ConocoPhillips CEO: Scale — and Conventional Oil — Backstop Competitiveness

Under the leadership of CEO Ryan Lance, ConocoPhillips has taken to M&A and organic growth to cement its status as a “superindependent” in both size and scale — characteristics he sees as critical to ensuring long-term viability. Lance has been named Energy Intelligence’s Energy Executive of the Year for 2025 and recently sat down for an exclusive interview. The interview has been edited for length and clarity.

Q: Based on your experience being at ConocoPhillips when it was still an integrated firm and serving as CEO over its entire time as an independent E&P, how would you characterize the evolution of the industry’s competitive landscape and what it means to be an international oil company today?

A: I’m in my 41st year in the business, and to watch the development just over the past 20 years has been really quite remarkable. You know, nothing ever kind of goes away. Don’t bet against the technology and the innovation in this industry. It comes to pass whether you talk about conventional oil, deepwater, the Arctic — and certainly this remarkable journey that we’ve been on in the last 15-20 years in the unconventionals. You think about how it’s revolutionized what we’re doing here in the United States, going from a majority [oil] importer to a majority exporter, the lifting of the crude oil export ban. You watch what technology has done to improve the efficiency in the business. And we’re going back to build a big project in the Arctic after being there for 50 years, discovering Prudhoe Bay back in 1968.

So I think that describes the industry a bit to me: Don’t bet against it. And if you think out to the future, the need’s still there for it — albeit we are going through a transition, and that’s important to the world, but the need for oil and gas and reliable and affordable energy is still there at the forefront. We’ll continue to innovate. Now, you’ve got the additional AI [artificial intelligence] space [and] machine learning, and all that’s happening in the world around us — this industry will use that to take that next leap forward in terms of innovating and driving efficiency through a very mature business.

The macro is only growing at arguably 1% per year, so it’s a low-growth, mature business, but it’s going to be around a long time. So you reflect on the past, and it just looks like more of the same going forward.

Q: How do you find your competitive positioning as such a large E&P when the majors and many national oil companies are also looking to get bigger again?

A: We find it pretty well. You go back to the spin transaction we did in 2012 [of ConocoPhillips’ downstream business into Phillips 66], and I don’t think there’s much regret around that [given] the focus and attention that it brings to the singularly focused upstream business in the E&P space. The integrated majors have done a fine job running refining, petrochemicals and E&P differently. Our experience was that focus and the shareholder reward for spinning the company was certainly there. But there’s a place for the integrated majors as well.

We were a small integrated major. We didn’t have the scale and scope — and that’s what you find in this business, whether you’re refining, petrochemicals or E&P, just to have an appropriate amount of scale in order to be efficient at what you’re doing and be competitive at what you’re doing. So I think what we’ve built is a unique E&P company that has global, diverse scale, and that’s just so important in this business to go forward. That’s why I think we can certainly compete against the integrated majors in the upstream side of their business, and we’re trying to deliver returns on capital employed and total shareholder returns that are not only competitive with our industry but with the S&P 500. That’s where we’re going to attract investors.

So it’s not like I think the integrated model is any better [or worse] than the E&P model, it’s just the scale is so important. We didn’t have the scale as an integrated major. We’ve developed that scale as an E&P. And I think that’s where it matters in the business, and that’s why we can compete.

And look, we benchmark ruthlessly inside the company. Our Canadian operation looks different than our Alaska operation, looks different than our US lower 48 operation — and it should because the benchmarks are different, the competitive landscape is different [in each]. We’re trying to be the best E&P there is in the business, and that means each one of our segments needs to be the best, and you need to have competitive advantage. The competitive advantage in an E&P business like ours is low cost of supply combined with low emissions intensity. So I mean, that’s the winner. I don’t care what scenario you think might be out there going forward [regarding the pace of the energy transition].

Q: Speaking of scale, one way ConocoPhillips and the industry at large have built scale is through consolidation, particularly in US shale. What running room is left for further consolidation, and do you see the objectives evolving?

A: I think they’ll evolve a little bit, but it will be a lot more of the same. Again, scale matters in this business. So if you think about it just very simply, there’s an efficient operating frontier. The best way to describe that is, if I were to cast back four or five years ago, one frack spread could keep up with two rig lines. Today, that ratio is probably 1-4. So we’ve gotten so efficient — efficient in the drilling side, really efficient in the completion technology that’s coming — that if you don’t have the inventory or the capital or the balance sheet to operate in the unconventionals in this efficient frontier, which I would describe as that 1-3 or 1-4 ratio, you’re not going to be competitive. And so that’s why M&A has to happen with these guys, because you’ve got to build scale.

And as you’re fighting significant first-year [natural production] declines in the shale — which everybody has; I’ve got that in my portfolio just like a small independent does — the capital intensity increases over time unless you can offset that with efficiency gains and technology. We’ve done a lot of that, but the implications are that you have to operate in this efficient operating frontier. If you don’t have the scale to do that — it’s scale in terms of inventory, capital, balance sheet capacity to handle the volatility and the commodity. So scale comes in lots of different fashions.

That’s what we’ve been busy trying to do — make sure we’ve got that scale to be really competitive wherever we operate, but it’s really important in the unconventionals, and that’s why it’s going to continue. The pure-play unconventional players are sitting there saying, “You know, I’ve got line of sight on the next two to three years, but I don’t know what the heck I’m going to do in five years because I’m exhausting my inventory, my capital intensity is ratcheting up, and I’ve either got to sacrifice my capital to keep my [shareholder] distributions going, or I’ve got to cut my distributions to keep my capital going.” They clearly face that decision.

And that’s why I think there’s going to be more of the same [in terms of consolidation] because you’ve got to stay relevant. We’re all fighting for the same shareholders in this business. I don’t think you can go ex-growth in this business and be successful. There are periods of time where you might do that because the commodity price demands it, but over the long haul, you need to show a flat-to-growing size as a company.

Q: ConocoPhillips recently announced 20%-25% layoffs and mentioned needing to recapture line of sight on internal cost controls following years of acquisitions. Can you walk through more specifically what the needs and lessons are here?

A: So when you make an announcement, it’s an event, it’s a surprise. But actually it dates back a couple years. Let me explain. We started a journey about three years ago to build a new enterprise-wide resource system in our company. We call it NextGen. We had a 25-year-old single-instance application of SAP [software] that runs our company. It had 130,000 lines of customized code. We embarked a few years back to build a brand-new enterprise-wide system in our company. We went live Jan. 1. We spent hundreds of millions of dollars to build that. We now have a single-instance S/4HANA [database environment], we cleaned up all of our data, we put it into Snowflake [cloud-based data storage], and so we have a clean version of what we’re doing. Now, that was all justified on efficiencies in the business, and it touches a lot of pieces — supply chain, materials management, back office, how we pay our royalty owners and our working-interest owners. It touches everything inside the company. And you combine that then with all the transitions we’ve done over the last four years.

Look, I wasn’t out there looking to buy Marathon [Oil]. The opportunity presented itself, and for various reasons, it became quite compelling inside the company. The combination of that with what we were already doing inside the company — it just accelerated our effort around making sure that we capture the synergy out of the Marathon transaction, and then we do the other things that we’d planned on doing.

So the minute you make the announcement, people make it sound like there’s a fire over there, that all hell is breaking loose, and ask what happened. This is a journey that we’ve been on really for a couple years that culminated to a point where it became significant enough in aggregation that we needed to inform our own employees, obviously, because that transparency is really important, but it’s also material to the market and the company, so we had to come out. But we didn’t just wake up one day and say we need to cut 20%-25% of our employees. We’ve been studying this for a long time — and also watched what other people in the market are doing. You’ve got to be competitive in what you’re doing. The competition is running hard, too, and you’ve got to keep up. It’s not just how much absolute money we’re making — it’s how competitive we are in the business.

Q: Based on your views around the price sensitivity of US tight oil supply, where is the market positioned heading into 2026?

A: When we reset the company back in 2015-16, we went out to the market as an E&P that said, “We’re frustrated with this model. How do you give money back to the shareholders, how do you create a portfolio that can only live on a portion of your cash flow, and you can give some of your cash flow back to the investors right off the top?” We’ve done that, and I think the rest of the E&P business has come our way and recognized that putting every bit of your cash back to the [drill] bit and growing well in excess of what the macro market is growing is really a failed business model going forward. So we feel good that everybody’s gotten the religion, if you will.

So if you apply that now to the efficiencies we’ve gained in the system and the market today, I think it’s a price call. I think at $55-$65 [per barrel] WTI [West Texas Intermediate crude] prices, a lot of industry is moving to Tier 2 acreage in the unconventionals, and you probably are at a plateau-ish kind of number [for US crude oil production]. If you went back to the $70s, you probably get some modest growth. But it’s not going back to a million barrels per day a year of supply growth coming out of the unconventionals; it’s something like a couple hundred thousand, 3- or 400,000 [b/d] — price dependent.

At the kinds of prices we’re seeing today, yeah, I think we would share the macro view of most people that we are probably in a plateau-ish period. And I say that for two reasons: One, as we move to Tier 2 inventory, and second, I don’t think people are going to put in their capital program at the expense of their distributions. It goes back to what we think is the right financial model for the E&P business, whether you’re a private equity company and you’ve got to pay your LPs [limited partners] or whether you’re a publicly traded company and you have to pay your shareholders. But I think that’s healthy for the business.

Q: What will it mean for global oil markets when the US is no longer a growing crude oil producer?

A: Our in-house view is that demand growth is going to continue well into the next decade. It’s probably circa a million b/d of [annual] demand growth — it could be a little bit lower, a little bit higher, but probably not a bad number. So the implications for flat-to-maybe-declining crude oil production out of the US is Opec-plus’ market share moving from the mid-30s% today to probably something over-40% to mid-40s%. So we’re going back to that world where that market share is required. And then it’s going to be: Do they have the spare capacity to do it? Are they investing for that future?

We are underinvesting in the E&P business today, just relative to broad F&D [finding and development spending] numbers against total production. I think actually this year will be one of the lowest investment years we’ve had in a long time other than Covid. So there’s going to be required new investment. And then the question is: What is the cost of supply that you’re bringing on to meet that growing demand? That sets midcycle [crude oil] prices. I think we’re going into a period of rising midcycle prices — and I would have told you 10 years ago we were in a period of declining midcycle prices. I think there is a structural shift coming in the business that you’re going to need $65-$70 cost of supply things coming into the market to satisfy demand, if it continues to grow as we project.

I think it is a growing market share for Opec-plus, but we’re going to be fighting hard on our side with technology, innovation. It’s just physically tough to offset first-year declines in the unconventionals to get absolute growth. It takes a fair amount of investment in inventory to go do that.

We’re fortunate as a company. There are haves and have-nots in the unconventional space, and I think we’re one of the two or three “haves.” We’ve got a deep inventory of Tier 1 unconventionals as a result of all the work we’ve done over the last four to five years. So we’re excited about the opportunity for our company going forward in a relative competitive positioning in the unconventionals.

And then broadly speaking, you step back and you’re going to say, “Where is the conventional oil going to come from to satisfy the growing demand, if shale is peaking to declining?” We’re fortunate: We’d look to places like Alaska and Canada, in terms of what we’re doing. You’re going to look to Brazil, to Guiana [Guyana and Suriname], to Africa, and some of these other places. And the question is: What’s that cost of supply? What does the [oil] price have to be to incentivize that supply?

Q: In terms of conventional supplies, what is your appetite for additional exposure in Alaska given the positive shift in support for oil and gas development under the Trump administration?

A: I would tell you that M&A is a pretty high hurdle for our company because we’ve got over 20 billion barrels [of oil equivalent] of captured resource that has a cost of supply of less than $40 WTI. So our focus is really on the organic side of the business.

Specific to Alaska, it’s no secret that we’ve gone out to the Department of Interior, to the BLM [Bureau of Land Management] to try and permit exploration wells this year out in the NPR-A [National Petroleum Reserve — Alaska] because we’d like to go back to work — something we weren’t allowed pretty much to go do over the previous administration’s term. So we’re excited about the opportunity, and we’re working hand in glove with the regulators to make it so that we can continue to explore and eventually develop, if we have success.

There’s a lot going on around Prudhoe Bay, around Kuparuk and around what we call our western North Slope area, Alpine. We’re continuing to find great opportunities: They’re called Coyote, Nuna, Narwhal, Minke. We’ve seen a new exploration system develop on the North Slope — and again, here’s a 50-year-old basin where we’re finding new deposits of crude oil that’s a different petroleum system than what charged Prudhoe Bay and Kuparak. So that’s what’s exciting about it, and that’s why we’re leaning into some of those opportunities, because we have a current administration that is supportive rather than the last administration that was trying to shut it down.

Q: Given your diverse position in Europe’s gas market across regasification, trading and supply positions, what are your views on the future direction of European gas? Will it fully wean itself off Russian gas? Do you see Russian gas returning if a peace agreement in Ukraine is achieved? How do you weigh your exposure?

A: It’s a large market; they need gas, and obviously, that got accelerated with the Russian invasion of Ukraine. We don’t think that that status stays forever. Do you say that some Russian gas will flow back into Europe? Yeah, it might. I think our base case has a little bit, starting with Arctic LNG. Pipeline gas is going to take a long time — to repair Nord Stream if you’re going to do it, the Ukrainian transit line needs a lot of repair. So does pipeline gas show up? Not for a long time. So yes, I think Europe needs the gas.

We’ve been delivering gas into Europe for a long time from our Norwegian operations. We have a commercial team. We’re in that market every day, so we understand it pretty well. We’re in the pipeline and now we have the aspiration to supply LNG into the European market as well. They need it from an affordability and reliability perspective. I think there’s a genuine interest to try to get off of Russian gas and oil. I think that’s laudable because they’re not a trusted supplier, and I don’t think anyone should trust them as a long-term supplier either. So I think the need is there.

I think the dyslexic nature of it is kind of interesting. I get the sustainability drive that’s going on in Europe, and I think that’s very laudable. But they run counter to themselves in some of the regulations — the CSDDD [Corporate Sustainability Due Diligence Directive], methane. They’re trying to tax the whole world, and they’re just not going to get the gas that they need if they continue to go down this path. They’re making it uncompetitive for their own bloc, so I think there’s a lot of conversation right now on methane and CSDDD.

We believe in the market. We think it’s there. We think it has moved into affordability and reliability being the No. 1 issues, security being really, really important. And I think that’s going to be necessary for them. They’ve got to sort out sort of the balance that they strike between that and some of these other things that are making it much more expensive — and putting rules in place that frankly will eliminate them as an import market, if they go to the full extent of executing the full CSDDD, for instance, and putting in methane regs that just continue to ratchet it up like this. The technology today doesn’t even exist to do what they want to go do. So that’s really slowed the whole thing down. The technology hasn’t kept up with the desire, the aspiration that many of these countries have from a regulatory perspective.

Q: There has been a flood of movement on US LNG in terms of proposed and advancing greenfield projects and brownfield expansions. Does the market have a saturation point for US LNG exposure?

A: I think the people will look at that. I think the uniqueness of the US market is it is distributed geographically across the Gulf Coast, so you can diversify your risk. Now, if you want to diversify your risk away from the United States? There are three big suppliers in the world. There’s Qatar, Australia and the United States. And who would have thought five years ago that Australia would be having export controls and price control conversations? I think people are looking at that.

I think globally some of the consultancies are seeing these slugs of tons of LNG coming in. It’s a 400 million ton [per year] market today that’s growing at 6% compound annual growth. So you’re growing at 25 million-30 million tons/yr. And actually, in our view, of all the projects they forecast coming on line globally over the next four years, a lot of them are slipping to the right. So I don’t doubt anyone that gives a year or six months where you’ve got more supply going into the market than demand, but I think you’re going to chew through that because we’re a 400 million ton market going probably over 700 million tons over the next decade. That’s our view, so that’s why we’re leaning into this business.

Usually the excursions below the [supply-demand balance] equilibrium point are short in duration and short in magnitude. The excursions above that equilibrium point tend to be wide and tall, example being the initial invasion of Ukraine by Russia [driving] $80-$100 per million Btu gas prices over in Europe for a period of time. So we don’t doubt there could be some lumpiness, but long term, we’re excited about the growth opportunities. And I think buyers have diversification opportunities in terms of the locations they’re going to, the suppliers they’re going to.

Will they reach saturation point on “United States?” I think they’re a long way from that.

Q: Today, what is the most fundamental investment case ask on ConocoPhillips and your peers from shareholders?

A. I think investors, thankfully, post-Covid have moved beyond questioning terminal value. That was a big issue coming out of Covid and the whole conversation around the transition, basically telling companies they’re going to disappear off the face of the earth in 10 years. Not a good conversation, a tough one. I think we’ve gotten well beyond that.

There’s probably not one seminal thing they’re looking at, but if I had to rank them, it’s free cash flow that probably tops the list. But I think they’re also worried about what sort of inventory life do you have, and what’s the quality of that inventory, what’s the cost of supply of that inventory? Are you getting capital efficient to deliver more cash flow, and do you have a model that rewards the shareholder appropriately? Now, we give a minimum of 30% of our cash flow off the top back to the shareholder; we don’t give a percentage of free cash flow. We just say, “Look, we’re going to build a company that at a midcycle [oil] price will give you a minimum of 30%.” For the last six years, we’ve been about 45%. We’re going to have a portfolio that we can modestly grow the company on only 70% of our cash flows at a midcycle price. Now, if the midcycle price is going up over time, which we think, then that 30% probably rises just like it has over the last three to four years because prices have been above our call for midcycle prices.

So the complexity in the system right now is that most people are underweight energy, and energy represents 2.5% of the [S&P 500] market right now, so we’re all competing for this small group of shareholders, and how do you differentiate yourself? I think it’s balance-sheet strength, it’s quality and depth of your inventory, and that business model around how much you can sustain back to the shareholder yet still grow your company modestly in the background.

Q: ConocoPhillips has significantly increased its expectations for the resource capture coming from your recently completed acquisition of Marathon. How has this been possible?

A: Yes, we raised the resource estimate by about 25%. I think it’s in two distinct but important buckets. We bought them primarily on the Eagle Ford and Bakken [US shale play] inventory. We were surprised when we dug into some of the Permian and some of the deeper horizons that are turning out to be very competitive on a cost-of-supply basis. I’d say the Permian has surprised us to the upside. It was a smallish position, but one when you combine it and aggregate with ours, we’re able to do more trades with offset operators, we’re able to drill a lot more two and three mile laterals, which lower the cost of supply by about 30% in this business, and the trading we can go do has led to a renewed, fresh, very encouraging look at the Permian.

The second bucket is what we saw in the Eagle Ford and Bakken. Some similarities. We can do more trades, more extended laterals. There’s some refrack potential that we like, primarily in the Eagle Ford assets. But the biggest overrider between those two is, if you look at our plans, if you combine the rigs and frack spreads that we were running and just combine them with the Marathon rigs and frack spreads, we’re essentially able to deliver pro forma production and grow it but eliminate completely the Marathon rigs and fracks. And so that’s again this efficient operating frontier.

Marathon found themselves in a place where at a $70 [WTI] price, they were making about $4 billion. They were investing $2 billion, giving away $2 billion [to shareholders]. The $2 billion investment wasn’t enough to run steady state across the whole course of the year. So they ran like this [demonstrates an up-down cycle]. They’d ramp up in March, ramp down in October, reramp back in March. To do that and show flat production or maybe some slight growth, you’ve really got to pull on the rigs and frack crews, and they weren’t operating in this efficient frontier. Bringing the scale back into our company, we were able to do that. So that’s when it went from kind of an interesting [M&A] opportunity to a pretty compelling opportunity for our company because we saw what we could bring to that.