Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's first quarter 2023 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 touchtone telephone. As a reminder, this conference call is being recorded. I will now turn the conference call over to General Manager of Investor Relations of Chevron Corporation, Mr. Jake Spiering. Please go ahead. Thank you, Katie. Welcome to Chevron's first quarter 2023 earnings conference call and webcast. I'm Jake Spiering, general manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. Please review the cautionary statement on slide two. Now I will turn it over to Mike. All right. Thanks, Jake. Chevron delivered strong financial results again last quarter, the seventh consecutive quarter with return on capital employed greater than 12%. This enabled another record for cash returned to shareholders while maintaining a strong balance sheet. Since our investor day 2 months ago, we've remained focused on executing our plans, achieving important milestones on our project in Kazakhstan, continuing to build activity levels in the Permian, positioning Bayou Bend to be one of the largest carbon storage projects in the United States, and safely and reliably delivering oil products and natural gas that help power the global economy. Next week, we'll publish our corporate sustainability report. I encourage you to review it on our website as we provide updates on the ESG topics that matter to our business and our stakeholders. In closing, while commodity markets remain uncertain, our approach is unchanged. Capital and cost discipline applied to advantaged assets in both traditional and new energy businesses and steady returns of cash to shareholders. You can see that consistency in our actions and our results. Now over to Pierre to discuss the quarter. Thanks, Mike. We reported first quarter earnings of $6.6 billion or $3.46 per share. Adjusted earnings were $6.7 billion or $3.55 per share. We had one special item this quarter related to changes in the Energy Profits Levy in the United Kingdom. The appendix of this presentation contains a reconciliation of non-GAAP measures. Strong operating cash flow enabled Chevron to deliver on its financial priorities during the quarter, a 6% per share dividend increase, higher CapEx within budget, net debt ratio under 5%, share repurchases at the top of our prior guidance range. Adjusted first quarter earnings were up over $200 million versus last year, despite 20% lower oil prices. Adjusted upstream earnings were lower, mainly due to realizations, and adjusted downstream earnings increased primarily due to higher refining margins. Both segments benefited from a change in timing effects. Higher interest income and lower accruals for stock-based compensation decreased all other charges. Compared with last quarter, adjusted earnings were down $1.1 billion. Adjusted upstream earnings decreased primarily due to lower realizations. Other items include the absence of last quarter's dividend withholding tax at TCO and lower exploration and transportation expenses. Adjusted downstream earnings were essentially flat. Lower margins and volumes were offset with higher chemical earnings and other favorable items, including trading results. Lower accruals for incentive-based compensation decreased all other net charges and also benefited the operating segments. First quarter oil equivalent production was down about 80,000 barrels per day from last year due to the expiration of a contract in Thailand and the sale of our Eagle Ford asset. This was partially offset by growth in the Permian. We expect 2023 production growth in the Permian to be back-end loaded as wells put on production, POPs, increase across both operated and non-operated areas. We expect our royalty production to be roughly flat. As discussed during our investor day, we're increasing activity in New Mexico. All four company-operated rigs added this year, one each quarter, will be in New Mexico, leading to more POPs expected in the second half of the year and into 2024. We also continue to be active in Texas. Last year, about half of our company-operated production was in the Delaware Basin in Texas, with the remainder split about evenly between the Midland Basin and New Mexico. More than half of our non-operated production is with five major operators in large contiguous positions in core areas of multi-year development programs where we have visibility to capex and execution schedules and a royalty benefit compared to the operator. The balance is with dozens of other operators, where we have a little less visibility but similar predictability from greater diversification. More than half of our royalty production comes from the Pecos River area in the heart of the Delaware Basin. The balance of our royalty position is in the remainder of the Delaware and Midland basins, also with well-known operators. In summary, Chevron has a large, diverse position in the Permian with a unique royalty advantage, where we learn from our own operations and from others. Looking ahead. In the second quarter, we expect planned turnarounds at Gorgon and in the Gulf of Mexico, along with downtime at an FSO in Thailand and a number of planned refinery turnarounds. We expect share buybacks to increase to a $17.5 billion annual rate. In summary, one Q was another quarter with strong financial results, continued capital discipline, and a steady return of cash to shareholders. We're confident that consistent and straightforward management through commodity cycles will create value for stakeholders. Back to you, Jake. That concludes our prepared remarks. We are now ready to take your questions. Please limit yourself to one question and one follow-up. We will do our best to get all of your questions answered. Katie, please open the line. Thank you. If you have a question at this time, please press star one on your touchtone telephone. You may ask one question and a follow-up question. If your question has been answered or you wish to remove yourself 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 touchtone telephone. Our first question comes from Devin McDermott with Morgan Stanley. Hey, good morning. Thanks for taking my question. Morning, Devin. There was some helpful detail, in the slides and the remarks on the breakdown of Permian operations. If I look at the quarter, your volumes did fall a bit sequentially in 1Q versus 4Q. I was wondering if you could just talk in a bit more detail about some of the drivers there, how things are going as you ramp New Mexico activity, and then specifically the confidence that you have in that back half-weighted production ramp. Yeah. Thanks, Devin. Pierre tried to show a little more detail, including breaking out co-op NOJV and royalty, talking about drilling activity and feet drilled, et cetera. Glad that was helpful. First quarter performance was a function of really the fact that NOJV and royalty production, which as you can see from that chart is, you know, a meaningful portion of our overall production, was down a little bit from fourth quarter of last year. You know, this gets a little lumpy due to how it gets reported by partners. You know, over time, it's trended up, particularly the NOJV piece. It was a little lumpy, and it was down first quarter versus fourth quarter last year. Co-op production was mostly flat from 4Q of last year to first quarter of this year. In terms of the full year outlook, on slide 9, you know, we show full year outlook. It's about 770,000 barrels a day. 2022 was a little bit over 700, 707, I think. Our co-op production will grow in the mid-single digits. NOJV, we expect to grow in the mid-teens. Royalty is roughly flat year-on-year as our expectation. That kind of lays out first quarter, and we still think that the guide we've given is appropriate, as Pierre said, you know, back-end loaded. We'll be updating each quarter on that. Got it. Makes sense. Thanks. My follow-up is on TCO, and it's exciting that we're now, you know, less than a year away from startup there. Back at the Investor Day, you noted that you had shifted to commissioning and the startup work for WPMP. I was wondering if you could just give us an update on how things are going there, latest expectations on timing, and then also the key milestones that we should be keeping an eye out for the balance of this year ahead of startup. Yeah, absolutely. I actually was in Kazakhstan earlier this month. I had a chance to meet with the president of the republic, some other senior officials, and also spent time down at Tengiz and visited the job site, talked to both people from our construction team, people from the commissioning team, people from operations as we're preparing for startup. I'll tell you, it looks a little less like a construction site and a little bit more like a plant than it did the last time I was down there. The progress is very obvious. You know, the headline I'll give you is there's no change to our cost or schedule guidance. We expect WPMP startup to begin by the end of this year. Now that's a conversion of the field from high pressure to low pressure. That will take some time as we take all the metering stations and field infrastructure down to low pressure, but that will still begin by the end of this year. The startup of, you know, the Future Growth Project, the portion that adds 260,000 barrels of oil production, that will begin by mid-next year. You know, both of these require a series of turnarounds and tie-ins and things like that. It's quite a complex set of activities to get us to the point where we've got everything online. There's a lot of work behind us. While I was there, we achieved mechanical completion on the third generation sour gas injection facility, which was ahead of schedule. There were a number of milestones that I mentioned or we talked about at the Investor Day that we've achieved. We completed tie-in of the fuel gas system to the first gas turbine generator. We fired that generator, so we know that it's working. In the second quarter, in terms of milestones to watch for, we're working to commission boilers, a steam system, other utilities that are required for the startup of the pressure boost facility, which is the key driver of that conversion from high pressure to low pressure field operations to enable, you know, sustained well deliverability. In the third quarter, we expect mechanical completion of the Future Growth Project. As I said, we'll begin start-up activities on the field conversion to low pressure by the end of this year. Those are some of the key milestones and, like I say, a lot behind us, but there's still a lot of complex work ahead. We'll be updating you on it every quarter. All good to hear. Thanks, Mike. All right, Devin. Thank you. We'll take our next question from Neil Mehta with Goldman Sachs. Yeah, thank you so much, Mike and Pierre. The first question is just around the LNG portfolio. A lot of volatility in the global gas markets over the course of last year. Just be curious how you guys are seeing the outlook and any updates on your portfolio, particularly down in Australia, where recognize you're gonna be taking some maintenance, but seems like it's operating pretty well. Sure. Look, overall, it's been a bit of a wild ride in gas markets over the last year. We've seen, you know, prices extraordinarily strong. If you go back 2 years ago, they were extraordinarily weak. They've certainly moderated now as we've had, you know, warmer weather in the northern hemisphere through the wintertime as the situation in Europe has, I think, become a little more stable. Certainly inventories both in Europe and in the U.S. are, you know, much healthier than people were concerned about it at one point in time. You know, we're into a market that still is perhaps strong by historic standards, but certainly not nearly as strong as what we saw you know, operations at Gorgon and Wheatstone are running very well. We had a record number of LNG cargoes go out of Australia last year. It was 10% better than the best year we've ever had. Reliability was first quartile for the two facilities. We feel good about that. We've started, or this year, we'll start the second turnaround cycle, which is a four-year cycle to turn trains around Gorgon train one. We'll have a major planned turnaround in the second quarter of this year. Of course, we're working on, you know, the next stage of field development to continue to keep the field full with wells drilled and start-up activity, tie-in activity, et cetera, underway on a, you know, the next phase of the gas developments to bring that into, you know, into the facility. Things in Australia are good from an operational standpoint and a reliability standpoint. More broadly speaking, you know, we continue to look at opportunities in our LNG portfolio beyond Australia. Certainly we've talked at some length about the Eastern Med, so I won't belabor that. You know, we've looking at, you know, concepts and expect to select a concept on the Leviathan expansion by the end of this year. In Equatorial Guinea, we're looking at opportunities to bring additional gas resources in through existing infrastructure. Continue to be very focused on what we can do to add value in our LNG business, but to do it in a way that's returns accretive. Yeah, that's great. Then the follow-up is just on return of capital and, you know, I think you guys have been pretty clear about the range that we should be thinking about from a buyback perspective. Just on dividend growth, just talk about how you expect that to track relative to your free cash flow per share expectations. Yeah, you know, on, I think we have been clear on buybacks, so I won't spend time on that. On dividends, you know, I would say our track record should speak for itself. Of course, these are decisions that are made by the board each year, but we've got 36 consecutive years now of higher payouts. Over the last 5 years, our dividend growth per share has been double that of our closest peer. We've sustained this not over the long haul, but also in the short term through the volatile period of time that we've seen. Our dividend track record, I think stands very well. You know, reiterate our 4 financial priorities, the first of which is to sustain and grow the dividend. As I just mentioned, 6% increase earlier this year and a compound annual growth rate of 6% over the last 15 years. You know, I think, you know, again, I'll say our track record on the dividend speaks for itself. I think Pierre mentioned that, you know, the quarter we just closed included the highest ever cash distributions to shareholders for the fourth consecutive quarter, that we can say that. We're very mindful of, you know, continuing to deliver cash in a predictable and consistent manner back to shareholders through both of those vehicles. Yeah. Thanks, Mike. Okay. Neil, thank you. We'll go next to Roger Read with Wells Fargo. Yeah, thank you. Good morning. maybe come back to the Permian a little bit. I know you've been providing us a lot more detail on things, and appreciate that, and the detail for the overall production breakdown in the U.S. Looking at the Permian, the Chevron-operated portion versus your JV non-op, as we think about some of the, you know, the snags that have been hit over the last couple of quarters. Where have been the biggest problems? Has it been in the operated or the non-operated? as you think about correcting those over the next couple quarters, you know, how much of that is Chevron control versus partner? You know, I will speak to our operated operations because I really can't speak on behalf of the others. They should speak on behalf of their operations. We certainly learn from those. You know, we spent a pretty good amount of time at the Investor Day talking about the learnings on drilled but uncompleted wells that had sat for a long time, talking about the prior basis of design for the wells, including spacing and proppant loading, talking about multi-bench development. We've learned a lot from our own operations, and those learnings are augmented by the things that we learn from others. We talked about more single-bench development, more activity in New Mexico. We continue to be very focused on driving strong returns, and not optimizing to production or some other metric. You know, just to give you a little bit more guidance, Roger, for this year in terms of how to think about it, you know, expect royalty production to be roughly flat, you know, in the neighborhood of, you know, a little bit over 100,000, maybe 110,000 barrels a day. Most of that comes from the Pecos River area, where we've got big operators, you know, Oxy's the largest operator in that area, but others that are, you know, well-known operators in that area. I know we've got to have some that comes in from the Midland as well, from big operators where there's a lot of visibility into what their plans are. Our co-op production growth, we expect to be mid-single digits for the full year, maybe a touch higher than the midpoint of single digits. And expect roughly 190 wells to be put on production this year, which is down a little bit from last year, maybe 10% from last year when our co-op production increased 35,000 barrels a day. We've got growth in the Texas side of the Delaware earlier in the year, the New Mexico side later in the year, which follows the chart Pierre showed you with drilling lateral feet In the NOJV, you know, the growth is higher. It's in the mid-teens for the full year. The gross number of POPs in our NOJVs are expected to be up about 15% year on year. It's interesting, our net POPs actually increase more than the gross because we have relatively high working interest and a significant royalty advantage in the non-ops. A 15% increase in gross POPs actually translates into more production than you might presume. We've got really good visibility into the execution schedule. We've received more than 3/4 of the AFEs for this year's activity, and operations have actually begun on more than 3/4 of the NOJV wells that we expect to be POPed this year. It's a mix. We've got, you know, a really strong but also a bit of a complex portfolio because of these three different contributors. We're continuing to hold the guidance, as I said earlier, to about 770 for full year. No, that's great. I appreciate that. Follow-up question I suspect is for you, Pierre. Working capital obviously, you know, tends to be a draw in Q1. You've got Sounds like a decent level of planned maintenance in Q2. Just any thoughts on how we should look at, you know, overall cash flow generation Q2, maybe rest of the year in terms of the cadence? Well, in terms of working capital, Roger, the 1st quarter, as you said, was a build on working capital draw on cash, and that was primarily inventory related. If you saw last year, we had draws on working capital. That was primarily through taxes payable, and you'll see in the second quarter, some of those payments happening. We try to give everything excluding working capital, because over the course of time, you know, that tends to zero out. There's a pattern, but there's some variability around it. That's the guidance I would give on you. In terms of free cash flow, it depends on, you know, and cash amounts depends on commodity prices and margins, and we gave a lot of that during our Investor Day, and some upside and downside cases. In terms of working capital, you'll see timing effects. We try to look through them and exclude them. Next quarter, you should expect some large tax payments, which will be obviously a draw on cash. Okay, great. Thank you. We'll take our next question from Paul Cheng with Scotiabank. Hey, good morning, guys. Morning, Paul. My every kind of project, due to their characteristic that we have different return and different payback period, criteria that I think management put. For your low carbon investment, not those that for the own emission mitigation activity, but that in terms of like CCUS as a new business. For that kind of business that what is the minimum internal way of return and payback period that you will assign in order for you to sanction the projects? Yeah, Paul. Look, the reality is these are brand new businesses, and we've got a lot of confidence in the returns and payback periods that we expect out of businesses we've been in for many decades and understand very well in well-established markets. These are businesses that don't exist today. They are in part enabled by a government policy, the rules of which are not yet fully written and the durability of which, you know, we need to ask ourselves questions about as we commit capital to it. They're different. They're very different. Our goal over the long term is to get similar returns out of these businesses as we get out of our core business. That would be double-digit returns. In the midterm to the near term, we're gonna have to go into some of these things that offer high growth and opportunity with our eyes wide open, but also understand that as we establish them in the early days, we may not see the returns that we expect in the fullness of time. We make big investments. Our expectation is over the life cycle of these investments, we're gonna deliver those kinds of returns. We're also mindful of the fact we've got to develop technology, we've got to scale these things, we've got to help markets mature, we've got to build operational experience, we've got to build risk management experience, supply chain and customer capabilities in these businesses. In the near term, we'll be, you know, understanding of the fact that the returns in the short term will probably look different than our long-term expectations, but we won't go into things that we don't believe offer the long-term prospect for returns, which is why we have steadily avoided more well-established sectors like wind and solar, where we could go into those today because the risks are better defined, but we also understand the returns. If we were just trying to do these kinds of projects, we would go into those, but they don't offer the kinds of returns we expect out of the things that we're working on. A second question is that, your largest U.S. competitor just announced that they're going to push more aggressively into trading and establish a single trading organization and think that there's quite a fair amount of opportunities out there in the market that they can capture. Essentially taking maybe that, somewhat of a playbook from. I think Chevron has always been a little bit more conservative on that. Do you think that really opportunity for a company similar to Chevron that have a lot of global reach and a lot of physical asset and have a knowledge edge over others, so is that an opportunity that we may be missing, that for Chevron? Well, Paul, what I would say is I think maybe your perception is a little bit miscalibrated from what I would describe. We have always had a global trading organization for many, many years. I used to run it. Pierre used to run it. We're an active trader. We trade in a certain way. I'll give you the three-word kind of overarching description. We flow, optimize, and trade. The first role of our commercial organization is to ensure our barrels and molecules flow to the market. The second is to optimize assets, ships, market positions, market knowledge, and be sure we get the most value out of our system that we possibly can. Then the third responsibility is to trade. We do third-party trading, we do, you know, what we call Quad 4 trading, on a regular basis. We make money at it, we have very talented people in our organization that do. We also have good risk management systems to ensure that we understand what we're doing. I wouldn't describe us as not being a trader. I don't know if there's a definition. I think you used the word conservative. Look, we're a, we're a trader, but we do it in the order that I just described and have done it for a long time on a global basis. It's a contributor to our earnings, we continue to look to grow that part of our business. Hey, the only thing I would add, Paul, to Mike's answer is shareholders and investors don't own Chevron or like companies for trading, earnings. They tend to be volatile. I think the multiples on trading earnings, you know, historically have been very low. In fact, most of the large trading houses are private companies. Mike described exactly what our strategy is. It works within the framework of a resource company and a refining and petrochemicals, company where investors are owning us for safely and reliably delivering energy, having the commodity price exposure. Yes, if we can enhance that with trading results, that's great, but we're not gonna lead with trading. Thanks, Paul. Okay. Thank you. We'll take our next question from Sam Margolin with Wolfe Research. Good morning. Thank you. This one's just a clarification question on something you said about the Permian, because I think it's important. In the NOJV section, because you stack royalties with the NOJV acreage, your growth rate in the NOJV portion actually exceeds the growth rate of your partners as they report it. That's the correct interpretation, right? That's what we're trying to communicate? Yeah. I mean, our because we not only get our working interest production out of that, but because we also have. We have relatively high working interest in most of our these ventures. It's not dissimilar to the working interest of the operator in most cases. We also have royalty advantage. We account for that, or we report that to you through that NOJV. What we describe as royalty barrels are pure royalty. We've got no capital, we've got no working interest, we're just collecting royalty as the landowner. You're correct in your interpretation there, Sam. That is why, our NOJV is growing a little faster than our co-op production for the same levels of activity. Okay. Thanks. Just as a follow-up, this is on capital allocation. You know, understood that you have the range out there in the buyback, but the range is pretty substantial. You know, there is a decision to make right now about where to be within the range, about whether to preserve cash for an opportunity that might come in a downturn if that's what looks like is on the horizon, or whether to stay at the top end because we're in sort of a market equilibrium in the commodity environment, and you feel good about the pace. I'm not asking you to predict the future, but it would be great to sort of hear your thoughts directionally about, you know, the value of kind of preserving cash on the balance sheet for a rainy day or, you know, maintaining a faster pace. Thanks. Yeah. I'm gonna invite Pierre to say a couple of words, but Sam, you know, we tried to lay out a couple of cases at Investor Day that showed you in two different price environments, what our capacity was to operate and be within the range. You know, with a low breakeven to cover our capex and dividend with a lot of surplus cash already on the balance sheet, and then with, you know, with the very low net debt, low debt levels that we have, we've got plenty of capacity. Pierre, maybe you just give a thumbnail recap on the scenarios to bookend them for Sam. In our Investor Day, we looked at the high case and low case scenarios, and our guidance right now is towards the high end. And let me just first be clear that we don't intend to hold, you know, $15+ billion of cash on our balance sheet. We can run the company at with $5 billion, and this is surplus cash, and this is cash that is temporarily on the balance sheet. It will be redistributed and redeployed to shareholders over time, depending on the scenario and the price. Both scenarios had us working down that surplus cash because it's economically inefficient for us to hold it. It's not our cash, it's our shareholders' cash. We wanna return it through the cycle in a steady way, not procyclically. That's why it's accumulating. We've paid off all our debt economically, but it's a timing effect. We showed certainly in the low side case, which averaged about a $60 Brent, that we could continue buybacks near the low end of the range. We can do that by taking surplus cash down and then also using some of our excess debt capacity because we're well below our 20% to 25% net debt ratio. We'd wanna work towards that low end of that guidance range of 20%, again, to get to a more efficient capital structure. In terms of keeping cash for a rainy day, or a strong. We're always gonna maintain a strong balance sheet. We've been in this business for decades and decades. We know the good times don't last. We know that prices are cyclical. We wanna manage that volatility for our shareholders, so our shareholders don't have to worry about the commodity price because they're gonna get the dividend that Mike talked about that's been growing for 36 consecutive years, that's grown 6% annually for 15 years. They're gonna get that. Through a cycle, as we approach a cycle, and we're looking at the cycle coming up here, additional cash in a steady way, right now about 5% of our shares outstanding through the form of a buyback. So that's how we're planning to manage the volatility for our shareholders. We've talked about if M&A is implied in your question, that we've shown that we tend to use equity for M&A because there is commodity prices are volatile. It creates a more stable deal structure. Our balance sheet will always be strong enough to enable us to not only manage commodity prices but also make sure we're positioned to do what we need to do. I don't need to remind you that we were the first to do a transaction coming out of COVID, when we announced the acquisition of Noble Energy, and then we followed, a year or so later and acquired Renewable Energy Group. Thanks, Sam. Thank you. We'll take our next question from John Royall with JP Morgan. Hi. Good morning. Thanks for taking my question. Can you talk about the general demand trends you're seeing within your system? Are you starting to see any signs of weakness on the demand side? If the answer is no, just curious on your views on what's happened to spot refining margins globally and what seems like still a relatively tight market. Yeah. John, a couple of thoughts, I guess. I'll just go by, you know, the product commodities. I mean, gasoline demand is essentially back to pre-pandemic levels globally. Obviously, there are regional variations in this. You know, we're sitting in California here on this end of the call. We've had a very wet winter, the first quarter, you know, reflects, you know, an unusually, you know, wet season on the West Coast. In Asia, we see demand coming back, right, as economies continue to open up and mobility has increased, et cetera. Broadly speaking, gasoline, flat. Diesel had kind of carried the complex through COVID and global demand has been at pre-pandemic levels for a while now. First quarter demand in 2023 is a touch lower than it was in first quarter of 2022. Could be an indicator of the beginning of some economic slowdown. You know, it's certainly, you know, I think premature to conclude that. Diesel is maybe not leading the parade quite as strongly as it had been for the last couple of years. Jet demand continues to growAnd, it's still below, you know, kind of pre-pandemic levels. China's the place, obviously, that everybody has been paying attention to. Domestic travel up to nearly 90% of pre-COVID. Flights in and out of the country still well below that. We see flights being scheduled. You see, indicators that suggest travel will grow. You listen to the airlines, and that certainly seems to be what they anticipate, but that's in progress. That's a kind of a quick look across the product slate. You know, I think margins reflect a couple of things. One, a year ago, you know, we were in a period of, you know, recovering economies and, we're coming out of a period of rationalizing refining capacity around the world. You can go to any part of the world and find refineries that had shut down that perhaps, you know, people expected would close one day, but it happened relatively quickly. At the same time, you saw big growth projects that had been deferred because of the uncertainty relative to COVID. A year later here, you don't see refineries closing at the same rate. We've seen refinery startups in the Middle East. We've seen, you know, projects here in the U.S. and in Asia as well. Refining capacity coming into the system, demand has moderated a little bit. Margins have come down. They're still stronger than historic margins if you look out over a longer period of time, but trending back down towards mid-cycle. Pretty strong in the U.S., maybe under a little more pressure in Asia, but you gotta think about the feedstocks in Asia, where they're coming from, how they're priced, and how those markets are working. You know, I don't see any big warning signs flashing, but certainly, you know, we're paying close attention to it. Very helpful, Mike. Thank you. Maybe sticking with the downstream, and you mentioned California. Can you just talk about the new regulations in California around the potential for excess profit penalties? Not sure if that's exactly how to refer to it, but, how much does that impact how you think about refining in California and your position in California and, maybe the expected impacts on the broader market there? Yeah. I'll talk about it, sure. You know, the bottom line is this is now into a rulemaking process. There's no impact right now, and it's into kind of a bureaucratic phase. I think implementation is likely to take quite a while, and it's hard to say exactly how it plays out. You know, What started as an effort to create a windfall profits tax was unsuccessful because you need two-thirds of a vote in the legislature for a new tax in California. That then modified into, you know, some other forms and ended up moving into the Energy Commission, where there'll be a, you know, a group established that will gather a lot of data and try to assess the profitability of the industry against some standard which I think is yet to be, you know, fully articulated. This is gonna take some time. It could potentially result in some sort of a fine or a penalty for margins or profits above a level, but I can't tell you how it's gonna play out because it's there's a lot of work to be done there. I guess the things that I would say are pretty predictable are maybe two. One, there are substantial new reporting requirements, and so there's a lot of data we're gonna have to produce. We're happy to do that. We'll work closely with the Energy Commission to make sure we get them the information that they're requesting. The second is, I don't think this does anything to encourage investment or new supply, which is really what's needed in a marketplace, a commodity market, to bring prices down on average over time. In fact, I think it runs the risk of doing the opposite, of discouraging investment, of decreasing supply over time, which if demand does not moderate, will tend to exacerbate volatility and over time probably result in, on average, higher levels of price. That's about all I know about it at this point, and we'll watch it as it unfolds. Thank you. Thank you. We'll take our next question from Doug Leggate with Bank of America. Hey, good morning, guys. This is Kaley on for Doug. Thanks for taking the question. The first one is on the new Permian disclosure. You guys are forecasting flat royalty volumes, so I'm wondering, as that becomes a smaller part of the production mix, how is the cash margin from that asset affected going forward? Well, the royalty barrels have essentially an infinite margin. I think, you and Doug can do the math as it's a slightly lower% then that'll be a part offset. There's lots of other drivers that we're doing to enhance margins. We've shown return on capital employed near 30% at $60 Brent equivalent for our premium. It's a high return, low carbon asset. The royalty barrels, as you know, come with virtually no cost, and that's part of the advantage that we have. Understood. I appreciate that, Pierre. My second question goes to TCO. Just wondering if we can get an update on timing of first oil from the new expansion project and the dividend magnitude for 2023. Yeah. The expansion project, as I said, there's a lot of turnarounds and activity both this year and next year. At our Investor Day, we laid out a bar chart that gave you an idea on production. The real, I think the time, as I said earlier, when you're gonna see the production growth will manifest itself in 2024 because the next 2 years we've got a lot of these turnarounds, tie-ins, et cetera, in place. Pierre, you can guide on dividends. No, no change in our affiliate dividend guidance that we shared on the last call of $5 billion-$6 billion for the full year. That includes Tengiz and our other affiliates. We expect, like last year, a dividend in the second quarter that'll be modest and then a larger dividend in the fourth quarter. TCO continues to hold more cash on its balance sheet to manage through both completing uncertainty around the project and around transport alternatives. That cash will come back over time. It's been performing very well. We don't give specifics on that by year. It's embedded in our overall affiliate dividend guidance. I appreciate that there's still some turnaround to work through, as the production hits a steady state, what do you expect the dividend cadence to look like? As I said, last year, it was in 2 quarters. This year, again, it'll be second quarter and fourth quarter. It's up to the TCO board of directors to make dividend decisions going forward. Hey, thanks for your questions. Our next question comes from Josh Silverstein with UBS. Hey, thanks. Good morning, guys. Just curious about the pace of rig activity in the Permian. You guys are adding 1 per quarter this year. A lot of that's going to be to support growth next year. I'm just curious, as you're continuing looking forward into next year, do you need to add 4 more rigs next year to keep kind of that 10% growth pace? Is it less because you're getting more efficient in the Delaware production? I'm just curious how you're thinking about the step up in activity going forward. Yeah, I mean, we've pulled rigs down dramatically in 2020, and we didn't wanna surge back with everything all at once. You know, we entered this year with 10. We expect to exit this year with 14 co-op rigs running. I think, you know, consistent with the longer-term production profile that we've outlined, you know, we got a big base business that does have decline underneath it, and so you're, you know, you can expect us to add some additional rigs as we move into 2024. Got it. Then I know there's a lot of activity stepping up across the rest of the kind of lower 48, Haynesville, DJ. They're a little bit more on the gassier side. I'm curious if you guys are pulling back any activity because they're a little bit more gas-prone in this price environment. Thanks. We're adding a rig in the Haynesville. We talked about that for a number of years building up to that activity. You know, gas prices are gonna be volatile, and frankly, we need to get developing that resource. We have some offset operators, if we don't get after it's a time for us to do that. The DJ still has a heavy liquids component, no change in our plans. In In fact, the DJ in Argentina are a couple of other areas where we expect production in the second half of the year to be higher, where we're increasing a little bit of activity. Again, all of that's within our existing CapEx budget. Thanks, Josh. We'll go next to Ryan Todd with Piper Sandler. Great. Thanks. Maybe first off, just a quick follow-up on the comments earlier on and the question on trading. In the international downstream, your earnings were particularly strong this quarter, and I think in the slides there's a $270 million other BAR, positive other BAR on the chart there. Is that primarily trading? Anything to read on that going forward? Is that something that likely reverses? Or, maybe some clarity there. You're right. We refer to it. I would not say it's primarily. It's a lot of factors, and we pointed out to that. It's consistent with how Mike described our trading business. As all trading businesses are, it can be variable in future quarters. It's just one of many factors. It's not primarily, but we wanted to cite it as one of the elements in that other variance. Thanks, D.A. Then maybe, on the Permian, if we look back at the Permian, you obviously talked, and at the Analyst Day, you talked about a variety of the shifts in the 2023 development plan versus 2022. I think, and you highlighted some more here today, I think we appreciate some of the near-term impact. Can you talk at all to what some of the longer-term implications are of, you know, the shift to more single-bench development, adjustments to spacing, more shifts towards New Mexico, et cetera? Does it have any impact on? Like, does the move to increase single-bench development have any impact on the productivity or recovery of other zones in the area? Does it change at all how you think about service infrastructure and logistics? How you think about resource depth in different parts of the portfolio over the long term? Yeah, Ryan, I would say not really. You know, we've always been returns seeking. This is all about optimizing the return we can get out of this asset over the long haul. We've tried to be thoughtful about surface infrastructure. We've tried to be thoughtful about drilling to keep surface infrastructure fully utilized, not overbuilding it for peaks and then leaving it underutilized for long periods of time. As we're, you know, continuing to learn, the fundamental principles about optimizing return on investment continue to drive all of this activity. You know, as we learn more about benches, about communication, about productivity, as technology changes recovery factors, we will continue to apply all of those learnings. But the real objective remains the same. It's not volume, it's value and returns. Hey, Ryan, just as a reminder, the move to more single bench is in the Delaware Basin, right? Midland Basin, three-quarters is multi-bench development. All right. Thanks, guys. We'll take our next question from Jason Gabelman with TD Cowen. Hey. Morning. Thanks for taking my questions. Sorry to go back to the Permian, but I'm gonna ask another. I was wondering, and I appreciate all the disclosures, they're really helpful, but in terms of the non-op component of production, does the proportion stay relatively stable through your forecast period? I think, you gave a forecast out to 2027 at the Analyst Day. Does the non-op proportion stay the same, or do you have more operational barrels between now and 27? You know, it stays, relatively similar, I would say, Jason. We can, you know, provide further insights on that as we have a few. There's not a big shift. We're growing activity, as I mentioned earlier, we're adding rigs and you got a pretty big base you're adding in on top of. Those percentages don't move a lot. All right. That's helpful. Then just one accounting question. Depreciation fell decently quarter-over-quarter in upstream. What was that related to? Are you looking at it excluding special items? Yeah. If I look at the quarter-over-quarter slide 7 upstream DD&A was positive $345. Yeah. Why don't you follow up with Jake? That could be tiresome exploration activity. Okay, thanks. We'll take our next question from Biraj Borkhataria with Royal Bank of Canada. Hi there. Thanks for taking my question. I wanted to ask about Namibia. You recently farmed in a few months ago. Could you just walk me through, you know, plans for the next, you know, 12 months or so, what you've got penciled in? I've got a follow-up on something else. Thank you. Sure. We've completed seismic acquisition in Namibia at the end of February, and that's being processed right now. I can't really comment any further on that. We certainly are mindful of others who have had certain exploration success in the region, which is encouraging. We need to do the work on that and then, you know, determine, you know, what the next steps are, which can include drilling exploration wells. Stay tuned on that. As we got more information, we'll share it with you, Biraj. Okay. Just on a different topic, cost inflation, 'cause more and more you hear, some of the service providers talking about improving pricing and so on. Could you just comment on your latest thoughts and what you're seeing on the cost inflation side outside of the lower 48? Thank you. Sure. Really no change to our mid-single digit inflation guidance in our current year capital spending. As you note, in the lower 48, there are some areas where, you know, we planned for higher inflation and are seeing that. I'll remind you that a lot of what we do in our, you know, procurement activities are longer term contracts that are either fixed price or index based. We've got detailed cost models to challenge price increases. We commit volumes to certain things over longer periods of time to try to create a win-win between us and our suppliers. We've not seen some of the cost push through that you would see if you were buying services or commodities inputs on a spot basis or then current basis because we manage that activity differently. You know, for instance, on offshore rigs, you know, we're fully contracted for this year. We came into the year with three rigs working in the Gulf of Mexico. They're generally below current market rates. I think we're managing this well. The one thing I would say is, given these kind of index-based contracts, there are periodic reviews where we will reset based on market indicators. You know, in the second quarter, in certain parts of our business, we'll be going through this with some of our partners, and we'll see some resets on there that'll probably reflect a little bit of the inflation that I referred to earlier that's already built into our plans. I think we're managing all that within the range that is embedded in the guidance we've given you. Great. Thank you very much. Thank you, Biraj. Thank you. We'll take our last question from Neal Dingmann with Truist Securities. Hi, this is Patrick entering on behalf of Neal Dingmann. For my question, it's with respect to Venezuelan exports. I know previously you'd made mention of real no further capital investment in Venezuela. What we're curious to know is there a maximum threshold of export and sales that you're anticipating out of Venezuela? Is there a maximum? I mean, it's limited by, you know, our position there and the entities that we're involved in and what our portion of that, you know, production that we're entitled to market is. You know, we're currently seeing about 100,000 barrels a day of production up from about 50 when the license terms changed. That could go up further this year, maybe another 50% if everything goes well. You know, the crude comes to the U.S., and we're finding a market for the crude. Yeah, it's a six-month license from OPEC, and we have to bear that in mind. That's why we are proceeding, as you said, which is, you know, we've got some past receivables that are being paid from some of these proceeds. There's a lot of, you know, relatively straightforward work over and other activity that can help bring production up at, you know, without major capital commitments. That's, that's the current model. We'll, we'll see how things unfold and hopefully point it in a good direction. It's been, you know, it's been a bit of a, an up and down situation and we have to, you know, we just have to take this one step at a time. It's tough there. I guess, just as a follow-up, would there be, Are you exploring that six-month term? Are you looking to extend that at all, or is it too early to be negotiating on that? You know, that's a decision made by the U.S. government. It's not really a negotiation. It's their decision, and it's a, it's a policy matter. We're asked for input, and so we provide input on these things. For the last several years, these things have had relatively short time lines associated with them. So we're in full compliance with all the conditions of the sanctions and intend to stay that way. We'll just see how the, you know, how the policy making turns out. All right. Good to hear. Thanks very much. Hey, this is Pierre. I'm gonna go back to Jason's question. Yeah, lower depreciation is really 3 drivers. Some of it was the absence of some abandonment accruals that were in the fourth quarter, you can view those as sort of non-recurring. Some of it is due to new rates. Each year, we revise our depreciation rates based on additions to approved reserves, and those rates are a little bit lower. Of course, first quarter production was a little bit lower than fourth quarter production. Lower volumes also contributed to that lower depreciation. Tech, I would like to thank everyone for your time today. We appreciate your interest in Chevron and your participation on today's call. Please stay safe and healthy. Katie, back to you. Thank you. This concludes Chevron's first quarter 2023 earnings conference call. You may now disconnect.