Q2 2023 Chevron Corp Earnings Call

Participants

Jake Spiering

Michael K. Wirth; Chairman & CEO; Chevron Corporation

Pierre R. Breber; VP & CFO; Chevron Corporation

Biraj Borkhataria; Director, Co-Head of European Energy Research Team & Lead Analyst; RBC Capital Markets, Research Division

Devin J. McDermott; VP, Commodity Strategist for Power Markets & Equity Analyst of Power and Utilities Research Team; Morgan Stanley, Research Division

Douglas George Blyth Leggate; MD and Head of US Oil & Gas Equity Research; BofA Securities, Research Division

Irene Himona; Equity Analyst; Societe Generale Cross Asset Research

Jason Daniel Gabelman; Director & Analyst; TD Cowen, Research Division

John Macalister Royall; Analyst; JPMorgan Chase & Co, Research Division

Neil Singhvi Mehta; VP and Integrated Oil & Refining Analyst; Goldman Sachs Group, Inc., Research Division

Paul Cheng; Analyst; Scotiabank Global Banking and Markets, Research Division

Roger David Read; MD & Senior Equity Research Analyst; Wells Fargo Securities, LLC, Research Division

Ryan M. Todd; MD & Senior Research Analyst; Piper Sandler & Co., Research Division

Sam Jeffrey Margolin; MD of Equity Research & Senior Analyst; Wolfe Research, LLC

Stephen I. Richardson; Senior MD and Head of Oil and Gas & Exploration and Production Research; Evercore ISI Institutional Equities, Research Division

Presentation

Operator

Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2023 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.
I will now turn the conference call over to General Manager of Investor Relations of Chevron Corporation, Mr. Jake Spiering. Please go ahead.

Jake Spiering

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

Michael K. Wirth

Thanks, Jake, and thank you, everyone, for joining us today.
Earlier this week, we announced several senior leadership changes, including Pierre's plans to retire next year, along with second quarter performance highlights. In a few minutes, Pierre will share more details on our financials, which included return on capital employed greater than 12% for the eighth consecutive quarter and another quarterly record in shareholder distributions, more than $7 billion.
At TCO, we're making good progress with commissioning and pre start-up activities, including introducing fuel gas to new facilities. In the third quarter, we expect mechanical completion for the future growth project and to complete a major turnaround. Cost and scheduled guidance is unchanged.
Conversion of the field from high pressure to low pressure is expected to begin late this year and FGP is on track to start up by mid next year. We have unused contingency, which gives us confidence that we'll complete the project within the total budget.
After completion of these projects, TCO is expected to deliver production greater than 1 million barrels of oil equivalent per day and generate about $5 billion of free cash flow, Chevron share at $60 Brent in 2025. Chevron's Permian production set another record in the second quarter, about 5% above the previous quarterly high.
We expect next quarter's production to be roughly flat before growing again in the fourth quarter, on track with our full year guidance. Early 2023 well performance in our company-operated assets in all 3 areas is consistent with our plans. In New Mexico, we've put on production at 10 wells. Before year-end, we expect to pop an additional 30 wells with higher expected production rates. As a reminder, about half of Chevron's production is company operated with a balanced non-operated and royalty production.
While short-term well performance is one measure, we're focused on maximizing value from our unique, large resource base expected to deliver decades of high-return production. Over the next 5 years, we expect to develop over 2,200 net new wells, growing production while delivering return on capital employed near 30% and free cash flow greater than $5 billion in 2027 at $60 Brent.
Longer term, we've identified well over 6,000 economic net well locations that support a plateau greater than 1 million barrels per day through the end of next decade. Our deep resource inventory and advantaged royalty position allow us to optimize our development plans for high returns, incorporating learnings and technology improvements as we expect to deliver strong free cash flow for years to come.
In the Deepwater Gulf of Mexico, the floating production unit anchor is on location and the project remains on track for first oil next year. We continue to build on our exploration success and were awarded the highest number of blocks in the most recent lease round. In the Eastern Med, our Aphrodite appraisal well in Cyprus met our expectations, and we've submitted a development concept to the government.
At Leviathan, we're expanding pipeline capacity to nearly 1.4 Bcf per day. We expect to close our PDC Energy -- our acquisition of PDC Energy in August after their shareholder vote next week. Our teams are working on integration plans, and we look forward to welcoming PDC's talented employees to Chevron.
Now over to Pierre.

Pierre R. Breber

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

Jake Spiering

That concludes our prepared remarks. We'll now take your questions. (Operator Instructions) Katie, please open the lines.

Question and Answer Session

Operator

(Operator Instructions) Our first question comes from John Royall with JPMorgan.

John Macalister Royall

Glad to be the first on this call to congratulate Pierre on his retirement. So my first question is on upstream production. Can you bridge us maybe from the midpoint of your production guidance to the low end that you mentioned in the opening. It sounds like the Permian is on plan. So what pieces have come in below the midpoint of plan to move to that well end?

Michael K. Wirth

Yes, John. We're -- guidance remains unchanged. We expect to be at the lower end of that. And as we said, Permian production has been strong. The things that Pierre mentioned, I think, are the key things that we've seen. There's been some impact of fires in the -- in Canada that have impacted our ability -- not really our operations per se. We did some evacuations on a precautionary basis, but it was midstream and processing downtime that we weren't able to move our production to market. And the rest of it is and Benjamins too, I guess, is the other one. We have an FPSO in Thailand that had an incident and early in the year was taken off station.
And so that's another 10,000 or 11,000 barrels a day yet, which is off for the foreseeable future. And so it's really those 2 things are the ones that are pushing us down that were both unexpected.

John Macalister Royall

Great. And then my next question is sticking to production, but just drilling in a bit on the Permian. The well results generally looked very strong in the first half, but still a bit below 2022 in New Mexico. Maybe you can just update us on what inning you think you're in just in terms of optimizing the single bench developments in New Mexico?

Michael K. Wirth

Yes. So the thing that I think it's important to bear in mind is that New Mexico type curve we showed there, there are only 10 POPs represented or 10 POPs that we achieved, all in the second quarter there. So there's no first quarter POPs. And there's only 7 that actually had enough data to make it into the curve you see on the chart. So it's a very thin set of data. We expect 30 more POPs in the second half of this year. So the bulk of the program is not represented in those curves.
And there's a couple of other things. One, the wells we did POP have had some facility constraints that have limited full productivity. So we actually haven't been able to move all the production due to some third-party facility constraints that we faced. And the rest of the program is actually in a different part of the New Mexico portion of the Delaware where we expect higher productivity. So it's a combination of things, but I really -- I'd caution you not to over index on a very thin data set with a lot more data to come in the second half of the year.

Operator

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

Devin J. McDermott

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

Michael K. Wirth

Yes. Devin, we're still drilling primary benches so we can optimize the oil cut. Across the basin, our production remains roughly 50% oil, 25% NGLs, 25% gas. We look at all the commodities, oil, NGLs and gas and have our own long-term views on prices and markets to run the economics, to optimize to returns.
And the gas oil ratio in aggregate has been relatively flat for a number of years and we don't see it changing a lot. It can vary a little bit in different parts of the basin. But if you take it for our whole portfolio, that 50%, 25%, 25% remains a pretty good way for you to think about it.

Devin J. McDermott

Okay. Great. And then I wanted to shift over to TCO. Good to hear the continued positive progress there as we get closer to the finish line. There's a lot of moving pieces over the next year, 1.5 years as we get the 2 phases of development online, you give the guidance for the turnaround impact in 3Q.
I was wondering if you could talk a little bit more about how you see the evolution of production into the fourth quarter of this year and then through 2024 as we get to that 2025 run rate, so shape it a bit for us as we look out over the next few quarters.

Michael K. Wirth

Yes. So the headline here is no change to cost and schedule, I think that's really important. In the second quarter, we made really good progress. As we said, 98% project completion and commissioning is essentially 2/3 complete. In the second quarter, we achieved mechanical completion of the 3GI gas injection facilities and got fuel gas into the flare system, which is very important to enable on-time startup of FGP.
In the quarter that we're in now in the third quarter, we expect full mechanical completion of the future growth project and also a turnaround at one of the complex technology lines or KTLs. We'll begin a lot of work and start up on utility systems, boilers, steam system, other utilities that are required for a start-up of a pressure boost facility, which is the key driver of WPMP, which enables us to convert from high pressure to low pressure across the field.
Once that that turnaround is done in the third quarter, and you will see some production impact. I think Pierre guided to that, we expect to have 2 of the 4 big pressure boost compressors online, which allows us to begin the conversion of metering stations from high pressure to low pressure, and that will initiate -- we'll get that started at the end of this year. It will take 10 to 12 months for all of those conversions to occur.
Next year, there will be turnarounds next year as well, 2 more turnarounds, 1 at SGI and another one in one of KTLs and all of that is part of a very carefully choreographed sequencing of turnarounds and start-up activity that will bring the full field to the 1 million barrels a day for 2025.
So as we indicated at our Investor Day, what you're going to see in '23 and '24 is the normal turnaround activity interlaced with all of this project start-up activity. This is not as simple as bringing on a new portion of the field, really reworking the entire gathering and producing capacity of the field. And so it's quite a complex series of activities to execute all of that. And so the production reflects that. And we've put, I think, and said in earnings, a chart to kind of give you some guidance for both this year and next year.

Pierre R. Breber

Yes, Slide 10 from our set has annual production '23, '24, '25. No change in that guidance.

Operator

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

Neil Singhvi Mehta

I want to stay on TCO and while there will be a volume inflection in '25, there's probably going to be a free cash flow inflection in 2024, just as affiliate CapEx rolls off first. And so just can you talk about the cadence of that and how it manifests itself in terms of dividends?

Pierre R. Breber

Yes. We've been guiding, Neil, it's Pierre, to the clean year because that's the $5 billion of free cash flow at $60 Brent in 2025. And of course, regarding the free cash flow because as you recall, it's not just dividends, it's also repayment of the loans and the co-lending that we have done along the way and the profile of those loans are disclosed in our SEC filings.
I mean you will see exactly to your point, you'll see a build towards that just as the CapEx has rolled off is not, not that long ago, we were investing $3 billion to $4 billion a year our share into the project, and that's down to $1.5 billion or so this year and will continue to trend down. So there's that inflection point.
What's also being managed, of course, our commodity prices and those vary. And as we've said, TCO continues to be conservative in managing its balance sheet. But as the -- so it's been holding more cash on the balance sheet. As the project gets closer to the end, as we've demonstrated that TPC is running very reliably now for almost 1.5 years, we expect some of that cash to come on.
So I can't get in front of the board of directors of TCO. It's a separate company that we are a shareholder in, but we expect, as we said, a much bigger dividend in the fourth quarter than we saw in 2Q, and we expect to see a release of some of that extra -- surplus cash that's been held on the balance sheet, and that will continue over the next couple of years as we head into that $5 billion of free cash flow in '25.
And maybe the last thing, Neil, I know you know this, TCO has really good price sensitivity. So I've seen yours and other estimates that [70] or [80], the cash flow is even stronger.

Neil Singhvi Mehta

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

Pierre R. Breber

Yes. The range, Neil, is tied to the upside, downside cases that we showed at our Investor Day roughly, right? So this $10 billion to $20 billion. So you're right, it's a wide range because it reflects a wide range of prices between that upside case and the downside case. And of course, in between, there's sort of a mid-cycle case. And as a reminder, that downside case gets to $50 in a couple of years and stays there for 3 years. So that is a real downside case. And that's what the low end of the buyback range is notionally tied to.
The upside case is a case that's not too different from what we're seeing now. It averages about $85 over the 5-year period, it trends down to $70 towards the end of that period. And that's why you're seeing a buyback very close to the top end of the range at the $17.5 billion. So it's certainly a signal that as we look out over this commodity cycle, and again, we think of the buybacks as being steady across a cycle that we feel good about it.
So we said we could do a much larger buyback, but that would be not steady, and we want to be -- we don't want to be procyclical. We're trying to be across the cycle. And so yes, when we guide on buybacks, we're guiding with the intent of maintaining it for a number of years across the cycle.

Michael K. Wirth

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

Operator

We'll go next to Stephen Richardson with Evercore ISI.

Stephen I. Richardson

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

Michael K. Wirth

Sure. Why don't I'll put those 2 together, actually. Look, we'll do both build and buy, I think, in new energy. So I would fully expect us to do that in renewable fuels. We have built a business, but then we also went out and acquired Renewable Energy Group.
So I think you'll see both. Certainly, the Denbury transaction is one that the market somewhat anticipated and you can presume that multiple market players probably took a look at or had conversations with Denbury. For us, like in CCUS, we look for areas that have good geology or poor space. They're near concentrated emissions and have the right policy support to enable a business. The Gulf Coast has all of these things. And while you've been, we've got about 140,000 acres of permanent CO2 sports -- core space, both onshore and offshore. We've got storage potential there of greater than 1 billion metric tons. In the second half of this year, we're going to drill a strat well in the offshore acreage to further delineate and characterize the subsurface. In the first part of next year, we expect to drill a strat well in the onshore acreage and do the same.
And of course, we're in conversations with a number of customers in that region in the Golden Triangle, up at Mont Belvieu all the way across the Houston ship channel, and we've got term sheets going back and forth. We're in negotiations with a number of different potential customers. The commercial framework for this is still evolving. And we're working on the other pieces you need. So classic well-injection permits and midstream assets. We've got an RFP out right now with a number of midstream providers consistent with the way we have generally approached the midstream. We own assets if they're strategic. If there's a way for us to go to somebody who is in the business of operating -- building and operating midstream infrastructure, we certainly look at that as well.
So we're putting all the pieces together there for a phased development. We like the Bayou Bend project, and we'll report more. But to your kind of underlying question, we'll build organically, and we'll do inorganic where it makes sense.

Operator

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

Biraj Borkhataria

Pierre, best of luck with retirement. My first one is on portfolio concentrations. At your Analyst Day, you talked about just over $20 billion of free cash flow at $60 a barrel and looking through today's slides, roughly half of that in the medium term will come from the Permian plus TCO. So I understand you want every dollar to go to the highest level of return, which is completely sensible.
But I was wondering if you can talk about portfolio concentration because it is quite unusual for a super major to have that level of concentration in terms of free cash flow. So how do you think about portfolio diversity? And is this something you're actively trying to address going forward? And I've got a follow-up on a different topic.

Michael K. Wirth

Yes, Biraj, if you look back over the last decade, we've cleaned up our portfolio. We had a lot of assets that were kind of at the smaller end of the tail that pulled capital and management time and resources. And we want to be diversified. We've got a diverse portfolio, but we don't need to be diversified just for the sake of it. We want to have assets that have scale and are material and long lived.
You can start in the Far East and look at our LNG positions in Australia, which aren't drawing a lot of capital right now, but are throwing off a lot of cash. We've got a strong position in West Africa that we strengthened with the Noble acquisition and the EG assets that can feed LNG into Europe. Obviously, you mentioned TCO. The Eastern Med is a very strong position. We've recently taken FID and are working on expansion projects for Tamar, Leviathan, and have submitted a concept on Aphrodite. So there's a lot of opportunity in that asset.
When we close PDC, we're going to be producing 400,000 barrels a day in the DJ Basin. We've talked about some of our other shale and tight assets in Argentina. In Canada, we've got 2 crackers underway in CPChem. It will come online middle of this decade, 1 in the U.S. 1 in the Middle East.
We've acquired REG and are growing our renewable fuels business. So we have exposure across a large portfolio and then, of course, we also have projects coming online in the Gulf of Mexico. I mentioned Anchor earlier, Whale, Ballymore and we recently acquired more leases in this recent lease sale than the -- twice as many leases as in the biggest lease sale over the last 8 years. So we're adding to our position in the Gulf of Mexico. So this idea that we're a 2-asset company, the Permian and TCO, I don't think really stands up to careful inspection. They are 2 great assets. And so they get a lot of attention, but we've got a lot of other strong assets in our portfolio.

Pierre R. Breber

If I can just build off that and go to the return of capital question that Neil asked and that's what gives us confidence not only on the buyback, but on the track record of dividend growth. So we guided to 10% annual free cash flow coming from all of those businesses.
Some are holding cash constant. Some are growing cash flow that Mike covered, and that goes to leading dividend growth, where we've grown the dividend over the last 5 years at rates double our closest peer and much higher than others and where we have a buyback that is nearly 6% of our shares outstanding annually.
Our business is built for $50. So part of the confidence in our ability currently, if you look at our breakeven and adjust for working capital this quarter, if you look at the last 4 quarters, it's actually probably a little bit lower than that with the strong refining margins that we've been seeing.
So we're built for lower prices. Free cash flow is going to grow from this space. That should give investors confidence in our ability to continue to grow the dividend at leading rates and to maintain buybacks at also very high rates.

Biraj Borkhataria

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

Michael K. Wirth

Yes. I mean, it's consistent with what we've described earlier, and I think you've captured it. It depends on the circumstance in places where we've got remote gas where you need to be in the entire value chain, and you can create an economic model that supports the investments, we've done that. In other locations where you've got other people that will put capital into the midstream assets and we can sell gas into that. We can offtake gas off of it, but not participate in some of the very capital-intensive and lower return portions of the value chain, that's certainly a model that helps us support our aspiration to drive higher returns.
Now you have to have good partners. You have to have reliable operations, and we'll work closely with the companies that we have offtake with. We vet them carefully, and we -- we have confidence in the people that we are working with to provide those reliable operations. But we're really looking to drive high returns, not necessarily to own assets for the sake of control, unless it creates a differentiated value proposition.

Operator

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

Sam Jeffrey Margolin

Question.

Michael K. Wirth

Sam, you're breaking up.

Sam Jeffrey Margolin

The question's on the cash balance, it looks like, nominally, it's drawn down, but it feels -- there's some inputs that would theoretically help it rebuild in the second half, you've got working capital, and I think TCO is going to pay a dividend in third quarter and PDC had a very front-loaded capital program too. So that's coming on with free cash. So just wondering about the cash balance and how you think about the level or if we're going to be in a rebuild phase for 2H?

Pierre R. Breber

Well, the direction that it goes depends, of course, on commodity prices and margins and a number of other factors. You're right, our cash levels have come down in part due to working capital outflows, timing of affiliate dividends. And we've also paid down some debt. We've been, I think, very clear that we don't want to hold surplus cash, certainly not permanently that it's where the cash goes in the short term. But over time, that cash is going to be returned to our shareholders in the form of this growing dividend and ratable buyback program. So we need only about $5 billion to support our operations. We are nearly $10 billion at the end of the second quarter. So that's more than sufficient.
We have access to lots of liquidity. We don't have any commercial paper now again, we've been paying down debt. So that's the more economically efficient way to manage the balance sheet if we get there and whether the cash balance goes up or down again, depends on all the inputs and outputs that we've been showing.
We're guiding towards the net debt, as Mike said, the net debt is well below the low end of our guidance range. So we look at all those factors. And again, if cash balances head down to $5 billion, that will be adequate to cover the operations.
On working capital, our pattern in the second half of the year is that we tend to see some draws on it. But we're certainly not going to recover from what we see in this first half of the year. A big portion of what we saw in the first half of this year on working capital are really tax payments tied to earnings last year. So you can kind of think of those as being offset from last year where we had -- where we had that a favorable working capital environment. So there'll be ups and downs along the way. Over time, working capital tends to average out over 0, but these are just timing effects. We look through them. We knew we were -- had taxes due. And so that's all part of the planning as we look at the balance sheet.

Jake Spiering

And Sam, I guess that we've guided to a TCO dividend in the fourth quarter. We do not expect a dividend in the third quarter.

Sam Jeffrey Margolin

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

Michael K. Wirth

Yes, Sam. So I think your question started with people and ended up kind of at our kind of investment priorities in new energies. Look, across the entire leadership team. We've got a commitment to driving higher returns and lower carbon and people move through different kinds of roles, but this is part of every role in the company today. So it's a part of the business. It's something we're committed to.
Our focus is, as we've said before, it's on things where we can leverage our unique capabilities, assets, value chains, customers to create sustainable competitive advantage in these new energy businesses. It's why we've not gone into wind and solar on a merchant basis because there's others that can do that, and we don't really bring anything unique there.
Our renewable fuels business today is profitable and generating cash. We expect to start up the Geismar expansion and be producing more renewable diesel next year. So that's a business today that is economic and attractive, and we continue to grow, particularly back into the feedstock side. We announced an acquisition this last quarter of a small company that's got some interesting feedstock technology.
Carbon capture and storage obviously is being built. We do it today in some assets. But as a business, we're building out Bayou Bend I talked about. We're working on projects in other parts of the world as well. And we do believe that with the right technology, the right business model and policy environment that there's an opportunity there.
Other things that we're working on hydrogen is one that both electrolytic hydrogen and then traditional hydrogen paired with carbon capture and storage. In the U.S., the IRA incentives can certainly support the development of business models there.
So I think we'll stay consistent with this. We're looking at it -- always looking at new technologies, but the area we're focused on is the primary area you should expect to see us investing.

Operator

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

Jason Daniel Gabelman

Pierre, congrats on your retirement. I'd like to go back to the Permian detail for a minute, if I could, and kind of 2 questions on this. First, has CapEx in the Permian deviated at all from that $4 billion budget that you highlighted at the Analyst Day? And then the second part, on the Permian inventory over the 5-year plan and long term, how much -- what percentage of those locations would you categorize as (inaudible) ?

Michael K. Wirth

Yes, Jason. Permian CapEx is up a little bit this year, primarily 3 things. Number one, we've actually seen drilling performance continue to improve and completions performance continue to improve. So out of the same fleet of rigs and completion spreads, we're getting more work done, which means you consume more tubulars, more sand, more water, et cetera. So that's kind of a good thing.
We're seeing some longer lead times on some of the critical elements in facilities. And so we've actually had to make some long lead purchases for next year's program that we didn't anticipate as we were lining up this year's program. And then we've increased facility scope for water handling in some areas of the Permian, particularly as we're trying to manage some of these induced seismicity issues. We're being more careful, moving more water. And so that has all led to some increase in CapEx.
Not a lot of inflation there. The inflation has been largely in line with what we had expected, and the rig fleet is being activated in line with what we expected.
Your second question on inventory, we don't really -- we haven't broken our portfolio into tiers. There's not a very clear definition of that in a way to kind of do that on a standard basis. So when we've outlined the drilling locations and the long-term guidance there, it's really based on economics. And we've got locations that are economic at our price view for the future, which has historically not been a super aggressive price view. It's based on today's technology. And as indicated, we've got more than 6,000 locations in that outer time window that are economic based on those assumptions. By the time we get to that window, we may or may not see a different price environment. I fully expect we'll see a different technology environment, which can allow that number to grow even further. So -- we look at it more in terms of the economics of the development than tiers.

Jason Daniel Gabelman

Great. And my follow-up, just going back to TCO. You made some comments on kind of maintenance effects over the next 4 quarters. And I know you showed it graphically. But are you able to quantify the actual impact to production over the next 4 quarters from all these turnarounds and start-up activities?

Pierre R. Breber

Well, Jason, we do it quarterly, like it's included in the third quarter guidance that we provided, and we'll continue to do that quarterly, and you're seeing it sort of annually, we're giving annual guidance on TCO. So it's all embedded in there. I think we showed it relative to '22, but there's just a lot of moving parts, but we'll continue to give that guidance each quarter and you have annual guidance that incorporates all of that.

Operator

We'll take our next question from Irene Himona with Societe Generale.

Irene Himona

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

Michael K. Wirth

Yes. So the chemicals business is cyclical, as everybody knows. We're certainly in a period now where we're seeing some length in supply due to new build facilities, some -- so there's some length there is weighed on margins in the olefins chain. And in the short term, we think we're going to continue to see that would be a pretty tough sector.
Longer term, as you get out to mid-decade and beyond, demand will continue to grow, and we expect demand and supply will come into better balance, and we'll see those margins recover out towards the middle and second part of this decade.
Your second question -- I'm sorry, I was thinking about chemicals there and...

Irene Himona

Or the refining that refining outlook...

Michael K. Wirth

Refining margins, yes. Certainly, we've seen refining margins come off the very strong levels that they were at last year. There's been some new capacity come into the system around the world, some big new refineries that have begun to start up or major projects that have come online. And so margins have softened year-on-year. .
Certainly, the West Coast in our portfolio is important, West Coast margins, both in the refining and the marketing part of the value chain have held up a little bit better because it's a market that is a little bit more cut off from the rest of the world than the Gulf Coast or Asia. And so demand continues to be pretty strong out there.
Gasoline demand is strong. Jet demand continues to come back. Diesel demand has maybe flattened out a little bit, but certainly holding. And so -- we're in an environment where I would expect the inventories are towards the lower end of the products in a number of parts of the world. I think refining margins for the second half of this year will be -- are likely to be as good as they were in the first half of the year at least.

Irene Himona

Am I allowed a follow-up? Sorry.

Michael K. Wirth

Yes, just go ahead.

Irene Himona

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

Michael K. Wirth

Yes. No, we continue to evaluate other options. In fact, we're working towards a concept select for the next expansion of Leviathan ideally at the end of this year. And floating LNG is one of the concepts that we continue to look at.

Operator

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

Ryan M. Todd

Great. Maybe if I could follow-up on some earlier Permian conversations. You talked a little bit about some of the New Mexico well performance. But on well performance overall that you disclosed, it appears that first half results are showing improved performance across much of the basin as you expected.
What have you seen to date in terms of addressing -- I know you don't have a lot of data -- but in terms of addressing some of the concerns from last year, particularly what have you learned regarding spacing, single versus multi-bench approach, et cetera, on the wells that you've done so far this year?

Michael K. Wirth

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

Ryan M. Todd

Okay. And maybe if we turn to the Gulf of Mexico, as we think about your Gulf of Mexico Deepwater portfolio, you've got an impressive string of project start-ups coming over the next few years. How exposed are you to escalating trends in Deepwater drilling and development costs as you look across those projects? Do you have costs locked in across some of those projects, rigs under multiyear contracts, et cetera? Or is this I guess, how much are you able to mitigate cost escalation as we think over kind of CapEx requirements over the next few years?

Pierre R. Breber

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

Michael K. Wirth

We came into the year with 3 rigs under contracts that were contracted back in a different environment. .
Okay. We've got a handful of people still in the queue.

Operator

We'll go next to Paul Cheng with Scotiabank.

Paul Cheng

First one is wish Pierre an exciting and very happy post retirement. Thank you for the help over the past 20-plus years. Maybe the 2 questions, if I could. One, you're talking about your development plan in sites discovery. Can you give us a little bit in terms of the timeline, what should we expect? And also that what is the preliminary design of the development is going to look like in the scale and what kind of time that is going to see the first oil?
The second question that you haven't talked much about Argentina and over there, the government seems to be pretty excited with the shale oil development and you have a position there. Can you give us an update what is your thinking over there?

Michael K. Wirth

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

Operator

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

Douglas George Blyth Leggate

Pierre, it's been a pleasure. Congratulations and good luck to everybody. And Mike to you as well on your extended tenure. Guys, my first question is on the Permian ratability. It looks like you've got about a couple of hundred POPs this year, wells to sales. 2,000 over the next 5 years. Is that ratable? How should we think about step up in activity?

Pierre R. Breber

Just one thing, it's the co-op POPs is 200. But if you were to include net POPs, again, half of our portfolio is non-open royalty, it'd be more like 300. So it looks more consistent, right, the long-term plateau and the well inventory, the 2,200 over the next 5 years incorporates all of the activity and the POP data was just on company operate. So there is some increase, but not as not as large as it looks. You just got to get apples-to-apples.

Douglas George Blyth Leggate

It'd fairly ratable, Pierre, I mean, like 500 a year type of deal or 400 a year type of deal?

Pierre R. Breber

Yes. As we get up to activity and as Mike said, we're becoming more efficient, as our other operators that we work with, yes, it's going to be pretty ratable once we get full up to our full rate activity.

Michael K. Wirth

Yes. Of course, Doug, quarter-to-quarter, there's some variability as we saw first quarter to second quarter of this year. Third quarter is going to be a little -- so there can be some surges in plateaus quarter-to-quarter, but on an annual basis, yes, it's going to be pretty ratable.

Douglas George Blyth Leggate

That's helpful. My follow-up guys is on Tengiz, but it's a slightly different question. I guess Pioneer is similar vintage. You signed Tengiz in 1993. It expires 6 years after the end of your Analyst Day trajectory through 2027, it's 1/4 of your free cash flow. So my question is, what are your options there, whether we extend or replace and perhaps maybe some color on what the production profile looks like post 2027, Wood Mac is going into fairly severe decline after 2030. So I just want to know what you're thinking about the long-term sustainability of those free cash flows?

Michael K. Wirth

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

Operator

Our last question comes from Roger Read with Wells Fargo.

Roger David Read

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

Michael K. Wirth

Well, Roger, it's been a pretty turbulent first part of my tenure with a major restructuring, of pandemic and oil prices that collapsed, a war and oil prices that spiked, the political and geopolitical noise that comes with those things, the ongoing climate and ESG issues, 3 acquisitions, one of which we still haven't closed. And so I'm actually looking forward to a little smoother water, I hope, one day.
And look, we still have work to do to continue to drive higher returns and lower carbon. And so it's to continue that work. We've got good momentum in our business. We've delivered strong results through all of that turbulence and have maintained strong shareholder distributions throughout and strategic consistency throughout where we've seen others in the industry buffeted it around a little bit by these forces. And so I'd like to continue that and to drive more value to our shareholders and higher returns and lower carbon.

Roger David Read

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

Pierre R. Breber

Roger, our view that -- not quite picked that up. So why don't you follow up with Jake after the call and make sure we understand your questions and give you our best take on it. But our oil realizations have looked good and our natural gas realizations have looked strong. We had a little more -- we had better timing in the first quarter. So if you look quarter-on-quarter in some of our international gas, it might seem a little weaker. But I'm not sure on liquids. So please follow up with Jake.

Jake Spiering

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

Operator

Thank you. This concludes Chevron's Second Quarter 2023 Earnings Conference Call. You may now disconnect.