Earnings Call Transcript
CHEVRON CORP (CVX)
Earnings Call Transcript - CVX Q2 2023
Operator, 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. At this time, all participants are in a listen-only mode. After the speakers' remarks, there will be a question-and-answer session, and instructions will be provided at that time. As a reminder, this conference call is being recorded. I will now turn the conference call over to the General Manager of Investor Relations of Chevron Corporation, Mr. Jake Spiering. Please go ahead.
Jake Spiering, General Manager of Investor Relations
Thank you, Katie. Welcome to Chevron's second quarter 2023 earnings conference call and webcast. I'm Jake Spiering, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. Please review the cautionary statement on slide 2. Now, I will turn it over to Mike.
Michael Wirth, CEO
Thank you, 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 a return on capital employed greater than 12% for the eighth consecutive quarter and another quarterly record in shareholder distributions of more than $7 billion. At TCO, we're making good progress with commissioning and pre-startup 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 schedule 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 three areas, is consistent with our plans. In New Mexico, we've put on production at 10 wells. Before year-end, we expect to put an additional 30 wells into production with higher expected production rates. As a reminder, about half of Chevron's Permian production is company operated, with the balance 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 that is expected to deliver decades of high-return production. Over the next five years, we expect to develop over 2,200 net new wells, growing production while delivering a 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 the 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 at 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 Mediterranean, 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 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.
Pierre Breber, CFO
As Mike said, strong, consistent financial performance enabled Chevron to return record cash to shareholders this quarter, while also investing within our CapEx budget and paying down debt. Working capital lowered cash flow primarily due to true-up tax payments outside the US. Excluding tax payments, working capital movements are variable. Our typical pattern in the second half of the year is to draw down working capital. Chevron's net debt ratio ended the quarter at 7%, significantly below the low end of our guidance range. Surplus cash on the balance sheet was reduced during the quarter, with cash balances ending at $9.6 billion, well above the cash required to run the company. Adjusted second quarter earnings were down $5.6 billion versus the same quarter last year. Adjusted Upstream earnings were lower mainly due to realizations, partly offset by higher liftings. Other includes primarily favorable tax items and income from Venezuela non-equity investments. Adjusted Downstream earnings decreased primarily due to lower refining margins. OpEx was up mainly due to higher transportation costs and the inclusion of REG. Compared with last quarter, adjusted earnings were down $900 million. Adjusted Upstream earnings decreased primarily due to lower realizations. This was partially offset by higher production in the US and non-recurring tax benefits. Adjusted Downstream earnings were down modestly; lower margins were partially offset by higher volumes. Second quarter oil equivalent production was down about 20,000 barrels per day from last quarter, primarily due to planned turnarounds at Gorgon and in the Gulf of Mexico and downtime associated with the Canadian wildfires. This was mostly offset by growth in the Permian. Now, looking ahead, in the third quarter, we have a planned turnaround at TCO and a planned pitstop at Gorgon, completed earlier this week. Our full-year production outlook is trending near the low end of the annual guidance range. Since PDC's proxy solicitation on July 7th, we've not been permitted to buy back our shares. After we close the acquisition in August, we plan to resume buybacks at the $17.5 billion annual rate, which we expect to continue through the fourth quarter. We do not expect a dividend from TCO until the fourth quarter. Full-year affiliate dividends are expected to be near the low end of our guidance. Putting it all together, we delivered another quarter with solid financial results, strong project execution, and continued return of cash to shareholders. Our approach is consistent, and you can see that in our actions and results.
Jake Spiering, General Manager of Investor Relations
That concludes our prepared remarks. We are now ready to take your questions. Please limit yourself to one question and one follow-up. We will do our best to get all your questions answered. Katie, please open the lines.
John Royall, Analyst
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? Sounds like the Permian is on plan. So what pieces have come in below the midpoint of plan to move you to that low end?
Michael Wirth, CEO
Guidance remains unchanged. We expect to be at the lower end of that. And as we said, Permian production has been strong. The things that Pierre mentioned, I think, are the key things that we've seen. There's been some impact of fires in Canada that have impacted our ability, not really our operations per se, we did some evacuations on a precautionary basis, but it was midstream and processing downtime that we weren't able to move our production to market. And the rest of it is – oh, and Benchamas too, I guess, is the other one. We have an FPSO in Thailand that had an incident and early in the year was taken off station. And so that's another 10,000 or 11,000 barrels a day net, which is off for the foreseeable future. And so, it's really those two things are the ones that are pushing us down that were both unexpected.
John Royall, Analyst
My next question is just sticking to production, but just drilling in a bit on the Permian. The well results generally look very strong in the first half, but still a bit below 2022 in New Mexico. Maybe you can just update us on what innings you think you're in just in terms of optimizing the single bench developments in New Mexico?
Michael Wirth, CEO
The important point to bear in mind is that New Mexico type curve we showed, there are only 10 new well completions represented or 10 wells that we achieved all in the second quarter there. So there's no first quarter completions. And there's only seven that actually had enough data to make it into the curve you see on the chart. So it's a very thin set of data. We expect 30 more wells to come online in the second half of this year, so the bulk of the program is not representative of that curve. And there are a couple of other things. One is that the wells we did complete 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 New Mexico where we expect higher productivity. So, it's a combination of things. But I'd caution you not to over-index on a very thin dataset with a lot more data to come in the second half of the year.
Devin McDermott, Analyst
I wanted to just stick with the Permian since we're on that topic. I was wondering if you could talk a little bit just around the mix trend that you're seeing there. And if we disaggregate the productivity a little bit further, you talk about how much of the uplift is coming from gas and NGLs versus oil. And then similarly, as you progress towards your longer-term production goals, how you expect the mix in the basin for you to trend oil, gas, NGLs over time.
Michael Wirth, CEO
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 the returns. And the gas/oil ratio in aggregate has been relatively flat for a number of years. 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 McDermott, Analyst
I wanted to shift over to TCO. Good to hear the continued positive progress there as we get closer to the finish line. There's a lot of moving pieces over the next year, year and a half as we get the two phases of development online. You give the guidance for the turnaround impact in 3Q. I was wanting to talk a little bit more about how you see the evolution of production into the fourth quarter of this year and then through 2024, as we get to that 2025 run rate. So, shape it a bit for us as we look out over the next few quarters.
Michael Wirth, CEO
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 two-thirds complete. In the second quarter, we achieved mechanical completion of the three gas injection facilities and got fuel gas into the flare system, which is very important to enable an on-time startup of the Future Growth Project. In the quarter that we're in now, the third quarter, we expect full mechanical completion of the Future Growth Project. Also, a turnaround at one of the Komplex Technology Lines will begin, and a lot of work will start up on utility systems, boilers, steam systems, and other utilities that are required for the startup of the pressure boost facility, which is the key driver of WPMP, enabling us to convert from high pressure to low pressure across the field. Once that turnaround is done in the third quarter, you will see some production impact. We expect to have two of the four big pressure boost compressors online, which allows us to begin the conversion of metering stations from high pressure to low pressure. This conversion is anticipated to take 10 to 12 months. There will be turnarounds next year as well, two more turnarounds, one at SGI and another one in one of the KTLs. All of that is part of a very carefully choreographed sequencing of turnarounds and startup activity that will allow us to bring full field production to 1 million barrels a day for 2025. What you're going to see in 2023 and 2024 is normal turnaround activity interlaced with all of this project startup activity. This is not as simple as bringing on a new portion of the field. We're 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.
Jake Spiering, General Manager of Investor Relations
Slide 10 from our set has annual production, 2023, 2024, 2025. Yeah, no change in that guidance.
Neil Mehta, Analyst
I want to stay on TCO. And while there will be a volume inflection in 2025, there's probably going to be a free cash flow inflection in 2024, just as affiliate CapEx rolls off first. Can you talk about the cadence of that and how it manifests itself in terms of dividends?
Pierre Breber, CFO
Yeah, we've been guiding to the clean year because that's the $5 billion of free cash flow, $60 Brent in 2025. And, of course, we're guiding to 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. The profile of those loans are disclosed in our SEC filings. Exactly to your point, you'll see a build towards that just as the CapEx has rolled off. It was 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, are commodity prices, and those vary. As we've said, TCO continues to be conservative in managing its balance sheet, 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 a year and a half, we expect some of that cash to come on. 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. We expect to see a release of some of that surplus cash that's been held on the balance sheet. That will continue over the next couple of years as we head into that $5 billion of free cash flow in 2025. Maybe the last thing, Neil, you know that TCO has really good price sensitivity. I've seen yours and other estimates, at 70% or 80%, the cash flow is even stronger.
Neil Mehta, Analyst
The follow-up is just on the return of capital. I think while you have a big buyback range, a lot of market participants have viewed your $17.5 billion dollars as the P50 outcome in any reasonable commodity price environment. And so, thinking less of it like a flywheel and more as a relatively fixed number unless commodity prices go wacky. Any thoughts on that statement and whether you're trying to give us a little more surety around that number as opposed to a more volatile number?
Pierre Breber, CFO
The range, Neil, is tied to the upside and downside cases that we showed at our Investor Day. 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. As a reminder, the downside case gets to $50 in a couple of years and stays there for three years. That is a real downside case, and that is 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 five-year period, trending down to $70 towards the end of that period. That's why you're seeing a buyback very close to the top end of the range at the $17.5 billion dollars. 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 don't want to be procyclical. We're trying to be consistent across the cycle. 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 Wirth, CEO
Neil, I would just add, you see in our second quarter results that our net debt remains very, very low. 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.
Steven Richardson, Analyst
Mike, I was wondering if you could talk a little bit about new energies. I think you've been clear from the beginning that build versus buy was part of the consideration in a lot of these businesses. We saw a big CO2 pipeline and EUR company transact recently. So maybe you can talk a little bit about the CCUS business as you view it and why build versus buy is maybe the better choice for Chevron? Maybe I should get ahead of it with a follow-up as maybe you could give us a little bit of an update on Bayou Bend, please?
Michael Wirth, CEO
I'll put those two together actually. Look, we'll do both build and buy, I think, in new energies. 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. You can presume that multiple market players probably took a look at or had conversations with Denbury. For us, in CCUS, we look for areas that have good geology or pore space, are near concentrated emissions, and have the right policy support to enable a business. The Gulf Coast has all of these things. At Bayou Bend, we've got about 140,000 acres of permanent CO2 pore space, both onshore and offshore. We have 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. We're currently in conversations with a number of customers in that region, and we’ve got term sheets going back and forth. The commercial framework for this is still evolving. We are working on the other pieces you need; for example, well injection permits and midstream assets. We have an RFP out right now, with a number of midstream providers, consistent with how 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's in the business of building and operating midstream infrastructure, we will certainly look at that as well. We are putting all the pieces together there for a phased development. We like the Bayou Bend project and will report more. But to your kind of underlying question, we'll build organically and we'll do inorganic where it makes sense.
Biraj Borkhataria, Analyst
My first one is on portfolio concentration. So at your Analyst Day, you talked about just over $20 billion of free cash flow at $60 a barrel. Looking through today's slides, roughly half of that in the medium term will come from the Permian plus TCO. I understand that you want every dollar to go to the highest level of return, which is completely sensible, but could you talk about portfolio concentration? It is quite unusual for a supermajor to have that level of concentration in terms of free cash flow. How do you think about portfolio diversity? Is this something you're actively trying to address going forward? I have a follow-up on a different topic.
Michael Wirth, CEO
Biraj, if you look back over the last decade, we’ve cleaned up our portfolio. We had a lot of assets that were at the smaller end of the tail that pulled capital and management time and resources. We want to be diversified. We’ve got a diverse portfolio. But we don’t need to be diversified just for the sake of it. We want to have assets that have scale, that are material and long-lived. You can start in the Far East and look at our LNG positions in Australia, which aren't drawing a lot of capital right now. We have a recent acquisition in the EG assets that can feed LNG into Europe. Obviously, you mentioned TCO. The Eastern Mediterranean is a very strong position. We've recently taken FID and are working on expansion projects for tomorrow, Leviathan, and have submitted a concept on Aphrodite. There are many opportunities in that asset. When we close PDC, we will be producing 400,000 barrels a day in the DJ Basin. We've talked about our other shale and tight assets in Argentina, in Canada. We have two crackers underway in CPChem that will come online in the middle of this decade, one in the US and one in the Middle East. We’ve acquired REG and are growing our renewable fuels business. So we have exposure across a large portfolio. And then, of course, we also have projects coming online in the Gulf of Mexico. I mentioned Anchor earlier, as well as Whale and Ballymore. We recently acquired more leases in this recent lease sale than the twice as many leases as in the biggest lease sale over the last eight years. We are adding to our position in the Gulf of Mexico. So this idea that we are a two-asset company, the Permian and TCO, I don't think really stands up to careful inspection. They're two great assets, and get a lot of attention, but we have many other solid assets in our portfolio.
Pierre Breber, CFO
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. We guided to 10% annual free cash flow coming from all those businesses. Some are holding cash constant, while some are growing cash flow that Mike covered. This leads to our dividend growth, which we've increased over the last five years at rates double our closest peer and much higher than others, along with 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 four quarters, it's probably a little bit lower than that with the strong refining margins we have been seeing. Free cash flow is going to grow from this base, which 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, Analyst
Just following up on a different question. Through the Permian, you'll be producing a lot more gas over time, and you've expressed a desire to grow in LNG. You've signed a couple of deals as an offtaker to synthetically integrate your US gas position to global markets. I wanted to ask about whether you'd be interested in owning liquefaction or if you feel being an offtaker is enough. Some of your peers have argued the benefits of integration and owning through the value chain. However, I think in the past you've noted that the returns are typically lower. I’m particularly interested in this now, as a number of players have signed offtake agreements with companies such as Venture Global, and then they’re not receiving the gas as agreed. So, it's interesting how you're thinking about that value chain in LNG.
Michael Wirth, CEO
It's consistent with what we've described earlier, and I think you've captured it. It depends on the circumstance. In places where you've got remote gas that requires you to be in the entire value chain and you can create an economic model that supports the investments, we would do that. In other locations, where you have other capital in the midstream assets, 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. You have to have good partners, you must have reliable operations, and we'll work closely with the companies that we have offtake with. We vet them carefully and we have confidence in the people that we're working with to provide those reliable operations, but we're looking to drive high returns, not necessarily to own assets for the sake of control unless it creates a differentiated value proposition.
Sam Margolin, Analyst
The question is on the cash balance. It looks like nominally, it's drawn down, but it feels like there are 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 the third quarter. PDC had a very front-loaded capital program too; that's coming on with free cash flow. 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 the second half?
Pierre Breber, CFO
The direction that it goes depends, of course, on commodity prices and margins and other factors. You're right, our cash levels have come down, in part due to working capital outflows, timing of affiliate dividends. We've also paid down some debt. We've been very clear that we don't want to hold surplus cash, certainly not permanently; that'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. We need only about $5 billion to support our operations. We're nearly $10 billion at the end of the second quarter, which is more than sufficient. We have access to a lot of liquidity. We don't have any commercial paper now. Again, we've been paying down debt. This is the more economically efficient way to manage the balance sheet. 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. We look at all those factors. If cash balances head down to $5 billion, that'll be adequate to cover operations. On working capital, our pattern in the second half of the year is that we tend to see some draws on it. We're not going to recover from what we've seen in the first half of the year. A significant portion of what we saw in the first half of this year on working capital are tax payments tied to earnings from last year. You can think of those as akin to being offset from last year where we had that favorable working capital environment. There will be ups and downs along the way. Over time, working capital tends to average out over zero. But these are just timing effects. We look through them. We knew we had taxes due. That is all part of the planning as we look at the balance sheet.
Jake Spiering, General Manager of Investor Relations
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 Margolin, Analyst
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. Pierre had spent some time in an ESG role and the low carbon role. 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. 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. As we 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 pivot? I think that ties into carbon capture too, because that seems like a place where the incentives are pretty transparent.
Michael Wirth, CEO
I think your question started with people and ended up at our kind of investment priorities in new energies. Our entire leadership team is committed 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. It's a commitment we make. 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 and competitive advantage in these new energy businesses. It's why we haven’t gone into wind and solar on a merchant basis because others can do that and we don't want to bring anything unique there. Our renewable fuels business today is profitable and generating cash. We expect to start up the Geismar expansion and produce more renewable diesel next year. That business is currently economic and attractive as we continue to grow, particularly back into the feedstock side. We announced an acquisition last quarter of a small company that's got some interesting feedstock technology. Carbon capture and storage is being built. We aim to continue doing it today across various assets. We're expanding it through Bayou Bend. I discussed our work on projects in other parts of the world as well. We believe, with the right technology, business model, and policy environments, there is an opportunity there. Other things we are working on include hydrogen, both electrolytic hydrogen and traditional hydrogen paired with carbon capture and storage. In the US, the IRA incentives can certainly support the development of business models there. I think we'll stay consistent with this. We're always looking at new technologies, but the area we focused on is the primary area you should expect to see us investing.
Jason Gabelman, Analyst
I'd like to go back to the Permian detail for a minute, if I could, and kind of two 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 the second part, on the Permian inventory over the five-year plan and long term, what percentage of those locations would you categorize as tier one?
Michael Wirth, CEO
Jason, Permian CapEx is up a little bit this year. Primarily, three things. Number one, we've actually seen our drilling performance continue to improve, and completions performance continue to improve. So out of the same fleet of rigs and completion spreads, we're getting more work done, which means you consume more tubulars, sands, water, etc. So, that's a positive development. We're seeing some longer lead times on critical elements in facilities, and hence, we had to make some long lead purchases for next year's program that we didn't anticipate while lining up this year's program. Also, we've increased the 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 increasingly careful about removing more water, which has led to an increase in CapEx. There isn't a lot of inflation there; it has been largely in line with what we expected, and the rig fleet is being activated in line with the expectations. Your second question on inventory: we haven't broken our portfolio into tiers. There's no clear definition to categorize that on a standard basis. When we've outlined the drilling locations and long-term guidance, it's based on economics. We've got locations that are economic at our future price perspective. By the time we reach that point, we may or may not see a change in the price environment; I fully expect to see a different technology environment, which could allow that number to grow even further. So, we look at it more in terms of the overall economics rather than by tiers.
Jason Gabelman, Analyst
My follow-up, just going back to TCO, you made some comments on kind of maintenance effects over the next four quarters. I know you showed it graphically, but are you able to quantify the actual impact on our production over the next four quarters from all these turnarounds and startup activities?
Pierre Breber, CFO
Jason, we do it quarterly. It's included in the third quarter guidance that we provided. We'll continue to do that quarterly, and you're seeing sort of annual guidance on TCO, which incorporates all of that.
Irene Himona, Analyst
My first question is on the Downstream, please, if you can talk about the performance of your chemicals affiliates, in particular in Q2, and then what you're seeing so far in the third quarter. Also, what you would expect in terms of refining margin evolution in the second half of the year, given the weakness in Q2.
Michael Wirth, CEO
The chemicals business is cyclical, as everybody knows. We are currently in a period where we are seeing some length in supply due to new build facilities. This has weighed on margins in the olefins chain. In the short term, we think we will continue to see challenges in this sector. Longer term, as we get out to the middle of this decade and beyond, demand will continue to grow and we expect demand and supply will come into better balance, leading to margin recovery towards the middle and later part of this decade. Regarding refining margins, yeah, certainly, we've seen refining margins come off the very strong levels experienced last year. There's been new capacity introduced globally due to some major refineries that recently came online, which has softened margins year-on-year. The West Coast in our portfolio is important; West Coast margins, both in refining and marketing, have held up a bit better because this market is more isolated from the rest of the world compared to the Gulf Coast or Asia. Therefore, demand there continues to be pretty strong. Our gasoline demand is solid. Jet demand is recovering, and while diesel demand has flattened somewhat, it’s still holding. I'm expecting that inventories are towards the lower end of products in several parts of the world. I think refining margins for the second half of this year are likely to be as good as those seen in the first half, at a minimum.
Irene Himona, Analyst
Based on that, following your FID for the pipeline in Israel, is that it for the time being for Leviathan? Or do the partners continue to examine other options like FLNG, for example?
Michael Wirth, CEO
Yes, 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 among the concepts that we are still considering.
Ryan Todd, Analyst
Maybe if I could follow up on some earlier Permian conversations. You talked a little about some of the New Mexico well performance. But regarding overall well performance that you disclosed, it appears that first half results show improved performance across much of the basin, as you expected. What have you seen to date in terms of addressing some. I know you don't have a lot of data here, but I want to know what you've learned regarding spacing, single versus multi-bench approaches, etc., on the wells that you've done so far this year?
Michael Wirth, CEO
The performance aligns really well with our expectations set out at our Investor Day earlier this year, Ryan. There are a couple of things just to remember. I mentioned earlier that, in New Mexico, we faced some infrastructure and third-party constraints, which is applicable to other parts of our portfolio as well. There are factors that may show up on these curves that do not necessarily reflect the geology or the well performance. As we continue to refine our development strategies on well spacing, profit loading, well length, etc., those evolutions will be reflected in those curves. What’s really important is production metrics, which everyone focuses on because it’s popular. However, we focus on optimizing our returns. Factors like fluid mix, EUR, and capital investments are all vital components of what we're optimizing to drive returns. The high-level answer is that performance meets our expectations as we evolve our program.
Ryan Todd, Analyst
As we think about your Gulf of Mexico deepwater portfolio, you have an impressive string of project startups coming up over the next few years. How exposed are you to escalating trends in deepwater drilling and development costs? Looking across those projects, do you have costs locked in across some of those projects, rigs under multi-year contracts, etc.? How much are you able to mitigate cost escalation over the next few years regarding CapEx requirements?
Pierre Breber, CFO
Yeah, those projects were contracted at a different time, so they reflect mostly locked-in rates, as you would expect. Our procurements are well behind us as the projects are pretty far along. For new exploration activities, we may get exposed to higher rig rates, but for our existing major capital projects, most of that cost is locked in.
Michael Wirth, CEO
We came into the year with three rigs under contracts that were arranged back in a different market environment.
Paul Cheng, Analyst
Maybe two questions, if I could. One, you're talking about submitting a development plan in Cyprus discovery? Can you give us a bit more detail regarding the timeline? What should we expect, and what is the preliminary design of the development going to look like? What kind of time frame are we looking at for the first oil?
Michael Wirth, CEO
Paul, in Cyprus, we're pleased with the outcome of the recent appraisal well. We've submitted our development plan to the government for their approval and it involves a capital-efficient way to take the gas to market via subsea tiebacks to existing infrastructure. However, this is all pending government approval. If we get that, we could enter FEED later this year, but it's a bit early to provide timelines for first gas. Regarding Argentina, we remain very positive about the resource there. There’s an election coming up, and the country is facing some macroeconomic challenges. Still, we like the block, particularly our El Trapial area, where we're doing more development work now with increased capital. We'll discuss that at Investor Day and beyond as we're committed to the growth story.
Doug Leggate, Analyst
My first question is on the Permian ratability. It looks like you've got about a couple of hundreds of wells to sales, and 2,000 over the next five years. Is that ratable? How should we think about the step up in activity?
Pierre Breber, CFO
Just one thing, the coop wells are 200, but if you include net wells, again, half of our portfolio is non-operated and royalty, it'd be more like 300. It looks more consistent. The long-term plateau in the well inventory, the 2,200 over the next five years incorporates all of the activity, and the well data was just on company-operated. There is some increase, but not as large as it seems. It’s really an apple-to-apple comparison.
Doug Leggate, Analyst
Are they fairly ratable, Pierre? Like, is it 500 a year or 400 a year type of deal?
Pierre Breber, CFO
As we ramp up activity, and as Mike said, we're becoming more efficient as are other operators we work with. Yeah, it's going to be pretty ratable once we get up to our full activity rate.
Michael Wirth, CEO
Of course, Doug, quarter to quarter, there's some variability, as we saw first quarter to second quarter this year. The third quarter is going to be a little different, so there can be some surges and plateaus quarter to quarter, but on an annual basis, yeah, it's going to be pretty ratable.
Doug Leggate, Analyst
My follow-up, guys, is on Tengiz, but it's a slightly different question. Pierre and I are similar vintages; the same Tengiz in 1993. It expires six years after the end of your Analyst Day trajectory through 2027 and it's a quarter of your free cash flow. So, my question is, what are your options there? Whether it be extended or replaced? Any color on what the production profile looks like post-2027 as it seems to be heading into fairly severe decline after 2030? Just want to know what you're thinking about the long-term sustainability of those free cash flows.
Michael Wirth, CEO
The concession is a decade away. We're focused on delivering the project right now. This is a big, complex asset and project. We will certainly be in discussions with the government regarding potential extension over time. It will reflect what we see in terms of reservoir performance and production opportunities into the future. These concession discussions should create value for both the country and for Chevron, so we've got to find something that works for both parties. We've walked away from concessions, as you've covered extensively, where it didn't work for us, in places like Indonesia and Thailand. We've extended in places like Angola where it did. However, right now, we remain focused on project execution and on delivering FTP.
Roger Read, Analyst
I guess my first question for you: with the extension of your tenure, are you willing to share with us what some of the things you're hoping to accomplish? What are the real opportunities here that you'd like to shepherd through?
Michael Wirth, CEO
Roger, it's been a pretty turbulent first part of my tenure: significant restructuring, a pandemic, and oil prices collapsing. Then, the war caused oil prices to spike, and the political and geopolitical noise that accompanies those events, along with ongoing climate and ESG matters, three acquisitions, one of which we still haven’t closed. I'm actually looking forward to a little smoother waters in the future. We've still got work to do to drive higher returns and lower carbon. It's about continuing that work. We've generated strong results despite all of that turbulence and maintained robust shareholder distributions along with strategic consistency, where we've seen others in the industry buffeted around. I'd like to continue that momentum and create more value for our shareholders while increasing returns and reducing carbon emissions.
Roger Read, Analyst
I commend you for not trying to duck out when things finally look good for at least a short time. My follow-up question is really much more on the modeling front. If we look at your realizations on oil, they were much stronger here in the second quarter. I think that contributed to some of the outperformance. What we saw was a dip in Q1 and an improvement in Q2, sort of back in line with tradition. So, I was just wondering, is that a timing issue, a regional issue, on first quarter, and anything we should be thinking about as we look at your realizations or capture on oil prices going forward?
Pierre Breber, CFO
Roger, we might not have picked that up. Please follow up with Jake after the call to ensure we understand your question. Our oil realizations have been strong, and our natural gas realizations have also been good. We had better timing in the first quarter. If you analyze quarter-on-quarter on some of our international gas, it might seem a bit weaker, but not particularly for liquids. Please follow up with Jake.
Jake Spiering, General Manager of Investor Relations
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, Operator
Thank you. This concludes Chevron's second quarter 2023 earnings conference call. You may now disconnect.