Jake Spiering:

Thank you, Justin. Welcome to Chevron’s second quarter 2024 earnings conference call and webcast. I’m Jake Spiering, Head of Investor Relations. Our Chairman and CEO, Mike Wirth; and CFO, Eimear Bonner are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron’s website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. A reconciliation of non-GAAP measures can be found in the appendix to this presentation. Please review the cautionary statement on Slide 2. Now, I will turn it over to Mike.

Eimear P. Bonner:

Thanks, Mike. We reported second quarter earnings of $4.4 billion, or $2.43 per share. Adjusted earnings were $4.7 billion, or $2.55 per share. Results in the quarter were impacted by downtime in Upstream that weighed on realizations, higher exploration expense and Downstream turnaround timing. Organic CapEx was $3.9 billion, in-line with budget. Our balance sheet remains one of the strongest in the industry, ending the quarter with a net debt ratio of 10.7%. Chevron generated solid cash flow of nearly $9 billion excluding working capital. Working capital lowered cash flow due to tax true-up payments outside the U.S. and a build in inventories. We expect about half of the working capital to unwind in the second half of this year, primarily in the fourth quarter. We again demonstrated our consistent approach to returning cash to shareholders with $6 billion of dividends and share repurchases. Adjusted earnings were lower by $700 million versus last quarter. Adjusted Upstream earnings were down mainly due to lower liftings, higher exploration expense and absence of favorable tax impacts from the prior quarter. Partly offsetting were higher realizations. Adjusted Downstream earnings were down due to lower margins and reduced capture rates, this was partially offset by timing effects. All Other decreased mainly due to a tax true-up. Versus last year, adjusted second quarter earnings were down $1.1 billion. Adjusted Upstream earnings were flat, higher realizations and liftings were mostly offset with higher DD&A due to the PDC acquisition and the absence of prior year favorable tax items. Adjusted Downstream earnings decreased mainly due to lower refining margins and higher turnaround and transportation OpEx. The Other segment was down primarily due to state tax adjustments. Worldwide oil equivalent production was up over 11% from last year due to the acquisition of PDC Energy and significant growth in the Permian Basin. Now, looking ahead. The third quarter will have heavier than usual maintenance with several turnarounds at Upstream assets, including TCO and Gorgon. Impacts from refinery turnarounds are mostly driven by El Segundo. There will be a one-time payment related to discontinued operations of around $600 million. We anticipate affiliate dividends to be around $1 billion this quarter. With the project in Kazakhstan nearing completion, we expect quarterly dividends from TCO moving forward. As a reminder, Chevron pays a 15% withholding tax on dividends from TCO which lowers both earnings and cash flow. Share repurchases are targeting the $17.5 billion annual guidance rate. Asset sales in the second half of the year are expected to be aligned with full-year guidance. Back to you, Mike.

Jake Spiering:

That concludes our prepared remarks. We’re now ready to take your questions. Please ask you to limit yourself to one question. We will do our best to get all of your questions answered. Justin, please open the line.

Neil Mehta:

Yes. Thank you so much and congratulations to Nigel, Colin and Rhonda on their retirement. My question, Mike, was really focused around TCO. And, it sounds like we are making progress on that project, but this is a critical period of time during the summer productivity period. So, just would love your thoughts on how FGP is progressing. And then, as it relates to Kazakhstan, we’re getting a lot of questions about the concession extension as we think about next decade and I recognize that’s a long way away, but maybe you can help to address some of the investor debate around that topic as well?

Operator:

And, next is Alastair Syme with Citi.

Michael K. Wirth:

Yes. You could do something else if you wanted to. This is the transaction, that’s the right transaction for us. And so, we’re very focused on it, Alastair, and we’ve made good progress with the shareholder vote, we’re steadily marching along with the FTC, and I’ve already mentioned the timeline on the arbitration. So, it’s sometimes good things you have to work for and this will take a little bit more time than we had anticipated, but we remain confident in the outcome. And, as I tried to cover in our prepared remarks, we’ve got a really strong queue of organic growth opportunities in flight right now. We didn’t mention the Eastern Med, which is another one. So, we’ve got projects in multiple regions of the world that are poised to deliver growth over the next three years, absent it we be at 10% growth in free cash flow, we’ve got projects coming on in numerous basins in the world and in our chemicals business as well. So, we’re really focused on that and creating value there. But, if another opportunity were to present itself that were compelling, we’re certainly in a position to consider it. Thanks for the question.

Paul Cheng:

Thank you. Mike, can you talk about the potential for further cost efficiency gain? Where that you see over the next, say, two or three years the biggest opportunity? And, could you quantify that? I mean, how big is that opportunity set for you guys? Thank you.

Jake Spiering:

Thanks, Paul.

Operator:

And, the next question will come from Biraj Borkhataria with RBC.

Michael K. Wirth:

Yes. Thanks, Biraj. So, obviously we are not party to those discussions. We comply with the requirements in any country where we operate including if they have some sort of production targets or requirements that they impose upon producers in the country. We have not received any indication from the Republic of Kazakhstan with regards to any curtailments relative to OPEC+. What oftentimes happens there is with the production in several big assets, you have turnarounds, projects and other things that create some degree of variability across multiple different producers and I think the Republic looks to manage that and fit their plan together. So, I don’t have any unique knowledge about 2025, but we have a very close relationship. I will tell you that the TCO barrels, I think from a contribution to the Republic standpoint are very attractive and our intent is to produce at the full capacity any point in time for our facility in order to maximize revenue for the Republic and for Chevron. So, if there’s further developments on that front, we’ll certainly provide them, but we don’t have anything from the government right now. Thank you.

Doug Leggate:

Thank you. Good morning, everyone. Hey, Mike. I’m delighted to see you guys come to Houston. Welcome. But, if you want to stop by for coffee, let me know. But, Mike, I missed out on the last earnings call, and I apologize for bringing it up. I know it’s highly sensitive and highly, I guess, subjective, but the issue around the delayed arbitration, I wanted to pose a question to you and see if we can get you to probe a little bit on this. ExxonMobil, regardless of their motivation, has stated that they have no interest in buying Hess. But, at the same time, our understanding is the bigger concern is global contractual rule for credibility, protecting that aspect of a contract. So, when I go into two months of the legalities, I wonder, is there a compromise that could cut short the arbitration timeline so you don’t have to go to arbitration? For example, acknowledge you have a ROFR, but Exxon acknowledges they’re not going to exercise a ROFR so everybody gets to protect your contracts for Exxon and secure your acquisition for Chevron. Is it a compromise that could cut the arbitration short is my question?

Jake Spiering:

Thanks, Doug.

Josh Silverstein:

Hey, thanks, good morning, guys. Nice update in the Permian. I was wondering if you could provide a little bit more details around increase in the fourth quarter outlook. Was this due to the new Delaware completion technique from Chevron? Any thoughts on non-op royalty volumes? And then, just looking at the Midland side, was there anything kind of specific as far as the zone or completion that you guys are now shifting away from to get increased productivity there? Thanks.

Operator:

And the next question comes from Roger Read with Wells Fargo.

Michael K. Wirth:

Good morning, Roger.

Michael K. Wirth:

Yes. I might make a couple of comments on that and then ask Eimear who before becoming our Chief Financial Officer was our Chief Technology Officer. The moving into that pressure regime, obviously you need bigger equipment because you got to contain higher pressures, you’ve got greater wall thickness on all your equipment, it’s heavier, you need heavier hook loads to lift and deploy equipment. You’ve got a lot of technology qualification to satisfy our own standards and to satisfy the regulator that every element of your kit is proven at pressures well beyond what anything that it will see in service. So, this goes from components large to small and you get into tighter tolerances and a whole host of things as you step up the pressure regime there. So, I would say that we’ve worked closely with some of our suppliers who have developed the specific equipment that is in place and we’re very pleased with everything from the drilling rigs and the equipment that’s used in drilling to trees and production kit both subsurface and surface. Eimear, you might have some thoughts from your technology days to share with folks.

Operator:

And the next question will come from Devin McDermott with Morgan Stanley.

Eimear P. Bonner:

Yes. Thanks, Devin. Well, I’m thinking about it consistent with how we have for decades and consistent with our long-standing financial priorities. So, just to step through them, first, it’s growing the dividend, that’s our first priority. So, cash that enables us to continue with our track record of growing the dividend for 37 years. So, that’s the first priority. And when we look at the projects that we have and the growth that’s underway that Mike talked about, our 10% free cash flow growth really supports future dividend increases. So, when we think of cash, that’s where it goes, first and foremost. Secondly, is to invest in the business to deliver profitable growth and do that capital efficiently. This is an area of leadership for Chevron when you look at the percentage of the CapEx as a percentage of CFFO. So, I’m focused on ensuring that we maintain leadership in this area. To your point about the balance sheet, our third priority is to maintain a strong balance sheet, and we are currently under levered and we expect and are comfortable to modestly relever over time, but to stay within historical ranges. And we look at our balance sheet as an asset to create value, and manage volatility and ensure steady capital returns through the cycle. And when we’ve satisfied all three of the financial priorities, the fourth is to return surplus cash to shareholders through buybacks and that’s what we intend to do and we take a multi-year view of that considering a range of commodity prices. So, in my time with the company in the business side and on the corporate side, I’ve seen how these financial priorities have served us well and they’ll continue to serve us well. And so in my time, they’re not going to change. Thanks.

Nitin Kumar:

Hi, good morning, Mike, and thanks for taking our questions. I want to maybe shift focus on the downstream side. Last quarter you had a heavy turnaround schedule and just the way cracks worked out, it probably wasn’t the best timing. As you’re coming out of that turnaround, what are you seeing in your markets? And if you can maybe touch on renewable diesel specifically with Geismar coming on later this year, what’s the outlook for economics of biofuels?

Operator:

And the next question will come from Jason Gabelman with TD Cowen.

Michael K. Wirth:

Yes. Thanks, Jason. You’re right. We have added some new acreage to our portfolio and some acreage that’s in areas that are kind of more frontier than some of the stuff we’ve historically held. Look, we’re excited about I’m excited about any number of regions in the world. I’ll start with the Gulf of Mexico where we’ve got projects lined up as I mentioned earlier and a lot of expertise. We’re one of the largest leaseholders in the Deepwater Gulf of Mexico. And as we move into these higher pressure regimes, we’re well positioned to continue to have exploration success and development success there. The second one I’ll point to is the Eastern Mediterranean, where we’ve got interesting acreage in the offshore western portion waters off of Egypt. We’ve got some plans to drill there. We’ve got a discovery where we’ll do a delineation well on the Nargis discovery. And then the third one I would point to is West Africa and that would include existing positions in places like Nigeria, Angola, Equatorial Guinea and Namibia, where there’s certainly been a lot of interest lately in Namibia. We’ve seen others make some discoveries. In the Orange Basin, we’ve got a lease PEL 90, which sits just outboard of where an interesting discovery has recently been made. And we’ve got a well there that will spud in the fourth quarter of this year. It will be completed in early 2025. We’ve already executed the Reagan well construction contract. So, we’re very excited to see what that delivers. In terms of additional acreage in Nigeria, we farmed into a block in the Walvis Basin, PEL 82 and are interested in continuing to add to our acreage position there if opportunities present themselves. So, we’ve got three ways of bringing resource into the company. You can explore for it and discover it. You can acquire it or you can unlock it through technology and all three of those receive lot of attention. We’ve got talented people working in each area to bring resource in through all of them. But I’m excited about some of the new exploration acreage that we’re adding. Thanks, Jason.

Bob Brackett:

Good morning. I had a question given that you have a unique position in Venezuela and we’re watching an election and a post-election unfold. Any comments on what you’re seeing from your folks on the ground? And maybe if there’s any vision, what your role in Venezuela could look like in a range of presidential outcomes?

Operator:

And next is Neal Dingmann with Truist.

Michael K. Wirth:

Yes, certainly in the economy broadly speaking, we have seen inflation pressures easing and I think that’s good for consumers, it’s good for economic growth. These things vary across geographies and as you say, you can see different dynamics in the onshore and the offshore. We are seeing some softening of pressure in the onshore, some declining in prices for oil country or oil class tubulars, rigs, prop and trucking. Some of the frac services are more stable. We have a contracting approach that generally sets up index-based pricing over longer periods of time which tends to buffer increases. It can also buffer the decreases. So, we’re not a big spot player. We tend to have longer term contracts and look for things that allow our suppliers to plan their work and allocate their people and resources accordingly. And some of these things lag on the way up, they lag a little bit on the way down. But I think in the onshore, you’re right, you’re seeing some easing of pressures. I think in the offshore, you’re seeing a little bit of a reverse. There is more activity going on in the Deepwater. You’re seeing rig rates firm in some cases. So, this is a place where we also take a longer term contracting approach. We’ve got multiple rigs contracted out over multiple years. They are typically laddered, so that they don’t expire simultaneously and we’ve lagged into the market across the cycle, so that we’re not exposed to any one particular point in time. So, certainly not the inflationary pressure we’ve seen a couple of years ago. Thank you, Neal.

Geoff Jay:

Hey, guys. This is, maybe a follow-up to Jason’s question about exploration earlier, but I noticed you got involved in Uruguay back in March. Is that an analog to the Orange or Walvis basins? And just wonder if you can maybe update us on what you think the potential could be there and what the timeline of exploration might be there?

Operator:

And the next question will come from Betty Jiang with Barclays.

Michael K. Wirth:

Okay. Let me start with the royalty and non op first. We’re continuing to see strong contributions from that. We’ve got line of sight to essentially all the AFEs this year across that acreage and it’s been if you want to call it the upside performance we’ve seen this year has been spread across all three of those portions of our business, company operated royalty and NOJV. So, strong contributions from those two. When you get to the Permian, yes, these efficiencies have accelerated activity. We get through more lateral feet of wells, we complete more feet, we use more consumables and sand and everything as we do that. Some of the easing of pressure on cost of goods and inputs helps us offset that and so we are trying to manage, we are going to manage to our CapEx numbers. And you can expect us to balance out activity and capital. We’re not going to get off to the races on capital. We’re going to see very disciplined out of the budget is a budget. But the nice thing is we’re getting -- because of the improved cycle times, improved efficiencies, we’re getting more productivity out of the equipments, we’re getting more production per unit of capital input and that really is the story here. So, you can expect us to land our capital as we’ve guided it at close to $5 billion and the production as we have guided in our prepared remarks.

John Royall:

Hi, good morning. Thanks for taking my question. So, my question is just if you could give some color on the downtime you saw both Gorgon and Wheatstone in 2Q. What was the source of those outages? And how are the facilities running now? And maybe include some color on the planned work you called out for Gorgon in 3Q?

Michael K. Wirth:

Thanks, John. I would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation on today’s call. Please stay safe and healthy. Justin, back to you.

Michael Wirth:

Thanks, Jake, and thank you, everyone, for joining us today. Chevron continues to deliver strong operational performance, maintain cost and capital discipline and consistently return cash to shareholders. First quarter marked 9 consecutive quarters with adjusted earnings over $5 billion and adjusted ROCE above 12%.

Eimear Bonner:

Thanks, Mike. We delivered another quarter of strong earnings, ROCE and cash returns to shareholders. We reported first quarter earnings of $5.5 billion or $2.97 per share. Adjusted earnings were $5.4 billion or $2.93 per share. Cash flow from operations was impacted by an approximate $300 million international upstream ARO settlement payment and $200 million for the expansion of the retail marketing network. We also had a working capital build during the quarter consistent with historical trends.

Operator:

[Operator Instructions] Our first question comes from Sam Margolin with Wolfe Research.

Michael Wirth:

Yes. Sam, let me talk a little bit to the project and operational dimensions of this, and then I'll let Eimear comment on the financial ramifications of that. So look, we're really pleased with the progress that's been making and pleased that we've begun the initial start-up of WPMP with the first PBF compressor online and processing crude through the plants after conversion of the first metering station.

Neil Mehta:

My question is really on the exploration program. Specifically, you have an interesting position in West Africa and Namibia. So maybe you can just give us some historical context of how you got involved here. Is this an asset that you see a lot of opportunity in, especially given some of the announcements from peers over the last couple of weeks? And how do you think about prosecuting it going forward?

Paul Cheng:

You guys did a small deal look like on the retail marketing asset, adding over 200 stations in the Gulf Coast and West Coast. I actually don't remember. I think since you've become the head of downstream, say, call it, 20 years ago, you guys have been selling asset there. So is there a change of your view in terms of the overall strategy we made to that part of the business? And whether that -- this deal you are going to be owning the asset or that this is wholesale marketing [ drop ] network type of deal that you are acquiring?

Operator:

We'll go next to Betty Jiang with Barclays.

Michael Wirth:

Sure. So yes, first quarter production in the Permian was good, 859,000 barrels a day, down about 1% from the fourth quarter of last year, stronger than what we had anticipated. Really good, strong performance in our company-operated business, building off the momentum from the fourth quarter of last year. We have seen reliability improvements that translate into a slightly less decline in our base production.

Joshua Silverstein:

You had around $1 billion of debt this quarter to manage some of the working capital and really distribution timing. Do you see the cash balance growing sequentially? Did you repay the commercial paper in 2Q? Just wanted to get a sense of where the cash outlook may go sequentially.

Eimear Bonner:

Yes. Josh, yes, so we had some commercial paper issued in the first quarter, and it was just to manage short-term liquidity. Timing of affiliate dividends can be a bit lumpy, repatriation of cash can be a bit lumpy. So this was normal business for us in the first quarter.

Operator:

We'll go next to Biraj Borkhataria with RBC.

Michael Wirth:

Yes. Thanks, Biraj. Nothing's really changed. I mean this is a very large base business now with thousands of wells over a very large footprint. And it's important that we focus not only on productivity, efficiency and reliability and drilling and completions, but also in all aspects of operations. And that's midstream takeaway, it's gas processing, it's water handling.

Operator:

We'll go next to Nitin Kumar with Mizuho.

Michael Wirth:

Yes. Thanks, Nitin. So you might recall that the Department of Treasury and OPEC, a division within treasury, has issued a couple of different, what are called general licenses for operations for companies in Venezuela. There's one called General License 41, which primarily pertains to our position in the country. There's some specific licenses as well that kind of go along with that. And then there had been a second one that was issued subsequently called General License 44, which applied more broadly. That's the one where the administration has announced some changes. And those don't really impact us. There have been no changes to GL 41. And so we're not really affected by the news you've read about recently.

Operator:

We'll go next to Jason Gabelman with TD Cowen.

Michael Wirth:

Yes. Yes, sure. Happy to do that, Jason. So the first thing is you're right. We're always high-grading our portfolio. And it's not because we need the cash. You already covered the strength of the balance sheet. But it's really to set value to optimize our portfolio. We find times there are things that don't compete for capital in our portfolio and they fit better with somebody else.

Bob Brackett:

Given the launch of Future Energy Fund III, can you give us a thought of what you saw success cases coming out of I and II that caused you to move to III? And maybe compare and contrast how you do it yourself in-house solar to hydrogen, for example, versus where you might see third parties to try new technologies.

Operator:

We'll go next to Roger Read with Wells Fargo.

Michael Wirth:

Yes, you bet. So first of all, we are back in full operations in the Eastern Med. We've -- Tamar was down for about a month at the very beginning of hostilities. But we're excited about the opportunities there. Just to remind you, we've got the 2 existing platforms, Tamar and Leviathan, in service. And we've really structured our development plans there to focus on capital efficiency, higher returns, to the earlier answer, things we've got to compete for capital in our portfolio.

Francis Lloyd Byrne:

I know we've covered a lot of ground this morning. We talked about the Permian productivity, which looks really good. But could you just touch on the DJ? And that production looks stronger than we expected. And then also any political risk you might want to comment on that there?

Devin McDermott:

I wanted to bring it back to TCO. And Mike, I think you've talked in the past about how there is some similarity in the design between [ WPMP ] and FGP as a result of that. As you bring WPMP online, it helps derisk part of the FGP ramp as well. I was wondering if you could remind us what some of that commonality is. And as you look at the milestones you look out over the next few months at WPMP, which are the ones that you think about as being key to help derisk FGP as well?

Operator:

We'll go next to Ryan Todd with Piper Sandler.

Michael Wirth:

Yes. So the 2 projects. One is an oilseed processing plant in our joint venture with Bunge. It's a project at Destrehan, Louisiana. And so FID was announced for a new oilseed processing plant there. This one will feature a very flexible design, and that's important because it gives you feedstock flexibility, which matters in any fuels manufacturing business. So in this case, we can process soybeans and softseeds, but we can also be able to process winter oilseed crops, things like winter canola, cover crest. And so it gives us a greater range of potential feedstocks that can then feed into our renewable fuels business, particularly the Geismar real diesel project, which will start up later this year. And it's really important that we have exposure across these value chains.

Operator:

We'll go next to John Royall with JPMorgan.

Michael Wirth:

Well, look, we've been in California for our entire existence, 145 years. We've got an integrated value chain that allows us to serve 2 competitive refineries and advantaged logistics that take us out into a market where we've got a very strong brand and where the demand for all forms of energy continues to grow, be it power, be it transportation fuels. It's an economy that is large and demand continues to go up.

Alastair Syme:

Mike, can you help me understand a bit the sequencing of the base case on the Hess timetable? I've read all the documents, but just to get your sort of view. We've got a shareholder vote in May and we got limbo pending regulatory issues, but obviously, importantly, the arbitration. But maybe just talk about the arbitration timetable.

Neal Dingmann:

My question is on broad capital spend question specifically. Could you just maybe speak to -- do you have sort of broad strokes what percent of total spend would be directed towards the New Energies and maybe the Chevron technology ventures? And I'm just wondering how you think about margins, even though it's still early for some, how the margins of these compare to your higher-return traditional margin business.

Jake Spiering:

We would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation on today's call. Please stay safe and healthy.

Operator:

Thank you. This concludes Chevron's First Quarter 2024 Earnings Conference Call. You may now disconnect.

Jake Spiering:

Welcome to Chevron's fourth quarter 2023 earnings conference call and webcast. I'm Jake Spiering, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Reconciliation of non-GAAP measures can be found in the appendix of this presentation. Please review the cautionary statement on Slide two. Now, I will turn it over to Mike.

Pierre Breber:

Thanks Mike. We reported fourth quarter earnings of $2.3 billion, or $1.22 per share. Adjusted earnings were $6.5 billion, or $3.45 per share. Included in the quarter were $3.7 billion in charges pre-announced in January. Foreign currency charges were almost $480 million. Our 2023 CapEx included $650 million of inorganic acquisitions and around $450 million invested in legacy PDC assets post-closing. Excluding these items, CapEx was about 5% above budget after three consecutive years below. Share repurchases matched the third quarter. Our balance sheet remains strong, ending the year with a net debt ratio comfortably in the single digits. Turning to the quarter, adjusted earnings were higher than last quarter by roughly $730 million. Adjusted upstream earnings improved due to higher liftings, in line with record quarterly production, and favorable timing effects. Adjusted Downstream earnings decreased on lower refining margins, partially offset by a favorable swing in timing effects. All Other benefited from lower corporate taxes and employee costs. For the full year, adjusted earnings decreased nearly $12 billion compared to the prior year. Adjusted Upstream earnings decreased primarily due to lower prices. Adjusted Downstream earnings were lower largely due to declining refining margins. Other segment earnings improved on lower employee costs and higher interest income. Solid financial performance enabled Chevron to deliver, again, on all four of its financial priorities. We announced an 8% increase in our dividend, reflecting our confidence in expected future free cash flow growth. We maintained capital discipline in both traditional and new energies. We reduced debt by over $4 billion, including all debt assumed in the PDC acquisition and we repurchased about 5% of our shares outstanding. Last year, we produced more oil and gas than any other year in the company’s history, including a record number of LNG cargoes out of Australia. We expect 2024 production to be higher again, by 4% to 7%. Our plans include production growth in the DJ Basin, with a full year of legacy PDC operations and continued organic growth in the Permian. Our guidance this year includes an estimated impact from asset sales as we further high-grade our portfolio. Looking ahead, our first quarter downtime estimate includes around 20 thousand barrels of oil equivalent per day associated with January’s cold weather in North America. Earnings estimates from refinery turnarounds are mostly driven by Pascagoula. Share repurchases in the quarter will continue to be restricted under SEC regulations. Depending on commodity prices and margins, affiliate dividends are estimated around $4 billion, roughly flat with last year. We do not expect significant affiliate dividends in the first quarter. The difference between affiliate earnings and dividends is expected to decrease in the second half of the year after TCO’s start-up of WPMP. Our CapEx guidance range is unchanged from the December budget announcement. In prior years, our CapEx rate in the first half of the year was about 20% lower than the second half. Our price sensitivities have increased at higher production levels. About 20% of the Brent sensitivity relates to oil-linked LNG sales and less than 10% relates to North America natural gas liquids. Back to you, Mike.

Jake Spiering:

That concludes our prepared remarks. We are now ready to take your questions. We ask that you limit yourself to one question. We will do our best to get all your questions answered. Katie, please open the line.

Biraj Borkhataria:

Hi, thanks for taking my question and firstly, Pierre, congrats on a great career and all the best for retirement and thanks for all the help over recent years. I feel compelled to ask you a question on buybacks because it's your last time, but I'll try and resist. So the question's on the Permian. You had a very strong production number in Q4, quite an inflection from what we've seen in the last few quarters and I was interested in particular the comment on that volume growth alongside building the DUC inventory. So presumably the non-op side was a nice contribution in Q4. Could you just give some clarity on the bridge sort of 3Q to 4Q because the market has been concerned about you hitting the number of the lease for this year most recently. Thank you.

Operator:

We'll go next to Neil Mehta with Goldman Sachs.

Pierre Breber:

Thanks, Neil. My question's on Slide six, the TCO update. It sounds like the schedule and the cost guidance that was provided in November is still on track, but for us non-engineers, maybe, Mike, you can kind of walk us through the schematic and help us understand what of these boxes are the critical path issues that we should be focused on.

Operator:

We'll go next to Doug Leggate with Bank of America.

Pierre Breber:

Thank you, Doug.

Mike Wirth:

Yeah. Doug, it's really premature for us to comment on that until the transaction closes. Hess has a pretty tight portfolio of assets that are performing well and we really need to close the deal, have access to all the data and re-optimize all of our views of portfolio investments and update our new plan and so I don't want to speculate on any assets and look, we've got some of our own assets that we do have out in the public domain already. You may have seen reports on Kaybob Duvernay on Congo. So, there are some divestments that we have signalled out of the Chevron portfolio and I think as you see the divestments unfold over the next few years because we will have more assets in the portfolio that come from Legacy Chevron that is likely to be a greater contributor I would guess to the overall $10 billion to $15 billion number than things that come in through this transaction, but I can't comment on Malaysia or any other particular asset until we get past the close.

Operator:

We'll go next to Josh Silverstein with UBS.

Pierre Breber:

Yeah no. Appreciate the question Josh. We're starting this year with 12 rigs and three frack crews. I mentioned we'll add a fourth frac crew around the middle of the year, but at the same time, we're becoming more efficient. We need fewer rigs to drill the planned lateral feet that we've got out in front of us and so as we as we close in on a million barrels a day, we're at the capital level that I think is going to be required to get us there and then the really nice thing about this is when you're trying to hold the plateau as opposed to grow from seven to eight to nine hundred 700, 800 to 900 to a million a day, you actually can pull capital spending down because you're offsetting decline. You're not trying to offset decline and grow by significant chunks each year and so inflation has moderated and that has been a challenge. We've talked about some of the things we're moving water around a little bit more, but that's embedded in our plan now going forward. So I would not anticipate that we're going to have to go towards $6 billion in order to get there and you know as we as we get to each year, we'll give you an updated guide on it, but when we plateau production capital spending and capital discipline really matters. I just want to emphasize this. We intend to live within our capital means and be really tight on capital and that applies to the Permian along with every other asset.

Paul Cheng:

Thank you and first I want to congratulate Pierre and thank you for all the years that actually all over the past couple of decades that all the help. We may appreciate.

Paul Cheng:

Michael and Pierre, I think Michael when you when you first become the CEO, I think one focus is that course method for you and that full for the last several years, there's a lot of acquisition and change in portfolio. So it's very difficult for us from the outside to see where's your cost structure compared to let's say before the pandemic in 2019? Is there any way that you can help us in terms of what is the structural cost base that for you today compared to say a number of years ago, especially during the early part of the pandemic. You guys did have a restructuring effort. Thank you.

Operator:

We'll go next to Sam Margolin with Wolfe Research.

Mike Wirth:

Thanks, Sam. Absolutely, TCO dividends are on a higher trajectory just because capital is wound down and as we've said, when we get the incremental production from FGP, it goes even higher. There are some puts and takes. So we talked in last year that TCO had held some surplus cash and released that last year. This year, they're going to have to build some cash as they head into debt payments, which as you recall, we co-lent. So we'll be receiving that. So there are some -- there'll be some timing variation, but your point around the trajectory is absolutely right because CapEx is winding down. So this has been largely self-funded as an affiliate company. As CapEx goes down, there's more cash available. It does depend on commodity price assumptions. You're right, LNG is in there and also petchem. And so those are the major drivers, a little bit of refining are the major drivers of our affiliate dividend. So it's a roughly flat with the prior year. We'll update that as we go along during the year, but absolutely, TCO, we've been investing in that project for eight years. It's going to generate a lot of cash when it comes on next year.

Operator:

We'll go next to Nitin Kumar with Mizuho.

Mike Wirth:

Yeah Nitin, what I would say on technology, I reference the fact that we're drilling more feet out of the same rig fleet, we're improving on completions and so there are a lot of small things that are contributing to the performance that we're seeing right now. The improved recovery technologies are in various stages of being piloted out in the field and so to the extent some of those pilots are in the production, they contribute, but I would say it's at the margin, because we're gathering field data to look at changes in completion and fracture techniques using gas injection and gas lift in different ways using some different chemicals to improve flow. So as we get those into large scale deployment, we'll start to talk about that and we'll help you understand how they're contributing, but I would say right now it's more on the drilling and completions cycle time side that we're seeing some of these improvements and so there's more to come. On midstream infrastructure, some of the issues that we've talked about before can be -- they can be weather related, they can be related to some regulatory items, they can be related to a particular gas processing plant or gathering or off-take pipeline system. We're working all of those because your point is well made as a large producing asset at that scale. We need really, really reliable performance downstream of the wells and we have no constraints on takeaway capacity out of the basin. So we're well positioned, not just for '24 but into '25 and '26 with ultimate takeaway capacity to access the market, but we do have a lot of pipes, pumps, tanks and other things between the field and the market and those things need to perform and that is a high priority for our operations team in the field. As I mentioned, fourth quarter performance was very strong and they're on this and it's a very high priority. We saw a little bit of weather in January, which Pierre guided to that will have a modest impact, but we're confident that we've got a line of sight on all the operational priorities in order to ensure that that market access isn't constrained.

Devin McDermott:

Hey, thanks for taking my question and Pierre, I want to echo the congrats. Thanks for all the help over the years. I wanted to circle back to TCO and Mike, I think last quarter when you provided the updated guidance on timeline, one of the things that you noted was workforce productivity and I was wondering if you comment on some of the changes that you've implemented to improve labor productivity over the past several months, how it's progressing first plan and in your comments, you mentioned improved scope of work in the context of FGP. I'm not sure that's related to labor or something else, but if you could elaborate on that comment as well, that'd be great. Thanks.

Operator:

We'll take our next question from Jason Gabelman with TD Cowen.

Pierre Breber:

Thank you, Jason.

Mike Wirth:

Yeah. So I'll quickly just touch on the Midland Basin where we continue to be a first quartile performer, steady consistent performance. We understand the geology. There's less fluid complexity and so we're a top quartile, first quartile performer there in the Midland. In the Delaware, we last year showed actual data on a Delaware-wide basis and then we showed some forward guidance, particularly focused on New Mexico because we were shifting so much of our program into New Mexico, which, as I mentioned earlier, is a more productive portion of the basin and in the Delaware, New Mexico, we saw significant improvement with our second half POPs. Last year more than 80% of our POPs were in the second half in these more productive areas and the subsurface performance there has been very strong. In the appendix, we've got a slide that shows you 49 POPs out of the 59 POPs were in the second half and you can see that they lay right on the type curve and then you can see the improvement in the Delaware Basin, Texas, which we didn't guide to last year because it was in that combined chart there, but we've seen strong improvement. We've updated our well spacing and completion designs there and within the basin, there are sub-basins and some of those are performing exceptionally strong as well. So we're seeing performance that is very consistent with what we outlined in the markets today last year. I think the shift in basis was just to provide you a little bit more detail into these sub-basins and we'll continue to report on that basis going forward.

Operator:

We'll take our next question from Jeffrey [ph] with TPH & Company.

Mike Wirth:

Yeah, so, we're constantly looking to learn and improve and as I mentioned earlier, we've seen significant improvement in drilling time, completion time, time from completion to POP this year and these are a lot of little things, right? This is as you continue doing things, you find more and more efficiencies. We can bring more technology to bear, etcetera. So, and we look to extend those learnings across the basin and frankly between basins. So into the DJ basin and from the DJ basin down to the Permian, there are differences in the sub-basins that you have to understand and respect, but, the short answer is yes. We are looking for ways to transfer, learnings across there and every time I think we're probably, at the plateau in terms of productivity improvement, smart people find ways to continue to get even better at this and so, I don't think we've seen the end of the performance improvement cycle. Our overall capital allocation into the basin is largely a function of where our portfolio lies. About 25% is in the Midland Basin. 25% is in the Delaware, New Mexico portion of the basin and then the balance about 50% is in Delaware, Texas. It's been that way here, this past year and going forward, that's a pretty good way to approximate it.

John Royall:

Hi, good morning, and thanks and congratulations to Pierre. I'm going to give you guys a break on TCO and the Permian. I'm going to ask a question on the DJ. So just looking at this growth of 125 KBD for '24, how should we think about that growth off of a pro forma '23 basin? Just trying to understand what's kind of the underlying, real growth rate in the DJ and then if you could just update us, with a couple quarters behind you now post PDC [ph] on your broader plans for development, the DJ.

Operator:

We'll go next to Lucas Herman [ph] with BNP Paribas.

Pierre Breber:

Right. No, thanks, Lucas. I'll take it. We've been overweight upstream and overweight oil liquids for a long time and you're right. Recent acquisitions and Hess certainly adds to that and we like that exposure. In terms of how we manage the balance sheet, the first thing is we start with our break even. So what it takes, the oil price it takes to cover our CapEx and dividend, that was in the low 50s last year and so we see mostly upside and that's why we had record share buybacks last year, almost $15 billion, 5% of our shares outstanding, because we're built for a price well below where we currently are. We've also done it while maintaining a strong balance sheet. Our net debt ratio of 7%. We've said as we keep our share, we purchase this steady across the cycle that we're okay re-levering back up towards the low end of our guidance range, which is 20% to 25%. So that guidance that's a kind of through the cycle net debt ratio guidance, that still holds and if we had a significant change in the portfolio, of course we would look at that going forward, but I think the actions that we're taking are consistent with that guidance and again, adding that exposure when you're built at the break even, when we think about our balance sheet, you take into account lots of things, your portfolio, the commodity price outlook, but your breakeven is really key and Mike was talking about capital and cost discipline, our ability to fund our reinvestment program in both traditional and new energies and grow the company and pay a growing dividend, right? More than twice our nearest peer, greater than S&P 500. We just increased at 8%. So all those numbers are before the latest increase. We can do all that at a low price, return surplus cash. That's how we're going to think about it. So again, you'd expect our net debt to increase over time depending on commodity prices and how we return cash to shareholders. We're not having more exposure to high margin barrels, as you say. That's a good thing. We're built for it and as long as we keep our break even low and below where prices are trading, we're in a really good spot.

Pierre Breber:

Oh, yeah. So TC loan payments, sorry about that, yeah, because I alluded to that. That will not be in cash from ops. That shows up in our investing cash. So Jake and the team will take you all through that, but yeah, what I was saying about that affiliate line flipping, that's separate from this in a different line. We will see cash being returned and it's a billion our share next year, again two billion in '26, and then in '28 or '30. So all that's disclosing our 10-K. Jake can take you through that. but yeah, that's only additional and again, we shouldn't be surprised. We've been investing for eight years in this project. That cash is going to come back once the project starts up.

Operator:

We'll take our next question from Irene Himona with Société Générale.

Pierre Breber:

So I'll start, Irene, and then Mike can take the macro. Yeah, it's a function of PDC, certainly, and then just continued the associated gas that comes along with the Permian. So as we're growing that, it obviously comes along with natural gas.

Operator:

We'll go next to Bob Brackett with Bernstein Research.

Mike Wirth:

Well, coming into this year, we now have a full year of PDC that will be part of the portfolio. So that's pretty safe in terms of counting on that. I've already mentioned that fourth quarter was a little bit higher than maybe we even might have expected because we had high reliability. Some of these midstream issues we'd faced in the Permian had didn't repeat. We had this accounting catch-up thing in the Permian as well and we had a pretty light turnaround schedule in the fourth quarter. So it was a strong quarter all the way around. As we head into next year, we've got some asset sales in the guidance and, Bob, we've been at the low end. We've kind of ended up last couple of years hitting our guidance range, but at the low end and so I think you could probably think of this as being a little more comfortably in the middle of the range this year, given a number of the things that you mentioned. So, we try to give you guidance each year that we expect to hit, and we certainly expect to hit it this year.

Neal Dingmann:

Thanks for getting me in. My question, Mike, is maybe just on the Chevron return specifically trying to get a sense of, sounds like you will, but just want to get a sense if you'll continue paying out a majority of free cash flow for the remainder of this year and if the buybacks will continue to constitute, a bit over 50% of that payout?

Pierre Breber:

Hey, and I would just add, let me just add a little bit. It's fitting maybe my last words will be on share buybacks, six straight years of buybacks, right, 17 years out of the past 21 years, but we actually bought back more shares last year than the year before, even though earnings and cash flow were higher, right? There were records in '22, still strong in '23. That's the whole point. We're trying to be steady across the commodity cycle. We've heard from investors that buybacks should not be pro-cyclical. And it's hard to be counter-cyclical in the commodity business that has some price volatility. So being steady across the cycle is how we guide to it and these formulas, in fact, reinforce the opposite. They reinforce pro-cyclicality. So we're giving a return that in some ways is almost independent of prices within a range because we're could have paid more out in '22, but we held it back and we use some of that to pay in '23. We'll see where it goes, but the intent is to try to be steady across the cycle, either pro-cyclical nor counter-cyclical. Thanks Neal.

Mike Wirth:

I would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation on today's call. Please stay safe and healthy. Katie, back to you.

Jake Spiering:

Thank you, Katie. Welcome to Chevron's third quarter 2023 earnings conference call and webcast. I'm Jake Spiering, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement on Slide 2. Now, I will turn it over to Mike.

Pierre Breber:

Thanks, Mike. We delivered another quarter with strong earnings, cash flow and ROCE. This quarter's results included two special items

Operator:

Thank you. [Operator Instructions] We'll take our first question from Roger Read with Wells Fargo.

Michael Wirth:

Yes, Roger. Look, I'll let Pierre cover this in a little more detail, but there's – I recognize this quarter was a tough one to model. And there's pretty material or significant non-cash charges. Timing effects, primarily inventory costs, we see with rising prices some tax reserves and charges for legal abandonment and other things and then some lower realizations with your mix and the lag effect in some of our LNG pricing. On timing and inventory costs in particular, on period-to-period comparisons where we had a prior period, whether it was last quarter or the same quarter last year, where prices were coming down and then in the current period, we see prices strengthening significantly, you really get pretty significant deltas on the way we cost inventory. And if you go back to the, I think, the first quarter of 2022, we had some similar dynamics. So anyway, that's kind of high level on it. Pierre, maybe you can talk a little bit more about the upstream and international upstream in particular.

Roger Read:

No, thanks. I'll sum it up as messy. I appreciate it. Thanks.

Operator:

I apologize. We'll take our next question from Josh Silverstein with UBS.

Michael Wirth:

Yes. So Josh, there's going to be some more capital, we said 3% to 5%. So think about around $1 billion Chevron share over 2024 and 2025, probably a little more weighted to 2024 than 2025. Cash flow from the operations will be lower by about $1.5 billion at $60 Brent in total over the next two years really due to the delay in the project. So it's equivalent to about 50,000 barrels a day in net production in each of those years. So in total, we expect our share of dividends to be lower by about $2.5 billion across 2024 and 2025 from the prior guidance. And so it's a combination of those things. And so we had previously guided to above $5 billion. We're now seeing above $4 billion and a little more of that coming from production and cash flow from ops as opposed to CapEx.

Michael Wirth:

Thank you, Josh.

Operator:

We'll go next to Neil Mehta with Goldman Sachs.

Michael Wirth:

Yes. So the main message here, Neil, is as we completed both WPMP and then mechanical completion of FGP and we've begun to get deep into the commissioning, we've, I think, previously mentioned we worked with some technical issues with our utility systems. And as we did that and we saw some of these impacts, we commissioned an independent cost and schedule review off cycle. We normally do these annually, but we didn't want to wait. And so as we saw some of this evidence that things were going slower, there were some more discovery work, we sent in an independent team to give us kind of a cold eyes assessment on cost and schedule. And I think the main thing that I would distill that down to is the recommendations from that and that are embedded in our updated guidance today reflect a more conservative forecast of commissioning progress. And so we're assuming things will take longer than the prior plan. We're assuming we're going to have discovery items that tend to come up in complex projects like this. And in response, we've implemented some significant changes in terms of how we're approaching this. We've moved contract resources over from 3GI, which is a portion of the Future Growth Project, which is now completed and fully commissioned over onto the other commissioning work. So we've added contract resources there. We brought in experienced turnaround and operations people that are very skilled in the discovery work, in managing through the restart of and operations of facilities now to help us with this. And then we've also added technical resources to address any unplanned discovery items that would come up. So we've had a significant change in our approach to this. We've got a more conservative guidance here that we're issuing now. And we'll continue to talk about this every quarter. I guess, the main things to look at here are we've got big compressor trains that will start up for pressure boost, which is a key driver of this high-pressure to low-pressure conversion. These are very large machines. And so those are key milestones. After that, we've got metering stations that are converted from high pressure or low pressure. And so over the next few quarters – and there's, I think, 40-some-odd metering stations as you go out through the entire field. We've got these two big turnarounds that I've talked about. All of those are really key milestones that we'll be tracking very closely. And we'll update you on those as we go forward.

Devin McDermott:

Hey, good morning. Thanks for taking my questions. I wanted to just stick with upstream, but actually ask about Venezuela. You've had some increase in production year-over-year, given the initial sanction relief. And there's obviously been some additional sanction relief announced just since the last quarterly call. I think you might have been on an interview this morning. You made some comments that you could see a sequential increase in production between now and year-end. I was wondering if you could just step back, talk through what impact this sanction relief has on your production profile and also willingness to invest in that region. And can you remind us how impactful Venezuela volumes are for your corporate cash flow?

Pierre Breber:

Yes. Consistent with what Mike just said, we're continuing to do cost affiliate accounting, which means we are not – we don't record production or reserves, right? So that's not reflected in our numbers. And we only record earnings when we receive cash. So we're not – we're recording a proportionate share of equity earnings, but only what we actually receive in cash. And that's something that we'll continue to look at. And as Mike said, depending on all those potential triggers down the road, elections and such, we could go back to equity accounting at some point in time. But we have not made that decision yet. In terms of cash flow, it's about 1% of our cash flow. So it's modest, of course. But it's more than it was before. And so as Mike said, operations there are continuing well. And we're getting a little bit of cash. And we'll just see where it goes from here.

Michael Wirth:

Thank you, Devin.

Biraj Borkhataria:

All right. Thanks for taking my question. I'm sure you get a few more on TCO. I just want to ask about the Permian. Last quarter, you gave some very helpful data points on well productivity this year. I was wondering, particularly for the New Mexico side, if you had any incremental comments for wells driven in the third quarter. Because I know it was a pretty small sample size of POPs in the first half of the year. So any comments there would be helpful. Thank you.

Biraj Borkhataria:

Okay. Understood. Thank you very much.

Operator:

We'll go next to Sam Margolin with Wolfe Research.

Michael Wirth:

Good morning, Sam.

Michael Wirth:

Yes. Sam, you're right. I mean, we are seeing pressure in the U.S. And I think we're probably going to end up higher than our budget as we end the year. PDC is being integrated into the factory pretty much as we expected. And so it's an increment because it wasn't in our original plan. But it's really not a driver of this. The big thing is we're seeing actually more feet drilled per rig and more completion feet than we had planned. And so the productivity of the primary development activity has continued to improve. But that means we spend more money on tubulars, on sand, on water than we had anticipated. So it's kind of a good news, but it brings with it some costs. We've got some long lead items, where we're seeing supply chain realities that say we need to place long lead orders earlier. So some things we otherwise would have ordered next year that we've actually moved ordering and initial payments on into this year. So there's some long lead dynamics going on. And then I mentioned earlier, produced water is becoming an issue, the reinjection of that and doing that in a way that minimizes the incidences of induced seismicity. So we've got some more produced water handling infrastructure spend. So I would say those are kind of the primary drivers. And that's pushing the Permian to be a little hot. Gulf of Mexico is pretty well right on plan. And so what you're seeing there is really a function of PDC, which is just an increment that's been added, and then some additional costs in the Permian program that we really hadn't anticipated as we went into the year.

Sam Margolin:

Understood. Thank you.

Paul Cheng:

Thank you. Good morning.

Paul Cheng:

Mike, can I get back – can I go back to TCO? It's a little bit of the late stage for the cost increase and everything. I guess the question is that, I mean, what have we learned from this process and to ensure that your future project execution will become better and not facing the kind of problem that, I mean, it has been a challenging project that all along due to a number of different reasons. But quite frankly that this is a bit disappointing at this very last stage for the bit of the slip in the schedule and also the cost increase? Thank you.

Pierre Breber:

And I'll just add some comments on affiliate dividends. So we've given a guide on fourth quarter affiliate dividends, which falls short of the full-year guide that we did at the start of the year. That shortfall is not from TCO, that's from CPChem, Chevron Phillips Chemical Company, on lower petchem margins. It's also from Angola LNG on lower TTF prices than we had assumed. We've also had some of the Angola LNG cash has come back to us as return to capital. In terms of TCO, we had a $600 million dividend Chevron share in the second quarter. We can't get ahead of the TCO Board on the fourth quarter. But 90% or so of the fourth quarter guide is related TCO. I'll remind you last year that TCO dividend was $1.6 billion Chevron share. All these numbers are before the withholding tax. So we'll see a pretty significant increase in the total year TCO dividend. Now some of that was the – getting some of the excess cash off the balance sheet like we were talking about. But if you go back to the period prior to the start of this construction, so the period into 2015, we're seeing dividends now – or this year's dividend will be similar to what we saw from that time period. So the inflection is happening after five years of either not receiving dividends or, in fact, putting cash out, essentially having negative free cash flow. So we know production is going to be down next year. We showed that. So you'd expect dividends to reflect that a little bit. We have a little bit of increase in CapEx. And then we'll be heading to this more than $4 billion in 2025. And all of that is – that guidance is at $60. So we're seeing some positive news in terms of the cash flow coming out. Clearly disappointing news on the revised schedule, but we're going to work hard to deliver it in the front end of the range. Thanks, Paul.

Operator:

We'll go next to John Royall with JPMorgan.

Michael Wirth:

Yes, John, we're not changing the guidance. Overall on production, excluding PDC, we expect to be the lower end of overall guidance. Permian production is expected to ramp up in the fourth quarter. Full year production expected around 770,000, 780,000 or so if you include PDC. And so yes, the guidance is still intact for the Permian. Go ahead, Pierre.

John Royall:

Thank you.

Douglas Leggate:

Thanks. Good morning everyone. Mike, I know you've been traveling around, so thank you for making the time for us this morning. I want to try and defend you a little bit here this morning. Because if you look at the remaining life of Tengiz, about half of that value has been taken out of your stock this morning. I can't imagine you're happy about announcing another series of challenges. So my question is this, at a philosophical level, how would you characterize what you and your management team and the organization are doing to avoid these kind of issues on major projects going forward? You've got a lot of things in the queue through 2027. Why should the market be comfortable that you can execute on that timeline with what you have in your portfolio?

Pierre Breber:

And I'll just restate the impact that Mike – yes, thanks, Doug. And I'll just restate the impact that Mike talked about. It's $2.5 billion, that's at $60, that's less than $1.50 a share. So clearly, they were down a lot more than that. We talked about the earnings in this. We know that weighs also on the shares, at the same time, non-cash items, timing effects that reverse and discrete items that are nonrecurring. So we feel good about the company's performance in the quarter in terms of how we operated safely and reliably, how we captured margin. We know, as Mike said earlier, we have these quarters where it can be messy, can be noisy. It's one of them. But the underlying company is very strong and healthy.

Pierre Breber:

Thanks.

Irene Himona:

Thank you very much. Good morning. You're referring to your comments to higher OpEx and DD&A from the PDC legacy assets having impacted Q3 upstream. Now that you own that business fully and you can sort of look under the bonnet, how are you thinking about your original synergy estimates on PDC OpEx and CapEx? And how long would you expect it takes for those to start accruing to you in the results? Thank you.

Irene Himona:

Thank you very much.

Operator:

We'll go next to Jason Gabelman with TD Cowen.

Michael Wirth:

Good morning, Jason. Yes, we are here.

Michael Wirth:

Sorry to wake you up, Jason.

Michael Wirth:

I can.

Michael Wirth:

Yes, I'll take the second part of that and then ask Pierre to address the cash and production impact. It doesn't change our view on the development opportunities really at all, Jason. This is a long-term play. It's a very, very large gas resource. We like some of the follow-on exploration opportunities in the region. We're working on the Aphrodite field in the waters offshore Cyprus to develop. We're working expansion projects that have been sanctioned on both Tamar and Leviathan and further expansion ideas on Leviathan. And so we've got to take a long-term view, which is measured in years and decades. And when you have things in the short-term that create the circumstances that we see right now, we have to be prepared to mitigate those risks and to keep people safe and maintain the integrity of our operations. But it doesn't change our long-term view on the attractiveness of the asset and the development opportunities. I'll let Pierre address the cash question.

Jason Gabelman:

Okay.

Ryan Todd:

Thanks. Maybe switch gears a little bit to the Gulf of Mexico. Can you maybe just provide any update on an overall basis? Do you anticipate the addition of the Hess assets in the Gulf to have any impact on your approach to the basin in the coming years? And then you're scheduled to have three separate projects hitting at Anchor, St. Malo and Whale come onstream during 2024. Could you maybe update us on the progress of those projects and maybe the timing whether we should expect those in the first half or the second half of the year?

Pierre Breber:

Ryan, just more broadly on Hess, we are not planning to hold our Investor Day at our usual timing. We'll likely either have just closed or will be in the antitrust review process. This is a big transaction impacting Gulf of Mexico but transforms the portfolio overall. We gave some guidance on potential asset sales also. So you should expect us to do an Investor Day several months after we close and when we have time to really put together a combined business plan for our investors.

Pierre Breber:

Thanks, Ryan.

Operator:

We'll go next to Bob Brackett with Bernstein Research.

Michael Wirth:

I'd say overall – and of course, we met with – I was out. Pierre was in some separate meetings than I was. But I was out in a number of meetings with John Hess, sometimes the larger Hess shareholders, sometimes with larger Chevron shareholders. I would say, in general, people see the long-term value proposition very clearly here. And I think they see it as a combined company that is stronger and one that is set up to be stronger for longer with the ability to really sustain cash distributions to shareholders in a very consistent, predictable and durable fashion long into the future. And so that is – there's no doubt about that. Some of the questions, on the one side, did you get a high enough price? On the other side, did you pay too much, right? So there was tension in the – in that, to be honest, during the negotiation. It was – as we mentioned, this has been going on for some time. And John and I have been looking for a way to do a deal that is actually one that's good for both sets of shareholders and not easy because it's a great asset and the market recognizes that value. And so I think you can find nuances from people who either held one of the stocks or the other for certain reasons. And maybe this wasn't exactly what they expected. But broadly speaking, I would say people see the long-term value creation. They see the transparency to resource depth, to production growth. The fact that you now have – with Hess, you've got a much more diversified set of assets attached to their portfolio, which derisks any one of those assets. And it brings forward cash distributions to their shareholders meaningfully that would have still been several years into the future. For the Chevron shareholders, who were wondering what comes next after what they can currently see over the next several years in our portfolio, rather than us pointing to a range of potential answers to that and say, "We'll do the best of these," and we've got plenty of organic investment opportunities we're working on, I think it gives some confidence and certainty of what underpins that for the future. And so broadly speaking, those are the kinds of discussions that we've had.

Operator:

We'll go next to Neal Dingmann with Truist Securities.

Michael Wirth:

Yes. We've had a very consistent set of financial priorities for many, many years. The first of which is to sustain and grow the dividend, 36 consecutive years now of per share dividend payouts for the last five years has been a 6% CAGR. Actually, I think the last 15 years have been a 6% CAGR and an announcement of 8% early next year, subject to Board approval. I think there's a strong track record there you can expect to continue. Second is to be disciplined in organic reinvestment into the business to grow those cash flows. You can be confident that we will continue to be disciplined in that reinvestment to drive returns and value. Number three is a strong balance sheet. Pierre mentioned we're single-digit net debt ratio today. That's lower than we have guided to over time. And so over time, you can expect the balance sheet to move back towards the 20% to 25% gearing range that we've identified as where we're comfortable through the cycle. And then the fourth are the share repurchases. And we've got a range now of $10 billion to $20 billion. We're at the high end of that range when we close the transaction with Hess with $17.5 billion annually. Today, that's 5% to 6% of our float each and every year. And we've – I won't go through the details, but we've indicated we can sustain that in a lower price environment. And that's where the lower end of that range would apply. And certainly in a higher price environment, which is where we find ourselves today, we're at the high end of that range. And so we would expect to be consistent, predictable and to sustain that. I mean, consistent and durable being the keywords here. So I think the broad framework is likely to remain unchanged. And I think our behavior will be very consistent with what you've come to see from us historically.

Michael Wirth:

Thank you, Neal.

Alastair Syme:

Thanks. Hi, Mike, Pierre and Jake. Can I go back to Hess? For several years, Chevron has looked a bit different to the other integrated oil companies in terms of the low downstream exposure. And of course, now you're re-weighting even further to the upstream. So does that balance bother you at all? Or maybe how do you think about what an integrated oil company is?

Alastair Syme:

Thank you, Mike.

Jake Spiering:

I would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation on today's call. Please stay safe and healthy. Katie, back to you.

Jake Spiering:

Thank you, Katie. Welcome to Chevron's second quarter 2023 earnings conference call and webcast. I'm Jake Spiering, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. Please review the cautionary statement on slide 2. Now, I will turn it over to Mike.

Pierre Breber:

As Mike said, strong, consistent financial performance enabled Chevron to return record cash to shareholders this quarter, while also investing within our CapEx budget and paying down debt. Working capital lowered cash flow primarily due to true-up tax payments outside the US. Excluding tax payments, working capital movements are variable. Our typical pattern in the second half of the year is to draw down working capital. Chevron's net debt ratio ended the quarter at 7%, significantly below the low end of our guidance range. Surplus cash on the balance sheet was reduced during the quarter, with cash balances ending at $9.6 billion, well above the cash required to run the company. Adjusted second quarter earnings were down $5.6 billion versus the same quarter last year. Adjusted Upstream earnings were lower mainly due to realizations, partly offset by higher liftings. Other includes primarily favorable tax items and income from Venezuela non-equity investments. Adjusted Downstream earnings decreased primarily due to lower refining margins. OpEx was up mainly due to higher transportation costs and the inclusion of REG. Compared with last quarter, adjusted earnings were down $900 million. Adjusted Upstream earnings decreased primarily due to lower realizations. This was partially offset by higher production in the US and non-recurring tax benefits. Adjusted Downstream earnings were down modestly, lower margins were partially offset with higher volumes. Second quarter oil equivalent production was down about 20,000 barrels per day from last quarter, primarily due to planned turnarounds at Gorgon and in the Gulf of Mexico and downtime associated with the Canadian wildfires. This was mostly offset by growth in the Permian. Now, looking ahead. In the third quarter, we have a planned turnaround at TCO and a planned pitstop at Gorgon, completed earlier this week. Our full-year production outlook is trending near the low end of the annual guidance range. Since PDC's proxy solicitation on July 7th, we've not been permitted to buy back our shares. After we close the acquisition in August, we plan to resume buybacks at the $17.5 billion annual rate, which we expect to continue through the fourth quarter. We do not expect a dividend from TCO until the fourth quarter. Full-year affiliate dividends are expected to be near the low end of our guidance. Putting it all together, we delivered another quarter with solid financial results, strong project execution and continued return of cash to shareholders. Our approach is consistent and you can see that in our actions and results. Back to you, Jake.

Operator:

Our first question comes from John Royall with J.P. Morgan.

Michael Wirth:

Guidance remains unchanged. We expect to be at the lower end of that. And as we said, Permian production has been strong. The things that Pierre mentioned I think are the key things that we've seen. There's been some impact of fires in Canada that have impacted our ability of, not really our operations per se, we did some evacuations on a precautionary basis, but it was midstream and processing downtime that we weren't able to move our production to market. And the rest of it is – oh, and Benchamas too, I guess, is the other one. We have an FPSO in Thailand that had an incident and early in the year was taken off station. And so that's another 10,000 or 11,000 barrels a day net, which is off for the foreseeable future. And so, it's really those two things are the ones that are pushing us down that were both unexpected.

Michael Wirth:

The thing that I think it's important to bear in mind is that New Mexico type curve we showed there, there are only 10 POPs represented or 10 POPs that we achieved all in the second quarter there. So there's no first quarter POPs. And there's only seven that actually had enough data to make it into the curve you see on the chart. So it's a very thin set of data. We expect 30 more POPs in the second half of this year, so that the bulk of the program is not representative of those curve. And there's a couple of other things, one that the wells we did POP have had some facility constraints that have limited full productivity. So we actually haven't been able to move all the production due to some third party facility constraints that we faced. And the rest of the program is actually in a different part of the New Mexico portion of the Delaware, where we expect higher productivity. So, it's a combination of things. But I'd caution you not to over-index on a very thin dataset with a lot more data to come in the second half of the year.

Devin McDermott:

I wanted to just stick with the Permian since we're on that topic. I was wondering if you could talk a little bit just around the mix trend that you're seeing there. And if we disaggregate the productivity a little bit further, you talk about how much of the uplift is coming from gas and NGLS versus oil. And then similarly, as you progress towards your longer term production goals, how you expect the mix in the basin for you to trend oil, gas, NGLs over time.

Devin McDermott:

I wanted to shift over to TCO. Good to hear the continued positive progress there as we get closer to the finish line. There's a lot of moving pieces over the next year, year-and-a-half as we get the two phases of development online. You give the guidance for the turnaround impact in 3Q. I was wanting to talk a little bit more about how you see the evolution of production into the fourth quarter of this year and then through 2024, as we get to that 2025 run rate. So, shape it a bit for us as we look out over the next few quarters.

Jake Spiering:

Slide 10 from our set has annual production, 2023, 2024, 2025. Yeah, no change in that guidance.

Neil Mehta:

I want to stay on TCO. And while there will be a volume inflection in 2025, there's probably going to be a free cash flow inflection in 2024, just as affiliate CapEx rolls off first. And so, can you talk about the cadence of that and how it manifests itself in terms of dividends?

Neil Mehta:

The follow-up is just on the return of capital. I think while you have a big buyback range, a lot of market participants have kind of viewed your $17.5 billion dollars as the P50 outcome in any reasonable commodity price environment. And so, thinking less of it like a flywheel and more as sort of a relatively fixed number unless commodity prices go wacky. Just any thoughts on that statement and whether you're trying to give us a little bit more surety around that number as opposed to a more volatile number.

Michael Wirth:

Neil, I would just add, you see in our second quarter results that our net debt remains very, very low. And we've indicated multiple times that we don't have a problem gearing back up and putting more debt on the balance sheet to get back towards the range that we've guided to through the cycle in order to sustain a very steady share repurchase program.

Stephen Richardson:

Mike, I was wondering if you could talk a little bit about new energies. I think you've been clear from the beginning that build versus buy was part of the consideration in a lot of these businesses. We saw a big CO2 pipeline and EUR company transact recently. So maybe you can talk a little bit about the CCUS business as you view it and why build versus buy is maybe the better choice for Chevron? Maybe I should get ahead of it with a follow up as maybe you could give us a little bit of an update on Bayou Bend please?

Operator:

We'll take our next question from Biraj Borkhataria with RBC.

Michael Wirth:

Biraj, if you look back over the last decade, we've cleaned up our portfolio. We had a lot of assets that were kind of at the smaller end of the tail that pulled capital and management time and resources. And we want to be diversified. We've got a diverse portfolio. But we don't need to be diversified just for the sake of it. We want to have assets that have scale, that are material and long lived. You can start in the Far East and look at our LNG positions in Australia, which aren't drawing a lot of capital right now, but are [Technical Difficulty] acquisition in the EG assets that can feed LNG into Europe. Obviously, you mentioned TCO. The Eastern Med is a very strong position. We've recently taken FID and are working on expansion projects for tomorrow, Leviathan, and have submitted a concept on Aphrodite. So there's a lot of opportunity in that asset. When we close PDC, we're going to be producing 400,000 barrels a day in the DJ Basin. We've talked about some of our other shale and tight assets in Argentina, in Canada. We've got two crackers underway in CPChem that will come online middle of this decade, one in the US, one in the Middle East. We've acquired REG and are growing our renewable fuels business. So we have exposure across a large portfolio. And then, of course, we also have projects coming online in the Gulf of Mexico. I mentioned Anchor earlier, Whale, Ballymore. And we recently acquired more leases in this recent lease sale than the – twice as many leases as in the biggest lease sale over the last eight years. So we're adding to our position in the Gulf of Mexico. So this idea that we're a two asset company, the Permian and TCO, I don't think really stands up to careful inspection. They're two great assets, and so they get a lot of attention, but we've got a lot of other strong assets in our portfolio.

Biraj Borkhataria:

Just following up on a different question. Through the Permian, you'll be producing a lot more gas over time and you have expressed a desire to grow in LNG. So, you've signed a couple of deals as an offtaker to synthetically integrate your US gas position to global markets. I wanted to ask about the sort of – whether you'd be interested in owning liquefaction or whether you feel being an offtaker is enough because some of your peers have argued the benefits of integration and owning through the value chain. But I think in the past, you've noticed the returns are typically lower. And I'm particularly interested in asking that question now because a number of players have signed offtake agreements with companies such as Venture Global, and then actually they're not receiving the gas as agreed. So it's interesting how you're thinking about that sort of value chain in LNG.

Operator:

We'll take our next question from Sam Margolin with Wolfe Research.

Pierre Breber:

Well, the direction that it goes depends, of course, on commodity prices and margins and a number of other factors. You're right, our cash levels have come down, in part due to working capital outflows, timing of affiliate dividends. And we've also paid down some debt. We've been, I think, very clear that we don't want to hold surplus cash, certainly not permanently, that it's where the cash goes in the short term. But, over time, that cash is going to be returned to our shareholders in the form of this growing dividend and ratable buyback program. So we need only about $5 billion to support our operations. We're nearly $10 billion at the end of the second quarter. So that's more than sufficient. We have access to lots of liquidity. We don't have any commercial paper now. Again, we've been paying down debt. So that's the more economically efficient way to manage the balance sheet if we get there. And whether the balance the cash balance goes up or down again depends on all the inputs and outputs that we've been showing. We're guiding towards the net debt, as Mike said. The net debt is well below the low end of our guidance range. So, we look at all those factors. And again, if cash balances head down to $5 billion, that'll be adequate to cover the operations. On working capital, our pattern the second half of the year is that we tend to see some draws on it. But we're certainly not going to recover from what we've seen this first half of the year. A big portion of what we saw in the first half of this year on working capital are really tax payments tied to earnings last year. So you can kind of think of those as being offset from last year where we had that favorable working capital environment. So, there'll be ups and downs along the way. Over time, working capital tends to average out over zero. But these are just timing effects. We look through them. We knew we had taxes due. And so, that's all part of the planning as we look at the balance sheet.

Sam Margolin:

Sorry, I must have misread that remark. The follow up is actually sort of on the organization. It's a follow-up to Steve's question earlier. But Pierre had spent some time in an ESG role and the low carbon role. And the incoming CFO is coming from a role where there was a lot of work on the ground on the low carbon front, on the technology side. And so, Chevron has this really interesting sort of marriage between finance and low carbon that I think is differentiated when you look at some of the peers. And so, the question is, as we make progress through the low carbon development, do you feel like you're embedded in the highest return areas? Or are there other ones where capital is going to maybe pivot? And I think that ties into carbon capture too because that seems like a place where the incentives are pretty transparent?

Operator:

We'll go next to Jason Gabelman with TD Cowen.

Michael Wirth:

Jason, Permian CapEx is up a little bit this year. Primarily three things. Number one, we've actually seen our drilling performance continue to improve and completions performance continue to improve. So out of the same fleet of rigs and completion spreads, we're getting more work done, which means you consume more tubulars, more sands, more water, et cetera. So, that's kind of a good thing. We're seeing some longer lead times on some of the critical elements in facilities. And so, we've actually had to make some long lead purchases for next year's program that we didn't anticipate as we were lining up this year's program. And then, we've increased facility scope for water handling in some areas of the Permian, particularly as we're trying to manage some of these induced seismicity issues. We're being more and more careful removing more water. And so, that has all led to some increase in CapEx. Not a lot of inflation there. The inflation has been largely in line with what we had expected and the rig fleet is being activated in line with what we expected. Your second question on inventory, we haven't broken our portfolio into tiers. There's not a very clear definition of that and a way to kind of do that on a standard basis. So when we've outlined the drilling locations and the long term guidance there, it's really based on economics. And we've got locations that are economic at our price view for the future, which has historically not been a super aggressive price view. It's based on today's technology. And as indicated, we've got more than 6,000 locations in that outer time window that are economic based on those assumptions. By the time we get to that window, we may or may not see a different price environment. I fully expect we'll see a different technology environment, which can allow that number to grow even further. So we look at it more in terms of the economics of the development than tiers.

Pierre Breber:

Jason, we do it quarterly. Like, it's included in the third quarter guidance that we provided. And we'll continue to do that quarterly and you're seeing sort of annually. We're giving annual guidance on TCO. So it's all embedded in there. I think we showed it relative to 2022. But there's just a lot of moving parts. But we'll continue to give that guidance each quarter and you have annual guidance that incorporates all of that.

Irene Himona:

My first question is on the Downstream, please, if you can talk around the performance of your chemicals affiliates, in particular in Q2 and then what you're seeing so far in the third quarter. And then, also what you would expect in terms of refining margin evolution in the second half of the year, given the weakness in Q2.

Irene Himona:

Based on that, following your FID for the pipeline in Israel, I was wondering, is that it for the time being for Leviathan? Or do the partners continue to examine other options like FLNG, for example?

Operator:

We'll go next to Ryan Todd with Piper Sandler.

Michael Wirth:

The performance is really consistent with our expectations and what we outlined at our Investor Day earlier this year, Ryan. There are a couple of things just to remember. I mentioned earlier that, in New Mexico, we saw some infrastructure and third party constraints, and you can have that – we've got that in some other parts of our portfolio as well. So there are things that will show up on these curves that are not necessarily – just a reflection of the geology and the well performance. And as we continue to change our development strategy on well spacing, profit loading, well length, et cetera, those will continue to be reflected in these curves. The thing that is really important is production – we put production out there because everybody likes to see it. We're not optimizing the production. We're optimizing the returns. And so, fluid mix, EUR, capital investments are all important parts of what we're optimizing to. It's harder for you to see all the things that we're looking to optimize to drive returns when you're just looking at production. The high level answer is performance in line with the expectations as we've continued to evolve our program.

Pierre Breber:

Yeah, those projects were contracted at a different time. So they reflect mostly locked in rates, as you'd expect. Procurements well behind us as we're getting – as projects are pretty far along. So new exploration activities, we'll get exposed to some of the higher rig rates on that, but for the existing major capital projects, that's largely locked in.

Operator:

We'll go next to Paul Cheng with Scotiabank.

Michael Wirth:

Paul, in Cyprus, we're pleased with the outcome of the recent appraisal well. We've submitted our development plan to the government for their approval and it involves a capital efficient way to take the gas to market via subsea tiebacks to existing infrastructure. But this is all pending government approval. If we get that, we could be into FEED later this year. But it's a little early for us to really lay anything out on first gas. So as we get through the government approval process, we'll get back to talk to you about the timeline on that one. On Argentina, we remain very positive on the resource there. There's an election coming up. The country's got its some kind of macroeconomic challenges that it's facing right now. But we like the block, particularly our El Trapial area where we're doing some more development work now with some increased capital that flows with that. We'll talk to you about that at Investor Day and beyond. But no real changes there. It's going to be part of the growth story.

Doug Leggate:

My first question is on the Permian ratability. It looks like you've got about a couple of hundreds POPs this, wells to sales. 2,000 over the next five years. Is that ratable? How should we think about the step up in activity?

Doug Leggate:

They're fairly ratable, Pierre? Like, 500 a year type of deal or 400 a year type of deal.

Michael Wirth:

Of course, Doug, quarter to quarter, there's some variability as we saw first quarter to second quarter this year. The third quarter is going to be a little – so there can be some surges and plateaus quarter to quarter, but on an annual basis, yeah, it's going to be pretty ratable.

Michael Wirth:

The concession is a decade away. We're focused on delivering the project right now. This is a big, complex asset, a big, complex project. We'll certainly be in discussions with the government over time about potential extension of this. It'll reflect what we see in terms of reservoir performance and production opportunities out into the future. These concession discussions have to create value for the country and for Chevron. So we've got to find something that works for both parties. We've walked away from concessions, as you've covered extensively, Doug, where it didn't work for us, in places like Indonesia and Thailand. We've extended in places like Angola where it did. So we'll be talking more about that over time. But, right now, we're really focused on project execution and delivering FTP.

Roger Read:

I guess my first question for you, with the extension of your tenure, are you willing to share with us what some of the things you're hoping to get done and the extra time will be, or maybe what some of the real opportunities are here that you'd like to shepherd through?

Roger Read:

I commend you for not trying to duck out when things finally look good for at least a short time. My follow-up question is really much more on the modeling front. If we look at your realizations on oil, they were much stronger here in the second quarter. I think that contributed to some of the outperformance. But what we really saw was a dip Q1 and an improvement Q2, kind of back in line with traditional. So, I was just wondering, as we think about – was that a timing issue, a regional issue, first quarter, and anything we should be thinking about as we look at your realization or capture on oil prices going forward?

Jake Spiering:

I would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation in today's call. Please stay safe and healthy. Katie, back to you.

Jake Spiering :

Thank you, Katie. Welcome to Chevron's first quarter 2023 earnings conference call and webcast. I’m Jake Spiering, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me. We will refer to the slides and prepared remarks that are available on Chevron’s website Before we begin, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. Please review the cautionary statement on Slide 2. Now, I will turn it over to Mike.

Pierre Breber :

Thanks, Mike. We reported first quarter earnings of $6.6 billion, or $3.46 per share. Adjusted earnings were $6.7 billion, or $3.55 per share. We had one special item this quarter related to changes in the energy profits tax in the United Kingdom. The appendix of this presentation contains a reconciliation of non-GAAP measures. Strong operating cash flow enabled Chevron to deliver on its financial priorities during the quarter a 6% per share dividend increase, higher CapEx within budget, net debt ratio under 5%, share repurchases at the top of our prior guidance range. Adjusted first quarter earnings were up over $200 million versus last year despite 20% lower oil prices. Adjusted Upstream earnings were lower mainly due to realizations and adjusted downstream earnings increased primarily due to higher refining margins. Both segments benefitted from a change in timing effects. Higher interest income and lower accruals for stock-based compensation decreased all other charges. Compared with last quarter, adjusted earnings were down $1.1 billion. Adjusted Upstream earnings decreased primarily due to lower realizations. Other items include the absence of last quarter’s dividend withholding tax at TCO and lower exploration and transportation expenses. Adjusted Downstream earnings were essentially flat. Lower margins and volumes were offset with higher chemical earnings and other favorable items including trading results. Lower accruals for incentive-based compensation decreased All Other net charges and also benefitted the operating segments First quarter oil equivalent production was down about 80,000 barrels per day from last year due to the expiration of a contract in Thailand and the sale of our Eagle Ford asset. This was partially offset by growth in the Permian. We expect 2023 production growth in the Permian to be back-end loaded as wells put on production, POPs increase across both operated and non-operated areas. We expect our royalty production to be roughly flat. As discussed during our Investor Day, we’re increasing activity in New Mexico. All four company-operated rigs added this year, one each quarter, will be in New Mexico, leading to more POPs expected in the second half of the year and into 2024. We also continue to be active in Texas. Last year, about half of our company-operated production was in the Delaware Basin in Texas with the remainder split about evenly between the Midland Basin and New Mexico. More than half of our non-operated production is with five major operators in large, contiguous positions in core areas with multiyear development programs, where we have visibility to capex and execution schedules and a royalty benefit compared to the operator. The balance is with dozens of other operators where we have a little less visibility, but similar predictability from greater diversification. More than half of our royalty production comes from the Pecos River area in the heart of the Delaware Basin. The balance of our royalty position is in the remainder of the Delaware and Midland Basins, also with well-known operators. In summary, Chevron has a large, diverse position in the Permian with a unique royalty advantage where we learn from our own operations and from others. Now, looking ahead. In the second quarter, we expect planned turnarounds at Gorgon and in the Gulf of Mexico along with downtime at a FSO in Thailand and a number of planned refinery turnarounds. Also, we expect share buybacks to increase to a $17.5 billion annual rate. In summary, 1Q was another quarter with strong financial results, continued capital discipline, and a steady return of cash to shareholders. We’re confident that consistent and straightforward management, through commodity cycles, will create value for stakeholders. Back to you, Jake.

Operator:

Thank you. [Operator Instructions] Our first question comes from Devin McDermott with Morgan Stanley.

Jake Spiering :

Good morning, Devin.

Mike Wirth :

Yeah, thanks. Thanks, Devin. Pierre tried to show a little more detail, including breaking out COOP JV, royalty, talking about drilling activity and feed drilled et cetera. So glad that that was helpful. First quarter performance was a function of really the fact that NOJV and royalty production, which as you can see from that chart is, a meaningful portion of our overall production, was down a little bit from fourth quarter of last year. Now, this gets a little a little lumpy due to how it gets reported by partners. And so, over time, it's trended up, particularly the NOJV piece. But it was a little lumpy, and it was down first quarter versus fourth quarter last year, COOP production was mostly flat from 4Q of last year to first quarter this year. In terms of the full year outlook, on Slide 9, we show full year outlook, it's about 770,000 barrels a day. '22 was a little bit over 700 -- 707, I think, Our COOP production will grow in the mid-single digits. NOJV, we expect to grow in the mid-teens, and royalty is roughly flat year-on-year as our expectation. So that kind of lays out first quarter and we still think that the guide would give us appropriate as Pierre said, back-end loaded. So, we'll be updating each quarter on that.

Mike Wirth :

Yeah, absolutely. I actually was in Kazakhstan earlier this month. I had a chance to meet with the President of the Republic, some other senior officials, And also spent time down at Tengiz and visited the job site, talk to both people from our construction team, people from the commissioning team, people from operations as we're preparing for startup. And I'll tell you, it looks a little less like a construction site a little bit more like a plant than it did the last time I was down there. So the progress is very obvious. The headline I'll give you is there's no change to our cost or schedule guidance. We expect WPMP startup to begin by the end of this year. Now that's a conversion of the field from high pressure to low pressure. So that will take some time as we take all the metering stations and field infrastructure down to low pressure, but that will still begin by the end of this year. And the startup of the future growth projects, the portion that adds 260,000 barrels of oil production that will begin by mid next year. Both of these require a series of turnarounds and tie-ins and things like that. So it's quite a quite a complex set of activities to get us to the point where we've got everything online. But there's a lot of work behind us. While I was there, we achieved mechanical completion on the third-generation sour gas injection facility, which was ahead of schedule. And there were a number of milestones that I mentioned that we talked about at the Investor Day that that we've achieved. So we completed tie-in of the fuel gas system so the first gas turbine generator we fired that generator so we know that it's working. In the second quarter in terms of milestones to watch for, we're working to commission boilers, steam system, other utilities that are required for the startup of the pressure boost facility, which is the key driver of that conversion from high pressure to low pressure field operations to enable sustained well deliverability. In the third quarter, we expect mechanical completion of the future growth project. And then, as I said, will begin startup activities on the field conversion to low pressure by the end of this year. So those are some of the key milestones. And, like I say, a lot behind us, but there's still a lot of complex work ahead. We'll be updating you on it every quarter.

Mike Wirth :

All right, Devin. Thank you.

Neil Mehta :

Yeah, thank you so much, Mike and Pierre. The first question is just around the LNG portfolio, a lot of volatility in the global gas markets over the course of the last year, just be curious how you guys are seeing the outlook and any updates on your portfolio, particularly down in Australia, where recognized you're going to take into maintenance, but seems like it's operating pretty well.

Neil Mehta :

That's great. And then the follow up is, is just on return of capital. And I think you guys have been pretty clear about the range that we should be thinking about from a buyback perspective. Just on dividend growth, just talk about how do you expect that to track relative to your free cash flow per share expectations?

Neil Mehta :

Yep. Thanks, Mike.

Operator:

We'll go next to Roger Read with Wells Fargo.

Mike Wirth :

Yeah. So I will speak to our operated operation, because I really can't speak on behalf of the others. They should speak on behalf of their operations. We certainly learned from those. But, we spent a pretty good amount of time at the Investor Day, talking about the learnings on a drill been uncompleted wells that had sat for a long time talking about the prior basis of design for the wells, including spacing and profit loading, talking about multi-venture development. And we've learned a lot from our own operations, and those learnings are augmented by the things that we learned from others. And so we talked about more single bench development, more activity. In New Mexico, we continue to be very focused on driving strong returns, and not optimizing to production or some other ther metric. Just to give you a little bit more guidance, Roger for this year, in terms of how to think about it. We expect royalty production to be roughly flat, in the neighborhood of, a little bit over 100,000, maybe 110,000 barrels a day. Most of that comes from the Pecos River area where we've got big operators, Oxy's largest operator in that area, but others that are well known operators in that area. And then we've got some that comes in from the Midland as well from big operators where there's a lot of visibility into what their plans are. Our COOP production growth, we expect to be mid-single digits for the full year. Maybe a touch higher than the midpoint of single digits and expect roughly 190 wells to be put on production this year, which is down a little bit from last year, maybe 10% from last year when our COOP production increased 35,000 barrels a day. We've got growth in the Texas side of the Delaware earlier in the year, the New Mexico side, later in the year, which follows the chart Pierre showed you with drilling lateral feet. And then in the NOJV, the growth is higher. It's in the mid-teens for the full year. The gross number of POPs in our NOJVs are expected to be up about 15% year-on-year. And it's interesting, our net POPs actually increased more than the gross because we have relatively high working interest and a significant royalty advantage in the non-ops. And so a 15% increase in gross POPs actually translates into more production than you might presume. We've got really good visibility into the execution schedule we've received more than three quarters of the AFEs for this year's activity. And operations have actually begun on more than three quarters of the NOJV wells that we expect to be popped this year. So it's a mix. We've got a really strong, but also a bit of a complex portfolio because of these three different contributors and we're continuing to hold the guidance, as I said earlier, at about 770 for full year.

Pierre Breber :

Well, in terms of working capital, Roger, the first quarter, as you said, was a build in working capital draw on cash, and that was primarily inventory related. If you saw last year, we had draws on working capital that was primarily through taxes payable. And you'll see in the second quarter, some of those payments happening. We try to give everything excluding working capital because over the course of time, that tends to zero out and there's a pattern, but there's some variability around it. So that's the guidance I would give on you. In terms of free cash flow, it depends on -- and cash from ops depends on commodity prices and margins, and we gave a lot of that during our Investor Day and some upside in downside cases. But in terms of working capital, you'll see timing effects. We try to look through them and exclude them. And then next quarter, you should expect some large tax payments, which will be obviously a draw on cash.

Operator:

We'll take our next question from Paul Cheng with Scotiabank.

Mike Wirth :

Yeah, Paul. Look, the reality is these are brand-new businesses. And we've got a lot of confidence in the returns and payback periods that we expect out of businesses we've been in for many decades and understand very well in well-established markets. These are businesses that don't exist today. They are in part enabled by a government policy the rules of which are not yet fully written and the durability of which we need to ask ourselves questions about as we commit capital to it. So they're different. They're very different. Our goal over the long term is to get similar returns out of these businesses as we get out of our core business. And so that would be double-digit returns. In the mid-term to the near term, we're going to have to go into some of these things that offer high growth and opportunity with our eyes wide open, but also understand that as we establish them in the early days, we may not see the returns that we expect in the fullness of time. So we make big investments. Our expectation is over the life cycle of these investments, we're going to deliver those kinds of returns. But we're also mindful of the fact we've got to develop technology. We've got to scale these things. We've got to help markets mature. We've got to build operational experience. We've got to build risk management experience, supply chain and customer capabilities in these businesses. And so in the near term, we'll be understanding of the fact that the returns in the short term will probably look different than our long-term expectations but we won't go into things that we don't believe offer the long-term prospect for returns, which is why we have steadily avoided more well-established sectors like wind and solar, where we could go into those today because the risks are better defined, but we also understand the returns. And so we were just trying to do these kinds of projects, we would go into those, but they don't offer the kinds of returns we expect out of the things that we're working on.

Mike Wirth :

Well, Paul, what I would say is I think maybe your perception is a little bit miscalibrated from what I would describe. We have always had a global trading organization for many, many years, I used to run it. Pierre used to run it. And so we're in active trader. We trade in a certain way. And I'll give you the three-word kind of overarching description, we flow, optimize and trade. So the first role of our commercial organization is to ensure our barrels and molecules flow to the market. The second is to optimize assets, ships, market positions, market knowledge and be sure we get the most value out of our system that we possibly can. And then the third responsibility is to trade. And we do third-party training. We do what we call Quad 4 trading. On a regular basis, we make money at it, and we have very talented people in our organization to do. We also have good risk management systems to ensure that we understand what we're doing. So I wouldn't describe us as not being a trader. And I don't know if there's a definition, I think you used the word conservative. Look, we're a trader, but we do it in the order that I just described and have done it for a long time on a global basis. So it's a contributor to our earnings, and we continue to look to grow that part of our business.

Paul Cheng:

Okay. Thank you.

Sam Margolin :

Good morning. Thank you. This one is just a clarification question on something you said about the Permian because I think it's important. In the NOJV section, because you stack royalties with the NOJV acreage, your growth rate in the NOJV portion actually exceeds the growth rate of our partners as they reported. Is that -- that's the correct interpretation, right? That's what we're trying to communicate.

Sam Margolin :

Okay. And then just as a follow-up. This is on capital allocation and I understood that you have the range out there in the buyback. The range is pretty substantial, and there is a decision to make right now about where to be within the range about whether to preserve cash for an opportunity that might come in the downturn, if that's what looks like it's on the horizon or whether to stay at the top end because we're in sort of a market equilibrium in the commodity environment, and you feel good about the pace. And I'm not asking you to predict the future, but it would be great to sort of hear your thoughts directionally about the value of kind of preserving cash on the balance sheet for any day or maintaining a faster pace? Thanks.

Pierre Breber :

Yeah. In our Investor Day, we looked at the high case and low case scenarios and our guidance right now is towards the high end. And let me just first be clear that we don't intend to hold $15 billion plus of cash on our balance sheet. We can run the company at $5 billion, and this is surplus cash. And this is cash that is temporarily on the balance sheet. It will be redistributed and redeployed to shareholders over time depending on the scenario and the price of both scenarios had us working down that surplus cash because it's economically inefficient for us hold it, and it's not our cash, it's our shareholders' cash. We want to return it through the cycle in a steady way, not pro-cyclically. So that's why it's accumulating. We've paid off all our debt economically, but it's a timing effect. And we showed certainly in the low side case which averaged about a $60 Brent that we could continue buybacks near the low end of the range, and we can do that on by taking surplus cash down. And then also using some of our excess debt capacity because we're well below our 20% to 25% net debt ratio. So we'd want to work towards that low end of that guidance range of 20%, again, to get to a more efficient capital structure. In terms of keeping cash for any day or strong we're always going to maintain a strong balance sheet. We've been in this business for decades and decades. We know the good times don't last. We know that prices are cyclical. We want to manage that volatility for our shareholders. So our shareholders don't have to worry about the commodity price because they're going to get the dividend that Mike talked about, that's been growing for 36 consecutive years. That's grown 6% annually for 15 years. They're going to get that. And then through a cycle, as we approach the cycle, and we're looking at the cycle coming up here, additional cash in a steady way, right now, about 5% of our shares outstanding through the form of a buyback. And so that's how we're planning to manage the volatility for our shareholders. And we've talked about if M&A is implied in your question that we shown that we tend to use equity for M&A because there is -- commodity prices are volatile. It creates a more stable deal structure. So our balance sheet will always be strong enough to enable us to not only manage commodity prices, but also make sure we're positioned to do what we need to do. And I don't need to remind you that we were the first to do a transaction coming out of COVID when we announced the acquisition of Noble Energy, and then we followed a year or so later in acquired Renewable Energy Group. Thanks, Sam.

Operator:

We'll take our next question from John Royall with JPMorgan.

Mike Wirth :

Yeah. So John, a couple of thoughts, I guess. I'll just go by the product commodities. I mean gasoline demand is essentially back to pre-pandemic levels globally. Obviously, there are regional variations in this. We're sitting in California here on this end of the call. We've had a very wet winter. And so the first quarter reflects an unusually wet season on the West Coast. In Asia, we see demand coming back, right, as economies continue to continue to open up and mobility has increased, et cetera. But broadly speaking, gasoline flat. Diesel had kind of carried the complex through COVID and global demand has been at pre-pandemic levels for a while now. First quarter demand in '23 is a touch lower than it was in first quarter of '22. Could be an indicator of the beginning of some economic slowdown, but it's certainly, I think, premature to conclude that. But diesel is maybe not leading the parade quite as strongly as it had been for the last couple of years. Jet demand continues to grow. And it's still below kind of prepandemic levels. China is the place, obviously, as everybody has been paying attention to domestic travel up to nearly 90% of pre-COVID flights in and out of the country still well below that. And we see flights being scheduled. You see indicators that suggest travel will grow. You listen to the airlines, and that certainly seems to be what they anticipate, but that's in progress. So that's a kind of a quick look across the product slate. I think margins reflect a couple of things. One, a year ago, we were in a period of recovering economies and we're coming out of a period of rationalizing refining capacity around the world. And you can go to any part of the world and find refineries that had shut down that perhaps people expected would close one day, but it happens relatively quickly. And at the same time, you saw big growth projects that had been deferred because of the uncertainty relative to COVID a year later here. You don't see refineries closing at the same rate. We've seen refinery startups in the Middle East. We've seen projects here in the U.S. and in Asia as well. So refining capacity coming into the system demand has moderated a little bit. Margins have come down. They're still stronger than historic margins if you look out over a longer period of time, but trending back down towards mid-cycle. Pretty strong in the U.S., maybe under a little more pressure in Asia, but you got to think about the feedstocks in Asia, where they're coming from, how they're priced and how those markets are working. So I don't see any big warning signs flashing, but certainly, we're paying close attention to it.

Mike Wirth :

Yeah. I'll talk about it, sure. So the bottom line is this is now into a rule-making process. There's no impact right now. And it's into kind of a bureaucratic phase. I think implementation is likely to take quite a while, and it's hard to say exactly how it plays out. What started as an effort to create a windfall profit tax was unsuccessful because you need two thirds of a vote in the legislature for new tax in California. That then modified into some other forms and ended up moving into the Energy Commission, where there will be a group established that will gather a lot of data and try to assess the profitability of industry again some standard, which I think is yet to be fully articulated. So this is going to take some time. It could potentially result in in some sort of a fine or a penalty for margins or profits above a level, but I can't tell you how it's going to play out because it's -- there's a lot of work to be done there. I guess the things that I would say are pretty predictable are maybe two. One, there are substantial new reporting requirements, and there's a lot of data we're going to have to produce. We're happy to do that. We'll work closely with the Energy Commission to make sure we get them the information that they're requesting. And then the second is, I don't think this does anything to encourage investment or new supply, which is really what's needed in a marketplace commodity markets to bring prices down on average over time. In fact, I think it runs the risk of doing the opposite of discouraging investment of decreasing supply over time, which if demand does not moderate, will tend to exacerbate volatility and over time probably result in, on average, higher levels of price. So that's about all I know about it at this point, and we'll watch it as it unfolds.

Operator:

I'm sorry, we'll take our next question from Doug Leggate with Bank of America.

Pierre Breber :

Well, royalty barrels have essentially an infinite margin. And so I think if you and Doug can do the math is it's a slightly lower percentage than that will be a part offset, but there's lots of other drivers that we're doing to enhance margins. And we've shown return on capital employed near 30% at $60 Brent equivalent for our premium. So it's a high return low-carbon asset and the royalty barrels, as you know, come with virtually no cost, and that's part of the advantage that we have.

Mike Wirth :

Yeah. So the expansion project, as I said, there's a lot of turnarounds in activity, both this year and next year. And at our Investor Day, we laid out a bar chart that gave you an idea on production. The real I think the time, as I said earlier, when you're going to see the production growth will manifest itself in 2024 because the next two years, we've got a lot of these turnarounds, ties, et cetera, in place. So Pierre, you can guide on dividends.

Unidentified Analyst:

I appreciate that there's still some turnarounds to work through. But as the production hit a steady state, what do you expect the dividend cadence to look like?

Operator:

Our next question comes from Josh Silverstein with UBS.

Mike Wirth :

Yeah. I mean we've pulled rigs down dramatically in 2020, and we didn't want to surge back with everything all at once. And so we entered this year with 10 we expect to exit this year with 14 COOP rigs running. And I think consistent with the longer-term production profile that we've outlined we got a big base business that does have decline underneath it. And so you're going to expect us to add some additional rigs as we move into '24.

Pierre Breber :

We've -- we're adding a rig in the Haynesville. We talked about that for a number of years building up to that activity. Gas prices are going to be volatile. And frankly, we need to get developing that resource. We have some offset operators. And so if we don't get after it, it's the time for us to do that. DJ still has a heavy liquids component, no change in our plans. In fact, the DJ and Argentina are a couple of other areas where we expect production in the second half of the year to be higher where we're increasing a little bit of activity. And again, all of that is within our existing CapEx budget.

Operator:

We'll go next to Ryan Todd with Piper Sandler

Pierre Breber :

You're right. We referred to it. I would not say it's primarily -- it's a lot of factors, and we pointed out to that. It's consistent with how Mike described our trading business. And as all trading businesses are, it can be variable in future quarters. So it's just one of many factors. It's not primarily, but we wanted to cite it as one of the elements in that other variance.

Mike Wirth :

Yeah, Ryan, I would say not really. We've always been return seeking. And so this is all about optimizing the return we can get out of this asset over the long haul. We've tried to be thoughtful about surface infrastructure. We've tried to be thoughtful about drilling to keep surface infrastructure fully utilized, not over building it for peaks and then leaving it underutilized for long periods of time. And as we're continuing to learn, the fundamental principles about optimizing return on investment continue to drive all of this activity. So as we learn more about benches about communication, about productivity as technology changes, recovery factors, we will continue to apply all of those learnings. But the real objective remains the same. It's not volume, it's value and returns.

Ryan Todd :

Thanks, Pierre.

Jason Gabelman:

Hey, good morning. Thanks for taking my questions. Sorry to go back to the Permian, but I'm going to ask another. I was wondering, and I appreciate all the disclosures are really helpful. But in terms of the non-op component of production, does the proportion stay relatively stable through your forecast period? I think you gave a forecast out to 2027 at the Analyst Day. Does the non-op proportion stay the same? Or do you have more operational barrels between now in '27?

Jason Gabelman:

All right. That's helpful. And then just one accounting question. Depreciation fell decently quarter-over-quarter in upstream. What was that related to?

Jason Gabelman:

Yeah. If I look at the quarter-over-quarter Slide 7, Upstream DD&A was positive $345 million.

Jason Gabelman:

Okay. Thanks.

Biraj Borkhataria :

Hi, there. Thanks for taking my questions. I wanted to ask about Namibia. You recently farmed in a few months ago. Could you just walk me through plans for the next 12 months or so what you've got pencilled in? And then I've got a follow-up on something else. Thank you.

Biraj Borkhataria :

Okay. And then just on a different topic, cost inflation because more and more, you hear some of the service providers talking about improving pricing and so on. So could you just comment on your latest thoughts and what you're seeing on the cost inflation side outside of the Lower 48? Thank you.

Biraj Borkhataria :

Thank you very much.

Operator:

Thank you. We'll take our last question from Neal Dingmann with Truist Securities.

Mike Wirth :

Is -- there a maximum -- I mean it's limited by our position there and the entities that we're involved in and what our portion of that production that we're entitled to market is. We're currently seeing about 100,000 barrels a day of production up from about 50 when the license term changed. That actually go up further this year, maybe another 50% if everything goes well. The rude comes to the U.S., and we're finding a market for the crude. And yeah, it's a six-month license from OPEC, and we have to bear that in mind. So that's why we are proceeding, as you said, which is we've got some past receivables that are being paid from some of these proceeds and there's a lot of relatively straightforward workover and other activity that can help bring production up at -- without major capital commitments. And so that's the current model. We'll see how things unfold and hopefully pointed in a good direction, but it's been a bit of an up and down situation, and we have to -- we just have to take this one step at a time.

Mike Wirth :

That's a decision made by the U.S. government. It's not really a negotiation. It's their decision, and it's a policy matter we're asked for input and so we provide input on these things. But for the last several years, these things have had relatively short time lines associated with them. And so we're in full compliance with all the conditions of the sanctions and intend to stay that way. And we'll just see how the policy making turns out.

Jake Spiering:

I would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation on today's call. Please stay safe and healthy. Katie, back to you.

Roderick Green:

Thank you, Katie. Welcome to Chevron's fourth quarter 2022 earnings conference call and webcast. I'm Roderick Green, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth; and CFO, Pierre Breber, are on the call with me. Also listening in today is Jake Spiering, the incoming General Manager of Investor Relations, who will assume this position effective March 1. Jake and I will be transitioning together over the next couple of months. It's been my sincere pleasure working with each of you over the last two years. Thank you for your questions, feedback and investment in Chevron. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement on slide two. Now, I will turn it over to Mike.

Pierre Breber:

Thanks, Mike. We reported fourth quarter earnings of $6.4 billion or $3.33 per share. Adjusted earnings were $7.9 billion or $4.09 per share. Included in the quarter were $1.1 billion in write-offs and impairments in our international upstream segment, and negative foreign currency effects over $400 million. A reconciliation of non-GAAP measures can be found in the appendix to this presentation. Record operating cash flows in combination with continued capital efficiency, resulted in over $37 billion of free cash flow in 2022. The only other year Chevron's operating cash flow exceeded $40 billion was 2011. Free cash flow in that year was less than 40% and of this year's record. In 2022, Chevron delivered outstanding results on all four of its financial priorities. Announcing earlier this week another 6% increase in our dividend per share, positioning 2023 to be the 36th consecutive year with annual dividend payout increases, investing within its organic budget despite cost inflation. Inorganic CapEx totaled $1.3 billion nearly 80% for new energy investments. Paying down debt in every quarter and ending the year with a 3% net debt ratio, returning record annual cash to shareholders through buybacks and exiting the year with an annual repurchase rate of $15 billion. Two days ago, Chevron's Board of Directors authorized a new $75 billion share repurchase program. Now is a good time to look back on our execution of the prior programs. Over the past nearly two decades, we bought back shares in more than three out of every four years, returning more than $65 billion to shareholders. And we've done it below the market average price during the whole time period. Going forward with the new program, our intent is the same, be a steady buyer of our shares across commodity cycles. With a breakeven Brent price around $50 per barrel to cover our CapEx and dividend and with excess balance sheet capacity, we're positioned to return more cash to shareholders in any reasonable oil price scenario. Turning to the quarter. Adjusted earnings were down nearly $3 billion compared with last quarter. Adjusted upstream earnings decreased primarily on lower realizations and liftings as well as higher exploration expense, partially offset by favorable timing effects. Adjusted downstream earnings decreased primarily on lower refining and chemicals margins and negative timing effects partially offset with higher sales volumes following third quarter turnarounds. The Other segment charges increased mainly due to accruals for stock-based compensation. For the full year, adjusted earnings increased more than $20 billion compared to the prior year. Adjusted upstream earnings were up primarily due to increased realizations. Other items include higher exploration expenses, higher incremental royalties and production taxes due to higher prices, partially offset by favorable tax benefits and other items. Downstream adjusted earnings increased primarily due to higher refining margins, partially offset by lower chemical earnings and higher maintenance and turnaround costs. 2022 production was in line with guidance after adjusting for higher prices. As a reminder, Chevron's share of production is lower under certain international contracts when actual prices are higher than assumed in our guidance. Reserves replacement ratio was nearly 100% with the largest net additions in the Permian, Israel, Canada and the Gulf of Mexico. Higher prices lowered our share of proved reserves by over 100 million barrels of oil equivalent. 2023 production is expected to be flat to up 3% at $80 Brent. After adjusting for lower prices and portfolio changes, primarily the sale of our Eagle Ford asset and the expiration of a contract in Thailand, we expect production to grow led by the Permian and other shale and tight assets. We remain confident in exceeding our long-term production guidance. Looking ahead to 2023, I'll call out a few items. Earnings estimates from first quarter refinery turnarounds are mostly driven by El Segundo. Based on the current outlook, we expect higher natural gas costs for our California refineries. Full year guidance for all other segment losses is lower this year due to higher expected interest income and again excludes special items such as pension settlement costs. The All Other segment can vary quarter-to-quarter and year-to-year. We estimate annual affiliate dividends between $5 billion and $6 billion, depending primarily on commodity prices and margins. The difference between affiliate earnings and dividends is expected to be less than $2 billion. We do not expect a dividend from TCO in the first quarter. We updated our earnings sensitivities. About 20% of the Brent sensitivity relates to oil-linked LNG sales. Also, we expect to maintain share buybacks at the top end of our guidance range during the first quarter. Finally, as a reminder in Venezuela, we use cost affiliate accounting, which means we will only record earnings, if we receive cash. We do not record production or reserves. 2022 was a record year for Chevron in many ways. We look forward to the future, confident in our strategy with a consistent objective to safely deliver higher returns and lower carbon. We'll share more during our Investor Day next month. Back to you, Roderick.

Operator:

Thank you. [Operator Instructions] Our first question comes from Jeanine Wai with Barclays.

Mike Wirth:

Good morning, Jeanine.

Mike Wirth:

Yeah, Jeanine, let me start, and then I'll have Pierre add a little bit of color. We included a little information on this call looking back at our past programs. And as you saw on the slide 15 of the last 19 years, we've bought shares back lower than the market volume weighted average over that period of time. We look at the decision going forward in the context of the cash-generating potential of the portfolio, the outlook for the market environment, the strength of the balance sheet. And we don't want to be authorizing a program every year. So, we talk to the Board about a multiyear outlook. So, the fact that there's not an end date on it is only significant if you're trying to do some sort of math and annualize this. We think our track record speaks for ourselves and the steady, consistent way that we've done this. And so, we increased the rate three times last year as we saw the situation evolve, and we're now at an all-time high with the rate of repurchases. So, the last thing you said it, but I'll repeat it, is sized to maintain our program through the commodity cycle. We aren't pro-cyclical. We're not countercyclical. We're steady through the cycle, and that is the intention. Pierre, do you want to add anything?

Jeanine Wai:

Thank you for that clarification. We appreciate that. Maybe our second question, it's that time of year again, reserve replacement ratio, your ratio for 2022 was 97%. And we believe that compared to 112% last year, and then I think it was around 99% on average for the five years before that. So, our question for you is just -- how do you see this ratio trending over time? And I guess the over or under bogey is probably 100%. Thank you.

Operator:

We'll take our next question from Devin McDermott with Morgan Stanley.

Mike Wirth:

Yes. Devin, I'll talk to the project and let Pierre talk a little bit to the financials. First of all, no change to cost or schedule guidance. WPMP is trending toward a beginning start-up by the end of this year. We've got a lot of work done. We've got a new power grid up and running and this was a power grid built back in the Soviet days. The control room is up and running, where everything comes into one central control room. All the production on gas injection wells are done, the gas injection facility is now in early commissioning. In just the next few days, we'll tie in the fuel gas system to the first gas turbine generator, which is really an important milestone to test the first of the three GTGs, begin the process of powering up electrical generation capacity and commissioning boilers, steam and other utilities. So, that all happens sequentially here over the next period of time, which leads to commissioning the pressure boost compressors in the third quarter and then converting the field from beginning the conversion from high to low pressure by the end of the year. A couple of things that will bear on production. We've got two planned turnarounds of the old processing trains. They're called the KTL. There's five of them. We had two turnarounds this year that are planned in the third quarter. So those will be down for a period of time. And then as those come back up, production may not fully recover on those two as some of the wells won't resume flowing until we get to the low-pressure system. So, back half of the year, you'll see a little bit of that impact. And then as we move into '24, we've got more of these high pressure to low-pressure conversions in the field and we've got FGP start-up first half of '24. So you don't see the full effect of FGP roll through, you get partial effect in ramping in '24, and then the full effect will show in '25. Cash will kind of follow that pattern. So Pierre, maybe you can talk about the pattern on CapEx and dividends.

Mike Wirth:

Devin, just to kind of put a final punctuation on that. In our Investor Day last year, we showed in 2026, so once we get fully on the other side of all this stuff I just described, a 5x expansion in free cash flow out of TCO versus 2021. So it's meaningful.

Mike Wirth:

Yes. Maybe I'll finish on -- I think the second question is about overall production, and the first was about Permian. So our outlook for 2023 at $80 is flat to up 3%, so that post between 3 million and 3.1 million barrels a day. There's a modest adjustment that relative to our Investor Day guidance. A couple of things driving that, some project deferrals like Mad Dog 2, which we thought would start up in 2022 and now looks like a 2023 startup. We've got some downtime, plans downtime that shifted from 2022 to 2023. And then our Permian growth would be a little bit lower in 2023. A couple of things. One, in 2022, we had the benefit of a lot of prior DUCs that had been sitting that came online and it boost early production in 2022, a little bit more. And then we also are re-optimizing some of our development plans to factor in some of the things we continue to learn relative to interactions between wells and benches, how we space laterals and do single or multi-bench development. So our revised plan will have some deeper targets, a few more rig moves and a few more single bench developments, all of which brings that pace down a little bit. So that's kind of at the highest level, what is behind the production numbers. We'll talk about that more when we see you guys in a month here. And maybe I'll stop there, because I did cover the Permian as part of that. Thanks, Devin. Katie, we can go the next question. Katie, can you hear us?

Neil Mehta:

Yes. Good morning team and congrats here on a good year. Hey, Mike, I guess the first question I have for you is around global gas. And maybe you can talk about how you're seeing the market. There's obviously been a tremendous amount of volatility and remind us again how you're positioned from a contracted versus spot position? And then I have a follow-up on gas as well in the Eastern Med.

Neil Mehta:

Thanks, Mike. And that's the follow-up. You have a large gas position in the Eastern Mediterranean, following the noble acquisition with Leviathan and Tamar and some discoveries out there as well. So how do you think about prosecuting that asset? Where does it fall in terms of prioritization? And how big can it be?

Neil Mehta:

Very well. Stay tuned. Thanks, Mike.

Operator:

We'll take our next question from Doug Leggate with Bank of America.

Mike Wirth:

Well, let me try to be clear on this, Doug. We do not do buybacks to manage dividends. Dividend -- absolute dividend load is an outcome. It's not a reason that you would do buybacks. Our dividend growth expresses confidence in the ability to grow free cash flow at mid-cycle prices, and it is a long-term decision, a long, long, long-term decision. We haven't cut the dividend since the great depression. Pierre mentioned, we've increased the payout 36 years in a row now. Buybacks are different. They signal confidence that we're going to generate excess free cash flow, where we've got excess balance sheet capacity, which we have significant capacity in the current commodity cycle. And as we satisfy our commitments on the dividend, our reinvestment plans in a disciplined manner to grow free cash flows and maintain that strong balance sheet, we've got the capacity then to buy shares back through the cycle. An outcome of buybacks is a lower absolute dividend, but it's not the driver. And so, I don't want -- there should be no confusion about that. We've got confidence in our dividend increases, whether we're buying shares back or not. We wouldn't increase the dividend if we didn't have that confidence. And so the two are not linked in that manner.

Mike Wirth:

Yes. I mean, we'll talk about it more in February. I'm not sure I followed all your math there, but we're growing. We had a 3% compound annual growth rate at $15 billion to $17 billion of CapEx in a market that's not growing that fast. We're growing well better than the overall demand for oil or for gas, which is growing faster than oil is. And so, we are growing production, but what we're really focused on is growing returns and cash flow. And if we can grow returns and cash flow, the equation works. And so, I -- we'll be happy to talk about this more when we're together at the end of the month, but -- or at the end of next month. But we can grow cash flow; we can improve returns at the rate that we're spending at. And so, I don't know why there would be a question about our ability to do that and the production numbers and outcome of those decisions. It's not the goal.

Operator:

We'll take our next question from John Royall with JPMorgan.

Mike Wirth:

Good morning, John.

Pierre Breber:

This is Pierre. I'll take that. Our guidance is for the net debt ratio to be between 20% and 25% and mid-cycle conditions. And as you said, we're at 3%, so we're much stronger than that. And that's what happens in the short-term. So Mike has talked about our financial priorities. They're simple. We've been consistent with them for a very long time. And three of the four are pegged. We just increased our dividend 6%. We have a 2023 CapEx budget of $14 billion. We've given guidance that keeps that CapEx flat over the next several years. And we have the buybacks at the top end of the guidance range of $15 billion. So swings in cash flow in the short-term will go to the balance sheet. And that's because commodity prices and margins, we just were talking about natural gas prices and refining margins and things are moving up and down. But over the long-term, those cash flows will be returned to shareholders. And so we want to do it in a way that is steady across the cycle. As Mike said, we don't want to be pro-cyclical. And by the way, we haven't, right? Our track record shows that over the past nearly two decades that we've been able to buy actually below what the market average price has been. So the intent is to, yeah, we'll be a little strong balance sheet depending on commodity prices and margins and how strong our operations have been. But then over time, the cycle will correct and then we'll continue buying back shares. We've said we could have a higher buyback rate right now. We're sizing it at a level to maintain it for multiple years across the cycle. That means there'll be a time period where we'll be buying back shares off the balance sheet, and we'll lever back up closer to that 20% to 25% guidance. Thanks, John.

Mike Wirth:

Yeah. So last year, there was probably more news than there was impact on a variety of issues relative to the pipeline and the terminal. There was work going on in the late third and into the fourth quarter on the two of the three single point mornings. All that work is done. All three SPMs are operational today. There are no constraints on loading. There are no constraints on throughput on the pipe. Despite a lot of the things that people heard and worried about last year, the pipeline was very reliable. Our production was impacted less than 10,000 barrels a day over the course of the year. It was all a few weeks in March and April. And so everything there is running very smoothly now, and we don't see any constraints. Discounts have come in a little bit on CPC. In the immediate aftermath of some of the sanctions and changes related to Ukraine. We saw a trading range that was like $4 to $10 below dated Brent. And before the conflict began, it was plus or minus $1. We're seeing kind of $1 to $3 discounts now. So maybe not quite at pre-invasion levels, but not as deep as they were immediately afterwards. And given the overall flat price environment and the way it has strengthened the impact to CCO is relatively muted.

Roger Read:

Yeah. Thank you. Good morning.

Roger Read:

Hey, good morning, guys. Just looking at, let's call it, refined product demand. You talked about gas demand earlier. I'm just curious, as you look around the world, we've got positives moving away from COVID on a year-over-year comparison and then everybody's got high expectations for the China reopening. I was just curious, as you look across your operating base, what you're seeing there?

Roger Read:

Always the big guys, right? A follow-up question to come back to the Permian, and I recognize the Investor Day coming. But Pierre, when we were at the sell-side dinner end of November, there was a lot of discussion over kind of the changing in the range and how that was really just a function of messaging more so than – overall change in the way you're developing the Permian, kind of following from that to the comments about things a little different in the bench and the DUC comparisons year-over-year. You look at it as any different from the messaging at the end of November, or is this – is there something else here with.

Mike Wirth:

And Roger, just to emphasize the point I made earlier to another one of the questions, we remain focused on returns and value, not on production. And so that is the -- that's what drives all of this. Thanks.

Irene Himona:

Thank you very much for taking my questions which are both related. So, I will ask both at the same time. So, firstly, thinking about balance sheet strength, of course, the other use it can be put to is M&A. You've been very disciplined with your M&A timings, both with Noble and Regi [ph]. How do you see the current market in these two, let's say, POTS [ph] legacy oil and gas versus low carbon? And then secondly, has the IRA Act perhaps changed your appetite for faster expansion in low carbon businesses, please? Thank you.

Pierre Breber:

And just to add some of the other important effects, permitting really critical for traditional energy, super critical for new energy, new technology developments, you've seen us make some investments on technology to reduce the cost of capture of CO2 and then scale, getting cost down. So it's helpful, but it's just one element, as Mike said.

Operator:

We'll take our next question from Ryan Todd with Piper Sandler.

Mike Wirth:

Yes. I would say it's a pretty typical year for turnaround activity. We've got the FCC at El Segundo in the first quarter of this year, which Pierre mentioned in his comments. But there's nothing unusual in our turnaround plan for this year. What you do see across the US and I think in some of the other markets are two things that are really kind of still echoes of COVID. One is you're just seeing capacity go out of the system. And two, you see maintenance that was deferred during COVID is -- had to be rescheduled and replanned. And so there's probably still a bit of a bow wave of pushing through the system in some places of activity that needs to get done for safety and reliability and regulatory reasons. And so that could be driving some of the speculation. I can't really comment on other companies' plans. I'll let you talk to them about that.

Mike Wirth:

These tend to be long period cycles for the most part, Ryan. And so, at the margin, I think that's economic growth and development in China is a positive. But you don't slide into the lower part of the cycle quickly or easily, and you generally don't come out of it quickly or easily. So these things track over a longer period of time. And so, I do think we're -- it feels like we're kind of bumping along near the bottom here, but I don't know that there's a steep climb out as opposed to a gradual climb over time.

Jason Gabelman:

Good morning. Thanks for taking my questions. I wanted to first follow up on the affiliate distribution guidance because it is taking a step higher year-over-year, and it sounds like that was due to TCO having excess cash. Is that kind of $5 billion to $6 billion, something you can maintain assuming oil price stays stable until the project actually starts up until TCO FGP starts up or would you expect that to fall off after this year? And then my second question is on a different topic, Venezuela. I believe you have now boots on the ground there again. Can you just discuss what you're seeing in terms of the health of the infrastructure there, the ability to ramp production and the desire from Chevron's standpoint to participate in that? Thanks.

Mike Wirth:

Yes, Jason, on Venezuela, we always did have boots on the ground. We just were very limited in where those boots could go and what they could do. The shift in the sanctions policy has opened up a little more room. It's allowed us to work with PDVSA to put some of our people into different roles in these mixed companies there. So we do have a little more ability to have influence and involvement in some of the decision making. Your question about the state of the infrastructure, there's been a lack of investments there for a number of years in the infrastructure reflects that, and it will take time for things to turn around. We have seen some positive production response already in the entities that we're involved in. They're producing about 90,000 barrels a day now, which is up about 40,000 barrels a day since we saw the change in these license terms. So that's been a good short-term effect. I'm not going to say you can extrapolate that, but it's where we are today. We are continuing to work on the ground to expand production, but it's too early to guide to anything. We're also lifting oil and bringing it to the US. We've got a couple of cargoes coming into our Pascagoula Refinery. We're going to be delivering cargoes to other customers on the Gulf Coast. And then the revenues go into a series of structured channels to pay expenses and other obligations. On the accounting standpoint, we're using cost affiliate accounting. So we'll record earnings only if we receive cash. And at this point, I would say the cash flows are expected to be modest. So this is a step-wise change in the environment there. We're going to go into it thoughtfully. It's a six-month license, and it's a dynamic environment. So we'll continue to advise you as we learn more and as things evolve.

Mike Wirth:

You bet.

Sam Margolin:

Hey, good morning. Thank you.

Sam Margolin:

I'll ask about the Rockies. The Rockies is interesting. It's a place where you could maybe add a little bit of activity to face your aggregate Lower 48 activity levels, but without some of the inflationary pressures and just infrastructure tightness in the Permian and inventory depth there is good. Is the Rockies a place where there may be a little bit of extra focus. And I ask that in the context of sort of the broader theme around your overall resource depth and production and all these topics that are sort of flowing into the broader conversation today.

Sam Margolin:

Okay. And yes, just a follow-up. I mean, because obviously, between -- I think you can surmise the reserve numbers getting some attention to the overall pace of activity and production trends over the long-term are getting attention. But we'll get to this at the Analyst Day, I'm sure. But is there a way right now where you can kind of add it all up and size the Gulf of Mexico, other shale and tight, Eastern Med gas and just kind of frame that aggregate resource number against maybe what you see in the portfolio today as tail resource and just speak to a final answer around your organic portfolio and how it extends.

Operator:

We'll take our next question from Paul Sankey with Sankey Research.

Mike Wirth:

Yes. So, Pierre answered the question earlier, it's not a five-year authorization. It's an open-ended authorization. It is -- it's our intent to maintain it across the cycle. I'll just say that again. It's actually aligned with our upside in our downside cases from the 2022 Investor Day and consistent with our track record of being in the market steadily buying $2 below the market over nearly the past two decades. And we could increase our guidance range, Paul. We need to be confident we could maintain that higher rate for multiple years across the cycle. And I think that you should read it as a signal of confidence and we'll continue to talk more. We raised our buyback rate three times last year. So we're not averse to doing that. And I would just say stay tuned. In terms of the reaction to it, I think it's perhaps been a touch overblown given that it's an open-ended program, and we could have sized a smaller one and just been prepared to do another one sooner. Pierre said, we're closing one out. We just looked at something that would last over a number of years, and we were trying to be splashy when we're trying to create any reaction out there. We're just trying to indicate the confidence we have in our cash generation.

Mike Wirth:

Yes. I don't know if I describe the spending as being up quite a lot. We've got a nice portfolio that we like. And I'll just touch on -- you mentioned Eastern Med. We still have a lot of blocks in the deepwater Gulf of Mexico. We've got block in Suriname that we're still working on and that are on trend with some of the things in that region. We've picked up acreage in Namibia that's on trend with explorations in that part of the world as well. And so we got stuff in Brazil, we had stuff in Mexico that we acquired a few years prior to that. So we've got a nice portfolio of opportunities that we continue to work on. And we don't go out and drill the wells until we're ready to drill them. But it's spread across a number of basins where there's good working oil and gas systems. And the Nargis discovery is a recent example of what happens when you focus in those areas, and I'm optimistic that we're going to see more of that in the future.

Operator:

Our last question comes from Biraj Borkhataria with RBC.

Pierre Breber:

We expect fewer employee and retiree exercises of stock options. That was extraordinary unusual in the first quarter. And it's a zero-sum game. In other words, if employees and retirees do it early, there's fewer to do going forward. But that will be up to them and the stock price performance. And the share buybacks, I mean, you just divide it, depends on what our stock price is. We give guidance quarterly, and I think you can do the math. It is confusing the difference between average annual share count and where we end, right? So we are clearly taking our share count down. But when you look at average annuals, that's exactly what it implies. It's an annual each day, but the trend is going down. Our buybacks exceed the issuances and we expect that to continue.

Mike Wirth:

Yeah. So Biraj, we are a little lower than what our typical level of guidance has been a level of activity. Over the last decade, we've generated about $35 billion in asset sales. So that's, say, 3.5%. There was some portfolio cleanup underway there that was needed to be done, and we get good value as we sold those. You're always looking at your tail. There's always -- when you sell things off, there's a new part of your portfolio and say, okay, this sits at the margin. And so you're always challenging that. If we were to find interested buyers and some of the things that might fit better for others than they do for us, we could transact on that. This is -- the guidance that we've got right now and the things that are underway and in process is what we've put out there, and we'll update you if there's any changes to that.

Roderick Green:

Thanks Biraj. I would like to thank everyone for your time today. We appreciate your interest in Chevron and everyone's participation on today's call. Please stay safe and healthy. Katie, back to you.

Roderick Green:

Thank you, Sarah. Welcome to Chevron's Third Quarter 2022 Earnings Conference Call and Webcast. I'm Roderick Green, GM of Investor Relations. Our Chairman and CEO, Mike Wirth; and CFO, Pierre Breber, are on the call with me. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement on Slide 2. I will now turn it over to Mike.

Pierre Breber:

Thanks, Mike. Third quarter financial results were strong. Included in the quarter were $177 million of pension settlement costs and positive foreign currency exchange effects of $624 million. The appendix of this presentation contains a reconciliation of non-GAAP measures. We repurchased shares at the high end of our guidance range and ended the quarter with a net debt ratio under 5%. Cash CapEx was $3 billion, up over 50% from last year. For the sixth consecutive quarter, Chevron's free cash flow exceeded $5 billion. We're on track to beat 2021's free cash flow record. Adjusted third quarter earnings were up more than $5 billion versus last year. Adjusted upstream earnings increased mainly on higher realizations partially offset by inventory timing impacts. In Other, tax benefits are more than offset by higher operating expenses and other costs. Adjusted Downstream earnings increased primarily on higher refining margins and favorable inventory timing impacts. The planned turnaround at our Richmond refinery was a driver of higher OpEx and lower volumes for the period. In Other, lower chemicals earnings were partly offset by higher trading gains. Compared with last quarter, adjusted earnings were down modestly. Adjusted Upstream earnings increased primarily on higher liftings and tax benefits, partially offset by higher charges for abandonment accruals and exploration leases. Adjusted Downstream earnings decreased primarily on lower refining margins and lower volumes and higher OpEx due to the Richmond planned turnaround. Partially offsetting is a favorable swing in timing effects. Third quarter oil equivalent production was flat compared to a year ago. Growth in the Permian, along with the absence of turnarounds and Hurricane Ida impacts were offset by the expiration of our contracts in Thailand and Indonesia and the sale of our Eagle Ford asset. Now looking ahead, in the fourth quarter, we expect modest turnaround. After producing a record number of LNG cargoes in third quarter, we expect fewer spot cargoes out of Australia due to maintenance and summer temperatures. In the third quarter, we received a dividend from Angola LNG. In the fourth quarter, we expect dividends from TCO and Angola LNG, and we expect to end 2022 at the top end of our full year guidance for affiliate dividends. As a reminder, Chevron pays a 15% withholding tax on TCO dividends that lowers earnings and cash flow. In the fourth quarter, we will pay over $700 million associated with the early termination of a long-term LNG regas contract at Sabine Pass. This payment was accrued previously through working capital. Also, we expect to buy back shares at the top end of our guidance range. In closing, the third quarter showed again how Chevron's higher returns, lower carbon objective creates value for all of our stakeholders. Back to you, Roderick.

Operator:

[Operator Instructions]. And our first question will come from Jeanine Wai with Barclays.

Michael Wirth:

Yes, Jeanine, my numbers say year-to-date, Permian production, a little over 700,000 barrels a day, up about 15% from first 3 quarters of last year, which was just a touch over 600. So we're seeing good growth. And for the quarter itself, production was up about 10% at 708,000 barrels a day versus 646 in the same quarter last year. I think the thing that some people may miss is during the pandemic, drilled but uncompleted well inventories really grew. And rightfully so, we didn't need to frac wells and bring them online when there was declining demand for the production. So -- and we kept some drilling going. So that inventory grew. As we went back to work, the first thing we did was send completion crews out and start to bring the DUCs online. And you saw that through the back half of last year and certainly the first part of this year, which may have misled a little bit in terms of the rate of growth because this was this kind of surge capacity. We're back to [factory] (ph) drilling now. Our DUC inventory is kind of in line with what our plan would suggest it would be. And so we're seeing production level out at a growth rate that is more the kind of underlying rate that you should see. So we likely will be towards the lower end of the range. We get some non-ratable bookings from our non-operated joint ventures. We give you a range because we expect to be in the range, but we don't always hit the high end of the range. So in this case, we'll be towards the lower end. But we're not changing guidance for this year or our forward guidance.

Jeanine Wai:

Okay. Agreed. Thank you for that clarification. Maybe, Pierre, just sticking with you here. In terms of your comments earlier this morning, I think I caught it in an article that '23 CapEx would be at the top end of the $15 million to $17 million medium-term guidance range. There's a lot of moving pieces, and I don't know if you're going to talk about this because you'll have to -- you'll release it in a month or so. But the most obvious moving pieces that we see next year are that TCO spend starting to roll off, and some of that will be absorbed by the Permian, which we know is going to garner some more capital next year. So our question is, is capital trending to the higher end of that range? Is that more a reflection of Chevron responding to the macro environment? Or was that always part of the plan? And maybe just some inflation is pushing the capital a little higher?

Operator:

And our next question will come from Neil Mehta with Goldman Sachs.

Michael Wirth:

Sure. So I'll start with the project. We're on track to complete bulk construction by the end of this year. No change to our cost or schedule guidance, we're 97% complete on construction right now. There's still a lot of work to be done, but the risk and uncertainty are certainly narrowing and the remaining risks tend to be smaller in scale and potential impact. So we're moving into commissioning systems testing and start-up activities. We built a new integrated operations control center that I visited, which is fully operational with systems online. Our drilling program is complete. The final metering station is online. So very good progress on the construction side, and we'll continue to update you as we progress toward WPMP, the pressure management startup indicated right now for second half of '23 and then the future growth project in '24. On the CPC and the pipeline, there are no constraints on our ability to move barrels on that line. We've flowed everything out that we've been producing. And you've probably seen the media reports that a couple of the single-point moorings are offline right now for some repairs. So the buoyancy system, those repairs are underway and expected to be completed shortly. So at this point, everything flowing and it looks like we'll continue to do so.

Michael Wirth:

Sure. It's been an interesting couple of years in the refining sector, Neil. With COVID, we actually saw through that period of time, some refineries shut down around the world that maybe at a rate greater than we would have expected before as the economics really collapsed, as demand collapsed. There were -- been some refineries in the U.S. that have been taken offline after storm damage or operating incidents that are not coming back. We see others being converted to renewable diesel. And so you had a constraint or a reduction in refining capacity that occurred over the last couple of years in a way we really haven't seen previously. And the other thing that happened is some of the new builds that are in various stages of development, primarily in the Middle East or Asia, slowed down during COVID. And a lot of the industry slowed activity until we had a better view on how we were going to come through that period of time. I think those will come back into developments and eventually online which will ease some of these global constraints. But the system is tight right now. And what you see is when you have some maintenance that runs along, some unplanned events, as we've seen on the West Coast, or when you see things like the strike that we've seen in France here recently, markets tighten up really quickly. And that sends a price signal to try to bring supplies in from further away. And so the entire refining complex right now is a little more tightly balanced than it historically has been. And I think in the short term, if you want to call that the next year, plus or minus, probably stays that way, maybe a little bit longer to some degree. And then I think as you see some of this new capacity come online, we get back into a situation where it's not quite as finely balanced as it is today. But to no doubt, we're in a market that we really haven't seen probably in my career in terms of the overall tightness on supply and demand.

John Royall:

Just thinking about your buyback range, $5 billion to $15 billion. 3Q is a strong quarter from a fundamental perspective, but maybe feels more repeatable to me than as an upside case than 2Q did. In 3Q, you still generated free cash flow well in excess of both your dividend and the buyback at the top end of the range. So my question is do you think you could go further than the $15 billion at the top end, given you still have a good amount of deleveraging happening at this point in the cycle, it doesn't seem quite as extraordinary as 2Q did.

Pierre Breber:

I'll just point out that we increased our dividend 6% earlier this year. We've been growing our dividend at a compounded annual growth rate of 6% for 15 years. And that is our first financial priority. So there's a lot of tension on the buyback, but it's clearly our fourth priority after sustaining and growing the dividend, investing to grow both traditional and new energy businesses, maintaining a strong balance sheet. And as Mike said, we intend to do it across the cycle for multiple years.

Pierre Breber:

In terms of international upstream, the benefit in the third quarter was primarily around a record LNG cargoes out of Australia, primarily Gorgon and Wheatstone are very happy to see that. It was a time when the world needed the energy. And again, a lot of that is under long-term contracts, but that included cargoes in the spot market, which we know we're at high prices. So we signaled that we expect of fewer LNG cargoes in the fourth quarter because during the summer temperatures in the southern hemisphere is just how -- you just produce less. And then we do have a pit stop that is planned for 1 of our facilities. In terms of tax items, those are items that can be onetime in nature. And so I would not look for those to be necessarily repeating.

Roger Read:

Maybe just to ask a question that kind of ties a little bit into the question on the Permian. Maybe as you said, lower end in the non-op portion and the CapEx discussion. But just a broad question on inflation and not just inflation in the price sense, but some of the productivity challenges that come when you start getting busier. I mean you've got as good a global footprint as anybody. I'm just curious how you'd characterize that as you look across? And is there -- is it becoming more challenging to mitigate some of those issues?

Roger Read:

Yes, for sure. Follow-up question. Renewable natural gas RNG, we saw big acquisition announced here a few weeks ago on that front. You've been one of the leaders. And I was just curious, as you look at what's been going on in terms of some of the legislation that's come out federally as well as just the extent of the impact of the LCFS in California. Any updates we should think about in the RNG business. One of the things mentioned in that acquisition was the position that company already had in terms of -- I guess you'd call it leaseholds, right, on landfills and stuff and just characterize kind of where you are relative to where you want to be and to where maybe this competitor is setting up.

Operator:

Our next question will come from Devin McDermott with Morgan Stanley.

Michael Wirth:

Sure. So we're excited about the announcements to work with a number of really good partners to try to develop hydrogen opportunities there on the Gulf Coast. One of the things I think you're going to see in these New Energies businesses as they evolve is we're going to have to build entire new value chains. And that means we're going to partner with different people who have expertise in different parts of these value chains and can bring technology, can bring customers, can bring experience to a venture that no one company necessarily would have all of that, but collectively, we can work with people that can build these new value chains. And so it's early days on many of these things, we're studying all the different opportunities in terms of blue hydrogen, green hydrogen, there's a lot of different colors that are possible as you get down into the details of it. And it will require significant investments. So I don't want to get ahead of ourselves here. This is to really develop well-informed perspectives on the investment opportunities, the business models and ultimately, how we would build the business up there. But it's exciting. They're high-quality partners that we are working with. And I think you'll see more of these efforts announced here. We've got a lot of it that we're working on around the world, not just here in the U.S.

Michael Wirth:

Sure, Devin. So we're always looking. We've got an evergreen process where we scan all the different sectors that are of interest to us. And so we watch companies, we watch sectors, we watch opportunities. Although we've had a pretty high bar, which is why we've only done a few deals. And as you say, we feel like the deals we've done are likely to turn out well. We've got a strong portfolio. We've got a really strong base case. And so we don't need to do a deal unless it really improves on what we expect to deliver otherwise. So I would just say we're going to continue to be very disciplined. We don't have an open checkbook even when times are good like this, especially when times are good like this. We walked away from a deal a few years ago rather than chase value out of it. We've sold assets out of our portfolio at well times. And as you say, the last couple of deals were done at a pretty good time. So over time, I think in the oil and gas business, there's likely to be some more consolidation. You need fewer and stronger companies that normally happens at the bottom of the cycle rather than at the top of the cycle. In New Energies, there's a lot of activity, to Devin's question, and I think there's a very active market out there where you could see some things come together because nobody has all the pieces. And I think as you look at building these businesses, we're going to find combinations probably are necessary to actually begin to put those pieces together. But we're going to be disciplined as we have been all along. And if we do anything, we'll come out to explain to you how it's going to create value for shareholders.

Doug Leggate:

Mike or Pierre, maybe I've got one for each of you guys, and I'll go to Pierre first. So Pierre, I think you've been -- both of you guys have been very clear about managing the buyback through the cycle. And I think we all probably agree that your breakeven is not one of the best in the industry. But you still end up building a ton of cash and your share price is at, I guess, pretty close to an all-time high. So I'm just curious, the last thing you had this situation, you had multiple parallel projects going on to manage almost close to a net debt 0 balance sheet. What's to prevent you from building cash on the balance sheet and being opportunistic, whether it be through M&A or whether it be a cyclical opportunity to buy back your shares at a low level? I'm just curious how you think about that.

Doug Leggate:

Mike, I hate to put you in the spot, but you have the privilege or the challenge, I guess, of meeting with administration recently. I asked this question to your larger peer earlier today. And I'm just curious if you would care to share your thoughts on some of the potential legislative risks that might face the industry. And I guess, at a big picture level, I'm curious whether if you feel that the kind of ESG pendulum from an investor standpoint is beginning to swing back in your favor? Just that any thoughts you may care to share on that.

Operator:

Our next question will come from Ryan Todd with Piper Sandler.

Michael Wirth:

Sure. So I'll start with the REG acquisition. The assets are good, the people are little better. Any surprises so far have been to the upside. We've already identified quick wins, commercial opportunities. We've lowered insurance and financing costs. Integration efforts are all on track and delivering on our expectations. We're seeing placement of biodiesel in the Chevron's West Coast refining or in the marketing network, and that continues to ramp up. We're optimizing freight and feedstocks across the system. So all of that builds on the strength that both companies had in the renewable fuels value chain. And we just see it as really a nice combination here. The Geismar expansion is underway, and we're halfway already to our renewable fuels target as that's completed. We indicated we're going to grow to 100,000 barrels a day. We're well on our way to do that. And of course, we're investing in other relationships. We've got a joint venture with Bunge, where we're now participating in the soybean crush spread and bringing feedstocks into the system. We're working on converting hydro processing capacity at some of our refineries to be able to run bio feedstocks. So this is a part of our business that will grow the economics on it, like anything in the downstream or a function of feedstock costs, supply demand in markets. But they've been good so far, and we expect across the cycle and out into time that they're going to continue to be an important part of our portfolio. We are seeing more people go into renewable diesel. It's a market that, like any other commodity market at times may get long and margins may reflect that. But we're familiar with those dynamics from our traditional business.

Michael Wirth:

Yes. Any of these export bans have to be looked at within the context of the broader market. And as you say, just as we've seen on crude, where the U.S. has managed the import of Russian crude Europe hasn't yet that's coming. And -- but it's a global market. And you've got other buyers that need -- they need the products and they're not participating in the sanctions necessarily. And so going to the earlier question from Neil about the products side of the business, markets are tight right now. Diesel, in particular, as we've seen here recently and likely to stay that way through the winter, I think. Further, we get into the first quarter when the products ban comes into effect in Europe. And I think that's going to be set against a backdrop of pretty tight product markets, and you are going to find countries around the world need that fuel. And you get into logistics then, you've got longer shipping legs, which do you have enough ships to move it and how do you -- how does the system reoptimize? It's a less efficient optimization for sure than moving it to the natural closer markets. But I do think that you'll see those products continue to flow although just go to more distant markets with increased costs and logistics and continue to keep some of this pressure on the overall balances out there.

Lucas Herrmann:

Two, if I might. The first for you, Pierre. Just remind me, in terms of the associate contribution towards the top end of the range, I think the indication was $3 billion at the top end of the range, but perhaps you could give us an indication of the level of dividend that's been paid out to associate to date. And I guess I'm a little surprised that in the current environment, one might expect that the associate dividend would be beyond the $3 billion? And then, Mike, just if you could just give us a whirlwind tour or it's not whirlwind, but just talk around the Gulf the developments that are taking place there within your own portfolio and how those are proceeding and your current thoughts on timing. That'd be great.

Lucas Herrmann:

Sorry, Gulf of Mexico. Yes, no, Gulf of Mexico.

Lucas Herrmann:

You're welcome to talk about both, Mike.

Michael Wirth:

Okay. Gulf of Mexico, Lucas, as you know, we're one of the largest leaseholders in the Gulf. We've got over 270 leases out there and a strong base business, a lot of installed infrastructure that enables capital-efficient brownfield development. And importantly, it's one of the most carbon-efficient assets in our portfolio with a carbon intensity of about 6 kilograms of CO2 per barrel of oil equivalent. Lease Sale 257 is the one that was in question. Here a few months ago, as a result of the Inflation Reduction Act, that's been clarified and that lease sale is proceeding. We picked up 34 leases in that sale. And we look forward to continued leasing by the federal government as indicated and kind of encouraged by the Inflation Reduction Act, and we'll participate in those. In terms of production growth, we will advance a number of projects that are underway right now. Jack St. Malo has a multiphase pumping project that starts up this year and some additional development drilling. Bigfoot has ongoing development drilling and water injection that will begin in the first quarter of next year. Mad Dog 2 is operated by one of our partners, and I would refer you to them for an update on that project. We've got at St. Malo, our waterflood first injection plan for next year. Anchor a new greenfield project. We expect first oil on that in 2024. Whale, another greenfield project operated by one of our partners. I expect first oil on that towards the end of 2024. And then we recently took FID in the second quarter of this year on the Ballymore project and expect first oil on that one in 2025. So I appreciate the question because oftentimes, I hear people say, well, we can see the Kazakhstan growth. We can see the Permian. What else do you have? We've got a string of projects there in the deepwater Gulf of Mexico that are kind of sequentially lined out that will steadily contribute to production growth here in the U.S. from the deepwater.

Biraj Borkhataria:

I've got two left, please. First one is just going back to Kazakhstan and CPC. My understanding is there's been sort of fortuitous timing for Tengiz because one of the other projects in Kazakhstan has been offline, which has allowed Tengiz to flow despite the capacity obviously being lower. So I was just trying to understand, hypothetically, if Kazakh production comes back up to full capacity, but the pipeline capacity is maintained to be reduced or is not at full capacity? Then do all the projects get pro rata down equally? Or is there any other quirks that we need to be aware of there as it relates to Tengiz? And then the second question is on your LNG portfolio, performed extremely strong this quarter. Can you say what proportion of your LNG portfolio is sold under long-term contracts? And what portion is sold on a spot basis, either for the year or over the medium term?

Pierre Breber:

I'll just add that the nominations for CPC for November have already been put in place and Tengiz TCO essentially got a full nomination even for November. And again, that's even in a situation if the SPMs are not repaired. Of course, if they're repaired by then, fine issue, but even if they stay down for November, TCO has already received a full nomination. On the LNG question Biraj, it's notionally around 80% contracted, 20% spot. That's a combination of both of our Australia LNG operations and our West Africa operations. Our West Africa tends to be almost all spot and Australia is closer to 90-10. So that averages out to about 80-20. And we'll give guidance on our spot price sensitivity. We'll do that in the fourth quarter call at the end of January. It depends on how many spot cargoes are produced, both out of, again, our West Africa and Australia operations.

Irene Himona:

Congratulations on the very strong results. My first question, your financial framework is clearly to manage through the cycle. But at the same time, the current uncertainty on the commodity price outlook is rather extreme, and that is partly because of the risks or fears of a recession. So my question is, as you look at your Downstream businesses, whether in the U.S. or Asia, have you seen any signs of an economic slowdown which would cause you some concern as you look ahead to 2023 and which might perhaps drive a more conservative approach to CapEx growth?

Irene Himona:

My supplementary question, if I can go back to renewable natural gas, please. LCSS prices have more or less halved over the last year. I wonder if you can help us understand the impact, if any, on your own R&D. Does it create some pressures to perhaps work more on the technology to try and reduce the costs, given that the value of the incentive is half what it was last year?

Operator:

And our last question comes from Paul Cheng with Scotiabank.

Michael Wirth:

Sure, Paul. Yes, quickly on chemicals, earnings were a little bit lower quarter-on-quarter. And that's really a function of margins. We had higher ethane prices and lower polyethylene prices. And so the olefins margins, which is the largest driver of our performance were squeezed. So it did go down sequentially. On LNG strategy, we've long favored the Pacific Basin, given the best customers were in Japan, Korea, Taiwan markets and our resource position in the Pacific. The Atlantic Basin, we've got exposure to it. But Europe traditionally has been a market where you were competing with Russian pipe gas and just less attractive. With the changes now that we see in markets, we're increasing exposure to Atlantic Basin LNG. We've done a couple of deals with Gulf Coast projects that are being developed that will give us offtake that we can move into global markets. And then we're advancing projects in the Eastern Mediterranean and the assets that were acquired with the Noble acquisition, that would potentially allow an expansion of the Leviathan field to provide LNG supply that can go into global markets. We've looked at other things. So the big process has been underway in cutter. We certainly were deeply involved in evaluating that opportunity. Like everything that we look at, LNG has to compete against the other investment opportunities in our portfolio. We're going to stay very disciplined on capital and we won't invest in everything that we could. We're going to invest in the best things that we can. And I expect that will include some LNG projects over time.

Operator:

This concludes Chevron's Third Quarter 2022 Earnings Conference. You may now disconnect.

Roderick Green:

Thank you, Katie. Welcome to Chevron’s second quarter 2022 earnings conference call and webcast. I am Roderick Green, GM of Investor Relations. Our CFO, Pierre Breber; and EVP of Upstream, Jay Johnson, are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron’s website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement on Slide 2. Now, I will turn it over to Pierre.

Jay Johnson:

Thanks, Pierre. Second quarter oil equivalent production decreased about 7% year-on-year due to expiration of our contracts in both Indonesia and Thailand, the sale of our Eagle Ford asset and CPC curtailments impacting TCO during April. This was partially offset by shale and tight growth, primarily in the Permian. In the Permian, we are delivering on our objectives of higher returns and lower carbon. Our development costs are down about 25% since 2019 and we expect to keep them flat this year by offsetting inflation with productivity improvements. An example of simul-frac where we perform completion activities on 4 wells at a time reducing cycle time by a quarter. We continue to design, construct and operate facilities to limit methane emissions. Two of our Midland Basin sites recently earned the highest ratings from Project Canary’s independent certification program. Production is at record levels and growing in line with guidance with our royalty position, providing a distinct financial advantage for our shareholders. At TCO, the drilling program is complete and the final metering station is online. We expect to complete construction by year-end with remaining project activities, primarily focused on systems completion, commissioning and startup. Total project cost guidance is unchanged. WPMP startup is expected in the second half of next year and FGP expected timing remains first half of 2024. TCO’s operations continue to generate strong cash flow, enabling a midyear dividend with project spend decreasing we are expecting higher dividends going forward. In Australia, we shipped 87 LNG cargoes from Gorgon and Wheatstone in the first half of this year, up over 10% from last year. Our reliability benchmarks in the first quartile and we intend to stay there with an ongoing focus on operational excellence. Gorgon Stage 2, the first backfill project is on track to deliver first gas in September. Our Gulf of Mexico projects are progressing well with Ballymore receiving FID as a tieback to Blind Faith, an example of leveraging our existing infrastructure to improve returns. The Anchor hull is currently sailing from Korea and work on its top sites continues in Texas. Lastly, we recently signed agreements to export 4 million tons a year of LNG from the U.S. Gulf Coast with 1.5 million tons a year expected to start in 2026. These agreements leverage our growing U.S. natural gas production and expand our value chains in Atlantic Basin markets. Now, back to you, Pierre.

Roderick Green:

That concludes our prepared remarks. We are now ready to take your questions. Please limit yourself to one question and one follow-up. We will do our best to get all your questions answered. Katie, please open the lines.

Devin McDermott:

Good morning. Thanks for taking my question.

Devin McDermott:

Good morning. So Jay, I wanted to congratulate you on the retirement plans and take advantage of having you here on the call. My first one is on TCO and it’s great to see the project progress there. And with the WPMP portion of the project largely complete, I was wondering if you could talk a little bit more about the remaining milestones for that second phase FGP as you progress toward that first half 2024 startup?

Devin McDermott:

Great. Thank you. Very helpful and great progress there. And sticking with TCO in that part of your portfolio, there has been a lot of headlines around the CPC pipeline in recent weeks and months. I was just wondering if you could give us a status update on where things stand there? And then also to the extent that there were to be any further disruptions to flows on that pipe, can you talk a little bit about the impacts to operations for your base existing production in that area?

Devin McDermott:

Got it. Just to clarify, at the moment, operationally, at normal nameplate and flow rates through the pipe?

Devin McDermott:

Great. Thanks so much.

Neil Mehta:

Yes, good morning, team. And Jay, thank you for all the insights over the years and wish you well in your retirement, sir.