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F500-2023-049-ConocoPhillips

ConocoPhillips, one of the world’s largest independent oil and gas exploration and production companies, skyrocketed 28 spots up the rankings in 2023, surfing a rise in crude oil prices driven largely by the war in Ukraine. 
<ul> 
 	<li>ConocoPhillips revenue rose nearly 70%, and its profits increased 131% in 2022 compared with 2021, when energy companies were still recovering from the dip in oil and gas demand resulting from the pandemic’s effect on travel.</li> 
 	<li>Throughout 2022 ConocoPhillips doubled down on liquefied natural gas (LNG), increasing its ownership of LNG operations in Australia, Germany, Qatar, and the U.S. Gulf Coast.</li> 
 	<li>In March 2023 President Biden formally allowed ConocoPhillips to drill for oil in the National Petroleum Reserve in Alaska, the nation’s largest untouched expanse of wilderness, miring the energy giant in a larger controversy over government-sponsored oil and gas drilling projects.</li> 
</ul>

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Aggregate sales hit $37.8 trillion last year—an increase of 19%, the highest annual growth rate in the list’s history.

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F500-2022-077-ConocoPhillips

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F500-2021-156-ConocoPhillips

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G500-2020-348-ConocoPhillips

The oil and gas company's 29-spot dip in rankings doesn’t tell the full story, given an enduring period of volatility in the crude market. While sales for the year fell 5%, to $36.7 billion, profits shot up 15% year-over-year, as ConocoPhillips tightened its structure and grew daily production volume by 5%. The Houston-based company generated more than $3 billion from the sales of its U.K. and northern Australia businesses, bringing total cash and short-term investments for the year up to $8.4 billion. The refocusing of its portfolio, as well as disciplined spending, allowed ConocoPhillips to reward shareholders with $1.5 billion in dividends and $3.5 billion in share buybacks.

This year's Fortune 500 marks the 66th running of the list.

F500-2020-093-ConocoPhilips

The oil and gas company's seven-spot dip in rankings doesn’t tell the full story, given an enduring period of volatility in the crude market. While sales for the year fell 5%, to $36.7 billion, profits shot up 15% year-over-year, as ConocoPhillips tightened its structure and grew daily production volume by 5%. The Houston-based company generated more than $3 billion from the sales of its U.K. and northern Australia businesses, bringing total cash and short-term investments for the year up to $8.4 billion. The refocusing of its portfolio, as well as disciplined spending, allowed ConocoPhillips to reward shareholders with $1.5 billion in dividends and $3.5 billion in share buybacks.

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Global business is back. After limping through a worldwide financial crisis and economic slowdown, the 500 largest companies ranked by revenues shattered all sorts of performance records in 2013: They racked up combined revenues of $31.1 trillion, up 2.5% from 2012, and profits soared 27% to nearly $2 trillion. China’s 95 companies (up from 89 last year) posted $5.8 trillion in revenues. The U.S. has four fewer companies on the list than last year but remains (for now) the country leader, with 128 corporations on the list—including No. 1 Wal-Mart Stores—reporting $8.6 trillion in revenues. 

Wal-Mart stayed on top as its sales crept closer to half-a-trillion dollars. Apple moved into the top five. And UnitedHealth Group continued its steady climb. 

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The corporate history of ConocoPhillips traces back to 1875, when early precursors of today’s energy giant transported kerosene by rail to pioneers in the Mountain West. The firm’s current name comes from a 2002 merger between Phillips Petroleum and Conoco. Headquartered in Houston, ConocoPhillips extracts, processes, and transports a variety of fuels, including petroleum, natural gas, and bitumen. The company has operations in more than a dozen countries, with the bulk of its production in the United States, particularly Alaska. Other sites of production include Canada, Norway, Australia, and Southeast Asia.

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ConocoPhillips (COP): Company Profile, Stock Price, News, Rankings

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ConocoPhillips

conocophillips

Welcome to the first quarter 2026 ConocoPhillips earnings conference call. My name is Liz, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. During the question-and-answer session, if you have a question, please press star 11 on your touchtone phone. 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, Strategy and Commercial; Nick Olds, Executive Vice President, Lower 48 and Global HSE; and Kirk Johnson, Executive Vice President, 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 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 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 provides stability in the region. 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 mi 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 four-well exploration program in Alaska, the first in a multi-year 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 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. Amid 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 strengthened 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. 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 objective. 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. 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. 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 BOE 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 BOE 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 for you to model and assess the underlying performance of the company. For production, the midpoint of our annual guidance is updated to 2,310,000 BOE per day.

This reflects a 20,000 BOE per day annual impact due to Qatar being excluded from second quarter production guidance and a 15,000 BOE per day annual royalty rate adjustment at 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 BOE per day, which reflects the full exclusion of Qatar production from guidance for the quarter, the Surmont 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. 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-$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. We expect higher levels of non-operated 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 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. 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 ANS and Dated Brent. Shareholders are directly participating in this upside as we remain committed to returning 45% of our CFO consistent with our long-term track record.

Looking ahead, we remain focused on executing our plan and enhancing our differentiated investment thesis, unmatched portfolio quality, including leading Lower 48 inventory depth, attractive long-cycle investment, strong return on all 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.

Thank you. We will now begin the question-and-answer session. In the interest of time, we ask that you limit yourself to one question. If you have a question, please press star one one on your touch-tone phone. If you wish to be removed from the queue, please press star one one again. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star one one on your touch-tone phone. Our first question comes from Scott Hanold from RBC Capital Markets. Your line is now open.

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

Yeah. 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 can come back and address some of your broader set questions after that.

Thanks, Ryan, and morning, Scott. I'll start with, I think you said this for me. There's certainly a lot of moving pieces out there right now. 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 two 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. The ongoing SPR releases that have been announced, they'll certainly help through the May-July timeframe.

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. If you include the Persian Gulf refineries that, you know, have been damaged, the total global refinery run cuts right now probably amount to around 8 million barrels a day. 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. All of those have reached their destination. You know, the impacts of the lost supply is gonna start to become more apparent. You know, we could possibly see from here now inventory draws really start to accelerate.

You've already seen that governments in over 12 countries are implementing policies to ration or otherwise reduce demand in advance of, you know, physical shortages. You know, given those factors, you know, I've just described, you know, 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. Probably one final point I'd make before sort of passing it off to Ryan is, you know, despite efforts that are ongoing to manage demand, you know, we are gonna start to see some import-dependent countries, you know, potentially start to face critical shortages as we get into the June-July timeframe. I'll probably stop there and let Ryan sort of add sort of a bit more to that.

Yeah. Maybe, Scott, how are people acting? You know, I think people are watching pretty closely to see what happens. Maybe a little bit of short cycle investments. I'm sure that'll come up in our call with the, with the capital. We're just trying to maintain the efficiency gains that we've got in the Lower 48. We won't be drilled out of some of our OBO activity. We're trying to look longer term as well as Andy said, assess the supply and the demand fundamentals. I think at a minimum, we think the floor probably is gonna have to raise up a little bit, at least relative to where we were before the conflict started.

Recall we had a mid-cycle WTI price of about $65, and we believe that's probably going to come up with the floor. We're trying to assess right now, given the demand dynamics and the supply dynamics, what 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. 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. 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. Your line is now open.

Ryan, Andy, great comments there. Definitely our thoughts are with your people in the region. I want to pivot over to Alaska. We went through winter construction season here, so just love a mark to market on how those plans progressed. Where do you stand in terms of Willow construction, and what are the big milestones as we continue to de-risk this project and get to that free cash flow inflection?

Yeah. Good morning, Neil. Thanks for the question. We've had a really strong showing here just in the last six months in Willow. I'll probably address maybe a couple 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 in exploration as well. 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

Yeah, achieving that requires a collection of key milestones that our teams have been able to accomplish and get behind us here. This week's 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. Despite that, again, the teams were able to accomplish the full winter scope. By that, certainly probably most important to us as part of critical path was the civil work. We were able to get all of the bridges down and the entirety of the gravel scope. Think roads, pads, and then even the airstrip.

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, create the compression necessary on that to continue, the structural work that's upcoming then obviously in the construction of future facilities and, and even pipelines. Then as it relates to pipelines, important this year for us to-- was the east-west scope. And, 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 North Slope or Alpine, with those connections just within the coming week, we'll be, we'll be bringing fuel gas in, and we'll be firing up our power for Willow.

Again, we're just been really successful in accomplishing the scope here in Willow that we've laid out as we continue to commission the ops center. 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 sea lift those into Alaska, which becomes the next major milestone for us to get those processing modules up there. Again, all of this in aggregate puts us in just a very strong position for this early oil expectation that we have for 2029, all of that is on track.

That's obviously important as it's underpinning this compelling value proposition that we have for the $7 billion free cash flow inflection. Even thinking well beyond that is exploration. Again, also as you heard from Ryan, we had a strong showing here too. We speak a lot to the four 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. With that came the four wells, but we also shot seismic. We also did quite a bit of gravel exploration and had really high success ratio there on finding gravel for future pads.

When we look at that exploration program, again, as you heard from Ryan, really pleased to report, and by that I mean we found hydrocarbons out there where we were prospecting and drilling. Naturally then our subsurface teams are pouring over the results, seeking to ensure that we can well characterize what we found. Of course, commerciality comes with typically more than one season. That's why we call these exploration and appraisal wells and seasons. It'll 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. You've seen the track record from us in the past and, with the success that we've been realizing just in the last six months, again, just a really strong showing from our Alaska team.

Our next question comes from Betty Jiang from Barclays. Your line is now open.

Hi. Good morning, guys. A lot of eyes 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, Can we just get a bit more color on the decision process from Conoco's perspective to lean into Permian activity now? 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?

Morning, 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. You know, I did cover in the prepared remarks, you know, that we, you know, what we've done here is effectively increased the midpoint of the CapEx by about $250 million. I think it is important sort of to, you know, describe why we're doing that. You know, it is, you know, we keep having the operational efficiency that Nick will talk to. It's important basically the way we think about steady state that we keep that going. On the operated side, it really is just a continuation basically of our steady state, just given how efficient we're being.

On the non-operated side, as I, as I said in our prepared remarks, you know, it's, it's more, you know, in anticipation and starting to see the early signs of this, of, you know, some of our non-operated partners starting to ballot us for more wells. I'd say it's more sort of, you know, the $250 million is more around sort of operationally, setting ourselves up and being thoughtful about, we keep our steady state, and we react to partners versus a, you know, a big sort of, you know, macro call on price. You know, maybe with that, I'll let Nick just give a bit of the specifics on what we're doing, and we can come back to anything you want to cover.

Yep. Thanks, Andy. Good morning, Betty. As Andy mentioned, that $250 million 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. We're adding another Permian rig versus prior plan to help us keep pace with our frack 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 wanna take place, is have any frack 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. On the completion efficiencies, those are outpacing them. Now, if I pivot to the non-operated OBO side, we have started to see more well ballots from our partners, which will likely translate to higher level of OBO spend over the second half of the year. You know, 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. They're good returns. That's the right choice from a returns perspective.

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

Yeah, I would just add, Betty, these are no-brainers. These are does for us. We're not gonna be drilled out of inventory by others, and we're gonna keep our efficient machine running. You know, these are last half of the year. It 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'll continue into 2027.

In the meantime, we'll be assessing what we think mid-cycle price is gonna 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 gonna send back to our shareholder, and what we reinvest for growth and development in the company. That'll be coming later this year, just as part of our normal processes.

Our next question comes from Doug Leggate from Wolfe Research. Your line is now open.

Thanks for taking my questions. Hi, everybody. I guess, Ryan and Andy, I'm looking at slide five and, you know, those of us who've been around long enough, Ryan, remember what you went through in 2016 with the dividend. 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 got 70% upside. My question is that you've stuck to the 45% cash flow payout. Your commitment is actually more than 30%. Clearly, there's a little bit of pro-cyclical stuff going on with the share price. These windfalls can be capitalized in different ways, especially through your dividend policy.

I just wonder if you can walk us through, in these kind of situations, why not flex down in the payout? Why not, you know, think more about the longer-term dividend, the break-even, the balance sheet? Although I'm just curious where your head's 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.

Yeah, 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. You'll see probably us buying more in the second quarter as we go forward. More fundamentally to your question, our 30%, you know, floor is set in a mid-cycle price construct that we start with for the company.

We think about what mid-cycle prices are. We know we're never in a perfect kind of world, but we have to understand that from a supply and demand perspective, so we can understand sort of what cash flows do we generate, what can we give back to the shareholder. Clearly, since we set that coming out of the downturn in 2014 and 2015, when we re-recast the value proposition for the company, you know, it made sense. We've had, you know, mid-cycle price, so the actual price has been higher than our mid-cycle call for most of that time. 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. We think about it through cycle. We try to set a mid-cycle price. We just are constantly trying to drive down the reinvestment rate in the company. We're trying to drive growth for as 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, what Kirk's doing around the rest of the world, and the opportunity we have in our legacy assets.

We've been able to afford something higher than our base, and that represents the 45% commitment that we've made for this year. We recognize that the strength and the power the company is doing. 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 many of us around anymore, Doug. Maybe you and I, that's about it. Look, we wanna make sure that we can sustain the dividend. We wanna 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, something we think is competitive with the S&P 500 top quartile.

That's our commitment to go continue to do that. At the same time, we want to make sure the dividend doesn't get an outsized portion of our cash flows at a mid-cycle price, whatever mid-cycle price we call. We're trying to manage both those things. Typically, the dividend today is certainly affordable, growable, but doesn't represent the full 45%, so we're augmenting that with the share repurchases. We think that makes sense over the long haul. It reduces the absolute burden of the dividend going forward. It might have some pro-cyclic nature to it a little bit, but 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. 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. We try to take a pretty ratable effort to go do that.

Our next question comes from Lloyd Byrne from Jefferies. Your line is now open.

Hey, good morning, Ryan and team. Can we talk about OpEx a little bit? It continues to stand out. If you could just maybe comment on the trajectory from here. Is there anything other than maybe conservatism that keeps you from bringing the full year guide down?

Hey, hey. Morning, Lloyd. Andy here. Yeah, so I think I can take this one in terms of, you know, we did set our budget at $10.2 billion, and that, you know, that was, as a reminder, $400 million lower than last year. As you point out, our 1Q results, you know, were very strong. We're really pleased with them. It's broadly being driven by that we are taking costs, you know, out faster than we'd originally premised from our cost reductions, both on the labor side and on the non-labor side with our lease operating costs.

When we look at it, and Q1 is reinforcing this, you know, we're very confident that we're gonna, you know, hit that $1 billion in run rate savings by the year-end. Really to get, I think to the heart of your question, you know, in terms of guidance, you know, I think it is only the first quarter. We're very, very pleased with how things have gone. We'd, we'd like just a little bit more time before we revisit, you know, whether we would wanna reduce guidance or not.

Our next question comes from Devin McDermott from Morgan Stanley. Your line is now open.

Hey, thanks for taking my question. I wanted to ask on the LNG portfolio outside of the Middle East for just a little bit of additional detail on this EG agreement you signed. You know, 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 that 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 specifically to Equatorial Guinea. I'll let Kirk jump in and maybe share a bit more on that. Yeah, our LNG strategy, on the commercial side, we really couldn't be more pleased with the progress we're making. You know, I think as you say that what's happening in the market right now, you know, our view is that we, you know, we have seen, you know, a structural tightening of global LNG, not just for this year, but for, you know, quite some time, you know, to go.

You'll, you'll recall that, you know, you know, pre all the events in the, in the, in the Middle East, we actually had a bit of a contrarian sort of view versus consensus, where we thought the market was, you know, more in balance, versus sort of a thesis of, you know, a bit of a glut. You know, that's obviously all gone away now. If anything, you know, I think everyone is now sort of seeing sort of the tightening market. As we, as we look at it specifically, you know, where we're in a situation where we've got sort of, you know, first-mover advantage here now where we've, you know, pretty pleased that we put, you know, our 10 million tons that we already have in place.

You know, just like we think about our EMP portfolio, low-cost supply. In this world, low liquefaction costs, you know, are important. We've got that, you know, where, you know, we've already placed the first 5 million tons, you know, predominantly into Europe and a bit into Asia from phase I. 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, you know, the global security element of it as well in terms of sort of the importance of having, you know, positions, on the Gulf Coast and the value of that. You know, that, you know, that's really just played into our strategy, really.

The first-mover event has been very important to us on the commercial side. Probably one last comment before just passing it off to Kirk. It's, you know, we'd be remiss not to also mention sort of the rest of our resource LNG business, outside of commercial with, you know, APLNG and, you know, others where effectively those projects are priced off of long-term contracts linked to Brent for the most part. They're also sort of, you know, doing well in this environment as well. I think the LNG strategy is all proving out very nicely for us, sort of along the lines that we would hoped. Then maybe specific to your Equatorial Guinea question, I'll let Kirk jump in.

Yeah. Morning, 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. The question for us was really about longevity. 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. 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 Alba unit.

Obviously, we have production facilities offshore and then there on the island next to Malabo, the capital. Of course, we have an equity position in EG LNG as well. Our ability then through EG LNG to strike 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. 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.

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

Our next question comes from Arun Jayaram from JPMorgan.

Yeah, thanks for taking my question. 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 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.

Yeah, 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 two months that we've basically had Qatar production shut in terms of not going through the Strait, so that's 20% basically of the LNG sort of that's not flowing. Maybe a better way to put that into context so people can visualize it, that equates to something like 200 cargoes that have not basically sailed. 200 cargoes haven't been delivered.

You know, our view of the macro is that, you know, we, we likely have already seen a little bit of a structural change here where, you know, there's gonna be LNG shortages, you know, for quite some time. You know, when we look at basically where we're at with this is that it's gonna, it's gonna be a situation where, you know, prices are likely gonna be quite constructive for a period of time as, you know, really people are gonna have to, you know, basically bid up price to sort of manage the demand supply piece of this equation.

You know, I think, you know, when you look at what Qatar has, you know, publicly said around, you know, the damage to Ras Laffan, that it's gonna take some time to get that capacity back on the market as well. You know, our in-house view is that we've essentially seen, you know, a bit of a structural change on LNG with all that's happened. You know, it's gonna take quite a long time to basically get anything back close to where we used to be. I think with that, I can let Kirk talk specifically about sort of, you know, our position in NFE and NFS.

The broader macro is one where, I think this is sort of crystallizing to be, you know, a little different to the oil in terms of kind of start to know where we're, where we are with this.

I would add too, Arun, before Kirk jumps in on NFE and NFS, that, you know, we're watching gas inventories in Europe that today are well below where they should be given, you know, the build that they should be experiencing. Really concerned depending on when winter comes across Northern Europe and how hard that winter comes, is the gas gonna 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. Maybe Kirk can talk specifically about Qatar.

Maybe just a few quick clarifying comments, Arun, on how this certainly is affecting us. Naturally, I think all you understand and folks know that our single producing asset there in Qatar is in three. As a run rate, that was roughly 80,000 BOE here last year, so a good run rate. That's roughly 3% of our total company production and very similar on total CFO. Worth clarifying that the remainder of our global portfolio has been largely unaffected, really unaffected by these recent events. It's really been quite contained to just simply this QG3 asset.

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. Also because clearly, as Andy mentioned, with the Strait closed, there's just limited capacity, if any, to lift cargoes there. As QE disclosed, two trains were struck.

Those were not, those were not ours. Again, you know, that took just under 12 MTPA off the market. QatarEnergy has been quite explicit about the fact that they expect that to impact the global market for upwards of 3-5 years. Again, unaffected for us. While it's easy to conflate the construction of NFE and NFS with the operation of those, they're really quite separate. 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 operations.

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. I would say largely, we're expecting the delay to be to the tune of months. You'll also recall, QE guided on a second half of this year's startup. Could be possible certainly that extends into the early part of next year. Again, we chose to simply guide on production for the company on 2Q. Removing that from guidance certainly felt like that was best in terms of clarity for all. 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. Your line is now open.

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

Okay, Bob, it's 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. Maybe I'll describe it from sort of our perspective from ConocoPhillips, and hopefully, that's helpful. I'll let Ryan maybe talk about the other parts of your question. In terms of sort of, I think it might be if I answer your question from the pricing, really from our portfolio perspective, then you can sort of, you can infer from that.

You know, when you think about our portfolio, you know, we're in a situation where about 40% of our crude volume is linked to either Alaska or international price markers. Conveniently, that's split pretty equally between the two. Then specifically to what we're linked to and how the pricing works, you know, the international crude oil volumes, you know, they're mainly linked to Dated Brent pricing, which you've been seeing, we're all, I think everyone's now talking about Dated, dated and ICE like we, you know, haven't done in a long time. You're seeing basically how the Dated Brent basically has been trading at a premium to ICE. More the physical to ICE.

Now on the ANS side of things for us, you know, ANS is effectively priced off of ICE Brent. We basically have a bit of a, you know, of a 50/50 split between the two, but with a lot of Brent leverage. You know, specifically to your question around then, you know, you do see a, you know, a bit of a lag basically in terms of when do you see the cash versus when do you see the earnings, you know, related to these things. You know, you'll see it flow through the earnings first, obviously. You know, with the lag basically in timing of when the cash actually comes in. That, you know, varies basically market to market for us.

You know, you'll start to see the cash more meaningfully come in, you know, a month or so later. That, that hopefully helps explain our exposure to it and maybe helps you understand how the importance of whether we're on Dated or whether we're on ICE. I am gonna take an opportunity while you ask the question, because I think there's another point that sometimes gets lost in all of this this quarter. That, yes, we've got that global exposure, and that's really important. I also wanna just mention on our realizations that, you know, we, we have a large Lower 48 component as well, which is obviously priced off the WTI.

You know, we were really pleased with the realizations we were getting on our WTI. I think we had about a 98% realization this quarter. That might get a bit lost when you look at our total company realization when it all gets mixed together. When you mix it all together, you had three or four things happening. You saw the WTI to Brent diff expand out to about $9 a barrel. Obviously you've got the timing of the sales that we have in places like Norway. It is, you know, it is a pretty complicated set of moving parts right now.

you know, there's going to be some timings between cash and earnings that are going to take a, I don't know, a month or two to sort of all start to line back up.

On your second part, Bob, I assume what you're talking about is the subsurface impacts to shutting. 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. It'll be a wrap-up period, but 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. In some of these, you know, you have to ask here, are they keeping the water flood going while they're shutting in?

If that's the case, they're probably building pressure, and you probably get some flush production. It's probably a very, very high-level answer to your question, but I wouldn't expect a huge supply impact as they bring back on these fields or damage to the subsurface.

Our next question comes from Josh Silverstein from UBS. Your line is now open.

Thanks, everyone. I wanted to get an M&A update from you guys, maybe more from a divestiture angle. You know, I know you guys are very resource-rich, as you mentioned, and you do have an ongoing divestiture program. I was just curious if these non-core assets, are you seeing strengthening valuations for these right now, given the higher pricing? Does it make you wanna be more aggressive in selling assets into this market? Then maybe just an update as to how you're thinking about, you know, the Port Arthur Phase 1, you know, equity stake that you have in there on the divestiture front. Thanks.

Yeah. Morning. I can take that question. You know, probably worth just putting our divestiture program that we've announced sort of in context. You know, we'd announced a $5 billion program, and $3 billion of that's already behind us. There's about $2 billion of the program that's to go. I would really very much put this in sort of the business as usual for us. I think it's, you know, I'll say 'cause I think it's out there in the public markets and being talked about a lot. You know, we do have, you know, a data room open in the Permian right now, and, you know, we've got a couple of, you know, packages in that. You know, this, it's really important when we think about this.

The Permian is not one sort of big thing. You know, it's a, you know, it's a collection of assets within a basin. You know, these are assets that we would consider within the Permian that are, you know, non-core to us, probably something that we wouldn't get to in, you know, in 10, you know, 10-15 years, given the depth of our inventory. Of course, yeah, we are seeing sort of a lot of interest in that. You know, I think it's very important to sort of emphasize, I think our track record will show this, that, you know, we are not gonna be schedule-driven by this. We won't sell anything that we're not getting full value for.

You know, we'll go through a process, and if we get, you know, offers for full value for non-core assets that, you know, we're not gonna develop for a while, we'll certainly take a look at it. It's, you know, it's very much around the edges and just the usual portfolio type cleanup work that we always do. Then to the last part of your question on, you know, Port Arthur Phase I, you know, we're kind of in a perfect situation here where we certainly don't need to sell anything. That asset is being de-risked every day as it comes closer to first production. You know, we'll have that asset online in, you know, in 2027, so, you know, we can't wait to see that happen.

I think everything that's happened in the Middle East has just reemphasized sort of the, you know, the importance of having these secure assets that we have, in our portfolio. You know, maybe a day will come in the future where, you know, it, you know, we get an offer that basically, you know, it fits into sort of a, an infrastructure type investment. We're certainly, you know, under sort of no need to basically sell that asset. I can't really see why we would contemplate that while it's still under construction. We'd rather get it on and, you know, maybe in the future, you know, it, it isn't core, but, nothing there that I would say that we're not happy with.

Our next question comes from Phillip Jungwirth from BMO Capital Markets. Your line is now open.

Thanks. 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 value creation opportunity to add to this liquids-rich position, where others might not have the same technical understanding or operational capabilities? Separately, could Canada at all fit into the LNG offtake strategy if you were to target the high end of 10-15 MTPA?

Yeah. Morning, Phillip. 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. 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. 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 one 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 streams there between NGLs and then condensate and crude. We're able to take advantage within that liquids market of each one of those. 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, you know, we'll be smart about this. If we see there's an opportunity that creates a lot of synergies for us, naturally we'd entertain that.

Then of course, on the gas side, because we are so dominant in the liquids position, this is not a major driver for us. 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 sand. 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.

I would just say our growth plans are certainly dependent on offtake to get very aggressive in the Montney with our own development plans we're gonna need to see a call on those barrels and on that gas and more offtake coming out of BC. 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, you know, we'd be very happy to have a bit more offtake on the West Coast. Just like our E&P portfolio, we know cost of supply, liquefaction fees basically drives everything. You know, as we look at it, you know, if there's competitive liquefaction fees, you know, from expansions that happen and new projects in Canada, we'd certainly wanna take a look at that, just like we'd like to look at, you know, offtake from many other locations. Yeah, you know, I think having some West Coast offtake wouldn't be a bad thing in our portfolio.

ConocoPhillips (COP) Q1 2026 Earnings Call Transcript

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