Marathon Oil Corporation (NYSE:MRO) Q1 2023 Earnings Call Transcript

Marathon Oil Corporation (NYSE:MRO) Q1 2023 Earnings Call Transcript May 4, 2023

Operator: Good morning, everyone, and welcome to the Marathon Oil First Quarter 2023 Earnings Conference Call. Please also note today’s line is being recorded. At this time, I’d like to turn the floor over to Guy Baber, Vice President of Investor Relations. Please go ahead.

Guy Baber: Thanks, Jamie, and thank you as well to everyone for joining us on the call this morning. Yesterday, after the close, we issued a press release, a slide presentation, and investor packet that address our first quarter 2023 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, Executive VP and CFO; 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 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. With that, I will turn the call over to Lee and the rest of the team, who’ll provide prepared remarks. After the completion of those remarks, we’ll move to a question-and-answer session. Lee?

Lee Tillman: Thank you, Guy, and good morning to everyone listening to our call today. First, I want to say thank you to our employees and contractors for another quarter, a comprehensive execution against our framework for success. I’m especially grateful for your commitment to safety, differentiated execution, and environmental excellence. Well done on another great quarter, while staying true to our core values. We have a number of notable topics to cover today to continue to build on our peer-leading and market-leading financial and operational performance. I’ll start by reviewing some key takeaway consistent with the summary on Slide 5 of our earnings presentation. First, we reported another very strong quarter, both financially and operationally that is fully consistent with the guidance we provided back in February and further built on our track record of delivery.

We continue to execute against our differentiated cash flow driven return of capital framework, again exceeding our commitment to return at least 40% of our cash flow from operations to shareholders and industry-leading commitment. Our adjusted earnings per share handily beat consensus, and we generated strong free cash flow during first quarter, despite not receiving any E.G. cash dividends. The entirety of the variance in our cash flow and free cash flow versus consensus can be explained by the fact that we reported $80 million of E.G. equity income, but did not receive any E.G. cash dividends. This difference is strictly related to timing, and importantly, we expect to receive over $200 million of E.G. cash distributions during second quarter, more than making up for the first quarter delta versus consensus.

And in fact, we expect E.G. cash distributions to exceed E.G. equity income for full-year 2023. We continue to strengthen our already investment-grade balance sheet, proving we can both deliver industry-leading shareholder returns and reduce our gross debt. It’s not an either/or proposition. And operationally, first quarter oil production came in at 186,000 barrels of oils per day, consistent with our guidance. We expect an improving oil production trend into the second and third quarters, given our first-half weighted capital program and the associated timing of our wells to sales. Second key takeaway. Our full-year capital spending and production guidance remains unchanged. We remain on track to deliver our 2023 business plan, our plan that benchmarked at the very top of our high-quality E&P peer group on the metrics that matter most.

Those metrics include total shareholder distributions relative to our market capitalization, free cash flow yield and free cash flow efficiency, reinvestment rate and capital efficiency, free cash flow breakeven on both the pre and post-dividend basis, and growth in our production per share. This is strong evidence that not only the quality of our assets but the strength of our operational execution and the merits of our disciplined shareholder-friendly capital allocation and return of capital framework that focuses on per-share growth. And my third and final takeaway this morning. While we are focused on executing our 2023 plan that leads our sector, we’re equally focused on continuous portfolio enhancements to further improve our competitive positioning and longer-term sustainability.

We’ve now successfully integrated the highly-accretive Ensign acquisition ahead of schedule and we’re realizing excellent results from our initial wells to sales. We’re delivering tremendous results in the Permian Basin since our return to activity last year. Today, the Permian is effectively competing for capital on a heads-up basis with the best of the Eagle Ford and Bakken in our portfolio, a very high bar to clear. And finally. in Equatorial Guinea, we’ve made great strategic progress and further strengthening the longer-term outlook of our unique, fully-integrated global gas business. With that, I’ll turn it over to Dane, who will provide more detail on our 2023 outlook and how it stacks up to peers.

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Dane Whitehead: Thank you, Lee, and good morning, everybody. Full year 2022 data shows that we performed at the very top of a high-quality E&P peer group last year, as well as the broader market, consistent with the charts on Slide 7 of our deck. An analysis of 2023 guidance indicates that our business plan again benchmarks at the very top of our sector and all the metrics that we believe matter most. I’ll start with a recap of our 2023 return of capital outlook summarized on Slide 8 of our slide deck. As I’ve stated many times on our earnings calls, returning significant capital to shareholders through the cycle remains foundational to our value proposition. We’re focused on building — excuse me, a long-term track record of consistent shareholder returns that can be measured in years, not just quarters, and 1Q was another step on that journey.

We again exceeded our commitment to return a minimum of 40% of our CFO, returning 42% to shareholders, including $334 million of share repurchases and our $63 million base dividend. Looking at the full year, we expect to continue adhering to our return on capital framework, while also paying down debt, including some of the Ensign-related finance. We believe we can do both, maintain our return-of-capital leadership and further enhance our already investment-grade balance sheet. And we’re off to a great start, beating our 40% of CFO target in 1Q, while paying down $70 million high-coupon USX debt and remarketing $200 million of tax exempt bonds at a very favorable rate. We’ll take down our remaining $130 million of USX debt in July and maturity.

We continue to believe our cash flow driven return of capital framework is uniquely advantaged versus peers, truly providing investors with the first call on cash flow and insulating shareholder returns from the effects of capital inflation. Offsetting inflation is on ops, not the shareholder. Even at our minimum 40% of the CFO commitment, our return of capital framework is sector-leading. It provides clear visibility to a double-digit distribution yield across a broad range of commodity prices as shown on the top-right graphic on Slide 8, and it benchmarks the very top of our peer group with a total shareholder yield about double the peer average. In terms of our preferred vehicle for shareholder returns, there’s no change to our approach.

We’ll pay a competitive sustainable base dividend with the lion’s share of shareholder returns coming through share repurchases. We currently have $2 billion of buyback authorization outstanding, which gives us plenty of room to keep executing. With our free cash flow yield in the high-teens, buybacks remain significantly value-accretive, a very efficient means to drive per-share growth, and highly synergistic withdrawing our base dividends, which we’ve raised eight out of last 10 quarters without compromising sustainability. Though peers have now migrated to our model, we were an early proponent of share repurchases and our dollar-cost averaging approach since October 2021 has delivered a peer-leading 22% reduction in our shares outstanding.

The strength and durability of our shareholder return profile underpinned by strong free cash flow generation and capital efficiency. While first quarter free cash flow was solid at $330 million, we expect both our underlying free cash flow and cash flow from operations to strengthen as we progress through the year. There are a number of factors driving this trend. As we mentioned, we didn’t receive any E.G. cash dividends during 1Q. We expect to start receiving those distributions in the second quarter, beginning with a larger-than-normal dividend of more than $200 million. Additionally, our CapEx is front-end loaded with 2Q capital spend expected to be comparable to first quarter consistent with our outlook for about 60% of our full-year capital to be concentrated in the first half of the year.

And the timing of this spend will drive oil production growth from 1Q levels, improving our cash flow generation capacity as we move through the year. Therefore, operationally and financially, we remain fully on track with the assumptions that underpinned our initial full-year free cash flow outlook provided earlier this year. And our 2023 outlook very clearly benchmarks at the top of our peer space as illustrated on Page 9 of the deck. We continue to trade at one of the most attractive free cash flow yields in the entire S&P 500, as the top-left graphic shows. While this meeting free cash flow yields is in part due to attractive valuation, it’s also a function of our peer-leading free cash flow efficiency. The top right graphic shows our free cash flow margins well above the peer average.

For every barrel we produce, we’re delivering 30% more free cash flow than the average high-quality E&P. Similarly, our reinvestment rate, a direct measure of capital invested versus cash flow generated, a true cash flow efficiency metric as it considers both capital and operating expenditures, is the lowest in the peer space, a full 10 percentage points below average. Further, our capital intensity is measured by CapEx per barrel of production, is more than 20% better than the peer average. This strong performance is a testament to not only the quality of our asset base but the strength of our operational execution and the discipline inherent in our capital allocation framework. Our focus remains on maximizing the free cash flow and corporate returns on every dollar we spend.

Turning to Slide 10, we benchmarked ourselves on one of the most important metrics for our sector, our free cash flow breakeven or the WTI oil price necessary to achieve free cash flow neutrality, a metric so important that we’ve hardwired it into our short-term incentive scorecard. Through disciplined capital allocation, ongoing cost structure optimization and a relentless focus on our capital and operating efficiency, our objective is to maintain the lowest sustainable free cash flow breakeven level. This is crucial to maintaining business model resilience and ensuring we’re positioned to deliver compelling free cash flow across a broad range of commodity prices. When commodity prices are healthy, we expect to materially outperform the S&P 500 in free cash flow generation.

When commodity prices are challenged, we expect to remain competitive with the S&P 500. And we can only do this by maintaining a low free cash flow breakeven. And Slide 10 shows we have the lowest 2023 pre-dividend free cash flow breakeven among high-quality peers at around $40 per barrel WTI. Additionally, we expect to realize significant improvement in our free cash flow breakeven from 2023 to 2024, largely driven by the expected financial uplift in E.G. So while our 2023 competitive positioning is strong, it’s even better in 2024. Finally, our free cash flow breakeven is also the lowest on a post-dividend basis. While we’ve raised our base dividend in eight of the last 10 quarters, we stay focused on base dividend sustainability and the synergies that exist between share buybacks and sustainable dividend growth.

Whereas certain peers now have base dividends that add $10 or even $15 per barrel to their breakeven, our base dividend adds a more modest $3 to $4 a barrel, underscoring a sustainability and our headroom for longer-term growth as long as we continue to reduce our share count. Turning to Slide 11. While we’ve been a leading proponent of a capital allocation framework that strongly prioritizes corporate returns and free cash flow generation over production growth, the reality is that we’re leading the peer group in growth on a per-share basis. 2021 to 2023, we expect to grow our production per share by more than 40%. In 2023 alone, we expect to grow production per share by approximately 30% year-over-year. Absolute production growth is not the objective, but we do see value in significantly growing our underlying per-share metrics.

Two primary factors are driving our exceptional per-share growth profile. First, a consistent and disciplined approach to shareholder returns with a strong emphasis on buybacks. Through our buyback program, we’ve reduced our share count by 22% in the last six quarters. Our peers have moved toward our model, but we’re definitely enjoying a first-mover advantage. And second, the highly accretive Ensign acquisition, which increased our maintenance of oil production by approximately 12% with no increase in share count. So with that summary of our 2023 business plan and competitiveness, I’ll turn it over to Mike to provide a brief update on Ensign and our recent outstanding performance in the Permian.

Mike Henderson: Thanks, Dane. As we’ve stated, the Ensign acquisition checks every box of our M&A framework, immediate financial accretion, return of capital accretion, accretion to inventory life and quality and industrial logic with enhanced scale, all while maintaining our financial strength and investment-grade balance sheet. We stated before our early focus with Ensign has been on integration and execution. Today, I’m happy to report that our integration of the asset is now complete. With a faster-than-anticipated timeline underscoring the execution confidence that comes with an acquisition and an established basin where we have a track record of success. And on the execution side, as highlighted on Slide 12 of the deck, early well performance continues to demonstrate that the acquired inventory offers some of the strongest returns in capital efficiency in the entire Eagle Ford.

Of our first three parts, 14 wells in total, are delivering top decile oil productivity in the basin. We plan to bring online another 20 or so Ensign wells during the second quarter. These wells are expected to deliver accretive capital efficiency and financial returns with comparable oil productivity to our legacy Eagle Ford program. With that, let me turn to our Permian operations where the team has been delivering tremendous results since we returned to a higher level of activity last year. As a reminder, we effectively shut down our Permian program in 2020 during the COVID-related commodity price collapse. In hindsight, pausing activity was one of the best things we could have done, not dissimilar from the pause in activity we took in the Bakken during 2016, also during a period of low commodity price before we transformed the performance of that asset.

More specifically, in the Permian, our team spent the last couple of years better understanding our acreage position from a top-down, bottoms-up perspective and repositioning that asset for success. We closely analyzed peer results across the basin by taking a hard look at our well spacing and our completion designs and we worked diligently on traits to core up areas we like to enable the extended laterals we are drilling today. The culmination of this hard work is shown on Slide 13. Since returning to activity at scale during the second half of last year, we brought 23 Northern Delaware wells to sales, 18 of which are extended laterals with an average lateral length of about 9,000 feet. These 18 extended laterals are significantly outperforming the Delaware Basin top-quartile on a cumulative oil basis by about 30%, truly exceptional results that compete with the absolute best operators in the basin.

This well set also includes the strongest well in the entire Delaware Basin during 2022, the Thunderbird 014H in Red Hills, which produced over 380,000 barrels of oil during its first 180 days. Geographically, these 18 extended laterals are evenly split between our Red Hills and Malaga areas. And from this point forward, as we benefit from coring up our acreage footprint and high grading our development program, we’ll almost exclusively be drilling the extended laterals. With these results, the asset is now effectively competing for capital against the best in the Eagle Ford and Bakken in our portfolio, which is no easy task and enhancing the long-term outlook for our company. I’ll now hand it back to Lee, who will provide an update on our E.G. operations and then conclude our prepared remarks.

Lee Tillman: Thank you, Mike. As highlighted on Slide 14, we recently completed a significant planned E.G. turnaround and the asset is now back to normal operations. While the downtime reduced our second quarter E.G. production by about 12,000 oil equivalent barrels per day, it’s intended to contribute to stronger uptime for both the winter of 2023, as well as next year and beyond when we’ll benefit for more attractive pricing for our Alba equity gas. The turnaround impact is fully contemplated in our full-year production numbers. We are reducing our full-year E.G. equity income guidance by about $50 million, strictly due to lower assumed natural gas prices. However, we expect our E.G. cash flows to prove more resilient. E.G. cash distribution should actually exceed equity income this year, starting in second quarter, illustrating the strong cash flow nature of the assets plus a bit of catch-up in dividends from prior quarters.

Looking ahead to 2024, we continue to expect to realize significant earnings and cash flow improvement on the back of an increase in our global LNG price exposure. While we’re still working through contractual specifics, the bottom line is, the beginning January 1, 2024, Alba sourced LNG will no longer be sold at a Henry Hub linkage. It will be sold into the global LNG market, which is expected to drive a significant financial uplift for our company, given the material arbitrage between Henry Hub and global LNG pricing. Yet, it’s not just about capturing commercial uplift in E.G. We’re equally focused on the longer-term outlook and fully leveraging the value of our unique infrastructure in one of the most gas prone areas of West Africa to enhance our multiyear free cash flow capacity.

That’s exactly what our recently-signed HOA summarized on Slide 15 as intended to accomplish. A few elements of the recently-announced HOA are worth highlighting. For clarity, Phase 1 of the E.G. Regional Gas Mega Hub is already completed and delivering value via the processing of third-party gas on a toll plus profit share basis from the Alen Field. Phase 2 of the Gas Mega Hub involves the expected 2024 cash flow uplift I just discussed, processing our equity Alba gas molecules under new contractual terms as of January 1, 2024, with linkage to the global LNG market. The HOA aligns all the critical parties on the necessary commercial principles to that end. Under Phase 2, we’re also analyzing the potential for infill drilling on our Alba block, giving — given our alignment across the value chain for equity Alba molecules.

Recall that we have a 64% working interest in the upstream Alba Unit and a 56% working interest in the downstream E.G. LNG facility and are the operator of both. More specifically, we’re assessing up to a two-well program targeting high confidence, low-execution risks, shorter-cycle opportunity that could mitigate Alba base decline and maximize flow of Alba equity molecules through the LNG plant under more attractive global LNG-linked terms. These opportunities are expected to compete with the risk-based returns generated from our U.S. resource plays. Phase 3 highlights the next step in the development of the Regional Gas Mega Hub. The intent to process third-party Aseng gas at our facilities once capacity at the LNG plant begins to open up.

The Aseng gas cap blowdown can access the same upsized pipeline that was funded and constructed by the Alen partners. This is fully consistent with our long-stated objective to extract maximum value from our world-class E.G. infrastructure by keeping the LNG facility as full as possible or as long as possible. Phase 3 will effectively extend the life of the E.G. LNG facility into the next decade, enhancing our long-term free cash flow capacity. Beyond Phase 3, we’ll continue to assess additional opportunities with the same objective in mind. There is a lot of discovered undeveloped gas in the area and the path to monetization runs through our infrastructure. A recent cross-border agreement between E.G. and Cameroon opens the door to additional fast track opportunities in addition to other regional discoveries.

Turning now to Slide 16. I’ll close our call on the same slide we’ve used to conclude our remarks in recent quarters. For years now, I’ve reiterated that for our company and for our sector to attract increased investor sponsorship, we must deliver financial performance competitive with other investment alternatives in the market, as measured by corporate returns, free cash flow generation and return of capital or S&P, less E&P. We’ve delivered exactly that type of performance over the last two years and not just competitive, but at the very top. Our one line investment thesis, top-tier sustainable free cash flow yield at an attractive valuation with an advantaged return of capital profile, centered on per-share growth. And as our detailed 2023 competitive benchmarking slide show today, we’re well positioned to again lead both our peer group and the S&P 500 on the metrics that matter most.

This peer-leading financial and operational delivery is not a one-year phenomenon. It’s a continuation of a multiyear trend. It’s sustainable, underpinned by our high quality and oil-weighted U.S. unconventional portfolio, recently strengthened by the Ensign acquisition that is complemented by our unique fully-integrated global gas business in E.G. To close, I want to iterate — reiterate how proud I am of the way we positioned our company. We are results-driven, but it is also about how we deliver those results, staying true to our core values and responsibly delivering the oil and gas the world needs. And the world needs more energy, not less. The energy transition is really an energy expansion and oil and gas is uniquely positioned to drive global economic progress, defend U.S. energy security, lift billions out of energy property and protect the standard of living we have all come to enjoy.

With that, we can open the line for Q&A.

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Q&A Session

Operator: Our first question today comes from Arun Jayaram from JPMorgan. Please go ahead with your question.

Arun Jayaram: Yes, good morning. Lee, I wanted to get maybe a few more insights on the dividend expectations for 2Q out of E.G. and wanted to run some math by you. In the first half of the year, you — including 1Q actuals, you would expect to generate about $115 million of equity income based and on that $200 million dividend, that would suggest maybe an $85 million tailwind to cash flow relative to your equity income guide. So wanted to run that math by to see if that made sense to you.

Lee Tillman: Yes, Arun, thanks for bringing a little bit of clarity to this point, but your math is relatively spot on. And the reality is that we do have a little bit of dislocation from time to time between equity income and receipt of the cash dividend and we’re in that space in first quarter. But as you accurately stated, we’re going to more than make up for that in second quarter with a greater than $200 million cash dividend payment coming from E.G. LNG, but your math is spot on, Arun.

Arun Jayaram: Great. And just my follow-up, Lee, I wanted to go back to E.G. again. Looking at the 10-K, gross sales out of Alba we’re about 2 million tons per annum at the 3.7 million ton per annum facility. I know that the Alen volumes bring you closer to nameplate, but as you know, Lee, one of the bare thesis on the stock has been the fact that Alba volumes are declining, call it, at a 10% to 15% annum clip. And so, wanted to get your thoughts on how Phase 1, Phase 2, Phase 3 of your strategy on Slide 15 can help keep the plant full. The duration that you see from these opportunities and just broader thoughts on your — on Marathon continuing this capital-light strategy with third-party volumes or wanting to get more operating volumes through that facility.

Lee Tillman: Yes. Thanks for the question. You’re exactly right. Right now, coupling both the Alba equity volumes with the Alen volumes, we’re at a relatively high utilization rate through the physical plant. And that was really part of the design of Phase 1 was to ensure that with a long life, low decline deals like Alba, coupled with some third-party volumes, in this case Alen, that we would kind of bridge to that next set of opportunities and keep that facility utilized. And that — that’s been networks — that work’s completed. We now have another piece, the fantastic infrastructure and a pipeline that connects us with the Alen Field. So that phase is doing exactly what it was designed to do. As we look out ahead, Phase 2 is really dominated by really the shift in the commercial structure, which is less about really production volume and more about gaining more exposure to the global LNG market and the associated cash flow uplift that we’ll see from that, of course.

Even though we’ve seen a weakened gas environment, the reality is that the arbitrage between Henry Hub and global LNG pricing remains intact, and so that’s going to be a value uplift. And an additional element that we’ve kind of brought into play as part of Phase 2 has been the fact that we are evaluating the potential for some Alba infill drilling opportunities, which have the potential to mitigate some of that base decline, but also allow us to move equity — high-value equity molecules through the E.G. LNG facility. And just for clarity, we’re still in the early days in that evaluation, but these are going to be — this is relatively shallow water. This is jack-up drilling, dry trees, so when you think about it from a capital standpoint, there is not — these are not going to be material movers in our capital budget.

That will also be kind of phased out in time. And the test for those is just making sure that those do compete head-to-head with the opportunities, of course, that we have here in the U.S. So that’s a little bit of an addition that we weaved into the story this quarter. And then, finally, when you get to Phase 3, this is again looking at third-party molecules coming from that broad kind of Alen-Aseng area, this is a gas cap associated with the Aseng Field that, of course, is operated by Chevron, just like the Alen is, and it’s our view that we will be the monetization path for that, and that was part of the HOA that was signed with E.G. and other relevant parties. The positive there is all of that work, Phase 1, Phase 2 and Phase 3, really extends us out through into the next decade.

So it gives us this runway to now advance additional opportunities. So what could be beyond Phase 3? Well, we talked about and I mentioned in my opening remarks the bilateral agreement between E.G. and Cameroon, that opens up the aperture to cross-border opportunities. And quite frankly, as I said in my remarks, this is one of the most gas-prone areas in West Africa. There’s a numerous discovered, undeveloped opportunities that E.G. LNG could provide a very efficient and profitable monetization route.

Arun Jayaram: Great. Thanks a lot, Lee.

Operator: And our next question comes from Scott Hanold from RBC. Please go ahead with your question.

Scott Hanold: Yes, thanks. Just turning to the Permian, the results looked pretty impressive. And my question would be — is, can you talk about the depth of inventory and the sustainability of those extended laterals? And how do you kind of look at this play going forward? I mean it seemed like it was complementary to kind of the overall asset base, but it does seem like now it’s got the ability to really step up and be a bigger part of the portfolio. So is — what’s the depth of that inventory look like? And are you guys looking at opportunities to add to that acreage position?

Mike Henderson: Hi, Scott, it’s Mike here. I’ll hopefully answer that question for you. In terms of the runway that we’re looking at, at the current consumption rate, current activity rates, I think we’ve disclosed publicly that you’re looking at almost two decades or up to two decades of — maybe even more than two decades of potential inventory there. So that maybe gives you a fuel for what we could be looking like in the future. And you’re absolutely right, based on the performance that the team has delivered there, not only from a well productivity perspective, but from an execution perspective as well, I mean, some of the drilling completion results that the team’s delivered since they’ve got back to work in the middle of last year, absolutely competing for capital.

And I would remind you that while maybe the completion activity, wells to sales is from and Permian. We do have a pretty heavy drilling program this year, which will then set us up well for 2024. So we’ve kind of preempted this a little bit in terms of the performance with the additional drilling. We’ve been looking for those wells. We’re not probably going to see those wells coming to sales until the early part of next year. But you’re absolutely right, based on the performance that we’ve seen since getting back to work there, that asset is definitely going to be competing for capital as we go forward.

Lee Tillman: Yes. And if I — maybe if I could just jump in for a minute as well, one thing I want to highlight is that, in the Permian numbers now, we have fully integrated what we refer to as the Texas Delaware oil play, the Woodford-Meramec oil play and it’s been very successful for us. It has now migrated for more of an exploration play into really part of our base capital allocation within the Permian Basin. And so that’s another tranche of inventory that has now moved in to that asset team. And that’s unique in the sense that, I’ll just remind everyone that our Permian and Oklahoma teams, they are integrated teams. And so it makes absolute natural sense for that Woodford-Meramec play to migrate into a team that already has such broad experience in how to develop those two zones.

To your other question around acreage addition, what I would say to that is that our M&A framework remains unchanged. And if anything, the addition of Ensign probably rates that are even further. We still look at everything within our core basins. But I would just tell you that today, we don’t see anything in the market that really satisfies what is a very demanding M&A criteria.

Scott Hanold: Got it. And just to clarify one thing on — you said there’s two decades of inventory there. Are those extended lateral? Are those two decades of extended laterals?

Mike Henderson: Pretty much, Scott. There’s maybe — it maybe tails off to the back end, but predominantly extended laterals. And quite frankly, the team have been very active converting some of those smaller SLs to XLs. So maybe some of those SLs that are at the back end of the portfolio at the moment. Expectation is that we’d be looking to convert those to longer laterals over time.

Scott Hanold: Okay. Understood. And then, my follow-up question is going back to E.G. again. Thinking about the contract kind of rolling over at the end of this year, how are you positioning for that? Like, what steps are you taking right now to look at what is the best way to kind of optimize it going forward? Do you expect to sign some sort of a hard longer-term contract? Or do you want to keep it more open and flexible just to be more opportunistic with it? But just give us a sense of how you’re looking at setting up the pricing dynamics starting in 2024.

Pat Wagner: Hi, Scott, this is Pat. I’ll take that one. Yes, obviously, we’re getting ready to market on January 1, 2024. We will be going to market shortly with an RFP for global LNG providers. And that will be, as Lee has said, linked to global LNG prices, what marker is still to be determined, but we’ll have a big process through that and expect to tie up those contracts probably in Q3.

Scott Hanold: Understood. Thanks.

Lee Tillman: And I — Scott, there’s still details to be worked out there, but we believe that there will be competitive tension in the market for such an advantaged set of LNG cargoes that are proximal to the European market.

Scott Hanold: Right, right. What is that cost benefit do you think relative to, say, like U.S. — shipping U.S. volumes?

Lee Tillman: Well, I think we look at it through the lens of kind of how does that look relative to where we stand today. And when you think about the movement — the bulk movement from a Henry Hub link to a global LNG link, I mean, the torque there, regardless of where absolute gas pricing goes is going to be pretty significant. I mean you’re going to be talking about 2x or 3x kind of uplift as you move to a more index — global index contract..

Scott Hanold: Understood. Thanks.

Lee Tillman: Thanks, Scott.

Operator: Our next question comes from Doug Leggate from Bank of America. Please go ahead with your question.

Unidentified Analyst: Hi, good morning, guys. This is actually on for Doug. I’ve got a couple of follow-ups on E.G. First one, can you discuss what your decline rate is and what the infill drilling opportunity could do to stem that decline? And secondly, you guys highlighted that there will be a turnaround or a turnaround has been completed and that’s going to improve the uptime. What does that mean for volumes in ’24? And does that simply means less downtime? Can you qualify what that downtime is that we’ve avoid it? And I’ll leave it there. Thanks.

Lee Tillman: Yes. Well, maybe to start off with the decline question. I mean, our nominal decline in E.G. is about 10% per year, so that’s really where we land. There’s no doubt that an Alba infill program will help mitigate some of that decline. It’s probably too early to talk about the contribution and the amount of offset until that program is fully defined and ultimately funded by the partners. With respect to the turnaround, that’s really a triennial turnaround. It’s very comprehensive. It occurs usually every three to four years. It’s both onshore and offshore, so it’s a very comprehensive turnaround. And really, that’s protecting uptime performance that’s already world class at E.G. LNG. This is recognized as one of the best operating, most reliable facilities globally in the LNG market.

And we’re really investing to continue to protect that exceptional uptime performance that that team delivers really each and every year. And so this really is that investment. And it becomes even more important as we transition into this commercial phase where we’re going to be leveraging much more heavily global LNG prices through the Henry Hub. So it’s very fortuitous. It’s beginning that turnaround done during low gas prices and while we’re still linked to Henry Hub contracting.

Mike Henderson: Yes, Clay, I’ll speak about a little bit more color. We’re looking at 99% plus uptime there from the facilities in E.G. So as we pointed out, it’s really about protecting that uptime as we get into next year specifically.

Unidentified Analyst: I appreciate it, guys. Thank you.

Operator: Our next question comes from Neal Dingmann from Truist. Please go ahead with your question.

Neal Dingmann: Hi. Thanks for the time. My first question, maybe for Lee or Mike, just on Ensign, just wondering now that you’ve operated the asset for just a brief time. Can you speak to any thoughts or changes on how you think the asset will compete for capital versus the legacy assets? Both are good, so I’m just curious how they’ll compete.

Mike Henderson: I mean, obviously, super, super happy with how the integration’s gone, ahead of schedule, no surprises, everything’s positive. You saw the well results that we put at, I think it’s in Slide 12 of the deck. Top- decile performance there on oil basis within the basin. I think it’s a little bit too early to say in terms of a view of what that does from a capital allocation perspective. But I think first impression is very, very positive, and if we are going to be doing anything from a capital perspective, it feels like we may be allocating more in the future, but a little bit early just to get too definitive on that.

Neal Dingmann: forward to see what you can do with it, Mike. And then, second question just on OFS inflation. I’m just wondering if you could speak to any potential — not only potentially some softness that some others have spoken about, but any specific areas, either domestically or E.G. that you might be seeing.

Mike Henderson: Yes, I’ll take that one again, Neal, maybe just start with a reminder. Our 2023 guidance, we did incorporate about 10% to 15% inflation compared to 2022. And what we were assuming was the cost environment through 2023 would be comparable to the fourth quarter of 2022. We didn’t assume any deflation over the second half of the year. We did assume a little bit of moderation in steel pricing, which we’re actually starting to see. What I’d say we’re seeing at the moment is maybe a general flattening or plateauing of service costs. What we are definitely seeing is the access side. That has definitely improved. And that could potentially lead to maybe some improved pricing later in the year. As I look at the specific or the larger areas of spend, start with maybe rigs, I think we’ve all seen the softer guidance and activity that the publics have come out within the second quarter again, could lead to some modest softening in the rig rates later in the year.

Pressure pumping market access certainly improved, but I still think it’s a little bit early to make the call on where rates potentially go in the second half of the year. And as I mentioned, steel pricing is definitely trending lower there, and that’s pretty consistent with just the general softness that we’re seeing in all of the commodities. One point I would make is with the improving market access situation and the contracting flexibility that we’ve got in the second half of the year, we’ve actually already been able to hybrid in a few areas of the business. So for example, we get more experienced crews, we’re getting better equipment. That was something that couldn’t happen five, six months ago. So I’m pro with painting a somewhat positive trend there.

I would just caution, it does feel a little bit too early to be counting in deflation in the second half of the year. I think, particularly just when you think about the volatility of the backdrop that we face at the moment.

Lee Tillman: Yes, I think that, if I could just jump in, Neal. I think that we intentionally left commercial and contractual flexibility in the second half of the year such that we would have the opportunity to take advantage of any softening in the market. However, we took no credit for that within the budget. So as Mike said, our budget fully reflects inflation across the full year. So if we were to see more softening, that would certainly be perhaps a bit of a even a tailwind in the second half of the year.

Neal Dingmann: That’s great detail. Thanks, guy.

Operator: Our next question comes from Matt Portillo from TPH. Please go ahead with your question.

Matt Portillo: Good morning, all. Maybe just starting out in the Permian, you turned in line an additional four wells in the Texas Delaware. Looking at the state data over the last few years, that’s been an area that’s been quite surprising in terms of well performance. Curious if you could give us any color on the early time performance from these wells, and also just updated thoughts on the spacing design. I know you guys are working on some tests, but may be a bit too early to infer anything, but just curious how you all are thinking about the spacing design going forward.

Pat Wagner: Matt, this is Pat. I’ll take that one. Yes, as you said, we brought on four wells in the first quarter. I would characterize those wells as performing in line with pre-drill expectations. This is a reminder for everyone. I think we heard this a little bit last call. This was a down spacing test, so we did three wells in the Woodford at 880-foot spacing and one Meramec about 650 feet above those kind of between two of the wells. So the key takeaway from early time in this pad is that the wells are — they’re acting just like the other wells, strong oil production, high oil cuts, low oil ratio and already low decline that we’re seeing. The other key takeaway is that there’s been no communication between the Woodford and the Meramec, which gives us a lot of confidence about co-development moving forward.

We do now have 13 wells online across our 55,000 acre blocking position, nine of the Woodford and four of the Meramec. And as I said, we’re very confident now in productivity and we’ve moved it into the Permian asset team and fully integrated it there. In terms of future development, this was a down spacing test. I think our early learnings is that we’re going to probably pursue a 4×4 co-development, which will maximize capital efficiency. But there’s such a large volume of oil in place in the Woodford, we’re going to continue to look at maybe a little bit tighter spacing in the Woodford, and just as we drill the next pad, we will look at that again.

Lee Tillman: Maybe if I could just add too, Matt, we were really a first mover in this kind of combination Woodford-Meramec oil window and we were able to essentially amass a 55,000 net acre continuous position at relatively low cost at 100% working interest. And of course, now we see other operators are starting to get more active in both the Woodford and the Meramec. And I think that all is constructive and supportive of kind of what we’ve been saying all along. And we believe that that this asset can compete for capital allocations. One of the key reasons we’ve now integrated it in with the Permian is we believe we’re out of the exploration phase and really moving into that developmental phase.

Matt Portillo: Perfect. And then, just as a follow-up question, just wanted to clarify on the color for the volume cadence for the year. You guys gave context on Q2 and Q3, which is quite helpful. Just curious as we look towards the second half of the year, I know you’ve got a heavy fill program in the Eagle Ford in Q1 and Q2. And it looks like the Permian. For the most part, will wrap up from a TIL perspective in the first half as well. Any additional color you might be able to provide into Q4 as we should think about volume cadence? I know you gave some color there on Q3, but just trying to figure out how we should be thinking about the back half of the year in general.

Lee Tillman: Maybe let me jump in on that one, Matt. I think as Mike mentioned in his opening comments, we expected first quarter to be right where we landed at, the 186,000. Our guidance for second quarter is right around the midpoint of the full-year guidance. But we do see second and third quarter being an increasing, if you will, oil production trend moving forward, which is really reflective of the capital program. Having said that, our full-year guidance remains intact and — on both the oil and OEB basis. And so that profile will, in fact, generate those midpoints that we provided. And we also are very mindful, of course, of making sure that we maintain momentum as we start thinking ahead to 2024 as well.

Matt Portillo: Thank you.

Operator: Our next question comes from Scott Gruber from Citigroup. Please go ahead with your question.

Scott Gruber: Yes. Good morning. I actually want to come back to the theme of the future opportunities, maybe look out a little bit further. But as we contemplate the growth potential for gas demand along the Gulf Coast, we may need more than just the Haynesville and associated out of the Permian and Eagle Ford. Do you guys have a good sense for the economics in the dry gas window of the Eagle Ford? It’s deeper, so the wells are going to cost more, but wondering whether you have a sense of the breakeven.

Lee Tillman: Yes, well, certainly, as we look at the complete inventory in all of our basins, dry gas today is at a bit of a disadvantage, both pricing and as you say cost, as you get into some of these areas of these plays, the drilling and completion costs will get quite high. We also have, of course, dry gas optionality within our Oklahoma position as well. And that’s a good example. I think, Oklahoma, we put in place a JV structure in Oklahoma that allows us to protect our acreage, keep our crews operating, and in general, be prepared if we do find that we see a more favorable environment for gas production and these combo plays that do rely a bit more heavily on both gas as well as NGLs. But the JV program is a good example of how we’re really keeping everything warm and ready to go.

So I don’t think that gas question is necessarily limited to the Eagle Ford. I think it could apply to Oklahoma as well. And we just need to be ready with opportunities when that makes sense. It’s all going to be done based on return and capital. I mean, I won’t say we’re completely agnostic on commodity. But at the end of the day, it’s going to be driven by economics.

Scott Gruber: Yes, no, of course. It’s good to highlight the Oklahoma position. I’m just thinking about kind of with gas prices depressed here near term, but given the potential demand recovery and future growth, whether it’s worthwhile to contemplate building out a acreage position kind of further south from the inside position, or is that — I know you guys have a lot on your collective plate today. Just wondering whether that’s on the radar or not.

Lee Tillman: Yes. Well, I think you’re right in the sense that there’s, certainly, there is more gas optionality. Even though we’re getting a lot of oil production from Ensign, it also brings significant gas with it as well, particularly in this very strong condensate window. But there are dry gas opportunities within Ensign as well that we could certainly look to exploit in the future. I do think, though, if you just step back, Scott, when you think about our portfolio today, we’re generally kind of a 50% oil, 50% gas and NGL company. And we like that balance and we like that commodity price exposure. So we want to be very mindful of just, again, at an enterprise level, keeping that balanced exposure to the kind of the full commodity price.

And that even includes our E.G. assets, which, of course, have a different kind of commodity price exposure and that they’re exposed to both Brent on the condensate side, and then right now, clearly linked into global LNG. And in the future, that linkage is even getting stronger.

Scott Gruber: Got it. Appreciate the color, Lee. I’ll turn it back. Thank you.

Lee Tillman: Thanks, Scott.

Operator: Our next question comes from Umang Choudhary from Goldman Sachs. Please go ahead with your question.

Umang Choudhary: Hi, good morning and thank you for taking my question.

Lee Tillman: Good morning.

Umang Choudhary: Hi. My first question is on just on the international gas price outlook. Clearly, the arb between international gas and Henry Hub is very attractive today. But would love your thoughts, if you see any risk to those arbs with the sharp build out in LNG capacity through 2027?

Lee Tillman: Yes. Without trying to look too deeply into the crystal ball, one of the things that we never want to pretend to do is to predict pricing going forward. But what I will say is that the world certainly needs more energy. A lot of power generation is going to still lean heavily on gas and in Europe, that’s likely going to be LNG. There are LNG projects that are coming on in the second half of this decade that I think will start to meet that demand, but demand is growing. And so U.S. LNG as well as global LNG, we believe will still be in strong demand. And I think that that arbitrage will still be in play, certainly, between Henry Hub and global LNG linked contracts. So even if we see volatility in the absolute gas pricing, we think that arbitrage will still remain intact. And certainly, when you look at Europe today and you look at the dynamic there, we still believe that’s going to be a strong market for LNG in the future.

Umang Choudhary: Got it. Very helpful. Thank you. And then just given the weakness in natural gas prices today, as we think through your plan, I was wondering if there’s any flexibility to shift more towards any liquids-rich drilling away from a more-gassier areas.

Lee Tillman: Yes. Well, the reality is that we’ve already optimized our plan around that outcome. As I mentioned, we have a very balanced program at an enterprise level. But the reality is that our program is a very oil-weighted program in terms of capital allocation. The bulk of our capital allocation is flowing to our black oil basins, which are the Eagle Ford and the Bakken. So — and that’s, again, going back to that Oklahoma JV, we recognized that early on. And so rather than spending our operated capital there, we’re basically leveraging the funding of others for that very reason. So we believe the program is already optimized around the commodity pricing that we’re seeing today, and we feel very good that it’s going to generate extremely strong returns.

Umang Choudhary: Thank you. Thanks for taking my questions.

Operator: And ladies and gentlemen, with that, we’ll be concluding today’s question-and-answer session. I’d like to turn the floor back over to Lee Tillman for any closing remarks.

Lee Tillman: Well, thank you for your interest in Marathon Oil. And I’d like to close by again thanking all our dedicated employees and contractors for their commitment to safely and responsibly deliver the energy the world needs now more than ever. Cannot be prouder of what they achieve each and every day. Thank you. And that concludes our call.

Operator: Ladies and gentlemen, with that, we’ll conclude today’s conference call and presentation. We thank you for joining. You may now disconnect your lines.