ConocoPhillips (NYSE:COP) Q3 2023 Earnings Call Transcript

ConocoPhillips (NYSE:COP) Q3 2023 Earnings Call Transcript November 2, 2023

ConocoPhillips beats earnings expectations. Reported EPS is $2.33, expectations were $2.04.

Operator: Welcome to the Third Quarter 2023 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 Phil Gresh, Vice President, Investor Relations. Sir, you may begin.

Philip Gresh: Yes. Thank you, and welcome to everyone, to our third quarter 2023 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; and Tim Leach, Adviser to the CEO; Bill Bullock, Executive Vice President and Chief Financial Officer; Dominic Macklon, Executive Vice President of Strategy, Sustainability and Technology; Nick Olds, Executive Vice President of Lower 48; Andy O’Brien, Senior Vice President of Global Operations; Kirk Johnson, Senior Vice President, Lower 48, Assets and Operations; and Will Giraud, Senior Vice President, Corporate Planning and Development. Brian and Bill will kick it off with opening remarks, after which the team will be available for your questions.

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. And before I turn it over, I just want to flag for today, we’ll do one question per caller. So with that, let me turn it over to Ryan.

Ryan Lance: Thank you, Phil, and thank you to everyone for joining our third quarter 2023 earnings conference call. It was another solid quarter for ConocoPhillips, as the team continued to deliver strong underlying performance across the portfolio, and we have achieved several additional project milestones in our international portfolio in early October. Now before I get into the details, I wanted to address the topical news in the industry, which has been the M&A headlines in recent weeks. This is not a surprise to us. We have long said that we expect to see further industry consolidation. ConocoPhillips remains steadfast in our returns-focused value proposition and cost of supply principles, which creates a high bar for M&A.

And as a reminder, we’ve been actively high grading our own portfolio over the past several years. And as a recent example, we are pleased to have closed on the acquisition of the remaining 50% of Surmont, in early October. An opportunity came along to acquire this asset at a very attractive price that fit our financial framework, an asset we can make better through our full ownership and an acquisition that makes our 10-year plan even better. Surmont is a long life, low declining and low capital intensity asset that we know well. We achieved first steam from Pad 267 in the third quarter, and production is expected to start up in the first quarter of 2024. This is our first new pad addition since 2016, and as we said at our recent analyst meeting, we can leverage existing infrastructure to add additional pads with very limited capital requirements in the years ahead.

Now moving to global LNG. We’ve also continued to progress our strategy, securing 1.5 mtpa regas capacity at the Gate LNG terminal in the Netherlands. This will take our total European regas capacity to 4.3 mtpa. We have now effectively secured destinations for nearly half of our Port Arthur LNG offtake commitment in the first 6 months. since we sanctioned the project. Now elsewhere in the international portfolio, we started up our second central processing facility, CPF2 in the Montney. And in Norway, we just announced that we have started up 3 project developments ahead of schedule in October. This includes the company-operated Tommeliten Alpha A, subsea tieback project at Ekofisk, which is nearly 6 months earlier than originally planned as well as 2 nonoperated projects.

Finally, in China, our partner started at Bohai Phase 4b ahead of schedule, in October. So as you can see, our diversified international portfolio continues to be a strong differentiator for our company. Shifting to results. We have record global and Lower 48 production in the third quarter, and we raised our full year production guidance to account for the closing of the Surmont acquisition, all this while achieving continued capital efficiency improvements as our full year capital guidance remains unchanged. We also continued to deliver on our returns to our shareholders. We increased our quarterly ordinary dividend by 14%, consistent with our long-term objective to deliver top quartile increases relative to the S&P 500. We have distributed $8.5 billion in dividends and buybacks year-to-date, and we remain on track for our $11 billion full year target.

And we did this while funding the shorter and longer-term organic capital growth opportunities that we see across the entire portfolio. The team continues to execute well. Our deep durable and diversified asset base continues to get better and better, and we are well positioned to generate competitive returns, and cash flow for decades to come. Now let me turn the call over to Bill to cover our third quarter performance in more detail.

William Bullock: Thanks, Ryan. In the third quarter, we generated $2.16 per share in adjusted earnings. We produced 1,806,000 barrels of oil equivalent per day, representing 3% underlying growth year-over-year. Planned turnarounds were successfully completed in Norway and Alaska and Lower 48 production averaged 1,083,000 barrels a day equivalent per day, including 722,000 from the Permian, 232,000 from the Eagle Ford, and 111,000 from the Bakken. Lower 48 underlying production grew 8% year-on-year with new wells online and strong well performance relative to our expectations. Moving to cash flows. Third quarter CFO was $5.5 billion, including APLNG distributions of $442 million. Third quarter capital expenditures were $2.5 billion which included $360 million for longer cycle projects.

And through the end of the third quarter, we have now funded $875 million for Port Arthur LNG, out of our planned $1.1 billion for the year. Regarding returns of capital, we delivered $2.6 billion to shareholders in the third quarter. This was via $1.3 billion in share buybacks and $1.3 billion in ordinary dividends and VROC payments. And today, as Ryan said, we announced an increase to our organic dividend of 14% to $0.58 per share. We ended the quarter with cash and short-term investments of $9.7 billion, which included proceeds from the $2.7 billion of long-term debt that we issued to fund the Surmont acquisition, which closed in early October. Before shifting to guidance, I do want to take a quick moment to update about our VROC. Beginning in 2024, we will be aligning both the announcement timing and subsequent payment of our VROC with our ordinary dividend.

Therefore, you can expect us to provide details on our first quarter VROC payment on the fourth quarter call in February. Now turning to guidance, which now reflects additional 50% of Surmont starting in early October, we forecast fourth quarter production to be in a range of 1.86 million to 1.9 million barrels of oil equivalent per day. Full year production guidance is now roughly 1.82 million barrels of oil equivalent today. Now to put this production guidance in the context, we expect underlying growth for both the fourth quarter and the full year to be roughly 4% year-over-year, which includes Lower 48 production growth of roughly 7%. And this is very consistent with our full year guidance and our long-term plan we laid out at our Analyst and Investor Meeting.

For APLNG, we expect distributions of $300 million in the fourth quarter and $1.9 billion for the full year. And while APLNG distributions can vary quarter-to-quarter, a normalized run rate to think about moving forward is around $400 million per quarter at current price levels. Shifting to adjusted operating costs. We raised our full year guidance by $300 million to $8.6 billion. This was driven by our increased working interest in Surmont, increased Lower 48 non-operated activity and inflationary impacts on the Lower 48. We’ve also raised our DD&A guidance by $100 million to $8.3 billion, which is also primarily due to Surmont. And full year adjusted corporate net loss guidance remains unchanged at roughly $800 million, and the second half run rate is a good starting point for 2024.

Finally, our full year capital spending guidance range is also unchanged. So to wrap up, we had another solid operational quarter. We continued to deliver on our strategic initiatives across our diverse portfolio, and we remain highly competitive on our shareholder distributions. That concludes our prepared remarks. I’ll now turn it back over to the operator to start the Q&A.

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Q&A Session

Operator: [Operator Instructions]. Our first question comes from the line of Neil Mehta with Goldman Sachs.

Neil Mehta: There’s been a lot of variability in Lower 48 results from some of your competitors, and you guys have been very steady tracking at the 7% growth rate. Just love your perspective and walking through the basins and particularly the Permian, what is working, what’s not for you, guys? And how do you feel about the plan as you move into 2024?

Nicholas Olds: Yes, Neil, this is Nick. You’re right. I mean, overall, if you look at our performance across all of our basins, it’s been strong, and in line with prior year performance across, again, all those Lower 48 assets. I’d also mention that it’s been in line with our type curve expectations. I’ll call out, for example, Delaware well performance is showing top quartile on volumes produced, not only on a barrel of oil per basis, but also on a BOE per basis per foot. So we’re seeing very encouraging results there. I think the key point, too, is the strong performance reinforces our strong focus on returns, capital-efficient environment that we’ve set there.

Ryan Lance: And I would add, Neil, it speaks again to the quality and the depth of the inventory in the company. We’ve got, we’re prosecuting some of the best acreage in the basin and doing it in such a way that’s focused on capital efficiency and returns, as Nick described.

Operator: Our next question comes from the line of John Royall with JPMorgan.

John Royall: You’ve had a handful of international project start-ups that you touched on in the release. If you could give us some more color on these projects, that would be helpful. And maybe if you could tie that into a growth outlook for the international business in ’24 as well, that would be helpful.

Andrew O’Brien: John, this is Andy. I can take that one. It’s a little early to be getting into full year guidance for 2024. As you mentioned, we have had some pretty good news across our Alaskan international projects. So we’ve made some pretty significant progress across the portfolio, and it really is nice to see so many of those projects achieved major milestones on or ahead of schedule and budget. Ryan touched on Norway, where there we achieved first production ahead of schedule on 3 of our 4 subsea tiebacks. And we expect the fourth one to come online as planned in Q2 ’24. So we expect those 4 projects in aggregate to add about 20,000 barrels a day of production next year, which should more than offset normal decline in ’24.

We also had some good news in China where our partner-operated Bohai Phase 4b achieved first production ahead of schedule from the first platform. Now that’s going to be 2 platforms tied back to a central processing facility, and we’d expect the second platform to come on in the first quarter. And then with that, we’ll then have the opportunity to drill new wells in Bohai for the next 4 to 5 years. And then we also had some pretty big major milestones in Canada with CPF2 in the Montney and Pad 267 in Surmont. So CPF2 has successfully started up in September, and that’s going to add to about 100 million cubic feet a day of gas processing, and about 30,000 barrels of condensate, above handling capacity. So in the Montney, we averaged about 20,000 barrels of production in Q3, and we’re going to substantially grow that next year.

And then finally, with Surmont Pad 267, we achieved first steam in September, and we’ll get first half in early ’24. Now with 267 online, we’d expect to see Surmont grow — something 5,000 and 10,000 barrels a day next year. And importantly, that’s inclusive of a month-long turnaround that we conduct every 5 years and somewhat. So I’m really proud of what we’re doing and executing across these projects. And I think all this is a really sort of example of how we leverage our existing infrastructure to deliver on our low cost of supply opportunities. So hopefully that gives you a feel for sort of the momentum we’re building going into next year.

Operator: Our next question comes from the line of Steve Richardson with Evercore ISI.

Stephen Richardson: Bill, I was wondering if maybe you could help us on a little bit of broad strokes on 2024, CapEx thoughts. I think in the past, you’ve talked about kind of flattish CapEx around $11 billion, with admitting, there’s a lot of moving parts in an M&A environment. Maybe you could just talk a little bit about that as you’re thinking forward.

Dominic Macklon: Yes, it’s Dominic. Stephen. What we’d say is very consistent with the AIM framework we laid out on CapEx. Just to recap the moving parts. We’ve got several moving pieces. We got — assuming Willow is sanctioned, which we expect spending on that project will be higher. And then, of course, you have the incremental $100 million or so for the other 50% of the term of the Surmont that we’re adding. And those increases will be mostly offset by, we’re going to see lower spending on our LNG projects and roll off of the project capital at Norway. So but I think the key message there is really very much in line with the framework we laid out at AIM. Of course, you do have the addition of Surmont to extra 50% there.

Operator: Our next question comes from the line of Doug Leggate with Bank of America.

Doug Leggate: Although Phil has gone to the dark side with the one question…

Ryan Lance: One man’s opinion, Doug.

Doug Leggate: If I may, I’d like to make one comment and ask one question. My one comment is your stock’s up almost 5% this morning. I think acknowledging your dividend move — ordinary dividend move is gaining recognition in the market. And congratulations on taking that step. We’d like to see more of it. Okay. With that, my question is simply this. One of my peers asked a question earlier about performance in the Permian. I thought I’d like to ask it a little differently, one of your very large peers had some nonoperated portfolio problems in the quarter. You guys have got a large part of your production that comes from nonoperated production. Is there any discernible difference between your operated performance and your nonoperated performance that’s driven this reliable production growth year-over-year.

Ryan Lance: Yes. So I can’t resist but to comment on your comment, Doug, and then I’ll let Nick answer a question on the Lower 48. But it’s exactly what we thought should happen with top quartile targeted dividend growth as a company relative to the S&P 500. So that’s been our plan, and we’re sticking to it and executing on that plan. But yes, I can let Nick comment on your question about — open up in the Permian.

Nicholas Olds: Yes, Doug, good question. I mean, I think you’re looking at the Q2 to Q3 performance this year, we were up 2%, so sequential growth. And as Bill mentioned in his prepared remarks, we’re seeing 7% year-over-year. Obviously, that has a combination of our operated and nonoperated portfolio. Both are performing well. Specifically, Doug, in Q2 to Q3, a large component of that increase was our operated Permian program, as well as OBO. So we’re seeing increases in the operated by others, and a little bit of Bakken as well. I mean we — these operated by other assets are very competitive. We look at every ballot. We benchmark each one, and it performs well within our cost supply framework. As a reminder, if you look at Permian in general, about 30% of our production is coming from operated by other, within the Permian.

And if I take you back a little bit in time to the Analyst Investor Day, when you think about the split between the 2 basins, we’ve got 2/3 of our inventories in the Delaware, 1/3 in the Midland Basin to generate the full Lower 48 of 5%. But bottom line, Doug, is that they’re both competing well. We will review every ballot to make sure we’re investing the right capital and drive that capital efficiency.

Operator: Our next question comes from the line of Lloyd Byrne with Jefferies.

Francis Byrne: Ryan, you mentioned it in your prepared remarks, but I’m hoping you could comment further on international gas integration strategy. And I recognize it’s early, but by our numbers, there seems like a lot of option value there. So maybe just thought process behind it and maybe any targets you might have to help us think about the future there.

Ryan Lance: Yes, I can let Bill give you some details there, Lloyd. But yes, we’re excited about the opportunity to add the regas capacity in the Netherlands at the Gate LNG, complements well our German edition, and we’re looking elsewhere as we try to build out and move the Port Arthur volumes and the volumes we have in other places around the globe into that market, which we think is going to be a strong market for many decades to come, which is why we’re moving into this. I can — Bill can be a bit more specific to your question on the details there.

William Bullock: Yes. I’m happy to put a bit more color on that. So we’re very focused on developing market. And as we’ve talked about, we want to do this in a stair-step fashion with how we originate supply. You’ve seen us announce Port Arthur LNG and LNG. We’re making really strong progress at 2.8 million tonnes per annum of regas capacity at German LNG, 2 of that is dedicated to supporting our LNG out of Qatar that leaves 0.8 at Germany. We just added 1.5 million tonnes of regas capacity at Gate. So that’s 2.3, that’s roughly half of Port Arthur. And I think importantly, we’re continuing to see a lot of interest and strong demand for LNG. As we’ve talked, we’re looking to develop a diversified portfolio that’s both sales into Europe and also sales into Asia, perhaps some FOB sales at the facility and having a mix of variety of term links in that.

And so I’m just — I’m really pleased with the progress we’re making within 6 months of kind of FID on Port Arthur, we’ve got roughly half of it placed. And I think the way to think about that, just going back to the vignette, I showed at AIM is, you look at the capacity that we have into Germany and the TTF, the way to think about that as you’re modeling returns as you start with the Henry Hub price, you add liquefaction tools shipping and regas, you compare that to what you think European gas price will be. That’s going to give you your base CFO for volumes into Europe before adding any diversion optionality on to that. You can do a similar type analysis going to Asia. So yes, we share your view here that these are very interesting additions to our portfolio, and we’re really pleased with the progress we’re making.

Operator: Our next question comes from the line of Devin McDermott with Morgan Stanley.

Devin McDermott: So I want to echo the earlier comment on the dividend raise and ask a question on the shareholder return. So it’s good to see the 14% increase. I was wondering if this large change in the dividend is more tied to incremental cash flow on Surmont, or there’s been a broader change in how you’re thinking about the target payout, or dividend breakeven as you look out at the business over the next few years? And just as part of that. Maybe you can give us an update on your broader thinking on shareholder return strategy and the breakdown of dividend VROC and buybacks in the context of dividends increase.

Ryan Lance: Yes. No, I don’t think anything has changed in our framework, which we outlined, I think, pretty extensively in our last analyst meeting. So based on our mid-cycle price call, you can expect us to deliver at least 30% of our cash flow back to our shareholders. And then we’ve said, when the prices are in excess of our mid-cycle price call, which is where the prices are today and where they’ve been over the last few years, you should expect us to be delivering more of our cash back. And that’s, in fact, what we’ve done over the last 5 to 6 years, delivered mid-40%, 45% or so of our cash, has gone back to our shareholders. And it’s done that in a form of both the cash and buying our shares back. So our construct around that really hasn’t changed.

We like to provide an affordable, reliable ordinary dividend that grows competitive with the top quartile, the S&P 500 over time. We’d like to buy some of our shares back through the cycle in a mid-cycle construct, and then we introduced the third leg VROC to add additional return back to our shareholders when prices are above our mid-cycle price call. So that’s the construct we have and as we — and we’re sticking to that. We think it’s served the company pretty well and it provides — like this year, we expect cash flow of close to $22 billion, and we’re giving half of that back to our shareholders. So it’s probably not a bad starting point for next year.

Operator: Our next question comes from the line of Nitin Kumar with Mizuho.

Nitin Kumar: I guess just sticking with the theme of M&A and I appreciate, Ryan, you touched on it in your comments. But one of your peers out there has talked about improving recoveries in the Permian to the tune of 20% or higher than everybody else. You operate across the entire Permian Basin. I’m curious, are you deploying or seeing others deploy technologies that you think can improve recovery rates that significantly?

Ryan Lance: Yes. I’ll let Nick respond to that specifically. And I guess I’d make this one broad comment is, I think as we talk about this topic, I think in the companies and a lot of people are guilty of this inflation a bit, between recovery and recovery rate or recovery factor. So I think you have to be really careful when we talk about this, in light of these unconventionals, we’re doing everything we can to improve the recovery that we get from the wells, the acreage, the blocks, the layers that we have within our portfolio. And — but be careful not to conflate that to recovery factor or a recovery rate. And I can have Nick speak a bit more specifically about the things we’re doing to make sure we get maximum recovery out of our assets.

Nicholas Olds: Thanks, Ryan. Yes, in our asset teams, as Ryan mentioned, are very focused on optimizing the recovery of our wells and our development projects across all of Lower 48 assets. I think it’s important, too, is we seek to maximize recovery but also driving improvement in capital, and that’s part of our returns-focused strategy and the cost supply framework that we judge every decision against. We look at kind of improving recovery across kind of 3 primary buckets, so I’ll take you through that, what we’re looking at what we’re deploying within our assets. So first, we look at development decisions, we used our first bucket. Secondly, is how do we optimize the reservoir, and that’s our second bucket. And then the third one is really, when we look at enhanced oil recovery, but that’s more longer term.

Now, then one of the things that we obviously have within the Permian, and we mentioned this at the Analyst Investor Day, is that we have 2 decades of inventory within the Permian at current rig activities level. So we have a lot of focus on development decisions and the reservoir optimization to improve recovery. A couple of things. Well, lateral length is critical. We speak to about the inventory length, more you can go from a 1 lateral to a 2 to a 3-mile lateral. You increase the recovery per well. And as we’ve mentioned before, you go from a 1 to 3, we improve our cost of supply, which drives capital efficiency by 30% to 40%. So we’re doing that. As a reminder, we’ve got 80% of our Permian well inventory is 1.5 miles or greater, and 60% is 2 miles or greater, and we’re continuing to execute 3-mile laterals year-to-year growth on those as well.

On the well completion side, again, this still sits in that development decision bucket. We’re doing some interesting work in the Bakken, as an example, using multi-varied analysis where we optimize completion design to maximize both recovery and capital efficiency and seeing recent completion results that are very favorable in that space. And then the kind of the last item I’ll address on the development decision is around spacing and stacking. One thing that we do out in the Midland Basin that you’ve heard here recently is co-development. Co-development allows us to minimize the parent-child impacts, while improving recovery as well as capital efficiency. And we’ve demonstrated over the last 4 years, both in the Midland Basin, as well as the Delaware Basin around improved performance there.

On the second component that we’re focusing in, on reservoir optimization, I’ll draw you to — your attention to Eagle Ford. We’re using kind of techniques where we refrack these wells, kind of late life in the wells. And we’re seeing improved well performance on expected ultimate recovery by 60%, which is very competitive in our cost supply framework. And then I’ll take you up to the Bakken. We’re using infill wells and upcoming edge wells to further increase overall recovery, and these are also a competitive cost of supply. Again, that’s increasing the recovery per pad. And then the final bucket, that enhanced oil recovery component, where we’ve done many pilot studies, mainly in the Eagle Ford, around gas injection, huff-and-puff. And we’ve seen technical success.

We’ve seen injectivity and the corresponding oil response. But I’ll leave you with this on the enhanced oil recovery, these projects don’t compete within our expansive drill 1 inventory at this point in time. We’ll continue to study it and analyze it, and that’s something we can address in the future. So from long laterals to improve completion design to infill wells, we’re improving recovery in our assets.

Operator: Our next question comes from the line of Roger Read with Wells Fargo.

Roger Read: A lot of this has been hit. But I guess I’ll just ask about Alaska. There has been a little more noise up there on the — I don’t know if you call it, regulatory, legislative side, and then we’re about to head into the winter season. So I’m just curious, Willow and other things, what’s going on there.

Andrew O’Brien: Roger, this is Andy. So yes, let me take that one. I’ll start with the legal and then we’ll give you a bit of an update on where we are with the project. So on the legal side, I talked about this on previous calls, there are lawsuits challenging the federal government’s approval of the project. As I mentioned on the last call, we expect to see a ruling on this in November. The preliminary rulings in April were favorable and then the upcoming ruling will address the full scope of the legal challenge. Again, I’m repeating myself a little here, but as I said on the last call, we’re very happy with how the BLM and competing agencies conducted the process, and satisfied all the requirements to grant their approval.

So we’re confident, and we’re looking forward to those court rulings in November as we get ready for the 24 season. And then I think the other part of the legal question you were alluding to is the, separately, in September, the Department of Interior proposed additional regulations for the management and protection of the NPRA. And we don’t expect these draft rules to impact Willow or prevent our exploration program. It doesn’t have any impact on the 10-year plan we’ve previously laid out at AIM. But that said, we are concerned if the rules are adopted as currently drafted, they could impact future developments beyond Willow, in the National Petroleum Reserve Alaska. So the way to be providing feedback to the Department of Interior to try and make the proposed rules more consistent with the existing statute.

And again, I’ll just finish the legal bit with — as a reminder, the statute recognizes the primary purpose of the NPRA is to increase domestic oil supply. So that’s kind of where we are on the legal side. And then just very quickly where we are in terms of the project. Taking a step back here, as I described back at our investor update, Willow, is the kind of project that’s right in our wheelhouse. We’ve got no first-of-the-kind type risk here. It’s 3 drill sites to 1 new processing facility. And our track record and our [indiscernible] of excellence in delivering on schedule and on budget. But specifically to where we are right now, work is progressing well, and our 2023 capital is fully factored into the total company guidance we gave today.

We started the first phase of module fabrication on the Gulf Coast. And then on the North Slope, we’ve successfully opened the gravel mine, and we’re preparing for the 24th construction season. We’ve already got over half of the project scope under firm contract. And these contracts include clauses if we don’t FID the project that we can exit. Now all the contracts we’ve issued today, 75% from a lump sum or unit rate for these type of contracts, we have a greater price and now have limited exposure to future inflation. So as we continue the contract negotiations, our estimate of capital to first production remains unchanged at $7 billion to $7.5 billion that we previously provided. So I think that probably gives you a good update on where we are on the legal and on the project side of things.

Operator: Our next question comes from the line of Ryan Todd with Piper Sandler.

Ryan Todd: Maybe one for you, Ryan, you’ve been on you’ve been busy on the portfolio over the last few years across a wide range of regions and types of assets across the portfolio. As you — and some of that is obviously opportunistic just when the timing of things like Surmont and APLNG came up. But if you take a step back now and look, is there still more to do on the portfolio, in terms of portfolio management? Are there increased high-grading opportunities on the divestiture side that we should expect, as you continue to develop things, or any places that you would like to change or increase your exposure, maybe as you look going forward down the line in terms of long-term competitiveness.

Ryan Lance: Yes, Ryan. No, I think as we tried to show you at the Analyst Meeting earlier this year, we’re pretty pleased with all the efforts we’ve made in the company over the last 4 to 5 years to really, what we think has put out an extremely compelling 10-year plan. So I wouldn’t describe the — really, really like where the portfolio has gotten to. It’s got a — it’s global, it’s diverse. It’s got a great mix, a short-, medium- and longer-cycle opportunities organically to invest in. All those investments lead to 20 billion barrels, less than $40 cost of supply. So we’ve got a lot of visibility into what we think is a great plan. We’re ruthless high graders of the portfolio. If some doesn’t compete, we’re looking for opportunities moving out.

I wouldn’t describe we’ve got anything significant inside the portfolio today that would fall into that category. And we’re always looking and trying to be opportunistic, which I think describes to your point, the APLNG ROFR and the Surmont ROFR that we hold. So you never quite know when your partners make a change that you didn’t anticipate, and you get a great opportunity to acquire an asset that you know really well. And the one that we know we can make better if we have it under our control, and ultimately, as I said, it makes our 10-year plan better. So we’re always out looking to find — because you never quite know when these things might materialize, but we tend to be very opportunistic. And I just remind people, our framework is intact.

It has to meet our financial framework. We got to see a way clear to make the asset better, and does it make that 10-year plan that we think is quite compelling, does it make that 10-year plan better, which is a pretty high hurdle inside the company.

Operator: Our next question comes from the line of Paul Cheng with Scotiabank.

Paul Cheng: Can you hear me?

Ryan Lance: Yes, we sure can, Paul.

Paul Cheng: If I can go back into Permian. What’s your average lateral length now? And then how much do you think you can improve or lengthen it over the next several years? Is that the — one of the primary contributor that you think you could improve the result in your OBO, Permian operation. And also that, whether you guys have tested because at some point, I would imagine it will reach this economy of scale when you get longer and longer. Do you have any experiment that you guys have done that, what that limit may be? Is it 4 miles? Is it longer than 4 miles or less than 4 miles?

Ryan Lance: Yes. Thanks, Paul. I can let Nick kind of weigh in on some of that. We’re not, yes, I think lateral length is just one of the things that we’re working on. Nick described a bunch more on an earlier question around completion efficiency and how we’re attacking the spacing and the stacking. So I think it’s all of those things that we’re trying to attack, and they’re different depending on where you’re at in the Bakken, the Eagle Ford or the Permian. But we have deep experience in all 3 of those basins and using all that knowledge to make sure we’re maximizing the recovery and minimizing the cost of supply, and maximizing the efficiency that we’re getting out of it, specifically on lateral lengths, I can let Nick weigh in on that.

Nicholas Olds: Yes, Paul. Just to reiterate, again, we’ve got a significant deep and broad, long lateral inventory across the assets. Just mentioned previously, the 80% of Permian inventory is 1.5 miles or greater, and the 60% greater than 2 miles, and we continue to see more and more 3-mile laterals and are very — we’re seeing good results coming out of the 3-mile laterals, both from our 2022 program, as well as 2023. So we continue to see increases in that space. Our teams continue from a BD standpoint and a land standpoint, look at core opportunities. And this is not only in the Permian. But as Ryan just mentioned in the Bakken, we just finished up some trades there to allow us to drill some 3-mile laterals in the future.

So we’re increasing the portfolio of long laterals across all 4 assets. The thing that you had talked about related to how far can you go, I’ll just step back, the 3-mile laterals that we’re seeing over the last couple of years are performing well. We’re very encouraged with the results. You want to make sure you get contribution across that entire lateral length. As we would think about going further longer lateral lengths, I think you mentioned 4 miles, there’s a trade-off. You can potentially drive down and improve cost of supply. And then also, you have to look through the lens of operational risk, because that operational risk is also, oddly, in development drilling, actually drilling the well, but also future workovers. And so we’re looking at that in the future, but I’ll leave you with the fact that the 3-mile laterals performed extremely well, and we’ve got a very deep inventory of long laterals, as I mentioned earlier.

Operator: Our next question comes from the line of Josh Silverstein with UBS.

Joshua Silverstein: Ryan, I appreciate the comments before on the return to capital thoughts for next year. I was curious with the added debt from the Surmont transaction, how you might think of additional shareholder returns versus this year or that want to build cash, or pay down the debt there.

Ryan Lance: Yes, I think we’re in that planning process as we kind of think about next year and all those moving pieces. So I say it looks to me like at this 10 seconds, commodity prices are kind of very similar to where we were coming out at the end of last year coming into the beginning of 2023. So I think that framework around total return as a starting point is pretty good for 2024. We’ll just have to see what commodity prices are as we go forward. And we have a plan, and Bill can address that, to kind of pay off the pay off debt as it comes due over the next few years. That gets us down to our original target of $15 billion in gross debt, and we can continue to do that. And I think if we had a very large up cycle to the price commodity price, we might look at adding more cash to the balance sheet as well. So I think all 3 of those are in play as we think about, what we do over the course of each quarter as we go into next year.

Operator: Our next question comes from the line of Sam Margolin with Wolfe Research.

Sam Margolin: I guess I wanted to ask for an update maybe on the Venezuela process. It’s come up in prior calls and the process is advancing. And I guess, specifically, I want to ask about a scenario where the assets that aren’t strategic to you get returned or surrendered to creditors, and what might be the path forward from there because it’s a large claim, and it’s material. And it seems like it will be a good outcome for you, but might require some actions in the aftermath.

Timothy Leach: Yes. Sure, Andrew. It’s Tim. But yes, we’re in a process with the Venezuelans right now. They also have a considerable amount of money through both our or ICSID and our ICC claims, approaching over $8 billion. They own some, on the full judgment on the ICC, they still owe us $1.4 billion, $1.5 billion. So we’re pursuing that pretty aggressively. I think we’re watching the progress closely. Clearly, the U.S. government has provided a lifting of some, if not all, of the sanctions here, waiting on results of what the Venezuelans do on the other end for free and fair election. So that may create a bit of an opening. But this is a long process, but we’re pretty committed to doing everything we can to make sure we get our money out of Venezuelans that they owe us. And that’s what we’re focused on.

Operator: Our next question comes from the line of Neal Dingmann with Truist Securities.

Neal Dingmann: My question, you get on this a little bit, just on M&A specifically, why I appreciate your earlier comments about any assets needing in the 10-year plan. I’m just wondering, is there a preference for, when you’re seeing things shorter longer-term cycle assets? And just also curious on how you view valuations of some of the recent public deals.

Ryan Lance: Well, certainly, the way we look at it, Neal, is we like a global, we like a diverse portfolio. We like it to be balanced. I think we’re mostly focused on what’s the cost of supply to make sure it fits our framework around that, and that any asset that you bring into the company, make sure it compete for capital on an ongoing basis against a pretty rich, deep, durable, long life and a lot of inventory sitting in the company today. So as I said, it’s a pretty high bar. I don’t know quite how to comment on the recent deals that have been done. Those are transactions. Those are really good companies that were bought. Clearly, they have good assets. we’re pretty familiar with them. We’ve watched them for a long period of time, and they’re good companies with good assets. Transactions were, in a part of the cycle that’s, little frothy and probably at a higher mid-cycle price than we would ascribe to them, I guess. Maybe that’s all I should probably say.

Operator: Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold: I was just kind of curious, does consolidation that creates larger peers in the Permian impact the competitiveness of comps development and positioning. Specifically, if you look at services and midstream capacity, as you kind of move forward on your — kind of 7% growth CAGR over the next decade plus?

Ryan Lance: I don’t think we see a huge issue there at all, Scott. There’s a lot of operators already in the Permian Basin. And it seems like the service side of the business has been accommodating all the activity that we have out there. There’s been periods of tightness on certain categories. There’s been, there are certain services that, by and large, we don’t think it’s going to be a big issue for us going forward. The advantage of being one of those large operators in the basin is, you get the attention of the service companies because they know you’ve got a program that’s durable. I know you got a program that has some link to it. They know you’re not going to be whipsawing them around. And those are the kind of customers that they want to work for. And then those are the — so they tend to work with us, and so we don’t see any exposure to the current consolidation trend in the Permian, and it’s going to continue. No questions. So more probably needs to happen.

Operator: Our next question comes from the line of Kevin MacCurdy [ph] with Pickering Energy Partners.

Unidentified Analyst: I wonder if you can provide your current thoughts on adding activity in the Lower 48. I know you said that you can grow production without adding, but others are looking at the current service prices and commodity prices and seeing this is a good time to add. So I just want to hear your most recent thoughts on that.

Ryan Lance: Well, I think that will be part of the process we’re going through right now, Kevin. I think we’re trying to think about what 2024 looks like, but our starting point is, we’re seeing the efficiencies and we’re seeing growth coming out of our assets. So we started to a place that says, let’s just think about flat scope, and then we’ll think about these other drivers like commodity price or service capability to your point and make a decision as we go into next year about what the scope and the resulting capital will look like.

Operator: Our last question will come from the line of Leo Mariani with ROTH MKM.

Leo Mariani: I wondered if you could just comment on what you’re seeing in terms of — kind of Lower 48 service cost trends. I think there was a lot of expectations a handful of months ago that costs may be falling, but now kind of commodities that have kind of recovered. Maybe just give us kind of your perspective of what you’re seeing there on leading edge costs.

Dominic Macklon: Yes. Leo, it’s Dominic. So as we talked about in the last quarter, we’re certainly seeing some areas of deflation of Lower 48. I think, if you look at our capital spend this quarter, that’s part of that trend is in there, in terms of being lower capital this quarter than the previous. But we still expect our overall company capital inflation to average out in the mid-single digits this year over last year, and that’s all reflected in our guidance. I would say that as we approach the end of the year, and this is something that is in our thought process right now is — kind of Ryan was alluding to. We do think the market is kind of finally balanced. We do see some deflation coming through, but we have seen oil and gas prices recently strengthened.

So what we’re looking very hard is, how we think that will trend into next year. But I think, as I said earlier, in terms of our overall capital expectations next year, very much in line with what we laid out at AIM, of course, plus our additional interest in Surmont. So that’s just something that we’re watching closely, but that gives you a good sense of how we’re thinking. So…

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