Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's second quarter 2022 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone should require assistance during the conference call, please press star and then zero on your touch-tone telephone. 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. 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. 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 and 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 return 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. 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 is simul-frac, where we perform completion activities on four wells at a time, reducing cycle time by a quarter. We continue to design, construct, and operate facilities to limit methane emissions. Two 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 startup. 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 mid-year 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 Two, 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 topsides continues in Texas. Lastly, we recently signed agreements to export 4 million tons a year of LNG from the U.S. Gulf Coast, with 1.5 million tons a year expected to start in 2026. These agreements leverage our growing U.S. Natural gas production and expand our value chains in Atlantic Basin markets. Now back to you, Pierre. 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 Cynthia 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 two 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 U.S. 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 Tengizchevroil or 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. That concludes our prepared remarks. We are now ready to take your questions. Please limit yourself to one question and one follow-up. We'll do our best to get all your questions answered. Katie, please open the lines. Thank you. If you have a question at this time, please press star one on your touch-tone telephone. You may ask one question and follow-up question. If your question has been answered or you wish to remove from the queue, please press star two. If you are listening on a speakerphone, we ask you please lift your handset before asking your question to provide optimum sound quality. Again, if you have a question, please press star one on your touch-tone telephone. Our first question comes from Devin McDermott with Morgan Stanley. Good morning. Thanks for taking my question. Good morning. Good morning. 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 Tengizchevroil, and it's great to see the project progress there. With the WPMP portion of the project largely complete, I was wondering if you talk a little bit more about the remaining milestones for that second phase FGP as you progress toward that first half 2024 startup. Thank you, Devin, for both the retirement wishes and the question. With Tengizchevroil, 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. 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. 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 startup for FGP, where we will start to see incremental production coming through the plant. 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 from high pressure to low pressure. They'll be done kind of one at a time so we can maintain production through that period. 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 gonna be more important are just the rundown curves as we bring each system to completion. Great. Thank you. Very helpful and great progress there. Sticking with TCO and that part of your portfolio, there's been a lot of headlines around the CPC pipeline in recent weeks and months. I was just wondering if you could give us a status update on where things stand there. 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? 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. We've done a lot of work in Washington and Brussels to make sure people understand the importance of the pipeline to world supplies. We've seen the reliability overall still and the capacity 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 our export route for the crude. There are some alternate export routes being developed, but CPC remains the primary and most important route for us. Got it. Just to clarify, at the moment, operationally, at normal nameplate and flow rates through the pipe? Yeah, 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. 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. Great. Thanks so much. Thanks. Thank you. We'll take our next question from Neil Mehta with Goldman Sachs. Hey, good morning, team, and Jay. Thank you for all the insights over the years and wish you well in your retirement, sir. Thank you. The first question's on capital returns. You guys raised the top end, the buyback, guidance here. Just talk about the math that went into it and, you know, how you think about the optimal return of capital formation, whether it is through buybacks or dividend growth. 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. You saw that our total investments, first half of the year are 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%-25%. When we have cash in excess of those first three priorities, we buy back shares, and we intend to do it ratably over the cycle. We've repurchased shares 15 out of the last 19 years. We bought back almost $60 billion during that time at an average price around $90 a share, very close to the weighted average price during that whole time. As you said, 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 five 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%-25% guidance range. Pierre, the follow-up is just on the Permian. Could 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? Neil, I'll start out with that, and then Pierre can finish if he's got any other thoughts. The Permian, you know, 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. We're not responding to short-term price, but we are increasing our activity levels since the turndown during COVID. We have seen our investment go up. This year, it's $1 billion higher than it was last year. 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 two 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. I'll remind you also, one of our rigs today drills the equivalent of what two rigs could do in 2018. 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 frack crew today is also completing roughly double the work they were doing back in 2018. We're much more efficient than we were just four 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 nine net rigs running on the non-op side. That also contributes significantly to our production profile. Our guidance remains unchanged. We'd expect to see about 1.2 million-1.5 million barrels a day of a production ultimately as our plateau. As we continue to gain insights and knowledge, and as we look at our efficiency, 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. 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. Thanks, Neil. Thank you. We'll take our next question from Jeanine Wai with Barclays. Hi, good morning, everyone. Thanks for taking our questions. Morning. Jay, we'd also like to wish you well, and thank you for all your time over the years. We'll stick to two upstream questions just so we can get two last in before you leave. Thanks, Jeanine. Our first one is on LNG. This week, there was an announcement that Chevron, along with a couple other partners, that you guys reached FID on development that'll help boost Angola LNG plant volumes. 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? Is there a preference on how your involvement evolves with LNG plants? Because you have some equity ownership, but we also know that you had a SPA agreement that you announced recently that was more just on the marketing front. Just wondering how you're seeing your role there on new opportunities. That was pretty good, Jeanine. I think you got three questions in there, and I'm gonna try and move right through those. Oh, no, that was just one. I know. Teasing you. 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 two 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. 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. 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. 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. 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. 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. Where we can do commercial deals and not have to use capital, but to really be able to leverage others' 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 U.S. 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. Great. Thank you. We won't sneak in our, unrelated follow-up since that was a very wholesome response. Thank you. Okay. Thanks, Jeanine. Thanks, Jeanine. We'll take our next question from Doug Leggate with Bank of America. Thank you. 41 years in one place, Jay, that's pretty impressive. Congratulations, sir. Thank you. I wonder if I could take maybe two questions for you actually. Maybe Pierre might prefer the second one. I wanna go to the Permian first. You have about half your production operated and half non-operated. Can you parse between the inflationary pressures between your operated and non-operated, you know, from what you're seeing currently? 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 multi-year contracts and other mechanisms commercially that allow us to mitigate some of the inflationary pressures that we see today. 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. Just as a proof point, the last 800 wells over the last five 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 four central tank batteries. While others are having to invest in this high, inflationary period, we're largely using infrastructure that was built over the past five years with very small incremental surface facilities required. I think that's gonna be hard for others to match. That was a different answer, a very clear answer. Thank you. Pierre, I don't know quite how to ask this question. I'm gonna try and get a part A and a part B perhaps, but I'll be respectful. Mike was interviewed recently talking about the tightness in the global oil market, and I think he said something like, I know I put words in his mouth, but any weakness in oil prices is going to be fleeting because of the underinvestment. You guys obviously have stepped up your spending from COVID levels, but you're still well below pre-COVID levels, 2016-2019, let's say. With your balance sheet where it is and the depth of opportunities that you obviously have that you're not funding, how should we think about your, you know, continued commitment to the current CapEx level? Do we see Chevron reengage in organic growth at some point? You should think that there's no change in our guidance. 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-$17 billion of organic capital investments through 2026. Our budget this year is around $15 billion. We have $2 billion of room to increase activity and investment within the guidance. As Jay just described, our major capital project in Kazakhstan is winding down. It'll decrease spending by about $1 billion, and that opens up another $1 billion. We will increase investment and 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. 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 U.S. refineries through COVID and are making investment in that Pasadena refinery that was just recently FID'd. Of course, all the activities we're doing to grow new energies. We can do all of that within the guidance. 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. If we do that, there's more free cash flow for shareholders. Thank you. We'll take our next question from John Royall with J.P. Morgan. Hey, good morning. Thanks for taking my question. Can you talk about your growth in the Gulf of Mexico in the upstream? You're leaning in there with the number of brownfield projects. Can you just speak broadly on how you view GOM within your portfolio and how the returns look on those bolt-ons relative to your other options globally in the upstream? What does the service inflation picture look like in that part of your system relative to, you know, say, the Permian? Thank you, John. I'll start this and let Pierre add in. 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 six kg of CO2 equivalent per barrel produced. On a world scale, on even our company scale, which is already top quartile, it's right at the bottom end of that range. 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 water flood at St. Malo, which is part of the Jack/St. Malo complex. We've installed our multi-phase pumps and are commissioning those. That's gonna be an important milestone technologically in 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 three wells back to a host facility at Blind Faith and be able to develop that. 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 gonna see growth in our Gulf of Mexico production. It's gonna 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 tieback to this great chain of infrastructure that we have, and be able to produce this lower carbon fuel. Only added is our rigs were largely contracted when rates are lower. Clearly, offshore rigs have increased, but we're largely contracted at prior rates. Thanks, John. Great. Thank you. So on the downstream, just had a question on particularly California, just kinda your go-forward views there. Product balance is not quite as tight as they are in other parts of the country. You know, we're seeing some capacity come out due to RD conversions there. Just looking for maybe your medium-term view on refining and California specifically. On the downstream side, we had a strong quarter. Well, good execution, reliable operations, high refinery utilization. I'm talking generally now, U.S. West Coast and Gulf Coast. Good cost control, and we were able to capture the margins in the marketplace. We had a slight benefit in the second quarter because the Richmond turnaround was deferred. It's a little bit less of an impact than what we had guided to on the first quarter call. Timing effects really weren't a driver, right? It was more 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 U.S., a little bit higher on the West Coast, a little bit lower on the Gulf Coast. Didn't really see much on the diesel side, and jet is really tied to the recovery of travel. 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. Thanks, John. Thank you. We'll take our next question from Jason Gabelman with Cowen. Hey, thanks for taking my questions. 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 something that you're looking at. Then, I'll ask my follow-up after. Thanks. Okay, thank you. We have a lot of gas opportunities, and we've got a lot of infrastructure to build those opportunities on, which is really important 'cause 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 two kg 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, where it can 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's 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. 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 that area. It was very profitable. Even at the low prices, it's profitable now. Again, our focus is gonna be on discipline, on continuing to drive for those efficiencies. We really are excited to get Haynesville underway and add that to our portfolio in that part of the country. Thank you. Great. Thanks. My follow-up is just on the share count. I believe it went up again this quarter despite the buyback, and it's, you know, gone up since the buyback started. I think if you back out the shares issued for Noble, it's been flattish. Can you just discuss exactly what's going on there and your expectations for the share count moving forward with the higher buyback, but also at a higher share price? Thanks. Yeah. 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. You'll see in our queue that the share count at the end of second quarter is in fact lower than the first quarter, which you'd expect 'cause 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. 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. The math does work. It is going down. It's you have to look end of quarter to end of quarter. What you see in terms of, you know, 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 as share counts are going down. Thanks, Jason. Thank you. We'll take our next question from Manav Gupta with Credit Suisse. Thank you, guys. My first question here is I wanted to tap expertise from Jay again. This was a heavy turnaround quarter for you, but even then, some of the things that you were turning around were very high margin barrels for you. Whether it was Tengizchevroil, 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, you know, upstream results were good, but they could have been even better because some of the higher margin barrels were actually in a turnaround. I appreciate the question. You know, one of the things that's really important to us is that we operate safely and reliably. We look and we schedule our turnarounds, and they're predominantly to ensure asset integrity and ongoing reliable performance. When we schedule those, we don't like to shift those because of market conditions. 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. 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 Angola, in Australia, all five trains have been through the first round of turnarounds, 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. That's really how we think about this. Thank you. I have a quick policy question. About a month and a half ago, things got a little heated between the oil companies and the White House. As we understand, when the actual executive meetings happened between you guys and all others, and the Secretary of Energy, those were pretty cordial and you guys are looking for solutions out there. Help us understand what happened in the meetings with Energy Secretary and how did those go? Manav, we won't comment on the specifics of our engagements. I think you're right that it's constructive and productive. I'll point out our U.S. oil and gas production, first half of the year was up 7% versus last year. Our U.S. 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 U.S., more than double when you include REG. Chevron is growing energy supply, increasing investment, and we're engaging constructively with Congress and this administration. Thanks, Manav. Thank you. We'll take our next question from Biraj Borkhataria with RBC. Hi. Thanks for taking my questions. Just one from me on Australia. I mean, there's gas shortages in you know, 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 going to domestic market versus what's being exported or anything like that? Any color would be great. Thank you. 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. Actually the only way that we could supply any gas to the East Coast of Australia is in the form of LNG. 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. Okay, understood. Just 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. As you go through the various debottlenecking exercises. Are you able to provide an update on, you know, whether that's still in the works, where you are and what kind of timeline that would be on, if that's possible? 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. 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. You can see the improvement happening there. We have seen capacity increases at both Wheatstone and Gorgon, and I would expect those to continue as we move forward. Thank you. We'll take our next question from Sam Margolin with Wolfe Research. Hi. Good morning. Good morning, Sam. I wanted to revisit the LNG topic and maybe specifically tie it to the Permian, because, you know, there's just a lot of resource in the Permian that's not commercial, and that's, you know, that includes different zones of what you're already developing, plus, you know, areas that are not on your development calendar in the near term. LNG didn't historically help with that 'cause it's expensive, but obviously things have changed now. You know, I'd 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, you know, add some extra capital, or even commit to a spread, but, you know, monetize gas for a double-digit price. Look, what 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. 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. 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. 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. 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. Okay. I mean, maybe just to follow up, like, are there any ancillary factors that might be a consideration, like an opportunity to fit a, you know, another CCUS project on a facility or what it might contribute to, like, a flaring mitigation effort or anything, you know, besides just, like you said, a price signal? As Pierre said earlier, the Permian actually has very good carbon intensity on a Scope 1 and 2 basis. We're at 15 kg 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. Carbon capture, in particular, is critically important for not just us, but the world. We have three pilots going on at San Joaquin Valley operations to capture the CO2 that's coming off of our cogen units there. 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. 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. Thanks, Sam. Thank you. We'll take our next question from Irene Himona with Société Générale. Thank you. Good morning and congratulations on the strong quarter. 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. Irene, I said it very quickly earlier. I mean, we've seen, I would call it demand response to higher prices, that it, in the second quarter was around in the mid-single digits in the U.S. on gasoline. Again, a little higher on the West Coast, a little lower on the U.S. Gulf Coast. I think we've seen some recovery since 'cause prices have come off. We'll see where our third quarter ends up. On diesel, it's very hard to see. Not as price sensitive. It's tied to commercial industrial activity. Maybe a little bit of response at retail diesel. Then again, jet is largely tied to the recovery in air travel, and 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 kinda see the data. I mean, what's interesting is there's obviously concerns around a 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. If you look at that demand response on gasoline, that's in line or even higher than some past recessions. 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. 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, you know, scheduled and have pilots and all the rest, some of the challenges that have been happening over there. That's a little bit of 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. Thank you, Pierre. For my follow-up, 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 about the recent performance of the Gorgon carbon capture project. Is utilization improving? Is there any read-through perhaps on the technical side from that project to the ones you're launching now? Thank you. Thanks, Irene. At Gorgon, we've now stored successfully about 6.6 million tons of CO2 into that reservoir. 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. It's just, it's compounded a little bit because Gorgon sequestration is in a Class A nature reserve, so it is a very cumbersome process to approve additional facilities and additional wells. 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. 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. 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. Thank you. We'll take our next question from Paul Cheng with Scotiabank. Hey, guys. Good morning. Jay, may I add my congratulations and thank you for the help over the years. Really appreciate it. Thanks, Paul. Two questions. First, you touched on the inflation in different parts of your business, but Given your footprint, can you give us an overall view that what is Chevron's expectation on the inflation for next year? I know it is 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. Don't know whether that you agree with that assessment. If you can tell us that where you see along the supply chain is the biggest maybe pressure point and where that you see the least inflation. Repair shop. That's the first question. The second question on Mexico and Brazil. You guys entered, I think, a couple years ago and have some block over there, but I haven't heard you guys talk too much about those. Where those rank within your portfolio today, and what is the next step in those? Thank you. Thanks, Paul. I'll take the first, and then I'll hand it to Jay on the second. On the onshore U.S., we've seen cost inflation this year in the single digits. We've been able to mitigate part of that through good planning, smart procurement, and good relationships with suppliers. 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 U.S., we're seeing much more modest inflation than 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. We'll share estimates of what we're seeing in terms of cost inflation when we disclose our CapEx budget in December. We're just in the middle of that work right now. Feel very good that we'll have all the goods and services that we need, and we're finalizing our plans. Jay? Yeah, thanks. 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. As we do in exploration, we're always going through and looking for the next opportunities. I would say our focus primarily is shifting now towards Egypt and Suriname. Thanks for the question. Thank you. We'll take our last question from Ryan Todd with Piper Sandler. Yeah, thanks. Maybe first one on the biofuel side, you've 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? Thanks, Ryan. We're really excited to welcome REG's people to Chevron and Cynthia Warner to our board. She's already participated in our first board meeting. She's fantastic. Has great knowledge of traditional and new energy businesses, and is just a great add to our board. As I said, we've had some early wins. I won't get into the details of the commercial opportunities, but it's, you know, 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 two great teams together, we're seeing, you know, as you'd expect, one plus one is more than two. We've got our renewables 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 'cause we chose a convenience date of June thirtieth. All you'll see and all you saw in our earnings release, and you'll see on the Q, is just the purchase accounting. Starting in third quarter, we'll see REG in our results. REG had a good second quarter. You know, margins have been bouncing around, but the results are largely in line with expectations, and Geismar continues on track. Same thing with Bunge. You know, operating two crushers. Very excited to be part of that. Invested in CoverCress jointly, which is a crop that won't compete with food. Lots of work in this space as we work to get our renewable fuels capability up to 100,000 barrels a day. Still working on track to convert a diesel hydrotreater at El Segundo to have renewable fuel capability and work across other parts of Chevron's system. 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. Thanks, Pierre. Maybe the final one for Jay. Congrats on the retirement. I wanna ask kind of a higher level question on upstream project development and technology. I mean, there's been a pretty significant shift over the last five to 10 years in the way that you've approached project development, more standardization, oftentimes smaller, more capital efficient style projects. Ballymore is a great example of this. It's lowered the cost of supply a lot, especially in the deep water. As you pass the baton and look forward kind of into the next 10 years, are there things that you can see on the horizon, either strategically or technologies that may continue to drive, you know, changes in project development and technology that may drive things forward even further, whether it's, you know, 20K kit in the deepwater or SURF and flowline improvements that allow longer tiebacks and, you know, what could this mean for, you know, the future of your resource development portfolio? 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 'em. 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 in capital that we choose to invest. Getting more focused. The factory model has been really important to us. 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, in Argentina. 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. We're developing the capability for further and further reach. I mentioned earlier that Jack St. Malo is now putting into service multi-phase pumps. These multi-phase 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. Our focus on standardization, our focus on minimum viable facilities, our focus on capital efficiency over just scale and MPV, 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 gonna need going forward. 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. Hey, 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. 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. Thank you. This concludes Chevron's second quarter 2022 conference call. You may now disconnect.