ConocoPhillips Aktie

Welcome to the First Quarter 2026 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. [Operator Instructions] I will now turn the call over to Guy Baber, Vice President, Investor Relations. Sir, you may begin.

Thank you, Liz, and welcome, everyone, to our first quarter 2026 earnings conference call.

On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; Andy O'Brien, Chief Financial Officer and Executive Vice President of Strategy and Commercial, Nick Olds, Executive Vice President of Lower 48 and Global HSC; and Kirk Johnson, Executive Vice President of Global Operations and Technical Functions.

Ryan and Andy will kick off the call with opening remarks after which the team will be available for your questions. For the Q&A, we will be taking 1 question per caller. A few quick reminders.

First, along with today's release, we published supplemental financial materials and a slide presentation, which you can find on the Investor Relations website.

Second, during this call, we will be making forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings. We will make reference to some non-GAAP financial measures today, Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website.

With that, I'll turn the call over to Ryan.

Thanks, Guy, and thank you to everyone for joining our first quarter 2026 earnings conference call. As we begin, I want to start by acknowledging the ongoing conflict in the Middle East. Our thoughts are, first and foremost, with our employees, our partners and the broader communities directly affected by these events. The supply curtailment and ensuing macro volatility have not only impacted energy markets but are also being felt across the global economy. Periods of volatility in our industry are inevitable, but this conflict reinforces the importance of both U.S. and global energy security.

We certainly hope for a swift and diplomatic solution that resolves the conflict, protects U.S. interests, opens commerce and provide stability in the region.

Now turning to the first quarter results. We delivered another strong quarter of strong financial and operational performance. We generated $2.4 billion of free cash flow and returned $2 billion of capital to our shareholders. In the Lower 48, where we have the deepest and highest quality inventory of any operator, we continue to improve our peer-leading capital efficiency, meaningfully increasing the number of 3-mile plus laterals in our program.

In Alaska, we're winding down another successful winter construction season, with the Willow project now 50% complete. Our teams have completed the project's gravel scope, an important milestone and mobilization for summer work is underway. We also recently completed our 4-well exploration program in Alaska the first in a multiyear program to leverage existing infrastructure to unlock additional low-cost of supply resource consistent with our long-term track record. It's still early days but we are excited about the opportunity and the results and more low cost of supply resources coming to the greater Willow area.

As the broader industry increasingly recognizes Alaska's unique resource potential, we believe our long-standing position, legacy infrastructure investments and technical expertise provide us with a meaningful competitive advantage.

Turning to LNG. We recently executed a third-party tolling agreement in Equatorial Guinea, extending the life of the LNG facility well into the next decade. This is a strategically located asset in a gas-rich part of the world surrounded by a discovered resource which supports its long-term potential. Additionally, the Port Arthur LNG project continues to progress very well, with first LNG expected next year.

Turning to the outlook. While ongoing events have significantly tightened crude oil and LNG markets, the macro environment remains volatile and pretty impossible to predict. Amidst such uncertainty, it's critical our priorities remain steadfast. They are clear, consistent and they are durable. They have served us well for the last decade and will continue to guide us into the future. We will continue delivering base dividend growth competitive with the top quartile of the S&P 500. We will maintain and protect our investment-grade balance sheet.

Recall last year, we were one of the only companies that delivered on our shareholder return objectives and strengthen the balance sheet. We'll continue returning significant CFO to shareholders right off the top. We've averaged about 45% over the past decade through the cycles and after meeting all these priorities, we'll evaluate disciplined reinvestment for growth.

In terms of how these priorities are translating to our 2026 plan, our expected CFO generation is up materially given our unhedged oil and LNG torque. Shareholders will directly share in this upside with our 45% of CFO return of capital objectives. We have also added a modest amount of Permian activity over the second half of the year to maintain our operational efficiency into 2027.

Long term, ConocoPhillips continues to offer a compelling value proposition that is differentiated in the market. We believe we have the highest quality asset base in our peer space. As we have said before, we are resource rich in a world that is looking increasingly resource scarce. This is a distinguishing competitive advantage. We have the deepest and most capital-efficient Lower 48 inventory in the sector. And outside the Lower 48, we have an abundance of diversified, low cost of supply legacy assets, and we are uniquely investing in our portfolio to drive peer-leading free cash flow growth.

We're on track to deliver our previously announced $7 billion free cash flow inflection by 2029, driven by our cost reduction efforts, LNG projects and Willow.

So with that, let me turn the call over to Andy to cover our first quarter performance and updated outlook in more detail.

Thanks, Ryan. . Starting with our first quarter performance, we produced 2,309,000 barrels of oil equivalent per day. This includes the impacts of the Middle East conflict on Qatar volumes and higher royalty rates at Surmont from higher oil prices. These impacts were partially offset by strong performance across our Lower 48 and international portfolio. In the Lower 48, we produced 1,453,000 barrels of oil equivalent per day, representing 4% year-over-year growth on an underlying basis.

We generated $1.89 per share in adjusted earnings and $5.4 billion of CFO. Capital expenditures were $2.9 billion. We returned $2 billion to our shareholders during the first quarter, $1 billion in ordinary dividends, and $1 billion of share repurchases. We ended the quarter with cash and short-term investments of $6.7 billion as well as $1.2 billion in liquid long-term investments.

Turning to our outlook. We are updating our guidance to account for the impacts of recent macro events and the uncertainty surrounding the Middle East conflict. To be clear, this is not a call on when we think the conflict will resolve, we're simply trying to provide a clear and transparent framework you to model and assess the underlying performance of the company.

For production, the midpoint of our annual guidance is updated at 2,310,000 barrels of oil equivalent per day. This reflects a 20,000 barrels of oil equivalent per day annual impact due to Qatar being excluded from second quarter production guidance and a 15,000 barrel of oil equivalent per day annual royalty rate adjustment and Surmont due to higher prices. We've made no other adjustments to our annual production guidance. The midpoint of our second quarter production guidance is 2,200,000 barrels of oil equivalent per day, which reflects the full exclusion of Qatar production from guidance for the quarter, the Surmount royalty rate adjustment and planned second quarter maintenance.

Moving to operating costs. Full year guidance of $10.2 billion is unchanged, reflecting a $400 million reduction from 2025 due to the benefits of our cost reduction and margin enhancement program. We made strong progress in the first quarter, and we remain confident in realizing the full $1 billion run rate by year-end. For capital spending, we're updating our guidance to a range of $12 billion to $12.5 billion versus our prior guidance of about $12 billion, representing a 2% increase at the midpoint. This increase is due to slightly more Permian activity over the second half of the year. We're adding a rig to keep pace with the completion efficiencies, and we expect higher levels of nonoperated spend. These modest activity additions will maintain our operational continuity into 2027.

Additionally, we're incorporating a guidance range to capture the uncertainty around the macro environment as well as the Middle East conflict, specifically as it pertains to the timing for NFE and NFS spending.

To wrap up, we delivered strong first quarter results. We executed well financially and operationally. We continue to advance our strategy and amid a volatile macro environment, we remain committed to clear, consistent and durable priorities, that have served us well for the last decade. As Ryan mentioned, our expected CFO is up materially from the beginning of the year. We remain unhedged on oil and LNG to ensure we capture the price upside with 40% of our crude production linked to premium markets such as A&S and dated Brent. And shareholders are directly participating in this upside as we remain committed to returning 45% and of our CFO, consistent with our long-term track record.

Looking ahead, we remain focused on exiting our plan and enhancing our differentiated investment thesis, unmatched portfolio quality including leading Lower 48 inventory debt, attractive long-cycle investment, strong return on and of capital and driving sector-leading free cash flow growth through the end of the decade.

That concludes our prepared remarks. I'll now turn it over to the operator to start the Q&A.

[Operator Instructions] Our first question comes from Scott Hanold from RBC Capital Markets.

A lot happening, obviously, out on the macro front. And I know you all do a lot of work on the oil macro in addition to obviously having feelers out there. Can you give us a sense of your view of what's happened in the market if you've got any view of physical versus the financial kind of position of oil? And how you expect like operators to act and react? It sounds like you guys are going to maintain operational efficiency, but it would be good to see if you've got a view on what you're seeing and hearing from others.

Yes. Thanks, Scott. Maybe I'll let Andy talk a little bit about some of the numbers that we see out there and then maybe I come back and address some of your broader set questions after that.

Thanks, Ryan. Scott. Yes, I'll start with -- I think you said this for me. There's certainly a lot of moving pieces out there right now. And I'll summarize sort of our view of the world. I'm not sure it's too different to others, but it's -- I think it's good to summarize it. For about 2 months now, we've had about 10 million barrels a day of production offline that even factors in the redirected volumes in countries like Saudi Arabia. We have seen inventory and SPR releases that have partially backfilled some of that lost supply. And the ongoing SPR releases that have been announced, they'll certainly help through the May, July timeframe.

But I do think it's really important for people to understand that the brunt of the supply shortfall is currently being absorbed by refinery run cuts and demand curtailments. Now if you include the Persian Gulf refineries that have been damaged, the total global refinery run cuts right now probably amount to around 8 million barrels a day. Now as we look forward from here, we think the biggest challenge we're about to face is that the markets sort of had a bit of a grace period initially when the tankers that left the Persian Gulf in late February were still on the water.

Now all of those have reached their destination. The impacts of the lost supply is going to start to become more apparent. We could possibly see from here now inventory draws really start to accelerate. You've already seen that governments in over a dozen countries are implementing policies to ration or otherwise reduce demand in advance of physical shortages. And so given those factors I've just described, we are downgrading our view of global oil demand to be sort of flat year-over-year with probably a bit more risk to the downside if the conflict goes on.

And probably one final point I'd make before sort of passing it off to Ryan is, despite efforts that are ongoing to manage demand, we are going to start to see some import dependent countries potentially start to face critical shortages as we get into the June, July time frame. So I'll probably stop down. I'll let Ryan sort of add sort of a bit more to that.

Yes, maybe Scott, how are people acting. I think people are watching pretty closely to see what happens. Maybe a little bit of a short cycle investments and I'm sure that will come up in our call with the capital. We're just trying to maintain the efficiency gains that we've got in the Lower 48, and we won't be drilled out of some of our OBO activity. But we're trying to look longer term as well, as Andy said, assess the supply the demand fundamentals. I think at a minimum, we think the floor probably is going to have to raise up a little bit, at least relative to where we were before the conflict started. Recall, we had a mid-cycle TI price of about 65%, and that's -- we believe that's probably going to come up with the floor.

But we're trying to assess right now given the demand dynamics and the supply dynamics, but a long-term effect that's going to have on what we would call a mid-cycle equilibrium price and for how long that might persist. And recall, we were pretty constructive over the last few years before this got started with some uncertainty around how the physical and paper markets were acting a little bit, and this has just accelerated a lot of that. But certainly think the floor probably has to come up to account for the changes that have occurred over the last couple of months.

Our next question comes from Neil Mehta from Goldman Sachs.

Yes. Ryan, Andy, great comments there. And definitely, our thoughts are with your people in the region. I want to pay it over to Alaska, and we went through winter construction season here. And so I love the mark-to-market on how those plans progressed, where do you stand in terms of well construction? And what are the big milestones as we continue to derisk this project and get to that free cash flow inflection?

Yes, Neil, thanks for the question. We've had a really strong showing here just in the last 6 months in Willow. So I'll probably address maybe a couple of things. I'll touch on Willow, directly your question, and then very related to that, given it is the winter season, we've also had a really strong showing and exploration as well. So I'll take you through a little bit of how we're seeing these projects progress.

Starting with Willow, as mentioned in the opening remarks, we are, in fact, at 50% complete on the project. And that -- achieving that requires a collection of key milestones that our teams have been able to accomplish and get behind us here. And this winter season in Alaska, we accomplished the entirety of our planned work scope, which admittedly was a little bit of a challenge. We had quite a few weather days, not dissimilar from our very first winter season. And despite that, again, the teams were able to accomplish the full winter scope.

And by that, certainly probably most important to us as part of critical path was the civil work. And so we were able to get all of the bridges down and the entirety of the gravel scope. So think roads, pads and then even the airstrip and that sets us up then for our ability to execute the summer work and especially important with gravel, it allows you to dry and mature that gravel will create the compression necessary on that to continue the structural work that's upcoming, then obviously in the construction of future facilities and even pipelines.

And then as it relates to pipelines, important this year for us was the east-west scope. And that's important because it allows us to begin to make the connections back into the existing operations. And by that, I mean Western or slope or Alpine with those connections just within the coming week, we'll be bringing fuel gas. And then we'll be firing up our power for Willow. And so again, we've just been really successful in accomplishing the scope here, we've laid out as we continue to commission the op center.

And then, of course, with engineering largely wrapped up and complete here in the Lower 48 on the Gulf Coast, our process modules achieved a similar milestone, which is also being 50%, just slightly better than 50% complete there in fabrication. That's important because certainly not this summer, but next summer, we have plans to see lift those into Alaska, which becomes the next major milestone for us to get those processing modules up there. And so again, all of this in aggregate, puts us in just a very strong position for this early oil expectation that we have for 2029, and all of that is on track. And that's obviously important.

So it's underpinning this compelling value proposition that we have for the $7 billion free cash flow inflection. But then even thinking well beyond that is exploration. And again, also, as you heard from Ryan, we had a strong showing here too. We speak a lot to the 4 wells that we had planned this year, which were successful for us, but this is the largest winter season and exploration that we've had since 2020. And with that came to 4 wells, but we also shot seismic and then we also did quite a bit of gravel exploration and had really high success ratio there on finding gravel for future pads.

So when we look at that exploration program, again, as you heard from Ryan, I'm really pleased to report. And by that, I mean we found hydrocarbons out there where we were prospecting and drilling. And so naturally, then our subsurface teams are poring over the results, seeking to ensure that we can well characterize what we found. And of course, commerciality comes with typically more than 1 season. And that's why we call these exploration and appraisal wells and seasons. It will take several, but certainly with what we found really looking forward to the opportunity to keep Willow full.

Again, and I think that underpins our objective here, which is we're in this to identify new resource and pad development opportunities to do just that, which is keep this infrastructure full. And you've seen the track record from us in the past. And with the success that we've been realizing just in the last 6 months, again, just a really strong showing from our Alaska team.

Our next question comes from Betty Jiang from Barclays.

The -- a lot of buys right now on the short cycle response to higher oil prices and you guys being the first one out of the gate and sort of leaning into activity in the Permian, which clearly makes sense for you guys given the deep inventory. But can we just get a bit more color on the decision process from Conoco's perspective to link into Permian activity now? And alluding to your mid-cycle views earlier, what price would it take to flex activity further? And what will be the sensitivity on production outcome in 2027?

Betty, Andy here. Maybe I'll quickly start this and then Nick can talk a bit more specific about the details of what we're doing in the Permian. I did cover in the prepared remarks that what we've done here is effectively increased the midpoint of the CapEx by about $250 million. And I think it is important to sort of to describe why we're doing that. It is -- we keep having the operational efficiency that Nick will talked to. And it's important basically the way we think about steady state that we keep that going. So on the operator side, it really is just a continuation basically of our steady state, just given how efficient we're being.

And then on the nonoperating side, as I said in our prepared remarks, it's more in anticipation and starting to see the early signs of this of some of our nonoperated partners in to ballots for more wells. So I'd say it's more sort of the $250 million is more around sort of operationally setting ourselves up and sort of being thoughtful about what we keep our steady state and we react to partners versus a big sort of macro call on price.

Maybe with that, I'll let Nick just give a bit of the specifics on what we're doing. We can come back to more to cover.

Yes. Thanks, Andy. As Andy mentioned, that $250 million of additional activity is concentrated in the Delaware, and that's a combination of operated and non-operated. On the operated side, we continue to drive significant efficiencies both on the drilling and the completion operations. On our completion efficiencies, that's slightly outpacing the drilling side. So we're adding another Permian rig versus prior plan to help us keep pace with our frac crews and maintain our level-loaded steady-state operations approach that we've talked about for a number of years.

The key item and ultimately, what we don't want to take place is have any frac gaps due to the efficiency improvement that we're continuing to capture. If you recall, last year, as we exited 2025, we had a 15% improvement in D&C both operational efficiencies, and we continue to see those trends. But on the completion efficiencies, those are outpacing it.

Now if I pivot to the nonoperated OBO side, we have started to see more well ballots from our partners which will likely translate to a higher level of OBO spend over the second half of the year. And we're not going to elect out of low cost of supply, high-return OBO projects in this price environment. We've seen it in the past. They're competitive projects, they're short cycle with good returns. So that's the right choice from a returns perspective.

Again, this activity additions are a modest capital add to our second half program, and we'll maintain our operational efficiency going into 2027.

Yes. I would just add that these are no-brainers. These are does for us. We're not going to be drilled out of inventory by others, and we're going to keep our efficient machine running and so these are last half of the year doesn't have a large impact on 2026, but sets us up for the continued growth that we're seeing in the Lower 48 in our portfolio. Year-on-year, you saw it in the first quarter, you'll see it year-on-year, and that will continue into 2027. In the meantime, we'll be assessing what we think mid-cycle price is going to go do and what the new equilibrium might look like and then what that follow-on means to the cash flows that we generate as a company, the returns that we're going to send back to our shareholder in what we reinvest for growth and development in the company. And that will be coming later this year just as part of our normal processes.

Our next question comes from Doug Leggett from Wolfe Research.

So I guess, Ryan and Andy, I'm looking at Slide 5 and those of us who have been around long enough, Ian, remember what you went through in '26 with the dividend. And now we're sitting here looking at low 70s, you're probably doing $10 billion of free cash flow according to your chart, and that's 70% upside. My question is that you've stuck to the 45% cash flow payout. Your commitment is actually more than 30%. And clearly, there's a little bit of post-cyclical stuff going on with the share price. These windfalls can be capitalized in different ways, especially through your dividend policy.

So I just wonder if you can walk us through in these kind of situations, why not flex down in the payout? Why not think more about the longer-term dividend to breakeven the balance sheet. I'm just curious where your head is at on buying your shares at the top of the cycle? It might not be the top of the cycle, but it's certainly elevated for the time being.

Yes. No, thanks, Doug. I mean, we like to think about share repurchase sort of in a dollar cost average. We tweak around the edges, which is why it was probably a little bit lower in the first quarter, but it was a good time to be buying in March and in April. So you'll see probably is buying more in the second quarter as we go forward. But more fundamentally to your question, so our 30% floor is set in a mid-cycle price construct that we start with for the company. So we think about what mid-cycle price are, what an equilibrium, look, we know we're never in a perfect kind of world, but we have to understand that from a supply and demand percentage perspective, so we can understand sort of what cash flows do we generate, what can we get back to the shareholder.

And clearly, since we set that coming out of the downturn in 2014 and 2015, when we recast the value proposition for the company, it made sense, but we've had mid-cycle prior. So the actual price has been higher than our mid-cycle call for most of that time. So we've been able to afford and be able to provide more than 30% back to the shareholder. Our history has been, I think, now coming up on a decade through the cycles even through the low point of the COVID pandemic in 2020 and the high point of 2022 when we were sending quite a bit back to the shareholder. So we think about it through cycle, we try to set a mid-cycle price. And we just are constantly trying to drive down the reinvestment rate in the company.

We're trying to drive growth for the least amount of capital as we can in the business, which is why Nick talks about what we're doing in the Lower 48 to drive the efficiencies that his team is doing, but Kirk is doing around the rest of the world and the opportunity we have in our legacy assets. So we've been able to afford something higher than our base, and that represents the 45% commitment that we've made for this year. because we recognize that the strength and the power of the company is doing.

Now we don't want the dividend to get outsized as you referred to before, which may have been -- for those that remember pre-2015, 2016, there's not any of us around anymore, Doug, maybe you and I, and that's about it. But look, we want to make sure that we can sustain the dividend. We want to make sure we can grow the dividend at a competitive S&P 500 rate. We think that's important, being able to constantly continually, annually grow it. It's something we think is competitive with the S&P 500 top quartile.

And that's our commitment to go continue to do that. But at the same time, we want to make sure the dividend does get an outsized portion of our cash flows at a mid-cycle price, whatever mid-cycle price we call. So we're trying to manage both those things. And typically, the dividend today is certainly affordable, growable but doesn't represent the full 45%. So we're augmenting that with the share repurchases. And we think that makes sense over the long haul. It reduces the absolute burden of the dividend going forward. It might have some politic nature to it a little bit. But we aren't -- we don't cling to it steadfast. We'll ratchet up and down a little bit quarter-to-quarter to try to manage some of that, but we do want to make sure we hit the 45% made up between the base dividend and whatever shares we're repurchasing in the market and we try to take a pretty ratable effort to go do that.

Our next question comes from Lloyd Byrne from Jefferies.

Can we talk about OpEx a little bit. It continues to stand out. And if you could just maybe comment on its trajectory from here? And then is there anything other than maybe conservatism that keeps you from bringing the full year guide down?

Andy here. Yes, so I think I can take this one in terms of we did set our budget at $10.2 billion, and that was, as a reminder, $400 million lower than last year. And as you point out, our 1Q results were very strong. We're really pleased with them. And it's ratably being driven by that we are taking costs faster than we'd originally premised from our cost reductions, both on the labor side and on the non-labor side of our lease operating costs. So when we look at it and Q1 is reinforcing this, we're very confident that we're going to hit that $1 billion in run rate savings by the year-end.

But really to get, I think, to the heart of your question in terms of guidance, I think it is only the first quarter. We're very, very pleased with how things have gone. But we'd like a little bit more time before we revisit where we would want to reduce guidance or not.

Our next question comes from Devin McDermott from Morgan Stanley.

I wanted to ask on the LNG portfolio outside of the Middle East first, just a little bit of additional detail on this EG agreement you signed and more broadly, you have this big commercial portfolio of LNG offtake contracts, including 5 million tons off of Port Arthur. I was wondering if you could just give an update on where you stand in marketing and placing those commercial LNG volumes? I'd imagine have gotten more valuable with everything going on in the market. right now.

Sure. I can start with the second half of your question and then specifically to Equatorial Guinea, I'll let Kirk jump in and maybe share a bit more on that. So yes, our LNG strategy, we -- on the commercial side, we really couldn't be more pleased with the progress we're making. I think as you say that what's happening in the market right now, our view is that we have seen a structural tightening of global LNG, not just for this year but for quite some time to go. You'll recall that pre all the events in the Middle East, we actually had a bit of a contrarian sort of view versus consensus where we thought the market was more in balance versus sort of the thesis of a bit of a glut.

So that's obviously all gone away now. And depending -- I think everyone is now sort of seeing sort of the tightening market. And as we look at it specifically, where we where -- we're in a situation where we've got sort of first movement advantage here now where we've pretty pleased that we put our 10 million tonnes that we already have in place, just like we think about our E&P portfolio, low-cost supply in this world, low liquefaction costs. important, we've got that where we've already placed the first 5 million tonnes predominantly to Europe and a bit into Asia for Phase 1.

And as you can imagine, sort of the conversations we're having about placing sort of what else we have is intensifying right now with interest in sort of in those volumes that we have. So I think it's just reinforced. The global security element of it as well in terms of the importance of having positions on the Gulf Coast and the value of that. And that's really just played into our strategy really say the first mover event has been very important to us on the commercial side.

And probably one last comment to make beofre passing it off to Kirk. It's -- we'd be remiss not to also mention sort of our -- the rest of our resource LNG business outside of commercial with APLNG and others that where effectively, those projects are priced off of long-term contracts linked to Brent for the most part. So they're also sort of doing well in this environment as well. So I think the LNG strategy is all proving out very nicely for us sort of along the lines that we would hope. And then maybe specific to your actual Guinea question. I'll let Kirk jump in.

Devin, certainly, as you're pointing to, the EG LNG asset came to us through the Marathon acquisition, and it came with a strong reputation of performance. And so the question for us was really about longevity. And the more we've come to understand just the performance and the capability of that asset and that organization. We've just been really quite pleased. As described, certainly in the release, we were able to strike an agreement, a tolling agreement with a third party at EG LNG. And so again, maybe to just step back a bit, this EG LNG asset for us or the Equatorial Guinea asset comes with an upstream operation from the Elba unit.

Obviously, we have production facilities offshore, and then they're on the island next to Moab, the capital. And then, of course, we have an equity position in EG LNG as well. And so our ability then through EG LNG to strike this this agreement then comes with an opportunity to further extend the life of this EG LNG asset. It allows us to run that facility at a strong utilization rate and pushes the life of that asset again well into the 2030s. And that gives us a bit of time, which you've also seen some press from us around the HOAs that we've been striking there with the Ministry in Equatorial Guinea looking at discovered resource.

And I think that's an important clarification, which is there are opportunities, known resource, specifically gas in and around the island and Equatorial Guinea waters that we can begin pursuing to understand what those look like for us to bring those to a commercial opportunity. And again, utilize the age of the capacity that will exist for us long term in that asset. So again, it's an interesting asset. Sales out of EG LNG consists of both SBA and a long-term SPA as well as spot. And it's in a great position to take cargoes both north and Europe or around the horn into Asia. So again, pleased with how this asset is continuing to prove itself out there as well.

Our next question comes from Arun Jayaram from JPMorgan.

I had a quick follow-up on LNG. I was wondering if you could comment how some of the Middle East disruptions are impacting your view of the LNG macro picture. I was wondering if perhaps you can give us a little bit of an update on the NFE and NFS projects, just given some of the disruptions in that part of the world?

Yes, I can start with the macro and then Kirk can go into the specifics on NFE and NFS. From a macro perspective, I kind of touched on this on an earlier answer, but if you think about what's actually happened with the 2 months that we've basically had, Qatar production shut in, in terms of not going through the straight. That's 20% basically of the LNG sort of that's not flowing. And maybe a better way to put that into context so that people can visualize it. That equates to something like 200 cargoes that have not basically sailed. So 200 cargoes haven't been delivered.

So our view of the macro is that we likely have already seen a little bit of a structural change here where there's going to be LNG shortages for quite some time. And when we look at basically where we're at with this is it's going to be a situation where prices are likely going to be quite constructive for a period of time as really people are going to have to basically better price to sort of manage the demand supply piece of this equation. And I think when you look at what Qatar's publicly said around the damage to Ras Laffan that it's going to take some time to get that capacity back on the market as well.

So our in-house view is that we've essentially seen a bit of a structural change on LNG with all that's happened and it's going to take quite a long time to basically get anything back close to where we used to be. So I think with that, I can let Kirk talk specifically about sort of our position in NFE and NFS but -- so the broader macro is one where I think this is sort of crystallizing to be a little different to the oil in terms of where we know we kind of start to know where we are with this.

I would add too, Arun, before Kirk jumps in on naptha we're watching gas inventories in Europe that today are well below where they should be given the build that they should be experiencing. So really concerned, depending on the when winter comes across Northern Europe and how hard that winner comes is the gas going to be there. Certainly, the inventories that today at this moment in time would put a kind of a blinky light on some of that going forward. So maybe Kirk can talk specifically about Qatar.

Yes. Maybe just a few quick clarifying comments, Arun, on how this certainly is affecting us Naturally, I think you understand and folks know that one, our single producing asset there in Qatar is in. And as a run rate, that was roughly 80,000 barrels of oil equivalent here last year. So a good run rate, and that's roughly 3% of our total company production and very similar on total CFO. So worth clarifying that the remainder of our global portfolio has been largely unaffected, really unaffected by these recent events. So it's really been quite contained to just simply this entry asset.

And naturally, as you'd expect, QatarEnergy QE executed a very controlled ramp down and ultimately largely a shutdown across most of their trains there at Ras Laffan for both security and process integrity reasons, but also because clearly, as Andy mentioned, with the straight closed, there's just limited capacity, if any, to lift cargoes there.

As QE disclosed, 2 trains were struck. Those were not ours. And again, that took just under 12 MTPA off the market. And QatarEnergy has been quite explicit about the fact that they expect that to impact the global market for upwards of 3 to 5 years. And so again, unaffected for us. And while it's easy to complete the construction of NFE NFS with the operation of those, they're really quite separate. And what we are pleased to see is despite the conflict construction on NFE and NFS both has been progressing.

Now naturally, there has been some impacts and some interruptions, but much different than an operations. And so -- also, while QE has disclosed that they do expect delays, it's a bit premature to provide really strong guidance on just specifically how that's going to manifest. But I would say, largely, we're expecting to delay to be to the tune of months. And you'll also recall QE guided on second half of this year's start-up. And so it could be possible certainly that, that extends into the early part of next year.

So again, we chose to simply guide on production for the company on 2Q removing that from guidance. I certainly felt like that was best in terms of clarity for all and then we'll be watching this closely as both construction and our own production there in QE continue to evolve very conflict dependent. Hopefully, that's helpful.

Our next question comes from Bob Brackett from Bernstein Research.

Apologies for a bit of an educational question, but there's a couple of topics that I'm working on educating folks and you may help. One is just the idea of one on one price realizations, especially as they pertain to timing given the very sharp moves in crude price we've seen. And the second would be I've been at 101 around the engineering of shut-ins. You guys have certainly a 2020 track record of understanding that stuff, shut-ins and the potential long-term impacts to production. I appreciate that.

Okay. Bob, Andy here. I'll start with the -- maybe the first part of that question on pricing. I'm looking forward to reading your report on this because you can probably teach us a thing or two as well. But maybe I'll describe it from sort of our perspective from ConocoPhillips. And hopefully, that's helpful, and I'll let Ryan maybe mention -- talk about the other parts of the question.

So in terms of sort of -- I think it might be -- if I answer your question from the pricing, really from our portfolio perspective and then you can sort of -- you can infer from that. When you think about our portfolio, we're in a situation where about 40% of our crude volume is linked to either Alaska or international price markers. And conveniently, that's split pretty equally between the 2. And then specifically to how the -- what we're linked to and how the pricing works, the international crude oil volumes, they're mainly linked to date rented pricing which you've been seeing, we're all -- I think everyone is now talking about dated and ICE like we haven't done it in a long time.

But you're seeing basically how the data grant basically has been trading at a premium to ICE, more the physical to the outlets. Now on the A&S side of things for us, A&S is effectively priced off of ICE Brent. So we basically have a bit of a 50-50 split between the 2, but with a lot of Brent leverage. And then -- specifically to your question around then, you do see a bit of a lag basically in terms of when do you see the cash versus when do you see the earnings related to these things. So you'll see it flow through the earnings first, obviously, but with the lag basically in timing of when the cash actually comes in.

And that varies basically market to market for us. But you'll start to see sort of the cash more meaningfully come in sort of a month or so later. So that hopefully helps us explain our exposure to sort of hit and sort of maybe help you sort of understand sort of how the importance of whether we're on dated or whether on ICE. But I am going to take an opportunity while you asked the question, there's another point that sometimes gets lost in all of this, this quarter. But yes, we've got that global exposure, and that's really important.

But I also want to sort of just mention on our realizations that we have a large Lower 48 component as well, which is obviously priced off the WTI. And we were really pleased with the realizations we were getting on our WTI. I think we had about a 98% realization this quarter. And that might get a bit lost when you look at our total company realization when it all gets mixed together because when you mix it all together, you had 3 or 4 things happening with you saw the WTI to Brent diff really, really expand out to about $9 a barrel. And then obviously, you've got the timing of the sales that we have in places like Norway.

But it is a pretty complicated set of moving parts right now. And there's going to be some timing between cash and earnings that are going to take a month or 2 to sort of all start to line back up.

And on your second part, Bob, I assume what you're talking about is the subsurface impact to shut in. And I guess some of our experience would be -- don't have direct experience with a lot of the Middle Eastern assets, Saudi and UAE and others, but probably similar to what we have on the North Slope, very large, productive, high porosity, high permeability assets like that, we wouldn't expect a whole lot of problem with them coming back to -- it will be a ramp-up period to be coming back to pretty much full capacity, minus any surface constraints or issues that were created as a result of damage that they might have above ground.

But in some of these, you have to ask here, are they keeping the waterflood going while they're shutting in, if that's the case, they're probably building pressure and you probably get some flush production. So it's probably very, very high-level answer to your question, but I wouldn't expect a huge supply impact as they bring back on these fields damage to the subsurface.

Our next question comes from Josh Silverstein from UBS.

I wanted to get an M&A update from you guys, maybe more from a divestiture angle. I know you guys are very resource risk as you mentioned, and you do have an ongoing divestiture program. I was just curious if these noncore assets are you seeing strengthening valuations for these right now given the higher pricing, does it make you want to be more aggressive in selling assets into this market? And then maybe just an update as to how you're thinking about the part of their Phase 1 equity stake that you have on the investor front?

Yes. I can take that question. So probably worth us putting our divestiture program that we've announced sort of in context. We'd announced a $5 billion program and $3 billion of that is already behind us. So there's about $2 billion of the program that's to go. And I would really very much put this in sort of the business as usual for us. I think it's -- I'll say because I think it's out there in the public markets and being talked about a lot. We do have data room opened in the Permian right now, and we've got a couple of packages in that.

And -- but this -- it's really important when we think about this. It's not -- the payment is not 1 sort of big thing. It's a collection of assets within a basin. And these are assets that we would consider within the Permian that are noncore to us, probably something that we wouldn't get to in 10 to 15 years, given the depth of our inventory. And of course, yes, we are seeing sort of a lot of interest in that. But I think it's very, very important to sort of emphasize I think our track record will show this, that we are not going to be schedule driven by this. This will be -- and we won't sell anything that we're not getting full value for.

So we'll go through a process and if we get offers for full value for noncore assets that we're not going to develop for a while, we'll certainly take a look at it. But it's very much around the edges and just the usual portfolio type cleanup work that we always do.

And then to the last part of your question on pull out of Phase 1, we're kind of in a perfect situation here where we certainly don't need to sell anything. That asset is being derisked every day as it comes closer to first production and we'll have that asset online in 2027. So we can't wait to see that happen. And it's -- I think everything that's happened in the Middle East is just reemphasize sort of the importance of having these secure assets that we have in our portfolio.

So maybe a day will come in the future where we get an offer that basically, it fits into sort of an infrastructure type investment. But we're certainly under sort of no need to basically sell that asset. And I can't really see why we would contemplate that while it's still under construction. We'd rather get it on and maybe in the future, it isn't core, but nothing there that I would say that we're not happy with.

Our next question comes from Philip Jungwirth from BMO Capital Markets.

Your Montney position has a lot of resource and you've had better results than some of the offset operators up there. Just wondering what's the appetite or valuation creation opportunity to add to this liquids-rich position where others might not have the same technical understanding or operational capabilities? And separately, could Canada all fit into the LNG Awake strategy, if you were to target the high end of 10 to 15 MTPA.

Yes, Philip. I appreciate the question on Montney. We've been continuing to see some really strong performance, and certainly, as you highlight, coming out of our Montney asset. We've been progressing this in a very disciplined and deliberate manner. And while we're out of the appraisal phase, we are admittedly still in what we would describe as early development, actively optimizing our plans and incorporating all of the learnings that are really quite unique to the basin.

And as well as all of the optimizations that we're able to reap from our mature and very distinguished position here in the Lower 48. We've been running roughly 1 rig and expect to continue in a very similar pace and fashion because, again, certainly, as we've experienced in the Lower 48, when we naturally pair up really strong crews, whether it be drilling and completions with each other. We, too, are seeing some really strong performance across the two.

And we like the performance again because it is so strong liquids. We're roughly 50% liquids with a couple of streams there between NGLs and the condensate and crude, and we're able to take advantage within that liquids market of each 1 of those. And so it's a very competitive resource Naturally, we do, in fact, because we have such a strong position, and we've been seeing such good performance. We're watching the opportunities. We watch the landscape, but certainly as it relates to M&A or BD work, we'll be smart about this.

And if we see there's an opportunity that creates a lot of synergies for us, naturally, we'd entertain that. And then, of course, on the gas side, because we are so dominant in the liquids position, this is not a major driver for us. And in fact, we're naturally hedged to some degree because we use fuel gas. We use the gas directly associated with Surmont and our operations there in the oil sands. So I would say we're encouraged to hear that there are plans for the next phase of LNG offtake coming out of Canada. We'd like to see Canada bringing much more scope and scale at a better pace there.

And so I would just say our growth plans are certainly dependent on offtake to get very aggressive in the Montney with our own development plans are going to -- we're going to need to see a call on those barrels and on that gas and more offtake coming out of BC. So again, I would just say this is something for us to watch carefully, and we'd like to see some more progress by those who are maturing those projects.

Maybe I'll just quickly jump in there as well, very directly from a commercial LNG perspective, we'd be very happy to have a bit more offtake on the West Coast. But just like our E&P portfolio, we cost of supply, liquefaction fees basically drives everything. And as we look at it, if there's competitive liquid action fees, from expansions that happen and new projects in Canada, we'd be -- we'd certainly want to take a look at that just like we'd like to look at offtake from many other locations. So yes. I think having some West Coast offtake wouldn't be a bad thing in our portfolio.

Our next question comes from Alastair Syme from Citi.

I wonder if I can get you to talk to the attract business of incremental capital of the Delaware versus refrac opportunities in the Eagle Ford? How would you compare and contrast as ?

Yes. So if you look at the Delaware and Eagle Ford, obviously, they're quite different. But on the refracs in the Eagle Ford, we do typically do 50 or 60 in a year -- you can think about -- you can execute 1 for about 60% of a development well and get a 60% uplift on that original completion on your EOR. So in that case, you're looking at kind of mid-$30 cost of supply to upper $30 for refracs. If you then go to the Delaware, which is some of our lower cost of supply, you're executing currently kind of the low $30s to mid-30s. So from an overall Delaware, we'll have a stronger overall return than a refrac, but they're very, very close. We're talking probably $2 to $5 of cost supply difference. So very very, very competitive in the portfolio between those 2 opportunity sets.

Our last question comes from Kevin MacCurdy from Pickering Energy Partners.

Looking at the updated capital program this year, you addressed the Permian activity earlier. But on Slide 5 of your deck, you show some potential variance in regard to the macro Middle East uncertainty. Can you expand on that a little bit? Would this just be deferred Middle East spending? Or are there any other considerations represented in that chart?

I think predominantly, I think, as Kirk's covered and I've covered it earlier, it's really a range of uncertainty on what happens with NFE and NFS capital during the year. I think Nick also covered 1 of the other uncertainties and Ryan covered that we don't know exactly what's going to happen on the nonoperated side in the Lower 48, but we're not going to -- as we described, we're not going to put ourselves in a situation where if we get balanced that we won't participate in low-cost supply projects. So I would just take it as a general uncertainty bar right now in a very uncertain world basically.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

Welcome to the Fourth Quarter 2025 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. [Operator Instructions]

I will now turn the call over to Guy Baber, Vice President, Investor Relations. Sir, you may begin.

Thank you, Liz, and welcome, everyone, to our fourth quarter 2025 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; Andy O'Brien, Chief Financial Officer and Executive Vice President of Strategy and Commercial; Nick Olds, Executive Vice President of Lower 48 and Global HSC; and Kirk Johnson, Executive Vice President of Global Operations and Technical Functions.

Ryan and Andy will kick off the call today with opening remarks, after which the team will be available for your questions. For the Q&A, we will be taking 1 question per caller.

A few quick reminders. First, along with today's release, we published supplemental financial materials and a slide presentation, which you can find on the Investor Relations website. Second, during this call, we will make forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings.

We will make reference to some non-GAAP financial measures. Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website.

With that, I'll turn the call over to Ryan.

Thanks, Guy, and thank you to everyone for joining our fourth quarter 2025 earnings conference call. 2025 was another very strong year for ConocoPhillips, marked by consistent financial and operational execution and a number of important strategic accomplishments for our company.

First, we outperformed all our major guidance drivers from the beginning of the year. CapEx, operating costs and production, demonstrating the strength of our team's quarter-to-quarter execution. On a pro forma basis, we grew production by 2.5% in 2025, while driving significant reductions to both our capital and costs.

On return of capital, we met our objective to return 45% of our CFO to shareholders, consistent with our long-term track record, while again increasing our base dividend at a top quartile S&P 500 growth rate. And we did so while further strengthening our investment-grade balance sheet, certainly a differentiated accomplishment. Our cash balances are higher today than a year ago, and our net debt is lower, putting us in a very strong financial position to start the year.

We successfully integrated Marathon Oil outperforming our acquisition case on the most important metrics. We added more high-quality, low-cost of supply resource, doubled our synergy capture, realized a further $1 billion of onetime benefits and completely eliminated the Marathon Capital program while still delivering pro forma production growth. And as part of our drive for continuous improvement, we launched and have already made great progress on our incremental $1 billion cost reduction and margin enhancement initiative.

We progressed our commercial LNG strategy, growing our offtake portfolio to approximately 10 million tonnes per annum. And finally, we improved our Lower 48 drilling and completion efficiencies and advanced our differentiated major projects, which we expect to drive peer-leading free cash flow growth through the end of the decade. So 2025 was a great year for the company. While these are significant achievements, we're not stopping there. We will build on this success.

Turning to 2026. Our primary focus is on delivering $1 billion combined reduction across our capital spending and operating costs while growing our production on an underlying basis. On shareholder returns, we once again expect to return about 45% of our CFO to shareholders while continuing to grow our base dividend at a top quarterly S&P 500 rate. Top quartile dividend growth is sustainable as we expect our free cash flow breakeven to decline into the low $30 per barrel WTI range by the end of this decade.

Looking beyond 2026, I believe ConocoPhillips continues to offer a compelling value proposition that is differentiated both within our sector and relative to the broader S&P 500. As I've said before, I believe we have the highest quality asset base in our peer space, a distinguishing competitive advantage, especially in the context of a U.S. shale industry that continues to mature.

We are resource rich in a world that is looking increasingly resource scarce. We have the deepest, most capital-efficient Lower 48 inventory in the sector. And outside the Lower 48, we have an abundance of high-quality, low-cost of supply legacy assets, and we are uniquely investing in our diverse major projects to transform the free cash flow generation profile of our company.

As a reminder, the 4 major projects we have underway, combined with our cost reduction and margin enhancement initiatives are expected to drive a $7 billion free cash flow inflection by 2029 that will double our 2025 free cash flow generation. And that free cash flow inflection is now underway. We anticipate realizing approximately $1 billion of incremental free cash flow each year from '26 through 2028, with another $4 billion from Willow coming online in 2029. And that's a growth profile that's unmatched in our industry.

Now with that, let me turn over the call to Andy to cover the fourth quarter performance and 2026 guidance in more detail.

Thanks, Ryan. Starting with our fourth quarter performance, we reported another quarter of strong execution across the portfolio. We produced 2,320,000 barrels of oil equivalent per day, consistent with the midpoint of our production guidance. We generated $1.02 per share in adjusted earnings and $4.3 billion of CFO. Capital expenditures were $3 billion, which brought our full year capital spend to $12.6 billion. We returned $2.1 billion to our shareholders during the fourth quarter, including just over $1 billion in buybacks and $1 billion in ordinary dividends bringing the full year return of capital to $9 billion or 45% of our CFO, consistent with our guidance and our long-term track record.

We closed over $3 billion of asset sales during 2025, demonstrating strong progress against our recently upsized $5 billion divestiture target with $1.6 billion of proceeds received in the fourth quarter. For the full year, we paid down $900 million of debt and cash balances were up $1 billion resulting in net debt reductions of nearly $2 billion, highlighting our commitment to both returning cash to shareholders and our investment-grade balance sheet. Cash and short-term investments finished at $7.4 billion, along with $1.1 billion in long-term liquid investments. On reserves, 2025 was another solid year. Our organic reserve replacement ratio was just under 100% while our trailing 3 years was 106%.

Turning now to our guidance for 2026. As Ryan said, we continue to expect a significant reduction in both our capital spend and our operating costs combining to drive a year-on-year improvement of about $1 billion. 2026 capital spend guidance of about $12 billion is consistent with the preliminary outlook provided last quarter down about $600 million year-on-year due to significant capital efficiency gains in the Lower 48 and a decline in our major project spending. 2026 operating cost guidance of about $10.2 billion is also consistent with the preliminary outlook, down about $400 million compared to 2025.

The improvement in 2026 is driven by a combination of our cost reduction program and a full year of [indiscernible] and oil synergies. 2026 production guidance is 2,230,000 to 2,260,000 barrels of oil equivalent per day providing modest growth for the year. First quarter production is expected to be in the range of 2,300,000 to 2,340 000 barrels of oil equivalent per day, including the estimated impacts of weather-related downtime from Winter Storm fern.

In the Lower 48, once again, we expect to deliver more production for less capital as we continue to benefit from the highest quality asset base in the sector. We are a clear leader in inventory debt with over 2 decades of low-cost supply inventory across the Permian, Eagle Ford and Bakken. We're also the clear leader when it comes to bottom line results, capital efficiency, the amount of oil we recover for every dollar of capital we invest. We have the best rock in the best part of the best plays, and our team continues to execute really well. In 2025, we improved our drilling and completion efficiencies by more than 15%. We expect our capital efficiency improvements to continue in 2026, again driven by strong well productivity ongoing D&C excellence and further increases in our longer lateral developments.

Now turning to Alaska and International. A few important themes stand out for 2026. First, we continue to progress our advantage major projects, consistent with the comprehensive update we provided last quarter. Our LNG projects are more than 80% complete with NFV expected to start up in the second half of this year, while Willow is nearing 50% complete and on track for first oil in early 2029.

Second, we remain focused on infrastructure-led exploration and are shifting our focus this year to Alaska, where we have 4 wells fully permitted and are looking to unlock additional resources near to our infrastructure hubs building on our decade disciplined exploration and appraisal spend in Alaska. And third, we'll continue to leverage our diverse low-cost supply legacy assets for ongoing capital efficient development. including at Surmont, where we delivered our most recent pad ahead of schedule and on budget, with another pad expected online early next year.

To wrap up, 2025 was a very strong year for ConocoPhillips and we're looking to build on this success in 2026, starting with a $1 billion improvement in our CapEx and costs as the multiyear free cash flow growth profile we've discussed is now well underway. And we'll continue to find ways to enhance our differentiated investment thesis, unmatched portfolio quality, including leading lower footing inventory depth, attractive long-cycle investments, strong returns on and of capital and a sector-leading free cash flow growth profile through the end of the decade.

That concludes our prepared remarks. I'll now turn it over to the operator to start the Q&A.

[Operator Instructions] Our first question comes from Neil Mehta from Goldman Sachs.

Ryan, you talked about depth of inventory, strong reserve replacement and you've got some great projects coming on here in the next couple of years. Just your perspective, as the industry is now set to accelerate consolidation potentially of whether Conoco is really more of an organic story on the go-forward given those characteristics? Or do you see a role that Conoco is playing in consolidation?

Yes. Thanks. Yes, I appreciate the question. Look, we've done our heavy lifting on the M&A side over the last 4 to 5 years. And I think I've never seen the portfolio in a better shape and really no strategic gaps that we can identify. We're globally diverse. We like our combination of a leading resource position in the Lower 48 combined with what we've got going on around the world and the LNG projects that we're leaning into the Willow development and then what Andy talked about in some of our other projects going on around the world.

So our pivot has been to the organic side of the portfolio. I can see the rationale for some of the M&A activity and in terms of capturing the synergy, but we've been there, done that. We've got that behind us, and our focus is on the organic opportunity set that we have inside the portfolio, which we think is significant. As I said in my opening remarks, I think where we've gotten ourselves to is pretty resource rich and what we believe is becoming a more constrained world on the resource side. But we like where we're at. We like the portfolio, and we're pretty focused on the organic side of the business.

Our next question comes from Lloyd Byrne from Jefferies.

Can you -- you've been pretty clear in the past, Ryan, about what it would take to go back into Venezuela. And I was just wondering if there's any update there? And if I may, do the recent events impact the Citgo sale at all?

The Venezuelan question right off the top, Lloyd. Yes, look, I get it, seeing the news and look, our -- we're pretty focused on what we've talked about in the past, and that's the focus on the pathway to get some recovery on what's [indiscernible] in Venezuela. And that's our first priority right now is making sure they avail us a significant amount of money we've been after that. So we know where all the assets are and that's the basis of our focus as well.

We're trying to be helpful with the current administration and provide them with our sense of what's happening on the ground. A lot has to happen. Obviously, security needs to improve fiscals. We need a constructive relationship with local governments and the local people that actually want U.S. companies there. And then you need durability on the policy side. You need durability both in Venezuela and clearly here on the U.S. side. But we're helping the administration kind of think through the short, medium and long term, but our focus remains on trying to get the recovery that has [indiscernible] from the 2 judgments that we have in place.

With respect to Citgo, we see no change at this point, encouraged by the administration's comments regarding wanting to get the asset in American hands or U.S. hands, that's constructive. And obviously, if there's still an appeal process to work through in that judgment from the courts. And then [indiscernible] license is required ultimately to satisfy that, but we would stand to collect some of our judgment through that process, but we see no change -- no reason to believe that it isn't going forward as it's been described to us.

Our next question comes from Steve Richardson from Evercore ISI.

Maybe we can step back a little bit from the Venezuela question, Ryan. I was wondering if you extended the concession in Libya this quarter. And this seems to be part of a broader trend where there's a lot of opportunities arising internationally for your company and others. And so I was wondering if you could just talk more broadly about how you evaluate those options versus your current portfolio? And is it just a question of kind of risk-adjusted cost of supply? Or -- there's obviously other opportunity costs there, but I was wondering if you can just talk about that more broadly in how you're evaluating those opportunities.

Yes. Thanks, Steve. So I'd draw a little bit of a distinction. I mean, we've been we've been trying to improve fiscals in Libya for nearly a decade. So we finally got to that point with here a couple of weeks ago was signing the agreement with the Libyan government and our partner there. But it's something -- it's an asset inside the portfolio that we're trying to improve every day. And so this just is another organic opportunity inside the portfolio, specifically to Libya.

And the improvement in the fiscals are just going to make it more competitive as we think about it. But we've been investing money in Libya, and this just makes those investments even more profitable and more competitive in the portfolio as we go forward. as a result of what we've done.

I think more broadly, what you're getting at, yes, there are some opportunities. And as the world becomes a little bit more resource constrained, there's opportunities in around. We look at those as well. We had a new one coming to the portfolio through the Marathon acquisition of Equator Guinea. And so that's one we're focused on as well, trying to figure out how we can grow that LNG plant on the island and make it a long-term asset for the company, but that kind of fits into that organic side of the business, just trying to make that asset better over the long term for the company, doing similar things in Malaysia.

But there are new country entries that are happening, and we see that with new wildcat exploration maybe around the world from other competitors in new countries. We look at those and look for opportunities that might benefit the company and be additive to our plans and be consistent within our financial framework. And so it's exactly what you did. It's a risk-adjusted cost of supply of that opportunity and would it compete for capital inside the company? And could we slotted in with what we're doing inside the company over the long term, the next 10 and 20 years.

So the uniqueness about our company is we have that muscle inside the company. We're already pretty diverse company. We've got a BD organization that looks around the world, not just in the Lower 48 in the unconventional space, but also conventionally around the world, but it's got to compete inside the portfolio, just like everything does in the organic side of the business. So I think we're really well positioned to look at that and see what can be additive to the company.

Our next question comes from Betty Jiang from Barclays.

I want to ask about the Alaska exploration program. So we just started this year, the first of a multiyear program. Can you speak to the objective of that exploration program? What's the risk how big is the scale of the resource being targeted? And if successful, are we talking about extending the plateau for Willow? Or is it more upside to the ultimate production capacity of that project?

Great question, Betty. Yes, certainly pleased to report that we're out in front of this winter season here. We got an early start just based on weather under ice road activity. And of course, we have all of the permits required for both the wells as well as the seismic that we have planned up there here this year. And even to that end, we were able to spud the first of those 4 wells just within the last couple of days. So strong progress that we're seeing on those 4.

But again, to your question around intent and objectives here, we're out there exploring to the west of Willow and actually to the south a bit. And so as you've certainly heard from us before, our objective is to continue to find what we might describe even though it's onshore is tieback opportunities into both Willow and actually into our WNS Alpine asset as well. So to your point, this is an opportunity for us to identify continued volumes, continued resource plays to bring into this existing infrastructure and Willow being the next hub, if you will.

And when we look back on our performance history there in Alaska, we have and continue to project or expect we'll produce well over double the volumes through those existing facilities through that existing infrastructure over double what we originally promised when we took FID on those. And so naturally, then that's our same objective here for Willow specifically as we explore to the west, we'll be looking for those resource opportunities to just keep that infrastructure full.

Obviously, a bit early to start making a call on total resource size, et cetera. But naturally, we have some pretty high aspirations and some targets that we're pursuing, and we'll be going after this for several years here now. We've got 4 wells here in premise this year. but we've got a multiyear plan that we intend to carry out again, so that we can maximize as we do globally the infrastructure that we have and our ability to bring new volumes into that creates this advantaged cost of supply for us using the existing kit.

Our next question comes from Arun Jayaram from JPMorgan.

Gentlemen, trends in well productivity, increasing recovery rates have become a pretty hot button topics in U.S. shale. I wanted to talk a little bit about ConocoPhillips' Lower 48 business, looking at the data, the inverse data in '25, you guys had a really good year in terms of productivity in the Bakken, Eagle Ford and the Permian. And I know it starts with good rock, but I was wondering if you could talk about some of the levers you may be pulling from a technology standpoint that may be contributing to the attractive trends in well productivity that we're observing today.

All right, Arun. Yes, we certainly did have a strong productivity year in 2025 across that entire portfolio, as you mentioned. It was definitely consistent with our type curve expectations and consistent with the high quality of inventory, as you mentioned, One of the things we continue to do is we benchmark ourselves in each of our basins. And I'm pleased to say, on an oil productivity per foot, we're amongst the best in every basin we operate.

Now specifically, I want to call it a couple of areas that you mentioned in the Delaware Basin and Eagle Ford, we saw impressive year-on-year improvements. In the Delaware, our oil productivity per foot in 2025 is up about 8% year-on-year, and that's even with a notable increase in our average lateral length of 9% year-on-year.

Now a couple of components to dive in on the Delaware side. Again, we know the depth and quality of our acreage position out in the Delaware, but the teams are continuously optimizing our development strategies and adjusting spacing and stacking. And then, of course, depending on where you're drilling in North Delaware, Southern Delaware, you have a little bit of mix driving that, just due to the vast deep broad portfolio. Now pivoting to the Eagle Ford, our 2025 oil productivity per foot was up another 7% and that's off a very strong program in 2024.

And again, we're a clear leader in the Eagle Ford, and we have the lion's share of remaining Tier 1 inventory and have had strong well results of any operator. Now in the Eagle Ford, we brought in the Marathon assets. We've integrated that together. Teams continue to optimize completion designs using diverters to improve recovery, and we're seeing those in the results that you had mentioned.

If you look ahead to 2026, we expect consistent strong performance across all of our basins like we've demonstrated over the past several years. And this is a key driver in our ability to deliver low single-digit growth in the Lower 48 alongside a reduction of more than 5% in capital compared to 2025.

Our next question comes from Doug Leggatt from Wolfe Research.

Good morning. I think it's good afternoon, everybody, I should say apologize. I'm in Europe, so I don't know what the heck time is. Guys, I wanted to go back to Ryan's comment about the breakeven trajectory getting to the low 30s by 2030. I'm trying to understand a little bit about what the moving parts are. Where is it today? And what is the assumption in where CapEx is from the $12 billion this year in 2030 that gets you to that number, please?

Good morning Doug or afternoon, Doug or evening Doug, depending on where you are in Europe. Yes, I can step through that one. So where we are right now, sort of our pre-dividend free cash flow breakeven right now is in the mid-40s. And you'd add about $10 for that with the dividend. So that's kind of your starting point. And then as you say, as a reminder, we have our preproductive capital spend. it's down from where it was in 2025. We still have the preproductive CapEx between now and Willow coming online, and that works off that -- if you do the math on what we said on that, that's about $6 basically just on that simple preproductive capital.

And then as we've talked about sort of in our prepared remarks, you kind of got the free cash flow. It's already starting to improve today, and it's going to continue to improve and we're effectively going to almost double our preproductive CapEx -- cash flow, sorry, by the time that Willow comes online. And when you put all of that together, that's basically how we take our free cash flow all the way down into the low 30s by the time that Willow is coming online and then you add the dividend back on top of that.

So we're going to be down right in the low 30s when we have low and then adding another $8 to $10 for the dividend as we remember, we're buying back shares as well. So that sort of reduces the dividend burden over time as well. So that's kind of the trajectory we're on, and we're pretty excited about it. And I think we think it's part of the story we have here in terms of that free cash flow trajectory we're on, we think is second to none, and it's going to drive sort of a breakeven that comes down, I think, faster than anybody else can come close to matching.

Our next question comes from Devin McDermott from Morgan Stanley.

Ryan, I wanted to come back to 1 of the international growth assets that you listed in response to a prior question, and that's Equatorial Guinea. I know you've been evaluating potential backfill projects for the LNG facility there. And I believe just over the last few days, there was an agreement reached between Equatorial Guinea and Cameron for the unitization of the Yoyo-Yolanda fields. I know it wasn't Conoco-operated asset, but it's 1 of the potential tie back resources into that LNG plant. So kind of a broader question since you listed as a growth potential area. Just talk about how you're seeing the opportunity set there and where we stand on projects to backfill and keep that LNG plant full?

Yes, I can provide some over comments and maybe have Kirk come in by. I think we were encouraged by the Cameroon conversations and then here recently, Chevron's conversations saying. So we're working hard to try to make the asset that we acquired from Marathon something more than a 5-year asset, how do we make a 10-, 15-, 20-year asset. So we've been busy with some HOAs with the Equatorial Guinean country and doing exactly that.

We're encouraged by the opportunities that we see out there. We're encouraged with the cross-border cooperation because that just leads to more opportunity to bring more volumes across the island.

Maybe Kirk can describe some of the more specifics that we're looking at today.

Yes. Certainly, Ryan. And Devon, as Ryan has been describing, we've been in discussions, certainly haven't taken on this asset through the Marathon acquisition. And as we've taken it into the company, we've been actively in contact with a number of other operators in and around our LNG facility and upstream assets, thinking about how do we leverage that infrastructure, specifically the liquefaction facility that's using our technology there on the island.

Certainly, discussions have progressed very well, really pleased with that, specifically with Chevron. They've made some notable progress in a few of their projects. A couple of both new fields as well as continued development of some existing fields that create some upside for that. And then naturally, we are, as Ryan said, we're in some confidential discussions with the government and a few others around continued infill opportunities, especially gas in and around Malabo and our operation there.

So Again, this is a continuation here of the theme of what we've been able to do so well, whether it's internationally in Alaska, which is continue to find resources that exist to create this advantaged cost of supply to use existing infrastructure. So expect us to continue to make some progress in that way there in EG.

Our next question comes from Ryan Todd from Piper Sandler.

Maybe can you talk about how you think about Lower 48 activity levels and commodity price. As you highlighted in your presentation, you clearly have a tremendous amount of high-quality drilling inventory. You've moderated your pace of growth in the Lower 48 of late, given kind of current global crude supply balances and a weaker crude price.

But as you look over the next 1 to 2 years, what would you need to see to step up activity levels and grow a little faster in the Lower 48. And maybe with that, could you maybe elaborate on what you've said a couple of times is the pretty constructive maybe crude oil view in the medium to longer term?

Yes. Thanks, Ryan. Yes, we have our own sort of macro view on supply and demand and I'd say, consistent with a lot of what people were saying, we see some -- saw some softness coming into the year. So we set our plans and our budgets in '26 based on that. Obviously, we've seen a little bit of tailwinds with the current geopolitical things that are going on around the world.

But generally, I thought 2026 would be a little bit more tougher year on the commodity price. We set our plans accordingly. And Nick's team, as he's described, has been doing a great job capturing the efficiencies, and we've been able to grow that business without adding more capital to it. And that's kind of our starting place. So I would say our scope is kind of set for 2026 with what we're trying to execute. We don't like to whipsaw these programs up or down, and we'll use the balance sheet in the downside case if we need to. And we're comfortable with where we're at in '26. If prices were even to increase, would just give us more flexibility to -- in the company.

We are constructive going forward over the next number of years. as we think about later down the road in this decade, we think we're going to have LNG and Willow coming on at the right time when the world needs this oil. So we're pretty constructive as we go forward. And over time, we'll see what our view of the macro is. We'll see what we think about the cost. And if we want to start ramping up in the Lower 48, we can do that. If there's a call on more unconventional crude. But today, I think we're pretty comfortable with our plans. There's a lot of volatility in the market, but we're built for this. We're built to handle it with the balance sheet that we have and the programs that I know the teams are executing there. trying to get as much as they can for every purchase capital dollar for spending.

So we're trying to balance our returns of our capital back to our shareholders with the returns we're getting on the capital that we're putting back into the company. So this year, we should see some modest production growth and executing the plans to start delivering the free cash flow inflection that we see over the course of this decade, starting this year with $1 billion and next couple of years with $1 billion and then another $4 billion coming with Willow. And we think that's hugely differential in relative to our competitors in this space.

Our next question comes from Nitin Kumar from Mizuho.

Ryan, I'm sorry, I'm going to take you back a little bit to the direction of Venezuela, but it's not really about Venezuela. The expectation is the Venezuelan heavy crude might back up so the Canadian production. What's your view of WCS spreads given that you're seeing some of the other heavier crude from other parts of the world hitting the Gulf Coast?

This is Andy. I can jump in and take that one. I think the short answer is sort of in the short and medium term, we're not really expecting to see that much of an impact. As most people know, that if you start with sort of the PADD II refiners that structure you align on the Canadian heavy and have minimum alternative options to displace those barrels. And as you say, the Gulf Coast refiners can process the heavy valves and we're starting to see some of those refiners expressed interest in purchasing some of those Venezuelan barrels.

But our view is the incremental Venezuelan barrels will likely get absorbed. The market will rebalance the global flows and we kind of -- will you see a thing from month to month where there's maybe crude being backed out or being moved in different directions, possibly. But take a step back and look at the bigger picture. The way we are thinking about it is that the annual global demand is growing basically 1 million barrels a day. And we're going to need incremental sources of supply to help meet that demand growth. So our modeling isn't really sort of showing that the Venezuelan crude coming in is going to have a particularly material impact on Canadian heavy.

Our next question comes from Scott Hanold with RBC Capital Markets.

My question is on your balance sheet. Obviously, you've got a very strong cash position and investments I think there is some investor kind of concern over there, at least in the short term where your shareholder return strategy, at least in that 45% rate does dip into it. Could you just give us your context on how you think about your cash balance, how much is reserved for utilizing at this as you ramp to that free cash flow inflection point?

Yes, I can take that one, Scott. I think in the prepared remarks, I stepped through sort of just how strong our cash balances are starting this year and the fact that we actually reduced our net debt by $2 billion. So we're starting with our balance sheet that is in a really, really, really solid position. I think we look at it across a range of crisis. And I think we've been pretty clear that 45% of our CFO basically works across basically a range of prices in terms of our distributions and that's kind of what you could expect.

And there's a reason we have a strong balance sheet is if there were a period where sort of a quarter here and a quarter there you're needing to crop into the balance sheet to sort of help fund that. That's what we would do. That's what it's there for. So I think given where we're starting with cash, I don't really see sort of any real concerns basically around sort of headwinds to being able to fund distributions or maintaining a strong balance sheet.

Our next question comes from Sam Margolin from Wells Fargo.

This question is about the progression of the free cash flow contribution in '27 and '28 before Willow and in the context of NFE coming on in the visible horizon here. Could we ask you to decompose that progression a little bit and maybe at least frame where the range of LNG contribution, both on the cash flow side and on the spending roll off are coming in? And then I guess the market context is that European gas inventories are pretty low and you have some European regas exposure that looks like it will be full over the next season. So if we could get some color on that, it would be great.

Okay. Kind of touching a few different topics there. I'll try and sort of -- try and cover them. The first part of it is we've been very clear that sort of basically, we're seeing $1 billion per year, '26, '27, '28 million of free cash flow improvement. And I think you're starting to allude to this, that '26 basically is essentially being driven by the our OpEx and CapEx guidance that we've given driving that. But as we get into '27 and '28, a significant part of that is being driven by the LNG where we have NFE coming on, Port Arthur coming on and NFS coming on.

So we're seeing that basically drive the next $2 billion after the one we have now, then the next 2 comes from those LNG projects. And remember, it's a combination of the revenues coming on, but the CapEx is going away as well. So that's $2 billion. A big chunk of that is coming in '27 and '28 from the LNG projects. We've when we've given those sensitivity on the $7 billion of free cash flow inflection, we've put prices out there basically for that. And I think where we basically placed the first 5 million tonnes that we have out of Port Arthur Phase 1 into Europe and Asia. So we feel pretty good about that.

And our view, I think, is that we're feeling pretty confident basically around sort of LNG prices basically holding up over the rest of this decade. So it's kind of -- that's what's built into our sensitivities. And we're also in a situation where between now and 2030, where we're actually much longer Henry Hub natural gas than we are LNG. So if you think about it in Nick's area, in the Lower 48, we produce of gas, that's about 15 Mtpa.

And for every dollar we see move on the price on Henry Hub, that's over $400 million of sensitivity to us, whereas the first 5 million tonnes that we have coming out of Port Arthur between now and the 2030 time frame, every dollar movement on that is about a $200 million movement that we have. So we're actually much more exposed to higher gas prices than we are compressing LNG margins in the -- between now and the end of the decade. So I think I touched on most of what you're asking there.

Our next question comes from Philip Jungwirth from BMO Capital Markets.

You reached an agreement with Western Gas during the quarter to restructure Delaware gas contracts. The question is more around -- you have over 200,000 net acres in the core that you picked up from Shell couple of years ago. Maybe it's a little less optimal in terms of operatorship, working interest or acreage configuration. But with the midstream getting more ironed out, does this at all advance the ability to do a larger acreage swap here? And if so, how meaningful could that be for Conoco's capital efficiency and developing this asset going forward?

Yes. Exactly. If I go back to Shell, I mean one of the key things as you look out in that area, as we continue to core up in strategic trades all the time, to increase our lateral lengths in that area. That drives our capital efficiency as we extend the laterals in there, and we continue to do that on an ongoing basis. As you mentioned, for the Western Midstream we did directly contract that through West, and that's one of the key drivers that Andy had mentioned that achieves that $1 billion of cost savings run rate by year-end 2026.

But on the strategic trades, we continue to do that on an ongoing basis. And if you look at long lateral inventory in that area you mentioned, if I step back to 2023, about 60% of our Permian future well inventory was 2 miles or greater. But today, that's at 80% due to the strategic trades in core ups. And in fact, you look at the 2026 program, 90% of those wells are 2 miles or greater. So we continue to do that with our BD and land teams coring it up, and that drives the capital efficiency. When you look at that core up opportunities. If we go from a 1 mile to a 2-mile lateral. We improved the cost supply about 25%. But if we go to 3 or 4 miles, we add another 10% to 15% cost supply reduction.

Our next question comes from James West from Melius Research.

One thing that came up that I noticed in the slide deck this morning that stood out to me was your reserve replacement ratio. It's been very impressive over the last 3 years, well above your peer group and the big oils Curious what's been driving that. I'm curious how you see that going forward.

This is Andy. I'll take the question. Actually, thank you for the question. So asking about reserves. We think reserves remains an important and very relevant metric, especially the organic reserve replacement. As you know, that's basically essentially what we're replacing with the drill bit.

As you said, 1 year performance is important. We do also focus on our multiyear track record, especially when you think about some of the longer cycle projects. So just to quickly step through the numbers, our 3-year organic reserve replacement is 106% and our 5-year organic reserve replacement is 133%. And what's particularly pleasing about that is across that time frame, we've got strong contributions across our entire global portfolio, Lower 48, Alaska International is another example as Ryan was pointing to earlier the power of our diversified portfolio.

And '25 was no different. It was another solid year of organic reserve replacement. So we effectively maintained the reserves technically 99%. And that -- if you then take that basically we exclude the impacts of revisions date to the lower oil prices, the organic reserve ratio, when you're not taking price provisions into account, we've been 110%. So again, it was a really good year for us. And I think where you alluded to, we think our track record, we'll put it up against anybody in terms of the majors or the E&Ps over the short, the medium and the long time frame.

And just in terms of how we think about it, we really do think reserves continue to be an important barometer for our industry. And no matter how you slice it, it continues to be another proof point, just on the quality of our portfolio. And it was a really good year for us again, where we had additions yes from the Lower 48. We had additions coming from Coyote up in Alaska, great performance out of our Australian business unit where we increase some reserves there. And then just some of the commercial negotiations we do across Asia and that is to add some reserves there as well. So Important for us reserves to keep a really close eye on it. And I think it's a good litmus test of sort of how well basically we're doing and we couldn't be happy with it.

And I would add just one thing, James, as well. I mean people ask us, when we talk about our sub-$40 resource -- sub-$40 cost resource that we have inside the company. And is it real or how real is it? I think this is the proof point is we're converting those resources into reserves you ought to feel comfortable, and we've been doing this over the long haul, both in our history and we given Andy's comments, that's what we expect to happen going forward because of that the resource that we've got captured inside the company and our focus on the organic investments in the company to turn that resource into reserves.

Our next question comes from Paul Cheng from Scotiabank.

Ryan, just curious, you still have another $1 million the Lower 48. But I think no matter how we look at it, Shale oil is getting mature. And as that happened, how over the next 5 years, your capital allocation is going to shift or that is going to make any changes to position the company post 2030.

I mean we clearly that you have a very, I think, visible path for the next 5 years. But post 2030 that with that major asset is going to be maturing. How are you going to position given your very large companies, so to turn a big ship going to take time?

Yes. Thanks, Paul. Look, we -- our view inside the Lower 48, just in particular, is over 2 decades of low-cost supply inventory. So we're going to be in this business for 20-plus years. It's not going to roll over in 5 years in our portfolio. But I take your point, I think broadly in the industry, we're at these kinds of prices seeing sort of flattish production in the shale, North American or U.S. shale, but that is not the case inside our company. So we will see sort of major project capital spend, the preproductive capital that Andy talked about, that will start to roll off through the end of this decade.

We continue to -- we'll see growth in our unconventional investments as we continue to capture efficiencies and look at that business, but we've got multiple decades of growth opportunity there. And then Kirk talked about the rest of the business. We see opportunities in Alaska. We see them in Canada. We see them -- we talked about at [indiscernible], the signing of the new agreement in Libya. So I think we're just in a completely different place than a lot of our competitors, and we've got a lot of optionality for investment in the portfolio to continue sort of modest growth depending on what the commodity price environment ends up being.

And again, we're pretty constructive long term as we see demand growth continuing to grow. So that's going to give us the opportunity to continue to invest organically in the portfolio across a broad set of assets that have already captured to develop that resource potential that we have. And it doesn't stop by the next decade in the Lower 48, it continues for quite a period of time. And I think all the data -- third-party data supports that. We're just not talking our book here.

Our next question comes from Charles Meade from Johnson Rice.

If I could, I'd like to go back to Alaska. And can you give us an update on how this season's costs at Willow are tracking versus the updated assumptions you guys gave us last quarter and perhaps fitting in that or maybe tacking on to that, if -- how the loss of this rig 26, whether it's going to affect you either on your development or exploration side?

Charles, thanks for the question. We certainly had a number of inbounds especially on the latter part of your question around the rig incident. So I might start there, and then, of course, I'll address your question on Willow. Certainly, a very unfortunate event there with that rig D26. Of course, naturally top of mind for us, we're the folks that -- the individuals that were around the rig and the few that we're piloting that rig. Fortunately, no injuries. And of course, the owner, the operator of that rig are ultimately accountable and they are leaving both the investigation and the response. We're naturally in support of that company. And working with them as they coordinate and manage in and around that.

That rig was 1 of 2 rigs that we had planned for the exploration program. here this year. We roughly assigned 2 wells for each one of those rigs. And of course, we have multiple rigs up there running. And so we were able to just simply backfill that D26 rig with one of the active rigs that we have operating within our existing units. And so the exploration program continues, and we'll be able to pivot those rigs back after the exploration season into our ongoing development. So no change to either exploration.

And to your point around Willow, we have 2 rigs premised for the predrill on Willow leading up to start up in early 2029. And D26 was one of those rigs. Now again, because we have multiple rigs deploying, no impact. And again, pre-drill starts for Willow next year in 2027. So ultimately, what you're hearing from me is after that unfortunate event, no impact on our exploration and no impact on Willow.

On Willow, you heard certainly earlier in my comments that we were able to get out early due to an early start to the winter season and some cold weather with ice, the same goes for Willow. And so that winter construction season for us started early. It's on track and proceeding really quite well. When we think about the work scope that we have planned here for this year, it really revolves around some of the earlier points you've heard from me. We're trying to knock out the bulk of the grab work here this year, roads, pads, the airstrip so that we have full year-round access into Willow in a more efficient way than we have in the past. We'll be continuing pipeline work, bridges, et cetera.

And then, of course, all the work here out of the state on prefab of the process modules continues, and we're seeing some strong progress from our business partners on that front as well. And then back to your point, yes, we're seeing costs come in as we guided. We're seeing that cascade down largely because last year's winter construction season was our largest. And then we've been able to knock out some pretty important milestones up there on the North Slope. Our permanent camp there in Willow is open. And that's because it allows us to start moving away from a turning away a lot of these temporary camps that we've had to rely on. And so this is part of the story about our ability to wind capital down from previous levels in the last few years.

So we'll be coming in on pretty major milestone here within the next couple of months of being 50% complete on the project. And so naturally, both cost and schedule are looking good for us for an early 2029 first oil.

Our last question will come from Kevin MacCurdy from Pickary Energy Partners.

I wanted to ask about Canada. You highlighted that the 104 WA Surmont pad was ahead of schedule. I wonder if you can talk about the financial and operational impacts and the timing of that pad was CapEx and production brought forward? And do you think this could be like an ongoing trend for your operations there?

Yes. Appreciate the question on Canada. It's a place the Surmont asset specifically is one where we just continue to see really strong performance. And ultimately, we have positioned ourselves for first oil -- first team late last year and then first oil early this year. That came in about a month early. And that was on PAD 104 WA. And so ultimately, that activity is cascading through. It's, in essence, rolling through as we have started work on the next PAD 104 WB. And as you've heard from me in the past, we're expecting to bring on a new PAD roughly every 12 to 18 months, and we are expecting this next PAD to come on in about 12 months from now for a first team and first oil.

And so that activity is really quite level loaded. Certainly, as you can imagine, with that kind of pace. And so we're not seeing necessarily a material change in certainly how we think about capital or even or even our production profile, other than it derisks certainly the growth that we've started to see.

And when we think about -- I talk about growth in Surmont, it's really quite moderate and disciplined with this pace of capital deployment. So again, we took a bit of a cut last year with having reached payout on the full Surmont project last year. Net royalty has changed on us. And yet when I back up a little bit and I think about the health of the asset and how it's performing, gross volumes continue to be climbing and to be up. So we're -- the performance of these pads is offsetting decline. And again, just really pleased with how the overall asset is performing and how our capital and production is coming in on trend.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

Welcome to the Third Quarter 2025 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. [Operator Instructions]

I will now turn the call over to Guy Baber, Vice President, Investor Relations. Sir, you may begin.

Thank you, Liz, and welcome, everyone, to our third quarter 2025 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; Andy O'Brien, Chief Financial Officer and Executive Vice President of Strategy and Commercial; Nick Olds, Executive Vice President of Lower 48 and Global HSE; and Kirk Johnson, Executive Vice President of Global Operations and Technical Functions.

Ryan and Andy will kick off the call with opening remarks today, after which the team will be available for your questions. For Q&A, we will be taking one question per caller.

A few quick reminders. First, along with today's release, we published supplemental financial materials and a slide presentation, which you can find on the Investor Relations website.

Second, during this call, we will make forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings.

We'll make reference to some non-GAAP financial measures today, Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website.

With that, I'll turn the call over to Ryan.

Thanks, Guy, and thank you to everyone for joining our third quarter 2025 earnings conference call. We have a lot to cover today, including our third quarter results, improved 2025 outlook, strategic updates and our preliminary 2026 guidance.

Now starting with our third quarter results. This was another very strong execution quarter. We again exceeded the top end of our production guidance, demonstrating the power of our diversified portfolio with both capital spending and operating costs declining quarter-on-quarter. On the back of this strong performance, we raised our full year production guidance, and we have reduced our adjusted operating cost guidance for the second time this year. In fact, we have improved all our major guidance drivers since the beginning of 2025. CapEx, operating cost and production, further demonstrating the strength of our team's execution.

On return of capital, we raised our base dividend by 8%, consistent with our goal to deliver top quartile dividend growth relative to the S&P 500. This type of dividend growth is sustainable given the strength of our outlook and expectation for our free cash flow breakeven to decline into the low 30s WTI by the end of the decade. Year-to-date, we've returned about 45% of our CFO to shareholders, in line with our full year guidance and our longer-term track record.

Turning to our strategic updates. At the Willow project in Alaska, after completing our largest winter construction season and conducting a comprehensive project review, we've increased our project capital estimate to $8.5 billion to $9 billion. This change is primarily attributable to higher-than-expected general inflation and localized North Slope cost escalation. Despite cost pressures, we have maintained the project schedule and made excellent progress on scope execution, nearing first oil to early 2029.

We also continue to advance our global LNG projects, another key driver of our expected free cash flow inflection. We have reduced total LNG project capital by $600 million. Our three equity projects, NFE and NFS in Qatar and Phase 1 at Port Arthur LNG are on track and have been substantially derisked. Capital spending is now about 80% complete with our first startup expected next year at NFE.

Looking ahead to 2026, recognizing it's early, the macro remains volatile, and that our portfolio is highly flexible. Our preliminary guidance for both CapEx and OpEx is to be improved significantly, down about $1 billion on a combined basis from this year. And in fact, relative to our pro forma 2024, they are down about $3 billion. Underlying production should be flat to up next year, a reasonable starting point given the current macro environment.

Looking beyond just the near term, ConocoPhillips continues to offer a compelling value proposition to the market, one that is differentiated relative to our sector and to the broader S&P 500. We believe we have the highest quality asset base in our peer space. Our global portfolio is deep, durable and diverse with the most advantaged U.S. inventory position in the sector. We are uniquely investing in our portfolio and driving significant efficiencies throughout the organization to deliver improving returns on and off capital and a leading multiyear free cash flow growth profile.

Consistent with our guidance last quarter, we continue to expect the four major projects we are progressing along with our recently announced cost reduction and margin enhancement efforts to drive a $7 billion free cash flow inflection by 2029, potentially doubling the consensus expectation for free cash flow this year. That free cash flow inflection is now underway. We expect to realize about $1 billion annually through 2026 through 2028 before an additional $4 billion in 2029 once Willow comes online. That's a growth trajectory that's unmatched in our sector.

So bottom line, we're performing well. We are delivering on our plan, and we're well positioned for 2026 and beyond.

Now with that, let me turn the call over to Andy to cover our third quarter performance, major project updates and 2026 guidance in more detail.

Thanks, Ryan. Starting with our third quarter performance. As Ryan mentioned, we had another quarter of strong execution across the portfolio. We produced 2,399,000 barrels of oil equivalent per day, once again exceeding the high end of our production guidance. Regarding third quarter financials, we generated $1.61 per share in adjusted earnings and $5.4 billion of CFO. Capital expenditures were $2.9 billion, down quarter-on-quarter as we passed the peak of our major project capital investment cycle.

We returned over $2.2 billion to our shareholders including $1.3 billion in buybacks and $1 billion in ordinary dividends. Through the third quarter, we've now returned $7 billion to our shareholders or about 45% of our CFO, consistent with our full year guidance and our long-term track record. We ended the quarter with cash and short-term investments of $6.6 billion plus $1.1 billion in long-term liquid investments.

Turning to our outlook for 2025. We've raised our full year production guidance to 2,375,000 barrels of oil equivalent per day, up 15,000 from our prior guidance midpoint. This is even after considering Anadarko's sale of approximately 40,000 barrels a day of oil equivalent, which closed on October 1.

We're reducing our operating cost guidance to $10.6 billion down from the prior guidance midpoint of $10.8 billion and our initial guidance at the beginning of the year of $11 million.

We're also making great progress on our asset sales program. with another $0.5 billion on top of what we announced last quarter. That takes us up to over $3 billion of asset sales out of our $5 billion target. Of this amount, $1.6 billion was closed and the cash was received through the third quarter, and we have another $1.5 billion that will have closed in the fourth quarter. That includes the remainder of the Anadarko disposition proceeds as well as additional noncore Lower 48 assets.

Turning now to our strategic updates. At Willow, we have updated our total project capital estimate to $8.5 billion to $9 billion. After successfully completing peak winter season, we undertook a detailed bottom-up reforecast of the project. And as a result of increased our cost estimate. The increase is primarily due to higher general labor and equipment inflation and increased inflation on North Slope construction.

Scope execution has remained strong. We're nearing 50% project completion. This has allowed us to narrow our estimate of initial production to early 2029. Importantly, we can now level load the pace of our future work. More specifically, 2025 Willow project capital is forecast to be just north of $2 billion. We plan to reduce capital to around $1.7 billion a year from 2026 through 2028. After achieving first oil, ongoing development capital will decline to about $0.5 billion a year for several years. We continue to expect Willow to deliver $4 billion of free cash flow inflection in 2029 consistent with our prior commentary.

Turning to our three LNG projects, NFE and NFS in Qatar and Port Arthur LNG Phase 1. We are reducing our total project capital estimate from $4 billion to $3.4 billion. This reduction is due to a $600 million credit from Port Arthur Phase 2. The credit is for shared infrastructure costs previously incurred by Phase 1 equity holders. As a reminder, we only have equity in Phase 1, not Phase 2. With this credit, we're approximately 80% complete with our total project capital for these three LNG projects, approximately $800 million of project capital remains averaging just north of $250 million of spend annually with a declining trend from 2026 to 2028. All projects remain on track, we continue to expect first LNG from NFE in '26, Port Arthur after in '27 and NFS after that.

We're also making considerable progress in advancing our commercial LNG strategy which will further strengthen our long-term free cash flow generation capacity. As a reminder, our strategy is to connect low-cost supply North American natural gas to higher value international markets. We are leveraging our decades of LNG experience and our global scale to advance our strategy, which nicely complements our more than 2 Bcf a day or 15 MTPA equivalent of Henry Hub-linked U.S. natural gas production. We have fully placed the first 5 MTPA from Port Arthur Phase 1 with combined [indiscernible] and sales agreements into Europe and Asia.

In terms of offtake, we've recently agreed to take 4 MTPA from Port Arthur 2 and 1 MTPA from Rio Grande LNG, bringing our total offtake portfolio to about 10 MTPA, the lower end of our stated 10 to 15 MTPA ambition.

Now turning to our outlook for 2026. We are providing a high-level framework, assuming about a $60 a barrel WTI price environment. First, we continue to expect a significant reduction to our capital spend next year, about $0.5 billion lower than the midpoint of our 2025 guidance. So in round numbers, that's about $12 billion for 2026. The year-on-year decline is driven by a reduction in our major project spend, including Willow and the steady-state activity we achieved on the Lower 48 methane oil assets earlier this year.

In addition to lowering our capital spend in 2026, we also expect to lower our operating costs. This is largely due to the $1 billion of cost reduction and margin enhancement efforts we disclosed last quarter. We expect our cost in 2026 to be approximately $10.2 billion, down $400 million from our current year guidance and down $1 billion from our pro forma 2024 operating costs, including Marathon Oil.

Turning to our production. We expect to deliver flat to 2% underlying growth in 2026, a reasonable planning assumption considering the ongoing macro volatility. Additional guidance can be found in our earnings material including our oil mix and our equity of full year distributions.

Now addressing our multiyear outlook, there are a few important points I'd like to make. First, the free cash flow inflection guidance we previously provided remains unchanged. We expect our four in-progress major projects and our $1 billion cost reduction and margin enhancement efforts to deliver $7 billion of free cash flow inflection by 2029. In terms of the timing of that $7 billion, we expect to realize about $1 billion of improvement each year from 2026 through 2028, amounting to $3 billion of free cash flow improvement by 2028. The remaining $4 billion will come in 2029 once Willow starts up.

Bottom line, using 2025 as a baseline, this translates to a double-digit free cash flow growth CAGR through 2028 before another material step-up in 2029, which will approximately double our 2025 free cash flow.

So to wrap up, we continue to execute well, operationally, financially and across our strategic initiatives. We are well positioned for a strong finish to the year and a good start to 2026. We and we continue to find ways to enhance our differentiated long-term investment thesis. That concludes our prepared remarks. I'll now turn it over to the operator to start the Q&A.

[Operator Instructions] Our first question comes from Neil Mehta from Goldman Sachs.

I appreciate the time here, and I want to unpack Willow a bit because while there was a lot of good stuff in the -- in terms of execution in the quarter, the Willow update, obviously, was a little disappointing. So on your perspective on -- the bridging from the [ 7 to 7.5 to 8.5 to 9 ], do you feel, Ryan, that we've got a good handle around the project at this point because the history of major capital projects sometimes is there are multiple legs of announcements around overruns. And on the bright side, it seems like while there's cost overrun here, the timing is really intact. So just unpacking Slide 4 would be great.

Yes. Thank you, Neil. Appreciate the question. And certainly, I appreciate key project for the company. And I know giving some clarity on where we've been, where we're at today and what that future looks like is important to provide that insight and to clarity. So I've asked Kirk to unpack this a little bit using your words, Neil, and spend a little bit of time to make sure you all understand sort of where we're at today and where we're going in the future. So let me ask Kirk to do that and provide a lot more clarity to that.

Certainly, as you heard in our prepared remarks or this morning from Ryan and from Andy, we are increasing our guide on total project capital for the Willow project to a range of $8.5 billion to $9 billion. And I'll start by recognizing the strong execution that we've been achieving through our project team. Certainly, as you've heard from me before, we're hitting the key milestones that we premised in our project plan that, of course, we laid out at FID back in 2023.

And so in this past quarter, we chose to perform a pretty rigorous bottoms-up comprehensive project review, and we were looking at scope, schedule and, of course, total project costs. And we were doing that in recognition that we knew we were coming in on about 50% completion, expect to see that as we move into this next winter season. And it's common practice for us to take on a pretty rigorous again, bottoms up at this place and projects of this nature and of this size. And coming out of that exercise, we were able to provide two new guides on the project, not just capital but also on schedule.

So starting with the first, the new guide on capital. is a confirmation really largely of one driver. And that's what we've realized higher inflation post FID in 2023. So addressing that maybe a little bit more detail here. Total inflation is roughly 80% of the increase on our new capital guide. And I'll start with general inflation, which has been modestly higher across a few key categories that we've seen on the projects, general labor materials and then engineering equipment as well. And all of that makes up over half and in fact, about 60% of our total project spend. So seeing that higher inflation is really culminating largely in what you're seeing in this new capital guide. As you can imagine, just a few percent higher. We originally expected just a couple of percent of routine standard inflation across the period of the project, but just a couple of percent higher in inflation rates across the 5-year duration on our project is driving this 15% increase against what was our original expectations at FID expecting lower inflation.

And then a bit more unique to this project. We've also incurred some localized escalation, particularly in our Alaska North Slope specific markets. And that's really been driven by the fact that we've incurred more overlap of the peak construction seasons between our project and other projects ongoing in Alaska than we had originally expected. And that's resulting in roughly a 2x increase in the regional activity there in the state. That stressed the local markets, [ zinc ] labor, logistics, such as trucking marine and then even the availability of camps for our construction work there on the slope.

We're often asked about tariffs. We have seen some impacts on tariffs, but albeit it's really been low single-digit percentages as a total of the increase we're seeing on that project.

And then the last component on the upward cost pressure is related to a few decisions that we've made to ensure that we're mitigating total project risk and especially schedule risk, just to ensure that we're hitting the milestones that we need especially on the front end of this project. And you've heard from me that we're hitting those. And so those have really paid well for us. We pre-staged equipment on winter season to ensure that we can knock out all the scope that we had originally premised. And again, that's giving us the ability and the confidence to be able to guide you a bit more even on schedule.

So to summarize, we've moved from about 50% of our contracts being locked up at FID back a couple of years ago to now being well over 90% of our facility contracts being secured. And a bulk of those are tied to market indices that gives us transparency as the market moves and creates a lot of accountability with us and our business partners as we move through a project of this size. And so this summer, again, was the time for us to reconcile the actual inflation that we've been seeing over the last couple of years against the forward-looking expectation. And you're hearing from me, we're, in essence, taking forward the type of inflation that we've been realizing forward into the next couple of years just to ensure that we're being conservative through this process.

So looking ahead, again, back to execution. We've wrapped up detailed engineering that compels us to keep moving forward on the process module fabrication that's a longer duration activity. It moves from this year into early 2027 in which we'll see lift those modules to the slope, spend 2028, getting those into the Willow development area and hooking up and commissioning those first oil in 2029.

Again, I'll wrap this up with an acknowledgment that we're just seeing really strong execution across the project, and that's foundational. It's paramount for us in a project of this kind and we're on track with all of our major scopes of work. And again, all of this is culminating and not just to guide on capital, but then our ability to provide an accelerated guide on first oil to the early part of '29.

I would just wrap it up, Neil, by saying that we're certainly disappointed that the costs are higher, but certainly, we've taken measures across our portfolio to mitigate the increase. And I think you see that in our first -- that's why we thought it was important to give some guide to 2026. But the teams are executing well and the projects really hitting all the milestones as Kirk described. We think it's a -- continues to be a world-class project. It will be a huge driver of our free cash flow inflection that's coming over the next 3 to 4 years and towards -- and really complete towards the end of the decade.

And then -- the last thing I'd say is we're going out probably with a bigger exploration program we've had in Alaska in a number of years. And it's that opportunity again to take advantage of this infrastructure that we're building for the long-term growth and development of the company. And if we're right about our macro call and where we think the macro is going, we're going to need this conventional oil to satisfy some of that growing demand around the world that we see. So it fits all of our strategic buckets as well. So I know a long kind of explanation to the initial question out of the bat, we thought it was important to provide some of that clarity and context around it to give you comfort. We know where we've been, we know where we're at, and we know where we're going.

Our next question comes from Arun Jayaram with JPMorgan.

Ryan, I was wondering if you could just -- maybe a quick follow-up on Willow, the F&D on the project goes up by $200 to $250 per BOE based on your updated outlook. I was just wondering if you could comment on how this impacts your project returns and just overall breakevens assuming, call it, mid-$60 Brent type of price.

Well, yes, thanks, Arun. Certainly, the estimate increase does impact the cost supply of this individual project going forward. It still fits well within our portfolio. It's still very competitive within the portfolio. And again, we think longer term, we think about the future opportunities that are going to come from this infrastructure, which is our history sitting on the North Slope. We've always -- the satellite discoveries that we get benefit from the infrastructure that we built and we fully expect that to be the case going forward with Willow.

And then I'd remind you on the back end of this, the margins are still quite attractive because Alaska is 100% oil, sells at a premium to Brent typically on the West Coast of the United States. So that's why even with maybe a little slightly higher F&D as you pointed out, we still feel very comfortable with the margin and it's competitive in the portfolio, and it's going to deliver a project for the company that will add to its future growth and development.

Our next question comes from Betty Jiang from Barclays.

I want to maybe shift focus to the Lower 48. Just -- we talk a lot about the free cash flow from the major capital projects, but noticing that the Lower 48 CapEx is also trending lower in the second half of '25 versus first half? And if you're staying here, CapEx will be lower year-on-year in '26, while still perhaps growing in that asset. So can you speak to the CapEx trajectory there? And how do you see the free cash flow progressing from the Lower 48?

Yes. Because -- Betty, you're exactly right. Maybe I'll take you back a little bit on the capital projection and a little bit of the efficiencies that we're seeing within the Lower 48 portfolio.

If you recall back in 2Q, we achieved our level-loaded steady state program within the development strategy with integrating the Marathon assets. And so if you recall, we went from 34 rigs down to 24 rigs, so a pretty significant reduction. And we're still delivering kind of low single-digit growth in that. So obviously, we're taking in stock that lower capital from going first half to second half, and you're going to see that in the capital projections going forward.

Another key component of that, Betty, is a lot around the efficiency improvements that we've seen getting into that level [ though at city ] state program, which I can talk more about, but we're seeing a significant improvement on drilling performance as well as our completions, that will continue into 2026. So if you kind of look at where we're currently at, we're probably going to be on a run rate basis for 2026, something similar to 3Q for capital in 2026, and we will continue to have that level-loaded steady-state program, roughly at 24 rigs in [ a frac crews ] going forward.

As far as free cash flow, I'll probably let Andy talk about the total company, but we continue to see expansion with, again, all the efficiency improvements that we're seeing with the productivity that you saw in 3Q, a really good strong quarter.

Yes, Betty, it's Andy. I'll just jump in and sort of add on to what Nick was saying there. So we feel it's important sort of on the free cash flow inflection to talk specifically to the three LNG projects of Willow. But of course, there's a lot more than that going on in our company, and Nick just described what we've got with Lower 48. And the flexibility we have within the Lower 48, without inventory if we wanted to ramp up that cash flow growth. But even beyond that, there's other things that we don't factor into that free cash flow inflection.

Commercial, for example, we talked about the commercial sort of strategy, we've got put off of Phase 2. We've got Rio Grande that we just mentioned today that will come on after Willow. That's going to be sort of the 2030 time frame. So there's a lot more going on in a company than just those four projects. We've got other things going on sort of in Canada, in Alaska, around some other international assets, but we just wanted to keep line of sight on this specific free cash flow inflection and then we obviously have ability to add to that.

Our next question comes from Stephen Richardson from Evercore ISI.

Andy, it's a good segue from what you just mentioned about some of the other assets. I was wondering if you could -- it sounds like you've got some good visibility on some of the organic and capital-efficient opportunities in the portfolio. In Alaska, I was wondering if you could talk about some of the regulatory and permit changes and how you're thinking about incremental opportunities either in legacy ops or extending the resource at Willow. And then if I could, if you could maybe talk a little bit about Surmont. You've talked about incremental steam potential, but I understand that there's some other things that you could be doing now that you've got your arms around that asset and to improve it with minimal capital.

Yes. Thanks, Steve. I'll take that. I think that it's -- yes, Andy's answer to the last one. It's -- this update is a lot about Willow and some of the major projects to give the market some clarity as to what we have going on there and some clarity into our free cash flow growth. And it doesn't really address and assume some of the things we have that we're studying inside the portfolio as well, and you mentioned a few of those because I think we do have a strategic question longer term, if I recall on the macro, he's right. where is the conventional oil going to come from to satisfy the growing demand. And we see that demand growing clearly 1 million barrels a day or so per year for the foreseeable future.

And when we look inside the portfolio, it's not only what we're doing in Willow and what we believe are going to be the added sort of pads that we can develop there. And to your point, we're working with the administration to identify some ways to streamline the permitting. I think you saw an early read of that with the new rules that are coming out for development in NPRA, that's just sort of the start. There's more things coming that will give us -- what we think is going to be a lot more clarity to faster permitting approvals coming in Alaska going forward. So watch that space as we move on and hopefully not only make it more profitable and easier and faster but also more durable with changing administrations.

And then to your other point, yes, when we look -- that's just Alaska, and I commend the team also managing the base. There's a lot of activity going on the base side in Alaska as well. We have flexibility at the Montney asset to ramp up, should the call on crude be required to go do that. You mentioned Surmont. We're right now debottlenecking that plant as we speak. Now that we own 100% of that plant, we were able to make some investments in there that our previous partner were not approving. So we're taking the gross productive capacity of the plant up today. And then looking at future. Can we add a few scheme generation capacity to accelerate some of the development that we have with the huge resource that we have around Surmont. That's very competitive in a -- all at sub-$40 cost of supply.

So when we look at the whole portfolio and you look at the deep inventory, we have in the Lower 48, combined with the other conventional opportunities we have around the world, we're really set up for decades of growth in this business. I like where we're at, and I like the portfolio and what we're doing today and the optionality that it creates for the company over the short, medium and long term.

Our next question comes from Lloyd Byrne with Jefferies.

Ryan or Andy, I was just hoping you could spend a little bit more time on the OpEx. I mean, $400 million improvement and in light of it kind of being the second cut this year, it's just what's changing? Maybe remind us of the big factors that have improved and whether you can improve it further?

Yes. Thanks, Lloyd. I can take that one. I think at the highest level, the first thing I would say is that we're executing really well in -- with our cost and capturing the savings. And as you said, that's why we've been able to reduce the guidance for the second time this year. But going into a few specifics, I would remind people that we've already achieved now 75% of the mouth and synergies that we were talking about over the prior quarters, that's in our cost, and we'll have that basically completely into our cost by the time we get sort of to the end of this year on a run rate basis. So we're exceptionally pleased with how smoothly that's gone in delivering on those cost reductions that we've previously talked about.

And then as we look to 2026, stepping the cost down again, as you said, that's basically getting the full year benefit of some marathon synergies that we've just described. But then we expect to capture a meaningful amount of the cost improvements that we announced on our last quarter call. And we're -- that's basically going to drive some pretty meaningful reductions in our costs as we go through next year. It's -- they are the kind of the key things. And when we think about sort of how we reduce costs, we have sort of a mindset that this is continuous improvement. So we absolutely sort of challenge ourselves to sort of look at how we can basically continue to reduce those costs over time. But I think we're very pleased with sort of how we're doing that and sort of how that's showing up in our bottom line.

And I would add, Lloyd, you know us well, these reductions aren't conflated with capital kinds of things. They're not due to dispositions in the portfolio. We don't have lines of reconciliation because the net doesn't ever show up, and they're not cumulative. These are costs that will show up on our bottom line. And as I've said before, just watch us every quarter, and you'll see them materialize. They'll be real and they'll head straight to the bottom line and to our free cash flow inflection that we've been talking about for the next number of years.

Our next question comes from Scott Hanold from RBC Capital Markets.

I know it's always challenging to provide forward guidance with some uncertainty on commodity prices. So I appreciate the details on '26. Looking at total production and capital, it does appear similar to consensus numbers, but there does appear to be a variance to oil, our oil guide relative to consensus. And was hoping you could help us walk through where we might have sort of missed that? And we do understand there's a lot of complexity given the diversity of assets and other things like [ Surmont Post ] payout. But I was wondering if you could walk us through some of that.

Scott, this is Andy. I'll get us started with a couple of points here, and then maybe Nick can add a bit more detail on the Lower 48 for us. So just a couple of things I'd say is that if you look at our third quarter, at the total company, we're at a mix of about 53% oil. And this is the first quarter now where we have the full impact of Surmont that you just referenced. So we now have a higher royalty into Surmont. So the third quarter is a pretty good mark basically as we think about 2026. And we've provided guidance. I hope you found that helpful, where we've now provided guidance basically for an oil split. And we're basically forecasting '26 to be about that 53% for the total company, and that does include sort of the bitumen impact of higher royalties of Surmont. And then specifically to Lower 48, we're guiding about 50% for the Lower 48.

And then just one final point I would make before Nick can maybe comment on the Lower 48 is when we provided our '26 guidance of 0% to 2% range, for BOEs, that's also a good range for how we're thinking about oil as well sort of -- so I think we've tried to sort of guide a bit more on this time, we would say, we recognize as you provided for us upfront, there's a lot of moving parts here, but across the portfolio. But now that's 53% for the total company, we think, is a good mark for next year. And maybe Nick can just had a few comments on Lower 48.

Thanks, Andy. Yes, if you look at 3Q Lower 48 oil mix, we are around above 50% and you can compare that to 2Q, it was about 50.5%. And that was in line with our expectations and our development plan. going forward. As Andy mentioned, we're guiding to oil mix at 50% when you look at 2026 forward. And again, that's simply an output of our plan and an output of our development plans where we're developing in the various basins.

Now as a reminder for the group within the Delaware, that is our most significant growth driver within the Lower 48. So it shouldn't be a surprise to this group that oil mix will trend in that direction. It's low cost of supply, higher gas content, but very good strong oil content and good returns. Another key component to think through is we've got two decades plus of drilling inventory at current rig activity levels in the door. It's a peer-leading opportunity set out there.

Now one other component I need to think through is that oil mix can fluctuate depending on the relative contributions from these basins as we drill in different areas. So you might have some higher oil mix and some more oil mix and variations from quarter-to-quarter. But overall, as Andy mentioned, 50% on Lower 48 [indiscernible] Mexico forward.

Our next question comes from Doug Leggate, from Wolfe Research.

Guys, I'm going to try very hard to make this one question, but I'm hoping you can maybe help us navigate the moving parts a little bit. My question is on -- it's principally on Willow and the CapEx, what happens after Willow, but it's really about the evolution of your dividend breakeven because I think the Willow news has overshadowed the other big news, which, of course, is your dividend increase. So I guess my -- the way I would try to phrase the question is how damaging is the increase in Willow's spending to the cash cadence of the cash flow coming back. And I guess my point specifically is you get qualified CapEx deductible and taxes in Alaska is pretty advantaged. So can you walk us through how big a deal this really is and what happens to the dividend breakeven as Willow comes online.

Doug, this is Andy. I can try and step through that. I think you sort of half answered the question for me in terms of sort of how this works on a tax basis. And Ryan touched on this also in the prepared remarks. And the way I would look at it sort of at a total company level, is our breakeven is coming down, and it's coming down pretty substantially. Just right -- we think about where we are right now our breakeven this year, so just on CapEx is in the mid-40s, you'd add another [ 10 ] to that for the dividend. Just from what we've described today from what we're doing from '25 to '26, that brings our breakeven down in of itself $2 to $3. So we're on this trajectory of, yes, cash flow inflection is going in one direction, which is great. And then our breakeven is also coming down, which is great.

And as Ryan said in his prepared remarks, that's going to continue to happen where we're going to go all the way down to being in the low 30s on a capital breakeven, but the time will comes online. So I don't think what we've described today with CapEx in Willow going up. And let's not forget also the LNG CapEx coming down, there's having any really sort of notable impact on our breakevens and our ability to sort of generate cash flow over this time frame and our cash flow inflection remains unchanged. And that's why -- and I think you started the question with the dividend. And hopefully, that isn't getting lost in all of the news that we're describing today. But we have now increased that dividend by 8%, and this is now the fifth year of us having top quartile growth of the dividend. And versus the S&P 500. And we feel very confident with that breakeven that, that continues.

Yes. And I would add as well, Doug. Look, it's -- and it's sustainable given the breakeven coming down, as Andy described, the dividend is representing a lower portion of our total cash flow in terms of our distribution back to the shareholders. So how to give the shareholders and stakeholders in the company, a lot of comfort and conviction that we can continue to deliver top quartile S&P 500 dividend growth in the company well into the future given the projects that we're executing, the cost supply of those projects and the free cash flow growth we're going to see coming out of the company. So it's quite sustainable and leaves us room to buy back some of our shares, which we're leaning into quite a bit right now.

Our next question comes from Bob Brackett from Bernstein Research.

As much as I'd love to ask a few questions on Willow, I'll change the topic a bit, and that is to talk about the 2026 guide at 0% to 2%. And we've seen other large E&Ps and integrators with similar sorts of guides in a backdrop where WTI is sitting below [ 60 ]. So can you talk about what macro world you envision or which you plan for that we're going to see next year? And how does that inform that capital guide and production guide?

Yes. Thanks, Bob. I think -- I would like to say we have a lot of flexibility in the company. Production is kind of an output of our plans. We kind of set sort of a constant level loaded scope within the Lower 48. Nick talked a lot about what that means for kind of the production growth we see coming out of that.

Our view of the macro supportive, again, we kind of set this at a $60 WTI to your point, WTI is trading a little bit below $60 at this moment in time. Our call would be probably seeing some inventory builds. We saw some of this last week. We'll see how it continues onshore in the OECD countries, but we price some downside pressure coming through the latter part of the ending part of this year and into maybe the first part of next year.

So -- but that's why we have a balance sheet. That's why we have cash on the balance sheet. We want to continue to fund our programs. We came out with a 0% to 2%. We think that sort of makes a lot of sense with the macro that we're seeing today, but it also is informed by the medium and longer term, which we're quite constructive on today. Again, we see about 1 million barrels a day of demand growth not abating itself throughout this decade and well into the next decade. And we think there's going to be a call on crude and even a call on conventional crude depending on what you believe the unconventional supply coming out of the U.S. is going to look like at these kinds of prices or even elevated prices. So we see some modest growth in the unconventionals, continuing maybe flat to slightly -- some slight growth into next year depending on the price. But I think it sets up well to be a bit more reflective as we go into 2026, which is what we've tried to show with our 0% to 2%. But remind everybody, we've got a lot of flexibility in the portfolio, both ways. We can -- we have opportunities to reduce more CapEx. Should we think that's the need. We can use the balance sheet? Should we decide to do that? Then obviously, we've got opportunities to ramp up on the other end as well. So we just think we have a lot of flexibility in the company, but I think this is a good place to start based on sort of how we view the near-term macro and where it's been developing.

Our next question comes from Jeoffrey Lambujon from Tudor, Pickering and Holt.

I'll bring it back to Willow, if I could. And honestly, I appreciate the detail earlier in the call that spoke to the breakdown there on the refreshed expectations. Can you also talk about the confidence level in the updated range? And essentially, what might be locked in from here? It would be great to just get a sense for what flexibility there might be up or down if things change enough over the course of the build-out or if the wider range that you have now captured the most likely scenarios in your view, and it's more a function of where you end up within that range.

Again, I would say we're winding back here a little bit, we recognize there was quite a bit of inflation coming out post COVID over the couple of years leading up to our taking FID in late 2023, and we're actually seeing that a bit in late 2023, which is why we took a view of just a couple of percent and we felt like, obviously, the monetary actions globally, we're going to knock that back a little bit. And so again, we took that view at the time. And this is just a really good time for us being roughly halfway through the project to reconcile what we've been seeing over the last couple of years. And as you know, it's across labor markets and engineered equipment, we've definitely seen some movement which is much more on the average of 4.5% to 5%. And that's been actual and realized you can certainly see the data yourself across the last couple of years.

Now sitting here today, we're seeing inflation rates abate a bit. We're starting to see inflation again in the 3%, 3.5%. But candidly, we're taking a view that this compounding inflation could based on the contracts that we have tied to market indices could continue in that 4% to 5% range. And so we've largely budgeted for that for the next 3-plus years of the project, just to ensure that we're not kind of falling back into prior assumptions in FID. So I would say we've got a lot of confidence in the -- Obviously, in the way we're putting this capital guide forward here at this time. And again, able to stand here in this position with that confidence because the team is executing just so well on the project. And we're not seeing schedule slip. We're not seeing other challenges. Certainly, the upward cost pressure. You're not seeing you talk about scope discovery. This is really about inflation across the broader market, and we've taken a conservative view for the next couple of years. So confidence in how we're pushing this out here today. And again, just pleased with how the project is moving forward here for the next couple of years.

Our next question comes from Paul Cheng from Scotiabank.

Ryan, I think, as you mentioned earlier that you think that the maybe increasing coal and oil, even on the conventional, and when we're looking over the past 10 years, I think you guys [indiscernible] reduced your dependence on exploration because you have such a great profile in the Lower 48. And as the shale oil is maturing, how should we look at it? Would you think that you still have such a huge portfolio that you really don't need to increase your exploration effort, and you can just rely on that on the share [indiscernible] to continue with your resource, your production? Or that you think the challenge on the longer term is really not that we need to start maybe increasing the effort given it's a long-cycle business.

No. Thanks, Paul. I think you bring up -- I guess there's probably an industry-wide macro question around that. Are we investing enough industry-wide on the exploration side and we lost some of that muscle inside the industry for that and large project execution for that matter there. And there's probably a bit to that from the industry side. Speaking specifically to our company, you're right after kind of the early 2000 time frame when we first got into the Eagle Ford and saw the -- grown our unconventional position inside the company and then really changed the portfolio pretty dramatically over the last number of years to really focus on those low cost of supply opportunities and resources that we now have captured inside the company, it has put a less reliance on exploration. But I remind everybody, we continue to spend $200 million to $300 million a year on exploration to continue to feed some of the legacy assets we have around the company in years past, that's been in Malaysia and in Norway, we've moved that around throughout the years, depending on some of the activity level and the opportunity set that we find. And we're doing that again next year because we're focusing most of that exploration probably up in Alaska to support the Willow development and get our -- get the company in a position to be able to feed that infrastructure that we're building out there for decades to come. So it's about a redirection of exploration. But we've been able to do that within that $200 million to $300 million allocation inside the company. We just spud a well in the [indiscernible] Basin of Australia to try to find more gas that we can bring into Australia. So this is not just a one, area we're appraising the discoveries for Google that we had in Norway a year or so ago. So we are spending some of that money. To date, it hasn't captured a higher capital allocation inside the company because we've been able to get everything we wanted to get done for that $200 million to $300 million. But I think you're right, macro-wise, within the industry, you're seeing a lot more of that. We've just been blessed with a -- we're a resource-rich company in a resource starved world. It looks like going forward. So I think we're uniquely positioned relative to many of our peers in the industry with having to consider significant ramp-up in that capital allocation.

Our next question comes from Charles Meade from Johnson Rice.

I'd like to ask a big picture question about your global LNG strategy. And you guys make this distinction between resource LNG and commercial LNG. And I'm wondering if you can talk about how those two -- how you think differently about those two pieces of the business, how they complement each other and perhaps how they compete with each other? And maybe wrap into that, one can make the argument that with the amount of resource you guys have in the Lower 48 that make a distinction between resource LNG and commercial LNG is kind of a distinction without a difference. And maybe comment on whether that's a valid argument in your view.

Charles, this is Andy. Yes, it's a great question. And a big question, as you say, in terms of sort of comparing the two and how we think about them. So I'd probably go maybe back all the way to the beginning, we've been in the LNG business really since the 1960s. I think we're involved in basically sort of inventing this business. So we kind of know a thing or two about it. And we traditionally sort of until recent years, had the, what I would call the sort of the resource LNG sort of the [indiscernible] LNG business, where it's been very much about finding a stranded gas asset and you find a gas asset, you find people who will buy the LNG, then you build an LNG facility and off you go. That's kind of where this industry was for yours. And we are we've been a big player in that with our Australia asset and our Qatar assets over the years. And that has served us really well. But as you fast forward sort of to what's happening in the Lower 48. It's a little bit of a different model in and you kind of started to touch on this where you've got so much gas in the Lower 48. But you don't need to treat it like a facility-by-facility approach, where you've got the stranded gas that you're trying to tie to one facility. So it's -- the whole model is different effectively in that you're trying to take this gas in the Lower 48. And our strategy is pretty simple. We're trying to basically take what we think is low-cost supply in North American gas and get ourselves access to international pricing in TTF and JKM and that's exactly what we're positioning ourselves to do. We've made great progress in doing that with -- as I talked about in the prepared remarks, the 5 MTPA of Port Arthur Phase 1 that we've now fully placed. And then we're now moving on to Port Arthur Phase 2 where we took 4 MTPA and another 1 MTPA at Rio Grande. So we're trying to basically get ourselves in a situation where we can basically convert Lower 48 gas into international pricing.

And what I would remind everybody is that we're also in a position where this commercial strategy complements our business so well. We produce over 2 Bcf a day in the Lower 48 and 2 Bcf a day in round numbers is about 15 MTPA. So it also works as a natural hedge to our Lower 48 gas exposure. So I don't -- back to your -- first off, because I don't really see them as the resource LNG competing with what we're doing in the Lower 48. They're kind of different modules, but we've certainly been able to learn from the resource LNG. And that's why we've been able to sort of implement the strategy we are doing basically where we're trying to control the entire value chain and the only can do that with our global size and scale, and that's how we basically think we capture the economic rent. So hopefully, that helps sort of frame up how we think about the difference between the two. But I don't -- it's not like an either/or choice for us. We think that they both serve a really important role and we're happy to be playing in both as you can see with NFE and NFS on the resource side and what we're doing on the commercial side. With Port Arthur and the other announcements we've made today.

Our next question comes from James West from Melius Research.

I wanted to follow up on the LNG question. Obviously, the strategy is pretty clearly defined here. You had a lot of commercial movement. During the quarter, you're at 10 MTPA now, I think you've said in the past, 10 to 15 is kind of a range. Are we at a point where maybe you pause and digest or do you lean in and go up to that 15?

Yes. I'd say very briefly, our strategy remains unchanged. We're executing exactly what we said. We -- the 10 to 15 MTPA is a size that we feel very comfortable about. It gives us the size that we want to be able to optimize our portfolio, be able to divert cargoes as I mentioned in the prior question, be able to control really the value chain. And I don't think anything's really changed there, that the 10 to 15 is kind of what we're looking to fill out right now.

And I think, James, it's also a function of not getting too much commitments on the front and make sure you can place it on the back end. So we're being deliberate about that. And if we get more opportunity for low liquefaction costs opportunities will add more to the $10 million MTA, but we got to back it up with regas on the other end and have a plan for it. So we're being deliberate now that we've reached that 10 million-ton mark.

Our last question comes from Kevin MacCurdy from Pickering Energy Partners.

Thank you guys for fitting me in. I want to come back to Slide 7 for a moment on the incremental free cash flow. And I know that you've shown this before with the $4 billion of free cash flow from Willow but I think that's quite an eye-catching number. And I was wondering if you could provide anything high level on how you get there in terms of margins, production, maintenance, CapEx in that first year? And if that -- and also to ask if that's a fairly good number to use heading forward for Willow post-2029?

This is Kirk. Certainly, as you saw in the waterfall in the details in the supplementals on Willow, you can really take it directly from that. So as we compare against what was a historical and expected spend here this year of just over $2 billion, as mentioned by Andy, in the prepared remarks, we're expecting that here on the Willow Capital spend here for this year, and then that moves down, plateaus for the next couple of years. And then on sustaining capital, post first oil, we're expecting to spend roughly $0.5 billion and just continue development drilling for the Willow Project. Obviously, we're starting free drills, we've got predrill planned in 2027. And then that will extend in that predrilling is all baked within our total Willow project spend. But then post first oil, that $0.5 million. So in essence, what you're seeing is this inflection downward of capital from roughly $2 billion to an average of $0.5 billion first oil and then first oil, you're getting the CFO associated with, again, why we like Alaska. It's 100% oil sales, it's Brent premium. And again, that is the balance then of the $4 billion free cash flow improvement against a reduction of roughly $1.5 billion on CapEx.

And I'd just remind, Kevin, that you see how the prices that, that's assumed at $70 prices. And we've given a sensitivity to that as well in the materials.

Well, let me thank everybody for participating today. Just a few summary comments. We continue to execute well. We're improving our plan, and we're well positioned for a strong 2026 as evidenced by the new guidance we provided today.

And I'd say the team continued to find a lot of ways to enhance value in what we think is a differentiated investment thesis. We have an unmatched portfolio quality. We've got a leading Lower 48 inventory depth, combined with attractive longer-cycle investments in the LNG in Alaska that we've described today in quite a bit of detail. And we continue to have a strong track record of returns on and of our capital, and that's all leading to a sector-leading free cash flow growth profile that takes us all the way to the end of this decade. So thank you all for your interest in ConocoPhillips, and we appreciate the questions.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

Welcome to the Second Quarter 2025 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. [Operator Instructions]

I will now turn the call over to Guy Baber, Vice President, Investor Relations. Sir, you may begin.

Thank you, Liz, and welcome, everyone, to our second quarter 2025 earnings conference call.

On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; and Andy O'Brien, Chief Financial Officer and Executive Vice President of Strategy and Commercial; Nick Olds, Executive Vice President of Lower 48 and Global HSC; and Kirk Johnson, Executive Vice President of Global Operations and Technical Functions.

Ryan and Andy will kick off the call with opening remarks, after which the team will be available for your questions. For Q&A, we will be taking 1 question per caller.

A few quick reminders today. First, along with the release, we published supplemental financial materials and a slide presentation which you can now find on the Investor Relations website. Also during this call, we will make forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings. We will make reference to some non-GAAP financial measures Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website.

With that, I'll turn the call over to Ryan.

Thanks, Guy, and thank you to everyone for joining our second quarter 2025 earnings conference call.

Starting with results and outlook. We delivered another strong execution quarter, once again exceeding the top end of our production guidance range. We reiterated the midpoint of our full year production guidance even with the announced agreement to sell our Anadarko Basin asset for $1.3 billion. And our capital spending and operating cost guidance ranges, both of which we lowered last quarter remain unchanged. On return of capital, we remain on track to distribute about 45% of our full year CFO to shareholders this year. That's consistent with our prior guidance and our long-term track record. The bottom line, we're operating well. We're delivering on our plan, and we're well positioned for a strong second half of the year with clear free cash flow tailwinds, including lower capital spending.

Turning to the Marathon Oil acquisition. I'm pleased to announce that the asset integration is now complete and that we've significantly outperformed our acquisition case. We added more high-quality, low-cost supply resource. We're achieving more synergies. We're delivering a more efficient Lower 48 development program, and we've already announced more asset sales than we guided at the time of the transaction announcement. While these are all significant achievements, we're not stopping there. Given our integration success, which builds upon other successful transactions as well as our recent implementation of a new company-wide enterprise resource system, we continue to drive for improvement across every level of the organization. As part of this effort, we've identified more than $1 billion of additional cost reduction and margin enhancement opportunities. Now to be clear, that's on top of the more than $1 billion of Marathon synergies we've already expected to realize. Additionally, now that we've exceeded our $2 billion asset sales objective ahead of schedule, we're raising our total disposition target to $5 billion. Collectively, these initiatives will strengthen our ability to generate strong returns on and of capital through the cycles and enhance our long-term value proposition. And that's a value proposition that's already differentiated, not only relative to our sector, but relative to the broader S&P 500 as well. We believe we have the highest quality asset base in our peer space. Our global portfolio is deep, durable and diverse and were recognized as having the most advantaged U.S. inventory position in the sector. We believe this will -- advantage will become increasingly apparent as the U.S. shale industry continues to mature. And investors are forced to more clearly sort through what we call the inventory haves and have nots. We are a clear leader in the U.S. inventory halves. In addition, we're uniquely investing in our high-quality portfolio, specifically in our longer cycle projects in LNG and Alaska to deliver strong returns and a compelling multiyear free cash flow growth profile. Assuming a $70 per barrel WTI price environment, we expect the major projects we're currently progressing in combination with the additional cost and margin enhancements we just announced to drive a $7 billion free cash flow inflection by 2029. That would almost double the consensus free cash flow expectation for the entire company this year.

Now with that, let me turn the call over to Andy to cover our second quarter performance, 2025 guidance and strategic objectives in more detail.

Thanks, Ryan. Starting with our second quarter performance. As Ryan mentioned, we had another quarter of strong execution across the portfolio. We produced 2,391,000 barrels of oil equivalent per day, once again exceeding the high end of our production guidance. In the Lower 48, production averaged 1,508,000 barrels of oil equivalent per day. Alaska international production averaged 883,000 barrels of oil equivalent per day as we successfully completed turnarounds in Norway and Qatar.

Regarding our second quarter financials, we generated $1.42 per share in adjusted earnings and $4.7 billion of CFO. We had a $1.5 billion working capital headwind, effectively offsetting the equivalent sized tailwind on we realized last quarter. Capital expenditures were $3.3 billion, slightly down quarter-on-quarter. We returned $2.2 billion to our shareholders, including $1.2 billion in buybacks and $1 billion in ordinary dividends. Through the first half of this year, we've returned $4.7 billion to our shareholders, about 45% of our CFO, consistent with our full year guidance and long-term track record. We ended the quarter with cash and short-term investments of $5.7 billion, plus $1.1 billion in long-term liquid investments.

Turning to our outlook. For full year production guidance, we have narrowed the range and reiterated the guidance midpoint, even after adjusting for the Anadarko sale of approximately 40,000 barrels of oil equivalent per day, which is expected to close at the beginning of the fourth quarter. Our capital spend and cost guidance ranges, both of which we reduced last quarter are unchanged. We now expect our full year effective corporate tax rate to be in the mid- to high 30% range, excluding onetime items, lower than we previously guided due to geographical mix. And we now expect a total full year deferred tax benefit of about $0.5 billion, primarily reflecting the positive impacts from the 1 big beautiful bill. In the second half of the year, we expect free cash flow tailwinds in the form of higher APLNG distributions, cash tax benefits and lower capital spending. Further guidance details can be found on our earnings slide deck.

Turning now to our strategic updates. As Ryan noted, we have completed the math and asset integration and are realizing comprehensive outperformance against our acquisition case. We're delivering everything we said and much more. First, we've upgraded our low-cost supply resource estimate by 25%. While we are most attracted to Marathon significant Eagle Ford and Bakken positions, both of which are every bit as good as we expected, and delivering excellent well results, the majority of the increase has been driven by the permian, where our resource estimate has approximately doubled versus the initial estimate.

The second point I would highlight, we have significantly outperformed our initial synergy guidance. At the time of the transaction announcement, we guided $500 million of annual synergies. With our steady-state capital development program achieved and critical system cutovers now in the rearview mirror, we are on a glide path to realize more than $1 billion of run rate synergies by the end of the year. In addition, we've identified over $1 billion of onetime benefits, largely cash related -- cash tax related. While we don't count these -- this is a synergy, it's real value and a material benefit to our company.

The third point I'd highlight, we brought the power of our more efficient and steady state development program to the combined portfolio. At the time of the transaction announcement, we highlighted our ability to more efficiently develop Marathon's acreage given our size and scale advantage and ability to level load our program versus Marathon's practice of ramping activity up and down. We've now achieved optimized level of steady-state activity, and we're delivering more combined production with 30% fewer rigs and frac crews in comparison to the pre-transaction pro forma activity levels.

And finally, with the announced Anadarko sale, we've now signed over $2.5 billion of dispositions within 9 months of the transaction close, beating our $2 billion target well ahead of schedule. Given our growth in recent years and implementation of our new company-wide ERP system, we are taking the opportunity for further cost and margin improvements across the entire company. We've identified more than $1 billion of opportunities that we expect to realize on a run rate basis by the end of 2026. All of this is in addition to the $1 billion of Marathon synergies we previously discussed that we expect to realize on a run rate basis by the end of this year. These additional improvements will be wide-ranging, encompassing cost reductions across our SG&A, operating costs and transportation costs as well as margin enhancement through commercial opportunities. All in, including the math and synergies, we expect to drive over $2 billion of run rate improvements by the end of next year.

In addition to furthering our cost reduction initiatives, we are more than doubling our asset sales target to $5 billion, which we also expect to achieve by the end of next year. We see a clear opportunity to further high-grade our portfolio and accelerate value realization of assets that are not currently competing for capital.

So to wrap up, we continue to execute well operationally, financially and across our strategic initiatives, we are well positioned for the second half of the year with clear free cash flow tailwinds, and we continue to find ways to enhance our differentiated long-term investment thesis. That concludes our prepared remarks.

I'll now turn over to the operator to start the Q&A.

[Operator Instructions] Our first question comes from Neil Mehta with Goldman Sachs.

Really appreciate the incremental disclosure and love the Slide 7. So Ryan, maybe we could start there, which is if you look at street numbers, at around $60 to $70 WTI, you're generating close to $8 billion of free cash flow this year. So if you add 6 to 7, you're kind of closer to 14, which implies by '29, a 12% free cash flow yield. So I first wanted to just check the math on and make sure that we're not missing any pieces around it. And then to the extent that is the right framework, which is a great prize in a couple of years, the pushback might be, you got to wait for it and so Ryan maybe your perspective on, hey, with every year, you derisk towards that free cash flow number as capital intensity improves. So you don't necessarily have to wait to 2029 would be in theory, but it would be just your perspective on all that.

Yes. Thanks, Neil. Got ahead of the class, your math is pretty good. Look, yes, we're working pretty hard, as you mentioned, the numbers fit exactly what we're thinking about in that $60 to $70 range, we'll add about $7 billion of free cash flow between now and 2029. I mean you don't have to wait until 2029. Some of that is coming through the -- about 1/3 or so is coming through the LNG channel, and there's going to be consistent start-ups starting next year with Qatar -- 1 of the trains in Qatar '27 with Port Arthur '28 with another train in Qatar, and then, '29 with Willow. So all of that's coming. Everything is on track. And you're right, it nearly doubles our current consensus free cash flow that I said in my opening remarks. And I think this is a trajectory and things that are coming that are unique in the business. There's no other E&P that I think can match what's coming for us, including the integrated majors. So I think we're unique in this space. We've been leaning in and making these investments that are very competitive in the portfolio, a low cost of opportunities for the company that are going to contribute to our growth and development for decades to come. And I would say, too, that it does not include the inventory advantage we currently have in the Lower 48, a very deep and Tier 1 inventory that we have, and where we're constructive in the macro going long term. And if the call for shale production starts to come up because where is the supply coming to meet the growing demand that we believe is going to be there. This doesn't even include what we could do to lean into our Lower 48 a little bit more. We haven't because the call hasn't been there to date. So we're growing at a bit more modest rate, but we're taking advantage of the integration, we're taking advantage of the synergies. I remind people, we haven't added a rig in 3, 4 years. So we're just continuing to grow our Lower 48 just through the efficiency in the channels. So none of that even includes what we could do, depending what the call is for unconventional production going forward. So no, your math is good. We're excited about the opportunities for the company.

Our next question comes from Arun Jayaram with JPMorgan.

Ryan, I was wondering if you could unpack the $1 billion cost reduction in margin optimization plan, which looks to be a new wrinkle in the update. You mentioned the ERP system integration. I was wondering if you could talk about what are some of the drivers of the $1 billion? And are you doing anything at the organizational level to reengineer kind of your operating structure?

Yes. No, Arun. It's going to touch all pieces of the company. There are some some workforce centralization, some things that we've learned over the last 3 to 4 years with all the transactions that we've done, that we're going to be implementing kind of globally throughout the company. So there's a piece of G&A built into this. There's utilizing the scale and scope of the company to drive some lease operating expense improvements as well, things that we're doing contractually, things that we've captured in the Lower 48 and understand from an efficiency perspective that we can drive throughout the whole company. As we've grown our scale, we also see opportunities in transportation and processing, and that's going to show up as expense reduction and margin expansion through realized price improvement commercially. I'd say about 80% of it sits within the G&A, LOE, T&P just expense reductions, 20% of it sits in that kind of margin expansion bucket. And I would -- and I'd tell you, none of this includes capital sort of things. We don't count that in our synergy estimates. We're just talking about stuff that will flow through the bottom line and changes that we need to make as a result of some of the technologies we're deploying and the size, scale and scope of the company through the inorganic expansions that we've had over the 3 to 4 years, and it's with that behind us now time for us to get the whole company running, taking advantage of stuff that we've invested in over the last few years.

Our next question comes from Steve Richardson with Evercore ISI.

I appreciate you're probably not going to tell us what's for sale. Ryan, in terms of this meaningfully increased divestiture target. But perhaps you can give us some perspectives on the acquisition market from the sell side. And maybe just talk about the types of assets, and I'm sure you're intently focused on cost and supply in terms of high grading. But maybe you could talk just sort of asset types and that process and the confidence on that higher target.

Yes. No. Thanks, Steve. I think we've described to you and others that are on the call, and we go through a pretty rigorous exercise every year. We've kind of come out of the back end of our planning exercise that ramps up during the summer months. And through that process, we look at every asset in the portfolio. And we look for the ones that are competing for capital and those that aren't competing for capital. And we tell our teams for the assets that are on the outside looking in a little bit, maybe there's different technologies we can deploy different ways to think about it, different learnings from across the company. And we give them some time to see if they can compete for capital long term. But if they don't, then they they migrate to a different list. And look, we're resource rich in a resource-scarce world today. So that's what I think we were pleasantly surprised with the Anadarko Basin. We -- there's an example that wasn't going to compete for capital in the portfolio. We're getting plenty of North American natural gas production from our assets in North America, it just wasn't going to compete for capital as we integrated that asset into the company, and we were pretty pleased with the price that we got. So as we scrub the portfolio and think about it, going forward with the remainder of this year and through 2026. We just felt like we see the assets that are out there and that aren't competing for capital, and we think it's going to be a reasonable market to be selling into, which is what gave us confidence to increase the target to $5 billion, and we've already surpassed our $2 billion target, as Andy described in his remarks to date with about $2.5 billion sold through this point in time.

Our next question comes from Doug Leggate with Wolfe Research.

Ryan, I missed all these incredibly positive updates. I hate to ask such an asking question is cash tax, but going to make Andy earnest crossed today. And the $500 million incremental deferred for '25. Obviously, there's a lot of moving parts with the M&A, the Marathon and obviously asset sales and so on. What is the sustainable deferred tax visibility do you have for the Lower 48 at this point if you're able to offer any color beyond 2025.

Doug, it's Andy. Yes, you're going to make me on my strikes for the first question. There's quite a few moving parts to tax is core. And maybe I'll just try to cover them sort of step by step and sort of trying to get everything covered in tax in 1 question here. So just so we -- just to clear because I think some of this gets conflated in terms of what's the 1 big beautiful bill impacting, what isn't impacting. So just starting with the quarter in terms of our 2Q effective tax rate, we were lower than we guided last quarter. And we've actually reduced the full year effective tax rate to the mid-30s for the rest of the year. So that was purely due to sort of a mix where we had domestic commodity prices relative to international markets were a bit higher than we forecast, and that resulted in a higher mix of income from our lower tax jurisdictions like the U.S. So that's probably the first thing that jumps out to people is the effective tax rate. The second thing going on to the deferred taxes, we saw a larger-than-expected deferred tax benefit during the second quarter. That had nothing to do with the new tax bill, that was largely due to one-off discrete items that we really don't forecast. And then getting pose to the meat of your question in terms of, first of all, the expected benefits, we covered this in our prepared remarks that this year, we think the 1 big beautiful bill will have about a $0.5 billion impact to us. And that's primarily due just simply to the bonus depreciation rate going from 40% to 100%. Now of course, that's going to carry on into 2026, and we'll continue to benefit from that bonus depreciation. But specifically to get into numbers at this point, it's a little bit too early, and I think you helped to answer the question for me in terms of why we've got to land exactly where the CapEx is, what's happening with, which assets are being disposed of. But what we do know is that it's going to be a tailwind for us for the next year.

Our next question comes from Lloyd Byrne with Jefferies.

Bryan, Andy. I think that 30% fewer rigs and frac crews actually equates to almost 100% of what Marathon is running at the time of the deal was very impressive. But let me just -- I guess, my question about LNG and kind of the downstream strategy. And just kind of what you're expecting from regasification sales deals going forward? And then how do we expect that to contribute over the next few years?

Yes, I'll maybe start and let Andy jump in on the NG side, but you stuck in 2 for 1 there. Good job, Doug, or Lloyd, you're good there. Look, yes, I think we're pretty impressed with what Nick and his team have done with the integration in Marathon. But you're right, we've effectively eliminated their 10-rig program and not only deliver the pro forma production between the 2 companies, but growing the production as well. So I think Nick's team is really hitting on all the cylinders, and we're really pleased with the success we've had in the aggressive way that they tackled that program as well. I can let Andy talk a little bit about the LNG side.

Sure. I think on the LNG side, you are probably specifically referring to some of the stuff that we've announced this quarter where we've added another 1.5 MTPA of regas capacity at Dunkirk in France. And we also executed an SPA with an Asian buyer. And what I'm quickly pleased about is with those 2 announcements, we've now effectively placed the entire 5 MTPA from Port Arthur. So going forward, we're now at a point where we're continuing to have conversations both on the offtake side of things and on the placement that everything is tracking really well. We're placing 0we've placed everything that we have to date. So now what we're looking basically to the next steps. And what I can say in that space is that things certainly aren't slowing down, both in terms of opportunities for more offtake and conversations with customers in Europe and Asia. So probably a bit of a watch this space. Hopefully, we'll have more to talk about in coming quarters and really pleased to have the commercial LNG are starting to come together to any complement what we've already got with our resource LNG in Australia and Qatar.

Our next question comes from Betty Jiang with Barclays.

Maybe, Andy, a follow-up to your comment earlier about trying to understand where the CapEx lands for next year. I was wondering if you guys can give an early read on how you're thinking about 2026 at the moment with the additional cost savings you're envisioning, commodity price is probably a bit more supportive, how do you see development evolving next year? Where do you expect the major capital spend to trend, and maybe just frame how much of that long-term free cash flow inflection could get captured next year?

Thanks, Betty. I can try and take that one. And yes, it is a little early to be talking about 2026. But I'm happy to share a few high-level thoughts. So starting on the capital spending side of things. We've been saying this for a number of quarters now. We expect our capital next year to be lower than this year as we -- at the beginning of the cash flow for inflection. And then maybe also just to touch on production. I think we've always been saying that for us, production really, it's just simply an output of our plan. And if you look at what we're doing this year, from our guidance, basically, it implies about 2% growth on an underlying basis this year. And in the macro environment, we see right now I think this would be a pretty good place to start for modeling purposes for next year. I think Ryan mentioned on the rig side in a previous question, we haven't added essentially a rig in the Lower 48 on the on the concrete side over 3 years. And right now, I probably don't really see a good reason to do that. But the other thing I would add is that in terms of maybe just going to sort of 1 half this year to the second half next year, we're already starting to see the cash flow inflection coming. If you look at our CapEx guidance, we're guiding from 1 half this year to the second half that our CapEx is going to be down $1 billion. You can see from our CFO from the first half to the second half that -- we're also going to have some tailwinds from higher APLNG distributions and the 1 big beautiful bill. So when you look at that, and that continues on into 2026, I'd actually say that the cash flow inflection is effectively already starting.

Our next question comes from Nitin Kumar with Mizuho.

Ryan, 1 of your peers talked about industry consolidation going forward. You mentioned in the last 3 to 4 years, you've been at the forefront of that. So I just want to get a take on where do you see the M&A landscape right now, particularly in Lower 48.

Yes, Nitin, I think -- look, I think there's still going to be consolidation in this business. I think a lot of the E&Ps in the unconventional space look out into their plans 2 to 3 years out and wonder what's going to happen. And I think -- and that hasn't changed as capital intensity, people that don't have the inventory like we do face higher capital intensities and just what do they do about that. Now specific to us, this is the strongest, I think our portfolio has ever been. And so it's a pretty high bar. And we're focused pretty heavily right now on the organic side of the business, where the investments we're making to grow and develop the company, both short, medium and long term. So I think that's where all of our focus is going. But look, we watch the market every day. We see what other people are doing, and I'm familiar with the comments that were made by 1 of our peers. But we're just in a different position because of the effort in the -- what we've done over the last 4 years that you pointed out and then the focus we're trying to drive internal to the company to chase another $1 billion of additional cash flow growth in the company. We see the inflection that Andy just talked about in our free cash flow coming as these projects starting up over the course of the next 3 to 4 years. So we've got a pretty high bar and a pretty full plate today, just executing on our organic plans.

Our next question comes from Ryan Todd with Piper Sandler.

Great. Maybe a question on the on the Marathon transaction. You increased your expectation for the incremental resource adds from 2 billion to 2.5 billion barrels with a doubling of resource estimated resource in the permian. Can you talk about what's driving that? What's been better than expected, particularly in the permian?

Yes, Ryan, Yes. As a reminder for the folks on the call, the Marathon transaction, we announced the 2 billion barrels of low-cost supply resource. Now we've got 8 months under the Marathon hood to further assess the inventory and the development strategy across all the assets. As Andy mentioned, after completing the integration, we've got a 25% increase. So that's the 2.5 billion. Now we were clear at the time of the acquisition that the quality positions in the Eagle Ford and Bakken were the primary strategic rationale for the transaction. And we're seeing on aggregate, the performance in those 2 basins have been in line to even better than we expected with very strong well productivity versus the acquisition case. Now the upside identified, as Andy mentioned, is primarily in the Delaware Basin, where we've approximately doubled our low-cost supply resource estimate with some additional resource in the Bakken as well. Now in the permian, this is largely driven by a greater contribution of both primary and secondary intervals across the play. For example, we got inventory across Wolfcamp A and C, Bone Springs and Woodford formations, which are very competitive cost of supply. And Ryan, that's through really reassessing the inventory and applying our development strategy, including spacing and stacking. In fact, we're drilling some Wolfcamp A and C wells as well as some Woodford wells right now and seeing really promising results in line or even better than the type curves. In addition to the inventory I just described, we're also seeing opportunities to trade acreage to core up positions, adding more longer laterals, which improves the cost of supply, if you go from a 1 to a 3-mile lateral, we see that 30% to 40% improvement. So I just got the hats off to the team as we get under the hood, they're excited. There's more opportunities in there. So getting ready in those and execute upon it.

Our next question comes from Scott Hanold with RBC Capital Markets.

Ryan, it would be good to hear your view of what you're seeing on the old macro front, obviously, if we wind the clock back last quarter. There's a lot of uncertainty. Oil price obviously has firmed up I know you all do a lot of work, but I'd be interested in your thoughts on what you're seeing right now, and how that could shape your plans into '26?

Yes. Thanks, Scott. I think I described it as choppy this morning on CNBC, I think. And that's kind of our, let's say, short near-term view of the macro. Look, the OPEC Plus group has added about. They've unwound all the 2.2 million barrels a day of cuts and then they added 300,000 more allocation to the UAE, bringing that to 2.5. Our internal view is about 800,000 of that is already in the market. So of that 2.5, you take 800,000 [indiscernible]. So there's about 1.7 million barrels a day true incremental production, but it hasn't shown up in exports either because of the power burn and all the summer burn in the Middle East that's going on right now. And the demand grew in the first half, a little bit more than what we would have predicted a little bit over 1 million barrels a day. I think for the full year, we're still at about 800,000 barrels a day of demand increases coming forward. So you can see it's a bit imbalanced more supply than the demand in the short term. But we got to remember that inventories that are 5-year low. Certainly, here in the U.S., we're seeing some early indication that floating inventories might be coming up a little bit. Certainly, China is filling their SPR right now to feed their 2 bat refineries. So there is a lot of moving pieces, as you say. So how do we think about that? We step back, we see the choppiness, although prices are hanging in about at our mid-cycle price, and they've been relatively stable in the 60s. So we see probably that continuing with probably a bit more pressure to the downside, which is why Andy talked about how we're executing our program and kind of how you should think about modeling our production as we go into 2026, and that's just we probably see a little bit of choppiness and some slight slight headwinds as we go, but we're very constructive when you start stepping back for a minute and thinking about the longer term. We see demand continuing to grow at a million barrel a day incremental clip or at all-time highs in the demand side, and we don't think that's stopping. So we do wonder where the supply is going to come to fill that growing demand over the next 2, 3, 4, 5 years and beyond, which is -- was our view over the last few years, which is why we're leaning into some of the longer cycle projects. That's the oil side. And then obviously, on the gas side, we're pretty bullish there. We see the LNG market growing from a a 400 million-ton market to over 700 million-ton market within the next 5 to 10 years, which is why we wanted to lean into the LNG side of the business, and we see a lot of resource in the U.S. to support that and to underpin that strategy. So maybe that's reader's digest abridged version of our view of the macro, both on the oil and the gas side.

Our next question comes from Charles Meade with Johnson Rice.

Ryan, I cut your CNBC appearance, I thought that was a fine job. I wanted to ask a question on Willow. If you could perhaps give us a bit of a preview for what -- when you do get back to work there on the ground in the winter season, what does this next winter season hold as far as key milestones and work streams and just an overview.

Yes, I can let Kirk take that, Charles. I would say we haven't quit working. We're pretty busy right now. We got a -- I was just up there last week. We got a full team on the slope and working through the summer and a lot of work going on in the Corpus Christi [indiscernible] II building modules, but Kirk can jump in and give you a bit more specifics.

Yes, certainly, as Ryan is mentioning, our execution here this year just continues to be really quite strong. We did ramp that winter season up. It was the largest that we had certainly in the last couple of years and really the largest we have here planned for the project. We wrapped that up late April, early May. And so we've transitioned again, as Ryan witnessed, we're transitioning to year-round construction up there on the slope. We actually have about 900 trades and craftsman up on the slope right now. And that's down from again, what we were seeing during this peak winter season, which was closer to 2,400, if not 2,500 people up there on the slope. So it's been a pretty big transition for us here this spring. But of course, our teams are really focused now as you're alluding to, which is our the activities we have here this summer in this fall. So with that transition, those 900 craftsman on the slope are continuing to build out that operation center that we see lifted up here last year with those modules on location. And so there's a lot of work ongoing so that we can truly begin year-round construction there in Alaska at the Willow location. And then again, as Ryan mentioned outside of Alaska, we're focused on completing engineering in support of these process modules that we're building here on the Gulf Coast. And then naturally, that's going to continue through 2027. But certainly, I would say, as it relates to the activities here this year, there's a lot of work by the team focusing appropriately on contracting, procurement -- general supply chain activities. Admittedly, tariffs have introduced some level of uncertainty and that's manifesting with internationally sourced equipment alongside a trend of inflation that's pretty similar to what we've seen in the international markets. And that's stabilizing as activity stabilize here. So it's a good time for us to put a wrapper on some of these contracts here this year. We'll have close to 90% or 95% of these contracts pretty well secured by year-end, and so a lot of work in that space. So again, Charles, I would say strong execution. We're hitting the really key milestones. We have some more work, of course, in this next winter season as it relates to gravel on the North Slope continuing to build that out towards the next set of pads and kind of wrapping up the last pieces around pipelines and a bit of civil work. So certainly more to come, but the milestones we're achieving we're hitting those as we expect. And so it just continues to give us a lot of confidence in execution and strong expectations again around 2029 and first oil.

Our next question comes from Paul Cheng with Scotiabank.

Ryan, I want to ask about Eagle Ford. But before that, can I just sneak in and just clarify all that confirmed will load the CapEx is still at $7 billion. And in terms of Eagle Ford, with the Marathon deal, they do have some really different assets there. Can you give us an outlook where that you see Eagle Ford on a longer-term basis? I mean I think in the past that you have a view where that Eagle Ford you get to maybe for you guys, they call you 300,000 barrels a day now with this better performance in the second quarter and also the much larger resource base. How should we look at Eagle from your portfolio?

Yes. Thanks, Paul. I can let Nick chime in on [indiscernible]. I think we're seeing everything and then some based on the acquisition case we had for Marathon and some of the well results that I've seen over the last few months coming out of Eagle Ford on the Marathon acreage in particular, leaner acreage has given us a lot of comfort in the case. And we're seeing upside out of that as well. And I can let Nick talk a little bit about the longer-term perspective we might see in the Eagle Ford.

Yes. Thanks, Paul. Maybe just talk about short term here on the Eagle Ford. Obviously, as you pointed out, we had a really strong quarter related to Eagle Ford production, had really strong base production as well as new wells coming online. We actually had a little bit of lumpiness, about 10% more wells online in 2Q in Eagle Ford. So you saw that slight bump in production. I will say we're really starting to get our understanding around the heritage Marathon component in Eagle Ford. And what we're seeing there, Paul, is the wells are performing at or above type curve. So that's really good. I also say in Eagle Ford, it's -- we're sharing best practices across heritage Marathon, here to COP, and you may have heard that we had our best year ever in drilling within that asset. We had a 13% improvement in fee per day by combining best practices and drilling. So just hats off to the team there. A couple of other things on near term, 1 of the things related to the acquisition. We're also sharing our facilities being able to combine those 2, where we can reroute production, we can shelter maintenance, and that's leading to that increased production as well. So in summary, a really strong Q2. Now if I look longer term, as Ryan mentioned, when you take a look at the inventory combined for Eagle Ford, we have an industry-leading position. We're sitting on 15 years of inventory. That's at current rig activities levels and now hold a significant share of the remaining tier 1 inventory in the play. No one else comes close to that. Longer term, we're continuing to assess the optimum plateau of that asset, and we'll give you an update. One of the things we're looking at is the ongoing efficiencies that we continue to see outperform quarter-to-quarter. And so dialing into an exact plateau remains ongoing discussion. But that said, we'll land somewhere modestly below 2Q production as we go forward here in the near term. So really strong performance across Eagle Ford, really strong, what we're seeing with the well results.

Our next question comes from Leo Mariani with ROTH.

I just wanted to follow up a little bit on the asset sales here. Can you maybe give us what the rough production split is on the 40,000 barrel a day you're selling there in the Anadarko in terms of oil and gas? And then can you just talk a little bit about the timing on asset sales. Was there a particular reason you decided to kind of increase it right now. Certainly, a lot of the conversation on the call is talking about kind of macro uncertainty out there. So maybe just kind of talk about the environment to sell stuff now.

Yes. No. Thanks, Neil. I think we're -- yes, we -- as again, I tried to describe, we just go through a standard process inside our company to identify potential assets that that we think would be worth more to other people than they are to us. And that's certainly proven out in the Anadarko Basin asset sale, too. I can have Guy come back to you with the -- I don't know the -- it was mostly gas, but I don't know what the liquids mix is on that 30,000 barrels a day, but Guy can come back and provide that to you. And look, we don't -- we'll sell assets when we think we're getting good value for them. Look, we know what our hold value is. We know what they're worth to us inside the portfolio. We're not fire selling anything in the company. And there's assets that we've marketed that we haven't sold. And we haven't sold because either the -- the macro current macro environment was the supportive of it. And again, we know what our hold value is, and we know what the market is, and we'll move them out. We -- as we look across that portfolio of opportunities for the company, we felt comfortable with the $5 billion target by the end of next year. So feel comfortable we've got those assets to kind of sell, and we're hard at work trying to deliver that

Our next question comes from Philip Jungwirth with BMO.

I wanted to ask about return on capital. Conoco has historically been a leader here among the independents and integrated. We have seen corporate returns come down across the sector, much of which is oil price, but also M&A. So when you look at the organic -- $6 billion free cash inflection that you have for major project start-ups, I was hoping you can talk to how this improves ROCE by the end of the decade? Or there'll be more improvement really from accelerating the Lower 48 growth at the right commodity price?

Yes, Phil, look, all these projects that we're executing meet our cost supply hurdles. So almost kind of doesn't matter where you allocate, you're going to see the growth in the ROCE. And that's what we're trying to drive inside the company. We're trying to be competitive with the S&P 500, not just competitive with our peers in this industry, we want to outperform even the S&P 500, give investors a resource or an E&P choice that they can invest in that can deliver year in, year out through the cycles, competitive ROC. And obviously, when the price whistles down as much as it did in the COVID year. It's tough in 2022, it was pretty damn good as prices goes back. But we're trying to deliver through the cycle, ROCE improvements and invest to compete against the S&P 500. That's what we're about. That's what -- that's how our performance gets judged, and that's what we're trying to go do. And as you as you inflect your free cash flow, $6 billion, $7 billion over the course of the next 3 to 4 years, obviously, the CFO is growing. And we have -- we do have a unique value proposition in this business, which is you get your CFO off the top from us. We have a commitment of a minimum of 30% at a mid-cycle price. And when prices have exceeded that, like they have for the last number of years, we've given a lot more of that CFO back about 45%. So that's what we're signaling again this year, and we don't see that changing. So as that free cash flow on Flex and our CFO grows, distributions are going to grow with that. The opportunity to invest in our organic programs come wIth that and strengthening the balance sheet comes with that as well. But absolutely, as our cash flow grows and free cash flow grows, distributions grow as well. And we're investing in the right things. We believe and what we're investing in, our ROCE will grow on a mid-cycle case basis as well.

Our last question will come from Kalei Akamine with Bank of America.

Look, I appreciate the strong performance in Lower 48. Last time you guys had an outlook on a multiyear basis was in 2023. And you suggested that there will be a capital ramp through the early 2030s. But when you look at the business today and the efficiency is achieved, it appears that you're still in the same production track. So kind of wondering if you can hit those production targets without adding significant activity or without any change in CapEx.

Yes. I mean that's the name of this game. You've got to be capital light, capital efficient, and that's how you grow your ROCE and that's how you grow your distributions and your free cash flow. So you're right to observe the last time we updated the market since then we've done the Marathon transaction, as I think Andy alluded to in some of his questions and comments, we haven't added a rig line anyone in the last 3 to 4 years, we're still delivering the production growth out of Lower 48. We're just being a lot more efficient, a lot less capital spend, and that's the name of the game. So we start every year thinking about, let's just keep the scope of what we're doing, constant. And as Andy said in his response to 1 of the questions, the production or the growth that comes out of that is purely an output. We will always start or trying to keep our stable programs in place. We don't want to whipsaw up. We don't like to whipsaw down. And obviously, we can react to both sides of that environment, but we like the consistent, stable execution and programs. And we haven't had a rig line or significantly increase the frac spreads, and we're operating within a pretty efficient frontier range where when frac spread can handle 3 to 4 rig lines. And that's improving with the technology, and we want to be improving with that as well. So I think we have a lot of flexibility. We have a lot of inventory and -- deep diverse inventory. So we've got a lot of choices and options. And as I said in 1 of my comments earlier that it's really the best place and the strongest portfolio we've ever had as a company

We have no further questions at this time. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.