Michael K. Wirth; Chairman & CEO; Chevron Corporation
Pierre R. Breber; VP & CFO; Chevron Corporation
Alastair Roderick Syme; MD & Global Head of Oil and Gas Research; Citigroup Inc., Research Division
Biraj Borkhataria; Director, Co-Head of European Energy Research Team & Lead Analyst; RBC Capital Markets, Research Division
Devin J. McDermott; VP, Commodity Strategist for Power Markets & Equity Analyst of Power and Utilities Research Team; Morgan Stanley, Research Division
Douglas George Blyth Leggate; MD and Head of US Oil & Gas Equity Research; BofA Securities, Research Division
Irene Himona; Equity Analyst; Societe Generale Cross Asset Research
Jason Daniel Gabelman; Director & Analyst; TD Cowen, Research Division
John Macalister Royall; Analyst; JPMorgan Chase & Co, Research Division
Joshua Ian Silverstein; Analyst; UBS Investment Bank, Research Division
Neal David Dingmann; MD; Truist Securities, Inc., Research Division
Neil Singhvi Mehta; VP and Integrated Oil & Refining Analyst; Goldman Sachs Group, Inc., Research Division
Paul Cheng; Analyst; Scotiabank Global Banking and Markets, Research Division
Robert Alan Brackett; Senior Research Analyst; Sanford C. Bernstein & Co., LLC., Research Division
Roger David Read; MD & Senior Equity Research Analyst; Wells Fargo Securities, LLC, Research Division
Ryan M. Todd; MD & Senior Research Analyst; Piper Sandler & Co., Research Division
Sam Jeffrey Margolin; MD of Equity Research & Senior Analyst; Wolfe Research, LLC
Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2023 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded. I will now turn the conference call over to General Manager of Investor Relations of Chevron Corporation, Mr. Jake Spiering. Please go ahead.
Thank you, Katie. Welcome to Chevron's Third 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. Please review the cautionary statement on Slide 2.
Now I will turn it over to Mike.
Michael K. Wirth
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 continued 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 planned 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 3 months. Total project cost is expected to increase between 3% and 5%.
TCO 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. Free 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 start-up.
I'll now turn it over to Pierre to discuss the financials.
Pierre R. Breber
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 a 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 DD&A, 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 the 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 2 months in the 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 2 months of legacy PDC production. This was partly offset by a 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 Tamar. We anticipate affiliate dividends in the fourth quarter to be largely from TCO. As a reminder, we recorded 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 Hess 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. (Operator Instructions) Katie, please open the lines.
Question and Answer Session
(Operator Instructions) We'll take our first question from Roger Read with Wells Fargo.
Roger David Read
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.
Michael K. Wirth
Yes, 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 noncash charges. Timing effects, primarily inventory costs, we see with rising prices some tax reserves and charges for legal abandonment and other things and then some lower realizations with your mix and the lag effect in some of our 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 the, 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 upstream and international upstream in particular.
Pierre R. Breber
Yes, 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, 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 estimate. So those will show up in depreciation. And we 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.
Roger David Read
I'll sum it up as messy. I appreciate it.
Michael K. Wirth
[We'll check next quarter] every now and again. Go ahead, Katie.
We'll take our next question from Josh Silverstein with UBS.
Joshua Ian Silverstein
On the TCO, you had mentioned that in 2025, you expect 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?
Michael K. Wirth
Yes. So Josh, there's going to be some more capital, we said 3% to 5%. So think about around $1 billion Chevron share over '24 and '25, probably a little more weighted to '24 than '25. Cash flow from the operations will be lower by about $1.5 billion at $60 Brent in total over the next 2 years really due to the delay in the project. So it's equivalent to about 50,000 barrels a day in net production in each of those years.
So in total, 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 $5 billion. We're now seeing above $4 billion and a little more of that coming from production and cash flow from ops as opposed to CapEx.
Pierre R. Breber
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 in the start-up of FGP, which obviously adds incremental production.
We'll go next to Neil Mehta with Goldman Sachs.
Neil Singhvi Mehta
I just want to stay on the TCO question. As you think about, Mike, the biggest gating factors to getting from here to completion around FGP, just walk 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 is coming into service.
Michael K. Wirth
Yes. So the main message here, Neil, is as we completed both WPMP and then mechanical completion of FGP and we've begun to get deep into the commissioning, we've, I think, previously mentioned we worked with 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 were some more discovery work, we sent in an independent team to give us 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 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.
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 or 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.
We'll go next to Devin McDermott with Morgan Stanley.
Devin J. McDermott
I wanted to just 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 since the last quarterly call.
I think you 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 you could just step back, talk through what impact this 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?
Michael K. Wirth
Sure. So yes, 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. We already -- it doesn't materially change our circumstances here.
And so I think what you'll see is some more people lifting crude, bring it to the -- 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 150,000 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.
And that's driving -- the cash from that is going to pay legitimate operating expenses, tax 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.
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.
Pierre R. Breber
Yes. Consistent with what Mike just said, we're continuing to do cost affiliate accounting, which means we are not -- we don't record production or reserves, right? So that's not reflected in our numbers. And we only record earnings when we receive cash. So we're not -- we're 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.
We'll go next to Biraj Borkhataria with RBC.
I'm sure you get a few more on [TCO]. 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 I know it was a pretty small sample size of POPs in the first half of the year. So any comments there would be helpful.
Michael K. Wirth
Yes. 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 frac hits and some other factors. There was also some takeaway capacity on the Permian highway that -- 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 co-mingling. 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 got more POPs in the second half of the year. We've POP-ed about 60% of the planned wells in New Mexico. So the balance, 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, Biraj, 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.
We'll go next to Sam Margolin with Wolfe Research.
Sam Jeffrey Margolin
Maybe we'll stick with the U.S. and ask about just the U.S. upstream CapEx number. There's a lot of moving parts in here. You've got incorporation of PDC. You have kind of GOM projects and Ballymore 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?
Michael K. Wirth
Yes. 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.
And so 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.
Pierre R. Breber
I'll just add. So if you take out inorganic, which is $600 million year-to-date, $400 million in the third quarter for -- primarily for ACES and the $200 million that we had for PDC in the third quarter, through third quarter year-to-date, we're about $200 million above the ratable budget. Of course, fourth quarter tends to be higher. So as Mike says, we'll likely end the year a little bit above budget.
We'll go next to Paul Cheng with Scotiabank.
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 that, I mean, what have we learned from this process to ensure that your future project execution will become better and not facing the entire problem there?
I mean, it has been a challenging project all along, I think, to a number of different reasons. But quite frankly, that is a bit disappointing at this very last stage for the bit of the slip in the schedule and also the cost increase.
Michael K. Wirth
Yes, Paul, thank you. And look, I share the sentiment. So I understand where you're coming from. Big complex projects, you've been along for the whole ride. So you know early on, there were some engineering issues that we confronted and addressed. In the middle of it, the big thing was the pandemic and demobilizing, remobilizing, building medical facilities and a whole bunch of stuff 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 the big thing here, Paul, is as we've gotten into -- and you have to remember, this is -- 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 -- so 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 early in -- 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 it -- 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, it's 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 had 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, ought to be -- 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 a few, in the future, our commissioning plans will reflect that complexity more completely than the commissioning plans did on this one.
Pierre R. Breber
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 CPChem, Chevron Phillips Chemical Company, on lower petchem 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 as return to 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 the -- 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 5 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 increase in CapEx. And then we'll be heading to this more than $4 billion in '25. 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.
We'll go next to John Royall with JPMorgan.
John Macalister Royall
So I have a follow-up on the Permian ex PDC. You were down 2% in 3Q, including the non-op piece, and really helpful color there from Mike on Biraj's question. But just -- 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 770,000 guide for the legacy piece? And if not, is there a good way to think about 4Q production in general?
Michael K. Wirth
Yes, John, 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 770,000, 780,000 or so if you include PDC. And so yes, the guidance is still intact for the Permian. Go ahead, Pierre.
Pierre R. Breber
Yes. 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 the 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.
We'll go next to Doug Leggate with Bank of America.
Douglas George Blyth Leggate
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 another 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?
Michael K. Wirth
Well, Doug, you're right. I think there has been a reaction apparently in the market this morning to this. We've spent a lot of time -- I'll go back to Jay Johnson spending 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 this is a large, multiyear effort that had supply chains coming in from all the way around the world through the Russian inland waterway system through the pandemic.
And we've had our challenges with it. There are not projects in our queue that are remotely similar to this one. The kinds of things that we're talking about now are factory development projects across multiple shale basins. They're deepwater developments that I think the track record on those is quite different. And so I think the lessons on these really complex capital projects are that despite employing the best 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'd be very selective about the ones we do. 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 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 start-up. And the lessons from that will be applied in every other project that we do.
Pierre R. Breber
And I'll just restate the impact that Mike -- yes, thanks, Doug. 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, they were down a lot more than that. We talked about the earnings in this. We know that weighs also on the shares, at the same time, noncash items, timing effects that reverse and discrete items that are nonrecurring.
So we feel good about the company's performance in the quarter in terms of how we operated safely and reliably, how we captured margin. We know, as Mike said earlier, we have these quarters where it can be messy, can be noisy. It's one of them. But the underlying company is very strong and healthy.
We'll go next to Irene Himona with Societe Generale.
You're referring to your comments to higher OpEx and DD&A 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 in the results?
Michael K. Wirth
Yes, Irene, the -- so I think that the reference was simply these are additive to -- 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 DD&A are not different than what we expected. Synergy capture is good. 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 the nice thing about this in a quarter, where I appreciate Doug's view that maybe the reaction here has been a little -- we closed the transaction 5 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.
We'll go next to Jason Gabelman with TD Cowen.
Jason Daniel Gabelman
I wanted to ask about what's going on in your Middle East footprint. You've obviously had to take Tamar 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 gas somewhere else or offset those losses, and then how you think about the Eastern Mediterranean growth profile overall, if there's any change how you're thinking about it in light of the recent events over there.
Michael K. Wirth
Yes, 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 expansion projects that have been sanctioned on both Tamar 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.
Pierre R. Breber
Yes. 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.
We'll go next to Ryan Todd with Piper Sandler.
Ryan M. Todd
Maybe switch gears a little bit to the Gulf of Mexico. Can you maybe just provide any update on an overall basis? Do you anticipate the addition of the Hess assets in the Gulf to have any impact on your approach to the basin in the coming years?
And then you're scheduled to have three separate projects hitting at Anchor, St. Malo and Whale come onstream 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?
Michael K. Wirth
Sure. So on the combination with Hess, I think we'll come back to you as we close the transaction and we integrate those. 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 and -- but we'll talk to you more about that as we go forward.
In terms of specific projects, yes, you're right, we've -- 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 7 wells in total, 2 that will be online in '24, 3 in '25 -- no, 2 in '25, 2 in '26 and 1 then in '27. The FPU is safely moored out there in the field right now. The 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 of wells online. Think of it midyear 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 '25 and '26 in a greater way than it does in 2024. And then Ballymore is actually first oil in 2025, not 2024. But that will come online in 2025, simpler development, tiebacks to Blind Faith, 3 wells, 2 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.
Pierre R. Breber
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 will be in the antitrust review process. This is a big transaction impacting 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.
We'll go next to Bob Brackett with Bernstein Research.
Robert Alan Brackett
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 details, obviously, but perhaps the tone of those conversations, the enthusiasm, anything that surprised you?
Michael K. Wirth
I'd say overall -- and of course, we met with -- I was out. Pierre was in some separate meetings than I was. But I was out in a number of meetings with John Hess, sometimes the 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.
Some of the questions, 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. It was -- 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 derisks any one of those assets. And it brings forward cash distributions to their shareholders meaningfully that would have still been 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.
We'll go next to Neal Dingmann with Truist Securities.
Neal David Dingmann
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 side, 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 you do, do you see any change in that shareholder return, particularly on the share buyback or you continue to try to balance kind of the growth and buyback programs you have now?
Michael K. Wirth
Yes. We've had a very consistent set of financial priorities for many, many years. The first of which is to sustain and grow the dividend, 36 consecutive years now of per share dividend payouts for the last 5 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 the fourth are the share repurchases. And we've got a range now of $10 billion to $20 billion. We're at the high end of that range when we close the transaction with Hess with $17.5 billion annually. Today, that's 5% to 6% of our float each and every year. And we've -- I won't go through the details, but we've indicated we can sustain that in a lower price environment. And that's where the lower end of that range would apply.
And certainly in a higher price 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 keywords 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.
We'll take our final question from Alastair Syme with Citi.
Alastair Roderick Syme
Mike, can I go back to Hess? For several years, Chevron has looked a bit different to the other integrated oil companies in terms of the low downstream exposure. And of course, now you're re-weighting even further to the upstream. So does that balance bother you at all? Or maybe how do you think about what an integrated oil company is?
Michael K. Wirth
Yes, Alastair, 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 we've been -- 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've got 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 and chemicals to 80-20 over the last few years. When we close this transaction, we'll be back at 80-20, which is -- 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 clip -- tend to put the peaks off of those, whereas in the upstream, you've got a 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 takeover and you see demand continue to grow. And so markets get imbalanced and 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.
Pierre R. Breber
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.