Jay Wilson:

Thank you, Kevin. Good morning, everyone and thank you for participating in our second quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I'll now turn the call over to John Hess.

Greg Hill:

Thanks, John. In the second quarter, we demonstrated strong operational performance across our portfolio. Company-wide net production averaged 387,000 barrels of oil equivalent per day, well above our guidance of approximately 355,000 to 365,000 barrels of oil equivalent per day. In the third quarter, we expect company-wide net production to average approximately 385,000 barrels of oil equivalent per day, reflecting planned maintenance and hurricane contingency in the Gulf of Mexico. For the full year 2023, we now expect company-wide net production to average between 385,000 and 390,000 barrels of oil equivalent per day, up from our previous guidance of 365,000 to 375,000 barrels of oil equivalent per day, primarily reflecting our strong performance in the first half of 2023 and the expected startup of the Payara development in Guyana early in the fourth quarter. Turning to the Bakken. Second quarter net production of 181,000 barrels of oil equivalent per day was above our guidance of 165,000 to 170,000 barrels of oil equivalent per day, with approximately half of the increase due to strong operational performance and the remainder from higher production entitlements under our percentage of proceeds contracts as a result of lower NGL prices. In the second quarter, we drilled 32 wells and brought 30 new wells online. In the third quarter, we expect to drill approximately 27 new wells and bring online approximately 30 new wells. For the full year 2023, we expect to drill and bring online approximately 110 new wells. Individual well results in terms of IP180s and EURs continue to meet or exceed expectations. For the third quarter, we expect Bakken net production to average approximately 185,000 barrels of oil equivalent per day. And for the full year 2023, we have increased our forecast of net production to between 175,000 and 180,000 barrels of oil equivalent per day, up from our previous guidance of 165,000 to 170,000 barrels of oil equivalent per day. Moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 32,000 barrels of oil equivalent per day. In the third quarter, we expect net production to average approximately 25,000 barrels of oil equivalent per day, reflecting planned maintenance downtime and hurricane contingency. For the full year 2023, we continue to forecast Gulf of Mexico net production to average approximately 30,000 barrels of oil equivalent per day. We are excited to announce that the first well of our 2023 Gulf of Mexico drilling program has resulted in an oil discovery. The Hess operated Pickerel-1 infrastructure-led exploration well in Mississippi Canyon, encountered approximately 90-feet of net pay and high-quality oil-bearing Miocene-aged reservoir. Long lead construction activities are underway to tie the well back to the Tubular Bells production facility, with production expected to commence in mid-2024. Following Pickerel, we plan to drill the Black Pearl development well in which Hess is the operator and has a 25% working interest and Chevron, CNOC and Equinor each have 25%. This well is planned as a tieback to the Stampede Production Facility. Following Black Pearl, we plan to drill the Vancouver prospect located in Green Canyon Block 287. Vancouver is a large hub class exploration prospect, targeting subsalt Miocene-age reservoir. Hess is the operator and has 40% working interest and Shell and Chevron each have 30%. In Southeast Asia, second quarter net production averaged 64,000 barrels of oil equivalent per day. For the third quarter and full year of 2023, we forecast net production to average approximately 65,000 barrels of oil equivalent per day. In Guyana, where Hess has a 30% interest in the Stabroek Block, second quarter net production averaged 110,000 barrels of oil per day at the high end of our guidance range of 105,000 to 110,000 barrels of oil per day, driven by strong facility uptime and well performance. For the third quarter, net production from Guyana is expected to also average approximately 110,000 barrels of oil per day. We now expect full year 2023 net production to average approximately 115,000 barrels of oil per day compared to our previous guidance range of 105,000 to 110,000 barrels of oil per day, reflecting the expected early fourth quarter start-up of Payara, with a gross production capacity of approximately 220,000 barrels of oil per day. We forecast Payara to contribute approximately 15,000 net barrels of oil per day in the fourth quarter. Turning to our fourth development, Yellowtail. The overall project is approximately 60% complete and remains on track for first oil in 2025, with a gross production capacity of approximately 250,000 barrels of oil per day. The fifth development, Uaru, was sanctioned in April. Uaru will develop more than 800 million barrels of oil from the Uaru, Mako and Snook fields. The FPSO will have a gross production capacity of approximately 250,000 barrels of oil per day and is on track to achieve first oil in 2026. With regard to our sixth development, Whiptail, the partnership anticipates submitting a plan of development to the government of Guyana in the fourth quarter, with first oil targeted for 2027. Now turning to exploration. In Guyana, the Stabroek Block exploration license was formally extended by 1 year to October 2027 due to the COVID-19 pandemic. The extension also pushes out the contractual acreage relinquishment by 1 year to October 2024. In the Fangtooth area, drill stem tests and core analysis are ongoing. Moving forward, we plan to drill the Bacher-1 well which is a deep prospect located approximately 7 miles west of Fangtooth-1 and the Lancetfish-1 well, located approximately 2 miles southwest of Fangtooth-1. We also plan to drill the Lancetfish-2 appraisal well also in the Fangtooth area. Exploration and appraisal activities are also planned in the southeastern portion of the block to better understand the longer-term potential of this area. Activities will include drilling and exploration prospect called Blue Fin, located approximately 6 miles southwest of Himara-1. In closing, we achieved strong operational performance in the quarter. The Bakken is on a steady growth trajectory. We had exploration success in the Gulf of Mexico with more drilling planned. Our Southeast Asia assets continued to deliver steady production through high reliability and successful ongoing drilling programs. And Guyana keeps getting bigger and better, all of which position us to deliver significant shareholder value for years to come. I will now turn the call over to John Reilly.

Operator:

[Operator Instructions] Our first question comes from Doug Leggate with Bank of America.

Greg Hill:

Yes. So thanks for that question, Doug. Yes, as we mentioned it's coming on early in the fourth quarter and I would expect the ramp-up to be like Liza Phase 2 kind of on the order of 5 months or so in terms of ramp Payara is a little bit bigger, so it might take marginally a little bit longer but I would say 5 months, yes.

Greg Hill:

Yes, I think there will be because there is a lot of discovered resource in and around Payara. So there will definitely be a debottlenecking strategy as well.

John Hess:

Sure. Doug. It's John and thanks for the question. Look, we have a very active exploration appraisal program this year on the Stabroek Block. A lot of it in terms of appraisal, especially in the Fangtooth area. Greg addressed that in his remarks. And other appraisal on the block, some exploration on the block. And I think the real takeaway, Doug, is that we still see multibillion barrels of oil equivalent. And at the appropriate time, we'll consider increasing the resource estimate of greater than 11 billion barrels of oil equivalent.

John Hess:

Doug, that line continues to get upgraded. And I would say, it's the overall program and there's still more to be recognized from some of the outstanding wells we drilled. As you know, a lot of evaluation work is underway in an area like Fangtooth. And until we get that evaluation work done, including the drill stem test, production tests, it's a little premature to jump that number until we're ready to give more clarity on it.

Arun Jayaram:

Greg, I was wondering if you could give us maybe an update on how the debottlenecking efforts are going at Liza 1 and Liza 2. Are there any other projects scheduled for the back half of the year? And give us a sense of where you think the new plateau level of production is for both facilities in the post debottlenecking?

Arun Jayaram:

Great, that's helpful. And maybe one for John Rielly. John, I was wondering if you could maybe offer some soft CapEx guidance for 2024, including kind of an expectation that you do kind of purchase the FPSO and you obviously announced the discovery now at Pickerel.

Operator:

Our next question comes from Paul Cheng with Scotiabank.

John Rielly:

Yes. So we have Guyana, obviously, the ramp going there, getting Payara online. And look, we managed just the progression of the developments there. So we'll be working on Yellowtail. There's obviously working on Uaru. So you just got -- the back half of the year, you've got more spend coming in Guyana. Then also, what we have is the Gulf of Mexico rig. So as Greg mentioned, we have -- that rig came in right at the tail end of Q2 and so it drilled Pickerel. We had the success there. And as Greg mentioned, it's going to be doing Black Pearl and then Vancouver. So again, that's tilted towards the second half of the year. And the only other thing I would add on that and this was expected, is that the weather window up in North Dakota, this is the best time for some of the facilities to work up there. So that's why we get a little bit more in the back half in the Bakken as well.

John Rielly:

Paul, I think we are just going to keep reiterating the $3.7 billion. The execution has been terrific so far, as you can see on the production side and we've been very efficient on the capital side. But we do have plans to spend that full $3.7 billion. So I would look just to keep the capital at that level in your model.

John Rielly:

Let me start with that 1-year payment. No, there was no payment. That was really, as Greg had mentioned earlier, due to COVID-19 and the force majeure us not being able to explore during that period. So that just is extended to one year. As far as the deferred taxes which are always a bit difficult to actually the forecast, you are right, it was approximately $45 million in Q2. It was about $36 million in Q1. I would say, from our forecast and what we're looking and you've got the Payara start-up which makes it even harder to forecast, that it will be a little bit higher than that $45million number you mentioned in Q3 and Q4 on the deferred taxes.

Ryan Todd:

Maybe just one follow-up on the extensions there in Guyana. And congrats on getting the extension for both the acreage relinquishment and the exploration license. I know you had always said that this was going to be easily managed and now have a huge impact. But does the extension have any impact on how you may allocate resource there over the next few years or, in general, on your approach or what you're able to do there in the basin?

John Hess:

Yes. To be clear, each year, we plan to drill 10 to 12 exploration appraisal wells. So it just gives us another year to have further evaluation, then it will be in the best interest of the country and also our joint venture itself. So we have, as I said before and Greg did as well, multibillion barrels of exploration potential remaining. And we can orderly have a prosecution of that opportunity.

Greg Hill:

Yes. So let me address both the onshore and the offshore. So in the Bakken, we observed inflation of between 10% to 15% blended in the first half of 2023. And we were able to mitigate about half of that through the application of strategic contracting, lean manufacturing and technology. Now we're starting to see some costs, such as oil country, tubular goods beginning to moderate. We're still maintaining our well cost guidance at $6.9 per well because we're increasing proppant loading in several areas of the field to further maximize the issue NPV. So we're just going to stick with our 6.9%. But again, we are seeing some deflation start to occur in the Bakken. If we go in the offshore, rig utilization remains very high in the offshore, so costs have not moderated there. However, most of our spend is in Guyana were the first 5 FPSOs are contracted. ExxonMobil was doing a great job of mitigating inflationary effects using its Design One, Build Many strategy. And in addition, recall for our 2023 Gulf of Mexico program, most services were contracted in 2022 when costs were lower. So long and short, our overall 2023 capital guidance of $3.7 billion remains unchanged and we'll provide 2024 guidance in our January call, as John Rielly said.

Neil Mehta:

Yes. It was a strong quarter in the Bakken, recognizing that volume can be noisy with commodity prices. But just curious on your thoughts on getting to that 200,000 barrels a day of plateau. And is there visibility to pull that forward if you continue on this execution track?

Neil Mehta:

All right. The follow-up is just around -- it's a couple of cash flow items. First is around return of capital. What's the framework for increasing that as you continue to progress through the program in Guyana? And the second, is there any update on hedging strategies as we look into 2024?

Neil Mehta:

Great. And on hedging?

Operator:

Our next question comes from Roger Read with Wells Fargo.

Greg Hill:

No. The wells are performing better than expected, really across the board. And of course, the capacity is driven by the physical constraints on the vessel. But obviously, with those wells outperforming, we want to increase that capacity view as high as possible through debottlenecking. But the wells are doing fantastic.

Greg Hill:

Yes, absolutely. I think there's 2 things that really have been the discontinuity, I'll call it, in the last 5 years in exploration in the Gulf of Mexico. And the first one is ocean bottom nodes. So we are shooting ocean bottom node surveys in and around all of our hubs. And that is coupled -- that coupled with the new algorithms, so Full Waveform Inversion, FWI, the combination of those 2 things are allowing us to see new opportunities in subsalt in the Gulf of Mexico. And that's not only true for in and around our hubs but it's also true for hub class opportunities as well; so very exciting. We've got over 80 blocks in the Gulf of Mexico. And with that inventory, our aim is to maintain that cash engine in the Gulf of Mexico at a minimum, hold production broadly flat but then also potentially grow that production with a hub class success. And those seismic improvements that I talked about are leading that charge with the great portfolio that we have.

Kevin MacCurdy:

Just one question on the Bakken production guidance raise. Gas and NGL has obviously outpaced your quarterly guidance but you also had strong oil production above our expectations. Is there any color you can provide on how much of the guidance raise was oil versus gas and NGLs?

Operator:

Our next question comes from Biju Perincheril with Susquehanna Financial Group.

Greg Hill:

Yes. So I think the thing I will say is that every vessel will be bespoke. So the way that we do this debottlenecking is we produce the vessel for a year or so and then get all of the dynamic data. And then from that data, make a decision on how much we think that we can squeeze more out of the vessel, or do an engineering project to further debottleneck that. But I think the bias will be to debottleneck these vessels as much as we can because there is so much additional resource around each one of these hubs. And that, coupled with the multibillion barrels of additional upside says that these vessels are going to be full, at plateau longer than what would be typical for a deepwater development. And -- but again, each one will be bespoke. So -- but certainly, the bias is going to be there to debottleneck as much as possible.

Greg Hill:

Yes. So longer term, when we're at that 200,000 barrels a day, you can expect about 100,000 barrels a day of oil. So about 50%.

Noel Parks:

You made a mention in the Guyana discussion about just putting resources into more exploration of the Southwestern part of the block. I wonder if you could just sort of refresh us on sort of what the original view of that geology was. And now with benefit of the incremental drilling of what you hope to discover or discern there.

Noel Parks:

Great. And I appreciate your comments just a minute ago about seismic improvement and the opportunity in the Gulf of Mexico. I was just wondering whether there were any projects that Hess is participating in on a non-operated basis in the Gulf? Whether -- I was wondering if there were any of those sort of under the radar that might be worth mentioning?

Noel Parks:

Are those sort of near term or more sort of on the horizon?

Operator:

Our next question comes from Paul Cheng with Scotiabank.

Greg Hill:

Sure, Paul. So that we're still evaluating the well results. But we anticipate peak gross production rates to be in the range of 8,000 to 10,000 barrels a day.

Greg Hill:

Yes. And that -- as we said, that will be tied back to the Tubular Bells facility kind of midyear next year.

John Rielly:

Again, we are still overall coming -- evaluating the results of the well. One, I can tell you, it's a very high-return project, obviously, with it being a tieback to Tubular Bells. And typically, these type of tieback wells are going to have like a $10 per barrel kind of costs or lower. That's what we'll typically see in those -- in these tieback wells.

Paul Cheng:

Right. And Greg, what's the resource -- recoverable resource that we estimate for this? And is it all oil or that is the mix between oil and gas?

Paul Cheng:

Okay. And final one from me. Yellowtail and Uaru, you're talking about 2025, 2026, should we assume you're somewhat like similar to the Payara, is going to be in the early fourth quarter?

Paul Cheng:

Okay. And on the Gulf of Mexico, second quarter production is better. Is it because that some of the maintenance downtime has been able to perform at a shorter period? Or that something is actually being pushed to the third quarter?

Operator:

Our next question comes from Phillips Johnston with Capital One Securities.

John Rielly:

So let me just start high level that we remain committed to maximizing the long-term value of Hess Midstream. It's adding differentiated value to our Bakken E&P assets. And part of it is allowing Hess to maintain operational control which we can for -- even with a much lower ownership percentage. So nothing to worry about there from that, Phil. Then what it also does, it provides takeaway optionality to high-value markets. And also, it's that ability to increase our gas capture to drive down flaring in our GHG emissions intensity. So -- and as you know, we've set a zero routine flaring goal by 2025. So the one other thing about it, to your point but with a strong credit position and its continuing free cash flow growth, Hess Midstream has said they continue to have greater than $1 billion of financial flexibility through 2025 to support potential incremental share repurchases. Similar to the ones that we've done this year, we had 2 $100 million gross transactions executed in March and June. So you should expect some more of those with that financial flexibility.

Jay Wilson:

Thank you, Kevin. Good morning, everyone, and thank you for participating in our first quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I'll now turn the call over to John Hess.

Greg Hill :

Thanks, John. We demonstrated strong operational performance across our portfolio in the first quarter. Company-wide net production averaged 374,000 barrels of oil equivalent per day, above our guidance of approximately 345,000 to 355,000 barrels of oil equivalent per day. For the second quarter, we forecast the company-wide net production will average between 355,000 and 365,000 barrels of oil equivalent per day, reflecting planned maintenance activities at Liza Phase 2 in Guyana, several of our Gulf of Mexico fields and at North Malay Basin in Southeast Asia. For the full year 2023, we now expect company-wide net production to average between 365,000 and 375,000 barrels of oil equivalent per day, an increase from our previous guidance of 355,000 to 365,000 barrels of oil equivalent per day due to strong performance in the first quarter of 2023. In the Bakken, first quarter net production of 163,000 barrels of oil equivalent per day was above our guidance of 155,000 to 160,000 barrels of oil equivalent per day, reflecting high uptime and strong recovery from challenging weather conditions this winter. In the first quarter, we drilled 25 wells and brought 24 new wells online. In the second quarter, we expect to drill and bring online approximately 27 new wells. For the full year 2023, we expect to drill and bring online approximately 110 new wells. Individual well results in terms of EURs and IP 180s continue to meet or exceed expectations. For both the second quarter and full year 2023, we expect Bakken net production to average between 165,000 and 170,000 barrels of oil equivalent per day. Moving to the offshore. In the Deepwater Gulf of Mexico, first quarter net production averaged 33,000 barrels of oil equivalent per day, above our guidance of approximately 30,000 barrels of oil equivalent per day, primarily reflecting better uptime. In the second quarter, we expect net production to average approximately 25,000 barrels of oil equivalent per day, reflecting planned maintenance at several of our Gulf of Mexico fields. For the full year 2023, we continue to forecast Gulf of Mexico net production to average approximately 30,000 barrels of oil equivalent per day. The Deepwater Gulf of Mexico remains an important cash engine for the company as well as a platform for growth. In May, we plan to spud the Pickerel 1 well located in Mississippi Canyon Block 727. Pickerel is an infrastructure-led exploration prospect, which will be tied back to Tubular Bells. Following Pickerel, we plan to drill another tieback well at Stampede and a hub class exploration well in the Green Canyon area. In Southeast Asia, first quarter net production averaged 66,000 barrels of oil equivalent per day. Second quarter net production is forecast to average approximately 60,000 barrels of oil equivalent per day, reflecting planned maintenance at North Malay Basin. Full year net production for Southeast Asia in 2023 is now forecast to average approximately 65,000 barrels of oil equivalent per day compared with our previous guidance of 60,000 to 65,000 barrels of oil equivalent per day. In Guyana, where Hess has a 30% interest in the Stabroek Block, the operator ExxonMobil continues to deliver outstanding facilities reliability and project execution success. First quarter net production averaged 112,000 barrels of oil per day above our guidance of approximately 100,000 barrels of oil per day, primarily driven by strong facility uptime and well performance. For the second quarter, net production from Guyana is expected to average between 105,000 and 110,000 barrels of oil per day, reflecting reduced capacity at Liza Phase 2 for planned maintenance. We now expect full year 2023 net production, the average between 105,000 and 110,000 barrels of oil per day compared to our previous guidance of approximately 100, 000 barrels of oil per day. Turning to Guyana developments. The Prosperity FPSO, with a production capacity of approximately 220,000 gross barrels of oil per day, arrived at the Stabroek Block on April 11. The vessel is undergoing hookup and commissioning and is targeted to achieve first oil from Payara, our third development early in the fourth quarter. Yellowtail, our fourth development is approximately 45% complete and remains on track for first oil in 2025. The 250,000 barrel of oil per day One Guyana FPSO hull entered dry dock in Singapore on April 2. Topside fabrication and installation activities have commenced and development drilling is underway. Government and regulatory approvals are expected very soon for our fifth development at Uaru, with a gross production capacity of approximately 250,000 barrels of oil per day. Finally, for our sixth development, Whiptail, the partnership is on track for final submission of the field development plan to the government of Guyana later this year. Now, turning to exploration. The Lancetfish-1 Well, located 4 miles southeast of the Fangtooth 1 discovery, encountered 92 feet of oil-bearing sandstone reservoir. This discovery further underpins the potential oil development in the Greater Fangtooth area. Drill stem tests and core analysis are underway at Fangtooth 1 and further appraisal activities for Lancetfish and Fangtooth Southeast are planned for later in the year. In the second half of the year, we plan to drill the Bacher 1 well, which is a deep prospect located approximately 7 miles west of Fangtooth 1 and another deep exploration prospect called Lancetfish, located 2 miles southwest of Fangtooth 1. Moving to offshore Canada, we expect to spud the BP-operated Episys 1 well in the Northern Orphan Basin in May. The well will target a very large submarine fan of tertiary age. BP has a 50% working interest in Hess and Chevron, each have 25% interest. In closing, our execution continues to be strong. The Bakken is on a steady growth trajectory. Our Gulf of Mexico and Southeast Asia assets have active drilling programs and we continue to advance our major projects and further delineate the enormous upside in Guyana, all of which position us to deliver industry-leading performance and significant shareholder value for years to come. I will now turn the call over to John Reilly.

Operator:

Thank you. [Operator Instructions] Our first question comes from Ryan Todd with Piper Sandler. Your line is open.

Greg Hill:

No worries.

Greg Hill:

Yes. Thanks, Ryan. So, first of all, the wells have been performing extremely well above expectations. So subsurface going great, continue to see further upside in the subsurface as we kind of produce the wells. And then, as I mentioned in my opening remarks, Exxon Mobil and SBM are just doing an outstanding job of topsides reliability and also the debottlenecking side. Recall that Phase 1 was debottlenecked to the 140,000 barrels, it's actually producing between 140,000 and 150,000 barrels, sort of in that range. And then if you look at Phase 2, it has a nameplate of 220,000 barrels. It's on track to be debottlenecked towards 250,000 barrels by the end of the year. So, again, more upside coming on Phase 2. And it's been operating kind of 230,000 barrels or so on a regular basis, but we'll pick up that up towards 250,000 barrels by the year -- by the end of the year. So upside, upside.

Greg Hill:

Sure. Yes. So in some areas such as oil country tubular goods, we're expecting some moderation in inflation coming. Onshore rigs pretty much staying flat, but we're still seeing some pressure in certain areas, particularly labor. Now, specifically in the Bakken, we anticipated year-over-year inflation of between 10% to 15%. That's about where it's running. However, remember, we're mitigating about half of these impacts through the application of strategic contracting, lean manufacturing and technology. So, our Bakken well guidance of $6.9 per well for the year, remains unchanged. So if we look at the offshore, we're expecting year-over-year industry inflation there between 15% and 20%. Now remember, in Guyana, the first four FPSOs are contracted, so they'll have limited the exposure going forward. And then in addition, ExxonMobil is just doing a fantastic job of mitigating kind of inflation effects through their outstanding execution and performance using that design one, build many strategy, which is sort of like lean manufacturing in the offshore. And then finally, in our Gulf of Mexico operations, we contracted our services in 2022, so we missed some of the recent uptick. So because of that, our overall capital guidance of $3.7 billion remains unchanged this year.

Operator:

One moment for our next question. Our next question comes from Doug Leggate with Bank of America. Your line is open.

John Hess:

Good morning.

Greg Hill:

Yes. Thanks, Doug. So let me co-quarry [ph] first. Recall that was a higher-risk carbonate play that was located 37 miles from Liza 1 and it didn't encounter commercial hydrocarbons, but it did provide a lot of valuable data that further improves our understanding of the subsurface. Going forward, Doug, we still continue to see multibillion barrels of upside that hasn't changed. And finally, in reference to your question, the 11 billion barrels, the majority of that is in the upper campaign. And obviously, with our exploration program this year, we're really starting to understand the deep and what potential that holds. But across the block, this multibillion barrels of additional upside remains unchanged. Yes, we'll have a few dry holes as we test different things along the way, but there's still a lot more to play with.

Greg Hill:

What's not included in the 11 billion? So, the recent discoveries that we've had are obviously not included in that. Again, Doug, it's mainly Upper Campanian, right? So, as we get results, the lower Campanian, obviously, that will be incorporated. But the multibillion barrels of additional upside encompasses the upper and the lower. It's not just the lower. It's -- there's still a lot of upper Campanian to play for as well.

John Rielly:

Sure Doug. So, let me just back up and talk about our financial priorities that we have. So, the first priority is obviously to invest in these high-return opportunities, obviously driven by Guyana and the Bakken because that's going to drive our free cash flow growth. And as John said earlier in his comments that we can grow intrinsic value and cash returns and it's Guyana Bakken that will allow us to do that. Our second priority is to maintain a strong balance sheet. Again, we're in a good position with that. We want to also have a strong cash position, and we do have $2.1 billion of cash on the balance sheet. So, we're in a good place with that to fund our high-return projects. So, for us, we have this capital return framework, and we're going to follow that, that we put out. And so what we do is return up to 75% of our free cash flow on an annual basis, so that is after working capital, that is after capital expenditures, and even after debt maturities, which we don't have any this year, we do have $300 million in 2024. And so first thing that we'll do in that return of capital framework is focused on the dividend. As John mentioned in his opening remarks, we want to increase that dividend each year. And we did do that in March, so we had that 17% increase $0.25 per share increase and so that is going to be the first thing. So, we did increase our returns shareholders here in the first quarter with that dividend increase. Then the remainder of that free cash flow, that 75% will be done in share repurchases. And you're right, we agree with you about the NAV accretion that we'll be having with these FPSOs. And just to remind everybody, with each FPSO comes on, like obviously, we have Payara here coming early this year that generates net to us $1 billion of cash flow. So, again, the Payara and the Yellowtail wireless. So we're getting that $1 billion kind of a year adding to our portfolio. And so as we go forward, more and more of our capital returns will be share repurchases. And so buying our shares basically in advance of those as we get -- as Payara comes on, generates that $1 billion and gets in front of Yellowtail and Uaru, obviously, will be, I think, be able to deliver significant value to shareholders just following this framework that we have.

Operator:

One moment for our next question. Our next question comes from Neil Mehta with Goldman Sachs. Your line is open.

John Hess:

No. Look, we obviously focus -- and thank you for the question. We focused our portfolio on high return, low cost of supply opportunities. Obviously, we think we have built a highly differentiated value proposition and part of that is the low-cost model. The fact that over the next five years, we can get our breakeven to $50 Brent. Also, the cash cost going down 25% as well. I think that makes our portfolio very resilient in a low price environment. John Reilly talked about capital discipline and also the priority on keeping a strong balance sheet and cash position, our cash position at the end of the quarter was over $2 billion. And we will continue to hedge by buying puts to protect the downside and still give our shareholders the upside. So I think relative to a lot of our competitors that are having cost pressures going up, our costs are going down, and we're going to keep a strong balance sheet to stay resilient through the cycle.

Greg Hill:

Yeah. So we exited Q1 in line with our forecast, a little bit ahead of guidance, but it was in line with our forecast, and we expect to see a build through the end of the year as we continue to steadily bring wells online. Now we'll provide guidance for the Bakken as usual, in our second quarter conference call for the rest of the year. But I think, Neil, just expect sort of a steady increase with a four-rig program across 2023 and 2024. We'll get to 200,000 barrels a day in 2025. And then be able to hold that flat for almost a decade with the inventory that we have. So steady increase to 200,000, hold it flat for a decade. I want to remind people that when Bakken reaches that 200,000 plateau, it will generate about $1 billion of free cash flow. So steady cash flow generator for the company.

Operator:

One moment for our next question. Our next question comes from Paul Cheng with Scotiabank. Your line is open.

John Hess:

Hi. Good morning.

John Rielly:

Sure, Paul. I mean we remain committed to maximizing the long-term value of Hess Midstream. It's been a key strategic partner for us. It adds differentiated value to our E&P assets up there in the Bakken with us maintaining that operational and marketing control so we get provides takeaway optionality to high-value markets. Also, it's key to our gas capture and driving down flaring in our GHG emission intensity. So I would say think about Hess Midstream more of the same, they've been doing -- they've been executing brilliantly really for us on the ESG and also just getting the E&P production to markets. And then when you think about Hess Midstream, it has a very strong credit position and continues to generate free cash flow growth. So the Hess Midstream, they did outline that they have about $1 billion of financial flexibility through 2025 for capital allocation, which includes then the potential for incremental returns of capital, like the recent $100 million transaction that they just did. And so that $100 million is a small part of that $1 billion financial flexibility. So Hess Midstream has the potential to execute multiple buybacks basically each year through 2025. So I think you can think about it just more of the same that way, Paul, and we are happy with the investment.

Greg Hill:

So let me answer the exploration part first. So Paul, remember, we've got multibillion barrels of upside. The license expires in October of 2026. We will take the next four to five years to fully understand that potential get it locked down. So I think you should think about three wells -- three exploration rigs a year pretty much going through 2026. And we can drill usually about 10 or so exploration and appraisal wells a year. So think of that sort of a level exploration prospectivity going forward, again, going after that multibillion barrels of upside that we continue to see. Your question on Yellowtail. Look, Yellowtail...

Greg Hill:

No, we don't. Obviously, that's going to depend upon success, right? So when we have an exploration success, we tend to then want to appraise that success. Just like we're doing at Fangtooth, remember, Fangtooth 1 was 160 feet. Fangtooth Southeast was 200 feet. Now we have Lancetfish with 92 feet of pay, probably going to be a development. So we're going to want to appraise around that greater Fangtooth area. So it's really going to depend upon success as we go forward as to what the split is. Yes. Now regarding Yellowtail, look, it's too early. I mean Yellowtail is running ahead of schedule right now. Looking good, but these are major projects. So I think just right now, in 2025 is the right way to think about it. And obviously, as we get further down, we'll narrow the window on those dates.

Operator:

One moment for our next question. Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

John Hess:

Good morning.

John Rielly:

Sure. So our philosophy on the hedging is we believe it is strategic importance, just like you said, from the downside protection. We view it as an insurance, and so what we do ensure we buy the insurance, and we use puts. Our strategy is to use puts to protect full downside, but leave the upside for investors. So again, that's what we did this year. And you see we have 130,000 barrels a day this year, very comfortable with that level. We had 150,000 barrels a day last year. So I think you can think about that, let's just say, approximately 150,000 barrel a day level as we go forward. And for your question like for 2024, you can assume we'll put on insurance or hedges at that type of level as we move into 2024. And with the put options, the way we do that is we'll look more to do that in the latter part of this year, right, because of the cost, the time value of the money on the put option. So you typically would see us putting it on either towards the end of 2023 or early in 2024, like we did this year. And again, so we're trying to get -- obviously, within our putting the insurance on trying to be as opportunistic as possible, but we will eventually get that hedge on because we want that downside protection, really just as John Hess mentioned earlier.

John Hess:

No. The Guyana government is very rigorous and overseeing the government and regulatory approvals. I think there's a very good working relationship with ExxonMobil as operator and the government itself. I think the approval process is appropriate for both sides. And the fact of the matter is, hopefully, this week, we'll be getting approval on Uaru, and I think that speaks volumes about the approval process. So it's going appropriately in timing and also in depth of analysis by the government. The government obviously has their own priorities and the ExxonMobil as operator addresses those. So I'd say the approval process continues to be one that's diligent and thoughtful for both sides.

Operator:

One moment for our next question. Our next question comes from Arun Jayaram with JPMorgan.

John Hess:

Good morning, Arun.

Greg Hill:

Sorry, I turn. Yeah. Thanks, Arun. So first oil from Payara, remember now has been brought forward. So we were saying into the fourth quarter to early fourth quarter now. So we've already pulled it forward few months. In terms of what has to be done, remember, Payara is more extensive than Phase 2. So it's got 30% more wells. It's got 80% more surf the leads of Phase 2. And so it's expected to take a bit longer to hook up and commission in Phase 2 is. But things are well on track. I think we've adequately risked things as well as the operator, ExxonMobil to confidently say at this point, early first quarter or early fourth quarter of this year, yeah.

Greg Hill:

We haven't included anything yet. So at the midyear, obviously, as we get closer to that first oil date, we'll be updating our guidance.

Greg Hill:

No. I think about the Fangtooth area as a big hub. And as you mentioned, we do have both drill stand tests and core analysis for Fangtooth-1 and Fangtooth Southeast. Fangtooth 1 is underway. Fangtooth Southeast is planned for later in the year in terms of the DST. And then we also are planning an appraisal well at Lancetfish. So as you intimated when you add Bacher in and the other wells that we're going to drill Lancetfish, obviously, there's potential for a hub there, but we really need that DST data to figure out what the field development plan will be.

Operator:

One moment for our next question. Our next question comes from Paul Cheng with Scotiabank. Your line is open.

John Rielly:

So you're right, we are booking deferred tax in Guyana. Guyana has a 25% statutory rate. So we will be recording a 25% effective rate and it's just similar. Let me just say to like the US, where the tax rules for depreciation, you can amortize the fixed assets quicker for the tax basis, so you get a higher deduction for tax purposes versus book. And so as a result of that, your current cash tax rate is lower than the $25 million, and therefore, we book deferred taxes. I would, Paul, just for guidance purposes, let's just say, for the rest of this year, it can change obviously as we continue to bring on more and more boats, but use a similar deferred tax level that you see in the first quarter for Guyana.

John Rielly:

I don't want to go in the next several years because every year when we add the capital and it changes the depreciable base, and you're going over five years, so you get higher depreciation. So it's difficult to provide that to you for the next couple of years. So we'll try to guide you year-by-year as the boats come on.

John Rielly:

Yes. Yes, you can assume that.

Operator:

There are no further questions at this time. Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect, and have a great day.

Jay Wilson:

Thank you, Kevin. Good morning, everyone and thank you for participating in our fourth quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today’s conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties and that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess’ annual and quarterly reports filed with the SEC. Also on today’s conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I will now turn the call over to John Hess.

Greg Hill:

Thanks, John. 2022 was another year of strong strategic execution and operational performance for Hess. Proved reserves at the end of 2022 stood at approximately 1.26 billion barrels of oil equivalent. Net proved reserve additions of 184 million barrels of oil equivalent were primarily the result of the Yellowtail sanction in Guyana and the Bakken. Excluding asset sales, we replaced 144% of 2022 production at a finding and development cost of approximately $14.80 per barrel of oil equivalent. Turning to production. In the fourth quarter of 2022, company-wide net production averaged 376,000 barrels of oil equivalent per day, excluding Libya, which was above our guidance of approximately 370,000 barrels of oil equivalent per day. Strong performance across the portfolio more than offset the severe winter weather impacts experienced in the Bakken during the month of December. For the full year 2023, we forecast net production to average between 355,000 and 365,000 barrels of oil equivalent per day, an increase of approximately 10% compared with 2022 production of 327,000 barrels of oil equivalent per day, excluding Libya. For the first quarter of 2023, we forecast company-wide net production to average between 345,000 and 355,000 barrels of oil equivalent per day. In the Bakken, fourth quarter net production of 158,000 barrels of oil equivalent per day was below our guidance of 165,000 to 170,000 barrels of oil equivalent per day, reflecting severe winter weather impacts in December, which limited our new wells online to only 15 in the quarter. For the full year 2022, net production averaged 154,000 barrels of oil equivalent per day. In 2023, we plan to operate 4 rigs and expect to drill approximately 110 gross operated wells and bring online approximately 110 new wells. In the first quarter of 2023, we plan to drill approximately 25 wells and bring 25 new wells online. In 2022, our drilling and completion cost per Bakken well averaged $6.4 million. In 2023, we estimate industry inflation will average between 10% and 15%. However, we expect to mitigate this impact through the application of lean manufacturing and technology and forecast our D&C cost to average approximately $6.9 million per well or about 8% above last year. For the full year 2023, we forecast Bakken net production will average between 165,000 and 170,000 barrels of oil equivalent per day. First quarter net production is forecast to average between 155,000 and 160,000 barrels of oil equivalent per day, reflecting weather contingencies and the carryover effects from the severe winter weather in December. Net Bakken production is forecast to steadily grow over the course of ‘23 and ‘24 and average approximately 200,000 barrels of oil equivalent per day in 2025. We expect to hold this level of production for nearly a decade. Moving to the offshore, in the Deepwater Gulf of Mexico, net production averaged 35,000 barrels of oil equivalent per day in the fourth quarter and 31,000 barrels of oil equivalent per day for the full year 2022. For the first quarter and full year 2023, we forecast net production in the Gulf of Mexico will average approximately 30,000 barrels of oil equivalent per day, reflecting normal field declines and planned maintenance. The Deepwater Gulf of Mexico remains an important cash engine for the company as well as a platform for growth. In 2023, we plan to participate in 4 wells, 1 infrastructure-led exploration well, 1 hub class exploration well, and 2 tieback wells. The infrastructure-led exploration well will be the Hess-operated Pickerel Prospect located in Mississippi Canyon Block 727, which is expected to spud in April and will be brought online through existing infrastructure at Tubular Bells. The well will target the same Miocene interval that was successfully drilled at Esox and tied back to Tubular Bells in 2020. The hub class exploration well will be spud in the second half of the year and will be a Hess-operated opportunity in the Northern Green Canyon area in the Gulf of Mexico, targeting high-quality sub-salt Miocene sands in areas where the application of the latest seismic imaging technology has improved the sub-salt image. The 2 tieback wells will be spud in the fourth quarter, 1 well will be at Stampede and the second well will be at the Shell-operated Llano field. First oil from both wells is expected in 2024. In Southeast Asia, net production from the joint development area in North Malay Basin, where Hess has a 50% interest, averaged 67,000 barrels of oil equivalent per day in the fourth quarter and 64,000 barrels of oil equivalent per day for the full year 2022. For the first quarter and full year 2023, we forecast net production in Southeast Asia, the average between 60,000 and 65,000 barrels of oil equivalent per day. Turning to Guyana, where Hess has a 30% interest in the Stabroek Block and ExxonMobil is the operator, the partnership delivered exceptional facilities for liability, project delivery and exploration success in 2022. Net production from Guyana averaged 116,000 barrels of oil per day in the fourth quarter of 2022 and 78,000 barrels of oil per day for the full year 2022, both above our guidance. For the first quarter and the full year 2023, we forecast net production in Guyana to average approximately 100,000 barrels of oil per day. Turning to developments. Liza Phase 1 was successfully debottlenecked in 2022 and has been operating at or above its revised nameplate capacity of 140,000 barrels of oil per day. Liza Phase 2, utilizing Liza Unity FPSO, achieved first oil in February of last year and production ramp-up from start-up to nameplate capacity was achieved in about 5 months, which is world-class performance in the deepwater. The Liza Unity is currently operating at or above its nameplate capacity of 220,000 barrels of oil per day. Production optimization opportunities are currently being considered for late 2023. The third development, Payara, is approximately 93% complete. The Prosperity FPSO is expected to depart from Singapore in late first quarter and commence hookup and commissioning activities following arrival in Guyana. The project remains ahead of schedule and is anticipated to achieve first oil by the end of 2023. Yellowtail, our fourth development, is approximately 40% complete and remains on track for first oil in 2025. The ONE GUYANA FPSO is - hull is completed and is expected to enter drydock in Singapore in April. Topside fabrication activities have commenced and module fabrication sites in Singapore and China and development drilling is underway. The final development plan for our fifth development, Uaru, was submitted in November, and we are currently awaiting approval by the Government of Guyana, which we anticipate by the end of the first quarter. Pending government approvals, our sixth development, Whiptail, is expected to be sanctioned early next year. Turning to exploration. The Fangtooth Southeast-1 well, located approximately 8 miles southeast of the original Fangtooth-1 discovery well, resulted in a significant new oil discovery, and this area could form the basis for a future oil development on the Stabroek Block. The Fangtooth Southeast-1 well encountered approximately 200 feet of oil-bearing sandstone reservoirs and further appraisal activities are underway. We continue to see multibillion barrels of additional exploration potential on the Stabroek Block. And in 2023, we plan to drill approximately 10 exploration and appraisal wells that will target a variety of prospects and play types. These will include lower risk wells near existing discoveries and several penetrations that will test deeper intervals. With regard to upcoming wells, operations are continuing at the Tarpon Fish-1 well in the northwest corner of the Stabroek Block, approximately 43 miles northwest of the Liza-1 well. The well is in the first test of cretaceous age clastic reservoirs in Northwest Stabroek. The well will also test a deeper Jurassic aged carbonate prospect. Lancetfish-1 is a deep play exploration well, located approximately 2.5 miles northeast of the Fangtooth Southeast-1 well that underlies a portion [underneath] the field. Drilling operations are underway on the Noble Don Taylor drillship. Beyond that, there is a well called Basher, which will target a deep prospect in the Fangtooth area and a well called Blackfin which will penetrate an updip upper Campanian prospect east of Barreleye. Moving to offshore Canada, we plan to participate in the BP-operated Ephesus-1 well in the Northern Orphan Basin. The well will target a very large submarine fan of tertiary age. The Stena IceMAX rig is expected to arrive on location in the second quarter despite the well, which is located in approximately 4,000 feet of water. BP has a 50% working interest and Hess and Chevron, each have 25%. In summary, our execution in 2022 was again strong, and 2023 will be an exciting year with the Bakken returning to a steady growth trajectory, with an active drilling program in the Gulf of Mexico and with the advancement of our major projects and further delineation of the significant upside in Guyana, all of which position us to deliver industry-leading performance and significant shareholder value for many years to come. I will now turn the call over to John Rielly.

Operator:

[Operator Instructions] Our first question comes from Arun Jayaram with JPMorgan. Your line is open.

John Hess:

Good morning.

Greg Hill:

Well, thanks for the question, Arun. Again, as we have said before, if you look at the deeper interval, it’s only 3,000 feet below the upper Campanian in which the majority of our discoveries and if you look at that interval, it really underlies a lot of Stabroek Block. And over the past couple of years, we’ve had a number of penetrations in that tails of existing wells. But I think importantly, the Fangtooth discovery was our first stand-alone deep prospect and the Fangtooth-1, the first well had 164 feet of pay. In the Fangtooth Southeast well, which is located 8.5 miles southeast of that original discovery well, it had 200 feet of oil-bearing pay. And so we are going to continue to appraise that this year, probably get a DST in it. And as you mentioned, there are some other channels in and around Fangtooth, there is one called Lancetfish that’s northeast of Fangtooth, and there is a prospect called Basher, which is actually west of Fangtooth and the combination of all that is pretty exciting. And as John mentioned in his opening remarks, it could mean a potential future oil development in there. We will also continue to explore the deep as we kind of go through the next couple of years. But I think it’s very encouraging, and we will just continue to add to the discovered resource and also the significant exploration upside we see.

Greg Hill:

Yes. I think it’s that we’re seeing good quality reservoir and again, oil bearing. So our strategy is to continue to progress the oil developments as quickly as we can on the Stabroek Block. So good quality sand and oil bearing. So it’s coming up in the queue.

Operator:

[Operator Instructions] Our next question comes from Jeanine Wai with Barclays. Your line is open.

John Hess:

Good morning, Jeanine.

John Hess:

Yes. No. Excellent question, Jeanine. As I said earlier, with this capital budget of $3.7 billion, our first priority is to continue to allocate capital to our high-return, low-cost investment opportunities. That’s really priority number one for this year. Along with that, the next priority is to keep a very strong cash position and balance sheet. You heard John saying we bought some puts to provide downside protection, still have unlimited upside appreciation for our shareholders. But I want to protect the downside where it’s a volatile market, and we want to make sure the downside is protected. And then in terms of return on capital, yes, over the year, 75% of that free cash flow will be returned to our shareholders as we did last year. The first priority within that, Jeanine, is to grow our dividend. So our Board meets regularly and will give strong consideration to increasing our dividend during this quarter. Then as the year goes on as market conditions and our return of capital framework provide, then strong consideration will be to increase share repurchases as we did last year.

Greg Hill:

Yes. So the $12.7 billion is consistent with the estimate that the operator submitted as part of their EIA to the Government of Guyana. And that number is going to be finalized as the project progresses. And once we sanction it, we will give the final details. But in any case, the final cost of Uaru reflects a couple of things. It reflects current market conditions and then also additional scope. One example is, is the surf is twice as big as Yellowtail, for example, because it connects a number of further away kind of reservoir systems. But we will give you a final color on that once the project is finally sanctioned.

Jeanine Wai:

Great. Thank you, gentlemen.

Doug Leggate:

Hi, good morning, everyone.

Doug Leggate:

Guys, I wonder if I could ask a kind of a longer-term question. So Exxon had signaled a couple of years ago that if the deeper horizon worked, John, I think you’ve talked about this a number of times, we could be looking at double the resource potential at the time they were talking 10, so that would be 20 billion BOEs. It seems crazy to think that. But my question is, are you going to have enough time because the exploration phases on the stand that runs out in 2026. And this thing continues to get bigger, we’re already in 2023. What needs to happen for you guys to retain everything that you ultimately could find over the next several years? And what does that mean for development time lines and, I guess, relinquishment of block acreage and so on?

Doug Leggate:

So, just to be clear, John, you think you are going to have enough time in terms of securing the development approvals before ‘26, or do you have an extension on that to secure the development approvals?

Doug Leggate:

Thank you. Appreciate that, John. My follow-up, I here want to take this is it’s kind of a two-parter, if you don’t mind, because I think you did mention Uaru's EIS but you have also given guidance on Guyana for this year, which has got a lot of kind of cryptic comments perhaps around downtime for debottlenecking Liza and so on. So, there is a lot of things going on in terms of that 3-year, 4-year visibility. So, my question is this. First of all, can you give us some kind of a guide as to what the downtime and ultimate capacity would look like for Liza-2 as we go through this year? Some sort of trajectory, I guess. And then my kind of Part B is, a lot of people are freaking out over the $12.7 billion number that Exxon put in the EIS. Now, we know that the absolute cost recovery is not a big of a deal. But you guys typically have come in lower than that because of contingency. Can you tell us what Hess’ number is relative to that $12.7 billion?

John Rielly:

Yes. On the $12.7 billion, Doug, right now, look, we are going to wait for the final sanction where we come out with our estimates. But you are correct, there was always a contingency in at the beginning of these projects and rightfully so, several years of construction. What we can say is that ExxonMobil has done a fantastic job on every single project, meeting or beating their estimates on cost and on time on execution. So, John has said it earlier, this project will have world-class breakeven, will be world-class returns there in Uaru. We are excited about that. Final details once the government has approved it, we can provide.

Operator:

[Operator Instructions] Our next question comes from Paul Cheng with Scotiabank. Your line is open.

John Rielly:

Sure. So, let me do your first question was on the hedges that we put on. We have WTI put options on right now. So, that’s 75,000. And like I said, we do intend to get to a similar level as last year. And combined between WTI and Brent, we had about 150,000 barrels a day hedged last year. So, again, you should be looking for us to add to this position. But currently, that 75,000 is for WTI put options at $70.

John Rielly:

That is correct. That is just for the 75,000 we have. Simple math, if you want to double it to get to 150,000, you could double it, but we will give you updates on that as we increase our hedge position. Then your second question on the carbon credits. So, what we have, that 75,000 – 75 million purchase on the carbon credits, you will see it on our balance sheet in other long-term assets. And when you look at, there is nothing on the income statement because that is an asset being held. And on that cash flow statement, it is in working capital.

Greg Hill:

No. So, I think let me talk first about the snowfall for that. The severe snowfall coupled with really low wind chill, significantly impacted our ability to mobilize resources. You just can’t put people to work at minus 30, minus 40 wind chill. And so what that did was it significantly increased our backlog of down wells. And then importantly, it delayed bringing new wells online. We projected 25 new wells online coming on in the fourth quarter, that number was 15. So, we lost 10 wells. And if you assume those things come on at 1,100 barrels a day, 1,200 barrels a day, you can see that’s a fairly significant impact. I think we are in recovery mode. We expect to recover in the quarter from that. It just takes time to build and dig out of that literally. But importantly, Paul, I think the Bakken now is on this steady build, this steady cadence, a steady build to get to that 200,000 barrel a day average in 2025, so there will be this regular cadence. We will probably touch 200 towards the end of 2024. But I think importantly, we will average 200,000 barrels a day in 2025. So, we are on a solid trajectory from here to 2025 and not concerned at all about it. Wells are performing as expected. You are coming in with these IP 180s of 120, EURs of 1.2. That’s in spite of going into a little bit less quality acreage. So, the reservoir is performing exactly as expected. These are just weather aberrations as you kind of go through the year. That’s all it is.

Greg Hill:

No, not yet and we will guide that as we go through the year, Paul. And as I am always kind of hesitant because fourth quarter is always a little odd on weather, so we wait until we are closer and kind of look forward at weather forecast before we like to project that far out.

Operator:

[Operator Instructions] Our next question comes from Neil Mehta with Goldman Sachs. Your line is open.

John Hess:

Thanks Neil. Just going back to what John has said a little early, you reiterated our priorities, invest in those high-return opportunities Guyana and Bakken, maintain that strong balance sheet. So, the first thing, as John had mentioned, we will be looking at the dividend because that will give strong consideration first to that dividend increase. And then in line, we are going to return cash up to the 75% through further share repurchases then. So, as we look at – as you said, with the stock appreciation, we are committed to that return framework, and we will return up to that 75% through both the dividends and share repurchases. And the way we look at it right now is we currently only have two FPSOs on producing in Guyana. We have Payara starting in this year. And remember, every time an FPSO comes on and once it’s fully ramped, Payara is going to be about 55,000 barrels a day, 60,000 barrels a day to us and $1 billion in cash flow. So, then you have Yellowtail similarly in 2025, a little bit bigger. So, 65,000 barrels a day approximately. When that’s fully up and running, a little bit more cash flow than that $1 billion. Now, we have got Uaru in ‘26, and we got up to 10 FPSOs to develop all the resources we have found. So, we believe in buying our shares in advance of that significant cash flow growth and NAV accretion that each of these FPSO generates. So, we believe that will deliver significant value to shareholders by continuing the share repurchases.

John Hess:

So, obviously, this is really early, Neil, so thanks for that question. But as you move into next year, just think Bakken steady four-rig program shouldn’t be much changes there. Gulf of Mexico, we will see what happens. Greg had talked about the wells we are drilling this year and we will see what – any follow-ons as it relates to that. So, it’s a little early. Southeast Asia may be slowly coming down. You saw it came down a bit in ‘23 from last year. And then Guyana, obviously, the big spend. So, we will continue to have three FPSOs kind of coming in line. So, Payara will be on, but we will still have three FPSOs that are in the development phase. So, with those, I mean you see with current market, so the current market is a bit up, so you can kind of take up those three FPSOs a bit as compared to what we have this year. And then the one other piece to add is the FPSO purchases, which we expect to have our first FPSO purchase in early 2024.

Operator:

[Operator Instructions] Our next question comes from Ryan Todd with Piper Sandler. Your line is open.

Greg Hill:

Well, I think as you mentioned, I mean certainly, rigs are going up kind of the mid to high-3s, approaching 400, I think for offshore rigs, not unreasonable. Now remember, we are largely insulated from that because the – certainly, the first three developments in Guyana are actually already locked in four actually with Yellowtail. So, those costs were locked in. Some of the rig rates flowed a little bit. And obviously, oil country tubular goods were up, but I will say that ExxonMobil has done an outstanding job of delivering improvements to offset both rig cost increases and oil country tubular good increases. So, we are fairly insulated because of the projects we have going on. And as we mentioned, the cost in Uaru will reflect that market inflation, and we will get into details all that once it’s finally sanctioned. But those are sort of the levels we are seeing. But again, we are largely insulated from that in our portfolio because of the nature of Guyana.

John Hess:

We definitely view it as strategic importance from an insurance point of view. And I think you can clearly expect our WTI hedge levels to remain at similar levels that we have done before, again, the tax and royalty aspect of it. Percentage-wise from on the Brent side as production keeps growing each time we bring on FPSOs, you could see maybe percentage-wise that we could have a lower hedge percentage overall. But again, I think you should expect us to have a good significant insurance protection each year just to protect that downside and again, leave the upside for investors.

Operator:

[Operator Instructions] Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

John Hess:

Good morning.

Greg Hill:

No. What my earlier comment was if you look at Q4 in Guyana, there was little maintenance at all in Guyana. And then as we look forward for a whole year, you have to build some of that in. You will have some pigging runs and some facility maintenance. So, we had to build that into the downtime as we kind of look forward for a full year of Guyana production, but Q4 was exceptional, very high reliability.

Greg Hill:

Yes, sure. So, we identified this prospect with a number of partners really about the same time that we identified the Guyana opportunity. And this is a very large stratigraphic trap. There is only a one-well commitment. As we mentioned in our opening remarks, the rig will show up in the second quarter. The prospect is very shallow. It’s about 15,000 feet or so, and it’s only in 4,000 feet of water, total depth 15,000. So, this is going to be a kind of a one-well wonder, and we will see where it goes. But it’s very large.

Greg Hill:

Thanks.

Operator:

Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect and have a wonderful day.

Jay Wilson:

Thank you, Carman. Good morning, everyone, and thank you for participating in our third quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today’s conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess’ annual and quarterly reports filed with the SEC. Also, on today’s conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case there are any audio issues, we will be posting transcripts of each speakers prepared remarks on www.hess.com following the presentation. I’ll now turn the call over to John Hess.

Greg Hill:

Thanks, John. In the third quarter, we delivered strong operational performance. Companywide net production averaged 351,000 barrels of oil equivalent per day excluding Libya, compared to our guidance of 330,000 to 335,000 barrels of oil equivalent per day. This production beat reflects strong performance across our portfolio. For the fourth quarter, we expect companywide net production to average approximately 370,000 barrels of oil equivalent per day, excluding Libya. For the full year 2022, we now expect companywide net production to average approximately 325,000 barrels of oil equivalent per day, excluding Libya, up from our previous guidance of approximately 320,000 barrels of oil equivalent per day. Turning to the Bakken, third quarter net production averaged 166,000 barrels of oil equivalent per day. This was above our guidance of 155,000 to 160,000 barrels of oil equivalent per day and primarily reflected strong execution and recovery following challenging weather conditions in the first half of the year. For the fourth quarter, we expect Bakken net production to average between 165,000 and 170,000 barrels of oil equivalent per day. For the full year 2022, we now forecast Bakken net production to average approximately 155,000 barrels of oil equivalent per day, which is the high end of our previous guidance range of 150,000 to 155,000 barrels of oil equivalent per day. In the third quarter, we drilled 20 wells and brought 22 new wells online. For the fourth quarter, we expect to drill approximately 30 wells and to bring approximately 25 new wells online; and for the full year 2022, we expect to drill approximately 90 wells and to bring approximately 80 new wells online. In terms of drilling and completion costs, although we continue to experience cost inflation, we are maintaining our full year average forecast of $6.3 million per well in 2022. Given the improvement in oil prices and our robust inventory of high return drilling locations, we added a fourth rig in July. Moving to a four rig program will allow us to grow net production to approximately 200,000 barrels of oil equivalent per day in 2024, which will maximize free cash flow generation, optimize our in-basin infrastructure and drive further reductions in our unit cash costs. Now moving to the offshore. In the deepwater Gulf of Mexico, third quarter net production averaged 30,000 barrels of oil equivalent per day, which was at the high end of our guidance range of 25,000 to 30,000 barrels of oil equivalent per day, primarily reflecting the successful start up of the Shell-operated Llano 6 tieback. For the fourth quarter and full year 2022, we forecast Gulf of Mexico net production to average approximately 30,000 barrels of oil equivalent per day. In Southeast Asia, net production in the third quarter was 57,000 barrels of oil equivalent per day, above our guidance of approximately 55,000 barrels of oil equivalent per day. Planned maintenance work was successfully completed at both the North Malay Basin and JDA assets during the third quarter. Fourth quarter and full year 2022 net production is forecast to average between 60,000 and 65,000 barrels of oil equivalent per day. Now turning to Guyana. In the third quarter, net production from the Liza Phase 1 and Phase 2 developments averaged 98,000 barrels of oil per day, including tax barrels of 7,000 barrels of oil per day – above our guidance of 90,000 to 95,000 barrels of oil per day. Both the Liza Destiny and Liza Unity Floating Production, Storage and Offloading vessels delivered strong operating performance and high facility uptime during the quarter. Guyana net production is forecast to average approximately 110,000 barrels of oil per day in the fourth quarter, including tax barrels of 20,000 barrels of oil per day. For the full year 2022, Guyana net production is forecast to average approximately 77,000 barrels of oil per day, including tax barrels of 7,000 barrels of oil per day, slightly above our previous guidance of 75,000 barrels of oil per day. Turning to our third sanctioned development at Payara, topsides installation and development drilling are underway. The overall project is approximately 88% complete. The FPSO Prosperity will have a gross production capacity of 220,000 barrels of oil per day and is on track to achieve first oil at the end of 2023. Our fourth sanctioned development at Yellowtail will utilize the ONE GUYANA FPSO with a gross capacity of approximately 250,000 barrels of oil per day. Fabrication of topside modules kicked off in September and the hull is expected to arrive in Singapore in early 2023. The overall project is approximately 29% complete and is on track to achieve first oil in 2025. With regard to our fifth development, Uaru, the operator plans to submit a Plan of Development to the government before the end of this year, with approval expected by the end of the first quarter of 2023. The plan utilizes an FPSO with a gross capacity of approximately 250,000 barrels of oil per day with first oil targeted for the end of 2026. As John mentioned, this morning, we announced discoveries at Yarrow and Sailfin. The Yarrow-1 well, located approximately nine miles southeast of the Barreleye-1 well, encountered 75 feet of high quality, oil bearing sandstone reservoir. The Sailfin-1 well, located approximately 15 miles southeast of the Turbot-1 well, encountered 312 feet of high quality, hydrocarbon bearing sandstone reservoir. The Banjo-1 well did not encounter commercial quantities of hydrocarbons and was expensed in the third quarter. The Banjo-1 well did not encounter commercial quantities of hydrocarbons and was expensed in the third quarter. On Block 42 in Suriname, we recently drilled the Zanderij-1 well, where Hess has a 33% interest and Shell is the operator. The well demonstrated a working petroleum system and encountered oil pay. The well results are being evaluated and further exploration activities are being considered. Looking forward, fourth quarter exploration and appraisal activities on the Stabroek Block in Guyana will include the Fangtooth SE-1 well, which is a deep test located approximately 8 miles southeast of the Fangtooth-1 discovery well. We will also drill the Fish-1 exploration well located approximately 62 miles northwest of Liza-1. This well will target multiple stacked reservoir intervals. In addition, we plan to drill the Lancetfish-1 well, located approximately 3 miles west of the Liza-3 well which will target deeper reservoirs. In closing, our execution continues to be strong. The Bakken is on a strong, capital efficient growth trajectory, our Gulf of Mexico and Southeast Asia assets continue to generate significant free cash flow, and Guyana continues to get bigger and better – all of which position us to deliver industry leading returns, material free cash flow generation and significant shareholder value. I will now turn the call over to John Rielly.

Operator:

Thank you. [Operator Instructions] Our first questions come from the line of Arun Jayaram with JPMorgan Securities. Your line is open.

John Rielly:

Morning.

John Rielly:

Sure, Arun. Thanks for the question. As usual, we will provide, to your point, our 2023 capital guidance in January, but I'll try to give you some high-level information now compared to 2022. So if we're going to start with Guyana. In 2022, we have $1 billion of development spend. And as you know, that includes two projects, Payara and Yellowtail. So in 2023, we will continue spending on Payara and Yellowtail, but we will add, subject to government approval, a third development project at Uaru. And, to a lesser amount a gas to energy project as well. So while the Uaru project is going to have industry-leading returns and a low cost of supply, the cost of the Uaru project, as you mentioned, will be higher, reflecting the current market conditions as well as additional scope to reduce greenhouse gas emissions. So with that, we currently expect our Guyana spend to increase by approximately $500 million to $700 million in 2023. So the midpoint of that would be going up from $1 billion to $1.6 billion. In the Bakken, we are spending approximately $850 million this year, and we added the fourth rig later in the year. So we expect an additional $250 million of spend in 2023, reflecting a full year of a 4-rig program. And that 4-rig program as well as the expected industry inflation drives that $250 million increase there in the Bakken. In the Gulf of Mexico, we are still finalizing our 2023 program, but we do see the potential for two well tiebacks and also one hub class exploration opportunity. So with that is approximately $150 million increase in the Gulf of Mexico. So therefore, adding those up, taking the midpoint of the Guyana number, we expect our 2023 capital exploratory spend, and again, it's preliminary to be approximately $3.7 billion or about $1 billion more than 2022.

John Rielly:

It is premature at this point. And I mean, again, think about us from a longer-term standpoint on production growth, we've seen that we can grow our top line production growth. And it's just an output of the great opportunities that we have in Guyana that over the long term, we can grow at greater than 10%. Because – just think about in 2024 now, as Greg mentioned earlier, we'll get the Bakken to 200,000 barrels a day. And then we'll have Payara on as well. So that's going to add another 50,000 to 55,000 barrels. So right then add those two together, you're almost up 25% absolute from where we are right now. So again, as we move into next year, we'll give that production guide early in the year. But the growth is going to be lumpy basically when the FPSOs come online. So that's how you should think about it as we move into next year.

John Hess:

No, you have to ask Exxon about that but our comment about by 2027 having productive capacity growth of over 1 million barrels of oil per day. That's very consistent with what Exxon has said the last several years, and that's the correct…

Operator:

Thank you. [Operator Instructions] Our next question comes from the line of Doug Leggate with Bank of America. Your line is open.

John Hess:

Good morning Doug.

John Hess:

Doug, I think the 2027 number of six FPSOs and at least 1 million barrels a day of gross production is a good number. It's a conservative number, and is there some upside to that? Yes, there certainly is.

John Hess:

No. Well, as opposed to talking about your math, let's talk about our math. We're saying 1 million barrels a day, six FPSOs, 2027, there's upside to that number.

John Hess:

Yes Doug, thanks for the question. It's an excellent one. As we look to 2023, our financial priorities remain first, to invest in our high-return opportunities, especially in Guyana and Bakken that John talked about, the $3.7 billion capital program. Second to maintain a strong cash position and balance sheet to ensure that we can fund these high-return opportunities and investments through the cycle. Then we would give strong consideration next year to further increasing our regular dividend. And then following that, in line with the capital return program, where we have committed to returning the remainder of our free cash flow up to 75% through share repurchases. And similar to this year, we have the flexibility to return in excess of 75%. You'll recall, at the end of the quarter, we had $2.38 billion of cash on the balance sheet. So we have flexibility for next year. So depending upon market conditions, oil prices, financial prices, where the recession and the economic slowdown come out, we'll be positioned to increase our return on capital further. But that's going to be a decision that we'll make as we go into next year. First, to make sure that we can fund our high-return programs; second, keep the strong balance sheet; third, increase the dividend. And then anything left over as we go out, not just next year but in the years ahead, and we deliver increasing levels of free cash flow. We expect share repurchases will represent a growing proportion of our capital return program in the years ahead.

John Rielly:

It's actually in 2024, and it's $300 million, in 2024. And we do expect to...

John Rielly:

Yes. Hey Doug, I just want to make sure what you said earlier because this year, we are actually returning more than our 75% in our framework. So just remember, our framework, we did our debt reduction of $500 million. And as John mentioned, our framework has the flexibility when oil prices are strong to do more than 75%. And that's what we are doing this year. As John mentioned, we'll complete the $310 million in the fourth quarter. So again, we have that flexibility to stay strong. And as John said, depending on market conditions, we'll do 75% or more, we'll see.

Operator:

Thank you. [Operator Instructions] Our next question comes from Stephen Richardson with Evercore. Please go ahead.

Greg Hill:

Yes, sure. So first of all, I would say the inboard oil play has been very successful because we've had four discoveries in the area. So recall, Barreleye had 230 feet of high-quality pay. Seabob had 131 feet of high-quality pay, as we announced this morning; Uaru had 75 feet of high-quality pay. And finally, Lukanani had 115 feet of high-quality pay. So all of those will help to underpin a future development. And even though Banjo was dry, it had noncommercial qualities of – quantities of hydrocarbons; it had hydrocarbons that went through it. We've got more wells to drill in that area. So if I step back and say four successes, one non-commercial and more to come, I still feel very optimistic about – I still feel very optimistic about the inboard play. And also, I think it's important to know that Banjo was the Western most prospect that we drilled in that inboard play as well.

John Hess:

Yes. Steve, I want Greg to answer that. But you have the clarity on what production is going to be. It grows a million barrels a day at least in 2027. I think that’s really important. So people don’t get confused by other releases. That is the number, and there’s upside to that. Now, Greg can talk more about tiebacks and plateaus, but that million barrels a day is a very good number that people should use in terms of having clarity and visibility of the production growth trajectory.

Stephen Richardson:

Thank you.

Neil Mehta:

Good morning team.

Neil Mehta:

Morning, John. First question is around the Bakken. Really good quarter for you guys here after some weather issues earlier this year. Can you just refresh us on how we should be thinking about the trajectory in the Bakken in 2023 and then as you get into 2024 as well?

Neil Mehta:

All right. That’s good color here. And then, John, if I could ask you to step back and talk about your view on the macro, you always have a good read on the oil markets. Just your perspective on where we are in terms of the rebalancing as you go into 2023? And how that feeds into your framework around hedging given the backwardation in the curve?

John Rielly:

Sure. So with that backdrop, I mean, Neil, what we do is, we use put options for our hedging strategy. And with all the variables that John just mentioned and the time value here the volatility levels right now, putting on the puts would be too expensive. So, we do plan to get the similar level of hedge protection that we had this year. Now, we will continue to watch the market. We’ll try to get some on in the fourth quarter, but it could be early next year that we get these hedges on. So, you should expect us to get that – a similar hedge position on. It will just be a matter of timing when we do it. And again, just with put options.

Neil Mehta:

Makes a lot of sense. Thank you both.

Roger Read:

Yes. Good morning. Going to come back, I guess, a little bit on the CapEx, and I know you’re hesitant to get any more than what you’ve had. But I’m just a little curious as you look across the various regions you operate onshore, U.S., offshore, U.S. and Guyana, how much of – when you look out, you can say, is fairly well committed or contracted, signed where there’s not a lot of risk of a surprise as we think about 23% on the CapEx front, the underlying inflation that we’re just kind of seeing everywhere?

Roger Read:

Yes, it’s certainly something to watch down there. And the only other question I had is related to Guyana. Has there been any update, any change to the thoughts of gas development down there long term? I mean I know we have the pipeline to be onshore, but anything else as you’ve had these additional discoveries and as you’re thinking about out to the 2027 period with six FPSOs?

Roger Read:

Great. Thank you.

Paul Sankey:

Good morning, everyone. John Hess, while you’re on the subject of oil markets, could you give an update and outlook for Libya, please? Thank you.

Paul Sankey:

Understood. Another thing which is a little bit inside baseball, but maybe an opportunity for you to talk about a big theme is the asset retirement obligations that you had in the quarter. Is that a sort of a one and done payment that you’re making in the Gulf of Mexico? Is there an outlook there for more of the same, or is that sort of putting an end to it? And could you comment on the overall attractiveness and position in the Gulf in Mexico and your plans there? We don’t really talk too much about it. But obviously, we’re aware you’ve got a pretty good position. Thanks.

Greg Hill:

Thanks. And Paul, let me talk about, kind of where we’re headed, in the Gulf. So, as you kind of intimated, the Gulf of Mexico remains in a really important cash engine and platform for growth for us. And so our objective is to sustain or grow production there through both tiebacks and hub class exploration opportunities. So we’ve been selectively rebuilding our Gulf of Mexico portfolio, as you know, in the last six years, and we’ve acquired more than 60 new lease blocks and have a really good balance of both types of opportunities. So I think a good planning assumption is that we would drill two wells per year for the next several years, and then if we kind of hone in on 2023, we’re still finalizing the program. But we’re seeing the potential next year for two tiebacks and one hub class exploration opportunity based upon the success of our Huron well this year. And also in most of these prospects that I talked about, our partners are Shell and Chevron. So we’re in with a very good partnership in the Gulf.

Greg Hill:

No, it hasn’t.

Operator:

Thank you. One moment for our next question, please. Our next question, one moment. [Operator Instructions] Our next question comes from the line of Bob Brackett with Bernstein Research. Your line is open.

Greg Hill:

Oh, thanks, Bob. I think, the opportunity to kind of debottleneck is going to be bespoke. So it’s going to be vessel by vessel. Now, recall with debottleneck Phase 1, it went from 120 to 140. Based on the early production performance of Phase 2, it looks likely that we will probably have some debottleneck potential there. As these well – as these vessels come on, based upon the early production history, call it the first year or so, that is when you’ll decide, where your pinch points are and how much bottlenecking capability there is on each vessel. So it’s going to be bespoke and we’ll just have to wait and see what that early production data shows.

Greg Hill:

Well, I think, 10% to 15% is kind of what would be typical, if you look at Phase 1 and maybe potentially Phase 2, 275, I don’t know, I just don’t know. Again, every vessel is going to be different and I think it’d be premature to throughout numbers like that.

Bob Brackett:

Very clear. Follow-up then, this has been your biggest year of sort of deeper Santonian exploration Guyana, any update on progress and learnings thoughts about the Santonian?

John Hess:

Yes. And there are a number of other prospects that we had a recent review on one’s called Lancetfish, which is the East of Fangtooth. Then we have Fish-1 and Fish-2 that are reasonable distance to the West and Northwest of Fangtooth. So, there’s a lot of prospectivity to come. As we get more success in finding these deeper horizons, our ability to correlate the seismic new prospects are lighting up. So there’s a lot more upside that Greg’s talking about that hopefully in the next six months we’ll be able to give updates on.

Bob Brackett:

Thanks for that.

Noel Parks:

Hi, good morning.

Noel Parks:

I was wondering at Banjo if you could just talk a bit about how the results there sort of maybe ripple through your analysis. It – thinking about maybe the seismic interpretation or if there is anything else you learned about beyond just the aerial extent of the resource there?

Noel Parks:

Okay. fair enough. And I just wanted to turn to the Bakken for a minute, and just wondering if you had any updated thoughts on or experience with recompletions up there. If I recall, you had done some work going back to some of the oldest vintage wells were done sort of with the original much lighter completions out there. And so, and if you have been doing anything out there, what adventure, I guess, about what the returns might look like for that sort of work?

Noel Parks:

Okay. Thanks a lot.

Operator:

Thank you. One moment for our next question, please. Our next question comes from the line of Ryan Todd with Piper Sandler. Please go ahead. Oh, and Mr. Todd – remove himself. So thank you very much. This concludes today’s conference. Thank you for your participation and you may now disconnect.

Jay Wilson:

Good morning, everyone, and thank you for participating in our second quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors sections of Hess's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case there are any audio issues, we also will be posting transcripts of each speaker's prepared remarks on www.hess.com following the presentation. I'll now turn the call over to John Hess.

Greg Hill:

Thanks, John. Although in the second quarter, we experienced continued weather impacts in the Bakken and a ramp up of Liza Phase 2 that was modestly slower than expected. Net production was up 10% from the first quarter and we anticipate company-wide net production to continue to build in the second half of the year as we bring more wells online in the Bakken, and Liza Phase 2 operates at nameplate capacity. In the second quarter, company-wide net production averaged 303,000 barrels of oil equivalent per day, excluding Libya. In the third quarter, we expect company-wide net production to increase by approximately 10% from the second quarter and to average between 330,000 and 335,000 barrels of oil equivalent per day, excluding Libya. In the fourth quarter, company-wide net production is expected to further increase to between 365,000 and 370,000 barrels of oil equivalent per day, excluding Libya. For the full year 2022, we now forecast net production to average approximately 320,000 barrels of oil equivalent per day, excluding Libya. Turning to the Bakken. Second quarter net production averaged 140,000 barrels of oil equivalent per day. This was in line with our guidance and reflected the impact of severe weather in April and May. Production is now recovering and is expected to increase to between 155,000 and 160,000 barrels of oil equivalent per day in the third quarter. For the fourth quarter, we forecast net production to further increase to between 160,000 and 165,000 barrels of oil equivalent per day. For the full year 2022, we now forecast Bakken net production to average between 150,000 and 155,000 barrels of oil equivalent per day. This reflects a volume reduction of approximately 7,000 barrels of oil equivalent per day under our percentage of proceeds contracts as a result of higher NGL prices. Although NGL volume entitlements are lower, overall cash flow is substantially higher. In terms of drilling and completion costs, we are continuing to see upward pressure across our supply chains, particularly in oil country tubular goods. As a result, we have increased our full year average drilling and completion cost forecast by $100,000 per well to average $6.3 million per well in 2022. I am proud of our team's effectiveness in mitigating the impacts of inflation, tight supply chains largely through our distinctive lean culture. While we believe the industry is experiencing overall inflation of between 15% and 20%, our full year drilling and completion costs are forecast to increase by only about 8.5% year-over-year. In the second quarter, we drilled 20 wells and brought 19 new wells online. In the third quarter, we expect to drill approximately 25 wells and to bring approximately 20 new wells online. And for the full year 2022, we now expect to drill approximately 95 wells and to bring between 80 and 85 new wells online, which is slightly lower than previous guidance due to the second quarter weather-related delays in mobilizing equipment. Individual well results in terms of EURs and IP180s continue to meet or exceed expectations. Earlier this month, we added a fourth drilling rig in the Bakken. Through our strategic partnerships with Nabors and Halliburton we were able to secure a fully staffed, high spec class rig and a second completion crew. Moving to a 4-rig program will allow us to grow net production to approximately 200,000 barrels of oil equivalent per day in 2024, which will optimize our in-basin infrastructure and drive further reductions in our unit cash costs. Now moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 29,000 barrels of oil equivalent per day compared to our guidance of approximately 30,000 barrels of oil equivalent per day. In the third quarter, we forecast Gulf of Mexico net production to average between 25,000 and 35,000 barrels of oil equivalent per day reflecting planned downtime at Tubular Bells and a Penn State Well being shut in due to a mechanical issue. This downtime will be partially offset by the planned start-up of the Lano 6 tieback in August, which logged 123 feet of high-quality Miocene pay. For the full year 2022, our forecast for Gulf of Mexico net production is now approximately 30,000 barrels of oil equivalent per day. In June, we completed drilling operations on the Huron prospect on Green Canyon Block 69 with encouraging results. Hess is the operator with a 40% working interest and Chevron and Shell each have 30%. The well encountered high-quality oil-bearing Miocene age reservoirs and established the existence of a working petroleum system. Well results are still being evaluated and an appraisal sidetrack is planned. In Southeast Asia, net production in the second quarter was 67,000 barrels of oil equivalent per day compared to our guidance of approximately 65,000 barrels of oil equivalent per day. Phase 3 of the North Malay Basin development came online in June and is producing above expectations, and Phase 4 is on track to achieve first gas in early 2023. Third quarter net production is forecast to average approximately 55,000 barrels of oil equivalent per day, reflecting planned maintenance at both JDA and North Malay Basin. Full year 2022 production is expected to average between 60,000 and 65,000 barrels of oil equivalent per day. Now turning to Guyana. In the second quarter, net production averaged 67,000 barrels of oil per day, reflecting a modest delay in the ramp-up of Liza Phase 2. Overall, the start-up has been very successful. In July, Liza Phase 2 reached its nameplate capacity of 220,000 barrels of oil per day or about 56,000 barrels of oil per day net to Hess. For Liza Phase 1 production optimization work was completed in the second quarter, and the FPSO is now operating at or above its new gross production capacity of 140,000 barrels of oil per day. Earlier this month, SBM Offshore also completed the replacement of the flash gas compressor, which has resulted in high reliability and 0 routine flaring. Third quarter net production from Guyana is forecast to increase to a range of 90,000 to 95,000 barrels of oil per day and average approximately 75,000 barrels of oil per day for the full year 2022. With regard to our third development of Payara, topside fabrication and installation on the Prosperity FPSO is well underway in Singapore and development drilling in Guyana continues at pace. The project, which will have a gross production capacity of 220,000 barrels of oil per day is now more than 80% complete and is well on track to achieve first oil in late 2023. In April, we sanctioned a fourth development at the Yellowtail, which will develop approximately 925 million barrels of oil and have a breakeven Brent oil price of approximately $29 per barrel. The project will have a gross production capacity of 250,000 barrels of oil per day and is on track to achieve first oil in 2025. As for our fifth development at Uaru Meco, the operator anticipates submitting the plan of development to the government of Guyana in the fourth quarter with first oil targeted for 2026, pending government approvals and project sanctioning. Turning to exploration. Yesterday, we announced 2 new discoveries on the Stabroek Block. The Seabob-1 well encountered 131 feet of high-quality oil-bearing upper campaign sandstone reservoirs. The well is located in the southeastern part of the block, approximately 12 miles southeast of the Yellowtail field. The Kiru-Kiru-1 well has also thus far encountered 98 feet of high-quality hydrocarbon-bearing upper campanion sandstone reservoirs. The well is currently drilling ahead to test deeper intervals and is located in the southeastern part of the block, approximately 3 miles southeast of the Cataback-1 discovery, both discoveries will add to the gross discovered recoverable resource estimate for the block of approximately 11 billion barrels of oil equivalent. In terms of future drilling activity on the Stabroek Block, next up in the queue are Yarrow and Banjo. The Yarrow-1 well will test stacked Upper Campanian targets, up-dip of discoveries at Whiptail and Tilapia. The well is located 19 miles south of the Yellowtail 1 discovery well. The Banjo-1 well will also target stacked Upper Campanian targets west of Barreleye and up-dip of Mako. The well is located 8 miles northwest of the Barreleye-1 discovery well. These wells will appraise the development potential of the inboard oil play in the southeast portion of the block. In addition, on Block 42 in Suriname, we will participate in the Zanderij-1 exploration well. The Shell operated well is expected to spud in late August and will test both Upper Campanian and deeper play stacked targets. Hess, Chevron and Shell each have a one third working interest. In closing, our Bakken assets are now recovering from the severe weather impacts experienced in the first half of the year and we expect to see steady production growth in the coming quarters, particularly with the addition of the fourth rig. We had positive drilling results in the Gulf of Mexico at both Llano 6 and Huron and have a robust inventory of both infrastructure led tie back opportunities and exploration prospects. Malaysia continues to generate steady production and cash flow, and our extraordinary success in Guyana continues on all fronts. Our distinctive, long-lived portfolio uniquely positions us to deliver material and accelerating production and free cash flow growth and significant value to our shareholders. I will now turn the call over to John Rielly.

Operator:

[Operator Instructions] Our first question comes from Arun Jayaram with JPMorgan.

John Hess:

Yes, John Reilly.

Arun Jayaram:

Great. And maybe John Riley, a follow-up for you. $2.7 billion in CapEx update, a little bit lower than you told us last quarter. I was wondering if you could just provide us maybe some soft commentary around 2023 CapEx if you sustain 4 rigs in the Bakken and continue your E&D program in Guyana.

Arun Jayaram:

And what about the FPSO? Have you all made a determination with Exxon on buying those on your buy option?

Operator:

Our next question comes from Doug Leggate with Bank of America.

John Hess:

Yes, Greg.

Doug Leggate:

Okay. Greg, I just wanted to kind of address that upfront. My follow-up, I'll leave everyone else to ask on Guyana today. Greg, I want to ask you about Huron. This is perhaps a little bit more material news and perhaps your short comments might suggest. Can you give us a little bit more color on pre-drill scale? And if you're sidetracking, 1 assumes that you're pretty encouraged with what you're seeing. So what was the predrill target here? And what is this -- you've talked about 1 potential hub development exploration well per year going forward. Does this qualify as a potential hub development?

John Hess:

I would just add to that. I mean we're encouraged by the prospectivity in this area. The fact that there's a working petroleum system. So there's going to be further drilling and appraisal ahead of us, and we're encouraged by it.

Greg Hill:

Well, still under evaluation, Doug.

Paul Cheng:

First 1 is for John Rielly. John, with the rising fear on recession, how does it or does it have all impact on the thinking or in your decision process -- in you guys' decision ports and on the budget?

John Rielly:

Sure. So that's one of the things I mentioned why, as Arun said, soft guidance and what our budget would be for next year. We are looking at that -- obviously, it's -- there's no change to our base program in the Bakken. We're going to have the 4 rigs. We're doing that. We want to optimize our infrastructure up there, lower our cash cost, and it's the best return way to develop the Bakken. So there won't be any change there. And so we'll continue to monitor the cost and update everyone on where the budget ends up with that. So on a go-forward basis, then Guyana, again, the plan is there unchanged. Obviously, just a phenomenal province for us for oil development, the returns there are excellent, and we will be trying to bring forward as much as we can to get this oil for the country of Guyana on as early as possible. So again, Payara, Yellowtail, getting the fifth ship in for FID, try to get the development plan into the government. So no change there. Again, with Exxon, has been doing an excellent job managing the cost there. But we are susceptible to that cost inflation that everybody else is seeing. So we'll update again where that number comes. But as I said, we have about $1 billion this year in our plan in our original budget, and we're not changing that in Guyana. So again, Exxon has done a really good job this year managing that inflation. And as I said, it will be several hundred million dollars more, but again, we'll see where the inflation ends up. And then kind of the new thing because we were just talking about a Gulf of Mexico and our program, we are looking at the rig rates and being able to get slots. So that's something, again, that we will be looking at managing, but we do want to do this appraisal that we talked about, and we'd like to do some of our infrastructure-led tiebacks. So -- again, those are extremely good returns even if the cost inflation is a little bit higher. So I think you can take that again as our soft guidance on what we're doing, and we keep practicing our lean culture and trying to get it as much as possible working with our strategic -- So again, Exxon has done a really good job this year managing that inflation. And as I said, it will be several hundred million dollars more. But again, we'll see where the inflation ends up. And then kind of the new thing because we were just talking about Gulf of Mexico and our program, we are looking at the rig rates and being able to get slots. So that's something, again, that we will be looking at.

Paul Cheng:

Great. And going back to John Rielly, you mentioned some activity has been pushed from this year to next year. Can you quantify roughly how much?

Operator:

Our next question comes from Jeanine Wai with Barclays.

John Hess:

Yes, Greg, Wai, we appreciate it if you just go over our strategy. The role of the Gulf in our portfolio, the exploration acreage that we have. And I can comment on M&A side, Jeanine, in the normal course of business, we always look to optimize our portfolio, but we have not seen anything in the market, be it in the Gulf for or elsewhere that makes sense for us to do an acquisition. We have better opportunities to invest in our portfolio of high return and low cost investments. So we're much more focused on getting return from the inventory of investment opportunities that we have then looking to the outside. We don't need M&A to grow the returns of our business and quite frankly, most of the stuff that we've seen would erode returns. We're going to do that. We're going to stay financially disciplined. But Greg, can you talk about the role of the Gulf in our portfolio.

Operator:

Our next question comes from Ryan Todd with Piper Sandler.

John Hess:

Greg?

Ryan Todd:

Perfect. And then maybe a follow-up on an earlier comment. You talked a little bit about the dividend, the desire to grow it to a position of competitiveness. How would you define -- I mean, you've obviously increased it materially earlier this year, but how would you define a competitive dividend? What peer group are you looking at? And any thoughts on kind of the timetable of over which you'd like to grow that dividend to kind of a sustainable level where you'd like it to be?

John Rielly:

Sure. So I mean John did give a good explanation on that, but that's clearly what we're looking to do, continual increases here. And John did mention it that we'd like to get our dividend to a level that is attractive to the income-oriented investors. So I think yield is an output, but you can think about the yield that the income-oriented investors are looking at. So with our ability here, again, as I mentioned, Bakken growing to 200,000 barrels a day and then Guyana, Payara coming in late 2023 and then almost an FPSO a year here as we move out the next couple of years, we're going to have a significant free cash flow that we're able to continue to increase the dividend and we can kind of move that dividend as our cash flow grows. But actually, the bigger part of our return will be share repurchases because that growing free cash flow when you put that 75% against that as we will grow that dividend, we want to make it sustainable in a low oil price environment, but the bigger portion ultimately will be share repurchases.

Neil Mehta:

I had a couple of questions on the macro. And the first is around price realizations, they were good in the quarter. And John, you had made the comment that what we see in the financial markets, it might be lower than what you're realizing in the physical market. So can you just talk about that divergence and whether you're able to realize something higher than the front price?

Neil Mehta:

And the follow-up is on natural gas. And so we do love your perspective on how you're thinking about U.S. natural gas, in particular -- and if anything structurally changed in your view of mid-cycle? And then as it relates to your hedging position, remind us how open you are over the next couple of years? And can you participate in the strengthening commodity curve.

John Rielly:

Sure. So for hedges for next year, we do not have any hedges on in 2023 or beyond at this point. Now, you know our strategy, and you should assume that we'll continue with that strategy is to put a floor price on. So as we get to the end of the year, we'll use puts, obviously, where volatility is, that from everything that John has been discussing on this call and also just the time aspect of the put options. We'll be putting them on closer to the end of the year or early into next year. That's typically the time frame that we do that. But we do want to put a floor on. You can expect us to do that again next year and years after to just again to provide that insurance, should prices -- should there be a change? Should there be a recession or something happening that drops those prices, but we'll do that towards the end of the year.

Roger Read:

Maybe just follow up on some of the last discoveries here in Guyana and some of the stuff before. Where are you in terms of drill stem tests, flow rate tests, things like that as we try to think about some of the things that will eventually raise -- more than likely raise the 11 billion-barrel resource target that's out there.

Greg Hill:

Yes. So as we said, these 2 discoveries, Seabob and Kiru-Kiru, which are still underway, so those will be additive to the already announced 11 billion barrels gross recoverable hydrocarbons. I think the significant part about these discoveries is why they're so encouraging is that if you look at Seabob, that is leading to a potential inboard oil play in the southeastern part of the Stabroek Block. And in fact, as we look forward, the next 2 wells, Yarrow and Banjo will help further delineate that inboard oil opportunities. So there could be another oil FPSO centered on that inboard oil play. So as you mentioned, after we get these wells done, we'll do some DSPs, et cetera, on them really trying to prove up really that inboard oil play. So very, very exciting.

John Hess:

John, do you want to answer that part?

John Hess:

Yes. And I think, Roger, the other thing is Greg and his team moved expeditiously this secure excellent equipment with Nabors and also with -- and cruise with Halliburton as well. So some of our competitors, I don't think are as well positioned as we are to have high-quality equipment and people. And I think that will inure to our benefit as we go into next year to mitigate the cost pressures plus the fact that Greg and his team are leaders of the manufacturing and have a proven track record of mitigating cost increases. So the exact number, as John said, we’ll give you at the end of the year, but I think we're staying ahead of it and taking steps to mitigate whatever that impact is.

Vin Lovaglio:

The first question was just on debottlenecking work at Liza Phase 1. I was just wondering if you could remind me about the investment required to get those 20,000 barrels extra online? And then probably more importantly, your ability to carry over a similar debottlenecking work to future projects.

Greg Hill:

Yes, sure. So the investment level to get to that new nameplate of that new capacity of 140,000 barrels a day from the 120 on Phase I, very minimal. I mean this was some piping changes, et cetera. So you shouldn't think about that as a major investment on Phase 1. As we look forward to future phases, certainly in Phase II and also Payara, I think we could see the potential for additional debottlenecking for those 2 vessels. Beyond that, as your vessels get bigger, say, the 250 class, we'll have to wait and see. And I think the important thing to remember about these debottlenecking efforts is it's going to be bespoke for each vessel. So it's going to depend on the individual dynamics of that vessel operating as to how much additional capacity you can eke out of it. So hopefully, that answers your question.

John Hess:

Yes. We certainly intend to increase the dividend each year and at a moderate pace, but 1 that builds value over time that will be sustainable, but also meaningful.

David Deckelbaum:

I really only had, I think, 1 additional follow-up to some of the other questions that were answered already. But as we think about -- you've thrown out the 200,000 a day target in the Bakken as a most optimal level of performance for the asset. Just given some of the inflation that we're seeing there, some of the inflation that we're seeing both on the unit cost size, is 200,000 still the right number? And is there -- is that still a steady-state 4 rig program? Or just given the move in higher pricing if we were to believe in the long-term price at higher given some of the inflation, do all of these numbers move slightly higher?

Greg Hill:

No. Look, I think if you look at our portfolio, we've got 2,100 or more drilling locations that generate great returns at a $60 WTI. So obviously, at current prices, those returns are fantastic, right? And so certainly, the movement in the oil price from a return standpoint is outstripping any inflationary effects. And the 200,000 barrel a day kind of plateau rate, if you will, for the Bakken is absolutely the optimum place to be because it really fills up all the infrastructure that we have in place in the Bakken. So you need to think about future wells as almost like a tieback in the Gulf of Mexico. The infrastructure is already there. So the incremental returns are very high for those Bakken wells. So we'll hold that with the portfolio we have, we'll hold that for rigs and be able to hold that plateau at about 200,000 barrels a day for almost a decade, all the while, the Bakken generating significant amount of free cash flow during that period. So at $60, it generates over $1 billion of free cash flow. Obviously, current price is much higher. So it becomes this massive cash annuity for the portfolio at that 200,000 barrels a day.

Jay Wilson:

Thank you, Liz. Good morning, everyone, and thank you for participating in our first quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC. Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case there are audio issues, we will be posting transcripts of each speaker's prepared remarks on www.hess.com following the presentations. I'll now turn the call over to John Hess.

Greg Hill:

Thanks, John. Let's begin with several positive developments on the Stabroek Block that have created significant long-term value for the people of Guyana and our shareholders. Current production on the Liza Destiny FPSO is 130,000 barrels of oil per day, ahead of its original base nameplate capacity and is expected to increase to more than 140,000 gross barrels of oil per day over the course of this quarter. Production on the Liza Unity FPSO is ramping up ahead of schedule and is expected to reach its gross capacity of 220,000 barrels of oil per day by the third quarter. The Payara development is also ahead of schedule and is now forecast to start up in late 2023 versus 2024 previously. Pulling forward production start-up reflects strong execution by the operator and significantly enhances the net present value of the project. The Payara development will utilize the Prosperity FPSO with a gross capacity of 220,000 barrels of oil per day. In April, we sanctioned the Yellowtail development. This project is designed to develop 925 million barrels of oil and will utilize the 1 Guyana FPSO with a gross capacity of 250,000 barrels of oil per day and first oil is planned in 2025. We have also made 5 additional discoveries this year, which have increased the estimate of gross discovered recoverable resources to approximately 11 billion barrels of oil equivalent. We have also faced some challenges this year in the form of transitory weather issues in the Bakken and cost inflation across our portfolio. In March, we revised our Bakken and company-wide first quarter and full year 2022 production guidance lower to reflect impacts from severe weather in North Dakota as well as higher NGL prices in the first quarter, which enhanced profitability but reduced production entitlements under our percentage of proceeds contracts. These weather conditions continued in April but are transitory, and we expect to recover and resume normal operations over the balance of the second quarter. Like our competitors, we are also seeing upward cost pressure across both our onshore and offshore business. We are mitigating many of the effects through lean manufacturing, strategic partnerships with key service providers and technology-driven cost efficiency gains. Nevertheless, we now expect additional cost inflation of approximately 3% to 4% on our 2022 capital program, including higher drilling and completion costs in the Bakken that we now expect to average approximately $6.2 million per well or 7% above last year. Of course, higher oil prices are also driving much higher earnings and cash flow. Now let's review our operating results and forecast. In the first quarter, company-wide net production averaged 276,000 barrels of oil equivalent per day, excluding Libya, which was above the high end of our revised guidance range of 270,000 to 275,000 barrels of oil equivalent per day that we provided in March. For the second quarter, we forecast that company-wide net production will average approximately 310,000 barrels of oil equivalent per day, which is 12% above last quarter. For the full year 2022, we now forecast our company-wide net production to be at the low end of our 325,000 to 330,000 barrels of oil equivalent per day guidance range due to the previously mentioned weather impacts in the Bakken in April. In the Bakken, net production in the first quarter averaged 152,000 barrels of oil equivalent per day compared to our revised guidance of 150,000 barrels of oil equivalent per day. In the first quarter, we drilled 19 wells and brought 13 new wells online. In the second quarter, we expect to drill approximately 22 wells and to bring approximately 18 new wells online. And for the full year 2022, we expect to drill approximately 90 gross operated wells and to bring approximately 85 new wells online. For the second quarter, we forecast that Bakken net production will average between 140,000 and 145,000 barrels of oil equivalent per day and that our full year 2022 net Bakken production will be near the bottom of our previous guidance range of 160,000 to 165,000 barrels of oil equivalent per day, again reflecting the severe weather impacts. Net production in the Bakken, however, is expected to build in the second half of the year, reaching 175,000 to 180,000 barrels of oil equivalent per day in the fourth quarter, with more wells online and improving weather conditions. We plan to bring approximately 54 new wells online in the second half of this year compared with 31 wells in the first half. It's also important to note that well results have been strong with IP180s and EURs comparable to last year's results. As John mentioned, we're giving strong consideration to adding a fourth operated drilling rig later this year. Moving to the Gulf of Mexico. First quarter net production averaged 30,000 barrels of oil equivalent per day, which was within our guidance range of 30,000 to 35,000 barrels of oil equivalent per day. In the second quarter, we expect to maintain net production of approximately 30,000 barrels of oil equivalent per day. And for the full year 2022, we forecast net production to average between 30,000 and 35,000 barrels of oil equivalent per day, reflecting the addition of the Shell-operated Llano 6 well in which Hess has a 50% working interest late third quarter. The well will spud in May by Shell and will be tied back to Shell's Auger platform, with gross production from the well expected to build to a plateau rate of between 10,000 and 15,000 barrels of oil equivalent per day by the end of the year. The Gulf of Mexico is an important cash engine and a platform for growth for the company. We have multiple options for tiebacks to over -- to our 3 Gulf of Mexico hubs, including both infill and near-field exploration prospects. Recent acquisition and processing and proprietary ocean bottom node 3D seismic across all 3 areas has identified opportunities for drilling in 2023 and beyond. In terms of -- for Mexico exploration, we spud the Huron-1 well in February on Green Canyon Block 69, where we are targeting a hub class Miocene opportunity. Results are expected during the second quarter. Hess is the operator with a 40% working interest and Shell and Chevron each have a 30% interest. Moving to Southeast Asia. First quarter net production was 64,000 barrels of oil equivalent per day, in line with guidance. Second quarter and full year 2022 net production are forecast to average approximately 65,000 barrels of oil equivalent per day. Now turning to Guyana. Our discoveries and developments on the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, are world-class in every respect with some of the lowest project breakeven oil prices in the industry. First quarter net production averaged 30,000 barrels of oil per day, which was at the high end of our guidance range of 25,000 to 30,000 barrels of oil per day. As a result of the Liza Phase 1 optimization work and the continued ramp-up of Liza Phase 2, we forecast second quarter net production from Guyana to average between 70,000 and 75,000 barrels of oil per day and to increase to 85,000 to 90,000 barrels of oil per day in the fourth quarter. Our full year 2022 net production guidance for Guyana remains unchanged at between 65,000 and 70,000 barrels of oil per day. Turning to exploration. In January, we announced significant discoveries on the Stabroek Block at Fangtooth and Lau Lau wells. Positive results at Fangtooth, our first stand-alone deep exploration prospect, will help confirm the deeper potential of the block. Lau Lau further underpins our queue of future low-cost development opportunities in the southeastern portion of the Stabroek Block. Yesterday, we announced discoveries at Barreleye, Lukanani and Patwa, all of which will require appraisal but will further underpin future developments on the block. Upcoming wells in the second quarter will include CBOB targeting Campanian reservoirs and located 10 miles south of Yellowtail; and Kiru targeting Campanian and Santonian reservoirs and located 3 miles southeast of Catabac. A Fangtooth appraisal well is also planned for the fourth quarter of this year. Moving to Suriname. Planning is underway on Block 42 for drilling the Zanderi-1 prospect around midyear. The well will target both Campanian and Santonian aged reservoirs. We see the acreage as a potential play extension from the Stabroek Block with similar play types and trap styles. Hess, Chevron and Shell, the operator, each have a 1/3 interest in the block. In closing, while we are managing some short-term issues with weather and cost inflation, our long-term outlook has never been brighter. Our distinctive strategy and world-class portfolio have positioned us to deliver differentiated value to our shareholders for many years to come. I will now turn the call over to John Rielly.

Operator:

[Operator Instructions] Your first question comes from the line of Doug Leggate with Bank of America.

John Hess:

Yes, Doug, great question. I think ExxonMobil will be addressing that on their call, I understand, but we're sticking to the guidance that we gave, which by 2026 will be -- '27 will be over 1 million barrels a day of capacity. And I'd say that's a conservative number.

John Rielly:

No, Doug. It really has not changed. If you read our 10-K, so we do have a U.S. net operating loss in excess of $16 billion here for the U.S. So from a cash tax payment, the horizon really hasn't changed, so we do not anticipate paying cash taxes in the next 5 years or more.

John Rielly:

I don't want to go out that far, Doug, but yes, nothing in the near term.

Paul Cheng:

Couple of questions. And I think with Payara, the schedule is being pushed forward. John, you talked about the potential inflation impact for 2022 as well as the fourth rig that [indiscernible]. How about for the Payara? The good thing is that you accelerate the development. How about in terms of the budget impact?

John Rielly:

Yes. And just to add to that, Paul, we don't have anything really right now from an add to our 2022 capital budget related to Payara. The Guyana developments are actually -- this is really just great execution by Exxon and SBM. So there's been no add to our budget for this acceleration of the Payara start-up.

John Rielly:

Yes, sure. So again, with this year, right, let's just do a reasonable approximation, as Greg mentioned, 3% to 4% inflation so that's $80 million to $100 million on this year, plus adding the fourth rig, which we're giving serious consideration to, up to $100 million. So look, let's talk this year with an approximation around $2.8 billion. And then I just have to remind everybody going back like to the Guyana lifts, with 2 lifts in the first quarter, 7 in the second, 8 in both the third and fourth, that we're -- even with any increase in our capital budget, we're going to have significant cash flow growth and significant free cash flow growth throughout this year. Then start talking about next year. Now with Payara coming forward, it obviously accelerates our cash flow growth from our previous profile. So again, this durability story on our cash flow growth really can -- goes out, as John was mentioning earlier, to 2027. So when you look at the capital increase for next year, so what that really means if we accelerate this fourth rig in, and if I can just round it to $100 million, typically adding a rig is $200 million, rule of thumb. So for a full year, you're going to add another $100 million then to -- from Bakken standpoint. Then Guyana, to your point, I just want to say you did say it's early so this is early, but clearly, there will be some increase in Guyana capital, nowhere near matching this increase in cash flow growth that will be happening because at that point, now you're going to have finishing up work on Phase 2 but then you're going to have Payara in full swing. You got Yellowtail and then really that fifth FPSO that we talked about. So we're going to have those 3 FPSOs in capital. So there will be an increase, can I say, several hundred million in that capital in Guyana as you move into next year. Should be some offsets then. Southeast Asia down a little bit from this year. But that's kind of a rule of thumb, I would say, Paul. But the biggest thing for us is we've got this just increase in cash flow starting really next quarter with Guyana and now with Payara coming next year. First, we have Phase 2 and Phase 1 operating at full capacity and then Payara coming in, so significant cash flow growth tied into some additional capital.

John Rielly:

So the way I would look at it is we picked up this inflation for the second half of the year. It's really -- that's what's happening. A lot of it, we did have some tubular steel kind of locked up in the first half, and we're seeing some increases now going into the second half of the year. So we're picking it up for half the year. I don't necessarily think you then need to double this as you move forward. We'll see what happens with oil prices and basically industry investment, too, for next year. So at this point, I wouldn't want to guide to that kind of level, Paul. And again, we do everything we can with lean and with different technology as well as, again, a lot of these contracts for Guyana, as Greg mentioned, we've kind of fixed these prices that we have so far. So at this point, I think it's early for us to talk about what the inflation will be next year.

John Rielly:

Sure.

John Rielly:

Okay. So as mentioned previously, from a cash tax standpoint, we will not be incurring cash taxes, let me just say, for 5 years or anything in the near term. To your point, what happens now with higher prices and more income here in the U.S., we have a full, what we call, sorry, this is going to be accounting technical, valuation allowance against that net operating loss. So there will come a point in time where we will release that valuation allowance, effectively book a big gain, increase equity. And then what would happen is, as you use the NOL, we would be recording deferred tax expense. The exact timing of that, Paul, I don't know at this point. But again, this would all be noncash from that standpoint.

Arun Jayaram:

Yes. My first question goes back to the Yellowtail FID. Greg, you FID-ed that with Exxon at a gross cost of $10 billion, which is, call it, $1 billion more than Payara yet. You're doing a lot more wells, 51 versus 41, a lot more resource and we are in a more inflationary environment. So I was wondering if you could kind of walk through the cost numbers at Yellowtail, which was a little bit lower than we were thinking, just given some of the inflationary pressures.

Arun Jayaram:

Great. And just my follow-up, Greg, I was wondering if you could just maybe give us a little bit more detail on some of the transitory weather issues in the Bakken. We're seeing, call it, gas flows are running, call it, 400 million a day in the basin versus 2.1 Bcf a day or so, which is more typical. So can you give us more details on the weather event and how this is impacting you and the rest of the industry in April and maybe any implications for the rest of the year?

Operator:

Your next question comes from Jeanine Wai with Barclays.

John Hess:

Sure. No. Great question, Jeanine. I think a couple of perspectives on this. Obviously, we have a unique value proposition that we offer, which is industry-leading cash flow growth of compounding 25% a year each year out for the next 5 years based upon $65 Brent. So we certainly can see the visibility of our cash flow growth compounding and our free cash flow along with it. In terms of the timing of the share repurchases and commencing that, look, based upon market conditions and our significant cash flow growth that John Rielly was discussing earlier, we will give serious consideration to commencing our share repurchases this year. And as we look forward, we plan to continue increasing our regular dividend to a level that is attractive to income-oriented investors, as we said, but also sustainable in a low price environment. And as our free cash flow generation steadily increases, share repurchases will represent a growing proportion of our return of capital. We will try as best we can to be opportunistic in buying our stock, buying more on dips. But at the same time, we do have a commitment to, on an annual basis, to return 75% of our free cash flow annually. But as you look forward, we'll continue to grow our dividend and then the greater proportion of our return of capital will be share repurchases. And based upon the market and cash flow growth for this year, we'll give serious consideration to moving forward with our share repurchases this year.

GregHill:

Thank you for the question. We're very pleased with the results. As you mentioned, Barreleye, 230 feet of hydrocarbon-bearing reservoirs and 52 feet of that was high-quality oil bearing. Lukanani, 115 feet of sandstone, 76 of which was high-quality oil-bearing, so very, very pleased. And as you mentioned, it does -- these are further step-outs. And I think what it does show is just how massive this accumulation is down in Guyana, and it just keeps getting bigger and better as we continue to grow. And then we talked about Patwa, 108 feet of hydrocarbon-bearing sandstone reservoirs. Now what do all 3 of these mean? Well, they basically have allowed us to increase expected gross recoverable hydrocarbons to approximately 11 billion barrels, including Fangtooth and Lau Lau that we announced earlier in the year. Now how and when these resources will get developed to be a function of appraisal drilling results and development studies, but we are very pleased with the results of all of the wells that we've seen this year, met or exceeded all of our expectations.

Neil Mehta:

A lot of the questions have been asked already, so I'll do 2 quick ones here. The first is, as you think about taking up that fourth rig in the Bakken, any gating factors in terms of executing it? Certainly, the commodity price environment would suggest it could make sense, but just any questions around that -- comments around that. And the second is, John, any perspective on the relationship you have from a regulatory and a fiscal perspective in Guyana. It seems like that has been stable, but given it represents a disproportionate amount of the asset value, we always want to stay on top of any inflections that might be happening there.

John Hess:

Yes. And Neil, in terms of the Guyana government, our company and our joint venture have an excellent working relationship, a very constructive one with the government. Testament is the early April approval of Yellowtail. The government has been very clear with us that they would like us as a joint venture to accelerate the development of their oil resources to basically improve the prosperity and have shared prosperity for all Guyanese citizens. So it's a very constructive working relationship. It continues. We also want to help the government in social responsibility as well, trying to make a better future for all Guyanese. So it's an excellent relationship and we continue to work with them. And as I said before, ExxonMobil has done an outstanding job on project management and execution, bringing a lot of value forward for our joint venture, for the people of Guyana and for our shareholders in the excellent achievements they've had in terms of being really ahead of schedule now on Liza Phase 1, ahead of schedule on Liza Phase 2, ahead of schedule on Payara. And that track record is to the benefit of the Guyanese people as well as our shareholders.

Roger Read:

Seems like the Bakken fourth rig thing has been hit quite a bit, but I do have just 1 question on that. What, at this point, would be the reason for not pulling the trigger on that at some point this year? Meaning would it be hard to get a rig in the Bakken with crew and all the other associated items you need or is it just an internal decision on your part?

Roger Read:

Okay. And then comments earlier about inflation at the CapEx side, which all makes sense. I was just curious and not trying to go against the guidance on the LOE side, but what should we think about in terms of inflationary pressures, if any, at the cash OpEx level?

Operator:

Your next question comes from Bob Brackett with Bernstein.

John Rielly:

No. Not really, Bob. Now look, we did set that out in a $65 world, that's for sure. That was how we set that up. All our forecasts going out is in a $65 world. So obviously, there can be impact. Again, like I just mentioned, with production taxes being higher from that standpoint. But you are correct that really what drives that down is Guyana. And in fact, if you look just at our numbers and the guide I gave and you just did the math on the second half of the year, second half of the year has to average about $12.60 on that cash cost to get to those numbers basically in the midpoint. And what's going to happen is third quarter will be a little bit higher, and then the fourth quarter is going to be lower than that $12.60. Why? Again, because Guyana continues to build up its production. So the more and more now that Payara is moving up early, and that it's -- to your point, it's that mix and having Guyana just drive down our cash costs, as well as Greg mentioned, getting that fourth rig on, we'll optimize our infrastructure and lower our unit cost in the Bakken as well.

GregHill:

No. There's also a Redtail discovery that's being tied into that as well.

GregHill:

And then, Bob, I think also we -- as we've mentioned before, the plateau on all of these vessels, really, they're all going to be -- they'll all be bespoke, but I think you could assume extended plateaus on all the vessels as we go out in time, just because of resource density in and around these hubs. So they'll be longer than what a typical deepwater development would be. But again, they'll all be different.

Jay Wilson:

Thank you, Josh. Good morning everyone and thank you for participating in our fourth quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today’s conference call contains projections and other forward-looking statements within the meaning of the Federal Securities Laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess’ annual and quarterly reports filed with the SEC. Also on today’s conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the call with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case of any audio issues, we will be posting transcripts of each speaker’s prepared remarks on www.hess.com following the presentation. I’ll now turn the call over to John Hess.

Gregory P. Hill:

Thanks, John. 2021 was another year of strong operating performance and strategic execution for Hess. Starting with reserves, proved reserves at the end of 2021 stood at 1.3 billion barrels of oil equivalent. Net proved reserve additions in 2021 totaled 348 million barrels of oil equivalent, including positive net price revisions of 107 million barrels of oil equivalent, resulting in an overall 2021 production replacement ratio of 295% and a finding and development cost of approximately $5.25 per barrel of oil equivalent. Now turning to production. In the fourth quarter and full year 2021, company-wide net production averaged 295,000 barrels of oil equivalent per day, excluding Libya in line with our guidance. For the full year 2022, we forecast net production to increase by 12% to 15% and average between 330,000 and 340,000 barrels of oil equivalent per day, excluding Libya. For the first quarter of 2022, we forecast net production to average between 275,000 and 285,000 barrels of oil equivalent per day, excluding Libya. This forecast reflects the impacts of severe weather in the Bakken, remedial maintenance work at the Baldpate and Penn State fields in the Gulf of Mexico, and planned downtime on the Liza Destiny FPSO for production optimization work. Companywide net production is forecast to significantly increase over the course of the year driven both by Guyana and the Bakken, with the fourth quarter expected to average between 360,000 and 370,000 barrels of oil equivalent per day. In the Bakken, both fourth quarter and full year 2021 net production were in line with our guidance, averaging 159,000 and 156,000 barrels of oil equivalent per day respectively. We have a robust inventory of approximately 2,100 drilling locations in the Bakken that can generate attractive returns at $60 WTI, representing approximately 70 rig years of activity. In 2022, we plan to operate three rigs and expect to drill approximately 90 gross operated wells and bring approximately 85 new wells online. In the first quarter of 2022, we plan to drill approximately 22 wells and bring 10 new wells online. For the balance of the year, we expect to bring online an average of 25 wells per quarter. In 2021, our drilling and completion cost per Bakken well averaged $5.8 million, which was $400,000 or 6% lower than 2020. In 2022, we expect to fully offset anticipated inflation through lean manufacturing and technology driven efficiency gains, and therefore D&C costs are expected to be flat with last year at approximately $5.8 million per well. For the full year 2022, we forecast Bakken net production to average between 165,000 and 170,000 barrels of oil equivalent per day, a 6% to 9% increase over 2021. First quarter net production is forecast to average between 155,000 and 160,000 barrels of oil equivalent per day. Beginning in the second quarter we expect to benefit from the addition of the third rig, which we added last September, and improving weather conditions. Net Bakken production is forecast to steadily ramp over the course of 2022 and to average between 175,000 and 180,000 barrels of oil equivalent per day in the fourth quarter. Moving to the offshore, in the Deepwater Gulf of Mexico, net production averaged 39,000 barrels of oil equivalent per day in the fourth quarter and 45,000 barrels of oil equivalent per day for the full year 2021, in line with our guidance. The Deepwater Gulf of Mexico remains an important cash engine for the company as well as a platform for growth. In 2022, we will resume drilling operations after a two-year hiatus, with one tieback well planned at the Shell-operated Llano Field, and one exploration well planned at the Hess-operated Huron prospect on Green Canyon Block 69. Over the last five years, we have focused our efforts on getting best in class imaging across our acreage position in Northern Green Canyon, where we believe there is high potential for multiple, high-return hub class Miocene opportunities. Huron is the first of these opportunities, which attracted interest from multiple parties during the farmout process. We expect to spud Huron in the first quarter, with Hess having a 40% working interest as operator and Shell and Chevron at 30% each. As part of our agreements with Shell and Chevron, we have also accessed additional Miocene prospects across Green Canyon and are excited about further potential in the play. In February, Shell plans to spud the Llano-6 development well, in which Hess has a 50% working interest. The well will be tied back to Shell’s Auger platform, with gross production from the well expected to build to a plateau rate of between 10,000 and 15,000 barrels of oil equivalent per day by the end of this year. For the full year 2022, we forecast net production in the Gulf of Mexico to average approximately 35,000 barrels of oil equivalent per day. First quarter net production is forecast to average between 30,000 and 35,000 barrels of oil equivalent per day. In Southeast Asia, net production from the Joint Development Area and North Malay Basin, where Hess has a 50% interest, averaged 66,000 barrels of oil equivalent per day in the fourth quarter and 61,000 barrels of oil equivalent per day for the full year 2021, in line with our guidance. For the full year 2022, we forecast net production in Southeast Asia to average approximately 65,000 barrels of oil equivalent per day. In the first quarter, we forecast net production to average between 60,000 and 65,000 barrels of oil equivalent per day. Turning to Guyana, where Hess has a 30% interest in the Stabroek Block and ExxonMobil is the operator. We have continued our extraordinary run of exploration success and increased our estimate of gross discovered recoverable resources to more than 10 billion barrels of oil equivalent. Net production from Guyana averaged 31,000 barrels of oil per day in the fourth quarter of 2021 and 30,000 barrels of oil per day for the full year 2021, in line with our guidance. For the full year 2022, we forecast net production in Guyana to average between 65,000 and 70,000 barrels of oil per day. In the first quarter we forecast net production from Guyana to average between 25,000 and 30,000 barrels of oil per day reflecting planned downtime on the Liza Destiny for production optimization as previously mentioned, and net production in the fourth quarter will increase to between 85,000 and 90,000 barrels of oil per day. Earlier this month we announced significant discoveries on the Stabroek Block at Fangtooth and Lau Lau. Positive results at Fangtooth, our first standalone deep exploration prospect, help confirm the deeper exploration potential of the Stabroek Block. In the coming months, we will complete the analysis of the exploration well results. Appraisal activities will then be conducted to determine the optimum development approach and timing. Lau Lau further underpins our queue of future low-cost development opportunities in the Southeastern portion of the Stabroek Block. This discovery will also require appraisal to determine the ultimate development approach and timing. We continue to see multi billion barrels of exploration potential on the Stabroek Block and in 2022, we plan to drill approximately 12 exploration and appraisal wells that will target a variety of prospects and play types. These will include lower risk wells near existing discoveries, higher risk step outs, and several penetrations that will test deeper Lower Campanian and Santonian intervals. Exploration wells planned for the first quarter of 2022 include; Barreleye-1, located approximately 20 miles Southeast of Liza. The primary target is lower Campanian with shallow and deeper secondary targets. The well spud on December 30th. Tarpon-1, located approximately 63 miles Northwest of Liza, will target lower Campanian clastics, plus a deeper Jurassic carbonate. The well will spud following completion of Fangtooth operations. Patwa-1 is near our Turbot area discoveries. The well is approximately 3 miles Northwest of the Cataback-1 discovery, with targets in upper Cretaceous clastic reservoirs. This well is anticipated to spud in March. Lukanani-1 is in the Southeastern part of the Stabroek Block, located approximately 2 miles west of Pluma and is anticipated to spud in March. The primary target is Maastrichtian age clastic reservoirs, with secondary objectives in lower Campanian reservoirs. The appraisal program in 2022 will be focused on delineating future developments. First quarter appraisal activities will include the Tilapia-2 appraisal well, located approximately 24 miles Southeast of Liza-1. The well will appraise the February 2019 Tilapia-1 discovery in the Turbot area and is anticipated to spud in March. In addition, we plan to conduct drill stem tests at Tilapia-1 and Pinktail-1. Turning now to our Guyana developments. Development activity this year will include drilling for both the Liza Phase 2 and Payara projects. Initial development drilling activities will also begin for the Yellowtail project following approval of the Field Development Plan by the government. A planned turnaround will be conducted in March on the Liza Destiny FPSO. Work activities will include production optimization work, designed to increase the vessel’s production capacity. At Liza Phase 2, the Liza Unity FPSO vessel is undergoing final hookup and commissioning after arriving in Guyanese waters in October 2021. Unity is on track to start production in the first quarter of 2022 with a capacity of approximately 220,000 gross barrels of oil per day. With regard to our third development, at Payara, the overall project is 66% complete. SURF activities are progressing ahead of plan and we are preparing for a 2022 installation campaign. The hull for the Prosperity FPSO vessel is complete, and topside construction activities are ongoing in Singapore for planned production start-up in 2024. The Field Development Plan and Environmental Impact Assessment for the fourth potential project, Yellowtail, have been submitted for government and regulatory review. The government is supportive of the project and startup remains on track for 2025. We look forward to continuing to work with the Government of Guyana and our partners to realize the extraordinary potential of this world class project. Moving to Suriname, planning is underway for our second exploration well on Block 42 at the Zanderij-1 prospect targeting the Santonian and Deep play potential. The operator, Shell, has indicated that they expect to drill the well around mid-year. We see the acreage as a potential play extension from the Stabroek Block, with similar play types and trap styles. Shell, Chevron and Hess each have a one third working interest in Block 42. In closing, our execution continues to be strong. The start-up of Liza Phase 2 and steadily increasing production in the Bakken are expected to drive an approximate 30% increase in net production between the first quarter and fourth quarter of 2022 along with a significant increase in operating cash flow, which will underpin our commitment to increase cash returns to shareholders. I will now turn the call over to John Rielly.

Operator:

[Operator Instructions]. Your first question comes from the line of Jeanine Wai with Barclays.

John B. Hess:

Jeanine, thank you. In terms of our return of capital framework, once the lease of Phase 2 is up and producing oil, we will pay off the $500 million remaining on our term loan and we'll start to increase our base dividend. At that time, we'll also communicate our return of capital framework, not just where we want to take the dividend but also how we plan on returning our free cash flow. As a reminder, as you have said earlier, we've been consistent in saying that our cash flow compounding as it does, we intend to return the majority of our free cash flow to our shareholders by further increasing our dividend and also accelerating share repurchases. And in terms of the dividend itself, the base dividend as our cash flow grows, we plan to have a dividend that will have a meaningful premium to the S&P 500 dividend yield.

John P. Rielly:

Sure, Jeanine. Basically, we had tax and royalties related to our production on the Waha concessions. And these taxes and royalties were held by Hess and our other Waha partners after receiving instructions from the Libyan authorities to withhold payment. Then, just recently the authorities instructed us to make those payments so we did release it. Hess and our partners released those taxes and royalties paid during January as it was mentioned in the release and I mentioned earlier in my discussion. Going forward, this is just normal taxes and royalties related to our production. It's typically paid monthly. We expect it to be paid monthly here in 2022. So that's what I would say the go forward is. And just so you know, I mean, all those things are just normal taxes and royalties, they were all accrued, all in earnings, all in cash flow from operations during 2021.

Jeanine Wai:

Great, thank you.

Operator:

Thank you. Your next question comes from Arun Jayaram with J.P. Morgan.

John B. Hess:

Yeah, no. It is a great question. We will be coming out with a framework that will be pretty clear about how we allocate capital, but also how we intend and how much we intend of our free cash flow to return. It will have some flexibility in it. But it will be very clear of our commitment to return the majority of our free cash flow to our shareholders. By further increasing the dividend they will have their first piece in the dividend, once lease of Phase 2 is up and running and producing oil. But then we will intend as our cash flow compounds, the majority of that free cash flow go back to our shareholders by further increasing the dividend and also accelerating the share repurchases. I think the return of capital framework when we announce it will be clear and help provide clarity to the question you're asking.

Gregory P. Hill:

Sure. So let me take your second question first Arun. So, as I mentioned in my opening remarks, the objectives of the program this year are twofold, like they always have been. The first one being to explore for new opportunities. So that includes things in the upper Campanian, but also more penetrations in the deeper section that we saw as Fangtooth, right. And so if you look at the 12 wells that we're going to do this year, about two thirds of those wells are exploration wells, and about one third is appraisal wells. So pretty active this year on the exploration side. And again, we're going to be testing deeper zones and also shallower zones with that exploration program, and I kind of lined out that the first quarter my opening remarks as to where we're headed with that. And then appraisal, of course, is about appraising the existing discovery so that we can figure out what that development cue is for the playout of the vessels, the up to 10 FPSOs that we've talked about. Now, if I get back to your question on Yellowtail so first of all, the Yellowtail developments, world class economics will be the largest to date on the Stabroek Block. It's as you mentioned, it's going to develop new nearly a billion barrels of oil, have a gross capacity of 250,000 barrels a day. So it's got a little bit bigger top sides and it's also got more wells. So Payara has 41 wells, whereas Yellowtail will have 51 wells. So it's just a bigger project, very large area of extent, very fantastic reservoir. So it's going to be one of the, again, the world class economics.

Arun Jayaram:

Great, thanks a lot gents.

Doug Leggate:

Thanks. Good morning, everybody. I don't know if it's too late to say Happy New Year, but Happy New Year everybody. So, John or Greg, I'm not sure who wants to take this but I want to ask a portfolio question given you touched on the Libya news earlier. You have a very, very large footprint in the Gulf of Mexico. Obviously, you've taken advantage of [indiscernible] when no one else cared, and so on. But when I look at Payara, Yellowtail adding essentially five times the current production in the Gulf of Mexico, I got to ask if the Gulf of Mexico is a keeper longer term for the portfolio, given the effort that has to be put into maintaining the production and so on. So just long term thoughts on whether the Gulf stays in the portfolio?

Gregory P. Hill:

Yeah, sorry, took me a second to get off on mute. So Doug, as we talked before, the Gulf of Mexico remains an important cash engine and platform for growth for Hess. We have top quartile capability in both Deepwater drilling and project delivery in the Gulf. And so our objective is maintain that cash hub, sustained production and cash flow generation through both tie backs, and also selectively pursuing these high return hub glass exploration opportunities, hopefully, here on would be the first cap off the rank there. And as you said, we've been selectively rebuilding our Gulf of Mexico portfolio, acquire more than 60 lease blocks at that really low prices. And that's, again, that balance of high return tie back opportunities have class prospects, it remains a very important province for Hess, good returns in the Gulf of Mexico, and as I mentioned, we do have the capability to execute well, there. So it's a core hold for us.

John P. Rielly:

Sure, Doug. So as you know, right, once we start up Liza Phase 2, we are going to pay off the remaining $500 million of that term loan. Then our next maturity because we've got a liquidity position is until 2024, and it's $300 million. We do intend, as you said with our rising free cash flow to pay off that maturity in 2024, and then we don't have really another debt maturity until 2027. So we're happy when we pay off that 2024 amount with the absolute level of debt that we have. And if we -- let me just say it like $65 Brent and we run this out, we bring Payara on and obviously other FPSOs, we're going to drive our leverage down to under 1 times debt to EBITDAX. That's gross, debt to EBITDAX. So we're going to have really a strong, low leverage position, improving credit metrics, as I mentioned earlier. So we are happy with that debt level, that absolute debt level as our EBITDAX grows from there. And so there's no real benefit. We've run NPVs on doing some things with either just doing paying off the debt at this point. But right now, with our low leverage, we are very comfortable with leaving the debt levels where they're at. And then like we said, with that balance sheet, so strong at that point and the rising free cash flow from Payara, from Yellowtail, from the development we will then increase returns to shareholders, obviously, with the rising free cash is more of that free cash flow return versus will be share repurchases, but we'll also be growing our dividend over the time too as well. So I think we're in a really good position for this with Guyana coming on these low-cost development, strong balance sheet, and increasing return of capital to shareholders.

Operator:

Thank you. Your next question comes from Neil Mehta with Goldman Sachs.

John B. Hess:

Yes, Greg, please.

Neil Mehta:

Thanks Greg and the follow-up here is for John, and John on the hedging strategy here. So you did provide an update around the collars and increased the ceiling price there. Just talk about how you think about the optimal way to approach hedging is and John, if you don't mind, tying that into your own view of the oil macro as you've been constructive, you were near 90 Brent, is anything changing for the better or the worse relative to what you've talked about over the last couple of months?

John B. Hess:

Yes, Neil. And obviously, it does reflect a constructive view on the market and very consistent with our approach of protecting the downside and giving the majority of the upside to our shareholders. On the macro oil outlook, on the demand side, V-shaped recovery, temporary setback of about 1 million barrels a day globally because of Omicron, starting to see cases going down, thank God. We think we'll be back at pre-COVID global demand levels of 100 million barrels a day in the next month or so. And as the year unfolds, we see jet demand increasing as international travel increases and probably see a number of about 102 million barrels a day by the end of 2022. Supply side is different, it's a U-shape recovery, more sticky. Shale is growing but at a more tempered pace function of the rig count of about 604 U.S. rigs operating. We think that adds about 750,000 barrels a day over the year of increased oil production. Remember, U.S. production probably end up at the end of the year about 12.2 million barrels a day, that's still short of the 13 million barrels a day we had pre-COVID. So shale is on the recovery, but not at pre-COVID levels in terms of absolute U.S. oil production. OPEC sounds like they're going to stick to their 400,000 barrels a day increases each month as has been written by a number of commentators. A couple of countries are not meeting their quotas there. So again, I'd say, disciplined tempered recovery in OPEC plus, discipline tempered recovery in shale all of which adds up to global oil inventories, which had been a year and half ago, in April, $1.2 billion excess inventories globally. That's all been eaten up and now we see global oil inventories about 200 million barrels less than pre-COVID levels. So as you go through this year, with demand increasing, inventory is tight, not much spare capacity in OPEC plus, we're pretty constructive on the oil market. And really, the oil price is giving a signal that investment has to increase, which is why I referred to the World Energy Outlook earlier. Depending upon what scenario you pick, any credible scenario from the International Energy Agency, more investment is going to be needed to grow oil and gas supply to meet global oil and gas demand. And currently, we're not investing enough as an industry to do that. So we're going to have to have the right balance of being capital disciplined, returning capital to shareholders, but at the same time grow the resource and grow the production capacity of the world. So that's the challenge that we have ahead. And I think that also really presents a constructive oil market as the year unfolds.

John B. Hess:

Thank you.

Paul Cheng:

Hey guys, good morning. I guess two questions, one for Greg and the other one is for John Rielly. Greg, when you're looking at Fangtooth and other that you also have penetrated the different formation, is there anything you can tell us that in terms of the oil and gas ratio, in terms of the permeability, oil quality comparing to the more shale formation, is there any significant differences that we see or any kind of conclusion that you can share?

Paul Cheng:

Well, we understand that it's good, but is there any contrast or comparison you can provide in terms of the gas oil ratio, the grade of the oil and the permeability and the kind of data that you can share?

Paul Cheng:

Okay. The second question is for John Rielly that, by the fourth quarter you indicated that your unit cost is going to come down a lot because Guyana these are two went to the full capacity and all that. So what's the contract unit cost that you have by the fourth quarter in Guyana? And also that have you looked at -- I know you guys talking about next year that you may start the buyback. But have you between the variable dividend and the buyback and that the plus and minuses that have you -- that why you decided that variable dividend is not a better tool then the buyback is the right tool for the company? I'm not saying that it should be variable dividend. Just curious how the internal debate that has been the case?

John B. Hess:

Yes. Paul, is some -- is that you, Paul?

John B. Hess:

Okay. Yes. No, we were getting some feedback. In terms of the dividend, we've done studies. We don't think the variable dividend sustains the creation of long-term value. We believe strengthening the base dividend and consistent share repurchases are a better way to go. And in terms of the timing on that, as I said, once Liza Phase 2 is up and producing, we paid the $500 million of remaining debt off from our term loan. We will increase our base dividend. We will start the process of that increase. And then as you look forward in time, further dividend increases and accelerating share repurchases will be a function of market conditions and the growth in our cash flow. So the framework for that will be very clear and I think something that will be very competitive.

John P. Rielly:

Okay. So answering your last question first. Yes, that's what will be reported in our financial statements. So that's our, if you want to call it, our net cash cost on our entitlement production in Guyana. So those are those numbers. And as far as the FPSO purchases, the operator, ExxonMobil is still in discussions with SBN on the actual date of the purchases of the FPSOs. And we'll give you the specific timing of that when that is set. But having said that, as you noted, when our 2022 CAPEX release, we don't expect any purchases in 2022 or in 2023.

John P. Rielly:

You are welcome.

David Deckelbaum:

Thanks John. Thank you guys for squeezing me in here. I will try to make it quick. I had one question just on the reserve report. It looked like your net additions were organically at the drill bit, like $241 million, where you noted in the press release were primarily from the Bakken. Is that just reflecting increased gas capture or have there been some performance revisions there as well?

Gregory P. Hill:

No, there have been -- go ahead.

Gregory P. Hill:

Yes. So look, there were both performance additions in the Bakken plus we brought additional wells into our five-year plan due to price increase, which was 107. But then the other wells bringing in. So if you look at the Bakken, we had adds of about $209 million and then the price of about $119 million, specifically to Bakken, right? So both performance adds and also bringing additional wells into the five-year plan.

John P. Rielly:

So again, with our growing free cash flow and obviously, our growing cash flow and our growing free cash flow, our debt metrics are going to significantly improve as -- and basically, as each FPSOs comes on. And like I said, we are targeting to be on a gross debt to EBITDAX under one, and we will achieve that as the cash flow grows. Now I can't specifically say with the rating agencies on timing. Obviously, we are investment grade with two of them, and we're below on one, but have a positive outlook with the one. So I do expect, as our cash flow improves, that we'll become investment grade and actually we'll improve from where we are today as our cash flow grows. So what we try to do from our own strategy standpoint is we want to have a strong balance sheet, obviously, to fund the growing resource base that we have and also for further return to shareholders. So from our standpoint, that will be the outcome of our strategy of having a low leverage, strong liquidity position, which you mentioned as well. And then as each FPSO comes on, it will just continue to improve and it will improve our credit metrics as well as still providing increasing cash returns to shareholders. So the portfolio is set to be in a nice spot. As John has mentioned earlier, it is kind of the inflection year, and we'll expect to grow on it from here.

John B. Hess:

Thank you.

Ryan Todd:

Good, thanks. Maybe just a couple of quick ones. I know as we think about the medium-term outlook in the Bakken, I know you've talked about eventually wanted to get back to a four-rig program and a production plateau closer to 200,000 barrels a day. How much impact does the price of oil have on the timing of adding a fourth rig, is that something that would be possible by the end of this year, if prices stay high or is that further down the line?

Gregory P. Hill:

Yes. Again, Ryan, I think as we've talked before, the role of the Bakken in the portfolio is to be a cash engine. So any decisions on pace or timing of addition of the fourth rig is going to depend upon corporate cash flow needs and also returns. Now having said that, assuming prices hold at this relatively high level, we would look to add that fourth rig next year. And by doing so, we could then take the Bakken to 200,000 barrels a day and with the inventory we have at four rigs, we could hold that flat at broadly that 200,000 barrels a day for almost a decade with that fourth rig. Now at 200,000 barrels a day, we really maximize utilization of the infrastructure. So that would be another objective to fill that infrastructure up and, of course, at these prices the Bakken becomes this massive cash generator. And at that 200,000 barrels a day, even at $60 to $65, it generates about $1 billion of free cash flow. So you can see the real cash firepower of the Bakken.

John B. Hess:

Greg, please?

Ryan Todd:

Thanks for the help.

Bob Brackett:

Good morning all. I had a question around Payara, and I'm going to try to type a date and a percent completion. So if I'm not incorrect, Payara was sanctioned maybe five quarters ago. First production is expected maybe eight-plus quarters from now, but at the same time, it's 66% complete. So if those numbers are right, can you talk about maybe the rate limiting steps for Payara and maybe for future developments?

Gregory P. Hill:

Sure, yes. Bob, so Payara, I think, what's different about Payara is there are three offshore installation campaigns. So yes, the project is 66% complete. But because there are three installation campaigns, you will build a little bit more contingency into that project because while you don't have hurricane issues or anything down there, you do have some current issues, offshore currents during the installation campaign. So that's why there's still contingency in Payara. We agree with the operator that that's the appropriate thing to do at this stage of the project. And so we are firmly on track for a 2024 startup. A little ahead right now, but again, it's early days.

Gregory P. Hill:

You mean in terms of drilling?

Gregory P. Hill:

No Bob, it's really kind of bespoke. Some of these horizontals are longer than other ones, for example in some of these developments. So there's not a great rule of thumb that I would say because, again, each development is very bespoke on not only the length of the horizontals, but also what reservoirs they're tapping into as well.

Operator:

Thank you. Your next question comes from Noel Parks with Tuohy Brothers.

John B. Hess:

Yes. Greg?

Noel Parks:

And then are most of those deeper targets then, things that you've identified largely through seismic or are any of them -- are your expectations informed any of them by actual analogies you have or have already seen?

Noel Parks:

Okay, great. Thanks a lot.

David Heikkinen:

Good morning guys and really just making sure that I'm thinking about this correctly. You all continue to be cash taxpayers in the U.S. and Malaysia and then continue to build a cost pool at a faster pace given your spending in the ring fencing in Guyana for the next couple of years. Just thinking $80-plus oil 2022 and 2023 is, you got this, call it, the hug of higher oil prices but a bunch of higher cash taxes, but you're already essentially a full payer is the way we're thinking about it, is that correct?

David Heikkinen:

I think I said that opposite. Sorry, I got a little brain...

David Heikkinen:

Yes, you just keep building a cost pool for the next three years even at these prices.

David Heikkinen:

Yes. Okay, thanks guys. I think I said that opposite. My apologies.

David Heikkinen:

You have answered my question. Thank you all.

Phillips Johnston:

Hey guys, thanks. Just one question for Greg on the production outlook. You guys have a large ramp throughout the year, and I know you don't give specific guidance on oil production, but just wondering if you could help us with the oil mix in both the Bakken and the Gulf of Mexico and how those numbers should trend throughout the year? I realized the Bakken mix can fluctuate depending on gas capture and NGL prices, but just from a high-level perspective, should we stick with around 50% of the Bakken and around 65% or so for the Gulf of Mexico for the rest of the year?

Phillips Johnston:

Okay, perfect. Thanks Greg.

Operator:

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.

Jay Wilson:

Thank you, Josh. Good morning, everyone, and thank you for participating in our third quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today’s conference call contains projections and other forward-looking statements within the meaning of the Federal Securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess’ annual and quarterly reports filed with the SEC. Also on today’s conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case there are any audio issues, we will be posting transcripts of each speaker’s prepared remarks on our website following the presentation. I’ll now turn the call over to John Hess.

Greg Hill:

Thanks, John. In the third quarter, we continued to deliver strong operational performance, meeting our production targets despite extended hurricane related downtime in the Gulf of Mexico and safely executing a major turnaround at our Tioga Gas Plant in North Dakota. Companywide net production averaged 265,000 barrels of oil equivalent per day excluding Libya, in line with our guidance. In the fourth quarter and for the full year 2021, we expect companywide net production to average approximately 295,000 barrels of oil equivalent per day, excluding Libya. Turning to the Bakken, third quarter net production averaged 148,000 barrels of oil equivalent per day. This was above our guidance of approximately 145,000 barrels of oil equivalent per day and primarily reflected strong execution of the Tioga Gas Plant turnaround and expansion, no small task in a COVID environment that required strict adherence to extensive safety protocols to keep more than 650 workers safe. For the fourth quarter, we expect Bakken net production to average between 155,000 and 160,000 barrels of oil equivalent per day. For the full year 2021, we forecast our Bakken net production to average approximately 155,000 barrels of oil equivalent per day, compared to our previous guidance range of 155,000 to 160,000 barrels of oil equivalent per day. This guidance reflects an increase in NGL prices, which reduces volumes under our percentage of proceeds contracts, but significantly increases this year’s earnings and cash flow. In the third quarter, we drilled 18 wells and brought 19 new wells on line. In the fourth quarter, we expect to drill approximately 19 wells and to bring approximately 18 new wells on line. And for the full year 2021, we continue to expect to drill approximately 65 wells and to bring approximately 50 new wells on line. In terms of drilling and completion costs, although we have experienced some cost inflation, we are maintaining our full-year average forecast of $5.8 million per well in 2021. Since February, we had been operating two rigs, but given the improvement in oil prices and our robust inventory of high-return drilling locations, we added a third rig in September. Moving to a three-rig program will allow us to grow cash flow and production, better optimize our in-basin infrastructure and drive further reductions in our unit cash costs. Now, moving to the offshore. In the deepwater Gulf of Mexico, third quarter net production averaged 32,000 barrels of oil equivalent per day, compared to our guidance range of 35,000 to 40,000 barrels of oil equivalent per day. Our results reflected an extended period of recovery following Hurricane Ida, which caused power outages at transportation and processing facilities downstream of our platforms. Production was restored at all of our facilities by the end of September. In the fourth quarter, we forecast Gulf of Mexico net production to average between 40,000 and 45,000 barrels of oil equivalent per day. For the full year 2021, our forecast for Gulf of Mexico net production remains approximately 45,000 barrels of oil equivalent per day. In Southeast Asia, net production in the third quarter was 50,000 barrels of oil equivalent per day, in line with our guidance of 50,000 to 55,000 barrels of oil equivalent per day, reflecting the impact of planned maintenance shutdowns and lower nominations due to COVID. Fourth quarter net production is forecast to average approximately 65,000 barrels of oil equivalent per day and our full year 2021 net production forecast remains at approximately 60,000 barrels of oil equivalent per day. Now, turning to Guyana. In the third quarter, gross production from Liza Phase 1 averaged 124,000 barrels of oil per day or 32,000 barrels of oil per day, net to Hess. Replacement of the flash gas compression system on the Liza Destiny with a modified design is planned for the fourth quarter and production optimization work is now planned to take place in the first quarter of 2022. These two projects are expected to result in higher production capacity and reliability. Net production from Liza Phase 1 is forecast to average approximately 30,000 barrels of oil per day in the fourth quarter and for the full year 2021. The Liza Phase 2 development will utilize the 220,000 barrels of oil per day Unity FPSO, which arrived in Guyana Monday evening. Next steps will be mooring line installation and umbilical and riser hook up. First oil remains on track for first quarter 2022. Turning to our third development at Payara, the Prosperity FPSO hull entered the Keppel Yard in Singapore on August 1st. Topsides fabrication at Dyna-Mac and development drilling are underway. The overall project is approximately 60% complete. The Prosperity will have a gross production capacity of 220,000 barrels of oil per day and is on track to achieve first oil in 2024. As for our fourth development at Yellowtail, earlier this month the joint venture submitted the plan of development to the Government of Guyana. Pending government approvals and project sanctioning, the Yellowtail project will utilize an FPSO with a gross capacity of approximately 250,000 barrels of oil per day. First oil is targeted for 2025. As John mentioned, we announced three discoveries since July. In July, we announced that the Whiptail1 and 2 wells encountered 246 feet and 167 feet of high quality, oil bearing sandstone reservoirs, respectively. This discovery is located approximately 4 miles southeast of Uaru-1 and 3 miles west of Yellowtail. In September, we announced that the Pinktail-1 well, located approximately 22 miles southeast of Liza-1, encountered 220 feet of high quality, oil bearing sandstone reservoirs. And finally, earlier this month, we announced a discovery at Cataback, located approximately 4 miles east of Turbot-1. The well encountered 243 feet of high quality hydrocarbon bearing reservoirs, of which approximately 102 feet was oil bearing. These discoveries further underpin future developments and contributed to the increase of estimated gross discovered recoverable resources on the Stabroek Block to approximately 10 billion barrels of oil equivalent. Exploration and appraisal activities in the fourth quarter will include drilling the Fangtooth-1 exploration well, located approximately 11 miles northwest of Liza-1. This well is a significant step-out test that will target deeper Campanian and Santonian aged reservoirs. Appraisal activities will include Drill Stem Tests at Longtail-2 and Whiptail-2, as well as drilling the Tripletail-2 well. In closing, we have once again demonstrated strong execution and delivery, and are well positioned to deliver significant value to our shareholders. I will now turn the call over to John Rielly.

Operator:

Thank you. [Operator Instructions] Your first question comes from the line of Arun Jayaram with JP Morgan.

Greg Hill:

Yes, sure. So, thanks for the question, Arun. Remember now that it’s arrived in water, the first thing that we have to do is more to the seafloor. And then obviously, there’s a lot of flow lines and risers and umbilicals to get hooked up to the vessel. So, what I would say is we are firmly on track for an early 2022 start-up, and don’t think I could be more definitive than that, but early 2022 looks like very possible.

Greg Hill:

Sure. I think first of all, yes, there is inflation going on. I think there’s a couple of things we have to remember. First of all, for the first three phases, which you mentioned, those are under existing EPC contracts. So, we’re basically insulated from cost increases on those EPC contracts? And then, ExxonMobil is doing an extraordinary job I think of utilizing this design one, build many strategy, to deliver efficiencies. Now, on the Yellowtail, we still don’t have the final numbers. So, once that project is sanctioned, we’ll give the market color on what the costs are. I do think it’s important to remember the nature of the PSC though. So by the time you get the Yellowtail, the efficiency of the PSC is so rapid that any cost increases rapidly get recovered. So, the impact on overall project return is not very much at all, right, because of that superefficient PSC. And the breakevens for Yellowtail, we project even with some cost increases, we’ll be in the -- firmly in the $25 to $32 barrel range. So, one of the best projects on the planet, even with some potential cost increases. Great project.

Doug Leggate:

Guys, I know you haven’t given a 2022 outlook yet. But, given the oil price recovery that we’ve seen and the very smart hedges, I think you guys have put in place. I go back to the CapEx guidance that you gave in 2018 at your Strategy Day. And I wonder if I could just ask you to give us a kind of framework as to how we should think about the spending trajectory? And if I may, embedded in that question, be blunt with you that I think there’s some concern over the cost, the sticker shock on Yellowtail. So, if I threw out a number and said where we should be thinking something in the $12 billion type of range, would that be off the mark?

John Hess:

Yes. And Doug on Yellowtail well, the FTP has been submitted to the government, and it is higher cost. I think everybody needs to realize that this FPSO is going to have capacity approximately 250,000 barrels of oil per day on a gross basis. It will be our largest oil development to date in Guyana. And while its cost will be higher, the resource we are developing is significantly higher. And this development has simply outstanding financial returns, some of the best in the industry, as Greg mentioned, and a breakeven cost between $25 and $32 per barrel Brent. So, it’s outstanding economics. Yes, the costs are higher, but the resource we’re recovering is much higher, and these are some of the best economics in the industry.

John Hess:

I won’t comment on that. Let’s let the FTP be approved, and then we’ll announce the official number.

Greg Hill:

Yes, Doug. So, I think based on -- again, this is just my experience being in this business 38 years. I would think that for developments of these sizes and everyone will be bespoke, so everyone will be a little bit different. But I think a range of 10% to 20% capacity for debottlenecking or capacity increases. This is a reasonable expectation. Again, everyone will be a little bit bespoke. You’ll wait and get some dynamic data to see where the bottlenecks are. But, I don’t think that’s an unreasonable expectation for future vessels. And I think the second point is, remember, these increases in capacity are typically achieved for very low investment. And obviously, with PSC, the rapid cost recovery, these are very profitable things to do.

Paul Cheng:

I think previously that the expectation of the debottleneck in Liza-1 will be doing at the same time as the turnaround, and now, it’s being separate and push it to the first quarter. Is there any particular reason for that decision?

Greg Hill:

Yes. So, Paul, as you said, the optimization work on Destiny is now planned for the first quarter. This was simply deferred to allow other planned maintenance and inspection work to be done concurrently, which is much more efficient. So, the operator just pushed it to get some efficiencies and completing a bunch of other work at the same time while they had the vessel down, which we fully support.

John Hess:

No, it won’t. That’s what I meant, Paul, is that when we take it down to do the optimization, ExxonMobil wanted to do some other work while the vessel was down. So, pulling some work forward, some maintenance work that was scheduled for later in the year, by doing that all at the same time concurrently, it’s just much more efficient. And so, they needed parts and pieces and et cetera and that’s why it got pushed to the first quarter.

John Hess:

Greg?

Paul Cheng:

And the final question for me, I think, it’s for John. John, I think you mentioned that once that your net debt to EBITDA get to say below 2 times, you will consider increasing the cash return to shareholders. And at that point that how should we look at it? I mean, is there ways you’re targeting that the incremental cash flow, say 50% still going to the balance sheet and 50% for incremental cash return to shareholder, or any kind of estimate that you can share? And also, at that point, should we assume that the main vehicle is going to be buyback, or it’s just going to be increasing the common dividend, or that is the variable dividend? How should we be looking at those?

Paul Cheng:

John, when you’re talking about that once you drop below 2 times, I suppose that your ultimate target will be much below 2 times EBITDA ratio. So, what is that ultimate ratio you want? Is it less than 1-time or less than half a multiple point?

Operator:

And your next question comes from Phillips Johnston with Capital One.

Greg Hill:

Phillips, I mean, we are very happy with our midstream investment and GIP is two. So, the midstream continues to add what we believe is differentiated value to our E&P assets. Like you said, being able to get it up to 200,000 barrels a day, also with that maintaining the operational and marketing control, it provides takeaway optionality for us to high-value markets. And as John mentioned earlier, we’re very focused on minimizing our mission. So, it gives us the ability to increase our gas capture and drive down flaring. So, both GIP and Hess remain committed to maximizing the long-term value of Hess Midstream. So, the offerings we did, we had the secondary in Q1 and earlier this month, they were designed to increase the float, as Midstream get their liquidity up there. And the Q3 buyback actually helped Hess Midstream optimize its capital structure, getting to that 3 times leverage position. So, pro forma for these transactions, Hess Midstream, it maintains a strong credit position and it has continuing free cash flow after distributions. So, it will continue to have that low leverage and ample balance sheet capacity because with the free cash flow, we’ll continue to drive that leverage down. So, that can support future growth there on the Midstream side or incremental return of capital to its shareholders, including Hess. So basically, what we’re talking about is continuing what we’ve been doing here with Hess Midstream.

Operator:

Our next question comes from Neil Mehta with Goldman Sachs.

John Rielly:

Sure. So, I mean, our hedge strategy, I mean, this is for 2022. It’s consistent with our past strategy. We look to provide significant downside protection to put -- do this while also giving the majority of upside to our shareholders. And we’re looking for that price protection as we continue to fund our world class investment opportunity in Guyana. So, with it, as I mentioned, we have the collars, 90,000 barrels of oil per day of WTI puts at a floor of $60 and the ceiling at $90 and the 60,000 barrels of oil per day Brent puts floor at $65 and the ceiling at $95. We use those high ceiling collars to reduce the cost of the program, just to be more efficient with our hedging program. But also, as you mentioned, we retain the exposure to greater than $2 billion in additional cash flow. In the case of high oil prices above those hedge floor prices. So, in addition, we have not hedged any of our natural gas, obviously, no NGL productions hedged, and we haven’t hedged all of our oil production either. So, we continue to be in a good position to be able to accrete up value with higher oil prices. But again, we’ve got that significant price protection on the downside to continue the investment.

John Hess:

Greg?

Operator:

Our next question comes from Noel Parks with Touhy Brothers.

John Hess:

Yes, Greg.

Noel Parks:

I’m just wondering, in the more recent discoveries, anything you can -- you have been able to extrapolate, I guess, maybe just from the consistency among the findings? Does that help inform your optimism for future drilling and as you step out further?

Operator:

Our next question comes from David Heikkinen with Pickering Energy.

Greg Hill:

Yes. No, that’s still under discussion with the partnership exactly what that configuration will be. And as we said, when we take final sanction, we’ll be able to share all those details as to what the final project actually looks like.

David Heikkinen:

Yes, it’s a much bigger barrel extent, it looks like.

David Heikkinen:

A huge area of being developed with that versus Payara, even. And then it was very helpful to put together the kind of incremental capital year-over-year. I did my math right, is that roughly $2.5 billion before exploration expense?

David Heikkinen:

Okay. I thought…

David Heikkinen:

And that’s before a potential fourth rig in the Bakken that would get you upto 200,000 barrels equivalent a day?

David Heikkinen:

Perfect. I’ve got my numbers right, now. Thanks, guys.

Operator:

Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

Jay Wilson:

Thank you, Liz. Good morning everyone and thank you for participating in our second quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the Federal Securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case of any audio issues, we will be posting transcripts of each speakers prepared remarks on www.hess.com following the presentation. I'll now turn the call over to John Hess.

Greg Hill:

Thanks, John. In the second quarter, we continued to deliver strong operational performance. Companywide net production averaged 307,000 barrels of oil equivalent per day excluding Libya, above our guidance of 290,000 to 295,000 barrels of oil equivalent per day driven by good performance across the portfolio. In the third quarter, we expect companywide net production to average approximately 265,000 barrels of oil equivalent per day, excluding Libya, which reflects the Tioga gas plant turnaround in the Bakken and planned maintenance in the Gulf of Mexico and Southeast Asia. For full year 2021, we now forecast net production to average approximately 295,000 barrels of oil equivalent per day, excluding Libya, compared to our previous forecast of between 290,000 and 295,000 barrels of oil equivalent per day, so we are now forecasting at the top of the range. Turning to the Bakken, second quarter net production averaged 159,000 barrels of oil equivalent per day. This was above our guidance of approximately 155,000 barrels of oil equivalent per day, primarily reflecting increased gas capture which has allowed us to drive flaring to under 5%, well below the state’s 9% limit. For the third quarter, we expect Bakken net production to average approximately 145,000 barrels of oil equivalent per day, which reflects the planned 45-day maintenance turnaround and expansion tie-in at the Tioga Gas Plant. For the full year 2021, we maintain our Bakken net production forecast of 155,000 to 160,000 barrels of oil equivalent per day. In the second quarter, we drilled 17 wells and brought 9 new wells online. In the third quarter, we expect to drill approximately 15 wells and to bring approximately 20 new wells online, and for the full year 2021, we now expect to drill approximately 65 wells and to bring approximately 50 new wells online. In terms of drilling and completion costs, although we have experienced some cost inflation, we are confident that we can offset the increases through technology and Lean Manufacturing efficiency gains and are therefore maintaining our full-year average forecast of $5.8 million per well in 2021. We have been operating two rigs since February but given the improvement in oil prices and our robust inventory of high return drilling locations, we plan to add a third rig in September. Moving to a three rig program will allow us to grow cash flow and production, better optimize our in-basin infrastructure and drive further reductions in our unit cash costs. Now moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 52,000 barrels of oil equivalent per day, compared to our guidance of approximately 50,000 barrels of oil equivalent per day. In the third quarter, we forecast Gulf of Mexico net production to average between 35,000 and 40,000 barrels of oil equivalent per day, reflecting planned maintenance downtime as well as some hurricane contingency. For the full year 2021, our forecast for Gulf of Mexico net production remains approximately 45,000 barrels of oil equivalent per day. In Southeast Asia, net production in the second quarter were 66,000 barrels of oil equivalent per day, above our guidance of approximately 60,000 barrels of oil equivalent per day. Third quarter net production is forecast to average between 50,000 and 55,000 barrels of oil equivalent per day, reflecting planned maintenance at North Malay Basin and the JDA as well as Phase 3 installation work at North Malay Basin. Full year 2021 net production is forecast to average approximately 60,000 barrels of oil equivalent per day. Now turning to Guyana. In the second quarter, gross production from Liza Phase 1 averaged 101 thousand barrels of oil per day or 26,000 barrels of oil per day, net to Hess. The repaired flash gas compression system has been installed on the Liza Destiny FPSO and is under test. The Operator is evaluating test data to optimize performance and is safely managing production in the range of 120,000 to 125,000 barrels of oil per day. Replacement of the flash gas compression system with a modified design and production optimization work are planned for the fourth quarter which will result in higher production capacity and reliability. Net production from Liza Phase 1 is forecast to average approximately 30,000 barrels of oil per day in the third quarter and for the full year 2021. The Liza Phase 2 development will utilize the 220,000 barrels of oil per day Unity FPSO, which is scheduled to sail away from Singapore at the end of August and first oil remains on track for early 2022. Turning to our third development at Payara, the Prosperity FPSO hull is complete and will enter the Keppel Yard in Singapore following the sail away of the Liza Unity. Topsides fabrication has commenced at Dyna-Mac and development drilling began in June. The overall project is approximately 45% completed. The Prosperity will have a gross production capacity of 220 thousand barrels of oil per day and is on track to achieve first oil in 2024. As for our fourth development at Yellowtail, the joint venture anticipates submitting the plan of development to the Government of Guyana in the fourth quarter, with first oil targeted for 2025, pending government approvals and project sanctioning. During the second quarter, the Mako-2 appraisal well on the Stabroek Block confirmed the quality, thickness and areal extent of the reservoir. When integrated with the previously announced discovery at Uaru-2, the data supports a potential fifth development in the area east of the Liza complex. As John mentioned, this morning we announced a discovery at Whiptail, located approximately 4 miles southeast of Uaru-1. Drilling continues at both wells to test deeper targets. In terms of other drilling activity in the second half of 2021, after Whiptail-2, the Noble Don Taylor will drill the Pinktail-1 exploration well, which is located 5 miles southeast of Yellowtail-1, followed by the Tripletail2 appraisal well, located 5 miles south of Tripletail-1. The Noble Tom Madden will spud the Cataback-1 exploration well, located 4.5 miles southeast of the Turbot-1 discovery, in early August. Then in the fourth quarter, we will drill our first dedicated test of the deep potential at the Fangtooth prospect, located 9 miles northwest of Liza-1. In the third quarter, the Noble Sam Croft will drill the Turbot-2 appraisal well, then transition to development drilling operations for the remainder of the year. The Stena Carron will conduct a series of appraisal drill stem tests at Uaru-1, then Mako-2 and then Longtail-2. In closing, we continue to deliver strong operational performance across our portfolio. Our offshore assets are generating strong free cash flow. The Bakken is on a capital efficient growth trajectory and Guyana keeps getting bigger and better, all of which positions us to deliver industry leading returns, material free cash flow generation and significant shareholder value. I will now turn the call over to John Rielly.

Operator:

[Operator Instructions] Your first question comes from the line of Ryan Todd with Piper Sandler.

John Hess:

Yes, it's a great question, Ryan, and thank you. Look, Whiptail drilling activities are still underway. We're going to be drilling in both wells to some deeper targets, Whiptail adds to our queue of high value potential oil developments in Guyana, Uaru and Mako, as Greg talked about, have the potential to be our fifth FPSO. Whiptail has a potential to be another oil development. And since evaluations work is still going underway, it's a little premature to talk about resource size. But definitely what we're seeing is a foundation for potentially another oil development with Whiptail. And then to remind everybody, we still have a very active exploration appraisal program on the Stabroek Block, the remainder of this year, which should provide even more definition for future development investment opportunities. So the queue of high value potential oil developments is growing. And we're going to optimize it as we continue to get more data and well results to further get clarity on what the queue will be.

Ryan Todd:

All right, thanks. Thanks, John and Greg. Maybe a follow up on CapEx, prior guidance for 2021 Balkan CapEx is $450 million. Is that still the same with the addition of a third rig in September? Or was the possibility of a third rig already built in there? And you've been running low on CapEx, obviously in the first half of the year, but activities accelerated in the second half. Is there a potential for maybe downward pressure on CapEx on a full year basis? Or is the kind of the trend upward in the second half likely to or I guess things trending line with where you would have expected?

Operator:

Our next question comes from Arun Jayaram with JPMorgan.

John Hess:

Thanks, Arun. Greg?

Arun Jayaram:

Great. My follow up is for John Hess. John, I wanted to see if you could help us think about the order of operations here regarding additional cash return to shareholders and maybe outline, paying off the term loan, maybe the timing of step two of the strip holds and when we could see it in the board kind of move on the dividend.

Operator:

Your next question comes from David Deckelbaum with Cowen.

John Hess:

John, you want to take the exit rate and then Greg, any color you'd like to provide as well.

Greg Hill:

Yes. So I think just one couple more comments on the third rig. So with that third rig, we'll drill 10 more wells. So that's why we increased, our drilling well count from 55 to 65. And then, we'll also bring five more wells online with that third rig. So that's why we raised the wells online count from 45 to 50. But as John said, those wells come on right at the end of the year. So the impact of that will be seen in 2022 volumes. The fourth rig, as we've always talked about, the primary role of the Bakken in our portfolio is to be a cash engine. So that's its number one role. So any decision they add any rigs in the Bakken is going to be driven by returns and corporate cash flow needs. Now, having said that, assuming oil prices stay high, in the next year, then we'd consider adding a fourth rig at the end of next year. Why is it at the end because you build all your locations in the summertime. And then by doing so, that would allow us to take Bakken production up to around 200,000 barrels a day and that level, really optimizes our in basin infrastructure. But again, that's going to be a function of oil price, the function of corporate cash flow needs, how much cash do we need the Bakken to deliver for the corporation, that's going to be the primary driver of whether or not we have that fourth rig or not. I will say, the fourth rig would be the last rig. So the highest we would go is four rigs. And we could maintain that 200,000 barrels a day with four rigs for nearly a decade, given the extensive inventory of high return wells that we have.

John Hess:

Yes. Libya, obviously, it generates some cash for us. It has been running at fairly stable levels, and we would estimate those levels would continue at the current rate. And it really is a function of political security stability in the country, which is increased. And so we would intend that Libya would continue at the pace of cash generation that it's at now in the future.

Roger Read:

Just one question to follow up on just from the comments earlier about, well costing flat in the Bakken. But as you step back and look at cost inflation almost anywhere, I know, you're relatively silent in the Gulf of Mexico today, but the expectations for next year. And then as we think about building the FPSOs, or any sort of, I guess, supply chain issues that may be affecting anything as we think about the next like, it's FPSO and FPSO 2 and FPSO 3, as we think about the timing in Indiana.

Greg Hill:

Yes, sure. So, let's talk about the onshore first because it's easiest. Yes, as I said in my opening remarks, we are seeing some minor inflation in the Bakken. The first half of the year was all tubulars. However, we recall, we pre-bought all of our tubulars for the program this year. So we're covered on that. Commodity base chemicals obviously have gone up. But it really doesn't matter because we're able to cover that through technology and lean manufacturing gains and that's why we held our well cost forecast for the year still at five eight, even though we're feeling some, single-digit kind of levels of inflation. Now, if I turn to the offshore, yes, industry seeing cost increases there as well. Day rates on deepwater rigs are out modestly. They're nowhere near what they were in the halcyon day say five years ago. But remember, almost all of our offshore investment is in Guyana. And we operate under EPC contracts there. So that largely insulates us from cost increases after the contract sign. And then I've got to say, Exxon Mobil is doing an extraordinary job of utilizing this design one build many strategy to deliver large amount of efficiencies from that project. So certainly now and in the very near term, I wouldn't expect any cost issues there. And of course, because the PSC, if your costs do creep up, that's all covered under cost recovery.

JohnHess:

Well, the majority of our drilling is going to be on this Stabroek Block. And I think Greg gave pretty good roadmap for what our drilling the rest of the year is going to be, it's going to be a comment of exploration and appraisal. I think, Greg, the only other thing to talk about his Surinam probably Block 42 because we do have some drilling planned there next year.

Operator:

Your next question comes from Paul Cheng with Scotia Bank.

John Rielly:

So our target and what I always say it's a maximum target is a two times debt to EBITDAX targets. So as you said is, when we pay off this term loan next year, and we have phase two coming online, we're going to drive under that two times. And what I expect here, because I think, we mentioned earlier, we really don't have any material near term debt maturity. So what we'll do is, we'll pay off that term loan. We have small amounts in 2024 and it's not till 2027 that we have our next big maturity. So we'll just pay off the small maturities as we have and we'll continue to let our EBITDAX grow basically, you're going to get Phase 2, then Payara, then Yellowtail, then Uaru-2, so we're going to have to significant growth in EBITDA, and our balance sheet is just going to get stronger and stronger from that standpoint. So what I would say is we hold that absolute debt level, flat and decrease it for the maturities that that come about. And then, as John mentioned, we're going to start driving, significant free cash flow generation and once that term loans paid off, we'll start with dividend increases, and then we'll move on to the opportunistic share repurchases.

John Rielly:

No. We look at even lower prices, what I would say that target is there for us no matter what the commodity price is. And look, we always say this as the additional FPSOs come on, chance of these very low cost developments come on, our margins and our cash flow just continues to improve. So, even at lower commodity prices, when we start getting Payara, Yellowtail, Uaru, Mako online, we're going to have significant free cash flow and the balance sheet is going to be very strong. So our target doesn't vary based on commodity prices. And we'd like to say that, with these episodes coming on, we can win in any commodity price environment.