Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's Fourth Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' remarks, there will be a question-and-answer session and instructions will be given at that time. 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.

Welcome to Chevron's fourth quarter 2023 earnings conference call and webcast. I'm Jake Spiering, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth, and CFO, Pierre Breber, are on the call with me today. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. Reconciliation of non-GAAP measures can be found in the appendix of this presentation. Please review the cautionary statement on Slide two. Now, I will turn it over to Mike.

Thanks, Jake, and thank you everyone for joining us today. Chevron delivered another year of solid results in 2023. During a time of geopolitical turmoil and economic uncertainty, our objective remained unchanged: safely deliver higher returns and lower carbon. Our clear and consistent approach resulted in an adjusted ROCE of 14% and enabled a record of $26 billion in cash return to shareholders while growing production to accompany a record. We also successfully integrated PDC Energy and announced the Hess acquisition. We're now focused on the FTC's second request and expect to file the draft S4 later this quarter, with closing anticipated around the middle of the year, and we continue to take action in lowering the carbon intensity of our operations and growing lower carbon businesses, advancing foundational projects in both hydrogen and carbon capture. Over the past five-year commodity cycle, with prices high, low, and everywhere in between, Chevron led the peer group in what we believe are the most important measures that create value. We were the most capital efficient while managing unit costs well below inflation and many peers. Capital and cost discipline always matter in a commodity business. Combining this discipline with our focused portfolio of advantageous assets, Chevron was able to lead the peer group in returning cash to shareholders. Our five-year dividend growth rate was greater than the S&P 500 and more than double our nearest peer. Surplus cash was returned to our shareholders in each of the past five years through share buybacks. Our track record has proven, and we intend to continue growing value for our shareholders in any environment. In the Permian, we delivered on our full-year production guidance. Instead, a quarterly record of 867,000 barrels of oil equivalent per day while building our DUC inventory in the fourth quarter. Looking to the year ahead, our program is back-end loaded as we plan to continue to build our DUC inventory before adding an additional completion crew in the second half of the year. As a result, we expect production in the first half of the year to be down from the fourth quarter by about 2% to 4% before climbing toward a 2024 exit rate around 900,000 barrels per day. Chevron is a clear leader in Permian financial returns in the Permian with our unique royalty advantage and strong execution across a diverse portfolio. We have strong momentum and expect to achieve one million barrels of oil equivalent per day in 2025. At TCO, we’re making progress towards the first phase of WPMP FGP start-up. The slide shows how the project fits within the overall field and facilities. The field, currently flowing at high pressure, continues to keep the existing plants full. In fact, 2023 net production was the highest since 2020. We’ve completed a lot of project scope that is already operational. TCO is producing from the new wells. The upgraded and new utilities, gathering system, control center, and power distribution system are all currently in operation. For WPMP, we’re focused on starting up major equipment – including gas turbine generators, pumps, and compressors. We expect to hand over to operations the first pressure boost compressor in March for final dynamic commissioning. Once we have PBF compression online, WPMP start-up is expected to begin in the second quarter when the first metering station is converted to low pressure, which will enable increased flow rates. Low pressure production streams going back to existing process units will be driven by the pressure boost compression. At the same time, production from metering stations not yet converted will continue to flow in the high-pressure system. We expect metering station conversions through the remainder of the year as additional pressure boost compressors start up, keeping the existing plants full around planned KTL and SGI turnarounds. For FGP, we’re focused on starting up additional gas turbine generators and compressors along with multiple processing units. The sour gas injection facilities have already been handed over to operations for final commissioning. FGP start-up is expected in the first half of next year when incremental production enabled by field conversion to low pressure will be processed in the new 3GP facility. Since last quarter, two boilers came online, and two gas turbine generators have delivered power. We’ve seen improvement in work scope delivery and have been working through additional discovery items. We’ll continue to update you on progress and remain focused on key milestones to deliver a safe and reliable start-up. With that, I’ll turn it over to Pierre to discuss the financials.

Thanks, Mike. We reported fourth quarter earnings of $2.3 billion, or $1.22 per share. Adjusted earnings were $6.5 billion, or $3.45 per share. Included in the quarter were $3.7 billion in charges pre-announced in January. Foreign currency charges were almost $480 million. Our 2023 CapEx included $650 million of inorganic acquisitions and around $450 million invested in legacy PDC assets post-closing. Excluding these items, CapEx was about 5% above budget after three consecutive years below. Share repurchases matched the third quarter. Our balance sheet remains strong, ending the year with a net debt ratio comfortably in the single digits. Turning to the quarter, adjusted earnings were higher than last quarter by roughly $730 million. Adjusted upstream earnings improved due to higher liftings, in line with record quarterly production, and favorable timing effects. Adjusted downstream earnings decreased on lower refining margins, partially offset by a favorable swing in timing effects. All other benefited from lower corporate taxes and employee costs. For the full year, adjusted earnings decreased nearly $12 billion compared to the prior year. Adjusted upstream earnings decreased primarily due to lower prices. Adjusted downstream earnings were lower largely due to declining refining margins. Other segment earnings improved on lower employee costs and higher interest income. Solid financial performance enabled Chevron to deliver, again, on all four of its financial priorities. We announced an 8% increase in our dividend, reflecting our confidence in expected future free cash flow growth. We maintained capital discipline in both traditional and new energies. We reduced debt by over $4 billion, including all debt assumed in the PDC acquisition, and we repurchased about 5% of our shares outstanding. Last year, we produced more oil and gas than any other year in the company’s history, including a record number of LNG cargoes out of Australia. We expect 2024 production to be higher again, by 4% to 7%. Our plans include production growth in the DJ Basin, with a full year of legacy PDC operations and continued organic growth in the Permian. Our guidance this year includes an estimated impact from asset sales as we further high-grade our portfolio. Looking ahead, our first quarter downtime estimate includes around 20 thousand barrels of oil equivalent per day associated with January’s cold weather in North America. Earnings estimates from refinery turnarounds are mostly driven by Pascagoula. Share repurchases in the quarter will continue to be restricted under SEC regulations. Depending on commodity prices and margins, affiliate dividends are estimated around $4 billion, roughly flat with last year. We do not expect significant affiliate dividends in the first quarter. The difference between affiliate earnings and dividends is expected to decrease in the second half of the year after TCO’s start-up of WPMP. Our CapEx guidance range is unchanged from the December budget announcement. In prior years, our CapEx rate in the first half of the year was about 20% lower than the second half. Our price sensitivities have increased at higher production levels. About 20% of the Brent sensitivity relates to oil-linked LNG sales and less than 10% relates to North America natural gas liquids. Back to you, Mike.

In closing, our priorities are clear: Safely execute with excellence, maintain capital and cost discipline; and return cash to shareholders. We’re excited about the pending Hess acquisition, which will further strengthen Chevron. I also want to personally thank Pierre for his invaluable contributions over his 35-year career with the company. He’s been an exceptional strategic partner to me and an outstanding leader, helping guide Chevron to create significant value for shareholders. I wish him all the best in his retirement. I’ll now hand it off to Jake.

That concludes our prepared remarks. We are now ready to take your questions. We ask that you limit yourself to one question. We will do our best to get all your questions answered. Katie, please open the line.

Our first question comes from Biraj Borkhataria with RBC.

Hi, thanks for taking my question and firstly, Pierre, congrats on a great career and all the best for retirement and thanks for all the help over recent years. I feel compelled to ask you a question on buybacks because it's your last time, but I'll try and resist. So the question's on the Permian. You had a very strong production number in Q4, quite an inflection from what we've seen in the last few quarters and I was interested in particular the comment on that volume growth alongside building the DUC inventory. So presumably the non-op side was a nice contribution in Q4. Could you just give some clarity on the bridge sort of 3Q to 4Q because the market has been concerned about you hitting the number of the lease for this year most recently. Thank you.

Sure. So, in the third quarter, non-op was a little light, but in the fourth quarter, it came back. It didn't end the year. Non-op and royalty are right where we guided to from the beginning of the year. So, throughout the year, the quarterly ups and downs on some of these things, can create some questions, but it came in right as we guided to it in the mid-teens. The story on the fourth quarter was really strong execution. We had more POPs because we had faster drilling and faster cycle time on completions. We had a shorter cycle time from frack to POP. So all of those increased, and as you noted, we did continue to build our DUC inventory because drilling performance was so strong. A couple other things, POPs in the fourth quarter were weighted towards New Mexico. We had guided towards activity that would lead to more POPs in New Mexico in the second half of the year. Those wells are more productive than kind of on average than the rest of the portfolio. So that flows through. And then the final thing that I would point to is we had higher reliability. You'll recall in the third quarter, we talked a little bit about some midstream constraints and other things that weren't related to completions or POPs or anything else, but they were constraints on flow. We had fewer frack hits. We had fewer scheduled delays, weather downtime, and midstream issues in the quarter. So all of that contributed to the strong performance there in the fourth quarter, and we ended the year right on our guidance.

Yeah, thank you so much, Pierre. You're going out in style, and thanks for all the great insights and wisdom over the years.

Thanks, Neil. My question's on Slide six, the TCO update. It sounds like the schedule and the cost guidance that was provided in November are still on track, but for us non-engineers, maybe, Mike, you can kind of walk us through the schematic and help us understand what of these boxes are the critical path issues that we should be focused on.

Yeah. So, you're right, Neil. The schedule and cost guidance is unchanged. I apologize for a more complex slide than we usually put out in front of you, but we want to be as transparent as we can and help people understand what's going on there at the field. Last quarter, we talked about our action plan, and we're seeing improved productivity. We've shifted scope amongst contractors. We've added more engineering support in the field and as we move through this, we're encountering discovery work, as we expected. We found some around piping stress and alignment that we're working on right now. The key thing to think about here is, first of all, there's a lot of stuff that's up and running. All the new wells are producing right now, and all this infrastructure, in terms of utility and power distribution and control center, is up and running, and so that's keeping the plants full, and we saw really strong performance last year. I mentioned the strongest in four years and the fourth strongest in the history of the field. So, we're seeing good deliverability out of the new wells, which is the key thing for production this year, is keeping those plants full while we begin to convert the field from pushing into a high-pressure plant to lower back pressure on the field, which improves deliverability from the wells and allows us to extend the life of the field and get up to a million barrels a day. So when we begin converting these metering stations and there are 21 of them, we will then take production from a metering station now that is producing under low pressure and we'll boost that back up to get into the existing plant. As we get more and more of those converted, more of these pressure boost compressors online, we'll get the whole field now producing against the lower back pressure, which gives us a lot of excess well capacity and ensures that we are going to keep the plant full, and as we then bring on the new process equipment, we start to route that low-pressure production into a plant that will run at lower pressure. And so that's really the kind of high-level description of what we're trying to convey there, and we've got a legend that shows you certain things are going to begin start up in various quarters. For FGP, we're focused on commissioning the major equipment there that will allow us to bring up the plant that will take us to a million barrels a day, and we're transferring learnings from compressors, pumps, and other things that we're working on now, walking down all the critical substations, and we'll continue to provide updates on the key milestones here. We're talking about a couple of gas turbine generators online. First quarter is the Inlet separator is ready for operation and we'll commission that on sweet fluids as we prepare it for sour production, and then, as I said, in the second quarter, we begin the PBF startup and metering station conversions. So it's all on track with our guidance, and we will continue to provide you detail as we move forward each quarter on specific milestones and progress.

Thank you. Good morning, Pierre. I have to offer my congrats as well and with the quarter today, thanks for making us in the sales side look smart. It's a nice way to go out. So best wishes in retirement.

Thank you, Doug.

My question, Mike, is I guess it's got a part A and B, so apologies to Jake on that, but it's kind of around disposals. Our understanding from the Hess side is that despite the fact that you haven't filed the S4 yet, you haven't got the FTC yet, and I realize those processes are ongoing, but the integration planning is still going ahead full steam, and I'm just curious if you can offer any color on how that process has evolved as it relates specifically to portfolio high grading. The absence of Malaysia in your go-forward plan, for example, it seems to me the $15 billion number might have a lot of upside. So any color you can offer on that topic, please.

Yeah. Doug, it's really premature for us to comment on that until the transaction closes. Hess has a pretty tight portfolio of assets that are performing well and we really need to close the deal, have access to all the data and re-optimize all of our views of portfolio investments and update our new plan and so I don't want to speculate on any assets, and look, we've got some of our own assets that we do have out in the public domain already. You may have seen reports on Kaybob Duvernay on Congo. So, there are some divestments that we have signaled out of the Chevron portfolio, and I think as you see the divestments unfold over the next few years because we will have more assets in the portfolio that come from Legacy Chevron that is likely to be a greater contributor, I would guess to the overall $10 billion to $15 billion number than things that come in through this transaction, but I can't comment on Malaysia or any other particular asset until we get past the close.

Thanks. Good morning, guys. Going back to the Permian, you're stepping up the CapEx this year to about $5 billion versus $4 billion last year to help you deliver the year-over-year growth. As you continue to ramp towards the million BOE per day target, what's needed from a CapEx standpoint to deliver this growth? Can you stay closer to the $5 billion range or does that step up towards $6 billion in 2025 because you have an accelerating pace to hit that? Thanks.

Yeah, no. Appreciate the question, Josh. We're starting this year with 12 rigs and three frack crews. I mentioned we'll add a fourth frac crew around the middle of the year, but at the same time, we're becoming more efficient. We need fewer rigs to drill the planned lateral feet that we've got out in front of us, and so, as we close in on a million barrels a day, we're at the capital level that I think is going to be required to get us there. And then the really nice thing about this is when you're trying to hold the plateau as opposed to grow from seven to eight to nine hundred, 700, 800 to 900 to a million a day, you actually can pull capital spending down because you're offsetting decline. You're not trying to offset decline and grow by significant chunks each year, and so inflation has moderated and that has been a challenge. We've talked about some of the things we're moving water around a little bit more, but that's embedded in our plan now going forward. So I would not anticipate that we're going to have to go towards $6 billion in order to get there and as we get to each year, we'll give you an updated guide on it, but when we plateau production capital spending and capital discipline really matters. I just want to emphasize this. We intend to live within our capital means and be really tight on capital, and that applies to the Permian along with every other asset.

Thank you, and first, I want to congratulate Pierre and thank you for all the years that actually all over the past couple of decades that all the help. We may appreciate.

Thanks, Paul.

Michael and Pierre, I think Michael when you first became the CEO, I think one focus is that course method for you and that full for the last several years, there's a lot of acquisition and change in portfolio. So it's very difficult for us from the outside to see where's your cost structure compared to let's say before the pandemic in 2019? Is there any way that you can help us in terms of what is the structural cost base that for you today compared to say a number of years ago, especially during the early part of the pandemic? Thank you.

Yeah, Paul, I don't have all that stuff right on the top of my head to go back to 2019. It's a fair request, but look, I think we showed a chart in here over the last several years that our unit costs are relatively flat in fact. I think we're number two on that chart. We don't break out each of the competitors. Our unit OpEx last year was about $15.80 a barrel, which is about 5% lower than the year before, and we still have outstanding unit optics reduction targets going out to 2026 at mid-cycle. We've had some inflation along the way, but you're right. We took a lot of costs out of the business in 2020 and 2021. So, as we bring together, Hess, and this gets a little bit to the question that Doug was asking as well, we will come out with an update to investors that talks about the portfolio updates, guidance on all the metrics that matter, and I assure you that I have not changed my view that cost control, excuse me, cost control always matters, and capital discipline always matters. So, we will update you on those numbers specifically, Paul.

Hi. Good morning. Thanks for taking the question, and thanks for everything, Pierre. Maybe this one will be an easy or a hard one for you, depending on what you were planning for, but it's about, it's a follow-up on TCO in Kazakhstan and the affiliate dividend guidance and what's interesting about it is that it's flat year-over-year with a commodity assumption that maybe a little bit lower than the prior year and within affiliates, there's also some LNG exposure, which isn't as strong as it was last year, ex-TCO and so, I guess the question is like, you've given this really robust technical update on Tengiz and where we stand, but are we already at a point where TCO is sustaining a level of dividends that's a little bit more stable than it was kind of at the peak of the construction process or the installation process, and we're sort of in a progression to this pro-forma, very stable cash flow profile from TCO, or is that number, am I reading too much into that affiliate guidance number? Thank you.

Thank you, Sam. TCO dividends are increasing since capital expenditure is decreasing, and as we mentioned, when we see the additional production from FGP, those dividends will rise even more. There are some fluctuations to consider. Last year, TCO had some surplus cash which was released, but this year they will need to build cash for upcoming debt payments, which we co-lent, so we will be receiving that as well. There may be some timing variations, but your observation about the upward trend is accurate because capital expenditures are reducing. This has primarily been self-funded as an affiliate company. As capital expenditures decline, there is more cash available. It is contingent on commodity price assumptions, and you're correct that LNG and petrochemicals are key contributors, with a bit of refining also being a significant factor in our affiliate dividends. It remains roughly stable compared to the previous year. We will provide updates throughout the year, but TCO has been an investment for eight years, and it is expected to generate substantial cash when it comes online next year.

Thank you so much and maybe, Sam, just one more point and what you're going to see too is because it's tricky as an affiliate that line that's affiliate earnings less dividend, that's going to flip, and until you'll see it, it'll be hard for everyone to model it, but what has been historically a line where affiliate earnings are higher than dividends, you will see that flip in time as we pull out more cash out of TCO in particular than the earnings than the book earnings are.

Hi, good morning, everyone, and thanks for taking my question. So it's a party in Part A and Part B type of question, but really on the Permian, Mike, in your slides, you highlight that optimizing well spacing and maybe coring up where you were drilling in 2023 helped the well productivity. At the Analyst Day, you had talked about some technologies, and I'm just curious where any of the improvements you saw in '23 related to those, and then Part B very quickly, you're growing almost 200,000 barrels from here until in the next two years. Last core, you had some infrastructure issues. What are you doing to get ahead of those infrastructure issues that don't resurface over that plan period?

We're drilling more feet with the same rig fleet and improving completions, which are contributing to our current performance. We are piloting improved recovery technologies in the field, and while some are already in production contributing marginally, we're mainly focused on gathering data to enhance completion and fracture techniques using gas injection and gas lift, along with different chemicals to boost flow. As we roll these out on a larger scale, we'll share how they contribute, but for now, we're seeing improvements primarily in drilling and completions. Regarding midstream infrastructure, issues we previously mentioned can be related to weather, regulatory matters, or specific gas processing plants and pipelines. We're addressing those since reliable performance downstream of the wells is essential for a large asset like ours, and we currently have no constraints on takeaway capacity out of the basin. We're well positioned not just for 2024 but also for 2025 and 2026 in terms of takeaway capacity to access the market. However, we need all the pipes, pumps, tanks, and other components between the field and the market to perform reliably, which is a top priority for our operations team. Our fourth quarter performance was very strong, and they're actively focused on this. We experienced some weather in January that may have a modest impact, but we have a clear understanding of all operational priorities to ensure unimpeded market access.

Hey, thanks for taking my question, and Pierre, I want to echo the congrats. Thanks for all the help over the years. I wanted to circle back to TCO, and Mike, I think last quarter when you provided the updated guidance on timeline, one of the things that you noted was workforce productivity, and I was wondering if you comment on some of the changes that you've implemented to improve labor productivity over the past several months, how it's progressing first plan. In your comments, you mentioned improved scope of work in the context of FGP. I'm not sure that's related to labor or something else, but if you could elaborate on that comment as well, that'd be great. Thanks.

Yeah. So, we have multiple contractors working on commissioning and startup, and so this is everything from walking systems down to ensure that they've been properly inspected that we refer to as punch list items have been identified, which is work that still needs to be completed by contractors, and then you get into the loop checks and equipment runs and all the work to bring pieces of equipment up into service. So we've got a number of contractors working on this. We've moved scope from contractors that have had lower productivity to those that have exhibited a higher productivity. We've brought in additional resources to beef up the overall capacity, and the resources are the contractors that had lower productivity, we've worked with them to understand where are the constraints in the bottlenecks, and we've seen one who had a productivity factor as we measure it that was down in the kind of 0.4 range previously is up above 0.7 now, and we're targeting to get that up again by a similar quantum. So there's a lot of work on the ground to be sure we've got the right people working on the right things that we have enough contract resources. We're also bringing in technical resources as we discover items that need more technical solutions, and that can include company people or vendor people, and we're out much further ahead. Last quarter or the quarter before, the walk downs and other identification of issues were a few short weeks ahead of the crews that were actually doing this work. We're several weeks now, seven, eight or more weeks out ahead of the teams that are doing the work. So you've got much better ability to plan and execute the work in a much more efficient manner because you've got some time to put the work back together, get the permitting done, and be sure that you've got all the right tools, equipment, etcetera. So it's a great big project, Devin. It's the largest brownfield project and most complex brownfield project I've seen in my life, and we're seeing good improvements in terms of the on-the-ground performance out of our team and out of all the contractor teams that are working on this.

Yeah, hey, I just want to echo everyone's comments. Pierre, been great working with you and good luck in retirement.

Thank you, Jason.

I wanted to ask, go back to the Permian Basin, and I appreciate the type curve data that you provided in the back of the slide deck. It's a bit difficult to reconcile with the data with the type curves you provided, particularly for the Delaware at the 2023 Capital Markets Day when you forecasted a large improvement in productivity. Can you just talk about if your type curves, particularly in the Delaware basin, ended up in line with where you anticipated them being as shown in that Capital Markets Day type curve? Yeah. So I'll quickly just touch on the Midland Basin where we continue to be a first quartile performer, steady consistent performance. We understand the geology. There's less fluid complexity, and so we're a top quartile, first quartile performer there in the Midland. In the Delaware, we last year showed actual data on a Delaware-wide basis and then we showed some forward guidance, particularly focused on New Mexico because we were shifting so much of our program into New Mexico, which, as I mentioned earlier, is a more productive portion of the basin, and in the Delaware, New Mexico, we saw significant improvement with our second half POPs. Last year, more than 80% of our POPs were in the second half in these more productive areas and the subsurface performance there has been very strong. In the appendix, we've got a slide that shows you 49 POPs out of the 59 POPs were in the second half, and you can see that they lay right on the type curve, and then you can see the improvement in the Delaware Basin, Texas, which we didn't guide to last year because it was in that combined chart there, but we've seen strong improvement. We've updated our well spacing and completion designs there, and within the basin, there are sub-basins, and some of those are performing exceptionally strong as well. So we're seeing performance that is very consistent with what we outlined in the markets today last year. I think the shift in basis was just to provide you a little bit more detail into these sub-basins, and we'll continue to report on that basis going forward.

And just as a reminder, too, Jason, so last year's performance in New Mexico wasn't impacted by long-sitting DUCs. So the year-on-year is bang-on. It's consistent with the set guidance, and you see the improvement in Texas because there was the impact from long-sitting DUCs in the prior year.

Good morning, everyone. Thanks for taking my question. I wanted to follow up actually on the Permian and specifically ask on the program this year, what kind of opportunity do you see from here for further improvements to spacing and completion design cycle times, if any, in the Texas Delaware region? And could what's working well there translate to New Mexico to make those wells even stronger or quicker to drill and complete or even to the Midland side? And then secondly, how are you all thinking about the mix of capital allocation across these regions within the Permian throughout this year? Thanks.

Yeah, so we're constantly looking to learn and improve, and as I mentioned earlier, we've seen significant improvement in drilling time, completion time, time from completion to POP this year, and these are a lot of little things, right? This is as you continue doing things, you find more and more efficiencies. We can bring more technology to bear, etcetera. So, and we look to extend those learnings across the basin and frankly between basins. So into the DJ basin and from the DJ basin down to the Permian, there are differences in the sub-basins that you have to understand and respect, but the short answer is yes. We are looking for ways to transfer, learnings across there, and every time I think we're probably at the plateau in terms of productivity improvement, smart people find ways to continue to get even better at this, and so, I don't think we've seen the end of the performance improvement cycle. Our overall capital allocation into the basin is largely a function of where our portfolio lies. About 25% is in the Midland Basin. 25% is in the Delaware, New Mexico portion of the basin, and then the balance about 50% is in Delaware, Texas. It's been that way here, this past year and going forward, that's a pretty good way to approximate it.

Hi, good morning, and thanks and congratulations to Pierre. I'm going to give you guys a break on TCO and the Permian. I'm going to ask a question on the DJ. So just looking at this growth of 125 KBD for '24, how should we think about that growth off of a pro forma '23 basin? Just trying to understand what's kind of the underlying, real growth rate in the DJ and then if you could just update us, with a couple quarters behind you now post PDC on your broader plans for development, the DJ.

We have completed the fourth quarter, which was the first full quarter integrating PDC. In the previous quarter, PDC was included for two months out of three. In the fourth quarter, we achieved slightly over 400,000 barrels per day, aligning with our plans to maintain that level in the DJ basin moving forward efficiently. The fourth quarter performance was perhaps slightly stronger than our expectations due to less weather-related downtime in November and December, along with some accounting adjustments that were not operationally related. The result of over 400,000 barrels per day was influenced by factors that may not be repeatable. However, we are confident in sustaining around 400,000 barrels per day. We are still implementing the well design and spacing based on PDC’s specifications, which differ from ours by having more wells and tighter spacing focused on volume. Our design emphasizes return on invested capital, using wider spacing and larger fracking operations but with lower overall capital and higher returns. As we move towards a more standardized design across the basin, this will reflect in our numbers. We have four active rigs and long-term permits nearly extending to the end of the decade, which is very encouraging. We have gained insights from PDC that will be beneficial not only in the DJ basin but also in the Permian. Looking ahead, we are focusing on high cash margin, low break-even barrels and aim to stabilize production around 400,000 barrels. Our synergies are progressing well, and nearly all CapEx synergies are secured, bringing our expenses down to $1 billion. Operating expenses are approaching the targeted $100 million. Additionally, we are experiencing some procurement synergies that we did not initially anticipate. Overall, our performance is meeting or exceeding our guidance.

Yeah, thanks very much, and Pierre, I'll add my comments to the host already, but thank you for all the insights. Always been worth listening to. When I look at the growth that you're likely to see in oil in particular over the next two to three years, it feels as though you're going to be adding towards 0.5 million barrels, maybe slightly more barrels of pretty high margin black oil, and I guess the question is about whiplash and it's the increased sensitivity that the business is going to have to movement in, of all this high-efficiency. And what, you feel Pierre, Mike, that implies the balance sheet and the way you think about balance sheet and managing things. And just if I could add on, just give me an idea of what the loan repayment schedule looks like at TCO, and I presume that loan repayments will go through the net in the net outline on the CapEx side or the investment side of the equation. Or, do they play elsewhere? Thank you.

Right. No, thanks, Lucas. I'll take it. We've been overweight upstream and overweight oil liquids for a long time, and you're right. Recent acquisitions and Hess certainly adds to that, and we like that exposure. In terms of how we manage the balance sheet, the first thing is we start with our breakeven. So what it takes, the oil price it takes to cover our CapEx and dividend, that was in the low 50s last year, and so we see mostly upside, and that's why we had record share buybacks last year, almost $15 billion, 5% of our shares outstanding, because we're built for a price well below where we currently are. We've also done it while maintaining a strong balance sheet. Our net debt ratio of 7%. We've said as we keep our share, we purchase this steady across the cycle that we're okay re-levering back up towards the low end of our guidance range, which is 20% to 25%. So that guidance that's a kind of through-the-cycle net debt ratio guidance, that still holds, and if we had a significant change in the portfolio, of course we would look at that going forward, but I think the actions that we're taking are consistent with that guidance, and again, adding that exposure when you're built at the breakeven, when we think about our balance sheet, you take into account lots of things, your portfolio, the commodity price outlook, but your breakeven is really key and Mike was talking about capital and cost discipline, our ability to fund our reinvestment program in both traditional and new energies and grow the company and pay a growing dividend, right? More than twice our nearest peer, greater than S&P 500. We just increased at 8%. So all those numbers are before the latest increase. We can do all that at a low price, return surplus cash. That's how we're going to think about it. So again, you'd expect our net debt to increase over time depending on commodity prices and how we return cash to shareholders. We're not having more exposure to high margin barrels, as you say. That's a good thing. We're built for it, and as long as we keep our breakeven low and below where prices are trading, we're in a really good spot.

And how TC loan payments flow through?

Oh, yeah. So TC loan payments, sorry about that, yeah, because I alluded to that. That will not be in cash from ops. That shows up in our investing cash. So Jake and the team will take you all through that, but yeah, what I was saying about that affiliate line flipping, that's separate from this in a different line. We will see cash being returned, and it's a billion our share next year, again two billion in '26, and then in '28 or '30. So all that's disclosing our 10-K. Jake can take you through that, but yeah, that's only additional, and again, we shouldn't be surprised. We've been investing for eight years in this project. That cash is going to come back once the project starts up.

Okay. Pierre, thanks. And if you're in London and fancy a game of tennis, give us a buzz. That's what I'll be doing.

Thank you very much, and Pierre, all the best for the next chapter. My question is on Henry Hub. In the new sensitivities you published today, you saw a very material 30% increase in your Henry Hub sensitivity. Is this purely because of PDC and related to that on a macro level, if you can perhaps share your views on the 2024 outlook for Henry Hub, please. Thank you.

So I'll start, Irene, and then Mike can take the macro. Yeah, it's a function of PDC, certainly, and then just continued the associated gas that comes along with the Permian. So as we're growing that, it obviously comes along with natural gas.

Yeah. And Irene, the macro, I was pulling up the slide on the Henry Hub sensitivity. So broadly speaking, oil markets are pretty balanced right now. I think the geopolitics are the thing that are harder to call and could drive movements one way or another. It could be OpEx plus decisions. It can be this conflict in the Middle East. Economic growth in the world continues to be decent, and our outlook on demand growth for all this year is maybe not quite as strong as last year but still growing. Gas is a little bit different. The inventories are high in the U.S. Inventories are high in Europe. We're kind of mostly through the wintertime, certainly through the riskiest period of the wintertime and now, there's these questions that are not going to really weigh in the market. In the near term but maybe longer term, about exports out of the US, and so all of that has got gas markets under a little more pressure than oil markets or refined products and it's not unusual. Pierre was just talking about how we build the company to compete through the cycles and different parts of the portfolio basket. Petrochemicals are under some pressure right now as well and so at any point in time, we're going to find some of the fundamentals probably under pressure. Others are looking pretty good, and here in the short term, I think Henry Hub is in the under pressure category.

Good morning. If I look at the production guide of 4% to 7% growth on, say, $3.1 million, and I try to book in that between a fourth quarter closer to 3%-4%, and a 2025 where we're going to see TCO, FGP startup, plus hitting that million barrel a day milestone in the Permian, sort of implies there's an inflection point in production growth coming at some point, or perhaps there's a conservative guide for this year. Is that the right way to think about it?

Well, coming into this year, we now have a full year of PDC that will be part of the portfolio. So that's pretty safe in terms of counting on that. I've already mentioned that fourth quarter was a little bit higher than maybe we even might have expected because we had high reliability. Some of these midstream issues we'd faced in the Permian had didn't repeat. We had this accounting catch-up thing in the Permian as well, and we had a pretty light turnaround schedule in the fourth quarter. So it was a strong quarter all the way around. As we head into next year, we've got some asset sales in the guidance, and Bob, we've been at the low end. We've kind of ended up the last couple of years hitting our guidance range, but at the low end, and so I think you could probably think of this as being a little more comfortably in the middle of the range this year, given a number of the things that you mentioned. So, we try to give you guidance each year that we expect to hit, and we certainly expect to hit it this year.

Thanks for getting me in. My question, Mike, is maybe just on the Chevron return specifically trying to get a sense of, sounds like you will, but just want to get a sense if you'll continue paying out a majority of free cash flow for the remainder of this year and if the buybacks will continue to constitute a bit over 50% of that payout?

Yeah, Neil, we have not used some percentage or range of percentage of cash from operations as kind of a go by for distributions. What we've done is, have leaned on our track record on the dividend, first of all, and we've already clarified what you can expect this year with the 8% increase that we've announced. And then, I would point you back towards our upside and downside guidance that we've had out there now for a number of years, $10 billion to $20 billion on the range for buybacks, and that's in an upside price case. We'd be up towards the higher end of that in a lower price case down at the lower end, both of which we can comfortably handle. We have indicated that post the Hess close, all other things equal, we'll see when it happens and how the world looks when we get there, but we would expect to move from a rate of 17.5 to the top end of 20 because we're so confident in the long-term cash productive capacity of our portfolio and the strength of our balance sheet. So rather than focusing in on those percentages, I'd really point you towards the specific guidance that we've issued in the kind of the track record. Now, and of course, I think Pierre mentioned this in his comments. We do remain under SEC restrictions right now relative to the rate at which we can buy back, and then we'll be out of the market when the Hess proxy is open, and so all of these things are under normal times, we don't have one of those constraints on this.

Hey, and I would just add, let me just add a little bit. It's fitting maybe my last words will be on share buybacks, six straight years of buybacks, right, 17 years out of the past 21 years, but we actually bought back more shares last year than the year before, even though earnings and cash flow were higher, right? There were records in '22, still strong in '23. That's the whole point. We're trying to be steady across the commodity cycle. We've heard from investors that buybacks should not be pro-cyclical. And it's hard to be counter-cyclical in the commodity business that has some price volatility. So being steady across the cycle is how we guide to it, and these formulas, in fact, reinforce the opposite. They reinforce pro-cyclicality. So we're giving a return that in some ways is almost independent of prices within a range, because we're could have paid more out in '22, but we held it back, and we use some of that to pay in '23. We'll see where it goes, but the intent is to try to be steady across the cycle, either pro-cyclical nor counter-cyclical. Thanks, Neal.

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

Thank you. This concludes Chevron's fourth quarter 2023 earnings conference call. You may now disconnect.