Marathon Oil Corporation (NYSE:MRO) Q4 2023 Earnings Call Transcript

Marathon Oil Corporation (NYSE:MRO) Q4 2023 Earnings Call Transcript February 22, 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 morning and welcome to the Marathon Oil 4Q and Full Year 2023 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Guy Baber, Vice President, Investor Relations. Please go ahead, sir.

Guy Baber: Thank you very much and thanks 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 packet that address our fourth quarter 2023 results and our full year 2024 outlook. 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, our 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. 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 prepared remarks, we’ll move to a question-and-answer session. And in the interest of time, we ask that you limit yourselves to one question and a follow-up. Lee?

Lee Tillman: Thank you, Guy, and good morning to everyone joining us on our call today. As I always start these calls, I want to first and foremost thank our employees and contractors for their dedication and hard work in delivering the excellent results we have the privilege of discussing today. And I especially want to thank our employees and contractors for their enduring commitment to our core values. On that front, we have a few notable accomplishments to highlight today. First, we delivered a record safety year in 2023 as measured by total recordable incident rate for both our employees and our contractors. This builds on a multi-year track record of top quartile TRIR in our industry. Providing a safe, healthy, and secure workplace remains a top priority for us.

With our safety performance a key element of our executive and employee compensation scorecards. Second, we continue to make progress in reducing our natural gas flaring, improving our total company gas capture to 99.5% in 2023, a new high for our company. We’ll continue to work hard on our journey of continuous improvement, moving toward our ultimate objective of zero routine flaring. And third, we achieved our 2025 GHG intensity reduction goal of 50% relative to 2019 levels a full two years ahead of schedule. Consistent with our objective to help meet the world’s growing demand for oil and natural gas, while achieving the highest standards of environmental excellence. We are a result driven company, but how we deliver those results matters and I couldn’t be more proud of our people and what they’ve accomplished.

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Q&A Session

Yet this type of delivery isn’t new for us. It’s the continuation of a well-established trend. And before I get into our 2023 results and 2024 outlook, I’d like to reflect on what I believe is our unmatched track record of delivery on our framework for success. We’re now more than three years into our more S&P less E&P journey. My challenge for our company was to raise our game and compete heads up with not just the best companies in our sector, but with the best companies in the S&P 500. And to do so year in, year out, through the commodity cycle on the metrics that matter most. Sustainable free cash flow generation, return of capital to shareholders, and capital and operating efficiency. For the last three years, we consistently held true to our framework for success.

We’ve prioritized corporate returns, sustainable free cash flow, meaningful return of capital, and we delivered differentiated execution quarter in, quarter out. We continue to enhance our multi-basin portfolio, which has produced the best capital efficiency in the sector. And we protected our investment grade balance sheet while prioritizing all elements of our ESG performance. I believe our commitment to our strategy and the consistency of our execution over the last three years have successfully differentiated Marathon Oil in the marketplace. The proof points are summarized in slide six of our deck. First, sustainable free cash flow generation. Through discipline, corporate returns, focused capital allocation, we’ve generated $8.4 billion of free cash flow over the trailing three years.

That equates to over 60% of our current market cap, almost double that of our E&P peers and six times that of the S&P 500. Next, a meaningful return of capital to shareholders. Over the last three years, we’ve consistently held true to our transparent cash flow driven return of capital framework that prioritizes our investors as the first call on cash flow, not the drillbit and not inflation. In total, we’ve returned $5.6 billion to our shareholders, equivalent to over 40% of our current market cap. Again, that’s double that of our E&P peers and well in excess of the S&P 500. Capital and operating efficiency, a testament to the quality of our multi-basin portfolio and the extreme discipline inherent in both our capital allocation and cost structure.

Over the trailing three years, we’ve delivered the lowest reinvestment rate in the E&P sector, below the S&P average. And our well-level capital efficiency, according to independent third-party data, has been the best in the E&P’s peer space, 35% superior to the peer average. And 2023 was emblematic of these three proof points. Last year, we delivered $2.2 billion of adjusted free cash flow, $1.7 billion of shareholder distributions, equivalent to 41% of our CFO, providing a shareholder distribution yield of more than 12%. $1.5 billion of share repurchases that drove a 9% reduction for our outstanding share count, a 22% increase to our base dividend while maintaining our peer low, free cash flow break-even, $500 million of gross debt reduction, and 28% growth in our production per share, driven by our share repurchase program and the seamless integration of the Ensign Eagle Ford acquisition.

That’s what comprehensive delivery on our key properties looks like. And if you like 2023, then you will not be disappointed in our 2024 business plan, which offers more of the same as we continue to build on our multi-year track record. We have confidence in our strategy and in our capital allocation and return of capital frameworks and our focus will be on consistently executing our plan amidst all the volatility inherent in our sector. And at the end of the day, I expect our plan to again benchmark with the very best companies in our sector outperforming the S&P 500. More specifically, this year, we expect our $2 billion capital program to deliver approximately $1.9 billion of free cash flow, assuming $75 WTI, $250 Henry Hub and $10 TTF.

We fully recognize that we are a price taker, not a price predictor and commodity price volatility impacts our financial outcomes. As such, we’ve provided cash flow sensitivities for each of the key commodities within our slide deck to help you model expectations based on your own commodity forecast. We’ll stay true to our CFO return of capital framework, expecting to return at least 40% of our CFO to shareholders, again, providing visibility to a double-digit shareholder distribution yield. We expect the underlying capital efficiency of our 2024 capital program to improve as we maintain our well productivity leadership and work all avenues to improve capital efficiency, including further extending lateral links. And perhaps most importantly, we believe our results are sustainable.

That’s true for our U.S. multi-basin portfolio, and that’s true for our integrated gas business and E.G. As you all know, our E.G. business now has no Henry Hub exposure with the expiration of our legacy contract at the end of 2023. That business is now fully realizing global LNG pricing, which will drive improved financial performance this year. We believe this improvement is sustainable due to all the great work our team has done to advance the E.G. gas mega hub concept. For example, over the next five years, we’re expecting our E.G. business to generate cumulative EBITDAX of approximately $2.5 billion, assuming flat $10 TTF commodity price. With that, I’ll turn it over to Dan, who will walk through our commitment to return of capital while also fortifying our investment grade balance sheet.

Dane Whitehead: Thank you, Lee, and good morning, everybody. As Lee mentioned, in 2023, we continued building on a peer leading track record of returning capital to shareholders as consistent with our differentiated cash flow driven framework that prioritizes our shareholder as the first call on capital. Importantly, we did this while continuing to make progress on our balance sheet objectives through $500 million of gross step reduction. We’ve built a track record of providing a truly compelling shareholder return proposition, while at the same time continuing to enhance our investment rate balance sheet. We did both in 2023, and that’s my expectation again for 2024. More specifically, on our 2023 return of capital delivery, total shareholder returns amounted $1.7 billion, including more than $400 million during the fourth quarter.

That translates to 41% of our CFO consistent with our framework, and an annual distribution yield of over 12% on our current market cap, compelling relative to any investment opportunity in the market. The majority of shareholder returns came in the form of share repurchases, which reduced our share count by 9% last year. That’s about double the share count reduction of our next closest competitor. For full year 2023, we grew our oil production per share by a peer leading 28% due to our share repurchase program and the integration of the accretive Ensign acquisition. Looking to 2024, we expect to prioritize free cash flow via our disciplined capital allocation framework by holding our top line oil production flat. We also remain focused on driving significant per share growth and fully expect to maintain our long held leadership position in the peer group.

While the majority of our capital returns 2023 came in the form of share repurchases, our base dividend remains foundational and we remain committed to paying a competitive and sustainable base dividends to our shareholders. During 2023 we raised our base dividend by 22%, one of the strongest growth rates in our sector. Importantly, we did so with laser focus on sustainability, maintaining one of the lowest post dividend free cash flow break-evens in the peer group. Our consistent and committed approach to shareholder returns over the last three years has positively differentiated our company and our approach in 2024 will remain the same. Priority number one remains consistently delivering returns of at least 40% of our CFO in the form of share of purchases and base dividends.

That minimum 40% level translates to about $1.6 billion of expected shareholder distributions at a reference price deck, again providing visibility to a compelling double-digit shareholder distribution yield. With our stock trading in the low $20 per share range and at a free cash flow yield in the mid-teens at strip pricing, repurchases remain highly value accretive. They’re also a very efficient means to continue driving our per share growth and are highly synergistic with continuing to grow our per share base dividend without negatively impacting our peer leading free cash flow break-even. To summarize our 2024 return of capital plans, at least 40% of our CFO to shareholders which will be near the top of our sector, driving peer leading per share growth and competitive sustainable growth in our base dividend.

We’re also committed to further improving our investment grade balance sheet and we plan to direct excess cash flow to continue reducing gross debt. We have tremendous financial strength and flexibility in our capital structure with net debt to EBITDA approximately one times at strip pricing. We have $400 million of tax exempt bonds that mature this year. This is a really unique vehicle in our capital structure and will likely remarket those at an advantaged interest rate relative to taxable debt as we’ve done previously. We also have plenty of flexibility to manage the 1.2 remaining outstanding on our Ensign term loan due at the end of this year. The markets are wide open for us to potentially refinance a portion of that debt and as a reminder we have $2.1 billion available capacity on our credit facility that matures in 2027.

And even if we opt to refinance in total the maturing tax exempt bonds and the term loan, we will retain capacity to payoff at par almost $1.5 billion of commercial paper and bonds which would get us to our medium term gross debt goal of $4 billion. One final comment for me on our ’24 outlook before I turn it over to Mike to walk through some of the details of our capital program. Consistent with our prior messaging, our 2024 financial guidance assumes we’ll transition to becoming an alternative minimum tax, or AMT, cash taxpayer this year. The AMT tax rate is 15% on our pre-tax U.S. income. Our primary exposure here is domestic as our E.G. income will largely be offset by current year foreign tax credits. The new information we’re providing today involves research and development, or R&D, tax credits.

We recently completed a study of capital spent in past years on organic enhancement activities that qualified for R&D tax credits. As a result, we expect to apply approximately $150 million of these R&D tax credits this year as a direct offset to a significant portion of our 2024 AMT cash payments. A direct benefit to our free cash flow is most likely not included in any sell-side models at this point. With that, I’ll hand over to Mike who will walk us through the final points of our 2024 capital program.

Mike Henderson: Thanks, Dane. As we highlighted earlier, we’re a results-driven company. So I’ll start with the expected bottom-line results of our 2024 capital program. We expect our $2 billion capital program to deliver $1.9 billion of free cash flow with one of the lowest reinvestment rates and free cash flow break-evens in the sector. This will enable us to deliver our investors a truly compelling shareholder return profile. We fully anticipate these bottom-line financial outcomes and the underlying capital efficiency of our 2024 program to again benchmark at the very top of our high-quality E&P peer group. To deliver these outcomes, we’ll operate approximately nine rigs and four frac crews on average this year. We expect our capital program to again be first half weighted with about 60% of our CapEx concentrated in the first half of the year, largely a function of the timing of our wells to sales.

This should drive stronger production and underlying free cash flow over the second half of the year. At the midpoint of our full year guidance we expect to deliver flat total company oil production approximately 190,000 barrels of oil per day consistent with what we previewed last quarter. Yet importantly, as Dane highlighted, we fully expect to continue driving significant growth in oil production on a per share basis. We’re guiding to a modest year-on-year decline in our oil equivalent production this year. This BOE decline is largely a function of well mix and our focus on value over volume. Given the extreme weakness in natural gas prices relevant for oil, we’re allocating capital to the oiliest and thus highest volume areas in each of our plays consistent with our prioritization of corporate returns and free cash flow generation.

We’re also expecting some modest ongoing base decline in Equatorial Guinea. As is typical for our business and consistent with last year, there will be some quarter-to-quarter variability in our production. First quarter should mark the low point for the year impacted by about 4,000 barrels of oil per day of winter weather-related outages largely concentrated in the Bakken. We’ll then grow from first quarter levels as we bring more wells to sales as the year progresses. Now to the more important details of our 2024 program. We expect to deliver our flat oil production guidance with 5% to 10% fewer net wells to sales than last year. This is a function of improving underlying capital efficiency driven by durable well productivity at peer leading levels, an additional 5% increase to our average lateral lengths and modest deflation recapture that is built on conservative underlying assumptions.

Approximately 70% of our total capital will be allocated to our high confidence Eagle Ford and Bakken programs where we have a demonstrated track record of execution excellence. For 2023, external state data indicates we delivered six months per foot oil productivity 60% better than the basin average in the Eagle Ford and 40% better than the basin average in the Bakken. With our cost structure, we believe we’re leading each basin in capital efficiency. We expect another year of leading performance in 2024 as we maintain our productivity advantage and find ways to continue enhancing our capital efficiency. The bulk of our remaining resource play spend will be dedicated to the Permian where we’re increasing our activity and capital investment in a disciplined manner.

Since getting back to work with a consistent D&C program in the Permian a couple of years ago, we’ve delivered among the best well productivity in the basin with competitive drilling completion performance for transitioning to an almost exclusive two-mile-plus lateral program. This year over 20% of our Permian wells will be three-mile laterals. We’ll get into more details in E.G. in a minute, but our E.G. CapEx will be up modestly this year with spend limited to long lead items in preparation for potential Alba infill program in 2025. Our non-developing capital is higher this year to large-late to more environmental regulatory and emissions-related spending, as well as some nonrecurring projects such as water infrastructure and pipeline additions.

For context, a couple of years ago this bucket represented about 5% of our total capital. It’s about 10% this year. Importantly, however, we expect our non-D&C capital to peak this year and to trend lower in 2025. I would also add that many of those projects designated as emissions-related have the added economic benefit of enhancing our reliability and uptime performance. Now to Lee for E.G. and the wrap up.

Lee Tillman: Thank you, Mike. Focusing on slide 15 in our deck with the expiration of our legacy Henry Hub linked LNG contract at the end of last year, our E.G. integrated gas business is now fully realizing global LNG pricing, and in January we lifted our first cargo under these new contractual terms. Consistent with our prior disclosure, the majority of our Alba LNG sales are covered by the five-year sales contract we announced last year. That contract is TTF linked. The balance of our 2024 LNG cargos have now all been contracted, but at a JKM price linkage. This will afford us a nice combination of both TTF and JKM price exposure this year. Although, global LNG pricing has weakened somewhat on warmer winter weather, the arbitrage between global LNG and Henry Hub pricing is still significant and therefore should still drive improved financial performance for our international operations.

We’re guiding to $550 million to $600 million of E.G. EBITDAX this year, assuming $10 TTF, that’s a significant increase from actual 2023 EBITDAX generation of $390 million. Importantly, we don’t expect this to be a one year financial uplift. For some time we’ve been focused on sustaining this improved financial performance by progressing all elements of the E.G. gas mega hub concept supported by the HoA signed with the E.G. government and our partner last year. The five-year E.G. EBITDAX outlook we’re providing today is intended to demonstrate the sustainability of our E.G. cash flow generation. Over the next five years, we expect to deliver cumulative E.G. EBITDAX of approximately $2.5 billion, assuming $10 TTF and $80 Brent flat. Beyond realizing global LNG pricing, there are a few drivers of the strong performance over the duration of the five-year period.

They include, ongoing methanol volume optimization to maximize higher margin, higher working interest LNG throughput; an Alba infill well program, which will help mitigate Alba decline and maximize the amount of Alba equity gas through the LNG plant in coming years; and further monetization of third-party gas through the Aseng gas cap as we continue to take full advantage of our unique and highly valuable gas monetization infrastructure in one of the most gas prone areas of the world. And while this five-year EBITDAX scenario reflects the life of our recent global LNG sales agreement, we fully expect to extend the life of E.G. LNG beyond the next five years, well into the next decade as we continue to advance the longer term gas mega hub concept.

In summary, consistent with our more S&P mandate, for the last three years, we’ve been 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. 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. Sector leading growth in first share metrics, and a multi-year track record of consistent execution and proven discipline.

And perhaps most importantly, everything we’re doing is sustainable 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. It’s also due to our differentiated integrated gas business that’s now fully realizing global LNG pricing as we continue progressing 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 the line for Q&A.

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our next question comes from Arun Jayaram with JP Morgan Chase. Please proceed.

Arun Jayaram: Good morning, Lee. Lee, I wanted to start off with an M&A, obviously a significant level of industry M&A activity, including a large transaction announced in your Bakken backyard last night. I was wondering if you could provide some perspective on how should we think about M&A for MRO post the Ensign transaction, and I did want to cite a recent example of a low cost Permian producer as a low cost structure such as yourself did announce a deal to get more scale in the Permian, adding more sticks on the map and the multiple appears to rerated it on that deal. So again, just some thoughts on where the M&A landscape and what this means for MRO.

Lee Tillman: Yeah. Thank you, Arun. First of all, size and scale are important, but it’s not obviously just about getting bigger, it’s about how do we get better. So any consolidation opportunity fundamentally needs to enhance our ability to execute on the path that we’ve been on really for the last three years that I just described in my opening remarks. We have a very clear, very transparent framework for assessing M&A. That framework is unchanged, and if anything, the bar is even higher now with the successful addition of the Ensign asset that you mentioned. And just as a reminder, Arun, there really five elements of that criteria. First and foremost, of course, is accretion to financial metrics. Secondly, accretion to our cash flow driven return of capital framework.

Third, accretion to our resource or inventory life with inventory that competes for capital from day one, clear industrial logic, which to us means going into basins where we have a well-established level of execution, excellence and credibility. And then finally, of course, doing all this without any harm to our investment grade balance sheet. We know that’s a challenging criteria, but we can be discerning and we can be patient. As I mentioned, with over a decade plus of high quality inventory, we can wait for those opportunities like Ensign that ticks all the boxes and that’s what made Ensign so compelling. I mean, we integrated that asset into our operations and essentially a couple of months, Mike and his team did a fantastic job doing that.

We never missed a step and we’ve seen others stumble in that very critical integration step. So, can we be acquirer? Absolutely. Should you expect us to still apply our criteria and be a discerning and be as disciplined as we are in our organic business? Absolutely.

Arun Jayaram: Great. My follow up is on E.G., Lee. You provided a five-year outlook, which suggests relatively stable earnings profile or EBITDAX relative to your 2024 guide. I was wondering if you could talk about opportunities to extend these financial outcomes in E.G. beyond the five-year threshold. As well as I was wondering if you could address the recent decision by a super major to exit E.G. And does that open up any opportunities for you given that country exit?

Lee Tillman: Absolutely. Well, first of all, I want to be very clear, the five-year view we provided was really just a scenario that matched up with the LNG sales agreement that we just inked last year. And so you should not interpret that as a life of LNG kind of model. This was just to match up with that certainty that we now had around that five-year TTF linked LNG sales agreement. The reality is that when we look at all of the things that we have active now and E.G., whether that’s methanol volume optimization, the future — potential for Alba infill drilling and even more third-party molecules like Aseng, we already see the path to extend well past 2030. So, don’t view that five-year view as anything other than just matching up with, in fact, that five-year sales agreement that we inked on TTF.

In terms of exits, out of E.G. by super majors, clearly that’s a very unique set of circumstances where you have a concession that’s kind of at the end of its PSC term. It’s a very mature oil play there. And again, pretty much end of field life that likely is going to be taken over by the government and run by the government. So very different set of opportunities than we would look like. And again, I would just take you back, Arun, to the criteria that we just talked about and making sure that we look at any opportunity through that same lens when we’re talking about doing something inorganically. But we do believe there’s a lot of opportunity outside of that within E.G., both from an equity molecule standpoint as well as a third-party molecule standpoint.

And the good news for us is when we were able to bring the Aseng molecules to E.G. LNG, that was our first kind of third-party framework, we can now replicate that framework going forward, and that project constructed a very significant piece of infrastructure that we can now use for the future.

Arun Jayaram: Great. Thanks a lot.

Lee Tillman: Thank you.

Operator: Our next question comes from Neal Dingmann with Truist Securities. Please proceed.

Neal Dingmann: Morning. Nice update. First questions likely for Mike, on your — you mentioned — Mike, you referenced the leading operational efficiencies, which are noted. I’m just wondering, could you maybe give a little more detail? Is it largely the longer laterals or, maybe what other key drivers would you point us to that that’s really driving this remarkable upside?

Mike Henderson: Yeah. We all, Neal, I can certainly answer that. So yeah, underlying resource play capital efficiency as we noted is improving in ’24. And I highlighted a few things there in my prepared remarks, but I think it probably starts with that consistently strong peer leading well productivity. When I look at our ’24 productivity by basin compare it to ’23 and Eagle Ford, I would say ’24 is looking very comparable to what we delivered in ’23. When I look at the Bakken, I would actually say our productivity is up marginally in ’24 really on the back of — we are going to go Bakken, Myrmidon and complete a few wells there. And then the Permian, it looks pretty flat from ’23 to ’24. So I think that’s the first thing I would point to.

The second thing, as you noted was the longer laterals we mentioned in the prepared remarks, they’re up 5% at a company level. Eagle Ford, they’re up about 10% year-on-year. Even Bakken is up just notionally a couple of percentage points. And then you look at the Permian, they’re up by 10% as well. And that is a big part of that capital efficiency driver. And then the third part is we are forecasting a little bit of deflation, albeit very modest kind of low single digit numbers there.

Neal Dingmann: Makes a lot of sense. And then, my second question, Lee, maybe for you or Dane, just on capital allocation. I’m just wondering, is there anything that would cause you to move towards — more towards the variable dividends or do you believe your active buyback program continues to be most strategic? And maybe around that, I mean, how should we continue to think about per share of growth? Obviously as you keep buying the shares back, it really continues to ramp that nicely, so I’d just love to hear your comments there.

Dane Whitehead: Yeah. Hey, Neal, this is — good morning. This is Dane. I’ll take a first cut at it. So, the bottom line is expect our framework and sort of the mix of return vehicles to remain unchanged in 2024. We’ve set all along sort of variable dividend is a — it’s a third mechanism that it’s on the table, but it’s not front and center for us at this point. 40% return to shareholders is a very firm commitment. That’s our primary commitment for use of capital. Base dividend, I talked about the sustainability of that base dividend is critically important to us, so dividend increases will probably be driven by the pace of share repurchases as much as anything because that kind of keeps the post dividend break-even flat. And it’s — right now we’re peer leading in the low to mid 40s.

Share buybacks again at mid-teens free cash flow yield, super efficient vehicle. And as you noted, they drive that per share growth on a pretty significant basis. The second use of CapEx or of cash — available cash for us, and you saw us do some of it this year, is paydown debt. We paid down $500 million worth of debt last year. Our leverage levels are — we’re comfortable with, they’re like one time net at the EBITDA at strip pricing, but I’d like to get them down and we’ve stated, we’ve got $5.4 million of gross debt today. We’d like to drive that down to $4 million gross debt, which was the pre-Ensign debt level. And so we will continue to allocate some excess free cash flow in excess of the 40% return to further improving the balance sheet.

Neal Dingmann: Great details. Thank you both. Go ahead.

Lee Tillman: Yeah. Maybe I’ll just add one thing to that too. I think, the power of a consistent and meaningful share repurchase program, you really see that showing up in the growth and the per share metrics that really matter. If you just look at 2023, we took out 9% of our outstanding shares that was roughly double the next best in our peer group. And, of course, that translated into tremendous value growth on a per share basis for our shareholders. So we still believe in that. I mean, again, we kind of look through the cycle. It’s a program that we set in place and let it run we dollar average. And we think it’s very powerful. If you rewind all the way back to October of ’21 that 9% comes 27% of our shares outstanding that we’ve retired. So it’s been a very powerful program for us and we remain extremely committed. We still have $2.3 billion of outstanding authorization against the repurchase program with our Board of Directors.

Neal Dingmann: Great point, Lee. Thank you all.

Operator: Our next question comes from Matt Portillo with TPH.

Matt Portillo: Good morning, all. Two asset level questions that I wanted to run by you. I guess first in the Bakken. Looking at the early time results on Ajax looks quite encouraging from a production and productivity perspective. Just curious if you could talk about potentially your learnings on the spacing design here. And then also as you kind of look across your acreage position, how much of your Bakken acreage might be set up for three-mile development moving forward?

Mike Henderson: Yeah. I’ll answer that one, Matt. In terms of the spacing pattern there, it was in a kind of 5 by 0 spacing, so five wells in the middle Bakken and there’s no three forks opportunity down there. And as you probably know, that’s kind of down to the southwest of the Hector area where we’ve been pretty active the last couple of years. What I’d say in terms of maybe a read through probably feels a little bit early, don’t have a lot of data to share. Obviously, we’ve just brought three of the wells online, we’ve got some early production there. What I’d probably tell you this quarter may well change next quarter. So rest assured thought we’ll continue to work our land position there hard and if there are any opportunities to get more extended laterals, you could — you can expect us to be talking about those in the future.

Lee Tillman: I think one of the things I would add too, Mike, though, is that certainly — even though we’re still waiting for a little bit more longitudinal production data to declare victory. When you look at the total well cost per foot and the savings that we’ve already captured there, it’s very significant. So from an execution standpoint, we feel very good about the D&C performance. So as you said, early returns on the production side, very strong, but absolutely encouraging on the cost side, on the D&C side.

Mike Henderson: Matt, I’ll maybe provide a little bit of more color there. The first of the wells that we did execute on a TWC per foot basis, we’re looking at those be 25%, sorry, below comparable to milers. And I think you couple that with the early production, couple of thousand barrels of oil equivalent a day, 80% oil, the IPs will probably be not as stout as you might expect up in Hector, but I think you’ll get that volumes back over the long term. So as Lee pointed out, you take the well productivity with the well costs, I would like to think that that’s going to present a pretty compelling case for Ajax in the future.

Matt Portillo: Great. And then just as a follow up. Looks like the Texas, Delaware is going to be about a third of your program, give or take in 2024. I’m curious one on the development plan here, are you moving towards development, or are you still working on delineating the resource? I know that 2023 was still kind of a learning year for you. And then two, just curious how well cost have progressed in this area. I think that was also kind of initiative last year is to get more reps on wells and get the cost down in that Texas, Delaware play, given that there’s high productivity trends, but the cost side of the ledger still needed some work.

Pat Wagner: Matt, this is Pat. I’ll take the development piece and maybe I’ll let Mike take out the cost piece. Yeah. As you said this — we moved this project into our development team last year. So it’s still longer an exploration project. It is in our development program. As I think you probably know, we have 13 wells that have been online for some time, nine in the Woodford, four in the Merrimack. And they continue to perform this as we expect. Excellent productivity, high oil cut, shallow declines, and low moral ratios. We will be bringing on nine wells this year. Two of those are leasehold wells, and then there’s two multi-well pad that will be bringing on. We’ve gone to longer laterals. We have this 57,000 acre blocking position, so that gives us the ability to drill really long laterals.

The wells we’re bringing on this year will average around two miles next year, or the wells will be drilling in the future will be up to 13,000 feet. From a development standpoint, we’re still looking at four by four spacing in the Woodford and Merrimack. I think I hit it all there maybe.

Mike Henderson: Yeah. Matt, from a cost perspective, what I’d say is we’re kind of still mid program, so to speak. We’ve just completed drilling the wells, not completed them yet, so don’t have all of the data to share. What I would say is from a drilling perspective, costs are in line with kind of pre-drill expectations. What I would say, maybe the encouraging thing is as we progressed through the drilling, it seemed that the efficiencies were getting better and therefore when we do get all of the costs, and I would expect that — you would see that natural that improvement in the cost as we get — quite frankly, we just get more reps.

Lee Tillman: Yeah. One other thing I’ll just mention too, this is a little bit of a subtlety, but the fact that we brought the two asset teams, Permian and Oklahoma together, and now that’s under a single leadership structure. And this is one of the areas where we can benefit from learning because of course, Woodford Merrimack drilling and completing in Oklahoma, that’s something that we’ve already kind of cut our teeth in. So we’re bringing a lot of those learnings and expertise now into this, if you will, joint asset team. Now that we have this Texas, Delaware play, with the Woodford Merrimack, because it is challenging drilling. I mean, let’s be honest. It’s deeper, it’s hard pressure, it’s more challenging, hard rock drilling, but bringing that expertise in from Oklahoma is certainly allowing us to advance up the learning curve a bit more efficiently.

Matt Portillo: Thank you.

Operator: Our next question comes from Neil Mehta with Goldman Sachs.

Neil Mehta: Yeah. Good morning Lee and team. First question I had was just post 2024, capital efficiency this year, another very strong year. But as you think about setting the sticks for 2025 and ensuring that you’re able to sort of continue at this capital efficiency pace, just some thoughts post 2024, and can you hold 190 of oil at 2 billion the CapEx?

Lee Tillman: Yeah. Well, it feels like we’re just now releasing 2024. So jumping hit 2025 is a bit of a leap. But first of all, let me just say Neil, we feel very good about our, I’ll say, underlying well productivity. I think it’s actually pretty remarkable when you think about the fact that we operated to, of what the market uses very mature basins, and we’re still very much holding the line on productivity that is already at the top of the peer space. So I think you have to keep all of this in the proper context. And certainly as we do our longer term modeling, clearly Permian will start competing for a bit more capital, but we believe that from a productivity as well as a capital efficiency standpoint, certainly as we look out over the horizon, we see ways to continue to hold the line and certainly hold the line if not improve on some metrics.

And again, we can have a lot of tools available to us, right? I mean, there’s some of the things that Mike talk about. There’s the fundamental, well designed, longer laterals, better completions, there’s execution efficiency, stages per day. Our rate of penetration on the drilling side, we’re just talking about the Woodford hard rock drilling. There’s supply chain optimization. We continue to work on how best to integrate and manage our supply chain. And then finally, there’s just the sheer commercial leverage. You can kind of put that in the deflation/inflation bucket, but all of those things give us an opportunity to continue to work on overarching capital efficiency as we move forward in time. Even though we may be moving to different parts, different geology, we certainly see a path to continue to protect our peer leading capital efficiency that we’ve worked very hard for.

Neil Mehta: Thank you. Yeah. And it definitely is notable. The question — the follow up question is just on the natural gas outlook in the U.S. It’s obviously a tough environment as you referenced in your comments, but how is your designing your plan for 2024, and you’re thinking about which areas you want to prosecute? Are you trying to maximize the value of your net backs? Thank you.

Lee Tillman: Yeah. I think Mike was pretty clear in describing the capital program that, that our program for ’24 already reflects the reality of where natural gas pricing sits today. So not surprisingly, we’re driving capital allocation to our three kind of black oil basins, Eagle Ford, Bakken and the Permian. Thus, a combination play essentially like Oklahoma is struggling obviously to compete for capital because of where we are on the commodity cycle, right? Doesn’t mean that it won’t compete in the future, but today because of the multi-basin model, we’re able to take a hard look. I mean, I think Mike said, it’s value over volumes and even though we’re taking a little bit of a downtick on OEVs, that’s by design, we’re driven by returns and value optimization, which is making our oil program very efficient in 2024, and very much our focus given where gas pricing sits today in North America.

Neil Mehta: Thanks team.

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

Unidentified Analyst: Hey, good morning, guys. This is actually Kaleo [ph] for Doug, so I appreciate you taking the question. My first question goes to inventory depth. You guys obviously can — continue to show a very consistent capital program with the emphasis on harvesting those mature assets. So hoping that you can provide a view on how you see the resource depth evolving on each one of your four U.S. plays. And when you think about that program as you work into the future, do you ever see the Anadarko Permian carrying the load of that program? And if so, when do you see it?

Lee Tillman: Yeah. There’s a lot in there. So let me maybe try to unpack a little bit of that. First of all, maybe just let me deal with the inventory question. Our team has been very successful at replacing inventory over the last five years, and there’s several ways that we’re able to do that. One is organic enhancement, and that can include everything from cost reductions in places where we operate, extending laterals, refrac and redevelopment work like we have ongoing in places like the Eagle Ford, so that’s helpful. We do small bolt-ons and even trades. One of the reasons that we’re now having a primarily two-mile-plus program in Delaware is because of all the good work around small acquisition, small trades there to allow us to get a more contiguous kind of position there.

And then we just talked about the migration of the Delaware, I’m sorry, the Texas, Delaware play from kind of exploration into the development program. And then finally there is large scale — larger scale M&A like we do with Ensign. You’ve got these four avenues to continue to replenish and in some cycles you lean on one more than another, but typically you need to see all four of those to have a sustainable replenishment model. And that’s really what we’ve been able to prosecute over the last five years and hold that 10-plus-decade plus of inventory relatively constant over that period of time. So you should expect us to use that same playbook going forward. I mean, every year is not going to have a large scale M&A, but certainly every year we’re investing in things like organic enhancement.

We’re investing and still trying to progress some of our exploration place. So those things are just part and parcel of how we address inventory replenishment. At a basin level, we allocate capital at an enterprise level, so when we look at our inventory, we’re looking at it from a holistic standpoint. And that’s why, for instance, today you see Permian starting to compete for more capital allocation. And so, when we think through that 10-plus-year inventory, we think through it with a mindset of managing it at an enterprise level with basins coming in and out and receiving capital allocation based on the highest return and the best fit for us to continue to generate sustainable free cash flow generation.

Unidentified Analyst: Thanks, Lee. I appreciate those comments. My quick follow up just goes to E.G. I’m just trying to get a sense of the readability for the perspective of the commodity sensitivity. Not to be stupid about it, but let’s say prices blew out to $30 per MMBtu in a very extreme scenario. I’m wondering if the earnings that you’ve shown here would exhibit the same linearity compared to the $10 to $15 scenarios that you’ve laid out.

Lee Tillman: Well, first of all, it goes to $30. We’re going to be very happy. But there is a bit of linearity there though. And one of the reasons that — and I think I mentioned this my open comments, we’ve provided some sensitivities at an enterprise level for all of the key products. So you can see how E.G. factors into the overall enterprise delivery, but certainly the data that we’ve included in the deck, you should be able to test those sensitivities because it is a commercial framework, it’s a linked to global LNG pricing. So the extent that we’re delivering, same level of volumes under the same cost structure, then that should be a pretty linear relationship with commodity pricing.

Unidentified Analyst: I appreciate that. Thank you.

Lee Tillman: I want to make that $30 as a prediction too, by the way.

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

Paul Cheng: Thank you. Good morning, guys.

Lee Tillman: Morning.

Paul Cheng: Maybe this is, for both Lee and Dane. You guys are changing a bit on the accounting in E.G. shifting the transfer price. Just curious that — with that other than say the shift on earning between the equity affinity and fully owned operation, but see in any way that changed the way how your decision making for that operation level. That’s the first question. The second question that I want to — maybe go back to the consolidation, in your operating region, because of that, we are going to see some bigger payer, do you foresee that going to change the landscape in terms of the service supply, in terms of all that, because of the consolidation, people become more rational. So you actually think that the pricing on the survey will become better for the rest of the payer. So just curious then, I mean, what you view on the competitive landscape that may have changed, if any, due to that consolidation in the operating regions that you are in.

Lee Tillman: Okay. Great. Well, again, lots to unpack there, Paul. Let me, maybe start off on the E.G. question. I’ll get Dane to jump in here and help me out. But you’re spot on in that under the new contractual structure that we will be shifting some element of profitability from the equity companies over to the consolidated reporting. And in fact we provided a very kind of detailed breakdown of that in our guidance in the deck just to hopefully eliminate any confusion or lack of clarity around this point. I mean, we know E.G. still is complex, but in some ways this will bring more transparency by migrating more of that profitability into the consolidated entity. It will also limit kind of this timing dislocation that we also have between when we generate the income or the earnings and when we receive, say, the dividend from an equity company.

Because in the consolidated entities, obviously that step does not occur. The only other thing you said, well, would this change anything around our decision making because of this new structure? And what I would tell you is, the beauty we have in E.G. is that we are aligned from an equity percentage standpoint across the value chain. So there’s really no impact to our decision making or how we think about investments across that value chain because we have alignment in every aspect of it from the upstream, all the way through the LNG plan. I don’t know, Dane, if I missed anything there.

Dane Whitehead: No, I agree completely, Lee. I would just add the guidance that we provided on page 15 of the slide deck, it’s really sort of at an — holistic E.G. business unit level $550 million to $600 million EBITDA in 2024, assuming $10 TTF and we gave price sensitivity. So you can dial that how you want. But I will say that’s the best way to look at the business is the aggregate EBITDA generation. That’s how we think about it. So it doesn’t really — to echo Lee’s point, I don’t think it drives our decision making which entity, whether it’s consolidated or an equity affiliate where that earning is coming from. We like it all. The other thing is that guidance is quite a bit stronger than what we previously provided for ’24 and now we’ve actually gone out five years and given you a five-year average.

So this business is very strong and it’s improving with the infill opportunities and bringing the same gas into the system. I mean, there’s a lot of running room here and a lot that’s not fully baked into the future model yet. So we’re pretty bullish on E.G.

Lee Tillman: I think the last question you had was just around kind of the, I’ll call it, the competitive landscape certainly in some of the basins where we operate today. Consolidation is absolutely a factor in all basins. It’s probably in some ways it becomes a bit more challenging and mature basins as the best operators tend to be aggregating the best assets and many of them have already done so and have a material position. The other challenge I think you have in those assets is it’s the balancing act between PDP production versus forward inventory. And I would use the example, for instance, of Ensign where we really struck that balance. It brought cash flow and EBITDA with it, but it also brought 600 plus locations that was not only inventory life accretive to the Eagle Ford, but with inventory life accretive to the overall company.

And those opportunities came in and competed immediately and continue to compete within our capital allocation today. And so there are some unique challenges as you look at the more mature basins, but ultimately the high quality assets will be run by the highest quality operators. And we certainly put ourselves in that category.

Paul Cheng: Thank you.

Operator: Our next question comes from Scott Gruber with Citigroup.

Scott Gruber: Yes. Thanks for squeezing me in and just have one question here. Lee, I think your M&A framework is certainly a very prudent approach. But obviously there does seem to be an industry rush here to secure good rock and scale up. So the question we get from investors is, do you worry about the opportunity set for acquisitions shrinking and the quality of the opportunity set fading? And does that warrant a tweak to your M&A strategy? I guess ultimately the question is, are you comfortable with the longer term outlook for adding quality resource, whether that’s organic or inorganic within the construct of your M&A approach or — and in the context of this hyper consolidation phase?

Lee Tillman: Yeah. Well, definitely there — we’re in that phase today, but we see no upside to our shareholder to compromise our criteria today. Again, all of these transactions are very bespoke. They reflect the attributes of the counterparties. Most of those counterparties are searching for something. They’re searching for scale, they’re searching for resilience, they’re searching for balance sheet help. I mean, they’re searching for sustainability in inventory, so they’re trying to fill a void. And what that drives is, is this I’ll — I won’t necessarily refer to it as desperation, but it drives a different kind of behavior for us. We’re sitting with 10-plus years of inventory. So we can be patient, we can be thoughtful, we can exercise the same level of discipline that we do in our organic business and be very successful.

And we’ve demonstrated that. We’ve got a track record. I talked about those four levers we have available for inventory replenishment. Large scale M&A is just one of those levers that we can apply. And also keep in mind that even when transactions occur, the assets are still there and so they’re not going anywhere. And so there is still that aspect of ultimately the best assets will find their hands into being operated by the best operators.

Scott Gruber: I appreciate the color. Thanks, Lee.

Lee Tillman: Thank you, Scott.

Operator: Thank you. This concludes our question-and-answer session. I would like to turn the conference back over Lee Tillman for any closing remarks.

End of Q&A:

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

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.