Good morning. My name is Justin, and I will be your conference facilitator today. Welcome to Chevron’s Second Quarter 2024 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. As a reminder, this conference call is being recorded. I will now turn the conference call over to the General Manager of Investor Relations of Chevron Corporation, Mr. Jake Spiering. Please go ahead.

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.

Thanks, Jake. This quarter, Chevron delivered strong production and extended our track record of consistent shareholder returns. Production increased by more than 11% from the prior year and included a new quarterly record in the Permian. Over the past two years we’ve returned over $50 billion to shareholders, approximately 18% of our market cap. We continued to advance growth opportunities in our traditional and new energies businesses by adding new exploration plays in West Africa and South America, achieving key milestones on the ACES green hydrogen project and commissioning the Geismar renewable diesel plant expansion, which is expected to come online by the end of the year. The merger with Hess achieved a successful shareholder vote, and we now expect the FTC review process to conclude in the third quarter. The arbitration panel addressing the Stabroek JOA has set a hearing for next year. Hess had requested an earlier hearing, but the panel ultimately sets the schedule. We remain confident this is a straightforward matter and the outcome will affirm a preemption right does not apply. We’re committed to the merger and look forward to combining the two companies. In the Gulf of Mexico, we’re leveraging our deepwater expertise with plans to deliver high cash-margin, low carbon intensity production growth. First oil at Anchor is imminent, delivering the industry’s first deepwater 20,000 pounds development. The project is on-track to come in under budget while deploying multiple breakthrough technologies. After Anchor, three more projects are scheduled to come online, and we expect production to grow to 300,000 barrels a day by 2026. Our developments have become more capital-efficient, unit drilling costs have come down, and facility designs are optimized for high returns. As one of the largest leaseholders in the basin, we’re well-positioned for the future with leading technology capability and attractive exploration opportunities near existing infrastructure and in frontier areas. In the Permian, base business performance continues to improve, with higher reliability and lower decline rates. Development activity continues to get more efficient. We’re one of the first operators to deploy triple-frac, delivering cost reductions of more than 10% and shortening completion times by 25% where applied. In the Delaware Basin, company-operated well performance continues to improve as we optimize development strategies. In the Midland Basin, early well results are lower versus last year, but our program in the second half of the year is more heavily weighted to development targets that we expect to perform better. With strong momentum in our operated portfolio and predictable results from our non-operated and royalty acreage, we now expect full-year production growth of about 15% and fourth quarter production to average around 940,000 barrels per day. At TCO, cost and schedule guidance is unchanged, with FGP expected to start up in the first half of 2025. We continue to bring major equipment online and complete key project milestones. Eight out of 21 metering stations have been converted to low pressure. Three Pressure Boost Facility compressors are in operation. A third gas turbine generator is in service. The first 3GP process system is ready for operation, and we completed the SGI turnaround on time and under budget. The wells converted to low pressure are meeting expectations, and the Pressure Boost Facilities are operating with high reliability. Over the next two quarters, we’ll continue converting the field to low pressure while further commissioning key equipment for FGP. The project team remains focused on completing the project safely and starting up reliably to deliver value to Kazakhstan, TCO, and shareholders. This quarter was a little light due to some operational and other discrete items that impacted results, but I remain confident we’re well-positioned to deliver on long-term earnings and cash flow growth. Now, I’ll turn it over to Eimear to cover the details.

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 the 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, which 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.

Okay. Thanks, Eimear. Today we announced we’re moving Chevron’s headquarters from San Ramon to Houston to enable better collaboration and engagement, both internally and externally. We also announced the retirements of Nigel Hearne, Executive Vice President, Oil, Products & Gas; Colin Parfitt, Vice President, Midstream; and Rhonda Morris, Vice President and Chief Human Resources Officer after long and distinguished careers. I want to extend my sincere thanks to Nigel, Colin, and Rhonda, for their service and their many contributions to our company. Finally, I’d like to offer our deepest condolences to the family of our former Chairman and CEO, Ken Derr, who passed away three weeks ago. Ken’s vision and leadership helped guide Chevron through momentous times to create a high-performing company with outstanding people and a portfolio that distinguishes our business to this day. Ken left an indelible legacy for our company and all those whose lives have been made better by his leadership. He will never be forgotten. Back to you, Jake.

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

Thank you. Please follow the operator's instructions. And our first question comes from Neil Mehta with Goldman Sachs.

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 the 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?

Sure. Thanks, Neil, and thanks for your kind remarks about our retiring executives. So, at TCO as I covered in my comments, we’re seeing steady and consistent progress. Work is being planned and liquidated in sequence, which is resulting in strong daily, weekly, and monthly progress. I get a weekly report straight from the project team with a tremendous amount of detail. I’m in regular contact with them, and I can tell you that they are really on top of their game. As I said, we’ve got three of the pressure boost facilities up and running; the fourth not far away, and WPMP is operating very reliably. So, we’re pleased with the performance of the equipment. We’re very pleased with the performance of the wells flowing at low pressure, and its early days, but it augurs very well for the maintenance of strong production out of the field for a long time to come. On FGP, we’re going to have additional major equipment and systems ready for operations or started up later this quarter. And, we’re just going to continue to work our way through that. We’re moving in a more complex process unit as opposed to some of the big rotating equipment and field metering station conversions. We do have a large turnaround this quarter. So, good progress. The one thing that we won’t compromise is safety or reliability in pursuit of schedule, but I can tell you that the team is all over that. With respect to the concession, we’re really focused right now on getting this project up and running. The concession exploration is nearly a decade away, and the most important thing we can do is make sure that this complex project is started up safely and reliably. To remind people that may not know, this is one of the world’s deepest producing supergiant oil fields and the largest single trap producing reservoir in existence. So, TCO is very important to the Republic of Kazakhstan, it’s very important to us, and we’ll certainly be in discussions with the government over time about potential extension. The key thing is an extension needs to create value for the country and it needs to create value for Chevron shareholders. We always seek that kind of an outcome. We’ve extended concessions in other places where value was created for both parties. And there have been some instances over the recent period of time where we couldn’t achieve the outcome, and we did not extend. We’ll be talking more about this subject over time, but right now we’re focused on project execution and continuing strong performance on delivering FGP. Thanks, Neil.

And, next is Alastair Syme with Citi.

Thanks, Mike. This period of limbo around Hess is obviously a period you don’t want to be in. It’s not clear to me when the FTC rules or if they push out, until arbitration as I sort of previously indicated. But my question to you is, do you feel limited to do any other significant portfolio development in this interim period? I guess if the right opportunity came along that is?

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. 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. We’ve projected 10% growth in free cash flow, with projects coming on in numerous basins around the world and in our chemicals business as well. 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.

And the next question will come from Paul Cheng with Scotiabank.

Thank you. Mike, can you talk about the potential for further cost efficiency gains? Where do 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.

Yes. Thanks, Paul. I appreciate it. You and I have known each other for a long time. You know that capital discipline and cost discipline are near and dear to my heart, and they always matter in a commodity business. Year-to-date and Q2 unit OpEx for us was about $16 a barrel, which is down about 5% from 2022. Improving unit OpEx continues to be a focus. Some of the actions we’re taking today drive down energy usage, which is a way to both reduce costs and emissions. At the same time in the Upstream, we’re electrifying rigs in the Permian, we’re lowering steam use at our San Joaquin Valley operations, and in the Downstream we’re implementing energy efficiency projects at our refineries that reduce gas consumption and power use. We’re also optimizing supplier contracts, implementing a minimum functional objective approach to operations, and maintenance activities at key assets like TCO and our LNG plants in Australia. We’re confident that we’ll continue to find ways to increase efficiencies and reduce unit costs. Our plans call for further unit cost reductions. You can look for us to use technology. The breakthroughs we’re seeing in data technology offer significant opportunities for efficiency, asset productivity, improved safety, and other performance. You can rest assured that I am focused on costs; we are focused on costs, and you’ll continue to hear more about that from us over time.

Thanks, Paul.

Thanks, Paul.

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

Hi, thanks for taking my question. I wanted to just go back to Kazakhstan and the FGP ramp up. So, I wasn’t asking an operational question, but I appreciate FGP is on-track. But it was related to the OPEC promises or curtailments. Kazakhstan this year has been a bit ahead of its stated quota. If you take the headline figures from OPEC into next year, it doesn’t look like there’s a huge amount of room in that quota to grow. And obviously, FGP is a fairly substantial project. So, just wanted to get your thoughts on any sort of issues or risks related to that? Thank you.

Yes. Thanks, Biraj. 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 on producers in the country. We have not received any indication from the Republic of Kazakhstan regarding any curtailments relative to OPEC+. What often happens there is, with the production in several big assets, you have turnarounds, projects, and other things that create variability across multiple 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, from a contribution to the Republic standpoint, are very attractive and our intent is to produce at full capacity at any point in time for our facility in order to maximize revenue for the Republic and for Chevron. If there are further developments on that front, we’ll certainly provide them, but we don’t have anything from the government right now. Thank you.

And we’ll take a question from Doug Leggate with Wolfe Research.

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 if there’s 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 that a compromise that could cut the arbitration short is my question?

Yes. Hey, it’s great to hear a familiar voice back on the call, Doug, and I look forward to seeing you in Houston. What you have outlined is very sensible. It could be the foundation for something, but I really can’t comment on specific conversations. I think we have indicated previously that there was a period of time where Hess and Chevron worked with the other partners in the Stabroek block to try to find a resolution that accommodated everybody’s interests, and that time has now passed and we’re in the arbitration process. So, that’s the path that we’re on. We sought something along the lines of an outcome as you described earlier, but it doesn’t appear that this is how this is going to end up. Everything is confidential obviously, the language in the contract, and contracts around the world have specific language in each instance. I think the parties understand how that contract is written and how it would apply. So, I can’t say anything more about it than that.

Thanks, Doug.

And the next question comes from Josh Silverstein with UBS.

Hey, thanks, good morning, guys. Nice update in the Permian. I was wondering if you could provide a little bit more detail around the 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.

Yes. So look, the Permian is performing strongly as you can see in the numbers. Just to remind everybody about 80% of our program is in the Delaware. Delaware performance is up year-on-year and first half ‘24 production overall in the basin now averaged over 870,000 barrels a day, which is essentially flat or even a touch up from the fourth quarter of last year. The drivers of that are improved performance across multiple dimensions of the business, and in the base business we’re seeing lower decline from proactive maintenance efforts, lower operated downtime, and artificial lift optimization. I mentioned triple-frac earlier, which is reducing costs and increasing cycle time. So, the spud-to-pop cycle has shortened further. We’re getting more pop days online than we might have a year ago, and well performance, as I said, in the Delaware has been very strong. In the Midland, some of the first half pops have been a little bit below expectations. There’s only a finite number of pads I could count them on one hand that are involved in this, and we’re always moving into new zones, new acreage. We’ve got an active learning and continuous improvement effort to be sure we’re optimizing development across the basin because it is not completely homogeneous. As we’re testing new zones to better inform our future development plans, we learn. In this particular case, the learnings will be applied as we go forward. That said, it performed very well in the past. This is a big long-term asset that has a lot of life ahead of us and we should be continually improving in it, so that over time we can deliver even stronger returns, stronger performance, and stronger production than previously expected. We’ve raised our full year guidance and we’ve got great confidence in what we’ll deliver in 2025. Thanks, Josh.

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

Hey. Good morning.

Good morning, Roger.

Good morning, Mike. And, yeah, welcome to Texas. If we could maybe dig into the Gulf of Mexico, as you said, the first kind of 20,000 PSI development. What are some of the experiences you’ve had or the industry has had with this level of pressure? And what are some of the things we should be watching for, maybe in another way of asking the question, how have you gotten comfortable on the technology side in terms of bringing this forward and developments behind it?

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. Moving into that pressure regime, obviously you need bigger equipment because you’ve 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. 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 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.

Yes. Mike, you hit on one key thing, and that is that the partnership that was demonstrated here with ourselves and industry partners to deliver the first 20K subsea development. To your question in terms of how did we get comfortable, I think it was because we brought the best of our engineers, the best of our suppliers, and the best technology that we had, several examples of proprietary technology that we brought. The extensive testing and quality testing that took place before we went out to the field. We delivered the first 20K subsea well completion and subsea production trees and manifolds. So, this is the core equipment that protects us from loss of containment and ensures that we safely and reliably can operate the field. We drilled wells. We developed a drilling rig. We built a drilling rig with our partners to enable drilling at these depths and the equipment to allow us to do that; that had very special dynamic positioning and technology as well. When we think about the prospect and how we were able to see it and get a really good accurate image of the prospect, we used our proprietary seismic technology; this is our in-house Chevron proprietary technology to help us with that image and to enable us to make the right decisions about the development and optimize the development.

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

Hey. Good morning. Thanks for taking my question. Eimear, I wanted to stick with you, and I have a bit of a strategy question for you. If we kind of put together several of the things that’s been talked about on this call so far, the TCO start up, strong Permian production growth, rising production in the Gulf of Mexico, it all kind of materializes in the form of this inflection in free cash flow as we go into 2025 and beyond. Chevron has historically had four consistent priorities for use of cash. But now that you’ve had some time in the CFO’s team, I was wondering if you could talk about your views for the optimal use of cash, especially in the context of your current low leverage levels and how you’re thinking about the trade-off between further dividend growth or more buybacks as cash flow rises over the next few years?

Yes. Thanks, Devin. I’m thinking about it consistent with how we have for decades and consistent with our long-standing financial priorities. 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. 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. 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. We look at our balance sheet as an asset to create value, manage volatility, and ensure steady capital returns through the cycle. 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. We take a multi-year view of that considering a range of commodity prices. In my time with the company on 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. They’re not going to change.

And the next question comes from Nitin Kumar with Mizuho.

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 the economics of biofuels?

Yes. You’re right. We had some turnaround activity in the second quarter that occurred during the more attractive margin portion of the quarter, and then we had more capacity back online as margins dropped precipitously in some cases. We didn’t capture as much as we could because of the timing of some of our activity. Globally, product demand is decent. Overall demand for oil is going to be up 1% to 2%. Most products have recovered to pre-COVID levels. We see decent economic growth underway around the world. We’ve had some new refining capacity come into the system in the Middle East, Africa, Mexico, and Asia, so it’s coming online, so it’s in startup. Inventory levels have risen over the first half of the year and they’re at or above five-year levels. For some period, we’ve been of the view that margins were going to revert toward mid-cycle by this year or next year, and that’s certainly what we see going on in some cases. Mid-cycle has been pretty tough in some parts of the world, and we’re back to pretty tough margins. This maybe transitions us to renewable fuels, where these are markets that are heavily influenced not just by supply and demand but also by policy because a lot of the value is driven through the credits associated with those. We’ve seen periods of time in the past where the targets didn’t come out of the EPA until after the compliance year had ended, which was challenging. We’ve seen the EPA get ahead of the game and set numbers well into the future. It’s hard for people to anticipate markets. Right now, we’ve got a market where a lot of capacity has been incentivized, and we don’t have the RBOs that necessarily match up with it. In an oversupplied market, credit values are down both at the federal level and state level. We welcome to our margin business. This is the way value chain businesses work, at least through my career, much of which has been in the Downstream, and you need to be prepared for it. You need to have a capital-efficient investment philosophy, which we do. Some of our refinery investments have been to create flexibility to move back and forth between fossil feed and renewable feed. We’ve done that. We’ve idled some plants, which you do when you’re in a period like this, and we’re completing the Geismar project, which will give us scale and importantly feedstock flexibility. In the margin business, you need to have access to affordable, competitive, and reliable feedstock. The flexibility that Geismar will have will allow it to compete very well. We’ve got another project underway, a joint venture with Bunge to move back into the bean crush portion of the value chain, which further helps us assure competitive supply into Geismar. This is a business where we’ll see periods of time where margins are tough, and you probably see some competitive capacity under pressure, and so that shutdown and over time then they’ll tend to cycle the other way. We’re in this business for the long haul. We think drop-in renewable fuels are going to be part of creating a lower carbon energy system in the future. We’re very committed to that business through good times and challenging times, and we’ll be pragmatic, efficient, and value-chain-oriented in optimizing that business.

And the next question comes from Jason Gabelman with TD Cowen.

Good morning. Thanks for taking my question. You guys have built out a pretty large exploration portfolio in the past few years, and I think you’re starting to delineate some of that acreage. I’m wondering, out of the positions you’ve amassed around the world, what you’re most excited about? And then related to that specifically on Namibia, there’s a lot of interest in the market about that region. Could you remind us what your drilling plans are for that region this year and any interest in consolidating the space given the number of small and large players over there? Thanks.

Yes. Thanks, Jason. You’re right. We have added some new acreage to our portfolio and some that’s in areas that are kind of more frontier than some of the stuff we’ve historically held. Look, we’re excited about several 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. 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 of Egypt. We’ve got plans to drill there, which include a delineation well on the Nargis discovery. The third one I would point to is West Africa, including existing positions in Nigeria, Angola, Equatorial Guinea, and Namibia, where there’s a lot of interest lately. We’ve seen others make some discoveries. In the Orange Basin, we’ve got lease PEL 90, which sits just outboard of where an interesting discovery has recently been made. 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. We’re 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 we’re interested in continuing to add to our acreage position there if opportunities present themselves. We’ve got three ways of bringing resource into the company: exploring for it and discovering it, acquiring it, or unlocking it through technology. All three of those receive a lot of attention, and we’ve got talented people working in each area to bring resources in through all of them. I’m excited about some of the new exploration acreage that we’re adding.

And the next question comes from Bob Brackett with Bernstein.

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?

Yes. Bob, on the ground, what we’re doing is really monitoring the situation. You’ve seen the news coverage, and our focus remains on the safety of our employees and their families and the integrity of the assets in our joint venture operations. We’ve been a constructive presence in Venezuela for most of the last 100 years. We conduct our business there in compliance with their laws as well as the laws of the U.S., which are administered under a general license issued by the Treasury Department. We’ve seen some encouraging results here recently since the issuance of the most recent general license; our JVs are producing around 200,000 barrels a day. We’re being repaid debt that we have been owed and are steadily achieving that objective. We’ve also seen the extension of some of the concessions on some of these non-operated joint ventures that we are involved in. We remain apolitical in Venezuela and in other countries. We’re there to help develop the economy, support the people, create jobs, and not get involved in politics, which can swing in any country from party to party. We’ve found that it’s best to work with the government that’s in power, respect the fact that that is the government that we have, and not take positions that would make it difficult for us to continue to work with a subsequent government. We don’t have a role in selecting governments; we’re a commercial player, not a political player. Our focus is on keeping our people safe and the assets protected. Thank you, Bob.

And next is Neal Dingmann with Truist.

Good morning. Thanks for getting in. Mike, my question for you and the team is just on OFS costs. I’m just wondering if you’ve seen any change in prices given the very recent fall in oil prices. If so, or just going forward, would you expect to see maybe domestic cost hold while international stays firmer or vice versa?

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, with 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. 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. Some of these things lag on the way up, they lag a little bit on the way down. In the onshore, you’re right, you’re seeing some easing of pressures. 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. 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 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. Certainly not the inflationary pressure we’ve seen a couple of years ago. Thank you, Neal.

And the next question comes from Geoff Jay with Daniel Energy Partners.

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? Just wondering if you can maybe update us on what you think the potential could be there and what the timeline of exploration might be?

Yes. So, we did pick up a block off Uruguay; and there are beliefs that there are certain conjugate margin analogs that we see on the South American side of the Atlantic. Obviously, there’s a lot of work that needs to be done to explore those theories. In some instances, we have seen evidence that supports it and in others less so. We’ve also picked up some acreage in Brazil and in Suriname. Across the whole Eastern Coast of South America, we’ve got some exposure and intend to do the geotechnical and seismic work to understand the prospectivity of it. Very early days on that particular prospect, but we’re intrigued by it, and it’s an example of what I mentioned earlier that we’re moving into some areas that are a little more frontier than where we’ve been over the last number of years.

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

Good morning. Thanks for taking my question. I want to go back to the Permian. It’s great to see the momentum, the operational momentum you’re seeing on the operator side. Just given the triple fracs and certainly acceleration of the cycle time, curious how you think about this pull forward of activity. Would you likely do more with the same equipment, or would things slow down or end up using less equipment? Also, curious about what you’re seeing on your royalty and non-operated production front as well.

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 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, complete more feet, and use more consumables and sand as we do that. Some of the easing of pressure on cost of goods and inputs helps us offset that, and we’re trying to manage to our CapEx numbers. You can expect us to balance activity and capital. We’re not going to get off to the races on capital. You can expect us to manage within the budget; the budget is a budget. The nice thing is we’re getting, due to improved cycle times and efficiencies, stronger productivity out of the equipment, 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.

And our last question comes from John Royall with JPMorgan.

Hi, good morning. Thanks for taking my question. So, my question is just if you could give some color on the downtime you saw at 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?

Yes, John. So, the downtime in upstream in May and June was associated with some unplanned events in Gorgon and Wheatstone. On Gorgon, there was a blade failure, so they had to take some time to repair that. They used the time when they were down to try and do as much maintenance as possible. On Wheatstone, they actually had a gas leak that was discovered by an operator. We’re always going to shut the plant down and repair any leaks in the spirit of operational excellence. So, they repaired that, and it was on the fuel gas system and got things back up and running. The repairs were executed safely and efficiently, and we expect both of those assets to run with good reliability this year with top quartile performance. The Gorgon asset turnaround is currently underway and that’s going really well. We expect that to come in under the planned duration this quarter. Despite the downtime, we expect to close the full year and deliver on the planned production for the combined Australia assets.

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.

Thank you. This concludes Chevron’s second quarter 2024 earnings conference call. You may now disconnect.