Marathon Oil Corporation (NYSE:MRO) Q1 2024 Earnings Call Transcript

Marathon Oil Corporation (NYSE:MRO) Q1 2024 Earnings Call Transcript May 2, 2024

Marathon Oil Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, and welcome to the Marathon Oil First Quarter 2024 Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to Guy Baber, Vice President of Investor Relations. Please go ahead.

Guy Baber: Thank you very much, Danielle, and thank you as well to everyone for joining us on our call this morning. Yesterday, after the close, we issued a press release, a slide presentation and investor pack that address our first quarter 2024 results. Those documents can be found on our website at marathonoil.com. Joining me on today’s call are Lee Tillman, our Chairman, President and CEO; Dane Whitehead, who as of yesterday is now our adviser to the CEO, Dane successor as our EVP and CFO, also effective yesterday; Rob White, welcome Rob; Pat Wagner, Executive VP of Corporate Development and Strategy; and Mike Henderson, our Executive VP of Operations. As a reminder, today’s call will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

I’ll refer everyone to the cautionary language included in the press release and presentation materials as well as to the risk factors described in our SEC filings. We’ll also reference certain non-GAAP terms in today’s discussion, which have been reconciled and defined in our earnings materials. So with that, I’ll turn the call over to Lee and the rest of the team who will provide prepared remarks. After the completion of their remarks, we’ll move to a question-and-answer session. And in the interest of time, we have a lot to cover today, so we ask that you all limit yourselves to 1 question and a follow-up. Lee?

Lee Tillman: Thank you, Guy, and good morning to everyone joining us on the call. I want to start by again extending my heartfelt thanks to our employees and contractors. We built a track record of execution excellence that is differentiated in our peer space and the S&P 500. A track record that now spans multiple years through the ups and downs of the commodity cycle. Such execution is only made possible to the hard work and dedication of our talented people, who, through it all, remain committed to our core balances, including safety and environmental excellence. Now turning to first quarter results. We have a lot to cover today. I’ll start with 3 key takeaways. First, first quarter was another strong financial and operational quarter.

We executed our plan and we’ve built on our multi-year track record of sustainable free cash flow generation, meaningful return of capital to shareholders and strong capital and operating efficiency. More specifically, we returned 41% or $350 million of our cash flow from operations back to our investors, consistent with our cash flow-driven return of capital framework that provides our investors with the first call on capital. Oil production of 181,000 barrels of oil per day was just above our guidance and free cash flow generation was solid despite not receiving any EG cash distributions from equity affiliates. This is purely due to timing, and we expect to receive a catch-up in EG cash distributions during the second quarter. Importantly, and similar to last year, first quarter marked the trough for both our oil production and free cash flow generation for 2024.

Free cash flow momentum should build significantly as the year progresses, starting with the second quarter. This is driven by several factors, including the expected catch-up in EG cash distributions, a significant increase to our oil production, especially into the second and third quarters and a moderating capital spending profile over the second half of the year, consistent with the phasing of our capital program. My second key takeaway this morning. We continue to make important strides to organically enhance our asset base, making Marathon Oil a stronger, more resilient and more sustainable company. Specifically, we’re improving our capital efficiency through extended lateral drilling. About 25% of our first quarter wells to sales were 3-mile laterals spread across the Permian, Bakken and Eagle Ford.

Execution on this program was excellent, including a record pad in the Permian Basin. We continue to bolster the strength of our asset base through refracs and redevelopment, disclosing approximately 600 opportunities across the Bakken and Eagle Ford. These opportunities are complementary and additive to our company’s decade plus of primary development inventory life and have been derisked through multiple years of technical work by our teams and actual results generated in the field. Notably, 30% of these opportunities are concentrated in the acquired inside acreage and upside to our acquisition basis. And we continue to progress the EG Gas Mega Hub a key competitive differentiator for our company. During the first quarter, we realized the long-awaited shift to global LNG pricing for our Alba LNG.

We started optimizing our integrated gas operations by diverting a portion of our Alba Gas away from methanol production and towards higher-margin LNG sales. And we sanctioned a high competent low-execution risk Alba infill program that offers risk-adjusted full cycle returns that are competitive with our U.S. onshore portfolio. So not only are we realizing improved financial performance this year on the back of our shift to global LNG price realizations, but we believe this improvement is sustainable, due to all the great work our teams continue to do to advance the EG Mega Hub concept. My third and final key takeaway this morning. We remain fully on track to deliver a 2024 business plan that once again benchmarks at the top of the E&P sector on the metrics that I believe matter most.

Free cash flow generation, capital efficiency and shareholder returns. This is demonstrated by the strength of our first quarter execution supporting no changes to our annual guidance. This data is comprehensively summarized on Slides 8 and 9 of our deck and is a compelling endorsement of our value proposition in the marketplace. No peer offers such comprehensive top quartile performance across this powerful combination of metrics. More specifically, we’re expecting $2.2 billion of free cash flow generation this year, equivalent to a mid-teens free cash flow yield. We’ll stay true to our CFO-driven return of capital framework and expect to again return at least 40% of our CFO back to investors through the combination of our base dividend and material share repurchases, providing visibility to both a double-digit distribution yield and significant growth in future metrics.

We’ll keep improving our capital efficiency delivering flat year-on-year total oil production with fewer net wells to sales. And perhaps most importantly, we believe all these results are sustainable. That’s true for our U.S. multi-basin portfolio, and that’s true for our Integrated Gas business in EG. Before I close my introductory remarks, I’d be remiss if I didn’t use this time to recognize Dane Whitehead and his contributions to Marathon Oil as our Executive VP and CFO over the last 7 years. Under Dane’s watch, we’ve established a truly differentiated track record of sustainable free cash flow generation and return of capital to our shareholders, underpinned by an investment great balance sheet. Dane’s contributions to this success have been invaluable.

But more than that, he’s led his organization with the post integrity and humility. Dane on behalf of the entire organization, thank you, and you’ll be missed.

Dane Whitehead: Well, Lee, thank you for those kind words. I really appreciate it. The past 7 years at Marathon Oil has certainly been the highlight in my 40-year career, working with you, our executive leadership team and Board and with all of our talented employees and in forms like this with our analysts and investors. Rob and I have been working very closely together in recent months and that will continue for a while as we ensure a seamless transition. Rob has been with the company for more than 30 years and have all the confidence in the world in his leadership. With that, I’ll pass the CFO torch to Rob, who will be handling our prepared commentary today on our financial performance and return of capital initiatives. Rob, welcome to the show.

Rob White: Thanks, Dane. As Lee mentioned, under Dane’s leadership, our company has built a track record of providing a truly compelling shareholder return proposition while at the same time continuing to enhance our investment-grade balance sheet. You can expect more of the same going forward with continuity in our long-held capital allocation framework and conservative financial policies. I’ll now walk through a few key highlights regarding our first quarter performance and reiterate our key financial priorities for this year. First quarter cash flow and free cash flow generation were solid and consistent with our plan, despite not receiving any EG equity affiliate cash distributions in the quarter. As Lee mentioned, this is purely a timing issue.

For the full year, we expect total EG Cash distributions to approximate our annual equity earnings, starting with catch-up payments during 2Q. The EG catch-up distributions during the second quarter will contribute to an overall significant improvement in our free cash flow momentum as 2024 progresses. This is driven primarily by a significant production increase, especially in the second and third quarters and a moderation of our capital spending starting in the third quarter given the front half-weighted nature of our capital program. Turning now to our key financial priorities for this year. Priority 1 is clear: continuing to return at least 40% of our cash flow from operations to shareholders consistent with our return of capital framework, which represents 1 of the strongest shareholder return commitments in our peer space and across the entire S&P 500.

For 2024, our minimum 40% commitment translates to $1.7 billion of total distributions to shareholders at $80 per barrel WTI price deck, providing our investors visibility to double-digit shareholder distribution yield, a truly compelling shareholder return proposition. During 1Q, we returned $350 million, 41% of CFO to shareholders. We believe our commitment to shareholder returns and the consistency and transparency of our approach have positively differentiated our company. Over the trailing 10 quarters, we now returned $5.8 billion to equity holders, including $5.2 billion of share repurchases, reducing our outstanding share count by 29% and contributing to peer-leading growth in our per share metrics. We continue to see share repurchases as the preferred return vehicle with our stock trading at a free cash flow yield in the mid-teens.

Repurchases remain value accretive, are a very efficient means to continue driving per share growth and are highly synergistic with sustainable base dividend growth. Regarding the base dividend, as we’ve messaged before, our focus remains on competitiveness and sustainability. Given the ongoing benefits of our material share repurchase program as well as the interest expense savings from our gross debt reduction initiatives, we see clear potential for further base dividend growth while protecting the lowest enterprise free cash flow breakeven in the peer group. After meeting our shareholder return commitment, our second priority this year remains continued enhancement of our investment-grade balance sheet through gross debt reduction. Last year, we returned meaningful capital to shareholders and also reduced our gross debt by $500 million.

My expectation is that you’ll see more of the same amounts in 2024. During first quarter, we strengthened our financial flexibility by completing a $1.2 billion offering of 5- to 10-year bonds. Investor demand was strong at greater than 7x oversubscribed which enabled us to achieve a timely and competitive weighted average interest rate of 5.5%. Proceeds from the offering were used to repay the remaining balance on our variable rate term loan facility in its entirety, which in turn delivers $20 million of annual interest savings. With the term loan facility paid off, our focus now turns to the $400 million of tax-exempt bonds that are due in July. As a reminder, this is a very unique vehicle in our capital structure with advantaged interest rates relative to taxable debt instruments.

As such, we will likely remarket those bonds as we’ve done previously. At the bottom right graphic on Slide 11 of our deck shows, after having paid off terms of the term loan, we have minimal bond maturities over the next 5 years. We do, however, retain the ability to efficiently delever down to our medium-term gross debt objective of $4 billion, which would make our current debt-to-EBITDA of 1x at strip durable down to a more conservative $50 to $60 WTI pricing environment. To be clear, our balance sheet is in great shape and provides us with tremendous financial flexibility, including $2.2 billion of liquidity at quarter end. Our top priority remains consistently meeting our 40% of CFO shareholder return commitment. We are also committed to reducing debt over the medium term down to our $4 billion gross debt objective.

We can do both. With that, I’ll turn the call over to Mike to walk through the operational highlights.

Michael Henderson: Thanks, Rob. With strong first quarter execution, consistent with our plan. We’ve made no changes to our annual guidance and remain fully on track to deliver our 2024 program, but once again benchmarks at the top of our sector on metrics that we believe matter most. The combination of free cash flow generation, capital efficiency and shareholder returns. During the first quarter, oil production of 181,000 barrels of oil per day was slightly better than our guidance, while capital expenditures of $603 million were enlarged. It’s been a very strong start to the year for our asset teams. That’s especially true in the Eagle Ford is our first quarter drilling rate of penetration was among the best it’s been in the last 5 years.

First quarter Eagle Ford completion efficiencies also continue to improve. And in the Bakken, despite the challenging winter weather, we held on to the same execution efficiencies on both the drilling on completion site that we were delivering during the second half of last year, a trend, which bodes very well for execution in future quarters. Referencing Slide 14 of our deck. I’d like to highlight the performance of our Permian team. First quarter was another excellent execution quarter, marked by significant production growth. The primary driver of the production increase was our growth while outperformance 3 Upper Wolfcamp wells in core Red Hills at all at 100% working interest are significantly outperforming tight, realizing early well productivity, almost 4x that of the average Delaware Basin well.

The business isn’t just about 1 pad or 1 quarter performance. Our Permian team has now built up a clear track record of execution success. We’re all wells brought online since 2022, our Permian program has delivered among the best results of any Delaware Basin operator for oil productivity per foot. And the team has done so very competitive drilling and completion execution now almost exclusively bringing online 2-mile-plus laterals. Additionally, after taking a 2-year break in the Permian during the 2020 pandemic, we now have 1 of the more likely developed acreage positions in the play, with over 2 decades of high-quality drilling inventory at current activity levels. We’re allocating more capital to Permian and the asset will continue to be a growth driver for us.

But we’ll continue to increase our capital investment at a disciplined pace with an eye on maintaining our execution excellence. With this exceptionally strong start across our U.S. asset bases, our annual guidance midpoints for both production and capital expenditures remain unchanged. And my confidence in delivering on our full year guidance commitment is high. Consistent with our initial outlook, we expect our 2024 capital program to be heavily weighted in the first half of the year, similar to the profile we’ve seen from us before. Driven by relying execution efficiencies, we’re pulling forward some of our activity. This should result in a slight increase to both our expected capital spending and our oil production during second quarter versus our original assumptions.

We now expect our capital spending to be just over weighted for the first half of the year. which will drive a significant sequential increase in second quarter oil for production, up to the midpoint of our annual guidance range, 190,000 barrels of oil per day. In addition to delivering on our guidance commitments. We also remain focused on continuing to enhance our capital efficiency and the strength of our underlying asset base through both the application of extended laterals and other organic enhancement initiatives summarized in more detail on Slide 13 of our deck. Extended laterals remain a compelling opportunity to continue enhancing our capital efficiency. At a high level, we’re expecting significantly lower total well cost per foot, yet similar EUR per foot.

And thus, better returns and higher per well NPV in comparison to shorter laterals. And that’s exactly what our initial cohort of 12, 3 milers during first quarter representing 25% of our total well set is delivering. Execution on the cost front is a clear positive as we’re consistently realizing well cost savings on a per foot basis of more than 20% versus comparable 2-mile laterals. While early train production in the Bakken and Eagle Ford has been consistent with our expectations. Our first 3-mile pad in the Permian Basin, as previously mentioned, has dramatically outperformed. It’s shaping up to be 1 of the strongest pads in Basin history. In addition to the extending laterals, we also continue to further bolster the strength of our asset base through refracs and redevelopment.

More specifically, we’re disclosing approximately 600 high-quality refrac and redevelopment opportunities across the Bakken and Eagle Ford. Approximately 30% of these opportunities are concentrated in our Ensign acreage in the Eagle Ford, representing upside to our acquisition based. These refrac and redevelopment opportunities are complementary and additive to our decade-plus primary drilling inventory at the total company level. With this derisk through multiple years of tank work numerous trials over the last 5-plus years and a recent track record of very strong bottom line results. Importantly, we progressed this opportunity set with tremendous discipline and intentionality. Redev and refrac testing has been a key part of what we’ve long described as our organic enhancement program, which typically comprises 5% to 10% of our total capital budget for a given year.

This capital dedicated to enhancing the returns and resource recovery of our existing asset base through targeted testing of the best concepts the asset teams bring forward each year. For redevs and refracs, we’ve specifically identified potentially stranded resource from early advantage completions that we can economically access through integration into our primary plan of development. In total, we brought online over 100 refracs and 50 redevelopment wells across the Bakken and Eagle Ford to date. So we’ve compiled a rich technical data set and a master deep operational understanding. All 600 of future opportunities we are disclosing are strongly economic and prevailing commodity prices and about half of the 600 we believe, are directly competitive with a Tier 1 primary development inventory industry is drilling today.

More recently, we’ve been bringing on around 20 or so of these opportunities per year. This year, we’re expecting to bring online just over 25. Again, this can account for around 10% of our activity in the Bakken and Eagle Ford. In terms of our development approach, for the most part, we aren’t doing refracs or redevelopment as part of a separate stand-alone program. Rather, these opportunities are mostly integrated into our primary plan of development, typically directly offsetting our primary activity with the goal of maximizing the capital efficiency financial returns of our overall program. Recent results have been very strong, proving out the economic attractiveness of these opportunities supporting the disclosure we’re now providing. In the Bakken, our opportunity set is more heavily weighted to refracs, where we’ve had good success.

Over the last couple of years, our refrac program has delivered 6-month oil productivity per foot that is competitive of the basin average for industry new drills. And we delivered this competitive productivity with a total well cost per foot more than 20% below the industry average for a new drill well. Again, most of our Bakken refracs have not been stand-alone, rather they offset new development wells. This has had the added benefit of improving the productivity of direct off-set Middle Bakken wells by around 10%. In the Eagle Ford, our opportunity set is a bit more balanced, split roughly 55% to refracs and 45% to redevelopment. Over the last couple of years, our refrac and redevelopment productivity has actually even better than the basin average for industry new drills.

In fact, it’s been closer to top quartile. And with our refracs, we realized the same positive impact to offset wells that we see in the Bakken. To summarize, at approximately 10% of our activity in the Bakken, Eagle Ford, our refrac and redevelopment programs aren’t primary drivers of our capital spend in those big basins. But they still represent a very valuable opportunity set that is positively contributing to our bottom line results and extending effective inventory life and they’re a great example of our ability to extract the most value possible out of our existing high-quality resource base. I’ll now turn the call back to Lee, who will wrap up with an EG update and some closing thoughts.

Lee Tillman: Thank you, Mike. Shifting to our EG operations on Slide 15. With the expiration of our legacy Henry Hub-linked LNG contract at the end of last year, first quarter marked the transition to fully realizing global LNG pricing for Alba Gas. Under the new contractual agreements effective this year, we began marketing our own share of Alba LNG directly into the global LNG market. During the first quarter, these LNG sales at $7.21 per Mcf realization drove a significant increase to the international revenue within our consolidated financials. In comparison to previous years, when our EG income was dominated by equity affiliates, a greater share of our EG profitability will accrue to the upstream through our Alba LNG sales and will, therefore, be consolidated in our financial statements.

These reporting changes should all result in improved transparency into the underlying operations of our integrated gas business in EG. We see no change to our 2024 guidance as we continue to expect $550 million to $600 million of total EG EBITDAX this year, assuming $10 TTF. That’s a significant increase from our actual 2023 EBITDAX generation of $309 million. Importantly, we don’t expect this to be a 1-year financial event. For some time, we’ve been focused on sustaining this improved financial performance by progressing all elements of the EG Gas Mega Hub concept. The 5-year EG EBITDAX outlook we provided last quarter demonstrates the sustainability of our EG cash flow generation. You’ll recall the strength of our multi-year outlook is driven by a number of additional factors beyond realizing global LNG pricing.

Ongoing methanol volume optimization, which started during first quarter, our Alba infill program, which we just sanctioned and further monetization of third-party gas through the ethane gas cap. A few more details on our just sanctioned Alba infill program. This is a high confidence, low execution risk, shorter cycle project with returns that are competitive with our high-quality U.S. onshore reinvestment opportunities. We successfully contracted a rig within the region and expect a first half of 2025 spud with first gas from both wells expected during the second half of the year. These wells will largely mitigate Alba base decline, contributing to a flat production profile from full year 2024 to full year 2026. Our 2024 capital spending for this program is limited but fully accounted for in the capital spending guidance we provided to the market in February.

We expect 2025 capital for the program to be about $100 million. We covered a lot of ground today. All great stuff and all intended to further our more S&P mandates. Consistent with that mandate for the last 3-plus years, we’ve been in delivering financial performance highly competitive with the most attractive investment alternatives in the market as measured by corporate returns, free cash flow generation and return of capital. I fully expect 2024 to build on this track record, and we’re off to a great start. Our compelling investment case is simple. A high-quality multi-basin U.S. portfolio and integrated global gas business that delivers peer-leading free cash flow. A unique and differentiated return of capital framework that provides our shareholders with the first call on cash flow.

The output of which is clear visibility to compelling shareholder distributions across a broad range of commodity prices and sector-leading growth in per share metrics and a multiyear track record of consistent execution and proven discipline. And perhaps most importantly, everything we’re doing is sustainable with resilience through the commodity cycle. This is due to the quality and depth of our U.S. multi-basin portfolio, where we have over a decade of high return inventory and a disciplined and multifaceted approach to portfolio renewal, including organic enhancement initiatives. It’s also due to our differentiated integrated gas business that’s now fully realizing global LNG pricing, as we continue to progress all elements of the Regional Gas Mega Hub concept.

Rest assured, our commitment to our strategy is unwavering, and is built upon our core values, resilience across the commodity cycle and our long-term track record of success. With that, we can open up the line for Q&A.

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Q&A Session

Operator: [Operator Instructions]. The first question comes from Scott Hanold from RBC.

Scott Hanold: Mike, you spent a lot of time kind of going through the refracs and talking about that a lot. Obviously, it seems like it’s going to be — it has been an initiative, but it’s got a little bit more prominence. But could you sort of dumb some of the sort of the economic and productive parameters down for us? Like what would a typical Bakken and then a typical Eagle Ford well be producing when you’d kind of play to refrac. And what would that bounce to after that? And could you just give us a sense of the cost associated with it?

Michael Henderson: Yes. Let me start with the cost, Scott. So I mean specifically, when you look at these refracs, I mean, refracs, we got a deeper history in the Bakken and the Eagle Ford necessarily. But when you look at the cost, we’re kind of thinking about it roughly 80% of a new grassroots well, and that’s kind of how we’d be thinking about it on a go-forward basis. And in terms of the well productivity, I think I covered that in some of the prepared comments that we just gave you. The refracs that we’re seeing in the Bakken pretty comparable from when we look at some of the new wells that the peers are bringing online. In Eagle Ford, it’s actually a more constructive story for — we’re seeing the refrac/redev well is actually outperforming some of the new wells that are bringing online. In fact, if anything, there you’re looking at kind of top quartile performance there.

Scott Hanold: Yes. And I guess maybe the point I was trying to ask is, are these wells like producing like 50 or 100, 100 a day and then they’re going to get back to a new well and kind of continue the typical profile that you would see with the new well that I guess that was my specific kind of question.

Michael Henderson: Yes. I mean, very similar to new well, you get that initial production and then you get back on to that pretty regular decline rate that you would expect with the new well.

Scott Hanold: Okay. And then my follow-up question is the Permian. Obviously, you guys really stood out this quarter with those Lea County wells. And you talked about having like 2 decades roughly of inventory but looking to maybe increase that pace. Like where should we think about like Marathon kind of moving the Permian terms of capital allocation as you think about 2025 and beyond. Because obviously, 20 years is nice, but optimally, it seems like your investment there should probably increase given returns and your visibility of inventory.

Lee Tillman: Yes. Maybe I’ll start, Scott, and let see if Mike wants to add any additional color. I think we’ve been very methodical in our approach to the Permian. I think as we stated in the prepared comments, it’s probably 1 of the more likely developed positions in the basin because we have pace. I mean we have fantastic black oil assets right in the Bakken and the Eagle Ford to deliver superior top of Tier 1 kind of returns. And so it’s taken a bit of time for Permian to kind of penetrate into the capital allocation. But based on the results that we’ve really seen kind of post, I’d say, the pandemic pause, they are now competing. What you’ve seen is a steady increase and the capital that is flowing into the Permian. And you should expect to see that continue, we don’t view it as a — it’s going to be a step change increase in 1 given budget cycle, but you should expect to continue to see us drive more investment there as Permian, as you said, it is going to be a growth asset for us as we move into the future.

And there’s a tremendous amount of potential. And so with no doubt, as that consumption of wells to sales goes up, that 20-plus years of inventory will obviously moderate. But the strength of that inventory is unquestioned. And probably at least half of that inventory like we believe we can ascribe to extended lateral drilling as well. So it’s — we’re very excited about it. I mean the Permian team has definitely earned their spot in capital allocation now.

Michael Henderson: I think the only other thing I can say is we’ve been very thoughtful in terms of both how we reengage with that asset. And I think I described in the prepared comments, we’ve been doing things at a very disciplined pace. I mean that’s — we’ve done that for a number of reasons. It certainly allows us to mitigate any potential execution risk and moving too quickly. It also provides us the ability to integrate any learnings into what we’re doing. Maybe the final thing I’ll say is when I think about our go-forward program in the Permian, I’d probably characterize it we have been focused on the Wolfcamp. But as I think about the go-forward program, I’d say we’re going to be targeting, it’s going to be proven benches at a very proven well spacing, maybe even slightly conservative well spacing. So I think just echo Lee’s comments about we feel very, very good about the go-forward program there.

Lee Tillman: And the last thing I would maybe add, Scott, is this is also a great demonstration of the strength of the multi-basin portfolio and how we kind of feather these other assets. I mean, today, as you see the dislocation between value between oil and natural gas, obviously, the true black oil areas are very strong, the Eagle Ford and the Bakken. And then even if you look at some of the realizations coming out of the Permian, which are challenged today on the gas side, very little of our revenue and production is being sourced or being exposed to that today. And again, it just really demonstrates the strength of having a multi-basin approach where you can move capital allocation around.

Operator: The next question comes from Arun Jayaram from JPMorgan.

Arun Jayaram: Mike, I wanted to get a little bit more details on the refrac program. As you know, the buy side has historically been a little reticent to give value for refracs versus, call it, primary sticks on the map. So you mentioned that you’re doing kind of 25 refracs this year. I’d love to get a sense of what kind of NPVs per well do you see in this program versus a primary development? And how do you think about value creation potential, you highlighted 600 opportunities across the Bakken and the Eagle Ford.

Michael Henderson: Yes. I mean as I mentioned to Scott in the last call, in terms of volume, we’re looking at these Bakken and refracs being very comparable to industry new drills. So I think you could tag a number of that are. And then similarly, in the Eagle Ford, again, we mentioned that refracs there were probably outcompeting some of the new drills that industry was bringing on, if anything, there kind of top quartile. So again, I think you could get at a number there. And you can do the math, 600x that number, it gets you to gets you a potential volume uplift.

Lee Tillman: Yes. And maybe just to stress around, we’re not looking at refrac and redevelopments and necessarily displacing primary development opportunities within our portfolio. But when we benchmark them against what others are drilling today, economic-wise, they’re very, very competitive. But it’s going to be also main-ish of the Eagle Ford Bakken program. It’s not a major driver necessarily in terms of capital, but it is very high value. And that’s what I think is very exciting. The other thing that I’ll just emphasize is if you rewind back to when we talked about the Ensign acquisition, we were very clear that we ascribe no value in that transaction to refrac and redevelopment. And here — and so the importance to think of this disclosure is multifold not only at an enterprise level, but even zooming in on that acquisition. 30% of these opportunities lie in the Ensign acreage, which is that upside that we referenced when we described that acquisition.

Michael Henderson: Still make it. When I think about we’re doing 10% refracs, redevs. I think that talks to the quality of our primary inventory. The fact that we are undertaking the refrac suite development as part of the overall primary development. It’s not a stand-alone program. Again, I think it just talks to the quality that we’ve got in the existing primary, hopefully.

Arun Jayaram: Great. And just my follow-up. I know that some of the accounting in EG will change. This year, you’re giving the change in the marketing agreements we’ll have to spend some time with Guy to go through this in terms of our model. But 1 of the questions that’s come in is, does it impact how you’re recognizing cash flow from ops versus CFI. Just wanted to see if there’s any changes to how you’re — how this will impact the reporting of cash flow on a go-forward basis?

Lee Tillman: I’ll maybe hand over here in just a minute to Rob and or Dane. But first of all, I want to be clear don’t let the accounting situation kind of take away from the results in EG. If you look at the bottom line results, that we generated this quarter, they were very much in line with the expectations of capturing that global LNG pricing. So being into the vagaries of consolidated versus equity accounting but from a bottom line delivery standpoint, the asset is delivering exactly what we described. Okay. So now I’ll turn over to the green eyeshades here and let them talk a little bit about this piece.

Rob White: Arun, this is Rob. Just a quick point there. I think actually, a difference you would see would be a positive difference on a cash flow perspective with more of our business flowing through the consolidated side, it kind of eliminates the timing issue of the dividend. So as we’ve migrated that from the EG LNG EMI earnings over to the consolidated side, these LNG listings, the cash would come in without a dividend process will be subject to lifting schedules. So the timing of some of those liftings might fall under overly position at the end of any quarter. But would potentially be a positive on dividend timing.

Arun Jayaram: Great. Dane, I wanted to thank you for all of your counsel and help over the years, and glad you had a successful act after EPE, but great work. But we’ll miss you.

Dane Whitehead: Thanks, Arun. I really appreciate it. Yes, thinking back to the early days of EP Energy, boy, there’s been a lot of water under the bridge, but it’s been a great run here at Marathon and really proud of where this company is right now. So thank you for all your support.

Operator: The next question comes from Betty Jiang of Barclays.

Betty Jiang: I want to ask about the continued value maximization efforts that we’re seeing here at EG integrated gas assets. Lee, perhaps if you could help us think about the value uplift from redirecting the volumes into the methanol plant instead of LNG sales? And basically, is there opportunity to do more of that before that gas contract expires in 2026, I believe?

Lee Tillman: Yes. No, thanks for the question, Betty. Yes, I think the overall approach in EG has been very comprehensive. We’ve always talked about EG in terms of a value proposition that consists of the Alba Gas condensate field, but also this world-class infrastructure and how we can maximize taking advantage of that. And so we’re always looking to drive more opportunity here. And you just highlighted 1 of the very key ones as we look to optimize gas flows within this integrated gas asset. And for where methanol stands today, and we’re obviously uplift to global LNG stands today, it makes a lot of sense to divert a large component of the gas speed into AMPCO or the methanol facility into LNG. It’s best for our partners. It’s also best for the state as well in terms of maximizing revenues.

The GSA, the Gas Sales Agreement that we have with the methanol plant runs its course in 2026. And obviously, at that point in time, we’ll have another strategic decision to make going forward around what is the future of that facility. But again, we would not be subject to that gas sales agreement in 2026. So maximizing flow to EG LNG becomes a real option for us at that stage. Today, you should really think about it as we’re taking advantage of that arbitrage to the extent that we can while also keeping AMPCO running in good stead and continuing to meet our marketing obligations on the methanol side.

Betty Jiang: Got it. That’s clear. And then I have another question on the Permian. It’s great to see that the 1Q results showcased the strength of the wells that were brought on line during the quarter. But I’m also wondering how sustainable is this level of productivity that we’re seeing in the Permian. Basically, as you start ramping up activities in the basin as the development approach potentially evolve can we expect to see this level of productivity going forward? Or would there be some level of dilution as you get into full development?

Michael Henderson: Betty, it’s Mike here. I’ll take that question. Yes. I mean we probably touched on that 1 a little bit, 1 of the earlier responses. But when I look at the Permian, we talked about over 20 years of inventory at the current drilling pace. When I look at what we’re going to be targeting in the future, again, I’d describe it as it’s — we’re going to be targeting proven benches at proven if not conservative well spacing sold. When I think about the capital efficiency coming out of that basin, I think it’s going to be pretty consistent certainly in the near term. So you should expect more of the same as we potentially look to even ramp up some activity there in the coming years.

Lee Tillman: Yes, Betty, I would just reference the fact again that when you look at our acreage position just because of the way we’ve developed it, it is 1 of the more lightly developed position in the peer group, which I think just underpins what Mike says, we’ve got a lot of running room there with very high-quality inventory, a big chunk of which will still be subject to extended lateral drilling as well.

Operator: The next question comes from Neal Dingmann from Truist Securities.

Neal Dingmann: My first question is on capital allocation. Specifically, I was hoping maybe you could just maybe give a broad comment on how you view the current value of your stock versus what you’re seeing out there for potential assets in the market. I’m just wondering, I mean, I love how you continue to sort of dig in and keep repurchasing those shares. And I’m just wondering if that’s still because of your view on the valuation versus where some of this external assets are at.

Lee Tillman: Yes. Well, certainly, as you look at the efficiency of a share repurchase program, when you quickly go to the free cash flow yield that you’re generating and being strongly and double-digit yields there. It still makes a lot of sense to see any discretionary cash flow above and beyond our base dividend and flowing to that vehicle. I mean, I think as we said in the opening remarks that, that still is our preferred vehicle. The combination of a competitive and sustainable base dividend as well as ratable share repurchases. We still believe in that. Now I would say there’s really 2 independent questions there. I think that your shares can be a good value in the market, but we obviously continue to watch all of our basins for opportunities, inorganic opportunities to enhance our business, but we have a very strict criteria for that.

And we’ve been very clear about that from the beginning and that was really exemplified in the Ensign transaction. If anything, that criteria is even higher when you consider the addition of Ensign, some of the Permian performance that we just described and the length and duration of inventory there and even the refrac and redevelopment opportunity set that we’ve disclosed here. So that bar for that type of opportunity remains high as it should be in such a high-quality portfolio. But I kind of view those a little bit as 2 independent decisions. I still think from a return of cash to shareholder standpoint, a 40% CFO commitment that reign supreme and the best vehicles for accomplishing that our base dividend and share repurchases. But we’re going to continue to obviously watch and evaluate any and all high-quality opportunities that come into the market, but we’re going to scrutinize those through the lens of a very exacting M&A criteria.

Neal Dingmann: Very clear. And then just a quick second one on EG, I think I know the — as I want to ask. Is there any room there to expand your current footprint? I’m just wondering how positive, the contractual terms and other things you have there. Is there any opportunities for expansion over EG?

Lee Tillman: Yes. I think when you say expansion, we continue to look at, I would say gas aggregation in the area, both indigenous gas and EG, but also cross-border opportunities as well, particularly in Cameroon. So yes, I think there is opportunity there to expand our footprint. Now that may not necessarily look like upstream investment. It could look at — look like maximizing throughput through EG LNG, for an extended duration. But we see a lot of opportunity there. But right now, I think as you look at kind of the multiple phases and how we’re executing those within the Gas Mega Hub, it really started with the Alen third-party molecules that got infrastructure built using someone else’s money, and we now have access to that infrastructure, and we’re realizing both tolling plus profit share on those molecules.

The next step was really coming into the global LNG market with our Alba equity molecules. We can now kind of tick that 1 off the list. Complementary to that was to get more Alba molecules, which the infill program will help us drive more high-value molecules, equity molecules there. And then finally, we’re right now in the throes of negotiating the ethane gas processing, which that’s the ethane gas cap that we know is there. We’re well positioned with the infrastructure that was built for a land to bring those molecules to EG LNG. And all of these are continuing to extend the runway of this world-class infrastructure. And by extending that runway, you just open up the aperture for even more opportunities, which may look like something like could be indigenous EG Gas, but it could also very well be cross-border gas because this facility is going to be the natural aggregation point for regional gas in this area.

Operator: The next question comes from Nitin Kumar from Mizuho Securities.

Nitin Kumar: Lots of good updates this quarter. I just want to focus on the long laterals. Obviously, this quarter, you did, I think, about 8 long laterals in the Eagle Ford and the Bakken and a few less in Permian. Given that your Bakken and Eagle Ford are more developed than your Permian assets, what’s the mix of your future inventory when it comes to these 3-mile laterals?

Lee Tillman: Yes. Maybe I’ll take it at a high level, and I’ll let Mike jump in and maybe talk a little bit about at an asset level. Year-over-year, the portfolio is actually the lateral length has increased by about 5% to 10%. And so we are moving the entire portfolio toward longer laterals, some areas, some leases and some basins are more adaptable to an extended lateral to 3-mile kind of approach. So it’s going to be very dependent upon the lease form, our position in that particular basin. But we’re definitely pressing hard to drive as much of our capital allocation toward extended level because we see just the efficiency of doing that. The reduction in costs on a per foot basis and then essentially very similar EUR per foot in the same laterals.

I mean, what we’re seeing in the third mile is consistent with a lot of capture out of that third mile. So there’s a lot of incentive for us to continue to drive and other operators feel the same way. And so in areas where perhaps there are some trades or some swaps that you can make it kind of benefits everyone to continue to consolidate and drive as much of their operated acreage toward extended laterals as they can.

Michael Henderson: I think you’ve covered it, Lee, I think maybe the only thing I’d add in. Our land team has done a great job. They’ve done a great job, continue to do a great job. I think as we mentioned, we see the capital efficiency enhancements. There’s alignment there with offsetting operators. So the trend that we’ve been on in terms of increasing our average lateral lengths, obviously, gets a little bit more difficult every year. But see, the land team has done a phenomenal job and all of the asset teams are very, very active in terms of engaging with those offset operators just to see if there are deals that we could do to just extend the average out for land.