be limited to an average annual rate of approximately 5%. I'll now turn the call over to Rob, who will walk you through our shareholder return framework.
Robert Peterson:
Thank you, Vicki, and good afternoon. As Vicki mentioned, the first phase of our shareholder return framework consists of the debt reduction; an increase in the common dividend to $0.13 per share; and the reactivation, expansion of our share repurchase program.
With net debt expected to be below $25 billion by the end of the first quarter, we are ready to begin returning more capital to shareholders, but we'll continue to prioritize debt reduction to focus on our medium-term goal of regaining our investment-grade credit rating. We place high importance on debt reduction for the reasons I highlighted last quarter, mainly that as debt is reduced, our company's enterprise value rebalances to the benefit of our shareholders. We recognize that oil prices are uncertain and may remain volatile, particularly in the current environment. We then prioritized retirement of an initial $5 billion of debt to drive our net debt towards our next milestone of $20 billion. When this milestone is achieved, our balance sheet will improve significantly even from where we are today. We intend to provide our shareholders with a competitive common dividend while maintaining a long-cycle cash flow breakeven at $40 WTI or less. The long-term sustainability of our dividend will be enhanced by continued deleveraging and share repurchases as well as our best-in-class capital efficiency and a deep low-cost portfolio of assets. As debt is retired, our cash interest payments will decrease, freeing up cash that can be used to support future common dividend growth. In addition to increasing the common dividend to $0.13 per share, we intend to purchase approximately $3 billion of outstanding shares of common stock. Maintaining an active share repurchase program with the benefit of a healthy balance sheet will potentially enable us to grow the dividend on a per share basis at a faster rate. As evidenced by our progress reducing debt last year, debt retirement remains a higher cash flow priority than our share repurchase program. We intend to make substantial progress towards retiring an additional $5 billion of debt before initiating share repurchases.
It is our goal to reward shareholders with the triple benefit of:
A sustainable common benefit, an active share repurchase program and a continuously strengthening financial position. We believe the shareholder return framework we have detailed this afternoon delivers these in a manner that is transparent for shareholders.
I'll now turn to our fourth quarter results. In the fourth quarter, we announced an adjusted profit of $1.48 and a reported profit of $1.37 per diluted share. Our adjusted income improved significantly through 2021, with the fourth quarter being the strongest quarter of the year. The increase in earnings was primarily driven by higher commodity prices and volumes as well as OxyChem's excellent financial performance. Our domestic oil and gas expenses experienced a sizable reduction on a BOE basis from the previous quarter and reflected a more normalized environment absent any significant weather disruptions. The strong performance of our businesses, combined with the benefit of a healthy commodity price, enabled us to deliver another consecutive quarter of record free cash flow. On our third quarter call, we announced the completion of our large-scale divestiture program, but reiterated our intention to continue seeking opportunities to optimize our portfolio to create shareholder value. In November, we completed a bolt-on acquisition to increase our working interest in EOR assets that we'd operate. And in January 2022, we divested a small package of Permian acreage that had yet no immediate plan to develop. The purchase and sale prices of these transactions largely offset each other, while the EOR acquisition added approximately 5,000 BOE per day of low-decline production as well as increasing our inventory of potential CCUS opportunity. We exited the fourth quarter with approximately $2.8 billion of unrestricted cash on the balance sheet after repaying approximately $2.2 billion of debt in the quarter. In total, last year, we paid approximately $6.7 billion of debt and retired $750 million of notional interest rate swaps. Our debt reduction continues to drive a pronounced improvement in our credit profile. Since our last call, both Fitch and S&P upgraded our credit ratings to BB+, 1 notch below investment grade; while Moody's assigned us a positive outlook on our debt. Reducing the amount of cash that is committed to interest payments today places us in a stronger position for a sustainable return of capital in the future. We estimate that the balance sheet improvements executed in 2021 will reduce interest and financing costs by almost $250 million per year going forward, which will fund approximately half of the increase in our common dividend. Our business incurred a negative working capital change in the fourth quarter. It was primarily driven by higher accounts receivable balance due to higher commodity prices and, to a lesser extent, an increase in inventories, including a higher number of barrels on the water at year-end. The oil and gas hedges we had in place rolled off at the end of the fourth quarter, and we are now positioned to take full advantage of the current commodity price environment. We recognize the possibility of a swift change in commodity prices always exists. The debt maturity profile we have today is far more manageable mantle than it was 2 years ago, and our liquidity profile remains robust. In addition to cash on hand, we have $4.4 billion of committed unutilized bank facility. We continue to believe that reducing debt and maintaining maximum flexibility in our capital plans is the most effective long-term solution to managing risk while providing shareholders the benefits of commodity price gain. We expect our full year production to average 1.155 million BOE per day in 2022. Production in the first quarter of 2022 is expected to be lower than the fourth quarter of 2021 due to the timing impact of wells that are brought online in 2021, severe winter weather in the Permian earlier this month and the impact of significant planned international turnaround activities this quarter. Algeria, Al Hosn and Dolphin are all undergoing scheduled maintenance in the first quarter, which is reflected in our international production guidance. The downtime associated with Al Hosn is notably larger than typical years as the plant is undergoing the first full shutdown since its inception to substantially complete the tie-ins associated with the expansion project and to enhance plant sustainability and reliability. Additionally, a portion of our international production is subject to production-sharing contracts, where we typically receive fewer barrels in a higher-price environment, the impact of which is captured in our full year and first quarter guidance. The Permian activity we added late in the fourth quarter is expected to replace the production benefit received in 2021 and completed our DJ -- our inventory of DJ Basin undrilled, uncompleted wells in the early part of last year. Our 2022 Permian capital allocation is expected to provide benefits that will last into 2023. We anticipate that our activity this year will provide us the flexibility to either hold Permian production flat at our 2022 exit rate for similar capital next year, or spend less capital in 2023 to hold production relatively flat to our 2022 average. We also expect that our production in 2022 will increase throughout the year to achieve our full year guidance as our international operations will resume their normal production levels and our activity in the Permian brings new production online. Additionally, the trajectory of operating production is anticipated to offset lower production in the Rockies this year as our activity in the DJ Basin is tapered, reflecting development planning timing to ensure efficient operations as new permits are obtained. Partially offsetting lower Rockies production with higher Permian production, combined with an increase in EOR activity, will result in a slightly higher domestic operating expense as the DJ Basin has one of the lowest operating costs on a BOE basis in our portfolio. The increase in Permian production is expected to result in domestic cash margins improving by -- in 2022 as the company-wide oil cut increases approximately 54.5%. The mid-cycle level of capital we intend to spin this year provides flexibility to sustain production in 2023 and beyond at our multiyear sustaining capital level of $3.2 billion in a $40 price environment. We expect that OxyChem's 2022 earnings will exceed even 2021. OxyChem continues to benefit from continued demand improvement for caustic soda, while PVC pricing remains strong. Additionally, as I mentioned on our last call, we expect chlorine markets to remain tight as chlor-alkali producers seek the highest value for their products. OxyChem's integration towards multiple chlorine derivatives enables us to optimize our production mix to supply the products the market requires, whether this is for chlorine for water treatment, vinyls or PVC, for example. This year, we will make an incremental capital investment as we complete a FEED study for the modernization of certain Gulf Coast chlor-alkali assets from diaphram to membrane technology. Modernizing these assets would result in a material energy efficiency improvement, but will also lower the carbon intensity per ton of the product produced and delivered. The project would also provide the opportunity for a significant expansion of our existing capacity to meet growing demand for our key products. We expect to reach final investment decision later this year, at which time, we will be prepared to share additional details. To assist investors to reconcile our guidance with our segment earnings, we have made a change in how we guide midstream going forward. Our midstream guidance now includes income from WES, which is a change to how we've guided midstream previously. Quarterly guidance now includes Oxy's portion of WES income using the average of the previous 4 publicly available quarters. Our annual guidance now includes Oxy's portion of WES income using the sum of the previous 4 publicly available quarters. As we look to the year ahead, we will work to continue to improve on the numerous operational and financial success of 2021, including making additional inroads on reducing debt, implementing our shareholder return framework and advancing our low-carbon aspirations. I'll now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. When we established Low Carbon Ventures in 2018, we knew we were ahead of the curve in recognizing the opportunity and necessity of building a carbon management business, both to help reduce global emissions and to enhance our business. At that time, we were focused on key technologies and projects that would reduce Oxy's emissions and provide a more sustainable future business.
Today, we have advanced that vision and fully appreciate the vast scope of the carbon management opportunity as well as the cross-industry support and partnership in front of us. On past earnings calls, we had discussed several of the initiatives Low Carbon Ventures is developing and Oxy's ambition to achieve net zero before 2050. We've been working on key technology developments and important commercial needs to advance LCV's projects that are now in a position to move more fully -- and more fully detail our low carbon business and how it positions us to realize our net-zero ambition and improve our long-term business. On March 23, we will host a Low Carbon Ventures investor update, where we will provide a detailed update on our low-carbon strategy, with a focus on the technology and commercial development of carbon-capture projects, specifically direct air capture. The event, which we expect may last up to 2.5 hours, will be accessible through our website. As I've said before, we are excited about our unique position and capabilities as a company. We value our broader low-carbon and business partnerships that are growing, and our workforce is energized to advance this immense opportunity before us. We'll now open the call for your questions.
Operator:
[Operator Instructions] Today's first question comes from Jeanine Wai with Barclays.
Jeanine Wai:
Our first question is on the gross debt reduction. We're assuming that the $5 billion that you're planning on getting through, that can be executed through tenders. And so just any idea on what the timing of that could look like for you to complete that, given what you've seen in the market.
And do you need to get through the full $5 billion of tenders before you begin the buybacks? We were looking back at your prior tender, and you almost got the whole thing done, but that was only about $1.5 billion.
Robert Peterson:
Yes. Good question, Jeanine. And so I guess, first, let me comment on the tender that we did at the end in December. We were pretty aggressive on the premiums we've put in that tender because we knew we had an additional $700 million of callable debt available to us at the time. And so we were pretty happy with the ultimate outcome that came out of that.
As we moved forward since then, we have a lot of opportunities to reduce the debt. Last year, we were able to reduce, of the $6.7 billion of debt we did last year, we only paid a 1.5% premium for that. And within that, $4.7 billion of that was actually concentrated on maturities that were 2024 or newer. And so when I look at the opportunities to retire debt this year, as we indicated, we already retired the remaining January -- last of our 2022 maturities, for $101 million, already this month -- or this quarter. So we do have tenders, make-whole provisions. We have the ability to build cash on a net debt basis as maturities come forward. We do have the option to settle the February '23 notes, which is the bulk of our 2023 maturities, come callable in November. But overall, when I look at the -- our debt, it is actually even cheaper than it was at the end of the year, largely because as interest rates have risen in the perspective of interest rates rising again. And so certainly, the next dollar we put forward will be towards debt reduction. And with the cash we ended the year at and the cash we're adding during the quarter, it's pretty safe to say that's probably not too far in the future that we initiate that process again. We don't need to have all of that completed before we return to buying share -- initiate a share purchase program, but we need it to be substantially completed or have line of sight on it being completed before we begin repurchasing shares.
Jeanine Wai:
Okay. Great. That's really helpful information. Maybe just going forward a little bit beyond that on your future cash flow priorities. Oxy has got a real high-class problem. Assuming oil prices stay anywhere close to where they are today, you'll be building a significant amount of cash on the balance sheet over the next few years even after you do the $5 billion of debt reduction and the $3 billion of buybacks.
So I guess, have you started to assess the next steps in capital allocation after hitting your debt goals and the buyback? And I guess specifically, do you have any thoughts on potentially trying to tackle the preferreds early and doing that versus either other debt reduction or production growth? And just how you're thinking about the preferred.
Robert Peterson:
So we have discussed previously provisions with regards to the Berkshire agreement related to shareholder return, enabling us to begin redemption of the Berkshire to $4 per share common dividend to our shareholders. Assuming we repurchased $3 billion of shares in a 12-month period and then you combine that with $0.52 of dividend payments over 4 consecutive quarters, we still won't have distributed enough to reach a $4 per share distribution trigger. It would be about $3.72 at that point.
But I want you to know, the Berkshire common provision isn't a limit on our ability to return value to shareholders. It simply means, if the circumstance arrives and the macro puts us in a place where we have exceeded $4 per share on a trailing 12-month basis, we would just be in a position where we have to redeem an equal portion of Berkshire at a 10% premium as we return to shareholders above and beyond that. And so as we sit here today in February, agreeing that, yes, there's a lot of potential for elevated oil prices over an extended period of time to create a constructive macro for going beyond our debt focus. But it's a little too early, I think, to speculate on what we would do at that point in time.
Operator:
Our next question today comes from Phil Gresh at JPMorgan.
Phil M. Gresh:
Yes, I guess just a follow up on that question around the net debt, the $20 billion next step, so to speak. What is the ultimate goal with the balance sheet? Is it $10 billion to $15 billion? I mean, how do you think about that today?
Robert Peterson:
Yes, Bill. I think we've already seen in notes published from the various rating agencies that their expectations would be investment grade is somewhere in the mid- to high teens. And so I think getting to that point -- getting to a level at some point, that is, in that $15 billion or less net debt is an ultimate goal for the company.
That would put us in a place -- there -- it also depends sort of on their long-term price horizon. If you take their $60, getting down to a net of $20 billion puts us close to a 2 multiple at that point, depending on EBITDA going on a year in year out basis. So we know we've got to do a little further than that in order to get consideration for investment grade.
Phil M. Gresh:
Okay. That makes a lot of sense. And then, Rob, you made a comment just about the Permian exit rate in '22 and into 2023. And I was just wondering, where do you stand in terms of the CapEx carry with the EcoPetrol JV? Is there any spending in 2022 that kind of moves into the full 50-50 split? Or is that a 2023 event? I'm just curious, based on your comments you're making, how you incorporated how that could flip to the 50-50 and when?
Robert Peterson:
Based on the activity level we have planned for this year, we would probably consume the balance of the carry this year, but we don't anticipate really flipping in 2022.
Operator:
And our next question today comes from Doug Leggate with Bank of America.
Douglas Leggate:
Rob or Vicki, I wonder if I could follow-up first on the buyback just so I understand it correctly. So $3 billion, is that an annual number that, depending on when you start the buyback, would you still expect to execute the full $3 billion in 2022? Irrespective of when you hit, you get that line of sight, which I'm guessing is a matter of months.
And I guess related, you're kind of front-running yourself a little bit. And one could argue, taking the stock is heavily discounted because of your capital structure, why not consider something like an ASR?
Robert Peterson:
So Doug, I think the first way I'd answer part of your question is the -- once we begin to initiate the share repurchases, it will be done both in an open-market repurchase basis when the market is open; and when it's closed, through a 10b5 type programmatic program.
The stock, as you know, is extremely liquid. I mean, we can easily purchase $1 billion of shares in less than 14 trading days without -- I mean, close to 15% of the average daily trading volume. So that's a pretty safe way that, over a fairly short period of time, if we wanted to, we could accomplish $3 billion goal. But that goal, certainly be dictated by our free cash flow generation. That's largely related to the commodity prices. And it's -- we're in an environment right now where we've -- the hedges have rolled off, we're giving our shareholders full exposure to commodity prices, which we think over the cycle of the commodities, will deliver the most value to the company and ultimately the most value to shareholders. But along with that, we realized that the macro can change for a lot of different risk factors that can cause prices to go unconstructive for us in a rapid fashion also. And so we can't find ourselves in a position where maybe we'd tackled the stock ahead of time, and the price environment changed for whatever reason, and we haven't addressed the debt first. And that's part of the reason why we understand that, over the long -- over the course of the year, we may end up paying more for the stock to retire it. But in aligning risks and opportunities for shareholders, we think the approach are taking the most prudent way to do it.
Douglas Leggate:
Okay. So just to be clear, so if you started the buy back in May, you'd still expect to get $3 billion done this year? That's just for clarity, that's not my follow-up.
Robert Peterson:
Well, the time line is going to be dependent upon the availability of cash, Doug. That's what's going to be the driver of it. But in terms of ability to execute, with the liquidity of the stock, a time frame of being we complete it in the second half of the year, even if we didn't initiate until the second half of the year, would not be a challenge.
Douglas Leggate:
Okay. My follow-up is a resource question. Vicki, I'm guessing this was deliberate, but you've given -- you've kind of laid out the inventory depth for the onshore portfolio, looks at the current rate, something around 15 years, assuming not a lot of growth. What about the Gulf of Mexico and the rest of the portfolio? Can you give us a kind of an update as to how you see the resource depth or sustainability that goes along with the sustaining capital number that you gave us?
Vicki Hollub:
Yes. I'll let Ken answer that. He's got his team actually working on that in view of some of the challenges we've had with the recent lease sale. Actually, we have a great new story on that.
Kenneth Dillon:
Doug, in terms of Gulf of Mexico, we recently completed our field architecture studies. As you know, we have a 179 blocks, wherein 90 of those are tagged as exploration. When we look at the risk portfolio and the opportunities we have, we have substantial work, hundreds of millions of risk barrels, opportunities going forward.
We have a solid assembly line of projects. We've got 3 projects in flight at the moment. Caesar Tonga expansion, our Mountain expansion, A2 subsea pumping. And the recent -- as Vicki alluded to, our recent lease round attempt, our goal there was to try and obtain acreage close by our existing infrastructure to accelerate simple tiebacks. But that doesn't inhibit us. We have a large portfolio, and we feel comfortable going forward within the plans that have been presented in the slides.
Operator:
Our next question today comes from Neil Mehta with Goldman Sachs.
Neil Mehta:
So the first question is on the production profile. Vicki, you had made the comment, as you think about the long term, you want to see growth somewhere between 0% and 5%. Is that sort of -- why is -- how do you think about the long-term profile? And based on the way you've you view normal, that's a big range. Where do you see yourselves planning in the context of that range?
Vicki Hollub:
Well, it really depends on the projects. And what we always do is we try to design our capital programs to deliver the best returns. And so it's always -- as we develop our areas, it's always with that in mind and to build the facilities that require a pace of development that delivers the maximum return.
So we could have lumpy -- a little bit lumpy growth going out. The Gulf of Mexico is a little bit lumpy. In the shale play, depending on whether you're starting a new area or not, it would be a little bit lumpy. But certainly, our capital intensity, we believe, is going to continue over time to be the best in the industry. And the development that we'll have, and whether or not we're at 0% or 5%, will depend on how the program lays out to maximize returns. So we have, as you see, inventory onshore, inventory in the Gulf of Mexico. We have the -- as well some international projects that could add value. And as I mentioned in my script, we do have in our chemicals business opportunities to grow there. And so the efficiencies and opportunities that we see really will depend on how we can piece it together to deliver the best possible return.
Neil Mehta:
Certainly an evolving situation. Let me ask you about chemicals, Vicki, because the '22 guide was stronger than what we anticipated. I think a lot of investors expected chemicals to be sequentially lower. Just talk about some of the moving pieces that allows for some profitability to improve year-over-year. And what are the biggest risks to actually achieving the guide?
Robert Peterson:
Yes, Neil, I'll take the one on chemicals. And so what I'd point to first, I know you understand the business well, is obviously, we -- if you look at Slide 39 in the deck, the 2 business -- profit drivers in the business are the PVC business or the vinyls business and the caustic soda business. And both of those did materially improve throughout 2021. And when we have favorable conditions in both, the impact to earnings is pretty significant.
And so what you're seeing is -- first, let me just say that where the market is at right now, as the PVC business is still quite tight, very tight supply/demand balance. We think operating rates for the industry were in 80%, 81% in January. Demand was slightly higher in January of '22 relative to January '21, less than 1%, but a little bit better. Producers are attempting to build inventory in PVC right now in advance of outages that are scheduled, but you've got this situation where they're already at low inventories and the pull from the construction sector remains strong. And so you've got attempts to grow inventories while demand is still quite strong. We expect demand to remain strong in the PVC business throughout 2022. There's a very favorable housing starts outlook. Mortgage rates obviously remain pretty low, and the remodeling sector also remains very attractive. And so you can look at the export side of the business. So in January, there's only about 250 million pounds of export, which is about 30% less than '21. That's reflective of the lack of product available right now. And so we certainly see -- you're not going to have an opportunity for inventory to really replenish itself and exports to even return until probably the latter part of the second quarter when resin supply might be normalized in the wake of outages, assuming there's no unplanned outages over that period. And then in case of the chlor-alkali side, we're seeing a very tight supply/demand market, largely because of production challenges. Operating rates, we think, in the industry are going to be somewhere in the low 80s for the first quarter. There's a lot of planned outages scheduled between now and May of '22, but there's been a significant number of unplanned outages still in the industry impacting product availability. And on the chlorine side, we think growth -- we'll see growth at least 3% to 4% this year. Again, all the sector markets are strong with the similar markets to the PVC that draw on the chlor-alkali side of the business. We think that will be also supplemented by there's improving travel and then business spending, return to office will drive pulp and paper usage for caustic soda, et cetera. So a lot of things that we think are going to be positive on that. And on the international side of the caustic business, certainly rising natural gas prices and availability in Europe and Asia will have already impacted operating rates or chloro vinyl producers overseas, which is driving up values to that. And so the biggest change year-over-year and why I think there's maybe a surprise because conditions were so remarkable in 2021. And why would we be guiding to something higher than that? Is that if you go back and look at the beginning of the year, caustic soda at the beginning of 2021 was still coming out of the really low values at the post-COVID drop in 2020. PVC has recovered very quickly on the construction side, but caustic was dragging its way up a little by a little out of the lows experienced during 2020. And so caustic prices improved sequentially quarter after quarter throughout 2021, which is why you'll see the earnings for the segment in the fourth quarter was -- typically, the first and fourth are the shoulder quarters and the strong ones are the midyear, Q2, Q3. But you had almost -- you had doubled the earnings in the chemicals segment in the fourth quarter compared to the first quarter. And so we're coming in with so much more momentum, which is why our guide for Q1 is so strong for the chemical business. And so it's not that we're predicting those conditions persist all the way through the entire year, we're just going to start from a higher point. How long that these conditions persist will impact whether that guidance actually could increase over the balance of the year potentially, if it holds on longer than we're anticipating. We do anticipate that things, as I said, will start to normalize maybe the middle part of the year.
Operator:
And our next question today comes from Matt Portillo with TPH.
Matthew Portillo:
Just the first question on the DJ Basin. You mentioned in the prepared remarks some timing around permits. Just curious if you could provide some context on the permitting process as it stands today. And is this a good level of development to think about for next year? Or should we expect a rebound in the DJ in 2023 as it relates to drilling?
Richard Jackson:
Matt, this is Richard. I'll take that one for us. So with respect to the permits in the DJ, really have had good progress over the last years is how I would describe it. Just looking at some of the permits in hand, we've had about 46 wells permitted, which takes us through really past half the year.
And so what we've really put in place is optionality in our program. So you dig into sort of our onshore plan for this year, we have plans to pick up a second rig in the year. And really, that's based on confidence with where we're going with our permit. So as you know, last year, some changes in terms of the process happened. And so we've been meaningfully engaged over the last year, importantly, at the stakeholder level and communities and then now with the state. But we've seen in our own pads approved as well as other operators. And I think the feedback that we've received, and we continue to work on together, is continuing to improve technology and things that we know that can really place us in a good place for development. So I guess, in short, we're optimistic. We've got a rig plan to come in, in the second half of the year, but have optionality within the program to be able to adjust as needed.
Matthew Portillo:
Perfect. And maybe a follow-up on the marketing side. I know as an organization, you guys have been very thoughtful about this process through the cycle. The basin, it looks like there's possibly some solutions on the horizon for incremental gas takeaway. And just curious how you all might be thinking about potentially adding to your takeaway portfolio from a gas marketing perspective.
And then maybe dovetailing into that. On the crude oil side, could you just remind us when some of those contracts start to roll over? And if there's any tailwinds to the financials kind of moving forward over the next few years around crude oil marketing.
Vicki Hollub:
Yes. Matt, we really have enough gas capacity, and as much as we feel like we need at this point and with respect to our growth profile. And for the oil side of it, the contracts start rolling off in 2025 for the oil and gas -- for the oil part of the contract. So we have plenty of capacity. At that time, I think it will take probably a couple of years to get us down to the point where all the contracts are aloft.
Operator:
Our next question today comes from Neal Dingmann at Truist Securities.
Neal Dingmann:
Vicki, my first question maybe for you. You mentioned just a couple of minutes ago here that you thought you maybe would ramp the chemicals. And obviously, as a finance guy, that just continues to be. I know when I saw Rob in December, and it just continues to get better and better.
I guess my question is, as a financial guy, how much can you grow that? And would that grow in conjunction with your low carbon mission? I know you talked about that in the past. I'm just wondering how much could you push that business, given it just continues to hit the ball out of the part on that one?
Vicki Hollub:
I think we'll talk about that a little bit more as we talk about the project and the capital that we're executing to convert our diaphragm to membranes, because that's going to improve some efficiency in the areas where we're doing that conversion. So we'll actually increase -- be able to increase our capacity. And we'll outline that and detail that a little more in the next earnings call. Because right now, we're currently in the process of doing the FEED study on that.
For today, with respect to other opportunities, we will continue to consider incoming calls about potential partnerships, where it makes sense, to do projects with either customers or more from the perspective of supporting Low Carbon Ventures. We try to be opportunistic in chemicals and not build without a -- certainly, the demand for the product. And so on the Low Carbon Ventures side, we're, as we go through this, finding opportunities where there are synergies and growing synergies between the chemicals business and the low carbon business. So it will have some growth around that.
Neal Dingmann:
No, that's great to hear. And then just the second. You talked just a minute also about the DJ. And my thought is it sounds like some of the Perm production is due to replace DJ this year. Is that going to be the case going forward? And is that because you're talking about -- I know Richard talked about permitting is all in shape. I'm just wondering, what's sort of the reason or rationale for why not just grow both of these? I mean, I'm looking at that...
Vicki Hollub:
Yes. It just -- it really just depends on the permitting process because we do have really good inventory in the DJ Basin as well. And as we go forward and we work out the process, if we get ahead on the permitting, we would consider adding a rig to the -- or a rig or 2 to the DJ as well.
Operator:
Our next question today comes from David Deckelbaum at Cowen.
David Deckelbaum:
Thanks for all the details today, Vicki and team, and congrats on the visibility to $20 billion of debt. I wanted to ask just on the sustaining capital. There were lots of in and out, particularly around the Gulf of Mexico and the EOR catch up, some normalization of Rockies DUCs.
I guess, when we think about that delta between the $2.8 billion or $2.9 billion that you guys had talked about last year, kind of in the $400 million increment this year, how do we think about that sustaining capital level progressing into the out years now? Does it have some upwards pressure on it because of catch ups? Or should we look at this as a catch-up year, and that should moderate, potentially decline, along with base declines moderating?
Richard Jackson:
Maybe we'll start with onshore and speak to that a little bit. I think you've got it right. I think if you look over the last couple of years and what's happened, certainly, 2020 had a significant reset for us in terms of activity levels. And so preserving cash investment at that point and really dropped activity levels almost completely.
And so coming on the back half and into 2021, we had things like the DUCs in the DJ that allowed us that ability to add production and maximize cash flow for 2021 with a lot less capital investment. And so what happened last year was really, as we think about the transition, it went from transitioning from DUCs as we restored activity, really to drilling and completion, which is a much more steady-state pipeline for our production delivery. And so the way that played out was really, at the end of the fourth quarter, beginning of the first quarter, we were able to pick up our drilling in frac cores to sustain the production for this year, which did a couple of things. One, it was good because as we head into inflationary period, we were able to gain activity and create that stability within our capital program. But what it does is it did create a bit of a lump that we have most of our wells online really starting late in the first quarter, and then you hit more steady state in the second and third quarter. And so as that projects into the end of the year and into 2023, you can tell from our first quarter guidance to total year, that we do have an increase of production. But those type events as well as restoring activity, really from a cash investment perspective and EOR, adding low-decline production barrels, really gives us a much more sustainable production level across the cycle. And so I think we're restoring, as you said, a much more normal steady-state activity level and a much more robust or sustainable free cash flow capability.
Vicki Hollub:
I think, considering the rest of the portfolio, we don't see a lot of upward pressure for the $3.2 billion as a whole.
Robert Peterson:
And David, just to add to your point, I mean, on top of what Richard and Vicki just went through, I mean, from a decline standpoint, as you know, we improved the base decline from 25% 2 years ago to 22% last year. And it's the same this year, it's at 22% as well. But given the things Richard said, that gives potential to flatten that out of it in the future.
David Deckelbaum:
I appreciate all the color on that. And if I could just ask a quick follow-up. Just the -- so I'm understanding, there was $400 million, I think, that was attributed to the difference to the low end versus the high end of capital guide, which I think you talked about Low Carbon Ventures spend that would be potential in OBO. I guess for the Low Carbon Ventures spend, would that just be accelerating some projects? Or is it the contingency for things that you're considering doing but aren't sure if you want to pursue at this point? I guess how do we think about that sort of allowance that's built in to the difference in the low and the high end?
Richard Jackson:
Yes. This is Richard again. I think you've got it right from the standpoint of really the LCV capital's certainly focused meaningfully on our direct air capture plant 1. So there is a project time line associated with that, where engineering is going great. The commercial aspects of the project continue to be supportive. And so there's a little bit of uncertainty there, but that component, we'll have more visibility and be able to talk more about even with you next month.
In addition to that, what's happened is really beyond strong engineering progress, we continue to have good commercial support, whether that's global policy recognition for carbon capture or even direct air capture in particular, or even with strategic net-zero businesses. And so these things support commerciality. And so what's happened is we do see additional opportunities for direct air capture. For example, we had an opportunity in Canada to look at, with a developer, direct air capture with air-to-fuels. And so a bit of that money is, as these projects become more opportunistic, we would allocate some feasibility capital to be able to look at these other type projects. The final piece is really our CCUS. And you've probably seen some pieces around projects that we're involved with. And so those continue moving beyond into commercial development. And so we have some capital associated to continue those. But that, again, be able to share more in March around that, but look forward to these projects advancing meaningfully this year.
Operator:
And ladies and gentlemen, our final question today comes from Raphaël DuBois with Societe General.
Raphaël DuBois:
The first one is related to your EOR business. Could you maybe tell us a bit more how production in this division has trended since you stopped reporting it as a single entity? And also, I was wondering if the extra CapEx you will throw at this business is solely to stop decline, or whether you intend to restart growing this business as well.
Richard Jackson:
Maybe I'll start with the EOR just a little bit. As we think about the last couple of years, I'd say the opportunity in front of us really to address any decline that we've seen is really -- and this comes to our OpEx, when we talk about that, that's really restoration of maintenance and specifically downhole maintenance. And so the ability to allocate some of that cash investment to restore down production is some of the best cash investment we have. It's very high-return even at mid-cycle prices.
And so we expect to be able to -- and have added some well service rigs, to add up to 6,000 barrels a day by year-end. And that really restores the normal backlog and maintenance schedule that we had really going back to 2019. So that's the most meaningful change in terms of the EOR business that we're approaching this year.
Raphaël DuBois:
Excellent. And my follow-up will be actually on Algeria. I see that you're going to have some activity there in 2022. I was wondering if you could tell us a bit more what you have in store for the for this part of the world, knowing that we in Europe are going to need much more gas from other suppliers. And it will be great if you had some projects, some gas projects in Algeria, for instance.
Kenneth Dillon:
It's Ken here. First of all, I'd say the operations team had a great year last year and achieved a 50,000 barrel a day milestone. On the contract side, we spent the time optimizing the future development plans that you're sort of alluding to. And we worked through the legal framework around the new hydrocarbon law, which is designed to encourage foreign investment in the country.
This year, we'll drill 4 wells. There'll be 2 injectors, 2 producers. And we've now started negotiations with Sonatrach and we're in early stages. It's a large American company with state-of-the-art shale capabilities. We think we have a lot to offer the country going forward. And hopefully, that helps in Europe also. And we'll keep you updated on our progress at the next call.
Operator:
Thank you. And ladies and gentlemen, this concludes our question-and-answer session. I'd like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Thank you all for your questions and for joining our call today.
Operator:
Thank you, ma'am. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.
Operator:
Good afternoon, and welcome to the Occidental's Third Quarter 2021 Conference Call. [Operator Instructions] I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Eileen. Good afternoon, everyone, and thank you for participating in Occidental's Third Quarter 2021 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Rob Peterson, Senior Vice President and Chief Financial Officer.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. I will now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good afternoon, everyone. Our strong operational and financial performance continued in the third quarter. Consistent with prior quarters this year, we generated a record level of free cash flow before working capital, which we apply towards reducing debt and strengthening our balance sheet.
Operationally, our business has excelled driving our robust financial performance. OxyChem had its strongest quarter in over 30 years in our Permian, Rockies, Gulf of Mexico and Oman teams, set new operational records and efficiency benchmarks. As was the case last quarter, our cost structure and capital intensity leadership served as catalysts for our strong financial results and provided a solid foundation for free cash flow generation. Our Gulf of Mexico and OxyChem operations were impacted during this quarter by Hurricane Ida. Our primary focus was the safety and well-being of our employees and contractors, and we were relieved to hear that our people remained safe during the storm. We are working closely with those that were impacted, and I could not have been more pleased with how our teams overcame the challenging events triggered by the storm. The Gulf of Mexico and OxyChem operations that were affected by Ida are back online with no lasting impacts. I'd also like to pass along our best wishes to our coworkers in Oman's capital of Muscat and to all the people of Oman as they recover from the devastation recently caused by Cyclone Shaheen. This morning, I'll cover our third quarter operational performance and divestiture progress, Rob will cover our financial results and balance sheet improvement as well as our fourth quarter guidance. Our guidance for the fourth quarter and full year includes an increase in production and an improvement to earnings guidance for Midstream and OxyChem. The commodity price environment continued to be supportive in the third quarter as our focus remained on generating free cash flow and maximizing margins. This is the third consecutive quarter that our operational success and capital intensity leadership have produced a record level of free cash flow. In fact, our third quarter free cash flow was the highest it's been since at least the turn of the century. As you know, that time frame included several periods of significantly higher oil prices. Total production for the quarter reached the high end of our guidance, which is a noteworthy accomplishment considering the extended downtime in the Gulf of Mexico. Hurricane Ida's impact on third quarter production and the costs associated with safely shutting in production, evacuating and then restarting the platforms and ongoing projects resulted in higher-than-expected domestic operating costs for the quarter. Our fourth quarter domestic operating cost guidance reflects normalized conditions and is relatively in line with our previous expectations for the year. On our last earnings call, we highlighted OxyChem's many strengths and consistent free cash flow generation. OxyChem's third quarter earnings were the strongest since 1990 and are a great example of what the business is capable of delivering. While Hurricane Ida disrupted third quarter operations, the impact to OxyChem's Louisiana-based facilities was temporary. The storm reduced production capacity in the period when market inventories were already fairly tight by historical standards. OxyChem continued to benefit from supportive PVC and caustic pricing resulting in a stronger-than-anticipated earnings. Our Midstream and marketing business benefited from the timing of export sales during a rising crude price environment and a healthy market for the sulfur produced at Al Hosn. The marketing team was able to capitalize on natural gas price volatility during the quarter by directing gas towards transportation solutions, yielding the high spreads. In summary, our team was once again able to utilize existing contracts and their expertise to maximize margins by delivering product to the markets that needed it the most. We continue to make notable progress in reducing debt and strengthening our balance sheet. We exited the third quarter with approximately $2.1 billion of unrestricted cash following the repayment of $4.3 billion of debt and the settlement of $750 million of notional interest rate swaps. We are pleased to have delivered such a sizable reduction in debt in a single quarter. In a healthy commodity price environment, we expect to continue reducing debt in future quarters as we delever and take the necessary steps to move towards returning additional capital to shareholders. Our oil and gas teams continued to demonstrate a consistent drive for efficiency as we never tire of setting new operational records or generating record levels of free cash flow. I continue to be impressed by how our global teams are able to deliver outstanding results. And I want to highlight several of the examples of operational excellence in the third quarter. I'll start in the Permian, where we drilled our first 15,000-foot lateral wells in the Midland Basin and did so with impressive results. One of the first wells was delivered in less than 10 days from spud to rig release. In the Delaware Basin, year-to-date, we're drilling 16% faster than we were just a year ago. The efficiency gains that our teams are recording extend well beyond the Permian. Our Rockies teams set a new Oxy daily drilling record in the DJ Basin with over 9,700 feet drilled in 24 hours. In the Gulf of Mexico, we set a new cycle time drilling record, and our hosting platform achieved a size production in 10 years. In Oman, we set new multiple drilling records and completions efficiency records as our teams continued to leverage new technologies and drilling techniques to improve performance. Another significant milestone reached by our international business was Dolphin, delivering its tenth Tcf of natural gas in the third quarter. The impressive efficiency gains we have highlighted on the last few earnings calls are translating into tangible financial results. Our innovative approach to drilling and completion techniques, coupled with supply chain optimization, will enable us to deliver higher production than initially planned this year. And I want to point out, we're accomplishing this all while maintaining our commitment to capital discipline. We continuously seek new ways to work with our partners to lower cost in a socially and environmentally responsible way, and we're pleased to have been able to do that in the third quarter. Through our partnership with a leading midstream company, we increased by about 30% the capacity of the water recycling plant that supports our Midland Basin, South Curtis Ranch development. This expansion has enabled us to recycle and utilize higher volumes of water from the plant. In addition to lowering costs, we have not disposed of any water at the South Curtis Ranch development since August. Across our U.S. onshore assets, our transition to using dual fuel frac fleets and drilling rigs has saved over 6 million gallons of diesel year-to-date, lowering cost and reducing emissions. And Colorado's new permitting process became effective at the beginning of this year, we worked closely with regulators to adapt to the new process and requirements. As members of the communities where we operate, our goal is to serve as a resource and educate stakeholders on Oxy's approach to responsible development. Our inclusive approach has been helpful in securing DJ permits. In September, we were pleased to see the process move forward for Oxy with the approval of additional permits in Weld County. Our engagement with and support from communities remains strong, as does our commitment to responsible development as we work to secure additional permits. The momentum that our oil and gas business has generated throughout 2021 has helped position us for a strong start in 2022. We recently completed our large-scale divestiture program with the sale of our Ghana assets for $750 million. As many of you know, we have been working closely with our partners in Ghana to complete this divestiture and have successfully closed the transactions with both buyers. For the Ghana divestiture, we have completed our goal of divesting $2 billion to $3 billion post Colombia, marking the end of our large-scale ongoing divestiture program. We have now divested approximately $10 billion of assets since August of 2019, and including the debt that was repaid in the third quarter, we have repaid approximately $14 billion of debt. As we maintain our focus on shareholder value, we'll continue to seek opportunities to optimize our portfolio. We will continue to complete acreage trades or bolt-on acquisitions if they create value for our shareholders. I'll now hand the call over to Rob, who will walk you through our financial results for the third quarter and guidance for the fourth quarter.
Robert Peterson:
Thank you, Vicki. In the third quarter, we generated a record level of free cash flow as commodity prices remained healthy and our businesses performed well. We exited the third quarter with approximately $2.1 billion of unrestricted cash on the balance sheet after repaying $4.3 billion of debt in the quarter. Through September 30, we have repaid $4.5 billion of debt and retired $750 million of notional interest rate swaps. We estimate this will reduce interest and financing costs by $170 million per year going forward.
Our consistently strong operational results, in combination with current commodity price environment, are driving improved profitability on top of our already robust free cash flow generation. In the third quarter, we announced an adjusted profit of $0.87 and a reported profit of $0.65 per diluted share, following on a return to profitability on an adjusted basis in the second quarter. Similar to previous quarters this year, our reported results were less than our adjusted results primarily due to the mark-to-market impact of derivatives. As commodity prices improved throughout the third quarter, we made payments of $14.2 million on the remaining oil hedge position and $24.1 million under our gas hedges. We recognize that shareholders appreciate our leveraged oil prices, and the recent uplift in natural gas prices. Our current oil and gas hedges will expire by the end of this year, and we have not added any new hedges for future periods. As Vicki mentioned, the sale of our Ghana asset marks the completion of our large-scale divestiture program. These assets were classified as discontinued operations around financial statements, so there will be no impact on ongoing production. We will apply the cash from this divestiture and any cash to generate from future portfolio optimization towards our cash flow priorities, which are currently focused on reducing debt. We have raised our full year production guidance to 1.155 million BOE per day for 2021, while our full year capital guidance of $2.9 billion remains unchanged. Last quarter, we raised our full year production guidance shortly before Hurricane Ida temporarily disrupted our Gulf of Mexico production. Even taking into account the impact of this sizable storm, we met the high end of our company-wide production guidance for the third quarter. Our fourth quarter capital spend is expected to be higher than prior quarter this year primarily due to the timing of maintenance activities in all 3 of our business segments. In oil and gas, for example, a portion of the capital spending in the Gulf of Mexico was moved from the third to the fourth quarter due to Hurricane Ida, and we plan to accelerate the start of 2 rigs in the Permian, which I'll touch on shortly. Company-wide fourth quarter production is expected to be 1.14 million BOE per day, which represents a 5,000 BOE per day increase from the guidance provided on our last call. Our fourth quarter guidance, which is slightly lower than our third quarter results, takes into account production sharing contract price sensitivities, planned maintenance and our activity schedules. We expect to exit 2021 at approximately the same average quarter production as we exit 2020 with. We have updated our activity slide to include 2 additional Permian rigs that were originally scheduled to start early next year and will now begin operating in the fourth quarter in the Texas Delaware and New Mexico. Similar to the activity change we announced last quarter, this adjustment will be fully funded through cost savings and optimization of capital projects gained through efficiency improvements and will not increase our 2021 capital budget. Texas Delaware and New Mexico are 2 of our highest return assets, and introducing activity in the fourth quarter will place us in a stronger position for 2022. We expect that the market dynamics, which drove Midstream and marketing performance in the third quarter, will continue in the fourth quarter. We have increased forward guidance to reflect improved differentials benefiting the gas marketing business and robust sulfur pricing at Al Hosn. We have increased earnings guidance for OxyChem for the third time this year, reflecting year-to-date performance and continued strong product demand. Not only do we expect 2021 to be a record year for OxyChem, we also anticipate the fourth quarter will be even stronger than the record third quarter. We believe that the market recognizes and appreciates the value being delivered to shareholders through debt reduction and balance sheet improvement. As we work to repay additional debt, we expect that shareholders will continue to benefit in several key ways. First, we expect that the additional debt reduction will translate into share price appreciation. We acknowledge that healthy commodity prices have played a role in the improvement of Oxy's enterprise value over the last 18 months. Assuming the enterprise value our company remains stable or improves, equity will become a larger portion of enterprise value over time as debt is reduced. The interest and financing costs saved on a go-forward basis lowers our cash flow breakeven. We expected a lower cash flow breakeven will result in additional discretionary cash being available to allocate towards our future cash flow priorities, including returning capital to shareholders. As we stated previously, we want to ensure that returning additional capital to shareholders, including any increase in the dividend, is sustainable and ratable throughout the cycle. Reducing the amount of cash committed to interest payments today places us in a stronger position for the sustainable return of capital in the future. Finally, lowering fixed costs in the form of interest or interest rate swap payments improves our flexible and optionalities at any point in the commodity cycle. Our balance sheet improvement efforts have placed us with a clear runway for the next few years, and we are taking a thoughtful approach to repaying additional debt in a manner that is opportunistic for Oxy. Executing additional tenders or exercising attractive make-whole provisions are just 2 of the solutions we are considering. We may also choose to retire the remaining interest rate swaps, which have an uncollateralized value of approximately $400 million and could be another opportunity to improve cash flow by approximately $45 million per year at the current interest rate curve. As we advance our cash flow priorities, we expect Oxy's financial position to strengthen, aided by our deleveraging efforts and our strong liquidity position. As we near the end of 2021, we are preparing for the year ahead with the underlying focus on safe, responsible operations and financial discipline, which we believe will create value for our shareholders. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. We understand that there's a high level of interest in our 2022 plan, which we'll announce in our next call. But now we'd be happy to take your calls for this segment of the call.
Operator:
[Operator Instructions] Our first question today comes from Jeanine Wai with Barclays.
Jeanine Wai:
Our first question is perhaps on the balance sheet and growth. When do you see Oxy getting to the net debt of about $25 billion for that marker? Depending on oil prices, our model suggests you can achieve that by about year-end. And if that's the case, is it just a matter of waiting for the macro to give you the all-clear sign in order to begin layering some growth capital?
Vicki Hollub:
Certainly, we are achieving a line of sight towards getting to that net debt target of $25 billion. So we're going to get there sooner than we expected. But in terms of what we would do with the cash flow after that, we'll follow our commitment to our cash flow priorities, and the next in line would be to start to increase our fixed dividend. So that would be in terms of orders of priority, our next target. We really don't feel like we need to provide growth at this time from the standpoint of where we are today with respect to our cash flow generating capability. So future growth for us really is -- would be in support of growing a dividend, not growth for growth's sake.
Robert Peterson:
Yes. And Jeanine, I'll add to Vicki's comments on that. Just as we get to that, we've discussed feathering in the dividend at $25 billion. We're not going to stop our debt reduction at that point. We're continuing to put cash flow into our debt reduction priorities beyond our other top priority of maintenance capital.
Jeanine Wai:
Okay. And then maybe we can pivot to a different kind of growth. The role of carbon capture, it's going to be absolutely tremendous in the energy transition. And Oxy clearly has core competency in this area. And Vicki, in the past, I think you've sized the potential of Oxy's carbon capture business as rivaling that maybe of your other businesses over time. So if you have any comments or update on that, that would be great. And if overall, you can just discuss your updated view on Oxy's future as a carbon management company?
Vicki Hollub:
We still believe and are moving toward becoming a carbon management company. We think that's going to be needed for the energy transition. And we're actually filling a gap with what we're doing, as you know, with respect to what others are doing. Every -- there's a lot that really needs to happen in this energy transition for us to be successful to cap global warming at 1.5 degrees.
So there are some companies in the oil and gas industry that are moving more towards renewables, and that's very much needed. And there's -- there are others that are working very hard to mitigate all of their emissions from current operations. We're working on both of those but not the renewables. We're working on reducing our current emissions from ongoing operations but we're also, as you know, taking advantage of the core competence we have with CO2 and the handling of CO2 will enhance oil recovery. So we believe that that's a gap that nobody else is filling. And the reason that gap is necessary is for several reasons. First of all, there has to be CO2 removed from the atmosphere. There's nobody in the world that disputes that. So direct air capture is going to be critical for that to happen. So with direct air capture, not only can we remove CO2 from the atmosphere, but also that helps us to develop and produce oil that's either net zero or net negative carbon. So that enables us to provide the hard to decarbonize industry, such as aviation or maritime with fuels that are net zero carbon. So there are 2 reasons to build direct air capture, first of all, for the removal from the atmosphere, the provision for providing those net zero carbon fuels. And the things that makes it very versatile is you can build it anywhere. So we think that because of the magnitude of that impact around the world and the need for thousands of these to be built, it provides us the opportunity to be a big part of that and to actually be a leader in developing the technology. So we think we will transition, the transition will take some time. But over the next 10 to 15 years, I think we'll make a lot of progress towards becoming net carbon management company and a go-to company for those that need the CO2 offsets.
Operator:
Our next question comes from Doug Leggate with Bank of America.
Douglas Leggate:
And welcome to the end of earnings week, Vicki, thanks for closing us out, I guess. I've got a couple of questions, specifically around the return of cash comments. And if you don't -- if you can indulge me for a minute, I'd like to kind of lay out my thinking here. Your share price is lagging pretty badly today despite extraordinary free cash flow yield in our numbers and a clear line of sight to deleveraging. So there's something the market is not acknowledging, obviously.
And our feedback, I guess, is that you're the only company not giving meaningful cash returns back to investors. So my question is, how do you think about the right level or the appropriate mechanism to return cash when your stock has such a high free cash flow yield. Let's assume that persists. That's my first question. And my second question is Pioneer and NOG, one has practically no net debt, the other is targeting no net debt. Where do you think the right level of debt is once you surpass your $25 billion target? Where do you want it to be? So first question, the mechanism for cash returns. Second question, the long-term mid-cycle appropriate level of your balance sheet.
Vicki Hollub:
Well, as you know, to get to around $25 billion net debt was our target. And as Rob mentioned earlier, now that target is in line of sight and, again, much sooner than we expected. So once we have actually achieved that, then we'll begin to layer in some of the other things that we can do with our cash, most notably and primarily would be to grow a fixed dividend. And then beyond that, again, I don't see capital growth until we've gotten to a point where we need to make that happen.
I think we've talked about it over the last couple of years that we feel like it's very important to keep our breakeven around $40. So as we establish a fixed dividend and move forward, we would grow our cash flow to match the growth in the dividend rate. So that it will happen, and it will happen over time. With respect to other considerations for the use of cash, it will really depend on the circumstances that we're in when we actually have reestablished or actually grown the existing fixed dividend that we have.
Robert Peterson:
Doug, I guess a piece I'd add to that is what we've done is consistent of what we've been messaging ever since we got into this deleveraging process. We indicated to market, as Vicki said, that we were going to get into that net $25 billion debt range before we considered raising -- increasing value return to shareholders. And so we do have line of sight. It's obviously here a lot closer than we anticipated it would be because of the combination of all the work we did to strip out cash, but certainly commodity prices are much stronger than we anticipated.
And if it continues that way, it's not that far away that we'll reach that target. But we aren't there yet, and that's the reason why we're not increasing value returned to shareholders because we're sticking to our messaging and the plan we've set out in front of our shareholders. And so for us to prematurely deviate from that plan, bringing inconsistency to that message, we certainly don't want to bring to the marketplace.
Douglas Leggate:
Okay. This is a quick follow-up, and I'll jump off. I'm looking at the Apache example. We've come out basically given a framework where they are saying essentially, like you guys, the free cash flow yield is extraordinary. And so we're going to buy back a bunch of stock. That's really what I'm driving out here. Your capacity for potential buybacks is pretty material. Can you offer any kind of thoughts as to why that might not be the case and what the limitations are around the preference shares as it relates to whether share buybacks would be practical. I'll leave it there.
Vicki Hollub:
I would say, Doug, we're not at the net debt of $25 billion yet, and we want to see what the macro conditions are and what's happening with our stock at that point. So since we're not there, it's really hard to provide any direction right now on what we would do. The one thing we can tell you is that we will follow our cash flow priorities, which is the fixed dividend first, before we would do and consider anything else. The share repurchases are a longer-term possibility for us but not the nearest term. The nearest term would be the growing the dividend.
Operator:
Our next question comes from Neil Mehta with Goldman Sachs.
Neil Mehta:
Vicki, the first question is just around sustaining capital, recognizing you're going to provide a little bit more clarity on '22 here in the coming months. But can you just talk about how you see that trending as we move into '22? And what are the tools that you have in place to mitigate the natural cost inflation that should arise as oil prices stay at elevated levels?
Vicki Hollub:
I'll take the second one first. Our teams have worked hard to try to establish the right kind of contracts and business situations with service providers and material providers to mitigate inflation. We don't think necessarily we would mitigate all of it. We're just not sure right now what inflation will be. But we know that our efficiencies and our established relationships and business situations will help to mitigate some of it.
We're hoping to continue also to further improve our efficiency so that we can mitigate more than what we would see today. But that's -- there's a lot of work going on around that and especially with respect to how we manage our supply chain and the strength of our position not only in the U.S. but around the world. So we're leveraging that as well. With respect to the sustainability capital, I will say that inflation, whatever amount we can't mitigate would be certainly on top of what we have today. And the only thing that I could really point to in terms of what we've said before about this is, in 2022, we won't have as many DUCs to complete as we did in 2021. So there's a difference there. We completed about 100 DUCs this year. In addition to that, we're going to have some capital investment that we'll need to make in 2 other areas, both of which we mentioned before. Al Hosn, we'll begin the expansion of that in 2022. So we'll have that cost. We'll also have some incremental cost in the Gulf of Mexico. So it will be higher than the $300 million we had this year because the Gulf is a little bit lumpy in terms of capital investments. So we'll have those things to consider when we are putting together our final plan for 2022.
Neil Mehta:
That's helpful. And just the follow-up is the composition of the portfolio. As you evaluate the different upstream buckets, the Permian, Rockies, Gulf of Mexico, Middle East, how do you see that evolving over time? Is there an area where you see is going to represent a disproportionate amount of the incremental capital beyond what you've already laid out?
Vicki Hollub:
The Permian will always see a bigger portion of the growth capital or even the maintenance capital than anywhere else. As we're starting to -- are continuing to offset declines, there may be some of our areas that do decline. That would be made up usually by the Permian Basin. But all of our areas play a role in what we're doing. In fact, the -- for example, the Middle East, that's a -- that area for us is very helpful to continue development there because the contracts provide us some protection in a down market the PSCs do.
So Oman is important to us from that respect. And we do have a low cost of development there, and we get our cash back fairly quickly. So that's the good part of Oman. It delivers good returns. And Al Hosn is a low decline asset for us. So it plays that role. We want to continue building on our low-decline assets, but that will be -- a lot of the growth for that will be going back to EOR at some point to start building there as we get this anthropogenic CO2. So EOR in the Permian will play a bigger role in the future. But low decline assets are important to us, but the bulk of our dollars beyond sustainability ultimately would go to the Permian.
Operator:
Our next question comes from Raphaël DuBois with Societe Generale.
Raphaël DuBois:
The first one is a follow-up on the shareholder return. Can you please remind us why you think it is more appropriate to start by increasing the dividend instead of starting shareholder return by a large buyback program considering you -- I think we all agree that you are somewhat undervalued? So wouldn't it make more sense to start by the last buyback program?
Vicki Hollub:
The reality is that there are multiple things that we could do with our cash. We believe that restoring the dividend as the -- and not restoring it to the prior level but continuing to increase it over time is a better and more predictable value creator for our shareholders. We have always been a dividend-paying company. It's important for us to get back to that and make it a more -- get it to a level where it's more meaningful to our shareholders, but we always want to evaluate buybacks. And so I'm not saying that we would never do it or never consider it. We're just not at the point now where we have all the data to be able to make that assessment.
For example, today, we're not at $25 billion net debt. Now when we get there, we will take a look at all the things that are available to us to do. But starting to grow the dividend we have today is a high priority because of the fact that we did have to reduce it significantly, we want to start restoring it. But any time we look at cash, we would have cash beyond that available. And then we would just do the value calculations to determine whether it makes sense given the other opportunities for us to buy back shares. It's always a consideration.
Raphaël DuBois:
Great. One extra question on OxyChem, the results in Q3 were excellent, and your guidance in Q4 is nothing short of amazing considering there is always seasonality in this business. And usually, Q4 is not as strong as Q3. So can you maybe tell us a bit more about the market dynamics in terms of supply and demand? When do you think we should expect some sort of normalization of your chemical business?
Robert Peterson:
Yes. Sure, happy to discuss it, Raphaël. So I would say what we see today in the chemical business is still very strong conditions in our vinyl business and steady improvements in the caustic business. And you're correct. Typically, we're normally entering into a seasonally slower period of time. But we're just not seeing that thus far because if you step back and look at the year, the industry, which already was pretty tight on supply to begin the year, lost almost 2 months of production because of the freeze we had in the Gulf states in February and then the impact of Ida that we had in the third quarter. So the combination of those 2 has kept coupled with the demand being as strong as of all our products has kept the supply-demand balance much tighter than anticipated or typically historically at that time of the year.
Those are the 2 main drivers. On Slide 31 of the deck, we included. Obviously, the main profit drivers for the business and the earnings are going to come from both the PVC business and the caustic soda business. The operating rates year-to-date are over 80% in the PVC business despite the impacts of the 2 storms and the lost months of production. And domestic demand is up over 13% versus this time year-to-date last year. And that's even when we started picking up the demand post COVID last year. The other thing I would say is that the construction sector, much like it is with other building products remains very strong with inventory levels still very low. And you can tell that inventories are very tight because exports are really soft still compared to historical levels. And what you have is with exports being down over 1/3 versus prior year, even prior being a COVID year, that's because the discretionary resin is just not available. And so what you only exported PVC resin is really destined for long-term contractual sales from U.S.-based producers that have relationships overseas. And you're not seeing that spot resin flow into the market, which means people are still just trying to get enough resin for the domestic market, which is going to keep prices elevated and margins elevated through that period of time. And so that's kind of atypical for this time of the year, but we do see it continuing through the balance of the year. Does it continue all into the winter? Construction necessarily has to slow during the winter, but we don't have a flavor for is how much are people going to want to restock inventories to be ready for what looks like another strong spring construction, which will return pretty early in the year next year. On the chlor-alkali side, I'd say chlorine is extremely tight as producers are still trying to seek the highest value for the outlet. This is where OxyChem's vast portfolio of derivatives gives us so much strength versus many others because we're not just making PVC, we're making all 3 parts of the Vinyl's chain. We're also selling into a domestic market that gives us exposure to the polyurethane markets, the TiO2 markets, et cetera, and water -- beyond just water treatment and others that traditionally think of and our own chloromethanes business. And so all those we're seeing strong demand and supply/demand balances are very tight. And we will see more than likely in the backside of another difficult operating year in the industry a continued effort to rebuild inventories, not only in supply chain, but there's also -- we're seeing a lot of pent-up demand still coming back as things somewhat return to normal on the backside of the pandemic. Particularly, caustic soda demand globally will continue to improve as manufacturing activity is restored in both South America and Asia and Europe. And so what we're seeing on the caustic side is, again, steady improvements where we're not seeing record prices on caustic soda yet like we are on PVC, but some of the prices in Asia have risen to levels that haven't been seen before. And so both businesses are very strong right now. We will see a seasonal slowdown in caustic domestically because you're no longer able to transport caustic up the Mississippi River for the winter, but we don't see it really impacting the industry enough just because inventories are so tight. And so I still think January, February will continue to be slower months for the industry but it's going to be such a narrow period with the tight inventories. We'll probably hit the ground running pretty quick in this spring again.
Operator:
Our next question comes from Neal Dingmann with Truist Securities.
Neal Dingmann:
Vicki, can you just share maybe just broadly how you're currently thinking about sort of just on the strategy growth versus capital discipline today in light of -- I know Rob's just had some minor comments on just adding some Permian rigs, but just maybe if you could share your thoughts on where you sit with that today.
Vicki Hollub:
Yes. I would say that, for us, growth -- production growth is not a priority for us right now. because if you look at our cash flow generating capabilities and with our strategy around that going forward, is to basically when we get to our net debt target of $25 billion, that's not where we'll end. As Rob mentioned, we want to continue working to reduce our debt beyond that. But the need to do so at a bigger level is just not there. We get to the $25 billion. We'll share more information as we get there about what our next target would be with respect to debt reduction. And then again, it's to start growing our dividend again.
And the only point at which we would really need to start growing our production would be down the road, where we want to continue growing the dividend. We don't need additional growth from production right now to be able to increase the dividend over the next couple of years because, again, with what we expect the macro to be and the level of increase in our dividend, we believe that we can do that without any production growth over the next at least couple of years. So it would be continuing to maintain our operations, our production level. And then these occasional projects that are beyond the sustainability capital, like the GoM, Al Hosn could be those over the next couple of years. But other than that, it's then going to the dividend and further debt reduction.
Neal Dingmann:
And I assume your low decline helps with all that.
Vicki Hollub:
Pardon me? Yes. And that's why it's important to have these low decline projects that enables us to execute on this strategy.
Neal Dingmann:
Absolutely. And then one last one, if I could. You've mentioned, I think maybe even on the last call or maybe the prior in the past about maybe having hopes to get more than just a Q45 tax credit can maybe help you and others potentially expedite some of your plans in that low carbon area. I'm just wondering, is this still something you think is needed to help you and others expedite clients with low carbon and if you did end up expediting this, would that come at the expense of cash going towards the upstream business?
Vicki Hollub:
I would say that the world absolutely has to have acceleration of direct care capture, not just our DAC facilities, the carbon capture and retrofitting industry. It has to happen. So the only way that it can happen and at the pace that's needed for the world is for the U.S. to get on board with supporting it, and the U.S. has the strength and the capability to do that. And the best way to do it is through 45Q and direct pay 45Q.
So you're right on that, that's incredibly important to us. Otherwise, the U.S. will not achieve the targets that we've set with even the prior Paris accord, much less what's happening in Glasgow right now. So 45Q has to happen and really needs to be direct pay. Otherwise, we're going to struggle to be successful. But with respect to what we're doing, there is going to be a price for carbon because there's a lot of commitment from corporations now to get to net neutral. Everybody, I think, realizes at some point that if we don't achieve our goals through the incentives like 45Q, and there's going to have to be some price mechanism on carbon to make it happen. And so what we're seeing is a lot of corporations are trying to get ahead of that. A lot of corporations are starting to fill. Just see that there's a social license to operate in that -- to have that, there has -- they have to proactively start seeking CO2 credit offsets to become net neutral. United has been one, as you know, that we've announced that wants to do that, and they're proactively committing to dollars to the building of the direct air capture plus, the purchase of the oil that would be the net zero oil. Other corporations are calling us. We're getting a lot of incoming interest in the direct air capture because of that. So I do believe that there's going to be sufficient growth and commitment to make what we're doing here in the next -- in the initial phases work. But beyond that, again, what it's going to require is a much more acceleration than that.
Operator:
Our next question comes from Phil Gresh with JPMorgan.
Phil M. Gresh:
One follow-up question just around the dividend situation. You talked about wanting to have a $40 WTI breakeven. And I just wanted to get some clarification of how you would calculate where we are today. And then it sounds like you would want to grow the dividend multiple years up to the $40 WTI breakeven as opposed to call it once. So just a clarification around that, please.
Vicki Hollub:
Yes. The clarification is, right now, we're in the probably upper 30s on a breakeven, but that's not -- that's assuming that's without the preferred. So we're really close to where we want to be and where we want to stay. So as we grow -- as we restore the dividend at a moderate level, we'll do it in a way that enables us to grow it over time but probably not at the pace that we've done in the past. So it will be a moderate growth, but it will be a material dividend as we've always tried to maintain.
Phil M. Gresh:
Okay. So are you willing to go above the $40 WTI breakeven for the dividend? Or you want to keep the dividend within that, just to be clear?
Vicki Hollub:
Ultimately, we want to keep it within that. Now there's going to be some discussion and some evaluation of how do we start out that dividend growth, but we'll determine that when we get to the $25 billion net debt. We'll see, again, what will be supported by mid-cycle, what would be supported by a $40 breakeven.
Phil M. Gresh:
Got it. And then just one follow-up for Rob. Do you have a sense that you can share with us around U.S. cash taxes, what your situation is there when you become a full U.S. cash taxpayer?
Robert Peterson:
Yes. I think, Bill, from the standpoint, certainly, of this year where you don't anticipate any material cash taxes. Based on our viewpoint of 2022, we don't see that happening again also. We see ourselves, depending upon certainly the macro conditions, becoming a U.S. cash taxpayer in a meaningful way in 2023.
Operator:
Our next question comes from Paul Cheng with Scotiabank.
Paul Cheng:
Vicki, 2 questions, please. Shell had just sold their Permian asset to Conoco. Just want to see if you see that as a maybe additional opportunity for you guys to work with different partners and seeing either asset swap or other opportunity associated with that. Or do you think that this is just business as usual given that you are the operator and that doesn't really change anything. That's the first question.
On the second question, I think the focus has been everyone knows, nothing new about when you're going to increase your CapEx in the oil and gas sector, and you made it very clear not in any time soon. But how about in the chemical? And in the chemical, you guys have a very unique position. You are not in the typical olefin chain. And that, with the housing sector, has been very strong, and that really has been doing quite well or much better than before. So do you have any intention to expand and grow that business? And that may also be good in terms of energy transition. So I want to see that what is your overview in terms of from a growth prospect standpoint for that.
Vicki Hollub:
Okay. I'll start with the Shell assets. And we're always looking for opportunities to core up while we operate. And so asset swaps have been a big part of helping us to increase our working interest in the areas that we already operate over the last few years, and that's been very successful. And we will continue to try to do that. And we'll be working with Conoco and any other partners that are in our current operations and or nearby what we have to make swaps that work because those are always better for each company. Those are win-win scenarios. So those are something that's really important for us to do. We'll continue that. The second part of the question is OxyChem...
Paul Cheng:
Actually, before that, have you already reached out or that Conoco already reached out and talked to you between you and mine on that? Or that this is something that you guys are going to do?
Vicki Hollub:
Well, we had been in conversation with Shell for a long time, and we certainly have had conversations. Our teams worked with Conoco on other things. And so we have had contact about potential swaps. We think it would be best for both of us to be open to that and pursue that. So just as we have done with Shell, we're doing the same with Conoco.
So with respect to the OxyChem business, Rob knows this better than I do, but OxyChem has been very opportunistic in the past to ensure that they mitigated market risk by working out with partners opportunities to build and to grow but, again, without taking market risk. You have more to add?
Robert Peterson:
Yes. I would just add to that, yes, Paul, that if you look back to the history of projects, whether it was the chlor-alkali plant adjacent to the CO2 plant, or the cracker that we built at Ingleside the venture together or any of the relationships that we have, what we've been able to do is build long-term partnerships with our downstream customers that gives us sort of a pseudo integration into markets. Otherwise, we don't want to build into like CIO2 or polyurethanes or et cetera and partner with the leaders in those industries.
And so we're always evaluating that. But to Vicki's point, it's going to be something we're going to structure around where we're guaranteed a return on and of the capital necessary to continue to fund the cash from that towards the rest of -- the remainder of the business as a cash flow source. And so I think we're constantly evaluating that. Like anything else, there's probably a dozen projects that end up on the drawing board to get one good one that works out. But you're right that, there's a lot of growth in the chlorovinyl sector as a building product, and the advantage the United States has versus the rest of the world, the feedstocks is pretty significant. So we'll continue to evaluate those. And if something comes together, we'll be happy to share it with the market.
Vicki Hollub:
And you're right, Paul, that it is really an important part of our transition story. OxyChem will be a key player in that, and certainly, we're open to opportunities from any of our existing partners and new partners to help with that.
Paul Cheng:
They can. And Rob do you guys foresee growth capital into the OxyChem over the next 1 or 2 years or a little bit longer term?
Robert Peterson:
Yes. It's hard to say, Paul. I mean, I think it depends on timing of investments and what the opportunities are out there. And so we're constantly evaluating that and would integrate it in our portfolio if it made sense. But I would be purely speculating to give timing on when we might make the next significant investment in OxyChem.
Operator:
Our final question today comes from Leo Mariani with KeyBanc.
Leo Mariani:
Wanted to follow up a little bit on one of the prepared comments that you guys made. I think you commented there could be some bolt-ons in the future. Just wanted to get a sense in general of what Oxy's appetite might be for doing those type of things, just given that you've had a pretty prolific asset sale program for the last couple of years.
Vicki Hollub:
Yes. We would only do it if it was very strategic and something that fills the gap that we currently have. And there are situations where picking up some acreage would enable us to drill longer laterals. There are situations where we have the opportunity to increase working interest in something that we already own. And so those are situations that when they do come along, you almost need to do it. Otherwise, you may not get the chance to do it again.
Leo Mariani:
Okay. That makes sense. And I just also wanted to ask you guys, is there any update that you might have on the funding situation for your direct air capture projects? I think you guys were seeking kind of external off-balance sheet financing for that.
Vicki Hollub:
We don't have an update currently, but our plan is still to hold an LCD day, a rivet in the first quarter of next year. By then, a lot of what we're working on right now, we hope to be able to talk about publicly.
Operator:
This concludes our question-and-answer session. I'd like to turn the call back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Thank you all for your questions and for joining our call. Have a great day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to the Occidental's Second Quarter 2021 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Chad. Good afternoon, everyone, and thank you for participating in Occidental's Second Quarter 2021 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Robert Peterson, Senior Vice President and Chief Financial Officer.
This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good afternoon, everyone. Our strong operational performance in the second quarter continued to drive robust financial performance as we marked our second consecutive quarter of generating the highest level of free cash flow in over a decade. As was the case last quarter, our cost structure and capital intensity leadership were catalysts for our strong results and continue to provide a solid foundation for free cash flow generation in the future.
We were especially pleased to have been in a position at the end of the second quarter to launch a tender process to retire over $3 billion of debt using excess cash generated from operations as well as proceeds from divestitures. While we made incremental progress in reducing debt throughout 2020 in the first half of 2021, the completion of this tender represents a sizable step forward in our deleveraging efforts. This morning, I'll cover our second quarter operational performance and divestiture progress, and Rob will cover our financial results and balance sheet improvement as well as our updated guidance, which includes an improvement to our DD&A rate, an increase in guidance for our full year production and for midstream and OxyChem's 2021 earnings. In the second quarter, our business -- all of our businesses outperformed. Our capital discipline and efficiency, combined with the supportive and improving commodity price environment, positions us to generate the highest level of free cash flow before and after working capital since the third quarter of 2008 when WTI hit $145 a barrel. We are proud of our teams for this accomplishment, and we appreciate that they are continuing to improve our capital execution and operating efficiencies to further expand our margins. We exited the quarter with approximately $4.6 billion of unrestricted cash, which does not include cash received in July from the recently closed divestiture or the cash used for the debt tender which closed in July. Rob will touch on the under in a little more detail, but I would like to reiterate how pleased we are to be once again making notable progress in reducing debt and strengthening our balance sheet. Turning to our operational results. Our oil and gas business delivered second quarter production from continuing operations of over 1.2 million BOE per day, with total company-wide capital spending of almost $698 million. Our domestic oil and gas operating cost of $6 per BOE came in substantially below our full year guidance as our teams continued to demonstrate their innovative operations expertise by finding new ways to safely reduce costs in our field operations. In the second quarter, OxyChem continued to benefit from robust PVC demand and pricing as well as gradual strengthening in the caustic soda market. We believe the fundamentals for these markets will remain supportive through the second half of 2021, and we are confident in increasing our full year guidance to a midpoint of $1.25 billion, representing an almost 60% increase over our original guidance for the year. The ability of our oil and gas business to overcome challenges while increasing efficiencies has been transformational. Looking back over the first 6 months of this year, we overcame the impacts of a major weather event and divested a producing asset. We were able to make up the loss and divested production and have increased our full year production guidance for continuing operations to 1.15 million BOE per day. We continue to be highly encouraged by well performance across our portfolio. For example, in the Texas Delaware, we recently brought online a new Silvertip development that is producing approximately 20% more oil compared to a prior development in this area. Additionally, in an area of roughly 10 miles southeast of Silvertip, we brought online a 5-well development with average 30-day peak rates of almost 5,000 BOE per day. As I mentioned, operationally, our teams continue to set new efficiency records while constantly pursuing opportunities to improve. We set new quarterly records across our portfolio on feet drilled and hours pumped in a single day. In the Midland Basin, we set a new drilling record with over 9,500 feet drilled in 24 hours, contributing to a new Oxy Permian spud-to-rig-release record, drilling a 10,000-foot horizontal well in only 8 days. In the DJ Basin, we set a new company-wide track record of pumping over 23 hours in a single day. Utilizing Oxy Drilling Dynamics in the Gulf of Mexico, we have significantly lowered drilling cost and duration as the well drilled in 2021 have cost 15% less than the average for 2019. As I mentioned on last quarter's call, we've had excellent results leveraging remote operations. Our innovative mindset and ability to leverage technological breakthroughs have allowed us to continue pushing the performance envelope, giving me confidence that our best-in-class capital efficiency will continue. Our divestiture plan advanced in the second quarter with the recent closing of a noncore Permian acreage sale for approximately $510 million. Given our industry-leading inventory depth, we welcome the opportunity to monetize these assets at an attractive price as it is unlikely that we would have developed this acreage in the near future. We expect to close at least $2 billion of divestitures post Colombia. And as we've said previously, we'll always prioritize obtaining value for our shareholders over meeting a deadline. I want to take a few minutes to talk about our Chemical business and how we plan to leverage its leadership and expertise into our Low Carbon Ventures business. OxyChem's success is demonstrated by its financial performance and track record of consistent free cash flow generation. OxyChem has been a consistent generator of free cash flow during the past downturns. And with the macro environment improving, OxyChem is on track to deliver record earnings this year, even surpassing 2018's results. The business may also continue to strengthen in future years as caustic soda, one of the key profit drivers for the business, has experienced only a moderate price recovery to date. Last quarter, I spoke about how OxyChem's integration across multiple chlorine derivatives provides us with the ability to optimize our caustic soda production while opportunistically adjusting our production mix to maximize margins. There are many opportunities for us to apply the same approach to integration as we develop opportunities between OxyChem and our Low Carbon Ventures business. As a major producer of PVC and caustic potash, OxyChem has the engineering, R&D and process technology expertise as well as the production capability necessary to build our Low Carbon business. OxyChem is a world leader in the customization, handling and usage of PVC, which will be a major component in the construction and ongoing operation of the direct air capture facility. We're also one of the world's largest leading producers of caustic potash, the key chemical utilized in the direct air capture process to separate carbon dioxide for sequestration of carbon-neutral enhanced oil recovery. Our vast knowledge of equipment design and our experience with operating and handling the caustic potash will be key to helping us quickly optimize our direct air capture facility. In addition to being a market leader and consistent free cash flow generator, OxyChem is integral to our business of today and of tomorrow. It's also worth noting that OxyChem is a market leader in health, safety and environmental performance. OxyChem recently earned a remarkable 31 Responsible Care awards. These are from the American Chemistry Council and are the U.S. chemical manufacturing industry's leading performance awards. The awards recognize OxyChem's achievements in safety, waste reduction and improving energy efficiency. Several of the award-winning initiatives focused on waste minimization, reuse, recycling and energy efficiency, which will all contribute to our 2025 sustainability goals. I will now hand the call over to Rob, who will walk you through our financial results for the second quarter and guidance for the remainder of the year.
Robert Peterson:
Thank you, Vicki. Our businesses continued to perform well in the second quarter as our free cash flow generation affirmed our confidence in Oxy's ability to generate cash in a healthy price environment. The strong performance contributed to a quarter end unrestricted cash balance of $4.6 billion.
On our last call, I mentioned the potential for a partial reversal of the working capital change incurred in the first quarter. As expected, we benefited from a positive working capital change this quarter of approximately $600 million, further contributing to our cash build during the quarter. As Vicki mentioned, we launched a tender late in the quarter and enabled us to repay over $3 billion of debt in July. Subsequent to successful execution of a debt tender in July, we received proceeds from the nonstrategic Permian acreage, partially refreshing our post-tender cash position early in the quarter. In the second quarter, we announced an adjusted profit of $0.32 and a reported loss of $0.10 per diluted share. While we placed a greater importance on cash flow generation, especially as we are focused on deleveraging, we are pleased to be generating income on an adjusted basis. Indeed, this is a positive indication that our financial position continues to improve. Our reported results were less than our adjusted results primarily due to the mark-to-market impact of derivatives. We delivered outstanding production results year-to-date while having deployed less than half of our full year capital budget of $2.9 billion. We expect capital expenditure to remain within budget, demonstrating our commitment to capital discipline and our capital intensity leadership, even as capital spending has been higher in the second half than the first half of the year. The positive working capital change realized in the quarter was driven by lower cash payments for items that are accrued throughout the year and lower crude inventory from fewer barrels in the water, partially offset by higher accounts receivable balance due to the increase in commodity prices. As the interest payments on our bonds are made semiannually, our cash interest payments are going to be lower in the second and fourth quarters than they are in the first and third quarters. During the downturn last year, we received approximately $1 billion of additional cash flow from our oil hedges. To obtain a costless structure, we sold a 2021 call position of 350,000 barrels a day with an average strike price of $74.16 Brent. As the commodity prices rose at the end of the second quarter, we made payments of $5.7 million under the sold call position and $1 million under our gas hedges in July. Cash settlements paid to date on the hedges have been minimal and are certainly worth the benefit we received last year. We continue to maintain an opportunistic approach towards hedging, and the forward curve is supportive but have not added any hedges past the end of this year. We believe creating a manageable debt maturity profile and reducing debt is a more effective long-term solution to derisking the balance sheet while providing shareholders with exposure to commodity price gains. We raised our full year production guidance following our strong second quarter results and have increased our earnings guidance for OxyChem and midstream for the second time this year, reflecting strong first half performance and improved market conditions. We expect that 2021 will be a record year for OxyChem, even surpassing our earnings in 2018. We benefit from exceptionally strong caustic soda prices in the middle part of that year. Midstream is expected to benefit in the second half of the year from continued higher sulfur prices at Al Hosn as well as an uplift in the third quarter related to the timing of export sales. We also lowered our DD&A guidance for 2021, reflecting the midyear reserves update. This update takes into account more supportive trailing 12-month commodity prices at midyear compared to year-end 2020 as well as our activity plans and recent success in lowering operating costs. The combination of these factors have increased our proved reserves, which we expect to result in a lower DD&A rate going forward. Our production in the second half of 2021 is expected to average 1.14 million BOE per day. Production in the second quarter benefited from time-to-market acceleration in the Rockies and Permian. Favorable weather conditions and optimization of planned maintenance schedules to better sequence shutdown activities resulted in lower-than-expected downtime in the Gulf of Mexico, contributing to higher-than-expected production. Our expected third quarter production of 1.145 million BOE per day includes an allowance for seasonal weather and maintenance in the Gulf of Mexico, the divestiture of approximately 10,000 BOE per day in the Permian, the timing impact of our Rockies capital program, which was front-loaded in 2021 as well as PSC impact due to price. Even as production in the second half of the year is pretty lower than the impressive second quarter production results, we remain confident in our production trajectory leveling out as we enter 2022, where we anticipate a production pattern similar to 2021. We have updated our activity slide to include 2 additional New Mexico rigs. The New Mexico activity change will be fully funded through the cost savings and optimization of our capital projects' gain through efficiency improvements and will not increase our capital budget. Adding activity in one of our highest return to assets will place us in a strong position as we transition into 2022. With the successful completion of our debt tender, we paid over $3 billion of 2022 through 2026 maturities and have a clear runway over the next few years. As we generate cash from organic free cash flow, we continue to value the options available for additional debt reduction, and we'll seek to further our debt maturity profile so that we're not exposed to any significant amount of maturities in any single year. The options available to us for debt reduction include potentially calling the 2022 floating rate notes prior to maturity, executing additional tenders, exercising attractive make-whole provisions, pursuing all the market debt repurchases, or we may choose, in some cases, to build a cash position which may be applied towards retiring maturities as they come due. We also plan to retire $750 million of notional interest rate swaps in the third quarter for the fair value amount, which will improve cash flow by almost $50 million per annum at the current curve. We entered the second half of 2021 in a strong position at the beginning of the year, and as we look forward, we remain focused on maintaining a strong liquidity position, deleveraging to regain investment-grade metrics and preserving financial policies and cash flow priorities and embed capital discipline. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. We are proud of the substantial progress in delivering our near-term cash flow priorities. We have significantly derisked our balance sheet with the successful completion of our recent debt tender. And this marks the next stage of our deleveraging effort as we work to further reduce debt and to lower our breakeven. While we still have work to do before transitioning to the next stage of our cash flow priorities, including returning additional capital to shareholders, we're confident that the steps we have completed to date and the strong operational performance that we continue to deliver will accelerate our progress.
We'll now open the call to your questions.
Operator:
[Operator Instructions] And the first question will be from Neil Mehta with Goldman Sachs.
Neil Mehta:
And really strong results here on Chemicals, and that's where I want to start. Can you talk to your views on caustic soda and PVC pricing for the remainder of the year and next year and the sustainability of the margins that we see out there?
Robert Peterson:
Yes, Neil. We continue to see very strong conditions in both our vinyl business and steady improvements in the caustic soda business, as Vicki indicated. As you can see on Slide 7 of the deck, these 2 businesses are the major profit drivers for our Chemical business. And it's unusual, but we do have conditions when both businesses are seeing favorable market conditions, the earnings impact that you're seeing is significant. So on the PVC business, the business remains extremely strong due to a tight supply/demand balance.
On a year-to-date basis, we're seeing domestic demand as an industry about 16% higher compared to the same period in 2020. But more importantly, it's up 13% from where it was in 2019 in a non-COVID period. And so strong demand is also attributed to really low levels of inventory and supply chain, combined with the construction sector, which we're seeing in, obviously, in a lot of their construction materials. And we expect demand to remain strong with a very favorable housing start outlook, mortgage rates remaining low, which tends to also drive historically the business and a lot of investment remodeling. And so we're -- those kind of factors are all pointing towards sustained improvement in the PVC business. The other thing I would say is that when the export business is soft like it is now, where we're seeing year-to-date exports are down 33%, which tends to be the last location of PVC production, that's indicative of a strong market. And so when there's not enough product to go around, we shouldn't see margins remain favorable for us. On the chlor-alkali side, the chlorine molecule itself is very tight, and so producers are seeking the highest-value outlets for chlorine molecules. And as Vicki mentioned, our very diverse portfolio of chlorine derivatives allows us to really maximize the bag of these chlorine molecules through our chain of opportunities. And so chlor-alkali production itself has been under pressure for the year simply because of a lot of both unplanned and planned outages. And if you look at chlor-alkali rates, they're actually lower in '21 than they were in '20 year-to-date, running about 75% year-to-date versus 80% over the same period last year, resulting in about 6% less caustic production available this year versus last year. So caustic is quite tight, which is helping to improve prices. And with it playing out into the schedule in the third quarter, we would anticipate that -- further support for additional price increases in the caustic soda business. And then as you see, caustic for us tends to be something that moves with the global economy. And well, certainly, as economies open up and eventually travel restrictions close -- ease globally, we should see additional demand in underlying sectors. And so as far as the key demand sectors in the second half, we see better demand in the alumina sector, the pulp/paper sector, water treatment and certainly the leasing sectors all improving in the third quarter. So both sides of the ECU are looking strong headed into the second half of the year. And the underlying factors certainly are bullish for both of them as we move into 2022 and beyond.
Neil Mehta:
And the follow-up is one of the key takeaways from earnings season is the emphasis investors continue to place on cash returns. And at this point, Occidental is more focused on deleveraging the business, which makes a lot of sense. Can you just remind us what your absolute debt target is? And then at what point or what milestones should we be thinking about the company shifting from a deleveraging approach, to one of where you can reintroduce something like a dividend?
Robert Peterson:
Yes. So certainly a topic du jour. So we depicted on the 13th slide of the deck, which was newly included, that we're essentially on a journey when it comes to cash flow priorities. And after a lot of risk in 2020, to derisk the company in what I call a post-COVID world, between the stabilization of production, the slashing of our costs and refinance near-term maturities, now we're making headway, as Vicki detailed, on our deleveraging process. And we took a significant step forward with the upside tender in July, through both a combination of cash available, from strong production performance, the continued capital execution and diligent cost management and really the remarkable turnaround in Chemicals, all contributed to the success of that.
And so now we've retired about $12.7 billion of principal since the middle of '19 through that combination of our great cash generation and investor program. And I think we'll continue to work towards the $2 billion to $3 billion post-Colombia divesture target that we've established. But as we look forward, it's anticipated that the majority of free cash flow from the business will be the source of future cash for debt retirement. And it's critical that as we take advantage of the elevated prices, to deleverage the balance sheet because we know any time there are going to be changes in the macro environment that could affect or alter commodity prices, that it would inhibit our ability to do that. So when I look at the time it takes, our path does remain focused right now on the 2 top priorities being that we're focused on in our list. And how long we're on that path is certainly dependent upon future commodity prices because that certainly impacts the rate at which we're able to move down the path. But I do think that the steps we've taken since March of '20 are all part of a long-term strategy around increasing value to our shareholders. For example, if you look at last year, in the derisking side, we could have saved a little interest in our refinance process by using more owners and ventures. But we sit here today with a much less risky maturity profile and much in the same simple capital structure we started with. And we do believe ultimately deleveraging the company is going to be the benefit of equity holders in the form of equity appreciation. And we also understand that, that leverage to oil price remains attractive and is determined at the pace of that process. And our EBITDA does fluctuate obviously a lot with commodity prices. And while some agencies have modestly increased their models, their prices are still well below the current strip. So that's why we keep saying that to get to a more sustainable debt level in the mid-20 range is likely necessary to achieve those ivy-like financial metrics. In addition to debt ratio, we understand obviously financial policies matter and thus great decisions. So use of cash or dividends, growth, et cetera, will also be viewed in the near-term unfavorably, so that's why we remain focused on the deleveraging process. And once we reach that more sustainable debt level, we will start resuming a greater amount of cash to shareholders.
Operator:
And the next question will come from Doug Leggate with Bank of America.
Douglas Leggate:
It's amazing to me how folks continue to look for cash returns, Vicki, when you've got the potential of moving 40% of your market cap between debt and equity over the next year. And I guess it's -- that's really the rub of my question, these disposals and how you can accelerate that. But I would like to frame it like this. When you announced the $2 billion to $3 billion target post-Colombia, Brent was $42 for the $2 billion to $3 billion target. Obviously, it's not there today.
So can you just give us an update as to do you expect to do more than the [ 2.3 ] on a pari passu basis for the oil price? Or are you moving and are you targeting $2 billion to $3 billion albeit, I'm guessing, you can do that with fewer assets given where the oil price is? So I just wanted you to help me risk the $2 billion to $3 billion. It seems to me you can probably do a lot more in absolute terms given the oil prices [ are still volatile ].
Vicki Hollub:
So at this point, we're not really prepared to change the goals that we've set out, although we feel very comfortable we will achieve the lower end of that goal. But Doug, you're exactly right. Given our portfolio, there could be other opportunities available to us to continue to optimize what we have today. And optimization to us is not just ensuring that you have the best quality assets in your portfolio, that you're putting the -- your dollars where they generate the most value. It's also looking at the opportunities to do as we just did, and that is to monetize where you see that the monetization of that is going to be so far out into the future. It's not meaningful value for our shareholders today.
So we're constantly looking at and updating, optimizing our plans and looking at those opportunities, where could there be additional situations where we have the same thing that we just did with this Permian acreage, monetize it today and have the opportunity to create better value today than to keep it in the portfolio when we know we can't get to it. So we're still looking at all those things, not prepared yet to change our guidance, but I can say that, opportunistically, we do want to create value sooner rather than later. So we'll continue to keep that in mind as we review the portfolio and optimize as we go along.
Douglas Leggate:
Vicki, I apologize for asking for clarification on this, but if you have the same number of assets, are you ahead of schedule then in terms of the absolute proceeds, again reflecting the fact that the oil price is higher?
Vicki Hollub:
We are on schedule with what we need to do. But with that said, given where oil prices are today, we're quite comfortable looking at opportunities as they come in. And by that, I mean, we're still getting opportunities coming in the door for various parts of our portfolio. And we look at all of those very critically. And I think that there's going to be situations that come up over the next 12 to 18 months that would provide us more opportunity to raise additional funds. But I don't want to commit to that because where we are now, and with respect to our cash flow generation and our deleveraging progress, we're in a position to be, I would say, much more careful, not -- and careful is not the right word, but much more, I guess, opportunistic, is the only word I can think of, to ensure that we get maximum prices for what we would sell.
Because we started out the divestiture program by cutting off the very tail end of what we felt like fit within our portfolio, that could fit with another portfolio in a higher level. But for us, the things we've sold just could not compete and could not add the value that other things in our portfolio could. So now as we have divested of those assets, we're now getting to the assets where we expect to get more value from a divestiture than those that were at the lower end, I guess, is the best way to say it. So -- but we're open to looking at opportunities as we see them.
Operator:
And the next question will come from Roger Read with Wells Fargo.
Roger Read:
And congratulations on the quarter. It's nice to see everything clicking for the first time in a while. I guess what I would like to maybe address, some of the metrics you're using that underpin the decision to move away from any sort of a hedging strategy and maybe getting back to thinking about from a debt-to-EBITDA, debt-to-cap, maybe a long-term debt number you're more comfortable with, just maybe all the pieces that have gone into it that kind of speaks to where you are now versus where everything was 12 and 24 months ago.
Robert Peterson:
Yes, fair question, Roger. So certainly, historically, the company has not been one with a hedging philosophy and felt like the combination of our exposure to commodities and exposure to the price of a long-haul would ultimately deliver the most value to our shareholders versus attempting to use hedges to try and create value. And that certainly changed in 2020 because we were in a position where our leverage was such that it was necessary for us to create some protection in the event we were in a negative price environment, like -- but it ultimately worked out that way.
And certainly, the $1 billion that we were able to create in value last year from the hedge was something that was critical to our success last year. And we'll continue to maintain the opportunistic approach. But as we evaluate hedges, we're considering a lot of factors. Number one is the cost to execute the hedge. Certainly, as a -- the cost of hedges that we did last year came with a call provision this year, which hasn't been very expensive, but they can be, and the implications that the hedge is going to have on the upside to leverage our oil price, such as a collar. And so a pure put hedge is pretty expensive. I think collars introduce an upside to that limitation that we would like to put on our shareholders. And so if you look at the -- we think that creating that manageable debt profile, as I discussed in the comments, particularly knocking down the taller towers beyond just the near-term stuff that we focused on, if you look at the recent tender, 80% of the bonds that we addressed were in that 2022 to 2024 time frame. And it's a more effective long-term solution by [ certainly providing ] that. And so I do think that you can use a trailing -- if prices were to continue with the current strip values and use a trailing EBITDA by the end of the year, you could -- and we were able to continue on as we've been doing with debt retirement, would be easily be below a 3x multiple. But certainly, as I discussed, that's [ nothing necessarily that slipped in ] with a strip value that's much higher than the -- what's being used by the rating agencies. And so I do think it's important to us to maintain those ratios, but it's also why I mentioned in my comments it's important for us to really go after the maturities while we have the wind at our back in terms of commodity prices, which is exactly what we're doing and so taking that out and continuing to move forward. And then you can look at the way that we structured the tender and strategy approach on that, we left aside a significant amount of debt that's easily available to us, $2 billion worth, it's either going to be maturable at the end of the year, is callable for the new year, or we have attractive make-whole payments in addition to the floating interest rate notes. And so that gives us access to very cheaply continue to retire debt moving forward over the balance of the year, which will go further and further towards that. And so we've just got work to do. We made a giant step forward with the debt tender in the last quarter. But we see still have a little more work to do. But I do feel like that the work we've done, particularly between the deleveraging and the [ cleaned out ] runway has made us -- [ give us that ] -- a lot more selectivity around hedging strategies moving forward, not to say that we would never do them again, but it certainly [ is going to ] -- certainly, our preference is to create the value for shareholders and give [ them the exposure ] to oil price, which is something that Oxy has to offer right now that many others don't.
Roger Read:
I appreciate that. That's a good answer and it just sort of gets to the reduced risk profile overall. I appreciate that. Maybe just changing directions with my other question a little bit here. The comment about being able to add the 2 rigs in New Mexico, no impact on CapEx. I was just curious, so does -- is that a function or a reflection of improved efficiency and productivity, some of the other things mentioned like the uptime on the pumping jobs. Maybe, Vicki, just a question overall as you're seeing the evolution and continued productivity and efficiency gains out on the field.
Vicki Hollub:
Yes, it was a combination of the efficiencies of the current drilling program and also the utilization of existing facilities to ensure that we could shift our capital to 2 additional rigs without needing any incremental infrastructure expenditures. So this has created a really good opportunity, the fact that our teams are continuing to improve what they're doing.
Jeff Alvarez:
And Roger, on top of what Vicki just said, I think it's important to note, I mean, if you look at our activity profile, I mean, we were ramping down through the year. So it's not that we necessarily are ramping up activity. It's not the case. We're just not ramping down. We still went from 12 rigs down to 10. Today, we're at 11. So we're just kind of flattening out that activity profile while still keeping the capital budget exactly the same. So we're not adding to that, as you pointed out.
And the impact is really more about next year. If you look at that activity set, those -- one rig started up, another will start up soon, that -- it will add approximately 20,000 barrels a day to second quarter next year. So that will help our capital profile going into next year.
Operator:
And the next question will be from Phil Gresh with JPMorgan.
Phil M. Gresh:
Yes, Jeff, just to follow up on what you were talking about with the activity levels, as you look at the second half spending, you annualize that second half spending is around $3.2 billion or so. Any initial thoughts around the 2022 CapEx levels? Would you just be looking to kind of keep it where it is?
Jeff Alvarez:
Yes. It's a good question. And as you know, Phil, it's a little early for us to forecast what 2022 looks like. We usually do that on our fourth quarter call. But to your point about cadence because I think that's relevant and you can kind of read some things into that, when you look at our capital profile, and that's $2.9 billion for the year, as you mentioned, we spent $1.3 billion in the first half. And there's a couple of things that drive that, and you can see it. Like for example, our Chems business, we forecasted about $300 million. They've spent a little over $100 million. So a lot of those activities are back-end-weighted.
On our Permian activity slide, you can see, of our $1.2 billion, we've only spent $500 million of that. And the reason for that is a lot of our Midland Basin wells were front-end-loaded, so much lower working interest with the carry. Now we're getting to some of our higher-working interest wells that go with that. So it's really more about where we're spending capital and how it is more than a cadence of an activity set drastically changing. So I wouldn't read into like a 800 quarter-type number being what we need for next year. So as you look to 2022, I mean, obviously, we would give a lot more color on this going forward, but I think the same narrative we've talked about in previous calls, we continue to see great improvement from an operational standpoint. I think when you look at what our teams have done this year, it's exceeded all of our expectations from an efficiency standpoint. I mean we -- every time we look to put the slides together and we ask for new records that have been set, we're blown away by the new things that come up again and again and again that our teams are doing. And so I don't think that's going to stop. I mean we -- even after we put the slides together for this, we got notice last night, where our Rockies team set a record for the month of July for pumping efficiency of like 630 hours pumped. So you start doing the math on that, and that's 10% better than our previous record and the best Western Hemisphere record for the service provider that did that in Halliburton. So I think we're going to continue to see those improvements that are going to help with capital efficiency going forward. And we do know there's takes against that, that we'll need to build in, that we've talked about. GoM was especially low this year, and we know that probably takes a little more capital to run the type of business we want to run there. We've got other projects going on that could push that up, but those will be offset by some improvement. So more to come on that in the future. But I do think, as we kind of roll that out, we will talk about some of the benefits and then some of the things that may cause us to spend a little more capital in the short term. But we definitely don't want to underestimate all the great things the teams are doing to get more efficient and get better results from the money that they spend. And I think that's what you saw in the first half of this year, is that rolling through and hence, why we could add activity compared to what we thought without increasing the capital budget.
Phil M. Gresh:
That makes sense. My next question, I guess, would be for Vicki. As you think about the EOR business moving forward, where would you say you are in terms of the opportunity to process anthropogenic CO2? And how should we think about the timing of potential updates from the company as we look ahead, say, the next 6 to 12 months around CCUS?
Vicki Hollub:
Yes. As you may remember, we have 2 billion barrels of resources yet to be developed in the Enhanced Oil Recovery business in the Permian and the conventional reservoirs. And so we're really excited about the fact that the Low Carbon business will provide us either a very low cost or net 0 cost CO2, so for those projects.
But we see that the incremental for Enhanced Oil Recovery will probably come closer to the time of the -- getting the first direct air capture facility online. We still have access to organic CO2, and we'll have minor increases as we continue to expand phases within the Permian EOR business. But significant improvement in escalation will come as a part of our low carbon strategy, and that will help to provide the low-decline assets and production that we've been used to having in the past, which will help to offset some of the resources' decline. So it's a key part of our low carbon strategy, and it's -- will be a key contributor and growth engine for us as we go forward beyond the implementation of the first few DACs.
Operator:
And the next question will come from Paul Cheng with Scotiabank.
Paul Cheng:
2 questions, please. First, Vicki, just curious, you guys are definitely one of the very efficient operators in Permian and you have done a good job. And in the past, that you have formed some joint ventures, you essentially are sort of like trying to prove the value forward and by having someone to fund you. But going forward, with your balance sheet starting getting in shape and cash flow getting better, if you look at opportunities that if you talk to some of your peers, like Shell, that to maybe pool the Permian asset together into a giant joint venture and you guys would [ respond by ] not going to extract cash upfront, but just drive really great efficiency gain going forward that leverages your technical expertise here.
Vicki Hollub:
I think that's -- what you said is a great idea. We always look at opportunities to do that. For us, it's not a matter of how you do it. We just look for ways to create value. And any way that we can create value for our shareholders, we're open to doing it. And so we have -- the JV with EcoPetrol in the Midland Basin has been very successful for us. We actually may look at additional JVs in the Delaware Basin to continue to accelerate what we're doing there. And partnering with others where we can join forces and find ways to obtain synergies and to utilize our team to -- for the execution part of it and the evaluation part, I think is a really good idea because I'm so proud of our teams.
As Jeff said, I can't reiterate enough how they've blown us away with the work that they've done that is not just at steady-state today, it's continuing to improve. As Jeff mentioned, the subsurface work goes beyond what I ever expected to see in the shale play. And they're now really pushing the technology envelope on how to model, how to first evaluate, do the data analytics and then model the surface production in the shale reservoirs and to know exactly where to land and how to frac and how to complete. You combine that with the fact that our drilling and completion guys are continuing to set records. And I tell you, 3 years ago, we would not have predicted where we are today. And even last year, we wouldn't have predicted some of the things that are happening this year. That's why when we talk about capital in the future, it's really hard to say what our sustaining capital would be because we didn't expect it to be $2.9 billion this year back when we looked at it 18 months ago. So the progress made in pushing the envelope, being innovative and really developing the leading-edge part of the industry, with respect to this kind of technology, has been amazing. I'm so proud of the team. So I'll say again, I don't know of any other group that I've ever seen, that could do this kind of work and continue to progress it.
Paul Cheng:
I'm just curious, Vicki, have you talked to any of your peers, the other CEOs? I mean because everyone seems to have a big ego and think their team is the best. But I mean, is that something that the industry is ready to do something like that. Because it could be great for you and great for everyone, actually for the whole industry if someone was willing to say, put aside the ego and do something like that. I just don't know whether that is...
Vicki Hollub:
I think there has been some discussion -- yes, I don't want to mention names, but there has been some discussion around that. And I think that, that is something that the industry is opening up to because we as an industry, we want to create value, we want to do business differently than we've done in the past. We have to do that as an industry to attract investors back to the oil and gas industry. It's going to be important that we change our paradigm about how business should be done.
And I have had some conversations with other CEOs about exactly what you've said. And -- And there are some open to it, some are not, but there are some open to that. And I think this sort of thing needs to happen and has to happen for us to maximize the value of the assets that we and others have today.
Jeff Alvarez:
Hey, Paul, and if I can add, I think a lot of people forget, I mean, our Permian position was built on one of those JVs. Basically, we bought the joint venture between what was Amoco, Shell and then BP, and ARCO, which was exactly that. So a lot of the people in the company are very well-versed and the benefits that come from that and continually look for those opportunities. But that is the heart of our Permian operation.
Operator:
And the next question comes from Neal Dingmann with Truist.
Neal Dingmann:
Vicki, one, just sort of following on what you said earlier, I want to make sure I'm clear on this. You mentioned, I think, the [ preferred one ] you said there could be some coordination, you said, between OxyChem and your decarbonization business. I'm just wondering what -- how you're thinking about that or how quickly you could -- something like this could occur.
Vicki Hollub:
Well, OxyChem is already involved in the design of the direct air capture facility. So they will be a key part of the front engine -- front-end engineering and design that's happening today. We're doing the FEED study. So OxyChem participants are a part of that. They're helping to drive that. And we really want to leverage their expertise around the use of caustic potash, and the -- we need to use PVC products in the direct air capture facility that's going to be a key part of some of the components going into it.
So they will, not only in this, but in potential other kinds of processes in the future, with respect to how to use the product. So it's not just in the first direct air capture facility, we believe also they have an R&D mindset, and they have a group that's been very innovative in the past around developing new ways to do things. And Rob could speak more to that history if we had time. Maybe in the future, we will have them do that. But right now, they are a key part of the low carbon strategy and give us a strength that others don't have in this regard.
Neal Dingmann:
Got it. Got it. And then just my follow-up is just more on upstream activity. It appears, despite your kind of indication for stable U.S. activity going forward, it looks like you've slowed in the DJ from first to second half. I'm just wondering is this more of a function of slower permitting or shift of interest. I'm just wondering then as you see '22, would '22 be more like first half with more than 50 [ kils ] or more like second half this year with less than 25 [ kils ].
Jeff Alvarez:
Yes. I think what you're seeing there, when you look at wells online, that's heavily influenced by the amount of ducts we brought on early in the year. So if you look at the activity set relatively flat, we're basically running 2 rigs up there, one in the Powder, one in the DJ and a frac core. That activity set is pretty consistent. But you're right, Neal, in that you point out, we think we brought on 70% of the wells, but that was heavily influenced. We brought on about 100 ducts late last year into the early part of this year. So that's what's heavily influencing the wells online number. But the activity set is pretty constant, and the teams are continuing to build inventory so we can keep that activity set ongoing.
Operator:
And the next question is from Leo Mariani with KeyBanc.
Leo Mariani:
I wanted to just jump in a little bit more on the kind of direct air capture side of things here. So correct me if I'm wrong, but it's my understanding you have like a pilot project coming on in the Permian sometime early next year. I was just hoping to get a little more information about that in terms of like what type of capacity, in terms of tons of CO2 or whatever it might be able to kind of pull out of the air and maybe just a little bit more about what you're kind of hoping to achieve with that pilot.
Vicki Hollub:
We're using the technology that was developed by carbon engineering of which we're an equity owner. And carbon engineering has a pilot [ to fill the ] already in operation in Canada. So the pilot is already working. And so we'll be designing the facility that we build on the basis of that pilot. And that's where OxyChem also comes into play because OxyChem has done this in the past. They've done pilots and then scaled up those pilots and they've done that very successfully. So they have experience doing this.
So the one that we're going to build will be the largest direct share capture facility in the world. Currently, there are a couple of other different technologies that can capture CO2 from the air. Those other technologies, the largest one that's built today, captures about 4,000 tons per year. The facility that we intend to build in the Permian will capture 1 million tons per year. So it's on the basis of taking that pilot, upscaling it. And in the process, what we're also doing is we're working on the FEED study, is there's a separate group kind of working together to optimize the facility. So we're not wasting time to get it in operation and then see how it works. We're actually innovating as we build and as we look at the study for the engineering. As we're doing that, we're innovating, too. So we expect that when we get into operation, it's going to be, we think, certainly a better product than it would have been had we not involved both OxyChem in the innovation process simultaneous to the FEED study.
Leo Mariani:
Okay. That's definitely helpful. And I guess, just can you remind us a little bit on the kind of rough time line to get that first project in place? And then additionally, is there -- I think there was a plan to maybe fund that sort of off-balance sheet or maybe looking in kind of more creative financing. Can you maybe update us on where you are there?
Vicki Hollub:
Well, the FEED study should be done, and we should have final investment decisions in the early part of next year, and we hope to begin construction by the end of 2022 or beginning of 2023. So -- and it should be then online toward the end of 2023 or into 2024. So it will be up and running certainly by 2024. The process around what we're doing to ensure that we get the right funding for it is we have been talking with partners. And so we have multiple opportunities to bring in others who want to be a part of this.
United Airlines has announced that they will be a part of our direct air capture facility. So they will be not only contributing to the capital needed to build it, but they will be taking the fuel from the facility. So they are committing to an offtake of the low carbon fuel that will be provided by the CO2 that's captured from the air. So there are multiple ways to fund it. So one is to making investment in the facility itself. Second is to commit to taking the CO2 credits. Third is to commit to purchasing the oil that's generated from the CO2 that goes into Enhanced Oil Recovery. So we have several ways of financing the facility. And so it's -- we haven't finalized how we'll do that. We're working through that now and talking to a lot of interested parties. We should have more information on how we're going to do that by early next year. But it's -- there's definitely a lot of interest in making this happen. It's for the U.S. and for the world. Direct air capture needs to happen successfully and happen in a big way. And so that's generating the interest in the parties that want to be contributing to it and then get to participate in the results of it.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I just want to thank you all for your questions and for joining our call today.
Operator:
And thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good afternoon, and welcome to the Occidental's First Quarter 2021 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead, sir.
Jeff Alvarez:
Thank you, Chuck. Good afternoon, everyone, and thank you for participating in Occidental's First Quarter 2021 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Rob Peterson, Senior Vice President and Chief Financial Officer.
This morning, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this morning. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good afternoon, everyone. I'd like to start this morning by saying how pleased we are with our first quarter operational and financial performance. The momentum generated by our improved cost structure and capital intensity leadership was a catalyst for our strong results this quarter and is expected to continue to provide a solid foundation for free cash flow generation.
This morning, I will cover our first quarter operational performance and divestiture progress. Rob will cover our financial results and balance sheet improvement as well as our updated guidance, which includes an increase in guidance for midstream and OxyChem's 2021 earnings. Our first quarter results are a perfect example of how our ability to consistently deliver strong operational performance has strengthened our financial position. In the first quarter, we generated $1.6 billion of free cash flow, which is our highest level of quarterly free cash flow in a decade. We also closed almost $500 million of divestitures, repaid $174 million of debt and exited the quarter with approximately $2.3 billion of unrestricted cash. Our plan to stabilize 2021 production at our fourth quarter 2020 exit rate is on track. We delivered first quarter production from continuing operations of over 1.1 million BOE per day, with total company-wide capital spending of only $579 million. We're particularly proud of this achievement, given the operational challenge posed by winter storm Uri. Our domestic oil and gas operating cost of $7.20 per BOE continued to demonstrate the lasting impact of our cost-reduction measures and includes about $83 million of atypical costs related to the winter storm. I want to note that we have fully recovered from the storm with no lasting impact. Even with incurring storm-related costs in the first quarter, our full year domestic operating guidance has only increased by $0.10 per BOE, which represents a significantly smaller increase than the approximate $0.25 per BOE that the $83 million in total OpEx would have otherwise added. This is a significant achievement made possible by our teams continuously seeking efficiencies and finding innovative ways to safely and effectively lower costs. In the first quarter, OxyChem benefited from robust PVC pricing and gradual strengthening in the caustic soda market. OxyChem's integration across multiple chlorine derivatives provides us with the ability to optimize our caustic soda production while opportunistically adjusting our production mix to maximize margins. OxyChem's ability to adjust to rapidly changing market dynamics was invaluable during the downturn last year, and we were able to provide critical products to the medical, pharmaceutical and disinfection markets to respond to COVID. Given the recent improvements in the chlorovinyl and caustic soda markets, we expect OxyChem to extend its track record as a market leader and consistent generator of free cash flow. Additionally, during winter storm Uri, our team was able to safely protect our assets as well as provide essential products to our customers. Our team's effective response limited the storm's impact on facility maintenance cost to an immaterial amount. Midstream and marketing's outperformance compared to guidance in the first quarter was primarily driven by our ability to optimize long-haul gas transportation in the Rockies, along with the timing impact of export sales. Following the increase in activity in the fourth quarter, our oil and gas business continued to push the envelope with new efficiency gains as we seamlessly transitioned into the first quarter. Our Permian teams outperformed expectations in the first quarter by setting new drilling records in New Mexico, the Texas Delaware and the Midland Basin, while also driving down costs. Our first quarter Permian achievements are especially impressive as we have now augmented the efficiencies of our Oxy Drilling Dynamics with remote directional drilling, an exciting innovation that allows the drill bit to be steered from a separate location. Being able to control and optimize our operations remotely and instantaneously apply shared expertise to similar activities has numerous advantages that we expect our operations to benefit from in the future. We also continue to achieve significant efficiency improvements in the Rockies, where in the first quarter, our DJ drilling team reached our lowest average cost per foot in program history. I'd also like to highlight Oman for their best-ever HES performance with no recordables in the first quarter while drilling the longest laterals in Oxy Oman history and achieving record drilling times. After a pause of the issuance of new drilling permits on federal land earlier this year, we have now started to see the process move forward again with the approval of new permits. We currently do not expect the permitting process to have an impact on our activity levels as we still plan to run an average of 11 rigs in the Permian this year and 2 in the Rockies. In late April, I testified before the U.S. Senate Energy and Natural Resources Committee in support of lifting the federal leasing moratorium. As I told the committee, continued onshore oil and gas development means high-paying jobs, community reinvestment and meeting energy and product needs during the transition to a low-carbon economy. We look forward to working with Congress and the administration on ways to create clarity and short- and long-term regulatory certainty. After we announced the sale of our Colombia onshore assets last year, we updated our divestiture plan to sell $2 billion to $3 billion of assets by the middle of this year. Our progress towards this target continues as we closed almost $500 million of sales in the first quarter. Post Colombia, we now have closed approximately $835 million of divestitures and are well on our way to achieving our target. But we will continue to make the best value decisions by weighing the impact of future cash flows in our current environment versus the benefits of meeting a deadline or divestiture target. Looking back over the last year, I'm particularly proud of the accomplishments our teams have achieved and look forward to the opportunities that lie ahead. Not only have we optimized our portfolio, improved our balance sheet and continued to reduce costs, we've also created the pathway to achieve net 0 emissions. As we take our next steps toward achieving our future goals, including further balance sheet improvement, returning additional capital to shareholders and bringing our first commercial scale direct air capture plant online, we will continue to maintain our low-cost, capital efficient, stable production base with a goal of maximizing free cash flow generation through capital discipline and margin preservation. Our cash flow priorities are structured with the aim of positioning our company for future success. While we are encouraged by the improving macro environment and are especially proud of our team's ability to maintain and sustain our production base, we will continue to improve our balance sheet until we reach the point where our financial position will support a more meaningful return on capital and return of capital to our shareholders throughout the commodity cycle. I'll now hand the call over to Rob, who will walk you through our financial results for the first quarter and guidance for the remainder of the year.
Robert Peterson:
Thank you, Vicki. I want to echo Vicki's comments on our strong performance in the first quarter. Our cash flow priorities illustrate the importance we continue to place on capital discipline, free cash flow generation and balance sheet improvement. As we look ahead on the steps necessary to transition from our current to our medium-term cash flow priorities, our focus on balance sheet improvement will continue to influence our financial policies.
Throughout 2020, which was one of the worst years our industry has endured, we focused on deleveraging and have continued to reduce debt in the first quarter of this year. We repaid approximately $9.6 billion of principal since August of 2019, with more to come as we can complete our divestiture program combined with leveraging our ability to rate excess free cash flow and maintain our commitment to capital discipline. On past calls, I've highlighted our preference for a viable path to return to investment-grade credit rating. We're allocating excess cash flow to our medium-term priorities. Our credit ratings are based on several factors, including a certain level of debt, returning to investment-grade in a mid-cycle commodity price environment may include reducing debt to the mid-$20 billion range. We are not there here today, but we believe this goal is achievable, given our potential to generate free cash flow. We repaid $174 million of debt in the first quarter and now have less than $225 million of maturities due the remainder of 2021. If we generate cash from organic free cash flow, close our remaining divestitures, we have some more options available to deploy that cash, improve our balance sheet. We have the option to call the 2022 floating rate notes prior to maturity and may at times allow our cash cushion to build until maturities come due. We have additional options available to address future maturities, which we are currently evaluating. We may also consider retiring $750 million of notional interest rate swaps later this year for the fair value amount, which was approximately $665 million at quarter end. This would improve cash flows by almost $50 million per annum at the current curve. In the first quarter, we announced an adjusted loss of $0.15 per share and a reported loss of $0.36 per share. The difference between our adjusted and reported results is primarily due to a gain on asset sales and positive fair value adjustments, offset by planned lease expiries and a legal contingency related to our 2016 settlement with Ecuador. This quarter, we classified all derivative instruments with mark-to-market adjustments as items affecting the clearability. We expect this change will be helpful to investors comparing underlying business performance between periods and reconciling actual results to our guidance, which had previously excluded the mark-to-market adjustment. We were able to add additional gas hedges in the quarter and have now hedged approximately half of our 2021 domestic natural gas production with a floor of $2.50 per Mcf. We are on track to spend within our full year capital budget of $2.9 billion, having incurred capital expenditures of only $579 million in the first quarter. Our operational success, combined with our focus on sustaining production in a more supportive commodity price environment, enabled us to generate $1.6 billion in free cash flow and exit the quarter with almost $2.3 billion on restricted cash in hand. Our business incurred a negative working capital change in the quarter, which was largely driven by higher accounts receivable and inventory balances due to commodity price recovery. Over half of the working capital change was due to commodity price, which reflects the timing difference between whatever is recognized when the cash is received. We also made several payments that are typical in the first quarter, including property taxes, cash interest payments, employee benefit payments and pension contributions. We see the potential for the working capital change to partially reverse over the remainder of this year as expenses accrued last year were already paid in the first quarter of this year. We are pleased to be able to update our full year guidance for midstream and OxyChem, reflecting strong first quarter performance and improved market conditions. Our revised guidance, combined with our operational achievements, have enabled us to lower our 2021 breakeven to the mid-$30 range on a WTI basis before the preferred dividend. I would like to reiterate that despite the first quarter weather impact to our Permian production of approximately 25,000 BOE per day, as guided on our last call, combined with the production impact associated with divesting $282 million -- $285 million of minerals and a negative PSC impact of over 5,000 BOE per day related to higher oil prices, our full year production guidance of 1.14 million BOEs per day remains intact, as does our full year capital budget of $2.9 billion. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Rob. We are encouraged by the positive reception our 2020 Climate Report received following its release in December as well as the enthusiasm our low carbon strategy continues to generate. We understand that many of our stakeholders have a desire to learn more about our low carbon projects and the returns these projects will generate.
While we are not yet able to share the economics, we will have created partnerships to finance and deploy cutting-edge CCUS technology, which leverages our expertise and our tens of billions of dollars worth of CO2 infrastructure, assets and floor space. We are creating these cross-industry opportunities for others to invest alongside us to maximize the deployment pace and carbon removal impact. We look forward to sharing more information when possible. As part of being a socially and environmentally responsible operator, we consistently make operational improvements in addition to working toward our net 0 goals. In the first quarter, we started a water recycling facility in the Midland Basin and began utilizing recycled water in our South Curtis Ranch development. In partnership with an industry-leading water midstream company, we were able to increase our water recycling efforts and lower cost. Recycling water has been a large focus of ours in New Mexico for several years, and we are pleased to have been able to expand this effort into Texas. Before we begin the Q&A, I want to announce that in April, we became the first U.S. oil and gas company to commit to adopting the World Economic Forum's stakeholder capitalism metrics. This commitment will guide our process to incorporate the forum's metrics most relevant to our business into our environmental, social and governance reporting. We believe this is the appropriate framework to supplement our reporting on ESG progress, enhance transparency and strengthen our engagement with investors and other stakeholders. We'll now open the call for your questions.
Operator:
[Operator Instructions] And the first question will come from Dan Boyd with Mizuho.
Daniel Boyd:
So I want to ask one on direct air capture, but I think, first, just kind of starting with the free cash flow outlook here. Could you give us an update on your dividend breakeven? I think last time you talked about it, it was in the high 30s. Presumably, it's lower given the improvements that you've seen in chemicals and midstream. And maybe also just comment on your free cash flow generation this year at the strip, adjusted for work -- even if you include working capital, I think there's probably a lot of questions on that today, given what the stock is doing.
Robert Peterson:
Sure, Dan, thanks. So our revised guidance, when you combine in operational achievements, did lower our breakeven, I would say, mid-$30 range on a WTI basis before the preferred dividend. Specifically, we give a range because it is influenced by a number of factors that you listed, including the cash flows, including the natural gas prices, realization for our products, divestiture timing and where chemicals and midstream falls in respect of earnings guidance. And obviously, this quarter, we were able to significantly improve our guidance on both the chemicals and midstream business, which has a material impact on that range.
In addition to that, as we take that organic cash flow and we can further improve the breakeven and doing things like I mentioned in my opening comments regarding interest rate swaps, where we retired the $665 million of notional value or $750 million notional value, that was $665 million at the end of the quarter, we're able to eliminate about $50 million of interest costs for the year using the current curve. So there's a lot of things that go into that. In terms of forecasting out cash flow into the year, we don't forecast cash flow forward on that side of it. I think you can see a pretty representative quarter. It's a fairly clean quarter outside of a few things. And I think you can see -- illuminate the working capital and get an idea what kind of cash we would generate at similar prices moving forward.
Daniel Boyd:
Okay. I'm sure you're going to get more on that. So Vicki, I wanted to go back to the direct air capture. I came across a document, it was a presentation that someone on your team made to the California Air Resource Board, I think, back in October that talked about building or at least having 4 facilities online in 2025. And there was also a petition to get credits or, I guess, generate the credits during the construction phase. So can you just talk about that, and what that might be able to do in terms of your ability to finance this in creative ways as you just touched upon?
Vicki Hollub:
Yes. I'll say that we don't have any concerns about being able to finance our first direct air capture facility. The first one where -- once we have both trains built, we'll be able to capture 1 million tons per year of CO2. So they're -- to us, there are no financing concerns. But it's helpful to -- when we can to generate some cash as we're building the facility. That's what that request was about. And if we could get that request, what that enables us to do is accelerate development of the next facility. So what we're trying to do is what I believe the CARB and others want to do, and that is accelerate our ability to be able to have a positive impact on the environment and also to be able to create value for our shareholders.
We're trying to accelerate that where we can. And so we believe that we will be able to provide or obtain some funds either from that or potentially from some modifications that we think is critically important to 45Q because currently 45Q is a tax credit. If that were a direct pay to us for the carbon that we capture, that's another enabler that allows us to accelerate the construction of the technology, get that advanced faster and more built sooner. So there, we're looking at multiple ways to accelerate all that we're doing in the Permian with respect to direct air capture.
Operator:
The next question will come from Neal Dingmann with Truist.
Neal Dingmann:
Vicki, I know you mentioned on the prepared remarks that you were fine with -- as far as permits, and it's not going to influence the 2 rigs in the Rockies. Just wondering, if and when the decisions come out in August, what might, I guess, changes could we see either in the Gulf of Mexico or Rockies, I guess, depending on how -- to the degree of what comes out?
Vicki Hollub:
I think the changes that will come out will not impact current leases. I do believe that we'll be able to continue permitting on current leases. My concern is that there could be a moratorium, a longer-term moratorium on picking up additional leases. That would be bad for our industry. It would be bad for the United States. It would put our country in a position where we would likely have an even tougher time increasing production above where the United States is today.
As you know, we were at one point over 13 million barrels a day of oil production from the U.S. That's a scenario that gave us strength in world politics. It gave us the ability to completely supply our own oil and products domestically. We would not have to import very much at all at a 13 million barrel a day level because I believe our refining capacity is somewhere near 17 million. So we would have some capability to be almost completely independent. With a moratorium on federal leases, that would really drive down our industry's ability to react. Now where we are in that, we've got 9.5 million acres of -- to develop in the U.S. And of that 9.5 million acres, I think only about 1.6 million are federal, and about half of that is offshore. So from a new lease standpoint, there are some companies that are in better positions than others, and we believe we are. But what I'm advocating for is the industry and for the country because the other thing about this is some of this is being touted as a way to reduce emissions for the United States, which would be definitely a bad move because we are very prudent with what we're doing in United States compared to a lot of countries around the world. We've reduced emissions significantly in the U.S. and continue to push technologies to further reduce. API, we're part of API, and a lot of companies within API have committed to a voluntary partnership where we're all working to share technologies and to help each other reduce emissions and to get the best available technology in place to address emissions and climate change. So I think that, for me, the biggest worry is not on existing leases. It's just the moratorium could be extended for a long time on picking -- or anybody picking up any new releases.
Neal Dingmann:
No, very -- I really liked the details. And then just a follow-up. I'm just wondering, will your financial investments, and I guess, sort of 2-parter here, just talk about maybe what type of financial investments you see in your carbon capture. And initially there was other clean energy because you seem to have an advantage, especially out there in the Perm on some others. And really, my main question around that is, will the funds that you spend on that, is that going to influence what you're able to spend on either -- on some of the upstream? Or are they too sort of independent there?
Vicki Hollub:
No. Our low carbon strategy is very connected to our CO2 enhanced oil recovery projects. And as we have mentioned before, we started working on this low carbon strategy because we wanted a more sustainable source for CO2 and a lower-cost CO2 for our enhanced oil recovery.
Where we're positioned today is incredibly exciting because in the Permian Basin, we have such a footprint of not only reservoirs, floor space and resources, we have the processing plants. We have the pipelines and all of that necessary to further accelerate development of additional 2 billion barrels in our conventional reservoirs. And this, we haven't even been able to calculate yet what we could get from CO2-enhanced oil recovery in the shale. But doing that in the Permian, doing that in the DJ Basin and the Powder River, that sets us up for decades to come of generating new reserves and production from existing reservoirs. And so really, it's tied to that. It's tied to being able to create value for our shareholders through the extended production of more reserves than what can typically be produced out of conventional or unconventional resources. For example, in conventional reservoirs, with CO2, you can get up to 70% or better recovery. And whereas with just primary development, normally, you get 20% to 25% at most. So we can get better than 70% with CO2 flooding. In the unconventional where most companies will tell you that you'll get, at most, 10% to 12% recovery of the hydrocarbons from the shale play, but with CO2-enhanced oil recovery, we've tested it, we've run 4 pilots, and we now know that we can potentially get 75% additional recovery or maybe even double it. So we're sitting in a position now where we have a significant amount of future potential development. And we have it in the areas where we operate, the areas where we already have the infrastructure. So as we go forward, our incremental production and recoveries are just going to continue to be at lower and lower cost beyond the point where we were able to get these direct air capture facilities built. But what's also going to help us there, too, and help further lower cost is executing on our NET Power technology, which we're also an equity investor in. NET Power is a process that generates a lower cost of electricity by combusting hydrocarbons with oxygen, and it therefore spits off a pure stream of CO2 that -- and no other emissions. So we can take that CO2 and use it in our reservoirs. So it's essentially a lower-cost, emission-free electrical generation process for us. So we have a lot of ways as we go forward, and this is why we're incredibly excited, a lot of ways to get more oil out of the ground for lower cost. And so as we go forward, our cost structure will continue to decrease, not just from the debt reduction that Rob has talked about, but from the actual development and operations in the field. And in addition to that, we will be able to provide aviation and maritime industries with a net carbon 0 oil. So we're going to be the solution for actually aviation and maritime, and that's why United wanted to join with us on building this first direct air capture facility. So it's exciting for us. Sorry, if I'm talking too long on this. I'll stop here and see if you have anything else to ask, but it's exciting for us. And we're really looking forward to being able to talk more about this. And as I said in my script, we can't yet because we're in the middle of some processes and some discussions and interactions with others. But we hope that in the fall or close to the end of the year, we will be able to share more about it and get you a model that you'll be able to see and understand at that point.
Operator:
The next question will come from Doug Leggate with Bank of America.
Douglas Leggate:
Rob, I hate to speak on the tax breakeven question, but I want to go over the math with you real quick. $1.6 billion of free cash, obviously, before working capital. Annualized is $6.4 billion. $215 million per dollar is $30, and the average WTI price in Q1 was $57.61. So how do you get mid-30s? Even if I add back the press, that still only gets you to low 30s. What am I missing?
Robert Peterson:
So I think that part of what is missing from that is certainly the CapEx and then also where, I would say the chemicals, their performance in Q1, as you can see in the guidance, is sustained throughout the year. The midstream inclusion in Q1 is more of a onetime event associated with winter storm Uri. So I think it's part of annualizing the Q1 numbers. That's what I would modify your analysis by.
Douglas Leggate:
I realize they're not repeatable, but still, delta is about $7. Okay. I'll take it offline. My follow-up is, Vicki, I guess it's a regular question every quarter. The disposal update, a little bit more progress this time, but still a long way to go to get to the $2 billion to $3 billion. Can you give us any color on timing and visibility at this point?
Vicki Hollub:
Yes. I would say that if I include the unsolicited offers that we've gotten, we currently have offers in hand that would get us well above the $2 billion minimum target. However, in this environment, we expect to -- that we would -- we'll meet the $2 billion. But whether or not we go above the $2 billion really depends on how the macro continues to look for us. And then everything that we're getting in and every divestiture that we have the potential to do, we always want to evaluate what it delivers for us versus what the cash flow in the future would generate.
So it's a value proposition for us. And it's also ensuring that -- the other part of the consideration is making sure that we have enough cash flow to meet our maturities, debt maturities and even to go beyond that to, as Rob was saying, to deal with the interest rate swaps and some other minor costs that we have. So it's all about lowering our cost structure, making sure that we maximize our higher-margin cash flow, keep that intact. So we still have gone -- we have not announced any others that we have, but we do have a couple of -- several things actually in process, a couple that have a -- that are higher priorities for us to do. One is Ghana, as we've talked about it before. But because we have several processes running now, we feel comfortable that we'll get to the $2 billion. And then going beyond that, it's really going to be a preference based on -- and a decision based on the valuation.
Operator:
The next question will come from Neil Mehta with Goldman Sachs.
Neil Mehta:
I just wanted to build on the cash flow questions from the quarter. Can you just walk us through again why the cash flow -- working capital number was so large? And then how should we think about the reversal? A lot of this just sounds like timing stuff, and certainly export barrels will eventually hit their final destination. So I would think a lot would come back, but just walk us through that.
Robert Peterson:
Yes. Sure, Neil. Happy to do that for you. So if you look at a typical first quarter, we historically see a somewhat significant draw in the first quarter because of the -- but it was certainly more sizable in the first quarter of this year.
When you go back to 2018, Q1 draw of about $700 million. In 2019, it was about $900 million. And for the opposite reasons for this quarter 2020, it was about $200 million draw because with price going the opposite direction, obviously, in March when the pandemic hit and with the price wars going on. So regardless, the $1.3 billion draw we experienced in the first quarter does and is exceptionally large. The majority of that was driven by the change in commodity prices. It was the timing difference between revenue recognition and cash received. So at the end of 2020, WTI was about $48 a barrel, and it was $61 a barrel at the end of March. And so this price increase of 30% impacts both our AR balances and our inventory significantly, especially when you consider our midstream business and how many barrels are on the water at any given point in time. And even that's a bit exacerbated because we discussed a bit last time that Europe essentially has been shut down a significant cargoes of oil from the Gulf since the third quarter of last year. And as a result, we've had to change our mix or portfolio of export shipments, which are now, for the most part, heavily weighted to -- it's not exclusively related to shipments to Asia, which is longer voyages, more crude on the water longer because of the transit times. And then obviously, compared to other years, we have a pretty modest capital budget. And so we're not creating a significant amount of payables or capital spending. And so when you look at it, it's a combination of the price impacts, coupled with all those first quarter events like the financial interest payments, the payments for property taxes, we made a significant contribution to the APC pension plan during the first quarter, and then -- so we put it all together, we do expect, as you pointed out, as receivables start to come in, that some of that will reverse as the year goes on.
Neil Mehta:
Is it fair to assume Q2 should be a decent working cash -- working capital cash inflow, all else equal then?
Robert Peterson:
Again, it depends largely on what happen to the price going into the second quarter also. But we would expect it to.
Neil Mehta:
And the follow-up is just on the chemicals business. Obviously, margins are really strong, so just get your guys a big picture view of where we are in the chemical cycle and how your business fits into that?
Robert Peterson:
Yes. So absolutely, nothing happy to do than talk about our chemical business, which had an excellent start to the year. When you look at the chemical business, it has both some impacts from winter storm Uri, to some extent, but also because how winter storm Uri impacted the overall business itself.
And so chlor-alkali production struggled significantly in March post storm. If you think about Uri, it had a much wider impact than any individual hurricane we had in the past. And so you still have a lot of inspections, et cetera, going on, restarts going in the month of March. And that has extended into after a very difficult hurricane season last year. And so going into the end of 2020, we already had a pretty tight supply-demand balance in the second half of the year. And that was coupled with a pretty significant amount of demand. As you know, building products are in very high demand right now. So our PVC demand and margins were significant already going into the year. And so if you look at our operating rates as the industry, they're only about 71.5% for the first quarter of '21, whereas last year, they were 89%. And so the combination of the stronger demand, coupled with the production off-line to start the year, has already tightened up an already tight supply-demand balance. And so in the case of PVC, construction investment is very strong. Demand is expected to range strong, with the housing starts outlook, low mortgage rates, a lot of emphasis on remodeling, et cetera, right now that is driving PVC demand. So PVC demand domestically is up almost 5% compared to the same period in 2020, which drives down the amount of PVC that's actually being exported. And exports were actually down about 30% compared to the same period last year. And so with resin tight in the domestic market, we're able to expand margins, just like we would in our commodity under a tight supply-demand balance. And then what we're seeing in the caustic soda business is whereas previously when we guided, we anticipated to start -- we're seeing caustic soda bottom, and we thought we would start to see improvements in the second half of the year, Uri has pulled that forward a bit. And so now we're seeing caustic soda prices improve in the second quarter as we move forward. So we're just getting more of that as the year goes on. And so we're expecting not only continued high margins in the PVC business and resilient demand through the balance of the year as construction continues to pull. I mean, PVC's really different. We're seeing prices of wood and everything else. We'll also see caustic soda benefit from that process at all. And as Vicki mentioned, Oxy's significant amount of other derivatives beyond just PVC that we sell gives the company a lot more variability in the molecules that it can sell, produce additional caustic soda and produce additional value in other parts of the chlorine chain, which is going to expand our ability to increase the value delivered by the business. I just -- it's the reason why we talk about how much value is locked in the chemical business and why when people talk to us about the chemical business a lot of times and why we don't see something different with it is because it's just hard for people to grasp with a small commodity chemical business that can turn out these types of cash flow on this asset base. And it's really -- it's a remarkable business.
Operator:
The next question will come from Jeanine Wai with Barclays.
Jeanine Wai:
My first question probably maybe for Rob. I just want to make sure I heard your comments right in the prepared remarks. So getting down to the mid-$20 billion range on gross debt, that's where you think you need to be to hit IG status at mid-cycle prices. And I think ultimately, that's an important goal for you all. So about $10 billion more to go from there. Can you just remind us what your view of mid-cycle prices are at this point? And how does this jive with your prior target of 3x leverage as the trigger for growth, which I think was also at mid-cycle prices?
Robert Peterson:
Yes. It's around the $50 range. And if you look at the price decks that are being used by a lot of rate agencies, they're in the high 40s right now to look to close to $50. They're not -- so they don't move their price decks with the current environment of being in the mid- to high -- low 60s. And so that makes a significant difference on where that breakeven location is at.
And so is it exactly 20 -- $10 billion? Obviously, there's a lot of different things to factor, as I indicated in my remarks, but it's somewhere in the neighborhood of that. It's somewhere -- other things will go into that. It could mitigate it to be a little higher than that would be possible or even a little lower than that. But obviously, there's a lot of things that go into it, but it's somewhere in that range. So even though that you can probably move forward and get pretty close to that or lower that 3x in your model for the second half of the year. But by the end of the year, based on -- if current oil prices were to continue, it's not that price deck that we're going to be considered for investment-grade.
Jeanine Wai:
Okay. Got it. So in terms of the moving pieces on -- my follow-up is in terms of the moving pieces on the medium-term goals, there's a few, there's sustainable dividend, there's growth capital. Now we kind of have a bogey roughly on gross debt. So how do we think of the trade-off for all of those things? And it will take some time to reduce the debt. We've got the preferred, but you do have like very healthy oil prices as well as asset sales that are coming in. So I'm just kind of wondering, when we're looking at our free cash flow profile and the new debt targets, when we can kind of revisit the growth conversation versus the dividend and paying off other things?
Robert Peterson:
Yes. So Jeanine, I would say that, obviously, as with Vicki's remarks, we're squarely focused on the leverage reduction right now and looking at opportunity to get down to that investment-grade type level. Embodied in that is going to be using the proceeds, both from the free cash flow from the business, using the proceeds from divestitures that take place and combine those 2 things together to reduce the cost -- what we have outstanding. And that can be through a host of different things, as I discussed on remarks, between what we're evaluating near term on the ability to put that cash to work to reduce debt.
That conversation will eventually rotate over into medium-term priorities, focusing on the dividend. But we haven't established a policy on what the dividend might look like. It's going to need to be sustainable, as we've indicated in our priorities. So it could be a combination of something that's fixed and some variable component. We haven't decided on that at this point. But that conversation will come at the -- after we made more progress on our debt reduction.
Vicki Hollub:
I would just add to that. We had this great production profile right now. And with the production profile that we have, the chemicals business supporting it, that what we're really focused on is margin expansion. We have lots of opportunity for that, and that's what we're most excited about. So there will be continuing shareholder value growth through margin expansion.
Operator:
The next question will come from Devin McDermott with Morgan Stanley.
Devin McDermott:
So my first one kind of builds actually on that last point, Vicki, on margin expansion and just the comments you had in the prepared remarks as well on cost reductions. You had said that you were able to identify some cost-reduction opportunities in the quarter that offset some of the winter storm impacts. I was wondering if you could comment just whether that was deferrals or more structural reductions?
And then as part of that, as we think about the margin expansion opportunities going forward, are you still identifying things like upside with contribution from the Anadarko transaction? Or maybe said another way, is there still more room to run on reducing the cost structure here? And what are some of the levers to drive that cost structure down?
Vicki Hollub:
Yes, you're right. There's more opportunities to continue to reduce our cost structure in both capital and OpEx. And one example I'll give is we went back recently and took a look at our drilling performance between 2015 up through what we're doing in 2021. And I can tell you, we rolled out our physics and logistics space, Oxy Drilling Dynamics in our domestic operations in 2015 and then rolled it out internationally in late 2016.
And I think I said before, we haven't seen an area where we've rolled this out that we haven't had about a 20% to 30% reduction in our cost. And the exciting thing in looking at our data today is we've decreased our drilling cost from $200 a foot back in 2015 to $135 a foot in 2021 for our global drilling. That's everything around the world. And so we've individually pointed out the performance improvements in the Permian, but we've not only seen it in the Permian. We've seen it in the DJ, in the Powder River. And now Oman is seeing a lot of good things happening there by using this process, and it's proprietary to us. We developed it. So it's making a difference. We've also started deploying it to the Gulf of Mexico and seeing some good things there that we'll be able to quantify and report on here in the near future. So it's drilling. On the drilling side, it's still -- and I will say before I leave drilling, some people might say that you probably got all that. And right now, we're not improving. From 2019 to 2020, even in the downturn, we improved by 14% what we were doing there. So there's -- the improvement is happening even today. So far this year, we've improved by about 4% only 1 quarter into it. This is as we were picking up rigs. So this is -- what we're doing there is working. But also on the completion side, we're still setting records for how many fracs we can do in a 24-hour period, and so that's improving. The other thing we're seeing is that our Permian team, the -- every one of them actually is continuing to work on the subsurface model. And this has been a point of extreme emphasis for us because of the variation in the shale play. So we started really enhancing our subsurface expertise about 6 or 7 years ago and working hard to get that to where we needed it to be. We have some incredible people in-house that now do that work. And that -- what we've learned in the shale play, we've extended also to looking at conventional and to doing more with seismic. And part of that was driven by the good efforts that the Anadarko staff had accomplished and achieved with some of the 3D seismic. And our team, some of our domestic people started looking at how others were doing things and taking what others are doing and made it better. So every phase of what we're doing, we're trying to do better. And we're seeing still continuing improvement. Oman is using what they call an Oxy jetting system where in existing wells, they can go in and jet with a process that ensures maximum contact with the reservoir through each phase of the jetting process, both in vertical and horizontal wells. That's delivering better recovery from the existing reservoirs, too. And to me, the more you can get out of the reservoir that you've developed, the better off you are and even better when you can go back into existing wells and get more out of those. So I'm quite confident that we will continue on both the OpEx side and the drilling side, completion side and facilities to continue to lower our cost. Our teams are driven to do it and did it even during this pandemic and did it in a big way. So I think in New Mexico, they -- in several of the areas that they worked really hard there, they lowered our breakeven on some of those areas by $10 a barrel. So all of that's incredibly encouraging for what we have going forward, considering the footprint that we have in the areas that we know the best.
Robert Peterson:
And I think I'd just add to that. I mean, it's just -- I think that when you hear about all the exciting things underlying the business that Vicki talks about, and I know externally that the thesis of paying down debt seems incredibly boring for an external thesis. That's part of the reason why we're working so hard and committed to this and getting it behind us, so that, truly, that we can focus on the story of the company being beyond that, and what is going to be.
We do fully expect that when debt goes down, it will translate into equity value, in the total enterprise value, which is good for our shareholders. But we understand that talking about reducing debt doesn't seem to suit wholly exciting. But there's something exciting going on. And at times, we miss the fact of all the great things that we continue to break through what we thought was the best we could do before, we've been successively since the acquisition.
Devin McDermott:
Yes. No, that all definitely makes a lot of sense. And I think the progress forward and line of sight on the debt reduction is definitely a good story as well.
And maybe then shifting focus to some of the other initiatives. I know carbon capture and low carbon, you spoke a few times already, but I have one follow-up there. As we think about the milestones from here to reaching FID on some of these potential projects, including the direct air capture project in the Permian, can you just walk us through what's remaining there? It sounds like policy and financing isn't one of the milestones at this point. But what are we looking for in order to bring that project to fruition?
Vicki Hollub:
Well, we -- the big step was to select our engineering and construction partner. We did. That's Worley. So the FEE process is ongoing now, front-end engineering. So we're working that now. We expect to have FID early next year and start construction by the end of next year.
So I don't see that there would be anything, barring some weird macro thing happen to us, that would change our schedule right now. Our teams are -- what they have done, our major projects team led by Ken Dillon, as -- along with Worley, they've put together a sub team that as the front-end engineering is happening, they're looking for ways to -- already ways to optimize the designs as they're in progress. And so I'm really excited that the first one, I believe, is going to be surprising to some people in terms of its design and how we're going to be able to build it. There are some things already in process around deciding how do you do this on a -- at a faster pace and on a larger scale as we go forward. Some of that work is in place. But I do expect that there's -- that we will begin construction at the end of next year. And I don't see anything in the way of stopping that right now.
Operator:
The next question will come from Leo Mariani with KeyBanc.
Leo Mariani:
Guys, wanted to hear, it looks like your first quarter CapEx did come in quite a bit below expectations. And if you just annualize that number, it looks like it's quite a bit below budget on the year. Just wanted to get a sense, what was driving the lower first quarter CapEx? And just wasn't sure if maybe there were some costs or some expenditures that shifted from 1Q into other quarters? And kind of how you guys are feeling about this $2.9 billion budget?
Vicki Hollub:
Part of it was driven by the ramp-up, and we will have our highest spend capital quarter next quarter. So if you average the 2, it's going to -- that's going to be -- first half spending will be about the same as second half spending, maybe slightly less.
But generally speaking, mover parts, this is a part of the start-up process. And then we had a little bit of a delay on some of our activities as a result of the storms. So some things moved from Q1 into Q2.
Robert Peterson:
Yes. Certainly...
Leo Mariani:
Okay. That's very clear.
Robert Peterson:
Look, what Vicki said when she said next quarter, Q2 would be our highest.
Vicki Hollub:
Yes.
Robert Peterson:
Highest spend. And you can see that with Permian, where we only spent a couple of hundred million in the first quarter of its $1.2 billion. So you can definitely see that.
Leo Mariani:
Okay. That's very clear. And then just a question on the midstream for the year. Obviously, a very strong first quarter. You guys enumerated some of the reasons why in the press release and in the prepared comments. But just looking at your second quarter midstream guide, obviously, you're expecting a loss. When I look at it, it's not a big loss, kind of a small one. If I just add kind of the first quarter benefit, the second quarter loss, you're expecting, let's call it, roughly breakeven.
When I look at your full year midstream guidance, you're still expecting a very large loss, kind of implying significant loss in the second half of '21. Can you kind of just explain a little bit the dynamic there in terms of what you might be expecting later this year?
Robert Peterson:
Sure, Leo. I think if I understand what you're saying, if you look at the first quarter, we beat our guide by $234 million. And then we raised the full year outlook $200 million. So basically, last quarter to this quarter, we're expecting a deterioration of about $34 million on the remaining 3 quarters.
And basically, what's driving that is our view on gas differentials and on our oil export differentials. So if you look at -- and I think we talked about this a bit before, when differentials collapse, that helps our upstream business because realizations get better, but it hurts our midstream business. And so that's the piece you have going on. So most of the benefit of the Q1 rolls through to the year, and then you get a little bit of change for the remaining quarters, primarily driven by that differential collapsing.
Operator:
The next question will come from Raphael DuBois with Societe Generale.
Raphaël DuBois:
It's about the DSC plant that you intend to FID. You mentioned a couple of conf calls ago that you will benefit through OxyChem. Can you maybe share with us how -- what quantity of caustic soda will be required for this very first plant? And looking forward, do you think it could be any issue to access caustic soda to deploy this technology?
Robert Peterson:
Vicki, I can kind of tag team this a little bit. But I would say -- so first of all, the working fluid and the direct air capture unit is caustic potash, not caustic soda. So it's AOH, not NaOH, but we haven't disclosed utilization or what that first fill volume might be or like the first direct air capture unit moving forward.
Vicki Hollub:
Yes. Just to repeat, we're still in the engineering phase of that and still optimizing it. So we probably would not have that information until the end of this year.
Robert Peterson:
Another thing I would mention to you is the other piece is the majority of the infrastructure inside the actual direct air capture unit is also PVC, which obviously, there's a synergy with the OxyChem business on the amount of PVC that goes inside the direct air capture unit.
Operator:
The next question will come from Paul Cheng with Scotiabank.
Paul Cheng:
Looking in Permian, I think one of your competitors talking about they're going to move more into the 3 miles wells. Just curious that in your plan, is that something that you guys were trying to do or that you don't think is suitable for you?
And also, your talk about on the CO2 spotting in the unconventional side. So when we're looking at your prospect inventory, what percentage of your inventory that you think is applicable in here? So that's the first question. The second question is that at some point that you would bring down your debt and once you reach that mid-$20 billion range, what's the objective for your Oman, Algeria and Gulf of Mexico operation? Is that still trying to just maintain the production relatively steady? Or are you trying to grow over there?
Vicki Hollub:
Paul, could you just clarify for me? When you were asking the first question, you mentioned that our competitors are doing something. And then you were asking if we were doing the same. Could you clarify what that was again?
Paul Cheng:
At least one of your competitors is talking about they are drilling the lateral length, that 3 miles or 15,000 feet well. So just curious that given your position, is that something you guys found that is capital-efficient and productive for use to push for the 3 miles? Or that you don't think it's applicable to you?
Vicki Hollub:
I think that it's always important to not put yourself into a box to think that 5,000 feet's the right answer, 10,000 feet's the right answer. I really think that in all cases, you should do an engineering model. You should really look at what is the right design for maximizing recovery from the wells, and what does your acreage position allow? And what are the risk of drilling the 3 miles versus 1 mile or 10,000 feet?
So I think that there are cases where there may be situations and scenarios where longer lateral than 10,000. In fact, we drilled 15,000 ourselves. We did at least 1 or 2 of those. And we've drilled more than 10,000. In other cases, they didn't go all the way to the 15,000, but I think it really depends on the reservoir and all the things that you have to take into consideration against your acreage position, your full fill development plan, how you intend to complete it, how you intend to -- what kind of artificial lift you intend to use. So there are a lot of variables involved. But I wouldn't -- I certainly wouldn't say that we would never consider doing our 15,000-foot wells again. It's always under evaluation, not only in the Permian, but anywhere we drill horizontal wells. So we wouldn't rule it out. And with respect to CO2, CO2, we expect to use in both the conventional and the unconventional. And in the conventional alone, there's 2 billion barrels of additional resources that could be developed with what we expect to be much lower or no cost CO2 in the future. And the enhanced oil recovery of the shale as well. So we're excited about that.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks. Please go ahead, ma'am.
Vicki Hollub:
I just want to thank you all for your participation and your questions today. Thank you, and have a great day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good morning, and welcome to the Occidental’s Fourth Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Andrew. Good morning, everyone, and thank you for participating in Occidental’s fourth quarter 2020 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Rob Peterson, Senior Vice President and Chief Financial Officer.
Vicki Hollub:
Thank you, Jeff, and good morning, everyone. 2020 was a year of extreme volatility for our industry and the world. With the year now behind us, our operations have returned to a normalized activity level in support of stabilizing our full year production at our fourth quarter 2020 rate. We entered 2021 with an improved financial position by taking the necessary steps to protect our asset base and derisk our balance sheet. I’m particularly proud of our teams who leveraged our technical expertise to mitigate production decline while relentlessly lowering costs. The capability of our outstanding employees to consistently deliver remarkable results safely was key to our ability to navigate the challenges of the last year as well as the challenges presented by the winter storm last week. This morning, we’ll provide the details of our full year 2021 plan. This plan maintains our best-in-class capital intensity, even with the modest activity increase we started in the fourth quarter of 2020. We’ll also provide an update on our divestiture and deleveraging progress as well as reviewing our financial results and guidance for the year ahead. Throughout 2020, we focused on maintaining the integrity of our production and asset base as well as lowering overhead and operating costs. Our achievements have positioned us to build on our track record of operational excellence and efficiency gains as we stabilize production in 2021. In the fourth quarter, our businesses continued to outperform and generate momentum for a strong start to this year. We exceeded our production guidance while continuing to deliver lower-than-expected operating costs for the quarter. Our oil and gas operating cost of $6.80 per BOE and domestic operating costs of $6.05 per BOE continued to demonstrate the lasting impact of our cost reduction measures as our domestic operating costs were significantly below our original expectations for the year. Although our activity slowed in the second and third quarters, our teams did not miss a step as we normalized activity in the fourth quarter. Our onshore domestic assets went from running 22 drilling rigs in the first quarter, down to zero in the second quarter and then returning to 11 rigs by the end of the year.
Rob Peterson:
Thank you, Vicki. In the fourth quarter, we announced an adjusted loss of $0.78 per share and a reported loss of $1.41 per share -- per diluted share. The difference between our adjusted and reported results is primarily due to an approximate $850 million loss on sales related to the carrying value of assets divested during the quarter. As Vicki mentioned, our achievements last year contributed to the improved financial position that we have today. And reducing our debt by $2.4 billion and refinancing $7 billion of near-term maturities in 2020, we have significantly derisked our financial profile. This is especially relevant considering we are targeting an additional $2 billion to $3 billion of divestitures post Colombia. In 2020, we repaid or extended almost $6 billion of 2021 maturities to $2.7 billion of 2022 maturities and more than $250 million of 2023 maturity. This leaves us with less than $375 million of remaining 2021 maturity. We repaid over $9 billion of debt over the last 18 months, lowered outstanding principal to approximately $35 billion. While we were able to adequately manage this level of debt in a mid-cycle environment, our focus remains on debt reduction and strengthen the balance sheet to provide stability throughout the cycle.
Vicki Hollub:
…to the recent regulatory actions that the social cost of carbon and methane have become increasingly important for our industry, and we have been active and engaged in being part of the solution. Our low-carbon strategy enables Occidental to play a leading role in limiting methane emissions and removing CO2 from the atmosphere while amplifying our existing businesses and benefiting our shareholders. We expect to improve the profitability of enhanced oil recovery in the Permian and in other regions as we reduce the carbon intensity of our own emissions and products. As we implement our low-carbon strategy, we expect to continue working cohesively with regulators under the new administration while demonstrating our commitment to safety and the environment. We expect our operations on federal land to continue and have more than 350 approved permits in New Mexico and approximately 175 in the Powder River Basin with many more pending. In the Gulf of Mexico, we have not experienced any impact to our operations. Following our last earnings call, we released our 2020 climate report detailing our target of reaching zero emissions from our own operations by 2040, with an ambition to accomplish this by 2035 and an ambition to be net zero, including the use of our products by 2050. As part of our low-carbon strategy, we can provide a solution for partners and other industries as well, which is airlines and utilities. Those industries may not have an alternative means to significantly lower their carbon footprint. As I’ve said before, the opportunity before us is immense, and we are ready for the challenge. Thanks to our incredible employees, we can plan through the lens of being a best-in-class, low-cost operator with an exceptional portfolio of assets in tandem with a goal of reducing our greenhouse gas emissions and executing our strategy to lead in a low-carbon world. We’ll now open the call for your questions.
Operator:
The first question comes from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate:
Thank you. Good afternoon, everybody. I appreciate you taking my questions. Maybe, Vicki, first one is for you. It’s actually on midstream. I think, over the last couple of months, you talked about the possibility of maybe not quite a blend and extend, but some kind of a potential renegotiation of your midstream tariff. I wonder if you can walk us through where that stands today. And I’ve got a follow-up for Rob.
Vicki Hollub:
Yes. I’m going to start this out, and then let Rob add some to this. But, we have looked at alternatives and options. We’ve had conversations with other companies and potential partners, and we have not come across a solution that was acceptable to us from a value standpoint. We’re still continuing to consider options that are being brought to us, but we’re not willing to sacrifice value to do a deal that’s going to negatively impact us in the future. So, we’re still working the option around that. We believe that over time, there could be ways that we could adjust what we have today, but the strategy is just not in place for us to be able to execute on it now.
Rob Peterson:
Yes. I would second that, Vicki. Doug, those contracts roll off in 2025, as we’ve indicated before. And to Vicki’s point, simply finding a way to actually find a super economic value to
Doug Leggate:
Your voice is drifting in from the echo somewhere. So, I don’t know if someone else is tapped in here. But anyway, thank you for that. My follow-up is on the balance sheet and the disposal, I guess, the disposal target, Vicki. I realized that, it looks to me anyway that you’ve pushed out the maturities even further and you continue to talk about lineup side on the disposals for this year. So, I just wonder if you can walk us through your level of confidence in achieving that target and what lies behind that confidence. And while I realize that gets you to the bottom end of your original target, I wonder in a higher oil price environment, if you would still look towards the upper end of that $10 billion to $15 billion range that you laid out a year or so ago? Thanks.
Vicki Hollub:
Well, as I stated in my script, the most important thing for us is the value proposition. And as we consider options, and I can tell you, we have incoming offers for various things. So, if we wanted to simply achieve the $2 billion to $3 billion divestiture target, we could achieve that. But what we’re weighing is the value proposition of the offers that are coming in. And so, we’re going to stay very committed to making sure that we get the best value for whatever we execute on. But, I will say that I have some confidence that we’ll get there because of the fact that we have multiple opportunities. We’re not depending on just one or two possible divestitures. We have in our portfolio, so large, so diverse. We have multiple options to choose from. So, I do believe that we could get to the upper end, but it’s more likely that we would target the lower end. And the timing of the lower end really depends on how quickly we can get the offers to where we need them to be. And again, we have a couple of processes in place right now, and then the -- some things on hold. So, it’s all about value for us and getting to that number. And regardless of oil price, if the value is there, we still want to make the execution to get the divestitures to our $2 billion target, and we believe we can do that.
Operator:
The next question comes from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer:
My first question is with regards to the Low Carbon Ventures and the tie-in to enhance the oil recovery, and it might be a couple parter. First is with regards to enhanced oil recovery. Can you talk about your ability and need, and remind us of that your ability and need to expand investments and production of EOR to meet your net zero goals, and how that factors into your capital budget in 2021? And then, the second part is, on slide 38, focuses very much I think largely from a low-carbon pathway on the upstream side, arguably maybe with a more U.S. onshore bench. And I wondered if you could talk about the opportunities you see in petrochemicals and international to aid your decarbonization goals.
Vicki Hollub:
Well, our enhanced oil recovery projects in the Permian are -- they’re one of the anchors that we have for our Low Carbon Ventures strategy. I would say, it’s not -- the way we’re doing our strategy is not a necessity that we do it in association with our CO2 enhanced oil recovery projects in the Permian, but we believe that’s the best way to do it and the best value proposition for our shareholders. So that’s what we focus on initially. And if I could just point you to -- as I talk about the production cycle, point you to the time line where it shows how this idea was originally brought up, it was our CO2 enhanced oil recovery projects in the Permian. They were the reason that we started this vision. And we started the vision more than 10 years ago. We started the vision well before 2008, where you see on the timeline that the original 45Q tax credit was established. We were a part -- our government group was a part of helping to get 45Q tax credit approved and put in place. And so, back then, what we started looking at was how to maximize the vast resources that we had already in conventional reservoirs that were conducive to CO2 enhanced oil recovery. So, that started the process back then. What we wanted to do is, we wanted to come up with a way to have a lower cost, long term, no decline supply of CO2, and that’s why we came up with the anthropogenic CO2 option. So, you see, in 2010, it’s when our Century -- CO2 Century plant came on, and it’s capturing CO2, delivering it to our Denver units in West Texas. And the Denver unit MRV plan, you can see we got approved in 2015. The Denver unit is one of our largest CO2 projects. We are continuing to add reserves to it even today. It’s massive. And so, that and in addition to the Hobbs MRV plan that we got in 2017, it’s important to note that we were the company that got the first two permits ever issued by the EPA for the sequestration and capture of CO2 in the reservoir. And the MRV is, it means monitoring, reporting and verification. It’s just a plan that ensures that you put -- when you put the CO2 on the ground, you have properly sequestered it. So, we got the first two of those. And that whole process, as we started getting that done, was to try to take advantage of the more than 1 billion barrels of resources that we have left to develop in our current holdings and conventional reservoirs in the Permian. And as you know, the Permian is so vast, we have lots of ability to expand way beyond that. And I know you didn’t ask the rest of this question, but I do want to talk about what started as a vision to improve our cost structure and extend our ability to develop even more resources in the EOR business. It’s now turned into more than that. It’s turned into an ability for us to create a new business, a new business that not only will add additional value for our shareholders over time, but reduces emissions in the world. And it helps -- we’ll be the leaders in helping to test technology, the direct air capture technology, put it in place, make it operational and commercial, and that will be -- will provide an opportunity for others to expand it in the world. And so, moving to what that does beyond our enhanced oil recovery in the Permian, you have to look at some of the things that are a part of what we’re doing. In 2018, another thing that was critical for us was when 45Q was expanded. And when we -- when it was expanded and approved by Congress, it enabled us to make this commercial, the first direct air capture and carbon capture from industry commercial. So, that was an important step. Then we established our Low Carbon Ventures group. We joined the Oil and Gas Climate Initiative. We teamed up with White Energy to capture CO2 from their project. We did some other things around emissions, too. We announced our Goldsmith solar project. And two other things that we did is we invested in NET Power in 2018. NET Power is a technology that will generate electricity at a lower cost in a typical power plant and with the opportunity to capture the CO2 as a part of the process so that we can -- sequester it in our oil reservoirs. And then, at the start of 2019, we invested in Carbon Engineering. The Carbon Engineering has the technology that we will use as a part of our direct air capture process to pull CO2 from the air and to then sequester it in our oil reservoirs. And you can see through there, there are other things that we continue to do over time that’s led us to where we are today. There is -- I won’t go through and read all of those, but there’s a lot that’s been done. And the foundation has been very meticulously planned and staged, and now the foundation is set for us to finish some of the processes that we have and discussions that we have in place today to get to a point where this really becomes a business that has three ways of benefiting us and benefits the world. And so, without going through and reading the rest of that, I’ll go ahead and stop here and let you answer or ask your follow-up.
Brian Singer:
Great. Thanks. My follow-up is actually a similar line as it relates to the two of the technologies that you talked about, the emission-free power and direct air capture. What milestones are you looking for in 2021? Do you have full confidence that these two technologies can get to scale? The FEED study is out for at least half of maybe or the first train or half of where you kind of want to get capacity to for direct air capture, and I wondered if you can just kind of talk about your confidence in the technology, what the milestones are that they’re going to meet whatever cost thresholds you are looking for to get scaled on.
Vicki Hollub:
Well, the first real milestone for us was announced yesterday, and that was the -- or maybe today, and that was the selection of our engineering and construction company, and that’s Worley. Worley is -- they’re an incredible company. They’re -- they have also a passion around carbon capture and around doing the things that they need to do to also become carbon neutral. And I want to point out, in all the partnerships that we’ve developed so far, all the partnerships have been with people who share our vision and our commitment that this is -- has to create value for our shareholders, but it’s also the right thing to do for our operations and for the world. All of these guys share the same thing. United Airlines, who is partnering with us too to build this direct air capture, they share the same vision that we do. They’re committed to become carbon neutral. So, selecting Worley and having them on board with the commitment that they have and to get the FEED study done, that’s going to be a significant milestone for us. And we’re hoping to get that done by 2022. And then, the construction beyond that would take about 18 months to two years. But we’re very confident in the -- that the technology will work because every part of the direct air capture is being used in some way somewhere. And as I think I said on the last earnings call, one of the key things that’s needed in there as a part of it is that potassium hydroxide, which we use a lot of anyway. And so, we’re familiar with what we need to use. We’re familiar with the pieces and parts. And I have confidence that our team in working with Worley to work out the details. We’ll do the same thing that we’ve been able to do in Al Hosn where that was a very complex facility that we built there. And I know I belabored this probably too much, but that was incredibly impressive to build a facility out the middle of the desk at that huge and the sulfur recovery units that are a part of Al Hosn were very, very unique and different. And I don’t think there are any that are that large and anywhere else in the world. But, we working with our partners, ADNOC, were able to make that work right off the bat without any kind of glitch. And not only made it work, but we were able to expand it by 30% with just an incremental $10 million off of the $10 billion that it took to build it. So, our major projects team knows how to build things. Worley is very, very experienced and knowledgeable. I think between the two of us, our team and them, I think we have a great chance to build with this first one. And the first one is always more costly than the next ones to come because we -- you learn a lot from it. But, I believe we’ll learn a lot from building this first one and making it as efficient as we can be and then learning as we get it online, how to make it even more efficient.
Rob Peterson:
Yes. And Brian, I would just add for order of magnitude, that first DAC train, I think you described would capture 1 million tons annually, which is about 5% of what we sequester annually in the EOR business today.
Operator:
The next question comes from Paul Cheng of Scotiabank. Please go ahead.
Paul Cheng:
Two questions. First I think is for Rob. Rob, when I’m looking at your presentation, in terms of the cash flow priority, I’m actually surprised that you put retiring the preferred equity at the bottom, given it’s actually pretty high 2.8%. So, just wondering that why that would not be a higher priority for you to retire such a high coupon debt to some degree, I mean, even though you start deferred equity from our standpoint, it’s no different than the debt. So, maybe that you can elaborate a little bit of the thinking. Secondly, back on your page 15, I think, you gave some data about the Permian, 11 rigs that you’re going to run and the number of wells. And since that’s including the yield out now, so can you break it down, the number of rigs that is related to the unconventional and the number of wells that you’re going to come on stream? And in terms of the trajectory, is that a pretty steady program, variable throughout the year, or that is more heavy bottom, or that is early heavy or that is bottom heavy in terms of the program? Thank you.
Jeff Alvarez:
Paul, this is Jeff. I’ll answer your second one first because I think that one is probably a little more straightforward. So, to answer your question, it does conceptually include Permian EOR, now that we’re guiding those two businesses together. But I can tell you, there aren’t any drilling rigs in Permian EOR plan for this year. And as for trajectory, it’s -- I would say, it’s relatively flat except -- Q1’s got a few -- it’s not a huge difference, but a little bit, fewer wells coming on than you do in Q2, 3 and 4, and that’s just because of the ramp-up trajectory. So, if you look back, we averaged two rigs in the third quarter of ‘20, 5 rigs in the fourth quarter of ‘20, and then now we’re going to average about 12 rigs in Q1. So, when you just think about that trajectory and how the wells online lag that, it makes sense for Q1 to be a little bit lighter, but it’s -- there’s not a huge difference between those. And I’ll let Rob take your first one.
Rob Peterson:
Hey Paul. So, yes, so looking at the slides, you do see that the preferred equity is at the bottom of the slide. Frankly, obviously, we’re focused on the top two pieces of the project list right now. As it relates to the Berkshire, so the way the agreement works is that in order to retire principal, we would have to have at least a $4 per share common distribution over a 12-month period to open up and on a one-for-one basis down on the Berkshire preferred principal. And so certainly, we don’t foresee that type of distribution on the common in the near-term future to open it up. To do anything outside of that would require an agreement with Berkshire in order to make a reduction in the actual principal in the near term. It’s not that we’re not aware of the fact that our ability to source capital is well below the coupon rate today, but we don’t have the ability to force that upon the situation as we sit today.
Operator:
The next question comes from Dan Boyd of Mizuho Securities. Please go ahead.
Dan Boyd:
So, I just want to follow up with a few questions on the mission targets and the carbon capture business. So, just first, can you maybe give us an update or a review of your existing pipeline infrastructure and your ability to capture revenue from just the 45Q tax credits and sequestering carbon? And sort of as we think about, I think you’ve made comments, Vicki, about revenue from your carbon business matching your oil business in a couple of decades from now. How big does -- how big of a role is directly our capture versus using your existing infrastructure?
Vicki Hollub:
Our plan is to use both. As you may know, we have the largest infrastructure of any CO2 enhanced oil recovery in the world in the Permian. We have the pipelines that we need to move the CO2 around to wherever we need it to go and for our own fields. We also have the gas processing plants and the supporting infrastructure for those plants and the pipelines. So, that’s why when we think about how to maximize and continue to develop the EOR reserves, that’s our preference. And as I’ve mentioned in -- when I was going through the time line, the deal that we made with White Energy, they’re an ethanol company. So they have two plants in the Permian Basin, and they’re -- not in the Permian Basin, I’m sorry. They have two plants in Texas. And their plants are not too far from a pipeline that will get that CO2 to our infrastructure in the Permian. So, that’s why we did the deal with them. We’ve also teamed up with a cement plant in Colorado to do the same thing, and that plant there will tie into a pipeline that we have coming from Southern Colorado all the way down to the Permian. So, we’ll be getting CO2 from that plant into the pipeline and to our EOR operations in the Permian. So, it’s that infrastructure that we’re trying to definitely take advantage of. But, the really good thing about the direct air capture and the thing that some people have missed is you can put direct air capture anywhere because you don’t need to put it where the pollution is because the winds balance the concentration of CO2 around the world. So, what we can do with the direct air capture is put it right close to the facility or the reservoir that we want to put it into. That’s why it makes us possible to have direct air capture in the Permian and the DJ, the Powder River, Oman and ultimately, and hopefully in Algeria too. So, we can put it anywhere we want. And this creates opportunities way beyond the Permian. We wanted to prove it up in the Permian because that is the best place for -- almost in the world for enhanced oil recovery. The utilization of the CO2 is best there. And so, we’ve got a good option, good opportunity to maximize our infrastructure. Nobody else has the scale that we do and the size that we do and the opportunity that we have. So, we’re very, very excited about it. And we do believe that over the next 5 to 10 years that the benefits of our low carbon business will equal our chemical business. And then, as you said, ultimately, it’s going to be as profitable and deliver as much as our oil and gas business does.
Dan Boyd:
Okay. That’s very helpful. My follow-up would be, as we look at your goal of being carbon-neutral, can you talk about how much of that reduction comes from direct air capture? And how that ties in with getting companies like United to come in as a partner? And presumably, you’re talking to companies such as Amazon and the like of those that want to lower their carbon footprint. How do you share those carbon credits as you get others to come in and fund the facility cost?
Vicki Hollub:
Yes. I think it’s -- the direct air capture is going to be a huge part of our future to do this. We’re going to continue the other partnerships that we consider the services agreements with others to help them have a place to send their carbon from their facilities, from their plants or industry. But we’re -- I’m most excited about the direct air capture because of where we can put it, and the maritime industry, the airline industry, the tech industry. We’re having conversations with companies from all of those industries. And the thing that we really need to have in place and what we’re working on too is to ensure that we have -- that there is a way and a certified process to track the CO2 molecule from the reservoir to its end use. And as that matures, then we’re going to be able to ensure that as we build these partnerships that the partners we have will be able to take full credit for what their investment should provide them while we do the same. But, it’s all going to be associated with either anthropogenic from industry or direct air capture. And I believe, over time, direct air capture will be a bigger percentage of what we do.
Dan Boyd:
I hate to be greedy on my first conference call with you, but just my last one is just on the cost competitiveness and the cost curve of direct air capture, recognizing it’s still early days. But, I get a lot of pushback on just the cost of -- and the need for very high tax credits to make this economic. But, can you talk about where you think the cost curve can be three to five years from now as you start to build these facilities?
Vicki Hollub:
I think, it’s not going to take very long for us to get this to the point where the tax credits are going to be necessary. It’s just like solar and wind. I can tell you that I hear the most negative comments from those who have a reason to say that solar and wind are profitable today, a direct air capture never will be. Reality is, there’s never been a commercial plant built that -- where you can optimize the process like we’re going to do. We do expect -- as I said earlier, the first plant will be the most expensive, but I don’t believe it’s going to take very many plants for us to build to get it to the point where it is economical and does not need the credits. Initially, we do need the credit, but we’re very close to being in a position to -- for the credits to go away, we believe. Because of the fact that we’re -- if you couple direct air capture with an oil reservoir and you don’t have to build a pipeline to take it very far, you’ve already there optimized the cost of the initial bill and the ability to get it in place and make it operate. And every component in the direct air capture is working somewhere. So, it’s a matter of just putting the components together and getting them to be more efficient. I believe, like any new technology, that the cost definitely will come down. How quickly it will come down I think is going to be driven by the expertise, experience, commitment and drive of those working on it. I can tell you our team in Worley, the reason we selected them is because they clearly have a vision on how to make this work, and they’re committed to it as our team. And so, I have high confidence that over time and not too long a time within the second or third unit, we’re going to have it down to the level where credits are not going to be needed. That’s why we’re very confident that we can expand this to other areas internationally.
Operator:
The next question comes from Jeanine Wai of Barclays. Please go ahead.
Jeanine Wai:
Our first plan -- our first question is on the 2021 plan and kind of what that might mean for an early peak for ‘22. Leverage improvement is pretty significant this year and on the ‘21 completions trajectory in the amount that you have. Does it include a ramp into year-end to get ready for maybe modest corporate or corporate oil growth in 2022, if prices weren’t, or is the plan next year to instead get back to a more meaningful base event or is able just to do both? I think, in Paul’s question, you might have said the Permian TILs were maybe a little bit ratable 2Q. 4Q, but we’re just trying to figure out if there’s any kind of completion CapEx in there to get ready for ‘22.
Jeff Alvarez:
Let me start, Jeanine, and then Rob and Vicki can jump in on the back end. So, obviously, Q1 production is lower than the average for the year. So, there is -- 2, 3, 4 is going to be higher than Q1, partly because of the storm and then partly just because of how we started up our development program late in the year and how that flows through. But, I wouldn’t think of it as some continually increasing trajectory heading into 2022. It doesn’t necessarily look like that. It’s -- every quarter, it will be a little different. But definitely, the back three quarters are higher than the first one. I think, as Vicki said, we’re not driving towards growth for 2022. Our cash flow priorities remain intact. We’re very focused on deleveraging -- generating free cash flow from the business that we can use to continue that pace and move that forward as fast as we can.
Jeanine Wai:
Okay, great. That’s very helpful. For the Permian on sustaining CapEx, how do you anticipate that the area mix will change over the next few years? And can that $1.2 billion in CapEx, can that hold the Permian flat over, say, like a three to five-year time period as the Midland JV carry runs out? I know there’s some gross net issues with some of the TIL guidance this year, but how do you anticipate that $1.2 billion being sustainable?
Jeff Alvarez:
Yes. I mean, you mentioned a couple of points there, and let me hit on them. So, like the Midland Basin JV, it’s very helpful from a capital intensity standpoint. If you look at that, where the 750 carry or through, we’ve still got a little more than 600 left on that. So that will get us through at least another couple of years from a capital efficiency standpoint. If you asked us to guess where we’re going to be, it’s difficult to do that because I wouldn’t have expected would be as low as where we are today three years ago when we were doing this business as the teams continue to get better. And just as an example, our capital intensity in the resources business will be half this year of what it was two years ago. And that’s in a year where we’re ramping up capital, so usually that works the opposite way. So, our teams continue to get better and better. So, while I would hate to guess on what that’s going to be, it wouldn’t surprise me to see it be a little bit higher than a $1.2 billion three or four years from now, but I wouldn’t expect a meaningful change from that number to hold our Permian Basin flat. I think, you’ll get puts and takes. Our decline continues to come down, as you saw the corporate decline going from 25% to 22%. That’s largely driven by our improvements in our unconventional businesses, both in Permian resources going from 37 to 33. Also in the Rockies, that’s coming down to about 33. So, I continue to expect that to improve a bit. And as the teams get better and better, that should also help with that capital intensity going forward. So, I guess, the short answer is, it could go up a little bit, but I wouldn’t expect a huge change over the next few years.
Operator:
The next question comes from Raphaël DuBois of Societe Generale. Please go ahead with your question.
Raphaël DuBois:
The first one is about your hedging for crude oil. I was a bit surprised not to see a new slide on this in your presentation package. Could you please remind us what is your position on hedging? And can you confirm that you didn’t take further position in Q4? Thank you.
Rob Peterson:
Thanks, Raphaël. So, just historically, the Company is not one that’s regularly engaged in hedging, preferring to realize the prices over the cycle, that delivers the most to shareholders. But we did, to your point, with our increased leverage, take on an oil hedge in 2020 that had a collar in 2020, but then it also had a call provision in 2021. So, the only thing remaining from that oil hedge is the call provision in 2021. We have put in place, as the slide deck shows, slide 20, natural gas hedges for 530 million standard cubic per day as of 12/31 with a value between $2.50 and $3.64 on a costless basis, similar to a costless basis we had on the hedge on oil last year. There’s no extending call option though on the gas side. We continue to evaluate additional hedges, particularly on the oil side on a regular basis. We evaluate the cost of doing so versus not doing so. As you can imagine, we do a pure put. It’s still fairly expensive, despite the improvement in price, and a costless type collar hedge is going to require both the cap in the current year in addition to the one we have hanging others today last year’s hedge, extending one into 2022. And so, when we look at the -- we moved the debt maturities down quite a bit in the near term, which is somewhat of a hedge against downturns in the business in the near term. We also know that shareholders appreciate our heavy exposure, leverage to oil price. And so, we have not put something in place as of now, but we’re going to kind of continue to evaluate them and see if they’re going to be constructive in the future.
Raphaël DuBois:
That’s very helpful. Thank you. My second question is, have you quantified, if any, one-off cost for restarting your wells in Texas after the cold wave? And same question about your clinical division. Did you quantify any financial implications of the cold wave for this division?
Vicki Hollub:
We have not yet quantified the cost of either one, the oil and gas restart or the chemicals. We’re still in the -- as I think we put out. We’ve got 90% of our production back on, the chemicals in the oil and gas. The chemicals business is still starting up some of their facilities, but it’s going to take us a little while to get to the end of this to quantify the cost. But, the good thing is we see no permanent damage with anything. And the wells are starting back and looking very good.
Operator:
And the last questioner today will be Phil Gresh with JP Morgan. Please go ahead.
Phil Gresh:
First one here is just on the capital budget for this year. I think, in the past, Jeff, you’ve talked about for every $10 a barrel, there could be potentially 10% inflation risk. And I know that the CapEx guidance uses the $40 WTI price. So, I’m curious, what are you seeing on inflation? And if something were to pick up later in the year, is the priority to maintain the production if it requires raising the CapEx a bit for the inflation, or would you be more inclined to stick hard to the 2 times budget? Thank you.
Jeff Alvarez:
Yes. I mean the point you raised, Phil, is true. I mean we’ve seen that both flexing up and down generally as a pretty good guide for us with that $10 change in commodity price. We see that type of inflation, deflation. What’s a little different this time, and you guys are looking at it really closely, most of the time in the past, changes in oil price correlated with changes in activity. And so, this time, as you know, we’ve seen a pretty strong run-up in commodity price lately. We haven’t seen the correlative activity change that we historically see with that. And so, really, when you kind of layer down where a lot of the inflationary pressures come from, it’s from changes in activity and the need for resources and so on. So, this time, looks a little bit different. We’re not seeing huge inflationary pressures yet. Of course, there’s parts of the market that are driven by housing starts, more than they are, a number of frac crews running and things like that. And so, you get little puts and takes. And what we do know and what we see, we have built into the budget. So, it wasn’t absent of any of that, but it was largely poured on a lower price environment. But, we don’t expect with what we see at least right now, that number to have to change materially for inflationary reasons, a little early in the year. But at least with what we’ve seen right now, we don’t expect that to change.
Phil Gresh:
Okay, got it. And my follow-up was just along the lines of Jeanine’s question. You touched upon the Permian. But, I was curious because some of the other areas, Gulf of Mexico, DJ also, the implication of what sustaining CapEx for those businesses are is quite low relative to history. So, I was just curious if you had any additional color on those other lines of business and what the implication would be for go forward sustaining capital beyond ‘21. I know on past calls, you haven’t really wanted to comment too much beyond 2021 yet, but just anything else you could share there would be interesting. Thank you.
Jeff Alvarez:
Yes. I mean, I’d say the same thing. So, I mean, the GoM is interesting. And so, let me hit on that one first. I mean, you see what its capital is this year. I think it’s --if we looked at that over a long period of time, as you know, its capital tends to be a little more lumpy. It comes in bigger chunks than it does in the Permian or DJ because one well doesn’t just cost a few million dollars. There’s much more that goes with that, and there’s tieback costs and things like that. So, if I was going to characterize the GoM, I mean as you know, our strategy is generally around high-return tiebacks. The teams have been super successful with what they’ve been doing. And I think Vicki hit on the first two wells that they drilled, the Oxy Drilling Dynamics are coming in at cost 35% less than where they were in 2019. So, that’s really going to help when you look at sustaining capital, and we’re having good success delineating new reservoirs around our platforms. So, a lot of good things happening there. But to explicitly answer your question, if you looked over a five-year period, I would expect the sustaining capital to be higher than the number that we have this year. It may be a couple of hundred million in a given year higher than what we have this year. But it’s, again, not a huge difference from where we are this year, but probably a bit higher over a five-year period. When you look at the DJ, it’s probably similar to what we said on the Permian. Again, the performance improvements are making -- I know we talk about this a lot, but I am astonished at all our businesses and what they’re doing. And let’s look at the Rockies. You look at their rig release to rig release time in the fourth quarter, for the two rigs they ran, it was 4.3 days. That was 27% better than what it was in 2019, and that’s in a restart period. So, again, they’re doing really, really well. Same thing on our EOR business, one we don’t talk a lot about, they pulled over $350 million out of their OpEx last year. And that largely is sustainable this year. So, you look at those things and all of those kind of benefits are going to flow through to the sustaining capital as we look a few years out. So, for DJ, I’d give a very similar answer, and it could be a little bit higher than what we’re seeing this year just because of the number of DUCs we brought in this year, but it’s not going to be a huge material change. So, we feel pretty confident with our 2.9%, maybe a little bit higher, if you’re in a much higher commodity price world for a longer period of time, but we don’t see a change in 30%, 40%, that kind of thing. We feel pretty confident about that for the next few years.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I’d just like to say thank you all for your questions and for joining our call. Have a great day.
Operator:
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
Operator:
Good morning and welcome to the Occidental Third Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Neil Backhouse, Director of Investor Relations. Please go ahead.
Neil Backhouse:
Thank you, Grant. Good morning, everyone, and thank you for participating in Occidental’s third quarter 2020 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Ken Dillon, President, International Oil and Gas Operations. This morning, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on slide 2 regarding forward-looking statements that will be made on the call this morning. I’ll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Neil, and good morning, everyone. Our accomplishments in the third quarter including our continued operational excellence, progress in executing divestitures and successful extension of our debt maturities, have notably improved our financial position and provided us with a running room necessary to strengthen our balance sheet. The cost reduction measures we implemented earlier this year, combined with the early completion of our overhead and OpEx synergies, continued to bear fruit, as evidenced by the almost $1.4 billion of free cash flow generated in the third quarter. The synergies and savings we previously detailed are now embedded in our ongoing operations, and we expect to continue benefiting from our enhanced cost structure going forward. We are equipped to quickly adapt any future potential commodity crises while being positioned to leverage the benefits of future uplifts. This morning, I’ll provide updates on our divestiture progress, as well as our plans for increased activity, as we lay the groundwork to stabilize our production. Rob will cover our financial results and current guidance and runway we have created for de-leveraging. Our third quarter free cash flow generation was driven by the strong performance of our businesses and diligent attention to margin preservation, continuing to reflect our focus on operational excellence. Our oil and gas operating costs of $6.04 per BOE and domestic operating costs of $5.38 per BOE demonstrate the lasting impact of our cost reduction measures as our domestic operating costs were significantly below our original expectations for this year. All our businesses delivered strong operational performance in the third quarter. We exceeded our production guidance with lower-than-expected operating and capital costs for the quarter. Production from continuing operations of 1.24 million BOE per day exceeded the midpoint of guidance by 12,000 BOE per day, despite an unusual number of named storms, resulting in higher-than-expected production downtime in the Gulf of Mexico. Excluding the incremental impact from the storm, we would have achieved the high end of our production guidance. Our operational outperformance was primarily driven by strong well performance and continued improvements in operability in Permian Resources. While we ran a lower than normal development activity set in the third quarter, our teams have continued to advance their understanding of the subsurface and are constantly applying newly acquired knowledge to improve our well and completion designs. In the Texas Delaware, our team broke another Oxy record by bringing our Company’s best Permian well online in the Silvertip area, which is a former Anadarko acreage. This is just one of the latest examples of how we are leveraging the combined strengths of our assets and abilities to better position ourselves for a success, as macro conditions improve. In a moment, I’ll touch on our plans to ramp up activity, but want to talk -- take this opportunity to reiterate that we will retain a high degree of flexibility with our capital plans, allowing us to adapt to a changing macro environment. This flexibility combined with our best-in-class operational results and leadership as a low-cost operator will continue to be a competitive advantage. With the closing of the mineral and surface acreage in Wyoming, Colorado and Utah, and reaching an agreement to sell our onshore assets in Colombia, we are on track to exceed the 2-plus-billion-dollar target that we set for 2020. We have now closed or announced almost $8 billion of asset divestitures, net of taxes, since the close of the Anadarko acquisition. At the time of the acquisition, we established a $10 billion to $15 billion asset divestiture target to be completed within 12 to 24 months after close of the acquisition. 15 months later, we are closing in on the lower end of our original target, despite 2020 possibly being the worst market for asset divestitures in the history of our industry. We are targeting an additional $2 billion to $3 billion of assets sales to be announced in 2020, or in the first half of 2021. With the completion of these additional divestitures, we will have met our divestiture targets in less than 24 months from acquisition close. As we’ve said before, we will balance divestiture timing with value realization and will not sacrifice value to close transactions quickly. While we continuously review our portfolio to ensure we have the optimal mix of attributes, including free cash flow generation and capital efficiency and low decline, meeting our original divestiture target of at least $10 billion will mark the completion of asset sales on a large scale. The proceeds from our expected asset sales will continue to be applied towards debt reduction. These additional asset divestitures will be impactful in reducing debt and strengthening our balance sheet. We do recognize we must go further in reducing debt. Once our large scale divestiture program is complete, debt reduction will be primarily driven by the utilization of free cash flow to meet debt maturities. Our Permian Resources team delivered another record-setting quarter. As I’ve mentioned, our Texas Delaware team broken Oxy Permian record in the third quarter, by bringing in Silvertip well on and hit a peak 24-hour rate of over 9,000 BOE per day. In New Mexico, our team set a new completion pumping time record of over 20 hours per day for a three-well pad, while our Midland Basin team set a new Permian-wide record by drilling over 7,500 feet in a single day. The wells in the Silvertip section where the record wells completed were brought online with an average total well cost that achieved our synergy target for Texas Delaware well cost reduction. These savings were achieved despite the wells being drilled before our full cost reductions were implemented. We expect to continue lowering costs, based on our current drilling performance and future savings on hookups. Our other business units are also lowering D&C costs through design optimization, efficiency improvements, and collaboration with our vendors. Operational excellence means more than just consistently delivering strong well results. Safely delivering superior well results along with consistently improving operability while driving down operating costs are the bedrock of our operating philosophy, and then what we define as operational excellence. Our operating philosophy is instilled in our teams, continuously striving for improvement. This is evidenced by the impressive progress our DJ Basin team has made in reducing downtime by 78% from the third quarter of 2019 to the third quarter of 2020. And our Midland Basin team’s commitment to continuously lower operating costs which are now below $5 per BOE. After a modest resumption of activity in the third quarter, we plan to increase activity more meaningfully in the fourth quarter and add two rigs in each of the Texas, Delaware, New Mexico and DJ Basin. We restarted activity with our JV partner, Ecopetrol in the Midland Basin by running two rigs in the third quarter. And in the Gulf of Mexico, we returned the drillships to work in early October. The return to a more normalized activity set will be achieved within our full year 2020 capital budget of $2.4 billion to $2.6 billion. Although we drastically reduced activity earlier this year, our proven development expertise remains intact. As we increase activity, we will maximize operating efficiencies to sustain production and maintain our industry-leading capital intensity. I’ll now hand the call over to Rob, who will walk you through our financial results and current guidance and runway to deleveraging.
Rob Peterson:
Thanks, Vicki. Turning to slide eight. In the third quarter, we announced an adjusted loss of $0.84 and a reported loss of $4.07 per diluted share. Difference between our adjusted and reported results is primarily due to $3.1 billion of after-tax losses, accounting for the fair value declines in the unit price of WES compared to the book value and related to the carrying value of assets divested during the quarter. As mentioned on the last earnings call, charter related acquisitions are now de minimis. And the third quarter cash payment of approximately $115 million is expected to be the last sizable acquisition-related payment. Our operational excellence, repositioned cost structure, capital discipline enabled us to generate $1.4 billion of free cash flow before working capital and exit September with $1.9 billion of unrestricted cash on the balance sheet. This represents our highest level of free cash flow in the quarter since 2011 and reflects Oxy’s cash generating potential, even in a lower commodity price environment. Our overhead costs remained low, and were approximately $400 million in the quarter. We continue to demonstrate our commitment to capital discipline, spending less than $215 million of CapEx in the first quarter, more than 35% below our guidance. As we return to more normalized development activity set, we do not expect capital levels to remain at this level going forward and are pleased with how dynamic and flexible we can be with our capital spending. Our enhanced liquidity position, ability to generate cash and success in leveling our debt maturity profile, have resulted in our improved financial position. As a result, our debt maturity profile has been derisked to the point that we made a decision to pay the preferred dividend in cash on October 15th. Our Board of Directors will continue to review the preferred dividend payment method on a quarterly basis. As we continue to manage and review our liquidity and debt maturity profile, we view the non-cash payment options to preferred dividend at the level we have the option of pulling, but only if necessary on a temporary basis. We want our shareholders to know that our preferred position is to pay preferred dividend in cash, when possible, to preserve the value of our shareholders’ holdings. Further derisk our cash flow profile, we implemented a natural gas hedging program for 2021. We had a costless collar with a floor of $2.50, we hedged 530 million cubic feet per day, representing almost 40% of our domestic gas production. We continue to approach hedging on an opportunistic basis and may consider additional oil and gas hedges for future years. In setting our production guidance for the fourth quarter, we have excluded approximately 33,000 BOEs per day associated with Colombia and will report the assets as a continuing operation until the transaction closes, which we expect later this quarter. We expect fourth quarter production will be sequentially lower than the third quarter due to the combination of scheduled maintenance, additional weather impacts in the Gulf of Mexico as well as declining wedge and base production across many of our assets. Although the decline across our asset base has begun to level off. As we restore development activity, at a minimum, we intend to stabilize our 2021 average production at 2020 fourth quarter levels. This will require increasing capital spending in the fourth quarter as we add rigs and frac through across our highest return assets. Our current production base case assumption is that we’ll sustain 2021 production at our fourth quarter level of capital spending of approximately $2.9 billion, and we continue to evaluate our options considering the recent commodity price volatility. We expect our overhead and operating costs will remain low in the fourth quarter. Domestic operating costs will marginally increase in support of our continued return to normal operating conditions. Our full year 2020 domestic operating costs are still expected to be more than 20% lower than our original 2020 guidance on a BOE basis. The process we began in July to smooth out our debt maturity profile, provides us with the running room necessary to maximize value from our divestiture program, at a pace that reflects current market conditions. To date, we have extended $5 billion maturities due in 2021 to 2023 by 5 to 10 years. We have also resumed our deleveraging efforts, starting with the exchange of a percentage of our WES LP units in return for the retirement of a $260 million note. In early October, we called the August 21 floating rate note and repaid more than $1 billion of the term loan. In summary, including the term loan repayment, we have moved up $5.2 billion of 2021 maturities, $721 million of 2022 maturities and $52 million of 2023 maturities. This leaves us with $1.1 billion remaining 2021 maturities, of which only $350 million will remain non-callable by early next year as we allocate proceeds from asset sales to retiring debt. Accounting for debt repayments subsequent to September 30th, our debt balance is approximately $1.3 billion lower than it was at the end of the third quarter, and we still expect to receive the proceeds from Colombia transaction during the fourth quarter. Our liquidity position remains robust, and our financial position profile continues to improve. We recently entered into a new receivable securitization facility that will provide us with approximately $375 million of additional liquidity. Our $5 billion credit facility remains undrawn with no letter of credit outstanding, and we had approximately $1.9 billion unrestricted cash available on September 30th. I am confident we have taken the steps to succeed in this current environment. And I expect our differentiators, combined with our low-carbon strategy, will drive success that’s sustainably long into the future. I will now turn the call back over to Vicki.
Vicki Hollub:
While much has changed during this pandemic for our Company and our industry, the quality of our asset base and the skills of our teams will support our success as we move into 2021 and beyond. We’ll continue to apply and build our knowledge, continuously improve our track record of operational excellence. While our development activity has slowed down in recent months, our teams have worked diligently to further advance our development technologies and technical operations to ensure we emerge from this challenge, stronger than before. We still have work to do, but the foundation has been laid for us to further improve our balance sheet as we exploit our portfolio of world-class assets. The innovation and ingenuity of our workforce, combined with our differentiated low-carbon strategy will drive our success and sustainability long into the future. Before we turn to the Q&A section of our call, I’d like to announce that we have set a target to reach net-zero emissions associated with our operations before 2040 and an ambition to achieve net-zero emissions associated with the use of our products by 2050. Through the work Oxy Low Carbon Ventures, we expect our leadership in developing innovative technologies and services for carbon capture and sequestration will also help others achieve their net-zero goals, extending our impact well beyond our own emissions footprint. More detailed information will be available in our climate report, which we intend to release by the end of the month. I’ll now open the call for your questions.
Operator:
[Operator Instructions] Our first question will come from Devin McDermott with Morgan Stanley. Please go ahead.
Devin McDermott:
Hey. Good morning. Thanks for taking the question. So, the first one I wanted to ask is on some of the near-term strength -- or strength in the quarter, I should say, in your U.S. onshore production, particularly in Permian Resources. And you called out some of the increased uptime within the portfolio is one of the drivers there. I know, that’s an opportunity that you all talked about really since the closing of the Anadarko transaction. And I guess, the question is, can you talk about where you are more specifically in terms of uptime across the U.S. onshore portfolio, what the difference is between kind of legacy Oxy versus legacy Anadarko, and how we should think about the size of the opportunity here for further improvement in your base production from improved uptime?
Vicki Hollub:
Okay. On our onshore operations, part of the opportunity for us to further increase our uptime was associated with some of the WES infrastructure where we have done some things to improve working with the WES organization. We’ve done some things to improve the operability, one of which was to just start working the electrical system so that when storms do occur as they occur frequently in the Permian Basin, in particular, that the electrical infrastructure was such that we could easily identify issues as they occur and address them and ultimately start to isolate them so that we could, number one, lower the number of wells that -- and volume of production that’s impacted any given issue or scenario, and then to also try to ensure that besides isolation of issues that we could get to the wells and get them up sooner. So, that’s been one thing. It’s just working the facilities to have more reliability around the infrastructure. And secondly, it’s the operability in terms of making sure that our prioritization and reaction to wells down and facilities down was optimized and that we were focusing on the things that really matter the most. Then, the third thing was ensuring that when we’re out getting the wells on that we’re doing it in the most efficient way possible. So, I think that onshore, we made significant progress. And we called out the DJ Basin where they’ve made tremendous progress. And progress has also been made in the legacy Anadarko areas within the Permian too. On the Oxy side, we didn’t have a high downtime. So, the downtime that we’ve worked has been mostly associated with legacy Anadarko, and the teams have done a great job to address it. I don’t know that we have a lot more upside, but every time I say that, I get kind of fooled on that. Our team responds. But, I think, the uptime in the areas that we focused on has increased significantly, and the remaining is in those areas where we’ve had to do some more work. It’s just we’re scheduling out over time to ensure that we can get the hardening, like for the electrical system, done and done in the right way. So, there will be a little bit more. But, I think, we’ve probably seen the bulk of that.
Devin McDermott:
Got it, great. That makes sense. And my second question is on the low-carbon strategy and really building on some of your closing remarks, Vicki. And Oxy has been a leader on this front within the U.S. industry I think for a while now. And it’s good to see that even through this downturn you’ve been able to advance some of the low-carbon goals. And in the slide deck, you have some additional detail on the direct air capture plant that you’re planning in the Permian Basin. And I was wondering if you could talk in a little bit more detail about the return profile for these types of investments, given you’re able to offset some of the CO2 that you need within your enhanced oil recovery business, there’s cost savings there; the amount of capital spend; and then I guess importantly as well the scalability of this over time that you see within your business.
Vicki Hollub:
Thanks for the question, Devin. As you mentioned, we have been a leader in this. We’re very committed to this and excited about it because this for us is a win-win-win. This not only helps us to help the world by reducing CO2 out of the atmosphere, it will help our shareholders too by lowering our cost of enhanced oil recovery in the Permian and in other places as we advance this out. And thirdly, this helps others because we’re going to be able to expand beyond our own operations to give opportunities to those industries that can’t otherwise lower their carbon footprint, they can partner with us to do it. So, what we’ve done is, we formed a subsidiary called 1PointFive. And 1PointFive is a partnership and company formed between Oxy Low Carbon Ventures and Rusheen Capital. And we formed that to ensure that we have the best possible way to deploy large-scale direct air capture using carbon engineering technology, but to do it in a way that provided others the opportunity to invest, and minimizes the actual dollars that we spend because of what we’ve invested thus far. And what we bring to the table for this kind of project is the floor space. We bring the floor space that’s going to be required for the ultimate sequestration of the CO2, and we bring the infrastructure. Nobody has an infrastructure the size of the infrastructure that we have in the Permian. So, it’s extensive, and it’s going to be key to helping us develop this and to do it at a cost that delivers returns for Oxy, Rusheen and the other investors who want to come in and be a part of this. So, we’re very, very excited about it. I’ll point out that we’re beginning this in the Permian, where we’ll build the largest direct air capture facility that’s currently anywhere in the world. But our use of this, we expect to go beyond the Permian. We expect to go from the Permian, the Powder River, DJ and ultimately internationally. So, it’s something that is going to become, we believe, a significant business for Oxy over the next few years. And in 10 to 15 years, we expect that the cash flow and earnings from a business of this type could be similar or more than what we get from the chemicals business. This is something that the world needs without us pushing it, without others doing this, there’s no way that the world could achieve a cap on global warming of 1.5 or 2 degrees. So, it’s something that has to happen, needs to happen. But, unless you can make it a business, unless you can make it profitable, it’s likely not to happen. So, our teams have been very strategic with this and innovative in the way they’ve approached it. And certainly, the passage of 45Q was a big step for us to be able to make this happen in a way that will enable us to over time improve the technology, lower the cost and operating efficiency, so that this becomes ultimately profitable without tax incentives, and so just like solar and wind has done in the past. So, we are excited about it and expect it to take off. And so for us, the 2021 investment in terms of capital from Oxy would be minimal.
Operator:
Our next question comes from Jeanine Wai with Barclays. Please go ahead.
Jeanine Wai:
Hi. Good morning, everyone. This is Jeanine Wai. Thanks for having me on the call. My first question is for Rob on working capital, and my second question is on the Permian. So, Rob, on the working capital front, we noticed that there is a meaningful draw of about $829 million during the quarter. Can you walk us through some of the moving pieces of that? And how you see working capital trending in 4Q?
Rob Peterson:
Sure, Jeanine. Thanks for the question. There is really three big pieces that drove the significant working capital draw in the quarter. Number one is combination of cash interest payments. Majority of our cash interest payments come due the first and the third quarters. So, that was a big piece of it. Another piece was acquisition-related payments that were processed. And then, finally was just the timing of international crude sales in our marketing business. So, as we move forward, we do expect the marketing to improve as we reduce inventories towards the end of the year, certainly be a lower amount of the cash interest payments associated in the fourth quarter. And we won’t have the associated acquisition-related payments that drove a big piece that will happen in Q3. Directionally, we would expect a significant change in direction on working capital in Q4.
Jeanine Wai:
Okay, great. Thank you. That’s very helpful. My follow-up or my second question on the Permian. In the prepared remarks, you mentioned retaining flexibility to respond to the macro environment, and you’re getting a nice head start on activity in the Permian and the DJ heading into year-end. So, can you just comment on how you see the production trajectory throughout 2021? Given the time lag I guess between complete drilling and completions and getting things online, could the Permian flatten out in Q1 and then return to growth as early as Q2? Thank you.
Vicki Hollub:
It’s really hard to tell at this point because our teams are continuing to improve deliverability from the wells. So, a lot of it will depend on when we can actually get the wells on. We’ve got some frac crews already working with us now, so. And we’re setting records actually. So, I’d say currently, it’s going better than expected. But, whether we’ll be flat or up in Q1, I think, is a little too early for us to tell right now as we resume higher activity levels.
Operator:
Our next question will come from Paul Cheng with Scotiabank. Please go ahead.
Paul Cheng:
Thank you. Good morning. Vicki, just curious that you’re talking about the sustaining CapEx, $2.9 billion and actual CapEx is going to be different, based on the market conditions. Can you frame it for us that say if the oil prices is at a much higher level, what is the maximum ceiling of CapEx is going to look like, and that I guess, the minimum that if the oil price is really bad? And whether that the oil price is the only -- or that the strip price is the only factor that you look at, or there are other fact that you are going to take that into consideration? And for Rob, along that line, your capital accrue is over $700 million in this year, the use of cash. How that is going to trend in the fourth quarter and more importantly in 2021. In other words that the net investment, is that going to be much lower than what is your capital budget?
Vicki Hollub:
Yes. Paul, with respect to your question on the capital, we would view $2.9 billion, our sustaining capital to be a maximum capital for 2021, even if prices are higher than we expect. And, we take more into account than just strip oil prices. We look at what’s driving the oil prices and what is the sustainability. For example, while some may have thought a quarter or so ago that prices by the -- by this time would be higher than -- much higher than $40. I heard people talking about that. We never believe that because we were looking very closely at the fundamentals and what’s happening around the world with inventories and demand and things like that. So we’re very cautious about just basing our program on strip prices and/or what some might say they believe about near-term prices. So, we will go into 2021 conservatively. We’ll recommend to the Board a capital that would allow us to balance cash flows coming in. And so, if that ends up resulting in a scenario where we can recommend sustaining capital to the Board, we’ll do that. If not, if we’re going to be in a scenario where we need to be lower than that, then that’s something that we’ll discuss with the Board. But certainly, you can view the $2.9 billion as a cap. And our flexibility that we were talking about was to flex down, if necessary, just as we did in 2020. And you saw the magnitude of flexing -- of how we can flex down. And it’s always easier to decrease activity than to do a last minute increase in activity. And one of the things that’s important to us is to allow the teams to ramp up activity in a safe, efficient way and doing it in a planned way, as we have been, gives our teams the chance to be successful as they have been. They’ve brought rigs on and achieved the same efficiencies that we had when we ramp down. And it’s a credit to them and the way they plan and the way they work and the way they try to ensure that as they’re bringing activity back up, if they first and foremost, do it safely; and secondly, don’t lose efficiency in the process. And that’s almost unheard of in our industry to have a major shutdown and then to start bringing rigs back online and having this kind of efficiency that we’re seeing from our teams now. So, we’re really, really happy with that. But, the reality is that we will spend within our 2.4 to 2.6 budget this year with this increased activity, and then we’ll see if we can reach the cap of $2.9 billion in 2021.
Paul Cheng:
Vicki, can I just follow-up on that? Some of your competitors that because of the natural gas outlook, have decided to shift the CapEx more to the gas well from the oil. Is that something that you will consider, or that you think that is still Permian is your best asset?
Vicki Hollub:
Well, Permian is still our best asset and our other oil assets around the world. We don’t have any intention at this point to do any gas and build investment -- pure gas and build investment in the U.S. And our gas assets that we very much value, Al Hosn and Dolphin in the Middle East are important to us but we wouldn’t do -- there is nothing new investments that we need to make in those at this point. So certainly, our investment dollars will go to oil.
Rob Peterson:
And Paul, just to close out on your capital accrual question. Your intuition I think in your question is spot on, and so, you can actually see in the capital accrual in the third quarter, which is slightly positive. As activity levels pick up, the capital accrual will reverse itself from what it did when we sharply reduced activity coming out of the first quarter. So, your intuition is correct on that.
Operator:
Our next question will come from Doug Leggate with Bank of America. Please go ahead.
Doug Leggate:
Thanks. I guess, -- good morning, Vicki. It’s a follow-up to Paul’s question. So, there’s a lot of feedback or questions coming in about the fact that your capital is $600 million at midpoint in Q4, and you’re still obviously facing a very significant year-over-year decline. And my guess is, it’s a momentum issue, it’s a timing issue of when that capital is being spent. But, can you just give the market some confidence that the $2.9 billion is viable for your level of production, because it does leave you with the most capital-efficient portfolio in the industry by some margin. I just want to get some understanding as to how you -- what your confidence level is in that.
Vicki Hollub:
We have high confidence that we’ll achieve that because we’re looking at the efficiencies that our teams are achieving on the capital efficiency side and also the well deliverability. So, at this point, we do have high confidence that we’ll meet our sustaining production with the $2.9 billion.
Doug Leggate:
So, just for clarification, you’ve got some downtime from the Gulf of Mexico in Q4. So, what is the sustaining oil number that goes along with that?
Vicki Hollub:
So, the production volume that we average for Q4 is going to be the number that we try to sustain into 2021. We’ve taken into account the downtime for maintenance.
Doug Leggate:
Right. So, what is that number?
Vicki Hollub:
Are we guiding to that number?
Rob Peterson:
No.
Vicki Hollub:
No.
Doug Leggate:
Okay. It’s worth a try. Last one for me then. What is the sustaining capital breakeven oil price? It used to be $40 with a $2.8 billion, $2.9 billion dividend. When you net all the synergies and so on together, what do you think your breakeven oil price is today in sustaining capital? And, I’ll leave it there. Thanks.
Vicki Hollub:
Today, we’re well below $40 in our sustaining -- or in our breakeven capital. But, it’s well below $40. When you talk about breakeven capital, if you’re looking at it on a quarterly basis, the well below $40 is because of our current level of CapEx, which is below sustaining. So, going into 2021, we would expect to be in the high-30s in terms of breakeven price before the payment of the preferred.
Operator:
Our next question will come from Brian Singer...
Vicki Hollub:
I would say -- yes. And before Brian, could I hold you up just a second? The other thing I should have told Doug, I know I’ll get a chance to talk to him again on Thursday, is that -- but that also depends on your assumptions for midstream and Oxy can. And those are critical to be considered when we’re talking about what our breakevens will be. Okay. Brian?
Operator:
Our next question will come from Brian Singer with Goldman Sachs. Please go ahead.
Brian Singer:
Thank you, and good morning. I wanted to further follow up on the maintenance capital, the $2.9 billion. Is that a maintenance capital solely to keep 2021 production flat at fourth quarter ‘20 levels, or do you see that as a sustainable maintenance capital? And, do you expect that this will fully replace that reserves, i.e., production replacement would be 100%, or would your reserve life be coming down, even as your production stays flat?
Vicki Hollub:
The sustaining capital, this is a sustaining capital for 2021. We’ll have to look at 2022 when we get there. But, 2022 will be dependent on the efficiencies that we build in 2021 and the deliverability of the program that we’re developing. And so, we’ll look at that more starting in midpoint of 2021. So, we’ll be able to provide you something more on that as we get closer to the 2022 program. What’s happening to it now and what’s both, exciting but creates a little bit of an uncertainty is the more we learn about the Anadarko assets, for example, the Silvertip area is really delivering incredible results for us. And then, the record-setting well there was a record -- it broke Oxy’s record for the Permian Basin. And so, now that is our record. And so, as we continue to improve well deliverability, we’ll just have to look at what it means for our sustaining capital going forward.
Brian Singer:
Great, thanks. And then, my follow-up is about a three-part question with regards to the new carbon ventures. The first is, and I think you compared earlier in the call the potential contribution to what the petrochemical business is delivering now. And I wondered whether that makes the petrochemical business less strategic or a greater candidate for asset sale. You mentioned the direct air capture. Is that the main technology that you were looking to deploy, or are you considering others? And then, what is the extent of further cost reduction, scale and the timing for when you think that a plant like the one that you’re planning here to start investing in 2022 can be returns-enhancing in the absence of government incentives, which makes sense that that’s a key goal?
Vicki Hollub:
Okay. I’ll begin with the comment about OxyChem. No, this would not replace OxyChem. It wouldn’t make OxyChem something that we would want to divest because our OxyChem business really is very synergistic with what we’re trying to do in Oxy low-carbon ventures. And in fact, some of the OxyChem employees are associated with the development of this direct air capture. Because one of the two things about the direct share capture facility is that, one, it uses a lot of PVC, which OxyChem makes or uses the -- provides the products to make. Second thing is that potassium hydroxide is a chemical that’s used in the direct air capture process, and we’re the…
Rob Peterson:
Largest in the country.
Vicki Hollub:
Largest in the country.
Rob Peterson:
Second largest in the world.
Vicki Hollub:
Second largest in the world with respect to potassium hydroxide. So, there is a lot of synergies. And we’ve known this all along, and we want to capitalize on this. We believe there will be even more synergies into the future for OxyChem with us on that. So, that’s important. The second question was -- so there was a second and third question. The third question was with respect to lowering costs even further. The second question was -- oh, the third was the -- are the technologies feasible, how quickly can we get them to the point where they can make money without government subsidies? I’ll say that what I’m seeing from the strength of the teams here is we’re combining Oxy oil and gas people with OxyChem people to work this facility. And remember now, Ken is running our major projects team. That team partnered with ADNOC to build the largest ultra sour gas processing plant in the world in the middle of a desert where we’re at the peak of construction. We had to build a city to house the 40,000 people that had to be on-site to build that plant. We built it to have a capacity of 1 billion -- 1 Bcf a day. And now, they’ve expanded that plant. We firstly put it on without any glitches whatsoever. And it came on at capacity, no glitches, no safety incidents. And we’ve now expanded the capacity by 30% with only about a $10 million investment, and that’s incredibly impressive. So, combined that skill, again, expanding it by 30% and ultra sour largest gas plant in the world, they combine that expertise with our OxyChem expertise who understand this process very, very well and are experts at it, and so, that along with the innovation of carbon engineering. And while we don’t know yet exactly what the first plant will cost, but I guarantee that the first plant will -- from that plant, we will continue to optimize. And I think, the curve the pace of improvement for the direct air capture facility would be faster than what we’ve seen in solar and wind. I expect that. And Ken, do you have something to add?
Ken Dillon:
Yes. One observation is, these are -- the DACs consist of four existing technologies bolted together, where we are world leaders in terms of the chemical. In terms of the scale-up opportunities and the process and densification, we already see massive opportunities in process and densification, simply based on the value engineering work the teams have done so far. So, we are incredibly optimistic that not only can we get the process and densification results required but scale up opportunities also. And one thing to remember is, these can go anywhere. But, that’s one of the beauties of them.
Rob Peterson:
I think that portability of the DAC value is that as you can imagine, the transportation and compression of the CO2 molecule is not inexpensive infrastructure. So, now you can move the infrastructure to the reservoir and collect it from the air. And I think, underlying it, why we believe it will be commercially viable long term is because in order to achieve the 1.5 degree goal, it can’t simply be done through emission reduction. We firmly believe it has to be done through the capture and sequestration or capturing usage of CO2 to make that goal a reality. And I think, what differentiates Oxy’s approach to this is, we also believe that fossil fuel will have a role in the energy portfolio of the world long term. And this is a way to take the carbon footprint of those fossil fuels, keep them part of the portfolio and still generate a low, neutral, even negative carbon fossil fuel molecule.
Vicki Hollub:
Exactly. And Rob, that’s what differentiates us from others because if you look at what the Europeans are doing to lower their carbon intensity, the carbon footprint, they are getting into alternatives, into renewables. And so, we are doing a contrarian approach and that we believe that in using our core competence of CO2 enhanced oil recovery expertise is the best way to go, rather than trying to go learn a new business. And in fact, to Rob’s point about how much this is needed in the world and why it’s going to be a huge industry going forward is that right now, globally, there’s only 40 million metric tons of CO2 per year that’s sequestered or used. And if you look at what the IEA model says about what’s going to be needed, what’s going to be needed is anywhere from 5.6 billion metric tons to 10.4 billion metric tons. So, that’s up to -- that’s going to be more than 250 times what we’re doing today is going to be needed in the future. And so, that’s going to make this business incredibly important. The IEA model is not the only one that’s calling for this level of carbon capture and sequestration for us to be able to cap global warming at 1.5 to 2 degrees. Almost -- in fact, I have not seen a model that didn’t say that significant carbon capture was going to be required. The other thing about this carbon capture too is that when you look at it, it does the same thing. The equipment does the same thing as trees, but it requires -- it’s a much smaller footprint on the planet earth. It’s much smaller. So, while I love trees and we need trees, carbon capture is important. I think Rob’s point is huge in that we can put this anywhere. And what was kind of holding us up previously is that our first -- when we first started thinking about this 10 years ago, we thought we’d have to put carbon capture facilities on industrial sites. And getting the CO2 that’s captured from the industrial site to the Permian was a challenge. And so, we were trying to figure out how do we build the pipeline or how do we do that. And we’re going to do some of that. Some of that will happen because the industries along the Gulf Coast and other hubs where there’s a lot of CO2 emissions, they need to put either direct air capture there or somewhere or capture on their facilities. So, with respect to what other technologies are we thinking about, we had already signed an agreement with Wide Energy to carbon capture on an ethanol plant. So, that’s one thing that we will be doing to help them. But, if you put direct air capture in the Permian, it’s still going to help the emissions in the Gulf Coast because generally, the emissions around the world balance out over time. So, as Rob said, we can put it when we’re done with the initial installations in the Permian, the DJ and the Powder, we can put it in Oman; we can put it in Abu Dhabi; we can put it in Algeria. So we can do it anywhere we are, and/or at partners’ facilities.
Rob Peterson:
Hey Brian, I don’t think we caught the last part of your question. I just want to make sure that we address it and we answer there.
Brian Singer:
I don’t know that. Can you still hear me?
Rob Peterson:
Yes.
Brian Singer:
Okay, great. I think you said when you just mentioned that you were considering some other technologies like ethanol or putting CO2 in ethanol. It was whether you were pursuing other opportunities beyond direct air capture.
Rob Peterson:
Yes. We obviously have the Wide Energy project, which is an ethanol capture in Texas. We’re doing already that we’ll capture from the CO2 emissions from the Wide Energy’s ethanol facilities. And we’ll take those into the Permian for use in EOR.
Operator:
Our next question will come from Phil Gresh with JP Morgan. Please go ahead.
Phil Gresh:
Hi. Yes. Good morning. First question, Vicki, you had mentioned not having additional major asset sales beyond the $2 billion to $3 billion that you’re talking about, looking out to early 2021. I guess, we should presume then that something like chemicals probably would be off the table at this point in time. And just more broadly, once you achieve those asset sales and with the cash flow that you expect to generate in the fourth quarter in 2021, where do you think your leverage will be relative to where you want to ultimately get it to?
Vicki Hollub:
I think, that it’s going to take more than what we’ve said with respect to the divestitures that’s happening now and next year, and more than cash flow from Q4 of 2021 to get us to where we need to be. I do believe prices will be much healthier in 2022. And that’s where we’ll start to balance our cash flow with respect to using it for -- to meet our maturities and to advance maturity -- pay off early maturities where we can. We intend to ensure that our focus is on getting our leverage down. And we’ll have -- we’ll just have to see where prices are at that time, where cash flow is at that time. But, it’s still well into early 2022, at least, our cash flow priorities will remain the same, where first the priority is to maintain our reduction and our base facilities; second is debt reduction. So, the debt reduction will be the second priority for a good while now, I think.
Phil Gresh:
Okay. And then, second question, maybe I’ll just glue two together real quick. One was a clarification on your high-30s WTI breakeven to cover sustaining CapEx. You made a comment about midstream and chemicals. Is it fair to assume that perhaps you’re using fourth quarter run rate for both of those businesses as the assumption there? And then, my second actual question would be just your production mix in the quarter in the Permian or DJ. Was a bit gassier here, lower oil mix in general? So, anything you could provide there as to the driver of that and how you expect that to play out? Thanks.
Vicki Hollub:
I’d expect that the gas oil ratio with the continuing development program would be more stable. This decline -- this increase -- the slight increase in gas is partly due to the fact that we weren’t adding new production. During this time, our wedge production was so much lower than what it would normally be. So, we don’t expect that this is going to be an ongoing issue for us. With respect to the assumption of what OxyChem and Midstream will be, we haven’t guided to that. But, we’re optimistic about how the chemicals business is going to look next year, depending on the COVID situation. And so, we’re not guiding anything right now. But, we do believe that there is going to be progress made. We just don’t know what the timing will be. And, when that happens, we believe the chemicals business is going to do that back pretty well from this.
Operator:
Our next question will come from Roger Read with Wells Fargo. Please go ahead.
Roger Read:
Yes. Hello. Good morning. I guess, I kind of wanted to follow-up on Phil’s question there on thinking about the deleveraging and specifically the chart on page 15. And you’ve done a good job so far of taking the dates out, extending maturities and so forth. And I was just curious, as you look at the ‘22 debt that’s there, should we expect you to start attacking that in ‘21 in terms of some opportunities to extend the maturities there and not simply face a $4 billion wall of debt on top of some of the smaller maturities left in ‘21?
Rob Peterson:
Yes. Roger, good question. And absolutely, I think, we’ll continue to take a very thoughtful approach towards the management of debt between timing of divestitures and proceeds from the balance sheet and attacking those. And so, it certainly wouldn’t be surprising for us to access the market again at some point and start moving those out in a similar way that we did in the third quarter with the $5 billion in raises that we did. We’re trying to be very thoughtful about those access to market when it’s opportunistic for the Company to do so, and then also, looking at -- continuing that runway for us so that we can get the best value for our divestitures. And, we’ve done a good job now to make sure that as we approach the divestitures, we’re not in a position where we have to do under a specific time frame. And we’ll continue to give the Company that leeway, and so that we can get the best value for the divestitures as they occur. So, absolutely, we’ll be not waiting until the last moment to address the ‘22 maturities.
Roger Read:
Okay. I appreciate that. Follow-up question, Gulf of Mexico, since that’s I think your largest federal holdings exposure, I know you’re not in the exploration mode out there, I don’t think hardly anyone is. But I was just curious, as you look at drilling permits in hand, how a potential change in administration, like what’s your visibility for drilling wells in ‘21 and say ‘22 relative to permit availability?
Vicki Hollub:
So, Roger, our belief around what’s happening or what will happen with respect to the regulatory environment is first of all, we don’t think that it’s going to be the highest priority of the administration as they take over and start executing their plans. I believe that there’s going to be other things that are much more urgent for President -- soon-to-be President, Biden, to take on. So, I don’t -- we don’t expect any near-term impact on either Gulf of Mexico permitting or anything onshore. We believe this gives us time to start working with his staff. And, we’ve always stayed engaged with the EPA and the BLM, and we have great relationships with them. And so, what we want to do is we want to be a part of the solution to what they’re going to need to do to meet the needs of their constituency. And that is, I know they’re going to want more regulations; I know they’re going to want a deeper focus on permitting and where the permits are, what’s happening, what is the safety of what’s happening and what’s the impact on the environment. And I think, this is an opportunity for us to be collaborative, like we always are. I think, our Company has developed this as a core competence that because of some of the areas that we’ve operated in around the world, if you look back, I hate to mention country names, so I’ll hold it, but we had previously worked in some very, very challenging countries where collaboration, lots of patience but persistence is really required to help get to the point that’s reasonable for both the Company and wherever we’re operating. And here, we’ll use the same thing. We know that the BLM has a lot of great people. They’ve been very helpful as we’ve gone through our developments, both offshore and onshore U.S. And so, we know the competency of the people there. And that part of it won’t change. We’ll just be aggressive in the way we address it.
Rob Peterson:
And I think, also on that too, what I would add is, in addition to the relationships that we’ve built over in the history of working 100 years as a company with the federal -- different administrations is from a pure holding standpoint, we’re in very good shape, even with a different approach. We’re the largest leaseholder in the Gulf of Mexico. With respect to the onshore, which is -- since we have 1.6 million acres that are on federal land, have onshore have in the Gulf within the APC Delaware stuff and none of that is on federal lands that we purchased; from the biggest onshore exposures in the Powder River Basin, where we have very little activity. And in the case of New Mexico, we have well over 200 permits already in hand and a couple of hundred permits in the works. And so, we have a significant drilling inventory in New Mexico already.
Ken Dillon:
One thing I’d like to add is operational excellence really helps when you’re seeking permits, so you want to have discussions with the government in any country in the world. And this year, our GoM operations teams really carried out exceptional work in the most active storm season on record. We’ve improved safety results while managing COVID and demanning and remanning the platforms multiple times. And again, like Vicki said earlier, domestically, the process engineers have managed to improve uptime in one installation by 12%. And that should lead to about $40 million worth of cash flow next year, having spent almost nothing to do it. So, a really top-class achievement. And the last thing I’d like to mention is the supply chain teams, which have helped to significantly reduce spread rates, using alliances, which we think are win-wins for us and the contractors going forward.
Operator:
This will conclude our question-and-answer session, in the interest of time. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I just want to say thanks to all of you for joining our call today. We appreciate it. And have a great day.
Operator:
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
Executives:
Jeff Alvarez - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Robert Lee Peterson - Occidental Petroleum Corp.
Analysts:
Brian Singer - Goldman Sachs & Co. LLC Doug Leggate - BofA Securities, Inc. Jeanine Wai - Barclays Capital, Inc. Neal Dingmann - Truist Pavel Molchanov - Raymond James & Associates, Inc. Paul Y. Cheng - Scotia Capital (USA), Inc. Philip M. Gresh - JPMorgan Securities LLC Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Leo Mariani - KeyBanc Capital Markets, Inc.
Operator:
Good morning and welcome to the Occidental's Second Quarter 2020 Earnings Conference Call. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez - Occidental Petroleum Corp.:
Thank you, Andrea. Good morning, everyone, and thank you for participating in Occidental Petroleum's second quarter 2020 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Rob Peterson, Senior Vice President and Chief Financial Officer. This morning, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on slide 2 regarding forward-looking statements that will be made on the call this morning. I will now turn the call over to Vicki. Vicki, please go ahead.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Jeff, and good morning, everyone. On our first quarter earnings call, we outlined the cost reduction measures implemented across our company to adapt to the immediate crisis of the pandemic and to the ensuing market volatility. I'm pleased to be able to say that compared to a few months ago, our financial position has notably improved as we are currently free cash flow-positive and expect to generate significant free cash flow over the remainder of this year thanks to the relentless efforts of our teams as well as the moderate recovery in commodity prices. We're determined to build upon this progress, ever mindful that COVID-19 remains a threat to the global economy, the demand for the products we produce and to the health and safety of our employees and their families. We continue to manage our employees as carefully as possible through this health threat. To ensure that we continue to be positioned for success through this cycle, we're permanently embedding many of the implemented cost reductions into our repositioned cost structure. This morning, I will provide updates on our base management optimization progress, the pathway to and capital required to sustain our production and our cash flow priorities. Rob will cover our financial results, current guidance and debt management progress. Turning to our second quarter results. Our business has outperformed expectations despite a slowdown in activity. Production from continuing operations of 1.4 million Boe per day exceeded the midpoint of guidance by 36,000 Boe per day. Our outperformance was primarily driven by our consistent focus on efficiency, increased uptime and base management. Operability remains high across our oil and gas operations and we reduced downtime across the legacy Anadarko acreage faster than originally planned. To maximize the economic benefit from our existing base production, we have increased production by debottlenecking surface infrastructure, mitigating decline and reducing operating costs. We are employing remote surveillance processes, utilizing artificial intelligence to further enhance our predictive maintenance schedules, optimizing artificial lift systems, tying-in additional wells to centralize gas lift and reducing back pressure throughout our gathering systems and facilities. In the Permian, we also continued to lower our water handling expenses by increasing utilization of the WES infrastructure. Domestically, our midstream and marketing business has consistently and reliably delivered our products to market at times when other operators may have curtailed their production. The close integration of our upstream and midstream businesses enabled us to shut-in less production than originally planned. For the second quarter, shut-ins averaged about 29,000 Boe per day of which approximately half were OPEC plus-related. Shut-ins peaked in May at approximately 47,000 Boe per day. We have now brought back online a majority of the domestic production that was shut-in for economic reasons with no detrimental impact to well performance across our portfolio. We accomplished this with total oil and gas operating costs of $5.27 per Boe and domestic operating costs of $4.69 per Boe, significantly exceeding our guidance of $6.25 per Boe. Although a portion of the significant cost reduction relates to deferral of activity, we expect our repositioned cost base to lower full year operating costs on a Boe basis by over 15% compared to our original 2020 guidance as we maintain lower operating costs in the second half of the year even with declining production. Our teams are continuing to deliver exceptional operational results as they deliver better than expected production at lower than expected cost. This quarter, we achieved our combined overhead synergy and cost reduction goal by decreasing our overhead cost to below $400 million. On an annualized basis, we have fully realized $1.5 billion of total overhead savings versus our original synergies target of $900 million. We exceeded our original cost synergy targets and delivered these savings in less than a year after the close of the acquisition, a full year ahead of our original two-year plan. We expect that more than 90% of the additional cost savings will remain permanent in future years. We also reduced our operating cost by $800 million which is an additional $600 million more than our synergy target of $200 million. We expect more than two-thirds of the additional operating cost savings will be permanent even as we return to normalized activity levels. Our capital spending was below $400 million in the quarter, demonstrating our agility and adapting to changing circumstances. We're committed to spending within our 2020 full year capital budget of $2.4 billion to $2.6 billion and intend to moderately increase drilling and completion activities in the third and fourth quarters. We are restarting activity with our JV partner in the Midland basin and will be running two rigs there by the end of the third quarter. We're pleased to be continuing this development with Ecopetrol whose an excellent partner for us. In the DJ Basin, we will begin completing a select group of high-return drilled but uncompleted wells. We will also selectively resume activity across other assets including completing key development sections in Permian Resources within Greater Sand Dunes and Silvertip during the fourth quarter. In the Gulf of Mexico, we're restarting our drillship that was idled earlier in the year. As all of our businesses continue to outperform, they have also stayed true to our core value of safety for all. This includes all of our people in our operations, our employees, our contractors and the public. Recently, our OxyChem and Gulf of Mexico teams demonstrated their safety commitment by setting a new all-time safety record for their operations, joining others in our company who have also accomplished record-setting safety performances. We're proud of them all. In the second quarter, we continued to execute on our divestiture program. In June, we closed the sale of our Greater Natural Buttes asset in Utah. Although the asset accounted for 33,000 Boe per day in the second quarter, the cash flow impact from the sale is immaterial as the asset did not generate cash or income with gas prices below $2.50 per Mcf. While our Rockies production will now be lower this year, the remaining barrels are higher margin. We remain highly confident in closing over $2 billion of divestitures in 2020 and will close divestitures in excess of that amount over time. As we've said before, we will balance divestiture timing with value realization and will not sacrifice value just to close transactions quickly. During this downturn, base management proficiency has become increasingly important and maybe best described as multiple small actions compounding and having a sizable impact on the long-term decline rate. The actions we're taking today may not be highly visible within the quarter but remain an effective way to mitigate our decline rate over time, expand margins and minimize the growth wedge needed in future periods. As an example, we set new uptime records in New Mexico, the DJ Basin and on the Lucius platform by automating more processes where possible. We're applying these learning across all of our portfolio. Earlier this year, we swiftly and decisively maximized liquidity by lowering our capital budget and repositioning our cost base while maintaining the integrity of our assets. Some of the near-term actions we took were activity-based which will cause our production to decline through the rest of the year. However, our asset base retains its full potential which will enable us to stabilize our production through the allocation of capital to our highest return barrels. We expect approximately $2.9 billion of capital will be required to sustain production from our 2020 fourth quarter rate. At this capital spending level, we could keep production flat at approximately $40 WTI. This is a significant reduction from the sustaining capital of $3.9 billion we previously communicated for 2021 and is a testament to the progress we've made in stripping cost out of the business. The optimized capital activity in the second half of 2020 will help serve as a bridge to build momentum into 2021 as we thoughtfully ramp up activity. Our teams continue to optimize development plans to safely extract more value for less cost. Our approach to stabilizing production will involve exercising capital discipline by spending within cash flow and selectively allocating capital. We do not intend to grow production until we have significantly reduced debt and we view the long-term price of WTI to be sustainable at higher levels than where the current curve indicates. In any eventual growth scenario, we expect that annual production growth will be less than the 5% per year that we've previously stated. While our desire is to at least stabilize production next year, our 2021 capital budget will depend on what market conditions are indicating when we rollout the budget in the fourth quarter. We'll communicate our full 2021 capital budget in our future earnings calls. On our cash flow priorities slide, we have updated the framework for how we will prioritize capital allocation and excess cash flow going forward. As we move towards 2021, our top priorities are to stabilize and maintain our low-cost base production and to further de-lever. We intend to return to a position where we have the ability to deliver solid returns and again distribute more capital to shareholders with the support of a strengthened balance sheet. I'll now hand the call over to Rob who will walk you through our financial results, revised guidance and debt management progress.
Robert Lee Peterson - Occidental Petroleum Corp.:
Thanks, Vicki. Turning to slide 9. In the second quarter, we announced an adjusted loss of $1.76 per diluted share and a reported loss of $9.12 per diluted share. The difference between adjusted and reported results is primarily due to $6.6 billion of after-tax impairments related to the decline in oil prices which is at the lower end of the $6 billion to $9 billion estimate we communicated in June. Additionally, we have incurred approximately $100 million of debt charges including $149 million in acquisition-related transaction costs which was partially offset by a gain on pension and curtailments. Our commitment to capital discipline and liquidity preservation was evident as we exited June with approximately the same cash balance we reported for April 30. We reduced our capital spending to $375 million, more than 20% below our second quarter guidance. Our progress in reducing costs was equally impressive as we reduced overhead below $400 million in the second quarter and decreased our oil and gas OpEx by more than 40% versus the prior quarter. Contributions and new ideas our teams identified to reduce cost and quickly adapt to a low commodity price environment is just one example of how dynamic and nimble our company is. Including the amount expensed in 2019, we have now expensed approximately $1.9 billion in total acquisition-related costs. We do not anticipate incurring additional material acquisition-related expenses this year. In the second quarter, we had cash outlays of approximately $125 million related to these expenses, bringing the total including the amount paid in 2019 to $1.8 billion. For the remainder of 2020, we expect to incur acquisition-related cash outflows of approximately $150 million. We restored our guidance and cash flow sensitivities for the second half of 2020, but we continue to have a cautious outlook as the macroeconomic environment remains uncertain. In approaching our production guidance for the third quarter and full year 2020, we have taken into account a number of factors including a loss of 33,000 Boe per day associated with the divested GNB asset. Third quarter production will also be lower due to a combination of scheduled maintenance and seasonal contingencies for weather in the Gulf of Mexico, the impact of higher prices on production-sharing contracts, selective ethane rejection in DJ Basin and declining wedge and base production across all our assets. We expect third and fourth quarter production shut-ins to average approximately 20,000 Boe per day due almost entirely to OPEC plus production restrictions. As a testament to the strength of our base management cost reduction programs, our full year 2020 production guidance remains in line with the guidance midpoint we've communicated in our March 25 press release while our capital budget is expected to be $300 million less adjusting for Algeria and GNB. Our full year 2020 production guidance also reflects the outperformance from our business in the second quarter as higher than expected production essentially absorbed the OPEC plus restriction. A breakdown of our third and fourth quarter production guidance is available in the appendix of the earnings slides. We expect our production change from 2Q to our 3Q guidance will be greater than our base decline. This is due to the timing of activity and bringing wells online which impacts the size of the wedge especially over a period where activity changed significantly. We are pleased that our annual base decline rate of only 25% remains intact despite significant reduction in our operating cost. As a higher decline of our wedge production from newer wells naturally tapers off, the overall corporate decline will level out as demonstrated by the difference between our third and fourth quarter production guidance. The $2 billion in notes issuance and tender offer we completed in July are a key part of our effort to address near-term debt maturities. Leveling our debt maturity profile will allow us to continue our divestiture program at a pace that reflects current market conditions without sacrificing value. We continue to focus on generating as much value and cash as possible from divestitures, and our expectation of raising over $2 billion in 2020 remains in place. As we work towards closing these additional divestitures, we continue to take significant steps to preserve liquidity; for example, the payment of preferred dividend and common shares in lieu of cash in the second quarter. As a result of our cash preservation efforts, our liquidity position remains robust. Today, our $5 billion credit facility remains undrawn with no letters of credit outstanding and we have approximately $750 million of unrestricted cash available as of July 31. I will now turn the call back over to Vicki.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Rob. Looking forward, I'm confident in Oxy's continued success. We have one of the highest-quality asset bases of any company in our industry with a competitive advantage in the areas we operate due to our scale and unique operating and development expertise. Applying this expertise to our diverse portfolio provided us the optionality to manage through this crisis. We will continue to optimize our costs and capital allocation across our portfolio with high-return short-cycle opportunities. This will enable us to maneuver through the near-term volatility, facilitate profitable free cash flow growth in a normalized commodity price environment, enhance our ability to de-lever and generate substantial free cash flow in a higher-priced environment. We have taken these steps to succeed during this transition period and we expect our differentiators combined with our low carbon strategy to drive our success and sustainability long into the future. We'll now open the call for your questions.
Operator:
We will now begin the question-and-answer session. And our first question comes from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you and good morning.
Vicki A. Hollub - Occidental Petroleum Corp.:
Good morning.
Brian Singer - Goldman Sachs & Co. LLC:
Appreciate the greater color with regards to the maintenance scenario and you talked about not wanting to really invest for growth until the balance sheet is sufficiently de-levered. Can you add some greater color on what commodity environment and leverage would you deploy the maintenance scenario that you talked about here versus something more or something less?
Vicki A. Hollub - Occidental Petroleum Corp.:
Well, what we're looking at as we go forward is our debt reduction combined with our cash flow from operations. So the driver for us is to first of all ensure that we have the liquidity to go forward so we have the ability to meet our maturities. And then the second is to ensure that as we're processing through our asset sales that we're preserving the cash flow needed to enable us to do the things that we need to do, sustaining capital. And ultimately, when we get to the point where we see that that balance has turned for us where we have a lower cost structure that enables us still to meet our maturities with cash flow from operations, that's the point at which we would start to consider the next level down on the cash flow priorities which is growth after the dividend. So it'll be first the maintenance, second debt reduction, then sustainable dividend and then growth.
Brian Singer - Goldman Sachs & Co. LLC:
And is it fair to say that at current commodity prices you would want to be in that maintenance mode or would you be in sub-maintenance mode?
Vicki A. Hollub - Occidental Petroleum Corp.:
It really depends. We intend to, if we're within cash flow, to sustain our production, so that's the intent. And in 2021, with such a low sustainability capital required, we do expect to be in that mode at least.
Brian Singer - Goldman Sachs & Co. LLC:
Great. And then my follow-up is with regards to the asset sale targets. The Greater Natural Butte sale brought in $69 million. Your goal is $2 billion-plus. Can you just give us any color on how that's progressing? And then if there's any broad range when you talk about the $2 billion-plus of the EBITDA, how much EBITDA you would expect will be given up to achieve that target?
Vicki A. Hollub - Occidental Petroleum Corp.:
Well, first of all, I'll say we're on track with our asset divestitures. It's going well. We reported in the last earnings call that we had just completed round one of the land grant process, and in that process we got 13 bidders. We had commented that we expected with the process that we would be able to close on the land grant acquisition in the third quarter or fourth quarter, it being late third or early fourth quarter. We're still on schedule for that. And the update on the progress there is that after the first round, we went through and evaluated those bids. Then we finished the second round in the second week of July. Now we have selected a bidder to proceed with and we're working on due diligence and the purchase and sale agreement with the bidder that we selected. So the longer timeline for this divestiture is due to the meticulous work that really goes into a deal with so many different parts and of such size. But we're on progress there and I do expect that we'll get the $2 billion-plus divested by the end of this year. We also expect another $2 billion to $3 billion of divestitures in the first half of next year. And some of the things that's driving the timing there is that while we've had some companies that have tried to be opportunistic with us in terms of our divestitures and tried to get our assets at a discount, we've discarded those and moved to the more serious bidders. And some of the more serious bidders are working diligently on our divestitures, but the problem they're having is putting their model in place and getting more comfortable with what the pricing environment will look like. Fortunately, these more serious companies that we're dealing with now have a much stronger and longer-term view of oil prices. So we're confident about the additional asset sales and expect to more than achieve the lower end of our target of $10 billion.
Jeff Alvarez - Occidental Petroleum Corp.:
Hey, Brian. This is Jeff. And just for clarity on the GNB sale, we received $87 million in consideration, $67 million upfront, with a $20 million contingent payment based on oil prices just so there's no confusion there.
Operator:
Our next question comes from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate - BofA Securities, Inc.:
Thank you. Good morning, everyone. And Vicki, thanks for the walkthrough on a lot of the progress you've made so far. I guess my first question might be for Rob. And Rob, I'd like to just do a little math with you if that's okay so I understand what you're trying to tell us this morning. So Vicki basically said that you think you can sustain the maintenance capital outlook at $40 oil, but then she also said that you expect to be able to deal with debt maturities from operating cash flow, so I want to take those two data points and look at slide 11. So in 2021, it looks like you've got about $4.5 billion now outstanding; you've got $2.9 billion of sustaining capital, $800 million of preference shares – dividend, assuming that's paid in cash – and then you're seeing a little over $2 billion of disposals. That would get me to a little over $6 billion of operating cash flow at $40 oil. Am I in the ballpark?
Robert Lee Peterson - Occidental Petroleum Corp.:
Well, Doug, we've updated our guidance as you know for the second half of this year and told you to go along with what you've outlined. And so in the case of 2021, we did provide the sustaining capital guidance of the $2.9 billion that Vicki reviewed, holding the production flat in the fourth quarter. And I think what's noteworthy on that is that the last time we provided sustaining guidance as a stand-alone company prior to the acquisition, it was $2.5 billion to hold 715,000 to 730,000 barrels a day of production. That means our 2021 sustaining results in roughly 60% higher production for 2021 with only 15% more CapEx. And so with that said, breakevens going into 2021 are dependent upon more than just oil price including the performance of our midstream and chemical business; whether or not we do, as you said, pay the preferred dividend in cash versus common. And so rolling that all together as part of that fulsome plan for 2021 that Vicki mentioned that we would put together as the year goes along, and in the later part of the year have that reviewed with our board of directors and ultimately make that available to the market on what we think our breakeven number is for 2021.
Doug Leggate - BofA Securities, Inc.:
Okay. I understand. Forgive me, there's a part B to my first question but just to be clear. The last time you gave sustaining capital, Rob, was actually $3.9 billion for the combined company. And at that point, with a $2.8 billion dividend and an $800 million pref, the breakeven suggested to the market in the middle of last year was $40 oil. And now obviously production declined a bit since then, but I'm just trying to basically get to the equivalent number that you gave us a year ago which was $40 breakeven with those dividend commitments and so on. So again, I'll try just one more time. So ballpark, at $40 oil what do you think your operating cash flow is?
Robert Lee Peterson - Occidental Petroleum Corp.:
We're not going to guide that today yet, Doug, until we have a whole plan for 2021. But certainly as Vicki indicated, the company's focus is to maintain a breakeven value that's going to be at or below that $40 level.
Operator:
Our next question comes from Jeanine Wai of Barclays. Please go ahead.
Jeanine Wai - Barclays Capital, Inc.:
Hi. Good morning, everyone. Thanks for taking my questions. So I would say just following-up on some of the prior questions on the 2021 maintenance CapEx, can you provide just a little more color on what assumptions are factored into that? I know you mentioned whether you pay the pref in cash versus stock for example. But also in the past, you've mentioned that there's startup costs in year one of returning to maintenance mode and you've realized improvements in your US-based management. So we're just curious on what's embedded in your $2.9 billion estimate on both costs and base declines.
Jeff Alvarez - Occidental Petroleum Corp.:
Sure, Jeanine. This is Jeff. I'll take the first stab at that and Vicki and Rob can jump in if I miss anything. So I think, well, we're not prepared to go through business-by-business with the sustaining capital for each one of those, but we will give more color as we rollout the plan for next year. I can add a little bit of color to that. I think one of the important things to understand is while we call that to sustain production, there is between $400 million and $500 million of capital associated with our midstream and chems business. So first thing is you got to strip that out when you think about sustaining capital just to hold production flat. And the thing I'd say is what we've seen is pretty much across all of the businesses, we've seen improvements in sustaining capital primarily driven by driving cost out of the business, the developments get better and better. I mean, I look at – even though we've kind of taken this pause in activity, I've watched our development teams continue to learn from everything they've done and figure out optimal ways where I think all of them are confident we'll have better capital intensity when we restart the program than when we ended the program. Now previously, we have talked about some startup costs. We do think there will be some startup costs. When you bring rigs on, the learning curve will have to take effect. They won't start day 1 or they'll be on day 100. There'll be some facility costs. But what we're seeing is we'll see offsets to those like, for example, areas where we had developments that we thought we're going to have to build more facilities we're seeing decline come in, so you're getting incremental capacity on some of those same facilities and we'll be able to use some centralized infrastructure to take advantage of that. So we largely think the startup cost will be mitigated by some of these other benefits we've seen. So I think when you look at it, I mean, the 25% decline we gave – given the year we're having just as a corporation with lower production than what we previously thought from a growth standpoint, you would expect to see that decline to come down a little bit, so that will also help you. So when you look at all those things, better capital intensity, slightly lower decline across our entire portfolio, we're pretty confident in the sustaining capital we gave.
Jeanine Wai - Barclays Capital, Inc.:
Okay. Great. That's a lot of nice detail there. Thank you very much. My follow-up is just a quick clarification. That $2.9 billion, that's the whole total Boes flat. Is the number to hold oil flat something similar? And if not, do you have a rough ballpark estimate for that? Thank you.
Jeff Alvarez - Occidental Petroleum Corp.:
Yeah. I'd expect it to be very similar to that.
Operator:
Our next question comes from Neal Dingmann of Truist Securities. Please go ahead.
Neal Dingmann - Truist:
Good morning, all. My first question is kind of a tag-on with some of the guys have asked just on asset sales. I'm wondering, first, is there any official – Vicki, I'm just wondering is there any official processes currently going on with any of the properties? And secondly, for 2021, will potential asset sale success, will that dictate sort of what you spend maybe high end, low end CapEx or are they sort of exclusive to a degree?
Vicki A. Hollub - Occidental Petroleum Corp.:
So we do have other processes going on, and I think the only other one that's probably more public is the process around Ghana. And so it's still up for sale and we've had a very good conversation with the finance minister in Ghana about that. So that's the one that's more public, but we do have others right now in progress. I will say that though – let me – I would like to clarify one thing. The one that's in Africa that's not up for sale is Algeria. And as I mentioned on our last earnings call, we've taken the strategic direction to make Algeria a core asset for our company. Our teams continue to dive deeper into the data for Algeria, and the more we learn the more excited we get about our future there. We see upside not only in the areas we currently operate but also in expansion areas. Our initial focus will be to maximize the value of the assets we currently have, and to jumpstart that process we've utilized some of our experts from Oman and Houston to support extensive sub-surface reviews. And at the same time, we're taking steps to strengthen our operational capabilities in our joint venture operations with Sonatrach. Of particular importance, I want to highlight that our relationship with the government is excellent and we continue to engage to ensure alignment for the future. To support that, we're also having very productive meetings and working sessions with Sonatrach along with our other partners. We're looking forward to seeing the value we can create for Algeria and our other shareholders. So Algeria is not for sale and wanted to clarify that from the first quarter earnings call.
Neal Dingmann - Truist:
Okay. And that sort of leads me to my second question just on the growth for next year. To your point, Vicki, on Algeria and some of these international properties, if prices do continue to rally as they've been, how do you foresee sort of domestic growth or domestic sort of targeting CapEx and growth versus the international? Are they going to be pretty similar as far as if you could see both or will it be much more domestically?
Vicki A. Hollub - Occidental Petroleum Corp.:
I don't really see us growing next year. I see us optimizing and following our cash flow priorities which is really the maintenance first. And so I expect that, should we get approval from the board, that we would spend the $2.7 billion to $2.9 billion in maintenance capital to keep our production flat for next year as we continue to use all of the available cash to retire debt, to address our maturities. So that's the highest priority for next year. Now we do have, as we go forward, a general pathway to more cash flow, more earnings to start generating a return and to get to a competitive total shareholder return. So we do have things planned beyond next year that will help to increase cash flow without significant additional capital. Part of what we really needed to do to maximize the cash flow that we get out of our operations was, first, to capture the synergies. And as we've outlined in this presentation today, the OpEx and SG&A cost reductions that we've achieved are more than double our synergy targets and we achieved them in less than a year after the close of the acquisition. The second part is I've been talking about here is to divest of the appropriate assets. We're trying to make sure that we balance the divestitures with our cash flow, and so we want to make sure that we're divesting of the appropriate things as we go and that we're preserving all the cash flow that we're going to need for the future. So thus far, we've divested as you know of close to $6 billion of assets. And our divestiture process almost took like a three-month pause in March, April and May when everybody was really dealing with the crisis, and now we're back on track to, as I've said earlier, to achieve the low end of our divestiture range. So first, capture synergies; second, divest of the appropriate assets; and third, is to de-lever. So using the divestitures and any cash flow that's in excess from cash flow from operations while maintaining just a capital spend of the sustaining capital limit, we'll continue to de-lever with proceeds from divestitures and cash flow. And then Rob has been very involved in liquidity management here over the past few months. The funds we raised from the bonds helped us to move out some of the maturities, a little over $500 million into early 2021. So that's really given us some room to make sure that we optimize the timing of our divestitures. Again, as I've said in my script, not to sacrifice value for timing, so we've got some room to make the right decisions around our divestitures. And the third thing that I think that we haven't really talked a lot about but is something that is really important to us is the restoration of our cash flow. And we've started the first huge step to do that, and that's through increased margin from our significant cost reductions. The second way that we'll continue to restore our cash flow is to increase our oil production volumes. But when you talk about growth and ask about growth, the way we need to do that is not necessarily increasing our capital spend but taking on partners to form JVs, just like the one that we did in the Midland basin with Ecopetrol where we're getting carried for a portion of the capital. That's the way we're going to continue to restore cash flow for ourselves without exceeding in the near-term our capital maintenance. So the JVs that we'll be looking at – and first, we wanted to do the divestitures first; that was our highest priority. So now we'll be looking at, as we go along, JVs in our core areas. We're divesting of things that are not core or won't fit within our core in the future. But JVs on our core acreage, and that's in areas that are way further out in terms of development or longer-term inventory. So the JVs will enable us to bring on another wedge of cash flow that will get us to where we need to be to be able to get back to a stronger balance sheet, get back to growth probably sooner than most people are modeling at this point. So – and all of this is to – all the things that we're doing, every step we make, take and every decision we make is around ensuring that ultimately we get back to a stronger balance sheet and that we're breakeven at less than $40.
Operator:
Our next question comes from Pavel Molchanov of Raymond James. Please go ahead.
Pavel Molchanov - Raymond James & Associates, Inc.:
Thanks for taking the question. Is it fair to say that you've essentially given up on trying to sell Algeria or is there some chance that that will be revived further down the road?
Vicki A. Hollub - Occidental Petroleum Corp.:
It's not that we gave up on selling Algeria. There's a lot of interest in Algeria. It's that as we learned more about Algeria, took that deep dive into it, we believe that those assets there are of such high quality they're going to be very competitive with our domestic assets. We want to be in Algeria. The more we've met with Sonatrach and the more we get to know the government in Algeria, the better we learn the assets, the depositional environment, the operations. We're very committed to Algeria. We've had interest there but we're committed. Algeria is now a core area for Oxy, so Algeria will not be up for sale.
Pavel Molchanov - Raymond James & Associates, Inc.:
Okay. From the chart showing the breakdown of your 2020 budget, it's pretty clear that low carbon is a de minimis portion of the program. Thinking ahead to next year and the $2.9 billion kind of base number you've mentioned, what would be the role of low carbon in that level of budget?
Vicki A. Hollub - Occidental Petroleum Corp.:
I'd say that low carbon, just because you don't see the capital on the chart doesn't mean it's not a huge part of our business. We believe that our low carbon venture strategy is going to be – is certainly going to differentiate us from others, and we're very committed to it. There are two things that or three things probably that the Low Carbon Ventures will do for us. The first and foremost thing, the reason we actually formed it, and this has been 10 years in the making, but the reason we formed it is that we needed a way to reduce our cost in our EOR operations. And even in our conventional EOR operations, the biggest driver or one of the two largest drivers of our costs there is CO2 and the cost that it takes electrically to inject our CO2. So electrical cost and CO2 are the two highest costs. For us to further increase our margins as we've been trying really hard to do over the past few years and making a lot of headway there, we're now attacking the EOR business because what we've realized is that our EOR business is going to be critically important for us for the future. It got us up to – it was the foundation of our company as we got up to the shale development, and it's going to continue to be the foundation of our company because not only can we do enhanced oil recovery through CO2 processing in conventional reservoirs, we've now done four pilots in the shale play and we know it's going to be as successful in the shale as it has been in our conventional reservoirs. But what we need to do to ensure that we maximize the margins and get the most value that we can out of it is we need to lower the cost. So the Low Carbon Ventures team has put together a strategy that you're going to hear more about in the coming quarters. But for now, I'll just summarize to say they have worked out a business model that's going to enable us to get CO2 at either very low cost or no cost. And so when you start looking at an EOR project and you can get CO2 for essentially no cost, that's going to dramatically improve the margins of our EOR business in conventional. And we have about 2 billion barrels of resources available in the conventional that we can exploit. And when you take that and you expand it into the shale, that's another probably 2 billion barrels that we can exploit in that as well. So the massive recovery that we can get just by lowering the cost of our CO2 is, in and of itself, a reason to continue our low carbon venture strategy in a very strong way. The second thing about our low carbon venture strategy is that there's a lot of interest in the world now, and thankfully, to lower our CO2 in the atmosphere to reduce the impact on global warming that CO2 has. And if you look at the models that were put together by Stanford, by Columbia, by IEA and others, there's no way to significantly mitigate climate change without further reduction of CO2 from the atmosphere. So the second thing that our LCV business model will do is help to do that. It'll lower CO2 emissions, and that's important for the climate. And we started long ago feeling like that is the right thing to do for the environment. We wanted a lower-cost CO2; that was the primary thing. And secondly, it's good to lower the CO2 in the atmosphere to address climate change. And now the third thing is that we have – there are a lot of investors in the world that are interested in not only helping to invest in things that improve the world versus things that don't. So now, these investors who are interested in and also helping to do these kind of things realize that with the Low Carbon Fuel Standard in California and with 45Q that was passed just a few years ago, we're now able to provide revenue from this business model that we're creating. So it turns into a very safe, low-risk steady stream of revenue for investors. And so this checks three boxes for us and it's so critically important that we view this to be one day we'll certainly generate, we believe, significant cash flow for our company as well. So not only improving the economics of our EOR in conventional and ultimately shale, we're doing the right thing that'll help the world and we're going to get a revenue and cash flow stream from it.
Robert Lee Peterson - Occidental Petroleum Corp.:
And Pavel, I would add to that too is related – you asked a question also about the capital and the budget. I don't want you to just think about the things that Vicki just described which are really game-changers for the company as Oxy's contribution solely being cash in those projects. So the 40 years-plus of expertise we have in the EOR business coupled with having certified bore space capable for this EOR-type sequestration is a commodity in itself that is value the company can contribute relative to cash and still maintain a high equity percentage of these projects.
Operator:
Our next question comes from Paul Cheng of Scotiabank. Please go ahead.
Paul Y. Cheng - Scotia Capital (USA), Inc.:
Thank you. Good morning. Vicki, you mentioned about currently you already received revenue in the carbon (sic) sequestering. Can you share with us how big is that number right now? And my second question is trying to get a little bit better understanding how from the second to third quarter the drop as you mentioned that is bigger than your underlying decline and seeing that this is the timing of the well. So can you give us a little bit better understanding and color by month the number of well that is going to come on stream so that we can do our model better? Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
I'm sorry. Was your question was the source of the revenue? I didn't hear all of it.
Paul Y. Cheng - Scotia Capital (USA), Inc.:
No. How much is the revenue? How much you generate now on those carbon (sic) sequestering and what's the projection on that?
Vicki A. Hollub - Occidental Petroleum Corp.:
Yeah. We haven't talked about it externally, but we are today sequestering about I think 20 million tons a year. So we are sequestering today. I don't know off the top of my head what our revenue is for that, but we just now worked with the IRS to get the process in place to start to claim those credits. So probably in the next, in the coming quarters we'll be able to provide you a better estimate of that.
Jeff Alvarez - Occidental Petroleum Corp.:
And Paul, this is Jeff. If I understood your second question, it's cadence of wells coming online for the remainder of the year. Is that what you were looking for?
Paul Y. Cheng - Scotia Capital (USA), Inc.:
That's correct because I couldn't get to why the production dropped so much based on the activity levels that you're mentioning.
Jeff Alvarez - Occidental Petroleum Corp.:
Okay. So, yeah, so I guess two questions. Why production dropped from Q2 to Q3? I can talk through that. And then the cadence of activity, I'll hit that. So if you look at Q2 to Q3, I mean, I can walk you through some of the big things that take you from 1.406 million Boe to our current guide. So the first thing is take 33,000 Boe off the top; that's the GNB sale, that's pretty easy. The 25% base decline, we've said that that still looks where we're at. So if you back out from the number before that, you back out the wedge, you take 25%, that's about 75,000 barrels. Maintenance/weather is about 20,000 Boe. E&C impacts and additional OpEx another 15,000 Boe. And then the decline in the wedge we outlined is about 30,000 Boe. And then you take some other things with ethane rejection and you get about another 10,000 Boe. That pretty much gets you to the Q2 number in a relatively straightforward way. So when you look at cadence of wells coming online, on slide 16 we put out what the activity looks like for the second half of the year for both Permian Resources and Rockies. Permian Resources, the well count, our wells online went up about 10 to 15 from what we previously guided. Today, I think we have one frac core and one drilling rig in Permian Resources, so the activity has started there. If you look at the DJ, that's gone up about 40 wells from our last guidance for wells online. That activity really won't start in earnest probably till September or so. So most of those will come on late in the year, but that is – you get some mitigation in Q4, but the majority of the impact is in 2021.
Paul Y. Cheng - Scotia Capital (USA), Inc.:
Jeff, in Permian, are those well coming on stream in the second half will be pretty variable or that is going to be second half or more in the fourth quarter?
Jeff Alvarez - Occidental Petroleum Corp.:
It's probably more heavy to the fourth quarter, for sure.
Operator:
Our next question comes from Phil Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Yes. Hi. Good morning. First question would just be if we go back to the time of the Anadarko acquisition, you laid out a specific leverage target; I believe it was 2 times at $60 oil. If you think about where we are now and everything that's happened since then, do you have an updated view of what you'd like the leverage target to be and at what price?
Robert Lee Peterson - Occidental Petroleum Corp.:
Yeah, Phil. We've indicated that our intent is to get back to an investment grade, to move back from the high yield to investment grade, and we know that conversation doesn't start until we get below a leverage of 3 times. And so right now, obviously between all the things that Vicki has detailed with regard to divestitures and positioning the business to benefit from all the cost reductions that we've done and then coupling that with an improving overall macro commodity environment to allow the business itself to generate free cash flow to retire and reduce – moving both the numerator and the denominator at the same time in that process, that's our current goal, is to get below 3 times to have that conversation on being investment grade again and then move from there.
Philip M. Gresh - JPMorgan Securities LLC:
And do you have a price deck where you think you could accomplish that based on all the things you've been outlining today?
Robert Lee Peterson - Occidental Petroleum Corp.:
As far as looking at a price that we accomplished (50:07), obviously the trajectory of that price is going to impact the timing of that. And so that's one part of the equation we can't control, is the trajectory of the price. And so we realize that if it's obviously a sharper increase then the timeline to accomplish that is shorter, and if it continues on in a more moderate pace it's going to take longer to get there than otherwise.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. My follow-up question would just be I guess it's sort of getting at what Doug Leggate was asking about with the outlined $2 billion to $3 billion of asset sales for the first half of 2021 and the free cash flow generation with the sustaining CapEx and implied free cash flow generation you've outlined. Do you believe that those things are sufficient to address the 2022 maturities as well on top of the actions you've already taken for the 2021 maturities? Or just any additional color to help us think through not just 2021 but also 2022 maturities. Thanks.
Robert Lee Peterson - Occidental Petroleum Corp.:
Yeah. And, Phil, I think as Vicki outlined, one of the key things to manage our divestitures is doing them on a timeline that allows us to get the greatest value for those and not being sort of in that fire sale position. And as you highlighted, when you're running these many processes, you do have businesses where there are people that we're willing to close in a more rapid timetable but it's at the expense of our company and ultimately our shareholders in closing those, and we're not going to do that. And so we're not going to create arbitrary deadlines on ourselves. So one way we manage that is not just from the free cash flow of the business but also the capital markets. And so, the recent transaction we did was meaningful in several ways because our prior earnings call was only a few weeks removed from negative price environment in April. We discussed the company was looking at every possible form of liability management at our disposal. But the continuous improvement allowed us ultimately with the improvement in demand and commodity prices to approach the market despite getting probably the two worst days in the month of June to do it with an unsecured debt offering and raising what was intended to be $1.5 billion to $2 billion of unsecured debt on our existing maturities. And as we sit here today, those bonds themselves in a short period of time have rallied to the point to where at close yesterday the 5s were at $1.10, the 7s were over $1.12 and the 10s were over $1.15 and indicative of the strength of those bonds and our ability to probably return to the market when they're open at our discretion and to achieve similar results at a lower price. And so I think the one way we would look at that to manage both the 2022s and beyond and even potentially the 2021s to some extent to give ourselves time for the divestitures on our timeline is returning to the capital markets. And that gives us the time – even looking at 2021 itself where we just did the $2 billion of divestitures that we had outlined for 2020, couple that with a similar size transaction we did in July, that cleared us runway essentially going all the way into 2022 by itself and allows us the time for the free cash flow generation of the business, allows the impact of those cost reductions that we've done, and really goes back to the combination of our underlying thesis from the acquisition that we've now taken the world-class portfolio we have today and coupling it with the operational excellence that we have so that that allows us to make the acquisition work.
Operator:
Our next question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.:
Good morning. My first question, I wondered if you could update us on your federal land position, permits in place, percentage of current anticipated Delaware Basin spend that might be directed to the federal acreage assuming no change in government policy. Just sort of what's going on there assuming things stayed the same?
Jeff Alvarez - Occidental Petroleum Corp.:
Sure. So this is Jeff. So I'll take the first run at that. So one thing we did on – you'll see on slide 29, we updated the footnotes with what our federal acreage position is because it came down with the sale of GNB and a couple other things. So we have approximately 1.7 million net acres of federal land, 800,000 onshore, 900,000 offshore. And so if you look at our key development areas, Permian has about 280,000 acres of federal land; the vast majority of that is in New Mexico. None of the former APC development area is on federal land, so pretty clean running room there. And the DJ, it's miniscule; you'll see it's like 40,000 acres, so there's very little in the DJ on federal land as well. So from a permitting standpoint, both in New Mexico and GOM which would be the most exposed to federal land given the question you asked, we've got permits approved that give us running room for the foreseeable future, I mean, at activity rates even at a much higher activity than where we were prior to COVID. We would have plenty of running room of permits that are already approved in both of those areas. Was there another part of your question or did that hit it all?
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.:
No. Well, that's fine. I guess the only other thing I'd ask that might still be of interest is just if you can disclose at what percentage of current CapEx or the anticipated CapEx in 2021 might be directed to those federal positions.
Jeff Alvarez - Occidental Petroleum Corp.:
Yeah. I mean, since we haven't given a CapEx for 2021, for current CapEx, I mean, you could pretty easily take the GOM number that we disclosed. And then of the remaining Permian part which is only a couple $100 million for the rest of the year, I mean, assume that's a quarter of that for New Mexico, so it's a pretty small number.
Operator:
Our final question will come from Leo Mariani of KeyBanc. Please go ahead.
Leo Mariani - KeyBanc Capital Markets, Inc.:
Hey, guys. I was hoping you could talk a little bit on kind of leading-edge well costs in terms of what you're seeing. Obviously, there's been significant cost reductions in the business here that you guys have been able to implement. Could you give us maybe a little bit more color on what you're seeing in terms of kind of completion and drilling and kind of facilities cost kind of all-in on a per well basis in the Permian and the DJ, kind of where they are today versus kind of where they were maybe to start the year on like a per foot basis or something?
Jeff Alvarez - Occidental Petroleum Corp.:
Leo, we haven't updated that since our last disclosure on the last call. The thing I'd tell you is like I mentioned earlier on the call, I do fully expect that capital intensity cost plus the benefits will be better once we start back up. So I do expect those to come down, but the dataset has been so small that it'll almost be misleading to say this went from X to Y just because we've drilled and completed so few wells. But I do fully expect, I mean, they're continuing to make great progress on the operational designs and seeing that. The other thing I'd mention is we previously talked about how much of the capital synergy we captured. I think we said 70% because, again, we only measure capture if we've actually done it, and so it's a small activity set. It's hard to improve that number, but it went up to 80% when we looked this quarter, so they do continue to make progress on the small activity set that we're doing.
Vicki A. Hollub - Occidental Petroleum Corp.:
And I'll just add to that that our team, the New Mexico team is working on some really exciting things driven by Thaimar Ramirez who's working hard on trying to further reduce well cost, and there's a lot of collaboration going on there to make that happen. And so I think with the sub-surface team's support and all that's going on there, I think that we're in for exciting news for next year when we do pick up another rig or two maybe.
Leo Mariani - KeyBanc Capital Markets, Inc.:
Okay. That's helpful. And I guess just want to follow-up a little bit on the debt reduction initiatives that you guys obviously did a good job kind of talking about, sort of what's underway on the asset sale side. You guys also, of course, are free cash flow-positive. And then lastly, you talked about refinancing some of the nearer-term maturities. Are there any other levers that you guys might consider to kind of accelerate debt paydown not necessarily maybe today? But as you look forward into next year, any other things that you think you might pull out of the toolbox to try to cut debt a little faster here?
Robert Lee Peterson - Occidental Petroleum Corp.:
Leo, obviously, the other ones that aren't in that category right now would be issuing equity or something like that. We did do the warrants. I don't see us pulling that lever as we discussed last time. So I think the combination of the liability management tools that we have from accessing the capital markets, the divestitures and the free cash flow right now we feel like is going to give us a pathway that allows the business model to work.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki A. Hollub - Occidental Petroleum Corp.:
I'd just like to say thank you all for your questions and for joining our call. Have a great day.
Operator:
The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.
Operator:
Good morning, and welcome to the Occidental's First Quarter 2020 Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Brandon. Good morning, everyone, and thank you for participating in Occidental Petroleum's First Quarter 2020 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Rob Peterson, Senior Vice President and Chief Financial Officer. This morning, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this morning. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good morning, everyone. In the short period since our last earnings call, the actions taken by Saudi Arabia and Russia, as well as the worldwide spread of COVID-19, have pushed oil prices to the lowest level in recent memory and created significant uncertainty with the macro environment. As Oxy adapts to this challenging and evolving market, our thoughts remain, first and foremost, with those who've been impacted by COVID-19, and we hope that this tragic situation passes quickly and that you and your families will be safe through this crisis. We are taking extra precautions to preserve the safety and health of our employees and contractors with minimal disruption to our operations. And before I go any further, I want to express my appreciation to all of the Oxy employees for your focused performance and delivered results despite the stress of the past couple of months. I'll also thank you in advance for the success I know you will achieve as we realign our goals to maximize value through this recovery period. Since mid-March, we have taken a series of decisive financial and operational actions so that Oxy has the resiliency to weather this difficult period. In addition to reducing our capital budget by more than half, we expect to deliver an additional $1.2 billion of overhead and operating expense reductions in 2020. All of our long-term differentiators remain intact and we are well situated for success when market conditions improve. We have the best people in place to leverage our superior assets, and we will continue to deliver outstanding operational results, including our ability to safely and quickly reduce activity in this low price environment while preserving the integrity of our valuable assets. Before I highlight our first quarter results and our efforts to achieve cash flow neutrality in 2020, I would like to welcome Rob Peterson to the earnings call. Rob was named to the position of Senior Vice President and Chief Financial Officer. Before becoming CFO, Rob served as Senior Vice President of Permian EOR. Since joining Oxy in 1996, Rob has held key leadership positions, including serving as the President of OxyChem. In a few minutes, Rob will cover our financial results, revised guidance and debt management options. Now moving to Slide 4. To survive in this environment, we must continuously deliver best-in-class operational results and be a low-cost operator. In the first quarter, our core business did just that, delivering industry-leading results with lower capital spending and faster time to market. Our Midland Basin team set a Permian Basin record by drilling over 7,300 feet in 1 day. And they did it twice in the quarter. Our Texas Delaware team drilled a 10,000-foot horizontal well in the Silvertip area in 15 days, over 4 days faster than our previous record. In the DJ Basin, we drilled a 10,000-foot horizontal well in under 4 days and reached our lowest average cost per foot for oil drilling during the quarter. We also set a new record for both major frac providers in the Permian with 18 stages fracked in 1 day. These accomplishments completed by different teams demonstrate consistently high performance across all of our businesses. Our midstream business continued to provide flow assurance to deliver our products to market, a differentiator that has become more valuable in the second quarter as the industry faces storage restrictions around the globe. While we are shutting in barrels that had become uneconomic at extremely low price realizations, which Rob will touch on in a few minutes, our midstream business provides us with optionality in routing barrels to obtain more favorable realizations. Turning to divestitures. We did not disclose any additional material transactions in the first quarter as travel restrictions and the falling commodity prices have severely disrupted the market for asset sales. While we remain committed to closing divestitures over time, we will not sacrifice value to close transactions quickly. Given the market condition, we are no longer confident in raising sufficient funds from just divestitures to address all of our near-term debt maturities but have numerous options available, which Rob will highlight. Since acquiring Anadarko, we've been working towards the sale of our Africa assets and previously closed on the sale of Mozambique and South Africa. Over the past few months, Oxy has had several meetings with our partners in Algeria to discuss areas for mutual collaboration. And in April, we decided to continue operating in the country. The Algeria assets have high potential and generate free cash flow at low commodity prices. At the current Brent strip, we expect to generate $100 million of annual free cash flow from Algeria while investing $30 million of capital in 2020. We continue to discuss the sale of our Ghana asset but recognize that this transaction is at increased risk given the current environment. Now moving to Slide 5 and Slide 6. We are taking aggressive action to protect our long-term financial stability and the integrity of our assets. We are lowering cost and moderating activity to achieve cash flow neutrality while maximizing liquidity. Within 4 days of OPEC's failed Vienna meeting, we moved quickly to reduce cash outflows by reducing our SG&A and operating costs beyond our original synergy targets, and we cut our full year 2020 capital budget. Our operating teams immediately launched initiatives to capture an additional $1.2 billion in SG&A and operating cost reductions. This will get us to a $2.3 billion reduction from pro forma 2018, which is more than double our original synergy target. This has lowered our quarterly overhead consisting of SG&A, other operating expenses and exploration overhead to approximately $400 million on a run rate basis and will reduce our operating expenses to $6.25 per BOE in the second quarter. Our capital reductions will result in a full year budget of $2.4 billion to $2.6 billion. To achieve these cost savings, we have modified our operating processes, replaced a significant number of contractors with employees and reduced executive and employee compensation. We are leveraging existing inventory to reduce orders for new and replacement equipment, and we're further consolidating vendors and we're utilizing creative solutions such as reverse auctions to source commodities and services. The speed and magnitude of our reaction demonstrates our recognition that the oversupply of crude must be addressed by all of us. Within a few weeks, we dropped down to 2 domestic rigs and had substantially reduced activity in Oman and Colombia. We are also currently minimizing well interventions by taking a disciplined approach to downhole maintenance that preserves the long-term integrity of our assets and reservoirs. Despite these changes, our operability remains high, which we believe positions us strongly compared to other operators. As this downturn will inevitably stress oil producers, an operator's base management proficiency will become increasingly important. Oxy is well positioned with a large asset base, and we have the reservoir management expertise established in our conventional EOR operations to recover more barrels from existing reservoirs without the need to build a growth wedge. Many of the same teams that established our capital intensity leadership and have innovatively applied our advanced subsurface modeling to the shale reservoirs are now applying their knowledge and skills to base management across our portfolio. To preserve liquidity, one of the most difficult decisions the Board made was to announce its intention to reduce our common stock dividend. Those who know Oxy understand that this was not a decision that we took lightly but one that we had to take to protect long-term value. We also paid the April 15 preferred stock dividend and common stock to boost our liquidity position, which is an option our Board may consider each quarter. Going forward, our focus will remain on strengthening our balance sheet. I will now hand the call over to Rob, who will walk you through our financial results, revised guidance and debt management options.
Robert Peterson:
Thanks, Vicki. Turning to Slide 8. We are approaching the remainder of 2020 with a cautious outlook and have withdrawn our full year guidance and cash flow sensitivities. To prepare for a prolonged low price environment, we are taking decisive action to reduce cash costs. The progress our teams have made in reducing activity in collaboration with our partners and service providers while minimizing adverse impact has been remarkable. As Vicki mentioned, we have fully captured $1.1 billion of overhead and operating expense synergies and are repositioning our 2020 cost base with an additional $1.2 billion of overhead and operating expense reductions that we expect to be fully realized this year. We have also further reduced our full year capital budget to a range of $2.4 billion to $2.6 billion, which will lower our second quarter capital spending to approximately $500 million. Looking towards our 2021 and 2022 debt maturities, we are taking significant steps to preserve liquidity, including the Board's announced intent to reduce our common stock dividend and the payment of the preferred dividend in common shares in lieu of cash in the second quarter. We are intent on raising as much cash as possible from divestitures and expect to raise over $2 billion in the near term. It may take us longer to close divestitures in excess of this near-term estimate as we are not prepared to sacrifice value in today's challenging environment conditions. As we pursue divestitures across our portfolio, we are also actively reviewing and evaluating our capital structure and options available to manage our near-term debt maturities. In this context, we continue to review our debt management options which could include the utilization of free cash flow, continued asset divestitures, utilization of liability management solutions, such as debt exchanges and extension maturities, the refinancing of debt and accessing capital markets. Additionally, we are monitoring the 2036 0 coupon notes as they could be put to us in whole or in part this October based on where the security is currently trading. We may be required to retire up to $992 million of debt depending on the number of 0 coupon holders that choose to exercise their redemption option. At April 30, we had $6 billion of liquidity, including cash of approximately $1 billion and our unutilized $5 billion credit facility. To date, we have provided financial assurance through a combination of cash, surety bonds and letters of credit made available to us on a bilateral basis and have not issued any letters of credit under our credit facility. Moving to Slide 9. Turning to our financial results. The first quarter of 2020 is the first quarter since the acquisition closed that we reported Oxy's financial results without consolidating WES. In the first quarter, we announced an adjusted loss of $0.52 per diluted share and a reported loss of $2.49 per diluted share. The difference between adjusted and reported results is mainly due to $1.8 billion of charges, including the impairment of goodwill related to WES and other oil and gas properties and $148 million of costs related to acquisition, partially offset by a net positive mark-to-market gain on crude oil hedges. Through the first quarter, we have expensed approximately $1.8 billion in acquisition-related costs and anticipate expensing an initial $150 million in integration costs this year. In the first quarter, we had cash outlays of approximately $800 million related to these expenses, bringing the total, including the amount paid in 2019, to $1.7 billion. For the remainder of 2020, we expect to have acquisition-related cash costs of approximately $250 million. Moving to Slide 10. We have provided guidance for the second quarter of 2020 and expect to return to providing full year guidance and cash flow sensitivities once basin differentials and market conditions stabilize. The production ranges we have provided for the second quarter are wider than the previous quarters as we are accounting for the uncertainty of potential shut-ins beyond our forecast. In the second quarter, we are forecasting shut-ins averaging 45,000 BOE per day, of which approximately 2/3 is voluntary due to individual well economics, with the remaining 1/3 due to OPEC+ restrictions. We expect shut-ins to peak in June around 75,000 BOE per day. Our guidance does not account for potential involuntary shut-ins related to flow constraints. All oil and gas guidance now includes Algeria as a continuing operation. I will now turn the call back over to Vicki.
Vicki Hollub:
Despite our activity reduction, all of our long term core differentiators remain intact. Our leadership as a low-cost operator, track record of operational excellence and a portfolio of world-class assets are competitive advantages that better position us for success when market conditions improve. These attributes, combined with our differentiated low carbon strategy, are expected to drive our success and sustainability into the future. We're now open for questions.
Operator:
[Operator Instructions]. Our first question comes from Paul Cheng with Scotiabank.
Paul Cheng:
Vicki, I know maybe it's too premature and then you guys are just focusing putting out the fire. But with COVID-19, if we're looking at some point that it will pass on post COVID-19, how this event have changed your operating and financial parameter on a going-forward basis?
Vicki Hollub:
I'm sorry. What was the last part of your question, Paul?
Paul Cheng:
That in the post COVID-19, if we're looking at over the longer haul, that how that may have changed your financial and operating parameter? Like before that, I think, after the merger, you have been talking about potentially a 5% long-term growth rate that you guys may be targeting and that maybe a debt-to-EBITDA ratio in the 1.5x. With the event that we just passed through or went through, how that may have changed on those parameters?
Vicki Hollub:
So certainly, for us, what the COVID-19 situation crisis has done for us is it's caused a bit of a near-term focus for us to do differently than what we had set out. As you know and as you mentioned, we had a 5% growth plan going forward. But what our near-term priority is, is to protect our cash flow, so preserve cash and generate then growth in our cash. But the way we'll do it, we have plans for the near term. We have plans for cash flow neutrality, breakeven and eventually a low-growth plan. But for the next few months and into maybe the end of this year and through the recovery, our focus is going to be on base production management. So we have not abandoned our long-term future growth plans. But for now, what we're going to do is keep the capital as we've just said for 2020 and focus on mitigating our base decline. As you know, as we've often said, our base decline right now is about 25%. So our near-term focus will be on optimizing the performance of our existing wells and existing reservoirs to ensure that we're getting all we can out of those and focusing on for incremental barrels that help to mitigate the decline. We'll focus on developing behind pay -- pipe in the existing reservoirs. So there's going to be a lot more focus on our base production in our current assets rather than drilling new growth wedges in this near term. So we're really excited about the fact that with this vast base of assets that we have, everywhere we are, we have stacked pay. So that stacked pay enables us to, in the wells where we don't see opportunities, to optimize existing production, to develop other intervals and bring those intervals on at much lower cost than it would cost to drill and develop new wells. So the near-term focus is just that, is to mitigate our base production decline, that's optimizing performance from existing wells and using that infrastructure to help to lower our cost on a per unit basis. Doing that probably through the rest of this year and into the recovery, depending on how long that lasts will be our focus. Ultimately, I'm sorry, go ahead, Paul.
Paul Cheng:
Vicki, I'm sorry. I fully understand near term what you're trying to do. But I'm trying to understand that on the longer-term basis, has the event changed the way how you look at the business model and have you changed what is the criteria or parameter that you're going to use? Are you going to use it at a lower growth rate going forward from the 5% and that even a more stringent target for the debt-to-EBITDA or that a lower leverage ratio or that you think you're still business as usual? I think that is really is more of my question.
Vicki Hollub:
Yes. Our highest priority will be to lower the debt. So rather than generate or have a growth target, our target is more to take free cash flow to lower debt. And we'll structure our capital programs around ensuring that we can do that. We believe that with the assets that we have, we can get to a scenario where our sustainability price is such that we can generate free cash flow in a lower price environment. That free cash flow would then be used to lower debt. So debt will be the highest priority in the near term. And when I say near term, I'm talking over the next couple of years.
Operator:
Our next question comes from Pavel Molchanov with Raymond James.
Muhammed Ghulam:
This is Muhammed on behalf of Pavel. So can you guys provide an update about the status of discussions with the State of Wyoming regarding the sale of surface acreage there?
Vicki Hollub:
Yes. We are running a process to sell the land grant. And that process, we kicked off this year, early this year. We've just completed Round 1 of the bidding process for the land grant. And we were pleased that we had 13 bidders for the land grant. So now we'll take that to Round 2 of the bid process. And that's really about all I can disclose about that, but we're excited about what we've seen thus far. We would expect to be able to close on that asset in probably late Q3 or early Q4.
Muhammed Ghulam:
Okay. Understood. And so you guys have talked in the past about some of your carbon capture projects or investments in carbon capture technologies. Given that the 2020 budget has been cut so much, can you guys talk about how carbon capture fits into that program? Are any of the projects being postponed?
Vicki Hollub:
The way we're structuring our development of the carbon capture was such that we were not going to have to put out a lot of Oxy capital because what Oxy is providing to potential partners in our Low Carbon Ventures projects going forward is the opportunity for others to come in and be a part of it. We bring the reservoirs for the CO2 sequestration. We bring the land to build the facilities. And we bring the expertise to take the CO2 from those facilities and sequestered in our reservoirs. So what we bring to the table is our experience in our existing assets. What others could, as partners to us, bring to the table are the funds that will help us build those facilities.
Robert Peterson:
I'd like to add to that and also say that in the pursuit of the cash generation, lower cost basis, that this not only drives the cash flow neutrality, but there's also the opportunity to reduce our overall cost through it. So it's still very much part of our portfolio or our cornerstone to future development.
Vicki Hollub:
Yes. And the way we do that is that for our CO2 enhanced oil recovery operations, the two largest costs in that operation, in fact, 40% of the cost is associated with the cost of CO2 and the cost of the electricity that's required to inject that CO2. We're addressing both of those. This Low Carbon Ventures is, it's a lot more about sequestration. It's just sequestration. It's also about lowering our cost so that we can make our current CO2 business better, as Rob was saying. But by making it better and less expensive, we can also expand that out into our shale play. So that gives us the option to grow that a lot more and over the expanse of all the shale play, not only in the Permian, but then taking that once we have that model built and working and applying it in Wyoming and Colorado as well.
Operator:
Our next question comes from Doug Leggate with Bank of America.
Douglas Leggate:
And Rob, welcome to a bit of a baptism by fire, I guess. I wonder if I could start, Rob, with you, your slides on the options for debt. And I was just wondering if you could walk us through how realistic these options are. What discussions have you had with banks on potentially exchanging refinancing? Is a convert a possibility? And if you could clarify why it looks like you burned over $1 billion of cash in April? And I've got a follow-up, please.
Robert Peterson:
Okay, Doug. Let me hit the second question first. The primary reason of the cash was the payment of the dividend in April. So that was the predominant use of cash in the month of April. Normally, obviously, we don't provide an April cash on hand during the earnings call, but we thought it was important to put the most current information out in front. With regards to discussions we specifically had externally, I won't comment on those. But we do believe we have adequate liquidity for the near future based on the cash flow from operations, the known asset divestitures and the cash savings with the associated operational expense reductions that we've talked about already today. We're also well hedged for the balance of 2020, and we've taken that in combination with the steps to reduce our cash flow neutrality, which is going to help conserve the cash in a low price environment. We continue to look across the portfolio but recognize we may not be able to satisfy all those 2021 and '22 debt maturities without a significant market recovery. But we do believe that at our disposal, certainly beyond what we currently have in place is, we do have the free cash flow, the asset divestiture proceeds, exchanging the debt and extending maturities and then refinancing in the capital markets. So I think we're taking those actions. I do think those are all opportunities for us to address those near-term maturities that are in front of us.
Douglas Leggate:
So to be clear, you think refinancing, the markets are open to you?
Robert Peterson:
Absolutely.
Douglas Leggate:
Okay. My follow-up is on the underlying decline. Vicki, this one's probably for you. You talked about 25%. I assume that's unmitigated on the base business. But can you walk us through what that looks like as an exit rate, including what assumptions you have for asset sales? And obviously at the back of my mind is Ghana now that Algeria isn't going forward. So what does that exit rate look like? And if you could, what do you think the sustaining capital for that exit rate is if there's such a number going into 2021? I'll leave it there.
Vicki Hollub:
Well, we've said our base decline is 25%. And the reason I'm hesitant to give you a number for what it's going to look like in Q4 is because of what we're doing now to refocus our teams. As I said in my script, we're going to take these incredibly talented people who have done a great job growing Permian Resources and we're going to supplement them into our base production management teams. And that's not to say we don't have also great people operating our base production management. It's just that when you're in a high-growth mode, sometimes some of the base management doesn't get done as diligently as it should and can in an environment like this. So we don't expect that our decline will stay at 25%. What we expect is that we're going to have teams that find ways to mitigate that decline by, again, by optimizing production from existing wells by virtue of changing artificial lift types, by reducing back pressure on the wells and/or by doing cleanups, just doing acid treatments on perforations and things like that. So there's optimization opportunities with the existing wells that are producing today. The other thing that's there is, we've always had this inventory of zones above and below the existing producing intervals in our wells that have capability to produce. It's just that those were not going to get us to the higher growth rates that we were executing over the last few years. They're perfectly suited for mitigating a base decline but not for an intense growth program. So we expect that those will help to mitigate the decline, that 25%. So it's hard to tell you right now what a Q4 exit rate would be. We haven't put together all of our plans. The teams are working them. But I am very confident that from Q3 to Q3, we're not going to have a 25% decline. We're going to have something much less than that.
Jeff Alvarez:
Doug, and this is Jeff. I'll hit on your sustaining capital. And like Vicki said, I think the important thing to remember, and you've covered us for a long time, if you go back before the unconventional boom when we really brought all that great inventory forward, we were a base management company. You look at our EOR business and what we were doing in Oman and Colombia and Qatar, that is what we did. So a lot of the parts of our business have been -- continue to stay focused on that. Now we'll bring that to the rest of the business even to a higher degree, and we have a whole new data set to do that. But on sustaining CapEx, I think what Vicki said, it's worth pointing out why we don't give a specific number. So let's talk about what we have disclosed. Previously we said, in 2021 at our previous plan, our sustaining capital would be $3.9 billion at $40 WTI. And remember, that was growing into 2021. So let's now talk about the building blocks and how we're doing against those. Vicki talked about the decline rate. We've mentioned that. It's going to continue to get better. The other thing that helps that decline rate is we're not bringing on a bunch of unconventional barrels, high decline barrels this year. So you'd expect that to be better than what we said before. Starting production level, it was going to be higher than what we previously or what we think now just because we're not growing into 2021 like we previously thought. So that also gets factored in. Capital intensity, as we've shown, best-in-class capital intensity on our growth areas, and we continue to get better. So when you look at the barrels we can add for every dollar spent, not only is it best in class, it also continues to get better. So again, a helper on what the sustaining capital will be. Now what's going to work against that is obviously, as Rob said, spending $350 million a quarter in the last couple of quarters, that sustaining capital that we put out before was kind of on an ongoing basis to where you spent something similar the year before and you had an activity set. So when you start back up from the level we're at, we do expect to have some start-up capital, let's call it that. It's things like just when I spend $1 today, I don't get production for a couple of months from that. That will impact that period when you look at that first year of sustaining capital, the learning curve impacts, which always happen when you start back up on programs. But the great thing about that, if you look at the records Vicki talked about in the Midland Basin, that's an area we shut down and restarted. And within a few months, we're setting records from an execution standpoint across the business because they took learnings from other parts of the business and were able to immediately apply them. So while we do expect in that first year you would see some of that start-up capital come through in that sustaining capital number, we don't think it will be huge, and then we'll quickly work through that. So again, as you think about that sustaining capital, you can take all those components in place and look at how the business is changing and what you would expect it to be, but we do continue to be able to believe we can drive that down.
Vicki Hollub:
I'll just use one more example. Back in 2000 when Steve Chazen bought the Permian Basin Altura, the criticism of that was that he was buying harvest mode assets. And I can tell you, in Denver City now, all these years later, these decades later, we're still adding reserves to the Denver unit, still finding ways to increase the reserves and the production there. That is our niche. And we do it well. And we just got to refocus on it.
Operator:
Our next question comes from Brian Singer with Goldman Sachs.
Brian Singer:
I wanted to first start with just a couple of clarification questions on a couple of points that you made. First, I think you said, Vicki, in your comments that you expect $2 billion of divestitures coming in the near term. Can you clarify whether that includes versus excludes Ghana and includes versus excludes the land grant? And then also, I think it was also mentioned that accessing capital markets was a possible solution on the financial side. Can you talk to whether that is or whether there is a consideration of equity common equity issuance?
Vicki Hollub:
So I'll talk about the divestiture. The $2 billion does not include Ghana. That's all I can say specifically on that. Rob?
Robert Peterson:
Yes. With regards to the issuance of common stock, it's not something that we're considering right now in light of the price of the stock.
Brian Singer:
Great. And then my follow-up is more of a bigger picture. You have a slide on the change in corporate governance on the back of today's presentation. And given some of the recent changes, both in the Board, parts of management, the dividend, can you broadly discuss in the conversations you've had with the Board any shifts in focus or priorities generally or specifically relating to the urgency and levels of delevering, M&A and the breadth versus concentration of assets within the company?
Vicki Hollub:
Well, I'll say one thing that from a personal perspective, I'm incredibly excited that Steve Chazen came back on to the Board and as Chairman of the Board because specifically we did need help with dealing with the debt situation in this environment. And so from my perspective, what I see with the Board now is his ability to help lead us through what's a very, very challenging environment for every company in the world, but especially for us since we had these maturities coming up. I think the other experience that was brought on to the Board in Nick Graziano and Andrew Langham is also an ability and experience with debt exchanges and also with dealing with the debt situation. The experiences of those 3 that we just brought on is going to help us through this environment and already helping us and creating value for us. So I think that we've strengthened our Board in the way that we definitely needed to do in this environment.
Operator:
Our next question comes from Ryan Todd with Simmons.
Ryan Todd:
Great. Maybe a couple of questions on the -- a question first, I guess, on the CapEx and OpEx cuts going forward, pretty impressive cost reductions in the near term, in particular, the additional $600 million on the OpEx side. Can you talk about how you view the sustainability of those cuts going forward, I guess, both on the CapEx and the operational side? Are those the kind of things that necessarily ramp back up as you start ramping back up activity levels or how much of those do you think you can kind of structurally capture?
Vicki Hollub:
I think that certainly the full $600 million incremental in the OpEx is that full $600 million is not sustainable because one of the things that we did just to get us through this quarter because we expected Q2 to be the worst quarter, while some people are encouraged by prices where they are, we still have a concern about storage. So we expect the end of May, 1st of June to be particularly challenging for us. So we wanted to make it through Q2 at the lowest possible cost structure. So the $600 million in OpEx, probably about 60% to 65% of that is sustainable. The part that's not is where we're going to need to bring back some of our well service rigs because currently we're in a mode where since we need to reduce production anyway to help with the oversupply issue, as some of our wells fell right now, we're not putting those wells back online. So as we get beyond this difficult period over the next month or 1.5 months and start into the recovery, that's when we'll start bringing some well service rigs back at the point where we feel like it's necessary to start and we have the cash to be able to do that. So that will increase our cost a little bit, but we drop those rigs significantly. There are some other minor things that we would do differently, but I believe that our teams may find as we're doing this other opportunities to offset some of the cost and the activity that we'll need to start back.
Robert Peterson:
And I'll just add to that, I mean, building on Vicki's point that. One of the unintended benefits of the slowdown is it allowed us to really step back and take a very deep look at the way we do things and how we pursue the business and give us time to really impart this passion for cost reduction, margin generation and make that equal our passion for the growth we've had in the past so that we can really internalize into our culture that this is the way we do business and hold on to that as things turn the other direction eventually on the recovery. One of the challenges if it's such a short shock to the system, it's really difficult to move the culture of the business. But the things that we've done and the inspiration within our people to really get passionate about cost reductions and margin generation, to hold on to that moving forward will pay dividends for the company.
Vicki Hollub:
I think the quality -- I'm sorry, just to finish that. I think it speaks to the quality of our employee base that they are motivated, that they found these things so quickly and that they're excited about the challenge that we have and ready to address it and achieve it. And your next question is?
Jeff Alvarez:
Ryan, can I add one thing? Because I think it's a pretty remarkable thing with what Rob and Vicki said. If you look at our SG&A, where we'll be on overhead, we'll be at a level lower than we were as Oxy stand-alone in 2018. So the costs that have been driven out of the business by the teams is remarkable and we basically doubled the size of the company and we're back to the same overhead before we did that.
Ryan Todd:
That's impressive. I appreciate all the clarity there. Maybe a follow-up on the Permian. I mean, it gets lost in everything else that's going on right now, but well performance year-to-date in the Permian is again showing pretty significant year-on-year improvement. Maybe any comments on talks about the drivers of this? Is this high grading from lower activity levels or is that something that's more sustainable as activity eventually re-ramps in the basin?
Jeff Alvarez:
Yes, definitely sustainable. It's basically a continuation of everything we are doing and applying those things on the new assets and combining the learnings from both. So taking some of the learnings from the legacy Anadarko acreage and applying that in New Mexico on things like regional sand or landing points and development philosophy on the APC acreage. I mean, we showed you that Silvertip slide. You can see the level of improvements that are being made. I mean, that's probably the most disappointing thing for me in the whole thing that's going on is all of that momentum that the teams have built up and those improvements that we expect to be sustainable are now going to kind of be put on the back burner, but we strongly believe we'll get it back quickly. The other thing I'll point out on the slide you're looking at, Ryan, is that now includes wells on the former APC acreage that has the new design that we've talked about, that Atlas design. Those are in there. And they're driving that performance improvement as well.
Robert Peterson:
Again, I'll just build on that, too. One of the investment thesis still remained. And if anything, coming out of this because we have such a vast portfolio, we can high-grade even further than we would have been able to as stand-alone Oxy. Our ability to come out with lower cost, lower capital intensity wells and choosing those is much greater than would have been without the original Oxy assets.
Vicki Hollub:
And I can't let this conversation end without also adding the DJ Basin. The performance there has that team, that drilling team has been incredible. So we have to give a shout-out to them. They continue to improve their performance.
Operator:
Our next question comes from Paul Sankey with Mizuho.
Paul Sankey:
In trying to forecast your volumes, can you give us a bit more detail on the base decline rates and talk about the various regions and the various mitigations so that we can try and get towards a number that is obviously less, as you imply, than the 25% decline, but exactly where we should come out on that? My question essentially is, can you talk through the decline rates from the various components of your portfolio and how you're going to mitigate them?
Vicki Hollub:
Well, I think that it's important to note what Jeff has said earlier, is that when you -- as you know, the highest decline for the shale play is right in the first year, first 1.5 years, two years. So as we're slowing down, the decline of our shale production is going to start to mitigate itself just by virtue of the fact that we won't be drilling as many new wells, in fact, very few new wells. So that decline is going to be less than it traditionally is. The EOR business, we've said in the past, is normally a 4% to 5% decline, and that's when we're fully using our CO2. We have shut some of our CO2 wells in. So that decline now could be actually a little bit mitigated, but it's going to be versus a slightly lower volume, not a lot of production to shut in there. So the Middle East, the conventional reservoirs are lower decline. But overall, it's hard to go through and look at each of those as we're modifying what we do everywhere. So it's really hard to give you a number that you could then roll up into a single number. Just know that we're working on the decline everywhere. The shale decline will be less. EOR will be less with the production that's on. So lower than that, 5%, probably down to 4% with what's producing today.
Robert Peterson:
And I guess the other piece of that, too, is that unlike typical or historical quarters when we've been executing a development growth plan. We're building a significant backlog of existing wells that won't need to be redrilled or anything to bring that production back online. It's really the activity set that Vicki mentioned around downhole maintenance, et cetera, that will bring barrels back online in a way different than we've seen in prior year quarters, which is really difficult to measure in light of not knowing where prices or the recovery trajectory right now.
Paul Sankey:
And then the second and final, this was an awkward quarter to calculate the cash flows because of the mix of oil price. Can you talk about what sort of cash flows we can expect from you at the current price environment? And let's say, for example, the sensitivity, if we believe the strip, which is currently about $25 a barrel for next year -- actually, excuse me, $32 a barrel is the April next year strip. Could you give us a sense for how much cash flow would be generated in those 2 environments, current and future?
Vicki Hollub:
Paul, I can tell you, this is not going to help you at all. I was trying to think of a way to help you with your model here, but pretty much where we -- once we get past Q2, we'll be able to balance our cash inflows with our outflows. So we'll be neutral in Q3 and Q4, but I don't think we've given you our price assumptions either. So I'm not sure that helps you at all. But the sensitivities, I would say that as our production declines a bit, the sensitivities have gone down a bit. They're not at the $1 change in oil prices equal to 250. So they're not quite there yet. They've declined a little bit. Again, what that ends up, that sensitivity ends up being depends on how much we can mitigate the decline as we go.
Operator:
Our next question comes from Jeffrey Campbell with Tuohy Brothers Investment Research.
Jeffrey Campbell:
We've kind of beat on the dead drum quite a bit, so I thought I'd ask a couple of different questions. One is looking forward, is Oxy continuing to test technical solutions to reduce headcount and improve performance? And to give an example of what I'm thinking about, automated directional drilling seems to be gaining some increasing traction.
Vicki Hollub:
Yes. We're going to push the envelope on everything now, and that's part of the reason we've been able to reduce our SG&A significantly as our teams are leveraging technology and automation as much as we can. We probably have one of the most automated areas in our Permian EOR business. With respect to the drilling, yes, we're pushing the envelope there, too, because you've seen the improvements in how we're drilling our wells. So as much automation as we can install, we are. And part of that automation has gotten us beyond where in the drilling area where we need the typical tool pusher on the drilling rig or the driller to manage the process, we actually build models by which the computer can basically do the drilling of the well. But it takes an engineer to help to build those models. But once they're automated, then it's a process of just then tweaking to get better. That's on the drilling side. On the field operations side, our CO2 operations are very highly automated. We can actually manage those from a central control room. So we're managing that. As we've improved and started to better rely on our artificial intelligence with respect to well productivity and those sorts of things and what wells should be doing versus what they are, that's part of what I was talking about when I said we're modifying our production processes. We'll depend more on letting those tools help us manage which wells really need any kind of physical or visual on-site versus being able to completely manage from a control room. So there's a lot of automation that we've installed that's going to help us move toward a lower, much lower SG&A environment.
Robert Peterson:
Yes. And the thing I'll add on that too is also, we're doing a vast look at our portfolio, too. When you have a portfolio as large as Oxy's, you can't apply the same sort of techniques and approaches to every bit of the portfolio. And so this is allowing us time and again to reprioritize and bucket our portfolio in areas where, in some cases, we may be very quick to bring a well back to production or in other cases, we may leave wells down for an extended period of time or not use the same type of approach to actually how we're going to maintain the well or how we're going to automate the well. And this sort of not a one-size-fits-all approach is also bringing a lot of savings. And not only that, but also the number of people required to continue to operate the fields we operate in.
Jeffrey Campbell:
I appreciate the detailed color. And just to quickly get back to something that you mentioned in the prepared remarks regarding Algeria. I just want to make sure I understand this. Is it your intention to operate there now until price recovery or have you decided that it is a core asset going forward, notwithstanding receiving an offer to buy that can't be refused?
Vicki Hollub:
It's a core asset going forward. And if we got an incoming offer for Algeria that was something that we couldn't refuse, we would certainly need to coordinate that with Sonatrach and with the Ministry of Oil because we do have partners. And that's the way it is working internationally. Sometimes the decisions need to be coordinated and we need to be committed there. We're committed to be there and to do our best to increase value and enhance the operations, and we believe we have the opportunity to do that. It's a great asset. It's one of the best assets that's in that region. So we're excited about it, and we're going to stay. Again, if someone came in and made an offer that we couldn't refuse, I'm sure the ministry would be interested in that as well.
Operator:
Our next question comes from Leo Mariani with KeyBanc.
Leo Mariani:
Just wanted to ask a couple of housekeeping items on some of the guidance here into the second quarter. You guys talked about 45,000 BOE per day of shut-ins. I was hoping to get a little bit more detail around kind of what regions that's kind of split up to. And also on your midstream guidance, I think you guys are saying negative $310 million and minus $350 million, I guess, pretax income. Significant change versus first quarter. I was just hoping you could kind of elaborate on some of the reasons and the big change on the midstream.
Jeff Alvarez:
Leo, this is Jeff. I'll start with those and then Vicki and Rob can jump in. So as you mentioned, for second quarter, we're estimating 45,000 barrels of shut-in production. 1/3 of that, as Rob said, is OPEC+ related. So you can realistically assume that's from Oman and Algeria. The remainder is domestic and that's economically driven. And the best way to think about that, half of that, the domestic part is from the Permian, which is the EOR and resources. And then the other half is in the Rockies. And just to give you a little color, so that 45,000 barrels, about 3% production compared to our guide. The number of wells we're shutting in is about 9% of our well count with that. So as you would expect, you've got a proportionate -- a lot more wells being shut in because you're on the low end of that economic curve, and you do production being shut in. That first 1% of production we shut in is about 5% of our wells. So that just gives you some perspective and color. And when people talk about shutting in wells, they use all kinds of descriptors, whether they're temporarily abandoned with a bridge plug or just turning off the artificial lift or things like that. And we're definitely doing this in a way that ensures we protect the reservoir and the well integrity and also that we can start back up at the lowest possible cost. So your question about midstream, we can go through this offline in a lot more detail because, as you know, that business has a lot of moving pieces. But the primary difference in the Q2 earnings estimate versus what we saw in Q1 is almost entirely timing-driven. We recognized a large mark-to-market gain related to our hedge position. And as prices fell at the end of Q1, that impacts Q2. So in Q2, the same low prices are impacting the revenue we'll realize on our physical barrels when they're delivered. We can talk through that more offline, but that's the primary driver of that change.
Leo Mariani:
Okay. No, that's helpful for sure. And I guess just second question here in terms of philosophy. I was just trying to make sure I'm sort of reading it correctly in terms of what Oxy's plan is for the next couple of years. It sounded to me as though, just given the pending '21 and '22 maturities, that the company is going to continue to focus on just mitigating declines until there is much better line of sight for taking care of a lot of those maturities or for actually taking care of them with refis or exchanges or whatever. Just wanted to make sure I'm sort of understanding that correctly, if that's the message you guys are trying to deliver today.
Vicki Hollub:
It depends on the price environment, but primarily this year, it will be a decline mitigation. Going into 2021. It depends on how strong the recovery is and what prices we see in 2021. There's the potential that we could add a few more rigs back. But it would still be a scenario where we need to generate some free cash flow as well. So we would balance what were the activity level with achieving some free cash flow generation after capital.
Operator:
Our next question comes from Josh Silverstein with Wolfe Research.
Joshua Silverstein:
As part of the debt paydown strategy, and I'm sorry if you touched on this before, but would you consider equity as part of this as well? It looks like at least the base plan right now is to pay the preferred with $200 million in shares each quarter. So why not just do a larger equity deal to help derisk the balance sheet right now?
Robert Peterson:
No. We did touch on that a little earlier. And the share prices, we don't have an intention on issuing any additional equity to pay down debt.
Joshua Silverstein:
Got it. Okay. Sorry about that. And then you mentioned the $5 billion credit facility that you have available right now. How much of that can you use to pay down debt right now? And then secondly, you had an asset sale target before that was used to pay down debt. You guys now have an absolute debt reduction target of where you wanted to get to?
Robert Peterson:
So we can draw on the credit facility at any point in time. We're not drawing on it because we don't feel like there's any risk of drawing out at any point in time that we need it. In terms of a debt structure, a total debt number to get to, the goal is ultimately over time to get back to an investment-grade type rating. That's what our current path is.
Operator:
Our next question comes from Jeanine Wai with Barclays.
Jeanine Wai:
I just wanted to follow up quickly on Josh's question right now. In terms of debt management and the revolver, right now, I believe it's unsecured, and I don't think there's a trigger on it just because you're going from IG to high-yield status. But do I have that correct? And do you anticipate that sometime down the road that you might need to move to an RBL facility that might have a leverage covenant as opposed to a current debt-to-cap covenant?
Robert Peterson:
Jeanine, you do have that correct on the current RCF facility, and we don't see a need to go an RBL type facility.
Operator:
Our next question comes from Richard Tullis with Capital One Securities.
Richard Tullis:
Going back to the midstream quickly. I know you guided pretax losses the first half of the year, partly driven by the timing issues that Jeff just discussed. What do you see as a more normalized yearly pretax income run rate for that business going forward?
Jeff Alvarez:
Richard, this is Jeff. I'd put that in the category of, we didn't guide full year. So I mean that, there's just so much volatility in all of those markets that we didn't feel comfortable providing guidance beyond the quarter until we see more clarity on how things play out from a recovery differential standpoint and all of that. So we'll defer that. I would tell you, I mean, you understand the building blocks of the business or assets that go into that in the Middle East and cogen and some of the other things, those are still there and still good assets. So they're there. It's just the volatility around all the other aspects on the marketing side.
Richard Tullis:
Sure. Fair enough. And as a follow-up, if Total does not move forward with the Ghana acquisition, do you see almost immediately putting the asset right back on the marketing sale block or maybe you're doing that now? And then secondly, are there other assets that maybe you weren't looking at divesting at the time of the Anadarko acquisition announcement that maybe you look at now in a better commodity environment just given the difficulties closing the Algeria deal, et cetera?
Vicki Hollub:
I would say yes to that. Ghana is an asset that we still consider to be up for sale. Whether Total buys it or not, it would still be up for sale. And there has been some interest in it. So that's something that we would still pursue divesting. I think I said earlier, but let me reiterate that. At the early beginning of the year, when we looked at Algeria and Ghana's divestiture targets, we wanted to have an alternative. And the alternative that we came up with would deliver similar proceeds with a similar reduction in cash flow. So we started marketing in early this year an alternative to the sale of Algeria and Ghana. We started that process. And as we got into the process, all the travel restrictions were applied. And this is one of those things where we need people to come in and we need to do management presentations. We need to dive into details with the technical team that's assessing the value of that asset. So it's one that requires a little more interaction. So we have put that on hold right now as we wait for travel restrictions to be lifted and for the environment to get better. But we do have other assets to sell. The alternative that I'm talking about is just one. There are other things that we can do with some of the acreage in the Permian and potentially even in the DJ with respect to, even if it's not outright sales, it's JVs where we could generate some cash upfront and then a potential carry. There are lots of other options, but what we don't want to do is do it in this environment. It really depends on when the recovery occurs, how strong it is as to the timing of those. And that's why we're not going to put ourselves in a situation where we get closer to debt maturities and then where we found we can't execute the divestitures before the maturities occur. We've still got asset sales that we can do and we'll do as they make sense to do, but we're going to make sure that we can get maximum value for those.
Operator:
In the interest of time, this concludes our question-and-answer session as well as today's conference. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good morning, and welcome to the Occidental's Fourth Quarter 2019 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Elisa. Good morning, everyone, and thank you for participating in Occidental Petroleum's Fourth Quarter 2019 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Ken Dillon, President, International Oil and Gas Operations; BJ Hebert, President of Oxychem; and Oscar Brown, Senior Vice President, Strategy, Business Development and Integrated Supply. This morning, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this morning. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good morning, everyone. The integration of our business into one Cohesive Oxy is progressing extremely well. We are ahead of schedule to fully capture value from our $2 billion synergy program. We have repaid approximately 1/3 of our debt related to the acquisition, and we have the best people in place to leverage our superior assets to deliver outstanding operational results. As many of you may know, 2020 marks Oxy's 100-year anniversary. Success of Oxy's first century was driven by technical expertise, the ability to adapt quickly and our ceaseless drive to lead our industry forward through innovative problem solving. These same attributes, combined with our unique and defining approach to sustainability in a low-carbon world, will be integral to ensuring our leadership and success over the next 100 years. Before I touch on the fourth quarter and value-capture progress, I'd like to thank our remarkable employees who continue to work hard and responsibly deliver excellent results, whether their focus is on drilling the best wells with industry-leading capital intensity, operating our chemical plants efficiently, maximizing product margins or delivering on our value capture and deleveraging targets. Our teams continue to lead with passion to drive positive results. Every day, our people demonstrate that they are exceptional at what they do, while achieving the best safety performance in our history. Moving to Slide 3. As an innovative and sustainable energy leader, we intend to be at the forefront of our industry. The opportunity before us is immense, and our teams are energized and ready for the challenge. Our technical expertise, particularly in subsurface characterization is a competitive advantage that allows us to maximize the value of our assets. All of our core assets are free-cash-flow positive and maintain dominant positions in the prolific basins or markets in which we operate. Our focused portfolio includes multiple decades of high-return short-to-medium cycle development opportunities with primary, secondary and tertiary recovery options. The short cycle, high-return nature of our unconventional assets, combined with our low-decline conventional assets provide the flexibility to allocate capital to maximize cash margins, especially when taking into account our advantaged midstream position. Leading the industry as the low-cost operator has always been important to us as this metric will become progressively relevant in the years ahead. As secondary and tertiary methods become more attractive in recovering additional barrels from basins currently and primary recovery, our advanced technical excellence and decades of industry leadership in CO2 enhanced oil recovery position us to be the lowest-cost operator across multiple basins. As the assets we acquired are developed, we will utilize our subsurface and operating expertise to improve productivity and reduce full-cycle cost. Our diversified portfolio with decades of high-return inventory and our ability to produce high-margin barrels, enables us to generate sustainable free cash flow to return to our shareholders. Foremost, in the form of our dividend, which is one of the defining characteristics of our company. As an innovative and sustainable leader, Oxy must boldly drive improvement on all fronts, including reducing emissions. Our commitment to sustainability is woven into the fabric of our organization. I'm proud that we were the first U.S.-headquartered oil and gas company to endorse the World Bank's initiative to reduce routine flaring globally. This important effort is fully aligned with our strategic commitments. We plan for the future through lense of being a best-in-class operator with an unmatched portfolio of assets and the goal of reducing our greenhouse emissions while executing our strategy to excel in a low-carbon world. Now moving to Slide 5. The fourth quarter was our first full quarter as a combined company, and we continued to demonstrate our position as a best-in-class operator. Our businesses outperformed across the board. Our production of 1.4 million BOE per day from continuing operations exceeded the midpoint of guidance by 78,000 BOE per day. We accomplished this while spending $400 million less than our full year combined company capital budget of $8.6 billion. This demonstrates that our long-standing commitment to capital discipline remains paramount. Pro forma production for full year 2019 also exceeded guidance by 28,000 BOE per day. And we expect to grow production by 2% in 2020 off this higher base, and we've lowered our already reduced 2020 capital budget by another $100 million. Spending less to produce more barrels demonstrates our industry-leading capital intensity and the value we will create for shareholders. That said, as global commodity prices have declined sharply in recent days, we are prepared to reduce our spending if the current environment does not improve. We are monitoring the situation closely and retain the flexibility to adjust our budget if needed. We continue to execute on our divestiture program. In January, we closed the sale of our South Africa block to Total for net proceeds of approximately $90 million. This follows the close of an aggregate of $1.5 billion in divestitures in the fourth quarter. We applied the proceeds from these asset sales and $500 million of free cash flow to repay $2 billion of debt, and we recently announced our 182nd consecutive quarterly dividend, an outstanding record that few companies can claim. Returning cash to shareholders through our sector-leading dividend is an integral part of our philosophy. In the fourth quarter, we returned approximately $710 million of cash, an amount we fully expect to continue to grow. Moving now to Slide 6. We continue to perform -- outperform expectations and capturing value through synergies. Since closing the acquisition and on a run-rate basis, we have completed 60% of our $2 billion synergy target since closing the acquisition, including $799 million of overhead synergies, $83 million of operating synergies and $323 million of capital synergies. We expect that our success in lowering cost will enable us to fully achieve our $900 million overhead synergy target in 2020, a year earlier than originally promised. We also have announced divestitures totaling $10.2 billion net of taxes since closing the acquisition, demonstrating significant progress towards achieving our target of $15 billion. We repaid 32% of the debt raised for the Anadarko acquisition with proceeds from the divestitures closed to date, along with the $500 million in free cash flow that I referenced earlier. Our total balance sheet debt has decreased by approximately 30% since the close. We repaid $7 billion of debt in the second half of 2019 and have a clear line of sight on closing the remaining transactions necessary to meet our divestiture target. Operationally, our achievements are as significant as our cost reductions with the potential to accomplish much more. Moving now to Slide 7. As an example, let's look at what we have accomplished on the legacy Anadarko, Texas Delaware acreage. We are recovering more barrels per section with fewer wells and are lowering cost by applying our unique subsurface capability and development approach. Similar to the advancements we made on legacy Oxy Delaware acreage. Already, we have drilled a record well in the Silvertip area, showcasing our ability as a premier operator in the Permian Basin. We are enhancing our best-in-class Permian capital intensity by continuously improving time to market. We drilled our first five 10,000 foot wells in Silvertip, 18% faster than those drilled prior to closing the deal, and this is just the start. We have many more improvements to implement. We are already saving $1.9 million per well completion by utilizing Oxy's advanced Atlas casing design. We're able to pump frac stages, particularly at the toe of the well at much higher rates with lower trading pressures. Our completion design produces improved stimulation, faster pump times and uses significantly less water. Put simply, when including the optimized well count, we are spending 26% less in total capital to recover 7% more oil. Oxy's asset operability is unmatched and has greatly improved across the acquired assets by applying our base management expertise and best practices. Our relentless drive for efficiency has reduced production downtime by 22% on the acquired Delaware Basin acreage. We're also seeing downtime improvements across many of the other acquired assets, which is further improving cash flow and value. Additionally, we are working diligently with our partners and leaseholders to significantly reduce obligation wells and short laterals, allowing us to maximize value by focusing near-term activity on long-term development in our core areas. As we had committed to do, Slide 8 shows the measures we'll update each quarter to track the success of our progress. We have created the company with ample opportunities to efficiently allocate capital from a position of strength across the portfolio with sector-leading returns. We have made significant progress in divesting assets, reducing debt and capturing synergies. As part of our commitment to creating long-term value for our shareholders, we will continue to reduce debt, strengthen our balance sheet and enhance our ability to return even more cash to shareholders. I'll now hand the call over to Cedric, who will walk you through our financial results and guidance.
Cedric Burgher:
Thank you, Vicki. I'm also very pleased with how well our integration is proceeding. Completing our value capture program ahead of schedule is well within hand. And as Vicki mentioned, our teams are delivering outstanding operational results. As our integration progresses, we remain steadfast in our commitment to capital discipline and returning capital to shareholders. We demonstrated our ability to excel operationally in 2019, while spending $400 million less than our combined capital budget of $8.6 billion and lowered our operating costs on a BOE basis. Our capital intensity and value-capture advancements have enabled us to lower our 2020 capital budget by $100 million to $5.2 billion to $5.4 billion for the year. Since closing the Anadarko acquisition, we have strengthened our balance sheet by repaying 32% of the new debt raised, and we will continue deleveraging as additional divestiture transactions are closed. We have already achieved 60% of annual run-rate synergies, and I am confident that our 2020 financials will illustrate the progress we are making. In 2020, we expect to fully capture $900 million of overhead savings, meeting our target a year earlier than originally stated. Furthermore, we expect to capture more than 75% of our operating and capital synergies this year. In 2020, we remain focused on maintaining our dividend by optimizing free cash flow and operating in a capital-efficient manner. We have implemented a significant oil hedging program for 2020, encompassing 350,000 barrels per day, which represents over 45% of our oil production. This will enhance cash flow in a low oil price environment. As we have previously mentioned, it will be a transition period before our financial results fully reflect our rapidly improving operational performance and synergy realizations. In the fourth quarter, we announced an adjusted loss of $0.30 per diluted share and reported a loss of $1.50 per diluted share. The difference between adjusted and reported results is mainly due to a $1 billion loss reflecting Occidental's equity investment in WES at fair value on December 31 as well as $656 million of costs related to the acquisition. Turning to our business segments. Oil and gas adjusted fourth quarter income of $630 million represented an increase compared to the prior quarter, primarily due to a full quarter of production from the legacy Anadarko assets, and partially offset by lower international crude oil volumes as our contracts in Qatar terminated in early October. OxyChem surpassed guidance with fourth quarter income of $119 million despite scheduled plant outages and softer overall demand, which lowered production and sales volumes across many product lines. Marketing and midstream adjusted fourth quarter income of $200 million, which includes WES, decreased compared to the third quarter due to noncash mark-to-market losses, the tightening of the Midland to MEH differential and lower equity investment income due to the sale of our Plains units in the third quarter. For the fourth quarter of 2019, we reported a balance sheet without consolidating WES. Starting in the first quarter of 2020, we will present our full financial statements without consolidating WES. For the first quarter and full year 2020, we have provided guidance, which includes annual production growth of 2%. First quarter production guidance reflects planned downturn -- planned turnarounds at Dolphin and Al Hosn as well as the timing effects of several large pad developments in the Permian Resources. As we continue to reduce debt in 2020 by applying asset divestiture proceeds and free cash flow, we will update the debt reduction tracker in our earnings presentation, so investors can see our progress towards our divestiture target of $15 billion net of taxes and in deleveraging. I look forward to providing future updates on our progress. I'll now turn the call back over to Vicki.
Vicki Hollub:
As Cedric said, we will provide updates over the next few quarters as our continuing improvements and enhancements become increasingly evident. For decades, Oxy has proven its ability to innovatively recover more hydrocarbons from reservoirs. We have the technical expertise to operate and develop our unique portfolio of high-quality, short-to-medium cycle assets that are perfectly positioned to ensure we will maintain our leadership as a low-cost operator. This strengthens our ability to continue our long and steady track record of returning excess cash to shareholders. This, combined with our differentiated low-carbon strategy will ensure our success and sustainability into the future. We'll now open the call for your questions.
Operator:
[Operator Instructions]. The first question today comes from Doug Leggate of Bank of America.
Douglas Leggate:
Vicki, I've got two questions, if I may. The first one is on disposal progress. Obviously, there is a fairly significant macro change underway right now. I'm just wondering, your November 14 press release suggested line of sight to the upper end of your $15 billion target by the middle of this year. So I'm just wondering if you can give any color or confidence to reiterate that timeline and that target. Any color on the associated assets? And specifically, an update on Algeria and Ghana, where there seems to be some mixed news on whether the buyer is still -- has the appetite for those assets.
Vicki Hollub:
Okay, Doug, I'll let Oscar actually give a full update on our divestitures.
Oscar Brown:
Great. Thanks, Vicki. Doug, so regarding -- we'll start with Africa. Regarding Africa, of course, we continue to work with Total and the governments of Ghana and Algeria towards a positive resolution of the divestitures. So there is an increased risk, as you point out, associated with both timing and closing certainty, so that's become clear. We'll report more when we have something more substantial to talk about. And just to be clear, it's hard to comment beyond what's public already. In Africa, as again, we remain bound by our definitive agreement with Total around these assets, but we're also cognizant that these assets, to these countries are very important to them and their interest in retaining foreign investment is very sensitive in -- to all their constituents. So we want to be careful with that. But a couple of things I think I can say. As you probably know, the assets in Ghana and Algeria are very high quality, produce significant cash flow and we've used that to pay down debt as well. In the case of Algeria, the -- I guess, the one thing I can observe, which is obvious, is that since our -- the announcement of our deal with Total, Algeria has voted in a new president, has brought in a new administration. So that situation, in particular, is pretty fluid. So as we -- if you look at all that, we continue to run numerous sales processes as our commitment to hit the $15 million of asset sales hasn't changed, and that is something we'll hit with or without the remaining Africa divestitures. So a great example that's come up again, we really like to keep these processes private. We found that's the best way to protect value, but another asset sale, as an example, to address your broader question that is in the press is the land grant. So that asset is primarily in Wyoming. There's been some press on that. It has over 1 million surface acres and over 4 million mineral acres and includes revenues from producing royalties, primarily from trona, but also from oil and gas, coal, other hard minerals and surface use, such as wind farms and grazing and so forth. So while the state is clearly communicated a lot of interest in this asset. It is a competitive process, and there's a large number of qualified participants in that. And the winner of that asset will be one of the largest land and mineral owners in the United States. So that's an example, again. We don't want to list off a whole lot of those ideas and other things that we're actually pursuing. But we do think -- we do -- we're going to get to our $15 billion. And everything we do, it's really important, too. As it relates to timing, we're focused on value. And we understand in this market environment, our timeline may need to be a little flexible to protect that value. But we still stick by our original announcement, original schedule we committed back at the announcement of the Anadarko deal. 12 to 24 months to get these transactions done from closing. We're about 8 months in since the acquisition, and I remain confident we'll get to the $15 billion within the original time frame. So again, we're focused on value. We're focused on certainty of closing in terms of dealing with counterparts and all of our divestitures. We're still confident because, look, we've got -- as we've mentioned, over $100 billion of assets in our portfolio. We've got a good team and a good track record of success. So hopefully, that helps give a little color.
Douglas Leggate:
That's very thorough. My follow-up, Vicki, is really just on the synergy number. And first of all, pretty rapid progress on getting the operational synergies done. I know it's only, I guess, Oscar said 8 months in. But I can't help but ask, well, you're -- you've obviously done it quicker. I'm wondering if you're seeing other things. There's a potential to reset that synergy target at some point. And if so, and what time? I'll leave it there.
Vicki Hollub:
I think, certainly, we can reset the synergy target at some point. But now we're focused on making sure that we capture the synergies that we have that we've outlined as a goal. And I can tell you that progress has been actually amazing. And I want to emphasize that part of the reason for that progress is that we got the structure done and completed pretty quickly. We -- as you know, we've been working on our own company, our own organization and our own approach to business and to Shell versus EOR and all the other things that we do. We've worked on and optimized those over the past few years. So we had a business model that we felt was working well for us. So we brought the Anadarko assets into our structure and have now started working with their business units. We rolled the Gulf of Mexico up under Ken Dillon, who manages our international operations and major projects. He has the most offshore experience of any of our leadership team. So he's managing those, brought in some good Oxy people, but most importantly, we retained an incredibly good the Gulf of Mexico team from Anadarko. And then the Rockies business unit, we created the business unit there and just brought it under our domestic operations under Robert Palmer's leadership. And so the -- bringing the organization in was one thing that we did right off the bat. But the second thing that we were able to do very quickly was to start to work the culture. And fortunately, we found that culturally, the Anadarko employees that we brought with us and kept were -- had the same or similar culture to what we have. And I credit Jim Hackett for that. It's just been really good to bring those guys in. And part of the thing that has driven the synergy capture so quickly for us, too. It's not just the amazing and outstanding performance of Permian Resources, and they're certainly ahead of schedule there. Thanks to Jeff Bennett and his leadership, but it's making sure that this was a process that we owned. Some companies will bring in consultants and use them throughout the process. We have an internal team working this and full of -- and then composed of ambassadors that are working throughout the organization, and they're the ones that go out and help to ensure that our business units and teams know where we are, know what the goals are, know the specific numbers, we're tracking them weekly. Our board is very engaged on those 2. We actually have a board that's -- has an integration committee led by Dick Poladian, and Dick has done a great job to drive -- dive into the information and be a part of that team, driving progress very, very quickly. So culturally, organizationally, we're there. The synergies are coming sooner, but other things are happening in our other business units. They may -- we may not call it a part of the synergies. But there are good things happening elsewhere where we're continuing to advance our technical capability, some of that in our own operations, and some of that in the Anadarko assets that we picked up. So I'd like to just kind of turn it to Ken Dillon for him to cover some of those. I think you'll find this as -- these are some of the things that will quantify over time and share with you, but these are the kinds of things that we're working on.
Kenneth Dillon:
Thanks, Vicki. If we talk a little bit about Gulf of Mexico synergies with renegotiated contracts to date, we potentially see between an 8% and 15% reduction this year in the cost of the capital program. We've started to roll out Oxy Drilling Dynamics, and we're already making savings on the first wells with optimum sequencing. We expect a reduction in shutdown durations of 20% this year. The Oxy maintenance programs will lead to a further 20% improvement next year in uptime. And recently, we were delighted that members of the Oxy Board of Directors visited the Deepwater Horn Mountain spar to emphasize commitment to HSE per staff and our contractors offshore and this follows their visit to Safa' in the desert in Oman last year. Moving to Oman. We saw records this year in block 62 of 29,000 BOE per day, and we've developed new tools in-house for something we call Oxy jetting. It's a new completion technique, which we piloted on 15 wells. So far, we've seen improvements of between 200% and 300% on IPs of new wells for an increase of 5% in the D&C costs. It's not tracking, and I'm looking forward to being able to talk more about it on future calls. We previously talked about the Oxy field optimizer in Mukhaizna. So our high-speed reservoir models are now running in the cloud. And the system is making actual recommendations for steam allocation at Mukhaizna to the engineers. In the pilot area, which covered 3% of the field. We saw increases in oil production of about 1% with a decrease in steam of 14%, and we continue to increase the pilot area. In Colombia, we increased the production at Llanos by 17% year-on-year, and we kicked off the Teca continuous steam flood project. So far, we've drilled 16 wells, and we're optimizing the development plans with our good partner, Ecopetrol. In exploration, our teams delivered 52 million barrels of resources at a binding cost of $3 a barrel in 2019. So if you look over the last 3 years, they've added 200 million barrels of resources to our portfolio. Abu Dhabi, we saw a record production at Al Hosn of 86.6 MBOE per day as part of our winter plant trials. And on schedule, we awarded the feed this quarter to AMAC in the U.K., so we're on track for increasing capacity to 1.45. So overall, a good year with the HES performance, peak production and continue to innovate and break records.
Vicki Hollub:
And just one last thing on the divestitures. Remember, we're repaying 3% debt with proceeds and have no 2020 debt maturities. So while we share, certainly our investors' sense of urgency around lowering the debt. We do have flexibility as it pertains to retaining cash flow, for example, the Africa assets are generating right now around $700 million of annual cash flow at $60 Brent. So we do have some flexibility with that.
Operator:
The next question comes from Paul Sankey of Mizuho.
Paul Sankey:
Vicki, the investment case for oil is really very much about the dividend and no less at Oxy. Can you reassure us that it really is your highest priority to keep paying the dividend that the environment being as difficult as it is? And would you actually be -- want to cut CapEx in order to keep paying it?
Vicki Hollub:
Thanks, Paul. Yes. Our dividend policy is what it's been for the last probably 20 years are. And we approach it based on our cash flow priorities, which is, first, to maintain our operations. And after maintaining our operations, certainly, it's the dividend and capital share repurchases, those things come after that. So we do have the flexibility to do other impacts to our cost structure that -- to continue to pay our dividend. Our intent is to balance our cash flows, but we -- again, with the flexibility of this enormous portfolio that we have today with the things that our teams are doing to drive efficiencies and improvements and cost reductions. We're actually in a good scenario, I think, because we don't expect this situation to last, but we can last through this situation.
Paul Sankey:
Understood. And just to be clear, could you talk a bit more about your flexibility to cut? I mean, at the moment, you're growing, obviously, you could conceivably go growth flat or growth negative. And if you could just talk about some of your flexibility because it is important for people. Secondly and finally, could you just reiterate on the divestment program, because I think that's the other very important thing to people? Obviously, you've gone through it line-by-line. But to be clear, you're reiterating that by midyear, you will have done the $15 billion. Is that what I've read or already said, sorry, then seen re-reported online?
Vicki Hollub:
I'll address the dividend first, and you're right. We have built a scenario around currently -- certainly, the environment we're in. We don't know how long the -- this coronavirus impact will last. So what we've done is we've actually initiated our business continuity plans. And we started to look at various scenarios and what we would do in a situation where this looks to be lower for longer. So we have the flexibility to first lower our growth to no growth. Beyond that, we have the flexibility to go even lower than that and still maintain our production. So -- and beyond that, we -- I think we've said in the past that because of the high-growth assets that we have, we could actually allow our production to decline a little bit. If we're in a scenario where the lower prices are being driven by an event, and this is that case. Because remember now, prices were $55 or above before the coronavirus hit. So we believe that this is not a scenario that's going to last for so long that it would put us in a scenario that we can't deal with it -- with the situation that we have. So we've got those scenarios built in, and we've got time lines on when we would make decisions and pull triggers. So we're well prepared to address this. And with respect to the divestitures, we're very confident that we will achieve the $15 billion. But given the scenario we're in today, I think every company is now looking at what their plans are. And trying to decide what do you do in this scenario? And what are the things that will -- that you should start to adjust? We believe that we will achieve the synergies but I'm going to pass it Oscar. But I believe that some of the situations that we're in right now, our timeline could be impacted by just the fact that some of the interested parties can't travel. They can't leave their countries. And so there are some travel impacts that could have -- could lay some of what our interaction with counterparties would be. Oscar do you have more on that?
Oscar Brown:
Yes. I think that's totally fair, Vicki, and you summed it up pretty well. So we've got -- what I'd say is we've got line of sight to midyear and the processes we have going, but we've got to be cognizant of this environment whether it's travel, the volatility of the commodity, all of that. I think, again, we're focused on value. So the timing needs to slip a little bit to protect that. I think it's understandable if we look for that flexibility, I think you'd agree.
Vicki Hollub:
But I would say that if we believe that we still -- we'll still work the process with Algeria and Ghana, but we do have a plan Bs, as Oscar alluded to, we can go to plan Bs and replace the proceeds we would have gotten from Algeria with other asset sales that essentially have about the same cash flow impact.
Operator:
The next question comes from Devin McDermott of Morgan Stanley.
Devin McDermott:
So I wanted to build on some of the questions that were already asked around synergies, specifically. And I was hoping if you could comment on, given the reduction in capital spend that you've already made here for 2020 versus the original plan and the fact that you are on track to you -- achieve your synergies ahead of the original schedule, how that impacts the kind of capital budget ranges for 2021? I understand it's far out to give preliminary guidance there, but you previously talked about $6.6 billion of spend for 5% growth. And then also talked about a maintenance CapEx scenario there. How have those ranges? Or how has that range changed based on what you been to achieve so far in terms of synergy realization?
Vicki Hollub:
Well, the $6.6 billion that we said with a 5% growth was based on the synergies that we expected to capture in that timeline. And as you just said, the timeline has been accelerated. So we have not laid out what the scenario would look like yet, and we're working that. But we -- we're certain that, obviously, that we get the 5% at $6.6 billion, but we do believe that there's the opportunity that we could get to 5% with -- certainly, with a lower capital. We just haven't calculated that number. What we'd like to see is how some of these other ideas and opportunities play out. So we're -- I would just say that now, I'm pretty excited about 2021 and about what we can do based on what we're seeing today.
Devin McDermott:
Got it. Great. That makes sense. And I wanted to ask as my second question, a bit of a longer-term one, and it relates to some of what you're doing on the Low Carbon Ventures front. And I think Oxy is in somewhat of a unique position, given the large CO2 enhanced oil recovery business you have. And I like the proactive approach with the Low Carbon Ventures and work to use anthropogenic CO2 in that business. But I was wondering if you could talk specifically to the opportunity set that you see there, kind of the return profile of some of those investments, and how you're thinking about that fitting into the business in a more meaningful way longer term.
Vicki Hollub:
Longer term, we actually think that, that's going to be a business that will generate significant cash flow and earnings for us over time. With what our team is seeing today, there's a lot of interest in partnerships with companies that don't have the capability to otherwise lower their carbon footprint. So there are a lot of situations out there where that exists. For competitive reasons, I can't talk specifics here. But I will say that, that there is now so much interest in -- by all types of companies that this is going to be a scenario where we have partners that come in and invest and/or we can sell ultimately CO2 offsets. And we can generate our own electricity cheaper to also provide CO2 for our operations or we can provide electricity to others through the technology that we've invested in today. So with the combination of anthropogenic from industry with net power generating lower cost electricity for our CO2 operations, while also providing the CO2 for our operations. And then the the direct air capture, which is a process that we're doing a FEED study on now, and we'll ultimately start construction, we believe, late 2021 or 2022. With all of those, plus the interest and others to come in and invest and/or buy offsets, it's -- there's lots of opportunity for us to start making that a business line. And at this point, I really can't say more than that. But we will -- as we can, we will share much more information. And I think by the end of the year, we'll have a lot of exciting things to tell.
Operator:
The next question comes from Ryan Todd of Simmons Energy.
Ryan Todd:
Maybe a couple of follow-ups here. I mean, you've talked a lot about divestiture program and about, I guess, maintaining the dividend there in this period. I mean, what do you see as the trade-offs or the downsides of just -- I was just targeting maintenance CapEx until debt is reduced to a certain level on a multiyear basis. How do you view the trade-offs between modest growth you're targeting over the medium-term versus the potential to pull forward debt reduction? And maybe the trade-offs of the benefits of targeting a larger -- the larger divestiture program to get the debt down faster and be in a position where you can start to talk about distribution growth?
Vicki Hollub:
Well, I think Oscar could say a little bit more about going beyond the $15 billion here in a minute. But to start with, I would say that our -- we do want to get our debt down. We want to get our debt down to -- at a $60 WTI to be about 1.5% ratio, but in doing that, remember now, our investment in organic growth delivers incredibly good returns. So what we're trying to balance is delivering returns to our shareholders while repairing the balance sheet. We think we can do both. And so we're working to do both over time, and the divestitures are really what we are targeting to help to lower that debt a lot faster and with what we have in the portfolio, we believe we can do that. Oscar, if you want to make a comment or two?
Oscar Brown:
Yes. I guess, just simple math. So we said, clearly, we've got processes ongoing or prepared to launch well in excess of $15 billion, whether or not we close on Africa. So to be clear, we do have -- we've kind of done what you're suggesting, right? We've got a lot more in the market than we need under really any scenario just for this purpose to be competitive across assets, be able to pull deals that we don't like, to sell things we do like. The land grant is an interesting one, where it's relatively immune from volatility in the oil and gas price. Its value is elsewhere. And so these are kind of things we'll try to accelerate. So clearly, where we can protect value moving forward, we're moving them forward. And where this volatility, if it slows down a couple of them, it slows down a few of them. So it's a portfolio approach, and it's a big effort.
Ryan Todd:
Okay. And maybe one, you have a slide in the presentation where you run through the kind of the multiyear timing outlook on a number of your conventional assets around the world. What sort of timing requirements do you have on the various conventional assets globally? I mean, is there a limit to how far you can defer activity in places like Oman, Abu Dhabi and Colombia?
Vicki Hollub:
We are currently meeting all of our commitments on all of our international conventional assets. So I think we're doing a very good job of that. We work very closely with the governments and our partner companies in those areas to make sure that we're delivering what we said we would do, and we optimize where we can, and some of the activity that Ken talked about in Oman, in particular, is delivering better results with less capital than we had originally anticipated. So I think that we're doing well with all of our conventional asset commitments.
Kenneth Dillon:
Yes, it's Ken here. I think I walked through quite a few of the ones on the sheet earlier. I think we're on track for 2019, 2020, 2021. And we studied the well in Abu Dhabi. Things are going well there, Shah expansion, our Al Hosn expansion is going well. White Energy project is moving ahead, target 40 million scalps per day. It's in design with a company we like working with. We've got plenty of places to put the CO2, which takes you through the 2020-2021 timeframe. In Oman, seismic has gone well. We're interpreting the 3D seismic we captured last year on the main blocks. Exploration wells. We've got a 75% technical success rate there, just under 50% commercial success rate and our binding costs are about $3, barrels. That's going well. So overall, I think for all of the items listed, Colombia, we kicked off Teca. First 16 wells, drilling costs coming down facilities, well mapped out, moving ahead. I'd say, completions, we're working jointly with EcoPetrol. And then we're getting ready for the Teca ramp up. So I would say generally meeting everything on that Slide 21 in terms of dates, which is the on-time, on-budget is one of our mantras.
Operator:
The next question today comes from Paul Cheng of Scotiabank.
Paul Cheng:
Vicki, just curious that, once that you get your debt under control. Is there a target ratio of how much is the cash flow you want to reinvest, and how much is going to return to the shareholder? I'm not talking about the next month or 2 years, obviously, the way the debt repayment is going to be the priority, that may change it. But in the longer term, how should we look at the business model? How you're going to use on the cash flow? Is there a ratio that you are targeting?
Vicki Hollub:
Well, under the scenario that we're working today, you can model it that. We were assuming that a 5% growth is the cap of where we really feel like we need to be over time. So the -- no matter what the oil price is, whether it's $70 or $80, we don't think that we need to have more than a 5% growth. So the excess cash beyond what we need to invest organically to deliver that growth would go to generally the share repurchases or other investments like that. But from a capital standpoint, growth standpoint, we think 5% is sufficient. So I don't know what our ratio, it will change over time, actually.
Paul Cheng:
Okay. And the net is under, say, call it, $55, $60 Brent price, what will be the target growth rate for you guys then?
Vicki Hollub:
$55 to $60 is still the 5%. We're not going to adjust and run our capital -- our organic capital investment up as oil prices go up. We're really going to manage the business at an optimum investment rate. And that investment rate generally will deliver that 5% growth. And so we don't want to get ahead of ourselves with respect to maximizing net present value of our developments.
Operator:
The next question comes from Pavel Molchanov of Raymond James.
Pavel Molchanov:
When you said a few months ago that you will reduce your stake in Western midstream to less than 50%, the yield on Western midstream units was maybe 10% or so. To date, it's almost 20%. Given how distressed those units are trading, does it make sense to divest any of them under current conditions?
Oscar Brown:
It's Oscar. I'll take that one. No. Generally, no. But -- that's a short answer. But clearly, we've got a commitment in terms of what we've done and then standing less up independently and deconsolidation and all of that, where we do need to get below 50%. But we do have timing flexibility on that as well. It's not something that necessarily needs to be done right away. But we agree, we're the largest shareholder. We pay the price as much as anybody more. So probably, so some patience around that is clearly something that would make sense.
Pavel Molchanov:
Okay. One more on the decarbonization aspect to the story. Most other companies that have put out a net 0 target have given a timetable, 2050 or something else. Realistically, when do you anticipate being ready to give a timetable for your net 0 status.
Vicki Hollub:
Our teams have already worked out a fairly detailed strategy around getting there. In fact, this strategy that they worked is not an aspirational goal. It's the outcome of a defined program, where we actually have on a time line milestones for the development of direct air capture anthropogenic CO2 and the installation of net power over time. So the last I saw that -- and we're not saying this is a target, but the last I saw of what that would deliver, well, it looks like in the 2040 to 2045 timeframe, we would be carbon neutral.
Operator:
The next question today comes from Brian Singer of Goldman Sachs.
Brian Singer:
I wanted to start with a couple of follow-ups on questions from earlier. First, with regards to a lower commodity environment, given the low-cost of debt from your financing round last summer. How would you weigh going to no growth going to decline versus taking on additional debt to keep the dividend sustained? And then separately, since you brought up the land grant, can you characterize where you see free cash flow coming from there right now?
Vicki Hollub:
I would say that we will not take on debt. We don't feel the need to do that. We think that with the flexibility that we have in almost any scenario, especially given the fact that we've hedged 350,000 barrels a day. That, along with the fact that $40 oil is just not sustainable for our industry over time. So we have the time to work through this, and we would actually allow our production to decline a little bit because now with the Permian Resources business with the DJ Basin, and even ultimately, the power Powder River, those are very fast production cash flow recovery engines. And so we would have the ability to recover from allowing our production to decline. Remember now, back when we just had conventional assets, that were -- that had a much lower growth profile over time. That would not have been possible. But today, we have that flexibility. So we would not take on debt to pay the dividend. We would -- what we'd do is allow our capital investments, organic capital investments decline.
Oscar Brown:
Real quick, it's Oscar. On the land grant, we haven't disclosed the cash flow associated with it. But the way I think about it is like this, the value inherent in the assets. So again, a lot of surface and a lot of minerals and minerals of all kinds, hard and liquid and so forth, that -- at least as much value is in the optionality and the future development of the -- of that surface in the minerals and just the value of it there as to the value of the current cash flows today. So we do like the potential value of this asset in terms -- while it will have some impact on cash flow, because it has cash flow, we expect the multiple of the asset value to be higher than you'd expect with more traditional asset sales.
Brian Singer:
Great. And then my follow-up is with regards to two plays within the E&P portfolio, the Permian and the Powder River Basin. On the Permian on Slide 28, you highlight the significant increase each year in well performance and wondered what your outlook is for 2020 and the extent to which longer laterals will drive well performance versus other measures? And then just any milestones that you expect in the Powder River Basin this year and now you see that play developing within the portfolio?
Vicki Hollub:
I'd say on the Permian Resources business, I was really surprised. Well I had forecasted the 2019 from 2018 improvement to be in the 5% to 10% range. And you can see they clearly at that. With some of the things that our team is talking about today, differences in the way we do, not just our -- where we've put our laterals, but the way we pump our frac jobs. Going back to the improvements I've made previously. I believe there's still room to further stimulate the near wellbore along the full lateral and to recover more near wellbore reserves. And I think that they can work on some things to do that over time. So I think that -- I'd hate to give a number, but I do expect us to improve. I don't think we'll plateau from 2019 to 2020. I think we'll see improvement this year and improvement going into next year as well. With respect to the Powder River, that's an exciting area. We've done some appraisal work. The team and the sparking Powder Rivers, all legacy Anadarko, they're incredibly good. They've looked at the offset operators, looked at what they're doing. They're now -- they've shared their information with our internal people on the Permian Resources, we're learning things both ways. That team is going to -- that team will make some significant noise in the Powder river, I believe. Once they get started, we won't be very aggressive there this year. We'll pick up activity, probably the -- toward the middle to the latter part of next year.
Operator:
The next question today comes from Jeanine Wai of Barclays.
Jeanine Wai:
This is Jeanine. My first question is on Permian maintenance CapEx. We've had a lot of discussion on that play so far. Can you or maybe quantify how Permian maintenance CapEx trends over the next couple of years? So I mean, we're thinking depending on the growth rate, the decline rates could moderate and potentially facilities-related spending could also decline, and both of those would be tailwinds.
Vicki Hollub:
The way we look at that really is from a capital-intensity standpoint, and we see that our capital intensity right now is down in the low 20s. And so we believe that with the efforts that we can make around optimizing our base production. And designing our fracs so that they are recovering more ultimate reserves from essentially the same sort of designs, I think that the maintenance capital shouldn't significantly increase over time. Jeff, do you have any numbers around that?
Jeff Alvarez:
Yes. I mean, what Vicki said, and Jeanine, I think is what you're getting at is, the maintenance capital, obviously, as your base gets bigger, that drives maintenance higher. But what's going on is, with the lower growth rate, you get a lower decline. And then with what Vicki said, with the capital intensity continuing to improve, we wouldn't expect maintenance capital for Permian Resources to go up significantly even on a much larger base, which normally you would expect that to happen. We shouldn't see that because of the improvements in performance, lower decline. And as you mentioned, we will get lower facility costs with time because you're not opening up new areas or new fronts, you're able to leverage the facilities that are already in place. So that business will continue to get better on that front.
Jeanine Wai:
Okay, great. That's really interesting. My second question is just on activity, and Vicki, following up on your prior comments about willingness to respond to a potentially lower-for-longer scenario. You said that you could go ex-growth or maybe even decline a little bit, depending on the environment. Does that imply that there really isn't any non-D&C CapEx could be pushed off and that reducing CapEx for the year with just all the non-D&C activity. So we noticed that in the oil and gas CapEx budget, facilities and exploration between the 2 of those, it's about 24%. So maybe there's potentially a scenario that you could push some of that off and still kind of keep the machine going.
Vicki Hollub:
Yes. And that would be the first to go. We've tiered our capital so that as we go through this, and we start having to having lower capital, the less productive capital goes first. Now that would mean that there could be a point in the future where our facilities CapEx could be a higher percentage. But given where we are in optimizing our developments in this kind of scenario, that's exactly what we would do.
Operator:
The final question will come from Roger Read of Wells Fargo.
Roger Read:
I guess, one thing I'd like to touch on, if possible, on the Gulf of Mexico on the chart or Slide 21, you mentioned the Eastern Gulf of Mexico exploration discovery, and then obviously, targeting additional exploration in the out-years. As we think about the sensitivity of CapEx in a, call it, lower-for-longer period here with oil prices, where does the exploration need in the Gulf fit in with the general idea that you were going to keep production relatively stable there in the Gulf, sort of that question that's been asked about the Permian and maybe overall in the company? How do you manage constraints on one end with goals on the other and keeping that business on a sound footing?
Kenneth Dillon:
It's Ken. I'll take that one. Essentially, it's not only keeping production flat. It's -- the Gulf of Mexico generates a large amount of net free cash flow. So our goal is really to have a 10-year plan, which focuses on keeping the net free cash flow relatively constant over that time frame. As I mentioned on a previous call, we love Horn Mountain. That was one of our assets originally continues to look better and better. Central gun looks really interesting also. So we see really good opportunities for near-field tiebacks. And we're also participating in ongoing activities where we can consolidate around those areas. So that's -- the goal is maintain long-term steady net free cash flow from barrels, which are really, really high-margin barrels that can compete with everything in the portfolio. And we have great teams, long history, going all the way back to the Oxy in past years ago.
Roger Read:
Okay, great. And then a follow-up question. You mentioned, obviously, the change in the Board structure that's gone on, some of the other things in terms of accessibility for shareholder initiatives and all that. Since the next time you have an earnings call, we'll probably be deep into the proxy season. I was just curious, has there been any change on that front you'd want to comment on?
Vicki Hollub:
Sure. Recently, we announced that Andrew Gould would join our board, that's going to be effective March 1. And we think that adding Andrew complements the addition to Bob Shearer to the board in July of last year. Andrew's decades of operational and financial execution leadership in the industry will further strengthen our Board of Directors. So those two adds were part of a process that we feel like we're really excited about that's brought some new and different experience to our Board. And also as a part of the independent chair succession plan, the board approved last year, Gene Batchelder will step down as chair after this year's annual meeting, and he'll be succeeded by Jack Moore, who is our Vice Chair this year. Accordingly, Gene has indicated that he will not seek reelection to the Board. But I do appreciate Gene and Jack, as they've gone through this process, this has probably been the first formal succession to the chair role that Oxy has ever had. So that process has worked well this year. Additionally, Spencer Abraham has served us for a while now, has indicated to the board that he has decided not to stand for reelection. So we're grateful for both Mr. Batchelder and Mr. Abraham for their contributions and their service to the board. And then the other thing I wanted to highlight is, I already mentioned that the 2 new committees this year I mentioned that Dick Poladian was leading the integration committee. He's also our audit chair. So he's been a big part of helping us structure the metrics and follow the integration and make that as successful as it's been. But -- also, I want to highlight that Peggy Foran has been appointed Chair of the Sustainability and Shareholder Engagement Committee. Peggy's proactive shareholder outreach and thought leadership on key governance issues has earned her, really, the global recognition as a leader in corporate governance, and we appreciate the leadership and expertise that she brings to this committee and to our Board. That committee, we want that committee to help us be much more engaged and further proactive around shareholder concerns and engagement. So with that, what I'd like to do is one last information is to, again, reiterate that, that I'm very, very pleased with the acceleration of our synergies. And those -- that acceleration of synergies was only made possible by the fact that we accelerated the integration of our two businesses. I wanted to pass it to Cedric to talk a little bit about the one-time charges that have occurred and what you can expect in the first quarter, both fourth quarter that you just saw and first quarter coming up?
Cedric Burgher:
Yes, great. So there's been a number of questions logically so around the timing and magnitude of the one-time costs and also some confusion, we're going to try to clear up here with respect to when the costs are expensed and when they actually are paid out in cash because the timing will be different. So through the fourth quarter, we incurred approximately $1.6 billion in integrated related costs, and that is an expense item. And this year, we expect to incur an additional $400 million to $500 million in integration cost. So through the fourth quarter, $868 million was paid out in cash and the remainder of that total balance will be paid out -- expected to be paid out this year in 2020. So as we looked at it, the paybacks are phenomenally good with these moves. They're very good paybacks. And so incurring these costs earlier in the process will enable the benefits to flow to our bottom line sooner than it originally expected. So as Vicki mentioned, we are significantly ahead of plan and schedule. Very excited about that. And we think that the financials are going to reflect that beginning this year.
Vicki Hollub:
Okay. I'll close with another thanks to our employees and to all of the -- all of you who participated on our call today. Thanks again, and have a good day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good morning, and welcome to the Occidental's Third Quarter 2019 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Brandon. Good morning, everyone, and thank you for participating in Occidental Petroleum's Third Quarter 2019 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Ken Dillon, President, International Oil and Gas Operations; BJ Hebert, President of OxyChem; and Oscar Brown, Senior Vice President, Strategy, Business Development and Integrated Supply. In just a moment, I will turn the call over to Vicki. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements or more fully described in our cautionary statement regarding forward-looking statements on Slide 2. Our earnings press release, the Investor Relations supplemental schedules and our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good morning, everyone. I'm pleased to welcome you to our first earnings call since closing the acquisition of Anadarko on August 8. I'd like to thank our employees who are hard at work updating our development and capital spending plans and implementing our team-based structure across the combined organization with an emphasis on safety, collaboration, creativity and results. Our integration and value capture team is working with our business units to capture synergies at an early stage so we can deliver the full potential of this transaction for our shareholders. As we work through the integration process, we become more confident every day in our ability to fully realize annual capital overhead and OpEx synergies of $2 billion, which I'll provide more detail on in a few minutes. For those of you who know Oxy well, you'll see our third quarter financial statements include a number of changes due to the completion of the Anadarko acquisition mid-quarter. Our income and cash flow statements capture legacy Oxy results for a full quarter and include Legacy Anadarko results as well as consolidated WES results for only 53 days. WES is now consolidated in our financial statements as a fourth operating segment, and our balance sheet reflects the consolidated company, including WES as of September 30. For transparency for our shareholders, we have provided a schedule in our earnings release, breaking out key financial and operational information from Oxy and WES on a stand-alone basis. As our financial statements do not include a full quarter of Legacy Anadarko and WES results, we understand that Street consensus was not able to reconcile all of the line items affected by the acquisition this quarter, for example, DD&A, tax and interest. Going to Slide 4. Oxy's complementary assets and the alignment of our Upstream, Chemical and Midstream businesses, including our ability to compete in a low-carbon world, position us for a full cycle success. Our leadership in each area where we operate, combined with our enhanced portfolio of high-return, short-cycle cash-flow-generating assets will facilitate profitable free cash flow growth, which we will utilize to reduce debt and also to return additional cash to shareholders. The substantial free cash flow we will generate in higher price environments, combined with our ability to pay a sector-leading dividend throughout lower commodity price environments, is unmatched. Post-acquisition, Oxy's diversified portfolio provides numerous competitive advantages. Oxy is now the largest oil and gas leaseholder in the United States on a net acreage basis, providing us with ample opportunities in the Permian, DJ, Powder River and the Gulf of Mexico to selectively deploy capital in a way that optimizes capital intensity. Oxy was the largest U.S. producer of oil and liquids on a combined company basis in the first half of 2019. This will allow us to maximize cash margins on a BOE basis, especially when taking our advantaged Midstream position into account. Through the acquisition, we acquired approximately 450,000 square miles of modern 3D seismic data in our core domestic development areas. This included a 40% increase in our already extensive Permian seismic inventory. The advantages that Oxy's diversified portfolio provides, coupled with our unmatched subsurface characterization ability and the execution excellence that Oxy is known for, ensures that we are positioned for full cycle success in the years ahead. As we continue our integration efforts, we are aligning WES to work seamlessly with Oxy's Upstream business. We're standing WES up as a more independent operation and to improve operating performance to benefit both Oxy's Upstream business and WES, inclusive of enabling WES to be more competitive for third-party business. We're also evaluating alternatives that could result in the deconsolidation of WES in the future. However, we expect to retain a significant economic interest in WES for the foreseeable future as we recognize their tremendous value that WES provides, and we plan to drive long-term value for both companies. Before providing additional details on synergy capture, I want to turn to the excellent operational results that our businesses continue to deliver. Since completing the acquisition of Anadarko, we continue to make quick progress towards fully achieving our post-acquisition divestiture and deleveraging goals. During the third quarter, we divested our Plains interest for net proceeds of $650 million and closed the sale of our Mozambique LNG stake for $3.9 billion. Upon completion of the divestitures contracted since May 2019, we will have essentially reached the lower end of our $10 billion to $15 billion divestiture goal net of taxes. We applied the proceeds from our closed divestitures toward reducing debt and have already eliminated our 2020 debt maturities. I'm very proud of the progress our teams have made over the last few months. We know that we have more to do on the deleveraging front, and I look forward to being able to make that additional announcement as we move forward towards the top end of our goal. Our integration and value capture efforts are proceeding exceptionally well without shifting focus away from our core business, which is evident from our strong third quarter operational results. Oxy continues to deliver the best wells in the basin, having delivered 25 of the top 100 wells in the Delaware Basin while drilling less than 7% of the total wells. We accomplished this using less proppant than peers, which results in lower cost for us. We also designed our developments with a full cycle -- with our life cycle approach using appropriate well spacing that we expect to deliver optimal results now and in the future. While we tend to highlight the Permian as it is a growth asset for us, all of our businesses continue to perform well. Since the close of the Anadarko acquisition, single day or monthly production records have been set in the Gulf of Mexico, DJ, Al Hosn and Permian resources for both legacy Anadarko and Oxy assets. This demonstrates the quality and expertise of both the former Oxy and Anadarko employees as they stay laser-focused on delivering superior results even during this integration process. As proud as I am of all of our teams for the operational excellence they have maintained during integration, I'm even more pleased with our outstanding safety record. Our teams are continuing to look for ways to further improve our safety performance as operating safely is and will continue to be a core value for us. Our consistent industry-leading operational results, combined with our ability to fully deliver on value capture, positions us for a full cycle success and enhances our ability to generate increased excess free cash flow to reduce debt and to return cash to shareholders. Returning excess capital to our shareholders is a part of Oxy's DNA. In the third quarter, we returned approximately $600 million to shareholders. Going to Slide 7. I'm thankful to have had the opportunity to engage with many of our shareholders over the past few months to discuss the free cash flow potential of the new Oxy. Interest in our 2020 capital plan is high. While we typically do not release our full year capital budget until our fourth quarter earnings call, we're able to provide many details of our 2020 capital plan this morning. Our 2020 capital budget of $5.3 billion to $5.5 billion will deliver expected annual total company production growth of 2%. This represents an approximate reduction of $3.6 billion from Anadarko's and Oxy's combined 2019 capital budgets. When we communicated our annual synergy target of $2 billion, we also stated that capital spending would be reduced by $1.5 billion, lowering our company-wide annual production growth from approximately 10% to 5%. We have gone further than this for 2020. We anticipate that the combination of lower capital spending and production growth will generate greater free cash flow, enhanced by our industry-leading capital efficiency, which I'll touch on shortly. 2020 production growth on the company level will be driven by Permian resources, while we expect production from other areas to be flat or grow at a reduced rate compared to 2019. We expect Permian Resources production to grow by approximately 5% in 2020, operating 15 gross rigs and 8 net rigs. The rough breakout for specific areas is 5 rigs in new Mexico; 6 to 7 in Legacy Anadarko, Texas Delaware; and 3 to 4 in the Midland Basin JV. In the DJ, our plan represents approximately three operated rigs. As Permian resources shelf production becomes a larger portion of our total oil and gas production, we expect our oil and gas base decline rate to increase to 25% in 2020. However, we do not expect our base decline rate to continue to increase in future years given our moderated growth rate. Similar to 2019, our 2020 capital program is dominated by short-cycle investments. At approximately $35 WTI, our 2020 program would generate a double-digit rate of return. Oxy remains flexible throughout the commodity cycle. And if necessary, in less than 6 months, we can reduce capital spending to sustaining levels. Looking past 2020, we know that capital discipline will continue to be important to investors. Our intent is to cap our annual production growth at an average of 5% as we balance the vast opportunities in our portfolio with growing free cash flow. Our planned activity in 2020 should enable us to grow production by 5% annually in 2021 with a capital budget of $6.6 billion. As for 2019, capital discipline, as always, is intact at Oxy as we remain on track to spend within our combined capital budget of $8.6 billion, excluding Africa. Since the acquisition closed, we've had the opportunity to take a deeper dive into the company that's combined, Oxy/Anadarko, and are as excited today as we have been at any time during the last 2 years about the opportunities in front of us. Through the strength of our combined companies, we've identified approximately 150 specific capital synergy initiatives across our enhanced portfolio, which we plan to incorporate into our development plans. Applying these initiatives will lower well costs by $3.1 million per well in Texas Delaware and by $600,000 per well in the DJ Basin. In drilling and completions, we are implementing efficient development concepts utilizing Oxy drilling dynamics to improve the trajectory of the bid and wellbore, which reduces drill times and costs. For example, we expect to improve our drilling rates or footage drilled per day in the Texas Delaware about 35%. The technical work completed by all of our teams to identify savings initiatives and to improve well productivity has been outstanding, and I'm extremely confident in our ability to execute and realize the full synergy targets. On Slide 10, we provide a bottom-up view of the $605 million of drilling and completion synergies based on expected savings per well and estimated 2021 net well counts to achieve annual production growth of 5% in 2021. On Slide 11, in addition to realizing $900 million in capital synergies, Oxy's best-in-class capital intensity is expected to continue to improve. This often underappreciated measure of operational excellence and competitive advantage truly sets Oxy's capabilities in the Permian apart from other operators. As a reminder, capital intensity is defined as the total net annual capital required for 1,000 net barrels per day of average annual ledge production. Fully capturing our capital synergies and improving our overall capital intensity through faster time to market and better well performance will contribute to driving efficient wedge growth, enabling Oxy to deliver expected production growth of 5% in 2021 with $6.6 billion in capital. We've been a top performer in capital intensity for multiple years, and we will substantially improve the capital efficiency of our newly combined Permian resource portfolio. We expect the largest improvement in intensity to originate from legacy Anadarko Delaware acreage, along with continued improvements from legacy Oxy acreage. Our unmatched Permian capital intensity reflects significant improvements in time-to-market through our efficient operations and SIMOPS planning, applying Oxy's advanced subsurface characterization to improve well results and limited inference to reduce infrastructure costs in our legacy acreage from the reuse of existing facilities and the high grading of inventory as well as implementing our Midland Basin joint venture with EcoPetrol. In 2020, improvement in capital intensity is aided by the deceleration in capital spending. Moving into 2021, we will maintain our intensity in the low 20s -- $20 million range, even when production grows from Permian Resources is increased to support annual company production growth of 5%. While this example applies to our Permian Resources business, we continue to make notable productivity and efficiency gains across all business segments. We will highlight some of the exciting initiatives in our other areas in next quarter's earnings call. On Slide 12, overhead synergies will be derived from aligning our workforce to meet the current needs of our company and carving out costs related to assets that will be divested in reducing real estate and other costs. In terms of reducing OpEx, Permian cash operating costs continue to be at the lowest they've been in a decade, driven by our long-term, high-return investments, including facilities and infrastructure. We expect this trend to continue, especially with our large footprint in the Permian. On Slide 13, as I mentioned earlier, we have had many initiatives underway to fully capture the synergies promised. You can see on our energy tracker, we've already made progress in adding both overhead and capital synergies. While our progress in realizing synergies may not be linear, we will continue to provide updates so investors are able to clearly see our progress each quarter. Turning to Permian Resources. We again delivered the highest number of top wells in the Delaware Basin on a 6- and 12-month cumulative basis, and we continue to drive significant productivity improvements. We also continued to reach new milestones, including a record 10,000-foot lateral drilled in only 10.7 days and a record 267 completion stages in 1 month completed by one frac team. This is a record for Oxy and also for our main frac provider in the Permian. Following my earlier comment on safety, I'd like to draw attention to our new Mexico completions team, which went in an entire year without a single OSHA recordable incident for employees and contractors. That includes over 2 million work hours, conducting high-pressure frac operations without an incident. This is a remarkable achievement. The next slide reinforces our unique development approach and subsurface expertise, one of the key factors that continuously enables us to deliver the best wells while using less proppant than others, resulting in significant capital savings. Oxy's combined acreage portfolio supports nearly 1/3 of the top wells in the Delaware Basin, including Anadarko's 6 record wells. The subsurface potential in the acquired acreage is prolific, and we can't wait to unlock more top wells using our development expertise, combined with Anadarko's best practices. I'll now hand the call over to Cedric, who will walk you through our financial results and updated guidance.
Cedric Burgher:
Thanks, Vicki. As we move forward as a combined company, our commitment to capital discipline and returning capital to shareholders remains unchanged. We remain on track to spend within our full year pro forma combined capital budget of $8.6 billion, excluding Africa. Furthermore, we have an established -- we have established a capital budget for 2020 that we expect will fully optimize free cash flow and position us to grow production in a capital-efficient manner while maintaining the safety of our dividend. In the third quarter, we returned $660 million of cash to shareholders through our dividend, protecting our dividend as a top priority, and we look forward to continuing to return significant capital to our shareholders. Continuing with our third quarter results, taking into account the mid-quarter completion of the acquisition, we announced adjusted earnings of $0.11 per diluted share and reported a loss of $1.08 per diluted share. The difference between adjusted and reported results is mainly due to the $969 million of onetime costs related to the Anadarko acquisition and $325 million of oil and gas impairment charges. With respect to our segments, oil and gas adjusted income decreased in the third quarter compared to the prior quarter, mainly due to lower international production and lower realized oil prices. Total third quarter reported production from continuing operations of 1.1 million BOEs per day included contributions from legacy Anadarko operations of 377,000 BOEs per day. As Vicki mentioned, all of our U.S. upstream businesses are performing exceptionally well, with several single day or monthly average production records having been set since completion of the acquisition. Oxy's legacy Permian resources operations exceeded guidance with production of 300,000 BOEs per day due to best-in-class well results and execution. Actual production of 655,000 BOEs per day for Anadarko's legacy U.S. businesses exceeded guidance of 585,000 to 630,000 BOEs per day due to improved operability in the DJ, Permian and Gulf of Mexico. To assist investors with reconciling reported and pro forma production for the third quarter, we have included a table in the appendix of this presentation, breaking down actual total company production of 1.4 million BOEs per day by operating area. OxyChem surpassed guidance with income of $207 million for the third quarter despite vinyl margins coming under pressure from increased ethylene costs, which were driven higher by industry-wide ethylene cracker downtime. Higher ethylene costs were offset by stronger sales and production across most product lines. Our Marketing and other Midstream business reported third quarter adjusted income of $155 million, excluding $111 million gain on the sale of our Plains interest driven by a Midland to MEH differential of approximately $5.30. Compared to the second quarter, the decrease in earnings was largely driven by the narrowing of the Midland to MEH differential impacting Marketing margins. As the differential compresses and impacts Marketing income, currently, 70% of the impact will be realized as an income benefit to the Upstream business. For the fourth quarter, we have provided guidance on a combined company basis and expect Permian Resources growth to slow as we have begun moderating our capital spend going into 2020. Fourth quarter international guidance reflects the termination of the Idd El Shargi North and South Dome contracts in Qatar in early October. The continuous improvements we are making are evident in our operational results and outlook. Our revised fourth quarter production guidance represents an increase of 28,000 MBOEs per day compared to the implied fourth quarter guidance provided in Oxy's second quarter earnings call and the updated guidance we released for legacy Anadarko operations in early August. Pro forma production guidance for full year 2019 is included in a table in the appendix to this presentation. As has been the case in previous years, fourth quarter guidance for Oxychem is not representative of our full year outlook as chloro vinyls -- as the chloro vinyls market is typically subject to seasonal factors in the fourth quarter each year. In the third quarter, we applied the proceeds from our sale of Mozambique asset and Plains interest as well as free cash flow from Algeria and Ghana, to pay down $4.9 billion in debt. We have now retired all of our debt maturities for 2020 and will apply proceeds from future sales to retire debt due in 2021 and beyond. As we continue to apply asset divestiture proceeds and free cash flow to debt reduction, we will update the debt-reduction tracker shown on Slide 20 so that investors can see our progress in meeting our divestiture target of $10 billion to $15 billion net of taxes and in deleveraging. I look forward to continuing to provide updates on our progress on both of these fronts. I will now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Cedric. As a leader in our industry, Oxy must drive improvement on all fronts, including reducing emissions. In the coming quarters, we will provide updates on the progress our Low Carbon Ventures business is making and supplying anthropogenic or man-made CO2 to the Permian for the purpose of carbon utilization and sequestration. While Low Carbon Ventures is leading our strategy to produce the lowest carbon barrel of oil, we are also reducing greenhouse gas emissions. We are doing so by working to eliminate routine flaring, monitoring infrastructure for methane emissions and reducing miles driven by transporting supplies into the Permian via rail through our Aventine Logistics Hub. On an annualized basis, we reduced 1.9 million truck miles per year, which is equivalent to 1,700 metric tons of CO2 reductions. Also in this quarter, in the Permian Basin, we brought online the largest solar facility in the state of Texas that directly supports oil and gas operations. The latest publicly available emissions data shows that on a like-for-like basis, Oxy is a leader in greenhouse gas emission intensity in the Permian. While we are pleased to be ahead of peers on this metric, we are not satisfied with where we are, and we're committed to continue working on reducing emissions across all of our assets. Going to Slide 23. To Oxy, being an innovative and sustainable energy leader means maintaining leadership in each area that we operate. Our teams are relentlessly focused on value creation through the application of advanced technical excellence, applied technology, breakthrough innovation and operations and capital execution, all of which helped to make us a lower-cost operator and will translate into higher-margin free cash flow growth. The cash will be used to delever the near term and to return more cash to shareholders through a balance of our dividend and share repurchases in the future. Sustainability also means planning for the future, which we do through the lens of a best-in-class operator with an unmatched portfolio of world-class assets. Our focused portfolio includes multiple decades of high-return, short-to-medium cycle development opportunities that will include primary, secondary and tertiary recovery options. The diversity of our enhanced portfolio strengthens our strategy to operate profitably in a low-carbon world. The combination of technical and operations excellence applied over a vast set of diverse assets and a strategy to lower our carbon footprint sets us apart from other energy companies. This will enable us to further strengthen our value proposition and ensure our success and sustainability long into the future. In closing, I want to stress how much potential our newly combined company now has in terms of what we can achieve both financially and operationally. There is much to look forward to for our shareholders and for Oxy. And now we'll open it up for questions, and while we're lining up the questions, I do want to give a shout-out to our DJ Basin team for also achieving record production. Our DJ Basin team achieved almost 301,000 barrels a day just here recently, so we're excited about what they're doing and the improvements they're making and the commitment they have to operational excellence. Now we'll move to the first question.
Operator:
[Operator Instructions]. Our first question comes from Devin McDermott with Morgan Stanley.
Devin McDermott:
So my first question is on the synergy targets, and it seems like you've made some really good progress so far post the integration. I think the additional detail on the specific drivers of synergies is definitely helpful. It seems like you identified a lot of clear items that get you to the overall targets. My question is more on -- now that we're a few months into the deal post close, what you identified or what opportunities you've seen that might be incremental to or different than your expectations going into the deal, and specifically, if those might drive upside over time? And as part of that, I was hoping you could address some of the difference in capital efficiency between some of the legacy Anadarko, Permian wells and Oxy. And how much, if any, improvement in that productivity is baked into the synergy targets and also 2020 guidance?
Vicki Hollub:
Well, what we baked into our synergy targets were the things that we knew about, the things that we could see. And in the Permian Basin, we had the data there so we knew that we had the opportunity to significantly lower cost and to do that through a combination of our drilling expertise and our subsurface characterization. So we've looked at that. Our teams have delved into that. That's why we're very, very confident of the Permian resources synergies that we've outlined. We know that we can achieve those there. In the DJ, not only based on what we knew with respect to our Oxy drilling dynamics, we've been incredibly impressed with what the team up there is doing from a drilling perspective. They're -- and also completions. They have started to work their completions differently, and they are bringing some best practices that we believe are really advanced. We think that we can still improve that with the subsurface characterization that we've applied to the resources business. But I would say on an operational perspective, from drilling and completing, those guys are doing a great job, and they're doing a great job operationally, which is how they achieved their record production of almost 301,000 barrels here in the last couple of weeks. So what we're really excited about is that now that we've had a chance to work together, the 2 teams, we're coming up with more synergies. The ones that we identified in my script and the ones that we had counted on initially to deliver what we expected are -- we already had a little bit more than those because we wanted a little bit of cushion to ensure that we did deliver what we said we would. But now I'm really excited about what Anadarko's expertise is bringing to the table for us. And I believe that, that's going to be exciting news when we could roll it out. What we need to do first is quantify the value that it's going to add, but we know that they have some best practices that are really important to us. One, I can tell you that's not even related to the shale is their seismic interpretation. Some of the things they're doing there are very, very impressive, and we're going to be applying that to some of our international operations.
Devin McDermott:
Got it. Great. And just to clarify on the Permian operation. So as we think about the 2020 plan, how quickly can you implement some of the Oxy best practices, subsurface characterization, drilling techniques into the Anadarko development program. When might we see some of those productivity improvements show up as we move through 2020 and beyond?
Vicki Hollub:
Well, what we have found is that the subsurface work, that's going to be pretty immediate because those guys are starting to work that now. So from a completion cost perspective, that will start happening right away. Now the results of that, the improved recovery per well, you'll see that have a bigger impact from a production standpoint next year, but we'll see the efficiency improvements in using less proppant to still manage to frac and complete more effectively. That will start happening as we start drilling on the Anadarko acreage in a big way. The Oxy drilling dynamics, everywhere we've rolled it out, even internally, it takes a little while to get the teams used to it so that they can start to make it happen and work for them. There's always a little bit of a learning curve with that, but we do expect that we will achieve that process by the first quarter of 2020 for it to start taking hold. And so by the mid to later part of 2020, you'll start seeing, I believe, some improved drilling in the Permian, along with the efficiencies of the completions by midyear. So that by the end of the year, I'm quite confident that, that drilling and completion program will be much improved.
Devin McDermott:
Excellent. I look forward to seeing the progress there. And I have one more on a separate topic, and that's just on some of the asset sale and leverage reduction targets. So I mean, you've achieved the lower end of the $10 billion to $15 billion target so far. I was wondering if you could comment just on the overall market or backdrop for these additional divestitures, what your thinking is on the opportunities there. And then I understand it might be hard to comment, but any additional color on how you see that deconsolidation of WES potentially playing out with the intention of, as you mentioned, containing or retaining a large economic ownership but deconsolidating some of the debt and overall financials there.
Vicki Hollub:
Okay. I'll just say that one thing that we really want people to understand is that we are very focused. We're very intense on ensuring that we get the asset sales done because we believe we must get our debt down. That's an internal target. We talk about it every day. We're getting help throughout the entire organization because I don't think there are very many of our employees that you wouldn't walk up to and that they wouldn't be able to tell you that the highest priority we have as a company is to save every dollar that we can save and to become as efficient as we can be, as quickly as we can be, because making sure that we have the dollars either from cash flow or asset sales to lower the debt is critically important for us. And just as when we first rolled out our plan to achieve cash flow neutrality at $40, we had a plan to do that in 2 years, and we made that promise to the shareholders. As you all know, we achieved that 6 months ahead of schedule, and we did that because our teams are incredibly focused and determined to deliver results and to deliver what we say we'll deliver. We're taking that same intensity to this debt reduction. So we are approaching asset sales very aggressively and intently. But with that said, one of the things that we're not doing is we're not compromising on the value that we can get from those assets, and so we're balancing both of those. And I feel confident that with, not only the intensity that we're approaching it, but the creativity that I hope we've shown you all in the way that we've approached the asset divestitures thus far. So we will -- there will be some creativity. There will be some things that you might not expect, but none of those we can talk about or we compromise our ability to make it happen. So I appreciate you recognizing that. With respect to WES, I'm going to hand it over to Oscar to tell you a little bit more about how we're thinking about that.
Oscar Brown:
Sure. And as Vicki made earlier comments, obviously, we're focused on the integration right now and helping WES improve operations and really become more competitive, not only with the supporter of Oxy's upstream operations, but with third-party operations. So all that's ongoing. We've been working with our auditors to focus on the accounting deconsolidation of WES. So there's some work to do, but we think we can do that pretty quickly. That really not changed too much our ownership interest in WES. And so as Vicki said, we have the option to retain a substantial stake in WES economically both in terms of ownership, but also, obviously, we're tied together as their largest customer going forward. So all that's progressing just fine, and we hope to have some news on that in the near future.
Vicki Hollub:
I will add to that. I'm really excited about the new management team at WES. They're very operationally focused, and they're working on -- that's why I said the part about picking up third-party volumes, they're really focused on improving operations and efficiencies and being a really strong competitor to other midstream businesses in the Permian.
Operator:
Our next question comes from Ryan Todd with Simmons Energy.
Ryan Todd:
Great. Maybe to follow-up. At a high level, is it fair to characterize the large cuts to the 2020 program as an effort to demonstrate your priorities in terms of deleveraging in dividend and the 2021 plus outlook as a normalization of the business? And if that's the case, what sort of checkpoints would you have to see to normalize things again versus staying in belt-tightening mode? Is commodity price hitting certain checkpoint on debt metrics? What would you have to see to kind of renormalize in 2021? Or not?
Vicki Hollub:
Todd, thank you. You just answered the question for me. So thank you for that, but it really goes more beyond just trying to get back to normal. What we really would need to look at and evaluate when we get closer to 2021 is how oil prices look, what we've achieved on the debt reduction and what we've achieved with respect to the synergies and also how well our teams are performing from an efficiency standpoint. All of those factors will be considered as we go and move toward 2021 because the reality is that we don't have to be at the 5% right away. What we wanted people to know is that, over time, the 5% is what we believe is the right growth percentage to enable us to, not only start to grow our dividend more meaningfully again, but to also be able to, at the same time, return cash to our shareholders through buybacks.
Ryan Todd:
Okay. And on the leverage side, is there anything that you're looking at to say kind of until we get to this place, we'll probably keep things tight.
Vicki Hollub:
I would say that we have aggressive internal targets, and if we haven't met those, then that would play a big role in what we do in 2021.
Ryan Todd:
Okay. And maybe a follow-up on the 2020 plan. I mean, should we think about everything outside of the Permian resources as being held roughly flat from a production point of view with all the growth coming from the Permian Resources? And if that's the case, under a normalization to $6.6 billion in 2021, do some of these other assets, Rockies, EOR, et cetera, kind of return to growth? Or does the majority of that incremental capital will just go back to Permian? I guess on a multi-year view, should we think of ex Permian resources as being largely held flat? Or will we see growth outside of the Permian?
Vicki Hollub:
What we like to do with our teams internally is let them compete for capital, and they have to compete for capital by submitting projects that can beat the Permian. And actually, we have -- we believe that some of those projects, both in Oman, Abu Dhabi, Colombia, the DJ and probably in about 2 to 3 years, the Powder River, we believe -- and Gulf of Mexico. Looking at the data that we see now and the performance that we see, the margins and the returns, our returns from almost -- from everything that we have the opportunity to invest dollars in is double digits at $40 or above. And so we have -- this is what -- this is the value of this tremendous portfolio we have today. We have lots of options. We have lots of flexibility. And what the teams have to do is they just have to make their projects competitive enough to get the dollars. And ultimately, the way I see it now, in a $6.6 billion environment and by 2021, essentially, we would be potentially growing all of our areas, except Gulf of Mexico and maybe Powder River. But certainly, all the other areas would have the opportunity to grow because of the projects that they have in their inventory today.
Operator:
Our next question comes from Paul Cheng with Scotiabank.
Paul Cheng:
Vicki, earlier, you said that -- from your standpoint, 5% is the wide growth rate. Can you elaborate why 5%? I mean, given the size of the company, today and long-term or demand growth looks like it's going to be 1% or below. I think the market is actually will be more happy if you grow at 3% instead of 5%.
Vicki Hollub:
It would be -- commodity prices always come into play when we're deciding what our growth rate would be. And what I -- a better way for me to say it is that we're going to average a 5% growth rate on the average over time. So in those times when commodity prices because of weaker demand, we would grow at a lower rate. So we're going to adjust. And I think at one time, we showed a chart that showed that we would potentially grow from a certain oil price to a different oil price above which that our growth would be capped. We'll have that same scenario going forward. And as we delever and get back to the scenario where we'll start taking into account the opportunities to grow at that 5% cap, then we'll start looking at those metrics and providing those to you again. But it really depends on commodity prices, efficiencies, where we are from a leverage standpoint. And I guess, what I'm really trying to say is that once we put all the variables in our model and we run the various scenarios, it's -- at the end of the day, it's a value calculation. And whatever creates the most value is -- and then delivers the most return to the shareholders is what we'll do.
Paul Cheng:
But just my two cents is that given the increasing number of the journalists, there's a concern about the long-term oil demand outlook and correspondingly, that the longer-term commodity prices. The notion saying that we grow at 5%, I think the easy way to look at it is that most investors today probably one burn on hand and 2 burn in the bushes. The second question, quick one on Permian, how much is your percent of your land position, just in the federal land? And how much of your production today is in the federal land?
Vicki Hollub:
So in the Permian Resources business, we have a very low percentage of what is total federal lands. I can't remember overall. I think our overall percentage is about 2%. Let me hand this to Jeff. He's got those numbers.
Jeff Alvarez:
Yes. So domestically, of our 14 million acres, 2 million of that is federal, but half of that is offshore. So if you think of onshore, about 1 million acres is federal. And if you go to the Permian, about 270,000 acres across the Permian. And then if you continue to narrow that down into the Delaware Basin, that's where people want to talk about the most, approximately 20% of our acreage in the Delaware Basin is on federal land. And if you look at the DJ, it's less than 1%. It's very, very small there.
Operator:
Our next question is from Pavel Molchanov with Raymond James.
Pavel Molchanov:
On the low-carbon initiatives, as I look at the slide breaking out your 2020 CapEx, if it's there, it seems awfully small so I thought I would just ask. What level of funding you're planning to allocate to the low-carbon effort this coming year?
Vicki Hollub:
Our strategy for Low Carbon Ventures is more around a target and goal of the activities and what we need to accomplish. And how we accomplish that with respect to a capital standpoint is a part of the Low Carbon Ventures team. Strategic initiatives is to look at the best way to fund those. I -- ultimately, I'm so excited about this business because this is a win-win-win business in that we are going to be able to lower emissions both in the United States and in the other areas that we operate while also taking the anthropogenic CO2 and using it to increase oil production, thereby creating value for royalty owners, for the states and for the country in which we operate, wherever it is. And in addition to that, we're going to be able to ultimately, in my view, make -- and our team's view, make a business of this in that we will be able to build this into a business that generates cash flow and earnings for our shareholders. So the way we intend to do that is a bit -- at this point, something that's proprietary in terms of how we want to -- how we think about it and how we're building that to happen. But it's a win-win-win, and it's a great -- the team is doing just a great job in making this happen. And we've made some investments in some new technologies. Those have been direct investments. We have a -- one of those was net power, which generates a lower cost of electricity and still provides a CO2 stream, almost pure CO2 stream for use in enhanced oil recovery. And the other thing we've invested in, and we've even announced that we will build, we're evaluating building one of the largest or the largest direct air capture unit in the world in the Permian. And what that will do is take CO2 from the atmosphere, and we can then use that in our enhanced oil recovery projects. And the reason all of this is so important to use in enhanced oil recovery rather than sequestration is that using it in an oil reservoir still sequesters about 40% of what you're cycling every time you cycle through the reservoir, so you get the sequestration part of it. But what you also do is by using that, you're able to generate a lower-carbon intensity barrel of oil. And so the -- I believe that for the world, the last barrel of oil produced in the world, whenever that happens, should come from a CO2-enhanced oil recovery reservoir because then it will be a net lower emission barrel. And our teams are working toward that, and they've got some very creative commercial ways to deal with it.
Pavel Molchanov:
That's helpful. And then lastly, on the Board changes or the changes in the charter that you outlined at the very end of your slides today. Do these proposals that will be voted on next year potentially settle the disagreement with Icahn?
Vicki Hollub:
I'll say that when Mr. Icahn brought up the concerns he had, these were a part of his concerns. And that's one of the things that is -- a result of him bringing up is the reason we looked at it. We're not out to settle anything with this. What we're out to do is just to do the right thing for our shareholders, and we felt like he brought up an issue that we needed to address, and the Board did that. And the Board has actually gone further than that. We -- I'm -- not only are we responding to shareholder feedback on the 2 proposals to lower the percentage required for a special meeting, but also the procedure lowering the requirement for the written consent vote as well. But what I'm even more excited about is what the Board has done with respect to the creation of a committee now that specifically addresses ESG, and specifically addresses it in a way that engages the Board more with the shareholders. So what's sometimes missed in what that proposal was is it's yet to -- they're going to focus on the ESG things that fall sort of in between the Health, Environmental and Safety Committee and the Governance Committee. So there are some things that we were struggling with, where do we include that, who takes the ownership of that. So creating this committee clearly has a committee on our Board focused on our specific ESG initiatives that are not really so much safety- or environmental-related, and those that are not specifically governance-related puts them in this committee. So this committee is going to be focused on that. But the other things that our Chairman wants this committee to do is be a lot more engaged with the shareholders, both on the ESG side and on the portfolio management side to ensure that they are more engaged to know how our shareholders think, what are the topics that are top of mind for them. And if there are issues that we need to address, they're getting that feedback now directly. And so I think that's been a huge change for us, and I think it's going to be a positive thing for all of our shareholders going forward.
Operator:
Our next question comes from Brian Singer with Goldman Sachs.
Brian Singer:
With regards to the Permian, you talked about the rig split earlier. But can you talk a little bit more with regards to how you view the Anadarko Permian properties competing relative to the legacy Oxy Permian properties? And to the degree that you were to ramp back post 2020 to deliver a 5% growth rate, would that ramp-up occur more from Anadarko side versus the Oxy side?
Vicki Hollub:
I think our Southeast New Mexico area still remains, I believe, the top and the best that we have. And I believe the legacy Anadarko acreage is going to be very close in line, not even a second, maybe a 1B in terms of the priority. The acreage is really, really good. Subsurface is excellent. So I would say that our Texas Barilla Draw area would be probably second. And so behind 1A in Southeast New Mexico, 1B in legacy Anadarko acreage.
Brian Singer:
Great. And then to follow-up on the earlier question with regards to WES, I think in the past, Oxy said that the process to improve performance operationally could be done by early 2020. Is that still the case? Or what do you see -- and what do you see as the scope of the improvement and how you would measure success? And then one additional one on that thread is I think you commented on the potential for deconsolidation, but retention of economic interest. Does that mean that you would divest a portion, but not all of your interest in seed control? Sorry, I know there were a lot of questions in there.
Vicki Hollub:
I would say I'll address the operations one and throw it to Oscar for the structural one. But from an operations standpoint, what has been, I think, a huge change is the collaboration between the field upstream operations and the facilities guys and the WES team. I think that what they did early on is they decided to have a team approach, how we're doing business today, how Wes is doing their business, how we're interacting and where -- how we connect with them, and to look at ways to [indiscernible] and improve efficiencies. They've already outlined some specific things that they're addressing. One of the deals was that we were a bit surprised by the downtime that WES had, and it's just kind of unacceptable to us to have that level of downtime. And so combining the current management team's perspective with their designee, working with the Oxy side of it, these teams now have come up with ways to specifically address the downtime and get the downtime much lower. And that's -- those are inexpensive barrels of just making sure that your uptime is the best that it can be. That's the quickest and easiest way to get barrels, and I think we'll start seeing -- we have to change some infrastructure first to make that happen. So I think you'll start to see that happening in Q1 of 2020. And Oscar?
Oscar Brown:
Sure. It's Oscar. So on the deconsolidation front, one of the key things is the business -- WES has matured greatly over the years. And then everything that Vicki is talking about to improve operations and, most importantly, set up this company to really be aggressive in its ability to win third-party business, I think all those things are aligned with a company that can stand on its own, and being an independent company, and ultimately, a convenience for us is the deconsolidation on the accounting front. So all those things align. In terms of the specifics on how much control Oxy would need to give up and is there a related need to sell down some interest -- economic interest in the company, we're still working that with our auditors. But the key is that the company can -- is getting the company to a place that has its own employees that can stand-alone its own officers, great operations, it's a complement to our businesses. And then again, the real growth upside, the next stage for WES, beyond what we can do and we'll continue to do with Oxy to support WES is the third-party business, which is one of the great opportunities there. So again, more to come on that, but that's where we stand today.
Operator:
Our next question comes from Michael Hall with Heikkinen Energy Advisors.
Michael Hall:
I just wanted to, I guess, review a little bit on the capital efficiency or intensity disclosures you provided on the Permian Resources business. I'm just curious how you think about the ability to maintain that level of capital intensity, the 2020 level, as you think about kind of reentering more of a normalized or growth-type scenario in 2021. Is that a kind of a sustainable level? Or is that being kind of dragged down by the slowdown in 2020?
Vicki Hollub:
Well, that was one of the things that we took into account, is that -- and when we decided to lower our capital, how it would impact 2021 was a factor that we thought about and considered. And so we do have a plan to on-board rigs, should we go back up in 2021. We would make that decision at a point where it would give our teams the time to make that happen. Because every time you shut down a rig and you release crews, you have the issue of bringing those crews back, getting them back to the efficiency level that they were when they shut down. Obviously, you recognize that, and that's what your question is centered around. We have a more robust process around doing that because it's always irritated us that even though we know it happens, that it always happens. And so we try to -- we're trying to figure out now and have some people that are involved in trying to make that -- the reboot and the start-up, again, of a rig that's been idled to make that more efficient. And so as we go toward 2021 and see how that's looking, we'll take the steps to try to get the -- that rig, whatever rigs that we bring on, up and running and without too much loss of efficiency initially. Did you have anything to add on that, Ken -- Jeff?
Jeff Alvarez:
Yes. So to add, Michael, I mean to your point, and Vicki commented in our script, we do expect 2021 plus the capital intensity to be in the low 20s. So as synergies flow through and all that, we expect that to be in that level as we go forward. And if you spend time -- I know going through with our Permian resources leadership, they've got very, very definitive goals to drive it down from there. So I do think that is our new normal.
Michael Hall:
That's helpful. And then I guess, continuing on this thread. What's the base decline on the Permian Resources business, I guess, exiting 2019 pro forma, the combined businesses? And then how that looks coming out of 2020 as you look at it in these capital intensity figures?
Jeff Alvarez:
Yes. So without doing decline curve analysis on how it applies at cap intensity, I'll give you a couple of quick numbers. So the base decline exit-to-exit for Permian Resources is in the mid- to high 30s. So say, about 37%. But as you know, that's an exit-to-exit number. And when we do the capital intensity calculation, we use the real decline, which is exponential. So it's not straight. It's kind of concave. So just for easy math, if you think about the wedge we're adding in Permian Resources next year, there's about 105,000 barrels a day. So if you take the 2.2 billion, 105,000, that's what gets you to the $21 million capital intensity number. Is that answer what you're looking for, Michael?
Michael Hall:
Yes. And I guess I was also trying to understand like how that changes as you exit 2020 into 2021. It seems that, that would be a tailwind to the...
Jeff Alvarez:
Actually, it improved.
Michael Hall:
Yes, that's kind of what I was getting at. I'm just trying to understand how...
Jeff Alvarez:
Yes. So that's the point. As the base gets bigger and that you have less of those new high-decline barrels coming on, that base decline actually improves as you head into 2020.
Operator:
In the interest of time, this will conclude our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Yes, there's another couple of things we'd like to address before we go. But first, I wanted to pass it to Ken to -- there've been some questions offline about Gulf of Mexico. I'd like for him to share some mental on that.
Kenneth Dillon:
Good morning. Thanks, Vicki. So far, we're really excited about both the people and the assets. The subsurface characterization opportunities, we believe, can lead to being able to extend the plateau with modest cost over a long period. Our latest K2 well come in with really good logs, and it'll be on stream in Q1. Next year, we plan to spend $100 million on near-field exploration and also drill development wells from platforms. Artificial lift synergies are something we didn't build into our thoughts, and it's something we're working on together as a team here, and we see that as real potential upside to come. We see Ghana [ph] as a long-term steady cash flow business that has great significance, and everything we've seen so far supports that.
Vicki Hollub:
Okay. Then lastly, I'd like to say that in closing, that we are really positioning Oxy for long-term success. The acquisition of Anadarko has positioned us to more effectively address what I think are the 3 most critical issues facing our industry today. Those are climate change, geopolitical volatility and the regulatory environment in the U.S. So with the position that we have now, building on the fact that we're the largest handler of CO2 for enhanced oil recovery in the world, we intend to utilize now our position as the largest acreage holder in the United States, and with a vast amount of that being shale play to execute CO2 enhanced oil recovery in the shale. That will fit perfectly into our Low Carbon Ventures strategy and enables us to continue to grow and get the most out of the shale than anyone else over time. And we think these -- that these assets sit perfectly, and they're perfectly compatible with the conventional assets that we'll be developing in Oman and the UAE over time. So I think I'm really excited about our portfolio. We have an opportunity to continue to go into the future with the portfolio, the structure, the people and the sustainability to withstand oil price cycles while also maintaining a social license to operate globally in a low-carbon world. So thank you all for your questions and for joining our call. Have a good day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Operator:
Good morning and welcome to the Occidental. Second Quarter 2019 Earnings Conference Call. All participants will be in listen-only mode. Please note this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Alison. Good morning everyone, and thank you for participating in Occidental Petroleum’s second quarter 2019 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer, Cedric Burgher, Senior Vice-President and Chief Financial Officer, Ken Dillon, President, International Oil and Gas Operations, B.J. Hebert President of OxyChem and Oscar Brown, Senior Vice-President, Strategy, Business Development and Integrated Supply. In just a moment, I will turn the call over to Vicky.
Vicki Hollub:
Thank you Jeff and good morning everyone. Before covering our second quarter highlights, I would like to mention an organizational update and congratulate Robert Palmer. Robert was recently appointed to the position of President, Domestic Oil and Gas Operations with operational responsibility for Oxy’s domestic onshore, oil and gas assets. Robert was most recently Senior Vice-President of Technical Support. He's an engineer, and has operating experience in the U.S., Peru, Oman, and Russia. He'll play a key role in integrating Anadarko’s domestic operations and ensuring that our combined assets deliver the highest returns for our shareholders. As many of you know we expect to close on our acquisition of Anadarko one week from today. The combination of our two companies will strengthen our long term strategy and position us to drive profitable growth and return excess cash to our shareholders. We're truly excited about the many benefits that the combination of Oxy and Anadarko will bring to our shareholders, and we're encouraged by the feedback we've received from shareholders regarding the transaction and our discussions over the last few months. We also look forward to providing quarterly updates on Synergy capture, deleveraging and the integration process. I'd like to start this morning with the excellent operational and financial results that our core businesses delivered in the second quarter of 2019, along with some other key accomplishments. The strength of our integrated business model, confidence in our future performance and commitment to returning cash to our shareholders enabled us to increase our dividend for the 17th consecutive year. And we're committed to continue to increase the dividend. We returned approximately $600 million to shareholders in the quarter representing 33% of cash flow from operations before working capital. We remain focused not only on returning capital to shareholders, but also on generating higher returns on capital. Our ability to achieve best-in-class returns through investing in our high quality assets continues to be evident as we generated a top tier, annualized cash flow, return on capital employed of 22%.
Cedric Burgher:
Thanks Vicki. For the second quarter, we reported core earnings of $0.97 per diluted share and earnings of $0.84 per diluted share as all of our business segments continue to perform well. The difference between reported and core income is due to onetime costs incurred with the Anadarko Trans acquisition. Also in the second quarter, we returned approximately $600 million of cash to shareholders through our dividend, and as Vickie mentioned, increased our dividend for the 17th consecutive year to an annual rate of $3.16 per share. Over the past 17 years, our track record clearly demonstrates our commitment and ability to consistently grow our dividend and to ensure returning capital to our shareholders remains a top priority. Oil and gas core income increased in the second quarter, compared to the prior quarter reflecting higher crude oil prices and volumes partially offset by lower domestic natural gas prices and a negative non-cash mark-to-market adjustment on carbon dioxide purchase contracts. We are very pleased to have lowered our operating costs on a per barrel basis across the board, both year-over-year and compared to last quarter. These cost improvements reflect higher volumes, improved downhole maintenance costs, and lower energy and surface operations costs. So a big congrats to our field operations teams, who continue to excel and lead the industry with low cost operations. Total second quarter reported production of 741,000 BOEs per day exceeded guidance due to continued best-in-class execution and well productivity and Permian Resources, which exceeded guidance at 289,000 BOEs per day and International production exceeded guidance at 295,000 BOEs per day, driven by increased production in Colombia, due to new exploration wells coming online. OxyChem surpassed the guidance with income of $208 million for the second quarter. Income decreased from the prior quarter primarily due to lower realized caustic soda prices along with fees received under a pipeline easement agreement executed in the first quarter.
Vicki Hollub:
Thank you, Cedric. Now I'd like to share how Oxy is uniquely positioned to extract the most value from this acquisition by applying our core competencies across the combined portfolio to maximize shareholder value. We have proven ability and decade’s long track record of innovatively recovering more hydrocarbons from conventional reservoirs than others could. We are continually improving and maximizing efficiencies and recovering hydrocarbons through water flooding and enhanced oil recovery. Today, we routinely recover more than 60% of the oil from large Permian conventional reservoirs and sometimes reach almost 70% recovery. Doing this cost effectively has required the development of extensive automation, advanced methods of artificial lift and materials expertise, as well as downhole subsurface expertise. These tools will serve us well to maximizing recovery from other less mature assets. This is a competitive advantage for us in the future.
Operator:
Thank you. Our first question will come from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate:
Thank you and good morning, everyone. Good morning, Vicki.
Vicki Hollub:
Good morning.
Doug Leggate:
Vicki on page 23 of your slide deck, I don't know if you should take the 6.6 billion as a capital guide, but it looks like that at least gives us an idea of how to frame our thoughts going forward. So that, if the combined company is doing closer to 9 billion, even adjusting for the African assets, that still suggests that the combined capital is already falling on your plan by substantially more than the 1.5 suggested. So I just wondered if you could speak to that, and related maybe speak to how the capital allocation on what you're thinking about as a preliminary thought, particularly in the Permian Basin. I've got a follow-up.
Vicki Hollub:
Yes. The combined capital was 9 billion, and we had committed to reduce activity levels to what would be the equivalent of $1.5 billion. But when you consider the synergies that we will achieve, that gets that 7.5 down closer to 6.6, as we achieve our $900 million of capital synergies.
Doug Leggate:
So in terms of how that gets allocated in the Permian. Well, let me explain what's behind my question. To drop activity, the working interest that Anadarko had was only 40% on the acreage. So clearly dropping a rig there has a much lower impact on capital than dropping a rig in Oxy but then Oxy has much better wells. So I'm trying to think about how do we think about relative activity within that capital budget in the Permian Basin.
Vicki Hollub:
Well, we view it from an investment level, not a rig count per se. So if you're developing on wells that have a lower working interest for you, then that's just more wells, you're going to drill, potentially more wells you'll run but you'll get the same synergies. So we look at it from an investment standpoint, not from a rig level standpoint.
Doug Leggate:
I understand, but presumably you'll give us greater details on that as we go forward. My follow-up is obviously this deal with Ecopetrol looks extremely capital efficient. Line of sight on asset monetization’s. I wonder if you could share any additional thoughts and specifically, obviously, everyone myself included, is still quite focused on how you deal with the midstream of WES not least because it's giving you a better than $600 million income right now from the unit distributions. So any updated thoughts on those and I’ll let someone else jump on…
Vicki Hollub:
Thanks, Doug. I'd say that from an overall perspective, the good, the other good, really good thing about this portfolio is that we do have a lot more levers to pull with the combination of OXY and Anadarko in terms of monetizations. So there are some things that we can do, the joint venture with Ecopetrol was one example of how we can do something creative without negatively impacting ourselves. So we will look at those kind of opportunities and with respect to WES, we'll have to after close, when we can take a deeper dive into what's happening there. We can make some analysis of that, but I'll say that the good thing about it and the reason we're so confident about our asset divestitures, is that we have a lot of incoming calls about various things. And so we're able to -- we'll be able to high grade what we want to do over time. The difficulty we have right now is that we can't signal really what we want to do, because that would, that would compromise our ability to negotiate.
Doug Leggate:
Can you confirm the press speculation about whether or not you had hired an advisor on WES?
Vicki Hollub:
We always use advisors and so we have some advisors that are helping us with various things. So I think it's -- I think that as we look at lots of aspects of our business we'll be bringing in advisors to get their feedback. That should not signal anything in particular that we're thinking right now because we have no decision made, on that.
Doug Leggate:
Understood. Thanks so much, Vicki.
Vicki Hollub:
Thank you.
Operator:
Our next question will come from Devin McDermott of Morgan Stanley. Please go ahead.
Devin McDermott:
Good morning and congrats on the solid results.
Kenneth Dillon:
Good morning.
Devin McDermott:
I wanted to start by actually following up on one of Doug's questions, just on synergies and also some of the activity in capital reductions. With the deal closing now potentially next week, it’s earlier than the initial target. So I was wondering if you could address how, if at all, that impacts the timing of synergy realization versus the initial plan, and also on the 1.5 billion reduction in growth spending, how quickly post close can that occur? Is that something that happens fairly immediately or will it be staggered over time and where were those reductions occur? If you can provide some guidance on that.
Vicki Hollub:
So we're going to meet our capital plan for this year. So, we'll meet the $4.5 billion for ourselves this year, we'll have to after close look at what's happening with Anadarko to determine what we do with the rest of their spending for the year. But the real-- the full $1.5 billion capital reduction in activity level will come in 2020. And I would say that, that getting that really depends on what we see after close and certainly the acceleration of the closing date is going to help us get a jump-start on our synergies. We had committed to 1 billion in synergies in 2020. So being able to do you get started here before the end of August, when initially we thought it could be a much later than that that's going to be very helpful for us.
Devin McDermott:
Got it. Great. And then my second question's actually on the OpEx side, just for Oxy stand-alone. You had some nice reductions quarter-over-quarter there, and it looks like some of the drivers are a mix between lower downhole maintenance and lower energy costs. I just wonder if you could comment a bit, in a bit more detail on what's driving those cost reductions, opportunities for further cost reductions over time and how initiatives like utilizing solar power in the EOR business might drive cost down going forward as well.
Vicki Hollub:
Yes, so our Resources business has been continuing to drive down OpEx as they get better with the artificial lift, the artificial lift in these shale wells was really challenging early on because it's too deep to make being pumping optimized. So too deep for that, too shallow, and the fluid production, a little bit too challenging for ESPs. So our team has worked really, really hard to find the right kind of artificial lift to use, and how to optimize it. And as they do that they are beginning to get much better at selecting the right kind of lift, and lowering the cost on that and of course, energy helps. And with respect to the EOR business in the US, it's our biggest cost one of our two biggest cost in the EOR business is the purchase of CO2 and energy in general. So, with respect to CO2 our Low Carbon business strategy is certainly going to help there because we're going to be able to ultimately install net power in the Permian Basin, which will further reduce our electrical cost, while also supplying a pure stream of CO2 for use in our operations. So once we get that -- start installing that in the Permian that will help a lot, but in the interim, we put in some solar already and plan to install a little bit more over the next year or so, and the solar is really good to reduce OpEx in our EOR operations and it reduces it at the most expensive part of the cycle. So that's very helpful. So it's going to take a combination of things over time to continue to reduce it, but we do have a strategy to do it, and I believe that that's going to be one of the key drivers to helping us start to take off for the growth in the EOR business in about 3 or 4 years.
Devin McDermott:
Alright Great, thanks so much.
Vicki Hollub:
Thank you.
Operator:
The next question will come from Roger Read of Wells Fargo. Please go ahead.
Roger Read:
Yes. Thank you. Good morning. Coming back to some of your comments Vicki, about the ability to evaluate the acreage, decide where you want to move forward, just curious how, how long it takes to do that? And as a second part, or the second question really, if we look at what's happening with some of the other players in the Permian today, if you could give us a little bit of an idea, tying that evaluation, into the performance you've had and how you've been able to avoid some of these problems we're seeing, the too much well density, or the parent-child issues all that just maybe one big wrapper there, around that whole package.
Vicki Hollub:
Okay. Certainly, I appreciate the question. But let me -- let me address the OpEx one more point on that. I forgot to give kudos to Anadarko because there, they've really manage their OpEx well, they have a low OpEx and they are apparently doing a really good job to manage that. So the combination bringing that expertise in to us, for the types of wells that they're operating will be helpful too. But to your question, it's going to take us a little bit of time, because what we have to do, the way we do our business to our subsurface characterization is, we drill appraisal wells and that helps get us some data, so we get some petro-physical and geophysical data from the logs that we run when we drill the well. We take that data and we combine it with our 3D data -- 3D seismic data, combining those two, then we can perform data analytics on it, and with the data analytics now, we can take that even a step further with a paradigm shift, we had a couple of years ago, on how to look at the subsurface differently, with respect to how the frac is going to be perform in the zone as you're trying to pump it. So not to say too much about that, but that's, but we went through that process to get us to where our productivity was a couple of years ago or about a year and a half ago. Now what we've done is, we've been able to incorporate 4D frac designs, which is helping us to more accurately understand what's happening with the frac and then not only what's happening with the frac, but what's happening with the drainage area. And that's all really key to spacing and how you design your wells, where you land your wells and all of that. So our subsurface models are much more sophisticated today than they were about three or four, five years ago, and the kudos on that go to our subsurface teams that have worked it really hard, but also our business unit who watch these wells every day, figure out what's happening with them and collaborate with our subsurface team to really get down to trying to figure out what's happening in the subsurface. We've seen some operators that just do this on a statistical basis deal, but you really can't do that and optimize what you get from these wells and the value of these wells. This -- this takes a lot of science and it takes science that -- it goes beyond what we've ever had to do with conventional reservoirs. So the companies that that only drill conventional reservoirs around the world-they haven't dealt with what we are having to deal with here, from a complexity standpoint. We've conquered that, but it's taken a lot of data to do it. It's taken some patience and time, and it's taken getting it to the point where you know it's working, because now we can, and we're predictive with that we can blind wells that we've drilled in the past and run the model and the model will tell us --will match what we're seeing from the wells that we're producing. That's why we're very confident that this model, what we're using now will not only work in other areas outside the Delaware Basin, but in other basins. That's why we're very comfortable that in the D.J. and in the Powder we're going to see increased productivity there, based on the model that we're using. And we think it takes a lot of science and it takes patience so that's why we've said that some of our synergies we can't get in 2020, some of our synergies are going to come in 2021, because we're not going to spend dollars to do trial and error. We're really going to need to have our model and then that's going to take drilling some appraisal wells, and making sure that we have the 3D to match it, and the data analytics around it, but that's why it's going to take a little time to get all the synergies. But we're very confident that we'll get the synergies. Jeff, do you have anything to add to that?
Jeff Alvarez:
Hi, Roger. The only thing I'd add, Vicki did a great job covering that, but I think, and you know this that is our secret sauce. So I mean we've been like Vicki said, advancing that for years now and not only is it our secret sauce. It's a secret sauce worth having, and because of the value that it creates and I mean a couple of things that she hit on, I think are really important to stress, not just the integration of the work close with geo-modeling, geo-mechanics, petro-physics, stimulation, reservoir simulation, but it's really the combination of the people, tools and data, because the thing we get asked all the time by other people is, how easy is it replicated. And I think the important thing is, if you remove one of those things, the people, the tools or the data, the other two don't work is optimal as they will, if you have them altogether. So that's why we show on Slide 18, 19 and the performance results. It's not just one thing that goes there you need all of those ingredients to really extract the value, that's what makes us so excited when we look at other reservoirs and being able to apply it because we think it definitely works, not just in the Wolfcamp or the Bone Springs, but in all unconventional reservoirs.
Roger Read:
Thanks, build a better mousetrap and you win. Congratulations.
Vicki Hollub:
Thank you.
Operator:
Our next question will come from Will Atkinson of UBS. Please go ahead.
Will Atkinson:
Good afternoon. I was wondering if we could touch on the rationale for a joint venture, rather than a complete divestiture, especially given the depth of your inventory across the Delaware.
Vicki Hollub:
Yes. The reason for a joint venture, is we like the acreage in the Midland Basin, it's quality acreage, quality assets, and we think over time. Again, we haven't built us into our near-term model and we didn't include it in the --in how we evaluated this acquisition. But the upside over time is to use our enhanced oil recovery to get more of the reserves and resources out of the wells. So we are preserving our opportunity to get significant upside in the Midland Basin, through the application of CO2 enhanced oil recovery ultimately, and we think the more that we have of this, the more upside that we have over time and that we believe will give us an edge into the future on being able to get more out of existing wells rather than having to go drill new wells.
Will Atkinson:
Perfect. Thank you.
Vicki Hollub:
Thank you.
Operator:
Our next question will come from Pavel Molchanov of Raymond James. Please go ahead.
Pavel Molchanov:
Yes, thanks for taking the question. As you think about deleveraging, obviously the Ecopetrol deal marks the first step. Are you seeing other instances of this kind of rather unusual model, where a player that may not be in a particular geography that you're operating in, is going to rely on you for skill set development and sort of that kind of active partnership beyond simply selling acreage.
Vicki Hollub:
Well you are giving me an exciting opportunity to talk about our low carbon business strategy and that, we are getting calls from all over the world, with people wanting our help to -- to help them also figure out how to capture CO2 from industrial sources, and then what to do with it and oil reservoirs. We have the processing capability, we have the ability to design it and we're the largest handler of CO2 for enhanced oil recovery in the world. So what's happening with these calls that we're getting for technical assistance is that, in some cases, there has been offers, allowing us to come in as a participant in the project, so these are not only opportunities to earn some revenue for our low carbon ventures business through technical providing -- technical services and valuations, but also to, to look at projects around the world for possible participation. So that's one way. That's one unique and different thing that that we're seeing happening to our group now, and that's really exciting, because as we go forward, there's going to be more pressure on companies to do something about their climate change story, and so that's making a lot of people get much more interested in what we're doing than just a few years ago. So that's one example. There -- we are always trying to look for ways to monetize things but without losing the potential eventual upside. So, we are getting creative and continuing to look at ways to do that.
Pavel Molchanov:
Okay. Well since you mentioned ESG, let me follow up on that. I could not help noticing that your U.S. realized gas price in the quarter was $0.23 obviously some kind of one time shifts in there, but the -- is there a point where you would, have to resort to flaring in the Permian, because the economics of selling the gas are just lopsided.
Vicki Hollub:
We would not do flaring as a normal routine practice, we don't agree with that, and we wouldn't do it, so we will always try to find a way to utilize the gas and the net power concept that I just mentioned earlier, I should probably explain that a little bit better. Our team, last year or maybe it was the end of the year before, invested in a new way to generate electricity and it's called NET Power. What it does is, it takes natural gas combines that with oxygen and burns it together, and that's what creates electricity and it creates that electricity at lower costs, especially if you are using gas that cost like $0.10 or $0.15 or $0.20, which gives us this great opportunity because we're piloting that now, we have a pilot project where part-owner. We've invested in it and we are strategic partner to eight rivers, the group that developed the concept and put the pilot in place to start it. It's, it's in -- the pilot is just South of Houston here. So that's one of our solutions, is to put that in the Permian. It will utilize our gas that that if we sold it would make nearly as much. So it will, not only will it give us a way to utilize that lower-cost gas. It also, as I said earlier, provides that pure stream CO2 off of it, for use in our enhanced oil recovery. So it's a dual benefit of having a way to better utilize our lower priced gas, and also create the opportunity to you CO2 to increase our oil production. It's a really unique way of dealing with the scenario that we have in the Permian that we expect to be able to have that installed over the next two, three years. It's a little bit out, but in the near term, we don't see that we're going to have to flare. We have the capability to get it out it's just that it's certainly there. There are other ways to better utilize our gas and to get more value for it then selling it for $0.23.
Jeff Alvarez:
Hey, Pavel one other thing I'd add to Vicki's comment. EOR, so injecting we've been advancing EOR not just with CO2 but also hydrocarbon gas. And the cheaper the hydrocarbon gas, the better the economics get for EOR because you're basically replace and oil for gas. So that's another thing, we continue to advance, so that you don't flare. But you can extract value from.
Pavel Molchanov:
Okay. Very useful. I Appreciate it.
Operator:
Our next question will come from Phil Gresh of JPMorgan. Please go ahead.
Phil Gresh:
Yes. Thanks for taking my question. First, Vicki you made a comment in your prepared remarks, you expect a combined Permian business to be free cash flow positive at $45 WTI in 2020. So I was just wondering, for a little more detail on that, first part would be is that including EOR or is it just more of the standalone Resources business. And then, what level of rig count and CapEx and just underlying details to help us think about that in the context of this overall CapEx reduction plan that you have, through 2021. Thanks.
Vicki Hollub:
So in 2021, it would be the Resources business and it's at the capital level that we projected for 2020. So that would be capital for us and 2020 would be at the $6.6 billion -- have we given -- any additional. Okay. So the run rate of the 6.6, the actual 6.6 is in 2021.
Phil Gresh:
Right. So you are going from 9 billion to 6.6 and I think you said in 2020 you expect Permian Resources to be free cash flow positive at 45. Correct?
Vicki Hollub:
That's correct.
Phil Gresh:
Okay. And so I would be an equivalent level of cap, Resources' CapEx baked into the 6.6 to get to that.
Vicki Hollub:
Right, let's say the 7.5; make sure you use the run rate of 7.5% before the synergies of 900 million, which will be fully achieved in 2021.
Phil Gresh:
Okay. Okay, got it. Second question, I guess just on the balance sheet, Cedric any latest thoughts here. I think your target all along has been to get to sub 2 times. You've given numbers with and without WES obviously you announced the JV today but any new thoughts there about how quickly you can get to that leverage level and what other levers you might be wanting to pull to get there? Thank you.
Cedric Burgher:
Yes. Thanks, Phil. The asset sales obviously are the primary lever there. We've given you kind of a timeline of 12 to 24 months, we think will be on the early side of that. So, and then also as Vicki mentioned earlier, we have expect to have excess free cash flow and if need be, if we for whatever reason hit a snag we direct more of that than planned to delever, is at the very top of our list of priorities. We don't expect to need to do that. We think that that they asset sales will get us there and get us there fairly quickly. These things don't happen overnight, but. But we think we can easily get there in the timeline, we've allotted. The second thing I would say is that our target, we've said that 1.5 times debt-to-EBITDA that $60 oil WTI by the end of 2021 is kind of our target and base plan, and we're not going -- we're not going to stop there, that is we know for our weight class, we have too much debt, it's our highest priority to knock it down. We have the means to do it. We have a lot of levers, we can pull and so we're going to aggressively do that and we're not stopping at the end of 2021, but we expect to go through that, and get down too much even lower level -- leverage levels beyond that time. So we expect to basically be back to where we are, or better from a credit metric standpoint prior to the acquisition.
Phil Gresh:
Okay, thank you.
Cedric Burgher:
Yes.
Operator:
The next question will come from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer:
Thank you. Good morning. I had a follow-up actually, just a series of questions with regards to slide 18, given the strong productivity gain shown there in every year but particularly 2019. The first is, if we looked at this on an oil only basis with the gap between 2018 and 2019 look the same, second, what do you see as the longevity to continue to drive productivity gains on Oxy space assets and, third is, what is your base case I realize is an appraisal process to that you need to go through, but what is your base case for how Anadarko well performance and well costs will ultimately compare relative to Oxy's?
Vicki Hollub:
I'll take the second one. And I'm going to toss first two to Jeff. We really haven't gotten into their specific data well enough to know, we see the results of the wells, but what we want to do is dive a little deeper, see what data they have, and do our full analysis on it before we can answer a question like that but, we'll be doing that as quickly as we can. And fortunately, getting them to start doing that on a, on a deeper level here in about a week. So I'll pass it to Jeff.
Jeff Alvarez:
Hey, Brian. I think I got your first question was, what would it look like on a oil basis? It would look roughly the same. And the reason I would say that is, if you look at our, our oil cuts for Permian Resources over the last 2.5 years -- we've range from about 59 to 62. This year we've been right around 60, last year, we were 61 to 62, the year before we are just a hair below 60, so that's the kind of variability you get on total resources oil cut. So it wouldn't materially impact that curve when you look at it. Now obviously this year has been a percentage point or so less and that's just a function of where we're drilling different reservoirs that have different gas oil ratios with them, it's not anything that's problematic or something we didn't expect. It's just where we're developing.
Brian Singer:
Great, thanks.
Jeff Alvarez:
And then what was your other question, Brian. I'm sorry
Brian Singer:
The second one was the longevity to continue to drive productivity gains. Just on the Oxy assets. In other words, how many more years in the tank do you think you have faced in the processes of that you've, the technologies that you've talked about.
Jeff Alvarez:
Yes, again, I mean, this one is so hard. It is, it's always difficult to know, we can see what the teams are advancing. I mean, every time we talk to the teams working on advancing our performance, I just kept blown away at the things they're thinking about, and working on , like we talked about the 40 models that Vicki talked about, when you look at that our ability now to understand how frac geometry changes, not only in a single well over time, but how it changes in a multi-well section development over time. Two years ago I never thought we would be able to understand how frac geometry changes over time, or how wells would interrelate with each other given the time component. Now that we can understand that, we're able to figure out better landings, better placements, better frac designs, that continue to propel the advancements. So I would answer it is, I don't know how we will improve next year, but I guarantee you that the teams are going to figure out how they continue to make well performance better, and they've done it every year since 2015 when we really started aggressive development. So it's hard to believe that's going to stop any time soon. I think it will just come from different areas, different things will drive it, just like different things drove it from '15 to '16 and '17 to '18 and so on, but I do continue to think or we're going to get better and if you put this over and you focused on value instead of rate. I think that has even more running room than just rate and volume performance, but on the value side.
Brian Singer:
Great, thanks. And then lastly on outside of the Permian, can you talk about any key learning’s in the Anadarko, Gulf of Mexico are DJ Basin assets and any impacts that those have on your commitment to maintaining and retaining those assets in the going forward combined company, and on the capital and growth outlook there?
Vicki Hollub:
Well, Ken's been very involved in that. We'll let Ken answer that one.
Kenneth Dillon:
Yes, thanks. We're looking forward to operating again in the Gulf of Mexico. I think one thing I have to say, we're operating as two separate companies, at this time, but I think we're really pleased of our former asset Horn Mountain returning to Oxy again, we were involved with it since the Varstar days even before BP were involved in it. We always believed it had long-term potential. So I think we're looking forward to the picking that up. I think our goal with Gulf of Mexico so far is to the deliver long-term stable cash flow through step wells close to the existing facilities. So very similar to Anadarko's approach and with Horn Mountain back I think we can see that potential running in for some time.
Brian Singer:
Great, thank you.
Operator:
Our next question will come from Leo Mariani of KeyBanc. Please go ahead.
Leo Mariani:
Hey guys just wanted to follow up a little bit on the asset sale. Topic here, just wanted to get a sense, has kind of OXY at this point really identified what they want to sell. I know obviously, you'll be price dependent on ultimately what you sell, but you feel like you kind of have your punch list, sort of down. And have you guys integrated the rating agencies as well in kind of some of these discussions, as you look to hit your leverage targets over time.
Vicki Hollub:
I would say that we certainly, we have a punch list of things that we'd like to do, and that's why we want to keep that quiet for our negotiating power, but we do have a punch list and every now and then something comes up that that's unexpected and out of the ordinary and we look at those too. So that's why we're really encouraged that we'll be able to achieve our targets and Cedric will address the credit agencies.
Cedric Burgher:
Yes, we've had, we've for years, but even especially this year had extensive ongoing dialog with our rating agencies. We have a confidential arrangement with them, so we're able to share a little more information. All I would really say though is that you --so they are very well-informed on our plans and you can see some of the actions we're taking to today. In fact, some of that information or news comes out, but what I would say is that we've got a longer list and we have needs and so we think we can easily achieve our plans and I think the agencies understand that.
Leo Mariani:
Okay. And I guess just a brief follow-up to that, is there any update at all on the timing of the Africa sale and then additionally, Cedric obviously you got off the significant hedge. Are you guys considering other hedges for 2020, given that was portion of your production. But you still have significant remaining oil production unhedged?
Vicki Hollub:
I'll take the Africa question, we really, until after close would we really can't make any comments on timing or anything like that, we'd prefer to get a little bit further down the road and we'll update you when we can.
Cedric Burgher:
So on the hedging. We're very pleased with what we're able to pull off in actually a very short period of time I was skeptical, we'd be able to achieve what we've done. But as Vicki mentioned earlier in her prepared remarks, we've hedged just under 40% of our combined company oil volumes if you take a Anadarko's second quarter in our second quarter for oil volumes just under 30%, 40% there. And then if you exclude PSC volumes for us, you get approaching almost 50% of our volumes hedged. If you look at not just in the second quarter basis, so very pleased with the position, not going to be speculative about future hedging doesn't help us to do that other than to say, we'll be opportunistic. I would expect this to be primarily focused on when we're in a more leveraged situation this is giving us a great deal of additional support in a low price environment, potentially in 2020. But beyond kind of the deleveraging that we've talked about, we're not I'd expect us to kind of go back to the way we've been, which is a very little to no hedging but we'll be opportunistic and we could see ourselves putting on more hedges or possibly not doing that as well.
Leo Mariani:
Okay, thank you.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
Yes, I'd like to say thanks to the OXY employees for operating safely and delivering great results. And to say we're excited to bring on the Anadarko employees, looking forward to that and then it can't happen soon enough. Thank you all for your questions and for joining our call. Have a good day.
Operator:
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect your lines.
Operator:
Good morning, and welcome to the Occidental's First Quarter 2019 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Allison. Good morning, everyone, and thank you for participating in Occidental Petroleum's First Quarter 2019 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Ken Dillon, President, International Oil and Gas Operations; and Oscar Brown, Senior Vice President, Strategy, Business Development and Integrated Supply. In just a moment, I will turn the call over to Vicki. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the Federal Securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements, as more fully described in our cautionary statement regarding forward-looking statements on Slide 2. Our earnings press release, the Investor Relations supplemental schedules and our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good morning, everyone. I'd like to start by recognizing that many would like to discuss our proposal to acquire Anadarko, which we will address. But first, I plan to cover the excellent results we achieved in the first quarter and reiterate that our commitment to our value proposition remains unchanged. Creating shareholder value continues to be our #1 priority. Our integrated business is delivering outstanding results, and we continue to be a leader in each area we operate. We are dedicated to returning cash to our shareholders, delivering industry-leading returns and executing our strategy. During the first quarter, we did just that. We returned $800 million through dividends and share repurchases driven by excellent results from all 3 of our business segments. Since 2002, we've returned $34 billion of capital to our shareholders, and our assets continue to generate free cash flow for future distributions. In the Permian Basin, our operational expertise and deep knowledge of the subsurface is unmatched. And the well productivity data is clear
Cedric Burgher:
Thanks, Vicki. For the first quarter, we had reported earnings of $0.84 per diluted share as all three of our business segments continued to perform well despite a lower commodity price environment. We are also pleased to report that we returned $800 million of cash to our shareholders in the first quarter through our dividend and share repurchases, so overall, a very strong quarter across the board. Oil and gas core income increased in the first quarter compared to the prior quarter, reflecting lower DD&A rates as well as a positive mark-to-market adjustment on carbon dioxide purchase contracts, partially offset by lower crude, oil and NGL prices and lower sales volumes due to the timing of liftings. Total first quarter reported production of 719,000 BOEs per day exceeded guidance due to continued best-in-class execution and well productivity in Permian Resources, which came in at the high end of guidance at 261,000 BOEs per day. International production exceeded guidance of 298,000 BOEs per day driven by strong operational performance in Oman, as well as the oil price adjustment in our production sharing contracts. OxyChem exceeded guidance with earnings of $265 million for the first quarter. Earnings increased from the prior quarter primarily due to favorable feedstock costs, such as ethylene and natural gas, along with fees received under our pipeline easement agreement executed in the first quarter. The increase in earnings was partially offset by lower realized caustic soda pricing in addition to production being curtailed at various OxyChem facilities by a third-party tank farm fire in Deer Park, Texas. All OxyChem facilities have resumed safe operations. Our midstream business also exceeded guidance with a first quarter income of $279 million primarily driven by a higher Midland-to-MEH differential and a lower-than-expected mark-to-market impact. Compared to the prior quarter, the decrease in earnings reflected lower Midland-to-MEH differential, which decreased from approximately $15 to $9.78. Working capital changes included cash payments typical of the first quarter, including property tax and fourth quarter accruals. Both OxyChem and our marketing businesses also experienced a working capital draw as a result of a receivable build due to higher prices and volumes. Slide 9 details our guidance for the second quarter and full year 2019. We are on track to deliver annual production growth of 9% to 11% while staying within our capital budget of $4.5 billion. Due to our outstanding proposal to acquire Anadarko, we have suspended our share repurchase program. I'll now turn the call back over to Vicki.
Vicki Hollub:
Thank you, Cedric. Now turning to our proposal. As you have likely seen, yesterday, we delivered an updated proposal to the Board of Anadarko as well as announced a contingent agreement to sell Anadarko's Algeria, Ghana, Mozambique and South Africa assets to total for $8.8 billion when we complete our proposed acquisition of Anadarko. But before we discuss the details of those announcements, I'd like to quickly recap recent events related to our proposal and situate yesterday's important updates in the proper context. On April 24, we announced our superior proposal to acquire Anadarko for $76 in cash and stock. We continue to believe in the compelling financial and strategic merits of this deal, which would enhance Occidental's sustainable value proposition and benefit both companies' shareholders. On April 29, Anadarko announced its Board of Directors had determined that Occidental's April 24 proposal could reasonably be expected to result in a superior proposal, and our 2 companies have since been engaged for that determination. On April 30, we announced that Berkshire Hathaway has committed to invest a total of $10 billion in Occidental, contingent upon the completion of our proposed acquisition of Anadarko. We're thrilled to have Berkshire Hathaway's financial support for this transaction and believe it reaffirms what we've long believed that Occidental is uniquely positioned to generate compelling value from Anadarko's highly complementary asset portfolio. This is committed acquisition financing that provides us with the ability to increase the cash component of our proposal in a more balance sheet-friendly manner than issuing additional debt. Yesterday, we announced an agreement with Total to sell Anadarko's Africa assets, contingent upon us completing our proposed acquisition of Anadarko. We're pleased to have secured this agreement with Total as it fast tracks the divestiture plan we previously outlined in connection with our proposal. Our agreement with Total to sell these assets to a terrific company allows us to focus all of our integration efforts on the assets most valuable to Oxy. The almost $9 billion sale price funds a portion of the cash consideration to Anadarko while delivering on the majority of our $10 billion to $15 billion of planned asset sales. Importantly, this sale supports our expectations around synergies, and we continue to expect to deliver $2 billion of annual cost synergies and $1.5 billion of annual capital reductions from the proposed acquisition of Anadarko. The financial support of Berkshire Hathaway as well as the agreement we announced with Total also help us to de-lever our balance sheet while focusing our integration efforts on the assets that will provide the most value for us. Yesterday, we also delivered a revised and significantly enhanced superior proposal to the Board of Anadarko to acquire the company for $76 per share with the revised terms of 78% in cash and 22% in stock. Under the terms of the revised proposal, Anadarko shareholders would receive $59 in cash and 0.2934 shares of Occidental stock per share of Anadarko. Pro forma ownership of the combined company would be 84% legacy Occidental shareholders and 16% legacy Anadarko shareholders. The increased cash portion of $59 per share provides significant immediate value, greater closing certainty and enhanced accretion. This revised proposal represents a premium of approximately 23% to the $61.62 per share value of Chevron's offer as of Friday's market close. Our revised proposal does not require an Occidental shareholder vote, which has been cited as the explanation for Anadarko's Board's prior selection of Chevron's $65 offer over our $76 offer. Changing the consideration mix to be cash-heavy is more accretive to us and addresses the issue that Anadarko focused on as their reason for taking the lower bid last time. We firmly believe that Occidental is uniquely positioned to create significant and sustainable growth and value from Anadarko's assets. We've studied this opportunity for almost two years. This is a key long-term decision for us, and we understand what a great opportunity this is for us and our shareholders. We encourage Anadarko's Board to comply with their fiduciary obligations and accept this compelling proposal for Anadarko shareholders. We hope we can continue to execute this merger agreement without delay and proceed to bringing this exciting combination to fruition. We'll now open it up for your questions.
Operator:
[Operator Instructions] Our first question today will come from Brian Singer of Goldman Sachs.
Brian Singer:
My first question is with regards to the legacy assets and first quarter results. First quarter CapEx was about 28% of full year guidance, and Permian Resources' CapEx was about 30% of the annual budget. Can you run through your expectation for the CapEx trajectory for the remainder of the year? And given higher oil prices, what do you see as the potential to maintain spending run rates and raise the annual budget later in the year, as was done in 2018?
Vicki Hollub:
No, our plan is to hold the budget where it is at $4.5 billion. As we had mentioned I think in the last earnings call, we were going to be coming into the year hot, but we're going to be slowing down activity toward the end of the year to achieve our $4.5 billion capital budget.
Brian Singer:
And can you talk a little bit more about how you see that or where you see that? And is it fourth quarter specifically?
Vicki Hollub:
It would be a combination of third and fourth quarter, and they'll be mostly in the Permian Resources business.
Brian Singer:
And then my follow-up is one of the advantages highlighted in your letter to Anadarko and in your comments for Oxy's revised bid for Anadarko is that it does not require a shareholder vote. Recognizing that the requirement for shareholder vote at 20% equity issuance threshold is a rule from the NYSE, how do you and the Board weigh the benefits of the stronger bid as a result of no longer requiring a shareholder vote and the cost of capital that's come to achieve that relative to the Board's Corporate Governance objectives?
Vicki Hollub:
Well, I can say that in the 1.5 years that we've been engaged in making offers to Anadarko, we've always made offers up to this point that required a shareholder vote. So our objective in doing this was not at all to avoid the shareholder vote. It was to ensure that we had a reasonable chance to make this happen. We weren't playing on a level-playing field. From a governance standpoint, avoiding the shareholder vote is not something that we wanted to do. But rather than increase our price, we felt like it was in the best interest of our shareholders to hold our price where it is. And as you have seen, we put our last proposal in. And even though it has an $11 differential, our bid, still after 12 days, was not declared superior. So from our standpoint, we saw the two options as increase the share price or provide clarity of closing. We felt like clarity of closing was the lower cost even with the Berkshire financing because remember, our yield is 5% already. The incremental 3% of the Berkshire funds, for us, was well worth it when we took into consideration what the upside of this deal was versus losing this opportunity that for two years we've worked on. We know the upside pretty well. As you know, this fits within our core experience and expertise. So achieving the $2 billion in synergies is quite clear for us. And when you take all of that into consideration, we felt that our greater fiduciary responsibility from a governance standpoint for our shareholders was to make this deal happen.
Operator:
The next question will come from Josh Silverstein of Wolfe Research.
Josh Silverstein:
I'm just going to stick with the synergies since you ended there. You highlighted the $3.5 billion number on the initial deal, and I know why you're reiterating the views today. How does the Berkshire financing and the additional debt needed to increase the cash offer not eat into them?
Vicki Hollub:
Well, the synergies that we have are an estimate. We believe actually that we can exceed those. They're a conservative estimate just based on what we are achieving today. We haven't built in the upside. And we really haven't built much of the upside at all into the model that helped us arrive at a $76 offer price. We believe that the upside in these assets is far more than what we modeled, but we're being conservative in what we see with respect to not only synergies but the incremental and recovery from these wells. We've built nothing into our model for the Powder River and nothing for the mineral rights trend, and then very, very, very conservative for DJ and Delaware Basin. And for more specifics on each of the buckets, I'll turn it over to Cedric.
Cedric Burgher:
I'd just add that we have updated. We have two new investor decks out there today, one for the earnings, one for the revised proposal to acquire Anadarko. And on Slide 13, I'd just point you to those cash flow per share and free cash flow per share estimate for 2020 and 2021. They include our synergies, of course, but also the Berkshire Hathaway financing, as well as the sale of the African assets, so all of that has been updated. As you can see, this thing is very accretive, even more accretive than the prior deal on a cash flow per-share basis. And on a free cash flow per-share basis, you can see this deal is very powerful from an financial standpoint. And so when we looked at things, all things considered, it was just part of a more holistic approach to looking at the deal, what it took to get there versus losing it, especially losing it for non-financial reasons, the optics of a vote and so on.
Josh Silverstein:
And just on those points, I mean you guys are obviously willing to go out and put another bid on the table without knowing what Chevron's response would be. It seems as if you're finding more upside in this transaction and more willing to go out and get this deal, if I'm reading that correctly.
Vicki Hollub:
We believe this to be transformational for Oxy. It's very rare, in fact, generational. When you see an opportunity like this come along where you can check every box that you want to check from a value standpoint, it's accretive to cash flow. It's a, as Cedric just described, tremendous asset base with a huge upside. It's also it's got scale. And it's got things I believe that haven't even been evaluated yet, because Anadarko has been busy working on the DJ, the Delaware. They've begun working in the Powder, which I believe is going to be an upside. And Anadarko has incredible people, too. So we believe that the combination of their employees continuing to have the opportunity to work these assets and with the culture they have blending into our culture, which we think is going to be a fairly easy transition, we think that there's tremendous upside. And we've identified what we feel comfortable with and see today. But I think you're right, there will be more, and there are things we're excited about that we're just not quantifying yet.
Josh Silverstein:
So there's more than just the Permian Basin here. I'm guessing that's the reason why you're not just going out and doing one to two Permian consolidation transactions?
Vicki Hollub:
It's much more than just the Permian. It's the amazing cash flow from the Gulf of Mexico that's going to help to fund additional return of cash to shareholders because both the DJ and the Delaware are close to being free cash flow generating. And then you have to build on that ultimately as we go along the Powder River position. So we're really excited about it. It gives us so much more flexibility with what we can do with our dollars and the free cash flow.
Operator:
The next question will come from Devin McDermott of Morgan Stanley.
Devin McDermott:
So the first question I wanted to ask is just hoping you give a little bit more detail on the dialogue and process that you've had here with Anadarko's Board and specifically what the key areas of focus or concern are for them and what has or hasn't been addressed in the latest proposal. I understand the shareholder vote was a key one. That has now been taken out. But in your letter to the Board, you highlighted some others like the potential Board seats that Anadarko was asking. So I just wondered if you can talk a little bit more about what, in your view, has and hasn't been addressed and what some other sticking points have been in the conversation so far.
Vicki Hollub:
Well, I think as we've gone along, we went back and did some rehashing of some things that we had previously looked at and we've got worked through all of that. Their management team with our management team has been very engaged. We've got it down to working just some of the details around employees and benefits programs, making sure that we're making fair and equitable decisions for both sets of the employees and both companies. So it's just been a 12-day process. And my concern is that as we were going along and discussing things that were getting to the point where they weren't quite material, that our proposal still wasn't deemed superior, which is why we yesterday submitted the increased cash offer.
Devin McDermott:
And then my follow-up's on actually the balance sheet. So one of the changes with the revised bid is there's a higher cash component and we now have the preferred equity, as you noted, from Berkshire Hathaway in the mix. But the overall pro forma leverage with more cash does, at least on our estimates, look higher, and you've addressed that partially with the, I think, attractive asset sale here of the Africa portfolio. Can you just talk about how you're thinking about the balance sheet and de-levering plan here? Any dialogue you may or may not have had with the rating agencies as part of this revised bid?
Cedric Burgher:
So certainly, it's a higher cash bid, so more leverage. We have mitigated that through the two transactions we've talked about
Operator:
The next question will come from Phil Gresh of JPMorgan.
Phil Gresh:
Just I guess to follow up to the last question on the balance sheet. Cedric, on the last call we had, you talked about there being a lot of buyer interest in asset sales, inbound interest. And so I guess I was just wondering now that you've announced this transaction with Total, was that the main set of assets that you were referring to? Or do you feel like that there are other things you're working on in the Q that could get the balance sheet in better shape faster?
Cedric Burgher:
That was definitely the largest set of assets we were receiving inbounds on. There are others, and we certainly have a pipeline of other transactions we think we can execute. And so we can continue to de-lever further and over-achieve our asset sales targets.
Vicki Hollub:
I would just also reinforce that it's been really for us very, very encouraging to see the offers and the interest coming in and the fact that we believe that we will far beat what we've laid out to accomplish.
Phil Gresh:
And then just to clarify on the Total deal. Is that a done deal no matter what as long as the Anadarko deal closes, i.e., there are no other contingencies? And then secondarily, Cedric, you mentioned the leverage metrics, excluding Western Gas. If you could clarify what it would require in order to deconsolidate that. If that were something you're interested in, just mathematically, what would need to be done?
Vicki Hollub:
First, I'll start with the Total question. It is contingent only on the deal going through with Anadarko. And I will say we're really excited about that one because Total, we partnered with them for a long time in the Dolphin project. We know them well, and we know that they're going to be able to maximize the value out of the Africa assets and get more than anybody else could, we believe. And so we're excited about that arrangement, and we will continue working with Total on other opportunities in the Middle East and other areas.
Cedric Burgher:
And then with respect to Western Gas MLP consolidation, Anadarko currently owns about 55% of the MLP. And because of the governance structure that's unique to MLPs, in this one in particular, you could sell down to 20% and still have effective control again through the governance setup for that MLP, so you would therefore, in that instance, if you sold down to even 20%, you would still consolidate for sure. If you sell down below 20%, you still likely consolidate because again, there's a lot of control mechanisms that trigger consolidation. So not sure exactly where the line is, it probably is close to zero, if not zero ownership position in the MLP before you would deconsolidate. But if you think about it from a standpoint of legal liability and obligations, that debt at the MLP is nonrecourse. And so in some respects, it's purely an accounting nuance in terms of the consolidation and who's responsible for the debt at the MLP.
Operator:
The next question will come from Pavel Molchanov of Raymond James.
Pavel Molchanov:
You noted that share buyback has been suspended. Is that a purely legal step for the duration of the uncertainty over the outcome of the current process? Or do you anticipate keeping the buyback suspended even after closing Anadarko if that happens?
Cedric Burgher:
We think it's prudent to suspend the buyback now. We've actually done that for the last month or so, a little longer. Once we felt that this transaction had a higher probability of happening and there was enough material information that wasn't yet public, we thought it was the prudent thing to do to suspend it. So that was the first gate. Secondly, certainly, if we close on the transaction, we will be suspending the buyback. Our highest priority will be reducing debt, and we won't be buying back shares until we get down to the debt targets that we've established.
Pavel Molchanov:
Can I also ask about the carbon comments, previously with obviously a much more simplified asset base, you've said that you want to be 100% carbon neutral. Will that target continue to apply to the greatly expanded and diversified production mix if, in fact, this deal happens?
Vicki Hollub:
That will continue to be our goal. It could extend that out beyond where we had initially hoped to be, that's still our goal. We think we have the strategy that can accomplish that over time, and we think it's really our responsibility to do all that we can do to make that happen. And we're really excited about what our Low Carbon Ventures team is doing, the strategy that they're putting together. It's not just going to impact our operations, but they're actually in a position where they are influencing and helping others too. So we believe that the extent of the benefit of what we're doing will go far beyond just our company.
Operator:
The next question will come from Leo Mariani of KeyBanc.
Leo Mariani:
I wanted to see if you could provide with more detail around the $2 billion of ongoing annual cost synergies here. What I'm really trying to get at is whether or not there's maybe some breakdown as to how much of that you might see in the Permian versus the DJ. Just want to get a sense of what those synergies may be in the DJ given that's an area that I don't think you guys have operated in before.
Vicki Hollub:
I'll start with this and then we'll give you a little more view of what the full synergy outlook looks for each of the buckets. But the reason we say that is we, over the past few years, our team, our subsurface teams working with our business units, the combination of those hand-in-hand looking at how do we improve our performance in the shale play in general, have made some key breakthroughs. And I have to say, it's all of our teams working together from the geophysicists, petrophysicists, geologists, engineers and even a person that we brought over from a NASA contractor who helped us look at or see a similarity between looking at composites and how they fracture in aerospace industry with how we look at our subsurface. All of that together and then applying data analytics has enabled us to, we believe, find a breakthrough in how we look at not only how fracturing works but what you should expect your flow unit to be. And once you've determined what you expect your flow unit to be, then you can tailor your frac designs more appropriately for what you're seeing in the subsurface. And then by tailoring it, you can then optimize your profit. And we have gotten into the point where we're not only having really good results, but we're getting predictive with it, and predictive where you have 3D seismic and you can look at your attribute analysis and make some judgments and assessments on what you expect to see that's similar to what you already have in your analytics database. So when you look at that and you look at how we've been able to do with 23 of the top 100 wells and using less profit than the other wells in the top 100, they use 37 -- I think it's 34% or 37% more profit. So when you look at that, what that means is you're basing this on physics. You're basing it on a science. We're taking a little bit of the art out of fracking and completing shale plays and so when you can do that, then based on the science, you can take that and apply it to other areas. And so it doesn't matter whether you're moving geographically or vertically within a wellbore, science works the same. And so in the Delaware Basin, we've taken it, we bonded some wells and found that its predictive capabilities are really pretty good. And so we know that we can do it in other shale basins as well. And I have to give a shout out to our subsurface teams. They've just done amazing jobs in the business unit and working with them to look at the possibilities and to try new things and to optimize as a team. It's been amazing. And I never expected us to see the continuing improvement that we've seen year-on-year, and we're still continuing. You've seen in the basin, in some areas where the productivity improvements have plateaued. They haven't with us. They continued to increase again from 2017 to 2018. So I think we'll see the same success on the DJ. Now I'll go to Cedric for a little bit more color around the rest of the synergies.
Cedric Burgher:
Just looking at Slide 12 in the updated proposal deck that we put out this morning, and the synergies haven't changed, so the prior deck, same slide. But if you look at the 4 different categories of synergies we've laid out, the first one, the domestic capital operating efficiency, that really is just getting Anadarko well cost down to where we currently are, primarily using our Oxy Drilling Dynamics reducing drilling costs and the proppant loading reduction, which reduces the completion cost. So we're going to talk a little bit more about the drilling dynamics here in a second. Ken is with us to help in that front. So that's the first bucket there. The second one, procurement and supply chain. We've talked a lot about our Aventine Logistics Hub and the savings we get there for ourselves. Again, we can deploy that in the Permian. In that strategy, we can deploy elsewhere, but primarily we've attributed savings in the Permian plus our supply chain. And Oscar Brown is here who heads up global supply and strategy for us. He can address that a little further. And then the last, the third bucket there, general overhead and corporate. It's primarily people, real estate and aircraft. We have one corporate aircraft plus an all-employee shuttle, to therefore, corporate airplanes. And so we don't think we need all of those, and we can reduce that along with obviously people and duplicate offices and real estate. And then we've talked about the capital reduction synergies, as well as a fourth bucket for you. So now I'll turn it over to Ken to talk about Oxy Drilling Dynamics and the savings we've achieved around the world there and then follow that with Oscar on the supply chain.
Ken Dillon:
First of all, I'd like to say we compete and partner with majors and independent oil companies all around the world, so we can actually see how far ahead we are in drilling dynamics, started in Permian and it rolled out around the world. So we're very confident in the drilling and completion synergies, working with the excellent Anadarko engineers in each of their assets. ODD is basically a holistic approach to drilling. It's mechanical-specific, energy-focused and we have our own equations which drive our software that we install in the rigs. We have our own processes, and it's more like a social network of drilling rather than a data book on how to design wells. We optimize bid design ourselves. We design stabilizers ourselves in real time based on the results of the last well. And we use data analytics to make formation-by-formation improvements. If you look since 2014, we've worked together with international contractors altogether, so Halliburton, Schlumberger, Baker are all in the same room as we're drilling each individual well. Everyone has a chance to have input, and the focus is on the best well, not the best individual company performance. We've improved HES, and we've integrated and optimized the supply chain processes. Since 2014, we've saved over $708 million internationally. And we're very confident about making those synergies that we've talked about in this proposal. I'd like to hand over now to Oscar on supply chain.
Oscar Brown:
And I guess just stating the obvious. We'll be doubling our purchase power at Occidental with the combination with Anadarko. So that's a huge opportunity. We'll be maximizing our economies of scale in terms of purchasing power and combining the company, both companies' best practices in procurement. I'll just expand a little bit on Cedric's comments on Aventine and that model. Certainly, the Aventine Hub is only 40 miles from the heart of Anadarko's Delaware Basin assets. And so there's lots of capacity still available at Aventine for all the different services and products that are managed there. So there'll be a huge opportunity in terms of general logistics. And if you look on the map on Page 11, you can really see the sort of superhighway that's formed between the Southern and the Northern Delaware of the pro forma position. And you can see there may be opportunities to expand the Aventine-type model to other parts of the Delaware Basin. In addition, the combined purchasing power, I think we both have contracts where the increase in purchasing power will help us in terms of our cost, in terms of certain equipment, rig rates, OCTG, et cetera. So we believe there's great opportunities in supply chain to deliver the $600 million that's noted.
Leo Mariani:
All right very, very thorough answer from you folks around the synergies here. Just in terms of a follow-up. I think, Cedric, you clearly pointed out that leverage will increase at Oxy post the deal, and thank you for those sensitivities around the commodity prices. Is there any thought process to maybe hedge some volumes out over the next couple of years to maybe eliminate some of that cash flow uncertainty in the deal here?
Cedric Burgher:
It's certainly an option available to us. We don't think it will be necessary. As you've already seen, we're way ahead of schedule on what we can do to de-lever. And so we have historically not been an advocate of hedging for a number of reasons, but it is an option available to us to help reduce the risk if we feel like we need to fall back to that. None of the numbers we presented you with include any hedging.
Vicki Hollub:
I'll also point out that our chemicals business and our Al Hosn and Dolphin provide -- and our PSAs in the Middle East provide some form of hedging for us, so we're quite confident that the cash flow in a lower-price environment will be there.
Operator:
The next question will come from Doug Leggate of Bank of America.
Doug Leggate:
I just got two quick ones. I think it's really a follow-up to Phil's question earlier regarding Western Gas. For those of us who covered Anadarko for a while, Anadarko had pretty much built out their midstream facilities, so the control of that asset didn't really seem to be as strategic a requirement as it was in the past. So I'm just curious, given that you guys have made an arc ahead of retaining the takeaway rights while monetizing this deal, can you just give us a little bit more of a thought as to what you see as the strategic ownership requirement of West? My follow-up is really just a quick one on the Gulf of Mexico. Obviously, I know that Oxy had some interest in the long time ago, but clearly, Anadarko was using that to harvest cash. I'm just curious whether you see the role of that in your portfolio to continue to harvest cash or if you might consider yourself as perhaps a consolidator there as well, much as you expect to be in the onshore? And I'll leave it there.
Vicki Hollub:
I'll start with the first one on Western Gas. As you rightly pointed out, Doug, we don't really feel like we have to necessarily own infrastructure to take advantage of it. We were quite fortunate and by design, actually, selected the companies that we did for the sale of our midstream last year to two, what we feel like are great management teams that are very well positioned to maximize the value of those assets and to work well with us. And so we have a great relationship with them. The same thing would need to happen for Western for us to divest of it because it's important that you're working with someone who has interests that are aligned with yours when you're talking about infrastructure. So I wouldn't take that option off the table. As with any of our infrastructure in place today, we would be willing to consider the monetization of that sooner rather than later depending on the potential buyer. With respect to the Gulf of Mexico assets, our strategy would be the same as Anadarko's there, and that is to just use that asset to generate cash. It would not be to consolidate or extend the growth. It's to maintain production flat and keep our cash flow flat. And Anadarko has done a great job doing that, and they have a superior team working in the Gulf of Mexico today.
Operator:
Our next question will come from David Deckelbaum of Cowen.
David Deckelbaum:
I just wanted to confirm, included in the assumptions on capital reduction, the $1.5 billion. Was any of that capital allocated towards the African assets? This is $1.5 billion standalone post the African divestiture?
Cedric Burgher:
This is Cedric. Yes, it was. There was some capital associated with the African assets that's now been removed. So we're ahead of schedule on the capital reduction targets as well with that.
David Deckelbaum:
So how much of that was included in the $1.5 billion? Are you saying there's still another $1.5 billion that remains in capital reduction after the sale?
Cedric Burgher:
It was about $200 million, so that leaves about $1.3 billion remaining.
David Deckelbaum:
So there was nothing from Mozambique included in there then?
Cedric Burgher:
That's about $200 million for the next year, so a total of $400 million, excuse me. $200 million was ex Mozambique and then $200 million with Mozambique.
David Deckelbaum:
Okay. I appreciate that. And then just as a follow-up. I know pro forma, you talked about the capital reduction and then slowing the combined growth rate down to 5%. Is that purely a function of trying to augment as much free cash as you can in the first couple of years just to de-lever more quickly? And then if it's not the case, would Oxy standalone be better suited growing at a lower rate?
Cedric Burgher:
So yes, good question. We think that 5% is a very healthy growth rate. It's very sustainable for many, many, many years. And on a larger asset base, this would obviously be transformational, taking us up in terms of scale and size. We think that's an appropriate growth rate, and it certainly does help increase free cash flow so that we can de-lever more quickly. And then standalone, we have also considered doing that as well. As you know, in the last year -- up until the middle of last year, we were replacing a lot of cash flow that we had exited second-tier basins and countries and replacing that organically rather than through M&A. We accomplished that plan in the middle of last year. And then we were surprised with the loss of the Qatar cash flow, and so we've been replacing that as well. So we've been headed in that direction as well internally. We just haven't yet announced that, but I can tell you that's where we're headed fairly soon if we were to lose out on the Anadarko deal.
Operator:
And the final question will come from Richard Tullis of Capital One Securities.
Richard Tullis:
Vicki, in the past, Oxy has referenced about 3,000 drilling locations in the Permian Resources with breakevens below $50 oil. How would the Anadarko Delaware Basin properties generally rank within Oxy's existing inventory on a rate of return basis?
Vicki Hollub:
I think that they would fit well within the top couple of tiers. If you look at the, as Oscar had referenced, Slide 11 previously where it shows the portion of their acreage that is in between Barilla Draw and Southeast New Mexico, there's some prime acreage in there and there's some certainly, we believe, quite a few tier 1 opportunities. I think their inventory there, we believe, could be over 10,000 wells. And we believe that it would be very, very similar to our inventory. And we expect that over time, because of the lower cost that we can imply as a result of the entire trend, our two areas with theirs, we can further lower cost and infrastructure synergies so that we'll be able to move more wells down into the less than $50 breakeven category.
Richard Tullis:
And just lastly, not trying to jump ahead too much here, I know there's more work to be done, of course. But how does this pending acquisition impact further Permian acquisitions going forward that may materialize in the current environment that places more value on operational execution and free cash flow generation, albeit they may be smaller in the future?
Vicki Hollub:
Well, we will continue doing the very small asset trades that our teams do, acreage swaps and things like that. We would continue some bolt-on where it makes sense, but not of any size. We would be looking at smaller bolt-on acquisitions. I would say that anything of any material acquisitions would be something that we would not do until we achieve our debt reduction targets.
Cedric Burgher:
I'd like to add one thing that came up in a prior question just something we've had offline. I want to make sure we get it out there for everyone. For the transaction with Total, it's about $8.8 billion in gross proceeds. But after tax, net proceeds for the transaction will be about $8 billion, so about $800 million in tax and other cost.
Operator:
And in the interest of time, this will conclude our question and answer session. At this time, I'd like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub:
I just want to say thank you all for your questions and for joining our call. We're really excited about this opportunity and what it's going to mean for Occidental and for the Anadarko shareholders and ultimately for our shareholders. Appreciate it. Have a good day. Bye.
Operator:
The conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.
Operator:
Good morning and welcome to of the Occidental Petroleum Corporation Fourth Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez:
Thank you, Laura. Good morning, everyone, and thank you for participating in Occidental Petroleum's fourth quarter 2018 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Ken Dillon, President International Oil and Gas Operations; and BJ Hebert, President of OxyChem. In just a moment, I will turn the call over to Vicki. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements, as more fully described in our cautionary statement, regarding forward-looking statements on slide 2. Our earnings press release, the investor relations supplemental schedules, and our non-GAAP to GAAP reconciliations and the conference call presentation slides, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Vicki. Vicki, please go ahead.
Vicki Hollub:
Thank you, Jeff, and good morning, everyone. Today I'll begin our fourth quarter results followed by our 2018 achievements, a plan for the year ahead and an overview of the benefits of our integrated business model. The fourth quarter of 2018 wrapped up a successful year for Oxy both financially and operationally. We returned $900 million to shareholders in the quarter through a combination of dividend and share repurchases. Our continued focus on increasing returns for our shareholders was achieved due to outstanding performance from all three of our businesses in a changing market condition. Despite WTI falling below $43 a barrel in the quarter, we posted core earnings per share of $1.22 and generated the highest semiannual level of operating cash flow since 2014, making the second half of 2018 our strongest six-month period since our portfolio optimization. Permian cash operating cost were the lowest this decade, driven by the long-term high-return investments that we're making such as in facilities and infrastructure. We operate our assets with a full lifecycle view. Our investments will continue to provide payback in the form of lower cost as our production base expands. OxyChem and our Midstream business both achieved record fourth quarter earnings as a result of our integrated business model, which enables us to take full advantage of market conditions such as delivering higher realizations from our Permian take away position. In 2018, we grew cash flow to a level that exceeded both capital expenditures and our dividend, a key achievement we have been working toward since completing our portfolio optimization. Organic cash flow growth was driven by prioritizing the allocation of capital to opportunities that generate the highest full cycle returns. We are pursuing cash flow growth with two key objectives in mind, first and foremost to generate a higher return on capital; and second to return an increasing level of excess cash to shareholders. In 2018, we returned more than $3.6 billion to shareholders through our sector-leading dividend and $1.3 billion of share repurchases under our $2 billion-plus share repurchase program. We intend to complete the remainder of the share repurchase program in 2019. We remain committed to returning capital to shareholders through a balanced combination of dividends and share repurchases as we've done for a long time. Since 2002, we've increased our dividend each consecutive year and we've returned $33 billion to our shareholders through our dividend and share repurchases. That's about 70% of our current market capitalization. Almost 50% of this was returned in the last five years, a time period which included one of the worst downturns our industry has ever experienced. Through this downturn we also maintained our strong balance sheet and A-level credit ratings. Our focus on investing in our high-quality assets delivered a 2018 return on capital employed of 14% and cash return on capital employed at 27%, both significantly higher than 2017 and our per quartile performance versus our performance peer group. These achievements reflect our commitment to our value proposition, the strength of our integrated business model and the high quality of our assets. We made notable productivity and efficiency gains across all three business segments in 2018. The investments that OxyChem and our Midstream business completed in recent years paid off in 2018 as both segments optimized cash flow and delivered record earnings. Our Permian business continued to outperform with Permian Resources delivering an impressive 52% production growth and Permian EOR exceeding cost reduction targets for the acquired Seminole CO2 field. Our international business generated $1.4 billion in free cash flow in 2018 and has enormous potential to grow cash flow going forward. On our last call Ken provided details of our new international opportunities. Now we're pleased to have been awarded a new block in Abu Dhabi that Ken will describe in a few minutes. This new Abu Dhabi block along with six in Colombia and three in Oman, make 10 new blocks added in the last year. These new international opportunities will add significant high-return low-decline development inventory to our portfolio. At the same time, it's worth highlighting that these will require only a modest investment in the short-term. One of our key competitive advantages is our ability to develop assets in a way that efficiently maximizes all production recovery and generate significant cash flow growth over the next decades. For the last three years, we've achieved all-in reserve replacement ratios exceeding 160% companywide. The 2018 reserve replacement ratio of 164% is due to the excellent technical work our teams have completed in enhancing subsurface characterization across our portfolio and building customized development plans. Our momentum has continued into 2019 as our business segments continue to invest in high-return opportunities. Last month we discussed various capital budgets through three different pricing scenarios, but we've decided to limit our full capital spend in 2019 to $4.5 billion. This represents a $500 million or a full 10% reduction from 2018. By maximizing efficiencies, we are reducing spending to adjust to a lower oil price environment. As activity is adjusted to make full year capital spending of $4.5 billion, we expect spending to be higher in the first half of the year. In creating our capital budget to realize the highest returns, Permian Resources shale production will become a larger portion of our total oil and gas production. We expect this will increase our oil and gas base decline to 20% in 2019. As we continue to invest in the Permian, we will advance our appraisal in the short cycle low decline development opportunities in our new international blocks to prepare them for growth. Our 2019 capital program is dominated by short-cycle investments, the majority of which we’ll pay back within two years at $50 WTI. We will continue to be conservative and if necessary, within six months we can reduce capital spending to sustainable levels, meaning that OXY remains flexible throughout the commodity cycle. We will grow oil and gas production by 9% to 11% in 2019 to replace the cash flow from Qatar in 2020, but our long-term annual growth rate forecast remains at 5% to 8-plus-percent. Cash flow growth is an inherent driver in generating a high return off-capital and a higher return on-capital. Our 2022 roadmap details the projects we will prioritize and execute over the next few years, in order to grow cash flow from operations to $9 billion in 2022. While Permian Resources will continue to be the main driver of growth through 2022, our international business will also grow in terms of both cash flow and production. In addition to having many high return short cycle opportunities, we also continue to benefit from the stable sustainable cash flow generated by OxyChem, Midstream and Dolphin. Even with a lower activity level and a significantly reduced capital budget for 2019, we still remain on track to achieve the low end of the 2022 cash flow range of $9 billion to $9.5 billion that we communicated in our third quarter call. As you will have noticed based on our expectations for the WTI spread we’ve updated our Brent price assumption for 2020 onwards and this will have minimal impact based on our production sharing contracts. To be conservative, we modeled OxyChem and midstream cash flow at the low end of the previous range and our projection of $9 billion in cash flow by 2022 does not include significant upside from several additional projects that we're currently evaluating. We'll provide updates on these projects as we advance. This morning Cedric will take you through our financial results and updated guidance; and Jeff will detail the continuous improvements we are creating in the Permian. Ken will then provide an update on our new opportunities in our international business. I'll now hand the call over to Cedric.
Cedric Burgher:
Thanks Vicki. As Vicki highlighted, we are pleased to have continued repurchasing shares, allowing us to return $900 million of cash to shareholders during the fourth quarter and over $3.6 billion in 2018 including our dividend. On slide 10, I'd like to start with our earnings which improved across all segments year-over-year. For the fourth quarter we had core earnings of $1.22 per diluted share and reported earnings of $0.93 per diluted share. The difference between reported and core income is attributable to an impairment charge of $220 million which was driven by lower oil prices. Earnings also included a net tax benefit of $224 million, which significantly decreased our fourth quarter effective tax rate and it consisted of $100 million for additional EOR tax credits and tax credits related to U.S. export sales; $99 million for releasing a foreign withholding tax accrual; and $25 million for changes related to the 2017 Tax Reform Act. Oil and gas core income decreased in the fourth quarter compared to the prior quarter, reflecting lower oil and NGL prices as realized prices declined by 10% and 23% respectively from the third quarter. Fourth quarter oil and gas results included a non-cash mark-to-market change related to our CO2 purchase contracts, as well as higher operating and DD&A expenses in Qatar as a result of the ISND contract expiration later this year. Total fourth quarter reported production of 700,000 BOEs per day was above the midpoint of our guidance, due to the continued best-in-class execution and well productivity in the Permian Resources, which resulted in 250,000 BOEs per day during the quarter at the top end of the guidance range and represents an exit to exit increase of over 57%. Total international production of 290,000 BOEs per day was up slightly lower than guidance primarily due to the oil price adjustment in our production sharing contracts in Oman. The contracts utilize pricing mechanism with a two-month delay which resulted in a higher realized price and lower production for Oman in the fourth quarter. Fourth quarter international production was also impacted by weather and accelerated maintenance. OxyChem continues to perform strongly reporting its highest fourth quarter pre-tax income ever of $223 million, above guidance of $220 million. Earnings decreased from the third quarter, primarily due to expected seasonality and end market demand for core vinyl products as well as lower realized caustic soda pricing and higher natural gas and ethylene costs. Our midstream business reported record core fourth quarter earnings of $670 million, which exceeded the high-end of our guidance, due to positive mark-to-market movements and a higher-than-expected Midland to MEH differential. Compared the prior quarter fourth quarter earnings reflected lower marketing margins due to a decrease in the Midland to MEH differential from $16.67 to $15.31 and lower pipeline income from the sale of the Centurion Pipeline in the prior quarter. Fourth quarter revenue and cost of sales were both grossed up by $340 million due to the accounting treatment of certain Midstream contracts where we've used our excess takeaway capacity from the Permian to purchase and resale third-party barrels. The third quarter gross-up amount was $327 million. Operating cash flow before working capital for the fourth quarter was $1.9 billion, which covered our capital expenditures of $1.3 billion and dividends of $594 million. Our total year-end capital spend came in just under our planned spend amount of $5 billion. Slide 11 details, our guidance for the first quarter and full year 2019. As Vicki mentioned, we will pursue high-return reinvestment opportunities in 2019 that will be funded by a total capital budget of $4.5 billion, which will result in annual production growth of 9% to 11%. We are reducing capital spending year-over-year and due to technical and operational advances, we are still able to deliver significant cash flow growth. As we advance into 2019, our balance sheet remains strong and we have ample liquidity available to complete our share repurchase program. We ended 2018 with over $3 billion in cash and still hold PAGP units with a market value of approximately $700 million. I'll now turn the call over to Jeff.
Jeff Alvarez:
Thank you, Cedric. 2018 was an outstanding year for our combined Permian business as we improved the value of our conventional and unconventional assets through our value-based development approach. We're able to add high margin barrels and generate great returns on our investments. We replaced 216% of our production with new reserves through industry-leading performance and successful appraisal. Combined total year production per Permian Resources and Permian EOR grew 77,000 BOEs per day compared to 2017, and exceeded 400,000 BOEs per day in the fourth quarter. We lowered Permian operating cost 9% by utilizing advanced data analytics on our artificial lift, implementing new water recycling technology, and improving maintenance efficiency across the Permian. Permian Resources has a simple model that I love called 'leave no doubt' which refers to our relentless pursuit of generating the best returns in the industry. In 2018, we made tremendous progress toward achieving this principle as we increased our total production 52% and exceeded our initial 2018 guidance by 12,000 BOEs per day. Our subsurface characterization improvements have driven breakthroughs at an accelerated pace. By integrating advancements in geoscience with our 12,000 square miles of 3D seismic and subsurface characterization models, we are rapidly achieving step change improvements in well design and placement. In 2018, we improved our average six-month cumulative production by 25% compared to 2017. Over the last 12 months OXY has delivered 40% of the top 50 horizontal wells in the basin which is the most for any operator while only drilling 5% of the total wells over the same time period. On the capital efficiency front our operational improvement initiatives continue to drive efficiency, compressed time-to-market, and lower full cycle cost. In 2018, we increased our fee drilled per day by 19% and we drilled record 15-day 10,000-foot wells measured rig release-to-rig release in both our Mexico and Texas Delaware areas. On a base management front, our investments and operability and surveillance are transforming how we optimize our base as demonstrated by our 10% reduction in operating cost per barrel in 2018. In addition to efficiency improvements, we're also achieving major advancements in artificial lift optimization and well enhancements to lower the base decline rate. The rate of progress in Permian Resources is extraordinary and will lead us to exceed to 600,000 BOEs per day for this business alone within the next five years. Our Permian EOR business also had a great year. We continued the integration of the Seminole-San Andres unit and have now lowered OpEx by $8 per BOE since we took over operations in September of 2017. We start injection on new grassroots CO2 flood at the West Sundown unit which start injection four months earlier than planned and will achieve a development cost of under $6 per BOE. Permian EOR continues to provide a low decline cash flow and high returns for our shareholders. We're excited about the critical role it will play in our long-term business sustainability strategy, especially as we leverage our position and expertise to reduce our carbon footprint. Slide 14 provides more detail on the 2019 capital program. Permian Resources will comprise $2.6 billion of our $4.5 billion total capital budget in 2019. We will utilize approximately 12 operated rigs and one to two non-operated rigs with development focus on our core areas. We plan to operate six to seven rigs in New Mexico which will primarily develop the high return Bone Springs and Wolfcamp formations. We will continue development in areas proved to be highly prolific in 2018 and plan to allocate activity to the tanks area of Greater Sand Dunes in the second half of the year. The appraisal results from tanks area have been outstanding, the three wells online in 2018 averaging over 3,000 BOEs per day per well for 30 days. In Texas, Delaware, we'll operate five to six rigs primarily developing the Wolfcamp A and Hoban formations. The tapered well design we implemented in the second half of 2018 to significantly improve the returns of our new wells and we expect to see continued improvement through 2019. Overall our capital program for 2019 will generate significant value for our shareholders and result in 30% to 35% annual production growth. We will also be advancing the commercialization of unconventional EOR development and expect to share more information on results later in the year. As you can see, 2018 was an exceptional year for our Permian businesses. We saw well productivity records, significantly lowered operating cost, and realized breakthroughs with data analytics and subsurface characterization that improves the returns from our assets. 2018 may seem like a hard year to beat, but the organization is more energized and capable than ever and I'm sure we will leave no doubt in 2019. I'll now turn the call over to Ken to discuss international.
Ken Dillon:
Thank you, Jeff, and good morning, everyone. As Vicki and Cedric mentioned our 2019 capital plan focuses on investing in projects that grow cash flow and generate the highest returns. Today we're pleased to share the details of onshore Block 3, which is a new 35-year concession in Abu Dhabi. We feel honored to expand our relationship with ADNOC and the first award of its kind onshore. With Block 3 as well as the new onshore blocks landed in Oman and Colombia, we feel we have established the clear pathway for OXY to grow sustainable cash flow from our low-decline long-life international assets. We certainly appreciate the recognition as a partner of choice. As shown on slide 16 Block 3 covers an area of approximately 1.5 million acres, which is slightly greater than the total of our net unconventional acreage in the Permian. We have high expectations for this block given its location between the prolific oilfields of Abu Dhabi and Oman. It's also adjacent to our outhouse gas project. As I mentioned in the last call, our regional geological knowledge is best-in-class and it continues to develop. We utilize that experience in preparing our initial stacked pay prospect infantry for Block 3. In 2019, our capital spend in Block 3 will be modest. The initial scope of work involves participating in the state-of-the-art 3D seismic acquisition and degradation. Our plan is to initiate drilling in 2019. Expanding our footprint in UAE in such a meaningful way, especially through the 35-year concession has allowed us to enhance our long-term international portfolio at an attractive price of entry. Additionally in Abu Dhabi, we continue to look at cost effective ways to debottleneck the Al Hosn Gas facilities. In Colombia, in partnership with EcoPetrol, we have signed an agreement to develop Blocks 39 and 52. These blocks are adjacent to our giant Caño Limón field and where we had successful discoveries this year. In addition we formed into four blocks in the highly prospective Putumayo Basin where we have regional knowledge of the reservoirs. With these blocks, our net acreage in Colombia has arisen to approximately one million acres with a low cost of entry. Like your other recent word’s capital will be small in 2019. In terms of performance, our OXY international drilling teams continue to improve performance and since 2014 I'd say it's approximately $650 million for OXY and our partners, as well as improving efficiency cost and time-to-market, the international safety performance was again world-class. Our international exploration programs in 2017 added 47 million BOE of resources and bettered that in 2018 by adding 94 million BOE of resources while at the same time opening up new place. Funding costs were around $0.76 per BOE. In closing, we expect 2019 to be an exciting year for OXY internationally as the exploration programs in new blocks for gas we will continue to provide updates on significant developments. As you can see the work we are executing closely aligns with OXY's key technical competencies and returns focused on our true partnership. I'll now turn the call back to Vicki. Thank you.
Vicki Hollub:
Thank you, Ken. Before we go to Q&A, I'd like to emphasize that we believe the strongest oil and gas companies of the future will be those that have a shareholder-focused value proposition and our structure and sustainability to withstand the oil price cycles, while also maintaining a social license to operate in the world in general and operate in a low carbon world. Our value proposition will continue to deliver a growing dividend in the upper quartile or maybe best-in-class returns to our shareholders, while also growing oil and gas production 5% to 8-plus-percent annually. Unlike many companies in our sector, we delivered this through one of the longest downturns our industry has faced. Our company is primarily an upstream oil and gas company with integrated midstream and chemicals business, so that adds significant value and provides important support during low oil price cycles. The diversification of our upstream oil and gas business also provides strength in periods of low oil price along with substantial upside in higher oil price cycles. This upside is made possible by our short-cycle, high-return, unconventional assets in the Permian, along with a new conventional opportunities that we just picked up in Oman, Colombia and Abu Dhabi. Our strength in the low price environment bolstered by our very low decline enhanced oil recovery projects in the Permian, Oman and Colombia. I'm specifically referring to our CO2 and water plugs in the Permian, our water plugs in northern Oman, our steamflood in Mukhaizna which happens to be one of the largest steamfloods in the world and our new TECA steamflood in Colombia. Our production sharing contracts and our road to decline gas projects in offer and Al Hosn also provides significant support in low oil price cycles. I believe there is no other oil company’s in the oil gas industry that has this blend of high-quality, focused oil and gas projects that provides this diversity. This is why we can continue to deliver our value proposition. Not only do we have a great blend of assets with the addition of our new blocks, we have incredible inventory of development opportunities. Over the past few years, we've replaced our production with new reserves at a ratio of greater than 160%. With the inventory we now have, we expect to achieve that replacement ratio for the foreseeable future. This ensures the sustainability of our value proposition. With respect to our social license to operate, our commitment is to manage our business in a way that improves the quality of life for our employees, contractors and the communities where we operate, while also minimizing the potential impacts of our operations. Our employees are the lifeblood of our company. They are the drivers of our success and as such, we are committed to their continued development and helping them address the challenges of work/life balance. Many people refer to this as human capital management, but I don't. These are our people, the OXY family not just capital. It's personal to us. We want their lives to be the best that they can be at home and at work. This will enable them to be engaged and ready to deliver the best possible value to our shareholders as they have done in a significant way during this downturn. And in the areas where we operate, we want to ensure that we have a positive impact and can find ways that improve the quality of life in the community. Lastly, but equally as important is our commitment to use our unique skills and assets to lead carbon capture use in sequestration or CCUS, starting in the United States and ultimately in other parts of the world. Along with many other initiatives, CCUS is necessary to limit the impact of climate change. With our CO2 Enhanced Oil Recovery expertise and projects in the Permian, we believe we can lead the effort to capture current CO2 emissions from industrial sources to use in sequester in our Permian reservoirs. This will benefit the climate and our shareholders. As we have previously mentioned, we now have a low carbon team whose mission is to seek opportunities to innovatively reduce our carbon footprint in ways that also improve our operations and thus are expandable and sustainable. Our comprehensive strategy addresses all the factors that make a company great and sustainable. I believe this has built us into our next-generation company that is uniquely positioned to excel in our changing world. We'll now open it up to your questions.
Operator:
We will now begin the question-and-answer session. [Operator Instructions] And our first question will come from Roger Read of Wells Fargo.
Roger Read:
Yeah. Good morning. How are you? Hopefully, everybody can hear me? Yeah. I just wanted to kind of come at it from the capital discipline side. Obviously, the presentation you put out in January highlighted that you would live within cash flow given the oil price. Good to see the higher growth rate now 9 to 11 versus the 10 to 8. But just really my question is along the lines of trying to think about how Oxy and maybe the broader E&P space fits here, with what you're trying to do versus maybe what we’re seeing out of the super majors in terms of increasing activity in the Permian, and then we haven't seen the magnitude of drop-off, I think we would've expected out of some of the private companies. So as you think about capital returns, capital discipline, but then maybe a little bit of the risk being squeezed between these other two components, how do you kind of square that circle up? And what do you see as the driver for how you want to run the company?
Vicki Hollub:
The driver for us is to maximize returns. And so the way, we put together our development programs is, we don't try to design for peak rate production. We really try to design all of our development programs and our comprehensive development of the Permian with the synergies between EOR and resources. We try to design that in a way that creates the highest difference in value. And I can tell you, we're not trying to outpace the majors. We're trying to outperform the majors. And I think that, we're clearly doing that in the Permian at this time. I think it's – from the standpoint of our programs versus theirs. We're doing a lot more with the rigs that we employed today than many other companies are with almost double the rigs that we have. And our focus is more on making sure that every dollar we invest creates more value. And so we're trying to really work the side of maximizing recovery from the reservoir and minimizing our cost. So it's not a race for us to outpace them. And we have teams that have built our infrastructure and our position and our relationship in a way that grow as they will they will not impact our operations. We believe we are perfectly positioned to be able to do the things we need to do. We have the takeaway capacity. We have the export capacity. We have the infrastructure within the Permian. So we're positioned there, and I think in a catch-up mode at this point.
Roger Read:
Okay. Thanks. And then Jeff just the part you mentioned about data analytics, I understand it's helping. Is there any quantification that you can offer on that front? Or either what's been captured to-date or what you would expect going forward?
Jeff Alvarez:
Yes, I think the real quantification is when you look at performance improvements and ultimately what's going to play out from a capital efficiency standpoint. So, I think when we point to our well performance and our development performance, all of that -- or a good portion of that is being driven with how we utilize data analytics. And the thing I'd point to the most is as you can see our development; our performance isn't based on a lot of trial and error. It's largely based on our ability to go in, understand the reservoir from a subsurface standpoint, utilize the huge amounts of data that we have in an effective way, and come up with an optimal development that delivers very good results from the beginning, not in a trial and error mode, where we have to deploy a lot of capital that gets underutilized. And so it's almost unfair to point out we used artificial lift because that's where we've made some huge breakthroughs, but we are applying data analytics in almost every aspect of the business with sub-surface characterization is the one we talked about the most because it's so impactful. But it's being used universally across the business and there is example after example on how that's creating value.
Roger Read:
Great. Thanks. And it's okay from our perspective if you want to be unfair when we're thinking about other stocks.
Jeff Alvarez:
Thanks Roger.
Operator:
And our next question will come from Bob Morris of Citi.
Bob Morris:
Thank you. Good afternoon everyone. My first question, Vicki, is with regard to again the capital discipline side, you've capped the budget this year at $4.5 billion so you can return any cash generated above $50 a barrel to shareholders. But then beyond this year, you're stepping back up the CapEx and to do that you're spending -- you end up spending cash above $50 a barrel and I know you have to do that to still hit your 5% to 8% production growth target. But to what extent would you consider continuing what you are doing this year just sort of cap any spin to return cash above $50 per barrel to shareholders? I know that would put your growth at the lower end of the range and you can still obtain double-digit growth out of Permian Resources. So, is there a scenario where you may continue, like you do in this year, beyond this year to then return any excess cash above $50 a barrel to shareholders?
Vicki Hollub:
Our assumption for 2020 was based on our belief that oil prices will be $60 in 2020. And if that's the case, with a budget of 5 to 5.3, we would still be able to return cash to shareholders. And we want to continue to, at some point, grow our dividend more meaningfully and Cedric will talk about that a little later but our 5 to 5.3 capital budget would allow for us above a $60 environment to return cash and that's something that we've always done as I mentioned in my script and something that we'll continue to do. We think of balance to return of cash to shareholders through repurchases and strong dividend with a right balance between those is important to continue.
Bob Morris:
Sure, I appreciate that. So, my second question is for Cedric. Cedric last quarter you mentioned that M&A was part of OXY's DNA and so at this stage, do you see the A&D environment more conducive to opportunities for OXY out there or have you grown more optimistic with regard to potential acquisitions or adding to your portfolio in the Permian?
Cedric Burgher:
Well, it's -- we've certainly seen a few -- some activity picking up in M&A. I would say from OXY's perspective, we're always aware and we keep ourselves very informed. We look at a lot of opportunities, it’s rare when we don't get a call and when there's something coming to market. But if you look at our organic growth opportunities as we've described, they're robust across the globe and across each business sectors. So we don't have to do a deal and we only want to do a deal, if it's going to be very accretive to our shareholders and for values. So we do see ourselves over the long run being a consolidator. That's one of the things that goes with -- or opportunities that goes with being a low cost producer. We consider ourselves one-off, if not the lowest cost producer in the basins and places we choose to operate. So I think, there will be consolidation opportunities over time as I said before, however it needs to be a compelling deal for us and for our shareholders and that's how we look at it.
Bob Morris:
Is there an advanced catalyst that sort of sparks an increase in consolidation not necessarily for OXY, but across the Permian at some point?
Cedric Burgher:
That's hard for me to predict. You know there's certainly a lot of assets and small private companies that don't seem to have the scale or the technology to put themselves in a low-cost producer status. So at some point perhaps those come to market at more reasonable prices. There have been a few, but it's hard to predict those things. We're certainly ready when that happens. And then otherwise there are other operators that are trying to figure out, if they can make the breakthroughs that we have and so on and it will just be something that will be -- to be determined. It's hard to predict.
Jeff Alvarez:
Hey Bob, this is Jeff. I mean, the only thing I'd add to what Cedric said, if you look at the Permian history it's consolidated when the business got really hard, prices drop, margins get squeezed and then consolidation generally happen. I think when you look across though in conventional space, you all know better than anyone, the business continues to get harder not easier as people move to full section development, having to operate with lower operating cost, manage infrastructure, large KOLs all those things. So we're definitely progressing to where you're starting to see differentiation between those that are good operators and those that are maybe aren't as good.
Bob Morris:
No, I agree. OXY is positioned very well in that type of environment. So, I appreciate your comments. Thank you very much.
Operator:
The next question comes from Paul Sankey of Mizuho.
Paul Sankey:
Good afternoon. Just a couple of points of clarification on your presentation, if I could, on slide 4 you stated that you drilled less than 5% of the horizontal wells in the Permian, but have 40% of the top 50 well results. Could you expand on that a little bit in terms of what you're comparing and how you're comparing that? Thank you.
Cedric Burgher:
Sure Paul. I'll take that. Basically if you go to anyone who has the deck opened slide 31 shows that. So there's lots of ways to measure performance. Specific measure that we use is the cleanest as to where we look at over the last year top 50 wells from an IP standpoint, where are they? Who has them? And then you can see on the left, we've got 20 of the top 50 over the last year. We've showed this for several quarters, so you can see moves around and how it progress. And 40% of those were the top operators when you look at the data. Another thing we add to it, on the right, which is something we often talk about is, we are able to do it with less proppant. And the reason we highlight that is twofold; one, it’s a big cost driver. Obviously you all know, the more profiting in pump, the more cost. But two, its really indicates how we customize our development. You can see we don’t have a universal number where we use 2,000 pounds per foot on every well, we vary it. And that’s a function of our development strategy and our understanding on the subsurface to get really, really good wells in a customizable way. The other thing I'd point you to, Paul, one thing we put in there, because the question we keep getting asked all the time is, are results continuing to improve? And it seems like every time we show a comparison of results, they are normalized by something, or you cherry pick which wells you use, you exclude this, you include this. So we include a slide in this deck that I'll point out slide 28. So what this slide is, it shows our six-month performance for every horizontal well. We didn't cherry pick which wells that go in there, all appraisal wells, all development wells, all of our wells are in every year that you can see for 2015, 2016, 2017 and 2018, across Midland Basin, New Mexico, Texas, Delaware and it answers the fundamental question of are we able to continue to improve? And you can look at each year and there's reasons that vary on why we're improving. Some years, it may be more of the lateral length, some years it may be better completions. Every year is being driven by a better understanding of the subsurface. And so, there's lots of things driving it. But the fundamental question of are we continuing to improve, I think, is answered with this slide. And what makes it even more impressive is, when you dig in to the details and you look at 2018, that's with 90-plus-percent of wells that have an offset, so characterized as children wells. So the big debate on our children wells, versus some parent wells, we can have that discussion. But fundamental, you can look at for many different reasons; we continue to get better well performance every year.
Paul Sankey:
Thanks, Jeff. And follow-up along the lines of clarification on slide 7. You talk about unconventional EOR commercial success in 2019. Could you talk more about that? I'm not sure what you mean there? Thank you.
Vicki Hollub:
We have in the past, on done 4 CO2 injection pilots in the Midland Basin to test the efficiency and the commerciality of CO2 flooding the shale. And that's in the Midland. And what we're looking at in the Southeast New Mexico area is more of an enhanced oil recovery with using hydrocarbon gas injections, which would do two things for us. First, it would help us to maintain pressure. Secondly, it would become also somewhat miscible than the oil and would make it the same as CO2 does, make it less reluctance to flow, lower the friction and improve the ability to flow the oil from where it is to be freezed, to help in performing a full string. What we intend to do in Southeast New Mexico would be a continuous injection that would be full stream. So we're going to test that. We believe based on our models that it'll work and part of the objective there is to try to lower the decline of the Resources business and we believe that we'll successfully do that over time.
Paul Sankey:
Understood Vicki. Thank you.
Vicki Hollub:
Thank you.
Operator:
And next we have a question from Ryan Todd of Simmons Energy. Mr. Todd, your line is open.
Ryan Todd:
Sorry. Looking forward, as we think about the normalization of CapEx, you have a back door, it's kind of a $5 billion to $5.3 billion level beyond 2019. The incremental capital driven -- in that case, driven more by an acceleration of activity in the Permian Basin? Or by a resumption of activity in international regions?
Vicki Hollub:
It will be both. The incremental capital in 2020 will be spread between our resources and the international areas, part of which will go to the growth areas. We do expect to start seeing -- we're going to continue growth from our base areas internationally through exploration and some of the other things that we're doing. But we'll pick that up in the new areas as we complete our appraisal programs. Now, the bulk of the growth capital is still going to go to resources in 2020, but we will send more to these – to the new areas.
Ryan Todd:
And maybe on that as well, I mean, you referenced some of the base case kind of assumes $60 crude in 2020. If you were to be at $50 again in 2020, would you see a similar type of program that we see here in 2019, where you continue to kind of smear out the international investment and run a moderated program in onshore?
Vicki Hollub:
It will be dependent really on where we are with respect to our cash flow. Our commitment is to stay, keep our capital programs within cash flow going forward. So if we're in a $50 of environment with what we're seeing from efficiency improvements and are increasing production in 2020. I wouldn't say that, we would be at the 4.5, it would depend on how our costs are looking now and everything else, but we would stay within cash flow.
Ryan Todd:
Maybe an unrelated question, I appreciate some of the details you provided on water sourcing. Can you talk through how you see potential risk of increasing cost from water disposal going forward particularly in the Delaware Basin? And how you set up the handle water disposal over the long term?
Jeff Alvarez:
So one thing – this is Jeff. So, one thing given our full cycle value focus, water infrastructure is really, really important in all of our development areas from the very beginning. So if you go look at New Mexico and how much we're recycling up there, the size of our water infrastructure in Texas, Delaware. I mean, we see – not only a risk to the business, if you don't manage it properly, but definitely a significant economic risk if you can't do it well. So one of the things we do from the very beginning of when we go to a development area is ensure we have water infrastructure in place to collect the water, recycle it where we can as much as we can, and then have numerous disposal outlets for when we're done for whatever water is left over. And so I'd say, in all of our development areas, we're very well-positioned and where there are some areas that have different have risks than others, some may be cost and just availability, some maybe permitting related to seismicity or whatever it is, we've identified and mitigated those risk in all of our development areas.
Ryan Todd:
Great. And thanks, Jeff.
Operator:
And the next question comes from Brian Singer of Goldman Sachs.
Brian Singer:
Thank you. Good morning. A couple questions with regards to the longer-term outlook here. In the years to come, how do you see your skill in the Permian impacting global unit operating in G&A cost? Do you see these costs falling flat or rising on a per BOE basis? And then what base case into that 2022 to cash flow plan? And then if I might add to that separately and you talked a little bit about this earlier what gives you confidence to base case production in Oman in the UAE even if it's three to four years out at the key milestones that we should be focused on between now and then?
Vicki Hollub:
Firstly with respect to the G&A, the G&A on a per BOE basis will be coming down over time. So that should be the case. And that's what we've assumed in our 2022 plan. The other thing that with respect to the milestones, the milestones are listed on slide 7 and what we try to give you there is more of a roadmap of how we're going to get there and the international blocks, particularly for some information about the non-conventional EOR and when that might happen. But this is essentially of the roadmap you wanted to be able to see, so you can check what's happening as we go. With respect to what -- yeah, with respect to what the performance will be, it's going to be based on analogs. Ken pointed out something to me just recently, and that is that if you look at the four countries that are contiguous there, you look at -- we're probably the only company that has operated in all four of those countries that have this similar trend. So we have a lot of experience in this trend and we can do analogs and help us understand how to forecast what to expect. So we have a lot of good information around that. But with respect to the roadmap, I’ll let Ken tell you a little bit more about that.
Ken Dillon:
Thanks Vicki. If we start with the Oman in the north, the game plan is to further define the hydrocarbons in Block 30 and 51 in order that we can optimize the regional development by potentially using their existing Block 62 as a hub for facilities. On a previous call, I was asked would we spread the well in Block 30 before the end of last year. We did. It's an on trend discovery and in fact, we found a new zone that we were not expecting. We plan to drill a follow-on well this quarter on Block 51 we’re reprocessing the existing seismic lines and plan to be drill ready by Q3 this year, which led to look at the hub concept for Block 62. We think hub and spoke is the best and most efficient way to develop this area. In Block 72 we started shooting seismic and we hope to have useable data by Q2 2020, but we may use some fast-track data for early drilling. Again our oil targets there are similar to those we've seen in our existing Block 53 hub, again hub and spoke concept to maximize efficiencies. In Abu Dhabi we were delighted to land Block 3. The block is 90 miles long, 30 miles wide and very few wells have been drilled there since the 1970s. It's in a great location not only because of proximity of super giant fields, but also because of infrastructure for success where we can hook up the flow lines very quickly and get that oil to export very quickly. I mentioned earlier we’ll spud a well this year. We've already mapped 162 prospects into 11 stacked reservoirs as targets and within these based on the new 3D seismic, which we think is some of the most cost efficient seismic ever obtained by anyone in the industry. So overall we try to detailed the milestones for a mine in Abu Dhabi and Colombia we're ramping up TECA, we'll drill 30 wells this year in TECA and will stream online to them this year, replacing all of long lead items for TECA, which will enable the ramp up that continue through 2020 and 2021. And as Vicki said, we're continuing to explore in our core existing assets also. So we've tried to make the roadmap something that we can update you on periodically as we get good results and I hope that answers your question.
Brian Singer:
Great. Thank you, yeah. So my follow-up goes back to the Permian. And you highlighted some of the areas of efficiency and productivity gains in your comments and so far in the Q&A. I think if you look at across the landscape even among larger and more scaled Permian companies for a company of your Permian Resources production base, you're planning to grow production at a rate that other E&Ps kind of spend more in capital to achieve than what you're projecting. Can you just talk to what you see as the risk around the Permian capital and production plan this year? And to what degree Aventine hub is going to be a driver of further capital efficiency or whether that's already essentially been reflected in recent CapEx results?
Jeff Alvarez:
Yes, Brian, this is Jeff. I will take your question. So, I mean the rest -- we feel really good about the areas we're developing in because they are -- one, they're core development areas, we know them really well. There's not a huge appraisal component to it. There is a little bit. Again like last year when we drilled a lot of development wells, so we weren't just out drilling single wells. It fits that same old, so it's a progression of areas we feel very comfortable with technically. So, from a well performance risk, I think it's very, very low. The biggest risk I see is actually -- from a performance standpoint, we're starting to see high productivity gains and lower time-to-market, drilling faster, and things like that. So, the biggest challenge is with us is as that continues, what do we do when that pace keeps picking up. But from a cost standpoint, Aventine is up and running. So, we've realized two-thirds of the benefits from that. We feel very comfortable with that. We have our people in place. I mean one of the things we did very early on is not just wait until we have the activity to start getting all the right resources in place. So, I really feel like our program is de-risked from execution standpoint cost and performance standpoint for this year, especially at the pace we're going. Because like Vicki said running 12 rigs for us is a very moderate pace, especially compared to many others and especially compared if you go back a few years ago we are at 40. So, it's well within our bandwidth to handle this not just execution but technically.
Brian Singer:
Great. Thank you.
Operator:
And the next question comes from Doug Leggate of Bank of America Merrill Lynch.
Doug Leggate:
Thank you, good morning everyone. Cedric I wonder if I could just get some clarification from you on slide 21. And I guess I'm also comparing it to the slide you put up specific to 2019 capital back and I think there's a confidence at the beginning of the year. So, what I'm really trying to understand here is $50 TI post-2019, you're capping your spending is that the way to think about this and above that is going back to shareholders?
Cedric Burgher:
Hi Doug, good question, I appreciate the clarification. We're weren't intending to have it be precise where you move to one penny to the next and that shift gears but it’s indicative of our -- the way we think about it we would spend I guess two years ago when we came out with our breakeven plan which allows us to sustaining a world-class dividend and keep our production base flat at $40 oil. And what we're doing today two years later is nothing short of amazing in terms of beating those assumptions -- beating that plan we're beating it on cost. As Jeff outlined, we're beating it on productivity of our wells and so as we continue to lower our breakevens just by the way that is one of the keys to us raising our dividend at a more meaningful rates. We've continued to raise our dividend 16 consecutive years but it's been more modest since the downturn more modest rates. We'd like to go back to more aggressive rates but the key to that is lowering our breakevens and delivering more cash flow from that. So – but above $40, we are looking at reinvest first and would get to that 5% to 8% target long-term growth rate, continue modest dividend growth and then above the $50, we are looking at both balance sheet improvement as well as share repurchases and that's something we certainly demonstrated last first. So I wouldn't give you a precise $50.01. We're going to share buyback that number or dividend increase, but it is how we're thinking about it, as you get into a certainly a $60 environment which is what we're forecasting to the 2020 we think that as a logical price for the industry to balance supply and demand. That is something we would look to do as we return more capital at that point. We don't need to grow any more than that 5% to 8% long-term target.
Doug Leggate:
I understand. I appreciate the clarification, because I just wasn't – I think there was an earlier question it sounded like it was different but that's very clear. Just to talk on that very quickly the $50 TI I assume you're still using a $10 differential for Brent?
Cedric Burgher:
Yes.
Doug Leggate:
Okay. My follow-up then is also related to the dividend. So I know you guys talked to this many times in the past, but if you're at $9 billion let's assume in a couple of year's times or let's assume oil maybe is a little bit more generous in between times. Is your first priority to reduce the dividend burden by buying back stock because on a per share basis you still get the growth of your buyback the stock? So how should we think about absolute dividend growth versus per share growth through share buybacks? I'll leave it there. Thanks.
Cedric Burgher:
Great – great question. I mean, we see dividends and share buybacks as complementary. I will say our first priority is always the dividend. We prove that in the downturn. We're one of the few high-dividend paying companies that didn't cut the dividend. There's a long trail of bodies of companies that did. We're very proud of our track record in a very tough time. So our priority is and always will be the dividend. We want to – we will continue to grow it. That's our intent and we certainly want to grow it even more meaningful rates as we're able to. Can't forecast when that will be, but as we think about higher prices that's certainly like I said earlier, when we start to think about buybacks and it's complementary as you stated, because it does reduce the share count that which enables us to afford dividend growth more easily. So but certainly that $9 billion that we're forecasting in 2020 should we have a $60 environment? If you back out the midpoint of the CapEx range at that time of $5.1 billion that leaves you $3.9 billion of free cash flow. That compares to our current dividend of about $2.4 billion. So that's more than a 50% cushion on that dividend, if you will that would allow you in a $60 environment to both grow the dividend and do buyback. So I think we would be in a very good position that even a modest improvement in oil prices over that time to be in a really good position to deliver a return a lot more capital and we would do it in both dividends and buybacks, which again I think – we think of as complementary.
Doug Leggate:
I appreciate the full answers. Thanks Cedric.
Cedric Burgher:
Yep.
Operator:
And the next question comes from Phil Gresh of JPMorgan.
Philip Gresh:
Yes. Hi. Good afternoon. Thanks for squeezing me in here, just starting I guess with Midstream. Could you help maybe bridge the 4Q actual results to the 1Q guidance? I know, maybe there was some items on both sides here but it just seems a little bit bigger than the normal sensitivity, I would suggesting the differentials. And then if you have an outlook on the full year for the midstream business whether it's on differentials or the pretax income, if you could share that?
Vicki Hollub:
Yeah. Part of what's happening in Q1 is a Dolphin turnaround. So that's part of the difference between Q4 and the Midstream and the differential impact and Dolphin. We have some other just general marketing things that will have an impact in Q1 that we can detail out after Q1.
Philip Gresh:
Okay.
Vicki Hollub:
With respect to the full year, it's kind of hard to forecast the full year at this point because of the differentials and what the volatility there might be. So we’ll see how things go over the next few months or so.
Jeff Alvarez:
Hey, Phil this is Jeff and just to add to what Vicki said. I mean one thing that we wanted to update people on is to remember when the differential collapses, you see that in midstream from a negative standpoint. But the upstream now, given our oil production in the Permian, we’ll realize more than 50% of what you lose on the midstream side. So good way to think about that. We gave that sensitivity so, as that differential collapses just for everyone to remember that more than half of the benefit will be recognized in oil and gas.
Phil Gresh:
Sure. And is there a caustic price assumption that will be behind that chemicals guidance? I know that maybe early part of the year seems to be a little tougher than the back half, I'm just trying to calibrate that?
BJ Hebert:
Yes Phil, this is BJ. For caustic, and obviously, we saw price erosion towards the end of 2018. Our assumption in 2019 is we're going to see some price pick up but not to the level of the erosion that we saw towards the end of the year. So we're taking a conservative approach looking forward. But we feel really good about supply and demand fundamentals long term in the caustic market. So I think it's conservative but we still felt really good about the forward years.
Cedric Burgher:
Just to add one thing on. As we've certainly made a few adjustments to the 2022 cash flow outlook because we wanted to keep it current and that was one of the items that we were more conservative on caustic prices as well as sulfur which affects the midstream business. The combined effect of that is a deduct of about $150 million versus what we showed in 2022 versus what we showed you in the third quarter. We also had a deduct of a $250 million related to the lower production associated with a lower capital spend in 2019 and the less of a ramp in 2020. So that caused some confusion also last night, we didn't intend for that. We thought we’ve laid it out, but just to clarify. So that's $400 million combined which more than offset the $150 million pick up we have from the $5 increase in the Brent price differential versus last quarter. So just trying to bring it kind of current with current thinking, so it's not stale, but that's where we kind of move from the midpoint of the $9.25 billion last quarter to the $9.0 billion this quarter.
Phil Gresh:
That's really helpful. Thanks Cedric. Last question for Vicki, you just made a comment in your prepared remarks about 20% base decline rate and that it was higher than in the past. So I just wanted to understand that comment a little bit more, what would you have said it was in the past? And I guess just because Permian's only one-third of the production at this point, so it's a little bit high to me, but just any additional detail behind that would be helpful? Thank you.
Vicki Hollub:
In the past we were traditionally running at a little bit less than 10%. And so the increase in the Permian has gotten us to -- will have us by the end of this year to around 20%. But it's important to think about the strength of our chemicals business in this sort of environment is that, when you think about our overall cash flow decline that's really only about 15%. So the 20% decline in the oil and gas business is not alarming, although the international assets as we develop those that will somewhat mitigate that decline.
Phil Gresh:
Okay. Thank you.
Operator:
And the next question comes from Philip Jungwirth of BMO Capital Market.
Philip Jungwirth:
Thanks good morning. I was just hoping you can give a little more color around the 6% international production CAGR key drivers and then really just the progression of that growth over the next couple years because when we look at the 2019 guidance it looks like you're budgeting around $800 million of CapEx flat year-on-year production. So, how is that -- really either capital efficiency improved? Or is it more value increasing than the level of investment?
Ken Dillon:
It's Ken here. As I mentioned earlier in terms of capital efficiency, our drilling performances improved beyond measure over the last few years. So we're able to drill many more wells now than we could say three or four years ago. In terms of the roadmap on slide seven, we basically have a large portfolio in our opportunities going forward. We have milestones associated with Colombia, the TECA development and new blocks. If you look at it, it spades through year by year, each of these plans will be optimized over time, so that we can maximize the returns of every one of these streams. So we feel comfortable in reaching the 6% with the portfolio that we show here. We haven't talked about Al Hosn debottlenecking, we see opportunities there and we see great well performance and also a new geological and petrophysical model, so that we have additional gas there to enable that to be -- probably be debottlenecked.
Phillip Jungwirth:
Okay. And then on slide 6, where you lay out the facility investment at 24% of the 2019 program, I was wondering if you could just isolate that to the Permian Resources as a percent of the $2.6 billion capital budget, and then also how that would trend over time? And maybe provide some color around just operating cost benefits around that facilities investment?
Jeff Alvarez:
Sure, Phil, this is Jeff. So for 2019 it's around 21% facilities and I’ll carry that when we do our OBO, we exclude that but they also have a facilities component to it. So if you're looking at it from a peer standpoint you’d probably want that in. But of the $2.6 billion, it's about 21% as facilities and you brought up one of the most important thing, not just from a productivity standpoint, but that really helps drive full cycle cost, which shows up in operating cost. So when you look at our operating cost, us able to get down into the mid to low-sixes is really where you see the benefits of that. He also see it from a productivity standpoint it's harder to measure just from an uptime standpoint and ability to handle the production reliability it shows up there as well. So from a long-term standpoint, we look at most of our field development plans, we expect to get on average below 10%. So if you go and look at our more mature areas like in the Midland Basin where we have infrastructure developed and you look at the new developments there we're below 10%. So we expect to get there in the not too distant future from a total facility spend.
Phillip Jungwirth:
Great. Thanks a lot.
Operator:
The next question comes from Paul Cheng of Barclays.
Paul Cheng:
Hi, guys. Just couple quick question. On the breakeven you're talking about the 24% on average per year growth in the Permian Resource. But can you give the number for 2020 to 2022 what is your rig count per well, productivity improvement that you assume comparing to 2018 or 2019? And also what is it the CapEx assumption as well as the base decline curve?
Cedric Burgher:
Sure. So, Paul, what we said last year, so 24% CAGR, four-year CAGR. This year it will be 30% to 35%. So obviously, that number is coming down as the base grows. And so the way I think about it, when we originally rolled that out, we said capital would be roughly flat with where we were last year, which was around $2.8 billion. And so, what's going on when you do that it goes back to question Phil asked is, you actually -- we're running say 12 or 13 rigs at that pace. But as you spend less on facilities, you're able to dedicate more of that capital and to drilling wells. So just easy math, these aren't exact numbers because we'll factor in with working interest and other things, but facilities goes from 20% to less than 10%, that could add a couple operated rigs to better generating production growth, instead of being spent on facilities.
Paul Cheng:
So you're basically looking about 14, 15 rigs. And in the base assumption what kind of productivity improvement on the well production?
Cedric Burgher:
Yes. That's a great question. So, hopefully, you've heard, with our long-term forecast, we always want to make sure we can deliver our long-term forecast. So when it comes to productivity improvements, we've assumed almost zero. I think we've had like 1% in some areas for productivity improvements. When I just reference the slide that shows is 25% improvements in the last year, 20% improvement in the year before that and so on. So we've been really conservative with productivity improvements and how we've built that into the plan. So it's almost zero. But we had some areas that were new from an appraisal standpoint, so they have some uptick in them. But it's small on a global scale.
Paul Cheng:
And just a clarification, Jeff, you earlier had mentioned in your prepared remarks saying that in five years time that this will be over 600,000 barrel per day. Are you talking just the Permian Resource or Permian Resources plus EOR?
Cedric Burgher:
Yes. That's just Permian Resources.
Paul Cheng:
Just Permian Resources. Okay.
Cedric Burgher:
Correct. So that excludes EOR, obviously.
Paul Cheng:
A final question that, I think, Vicki was talking about, you guys have done a number of pilot on the CO2 as well as using the other hydrocarbon. Have you so far seen any distinct pattern, certain type of activities like of the reservoir will be better respond to a certain -- to CO2 flooding and the other one? And is there anything that you can share? And how wide spread is that application could be?
Cedric Burgher:
Yes. I mean, nothing meaningfully that we can share, but you're right. I mean, different reservoir characteristics will be more conducive to hydrocarbon gas versus CO2. And I'd say, you can look at, in a conventional world, many of the same principles will apply with miscibility, depth, pressures, temperature, all of those things. And so, as Vicki said, we're really comfortable now from a technical standpoint that we know with the EOR, hydrocarbon gas and CO2 through the different reservoirs, we can get more oil. And actually is better technically than what we thought. The real challenge is, from a commerciality standpoint what do patterns look like, how do you design them and how do you handle the gas processing, all of those things, that's where the real challenge lies and that's why we're focused on proving up that commerciality. But you will see differentiation based on reservoir characteristics, not that different than what you see in the conventional reservoirs.
Paul Cheng:
And when you guys will be in a position that you maybe share more of the data?
Cedric Burgher:
I would expect late this year, we'll share more of that.
Paul Cheng:
Thank you.
Cedric Burgher:
Thanks, Paul.
Operator:
And the next question comes from John Herrlin with John Herrlin with Societe Generale.
John Herrlin:
Yes, hi thank you. With respect to your CapEx budget, what kind of labor or oilfield services inflection cost are you baking in for this year?
Vicki Hollub:
We're baking at about 4%. 4% is domestically but internationally, we're not seeing the kind of inflation that we're seeing domestically.
Ken Dillon:
Internationally we're seeing the last 16 contracts we've bid; we've seen 4.1% deflation. And if we focus only on the sort of major suppliers what we're seeing is a 16% reduction internationally.
John Herrlin:
Good. My next question is regarding international policy, you had some good growth in Colombia and also me in it, was that all drilling-program elevated?
Cedric Burgher:
I think a combination of drilling also some of the reservoir characterization work we're seeing and overall, it's just a really good performance. I don't see anything one individual thing it's just a collective individual activities across the whole international.
John Herrlin:
Okay and the last one for me is on the Permian Resources. Earlier it was mentioned that you haven't had sort of the parent-child relationship that some of your peers have. Have you changed your spacing design balance in your core areas? Or is it very petrophysically specific.
Cedric Burgher:
Yes. I think it's very petro-physically specific. So, if you look at our core areas, they may vary from three well spacing to six or seven as where they are. And the numbers that we give in or less than 50 inventory we average about 4.7. So, I'd say significantly lower than many others. But again we're getting really, really good performance. So, that comes out there. But that's one of the variables that we continually update and modify and I think we mentioned an example in Texas Delaware where now we're doing more of a Chevron design in developing kind of two benches almost together and the implications of that are really good well performance and you are able to remove a well and get better performance when you combine those two together. So, it's one of the variables we turn all the time, but I would say when you mentioned the parent-child, we're not unique. That relationship exists. I would say we've just figured out how to manage it optimally from a net present value standpoint and not just try to drive up inventory.
John Herrlin:
Great. Thank you.
Vicki Hollub:
Thank you.
Operator:
And next we have a question from Leo Mariani of KeyBanc.
Leo Mariani:
Hey, guys. I just wanted to touch quickly on the EOR business. Obviously, you guys have put some longer term growth rates between 2018 to 2022 for Permian Resources and international. Just want to get a sense of how is that EOR business play out that outlook? Is it more flattish with cost reductions? Or how do you think about that production stream?
Jeff Alvarez:
It has very minimal growth. It's on the order of 1% CAGR over that time period. So we continue -- as we show we have tons of inventory for further EOR projects, so we continue to prosecute that. But we need more inject and other things. So it’s CAGR is around 1%.
Cedric Burgher:
The one thing I'd add to that is if you had noticed when created the Low Carbon Ventures group last year, we've got some milestones listed in that area too. It's not reflected in the 2022 outlook but it is certainly an area that we like to make great progress and develop. And as Jeff mentioned we have a lot of running room to grow in terms of EOR projects if you could just get more CO2. It's kind of the irony in today's world where most people want to eliminate CO2 emissions and we just can't get enough CO2 commercially to our locations. And it's an area we're focused on.
Vicki Hollub:
Yeah, the bottom line is that that's another potential upside for our 2022 plan.
Leo Mariani:
Okay. And just shifting gears over the new block you guys picked up in UAE there. You certainly talked about a plethora of prospects over there. Presumably is most of the activity going to be focused on oil over the next couple of years, obviously, you're neighboring out holes and block there is more gassy, can you just give us any color on what you're targeting?
Ken Dillon:
Yeah, it's mainly oil we’re targeting as I mentioned earlier between the super giant fields in Abu Dhabi and the prolific fields in Oman, we’re focused mainly on oil.
Leo Mariani:
All right. Thanks, guys.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back to Vicki Hollub for any closing remarks.
Vicki Hollub:
I want to thank you all for your questions and have a good day. Thanks. Bye.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Jeff Alvarez - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Cedric W. Burgher - Occidental Petroleum Corp. Kenneth Dillon - Occidental Petroleum Corp.
Analysts:
Doug Leggate - Bank of America Merrill Lynch Brian Singer - Goldman Sachs & Co. LLC Paul Sankey - Mizuho Securities USA LLC Leo P. Mariani - NatAlliance Securities Pavel S. Molchanov - Raymond James & Associates, Inc. Philip M. Gresh - JPMorgan Securities LLC Robert Scott Morris - Citigroup Global Markets, Inc. Paul Y. Cheng - Barclays Capital, Inc.
Operator:
Good morning and welcome to the Occidental Petroleum Corporation third quarter 2018 earnings conference call. All participants will be in listen-only mode. Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez - Occidental Petroleum Corp.:
Thank you, Andrea. Good morning, everyone, and thank you for participating in Occidental Petroleum's third quarter 2018 conference call. On the call with us today are
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Jeff, and good morning, everyone. Today I'd like to begin by highlighting the results we've achieved over the last 12 months, during which our focus on value growth and our high-quality assets delivered a cash return on capital employed of 26%. Combined with a double-digit return on capital employed over the same period, we have clearly demonstrated our ability to deliver industry-leading returns and have aligned our executive compensation to this principle. Our integrated business model provides us with numerous opportunities in which to invest and grow free cash flow in a sustainable manner well into the future. We remain disciplined and will continue to allocate capital to investments that generate the highest returns for our shareholders. This approach enabled us to deliver $3.3 billion of cash to shareholders over the last year through a combination of our dividend and share repurchases while also growing production by 14%. This morning, Cedric will walk you through our financial results and updated guidance. Jeff will detail the sustainable and value-creating improvements we continue to create in the Permian. And prior to leading our Investor Relations, I just wanted to let you know that Jeff served as President and General Manager for two of our Resources business units, Texas Delaware and Midland Basin. He also has significant prior experience in our Enhanced Oil Recovery businesses. After Jeff, Ken will provide an update on operations and opportunities in our international businesses. Before covering our third quarter highlights, I would like to mention an organizational update and congratulate Jeff Bennett and Barbara Bergesen. They have recently taken on heightened roles within our Domestic Oil and Gas business. Jeff is leading our three Permian business units in the Midland Basin, Texas Delaware, and Southeast New Mexico. And Barb is leading our Permian Enhanced Oil Recovery business. I'd also like to congratulate Richard Jackson in his new role, which includes leading our new Low Carbon Ventures team along with our Permian competitor analysis, land, and regulatory teams. The Low Carbon Ventures team will work across all of our businesses. These changes will enable us to focus more intensely on the Permian and to develop unique corporate strategies that address the key challenges facing our industry. As noted on slide 5, we delivered an exceptional quarter both financially and operationally. Our operating cash flow of $2.6 billion exceeded capital and dividends by $700 million. And during the third quarter, we returned $1.5 billion to our shareholders. Our earnings per share of $1.77 is the highest quarterly EPS we have achieved since the second quarter of 2014, when the average WTI oil price was over $100. All of our business segments exceeded key performance targets through production growth in the most profitable areas, lower unit cost, and better price realizations. In Permian Resources, we brought our best well to date online in the Greater Sand Dunes area. And in Barilla Draw, we brought online the best Texas Permian well to date for the industry. These achievements were made possible through the investments we've made in our people and the advances they have achieved in subsurface modeling and characterization. In Oman, we have three new blocks that will provide us long-term, short-cycle, lower-decline growth opportunities. Ken will provide additional information on these later in the presentation. Our Chemicals segment produced another record quarter of earnings as a result of our integrated business model, which allows us to take full advantage of favorable market conditions. Our Midstream and Marketing business continues to deliver high realizations from our advantaged Permian takeaway position. And as expected, we closed on the previously announced $2.6 billion Midstream transactions. Our priority continues to be the allocation of free cash flow towards investments that generate the highest returns, along with returning cash to shareholders through our dividend and share repurchases. This includes investing in high-return assets across our integrated businesses. With the additional three blocks in Oman and new opportunities in Colombia, we now have an even larger inventory of short-cycle high-return long-term growth options in our Oil & Gas business. OXY approaches each opportunity we consider with a disciplined focus on returns. Every project must create value for our shareholders, period. This is one of our core principles. Our priority now is to replace the cash flow from ISND [Idd El-Sharghi North Dome], and we're confident we'll do so in 2020, both from our ongoing development program and reallocation of capital from the North Dome. We will invest in our highest-return projects, with Permian Resources serving as a returns benchmark. Slide 6 shows the depth of opportunities across our portfolio from which we grow our high-return cash flow. Our integrated business provides domestic and international, conventional and unconventional opportunities from which to grow value from our oil and gas production. And our Chemicals segment also has opportunities to grow cash flow. As we communicated our plan for 2019, we'll provide further details of our capital allocation. Looking past next year, we will continue to focus on our highest-return opportunities and expect to increase cash flow to between $9 billion and $9.5 billion by 2022, as shown on slide 7. This level of cash flow is achievable through investments in short-cycle high-return projects and is sustainable with an annual capital investment of $5 billion to $5.3 billion in a $60 price environment. We will deliver higher rates of production growth in 2018 and 2019 to replace the cash flow from ISND in 2020 and to return to higher dividend growth, but our long-term production growth target remains at 5% to 8%-plus. Before I turn the call over to Cedric, I want to talk about what discipline means to OXY. We have honored our commitment to shareholders by returning capital and will continue to do so. We're one of only a few companies in our sector that did not cut our dividend in the downturn or dilute our shareholders. We continue to increase our dividend and plan to return to more meaningful growth in the future, which is one of the key reasons we're investing in our highest-return assets, so that we can increase cash flow and return more cash flow to shareholders. As shown on slide 8, we have increased our dividend each year since 2002 and repurchased a significant number of shares in a higher oil price environment. Also, since 2006, we have returned a total of $31 billion, or over half of our current market cap, to shareholders. Returning capital to shareholders via our dividend and share repurchases is not new to us and will continue to be a key part of the value we provide. I'll now hand the call over to Cedric.
Cedric W. Burgher - Occidental Petroleum Corp.:
Thanks, Vicki. As Vicki highlighted, we are pleased to have continued repurchasing shares, allowing us to return $1.5 billion of cash to shareholders during the quarter. On slide 10, I'd like to start with our earnings, which improved across all segments, with our third quarter reported earnings per share at $2.44 and core EPS at $1.77 per diluted share. The main difference between reported and core income is the gain on sale of our non-core domestic Midstream assets, which resulted in an after-tax gain of approximately $700 million. Improvements in the Oil & Gas segment income were mainly attributed to higher Permian Resources production and Middle East oil sales volumes. Third quarter realized oil prices were approximately flat compared to the second quarter. Total reported production for the third quarter was 681,000 BOEs a day, coming in above the midpoint of our guidance. This was driven by strong execution and well productivity in Permian Resources, which came in at the top end of the guidance range at 225,000 BOEs per day, representing a year-over-year increase of over 60%. Total international production came in at 297,000 BOEs a day, which is at the midpoint of our guidance. The increase in international production from the second quarter reflected the first full quarter following the successful debottlenecking and expansion of capacity at Al Hosn. The Chemicals segment had another quarter of record earnings. Chemical pre-tax income for the third quarter was $321 million, which came in above guidance of $315 million. Compared to the second quarter of 2018 earnings of $317 million, third quarter earnings were relatively flat, as vinyl margins came under pressure from higher ethylene costs, resulting in increased ethane costs. Export caustic soda demand helped offset the decline in vinyl margins. Midstream core earnings of $796 million reflected improved marketing margins due to an increase in the Midland to MEH differential from $7.86 to $16.67 quarter over quarter and exceeded the high end of our guidance due to the marketed market improvements, stronger gas processing results driven by higher NGL prices, and one-off items from the Midstream transaction that closed in the quarter. Third quarter revenue and cost of sales were both grossed up by $327 million due to the accounting related to certain Midstream contracts where we've used our excess takeaway capacity by purchasing and reselling third-party barrels. The second quarter gross-up amount was $85 million. Operating cash flow before working capital improved to nearly $2.6 billion, as all of our segments continued to outperform cash flow expectations, representing year-on-year growth of 136%. We spent $1.3 billion in capital during the quarter, and our total year capital budget remains at $5 billion. Starting in 2019, we will begin to redeploy approximately $200 million of capital per year that would have been invested in Qatar. Slide 11 details our updated guidance, which we have narrowed for the full year. We expect total production for 2018 to be 655,000 to 659,000 BOEs per day and Permian Resources production to be 211,000 to 213,000 BOEs per day. The midpoint of this range equates to an exit-to-exit Permian Resources production growth rate of 54% from Q4 2017 to Q4 2018. We have also narrowed our international production guidance range to 286,000 to 287,000 BOEs per day and assuming a $75 per barrel Brent pricing for the remainder of the year. In Midstream, we expect the fourth quarter to generate pre-tax income between $450 million and $550 million, assuming a Midland-to-MEH spread of $13 to $15. In our Chemical business, we anticipate fourth quarter pre-tax earnings of $220 million and are raising the full-year guidance to $1.155 billion based on the strong results delivered year to date. To close, we are very pleased with our performance so far this year, including the continuation and expansion of our share repurchase program. As we have shown, our focus is on returns, and our Permian operations set a very high bar for our company and, frankly, for the industry. We have a pipeline of projects across our integrated business that meet our hurdle rates and that have long-term potential. We continue to have the discipline to hold to these principles and occasionally take tough decisions. We believe this is what it takes to lead with respect to capital stewardship. We have aligned compensation in this regard, and we continue to demonstrate our long-time commitment to returns-driven reinvestment, a robust dividend, and share repurchases. I will now turn the call over to Jeff.
Jeff Alvarez - Occidental Petroleum Corp.:
Thank you, Cedric. Our Permian teams have delivered another great quarter by continuing to find innovative ways to improve and increase the value of our assets, and I'm excited to share these results with you today. Production for the quarter was outstanding, with Permian Resources exceeding the midpoint of production guidance by 5,000 BOEs per day. Continued improvements in well results along with great execution of our operational plan is resulting in high-value production growth. Permian Resources production guidance has now increased by 10,000 BOEs per day from the initial guidance we provided at the beginning of the year. These high-margin barrels have generated additional cash and added significant value to the returns of the underlying assets. Looking at our highlights on slide 13, we continued investments in the appraisal program to delineate our acreage and optimize development plans. In Greater Barilla Draw, we integrated the results of our Hoban appraisal efforts into our field development plans and expect to be more active in this bench in 2019. We also drilled two Avalon appraisal wells in Greater Sand Dunes that each averaged approximately 2,700 BOEs per day over 30 days. Our appraisal program continues to provide us confidence that Permian Resources will generate returns and sustainable cash flow growth for many years to come. As Vicki mentioned earlier, the third quarter was another record-breaking quarter for well results in both of our core development areas. We brought online our best Permian Basin well ever. The Corral Fly 21H in Greater Sand Dunes peaked at over 8,900 BOEs per day, with an average over 6,700 BOEs per day for 30 days. We also broke the industry record for the best well in the Texas Permian Basin with a Greater Barilla Draw well, the Peck 11H, which peaked at over 6,500 BOEs per day and averaged 4,900 BOEs per day over 30 days, a 30% increase over the prior record well for this area that we shared with you last quarter. These repeatable record-breaking results are a testament to our subsurface capability, value-based development approach, and leading acreage position. While we are excited about these results and the associated returns, we believe there is still more to come as we continue to progress our subsurface characterization work and apply innovative technologies to our development plans. In addition to the productivity improvements, we lowered our field operating cost in Permian Resources to an all-time low of $7.03 per BOE in the quarter and expect to exit the year at less than $6 per BOE. Returns in Permian EOR are also improving. We continue to demonstrate our unique ability to maximize recovery of the reservoir by capturing oil that would otherwise not be recoverable. As the largest EOR operator in the Permian, we continue to implement new CO2 expansions across our portfolio. We initiated initial development of the residual oil zone at the Seminole-San Andres unit, which is providing encouraging results that will further enhance the returns from this asset. Our expertise and position in enhanced oil recovery differentiates OXY. We plan to leverage this core capability to generate enhanced returns in many areas of our business. I'll close on slide 14 by summarizing our returns-focused investment approach and the resulting production growth. While the industry has been confronted with many challenges in the Permian this year, our Permian Resources business is delivering its best year ever due to our returns-focused approach. We have delivered 52% of the top Permian wells over the last 12 months, while only drilling less than 5% of the total Permian wells over that time period. Our Midstream business is providing flow assurance and exposure to the best pricing through our marketing arrangements, and we are protecting our development program from inflation and execution disruptions through our maintenance and logistics hub. Our inventory continues to improve as we advance and execute our development strategy, which provides us with sustainable high-return investment options for the future. We expect Permian Resources to grow at over 35% next year, which is an outcome of our disciplined approach and the high-return investments that our assets provide. I will now turn the call over to Ken to discuss International.
Kenneth Dillon - Occidental Petroleum Corp.:
Thanks, Jeff, and good morning, everyone. Let me start by saying how honored we are today to be able to announce three new blocks in Oman, which I will discuss in more detail in a minute. Overall, we had an excellent quarter from a financial and operational standpoint with world-class HES performance. Our International Upstream business is on target to realize $1.4 billion of free cash flow for 2018. In the third quarter, we produced 297,000 BOE per day. We expect this high level of performance to continue as we deliver strong return projects for OXY and our partners. The plan we outlined for 2018 is progressing well. Our innovative debottlenecking at Al Hosn has increased production by 11% to a peak rate of 83,000 BOE per day net. This is one example of how we create value and enhanced returns for our existing assets, as we executed the debottlenecking for only $10 million. The TECA Steamflood project was sanctioned this month with our partner Ecopetrol. We will begin ramping up production in 2020 and reach a gross rate of 30,000 BOE per day in 2025. We are starting to identify additional areas of high potential in the field, which we can develop at attractive returns for both parties. With our disciplined approach to major projects, the TECA Steamflood exceeds our hurdle rate with a breakeven price under $40 WTI. This is just one example of how our assets in Colombia will continue to generate long-term cash flow growth. Internationally, our step-out drilling programs are on track to add approximately 20 million barrels of resources this year at low finding costs. This is in addition to the 50 million barrels of resources added last year. Overall, since 2014, using OXY drilling dynamics and working with our suppliers, we have improved our drilling performance by 17% and reduced costs by 30%. Moving now to Oman, we as the Cities Service drilled the very first exploration wells in Oman in 1955 and made the first discovery in 1957. In 2017 we produced our 1 billionth barrel of oil in Oman, with two-thirds of that production coming in the last 10 years. We're excited today to announce three new blocks in Oman, which will more than double our land position to approximately 6 million acres and fit perfectly with our expertise in generating returns from water flood and EOR development. As you can see from the maps on slide 18 (sic) [17], in Northern Oman our acreage will stretch over 225 contiguous miles, allowing us to leverage existing infrastructure as we explore, appraise, and develop Blocks 65 and 51. Block 72 greatly expands our acreage position in central Oman, where we see opportunities to expand upon the success of our Mukhaizna development next door. In our existing blocks, as shown on slide 19 (sic) [18], with the use of OXY subsurface reservoir characterization workflows, we've helped redefine the stratigraphy. This has enabled us over a short period of time to move from five productive horizons to 17 producing and appraisal horizons. We will apply the same disciplined approach to the new blocks. We will shift 3D seismic and invest in targeted appraisal programs. Capital for next year will be modest as we acquire data and optimize future development profiles. These blocks have significant potential, especially when combined with our excellent Omani staff, exceptional partners, and inspirational leadership in the country. We expect our proven track record of value-based development and rapid time to market to continue. In closing, I'd like to say that our regional subsurface experience is now being fully leveraged. We believe that in the long term when combined with our approach to operational excellence and value creation, it will bring future potential opportunities. I will now turn the call back to Vicki. Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Ken. Before we move to the Q&A, I'd like to reiterate OXY's sustainable value proposition, through which we'll continue to deliver industry-leading returns. Our integrated business model enables us to take advantage of opportunities across the value chain and generate high returns in the Permian and internationally, while benefiting from the stable cash flows generated from our Midstream and Chemicals segments. We will continue to invest in our human capital and empower our employees with the culture and facilities, innovation and excellence. This is what their exceptional performance has enabled us to accomplish over the last couple of years. We've more than exceeded our targets, in addition to delivering the best wells in the Permian, our experience in operating wells beyond the initial development and through their entire life cycle, including enhanced recovery, that's second to none. Our Low Carbon Ventures business is making advances toward capturing and sequestering anthropogenic CO2, which will reduce carbon emissions while enhancing the economic development of our reserves. OXY is uniquely positioned to realize cost efficiencies, not only in developing and operating wells, but also through our capability to deliver our products to market at maximized realized prices. We remain committed to developing our resources in a sustainable manner while spending within cash flow. Last quarter we achieved our breakeven plan, meaning we will be cash flow neutral and pay our dividend at $40 WTI. And at $50 WTI, we can pay our dividend and grow production by 5% to 8%-plus. This plan remains in place. Our relentless focus remains on allocating free cash flow to investments with the highest returns across our integrated business and returning capital to shareholders through our dividend and share repurchases. Since resuming our share repurchases program this year, we will have returned over $5 billion to shareholders through dividends and share repurchases by the end of 2019. Lastly, across our businesses, we continue to focus on creating long-term value through industry-leading technical work, life cycle planning, and operations focused on maximizing margins. We'll now open it up for your questions.
Operator:
We will now begin the question-and-answer session. The first question will come from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thank you, everybody. Excuse me, I wasn't expecting to be first. I apologize. Guys, I've got two questions, if I may. My first one is actually on the Middle East. Obviously, I understand the comment about reallocating capital from Shah – I'm sorry – from Qatar, but my question is really around Shah Al Hosn. About a year or so ago, the government had talked about a project pre-FEED for something like a 50% expansion of that development. I understand you've done the debottlenecking project, but the secondary piece of that appears to have gone somewhat quiet. And I'm just wondering if you can give us an update as to where that stands, please?
Kenneth Dillon - Occidental Petroleum Corp.:
Good morning, Doug. It's Ken. We've successfully debottlenecked the plant. We continue to look for ways to tweak the plant overall. But at the moment, there are no full-scale debottlenecking plans in the near future. We will continue to work all different aspects of the project, but at the moment there's no commitment.
Vicki A. Hollub - Occidental Petroleum Corp.:
We're really happy with being able to expand it from 1 BCF to 1.3 BCF a day with only a $10 million investment. So with that accomplishment, that put the other project a bit on hold.
Doug Leggate - Bank of America Merrill Lynch:
Got it, I understand. Thank you for that. My follow-up is if I could turn it back to the Permian, and I don't know who wants to take this one. But with Jeff moving to take over I guess the other regions, it begs the question what assumptions lie behind your 35% in fact longer-term growth profile. And to be clear, what I'm asking is Red Tank is obviously in a much, I guess, more over-pressured area. The transition of some of the things you've done in Eddy and Lea going over to Midland and I guess Southern Reeves, what does all this mean for the assumptions that were embedded in your growth? Are you using 2018 productivity? Are you using data productivity? I'm just trying to understand what the well trajectory looks like that's embedded in your forecast? And I'll leave it there. Thanks.
Jeff Alvarez - Occidental Petroleum Corp.:
Doug, this is Jeff. I think when you look to next year, we've built in some of our recent performance. Definitely the improvement in performance we've seen in New Mexico starting in 2017 into 2018, we've built that in. We've talked about before, where we tend to be a little conservative is just additional improvements that are going to come in the future. We definitely expect to see additional improvements across our development areas. You can see that through not just New Mexico but what we've done in Greater Barilla Draw and beyond that. So the teams continue to work the subsurface methodology, which is the foundation of all the improvements we're making, so we expect those improvements to continue. But when you look at next year and the 35-plus percent growth that we've given out, we have built in many of those improvements that we're currently aware of. Where we are a little conservative is the things we just haven't figured out but we expect to when we get to that point.
Doug Leggate - Bank of America Merrill Lynch:
Just to be clear, is that trajectory on a flat rig count, or is there a rig count trajectory you can give us that goes along with that 2022 outlook?
Jeff Alvarez - Occidental Petroleum Corp.:
It's a flat rig count.
Doug Leggate - Bank of America Merrill Lynch:
Great stuff. Thanks so much, everybody.
Operator:
Our next question comes from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you, good morning. Can you talk more to the specific drivers of getting Permian Resources operating cash cost down below $6 per BOE in the fourth quarter from slightly above $7 in the third quarter, especially as that would be an acceleration in cost reduction relative to what we saw in Q3 versus Q2?
Jeff Alvarez - Occidental Petroleum Corp.:
Brian, this is Jeff, and I appreciate the question. So the big drivers of that, there are two components. Obviously, cost per BOE, there's the cost side. And so if you look at the details, you can see things like our downhole maintenance, the things we're doing from an artificial lift standpoint to finding effective artificial lift systems for very high-rate horizontal wells. We're seeing our downhole maintenance cost come down because we're getting much better at finding the right lift systems. And then when things do fail, which they do from artificial lift, getting them fixed cheaper and faster. So that's one area. If you look at what we're doing on the water recycling side, the chemicals side, getting trucks off the road, infrastructure in place, so all the things that we do from our initial developments to where we start planning, how do we need to operate these fields, start to translate into the cost side. The second part of that component is obviously the barrels. We're making a lot more barrels. We're making a lot more lower-cost barrels. So when you look at the cost per BOE of these new barrels we're bringing on, the high-rate unconventional barrels, they're much lower than the legacy barrels, so that helps drive that cost down as well. And Vicki mentioned it, but that's one area we're very excited about. As the unconventional business matures, that's one area where we think based on what we've done in our EOR business and the core capabilities we've built, we'll be able to use that and further differentiate ourselves when it comes to getting margin, by not just good development cost but excellent operating cost, and I think this is a testament to that.
Brian Singer - Goldman Sachs & Co. LLC:
Great, thank you. And then my follow-up is with regards to the allocation of free cash flow. You've highlighted the case for free cash flow well in excess of dividends out to 2022. And when you think about the needs for allocation, what if any is needed to advance the portfolio, either from new projects or via M&A versus what you see as returnable to shareholders? And then tangentially, Cedric mentioned $200 million that would have been invested in Qatar is going to be redeployed. Can you just talk more to where that's going, or maybe that was the point that you were making with regards to Colombia and Oman?
Cedric W. Burgher - Occidental Petroleum Corp.:
Brian, this is Cedric. A whole lot there in the question, but it's a good question. It's at the heart of what we're trying to do, which is to allocate capital to the very, very best places. As you know, we have a long history of a fairly diverse approach, which we are continuing today between dividends, buybacks, and reinvestment. M&A also is something that has certainly been a part of OXY's DNA and continues, and we look at opportunities there. So our organic plan is very strong, and that's really what we've touched on here so far on the call. But we've got lots of opportunities, and Ken touched on it. Internationally, you see what we're doing with EOR and our Low Carbon Ventures. And of course, the Permian is fantastic and even getting better each quarter. But that's how we're going to approach it. It's consistent with what we've been doing. But we'll just continue to look for the very best places to put the money and make those decisions as we go each year. We do look forward to growing the dividend at a faster rate and buying more shares, but it will be opportunistic in those cases.
Vicki A. Hollub - Occidental Petroleum Corp.:
And I'll just add to that. We've shown before that up to $50 we can actually grow 5% to 8%. So when we lean from $50 to $60, we have the opportunity to continue to either grow or use funds to buy back shares or to increase our dividend. And over time, the reason for the accelerated growth, what some consider accelerated growth, early is to try to put ourselves in a position with respect to cash flow that we can grow the dividend more meaningfully. But I will say that the international projects that we've just picked up in Oman are very good. The seismic analysis and the interpretation is showing good prospects. That's why Ken showed the stratigraph of the horizons that we had to choose from. This is stacked pay and it's quality stacked pay. So I'm really excited in that Oman provides us so many more opportunities now. And I feel a lot better today than I've ever felt about where we are with respect to the organic growth prospects and the ability to grow the cash flow. That's why we wanted to provide you the numbers for 2022. We're very confident in being able to achieve that with the assets that we have and hopefully continue to advance technology to improve upon that. But it's certain that we have – I think we're in a better position today than we've ever been. I'm excited about it. It's certainly taken a lot of pressure really off of our ability to continue to fund and develop and even improve projects within our portfolio.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you.
Operator:
Our next question comes from Paul Sankey of Mizuho. Please go ahead.
Paul Sankey - Mizuho Securities USA LLC:
Good morning, everyone. Vicki, you provided an illustration here of the company at $60 through 2022. It feels like you're planning at $50, and this is an upside illustration of the kind of cash flows you'd generate. In that regard, I was wondering. The dividend growth in the past you've talked about in line with production growth, I think. Can you illustrate or indicate to us what kind of dividend growth you'd be aspiring to? Do I assume that you would grow the dividend assuming $50 and do the rest as buyback? Thanks.
Vicki A. Hollub - Occidental Petroleum Corp.:
The way we're trying to model this, and it's a little bit difficult to explain, but this $40 cash neutrality is really the point that we want to maintain into the future. What that means is as we continue to grow our cash flow, our cash flow neutrality price actually will go down. As it goes down, we intend to grow the dividend accordingly so that we maintain the $40 cash flow neutrality. So that's what we're trying to come back to. That's why our model really shows that above $60 that providing cash back to the shareholders through buybacks is an option that for us will continue to be a part of our proposition. We don't want to increase the dividend so significantly that we put ourselves way above that cash flow neutrality, so we're targeting to keep that in place over time. And growing the cash flow to what we proposed in 2022 will enable us to grow the dividend more meaningfully than we've done in the past few years.
Paul Sankey - Mizuho Securities USA LLC:
Yes, so if we would triangulate that, would we be looking for something around a 5% dividend increase annually at a $50 assumption?
Vicki A. Hollub - Occidental Petroleum Corp.:
Potentially. But again, it depends on the cash flow. When you model that out and you see what your free cash flow is from that model, that free cash flow is something that we would be able to sustain beyond 2022, so that would be what we would then allocate to dividend growth over that time period.
Paul Sankey - Mizuho Securities USA LLC:
Got it. And can you just remind us? It's a separate subject with my final question. On risks such as we saw with Qatar in the past quarter, which I understand you couldn't pre-warn about insofar as you were still in negotiation, can you just highlight anything else that is in that realm of a potential shift that could happen over the period through 2022 in terms of PSCs and other contracts? Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
No, we don't have anything that would be expiring in terms of PSCs. Everything else we have is long term. The nearest term one that we would have would be ISSD, which is South Dome in Qatar. That expires in 2022, but that's very low production and that's really not even material to us. But everything else we're in good shape about. That's why I made the comment I really feel good about where we are. Qatar was ISND. We worked hard to get that and to extend that. But we're actually – this has turned into a win-win for us in that we've been able now to pick up in Oman those three projects, which are onshore, lower cost, and they're right next to the bolt-ons, so they're right next to what we know we have in the blocks that we have today. And with what we see on the seismic, we feel really good about that potential. So we went from a mature asset and higher cost to lower cost new field development, but near infrastructure. So, we're in a really good situation today.
Paul Sankey - Mizuho Securities USA LLC:
Great, thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
Our next question comes from Leo Mariani of National Alliance Securities. Please go ahead.
Leo P. Mariani - NatAlliance Securities:
Hi, guys. I wanted to explore a little bit further on Oman here. Obviously, you guys had some interesting prepared remarks on it. You certainly talked about some enhanced recoveries and some EOR opportunities. But I'm just trying to get a high-level sense here. Is there already production on some of these blocks? Are there some maybe lower-producing mature fields, or is this more of a rank exploration play in certain areas? Maybe you can just try to better characterize this a little bit just to get a sense of the risk profile of the opportunity here.
Kenneth Dillon - Occidental Petroleum Corp.:
Hi, Leo. It's Ken. If you look at the blocks individually, Block 65 is very close to our Block 27, so we see that as step-out wells for formations that we're used to dealing with. If you look at Block 72, it's beside Block 53 with the giant Mukhaizna field. We're also seeing recent discoveries with our step-out wells in Block 53 with a Buah trend running north. There are also blocks in the north, further north in Block 72 that have a Buah trend running south. The 2D seismic lines that we've seen over Block 72 look really, really appealing, and we've got the areas divided into clusters running north. Cluster 1, we plan on drilling a well late this year, and we'll start 3D seismic as quickly as possible, so we can get a crew next year. Low dollars in terms of capital, but we see really, really high potential in these blocks. And then if you look at the stratigraphy, we've done some recent seismic work in one of our existing blocks, where it looked like we saw something, so we put some pails very cheaply on development wells, a few hundred thousand dollars, and we've now got a 1,000 barrel a day well producing in a zone that has not been produced in Oman before. The question is how do we calibrate that, and does it run everywhere? And what we've got there is essentially a zone that's got 25 penetrations in an area the size of the Delaware Basin. So we see real opportunities with our step-out program, and we see real opportunities because of the proximity to existing facilities. We can get stuff on really, really quickly. And great familiarity with our Omani staff there, and our partners are really committed to these projects too. So we see holistically huge opportunities here for us.
Leo P. Mariani - NatAlliance Securities:
All right, that's very helpful color. Just switching gears a little bit to the Permian Basin, a bit of a high-level characterization I was looking for here. But I guess you guys just continue to make better and better wells here in the Permian. It's just very impressive results again here this quarter, more record wells. I'm just trying to get a sense. You certainly mentioned that there could be further improvements down the road. Where do you guys think you sit if I was to use a baseball analogy? Is this the fourth or fifth inning? Are we more towards the later innings of improvement? I was just trying to get a high-level perspective.
Jeff Alvarez - Occidental Petroleum Corp.:
Hey, Leo. This is Jeff. That's a good question and one we continually ask ourselves, especially the leaders of these businesses, because we always think these great results, they've got to stop at some point. But the thing I'll take you back to, you almost have to go back. Vicki initiated this transformation probably four years ago. So if you look at where we've come over the last four years, it's truly amazing. Inside the company, we really saw us turn the corner a couple years ago, but then now I think over the last couple quarters you're seeing that more externally. And the thing I'd tell you is while the foundation is built in subsurface technical excellence, which was always the primary building block for what we're doing, there are many other elements that allow us to take subsurface technical excellence and turn that into economic value and sustainable returns
Vicki A. Hollub - Occidental Petroleum Corp.:
I'd just like to add to that that during the downturn, another thing that we didn't do that others did is we didn't lay off employees. We took that opportunity to engage and empower our employees and let some of our team work on things that were longer-term so that we could start to impact our cost structure and with the subsurface, our characterization, and dramatically change how we view our subsurface now. But the credit for this all goes to our employees. We've empowered them to do the things that they need to do, take risks, do things differently, try some things that we haven't tried before, but most importantly when they felt the need, to do what they needed to do from a technical expertise standpoint to not only develop themselves and use the incredible mentors that we have internally but also to go external and to get the data that we need. On top of all this too is our really aggressive data analytics team that by working directly with the business units, the business units guide them through the questions and the problems that they need to solve, and the analytics group gets with them and works on those issues. And so it's a combination of a lot of things. But most importantly, it's the collaboration of our people to drive toward success, not just solving a problem that's not meaningful but driving toward the things that really improve the value of our portfolio and the production and value that we can deliver.
Leo P. Mariani - NatAlliance Securities:
All right, thanks a lot for the color.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
Our next question comes from of Pavel Molchanov of Raymond James. Please go ahead.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Thanks for taking the question, just one for me. One of the investor concerns about the story is the rising proportion of high decline rate production in your mix, one-third this past quarter, probably reaching 40% next year. Can you just address how high that proportion can get in your mind and still keep the dividend be sustainable?
Vicki A. Hollub - Occidental Petroleum Corp.:
We were managing both the growth of the dividend with what we know that we can deliver or think we can deliver over time with the assets that we have. But that's what's so valuable about our Colombia and our Oman and our Abu Dhabi assets is that they are essentially very low decline. Or when they are higher decline, there's the opportunity – these are conventional reservoirs mostly, so there's the opportunity for enhanced oil recovery. Some of is just going to be waterflooding. Others will be maybe perhaps either miscible gas or more specifically CO2. But these opportunities – and again, this gets back to why I'm saying I'm so comfortable and happy with where we are today. This is the part that I was referring to when I said it's taken some of the stress off the business for the growth potential. These three blocks along with what we have to develop on the existing blocks based on what we see with the seismic, these will deliver the conventional component of our growth going forward that's critically important to help us manage our base decline.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Right. Yes, go ahead.
Vicki A. Hollub - Occidental Petroleum Corp.:
I just wanted to add to that. A part of what's going to help the Permian Basin too with respect to the decline there is in our Resources business. We have performed multiple tests and pilots on CO2 injection into the shale, and that is technically successful. We're working now on establishing what that would look like from a full field development. So we do believe that that along with gas injection are two opportunities for us to offset decline going forward in the Resources business on a larger scale. Part of what will support that is our Low Carbon Ventures team, which is out looking for opportunities and actually have one in hand already, one where we're currently injecting anthropogenic CO2 but another that will come online. And this team will give us opportunities to take CO2 that is captured from industry, bring it to the Permian, and use not just in our conventional reservoirs but in our shale play as well. So that will work. That's another way that we can continue to lower our decline.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
I appreciate the color, thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thanks.
Operator:
Our next question comes from Phil Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Hi, thanks for taking my question. My first question is just around the guidance for 2022. How do you think about the amount of lost CFO between now and then from Qatar and Midstream and from Chemicals?
Vicki A. Hollub - Occidental Petroleum Corp.:
This is why we put the plan in place, because really now Qatar was a headwind, but we design our programs and our plans knowing that we're going to have cycles with respect to differentials in the Permian, we're going to have variations in caustic soda prices, variations in sulfur prices. So we plan around that, and we generally plan to be pretty conservative with those things that cycle up and down. So the program that we've put forth for 2022 we feel that certainly we can achieve that at $60 and with conservative assumptions on pricing.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, so I guess I was trying to run some numbers on this. Qatar you said there's $200 million of CapEx and you said it's $300 million of free cash flow, so I just assume that's about $500 million CFO. And with your Midstream sensitivities, it seemed like there's maybe $1.3 billion going from the 2018 differential down to the $3 differential in your assumptions. So I was calculating it might be approaching $2 billion of CFO backfill between that and chemicals to get you back to a normalized place, and then the CFO growth on top of that.
Vicki A. Hollub - Occidental Petroleum Corp.:
No, we're assuming the differential will be $3 starting in 2020 to 2022. The differential for next year we assume to be essentially what it averaged this year. But with respect to the replacement of the cash flow, what's important for us is the cash flow not only from operations but the cash flow pre-capital and post-capital. The reality is that had we proceeded with the ISND, the capital would have gone up, the take would have gone down. So in our models, we didn't have to replace that. So there was not going to be for us what we saw going forward as big a gap as you're calculating. So essentially, though, the replacement of that comes from the growth in Resources and the international growth. And again, conservative assumptions for Marketing and also Midstream and Chemicals.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. If I can just follow up on some of the prior questions, if you put it all together where the growth is coming from between now and 2022, embedded in your cash flow guidance, are you assuming basically all of the growth will come from the Permian, or should we be thinking that there will be with the blocks in Oman, et cetera, that there will be some international or other growth in the portfolio?
Vicki A. Hollub - Occidental Petroleum Corp.:
What we can say is that for Resources, you could assume that over the four-year period, there would be about a 25% CAGR plus or minus a couple percent. So that would be what would come from Resources. And then assume that the rest of the production growth would come from a combination of enhanced oil recovery in the Permian plus Oman and Colombia opportunities.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, thank you.
Operator:
Our next question comes from Bob Morris of Citi. Please go ahead.
Robert Scott Morris - Citigroup Global Markets, Inc.:
Thank you, a question for either I guess Vicki or Jeff. As you look at the Permian Basin, your growth forecast for next year assumes that the rig counts being flat basically on what it is currently and assumes about $60 WTI. This year you started out the year with a $50 WTI assumption with a higher cash flow, were able to land a few rigs versus what was the original plan to accelerate growth in 2019. And you're already looking at double-digit growth in 2019 now for the total company. But if oil prices end up being much higher than your assumption of $60 per barrel WTI, would you again look to perhaps add rigs later in the year to accelerate into 2020, or are you pretty dead-set on keeping the rig count flat through 2019 and dialing back that 5% to 8% growth then in 2020?
Vicki A. Hollub - Occidental Petroleum Corp.:
We're going to be dead flat with respect to our rigs in 2019 because we're going to stay within the $5 billion to $5.3 billion cash flow. We're putting together our capital plan now. We'll roll that out in the next quarter, so we'll provide you more information on it. But from what we're seeing right now, unless the board directs something else, we would go with the same rig count into 2019 that we have today.
Robert Scott Morris - Citigroup Global Markets, Inc.:
Okay, so even with a lot higher oil prices, that incremental cash is definitely going to go to dividend increases or share buybacks and not to accelerating activity in 2019?
Vicki A. Hollub - Occidental Petroleum Corp.:
In 2019, our capital is set for $5 billion to $5.3 billion.
Robert Scott Morris - Citigroup Global Markets, Inc.:
Right. Okay, that's helpful. Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
All right.
Operator:
Our next question comes from Paul Cheng of Barclays. Please go ahead.
Paul Y. Cheng - Barclays Capital, Inc.:
Hi. Good afternoon, guys. Vicki, on Oman, I know it's early days. Can you give us some idea? Did it work out as you expected? How big is the program that they can support?
Vicki A. Hollub - Occidental Petroleum Corp.:
I'll go ahead and let Ken take that. I think that Ken has modeled out some opportunities for growth, which really depends on what we find from the extension of our appraisal program. I think our capability is going to well exceed what will fit within our capital budgets, but I'm sure Ken is going to lobby for more. Ken, do you want to address that?
Kenneth Dillon - Occidental Petroleum Corp.:
I think that's a fair assessment. As you can see from one of the slides, we showed a number of wells in the inventory that is fairly substantial. Drilling Cluster 1 as soon as possible in Block 72 will open up that area very quickly. It's very close to our existing block; same with Block 65, close to Block 27. So I think we have to compete with Permian Resources, and I feel we've got the inventory to do so. So as Vicki said, we'll be coming along knocking on our door trying to drive the performance there.
Paul Y. Cheng - Barclays Capital, Inc.:
Ken, I think you guys mentioned that you're going to acquire more 3D seismic next year, so spending on the program will be pretty slow next year. So what kind of timeline – or is there any – maybe the benchmark that we can use or milestone we can use on how that progress?
Kenneth Dillon - Occidental Petroleum Corp.:
I think if you look at it that we have some existing 2D seismic over most of the areas, which we'll quickly reprocess. We also have some overlapping 3D seismic that other operators have shot in the area. So we're able to access those particularly around Cluster 1. Frankly, next year is appraisal, reprocessing, seismic, obtaining new 3D seismic, moderate to low drilling next year, and then the following year being in a position where we can expand the drilling program if we can obtain some capital. So a thoughtful disciplined approach, we want to add value to what are returns not only for us but for our partners and for the government also.
Paul Y. Cheng - Barclays Capital, Inc.:
So do you think that by the end of next year that you will have a much better idea on how big is the program that you could support from a resource standpoint?
Kenneth Dillon - Occidental Petroleum Corp.:
Absolutely, absolutely.
Paul Y. Cheng - Barclays Capital, Inc.:
And that in terms of the Permian, Vicki or Jeff, have you guys ever provided, say, by 2025, if we're going to maintain the same rig program as it is today, what kind of production that we may be talking about?
Vicki A. Hollub - Occidental Petroleum Corp.:
We know we have the capability to continue to grow the Resources business at pretty much the same CAGR we would see between now and 2022. Whether or not we do that really depends on the other international projects and opportunities. So I can tell you we have the capability, but whether that's what we're going to do would depend on what we see at that time.
Paul Y. Cheng - Barclays Capital, Inc.:
And will you be trying to maintain that, say, $5 billion to $5.5 billion over the next several years in terms of CapEx, or that will also be subject to change?
Vicki A. Hollub - Occidental Petroleum Corp.:
Our CapEx between now and 2022 we expect to be between $5 billion and $5.3 billion.
Paul Y. Cheng - Barclays Capital, Inc.:
Okay, thank you.
Cedric W. Burgher - Occidental Petroleum Corp.:
That of course assumes a $60 or better environment or call it $60. As we've said many times, prices are very volatile. And if it falls, we intend to keep our spending and our dividend within cash flow, and we can take that all the way down to $40 oil. And if that happens, the growth will moderate. But we intend to be disciplined to spending within cash flow.
Paul Y. Cheng - Barclays Capital, Inc.:
I understand. But I guess a lot of people are asking that if the prices end up staying substantially above the say $60 range, does that mean that you guys will also be looking at the opportunity to survey the growth, or Vicki already said that 2019 program is pretty dead set. So how about beyond 2019, if the commodity price environment is better, does that mean that you're going to spend more than the $5.3 billion, or that you're still going to stick to that program?
Cedric W. Burgher - Occidental Petroleum Corp.:
We've given a broad outline of how we would see things in a $60 environment further out. I think it's too early to speculate on wildly different price environments. I would say, certainly, like you've seen us already, in a price environment above $60, and we weren't that far above it this last quarter, we would certainly look to complement our spending with a much more substantial buyback program. But to go with a lot greater definition, I think it's just too early to do that today.
Paul Y. Cheng - Barclays Capital, Inc.:
Okay, thank you.
Operator:
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki A. Hollub - Occidental Petroleum Corp.:
I just want to say thank you all for your questions today. We're excited about where we're headed, and we'll continue to increase our opportunities and get better. So thank you all. Have a great day. Bye.
Operator:
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Jeff Alvarez - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Cedric W. Burgher - Occidental Petroleum Corp. Joseph C. Elliott - Occidental Petroleum Corp. Kenneth Dillon - Occidental Petroleum Corp.
Analysts:
Doug Leggate - Bank of America Merrill Lynch Paul Sankey - Mizuho Securities USA LLC Brian Singer - Goldman Sachs & Co. LLC Philip M. Gresh - JPMorgan Securities LLC Pavel S. Molchanov - Raymond James & Associates, Inc. Jason Gammel - Jefferies International Ltd. Roger D. Read - Wells Fargo Securities LLC Leo P. Mariani - NatAlliance Securities
Operator:
Good morning and welcome to the Occidental Petroleum Corporation second quarter 2018 earnings conference call. All participants will be in listen-only mode. Please note, this event is being recorded. I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Jeff Alvarez - Occidental Petroleum Corp.:
Thank you, Gary. Good morning, everyone, and thank you for participating in Occidental Petroleum's second quarter 2018 conference call. On the call with us today are
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Jeff, and good morning, everyone. During the call, we'll cover three key topics
Cedric W. Burgher - Occidental Petroleum Corp.:
Thank you, Vicki. I'll begin with commentary on the Midstream transaction and follow with our financial results and update to our 2018 guidance. Referring back to slide 8, we are divesting a package of domestic midstream assets for $2.6 billion that were not integral to our operations, which include the Centurion oil gathering system and long-haul pipeline, our southeast New Mexico oil gathering system, and the Ingleside export terminal. OXY is retaining its long-term flow assurance, its pipeline takeaway, and most of its export capacity through its retained marketing business. After the Ingleside export terminal expansion, we have secured the rights to market 450,000 barrels of oil per day through 2030, with options to extend for an additional seven years. The divested assets generated $180 million in EBITDA and required capital of $140 million during 2017. Our guidance for 2018 has been updated to reflect the transaction close at the end of the third quarter. As Vicki highlighted, we now expect to have an additional $5 billion of cash this year to allocate to increasing shareholder returns. We will deploy approximately 20% of the $5 billion in 2018 into our highest-returning organic opportunities, which will contribute an additional 17,000 barrels equivalent per day to Permian Resources in 2019. Approximately 80% of the $5 billion will go to opportunistic share repurchases and to strengthen the balance sheet. The share repurchase target has been set at more than $2 billion over the next 12 to 18 months. On slide 15, I'd like to start with our production results. Total reported production for the second quarter was 639,000 BOEs per day, coming in above the midpoint of our guidance. Adjusted for PSC impact, we would have come in at the top end of the production range we guided last quarter. This was driven by strong execution and well productivity in Permian Resources, which exceeded the top end of the guidance range by 3,000 BOEs per day, representing a year-over-year increase of 46%. Total international production came in at 281,000 BOEs per day, with Al Hosn, Dolphin, and Qatar all within our guidance. The increase in international production from the first quarter reflected the completed turnarounds at Al Hosn and Dolphin, partially offset by a decrease in production in Qatar due to its planned turnaround that was successfully completed. Earnings improved across all segments, with our second quarter reported and core EPS at $1.10 per diluted share. Results were adversely impacted by approximately $90 million or $0.12 per diluted share due to the timing of crude oil liftings in Oman and the non-cash mark-to-market impact on crude oil volumes. A typhoon in Oman delayed the lifting ships from June into July, and our growing crude oil export business is increasing our barrels in transit, and therefore our mark-to-market exposure has increased. The improvements in the Oil & Gas segment were mainly attributable to higher Permian Resources production and higher oil prices in our international operations, partially offset by lower international sales volumes due to the timing of the crude oil liftings in Oman. Second quarter realized oil prices increased by 3% from the prior quarter, and our DD&A rate for the second quarter was 9% lower than the average rate for 2017. Operating cash flow before working capital improved sequentially to nearly $2 billion. We spent $1.3 billion in capital during the quarter. Working capital changes for the second quarter mainly reflect the increase in crude oil inventories due to the timing of the international liftings and domestic export cargoes in transit. Chemicals core earnings of $317 million came in above our guidance of $300 million, primarily due to favorable product pricing across most product lines. Plant margins were also favorable, as ethylene costs were significantly lower than anticipated. Midstream core earnings of $250 million came in within guidance and reflected improved marketing margins due to an increase in the Midland-to-MEH differential from $3.12 to $7.86 quarter over quarter. Results included the aforementioned non-cash mark-to-market pre-tax loss of $67 million, which is due to rising oil prices and an increase in domestic export cargoes in transit. We declared an increase to the dividend in July and paid close to $600 million in dividends during the quarter. Total shareholder distributions approximated $700 million when considering the $73 million worth of share repurchases we made during the quarter. Slides 16 and 17 detail our updated guidance. We raised our total year production guidance from 650,000 to 664,000 BOEs per day. Excluding the impact of higher Brent price assumptions on PSCs, total year production guidance would be 655,000 to 669,000 BOEs per day. We increased Permian Resources production range by more than 3% to 207,000 to 215,000 BOEs per day, mainly attributable to the improved well productivity and an increase in well count. The midpoint of this range equates to an exit-to-exit Permian Resources production growth rate of 54%. Our international production range of 285,000 to 290,000 BOEs per day was adjusted lower for the PSC impacts of higher Brent prices, assumed at $75 per barrel for the remainder of the year, partially offset by improved production. We have increased our total year capital to $5 billion, with the majority of the increase allocated to Permian Resources. This is for high-return short-cycle projects that Jody will go into more detail in a minute. In Midstream, we expect the third quarter to generate pre-tax income between $600 million and $700 million, assuming a Midland-to-MEH spread of $15 to $17. On a full year, we expect pre-tax income to range between $1.650 billion and $1.850 billion based on a Midland-to-MEH spread range of $10.25 to $11.25. In Chemicals, we anticipate third quarter pre-tax earnings of $315 million, and total year guidance remains at $1.1 billion. Domestic operating expense per BOE of $12.80 was 4% lower than the prior quarter. Cash operating cost for the domestic Oil & Gas business are expected to continue to decline and average approximately $12.50 for 2018. We continue to forecast lower operating costs in Permian Resources for the second half of 2018, which are expected to average under $7 per BOE. We have updated our guidance for total company tax rate to 29% in 2018, which reflects higher earnings from our domestic businesses. On my last slide, we have provided you with key cash flow sensitivities. Our cash flow sensitivity to the Midland-to-MEH spread has not changed in the marketing business as we are retaining all of the previously secured Permian takeaway capacity. To close, we are very pleased with our performance so far this year, including the completion of our Breakeven Plan ahead of schedule. We have a tremendous opportunity in front of us, and we are working hard with a relentless focus on returns. I will now turn the call over to Jody.
Joseph C. Elliott - Occidental Petroleum Corp.:
Thank you, Cedric, and good morning, everyone. Today I'll provide an update on the industry-leading returns our Permian Resources assets are generating and details on how we will continue to invest in these projects to provide our shareholders with value-based growth. I'll start on slide 20 to highlight some of our achievements year to date. First, we achieved 213,000 BOE per day production in June which was above the 209,000 BOE per day breakeven target we set at the beginning of the year. We achieved the 80,000 BOE per day growth target six months earlier than planned through our step change in well productivity and steadfast execution. We continue to deliver record wells in our Greater Sand Dunes area and achieved an OXY record for the Texas Delaware, with the Lyda 13H delivering a peak 24-hour rate of almost 5,700 BOE per day and a 30-day rate of over 3,700 BOE per day. Our high-quality Permian Resources assets combined with our subsurface expertise are generating high double-digit full-cycle returns in many of the best wells in the Permian Basin. Our appraisal program is also delivering great results and continues to provide low breakeven inventory replenishment for sustainable high-return growth. Year to date, we've added 218 gross locations to our less than $50 WTI breakeven inventory and created additional value by increasing working interest and average lateral length through acreage trades. Our Permian Resources business is generating high full-cycle returns as we develop our assets in the most prolific areas of the Permian Basin. Our margins are protected through Aventine, our maintenance and logistics hub, and our Midstream business is ensuring we get maximum product realizations. We believe our Resources business is positioned to provide some of the highest-return growth in the industry. We're also generating excellent returns in our Permian EOR assets. We continued our progress at the Seminole-San Andres unit by lowering OpEx an additional $2 per BOE, for a total reduction of $7 per BOE since the acquisition. This $7 improvement is expected to generate over $400 million in NPV, which is two-thirds of the acquisition cost. In June we announced a feasibility study for a carbon capture, utilization, and storage project with White Energy. The project will capture carbon dioxide at White Energy's ethanol facilities in Hereford and Plainview, Texas and transport it to the Permian Basin for use and sequestration in our Permian EOR business. Our Permian EOR business provides us with a unique carbon emissions reduction opportunity that will also generate returns for our business. We look forward to advancing these important projects, and we'll update you as we move forward. On slide 21, we show the well performance results of our extended lateral program in our two core development areas and how both areas are outperforming other operators. In the second quarter, we continued our basin-leading results in the Greater Sand Dunes, with 32 Second Bone Spring wells online averaging 2,500 BOE per day over 30 days. Our wells in this area are generating industry-leading and are outperforming the average operator by 24% on a six-month cumulative production basis. Our Greater Sand Dunes area continues to generate great well results with multiple stack benches and will be a corner stone of our development for many years to come. In our Barilla Draw area, we're seeing similar improvements in 2018 and recently implemented a new well design that is delivering record results and lowering costs. Our 2017 Barilla Draw wells are outperforming the average operator by 26%, and our more recent wells are trending even better. We expect this gap to grow as we progress our subsurface characterization to optimize landing and continue to customize our well designs to ensure we are maximizing the net present value of each section developed. On slide 22, I'll provide details on how we're deploying additional capital into our high-return development areas. We began 2018 with an 11 operated rig plan that would achieve three primary goals
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Jody. As you can see, our business performance has put us in a remarkable position. We provide an industry-leading shareholder distribution yield through our dividend and buyback programs while delivering valuable long-term growth from incremental investment in high-return organic projects. We're committed to delivering this value proposition to our shareholders within cash flow. We've built a leading position in the Permian with the best wells, technology, excess takeaway capacity, export capabilities, and supply and services security. This combined with the outperformance of our other businesses is why we're so confident that our actions will enable us to extend our industry leadership and shareholder returns. We'll now open it up for questions.
Operator:
Our first question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. Good morning, everybody. Vicki, the market seems to be taking a fairly dim view of the increase in spending this morning, so I wanted to ask you. What's behind your decision to step up the pace? And I really want to think about it in the context of your peer group of similar size in terms of the Resource business because it would seem to us at least the pace of spending has been substantially lagging peers. It looks like you're catching up, but I'm just curious how you feel about the right investment pace and whether you would agree with that assessment.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Doug, for the question. The reality is and the way we do our business is we try to pace our developments so that we maximize net present value and return on capital employed. So as you guys have seen, we've had developments going on in certain areas. And for each development area, we build to ensure that we can maximize the value over the long term, which means that we don't build infrastructure for peak production. We build it for the life of the development area. We wanted to get to our Breakeven Plan to get to that milestone as quickly as we could. That was a key milestone for us, so we accelerated our pace to a level that we felt was the maximum before we started to destroy value. So the pace that we've been on up to this point was a pace that was driven by our commitment to return on capital employed. That's why we haven't gone faster getting to this Breakeven Plan. Now, however, we have some additional development areas which is driving the pace that we're going to increase to in the second half of this year. So rather than ramp down, we'll increase to ensure that we can cover these new development areas that Jody is going to talk about probably in a little more detail later. So the pace for us is always driven by ensuring we never get out in front of our technology, that we never go at too fast a pace, we never overbuild infrastructure, and that has always dictated our pace. And so we feel like that with lower capital than some of our peers, we've actually delivered more. And we've not only delivered more in terms of production in some cases, but also in terms of value, and we're going to continue to stay focused on value. Going forward, our additional development areas as they come into play, that could increase our capital as we go forward, but it's always going to be at a pace that maximizes returns. And you're right, not only about our Permian peers, but if you look at the companies that are operating that maybe don't even have Permian production, that have development in our areas, our total capital now, not only is our capital in the Permian Resources now more similar to our peers, but our capital overall is similar to our proxy peers that are of close size to us. So we think that we started the year a little bit under capital, but at the pace that we felt would maximize our returns.
Doug Leggate - Bank of America Merrill Lynch:
That's what I was getting at, thank you for that. I guess my follow-up then is really the impact on the philosophy of the business going forward because the growth in Permian has obviously been key to getting you back to breakeven, so has by definition been generating free cash flow. Do you expect the business at the new pace, the Permian Resources business specifically, to also continue to generate free cash flow under your updated commodity deck I guess? And if so, can you give us some idea how you see the exit-to-exit as you go into 2019? So exit 2018 going into exit 2019, what would you expect that growth pace to look like? And I'll leave it there, thanks.
Vicki A. Hollub - Occidental Petroleum Corp.:
We expect growth that would be similar to the activity level that you'll see in Permian Resources in the second half of this year, so the growth levels should be for our Permian Resources business probably in the high 30s.
Doug Leggate - Bank of America Merrill Lynch:
That's year-over-year or exit-to-exit?
Vicki A. Hollub - Occidental Petroleum Corp.:
That's year-over-year.
Doug Leggate - Bank of America Merrill Lynch:
And still free cash flow positive or no?
Vicki A. Hollub - Occidental Petroleum Corp.:
We should be free cash flow positive. I think it would be around 54% exit-to-exit.
Doug Leggate - Bank of America Merrill Lynch:
That's helpful, thanks very much. I appreciate it.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thanks.
Operator:
The next question comes from Paul Sankey with Mizuho Securities. Please go ahead.
Paul Sankey - Mizuho Securities USA LLC:
Hi, everyone. On the CapEx increase again, the magnitude is what surprised us. It really is a large number. Can you talk a little bit about how come we were not forewarned that you could make a move as big as this? Thanks.
Vicki A. Hollub - Occidental Petroleum Corp.:
One thing we were doing is watching commodity prices, watching the volatility around the world, and staying and getting pretty comfortable with the incremental development areas that we're going to expand into. So a lot of it is around ensuring that as we go into the second half that we'll still be able to see returns that are at least where we were and maybe in excess now, because we've done a lot of really good work. We feel comfortable with what we're doing. We've always talked about and tried to share with people that the plan we put together was based on a $50 plan. We actually start our planning process usually midyear, and then by December, we're ready to present it to the board. And as we were doing that last year, we were seeing $50, and it wasn't really until toward December or January that prices started to go up a bit. And so starting at that pace, we were, as I mentioned earlier, a bit under capital versus our peers. And then accelerating and getting to the Breakeven Plan early was driven by the efficiency improvements that we saw. So it was a combination of seeing the efficiency improvements, getting comfortable that we were going to be in a better than $60 environment for the full year, and gaining some confidence that 2019 is also going to be in a similar environment, because the reason for the ramp down, as we said, was to ensure that we always spend within cash flow. And so thinking that, when we prepared the plan at $50 that we didn't know what 2019 would look like, so we didn't want to go into 2019 at a higher pace and risk outspending cash flow because that is our commitment beyond the achievement of the Breakeven Plan.
Paul Sankey - Mizuho Securities USA LLC:
Okay. And then I guess the other thing that was different about 2018 versus initial expectations was the basin differentials. And I assume a large part of what you're doing here is to fill your own capacity, presumably to the detriment of your competitors. Is that the correct way of thinking about what you're planning to do?
Vicki A. Hollub - Occidental Petroleum Corp.:
That was not a driver for us. The driver really is to develop – to do the upstream development that delivers better than 75%. So first we plan based on what the development itself will deliver. Secondarily, we look at what's happening with the takeaway capacity. So we have, as you know, so much that we weren't really trying to fill it to move others out.
Paul Sankey - Mizuho Securities USA LLC:
Okay. And the final one, thank you, for me, would be in terms of you said you want to keep your CapEx and dividend covered by your cash flow. Can you just remind us what your aspiration is for cash return to shareholders because I think the other side here is that you could have done an awful lot more buyback? If you could, just talk about that balance. And I'll leave it there, thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
The reason that we want to buy back shares is we want to reduce our share count. We want to have the capability and capacity over time to grow our dividend in a more meaningful way, while at the same time we have to be conscious of the fact that investment in our Permian Resources business, our organic growth delivers better returns than the buybacks. So the buybacks really are specifically to help us with our dividend growth over time.
Paul Sankey - Mizuho Securities USA LLC:
Thank you.
Jeff Alvarez - Occidental Petroleum Corp.:
Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
The next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you, good morning.
Vicki A. Hollub - Occidental Petroleum Corp.:
Good morning.
Brian Singer - Goldman Sachs & Co. LLC:
As you've highlighted, the Delaware Basin well performance has been very strong over the last year. With the accelerated CapEx, you're now on the hook to deliver more growth. As you move into development mode, do you expect the level of well productivity we've seen the last couple of quarters to be sustained or improved, or do you see the impact of tighter spacing moderating those productivity gains? What do you see as the risk to the upside or the downside?
Joseph C. Elliott - Occidental Petroleum Corp.:
Hey, Brian. This is Jody. We see continued improvement in well performance. We continue to do more and more integration of seismic activity into our targeting and our well designs. We've got a new well design in the Texas Delaware area that's allowing us to both drill faster and complete in a more optimum way. So we expect the wells to continue to get better. With regard to spacing, we're probably more conservative than most in our spacing assumptions because we're so focused on returns and the net present value of each of these sections that we develop. And so we do a lot of modeling. We've done a lot of testing on spacing. So this isn't about downsizing and having parent/child interference issues. We take that into account and design for that as we go in. So hopefully, that answers your question, Brian.
Brian Singer - Goldman Sachs & Co. LLC:
It does, thanks. And then just going back a little bit to the capital allocation and then thinking even more strategically, two follow-ups. The first is you talked about your flexibility to pull back on CapEx in the event of unfavorable commodity prices. What, if anything, would you need to see to pull back to allocate more towards share repurchase? And then from a use of excess capital perspective, given that you're increasing activity in the Permian, does the potential increase to your decline rate increase your interest in low decline rate M&A or new projects on the EOR side?
Vicki A. Hollub - Occidental Petroleum Corp.:
Over time, we do want to pick up more conventional activity and projects. We actually have some of the incremental in our capital allocation is going to the Central Basin platform in EOR to drill horizontal wells and conventional reservoirs. So we'll do some things to work on mitigating the decline of the Permian Resources business. Some of our work in international, which I'll let Ken describe here in a minute, is also going to address that same thing. So we'll let Ken address that, and then we'll come back to the share buyback issue.
Kenneth Dillon - Occidental Petroleum Corp.:
As I mentioned in a previous call, one of the projects we're working on is the Teca steam flood in Colombia. So far, the pilot appraisal is performing above expectations, and it's a classical OXY international project implementing EOR techniques to an existing field discovered in 1963. We expect the green light before year end and expect to reach 30,000 barrels a day gross in Phase 1. Initial response shows wells going from 6 barrels a day to 58 barrels a day with the impact of the steam flood.
Cedric W. Burgher - Occidental Petroleum Corp.:
Brian, this is Cedric. I'm going to chime in for a second on the buyback. We're excited to be re-engaging in a more meaningful way with respect to the buyback. As you know, we have a long history of doing that, took a hiatus during the downturn, but we're excited to be in a position to do that. We've put out there $2 billion-plus as a target over the next 12 to 18 months. As we've said before, we like an opportunistic approach, so we're looking at value and we're looking at returns. We've got good models that we think, certainly not perfect stock pickers, but we like the idea of choosing the timing of when we invest in our stock. We think we have a good track record there, and we look forward to deploying some capital there. And as you know, the numbers we've given you don't add up to the $5 billion. We've got a lot that we're able to put on the balance sheet. We do want to keep a strong balance sheet. However, that also gives us more flexibility to go beyond the $2 billion over time should we choose, but we're going to pace ourselves. Maybe days like today are going to give us a good opportunity to be in the market buying our shares, and we look forward to doing that.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you.
Operator:
The next question comes from Phil Gresh with JPMorgan. Please go ahead
Philip M. Gresh - JPMorgan Securities LLC:
Yes, good morning. So first question is just a bit of a follow-up. Vicki, you talked about the Permian Resources growth rate for 2019. As we think about this step-function change and the spending to the $5 billion level not just this year but also next year, maybe you could just refresh us on how you think that will drive the overall company growth not just in 2019 but also beyond.
Vicki A. Hollub - Occidental Petroleum Corp.:
In 2019, we expect to exceed the growth rate we're seeing this year with a strong program. That's assuming that commodity prices stay where they are today. The slide that we have in the deck is not telling you that that's exactly what we'll do in 2019. But if we see the same market situation and all other things are similar, then we could spend in a $60 environment between $5 billion and $5.3 billion. We expect that would deliver a better growth rate than what we're seeing this year overall for the corporation. I think we're going to see healthy growth beyond that as well because of what we see in the Permian Basin. Having the inventory that we do, we've recently signaled that we do expect to be able to grow better than the 8% on average on an annual basis. So you could start to model out what you'll see next year from that sort of program, and going forward would be better than 8%.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, thanks. Second question is for Cedric. With this asset sale, if you could, just refresh us on the use of the NOLs and the impact it will have on you being a U.S. cash taxpayer. I think you're not expecting to for a couple of years. And if you could, just comment on whether you see additional assets that you would consider monetizing at this point. Or should we think that this is the majority of what you're looking to monetize?
Cedric W. Burgher - Occidental Petroleum Corp.:
Okay, sure. On the tax, we do expect to gain. We'll have more on that. Of course, it's expected to close in the third quarter and we've got some things to finalize there to get a precise amount. But if you look at our 10-Q, you can see assets held for sale, it's predominantly the Midstream assets. It's not exact, but it's close if you're just trying to get ballpark. But we're going to have – we have continued NOLs or tax attributes we can use to offset the gain, and we won't be in a cash tax position for some time, as you correctly stated. Our effective rate also, we've outlined that in my earlier remarks, but expect it to be in the back half of the year in the high 20s. And over time, we would expect to use up those tax attributes and then go to a cash tax position, but it still looks like it's going to be several years out. It obviously depends on commodity prices and a lot of other variables. In terms of other assets for sale, we're always looking to refine our portfolio, but we don't have any new news for you. We've given you the news of the day. And I'd say at this point, we have a really good core business on all the verticals that you can look at. And we're reinvesting in that and think we can grow within the business that we have.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, I guess my last question would just be on the buyback commitment. If we move to a lower price environment, and I know you've talked about the flexibility on capital spending to pull back. But if we move to a lower price environment, is there a strong commitment that either way we should expect the $2 billion of buybacks over the next 12 to 18 months? I know it's opportunistic, but it's also the flywheel. I'm just looking at slide 27, and it feels like it's the flywheel, so just any color on that. Thanks.
Cedric W. Burgher - Occidental Petroleum Corp.:
So obviously a lower price environment is, especially if that means lower share price environment, I certainly like the idea of investing our capital then. That's really what we're thinking about. If it's a lower commodity price environment, obviously those two tend to track together somewhat. But on a lower commodity price, we have, as Vicki mentioned, the ability to ramp down, and our plan works at $40. We think that is the answer for the industry. You need to be a low-cost producer, and I think very few can make those statements. But at $40-plus, we can ramp down within a six-month plus or minus time period and be within cash flow. So really, now that we've achieved that Breakeven Plan, we're in a position to balance our spending within cash flow pretty much at any commodity price. And then so the excess cash we're seeing for this year is really what we're targeting for reinvestment in shares, that $2 billion or so. That's cash that's not in the bank today but it's darn close. Beyond that, talking about a lower price environment, we've got that flexibility to make those share repurchases in a lower price environment.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, thank you.
Operator:
The next question comes from Pavel Molchanov with Raymond James. Please go ahead.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Thanks for taking the question. We've talked a lot about the buyback on this call. Let me ask about the dividend. One of the charts on the slides highlights the long-term 12% dividend growth. But obviously of late, it's been nowhere near that, only low single digits in recent years. Is that because implicitly you're saying the yield is high enough on the stock as it is, or what's the reason for the very slow upticks?
Vicki A. Hollub - Occidental Petroleum Corp.:
What we're trying to do is drive toward increasing our cash flow so we can increase our dividend. Currently, the payout ratio is still at a higher level than what we've seen historically. So part of the reason for ensuring that we increase our cash flow, increase our return on capital employed, is to continue to build on our value proposition and make sure that we strengthen all aspects of that. As I said earlier, getting to the breakeven milestone – breakeven and neutral milestones really were to get us to a point where we can do exactly what we're doing now, further strengthen not only the balance sheet but our cash flow, our returns. And through doing that, we think that we could then start to grow the dividend again. We don't want to get to a payout ratio that gets us away from being able to be cash flow neutral at $40 and breakeven at $50. So that's really the parameters that are driving what we do with it. So buying back shares, increasing cash flow gives us the ability to start growing it more than we've done over the last few years.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Okay, one more about the Permian. You've talked about having or maintaining the liquids midstream access that you will need. What about natural gas? We hear more and more about the risk of flaring having to run up against the regulatory limits in the Permian. Is that an issue on any portion of your acreage today, gas bottlenecks?
Vicki A. Hollub - Occidental Petroleum Corp.:
No, we don't feel like it's an issue. We currently are getting all of our gas out. We occasionally have short-term bottlenecks, as the industry has faced in the Permian. The way we've addressed that in the past, though, is with the enterprise 50:50 joint venture plant construction that we had a few years ago. When we see that there are going to be long-term issues for us, what we'll do is we have the capability – retained the capability to build infrastructure or to partner with others to ensure that the infrastructure is installed to be able to manage all of our products, so not just oil but gas and NGLs as well.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
All right, I appreciate it.
Operator:
The next question comes from Jason Gammel with Jefferies. Please go ahead.
Jason Gammel - Jefferies International Ltd.:
Thank you very much. I just wanted to ask about your firm transportation, which obviously extends pretty far into the future. We're in a period now where differentials are blowing out a bit. So I guess the question is twofold. Would you have any interest in potentially terming that out, the firm transportation out with another party, maybe at a level that is lower than differentials today but that would extend for a multiyear period to turn it into an annuity? And then I suppose are you being approached by other parties for that type of arrangement?
Vicki A. Hollub - Occidental Petroleum Corp.:
We've done a little bit of that. And what we try to do is balance a little bit of long-term to ensure that we can manage the downside risk. But we also feel that over the long term, we want to keep some of that flexible so that we can take advantage of periods like this where the differentials are high. We think we're going to continue to see cycles where both situations will exist, where we'll reap strong benefits as we're doing now, but there will also be times when we see the other side of that. So we have put together some contracts during this period that will protect us on the downside but without value destruction.
Jason Gammel - Jefferies International Ltd.:
Okay, great, and then if I could ask a second one please. You've highlighted two new areas within the Permian that you've been delineating. I was hoping you could just provide a little more detail on the Barilla Draw Hoban bench and also on New Mexico Red Tank just in terms of prospectivity, potential drilling locations, et cetera.
Joseph C. Elliott - Occidental Petroleum Corp.:
Jason, this is Jody. Both of those areas we're seeing really positive results. The Hoban is associated with the Wolfcamp A. We've done a lot of delineation work, seismic work to understand is that one big thick area that we can prosecute with a single well in a large frac, or do we need to put two wells and two different flow units and then optimize the frac to that. So what we're seeing, very good results, and I think it will add inventory in that area. In New Mexico, I think there's even a stronger story in the Red Tank/Lost Tank area. That's proximal to a few wells that here recently in the Permian are probably the largest that have been drilled. We see multiple benches. We've had some appraisal wells drilled there. We're very encouraged both in the Sand Dunes proper area. And in Red Tank/Lost Tank, we see continued improvement in Tier 1, both the quality of the existing wells that are in the inventory and adding more inventory. So we're very excited about that. In that capital spend increase that we talked about, about $400 million this year of the $900 million is going toward that kind of activity. That activity is the portion that will generate most of the production increase starting in – showing up in 2019 of approximately 17,000 barrels a day.
Jason Gammel - Jefferies International Ltd.:
That's great. Thanks, Jody.
Operator:
The next question comes from Roger Read with Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Good morning, thanks. Maybe to follow up on Pavel's question about ultimate dividend growth, do you have, Vicki, an idea, or Cedric, of maybe where production needs to be to support dividend growth? And let's just say assuming recent or current oil prices as the paradigm there.
Vicki A. Hollub - Occidental Petroleum Corp.:
I'll start out and let Cedric finish it. But it really goes back to basing it around being cash flow breakeven at $50 and cash flow neutral at $40. As we continue to grow our cash flow through increased production, we will be able to start to lower those breakeven and neutral points. As we start to lower those and buy back shares, that gives us the capacity to continue to grow the dividend. We've looked at that, and that's part of the reason for what we're doing today and where we're trying to head, but it's going to be dictated by that and can be modeled.
Cedric W. Burgher - Occidental Petroleum Corp.:
The other thing I'd mention on that, Roger, is on slide 13, which we've talked about, we put on there the dividend payout ratio in those little boxes above the bars, and it just shows a couple of things. One is we aren't where we were historically, well below 20%. And so, however, it also shows how much progress we've made in just the last year or so, so it's doing everything that we've talked about. It's focusing on returns. That trumps everything. But by doing that, you're allowing yourself to grow and grow your coverage ratio, improve your payout ratio. And so we don't have an exact number. We're not going to put ourselves in a box that way. We'd love to degree the dividend. We do grow it; we grow it every year. It's just at a modest rate in the last few years. We look forward to growing it more meaningfully, as we've done in the past. But the buybacks will help on that as will reinvesting at high returns. And the combination over time will get that payout ratio more like it has been in the past, and that will set us up for more meaningful dividend growth.
Roger D. Read - Wells Fargo Securities LLC:
Okay, that's helpful. Thanks. And then, Jody, if I could change direction to you, you mentioned as part of the CapEx increase some of the efficiencies that you've recognized this year. Can you give us an idea of maybe some of the things specifically you've seen in the way of efficiencies and how those are carrying along? I'm thinking not just on the drilling side, but well completions and maybe the impacts of Aventine at this point.
Joseph C. Elliott - Occidental Petroleum Corp.:
Aventine is a big part of this. We went live with Aventine earlier in the year. We have probably about 50% penetration of the sand and the sand delivery systems in our business, so there's still more opportunity to improve the other frac cores that are operating. Schlumberger finishes their facility end of September or early October, so we'll begin taking full advantage of that relationship on multiple product lines. On the drilling side, there's slide 36 in the back that talks about our feet-per-day improvements from 2017 to 2018. So just a couple of facts on Aventine, we've moved 230,000 tons of sand through there since we've started, but it's also helped us with ensuring we've got supply, so it's both cost and supply. The sand delivery system, Sandstorm that we talk about, has really had a big impact on trucking. The sand system hauls more sand per truck. We've avoided 450,000 miles already of trucking. So you think about the tightness in labor, that really helps in that area. The amount of time it takes to unload sand when your location has been reduced by 50%, and again, we still have more cores that will take advantage of this system as we finish out the year. So we're real excited about how not just Aventine but the work our drilling and completion engineers are doing to optimize wells, and the process will continue to drive efficiency. And any inflation or tariff impacts, those kinds of things get offset with this efficiency improvement.
Roger D. Read - Wells Fargo Securities LLC:
Nothing quite like tariffs, maybe a very specific question on the productivity. There was another company that doesn't operate in the Permian but mentioned on their call earlier that the amount of stages they were getting done on a daily basis were running ahead of their budget. And I was just curious in the Permian relative to budget on stage completions per day or per well if you were seeing an improvement in productivity there.
Joseph C. Elliott - Occidental Petroleum Corp.:
I think we highlighted one of the cores in New Mexico pumped 240 stages in a month, so we are seeing that improvement. Again, when you look back at the capital increase we're talking about, if you go through slide 22, some of that additional spending is exactly what you're talking about. We've improved time-to-market. We're getting more done with the same resources. That just brings capital forward. So we are seeing that kind of impact. And if you spend some time on that slide, you'll see that there are positive things that are driving the increased capital, more working interest, better time-to-market. And so it's really a cash return on capital employed accretive activity by spending this additional capital in Permian Resources.
Roger D. Read - Wells Fargo Securities LLC:
I appreciate that. I was just going to try to get you to draw it out between budget and actual, but we've got to try what we've got to try.
Operator:
The next question comes from Leo Mariani with NatAlliance Securities. Please go ahead.
Leo P. Mariani - NatAlliance Securities:
Hey, guys. I was hoping you could add a little bit of color around the new well design. You guys mentioned in the Texas Delaware. I was just trying to get a sense of some of the moving pieces here. Does this add a little bit of cost, but maybe just give you a much better result in terms of productivity? What can you tell us about that?
Joseph C. Elliott - Occidental Petroleum Corp.:
Leo, the simple answer is it's a tapered well design. But I won't go into a whole lot of specifics there, but it allows us to drill faster, run pipe faster, complete the well faster, have larger flowback in artificial lift equipment, which improves drawdown over the life of the well, but it's framed around a tapered production string design.
Leo P. Mariani - NatAlliance Securities:
Okay, that's helpful. And I guess just back to the Midstream divestiture here, I'm just trying to get a sense of what you guys saw out there on the market. Did you guys view this as an opportunistic time to go out and sell these assets here? Did you just feel like it was the right time where it was a seller's market where folks were looking for export infrastructure and Permian infrastructure? I'm just trying to get a sense of the dynamics of the deal.
Vicki A. Hollub - Occidental Petroleum Corp.:
The Centurion pipeline and the Ingleside export terminal, Southeast New Mexico gathering system, we've never considered those necessarily to be core to our business. We just need the capacity on those. Similar to what we did with BridgeTex a few years ago, we partnered with Magellan to build the BridgeTex line. Prior to that, differentials were going up to $10. We did that to ensure that we could manage the differentials back down. We didn't need to own the line to get the benefit of it, but we had to help build it to make sure it happened. We've done that in some of our international locations as well to build pipelines to ensure we could get our products to market. We've really never felt that we had to own Centurion or the export terminal. We happened into an opportunity where it was a win-win for us and the buyers. The buyers get quality assets that deliver solid returns. We get cash flow that we can now use to get even better returns for our upstream business and to buy back some shares. So it was opportunistic in that there was a buyer that had a need and got that, and we had the opportunity to do something that can help us to achieve our goals on both ends, organic growth and buybacks.
Leo P. Mariani - NatAlliance Securities:
Okay, so it sounds like just the bottom line is that getting the 75% full-cycle returns of the wells is just a far better use of capital. Is that just the simple way to think about it?
Vicki A. Hollub - Occidental Petroleum Corp.:
It is. Those returns are – they're certainly the best in our business. We do have some international projects that compete with that as well, and that's why we're doing some of those. But the returns we're getting in the Permian, especially with the way the teams have increased efficiencies and increased well productivity, this is just an opportunity to get and to rebuild our return on capital employed back to the point where we're a leader in that.
Leo P. Mariani - NatAlliance Securities:
Okay, thanks.
Operator:
This concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki A. Hollub - Occidental Petroleum Corp.:
I just wanted to build on the last question because of the fact that I think it's critically important for people to know where we've been, the path we've been on, and why we're doing what we do, that this all ties together. I won't repeat our story again about our portfolio optimization. But back in 2013, we had a really good history of delivering return on capital employed. From 2008 to 2013, we averaged close to 15%. That was the third best in our proxy peer group and the only two that beat us were major oil companies. There were no E&P companies that were beating the returns we were getting. We saw that we had some projects in our portfolio that could never meet our metrics, so we made the decision that, since it was a part of our value proposition, very important to us, the key metric that we use, we started the process of optimizing that portfolio, exiting those, and focusing on the Permian Resources business, which we had begun to realize was of a huge scale, high-quality, high-return projects. So we exited 40% of our production from 2013 to 2015. And to rebuild that cash flow that we lost from those lower-margin lower-return projects, we depended on the Permian Resources business to do that. It has done that. It's gotten us to what we consider to be just the first milestone; that is, the cash flow neutrality at $40 and breakeven at $50. We went at a pace that we felt was appropriate to maximize return on capital employed as we were doing that and replacing our cash flow. That worked out well for us. But to get it really where we need it to be, this is the next phase. The next phase is this year's capital program is a key part of getting us to where we need to be. Going into 2019, if market conditions are similar, we'll have a similar program. That will get us back in a leadership role. We will then be able to, I believe, exceed what any of our peers are doing, and that's what this is all about. It has nothing to do with price. It's back to our value proposition. It's back to ensuring that ultimately by focusing our return on capital employed, we can grow our cash flow, value-adding cash flow, and that we can then begin to grow our dividend again in a more meaningful way. This all fits together. It's all about the value proposition. And this is an opportunity that we have worked hard for the last five years to get to. We're there now and we're ready to execute on it, and it's an opportunity that we just can't miss. And I think for our shareholders, it's certainly the right thing to do. And I appreciate all your questions today to help us get our story out, and we'll be talking with all of you over the next month or so, and then we'll see you at Barclays. So I very much appreciate it. Thank you, bye.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Richard A. Jackson - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Cedric W. Burgher - Occidental Petroleum Corp. Joseph C. Elliott - Occidental Petroleum Corp.
Analysts:
Brian Singer - Goldman Sachs & Co. LLC Guy Baber - Simmons Piper Jaffray & Co. Philip M. Gresh - JPMorgan Securities LLC Doug Leggate - Bank of America Merrill Lynch Leo P. Mariani - NatAlliance Securities LLC Robert Scott Morris - Citigroup Global Markets, Inc. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Muhammed Ghulam - Raymond James & Associates, Inc. Roger D. Read - Wells Fargo Securities LLC Jason Gammel - Jefferies International Ltd. Michael Anthony Hall - Heikkinen Energy Advisors LLC
Operator:
Good morning and welcome to the Occidental Petroleum Corporation first quarter 2018 earnings conference call. All participants will be in listen-only mode. Please note, this event is being recorded. I would now like to turn the conference over to Richard Jackson, Vice President, Investor Relations. Please go ahead.
Richard A. Jackson - Occidental Petroleum Corp.:
Thank you, Kate. Good morning, everyone, and thank you for participating in Occidental Petroleum's first quarter 2018 conference call. On the call with us today are
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Richard, and good morning, everyone. Our first quarter key highlights demonstrate the significant progress we made to increase the value of our business while delivering free cash flow and value-based growth. Our low oil price Breakeven Plan will be achieved in the third quarter, six months ahead of our original estimate. This accelerated schedule has been driven in part by better than expected performance from Permian Resources, which added 18,000 BOE per day this quarter, and is currently on a trajectory to deliver a 47% year-over-year growth rate. This will be accomplished with only 11 operated rigs. We're truly doing more with less, as we demonstrated by our increased guidance in all business segments. It is important to note that our Breakeven Plan not only provides us with the ability to continue value growth in a low price environment, it delivers significant upside in a higher oil price environment. Slide 8 illustrates how leveraged our Permian EOR business is to higher oil prices. EOR will generate significant incremental cash flow in the prevailing environment. Similarly, Chemicals and Midstream have been positioned for long-term value creation and are capitalizing on today's pricing and marketing spreads to generate substantial improvements in free cash flow versus our Breakeven Plan. We have increased our full-year guidance for these two businesses, and they're actually capable of generating over $2 billion of annual free cash flow. As we did last year, we will continue to focus on enhancing our portfolio, increasing the value of our assets, and using technology to drive superior operational performance. On slide 5, I'd like to point out a few important Permian Resources achievements during the first quarter. First, we continued to bring wells online at basin-leading rates in Greater Sand Dunes, with an average 30-day IP of 31 BOE per day. We also increased new well performance by nearly 50% in our current Barilla Draw development area. Third, to support our growth in the region, we brought online our logistics and supply hub, Project Aventine. We have already started to see the benefits of our differentiated approach in well cost improvement and reliability of well site resources. Turning to slide 6, our value proposition has not changed; it is enhanced. The achievement of our Breakeven Plan strengthens our ability to provide a meaningful dividend with growth while maintaining a strong balance sheet, and will allow us to resume opportunistic share repurchases. The part of our value proposition that we have significantly enhanced is our ability to exceed our oil and gas production growth targets with industry-leading returns. The quality of our assets and the depth of our development inventory will enable us to deliver higher returns and higher growth rates within our cash flow from operations. We believe our meaningful dividend with a production growth rate greater than 8% is a unique value proposition within our industry. My last slide, 7, illustrates the differentiated approach OXY takes in developing our assets. Across our businesses, we are focused on long-term value creation through exceptional technical work, life cycle planning, project execution, and operations focused on maximizing margins. In our Oil and Gas segment, our goal is to get the most oil out of our rock in the fastest time, at the lowest cost, and to sell at the highest price. This means we start by understanding the potential of the reservoir through enhanced subsurface characterization. This is not only critical to producing the best wells under primary development, but also under future EOR applications. To ensure the best time-to-market and service costs, we have developed operational capability and technology, created strategic logistic networks and relationships, and built key infrastructure, including our Ingleside oil terminal to access world refining markets. As a result, we believe we are the best-positioned company in the Permian to execute on the value-added growth strategy. The benefits of our strategy are yielding significant productivity improvements, increased capital efficiency, and better product price realizations. We expect our differentiated approach to result in peer-leading value creation. I'll now turn the call over to Cedric to review our progress towards the Breakeven Plan and our financial results.
Cedric W. Burgher - Occidental Petroleum Corp.:
Thanks, Vicki. I will begin with an update on our Breakeven Plan and then address financial results and 2018 guidance. On slide 10, we have updated our progress towards our Breakeven Plan at low oil prices. We continue to make substantial progress on our plan and are exceeding targets across our businesses. In an effort to be conservative on sustainable cash flow, we adjusted our first quarter cash flow from operations for a positive seasonality and market-related items in Midstream and Chemicals net of turnarounds in the Middle East, which is represented by the gray bar. Once we achieve our remaining milestones, we will be well-positioned in the future with the cash flow necessary for our $40 oil price business sustainability and $50 oil price business growth scenarios. But we will continue to operate our business to reduce those breakevens even further. Slide 11 illustrates our progress towards the Breakeven Plan. In the Chemicals business, the 4CPe plant began contributing to cash flow and will achieve peak operating rate in the third quarter of this year. We categorized additional chemical product pricing improvement as seasonal in the gray bar of other improvements to maintain conservatism in our plan. In the Midstream business, the Midland to Gulf Coast spread for the first quarter came within our guidance at $3.12 per barrel. Additional Midstream margin improvements for crude export, gas processing, and crude inventory sales were categorized as seasonal in the gray bar of other improvements. We also had planned turnarounds in the Middle East which reduced quarterly cash flow but will be back to normal rates in the second quarter of this year. In the Permian Resources business, we grew 18,000 BOE a day sequentially, leaving 32,000 BOE a day to achieve our Breakeven Plan goal. Jody will give additional guidance on the timing of new wells online and production. Shifting to our quarterly financial and operating results on slide 13, I'd like to start with our production results. Total reported production for the first quarter was 609,000 BOEs a day, which exceeded the high end of our guidance of 603,000 BOEs a day. Much of this was driven by execution and well productivity in Permian Resources, which came in well above the high end of guidance at 177,000 BOEs a day. International also contributed to the production beat, with our planned first quarter turnarounds at Al Hosn and Dolphin ahead of schedule and successful step-out wells in Colombia. Total international production came in at 273,000 BOEs a day, above the high end of guidance of 271,000 BOEs a day, even after 2,000 BOEs a day of production impacts from production-sharing contracts. Earnings improved across all segments, and our first quarter reported and core EPS was $0.92 per share. Improvements in the Oil and Gas segment were mainly attributed to higher oil prices and lower DD&A rates. Realized oil prices increased by 14%, and our DD&A rate for the first quarter was 10% lower than the average 2017 DD&A rate. Operating cash flow before working capital improved sequentially to nearly $1.7 billion, due to higher oil prices along with higher Permian Resources production as well as higher contributions from the Chemicals and Midstream segments. We spent $1 billion in capital during the first quarter, in line with our full-year capital plan of $3.9 billion. We issued $1 billion in debt to retire $500 million of notes that were due in February and for general corporate purposes. Working capital changes included cash payments typical of the first quarter, including property tax and payments against our fourth quarter accruals. Our Chemicals and Marketing businesses also experienced a working capital draw, as a result of a receivable build due to higher prices and volumes. Chemicals first quarter core earnings of $298 million came in above guidance of $250 million. Pricing for caustic soda and other products continued to increase, as global demand remained robust and purchased ethylene prices declined throughout the quarter. Midstream first quarter core earnings of $179 million also came in well above our guidance. Included is a gain on the sale of a domestic gas plant for $43 million. Excluding the gain, Midstream reflected improved earnings from crude exports, gas processing, and higher equity income from the Plains All American investment. The better than expected result also included income from items considered timing-related such as crude inventory sales. Our updated guidance is provided on slide 15. With respect to full-year 2018, we raised our total production range in spite of a negative production-sharing contract impact of about 5,000 BOEs a day since our first quarter guidance. The increase to the Permian Resources production range was mainly attributable to improved new well productivity. Jody will give additional detail on the outlook for our Permian Resources business. International production is expected to benefit from Al Hosn volumes ramping back up to average 66,000 to 69,000 BOEs a day during the second quarter and 83,000 BOEs a day in the third quarter. Qatar will have planned downtime during the second quarter, which we expect to impact production by approximately 6,000 BOEs a day. Our guidance now assumes $63 WTI and $67 Brent prices for the second through fourth quarters. The guidance for the total year capital budget is maintained at $3.9 billion. In Midstream, our improved second quarter and full-year guidance reflects the significant increases in Permian to Gulf Coast spreads. In Chemicals, our guidance increases primarily are due to higher caustic soda prices, and we now assume that they remain at current levels. Our DD&A expense for the Oil and Gas is lower as a result of lower finding and development costs last year. First quarter domestic operating expense was up slightly over last quarter due to front-end loaded workover and maintenance activities in Permian EOR. Lower operating costs in Permian Resources, which are forecasted to average under $7 per BOE, are expected to be offset by higher costs in Permian EOR for oil price-sensitive purchased injectant and higher energy-related costs. We have updated our guidance for the total company effective tax rate to 32% in 2018, which reflects higher earnings from our domestic Oil and Gas business. To close, we are off to a great start to the year, and we expect to reach a major milestone with the achievement of the Breakeven Plan in the third quarter. We are significantly ahead of schedule right now and will evaluate opportunistic uses of excess cash flow that we expect to be generated in the remainder of the year. These could include sustaining current activity levels in Permian Resources, improving our balance sheet through net debt reduction, and more investment in international and Permian EOR. Last and certainly not least, we now intend to resume our longstanding share repurchase program this year. As a reminder, we have approximately 64 million shares remaining in our buyback program authorized by our Board of Directors. Since the inception of the program, we have repurchased approximately 121 million shares for nearly $9 billion. I'll now turn the call over to Jody.
Joseph C. Elliott - Occidental Petroleum Corp.:
Thank you, Cedric, and good morning, everyone. Today I'll provide an update on the continued improvements in our Permian operations and the progress we've made in delivering high-margin production growth to contribute to our Breakeven Plan. 2018 is off to a great start. Our value-based development approach continues to deliver record wells, and operational improvements are lowering cost and reducing time to market. On slide 18, you'll see that our Permian Resources New Mexico team delivered another quarter of play-leading results. We turned 16 new Greater Sand Dunes wells to production that averaged 30-day rates of 3,100 BOE per day, which is in line with the step change in productivity that began in the second half of 2017. I also want to highlight a two-well pad in the Wolfcamp XY bench that delivered an average 30-day peak rate over 10,000 BOE per day. As shown on slide 50 in the appendix, many of these record wells in New Mexico were stimulated with significantly less proppant than the industry average, which results in lower well costs and higher full-cycle value. We continue to integrate our vast seismic data with improved geomechanic and petrophysical analysis that enable us to land the wells in the best part of the rock and stimulate the rock with a customized frac. Our customized stimulation designs rely on our subsurface characterization workflows and data analytics to balance well productivity with incremental cost, ensuring we're developing each section for maximum value. Lastly in New Mexico, we continue to appraise and delineate our acreage across Greater Sand Dunes. We delivered one Second and one Third Bone Spring appraisal well in a field called Red Tank in the northern part of Greater Sand Dunes, which delivered an average 30-day peak rate of 2,300 BOE per day per well. We're excited about these results, as they provide additional low-breakeven inventory for future growth. On slide 19, we've updated our Permian Resources quarterly production guidance and increased the midpoint for total year by 2,000 BOE per day. Production in the first quarter of 177,000 BOE per day was above the high-end guidance, which was driven by better than expected well results in Greater Sand Dunes and Greater Barilla Draw and less downtime than expected from artificial lift installations on many new wells. Many of the artificial lift installations scheduled for the first quarter were delayed to the second quarter, as pressure in the new wells remained high and were able to flow longer without intervention. We expect to install lift on these wells in the second quarter, and the associated downtime is included in our production guidance. Turning to slide 20, I'll provide an update on Aventine, our maintenance and logistics hub located in southeast New Mexico. Since this one-of-a-kind facility the Permian began operations in February, we have received sand from 14 separate unit trains and supplied sand for 31 completions across Texas and New Mexico. In March, the Oil Country Tubular Goods part of the facility became operational and has since received approximately 1,400 tons of pipe, with over 1,000 tons delivered by rail. We also began servicing wells with the new Sandstorm system, which has reduced the number of trucks required to supply sand to the well site and reduced the amount of time each truck takes to unload. While the facility has started providing cost savings for our new wells, it also plays an important role in ensuring we can execute our plan. As activity has ramped up, we've been able to avoid logistics and supply problems by servicing our wells from Aventine. We expect this facility will be fully operational by the end of the third quarter, providing a competitive advantage for us in the Permian. Finally, on slide 22, we're delivering operational execution improvements that are reducing the costs of our wells and accelerating production by reducing time to market. We've increased drilled feet per day 23% in New Mexico and 17% in Texas since the first half of 2017. These efficiencies are a result of better well designs and improved well site operations from our proprietary OXY drilling dynamics. We've also seen improvements in our completions in New Mexico, where we achieved a 19% improvement in stages pumped per day compared to the first half of 2017. These first quarter improvements demonstrate our strong executional capabilities and provide a foundation for us to bring online the wells we forecasted for the year with the potential for upside. 2018 will be a great year for our domestic assets. Our Permian EOR business will continue to generate significant free cash flow while finding innovative ways to operate mature fields at lower cost. Permian Resources is growing high-margin production at the lowest capital intensity level in its history and providing cash flow for long-term sustainability. And thanks to investment in our Midstream business, we're positioned to maximize price realizations with oil and gas transportation agreements to the Gulf Coast, with volumes in excess of our current equity production. Lastly, we're also continuing to build future opportunities by advancing our understanding of EOR in unconventional rocks and will provide updates in future calls. I'll now turn the call over to Vicki.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Jody. I'd like to close by congratulating two members of our team on role changes. Richard Jackson will be moving into Jody's team to lead our operations support groups. Richard has been an incredible asset for the Investor Relations team and will continue to be actively involved with our IR activity. He has done an incredible job to change our communication and sharing our story with our investors and shareholders. Replacing Richard as VP of Investor Relations is Jeff Alvarez. Jeff most recently led the Permian Resources Texas/Delaware business unit as President and General Manager. Jeff's extensive international and domestic experience has prepared him to be our investment community spokesperson. Richard and Jeff have a long working history together and will be transitioning over the next few months. We'll now open it up for questions.
Operator:
We will now begin the question-and-answer session. The first question is from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you, good morning, and congratulations to Richard and Jeff. Vicki, share repurchases have not been vocally high in the pecking order for use of free cash. Can you talk to how you and the board will determine the magnitude and the timing of share repurchase and whether you view repurchases as more temporary to deploy excess free cash flow from above mid-cycle margins in Midstream and PetChem versus something more ongoing as an augmentation to OXY's dividend?
Vicki A. Hollub - Occidental Petroleum Corp.:
It's important to note that historically, we've always had a very active share buyback program. And as Cedric mentioned, from 2005 to 2015, we had bought back about $9 billion in shares. That's while we were paying a dividend over that time period of about $17 billion. That dividend that we paid over that time period had a CAGR of almost 14%. So even though we pay a healthy dividend, share buybacks are a part of our cash flow priorities. And in fact, in our last presentation on slide 6 for the last quarter, we had listed that share buybacks would be a possibility in an environment above $60. The reason we haven't talked about it here recently is the fact that we wanted to get a line of sight to see whether or not prices were going to remain that healthy, and we also wanted to get closer to our Breakeven Plan to resume our buyback program. As for the amount, as Cedric said, we have quite a volume of share repurchases that were authorized by the board for us to make. We'll begin those this year, but it really depends on the market conditions, pricing, and other opportunities.
Brian Singer - Goldman Sachs & Co. LLC:
Great, thanks. And then to shift on my follow-up to the Permian, you're planning an acceleration in the number of Permian Resources wells brought online in the second and third quarters, and you've guided to an acceleration in production and growth in the third and fourth quarters. What are the moving pieces around that and potential upsides? What type of well productivity improvements, if any, have you factored in versus what you're seeing? And how should we think about the natural decline rates in Permian Resources?
Joseph C. Elliott - Occidental Petroleum Corp.:
Brian, this is Jody. Good morning. We tend to take a cautious approach to updating our type curves and projections on new wells. So as we get data beyond the 24-hour IP, beyond the 30-day IP, we really want to start seeing consistency in the 6-month cumes or even the 1-year cumes we start moving up our type curves. So some of that is baked into this forward guidance. The wells online count, we're confident about that, given all the investment in Aventine and the logistics work and the improvements in our execution. The variability in those numbers is really just the fact that a lot of these land right at the end of the quarter, and so a few wells moving in or a few wells moving out changes your count, but it doesn't appreciably change your production forecast.
Brian Singer - Goldman Sachs & Co. LLC:
Great, thank you.
Operator:
The next question comes from Guy Baber of Simmons & Company. Please go ahead.
Guy Baber - Simmons Piper Jaffray & Co.:
Thanks and congratulations, everyone, on the strong results.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Guy Baber - Simmons Piper Jaffray & Co.:
I wanted to start with just a point of clarification on the Midstream. But just to confirm here, the slides show that for every $0.25 per barrel widening in the spread, that's another $45 million of cash flow annualized to the Midstream, which is clear. However, there is I believe a partial offset in terms of your upstream realizations. So can you just confirm for us what that sensitivity is on a net basis to OXY at the corporate level, inclusive of the Midstream benefits but also accounting for the hit to the upstream realizations? I just want to make sure that we're triangulating to the right bottom line, as the guidance is premised upon a $6 to $7 spread, obviously, but we're currently sitting closer to $15 on a spot basis.
Cedric W. Burgher - Occidental Petroleum Corp.:
Guy, this is Cedric, and that's a good question. The net is about $30 million, so the $45 million minus the $15 million.
Guy Baber - Simmons Piper Jaffray & Co.:
Okay, great.
Cedric W. Burgher - Occidental Petroleum Corp.:
I think that answered it.
Guy Baber - Simmons Piper Jaffray & Co.:
Okay, perfect. And then for my follow-up here, I wanted to ask an ops question. But, Jody, you alluded to this, and you have a slide on this in the back of your deck, slide 50, I believe. But you highlight how you all drilled some of the most prolific wells in the basin in the last 12 months with a step function improvement in the recent quarters, yet you're seeming to do that without any meaningful increases in your completion intensity and at a completion intensity that's well below average for peers. So that appears to bode pretty well for your capital efficiency. So can you just talk about that dynamic in a little bit more detail? I'm just trying to better understand the sustainability there and what you're seeing leading edge on the capital efficiency front.
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, Guy, thanks for the question. This all really starts with subsurface characterization. It's what we've been talking about over the last year of improvements on geomechanics and geochemistry and integrating our seismic and advancing our petrophysical modeling to better understand what we call flow units, and then how those flow units will behave with a stimulation. That leads to then a better stimulation design that's customized for basically each well. But from that customization comes efficiency gains built around standardization. So all of the execution with leveraging Aventine, with how we execute in the field, delivery of sand, the commercial arrangements that support that then turn something that's very customized into something that's very manufacturing-oriented. So the combination of those things is really what's driving what we believe is play-leading capital efficiency. The other piece in the middle that I want to highlight is what the team does in the area of field development planning. So they take all of those attributes and then optimize what's the best way to develop the field or the different flow units. Do we do them concurrently? Do we do them individually? How do you pace the rigs, how many rigs, how many frac cores? And there's many, many iterations on trying to optimize that, and the ultimate goal is maximum value per section. And so our teams have gotten very, very good at that, but they also retain flexibility in those field development plans, so as we have new learnings, we have surprises, both positive and negative, we can adjust those plans accordingly. So we really are hitting on all cylinders from subsurface through execution at the wellhead.
Guy Baber - Simmons Piper Jaffray & Co.:
That's great stuff. Thank you and congrats to you as well, Richard.
Richard A. Jackson - Occidental Petroleum Corp.:
Thanks, Guy.
Operator:
The next question is from Phil Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Yes, hi. Good morning. Congratulations on a strong quarter. First question is just on the capital spending for this year. If I look at the Permian specifically, the wells online in the first quarter are a fairly small percentage of the total-year plan. But the CapEx in the Permian, if I just take your guidance from the fourth quarter call, divide it by four, is tracking ahead of that. But I just want to get an understanding of how – it sounds like it was in line with your own expectations, but I just wanted to get an understanding of how you think about how that plays out. And if you could maybe just dovetail in the comments about potentially looking to spend more capital to sustain activity levels in the international investments that you talked about.
Vicki A. Hollub - Occidental Petroleum Corp.:
Yeah, I'll let Jody cover a little bit more of the lumpiness of the Resources business and what we had expected to see in the beginning of the year. But when we laid out our program, we intentionally designed it so that toward the end of the year we would have the flexibility to ramp down, and that's built into the capital program for 2018. What we wanted to do is to have the flexibility to ramp down to our $3.3 billion capital in 2019 if we were seeing a $50 environment, which is what we had talked about. Since we're not sure what pricing will do in 2019 and we want to stay within cash flow with our capital programs in the future, we haven't set that yet. So what you're seeing is an upfront-loaded 2018 capital. With respect to how the wells fit into that, I'll let Jody talk about that.
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, when you think about the plan for this year, the front end is considerably loaded with more facility activity. In fact, in the second quarter, we'll be commissioning two large facilities in New Mexico. And so as you move through the year, even though some of the well count is going up on the completion side, you're offsetting that with less facility spending. The wells are also the place where all of these efficiencies, the benefits of Aventine which are just starting and which will grow over the year, start coming into play.
Philip M. Gresh - JPMorgan Securities LLC:
And if I could just clarify, Vicki, on the second part of that question around the activity levels and the potential for further investment in international and EOR, is that something that would lead to spending above the $3.9 billion for the year at this stage?
Vicki A. Hollub - Occidental Petroleum Corp.:
At this point, we haven't made any decisions regarding that. But what I will assure you is that we have flexibility. We have a vast inventory of not only things to do in the Permian but internationally. Our opportunities are pretty much unlimited at this point with respect to what we're seeing. But for the program this year, we haven't made any decision yet to increase our capital. What we would consider doing at the most probably would be to sustain the activity level we have at this point, but we haven't made that decision yet. We'll see how things look over the next few months.
Philip M. Gresh - JPMorgan Securities LLC:
Got it, okay. And then my follow-up was just around the balance sheet. In past quarters, you've had slides there where you've talked about asset sales as a means of bridging some of your spending gap, which obviously at higher prices isn't as necessary. But does that mean that you're not looking to monetize these assets anymore? And just in general, when you talked about your debt reduction objective, what would be the goal at this stage? Where do you want gross debt or net debt, whatever metric you would choose to go by?
Cedric W. Burgher - Occidental Petroleum Corp.:
Got it. This is Cedric, Phil. On monetizations, we'll always be looking at high-grading, improving our portfolio. If there are things that we can get a good value for that aren't core or strategic to us, then we certainly would be looking at those kind of exits, like what we just did in the first quarter with the gas plant. It really wasn't – we got a good price for it, and it wasn't essential to what we needed to do. In a lot of those particularly Midstream areas, we can contractually cover our needs just as easily. You don't necessarily have to own the asset. So there aren't any big plans necessarily, but at the same time we'll always be opportunistic with improving our portfolio. With respect to the balance sheet and debt, we don't have a precise target other than we want to be at the strong side of the group within the peer group. We've got a good credit rating and a good strong balance sheet, and we would like to make some improvements to it. But there's nothing that's kind of a must-have. So improving the net debt with some of the organic cash flow we expect to be generating over the next few quarters is also on the list of things we'd like to do.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, thanks.
Operator:
The next question is from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. Good morning, everybody. Richard, you're not going to get rid of us that easily, but good luck in your new role. But two quick questions, if I can (34:41-34:54).
Vicki A. Hollub - Occidental Petroleum Corp.:
I'm sorry, Doug, but you're cutting out. Could you try to repeat that question for us, please?
Doug Leggate - Bank of America Merrill Lynch:
Sorry, I apologize. Can you hear me now?
Vicki A. Hollub - Occidental Petroleum Corp.:
Yes.
Doug Leggate - Bank of America Merrill Lynch:
Okay. So when I saw you last, you talked about achieving the milestone for cash breakeven as a potential turning point for the new OXY strategy going forward. I'm just wondering what you think is the right level of growth for a company of your size. What do you think your portfolio can support?
Vicki A. Hollub - Occidental Petroleum Corp.:
I think what the portfolio can support and what's appropriate and prudent to do are maybe two different things. Our portfolio would support significant growth rates. But we believe that a growth rate certainly above 8% is where we can be very efficiently and effective, and we think that that's the growth rate that would be appropriate for our dividend level and for the other cash flow priorities we have, as we mentioned earlier, buybacks. I'm not sure where that ultimate number would be. It really depends on how efficient we get and what types of projects come up. But certainly, one of the things we always want to do is stay within cash flow, so it will be somewhat driven by prices.
Doug Leggate - Bank of America Merrill Lynch:
I appreciate that. That was, just to be clear, compared to the current 5% to 8% target, right?
Vicki A. Hollub - Occidental Petroleum Corp.:
That's right, because currently, we've averaged 5% to 8% over the years. We now have the capability to go well above that. And how far above that we go, to say it more clearly, is going to be dependent on prices and cash available.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. My follow-up is probably for Cedric, if you can still hear me. Cedric, buybacks and dividend growth go hand in hand, meaning that on a per-share basis, buybacks amplify dividend growth, so I'm just curious. How do you think about the dividend policy going forward in the context of restarting the buyback program? Is that a per-share growth target on the dividend or an absolute target on the dividend amount? I'll leave it there. Thanks.
Cedric W. Burgher - Occidental Petroleum Corp.:
Thanks, Doug. No, on dividends, really our philosophy has not changed. We are absolutely committed to the dividend, as we've proven through the downturn, not just sustaining it but growing it at a modest rate. It will be dependent on our view of – a dividend is long-term commitment. Share buybacks are more opportunistic. This may be the way to say it. But on the dividend, we would look to continue with modest increases. Because it's a long-term, permanent commitment, if you will, the dividend, we look to do that at a more mid-cycle price. So today plus or minus $50 is what we have in mind. So with the higher price, as we showed last quarter on slide 6 of last quarter's presentation, buybacks come into play when you're in a significantly higher price than $50. So we run our business on a $40 to $50 price deck in terms of being prepared for lower prices, running a low-cost business, and then look for dividend increases as we continue to improve our efficiencies, our well productivity. The Aventine, all the things we've been talking about to drive our breakevens lower, we'll continue to do that. And that's what will position us potentially for further dividend increases.
Doug Leggate - Bank of America Merrill Lynch:
I appreciate the answer. Thanks, everybody.
Operator:
The next question is from Leo Mariani of NatAlliance Securities. Please go ahead.
Leo P. Mariani - NatAlliance Securities LLC:
Hey, guys. I just wanted to follow up on one of the earlier comments that you guys made. Obviously, your breakeven has been pushed forward to the third quarter. Obviously, that's nice. You talked about potentially higher CapEx later in the year. But you specifically said that that would likely be portioned over to international EOR. I just wanted to get your thought on that. Why those areas versus Permian Resources, for example, do you see better returns in international EOR? What's the thought behind that?
Vicki A. Hollub - Occidental Petroleum Corp.:
So for 2018, if we increased our capital, it would be not beyond the program we currently have planned for international. Any increase in capital this year would be to just sustain the Permian Resources business. We do have some capital allocated to our international assets to do some appraisal work and evaluations for a little more aggressive program internationally in 2019, if prices permit, but that's probably what you're talking about is just the work to set up those programs for 2019.
Leo P. Mariani - NatAlliance Securities LLC:
Okay, that's helpful. And I guess with respect to the Aventine hub, obviously you guys have put a lot of time and effort onto getting that up and running. If you were to do a bit of a lookback and project forward, is there any way to quantify what you might be able to save in terms of Permian Resources well cost? Is there any way to say look, once this is fully up and running by the end of the year, we can save 10%? Is there any way to quantify that?
Joseph C. Elliott - Occidental Petroleum Corp.:
Leo, this is Jody. Thanks for the question. I think we've stated $500,000 to $750,000 a well impact when we're up and running. But the concept of Aventine actually wasn't just well cost focus. It was also securing supply. And so we're really getting multiple benefits out of Aventine. Clearly, we think we will drive costs down. We have already shown that securing supply during this tight period has been very, very helpful, not just in New Mexico, but supporting contingency sand deliveries in Texas as well. The other part that really starts growing over time are the efficiencies that are gained because we've got all of our strategic partners in place that we can start whittling out all of the inefficiencies, the wasted motion, which does two things. It lowers our well cost and shortens time to market. But for our partners, it drives up their utilization. So their profit per frac core, per rig crew, per flowback unit, all of those things go up because we're more efficient than the industry average. And so the result of that is less pressure on price increase because they're driving higher margins. That's how we look at it. The number we've talked about is $500,000 to $750,000 a well. We think there's upside as the teams mature, not just in the physical assets but how we work the process.
Leo P. Mariani - NatAlliance Securities LLC:
Thanks a lot.
Operator:
The next question is from Bob Morris of Citi. Please go ahead.
Robert Scott Morris - Citigroup Global Markets, Inc.:
Thank you, good morning, Vicki and team. Congratulations on the continued improvement in the Delaware Basin wells. My first question is you raised the guidance on the Midstream pre-tax income, and that's based on an assumed spread of $7 to $8 from Midland to the Gulf Coast for the rest of the year. But that spread is currently around $15, and the strip on that is similarly wide. Would you or could you – have you given any thought to hedging that or trying to lock that in? Because that would be significant incremental cash flow that then you could use for the share buyback or otherwise.
Vicki A. Hollub - Occidental Petroleum Corp.:
I would say, Bob, up to this point this quarter, we're seeing an average of just a little more than $8. So while it might seem like we're being conservative, it's really based on some information, and some of the spikes we're seeing go well above that, but we're not sure we'll see that. But with respect to your question, I'll pass that to Cedric.
Cedric W. Burgher - Occidental Petroleum Corp.:
Bob, I'd love to lock in $15 if we could. The truth is there's no market really for hedging those differentials. It's very thin and short-term and just really non-existent. So it's a volatile market. Its outlook is difficult to predict. As we've seen, the primary driver is pipeline utilization, which we expect to continue to be high until these new pipes come on, particularly in the second half of 2019. But as it stands, hedging is just not really an option available to us.
Robert Scott Morris - Citigroup Global Markets, Inc.:
I suspected the market was pretty thin. And obviously, it would be nice to be able to lock that in. My follow-on question is I know you did mention you'd be opportunistic on non-core asset sales. You did say last quarter you expected to execute on some non-core asset sales this year. Has either the recent deal at a very high per-acre value or the widening in these Midland differentials change your view or approach on executing on non-core asset sales this year?
Vicki A. Hollub - Occidental Petroleum Corp.:
No, it's still the same. We will look for opportunities, and the opportunities have to be compelling enough to execute on. But we're still continuing to look at ways to monetize those things that are noncore to us.
Robert Scott Morris - Citigroup Global Markets, Inc.:
Okay, great. Again, congratulations. Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
The next question is from Matt Portillo of Tudor, Pickering, Holt. Please go ahead.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Good morning, all. Jody, you highlighted the value proposition of the Aventine logistics hub in the northern Delaware Basin, which appears to have a strong competitive advantage regionally. I was wondering if you see similar logistics potential in the southern Delaware and in the Midland Basin.
Joseph C. Elliott - Occidental Petroleum Corp.:
Matt, we sure do, but in a different scale. Actually, the one in the southern Delaware Basin is called Palatine, and it's more of a contractual relationship on sand trans-load. Midland Basin, there's more access to infrastructure, and so you could service Midland out of either Palatine or direct from some of the regional sand mines that are coming online. It's a little less exposed, plus our activity set is considerably lower in Midland. So we're really focusing on the Delaware Basin to ensure we have logistics, maintenance capabilities, those kind of things that are more regional to the activity to take out trucks, to take out inefficiency and downtime.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Great. And the follow-up question is actually around your export business. As pipeline capacity ramps towards Corpus, you mentioned industry volumes will continue to increase, allowing you to expand your Ingleside dock capacity for crude oil. My question actually revolves around your LPG asset base. I know OXY mothballed that facility due to lack of propane access. And I was wondering with some of the new greenfield NGL pipes potentially heading southbound if you see the potential to bring this asset back into service.
Vicki A. Hollub - Occidental Petroleum Corp.:
We stay aware of all the activity in the area, and we're just keeping a watchful eye to determine at what point. We believe at some point that could be an opportunity for us, but we don't see that now. We're really focused more on expanding the oil export part of that. However, we're going to stay opportunistic with respect to how those pipelines play out and what opportunities might come our way.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Great, thank you very much.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
The next question is from Pavel Molchanov of Raymond James. Please go ahead.
Muhammed Ghulam - Raymond James & Associates, Inc.:
Hey, this is Muhammed on behalf of Pavel. Thank you for taking the questions. First of all, when the buyback eventually does start, how should we think about it? Should it be a flex variable, as in will it remain relatively constant, or flex up or down with free cash flow?
Cedric W. Burgher - Occidental Petroleum Corp.:
I think the way to think of it, Muhammed, is opportunistic. We're going to be looking at – there's a competition for capital around here, and that's one great use of capital, but we'll look at reinvestment and other options as well. And obviously, we'll be looking at the value of the shares. So periods of weakness and things like that, we certainly could step in, but we'll be opportunistic with those buybacks.
Muhammed Ghulam - Raymond James & Associates, Inc.:
A follow-up on a different topic. The Middle East, it's now been almost a year since the economic embargo against Qatar started. You've said in the past there hasn't really been a significant impact on you guys. Is that still the same, or have there been any changes?
Vicki A. Hollub - Occidental Petroleum Corp.:
No, that's still the same. It never really impacted our business very much, and I think Qatar in general has made a lot of changes to the way the country now manages that. And so we don't expect, didn't see any, and don't expect to see any problems with any of our operations.
Muhammed Ghulam - Raymond James & Associates, Inc.:
That's all for me, thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
The next question is from Roger Read of Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Yeah, thanks. Good morning. Am I on?
Vicki A. Hollub - Occidental Petroleum Corp.:
Good morning. Yes, you're on.
Roger D. Read - Wells Fargo Securities LLC:
Good morning. Okay, I just wanted to make sure. Kind of blank there. Maybe to follow up on the dividend question that hasn't been quite beaten to death, Cedric, if you look at your debt and thinking about the period we've just been through here of focusing more on cash flow neutrality in a low oil price environment than where we are today, do you look at any of your long-term debt and evaluate that as something you might prefer to retire rather than buy back shares?
Cedric W. Burgher - Occidental Petroleum Corp.:
Certainly, we would look at that, have looked at it. We know the terms, so that's it. That is one option that we could consider down the road. So again, framing it, hopefully we've laid this out pretty clearly, but we have a plan that we're about to achieve that means we can pretty much in any reasonable oil price scenario stay within the guardrails of cash flow. And then with that, we've laid our priorities, and net debt improvement is one of them. And so in the short term, it likely means building cash a little bit because most of our debt is termed out, as you've noted. But there are ways to bring that in and make some reductions there too over time. But again, in that area we'd be opportunistic. I've worked on in the past debt buybacks and even a defeasance, and a defeasance is probably the last thing we'd want to do. They tend to be expensive, but there are ways to bring that debt in, and that's something we would look at over time should the cash flow continue to stay at a high level.
Roger D. Read - Wells Fargo Securities LLC:
Okay, thanks, and then maybe two quick questions on the Permian. This call, no comments or, at least that I saw in the presentation, anything on acreage swaps or additions or anything. Is that an indication the markets slowed down or just a quarterly kind of event? And then the other question was, if you could help us, just because it's been quite a while since we've had to think about high oil prices having an impact on EOR ops or OpEx, what exactly is exposed, what the percentage, maybe the right way to think about how that stair-steps in, in a higher oil price environment.
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, Roger, no. The first question on acreage trades, no, there's still a lot of activity there. Last year we did about 17,000 net acres in trades, and in the first quarter we've done 11,000. So there's still a desire to core up, be able to drill longer laterals, leverage your larger positions. With regard to EOR OpEx, it's primarily two things. It's energy, so as the cost of electricity goes up, you have some exposure to energy. And then some of the CO2 contracts have an oil price relationship. We can follow up with you later on trying to help model that a little closer. But the things we control with well work and activity, that's all managed pretty well and not so exposed to inflation. Our improvement activities typically offset any inflation.
Roger D. Read - Wells Fargo Securities LLC:
Okay, great.
Cedric W. Burgher - Occidental Petroleum Corp.:
Roger, sorry, this is Cedric. I just want to add one thing just for clarification. The first quarter financials, in our cash flow you'll see $177 million of acquisitions and $275 million of sales. We talked about the roughly $150 million Delaware Basin gas plant sale, which was non-core, in that sale number, but the other piece of it was really the swap. So really the acquisition, we just broke – the way we did from an accounting standpoint, we broke both the acquisition and the sale out in the financial statement. But it really was done as one deal and it was essentially a swap, a large one.
Roger D. Read - Wells Fargo Securities LLC:
Great, thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
And the other thing I'd add, Roger, about EOR is that we put the slide in there to show you it's leveraged to oil. And the reason for that is that it's about 80% liquids. And so on a BOE basis, we have a higher liquid – higher oil production from EOR on a BOE basis. So that's why it's that margin for – even though OpEx will go up a little bit, we really benefit from higher oil prices in the EOR business.
Roger D. Read - Wells Fargo Securities LLC:
I appreciate that.
Operator:
The next question is from Jason Gammel of Jefferies. Please go ahead.
Jason Gammel - Jefferies International Ltd.:
Yes, thanks very much. I just wanted to come back to the updated guidance on the Midstream, which obviously a very significant increase. I realize that most of it is due to differential. But if I just take the midpoint change in the differential, multiply it by the $45 million rule of thumb, which sounds like maybe I should be using $30 million, I get to about $625 million versus the $750 million step-up in the guidance. So I was wondering if you could talk about any other factors that are positively affecting your outlook for the Midstream this year.
Cedric W. Burgher - Occidental Petroleum Corp.:
Certainly, the Midstream business has more than just that – those contracts related to the takeaway. The export terminal in particular has been doing fantastic this year. As you know, we're a leader in that area, and so I think it would probably be the other thing I'd point to more specifically.
Jason Gammel - Jefferies International Ltd.:
So that's the ability to capture the arbitrage between, let's say, Brent and Corpus Christi pricing or something along that one?
Richard A. Jackson - Occidental Petroleum Corp.:
This is Richard. I may help with one piece of that. I wanted to clarify. The $45 million per $0.25 change, the Midstream segment fully benefits from that. The $30 million is really our upstream production that's based on Midland pricing, and so you'll see that in our realizations and our production schedules. So you do need to take the full $45 million and apply it to Midstream, and that's the benefit.
Jason Gammel - Jefferies International Ltd.:
Okay, thanks. That is to say even that would be a fairly significant uplift relative to just the rule of thumb that you're giving in guidance. But maybe if I could just transition, your comments around essentially pipeline utilization rates being very high and not really much relief until midyear next year, I know you're only giving guidance for 2018. But should we be able to extrapolate that Midstream is looking to have a pretty good first half of 2019 earnings period as well?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yes, that's our view. If you look at the alternatives, rail would be great, but it's got an $8 a barrel range, but that's limited today to around 100,000 to 150,000 barrels a day in terms of rail capacity. I think there will be efforts to try to increase that, but it's difficult to do. And then trucking – by the way, slide 63 lays this out pretty well for you. And then trucking, again, it's a higher cost with around $12 or so a barrel. So those would be some upper limits you might think about. However, with trucking, we've all seen bottlenecks there. The roads are crowded and in disarray, and getting trucks and getting truck drivers even is a difficult thing to do. So as we've said, the outlook for spreads is difficult to predict. It's going to be bouncy for a while as all of the takeaway systems are being stretched to their limits.
Jason Gammel - Jefferies International Ltd.:
That's really very useful. Thanks very much.
Joseph C. Elliott - Occidental Petroleum Corp.:
You bet.
Operator:
And the final question today comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Michael Anthony Hall - Heikkinen Energy Advisors LLC:
Thanks, a lot of mine have been addressed. I guess just one I wanted to hit on, on the Aventine facility, I guess dovetailing off of the comment on crude-by-rail. Is there any opportunity to I guess convert any of that facility into a crude-by-rail terminal, and to what extent might there be any interest in doing that on you all's end?
Joseph C. Elliott - Occidental Petroleum Corp.:
Michael, this is Jody. You've got to recall, we have 2.5 times our equity oil production volume that we can move on pipe. So for us, we wouldn't likely consider that as an option. We really see this more as an operational facility to support right now mostly the capital side of the business. Then as you go through the full life cycle, it will support the operating cost side of the facility as well.
Michael Anthony Hall - Heikkinen Energy Advisors LLC:
Okay, I guess I was thinking about it from a marketing business angle, so that was another way to capture even more potential upside from the current situation, but it sounds like no. And then I guess the other piece is just on local sand usage. To what extent, if at all, are you guys testing that in the Delaware Basin in particular is I guess where I'm curious.
Joseph C. Elliott - Occidental Petroleum Corp.:
Hey, Michael, we see application of local sand in both the southern Delaware and the Midland Basin. Our preferred sand provider is coming online now with their local sand mines, so we will start utilizing more local sand as a percentage of the total. We've the background work, the geoscience work, the lab work and all to test different sands, different sand quality, so we're comfortable applying those. It's just a matter of getting more activity in the local sand market.
Michael Anthony Hall - Heikkinen Energy Advisors LLC:
Great, I appreciate it.
Operator:
This concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for closing remarks.
Vicki A. Hollub - Occidental Petroleum Corp.:
I'd like to leave you with three takeaways today. First, we are ahead of schedule for achieving our Breakeven Plan. Second, our first quarter outperformance and improving business results have led us to increase our full-year guidance. Finally, we will reinvest excess cash flow in our highest-return opportunities. And to close, I'd like to thank all of our employees because they are the true drivers of our success. Thank you for joining our call today.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Richard A. Jackson - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Cedric W. Burgher - Occidental Petroleum Corp. Joseph C. Elliott - Occidental Petroleum Corp. Kenneth Dillon - Occidental Petroleum Corp.
Analysts:
Roger D. Read - Wells Fargo Securities LLC Brian Singer - Goldman Sachs & Co. LLC Phil M. Gresh - JPMorgan Securities LLC John P. Herrlin - Société Générale Pavel S. Molchanov - Raymond James & Associates, Inc. Leo P. Mariani - NatAlliance Securities LLC
Operator:
Good day, everyone, and welcome to the Occidental Petroleum Corporation's Fourth Quarter 2017 Earnings Conference Call. After today's presentation, there will be an opportunity to ask questions. Please also note, today's event is being recorded. And at this time, I'd like to turn the conference call over to Mr. Richard Jackson, VP of Investor Relations. Sir, please go ahead.
Richard A. Jackson - Occidental Petroleum Corp.:
Okay. Thank you, Jamie. Good morning, everyone, and thank you for participating in Occidental Petroleum's Fourth Quarter 2017 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Jody Elliott, President of Domestic Oil and Gas; Ken Dillon, President of International Oil and Gas Operations; and B.J. Hebert, President of OxyChem. In just a moment, I'll turn the call over to Vicki Hollub. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our fourth quarter 2017 earnings press release, the Investor Relations supplemental schedules and our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I will now turn the call over to Vicki Hollub. Vicki, please go ahead.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Richard, and good morning, everyone. Before I talk about our business results, I'd like to first thank our employees for their efforts to ensure a safe workplace for our employees, contractors and the public. In 2017 we had the best employee and combined employee contractor injury and illness rate than we've ever had. In addition, OXY Oil & Gas had an industry-leading employee IIR – that's illness and injury rate – of 0.11. This is a result of a long trend of improving safety performance which indicates that safety is not an initiative for us. It's a part of who we are. It's embedded in our culture, which is a reflection of the quality and commitment of our employees. On behalf of the management team and our board, I want to thank our employees for owning safety. Today, I'll share some highlights from 2017 and then some key items we consider for disciplined reinvestment and what that means for allocating capital. I'll then conclude with details of our 2018 capital program. Cedric will update our progress on our breakeven plan. In 2017, we focused on improving our cash flow through value-based growth in Permian resources, enhancing our portfolio, increasing the value of our assets and using technology to drive operational performance. We enhanced our portfolio by increasing cash flow from OxyChem in 2017 with the completion of the Ingleside ethylene cracker, which reached full capacity in 2017. OxyChem will provide additional incremental cash flow in 2018 from the 4CPe plant that was commissioned and put on production in December of 2017. The plant, located in Geismar, Louisiana, uses an OxyChem patented process to produce 4CPe, which is a raw material used in making next generation climate-friendly refrigerants with low global warming and zero ozone depletion potential. The project was completed on time and on budget and it represents another significant accomplishment within our breakeven plan. We increased the value of our assets through increased productivity, significant reserves replacement, optimum cash flow from our international operations and increased exports from our Ingleside crude export terminal. Our increased productivity came mostly from our Permian Resources business, where we achieved record initial production rates across eight benches and continued to deliver step change well results in Greater Sand Dunes during the fourth quarter. These results have helped drive our capital intensity down while adding to our long-term reserve potential. For two years in a row, we've achieved all-in reserve replacement ratios of nearly 190% companywide, with F&D costs of less than $10 per BOE. In Permian Resources, our reserve replacement ratio in 2017 was a record-setting 365% with an F&D of $9.77 per BOE. We've provided additional details on our 2017 reserve data in the appendix and earnings release. We'll continue to focus on optimizing recoveries and F&D costs through our value-based development approach. Equally important were similar improvements in our international businesses where we generated over $1 billion of free cash flow, and I want to take a moment to recognize our Oman team. We've operated in Oman for almost 35 years and recently achieved a significant milestone with a production of our 1 billionth barrel of oil. With the extension of Block 9 and a new contract in Block 30, we're excited about continuing our long history of success and partnership in Oman. Lastly, I'd like to emphasize how advancing technologies have improved our operations. Our investment in subsurface characterization has driven progress in both our unconventional EOR assets and our unconventional assets, and we're increasingly finding more synergies between them. Four unconventional EOR technical pilots that we began in 2014 have increased our technical understanding of how these two assets will work together in the future and will provide significant option value across our large Permian position. This innovative work in combination with our petrophysical advancements to improve primary recoveries positions us to lead the industry in full-cycle value and return on capital employed. We're also advancing our use and sequestration of anthropogenic or manmade CO2. One important step was our work with EPA to develop the first monitoring, reporting and verification, or MRV, plan for CO2 injected in our Denver unit asset in 2016. Our MRV plan provides transparent and formal accounting for permanent geologic sequestration as a part of our EOR process. During 2017, we applied for and received approval for another MRV plan in our South Hobbs asset, the second ever issued by the EPA. We reported volume sequestered at the Denver unit in 2017 and will report our sequestration amounts for both assets in 2018. These two assets represent two of our 34 CO2 EOR floods in the Permian and through our MRV plans, we'll demonstrate the significant potential that exists in our assets to store CO2. Another important advancement of CO2 sequestration through EOR occurred last week when Congress passed the FUTURE Act. This legislation can help incentivize the development of new carbon capture projects making more anthropogenic CO2 available for sequestration and EOR operations, operations that have MRV plans. This policy and technical advancements combined with our significant CO2 EOR position and infrastructure could provide emerging opportunities for OXY and the lower carbon future we must all work to achieve. We look forward to continuing to grow our leadership in this space. To complement our subsurface advancements, our teams have also worked on innovative solutions to manage costs long term. We continue to make progress on the recently developed technologies and operational differentiators that we introduced to you during 2017, such as SL2, our multi-lateral technology; and our logistics and maintenance hub in Southeast New Mexico, this hub which will ramp up operations through the first half of 2018. To summarize our key progress in 2017, we showed three key metrics on slide 5. Enhancements to our portfolio enabled us to fund our dividend and sustaining capital with our cash flow from operations and to fund our growth capital with a combination of cash on hand, our tax refund and proceeds from net asset sales. This advanced our plan to break even. The 20% improvement in the six-month cumulative production volumes we achieved in Permian Resources will significantly increase our resources value. This is a result of several years of excellent subsurface work that is beginning to fully mature and be visible in our results. Finally, our ability to replace our production at close to 190% replacement ratio with high quality, low F&D production makes us very confident that this is sustainable for a long period of time, and will deliver top tier return on capital employed and will provide more total returns to our shareholders. Turning to slide 6, our value proposition has not changed. When others chose to cut or eliminate their dividends, we developed a plan to continue and strengthen ours. We view our value proposition, which is founded on dividend growth, to be a commitment to our shareholders and not an option. We've been able to pursue this strategy consistently for many years as a result of the quality of our assets and the discipline of our management team. As you can see on slide 30, over the past 16 years, we've given $30 billion back to our shareholders through dividends and share buybacks. Our scale, combined with the free cash flow generation of our international assets, Permian EOR and Chemicals, along with the growth of our premium Permian Resources position creates a truly unique value proposition, in that we can provide strong dividends and meaningful growth as well. Our cash flow priorities also have not changed. Sustaining capital and dividends are non-discretionary items. Our first priority is to maintain an operationally and environmentally safe business. Our second priority is to grow our dividend as we've done for the past 15 years. As we look beyond our cash flow breakeven plan, we will consider several key factors for disciplined reinvestment that support dividend and production growth long term. Our investment decisions are focused on maximizing return on capital employed. We will not invest in projects unless they deliver a minimum return of 15% for domestic and 20% for international. The other factors we consider are, one, pacing growth to maximize net present value; two, improving low cost inventory; three, maintaining an industry-leading decline rate; four, sustaining a secure capital structure for downside protection and upside opportunistic value creation through the inevitable commodity cycles; and five, appraising long-term social and environmental opportunities to risk, like potential carbon pricing. Now I'll update you on what this means for our next steps immediately beyond achieving our breakeven plan, as on slide 6, where we've illustrated what this looks like at various oil prices. Our first priority is to complete our breakeven plan and we expect to achieve this ahead of schedule. Our breakeven plan will secure our sustaining capital, current dividend and 5% to 8% production growth at $50 WTI. Beyond these milestones, we believe it's important to improve our dividend payout ratio and reduce our net debt. This means that in the short term at $50 WTI, we'll grow the dividend at a nominal rate similar to last year, while investing in both short and long-cycle projects to deliver 5% to 8% growth. Any additional cash flow will be retained to improve our net debt metrics and be prepared for value-adding growth opportunities. We believe this conservative approach will further strengthen the sustainability of our dividend while giving us flexibility to remain opportunistic. Beyond these initial steps, we'll manage incremental dividend growth and reinvestment opportunities within the framework I've discussed. At greater than $60 WTI, we're able to accelerate our payout ratio improvement and net debt reduction, and will weigh growing towards the higher end of our 5% to 8% range and growing our dividend more meaningfully. Turning to slide 7, our capital program was designed to achieve our breakeven plan in the third quarter of this year. We expect this program will generate annual growth of 8% to 12%. Chemicals spending has rolled off significantly, which will enhance free cash flow generation. In Midstream, overall capital will increase modestly versus last year to accommodate an expansion of the Ingleside crude export facility. We recently awarded EPC contracts to expand the capacity of the terminal by 2.5 times, up to 750,000 barrels per day. Total Oil & Gas capital spend will be approximately $3.3 billion. The international capital is primarily for sustaining purposes as we complete our breakeven plan, but we expect higher investment in our international business in 2019 and beyond. Similar to the international business, the Permian EOR business will spend capital to sustain current production levels. Permian Resources will receive a total of $1.9 billion in capital, of which $1.2 billion is for growth. I'll now turn the call over to Cedric to review our progress towards the breakeven plan and our financial results.
Cedric W. Burgher - Occidental Petroleum Corp.:
Thank you, Vicki. I will begin with an update on our breakeven plan and then address financial results and 2018 guidance. On slide 9, we have updated our progress towards our breakeven plan at low oil prices. As the chart shows, we've made substantial progress towards this goal, and our business segments are exceeding targets. As noted in last night's press release, we have further accelerated our timeline and now expect to accomplish the plan by the third quarter of this year. As most of you know, once we achieve our remaining milestones, we will have the cash flow necessary for our $40 oil price business sustainability case or our $50 oil price business growth scenarios. Slide 10 illustrates our progress towards the breakeven plan. In the Chemical business, the 4CPe plant came online in December and will begin contributing towards the breakeven plan next quarter. In the Midstream business, the Midland-to-Gulf Coast spread remained wider than our breakeven plan assumption of $2.10 per barrel, as it averaged $4.61 per barrel during the fourth quarter. Ken Dillon will tell you about the Al Hosn Gas plant debottlenecking that's beginning in the first quarter, and we have provided additional details on the capacity upgrade to our crude export terminal in the appendix. In the Permian Resources business, we grew 20,000 BOEs per day sequentially, leaving 50,000 BOEs per day to achieve our goal. Jody will give you additional guidance on the timing of new wells online and production. The Chemical and EOR businesses are making operational gains and experiencing market improvements beyond our initial plan. Caustic soda realizations, a key profitability driver for the Chemicals business, improved further in the fourth quarter and solidified $150 million of market improvement shown in the other improvements category of our slide. In the EOR business, we have achieved the $5 per BOE of cost savings we expected from the integration of the Seminole-San Andres CO2 unit into our network of floods. We have included a slide in our appendix highlighting this progress. We are excited by the progress we have made and we will continue to communicate incremental progress towards our pathway to breakeven. My next slide illustrates our liquidity needs for 2018, and it has changed markedly in our favor since last quarter. We have adjusted the chart to reflect a commodity price of $50 WTI and our new capital budget of $3.9 billion. At $50 WTI, the cash required to attain our breakeven plan is more than covered by our cash balance, and, at current prices, we would not need a cash flow deficit – we would not run a cash flow deficit during 2018. At the end of the fourth quarter, we had $1.7 billion of cash and the Plains units with a market value of approximately $600 million. In addition, we expect to evaluate and find opportunity to monetize non-core assets to maximize net present value of our portfolio. Shifting to our quarterly financial and operational results on slide 13, I'd like to start with our production results. Total reported and ongoing production was 621,000 BOEs per day. Permian Resources came in within guidance at 159,000 BOEs per day. Permian EOR increased by 2,000 BOEs per day to 155,000, a result of a full quarter of acquisition volumes. International came in at 302,000 BOEs per day. I'd like to take a moment to reconcile our fourth quarter production versus guidance. On the international side, our fourth quarter guidance was based on a Brent pricing assumption of $53 per barrel. Production sharing contracts, or PSCs had approximately a 5,000 BOE per day impact on our production, given that Brent averaged over $61 per barrel or an $8 increase versus our guidance assumption. While higher Brent prices are clearly a net positive overall, it does result in reduced production volumes for us. On the domestic side, the Permian experienced third-party downtime of approximately 4,000 BOEs per day, outside operator production timing of 2,000 BOEs per day and weather impacts of 1,000 BOEs per day. The international and domestic items totaled approximately 12,000 BOEs per day, which reduced our production below our fourth quarter guidance. However, as Ken and Jody will detail, we are confident with our plan for 2018 and the execution fundamentals of our production growth continue to improve. Earnings improved across all segments in our fourth quarter. Reported EPS was $0.65 and core EPS was $0.41. Reported earnings included about $575-million benefit from the revaluation of deferred taxes related to federal tax reform, which significantly decreased our fourth quarter effective tax rate. Improvements in the Oil & Gas business segment were mainly attributed to higher oil and NGL prices. Realized oil prices increased 16% and NGL prices increased by 21% from the prior quarter. Operating cash flow before working capital improved sequentially to nearly $1.5 billion due to higher oil and NGL prices, along with higher Permian Resources production. We spent $950 million in our Oil & Gas capital program during the fourth quarter. Total year Oil & Gas capital was $2.9 billion and we met our total capital budget of $3.6 billion. Chemicals fourth quarter core earnings of $217 million came in above guidance, primarily as a result of higher realized caustic soda pricing. Midstream fourth quarter core earnings of $129 million also came in well above our guidance due to higher marketing margins from improved spreads and exports through our terminal. With respect to 2018, we are affirming a capital budget of $3.9 billion, which will generate 8% to 12% annual production growth. This equates to a total company production range of 640,000 to 665,000 BOEs per day. Our guidance assumes $60 WTI and $65 Brent for the first quarter and $55 WTI and $60 Brent for the remaining quarters. The 2018 Permian Resources budget of $1.9 billion will drive a production range of 195,000 to 209,000 BOEs per day. The midpoint of this range equates to an annual production growth rate of more than 40%. Jody will provide additional color on our 2018 Permian plan. The 2018 international budget of $800 million will maintain a production range of 286,000 to 297,000 BOEs per day, which is sequentially lower due to the impact of higher oil prices on PSC contracts. Ken will provide additional details on the capacity expansion of the Al Hosn Gas plant. In the first quarter, we expect total production to range from 592,000 to 603,000 BOEs per day. Jody will give additional detail on the Permian Resources outlook. International production in the first quarter will be impacted by turnarounds at Al Hosn Gas and Dolphin. Al Hosn volumes are expected to average 58,000 to 59,000 BOEs per day during the first quarter and will ramp to 83,000 BOEs per day by the third quarter. In Midstream, we expect the first quarter to generate pre-tax income between breakeven $10 million and $30 million, assuming a Midland-MEH spread of $3 to $3.25/BOE. The first quarter guidance also accounts for the turnarounds at Al Hosn and Dolphin. On a full year, we expect pre-tax income to range between $200 million and $300 million based on a Gulf Coast spread range of $2.50 to $3/BOE. In Chemicals, we anticipate first quarter pre-tax earnings of $250 million as the seasonality of sales for certain products improves in the first quarter. On a full year, we expect pre-tax income to approximate $1 billion, assuming caustic soda prices remain at current levels. As a reminder, a $10-per-ton move in caustic soda price equates to a $30 million in pre-tax income. Our DD&A expense for Oil & Gas is expected to be approximately $13.50 per BOE for 2018 compared to $14.87 last year, largely as a result of lower finding and development costs. Cash operating costs for the domestic Oil & Gas business are expected to average $12.50 during 2018, compared to $11.73 last year. Lower operating costs in the Permian Resources, which are expected to average under $7 per BOE, are expected to be offset by higher costs in the Permian EOR business for oil price-sensitive purchased injectant and higher energy-related costs. And, finally, on slide 16, we have provided you with key cash flow sensitivities. I'll now turn the call over to Jody.
Joseph C. Elliott - Occidental Petroleum Corp.:
Thank you, Cedric, and good morning, everyone. 2017 was an incredible year for our domestic business. Our teams leveraged our subsurface workflows and operating capability to drive improvements that derisked our cash flow breakeven plan and added significant long-term value to our assets. We monetized non-strategic assets with three key results. First, we acquired the CO2 EOR Seminole-San Andres unit to enhance our low decline Permian EOR business. Second, we invested additional capital into our Permian Resources strategic development plan and third, we cored up a Midland Basin multi-bench area we are now developing. We will continue to review our portfolio in 2018 and look for additional value-adding transactions. Our value-based development approach provided outstanding results across our business. Breakthroughs in geomechanics and petrophysical analysis of flow units drove an approximate 20% improvement in Permian Resources well productivity. Permian Resources lowered fourth quarter operating costs to $7.63 per BOE, a 9% improvement from the fourth quarter of 2016. In Permian EOR we've made significant progress at the recently acquired Seminole-San Andres unit. In just one quarter, we increased production by 3,600 gross BOE per day, reduced OpEx by over $5 per BOE and reduced flaring by 60%. We've also improved the economics of future development by reducing drilling costs by over 30% or $500,000 a well. I also want to highlight our progress in advancing new technology. As Vicki mentioned, we've implemented four different unconventional EOR pilots across the Midland and Delaware Basins. The initial results are encouraging and we believe that our position, scale and over 40-year history of operating EOR projects provide OXY with an advantage that will be extremely difficult to replicate. Progressing this technology will allow us to incorporate EOR into our future development plans and realize value with this upside option beyond just primary recovery. We're excited about these pilots and the future opportunity they represent. Turning to slide 19, the Permian Resources team added 750 locations to our less than $50 breakeven inventory in 2017, almost double the target set at the beginning of the year. This represents an additional four years of development at a 10-rig pace. The additional 325 locations added from lower cost and well performance are based on repeated improvements that are sustainable. Over 17,000 total net acre trades resulted in an additional 125 locations by enabling us to drill longer laterals and consolidate facilities. We are extremely pleased with the progress made improving our inventory in 2017 and believe that our focus on value-based development and innovative technology will continue to grow our breakeven inventory in excess of our drilling pace. On slide 20, our Greater Sand Dunes area delivered another quarter of play-leading results across multiple benches. In the fourth quarter, we brought online a total of 17 new development wells and one Avalon appraisal well. Our new wells in the fourth quarter had continued step change productivity results as we had achieved in the third quarter. Our confidence continues to increase in 2018 as in January, brought the Cedar Canyon 27/28 Fed 44H online that achieved a record 24-hour peak rate of 8,361 BOE per day and a 30-day rate of 6,111 BOE per day. As I mentioned in our last call, our understanding of localized production drivers across our position gives us confidence that we'll continue to deliver high rate of return wells across the more than 2,000 undeveloped locations in Greater Sand Dunes. In 2018, we will further integrate 3-D seismic, data analytics and deploy other emerging technologies for continued improvement. Beyond Greater Sand Dunes, I also want to highlight a new six section modular development area in New Mexico called Turkey Track. The Turkey Track 9-10 State 32H in the 3rd Bone Spring has produced over 200 MBOE in 90 days, and all five wells online in the fourth quarter are performing above expectations. We expect Turkey Track to deliver over a 40% all-in rate of return at $50 per barrel. While Turkey Track is only six sections, OXY has significant acreage in this region of Northern New Mexico Delaware Basin. This modular development approach allows us to leverage scale across multiple smaller development positions. Innovative facilities design and development sequencing allows us to reduce costs for operations across several sections while using regional subsurface characterization and operating efficiencies to leverage our basin-wide scale advantages. On slide 21, I'll walk through Permian Resources production for the fourth quarter and discuss the outlook for 2018. The continued improvements in well productivity and development optimization have put us ahead on our breakeven plan milestone. We now expect to achieve the 80,000 BOE per day of growth in the third quarter of 2018. We're extremely confident in our ability to execute this plan as critical resources were secured in 2017. Looking at the fourth quarter of 2017, good execution and well performance contributed to growing production by 20,000 BOE per day from the prior quarter, and achieving a December exit rate of 172,000 BOE per day. However, during the fourth quarter, we incurred approximately 6,000 BOE per day of downtime due to third-party pipeline and processing disruptions, OBO delays and weather downtime. In the first quarter, we changed our development plans to move a rig from Turkey Track, a two-well development area, to a Texas Delaware four-well pad development area. This change was made based on the better-than-expected 3rd Bone Spring results in Turkey Track, so we can now pace this development differently to allow multi-bench development with the 2nd Bone Spring and ensure there's no additional cost incurred for facilities or trucking. This change reduces the number of wells online in the first quarter due to the larger pad activity, but is the right value-based decision and enhances our total-year production delivery. First quarter production has been impacted by early January freezing weather by approximately 2,000 BOE per day. But again, this does not change our strong outlook for the year. We've provided a quarterly production range for 2018 to help follow our progress as we're set to achieve approximately 45% production growth from 4Q 2017 to 4Q 2018. On slide 22, we provided details on our 2018 Permian Resource capital program. Consistent with our cash flow breakeven plan, our capital for the year is $1.9 billion. We will operate a total of 11 rigs and fund an additional two net non-operated rigs. We plan to appraise at least six new benches across our development areas that will provide future growth opportunities. We will also start realizing the benefits of Aventine, our maintenance and logistics hub, which is now online with sand delivery and will be fully operational by the end of the second quarter. The partnerships created as part of project Aventine will provide efficiencies and allow better margins for OXY and our partners. Our initial savings target per well from project Aventine is between $500,000 to $750,000 per well, but we believe the full value implications are much higher as we expect improvement in time-to-market, last mile and well site logistics, safety and future operating costs. We will also continue progressing unconventional EOR pilots and implement new pilots in 2018, and will provide updates and share results as we can. 2017 was an incredible year, and we're even more excited and confident about 2018. Thank you, and I'll now turn the call over to Ken.
Kenneth Dillon - Occidental Petroleum Corp.:
Thanks, Jody, and good morning, everyone. We had a strong year in the international business with our achievements summarized on slide 24. The focus of the business during 2017 was twofold. First priority was cash generation which the upstream business delivered to the tune of over $1 billion in free cash flow. Second priority was continuing to develop a pipeline of potential projects in our core countries. This inventory is focused on strong returns for OXY and our partners. It builds upon our operational excellence in our core countries, including the use of the latest 3-D seismic technology and drilling successes in Oman and Colombia. Our major projects continue to be delivered on-time and on-budget as shown on slide 26. And we did all of this while achieving the best international HES performance in OXY's history. There are a number of topics that I'd like to mention today. First is the debottlenecking of the Al Hosn Gas plant which will begin during the first quarter and be completed in the second quarter 2018. Last year, during our annual turnaround, we were able to optimize the gas plant for no additional capital. This contributed to the increase in production from 64,000 BOE per day in 2016 to 71,000 BOE per day in 2017. This year during the turnaround, we will debottleneck the plant for an additional 11% in production from fourth quarter 2017 to third quarter 2018 for only $10 million of capital. This debottlenecking will bring the cumulative expansion versus the original plan to approximately 30%, as shown on slide 25. Production during the first quarter will be approximately 59,000 BOE per day, and we will achieve a peak rate of approximately 83,000 BOE per day in the third quarter. We're able to achieve this by utilizing a new patent-pending process to modify the inlets to the plants absorbers. Next, I'd like to talk about the continued consolidation of our position in Northern Oman. We successfully renewed our Block 9 contract and we recently signed an exploration and production sharing contract for Block 30, which enhances our position. We see opportunities for gas production in the area and synergies with our adjacent position in Block 62. I'd like to highlight the performance of several projects in Colombia. In December, we reached a milestone of 45,000 barrels a day at the La Cira-Infantas field. This was achieved just ahead of the 100th anniversary of the discovery well, and we're excited about the continued development of the field. The TECA Steamflood pilot continues to exceed our expectations, and a development project will be moving towards sanction this year. The project exceeds our international economic hurdle rates. Both of these projects are excellent examples of our organization's expertise in enhancing the recoveries of mature and complex fields. Lastly, we've been successful with our step-out drilling programs in Oman and Colombia, which have added over 50 million barrels of net resource in the two countries. I'd like to thank the team for its disciplined work and commitment to safety. We're very pleased with how the business performed in 2017 and excited about the opportunities in our pipeline. I will now turn the call back to Vicki.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Ken. I'd like to close by commenting on executive compensation since we've been engaging with the investment community on this topic. We have expanded the use of returns-based metrics for executive incentive compensation. The changes will impact both our short and long-term incentives by incorporating cash return on capital employed as a key performance target, with a short-term target of 18% and a long-term target of 20%. At our 2018 target compensation level, cash return on capital employed-based compensation will comprise about 20% of the total. This policy is consistent with our historical practices at OXY and improves alignment with our shareholders. We'll now open it up for your questions.
Operator:
Ladies and gentlemen, at this time we'll begin the question-and-answer session. Our first question today comes from Roger Read from Wells Fargo. Please go ahead with your question.
Roger D. Read - Wells Fargo Securities LLC:
Yeah. Thanks. Good morning. If we could go to slide 4, the talk about well productivity improvement. And I was curious, is there a way that you could break that out at all between just changes in physical things like lateral length and the number of stages versus – you've mentioned multiple times, the improvement in well productivity, how much of that is a design change or better rock, or you know, all the opportunities that are there?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yes, Roger. Good morning. This is Jody. It's really a combination of both. If you look at lateral length in 2017, it's about a 10% increase in overall lateral length. But our productivity improvement is on the order of 20%. And you have to remember this is based on a six-month cumulative, so a lot of the good wells that came online in the back half of the year aren't yet included in that improvement number. So it's a little bit lateral length, but a lot about, again, how we land these wells, the flow unit work that we do to optimize where we place them, and then continued completion design changes to increase stimulated rock volume. But it's a combination of both, but more performance-driven than lateral length-driven.
Roger D. Read - Wells Fargo Securities LLC:
All right. Thanks. Can I get you to hazard a guess on continued improvement on productivity at all or any sort of an internal target?
Joseph C. Elliott - Occidental Petroleum Corp.:
I don't know if I can throw a number out. I mean, I get surprised every day with the improvements our teams continue to make. And I see some of the technology things we're working, whether it's in the execution side or on the completion side, and I still think there's more ahead. We've got some new frac designs coming out this quarter in Greater Sand Dunes, and I think those are going to lead to even better rates. And in addition to better rates, I think we're reducing our issues with offset frac hits and having to shut wells in because of doing frac work nearby. So not only are we trying to improve performance, we're trying to minimize the base production that's already online.
Roger D. Read - Wells Fargo Securities LLC:
Okay. Kind of getting rid of the parent/child issues we've seen elsewhere then.
Joseph C. Elliott - Occidental Petroleum Corp.:
Exactly.
Roger D. Read - Wells Fargo Securities LLC:
Okay. And then maybe just changing direction with my follow-up. I don't know for you, Vicki, or for Cedric. With the company now certainly line of sight to the breakeven at $50 or effectively there at current prices, how do you think about the dividend or share repurchases as the company moves out of 2018 and into 2019? What's the preferred method for shareholder returns here?
Vicki A. Hollub - Occidental Petroleum Corp.:
Well, we prefer dividends, because the dividends are given directly to the shareholders, and it's often hard to predict the impact of the share repurchases. But we have done a lot of share repurchases over time, as we showed you in the graph, but the way we kind of look at it is we do it when we think it makes the most sense and adds the most value. And we sort of do that calculation by looking at the value of the Chemical and Midstream businesses and taking that from the total value of the company, but including debt and cash levels, then you divide that by your total proved reserves. Then when you compare that to your finding and development cost for the projects that you're in and, in that scenario, we would go today investing more in the projects that we're doing. But with that said, in those scenarios where we have incremental cash, and we don't want to accelerate our pace of development because that would potentially destroy value, in those scenarios, assuming our stock is a little bit lower than normal, those would be scenarios that we buy shares back into the company, and you've seen us do that. So that would be something that we certainly would consider doing. We never want to talk about it in advance, because we don't want to let others know that we're doing it. We want to make sure that we eliminate the potential of others buying our stock as we've talked about buying it back. So we think this approach, as we consider that limits our natural bias to think that the stock's always undervalued and it makes the calculation pretty straightforward.
Roger D. Read - Wells Fargo Securities LLC:
All right. Appreciate that. Thank you.
Operator:
Our next question comes from Brian Singer from Goldman Sachs. Please go ahead with your question.
Brian Singer - Goldman Sachs & Co. LLC:
Thank you. Good morning.
Vicki A. Hollub - Occidental Petroleum Corp.:
Good morning.
Brian Singer - Goldman Sachs & Co. LLC:
As we think about the path to achieving that $50 breakeven, I wanted to just focus a bit more on your expectation to reduce well costs in the Delaware, in particular, which I think you have on slide 53. Based on your contracts, how exposed are you to market inflation risk relative to what you have in the slide? And can you also talk a little bit more about the drivers of the design and efficiency improvements and the risk there to the upside and the downside?
Joseph C. Elliott - Occidental Petroleum Corp.:
Hey, Brian. This is Jody. The slide 53 is one example of a well type in New Mexico. It's a 2nd Bone Spring 10,000-foot well. It's a three-string design, assumes 2,000 pounds per foot in the completion, includes everything, its hookup, flowback, first artificial lift, capitalized overhead, so it's an all-in capital cost. We see pressure on inflation, obviously. It's probably in the 5% range in the drilling area and more like 10% to 15% in the completion space. But with securing our resources in 2017, we're separating sand from pumping service and now with the startup of Aventine in 2018, we see our ability to offset and even drive down cost in an inflationary period. This is something we started a couple of years ago when we looked back at what really drove our improvements back then, and anticipating an inflationary cycle, what would we do different. So we focused on maintaining time to market, securing supply, securing resources, working the things that drive time to market because they're a much bigger part of the equation than just unit cost. And I could talk for a long time about Aventine, but there's a lot of things in place not just sand delivery but oil country tubular goods on rail instead of truck, the OxyChem hydrochloric acid facility, our work with Schlumberger there, a new sand delivery system for the last mile logistics that will drive down trucking and reduce the number of people required on location. So I'm just naming off a few. There's a long list of things that we believe continue to improve the cost structure, the capital intensity of our work in the unconventional business.
Brian Singer - Goldman Sachs & Co. LLC:
Thanks. And I know this is just one example, but are well cost reductions of this type of magnitude baked into the $1.9 billion capital budget for Permian Resources or would achievement lead to lower capital needs relative to that?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yes, we've baked in kind of flat from where we are today. So I think there's upside opportunity as we work through this next generation of technology. So some of those are in there that's in our flat assumption, but we're just getting started with Aventine.
Brian Singer - Goldman Sachs & Co. LLC:
Thanks. And then can you talk a little bit more about the six new benches you're planning to appraise in the Permian in 2018, and how the acreage you plan to evaluate compares to the new acreage that I think you said added 150 locations in 2017?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, it's 1st Bone Spring, Avalon, 2nd Bone Spring Lower in New Mexico, 2nd Bone, 3rd Bone, Wolfcamp C and Greater Barilla Draw. Greater Barilla Draw is 50,000 net acres, so success in those other benches really gives you a lot of scale to work with.
Brian Singer - Goldman Sachs & Co. LLC:
Great. Thank you.
Operator:
Our next question comes from Phil Gresh from JPMorgan. Please go ahead with your question.
Vicki A. Hollub - Occidental Petroleum Corp.:
Phil, could you hold just a second? We did have another comment from Ken, international.
Kenneth Dillon - Occidental Petroleum Corp.:
Yes, just to follow on from Jody, on the international side, same drivers for us internationally, market forces and OXY in-house technology, we still see deflation continuing in drilling and completion arena at the moment, mainly because of the discipline of the NOCs and IOCs in this market, but also the entry of some new competition in the various product lines. We rolled out OXY Drilling Dynamics 3.0 at the start of 2018, we're making modifications to our drilling rig fleets and hardware, software and data analytics. If you look year-on-year in Oman North and in Colombia, we've reduced costs in Oman North by 12% and 26% in Colombia in these product lines. And if you look over the last three years for ourselves and our partners, we've saved over $420 million in the drilling and completion side and we're hoping that, that will continue this year.
Vicki A. Hollub - Occidental Petroleum Corp.:
Okay. Phil, good morning.
Phil M. Gresh - JPMorgan Securities LLC:
Good morning. First question coming back to capital spending, this year you're at $3.9 billion, which is towards the upper end of the range you had talked about previously of the $3.6 billion to $3.9 billion. Obviously, there's accelerating production growth that comes with that. But I guess I'm kind of wondering as we look ahead, Vicki, you've talked about a commitment to have a meaningful step down in CapEx in 2019 on the back of hitting the breakeven. So just want to get your latest thoughts on that. And you talked a bit about the various tradeoffs in your opening remarks, but is there a specific commitment you're thinking about or a roll-off of infrastructure spending or anything that will be driving CapEx materially lower next year?
Vicki A. Hollub - Occidental Petroleum Corp.:
Well, once we get to the breakeven plan, we're still going to go back to our original 5% to 8% growth. We're forecasting 8% to 12% this year but next year in 2019, we'll target the 5% to 8% growth. And targeting that growth with our dividend means that we'll certainly be able to reduce our CapEx below where it is today and back more toward the $3.4 billion to $3.45 billion range.
Phil M. Gresh - JPMorgan Securities LLC:
Okay. Got it.
Cedric W. Burgher - Occidental Petroleum Corp.:
Phil, this is Cedric. I would just add, as I said in my prepared remarks, once we complete the plan, we will be able to live within cash flow, including and cover the dividend, even as low as $40. And so part of the answer to your question depends on what the commodity price environment will be going into 2019. But we will have that ability even at low commodity prices to sustain our base and the dividend all within cash flow.
Phil M. Gresh - JPMorgan Securities LLC:
And if I could just ask maybe a clarification for my second question. There was a comment about higher international spend in 2019, and I heard some of the prepared remarks there, but what's the order of magnitude that would be baked into the $3.4 billion to $3.45 billion?
Vicki A. Hollub - Occidental Petroleum Corp.:
So it wouldn't be significant, because what we have in Oman and some of the international operations are these shorter cycle projects that actually could – we could vary that. We can almost vary like we do the Permian in terms of picking up rigs and activity levels. Ken, did you have an additional comment on that?
Kenneth Dillon - Occidental Petroleum Corp.:
Yes. Part of our focus this year is picking up on the exploration wells and step-out wells that we did last year. We've added 50 million barrels of net resource. Our goal is to call these up this year, get them online. So some of the capital in Colombia will go towards that.
Phil M. Gresh - JPMorgan Securities LLC:
Okay. Got it. And then my second question is around the OpEx for the U.S. The guidance of $12.50 a barrel. It's a little bit higher than my model, not hugely so, but given that the incremental – the resources barrels are coming on I think at $2 to $3 per barrel that you've talked about in the past. And I think 4Q ended sub-$8 a barrel. So I'm just trying to understand maybe some of the moving pieces there, and if you have any color about where the EOR cost is given the higher oil price et cetera?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, Phil. It's Jody. So in Resources, we exited fourth quarter with OpEx of $7.63. We expect operating expense in 2018 to be below $7, more like $6.75. We'll exit 2018 below $6. So that additional production growth will continue to drive down Resources OpEx. On the EOR side there's two components. The fundamental – the things we control on rig work and those kind of things is pretty flat. The two things that move with oil price, one is there's some CO2 contracts that are indexed to oil price, or part of the contract is indexed to oil price. So as oil price goes up, the cost of CO2 goes up. The other is we're injecting about almost 3% more CO2 this year in 2018 than we will in 2017. As you know we've started a new flood and we've expanded several others, and so that's consuming the CO2 on the front end, and obviously the production comes as you go through the lifecycle of those projects.
Phil M. Gresh - JPMorgan Securities LLC:
Got it. So EOR is closer to $20 then per barrel?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, I don't have the number right here in front of me. We'll get it to you.
Phil M. Gresh - JPMorgan Securities LLC:
Okay. Thanks a lot.
Operator:
Our next question comes from John Herrlin from Société Générale. Please go ahead with your question.
John P. Herrlin - Société Générale:
Yeah. Hi. Thanks. Most everything's been covered. I was just curious about the EOR activity in Permian Resources, what you're expecting to get out of the wells by pursuing that. And then the other one is on the Aventine venture. Will this be your only joint venture? Like Schlumberger mentioned the joint venture on their call with you, or working with you, I was wondering are you going to do more of these corporate things to help manage costs in the future? That's it.
Joseph C. Elliott - Occidental Petroleum Corp.:
Sure. Be glad to talk about both. So the EOR work in the unconventional space, when you look at primary production, you're recovering 8%, 10% of the production. So there's a tremendous resource there. So the objective or the challenge is how can we increase that materially and do it economically. And so with either CO2 injection or miscible gas injection, both in the lab and in the trials in the field, we've demonstrated we can recover incremental oil. And it doesn't behave like the traditional conventional CO2 flood where you inject then you push oil to the producers and it's a long cycle project. The oil recovery is actually quite quick, so it has a short cycle nature to it. So the objective is to continue to do pilots and understand how we take it from pilot to full scale, and then how that affects development plans in the unconventional space going forward.
John P. Herrlin - Société Générale:
So is this fracture or matrix porosity you're dealing with (54:04)?
Joseph C. Elliott - Occidental Petroleum Corp.:
Your matrix permeability is micro. It's not matrix. It's a function of the unconventional geology and whether you're in a sandstone or whether you're in a shale, so the behavior's different. That's all part of the learning that we'll talk about more as we're ready to disclose more of the details.
John P. Herrlin - Société Générale:
Great.
Joseph C. Elliott - Occidental Petroleum Corp.:
With regard to Aventine, Aventine is multiple companies at that site. So Aventine is set up to support Greater New Mexico, all the way from Turkey Track and then our Greater Sand Dunes area. And so it's pumping service, it's oil country tubular goods, it's sand transload, sand delivery. It's a new sand last mile logistics system called SANDSTORM. It's the OxyChem ACL facility, and that's just where we're starting. With Schlumberger, it's frac, it's drilling tools, it's cementing, and it's providing logistics improvements by the location. In the Texas Delaware – so you treat each area based on what the current infrastructure is. In the Texas Delaware, it's really more about securing transload. And so we don't have the full scale buildout of an Aventine-like facility, but we have transload secured. It's closer to the regional sands in Texas. Our sand provider has a regional sand mine that will be opening shortly, and so we'll take advantage of that in the Texas Delaware. And in the Midland Basin, really, the infrastructure is pretty good; it's just really securing supply of sand. To give you just a couple of stats on the New Mexico impact, you think about the proximity of that to the well sites. It's a 60% reduction in the number of miles driven. You go from almost 20 million miles to 8 million miles. And then, when you put in the new SANDSTORM system that we're starting up this year, we can haul 27 tons of sand per load versus 22 tons. You do that math, that drives another 1.3 million miles out of the equation. So it's 33,000 fewer truckloads over a five-year period. It also reduces 9,000 metric tons of CO2. You think about accident statistics. It will improve our safety. And then, the new SANDSTORM system, that's really the last mile part of this, reduces the number of people required on-site, because of the automated nature of the way it works. So that SANDSTORM technology would apply both in New Mexico, Texas Delaware and Midland. And then, the logistics hub design and complexity varies as you move across those three areas as well.
John P. Herrlin - Société Générale:
Great. Thank you.
Operator:
Our next question comes from Pavel Molchanov from Raymond James. Please go ahead with your question.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Thanks for taking the question. I know you don't generally give guidance by oil versus gas, but as we think about Permian Resources up 40-plus percent this year, is it going to be a broadly parallel increase between liquids and gas? So, in other words, the gas/oil ratio, is it going to remain broadly stable throughout the year?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah. Pavel, this is Jody. In 2017, our oil cuts were kind of on the 60% – right around 60% and it actually increases a little bit to 61% for total of 2018. So your mix stays about the same.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Okay. Helpful. And then, a quick one on Colombia. We've seen a lot of headlines, January in particular, about pipeline attacks affecting a number of the major fields in Colombia. To what extent is your Q1 international guidance affected by that?
Kenneth Dillon - Occidental Petroleum Corp.:
I think the best way to answer is to look at our production last year. In Q1 2017 – since Q1 2017, our production's remained steady quarter-by-quarter. That's thanks to a lot of work in the field and excellent collaboration with our partner Ecopetrol and the full support of the Colombian government, and we're planning to continue with the same approaches in 2018.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Okay. But I guess how many BOE a day have you lost year-to-date, for example, in Colombia, if you can share that?
Kenneth Dillon - Occidental Petroleum Corp.:
I think it's basically a variation on the answer I gave a moment ago. Our production from our areas is basically steady at the moment. And it's mainly as a result of the work that we've done with the government and with Ecopetrol. We're not seeing major impacts on our fields at the moment.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Okay. Fair enough. Appreciate it.
Operator:
Our next question comes from Leo Mariani from NatAlliance Securities. Please go ahead with your question.
Leo P. Mariani - NatAlliance Securities LLC:
Hey, guys. I was hoping you could talk a little bit about the way you're sort of splitting up capital in the Permian Resources division this year, really between just Midland and Delaware. I don't know if I had this right, but I think I was seeing maybe roughly one rig in the Midland and 10 in the Delaware. Is that something you're going to sustain this year, or is that going to move around? Can you just kind of talk about that broadly in terms of how you're thinking about Permian Resources capital over the next couple years with those two sub basins?
Joseph C. Elliott - Occidental Petroleum Corp.:
Yeah, you can kind of look at it two different ways, you can look at wells online, you can look at rig count. If you look at wells online, it's about 55% in New Mexico, 30% in the Texas Delaware, and about 15% of the wells in Midland. And that probably stays fairly consistent throughout the next couple of years. From a rig – we're running 11 rigs operated, again, that's about 6 in New Mexico, 4 in Texas Delaware and a rig or 2 in Midland, so I don't see that changing drastically. But again, we're continuing to develop inventory, learn new things. Turkey Track's a great example. We thought we had a single bench 2nd Bone Spring development there. Turns out we've got two. So as we learn more and we change how we think about our inventory, obviously, that could adjust. And I want to go back to Phil's question, he asked about OpEx and EOR. It's about $19 a barrel.
Leo P. Mariani - NatAlliance Securities LLC:
All right. And then maybe could you talk a little bit about plans for Oman Block 30? I think you guys recently signed that late last year. Are you starting to see incremental capital there in the budget in 2018? When can we start to see some incremental production? Is it going to be largely oil targets? I think you guys had mentioned gas potential as well in Oman. So kind of what can you say about that as it develops over time?
Kenneth Dillon - Occidental Petroleum Corp.:
Yeah, I think as you can see from the map on slide 24, Block 30 fits perfectly into the Oman North jigsaw. There's currently three discovery wells on the block and two reservoirs that we're completely familiar with due to the work in the other blocks. We have the same approach internationally as we have domestically. The goal is value, not just driving up production. So the short-term plans are basically to reprocess the existing seismic on the block, come up with a development plan and start drilling probably towards the end of this year, and have some production next year. So relatively small amounts of capital invested this year, mainly study work and coming up with a value-based development plan.
Leo P. Mariani - NatAlliance Securities LLC:
All right. That's really helpful. And last thing you mentioned, portfolio management, $0.5 billion to $2 billion. I guess it's kind of an ongoing thing for you guys. Do you see anything on the horizon here in 2018 where you might look to sell down any of your assets or is that just something that's out there and might take several years?
Vicki A. Hollub - Occidental Petroleum Corp.:
Well, certainly for our core assets, we're satisfied with where we are. The only thing that we're continuing to do is look for things, assets that are way out in the inventory and the Permian. So things that we can't get to any time soon, and when I say soon that's like 10 to 15 years, or that's non-strategic for us, we would certainly consider to sell or monetize, anything that's non-core for us and, of course, we still have the Plains units that we can monetize.
Leo P. Mariani - NatAlliance Securities LLC:
Thank you very much.
Vicki A. Hollub - Occidental Petroleum Corp.:
All right. Thank you.
Vicki A. Hollub - Occidental Petroleum Corp.:
So I want to thank you all for your questions, and I'd like to leave you with three takeaways from our call. First, we're ahead of schedule with our breakeven plan, but we're still focused on optimizing delivery across all of our businesses. And second, we're disciplined in our reinvestment and we'll provide additional security to our dividend through net debt reduction. Lastly, our expanded use of returns-based incentive metrics align our executive comp with shareholder priorities. So we're looking forward to the rest of 2018. Thank you for joining our call, and have a good day.
Operator:
Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending. You may now disconnect your lines.
Executives:
Richard Jackson - VP, IR Vicki Hollub - CEO, President and Director Joseph Elliott - SVP and President, Domestic Oil & Gas Cedric Burgher - CFO Ken Dillon - President, International Oil and Gas Operations
Analysts:
Evan Calio - Morgan Stanley Douglas Leggate - Bank of America Merrill Lynch Paul Sankey - Wolfe Research Philip Gresh - JPMorgan Chase & Co. Guy Baber - Simmons & Company International Brian Singer - Goldman Sachs Group Douglas Terreson - Evercore ISI
Operator:
Good morning, and welcome to the Occidental Petroleum Corporation Third Quarter 2017 Earnings Conference Call. [Operator Instructions]. Please note this event is being recorded. I would now like to turn the conference over to Richard Jackson, Vice President of Investor Relations. Please go ahead.
Richard Jackson:
Thank you, Kate. Good morning, everyone, and thank you for participating in Occidental Petroleum Third Quarter 2017 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Jody Elliott, President of Domestic Oil and Gas; Ken Dillon, President of International Oil and Gas Operations; and BJ Aber, President of OxyChem. And just a moment, I will turn the call over to Vicki Hollub. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our third quarter 2017 earnings press release, the Investor Relations supplemental schedules and our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I will now turn the call over to Vicki Hollub. Vicki, please go ahead.
Vicki Hollub:
Thank you, Richard and good morning, everyone. Before I get started on our third quarter results, I'd like to take the time to think and express my appreciation to our entire Oxy family in prevailing through Hurricane Harvey. We had hundreds of family members that were displaced due to the storm or experienced serious damage to their homes and personal possessions. Even in the face of this destruction, we were able to operate one of our assets safely and we have returned our business to normal operating rates. The teamwork across our organization was incredible. Oxy employers that were need of assistance received help from all parts of our organization from the Permian and chemical sites throughout the U.S., through our international employees who provided assistance from the Middle East and Colombia. I have never seen such unity among all of the parts of our organization and from our retirees. This storm was devastating to our Texas Gulf Coast community, but our organization was prepared for the storm and its aftermath. The financial impact would have been weighted without our team's efforts to enact our business continuity plans and manage the business during and after the storm. Times like this made me really proud to be part of this organization. I will now share some third quarter highlights on Slide 5, and then I'll provide an update on our progress towards our cash flow breakeven plan. Let's start with our most recent well result. While I don't want to steal this thunder from Jody, we've had some real exciting results in Southeast New Mexico. We attribute these new basin-leading well results through our value-based development approach. We're confident in our ability to sustain these results as well as in our ability to reach and surpass our breakeven growth targets of 80,000 BOE per day in Permian Resources. I'd also like to highlight the improvements we've made to our Seminole-San Andres CO2 unit. Since acquiring the asset in August, we've been able to increase our throughput capacity of the plant by 10%, which has enabled us to increase gross production by 2,300 BOE per day. We not only got a great asset, we got great people as well. Their integration into our plant and field operations teams has created the strong group that is already ahead of our plan. And I can assure you, the leaders of our field and plant teams don't set easy targets. Those teams are energized and performing at a very high level. Despite the impact of Harvey, chemicals had a strong quarter, generating $200 million in segment income. We received our first dividend from the Ingleside Ethylene Cracker JV, and our team continues to capture additional margin along the chloro vinyl chain. We expect this trend to continue due to improving industry fundamentals as well as a tighter supply market in the near term due to Hurricane Harvey. Turning to Slide 6. As I mentioned in last quarter's call, we will include this slide each quarter to update you on our progress towards our goal of cash flow neutrality at $40 WTI and breakeven at $50 WTI. This means we'll cover the dividend and the production sustaining capital within operating cash flow at $40 WTI, and at $50 WTI we'll be able to generate 5% to 8% production growth. As you might expect from Harvey negatively impacted our progress for the quarter. Even since so, all of our assets and teams showed progress towards their targets. Slide 7 illustrates this progress. We have included the annualized cash flow impact of $200 million for Harvey in the first gray column. This cash flow impact is a one-time event. And as I just mentioned, in the chemicals business, we received our first dividend payment of $55 million from our Ingleside Cracker JV. This included catchup for the prior quarter. We expect the ongoing quarterly dividend to average $30 million to $40 million. The remainder of chemicals target will be able to achieve that after the 4CPe repurchase plan comes online in the fourth quarter of this year. In the midstream business, we benefited from a wider Midland to Gulf Coast spreads, averaging $2.61 per barrel during the quarter. This exceeded our expectations. The segment has achieved over $200 million in annualized cash flow improvement. Additional milestones to achieve our midstream target of $300 million included the Al Hosn expansion and maximizing throughput at our Ingleside Crude Terminal. In the Permian Resources business, we grew 1,000 BOE pretty sequentially, net of the 4,200 BOE per day that we divested as of August 1. We expect our growth rate to increase substantially in the coming quarters as we have accelerated our activity. Jody will give additional guidance on the timing of new wells coming online. Finally, with respect to the improvements beyond our initial plan, the chemicals in the EOR businesses are experiencing operational end market improvements. Chemicals continue to capitalize on a strong pricing environment. Caustic soda prices, the primary profitability driver, have increased by approximately 14% since the first quarter of 2017. This price improvement equates to $120 million in annualized cash flow improvement. In the EOR business, we'll continue to improve the operations of the Seminole-San Andres CO2 unit, and expect to achieve the cost reductions of $5 to $10 per BOE that we previously mentioned. We are pleased with the progress we've made and we'll continue to communicate incremental progress towards our pathway to breakeven. My final slide quantifies the liquidity we have available to fund the gap between cash flow from operations and the capital needed to achieve our goal. I'd like to remind you that our preliminary capital budget for 2018 is in the range of $3.6 billion to $3.9 billion as presented in Slide 8. At the end of the third quarter, we had $1.8 billion of cash as well as PAGP units with a market value of approximately $600 million. Since WTI has averaged closer to $50 during 2017, we added an additional bullet to this slide to how a smaller cash modems that of less than $2 billion. We plan to manage our portfolio to contribute an additional $500 million to ensure we bridge the cash gap if prices average $40 through 2018. So to be clear, even with an average oil price of $40 versus 2018, we have sufficient cash and liquidity to cover sustaining capital and the dividend while also funding our path to our $50 breakeven at WTI price. I'll now turn the call over to Cedric Burgher.
Cedric Burgher:
Thanks, Vicki. Jody will cover our step-change in a in Permian well results, so I will address financial address updated guidance. We present our third quarter results on Slide 10, and I'd like to start recovering on a production results. Total reported an ongoing production was 600,000 BOEs per day, which came in at the low end of our guidance range. Reported production was impacted by Hurricane Harvey, also third-party downtime in Columbia in the Middle East and downtime at the Permian EOR plant. The Permian Resources production came in within our guidance range at 139,000 BOEs per day despite losing about 1,000 BOEs per day from the impacts of Hurricane Harvey. Permian and EOR production was 150,000 BOEs per day at the end -- at the high-end of our guidance range. Higher Permian EOR volumes sequentially reflect the successful integration of the Seminole-San Andres CO2 unit, and we expect to capture additional production volumes with the increased gas plant throughput. International production came in at 303,000 BOEs per day, which included the highest quarterly production rate at Al Hosn Gas of 76,000 BOEs per day. Third quarter reported EPS was $0.25 per share and core EPS was $0.18. Quarterly EPS improved sequentially despite the impacts of Hurricane Harvey. Improvements in the oil and gas segment were mainly attributed to lower operating cost of $0.61 per BOE and to higher NGL prices by $1.83 per BOE. Domestic operating costs for the quarter were $13.23 per BOE versus $13.55 in the second quarter, and they continue to stream lower. Permian Resources operating costs have averaged 3% lower year-to-date versus the 2016 average, and we expect these cost to trend lower with our production ramp-up. Operating cash flow improved sequentially as well to nearly $1.1 billion. The improvements to operating cash flow where maybe attributed to incorporation of the Seminole-San Andres CO2 unit in the Permian EOR as well as receipt for cash distributions from the ethylene cracker joint venture. We spent approximately $950 million our capital program during the third quarter, and we expect to spend roughly $1.1 billion in the fourth quarter with total year capital spend expected to be at all our $3.6 billion capital budget. Additionally, we expect to come in at the midpoint of our previously stated $1.6 billion to $1.8 billion capital range for the Permian Resources in 2017. With respect to our effective tax rate, the lower Q3 rate was mostly driven by our international assets. There are 2 primary reasons here. First, in Qatar, we were able to reduce operating costs by approximately $20 million -- and our production sharing contract allowed us to take 100% of that savings to the bottom line without additional tax. Second, we are recovering an additional $11 million related to our former business in Iraq with no associated foreign tax. In addition to those items, there were some smaller domestic items, which had some benefit in the net benefit in the quarter. OxyChem's third quarter earnings of $200 million were better-than-expected considering the $60 million impact of Hurricane Harvey. Favorable pricing and plan operations and lower raw material costs prior to the hurricane partially offset the negative impact the storm had on chloro vinyl production and plant maintenance. We have updated several slides on our chemicals business in the appendix, including additional information on the 4CPe plant which will come online during the fourth quarter. Midstream's third quarter came in within our guidance range excluding the impact of Hurricane Harvey and lower equity income from our investment in the planes pipeline. The business experienced exceptional performance during Harvey and achieved the highest monthly loading rates at our oil terminal in September. We included additional information on our Midstream business in the appendix as well, including a slide with our outlook for Midland to Gulf Coast spreads. On Slide 11, you can see that we continue to have ample liquidity to fund our breakeven plan with a cash balance of $1.8 billion. While our cash flow from operations is currently at a deficit to our capital expenditures and dividends, we expect this gap to narrow in the coming quarters and to be on balance by the end of 2018 at $50 WTI while our assets are generation -- generating production growth. Let me reiterate what Vicki said in regards to liquidity. We forecast our cash deficit to be less than $200 million through the completion of our plan, assuming average WTI prices of $50. Furthermore, our business is approximately 50% exposed to the Brent benchmark, which gives us additional support if that spread continues to hold at current levels. We have provided updated guidance on Slide 12. We have maintained the bottom end of our full year 2017 ongoing production guidance at 597,000 BOEs per day while lowering the top end of our guidance to 599,000 BOEs per day. Our updated full year guidance reflects actual third quarter production results and accounts for items particularly to the fourth quarter. In the fourth quarter, we will carry out the Seminole-San Andres planned turnaround to further optimize operations, and EOR will be impacted by a planned third-party pipeline maintenance activity. Jody will cover our improved visibility on our fourth quarter ramp-up and exit rate with information on our new wells and drilling progress. Given the improved results in the Greater Sand Dunes development area, we are excited by the trajectory of production heading into 2018. Permian Resources total year production guidance has been narrowed to 141,000 to 144,000 BOEs per day. We expect fourth quarter production in Permian Resources to be approximately 30% higher than fourth quarter 2016. My final point on our oil and gas segment is that we have lowered our annual domestic OpEx guidance from approximately $14 per BOE to $13.50 per BOE as these costs are trending lower due to our highly -- productive wells. Moving on to other areas of our business. Fourth quarter guidance for chemicals is $190 million, which accounts for the seasonality in the business, is due to lower construction activity. Midstream is expected to generate more income sequentially in the range of $60 million to $80 million. The business expects to benefit from wider Midland to Gulf Coast marketing spreads as well as wider Gulf Coast to Brent spreads, which enhances our export margins. Lastly, I would like to remind you of our commitment to our returns-focused strategy. Last quarter, we told you that we will be increasing the amount of compensation that is tied to returns or return on capital employed metrics. Our minimum hurdle rates are 15% after-tax in the United States and 20% internationally, which we believe will result in leading full cycle returns for our shareholders. I'll now turn the call over to Jody.
Joseph Elliott:
Thank you, Cedric, and good morning, everyone. And thank you, Vicki for your restraint during your opening highlights on our well results in the Permian. Thanks to our team's efforts, we had some basin-leading well results to share with you. Across our domestic business, we're delivering more production with less cost to generate growth and value towards our breakeven plan. As Vicki mentioned, we attribute this success to our differentiated value-based development approach. Our Permian Resources New Mexico team delivered record-breaking well results across multiple benches in the Greater Sand Dunes area as shown on Slide 14. During the quarter, our team put on a total of 7 wells in the Greater Sand Dunes area with 30-day production rates that averaged approximately 3,750 BOE per day. 3 of these wells ranked in the top 15 all-time best wells in the Permian basin based on 30-day BOE per day. Our Cedar Canyon 23 24 Fed 32H achieved a peak rate of 6,497 barrels of oil equivalent which is the highest 24-hour peak rate recorded in the Permian Basin. These record results span to second Bone Spring, the third Bone Spring and the Wolfcamp X-Y, which makes the Greater Sand Dunes area extremely attractive from a full-cycle returns perspective. Our engineered approach gives us confidence in the repeatability of these results across the 2,000 remaining undeveloped locations in the Greater Sand Dunes area. We've not yet incorporated this improvement into our Permian Resources inventory counts, but we expect to breakevens to improve by $5 to $10 in the Greater Sand Dunes area. While the focus of Slide 14 is our Greater Sand Dunes develop area, our Texas Delaware team also delivered Oxy record wells in the Wolfcamp B, and the second Bone Spring and our Greater Barilla Draw area, which are highlighted in our appendix on Slide 27. Our step-change and well performance as a result of ongoing subsurface characterization and customized well designs to maximize the potential of our plate-leading asset. In fact, our teams are studying results from surveillance to make additional improvements across the basin. In addition to these stellar productivity results, we saw improvements on the cost side. OpEx decreased 7% from a year ago to $7.61 per BOE during the quarter, and well costs continue to trend approximately flat as operating efficiencies and offset inflationary pressure from service and materials providers. On Slide 15, we provide visibility on the timing of wells online for our production ramp over the next 3 quarters. As a reminder, we added 4 Permian Resources rigs very late in the second quarter. We'll begin to place the majority of the segmental wells online in the fourth quarter with peak rates reach late in the year and into the first quarter. We'll also shift more activity to Greater Sand Dunes, increasing wells online in the second quarter of '18 to 26 from the 7 in the current quarter. We'll ship 1 to 2 rigs to the Greater Sand Dunes area at the beginning of 2018, while maintaining a total of 11 operated rigs. Our Permian Resources production in the third quarter grew modestly due to divestitures and third-party impacts from Hurricane Harvey. We expect to see strong growth in the fourth quarter and into 2018 that will generate the cash flow that Oxy needs for the breakeven unit plan. As well results continue to improve and the number of new wells on production increase, we're extremely confident in our ability to deliver on Oxy's cash flow breakeven plan. The plan we have laid out will result in a growth rate above 30% in 2018. Finally, I'd like to speak to the immediate success we've had in capturing value from our EOR acquisition. We became operator of the Seminole-San Andres unit on September 1, and have applied our technical know-how to achieve operational improvements. By optimizing the CO2 throughput of the plant, our team increased the field's production by 2,300-gross BOEs per day. This was 1 component of our operating cost improvement plan, and we're confident in further improvements in our plan to achieve $5 to $10 per BOE and OpEx reduction. Our newly-integrated team is energized with innovative ideas to continue to improve the asset. I'll now turn the call back to Vicki.
Vicki Hollub:
Thank you, Jody. Now I'd like to update you on a change we've made to our leadership team. Rob Peterson, who had served as President of OxyChem since August of 2014, was appointed Business Area Director in our Permian EOR business in mid-September this year. Rob did an exceptional job in Chemicals, but I'd know this I noticed that he also provided great input during our strategic meetings. So we felt that it will be beneficial for the company and for Rob to have them to spend some time in our EOR business. Rob was instrumental in OxyChem's success, and we anticipate to staying positive impact within EOR and oil and gas. Rob holds a Bachelor's Degree in the Chemical Engineering and an MBA in Corporate Finance from the University of Florida. Rob was replaced by BJ Hebert who is on the call with us today. BJ is now President of OxyChem. BJ joined OxyChem in 1991 from Vista Chemicals, and has 30-plus years of industry experience. He knows the chemicals business exceptionally well, and brings a wealth of strategic insight and passion for safety, environmental stewardship and success. BJ's most recent role was Senior Vice President of Basic Chemicals, and he was previously Vice President and General Manager of Oxley vinyls. BJ holds a Bachelors Degree in Chemical Engineering from Merkley State University, and an MBA from Southend Methodist University. I'd like to close by reiterating the timeline for achieving our production growth targets. We expect to add the 80,000 BOE per day by the end of 2018. We are excited about the trajectory of production growth in the upcoming quarters, which will begin with a large rampup of Permian Resources well completions in the fourth quarter and the step-change in well results to materially derisk the timeline for achieving the 80,000 BOE per day. Our teams are focused across our organization to meet and exceed our plan targets in the oil and gas, chemicals and midstream businesses. And finally, we ended the quarter with ample cash on the balance sheet and have liquidity to fully fund our plan while paying the growing dividend. We'll now open it up for your questions.
Operator:
[Operator Instructions]. Our first question comes from Evan Calio of Morgan Stanley.
Evan Calio:
My first question is -- you planned to support the 5% to 8% growth at 50 and funded yield at 40 -- is well understood. How does the higher oil price factoring the model? Meaning, do you use excess cash flow to accelerate the timing to reach our model via permitting resources growth? Or do you return cash to shareholders or further bolster the cash bridge to the model? How does that -- if we could talk to those pieces, if you could.
Vicki Hollub:
Yes. Specifically, the plan is for us in 2018 to lock into our capital plan of $3.6 billion to $3.9 billion. We plan to present the final numbers to our board in December and get approval for the plan for 2018. Then we'll update you on what those specifics are. So we'll be outspending cash flow again but as we said, we had the liquidity to get there. Once we achieved the milestone of breakeven at $50, any excess cash that we have a beyond that really depends on what the situation is. But our cash flow priorities are always to pay our maintenance capital first, followed by dividend. And in today's world, with the opportunities we have for organic growth -- the organic growth is our third priority. Beyond that, it would be acquisitions and the share repurchases. So we always, when we have excess cash, we want to make sure that we assess the situation and the opportunities to make the best decision to deliver value to the shareholders.
Evan Calio:
And second, if I could, the Greater Sand Dunes' performance is really the highlight of the quarter. Could you maybe walk us through what specifically is driving the step-change improvement in well performance? And are there any costs associated with improvements, targeting and subsurface -- is there -- any color there would be helpful.
Joseph Elliott:
Evan, good morning, this is Jody. You hit the high points there. It's really about improve subsurface characterization, which is leading us to better targeting wells to maximize kind of the value recovery from these assets. So it's a culmination of what we've been talking about for a long time -- value-based development, but that again leads to better targeting, better assimilation designs. And what's interesting in these well results is that the sand-loading for these wells is below what you probably find on average in the industry. So from a capital efficiency standpoint, I think that -- it argues even more how confident we are about this growth plan and how much cash we can contribute to the breakeven plan that Vicki has outlined.
Evan Calio:
Maybe just as a follow-up, if I could. I mean how representative do expect these results are across your 2,000 locations -- while it might be early, any thoughts there?
Joseph Elliott:
We think it's very representative. We continue to do appraisal work in other areas of Greater Sand Dunes. What's also exciting about this as is it's across 3 benches, not just 1 bench. I think the other color is -- this is done in an area that's more of a brownfield development, where there are legacy wells that we're having to manage -- offset wells and shut-in wells to avoid implications. As we move into 2018, we move into more of a greenfield area. We're able to take advantage of the latest generation of our field development plan and we're really excited about that, because it includes the startup of Advent team, which will help drive more capital efficiency, rig rates, our legacy rig rates rollup in the market, the field development plan at Sand Dunes is -- and we've got a central tank battery facility with water recycle. Most of the fluids that are being handled there will be on pipe. It's 4-well pad and 6-well pad development -- that includes the ability for us to do simultaneous operations of drilled, complete and produced. And so we believe these well results extend across that inventory and that we're set up for even better capital efficiency with the new field development plan.
Operator:
The next question is from Doug Leggate of Bank of America.
Douglas Leggate:
I guess the focus again is on Greater Sand Dunes well results. I wonder, Vicki, if you could help us understand what's changed as it relates to the timeline of your 80,000 BOE per day target? The wells are clearly substantially better than what you are expecting when you set that target, but you're still talking about a year end 2018 type of cadence. Are you just being conservative there, or is there reason why you're sticking with that timeline? And I've got a follow-up, please.
Vicki Hollub:
No. We may achieve the 80,000 a day earlier than the end of 2018, but there are other drivers like our Al Hosn expansion, our export facility where we are trying to ensure that we're at the full capacity there -- those may take place later in the year. So the timeframe is really intended to capture the point of which all of our improvements are fully in place and to ensure sustainability that we have full margins and that those full margins are being realized for the entire quarter.
Douglas Leggate:
And just to be clear on one of the slides Jody spoke to, you know I believe it is a repeatable, I guess you would never really given this as a tight curve but these results are repeatable across the 2,000 location?
Vicki Hollub:
Yes, we definitely believe that. We just sat through over the last couple of days some reviews of how they're doing this technically. And it's very impressive work. There's no reason for us to believe that this is not sustainable. In fact -- the fact that we have 3D seismic and can take that seismic, tie to the performance that we're seeing -- and now we are deploying where we can predict what the wells will do end where we need to drill. So this is really a breakthrough for us, and I think we're all really excited about.
Douglas Leggate:
We got to see the upclose and a few weeks ago in the field, so thanks, again for that, guys. My follow-up I guess is on portfolio management, Vicki, that -- just eyeballing the chart on the $40 breakeven, which obviously is under bear case, it still implies that you've got a couple of plus-billion dollars of assets sales planned. Does that happen regardless of the commodity backdrop? And if so, just quantify, quantify what you're thinking process the key parts of those -- of that monetization, and I'll leave it there.
Vicki Hollub:
Yes. So we've always said or have said most recently that at some point we'll monetize the plains unit. We will do that at some point but we want to pick the appropriate time to do it. Secondly, whatever environment, it really makes sense for us to continue to optimize our portfolio. And because of this huge position that we have in the Permian Basin, what we want to do first -- our highest priority is to swap acreage because we've had a lot of success blocking the development areas that we have, and we're really happy with that we develop in areas. So the more trading that we can do rather than outright sales is preferred. However, there are some acreage at the tail end of our portfolio that in any environment, we would sell.
Operator:
The next question is from Paul Sankey of Wolfe Research.
Paul Sankey:
Vicki, if I could ask simply a follow-up so early in the call, but could you go back to the idea that Evan had -- what happens given the oil prices above $50, I think you really answer that in the context of 2018 CapEx kind of being at a relatively fixed level. Can you go beyond that and talk about -- I think the longer-term investment case for Oxy that maybe you go the dividend of 5% to 8% a year off the base that you've got now of about 4.6%, that would get even to double-digit returns and conceivably, that would be a $50 assuming you made your plan, at which seems to be making. Could you talk to that and whether or not you see that as that is the investment case for Oxy.
Vicki Hollub:
I think that's a strong investment case for us. It is, as I mentioned -- the maintenance capital is the highest priority, but our second highest priority is the dividend and we continue to do that. We've come as you know, during this downturn, we haven't been able to return to what we were able to do historically, because over the past 15 years, we've more than doubled the S&P growth rates with our dividend growth rate. Going forward, we want to get that back to a meaningful growth and that will be consistent with our production growth.
Paul Sankey:
And then the second follow-up is it sounds a few disposals in acquisitions are going to be pretty neutral to 0, because it will mostly be about swapping and that there's no major portfolio moves to be made -- again, thinking long term.
Vicki Hollub:
There are no major ones, so just optimization of the tail-end.
Paul Sankey:
Okay, I get that. And finally, this is a little bit of a negative, but on a trailing basis -- I know the near new results are great, do you still -- perhaps, a little bit behind the rest of the industry in terms of your Permian performance. Do you see that as having been may be a slow adoption in new technologies, that the history of the company in terms of being -- growth by M&A? Or is it something about your acreage which I know is very extensive? What would you characterize this way you've been and what language you achieve can see this rapid improvement in result?
Vicki Hollub:
Well, it's certainly not the acreage. We have great acreage and -- I think part of it is that our team, we have over the past few years, we've changed our resources business significantly. And what we've been able to do is put the right people, the right leadership in place to approach this in the right way. And so now we're more value-based in terms of how we're doing our resources business, and we've made a breakthrough really taking all the acreage we have, all the information that we have from all of our offset -- operator wells, our outside operated, our offset competitors. We've taken all of that and we've started to apply not only data analytics, but we're applying a more sophisticated subsurface characterization than we have done in the past because honestly, for shale plays, some people initially in the early stages of shale plays thought they were statistical. But clearly, developing shale place in my view requires a lot more science than some of our conventional rest of us. And I think until you get to the point where you realize what you need to do and how you need to do it and what parameters really matter, I think that you can do struggle with that. But we're to the point now where we've done the work, the right work -- and that analytics had the help with that, but just the massive amount of data that we have, we've been able to achieve a breakthrough in terms of what parameters really matter the most, and that's going into our evaluations now. And also the other thing that sets us apart, I believe, from some others is that we are taking our development plan, we're using integrated planning and doing field by field development plans so that we maximize its value. We don't go far, although you heard us talk about initial rates and third end the rates from a really 30-day rates, really that's not the target for us. We're just trying to give you a measure of how good these wells really are. But the target for us is to optimize the value of the full field development. And you really need to focus on initial rates from 30-day rates to do that. But what you need to do is focus on how you build your infrastructure out, how do you pace your development to ensure that you're maximizing the value of the reserves.
Operator:
The next question is from Phil Gresh of JPMorgan.
Philip Gresh:
My first question, I guess, would be a follow-up to Paul's -- maybe ask it at a slightly different way. On Slide 6, where you break out your dividends, your sustaining capital, your growth capital, with all the improvement you've been talking about here in well results. I guess I'm wondering if the underlying required capital from sustaining basis or from a growth basis to hit the 5% to 8%, on longer-term basis, do you think that has a possibility of changing?
Vicki Hollub:
I think the more we learn about what we have and the more efficient we get, I think there is a possibility that, that could come down.
Philip Gresh:
Right, okay. My second question would be -- if I go into your appendix, Slide 48, where you're talking about the chemicals cash flows, you are implying that nearly -- the CFO can be nearly $1.5 billion on a normalized basis. And I guess I was a little surprised by that because I traditionally saw that pretax income for chemicals an annual basis to be maybe $1 billion, the tax effect that add back to the DD&A and you kind of get back to right around $1 billion. So is there something structurally different with the business? Or is there some other kind of cash flow effect there with respect to taxes or something else that drive the higher cash flow?
Cedric Burgher:
Yes, Phil, this is Cedric. I'm going to take a part of that, and then I'm going to ask BJ to come in for the other part. But there is something I guess people caught by surprise and that is some of the nuances with our tax position. But the income generated in chemicals is taxable, of course, but because we are integrated with the other parts of the business, we have domestic losses that are able to offset that. So we have been enjoying a very low, basically no tax position for some time in the chemicals business. We anticipate this situation to continue for some time at the current commodity price levels. So you've got a number of commodifies in play here, you've got the caustic soda prices obviously benefiting. The chemicals business as well as the oil and gas prices affecting the other parts of the business. So all that comes into play when you think about looking out and projecting your tax. But at the current levels, we think we've got sufficient tax losses to offset the chemicals income for the projected time period that we've given you. And then, BJ, do you want to address the other piece?
Unidentified Company Representative:
Sure. Good morning, Phil. This is BJ of our picker talking about chemicals continues to be positive in the market. And from a cash flow standpoint, obviously, there are step-changes with both the cracker and the 4CPe plan that's going to come online. But just from a fundamental standpoint, they're very positive, especially for costs I think you talked about that caustic prices were up 14% since the first quarter to the third quarter. And that was being driven by the fundamentals well before Harvey, and even after Harvey, it's tightened a little bit further. But when you look for a globally, we think the fundamentals are pretty strong for us when you look at the main driver for caustic remain -- consumption for caustic is in the aluminium industry, which is growing 5% to 6% per year. You have capacity coming down in Europe. And so when you look at all that in total, it's pretty strong from a fundamentals standpoint. So that's really what's driving the earnings.
Cedric Burgher:
This is Cedric again. And I want to mention one thing just because it's related. I really perhaps didn't give it due, in my prepared remarks, about our effective tax rate. But what was really cool about that this last quarter was in part, in large part, it was reflecting the operational improvements in cost reductions we've made in the international side of our business. And so Ken Dillon's with us -- and I feel like -- to ask him to just add a few comments about those cost reductions and the improvements we've made internationally.
Ken Dillon:
Phil, this is really a strong story in capital. Field OpEx as at the 7-year low now and it's been driven down by 6% to 8% since 2013. We're the lowest cost operator in country with the best-in-class performance. With our partner QP, we have worked the expense. We've been collaborative in logistics, including shared services, for example, work boots, lift boats and helicopters. And then on the technical side, we upgraded compressive bundles dry gas sales systems, to state-of-the-art improved reliability, performance and costs. We've also rolled out obviously less bleeding to improvements in the ESP run life. And lastly, and not the least, our supply chain team have been very successful in negotiating reductions in contracts of up to 27% for next year. Overall, it's a really strong team monthly performance and a really great partnership.
Philip Gresh:
And then just one last one, Cedric. On the foreign extreme tax rate, your guidance remains 55%, but you've been coming in well below that for the year-to-date, it's in the low 40s, at least on the foreign upstream side. So is that sustainable, or is there something you need to be going on there?
Cedric Burgher:
Well, we haven't adjusted the guidance because there were some were some more or less one-time items via rock lifting, I mentioned in the call -- our prepared remarks -- excuse me, but so that obviously would it be something that we would expect to recur. But of course, we did that, that in the first quarter also. But I really don't see much upside there. But on the operational improvements, we hope and expect that it will continue to improve their but we've not baked that into our guidance so there is some upside there.
Operator:
The next question is from Guy Baber of Simmons.
Guy Baber:
So I wanted to start on the CapEx side, but with the visibility of delivering the cash flow piece of your breakeven plan improving here, maybe we can talk a little bit about the capital spending side. But you're highlighting the sustaining CapEx of $2.1 billion to $2.3 billion going forward. I wanted to talk about how the capital intensity of your international upstream businesses is evolving in particular -- given the changes in your asset base over the last few years, given deflationary pressures and some of the cost reductions that you've highlighted in Qatar, for example, but just curious if you have an estimate of where your international SND might be trending and the degree towards that has improved over the last few years.
Vicki Hollub:
We are seeing improvements. We have seen over the past couple of years continued improvements in what we're doing in the international operations and in particular, in the Middle East. What we're seeing there is as you may have remembered, we required 3D seismic all over our blocks 9 and 27, so we have one of the largest onshore 3D surveys in the world. And we're using that survey to successfully drill wells that they virgin pressure in the field that we discovered a long time ago, 30 -- 35 years ago. And that's really helping us because when you can drill wells in a field that already has infrastructure, that helps you to start to drive down your F&D. We have some other opportunities, and I'm going to throw it over to Ken to provide you more detail on what we're doing there.
Ken Dillon:
Good morning. As you know, we've changed very much over the last few years instead of the large megaprojects or efforts this year, very much focused area similar to Permian. We've loves drilling program at Middle East and then Columbia. And we rolled out Oxy drilling dynamics across the whole region now. What we're seeing is, for example, in Oman North, we've seen a 12% improvement in foot per day, and an 11% reduction in cost per foot, which essentially drives lower F&D costs throughout the region. We just rolled out the same system in Qatar, and we've almost immediately seen a 6% improvement in dollars per foot, and a 7% improvement in feet per day. In terms of using the 3D seismic that we have across Oman, what we're seeing a similar results to Pearman, where our IPs are [indiscernible] than planned, 20% across the whole of international. Basically, we're drilling fewer wells, more productive wells for less capital.
Guy Baber:
And then my follow-up is on the U.S., the 4Q production growth in Permian Resources trajectory into 2018 is obviously impressive. So with the meaningful increase in the number of resource flows as you're bringing online especially in New Mexico, given some of the tightness of the labor market we're hearing about, logistical issues, tightness with services we've seen from others. Can you -- just discuss the confidence and the timing of your planned ramp that you've laid out and how your mitigating some of those risks regarding the timing of the delivery there, given what we've heard from some other operators? And then may be specific comment on 4Q. The guidance range is wide there. Can you just maybe want to talk about what went to get to the lower end or the higher end of that guidance. What the sensitivities are there?
Joseph Elliott:
Hey, Guy, this is Jody. I appreciate the question. This is strong guidance in the fourth quarter and there's kind of 2 catalysts there. Obviously one is the step-change in well results. There's been a significant improvement there. We're taking advantage of those development plans, utilizing 3D seismic, as Vicki outlined -- with respect to how we land the wells and how we stimulate them. The second part of this is the cadence of the wells also online. So as I said in my opening comments there, we added rigs late in the second quarter. We'll start seeing those wells come in and as we enter 4Q and go into the first quarter and as you can see on the chart there, that the well counts are also going up significantly. So there's a couple of aspects there that drive why the range is wide. One is, where you're putting the 3,500 barrel-a-day wells. Those wells take some time to reach peak production, and so when you have that many wells with that kind of the spread and production rate, depending on how -- when the well comes on the 1st of December or the 15th of December can make a big difference in what that quietly production rate this. To me, it's about the trajectory -- the trajectory, fourth quarter, first quarter, second quarter that we have a lot of confidence in. The other aspect is pad drilling. Year-to-date, we're probably 80% pad drilling, but we anticipate that going -- up to about 95% as we end the year and go into 2018, as I spoke about the field development plants. So good well results, pad drilling, ramp-up of number one well online, those are all really positive but that makes guidance in a single quarter a little more difficult. The second part of your question or one part of your question was around risk mitigation? So pad drilling, the way we do modular-based development. The well designs are very similar from module 1 to module 2. And so it's very repeatable. You have crews that get into a learning curve. Remember, we haven't ramped significantly. We're at a 11 operated rigs, we believe it's well within our headlights and the capability, we have for frac cores that continue to do work with us in repeatable activities. One of the risk mitigation techniques we employ is utilizing spudder rigs and rigs, right? Where you spud a rigs to set surface casing in many cases where it makes sense. And in other cases, we use batch rigs to set intermediate pipes. So if you set all your intermediate casing strings before you do your laterals, it derisks, if you want to call it a train wreck or a problem in one of those wells, you've derisked that because you've taken it out of the critical path timeline. So that's one example. There's a number of things we're doing on the supply side, on the cost side. Our logistics hub in New Mexico comes online, and that derisk supply. So I appreciate the question, Guy.
Operator:
Next question is from Brian Singer of Goldman Sachs.
Brian Singer:
When we look at the Slide 15, it's definitely noteworthy the increase in lateral length that you've achieved and are expected to achieve getting to 8,500 repeat on average in the first half of 2018 in the Permian. And I wonder if you could talk about the longevity of your inventory of 8,500-plus foot lateral length wells, and going into the earlier commentary on swaps here, swap there, at what point you would look for more meaningful opportunity or need to exit swap or add to your permanent position to bolster that continuity?
Joseph Elliott:
Yes, Brian, we've had -- last year, I think in the past, we said we did about 10,000 acres of trade swaps in 2016. In the slides, you see we've done already 13,000 acres this year to continue to core up. There's energy in the industry to do that, people recognize the value of scale and being able to drill longer laterals. So we have a good inventory of wells that are in the low natural category. And again, I go back to the value-based development. It's part of that process. There's a subsurface process. There's a commercial process, there is an execution planning process, but there's also a land process that goes with that. You could go chase production, but if you're not set up to do the longer laterals and spend the time to work your land position hard, then it's going to be the potential risk to overcapitalize and not deliver the rates of returns, which will lead to the return on capital employed that we're were driving for. So it's all wrapped up into that process. But we've had a lot of good land trades this year, and that gives us confidence about continuing to be able to drill longer lateral.
Cedric Burgher:
I guess to sum on this topic, when we would think about what needed for multiyear growth plans assuming $50 oil, and assume you've got to seminary piece, normal course land spud, would you have the inventory of 8,500-plus foot lateral length to support that ramp where we'd see these bars continue to go flat to go up to the right?
Joseph Elliott:
Yes. I mean, we're confident of these core long land positions have long lateral inventory deep. But remember, that's just one piece of the value based development approach. We continue to lower cost, we continue to drive well efficiency. There are places that -- again, you can see what our lateral length has done down over time not just in the inventory but the actual results. now we updated our inventory last quarter. Our average inventory and this is in the less-than-$50 category more -- went from 8,400 to 8,600 feet. So all of these steps we take continue to drive better returns at the end of the day.
Brian Singer:
And then shifting internationally can we have talk about some of the wells collective an impairment that you're seeing, I wondered to what degree that international is competing more per capital, or whether these productivity and the improvements or efficiency improvements just minute -- essentially repatriate have more capital available for us debt paydown or to shift to the U.S.?
Vicki Hollub:
Well, we're definitely not opportunity-limited in what we're seeing in international. And it really will depend on what adds the most value. As we get to the point where we have cash above and beyond our 5% to 8% growth that we've set as a target, we'll look at the opportunities and see what we can do. But I'm really excited about what we're seeing internationally.
Operator:
Our last question comes from Doug Terreson of Evercore ISI.
Douglas Terreson:
I had a capital management question as well and specifically, during the past year or so, several of your competitors, they changed their direction and in some cases, they extended production guidance -- just to demonstrate returns and value creation. And then they pledge to distribute increased cash flow to shareholders over the next five years and they were obviously awarded the stock market. So while there was plenty of commentary on growth today, the obvious question is, why not more parameters or frames for return of capital? Meaning, Cedric was pretty clear about to the commitment to return, and I think Vicki was, too. But is there a reason that pathways that free cash for the return on capital are not provided for an extended period and I asked because he clearly, it looks like your economics are improving, so it appears return probably improving normalize to or you guys I think that the returns so far will take care of itself as increases. So I guess the question is -- I just want to get you guys to comment on how you think about the importance of returns and the balance between growth and return. So if you could do that, that would be appreciated.
Vicki Hollub:
Okay, I do not want to say this in a negative way but our history points to the fact that return on capital employed has been a very important metric to us for the last 20 years. And we have a track record that shows that, that's -- we make investment decisions on that basis. The only reason we're struggling a little bit right now is that we certainly need to get to the point where we replace the cash flow that we loss from those lower returns and lower margins assets that we exited. That was really the main reason for that hold a strategic plan, was to get us back into a situation where every dollar we invest delivers the most -- the highest possible rate of return on capital employed. So we're really committed to that. We're going to execute this plan to get to our cash flow breakeven at $50 and beyond that, our return on capital employed will continue to go up.
Cedric Burgher:
Good. Doug, this is Cedric I would just add a couple of things. One, it sounds like -- from the question, was a little bit reflective of what does our guidance to reflect and so on. And while we don't guide ROCE, because one thing that's wonderful about ROCE, and I'm sure you a big advocate of it, Doug, but -- it captures pretty much everything and it's fully-audited, it's full cycle, it's harder for the IR guys to get gaming and so on. So it really is a great metric and it's one we've been committed to for a long time, and of course, we will never do that here. But the -- it's a great metric, we've been committed to it, in various pieces for a long, long time, organizationally, as well as personally. But if you get is reflective of that the really is difficult to do. And if you look at last year, we were in the top quartile of our peer group for ROCE. It was a tough year for anybody in the business just because of the downturn and historic cost on the books. As we work forward, every dollar be reinvested, as Vicki said, is going to very high return reinvestment returns where it won't get invested, and so that's our commitment to you and to our shareholders and we're finding a lot of success in progress in doing that. And so we believe that recipe will continue to give us industry or peer-leading ROCE metrics. So I know it's competitive environment but we were it's up quite a last year, and we intend to be that way over time year in and year out. And that's our goal, and then we tied our -- increasingly tying compensation to it meant, that's something we put out last quarter in one of our slides. And so I'm not sure -- but guidance is something that we aren't probably going to do in terms of guiding gaining ROCE. We'll give you components that may be can help you get there.
Vicki Hollub:
And Doug, I was going to add one more thing as well. As you know, we've also done share buybacks a lot in the past and we've done quite a bit of that and that's not something that we have gone away from being willing to do would the list but right now, with the opportunities that we have for organic development, it's not the highest priority or not the middle priority so -- but we would consider that in the future. That will be part of our value proposition. So just make sure you understand picker we're hoping to doing what we need to do to add value but appreciate the question. So to close, I just like to say that we are very excited about where we are in our direction but realize that more needs to be done. We have the highest quality assets across our businesses that we've ever had. And our teams are continuing to find ways to make them even better. This gives our entire management team confidence in our ability to sustain our value proposition of dividend mongering production growth and were looking forward to where we're headed. So thank you, all, for joining our call today and hope you have a good day, and go after us.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Richard Jackson - VP of IR Vicki Hollub - President and CEO Cedric Burgher - SVP and CFO Jody Elliott - President of Domestic Oil & Gas
Analysts:
Doug Leggate - Bank of America Charles Robertson - Cowen and Company Evan Calio - Morgan Stanley Philip Gresh - JPMorgan Roger Read - Wells Fargo Paul Sankey - Wolfe Research Pavel Molchanov - Raymond James Brian Singer - Goldman Sachs Jeffrey Campbell - Tuohy Brothers
Operator:
Good morning and welcome to the Occidental Petroleum Corporation second quarter 2017 earnings conference call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Richard Jackson, Vice President of Investor Relations. Please go ahead, sir.
Richard Jackson :
Thank you, Lora. Good morning, everyone, and thank you for participating in Occidental Petroleum's second quarter 2017 conference call. On the call with us today are
Vicki Hollub :
Thank you, Richard, and good morning, everyone. One the first quarter earnings call we announced our plan to achieve cash flow break even after funding the dividend and growth capital. As a reminder over the past few years we executed strategic initiatives to divested lower margin, lower return oil and gas production but to replace it with higher margin, higher return production from our Permian resources business. This was a return focus strategy with the objective of insuring that every dollar we invest delivers the highest possible return. To reach the cash flow needed to be break even at $50 WTI and cash flow neutral at $40 WTI. We determine we would need incremental production of 80,000 BOE per day from Permian resources along with the additional cash flow that was expected from our chemicals and midstream businesses. Today I will update our progress with the plan but first I will share some second quarter highlights. On July 13, the board approved an increase to our quarter dividend, this is the fifteenth consecutive year we’ve increased our dividend and as indicative of our core belief that dividend growth drives long-term share price appreciation. We believe dividend growth along with the earnings growth that will be generated from our returns focused pathway to breakeven, we’ll maximize shareholder return over the long-term. The confidence that I, our board and our management team have in our ability to significantly grow shareholder value is based on the quality of our assets, the capability of our organization and the strength of our pathway to breakeven. Our pathway to breakeven begins with the best portfolio of assets that Oxy has had and it’s nearly 100 years history. But it’s not enough to have great assets, we must also ensure we continue to increase margins through further cost reductions. To accomplish this, we’ve implemented a value based development approach along with innovative operations and technology applications. We’re seeing exciting progress across all of our assets. Our value based development approach has already resulted in 400 additional Permian resources locations year-to-date with breakevens under $50. We expect further additions through the remainder of the year exceeding our original guidance of 400 location additions during 2017. And finally, with the efforts of the housing gas team the plan reached operating rate of 75,000 BOE per day net to Oxy. We’re also managing our portfolio, during the quarter we announced multiple Permian transactions which resulted in the addition of low decline assets that will increase our operating cash flow by $80 million in 2019, with no incremental cash outlay. Turning to slide five, we have clarified what it means for Oxy to be breakeven at lower oil prices. Upon completion of our plan, we will be cash flow neutral at $40 WTI, meaning we’ll cover the dividend and the production sustaining capital within operating cash flow. At $50 WTI, we’ll also be able to generate 5% to 8% production growth. This chart walks you through the milestones we need to achieve this plan. Our entire organization is laser focused on our breakeven plan, in fact we introduced this plan as the key metric for our compensation across the organization. All the decisions that management will make in the upcoming quarters will align with achieving these goals. Slide six, illustrates our progress towards the breakeven plan. The chemical segment achieved a full quarter of operations at the new Ingleside ethylene cracker. However, our first cash distribution from the JV will be received in the third quarter due to funding of JV working capital during the second quarter. We did benefit from additional caustic soda volumes associated with the full quarter of operations from the cracker. Additional chemicals cash flow will come in 2018 from the startup of the fourth CPE plan in the fourth quarter of this year and from improving product prices. Then mid-chain segment improves substantially due to widening differentials between Midland and the Golf Coast. Improved marketing spread was partially offset by sequential declines in the NGL prices and gas processing fees. Further increases in volume through the export terminals as well as the additional debottlenecking of our hosing will also add to our cash flow. Our oil and gas segment added 9,000 BOE per day of high margin production from Permian resources bringing us closer to our production target. And finally, as I said earlier, Permian transactions will improve annual cash flow generation by $80 million in 2019 at $50 WTI. Each quarter we'll show the progress towards our pathway to breakeven on the same slide. Slide seven quantifies the liquidity we have available to fund the gap between cash flow from operations and the capital needed to achieve our goal of cash flow breakeven at low oil prices. At the end of the second quarter, we had $2.2 billion in cash as well as TIGP units with a market value of about 800 million. We will manage our portfolio to contribute at least an additional 500 million to ensure we bridge the cash gap, if prices average $40 through 2018. To be clear even with an average oil price of $40 through 2018, we have sufficient cash and liquidity to cover sustained capital, the dividend and our resources growth needed for the $50 breakeven plan. I will now turn the call over to Cedric Burgher.
Cedric Burgher:
Thanks Vicki, Jody will cover our Permian activity so I will address other significant items. Total reported production was 601,000 BOE per day with ongoing production coming in at 594,000 BOE per day which was at the top end of our guidance range. Domestic operating cost were below guidance and capital cost are on track to meet total year guidance. We spend approximately $800 million on our capital program with the majority of our $3.6 billion capital budget anticipated for the second half of the year. As a reminder, we received our tax-free fund of approximately $750 million during the second quarter. Second quarter core earnings per share was $0.15 with cash flow on track for our breakeven plan. Reported income included one-time gains on the sales of domestic oil and gas assets including sales taxes and a noncash fair value gain on our plains equity investment. Chemicals second quarter earnings were well above our guidance as caustic soda exceeded priced continue to increase based on a favorable supply and demand balance and low inventory levels. Chemical production and sales volumes were stronger than anticipated across most product line slightly offset by higher ethylene and natural gas cost. The second quarter Chemicals income also benefited from a full quarter of contributions from the joint venture ethylene cracker in Ingleside, Texas. However, our first cash distribution will not be received until the third quarter. The cash distribution will be approximately $50 million which includes some catch up from the second quarter. Midstream second quarter core earnings also came in above our previous guidance reflecting improved Midland and Gulf Coast spreads, higher volumes to the Ingleside crude terminal and improved foreign pipeline income with the completion of the Dolphin pipeline in our Hosn plant maintenance in the first quarter. Midstream improvements were partially offset by lower NGL prices and gas processing fees. On Slide 10, second quarter cash flows included $600 million in proceeds from the sales of assets including South Texas and $360 million in acquisition payments primarily related to the Permian resources and international operations. With respect to guidance please refer to Slide 11 in today's investor presentation. Our full year 2017 ongoing production guidance has been narrowed to a range of $597,000 to $605,000 BOE per day. From prior guidance of 595,000 to 615,000 BOE per day, the low end was raised to reflect the new production increase from the previously announced Permian transactions. The high end of the range was reduced as we finalized our ramp up scheduled in that Permian resources and recognized accumulative uncertainty in OPEC quarters [ph] extensions, Columbia downtime and our non-operated production growth timing. Permian resources total year production guidance has been narrowed with an adjustment only to the top end of our guidance to reflect the sale of our Permian resources acreage and our non-operated production growth timing. EOR production guidance has been increased to reflect the other part of that transaction. We continue to expect production in Permian resources to exit this year at a growth pace of approximately 30% higher than 2016 levels. We expect our capital expenditures to ramp up to about $1 billion for both the third quarter and the fourth quarters and our full year capital spending to be about $3.6 billion. Lastly, I would like to call your attention to our investor slide appendix which has been reorganized to include additional details on our business including several slides on our environmental, safety and governance framework and commitment. Since joining Oxy in late May, I have been thrilled to learn more about OXY’s industry leading efforts in Carbon sequestration which we have highlighted on slide 34. I’ll now turn the call over to Jody.
Jody Elliott:
Thank you, Cedric. Today, I’ll provide an update on our Permian business and the improvements we’ve made to the portfolio that will contribute to OXY’s cash flow breakeven goals. In June, we announced a series of transactions that monetized non-strategic Permian resources acreage to accomplish two things for us. One, enhance our low decline Permian EOR business and two, core up in an area of glass cut county that will now become a new development area. The Permian resources we divested had less value in OXY’s portfolio because of the expected timing of development, so we used it to provide liquidity to accelerate OXY’s pathway to cash flow breakeven and increase the value of our portfolio. We will continue to evaluate the tail of our Permian resources portfolio for additional value adding opportunities. The Seminole-San Andres Unit we acquired produces from the world-class San Andres reservoir and is a natural fit in our industry leading Permian EOR portfolio. Oxy has strategically pursued these assets since we became a non-operated partner in 2001, with an initial working interest of 7%. Overtime, we increased our working interest to 53% before the recent acquisition and now we’ll operate the assets with an 87% working interest. Our reservoir management expertise, operating experience and scale provide cost reduction and production optimization opportunities that will increase the value of this asset for Oxy. We’ve identified cost improvements of $5 per BOE that we target to realize by year-end 2017 and have an upside target of $10 per BOE that will bring the Seminole-San Andres Unit OpEx to parity with OXY’s nearby Denver Units CO2 flood. Turning to slide 14, beyond the operating cost opportunity, we have provided an initial estimate of resource potential for the Seminole-San Andres Unit. We estimate approximately 100 million barrels of resource potential with the less than $6 per BOE future development cost, which brings our Permian EOR total inventory of less than $6 FND to almost 1 billion barrels. We believe that OXY’s value base development approach which is grounded in subsurface characterization, operating capability and innovative technology along with the synergistic benefits from our scale in the area will provide significant upside to our initial resource estimates. I’d also like to highlight one additional milestone in the EOR business. In January, the US EPA approved the second monitoring, reporting and verification plan for injecting and storing CO2 safely in the Permian Basin as part of our CO2, EOR operations. Oxy was the first company to received EPA authorization for EOR with CO2 sequestration in 2015. EPA approval of these plans represents an important milestone in the development and commercialization of carbon capture, utilization and storage technology as an approach for long-term management of greenhouse gas emissions. We believe OXY's assets and expertise and enhanced oil recovery and CO2 sequestration provide a long-term competitive advantage under various possible carbon pricing scenarios in the future. Moving to Permian resources on Slide 15, we achieved our 2017 target of adding 400 locations to our less than $50 WTI breakeven inventory. We now have approximately 16 years of inventory at a 10-rig pace with less than a $50 breakeven. Improved capital efficiency and well performance added 255 locations and are based on repeated performance improvements from well design and technology that are sustainable and have further room for improvement. We've traded approximately 7000 total net acreage this year enabling us to convert shorter wells into higher value extended laterals bringing our less than $50 breakeven average lateral link to 8600 feet. We’ve also evaluated approximately 15,000 new net acres which added 100 locations to our less than $50 breakeven inventory. Our inventory now covers approximately 302,000 net acres which includes the effect of the divestitures during the year. As we progress our value based development approach we see continued potential for improvement in our inventory by applying new technology and enhancing operating efficiency. We continue our subsurface characterization to customize the development plans and well designs that will maximize the value of each section. Although we meet our 2017 less than $50 breakeven target of 400 locations, we believe we still have opportunity to further grow this number by year end. On Slide 16, updated our all-in capital intensity outlook through 2019, this metric provides an estimate of total annual CapEx for each 1000 barrels of annual average wage production during the given calendar year. Our improvements in 2017 to 2019 are the result of thoughtful development planning and created facilities infrastructure designs that increase facility utilization over the life of the field. We've also progressed our subsurface characterization and focused on understanding the why as opposed to just to what. For example, in Barilla Draw we utilized our advanced subsurface characterization that pin point a specific landing zone that would allow for maximizing SRV within the Wolfcamp A. This identification and execution of the why, resulted in a well specific landing point for the light of 16 edge, which contributed to an OXY record 30-day IP of 3200 BOE per day. As with our inventory we believe there is still upside to further improve our growth plans, all of our forecast assumptions are based on demonstrated performance where we have enough data to conclude that the improvements are sustainable. Our most recent improvements in well productivity, capital efficiency and improvements from applications and new data analytics projects represent upside opportunities. We also expect cost savings from logistics hubs multi-lateral drilling and additional water recycling that have not been recognized in the plan. We estimate there could be at least another 10% improvement as we continue development in our core areas through 2019. We believe our capital intensity is best in class and will the primary driver in providing OXY's growth while generating cash in 2019 and beyond. Turning to Slide 17, I'll provide an update on Permian resources drilling activity. Permian resources exited 2Q with 11 operated rigs an increase of four from the end of the first quarter. The increase in second quarter activity was late in the quarter which will primarily benefit production in the fourth quarter of 2017 and the first quarter of 2018. In the second half of 2017, we’ll operate five rigs in the greater San Dunes area, four rigs in the Greater Barilla Draw area and two rigs in the Midland Basin. As we build out infrastructure and progress our subservice characterization, we expect to move additional activities in the Mexico in 2018 and beyond. Resources are currently on the 30% CAGR trajectory based on our current development activity plans. You will also see that we lowered our expected rig count in 2018 and 2019 by one rig for both scenarios which is the result of the value based improvements we’ve discussed and that improved our inventory and reduced the capital intensity. I’ll now turn the call back over to Vicki Hollub.
Vicki Hollub:
Thank you, Jody. We’re fully on track to achieve our plan as shown across our oil and gas chemical industry businesses as each beat our second quarter expectations. Additionally, our teams are exceeding goal to increase value within the plan, we’ve already met our Permian resources inventory improvement goal by adding 400 additional locations below $50 breakeven, and we expect to add more. We were able to complete multiple Permian transactions to add value and enhance our plan as announced this quarter. We ended the quarter with more cash on the balance sheet than we had at the end of the first quarter and we have ample liquidity to fully fund our plan at any old price. We will now open it up for your questions.
Operator:
[Operator Instructions] And our first question today will come from Doug Leggate of Bank of America.
Doug Leggate:
So, Vicki, I wonder if I could just ask you to elaborate a little bit on the full year guidance. There seem to be a number of moving parts and I know it’s not easy to answer that in a quick question. But, CapEx is obviously backed loaded it looks like OpEx cut production but I’m also interested in slide 17 when you’re showing this 13-rig count basically coming on about six months earlier. So, can you just walk us through what the nature of the bringing the top end of the guidance is and how that impacts your timing of when you expect to get the incremental I guess is certainly 1,000 barrels a day in the Permian. I’ve got a follow up, please.
Vicki Hollub:
Okay. Thanks Doug. Our guidance really does not indicate any change in our confidence or in our pathway to breakeven as we’ve laid out. Actually, this is just a narrowing of the guidance, our business teams are progressing and working and achieving exactly what we need them to and actually where as I mentioned in my script, we’re really ahead of schedule in terms of performance. But there are several reasons that we did it, first we increased the low end of our range 2,000 barrels a day to account for the increased second half production as a result of our Permian transactions. And then we -- secondly, we now have a greater clarity on the redeployment of our South Texas sale proceeds. For example, we had said we would be able to deploy those into those proceeds and the Permian resources which we have done. And that activity is taking place in the second half of this year and now we expect that with the pad development that we had going on, some of that production will actually go into January and February. So, the activity we got better clarity on the timing of that. Third, our updated range really reflects some uncertainties around a number of things that have happened. Earlier in the year we had expected that the announced six-month quotas for OPEC would be in place and now that’s been extended for a full year. Also, we've had some impacts of electrical storms in the Permian in the second quarter, we wanted to take that into account and we've also had some third-party processing outages. In our own EOR business we had two unplanned plant client outages which are now behind us and we wanted to a be a little bit conservative with Columbia with respect to pipeline outages we been able to manage that recently and expect to be able to manage it but we don’t feel that there will be upside there. And then with respect to our Permian non-operative positive we are seeing indications that a lot of companies now starting to cut their capital. So, we feel like there could be some risk on the upside and again there are risk on the upside because we did increase the bottom side our range. And having said all that we felt like that it was small but wanted to make sure that we provided clarity around what we expect.
Doug Leggate:
Just to be clear on Slide 17 the earlier addition or move to 13 rigs I guess would be there in a couple of months, middle of next year looks like about the number for 80,000 barrels per day is that right?
Vicki Hollub:
The 80,000 barrel a day really is going to be dependent on our efficiency improvements and how well we're able to move from pad to pad, logistics and several things. So, I'm not prepared to just to accelerate that schedule, we've said that it would be happened by the end of 2018 or first of 2019. I don’t think that we see anything right now that would prompt us to change them.
Doug Leggate:
Okay my follow up hope is quick one, is another slide question on Slide 7, it looks as if I'm eyeballing this right, I guess you have broken it out, 0.5 billion to 2 billion of portfolio management I guess you called it, is that half in respect of the oil pricing or whether its $40 to $50 [indiscernible], I'll leave it there. Thanks.
Vicki Hollub:
What we're going to do is, we’re make the right decisions from a monetization and value stand point, so where they are assets that we certainly feel would be best monetized for them to add value to the shareholders that’s what we will do. We not going to monetize things that are not value adding, meaning we’re not going to sell assets that we think would add more value if we kept them for development. So, we will look at that and make the decisions as we go, we're not going to try to target any upper end; we just think we need to make the best value decision.
Operator:
Our next question will come from Charles Robertson of Cowen and Company.
Charles Robertson:
Thank you and thank you for all the update on the operational side but my question comes, I would appreciate your thoughts behind the 15th consecutive year of raising your dividend and you could expand on that appreciate it. Thank you.
Vicki Hollub:
As I said we felt like that, we have extreme confidence in our plan and we know we can execute this. So, we felt it important to continue to increase our dividend. We know that there are holders that expect that to happen and needs to happen for some of the holders of our stock. We wanted to do a modest increase at this point and expect that as we achieve our cash flow neutrality in our breakeven that we will then be able to grow our dividend more in line with our value growth.
Operator:
And our next question will come from Evan Calio of Morgan Stanley.
Evan Calio:
On the strategic plan, your strategic plan now evolves this lower stress case at 40. And given the capital efficiencies can you discuss the $50 side and is the 5% to 8% growth is that the sweet spot for growth or where improvements would rather lower to $50 threshold or could that allow the growth to drive higher. Just trying to understand how you see the upper end evolving with improving productivity or commodity price?
Vicki Hollub:
Well, one thing that we do expect to see is we do expect efficiency improvements. This plan that we’ve rolled out is very conservative, it does not include many of the things that Jody’s team is working on in the Permian resources business. And it also really doesn’t take into account some of the things internationally that we’re seeing that great success with, with respect to some of the capital efficiency improvements there as well as the improved recovery in OpEx reductions. So, I think that certainly our plan is conservative, so with the $50 oil price there would be potential for further increases, but in terms of production, but what we want to do is make the best decision so we would just look at market condition, we’d look at our other opportunities for use of capital and make a decision is to what’s the best thing to do. I believe overtime, because of the assets we have, we have the potential to grow more. But we’ll make those decisions as we get to that point.
Evan Calio:
Great. And my second question on the Permian. In your allocations, you’ve achieved your full year guidance to add the 400 horizontal locations sub 50 by mid-year versus full year. Maybe you discuss what drove that earlier, does that mean you are ahead of your guidance and should we expect another update before year-end. Just color on that process would appreciate.
Jody Elliott:
Yeah, this is Jody. Thank you for the question. Yeah, we have achieved that goal that we set out of 400. I’m still working on your stretch goal of 600 locations as well. But we do think we can continue to progress that better well productivity, some really innovative things around pad development sequencing, moving a little more activity over the next year and in the Mexico longer laterals you see in the slides that we’ve extended our average lateral length in the inventory. And that doesn’t stop, right so I think that will continue to add sub 50 inventory. Plus, we’re marching through the other 300,000, 350,000 acres that we really haven’t fully evaluated. We knocked off another 15,000 this last time. So, probably not every quarter an update on inventory but maybe every other quarter we would provide an update.
Operator:
And our next question comes from Philip Gresh of JPMorgan.
Philip Gresh :
Vicki I think one of the concerns I've heard from investors with the cash flow targets that have been outlined its just the timing of it, you mentioned end of '18 early '19, so I was just hoping that you could frame up some of the interim milestones you're thinking about here potentially exit rate '17, how much of this you think you might be able to achieve and I guess I'm thinking perhaps the mid-stream the chemicals pieces etcetera, do you think you could get 500 million to 600 million of this by the end of '17 or anything else you would be comfortable sharing on that front?
Vicki Hollub:
I think that certainly -- I think by the end of this year we will make more progress, we're going to see probably our biggest incremental changes in beginning in Q1 of 2018 because lot of the ramp up in Permian resources will really start to pay off in Q1. So, I would certainly expect to have significant incremental progress towards our goal by that time. But some of the other things will happen in mid like 2018 for example we expect the [indiscernible] expansion will be certainly before the end of 2018, the four CPE will be at the beginning of 2018 that’s the plant in Louisiana. We're going to see next quarter as we mentioned, the cash flow from the cracker starting to come in from the JV, so that should actually be happening next quarter, will help toward the end of this year. We expect that we will see incremental from the export terminal, we do plan to expand it a bit, but we're not sure the timing on that but that could also occur later in 2018. So, the closure things are immediate cash flow next quarter from the JV, the four CPE beginning of 2018 and then we're looking at [indiscernible] toward the end and the incremental growth from the Permian, while it wasn’t a straight line from the time we announced it, over the next couple of quarters is really they are ramping up, they are going to start, they will see good fourth quarter production and then they are on a very strong trajectory going into the 2018. So, the growth in 2018 is going to be well above the 30% CAGR from Permian resources.
Philip Gresh:
And then you outlined how you see the balance sheet progressing from a cash standpoint, how you see things progressing to help fund the growth plan. I'm wondering how you think about acquisitions at this point, you did the swap etcetera but when you say they are in the next 12 to 18 months acquisitions are still something you're looking at or is it more just your organic growth in the portfolio management on the other side.
Vicki Hollub:
That going to be mostly organic growth. Where we see opportunities to continue to increase our working interest or do bolt on acquisitions we would do those. But we're so confident with this organic execution plan that we have that we're really focused on it and making sure that happens.
Philip Gresh:
Okay if I could just ask one last one, Vicky I kind of asked you about this in other conference a month ago, but perhaps you could just refresh us on the 5% day growth rate in this long-term target versus may be targeting a slightly lower growth rate and covering the dividend sooner and I ask this kind of in the context of seeing a lot of E&P companies out there missing numbers, stocks getting hit on a weaker production outlooks and it seems like the cash flow oriented stocks have been doing much better on the execution front and from a share price perspective. So, just curious on your thoughts on this.
Vicki Hollub:
Yeah. I’m want to emphasize that our growth rate right now and what we’re doing over the next 18 months is, we’re just replacing cash flow from those assets that we exited or divested. So, this high growth rate that you’re seeing is a consequence of that, we need to replace the cash flow, we want to do that as quickly as we can and beyond that once we are cash flow neutral at 40 and breakeven at 50 with the 5% to 8% we will be -- we will stay within cash flow. And we expect over time, our cash flow to continue to increase. And that’s our goal.
Operator:
And our next question comes from Roger Read of Wells Fargo.
Roger Read:
Yeah. Thanks. good morning. Maybe the follow up on Phil’s question here on the dividend, for the growth rate potentially why not talk about maybe a higher growth rate in the dividend or some growth rate in the dividend versus slightly slower production growth number at $50?
Vicki Hollub:
I’m sorry Greg -- Phil, could you repeat that question, you’re asking why not growth, I’m sorry, Roger you’re asking…
Roger Read:
Yeah. So, the dividend is laid out at 2.4, 2.4 and then the production growth and just kind of getting back to the question that Phil asked. Why not talk about dividend growth blended with production growth as opposed to just a production growth number, or is just the goal here the toggle is always is production growth and the dividend secure at 40. I’m just trying make sure I understand where you kind of you’re laying out a sort of a drilling plan in 2019 and our productivity plan. How does that come back to the dividend?
Vicki Hollub:
Right. In this interim as we are on this breakeven plan, the dividend is going to be -- the increases will be modest as we’ve just show you. However, once we get beyond that the growth in the dividend will be consistent with our value proposition and that we’ll grow that accordingly. So, as we’re growing production, growing value, growing cash flow beyond the breakeven and our dividend at that point will certainly start to resume a healthier growth rate. And it will be according to at that point what the best use of capital is, best use of the cash. But it’s not that the dividend will not grow, it will beyond this breakeven plan. Does that answer that Roger?
Roger Read:
Okay. Great. Yeah it does, more of a timing issue here getting through this period and then focus on it. Okay. And then Jody maybe switching gears to you or Vicki if you want to keep on with it. In the appendix slide 25, 26, I think there was one or two more showed, it look like outperformance versus type curves. I was just wondering is that predominantly lateral linked which looks like some of it or is this kind of what’s driving that improvement?
Jody Elliott:
Yeah, Roger it’s a combination of things. It is better, continued subsurface understanding and progression and refining our landing points, changing our stimulation designs to maximize stimulated rod volumes so that connection to the reservoir and lateral length is really all of those things. If I had to wait, I might probably say that the landing point in stimulation changes are driving the bulk of that.
Operator:
And our next question comes from Paul Sankey with Wolfe Research.
Paul Sankey :
I guess to would be remising me not to ask you about gas, oil ratios given the opposition in the Columbian scale of your position in your experience. What's your prospective on this latest controversy that too [ph] much as regards OXYs competitive position.
Jody Elliott:
Paul this is Jody, thank you. I think as we've talked all along we really emphasize our subsurface work whether that’s geologic work or reservoir engineering and so the understanding of GOR [ph] behavior, it's not new to us, it is not a surprise for our assumptions, we model, we do more than just decline curve analysis, we have multiple defector [ph] changes like go through the life of this well, we model the GOR increase when you get to bubble point, we use rate transient analysis, we use reservoir modeling so it is a full cycle engineering analysis. And so, our plans have got those reservoir behaviors built into our forecast over the next couple of years, our GORs actually stay fairly flat based on the mix of new development and declining development. So that’s well understood by us and built into our plan.
Paul Sankey :
Looks like as though was playing the gas oil ratio bingo there and you excluded points for bubble point but you didn’t manage to throw in big data.
Jody Elliott:
Thanks, the big data is really is analytics, it's not big data, its analytics that helps us get even better at that, so we're adding statistical models on top of the engineering analysis whether it's in reservoir, whether it's in geology, completions drilling, we're seeing that across the board with our analytics projects and that just refines our confidence on our EOR predictions, on our type curve predictions even more as we move forward. It's some of the technology thing that Vicki mentioned that really aren’t based into this cash flow to breakeven plan, they act as upsides for us as we continue to solve those kind of though problems out there.
Paul Sankey :
Could you contrast, I know you are all over the Permian but can you talk about how things differ across acreage and where you might be differentiated or not as the case may be as regards some of these issues.
Vicki Hollub:
Our activity set over the next several years is predominantly in a Delaware basin, where we're positioned where we had good rock positions, its geo pressured for most of those benches that extends the period of time before you start having GOR effects. So, I think we're well positioned from an inventory standpoint relative to some of our competitors with respect to GOR.
Paul Sankey :
Got it, Vicki if I could just pin you down slightly, you're talking a lot about breakevens and then as you cost dividend increases, I think you know the market is getting tired of what is quite a modest time to ultimately to be a breakeven. But it feels as if the opportunities is better than it ever has been and can you not be more ambitious about your dividend growth over time, I'm for example pinning it to future volume growth assuming the margins were constant. Wouldn’t it be reasonable to say that in the future we can get a 5% to 8% annualized dividend growth as our target? Thanks.
Vicki Hollub:
I do expect that to be not only possible but likely, I just didn’t want to pin my sub down to a range on that, but that’s really time to target [Multiple Speakers] but that’s our goal, it’s in the interim we’re just trying to get to the milestone of being able to then refocus and get our dividend growth back.
Operator:
Thank you. And our next question comes from Pavel Molchanov of Raymond James.
Pavel Molchanov:
Thanks for taking the question. You’ve broken out your PAGP holding of $0.8 billion in the slide. And I remember the last time you sold some of that, I think it’s about 2.5 years ago. Is there a threshold for the yield on that stock where you would feel compelled to monetize it?
Cedric Burgher:
Yeah, Pavel this is Cedric. Really our approach is to be opportunistic, we have a number of assets in our portfolio that don’t produce cash or not much and those would be likely candidates for sale earlier. But clearly the plant units from a long-term perspective are not core to our business and therefore a source of liquidity. But, the way we look at it they’re throwing off good cash, we think it’s a well-run company with good assets and so, we’re happy to continue to hold on to those units and look for an opportunistic time to sell them down the road.
Pavel Molchanov:
Okay. Quick question about the sustaining capital under the $50 versus $40 scenarios. The difference is only 10%, $200 million, is there a certain amount of conservatism in another words if oil were $10 lower than your base line wouldn’t sustaining capital be meaningfully lower than in 2.1 billion potentially?
Vicki Hollub:
Sustaining capital does go down with oil prices because we would expect as you’re alluding to service company cost and some of our CO2s tied to oil prices. So, it would go lower, what the estimate that we have on our slide though is what we believe today without significant efficiency improvement. So, it’s conservative.
Operator:
And the next question comes from Brian Singer of Goldman Sachs.
Brian Singer:
Couple of questions on the Permian. You highlighted the coming shift in rigs in to New Mexico. Wondered if you could talk a little bit more about the decision to do that and the implications on the returns there versus the returns elsewhere in the Permian portfolio like the Southern Delaware and Midland Basins and also given that it’s topical, can you speak to how you see the rest associated with navigating drilling horizontal wells around areas where there are legacy vertical wells particularly in the Midland?
Vicki Hollub:
Yes, Brian the reason for the shift in the Mexico is really kind of grounded in our capital intensity calculations. The Mexico, because of the stack pace and very good stack pace is not like we have a primary bench and then three or four secondaries'. There are three or four primary benches that compete very well, very high returns and so it’s that nature that drives us toward more in the Mexico kind of second in the tier would be the Texas, Delaware and then Midland Basin. I mean, those two aren’t that different but they just have different production profiles with the wells as we drill and that’s why we're in a more dominated with our activity still [ph] on the Delver side. The risks of drilling with vertical wells a lot of the areas we're developing are not historical vertical development or they were done in a way that you still have a lot of room between those verticals wells for not having any collision areas. A lot of our New Mexico development that we're going to is clean acreage in very little historical development if it was, it was in shallower reservoirs. We got a long history of this. You’ve got to remember, we've been in the Permian for a long time at 25,000 wells, a lot of experience dealing with both vertical and now horizontal activity, we're doing more horizontal activity in our legacy EOR properties and on the central basin platform. So, it's something very manageable for us and I think the properties that we set themselves up well for continued horizontal development.
Brian Singer:
Thanks, and then on the technology side can you give us an update of some of the technology solutions that you're deploying such as I think most had lateral wells, one that you highlighted in the past. And if there is more to say on some of the predictive analytics, but then you already, that would be great, but, what the impact is on production or capital cost today.
Cedric Burgher:
We've got a great number of slides in the appendix that lays out the different projects that we’re working. We made a lot of progress here recently in one around reservoir management of our injecting. So, both in Kim's business and [indiscernible] with steam and then northern Oman with the water flood and then our EOR business with CO2 floods we're deploying kind of the early versions of those tools that combine essentially low fidelity reservoir models with the statistical models that we can make changes in where our injecting goes on a greater frequency and so what that does, it allows us to get the biggest bang for the buck for every molecule of injecting that we put in the ground. So those are starting to get rolled out and from a technology standpoint that’s all kind be done in the cloud. So, from an IT stand point, we’re able to do this work from Oman all the way back here to Houston and again that’s our starting point but technology applies to all three geographic areas. On the drilling side we're pushing out our bit trajectory data analytics tool, so we've been through kind of our early round of validating where the bid is based on serving equipment being 45 or 60 foot behind the bit, that’s now starting, start beginning to get penetrated across multiple rigs and what that does is it again it keeps you in zone, it allows you to build you curves more accurately because you know where you are instead of projecting where you are and that results in better wells, if you stay in zone longer. So that’s a couple of examples but there is a long list that we continue to push forward on the technology front.
Brian Singer:
And the multi-lateral wells, have there been any examples there?
Cedric Burgher:
We're continuing to as we spoke before, we have one that we have completed the stimulation on, we have others planned. The impact of multi-lateral is really when we move into our second and third and fourth bench kind of development. So, we continue to move down that path kind of no new news there on multilateral.
Operator:
And our final question today will come from Jeffrey Campbell of Tuohy Brothers.
Jeffrey Campbell:
Good morning. Vicki, I was just wanted to ask you, I’m looking at the various illustrations of the $40 and $50 per barrel spending and the 30% CAGR and the Permian resources and your remarks about replacing solid cash flows. Is the overall message that you’re going to maintain this spending plan through 2018 regardless of oil prices or is there any chance that you would pull back if prices really swooned. And in particular what I’m trying to understand is that the spending that you’re outlining is really necessary to drive the efficiencies that are going to continue to lower cost further out?
Vicki Hollub:
Well first of all, as long as we’re investing our dollars and things that deliver rate of return that are better than our cost of capital, we’ll continue to execute this plan. That also assumes that the fundamentals are there to support oil prices that are at least close to $40, because that’s about where we get the returns that we feel are appropriate for our dollar invested. With respect to, I think in slide seven shows the liquidity that we’ll have available to support that if that was the second part of your question at 40. And this is all for this 40.
Jeffrey Campbell:
But one other thing that I was just curious about is that and in addition investing for rates of return and so forth there has been a lot of illustration throughout the slice on driving cost lower overtime. And I was wondering if also part of this you want to get to a certain scale over the next 18 months to 20 months, that that’s going to help to drive cost further even going further out?
Vicki Hollub:
Yes, we set the $40 and $50 as milestones and we do believe that going forward beyond that in and again those are conservative because we haven’t baked in a lot of the things that we’re trying that we believe have a good possibility of working out. So, we do believe that overtime we’ll continue to lower our cash flow neutrality that will continue to improve our operations and drive our cost down and our margins up. So, this to us is just a milestone. And Cedrick, you have something to add?
Cedric Burgher:
I'll just say that the point of slide seven was to show you at $40 that we’ve got the liquidity path that works obviously, so we’re planning for the worst if you will, if things were to go below that on a sustainable basis then we would of course reassess the whole world probably would, but even as low as $40 WTI, we’ve got a path that this plan we can execute from a liquidity standpoint.
Jeffrey Campbell:
Okay. Well, that was really helpful. And just going back quickly Jody to your remarks about the multiple core opportunities in New Mexico as opposed to Texas and Midland. Slide 26 highlights that the Wolf Camp A and the Wolf Camp B are your core zones in the Midland Basin, but there has been pretty good success in the lower spread very in the Midland Basin as well. I was just wondering is that the zone that you’re looking at, does that have the possibility to maybe become a third core zone overtime?
Cedric Burgher:
Yeah. It does and in this new core development area that the transactions allowed us to develop their spray berry activity there as well, in New Mexico its second bone, its first bone its third bone, its XY, it's another zone in between the XY and the Wolfcamp, that’s the beauty of New Mexico again as there is more what I would call premium benches, per acre of opportunity that we have.
Jeffrey Campbell:
And if I could just, kind of going back to what Brian was asking about, when you look at all those two C [ph] basins in New Mexico, do you think of minimum amount of development that you will do with individual well bores and at some point, later on you'll come up with the multi laterals and how you’re thinking about that.
Cedric Burgher:
We take the multi-lateral -- we view multi-lateral as kind of an arrow in the quiver, it's one of many tools we have in our development plan. So, areas where we are location constrained, there are some environmentally sensitive areas that we operate in, there is BLM acreage, we're trying to minimize our footprint and so if you have multiple benches that’s a lot of well heads if you do them all by one well at a time. So, we take that into account when we think about the development plan of an area of whether we want to deploy multi-lateral in that future development or not.
Operator:
And that concludes our question and answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
Vicki Hollub :
To close I would just like to reiterate our excitement and our confidence in our plan. The quality of our assets, the capability of our organization and the strength of our pathway to our breakeven plan is well understood by our organization and we're completely in line toward achieving our goals. But looking beyond our breakeven plan we're also confident in our ability to sustain our value proposition for the foreseeable future and that does include meaningful dividend growth beyond this breakeven plan. In addition to the multi decade reserves and resources that we have in the Permian basin and the long-term cash flow from OXYChem, we also have long-term contracts in the Middle East and Columbia and they will provide significant cash flow for multiple decades. So, we do have sustainability. So, I would like to thank you all for joining our call today and wish you happy day. Thanks.
Operator:
This conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Richard A. Jackson - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Christopher G. Stavros - Occidental Petroleum Corp. Robert Lee Peterson - Occidental Chemical Corp. Joseph C. Elliott - Occidental Petroleum Corp. Kenneth Dillon - Occidental Petroleum Corp.
Analysts:
Edward Westlake - Credit Suisse Securities (USA) LLC Doug Leggate - Bank of America Merrill Lynch Evan Calio - Morgan Stanley & Co. LLC Roger D. Read - Wells Fargo Securities LLC John P. Herrlin - SG Americas Securities LLC Paul Sankey - Wolfe Research LLC Philip M. Gresh - JPMorgan Securities LLC Brian Singer - Goldman Sachs & Co. Doug Terreson - Evercore Group LLC
Operator:
Good morning and welcome to the OXY first quarter 2017 earnings conference call. Please note, this event is being recorded. I would now like to turn the conference over to Richard Jackson, Vice President of Investor Relations. Please go ahead.
Richard A. Jackson - Occidental Petroleum Corp.:
Thank you, Kate. Good morning, everyone, and thank you for participating in Occidental Petroleum's first quarter 2017 conference call. On the call with us today are
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Richard, and good morning, everyone. I'd like to focus on three topics in my opening remarks. First, I'll provide you an update on our portfolio optimization initiatives, and I'll share what this means for our near-term growth plans. Then I'll highlight some components of what we believe is our differentiated and value-based approach. And last, I'll provide details on our plan to get to cash flow breakeven after funding the dividend and growth capital. Turning to slide 4, in 2013 we began our strategic review process to divest of low-margin low-return assets and assets that simply could not compete for capital within our portfolio. We allocate capital based on the net present value of the project, the returns they generate, the cash flow profile, the reserves added, and its capital intensity. To support our value proposition, we need a balanced blend of short-cycle, high-growth investments along with low-decline long-term cash flow. But in both categories, we need relatively high-margin, high-return assets, and we need the ability to control our own destiny. By this I mean we need a high-quality development inventory with the potential to sustain our growth over the long term without needing to depend on acquisitions or the decisions of others. As the final step of our strategic review process, we have now divested of our South Texas gas properties, which were our last non-core upstream assets. Our remaining upstream assets are all within our core areas, which are the Permian Basin, Colombia, Oman, Qatar, and Abu Dhabi. The proceeds from the South Texas sale will be redeployed into Permian Resources. Given that Permian Resources margins are three times higher than South Texas gas, only 9,000 barrels of oil equivalent per day of Resources production is needed to replace the cash flow from the 27,000 barrels of oil equivalent produced by South Texas. As we've been going through this optimization process, we've been replacing the lower-margin, low-return divested production with better quality, higher margin, higher return production in order to restore our cash flow. About half the divested production has been replaced with incremental production from Permian Resources, Al Hosn, and Oman. The remaining growth needed to restore our cash flow to cover growth capital at $50 WTI will come mostly from our Permian Resources business. As you know, even in a $40 to $50 price environment, our Resources developments generate high returns with low risk due to the quality of the rock, scalability of the development, and availability of services. I want to point out that this has not been a shrink-to-grow strategy. This has been a deliberate drive to ensure the capital we invest will deliver the highest possible returns. This is a returns-focused strategy. We now have the highest portfolio that I believe we've ever had, but a great portfolio is not enough. We must also ensure we do the things necessary to maximize its value. On slide 6, I'd like to share how we're doing that. We have centered our entire business on a differentiated value-based development approach. The three goals on the left-hand side of the slide may seem basic to running oil company, but can be hard to achieve in actual practice. Our organization and culture are grounded in recovering more oil at less cost while continually building the required inventory to sustain and improve our results. Before I highlight several components of our approach, I'd like to say that we make decisions and weigh trade-offs that may differ from our competitors because we're focused on creating shareholder value over the long term. The first component is our niche. We have proven and long been known for our ability to get more reserves out of reservoirs than others can. That achievement starts with strong technical capability, a solid understanding of the subsurface, and the application of cutting-edge technology to develop and manage the reservoir over the full life of the reserve. We have done this in conventional, tight, and unconventional reservoirs in many areas of the world. We've done it with primary, secondary, and tertiary recovery methodologies, onshore and offshore, in deserts and in jungles. We've taken a similar approach in Permian Resources, where the key to our success has been investment in technology and our rigorous internal workflow of subsurface characterizations. We first needed to understand the reservoir and the fluids within the reservoir. Only then could we confidently understand where to land the wellbore, how to design the stimulation, how many wells are optimal per section, and the minimal infrastructure needed to support it. While many of our competitors are busy drilling the most wells per section, we're focused on drilling the optimal number of wells per section for less cost to recover the same, if not more oil through an infrastructure that's designed to deliver the highest net present value rather than to support a peak production rate. Today this requires strong chemical capabilities, detailed integrated planning, and an innovative culture across the entire organization. The second component is the early adoption of external trends because I believe this is where we truly separate ourselves from the pack. For example, several years ago we recognized that data analytics would be big for our industry. Early adoption has been key to enable full integration of this technology into our culture. Only culture will allow new technologies like data analytics to drive sustainable business results. The reality is that as we are rolling data analytics out to all of our disciplines, we're starting to find things that we had not previously seen and in many ways that we didn't expect. This will have a material impact on our future business and financial performance. We believe if you're thinking long term, you need to be thinking about data analytics now. Turning to my final slide, slide number 8, I want to reinforce that getting to a lower cash flow breakeven after dividend and growth capital is a top near-term priority. As always, our financial goal is to grow our dividend and company value by making returns-focused investments that will drive 5% to 8% average production growth over time. The pathway to this lower breakeven oil price is clear to us, and the actions listed on the slide will all work together to help us reach our goals. And it is important to note that we plan to accelerate cash flows from the tail of our portfolio to help fund the production growth needed to achieve our lower breakeven target. The tail of our portfolio includes Permian Resources acreage that is not strategic to us to but synergistic and valuable to others. This will be done as needed and opportunistically. On the right side of the slide, we have identified key milestones and accelerators. Our incremental growth target is 80,000 barrels per day above our 2016 average production rate, including the replacement of the South Texas cash flow. To fund this growth capital, we disclosed $2.2 billion of cash sources. Beyond these sources, we're continuing to work several options across our portfolio that will accelerate in value creation, including asset trades, partnerships, and sales. We're looking for win-win scenarios for ourselves and other companies. We believe oil prices could be lower for longer and only the companies with high-quality assets and top-tier operational performance will be up to the challenges our industry will face over the next few years. We believe we're well positioned to meet these challenges. I'll now turn the call over to Chris Stavros.
Christopher G. Stavros - Occidental Petroleum Corp.:
Thanks, Vicki, and good morning, everyone. Today, I'll focus on the following
Robert Lee Peterson - Occidental Chemical Corp.:
Thanks, Chris, and good morning, everyone. In February, OxyChem safely completed commissioning of our ethane cracker that will produce 1.2 billion pounds per year of ethylene at our Ingleside, Texas facility. The project is a 50/50 joint venture between OxyChem and our long-term partner, Mexichem. The project included a dedicated 115-mile ethane pipeline and storage dome in Markham, Texas. This project is the first grassroots cracker built in the United States in over 15 years. Completion of the project both on time and on budget while maintaining tremendous health and safety performance throughout its construction is a testament to our employees and our contractors to execute and deliver on objectives. The cracker has been operating at design capacity since the latter half of March. In addition, we improved our ability to transport ethylene to and from our Markham, Texas storage dome throughout our pipeline. Most importantly, the ethylene produced by the cracker is being consumed at Ingleside facility in the production of VCM, nearly all of which is being exported to Mexichem facilities in Mexico and Colombia, where they convert the VCM into PVC and PVC piping systems. The successful completion of the project and the structure of our partnership with Mexichem assures that the cracker will continue to operate at high operating rates over the course of our 20-year agreement and that both parties will receive returns on an investment that well exceed our cost of capital. This investment is not based upon any secured merchant sales of ethylene or new VCM business, but rather allows us to further back-integrate our value chain to support existing business with Mexichem. This value-based approach is in alignment with our overall company goals. While we continue to invest in our chemical operations, including our latest investment in Geismar, Louisiana that will provide the feedstock for the production of next-generation refrigerants, the completion of the ethylene project marks the conclusion of a significant capital spending cycle over the past five years. OxyChem's focus will now turn to what it has excelled at, maximizing the value of our assets to deliver significant free cash flow back to the parent company. On slide 14, I will go over a brief overview of the current trends in the chlorovinyl market. After a multiyear downturn at the beginning of 2013, the chlorovinyl market has been on a trend of sustained earnings improvement since the second quarter of 2016. The primary driver of the earnings improvement is increased margins in our liquid caustic soda business. OxyChem is the world's largest marketer of liquid caustic soda, selling approximately 3 million tons each year, and is the largest exporter of caustic soda in the United States, led by our advanced logistics from our Ingleside, Texas facility. Both domestic and export caustic soda prices have risen sharply. While average domestic spot prices have risen nearly $190 per dry short ton since March of 2016, export prices improved nearly $250 per dry short ton in the same period. In addition, OxyChem just implemented an additional $50 per dry short ton price increase for the second quarter in every account where contract terms permit it. On the PVC side of the business, we secured $0.06 per pound of price increases in the first quarter, as we worked to recover margin lost due to ethylene escalation since the second half of 2016. We are committed to take the actions necessary to improve the profitability of this business segment to an acceptable level. Two factors are the source of chlorovinyl business improvement
Joseph C. Elliott - Occidental Petroleum Corp.:
Thank you, Rob, and good morning, everyone. Today I'll provide an update on our Permian Basin business and how it's driving the plan that Vicki outlined in her opening remarks. Our efforts in the Permian are a clear example of how our differentiated value-based approach generates growth in value through a sustainable competitive advantage. As part of our corporate portfolio optimization, we will redeploy the proceeds from South Texas into three to five additional Permian Resources rigs, bringing the Resources rig count to 11 to 13 by year end, including outside operated. This activity will increase Resources 2017 capital to between $1.6 billion and $1.8 billion but without increasing OXY's capital budget of $3.6 billion. This activity is aligned with our value-based approach to development and should result in a moderate increase of about 10,000 MBOE per day to the 2017 exit rate. This impact will be more pronounced as we exit 2017 and enter 2018. We are pursuing trades, partnerships, and sales opportunities using the tail of our portfolio to fund accelerated growth within our core developments. We understand the value benefits of acceleration and believe our Permian inventory can support monetization opportunities and high-value long-term growth. We also appreciate the necessity for value-based development and have found that the NPV benefits of acceleration can be quickly offset by suboptimal development plans, so we will be disciplined in our approach to maximize shareholder value. Our value-based development begins with the subsurface and surface workflows, where we ensure all key attributes are aligned, including bench and well sequencing, well spacing, infrastructure, and technology advancements. We continue to apply innovative technology into our plans, and we will provide additional disclosure as we deliver results there. We understand the importance of cost leadership in our development plans, which starts with commercial strategies and partnerships to protect margins. So we're taking the right steps to minimize OXY's exposure to cost inflation and supply constraints as activity ramps up. As we work toward our OXY financial goals, both Permian businesses will play an integral part of the strategy. Permian Resources is capable of generating free cash flow in 2018 at greater than 20% growth. We will also continue modest investments in Permian EOR, which is currently generating free cash flow and provides a stable business to help manage through volatile market conditions. For reference, the Permian EOR business provides about $35 million of operating cash flow for every dollar increase in oil price. Turning to slide 16, I'd like to highlight the low capital intensity growth in Permian Resources. We can grow production at greater than 20% CAGR while investing only $1.3 billion to $1.5 billion in CapEx each year. That equates to approximately $30 million of CapEx for every 1,000 BOE per day of wedge production in the first year. Achieving this capital intensity metric represents a 50% improvement from our previous performance. Simply put, our development program is producing more oil with less cost. The sustainability of our low capital intensity will be grounded in replenishing our low breakeven inventory by realizing the full potential of our high-quality reservoirs through subsurface engineering, technology advancements, and thoughtful infrastructure design. In 2017, we are targeting a 400-plus well increase in our less than $50 breakeven projects, which is about three times our 2017 drilling pace. We believe our Permian Resources capital intensity differentiates us from most of our peers and will allow us to grow production and generate free cash flow by 2018. With the reinvestment of the South Texas proceeds, we're now on track for the 30% CAGR case. However, we will continue to assess the pace of our development program to ensure alignment with overall corporate objectives. Turning to our Greater Sand Dunes area on slide 17, we continue to see improvements in our Bone Spring program. On previous calls, we've highlighted our top-tier Second Bone Spring program, but our Third Bone Spring and Wolfcamp XY wells are also yielding play-leading results. We've optimized our well design and landing zone and expect to see continued improvement in returns as we get more oil and drill longer wells. In Q2 we will drill six total Third Bone Spring and Wolfcamp XY wells that utilize existing facilities and contribute to the value-based low capital intensity growth. Given the number of proven high-quality benches, New Mexico will continue to reduce its capital intensity and progress to multi-bench development, where we will realize more than a $10 breakeven reduction, as secondary benches can utilize many of the previous investments from the primary bench. We currently operate two rigs in the Greater Sand Dunes area and can reach five operated rigs by year end. Moving to slide 18, in our Greater Barilla Draw area, we're operating three rigs and will add two additional rigs in the second quarter. We continue to progress the detailed subsurface characterization in mapping in Red Bull South to ensure we maximize value while also working the surface constraints to drill longer laterals. In the short time we've operated Red Bull South, we've reduced the completion cost by 23% while improving well productivity. In the Lockridge area of the Greater Barilla Draw, we performed a Wolfcamp A and Bone Spring spacing test. The wells are achieving type curve, but we found a new landing zone option that we expect to improve future results and add significant value to future development. We expect to exit the year with approximately four to five rigs in the Greater Barilla Draw area. Slide 19 demonstrates where our value-based development is yielding great results in two benches at our Merchant area in the Midland Basin. The teams were able to optimize the landing zone and well design of the Wolfcamp B, which resulted in more oil and a significant increase to the economics of the program. The better well productivity, long laterals, and cost improvements have yielded two development benches with all-in breakevens under $40. We currently have two rigs in Merchant and will average two rigs for the remainder of the year in the Midland Basin. On slide 20, I'd like to introduce a new development technology we call single-location sequenced laterals, or SL2. This is an example where we leveraged our experience with multi-laterals in the Middle East to innovate the unique lower-cost design for onshore unconventional application. The technology will allow us to operate multiple benches in a field at lower full-cycle cost. We believe this technology, which is licensed to OXY, will drop secondary bench breakevens by approximately $5 a barrel. We successfully completed first multi-lateral in December 2016 and are designing many of our new wells to support the technology for future reentry. While we will continue to pilot the technology in 2017, we expect the development application to be in the 2018-plus timeframe, when second and third benches are more predominant in the development program. On slide 21, our logistics and maintenance hub, located in Eddy County, New Mexico, features a transloading facility capable of handling three unit trains of frac sand with 30,000 tons of storage capacity. In addition to frac sand, the logistics hub is also designed to handle hydrochloric acid from OxyChem, oil country tubular goods, and to provide a base for maintenance and support of strategic drilling and completion services. This project represents alignment of top-tier industry partners leveraging their strengths to remove cost inefficiencies from the overall value chain. In addition to economic benefits, this approach provides us with a secured supply of critical materials as well as distribution channels. With the sand supply tightening and existing terminal space being contracted, this project secures OXY's ability to execute our development program in southeast New Mexico without concern for scarcity of supply. This provides OXY the benefit of backward integration, with each partner managing their corresponding core businesses to remove the operational and business risks associated with the conventional vertical integration model. Based on the win-win value assessment for OXY and our partners, we're evaluating options for additional logistics and maintenance hubs in the Greater Barilla Draw and the Midland Basin. Our efforts in the Permian Basin are a clear example how through differentiated value-based approach generates growth and value through a sustainable competitive advantage and differentiates us from our peers. I'll now turn the call back over to Chris Stavros for guidance.
Christopher G. Stavros - Occidental Petroleum Corp.:
Thanks. With respect to guidance, we expect our full-year 2017 companywide production growth from ongoing operations and adjusted for the sale of South Texas to be in the range of 4% to 7% or between 595,000 to 615,000 BOE per day. This is unchanged adjusted for South Texas relative to what we said historically. This includes a modest impact of OPEC quota constraints and volume effects under our production sharing contracts due to higher oil prices. Our long-term production growth expectations remain at 5% to 8% per year. As a result of increased drilling activity later in the year, we expect production in the Permian Resources to exit this year at a growth pace approximately 30% higher than year-end 2016 levels. For the second quarter, we expect a significant recovery in total company ongoing production volumes and in the range of 580,000 to 595,000 BOE per day. Production at Permian Resources is expected to be between 135,000 and 140,000 BOE per day in the second quarter. Every $1 per barrel change in WTI affects our annual operating cash flow by about $110 million. In our Midstream business, we see a return to profitability, as we expect the second quarter to generate pre-tax income of between $5 million and $15 million. Foreign income from pipeline and other facilities should improve, as planned maintenance at Al Hosn and Dolphin was completed earlier in the first quarter. A large portion of the financial improvement in Midstream should be driven by wider oil price differentials between Midland and the Gulf Coast and partly as a result of rising production in the Permian Basin. In Chemicals, we anticipate pre-tax earnings of about $200 million for the second quarter as a result of continued improvement in caustic soda prices and the benefit of operations from the new joint venture ethylene cracker. Looking forward, our Chemicals business is on a pace to generate approximately $250 million per quarter of free cash flow for the remainder of the year. I'll now turn the call back to Richard.
Richard A. Jackson - Occidental Petroleum Corp.:
Okay. Thank you, Chris. Kate, we are now ready for questions.
Operator:
We will now begin the question-and-answer session. The first question is from Ed Westlake of Credit Suisse. Please go ahead.
Edward Westlake - Credit Suisse Securities (USA) LLC:
Yes, good morning and congratulations on the work on lowering breakevens. Maybe if I can talk about the dividend coverage. One of the numbers that helps when investors think about that is maybe the maintenance CapEx number, the CapEx to keep obviously your downstream units in operation and production flat. I don't know if you have an update on that, because obviously international costs are still deflating and the work you're doing in the Permian may have lowered that. So any color there would be helpful.
Vicki A. Hollub - Occidental Petroleum Corp.:
Ed, currently we're seeing about a $2.2 billion sustaining CapEx, but we do expect that to come down. We're seeing price improvements in international operations. We're also, as you've heard, still seeing significant improvements in our Permian Resources business so that we expect, as that capital intensity goes down, this will also decrease. But with our current situation, we're certainly less than $50 to be able to cover our sustaining capital and dividend.
Edward Westlake - Credit Suisse Securities (USA) LLC:
Okay. And then good color on the Chemicals. Thanks for that, that $400 million shift. The Midstream is improving, which is good to see. I don't know if you'd be able to hazard a guess at where you see mid-cycle Midstream earnings with the Permian perhaps closer to filling up the pipe sometime next year or 2019.
Christopher G. Stavros - Occidental Petroleum Corp.:
I think, Ed, certainly the arrows, as I said at the outset, the arrows are pointing in the right direction for that business as well. I think the differentials are suggesting that we see profitable periods for the remainder of the year, frankly, certainly in the second quarter and in the back half of the year as well. So if conditions continue to move in this direction as far as Permian production based on the rig adds that we've seen, it's, frankly, looking pretty good going even into – exiting this year and certainly going into next year as well.
Edward Westlake - Credit Suisse Securities (USA) LLC:
So you'd figure that there may be some acceleration around that at that point because, obviously, some of it's related to contracts you have that need certain volumes to be hit.
Christopher G. Stavros - Occidental Petroleum Corp.:
Yes, we would be profitable in excess of any contracts we have in place.
Edward Westlake - Credit Suisse Securities (USA) LLC:
Okay. Thank you.
Operator:
The next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. Good morning, everybody. Vicki, I'm not sure who wants to take this one, but I think you've talked about the Permian previously being self-funding in 2018 at around $50. With the higher level of activity, and obviously I think Jody had pointed to the higher end of the growth rate, what does that look like now? Are you still self-funding at $50 oil in 2018 with the higher activity?
Joseph C. Elliott - Occidental Petroleum Corp.:
Good morning, Doug. This is Jody. Even with the higher activity rate, all it does is push that timeframe out a few months in 2018. So the improvement in capital intensity really does help that timeframe for the Permian Resources breakeven.
Doug Leggate - Bank of America Merrill Lynch:
Okay. I appreciate that. The question that continues to come up, obviously, is around the dividend despite your assurances around breakevens and so on. So I wonder, Chris, if you could address one specific issue, which is the roll-off of your Middle Eastern contracts in Qatar, I think 2017 and 2019, respectively. What is the status of those contracts? Is it a material free cash contribution? And just a general status update as to how that might affect the breakeven calculus as you move forward. I'll leave it there. Thanks.
Vicki A. Hollub - Occidental Petroleum Corp.:
Doug, I'd like to start with that. We feel that we're in a good situation in Qatar. First, let me say we don't have anything rolling off in 2017. Actually, our ISND contract would be in October of 2019. But really what we're doing today in Qatar is, I believe, some of the best work that we've done anywhere in our company in a long time. I'm going to have Ken describe some of the things that we're doing there that give us some confidence that we would be able to extend that contract. Saad al-Kaabi, the CEO of Qatar Petroleum, the thing that mattered to him most is that we add the most value possible for every dollar we invest in Qatar. We believe that with the success our teams are having there, that we're going to be able to meet his expectations. And our teams are working well to be able to share best practices, to help each other to accelerate some of the technical work and new technologies that we want to do. So we've actually established some things there that are different than being done anywhere offshore in the Middle East. That, along with the fact that we successfully negotiated the extension of the Block 9 contract in Oman, gives me a lot of confidence that we'll be able to continue. I'll pass it on to Ken to give you some of the details around some of our activities.
Kenneth Dillon - Occidental Petroleum Corp.:
Good morning, Doug. It's Ken. Our approach is basically the same as the one we went with for the Block 9 extension. Our goal is to remain the partner of choice in Qatar. We're focused on technology, reputation, and operational excellence. Our new innovative wellhead platform designs, which provide drilling for about 50% cheaper than conventional Middle Eastern platforms with 40% more capacity, are in detailed design at the moment. Our next-generation reservoir models for ISND and ISSD are nearing completion and showing positive results. And the combination of just these two aspects mean we can deliver the same reserves for less than half the cost than our previously submitted Phase 5 proposal. We're now starting to roll out OXY Drilling Dynamics and OXY lift, so we think we can make improvements on the Phase 5 performance. And we are already the low-cost operator in Qatar. The last thing I'd really like to emphasize is last year offshore we hit zero recordable incidents and we've had none this year. That's really excellent worker safety performance in Qatar and one that I think that the team should be proud of. So we're very focused on this. We have regular meetings and we continue to improve month on month.
Doug Leggate - Bank of America Merrill Lynch:
Just to be clear, it sounds obviously you're – I can't help but think you're pretty optimistic about being able to extend the contract for a number of reasons. But could you quantify the free cash contribution in the current oil price environment, just to put that issue to rest?
Christopher G. Stavros - Occidental Petroleum Corp.:
Doug, the best way I would put it is that the plan we have in place from the other assets, and as Vicki discussed certainly around the Permian, would more than make up for cash flow absence if that were to happen in Qatar, I think is what you're asking. It's something that I would view as immaterial relative to the total cash flow that the company generates. By that, I mean less than 5% of the total cash flow that the company generates. So I think that based on the plan that we just laid out, we can accommodate additional cash flow growth and opportunities from the assets that we've got to make up for any shortfall if that were to occur, but we don't think that will happen.
Doug Leggate - Bank of America Merrill Lynch:
So sub-$200 million sounds about in the ballpark?
Christopher G. Stavros - Occidental Petroleum Corp.:
That's probably right. That's right.
Doug Leggate - Bank of America Merrill Lynch:
Okay, great. Thanks a lot, everybody.
Operator:
And the next question is from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Hey, good morning, guys. You guys are telegraphing a stronger commitment to a higher Permian growth rate exiting – I think it was 30%, which is at the high end of the range, in 2017, and you used operational momentum, asset sales, and balance sheet to support it. How do you think about the financial flexibility and willingness to support to continue to outspend if the commodity market remains challenging, or any thresholds? Specifically, you're stepping up as that market is backing off some.
Vicki A. Hollub - Occidental Petroleum Corp.:
Evan, we want to continue to grow Permian Resources. This is really a drive to continue to lower our cash flow breakeven for not only our growth capital but for additional opportunities in ways that we could use our cash. So currently, we'll continue to be active and aggressive with our development in Permian Resources. We're going to fund that through resources that we have. And so in an oil price above $50, $50 or above, we're going to continue on this path to get to a lower breakeven for our growth capital as well. Now if commodity prices are not what we expect, we would certainly adjust our plans because we do have that flexibility. But at prices above $50 and above, we'll continue on our plan. And with what we see, we expect that this year we will average better than $50, and then next year will be we think even better than that. Oil prices are doing pretty much what we expected them to do. We expected to see volatility early in the year. We expect to see that until inventories come down much further than they have so far. We do have contingency plans, but as of right now with what we see we'll continue aggressively on this path.
Joseph C. Elliott - Occidental Petroleum Corp.:
And, Evan, this is Jody. I think that's the reason why we provided you the guidepost between the 20% and the 30% CAGR case to show you that even with growth there's some flexibility in the capital depending on commodity price.
Evan Calio - Morgan Stanley & Co. LLC:
Right. And I guess you're running the exit rate at 11 to 13 rigs, which is well above the 9-year average for 2018. It sounds like that's something you'll address as you go into that budgetary period.
Joseph C. Elliott - Occidental Petroleum Corp.:
Exactly.
Evan Calio - Morgan Stanley & Co. LLC:
Second question, you guys are talking about adding 500 locations to your sub-$50 Permian Resources inventory in 2017. Could you just provide color on what's driving the additions or where is the focus? Are these new locations or moving existing locations down the cost curve, or within that, the 350,000 acres that are in your portfolio, whether you don't have associated location counts? Any color on that program would be helpful.
Joseph C. Elliott - Occidental Petroleum Corp.:
Evan, good question. And you sound a little like Vicki. I give her 400, and she changes it to 500. It's 400-plus, but our stretch is bigger than that. It's really coming from multiple places. It's second and third bench development in existing areas, so taking benches that may not have been profitable and finding ways to make them profitable through either the lower capital intensity, the better production rate. It is some from the acreage outside of the core areas. But again, you've got to remember, our inventory is big in those core areas. So we're not just working one area; we're working both. I think the other thing that really we see happening is wells – we're not adding wells in some cases, but we're moving them to the left in that inventory curve. So the breakevens are coming down, so really working all three areas.
Vicki A. Hollub - Occidental Petroleum Corp.:
But, Evan, let me add. I do appreciate you driving up Jody's target.
Evan Calio - Morgan Stanley & Co. LLC:
It's at 600, right?
Vicki A. Hollub - Occidental Petroleum Corp.:
I was looking for that.
Operator:
The next question is from Roger Read of Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Hi, good morning. I guess I'd like to understand. As we think about some of the cash margin and the cash breakeven here, the sale of your South Texas assets, how does the cash margin on something like that compare to the reinvestment? I recognize it's not a sell yesterday, get the cash flow tomorrow kind of thing, but what's the general today to say Q1 next year thought process on something like that?
Vicki A. Hollub - Occidental Petroleum Corp.:
What we looked at was the replacement ratio, which is 9,000 barrels of oil equivalent per day, which is three-to-one for Resources production versus South Texas production. And with the funds, we've added sufficient rigs to be able to make up that difference and that cash flow within about five to six months.
Roger D. Read - Wells Fargo Securities LLC:
That's pretty nice cash payback?
Vicki A. Hollub - Occidental Petroleum Corp.:
Yes, it is.
Roger D. Read - Wells Fargo Securities LLC:
All right. And then a follow-up to an earlier question on the Midstream. The expectation is that as pipelines start to fill, you're able to recapture some of the differential in the Midstream, something that hasn't been the case over the last probably 18 months. But there's also a lot of expansion in the pipeline system going on. So I was just thinking. As we look to 2018, has some of that recapture potential slipped from 2018 and maybe into 2019, just any clarity you can offer there?
Vicki A. Hollub - Occidental Petroleum Corp.:
Currently the expansions haven't really occurred, so we're still seeing some benefit from that. Now we expect that through the rest of this year we'll see benefit. Going into 2019, it will depend on the growth trajectory within the Permian Basin, but we do expect significant growth. So we're right now anticipating continued improvement in our Midstream business because of that.
Roger D. Read - Wells Fargo Securities LLC:
Any way to think about quantifying that though in terms of – I'm just really trying to think. There's typically a utilization level to think about, but then there's also the actual differential. Where are we today on utilization relative to where you think we need to be to start seeing you capture of that differential?
Christopher G. Stavros - Occidental Petroleum Corp.:
I think we're capturing it now. It's clear in our results. And that was, as I said in the prepared remarks, that was a large portion of the driver for the second quarter improvement. And based on how things are transitioning, it should potentially accelerate in the back half of the year. So I think you're seeing that.
Roger D. Read - Wells Fargo Securities LLC:
Okay, I'll follow up offline, but I appreciate it. Thank you.
Operator:
Your next question is from John Herrlin of Société Générale. Please go ahead.
John P. Herrlin - SG Americas Securities LLC:
Hi. With respect to big data, could you be a little bit more specific about what you're doing? Is it for better frackability, better design in your wells? What specifically are you doing, and what kind of savings do you think it will bring you?
Joseph C. Elliott - Occidental Petroleum Corp.:
John, this is Jody. It's really multiple areas. One of the first areas was a multi-variant analysis combining both geologic data and completion data to speed up the process of finding optimum frac designs. We're utilizing analytics and OXY Drilling Dynamics. It's what we call OXY Drilling Dynamics 2, which is putting predictability of motor yields and motor performance into that program. It's around reservoir modeling, being able to take what we do as a very – just slower process for reservoir optimization using very robust models, we actually are using a low-resolution model that we can optimize the injectant more on a real-time basis. That applies in Mukhaizna for steam flood. It will apply to our water floods. And then we will move to our CO2 flood. So these higher-cost injectants get optimized on a day-to-day basis. And I could just keep going here. The list is longer than the resources to tackle these, so we're putting them in priority order. We're really excited about what analytics can do to real step changes in our business going forward.
John P. Herrlin - SG Americas Securities LLC:
Great. Then the next one for me is on your logistics hub. Is this enough for your intermediate-term growth, or will you be building another one down the line?
Joseph C. Elliott - Occidental Petroleum Corp.:
So in southeast New Mexico, it's sufficient for our intermediate and long-term growth. There's quite a bit of capacity there. We also see it, as you mature in an area and you move off of the rapid growth and now you're into the day-to-day operating cycle, we have enough space there that you can start thinking about maintenance shops for pumping units and compressors. And so it migrates over time from a capital logistics and maintenance hub to an operating hub. And so we're looking in both Greater Barilla Draw and now in Midland to see what aspects of the Southeast New Mexico project make sense there.
John P. Herrlin - SG Americas Securities LLC:
Great. Thanks very much.
Operator:
Your next question is from Paul Sankey of Wolfe Research. Please go ahead.
Paul Sankey - Wolfe Research LLC:
Good morning all. Thank you. Vicki, historically the company's differentiation, and you spoke about differentiation in your comments, has been the dividend and the growth in the dividend. I assume that the lower breakevens that you're talking about and everything else are ultimately aiming towards the growth in the dividend approximately in line with volume growth. Is that fair? And could you also just repeat the free cash flow numbers from Chemicals? And, if you could, give us that number for the quarter? That would be all part of the same thought process. Thanks.
Vicki A. Hollub - Occidental Petroleum Corp.:
Yeah, Paul. We're trying to drive our cash flow breakevens down just for that. What we want to do is be positioned to be able to resume significant growth of the – or maybe I should say moderate growth, not exactly the growth we've seen over the last 10 to 15 years prior to the downturn in the dividend, but we do want to grow the dividend at a meaningful rate. So that's the reason for this accelerated growth to get to a lower breakeven.
Paul Sankey - Wolfe Research LLC:
And the Chemicals?
Vicki A. Hollub - Occidental Petroleum Corp.:
Rob?
Robert Lee Peterson - Occidental Chemical Corp.:
Free cash flow from Chemicals should be in the range of about $750 million for the year.
Paul Sankey - Wolfe Research LLC:
That's for this year and that could then be considered a run rate?
Robert Lee Peterson - Occidental Chemical Corp.:
Plus the additional $75 million I described in the prepared remarks for the contribution full year of the cracker and the refrigerant plant.
Christopher G. Stavros - Occidental Petroleum Corp.:
The run rate, Paul, as I said, is $250 million for each quarter for the remainder of the year and then it accelerates into 2018.
Paul Sankey - Wolfe Research LLC:
Yeah. I just thought it actually bore repeating and I wanted to make sure I heard you straight. That's great. Thanks very much indeed.
Operator:
The next question is from Phil Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Hey, hi. Good morning. My first question is just going back to the cash flow breakeven at $50 WTI. The slide was talking about including growth capital in the number. So I was wondering what total capital number you're using there. Would it be consistent with the $3.6 billion that you're talking about for this year, or a higher number?
Vicki A. Hollub - Occidental Petroleum Corp.:
Ultimately for 2018, the number would be higher. But on a run-rate basis, to provide the 5% growth would be somewhere in the $3.6 billion to $3.9 billion range.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. So if I look at that slide then and I take $3.6 billion or something slightly higher and the dividend of about $2.4 billion, that would imply CFO of around $6 billion at $50 WTI. And, Chris, I know a couple quarters ago for this year you talked about I believe at $50 it's $4.5 billion. So I was just wondering what drives a one-third increase in the implied CFO to get to that breakeven.
Christopher G. Stavros - Occidental Petroleum Corp.:
What drives it higher is the better margins and better productivity and better wells that we're seeing in the Permian Basin, number one, better margins and the refocus of the capital that we've discussed today from South Texas and from other things going forward. What drives it is the improvement relatively versus several quarters ago in the Chemicals business. What drives it is the improvement in the Midstream business that we're seeing that we had not seen several quarters ago. So there are several items that, frankly, have changed in a markedly better way that give us more confidence in our ability to generate that higher number going forward with the reinvestment and better conditions in some of the other businesses.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. Got it. Last question, just the domestic OpEx number. Chris, I think it went from $13 billion to $14 billion for the year. I was just wondering. What was the main driver of higher domestic OpEx?
Christopher G. Stavros - Occidental Petroleum Corp.:
Yeah, the main driver really is just reconstituting the number for the absence of South Texas going forward and a little bit higher prices for injectant CO2 prices. That's really it.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. Thank you.
Operator:
The next question is from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co.:
Thank you. Good morning. I appreciate some of the specifics on big data in response to the earlier question. I wanted to probe on what you think is uniquely going to be OXY here because I think beyond the secondary and tertiary recovery that has long been an OXY strength, it seems like you're confident in the ability to drive higher recovery rates from primary drilling versus peers. And I wanted to see what you think gets you to a superior recovery rate versus simply increasing recovery rate at a similar pace as your competitors.
Joseph C. Elliott - Occidental Petroleum Corp.:
Brian, this is Jody. At this point, probably not talking about what recovery mechanism might be the optimum. We've got experience everywhere, Ken's Mukhaizna field, the Qatar field, in our EOR business we find ways to get the most recovery out of these reservoirs economically. And so we believe the unconventional business is an incredible target because the recoveries in primary are so low. And so we believe OXY is uniquely positioned to find that extra 5% or 10% additional recovery and leverage the infrastructure investment we've already made in those fields.
Brian Singer - Goldman Sachs & Co.:
And that is in part by the various types of data analytics that you mentioned in response to the earlier question that you think will end up being more proprietary?
Joseph C. Elliott - Occidental Petroleum Corp.:
I think analytics plays a role there in accelerating your learning because you can do many things by analyzing the data quickly with different models that prevent you from having to do them with experiments or trials in the field. But it will be a combination of data analytics, field trials, laboratory work, research work that then point us to the right application of a technology, depending on which type of reservoir. Again, it all begins with the core understanding of the reservoir. Does the underlying rock fabric have some higher fraction of conventional fabric? Is it truly a source rock shale, very high organic? That application will be specific to the reservoir.
Brian Singer - Goldman Sachs & Co.:
Thanks. And then on the SL2, the multi-lateral wells, can you talk to the timeline for pilot results and what those pilots look like versus the schematic on slide 20?
Joseph C. Elliott - Occidental Petroleum Corp.:
We've completed our first one. We've drilled the second lateral, and the key part of that is we have stimulated the second lateral. So as the second lateral depletes, we're in the process of removing the frac string and then we'll put it on artificial lift. We'll do more of those this year. The real application of the technology plays out in 2018 and beyond because that's when you're doing your second and third bench development as a higher proportion of the program.
Brian Singer - Goldman Sachs & Co.:
Thanks, one very quick one, Chris. Did you say earlier what you expect 2Q asset sale proceeds to be net after tax?
Christopher G. Stavros - Occidental Petroleum Corp.:
We said – or I said that I expect the proceeds from South Texas to be nearly $600 million net after tax.
Brian Singer - Goldman Sachs & Co.:
Thank you.
Operator:
And the final question today comes from Doug Terreson of Evercore. Please go ahead.
Doug Terreson - Evercore Group LLC:
Good morning, everybody. I just have a quick question on corporate governance and specifically your new documents, which indicated a little bit of a shift away from the returns-based metric that you've used historically in favor of payouts that are based on total shareholder return, which is pretty similar to that of your peers. And so when you consider the emphasis on returns and value in your materials and commentary today, which is pretty prominent, my question is was this change undertaken because returns and other measures appear to be consumed by total shareholder in your view, or is something else at work here, meaning why did we have the shift there?
Vicki A. Hollub - Occidental Petroleum Corp.:
We had a shift because it was really a situation where we wanted to ensure that we were still looking at the metrics with respect to how others are performing. In the cyclic industry that we're in, we're in a situation where returns were very much impacted, as you know, by oil prices. Now we're in a situation where we have internally targets for all of our executives that are based to some degree on a returns metric. Going forward, we expect to resume including the returns metric as a part of our performance management programs. And that will be because of the fact that we believe that in the situation that we're in today, we're now generating positive earnings. We'll generate again positive returns on capital employed. And that's always been something that's been important for us, and it will be and is today an internal metric.
Doug Terreson - Evercore Group LLC:
Okay, so it's as important as it's ever been, it sounds like.
Vicki A. Hollub - Occidental Petroleum Corp.:
It is. That's why we've talked about it so much today. We're really building our business and we've gone through this whole process, this painful process I'll say of exiting 300,000 barrels a day to get us into a position where every dollar we spend goes for the highest possible return projects. Exiting the things that we did with the timing that we had has now given us the opportunity to grow production with the best possible quality assets. And you look at it, every asset we have today is generating double-digit returns on capital employed. And so we're better positioned now to take advantage of that, and our company is going to be able in the future to excel in that area.
Doug Terreson - Evercore Group LLC:
No, that's textbook. Thanks a lot.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you.
Operator:
This concludes our question-and-answer session. I would like to turn the conference back over to Richard Jackson for closing remarks.
Richard A. Jackson - Occidental Petroleum Corp.:
Thank you, Kate. We would just like to thank everybody for joining us today and look forward to future discussions with our team. Thanks.
Operator:
This conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Christopher M. Degner - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Christopher G. Stavros - Occidental Petroleum Corp. Joseph C. Elliott - Occidental Petroleum Corp. Kenneth Dillon - Occidental Petroleum Corp.
Analysts:
Evan Calio - Morgan Stanley & Co. LLC Roger D. Read - Wells Fargo Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC Asit Sen - CLSA Americas LLC Brian Singer - Goldman Sachs & Co. Pavel S. Molchanov - Raymond James & Associates, Inc.
Operator:
Good morning and welcome to the Occidental Petroleum Corporation's fourth quarter 2016 earnings conference call. Please note, this event is being recorded. I would now like to turn the conference over to Chris Degner. Please go ahead.
Christopher M. Degner - Occidental Petroleum Corp.:
Thank you, Kate. Good morning, everyone, and thank you for participating in Occidental Petroleum's fourth quarter 2016 conference call. On the call with us today are
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Chris, and good morning, everyone. Today we'll provide you a summary of our 2016 results, a high-level preview of 2017, and a more detailed update of our Permian inventory. But the key message I'd like to convey is that we will continue to provide value to our shareholders through an attractive dividend and an ability to grow our cash flow and earnings through moderate production growth while maintaining a strong balance sheet. This has been our strategy for a long time and it has not changed. What has changed is that we have dramatically derisked the delivery of that value proposition. The quality of our portfolio today enables us to achieve our corporate goals through organic growth. Our exit from non-core areas along with proving up our Permian Resources inventory provides us with a good blend of low-decline long-term cash flow generating assets that are important to support our dividends, along with significant short-cycle growth opportunities. We can now provide all of our targeted cash flow and earnings growth through organic development. In fact, Permian Resources can do it alone. From 2013 to 2016, we've doubled Permian Resources production. We can more than double it again over the next four years in a moderate commodity price environment. We can do this because we are a more geographically-focused company today. This focus has led to technical and operational improvements in all of our core areas. We have long been recognized as a global leader in enhanced recovery technology. As shown on slides 6 through 8, with our more focused approach, we have built on our historical successes and are achieving even greater success today in our core international operations. A recent example is the Al Hosn gas team, who increased the rated capacity of the gas plant to 110% of its original nameplate. We have now achieved the same level of success in our unconventional operations in the Permian. In late 2013, we began the transformation of our unconventional business by restructuring into smaller strategic teams with greater emphasis on subsurface technical excellence and operational execution efficiency. This has paid off as we executed an aggressive appraisal program in 2014 followed by focused development plans in 2015 and 2016. Our expanded subsurface expertise along with our innovative drilling and completion practices has resulted in step-change improvements in our unconventional operations. We can now generate play-leading returns that are robust, even with lower oil prices. Jody will provide more detail on our Permian business. As excited as we are about Permian Resources, the powerful combination of our long-term resource potential, our technical capability, and our partner relationships is even more compelling. The Permian, our Middle East countries, and Colombia all have one thing in common. They have significant remaining resource potential waiting to be unlocked by our technical expertise, from primary to secondary to tertiary recovery. Unlike some of our competition, we don't have to look elsewhere for opportunities, and we believe the Middle East and the Permian will continue to play a critical role in supplying the energy needed to meet the world's ever-increasing needs. We are unique in providing this opportunity to investors. In 2016, our oil and gas operations continued to lower total cost structure and increase recoveries from our reservoirs. You'll see the impact of this later in our reserve statistics. Slides 10 through 12 show highlights of key 2016 accomplishments in all of our areas. I won't read them all, but I would like to point out that we ended 2016 with $2.2 billion in cash, and we were able to achieve the higher end of our production guidance with less capital than expected. This is due to our capital execution efficiencies and is reflected in our F&D costs. We replaced nearly 190% of our production at a cost of $9.65 per BOE. As a result, our total proved reserves increased from 2.2 billion BOE to 2.4 billion BOE, mostly due to Al Hosn and Permian Resources. Al Hosn reserves increased due to better than expected reservoir performance. The increased reserves in Permian Resources were driven by a successful development program and higher well productivity. Based on our Permian Resources current inventory of 11,650 wells, we'll be able to continue to replace reserves for the foreseeable future. Our current proved reserves are limited only by the five-year SEC rule. Last year's drilling program in Permian Resources delivered strong reserve replacement at an F&D cost of less than $9 per BOE. When combined with our total cash costs of approximately $11 per BOE, an incremental dollar investment in our Permian Resources business delivers pre-tax margins in excess of 50% at $55 WTI. As we go into 2017, we have more confidence in the stability of the oil markets and increased flexibility in our capital plan, as we have completed most of our multiyear investment programs. We are encouraged by the recent OPEC decision to lower production quotas, and we've seen the read-through in our operations and an increased demand for our crude in international markets. Our capital plan will prepare the business for an improved commodity price environment heading into 2018 while maintaining the flexibility to adjust activity if market conditions warrant. We'll continue improving our operational and technical excellence to further reduce our cost structure and improve recoveries. Based on our available cash and market conditions, we'll execute a capital plan of between $3 billion and $3.6 billion in 2017. In addition to cash flow from operations, our capital program will be supported by cash flow from a sizable tax refund and the monetization of non-core assets. We're reducing capital in Permian EOR and Chemicals while holding capital flat in the Middle East and Midstream. We'll increase capital moderately in Colombia and significantly in Permian Resources. Our plan anticipates oil prices to remain approximately as reflected in the futures markets. In the Permian Basin, the increase in capital spending will be mostly directed to increased activity in southeast New Mexico and the Greater Barilla Draw area. As I mentioned previously, the short-cycle nature of our development programs provide us the flexibility necessary in an uncertain market environment. If we see declines in oil prices, we will adjust our capital program down. With increased spending in our oil and gas business, we expect production from our core assets to grow 4% to 7% in 2017 adjusted for production-sharing contract effects. Most of the increase in production will be driven by Permian Resources. In closing, I'd like to reiterate that our cash flow priorities have not changed. Our top priority for cash flow is and always will be the safety of our employees, contractors, and public along with the maintenance of our operations. The next priority is to support the growth of our dividend. Any remaining available cash will be used to fund growth opportunities, primarily through organic growth and Permian Resources. All of our decisions are driven by a focus on returns and our strategy to continue to grow the dividend over the long term. As you know, this puts us in a unique position in the industry. We are more similar to majors with respect to our dividend, cash flow, and balance sheet objectives. But unlike majors, we have a greater growth potential because we have an incredible portfolio. To maximize the value of this unique position, we must be technically excellent and have a high level of operational efficiency. Focus will do this for us, allowing us to widen our competitive advantage. And, we'll continue to make deliberate decisions with respect to capital allocation. Keeping our capital allocation decisions consistent with our long-term strategy we believe will result in increased stock market value. Now I'll turn the call to Chris Stavros for a review of our financial results.
Christopher G. Stavros - Occidental Petroleum Corp.:
Thanks, Vicki, and good morning everyone. Today I'll focus on the following items
Joseph C. Elliott - Occidental Petroleum Corp.:
Thank you, Chris, and good morning, everyone. During 2016 we asked our teams to outperform many demanding operational and financial targets. Our teams rose to the occasion and exceeded our expectations during an extremely challenging time in our industry's history. Our team showed their resolve and ingenuity by staying focused on the priority needs of the business while developing new ideas and innovative technologies. In particular, I'd like to acknowledge our field employees, who maintained a safe and productive environment every day across our operational locations. Our four main accomplishments in the Permian Basin during 2016 were
Christopher M. Degner - Occidental Petroleum Corp.:
Thank you, Jody. We will now open up the call for questions.
Operator:
The first question comes from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Good morning, everybody, and thanks a lot for the new disclosure this morning. My question is your relative capital allocation in 2017, it's increasing for the Permian Resources up to the mid-30s following these positive well results and inventory update. That appears to be a shift in the strategy towards the Permian. So how should we think about relative capital allocation within this growth bucket? Is it the high end of your Permian guidance, the first call on incremental capital above the dividend and maintenance? And would asset sales like those mentioned in Chris's opening comments, would that drive activity upside in 2017 on the strip, or how do you plan that?
Vicki A. Hollub - Occidental Petroleum Corp.:
Thanks, Evan. First of all, going back to our cash flow priorities, when we're looking at the use of cash flow from operations, as I said in my script, we first allocate to our maintenance capital, our HES [Health, Environment, Safety] safety and sustainability capital. Then we fund the dividend. Beyond that, what we consider the growth capital, to allocate that, what we really look at is the combination of what it can provide for us in terms of returns, and also what it does for us in terms of long-term cash flow. So when we make the allocation decisions, it's a combination of those two that we need to support our objectives and to continue to support the dividend. But within the portfolio now in terms of what we see in the Permian Resources business, that has been and will continue to be generally our highest return business. And we had this past year – it was really a focus for us. We've said for a long time that the Permian Basin is pretty much the foundation of our company, and so Permian Resources is the main growth engine. However, as you can see from the slide 23, of our free cash flow swing in 2017, $400 million we're expecting to come from our international operations. And of that $400 million, about two-thirds of that will come from our Block 9 contract, which we re-signed last month. So the rest will come from Colombia and Al Hosn. So it's critically important for us to continue to work on growing our cash flow while at the same time ensuring that we invest as much as we can in the Permian Resources business, which for now for us is generating really good returns.
Evan Calio - Morgan Stanley & Co. LLC:
Maybe just a point of clarification, does the asset sales that were mentioned earlier, do asset sales then drive upside to what you've provided in the guidance today?
Vicki A. Hollub - Occidental Petroleum Corp.:
Today's guidance was based on the liquidity that we expect to have available to us for 2017. So we don't expect any increase in our capital spend for 2017. We expect $3.6 billion to be the upper end. We'll go into 2018 with what we believe is a pretty strong cash balance, and we'll plan accordingly for increases in capital in 2018 should the market conditions warrant. So what we will look at is we'll look at the prices for not only oil, but in our Chemicals business, and we'll see what the market conditions look like.
Evan Calio - Morgan Stanley & Co. LLC:
Great, my second question, if I could. If we go to the new updated inventory data, can you provide color on what – I think you did in some of your prepared comments, but color on what the 300,000 acres that the location count is based upon represents? Meaning I just want to understand potential location upside from what's been analyzed and understand better your cash priority statement that includes acquisitions, if that reflects a desire to add acreage in the Permian.
Vicki A. Hollub - Occidental Petroleum Corp.:
Okay, we'll let Jody answer the first part of that.
Joseph C. Elliott - Occidental Petroleum Corp.:
Evan, good morning. The 300,000 acres, I think the way to think about that is it's really development-ready. We've been through that appraisal, subsurface evaluation, infrastructure investment, precursor to getting it to our development team. So that's the 300,000. The difference between that and the 650,000 is that's now in the appraisal queue, being worked. A lot of that is being derisked by competitor activity and our OBO [Operated by Others] activity. So that's the difference between the 300,000 and the 650,000 acres.
Vicki A. Hollub - Occidental Petroleum Corp.:
And, Evan, with respect to the monetization of assets, we're continually looking at opportunities too in our portfolio and prioritizing the projects that we have, and we'll always do that. And there may be opportunities down the road where we may find things that would be better monetized today rather than waiting on development. The issue in the Permian Basin is that everywhere we look, as we look deeper, we find more opportunities. So the Permian is a place where we think that it's first of all very difficult to drill a dry hole there. Secondly, the more you learn about it and the more you engineer it, the better your wells get. And so we value that portfolio, but we're still very conscious of the fact that we need to optimize the net present value. So we'll continually look at that. It's this process that we've gone through that's driven us to exit the non-core areas that we've exited in the last couple years. So we'll continue that process.
Evan Calio - Morgan Stanley & Co. LLC:
Great, I'll leave it there. Thank you.
Operator:
The next question is from Ed Westlake of Credit Suisse. Please go ahead. Mr. Westlake, your line is open. Next we have Roger Read of Wells Fargo.
Roger D. Read - Wells Fargo Securities LLC:
Good morning. Thank you. I'll take Ed's question for him. Actually, we could go back to the discussion, Jody, at the end there, the 2,500 locations, and then I guess the discussion of the 650,000 acres. What should we think of as the key items that get analyzed and changed such that you are able to double the number of locations and then think about and increase the number of below-$50 breakeven locations going forward? What are the critical path items we should be paying attention to here?
Joseph C. Elliott - Occidental Petroleum Corp.:
Roger, for us it's really probably two things. It's better execution efficiency. So we're drilling more wells with the same number of rigs at a lower cost. So our time to market is faster. That changes your economics. The other is subsurface characterization combined with stimulation design. So we're landing our wells in places that we believe give us the highest stimulated rock volume. We're staying in zone at a much, much higher percentage through our drilling technologies. And our stimulation designs, in general you're seeing larger, per-sand volumes tighter cluster spacing. But those are really custom designed by each area. So that's really created a lot of the increase as well as we continue to appraise and derisk new acreage. The 2,500 locations below $50, I would think that's a pretty conservative number given that our approach to spacing we think about in that capital-efficient return-based approach. We don't want to overcapitalize these assets, and so we look hard at what spacing ought to be. We evaluate that. We test different spacing scenarios, and then continue to look at spacing scenarios from our OBO exposure and learn from those as well.
Roger D. Read - Wells Fargo Securities LLC:
Thanks. And then along those lines, as we think about on slide 34 the nine-rig baseline of 20% CAGR and the higher rig count for 30%, does that require those 2,500 well sites going up, or is it an oil price-driven event? Or maybe another way of thinking about it, if all these efficiencies come through maybe quicker than you think, do we get 15 rigs and a 30% CAGR, even if crude stays, say, $50 to $55, where it's been here year to date?
Joseph C. Elliott - Occidental Petroleum Corp.:
Roger, there's plenty of inventory. That projection of the 20% and 30% CAGR is from those core development areas. So there's over 14 years of rig activity if you were at 10 rigs to drill up that inventory. So it's not an inventory question at all to drive those kind of growth rates. And the capital requirement for both the 20% and the 30% growth rates are pretty moderate.
Roger D. Read - Wells Fargo Securities LLC:
So I guess then my final question is why not something – and maybe this goes more to Vicki – but why not something a little more aggressive here if the numbers work fairly well?
Joseph C. Elliott - Occidental Petroleum Corp.:
It goes back to being capital-efficient and return-focused. We want to make sure we have the subsurface understanding, our execution efficiency, our technology and the infrastructure all timed properly so that you get the best rate of returns. And then the amount of capital that gets allocated goes back to the priorities that Vicki mentioned earlier.
Roger D. Read - Wells Fargo Securities LLC:
Okay, all right. I think I get that. Thank you.
Operator:
The next question comes from Ed Westlake of Credit Suisse. Please go ahead.
Edward George Westlake - Credit Suisse Securities (USA) LLC:
Hello. Can you hear me now?
Vicki A. Hollub - Occidental Petroleum Corp.:
Yes, we can.
Edward George Westlake - Credit Suisse Securities (USA) LLC:
Oh, thank God, okay. So just on the international production and CapEx, I was thinking that CapEx would come down a bit this year. The $900 million still feels flat year over year. But maybe talk about how long you can keep the international production flat or the growth outlook, say, out through the next few years and how much CapEx it would take to do so.
Vicki A. Hollub - Occidental Petroleum Corp.:
So, Ed, we have lots of opportunities in both – especially in Oman, where we just recently obtained some seismic over Block 9. So we're doing infill drilling that's very successful. We've got Block 62 gas development. We also see opportunities above and below our current steam flood interval in Mukhaizna. And so we have a lot of potential there, and that's why I mentioned it in my comments. I think people don't realize that actually Oman and Qatar have stacked pay, not exactly as obvious to most of the industry as the Permian is. But they're stacked pay intervals, and we're having success developing outside of what our traditional and original completion intervals were. So we're really excited about what the seismic is showing us. We're also pretty excited about our cost-cutting in Qatar, where our team has been able to develop a modular platform that will be able to enable us to expand what we're doing there at a much lower cost. And I'll pass it to Ken Dillon to talk a little bit more about those, but we have opportunities both in Oman and Qatar to continue to keep production flat, or slightly grow.
Kenneth Dillon - Occidental Petroleum Corp.:
Good morning, it's Ken here. As you can see from the slides, we've increased the Al Hosn gas plant capacity by 10%. That was done by very detailed technical reviews both by engineers and operational staff. And then controlled trials were done throughout the process before running the whole plant at capacity. That's an increase in capacity of 10% with virtually no capital at all. If you look at Qatar and you look at the new jacket design there, we basically eliminated the lift barge. We've eliminated going to large fabricators in the region, so we've dramatically dropped drilling costs in Qatar, which opens up all sorts of opportunities there. In terms of Block 9, as Vicki said, we last month signed the new Block 9 contract with His Excellency the Oil Minister. That's a 15-year contract where we see substantial growth opportunities both in oil and gas and in exploration. We think there are other opportunities in Oman that are a good fit long term for us, so overall very positive. Mukhaizna you can see from the slide, the growth trajectory that's possible with investment there. And we've also been trying to build on the Permian experience of assembly line processes in drilling, rolling out OXY drilling dynamics around the world. We're making significant savings, significant reductions in time to market. So in terms of opportunities, our goal is to try and compete with Jody and also deliver long-term cash flow for the corporation. In terms of how much capital you would need to keep it going, that's really a capital allocation point for Vicki, I believe. But our goal is to continue to get better for our international and continue to offer alternatives for the corporation.
Edward George Westlake - Credit Suisse Securities (USA) LLC:
Okay. And then on the theme of competing with Jody, on slide 34 you've laid out a Permian growth trajectory at different rig counts. Maybe just a little bit of color on how you've risked the EURs or the well performance behind that because obviously, your first half wells in the Sand Dunes area were better than your – third quarter was better than the first half, fourth quarter was better than the third quarter. Maybe just give a sense of how much of that improvement have you baked into that production forecast. Thank you.
Joseph C. Elliott - Occidental Petroleum Corp.:
It's a good question. I don't think we baked a lot of that improvement in the forward look, so I think there's upside potential. Our type curves represent the production from full-section development. So your first wells may be better than the last well on a section. So our type curves are based on the average, and that forward look is based on the average. So throughout this year, just like we did last year, we expect continued improvement in both cost and well productivity. So I think there's upside to that production plot, both from a pace standpoint, number of wells you drill per rig line, and productivity.
Edward George Westlake - Credit Suisse Securities (USA) LLC:
Thank you.
Operator:
The next question comes from Asit Sen of CLSA. Please go ahead.
Asit Sen - CLSA Americas LLC:
Thank you, good morning. I have two questions. One, on slide 14, Permian Resources gas margin looks like greater than $30 per BOE. When compared with EOR, which has a low cash cost, it looks like the cash flow profile of OXY Permian as a whole has improved. So, Chris, could you frame for us at what price given improvement are we cash flow neutral? And interest of cash flow overall, Permian for OXY, what happens at $60 or $70 oil?
Christopher G. Stavros - Occidental Petroleum Corp.:
At $60 or $70 oil, things change fairly significantly based on the numbers we gave you on our sensitivity around oil prices obviously. But keep in mind that what we said was that there's a lot of flexibility in the capital program. As Vicki pointed out, we'll see how things go in terms of commodity prices through the year. Obviously, we'd be more encouraged to maybe spend a little bit more money at the higher end of the range, better prices. So we'll just see how things go. We gave you all sorts of points in terms of cash flow changes and deltas from the different business segments. So I think I have a high degree of confidence in your modeling ability, so you should probably be able to come to some sense of what's going on. The Permian business as a whole, as I mentioned, generated quite a bit of free cash flow, and Permian EOR is there largely to harvest the free cash flow to redeploy into Permian Resources. So on cash neutrality, it could be whatever you want it to be. We were under $50 WTI in the fourth quarter. We're spending – so you're almost there now if you wanted to spend lower amounts of capital to keep production flat. But it's largely dependent on how much you'd like to grow, and we think we have a lot of opportunities, as Jody pointed out, 11,650 places to park the money at good returns. So I think that is the best way to frame it.
Asit Sen - CLSA Americas LLC:
Okay. And then given the new information, I was just wondering your thoughts on balancing the opportunity to sell some Permian acreage that's not in your core development areas and potentially use the proceeds to accelerate development drilling. And I didn't hear on asset sales the Texas gas assets. Has anything changed there?
Vicki A. Hollub - Occidental Petroleum Corp.:
As I said previously, we're continuing to look at our opportunities to monetize things where it makes sense, where we think that would increase the net present value for our shareholders. And while we're not prepared to talk about specific assets today, we'll continue that process. And as we make decisions, certainly we will share that with you. But it's something that we think about and evaluate pretty much on an evergreen basis.
Asit Sen - CLSA Americas LLC:
Thanks, a follow-up for Jody please. Jody, average lateral lengths have gone up 20% to 7,100 feet. Could you talk about the ability to drill longer laterals in this development mode? And could you remind us what percent of your Permian acreage, that focus area, is operated versus non-operated?
Joseph C. Elliott - Occidental Petroleum Corp.:
So the operated versus non-operated in that core 300,000, you can think 75% to 80% operating position there. With regard to the longer laterals, that's been a great effort by our business unit and our land organization to continue to core up, so doing swaps, doing trades, picking up pieces of acreage to drive that lateral length longer. So I expect us to continue to do that. The majority of our wells will be longer laterals. That's just an average of the whole inventory. Technically there's not a problem. 10,000 feet early on in horizontal development was a bit of a challenge. 10,000 feet is no longer a challenge. We're looking at even the option of 15,000 feet now.
Asit Sen - CLSA Americas LLC:
Thank you.
Operator:
The next question is from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co.:
Thank you, good morning, a couple of follow-up questions to what's been asked. First with regards to the Permian, to clarify on the longer laterals, can you talk about what the lateral length is that you expect for the 2017 program as it regards to the 300,000 acres your focused on? And then with regards to the 350,000 acres where you don't have identified locations, I think you mentioned in your prepared comments that you are delineating that. Can you talk more specifically about those plans and whether you see scale-enhancing acquisitions as likely in that part of the Permian?
Joseph C. Elliott - Occidental Petroleum Corp.:
So, Brian, the bulk of the development this year will be 7,500-foot or 10,000-foot laterals. If we have to drill a 4,500-foot lateral, it's because we've already developed or started developing a section that way and we really can't change. So most of our wells will be the longer version. On the 350,000 acres we're delineating, it's really multiple things. We're drilling appraisal wells on our own acreage. We're evaluating 3-D seismic. Again, those two equivalent non-operated rigs really are six to eight actual rigs any day of the year. So we get a lot of information from that non-operated position that helps derisk, plus just watching what other competitors do offset of this acreage. So with regard to acquisition, it's going to be a function of what we think about that acreage, what the current position is, what trade opportunities there are to core up before you go down the acquisition path.
Brian Singer - Goldman Sachs & Co.:
Got it, thanks. And then going to the point on free cash flow, I just wanted to also get just a clarification between slides 23 and 17. We see on slide 23 the $950 million to $1 billion incremental free cash flow you expect. And I think in your prepared comments you said you expect an incremental $500 million from the Permian, which I think was Resources and CO2. If you could, maybe just verify if that was the case. So is that essentially the incremental free cash flow you expect overall in 2017? And then more broadly, are you trying to reflect some greater comfort about spending cash flow relative to the dividend assuming the balance sheet doesn't go out of control, or is there still a more specific objective to try to stay within cash flow after dividend?
Christopher G. Stavros - Occidental Petroleum Corp.:
No, we provided the delta to free cash flow that we expect and some of the pieces of the business based on prior investments that we've made that are now completed, so there's to some extent that specifically around Chemicals. The Permian, a lot of that is driven by the production growth and the volume improvements that we've seen at good returns. And part of it obviously in oil and gas is some view around a little bit better price, but not much. And going forward, I would tell you that not sort of – we started the year with $2.2 billion of cash, and the capital program remains quite flexible. So we'll see how it goes as far as the spending. But again, the number one priority, as Vicki said, right after maintenance is really to continue to be able to fund and grow the dividend over time based on our ability to grow volumes.
Brian Singer - Goldman Sachs & Co.:
Great, thank you.
Operator:
Our next question comes from Pavel Molchanov of Raymond James. Please go ahead.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Thanks for taking the question, guys. Like many companies, you've been finding ways to squeeze out cost from the CapEx budget. But since the original budget last November, of course we've seen an escalation in U.S. service costs, particularly pressure pumping, et cetera. So what is the underlying assumption in your new budget for service cost inflation, whether it's by geography or by segment?
Joseph C. Elliott - Occidental Petroleum Corp.:
So we do believe there will be inflation pressure, and you mentioned pumping service. That's probably one of the areas where you'll see it the strongest. But to counter that, we're really working two approaches. One is to continue to get better technically, some innovations that are happening in the drilling space and in the completion s space. We can drill our wells faster and better over time. That will help offset that inflation pressure. But on the commercial side, we're working very closely with a group of suppliers to create the ability for them to have greater margins without just a price increase, more efficiency, better utilization, better logistics management. And so we think the combination of those two things can hold our overall well costs flat or continue to improve it.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
Okay. And supposing that second half commodity pricing ends up being better than the current strip suggests, would the incremental dollar go back to the buyback program that you formerly had active, or would it go directly into the drill bit again?
Vicki A. Hollub - Occidental Petroleum Corp.:
We'll have to see how conditions look in the second half of the year. But currently our plan would be not to increase our capital for this year but to go with the plan that we have in place and to look at what our program next year would look like. But it really is going to depend on how we feel about oil prices.
Pavel S. Molchanov - Raymond James & Associates, Inc.:
All right, I appreciate it.
Operator:
That concludes our question-and-answer session. I would like to turn the conference back over to Chris Degner for closing remarks.
Christopher M. Degner - Occidental Petroleum Corp.:
Thank you, everyone, for participating today. Have a great day.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Christopher M. Degner - Occidental Petroleum Corp. Vicki A. Hollub - Occidental Petroleum Corp. Christopher G. Stavros - Occidental Petroleum Corp. Jody Elliott - Occidental Petroleum Corp. Robert Lee Peterson - Occidental Chemical Corp.
Analysts:
Doug Leggate - Bank of America Merrill Lynch Philip M. Gresh - JPMorgan Securities LLC Ryan Todd - Deutsche Bank Securities, Inc. Roger D. Read - Wells Fargo Securities LLC Brian Singer - Goldman Sachs & Co. Evan Calio - Morgan Stanley & Co. LLC Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.
Operator:
Good morning and welcome to the Occidental Petroleum Corporation third quarter 2016 earnings conference call. Please note, this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead.
Christopher M. Degner - Occidental Petroleum Corp.:
Thank you, Kate. Good morning and thank you for participating in Occidental Petroleum's third quarter 2016 conference call. On the call with us today are
Vicki A. Hollub - Occidental Petroleum Corp.:
Thank you, Chris, and good morning, everyone. I'll begin by summarizing our key accomplishments in the third quarter. First, cost reduction efficiencies combined with improvement in new well productivity and better base management have enabled us to further reduce our total spend per barrel of production this year compared to 2015. Second, we again increased year-over-year production in our core areas, and we're on target to exceed the higher end of our guidance for 2016. Third, we remain prudent with our capital allocation as we focus on returns and maintain disciplined to stay within our $3 billion capital budget. Fourth, to further increase our low-decline production and improve efficiencies, we have acquired additional working interest in enhanced oil recovery projects and unconventional acreage in the Permian. Last, our aggressive appraisal and development efforts in our Permian Resources business have resulted in an improvement in the number and quality of wells in our inventory. As I've previously mentioned, our total spend per barrel of production metric includes our overhead, operating and capital cost per barrel of production. This metric is designed to drive cost reduction, increased well productivity and optimize base production. To align employees with this metric, we have linked this to incentive compensation. Our efforts to focus on efficiency and capital discipline are paying off, as we continued to lower our total spend per barrel of production. We averaged close to $62 per barrel in 2014, about $40 per barrel in 2015, and have targeted $28.50 per barrel in 2016. Year to date, we've beaten our target, with average total spend of about $27.50 per barrel. In the third quarter, total company production from our ongoing operations was about 605,000 BOE per day, an increase of 5% year over year driven by Al Hosn gas in Abu Dhabi, a new gas project in Oman and resilient base production in Permian Resources. The performance of the Al Hosn team continues to exceed our expectations as they optimize deliverability. They have again achieved record production of 74,000 BOE per day for the quarter. It's even more impressive that the plant operated well during the summer months, where temperatures can reach 120 degrees. We're optimistic that the plant can continue to deliver from 65,000 BOE per day to 75,000 BOE per day, depending on seasonal maintenance. We have commenced engineering studies for a potential expansion of the plant and expect to reach an investment decision in the second half of 2017. Permian Resources production this quarter was 121,000 BOE per day, representing year-over-year growth of 4%. As per our original development plans, Permian Resources production will decline slightly in the fourth quarter. We are adding rigs now to stabilize production and restart growth in early 2017. We continue to see improvements in well productivity in all of our areas. The increases in production from Al Hosn, Oman's Block 62, along with strong year-over-year production growth from Permian Resources will help us exceed the higher end of our production growth guidance for 2016. As we look forward to 2017, we expect to deliver 5% to 8% production growth, with the variance subject to our activity levels in the Permian. Longer term, we have a deep inventory of well locations in the Permian with the capability to drive direction growth above this range. Additionally, we have focused our international business on the core four areas
Christopher G. Stavros - Occidental Petroleum Corp.:
Thanks, Vicki, and good morning, everyone. Today I'll focus on the following items
Jody Elliott - Occidental Petroleum Corp.:
Thank you, Chris. Today, I will provide a review of our domestic operations during the third quarter, guidance on our program in the fourth quarter and an outlook for the start of 2017. For this year, our Permian Resources business achieved significant improvement in well economics across our Permian leading acreage position through step change advancements in well productivity and field development design. We believe this improvement in value starts with our subsurface characterization, where we are leveraging our geology, petrophysics and geochemistry expertise to achieve breakthroughs in our multi-bench appraisal, stimulation and other key subsurface design factors. We expect to quickly deliver a new series of breakthroughs in 2017 as we advance our seismic-based characterization and second phase of geoscience analytics. On the cost structure front, we continue to lower our capital and operating cost structure through faster drilling, leveraging engineering innovation and integrated planning to optimize execution and logistics. We expect these efforts, when combined in our field development plans, will ensure Oxy is a leader in realizing maximum value per acre by optimizing recovery and capitalization. Our unconventional business is well positioned to provide a competitive return in a low-cost environment and achieve significant growth in an improved price environment. As a result, during the third quarter we added a drilling rig in Permian Resources plus another at the beginning of the fourth quarter and have capacity and locations on standby to respond to improved pricing in 2017. Turning to the performance of Permian Resources. In the third quarter, we achieved daily production of 121,000 BOE per day, a 4% increase versus the prior year. Oil production declined modestly due to lower capital spending, with nine wells put online versus 54 wells in the third quarter of 2015. Improved well productivity and our emphasis on base management mitigated some of the base decline on the horizontal wells. In the second and third quarters, we completed gas processing and compression facilities, allowing for the capture and sales of more gas and NGLs. As we announced yesterday, we acquired producing properties and non-producing leasehold acreage in the Permian. In Permian Resources, we acquired 35,000 net acres in southern Reeves and Pecos Counties, where we currently operate and have a working interest. The properties will include approximately 7,000 BOE per day of net production, with 72% oil from 68 horizontal wells. On key portions of the acreage, we gained operatorship where we had existing non-operated interest, and most of the acreage is already held by production. Development will initially target the Wolfcamp A, Wolfcamp B and Bone Spring. Simply put, we know the acreage very well. It's very competitive with our existing inventory. We expect to drill longer laterals, execute multi-bench development and leverage our existing infrastructure in the area, notably the joint venture gas processing plant completed this summer. This transaction brings our overall position in the leasehold area to 59,000 net acres, with an aggregate acquisition cost under $2 billion. We plan on allocating approximately $200 million in capital in 2017 to the acquired acreage, utilizing one to two drilling rigs. Turning to our activities in our core development areas. Much of the focus of the drilling program in the second and third quarters was to appraise the potential for multi-bench development in southern Reeves, Eddy, Howard, Glasscock, and northern Reagan County. In southeast New Mexico, we drilled and completed two Cedar Canyon Third Bone Spring wells and one Cedar Canyon Wolfcamp A well in Eddy County. All of the wells had 30-day peak IPs over 1,000 BO per day. In southern Reeves County, we brought the Roan State 24 51H Second Bone Spring well online at a peak rate of 944 BOE per day and a 30-day rate of 702 BOE per day and a 90% oil cut. The well had a 4,500-foot lateral and increases our confidence in the potential for multi-bench development for our acreage in the area. We're on the learning curve in developing this bench and expect well productivity to improve as we apply our experience in drilling and completion technology and further integrate our subsurface analysis. In Glasscock County, we brought the appraisal well, Powell 1720 1H, online with a 7,500-foot lateral, which targeted the Spraberry formation with a 30-day rate of 931 BOE per day. As cited last quarter, we now compare and benchmark our well cost on a cost per 1,000-feet of lateral basis as we continue to increase our lateral lengths. Slide 23 illustrates our demonstrated improvement in well cost, which has declined roughly 38% from 2015. Similarly, our 1,000 foot of lateral per rig per quarter has also improved from 25.2 per rig in 2015 to 35.4 per rig in the third quarter. We believe that a significant percentage of these improvements in efficiency are driven by structural changes in how we drill and complete wells and expect to continue to improve these efficiencies as we add drilling rigs. In the Delaware Basin, we're aggressively appraising new benches while maintaining focus on improving well recoveries in our development benches. In southeast New Mexico, we tested a new Second Bone Spring slickwater frac design on the Cedar Canyon 27 Fed 5H with 2,000 pounds per foot and 50-foot cluster spacing. The cumulative production results from the new design have exceeded the first half 2016 design, and we expect to see continued improvement in future results. We're targeting an average well cost of $7.1 million for the Second Bone Spring and $8.3 million for the Third Bone Spring with 7,500-foot laterals and the increased completion size. Overall, we're very encouraged by the development and appraisal results in southeast New Mexico and we expect to increase activity in Q4 and throughout 2017. In the Texas Delaware, we drilled one well and turned one appraisal well to production. The reduction in activity in the area is consistent with the overall balance of activity shift between Texas and New Mexico, and we plan to increase activity in this area in the fourth quarter. Our upcoming wells in the fourth quarter will test new completion designs and drilling technology that we believe will drive step change value addition across all of our development areas. We expect to increase our average lateral length from approximately 5,200 feet in 2016 to over 9,000 feet in 2017. Shifting our results to the East Midland Basin, in the third quarter we drilled eight wells, brought four wells online, three of which have not reached peak production rates. We had multiple record drilling and completion achievements during the quarter. For example, we drilled a Wolfcamp B 7,500-foot lateral in 12.5 days rig release to rig release. We completed 10 frac stages in one day, and we drilled and completed two Wolfcamp A horizontals for $4.6 million and $4.9 million. Well productivity measured by the initial production rates per thousand foot of lateral continues to improve. In the Permian Resources as a whole, we achieved another quarter of lower quarter-over-quarter field operating expenses, due mainly to improved surface operations with optimized water handling, lower workover expenses, and better downhole performance. Since the second quarter of 2015, we've reduced our operating cost per barrel by 28%, continue to work additional cost reduction and efficiency improvements. As stated earlier, our focus on maximizing production from existing wells has been central to reducing declines in the business. We expect that our average annual uplift for our investment will be approximately 6,000 net BOE per day. This is another example of leveraging our decades of base management expertise in the EOR business to our Resources business. As previously stated, we expect to increase our drilling activity in the fourth quarter of 2016 and bring on approximately 20 wells. We expect production to be about 120,000 BOE per day in the fourth quarter and be growing as we exit the year. With over 115 wells planned for 2017, we expect to achieve double-digit production growth in Permian Resources. In addition to the recent acreage acquisition, we've been actively trading and swapping acreage in order to core up our position. We've traded approximately 10,000 acres, which will enable longer lateral development. So for 2017, we expect to drill more wells with more than double the total lateral length drilled in 2016. Now I'd like to shift to our Permian EOR business. We continue to take advantage of lower drilling cost and manage the operations to run our gas processing facilities at full capacity. Permian EOR had another quarter of free cash flow generation. Drilling costs are running 22% below our benchmark target, and we've lowered cash operating expenses by 20% since the fourth quarter of 2014 and 7% year over year, driven mainly by lower downhole maintenance and injectant costs. In similar fashion to our Resources business, the capital savings achieved by the EOR team will be reinvested into additional wells and CO2 flood expansions. As we've mentioned in previous calls, the residual oil zone development, or ROZ, is a vertical expansion of the CO2 flooded interval. The ROZ underlies most of our major EOR properties and can be developed between $3 and $7 per barrel. Year to date, we've completed 94 well deepenings and recompletions along with 36 new wells in the ROZ developments. We anticipate an additional 50 deepenings and recompletions and 10 new wells in ROZ developments in the fourth quarter of 2016. Yesterday, we announced acquisitions of working interest in 11 producing oil and gas properties and related infrastructure. The acquisition increases our ownership in several properties where we currently operate or are an existing working interest partner. These properties have production of approximately 4,000 barrels of equivalent per day at 80% oil, with estimated net crude developed producing reserves of approximately 25 million BOE and total proved reserves of approximately 41 million BOE. To summarize, our domestic business will provide competitive returns in a low-cost environment and achieve significant growth in an improved price environment. We believe our Permian business is uniquely positioned to leverage our subsurface innovation in unconventional and leadership in enhanced oil recovery to maximize the value per acre across our entire 2.4-million-acre portfolio. We plan to exit this year running eight drilling rigs on our operated acreage plus another 1.5 to 2 net rigs on our non-operated development acreage. We're pleased with the strides our teams have made in subsurface characterization, execution, and performance thus far in 2016 and look forward to continuing breakthroughs in 2017. Thank you, and I'll now hand it back to Chris Degner.
Christopher M. Degner - Occidental Petroleum Corp.:
Thank you, Jody. We'll now open up the call for questions.
Operator:
The first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. Good morning, everybody. I've got two questions. Vicki, I wonder if I could kick off with the acquisition last night. You've shown before the relative priority for the use of cash, and you've also shown us that you've got a fairly deep inventory of existing assets. I'm just trying to understand the rationale as to why $2 billion is the right use of cash versus a step up in activity on your existing acreage. If you could, just help us understand the rationale a little better and maybe some of the nuances about working interest changes, what it brings to you by way of operating capability and so on. Just help us understand the numbers a wee bit.
Vicki A. Hollub - Occidental Petroleum Corp.:
Doug, we've been looking at this. We've had ownership in this area for a while now. And what made us very attracted to this is the fact that it has the potential for five-bench development and the fact that it's so close to our Barilla Draw area where we've already installed infrastructure. We believe that the infrastructure in Barilla Draw combined with the infrastructure that was installed by a very prudent and efficient operator will enable us to combine the two and provide those synergies around that infrastructure to share that. The five benches, the shared infrastructure, and the operational efficiencies that we'll gain by combining these two areas and becoming operator of it where we can manage the development to maximize the net present value we believe was the best use of our cash at this point. This inventory fits within the less than $50 per barrel breakeven price for us or the price that generates positive NPV of $10 for us, so that we think is very prospective. We like how it fits. We believe that we can further develop Barilla Draw. It will help with the economics there. So the combination of the two of them provides us quite a bit of net present value.
Doug Leggate - Bank of America Merrill Lynch:
Vicki, I don't want to belabor the point, but I think Jody suggested one to two rigs in this area. I guess what I'm really trying to understand is, to justify the NPV – understand the NPV of the incremental wells, but to justify the NPV of the incremental wells plus the $2 billion acquisition cost, one would imagine you have to run at a pretty healthy pace above what you were going to do on your existing portfolio. So again, can you help us – guide us to where the activity level on this acreage goes to justify the $2 billion price tag?
Vicki A. Hollub - Occidental Petroleum Corp.:
The one to two rigs would be the initial starting point for us on this acreage. We expect to spend about $200 million in 2017. But in 2017, remember now, we're still trying to balance cash with what our expectations are around oil prices. We do expect improving prices in 2018, which is where we expect to really launch into a much more aggressive development of both Barilla Draw and this new area. So we expect that we're going to be very aggressive with the development on this once we get into 2018, where at that point we expect the supply gap to narrow such that the prices will warrant a much higher level of activity.
Doug Leggate - Bank of America Merrill Lynch:
Okay, and a very, very last one for me, a very quick one on Chemicals. Given the cracker starts up at the beginning of next year, can you just give us some guide on the free cash flow delta on that project as you move from 2016 into 2017? And I'll leave it there, thanks.
Vicki A. Hollub - Occidental Petroleum Corp.:
Okay.
Robert Lee Peterson - Occidental Chemical Corp.:
Hi, this is Rob Peterson. So we'll just continue the spending of capital. We'll carry a small amount for commissioning the startup into 2017, and then we'll stop spending that and start generating cash from it. So it will be a several hundred million dollar flip between spending capital and generating cash out of the cracker, depending on the ramp-up time.
Christopher G. Stavros - Occidental Petroleum Corp.:
The swing, Doug, is actually about $300 million in terms of spending versus the contribution. So that's the delta, if you will, spending to cash flow.
Doug Leggate - Bank of America Merrill Lynch:
I just wanted to check order of magnitude. That sounds great, guys. Thanks so much.
Operator:
The next question is from Phil Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Hey, good morning. I just want to follow up on the cash flow side of things. Chris, you mentioned $4.5 billion of CFO at $50. And if we use the CapEx, call it $3.5 billion, that would be $1 billion of free cash flow versus a dividend of $2.3 billion. So I guess what I was wondering is how you planned on funding that gap if oil is $50 or even if it's $55. Would you be looking to add debt to the balance sheet? Would you be looking to sell assets? And generally, Chris, just how are you thinking about target leverage following this acquisition?
Christopher G. Stavros - Occidental Petroleum Corp.:
Phil, it's a good question. It's going to come from a combination of a number of different sources for the cash. Without being completely or terribly specific about any given thing that we're going to do at any given moment, what I would say is obviously it's going to depend on commodity prices. I mentioned the sensitivity around our cash flow to commodity prices. But should the need arise, we would expect to monetize some non-core non-strategic assets that would more than, we believe, cover our needs and when including our expectations for next year's cash from operations. So I don't anticipate or expect us to fall short or have any issue with that. We've got multiple levers that we can pull on in terms of filling any gap, certainly to the extent that you just did the arithmetic around, and more should need be. And the capital remains very flexible, certainly within the range, depending on commodity prices.
Philip M. Gresh - JPMorgan Securities LLC:
And on the target leverage side of things, post this deal, Vicki, you mentioned maybe even looking at additional bolt-on deals. How do you think about target leverage and the size of what bolt-on would mean relative to the acquisitions you've just done?
Christopher G. Stavros - Occidental Petroleum Corp.:
The leverage amounts, we're comfortable with that within our ratings right now. We'll obviously, depending on what the acquisition looks like, if we do acquisitions, it depends on what it looks like in terms of how we're going to look to fund it. And so some acquisitions are better sourced through leverage, some through other means. So we'll just have to look at it. It depends on what the acquisition looks like, the composition of the cash flows around the acquisition, the composition of the production in terms of determining how much leverage you're comfortable with for any given type of activity or specific acquisition. So the answer is it really depends.
Philip M. Gresh - JPMorgan Securities LLC:
Okay.
Vicki A. Hollub - Occidental Petroleum Corp.:
And, Phil, with respect to the bolt-on acquisitions, we look at a lot of things in the Permian. And this is the first thing that we've seen in a while that really fits well with our current operations and really made sense from a long-term development standpoint. You may have heard our name associated with some things in here recently that – those are things we didn't bid on. We look at a lot of things, but what we always want to do is make sure that it's a good fit. and as Doug had alluded to, that our net present value of what we expect our development to be is going to cover the cost of the acquisition. And so that rules out a lot of things for us.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, thanks.
Operator:
The next question is from Ryan Todd of Deutsche Bank. Please go ahead.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great. Thanks. Maybe another follow-up – I know you referenced the addition of rigs into the fourth quarter in the Permian. But what level of activity is implied in the Permian in the $3.3 billion to $3.8 billion budget for 2017? And how much of that budget is allocated to Permian Resources?
Jody Elliott - Occidental Petroleum Corp.:
Ryan, this is Jody. The activity level currently planned for 2017 would be about six rigs in the Permian Resources area and three rigs in EOR. And then depending on what that final capital number is, we can scale that up, scale it down, again, depending on commodity prices or where that final direction is on the capital budget.
Vicki A. Hollub - Occidental Petroleum Corp.:
And we've said previously, although it's not final yet, that our capital spend would probably be in the range of $1.3 billion to $1.4 billion for Resources.
Jody Elliott - Occidental Petroleum Corp.:
And, Ryan, the other point I want to make is all the work that we've done this year around our characterization, around our field development planning, the upsizing and optimization of our stimulation has created this ability with very low capital intensity to generate a lot of production. So that inventory mix in 2017 will be optimized where we can grow production significantly with a fairly modest rig count.
Ryan Todd - Deutsche Bank Securities, Inc.:
Thanks. And then maybe as a follow-up to that, can you talk a little bit about your infrastructure position in the Basin, how you feel like you're positioned to be able to ramp activity in terms of the flexibility you have over the next few years, whether you see yourselves, or the Basin in general, the industry in general, having any bottlenecks? Anything there would be great.
Jody Elliott - Occidental Petroleum Corp.:
Ryan, I think as far as our field development planning, that's one of the key things is that we try to get ahead of the game, whether it's water disposal, frac water movement, gas takeaway, oil takeaway. We try to plan those things in advance and build out ahead of when that need is going to be. So whether it's southeast New Mexico, we announced the startup of the joint venture gas plant recently in the Delaware. Those are all things to stay ahead of the infrastructure game. The new acquisition has considerable infrastructure, fresh water, salt water infrastructure, 4 million barrels of frac storage, 40 miles of distribution line. It has produced water treatment systems, 15 SWD wells, gas compression. So all those things that have been done extremely well in this acquisition are the same things we do on our own assets. And maybe Vicki or Chris will want to address the greater Permian infrastructure takeaway.
Vicki A. Hollub - Occidental Petroleum Corp.:
Ryan, I would just say that with respect to our takeaway capacity out of the Permian, we're very well positioned there. We have excess capacity above and beyond what we expect our growth to be. That's been a little bit of a drag on our Midstream business here recently, but we expect that to be a real benefit to us going forward.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great. Thanks.
Operator:
The next question is from Roger Read of Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Thanks. Good morning. I guess maybe to come back to expectations in the fourth quarter here. How should we think about the acquired volumes coming in as part of the guidance of the 120,000 BOE per day for Permian Resources? Does that imply that Permian Resources is actually declining here in the fourth quarter and that adds on? Or how should we think about the exit rate you indicated would be higher?
Jody Elliott - Occidental Petroleum Corp.:
Roger, the 120,000 BOE per day includes our estimate of the acquisition. So there's some modest decline in the base core business pre-acquisition. Again, the activity level is ramping up. As you know, when you're doing multi-well multi-pad development with zipper fracking, the production comes lumpy. So a lot of that activity happens in the fourth quarter and the production will come very early in the first quarter of 2017.
Roger D. Read - Wells Fargo Securities LLC:
Okay. So potential for a little bit of – if things go really well, we can see it in December, otherwise thinking about it as a 2017 event?
Jody Elliott - Occidental Petroleum Corp.:
That's correct.
Roger D. Read - Wells Fargo Securities LLC:
Okay. And then can you walk us through with the acquisition here a little bit? The 700 locations obviously indicate potential for significant upside, some of which clearly will be price-driven and some of which is going to be based on drilling. How did you come to the 700? And what's an idea of how we should think at say maybe $60 oil in 2018 where that 700 locations could go?
Christopher G. Stavros - Occidental Petroleum Corp.:
Roger, the 700 locations is based on our conservative nature with assessing our developmental properties. So that's the minimum location count in the Wolfcamp A, the Wolfcamp B, Second Bone Spring. We're very optimistic about the two additional benches in the Bone Spring and in the Wolfcamp debris flow, which sits between the Wolfcamp A and Wolfcamp B. At $60, again, that inventory just continues to grow, whether it's tighter spacing. The other aspect is we continue to improve both well performance and our execution results. I mentioned that we have some technology things working in the drilling area, which we believe can be a step change in multi-well, multi-pad development. And so as we test those in the fourth quarter and in the first quarter of 2017, we'll be more able to talk about some of those details. But we think that would generate even more bench activity, not just in the acquisition, but on all of our core areas.
Roger D. Read - Wells Fargo Securities LLC:
Okay. Great. And just a final question. You mentioned this acreage was fairly HBP. Is there a percentage you can give us that maybe isn't? Give us an idea of maybe where the one to two rigs initially have to be focused.
Christopher G. Stavros - Occidental Petroleum Corp.:
I think it's north of 80%. And a lot of those are just clock drilling obligations as opposed to expiry issues.
Roger D. Read - Wells Fargo Securities LLC:
Okay. Great. Thank you.
Operator:
The next question is from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer - Goldman Sachs & Co.:
Thank you. Good morning. I wanted to go back to the comments with regards to the CapEx cash flow for 2017. And if we take the acquisition side of things away and just look at the strategy with regards to growth versus free cash flow versus dividend, I think in the past you talked about wanting to try to cover that dividend with free cash flow. And perhaps $50 is just the low end of your oil range and will ultimately go higher, but I wanted to see if there's any change in your strategic thinking about the importance of covering the dividend with free cash flow, recognizing that Oxy is unique in even having free cash flow of this magnitude in the first place.
Vicki A. Hollub - Occidental Petroleum Corp.:
I'll tell you, Brian, we consider that, covering our dividend with cash flow, to be a priority for us. It's very critical. But we do view 2017 as a transition year. We don't expect prices to get to the point where it's reasonable for us to cover our dividend with cash flow until 2018. That's why we're ensuring that all the decisions that we make will enable us to get through the transition year of 2017. We have other levers we need to pull if that supply/demand balance doesn't narrow in 2018, so there are other things that we can do. But we're certainly expecting an oil price that is certainly closer to our cash flow neutral standpoint.
Brian Singer - Goldman Sachs & Co.:
Great, thanks. And then shifting to the Permian, the acreage position as you highlighted it is very vast. Can you talk to whether you see your interest and the need for additional acquisitions to achieve the type of scale that you desire as you're doing with this acquisition here to be competitive to or more competitive with others in the basin that have contiguous acreage positions?
Vicki A. Hollub - Occidental Petroleum Corp.:
We viewed this acquisition as a very unique opportunity because of the reasons I've described. We don't see any need to acquire any additional acreage unless it's smaller bolt-ons that do provide us the efficiency to develop what we currently have, and those are the types of things that we would target going forward. Our inventory is huge, and we still haven't fully appraised the inventory we have. So what we view this to have done is in the greater Barilla Draw area, what it's done for us is just, in addition to the 59,000 acres associated with the acquisition, we have in that general area around 100,000 acres. So that gives us a really sizable position that's bigger than most positions, and that's why this was so important to us. It was a special case because, as you've noticed, we haven't really acquired anything in the last couple years. And this is the reason, we're looking for those things that provide us a unique opportunity to do something that's what we consider to be really a step change in a given area. Looking at the rest of our acreage, we're spending quite a bit of time and effort to appraise the rest of what we have and to rank it in terms of development. So now we feel very comfortable with the Greater Barilla Draw area. Southeast New Mexico is in prime position for aggressive development, and we have some areas in the Midland Basin as well. What we have to do now is we've got our appraisal team working on those parts of our acreage that are outside of those areas.
Brian Singer - Goldman Sachs & Co.:
Great. Could you characterize the sum of the acreage that you believe now is developable and to the comment you just made?
Jody Elliott - Occidental Petroleum Corp.:
I think we'll update the full inventory picture in the fourth quarter. To give you a little bit of color, with all the appraisal work and all the subsurface work we're doing, we've changed the landscape of that inventory. We've doubled the lateral miles of inventory. The NPV on that existing inventory is up over 66%. We have 27 rig years of inventory at less than $40 a barrel, so we've really grown the existing inventory. This asset, it's really – the acquisition asset is really about just taking ownership in an already derisked core area with incredible infrastructure. So that's going to allow us, when you think about sand, when you think about water, when you think about logistics, people, supply chain leverage, it really allows us to hit all of those key drivers that lower F&D cost and keep our OpEx costs really low.
Brian Singer - Goldman Sachs & Co.:
Thank you very much. I really appreciate it.
Operator:
The next question is from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Hey, good morning, guys. You significantly beat Permian Resources volumes guidance for the second time in three quarters. And if I shift to the guidance, what are the ranges on the 2017 fuzzy bars for Permian Resources on slide 22? I'm just trying to square the circle here of whether that range reflects the enhanced completions, longer laterals, and increased wells drilled in the presentation, or if it's based on 2015 year-end technology, as are the location counts? It just looks low versus the commentary.
Jody Elliott - Occidental Petroleum Corp.:
Evan, that forecast is based on what we know today. So it's the latest version of our completion designs and our expansion. The fuzziness is really a function of what's the final capital budget going to be that year. But we're not forecasting enhancements or improvements that have not been demonstrated at this point in time. So those are all upside opportunities.
Vicki A. Hollub - Occidental Petroleum Corp.:
And, Evan, let me add to that that Jody and his team along with the support of the subsurface characterization team have beaten their forecast for about what, eight quarters in a row or so?
Evan Calio - Morgan Stanley & Co. LLC:
Any numbers on the high end of that? It looks like 135,000 BOE per day. Is that right?
Vicki A. Hollub - Occidental Petroleum Corp.:
It's a little bit higher than that.
Evan Calio - Morgan Stanley & Co. LLC:
Okay, maybe a second one, if I could, on the acquisition. Could you say how much of the acquisition was allocated to Permian Resources versus EOR? It looks close to $21,000 an acre versus the $43,000 an acre headline for Permian Resources, if we back out what you paid for J. Cleo using that cost basis metric. Is that right? And then on the other side of I guess Singer's question is with a larger Tier 1 footprint, will that increase for high-grading your portfolio or potential asset sales? I'll leave it there.
Vicki A. Hollub - Occidental Petroleum Corp.:
I would say that on the net value per acre, we were in the upper $20,000s on what we calculated for that. And with respect to the tiering of the acreage, this certainly gets us what I believe is going to be Tier 1 for us. I believe that this area will certainly be comparable with our best area, which is southeast New Mexico. The fact is that the opportunity to have five benches is going to make the infrastructure cost so minimal on a per BOE basis that I do believe that this is just going to continue to improve.
Evan Calio - Morgan Stanley & Co. LLC:
And drive – since it would take capital, would there be another high-grading on the back of that?
Vicki A. Hollub - Occidental Petroleum Corp.:
There could be. It really depends on product prices for 2017. We'll continue to balance our capital with our cash flow needs and the balance sheet.
Evan Calio - Morgan Stanley & Co. LLC:
Great. I appreciate it, guys.
Vicki A. Hollub - Occidental Petroleum Corp.:
Thanks.
Operator:
And the next question is from Matt Portillo of TPH. Please go ahead.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Good morning. Just starting off on the Permian Resources side, I was curious if you could provide any incremental color or commentary around the base design that you're currently utilizing in the Texas Delaware Basin and what you may be testing on a leading-edge basis that may be giving you some incremental excitement in terms of increased productivity on the wells.
Jody Elliott - Occidental Petroleum Corp.:
Matt, it's really basin. It's sub-basin specific, almost field specific in those designs. But in general, it is tighter cluster spacing and higher sand concentrations, and then doing trials to understand where you've hit diminishing returns. But in general, more sand, tighter cluster spacing is generating better results. But combining that with longer laterals has really been the key for us. And as you look at the numbers I talked about on extending lateral length, that's another real benefit for us. In New Mexico, this year we'll average around 5,000-foot laterals. We'll go almost to 7,000 feet next year. In the Texas Delaware, it's a little over 5,000-foot laterals. Next year it will be closer – this is effective lateral length – over 9,000 feet. And in East Midland Basin, we probably averaged – we'll average around 7,800-foot laterals in 2016, and in 2017 that will be over 9,000 feet. So the combination of extended lateral giving us really better EURs, better decline profiles combined with this continued integration of our geoscience with the stimulation design. The drilling technology piece is something that we'll talk a little bit more about in future quarters, but it's really an innovative way to access multiple benches and again leveraging your infrastructure across multiple benches with minimizing your facility cost.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
And just a quick follow-up there, is there any color you can provide I guess just on what the base design looks like today? I'm just trying to reference point in the Texas part of the play specifically where your proppant loading is and where your fluid volumes are and maybe...
Jody Elliott - Occidental Petroleum Corp.:
It's in the 1,750 to 2,000 pounds per foot range, but we've trialed and will trial higher.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Great, and then just a follow-up question. On the New Mexico side of the border, it looks like you've started to delineate some of your acreage in Eddy County. I'm just curious. As you guys look at additional resource potential across New Mexico, what interest you have in, I guess moving into 2017, in terms of focusing on some incremental zone delineation in the Wolfcamp and Avalon horizons.
Jody Elliott - Occidental Petroleum Corp.:
So New Mexico will be one of the key places we operate in 2017. This year we've spent quite a bit of effort in the appraisal mode in New Mexico, testing the Third Bone Spring, testing the XY, Wolfcamp D. So we will continue as part of our development plans to appraise those other benches. Again, we believe New Mexico has many bench opportunities beyond what we've talked about previously in our inventory.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
And last question from me. I just wanted to follow up on a previous question from an infrastructure perspective. So just to clarify there, I think there's some industry concern that as Permian growth accelerates over the next few years that the main infrastructure bottleneck may become the pipe capacity out of the basin. And so I wanted to just make sure that I understood your comments that you guys feel comfortable over the next few years that there are no pipe constraints or you have solutions in the work that can essentially debottleneck that.
Vicki A. Hollub - Occidental Petroleum Corp.:
I suspect there are going to be pipeline constraints for others, but I can tell you, we have plenty of capacity tied up and we'll be able to actually still contract and take third-party volumes to Houston. We have quite a bit of capacity, so we feel very comfortable with where we are.
Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Thank you very much. I appreciate it.
Operator:
That concludes our question-and-answer session. I would like to turn the conference back over to Chris Degner for closing remarks.
Christopher M. Degner - Occidental Petroleum Corp.:
Thank you, Kate. And thank you, everyone, for joining us on the call today.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Christopher M. Degner - Senior Director, Investor Relations Vicki A. Hollub - President, Chief Executive Officer & Director Christopher G. Stavros - Chief Financial Officer & Senior Vice President Jody Elliott - President, Domestic Oil and Gas Edward A. Lowe - President, Oil and Gas, International
Analysts:
Doug Leggate - Bank of America Merrill Lynch Philip M. Gresh - JPMorgan Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Ryan Todd - Deutsche Bank Securities, Inc. Paul Sankey - Wolfe Research LLC Guy Allen Baber - Simmons & Company International Roger D. Read - Wells Fargo Securities LLC John P. Herrlin - SG Americas Securities LLC
Operator:
Good morning and welcome to the Occidental Petroleum Corporation second quarter 2016 conference call. Please note, this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Laura. Good morning, everyone, and thank you for participating in Occidental Petroleum's second quarter 2016 conference call. On the call with us today are
Vicki A. Hollub - President, Chief Executive Officer & Director:
Thank you, Chris, and good morning, everyone. Last quarter I told you our game plan for this year has been to address the things within our sphere of influence to ultimately not only survive but thrive in the current weak commodity price environment. To that end, we're on target to achieve the higher end of our production guidance for 2016 while keeping our capital program on budget at $3 billion. We continue to make progress lowering our cost structure, which we know is critical to both short and long-term success. Our capital discipline and cost reduction efficiencies combined with improvement in new well productivity and better base production management have enabled us to further reduce our total spend per barrel of production this year compared to 2015. In addition, our strategy around capital is to be prudent and remain focused on returns, as we expect the commodity price environment to stay challenging through the rest of this year and into 2017. At the same time, we'll maintain the flexibility necessary to maneuver through a range of price scenarios. Finally, due to the strength of our balance sheet and the quality of our portfolio, we have raised our dividend for the 14th consecutive year. Total company production for our ongoing operations increased to 609,000 BOE per day from 590,000 BOE per day in the first quarter. The increase was driven by Al Hosn gas in Abu Dhabi and a new gas project in Oman. The increase in average daily production of 26,000 BOE per day from Al Hosn versus the first quarter of 2016 is due mainly to lower production volumes in the first quarter caused by a scheduled warranty shutdown. However, 10% of the increase is due to improved plan efficiencies gained by the Al Hosn operations team. As you know, Al Hosn gas is a joint venture between ADNOC [Abu Dhabi National Oil Company] and Oxy in Abu Dhabi. The Al Hosn team has done an excellent job of optimizing deliverability through the plant. An additional 7,000 BOE per day came from Block 62 in Oman, where a recently constructed gas plant was put online to process production from two newly developed gas fields. The plant was completed on time and on budget. This enabled us to achieve record production in Oman this quarter. In addition, our Qatar team has worked to get production in the Idd El Shargi South Dome field, or ISSD, to its highest level in over 16 years. Completion design improvement in complex horizontal wells and enhanced base production management contributed to this production milestone. Permian Resources production this quarter was 126,000 BOE per day, representing year-over-year growth of 16%. As Jody will show, we're continuing to see improvements in well productivity in all areas. The increases in production from Al Hosn, Block 62, and ISSD, along with strong year-over-year production growth from Permian Resources will help us reach the higher end of our 4% to 6% production growth guidance for 2016. Our capital spending in the second quarter declined modestly, as we shifted timing of spending for certain Chemicals and Midstream projects and slowed our drilling program in the Permian. This drilling program is consistent with the plans we put in place at the beginning of this year and with our strategy to remain conservative in this price environment. Continued improvements in project designs and capital execution have helped us to do more than expected with our $3 billion capital budget. These along with improved production performance in many areas of our operations are the reasons we expect to achieve the upper end of our production guidance for the year. It's important to note that most of our cost reductions are due to our own efficiency gains, not service company unit cost reductions. In fact, approximately 80% of our drilling cost reductions are due to faster penetration rates achieved by the application of Oxy drilling dynamics, along with improved well construction design, lower cost of materials, and enhanced logistics. In Permian Resources, the cost savings we have achieved due to improved efficiencies will be redeployed into drilling incremental wells in the latter part of the year, which will positively impact 2017 production. Additional capital will also be shifted to Colombia, where our teams have generated opportunities to deliver attractive returns at current prices. This activity will also support 2017 production. The construction of the joint venture ethylene cracker at Ingleside by OxyChem is on budget and on schedule to be completed in the first quarter of 2017. In addition, the crude oil export terminal at Ingleside being constructed by Midstream is also on budget and on time to be completed by year end. The terminal will have a total oil storage capacity of 2 million barrels and throughput capacity of approximately 300,000 barrels of oil per day. Although these activities will slightly increase our capital spending during third and fourth quarters, we don't expect to exceed our $3 billion budgeted spending for the full year. With the completion of the long-term projects in both our Chemical and Midstream segments, we expect to have increased flexibility with our capital program in 2017. Our efforts to focus on efficiency are paying off, as we continue to lower our total spend per barrel of production. This metric includes our overhead, operating, and capital costs per barrel of production. Our organization is focused on this metric, and we have linked incentive compensation to it. The metric is designed to drive cost reductions, increase well productivity, optimize base production. In 2014, our total spend per barrel averaged close to $62. We lowered this to about $40 in 2015 and have targeted $28.50 per barrel in 2016. In the first half of this year, we've beaten our target with average total spend of about $27 per barrel. We expect similar results during the second half of this year. Despite the increase in oil prices and energy costs during the second quarter, we held our production costs flat on a sequential quarterly basis while achieving a year-over-year decline in production costs of approximately 19%. Maintaining a conservative balance sheet continues to be a focus and a top priority. We ended the second quarter with $3.8 billion of cash on hand, an increase of $600 million from the first quarter. Our cash flow from operations exceeded our capital spending in the second quarter, and we collected the remaining $300 million of proceeds from our settlement with Ecuador. Throughout this year, we have consistently said that we will prudently manage our activity levels to stay positioned for profitable growth in 2017 while maintaining the flexibility necessary to maneuver through the uncertainty and volatility of this price environment. The capital redeployed into Permian Resources will be used to add two rigs by the fourth quarter to support production growth in 2017. The incremental capital for Colombia will be around $20 million. It will be directed to activities in La Cira-Infantas, where we have a successful partnership with Ecopetrol to develop low-decline water floods. The incremental production from this activity is also intended to support growth in 2017. Given the short-cycle nature of our Permian Resources business and the flexibility we have in our Colombia operations, we can adjust our capital spending up or down relatively quickly, depending on the price environment. On the M&A front, we also continue to look for ways to expand and further strengthen our position in the Permian through asset acquisitions, as we rarely purchase whole public companies. Our objective is to pursue opportunities in both enhanced oil recovery and our Resources business that provide meaningful synergies to enhance the value of our existing assets. Our goal in acquiring additional EOR assets is to blend development of long-life, low-decline production with our faster growth unconventional development. While we continue to evaluate potential opportunities, we are staying returns focused and note that asset prices appear excessive when one considers the current product price environment. At our board meeting in July, we announced a modest increase in our annual dividend rate from $3.00 to $3.04 per share. We have now increased our dividend every year for 14 consecutive years and a total of 15 times during that period. The dividend increase reflects our commitment to shareholders to grow the dividend annually, as is consistent with our longstanding capital priorities. As a reminder, our top priority for use of cash flow is the safety and maintenance of our operations. Our second priority is to fund the dividend. With improved capital efficiency in our Permian Resources business, the startup of the ethylene cracker in Chemicals combined with long-life base production, and a portfolio of high-quality opportunities, we expect continued future dividend growth. I'm pleased to note that our board of directors has elected a new director, Jack Moore. Jack most recently served as the Chairman and CEO for Cameron International. Prior to joining Cameron, he held various management positions at Baker Hughes and has nearly four decades of experience in the energy sector. His industry knowledge and management experience will be a great addition to our board. Before I hand off to Chris, I'd like to summarize by pointing out that across all our upstream oil and gas operations and in OxyChem and in our Midstream business, our teams are executing efficiently and innovatively to achieve pinnacle and operational excellence in all of our areas. Three things are driving this; First, the ability to focus on our core areas without the distraction from activities that are not core to us, thanks to the initiative Steve Chazen started in 2013. Second, we have excellent leadership at all levels throughout our organization. Third, our employees are performing at a very high level. They're engaged, motivated, and delivering exceptional results. While I'm happy about that and the direction we're headed, none of us are satisfied with where we are today, so we'll continue to aggressively and innovatively improve our performance. I'll now turn the call over to Chris Stavros for a review of our financial results and detailed guidance.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Thanks, Vicki, and good morning, everyone. Today I'll plan to talk about the following
Jody Elliott - President, Domestic Oil and Gas:
Thank you, Chris, and good morning, everyone. Today I will provide a review of our domestic operations during the second quarter and guidance on our program through the end of 2016. As Vicki discussed earlier, we slowed our Permian Resources drilling program as planned due to severely depressed product prices in the beginning of 2016. We strategically increased capital spending in the EOR business, which will drive increased production in future quarters and years. In order to prepare for growth in 2017, we plan to add two drilling rigs in our Resources business later this year. We will increase our operated rig count over the second half of the year to seven to eight drilling rigs in the Permian, five of these in Permian Resources. This is an increase from our previous guidance of four to five rigs. This incremental activity is a direct result of program savings from improved capital and operating efficiencies as well as improvements in base production management. Our team has performed extraordinarily well to capture these savings, which will be reinvested back into the business. As stated last quarter, our Permian Resources operation is being managed to maximize the value of our workforce, enhance our operational capabilities, invest in areas with existing infrastructure, and gather critical appraisal information to drive better well productivity. Our focus for the remainder of the year is to prepare the business for profitable growth in 2017. Turning to the performance of Permian Resources, in the second quarter we achieved daily production of 126,000 BOE per day, a 16% increase versus the prior year. Oil production decreased quarter over quarter by 5,000 barrels a day to 79,000 barrels per day. However, this was a 10% increase from a year ago. The decline was due to lower capital spending, with 14 wells put online versus 37 wells in the first quarter. In addition to better performance of our wells, emphasis on production optimization has been central to reducing declines in the business, and we've exceeded our expectations versus our goals. As previously stated, we expect to increase our activity in the second half of 2016 and bring approximately 30 wells online. Due to the slowdown in activity in the first half of the year due to depressed oil prices and a disciplined development strategy, we expect to see declines in the third and fourth quarter. Third quarter production should average 116,000 BOE per day. For the full year of 2016, we expect to produce 121,000 BOE per day, a 10% growth rate year over year. As our activity increases, we expect production decline to stabilize. And with higher oil prices, we will deliver production growth in 2017. As we continue to increase our lateral lengths, we now compare and benchmark our well cost on a cost per thousand feet of lateral length basis. Slide 31 illustrates our demonstrated improvement in well costs, which have declined by roughly 30% from 2015. Similarly, our 1,000 foot of lateral per rig per quarter has also improved from 25.2 per rig in 2015 to 36.3 per rig in the second quarter. These metrics will be a primary focus as we continue our development plans. I would emphasize that we estimate 80% of these improvements in efficiency are not at risk of service price increases in a cyclical recovery. Our Delaware Basin well performance continues to be strong despite reduced activity. We placed seven horizontal wells on production in the Wolfcamp A benches in the second quarter. We continue to increase well productivity by increasing contact with the reservoir near the wellbore utilizing higher cluster density, higher proppant loading, and drilling longer laterals. For example, we placed three Buzzard State Unit wells online, with an average peak rate of 1,993 BOE per day and a 30-day rate of 1,733 BOE per day. The HB Morrison B 15H well with a 5,000-foot lateral achieved a peak rate of 2,265 BOE per day and a 30-day rate of 1,717 BOE per day. As can be seen on the chart on slide 32, well productivity continues to improve across all production metrics year over year due to our successful efforts of applying geologic and reservoir parameters into our landing zones and completion designs. In the Delaware Basin, our Wolfcamp A 4,500-foot well cost decreased by about 19% from the 2015 cost of $7.7 million to a first half 2016 cost of $6.2 million. We reduced our drilling time by six days from the average of 25 days in 2015 to 19 days, measured by rig release to rig release. We expect the cost and productivity improvements in drilling, completions, and facilities to continue as we progress our program. In addition, we drilled a Second Bone Spring appraisal well in the Texas Delaware region, with encouraging results, which we believe will add additional bench potential to the long-term development plan in this area. We did not put any additional wells online during the second quarter in New Mexico, but we are actively drilling in the region. However, our Second Bone Spring 180-day cumulative production rates are among the best in the play. During the second half of the year, we plan to increase drilling and completion activity in the southern Eddy County area due to these improved results. We're targeting an average well cost of $5.5 million, and we continue to appraise and delineate multiple benches in the core areas of this region. And our initial results have indicated high-return multi-bench development potential. In the East Midland Basin, we brought on the Waldron Eunice 1306WA well in the second quarter at a peak rate of 1,407 BOE per day and a 30-day rate of 1,286 BOE per day. We also brought online the Merchant 1404A well at a peak rate of 1,222 BOE per day and a 30-day rate of 1,061 BOE per day. Both wells are producing with high oil cuts. In the West Midland Basin, eight new Lower Spraberry wells at South Curtis Ranch are producing results among the best in the play. Improved well results are due to an optimized landing zone target and stimulation redesign. In the Midland Basin, we made similar improvements in well cost and drilling days in drilling the Wolfcamp A formation. We reduced the cost of these 7,500-foot horizontal wells by 10% from the 2015 cost of $7.1 million to a first half cost of $6.4 million, including the additional cost of increased frac size. We reduced our drilling time by three days from the 2015 average of 19 days to 16 days, measured by rig release to rig release. In the Permian Resources as a whole, we achieved another quarter of lower quarter-over-quarter field operating expenses, due mainly to improved surface operations with optimized water handling, lower workover expenses, and better downhole performance. Since the second quarter of 2015, we've reduced our operating cost per barrel by 27%. We continue to work additional cost reduction and efficiency improvements. As stated earlier, our focus on maximizing production from existing wells has been central to reducing declines in the business. We expect that our annual average uplift from our investment will be over 6,000 net BOE per day. This is another example of leveraging our decades of base management expertise in the EOR business to our Resources business. In addition to the Midland Basin and Delaware Basin results, we drilled and completed two horizontal Wichita Albany appraisal wells on existing HBP acreage on the Central Basin Platform. We are encouraged by the early results of these lower decline rate wells and would anticipate drilling six to eight follow-up wells in the play in the next 12 to 18 months. In Permian EOR, we continue to take advantage of lower drilling costs and manage the operations to run our gas processing facilities at full capacity. Permian EOR had another quarter of free cash flow generation, driven by resilient base production and low capital requirements. Drilling costs are running 23% below our benchmark target, and we've lowered our cash operating expenses by 20% since the fourth quarter of 2014 and 7% year over year, driven mainly by lower downhole maintenance and injectant costs. In similar fashion to our Resources business, the capital savings achieved by the EOR team will be reinvested into additional wells and CO2 flood expansion. As I mentioned in previous calls, the Residual Oil Zone development, or ROZ, is a vertical expansion of the CO2 flooded interval. The ROZ underlies most of our major EOR properties and can be developed between $3 and $7 a barrel. Year to date, we have completed 74 well deepenings and recompletions along with 28 new wells in ROZ developments. We anticipate an additional 30 deepenings and recompletions and 22 new wells in ROZ developments in the second half of 2016. In addition, one of our horizontal rigs from Permian Resources drilled two deep CO2 source wells, which will help provide long-term supplies of CO2 and support our vast inventory of EOR development projects. In summary, we are achieving better than expected results in both Permian businesses that will allow us to invest the savings into additional wells in each respective business. In the current environment, we believe this is a prudent investment philosophy that motivates our employees and works well with our total spend per barrel incentive metric. We're pleased with the strides that our teams have made in execution, performance, and safety thus far in 2016, which will afford us the ability to ramp up our activity should oil prices exhibit fundamental stability. Thank you, and I will now hand it back to Chris Degner.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you. Jody. We will now open up the call for questions. And we would ask that you please limit your questions to just one and then a follow-up.
Operator:
Thank you. Our first question will come from Doug Leggate of Bank of America Merrill Lynch.
Doug Leggate - Bank of America Merrill Lynch:
Thanks and good morning, everybody. Vicki, adding a couple of rigs to the Permian at the back end of this year, I'm just curious
Vicki A. Hollub - President, Chief Executive Officer & Director:
You're talking about run rate with respect to rig activity?
Doug Leggate - Bank of America Merrill Lynch:
Yes, and capital expenditures. Is there a limit as to how much you would want to allocate there because obviously in a rising oil price environment, you guys have got a lot of levers you could pull?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Right. Currently for at least next year and 2017, and it's hard to predict for 2018. But for 2017, we intend to stay pretty close to the capital allocation that we have for this year, and that's assuming that prices are as we expect. And I will say that we expected the prices to be in the neighborhood of where they are right now, and that's why we took a conservative approach to our capital this year. We do expect some improvement next year but we're not sure how much that will be, so we're going to wait till toward the end of this year to determine exactly what our capital program for 2017 will be. But our expectation is that if things are as we expect them to be that we would be close to $3 billion. We might spend a little bit more than that if prices are a little bit better than we expect. But the run rate for our company going forward with the assets that we currently have would continue to be in the $3 billion to $3.5 billion, maybe a little bit more, but not a whole lot more than that.
Doug Leggate - Bank of America Merrill Lynch:
Maybe just a quick follow-up to that. Perhaps a better way to ask the question, Vicki, is what's the operating capacity that you have in the Permian? Do you have a lot of headroom where you could add rigs without necessarily having to increase capability?
Vicki A. Hollub - President, Chief Executive Officer & Director:
We have the capacity to increase significantly. We will be more limited by our disciplined approach, but we certainly have kept the capability within our organization. We have the ability to put the infrastructure in in the Permian, so we have I would say significant ability. At one time, we were running over 25 rigs. And we could, if prices were in the range that would warrant that, we could get back to that. But bearing in mind now that back when we were running 25 rigs, we were not as efficient as we are today. We're significantly improved with our efficiencies, so we could get actually the same amount of productivity with half the number of rigs that we were at at that time. So I don't see us going back to a 25 rig count in the Permian unless we expand our operations and our footprint. But we could easily go back to somewhere in the neighborhood of up to 15 rigs reasonably and still have the capacity to do it. I think we could get ahead of it with our infrastructure as well. And actually, Jody could talk a little bit more, if you'd like, about the infrastructure development and how we're trying to stay ahead of it. He's got teams working on development plans for our key areas that will put us we believe well ahead so that we could ramp up to levels of that activity without being encumbered by regulatory issues and/or infrastructure issues.
Doug Leggate - Bank of America Merrill Lynch:
Got it. My follow-up, Vicki – I don't want to take up too much time – my follow-up is a bit of an obtuse question, and I apologize in advance. The use of cash, the priority for use of cash, acquisition is still at the bottom of that list. And your commentary and the slide deck again points to a fairly big bid/ask spread as it relates to CO2. However, your currency is also quite valuable, so I'm just wondering. Should we be thinking a little bit out of the box in terms of whether Oxy would be prepared to use equity to make a CO2 add to the portfolio? And I'll leave it there, thanks.
Vicki A. Hollub - President, Chief Executive Officer & Director:
I'll say that the way you should view the capital priorities right now is just the two that I mentioned. Certainly, maintenance of our operations is the highest priority. Dividends are second. But when you look at the other possibilities, whether it's organic growth or share repurchases or acquisitions, those three really depend on the situations that we're in, and so those three can vary over time or according to the environment that we're in. I would say that for today, as per my comments about M&A, we are certainly looking at acquiring and expanding – acquiring assets and expanding our position in the Permian. And we would be for the right project, for the right opportunity, certainly be willing to use our equity to do that.
Doug Leggate - Bank of America Merrill Lynch:
I appreciate the answer. Thanks, Vicki.
Operator:
And the next question will come from Phil Gresh of JPMorgan.
Philip M. Gresh - JPMorgan Securities LLC:
Hi, good morning.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Good morning.
Philip M. Gresh - JPMorgan Securities LLC:
The first question is just maybe following up on your commentary about capital spending for 2017. How would you tie that spending to what kind of growth you think you could achieve across the portfolio, factoring in that Permian Resources will be declining and leveling off in the fourth quarter? I'm thinking not only in Permian Resources, but also internationally when you think about the growth you're seeing out of Oman and what you talked about with Al Hosn.
Vicki A. Hollub - President, Chief Executive Officer & Director:
I would say with the future the way we view it and what we expect to see in 2017, we're going to try to achieve within our range of growth targets, but possibly on the lower end if prices are still on the lower end and we don't see fundamentals driving prices up. So we're going to wait pretty much to the end of this year to make final decisions on it. But we do believe that in a price environment that's certainly better than where we are today is what we would need to continue to grow. But Permian Resources, we will grow Permian Resources next year. The question for us is whether or not we'll grow other areas within our company for next year, and that will all depend on what oil prices do.
Philip M. Gresh - JPMorgan Securities LLC:
And just to clarify, the historical range that you're referring to?
Vicki A. Hollub - President, Chief Executive Officer & Director:
The historical range is 4% to 6%.
Philip M. Gresh - JPMorgan Securities LLC:
Okay, so you still think you could hit the low end of that range next year?
Vicki A. Hollub - President, Chief Executive Officer & Director:
We do, in the price range that we would expect.
Philip M. Gresh - JPMorgan Securities LLC:
Got it, okay. And of that $3 billion, I know you gave this number a couple quarters ago. But what do you think is your sustaining capital requirement at this point for the total company?
Vicki A. Hollub - President, Chief Executive Officer & Director:
I'm sorry, you cut out. Could you ask that question again?
Philip M. Gresh - JPMorgan Securities LLC:
What do you think the sustaining capital requirement is for the total company at this point? I know you gave that number a couple quarters ago in your slides. I'm curious if the view is the same or if that's changed at all.
Vicki A. Hollub - President, Chief Executive Officer & Director:
With the increased production that we have now, the capital that would be required to offset declines would be in the neighborhood of about $2.3 billion to $2.4 billion.
Philip M. Gresh - JPMorgan Securities LLC:
Got it. Okay, thank you. I'll turn it over.
Operator:
And next we have a question from Ed Westlake of Credit Suisse.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Just I guess the first question is just on that production outlook for 2017, very helpful. Given the improvement in the D&C days and the well performance, I guess, and the investments in EOR, I would have expected 2017 to be perhaps a little bit stronger than that, so maybe just talk through. Is it timing of when you complete the wells, pad drilling type stuff?
Vicki A. Hollub - President, Chief Executive Officer & Director:
It's really a lot more around the uncertainty of the price environment, and it has a lot less to do with our capability to do it. What we want to do is ensure that we're conservative with our capital programs. We have the potential and the opportunities to certainly not only meet the upper end but exceed it, but we're really trying to be careful about what we forecast and what programs we set up for next year. I can tell you that what we'll do is that we'll put the program together. We always do that at the end of this year, and we'll firm it up by first of next year. But what our teams have done during this downturn in this slower period is they've enabled us to have a lot more flexibility next year to be able to ramp up should we need to or should we have the opportunity to do so. And the ramp up could be not just in Permian Resources. As I mentioned earlier, the ramp up could be in Colombia as well. And in addition to that, we expect that because of the situation with Al Hosn, overall, Al Hosn will have a higher production rate in 2017 because it will have a full year of production versus the warranty turnaround that we had in Q1 of this year. In addition to that, we'll have Block 62 gas on for the full year, and that will be helpful. So if you take those things, combine it with the flexibility that we have in both Permian Resources and Colombia, we'll start the year probably conservatively until we see fundamentals start to support prices, but we will have the ability to ramp up in multiple areas. And if prices and the fundamentals are such that we feel comfortable, we'll have the flexibility to actually increase our programs throughout the year if we see that that makes sense.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
My second question is on the Bone Springs chart that you've got in here on page 34, just with the new design, 4,500-foot lateral 180-day cumes over 200,000 BOE, and a decent oil cut, that actually looks a bit better than the chart you've got here on page 36 for a 10,000-foot lateral in the Lower Spraberry. So I guess the question is, is this – and I think I've asked this before – really a sweet spot in the Bone Springs geology? Or really maybe just give us some color as to how optimistic you feel about the Southeast New Mexico asset.
Jody Elliott - President, Domestic Oil and Gas:
This is Jody, and good morning. It's more than a sweet spot. I think we're encouraged with Southeast New Mexico across the board, multiple bench development. These examples are over in our Cedar Canyon area. But further east of that area, there's acreage with even more benches that are prospective. So very encouraged with Southeast New Mexico, and the rig adds that we're talking about will likely be in the Delaware and in New Mexico.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay, thanks very much, well done.
Operator:
And the next question comes from Ryan Todd of Deutsche Bank.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great, thanks, maybe a couple. One, in regards to 2017 capital, can you talk about what you believe the year-on-year change in cash balance is driven by the Chemicals business? For example, how much capital do you see rolling off into 2017 relative to incremental cash flow from the startup of the cracker?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Yes, for the Chemicals cash flow, we expect that capital this year is around $500 million. Next year it should drop to less than $400 million. The following year it would be back down to basically its maintenance levels of around $250 million. So we'll have around $300 million in cash flow from Chemicals this year and expect that by 2018 that would be up to around $900 million, potentially a little bit more than that depending on product prices in the Chemical business.
Ryan Todd - Deutsche Bank Securities, Inc.:
Okay, so that should free up significant capital, I guess, in 2017. It would be, even at that $3 billion world, to be reinvested back into the organic upstream business.
Vicki A. Hollub - President, Chief Executive Officer & Director:
That's correct. We had about – total including the Chemicals and the Midstream business, we had this year $500 million of committed capital and almost $400 million of that's coming off for 2017. That will be redeployed into – most of that into the Permian Resources business.
Ryan Todd - Deutsche Bank Securities, Inc.:
Perfect, thanks, and then maybe just one follow-up on portfolio rationalizations. At this point, you guys have been very active over the last 12 to 18 months. Is it all done? Is there anything left to be done in terms of streamlining the portfolio? I'm not sure if you mentioned this in the prior comments or if I missed it. Within that regard, PAGP [Plains GP Holdings, LP], what would you need to see to further monetize that?
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Ryan, most of the rationalization in terms of Oil & Gas and certainly Middle East operations is largely behind us. We've done that over the last year or so. From a corporate asset perspective, we still have, as you point out, the Plains units. So there are about 80 million units of that, and they've just gone through their simplification process. So we'll let that close out here formally in the latter part of the year, fourth quarter with their plan. And then this is not a strategic investment on our part, so I would tell you that we don't look to hold on to that longer term. So that's an option in terms of liquidity that we've got, market value $800 million or thereabouts.
Ryan Todd - Deutsche Bank Securities, Inc.:
Okay, thank you.
Operator:
The next question is from Paul Sankey of Wolfe Research.
Paul Sankey - Wolfe Research LLC:
Hi, everybody. Thank you. Vicki, you keep talking about the oil price you're assuming. I assume that that's $50-ish. Previously, you had said that you would add rigs once you became confident that $50 would be sustained along the strip. I assume that you're maintaining the view that $50-plus is what we're going to see and hence you want to accelerate.
Vicki A. Hollub - President, Chief Executive Officer & Director:
That's pretty close to right. We do expect it to be $50 or above in 2017, but certainly we're not as bullish as some people. We're taking, as I said, a conservative view, but it would be fundamentally above $50.
Paul Sankey - Wolfe Research LLC:
And hence the minor acceleration I guess we'll call it?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Right.
Paul Sankey - Wolfe Research LLC:
On the Permian deal, I think you said very clearly you don't want to make a corporate acquisition. I think you need something material to make it worth your while. My sense is that the recent $1 billion type asset packages would not really be of a sufficient scale for you guys to really work the CO2 business in the way that you want to.
Vicki A. Hollub - President, Chief Executive Officer & Director:
The way we view it is the Permian, as you know, is a huge place. There are lots of opportunities. We're looking at this as a goal and an objective in terms of our total expansion, and there are multiple ways to get there. We could get there with several different options, and what we've done is prioritized our options. And we're working pretty much a lot of things to try to ensure that we reach our goals. But we're happy...
Paul Sankey - Wolfe Research LLC:
Can you specify – sorry. I was going to ask you. Can you just specify what the goals are?
Vicki A. Hollub - President, Chief Executive Officer & Director:
The goals are to try to match what our growth profile could be in EOR with Resources. And we haven't really put what that means in terms of exact production volumes or anything like that out there because it's hard to do at this point with respect to the EOR business. But we're really in a position because of where our operations are with respect EOR in the Permian, we've got the ability in multiple areas to play a Pac-Man approach where we can acquire a lot of smaller assets that could total up to make a material difference to us as a cumulative acquisition. So we're not opposed to looking at a variety of smaller deals. And again, because of our position, we would have the capability to do that and make it still fit within our goals to try to make sure that these are synergistic with our current operations.
Paul Sankey - Wolfe Research LLC:
And then on the CO2 side?
Vicki A. Hollub - President, Chief Executive Officer & Director:
That's actually what I'm talking about. We're going to do the same thing in both Resources and CO2 because we have the ability around the areas that we currently operate to add additional properties.
Paul Sankey - Wolfe Research LLC:
Okay. So what you're saying is on either side you could go smaller or larger basically in terms of adding assets?
Vicki A. Hollub - President, Chief Executive Officer & Director:
That's correct.
Paul Sankey - Wolfe Research LLC:
Is that something – I think you're more or less saying that you feel it's necessary if you're going to maintain the scale of growth that you're aiming for.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Yes, the scale of growth is much easier in the Resources business. In the EOR business, the issue that we have today is that we're constrained by some of our infrastructure. So we feel like some of the expanding to our footprint would enable us to also expand our infrastructure to support some growth, accelerated growth, with not only what we have but what we could potentially pick up.
Paul Sankey - Wolfe Research LLC:
Right. And I think just finally for me, just you are somewhat short, I think, if not short, depending on your growth plans, of CO2 itself?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Currently, we don't see an issue with the CO2 that we would need to accelerate growth. We're trying to look at options for where we get the CO2, but I don't see that being a bottleneck for us. I see the current bottleneck being just the fact that it doesn't make sense to accelerate some of our floods where our plants are sized more appropriately for a full field development. So that's really some of the bottleneck is the infrastructure around the existing plants.
Paul Sankey - Wolfe Research LLC:
Thank you very much, Vicki.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Okay.
Operator:
And next we have Guy Baber from Simmons.
Guy Allen Baber - Simmons & Company International:
Good morning, everybody. Thanks for taking my question. I wanted to start off with the Permian unconventional production trajectory. You referenced improved confidence in that business in the prepared remarks, but it looks like the guidance today calls for a bit bigger decline over the back half of the year than we would have expected, down 10,000 barrels a day 3Q. Can you talk a little bit more about the declines you're seeing there, how conservative that guidance might be, just how that's shaping up? And then secondly in the Permian also, you talked about year-on-year growth for unconventional in 2017. Can you talk about the spending level necessary relative to your $700 million or so budget this year that would be required to deliver production north of 120,000 barrels a day, as indicated in the slides?
Jody Elliott - President, Domestic Oil and Gas:
Guy, this is Jody. I appreciate the question. With regard to the decline, it's really a function of the activity set from this last quarter. One of the things I discussed, we moved a rig and drilled a couple of Wichita Albany wells. We drilled a couple of CO2 source wells. So the activity set in this quarter was fairly low for Resources, which is indicative in the forecast for the third quarter. But in the back half of the year, those rigs are back in Resources. We're going to add rigs. And so we will flatten that decline toward the end of the year and then set us up with the right trajectory for production growth into 2017.
Guy Allen Baber - Simmons & Company International:
Okay, great. And then did you have a spending estimate relative to the $700 million budget this year that would drive north of 120,000 barrels a day of production next year?
Vicki A. Hollub - President, Chief Executive Officer & Director:
We expect that would probably be in the $1.3 billion to $1.4 billion range. But with the way the teams are still improving efficiencies and the well productivities are getting better, we're not prepared to commit to that completely at this point. Every time we set a target for those guys, they meet or exceed it, so we're not sure that that's the exact number. We'll know better about that by the end of the year as we prepare our final plans and we get a little more information from our Southeast New Mexico developments.
Guy Allen Baber - Simmons & Company International:
That's very helpful. And then I wanted to ask one on Al Hosn, with obviously very strong performance during the quarter, above nameplate capacity. Can you talk a little bit more about what drove that? Is that type of performance sustainable? And are you already finding ways to sustainably I guess debottleneck that production into next year?
Edward A. Lowe - President, Oil and Gas, International:
Hey, Guy. This is Sandy Lowe, good question. As we do with other large facilities like this, when everything is stable, we tend to test individual components and processes within the plant. And we've been doing that during the summer, which is the toughest time and the most relevant proving because of the relatively high heat in the area. And we've been able to show our guidance of 60,000 barrels per day equivalent for Oxy's share, and we've been up in the high-60,000 barrels per day with the promise to get into the 70,000 barrels per day just by pushing individual processes pretty hard. The main reason for this is to assess what the expansion would look like and which components we'd need, either total addition or enhancement, or some that just might be able to take higher load. So we think that out of this will come, if you like, a new baseline, which could be 110% or 112%, and then from that – or even a bit higher. And from there we would design an expansion to get up to a good number. It's the sweet spot for the investment profile and the production profile, of course, working with our bigger partner, the Abu Dhabi National Oil Company. So that's where we are with it. I think it will be – the fact that we did this during the summer is probably pretty good for year-round enhanced production.
Guy Allen Baber - Simmons & Company International:
Thank you very much.
Operator:
And next we have a question from Roger Read of Wells Fargo.
Roger D. Read - Wells Fargo Securities LLC:
Thanks, good morning. I guess to jump into the Permian area, I was wondering. With some of the areas you've expanded into, specifically in Southeast New Mexico, and your discussion of additional benches, is part of the rig count increase reflective of any an HBP issue arising here, or is all the acreage fairly well secure and just simply reflects, like you said, the price outlook and budgetary expectations?
Jody Elliott - President, Domestic Oil and Gas:
Roger, most of our acreage is HBP. We have some drilling clocks, 180-day drilling clocks. But the activity set is driven by the value proposition and the returns from these investments. We have very few remaining lease obligation drilling wells, if any at all.
Roger D. Read - Wells Fargo Securities LLC:
Okay, thanks. And then I'm not sure if this is for you, Jody, or for Vicki, but the way to think about the drilling efficiencies that you have achieved, if we essentially quadruple from the drilling level we've been or double from the year-end exit rate, the 15 rigs that were mentioned, what would you think of budgetarily or operationally is the right way to think about those efficiencies that can continue to be realized, or do we see the curve bend the other way? And this is not specifically looking at you, but as we add that many rigs, we're going to get some less efficient crews potentially into the field, and I'm just trying to understand on a longer-term basis what that may mean for well costs breakeven, cash flow and all.
Jody Elliott - President, Domestic Oil and Gas:
I think that's manageable as long as the ramp up from an industry perspective is fairly moderate. What encourages me, at least for us at Oxy, is that we continue to have new ideas coming forward for cost efficiency. We've mentioned before, last year we had this cost stand-down day in Resources alone that generated over 1,400 ideas. We've put in place about half of those, and we're still vetting the other half for opportunities. And again, that crosses OpEx, capital, SG&A. We have some other technology things we're working on, on the drilling side that we think can provide efficiency gains. We know at some point that the price cycle will turn around on services, but I think we're getting well prepared to offset that with efficiency, not just for us but for the suppliers as well. In the areas of integrated planning and logistics, crew utilization, equipment utilization, bundling of services, there are just a number of things that we think can help offset the potential for either efficiency or cost pressure as we move forward. So I think we can hold those rates of return.
Roger D. Read - Wells Fargo Securities LLC:
Okay. And if I could sneak in one more along those lines of efficiencies, when you think about the additional rigs in the fourth quarter, what's roughly the time from adding that rig, spud date to first oil production? It sounds like you're pretty far ahead on the infrastructure side, so I would think pretty quick tie-ins.
Jody Elliott - President, Domestic Oil and Gas:
It's fairly quick. It's really more a function is it a single well or is it a multi-well pad where you want to drill all the wells and then complete all the wells, so your time to market for that package is a little bit longer. But again, we're drilling in areas mostly where we've got infrastructure, and so adding wells is fairly quick. There's not a long delay.
Roger D. Read - Wells Fargo Securities LLC:
Okay, thank you.
Vicki A. Hollub - President, Chief Executive Officer & Director:
I would add to that that the way they're doing the developments now is they're doing pad drilling. So as Jody mentioned, the pad drilling will result in lumpy production. That's why we're not expecting a production impact from the increased activity levels this year, but we do expect it to show up in early Q1. And that's why we set the program up that way. It was really a part of our plan to start getting ready for 2017 production, so that's when we'll see the incremental from the increased activity.
Operator:
And the next question is from John Herrlin of Société Générale.
John P. Herrlin - SG Americas Securities LLC:
Thanks. With your Permian acreage, what's the chance of you doing swaps? And then my other question is with Colombia. What would the response time be for the water floods once you get going?
Vicki A. Hollub - President, Chief Executive Officer & Director:
I'll start with Colombia first and then we'll let Jody take the Permian question. In Colombia, what we've done, we entered into – we currently have a water flood going there now that's successful. We got some additional intervals within that same area to develop two other zones. And we've been studying and putting the water flood pilot plans together, so we'll be starting the pilot first. So that's why we're adding the $20 million there to Colombia is to do the pilot so that we can get some information from that before we start into full field development. So the full field development of those water floods will come after we complete the pilot.
Jody Elliott - President, Domestic Oil and Gas:
And, John, with regard to Permian acreage swaps, that's probably our most active area right now with our land business. And so most operators are wanting to drill longer laterals, 7,500-foot, 10,000-foot. And so acreage swaps, especially where you've got more neighboring acreage, trying to swap Midland for Delaware is a little tougher. But in a general geographic area, we're seeing quite a bit of activity, and we've taken advantage of that so that we can drill longer laterals.
John P. Herrlin - SG Americas Securities LLC:
Okay, thanks. Vicki, back to Colombia, again, what response time, a year, six months? Do you have a sense?
Vicki A. Hollub - President, Chief Executive Officer & Director:
I think we would expect that from the time that we start water injection that it would be within six months to a year.
John P. Herrlin - SG Americas Securities LLC:
Okay, thank you.
Operator:
And this concludes our call today. I will now turn the call back over to Chris Degner.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Laura, and thank you, everyone, for participating on our call. Bye.
Operator:
The conference has now concluded. Thank you for attending today's presentation, you may now disconnect.
Executives:
Christopher M. Degner - Senior Director, Investor Relations Vicki A. Hollub - President, Chief Executive Officer & Director Christopher G. Stavros - Chief Financial Officer & Senior Vice President Jody Elliott - President, Domestic Oil and Gas Edward A. Lowe - President, Oil and Gas, International
Analysts:
Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Philip M. Gresh - JPMorgan Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Roger D. Read - Wells Fargo Securities LLC Guy A. Baber IV - Simmons & Company
Operator:
Good morning. And welcome to the Occidental Petroleum Corporation First Quarter 2016 Earnings Conference Call. All participants will be in a listen-only mode. After today's presentation there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner. Please go ahead
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Emily. Good morning, everyone, and thank you for participating in Occidental Petroleum's First Quarter 2016 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Jody Elliott, President of Oxy Domestic Oil & Gas; Sandy Lowe, President of Oxy International Oil and Gas; Chris Stavros, Chief Financial Officer; Rob Peterson, President of OxyChem. In just a moment I will turn the call over to Vicki Hollub. As a reminder today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our first quarter 2016 earnings press release, the investor relations supplemental schedules, our non-GAAP to GAAP reconciliations, and the conference call presentation slides can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Vicki Hollub. Vicki, please go ahead.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Thank you, Chris. Good morning, everyone. This quarter was another extremely difficult one for the industry. But we stayed focused on our game plan, addressing the things that are within our sphere of influence, so that we not only survive through this time but thrive. We'll do this through full cycle cost leadership, optimal capital allocation, and maintaining our balance sheet. Superior access to and lower costs of capital positions us to invest in opportunities that will grow our business organically or through acquisitions. We believe the world will continue to need oil. And when markets demand production growth, they will first look to the Permian. And we will be ready. First and foremost, we're focused on operational excellence to drive full cycle costs lower for all of our businesses. This requires subsurface and surface execution excellence. In the first quarter we demonstrated good operational performance. We grew Permian Resources production by 30,000 BOE per day or 31% year over year. We performed above our expectations on new wells brought online, particularly in New Mexico. And we delivered better base production. Permian production outperformance allowed us to exceed total production expectations for the quarter, despite lower than planned production from Al Hosn. Al Hosn was shut down for a successful warranty turnaround. But the shutdown was longer than expected. It is now back on production at full capacity. We also reduced our overall cash operating costs by 23% and achieved SG&A savings of 14% versus the first quarter of last year. To further improve our overall well performance we're focusing a portion of our workforce on initiatives that will have a step change impact on costs in the future. Such as artificial lift design improvements, multi-bench development, increased integration of new 3D seismic surveys, and the application of data analytics into our reservoir characterization. To incentivize our management and employees we developed a target metric, called total spend per barrel, which is our cash, operating capital, and SG&A costs, divided by our total production. Our target for 2016 is almost 30% lower than 2015's actual total spend. This is an aggressive target, especially in view of the fact that we reduced total spend per barrel from over $60 to $40 in 2015. Our 2016 capital program is $3 billion, a 50% reduction from 2015. We're on track to achieve this with first quarter capital spend of $687 million. Our capital is focused in our core areas. Taking advantage of reduced cost of labor and materials in this environment, we shifted more capital to Permian EOR to modify and expand existing facilities, increasing our capacity to handle and inject greater quantities of CO2. This will enable us to implement additional CO2 projects and further grow oil production. These projects will have a longer duration with typical production response time of 1 year to 2 years. By then we expect prices to be higher than they are today. We're also targeting lower-cost projects, including residual oil zone CO2 floods, where development costs are between $3 and $7 per BOE. In Permian Resources our development activities are in the Midland and Delaware basins, in areas where we have existing infrastructure, allowing us to achieve higher returns. We are maintaining minimal activity levels, sufficient to continue to improve execution efficiencies and well production performance. This allows us to retain our inventory of shorter cycle, unconventional wells for development during an improved environment. In the Chemicals business the Ingleside cracker remains on budget and on time for startup in the first quarter of 2017. Our balance sheet remains strong on an absolute basis and relative to our peers. In the first quarter we closed on $285 million of asset sales in the Piceance Basin, the Dallas Tower, and a small specialty chemical operation. We received $550 million of proceeds from our settlement with Ecuador. In April we issued $2.75 billion of bonds that will be used to retire and call about $2 billion of debt maturing in 2016 and 2017. We ended the first quarter with $3.2 billion, which is ample cash and liquidity to fund our capital program and dividends. With a strong start in the first quarter we've raised our production guidance on our core assets to a range of 585,000 BOE to 600,000 BOE per day. Overall domestic production is anticipated to decline slightly through the year, primarily due to the declining natural gas and NGL volumes, caused by the curtailment of drilling activity in our gas assets in 2014. We expect a modest increase in production from Permian Resources versus last year. And Permian EOR production will remain flat. In our capital programs we expect slightly higher spending in the second and third quarters due to the timing of major projects in our Chemicals and Midstream segments. As I mentioned earlier our full year production will not exceed – our program, our capital program will not exceed $3 billion. This plan should approximate our expected cash from operations at current commodity prices. In summary, I'd like to thank our employees for their commitment to excellence in both safety and operations during these challenging times. They're continuing to find ways to add value through increased sales and cost reductions across all segments of our company. While the macro environment remains challenging for the industry, we believe our continued focus on returns, improved cost structure, and a strong balance sheet provide us with the opportunity to emerge from the current cycle as a stronger company relative to our peers. Finally, I'd like to take a moment to recognize Steve Chazen. While he's not here today, I know he will eventually listen to this call. On behalf of investors, the Board of Directors, and employees, I would like to thank Steve for his leadership and outstanding service to Occidental over his 22-year career. He shaped our company into what it is today. And we're grateful to him for that. I'll now turn the call to Chris Stavros for a review of our financial results and detailed guidance.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Thanks, Vicki, and good morning, everyone. As Vicki noted, despite the severe weakness in product prices during the quarter, our business benefited from higher than expected production volumes from our ongoing domestic operations, lower cash operating costs, and improved capital efficiency. These factors help support our operating cash flow during the quarter. This, in combination with a strong balance sheet and ample liquidity, has allowed us to weather the continued weak product price environment. Our core financial results for the first quarter of 2016 were a loss of $426 million or $0.56 per diluted share, a decrease from both the year ago quarter and also the fourth quarter of 2015. The decline in both sequential and year-over-year core results were attributable to much weaker commodity prices, which more than offset the benefit from lower costs. Reported results for GAAP purposes during the first quarter of 2016 was income of $78 million or $0.10 per diluted share, compared to a loss of $218 million or $0.28 per diluted share in the prior year period. Reported results included gains on asset sales of $87 million after tax, and $438 million after tax as a result of proceeds received from the settlement with Ecuador, partially offset by several non-cash charges. Oil and Gas core after tax results for the first quarter of 2016 were a loss of $388 million, a sequential decline of about $200 million, mainly due to lower commodity prices, partially offset by improved cash operating costs. Our first quarter 2016 worldwide realized oil price of $29.42 per barrel fell by nearly $10 a barrel or nearly 25% compared to prices during last year's fourth quarter. Total company Oil and Gas production volumes from our ongoing operations averaged 590,000 BOE per day in the first quarter of 2016, 59,000 BOE per day higher than the prior year period, although down 7,000 BOE per day on a sequential quarterly basis. This was well above the higher end range of 570,000 BOE to 585,000 BOE per day for full year 2016 production guidance that we provided earlier this year. Total domestic production volumes climbed 3% sequentially at 307,000 BOE per day during the first quarter. Our domestic oil production was 197,000 barrels per day, up 7,000 barrels per day from last year's fourth quarter and 17,000 barrels per day higher from the same period a year ago. Production in our Permian Resources business grew to 128,000 BOE per day during the first quarter of 2016, compared to 118,000 BOE per day during the fourth quarter, far exceeding our earlier guidance of 121,000 BOE per day for the period. Permian Resources volumes grew by more than 30% compared to the year ago period. International production from ongoing operations was 283,000 BOE per day during the first quarter of 2016, down 16,000 BOE per day compared to the fourth quarter of last year, primarily due to the scheduled first quarter warranty shut down at the Al Hosn gas plant. Total production from our ongoing operations excludes volumes of 67,000 BOE per day from assets we have either divested or exited or are in the process of exiting. Domestically, this includes our Williston operations, which we sold in November 2015, and our Piceance operations, which were sold in March of 2016. Tables showing volumes both on a reported basis and also from pro forma ongoing operations are included in the schedules along with our press release. Domestic Oil and Gas cash operating costs from ongoing operations declined to $11.86 per BOE in the first quarter, compared to $12.28 per BOE during the fourth quarter of 2015 and 13% below full year 2015 costs of $13.58 per BOE. The reduction in costs is mainly a result of improved efficiency around our surface operations and maintenance. Overall Oil and Gas DD&A for the first quarter of 2016 was $15.61 per BOE, compared to $15.81 per BOE during 2015. Taxes other than on income, which are directly related to product prices, were $1.15 per BOE for the first quarter, compared to $1.32 per BOE during 2015. First quarter exploration expense was $9 million. Chemicals first quarter 2016 pre-tax core earnings were $126 million, compared with earnings of $116 million during last year's fourth quarter and $139 million in the year ago period. The sequential improvement in earnings reflected higher sales volumes across most product lines compared with lower natural gas costs, partly offset by weaker PVC, VCM, and caustic soda pricing. Weakness was also seen in the calcium chloride business as a result of the unseasonably warm winter evidenced in key markets, combined with the industry slowdown in fracking activity. Chemicals also closed on the sales of its corporate headquarters building in Dallas and a small specialty chemical operation, which together resulted in pre-tax gains of roughly $90 million. And those are excluded from our core Chemical earnings. Midstream pre-tax core results were a loss of $95 million for the first quarter of 2016, compared to a loss of $45 million in the fourth quarter of last year and a loss of $5 million in the prior year first quarter. The sequential decline was mainly attributable to lower midstream income from Al Hosn due to the warranty shutdown in the quarter and planned maintenance at the Dolphin [Gas] Project, which led to lower foreign pipeline income. Looking at our cash flows for the first quarter, we began the year with $4.4 billion of cash on hand. During the first quarter we generated $825 million of cash flow from continuing operations before working capital and other changes. Net working capital changes consumed $320 million of cash during the period. The use was related to the reduction in capital spending associated with deceleration of drilling activity, cyclical payments of property taxes and employee severance-related costs, and payment of liabilities accrued at year end related to the exit or exiting from some international operations. Capital expenditures for the first quarter were $685 million, a 41% decline from the $1.2 billion spent in the fourth quarter of 2015. While our first quarter capital was lower than expected, this was due to a deferral of some outlays in Midstream and Chemicals into the second and third quarters. Our 2016 total company capital program remains on track to be between $2.8 billion to $3 billion and ending the year at a rate similar to the first quarter as committed project capital winds down. We received $285 million from the sale of non-core assets in the Piceance Basin sale of some chemical assets as I noted earlier. We also collected $550 million from our settlement with Ecuador during the first quarter and expect to receive payment of more than $300 million in the coming months. These proceeds have been classified as discontinued operations in the cash flow statement. During the quarter we retired $700 million of debt which matured in February and paid $575 million in dividends. We ended the first quarter with a cash balance of $3.2 billion. On April 4 of this year, we completed a $2.75 billion three tranche senior notes offering with attractive coupon rates of 2.6%, 3.4%, and 4.4% on the 6-year, 10-year, and 30-year notes respectively. Primary use of the proceeds will go towards refinancing of $750 million in notes that mature on June of this year. And we've also exercised our early redemption option to call $1.25 billion of notes that were scheduled to mature in February of 2017. After this redemption, Oxy's total outstanding debt will be approximately $8.3 billion, essentially the same as at the end of 2015. Importantly, this transaction extended the life of our debt maturities by 5 years with our next maturity not scheduled until February 2018. Moody's currently rates Oxy at A3 stable, and S&P rates us at straight A stable. Turning to guidance. As Vicki highlighted, we are raising our full year 2016 production guidance from a range of 2% to 4% previously, to 4% to 6%, essentially a 2% increase. We're within a new range of 585,000 BOE to 600,000 BOE per day for the full year. The increase will be accomplished without any change to our original capital program and is primarily a result of better than expected production in our domestic operations. Specifically, results in the Permian Resources continue to outperform our expectations, due to improved well productivity and better management around our base volumes. Turning to guidance for the second quarter. We expect our total Oil and Gas production pro forma for ongoing operations to increase sequentially to a range of 600,000 BOE to 610,000 BOE per day, as Al Hosn and Dolphin ramp back up from the first quarter scheduled turnarounds. And as gas production from Oman's Block 62 continues to rise towards full production levels. Domestically, we expect production to be flattish with the first quarter levels or about 307,000 BOE per day. Second quarter should also see production in Permian Resources similar to the first quarter, despite the slowdown in activity. We expect production in Permian Resources to decline modestly during the second half of 2016. Variability around the outcome will be a function of well performance, capturing further efficiency gains and our ability to continue to manage base production. Permian EOR volume should remain relatively steady at about 145,000 BOE per day, while also providing stable cash flow. Our DD&A expense for Oil and Gas is still expected to be approximately $15 per BOE during 2016. And depreciation of the Oil and Gas segment is expected to exceed this year's capital investment by more than $1 billion. The combined appreciation for the Chemical and Midstream segment should be approximately $670 million for the year. Exploration expense is estimated to be about $25 million pre-tax for the second quarter. Price changes at current global prices affect our annual operating cash flow by about $100 million for every dollar per barrel change in WTI. A swing of $0.50 per million BTUs in domestic natural gas prices affects annual operating cash flow by about $50 million. Our Midstream operations has exposure to two separate and different lines of businesses. The results of our Oil and Gas marketing and gas processing businesses are inherently volatile and sensitive to changes in commodity prices and price differentials. Conversely, our pipeline and transportation operations and partial ownership interest of the Plains All American GP provide a stream of more stable and predictable income and cash flow. With regard to our marketing business we have supply commitments and takeaway capacity to handle our Permian and equity production volumes in addition to third party volumes. The downturn in oil prices has slowed production growth in the Permian, creating a situation of overbuilt infrastructure, where takeaway capacity exceeds production. Price differentials between the Permian and Gulf Coast have shrunk to levels that do not fully cover our cost of transportation. A gradual improvement in oil prices should incentivize production growth in the Permian Basin. And we expect price differentials to widen, as production fills some of the excess takeaway capacity over time. Our domestic gas processing business supports domestic upstream production. Margins in this business have suffered, as NGL prices have dropped significantly. The recent quarterly losses incurred in the Midstream business are a direct result of these factors. In Chemicals we anticipate pre-tax earnings of about $100 million for the second quarter. The expected sequential decline in income is due to planned maintenance outages at several of our chloro-vinyl plants during the quarter. While price support for chloro-vinyls has been lackluster so far this year, the combination of both scheduled and unscheduled industry outages are expected to tighten market conditions for both vinyls and caustic soda into the second half of this year. The worldwide effective tax rate on our core income was 29% for the first quarter of 2016. Using current strip prices for Oil and Gas, we expect 2016 domestic tax rate to be about 36%, and our international tax rate to be about 76%. Turning to our overall costs. Total spend per barrel, as Vicki mentioned, was added as a new internal performance metric last year, because of OXY's increased focus on operational efficiency, especially in consideration of the sharp decline in commodity prices. This metric is defined as the total cost per BOE of production and includes capital spending, cash operating costs, and G&A costs. A portion of senior management's incentive compensation is directly aligned with this performance metric, as it focuses our efforts on efficiency, financial returns, and free cash flow generation. This efficiency metric is designed to help manage the reduction in overall spending, while rewarding production growth. During 2015 we were successful in reducing our total spend per BOE by more than 30% compared to the prior year to approximately $40 per BOE. A reduction in our total spend per BOE of similar proportion is also targeted for 2016. I'll now turn the call over to Jody Elliott, who will discuss activity around our Permian operations.
Jody Elliott - President, Domestic Oil and Gas:
Thank you, Chris, and good morning, everyone. Today I'll review the highlights of our Permian Resources and Permian EOR results in the first quarter, provide guidance on our program for the remainder of the year. As Vicki highlighted previously with regard to capital priorities, due to the current oil price environment, our focus has been to prudently allocate capital to our Permian Basin businesses. With this in mind our Permian Resources operation is being managed to maximize the value of our workforce and enhance operational capabilities, invest in areas with existing infrastructure, and gather critical appraisal information to drive better well productivity. In Permian EOR we've proportionally increased the capital allocated to this long lived business to expand CO2 injection capacity and facilities and to bring forward the resource potential. We continue to invest heavily in the application of geoscience and data analytics into our development strategy to ensure we are competitively positioned to take advantage of a sustained improvement in commodity prices. Turning to Permian Resources. In the first quarter we achieved record daily production of 128,000 BOE per day, a 31% increase versus the prior year. Oil production increased to 84,000 barrels per day, an 11% increase from the previous quarter and a 35% increase from a year ago. Additionally, we have leveraged and extended our industry leading practices from our EOR business to drive improvements in base management in order to minimize decline. Our Delaware Basin well performance continues to be strong. We placed 15 horizontal wells on production in the Wolfcamp A benches in the first quarter. We continued to increase well productivity by increasing contact with a reservoir near the wellbore, utilizing higher cluster density, higher proppant loads, and drilling longer laterals. For example, the Vanguard 3 number 15-H achieved a peak rate of 2,099 BOE per day and a 30-day rate of 1,308 BOE per day. The HB Morrison B 13H, with a 10,000-foot lateral, achieved a peak rate of 2,335 BOE per day and a 30-day rate of 1,781 BOE per day. Our successful efforts of applying geologic and reservoir parameters into our completion design continues to drive breakthroughs in well productivity and will reduce the economic hurdle point of our inventory. In the Delaware Basin our Wolfcamp A 4,500-foot well cost decreased by about 18% from the 2015 cost of $7.7 million to a current cost of $6.3 million. We reduced our drilling time by 6 days from the 2015 average of 25 days to 19 days, measured by rig release to rig release. We expect the cost and productivity improvements in drilling, completions, and facilities to continue as we progress our program. In New Mexico we are delivering play-leading wells by applying our understanding of geologic and reservoir parameters into our completion design. We are enthusiastic about superior reservoir quality and multi-bench potential in this play. During the first quarter we placed six horizontal wells on production in the Second Bone Spring in New Mexico. One of our best well results to date, the Second Bone Spring Cedar Canyon 23 Federal 5H produced a peak rate of 2,820 BOE per day and a 30-day rate of 1,879 BOE per day at an 82% oil cut. We increased proppant from 1,000 pounds to 1,500 pounds per foot and trialed two wells with 2,000 pounds per foot. This has resulted in greater contact with the reservoir closer to the wellbore, as compared to the prior completion design. As a result of these advancements in our completion design, the last four Cedar Canyon wells put on production have achieved 90-day cumulative production totals, approximately double the prior results. We'll continue to leverage our geo-driven analytics to identify advancements in completion design. And we'll test more aggressive cluster spacing, more clusters per stage, and slick water fluid systems in the second half of 2016. Drilling and completion costs continue to improve in New Mexico as well, reducing costs per lateral foot by over 20%, resulting in a current completed well cost, including hookup, of $5.9 million. We expect continued improvement and efficiency gains and have targeted well cost of $5.5 million for our 4,500-foot Second Bone Spring wells in the second half of 2016. In the East Midland Basin we brought the Shields 3105 1WA well online in the first quarter at a peak rate of 1,606 BOE per day and a 30-day rate of 1,395 BOE per day. We also brought online the Polo 1605A at a peak rate of 1,265 BOE per day and a 30-day rate of 1,018 BOE per day. Both wells are producing with high oil cuts. In the Midland Basin we made similar improvements in well cost and drilling days in drilling the Wolfcamp A formation. We reduced the cost of these 7,500-foot horizontal wells by 14% from the 2015 cost of $7.1 million to a current cost of $6.1 million. We reduced our drilling days as measured by rig release to rig release by 16% from 19 days in 2015 to 16 days in the first quarter. In Permian Resources we're continuing to lower field operating expenses through optimized water handling, lower work over expenses, and better down hole performance. Since the first quarter of 2015, we've reduced our operating costs per barrel by 33% and continue to work additional cost reduction and efficiency improvements. We'll maintain flexibility to ramp up our rig activity in the fourth quarter of 2016 and full year 2017, should prices exhibit fundamental stability above the current strip prices. In Permian EOR we continue to lower our drilling cost and manage the operations to run our gas processing facilities at full capacity. With resilient base production and low capital requirements, Permian EOR continues to generate free cash flow at low product prices. Drilling costs are running 25% below our benchmark target, and we've lowered our cash operating expenses by 21%, driven mainly by lower downhole maintenance and injectant costs. Phase 1 of CO2 injection at South Hobbs continues to perform well. Additionally, the initial implementation of the residual oil zone, or ROZ, projects are underway at South Hobbs and West Seminole. The ROZ development is a vertical expansion of the CO2 flooded interval. This activity is economic in a low price environment, because we typically utilize work over rigs to drill the extra depth into the CO2 floodable sections of the reservoir. The residual oil zone underlies most of our major EOR properties and can be developed between $3 and $7 a barrel. In summary, we're focusing our resources to achieve four core goals
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Jody. And, Emily, we'd now like to open up the call for Q&A.
Operator:
Thank you. Our first question is from Evan Calio of Morgan Stanley. Please go ahead
Evan Calio - Morgan Stanley & Co. LLC:
Hey, good morning. And congratulations, Vicki, on officially assuming the CEO role.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Thank you.
Evan Calio - Morgan Stanley & Co. LLC:
To start, Vicki, as new CEO, any general strategic thoughts on how you see Oxy's portfolio changing over time? Or through an ultimate upcycle? I know the portfolio was in the middle of a restructuring when the commodity market began falling apart. And should we expect that strategy reasserts in a recovery? Or what are your thoughts there?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Well, we've almost done all that we wanted to do with our portfolio optimization. The main thing that we wanted to do was to exit those areas that were not core for us, where we didn't really have a competitive advantage and therefore were going to have a really hard time truly adding value at the rate and the delivery that Permian Resources and the Permian EOR can give us. So we – the remaining area that we are now that's non-core that we will be continuing to reduce our exposure to will be in Bahrain. Libya, where we've stopped all investment there. So now we're down to the core areas of Abu Dhabi, Oman, and Qatar in the Middle East, Colombia in South America, the Permian in the U.S. along with South Texas. So we view the Permian, Colombia, and the three areas in the Middle East to still have opportunities for us to continue to grow. And we're going to try to restrict our activities to just those areas, because the one thing that we think will make us better and where we can continue to get better is to focus. And again to focus in areas where we have a competitive advantage. And we believe that we do in all those areas. So our growth opportunities in the future will be focused on just those areas, with a priority being given to the Permian Basin. Because of our size, our exposure there, we feel like that's where we get the most value for the dollars that we invest. So we would prioritize the Permian as a growth strategy.
Evan Calio - Morgan Stanley & Co. LLC:
Great. That makes sense. And I know the Permian delivered strong results in the quarter. I know on the last call you'd mentioned the Permian Resources, 20% in future growth. And maybe you can elaborate that, given the performance and your opening comments on where you'd add capital? And where that mix and where that rig count can optimally go in an upcycle? I know you're used four rigs here, which is under your 24 peak. And I mean you even had ambitions to go higher at that point. So just any thoughts on how that mix changes in your ultimate rig redeployment strategy?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Yeah. I'll talk first about the 20% that I mentioned. Really the 20% that I'd mentioned in terms of what we expect ultimately our Resources business to contribute to total production. That comment was driven by the fact that we were really excited about our EOR business, and the fact that our teams over the past year-and-a-half have been working on ways to expand our capacity there, so that we could actually accelerate some of our development. We have about 1.4 billion barrels of oil equivalent remaining reserves and potential in EOR. And we want to – at our current pace of development that would take about 22 years. So we really wanted to accelerate that. But when we looked at cases where we would need to build a new massive mega plant to do that, it really didn't add the value that met our hurdles. So what our teams have done now is they've actually found ways to expand our existing infrastructure for a much lower cost. So we're really excited about being able to over the next 3 years to 5 years start to accelerate EOR. And the good thing about that is our EOR business has just a 4% decline. So we think that combining it with the continued growth from our Resources should get us to a point where we can manage the overall base decline of the company to a point where we can better weather these down cycles that are always going to occur at points as we go forward. So right now we – what we would do in the short term, though, as we're waiting for our facilities expansion in EOR, is any improvements in oil prices to a level that's sufficient to enable us to be able to ramp up, that activity would go first to Resources. So for example, this year we have about $500 million committed capital that will come off next year. And so we expect next year that we would shift that $500 million, most of that, to Permian Resources to continue the growth that we had started there. In terms of rigs, it's hard to estimate what our rig count would be because our teams are continuing to improve their efficiencies, they're continuing to reduce the days required to drill per well. So we would look at it more from a targeted production sample. And then Jody and his team would have to figure out what number of rigs that would require. And based on the productivity of the wells and the improved efficiencies, I think they want to go through another couple of quarters to get an idea of how much better that's getting before they put any estimates together. But we're really encouraged by what we're seeing.
Evan Calio - Morgan Stanley & Co. LLC:
Great. Appreciate it. Thank you.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Thank you.
Operator:
Our next question is from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. And I'm assuming Steve is listening in somewhere, so we wish him well. And, Vicki, congratulations.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Thank you.
Doug Leggate - Bank of America Merrill Lynch:
I have a follow-up actually to Evan's question on CO2. And it goes back to an announcement at the beginning of the year that you had been awarded the Pinon Field in the West Texas Overthrust from SandRidge, and all the facilities went along with that. Well, I seem to recall that then essentially gives you a CO2 source. And I'm wondering how that fits into the CO2 strategy as it relates to potentially additional capacity? So I wonder if you could speak to that first? Then I have a follow up please.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Yeah. We – as you said we just got that. We haven't had it very long. But our teams are already starting to work there and to see potential there. When SandRidge was developing it, they were developing it more for the hydrocarbons. Our teams are looking more – at it more from a standpoint of looking for CO2. And they're – so they're seeing some opportunities for us to increase our delivery through Century Plant for CO2. So that's going to help us going forward. Now that for us is not something that we absolutely have to have to begin our acceleration. But it does help. And it could help to lower our cost. So that will play a part in our strategy.
Doug Leggate - Bank of America Merrill Lynch:
Perhaps a related question. Vicki, you continue to show this lovely bubble map with all your CO2 competitors. And of course there's been a lot of chatter about whether M&A could be a factor there. So any additional thoughts you could give us on how this – the acquisition opportunity to look in that part of the business? And I do have one final one, if I may please?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Okay. We – as I said Permian will be our highest priority in terms of looking for growth potential and for acquisitions of assets. As other companies are still in the process of streamlining their portfolios, we're hoping that there will be properties that come available, assets that they may decide that are no longer core to them. We're staying abreast of that. And we're actually – we are proactively talking to other companies, some not on the list that you see on the slide. Some are companies that may have just water flood opportunities that we can expand into for future CO2 development. But we're certainly interested in both EOR assets, as well as resources. But the problem with the resources assets currently is that the prices are still very high for those.
Doug Leggate - Bank of America Merrill Lynch:
Okay. Thank you. And my final one if I may. I think this might be for Chris. A couple of – a couple quarters ago you gave us a slide showing the cash burn in the non-core assets, the stuff that basically you're trying to exit. I think it was at $100 oil. I wonder if you could you share with us what that cash burn associated with those was at the – in the first quarter? And I'll leave it there. Thanks
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
It really wasn't much, Doug, because to some extent we – or to a large extent we really exited most of those areas. So the cash burn that we had seen was really for the most part over with. And through the fourth quarter there may have been a little bit in the way of working capital. If you want to call it sort of $100 million more or less, as we continue to look at exiting scenarios internationally. But by and large it's largely through. I'd point out too that the only thing left really in terms of the difference between what we've defined as sort of core – non-core or core and not the ongoing operations at this point is really the Bahrain assets or operations. So that's really it. And so I think we're most of the way through
Doug Leggate - Bank of America Merrill Lynch:
Chris, does that explain the DD&A drop on the Middle East as well?
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Well, that's part of it. And also the uplift or continued ramp at Al Hosn.
Doug Leggate - Bank of America Merrill Lynch:
Got it. Thanks, everybody.
Operator:
Our next question is from Philip Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Hey. Good morning.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Good morning.
Philip M. Gresh - JPMorgan Securities LLC:
The first question is just on the Permian Resources and just the overall volume outlook for the year. If I look at what you achieved in 1Q on the core piece, and then your guidance for 2Q, that's running – at the midpoint you're running at about 597,000 BOE per day. So it's already toward the upper end of the full year outlook. So just wondering maybe what moving pieces we should think about in the back half? And I guess in particular Permian Resources, how you might think about at the current prices what the exit rate would be there in the fourth quarter?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Again getting back to what I said earlier, we're seeing better productivity from our wells. And we're particularly excited about the New Mexico wells. So we're really reluctant at this point to give a forecast. And Jody and his team would like to have at least one more quarter to see how that development will progress to determine not only what we expect Q3 and Q4 to look like. But also whether or not he might add another rig. Jody? You might have some more comments on that?
Jody Elliott - President, Domestic Oil and Gas:
Yeah, Vicki. I think the other thing that we want to see is the effect of our base management programs. We're having some really good success there with pump maintenance, with surveillance activities, re-completions. And that's providing some uplift as well. So we want to see all those play out before kind of committing to the back half
Philip M. Gresh - JPMorgan Securities LLC:
Yeah. Sure. Okay. And I guess there was a comment in the slides about the development and resources focusing on fields with existing infrastructure. So I was just curious is there a point at which you think you might need to add some chunky infrastructure spend in resources that could come up against a constraint?
Jody Elliott - President, Domestic Oil and Gas:
At this point we've got a pretty good inventory in those areas with the infrastructure that meet a pretty low price hurdle. So we'll have some infrastructure, but not the really big stuff in the near term.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. My last question is just on Midstream. Obviously you highlighted the multiple elements of what's been hampering that business for the past few quarters. I guess if you look out in a more normalized world – I know I asked this of Steve a couple quarters ago – but I mean what do you think, Vicki, is the kind of true earnings power of this business in terms of just higher level or maybe the sub-component? So any color you could provide?
Vicki A. Hollub - President, Chief Executive Officer & Director:
I think it's in a normal world – and that would be one where we would expect to see production increasing in the Permian and NGL and gas prices recovering to some degree – we would expect to see in the neighborhood of $100 million to $200 million income at least from the Midstream business.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. Thanks.
Operator:
Our next question is from Ed Westlake of Credit Suisse. Please go ahead.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Yeah. I wanted to come back to the Bone Springs. I mean obviously you've got a big acreage position there. So the improvement there obviously has a big impact on your resource base. So maybe just a bit of additional color around whether this is a particular geological sweet spot? Or whether you think the results you've seen extend across a large portion of your acreage?
Jody Elliott - President, Domestic Oil and Gas:
Yeah. Thanks, Ed. I think we see this extending across a good portion of that acreage. It's not just in that Cedar Canyon area that we've showed some highlights on. We're really encouraged with New Mexico.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
And in terms of stack pay potential outside of the Bone Springs?
Jody Elliott - President, Domestic Oil and Gas:
Multiple benches. And again that's going to be a function of where you are. Some benches are better and some geographic areas. But at least two and in some cases upwards of four.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay. And then a different trajectory just on costs. Obviously costs are very low today. And that's helping everyone in the industry. As the industry starts to get back to work, costs may start to inflate. Any thoughts about trying to lock in some of these sort of lower margins for longer – very low cost structures, I should say.
Jody Elliott - President, Domestic Oil and Gas:
Yeah. Good question, Ed. Trying to predict the time where that supply/demand balance occurs is a little bit like trying to predict oil prices. Today there's a pretty good excessive capacity in the market. But having said that a significant portion of our improvements are due to things like design changes, technology improvements, utilizing some proprietary things such as Oxy Drilling Dynamics. We've invented some special stabilizers and drilling. Integrated planning, manufacturing mode, all those things are really driving the portion of – the big portion of our cost improvements. And those are sustainable. We've maintained our workforce. So when we ramp back up we won't have to access high cost consultants to run rigs and run frac cores. And we've recently made an alignment change with our supply chain organization, where they've been integrated into operations as part of our integrated planning teams. And so the result of that is we've got better alignment of our commercial and our technical strategies to the actual value drivers in each one of those programs. And that lets us drive productivity, utilization, logistics improvements. And that takes cost out of the system, not only for us but for our suppliers. And so in most cases price is important, but it's not the needle mover. So but we are in conversations with our strategic suppliers to determine ways we can better align our operations, drive out combined system costs, and focus on goals where we've got common success. And given our scale in the Permian, we're getting pretty considerable interest. So we continue to make immediate improvements to cash flow and cost. We're proactively taking actions to mitigate against inflation in a higher WTI environment. I mean at the end of the day we'll be ready
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
And then, sorry, small one. Just on the EURs in the Bone Springs, any update?
Jody Elliott - President, Domestic Oil and Gas:
Again we take a pretty measured approach to updating our EURs in our inventory. We want to see more production, better understand GOR modeling. And so with a little bit more time we'll update our EURs. But we are really encouraged by the results we're seeing with kind of generation two, generation three, not only frac designs but our modeling efforts. We would expect those to help across the board
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Thanks.
Operator:
Our next question is from Roger Read of Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Thank you. Good morning.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Good morning.
Roger D. Read - Wells Fargo Securities LLC:
Sorry, I did get pulled away briefly, so I apologize if this was asked. But as you think about increasing spending, increasing the rig count, what oil price and what magnitude should we think about in either of those categories?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Well, what I'd say about that is we really don't have a set price at which we would increase. We want to see some sustainable improvement with prices. And we want to make sure that the fundamentals support prices. I know a lot of people are saying that around $50 they would start to ramp up. We have a very deep inventory in both resources and the EOR business that would generate really good returns at $50. We're pretty committed to staying at the $3 billion capital range for this year. But Jody and his team in the Permian business are looking at opportunities to ramp up in those areas where they've already started development. And we're prepared to do it when prices do recover. But we would expect that to be maybe adding a rig toward the end of this year. And then ramping up at some point next year again, if prices look like they're going to be in a range that's sustainable.
Roger D. Read - Wells Fargo Securities LLC:
Okay. And kind of following up I think originally on Evan's question about the portfolio. And again I apologize. I did get pulled away. But the – you've done the disposition side. A few more things you might do. Acquisition wise, you've talked a lot here about opportunities in Southeast New Mexico and all that. Are there other areas you want to expand your footprint in within the Permian Basin?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Yeah. We're looking at all areas within the Permian Basin. We're – for Resources we would look in Delaware [Basin], Midland Basin, Central Basin Platform. We'd also look in some of those same areas, particularly Central Basin Platform and parts of the Midland Basin for EOR opportunities. So we're definitely looking around the Permian.
Roger D. Read - Wells Fargo Securities LLC:
And just a final follow-up on that. We've heard obviously prices in the Permian have stayed stronger than most other regions. Any movement? I mean does anything look more affordable today? Or as you think about maybe a more sustained $50 to $60 oil price environment, are there things that look more attractive than maybe they have over the last several quarters?
Vicki A. Hollub - President, Chief Executive Officer & Director:
Well, we look at the long view of things. So the issue has not been with us in terms of what we would be willing to go out and do from a pricing standpoint, because we – especially around EOR assets, those are assets that produce 50 years, 60 years, 70 years. So we're taking a long view on looking at acquisition opportunities with both EOR assets and Resources. The issue has been with some of the sellers who seem to believe that prices were going to really spike back up to $80, $90, $100. And it seems now that both the outlook for prices is starting to come closer together between the buyers and the sellers. But not quite on the Resources side, where we think it ought to be.
Roger D. Read - Wells Fargo Securities LLC:
Okay. Thanks. I guess we can all dream about $80 to $90 oil, even if we don't see it.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Right.
Roger D. Read - Wells Fargo Securities LLC:
Thanks.
Operator:
Our next question is from Guy Baber of Simmons. Please go ahead.
Guy A. Baber IV - Simmons & Company:
Thanks for taking my question. Vicki, Oxy has not made the head count reductions that many of your peers have made. Can you talk about that decision and the internal capability that you're maintaining? And then in your prepared comments you noted that the workforce is focused on initiatives that could have a step function improvement on your performance. Can you just elaborate on those comments? The value you can create and how you retain capability to respond when higher activity levels might be necessary? And does that differentiate Oxy from peers in your mind?
Vicki A. Hollub - President, Chief Executive Officer & Director:
I think that what we've done with our staff has definitely differentiated us from our competition. And I think it's a contrarian view to how one should manage through a cycle like this. What we've done is we made the commitment to our employees that we were going to keep our staffing level. We did have just a voluntary separation program at the beginning, where some of our later career people who had family issues and needs to go and to leave the company. We allowed some people to leave. But we were selective in terms of trying to make sure that we lost no capability internally. And so those people that did leave had in most cases done a great job of training and mentoring people to take their place. So what we've ended up with is a very capable workforce that has the skills and experience necessary in the mid-career to later career experiences. But also some early career people who have done just a phenomenal job of helping us through this down cycle. Because what we did is to try to ensure that we were reducing cost, we took some of our early career people, sent them to the field. They replaced contractors in both our production operations, our well servicing, and our drilling activities. And so they were replacing contractors who had been doing these jobs for a number of years, had a lot of experience. And our early career people went out there, learned it quickly. And because of the way they view things and their fresh approach to asking questions and looking at things differently, we expected them to go out there mostly to learn. But they actually went out there to learn, they added value, they improved logistics, and improved efficiencies. And not only was it a cost reduction from the elimination of contractors, but it was actually an improvement, because they did a fabulous job to improve efficiencies and to think about how to do things differently. Our field staff on the other hand, what they did is they got really aggressive and proactive with mentoring these early career people. And so the combination of both our experienced staff and our earlier career staff working together, they have really added value. And that's part of the reason that our efficiencies are improving. We're seeing these cost reductions in the field. We have to attribute that to both the early career and the mentors out in the field. In addition to that, what we're doing is we know that to be successful for the long haul with an industry that has changed now – and the industry that we're facing today has reservoirs that are tougher to develop, costlier. And really a world that's more complex than it used to be. So what we feel like is we've got to get to the absolute lowest possible cost structure to ensure that we have sufficient margins in a wider price range than what we've worked in in the past. And so to do that we feel like you can't do business as usual. You really have to take a different approach to how you're looking at cost structure reductions. And so we've got teams that are working on things that are further out. Some of which I can't talk about right now. But they're looking at how do we change the cost structure of 2018, 2019? What we have to do now to do that? And so they're working on the longer view. And these are some of the people that were deployed to these project groups from the drilling and completion operations since we had the major reduction in that activity. What we've found is by giving our staff more time to become more strategic and innovative, they're delivering value. So we not only have a commitment from our management to keep our staff, our staff has more than paid for that decision by their delivery and their performance. And they're continuing to exceed our expectations. Every time it seems that we set targets for them, they exceed it, because they're not – they recognize that we've made the commitment. So they've already also made the commitment. And they're just – they've been phenomenal. And our staff is very, very engaged. And I believe we'll come through this cycle with a much more committed, loyal, and highly skilled workforce that will be well prepared for any kind of ramp up that we'll see over the next couple years.
Guy A. Baber IV - Simmons & Company:
That's very helpful, Vicki. And then my follow-up is when we think about growth for Oxy, we obviously typically think about Permian Resources, now EOR over time. But do you have any update to share or any new thoughts around whether you're becoming more optimistic on the potential for growth opportunities around your core Middle East operations? And any update on over what timeframe those opportunities might materialize? And I'm thinking of potential opportunities in the UAE or elsewhere for example.
Vicki A. Hollub - President, Chief Executive Officer & Director:
Yeah. I would say while we very much value our operations in Oman and Qatar, we also – I've been very impressed with the UAE, especially the leadership in Abu Dhabi. And they're very progressive. And we enjoy doing business there. We've had success with a couple of companies there, Mubadala when we developed the Dolphin Project. And now ADNOC in the Al Hosn Project. We've seen that our team partners very well with both of those companies. And both of those projects were highly successful. Now I'm going to let Sandy talk about a project that we just entered into an agreement a year ago or so to look at some offshore fields there. This is also a project I'm really excited about. And before I hand it to Sandy to talk about that, I would say in Oman, Block 62, we've just brought on some gas production there, which also is another growth opportunity for us there. So we still believe there are opportunities to grow in the Middle East. I'll hand it over to Sandy.
Edward A. Lowe - President, Oil and Gas, International:
Thank you, Vicki. We are – we've entered into an agreement with ADNOC on the Hail and Ghasha fields. These are fields that have been producing oil for some time. And they have had the gas discoveries, some going back 40 years. So we've worked up an appraisal program for a number of fields. And there's been a few additional fields thrown in, called the Dalma fields to determine just what and when we should be developing. Make a recommendation to the state as to how they can both increase their available gas supply, but also further develop some of the hydrocarbons that have not yet been developed, other liquids included. We've just amended that agreement to add a partner of – the Austrian state oil company, who we've partnered with in many places. So there's a pretty robust team working appraisal and engineering development. One other area of more immediate growth is that we recently – Vicki went to the region to participate in the inauguration of the Al Hosn facilities. And it appears that we are well along the way to getting an agreement to expand the Al Hosn plant. Engineering is underway. And we're having further discussions later this month to determine just on what schedule and how we would do that. So those are the good areas of growth, both medium term and long term.
Guy A. Baber IV - Simmons & Company:
Thanks, Sandy. Very helpful.
Operator:
This concludes our question...
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Sandy, and – operator?
Operator:
This concludes our question-and-answer session today. I'd like to turn the conference back over to Chris Degner for any closing remarks.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Emily. I know everyone has a very busy day with earnings. And appreciate taking the time to join our conference call. Happy Cinco de Mayo.
Operator:
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Christopher M. Degner - Senior Director, Investor Relations Vicki A. Hollub - President, Chief Operating Officer & Director Christopher G. Stavros - Chief Financial Officer & Senior Vice President Jody Elliott - President, Domestic Oil and Gas Edward A. Lowe - President, Oil and Gas, International
Analysts:
Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Philip M. Gresh - JPMorgan Securities LLC Ryan Todd - Deutsche Bank Securities, Inc. Roger D. Read - Wells Fargo Securities LLC Paul Sankey - Wolfe Research LLC John P. Herrlin - SG Americas Securities LLC
Operator:
Good morning and welcome to the Occidental Petroleum Corporation Fourth Quarter 2015 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead, sir.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Carrie. Good morning everyone and thank you for participating in Occidental Petroleum's fourth quarter 2015 conference call. On the call with us today are Steve Chazen, Oxy's President and CEO; Vicki Hollub, President and Chief Operating Officer; Jody Elliott, President of Oxy Domestic Oil & Gas; Sandy Lowe, President of Oxy Oil & Gas International; and Chris Stavros, Chief Financial Officer. In just a moment I will turn the call over to Vicki Hollub. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our fourth quarter 2015 earnings press release, the Investor Relations supplemental schedules, our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Vicki Hollub. Vicki, please go ahead.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Thank you, Chris, and good afternoon everyone. Despite sharp declines in product prices, we had a strong year of production growth, particularly in Permian Resources. And we made big strides in lowering our cost structure as well as executing our strategic review. I'd like to share highlights of our 2015 achievements. First, Permian Resources growth exceeded our expectations as we reached our 2016 growth target of 120,000 BOE per day. This was a year ahead of our original plan. We increased production by 35,000 BOE per day for a year-over-year growth rate of 47%. Al Hosn reached full production capacity and delivered an average of 35,000 BOE per day of production last year. In total we grew our production by 81,000 BOE per day, which was approximately 14% higher than 2014. We reduced our cash operating cost by 14%, achieved SG&A sayings of 16% and cut our average drilling and completion costs in Permian Resources by 33%. As a part of our strategic review that we launched at the end of 2013, we sold our Williston Basin properties and made significant progress in our effort to exit non-core areas in the Middle East including Iraq and Yemen, while also reducing our exposure in Bahrain. This will lead to lower capital spending in the region. Construction of the OxyChem ethylene cracker joint venture is on schedule and on budget for start up in early 2017. We reached a settlement with the Republic of Ecuador for approximately $1 billion of which we've collected $300 million and expect to receive the remaining proceeds in the coming months. And we exited 2015 with $4.4 billion of cash on our balance sheet. Now I'd like to reiterate our strategy and cash flow priorities. I want to emphasize these have not changed. Our overall strategy is to invest in projects that generate long-term value, achieving returns well above our cost of capital while maintaining a conservative balance sheet. Our assets in Colombia, ISND in Qatar, Block 9 in Oman, Permian EOR, Dolphin and OxyChem provide significant earnings, require relatively low maintenance capital and provide free cash flow in this low price environment. Our most recent addition to this list is our Al Hosn gas project which is a 30 year joint venture with ADNOC in Abu Dhabi. And the role of our Permian Resources business, the role it will play in our strategy is to provide quick production growth as needed to support our cash flow. Our top priority for use of cash flow is and always will be the safety and maintenance of our operations. Our second priority will continue to be funding the dividend. Third is allocating capital to our growth projects. The next priority for any remaining cash would be for potential asset acquisitions and/or share repurchases as opportunities arise. Commodity businesses are inherently volatile. We maintain a strong balance sheet to not only survive but to take advantage of potential opportunities. We'll invest our capital prudently and maintain a flexible program as we maneuver through this low price cycle. As I mentioned earlier, we made great progress last year on lowering our operating and SG&A costs. We plan to further reduce these costs during 2016 and expect that the financial impact of executing on initiatives from our strategic review will be evident through lower costs in capital in the coming months. In terms of our capital program for this year, our plan is to carefully reduce our activity levels without harming the strong progress we've made with our growth prospects. We'll fund only those opportunities that exceed our rate of return hurdles. Our 2016 capital program is expected to range from $2.8 billion to $3 billion. This represents a nearly 50% reduction compared to the $5.6 billion spent during 2015. This capital plan should approximate our expected cash from operations at current commodity prices. The majority of this year's spending program will be allocated to the Permian Basin and to completing long-term projects in our chemicals and midstream businesses. Our capital run rate is expected to be higher during the first quarter and falling in subsequent quarters as committed project capital winds down. In Permian Resources, our drilling activity will be highly focused on areas in both the Midland and Delaware basins where we have existing infrastructure, allowing us to achieve higher returns. Our level of activity will help preserve efficiency gains achieved over the past year. In Permian EOR, we'll take advantage of reduced cost for labor and materials to modify and expand existing facilities to increase our capacity to handle and inject greater quantities of CO2. This will enable us to implement additional CO2 projects. These projects will have longer duration and a typical production response time of one to two years. This will result in a modest increase in capital for our EOR business versus last year. Chris will provide greater detail on this year's capital program in a few moments. Despite the reduction in capital spending, we expect overall company production from our core assets to grow 2% to 4% on average compared to 2015. Our core assets are pro forma for the expected divestments in areas we plan to exit, including the Piceance Basin, Iraq, Yemen and Libya along with lower exposure in Bahrain. The full year contribution of production from Al Hosn and the startup of Block 62 in Oman should add approximately 35,000 BOE per day of production this year. Overall, domestic production is anticipated to decline slightly through the year, primarily due to the declining natural gas and NGL volumes caused by the curtailment of drilling activity in our gas assets in late 2014. We expect a modest increase in production from Permian Resources versus last year and will hold our Permian EOR production flat. Turning to our oil and gas reserves, the good news is that we managed to keep our proved producing reserves essentially flat in 2015 due to our development programs and improved recovery from some of our Permian Resources wells. We continued to see strong performance from our Permian Resources drilling program, which enabled us to replace 214% of our Resources production, excluding net sales and revisions. Our development programs added 149 million BOE of proved reserves. Our year-end 2015 proved reserves totaled 2.2 billion BOE consisting of 79% proved developed reserves, up from 71% proved development reserves at the end of 2014. Our liquids reserves comprise 74% of our total proved reserve base. In summary, while the macro environment remains challenging for the industry, we delivered strong production growth during 2015. We lowered our cost structure and continued to execute on our strategic review. Although we expect commodity prices to gradually recover, we've set our plan to be more aligned with a lower price environment. We're fortunate to have a great set of assets with the relatively low base decline rates that provide us with enormous flexibility for our capital. We believe our continued focus on returns, improved cost structure and strong balance sheet provide us with the opportunity to emerge from the current cycle as a stronger company relative to our peers. I'll now turn the call to Chris Stavros for a review of our financial results and further details on this year's capital program.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Thanks, Vicki, and good morning everyone. As Vicki indicated, we continue to have three main objectives over the long term
Jody Elliott - President, Domestic Oil and Gas:
Thank you, Chris. Today I'll review 2015 highlights from Permian Resources and Permian EOR and provide guidance on our program for 2016. 2015 was a very successful year. Permian Resources achieved our 2016 growth target ahead of schedule by reaching 120,000 BOE per day in November. We achieved this milestone by leveraging our advancements in geoscience, reservoir characterization and integrated planning to deliver better wells in less than half the time and at two thirds of the costs versus 2014. Throughout 2015, we reduced our OpEx costs by over 20% by improving field reliability, productivity and optimizing our surface and subsurface engineering. Our Permian EOR segment generated free cash flow in a low price environment and had its best safety metrics of all time. Turning to Permian Resources, in the fourth quarter we achieved record production of 118,000 BOE per day, a 40% increase versus the prior year. Oil production increased to 76,000 barrels per day, a 2% increase from the previous quarter and a 49% increase from a year ago. Winter storms at the end of December impacted total quarter production by approximately 1,300 BOE per day. For the full year, the business achieved production of 110,000 BOE per day, a 47% increase versus the prior year. Permian Resources continues to drive down capital cost through improved execution and drilling and well completions and reduced time to market. For each of our core development areas, we continue to monitor both our early time well performance and cumulative production to ensure our development approach is providing maximum value. In addition to improving individual well performance, we optimized field development value through pace, well sequencing, flowback designs to reduce cleanouts and fluid handling costs, artificial lift designs to maximize long-term production, and facility plans to ensure maximum utilization over time. Our Delaware Basin well performance continues to be strong. We placed 19 horizontal wells on production in the Wolfcamp A benches in the fourth quarter. We continue to increase well performance by optimizing the density of our completions and proppant loads and drilling longer laterals. For example, the Priest E 1H well achieved a peak rate of 1,659 BOE per day and a 30-day rate of 1,247 BOE per day. The HB Morrison B 12H achieved a peak rate of 1,487 BOE per day and a 30-day rate of 1,176 BOE per day. In New Mexico, we're delivering more productive wells by increasing our proppant concentration and reducing cluster spacing. For example, the second Bone Spring Cedar Canyon 27 #6 produced at a peak rate of 2,498 BOE per day and a 30-day rate of 1,750 BOE per day at an 82% oil cut. In the Delaware Basin, our Wolfcamp A 4,500-foot well cost decreased by about 45% from the 2014 cost of $10.9 million to a current cost of $6.2 million. We reduced our drilling time by 26 days from the 2014 average of 43 days to 17 days. In our new area of the Midland Basin, we brought the Adams 4231 Wolfcamp A online in the fourth quarter at a peak rate of 2,167 BOE per day and a 30-day rate of 1,841 BOE per day. We also brought online the Merchant 1409A well at a peak rate of 1,345 BOE per day and a 30-day rate of 1,132 BOE per day. Both wells are producing at over 80% oil cut. In the Midland Basin, we made similar improvements in well costs and drilling days in the Wolfcamp A formation. We reduced these costs of the 7,500-foot horizontal wells by 35% from the 2014 cost of $9.2 million to a current cost of $6 million. We reduced our drilling days by 63% from 46 days in 2014 to 17 days in the fourth quarter of 2015. Across Permian Resources we're continuing to lower field operating expenses through optimized water handling, lower workover expenses and better downhole performance. Since the fourth quarter of 2014, we've reduced our operating cost per barrel by 26% and expect this trend to continue this year. In our Permian EOR segment we continue to lower our drilling costs and manage the operations to run our gas processing facilities at full capacity. With resilient base production and low capital requirements, the EOR business continues to generate free cash flow at low product prices. We've lowered our cash operating expenses by 21%, driven mainly by lower downhole maintenance and injectant costs. Phase 1 of CO2 injection at South Hobbs has continued and we have a production response sooner than expected. We expect Phase 1 production to peak in 2020. We expect Phase 1 and Phase 2 to develop 28 million BOE at just over $10 per BOE. Additionally, we've started a pilot project in South Hobbs testing the residual oil zone. It has the potential to add about 80 million barrels of reserves. These residual oil zone reserves can be added between $3 and $7 per barrel of development costs. Given the current oil price, we will focus investment to achieve four goals
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Jody. We'll now open it up for questions.
Operator:
We will now begin the question-and-answer session. Our first question comes from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Hey. Good morning, guys. My first question is, one of your key or primary peers, they cut their dividend today two thirds after repeated defenses. I know your balance sheet is superior yet the macro has changed that underpins their decision. Can you discuss how you perceive your dividend sustainability through this cycle, and are there leverage levels or other metrics that would result in a change in your current priorities?
Vicki A. Hollub - President, Chief Operating Officer & Director:
Yes, Evan, to begin I'd like to refer you to slide 23. What we've done really is planned our programs over the next few years to – based on actually the strip prices. Although we actually believe that prices ultimately will be higher than the strip, we don't expect prices to really recover much until very late this year or maybe early next year and recover only to slightly above the curve. But based on the cash that we have on hand and what we project our situation will be over the next few years, we do expect to be able to make it through this cycle and get back to reasonable oil prices and secure our dividend throughout this entire process. We're organizing our plans and our activities around that. And the good thing about our portfolio is we have the flexibility to ramp up and down as necessary to ensure that we meet our priorities. And as we said, the top priority is just the maintenance and safety of our operations and then we're going to pay the dividend and we've got the cash to do that. And generally, the way we look at it is we can use our cash flow from operations to cover our capital programs and part of our dividends over some of the years. And then what can't be covered by our cash flow from operations, we'll certainly use the strength of our balance sheet to cover that. So we don't see a threat to our dividend going through this cycle.
Evan Calio - Morgan Stanley & Co. LLC:
Thank you. I have a related follow-up. The irony of a downturn I think is opportunities, maybe the best when liquidity is the lowest. And so any commentary that you have on the asset market and whether your views of the macro raise the hurdle for acquisition or change your views on what's potentially attractive. Such for instance, say a more longer lived, longer cycle resource versus a shorter cycle shale resource?
Vicki A. Hollub - President, Chief Operating Officer & Director:
Yeah, I'd say that we never want to get away from what we truly are as a company and that's what I stated in here, is that we're very much a, on the oil and gas side of the business, an EOR type company and a company that looks for the longer life reserves like Al Hosn that provide cash flow. That would be like Al Hosn and Dolphin. So what we'll be looking at is are the assets that have the longer life reserves. We're very proud of our shale position and we think that the work we've done over the last few years has certainly proved it up to be an asset that we want to take full advantage of. But currently our shale production is less than 20% of our total company production. And we don't really want it to ever be much higher than that because we feel like to have the asset base we have, that's part of the reason we'll be able to make it through this cycle with our current low declines. So that's sort of asset we'll be looking for.
Evan Calio - Morgan Stanley & Co. LLC:
Appreciate it. Thank you.
Operator:
The next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks, good morning everybody. Good morning, Vicki.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Good morning.
Doug Leggate - Bank of America Merrill Lynch:
Vicki, I wonder if I could follow up on Evan a little bit there. I'm looking at slide 7 which is the kind of classic slide you put up about the priority for the use of cash. You've talked about optimism in a rebound in oil prices but you still have growth capital ranked higher than share buybacks and acquisitions. And I guess my question is, you've kind of missed an opportunity here with the separation of California Resources to reduce your dividend burden by buying in your stock which was the original plan. Obviously, extenuating circumstances, but in the event of a rebound in oil prices, why does growth capital still rank above reducing the dividend burden? And I've got a follow-up please.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Let me point out, I'm very happy that we did not buy back shares. The $6 billion is going to really be part of what helps get us through this cycle. And so I think we're fortunate to have the cash that we on the balance sheet now and that's really what's protecting, helping to protect the dividend. But I would view the last two items on the list, the share repurchases and acquisitions to be right now, although we show one above the other, those we view as equally important. And what we're going to look for is the opportunities that arise through this cycle. We're not going to immediately go out and buy, repurchase shares, but what we want to do is look at how the cycle evolves over the next quarters, maybe even next year and a half or so, and look for opportunities and before we commit to share repurchases. But I would view those as right now both on the same level of priority. And Chris, do you have anything to add?
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Yeah, Doug, I'll just follow up on what Vicki said. I think what she said is right. I think in addition to that, we're going to have to look at it on a return basis and clearly the goal over time will be to reduce the share count as it will help us fund the dividend and fund growth of the dividend over time. So I do still view, we still view share repurchases as important over time and a reduction of the share base over time. So we'll look at opportunities opportunistically to go ahead and do that. And it's just going to sort of depend on where things are, vis-a-vis the stock price and other opportunities that may come up for capital.
Doug Leggate - Bank of America Merrill Lynch:
Okay. I appreciate the answer, Chris. My follow-up is also referencing the slide deck on slide 41. You're showing the economics of your drilling backlog at different oil prices. I guess my question is that it would seem that a lot of companies are looking to drill their very, very best assets in the worst commodity environment. So I'm just curious as to why does that make sense if you're so optimistic on the recovery? Because obviously the offset, the alternative would be to allow production to decline but would also imply you're preserving value which I think one of your competitors talked about the other day and I'll leave it there. Thanks.
Vicki A. Hollub - President, Chief Operating Officer & Director:
I'll start that but then let Jody add onto it. We actually were fortunate to be in the process of some development programs in key areas where we were kind of into a manufacturing mode. We already have the infrastructure installed. And so that's what's making our current program so economical and what we feel like is the right thing to continue to develop during this cycle. And Jody can add to that.
Jody Elliott - President, Domestic Oil and Gas:
Yeah, building on Vicki's comment there, this is some of our best areas but we really are leveraging more than just the best rock. It's the infrastructure that we've already invested in. There's good rock in all of those tranches of inventory. It's just the maturity of our development plans in some of those areas aren't quite as far along, so we would not develop those until we get those development plans further matured. And that's one of the focus areas we had this year is to move more of that inventory to the left side of that chart.
Doug Leggate - Bank of America Merrill Lynch:
Okay. I appreciate the answer. Thanks.
Operator:
Our next question comes from Ed Westlake of Credit Suisse. Please go ahead.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Yes. Good morning. Just again a follow-on I think to your answer about the types of assets in shale. So from that I'm taking that you're more interested in some of the long-lived assets. Maybe give a little bit of color as to where you think these opportunities may lie.
Vicki A. Hollub - President, Chief Operating Officer & Director:
One of the things that we'd like to continue to consider is adding to our position in Permian EOR. We have the infrastructure there that really can't be duplicated by any other companies. We've got the 12 gas processing plants, 1,900 miles of pipeline and operate two CO2 source fields. So we have the infrastructure in place to continue expansion of our EOR operations in the Permian. And that would be for us one of our higher priorities. In addition, we see opportunities in Colombia to continue our work there. We this past year signed an agreement to develop another couple of water floods there. We think that's going be a good opportunity for us going forward. And in addition, in our three core areas in the Middle East, those are the kind of opportunities that we would continue to look for.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay, and then a totally separate question. At the back of the deck, you've got that great chart on – I should find the slide – on slide 41 that Doug mentioned about the inventory. Obviously there's a big flip between $50 and $60. And then if you look at the colors of the bars, you've got a lot of Bone Spring acreage, Spraberry and then the Wolfcamp B. Maybe just, and this is based on 4Q costs, hopefully those are the ones that you identified, that $6 million in the Wolfcamp and $6 million in East Midland. What are the biggest levers you think about taking that inventory that works at $60 down to $50?
Jody Elliott - President, Domestic Oil and Gas:
I think one of the biggest levers is multi-bench development, ensuring that the field development plans allow us to economically develop more than one good bench at a time. And so that's part of the redeployment effort of our technical staff to figure out multi-bench to drive better utilization of our infrastructure costs in those areas. That will be the biggest thing to move them to the left.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
I mean you mentioned reduced cluster spacing in some of those Bone Springs wells. I mean is there a lot more technology that you can still apply?
Jody Elliott - President, Domestic Oil and Gas:
I think there is.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay. Good to know. I'll keep in touch.
Operator:
Our next question comes from Phil Gresh of JPMorgan. Please go ahead.
Philip M. Gresh - JPMorgan Securities LLC:
Hey, good morning.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Good morning.
Philip M. Gresh - JPMorgan Securities LLC:
The first question is just on the guidance. There's obviously a lot of moving pieces here on the production side. But, Chris, just with respect to the 1Q, the 620,000 to 630,000, I believe you said that that would exclude the asset sales, the domestic asset sales, but it does not have anything contemplated in there for the Middle East asset exits. So I wanted to clarify that, and then just generally ask how that's going and how you would expect that 72,000 barrels a day of non-core Middle East to roll off as the year progresses.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Sure. Thanks Phil. On the guidance, just to make it comparable for you to reconcile it, I mean the way I would think about it is that you've got the Piceance in the US that we'll exit or it would be sold and close this quarter. So that will come out of the system. And then there is production in there for Bahrain as well. So combined, I would tell you that it probably amounts to about 50,000 to 60,000 BOE per day on a like-for-like basis, that to adjust for sort of our ongoing core production for the guidance that I gave for the full year of 2016. So that would be the reconciliation.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. And then just as you think about more broadly all of the Middle East assets, how do you see that progressing through this year?
Vicki A. Hollub - President, Chief Operating Officer & Director:
Currently we're continuing with our operations in Bahrain, and we are working with our partners there to lower our exposure. But in Iraq we're progressing with the terms of the exit according to our contract terms. So we should be winding down in Iraq and that's going to be transferred to one of the national oil companies. So we will be out of there by we're hoping mid-year. Yemen, that's pretty much our contracts have expired and we're reducing our exposure in the one area that we currently have and expect to be able to exit that by mid-year as well. So everything is progressing. In Libya we're not quite to the point where we have been able to develop a specific exit strategy and specific steps because of the uncertainties around that process with the government, but we have stopped our capital investment in Libya and we're only spending the funds necessary to maintain the operation safely.
Philip M. Gresh - JPMorgan Securities LLC:
Got it. Okay. And then, Chris, my follow up is just on the balance sheet, understanding the willingness to protect the dividend. Is there a level of debt, whether it's debt to cap or debt to EBITDA? Oxy's always been fairly conservative on the balance sheet and for good reason. Just wondering if there's a level where you get less comfortable.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Well whatever that level is, we don't plan to take it there. So that's one of the reasons that we maintain a strong balance sheet, that it allows us to pay the dividend and not be overly concerned about it. And I think our view is that we sort of take a measure of offense on this and sort of view ourselves as competitively advantaged as an investment vehicle within the sector. So you keep a strong balance sheet with low debt because you're a dividend payer and having a lot of debt as a company in this sector, just the two don't mix. So that's sort of how we view it.
Philip M. Gresh - JPMorgan Securities LLC:
Okay. Fair enough. Thanks.
Operator:
Our next question comes from Ryan Todd of Deutsche Bank. Please go ahead.
Ryan Todd - Deutsche Bank Securities, Inc.:
Thanks. Good morning. Maybe if I could follow up a little bit on the capital outlook over the next couple years. You highlight $500 million of committed capital in 2016 that will roll off by year-end 2016. Is there any offset to this that's set to ramp into 2017? Or should we expect, on an apples-to-apples budget, does the budget roll by $500 million into 2017? And would this likely be – would you likely fill that gap with accelerated activity in the US onshore?
Vicki A. Hollub - President, Chief Operating Officer & Director:
Really in 2017 our only committed capital is the $100 million, and so we do expect the $500 million to be reduced to $100 million. And the rest of our capital program will be based on what we see with respect to oil prices. But nothing committed other than the $100 million and the maintenance capital that we'll need to allocate.
Ryan Todd - Deutsche Bank Securities, Inc.:
Okay. And I guess maybe as one follow up to that, you're going to two to four rigs in the Permian you said for the second half of the year. Can you talk a little bit – and I guess at a high level you've provided us in the past with what you felt was kind of a maintenance CapEx number for yourself. Do you have an updated view on what your maintenance CapEx is generally as an overall business in terms of holding production flat, and maybe a similar number to what you think you need either from a rig or a spend level to keep Permian Resources flat?
Vicki A. Hollub - President, Chief Operating Officer & Director:
Permian Resources is a challenge because our teams keep improving so much there. The efficiency gains they've made over the last couple of years has just been incredible. And Jody and I were talking about that this morning, and the reason we gave the range of two to four is we used to think that it would take more than four rigs to offset our decline. But we're certainly convinced now that with the efficiency gains we're having and particularly the way that Jody and his team are starting to develop the fields, we think it could be less than that. Jody, I'll let you provide some additional color on that.
Jody Elliott - President, Domestic Oil and Gas:
No, that's clearly correct, Vicki. Every day our teams amaze us with new drilling records, new production records. So predicting that exact rig count to keep production flat kind of changes month to month.
Ryan Todd - Deutsche Bank Securities, Inc.:
But I guess is roughly the goal to size your activity levels from the middle of this year to kind of hold the Permian Resources flat? Is that roughly what you're trying to target?
Jody Elliott - President, Domestic Oil and Gas:
That level would probably – flat to slightly increasing.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great. Thank you.
Operator:
Our next question comes from Roger Read of Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Thank you. Good morning.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Good morning.
Roger D. Read - Wells Fargo Securities LLC:
Guess I'd like to probably go down the path some of the other guys have as well. On the thinking about the drilling efficiencies and following up on the answer to the last question, two to four rigs maybe allows you to stay flat. Is it a function of more above ground, below ground or a combination of the two that's driving this? And I'm thinking of the slide 33 where you show drilling days and best is still significantly better than average. And then the comments earlier about the – I think it was specifically the benches, being able to develop those as a way to get the cost down. What's the way we should think about it maybe for 2016 and then beyond 2016?
Jody Elliott - President, Domestic Oil and Gas:
It's really about all the things you mentioned. It's drilling performance. It's well completion performance. I think the biggest gains we've had this year is the integration of our subsurface understanding into that execution activity as well, keeping wells in zone, keeping them in the sweet spot, engineering frac designs differently, optimizing cluster spacing, optimizing sand concentrations. All those things I think lead us to being able to do more with less, not just drilling days and drilling cost.
Roger D. Read - Wells Fargo Securities LLC:
And then as you think out beyond this year, what do you think gives you the greatest upside potential? Not just the bench that you mentioned earlier, is there anything else we should think about?
Jody Elliott - President, Domestic Oil and Gas:
I mentioned multi-bench. I think that's one. I think the other is really optimizing infrastructure, both our internal infrastructure and working with others to take advantage of infrastructure in the two different basins.
Roger D. Read - Wells Fargo Securities LLC:
Okay, great. And just my follow-up, unrelated. Al Hosn, I was wondering if we can get a little more of an update on just how that's performing relative to your expectations. The turnaround coming in Q1, I assume, is a normal part of the startup process. And maybe how we should think about it latter part of this year on forward.
Edward A. Lowe - President, Oil and Gas, International:
Yeah, this is Sandy Lowe. We're in the warranty shutdown, which is common for all these projects. And we had produced over nameplate for several weeks before the shutdown. We expect the year to give us slightly over nameplate as an average, after the shutdown of course. And it's performing very well.
Roger D. Read - Wells Fargo Securities LLC:
Great. Thank you.
Operator:
Our next question comes from Paul Sankey of Wolfe Research. Please go ahead.
Paul Sankey - Wolfe Research LLC:
Hi. Good morning everybody. Again going back to the efficiencies, you said fairly clearly that it was reliability, productivity, optimization. Can you first try and strip out how much of the performance improvement has simply been lower oil prices and how much is organic, and sustainable? And secondly, could you highlight or contrast how you're differentiated from others in the Permian in any of those themes? Thanks a lot.
Jody Elliott - President, Domestic Oil and Gas:
I think the majority of that improvement is organic. We've gotten price improvements and we worked that part of the equation hard. But most of it is boots on the ground, engineering geoscience work, time to market improvement, integrated project planning, all those things internally which gives me high confidence that it's sustainable going forward.
Paul Sankey - Wolfe Research LLC:
Right. And you think it can continue as well, I think you've said. You've talked about returns that are relatively low, what seems to be a fairly low view of the oil price for the rest of the year and beyond, even. Can you talk about what you think the breakeven price is for you guys for your returns in the Permian? And I'm aware that you've got both EOR, which is presumably a different answer from the unconventional. And then could you – I'll stop going on – but could you then also talk about how you compare to other companies in your view? Thanks.
Vicki A. Hollub - President, Chief Operating Officer & Director:
First of all, Paul, I'd like to address the comparison to other companies. One of the things that we've been able to do in the Permian versus others is we've been there for a long, long time. So we've got a lot more data than other companies and we're doing more with that data. We have a lot of 3D seismic. We have, in addition to the 3D seismic, we have more than 20,000 wells from which we have data. So, and we have 4,400 outside operated wells. And I know you've heard all those numbers from me before, but we're really taking that data and taking it to the next level. We have a team that works with our resources team. And our resources team, I just have to say is incredibly efficient in what they've been able to do and to drive the drilling costs down, the completion optimization and all the things that Jody's talked about, they've done a great job. It's just been incredible. But in addition to that, the team supporting them from a downhole science standpoint is our exploitation team which takes all that data that we get from every well. And we utilize every bit of data we can, not only applying data analytics to it but taking a lot more data than the other people have access to. I think we still have the only horizontal core in the Permian. We're doing much more modeling around geomodeling and learning more about the thermal maturity and the migration of the hydrocarbons. So I think that's really helped here recently to make a big difference in the improvement of the resources wells.
Jody Elliott - President, Domestic Oil and Gas:
And I think to build on Vicki's comments, we recently held what we called a cost stand-down day where we took the entire company and stopped and said let's get creative. Let's get innovative on how we improve our business. We focused on SG&A. We focused on capital costs. We focused on operating expense. We focused on development opportunities and there's literally thousands of ideas that we have vetted and are currently vetting and that gives me even more confidence that we can move that hurdle breakeven lower for a number of these areas.
Paul Sankey - Wolfe Research LLC:
And what is the hurdle breakevens on a full cycle, make your returns appropriate for Oxy basis?
Vicki A. Hollub - President, Chief Operating Officer & Director:
The returns for the Permian EOR business, we have for Permian EOR a cash cost right now that's less than $20 and our DD&A is less than $10. We're continuing to drive that down. Expect that to go lower this year. So in our Permian EOR business, currently we can flex that around a bit by developing some of these ROZ developments which Jody mentioned in his presentation. Some of those developments get down as low as $3 on the F&D side. So we have a range of opportunities in the Permian EOR business that we can develop. Some of the ROZ developments that go down to an F&D of $3, those are fairly limited in size. So what we always try to do is blend the bigger projects that maybe have the $8 or $9 or $10 F&D with the smaller projects to get a blend of all of those. And on the Resources side, certainly our costs have been coming down there. The operating cost is down much lower than it was. The DD&A for our Resources business currently is higher because of the infrastructure that you always install up front. But the F&D costs, development costs on a per BOE basis is coming down. To tell you a number of where that's going to be, I think I'd hate to prematurely forecast something that I'm sure the teams are about to beat, but we're continuing to lower our costs in Resources.
Paul Sankey - Wolfe Research LLC:
Just to press, can you give me a range at least?
Vicki A. Hollub - President, Chief Operating Officer & Director:
On the Resources side?
Paul Sankey - Wolfe Research LLC:
Yeah, I mean it's just really interesting to everyone because obviously we see it as the marginal, arguably the marginal cost of oil.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Yeah the Resources side I would say that we're in the total cash cost range of about $13 to $14. And we're working when we get our full development costs in line, our DD&A on the Resources side will be in the $10 range.
Paul Sankey - Wolfe Research LLC:
Thank you very much.
Vicki A. Hollub - President, Chief Operating Officer & Director:
Thank you.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Basically you've got positive cash margins here at the strip for the Permian Resources and EOR for sure, Paul. I mean that's the way I would think about it.
Paul Sankey - Wolfe Research LLC:
Appreciate that. Thanks all of you.
Operator:
Our next question comes from John Herrlin of Société Générale. Please go ahead.
John P. Herrlin - SG Americas Securities LLC:
Yes. Thanks. Getting back to slide 41, will you make more of a push towards the Delaware given the relative economics of plays like the Bone Spring? And specifically for the sub $40 type inventory you highlighted, could you give me a better sense and maybe this is redundant, but could you give me a better sense of the split between the formation itself, the well design and also the infrastructure? Because obviously you're stressing the integrated nature of your approach, but certainly good rock matters. But I was wondering about how important your well design changes have been to lower that threshold?
Jody Elliott - President, Domestic Oil and Gas:
Yeah. John, that's a great question. We're really encouraged by the recent results with upsizing our fracs in the Bone Spring in New Mexico. But when you look at field development maturity and our infrastructure maturity, the Wolfbone has just got a jump start on that over on the Texas side. So early in the year, we'll be in the Wolfbone where we can take advantage of that infrastructure and as we get the field development plans matured in the Bone Spring area, incorporate more of the appraisal data that we've captured over this last year to ensure that we're as efficient as possible when we do put the rig back in New Mexico.
John P. Herrlin - SG Americas Securities LLC:
Okay. That's fine. Last one from me is you sold a lot of reserves during the year, about 600 million barrels. I was wondering if you could break them down geographically what you sold.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Yeah, the Bakken reserves were very small. I mean at the end of the day, I mean we didn't sell. These are sort of, I mean that we took down the PUDs basically in the domestic part of the business.
John P. Herrlin - SG Americas Securities LLC:
Okay. Thanks, Chris.
Operator:
And this concludes our question-and-answer session. We would like to turn the call back over to Chris Degner for any closing remarks.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you. And I'll turn the call over to Vicki for some closing remarks.
Vicki A. Hollub - President, Chief Operating Officer & Director:
I just wanted to say I don't think we fully answered Paul's question. So to get back to that, in the EOR business with our cash costs and our DD&A of around $24 to $25, and then the Resources business, our cash costs and DD&A in the neighborhood of $22 to $23. That's basically about half of the price we're seeing on the strip, as Chris had said. Generally that delivers for us of about a 50% rate of return. So I just wanted to close with that.
Christopher M. Degner - Senior Director, Investor Relations:
Okay. Thank you, Vicki, and thanks to everyone for participating on the call. Have a good day.
Operator:
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.
Executives:
Christopher M. Degner - Senior Director, Investor Relations Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas Christopher G. Stavros - Chief Financial Officer & Senior Vice President Stephen I. Chazen - President, Chief Executive Officer & Director Edward A. Lowe - Vice President and President, Oil and Gas International Production
Analysts:
Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc. Phil M. Gresh - JPMorgan Securities LLC Timothy A. Rezvan - CRT Capital Group LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Jason D. Gammel - Jefferies International Ltd. John P. Herrlin - SG Americas Securities LLC Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. Brian A. Singer - Goldman Sachs & Co. Guy Allen Baber - Simmons & Company International
Operator:
Good morning and welcome to the Occidental Petroleum Corporation Third Quarter 2015 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner. Please go ahead.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Emily. Good morning everyone, and thank you for participating in Occidental Petroleum's third quarter 2015 conference call. On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer; Vicki Hollub, Senior Executive Vice President of Occidental and President, Oxy Oil and Gas; Sandy Lowe, Executive Vice President and President of Oxy Oil and Gas International; and Chris Stavros, Chief Financial Officer. In just a moment I will turn the call over to Vicki Hollub. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our third quarter 2015 earnings press release, the investor relations supplemental schedules, our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Vicki Hollub. Vicki, please go ahead.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Thank you, Chris. Good morning everyone. Despite the current environmental of low and volatile product prices, our Oil and Gas segment has been operating well in all of our core assets. Our third quarter average daily production increased to 689,000 BOE per day from last year's 595,000 BOE per day, an increase of 16%. Our core assets continue to drive production growth with an increase of 39,000 BOE per day from Permian Resources and 50,000 BOE per day from Al Hosn, which reached full capacity in September. We expect Al Hosn to produce 60,000 BOE per day in the fourth quarter. Our capital and operating costs have continued to decline as we've focused our development program and curtailed activity where current product prices do not support further investment. We continue to make progress to optimize our portfolio as a part of the company's strategic review to focus on our core assets in the Permian Basin and the Middle East. We're selling our assets in the Williston Basin and continue to evaluate our positions in non-core assets in the Middle East with the objective of minimizing our activity and exposure. Construction of the ethylene cracker has progressed well and is on schedule to start up in early 2017. Our principal goal this year is to adjust our business to the current environment of low commodity prices. We're targeting our operating cash flow to cover our dividend and capital investment at realized oil prices of $60 per barrel while continuing to grow our production. We'll achieve this goal through deploying our capital and operating cost savings and to further production and cash flow growth driven mostly by our Permian Resources business unit and the start-up of Al Hosn. While we don't believe current price levels are sustainable over the long term, we've taken aggressive actions to manage the business for a downturn that may last longer than market participants expect. During the boom period from 2010 to 2014, the industry experienced substantial cost inflation. Royalties and government takes on new projects increased. Service prices, labor costs and overhead all increased as well. There's ample room for us to continue to lower our cost, which will enable us to return the business to profitability at lower prices. These adjustments may be difficult in the short term, but our discipline on reducing costs will lead to a healthier business over the long term. Through our separation of California Resources in 2014, we reduced our annual G&A budget from $1.8 billion to $1.5 billion as we moved the corporate headquarters to Houston. Over the course of this year and into 2016, we expect to see continued reductions in our corporate overhead with a more focused company and will reduce our total G&A spending to about $1.2 billion in 2016. Two years ago we began working on strategic initiatives to focus our company and improve its profitability. We've continued to make progress on those initiatives. We reached an agreement to divest our Williston Basin assets and expect the transaction to close in the fourth quarter. Due to our curtailed spending in the basin and the nature of unconventional assets, our production declined about 25% quarter over quarter when annualized. We expected the production to continue to decline given our limited capital investments in the basin. Over the past several years, our efforts at appraising and delineating our acreage in the Permian have provided a large inventory of future development locations that are economic at oil prices under $60 a barrel. With ample takeaway capacity and an extensive midstream business of gathering lines, storage and gas processing, our economies of scale and deep inventory in the Permian Basin make it our top priority for capital allocation for the foreseeable future. Simply put, acreage in North Dakota, whether it's tier one, tier two or tier three cannot compete with our position in the Permian. We continue to pursue strategies to minimize our activities and exposure in our non-core operations in the Middle East and North Africa, which include Bahrain, Iraq, Libya and Yemen. As a result of these actions, we took impairment charges in the third quarter for our positions in Iraq and Libya. We will comply with our contract terms as we reduced our exposure through negotiations with our partners and host governments and expect capital investments to decline in 2016. These actions will improve the profitability and cash flow of our Middle East business as we focus on our core assets in Abu Dhabi, Qatar and Oman. Our capital spending in the third quarter declined by about $300 million and will continue to decline. As we capture price savings from suppliers and improve the efficiency of our operations, we're able to do more with less spending. We expect to exit this year at a quarterly spending rate of $1.1 billion to $1.2 billion. If product prices remain at current levels, our 2016 capital program will be less than the current rate. We're in the midst of our annual budgeting process and we'll provide more detailed guidance on our 2016 program in January. Over the last few years, we've undertaken multiple long-term investments to drive cash flow and earnings growth. These projects include the Al Hosn gas project, the ethylene cracker joint venture, our export facilities in Ingleside and gas processing infrastructure in the Permian Basin. Capital spending on these investments declined by about $500 million in 2015. We expect these investments to decline by about $300 million in 2016 and $400 million in 2017 as the projects are completed. This decline in capital spending on committed projects gives us a lot of flexibility in setting our capital budget for 2016. Our Permian business continues to execute a focused development program on low cost wells with high oil content. Permian Resources continues to drive down capital cost through improved execution in drilling and well completions. Our production exceeded expectations due to reduced time to market and better than planned well performance. In the third quarter, Permian Resources achieved daily production of 116,000 BOE per day, a 6% increase from the second quarter and a 51% increase versus the prior year. Oil production increased to 74,000 barrels per day, a 4% increase from the previous quarter and a 72% increase from a year ago. In the fourth quarter we'll drill and complete about 50 horizontal wells. We're currently operating 12 rigs in the basin and evaluating our needs for our 2016 program. In the Delaware Basin, our Wolfcamp A 4,500 foot well costs decreased by about 45% from the 2014 cost of $10.9 million to a current cost of $6.3 million. We reduced our drilling time by 24 days from the 2014 average of 43 days to 19 days. We've lowered our completion cost per well and optimized the density of our clusters and proppant loads. We've used some of our cost savings to up-size our frac treatments to drive higher productivity. Our well performance continues to be strong. We placed 21 wells, horizontal wells, on production in the Wolfcamp A benches in the third quarter. The Leigh State 40-11H well achieved a peak rate of 1,790 BOE per day and a 30 day rate of 1,528 BOE per day. Additionally, our Betty Lou 1013H well achieved a peak rate of 1,711 BOE per day and a 30 day rate of 1,310 BOE per day. We drilled the Betty Lou horizontal well in only 15 days. Most of these wells produce around 80% oil. In the Midland Basin, we've made similar improvements in well cost and drilling days in our Wolfcamp A wells. We reduced the cost of these 7,500 foot horizontal wells by 30% from the 2014 cost of $9.2 million to a current cost of $6.6 million. We reduced our drilling days by more than 60% from 46 days in 2014 to 18 in the third quarter. In Big Spring, which is our new area of the Midland Basin, we brought the Young A 2124 well online in the third quarter at a peak rate of 1,611 BOE per day and 30 day rate at 1,237 BOE per day. We also brought online the Adams 4201 well at a peak rate of 1,698 BOE per day and 30 day rate of 1,495 BOE per day. Both wells are producing at about 90% oil. These Wolfcamp A well results have been outperforming our initial type curves for this emerging play in Howard County. We're continuing to lower our cost structure. Since the fourth quarter of 2014, we've reduced our operating cost per barrel by 18% and expect to make further progress in lowering our costs through the end of this year and into 2016. In our Permian EOR business, we continue to lower our drilling cost and manage the operations to run our gas processing facilities at full capacity. With a resilient base production and low capital requirements, the Permian EOR business continues to generate free cash flow at low product prices. In the third quarter we started Phase 1 of the CO2 injection at South Hobbs, where we expect to develop low cost oil production at about $10.60 per BOE. In closing, we delivered strong production growth from our core assets in the third quarter. We continued to execute on our strategic initiatives to focus our oil and gas business around our core assets in the Permian Basin and the Middle East. We'll continue to execute a focused development strategy in 2015, and we'll pursue additional step changes in well productivity and cost structure. Strong production growth from our Permian Resources business along with a high volume, a low capital intensive Permian EOR business keeps us well positioned to not only meet the challenges of this lower price environment but also to profitably grow our combined Permian businesses. Now I'll turn the call over to Chris Stavros.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Thanks, Vicki, and good morning everyone. Today I'll cover our third quarter results, discuss the actions we have taken that led to the non-core charges we took in the quarter, and close by providing some guidance on the remainder of the year while highlighting key initiatives that will improve the company's financial strength going forward. We generated core income of $24 million for the third quarter of 2015, resulting in diluted earnings per share of $0.03, a decrease from $0.21 a share in the second quarter of 2015 and compares to earnings of $1.34 per share in the third quarter of last year. Our net GAAP reported results for the third quarter were a loss of $2.6 billion or $3.42 per diluted share. Our third quarter reported results includes non-cash after-tax net charges of approximately $2.6 billion. Our quarterly core results were negatively impacted by lower worldwide oil and NGL prices, which fell by nearly $7 and $3.50 a barrel respectively in the third quarter of 2015 compared to the second quarter of this year. US natural gas prices improved slightly, up about $0.15 per Mcf from the second quarter. Our third quarter capital spending was about $1.2 billion, down 18% from the $1.5 billion in the second quarter and down 30% from first quarter levels. We continued to ramp down our capital program, focusing our development activity primarily in core areas of the Permian Basin, with the intent of curtailing or eliminating spending which is less competitive and imprudent in the current product price environment. Our heightened focus around capital spending is centered on growing our oil production volumes and more importantly our operating cash flow. Despite the reduction in this year's capital program, efficiency gains and our increased focus around our inventory of drilling opportunities continues to drive growth in oil volumes and cash flow at our Permian Resources operations. Permian Resources grew its oil production 72% in the third quarter, adding 31,000 barrels per day compared to the year-ago period with total production of 116,000 BOE per day, representing growth of 51%. Production from Permian Resources improved by 7,000 BOE per day sequentially, above our previous guidance. As I mentioned earlier, we took after-tax impairment and other non-cash charges of approximately $2.6 billion in the third quarter. Oxy follows the successful efforts method of accounting where we review our proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of the oil and gas properties may not be adequately recovered, such as when there's a significant drop in the futures price curve. As of September 30, the futures curve for product prices had declined sharply yet again and we recorded an after-tax impairment of $1.3 billion related to our domestic gas properties and our oil and gas assets in Libya. As Vicki mentioned, we continued to make progress in our efforts to optimize our portfolio. In the third quarter of 2015, we entered into an agreement to sell our Williston operations, which have been classified as held for sale and resulted in an after-tax impairment charge of approximately $500 million. The sale is expected to close later this quarter, and we expect to receive net proceeds equivalent to approximately eight times free cash flow after acquired capital for facilities and safety. Additionally, and as part of our effort to focus our capital on opportunities that generate higher financial returns, we intend to minimize our capital allocated to non-core areas. As a result, we recorded an after-tax non-cash charge of $760 million for operations in Iraq. We expect to continue oil liftings out of the country in the fourth quarter. Our exit from these non-core areas will create a more focused domestic oil and gas organization and mitigate our exposure to areas we deem as having higher political risk. In addition, we expect our capital spending levels to decline and our financial returns to improve as we generate savings from associated overhead reductions that have yet to be captured. As slide 21 shows, for the first nine months of 2015, our operations in combined Williston, Iraq and Libya had total production of 45,000 BOE per day and generated an aggregate cash flow after capital deficit of approximately $260 million with Brent oil prices of about $56 a barrel. For the full year of 2014, when Brent prices averaged about $100 a barrel, these assets had an even greater cash flow after capital deficit of $340 million. Some of this free cash flow savings could be redirected to our higher return core operations in the Permian Basin. Turning to specific business segments. Oil and Gas after tax earnings for the third quarter 2015 were $17 million, about $90 million lower than the second quarter of 2015 and $880 million lower than last year's third quarter. Almost all of the impact of the change in year-over-year earnings is due to lower product prices. For the third quarter, total company oil and gas production volumes averaged 689,000 BOE per day, an increase of 31,000 BOE in daily production from the second quarter and 94,000 BOE per day from last year's third quarter. Total company oil volumes were 436,000 barrels per day in the third quarter, 54,000 barrels per day higher than the year-ago period for an increase of 14%. Total domestic oil and gas production averaged 332,000 BOE per day during the third quarter of 2015, about flat sequentially and 17,000 BOE higher on a year-over-year basis with all of the increase coming from Permian Resources. The increase from Permian Resources was partially offset by lower production from our Midcontinent natural gas assets where we have ceased drilling activity. Domestic oil production was 204,000 barrels per day during the third quarter of 2015, about flat with the second quarter and up 22,000 barrels per day or 12% from the year-ago period. We captured approximately 4,000 BOE per day of incremental NGLs and natural gas volumes in the third quarter due to the installation of compressors and gathering lines in the Delaware Basin. International oil and gas production volumes averaged 357,000 BOE per day during the third quarter, up 32,000 BOE per day sequentially, and 77,000 BOE per day on a year-over-year basis. Production from Al Hosn was 50,000 BOE per day in the third quarter, an increase of 32,000 BOE per day from the second quarter, and about 15,000 BOE per day above our guidance for the period. Al Hosn is currently running at full capacity, which is approximately 60,000 BOE per day. Our third quarter oil and gas cash operating costs of $11.15 per BOE declined 8% from the second quarter level of $12.10 per BOE due to higher production volumes, lower surface and downhole maintenance costs and lower energy costs. DD&A for the third quarter was $15.39 per BOE compared to $16.06 per BOE during the second quarter. Taxes other than on income which are directly related to product prices were $1.20 per BOE for the third quarter compared to $1.85 for the second quarter and $2.45 per BOE for the full year of 2014. Chemicals generated pre-tax core earnings of $174 million in the third quarter of 2015 versus $136 million in the second quarter and $140 million during the year ago period. The most recent quarter results were above our previous guidance and benefited from higher chlorovinyl production volumes, lower ethylene costs partially offset by lower vinyl sales prices. Midstream pre-tax core earnings were $31 million in the third quarter compared to $84 million in the second quarter of 2015 and $115 million for last year's third quarter. The most recent quarter results reflected lower marketing margins due to the narrowing of Midland and Gulf Coast differentials, and an increase in crude oil supply lowered premiums in the Gulf Coast. The lower marketing margins were partially offset by higher pipeline income from both domestic and foreign pipelines, and higher seasonal margins from power generation operations. Turning to our cash flow. Operating cash flow for the third quarter of 2015 was approximately $1 billion which was about $200 million higher than the second quarter. Higher oil and gas production volumes combined with better realized oil prices relative to benchmark prices positively impacted our operating cash flows during the third quarter. Working capital changes were minor during the third quarter as our drilling activity and capital spending stabilized from higher levels at the end of last year. We continued to ramp down our capital spending, with total company expenditures for the third quarter of 2015 of $1.2 billion, a sequential decline of $300 million from the second quarter. Total company capital expenditures for the first nine months of 2015 were $4.4 billion, which is running a little lower than our full year 2015 capital budget of $5.8 billion. Oil and Gas spent $3.6 billion during the first nine months of 2015 with Permian Resources expenditures comprising roughly half of the total Oil and Gas outlays, and the remaining $800 million of capital split nearly evenly between Chemicals and Midstream. We paid cash dividends of $1.7 billion during the first nine months of 2015. Continued growth in our operating cash flow combined with capital reductions and other cash cost savings should allow us to achieve our goal of being cash flow neutral after capital spending and dividends at oil prices of roughly $60 a barrel. Our cash balance at the end of third quarter was $4.3 billion and our long-term debt to capitalization ratio was 19% the end of the period. The worldwide effective tax rate on our core income was 90% for the third quarter of 2015. Beyond the efficiency improvements that have lowered our capital spending, we have also started to recognize the benefit of a reduction in our SG&A costs. Reducing our SG&A is an initiative we began working on ahead of the spinoff of our California assets and operations. Prior to the spin, our SG&A was at approximately $1.8 billion per year. Upon completion of the spinoff late last year, we had reduced our SG&A costs by about $300 million or roughly 17%. While our work force has come together and made a huge effort to reduce costs, we are still in the early stages of recognizing these benefits. During 2015 we expect to reduce our SG&A by another 10%, or roughly $150 million. We have taken a number of actions and will continue to pursue other initiatives that will serve to reduce our SG&A costs both this year and next, and is highlighted on Slide 30. We expect these initiatives to reduce our SG&A by at least another 10% and expect our total SG&A costs to decline to roughly $1.2 billion in 2016. This represents a one-third reduction in our total SG&A costs compared to levels before the California spin. Looking ahead to the fourth quarter, domestically we expect production from Permian Resources to be about 118,000 BOE per day. Production has been a bit lumpier as we have increasingly moved to pad drilling and we expect total Permian Resources production to exit the year in excess of 120,000 BOE per day. Continued growth in the Permian combined with declines in our Midcontinent natural gas production and adjusting for the sale of the Williston assets should result in total US production between 310,000 BOE per day and 320,000 BOE per day. We expect our international production to be between 365,000 BOE per day and 375,000 BOE per day, depending on volumes from Iraq, and assume 60,000 BOE per day of production from Al Hosn. Price changes at current global prices affect our quarterly earnings before income taxes by $30 million per $1 per barrel change in oil prices, and $7 million for a $1 per barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pre-tax earnings by about $15 million. Our fourth quarter 2015 exploration expense is anticipated to be about $20 million pre-tax. We expect our fourth quarter 2015 pre-tax Chemical earnings to be about $130 million. Our third quarter Midstream earnings will continue to be principally impacted by Midland to Gulf Coast oil price differentials which have narrowed since the third quarter, as well as weak NGL prices. We expect net cash proceeds from asset sales in the fourth quarter, which includes our assets in the Williston Basin, to be approximately $650 million. The worldwide effective tax rate on our core income was 90% for the third quarter of 2015. This rate reflects the mix of domestic source book losses and foreign-sourced income which is taxed at much higher relative rates. Simply put, you cannot utilize US tax losses to offset higher foreign taxes. Based on continued volatility in the mix of pre-tax income sources, we expect our full year 2015 domestic tax rate to be 36% and our international tax rates to remain at about 65%. To summarize, as we wind down the year, we remain financially strong and well positioned to weather the current low product price environment with $4.3 billion of cash on hand, roughly equal to our annualized capital outlays. We continue to grow our production volumes cost efficiently, and despite the decline in capital spending. We will continue our disciplined approach towards cost control, improving our capital efficiency, focusing and allocating our capital on only the highest return opportunities. Our capital spending run rate has been cut by more than half compared to year-ago levels and we expect to save at least $300 million as a result of initiatives to lower SG&A costs. I'll now hand the call back over to Chris Degner.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Chris. And Emily, could you please open up the line for questions?
Operator:
Thank you. Our first question is from Evan Calio of Morgan Stanley please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Hey, good morning guys. Your Permian Resources production again beat guidance. You're making progress on costs, efficiencies and you highlighted it as your top priority in your slides, but it's also one of the pieces your of portfolio where you can dial activity up and down. Can you talk about how you balance those factors when you're considering your 2016 Permian activity levels in the current environment?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Yes, Evan. As Chris said that our committed capital is coming down but we still do have some committed capital in 2016. So what we'll do is balance our Permian Resources business with the capital requirements elsewhere. As you know, we're trying to reduce our capital requirements in the Middle East and the reason for that is we would prefer to divert – to move capital to Permian Resources. But we do have the ability to swing it up and down. We're working on several scenarios that we could be ready to implement depending on what market prices are in 2016.
Evan Calio - Morgan Stanley & Co. LLC:
Let me follow up there. I mean, when you mention the potential in MENA (27:29) non-core asset sales, does that imply that the larger interest sell down remains back burnered? And on your G&A guidance, does that – that these announced assets are sold as well?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
You're talking about the Middle East?
Evan Calio - Morgan Stanley & Co. LLC:
Yeah, in the MENA. Sorry.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Currently we're looking at certainly exiting some of the non-core properties in the Middle East and ramping down activities in some of those areas that we're not going to exit. So that will certainly impact some of our SG&A cost. We expect those to go down as well as some of our operating cost. So that will be a benefit to us. And getting back to the resources question that you had previously, we do expect to, in all of the scenarios that we're looking at, to continue to grow production from our Permian Resources business.
Evan Calio - Morgan Stanley & Co. LLC:
Right.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Now on the G&A question, this is Steve. The answer to your question is no. We really haven't baked in the Middle East situation with the decline. So basically what we see now is – this is what we've said for next year's run rate are costs. We expect to continue to work on this as the portfolio changes.
Evan Calio - Morgan Stanley & Co. LLC:
Right. And the non-core – but by focusing on the non-core sales in MENA, I guess I'm saying does that also imply that the larger interest sell-down in that piece of the portfolio remains back burnered given the current environment. Is that fair?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Well, the countries have gone from being flush with cash to being cash users just to fund their own situation. So it's not likely that they're in the mood to – basically they're selling things. They're not buying things right now.
Evan Calio - Morgan Stanley & Co. LLC:
Right. And maybe if I could ask one more question, Steve. Can you discuss what drove the Bakken asset sales given your ample liquidity position? I mean, is there a general comment there on your view of prices in the asset market that you see better opportunities to sell versus buy where you've highlighted that you'd potentially be a buyer in the Permian?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, we sold the Bakken assets for about $600 million as opposed to the reported number, which I don't know where that came from. Anyway, we sold for about $600 million. We just can't see a situation where we would invest in it given what we have in the Permian. And so I mean, it's really a statement that says okay, we just don't see how it competes for capital inside the company in any reasonable price scenario that we can come up with. Generally it's always generated negative cash flow or at best neutral. It's declining about 1,000 barrels a day a quarter. So a year from now, it would be 13,000 or so a day just doing the arithmetic. So we don't see how the value increases over time. For us, this $600 million, we could run four rigs in the Permian basin for a year with this money or five, somewhere in that range and generate more production than we would get out of the Bakken with the $600 million. So pretty easy decision. Say well, you could hold on until it goes up in price. By the time it goes up in price you might be making 8,000 barrels a day. So I just don't know when it's going to go up. We believe we received a fair price given the prospects for it under our management.
Evan Calio - Morgan Stanley & Co. LLC:
Great. I'll leave it for somebody else. Thanks.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thanks.
Operator:
Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.:
Thanks. Good morning everybody. On the Middle East folks, the non-core areas that you're talking about, I'm trying to reconcile the $60 breakeven number with exiting some of these non-core areas. And I guess my question is, are these areas currently negative free cash flow, and if so, could you quantify what you think the delta would be in the event of an exit and if that's already assumed in your $60 breakeven assumption?
Stephen I. Chazen - President, Chief Executive Officer & Director:
$60 is just a cartoon. This is basically based on our current situation. The businesses are not cash flow positive.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Doug, we showed you on the slide that I pointed out, slide 21, that under various oil price scenarios, a higher oil price scenario of last year or lower prices this year, we're still running the combination of those assets are still running a sizable cash deficit after capital. So yeah, you were sort of at higher capital in a higher price environment, but still you weren't generating enough money to really see a free cash flow positive event.
Stephen I. Chazen - President, Chief Executive Officer & Director:
So we haven't gone back and recomputed what exactly the breakeven would be. So we don't really know whether it's $55 or $60.
Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.:
Okay. So maybe I could just slip in a macro question there. Could you update us on what you're doing in Iraq currently? Because obviously your partner, our understanding is the Iraqis are asking folks to slow down investment. So what are you actually seeing on your asset? And I've got a more Oxy-specific follow-up please.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Sandy can answer that I think.
Edward A. Lowe - Vice President and President, Oil and Gas International Production:
The Iraqis have asked us to slow down investment. And the infrastructure investment that we need to really take advantage of these fields that is the responsibility of the government has not taken place. So the production is just trucking along at a fairly stable amount. But not anything that would excite us.
Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.:
Okay. Thanks. And my final one if I may is, again I want to go back to this $60 breakeven, Steve, because if you look at this current quarter, obviously you're still burning through a fair amount of cash, and the oil price clearly is not $60. It's substantially below that. Although that's not our base case, what would you do in the event that you have another year of sub-$50 oil because that would imply you basically burn through all your cash at this rate?
Stephen I. Chazen - President, Chief Executive Officer & Director:
I don't think we'd burn through all the cash. Maybe we have a different model. But anyway, if you run through all the numbers, I think we'd look at it at the time. But as we cut back on the non-core assets, more cash will be generated. And so you could drill fewer wells in the Permian if that were necessary. We're not counting on -
Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.:
You'd basically slow things down. Right.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, we would bring the capital down lower. There's more savings as we go and so we're not exactly sure where we are in this process. So I think as we go through this next year, the large, the cracker basically ends at the end of this next year. The spending on that ends. Some of the stuff in the midstream ends at the end of next year. Al Hosn will be, all the capital will be spent. There's a little bit of capital in the beginning of the year for crew quarters as I recall. And so when now all that ends, the capital will naturally decline and the production goes up. So whether it's $60 or $55, we don't really know right now. But we would expect as we go into 2017 clearly that the capital program would be significantly less than – could be significantly less than next year even.
Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.:
Got it. I'll let someone else jump on. Thanks, everybody.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thank you.
Operator:
Our next question is from Phil Gresh of JPMorgan. Please go ahead.
Phil M. Gresh - JPMorgan Securities LLC:
Yeah, hey. Good morning. Just first question just on the CapEx side. How would you think about what sustaining capital requirements there are today given all the productivity that you've been seeing in the Permian? And how did that relate to the $60 breakeven for dividend coverage as you move forward? I would assume that that's generally underlying your seeing some improvement there, but any color you could provide would be helpful.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Yeah, Phil, we're continuing to see improvements in the Permian Resources business. And as we've just said and said previously, our Resources businesses are swing business with respect to capital, we can, we have the ability to ramp up and ramp down. But we do see a scenario if oil prices improve a little bit for us to be able to continue to grow Resources and to manage some of the capital spend and in international down so that we could be cash flow neutral and grow Resources slightly in 2016. And part of that's due to the fact that we're continuing to see improvements in our drilling and completion operations. And if you look at kind of the targets that, if you go back and look at our Q1 targets for our drilling and completion activity in Permian Resources, we've actually adjusted our targets a couple of times because our teams keep outperforming and beating our previous targets and setting new best rates. So currently two of the things that we're dealing with in terms of uncertainties is how much better can we get, and also what will prices be. So we're running both of those scenarios and we think we have opportunity to continue to improve.
Phil M. Gresh - JPMorgan Securities LLC:
Okay. Follow-up question just on the midstream business. In this lower for longer type of environment, how would you think about the earnings power of that business? I know it's volatile quarter to quarter, but if you think maybe on an annualized basis and you obviously have a couple of different sub-businesses within that. But any thoughts you have there would be helpful.
Stephen I. Chazen - President, Chief Executive Officer & Director:
It's a difficult business to estimate. It's hodgepodge of different businesses. It's got a power business. It's got a standard transmission business. It also holds the capacity to ship oil out of the Permian. And right now there's more excess capacity in the basin to ship oil because people assume that oil would, the production would go up and it's clearly not for the industry. So we're paying demand charges essentially for that. And that's what's eating into the profitability. So it's really a difficult number to quantify because you have to really have an idea about these demand charges and what's going to happen with that. It has a probably underlying earning power in the $300 million or so area. But there's a lot of volatility on these demand charges.
Phil M. Gresh - JPMorgan Securities LLC:
Sure. And is that $300 million including the benefits we'll get from sulfur at Al Hosn?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Probably not. Probably not going to include it.
Phil M. Gresh - JPMorgan Securities LLC:
Okay. Last question though for me.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Sulfur at Al Hosn is also, is makes predicting oil prices easy. I mean the price of sulfur can move $50 a ton overnight.
Phil M. Gresh - JPMorgan Securities LLC:
Sure. Understood. Last question.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Especially if there's a lot of tons.
Phil M. Gresh - JPMorgan Securities LLC:
On the Middle East you had a significant reduction in the cash operating costs in the third quarter. Any color on the big drivers and the sustainability of that?
Edward A. Lowe - Vice President and President, Oil and Gas International Production:
We've had a cost improvement program going for a long time. And we have recently been able to make some breakthroughs on that with various vendors and it's just focusing on it. And same as in the Permian. Everybody in the company's focused on more profit per barrel and less cost per barrel.
Stephen I. Chazen - President, Chief Executive Officer & Director:
I think to be – I mean the way the accounting works in the Middle East on a production sharing contract, the company always bears all of the cost, all of the operating costs. So when oil prices are high, you get fewer barrels to cover that operating cost.
Phil M. Gresh - JPMorgan Securities LLC:
Sure.
Stephen I. Chazen - President, Chief Executive Officer & Director:
And higher, and lower oil prices you've got a lot more barrels to cover the exact same operating cost even if they don't change. So I mean that's -
Edward A. Lowe - Vice President and President, Oil and Gas International Production:
It's a combination.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, it's a little different than comparing to the US or something like that because you always have all of the, 100% of the operating costs essentially there. And so whether you produce 10,000 barrels a day or 20 net, operating cost is the same.
Phil M. Gresh - JPMorgan Securities LLC:
Right. Okay, all right. Thanks a lot.
Operator:
Our next question is from Tim Rezvan of Sterne, Agee CRT. Please go ahead.
Timothy A. Rezvan - CRT Capital Group LLC:
Hi. Good morning folks. First question I guess was on the US cash OpEx numbers that you reported in the third quarter, kind of flattish from 2Q. I know that you've had some big improvements early in the year. I guess you've talked qualitatively about bringing that down more, but maybe can you talk about what happened in the third quarter and kind of how we should think about the trajectory of that into 2016?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Yes. We've continued to improve our operating costs and basically we're focusing on the OpEx in Permian Resources and Permian EOR because in Williston we had some high OpEx there just because of the fact that our production was lower. But in the Permian, what we're doing is, we see the biggest opportunities in our Resources business where initially we had difficulty pumping from the deeper unconventional wells. We were trying to use either ESPs or beam pumps. With both of those there were issues because of the depth of those wells and the initial very high volumes that then becomes lower volume pretty quickly in the life of the well. So now we've gotten to a point where we understand that better. We're addressing that better. We're actually ensuring that we installed a lift that's the right kind of lift for the full life cycle of the well so that we don't have high initial repair costs. So that's part of what's driving down our OpEx in the US. In Permian EOR, those guys are continuing to optimize what they do with respect to well maintenance. They have a lot more wells over there. So they've been able to reduce quarter over quarter the cost per barrel in the EOR business by improving the well service rig performance, and improving how they deal with replacement of pumps and things like that, the materials they use and what they're doing there to extend the life of the wells. So we do expect continued improvement in both of those business units.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, I think the short answer is that the Williston operating costs went up and it dragged the average up.
Timothy A. Rezvan - CRT Capital Group LLC:
Okay. Okay. I appreciate that comprehensive answer. Next question I guess on the repurchase program. Your average shares outstanding were down 3.3 million. You only spent $50 million in the third quarter. So I guess that's a factor, the timing of your 2Q activities. Should we expect in a $50 or sub-$50 oil environment that you will kind of run at a much lower pace on the repurchases? Or I guess what's your philosophy on that?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Well, if I had more confident in the oil price, we'd be more aggressive in the share repurchase. At this point it depends on two things; sort of a calculation of what's in the stock which is favorable to repurchase; and how fearful we are about the volatility in the oil price. So I think the fear overcame the calculation this past quarter. We keep on reading these analyst reports so that generates enormous fear.
Timothy A. Rezvan - CRT Capital Group LLC:
I appreciate that commentary.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thank you.
Operator:
Our next question is from Edward Westlake of Credit Suisse. Please go ahead.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
You clearly shouldn't read analyst reports.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Clearly. I just read the headlines.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay. No worries. Question on the Middle East. I mean you talk about ramping down activities, maybe non-core asset sales. I mean of the countries that you list there, Bahrain looks like one which might have a buyer in the sense of the production as opposed to those other countries. Is that what you're talking about?
Stephen I. Chazen - President, Chief Executive Officer & Director:
No.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Selling assets or just reducing activity?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Just reducing activity I think is the way to say it. There's a significant amount of, call them receivables or whatever you want to call it, where we produce the oil and gas but haven't been paid in some of these places. And basically you're effectively building up a liability over time and basically we can't afford to do that currently. And so we'll reduce the activity until we can catch up with that accrual if you will. It doesn't show up on a balance sheet. It's simply the difference between production and liftings.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
And then on Block 9 you said on the last call, we'll look for a contract extension that's as least as good as what we could get back in the Permian. Any progress on how the other side of the table view that?
Stephen I. Chazen - President, Chief Executive Officer & Director:
It's a difficult negotiation I think is the best way to describe it.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
And ongoing?
Stephen I. Chazen - President, Chief Executive Officer & Director:
And ongoing. I think it will go – it will go on until – all these things go on until there's no more time left.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
And as a reminder, just in terms of now as we get down to end 2015 what the actual drop dead date is or...?
Stephen I. Chazen - President, Chief Executive Officer & Director:
It's in December.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay, and then just moving to the midstream, the Ingleside cracker and the export facility for LPG should be fairly profitable in terms of EBITDA and free cash flow when they're on-stream.
Stephen I. Chazen - President, Chief Executive Officer & Director:
That's right.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Just an update as to when you'd sort of -
Stephen I. Chazen - President, Chief Executive Officer & Director:
Towards the end of next year.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Right, okay.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Mid – second to third quarter as I recall.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay. Good. So CapEx comes down. Cash flow goes up and that helps balance.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah and the same thing, when the cracker is the end of – be done the end of next year and then the cash flow really in 2017. Same sort of dynamic except probably larger.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay. Thanks very much.
Operator:
Our next question is from Jason Gammel of Jefferies. Please go ahead.
Jason D. Gammel - Jefferies International Ltd.:
Yes. Thanks very much. I was hoping to just get a little more understanding on what led to the write-down on Iraq. Because my understanding was that it was an acceptable place to invest because you never really had a lot of capital exposed. And if you're reducing investment activity even more and you're still lifting oil, does that imply that you got into a situation of a big arrears with the government that you don't think you'll actually ever be able to get paid back?
Stephen I. Chazen - President, Chief Executive Officer & Director:
There's clearly – I really don't want to get into a discussion about the contract terms there, except to say that in theory, you got your money back on a small profit pretty much as you spent the money, maybe a quarter or two off. And that really – and that hasn't exactly happened.
Jason D. Gammel - Jefferies International Ltd.:
Okay. I think that's a fair enough explanation. I think I get what's going on there. Now, at the risk of picking nits here, the Permian Resource production overall in the quarter, obviously very good, but it did seem to be a little more swung towards NGLs and gas and away from oil than what I would have normally expected. Vicki talked about moving to pad drilling and making it a more manufacturing process which makes it more lumpy. Is that the explanation for that or is there something else going on?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
In addition to the pad drilling, we were able to capture some stranded gas in the last quarter and we were able to put that online and through processing and that's what drove some of that.
Jason D. Gammel - Jefferies International Ltd.:
So should we still think about this as 5,000 barrels a day of oil growth out of Permian Resources on a move forward basis with recognizing there could be variation from quarter to quarter?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
There's going be lumpy production. So it could vary from quarter to quarter, but in terms of the differential with the gas with respect to oil this time, it was again – it was due to a one-time event to get some gas production on that we didn't previously have on.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, as you reduce the capital, have fewer rigs, the effect of this lumpiness is more obvious because you got these rigs working in one place and if you're in five places, well it sort of averages out. But as you reduce the number of rigs at work, the effect of the lumpiness from a quarter to quarter basis is a lot more obvious. So you might expect some more. You'll be able to see it in a normal environment. With a somewhat higher rig count, you wouldn't see it really. It would just smooth out.
Jason D. Gammel - Jefferies International Ltd.:
Yeah, okay. That makes sense to me. Okay. Thanks very much, folks.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thanks.
Operator:
Our next question is from John Herrlin of Société Générale. Please go ahead.
John P. Herrlin - SG Americas Securities LLC:
Yeah, thanks. With respect to the Permian Resources unit, can you describe what you're doing in terms of the well completions that are different, or are you doing anything materially different than your peer group?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
On the well completions, we've continued to try to find the exact mix of when to use slick water, when to use hybrid fluid systems and also what the cluster spacing should be, what the volume of the proppant should be. So what we've done is we've experimented a little bit trying to ensure that we get all of that optimized. And some of that we have enough data that we can optimize it and we know what to do. For example in cluster spacing, we can take the pressures that we see during the frac jobs and kind of get to a point where we know what that should be for a given area. So it's still really the proppant size and the fluid volumes and fluid types that we're experimenting with. We did some experimentation with using some of the sleeves and things like that versus plug and perf. And we found that while the sleeves are somewhat effective in being able to isolate and frac, they're not as good when we try to flow the wells back because the sleeves actually cause variations in the flow back which drops out proppant, causes cleanup issues later. So we're moving more toward now ensuring that what we do is we'll have optimum impact on not just recovery but the life of the well. So I think it's just still experimenting with those things that others do. We're waiting for our seismic. We should be done acquiring that in the Barilla Draw area soon, and we'll be processing that. And we hope that will lead to actual more improvements next year.
John P. Herrlin - SG Americas Securities LLC:
Great. Thanks. With your EOR operations in the Permian, at current prices how much free cash flow are you generating from that?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
At current prices, I can tell you, I can give you what we were generating. We were generating a couple of billion dollars when prices were in the $90 environment.
John P. Herrlin - SG Americas Securities LLC:
Okay.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Probably about -
Stephen I. Chazen - President, Chief Executive Officer & Director:
About a margin, Chris.
Christopher G. Stavros - Chief Financial Officer & Senior Vice President:
Probably cash margins of about $20 a barrel or so.
John P. Herrlin - SG Americas Securities LLC:
Okay. That's great. Last one for me. You took a big impairment on gas. Did you really kitchen sink it in terms of pricing?
Stephen I. Chazen - President, Chief Executive Officer & Director:
We hope so.
John P. Herrlin - SG Americas Securities LLC:
Okay. Thanks, Steve.
Operator:
Our next question is from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.:
Good morning. My first question is a quick macro question. Steve, as you are doing your business in the Middle East, are you seeing any tangible signs of stress or second thoughts regarding OPEC's current production strategy by any of the countries in the region?
Stephen I. Chazen - President, Chief Executive Officer & Director:
If they had stress, they wouldn't share it with us. I think that's fair to say. What you do see of course is a lot of talk about raising money and that sort of thing. So if you want to view that as stress, you can. But they all say that they're aligned, whatever that means.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.:
Okay. Thank you. You provided helpful color on non-core asset sales in MENA. As you continue to high grade your portfolio, how do you think about Colombia.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Vicki can answer that.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
In Colombia, we recently signed an agreement with the government to implement a couple more water floods in Colombia. We see that as our asset there is the opportunity to continue to maintain our production. We'd like at some point to be able to grow the production a little bit. But currently we have a great relationship with the government and with Ecopetrol. We have a team down there that's incredibly efficient and knows the area very well. And our operating teams are very good there. So we see it as a place that, we've been there for over 30 year, would like to continue to be there another 30 years. The country itself has some opportunities outside of what we currently have. And certainly, any opportunity that comes up in Colombia is something we'd want to take a look at.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.:
Okay. Great. And my last question is thinking about Permian capital allocation, with the results that you showed in East Midland, is it possible that capital in the Midland Basin can increase relative to the Delaware in 2016?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Currently, we were thinking that we would move more activity to the Delaware Basin. But you're right. Our Midland Basin team has been performing so well, and especially with this Big Spring area in Howard County, the performance there and in Merchant is getting to the point where those wells are really becoming very competitive with what we're doing in the Delaware.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.:
Okay. Great. Thank you.
Operator:
Our next question is from Brian Singer of Goldman Sachs. Please go ahead.
Brian A. Singer - Goldman Sachs & Co.:
Thank you. Good morning. Wanted to dig in a little bit on the broader Delaware and Midland Basin well performance to understand whether the strong wells you highlight here on slides 13 and 15 are trending relative to your broader acreage and drilling program and whether they're reflective of what we should expect going forward. I'm not sure if it's apples-to-apples, but if we look at the BOE a day per thousand feet of lateral you have for the 2015 averages, they both, on slides 13 and 15, appear to be below what was reported for the first half in the second quarter presentation. And so what I'm trying to get to is whether the specific wells you're highlighting here with much better rates are reflective of the wells we should expect going forward for specific portions of your acreage, whether they're good averages we should assume for your broader acreage or they're highlights of your best wells.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
I think the 2015 average is not exactly representative of what we'll see going forward, but it's indicative of a trend that we'll see. What you're talking about, the trend downward was certainly impacted by the Peck State and the Buzzard State because initially we had incredible rates from the Peck State. It was about 2,400 BOE per day, 24-hour rate for the Peck State. About over 2,000 barrels a day for the Buzzard State. Those wells were two of our best wells in the Delaware Basin. What we're trying to do and the reason we're still, and in answer to John's question, the reason I said we're still trying to tweak things and work things is that we feel like we should have the ability to continue to increase our performance per well. And we're still, we think that with the seismic, we'll be able to figure out what made the Peck State and the Buzzard State so good. And then we'll target trying to hit either the interval that was so good in there or the area, or types of areas like that. And so that's exactly the reason for the seismic is to try to determine whether their reservoir, whether there are areas that are driven by reservoir quality or characteristics that we can move toward in our development program toward the end of 2016. Because by the time we have the seismic processed and evaluated, it would not start impacting the program until the end of next year. But that's exactly what it's designed to do, is look for whether or not those wells were in a particular area that's limited, or whether it's broader and we just aren't getting the chemistry of the frac jobs right or the location within the interval. That's not to say we're not having great wells. We're having great wells, but we do want to continue to improve them. We'd love to see more of those types.
Brian A. Singer - Goldman Sachs & Co.:
That's very helpful. And my follow-up is also on slide 13 where you have the nice map of your focus acreage. Can you just refresh us on how many acres that focus area represents and what it would take and any plans to turn some of the other acreage we see there of Oxy's into focus acreage?
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
Well, we have as you know 1.5 million net acres in the unconventional business and our inventory of wells really, the appraisal wells that we've shown you, that 8,300 well inventory was really based on an appraisal of about half of that. And then our development areas, we're trying to keep at an even lower acreage percentage than that because what we're trying to do is ensure that we completely build out as we build our infrastructure. So probably the Barilla Draw area represents an acreage, at least what we're really concentrating on developing, probably two or three pods that would total up to be about 40,000 or 50,000 in the Delaware Basin.
Brian A. Singer - Goldman Sachs & Co.:
Great. Thank you very much.
Operator:
Our next question is from Guy Baber of Simmons. Please go ahead.
Guy Allen Baber - Simmons & Company International:
Thank you all for fitting me in here. I had a follow-up question on some of the earlier questions around capital spending flexibility into 2016. And I apologize if I missed this earlier, but can you just help us understand the amount of capital spending currently being dedicated to the portion of your MENA program that you deem as non-core? Just trying to understand the opportunity set for the potential spending reductions there that you might be pursuing.
Vicki A. Hollub - Senior Executive Vice President and President, Oxy Oil and Gas:
It's $400 million, $400 million.
Stephen I. Chazen - President, Chief Executive Officer & Director:
I think it's $400 million.
Guy Allen Baber - Simmons & Company International:
Okay. Thanks. And then Al Hosn ramping up faster than expected on the production front. Can you discuss that outperformance? And then also can you address the contributions during the quarter from a cash flow perspective? And really trying to understand the timing of the cash flow contributions there and what the peak cash flow contributions are in this environment. Obviously it's difficult to predict given the sulfur exposure and the less transparency on some of the pricing.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, I think the cash has normal settlement with it. So the production is actually doing pretty much the way it's said. I mean the 60,000 is what we talked about. Cash flow before capital settles like others and so it was a little back end loaded in the third quarter. So there was less of it in the third quarter than we'll see in the fourth quarter. There's some capital that needs to be spent in the fourth quarter and into the first quarter for some things which we'll use some of the money. The business just depends on really oil prices, the volatility in the business. So I think we're talking about $300 million of free cash. And then it could be as much as $1 billion depending on oil prices sort of in the $70s.
Guy Allen Baber - Simmons & Company International:
Okay, great. That's helpful, Steve. And then last one for me. You mentioned exiting 2015 with Permian Resources production of around 120,000 barrels a day. So on over $2 billion of CapEx this year, you're obviously growing that business very significantly. Do you have an estimate of the level of spending that could hold that 120,000 flat through next year? Just trying to understand how that compares to the $2 billion plus you're spending this year that's driving considerable growth.
Stephen I. Chazen - President, Chief Executive Officer & Director:
We're now discussing among ourselves as to what that number might be. So under $1 billion I think. But we don't know whether it's $700 million or $800 million or $900 million. Because things keep getting better, that's why we're slow in giving you these answers because we just don't know, and we don't want to mislead you.
Guy Allen Baber - Simmons & Company International:
Got it, understood. Thanks.
Operator:
This concludes the question-and-answer session today. I would like to turn the conference back over to Chris Degner for any closing remarks.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Emily, and thanks to everyone for participating. Have a great day.
Operator:
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Christopher M. Degner - Senior Director-Investor Relations Stephen I. Chazen - President and Chief Executive Officer Christopher G. Stavros - Executive Vice President & Chief Financial Officer Vicki A. Hollub - President, Oxy Oil and Gas – Americas
Analysts:
Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Edward G. Westlake - Credit Suisse Securities (USA) LLC (Broker) Leo Mariani - RBC Capital Markets LLC Ryan Todd - Deutsche Bank Securities, Inc. Paul B. Sankey - Wolfe Research LLC John P. Herrlin - SG Americas Securities LLC Matthew M. Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Brian A. Singer - Goldman Sachs & Co.
Operator:
Good morning, and welcome to the Occidental Petroleum Corporation's second quarter 2015 earnings conference call. All participants will be in a listen-only mode. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner. Please go ahead.
Christopher M. Degner - Senior Director-Investor Relations:
Thank you, Emily. Good morning, everyone, and thank you for participating in Occidental Petroleum's second quarter 2015 conference call. On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer; Vicki Hollub, Senior Executive Vice President of Occidental and President, Oxy Oil and Gas; Chris Stavros, Chief Financial Officer. In just a moment, I will turn the call over to our CEO, Steve Chazen, who will provide an updated outlook for 2015. Our CFO, Chris Stavros, will review our financial and operating results for the second quarter and also provide some guidance for 2015. He will be followed by Vicki Hollub, who'll provide an update of our activities in the Permian Basin. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our second quarter 2015 earnings press release, the Investor Relations conference call slides, our non-GAAP-to-GAAP reconciliations, can be downloaded off our website at www.oxy.com. I'll now turn the call over to Steve. Steve, please go ahead.
Stephen I. Chazen - President and Chief Executive Officer:
Thank you, Chris. We've made progress towards our objectives for this year. Our principal goal for the year is to achieve cash flow neutrality where our operating cash flow covers both our capital spending and dividend outlays at $60 per barrel realized oil prices. We will achieve this goal through deploying our capital and operating cost savings into further production and cash flow growth, driven mostly by our Permian Resources business unit and the start-up of the Al Hosn gas project. Year to date, we estimated about $450 million in captured cost reductions. We expect our 2015 capital outlays to be about $5.8 billion, as we have redeployed some of the cost savings to drilling more wells in our Permian Resources business unit. In short, we are learning to do more with less and expect continued improvement in productivity through the year. Despite volatile product prices, our Oil and Gas segment has been operating well in nearly all of our key assets. We've increased total oil production by 16% since second quarter of 2014. The focused development program in Permian Resources has driven most of the growth, as well as strong production volumes in Oman and Colombia. We've also focused on optimizing our base production. Rather than making head count reductions during this downturn, we've sent many of our engineers out into the field to replace contractors. They've done a good job of maintaining our base production and driving operating efficiency. In the Permian, we have shifted our Resources business to a focused development program. We're drilling completing wells at a faster pace and accelerated our time to market. Total production increased by about 50% year over year – has again exceeded our internal outlook. As such, we have increased our estimate of production for the second half of the year to 117,000 BOE a day. Actual results continue to improve and outperform our internal outlook. Al Hosn is a large world-scale project and the first of its kind. It is reasonable to expect some operational pains as it has ramped up to full production. In the second quarter of 2015, Al Hosn produced 18,000 BOE a day and sold its first shipment of sulfur. Due to mechanical challenge in the sulfur recovery units, the plant was limited to 50% of capacity for most of the quarter, and production was curtailed for most of the month of April. Repairs to stabilize the sulfur units were completed in July, and the plant has responded well as production has ramped up. The plant is currently producing at about 50,000 BOE a day to us, and we expect it to contribute about 30,000 BOE a day in the third quarter. Despite a lower capital production, we expect production growth of 70,000 to 80,000 BOE a day in 2015, driven by the start-up of the Al Hosn gas project and focused development program in Permian Resources. In the United States, we expect oil production growth about 8%, partially offset by declines in NGLs and natural gas production. Vicki Hollub will provide further details on the outlook for the U.S. Oil and Gas business. Construction on the Ingleside ethylene cracker is ahead of schedule and on budget. There are currently 1,300 workers on-site. Construction is about 30% complete, and over 80% of the equipment has been purchased and delivered. We expect to be more than 70% through our capital spending on the project by year-end and for the plant to start up in early 2017. As we capture price savings from suppliers and improve the efficiencies of our operations, we're able to do more with less spending. Our capital spending in the second quarter declined by about $250 million and will continue to decline throughout the year. As for – our forecasted capital spending level in some Middle Eastern assets may be slightly higher than expected this year. However, the production sharing contract should allow us to quickly recover our capital costs with increase in oil production. We expect the exit this year at a quarterly spending rate of $1 billion to $1.2 billion. If oil prices remain at current levels around $50, our 2016 capital will be less than both the 2015 full year and the fourth quarter run rate. Given our large acreage position and deep inventory, we have the flexibility to defer drilling and appraisal activities. Although we will outspend our cash flow this year, we expect that going forward our operating cash flow will cover our capital expenditures and dividend payments, assuming $60-per-barrel oil price realizations. We continue to invest growth capital in the Permian Resources segment. Over the first half of the year, we did not make any meaningful acquisitions, nor do we have any in the pipeline. The market for asset acquisitions in the Permian Basin has been heated, with new entrants paying sizable premiums for acreage. With our deep inventory of assets, we will focus on organic growth with a low possibility of selective bolt-on acquisitions that leverage our existing infrastructure and geologic understanding. We have approximately 64 million shares remaining under our current share repurchase authorization. At current stock price levels, we would view the stock as attractive for repurchase. Now I'll turn the call over to Chris Stavros for a review of our financial results.
Christopher G. Stavros - Executive Vice President & Chief Financial Officer:
Thank you, Steve, and good morning, everyone. First I want to highlight some new formatting around our quarterly disclosures. We created a set of earnings release schedules that replaces the previous IR supplemental schedules. The new format is more comprehensive, providing condensed quarterly financial statements, plus quarterly data going back for the entire prior year. We generated core income of $165 million for the second quarter 2015, resulting in diluted earnings per share of $0.21, an increase of $0.04 per share in the first quarter of 2015 and a decrease from $1.38 per share in the second quarter of 2014. Worldwide oil prices improved about $6 a barrel in the second quarter of 2015 compared to the first quarter, but still remain well below prices comparable to last year. U.S. natural gas prices continue to decline, down about $0.40 per mcf from the first quarter, and NGL prices stayed essentially flat. Our second quarter capital spending was about $1.5 billion, down 14% from the $1.7 billion we spent in the first quarter. We continued to ramp down our capital program in the second quarter, focusing our development activity in core areas of the Permian Basin and parts of the Middle East, with an emphasis on growing our production volumes and, importantly, our operating cash flow. Despite the reduction in this year's capital program, we continued to grow our domestic Oil and Gas volumes, driven by our Permian Resources operations. Permian Resources grew its oil production 78% in the second quarter, adding 31,000 barrels per day compared to the year-ago period, with total BOE growth of 51%. Production from Permian Resources improved 11,000 BOE per day sequentially, with 9,000 barrels per day coming from oil. Turning to the specific business segments, Oil and Gas core after-tax earnings for the second quarter 2015 were $108 million, $130 million higher than the first quarter and $833 million lower than last year's second quarter. As I mentioned earlier, the largest impact of the change in year-over-year earnings was due to lower oil prices. For the second quarter of 2015, total company Oil and Gas production volumes averaged 658,000 BOE per day, an increase of 13,000 BOE in daily production from the first quarter and 78,000 BOE per day from the same period a year ago. Total company oil volumes were 433,000 barrels per day in the second quarter, 61,000 barrels per day higher than the year-ago period, for an increase of 16%. Total domestic Oil and Gas production averaged 333,000 BOE per day during the second quarter 2015, up 7,000 BOE per day sequentially and 25,000 BOE on a year-over-year basis, with all of the increase coming from Permian Resources. This was partially offset by lower production from our Midcontinent assets, where we have ceased our drilling activity. Domestic oil production was 205,000 barrels per day during the second quarter, an increase of 7,000 barrels per day sequentially and up 26,000 barrels per day, or 15%, from the year-ago quarter, exceeding our earlier guidance for the period. For the year to-date, overall domestic production volumes have exceeded our expectations. Our domestic production growth for the first six months of 2015 resulted in an additional $175 million of operating cash flow when compared to the last six months of 2014 and using current product prices for both periods. We achieved this growth while reducing our domestic capital by $389 million. In summary, we not only drilled and completed the wells but sequentially grew both our production volumes and operating cash flow, which can be reinvested in the business. International Oil and Gas production volumes averaged 325,000 BOE per day during the second quarter, up 6,000 BOE per day sequentially and 53,000 BOE per day on a year-over-year basis. Production from the Al Hosn gas project increased by 9,000 BOE per day from this year's first quarter to 18,000 BOE per day in the second quarter and, as Steve mentioned, also realized the sale of its first shipment of sulfur. Production was curtailed during much of the second quarter, as mechanical modifications and adjustments were made to the sulfur recovery units. These adjustments have been completed, and we expect our net production to exit this month around 50,000 BOE per day. Our second quarter Oil and Gas cash operating costs of $12.10 per BOE declined 9.0% from the first quarter of $13.36 per BOE due to lower surface and downhole maintenance costs, lower workover costs, as well as higher production volumes. DD&A for the second quarter was $16.06 per BOE compared to $15.35 per BOE during the first quarter. Taxes other than on income which are directly related to product prices were $1.85 per BOE for the second quarter of 2015, compared to $1.63 for the first quarter of 2015 and $2.45 per BOE for the full year of last year. Chemical pre-tax earnings were $136 million for the second quarter of 2015. Results were lower than expected, due to higher ethylene feedstock costs and lower caustic soda prices, as well as some unplanned outages at two of our VCM plants. Midstream pre-tax earnings were $84 million during the second quarter compared to a loss of $5 million in the first quarter of this year and income of $130 million in the same period a year ago. Our Midstream segment is composed of physical marketing, pipelines, power, and gas processing. Our physical marketing is exposed to spreads between WTI Midland and Gulf Coast pricing through multiple pipeline commitments. In the second quarter, our Midstream segment results benefited from wide price differentials. We expect this benefit to partially reverse in the third quarter, as price differentials have narrowed. Our gas processing business converts wet gas to NGLs. Currently, NGLs are trading at an equivalent price to natural gas, which is insufficient to cover the plant operating expenses. Our domestic pipelines as well as the Dolphin pipeline generate a relatively stable and strong stream of tariff income from transporting crude oil and natural gas. Operating cash flow before working capital changes for the first six months of 2015 was $2.6 billion. As I mentioned, higher production volumes resulting from our continued investment in the Permian, as well as improved oil price realizations, resulted in a sequential increase of about $400 million in operating cash flow before working capital changes to $1.5 billion in the second quarter. Working capital declined by $950 million during the first six months of 2015. At December 31 of last year, accounts payable was $5.2 billion, and as of June 30 of this year, it decreased by $1.1 billion to $4.1 billion. This decrease was due to payments related to higher capital and operating spending accrued in the fourth quarter of last year but not paid until 2015. Total company capital expenditures for the first six months of 2015 were $3.2 billion, and about on track with our full-year 2015 capital budget of $5.8 billion. Oil and Gas spent $2.7 billion in the first half of 2015, with Permian Resources expenditures comprising 47% of the total and the remaining $500 million split nearly evenly between chemicals and midstream. The continued growth in our operating cash flow should help us to achieve our goal of being cash flow neutral after capital expenditures and dividends at oil prices of roughly $60 a barrel. In June we completed a bond offering, issuing senior notes at 3.5% and 4.625% and received net proceeds of approximately $1.5 billion. The proceeds were used to build liquidity and partially prefund some of our debt maturing in the first half of 2016. Oxy's credit ratings remain unchanged at A by Moody's and S&P. We paid cash dividends of $1.1 billion in the first six months of 2015 and purchased 7.4 million shares of our stock for $571 million. This amounts to an annualized cash return of 6.2% for our shareholders. The share repurchase activity for the first six months also has the benefit of reducing our annualized dividend outlays by approximately $22 million. Our cash balance at the end of the second quarter was $5.1 billion. Our long-term debt-to-capitalize ratio was 17% at the end of the second quarter. The worldwide effective tax rate on our core income was 65% for the second quarter of 2015. Looking ahead to the third quarter domestically, we expect production from Permian Resources to grow by roughly 5% sequentially on a BOE basis, including 5,000 barrels a day of oil growth. Growth in the Permian should be roughly offset by declines in our Midcontinent production, leaving overall third quarter domestic production about flat with the second quarter. We expect our international production volumes to increase by about 10,000 BOE per day in the third quarter. Production rates at Al Hosn should continue to improve, increasing to about 35,000 BOE per day on average in the third quarter. The increase from Al Hosn should be partially offset by approximately 8,000 barrels per day of lower volumes in Colombia due to pipeline disruptions experienced during July. Assuming no meaningful disruptions during the second half of the year, we are raising the lower end of our full-year 2015 production guidance range from 650,000 to 660,000 BOE per day. Our current estimate of full-year 2015 volumes of 660,000 to 670,000 BOE per day will provide year-over-year growth of 12% to 13%. Price changes at current global prices affect our quarterly earnings before income taxes by $30 million for a $1 per barrel change in oil prices and $7 million for a $1 per barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pre-tax earnings by about $15 million. Our third quarter 2015 exploration expense is anticipated to be about $20 million pre-tax. We expect our third quarter 2015 pre-tax chemicals earnings to be about $140 million. Our third quarter midstream earnings will be principally impacted by Midland to Gulf Coast oil price differentials. We expect our interest expense to increase to about $50 million in the third quarter from $7 million in the second quarter. The sequential increase is due to expensing of previously capitalized interest on the Al Hosn project and the $1.5 billion senior notes we issued in June. Using current strip prices for Oil and Gas, we expect our full-year 2015 domestic tax rate to be 36% and our international tax rates to remain about 65%. To summarize, we demonstrated strong year-over-year production growth of nearly 13% in the second quarter, bolstered by continued growth in Permian Resources and from the Al Hosn project. We also continued to grow our operating cash flow, which is being used to organically reinvest in the business while providing a balanced return of cash to our shareholders. I'll now turn the call over to Vicki Hollub, who will provide an update on our operations in the Permian Basin.
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Thank you, Chris. Today I'll review the highlights of our Permian Resources and Permian EOR activities in the second quarter, and then I'll provide guidance on our program for the remainder of 2015. I'd like to highlight a few key messages. First, Permian Resources is continuing to drive capital costs down through improved execution efficiency in drilling and well completions. Second, production again exceeded expectations due to reduced time to market and better-than-planned well performance. Finally, the positive returns of our Permian unconventional programs in this environment, along with the large-volume, low-decline production from our EOR operations, provides us flexibility and a wide range of product prices. The advantages this portfolio provides can't be duplicated in the Permian Basin. In the second quarter, Permian Resources achieved daily production of 109,000 BOE per day, a 12% increase from the first quarter and a 51% increase versus the prior year. Oil production increased to 71,000 barrels per day, a 15% increase from their previous quarter and a 78% increase from a year ago. We drilled 47 wells, including 42 horizontals. We placed 71 wells on production, including 53 horizontals. In the second half of this year, we'll operate about 12 rigs and drill and complete at least 100 horizontal wells. We continue to work on four key activities that are adding more wells to our inventory and reducing the economic hurdles of our inventory. First, we've used our vast database to update our basin hydrocarbon richness map and to build the petrophysical and geochemical models necessary to improve well performance and to add more locations to our inventory. Second, our teams have further reduced our drilling and completion costs and optimized the value of a manufacturing approach in our key areas. Third, although we have achieved significant cost savings from our vendors, we continue to look for creative ways to reduce service and materials cost further. Lastly, we're enhancing base management and maintenance operations to maximize production at minimal incremental cost. These activities have generated higher-than-expected production and have lowered our finding and development cost, thereby increasing our inventory of drilling locations that deliver returns which exceed our cost of capital. We'll provide an update of our inventory by play and breakeven prices later this year. In the fourth quarter of last year, we began transitioning from appraisal mode to a targeted development program, utilizing a manufacturing approach combined with integrated planning and engineering. This has reduced nonproductive time, maximized the efficiencies of pad drilling, including the use of zipper fracs, and has reduced infrastructure costs. As a result of these efforts, we have achieved significantly improved well delivery and lower well cost. As the example on slide 27 illustrates, we've reduced our drilling time by about 50% and our costs by about 40% in a recent Wolfcamp A well in the Delaware Basin. Our improvements were driven by adopting and adapting oilfield technology, including an advanced mud system to eliminate casing across the salt interval in the wellbore. Oxy Drilling Dynamics is a proprietary system we have developed by expanding upon mechanical specific energy concepts to improve rates of penetration. This improvement in drilling efficiency is a structural change to our business that will sharply lower our cost irrespective of pricing concessions from our suppliers. In the Delaware Basin, our Wolfcamp A 4,500-foot well cost decreased by about 40% from 2014's cost of $10.9 million to a current cost of $6.8 million. We've reduced our drilling time by 23 days from 2014's average of 43 days to 20 days. I would note that even as we have lowered our completion cost per well, we've optimized the density of our completions and profit loads and have been drilling longer laterals. As I'll highlight later, our productivity has continued to improve while we have lowered our costs. In the Delaware Basin, we've identified 900 additional horizontal development locations for a total of 5,700. We have 2,000 horizontal well locations ready for development, including 800 sites in the Wolfcamp A bench. The majority of these locations are in our operated areas in Reeves County. In New Mexico, our Bone Spring potential is equally as significant, with 2,300 locations. Our well performance in the Delaware Basin continues to be strong. We placed 13 horizontal wells on production in the Wolfcamp A benches in the second quarter. These wells achieved an average peak rate of 1,359 BOE per day and a 30-day rate of 988 BOE per day. The Moore Hooper 3H well achieved a 2,389 BOE per day peak rate and a 1,769 BOE per day 30-day rate. Additionally our Lenox 2 5H well achieved a 2,425 BOE per day peak rate and a 1,506 BOE per day 30-day rate. Both of these wells produced around 70% oil, and we believe that they are among the most prolific drilled to date in the Permian Basin. Now I'd like to shift to the Midland Basin. We've made similar improvements in well cost and drilling days in our Wolfcamp A wells in the eastern part of the Midland Basin. We reduced the cost of these 7,500-foot horizontal wells by 30% from 2014's cost of $9.2 million to a current cost of $6.5 million. We reduced our drilling days by more than 50%, from 46 days in 2014 to 20 in the second quarter. Through our program this year and in evaluating the acreage from the acquisition in December, we have added 600 horizontal locations in the Midland Basin for total now of 3,100. Most of the additions were in the Wolfcamp A and Spraberry formations, and we now have 2,000 identified locations ready for horizontal development. A new area for us is in the Midland Basin. It's called Big Spring, which was part of the December acquisition. We launched into development early this year, and in the second quarter we brought online the May 1102H (25:09) Wolfcamp A well at a peak rate of 1,846 BOE per day and a 30-day rate of 1,262. The well is producing at over 85% oil. These Wolfcamp A well results have been outperforming our initial type curves for this emerging play in Howard County. Now shifting to Permian EOR, where year to date we're ahead of plan and meeting our aggressive cost improvement target. We've reduced the cost of drilling San Andres wells by about 30% through optimized drilling parameters and crew efficiency. Additionally, we've reduced our downhole maintenance hours per job by 20% since the fourth quarter by applying the learnings gained from a manufacturing approach to well maintenance. We have 15,000 wells in the Permian EOR business and expect to reduce our 2015 downhole maintenance and enhancement cost by $60 million versus 2014. These cost reductions will further increase the free cash flow generated by our Permian EOR business in the current oil price environment. Despite the low price environment, we're – continued to commit to developing our technical talent and recently finished construction of a new training center in Midland that will open in September. In previous industry down cycles, we've seen in the industry overreact through widespread layoffs. We're taking a different approach with our response to low oil prices and have deployed many of our engineers in the early stages of their careers out into the field, where they have replaced contractors. They are successfully helping to optimize our base production, improve drilling times, and gain on-the-ground experience. In closing, we'll continue to execute a focused development strategy in 2015, and we'll pursue additional step changes in well productivity and cost structure. For the remainder of 2015, we plan to operate an average of about 12 drilling rigs to drill around 100 horizontal wells in Permian Resources. This is a higher activity level than planned, but we believe investing efficiency gains back into Permian Resources is a prudent action to take. We expect to produce an average of 117,000 BOE per day in the second half of 2015 and for the business to drive continued growth in operating cash flows. Strong production growth from our Permian Resources business, along with the high-volume, low capital-intensive Permian EOR business, keeps us well-positioned to not only meet the challenges of this lower-price environment, but also to profitably grow our combined Permian business. Now, I'll turn the call back to Chris Degner.
Christopher M. Degner - Senior Director-Investor Relations:
Thank you, Vicki. We'll now open up for questions. Emily?
Operator:
Thank you. We will now begin the question and answer session. Our first question is from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Hey, good morning, everybody. My first question – Permian Resources, production beats again, very impressive cost and efficiency improvements here. Really two questions, does your performance lower your existing targets? And secondly, how would you benchmark your Permian operating performance versus peers where there's a peer scope (28:36) to see some continued improvement for a group that's improving at a pretty fast pace?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Currently, we feel like in the Delaware Basin, we're definitely upper quartile in terms of drilling performance. And actually, we've recently compared our performance to some of our competitors. And we feel like there's maybe one or two operators that have had a couple of wells – a few wells better than ours. But with the direction that we're headed, we expect to be first in performance in drilling in the Delaware Basin, due to the activities and initiatives that I just discussed. And with respect to well performance, we looked recently at what some offset operators are doing, and, compared to offset operators in the Delaware Basin, as I said in my discussion here, we believe that we've just completed some of the best wells in the basin, in the Delaware. In the Midland Basin, this new area that we're developing now in Big Spring is certainly showing some of the best production that we've seen yet in the Midland Basin as well. So in some areas in the Midland Basin, we're about par, and, in some cases, slightly lower than some of our competition, but certainly this Big Spring area is competing very well, as is Merchant.
Evan Calio - Morgan Stanley & Co. LLC:
Right. And does that reset your targets in terms of the targets you put forth in the slides?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
For now, what we're trying to do is – we feel comfortable with what we've stated for the second half of this year. So that's the target we expect to be able to hit, which equates to about a 109,000 [BOE] average for 2015. With respect to 2016, our targets on a per-well basis, on the average, are going to increase, but what we haven't determined yet is what level of activity we'll have for 2016. So we feel very comfortable that we're going to have a stronger program going into 2016, but the level of capital spend will depend on market conditions.
Evan Calio - Morgan Stanley & Co. LLC:
Yeah, fair. My second question relates to locations. There's also a large uptick in locations in Delaware and Midland and particularly in development-ready locations. I mean, it sounds like a model change there that you discussed, but can you give us maybe any further color on that change? And how's that change continuing to evolve throughout the year? Are there drivers for additional scope change, given the pretty significant jump there?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Yeah, what's happening is our teams have become so efficient in a number of areas. So we're not just getting good with drilling – and the drilling has been the part of our performance that we've highlighted a lot. So drilling performance is significantly improving, and it's improving because of the modeling work that our teams are doing, in addition to the execution in the field. So it's a combination of our planning, our design, and our guys in the field executing it very well. In addition to that, though, we have an efficiency team that's driving how we do our business. From the time that we go out, we decide to spot a well, to the time that we get it to sales, every segment of that we've worked on to try to improve our efficiency. And that's gone really well, which has been a big part of the acceleration in addition to the improvement in a per-well basis in terms of initial rates and performance. The other thing that's helping us significantly is the business units working with our exploitation team to enhance what we understand about the reservoir now. So our modeling work, especially our petrophysical geomodeling and our mapping, has enabled us to do a better job of selecting where to place the lateral part of the well, not only where to spot the well, but where to put the lateral section of the well, and also how to complete it. And while we've seen significant improvements in our wells with the design changes we've made, we feel like there are still more improvements to be made, and we're continuing to work it.
Evan Calio - Morgan Stanley & Co. LLC:
I think you mentioned that you are going to provide price sensitivity later in the year, but are these locations conditioned on a strip or any particular price level currently?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Well, in the slides, you'll see that we have an inventory of our current well locations identified, and what it shows is the inventory that we can drill by price range. But I want to point out here that this inventory – it's on slide 25, I think – but the inventory that's shown on that slide really is not updated for not only well performance, but it hasn't been updated for our current cost structure. So we'll be updating that at the end of the year, and you can use that as the guide to see the level of inventory that we have based on what the oil price is. And this is based on delivering returns that are greater than our cost of capital.
Evan Calio - Morgan Stanley & Co. LLC:
Very good, great. I'll leave it there. Thanks.
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Okay.
Operator:
Our next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch:
Thanks. Good morning, everybody. Vicki, I can't help but notice the absence of any meaningful commentary around the Middle East in the slide deck this quarter. I guess, following on from Evan's question, substantially greater opportunity perhaps in the Permian Basin. As you think about the transition of the CEO role over the next year or so, how does your view of the Middle East (34:22) generally – obviously there's a lot of large core assets, but there's also a lot of smaller, non-core assets. How do you think about your preparedness to invest in those kind of areas, the type of returns, the risk profile, and so on, compared to the short-cycle, fairly-well-known entity that you have right your backyard? In other words, is the Middle East back on the table as a potential rationalization story? And I've got a follow-up, please.
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Well, we're looking at the Middle East basically as a group of what we consider core assets versus non-core assets. And the assets that we consider to be really core to our business over there are the assets in Oman, the Al Hosn project, the Dolphin project. Those are our cash flow generators, so the steam flood in Mukhaizna is certainly one of the projects that's very important to us. Some of the other assets in the Middle East – we're currently in Qatar, that's been a good project for us. That still has five years left on the contract there. Some of the other assets are assets that, as we've mentioned before, are assets that are non-core to us, and given the opportunity, we would work to try to monetize or exit those.
Doug Leggate - Bank of America Merrill Lynch:
I don't want to risk wasting my follow-up on this, but the Omani contract obviously is something that when you mentioned Oman you mentioned the steam flood, but you've got 35,000 or so barrels a day of production there today in a contract. Is that asset competitive? Is it delivering free cash flow at this point?
Stephen I. Chazen - President and Chief Executive Officer:
Yeah, this is Steve.
Doug Leggate - Bank of America Merrill Lynch:
In other words, would – go ahead, Steve.
Stephen I. Chazen - President and Chief Executive Officer:
She's new to the Middle East, but she'll answer next quarter. The answer is, yeah, it's a free cash flow generator at this point. Whether it's competitive or not is hard to measure. And so, as you know, what happens is you invest the capital and you get it back within the year, typically. So while you show a lot of investment, you get it back fairly quickly, and then some profit oil to go with it. So it's an okay contract at this point. But that's the same kind of financial characteristic that the Permian Resources has, frankly, just looking at it financially. And so the issue that Vicki will wrestle with over the next few months is whether it's competitive to continue to invest – basically shifting that capital to the Resource business, which basically has the same kind of payout timeframe, maybe a little longer than Resources but not much. So that's really what we're having to wrestle with, and we'll look for a contract extension that is at least as good as what we could get a lot closer to home.
Doug Leggate - Bank of America Merrill Lynch:
Okay. Thanks for elaborating, Steve. My follow-up is – I guess is one of the things that we periodically revisit, and it's the dividend. And obviously you've got a big dividend commitment. The stability of the underlying cash flow is a big, I guess, funding mechanism, CO2, chemicals, and so on. But if you shift your capital allocation, let's say, to the Permian away from those long-life assets that you have in the Middle East, one could argue that the visibility on long-life cash flow to sustain that dividend growth kind of starts to deteriorate a little bit. So what I'm really coming round to is how do you reset the dividend level such that you're able to maintain one of the – I guess the anchors of Oxy's legacy investment case, which is dividend growth? And, of course, what I'm really getting at is where's your head at on the buyback? Are you going to scale down the shares in order to reset that dividend commitment? And I'll leave it there, Steve. Thanks.
Stephen I. Chazen - President and Chief Executive Officer:
Yeah, I'll answer that for now. And we've talked about this a lot; it's not some new topic. If we concentrate the Middle East on the long-lived projects, that'll generate relatively more free cash flow. In fact, if we stopped investing in the so-called non-core group, we'd have more cash flow than we have now. So they're basically users of cash for either overhead or whatever. And so we think we could improve the cash flow out of the Middle East with that. The CO2 businesses and the chemical business, chemical business will finish the cracker here in a year or so. The cash flow will improve there. We think the dividend will be fairly easy to maintain. However, it will require some shrinkage of the shares; there's no question about that. And so one of our objectives over the next timeframe would be to shrink the shares and therefore reduce the dividend, especially at the current prices of the stock, where the dividend yield is exceptionally high.
Doug Leggate - Bank of America Merrill Lynch:
Appreciate the answer, Steve. Thank you.
Operator:
Our next question is from Ed Westlake of Credit Suisse. Please go ahead.
Edward G. Westlake - Credit Suisse Securities (USA) LLC (Broker):
Yes. Good morning, Vicki, back onto the Permian, if I may. So you've got this $6.2 million target for well costs – I think that's what Evan was trying to get to – to see where that could get down to. What the limit you think is on that? And then I've got a follow-on about recoveries.
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
The $6.2 million is the target, but we feel like that we still have opportunities to lower beyond that. We actually have achieved that with some of our wells, but we're just not achieving that on the average yet. We're still seeing opportunities; the teams are working on new ideas. I think that there's a good possibility we could get below the $6.2 million. Not only that target in the Delaware Basin but our targets in the Midland Basin as well. They're making some really good progress, doing some very good work modeling.
Edward G. Westlake - Credit Suisse Securities (USA) LLC (Broker):
The other experiment you that you spoke about on the last call, obviously making progress on landing zones, proppant intensity, and cluster spacing, all of these things that the industry's using. And we're seeing some individual well results that you flagged out, for example, in the Delaware on slide 30. And the average is kind of static. So I'm just kind of wondering if there's a sort of help you can give us in terms of where you think you could get to from these spot wells – they could be sweet spots – versus the average that you're delivering across the play?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Yeah, what we're trying to do in the Delaware Basin, I think I mentioned before, is that the 3D seismic that we're acquiring, that would be something that could help us identify – or actually it's the next step to high-grade the locations that we drill. So it's not – as we've said before, it's not only about where you place the well within the interval, but where you drill the well, too. And our basin modeling, which has recently been updated, that's another tool that we think is going to help us continue to move the average up a bit. So we think that those two tools, the basin modeling where we've done a lot of geochem work and updated our petrophysical models, the 3D seismic now, we're in the process of acquiring that. We should be able to have that processed and begin interpretation by the end of the year. So that should help to impact the 2016 program.
Edward G. Westlake - Credit Suisse Securities (USA) LLC (Broker):
Okay. Thanks very much.
Operator:
Our next question is from Leo Mariani of RBC. Please go ahead.
Leo Mariani - RBC Capital Markets LLC:
Hey, guys. Just question around Al Hosn here. I think you guys previous had a target of 60,000 barrels a day to eventually hit. You think that target's still realistic, and is that something we might get to in 2016?
Stephen I. Chazen - President and Chief Executive Officer:
Well, the answer is yeah, it's realistic. They could in theory do better than that. It's running – if you look at the numbers – more liquids rich than we had originally forecasted, and we see that continuing. So you're going to wind up with probably more liquids, I think. I think with a little luck we'll get to it by year-end, but if not, certainly by the first quarter.
Leo Mariani - RBC Capital Markets LLC:
Okay, that's helpful. And I guess just with respect to your comments around CapEx, obviously you guys are seeing CapEx move lower here in the second half of 2015. I know you guys previously had said that you might underspend the 2015 budget of the $5.8 billion. Is that still possible here? Because I know it sounds like you guys maybe have probably higher Permian drilling activity. Just trying to get a sense of where that spend may go.
Stephen I. Chazen - President and Chief Executive Officer:
I think the driver isn't the Permian. The Permian is well-managed. The question is the part that's not really in our control, which is some of the Middle East stuff. And, again, I think if we – effectively, if you put – it's not totally in our control because you have the issue with the not (43:57) foreign governments. So if we spend a little more or a little less, that really just affects the amount of – number of barrels we'll get back within six months. So that's about the only thing about the capital that I think is – what's within our control would be lower, effectively, than that, but there's a part of it that's really not in our control.
Leo Mariani - RBC Capital Markets LLC:
Okay. That's helpful. And I guess, just to be clearer on your intentions for next year, if prices stay low, at $50, you guys have these 12 rigs in the Permian, is that likely to stay at 12? Or potentially could you cut it back further next year?
Stephen I. Chazen - President and Chief Executive Officer:
Well, it just depends on what the price is. 12 is, I think, a reasonable guess for now, but we would – even in a more stable price environment, we would have a hard time at this point of the year in making a sensible outlook for next year. We could make one up, but I think it's hard to make sensible outlook for next year, even now, with the volatility of the prices. We're loath to say exactly what we're going to do. The intention is that we'd like – I think we can make – fairly straightforwardly make cash flow neutrality in a $60 environment. The question is can we make it in a $55 environment, and I just don't know that yet, but we're certainly going to try.
Leo Mariani - RBC Capital Markets LLC:
Okay. So it sounds like cash flow neutrality would be the overarching theme for next year.
Stephen I. Chazen - President and Chief Executive Officer:
You can't just run for the rest of your life outspending your cash flow. I mean, you can do it for a year, maybe two years, but that can't be a business model for any ongoing enterprise, although obviously there are companies that have been doing it for a decade, so.
Leo Mariani - RBC Capital Markets LLC:
Okay. Thanks, Steve.
Stephen I. Chazen - President and Chief Executive Officer:
Thanks.
Operator:
Our next question is from Ryan Todd of Deutsche Bank. Please go ahead.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great, thanks. Good morning. Maybe if I could start in the Permian as well. The addition to the well inventory was great to see. And I realize some of that is on the modeling side, but can you talk maybe a little bit of – it looked like there were additions across a variety of zones. With the new model and as you continue to drill, is there any zone in particular where you're seeing particularly strong improvements or where your view may be changing at all in the basin?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Yeah, I would say that our view changed a little bit in the Midland Basin, where we thought at the beginning of the year that the Spraberry would be the best interval for us in the Midland, but now we're seeing the Wolfcamp A and both the Merchant area and the Big Spring area as looking very, very good. So that was a positive sign for us. So we have now three intervals – the Wolfcamp A, Wolfcamp B, and Spraberry – that are economical to develop in the Midland Basin. And in the Delaware, what we're doing there is we're trying to stay very focused this year on developing what we plan to develop so that we have the infrastructure in place and that we maximize the use of that infrastructure as quickly as we can before we move on to other intervals in other areas. Two of the things that we're seeing is that the third Bone Spring and the Avalon are actually starting to look very good for us around our acreage, and so we're modeling that now. And actually we'll certainly, we think, unless we just have significant improvements in some other intervals, both of those intervals will be a part of our 2016 development program.
Ryan Todd - Deutsche Bank Securities, Inc.:
That's great. Are you still increasing lateral lengths in either basin, or where are you on that front at this point?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Yeah, actually in the Midland Basin what we're doing there is we've drilled anywhere from 4,500 feet up to 10,000 in the Delaware Basin, and our current average there is about 6,800. But we're trying to, where we can, target drilling 7,000 to 7,500 in the Midland Basin. In the Delaware, we've drilled up to about 7,850. And actually, our average in the Delaware Basin probably is around 4,500 there. We're expecting to, in that basin, have a minimum of 4,500 going forward in the future and would like to drill maybe in the 5,000 to 5,500 range.
Ryan Todd - Deutsche Bank Securities, Inc.:
Okay, great. And maybe if I could ask one on the overall U.S. portfolio, you discussed a little bit your views on the Middle East up to this point, but where do you stand at this point on portfolio, kind of on the state of the U.S. portfolio? The dust has settled a bit on some of your 2014 activity. Are there still assets that you would view as non-core at this point that you could potentially look to market?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
The assets that we'd consider non-core in the U.S. are still Williston and Piceance. We have a South Texas asset that, when liquids prices are good, it's a great project. And actually, we have a lot of work that we could do at South Texas. The team down there has worked up a lot of potential workovers. We have a lot of drilling prospects on our South Texas acreage. So I'm just going to use this opportunity to say that, even though we're not investing growth capital dollars in any of those three assets, those teams have done an incredible job to manage their base production and optimize it, and they're optimizing it with minimal expense of any kind. They're doing a tremendous job. So we still consider there to be a lot of potential in South Texas. Williston, we simply want to monetize because of the fact that we don't have a lot of running room there. We started some larger completions at the end of last year in the Williston Basin that really showed significant improvement in our well productivity there, but because of our running room, because of the differential in the Williston, it just can't compete with our Permian Basin assets, and we don't think it ever will. So we do want to monetize it, along with the Piceance.
Ryan Todd - Deutsche Bank Securities, Inc.:
Okay, great. Thank you. I'll leave it there.
Operator:
Our next question is from Paul Sankey of Wolfe Research. Please go ahead.
Paul B. Sankey - Wolfe Research LLC:
Hi. Good morning, everyone. Could I just jump back to the cash flow neutrality debate? What would the volume outlook be in that situation, Steve? Are we just talking about staying flat or some sort of growth?
Stephen I. Chazen - President and Chief Executive Officer:
There'd be growth in the volumes. The reason we're investing is to grow the cash flow, so, yeah, it isn't going to be a flat volume situation. We have our own outlooks for the end of the year, what the fourth quarter production will look like, volumes, and the same thing with some view into the first quarter of next year. So I think, generally speaking, it isn't just what we have but also what we see. But I think also, I think the capital, the cracker expenditures will fall next year. Some of the midstream expenditures will fall. So the amount of capital, which doesn't add to volumes, will decline next year. So I think time we get through, I think, we're fairly close to where we need to be. I mean, we generated cash from operations in this past quarter about $1.5 billion before working capital changes. So you're talking about a $6 billion sort of run rate. Our capital spending next year would be well below the current $5.8 billion number. So it's pretty much in sight – you get a little improvement in chemicals and a few more dollars really in oil price. What's really held us back more than anything is probably NGL pricing. We weren't as negative as it turned out to be, so that's another area where I think we've been – we've been more disappointed, frankly, in NGL pricing than we have the oil pricing, which is very similar to our outlook.
Paul B. Sankey - Wolfe Research LLC:
Sure. You said that you were struggling to think about cash flow neutrality at $55. I'm not clear why that would be so much more difficult than thinking about it at $60.
Stephen I. Chazen - President and Chief Executive Officer:
It's another $500 million.
Paul B. Sankey - Wolfe Research LLC:
Yeah, okay. And I guess ultimately you've said many times that you need to grow production if you're going to grow the dividend basically, right?
Stephen I. Chazen - President and Chief Executive Officer:
I need to grow production if I want to grow the dividend. I need to grow production if Vicki's going to attract the kind of employees she'd like to have. I think a stagnant business generates a stagnant workforce.
Paul B. Sankey - Wolfe Research LLC:
The alternative would be, I guess, just to sell Oxy if you can't make it, right?
Stephen I. Chazen - President and Chief Executive Officer:
Yeah, I think that you can ask her about that next quarter.
Paul B. Sankey - Wolfe Research LLC:
Uh, Vicki – all right. Thanks a lot.
Operator:
Our next question is from John Herrlin of Société Générale. Please go ahead.
John P. Herrlin - SG Americas Securities LLC:
Yeah, hi. Given all of the efficiency savings you're getting in the U.S. and the Permian on drilling and completion and all that, do you have a sense of where you think your DD&A rates will go to on kind of a normalized basis?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
I think our DD&A rates are – you're talking about for the Permian Resources business in particular?
John P. Herrlin - SG Americas Securities LLC:
Yes.
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
We're certainly headed toward DD&A of less than $15, and that sort of depends in terms of where it eventually lands, depends on our infrastructure and how we can optimize that. Thus far, we've done a really good job of building water-handling infrastructure and gas processing, gas to sales, gathering systems. So as we continue to optimize that, part of the reason that we're developing the way we are is to ensure that over time we can develop our reserves and minimize the facilities costs. So we're trying to spend the bulk of our dollars on getting the reserves out of the ground. Ultimately, we're putting together these lots of field (54:38) depletion plans, which help us to do that, and our target is to always make sure that our development of any particular area is with less than 10% of the capital spent on facilities and infrastructure.
Stephen I. Chazen - President and Chief Executive Officer:
As we look at DD&A, just to give you an accounting sort of answer, as you look to DD&A, you've got the historical costs when oil was $100 that are built up in there. We're adding at basically well below $15 currently, and so the finding cost currently, the incremental finding cost, is quite low. And so it just will take a while to roll through the old stuff, so it's probably going to take a couple of years or something to sort of get the bulk of the adds at the low F&D. So I think putting aside product price changes, you'll see a decline in the real finding costs over time.
John P. Herrlin - SG Americas Securities LLC:
Great. Yeah, I was just wondering about the timing of it.
Stephen I. Chazen - President and Chief Executive Officer:
It just depends on how fast you DD&A the historic cost, because that's what's holding it back.
John P. Herrlin - SG Americas Securities LLC:
Okay, great. Next one for me is on Howard County. You said you had some very good performers there, and it's newly acquired properties. Is that something that you would accelerate? Or it's just part of the program?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Actually, we're trying to stay disciplined in terms of how much we accelerate, so we'll do more drilling there. We do have drilling planned there. It'll be at a moderate pace through this year because we have other areas that are pretty good as well. If we see over time that, on a consistent basis, that that's tremendously higher than anything else we have in the Midland Basin, we'll certainly go over and try to accelerate that, but with minimal incremental cost.
John P. Herrlin - SG Americas Securities LLC:
Great. Thank you.
Operator:
Our next question is from Scott (sic) [Matt] Portillo of TPH. Please go ahead.
Matthew M. Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Good morning, all. Just a quick question on the Permian. I wanted to follow up in regards to the inventory update. I was curious, as we think about both the Wolfcamp A and the Wolfcamp B, what are some of the underlying assumptions from a downspacing perspective? And if you're testing any further downspacing in regards to stacked staggered development in the play?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
In the Wolfcamp A and the Wolfcamp B, we're being very careful not to downspace too much. So we have some pilots in place, and we have some reservoir modeling ongoing to ensure that we're spacing those wells appropriately. We're not going to drill wells where we have interference issues, so we're trying to maximize the reserves we get on a per-well basis. So downspacing is not something that we've built into our program. However, the staggered completions between the Wolfcamp A and B is something that certainly we're going to do to ensure that there's no risk of communication between a Wolfcamp A and a Wolfcamp B well.
Matthew M. Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Great. And just a follow-up to both the inventory update in the Wolfcamp B and then just potentially some color around well performance, you've provided a lot of detail in the past on the Wolfcamp A 30-day rates, and I think you've mentioned a type curve of up to 900,000 MBOE for your short laterals. I was curious how the Wolfcamp B wells look in comparison to that, and as we think about kind of the inventory added from 650,000 to 800,000, (58:22) was that based on delineation of additional wells on your acreage in the basin?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
Yeah, the incremental wells was additional delineation, and the Wolfcamp B, with respect to the Wolfcamp A, is – while the Wolfcamp B is prospective and delivers some better than cost of capital returns, it's not as prolific as the Wolfcamp A in either the Midland Basin nor the Delaware. However, we think there are opportunities to continue to improve the recovery from the Wolfcamp A, where we're doing, as I said, on each of our target intervals more modeling to try to get to the point where we can optimize the Wolfcamp B.
Matthew M. Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.:
Thank you very much.
Operator:
Our last question today comes from Brian Singer of Goldman Sachs. Please go ahead.
Brian A. Singer - Goldman Sachs & Co.:
Thanks. Good morning. If we look at – on slides 29 and 32, you highlight your focus acreage in the context of your broader large Permian position. Can you update us on strategically your plan for the acreage within the Delaware and Midland that are not in the focused acreage, either to delineate, to sell, or to hold, whether those priorities change in a low oil environment? And then also your level of interest and realistic opportunity to expand your acreage positions in the Permian proximate to your focus acreage?
Vicki A. Hollub - President, Oxy Oil and Gas – Americas:
So we have no intention to sell any of our acreage that's designated non-focus right now. The difference between our focus areas and not is the fact that our focus areas are those that we feel like we could put in development mode today or are in development mode today. The ones that are not considered focus right now are the ones that are still in appraisal mode, and we consider those areas to be prospective, but in the interest of trying to ensure that the infrastructure dollars that we spend are used and we get the benefit of that quicker, we're being pretty disciplined about where we spend and how we develop. So the non-focus areas are ones that we're preparing for development in the future. We at this point today don't have any acreage that we would consider for sale today. We have some acreage that falls way down the priority list and are things that we would get to years and years from now, so that, at some point, we might take a look at. Do we try to trade that to move into areas where it better fits where we're currently operating? And in terms of continuing to appraise, we still have the Central Basin platform where we haven't been drilling as of yet, or many unconventionals. I think we have a couple drilled, but we still have that to assess. So the good thing is that we have a tremendous inventory. The challenge with that is we're always looking at ways to try to accelerate but to do it in a way that's not value destructive. And so we're trying to moderate our pace and trying to ensure that we have things fully evaluated before we move to development.
Brian A. Singer - Goldman Sachs & Co.:
Great, thanks. And my follow up is on the midstream marketing business. Can you just talk to what you all see as the ongoing cash generation potential there and then how you're thinking about that business strategically?
Stephen I. Chazen - President and Chief Executive Officer:
Yeah, I think that it's still in a heavy – and basically it's supportive of the Permian business. That's really what it does. And they're still really spending more money than they're taking in, because they continue to build out to support the production business. People talk – it doesn't make any sense to us, given our financials position, to do anything to increase the fixed charges against the rest of the business by selling debt-like instruments called MLP units that go against that and increase our fixed charges. Fixed charges are okay at $100 oil, but not so much fun in a $50 environment, and I think that's – people miss that, that – just like interest. So I think on the cash flow generation, right now it basically is neutral to maybe slightly negative, as they continue to build out either gas plants or pipelines. At some point I think it'll probably generate $400 million, $500 million a year in free cash flow, but I think we're probably a year or two from that.
Brian A. Singer - Goldman Sachs & Co.:
Great. Thank you very much.
Operator:
This concludes today's question and answer session. I'd like to turn the conference back over to Mr. Degner for any closing remarks.
Christopher M. Degner - Senior Director-Investor Relations:
Thank you, everyone, for joining our call today. And I know it's a busy season. Thanks.
Operator:
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Christopher M. Degner - Senior Director, Investor Relations Stephen I. Chazen - President, Chief Executive Officer & Director Christopher G. Stavros - Executive Vice President & Chief Financial Officer Vicki A. Hollub - President, Oil & Gas Americas Edward A. Lowe - Vice President and President, Oil and Gas International Production
Analysts:
Doug Leggate - Bank of America – Merrill Lynch Evan Calio - Morgan Stanley & Co. LLC Guy Allen Baber - Simmons & Company International Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Ryan Todd - Deutsche Bank Securities, Inc. Roger D. Read - Wells Fargo Securities LLC Paul B. Sankey - Wolfe Research LLC John P. Herrlin - SG Americas Securities LLC
Operator:
Good morning, and welcome to the Occidental Petroleum Corp. first quarter 2015 earnings conference call. All participants will be in listen-only mode. After today's presentation there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Mr. Chris Degner, Senior Director of Investor Relations. Please go ahead, sir.
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Rocco. Good morning, everyone, and thank you for participating in Occidental Petroleum's first quarter 2015 conference call. On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer; Vicki Hollub, Senior Executive Vice of Occidental and President, Oxy Oil and Gas; Chris Stavros, Chief Financial Officer; Willie Chiang, Executive Vice President of Operations; and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment I will turn the call over to our CEO, Steve Chazen, who will provide an updated outlook for 2015. Our CFO, Chris Stavros, will review our financial and operating results for the first quarter and also provide some guidance for 2015; followed by Vicki Hollub who will provide an update of our activities in the Permian Basin. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause the results to differ is available on the company's most recent Form 10-K. Our first quarter 2015 earnings press, the Investor Relations supplemental schedules, our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Steve Chazen. Steve, please go ahead.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thank you, Chris. Yesterday we announced that Vicki Hollub has been named to head our worldwide oil company and will succeed me as CEO when I retire. Both of us will be visiting shareholders either at conferences or in their offices over the next few months. My commitment is to remain in place until the board and Vicki feel it is time for me to move on but not any longer. Vicki has worked for Oxy for over 30 years. She's had a number of very challenging assignments over the years including operations manager in Ecuador and Russia. In our California assets, she reorganized the business and changed its processes so that it would be stable in a wide range of product prices. She has built our Permian Resources business into a sustainable, profitable growth engine for Oxy. She's an accomplished team builder, has the confidence of executives and employees throughout the business. She also has had the misfortune of officing next to me for the last couple of years. The Board, of which I'm a part, has worked on this succession plan for the last two years. The directors interviewed a number of executives and considered both internal and external candidates. In the current volatile business climate, our view is that an experienced, successful executive who knows our business well is the best choice. You will find Vicki to be a thoughtful, engaging and agent of change for Oxy. Yesterday we also announced a dividend increase of just over 4%. This is our 13th consecutive year that we've raised our dividend. We carefully considered our future capital needs and likely cash flows. Our current estimates are that we should be able to continue to grow our dividend for many years into the future. The new ethylene cracker, which comes on in 2017, provides a substantial boost in distributable cash from our already-important chemical business. Our base oil business in Abu Dhabi, Oman and the Permian EOR will all support our cash flow and grow modestly over time. Without profitable growth the company will not prosper. High rates of growth and cash flow and profits will come from our Permian Resources business. We remain mindful of the need to pay close attention for drilling for profits not just volume growth. Our overall financial strength gives us confidence that we'll be able to spend what we need in a range of product prices and still grow our dividends. I'd like to lay out our goals for 2015 and how we have planned to adjust to lower commodity prices. Our principal goal for the year is to achieve cash flow neutrality where our operating cash flow covers our capital spending and dividend outlays by the fourth quarter of this year at around $60 per barrel oil prices. We will achieve this goal through deploying our capital and operating cost savings into further production and cash flow growth driven mostly by our Permian Resources segment and the startup of the Al Hosn gas project. Year-to-date we estimate that about $400 million is in captured cost reductions. We expect our 2015 capital outlays to be less than our $5.8 billion budget and some of the savings will be redeployed into Permian Resources. In short we are learning to do more with less and expect continued improvement in productivity through the year. The Permian Resources segment has made considerable progress over the last six months improving our capital efficiency. As slide six illustrates we have at least 16 years of inventory with returns that exceed our cost of capital at oil prices less than $60. Through continued reduction in drilling and completion costs, improvements in productivity, we will lower our finding and development costs and increase our inventory of well locations with returns that exceed our cost of capital. In addition to improved capital efficiency, we expect to see improvement in our cash operating costs with reduced workload activity, lower energy costs and a larger base of production. This improved cost structure gives us confidence in driving production growth. In the first quarter of 2015 we grew U.S. oil production by 9,000 barrels a day, a 5% gain over quarter-over-quarter and 14% year-over-year. Production growth was driven by our Permian Resources assets which produced 98,000 BOE a day in first quarter of 2015, a 46% increase year-over-year. Oil production growth in Permian Resources was stronger with a 25,000 barrels per day increase year-over-year. Given the strong start to 2015 we are increasing our full year guidance for the Permian Resources segment from 100,000 BOE a day to 105,000 to 108,000 BOE per day. The Al Hosn gas project started up in January with one train online. During the start-up process production was curtailed to modify the sulfur and NGL processing units. These adjustments were completed in late April and the plant was restarted. We expect to ramp-up production through the second quarter and to average (7:13) we expect production of 35,000 BOE a day with the plant running at full capacity in the second half of the year. Despite a lower capital program we expect production growth of 60,000 to 80,000 BOE per day in 2015 driven by the start-up of the Al Hosn gas project and the focused development program we will run in our Permian Resources segment. In the United States we expect oil production growth of about 8% partially offset by declines in NGLs and natural gas production. Vicki Hollub will provide further details in the outlook for the U.S. oil and gas business. As we capture price savings from suppliers and improve the efficiency of operations we are able to do more with less spending. Our capital run rate in the first quarter was higher than the $5.8 billion full year level and will decline through the year given our large acreage position, deep inventory with the flexibility to defer drilling and appraisal activities. Although we will likely outspend our cash flow in the first half of the year, we expect that by the fourth quarter our operating cash flow will cover our capital expenditures and dividend payments, assuming a $60 per barrel oil-price environment. We have approximately 69 million shares remaining on our current share repurchase authorization. We will continue to repurchase shares subject to stock price and market conditions and expect to ultimately repurchase the entire amount. Now I'll turn the call over to Chris Stavros for a review of our financial results.
Christopher G. Stavros - Executive Vice President & Chief Financial Officer:
Thank you, Steve, and good morning, everyone. We generated core income of $31 million for the first quarter of 2015 resulting in diluted earnings per share of $0.04, a decrease from both the year ago quarter and fourth quarter of 2014. The decline in core earnings is primarily due to lower commodity prices for all products. Our realized oil price for the first quarter of $48.50 a barrel was down about $23.00 a barrel sequentially. U.S. natural gas prices also declined, down more than a dollar, to about $2.50 per MCF. NGL prices also fell sharply to just under $18 a barrel in the first quarter, down about 35% from last year's fourth quarter. In response to the current price environment we have aggressively ramped down our capital program focusing our development activity in our core areas of the Permian Basin and parts of the Middle East with an emphasis on growing our production volumes more efficiently. We have also renegotiated many of our supplier contracts which should result in meaningful savings this year, which Steve outlined. The combination of reduced drilling activity, the wind down of spending for the Al Hosn project, and improved well cost efficiencies resulted in our total capital spending falling to $1.7 billion in the first quarter from $3 billion in fourth quarter of last year. As Steve noted earlier, we expect to be running cash-flow neutral after capital spending and payment of our dividends by the fourth quarter this year at oil prices of roughly $60 a barrel. Despite the cut in capital, we continued our strong domestic production growth generated from our Permian Resources assets. Permian Resources grew its oil production 68% in the first quarter, adding 25,000 barrels per day compared to the year-ago period with total BOE growth of 46%. Permian Resources oil production improved by 11,000 barrels per day or 22% sequentially to 62,000 barrels a day in the first quarter. Turning to the specific business segments, oil and gas core after-tax earnings for the first quarter of 2015 were $109 million, $259 million lower than the fourth quarter of 2014 and $851 million lower than last year's first quarter. For the first quarter of 2015, total company oil and gas production volumes averaged 645,000 BOE per day, an increase of 29,000 BOE in daily production from the fourth quarter and 72,000 BOE per day from the same period a year ago. As I mentioned earlier, our first quarter of 2015 worldwide realized oil price fell sharply, declining by 32% and 51% compared to the fourth and first quarters of last year. After-tax core results for our domestic oil and gas operations were a loss of $89 million, compared with income of $59 million in the fourth quarter of 2014 and income of $412 million in the first quarter of 2014. Results on both a sequential and year-over-year basis at our domestic operations were severely impacted by much lower realized oil prices, and to lesser degree, lower NGL and natural gas prices. The negative price impact was partially offset by lower DD&A rates and higher crude oil production volumes for both comparative periods. Total domestic oil and gas production averaged 326,000 BOE per day during first quarter of 2015, up 5,000 BOE per day sequentially and 24,000 BOE per day on a year-over-year basis, with substantially all of the increase coming from Permian Resources. Domestic oil production was 198,000 barrels per day during the first quarter of 2015, an increase of 9,000 barrels per day from the fourth quarter and 25,000 barrels per day from the year-ago quarter. International after-tax core income was $200 million for the first quarter of 2015 compared to $355 million from the fourth quarter and $553 million from the same period last year. The decline for both periods was driven by lower realized oil prices. International oil and gas production volumes rose by 24,000 BOE per day on a sequential quarterly basis to 319,000 BOE per day in the first quarter of 2015. Approximately half of the increases to production both year-over-year and sequentially resulted from lower prices affecting our production sharing contracts. Commencement of production from the Al Hosn gas project added 9,000 BOE per day in the quarter. Production at Al Hosn for the quarter was less than anticipated as during the start-up of production, during the ramp, we experienced some commissioning-related issues on the sulfur recovery units. Modifications have now been made and we anticipate reaching full productive capacity at Al Hosn over the coming months. Our oil and gas cash operating costs fell to $13.36 per BOE for the first quarter of 2015 compared to $14.18 from the fourth quarter of last year due to the benefit of higher production and lower energy costs. DD&A for the first quarter of 2015 was $15.35 per BOE compared to $18.09 per BOE during the fourth quarter. Taxes other than on income which are directly related to product prices were $1.63 per BOE for the first quarter of this year compared to $2.45 per BOE for the full year of last year, 2014. Our first quarter exploration expense was $8 million. Chemicals first quarter 2015 pre-tax core earnings were $139 million compared with $160 million in the fourth quarter and $136 million in the same period a year ago. The sequential decrease in earnings primarily reflected lower prices for most product lines and lower caustic soda volumes products, partially offset by lower ethylene and natural gas feedstock costs. Midstream pre-tax core results were a loss of $5 million for the first quarter compared to income of $168 million in the fourth quarter and $96 million in the same period a year ago. The decline in results for both comparative periods was caused by several factors including lower marketing margins as a result of tighter Midland to Gulf Coast crude oil differentials, lower gas plant income which reflected sharply lower NGL prices, lower pipeline income due to a turnaround at the Dolphin plant, as well as lower third party gas sales combined with the impact from our reduced ownerships in the Plains Pipeline GP after the fourth quarter sale of a portion of these units. Our cash flow from continuing operations before working capital changes was approximately $1.1 billion for the first quarter of this year. During the fourth quarter of 2014, our accrued capital spending and operating expenses were based on a work program that was significantly higher than the first quarter of this year. As we ramped down activity in the first quarter, our capital accruals declined and our net working capital declined. We used about $1 billion in the first quarter of 2015 for payments related to the higher capital operating expenses that were accrued at year end 2014. As we continue to reduce activity in the second quarter, we expect to see further working capital usage as we reduce our accounts payables. However, we expect this to be at a lower rate. This trend is normal in a commodity down cycle and one that we would expect to dissipate by the third quarter as we reach a more stable level of capital spending. Should we see a continued recovery in crude oil prices and increase our drilling activity, we would expect this trend to reverse and see positive working capital movements. Total company capital expenditures for the first quarter of 2015 were $1.7 billion and we expect our quarterly expenditures to continue to ramp down through the year. Oil and gas spent $1.5 billion with Permian Resources expenditures comprising nearly 50% of the total, with the remaining $200 million split about evenly between chemicals and midstream. Based on our lower pace of spending in the first quarter and continued cost efficiency gains, we expect our total capital spending for the year to be below our original guidance of $5.8 billion. Our fourth quarter 2015 exit rate of capital would imply an annualized spending level of approximately $4 billion. We paid cash dividends of $557 million in the first quarter and purchased 2.7 [audio skip] (16:51) of our shares for $207 million. Our cash balance at the end of the first quarter of 2015 was $5.4 billion. As a reminder, we currently hold shares in the Plains GP and California Resources Corporation with an aggregate value of about $3 billion. With respect to CRC we continue to own 71.5 million shares currently valued at about $600 million. We are required to dispose of all of these shares within approximately a year through either a dividend to our shareholders or in an exchange for either Oxy shares or debt. Our debt-to-capital ratio was 17% at the end of the first quarter 2015. The worldwide effective tax rate on our core income was 75% for the first quarter of 2015. The increase in the rate reflects a higher proportion of international income for the first quarter. With respect to our oil and gas production, domestically, we expect our oil production for the second quarter to grow by 5,000 barrels per day with the increase coming from Permian Resources. Permian Resources is expected to grow its overall volumes by more than 7,000 BOE per day in the second quarter. Our Midcontinent gas production is expected to decline from the first quarter levels resulting in an overall domestic sequential growth rate of at least 4,000 BOE per day. We expect our international production volumes to increase by about 15,000 BOE per day in the second quarter. The increase should come primarily from improving production rates at Al Hosn which we expect to be about 25,000 BOE per day, and offset by the loss of production in Yemen due to the civil unrest and security issues in the country. Although the contract in Yemen was set to expire at the end of this year, we anticipate no further production volumes from the country in 2015. For reference, Yemen contributed approximately 9,000 barrels per day in the first quarter. As Steve mentioned in his opening remarks we have raised our full year 2015 guidance for production growth to a range of 60,000 to 80,000 BOE per day, an increase of 20,000 BOE per day versus our previous guidance. We expect full year production in Permian Resources to be in the range of 105 and 108,000 BOE per day, a year-over-year increase of more than 40%. Overall, domestic volumes are expected to increase to over 325,000 BOE per day, at least 5% higher than 2014. Internationally we expect full year volumes from Al Hosn to be approximately 35,000 BOE per day. Should oil prices move higher, our production volumes could be negatively impacted by our production sharing contracts. Price changes at current global prices affect our quarterly earnings before income taxes by $30 million for a dollar per barrel change in oil prices and $7 million for a dollar per barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pre-tax earnings by about $15 million. Our second quarter 2015 exploration expense is anticipated to be about $35 million pre-tax. We expect our second quarter 2015 pre-tax chemical earnings to be about $185 million, and second quarter midstream earnings should be in the range of $100 million pre-tax as we anticipate higher gas sales from the Dolphin pipeline and improved marketing margins as a result of wider inland versus Gulf Coast crude oil price differentials. We expect our interest expense to rise to about $42 million in the second quarter from $28 million in the first quarter as the start of Al Hosn reduces our capitalized interest. Using current strip prices for oil and gas we expect our 2015 domestic tax rate to be 36% and our international tax rates to remain at about 65%. To summarize, we've demonstrated strong year-over-year production growth of nearly 13% in the first quarter bolstered by our Permian Resources unit. The performance of this business combined with growing volumes from Al Hosn provides us with confidence to raise our guidance on 2015 production growth. We expect the growth in our volumes combined with the reduction on our capital spending and improving efficiencies to lead us to a cash flow neutral position by the fourth quarter at oil prices of around $60. I'll now turn the call over to Vicki Hollub who will provide an update on our operations in the Permian Basin.
Vicki A. Hollub - President, Oil & Gas Americas:
Thank you, Chris. Today I'll first review the highlights of our Permian Resources and Permian EOR activities in the first quarter, and then I'll provide guidance on our program for remainder of 2015. I'd like to highlight a few key messages. First, Permian Resources performance is exceeding expectations. Second, our core Permian unconventional programs generate strong returns in the current environment and we believe they will get even stronger through our focus on execution excellence. Finally, our Permian portfolio is unmatched in the industry. The combination of our assets in Permian Resources and EOR along with the expertise and commitment of our teams will allow us to grow the business and live within cash flow in a $60 oil environment. In the first quarter Permian Resources achieved daily production of 98,000 BOE per day which is a 17% increase from the 84,000 BOE per day that were produced in the fourth quarter, and a 46% increase versus the prior year. With regard to oil, we produced 62,000 barrels per day for the first quarter. This is a 68% increase from a year ago and a 22% increase from the previous quarter. We would have achieved even higher production, but were negatively impacted by approximately 4,000 BOE per day by winter weather events in January. During the first quarter, our capital expenditures were $728 million. We operated 25 rigs and drilled 86 wells including 61 horizontal wells. We placed 126 wells on production including 67 horizontals. This is an increase of 20 horizontal wells from the previous quarter. At the end of the quarter 16 wells were on flow back and 48 were not yet completed. Permian Resources has a large inventory of profitable wells to develop in a low price environment and we are successfully implementing four actions that are reducing the economic hurdle point of our inventory. First, we are investing reservoir characterization and optimization to improve well productivity. Second, we are applying enhanced manufacturing principles to improve time to market and reduce costs. Third, we are aggressively working with suppliers to lower cost. Lastly, we are enhancing base management and maintenance operations to maximize production at minimal operating cost. In the fourth quarter of last year we began transitioning from appraisal mode to a targeted development program utilizing a manufacturing approach combined with integrated planning and engineering. This has reduced nonproductive time, maximized the efficiencies of pad drilling including the use of zipper fracs, and has reduced infrastructure cost. As a result of efforts we have achieved significantly improved well delivery and well costs. In the Delaware Basin our Wolfcamp A 4500-foot well cost decreased by 24% from 2014's cost of $10.9 million to a current cost of $8.3 million. We reduced our spud to rig release time by 17 days from 2014's average of 43 days to March's average of 26 days. In the Midland Basin we reduced the cost of our Spraberry 10,000-foot wells by 19% from 2014's cost of $9.7 million to a current cost of $7.9 million. In New Mexico we reduced the cost of our Bone Spring wells by 14% to $5.7 million. These reductions were achieved by implementing design enhancements such as two-string casing design, optimizing bottom hole assemblies and bits, and utilizing drilling dynamics to improve rates of penetration. Additionally we continue to achieve reductions in our commercial rates. Based on the results achieved so far, we are confident that by the end of this year we can achieve an average well cost that is 20 to 25% lower than in 2014. In the Delaware Basin we've currently identified 4,600 horizontal development locations. We have 1,500 horizontal locations ready for development, including 800 sites in the Wolfcamp A bench. The majority of these locations are in our operated areas of Reeves County. In New Mexico, our Bone Spring potential is equally as significant, with 1,500 potential locations. And in the Delaware in Q1 we operated 10 horizontal drilling rigs and two vertical rigs. We drilled 45 wells and placed 64 wells on production. In Barilla Draw we placed 18 horizontal wells on production in the Wolfcamp A benches. These wells achieved an average peak rate of 1,371 BOE per day and a 30-day rate of 1017. In the last call I discussed the Peck State 258 #6H well which achieved a 30 day rate of 1,760 BOE per day. I'm excited to report this well is still producing over 1,000 barrels of oil per day after four months of production. We continue to achieve encouraging results with our efforts to improve landing zones, optimized cluster spacing, and increased sand in concentrations. For example our Eagle State 28#6H well reached an average peak rate of 2037 BOE per day and 30 day rate of 1470 BOE per day. Additionally, our Peregrine 27#8H well achieved peak rate of 1768 BOE per day and 30 day rate of 1309 per day. In New Mexico, the performance of our Bone Spring wells continues to exceed our expectations. Recently our Cedar Canyon 15 Federal 5H was placed online with an average peak rate of 1322 BOE per day and a 30 day rate of 1127. In the Midland Basin, we've currently identified 2500 horizontal well locations with 1,050 in Spraberry and Wolfcamp A and B benches. In the first quarter here we operated 11 horizontal drilling rigs and two vertical rigs. We drilled 41 wells and placed 62 wells on production. Now I'd like to update you on Merchant, which is a new area in the Midland Basin that we mentioned last quarter. We launched into development mode early in this area and are drilling multi-well pads along with zipper frac completions. Our Wolfcamp A and B have achieved an average peak rate of 1408 per day, a 30 day rate of 1145 and a 60 day rate of 844. Our current well cost is $7.9 million, but we expect to lower it to $6.9 million as we move forward. The Merchant 1411A well that we discussed last quarter achieved six months' cumulative oil production of 100,000 barrels and equivalent production of 108,000 BOEs. I'd also like to provide an update on our Permian EOR business which provides a stable and low decline base to our production at an advantaged cost. As we discussed last quarter our Permian EOR business remains profitable in the current downturn and we are continuing to make investments in these projects that significantly increase oil production from our portfolio of large conventional reservoirs. The EOR business is expected to generate free cash flow this year even in the current oil price environment. Continued investment in these long-life projects during the current market will result in more efficient construction costs which will yield a strong base for future growth in resources. During the first quarter, we authorized the first portion of the North Hobbs phase II-A expansion project. The project will develop 13.7 million BOE of reserves for development costs of $13.82 per BOE. The phase II project builds on the success of the North Hobbs phase I project where CO2 flooding has added a sustained 5,300 barrels of oil per day that had a peak of 7,000 barrels of oil per day to the unit's production since the project began 12 years ago. Another significant EOR project in currently progress is the Denver Unit
Christopher M. Degner - Senior Director, Investor Relations:
Thank you, Vicki. I think we'll now open the call up for questions.
Operator:
And our first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate - Bank of America – Merrill Lynch:
Thanks. Good morning, everybody. And, Vicki, congratulations. It's nice to get that issue behind us. Looking forward to seeing what you're going to do next. I guess I've got two questions, if I may. The first one is the Al Hosn guidance. I just wonder if you could explain the difference between what you suggested at the beginning of the year and what you're looking at now in terms of the reduction in full year expectations. Then I've got a follow-up please.
Edward A. Lowe - Vice President and President, Oil and Gas International Production:
Yeah, Doug, this is Sandy Lowe. Plant started up and we have 25% sulfur recovery there. And some of the sulfur units weren't working quite properly so we took them offline, made some modifications. Today the plant is back up to 45% of production, which is about 25,000 BOEs to us and we should be back up at peak production of 1 million a day at the end of the month, beginning of next month. So the guidance that's given already by Chris should be good for the year.
Doug Leggate - Bank of America – Merrill Lynch:
I guess I had a couple of other issues I was going to touch on, Sandy, but taking advantage of you being there, maybe I'll make my second one on your region if I may.
Edward A. Lowe - Vice President and President, Oil and Gas International Production:
Sure.
Doug Leggate - Bank of America – Merrill Lynch:
There's been a fair amount of chatter around both the Adnoc concessions, obviously your – the slowdown, it seems, in terms of asset monetization in the region and finally the prospect of extensions in the Oman contracts. I'm just wondering if you could give us a kind of general update as to how those things stand, and I'll leave it there. Thank you.
Edward A. Lowe - Vice President and President, Oil and Gas International Production:
Well, I can guide you only as to what you see in the press on the Adnoc concessions. Everybody who's involved is still bound by a confidentiality agreement. The press has been reasonably forthcoming in that respect. As far as asset monetization, this – well, you know, when the price of oil dipped like it is, we have kind of two issues. People want to pay less for it and also they don't have quite as much money to get into it. So things are somewhat held in abeyance at the moment in that regard. And the last question I believe was about Oman, we're in discussions at the moment. We're now at record-breaking production in our block nine, which is the one under discussion of over 100,000 barrels a day. So everybody's happy with that. And so we're just ironing out the details of a new contract with the government.
Doug Leggate - Bank of America – Merrill Lynch:
Any timeline? Because I believe that contract expires this year, Sandy. So what's the prognosis if you don't get it done in the next six months?
Stephen I. Chazen - President, Chief Executive Officer & Director:
I don't think there'll be an issue with that. So it will be – if it weren't quite complete, I'm sure they would extend us.
Doug Leggate - Bank of America – Merrill Lynch:
All right. Steve, maybe I will just squeeze just one more in given that you jumped in there. The pace of buybacks given that your stock has lagged -- just curious on your thought process. Then I will leave it there. Thank you.
Stephen I. Chazen - President, Chief Executive Officer & Director:
We continue to buy the stock back on weakness. And so you should expect that we'll buy back shares over the next year or so and eventually get to our target. The exact date or exact number each quarter, just hard to tell.
Doug Leggate - Bank of America – Merrill Lynch:
All right. Thanks a lot, everybody.
Operator:
Our next question comes from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC:
Hi. Good morning, guys, and congratulations as well to Vicki. My first question is a strategic question. Oxy was in the midst of a restructuring and successfully unlocking value prior to the cycle turn and positioned you well with large cash position into this downturn. I know there's some leadership transition here yet. How has the cycle changed your restructuring outlook? I know you just mentioned the MENA asset divestiture or the partial divestiture. But does it alter your view as it relates to midstream or chemicals? And given the balance sheet and does it change your willingness to add resource and accelerate that shift here?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Sort of a complicated question. The downturn – the cycle of course is – we expect if it stays volatile, whatever that means, we'd expect opportunities to show up during the cycle either to repurchase our stock or to buy other assets just depending on what's going on. Right now the asset market is quite expensive, so there's no reason to believe we'll do much of that. As far as the Middle East assets are concerned, they fall into two classes of asset. Those that are – where we've already spent the money and we're clipping coupons, which seem fairly attractive in a more-volatile oil price environment. And those that are more volatile and follow normal trends which seem less attractive in this environment. So I think that's where we are. Some of those assets require some work and probably in the end divestiture or discontinuation of work there. As far as the chemical business is concerned, the chemical business, once the ethylene cracker is on and the business becomes fully integrated with ethylene, its cash flow will be substantially larger than it is now. And I think that would be the appropriate time to look at whatever makes sense to do. I think if you do it too early, you're going to wind up undervaluing the asset. So I think we're a couple of years away. Of course, I'll be watching that from the beach. But – so you can ask Vicki at the time what she wants to do.
Evan Calio - Morgan Stanley & Co. LLC:
Great. That's helpful. Maybe let me ask a different question that's kind of I guess the reverse direction of where we were just headed. Prior to the downturn, you discussed going to 54 horizontal rigs in the Permian by the end of 2016. You're at 21 active now. I know you just de-ramped, yet how are you approaching a potential re-ramp in activity given your potentially higher long-term goals? Is incremental free cash flow how you will drive that rate of incremental spend?
Stephen I. Chazen - President, Chief Executive Officer & Director:
I'm going to answer first then we'll let Vicki answer. You might get two different answers. But I think generally, in the most attractive asset we have at almost any product price environment is the Permian business. Maybe some in the EOR business but also in the Resource business. Any money we have that's excess is going wind up there. We've already – I think Vicki mentioned it – we've changed the number of rigs we're going to run by the end of the year. We're still looking at that. We got a lot of locations that work in a $60, $65 environment. If we start a well today, we won't see the production really until the third – late in the third or the fourth quarter. And we've gotten a lot better at bringing the stuff to market faster because the times have really shortened. That's why we're having a hard time keeping up with our estimates. I think our estimates are still – have room. But I think what we're going to try to do – so we may put some more rigs to work depending on the environment. Our view on this is different than maybe some others. You get – if you put the stuff on production, these wells work. There's no issue about the returns or whatever. If oil prices move up you'll get 90% to 95% of that change in that well, because you have a little bit of production this year some oil prices are higher next year, you're going get 90% of that. I think this – if there is a boost in prices I think in the end completion costs will start to rise, not fall. So we may be at the part where you want to finish the wells. And I don't – when you got a lot of locations – we've got thousands of locations – any locations that you put off for now, you've delayed drilling for 10 years from now, effectively, because you've moved them to the back of the line. So our view is that you drill through this environment. You reap the returns that are there now. Oil prices move up, you're going get the bulk of that. I think delaying your production, because you know what oil prices are going be next year seems to me to be, you know – if people do know, I wish they'd send me an email so I could get rich.
Vicki A. Hollub - President, Oil & Gas Americas:
I think I'll go with what Steve said. But just to build on that, I'd like to say that we're certainly keeping our team intact and ensuring that everybody is – has the resources necessary to prepare us to be able to maximize our flexibility. We're continuing to work on development plans in the areas that are not our core areas, because there's certainly a lot of opportunities where with increased prices we could start to ramp up and have lots of opportunities available beyond the core areas we're currently developing. So what we're doing is laying out those plans, evaluating those and starting to go ahead and permit. And just so that we can – if prices do go up we can ramp up rigs more efficiently than we have in the past.
Evan Calio - Morgan Stanley & Co. LLC:
Just one last one
Vicki A. Hollub - President, Oil & Gas Americas:
One of the things we're trying to do is make sure we maintain a minimum level of rigs in order to continue improving our efficiency, because you make a good point. You can't really get efficient if you're not actually out doing the work. And that's one thing that's provided us a lot of benefit here. In all areas we have continued operations, as you've seen on the charts, we've gained significant efficiencies. At Merchant where we – that's kind of a new startup where we don't have those efficiencies yet, but we're starting to see those coming as well. So we think it's critically important to maintain a certain level of activity with not only rigs, but the frac companies that you're using and the other service providers as well.
Evan Calio - Morgan Stanley & Co. LLC:
Great. Thanks.
Operator:
And our next question comes from Guy Baber of Simmons & Company. Please go ahead.
Guy Allen Baber - Simmons & Company International:
Good morning, everybody. Congrats on nice quarter, and, Vicki, congratulations to you as well. My first question was on cost structure, but obviously you've been very successful in reducing your cost structure in recent months. You've mentioned $400 million in savings. Can you discuss where you are in that process? Where you see that number potentially going? And then if you could also just discuss for us how much of that you see as structural and permanent versus temporary and what might reverse when prices begin to rise again? Just trying to understand how that outlook might be structurally proving on the cost front. Then I have a follow-up.
Vicki A. Hollub - President, Oil & Gas Americas:
The cost structure that we're trying to get to is, we currently have some of our contracts with suppliers tied to oil prices, so some of those contracts will go up with oil prices. However, the majority of our contracts for the drilling rigs and for our frac providers are not necessarily tied to an oil pricing index. So what we're really trying to do is get more efficient. And we expect that the cost structure that we're going to achieve by fourth quarter is going be one that does have some exposure to flexibility in prices, but I don't believe that more than 60% to 70% of our cost structure improvement will be associated with oil price changes.
Guy Allen Baber - Simmons & Company International:
Okay, great. And then I had a follow-up on – I wanted to talk a little bit more about the Permian and capital allocation. But obviously results in the Permian have improved very rapidly and considerably just in the last six months or so. So the question is, does that rapid improvement really change your view of capital allocation relative to what you would have thought six months or a year ago? Meaning, are you much more likely now to commit incremental discretionary capital to the Permian? Or perhaps even look for acquisition opportunities and bolt-ons as opposed to the buy-back versus one year ago. Just hoping you can elaborate on most recent thoughts there? And what those improvements to the Permian really mean?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Well, the Permian is obviously doing well. And we continue to put what's prudent into it. And we'll continue to focus on it. But as it generates better results, it generates more cash. And that cash a lot, the bulk of that will be reinvested in continuation as long as it does what it's currently doing. Facts are, the reason we sort of are running ahead of our outlook was simply because we didn't think we would be quite this good. So – and we continue to run ahead of outlook in our plans and we – so I think there's still room there. I think the buy-back question is quite a different one. We need to reduce the number of shares outstanding over time. And we'll do that, but just as important we need to increase our cash flow so that we can continue to have more free cash flow to – for dividends and share repurchases. That's really and the purpose – at the very beginning I said you have to focus on the fact that you can't just save and cut back and that's going to make it better. If you don't invest and you start to decline, you're going to have a hard time recovering from it because you have a decline curve and you're declining against it, and you're starting up again. So our objective is to continue to grow the volumes through the year. And to the extent we can unless you get a collapse in product prices. And then the free cash flow that that will generate over the next year can be used to enhance the dividend or repurchase shares.
Guy Allen Baber - Simmons & Company International:
That's very helpful. Thanks for the comments, Steve.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thanks.
Operator:
And our next question comes from Ed Westlake of Credit Suisse. Please go ahead.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Yes. Congratulations, Vicki. Two questions again on the Permian, it's probably going be a theme. You have a great slide in the deck just in terms of drilling days and getting from your 26 days down to a target of 16. What's the key thing you're doing differently? Is it just as simple as just getting to an efficiency mode or is there other things you need to do to get to the best in class? And then I've got a question on completions.
Vicki A. Hollub - President, Oil & Gas Americas:
In terms of the drilling days, one of the things our team is doing is they're taking an evaluation of the formations that we're drilling through and modeling what it takes in terms of the weight on our bit and rotation of the bit to really design exactly how much we should do, how fast we should rotate the bit. And how much weight we should put on it by interval. And it's a process that's called mechanical-specific energy and that's one of the processes that's helped us to significantly reduce our drilling days, that, along with the fact that we're better managing our mud systems and we've seen a lot of improvement there. We're seeing significant reduction in nonproductive time during our drilling operations. So – and part of that – a good part of the nonproductive time reduction is due to the efficiencies of our teams and the scheduling. Some of that is due as well to the fact that the Permian is not as stretched in terms of the support system now that activity is lower. So it's a combination of a lot of things but the thing I'm most excited about is the engineering that our teams are doing on the wells. And that's sustainable. So the drilling-day reduction is one of the things from a cost structure standpoint improvement that's sustainable and that's – we haven't been able to apply that everywhere yet, like in Merchant. That's one of the things that's going to help us further improve our drilling efficiency in Merchant. It's really based on some incredible work with teams especially with respect to the engineering aspect of what we're doing.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
My second question on completions, I was down at the Offshore Technology Conference, which they may as well call the Onshore and Offshore Technology Conference. Obviously there's a lot of new technology. Could you give a sense of any pilots or new solutions which you see driving the EUR improvements or lowering the cost.
Vicki A. Hollub - President, Oil & Gas Americas:
One of the things that we've been trying, and we are not prepared yet to talk about the results, but we've used several different techniques to isolate how we inject and place our proppant within the horizontal section of the well. And we feel like that that's the next area that we feel has the most opportunity for improvement. That's getting the most contact with your proppant through the formation. So it's getting the most surface area contact in order to create the conduits through the well bore. What we felt is that if we could isolate our stages with just single clusters rather than two to three to four clusters per stage, that we could more efficiently frac the formation. We've tried some of that and we've tried various types of tools to help us do that. We're in the process of evaluating those results now and hope to have some things that we can share in the next three to six months.
Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker):
Thanks very much. Good luck.
Operator:
And our next question comes from Ryan Todd of Deutsche. Please go ahead.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great. Thanks, and congratulations, Vicki. Maybe another follow-up question on the Permian. You have some slides in there that update on well cost deflation in the Permian. Can you – I guess with the 2014 level, a current level and a target level, I guess can you talk a little bit about where the current level of well costs are relative to what you implied in the 2015 budget? And then is the target well costs kind of a year end 2015 target? Is that an eventually full blown development program target? I guess maybe talk a little bit about how much of that is from service cost deflation versus improved efficiencies.
Vicki A. Hollub - President, Oil & Gas Americas:
Yeah, the target that we're trying to achieve, we already have achieved that with some of our wells. So the current costs where I'm saying we are there is that3 basically an average of what we're seeing. That is actually our planned numbers were a little bit higher than what – certainly what our target is and sort of in between our target and our current. But in terms of where we expected to be for Q1, we're ahead of schedule because we're implementing these things as we go. So the target was where we expect to be by year end. But we think we will be ahead of that.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great. That's helpful. And then, you addressed costs a little bit earlier and I wasn't clear whether you addressed this point or not. Last quarter you had targeted $500 million of cost savings. You said you'd captured $400 million to date. Any update on whether you expect greater than $500 million at this point, or is that a still a reasonable target for the year?
Stephen I. Chazen - President, Chief Executive Officer & Director:
This is Steve. I think it's a reasonable target for the year. I think we'll sort of get there. But I think – it could be more than that but I think right now we'll stick with that.
Ryan Todd - Deutsche Bank Securities, Inc.:
Great. I appreciate it. I'll leave it there.
Operator:
And our next question comes from Roger Read of Wells Fargo. Please go ahead.
Roger D. Read - Wells Fargo Securities LLC:
Yeah, good morning, and congrats, Vicki, on your new role there. Coming back around to the Permian Resources for the obvious reasons – as you talked about guidance and being in a situation where you could potentially still exceed that, can you quantify at all how much of that is the well performance issues that you highlighted earlier in terms of IP rates and 30 day rates and how much of it is just executing on getting the wells in the ground, sort of that if you spud today, whether or not you can get it started late Q3 or if it slides well into Q4?
Vicki A. Hollub - President, Oil & Gas Americas:
Currently it's principally performance execution. It's accelerating the well delivery. However, we do have a couple of areas where we're seeing improved performance. You'll notice that the graphs from the Delaware basin, we're still seeing strong performance versus our peers in the Wolf Bone and the Barilla Draw area. There are other areas where we're seeing improved performance in terms of our program design. So we're still seeing opportunities to increase our per-well performance and we're seeing – and then the main thing that we're doing there is targeting better landing zones. So I would say that right now just to go back and bottom-line answer the question, it's incredible execution on the part of our teams to get the wells on faster. And part of it is a little bit of improved recovery on a per-well basis, but we still expect there will be more of that to come.
Roger D. Read - Wells Fargo Securities LLC:
Okay. Thanks. And then Yemen, as you said earlier that was going to go away anyway. But I was wondering what was the margin or cash margin per unit that that impacts you?
Stephen I. Chazen - President, Chief Executive Officer & Director:
I don't remember. Chris has got it.
Christopher G. Stavros - Executive Vice President & Chief Financial Officer:
It was generating about $15 million a quarter after tax if you want to think about it that way.
Roger D. Read - Wells Fargo Securities LLC:
Okay. Appreciate it. Thank you.
Operator:
Our next question comes from Paul Sankey of Wolfe Research. Please go ahead.
Paul B. Sankey - Wolfe Research LLC:
Good morning, everyone, and congratulations, Vicki. Steve, you start your slides in a differentiated way with talk about dividend growth. And I think and I assume Vicki will continue this as the primary ultimate aim of OXY. Can you square the circle because, as I said, that's a differentiated strategy from most other if not all other U.S. E&Ps. Does it mean you have better geology costs, lower growth? How is it that you're going be able to deliver a higher dividend growth than others in essentially the same place? Thanks.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Well, most of them don't have any dividends. So comparing against an environment with – so we're sort of a tall midget here. So I think the -- dividends, if there is religious activity here, I think that's it. It provides discipline to the management, otherwise you print shares, do all sorts of wealth destructive things. The dividends give you discipline. We have a more diverse business than the typical E&P. We've got the sort of stable stuff that we've already spent the money on in the Middle East to generate cash. We've got the Chemical business, which always generates cash. We have a midstream business which generates cash, and we have less debt, relatively. So all that provides more cash than the typical, and what we do with the cash is we buy in some shares. And we pay more dividends. You have to have something that – you can't be at our size – you can't try to compete with somebody makes 10,000 barrels a day and grow. So we think that our long standing acreage position, that's also part of it, we didn't just acquire the acreage last month or last year. We got the EOR business which generates a lot of cash. In economic terms, those are called monopoly profits and that's what you're seeing. It's the same thing you see at the large integrateds. That's what differentiates it. The other guys have a different strategy. Nothing wrong with their strategy, it's just different but we think the cash here will be strong and we invest sometimes unpopularly, by the way, in things that will generate a lot of cash for a long period of time. So we always are thinking about how we're going grow the dividend. I guess she can speak for herself but I think Vicki and Chris have the same basic belief because they've been hearing it for a long time. So...
Christopher G. Stavros - Executive Vice President & Chief Financial Officer:
Yeah.
Stephen I. Chazen - President, Chief Executive Officer & Director:
And that's – and Chris is planning on staying so Chris will be your principal person to talk to about financial matters, but Vicki will certainly set the strategy.
Paul B. Sankey - Wolfe Research LLC:
Well, I'm glad to hear that Vicki's not planning to fire Chris. Could – I guess theoretically. Let's skip over your politically-incorrect comment and just say, assuming you're that not comping against other E&Ps, but I would assume an above inflation rate of growth, otherwise you're not growing the dividend. Would that mean that ultimately given the assets that you listed are all more/less zero growth once we get through some of the project start-ups, would that mean that we align your long-term volume growth with your long-term dividend growth?
Stephen I. Chazen - President, Chief Executive Officer & Director:
Yeah, that probably about right.
Paul B. Sankey - Wolfe Research LLC:
Which would be 5%-plus percent but not 10% I guess.
Stephen I. Chazen - President, Chief Executive Officer & Director:
That's right. It's hard to say exactly. Because you have the chemical business which is a little different and that's going to generate a sizable amount of free cash out here. I'm sure it will generate $1 billion in free cash. And so that will cover a fair amount of the dividend without doing anything and some growth there. It's sort of a GDP grower when all is said and done on its cash flow.
Paul B. Sankey - Wolfe Research LLC:
Yeah.
Stephen I. Chazen - President, Chief Executive Officer & Director:
So I mean...
Paul B. Sankey - Wolfe Research LLC:
Go ahead.
Stephen I. Chazen - President, Chief Executive Officer & Director:
That provides the base. And we just – the dividends are the cost of keeping the shareholders. It's cost of capital. However you want to say it. And without that sort of discipline, you'd do all kinds of crazy stuff.
Paul B. Sankey - Wolfe Research LLC:
Yeah, and just finally, would it be fair, if harsh, to say the other element here is you're coming off a lower base in terms of your operational performance in the Permian and that provides the potential for greater growth? And I'll leave it there. Thanks.
Stephen I. Chazen - President, Chief Executive Officer & Director:
I don't know. Maybe. But I think growth is growth. We've spent a lot of time building to this so that we wouldn't be in the same situation that a number of other companies are. We've spent money and time. And so we started the acceleration when we knew what we were doing, mostly. And that's really what – and I think we've told you that in the past, which nobody listened to.
Paul B. Sankey - Wolfe Research LLC:
Okay, thanks, Steve.
Operator:
And our last question comes from John Herrlin of Société Générale. Please go ahead.
John P. Herrlin - SG Americas Securities LLC:
Yeah, hi, just a quick one for me. Steve nobody would accuse Oxy as being a contra plastic but regarding the Permian, you're going to drill in the Resources division, I guess Vicki, 150 wells. Can you give me a sense what the split would be, Delaware, central basin and midland? And that's it.
Vicki A. Hollub - President, Oil & Gas Americas:
Yes of the 150 wells, none of them will be on the Central Basin platform. It'll be almost split half-and-half between the Midland Basin and the Delaware Basin.
John P. Herrlin - SG Americas Securities LLC:
Okay, great. That's it for me. Thank you.
Stephen I. Chazen - President, Chief Executive Officer & Director:
Thanks, John.
Operator:
And thank you. This concludes our question-and-answer session. I'd like to turn the conference back over to Mr. Degner for any closing remarks.
Christopher M. Degner - Senior Director, Investor Relations:
Hi. Yes. Thanks, everyone, for participating. I know it's been a busy day for you. Please give us a call if you have any follow-up questions.
Operator:
Thank you, sir. Today's conference has now concluded. We thank you all for attending today's presentation. You may now disconnect your lines.
Executives:
Chris Degner - SVP, IR and Treasurer Steve Chazen - President & CEO Chris Stavros - CFO Vicki Hollub - President, Oil and Gas in the Americas Willie Chiang - EVP, Operations Sandy Lowe - President, International Oil and Gas Operation
Analysts:
Doug Leggate - Bank of America Merrill Lynch Paul Sankey - Wolfe Research Doug Terreson - Evercore ISI Leo Mariani - RBC Jeffrey Campbell - Tuohy Brothers Investment Research Brian Singer - Goldman Sachs Ryan Todd - Deutsche Bank Evan Calio - Morgan Stanley Matt Portillo - TPH
Operator:
Welcome to the Occidental Petroleum Corporation Fourth Quarter Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to Chris Degner. Mr. Degner, please go ahead.
Chris Degner:
Thank you, Emily. Good morning, everyone and thank you for participating in Occidental Petroleum's fourth quarter 2014 conference call. On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer, Chris Stavros, Chief Financial Officer, Vicki Hollub, President, Oil and Gas in the Americas, Willie Chiang, Executive Vice President of Operations and Sandy Lowe, President of our International Oil and Gas Operation. In just a moment I will turn the call over to our CEO, Steve Chazen who will review our achievements in 2014 and provide an outlook for 2015. Our CFO, Chris Stavros will review our financial and operating results for the fourth quarter and also provide guidance for 2015. Then, Willie Chiang will review our 2015 capital plan followed by Vicki Hollub, who will provide an update of our activities in the Permian Basin. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the Federal Securities Laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our fourth quarter 2014 earnings press release and the investor relations supplemental schedules, our non-GAAP to GAAP reconciliation and the conference call presentation slides can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Steve Chazen. Steve, please go ahead.
Steve Chazen:
Thanks, Chris. I would like to start with some highlights from our accomplishments in the past year. We executed many of our strategic initiatives including the spin-off of California Resources, the sale of our Hugoton gas properties, BridgeTex pipeline and PAGP units. At the end of the year, our cash balance of $7.8 billion exceeded our total debt of $6.8 billion. We grew our domestic oil production by 11,000 barrels a day over 2013 to 181,000 a day. We grew our Permian resources production from 65,000 barrel equivalents a day over 2013 to 75,000 barrels a day this year. The 2004 capital program added 395 million barrels of proved reserves, replacement ratio of 181% before dispositions. Our costs incurred with these reserve additions were about $6.7 billion, resulted in an apparent finding and development cost of under $17 a BOE. We added 363 million barrels of liquid proved reserves, a replacement ratio of 223%, before dispositions. We completed the Al Hosn gas project on budget and on time which started production in early January. I have two comments about the macro environment. The confluence of U.S. supply growth, weaker Asian demand and extreme currency movements have led to significant decline in product prices. Our company is resilient and built to weather price shocks typical to this industry. Obviously, we have the financial resource to continue drilling at the 2004 rate. However, the current service company cost structure is more reflective of a $100 oil price environment, rather than the $50 environment we have today. While service companies have offered modest price reductions, they still do not reflect the current reality. We're focused on reducing our costs which include renegotiating our supplier contracts that are not reflective of weaker oil prices. We expect these efforts to result in a reduction in the cost of executing our capital program as well as reducing our operating expense. It makes little sense for us to push production so as to sell our oil at $50 or less. I would like to talk briefly about the impairments. We have virtually eliminated our capital spending in the Williston Basin, on domestic gas properties, in the Bahrain and Joslyn oil sands projects, as these have unacceptable returns in the current price environment. As a result of a thorough portfolio review, we have reduced the carrying value of the assets in the areas where we're minimizing development activity. This resulted in an after tax charge of $5.1 billion. These charges do not affect our cash position. Chris will detail the charges. Our policy has been and will continue to be to write-down assets to approximately fair market value when we believe that the impairment is other than temporary. In 2015, we will focus our capital spending on the core areas we operate, principally the Permian Basin. Our capital budget is $5.8 billion which is a 33% decline from 2014, 2/3rds of the capital budget will be allocated to maintenance capital and 1/3rd allocated to growth capital. To the start of the several long term projects, notably the Al Hosn gas project and the BridgeTex pipeline, our to 2015 capital program was on course to decline before the recent fall in product prices. Our capital run-rate in the first quarter will be higher than the $5.8 billion level and will decline all year unless product prices significantly improve. Given our large acreage position, deep inventory, we have the flexibility to defer drilling and appraisal activity. Although we will likely outspend our cash flow during the first half of the year, we expect that by the end of the year our operating cash flow will cover our capital expenditures and dividend payments, assuming a recovery to $60 oil price environment. Willie Chiang will provide more details on our capital program later in the call. Despite the lower capital program, we expect to deliver 6% to 10% annual production growth in 2015 driven by the startup of the Al Hosn gas project and the focused development program we will run in the Permian resources business. In the United States, we expect oil production to grow about 6% partially offset by declines in NGLs and natural gas production. Vicki Hollub will provide further details on the outlook for the U.S. oil and gas business. We had a successful year in growing the company's reserve base by adding substantially more reserves than we produced. Company-wide, we replaced 174% of our production before asset sales. We ended the year based on a preliminary estimate with about 2.8 billion BOEs of reserves. Through our organic development program, we replaced 181% of our production. This estimate excludes acquisitions, asset sales and revisions of prior period estimates. Our reserve replacement ratio for liquids from all categories before asset sales was 223%. This reflects our emphasis on oil drilling. Our total costs incurred related to the reserve additions for the year on a preliminary basis were approximately $8.3 billion. As a result of our organic development program, we estimate an apparent finding cost of under $17 a barrel. Our 2004 acquisitions were approximately $1.6 billion and we booked a conservative amount of proved, developed reserves. We expect to add incremental reserves as we exploit this acreage. At the end of the year, we estimate that 76% of our total proved reserves were liquids increasing from 71% in 2013. Of the total reserves about 71% were proved, developed reserves compared to 70% in 2013. Over the past several years we have built a large portfolio of growth-oriented assets in the United States. In 2014, we spent a larger proportion of our investment dollars on these resources. Our organic reserve replacement for the year reflects the positive results of the appraisal and development efforts, capitalizing on the large portfolio built over time. In the United States, we replaced 266% of our production before asset sales. We ended the year based on a preliminary estimate with about 1.8 BOE of reserves. Through our organic development program, we replaced 286% of our production. The estimate excludes acquisitions, asset sales and revisions of prior estimates. Our reserve replacement ratio for liquids from all categories before asset sales was 306%. Our total costs incurred related to domestic reserve additions for the year on a preliminary basis were approximately 5.7 billion. As a result of our organic development program, we estimate an apparent finding and development cost of about $12 a BOE. Through the success of our drilling program and capital efficiency initiative, we have lowered our finding and development costs over recent years. As a result, we expect our DD&A expense to be approximately $15 a barrel in 2015, a decrease from $17 a barrel in 2014. This is consistent with our expectations and DD&A rate of growth should flatten out as recent investments come online and finding and development costs come down. The success of our organic reserve additions and the efficiencies we’ve achieved in our operation demonstrate the significant progress we have made in turning the company into a competitive domestic producer. Through the execution of our strategic initiative, we have raised enough cash to exceed our debt at year-end. Slide 14 outlines priorities of our use of cash. This is the same slide we have shown for at least a decade. After spending on maintenance capital, the top priority for our cash flow is to continue to increase the dividend. We have increased the dividend for 12 consecutive years and are committed to annual increases. Given the uncertainty in product price, decision on the size of the increase will be made on the declaration of third quarter dividend. Our remaining cash flow will be allocated to growth capital, share repurchases and acquisitions. In 2014, we repurchased $2.5 billion of shares. We have approximately 71 million shares remaining under our current authorization. We will continue to repurchase shares subject to the stock price and market conditions and expect to ultimately repurchase the entire amount. Now, I will turn the call over to Chris Stavros for a review of our financial results.
Chris Stavros:
Thanks, Steve and good morning everyone. Oxy completed the spin-off of California resources at the end of November. Accordingly, we have reclassified the financial and operational results for discontinued operations for our core results disclosure. As such, our fourth quarter 2014 core income excludes all the California results and income on a reported basis includes two months of California results. Total year 2014 results on a reported basis include 11 months contribution from the California operations classified as discontinued. We generated core income of $560 million for the fourth quarter 2014 resulting in diluted earnings per share of $0.72, a decrease from both the year ago quarter and the third quarter of 2014. The decline in core earnings was attributable mainly to sharply lower realized oil prices on our worldwide production. Net results for the quarter were a loss of $3.4 billion or $4.41 per diluted share. In accordance with the successful efforts method of accounting which Oxy follows, we review our proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of the oil and gas properties may not be adequately recovered, such as when there is a significant drop in the futures price curve. Under the successful efforts method, if an oil and gas property's estimated future net cash flows are not sufficient to recover its carrying amount using the period end's future curve, an impairment charge must be recorded. As of December 31, Oxy recorded property impairments due to the fall in the futures curve for oil as of that date. The 2014 fourth quarter includes after tax, non-core net charges of $4 billion. Approximately $2.7 billion of this was a result of the sharp decline in the year-end WTI price curve that affected our domestic properties. Most notably this included a charge of $1.7 billion in the Williston Basin, $600 million related to our gas and gas condensate assets and $350 million for other domestic acreage. Foreign impairments amounted to $1.1 billion principally related to our operations in Bahrain. Additional charges included $700 million for our interest in the Joslyn oil sands project and a $550 million mark-to-market adjustment for the carrying value related to our remaining 19% interest in California resources. The fourth quarter also included after tax gains of $900 million from the sale of a portion of our investment in the Plains All American Pipeline GP and $400 million from the sale of our 50% interest in the BridgeTex pipeline. We continued our strong domestic oil production growth and achieved a year-over-year quarterly production increase of 19,000 BOE per day or about 11% led by our Permian resources assets. We also purchased 4.8 million shares of our stock during the fourth quarter and ended the period with $7.8 billion of total cash on our balance sheet. In oil and gas, our core after tax earnings for the fourth quarter of 2014 were $368 million, $549 million lower than the third quarter of this year and $731 million lower than last year's fourth quarter. For the fourth quarter of 2014, total company oil and gas production volumes from continuing operations averaged 616,000 BOE per day, an increase of 21,000 BOE per day in daily production from the third quarter and 41,000 BOE per day from the same period a year ago. This excludes production from the Hugoton and the California assets for all periods disclosed. Our fourth quarter 2014 worldwide realized oil price of $71.58 per barrel fell by $22.68 or 24% compared to the third quarter realizations of $94.26 per barrel. In the fourth quarter of 2014 after tax core income for our domestic oil and gas operations was $59 million compared with $310 million in the third quarter of 2014 and $391 million in the fourth quarter of 2013. On both a sequential quarter-over-quarter and year-over-year basis, results at our domestic operations were mainly impacted by lower realized oil prices and to a lesser degree, lower NGL prices. Higher oil production had a meaningful positive impact to both earnings and cash flow in the fourth quarter of 2014 compared to both periods. In the fourth quarter of 2014, we experienced a narrowing of the differentials in the Permian Basin from what we realized in the third quarter of last year. Total domestic oil and gas production averaged 321,000 BOE per day during the fourth quarter of 2014, up 6000 BOE per day sequentially and 26,000 BOE on a year-over-year basis. Domestic oil production was 189,000 barrels per day during the fourth quarter, an increase of 19,000 barrels per day from the year-ago period with our Permian resources business growing its oil production by 42% to 51,000 barrels per day. On a sequential quarter-over-quarter basis, total domestic oil production growth was 7000 barrels per day. International after tax core income was $355 million for the fourth quarter of 2014, a decline of 43% from the third quarter of last year and 50% lower on a year-over-year basis. The decline for both periods was driven mainly by lower realized oil prices with the sequential quarter-over-quarter period favorably impacted by higher liftings in both Iraq and Columbia. International oil and gas sales volumes rose by 39,000 BOE per day on a sequential quarter-over-quarter basis. The improvement was largely due to higher volumes in Iraq, resulting from liftings that slipped from prior periods, as well as higher spending levels, higher production volumes in Columbia along with increased volumes in the Middle East resulting from lower prices affecting our production sharing contracts. Oil and gas cash operating costs were $13.50 per barrel for the total year 2014 compared to $12.56 per barrel for full year 2013 and reclassified to exclude California. The increase in costs reflects increased activity in downhole maintenance and higher cost for purchased injectants. The DD&A rate for full year 2014 was $17 per barrel. Taxes other than on income which are directly related to product prices were $2.45 per barrel for the 12 months of 2014 compared to $2.48 for the same period of 2013. Fourth quarter exploration expense was $59 million. Chemical fourth quarter 2014 pretax core earnings were $160 million compared with third quarter results of $140 million and $128 million in the year-ago quarter. The sequential improvement primarily reflected lower ethylene and energy costs, partially offset by lower vinyls pricing and a reduction of volumes across most product lines, due to a combination of maintenance outages, holiday shutdowns and customer initiatives to reduce year-end inventories. Midstream pretax core earnings were $168 million for the fourth quarter of 2014 compared to $155 million in the third quarter and $106 million in the same period a year ago. Phibro's domestic trading book was closed in the fourth quarter of 2014 and we expect to wind down the remainder of the business in the current quarter. As such, Phibro's results have been eliminated from all core income periods. In the 12 months of 2014, we generated $9.4 billion of cash from continuing operations, a decline of approximately $1 billion compared to the year-ago period. Capital expenditures for 2014 were $8.7 billion, net of partner contributions. Last year's capital outlays included $1.1 billion associated with the Al Hosn gas project including $470 million related to the rail and sulfur handling facilities and $285 million for the BridgeTex pipeline. We received proceeds of $4.2 billion from the sale of assets which included fourth quarter proceeds of $1.1 billion from the sale of our investment in BridgeTex, $1.7 billion from the sale of a portion of our investment in Plains All American Pipeline GP, as well as $1.3 billion from the sale of our [inaudible] assets in the first quarter of last year. We spent about $1.7 billion on bolt-on property acquisitions, of which $1.3 billion was spent in the fourth quarter on a single acquisition in the Permian totaling 100,000 net acres and including a modest amount of oil production. In October, we received cash proceeds of $4.95 billion from the bond offering completed by California resources. IRS rules mandate that the use of these proceeds be restricted to share repurchase, dividend payments or debt retirement. We paid the fourth quarter dividend and repurchased our shares in December using the restricted cash, resulting in a $4 billion balance at December 31. We received an additional $1.15 billion of cash from California resources concurrent with the spin-off in late November. The use of those proceeds is unrestricted. We returned $4.7 billion of cash to our shareholders by paying $2.2 billion in dividends and repurchasing 25.8 million of our shares for $2.5 billion. Last year's share repurchase activity has the benefit of reducing our current dividend outlays by approximately $75 million. Our cash balance including restricted cash was $7.8 billion at December 31. Our debt to capitalization ratio was 16% at year end. After excluding the impact of non-core adjustments and discontinued California operations, our 2014 return on equity was 9% and return on capital employed was 8%. The worldwide effective tax rate on our core income was 39% for the fourth quarter of 2014 and 41% for the total year. Focusing on 2015, our capital program this year is expected to be about $5.8 billion, a decrease of 33% from our 2014 spending level of $8.7 billion. Willie Chiang will discuss the specifics of the 2015 capital program in a moment. Using a $55 WTI and $60 Brent price curve, we expect total company production to be between 630,000 BOE and 650,000 BOE per day in 2015 or an increase of roughly 6% to 10%. Domestically, we expect our oil production for the total year to grow in the 6% range with the increase coming from the Permian resources business. We expect gas volumes to decline modestly as we cease development activities in our gas properties. In the first quarter, we expect to lose approximately 4000 BOE per day production in our Permian Basin operations due to weather-related shutdowns and freezing conditions that occurred during January. Domestic gas production is expected to decline from the fourth quarter levels resulting in a slight sequential production decline on a BOE basis. We expect our international volumes to increase in the first quarter with the Al Hosn gas project having started up earlier this month. Volumes from Al Hosn should average roughly 20,000 BOE per day in the first quarter as the facilities ramp up through the first half of the year. Full year 2015 volumes from Al Hosn should average about 50,000 BOE per day with more than 40% of the production coming from NGLs and condensate. Production volumes should also be positively impacted from our production sharing contracts that are sensitive to the decline in oil prices. Oil and gas DD&A expense is expected to be approximately $15 per BOE this year. Combined depreciation for the midstream and chemical segments should be approximately $675 million. Price changes at current global prices affect our quarterly earnings before income taxes by $32 million for a $1.00 per barrel change in oil prices and $7 million for a $1.00 per barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pretax earnings by about $15 million. These price change sensitivities include the impact of production sharing contract volumes changes on income. Our first quarter 2015 exploration expense is anticipated to be about $30 million pretax. We expect our first quarter 2015 pretax chemical earnings to be about $140 million. Lower [inaudible] vinyl margins are the primary driver for the sequential decrease in earnings. Using current strip prices for oil and gas, we expect our 2015 domestic tax rate to be at 36% and our international tax rates to be about 65%. I will now turn the call over to Willie Chiang who will provide more detail on our 2015 capital program.
Willie Chiang:
Thanks, Chris. Good morning, everyone. As you now know, our 2015 capital program is expected to be $5.8 billion, a 33% reduction from our 2014 capital program. All business segments will see cuts in capital spending versus the 2014 levels with the exception of chemicals which is in the peak year of spending for the Ingleside ethylene cracker JV project. Despite the lower capital program, we expect to deliver the production growth in 2015, as Steve has said. Now let me expand on the 2015 program of which 80% is in the oil and gas segment and 10% each is in the chemicals and midstream segments. Domestic oil and gas capital will be about $2.5 billion or 43% of our total capital program, a decline of about $1 billion from 2014 levels. Overall spending levels in the Permian will decline slightly and significant reductions will come from Williston and south Texas which are most impacted by the sharp declines in product prices. Vicki Hollub will provide more details on that later in the call. International development capital will be about $2 billion or 33% of our total capital program. Spending levels in the Middle East, North Africa MENA region will decline by approximately $1.4 billion mostly from the Al Hosn gas project completion, Qatar and other mature projects. Exploration capital is expected to decrease significantly from the 2014 levels to roughly $150 million. Our 2014 exploration program was successful in supporting the appraisal and delineation of a strong inventory of drilling locations which is the basis of our development program this year. Chemical segment capital will be about $600 million which includes the Ingleside cracker project that we expect to complete late 2016 and commission in the first quarter of 2017. We expect OxyChem to be free cash flow positive through the construction of this project. U.S. midstream capital will be about $600 million, a decrease of about $150 million from the 2014 levels, driven primarily by the completion of BridgeTex pipeline. Key projects include the continued development of the Ingleside terminal for both propane and crude export terminaling as well as gas processing infrastructure in support of our key development programs in the Delaware basin. The 2015 capital program I have described ramps down over this year and where we expect to end the year at a balanced free cash flow run-rate which will cover capital, interest and dividend payments at the $60 oil environment. It also allows us to develop profitable production growth and allows us to continue to develop the key strategic projects in our chemicals and midstream segments. I would like to take a few minutes to share with you the status on our reductions of our cost structure. Clearly, lower oil price environments require lower cost structures to be competitive. Our 2015 plan assumes a very conservative amount of pricing concessions from our suppliers of roughly $250 million for key services. If the market environment remains where it is, we expect to see this increase to $500 million or more which will give us the flexibility to increase activity. We have been very engaged with our suppliers and service providers to capture immediate reductions in costs, ranging from 10% to 40%. In many cases, we have amended existing agreements to tie discounts to oil price. The lower the oil price, the greater the discount needed to meet the market environment. We're in the early stages of this process and have finalized agreements with about half of our key suppliers to date. Most of the cost savings that we have incorporated are capital costs, but we also expect operating cost reductions from the $15 per BOE domestic operating cost level. Beyond what we normally look at pure lifting costs of the business, there are a number of cost categories that comprise the total operating costs. Some of these categories are fairly consistent year to year and include labor, generally operating support and staff, plan expenses, pipeline transportation costs, surface maintenance. This activity allows us to produce our product reliably, safely and responsibly. Now, highlighted are a number of categories where we do expect to see significant reductions and are much more discretionary in nature. These include well workovers, well enhancements, downhole maintenance and purchased injectant costs, primarily CO2. Clearly, in a low product price environment many of these activities are just not economic to pursue. We also expect to see energy cost reductions which are linked to oil and gas prices, so they too will come down in this price environment. This should give more perspective on another key area of opportunity that we're working hard on and we will share more specifics with you as we develop more certainty around market environment and other optimization and efficiency improvements. I will conclude my remarks by emphasizing that our capital allocation is very dynamic in nature. We will proactively manage our program and we have ample flexibility to respond to both stronger and weaker conditions. I will turn the call over now to Vicki Hollub, who will review our 2015 domestic oil and gas plans.
Vicki Hollub:
Thank you, Willie. Today I will review the highlights of our Permian resources activities in the fourth quarter and then I will provide more details about the 2015 capital programs in our U.S. operations. In the fourth quarter, Permian resources achieved daily production of 84,000 barrels of oil equivalent per day which is a 9% increase from the 77,000 barrels of oil equivalent per day that were produced in the third quarter. With regard to oil, we produced 51,000 barrels of oil per day for the fourth quarter. This is a 42% increase from a year ago and a 19% increase from the previous quarter. During the fourth quarter, our capital expenditures were $791 million. We operated 29 rigs and drilled 85 wells including 56 horizontals. We placed 70 wells on production including 44 horizontals. At year-end, 11 wells were on flow-back and 61 were not yet completed. In the Delaware basin, we operated 14 horizontal drilling rigs and one vertical drilling rig in the fourth quarter. We drilled 47 wells and placed 39 wells on production. In our Barilla Draw area we placed 7 horizontal wells on production in the Wolfcamp A and B benches. These wells achieved an average peak rate of 1500 BOE per day and a 30 day rate of 1,190. We're extremely excited by the results achieved on the Peck state 258 number 6H, where we optimized the landing point and cluster spacing. This well achieved a peak rate of 2400 BOE per day and a 30 day rate of 1760. Additionally, we placed our first two 7500-foot lateral wells, the Buzzard state number 9H and number 10H on production with excellent results. Both were completed in the Wolfcamp A. The Buzzard state number 9H achieved a peak rate of 2020 BOE per day and a 30 day rate of 1780. We're achieving excellent initial results on our wells with sand concentrations ranging from 1750 to 2250 pounds per foot. For example, our Chevron Mineral 17-5 well achieved a peak rate of 1800 BOE per day. In New Mexico, we continue to be pleased by the performance of our Bone Spring wells. Recently, our Cedar Canyon 27 state 4H was placed online with an average peak rate of 1790 and a 30 day rate of 1030 BOE per day. In the Midland basin we operated 10 horizontal drilling rigs and four vertical drilling rigs during the fourth quarter. We drilled 38 wells and placed 31 on production. In the Spraberry, Wolfcamp A and Wolfcamp B benches, we placed 17 horizontal wells online with an average peak rate of 950 BOE per day and a 30 day rate of 790. To-date, we have placed 10 Spraberry wells online with an average peak rate of 900 BOE per day and a 30 day rate of 850. Last quarter we discussed our South Curtis Ranch 3526H well in the lower Spraberry. We're excited to report the six-month average production for this well was 740 BOE per day. In one of our new development areas, the [inaudible] 1411 well achieved a peak rate of 1560 BOE per day and a 30 day rate of 1,140 from the Wolfcamp A. The aggressive exploration and appraisal programs we completed in 2014 have helped us to clearly identify our best benches and to achieve significant improvements in well productivity and operational efficiency. We will continue to improve these results in 2015. Now I will provide additional details about our 2015 capital plans at our domestic operations. Our most significant capital reduction will come in our Mid-Continent business unit which includes our Williston operations and our gas properties in the Piceance in south Texas. We plan to spend $285 million in 2015 versus $570 million spent in 2014. The 2015 capital program will focus on maintenance activities along with high return workovers. This fits with our strategy to focus capital on higher margin oil production. In the Permian Basin we have two distinct, but synergistic businesses; resources and enhanced oil recovery. Our resources business provides the unconventional portfolio and expertise to achieve accelerated growth supported by our EOR business which provides the cash flow from efficient high volume production. In Permian resources our capital expenditures will be approximately $1.7 billion. This is a $200 million reduction from 2014 expenditures. We plan to operate an average of 19 rigs and drill approximately 167 horizontal wells which is equal to the number of horizontal wells we drilled in 2014. Additionally, we will drill only 48 vertical wells versus the 137 vertical wells drilled in 2014. Vertical wells are drilled to hold acreage or to appraise new benches. Our 2015 capital program will focus on the development of our best benches in concentrated geographic areas. In the Midland basin our development activity will be mainly in South Curtis Ranch and Mirchett [ph]. Here we plan to drill 45 Spraberry wells, where our performance is matching a 750,000 BOE type curve. In the Delaware basin, we plan to drill 67 Wolfcamp A wells and a concentrated number of leases in the greater Barilla Draw area. Our Wolfcamp A wells in the Delaware are exceeding a 900,000 BOE type curve. In New Mexico, we plan to drill 22 Bone Spring wells. We will execute this targeted capital program utilizing a manufacturing approach which will include the efficiencies of pad drilling, batch drilling of the vertical and lateral selections of the well, along with zipper fracs. This strategy will enable us to grow our production at a higher rate with less capital than in our 2014 appraisal program. In the first quarter of 2015, we plan to operate an average of 29 rigs. We expect to drill 85 wells and place 108 wells on production including 63 horizontal wells. We're on pace to have 42 wells on flow-back or on production in January. Permian resources has a sufficient inventory of wells to continue profitable development in a low price environment. Based on our current cost structure, we have the ability to continue drilling profitable wells for several years. We're taking the following actions to ensure we can deliver even more locations in this low price environment. First, we will continue our investment in reservoir characterization and optimization of key variables such as well bore spacing, lateral length, proppant concentration, surfactants, cluster count and spacing. These investments drive resource recovery and are fundamental at any price. Second, we will continue to apply enhanced manufacturing principals to our development program. This will enable us to achieve efficiencies at an accelerated pace. Third, we will continue our efforts to enhance our base management and maintenance activities. This will ensure optimized production levels while minimizing associated operating costs. Lastly, we continue to aggressively work with our suppliers to improve operating productivity, eliminate constraints and lower costs. These actions are consistent with the long term strategy I have discussed in previous calls. I'm encouraged by the urgency and actions our employees and contractors have already demonstrated in delivering on these initiatives. I will now discuss our Permian EOR business. While it hasn't drawn much attention in the last couple years with the industry focused on high growth resource programs, our Permian EOR business remains very profitable. Oxy is the leader in Permian basin CO2 flooding with over 30 active floods and 40 years of experience. This business has weathered prior downturns with resilience and the low decline of these large properties provides a stable base for our production at an advantaged cost. The Permian EOR business has the agility, scale and cost structure to operate in an ultra-low pricing environment. Currently, our total cash costs in Permian EOR is $30 a BOE as shown on the slide. This takes into account the cost reductions that we have already achieved. If prices stabilize at today's level or continue to decline, all costs that are linked to oil prices would also decline including energy CO2, production taxes and discretionary well maintenance activities. For example, in a $35 per barrel oil price scenario, our total cost would reduce to approximately $22 a BOE. Our DD&A cost is approximately $10 a BOE. We continue to see opportunity for investment in CO2 projects in the current oil price environment. Last year we drilled 277 infill wells and continued construction of facilities for new CO2 projects. When completed, our new project at South Hobbs will develop 28 million barrels of oil equivalent of reserves at a cost of $10.60 per BOE. The CO2 floods have remained a strong business through technology advancement that improves recovery from our large portfolio of conventional reservoirs. In the Permian, Oxy operates reservoirs that collectively contained approximately 18 billion barrels of original oil in place. Hence, even small improvements in recovery efficiency can add significant reserves. An example of this has been the recent trend towards vertical expansion of the CO2 flooded interval into residual oil zones or ROZ targets. Over the last few years, we have had an ongoing program of deepening wells with 109 wells deepened in 2014 and 81 wells planned in 2015. This activity escapes much attention because we utilize work-over rigs to drill the extra depth into additional CO2 floodable sections of the reservoir. These low cost projects add reserves at development rates ranging from $3 to $7 per BOE. These opportunities exist under many of our CO2 projects and thus far only a fraction of the CO2 flood wells has been deepened. The Permian EOR 2015 capital expenditures will be approximately $500 million to continue expansion of CO2 floods and water floods. The EOR business is expected to generate free cash flow this year even in the current oil price environment. We will complete construction and begin injection at the new South Hobbs project. Additionally, we'll also start construction of a significant expansion at the successful North Hobbs CO2 flood, where CO2 flooding has added a sustained 5,300 barrels of oil per day to the unit's production since this project began in 2003. Our EOR business has unrisked gross resource potential of up to 1.9 billion barrels providing us with a vast inventory of future CO2 projects which could be developed over the next 20 years or accelerated, depending on market conditions. Our current strategy for this business is to investment sufficient capital to maintain current production thereby providing cash flow to support growth in our Permian resources business. By exploiting natural synergies between our EOR and resources businesses, Oxy is able to deliver unique advantages, efficiencies and expertise across our Permian Basin operations. In closing, our 2014 exploration and appraisal programs have successfully set us up for a strong 2015 development program in Permian resources. Our portfolio of high quality assets combined with our value-oriented discipline enables us to deliver efficient growth. We will execute a focused development strategy in 2015 and continue to pursue step changes in well productivity and cost structure. Our first quarter production of 2015 will be negatively impacted by approximately 4000 BOE per day due to the winter weather events that occurred in the Permian Basin in January. But we do expect to deliver our previously stated target of 100,000 BOE per day from Permian resources in 2015. Our combined EOR and resources production is significant and accounts for 15% of the production from the Permian basin. Our development program, along with the synergies delivered by our resources, EOR and midstream businesses have us well-positioned to the meet the challenges of this lower price environment. Now I'll turn the call back to Chris.
Chris Degner:
Thank you, Vicki. Now we will open the call up for questions.
Operator:
[Operator Instructions]. Our first question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate:
I wonder if I could take two, please. Vicky, this one is profitability for you. I guess just to be absolutely clear in this current oil price environment, not the $55 that you have put in the plan I guess, has the Permian program delivering positive returns? And if you could maybe give some color as to what royalty ownership or what royalty rates you might have in the program for the current year of gas in the Delaware basin.
Vicki Hollub:
Yes, Doug, currently our program at today's prices will deliver about 15% to 20% rates of return and the reason for that is, we had an aggressive program, appraisal program in 2014, so we have - we're targeting in 2015 our best benches in our best areas. And we have had really good success recently with improving our completion design. So we expect the returns to be in the 15% to 20% range. And if you will refer back to the chart I included in the presentation in Q3, you will see that if you look at the areas where we're developing, I think I have some numbers there that generally would enable you to get to the net interest.
Doug Leggate:
Okay. Maybe just not to belabor the point, Vicki but what kind of inventory in terms of what the current pace, the wells would achieve, the program would achieve that kind of return of $45 oil, is that like high grading the portfolio or is that a multi-year inventory that you believe to achieve there?
Vicki Hollub:
We have high graded the portfolio but we expect to be able to at least at this pace go at least 3 to 5 years with the inventory that we have and if prices continue to improve with respect to the cost structure and I don't mean oil prices, oil prices, I mean if our cost structure continues to improve based on prices, we expect that inventory should increase. So we expect over time to be able to increase the inventory that we have today. But at today's pace, it would be about 3 to 5 years.
Doug Leggate:
My follow-up is I guess and not a lot of other questions with new operations, but Steve, I wonder if I could go back, just to the progress on the asset sales in the Middle East. Any updates you can provide, especially now that Al Hosn is on-stream and given that the [inaudible] contract expires this year, could you help us with how you see maybe things changing in this oil price environment?
Steve Chazen:
Well of course, the countries are saying that the prices will quickly rebound once the evil shale producers stop producing. But I think until that happens, I think it's going to be slow. I mean obviously, the countries are affected by this. I mean they are actually affected more by the decline in oil prices than anybody really. So I suspect that it will be slow. I think Oman will move along all year. We just don't know what is going on in Abu Dhabi at this point.
Operator:
Our next question is from Paul Sankey of Wolfe Research. Please go ahead.
Paul Sankey:
Steve, talking again back to the CapEx program, it seems that you have used the strip to come up with the 2015 number. I just wondered how much lower would you have to take CapEx if we stay at the smaller $45 environment for let's say another year?
Steve Chazen:
Well for another year, it a little more complicated. The capital spending on the chemicals and the midstream stuff will fall out naturally, going into next year. So the capital would come down any anyway. We have only built in the cost savings that have sort of been achieved at this point. And there is at least another 250 million and maybe another $500 million in savings if - just from the suppliers, if prices continue to be low because we basically we provide index how much we're paying to the oil price. So I don't really know exactly what it would be, but I would guess it would be used - if it's 60, we're covering everything at the end of the year. There is some other stuff that would be reduced and it's probably a little lower than the 60 actually and so if you said okay, it is going to be $10 less, $10 less is a billion dollars. So we would have to reduce the capital by a billion dollars. Most of that we would get from suppliers, but there would be some things that would have to be cut.
Paul Sankey:
And then a follow-up would be, have you considered selling Oxy and have you considered any major acquisitions? Thank you.
Steve Chazen:
Right now, people are cash flow challenged so I suspect selling Oxy is probably not real likely. But I looked at Chevron, it looks like they don’t have any free cash. So anyway, if you look at - we have 690 major acquisitions. It's way too early to be talking about acquisitions. I think there is still a lot of whistling in the grave yard going on. And way too early to consider any kind of acquisitions. Again, we generally are not interested in public acquisitions.
Operator:
Our next question is from Doug Terreson of Evercore ISI. Please go ahead.
Doug Terreson:
I had a question about divestures as well, there is some commentary in the market about possible divestiture of the Al Hosn project which you guys have just completed and so just wanted to ask you, is that a possibility? Just if you could provide some color on that and again it wasn't your commentary, it was that from others but can you give us an update on the strategic position attractiveness of that position?
Steve Chazen:
Well let's talk about what it is. We have already spent the money. So there is not really much capital going forward. There might be an expansion which is really cheap capital out a year or so, but putting that aside in a crappy oil price environment, probably generate about $300 million of free cash and sort of a decent run, about $600 million of free cash a year. So if you multiply it out by the 25 years that remain roughly, you multiply it, you get Sr. between $7.5 billion and it is $12.5 billion of cash generated over the 25 year period. So from our perspective, for a company that pays a lot of dividends and that sort of thing, having that sort of asset makes good sense to us. If on the other hand, for a variety of reasons, somebody wanted to buy 20%, 30% of it, to free up cash, for something that maybe works better, I guess we're open to that. But you know, only in a - if you just look at intrinsically, for somebody who pays a lot of dividends, you know, I think it's a pretty good asset over time.
Doug Terreson:
And then also, there is a lot of commentary about Oxy's historical proficiency and recovery so I wanted to see how are you thinking about the opportunity in Mexico, potential opportunity, meaning do you consider this to be kind of an area of natural alignment for Oxy? And if you do, how do you think about the opportunity in Mexico?
Steve Chazen:
I mean there's two issues always in foreign activities. One is the quality of the asset being offered. And I think if intrinsically they have some enhanced oil recovery assets on offer. The other part of it what's the financial arrangements. If you look at some of the other places, I won't say where, but look at some of the other places where intrinsically the asset might work at $20 a barrel or something like that, but if you lay the contract over it doesn't really work at today's prices. And I think that’s the issue in Mexico. While the asset may be attractive and you can get a lot of - if you had 100% of it would be something that would work pretty well, but they have taken a pretty aggressive view about the contract terms. I think they took the Chinese menu approach where they pick one from every column and everybody's contract. So I think they got a pretty difficult contract to want to do it and we're not doing it for advertising expense. I think we would rather frankly put the money into the CO2 projects in the United States where we have low royalties and in fact in some cases we owe the royalties than to fool around with some ridiculous contract in hopes it gets better over time.
Operator:
Our next question is from Leo Mariani of RBC. Please go ahead.
Leo Mariani:
Obviously, a lot of focus here in terms of how you guys can kind of conservatively manage things. Wanted to kind of flip the question around and just get a sense, if we do start to see an oil price recovery in the second half of the year, in 2016, kind of how quickly you can bring rigs back in the Permian and then just additionally, is there any kind of loose price framework we should think about, where if we do get to 70 is that the number where you start adding rigs? Anything you can help in terms of price would be great.
Steve Chazen:
I think the answer to your question is there's a lot of rigs around in the Permian and there's more available every day. So I don't think bringing rigs back is going to be a problem. I think the program has to be somewhat disciplined and so we will be cautious in adding rigs, because oil prices may rebound, may go back down again. I'm more concerned really about the demand issues in the world than I am how much the U.S. business is producing. But I think if you look at it and said - clearly, if we hit the $60, the program will be the way we’ve described it. As you get to $70 and maybe a little more aggressive and as you get north of $70, I think we would be somewhat more aggressive. But I really think that, if you look at - if you were able to see the layers, inside the company, we've got it all matrix, if we can actually figure what makes sense at whatever price you want and so our program going forward would reflect that expectation, but right now, our expectation is conservative, I would guess.
Leo Mariani:
All right. Maybe could you just talk a little bit about the importance of returns on the drilling program, plus kind of versus desire to stay cash flow positive or cash flow neutral when you include dividends. Obviously you focused on getting back to this cash flow neutrality, exiting the year at 60. So as we think about a recovery case in 2016, how much are you focused on making sure you don't outspend versus hey if the returns are good at 70 we're willing to outspend. Can you talk to that?
Steve Chazen:
You got to be pretty certain about your returns before you outspend. No offense to any oil engineers, but they tend to be a little more optimistic than the actual outcome. And so the corporate management will be fairly conservative about things. So we need some margin of error. A lot of damage has being done in the business, I think people underestimate the amount of damage being done, when this cycle when this current down cycle is complete whether it's a year or two years, everybody's balance sheet is going to be not quite as good as when they started. We're starting at a good spot, but I think even the large companies will have more debt-laden balance sheets and not really much to show for it. So I think you just got to be pretty careful in this environment about what you are doing. No one really, even though the price may recover in the back half of the year, I'm still concerned about world demand for oil, although I'm heartened to see that in the United States at least the lower gasoline prices have created more people riding around in big cars. So we're doing all right. We're rides around the corner.
Leo Mariani:
And I guess just lastly, in terms of M&A, I just wanted to kind of clarify some of the comments, you certainly talked about sort of a challenging market, you know for acquisitions at this point in time, it sounds like bid/ask spreads having a reset but they are also here in the prepared comments that you had made an acquisition in the fourth quarter of 2014 of 120,000 acres in the Permian of around for $1.3 billion. Can you give us more color on what you picked up there and what you think about it?
Steve Chazen:
It was early in the quarter, probably a little early in the acquisition I think, the acquisition cycle. We got we think a price that works in this environment. It's good acreage. And we picked up a modest amount of production. So the goal of the acquisition program in the Permian is to add to our current position, so we can drill more efficiently and it's not really to get more acreage. We have got plenty of acres. I mean the question really is can we fill in our play, what we currently own and allow us to drill more efficiently without moving the rigs so much. So this sort of acquisition was designed with that intent that we could - that would allow us to be more efficient. Without efficiency gains, I think acquisitions are not very interesting.
Operator:
Our next question is from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.
Jeffrey Campbell:
First, just a couple of quick Vicki questions. I noticed that the Delaware basin second spring had been re-rated from appraisal to development from last quarter to this one. Is that the zone that you’re focusing on in New Mexico?
Vicki Hollub:
Yes, it is. We're only going to drill second Bone Springs wells in New Mexico in 2015.
Jeffrey Campbell:
It sounded like the reduced vertical drilling is tied to less appraisal work. Can you identify which appraisal zones are likely to be most affected by the reduced 2015 CapEx?
Vicki Hollub:
It would really be the zones, the benches that are away from our current development areas. So for example we appraised the benches at South Curtis Ranch and several in the Barilla Draw area, so what we're really going to try to do now is focus on the development in those areas. And our appraisal program is so far ahead, we still know a lot about some of our other areas. We just wanted to get to manufacturing mode so that we can improve our cost efficiency. So we're still - we're pretty much way ahead with our appraisal program right now. The thing that we want to do next is to continue to improve on our completion efficiency.
Jeffrey Campbell:
And Steve, this is the last question, you have spoken some about concerns on demand. Can you outline where you look for signs of improvement? Particularly as we all can expect that U.S. oil production is going to increase as oil prices begin some kind of recovery?
Steve Chazen:
Well, you know, I think if I look at U.S. oil production, it will probably increase in the first and second quarter and maybe the rate of increase in the third quarter will fall off and maybe it will be some decline in the fourth quarter. You know, the main consumer of oil today is China. Any recovery in Europe would be helpful, but it's not a driver and so it's China and maybe India. Also the Middle East has been a large consumer of oil recently and the current environment is - it's just hard to say whether that growth will continue or not. And I think the world economy, I think, that’s the big question mark going forward. If we get demand growth, lower oil prices stimulate demand, this current situation will be over fairly quickly. If we don't, this could drag on quite a while.
Operator:
Our next question is from [inaudible] of Jefferies. Please go ahead.
Unidentified Analyst:
I wanted to ask the question about the importance of operational momentum in the Permian Basin and really where I am coming from here is you are generating very acceptable returns at current prices, but that could potentially be significantly higher rates of return assuming a recovery in the oil price. So given that you are more or less flat on horizontal drilling activity, what stops you from let's say having the rig count in the first half of the year and then moving up to a much higher count in the back half of the year?
Steve Chazen:
It's basically the contractual position we have. We have contracted for some rigs that basically come off at mid-year. And by the time you drill - I mean think about the timing. Let's say you actually drill a well in the first quarter. It's the third quarter before it actually produces, you know, you actually get the revenue, so the stuff in the first quarter will basically be a third and fourth quarter production for us. But I think we have some contracts that need to roll off and that's really controlling the timing more than anything right now.
Unidentified Analyst:
Okay. So there is nothing related to utilization of the work force and efficiencies that could be elastic, but if you did have a shutdown or anything of it--
Steve Chazen:
It's always inefficient - if just always stop in the middle it's always going to be a problem. It's got to be a phase-down, but it's contractual and a notion that may be there will be some recovery in the back half of the year and you need to drill the wells sort in this first and second quarter to have production in the back half of the year. We're pretty cautious about the whole thing. You just can't send things to zero, it's just an impractical thing to do right now. We're doing the best we can to manage through it and I think we will be all right.
Unidentified Analyst:
Okay. And if I could ask one more, completely unrelated topic, you mentioned that the restricted cash was used to pay the dividend in the 4Q, should we think in a low price environment restricted cash essentially funding the dividend and how does that affect then the pace of share repurchases? You said that the 71 million, you still ultimately expect to buy in on the share repurchase program, but would that be a five-year period or are you thinking more like a two-year period?
Steve Chazen:
We will start with - I wouldn't get wrapped around the axle on this restricted cash stuff. Cash is reasonably fungible and all we’re doing is showing you the account paying down. It's not really - rather than keep more restricted, we just say the dividend comes out of that bank account. So it has to come from somewhere. We don't really know about the pace. We're price sensitive. You know, I point out that really the domestic program last year had an F&D, if you cut through all of the BS of $13, $14 and we expect to bring that down some more. So we're running a pretty profitable program. Maybe not at $25 oil but certainly in the 50s. So as far as the pace of the share repurchase, the stocks are volatile and when there is negative volatility, I guess volatility is always used negatively, but nobody ever talks about upside volatility, but down side volatility which I'm sure will come at some point in this, that's almost a step up and buy a lot of shares rather than just treat it as a constant flow. So I don't really know. We set aside a fair amount of money for that this year, but if prices are more attractive, we will spend more. I don't really have a budget in the usual sense of the word.
Unidentified Analyst:
And would you want to comment on what you would find an attractive price to?
Steve Chazen:
No I wouldn't want to.
Unidentified Analyst:
Okay, I figured that. Thanks very much.
Operator:
Our next question is from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer:
I wanted to follow up on a couple of the earlier questions. First, you mentioned that you would have flexibility to increase activity if you can get another $250 million in savings. Can you just talk more to what that scenario looks like? Would that mean your portfolio would achieve attractive returns at $60 Brent and you would ramp back up in the areas that you are currently ramping down, i.e., you would recommit to MidCon or would you just ultimately look to focus more on the incrementally--
Steve Chazen:
It would be all Permian. The MidCon is, well, putting aside South Dakota, is basically gas. So the Brent price is sort of irrelevant. And it really can't compete for dollars for quite a while against the Permian. North Dakota has this huge differential to price right now. So that's really what's discouraging us up there. So I think you should plan that in the $60 environment or $65 environment, whatever you are thinking that we would spend more in the Permian. The savings, $250 million, we could add about 3 rigs on an annual basis to cover that. So it was running about 100 million a year or so, it would probably run a little less now. So that is a way to think about how much more we would do. But we got a fair inventory and as prices move up, the inventory obviously expands.
Brian Singer:
And then back to the Permian acquisition in looking at that 100,000 acre deal you mentioned the strength was the efficiency that it has with existing positions. Based on the placement of your existing acreage within the Permian can you just talk to the scope for how many more fill-in acres would be optimal for you with your acreage positions and whether you see those opportunities becoming available?
Steve Chazen:
We don't know about opportunities because some people may have debt and they probably don't want to sell it for less than their debt. We just don't have any way of pacing that at this point. We don't really know. If we found more in the Barilla Draw, that would be really interesting and there is acreage around there that’s held by others. And some a little bit in the Midland basin, but that is what we have. I don't know whether it's 300,000 acres or 200,000, it's not millions of acres.
Operator:
Our next question is from Ryan Todd of Deutsche Bank. Please go ahead.
Ryan Todd:
Maybe a couple more follow-up questions on the Permian. Can talk a little bit what you're seeing from a well performance point of view in 2015 and 2016 production targets [inaudible] despite CapEx cuts, is this the efficiency gains? Better well performance? Combination of both?
Vicki Hollub:
It is. We haven't changed our 2016 target yet, because we're still anticipating that. If prices were to go up, we would have the flexibility to add rigs. We may have to adjust that a little bit toward the end of this year if prices remain where they are, but one of the things we're encouraged is we certainly are seeing better performance particularly in the Barilla Draw area and particularly with the last well that I mentioned in the call today. We're seeing not only opportunities to improve our landing point within the benches but our completion efficiencies are improving and so we're really encouraged with what we're seeing there and what we're see from the Spraberry in the Midland basin.
Ryan Todd:
And then maybe on cost at this point, the 2015 budget, your approval budget costs in the Permian in 2015, what is it relative to 2014 costs and is it that mostly efficiency gains or do you have anything for price deflation or is that additional upside?
Chris Stavros:
We priced about 250 million for cost reductions that we pretty much achieved. And we expect to get some more, but we certainly do price that in already and efficiency gains are built in. Efficiency gains really come from focusing on a few places rather than going all over creation. That's really what causes it and we built that in.
Ryan Todd:
So I guess in additional $250 million that you had highlighted on the slide, there is certainly potential down side from a price deflation point of view but efficiency gains at least mark-to-market from where you guys are right now, I guess.
Chris Stavros:
I guess that's right.
Operator:
Our next question is from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio:
A few quick follow-ups for me. First on the buyback I presume most of the buyback in 4Q was executed after or in December after the spin?
Steve Chazen:
Yes.
Evan Calio:
And the second, I know that you're price sensitive and/or I would say price aware, so do you see the flexibility to use your currency for adding assets, if your view it were to be expensive relative?
Steve Chazen:
We have never - I think I used stock once in the last 20 years and regretted it ever since. So maybe I have been doing this too long. So too good of a memory about bad outcomes. If you are going to use your stock, you really have to make sure that whatever you are doing is significantly accretive. Cash, at least cash, you are you only paying 3% or whatever it is interest, but if you're using stock, we're paying almost 4% in dividends by putting even putting that aside, we don't want to dilute the quality of your portfolio with some whacky deal. And so if you are going to gamble on wackiness, you probably ought to gamble with cash rather than stock.
Evan Calio:
So maybe a follow-up on the Permian acquisition that you made in the quarter, any color in terms of location, well inventory--
Steve Chazen:
It's a Midland basin acquisition. And there is a - I mean just a matter of price. When you talk about locations, you also got to factor in price. I think going in, I thought it was about 2700 locations.
Evan Calio:
Okay. And will you expect activity there in 2015 or will that be part of your focus area?
Steve Chazen:
Yes, we do.
Evan Calio:
Is that due to economics or because it is non-HBP?
Steve Chazen:
It is economics principally. There is some non-HBP. We will probably use a vertical rig there to keep some of the acreage.
Operator:
Our last question is from Matt Portillo of TPH. Please go ahead.
Matt Portillo:
Just a quick follow-up question in regards to your Permian rig count and spending program. I believe you mentioned you're running roughly 29 rigs coming into the first quarter. Was curious if you could give us a little bit of color on the cadence of kind of that rig drop as you move through the year, to average the 19 rigs in 2015? And then I have a follow-up question with regards to your overall capital program.
Vicki Hollub:
Currently, we're going to average also 29 rigs in Q1 and then toward the end of Q1, we start to ramp down and by Q3, the beginning of Q3 we will be at 15 rigs. And at 15 through the rest of the year.
Matt Portillo:
And then in regards to your corporate capital program, you mentioned the first quarter will be a bit heavier in terms of CapEx versus the--
Steve Chazen:
You can see that in the rig count. It just flows out of the rig count.
Matt Portillo:
Right. And I guess just to maybe try to get a little bit of color around how we should think about the magnitude of the change on cap ex, is there any color you can provide as we think about kind of the exit capital program you have talked about in the fourth quarter of 2015, how you would kind of think about the magnitude of the change over the year?
Willie Chiang:
I would say directionally, we're starting off at about a 1.8 billion in Q1 and ramping down to about a 1.2 billion rough numbers.
Operator:
This concludes our question and answer session. I would like to turn the conference back over to Chris Stavros for any closing remarks.
Chris Degner:
Thank you, Emily and thanks everyone for participating today. Bye.
Operator:
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
Executives:
Chris Degner - SVP, IR and Treasurer Chris Stavros - CFO Steve Chazen - President and CEO Vicki Hollub - President, Oil and Gas, Americas Willie Chiang - EVP, Operations Sandy Lowe - President, International Oil and Gas Operations
Analysts:
Evan Calio - Morgan Stanley Doug Terreson - ISI Doug Leggate - Bank of America Merrill Lynch Leo Mariani - RBC Capital Markets Ed Westlake - Credit Suisse Jeffrey Campbell - Tuohy Brothers Investment Research Roger Reid - Wells Fargo Securities Paul Sankey - Wolfe Research
Operator:
Good morning. And welcome to the Occidental Petroleum Corporation Third Quarter Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation, there will be an opportunity to ask questions. (Operator Instructions) Please note, this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead.
Chris Degner:
Thank you, Denise. Good morning, everyone and thank you for participating in Occidental Petroleum’s third quarter 2014 conference call. On the call with us this morning are Steve Chazen, OXY’s President and Chief Executive Officer; Chris Stavros, Chief Financial Officer; Vicki Hollub, President Oil and Gas in the Americas; Willie Chiang, Executive Vice President of Operations and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment, I will turn the call over to our CFO, Chris Stavros, who will review our financial and operating results for the third quarter and also provide some guidance for the current quarter. Our CEO Steve Chazen, will then provide an update on the progress of our strategic initiatives and outlook for 2015. Vicki Hollub, will then provide an update of our activities in the Permian Basin. Willie Chiang will conclude the call with an update on OXY’s Midstream operation. As a reminder, today’s conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on the factors that could cause results to differ is available on the Company’s most recent Form 10-K. Our third quarter 2014 earnings press release, the Investor Relations supplemental schedules, and the conference call presentation slides, can be downloaded off of our Web site at www.oxy.com. I’ll now turn the call over to Chris Stavros. Chris, please go ahead.
Chris Stavros:
Thanks, Chris, and good morning everyone. We generated core income of $1.2 billion for the third quarter of 2014 resulting in diluted earnings per share of $1.58, a decrease from both the year ago quarter and the second quarter of 2014. The decline in core earnings was attributable mainly to lower realized oil prices on a worldwide production and the sharp decline in trading performance on a sequential quarterly basis. For the fifth consecutive quarter, we continued our strong domestic oil production growth. We met our guidance and achieved the year-over-year domestic oil production increase of 20,000 BOE per day or about 8%, let by our Permian and California assets. We also repurchased 4.7 million shares of our stock during the quarter and ended the period with 2.9 billion of cash on our balance sheet. Oil and gas core after tax earnings for the third quarter of 2014 were $1.1 billion, $90 million lower than the second quarter of this year and $236 million lower than last year’s third quarter. For the third quarter of 2014, total company oil and gas production volumes averaged 755,000 BOE per day, an increase of 19,000 BOE in daily production from the second quarter and 6,000 BOE per day from the same period a year ago, which excludes production from the Hugoton assets for all periods. Our third quarter 2014 realized oil prices of $94.68 per barrel fell by $5.70 compared to the second quarter realizations of $100.38 a barrel. In the third quarter of 2014 after tax core income for our domestic oil and gas operations was 538 million. On a sequential quarter-over-quarter basis, results at our domestic operations were negatively impacted by lower realized prices across all products. Improved volumes however offset roughly a quarter of the earnings decline caused by lower prices. On a year-over-year basis, domestic operations declined by 252 million after tax which reflected the impact of lower realized oil prices partially offset by increased oil production volumes. The lower realized oil prices were impacted by the large differentials we saw in the Permian Basin. Willie Chiang will provide a more in depth discussion around Permian differentials later on in the call. Total domestic oil and gas production averaged 475,000 BOE per day during the third quarter of 2014, up 11,000 BOE per day sequentially. Domestic oil production was 282,000 barrels per day during the third quarter, a new quarterly record for OXY. Domestic oil production volumes increased by 20,000 barrels per day from the year ago quarter with our Permian Resources business growing its oil production by 26% to 43,000 barrels per day. On a sequential quarter-over-quarter basis, total domestic oil production growth was 6,000 barrels per day. International after tax core income was $624 million for the third quarter of 2014 with results improving by 8% sequentially due to a lifting in Iraq which had none in the second quarter and higher sales volumes in both Colombia and Qatar. Income for our international oil and gas operations remained about flat versus the year ago period. International oil and gas sales volumes rose by 4,000 BOE per day on a sequential quarter-over-quarter basis. The improvement was largely due to higher volumes in Colombia which experienced fewer pipeline incidents in the period. Oil and gas cash operating cost were $14.89 per barrel in the third quarter of 2014 compared to $14.68 per barrel in the second quarter. Taxes other than on income which are directly related to product prices were $2.64 per barrel for the third quarter of 2014 and $2.80 for the first nine months of the year. Third quarter exploration expense was $53 million. Chemical third quarter 2014 pre-tax earnings were $140 million compared with second quarter results of $133 million and $181 million in the year ago quarter. Although slightly below our guidance, the sequential improvement in the third quarter was due to higher caustic soda prices and volumes along with lower natural gas costs, offset by lower vinyl’s margins resulting from rapidly escalating ethylene cost. We expect our fourth quarter pre-tax chemical earnings to be about $115 million reflecting a historical slowdown, seasonal slowdown, due to the combination of maintenance outages, holiday shutdowns and some customer initiatives to reduce year-end inventories. Midstream pre-tax segment earnings were $125 million for the third quarter of 2014 compared to $219 million in the second quarter and 212 million in the same period a year ago. The 2014 sequential quarterly decline in earnings resulted mainly from much weaker trading performance driven by sharp commodity price movements during the period, partially offset by higher income from power generation and the domestic pipeline businesses. In the first nine months of 2014, we generated $8.6 billion of cash flow from operations before changes in working capital. Working capital changes decreased our cash flow from operations by $416 million to $8.2 billion. 2014 year-to-date cash flow from operations declined by approximately 1.6 billion compared to the same year ago period. The first nine months of 2014 included tax payments of 570 million related to the gain of the sale of the PAGP units and our Hugoton assets and the first nine months of 2013 included the collection of a tax receivable. Capital expenditures for the first nine months of 2014 were 7.3 billion net of partner contributions. Our capital outlays included 410 million associated with the Al Hosn Gas project and $275 million for the BridgeTex pipeline. During the first nine months of this year, we received proceeds of $1.3 billion from the sale of our Hugoton assets and spent about $425 million toward domestic bolt-on acquisitions. We issued 1.6 billion of commercial paper during the latter part of the third quarter as part of our short-term cash management process which has already been repaid. After paying dividends of 1.6 billion buying back 2.1 billion of company stock and other net flows, our cash balance was 2.9 billion at September 30. Our debt to capitalization ratio was 16% at quarter end. Our 2014 annualized return on equity was 12% and return on capital employed was around 10.5%. Earlier this month, we received cash proceeds of approximately $5 billion from the bond offering completed by California Resources. IRS rules mandate that the use of these proceeds be restricted to share repurchases, dividend payments or debt retirement. We will be receiving an additional 1.2 billion of cash from California Resources concurrent with the spinoff in late November. The use of these proceeds will be unrestricted. The worldwide effective tax rate on our core income was 40% for the third quarter of 2014 and we expect to combine worldwide tax rate in the fourth quarter to remain about the same. Lastly, I will outline some guidance and a few points on our reporting disclosures for the fourth quarter. Due to the recent sharp decline in oil prices and the completion of the California spinoff at the end of the next month, it will be difficult for the financial community to predict our earnings per share for the fourth quarter. When OXY completes the spinoff of California resources at the end of November, we will reclassify the financial and operational results to discontinued operations for our core results disclosure. As such, our fourth quarter core income will exclude all of California results and income on a reported basis will include two months of California results. Total year results on a reported basis will include 11 month contribution from our California operations classified as discontinued. Included in the IR supplemental schedules is a pro forma table segregating OXY’s sold and spun off domestic production from our ongoing operations for the historical quarterly 2013 and 2014 periods. For the fourth quarter, we expect to see continued production growth from the Permian Resources. In addition, with the startup of the BridgeTex pipeline, OXY will capture a portion of the spread between LLS and WTI Midland on approximately 200,000 barrels per day of oil transported to the Gulf Coast. Willie will discuss the benefits of the BridgeTex startup in a few moments. We expect our international volumes to increase in the fourth quarter with the Al Hosn Gas project coming online and the positive impact to volumes for our production sharing contracts that are sensitive to the decline in oil prices. On a go forward basis, excluding California, price changes at current global prices affect our quarterly earnings before income taxes by $29 million for $1 per barrel change in oil prices and $6 million for $1 per barrel change in NGL prices. A swing of $0.50 per MMBtu in domestic natural gas prices affects quarterly pre-tax earnings by about $15 million. These price change sensitivities include the impact of production sharing contract volume changes on income. Our fourth quarter 2014 exploration expense is anticipated to be about $60 million pre-tax. I’ll now turn the call over to Steve Chazen who will provide an update on some of our strategic and growth initiatives.
Steve Chazen:
Thank you, Chris. The overall business is operating well, and our increased investment focused in the Permian Resources operation is evidenced by the 24% year-over-year growth in total production. Other long-term investments such as the BridgeTex pipeline and the Al Hosn Gas project should also begin contributing to our results in the current quarter. We continue to make steady progress towards furthering our strategic initiatives outlined a year ago. The spin-off of California Resources is on-track and we expect to distribute approximately 310 million shares to new California Company to OXY shareholders at the end of November. California Resources completed its debt financing earlier this month and distributed approximately 5 billion in cash to us as a tax free dividend on October 9th, the dividend of 1.2 billion of proceeds from the term loan and credit facility will happen concurrent with the spin-off. After the spin-off and for a period of lasting up to 18 months OXY will retain approximately 75 million shares of the California Company. At some point during this period we intend to conduct an exchange offer for the remaining California shares for OXY shares further reducing our own shares outstanding. Over the years OXY has made significant investments in California oil and gas and has built a solid business. With the separation of these assets the California operations will be classified as discontinued. The resulting impact is expect to provide lower unit rates for cash operating costs, DD&A and F&D costs for OXY as well as improved reserve replacement ratios on both on a historical and an ongoing basis. Regarding our interest in the Williston and Piceance Basins given the current product price environment we plan to operate these assets with less capital in order to generate free cash and shift our investment towards our higher growth and higher return on operations in the Permian Basin. In the Middle East we continue to make progress negotiation with our partners towards a partial monetization with a goal to improve the business’s ability to grow profitably from a somewhat smaller base. Overtime we expect to achieve a similar balance in our asset mix and roughly 60% of oil and gas production coming from the United States. Overtime we also expect to monetize our remaining interest in the GP of Plains All-American Pipeline which is currently valued at more than $4 billion. And this is some other midstream assets and market conditions warrant. We expect to generate a large amount of cash proceeds from initiatives I have mentioned. While we expect the bulk of these proceeds will be used to repurchase our own shares, we also hope to invest in the business through attractive bolt-on acquisitions in our core area of the Permian Basin. Opportunities may exist for accretive property acquisitions that have current production and growth prospects and also complement our existing acreage. We have no intention of acquiring public companies since their current pricing reflects high oil prices and a near perfect outcome for production. Since the end of the third quarter of 2013 we have repurchased approximately 31 million shares of the Company’s stock for nearly $3 billion. The Board recently authorized repurchase of additional 60 million shares of the Company’s stock leaving the program with 76 million shares. We’re currently undergoing our annual capital budgeting process and are mindful of the recent decline in oil prices. A significant amount of long-term investment including the capital for BridgeTex pipeline and the Al Hosn project is nearing completion. We expect our overall capital program to decline in 2015 given the absence of California and the completion of multiple long-term projects. We also expect significant decline in our spending in the Middle East as we begin to reap the benefits of some of our earlier long-term investments. The vast majority of capital budget next year will be allocated to our domestic oil and gas drilling operations while we maintain flexibility in our budget. We also expect that since the service companies were happy to raise prices when oil was going up that they would have been just as happy to have their prices lower in the future. Some of the reductions in the program in a long-term project will be allocated to profitable growth opportunities in the Permian Resources, midstream and chemicals. If lower crude oil prices persist or fall further, we will adjust our capital program to manage within our cash flow, probably by reducing or not growing this quickly in the back half of the year. We plan to provide more detailed capital program for 2015 during the fourth quarter earnings call or early next year. Excluding California we expect to see an acceleration of total oil and gas production growth in 2015 given the ample opportunity of capital deployment in the Permian Resources and the ramp-up of production from Al Hosn. In the United States we expect Permian Resource to deliver production growth of at least 20% in 2015 primarily from oil. We expect the resources business to exit 2014 at over 80,000 BOE a day and to exit next year at over 100,000 BOE a day. Our total domestic production excluding California should grow 5% to 8% reflecting a modest decline in our natural gas and NGL volumes. In the Middle East first production of Al Hosn Gas project is anticipated later this quarter. OXY’s net share of production is expected to ramp towards 60,000 BOE a day during the first half of next year. Company-wide and excluding California we expect our total oil and gas production to grow 8% to 10% next year. While a recent sharp decline in oil prices may provide some headwinds to the business in 2015, our commitment to a conservative balance sheet with low cost oil production gives us confidence in our operations and the capacity to make targeted property acquisitions. We expect our cash balance to exceed our total debt by the end of this year. OXY has built to thrive in an environment where our core properties in the Permian EOR business and production sharing contract for the Middle East which provides relatively stable cash flow. Following the execution of the California spinoff, OXY’s philosophy of disciplined capital allocation will continue. Our core businesses will continue to focus on delivering moderate volume growth, generating higher earnings and cash flow per share, as well as improved financial returns. Our Permian Resources business will represent the key area of growth within our domestic operations. I’ll now turn the call over to Vicki Hollub for an update on our activities in Permian Resources.
Vicki Hollub:
Thank you, Steve. In last quarter’s call, I discussed our progress toward reaching 120,000 barrels of oil equivalent per day of production in 2016 by achieving the following goals; first, correlating rock and fluid properties to production performance across OXY’s entire Permian acreage position; second, optimizing development strategy and design to unlock full primary development potential; and third, efficiently accelerating full field development and production growth. We made significant progress on these goals in the third quarter, and continue to improve and optimize our stimulation designs for each field and bench. In addition to testing slick water and hybrid fluid systems we are testing and analyzing other key variables such as pumping rate, pad volumes, propane type, propane concentrations, surfactants, cluster count and spacing, clusters per stage and alternate technologies to plug and perforate, our efforts to driving significant improvements in well productivity in our Delaware and Midland Basin assets. In the third quarter, Permian Resources had daily production of 77,000 BOE per day which is a 7% increase from the 72,000 BOE per day that were produced in the second quarter. We produced 43,000 barrels of oil per day for the third quarter. This is a 26% increase from a year ago and an 8% increase from last quarter. During the third quarter, our capital expenditures were $472 million. We operated 24 rigs and drilled 75 wells, including 44 horizontals. We placed 71 wells on production including 36 horizontals. The number of wells drilled and placed on production was adversely impacted by delays attributable to flooding which occurred in September. This impact reduced the number of horizontal wells placed on production by approximately 10. We’ve increased the number of frac spreads in the fourth quarter to address the additional carry in well inventory. And in the fourth quarter, we plan to operate an average of 30 rigs and exit the year with 34 rigs. We expect to drill 80 wells and place 75 wells on production, including 48 horizontals. Before discussing the third quarter activity in greater detail, I would like to share some more information regarding the drilling potential we see on our acreage. OXY’s unconventional plays in the Permian are spread across 2 million acres in the Midland Basin, Central Basin Platform, Northwest Shelf and Delaware Basin. Our teams continue to utilize our extensive knowledge and appraisal work to characterize prospective benches and target landing zones within each bench. To-date we’ve identified approximately 7,100 potential well locations. Overall, more than 92% of the locations are horizontal and our results confirm the economics of horizontal wells exceed most vertical wells. In the Delaware Basin we have currently identified 4,250 horizontal locations with 1,450 in the Wolfcamp A and B benches. The majority of these locations are in our operated areas in Reeves County. The Bone Spring potential is equally as significant with 1,500 potential locations. These are primarily located in New Mexico and could increase with further success in Texas. In the Midland Basin, we’ve identified 23 horizontal locations, and 1,050 of these are in the development phase targeting the Spraberry, Wolfcamp A and B benches. We’re highly encouraged with recent results of these benches achieved through our frac design optimization and increases in lateral lengths. In the Delaware Basin we operated 11 horizontal drilling rigs and one vertical drilling rig in the third quarter. We drilled 41 wells and placed 40 on production. In our Barilla Draw acreage we placed eight horizontal wells on production in the Wolfcamp A and B benches. These wells achieved a peak rate of 1,355 BOE per day and a 30 day rate of 1,067 BOE per day. Our Ryman 14 5H well achieved an average peak rate of 1,600 BOE per day and a 30 day rate of 1,365. We completed our first Delaware zipper frac on the Anna Katherine 5H and 6H reducing completion cost by $700,000 due to the efficiency gain from simultaneous operations. These two wells achieved an average peak rate of 1,600 BOE per day and an average 30 day rate of 1,225. The production rates achieved on our wells placed on production in the third quarter are significantly above our first half 2014 rates. This increase is directly attributable to the breakthroughs we’re achieving in our optimization program, including increasing sand concentration, lengthening laterals and optimizing cluster spacing. Additionally, our Wolfcamp A wells are matching the 900,000 BOE type curve and production from our horizontal wells in the Delaware Basin is averaging 89% total liquids, and 77% oil. Our appraisal efforts in the 2nd Bone Spring and Wolfcamp C benches in the Delaware Basin continued in the third quarter. We’re excited to see enhanced performance from the Bone Spring and anticipate further gains as we incorporate learnings from the full core we acquired in the third quarter. These learnings will drive improvements in 2015. Additionally, we’re encouraged by recent results achieved in the Wolfcamp C, our Totsy 206H well achieved an average initial rate of 1,356 BOE per day and a 30 day rate of 912. In the Midland Basin we operated eight horizontal drilling rigs and four vertical drilling rigs during the quarter. We drilled 34 wells and placed 31 on production. We’re very encouraged with the results of the Spraberry bench plan to accelerate development of this bench in 2015. During the third quarter we placed the South Curtis Ranch 3526H well on production, this well was completed in the lower Spraberry bench and achieved an average peak rate of 934 BOE per day at an average 30 day rate of 913. We have two additional Spraberry wells on flow back with initial production results that look similar to the South Curtis Ranch 3526. These wells are exceeding the 700,000 BOE type curve. In the Spraberry Wolfcamp A and Wolfcamp B we placed 11 horizontal wells on production in the third quarter with a peak rate of 731 BOE per day at an average 30 day rate of 541. Production from these wells averaged 91% total liquids, 81% oil. We continue to gather and evaluate cores, cuttings, advanced slogs, micro-seismic, tracers and pressure data, to link reservoir characterization to well performance. We have recently acquired 474 feet of continuous horizontal core from one of our Wolfcamp B wells. This will allow for better definition of lateral, reservoir with logic variations and enabled us to tune those differences to open hole logs to optimize placement of perforation clusters and improve frac design. We’re making significant progress in our design optimization efforts and are confident this will translate into further improvements in well productivity in upcoming quarters. For example at Dora Roberts we drilled a 10,000 foot lateral in the Wolfcamp B bench, this well the Dora Roberts 4027H achieved a peak rate of 1,437 BOE per day and a 30 day rate of 671. This well is exceeding the 650,000 BOE type curve. Additionally we recently drilled the Hendrix 1H well in Qatar that achieved an average 30 day rate of 775 BOE per day. In closing OXY’s program in 2014 is designed to delineate and appraise our acreage in order to maximize both ultimate recovery and financial returns. We continue to make progress, translating the knowledge gained in our appraisal efforts to create value from our unconventional acreage. We have positioned the required resources to execute accelerated development in 2015 but maintain the flexibility to optimize our portfolio and pace. We’re on target to deliver 15% to 18% production growth in 2014 and remain confident that we will achieve our target of 120,000 BOE per day in 2016. I’ll now turn the call over to Willie, who will provide you an update on the Permian marketing strategy.
Willie Chiang:
Thanks Vickie, good morning everyone. I’d like to just take a few minutes to briefly update you on our midstream and marketing strategies in the Permian. It’s particularly important in today’s market environment to maximize realized value for production and our strategy to do so is primarily by ensuring access to markets. Now I spent some time last earnings call on our midstream strategy to show you how we’re trying to develop and secure takeaway capacity in the Permian Basin. I have a Slide 29, that shows our strategy which is really focused on two new key takeaway points. Colorado City which is the origin of the BridgeTex pipeline in Midland South, which is the origin to keep third-party pipelines Long Horn and Cactus. These takeaway points complement our Centurion gathering system by providing us the additional access to multiple markets. Now as you are aware the BridgeTex pipeline commenced service this September and together with a start up of some additional pipelines in the next few months we expect differentials to return to levels that will reflect the marginal cost of transportation. Slide 30, shows the pricing differentials for Midland WTI versus LLS. During takeaway constrain periods you can see the LLS Midland differential widen to $30 a barrel and is averaged approximately $16 a barrel over the past four years. In 2014 the LLS Midland differential has averaged $12 year-to-date and today’s it’s currently roughly $10 a barrel. Our unique upstream and midstream perspective to the Permian basin has enabled us to be a driving force behind the construction of new pipeline infrastructure, as well as takeaway capacity from the Basin. Slide 31, shows how we view the key value components for infrastructure projects such as BridgeTex. As a standalone pipeline investment we look at tariff revenue to ensure a solid return consistent with our targeted rate of return for domestic midstream projects. This can generate cash of roughly $1 to $3 a barrel. Second value driver is when we enter into long-term and cost advantage transportation commitments on pipelines as a shipper. This gives us sufficient access to markets compared to other transportation routes and options, depending on the project advantage tariffs can add another $1 to $3 a barrel of incremental value. However the point I want to make is that the critical value for OXY is really to avoid discounted prices that result from infrastructure constraints and unplanned outages. The value is significant and if you look at the past four years can be $10 a barrel or more. Now our significant takeaway commitment on BridgeTex is a great example of how we capture this value and in today’s market is roughly a $1 million a day for OXY. Our Permian Basin strategy utilizes all these value drivers to reach multiple markets and we have secured access to long-term takeaway capacity of roughly 3 times our current production from the Basin. Now this really positions us well to continue to grow our production, maximize realized prices and capture market opportunities. I’ll turn the call back now to Chris Degner. Thank you.
Chris Degner:
Thanks Willie. And Denise we’re ready to take questions.
Question:and:
Operator:
Thank you. We will now begin the question-and-answer session. (Operator Instructions) The first question will come from Evan Calio of Morgan Stanley. Please go ahead.
Evan Calio :
Good morning guys. My first question is most of your large cap E&P peers are increasingly within cash flow or are more limited by their balance sheets. Given OXY’s under-levered balance sheet versus anybody, other than a super major, would you be willing to outspend cash flow in the downturn? And as a method to right size your balance sheet, or really I guess what’s the writer of targeted capital structure for OXY moving forward?
Morgan Stanley:
Good morning guys. My first question is most of your large cap E&P peers are increasingly within cash flow or are more limited by their balance sheets. Given OXY’s under-levered balance sheet versus anybody, other than a super major, would you be willing to outspend cash flow in the downturn? And as a method to right size your balance sheet, or really I guess what’s the writer of targeted capital structure for OXY moving forward?
Steve Chazen:
Well, first I would argue, we’re better capitalized in the majors. So, I think they are over leveraged myself, but anyway I think as Chris pointed out we’re going to have a lot of cash at the end of the year from variety of sources mostly from the California business. Some of that of course will be used to reduce our share count, maybe the bulk of that to reduce our share count. We continue to look for opportunities to grow the business in the Permian through investment. So, well, our drilling program or maybe in line with cash flow if we see other opportunities to small property acquisitions or even medium sized ones we’ll use our balance sheet to do those. And those would effectively be an increase in the program in excess of cash flow. So, I think we’ve always had a balance of drilling and acquisitions it’s more shifted clearly to drilling now because we have so much to do. But so I think I don’t think you will see massive changes in our leverage but you will see obviously less equity in our equity count as we buy down a lot of stock. So, I think there’ll always be a balance. If there was a sharp reduction in oil prices created more buying opportunities so we wouldn’t hesitate to increase our leverage to grow the business, so I think that from our perspective this is sort of good times. I sort of know what to do with $75 oil or less, but I have no idea what to do with the $120. So I think this is really good times for us, may not be good times for people who use this as a proxy for oil price, these are stocks or proxy for oil price but as a fundamental business matter see cyclical downturns is where you use the balance sheet to build the business. And I think that’s I am hoping a lot of happy talk now especially from service companies about how this is temporary I don’t know how anybody knows that. If I can predict oil prices I’d be sitting on a beach in Gali and wouldn’t come to work and wouldn’t mess with this production business. So, I think that as a practical matter you got to -- this is a volatile time there may be a recession worldwide I don’t really know I don’t see that. But a little lower oil prices I think could take some of the volumes out of it and gives us some opportunities to head to our business. So our goal is to grow our earnings per share, our reserves per share, cash flow per share through a combination share reduction and hopefully building the business either through drilling or acquisitions, and maybe both.
Evan Calio :
Absolutely well positioned for a down market, maybe a related question but on buybacks you used to have a slide where you built up to 100 million share buyback. And I guess there is two questions, it’s not included today. If there is any change in thought there? And secondly, when you did the 100 million share a potential buyback, it was determined when OXY was $100 a share, it’s $89 today. All things being equal it will be lower following the CRC spin. And at the same time the elements that are funding the buyback are largely flat, right? So I guess is there how do you think about that which is approximately about $1 billion delta or is it looking at your…
Morgan Stanley:
Absolutely well positioned for a down market, maybe a related question but on buybacks you used to have a slide where you built up to 100 million share buyback. And I guess there is two questions, it’s not included today. If there is any change in thought there? And secondly, when you did the 100 million share a potential buyback, it was determined when OXY was $100 a share, it’s $89 today. All things being equal it will be lower following the CRC spin. And at the same time the elements that are funding the buyback are largely flat, right? So I guess is there how do you think about that which is approximately about $1 billion delta or is it looking at your…
Steve Chazen:
We denominated the stuff in shares because that’s the way we think about it how many shares are we buying back. We’re fairly somewhat disciplined in making sure that we don’t buy shares at prices that are imply, that are excess of our finding and development cost. So I think that’s the way we sort of look at it. We announced the share repurchases as we actually have the cash in hand. It’s not intended as a forecast to what we might ultimately do as more cash comes in hand you should expect the share repurchase authority would rise. So it wasn’t the 60 million shares we’ve added so we got 76 I think roughly left to go. You should view that as sort of the cash in hand number not the ultimate and the ultimate will be dependent on the pace of proceeds from various things. So I think we’re not trying to forecast, when I say this is what we got in our hand now. But it turns out that we have excess money because the price of stock is too low, we’ll adjust the share repurchase to higher numbers.
Evan Calio :
And do how we consider a time table? Is that for the buyback, given it’s significantly higher than a level historically or is it still just going to be level driven program?
Morgan Stanley:
And do how we consider a time table? Is that for the buyback, given it’s significantly higher than a level historically or is it still just going to be level driven program?
Steve Chazen:
It’s driven principally by the stock price. So we look for buying opportunities in the market when people become irrational.
Operator:
Our next question will come from Doug Terreson of ISI. Please go ahead.
Doug Terreson :
Steve I have a couple of questions about the main E&P business. First from a strategic perspective, there has been commentary about divestitures in Oman and other countries and so whether or not you comment on assets individually or the positions in main in general. I want to see if we could get an update on likely strategic outcomes there and/or the environment for monetization and main in general which you have talked about in the past? And then the second question, you guys mentioned that Al Hosn is going to start up on time in the current quarter which is good. And so the second question is whether it is going to come in on budget as well? So two questions.
ISI:
Steve I have a couple of questions about the main E&P business. First from a strategic perspective, there has been commentary about divestitures in Oman and other countries and so whether or not you comment on assets individually or the positions in main in general. I want to see if we could get an update on likely strategic outcomes there and/or the environment for monetization and main in general which you have talked about in the past? And then the second question, you guys mentioned that Al Hosn is going to start up on time in the current quarter which is good. And so the second question is whether it is going to come in on budget as well? So two questions.
Steve Chazen:
The second, last we’ll have Sandy answer the budget question, but it’s sort of one word answer. But on the overall reduction it’s sort of one at a time but our objective is the same one way or another to get value out of the Middle East business some by selling it and may be some by speeding up the cash out of the asset where it is more difficult. So one way or another we’re basically using the business to downsize the size of that business make it less important on the company. Still an important part but it’s going to be a lot of cash is going to come out of that business one way or another over the next few months. And so I think we’re going along it slower than I would like of course. But to some extent by showing being too anxious sometimes you get a worst result than you might some other way. And so Sandy will answer the question on budget.
Sandy Lowe:
The answer is while I am worried yes we’re on budget it’s a well planned project and well tended the start up sequence has been initiated and we expect to have some product sales in the quarter.
Operator:
Our next question will come from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate :
Steve I also have two questions. I guess my first one is for Vickie. I really wanted to talk about the Permian or ask you about the Permian growth trajectory that you have provided for us. Your run rate since you ramped up the rig count by about 5,000 barrels a day per quarter and I realize it’s very simplistic just to look at the absolute move sequentially. But you are significantly accelerating the rig count and the backlog it looks like, so I am just trying to reconcile a substantially higher activity level with a similar quarterly rate of growth that we -- implied by your projections for the next couple of years. That’s my first question. I have got a follow-up please.
Bank of America Merrill Lynch:
Steve I also have two questions. I guess my first one is for Vickie. I really wanted to talk about the Permian or ask you about the Permian growth trajectory that you have provided for us. Your run rate since you ramped up the rig count by about 5,000 barrels a day per quarter and I realize it’s very simplistic just to look at the absolute move sequentially. But you are significantly accelerating the rig count and the backlog it looks like, so I am just trying to reconcile a substantially higher activity level with a similar quarterly rate of growth that we -- implied by your projections for the next couple of years. That’s my first question. I have got a follow-up please.
Steve Chazen:
I’ll let her answer the question but I think I wouldn’t confuse our expectations with our promises. There is probably a wide difference between them. Go ahead Vickie.
Vicki Hollub:
Yes Doug originally we had not planned to reach the exit rate this year with 34 rigs. But we’ve accelerated our development a little bit and as you noticed we’re a little bit behind on some of our wells completed but we’ve added another couple of frac spreads. So, now as of 1 of November we’ll be at 7 to address the well inventory. And with respect to the rigs going forward we still intend to stay somewhat as per the schedule that we had showed in our last presentation. We’re just seeing a little more opportunity here to get a little bit ahead of the game.
Doug Leggate :
So this not working interest issue, I think in terms of subsequent wells from here having a lower working interest maybe you could give us an idea of what after working interest is? Thanks.
Bank of America Merrill Lynch:
So this not working interest issue, I think in terms of subsequent wells from here having a lower working interest maybe you could give us an idea of what after working interest is? Thanks.
Vicki Hollub:
We kind of gave you an indication on the slide in the presentation that for the Midland Basin generally speaking our working interest is close to 92% overall and in the Delaware Basin around 76% generally speaking.
Doug Leggate :
Okay, thanks for that. Steve, my follow-up is really I realized we’re going to have to wait on the capital for the till the end of the year. But just as an order of magnitude I wonder if you could help given all the moving parts with California going BridgeTex and Al Hosn largely done. And what I am really trying to get at is how you think about balancing spending with the dividend as opposed to asset monetizations funding the buyback? How should we think about dividend policy and maybe a broad scale of spending for next year, if you could? Thank you.
Bank of America Merrill Lynch:
Okay, thanks for that. Steve, my follow-up is really I realized we’re going to have to wait on the capital for the till the end of the year. But just as an order of magnitude I wonder if you could help given all the moving parts with California going BridgeTex and Al Hosn largely done. And what I am really trying to get at is how you think about balancing spending with the dividend as opposed to asset monetizations funding the buyback? How should we think about dividend policy and maybe a broad scale of spending for next year, if you could? Thank you.
Steve Chazen:
It’s hard to do the budget right now because there is a number of moving parts and we have to talk with our partners in the Middle East about the size of the program there. And I just assume that telegraph or thoughts right now. But I think our Permian program certainly for the first half of the year will be what we told people would be. So I don’t expect any real change in that, some of the other stuff maybe tweaked a little bit and some of the other programs. We just don’t know. But as far as the dividends are concerned I think if you go back to the slide we’ve only shown for what I say 10 years but I think Chris who is shaking his head said that it is more, it says after maintenance capital which is making the company safe. The next line is dividends before growth, and so we view our commitment to the shareholders on dividends to be part of our overall commitment. How much exactly you’re going to raise the dividend wise is remains to be seen. And there is obviously a little confusion by with the lower oil prices. But I think -- I don’t think. We’ve raised the dividends I think for a dozen years I don’t think we’re going to break the theme next year. And so I assume the dividends will go up. We’ve got a lot of cash and a lot of projects to fund almost anything we want to do. And so I don’t think anybody should be concerned. And we’re focused on making sure that the drilling program delivers the results it’s supposed to deliver. If it delivers the results it’s supposed to deliver there’ll be plenty of money over the next two or three years for dividends, dividend growth continued dividend growth and the share reduction and lots of growth in the business. So if we deliver the results that we’re doing so far and our plans are pretty much on target and we have plenty of cash flow and I don’t think anybody should worry about where it will be a couple of years from now. Next year is going to be a messy year you have got comparisons against company with different set of assets we’re going to have some sales of things next year. And the share count is going to be really confusing for example the performance now for this year is the average shares outstanding for the year to do the EPS calculation which is a lot more than the shares outstanding right now and that remind at the end of the year. So lot of confusing numbers over the next year but I think if you focus if I were looking at the company I would focus on our program in Permian Resources and our cash generation and the rest of business and we’ve got a lot of -- and I think we’ve now fixed the realization issue of the Permian Basin we faced the last three or four years. Unfortunately we may have fixed it for everybody in the Basin but we certainly -- but we fixed it for ourselves. So I am pretty optimistic about where we are next year.
Doug Leggate :
Great, thanks a lot Steve.
Bank of America Merrill Lynch:
Great, thanks a lot Steve.
Operator:
The next question will come from Leo Mariani of RBC. Please go ahead.
Leo Mariani :
I was wondering if you could address a little bit more the comment that you all had made about potentially moderating activity I think the phrase you guys used is if oil prices stay here or move lower and you kind of referred it to the second half of ’15. Is there any kind of more granularity you can give around that? I recognized the budget is not done yet and there is moving parts. I know you have ambitious plans to ramp-up the rig count in the Permian. Is there any scenario you can sort of paint whether or not you stop ramping rigs in the second half of the year? Would you actually drop rigs? Could you maybe just talk to that a little bit?
RBC Capital Markets:
I was wondering if you could address a little bit more the comment that you all had made about potentially moderating activity I think the phrase you guys used is if oil prices stay here or move lower and you kind of referred it to the second half of ’15. Is there any kind of more granularity you can give around that? I recognized the budget is not done yet and there is moving parts. I know you have ambitious plans to ramp-up the rig count in the Permian. Is there any scenario you can sort of paint whether or not you stop ramping rigs in the second half of the year? Would you actually drop rigs? Could you maybe just talk to that a little bit?
Steve Chazen:
I don’t think we have any plans to drop rigs. The ramp rate is what we would fall with because the business as we continue to drill wells put them on stream generates cash, more cash, than some people are out looking. And so I think we’ll be okay. And we certainly have the financial flexibility to weather that. On a long-term basis we’re fairly optimistic about oil prices over the next year or two I don’t know. But I think on a long-term basis the industry despite what people say the U.S. business is not healthy at $70 oil. And so I think higher oil prices are in the cards overtime.
Leo Mariani :
Okay, and I guess just in the Permian, could you guys maybe talk to what type of well cost you’re seeing on the Midland side as well as the Delaware side?
RBC Capital Markets:
Okay, and I guess just in the Permian, could you guys maybe talk to what type of well cost you’re seeing on the Midland side as well as the Delaware side?
Steve Chazen:
Vicki can probably answer that.
Vicki Hollub:
Depending on the depth in the Midland Basin we’re seeing well costs better in the $7 million to $7.5 million range for our South Curtis Ranch and some of the areas around that. And the Delaware Basin in Texas we’re seeing well cost in the neighborhood of 8.6 million to 8.7 million and our drilling costs have been improving through some of our efficiency initiatives but it’s really the completion costs that are driving our total well cost right now. What we’ve done recently is increased the size of our frac jobs which is giving us better productivity and what we think will be better ultimate recoveries. So when you’re seeing higher well cost for us it’s because we’re increasing the size of our fracs.
Leo Mariani :
Is there any kind of like approximate lateral length you can sort of put around those well costs at all?
RBC Capital Markets:
Is there any kind of like approximate lateral length you can sort of put around those well costs at all?
Vicki Hollub:
Around the 8.6 to 8.7 that’s generally a lateral length of about 4,500 to 5,000. And in South Curtis Ranch area our lateral length is around 6,100.
Leo Mariani :
In terms of your Bakken and Piceance assets I guess you had it in your slides that you guys plan to limit capital there. Could you talk about longer term plans for those assets? I know you had spoken in the past about some in the Bakken properties and also putting the Piceance assets into a JV for maybe an eventual IPO. And I guess you also talked about additional midstream sales when market conditions warrant. Can you maybe just talk through strategically how you are thinking about those assets?
RBC Capital Markets:
In terms of your Bakken and Piceance assets I guess you had it in your slides that you guys plan to limit capital there. Could you talk about longer term plans for those assets? I know you had spoken in the past about some in the Bakken properties and also putting the Piceance assets into a JV for maybe an eventual IPO. And I guess you also talked about additional midstream sales when market conditions warrant. Can you maybe just talk through strategically how you are thinking about those assets?
Steve Chazen:
The issue in the Bakken as it simply can’t compete for the returns being earned in the Permian. It’s not that they are bad assets or anything it’s just not competitive in our portfolio. And the Piceance is all gas and gas is tough to compete in this environment. So we’ll look and I don’t see any way to change. I am not bullish about gas prices I don’t see any real way to change the relative competitiveness of North Dakota versus the Permian. We can move oil out of the Permian by pipeline. That’s a much more efficient way to move oil than by train. So I just think that it’s just we’ll not for our portfolio it won’t be able to compete, so ultimately we’ll have to deal with that.
Leo Mariani :
That kind of implies an eventual disposition I would assume at some point?
RBC Capital Markets:
That kind of implies an eventual disposition I would assume at some point?
Steve Chazen:
Yes sure. Right now it’s a little noisy because it’s probably not the perfect time to be doing that.
Operator:
The next question will come from Ed Westlake of Credit Suisse. Please go ahead.
Ed Westlake :
An intriguing comment from Steve just on saying cash flows being under estimated, I mean obviously oil price is making a lot of volatility but maybe some color on that. Is that because you think your promise is going to be exceeded by your expectation of volumes? Do you think it’s because cash margins are being underestimated as you shift to drilling in the Permian. Is it Al Hosn or is it all three and something else?
Credit Suisse:
An intriguing comment from Steve just on saying cash flows being under estimated, I mean obviously oil price is making a lot of volatility but maybe some color on that. Is that because you think your promise is going to be exceeded by your expectation of volumes? Do you think it’s because cash margins are being underestimated as you shift to drilling in the Permian. Is it Al Hosn or is it all three and something else?
Steve Chazen:
Generally I think people have underestimated the cash flow that will come out of the assets they basically take what we did this year and add 2% or something to it than adjust for price. The Al Hosn project will certainly add. There is other things that I think will add, but I think we show you I think, there is a difference without, we look different without California. And we give you some numbers to help you model that. We don’t know what the DD&A rate will be next year because it depends on reserves. But the underlying DD&A rate for example without California, United States is lower. And the same thing with operating costs and other things, so I think there is, people are just sort of taking the old numbers because that’s really all they had. But I think as you look at it, maybe a little more careful modeling with the new numbers might be more helpful for people.
Ed Westlake :
And then a question on the Permian, I mean obviously if you look at the Midland’s, you have outlined Dora Roberts, South Curtis may be and these are sweet spots in the Northern Midland but it’s not a huge amount of acreage but it will be very productive. And then in the Reeves, Barilla Draw area you’ve got this fantastic results again and that’s obviously a larger acreage position. So that drives growth over the next five, maybe six, seven, maybe even longer years. When I look at the rest of the Permian and particularly say if oil prices did have a longer excursion to the downside. How do you think the returns stack up and I am particularly say looking at the New Mexico, Delaware? What’s the sort of breakeven oil price you need for getting an acceptable return to that?
Credit Suisse:
And then a question on the Permian, I mean obviously if you look at the Midland’s, you have outlined Dora Roberts, South Curtis may be and these are sweet spots in the Northern Midland but it’s not a huge amount of acreage but it will be very productive. And then in the Reeves, Barilla Draw area you’ve got this fantastic results again and that’s obviously a larger acreage position. So that drives growth over the next five, maybe six, seven, maybe even longer years. When I look at the rest of the Permian and particularly say if oil prices did have a longer excursion to the downside. How do you think the returns stack up and I am particularly say looking at the New Mexico, Delaware? What’s the sort of breakeven oil price you need for getting an acceptable return to that?
Steve Chazen:
I get to take a longer view I guess, because it is a smaller proportion of my age. So if I look back two-three years ago what we thought about the Permian basin and what we thought internally for Delaware what other people were saying. And I look at programs have been proposed now, doesn’t even look like the same company. And I think as we have progressed we continue to find new things that we didn’t think of before, that we’ll act considerably I think the business, ultimately if oil prices stayed low or whatever you want to call the current price or at this level or lower for a extended period of time. Margins historically have adjusted by the reduction in service costs. I mean you are not going to get an environment where oil prices stay at say $75 or whatever you think for four to five years and service costs are going to be the same, it just doesn’t going to work. And so part of the gain sharing and loss sharing will be from both parties. So all the money isn’t going to just go in the service company coffers and we’re going to work for free and I don’t, not just we but everybody. So I think in the end it will calibrate and then we’ll generate acceptable returns. We think there is a lot of economic oil at $75, economic meaning we are in 15%, 16%, 17% returns. Though I think there is a lot of economic oil at $50 no I don’t and somewhere in that range but it also depends on service cost and so -- but if oil prices go back to 100 or whatever again service costs will rebound with that. So I just think that this thing will take work itself out over one or two year period. And I am, I hate to say it this way, but if I look forward to a little stress and some of the crazy stuff that sort of goes away for a while and that gives sort of rational people an opportunity.
Ed Westlake :
And then a final question just on the 2015 production outlook that’s very helpful, 8% to 10% and you can see obviously the great contribution of Al Hosn which probably still have a bit of tail into contribution maybe even ’16 as well at least I mean and obviously reducing activity in the mid-con. Do you think the Permian and it seems to in the well results and the activity level. Do you think the Permian can provide an offset to keep that production growth sort of at a similar pace in 2016 or does it just naturally slow as Al Hosn comes down?
Credit Suisse:
And then a final question just on the 2015 production outlook that’s very helpful, 8% to 10% and you can see obviously the great contribution of Al Hosn which probably still have a bit of tail into contribution maybe even ’16 as well at least I mean and obviously reducing activity in the mid-con. Do you think the Permian and it seems to in the well results and the activity level. Do you think the Permian can provide an offset to keep that production growth sort of at a similar pace in 2016 or does it just naturally slow as Al Hosn comes down?
Steve Chazen:
Well, Al Hosn will be eventually flat yes but I think at Al Hosn I think it’s possible that over in the next few years the plant is larger than it needs to be for the deliverable gas. And so and the country continues to need gas there and the result resolve in liquids of course. So I think overtime there will be an expansion probably and separately up to the government. And so there will be Al Hosn is not through so I think as we look at ’17 and ’18 and ’19, we’ll see more growth out of Al Hosn some point level off that’s true. But I think it will probably continue to grow. Because once you spent the base money the incremental capital will have really good returns I think. So I think that will do better. I think the Permian Resource business has the potential to cover to continue to grow and maybe grow better going forward as we work through some of the historical issues. So I think we’ve got more acreage and more will prove up and the Barilla Draw didn’t really exist a year ago I mean it landed but the concept didn’t exist. And so I think there is a lot of good concepts out there some will work and some won’t. And some are I think over promoted by some but it’s hard to imagine that 100,000 acres you’re going to have 4 billion barrels of reserves. But I think rational expectations are good for the base and I think Permian Basin is the best basin in the United States and will be for the next 20 or 25 years.
Ed Westlake :
Thanks very much.
Credit Suisse:
Thanks very much.
Operator:
The next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.
Jeffrey Campbell :
Good morning. First question I want to ask it refers to Slide 27, the SCR 3526H Spraberry well. Is the early shallow decline consistent with your expectations? And does this early positive results have any influence over your Spraberry appraisal plans going forward?
Tuohy Brothers Investment Research:
Good morning. First question I want to ask it refers to Slide 27, the SCR 3526H Spraberry well. Is the early shallow decline consistent with your expectations? And does this early positive results have any influence over your Spraberry appraisal plans going forward?
Vicki Hollub:
We’re still evaluating the South Curtis Ranch 3526 and the shallow decline on that is so far good news for us. But we still want to see a little more production data from that to determine what’s causing that.
Jeffrey Campbell :
Great, thank you. And just as a broader question, just looking at your plan as it’s unfolded in Permian over the last several quarters. It doesn’t really appear to encompass essential basin platform where some peers have drilled some noteworthy horizontal wells. I was wondering if you have any horizontal exploration potential in that area.
Tuohy Brothers Investment Research:
Great, thank you. And just as a broader question, just looking at your plan as it’s unfolded in Permian over the last several quarters. It doesn’t really appear to encompass essential basin platform where some peers have drilled some noteworthy horizontal wells. I was wondering if you have any horizontal exploration potential in that area.
Vicki Hollub:
We feel like we have a lot of potential on the Central Basin Platform and that’s just one of the areas that we have yet to get to. We’re working on a fairly structured plan to, with respect to our exploration, our appraisal and our development programs. And so what we showed you on the slide that has the breakout of the zones that are currently under appraisal and currently under development that list does not include what we’re doing from an exploration standpoint. So, our exploration group is one of their key areas to focus on over the next couple of years will be the Central Basin Platform where we do have significant acreage and we think there is a lot of potential there, so it just hasn’t gotten in the queue yet but it’s something that we’re optimistic about.
Operator:
Our next question will come from Roger Reid of Wells Fargo. Please go ahead.
Roger Reid :
A quick question on the OpEx side a couple of years ago you started an OpEx reduction effort obviously it was successful. This time around talking about OpEx and then last night on the call with CRC they talked about higher gas prices. I was wondering ex-California if you could walk us through what sort of the OpEx issues are here and how m of that is due maybe to just temporary gas price increases and how much of it is a function of maybe changes in what you’re doing in the Permian resources area.
Wells Fargo Securities:
A quick question on the OpEx side a couple of years ago you started an OpEx reduction effort obviously it was successful. This time around talking about OpEx and then last night on the call with CRC they talked about higher gas prices. I was wondering ex-California if you could walk us through what sort of the OpEx issues are here and how m of that is due maybe to just temporary gas price increases and how much of it is a function of maybe changes in what you’re doing in the Permian resources area.
Steve Chazen:
Just as you look at OpEx I think there is two, there is the cost of energy which is buried in that OpEx because we use a lot of electricity to run pumps and such. And so some of that’s in the energy and some of it is in basically driven by the EOR business which uses, where the gas the CO2 is tied to oil price. And these little more CO2 we expense that, looks or shows up as an operating cost. And some of it is we increased the work over activity principally in the EOR business. So when you look at our numbers for operating costs in the United States the driver the overwhelming driver is the EOR business which is basically a low capital business but a little higher operating cost business than say the resources business which is a high capital business and a low operating cost business. So what you see is as we put more CO2 in the ground as we try to repair the wells, you get more operating costs and we try to optimize that and what we look it is the base the underlying operating cost, not so much what we’re doing from quarter-to-quarter, we can’t do anything about CO2 prices or anything like that. So I think it’s a mix of things but the driver for operating costs for the OXY excluding California is the EOR business which is a large business and its principle expenses are not capital but are our operating costs. So it just looks a little different than you might be used to.
Roger Reid :
So with California soon to be gone…
Wells Fargo Securities:
So with California soon to be gone…
Steve Chazen:
We actually show you somewhere, Chris?
Chris Stavros:
We gave you a pro forma slide table in the IR schedules that shows pro forma without California and the Hugoton for cash operating cost, DD&A and some other metrics and also production. So you sort of can go back and model it off of that and you’ll see what happened over that period of time.
Roger Reid :
And then the other question I had was along the lines of catching up on the well completions and the addition of the frac spreads in West Texas. Any chance for upside performance in terms of production there relative to the guidance or is that all fully incorporated in the numbers?
Wells Fargo Securities:
And then the other question I had was along the lines of catching up on the well completions and the addition of the frac spreads in West Texas. Any chance for upside performance in terms of production there relative to the guidance or is that all fully incorporated in the numbers?
Vicki Hollub:
That is incorporated in our projections for production, so we do expect to catch up and we’ve accounted for that.
Steve Chazen:
What he’s asking, is have we been conservative in the number or not?
Vicki Hollub:
I would say that that based on the performance we’ve seen thus far, I’d say that’s a conservative number actually, it’s an achievable number.
Operator:
And our final question will come from Paul Sankey of Wolfe Research. Please go ahead.
Paul Sankey :
Couple of high level strategic questions, firstly do you think you have been behind technically in the Permian? Do you think you can get ahead and do you think any kind of technical advantage is sustainable in U.S. unconventional given the commoditization of the activity?
Wolfe Research:
Couple of high level strategic questions, firstly do you think you have been behind technically in the Permian? Do you think you can get ahead and do you think any kind of technical advantage is sustainable in U.S. unconventional given the commoditization of the activity?
Steve Chazen:
We’ll start with, yes we were behind. I think somewhat earlier I said if I look at what the presentation is internally were two years ago. Look at the quality and the detail the current presentations for next year’s program doesn’t even look like the same company. So I think we have made a lot of progress. We’re blessed with good acreage which compensates for whatever to some extent. So I don’t think there is much. I always believe that it’s the acreage or the reservoir that overwhelms overtime technology spreads quickly. So I don’t think there is no secret sauce that lasts very long. So I think as a practical matter we -- I think we’re where we need to be in technology, there is always going to be improvements whether you have relative improvements against other people I don’t know. But overtime the technology spreads very quickly. And so because we see lots of wells, so it’s not really something that’s hidden from us. So I think we’re where we need to be from a skill set at this point we were behind so no argument about that. But we are fortunate that we have an exceptional acres position which in the end the reservoirs matter.
Paul Sankey :
I guess the argument there would be that you were in early relatively speaking and paid less but it bubbled, the early entry allowed you to get a better acreage? Is there any other proof by the way that you have better acreage? I mean how can we show that?
Wolfe Research:
I guess the argument there would be that you were in early relatively speaking and paid less but it bubbled, the early entry allowed you to get a better acreage? Is there any other proof by the way that you have better acreage? I mean how can we show that?
Steve Chazen:
Maybe, Vicki can tell you about that.
Vicki Hollub:
I’d like to build on Steve’s comments with respect to your first question initially. Technically we have teams here with OXY that I think to compete or beat any other teams in the Permian Basin at this time. From a success standpoint in the unconventional plays one of the critical things is to understand what the reservoir is and what the reservoir is telling you. We don’t believe that these plays should be called statistical plays. We think that you’ve really got to understand what the reservoir is. And based on what the reservoir is you design your completions and your frac jobs. And I think right now we’re probably one if not the only company, one of the few companies that’s actually taken a horizontal core. And along with our vertical cores, our 3D seismic, our micro seismic and all the additional work that we’re doing around reservoir characterization I think nobody in the basin is any further along than we are with respect to that. But I think with that said the industry as a whole still has a lot to learn. We’re all very early in the development of these unconventional plays in the Permian. So, I still think that we’re going to continue to learn technology will continue to advance. And I think that as it does I expect overtime for cost to come down on at least from the drilling standpoint and possibly from the completion standpoint. We’ve got some plans in place over the next six months to do some things. I think that that could have a significant impact on our productivity and ultimate recoveries. But it’s just a matter of working those costs to make sure that they are economical for what we want to do. And as I said technology overtime the cost comes down and so I think we’ll be able to do some things that that will certainly help some of the areas that previously have not been as good as our Delaware Basin area. So there is -- I am sorry now I have forgotten your second question.
Paul Sankey :
No, I was just saying if there is some way that we would be able to show easily that your acreage is superior to someone else’s?
Wolfe Research:
No, I was just saying if there is some way that we would be able to show easily that your acreage is superior to someone else’s?
Steve Chazen:
Well, we’ve got so much of it that some of it’s going to be better and some not. I mean if you compare it to some guy that has got 100,000 acres nets his whole position and who knows. But I think if you look at the overall result and you say we started from a standing start two years ago. And we’ll pass 80,000 at the end of this quarter. And we’ll pass 100,000 at the end of -- by the end of next year for sure. So I just look at from a standing start two years ago we’ll be one of the biggest producers in this unconventional in no time. But our whole business historically had been an EOR business. So it’s whatever you want to think but I think there is always somebody who has got 40,000 acres that is real good. But the question is can you have 2 million acres, that is real good. And I think we got enough 40,000 acre pieces that we could compete with anybody. If we took one of our 40,000 acre pieces or 100,000 acre pieces and people were saying what a wonderful company it is, it is just good as the snake company or whatever it’s called.
Paul Sankey :
I have a couple of quick ones Steve the investment in Midstream simultaneous with the sell down of the GP of Plains All-American I assume that means that you wouldn’t be continuing to want to own those assets long-term. And further to that does the deliberate naming of Permian Resources rings a bell with California Resources. I wondered if that was a potential spin candidate and I’ll leave it there? Thank you.
Wolfe Research:
I have a couple of quick ones Steve the investment in Midstream simultaneous with the sell down of the GP of Plains All-American I assume that means that you wouldn’t be continuing to want to own those assets long-term. And further to that does the deliberate naming of Permian Resources rings a bell with California Resources. I wondered if that was a potential spin candidate and I’ll leave it there? Thank you.
Steve Chazen:
On the Midstream I mean our goal is to I think Willie pointed out. Our goal is to make sure that we get the best possible price for our product and we’re not disadvantaged we’ve gone through several years of disadvantage. If we can do that without spending capital and build pipelines we’re happy to do that by committing for space and reaping the advantages of owning space. And so I think you should view it as a -- its purpose is basically to make sure we get good prices for oil. And if we could monetize take back some of that capital someway and put it somewhere else with new higher returns and we’re definitely going to do that. As far as the name is concerned that’s sort of an accident I wouldn’t know all that well about the California Resources name. But I think that I don’t think you should view it as a spinoff candidate at this point. It needs right now the cash flow from the rest of the business to accelerate its drilling. And it’s unlike California, California is actually it’s a good business. It’s just -- but it’s sort of mature phase where you saw financing. The resource business needs cash to grow. And it’s just not the right time to even think about something like that.
Paul Sankey :
Thank you very much.
Wolfe Research:
Thank you very much.
Operator:
And ladies and gentlemen, this will conclude our question-and-answer session. I would like to turn the conference back over to Chris Degner for his closing remarks.
Chris Degner:
Yes, thank you everyone and please give us a call if you have any follow-up questions. Have a good day.
Operator:
Ladies and gentleman, this conference has now concluded. We thank you for attending today’s presentation. You may now disconnect your lines.
Executives:
Chris Degner – SVP, IR and Treasurer Chris Stavros – CFO Steve Chazen – President and CEO Vicki Hollub – President, Oil and Gas, Americas Willie Chiang – EVP, Operations
Analysts:
Doug Leggate – Bank of America Merrill Lynch Leo Mariani – RBC Ryan Todd – Deutsche Bank Jason Gammel – Jefferies Paul Sankey – Wolfe Research Ed Westlake – Credit Suisse John Harlan – Societe Generale
Operator:
Good morning. And welcome to the Occidental Petroleum Corporation Second Quarter Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions). After today’s presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Mr. Chris Degner. Mr. Degner, please go ahead.
Chris Degner:
Thank you, Ed and good morning, everyone. And thanks for participating in Occidental Petroleum’s second quarter 2014 conference call. On the call with us this morning are Steve Chazen, Oxy’s President and Chief Executive Officer; Chris Stavros, Chief Financial Officer; Vicki Hollub, President Oil and Gas in the Americas; Willie Chiang, Oxy’s Executive Vice President of Operations and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment, I will turn the call over to our CFO, Chris Stavros, who will review our financial and operating results for the second quarter and also provide some guidance for the current quarter. Our CEO Steve Chazen, will then provide an update on the progress of our strategic initiatives and also some comments on the composition of the remaining Oxy after the separation of our California business. Vicki Hollub, will then provide an update of our activities in the Permian Basin. And Willie Chiang will conclude the call with an update on Oxy’s Midstream business. As a reminder, today’s conference call contains certain projections and other forward-looking statements within the meaning of the Federal Securities Laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements and our filings. Additional information on factors that could cause results to differ is available on the company’s most recent Form 10-K. Our second quarter 2014 earnings press release, the Investor Relations supplemental schedules, and the conference call presentation slides, can be downloaded off of our website at www.oxy.com. I’ll now turn the call over to Chris Stavros. Chris, please go ahead.
Chris Stavros:
Thanks, Chris, and good morning everyone. Beginning with this quarter, the disclosure and discussion related to our oil and gas segment results will be both on a before and after tax basis. With the oil and gas results also segregated between our domestic and international producing operations and exploration program. Oxy generated core income of $1.4 billion resulting in the alluded earnings per share of $1.79 for the second quarter of 2014, an improvement of both the year ago quarter and the first quarter of 2014. For the fourth consecutive quarter, we continued our strong domestic oil production growth with increases coming from both our Permian and California assets. Domestic oil production for the second quarter of 2014 was 278,000 barrels per day, a new quarterly record for Oxy. Excluding the effect of the Hugoton asset sale, domestic oil production increased 21,000 barrels per day from the year ago quarter, with our Permian resources business growing it’s oil production by 21%. On a sequential quarter-over-quarter basis, the growth was 8,000 barrels per day or about 3%. Oil and gas core after tax earnings for the second quarter 2014 were $1.2 billion essentially flat with both the first quarter of this and the second quarter of last year. In the second quarter of 2014, after tax core income for domestic business was $679 million. On a sequential quarter-over-quarter basis, results at our domestic operations were roughly unchanged as improvement from higher oil volumes and realized prices were offset by lower prices for natural gas and NGLs and higher operating expenses, mainly it’s a result of increased down-hole maintenance and surface operation costs. International after tax core income was $576 million for the second quarter of 2014 and results improved about 4% sequentially due to a lifting in Libya which had none in the first quarter and also increased sales volumes in both Oman and Yemen. On a year-over-year basis, domestic operations improved by $44 million after tax and international operations declined by $65 million as our Latin American result were meaningfully impacted by insurgent activity in Colombia. For the six months, year-over-year comparison, domestic operations, after tax income was $1.4 billion, an increase of almost 13%. In the same six-month period, international operations core income was $1.1 billion, a decline of 4%. For the second quarter of this year, total company production volumes excluding the Hugoton production averaged 736,000 BOE per day, an increase of 9,000 BOE in daily production from the first quarter and down 17,000 BOE from the quarter a year ago. Excluding Hugoton, domestic daily production improved 8,000 BOEs from the first quarter this year, with half of the increase coming from the Permian and the remainder from the Williston Basin in California. On a commodity specific basis, our domestic oil production grew by 8,000 barrels per day, with 3,000 barrels per day each coming from the Permian and mid-Continent and the remainder from California. Domestic NGL and natural gas production volumes were virtually flat for the quarter. International production increased by 1,000 BOE per day on a sequential quarter-over-quarter basis. MENA production grew 11,000 BOE per day sequentially primarily due to the scheduled first quarter plant turnaround at Dolphin, higher production in Oman due to new wells coming online in the Northern blocks and in Iraq, which reflected increased cost recovery barrels. These increases were offset by 10,000 barrels per day of lower production Colombia did to pipeline disruptions from insurgent activity. Our second quarter 2014 worldwide realized oil prices of $100.38 per barrels improved slightly compared to the first quarter realizations of $99 a barrel. Our domestic oil price realizations were about 2% higher on a sequential basis despite continued widening differentials the Permian Basin. Realized prices for domestic for NGL and natural gas production fell at 6% and 7% sequentially reflecting declines in benchmark prices. Price changes at current global prices affect our quarterly earnings before income taxes by $37 million for a $1 per barrel change in oil prices and $7 million for $1 per barrel change in NGL prices, a swing of $0.50 per million BTUs in domestic natural gas prices that’s quarterly pre-tax earnings by $25 million. These prices change sensitivities include the impact of production sharing contract volume changes on our income. Our oil and gas cash operating costs were $14.68 per barrel in the second quarter of 2014 compared to $14.33 per barrel in the first quarter. Domestic operating expenses were higher in the second quarter this year compared to the first quarter of this year due to higher downhaul maintenance and surface operation costs primarily in the Permian Basin. MENA production costs increased in the second quarter due to higher costs related to the Libya lifting, partially offset by lower surface operations and maintenance costs. Taxes other than on income which are directly related to product prices were $2.83 per barrel for the second quarter of 2014 and $2.88 for the first six months of this year. And our second quarter exploration expense was $54 million. In Chemicals, our second quarter 2014 pre-tax earnings of $133 million were slightly lower than the first quarter results of $136 million and $144 million in the year ago quarter. The seasonal up-tick in demand in construction and agriculture markets in the second quarter were more than offset by routine planned plant outages and unplanned customer outages. We expect our third quarter pre-tax earnings to be about $150 million reflecting anticipated increases in sales and production volumes. In Midstream, pre-tax segment earnings were $219 million for the second quarter of this year compared to $170 million in the first quarter of this year, and $48 million in the second quarter of last year. The 2014 sequential quarterly improvement in earnings resulted mainly from higher marketing and trading performance driven by commodity price movements during the period and higher income from the Dolphin pipeline which was negatively impacted by plant turnarounds in the first quarter of this year. For the six months of 2014, we generated $5.7 billion of cash flow from operations before changes in working capital. Working capital changes decreased our cash flow from operations by $100 million to $5.6 billion. During the first six months of 2014, cash flow from operations declined approximately $650 million compared to the same period a year ago. The first half of 2014 included a tax payment related to the gain on the sale of the PAGP units in the first six months of 2013 included a collection of a tax receivable. On a normalized basis, cash flow from operations during both periods would have been similar at roughly $5.8 billion. Capital expenditures for the first six months of 2014 were $4.7 billion net of partner contributions. In the second quarter we received proceeds of $1.3 billion from the sale of our Hugoton assets that’s been about $240 million towards domestic Bolton acquisitions. After paying dividends of $1.1 billion, buying back $1.6 billion of our company stock and other net flows, our cash balance was $2.4 billion at June 30. Our debt to capitalization ratio was 13% at the end of the quarter. Our 2014 annualized return on equity was 13% and return on capital employed was around 11%. The worldwide effective tax rate on core income was 40% for the second quarter of 2014 and we expect to combine worldwide tax rate in the third quarter to remain about the same. Lastly, I’ll outline some guidance for the third quarter. In the domestic business, on April 30, we closed on the sale of our Hugoton assets. The Hugoton operations produced 18,000 BOE per day in the first quarter and 6,000 BOE per day in the second quarter. For the third quarter, excluding Hugoton, we expect our domestic oil production to grow 6,000 and 8,000 barrels per day sequentially, roughly 10% on an annualized basis. We would expect this domestic oil production growth rate to accelerate over time. Domestic NGL productions should see a modest increase, although this should be somewhat offset or equally offset by lower natural gas production volumes. We expect our total domestic production to grow between 5,000 to 7,000 BOE per day. For the international business, the current prices and assuming normalized operations in Colombia, we expect total international production in sales volumes to increase by about 10,000 BOE per day from the second quarter levels. Excluding the Hugoton, total company-wide production in the third quarter is expected to increase by 15,000 to 17,000 BOE per day sequentially for an annualized rate of about 8%. We expect third quarter 2014 exploration expense to be about $100 million pre-tax. I’ll now turn the call over to Steve Chazen, who will provide an update on some of our strategic initiatives.
Steve Chazen:
Thank you, Chris. We recently announced new executive management teams and responsibilities for both the California Resources Corporation or CRC and Occidental Petroleum. Todd Stevens, the President and CEO of CRC and Bill Albright, Executive Chairman bring proven leadership abilities and both have played an important part in building and managing our California operations. Mark Smith, the former CFO of Ultra Petroleum was hired as Chief Financial Officer at CRC and brings an extensive background in corporate finance and deep understanding of operations, had an independent oil and gas producer. With these appointments, most of the key roles in the organization have been filled. And we’re confident that their ability to succeed as a standalone public company. In addition to the developments regarding personnel, we continue to make progress in the plant spin-off of the California Company. During the second quarter we filed the initial Form 10 registration statement and have already responded to the comments received in the SEC. CRC has initiated steps to secure its debt financing which we expect to be completed in the third quarter. We anticipate $6 billion of proceeds from total funded debt. The cash proceeds from CRC’s debt financing will transfer to Occidental, it’s a tax free dividend and shortly prior to completion of the spin-off, which we expected to occur in the fourth quarter. On the spin-off of CRC, Occidental will retain ownership of approximately 19.9% of CRC for a period lasting up to 18 months. During that period, we intend to conduct an offer to exchange the CRC shares we retained for Occidental shares. The California business continues to perform well and its executing on its oil and gas production growth strategy. The second quarter of 2014 oil production grew 10% compared to the second quarter of last year and the business generated approximately $1.2 billion of cash flow from operations during the first six months of 2014. We expect the CRC management team to present a more detailed view of the business and its growth strategy to investors as it commences its road show in the fourth quarter. At Occidental Petroleum, each of the seven members, the new executive team have made significant contributions to the company. Their individual strengths and combined leadership will shape the future of Oxy as we embark on a new chapter in the company’s history. Following the execution of CRC spin-off Oxy’s philosophy of disciplined capital allocation and living within its cash flow continue. Oxy’s core businesses and we focused on delivering moderate volume growth, generating higher earnings and cash flow per share and leading to improved financial returns. And for completion of the strategic initiatives, we laid out last fall our area focus will consist of a significant and leading position in the Permian Basin. Our Permian resources unit will represent the key area of oil growth within our domestic business with annual production growth expected to easily exceed 20% per year over the next several years as we accelerate our horizontal drilling program. We also expect margins in the Permian to improve as we focus on additional drilling efficiencies, losing our well cost and further enhancing our oil price realizations. Vicki Hollub will provide a further update on the Permian resources business shortly. Our Permian Basin operation with Barilla Draw with other domestic oil and gas operations in South Texas, are 24.5% interest in Dolphin project and a smaller and improved business in the rest of Middle East North America, our operations in Colombia as well as our Midstream operations in the Chemical business. Each of these businesses identified opportunities to drive earnings and cash flow growth also supported our ability to grow our dividends for our shareholders. Operations with our profitable growth will see minimal capital spending or will be disposed of. After several years of significant capital investment two significant projects are nearing their completion. As Willie Chiang will describe more details shortly, we expect to BridgeTex’s pipeline to start-up later this quarter, provide with an advantaged access to the Gulf Coast for our Permian crude oil production. We also expect start-up of the Al Hosn Gas Project in the fourth quarter. Assuming similar product prices these two key projects combined with growing oil volumes in the Permian resources development program should provide us with a meaningful earnings and cash flow per share growth in the 2015. Finally, as a part of our strategic initiatives, we’ll continue to focus on raising cash from our lower growth and lower margin assets. In the Middle East we continue to make progress and negotiations with our partners, we will reduce our exposure to the region. Our goal here is to improve the businesses’ ability to grow profitably. Over time we expect to achieve a similar balance in our asset mix with at least 60% of our oil and gas production coming from the United States. We’re continuing to explore strategic alternatives for assets and the Piceance in Williston Basin. We expect to monetize our remaining interest in general partner Plains all American which is valued at approximately $4.5 billion as well as possibly some other mid-stream assets when market conditions warrant. Since the end of the third quarter of 2013, we have repurchased more than 26 million shares of the company stock of roughly $2.5 billion and approximately 20.5 million shares remain available under the current share repurchase authorization. We expect that we’ll be able to further reduce our share count by roughly 60 million shares for the cash dividend from the CRC separation and about 25 million shares to monetization of our remaining interest in the Plains pipeline. Coupled with 20.5 million shares in our current repurchase program, we should be able to reduce our total share count by more than 100 million shares or about 13% of the current outstanding shares. Most of this share repurchase-ability will occur after the spin-off of CRC. These amounts do not include the ability to repurchase additional shares through proceeds we’re seeing from the sale, a portion of our interest in the Middle East, share reductions in exchange of our remaining interest in CRC or the monetization of other assets. We expect Oxy’s remaining businesses deliver moderate volume growth result the expanded Permian resource development program and shift towards horizontal drilling to start-up the Al-Hosn gas project and our participation of several other attractive international growth projects. These identified an intermediate growth opportunities and projects capable of more than replacing the production from the spin-off of CRC by the end of 2015. And Oxy shareholders will still retain the value created from the spin-off as owners of CRC shares. We expect to generate higher financial returns going forward as a result of our investment strategic initiatives. Our improved capital efficiency and operating cost structure, start-up of operations for BridgeTex’s, the Al-Hosn gas projects along the separation of our California business provide a natural up-lift to our return on capital employed. Return on capital employed was 12.2% in 2013 we expect it to rise to around 15% as we exit 2015. Now, I’ll turn the call over to Vicki Hollub, for an update on our activities in Permian Resources.
Vicki Hollub:
Thank you, Steve. This morning I’d like to continue the discussion of our Permian Resources business. In the second quarter, Permian Resources produced an average of 72,000 barrels of oil equivalent per day, which is an increase of over 7% from last year this is 28% on an annualized basis. We produced 40,000 barrels of oil per day for the second quarter, this is a 21% increase from a year ago and an 8% increase from last quarter. During the second quarter, our capital expenditures were $490 million we averaged 24 operated rigs of which 17 were horizontal. We drilled 87 wells including 42 horizontals. Year-to-date we have drilled a total 67 horizontal wells of which 43 have been completed and put on production. 38 wells are currently waiting on completion or a hook-up. In the third quarter we planned to drill 54 horizontal wells and place an additional 54 wells on production. I’ll first discuss how our Permian Resources teams are well positioned to deliver long-term growth and then I’ll review the quarterly operations in more detail. We’ve been operating in the Permian Basin for more than 30 years and have considerable knowledge of the depositional history of geology. With that base knowledge we have been and are continuing to make significant investments to assess the rock and fluid properties in our own conventional reservoirs across our acreage. This is helping us to develop a better understanding of the key geologic parameters that drive productivity, such as porosity, saturation, brittleness, total organic content, mineral and geochemical composition, rock and fluid compatibility, fracture distribution and stress regimes. Our Permian resources and exploitation teams are applying this appraisal work to construct calibrated Petro-physical models to characterize perspective benches and target landing zones within each bench. As a result of our work today, we have now identified over 7,000 drilling locations across our 2 million net perspective acres. This is an increase more than 2,500 since the beginning of this year. We expect to continue to grow the number of locations through our successful exploitation efforts. We’re also conducting an extensive appraisal of high-potential benches to optimize our well designs and development plans. This appraisal work includes collection and analysis of hole cores, cuttings, advanced log sweeps, micro-size mixed surveys and 3D-siesmic surveys. We’re leveraging our learnings from our participation in more than 450 outside operated wells along with data from some of the existing 4,400 outside operated wells in which we have a working interest. Based on our findings, we’re testing various still development and well design alternatives including optimization of well spacing, lateral length and cluster spacing. Additionally we have also increased profit concentrations and are evaluating various frac fluids. Our results are exceeding expectations indicating that we are quickly moving toward optimal design for the Wolfcamp A and B benches in the Midland Basin and the Delaware Basin. For example, at South Curtis Ranch in the Midland Basin, we completed and put on production six wells which had average initial rates of 850 BOE per day versus prior initial rates of 750. Our recent South Curtis Ranch 2818 well achieved a peak rate of approximately 1,100 BOE per day on gas lift. At Barilla Draw in the Delaware Basin, our recent Eagle State 28-5 well achieved peak production of 1,620 BOE per day and a 30-day average production of 1,120 BOE per day, significantly higher than our average 30-day production of 830 of prior wells in the Wolfcamp A and B benches. With respect to supply services and logistics, we have secured key resources to efficiently accelerate full field development and product growth. We have ordered long lead-time equipment and figured favorable material and service contracts by leveraging our position across our Permian resources and EOR businesses. These contracts ensure the availability of productive resources at competitive cost in strategic areas such as drilling rigs, simulation, tubing, casing, cementing, directional drilling and artificial lift. We have contracts or options in place to expand our fit for purpose drilling rig fleet to 54 rigs in 2016. We have expanded our completion capacity to four 24-hour frac crews and plan to further expand the fleet as we accelerate development. On the efficiency front, we intensified our efforts to improve operational execution and compressed cycle time. In early 2014, we implemented a batch drilling program to accelerate and improve the cycle time on our horizontal wells. In our batch drilling program, we do all the vertical section of the well with a smaller fit for purpose drilling rig. And following the vertical section, we use a higher capacity directional drilling rig with specialized services to complete the more complex curve in lateral sections of the well. This approach has allowed Permian Resources to transition our existing lower cost vertical rigs into our horizontal development programs to improve our overall cost structure. This method enhances the utilization of specialized services to achieve reliability and improved cost. We have reduced drilling cost in South Curtis Ranch by 24% since the end of last year. Now, for a quick update of our water management strategy. The Barilla Draw system has been pressured up and is operational. Today we have completed six fracs including one zipper frac using this new system. We’re achieving a cost savings of $2.50 per barrel of water. In the Midland Basin, we are duplicating this effort by installing a water distribution system at West Merchant with delivery rates up to 90,000 barrels per day. The system will be fully operational by September and we expect similar cost savings from this investment. These two systems are the first phases of our comprehensive water management strategy which we will discuss in more detail in future calls. I would now like to share a few more details of our activity in each of our geographic areas. In the Texas Delaware, specifically in the Barilla Draw and Reeves County, I’m pleased to report that in the second quarter we drilled 10 horizontal wells and completed 7 wells with initial production rate for the Wolfcamp A and B, match the 1,150 BOE per day achieved in the first quarter. In the area highlighted on the map where we held over 35,000 net surface acres, we’ll drill an additional 27 horizontal wells in the second half of 2014. We continue to increase efficiency and expect our average well cost of $8.5 million to improve an additional 5% by the end of this year. We are encouraged by our success in this appraisal program. As a result, we are transitioning into an accelerated development phase in Barilla Draw. In the Midland Basin, where we held approximately 90,000 net surface acres, we’re continuing our appraisal and development drilling efforts. We drilled 14 horizontal wells in the second quarter and placed 21 horizontal wells on production. We will drill an additional 55 horizontal wells in the second half of 2014. Our average drill time for the horizontals is 27 days per well with total drilling and completion cost averaging $7 million per well. With the knowledge gained, we are transitioning from appraisal to accelerated development in our Merchant field. As a result of the strong performance this year, we’re increasing our 2014 production growth expectations to be between 15% and 18% from the previous 13% to 15%. In addition, we are increasing Permian Resources’ capital by $200 million to $1.9 billion. The total number of wells drilled will remain roughly the same with a greater percentage of horizontal wells. The result in production increase from the incremental capital will primarily impact 2015. In closing, our 2014 program is designed to delineate and appraise our acreage in order to maximize both ultimate recovery and financial returns. We’re on track to exceed expectations in 2014, and we have the required resources and infrastructure in place to meet our 2016 production target of more than 120,000 BOE per day. In addition, Oxy has several exciting Midstream projects related to our Permian infrastructure and takeaway capacities that is a unique competitive advantage. I will now turn the call over to Willie to discuss in more detail.
Willie Chiang:
Thanks, Vicki. Good morning everyone. I’d like to give you a very quick overview of our Midstream and marketing segment and describe how it literally connects our oil and gas production to market. And then spend the majority of my time to share our strategies to support Permian Basin growth that you just heard about from Vicki. We strongly believe in having multiple perspectives in house, those of a large Permian producer, a significant Midstream infrastructure operator and a crude NGL and gas marketer gives us a very unique advantage that differentiates us from others. The Midstream operations, not only enables us to unlock and preserve value for our core business, it also allows us to utilize our assets to move third party volumes to market. Further we have the scale to drive key strategies in the Permian Basin. First, let me provide a quick overview of our Midstream marketing segment. The role of the Midstream group is to maximize realized value for Oxy production by ensuring access to markets, optimizing existing assets and building out key assets across the value chain. This is increasingly important with the U.S. moving to an abundance of resource and a significant shifting of global supply and demand. Our Oxy owned domestic Midstream assets are shown in slide 33, these are supplemented with contracted capacity on third party assets, all of which allows to market substantially all of Oxy’s domestic oil, NGLs and gas production, comprise of roughly 470 BOE per day, 278,000 barrels a day of crude, 72,000 barrels a day of NGL and over 700 million cubic feet a day of gas. We also market third party crude and NGL volumes focusing on parties whose supply is located near our transportation and storage assets. These third party volumes are significant and add an excess of 200,000 barrels a day for third party, crude and NGL volumes. This aggregation of volume, both service a need for producers and end-users and allows us to better utilize and optimize our assets. We also have gas processing plants to CO2 fields and facilities. We process equity and third party domestic wet gas to extract NGLs and other gas byproducts including CO2 and deliver dry gas to pipelines. We produce approximately half of our CO2 requirements. Currently we operate 1,800 megawatts of power generation, the majority of these power plants are located next to our OxyChem and oil and gas facilities in order for us to share infrastructure, act as a steam host and to consume power with the remaining power sold to the power grid. Now, let me go back to our key Permian Basin assets, where our Midstream operations are focused on providing access to multiple markets for our Permian production. Our equity production is roughly 150,000 barrels a day and is expected to grow significantly. Additionally, we purchase and market over 200,000 barrels a day of third party crude production. Turning to slide 34, Centurion is a large gathering in mainline system in the Permian that we continue to optimize and significantly expand. Our Centurion system has roughly 2,900 miles of pipeline over 100 truck stations, 6 million barrels of storage and has access to most third party transportation assets that enable us to deliver crude to all Permian refineries as well as to the origin point of key pipelines taking production out of the Permian Basin. We’re focusing on two new takeaway points, Colorado City, which is the origin of our BridgeTex’s pipeline which we’re jointly developing with Magellan. In the Midland South exit which is the origin to third party pipelines Long-Horn and Cactus. When at full capacity BridgeTex and Cactus will add an additional 500,000 barrels a day of takeaway capacity from the Permian Basin. These new pipelines give us access to the Houston and Corps refining centers and to our own Ingleside Terminal in Corpus Christi. It also supplements our existing access to Cushing. We’re working on options to handle the growing light crude production in the Delaware Basin in Southeast New Mexico in order to preserve the Permian crude qualities in the Midland Basin. Currently Oxy and Magellan are in the final phases of construction on the BridgeTex pipeline which is expected to start up later this quarter. The 450-mile pipeline will be capable of transporting approximately 300,000 barrels a day of crude between the Permian region and Gulf Coast refinery markets, Oxy has a significant committed takeaway capacity on BridgeTex as well as other third party pipelines exiting from the basin. When all planned pipelines are in operation by mid-2015, our Midstream unit will have access to long-term cost advantage takeaway capacity. As a major producer in the Permian Basin, we’ve been a driving force behind the construction of new infrastructure adding transportation capacity from the basin in order to benefit Permian production and avoid production constraints. Now, I want to highlight how important adequate takeaway capacity is to market value. On slide 35 I’ve shown Midland WTI pricing compared to Cushing WTI in the U.S. Gulf Coast LLS markers for the period of 2009 through today. You can see how the differentials were transportation parity in a market with adequate takeaway capacity. Now, note the differentials in the widening significantly as the supply and demand balance tighten in a takeaway constrained market. We have seen Midland LLS differentials as wide as $30 a barrel in January 2012, in January 2013 during the winter refinery maintenance periods. This year, we’ve seen wide differentials throughout the entire year as increases in production have further tightened the supply and demand balance. The Midland LLS discount this year has averaged just over $10 a barrel versus just under $6 a barrel during the second half of 2013. With the upcoming completion of BridgeTex, in the start-up of Cactus pipeline in mid 2015, we expect differentials to return to levels that reflect incremental cost of transportation between the Permian and Cushing or the Gulf Coast. As you’ve heard in Vicki’s comments Oxy’s production growth will be significant in West Texas and Southeast New Mexico. With our long-term capacity on multiple pipelines, we will have security of placement with takeaway capacity of roughly three times our current equity production from the Permian Basin. We’ll also have access to key markets and options to protect our Permian crude premiums. Let me give you an update on our Ingleside Energy Center in Corpus Christi. This is the formal Naval Station that we purchased in late 2012 which is located outside of the congested ship channel near the mouth of Corpus Christi Bay. We’re developing a terminal facility that will be able to handle up to 100,000 barrels a day of propane and 200,000 to 300,000 barrels a day of condensate and crude. The site will contain 2 million to 4 million barrels of storage and also provides flexibility to accommodate future processing facility options, on-site or at a nearby OxyChem complex. We have sanctioned both projects and expect the LPG propane terminal to be complete mid-2015 in the first phase of the crude condensate terminal to be completed in the first half of 2016. Our Midstream business has demonstrated steady earnings growth over the last few years, slide 37 shows the premium or the value add from our Permian crude logistics and our marketing business. This is in terms of dollars per barrel on equity production adjusted. This is versus a group of six Permian producers based on the available public information we were able to pull. You can see we’ve added approximately $1.50 a barrel better than the group average. On the same basis we expect to capture an additional $2 plus of value once the BridgeTex and Cactus pipeline startup as a result of our long-term advantaged takeaway capacity. This reinforces the importance of key infrastructure, if these new pipelines were not sanctioned, the entire basin would suffer continued significant discounts to market due to the infrastructure constraints. You can see the reasons we’ve moved forward on these key pipeline initiatives. I hope this gives you a better view of our Midstream business and in particular its key role in supporting our domestic oil and gas business. This is an exciting time for our Midstream business as we continue to build out a strong platform for future opportunities. Thanks for your attention. I’ll turn the call back now to Chris Degner.
Chris Degner:
Thank you, Willie. Operator, we’ll now pull for questions.
Operator:
Thank you. (Operator Instructions). And our first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate – Bank of America Merrill Lynch:
Thanks, good morning everyone and thanks for all the additional color in the Permian. Steve or Vicki, I don’t know who wants to take this, if I could have one question on the Permian and then one on the restructuring process please. Specific to the Permian, my understanding is that when we look at the publicly available information, your well results have been wagging what we would expect for peers in the area. And my understanding is that some kind of reporting issues with you guys. I wonder if you could share something with us. And as it relates to the wells that you have drilled prior the presentation today, can you isolate where in the Permian you’re drilling in terms of which horizon out of these averages that you feel you’ve de-risked multiple sections across your acreage. Just a little bit more color as to what your confidence level is and the repeatability of these kinds of results across the 2,000 plus locations? And I’ve got a follow-up please.
Vicki Hollub:
Yes, Doug. Some of our reporting issues have been associated with what point in the flow back and production process of the well that we take the test. And some of our teams have been turning in 24-hour completion, initial completion rates to the railroad commission in the State of Texas that are not – when the well is fully cleaned up and not necessarily at its peak. With that said, I’m going to just be honest with you that in some areas we still are lagging behind our competitors in terms of our initial rates in production. And that’s why we’ve been aggressively here recently trying to try new things with respect of our frac designs to improve our performance. In the Midland Basin, South Curtis Ranch, we are getting better and we’re testing not only frac designs in terms of fluids and profit volumes rates and things like that. All of which are helping us to improve. But we are – we have discovered that our cluster spacing was not optimal for the initial fracs that we’ve done there. So, we’re confident that going forward our South Curtis Ranch performance is going to improve. Now certainly the best area that we have right now is our Wolfcamp production in the Texas Delaware. That’s where we’re doing best and we’re actually outperforming some of our competitors in the Texas Delaware. So, we’re confident that there we’ve gotten closer to figuring out the right completion technology. And the right, not only profit concentrations, sand, total volumes and rates but also the design of the total job. So, in the Texas Delaware, we’ve actually increased our profit volumes by about 20% and our fluid injection volumes by about 50%. We’ve also increased our rate there. So, we expect continuing good performance and maybe even better performance there. And in fact, it’s in the Texas Delaware where we’ve added most of the 2,500 new well locations that we’ve added since the beginning of the year. So, while in Texas Delaware, we feel like we’re doing a great job. We know we still could improve it. We see opportunities for that. South Curtis Ranch, in the Midland Basin, we’ve changed some things and we expect to see better results here coming pretty soon.
Doug Leggate – Bank of America Merrill Lynch:
On de-risking Vicki, of the locations on multiple benches or horizons I should say?
Vicki Hollub:
Yes, most of our, about – right now about 45% of the 7,000 wells are in the Wolfcamp. And as you know we probably as an industry know more about the Wolfcamp than any other. About 20% of our inventory right now is in the Bone Spring in Southeast New Mexico. Those wells as you know are also doing pretty good, where we’re seeing, in Texas Delaware we’re seeing payout time periods of one and half years or less. And in Southeast New Mexico we’re starting to see some good performance there in the Bone Spring. So, I’d say that right now 65% of our inventory is probably minimal risk in terms of economics and the ability to profitably grow it. The others are in benches that we still have some work to do.
Doug Leggate – Bank of America Merrill Lynch:
Thank you. And Steve, my follow-up hopefully quickly is, in the Middle Eastern process, you have a pretty major material contract expiring in Oman next year. And obviously things are kind of moving on this year in terms of obvious of news flow and the disposal process. My understanding as you may have things maybe moving a little quicker than perhaps you’ve been prepared to see previously. I just wonder if you could give us an update on your company as where everyone maybe getting the three separate transactions completed over the next let’s say 12 months?
Steve Chazen:
Yes, I think one of the transactions is moving on very well. And I think we’ll get to resolution here in the easily foreseeable future. There is the contract extension in Oman which will have to be part and parcel of whatever goes on there because otherwise it expires in 2015. So I think they take a little longer but pretty confident there. The third one is, I think more challenging. And we’ll see what can be done there. But there are some issues that are not related to us that I hope work their way out but I think that’s probably into next year.
Doug Leggate – Bank of America Merrill Lynch:
I’ll let someone else jump. Thanks very much.
Steve Chazen:
Thank you.
Operator:
Thank you. Our next question comes from Leo Mariani of RBC. Please go ahead.
Leo Mariani – RBC:
Hi guys, you referred a little bit some other projects where you may be able to grow international production outside of Al Hosn. Is that kind of part and parcel with your many negotiations? Could you guys just elaborate on that a little bit?
Steve Chazen:
I think there is two parts there. We have some new contracts in Colombia for heavy oil which I think we’re pretty enthused about. And I think those are pretty much there. So, I think those will be – they’re away from some of the areas where we’ve had political difficulties I want to call them that. So, I think those are I think in pretty good shape. And then, obviously we’re principally, one of the principal objectives of the program is either large scale reductions in areas where there is no growth or smaller reductions in areas where there is growth and a partnership with the local government. So, I think some of the growth will come out of the partnership with the local government in those areas where there is potential for that.
Leo Mariani – RBC:
Okay, that’s helpful. And I guess just in the Permian you guys clearly have a dramatic acceleration of the rig-count over the next couple of years here. Just trying to get a sense of how much of that maybe secured at this time by contract and what are you kind of seeing there in terms of service cost?
Vicki Hollub:
We’re definitely going to be able to get up to at least 54 rigs and by 2016. That’s – but our current plan is to go to 45, however we can – we have the options in place to go to 54. So that’s not really at risk for us right now. We know we can achieve it on the drilling rig side. And the reason we have that range there, we’ve got 47 in our plan for 2016 and the reason on the slide that the seven additional are grade. We have the option to get them. So we know we can. What we’ll be doing between now and 2016 is trying to ensure that all the rest of the support services in the Permian area available and that we can secure that to get to the 54. We feel like we’ve already secured the services – support services outside the drilling rig that can support 47, it’s just a matter of can we get to the 54 and we’re working on that plan now. Surface cost, we’re still trying to manage that cost in the basin are going up as demand increases. But we’re trying to leverage our size to minimize the increases that we’re seeing.
Leo Mariani – RBC:
Okay.
Steve Chazen:
There is, also productivity gains from this too. So, I think we’re – we’ve saved – we saved about 10% from last year’s cost already. That’s not driven primarily by reducing the day rate but by drilling more wells per day essentially. So I think with the productivity gains should more than offset whatever modest inflation there is in the cost.
Leo Mariani – RBC:
Okay, that’s helpful for sure. And can you guys just elaborate on other assets that you might be thinking about disposing we guys made a comment that said that anything that’s not profitable could be up for sale. Any more color you have around any of those processes?
Steve Chazen:
I think we’ve said that – reiterated this morning that we’re still looking at options for the Piceance in the Williston Basin, might be a little more activity in one of those, we don’t know yet. And we also said that buried in the comments was if we can get the right arrangement, perhaps some of the Midstream assets where we retain the contract so we can continue to move our crude and get the margins from the trading but perhaps dispose of the underlying asset. And let somebody else take the tariff.
Leo Mariani – RBC:
Okay. Thanks, that’s helpful.
Operator:
Our next question comes from Ryan Todd of Deutsche Bank. Please go ahead.
Ryan Todd – Deutsche Bank:
Great, thanks. If I could ask maybe a little bit more on the Delaware Basin, and I appreciate all the detail. Can you talk a little bit about your use of long laterals, I mean, have you drilled two-mile laterals or are you extending the lateral lengths. And if so, how much of your acreage there in the basin do you think would be conducive to longer laterals?
Vicki Hollub:
Currently in the Delaware Basin, we’re drilling lateral lengths of between 3,300 and 4,200 feet. What we’re doing right now is some modeling with respect to the optimum lateral lengths in the basin. As you know, the Wolfcamp productivity in the Texas Delaware is much better than in the Midland Basin. And thus far we’re seeing some good productivity from the lateral lengths that we’re drilling. We haven’t really drilled much yet over 4,200 feet to the challenges there as I said, at what point have you drilled so much that you start destroying value in terms of the just the friction effects of the longer laterals. And the other thing is that you have the challenges of the acreage positions with respect to ensuring that you’ve setup your opportunities to go with longer laterals. But currently, we’re seeing that probably it’s more likely to meet the longer laterals in the Midland Basin rather than in the Texas Delaware. However with that said we are trying a lot of things. We haven’t gotten to that point yet. We’re trying to minimize the variations that we have per stage of evaluation to ensure that we understand what impact each thing that we change is having on our productivity.
Steve Chazen:
I mean, maybe a little focus than some other people. I think we focus on our sort of our finding cost sort of calculation rather than the IP calculation. So, from our perspective in order to lengthen the laterals may cost us more money. You might get more IP but maybe at a cost of a higher finding cost. We’re just – it’s not the way we think about things. Some small producer may be more interested in IT.
Ryan Todd – Deutsche Bank:
Okay, that’s helpful. And have you seen – I guess still on the Delaware, have you seen, where are you seeing from an oil and gas mix in your Wolfcamp well there and you’re seeing much variation across the extent of your acreage?
Vicki Hollub:
We’re seeing a little bit of variation but typically we’re seeing anywhere from 72% to 80% oil in the Texas Delaware. And in most cases, we’re seeing above 75%.
Steve Chazen:
We’re a little pickier and maybe we have better acreage to some other people who are doing a fair amount, they get gassier results.
Ryan Todd – Deutsche Bank:
Okay.
Steve Chazen:
You can see that our oil is rising and our gas isn’t if you just looked at the numbers we’ve given you. So, we’re basically a little pickier than some other people who are maybe that’s all I got, so they’re drilling gassier wells.
Ryan Todd – Deutsche Bank:
Okay. That’s helpful. And on the pace, the outlook in terms of – obviously your ramp is pretty significant over the next few years. Is the pace of development there broadly going to be governed by your view of the entire logistical system and how much capital you can put into the Basin without destroying returns? What’s going to be the primary I guess governing factors on the potential to maybe even show upside over that three-year window?
Steve Chazen:
We think on the production numbers we’ve given, we have considerable upside just with the drilling we’re showing. But putting that aside, it’s a return based business. And we’ve just assumed, learned lot of people make mistakes and learned from them before we expand our footprint. But there is, also other logistical issues in the basin. And yes, we want to make sure that we have takeaway capacity for the oil, and more concerned frankly about takeaway capacity for gas. You’re not going to be able to flare the gas. And the gas production, the base is likely to grow sharply in the next year or two as people drill these gassier wells. And so you could wind up with a bad situation. So, one of our major focus is just to make sure that we have gas takeaway capacity so that we don’t drill wells we have to have shut in, because clearly you’re not going to be able to flare.
Ryan Todd – Deutsche Bank:
Great. Well, thanks, I appreciate the help. I’ll leave it there.
Steve Chazen:
Thank you.
Operator:
Our next question comes from Jason Gammel of Jefferies. Please go ahead.
Jason Gammel – Jefferies:
Yes, thanks. Maybe I’ll take another stab at this Permian drilling situation more in terms of managing the drilling inventory. And I’m just going to use some very simplistic numbers, at the current rig count and the number of wells that you drilled last. You have about 20-year inventory, obviously doubling the rig-count we’ll take that back to a 10-year inventory. But I also assume you’re probably going to be adding locations over time. So how do you actually then balance the amount of drilling inventory that you have from an MPV basis, and what I’m really getting out more broadly, do you see divestiture opportunities within the Permian Basin as well as potential acquisitions?
Steve Chazen:
Yes. If I look at the list of mistakes I’ve made over the last 20 years, the mistake I’ve made most is investing anything into Permian Basin. And because there is so many horizons, there are so much layer, there is so much oil available to the system. So we didn’t divest that much but I regret every acre. So I think that while I’m here we’re not going to be divesting anything. I do think that – I think the program that Vicki has outlined is sort of the minimum program that’s what we think we could achieve over the next couple of years without wasting money. As we get better at this and the basin matures there will be more opportunities because we’re sort of everywhere. I think that – I think we could accelerate the program further. This is what we’re talking about right now. As the basin matures, we find more stuff to do. The results maybe turn out a little better. I think we’ll go ahead. I am concerned about infrastructure constraints over the next two or three years. While we have, as Willie pointed out, lots of oil takeaway capacity, lot better positioned than most people I think. And so, I think we’re in pretty good shape for that. And we do control the gathering system so we can gather our own stuff. I’m little concerned about gas and so we’re probably going to take steps to make the gas more certain. I think that’s probably more my deeding concern is that the crowding in the business, I’m not really worried about cost because I think productivity improvements are more lost at the cost.
Jason Gammel – Jefferies:
Great, that’s pretty clear. If I could just ask one more on the CRC spin-out process. It looks to me and maybe I’ve just missed something but I think that your estimate on the amount of shares that you’ll be able to repurchase from the transaction has went to 60 million from the range of 40 million to 50 million. And my question is, is this going to be related to the just under 20%, retention of equity and the exchange over time and do you still expect to take a $5 billion dividend out?
Steve Chazen:
No, dividend $ billion.
Jason Gammel – Jefferies:
Okay.
Steve Chazen:
And so we haven’t counted the shares and the exchange. So we’re simply, our – we got our modelers out and so they divide $6 billion by $100 mop it to 60 million shares. We didn’t pay a lot for that advice.
Jason Gammel – Jefferies:
Very good, I think I understand now.
Steve Chazen:
Okay, thank you.
Operator:
Our next question comes from Paul Sankey of Wolfe Research. Please go ahead.
Paul Sankey – Wolfe Research:
Hi everyone, and congratulations to those who have new roles. I see, I kind of didn’t understand Steve that last point, believe it or not, the exchange of it has be completed within 18 months and any proceeds from that I guess is the word would be used for buyback – additional buyback?
Steve Chazen:
No, it’s actually just so you understand the shares the 19.9% shares that we own. Our options are sort of limited because it’s part of a tactual link. So, if we exchange it for Oxy shares, now it was – ad in the paper it says, anybody who wants to can get CRC shares and they give us back Oxy-shares for it, okay. We can do that without paying any tax. In theory, if we had that kind of debt around we could exchange it for debt, but there isn’t that kind of munch there around to do that. If we do anything – the third alternative would be simply distributed the shares to the shareholders if we couldn’t do that – that also would be tax free. If we sold it for money, we would have to pay tax on it. So, our preference would be to do the exchange offer. So basically, it’s a split off of the 19.9% in terms. So I think those are – so what we did was we sort of guessed it how much it might, we haven’t included that number in our 60 million shares. But there would be some number of shares that we’ll exchange the CRC shares for Oxy shares and we do that without paying any tax.
Paul Sankey – Wolfe Research:
Okay. And the follow-on slide which is 21, where you show that the same as 60 million says clearly that you don’t include anything from MENA. I was just wondering why is that does not reflect that reduction, does that mean that you’re going to pay down debt as well?
Steve Chazen:
Well, there is a small amount of debt reduction probably.
Paul Sankey – Wolfe Research:
Okay.
Steve Chazen:
It’s just in the rounding.
Paul Sankey – Wolfe Research:
Yes, I figured that I just wanted to confirm that. So, the fact that your list of mistakes just maybe think of Lindsay Lohan I see funny enough. But there you go, would that involve you potentially making an acquisition in the permit further acquisitions of there? Thanks.
Steve Chazen:
Actually the Permian acquisition scale is now – you have to speak to the next round of management about that. But I sure wouldn’t do that. The prices are ridiculous far above what we traded six or seven times wherever we want to say the cash flow. And the acquisitions are very dilutive and I can’t imagine doing one. I suppose if there is a collapse in oil price or something like that that would be a different story. But actually a huge reduction in the public market values for these companies, I can’t even imagine doing one, I don’t imagine that hopefully my successors are well trained enough not to do anything stupid too.
Paul Sankey – Wolfe Research:
Yes. And then finally from me, thank you. And then finally from me, in the past you’ve sort of openly debated the buyback as the benefits and the merits of a buyback. Is there some sort of price sensitivity to this or is this going to be a fairly blind part? And I’ll leave it there.
Steve Chazen:
No, hopefully it won’t be a stupid process I think that’s what you’re blind I guess another word for stupid.
Paul Sankey – Wolfe Research:
Well, I think you’ve said in the past that there is a fair value that you believe?
Steve Chazen:
There is a fair value we believe in. And we’ll do what we – yes, we’re going to buy back the shares ultimately but it also depends on the price. We would expect that during the process of divesting of California company, the stock will during the confusion will trade at the Oxy stock will trade at some what we would view as discounted value. And we would expect that a – we could buy a lot of shares during that period. And we’re pleased to be wrong but that would be a reasonable expectation during that period.
Paul Sankey – Wolfe Research:
I guess what I was driving at partly as well as the potential for you to spend more money organically to grow faster probably as to buyback?
Steve Chazen:
More but not materially more I think is the answer. Could you put another $1 billion to work, yes, could you put $2 billion to work, maybe, could you put $3 billion to work, no. I think we got a plan that we can execute efficiently, we could probably do a little better as things progress. So I think the answer is yes, we could do that but not for very long.
Paul Sankey – Wolfe Research:
Thanks very much.
Steve Chazen:
Thanks.
Operator:
Our next question comes from Ed Westlake of Credit Suisse. Please go ahead.
Ed Westlake – Credit Suisse:
Yes, one question on the Permian Vicki, just obviously you’ve broken out your current vertical and horizontal and then you’ve explained how doing the two-activity separately makes sense. As you look at that rig count chart, should we assume you’re still going to have the same sort of ratio or maybe help us understand how many vertical rigs are going to be in that 47 plus 7?
Vicki Hollub:
I don’t see us having more than about 6 or 7 vertical rigs at any given time in the future. So the bulk of the 47 to 54 that we’ll have only, I would expect only about 6 or 7 of those to be vertical.
Ed Westlake – Credit Suisse:
Right. And obviously you’ve given us 7,000 locations and Jason was prepping on that. But as you ramp up the rigs, your inventory is going to drop I think perhaps a little bit faster. So, at least on a forward-looking basis when we get to 2016 which is obviously a bit further in the future, where would you then go next after the initial inventory? I mean, it seems like you’ve got some good sweet spots in the Midland and fantastic sweet spot in the Texas Delaware. It feels like a lot of your equity is over in the Bone Springs and so to maybe talk about how the returns would change as you shifted those rigs around through the program?
Vicki Hollub:
Yes, let me say that 7,000 is based on the appraisal work and the evaluations that we have done to date. We fully expect that 7,000 to grow. As you know, we have a huge acreage position. And what we’re trying to do is go to our initial step of exploration and then appraisal before we’re adding, and some appraisal work has to be done before we add locations to our current inventory. So, I’m almost thinking with what we’re seeing, I wouldn’t be surprised to see that, our inventory increases by the amount of wells that we drill. So I expect that inventory to grow fairly significantly over the next couple of years. And I expect it to grow mostly in the Texas Delaware, Southeast New Mexico, although we still haven’t done a lot with some of the areas within the Midland Basin. What we’re trying to do is stay very focused on limiting our focus area so that we can make sure that we accelerate efficiently. And then we’re also limiting our appraisal areas too to make sure that we go in, we get our appraisal work done and then we transition to development mode. So, some appraisal work, there are some areas where we haven’t even begun our appraisal work.
Ed Westlake – Credit Suisse:
And then just a question on the Midstream, I mean, I know you sort of signaled you’re going to be selling the Plains All-American GP. Well, it seems like it’s time to build another one given the amount of Midstream assets that you are still building. So, I mean, would you think of about creating a new Oxy MLP down the road to help fund the infrastructure that will be required for you and for others in the Permian?
Steve Chazen:
Yes, I think that you just have to split the revenue streams that come out of us into two. One is the Terra streams and those are once you build the pipeline they’re sort of not very interesting. And the other is sort of the trading or stream’s ability to move the oil at different spots. We would just assume to retain the contracted volume streams and ultimately dispose of the Terra streams if you will. So, I think as far as building another line, I think we got plenty for us, we’re three times what we currently produce. So we got plenty for us. We’ll see how it goes. Again, I’m focused about putting the Midstream money right now in the movement gas to make sure that’s not an issue. When you run an MLP or any kind of Midstream business you’re thinking about $1 or $0.50 a barrel. When we look at a barrel of oil, we’re thinking about $100. And so our view is, we need to make sure that our $100 oil gets moved. And worry a little less about the $0.50 fee. So, we’re focused on making sure that the – by building this stuff out, we made it better for everybody in the Basin. And then, on the gas we expect to do the same thing.
Ed Westlake – Credit Suisse:
And then just a final question. You’ve seen these I guess royalty interest, mineral interest stream start to get traded independently of the companies or maybe just a reminder of where your royalty position is in some of your legacy acreage?
Steve Chazen:
It’s a complicated number to put it mildly. First of all, the king of this royalty stuff is in the California business, so you probably can ask them about it when they show up. But putting that aside, we – there is, royalties let’s say under one of our EOR fields that we own the royalty interest there or a large piece of the royalty interest. So, if we were to dispose that in some way, that would hurt our finding costs and our margins would shrink, our present worth would shrink, that may not make in that – and our reserves will go down because you’re economic limit is reached sooner. On the other hand, we have a fair amount of production where we just get checks from third parties. And we don’t really know the number at this point, I mean, it’s not – they’re counting the checks I think they try to figure it out. But for the – excluding California, the royalty income is somewhere in the range of $300 million a year and to find some way. We just have to go through it and figure it out. I think where it doesn’t affect our ability to manage our base business because our royalties are scattered in a number of places, somebody like the basis team times cash flow. I think we’re game. On the other hand, where it affects our base business, we just don’t keep it because I think it will hurt us in our finding cost going forward.
Ed Westlake – Credit Suisse:
Thanks, very clear and helpful. Thank you.
Steve Chazen:
Thanks.
Operator:
Our last question comes from John Harlan of Societe Generale. Please go ahead.
John Harlan – Societe Generale:
Close enough.
Steve Chazen:
The operator is not French obviously.
John Harlan – Societe Generale:
Yes, thanks Steve. In the Permian, how much of your drilling activity is pad based at this stage?
Steve Chazen:
Vicki.
Vicki Hollub:
Because of the early stage that we’re in and with respect to our drilling, we’re not doing a lot of pad drilling at this point. But the pad drilling will come, it’s already built into the development plan. What we’re doing is appraisal work and we expect to be very heavily independent drilling in 2015.
John Harlan – Societe Generale:
Which will also help, okay.
Vicki Hollub:
And as you know, we do a lot of pad drilling elsewhere so it’s not like we’re opposed to it. But we’re in the process of drilling the appraisal parts of some of these programs. And we will definitely go to not only pad drilling but manufacturing mode once we get beyond the appraisal stages.
John Harlan – Societe Generale:
Right. I was just wondering how quickly you’d be improving efficiencies. What about staffing, given the ramp in the Permian, do you think you have enough people?
Vicki Hollub:
We’re adding people. We’re ramping up and we are going to have to add a few more people to our Permian resources and exploitation teams and our field execution teams. But so far we’ve been able to add the people that we need as we progress.
John Harlan – Societe Generale:
Okay, great. Last one from me, Steve, you talked about addressing the Midstream. Does this mean MLP or just outright sale?
Steve Chazen:
Well, I mean, it doesn’t – if somebody would give you MLP multiple and all cash, I think that’s for us probably a better option. On the other hand, if you can’t do it that way and we get some other way, I think we can do an MLP.
John Harlan – Societe Generale:
Great. Thank you.
Steve Chazen:
Thanks.
Operator:
This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Degner, for any closing remarks.
Chris Degner:
Hi, thank you everyone for listening. I know it’s been a busy day for you all. We’ll be available at New York for your questions. Thanks.
Steve Chazen:
Thanks.
Operator:
The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.
Executives:
Chris Stavros – VP, IR Cynthia Walker – EVP and CFO Steve Chazen – President and CEO Vicki Hollub – EVP and Head, Oil and Gas Operations, U.S. Willie Chiang – EVP, Operations
Analysts:
Doug Leggate – Bank of America Merrill Lynch Paul Sankey – Wolfe Research Leo Mariani – RBC Roger Read – Wells Fargo Sven Del Pozzo – IHS Ed Westlake – Credit Suisse Pavel Molchanov – Raymond James John Harlan – Societe Generale
Operator:
Good morning. And welcome to the Occidental Petroleum Corporation First Quarter Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions). Please note this event is being recorded. I would now like to turn the conference over to Mr. Chris Stavros. Mr. Stavros, please begin.
Chris Stavros:
Thank you, Emily and good morning, everyone. And thanks for participating in Occidental Petroleum’s first quarter 2014 conference call. On the call with us this morning from Houston are Steve Chazen, Oxy’s President and Chief Executive Officer; Vicki Hollub, Executive Vice President and Head of Oxy’s U.S. Oil and Gas Operations; Cynthia Walker, our Chief Financial Officer; Willie Chiang, Oxy’s Executive Vice President of Operations and Head of our Midstream Business; Bill Albrecht, President of Oxy’s Oil and Gas in the Americas; and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment, I’ll turn the call over to our CFO, Cynthia Walker, who will review our financial and operating results for the first quarter and also provide some guidance for the current quarter. Our CEO Steve Chazen, will then provide an update on the progress of our strategic initiatives and also some comments on the composition of the remaining Oxy after the separation of our California business. Vicki Hollub, will then conclude the call with an update of our activities in the Permian Basin. As a reminder, today’s conference call contains certain projections and other forward-looking statements within the meaning of the Federal Securities Laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements and our filings. Our first quarter 2014 earnings press release, the Investor Relations supplemental schedules, and the conference call presentation slides, can be downloaded off of our website at www.oxy.com. I’ll now turn the call over to Cynthia Walker. Cynthia, please go ahead.
Cynthia Walker:
Thank you, Chris, and good morning everyone. My comments will reference several slides in the conference call materials that are available on our website. In the first quarter, we’re off to a strong start in our domestic oil growth strategy. Domestic oil production was 274,000 barrels per day, an increase of 4,000 barrels from the fourth quarter of 2013. Overall production was 745,000 boe per day. We had core income of $1.4 billion resulting in diluted earnings per share of $1.75 for the first quarter. This is an improvement over both the prior and year ago quarters. We generated $2.9 billion of cash flow from operations before changes in working capital and repurchased 10.5 million shares ending the quarter with $2.3 billion of cash on our balance sheet. Now, I will discuss the segment performance for the oil and gas business and begin with earnings on slide 3. Oil and gas core earnings for the first quarter of 2014 were $2.1 billion. As you can see, this was essentially flat with the fourth quarter of 2013 and an increase of almost $200 million over the first quarter of 2013. On a sequential quarter-over-quarter basis, we saw improvements from higher domestic realized prices on all of our oil and gas products and higher sales volumes in Columbia, which were offset by lower sales volumes in Iraq. In Columbia, while we recoup liftings in January, which had slipped from the fourth quarter of 2013, in search and activity continues to challenge both our production and listings in our Llanos Norte fields. Production from the fields was shutdown in April. However, now pipeline repair work has begun and we look forward to have normal operations in May. In Iraq, operations were as expected, although liftings continue to be lumpy. We had no liftings in Iraq in the first quarter. Turning to slide 4, total production from the current quarter was 745,000 boe per day. A decrease in daily boe production of 5,000 from the fourth quarter and 18,000 from the year-ago quarter. On a sequential quarterly basis, these results reflect domestic growth of 4,000 boe per day, mainly in the Permian Basin, offset by lower production in California. The Permian Basin improvement reflected recovery from fourth quarter severe winter weather and new production from our drilling program. California production was essentially flat excluding one-time benefits which positively impacted the fourth quarter of last year. In MENA, production was 9,000 boe per day lower primarily due to a scheduled plant turnaround in Dolphin and the remainder in Bahrain due to contract terms. If you turn to side 5, I will discuss our domestic production in more detail. Focusing on our commodity composition on a sequential quarterly basis, we saw oil production grow 4,000 barrels per day, with increase coming from all of our business units. NGL production increased 2,000 barrels per day, almost entirely in the Permian. Natural gas volumes were 10 million cubic feet per day lower or about 2,000 boe per day, with the decline coming from California, partially offset by higher production in the Permian and Mid-continent. Turning to slide 6, our oil and gas operating cash margins improved by $0.20 per boe, on a sequential quarterly basis. Our first quarter of 2014 worldwide realized oil prices were essentially flat compared to the fourth quarter of 2013. Although domestic realized oil prices improved slightly despite widening differentials in the Permian Basin. We also realized higher NGL prices domestically due to seasonal factors, and experienced a 37% increase in natural gas prices, reflecting an improvement in the benchmark. Oil and gas production cost were $14.33 per barrel in the first quarter of 2014 compared to $14.13 per barrel in the fourth quarter of 2013. Domestic operating expenses were higher in the first quarter compared to the fourth quarter due to higher energy and CO2 and steam injecting costs. Controllable costs were essentially flat on a sequential quarterly basis. MENA production costs decreased in the first quarter due to under-liftings in Iraq, which have higher operating costs. First quarter exploration expense was $55 million and we expect second quarter exploration expense to be about $80 million. Turning to chemical segment core earnings on slide 7, you’ll see first quarter earnings of $136 million, this was $8 million higher than the fourth quarter and exceeded our expectations, primarily driven by volume improvements across most products in preparation for a strong spring demand. This improvement was in part offset by the run-up in natural gas cost due to the extreme winter cold. We expect second quarter 2014 earnings to be about $130 million, a seasonal up-tick in demand in construction and agricultural markets is anticipated, although profitability will be somewhat negatively impacted by a number of routine planned outages by both OxyChem and its customers. On slide 8, is a summary of midstream segment earnings. You’ll see there were $170 million for the first quarter of 2014 compared to $68 million in the fourth quarter and $215 million in the first quarter of 2013. The 2014 sequential quarterly increase in earnings resulted mainly from higher marketing and trading performance, driven by commodity price improvements during the quarter. Higher income in the gas processing businesses which were negatively impacted by the plant turnarounds in the fourth quarter of 2013, partially offset by lower pipeline earnings which included a plant turnaround in Dolphin. The worldwide effective tax rate on core income was 40% for the first quarter of 2014 and we expect our combined worldwide tax rate in the second quarter of 2014 to remain at about 40% rate. Slide 9, summarizes our cash flow for the quarter. In the first three months of 2014, we generated $2.9 billion of cash flows from operations before changes in working capital. Working capital changes decreased our cash flow from operations by about $240 million to $2.7 billion. Capital expenditures for the first quarter of 2014 were $2.2 billion, net of partner contributions. And after paying dividends of $515 million, buying back stock of $945 million and other net flows. Our cash balance was $2.3 billion as of March 31. Our debt to capitalization ratio was 14% at the end of the quarter. Our 2014 annualized return on equity was 13%, and return on capital employed was around 11%. Lastly, I’ll turn to our guidance for the second quarter. On April 30, we closed the sale of our Hugoton assets for $1.3 billion. In the first quarter, the Hugoton operations produced 18,000 boe per day, invested $17 million in capital and contributed $46 million to our pre-tax segment earnings. For the full year, our previous domestic and capital expenditure guidance is unchanged adjusting for Hugoton. In the second quarter, excluding the Hugoton business, we expect domestic production will increase between 6,000 and 8,000 boe per day on a sequential quarterly basis. We expect oil production to grow between 7,000 and 9,000 barrels per day or approximately 3%. NGL volumes will be roughly flat with the first quarter levels and a modest decline in natural gas production resulting from continued limited drilling. Internationally, our current prices excluding Columbia and Libya, we expect total production to increase around 10,000 boe per day in the second quarter, primarily from the recovery of the Dolphin plant turnaround and activity in Oman. We expect Middle East liftings to also increase about 10,000 boe per day in the second quarter, primarily as a result of our production increases in Dolphin and Oman. I will now turn the call over to Steve Chazen, who will provide an update on our strategic initiative.
Steve Chazen:
Thank you, Cynthia. I want to focus on two topics this morning, our progress today in executing strategic initiatives we announced earlier, what our business will look like after the completion of some of these initiatives. Starting with our progress to date, we closed the sale our (inaudible) for pre-tax proceeds of just over $1.3 billion. We sold in the fourth quarter of last year about 25% of interest in Plains pipeline for pre-tax proceeds of $1.4 billion, the remainder interest in Plains is worth over $4 billion at current market prices. We continue to explore options to monetize the remaining interest in the financially efficient manner, once the restrictions on market transaction lapse. We’re continuing to explore strategic alternatives to our P-Ons (ph) assets and decided to keep our interest in the Williston Basin as they are currently more valuable to us for the true-value in the cash asset sale market. We continue to make progress in our discussions with our partners in the Middle East for the sale of a portion of our interest in the region. The separation of our California business from the rest of the company, which will be in the form of distribution of at least 80% of the company’s California stock to Oxy shareholders untracked. And the necessary work is rapidly moving forward. We expect to file initial Form 10 in June, announced California management team in the third quarter. Completion and separation of California is expected to occur in the fourth quarter of this year. We have repurchased more than 20 million of the company’s shares since the announcement of our strategic initiative in the fourth quarter of 2013, of which 10.5 million shares were purchased in the first quarter of 2014, 26.5 million shares remain in our current repurchase program which we planned to complete with the proceeds from the Hugoton sale and excess balance sheet cash. Now, discussing what the business will look like going forward. As a standalone company, which will be called California Resources Corporation, we expect our California operations with exciting growth oriented business, large resource space and self sufficient cash flow. This business will be a pure California resource company that will be able to spend virtually all its cash flow to grow its production, reserves and earnings. Currently, the California business spends about half of its capital on conventional water and steam floods and the other half on unconventional other development projects. Business is expected to initially increase its high margin, high return conventional spending such as water and steam flood investments to grow its production by 5% to 8% in the double-digit oil growth. As the floods reach their steady state in the near term, they are expected to generate significantly more cash flow, which the company expects to use the increase the amount of share of its capital spend on unconventional programs to grow its production higher rates on a sustainable basis. Business, we’re well positioned to accomplish our strategy as it generated operating cash flow before capital spending of $2.6 billion in 2013. The capital spend in 2013 was $1.7 billion and we expect to spend about $2.1 billion this year. We expect the California company will have around $5 billion of debt, proceeds from which will be distributed to Oxy, to use primarily to repurchase shares. After completion of the strategic initiatives, Oxy’s most important assets will consist of a significant leading position in the Permian Basin, round it up of the Al Hosn Project, Dolphin and a smaller business in the rest of MENA, our operations in Columbia, our midstream and chemical business and other domestic oil and gas operations. Each of these businesses supports our ability to grow our dividends for our shareholders. Further, one of Oxy’s objectives will be to grow earnings and cash flow per share and these businesses have already identified opportunities to do so. Permian resources, is the cornerstone growth operation for the domestic business. Our substantial acreage position in the Permian has a significant resource development potential. We have used our knowledge of the geology at the area and our experience to gradually shift our program towards horizontal drilling in efficient manner. We’ve already made significant progress in this process and on track to execute to shift this plant. We’re starting to see the positive results of our horizontal drilling program, plus the resources business to grow production rapidly, similar to what some other operators in the basin have been able to achieve. We believe this business could increase its production by 13% to 16% this in excess of 20% going forward. EOR business in the Permian Basin which is primarily CO2 assets along with the rest of the company’s businesses continue to be significant free cash flow generators. In 2013, excluding the California assets, Oxy generated operating cash flow $10.3 billion while spending $7.2 billion on capital expenditures. 2013 capital included $950 million spent for Al Hosn and $370 million for the combination of BridgeTex Pipeline, New Johnsonville chlor-alkali plant. We expect all three major projects to come online at various times in 2014, spurring up significant amounts of capital while starting to contribute to cash flow generation. Assuming current market conditions and similar product prices, once fully operational, these three assets should generate at least $700 million in annual operating cash flow. We expect this higher level of cash flow, coupled with significant reductions in capital needs for long lead-time projects were more than offset loss of cash flow generated by the California assets and provide a significant boost of free cash flow going forward. Our chemical midstream business will also continue to be meaningful cash flow providers in the future. The strong cash generation and combined with fewer shares outstanding, will enable us to continue to increase our dividend from the current rate of having sufficient funding to increase our investments domestic growth assets. We also expect Oxy’s remaining businesses to deliver higher returns going forward. As a result of our investments, strategic initiatives and assuming similar commodity prices, we expect to improve capital efficiency and operating cost structure to start up the Al Hosn, BridgeTex and Johnsonville plant along the separation of California business, to provide a natural uplift to our return on capital employed. In addition, we continue to execute our strategic initiatives and use proceeds from executive transactions such in the sale of (inaudible) and the monetization remaining portion of plants to repurchase our stock, which will be able to further increase our ROCE going forward. Our ROCE was 12.2% in 2013 and we expect it to rise to around 15% as we exit 2015. We have already repurchased more than 20 million of the company’s shares since the end of third quarter of 2013, we expect that we will be able to further reduce our share count by 40 million to 50 million shares through dividends in the California separation and by around 225 shares through the monetization of our remaining interest in the Plains pipeline. Coupled with the buyback of 26.5 million shares in our current repurchase program, we should be able to reduce our current share count by 90 to 100 million shares or about 12% of our currently outstanding shares. These amounts do not include the opportunity to repurchase additional shares through a sale of a portion of our interest in the Middle East or share reductions from the exchange of any remaining portion of interest in the California business. But they do reflect a modest amount of debt reduction. We are excited about the value propositions of both our California and remaining Oxy businesses, with a differentiated with focus business models, positioning both companies to maximize shareholder value. Now, I will turn the call over to Vicki Hollub to update you on our Permian activities.
Vicki Hollub:
Thank you, Steve. This morning I will update you on the activities to date in our Permian resource business, where we’re off to a good start in 2014. In the first quarter, Permian resources produced 67,000 barrels of oil equivalent per day, an increase of 5% over the fourth quarter of 2013. Capital expenditures were $328 million, was approximately 75% spent on drilling and completing company operated wells. The average 22 rigs during the quarter, of which 15 more horizontal rigs, this allowed us to drill 67 wells, including 25 horizontal. About three fourth of the 25 horizontals are currently on production. As I indicated in the last call, we have two main goals for our Permian Resources business in 2014. First, continue evaluating the potential across our full acreage position and second, pilot development strategies to optimize their ultimate returns. Today I’ll focus on the progress we made in areas where we are targeting the Wolfcamp Shale, and one where we are targeting primarily the Bone Spring. Those areas are at South Curtis Ranch and Dora Roberts Ranch in the Midland Basin, (inaudible) and the Texas Delaware Basin and South East New Mexico. These make up the core of our horizontal program thus far. Our Wolfcamp activity in the Midland Basin is focused in two operating areas, South Curtis Ranch and Dora Roberts Ranch, where we have identified about 800 drilling locations. In the Wolfcamp we brought 12 wells on production during the quarter and now have a total of 18 producing wells. Although, one of these wells are completed in the Wolfcamp B, the others completed in the Wolfcamp A, the initial production rate through averaging around 750 boe per day. While this is a good start, we believe we can improve on this result by increasing the lateral links of our wells and improving the efficiency of our fracs. The wells drilled thus far have an average lateral length of around 6,000 feet. We are piloting increase lateral links up to 10,000 feet. In addition, we have transitioned from gel fracs to slick water fracs which has improved well performance and we’ve adjusted our cluster spacing from 60 feet to 95 feet for this area. We’re also evaluating lift alternative. Today, we have primarily used gas lifts and ASPs. The ASPs averaged 1,020 boe per day initial production rate versus 680 per day for the other wells which are flowing or on gas lift. The rate benefit of the ASPs may prove to be economically equivalent to gas lift but we are closely monitoring potential impact of the reservoir. Average drill time for the horizontals was 27 days per well and total cost for drilling and completion has been averaging around $6.5 million per well. But these changes to the completions that I mentioned, initially cost may increase slightly but we expect to bring them down as we further progress the development program. While the program, and we have more to learn, we continue to be encouraged by the results that we see. We are currently drilling our first horizontal well and maybe ranch, where we hold over 9,000 acres. This is an area that we expect to have similar potential to South Curtis Ranch, which is of similar size. We’re also drilling two horizontal Sprayberry wells in South Curtis Ranch and expect to bring them up to production by the end of the second quarter. Shifting to the Wolfcamp and the Delaware Basin in Texas, we brought our first five wells on to production during the quarter and the results have been very strong. Two of the wells were completed in Wolfcamp B, one at Wolfcamp A and two in the Wolfcamp C. The initial production rate for the Wolfcamp A and B wells, averaged 1,150 boe per day. And these wells are located on our Barilla (ph) Draw area in Reeves County. Given the size of this development opportunity, we’re investing early in infrastructure, our exploitation team in Permian resources business unit have worked together to design and construct Barilla Draw water distribution project, which will provide an economic alternative to trucking water to support drilling and completion operations in Barilla Draw and the surrounding Oxy operated leases as we move into full scale development mode. The project plan includes over 50 miles of pipeline and 25 water ponds, networked together to allow Oxy to aggregate and transfer the water required to execute all operations including Zipper fracs by expediting water deliver to all of our locations. But the ability to incorporate a more efficient completion strategy, we can reduce time to market, decrease cost and accelerate to move the pad drilling operations. This project is expected to result in the 4% capital cost savings per well through reduction of water handling cost of more than 75%. And it will become the standard water handling template for future horizontal well developments. In the Delaware Basin, drilling and completion costs are averaging close to $8.5 million per well, due to the greater depth, pressure and holding stability associated with drilling the Wolfcamp C. Recently managed pressure drilling was successfully utilized to mitigate the whole problem. This technique will be evaluated for broader deployment in the other areas. We appreciate the efforts of our Permian resources business unit and the exploitation team as they have successfully ramped up our activity while continuing to efficiently manage operations and cost. In addition, they have identified several key ways to improve the performance of our wells in all areas, beginning with a switch from gel frac to slick water fracs which as I mentioned has already begun in South Curtis Ranch. We are transitioning to slick water fracs in other areas as well. In addition, we recognize that the appropriate cluster spacing is dependent on the reservoir characteristics for each area and we’re evaluating and then optimizing in all areas. Just as we have done in South Curtis Ranch, we’re also continuing to evaluate the lateral links of our wells in other areas and expect to find opportunities to continue to increase links in multiple areas. We expect these initiatives to have a positive impact on the performance of our future wells across Permian. Our most mature horizontal program is in South East New Mexico, where we began horizontal drilling at the end of 2012. We put seven new wells on production in the quarter and now have a total of 26 horizontal wells on production in this area. Of those, 17 are in Bone Spring intervals and the other nine are Brushy Canyon wells. The first and second Bone Spring wells averaged an initial production rate of 700 boe per day, three of the Brushy Canyon wells were put on EST with average initial production rates of 1,100 boe per day, and four other – others averaged 300 boe per day. Average drill time for the horizontal wells was 30 days per well and total cost for drilling and completion averaged $5.6 million. Looking forward, we expect to average 26 rigs during the second quarter and we’ll peak at 27 rigs in the third quarter of which 18 will be horizontal. For the full year, we remain on track to spend $1.6 billion and drilled approximately 340 wells. We continue to expect Permian resources to grow a total production for the year about 13% to 16%. As you can tell, there are a lot of exciting things happening in the Permian resources business, and the teams are working incredibly hard to increase our knowledge to move faster at the learning curve. I will now turn the call back to Chris Stavros.
Chris Stavros:
Thank you, Vicki. Emily, we’re now ready to pull for questions.
Operator:
Thank you. We will now begin the question-and-answer session. (Operator Instructions). And our first question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Doug Leggate – Bank of America Merrill Lynch:
Thanks, good morning everybody. Steve, I wonder if I could take a couple please. First of all, thanks for all the disclosure on the share buyback plan. But there was obviously fairly large omission from the discussion which is MENA on the differential proceeds from MENA. So, I’m wondering if you could give us an update as to where that process stands and how that may impact the buyback plan also? And then I have a follow-up on the Permian, please.
Steve Chazen:
Yes, I think we continue to make progress in it from both parties that are, or both groups or parties if you want to think of it that way, that are involved, and rather than speculate on the amount we will just say that would increase perhaps materially the share buyback program. But I think it’s not helpful at this point with the parties to speculate on what the amount might be.
Doug Leggate – Bank of America Merrill Lynch:
I understand. Could you maybe help us a little bit with the time line, because obviously, one of the things that we have talked about backwards and forwards is whether or not you would be prepared to sort of pre-fund the debt for California and buy back shares or are you going to wait until that process is complete? So, when you consider Plains as well is, this kind of an 18-month kind of time line that you are talking about for the buyback or would you be inclined to accelerate it?
Steve Chazen:
We’ll just see how the stock responds. If we see an opportunity, we could accelerate it. If not, we will wait. But you should expect continued reduction in the share count through the rest of this year, and into next year.
Doug Leggate – Bank of America Merrill Lynch:
Okay. My follow-up is really kind of related, I guess, because you’ve given us an idea what the free cash flow could look like for the residual company. And obviously, it would seem that even with this step-up in spending in the Permian, you’re still going to have substantial free cash available, especially from this business. So I guess what I’m kind of thinking are what are your plans on a go forward basis? The Permian is going to grow but would you expect the growth per share would be the kind of metric and the buybacks to become a more ratable piece or are the acquisitions in the Permian something that is still appealing to you over time? And I will leave it there. Thanks.
Steve Chazen:
Yes. On the acquisitions right now, it is really not accretive. Generally speaking, the public markets are way ahead of the cash markets. The public markets could be right and the cash markets could be wrong. But right now I don’t find acquisitions to be particularly interesting and we’re not doing anything that is dilutive. So I think as far as acquisitions, I think that’s unlikely. As we look forward, in our cash flow, we expect our earnings per share, fees starting with the current levels, to continue to grow. We hope it will grow this year, and we expect it to grow going forward. We expect our cash flow per share, if you want to use that metric, to continue to grow and we expect the dividends to grow. Share repurchase, I think for the next several years, I doubt if the company will need to do a large scale, any kind of major acquisitions. I mean there are always little pieces to be picked up. But I think the company will continue to use the cash flow to grow dividends where it’s predictable cash flow growth and to repurchase shares where it is less predictable. Some modest debt reduction to go with the smaller scale of business. But that’s – I think what people should expect, they should expect better earnings, better returns on invested capital, they should expect some continued reduction in the share count, at a modest, more modest rate after this process is done and growing dividends.
Doug Leggate – Bank of America Merrill Lynch:
I appreciate that. Thanks, Steve.
Operator:
Our next question is from Paul Sankey of Wolfe Research. Please go ahead.
Paul Sankey – Wolfe Research:
Good morning, everyone. Thanks for making the effort to get on the call all of you. Steve, could you just talk a little bit more about the decision to pull the Bakken sale, the process around that and what your plans are for that business going forward? Thanks.
Steve Chazen:
Yes, we’re not doing wealth destructive divestitures. So, if we got a price that was sort of comparable the way we trade, I think that’s one thing. But the cash market is just simply not that strong right now. And so our plan, it makes around 20,000 a day of production. We restarted our development program. And so, I think it will grow modestly over the next year or two. We don’t have – and we’ll just see what the markets give us going forward. I’m sort of – we could either grow it or we could divest, but right now, the cash just doesn’t get the kind of proceeds that we think are intrinsic in the business.
Paul Sankey – Wolfe Research:
Could you remind us why you wanted to sell it?
Steve Chazen:
The scale. It is 20,000 a day, the scale was below what we’ve been wanting. We probably need about a 40,000 or 50,000 a day business. The business has actually done better on an operational perspective over the last year, than it had done historically. And so I think its sub optimal scale. Perhaps at some point in the future there might be an opportunity to merge it in with somebody else. But right now, I think we’ll just keep it there. It’s not doing any – it may be doing some modest good, and not doing any harm right now.
Paul Sankey – Wolfe Research:
I guess the obvious follow-up is that if you’re not seeing the right prices to sell stuff, wouldn’t you want to buy stuff there to get up your scale?
Steve Chazen:
If there was stuff at the same price. The market is not – it’s not a robust market. And so the companies trade for much more than relative basis than people offered us for the asset. So, what they were trying to do is do accretive acquisitions for their company I’m sure but with multiple differences – difference.
Paul Sankey – Wolfe Research:
Yes. And then just to finish up on that and that will be it for me on slide 11, just to finish up on that particular paragraph, could you talk a little bit more about the P-Ons, as well because it’s this does explore strategic alternatives. I wonder what is worth and I’ll leave it there? Thank you.
Steve Chazen:
Yes, on the P-Ons, we’re in discussions with a private party to create a joint venture. They have a fair amount of interest in the P-Ons, we have a fair amount of the current plan as to put them together, run them as a private business for a while and then at some point in the future they would have enough scale to go public.
Paul Sankey – Wolfe Research:
Thank you.
Operator:
Our next question is from Leo Mariani of RBC. Please go ahead.
Leo Mariani – RBC:
I just wanted to follow-up a little bit on some of these asset sales. I appreciate some of the color here but could you give us a little bit more color potentially on timing of sort of the rest of the Plains GP, when you think that might exit the portfolio? A and then I guess I think there were maybe some other small U.S. non-core assets, wasn’t sure if you guys were still selling some other little things here that might be off the table as well?
Steve Chazen:
There is always small things for sale but nothing that’s moved the needle a lot. The Plains thing, I think it expires at the end of the year, toward the end of the year, and we will be looking to see what we can do early next year.
Leo Mariani – RBC:
Okay. And I guess just in terms of the Permian, you guys are creeping up the horizontal rig count, 17 now, it is like going to 18, I think you said, another quarter or two. And can you just give us maybe a better sense of where maybe that could get to you over the next couple of years? Do you have kind of a multi-year kind of rig ramp planned on the horizontal side in the Permian, any color on that would be appreciated?
Steve Chazen:
Vicki would be glad to talk about that.
Vicki Hollub:
We expect to double our rig count from this year, and two years, to double, so going from the 23 peak that we will have this year to possibly 46 in 2016. For horizontal rigs, this year, as you know, as you just said, in Q3, we will be going to 18 horizontal rigs and expect to end the year, this year with about 21 horizontal rigs. We’ll increase that from the end of the year 21, going up toward 2016. We don’t have an exact number as to what the horizontal rig count will be of that total but we expect it to be about double.
Leo Mariani – RBC:
Okay, that’s helpful. And I guess you guys specifically kind of highlighted this Barilla Draw acreage here in your slide. I just want to get a sense of kind of how much acreage that is in total and maybe you could just talk a little bit more about sort of the areas of the Midland that you think are kind of the most prospective in terms of the total acreage size there?
Vicki Hollub:
In the Texas Delaware, I can talk about basically what we expect our well potential to be. It’s going to be in that area, we expect to drill over 1,000 Wolfcamp wells, depending on the productivity of some of the benches that we have yet to test. So this is, the over 1,000 is based on the benches that we feel pretty comfortable with today. That would be in that Barilla Draw area plus the surrounding acreage. So, that would be for all of Texas Delaware.
Leo Mariani – RBC:
All right. And I guess just also, similar question on the Midland, you highlighted a number of kind of small kind of acreage parcels here, sort of in largely Martland and Midland and some in hector. Just want to get a sense that there is kind of, an acreage number that you guys could kind of throw out there in the Midland in terms of what you think is kind of the high graded stuff that’s most prospective for horizontal drilling?
Vicki Hollub:
In the Midland Basin, we expect that the acreage that we have listed there for the three areas that we show, we expect our prospective acreage to be about that, for the Midland Basin from what we know today, from the appraisal work that we are currently doing.
Leo Mariani – RBC:
Okay. Thanks, that’s helpful.
Operator:
Our next question is from Roger Read of Wells Fargo. Please go ahead.
Roger Read – Wells Fargo:
Good morning.
Steve Chazen:
Good morning.
Roger Read – Wells Fargo:
A lot of this stuff has been hit. If we could talk a little bit about the share repurchase pace again, you’ve mentioned several times where there is flexibility in terms of the pace of share repo. Maybe give us an idea assuming California goes out, on the schedule, you expect, the way you think about it, is it stock price driven. Is it cash flow on hand? Is it combination of the two and getting back to the earlier question about would you be willing to put the balance sheet to work here?
Steve Chazen:
It’s stock price driven.
Roger Read – Wells Fargo:
Just that simple?
Steve Chazen:
That simple.
Roger Read – Wells Fargo:
Okay. Well, that’s helpful. And then in the Permian, obviously, I understand everything going on in the spending front here, could you talk a little bit about the infrastructure you need. We’ve heard from various sources that some of the challenges are more in the gathering systems than in the trunk line systems. Kind of how you’re addressing that issue?
Steve Chazen:
Maybe, we’ll let Willie, to talk about – we’re a large gatherer in the basin. Maybe we could talk a little bit about our gathering system in the Permian.
Willie Chiang:
Sure. We really haven’t had too much problems in getting the gathering done. The big challenge, as you’ve seen is really the trunk lines which we think is going to resolve itself here with the startup of our BridgeTex pipeline later this quarter, early third quarter. So, from the infrastructure piece on gathering.
Roger Read – Wells Fargo:
Okay, well, I guess one of the questions along that along is if you are having issues with crude versus condensate versus gas handling, and then maybe what your spending will do on that front, and are we going up in concert with the rig count, or something more or less?
Willie Chiang:
Yes, we may be looking at some more gas processing facilities, but on the natural gas side, we feel it’s adequate.
Steve Chazen:
We’ve got a big gathering system, so we will probably have more flexibility maybe than somebody who doesn’t have their own gathering system. Willie, how many miles of gathering system do you have, roughly?
Willie Chiang:
We’ve got close to 3,000 miles of pipe, for the Permian.
Steve Chazen:
Permian. So, we’re a big gatherer not just of our own but other people’s crude and we may have more flexibility than maybe some of the smaller producers.
Roger Read – Wells Fargo:
Okay. Thank you.
Operator:
Our next question is from Sven Del Pozzo of IHS. Please go ahead.
Sven Del Pozzo – IHS:
Yes, hello. Wanted to – what’s your take on macro forecast for California gas because we’re – and I know you guys have those fields you bought from Benaco Rosetta. So you must be one of the biggest, potentially have the biggest fields for gas. And also those older discoveries you had, I don’t know, 6, 7 years ago that were gas and condensate, that I’m not sure if you got around to developing them because gas prices were not strong enough. So, what is your take on the local gas market in California and how you might use your gas assets to take advantage of that?
Steve Chazen:
Right now we have a lot of gas potential in the state. We could increase our gas production substantially. Right now, the oil drilling has got significantly better margins, and significantly better returns. If that changes, gas prices go up some more, some of our stuff I’m sure is economic in the 4.00, 4.50 area but just not as economic as $100 oil. And so, I think right now, we’ll keep our gas drilling modest in California, but clearly, when a California company is separate, they could take a different view of this and maybe have somewhat different return standards than we do.
Sven Del Pozzo – IHS:
All right. So then the gas production drop we saw in California sequentially from the fourth quarter to the first quarter is that – what kind of a decline is that? Could you consider that a base decline or you said it is going to flatten out now in the second quarter. So, I’m just trying to get a feel of how those – what the legacy decline rate of those gas assets might be, if you stop drilling?
Steve Chazen:
Yes. We’re pretty much stopped. So, Vicki can answer the rest of it.
Vicki Hollub:
Some of the decline of our gas assets was in excess of 25%, and that’s why we made the switch to move to more towards some of our conventional EOR projects and water floods. We’ve had some gas declines that were actually greater than 30% as well. So we’re trying to lower that decline and we’ve now been able to lower the decline of Elk Hills over the past few years by switching more towards our heavier liquids drilling and development.
Sven Del Pozzo – IHS:
Well, thank you. And then, one last question. When you mentioned the Permian unit, if I’m correct and repeating what you said, I think you said you spend about 1.6 billion to drill and complete about 340 wells. Was that a gross number, that’s in 2014, was that a gross number and if so, could we get a net number?
Vicki Hollub:
Currently, the number of wells is a gross number, and the capital is a net number. We don’t quite have here in front of us the net number on the wells.
Sven Del Pozzo – IHS:
And the gross number doesn’t include the third party wells?
Vicki Hollub:
Right.
Sven Del Pozzo – IHS:
Gross operated?
Steve Chazen:
Yes, those are gross operated and the capital is sort of a mix. And but it doesn’t include the non-operated wells because we don’t know what that will be.
Sven Del Pozzo – IHS:
Okay. All right, all right. Thank you.
Operator:
Our next question is from Ed Westlake of Credit Suisse. Please go ahead.
Ed Westlake – Credit Suisse:
Hi, yes, good morning. Yes, I just wanted to get a little bit more color on how you see the Permian developing. You’ve given us some extra disclosure on the Midlands. You got 40,000 acres there, plus you say you could double or 80,000. You’ve given us a 1,000 locations as the number for Barilla (ph) Draw. And then you got this large sort of acreage position in New Mexico. I guess the concern people have is that as you accelerate the rig counts, you guys don’t have as much inventory as some of the say pure plays in the region. So I’m just trying to get a sense of where, apart from what you’ve disclosed today we should be thinking would be the growth area in your existing organic portfolio? Vicki can answer that, I think better than I can, but we’ve disclosed how many acres we have that’s prospective and we just highlighted the areas in this call that are going to affect the production over the next 2 or 3 quarters. It wasn’t intended as what might be there for the next 20 years. But I think Vicki can probably answer better than I can.
Vicki Hollub:
Yes, we have close to 2 million in prospective acres in our Permian resources business unit and currently we’ve identified over 4,400 well locations to drill. So we’re not short on inventory yet because we’re still in the process of evaluating some of the other benches, too. So, we expect the well location number to go up with time.
Ed Westlake – Credit Suisse:
And I guess that, just to be clear again, that 4,400 or 4,500, that’s the net locations operated or what’s the definition of that? So we can compare that apples with apples.
Vicki Hollub:
That’s the gross operated well locations.
Ed Westlake – Credit Suisse:
Okay. So, that would compare with the 340, sort of give about 13 year inventory.
Vicki Hollub:
Yes, that’s correct.
Ed Westlake – Credit Suisse:
Right. And so, I guess, I’m trying to think about what’s the upside to that in terms of what percentage of the acreage you have drilled out as you think about that sort of 4,500 acres?
Vicki Hollub:
I think the important thing to remember for us is that with wells, horizontal wells we’ve drilled to date, we’ve really only drilled about 1% of our potential. So if you look at these kind of plays, normally that well count goes up significantly over time as you get to the other benches to appraise those. So, I think our estimate right now is conservative based on what we have available to evaluate and expect that number to continue go up as we learn more.
Ed Westlake – Credit Suisse:
Okay, great. And then, specific question on Barilla Draw. I mean, you’ve got 88% liquids, just a sense of how much of that NGLs and how much of that is condensate. IPs are looking good but just trying to get a sense of the liquid mix? Thank you.
Vicki Hollub:
72% of that is oil.
Ed Westlake – Credit Suisse:
And do you know the API of the oil, is it?
Vicki Hollub:
I think it’s in the 30% to 35% range.
Ed Westlake – Credit Suisse:
Okay, good. Thank you very much.
Operator:
Our next question is from Pavel Molchanov of Raymond James. Please go ahead.
Pavel Molchanov – Raymond James:
Thanks for taking the question. Steve, we saw in the last several months, City of Carson, LA County, a few other jurisdictions in California have been putting up proposals, anti-fracking, some cases, anti-drilling?
Steve Chazen:
No LA County. So, it’s a City of Los Angeles.
Pavel Molchanov – Raymond James:
Okay, City of Los Angeles. So, your talks on the trends, if there were trends?
Steve Chazen:
Well, I think it’s a fair way to describe that it’s basically supposedly regulated by the State of California, that’s where the laws were setup in California, not regulated by every town. To the extent that towns don’t want us there, we won’t be there. We’ve got lots of acreage in California, there is lots of counties and towns that would like us there, want the jobs. Some of these places that don’t want us have very high unemployment rates. And if they don’t want us there, it’s just fine. So far, these areas are not significant portions of our total position in California. They’re some relatively small positions, they’re being stirred up by people who don’t like oil and gas. And so, I think one of the California company is up and running, one of their major tasks will be to – and major focus would be on dealing with political issues in California. But noise, is sort of what California produces, the political guy wants to talk about fracking or something, that’s certainly no one you think about it. And just for the completeness, I think the Beverley Hills City Council voted of our fracking within the borders of the City of Beverley Hills. Now, initially I thought I misunderstood what they were saying and then they were kind of outlaw their most important export product. But actually I don’t – there are wells that have been proposed to be fracking in the wells or they were, I think there is one field there that’s been there for about 50 years. These are – they’re just politicians trying to make some good statement, maybe to people in Beverly Hills that parked their Rolls Royce’s and drive bicycle going forward.
Pavel Molchanov – Raymond James:
Good. And just one more quick one in California. When you referred to the $5 billion?
Steve Chazen:
You can see why I’m not going to be part of the California Company.
Pavel Molchanov – Raymond James:
I understood. When you referred to the $5 million of funded debt in the income, is that effectively going to be structured as a dividend $5 billion dividend to the parent?
Steve Chazen:
Yes.
Pavel Molchanov – Raymond James:
Okay, appreciate it.
Steve Chazen:
Thank you.
Operator:
Our next question is from John Harlan of Societe Generale. Please go ahead.
John Harlan – Societe Generale:
Yes, thanks. Some quick ones, how much in the Permian, how much incremental costs are the ASPs for you?
Steve Chazen:
Obviously, I’m not going to answer that one, so Vicki is going to answer it.
Vicki Hollub:
I’m going to just be honest, I’ll have to take a guess on this. I haven’t looked specifically at that number recently. But I believed it would be about $35,000 to $40,000 incremental over the gas lift, it could be a little bit more than that.
John Harlan – Societe Generale:
Okay. Steve, when you were in New York, you said that you thought you were top cortile in terms of your drilling and completion work in the unconventional Permian is that improving at all with subsequent wells drilled?
Steve Chazen:
Yes, I think so. But I think we’ll stay with the top cortile for now. We’ve got more to do. I think that things are getting better, our overall costs we didn’t say it actually, overall cost of the company are 9% better than the comparable wells drilled from last year and so far this year. So, I think we’re getting better. But we’ve still got more to do, more cost to be saved, better completion techniques, I think Vicki has been pretty forth right about, what she wants to accomplish in that. So, I think there is more to do, just good, it will never improve, continuous improvement that will never end.
John Harlan – Societe Generale:
Great. Last one from me is, the dividend for Oxy remain curve, are you going to hold it flat or go down a little bit for the spin curve?
Steve Chazen:
No, it’ll go up, it’ll go up.
John Harlan – Societe Generale:
Okay.
Steve Chazen:
The dividends, the way this thing is set up, there is a dividend from the post California company, company will be able to increase its dividends at a reasonable pace going forward. And the goal is not to have it reduce its dividend or hold it flat like some others have done, people should expect the same kind of increases, the percentages maybe different but the same kind of increases that they’ve enjoyed in the past.
John Harlan – Societe Generale:
Okay. Last one from me is on Fibro, are you going to monetize that or what’s the story?
Steve Chazen:
Yes, they are out, we would like to buy it. I think it’s available. So, their outlook talking to investors who want to do the credit support for Fibro. But in any case, their book is declining over the next couple of quarters.
John Harlan – Societe Generale:
Okay, thank you.
Steve Chazen:
Thanks.
Operator:
That concludes our question-and-answer session. I’d like to turn the conference back over to Chris Stavros for any closing remarks.
Chris Stavros:
Thanks for joining us on the call today. And please give us a call in New York if you have any further questions. Thanks.
Steve Chazen:
Thanks.
Operator:
The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.