Chevron Corporation

Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's third 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 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 Spearing. Please go ahead.

Thank you, Katie. Welcome to Chevron's third quarter 2023 earnings conference call and webcast. I'm Jake Spearing, 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 prepare 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.

Thanks, Jake. I want to start by acknowledging the tragic events in the Middle East. We're deeply saddened by the loss of life, and our hearts go out to those affected by the war. We continue to prioritize the safety and well-being of our employees and their families, and the safe delivery of natural gas. Earlier this week, we announced that Chevron entered into a definitive agreement to acquire Hess Corporation. We expect this transaction to close in the first half of 2024, and we look forward to providing updates in the future. Now turning to the third quarter, we continue to make progress on our objective to safely deliver higher returns and lower carbon by returning more than $5 billion to shareholders for the sixth consecutive quarter and delivering ROCE greater than 12% for the ninth consecutive quarter. and investing in traditional energy by closing the PDC energy acquisition and in new energies by acquiring a majority stake in a green hydrogen production and storage hub in Utah. And earlier this month, we released our climate change resilience report, which details our approach, actions, and progress in reducing carbon intensity and growing new lower carbon businesses. I encourage everyone to read the report available on chevron.com. At TCO, base business continues to deliver good results. The plant turnaround was completed ahead of schedule, the reservoir is performing well, and the plant remains full. We expect a higher dividend in the fourth quarter. TCO has achieved mechanical completion at the future growth project. Following slower than expected commissioning progress, we conducted an independent cost and schedule review. We now forecast the wellhead pressure management project which is the field conversion from high pressure to low pressure to begin startup in the first half of 2024 and to continue through two major train turnarounds. FGP is expected to start up in the first half of 2025 and ramp to full production within three months. Total project cost is expected to increase between 3% and 5%. CCO production on a 100% basis in 2024 is forecasted to be about 50,000 barrels of oil equivalent per day lower than 2023 due to a heavier turnaround schedule and planned downtime for WPMP conversions. TCO is expected to reach greater than 1 million barrels of oil equivalent per day in 2025 when FGP fully ramps up. Pre-cash flow from TCO in 2025 is expected to be more than $4 billion, Chevron's share at $60 Brent, down about $1 billion from our prior estimate. Our focus remains on safe and reliable commissioning and startup. I'll now turn it over to Pierre to discuss the financials.

Thanks, Mike. We delivered another quarter with strong earnings, cash flow, and ROCE. This quarter's results included two special items, a one-time tax benefit of $560 million in Nigeria and pension settlement costs of $40 million. Foreign currency benefits were $285 million. The appendix of this presentation contains the reconciliation of non-GAAP measures. Organic capex this quarter included about $200 million for PDC legacy operations after closing in August. Our balance sheet remains strong, ending the quarter with a net debt ratio in the single digits. Another quarter of solid cash flow enabled us to deliver on all of our financial priorities. Despite restrictions during the PDC transaction, we were able to repurchase well over $3 billion in Chevron shares. Cash used to reduce debt was primarily related to PDC's higher cost borrowing. Cash balances ended the quarter near $6 billion, a little above what's needed to run our businesses. Adjusted third quarter earnings were down $5.1 billion versus the same quarter last year. Adjusted upstream earnings were lower mainly due to realizations and negative timing effects. Higher unfavorable discrete tax charges and exploration expenses were partly offset by lower DDNA, Venezuela cash recoveries, and other favorable items. Adjusted downstream earnings decreased primarily due to a negative swing in timing effects and lower marketing margins. Compared with last quarter, adjusted earnings were down just over $50 million. Adjusted upstream earnings were roughly flat as higher prices and volumes were offset by unfavorable discrete tax charges and negative timing effects due to the rise in prices. DD&A and OPEX were both higher in part due to the addition of PDC legacy assets for two months and a quarter. Adjusted downstream earnings increased primarily due to higher refining margins partially offset by unfavorable timing effects. All other was down on unfavorable tax items and decreased interest income in line with lower cash balances. Third quarter oil equivalent production was up 6% over last quarter, primarily due to two months of legacy PDC production. This was partly offset by planned turnaround at TCO and pit stop at Gorgon. The Permian, excluding legacy PDC, was down 2% due to lower non-operated production. Company-operated production was flat with the second quarter. Now, looking ahead, our fourth quarter estimate for turnarounds and downtime includes approximately 30,000 barrels of oil equivalent per day for tomorrow. We anticipate affiliate dividends in the fourth quarter to be largely from TCO. As a reminder, we record a 15% withholding tax on TCO dividends. Due to the pending transaction with HESS, share repurchases will be restricted pursuant to SEC regulations. Chevron expects share repurchases in the fourth quarter to be around $3 billion plus or minus 20%, depending primarily on the timing of the HES definitive proxy statement mailing. In summary, our actions and performance show that Chevron keeps delivering strong results. With a strategy that remains clear and consistent, We're well positioned to deliver value to our shareholders in any environment. With that, I'll turn it back to Jake.

That concludes our prepared remarks. We are now ready to take your questions. To allow for questions from more participants, we ask that you limit yourself to one question. We will do our best to get all of your questions answered. Katie, please open the lines.

Thank you. If you have a question at this time, please press star 1 on your touchtone telephone. To allow for questions from more participants, we ask you limit yourself to one question. If your question has been answered or you wish to remove yourself from the queue, please press star 2. If you're 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 1 on your touchstone telephone. We'll take our first question from Roger Reed with Wells Fargo.

Yeah, thank you. Good morning.

I was hoping we could dig into the international upstream, just a little short on what we were expecting this quarter, what some of the factors were, other than the ones called out, the FX issue and the tax benefit in Nigeria.

Yeah, Roger, look, I'll let Pierre cover this in a little more detail, but there's, I recognize this quarter was a tough one to model, and there's pretty material or significant non-cash charges. Timing effects, primarily inventory costs, we see with rising prices, some tax reserves, some charges for legal abandonment and other things, and then some lower realizations, which are mixed, and the lag effect, and so are LNG pricing. On timing and inventory costs in particular, on period-to-period comparisons where we had a prior period, whether it was last quarter or the same quarter last year, where prices were coming down, And then in the current period, we see prices strengthening significantly. You really get pretty significant deltas on the way we cost inventory. And if you go back to, I think, the first quarter of 22, we had some similar dynamics. So anyway, that's kind of high level on it, Pierre. Maybe you can talk a little bit more about the international upstream in particular.

Yeah, it's a subset of what you talked to, Mike, Roger. So timing effects. The largest timing effects this quarter were on cargoes on the water. So you'll see that primarily in the international upstream and international downstream. Timing effects are in three buckets. You have paper, mark-to-market. You have on-the-water inventory, and then you have on-land inventory. So it's really cargoes on the water that drive most of the effect, cargoes that are in transit and cross over quarterly periods. And so that's what the trajectory of prices, as Mike indicated, is really what drives that. Mike talked about abandonment estimates, so those will show up in depreciation, and you saw that in the international upstream. And then in LNG, you see some lag pricing. We also saw some mix between contract cargoes and spot cargoes on LNG. And on the liquid side, we saw some mix effects. So it's a bit of where the liftings are relative to production in terms of tax jurisdictions. the types of products, how they trade in terms of discounts to Brent. So there were a number of items in International Upstream, and you could follow up, Roger, with Jake and cover any more details.

No, thanks. I'll sum it up as messy. I appreciate it. Thanks.

We get one per quarter every now and again. Go ahead, Katie.

I apologize. We'll take our next question from Josh Silverstein with UBS.

Hey, thanks. Good morning, guys. On the TCO, you had mentioned that in 2025, you had expected the cash flow to be about $1 billion lower, around $4 billion versus $5 billion previously. Is that just due to the project delays, or is there higher cost estimates now in that, so it would be lower distributions from there, or is there something else that's driving that?

Yeah. So, Josh, there's going to be some more capital. We said 3% to 5%. So think about around $1 billion sovereign share over 24 and 25, probably a little more weighted to 24 than 25. Cash flow from the operations will be lowered by about $1.5 billion at $60 Brent in total over the next two years, really due to the delay in the project. It's equivalent to about 50,000 barrels a day in net production in each of those years. So in total, you know, we expect our share of dividends to be lower by about $2.5 billion across 24 and 25 from the prior guidance. And so it's a combination of those things. And so we had previously guided to above five. We're now seeing above four. A little more of that coming from production and cash flow from ops as opposed to CapEx.

And the delay in WPMP doesn't have any impact really because there was no incremental production. So the effects that Mike was talking about in production are really from the delay and the start of FGP, which obviously adds incremental production.

Thank you, Josh. Thanks.

We'll go next to Neil Mehta with Goldman Sachs.

Yeah, thank you. I just want to stay on the TCO question. As you think about, Mike, the biggest gaining factors to getting from here to completion around FGP, just keep watching us through the landscape and the key milestones that you'll be watching and we should be watching to give us conviction that the project's coming into service.

Yeah, so, you know, the main message here, Neil, is... You know, as we completed both WPMP and then mechanical completion of FGP, and we've begun, you know, to get deep into the commissioning, we've, I think, previously mentioned we worked through some technical issues with our utility systems. And as we did that and we saw some of these impacts, we commissioned an independent cost and schedule review off cycle. We normally do these annually, but we didn't want to wait. And so as we saw some of this evidence that things were going slower, there was some more discovery work, we sent in an independent team to give us a kind of a cold eyes assessment on cost and schedule. And I think the main thing that I would distill that down to is the recommendations from that and that are embedded in our updated guidance today reflect a more conservative forecast of commissioning progress. And so we're assuming things will take longer than the prior plan. We're assuming we're going to have discovery items that tend to come up in complex projects like this. And in response, we've implemented some significant changes in terms of how we're approaching this. We've moved contract resources over from 3GI, which is a portion of the Future Growth Project, which is now completed and fully commissioned, over onto the other commissioning work. So we've added contract resources there. We've brought in experienced turnaround and operations people that are very skilled in the discovery work, in managing through the restart of and operations of facilities now to help us with this. And then we've also added technical resources to address any unplanned discovery items that would come up. So we've had a significant change in our approach to this. We've got a more conservative guidance here that we're issuing now, and we'll continue to talk about this every quarter. You know, I guess the main things to look at here are we've got big compressor trains that will start up for pressure boost, which is a key driver of this high pressure to low pressure conversion. These are very large machines, and so those are key milestones. After that, we've got metering stations that are converted from high pressure to low pressure. And so over the next few quarters, and there's, I think, 40-some-odd metering stations as you go out through the entire field, we've got these two big turnarounds that I've talked about. All of those are really key milestones that we'll be tracking very closely, and we'll update you on those as we go forward.

Thanks, Neil.

We'll go next to Devin McDermott with Morgan Stanley.

Hey, good morning.

Thanks for taking my questions. I wanted to stick with upstream, but actually ask about Venezuela. You've had some increase in production year over year, given the initial sanction relief. And there's obviously been some additional sanction relief announced just here since the last quarterly call. I think it might have been on an interview this morning. You made some comments that you could see a sequential increase in production between now and year end. I was wondering if we could just step back. talk through what impact the sanction relief has on your production profile and also willingness to invest in that region. And can you remind us how impactful Venezuela volumes are for your corporate cash flow?

Sure. So, yeah, we have seen some action now from the U.S. government. We had been previously operating under an OFAC license, which was modified at the beginning of this year. a general license. There's some specific licenses that go with that that define the terms under which we can operate. The recent action in the new general license issued by OFAC really kind of opens up operating room for others more so than it does for us. It doesn't materially change our circumstances here. And so I think what you'll see is some more people lifting crude, bringing it to the U.S. You'll see more crude flow to the U.S., I don't think the impact on our operations really is not particularly significant. We are up to something around 130,000 barrels a day from maybe 60,000 barrels a day earlier this year. We still think we can get to 150 or so by year end, so we are seeing improvements and expect there's some more that we can see through the balance of the year. The cash from that is going to pay legitimate operating expenses, taxes and royalties, recover some past dues that we are owed, and we're really working on what I would call pretty straightforward field maintenance and things to restore production that aren't particularly long cycle or capital intensive and staying within the kind of cash that's being generated from those sales in order to fund that operation. I would expect that's the posture we'll remain in for a while here until we see how the longer-term sanctions environment plays out, the political situation in the country with elections and the like, and continue to make progress on recovery of the past dues that I mentioned. And so not a lot of change, I guess I would say, from our point of view. Pierre, maybe you want to comment on the cash and production

Yeah, consistent with what Mike just said, we're continuing to do cost affiliate accounting, which means we don't record production or reserves. So that's not reflected in our numbers. And we only record earnings when we receive cash. So we're not recording a proportionate share of equity earnings, but only what we actually receive in cash. And that's something that we'll continue to look at. And as Mike said, depending on all those potential triggers down the road, elections and such, We could go back to equity accounting at some point in time, but we have not made that decision yet. In terms of cash flow, it's about 1% of our cash flow, so it's modest, of course, but it's more than it was before. And so, as Mike said, operations there are continuing well, and we're getting a little bit of cash, and we'll just see where it goes from here.

Great. Thank you.

Thank you, Devin.

We'll go next to Barrage Borkatario with RBC.

Hi, thanks for taking my question. I'm sure you've got a few more on the TCR. I just want to ask about the Permian. Last quarter, you gave some very helpful data points on well productivity this year. I was wondering, particularly for the New Mexico side, if you had any incremental comments for wells driven in the third quarter, because it was a pretty small sample size of POPs in the first half of the year. So any comments there would be helpful. Thank you.

Yeah, and I might give you some kind of broader commentary on Permian performance as well. Overall production was down just a little bit, about 2% in the quarter. That was entirely driven by non-operated joint ventures, and primarily a couple of the operators had delays in putting wells online due to frack hits and some other factors. There was also some takeaway capacity on the Permian Highway, you know, constraints that resulted in some unplanned downtime. So co-op production in the third quarter was essentially flat from the prior quarter, which is what we had guided to. And that's despite having some wells that were choked back due to some surface constraints. In one development area, we're seeing higher than expected CO2 content in the gas. and others in the area are as well. So we've got third-party handling and process facilities that are constrained by that and can't handle all the CO2, so we're choking wells back. There's a new federal regulation that I won't get into the details, but it affects how we meter production, and it prevents commingling. And so we've got wells choked back until we can get some new meters in place. And then we've got some produced water limits that have come into effect in some areas. So there's a number of things. that are not indicative of well performance but other surface realities that we're working our way through that are impacting co-op production a little bit. In New Mexico, you're right. We've got more pops in the second half of the year. We've popped about 60% of the planned wells in New Mexico, so the balance, you know, almost half come on in the fourth quarter. Pop performance has generally been strong. Some of those wells are hit by the facility constraints that I've talked about, but overall well performance is aligned with our type curve expectations. I think when we get to the fourth quarter call barrage, we'll come back with some more detail on type curves. We'll have enough of them online. We'll have enough months that we can start to give you some of the same kind of evidence that we did last quarter to show you the performance.

Okay. Understood.

Thank you very much.

Thank you.

We'll go next to Sam Margolin with Wolf Research.

Hey, good morning. Thanks for taking the question. Maybe we'll stick with the U.S. and ask about just the U.S. upstream CapEx number. You know, there's a lot of moving parts in here. You've got incorporation of PDC. You have kind of GOM projects and Balamore coming into play, inflation, and then timing effects that you alluded to. I guess when you think about this quarter's U.S. upstream capital, how would you characterize it just overall? Would you say it's sort of on plan or like overly influenced by any one of these factors that may or may not be mitigated over time? Thank you.

Yeah, Sam, you're right. I mean, we are seeing pressure in the U.S., and I think we're probably going to end up higher than our budget as we end the year. PDC is being integrated into the factory pretty much as we expected, and so it's an increment because it wasn't in our original plan, but it's really not a driver of this. The big thing is we're seeing actually more feet drilled per rig and more completion feet than we had planned. The productivity of the primary development activity has continued to improve, but that means we spend more money on tubulars, on sand, on water than we had anticipated. So it's kind of a good news, but it brings with it some costs. We've got some long lead items where we're seeing supply chain realities that say we need to place long lead orders earlier. So some things we otherwise would have ordered next year that we've actually moved ordering and initial payments on into this year. So there's some long lead dynamics going on. And then I mentioned earlier, produced water is becoming an issue. The reinjection of that and doing that in a way that minimizes the incidences of induced seismicity. So we've got some more produced water handling infrastructure spend. So I would say those are kind of the primary drivers. And that's pushing the Permian to be a little hot. Gulf of Mexico is pretty well right on plan. And so what you're seeing there is really a function of PDC, which is just an increment that's been added, and then some additional costs in the Permian program that we really hadn't anticipated as we went into the year.

Hey, I'll just add. So if you take out inorganic, which is $600 million year-to-date, right, $400 million in the third quarter primarily for ACEs, and the $200 million that we had for PDC in the third quarter through third quarter year-to-date were about $200 million above the rateable budget. Of course, you know, fourth quarter tends to be higher, so as Mike says, we'll likely end the year a little bit above budget.

Thanks, Sam. Understood. Thank you.

We'll go next to Paul Ching with Scotiabank.

Thank you. Good morning. Mike, can I get back to you? Can I go back to TCO? It's a little bit of the late stage for the cost increase and everything. I guess the question is then what have we learned from this process and to ensure that your future project execution will become better and not facing the kind of problem that, I mean, it has been a challenging project all along due to a number of different reasons. Quite frankly that this is a bit disappointing at this very last stage for the speed of the sleeping in the schedule and also the cost increase. Thank you.

Yeah, Paul. Thank you. And look, I share the sentiment. So I understand where you're coming from. You know, big complex project. You've been along for the whole ride. So you know early on there were some engineering issues that we confronted and addressed. you know, in the middle of it, the big thing was the pandemic and demobilizing, remobilizing, building medical facilities, and a whole bunch of stuff that, you know, that we had to manage our way through and was complex and difficult, and our folks did a great job, but it clearly impacted cost and schedule. And, you know, the big thing here, Paul, is as we've gotten into, and you have to remember, you know, this is, you know, we're redoing the power infrastructure for the entire field, which is... Geographically speaking, it's an enormous space, and this is infrastructure. Frankly, it goes back a lot of it to kind of Soviet days. So there's an entire new power distribution system. We're taking the entire field and taking it from high-pressure production to lower pressure in the WPMP. process and then building the really large sour gas injection and incremental production facilities. And it's almost a field-wide refurbishment of a lot of it and then this big increment of production. And the commissioning of that is incredibly complex. And as we went in and did this cost and schedule review relatively early in the commissioning process based on what we were seeing, what became evident is that we need to account for that complexity in our schedule. And I don't think it was fully reflected in the schedule. And in a big, complex project like this, you find things. And early on, we found challenges in the utility system. And it cost us some time. And that ripples through. And so the guidance we're giving you now is really what I would say is it's more conservative because it assumes that those kinds of things are going to be encountered for the balance of the project. And we need to set expectations that those are the realities that we're going to be dealing with. And so that's why the schedule relates all in commissioning. It's bulk construction is completed. All the equipment is there. And this really is the final commissioning process. If we do well, we could end up on the front end of those windows that I gave you, but we've given you those because our experience says we should not plan for that. We ought to plan for the reality of these things. And as I mentioned in response to the earlier question by Neil, we've added incremental resources in multiple areas now to anticipate and be prepared for these kinds of challenges. And so I think the lesson is on the projects like this, of which there are few, In the future, our commissioning plans will reflect that complexity more completely than the commissioning plans did on this one.

Hey, and I'll just add some comments on affiliate dividends. So we've given a guide on fourth quarter affiliate dividends, which falls short of the full year guide that we did at the start of the year. That shortfall is not from TCO. That's from CP Chem, Sherwin-Phillips Chemical Company on lower pet chem margins. It's also from Angola LNG on lower TTF prices than we had assumed. We've also had some of the Angola LNG cash has come back to us at return of capital. In terms of TCO, we had a $600 million dividend Chevron share in the second quarter. We can't get ahead of the TCO board on the fourth quarter, but 90% or so of the fourth quarter guide is related TCO I'll remind you last year that TCO dividend was $1.6 billion, Chevron share. All these numbers are before the withholding tax. So we'll see a pretty significant increase in the total year TCO dividend. Now, some of that was getting some of the excess cash off the balance sheet like we were talking about. But if you go back to the period prior to the start of this construction, so the period into 2015, we're seeing dividends now or this year's dividend will be similar to what we saw from that time period. So the inflection is happening after five years of either not receiving dividends or, in fact, putting cash out, essentially having negative free cash flow. So we know production is going to be down next year. We showed that. So you'd expect dividends to reflect that a little bit. We have a little bit of an increase in capex. And then we'll be heading to this more than $4 billion in 2025. And all of that is, that guidance is at 60. So We're seeing some positive news in terms of the cash flow coming out, clearly disappointing news on the revised schedule, but we're going to work hard to deliver it in the front end of the range. Thanks, Paul.

Thank you.

We'll go next to John Royal with J.P. Morgan.

Hi, good morning. Thanks for taking my question. So I have a follow-up on the Permian XPDC. You were down 2% in 3Q, including the non-op piece, and really helpful color there from Mike on Barrage's question. But it does leave a pretty big jump to hit guidance in 4Q around 10% if I calculate it right. So are you sticking with that 770 guide for the legacy piece? And if not, is there a good way to think about 4Q production in general?

Yeah, John, we're not. We're not changing the guidance overall on production, excluding PDC. We expect to be the lower end of overall guidance. Permian production is expected to ramp up in the fourth quarter. Full year production expected around 770, 780 or so if you include PDC. And so yeah, the guidance is is still intact for the Permian. Go ahead, Pierre.

Yeah, Mike talked about the 2% shortfall on non-op, which averages to about 0.5%. He talked about also some of these surface constraints. So we have worked to overcome the shortfall we saw in non-op in third quarter to deliver that. So no change in guidance, but clearly we have a little more work to do in the fourth quarter to achieve it. We do expect, though, fourth quarter more POPs and more production in line with the plan that we laid out earlier this year.

Thank you.

We'll go next to Doug Leggett with Bank of America.

Thanks. Good morning, everyone. Mike, I know you've been traveling around, so thank you for making the time for us this morning. I want to try and defend you a little bit here this morning, because if you look at the remaining life of Tengiz, about half of that value has been taken out of your stock this morning. I can't imagine you're happy about announcing other series of challenges. So my question is this. At a philosophical level, how would you characterize what you and your management team and the organization are doing to avoid these kind of issues on major projects going forward? You've got a lot of things in the queue through 2027. Why should the market be comfortable that you can execute on that timeline with what you have in your portfolio?

Well, Doug, you know, you're right. I think the, you know, there has been a reaction apparently in the market this morning to this. We've spent a lot of time, you know, I'll go back to Jay Johnson spending, you know, time not only in these calls, but on traveling around talking about what we're doing on capital project execution. This is a unique project, and I won't repeat the things that I went through earlier with Paul, but Uh, this is a large multi-year, uh, effort that, uh, you know, had supply chains coming in from all the way around the world through the Russian inland waterway system through the pandemic. And, um, and, and we've, um, you know, we we've had our challenges with it. There are not projects in our queue that are remotely similar to this one. Uh, you know, the kinds of things that we're talking about now are, are factory development projects across multiple shale basins, their deep water. developments that you know I think the track record on those is is quite different and and so I you know I think the the lessons on these really complex capital projects are that despite employing the best you know engineering and construction firms in the world bringing in partners that have strong capability they are really complex and challenging And part of the way we mitigate that is we be very selective about the ones we do. You know, we walked away from the Kitimat LNG project because we, despite a lot of efforts to make that project better, we had concerns about execution in that kind of an environment and ultimately said we're not going to take on a project like that, particularly, you know, at this point in time. And so part of it is the way you choose what you do. Part of it is continuing to learn. and apply those learnings, many of which from a decade ago have been implemented into the TCO project, but some of which from the TCO project will be implemented and integrated into other projects that go forward of similar complexity. So, look, we're close to the finish line on this thing, and we've got a full court press on it to make sure that the commissioning is safe and reliable and we have a clean startup. and the lessons from that will be applied in every other project that we do.

And I'll just restate the impact that Mike talked about. It's $2.5 billion. That's at $60. That's less than $1.50 a share, so clearly we're down a lot more than that. We talked about an earnings miss. We know that weighs also on the shares at the same time, non-cash items, timing effects that reverse, discrete items that are non-occurring. So, you know, we feel good about the company's performance in the corridor in terms of how we operated safely and reliably, how we captured margin. We know, as Mike said earlier, we have these corridors where it can be messy, can be noisy. It's one of them, but the underlying company is very strong and healthy.

I agree. It looks so well done, Pierre. Thanks so much. Thanks.

We'll go next to Irene Jimona with Society General. Hello.

Thank you very much. Good morning. You're referring your comments to higher OPEX and DDNA from the PDC legacy assets having impacted Q3 upstream. Now that you own that business fully and you can sort of look under the bonnet, how are you thinking about your original synergy estimates on PDC, OPEX and CAPEX? And how long would you expect it takes for those to start accruing to you and the results? Thank you.

Yeah, Irene, you know, so I think the reference was simply these are additive to, you know, versus prior periods. And so I wouldn't want anybody to interpret that somehow they were different than what we expected because the OPEX and the DDNA are not different than what we expected. Synergy capture is good. You know, we're right on track to capture All of the synergies, no change to the guidance. We're confident that there's upside, and we'll realize that over time as we have on other transactions. We think there's additional operational, midstream, and procurement synergies that we didn't build into our initial target, and the CAPEX synergy has been captured as well. So, you know, the nice thing about this in a quarter where, you know, I appreciate Doug's view that maybe the reaction here has been a little over. We closed the transaction five months ahead of guidance. We pick up additional production for a bigger part of the year, the earnings and cash flow that go along with that. We've already paid off some high-cost debt, and so we're integrating that into our business now, and it's a very sound transaction that is going to deliver, I think, everything that we expected and then some.

Thank you very much.

Thanks, Irene. We'll go next to Jason Gableman with TD Cowan. Hey. Hello? Morning, Jason.

Yeah, we're here. Hey. Sorry. Sorry about that morning. Sorry to wake you up. I wanted to ask... Yeah, hey, can you hear me?

I can.

Okay, good. I wanted to ask about what's going on in your Middle East footprint. You've obviously had to take tomorrow offline. I believe that's a fixed price asset that you're receiving. So probably not a large cash impact, but if you could remind us what the cash impact is and the ability to maybe reroute that cash somewhere else or offset those losses. And then how you think about the Eastern Mediterranean growth profile overall, if there's any change that you're thinking about it in light of the recent events over there. Thanks.

I'll take the second part of that and then ask Pierre to address the cash and production impact. It doesn't change our view on the development opportunities really at all, Jason. This is a long-term play. It's a very, very large gas resource. We like some of the follow-on exploration opportunities in the region. We're working on the Aphrodite field in the waters offshore Cyprus to develop. We're working on expansion projects that have been sanctioned on both Samar and Leviathan and further expansion ideas on Leviathan. And so we've got to take a long-term view, which is measured in years and decades. And when you have things in the short term that create The circumstances that we see right now, we have to be prepared to mitigate those risks and to keep people safe and maintain the integrity of our operations. But it doesn't change our long-term view on the attractiveness of the asset and the development opportunities. I'll let Pierre address the cash question.

Yeah, we don't talk about our specific contracts and there's numbers of them, but I think in effect, you're right, there's some escalators tied to inflation. There's some oil price sensitivity, but it's within sort of a floor and a ceiling. And these are regional gas prices that are well below international prices. So we don't know how long. We gave the guide on the production and the impact on cash flow is very modest. It's tens of millions of dollars in terms of doing the calculation. And so we'll just see where we end up in the quarter and how long it is shut in for. Thanks, Jason.

Thanks, Hess.

We'll go next to Ryan Todd with Piper Sandler.

Thanks. Maybe I could switch gears a little bit to the Gulf of Mexico.

Can you maybe provide any update on an overall basis? Do you anticipate the addition of the Hess assets on the Gulf to have any impact on your approach to the basin in the coming years? You're scheduled to have three separate projects, I think, at Anchor, St. Malo, and Will come on stream during 2024. Could you maybe update us on the progress of those projects and maybe the timing, whether we should expect those in the first half or the second half of the year?

Sure. So, you know, on the, you know, the combination with Hess, I think we'll come back to you as we, you know, close the transaction and we integrate those. You know, we're partners in a couple of projects that they operate. We both have lease positions out there. I think you would expect us to high-grade the exploration program as we look across a larger combined lease position. But we'll talk to you more about that as we go forward. In terms of specific projects, yeah, you're right. Mad Dog 2 actually saw first oil this year. and we expect peak next year on Mad Dog 2. You can refer to the operator for more on that. Anchor and Whale are both expected for first oil next year. Anchor is, you know, seven wells in total, two that will be online in 24, three in 25, or no, two in 25, two in 26, and one then in 27. The FPU is safely moored out there in the field right now. Manifold and pump systems and subsea manifolds are all fabricated. We've landed and tested the 20,000 PSI blowout preventer. So that project is moving along nicely. Production in 24 is modest because there's only a couple wells online. Think of it mid-year in terms of general timing. I'd refer you to Shell on the whale project, First Oil, probably the latter part of 2024, and a similar kind of a profile where you've got a smaller number of wells online initially, and then over the subsequent couple of years, you're going to see additional wells come online. And so the production impact of that starts to show up in 2025 and 2026. in a greater way than it does in 2024. And then Valleymore is actually first oil in 2025, not 2024, but that will come online in 2025. Simpler development, tie back to blind faith, three wells, two of which would be online in 2025. The third one would come online in 2026. And so, again, the production on that, a little bit in 25, and then you'll see more of it in 26 and 27.

Hey, Ryan, just more broadly on HESS, we are not planning to hold our investor day at our usual timing. We'll likely either have just closed or we'll be in the antitrust review process. This is a big transaction, impacts in Gulf of Mexico, but transforms the portfolio overall. We gave some guidance on potential asset sales also. So you should expect us to do an investor day several months after we close and when we have time to really put together a combined business plan for our investors.

Great, thank you. Thanks, Ryan. Thanks, Ryan.

We'll go next to Bob Brackett with Bernstein Research.

Good morning. You've spent part of the week engaging with your shareholder base and making the case for the acquisition of Hess. Can you talk to, not in details obviously, but perhaps the tone of those conversations, the enthusiasm, anything that surprised you?

You know, I'd say overall, and of course, we met with, I was out, Pierre was, you know, in some separate meetings than I was, but I was out, you know, in a number of meetings with John Hess, sometimes with larger Hess shareholders, sometimes with larger Chevron shareholders. I would say, in general, people see the long-term value proposition very clearly here, and I think they see it as a combined company that is stronger and one that is set up to be stronger for longer with the ability to really sustain cash distributions to shareholders in a very consistent, predictable and durable fashion long into the future. And so that is, there's no doubt about that. You know, some of the questions, you know, on the one side, did you get a high enough price? On the other side, did you pay too much, right? So there was tension in the In that, to be honest, during the negotiation, as we mentioned, this has been going on for some time, and John and I have been looking for a way to do a deal that is actually one that's good for both sets of shareholders and not easy because it's a great asset and the market recognizes that value. And so I think you can find nuances from people who either held one of the stocks or the other for certain reasons, and maybe this wasn't exactly what they expected. But broadly speaking, I would say, People see the long-term value creation. They see the transparency to resource depth, to production growth. The fact that you now have, with Hess, you've got a much more diversified set of assets attached to their portfolio, which de-risks any one of those assets, and it brings forward cash distributions to their shareholders meaningfully that would have still been, you know, several years into the future. For the Chevron shareholders who were wondering what comes next after what they can currently see over the next several years in our portfolio, rather than us pointing to a range of potential answers to that and say, we'll do the best of these, and we've got plenty of organic investment opportunities we're working on, I think it gives some confidence and certainty of what underpins that for the future. And so, broadly speaking, those are the kinds of discussions that we've had.

Very clear. Thanks.

We'll go next to Neil Dingman with Truist Securities.

Morning, guys. Thanks for the time. My question, Mike, is more on your shareholder return. You continue to have great financials and the shareholder return, both on the dividend and the buyback tie, continues to be quite high, paying out a bit over 100% of your free cash flow. I'm just wondering, as you continue to have the growth opportunities ahead, do you see any change in that shareholder return, particularly on the share buyback, or do you continue to try to balance kind of the growth and buyback programs you have now?

Yeah, you know, we've had a very consistent, you know, set of financial priorities for many, many years. You know, the first of which is to sustain and grow the dividend. 36 consecutive years now of per share dividend payouts. The last five years has been a 6% CAGR. Actually, I think the last 15 years have been a 6% CAGR and an announcement of 8% early next year subject to board approval. I think there's a strong track record there you can expect to continue. Second is to be disciplined in organic reinvestment into the business to grow those cash flows. You can be confident that we will continue to be disciplined in that reinvestment to drive returns and value. Number three is a strong balance sheet. Pierre mentioned we're single digit net debt ratio today. That's lower than we have guided to over time. And so over time, you can expect the balance sheet to move back towards the 20% to 25% gearing range that we've identified as where we're comfortable through the cycle. And then, you know, the fourth are the share repurchases. And we've, you know, got a range now of 10 to 20 billion. We're at the high end of that range when we close the transaction with Hess. We're at 17 and a half billion annually today. That's, you know, 5 to 6 percent of our float each and every year. And we've, you know, I won't go through the details, but we've indicated, you know, we can sustain that in a lower-priced environment, and that's where the lower end of that range would apply, and certainly in a higher-priced environment, which is where we find ourselves today, we're at the high end of that range. And so we would expect to be consistent, predictable, and to sustain that. I mean, consistent and durable being the key words here. So I think the broad framework is likely to remain unchanged, and I think our behavior will be very consistent with what you've come to see from us historically.

Perfect. Thanks, Mike. Thank you, Neil.

We'll take our final question from Alistair Sim with Citi.

Thanks. Hi, Mike, Pierre, and Jake. Mike, can I go back to Hess? You know, for several years, Chevron has looked a bit different to the other integrated oil companies in terms of, you know, the low downstream exposure. And, of course, now you're re-weighting even further to the upstream. So, you know, does... Does that balance bother you at all, or maybe how do you think about what an integrated oil company is?

Yeah, Alistair, the short answer is no, it doesn't bother me. We actually have been becoming a more downstream-weighted company the last several years, and that may not be obvious to most people, but our capex into the upstream has been below our depreciation. So our upstream business has been declining as a percentage of capital employed. In the downstream, we've made some big investments. We acquired a refinery in Texas. We acquired a renewable energy company. We've invested in new petrochemical facilities. We have two more of those petrochemical expansion projects underway right now. And so we had gone from 80-20 weighting or 85-15 weighting upstream to downstream in chemicals. to 80-20 over the last few years. When we close this transaction, we'll be back at 80-20, or 85-15, I'm sorry, which is where we've historically been. And that reflects a fundamental view that we believe that over the cycle, returns in the upstream are likely to be structurally higher than in the downstream, primarily because refineries are hard to close. They get built for reasons other than just pure economics. And governments tend to intervene in transportation fuels markets, in particular when prices are high, which kind of takes you out of full cycle economics and they kind of tend to clip the peaks off of those. Whereas in the upstream, you've got declining resource base and you've got growing demand. And so the fundamentals rebalance more quickly. You remove a little bit of investment and you see decline take over and you see demand continue to grow. And so markets that get imbalanced in the upstream rebalance more quickly. We also have been more oil-weighted than some of our peers. And fundamentally, that reflects a view that there are more alternatives to substitute for gas, particularly in power generation, than there are for liquids in transportation. And so those are kind of high-level drivers of why our portfolio has been constructed the way that it is. We want to be an integrated company. We think there are real opportunities to capture economic value through integration to build the capabilities to run our entire business by bringing capabilities, technology, skills to bear across those different segments. But our peers are all weighted more to the up than the downstream. The ratios are a little bit different. And we've long held those views and constructed a portfolio that reflects them. Thanks for the question. Thank you, Mark. You bet.

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 third quarter 2023 earnings conference call. You may now disconnect.