Chevron Corporation (NYSE:CVX) Q2 2023 Earnings Call Transcript July 28, 2023

Chevron Corporation beats earnings expectations. Reported EPS is $5.82, expectations were $2.97.

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 question-and-answer session and instructions will be given at that time. [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 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: 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 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-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 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 POP an additional 30 wells 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 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 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 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 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 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 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 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 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. Back to you, Jake.

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Jake Spiering : 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.

Q&A Session

Operator: Our first question comes from John Royall with J.P. Morgan.

John Royall: 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 well end?

Michael Wirth: 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 of, 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: 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: 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 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 POPs in the second half of this year, so that the bulk of the program is not representative of those curve. And there’s a couple of other things, one that 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’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.

Operator: We’ll go next to Devin McDermott with Morgan Stanley.

Devin McDermott: 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: 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. 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 McDermott: 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.