Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's First Quarter 2024 Earnings Conference Call. 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, Katie. Welcome to Chevron's First Quarter 2024 Earnings Conference Call and Webcast. I'm Jake Spiering, the General Manager 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. Reconciliation of non-GAAP measures can be found in the appendix of this presentation. Please review the cautionary statement on Slide 2. Now I'll turn it over to Mike.

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. The first quarter marked nine consecutive quarters with adjusted earnings over $5 billion and adjusted ROCE above 12%. During the quarter, we also returned $6 billion in cash to shareholders, the eighth straight quarter over $5 billion. We also grew production more than 10% from the same quarter last year and announced final investment decisions to grow our renewable fuels and hydrogen businesses. Earlier this month, we announced our third Future Energy Fund focused on venture investments in lower-carbon technologies. The merger with Hess is advancing, and we intend to certify substantial compliance with the FTC second request in the coming weeks. We believe that a preemption right does not apply to this transaction and are confident this will be affirmed in arbitration. We expect the proxy for the Hess shareholder vote to be mailed in April with a special meeting date in late May. This strategic combination creates a premier energy company with world-class capabilities and assets to deliver superior shareholder value, and we look forward to bringing the two companies together. At TCO, we achieved the start-up of WPMP this month with the first inlet separator and pressure boost compressor in service, and conversion of the first metering station to low pressure is now complete. Later this quarter, we expect a second pressure boost compressor online and a third gas turbine generator to provide power to the Tengiz grid. Metering station conversions are planned through the remainder of the year as additional pressure boost compressors start up, keeping the existing plants full around planned SGI and KTL turnarounds. We continue to make significant progress on FGP and expect to have additional major equipment ready for operations in the third quarter. Costs and scheduled guidance remain unchanged with FGP expected to start up in the first half of 2025. Now over to Eimear to discuss the financials.

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. Chevron delivered on all of its financial priorities during the quarter, an 8% increase in dividend per share; organic CapEx aligned with ratable budget inclusive of progress payments for new LNG ships; sustained net debt in the single digits while issuing commercial paper to manage timing of affiliate dividends and working capital; and share repurchases of $3 billion. Adjusted earnings were lower by $1 billion versus last quarter. Adjusted upstream earnings were down due to lower realization and liquids liftings, partly offset by favorable tax impacts. Adjusted downstream earnings were lower mainly due to timing effects associated with the rising commodity price environment. All other decreased on higher employee costs and an unfavorable swing in tax items. Adjusted first quarter earnings were down $1.3 billion versus last year. Adjusted upstream earnings were down modestly. Higher liftings were more than offset by lower natural gas realizations. DD&A was higher due to the PDC acquisition and Permian growth. Adjusted downstream earnings were lower mainly due to lower refining margins and timing effects. Worldwide oil equivalent production was the highest first quarter in our company's history. Production was up over 12% from last year, including an increase of 35% in the United States, largely due to the PDC Energy acquisition and organic growth in the Permian Basin. Looking ahead to the second quarter, we have planned turnarounds at TCO and several Gulf of Mexico assets. Following another strong quarter in the Permian, production is trending better than our previous guidance, and we now expect first half production to be down less than 2% from the fourth quarter. Impacts from refinery turnarounds are mostly driven by El Segundo and Richmond. We anticipate higher affiliate dividends in the second quarter, largely from TCO. With the start-up of WPMP, we expect TCO's DD&A to increase by approximately $400 million over the remainder of the year. Share repurchases are restricted under SEC regulations through the Hess shareholder vote, after which we intend to resume buybacks at a $17.5 billion annual rate. We've published a new document with our consolidated guidance and sensitivities that will be updated quarterly and posted to our website the month prior to our earnings call. Back to you, Jake.

That concludes our prepared remarks. We are now ready to take your questions. We will do our best to get all of your questions answered. Katie, please open the line.

Our first question comes from Sam Margolin with Wolfe Research.

Maybe we could start with Tengiz because there's movement there. Specifically, the effects of the WPMP start-up, if you don't mind going into some detail. I think the market understands that it's the FGP phase that really rerates TCO's distribution capacity. But if there's any incremental benefits from WPMP starting up, whether it's reliability or potential to produce over nameplate or even just the CapEx run rate and what it means for maybe an annualized TCO distribution at this stage, that would be very helpful.

Yes, Sam, let me talk a little bit about the project and operational dimensions of this, and then I'll let Eimear comment on the financial ramifications. So look, we're really pleased with the progress that's being made 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. It's an important milestone. I'm proud of the team and the work they've been doing. They've done this safely. We're seeing initial operation that is well aligned with our expectations. In fact, we've been encouraged by a very strong production response from the wells that feed into this first metering station. We now have the second metering station planned for conversion as off-line, and that conversion is underway. As we bring on more of the PBF compression capacity, we'll complete more metering stations over the balance of the year. What happens here is we get higher production because the wells are now flowing against lower back pressure. We've seen really strong response on this first set of wells. This gives us a high degree of confidence in keeping the plants full all year long, even with the planned turnarounds we have to do. We've had an SGI turnaround this quarter and a KTL turnaround planned for next quarter, to do some tie-ins and other normal maintenance. But in the periods in between those, it increases deliverability and our confidence that the plant will be full throughout that period. We've got a lot of operational project scope to remind you of; we're producing from new wells. Our reliability has significantly improved with upgraded control networks and new utilities. So all of this translates to a higher degree of reliability and strong production performance. Last year was the second strongest year in the past several years, giving us high confidence in delivering on our plans. As we get into the third quarter, we'll start commissioning some of the process equipment as part of FGP. So, good progress all the way around. I'll reiterate that schedule and cost guidance are unchanged. We'll continue to provide details each quarter on milestones and progress as we proceed. Eimear, maybe you can just talk about what that means financially.

Yes. Thanks, Mike. Yes, Sam, well, after years of investing, as the project starts up over the next couple of years, we do expect the CapEx profile to continue to decline, enabling free cash flow to grow. With WPMP, it will keep the plants full. So this will allow IBS business to generate significant cash, which will be available for distribution. The second phase of the project in 2025, TCO's free cash flow is likely to grow even further thanks to the incremental production from that phase. So, for Chevron, we're expecting $4 billion of free cash flow in 2025 and $5 billion in 2026 with a $60 Brent. This will flow to us through a combination of dividends and cash flow from operations.

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

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?

Yes. Thank you, Neil. We've got a nice portfolio of exploration opportunities around the world, including numerous prospects on Block 90 in the Orange Basin offshore Namibia, which lies just offshore from where a recent discovery was announced by another company. We're planning to spud the first exploration well in that block late this year or early next year based on rig availability. The rig will be completed in early 2025. We farmed into another block, Block 82, further north in the Walvis space, and that was just announced earlier this week. As you know, there have been a number of discoveries made by companies in the Orange Basin. Our block is on trend with those discoveries. We're encouraged by the success we see from others. This is certainly an area where the industry has had a high degree of success. We're pleased that we've got two blocks now offshore Namibia, and we will talk more when we get into the exploration program there.

We'll go next to Paul Cheng with Scotiabank.

You guys did a small deal on the retail marketing asset, adding over 200 stations in the Gulf Coast and West Coast. Since you've become the head of downstream, you've been selling assets there. So is there a change of your view in terms of the overall strategy related to that part of the business? Will you be owning the asset, or is this a wholesale marketing network type of deal that you are acquiring?

Yes. Thank you, Paul. As you know, I come out of that part of the business. We've got three strong brands around the world: Caltex internationally, Chevron and Texaco here primarily in the Americas. You're right; we only own about 5% of our branded stations in the U.S. Most of our business is done through large retailers and distributors. We've entered into supply and brand agreements with these marketers. We’ve done a couple of deals recently that added several hundred stations to our network. As part of that, we advanced some cash to support their brand conversion efforts and investments in the network and to solidify our relationships with these important customers. This spending will help us grow our branded sales and is critical to our business. We do these kinds of deals frequently, though they often are smaller, so they don't always get the attention they deserve. But it's important to note that we won't own these stations; they will be owned by strong independent retailers. Thanks for the question.

We'll go next to Wei Jiang with Barclays.

Mike, just so we're seeing that the U.S. operations look pretty strong this quarter, especially with Permian holding in better than expected relative to your expectations. Could you just talk about what drove the better performance in the Permian and how you think the rest of the year unfolds? And then just anything else within the U.S. that you want to highlight?

Sure. Yes, first quarter production in the Permian was good at 859,000 barrels a day, down about 1% from the fourth quarter of last year, which was better than anticipated. We have seen reliability improvements that have translated into slightly less decline in our base production. We also experienced a shorter frac-to-PAD cycle time. This resulted in more wells coming online in the first quarter, contributing to the production you see. Well performance was generally in line with expectations, and we're also seeing good contributions from our royalty acreage, which has the highest return barrels as we have no investment there. Increased activity in that area has led to increased royalty production, and our non-operated joint venture is right on plan with strong visibility for this year. Eimear mentioned that we now expect our first half to be better than previously guided. We initially expected a 2% to 4% decline compared to the fourth quarter of last year, and now we're looking at less than 2% down. Regarding the back half of the year, we expect to exit around 900,000 barrels per day with further improvements. Additionally, the Anchor project in the deep water Gulf of Mexico is on track for midyear start-up, and we expect to see positive developments from other Gulf of Mexico projects in the following quarters.

We'll go next to Joshua Silverstein with UBS.

You had around $1 billion of debt this quarter to manage some of the working capital and distribution timing. Do you see the cash balance growing sequentially? Did you repay the commercial paper in Q2? Just wanted to get a sense of where the cash outlook may go sequentially.

Eimear, why don't you take that?

Yes, Josh. We issued some commercial paper in the first quarter to manage short-term liquidity as the timing of affiliate dividends can be a bit lumpy. This was normal business for us in the first quarter. In terms of cash on the balance sheet, we aim to hold about $5 billion in cash, which can fluctuate. We have access to substantial liquidity and commercial paper through bond investors and credit facilities. While we've held higher cash balances in the past, having excess cash with low debt and high liquidity can be a drag on returns, so we're comfortable with the $5 billion target.

We'll go next to Biraj Borkhataria with RBC.

I wanted to ask a follow-up on the Permian. You put out the updated well productivity slide, which was very helpful. But a few quarters ago, Mike, you talked about some broader constraints in the Permian, whether it's CO2, water handling, and so on. It seems that this hasn’t impacted your volumes in the near term, but could you refresh us on if anything has changed in your views?

Yes, thanks, Biraj. Nothing has really changed. This is a very large base business now with thousands of wells. It's imperative that we focus on productivity, efficiency, and reliability in drilling and completions. This also includes managing midstream takeaway, gas processing, and water handling. We have plans for more development in the New Mexico portion of the Delaware, which requires building out some capabilities that's part of our capital program. It's very critical to monitor base business reliability daily, including seismic activity. Recently, we saw excellent performance despite some challenges in previous quarters. As for takeaway capacity concerns, we are well covered for oil, NGL, and gas, and we don’t expect to be affected by discounted in-basin pricing.

We'll go next to Nitin Kumar with Mizuho.

Mike, I wanted to get an update on Venezuela. There were reports that the Biden administration is reinstating some export bans on that country. It specifically stated that Chevron was not included, but I would like your thoughts on the future of oil production and exports from the country and how it would impact Chevron.

Yes, thanks, Nitin. As you might recall, the Department of Treasury has issued various licenses for companies operating in Venezuela. One relevant for us is General License 41, which pertains to our operations there. The second license, General License 44, applies more broadly, and recent changes to that don’t affect us. We’re not investing new capital in Venezuela currently; all spending is self-funded from operations cash. Since the license was obtained over a year ago, we’ve seen an increase in production from joint ventures in Venezuela, going from about 120,000 barrels per day to about 180,000 barrels per day now. Eimear, do you want to elaborate on the financial aspects?

Yes. Nitin, just to clarify, we apply cost accounting in Venezuela rather than equity accounting. So we don't record the production or reserves from that region. We only recognize earnings upon cash receipt, which shows up under other income on the income statement. In 2023, the cash flow from Venezuela was relatively modest, below 2% of overall cash flow from operations.

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

I wanted to ask about the divestment program. When the Hess deal was announced, you discussed plans for $10 billion to $15 billion in divestments. Given that's currently in a bit of a holding pattern, what do you expect the cadence or target for divestments to look like? Historically, you’ve done about $2 billion a year.

Yes, happy to clarify, Jason. You’re correct that we continuously review our portfolio to optimize value. This isn't due to a need for cash, but to ensure we’re capital disciplined. We've divested around $35 billion worth in the last decade and have historically kept divestments at about $2 billion per year, which constitutes about 1% of our capital employed. For 2024, the guidance remains at 1% to 2%. When the Hess transaction closes, we will add some attractive assets valued for capital investment. Our divestments currently are in regular course and include areas like Myanmar, where we exited, a planned exit in the Congo, and potential exits in unconventionals in Canada and the Haynesville.

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

Given the launch of Future Energy Fund III, can you provide insights into what success cases emerged from Funds I and II that prompted this move? Could you also compare your in-house solar and hydrogen projects with where you might see third parties trialing new technologies?

Yes, I appreciate the question. This is an area we've not sufficiently communicated about with investors. Funds 1 and 2 were smaller, at $100 million and $300 million. They're nearing full subscription, which is why we announced Fund 3. We've been investing in venture capital for over two decades. The Future Energy Funds focus on energy transition themes. Through Funds 1 and 2, we've invested in over 30 companies and partnered with about 250 co-investors. We act as a pilot site for technologies, helping to bring them from the lab to real-world applications. For instance, last year, I visited a carbon capture pilot project. We’re working on improving carbon capture efficiency and reducing costs. We're concentrating on industrial decarbonization, hydrogen, and energy decentralization, aiming to innovate in areas we aren’t developing in-house. In contrast, the projects in the Permian Basin, like solar to green hydrogen, rely on established technologies. Our venture investments focus on developing new technologies and systems, and over 25 years, we’ve seen a positive return on our investment. While not every company succeeds, many do, and this keeps us engaged with the evolving landscape. We’re enthusiastic about the new fund.

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

Can we talk about Eastern Med? I know operations shut down earlier, but everything seems to be back up and running. Can you also tie this into Egypt, where there's been exploration talk and efforts to improve the investment environment?

Yes, we're back to full operations in the Eastern Med. Tamar was down for about a month at the start of hostilities. We're excited about the opportunities there. As a reminder, we have the two existing platforms, Tamar and Leviathan, which are in service. We've structured our development plans to focus on capital efficiency and higher returns. Since completing the Noble acquisition, we've increased production at Tamar and Leviathan by over 10% through better reliability. We have ongoing projects that, when completed, are expected to further increase production by 40% over the next couple of years. We're evaluating larger expansion options for Leviathan. In Egypt, we have a discovery at Argus, with another appraisal well planned for late this year or early next year. There are additional blocks yet to be drilled with seismic data collected, including a spud well in Block 4 by year-end. It’s an area with genuine prospectivity, promising near-term growth through ongoing projects and exploration opportunities over the next decade.

We'll go next to Francis Lloyd Byrne with Jefferies.

I know we've covered a lot of ground this morning, discussing Permian productivity that looks very good. Could you touch on the DJ Basin? Production seems stronger than expected. Also, any political risk comments?

Sure. Yes, first quarter production in the DJ was above 400,000 barrels a day, higher than our long-term guidance. We had the timing of several fourth quarter 2023 wells coming online, and while we expect weather-related downtime in Colorado during the first quarter, we experienced less than anticipated this quarter. Overall, production remained robust. In the second quarter, we expect minimal impacts from a third-party gas plant outage, and we’re seeing continued strong performance. These are high cash margin, low-breakeven barrels that are valuable to our portfolio. Just a few years ago, we didn't have anything in DJ; now we’re producing at around 400,000 barrels a day. We aim to maintain that plateau amid timed pad completions. Regarding the political landscape, Colorado's energy sector is crucial to its economy, and I'm confident that responsible development will continue as a shared goal. We maintain strong relationships with state legislators and governor officials as the largest oil and gas producer in the state, contributing significantly to the local economy. While challenges may arise through ballot or legislative proposals, I believe we will work collaboratively moving forward. Eimear, would you like to touch on PDC and its benefits?

Yes, it has been about nine months since we closed on the PDC Energy acquisition. We're pleased with the progression we've seen and the synergies. On the CapEx side, we’ve realized $500 million in captures so far, which is $100 million ahead of our initial guidance. We are also seeing a similar achievement on the OpEx side, nearing $100 million. Our teams continue to integrate effectively, merging the best practices of both companies and creating a comprehensive development playbook to optimize returns in the basin. We're seeing strong free cash flow from these assets, putting us ahead of our target for an incremental $1 billion in annual free cash flow.

We'll go next to Devin McDermott with Morgan Stanley.

I wanted to bring it back to TCO. Mike, I believe you've discussed how there are similarities in design between WPMP and FGP. As you bring WPMP online, are there elements that help to derisk FGP?

Yes. Just to remind everyone, this TCO field is massive. FGP, the Future Growth Project, utilizes earlier second-generation plant designs for sour gas injection, an approach we've optimally integrated, increasing production while reducing back pressure with the help of compression technology. This brings longevity to our production. The project includes modernizing infrastructure that dates back to before Kazakhstan's independence. The start-up sequencing is essential for preparing and ensuring the systems are operational, which has strong parallels across both projects. The implementation of WPMP has shown productivity from the field resources, which translates positively to FGP too. Though the projects have distinct scopes, their similarities in equipment and commissioning convey that the successful milestones of WPMP will indeed give us confidence in FGP.

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

Regarding the renewable portion of your portfolio, you’ve announced FIDs on a couple of renewable projects—one in biofuels and another in solar to hydrogen. Can you provide confidence on these specific projects, whether it's commercial, technical, or regulatory support? Are there further opportunities to develop similar projects, or are there unique elements about these that enhance their attractiveness?

Yes. We have two significant projects. One is an oilseed processing plant in our joint venture with Bunge in Destrehan, Louisiana. This project features a flexible design, enabling feedstock flexibility, which is essential in fuels manufacturing. We can process various seeds, including winter canola, enhancing our renewable fuels business, especially the Geismar renewable diesel project launching later this year. The flexibility across the value chain is critical, capturing margins from multiple segments. The project in California focuses on green hydrogen, utilizing existing solar production capacity. Our 5-megawatt production facility in Lost Hills will yield about a metric ton of hydrogen per day for retail stations while leveraging current infrastructure. While smaller in scale, it adheres to our strategy of utilizing existing assets and promoting growth incrementally. These undertakings are influenced by government policies, such as the renewable fuel standard and the Inflation Reduction Act, which differ from our traditional business model. We thoroughly evaluate each opportunity to ensure viable returns before proceeding.

We'll go next to John Royall with JPMorgan.

My question is on West Coast refining. We have one West asset producing gasoline and an expectation for TMX to increase heavy crude availability once fully ramped. Nonetheless, the regulatory climate is challenging. Given your multiple assets in California, how is your perspective on that region today? Should we expect structurally higher gasoline margins in California due to reduced capacity?

We've been operating in California for over 145 years. Our integrated value chain supports a competitive refinery network with advantageous logistics, meeting the rising demand in a large economy. While ongoing operations are crucial, the policy environment is focused on reducing investment in traditional energy and fostering lower-carbon energy solutions. Several refineries have closed permanently or shifted to other purposes, tightening the supply-demand balance, even with still strong demand. So, in terms of margins, there can be added pressure as operational reliability becomes vital. Our focus is to maintain efficient operations and, while California presents investment challenges, our long-standing commitment remains. We’re looking at our global portfolio for optimal investment opportunities, and today, I wouldn't categorize California as a favorable investment environment.

We'll take our last question from Alastair Syme with Citi.

Mike, can you help me understand the sequencing of the Hess timetable? We have a shareholder vote in May and there are pending regulatory issues, including arbitration. Can you elaborate on the arbitration timetable?

Yes. There are three key factors to note regarding timing. Firstly, the shareholder vote is upcoming in May, with proxies mailed in April. Secondly, we are making progress on regulatory approval with the FTC, expecting substantial completion by midyear. Finally, the arbitration has its own timetable, set by the tribunal. Hess has requested the merits be heard in the third quarter, with a potential outcome by the fourth quarter. Assuming that aligns properly, we should be able to proceed with closing shortly after. We see no legitimate reason for delays in that schedule.

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