Categories Earnings Call Transcripts, Energy

Chevron Corporation (CVX) Q2 2022 Earnings Call Transcript

CVX Earnings Call - Final Transcript

Chevron Corporation  (NYSE: CVX) Q2 2022 earnings call dated Jul. 29, 2022

Corporate Participants:

Roderick Green — General Manager, Investor Relations

Pierre Breber — Vice President & Chief Financial Officer

Jay Johnson — Executive Vice President, Upstream

Analysts:

Devin McDermott — Morgan Stanley — Analyst

Neil Mehta — Goldman Sachs — Analyst

Jeanine Wai — Barclays — Analyst

Doug Leggate — Bank of America — Analyst

John Royall — JPMorgan — Analyst

Jason Gabelman — Cowen — Analyst

Manav Gupta — Credit Suisse — Analyst

Biraj Borkhataria — RBC — Analyst

Sam Margolin — Wolfe Research — Analyst

Irene Himona — Societe General — Analyst

Paul Cheng — Scotiabank — Analyst

Ryan Todd — Piper Sandler — Analyst

Presentation:

Operator

Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron’s Second Quarter 2022 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.

I will now turn the conference over to the General Manager of Investor Relations of Chevron Corporation, Mr. Roderick Green. Please go ahead.

Roderick Green — General Manager, Investor Relations

Thank you, Katie. Welcome to Chevron’s Second Quarter 2022 Earnings Conference Call and Webcast.

I’m Roderick Green, GM of Investor Relations. Our CFO, Pierre Breber; and EVP of Upstream, Jay Johnson, 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 get started, 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 Pierre.

Pierre Breber — Vice President & Chief Financial Officer

Thank you, Roderick, and thanks, everyone, for joining us today.

We delivered another strong quarter, another quarter of strong financial results with ROCE over 25%, the highest since 2008. Special items this quarter include asset sale gains of $200 million and a $600 million charge to terminate early a long-term LNG regas contract at Sabine Pass. C&E for the quarter was nearly $4 billion, including inorganic spend to form our JV with Bunge. With the acquisition of REG, our total investment was $6.8 billion, more than double last year’s quarter. Strong cash flow enabled us to fund this higher level of investment, pay down debt for the fifth consecutive quarter and returned more than $5 billion to our shareholders through dividends and buybacks.

Adjusted second quarter earnings were up more than $8 billion versus last year. Adjusted Upstream earnings increased mainly on higher realizations, partially offset by lower liftings from the end of concessions in Indonesia and Thailand. Adjusted Downstream earnings increased primarily on higher refining margins. Compared with last quarter, adjusted earnings were up nearly $5 billion. Adjusted Upstream earnings increased primarily on higher realizations, partially offset by tax and other items, including higher withholding taxes on TCO dividends and cash repatriations. Adjusted Downstream earnings increased primarily on higher refining margins and a favorable swing in timing effects. The All Other segment was up due in part to a favorable change in the valuation of stock-based compensation.

I’ll now turn it over to Jay.

Jay Johnson — Executive Vice President, Upstream

Thanks, Pierre.

Second quarter oil equivalent production decreased about 7% year-on-year due to expiration of our contracts in both Indonesia and Thailand, the sale of our Eagle Ford asset and CPC curtailments impacting TCO during April. This was partially offset by shale and tight growth, primarily in the Permian. In the Permian, we’re delivering on our objectives of higher returns and lower carbon. Our development costs are down about 25% since 2019, and we expect to keep them flat this year by offsetting inflation with productivity improvements. An example of simul frac, where we performed completion activities on 4 wells at a time, reducing cycle time by a quarter. We continue to design, construct and operate facilities to limit methane emissions. 2 of our Midland Basin sites recently earned the highest ratings from Project Canary’s independent certification program.

Production is at record levels and growing in line with guidance with our royalty position, providing a distinct financial advantage for our shareholders. At TCO, the drilling program is complete, and the final metering station is online. We expect to complete construction by year-end with remaining project activities, primarily focused on systems completion, commissioning and start-up. Total project cost guidance is unchanged. WPMP startup is expected in the second half of next year and FGP expected timing remains first half of 2024. TCO’s operations continue to generate strong cash flow, enabling a midyear dividend. With project spend decreasing, we’re expecting higher dividends going forward. In Australia, we shipped 87 LNG cargoes from Gorgon and Wheatstone in the first half of this year, up over 10% from last year.

Our reliability benchmarks in the first quartile and we intend to stay there with an ongoing focus on operational excellence. Gorgon Stage 2, the first backfill project, is on track to deliver first gas in September. Our Gulf of Mexico projects are progressing well, with Ballymore receiving FID as a tieback to Blind Faith, an example of leveraging our existing infrastructure to improve returns. The Anchor hull is currently sailing from Korea and work on its top sides continues in Texas. Lastly, we recently signed agreements to export 4 million tons a year of LNG from the US Gulf Coast, with 1.5 million tons a year expected to start in 2026. These agreements leverage our growing US natural gas production and expand our value chains in Atlantic Basin markets.

Now back to you, Pierre.

Pierre Breber — Vice President & Chief Financial Officer

Thanks, Jay.

We closed the REG acquisition last month, and integration is going very well. We’re pleased to welcome REG’s talented employees to Chevron and CJ Warner to our Board. Our teams have already identified further commercial opportunities, and we quickly acted to lower insurance and financing costs. In May, we launched our joint venture with Bunge. The JV is operating 2 existing crushers, and evaluation work is underway to expand crush capacity and add pretreatment facilities. In carbon capture and storage, we closed on the expanded JV to develop the Bayou Bend CCS hub. The lease held by the JV is in Texas state waters, near large industrial emitters, and we believe it is the first US offshore lease dedicated to CCS. Also, we recently filed for a conditional use permit in Kern County, California, to store CO2 emissions from one of our cogeneration plants.

Now looking ahead. In the third quarter, we expect turnarounds and downtime to reduce production in a number of locations. In Downstream, planned turnarounds are primarily at our California refineries. We do not expect significant dividends from TCO for Angola LNG until the fourth quarter. Our full year guidance for affiliate dividends is unchanged, with upside potential beyond the top of the range depending on commodity prices. Also, we increased the top end of our share buyback guidance range to $15 billion per year and expect to be at that rate during the third quarter.

In closing, we’re executing our plans, increasing investment to grow both traditional and new energy supplies and delivering value to our stakeholders. Although commodity markets may be volatile, our actions are consistent through the cycle and focus on our objectives to deliver higher returns and lower carbon.

Back to you, Roderick.

Roderick Green — General Manager, Investor Relations

That concludes our prepared remarks. We are now ready to take your questions. Please limit yourself to 1 question and 1 follow-up. We’ll do our best to get all your questions answered. Katie, please open the lines.

Questions and Answers:

Operator

[Operator Instructions] Our first question comes from Devin McDermott with Morgan Stanley.

Devin McDermott — Morgan Stanley — Analyst

So Jay, I wanted to congratulate you on the retirement plans and take advantage of having you here on the call. My first one is on TCO. And it’s great to see the project progress there. And with the WPMP portion of the project largely complete, I was wondering if you could talk a little bit more about the remaining milestones for that second phase FGP as you progress toward that first half 2024 startup.

Jay Johnson — Executive Vice President, Upstream

Thank you, Devin, for both the retirement wishes and the question. But TCO, we’ve been just steadily making progress here, and we had a very strong period in the first half of this year. We had the unrest in January, of course, and then the team responded well after that, even with some of the Omicron impacts. As we are finishing construction, we expect to finish construction on everything this year and be largely into the commissioning phase. And this is largely putting together doing the pressure testing, filling with fluids, cleaning systems and preparing them for eventual startup. The WPMP that we expect in the second half of next year will be around enabling us to boost the pressure from the field up to the facilities. So we don’t expect to see a material change in our production at that point in time, but it enables us then to move into the phase of start-up for FGP where we will start to see incremental production coming through the plant.

And some of the big milestones we’ve already accomplished. All 40 production wells are already now produced and completed and actually producing into the plant that helps us with the transition from the high pressure to the low-pressure phase. We’ve got the injection wells already completed so we can begin the FGP startup. Field facilities are well underway in terms of the new gathering system. We’ll have about all the metering stations have to be converted to high pressure to low pressure. They’ll be done kind of one at a time, so we can maintain production through that period. So those are the — you won’t see a lot of outward signs other than progress on the commissioning, the number of subsystems completed and that’s really what we’re moving into. Rather than percent complete, we’re 93% complete overall now. What’s going to be more important are just the rundown curves as we bring each system to completion.

Devin McDermott — Morgan Stanley — Analyst

Great. Very helpful and great progress there. And sticking with TCO in that part of your portfolio. There’s been a lot of headlines around the CPC pipeline in recent weeks and months. I just wondering if you could give us a status update on where things stand there? And then also to the extent that there were to be any further disruptions to flows on that pipe, can you talk a little bit about the impacts to operations for your base existing production in that area?

Jay Johnson — Executive Vice President, Upstream

The CPC continues to be an important export route for us. It handles the majority of Kazakh crude that’s being exported to Western markets, and it represents an important supply to the world. It’s about 1.4 million barrels of oil a day coming through that. The oil that we put into the line from Kazakhstan carries a certificate of origin from Kazakhstan. And we’ve done a lot of work in Washington and Brussels to make sure people understand the importance of the pipeline to world supplies. And we’ve seen the reliability overall still and the capacity to be able to maintain at the levels we need. The interruptions that we’ve seen have been managed. We’ve gotten through those. And as we look forward, we just continue to work with the Kazakh Government and with the international consortium that owns and operates the CPC pipeline to maintain this important source of — or export route for the crude. There are some alternate export routes being developed, but CPC remains the primary and most important route for us.

Devin McDermott — Morgan Stanley — Analyst

Got it. Just to clarify, at the moment, operationally, at normal nameplate and flow rates through the pipe?

Jay Johnson — Executive Vice President, Upstream

Yes, we’re at full capacity, both at TCO and through the CPC pipeline. They actually work quite well with us when they do have to take the pipeline down for ongoing maintenance, which all pipelines have to do from time to time. They coordinate with the producers. They’re often coordinated with turnarounds that the producing facilities are undergoing. So the recent downtime for CPC as they were dealing with some of the results of the survey work around the terminal was coordinated with the NCOC turnaround activities so that it didn’t have any impact at all on TCO’s production.

Operator

We’ll take our next question from Neil Mehta with Goldman Sachs.

Neil Mehta — Goldman Sachs — Analyst

Jay, thank you for all the insights over the years and wish you well in your retirement, sir.

Jay Johnson — Executive Vice President, Upstream

Thank you.

Neil Mehta — Goldman Sachs — Analyst

The first question is on capital returns. And you guys raised the top end, the buyback guidance here. So just talk about the math that went into it, and how you think about the optimal return of capital formation, whether it is through buybacks or dividend growth?

Pierre Breber — Vice President & Chief Financial Officer

Thanks, Neil. It’s Pierre. I’ll take that. I’ll go through our financial priorities. They’ve been consistent for decades, literally. The first financial priority is to grow the dividend. We’ve done that for 35 consecutive years, increased it 6% earlier this year. It’s up 20% since right before COVID, and it’s doubled since 2010. The second is to invest and grow both traditional and new energy, and you saw that our total investments first half of the year were up 80% versus a year ago. The third is to maintain a strong balance sheet. For the fifth consecutive quarter, we paid down debt. Our net debt ratio is at 8%. That’s well below our mid-cycle guidance of 20% to 25%. And when we have cash in excess of those first 3 priorities, we buy back shares, and we intend to do it ratably over the cycle. We repurchased shares, 50 now last 19 years. We bought back almost $60 billion during that time at an average price of around $90 a share, very close to the weighted average price during that whole time.

And as you said, we just increased the guidance to — we just increased the top of the range of our guidance to $15 billion a year. That represents about 1% of our shares each quarter. The $15 billion annual rate is based on our current outlook. It was tested against a number of scenarios. The rate is consistent with our Investor Day upside leverage case, which was a $75 Brent flat nominal price over 5 years. As we’ve said with previous buyback rates, we intend to maintain buybacks at this annual rate for a number of years across the commodity cycle. As a reminder, our net debt is well below our mid-cycle guidance range. So we’ll continue buybacks even when the commodity cycle turns down, and we’ll lever back up our balance sheet closer to that 20% to 25% guidance range.

Neil Mehta — Goldman Sachs — Analyst

Pierre, the follow-up is just on the Permian. Can you just talk about how you’re thinking about the growth profile there relative to what you guided at the beginning of the year, does the upward drift in commodity prices change the way you’re thinking about prosecuting that asset?

Jay Johnson — Executive Vice President, Upstream

Yes, I’ll start out with that and then Pierre can finish if he’s got any other thoughts. The Permian — our approach to the Permian, as you know, for many years, has been to be very disciplined, very focused on generating the returns and the efficiency that allow us to be profitable regardless of the prices. And so we’re not responding to short-term price, but we are increasing our activity levels since the turn down during COVID. And so we have seen our investment go up. This year, it’s $1 billion higher than it was last year. And we also see the number of wells that we’re putting on production going up, we expect to do over 200 POPs this year. And so we’re looking for about a 15% increase in our Permian production. We’ve increased 2 additional rigs in July. So we’re running now with a fleet of 10 rigs across the Permian in the current time, and we expect to maintain that through the second half.

But I’ll remind you also one of our rigs today drills the equivalent of what 2 rigs could do in 2018. So using just rig counts is a little bit of a — you have to be careful because we’re so much more efficient with our rigs. And each frac crew today is also completing roughly double the work they were doing back in 2018. So we’re much more efficient than we were just 4 years ago. We expect to see our investment continue to grow. We’ve given you guidance of increasing our investment rate up to about $4 billion a year by 2024. And then I would expect to see it relatively flat after that as we just maintain an efficient operation across the Permian.

We also have non-operated activity, and we currently have about 9 net rigs running on the non-op side. And so that also contributes significantly to our production profile. Our guidance remains unchanged. We’d expect to see about 1.2 million to 1.5 million barrels a day of production ultimately is our plateau. But as we continue to gain insights and knowledge and as we look at our efficiencies, as we look at our portfolio and world demand, that can change as we go forward. That’s our guidance as we see it today, and we’ll continue to update you as we move forward in time.

Pierre Breber — Vice President & Chief Financial Officer

My only add is it’s also among our most carbon-efficient barrels in the portfolio. And as Jay has said, it’s a demonstration of our — delivering on our objectives of higher returns and lower carbon.

Operator

We’ll take our next question from Jeanine Wai with Barclays.

Jeanine Wai — Barclays — Analyst

Jay, we’d also like to wish you well, and thank you for all your time over the years. And we’ll stick to 2 Upstream questions just so we can get to last in before you leave. Our first one is on LNG. This week, there was an announcement that Chevron along with a couple of other partners that you guys reached FID on development that will help boost Angola LNG plant volumes. So can you talk about how you’re viewing expansion opportunities in Angola and also hit on Equatorial Guinea where you also have kind of an equity position that feeds an LNG plant there? And is there a preference on how your involvement evolves with LNG plants because you have some ownership — some equity ownership, but we also know that you had a Cheniere agreement that you announced recently that was more just on the marketing front. So just wondering how you’re seeing your role there on new opportunities.

Jay Johnson — Executive Vice President, Upstream

That was pretty good, Jeanine. I think you got 3 questions in there, and I’m going to try and merge through those.

Jeanine Wai — Barclays — Analyst

Oh, no. That’s just one.

Jay Johnson — Executive Vice President, Upstream

I know. I’m allowed to do that. I’m the Upstream guy. Look, on the LNG in Angola, you’re right, we just took FID in the new gas consortium. There are 2 primary sources of gas for Angola LNG. Traditionally, it was built for the associated gas that’s produced along with the oil resources in Angola. And that’s been the main source of gas for Angola LNG up to this point. And we continue to develop new oil resources with our 20-year extension, just secured really good terms on both the oil and the gas. It encourages investment in that country. There’s a lot of oil still in Block 0. So that continues unabated. And actually, the investment will move forward. The non-associated gas. In other words, drilling and developing reservoirs that are gas only is a new investment mode, and we’re doing that through the consortium you mentioned. And that’s designed to be supplemental gas so that we can keep the Angola LNG facilities full.

And so the ongoing effort to keep that plant running, it’s really economic because it builds on existing infrastructure that’s already been built, the investments have already been made. And importantly, it’s supplying needed LNG into the European market and also gives us exposure to that Atlantic Basin. So that’s been a good project for us, and we’re pleased to take that FID. In EG, again, we have exposure now to the Atlantic Basin through that project. We continue to produce there. There’s not much more I can say, other than that’s also been a profitable area for us and it came to us through the Noble acquisition. So it was kind of one of those more hidden jewels. We talk about Eastern Med. We talk about the DJ Basin in particular. But EG is supplying a very good return to us through those gas and LNG facilities.

In terms of our focus on ownership versus commercial, we’re really pretty agnostic. We’re looking for the returns and the scale that we can build out of the business. We’re looking for multiple points of supply so that we can maintain an active and profitable portfolio. And so where we can do commercial deals and not have to use capital, but to really be able to leverage other facilities, that’s always a nice way for us to go, and I’m pleased to get that exposure out of the Gulf Coast into both European and potentially Asian markets. It gives us an access for a lot of our produced gas in North America to access those markets rather than just US. But where it makes sense, we’ll also make investments as we have in other places and own the facilities or run them through joint venture facilities or non-operated facilities. We really look at what gives us the best opportunity to generate the returns we’re looking for.

Jeanine Wai — Barclays — Analyst

Great. We won’t sneak in our unrelated follow-up since that was a very wholesome response.

Jay Johnson — Executive Vice President, Upstream

Okay. Thanks, Jeanine.

Pierre Breber — Vice President & Chief Financial Officer

Thanks, Jeanine.

Operator

We’ll take our next question from Doug Leggate with Bank of America.

Doug Leggate — Bank of America — Analyst

41 years in 1 place, Jay, that’s pretty impressive. Congratulations.

Jay Johnson — Executive Vice President, Upstream

Thank you.

Doug Leggate — Bank of America — Analyst

I wonder if I could take maybe 2 questions for you, actually. Maybe Pierre might prefer the second one. I want to go to the Permian first. You have about half year production operated and half non-operated. Can you parse between the inflationary pressures between your operated and non-operated from what you’re seeing currently?

Jay Johnson — Executive Vice President, Upstream

It’s difficult for me to really do that definitively. What I can say, though, is I think we have a competitive advantage in the Permian. We have a couple of things working in our favor. We maintain a global supply chain, and we’re able to tap suppliers of both equipment and materials, goods and services over a much broader range than maybe some of our competitors. We also do multiyear contracts and other mechanisms commercially that allow us to mitigate some of the inflationary pressures that we see today.

And then, of course, our focus on driving for improved productivity, improved efficiency has really helped us continue to counter the inflationary pressures. I think the other area that we have a distinct advantage is we’ve been building out our infrastructure in the Permian. And so just as a proof point, the last 800 wells over the last 5 years, to produce those 800 wells, we had to build 40 central tank batteries. As we look forward, the next 800 wells, we only need to build an additional 4 central tank batteries. So while others are having to invest in this high inflationary period, we’re largely using infrastructure that was built over the past 5 years with very small incremental surface facilities required. And I think that’s going to be hard for others to match.

Doug Leggate — Bank of America — Analyst

So that’s a differentiated answer, very clear answer. Pierre, I don’t know quite how to ask this question. I’m going to try and get part a and part b, perhaps, I’ll be respectful. Mike was interviewed recently, talking about the tightness in the global oil market. I think you said something like I know to put words in his mouth, but any weakness in oil prices is going to be fleeting because of the under investment. And you guys obviously have stepped up your spending from COVID levels, but you’re still well below pre-COVID levels ’16 through ’19, let’s say. With your balance sheet where it is in the depth of opportunities that you obviously have that you’re not funding, how should we think about your continued commitment to the current capex level? Or do we see Chevron reengage in organic growth at some point?

Pierre Breber — Vice President & Chief Financial Officer

You should think that there’s no change in our guidance. There’s — our 2022 capital is on track. It’s likely to end up below our $15 billion budget. We’ve been ramping up during the course of the first half of the year, and I think you’ll see us higher in the second half of the year, but likely end the year below our $15 billion budget. Our guidance that we shared at our March Investor Day is $15 billion to $17 billion of organic capital investments through 2026. Our budget this year is around $15 billion. So we have $2 billion of room to increase activity and investment within the guidance. And then as Jay just described, our major capital project in Kazakhstan is winding down. It will decrease spending by about $1 billion, and that opens up another $1 billion. So we have — we will increase investment in activity next year.

I expect that we’re doing that work right now. We’ll share the details in December when it’s finalized and approved by the Board. But we’ll increase it within the guidance. And that guidance enables us to sustain and grow the Upstream business, as we’ve talked about, 3% compounded annual growth rate between now and 2026. Add to our refinery capacity. We bought a refinery in Pasadena, Texas in 2019, kept all of our US refineries through COVID and are making investment in that Pasadena refinery that was just recently FID-ed. And of course, all the activities we’re doing to grow new energies. We can do all of that within the guidance. And as we recognize, Jay, one of the things he deserves a lot of credit for is our Upstream business is much more capital efficient than it’s ever been. And has a mindset of how do we deliver business results with less capital. And if we do that, there’s more free cash flow for shareholders.

Operator

We’ll take our next question from John Royall with JPMorgan.

John Royall — JPMorgan — Analyst

Can you talk about your growth in the Gulf of Mexico in the Upstream? You’re leaning in there with number of brownfield projects. So can you just speak broadly on how you view on within your portfolio, and how the returns look on those bolt-ons relative to your other options globally in the Upstream? And then what does the service inflation picture look like in that part of your system relative to, say, the Permian?

Jay Johnson — Executive Vice President, Upstream

Thank you, John. I’ll start this and let Pierre add in. But we’re really quite pleased with the portfolio we maintain in the Gulf of Mexico. It’s a good area of exploration for us. And it has some of the lowest carbon intensity in the world. It’s about 6 kilograms of equivalent per barrel produced. So on a world scale, and even our company scale, which is already top quartile, it’s right at the bottom end of that range. So this is a great area to develop for future production and carbon efficiency. When we look at the queue of projects we have, we’ve got the Anchor project that is expecting to have first oil in 2024. We’ve got Whale, is coming through. We expect in 2024. We’ve been expanding our existing facilities. We’re starting up the waterflood at St. Malo, which is part of the Jack/St. Malo complex.

We’ve installed our multiphase pumps and are commissioning those. That’s going to be an important milestone technologically and our ability to step out further and further. We just took FID at Ballymore. And Ballymore is an interesting one because it was a nice size discovery, but we could really capitalize and get a much higher return by taking 3 wells back to a host facility, at Blind Faith and be able to develop that. So we’re pleased to be able to see that higher return coming from Blind Faith. And it also helps our existing production at Blind Faith. As we continue to work forward, I think we’re going to see growth in our Gulf of Mexico production, but it’s going to be important that we continue to be able to lease and acquire additional acreage in that basin, along with others because there’s still, I think, room for continual exploration and tie back to this great chain of infrastructure that we have, be able to produce this lower carbon fuel.

Pierre Breber — Vice President & Chief Financial Officer

Only add is our rigs were largely contracted when rates are lower. So clearly, offshore rigs have increased, but we’re largely contracted at prior rates.

John Royall — JPMorgan — Analyst

Yes. So on the Downstream, I just had a question on particularly California, just kind of your go-forward views there. Product balance is not quite as tight as they are in other parts of the country. But then we’re seeing some capacity come out due to RD conversions there. And so just looking for maybe your medium-term view on refining and California specifically?

Pierre Breber — Vice President & Chief Financial Officer

On the Downstream side, we had a strong quarter. Well, good execution, reliable operations, high refinery utilization, and I’m talking generally now, US West Coast and Gulf Coast, good cost control, and we’re able to capture the margins in the marketplace. We had a slight benefit in the second quarter because the Richmond turnaround was deferred. So it was a little bit less of an impact than what we had guided to on the first quarter call. And timing effects really weren’t a driver, right, timing is more of the absence of timing effects that you saw.

In terms of these markets, they’re volatile right now. I mean, we’ve seen margins come off from where they were before. In the second quarter, we saw a demand response. On gasoline, probably around the mid-single digits across the US, a little bit higher on the West Coast, a little bit lower in the Gulf Coast. I didn’t really see much on the diesel side. And Jet is really tied to the recovery of travel. So we’ll just see where the market takes us, whether it’s West Coast or Gulf Coast, we’re focused on safe, reliable operations, continuing to have good cost control and delivering products that our customers are demanding.

Operator

We’ll take our next question from Jason Gabelman with Cowen.

Jason Gabelman — Cowen — Analyst

I have one on the Upstream portfolio and then one on the financials. On the Upstream, can you just talk about your other gas opportunities that you have available in the queue. Specifically, I’m thinking about the Eastern Med. I know you’re delineating some acreage there, and it seems like there’s a lot of gas available to exploit. And then also, I believe you have a Haynesville position. I’m not sure if that’s in the money or not and that’s also — that you’re looking at. And then I’ll ask my follow-up after.

Jay Johnson — Executive Vice President, Upstream

We have a lot of gas opportunities, and we’ve got a lot of infrastructure to build those opportunities on, which is really important because it gives us an advantage from a return standpoint. In the Eastern Med, which I’ll add, is one of the lowest carbon intensity areas from a Scope 1 and Scope 2. We’re at 2 kilograms of carbon equivalent per barrel produced. We have, of course, supplied a lot of gas into the Israeli market and that opportunity continues to grow as coal is displaced. We also take that gas into Jordan for conversion to electric power. And now we’re taking it into Egypt, work and supply, both domestic needs in Egypt, but also potentially access some of the ullage that exists in the LNG facilities that are already existing in Egypt. We’re considering floating LNG as well.

As you know, there are very benign conditions, Med Ocean conditions in the Mediterranean that lend themselves to floating LNG. So it represents a viable option for us. Developing additional gas capacity at Leviathan and Tamar is well within the scope of those projects and would allow us to access these additional marketing opportunities through the LNG and the flexibility that provides. We continue to have some upside potential in additional fields through EG. And then we’ve got access, as you pointed out, in the United States. We are ramping up our drilling activity in the Haynesville, and we expect to see rigs there starting later this year. They’ll be working in that area. It was very profitable even at the low prices, it’s profitable now. So again, our focus is going to be on discipline on continuing to drive for those efficiencies, but we really are excited to get Haynesville underway and add that to our portfolio in that part of the country.

Jason Gabelman — Cowen — Analyst

Great. And my follow-up is just on the share count. I believe it went up again this quarter despite the buyback. And it’s gone up since the buyback started. I think if you back out the shares issued for Noble, it’s been flattish. So can you just discuss exactly what’s going on there and your expectations for their share count moving forward with the higher buyback, but also at a higher share price?

Pierre Breber — Vice President & Chief Financial Officer

Yes. The share count is going down and will go down. What you see in the earnings press release is a weighted average during the course of the quarter, not necessarily the end of the quarter. So you’ll see in our Q that the share count at the end of second quarter is, in fact, lower than the first quarter, which you’d expect as we bought back $2.5 billion of shares and issued $0.8 billion. The first quarter, we had this very large issuances for our employees and retirees exercising stock options. And so we started the year with a lower share count, issued those for our employee retiree stock options. Therefore, started second quarter at a higher rate and then worked our way down. So the math does work. It is going down. It’s — you have to look at end of quarter to end of quarter. But what you see in terms of earnings per share, it’s an average over the quarter, and it’s kind of a quirk that second quarter average was higher than the first quarter, but just the nature of the pattern during the quarter. Share counts are going down.

Operator

We’ll take our next question from Manav Gupta with Credit Suisse.

Manav Gupta — Credit Suisse — Analyst

My first question here is, I wanted to take expertise from Jay again. This was a heavy turnaround quarter for you. But even then, some of the things where you were turning around were very high-margin barrels for you, so whether it was TCO, Angola or Wheatstone. And help us understand, like in terms of opportunity cost, if this volume was somewhere in the lower margin business versus some of your higher-margin business because you’re trying to say Upstream results were good, but they could have been even better because some of the higher-margin barrels were actually in a turnaround.

Jay Johnson — Executive Vice President, Upstream

I appreciate the question. One of the things that’s really important to us is that we operate safely and reliably. And so we look and we schedule our turnarounds, and they’re predominantly to ensure asset integrity and ongoing reliable performance. And when we schedule those, we don’t like to shift those because of market conditions. And so we tend to want to execute those on time. What’s important is that we execute them within the time frames that we expected so that our production is in accordance with our planning.

And both Wheatstone and Angola LNG were done really, really well. I was proud of our teams, they went in, they did the turnaround. This means now in Australia, all 5 trains have been through the first round of turnarounds. And so that’s an important milestone, an important accomplishment. This work that we do, while it may seem like we’re giving up some opportunities in the near term, it allows us to continue to drive higher and higher reliability, which means our overall production will be higher and our costs will be lower and our safety will be higher. And so that’s really how we think about this.

Manav Gupta — Credit Suisse — Analyst

And I have a quick policy question. About 1.5 months ago, things got a little heated between the oil companies and the White House. But as we understand, when the actual executive meetings happen between you guys and all the others and the secretary of energy, those are pretty cordial and you guys are looking for solutions out there. Help us understand what happened in the meeting with energy secretary and how did those go?

Pierre Breber — Vice President & Chief Financial Officer

Manav, we won’t comment on the specifics of our engagements. I think you’re right that we’re — it’s constructive and productive. I’ll point out our US oil and gas production in the first half of the year was up 7% versus last year. Our US refined product sales up 10% versus last year. The administration wants energy supplies to increase, we’re doing that. Our investment globally, up 80% first half of the year. If you look at the US, more than double when you include REG. So Chevron is growing energy supply, increasing investment, and we’re engaging constructively with Congress and this administration.

Operator

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

Biraj Borkhataria — RBC — Analyst

Just one for me on Australia. I mean there’s gas shortages in many geographies in Europe, in particular, but there’s been some talk about or noise around that in Australia. I wanted to understand whether we should expect any export issues at Gorgon and Wheatstone? Are you in discussions with the government around proportion of gas against domestic market versus what’s being exported or anything like that? So any color would be great.

Jay Johnson — Executive Vice President, Upstream

Thanks, Biraj. The shortages that you’ve heard about in Australia are all on the East Coast, and there are no pipelines connecting the West Coast and the East Coast. So actually, the only way that we could supply any gas to the East Coast of Australia is in the form of LNG. So we are under long-term contract with customers throughout Asia. We also sell into the spot markets with those facilities. We have interest in Northwest Shelf as well as, of course, Wheatstone and Gorgon. The Western Australian market is well supplied. It’s a part of our agreements for that supply. And so there really are no issues. I don’t see any impact to our export capabilities in Australia.

Biraj Borkhataria — RBC — Analyst

Okay. Understood. And just a follow-up on the same topic. A couple of years ago, I think I had a conversation with Pierre around the potential for increasing nameplate capacity at Gorgon and Wheatstone over time. And as you go through the various debottlenecking exercises, are you able to provide an update on whether that’s still in the works, where you are, and what kind of time line that would be on, if that’s possible.

Jay Johnson — Executive Vice President, Upstream

Yes. We continue to focus on incremental capacity increases at both Gorgon and Wheatstone. And that can happen through expansion of debottlenecking where we actually expand the capacity of the facilities. But importantly, it also happens as we increase the reliability of facilities, and their utilization is higher. If you just look at this year, we’ve supplied 87 cargoes. As I said, that’s up 10% on production from last year, even with the turnaround that we had. So you can see the improvement happening there. We have seen capacity increases at both Wheatstone and Gordon, and I would expect those to continue as we move forward.

Operator

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

Sam Margolin — Wolfe Research — Analyst

I wanted to revisit the LNG topic and maybe specifically tie it to the Permian because there’s just a lot of resource in the Permian that’s not commercial, and that’s — that includes different zones of what you’re already developing plus areas that are not on your development calendar in the near term. And LNG didn’t historically help with that because it’s expensive, but obviously, things have changed now. And so I just love your perspective on what happens to your Permian resource or your overall opportunity there or the duration of it in an environment where you can add some extra capital or even commit to a spread, but monetize gas for a double-digit price.

Jay Johnson — Executive Vice President, Upstream

Look, I would characterize it what determines our pace of activity in the Permian is a balance on what we can accomplish efficiently. We have a factory model all the way from land acquisition. We do deals all the time to fill in the checkerboards and ensure an efficient development plan. As an example, just since 2017, we’ve executed over 260 transactions that have added 3,500 long laterals. That’s allowed us to drive for this efficiency and the higher returns. Our activity levels really aren’t determined by how much we can export from the United States.

All these projects that we have would be economic at much lower prices. So it’s really not the price that’s unlocking the Permian, it’s developing the infrastructure for export from the basin into the markets that we supply, both domestic and international. So it’s all done in a coordinated fashion. We do it. So we stay within the capability of the organization to execute efficiently and safely. And that’s really what drives the Permian. So it’s nice to have access to these additional markets and the optionality they provide. We have an advantage in working closely with our midstream group, who has great capability, both again for the domestic offtake and setting up potential for international export, but it’s really not what I would view as the limiting factor on our pace. We determine that based on our overall balance of free cash flow, the returns and our resource and reserve replenishment.

Sam Margolin — Wolfe Research — Analyst

Okay. And then, I mean, maybe just to follow up, like, are there any ancillary factors that might be a consideration like an opportunity to fit another CCUS project on a facility or what it might contribute to like a flaring mitigation effort or anything besides just, like you said, a price signal?

Jay Johnson — Executive Vice President, Upstream

As Pierre said earlier, the Permian actually has very good carbon intensity on a Scope 1 and 2 basis. We’re at 15 kilograms of CO2 across the basin. We’re now benchmarking our facilities and achieving certification of platinum status on most facilities with Project Canary, which then provides independent third-party certification of our methane emissions and the performance that we have been talking about. We are working with both our Chevron Technology Ventures, which is our venture capital arm and our New Energies segment on the carbon capture and sequestration.

And carbon capture, in particular, is critically important for not just us but the world. And so we have 3 pilots going on at San Joaquin Valley operations to capture the CO2 that’s coming off of our cogen units there. And then, of course, we’re gaining experience at Gorgon and Quest up in Canada, where we learn more and more about what it takes to effectively and efficiently sequester CO2 into storage. So these are all going on. The beauty of having a portfolio like we do is we can put these pilot projects and we can put these demonstration projects wherever it makes the most sense, both from a regulatory, fiscal and return standpoint and develop these technologies that we’re all going to need going forward.

Operator

We’ll take our next question from Irene Himona with Societe General.

Irene Himona — Societe General — Analyst

I wanted to ask, first of all, about what you’re seeing on the ground in terms of any signs of persistent demand destruction at retail, but also at industrial customer level, please?

Pierre Breber — Vice President & Chief Financial Officer

Irene, I said it very quickly earlier, I mean, we’ve seen, I would call it, demand response to higher prices that in the second quarter was about in the mid-single digits in the US on gasoline. Again, a little higher on the West Coast, a little lower on the US Gulf Coast. And I think we’ve seen some recovery since because prices have come off, so we’ll see where our third quarter ends up. On diesel, it’s very hard to see, not price sensitive, it’s tied to commercial industrial activity, maybe a little bit of a response at retail diesel. And then jet is largely tied to the recovery in air travel. I think people are wanting to get out and see people and places. Asia, where we also have retail is a little more variable because there’s been still COVID restrictions, and so it’s hard to kind of see the data. I mean what’s interesting is there’s obviously concerns around the recession.

In terms of tailwinds, we still have very low unemployment, and we have a consumer that wants to spend money to go out and do things they haven’t been able to do for a couple of years. When prices were higher in the second quarter, they made some choices. And if you look at that demand response on gasoline, that’s in line or even higher than some past recession. So it’s not clear. I guess what I’d say is demand, I think, will be much more recession resilient going forward just because we’ve seen a little bit of that response in the second quarter. And again, diesel will be tied to underlying commercial activity. And I think jet will really depend on if the airlines can get all the flights scheduled and have pilots and all the rest and some of the challenges that have been happening over there. So that’s a little bit of a sense of the demand. We saw a response second quarter, seeing some of it come back here early third quarter, and we’ll just see where it goes from here.

Irene Himona — Societe General — Analyst

For my follow-up, and as you mentioned you’re launching some new carbon capture projects. I wanted to go back to Australia and ask if you can possibly talk around the recent performance at the Gorgon carbon capture project. Is utilization improving? And is there any read through perhaps on the technical side from that project to the ones you’re launching now?

Jay Johnson — Executive Vice President, Upstream

Thanks, Irene. At Gorgon, we’ve now stored successfully about 6.6 million tons of CO2 into that reservoir. The — ironically, the biggest issue we’re having currently is just the ability to remove water at a sufficient rate from the storage reservoir to create the space for the CO2 to enter. We’ve already demonstrated the capacity and capability to inject full CO2 rates into that reservoir, but the water that we’re producing has some solids in it and some other contaminants, ironically, oil and gas, because it’s an oil and gas basin. And we need the surface facilities that can just remove those before that water is injected into a third reservoir. These are not new or particularly high technology challenges at all. It’s what we deal with in everyday life around the world.

So it’s just — it’s compounded a little bit because Gordon sequestration is in a Class A nature reserve, so it’s a very cumbersome process to approve additional facilities and additional wells. But these problems are solvable. And they do not represent, in my view, any kind of a restriction on the viability of carbon sequestration as a means of storing CO2 for long periods. What I would expect is that and we said this before, as we learn, as we go through this, what it’s teaching us is that there are uncertainty ranges on any reservoir, whether you’re producing from it or injecting into it and having sufficient contingencies and mitigations, depending on where you find yourself in those uncertainty ranges when you actually put the facility into operation is important, and we’ll need to keep these in mind as we develop sequestration projects around the world. So the science is good. The technology works. It’s just the basic issues that we face on reservoirs around the world that we now need to overcome.

Operator

We’ll take our next question from Paul Cheng with Scotiabank.

Paul Cheng — Scotiabank — Analyst

And Jay may I add my congratulation and thank you for the help over the years. We appreciate it.

Jay Johnson — Executive Vice President, Upstream

Thanks, Paul.

Paul Cheng — Scotiabank — Analyst

Two questions. First, you touched on the inflation in different parts of your business. But can you give an over or — given your footprint, can you give us an overall view that what is sure on expectation on the inflation for next year? I know it’s still early for your budget, but are we talking about 10%, 15%? Some of your largest suppliers seems to suggest that everything is all used up in terms of manpower and equipment. So I don’t know whether that you agree with that assessment. And if you can tell us that where you see along the supply chain is the biggest maybe pass upon and where that you see the least inflationary pressure? So that’s the first question. The second question on Mexico and Brazil. You guys entered I think a couple of years ago and had some block over there. But I haven’t heard you guys talk too much about those. So where those rank within your portfolio today? And what is the next step in those?

Pierre Breber — Vice President & Chief Financial Officer

Thanks, Paul. I’ll take the first, and then I’ll hand it to Jay on the second. On the onshore US, we’ve seen cost inflation this year in the single digits. We’ve been able to mitigate a part of that through good planning, smart procurement and good relationships with suppliers. And as Jay pointed out, we’ve been able to also get more efficient with our drilling and completion operations, which also partially offsets it. Outside of the US, we’re seeing much more modest inflation, and we talked about our Gulf of Mexico offshore rigs, which were contracted at a time when the rig rates were lower.

As we’re looking towards 2023, we’re doing that work right now. We’re confident that we’ll be able to secure all the goods and services that were needed for our program. Again, our program will be a higher activity program next year, and that includes the Permian. And we’ll share estimates of what we’re seeing in terms of, COGS inflation when we disclose our capex budget in December. We’re just in the middle of that work right now, I feel very good that we’ll have all the goods and services that we need, and we’re finalizing our plans. Jay?

Jay Johnson — Executive Vice President, Upstream

Yes. Thanks. And Paul, in terms of Mexico and Brazil, we have not had exploration, significant discoveries there. We are turning our attention, I would say, towards Egypt, where we have a very nice exploration position. We’re shooting seismic. These are in areas that have been unexplored before because they’ve been in restricted areas and now available to us. As well as in Suriname. So as we do in exploration, we’re always going through and looking for the next opportunities, but I would say our focus primarily is shifting now towards Egypt and Suriname. Thanks for the question.

Operator

We’ll take our last question from Ryan Todd with Piper Sandler.

Ryan Todd — Piper Sandler — Analyst

Maybe first one on the biofuel side. You now closed both the REG and the Bunge deals within that business. Can you talk a little more about what you’re seeing in those markets? And whether you can elaborate at all about the broad types of commercial opportunities that you see that you mentioned in your prepared remarks?

Pierre Breber — Vice President & Chief Financial Officer

Thanks, Ryan. We’re really excited to welcome REG’s people to Chevron and CJ Warner to our Board. She’s already participated in our first Board meeting, is fantastic, has great knowledge of traditional and new energy businesses, and it’s just a great add to our Board. As I said, we’ve had some sort of early wins. I won’t get into the details of the commercial opportunities, but what we saw in the combination, the strength that REG has in terms of feedstock acquisition primarily of waste oils, and then combining that with our retail and marketing footprint. And just bringing 2 great teams together, we’re seeing, as you’d expect, 1 plus 1 is more than 2. We’ve got our renewable fuels business headquartered in Ames, Iowa. And we’re very excited about it. We closed in mid-June, just a comment on the accounting. There were no results in our second quarter results because we chose a convenience day of June 30.

So all you’ll see and all you saw in our earnings release, and you’ll see in the Q is just the purchase accounting starting in third quarter, then we’ll see REG in our results. REG had a good second quarter. Margins have been bouncing around, but the results are largely in line with expectations, and Geismar continues on track. And same thing with Bunge, operating 2 crushers, very excited to be part of that, invested in CoverCress jointly, which is a crop that won’t compete with food. So lots of work in this space as we work to get our renewable fuels capability up to 100,000 barrels a day. Still working, still on track to convert diesel hydrotreater at El Segundo to have renewable fuel capability and work across other parts of Chevron systems. So the combination of REG, our Bunge joint venture and our own assets, along with our customer relationships, we’re all putting that together to have what we think will be a very successful, viable renewable fuels business.

Ryan Todd — Piper Sandler — Analyst

Thanks, Pierre. Maybe the final one for Jay. Congrats on the retirement. I wanted to ask the kind of a higher level question on Upstream project development and technology. And there’s been a pretty significant shift over the last 5 to 10 years and the way that you’ve approached project development, more standardization, oftentimes smaller and more capital-efficient style projects. Ballymore is a great example of this. It’s lowered the cost of supply a lot, especially in the deepwater. As you pass the baton and look forward kind of into the next 10 years, are there — are there things that you can see on the horizon, either strategically or technologies that may continue to drive — changes in project development and technology that may drive things forward even further, whether it’s 20,000 kit in the deepwater sort of from flow line improvements and a lot of longer tiebacks. And what could this mean for the future of your resource development portfolio?

Jay Johnson — Executive Vice President, Upstream

Thanks for the question, and it’s pretty exciting. I mean the one bad thing about retirement is you don’t get to be part of the next steps, and I’m excited about them. I would start by just saying, I think we’ve accomplished a mindset shift in Chevron, and this is throughout our workforce, being very focused on returns, not chasing a production target, but continuing to run this as a business and thinking about the returns we can get. Scale is important, but it’s an outcome of the opportunity set that we have and the investments and capital that we choose to invest. Getting more focused, the factory model has been really important to us. And ironically, this started where we drilled lots of wells in places like Duri and San Joaquin. We’ve now successfully transferred that into our unconventional plays in Permian, in the DJ, in Duvernay and Argentina. And now we’re actually taking that factory model into places like the Gulf of Mexico, where we do what we call urban planning, and we try and have a steady progression of projects, and we’re developing the capability for further and further reach.

I mentioned earlier that Jack/St. Malo is now putting into service multiphase pumps. And these multiphase pumps sit on the sea floor, but they allow us to reach 30, 40 and even maybe 50 miles out from a host facility, which really gives us great capacity to make even smaller accumulations economic, and give us the returns we’re looking for while extending the life of these major hubs. I think the Gulf of Mexico will continue to be an important proving ground for some of these technologies that can then be exported around the world. So our focus on standardization, our focus on minimum viable facilities, our focus on capital efficiency over just scale and NPV, all these together are resulting in and aligning with our technology center, so that we continue to develop the technologies that are giving us the returns that we’re going to need going forward. And with the resource base that we have today, and the team of people that we have in our technology groups and in our businesses, I’m really excited.

Pierre Breber — Vice President & Chief Financial Officer

Ryan, thanks for that question. We will miss Jay, but his legacy will live on, and you’ll see it in the performance that the Upstream has been delivering and will continue to deliver.

Roderick Green — General Manager, Investor Relations

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

Operator

[Operator Closing Remarks]

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