Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's First Quarter 2024 Earnings Conference Call. [Operator Instructions] 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, 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. First quarter marked 9 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 2 companies together. At TCO, we had achieved 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 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 offsetting were 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 the $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. [Operator Instructions] We will do our best to get all of your questions answered. Katie, please open the line.

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

Maybe we could start with Tengiz because there's movement there. And 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 FGP phase that really rerates kind of 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 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. 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 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. And 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. And as I said, Sam, we've seen really strong response on this first set of wells. What that does is it gives us a high degree of confidence in keeping the plants full all year long with the fact being that we've got some turnarounds we have to do. We've got an SGI turnaround and a KTL turnaround, SGI this quarter, KTL next quarter, to do some tie-ins and some other normal maintenance. But in the periods in between those, it increases deliverability and the confidence of the plant will be full throughout that period of time. We've got a lot of project scope operational is the other thing that I just would remind you of. We're producing from new wells. We've got upgraded to new utilities now, gathering system, a new control center, power distribution system, 2 new, big-frame 9 gas turbine generators in service. So the reliability of the infrastructure and all of the control networks and everything is significantly improved as we got more modern equipment in place. So all of this reads through to higher degree of reliability, strong production performance. And last year was the second strongest year in the past several. So it gives us high confidence in delivering what we've said we'll deliver there. And then as we get into the third quarter, we'll start commissioning some of the process equipment as part of FGP, which, as you say, first half start-up next year is when you see the incremental production come online. So good progress all the way around. I'll reiterate that schedule and cost guidance are unchanged. And 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, and that will enable free cash flow over the next couple of years to grow. With WPMP, it will keep the plants full. So this will allow IBS business to generate significant cash, and that will be available for distribution. With the second phase of the project then next year in '25, TCOs free cash flow is going to grow even further because with that phase of the project, we get incremental production. So what does this mean for Chevron? Well, we expect $4 billion of free cash flow in 2025 and $5 billion in 2026. This is a $60 Brent. This will flow to us through a combination of dividends, so you'll see this come through cash flow from operations and loan repayments, which will flow through cash for investing. So we do expect dividends this year. We have guidance -- affiliate guidance to dividends for 2024. But we've also included in the deck today the outlook for affiliate dividends for the second quarter, $1 billion to $1.5 billion. And a significant portion of that is an assumption around TCO.

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 and including numerous prospects on Block 90 in the Orange Basin offshore Namibia, which lies just outshore -- outbound of where there was a recent discovery 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 '25. We farmed into another block, Block 82, which is further north in the Walvis space, and that was just announced earlier this week. And 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. And this is certainly an area where the industry has had a high -- a good batting average, a high degree of success. And we're pleased that we've got 2 blocks now offshore Namibia. And of course, we'll talk to you more as we get into the exploration program there.

We'll go next to Paul Cheng with Scotiabank.

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?

Yes. Thank you, Paul. As you know, I come out of that part of the business. I love talking about retail. Look, we've got 3 really strong brands around the world. Caltex internationally; in Asia, primarily; in Middle East and Africa, a little bit. Chevron and Texaco here primarily in the Americas. And you're right, we only own about 5% in the U.S., even less than 5% of our branded stations. So most of our business is done through large retailers and distributors. We enter into agreements of supply agreements and brand agreements with these marketers. And there are times, different mechanisms, we use to support their investments. We've done a couple of deals here in the last quarter that are substantial, that add a few hundred stations to our network. And as part of that, we advanced some cash to support their brand conversion efforts, their investment in the network and to solidify our relationship with really important customers of ours that ultimately sell on to consumers. And so you saw that consume some cash. It technically from an accounting standpoint doesn't get classified as capital, but we want to disclose it because it is cash. And it helps us grow our branded sales. And so it's an important part of our business. We're doing these kinds of deals all the time, Paul. They tend to be oftentimes smaller magnitude, so they don't necessarily get to a size where we would mention it the way that we did today. But we won't own these stations. They're owned by really strong independent retailers. Thanks for the question.

We'll go next to Betty Jiang with Barclays.

Mike, just -- so we're seeing that the U.S. operations look pretty strong 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. 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. We saw a significantly shorter frac to POP cycle time, so between completed frac and when we put it on production. So that resulted in a few more wells being POP-ed in the first quarter, which you see in the production. Well performance itself was generally aligned with our expectations. And so we've been talking a lot about type curves the last few quarters. We're seeing strong performance that's aligned with or even a little bit stronger than what we expected. And then we also saw some good contributions from our royalty acreage, which is the highest-return barrels we have because we really have no investment there and it's attractive acreage. Others are developing it. And we saw increased activity that resulted in increased royalty production. NOJV, right on plan with what we expected and a lot of visibility into the non-operated joint venture portfolio for this year, more even than last year at this time, and confidence that, that will deliver. So all of that translated into a very strong first quarter. Eimear mentioned that we now expect our first half to be better than we'd previously guided. We said 2% to 4% down versus fourth quarter of last year. We now think we'll be less than 2% down. And then, of course, the back half of the year, we had another frac spread. We've got more wells online and expect to exit the year around 900,000 barrels a day. So really strong performance there and consistent with the momentum that you've seen in prior quarters. The -- I guess the other thing I would mention relative to the U.S. more broadly is the Anchor project in the deepwater Gulf of Mexico is we've guided towards midyear start-up of that. It's right on track. The floating production unit is being commissioned. As we speak, we've got both buyback gas and back oil in the facilities. So that means the pipelines, the process units are now charged with live hydrocarbons. We're commissioning some of the subsea infrastructure, including flow lines. The completion of the first well is in progress. Second well is drilled and will be completed shortly. Third well is being drilled right now. So we'll talk more about this, but everything is right on track for start-up of Anchor midyear. And then, of course, we've got other Gulf of Mexico projects as well that are kind of stacked up right behind Anchor over subsequent quarters. So the outlook in the U.S. is especially strong.

We'll go next to Josh Silverstein with UBS.

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, why don't you take that?

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. I think in terms of what to expect in terms of cash on the balance sheet, I mean, we target to hold about $5 billion in cash, and that will bounce around as well. But I think $5 billion is a good number. We have access to lots of liquidity and commercial paper, bond investors, credit facilities. So while we've had higher cash in the balance sheet in the past, holding excess cash with low debt and lots of access to liquidity can be a drag in returns. So we're quite comfortable with the $5 billion cash, and that's a good number for you to focus on there.

We'll go next to Biraj Borkhataria with RBC.

I wanted to ask a follow-up on the Permian. So you put out there the updated well productivity slide, which is very helpful. But a few quarters ago, Mike, you talked about some of the broader constraints in the Permian, whether it's CO2, water handling and so on. It doesn't look like it's impacted your volumes in the near term, which have performed very well. So could you just refresh us on if anything has changed in your views on that there?

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. And we've got more development underway this year in the New Mexico portion of the Delaware, which is going to require a build-out of some of this capability, which will be part of our capital program addresses. But you really have to stay on top of base business reliability on all these things. Seismic is another one we've seen some issues on. And so they're all part of managing the business for safety and reliability each and every day. We had a quarter -- a couple of quarters back where a number of those things were a challenge. And the current quarter, we saw really good performance. Last thing I might mention, which might be implied in your question, you see some talk about the takeaway capacity out of the basin and are people constrained, is that impacting particularly gas prices within the other commodities. We're covered on takeaway capacity out of the basin on oil, NGL and gas well out into the future. And so we're not exposed to any in-basin discounted pricing as a result of that.

We'll go next to Nitin Kumar with Mizuho.

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

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. I'll just remind you, we're not putting new capital into Venezuela right now. All the spending is really self-funded from the cash from operations. We've been lifting oil and bringing it to the U.S., which has been helpful for the U.S. refining system, not just ours but others as well. And since that license was issued now a little bit more than a year ago, we've seen production at the joint ventures that we're participating in increase from about 120,000 barrels a day at the time that, that license was issued to about 180,000 barrels a day now. So that's an update. There are some -- maybe it might be worth reminding just how the financial side of that works because it's a little bit different than some of the other parts of our production. So Eimear, do you want to touch on that?

Yes. Nitin, just as a reminder, for Venezuela, we do cost accounting, not equity accounting. So Chevron is not recording the production here or the reserves. We record earnings when we receive cash, and that shows up under other income and income statement. Just to put this into context, in 2023, the cash was modest, probably less than 2% cash flow from operations.

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

I wanted to ask about the divestment program. I know when the Hess deal was announced, you discussed $10 billion to $15 billion. But given that's in a bit of a holding pattern here, I'm just wondering what you expect the cadence or the target for divestments to be. I think historically, you've done about $2 billion a year. So that's not too far from what the guidance was with the Hess deal. Just trying to try and lay those 2 numbers and getting a sense of what the divestment program could look like while that deal is in a bit of a holding pattern. If you could just remind us the assets that have been discussed in the market, that would be great.

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. They tend to be early-in-life assets. We were at Rosebank and divested that a few years ago or things that are much later in life and might fit better with somebody who works those kinds of assets. Over the last decade or so, 2012 through 2023, we divested about $35 billion worth. Our long-term history has been about $2 billion per year, maybe 1% of our capital employed, give or take. And our guidance for this year is 1% to 2%, so it's pretty consistent with history. We did say that upon the closure of the Hess transaction, we're going to add some assets that are going to be highly attractive for capital investment. And that means as you look through the rest of the portfolio, if we stay capital-disciplined, there are probably some things that we might otherwise have invested in that now we would choose not to. And so that's where the 10 to 15 guidance came from. That would still stand upon closure. The things we're doing now are things we would have done in the normal course. And so they're not really related to high-grading post the Hess addition. The things that are in the public domain, we talked about Myanmar, which we exited as of April 1. We've announced that we intend to exit the Congo, and we've got a deal there. We expect that to close before the end of the year. We have talked about our position in unconventionals in Canada and in Kaybob, Duvernay, which is a nice asset, which has some growth opportunities, but it may be a better fit for others. So we're looking at alternatives there. And then also the Haynesville, we paused our development activity in the Haynesville last year, and that's another one that we think may fit better with others. So I think those are the ones that are out in the public right now, Jason.

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

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.

Yes. So I appreciate that. This is one that we probably haven't talked about with investors as much as some of the other parts of our business. Funds 1 and 2 were smaller, $100 million, $300 million. And they're not actually fully subscribed yet, but they're getting there, which is why we announced fund #3. We've been in the venture investing business for 1/4 of a century, so going back to the late '90s when we first set up our venture investing organization. And in the Future Energy Funds, which are those that are really need on energy transition themes, through Funds I and II, we've invested more than 30 companies already. We're collaborating with 250 or so other co-investors in these companies. We can serve as a pilot bed for their technology so we can help them bring things from the lab and kind of bench scale out into the real world. And I've visited last year, one of our carbon capture pilots in the San Joaquin Valley with a company that's got some really interesting technology to help us improve the efficiency, reduce the cost for carbon capture. And so we're looking at things like industrial decarbonization, hydrogen, emerging mobility, energy decentralization, the circular carbon economy. And what we're really looking to do is support innovation in things that we probably aren't doing within the company, within our own R&D or scale up. As you mentioned, the projects in the Permian Basin or in the San Joaquin Valley, the solar to green hydrogen is using established technologies that are well proven. What we're doing in our venture investing is trying to develop these new technologies, new materials, new novel ways to integrate AI and other kinds of technology systems to help solve some of these problems. And hopefully, we find things that will help our business and help the world. Last thing I'll say is over the 25 years, we've more than earned our money back in our return on our investment. Not every one of these companies is successful, but we've seen a lot of technologies move into our business. We've seen a lot of the companies become successful. And there's a lot of innovation going on out there. This allows us to leverage ourselves into smaller start-up innovation that we might not otherwise see. So it's been a very, very positive for us, and we're excited to announce the new fund.

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

Can we talk a little bit about Eastern Med? I know at one point, operations shut down. It sounds like everything is back up and running. But also you would kind of tie that into Egypt a little bit, where there's been some exploration talk and in the government trying to do some things to improve the overall investment, I guess, environment there.

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. Since we've closed on the Noble acquisition, we've increased production at Tamar and Leviathan by more than 10% just through debottlenecking and reliability. We've sanctioned projects at both of those that are currently in progress that will increase production by another 40% over the next couple of years. And we're looking at larger expansion, particularly for Leviathan, where we've got a number of concepts that are being evaluated. Obviously, in the current environment, we're moving carefully with development of those. You mentioned Egypt. We've got a discovery at Argus. We expect another appraisal well there in late this year or early next year to better characterize the field and refine our development plan. We've got a number of other blocks that have not been drilled yet that we shot a seismic on. And we plan to spud a well in Block 4 there before the end of this year. And so it's an area that I think has got real prospectivity. As you look at growth in both the near term, with the projects I mentioned and then the longer expansion of existing and exploration prospectivity, it's a part of our portfolio that I expect us to see growth from over the coming decade.

We'll go next to Lloyd Byrne with Jefferies.

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?

Sure. So yes, first quarter production in the DJ was above 400,000 barrels a day, kind of higher than what our long-term guidance is. We had timing -- a lot of fourth quarter '23 wells put on production there. You'd typically expect some weather-related downtime in Colorado over the first quarter. We saw some of that, but less than what we had planned for. So production was good. Second quarter, there's maybe some minimal impacts that we expect from a third-party gas plant that's had an outage. But continued strong performance there thus far in the second quarter. These are high cash margin, low-breakeven barrels that we're really pleased to have in our portfolio. If you go back 3 years ago, we didn't have anything in DJ. We were not talking 400,000 barrels a day of production there. We plan to hold our plateau there around 400,000 barrels a day, and it will fluctuate a little bit based on the timing of bringing new pads on and completion of wells, et cetera. But it's a really strong asset for us. Let me talk about the politics and kind of the operating environment a little bit, and then maybe I'll have Eimear just touch on PDC and the benefits of that. But Colorado is a state where energy is an important part of the economy. And I grew up there. The environment is very important to the people and the state as well. And I think their goal has been to be a leader in responsible development and to recognize the important economic contribution that our industry makes to the states. I'm confident that, that will continue to be the case. We've got good relationships with members of the legislature, with the executive branch, with the governor. And as the largest oil and gas producer in the state with over 1,000 employees who live and work there and we were a significant investor there, we engage broadly within the community. And I think there's a recognition that responsible development in Colorado is what everybody wants and what we are committed to. And there's -- can be some noise around ballot proposals. There can be some noise around legislative proposals. But we're confident that the state is interested in working with us to be a responsible player and for this to be an important part of the economy. Eimear, maybe PDC, some of the benefits, just so people are reminded of that.

Yes. It's been about 9 months since we closed with PDC Energy. We're really pleased with the progress that we're seeing, the synergies. On the CapEx side, to date, we've captured $500 million, which is $100 million more than what we had initially guided to. We're also seeing capture on the OpEx side as well. So we're nearing $100 million there. The teams are continuing to integrate. We're bringing the best of both companies together and building a development playbook focused on optimizing returns in the basin. We're realizing strong free cash flow from these assets. So we're ahead of pace for the incremental $1 billion in annual free cash flow that we guided to.

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

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?

Yes. So it's -- just to remind everybody, this is a massive field. Some of you have visited it. And FGP, the Future Growth Project, is taking things we did almost 20 years ago now with the second generation plant in sour gas injection, where we injected about half of the sour gas. And we're now injecting all the sour gas, increasing production. And at the same time, we're reducing back pressure on the field and using compression to push the production into the facilities so that we're not relying on field pressure to do that. And that increases the life and longevity of the production out of the field. The other thing this project brings with it is what I've described sometimes as urban renewal. And it takes infrastructure that was built back even before Kazakhstan was independent. And it brings power and utility infrastructure, control infrastructure up to modern-day technology and modern-day standards. So the projects are quite integrated. The start-up sequencing in terms of what you do to walk down systems, ensure they're ready for operation, do all the testing and start-up is very similar, whether you're in one portion of the project or another. And the productivity of the field resources that we see on WPMP reads across to FGP as well. And so while they're fundamentally different project scopes and objectives, so much of the work is similar across equipment and the commissioning and start-up activities that I think the positive progress we're making, the success we're seeing in commissioning and start-up at FGP reads straight -- at WPMP, reads straight across to FGP as well.

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

Maybe one on the renewable side of your portfolio. I mean you announced FIDs on a couple of different renewable projects, one in biofuels, one in solar to hydrogen. Can you provide some color on what underpins confidence in these specific projects, whether it's commercial or technical or regulatory support? And do you see further opportunities to develop similar projects in the portfolio going forward? Or are there specific things about these ones in particular that make them attractive?

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. The margins can move from the crush margin into the upgrading margin or what you consider the refining margin, into the marketing margin. And just like in our traditional business, being able to catch all margin across the value chain as it moves is important. Having flexibility, scale and reliability are important. So all of those underpin the investment decision there. The project in California on green hydrogen is smaller in scale. And it really uses existing solar production capacity. We've got a 5-megawatt production facility in our Lost Hills oilfield in Kern County. And we're going to produce about a metric ton per day of hydrogen for retail fuel stations. So we're using existing infrastructure. We're integrating into the value chain. We've got another venture that is building hydrogen refueling facilities in California. And so we're leveraging existing assets, existing value chains and capabilities to invest here. As I say, smaller scale, and I don't want to overplay it, but it's very consistent with our strategy. And these things have got to start small and then scale. And so we're pleased with both of these. There are markets, maybe to your point about economics that are, in some ways, heavily influenced by government policy, be it the renewable fuel standard and the Low Carbon Fuel Standard, which affect renewable fuels or some of the things in the investment or the inflation reduction act that affect hydrogen. And so it makes them a little bit different than our traditional business, which really works off market fundamentals. But we look at a lot of cases there, and we invest in projects where we believe there's confidence that over time, we can generate a good return.

We'll go next to John Royall with JPMorgan.

So my question is on West Coast refining. We now have one West asset producing gasoline on the West Coast, and TMX should be increasing the availability of heavy crudes once it's ramped. But it's a tough regulatory climate. And you're well positioned as one of the players that still has multiple assets in California. How are you thinking about that region today? And should we see structurally higher gasoline margins in California given we've had some capacity come out?

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. That said, the policy environment has been one that is geared towards reducing investment in traditional energy, encouraging investments in these lower-carbon energies. And you've seen assets go out of the system, fossil fuel-fired power plants. There's a lot of questions about the one remaining nuclear power plant in the state. And you've seen refineries close down, as you say, some permanently, some to convert to uses, including to renewable fuels. And what that does is it creates a tighter supply-demand balance, particularly as demand continues to be strong and you need to have strong operations out of that entire system or you need to bring in supplies from somewhere else if you've got planned or unplanned issues that the system is dealing with. And so on an average, what does that mean? It means margins are probably under more pressure. It means reliable operations are very important. And it's a place where we've operated for a long time and expect to continue to do so. But putting new investment into the state is a different question. And I think we've been pretty clear that we've got a global portfolio and we'll invest where we see the best conditions, and I wouldn't describe California that way today.

We'll go next to Alastair Syme with Citi.

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.

Yes. So there are, I think, really 3 things, if you're looking at sequencing and timing here. One is the shareholder vote. And as I said, the proxy will be mailed out in April, and the shareholder vote will occur in May. You've got regulatory approval through the FTC, and we're making good progress on that. We're working closely with the FTC in respect to their role in the process and expect us to be substantially complete with that here by midyear. And then we have the arbitration, which is, I think, a little bit less well defined at this point. The specific scheduling and time line will be established by the arbitration tribunal. In our S-4, we indicated that Hess has asked the tribunal to hear the merits of the cases in the third quarter with an outcome in the fourth quarter, which would allow us to close the transaction shortly thereafter. We see no legitimate reason to delay that time line. It's consistent with what Exxon has outlined is what they would expect. But I can't say that's exactly how it unfolds because we haven't seen specific scheduling from the tribunal yet.

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

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.

Yes. So there's a couple of kind of broad framing points, I think, to bear in mind as you think about that. Number one is we've guided to a long-term capital spend at around $16 billion. This year, we've got $15.5 billion to $16.5 billion as a range. And we intend to be very disciplined with our capital investment and only invest in the most attractive opportunities. We've also indicated that over a period of time, beginning in 2022 through 2028, I think it was when we announced our -- we had our energy transition spotlight, that we expected to spend about $10 billion in our New Energies business over that period of time, $8 billion in kind of the newer -- emerging business lines of carbon capture and storage, renewable fuels and hydrogen and then another couple of billion in decarbonizing our own operations and businesses. It's not completely ratable. And that is a guide that we may or may not achieve. We may be a little below that, we may be a little above that, depending upon how these opportunities mature in new businesses. And to the earlier question, we need to be sure we've got confidence when we're putting capital, particularly large capital, some of the smaller things to help accelerate technology, learning, et cetera, like our venture investments, which tend to be a few millions of dollars in any particular company. We recognize the risk-return equation there. But larger investments, we've got to have a belief that this is a business that's going to deliver a return over time, and we're on the path to building a portfolio of businesses that will do that. And so that $10 billion is a guide, but we'll invest in things that make sense, and we'll explain the numbers if they end up a little bit different than that. And so what that can tell you is the majority of our spend is still going into our traditional business because the majority of the world's energy is still provided by our traditional business, and we've got an obligation to meet that demand as long as it's there. But we're going to be very disciplined in what we invest in and only invest in the highest-return opportunities. And so each year, we issue specific guidance that we can -- you can look at. But longer term, I think you have to stay within those broad parameters and expect us to remain disciplined.

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. Katie, back to you.

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