Marathon Oil Corporation (NYSE:MRO) Q4 2022 Earnings Call Transcript

Marathon Oil Corporation (NYSE:MRO) Q4 2022 Earnings Call Transcript February 16, 2023

Operator: Good morning. And welcome to the Marathon Oil Fourth Quarter and Full Year 2022 Conference Call. All participants will be in a listen-only mode. . Please note, this event is being recorded. I would now like to turn the conference over to Guy Baber, Vice President of Investor Relations. Please go ahead.

Guy Baber: Thank you, Anita. 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 addressed our fourth quarter and full year 2022 results, as well as our 2023 outlook. These documents can be found on our website @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, our 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.

As always I will refer everyone to the cautionary language included in the press release and presentation materials, as well as to the risk factors described in our SEC filings. We will 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 will provide prepared remarks. After the completion of these remarks, we will move to question-and-answer session. Lee?

Lee Tillman: Thank you, Guy, and good morning to everyone listening to our call today. First, I want to thank our employees and contractors for their collective contributions to another remarkable year. A year that can only be described as comprehensive delivery against all dimensions of our well established framework for success. Your dedication and hard work, as well as your steadfast commitment to our core values, including safety and environmental excellence that made it possible — that made possible the exceptional results I get to talk about today. So thank you. 2022 truly was an exceptional year. But our outlook for 2023 and beyond is equally compelling. While the team and I will cover a lot of ground today I’ll start by highlighting a few key things.

First, we’re successfully executing on the more S&P less E&P mandate our champions for the last two years. They are delivering financial and operational outcomes not just at the top of our high performing E&P peer group, but at the very top of the S&P 500. The results in 2022 really do speak for themselves. $4 billion of adjusted free cash flow generation, the strongest free cash flow yield in our peer group, and one of the top five free cash flow yields in the entire S&P 500. The lowest reinvestment rate in our peer group a full 10 percentage points below the S&P 500 average. And one of the lowest capital intensities, all indicators of a now well established capital and operating efficiency advantage relative to a high performing peer group.

Second, we’re returning significant capital back to our shareholders through our cash flow driven return of capital framework. Our framework is transparent, it’s differentiated, it prioritizes our investors as the first call on capital, and it uniquely protect shareholder distributions from capital inflation. During 2022, we’ve returned 55% of our adjusted free cash flow from operations or $3 billion to shareholders. And for those keeping score relative to the free cash flow based models of our peers, that equates to about 75% of free cash flow. That also translates to a 17% shareholder distribution yield, the highest distribution yield on our E&P peer space, and one of the top 10 distribution deals in the entire S&P 500. We’ve remained steadfast in our commitment to the powerful combination of a competitive and sustainable base dividend.

In addition to consistent share repurchases. That consistency paid off with $2.8 billion of accretive share repurchases that reduced our share count by 15%, driving significant growth on a per share basis. Rewinding all the way back to the start of this most recent share repurchase program in October of 2021, we have reduced our share count by 20%. Again, leading the peer group. And we raised our base dividend three times during 2022, bringing our track record to seven increases in the last eight quarters. Third, we successfully closed on the Ensign acquisition before year end. Materially strengthening our portfolio and enhancing our Eagle Ford scale. The Ensign acquisition makes us a stronger company. Checking every box of our disciplined acquisition criteria.

It’s a accretive to key financial metrics, it’s accretive to our return of capital framework, it’s accretive to our high quality inventory life and it offers compelling industrial logic in the core of a basin we know well. Pat will provide additional details later in the call but ensure integration efforts are progressing well and initial 2023 results have outperformed our expectations. Finally, while 2022 was certainly a banner year, I’m just as excited about our potential in 2023 and beyond. Fully consistent with our disciplined capital allocation framework, our 2023 budget prioritizes significant free cash flow generation and return of capital to shareholders. At reference commodity prices of $80 WTI $3 Henry Hub and $20 TTF we expect to generate $2.6 billion of adjusted free cash flow and we expect to return a minimum of $1.8 billion to our shareholders, providing clear visibility to a double digit shareholder distribution yield.

And recognizing the ongoing volatility in commodity prices, particularly natural gas it is important to note that a $0.50 per MMBtu change in Henry Hub only impacts our annual cash flow by just over $100 million. While dollar change in WTI moves cash flow by about $70 million, reflecting continued leverage to oil pricing at our balanced portfolio. Once again, we fully expect to lead our peer group and the broader S&P 500 when it comes to the financial and operational metrics that matter most. Free cash flow generation, capital and operating efficiency and shareholder distributions. While our 2023 outlook is compelling, we’re even better positioned for 2024 as our unique integrated gas business in Equatorial Guinea will benefit from an increase to global LNG price exposure.

Just as a reminder, the current Henry Hub index contract for our equity Alba gas through ET LNG expires at the end of 2023. And we will move to a market base global LNG linkage. With the current and significant arbitrage between Henry Hub and global LNG prices, we expect this to translate into an uplift to 2024 EBITDA of $500 million to potentially more than $1 billion relative to 2023. With that, I’ll turn it over to Dane, who’ll provide more detail around our return of capital performance and outlook. Dane?

Dane Whitehead: Thank you, Lee. Good morning, all. Lee (ph) capital high points, but giving you importance of the topic, I’ll further elaborate on our framework, our execution and our outlook. As we’ve stated before, returning a significant amount of capital to shareholders, through this cycle, remains foundational to our value proposition in the marketplace. And when it comes to shareholder distributions, track record matters. We’re building a track record we’re really proud of and that investors can trust. During 2022 we’ve returned 55% of our CFO to shareholders, significantly exceeding our 40% of CFO framework commitment. Total shareholder distributions amounted to $3 billion, good for a total shareholder distribution yield of 17%.

That’s the highest in our peer space and one of the top distribution yields in the S&P 500. That includes $2.8 billion of accretive share repurchases during the year. We continue to believe that buying back our stock is an excellent use of capital due to the value we see with our shares, trading at a free cash flow yield in the upper teens. Repurchases are value accretive, a very efficient means to drive per share growth and are synergistic to grow in our base dividends. During 2022, we reduced our share count by 15%. And since reinitiating our share repurchase program in October 2021, we’ve reduced our share count by more than 20%, by far, the most significant share count reduction in our peer space as shown on the bottom right graphic on Slide seven.

Photo by Dean Brierley on Unsplash

Another benefit of our buyback program, is the capacity it creates for ongoing growth in our per share base dividend. We recently raised our quarterly base dividend by 11% to $0.10 per share. The seventh increase in the trailing eight quarters. While its most recent increases more than fully funded by incremental cash flow from the Ensign acquisition, ongoing share count reductions from our buyback program create clear potential for further base dividend increases in the future. Our operating cash flow driven framework is differentiated and it protects distributions from the effects of capital inflation, offsetting inflation is on us. We believe this makes for a stronger commitment to our investors, as our investors will truly get the first call on cash flow.

For 2023, the recently completed Ensign acquisition makes our framework even more shareholder friendly adding close to 20% to our pre-acquisition operating cash flow, and therefore adding 20% to our shareholder distribution capacity. In addition, with the 2022 financial — actual financial results in hand, along with the December close at Ensign, we anticipate will be able to defer U.S. cash alternative minimum taxes to 2024. Our objective for 2023 is to firmly adhere to our return to capital framework, continuing to return at least 40% of CFO while also paying including some of the Ensign related acquisition financing. We believe we can do both, maintaining our return of capital leadership in this peer space, which is the top priority, and continue to enhance our already investment grade balance sheet through gross debt reduction, all supported by our financial strength and flexibility.

On the balance sheet, we have about $200 million of high coupon U.S.X debt maturing and replaced. We plan to pay that off with cash on hand to reduce gross debt and interest expense. We also have $200 million of low cost tax exempt bonds maturing in 2023. These tax exempt bonds are unique and very flexible component of our capital structure. We plan to leverage the cost advantage or tax exempt credit capacity to refinance those bonds in 2023. And we have the optionality to do the same with future tax exempt maturities in 2024 and 2026. With regard to shareholder returns, our 40% return on capital commitment in 2023 provides visibility to $1.8 billion of minimum shareholder distributions at our reference price deck as a double digit return of capital yield, one of the highest in our peer space.

We have been executing share repurchases so far in Q1 €˜23. And plan to continue to do so consistent with our framework. And we have ample capacity in our current Board authorization to keep moving. While 40% represents a good starting point for your models, our track record has been to exceed that minimum return, and we’ll look to keep that track record intact in 2023. Especially if we benefit from any commodity price support over the balance of the year, which would significantly enhance both shareholder returns and debt reduction. They have tremendous leverage to commodity price improvement. And we’ll use that to the benefit of our shareholders. Now I’ll turn the call over to Pat, who’ll briefly walk us through an update on the Ensign acquisition.

Pat Wagner: Thanks, Dane. Consistent with our market commitment, we successfully closed on the Ensign acquisition before the end of the year. As we’ve stated, this transaction checks all the boxes of our M&A framework, immediate financial accretion, return of capital appreciation consistent with Dane comments, accretion to inventory life and quality and industrial logic with enhanced scale, all on maintaining our financial strength and investment grade balance sheet. And we based our Ensign valuation on a one rig maintenance program with no credit for potential upside associated with redevelopment refrac. Our focus now is on integration and execution. In terms of integration, early efforts have gone exceptionally well. We had originally planned for major elements of the transition to take up to four months post close, we not expect to be substantially complete with operations transition activities by the end of this month.

That accelerated timeline is in large measure due to the excellent collaboration and cooperation between both organizations. And it serves to underscore the execution competence that comes with an acquisition and established base and then has a track record of success. On the execution side, as highlighted on Slide 11 on the deck. Early well performance is consistent with our stated view that the acquired Ensign inventory has the potential to deliver some of the best returns and highest capital efficiency in the Eagles Ford, and therefore the entire Lower 48. Our first two pads, nine wells in total are outperforming expectations delivering top decile oil productivity in the basin. This year we plan to bring approximately 40 wells to sales on the acquired acreage, accounting for about one-third of our total Eagle Ford program.

The Ensign wells are expected to deliver accretive capital efficiency and financial returns from comparable oil productivity to those legacy Eagle Ford program. I’ll now hand over to Mike, to provide more color on our 2023 capital program.

Michael Henderson: Thanks, Pat. Turning to Slide 12 of our deck. I’ll provide a brief overview of the high points of our 2023 capital pool. As expected, consistent with our disciplined capital allocation framework and our more S&P less E&P mandate, we expect to deliver strong free cash flow and significant return capital to our shareholders across a wide band of commodity prices as the graphics on the right of the slide show. At our reference price deck, we expect our $1.9 billion to $2 billion capital budget to deliver $2.6 billion adjusted free cash flow at just over a 40% reinvestment paid. As Lee and Dane both highlighted, we expect to return at least $1.8 billion of capital to our shareholders. To deliver these financial outcomes, we’ll operate approximately nine rigs and 3 to 4 frac crews on average this year.

We expect 2023 capital to be first half weighted, with about 60% of our total capital spend concentrated in the first half of the year largely driven by the timing of our activity. At the midpoint of our guidance, we expect to deliver maintenance level oil production of approximately 190,000 barrels of oil per day, flat relative to 2022 after incorporating Ensign volumes. As is typical for our business, there will be some standard quarter-to-quarter variability throughout the year. The lower end of our annual guidance range is a good starting point for our first quarter total oil production, approximately 185,000 barrels of oil per day. This is largely a reflection of activity timing and the associated impact on well sales, along with a very modest negative carryover impact from winter storm Ellie, concentrated in the Bakken.

With activity and wells to sales weighted to the first two quarters of the year, we expect to see an improving production trend for oil into the second and third quarters. Turning to oil equivalent production. The midpoint of our guidance is 395,000 oil equivalent barrels per day, inclusive of a planned second quarter turnaround in EG that is designed to set us up for a high level of uptime in 2024. Overall, our 2023 plan is a disciplined and high confidence program designed to deliver strong financial and operational outcomes. In the Eagle Ford, we run a 4-rig program. We expect an improving well productivity trend in 2023 from an already strong 2022, due in part to Ensign contributions. In the Bakken, we will run 3 rigs in average again, focusing our activity in our high-quality hectare area of the play, where the average well pays out and licensed six months at current commodity prices.

In the Permian, we expect to continue improving our capital efficiency by increasing on average lateral lines to 10,000 feet this year, an increase of over 25% in 2022. While our headline Permian wells sales guidance looks similar to last year, the strong well productivity and competitive drilling and completion performance that we’ve delivered is getting back to work over the second half of 2022 supports a higher level of capital allocation. We, therefore, plan to spud between 25 and 30 wells this year inclusive of at least one multi-well pad in our Texas Delaware, Meramac Woodford fleet, which will support a higher level of well to sales in early 2024. Our Texas Delaware position is no longer an exploration play. The asset is now fully integrated into our Permian asset development team where it will compete for capital on a heads-up basis with all the other assets.

So our Oklahoma asset continues to provide us valuable optionality to a fundamental strengthening of the gas and NGL price environment. We aren’t exposing much capital to the asset this year. Rather, near-term activity is limited to a 1.5 rig joint venture program that will allow us to efficiently defend our acreage position and delineate some lower priority acreage limited scope and capital. With that, I’ll turn it over to Lee, who will provide an update on our Integrated Gas business in Equatorial Guinea.

Lee Tillman: Thank you, Mike. 2022 was an exceptional year for our unique world-class integrated gas business in EG. We delivered over $600 million of equity income more than double our guidance at the beginning of the year. And we generated approximately $900 million of EBITDA. Our results were driven by solid operational performance as well as higher-than-expected commodity pricing, especially for Henry Hub and European natural gas. For 2023, we expect equity income and EBITDA to decline largely due to assume significantly lower commodity prices, especially for natural gas and the already referenced planned turnaround during the second quarter. The outlook beyond 2023, however, is robust as we expect to realize significant EG earnings and cash flow improvement in 2024 on the back of an increase in our global LNG price exposure.

A way of background, in addition to our 64% interest in the operated Alba gas condensate field, which produced approximately 60,000 oil equivalent barrels per day on a net basis in 2022. We also have a 56% interest in equity accounted 3.7 MTPA baseload LNG facility. This LNG facility currently processes equity gas from our operated Alba field that is sold on a legacy Henry Hub link contract and third-party Alen gas volumes on a total plus profit sharing basis. The Alba Henry Hub link contract expires at the end of 2023. While we’re still working through contractual and commercial details, the bottom line is that beginning January 1, 2024, Alba source 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.

More specifically, at pricing generally consistent with the forward curve or $20 per MMBtu TTF, we’re positioned to realize an approximate $500 million EBITDA uplift in comparison to 2023. As there is a wide range of potential global LNG price outcomes in 2024, we’ve also provided a high side sensitivity to help you better appreciate the leverage we’ll have in 2024 to global LNG prices. Assuming an upside case of $40 per MMBtu TTF in 2024 or a price consistent with the average of the trailing 12 months, the potential EBITDA uplift could be in excess of $1 billion. And beyond the significant financial uplift expected in 2024, we remain equally focused on further maximizing the long-term value of our unique EG gas assets by leveraging available haulage through EGL&G.

This world-class infrastructure is well positioned in one of the most gas prone areas of West Africa and is a natural aggregation point to monetize both indigenous EG gas as well as discovered undeveloped cross-border opportunities. In summary, for years now, I’ve reiterated my view 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 the return of capital. More S&P, less E&D. We’ve delivered exactly that type of performance over the last two years and not just competitive, but at the very top. And as I said before, our challenge now is to prove that our results are sustainable, quarter in, quarter out, year-end and year out.

We believe they are. We’re up for the challenge, and I believe our outlook is as strong as it has ever been. Our compelling investment case is simple. We offer a unique and differentiated return of capital framework that provides shareholders first call on cash flow and protect distributions from capital inflation. For 2023, we’re providing clear visibility to double-digit shareholder distribution yield. We have an established track record of market-leading free cash flow yield and shareholder distributions at an attractive valuation and offer investors a free cash flow and return of capital profile that competes with any sector and company in the S&P 500 across a wide range of commodity prices. We have delivered per share growth across all the metrics that matter via a consistent share repurchase program that leads our peers in addition to a durable and competitive base dividend.

We believe this peer-leading financial delivery is sustainable, underpinned by our high-quality U.S. unconventional portfolio with over a decade of high return inventory and a track record of sector-leading capital efficiency, recently strengthened by the Ensign acquisition. Our portfolio provides commodity leverage with strong oil weighting, coupled with a unique and increasing exposure to global LNG prices that will drive material financial uplift in 2024 and beyond, all underpinned by an investment-grade balance sheet. And finally, we’re delivering these results to help meet global oil and gas demand while prioritizing all elements of our ESG performance. To close, I want to again reiterate how proud I am of the way we position 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. The oil and gas that is critical to furthering global economic progress, defending U.S. energy security, limiting billions out of energy poverty and protecting 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: The first question today comes from Jeanine Wai with Barclays. Please go ahead.

Jeanine Wai: Hi, good morning, everyone. Thanks for taking our questions. Our first question, maybe just starting with the ’23 outlook for Lee or Mike, one of the things that really stood out to us in the outlook was actually the number of Eagle Ford wells to sales in the plan, which was decently below our forecast, and it’s about, I think, 20% lower year-on-year on an adjusted basis, if you just assume maintenance mode and then you add the 40 Ensign wells to the number of wells you did last year. And we saw your comments about higher aggregate year-over-year well productivity in the Eagle Ford in ’23. And we were just wondering if you could share any further details about the implied improved capital efficiency in the Eagle Ford because it seems to be pretty meaningful.

So for example, if the Eagle Ford — is the Eagle Ford actually in maintenance mode this year on an adjusted basis and are there any other factors out there that would be affecting the wells this year to sales, whether it be the mix, the working interest or anything else? Thank you.

Michael Henderson: Thanks, Jeanine, it’s Mike here. I’ll take that call. So to maybe answer part of your question. Yes, I think it is safe to assume that the Eagle Ford is in maintenance mode — all maintenance mode this year. And I think it’s also correct. You’re also correct in that the legacy position, we are holding volumes flat on a lower well to sales count in 2023, which is obviously a positive thing. A couple of elements that I would say go into that. The first one being the timing of when we bring wells online in the year. We are going to be bringing close to 60% of our legacy wells to sales in the first half of ’23. And that definitely helps the annualized volumes. I think the second element and probably the more important one from my perspective is well productivity and a lot goes into well productivity.

But one of the things that the team has been doing is really continuing to optimize our completion design. That has resulted in an uplift in our well performance. And you see that factored into this year’s business plan and the ultimate volumetric outlook. So we were already setting up for a strong year in Eagle Ford with the legacy business. I think the addition of the Ensign acreage only reinforces our position, as Pat mentioned. I think we’re particularly encouraged with the performance of the first 9 wells from the 2 pads that we brought online in the condensate window, very strong productivity, top decile and oil, really fully consistent with our belief that this is some of the highest capital efficiency inventory in the Eagle Ford. And that only adds to what was already a highly capital-efficient business.

So very, very excited about the opportunities that the acquisition brings us this year and even beyond.

Jeanine Wai: Okay. Great. Same (ph) on this well is always a good thing. Thank you for the detail. Maybe Dane, turning to you on just the shareholder returns versus debt pay down, you’re committed to returning at least 40% of CFO this year. The balance sheet is in a really comfortable place. At least at Barclays, our house forecast calls were meaningfully higher crude prices than $80 this year. And assuming our prices show up, how should we think about the allocation of capital in this scenario between buybacks and early debt pay down? We heard your prepared remarks where you talked about your track record is to actually exceed the original target percent return. In the past, you’ve given kind of different percent targets at different commodity prices.

But this time around, you’ve got the new Ensign debt in the mix. And so at what point do you really start chipping away at the Ensign debt? Is it as simple as if oil is $85 or $90, you start going after that more? Can you provide any more color? Thank you.

Dane Whitehead: Good morning, Jeanine, yes, definitely. Let me kind of go back to our return on capital commitment framework for a second, and then I’ll work my way to how we’re thinking about paying down acquisition debt and timing of that. One, as I stated, we’re firmly committed to our (ph) capital framework, a minimum of 40% of operating cash flow to shareholders as long as WTI is about $60 and obviously, we’re well above that right now. In ’22, we significantly exceeded that. We hit 55%, $3 billion back to shareholders, $2.8 billion of that was share repurchases. So significant return to in the form of share repurchases, and that’s how we’re thinking about 2023 as well. The Ensign acquisition really enhances our shareholder return capability added about 20% both our pre-acquisition operating cash flow and our shareholder distribution capacity.

So another way to think about that is a 40% minimum shareholder return post Ensign 50% pre-Ensign. So at a minimum, we’re pretty close to what we actually delivered last year, but we like having a track record not only of meeting our goal, meeting our minimum target but exceeding it, and that’s what we’ve done so far and we intend to continue that. Too soon to give you more guidance to model on that, but that’s our bias. With respect to how do we pay back acquisition debt in the context of that return framework, I think we really have the capacity to do both, even at today’s commodity price, as I look at this, I see the capability to not only meet and exceed our shareholder return goals but to start to meaningfully chip away at the acquisition debt and get that interest expense and just that gross debt out of the system.

From your lips to God’s ears on higher oil price, we have a tremendous amount of leverage to strong commodity prices, especially oil, and that would just increase our return capacity. You did note our balance sheet is really strong. Rating agencies have given us positive feedback around that. So we’re not in a mad rush to delever. But my base case is to get that taken down at $1.5 billion 2-year term loan paid off within that window. And we can prepay it without penalty so we can just start kind of slicing chunks off as we go through. And I think we’ll probably just assess that periodically as we go through the year based on how our cash generation is. But once again, restated our primary goal, our number 1 goal is return to shareholders, and that will not take a back seat to paying down the debt.

While I’m here, let me just talk a second about the flexibility we have in our capital structure. I noted in my prepared comments, we have $200 million of high coupon legacy USX debt that’s going to be — it’s like 8.5% to 9% coupon. So it’d be really nice to get that out of the system. It’s not a big quantum, so we’re just going to pay that off of cash on hand. Aside from that, and the acquisition term loan that I already referenced, the only other maturities we have between now and 2027 are in aggregate $1 billion in tax exempt bonds that mature somewhat ratably over ’23, ’24 and ’26. And under that tax exempt bond arrangement, we can refinance fees, as they come due in any tenor all the way out to 2037. So a ton of flexibility there. They’re very interest rate advantaged to taxable debt.

Even in this crazy interest rate environment, they’re quite a bit advantaged and the things normalize as we go forward here a little bit from an interest rate perspective, they’re — the coupon on this one we’re retiring now is 2%, and that’s kind of companies. So we really like that flexibility. And the last thing I’ll say is we extended recently our $2.5 billion credit facility out to July of 2027. So kind of flexibility there. Bottom line, shareholder returns first, pay back debt second. We have capacity to do both. I’m not going to give you a break line formula how we’re thinking about it. But that’s our commitment. And that’s how we’re going to proceed.

Jeanine Wai: Great. Thank you, gentlemen.

Operator: Next question comes from Neal Dingmann, Truist Securities. Please go ahead.

Neal Dingmann: I’ll leave my first question for you or Dane, on capital allocation, specifically. I definitely appreciate and really support the buyback focus. I’m just curious, have you all changed the way you think about your stock dividend or your stock valuation as the savers the dividend payout. Just wondering, I mean, you all think about some mid-cycle prices used when looking at the metrics? Or is there any other details you were taking to provide on kind of how you’re looking at the buyback versus the disk?

Michael Henderson: Yes. Go ahead, Dane.

Dane Whitehead: Neal, yes. So from a base dividend perspective, we want that to be competitive and sustainable. And sustainability is kind of the governor there. We look at sort of conservative mid-cycle pricing, maybe a $50 WTI world and trend not get too far of, say, 10% of operating cash flow on that base dividend. And so that’s a bit of a governor. Now we have the synergy with the share repurchases that surprisingly — is surprising how quickly you can buy back enough stock to pay for another 10% increase, and we’ll definitely be in that window again sometime this year. So that’s how we think about the dividend, share repurchases, obviously, organic lion’s share of our return of capital program, and I would expect that to continue as long as our free cash flow yield is indicative of a really efficient way to buy back stock.

Lee Tillman: Yes. I think, Neal, if you look at the aggregate efficiency of our share repurchase program, it really has been a differentiating, I think, feature for us since we started that program back in October of ’21. I mean to be talking about a 20% — over 20% reduction in shares outstanding and the dramatic impact that, that has on per share metrics it’s pretty notable. And as Dane noted, not only is that a very efficient mechanism for getting that cash back to shareholders. But the synergy effect that it has with the base dividend is also pretty remarkable. So that — those mechanisms, we believe, are still the case to be as we look ahead into 2023.

Neal Dingmann: Yes, I love that per share growth, it really stands out. And then my second question is just on cost, specifically. Incremental cost expectations for the next few quarters seem to be now the most topical once again. Just curious on how volatile you all believe these — that caused let’s say, for the next 2, 3, maybe even 4 quarters will continue to be. And can you continue? It seems like you’ve done a pretty good job in the past, locking in a good piece of those. I know when talking to Mike and the team. So I’m just wondering when you guys look at that, how you’re thinking about costs here for the — call it, the near term and locking in?

Lee Tillman: Yes. Maybe I’ll just provide a couple of comments and then hand over to Mike to perhaps get into some of the details of how we’re really working to mitigate those pressures in time. But when you think about cost overall, we have to bear in mind that 2022 was kind of a tale of 2 halves of the year. The first half of the year was — certainly didn’t see the level of inflationary impacts that we saw in the second half. So some of the pressure that I think we’re feeling not only the company but as a sector, in 2023 is the fact that we have the full year impact of those inflationary pressures. And our $1.9 billion to $2 billion number fully contemplates that full year impact of those inflationary pressures. I think the team has done an outstanding job being very disciplined about how we lock in both capacity and costs from our service providers. And maybe I’ll let Mike just expand a little bit on that point.

Michael Henderson: Yes. Thanks, Lee. It’s Mike here, Neal. Maybe a couple of things. How I’d maybe characterize ’23. At a high level, we’ve kind of assumed similar service cost on that fourth quarter environment. So that’s probably a good starting point for you. And maybe consistent with what we’ve highlighted previously, and we touched on this a little bit. We’re assuming 10% to 15% inflation that is built into our 2023 budget as relative to 2022. As we mentioned in the past, we’ve been working this one hard. Really, our objective was to really baseload the maintenance program kind of really try to minimize the need for spot work. A lot of benefits in doing that from safety, execution and commercial perspective. We’ve taken what I describe as a disciplined but thoughtful approach.

Our priority has been to really protect the execution side of the business and try to get access to the same high-quality providers and equipment that we were using in ’22, and I can tell you been successful there. And the majority of the folks that we’re working with in ’23 are we see folks that we’re working with in ’22. As I think about the year — for the first half of the year, majority of our reg pressure, pumping sand in leads all fully secured. Most of the price is locked in. There’s a little bit of open pricing, but not a lot where we can try to index link that to the pricing mechanisms. And then maybe for the second half of the year, that’s really been a little bit more patient. That feels like the right calls just given the macro volatility at the moment.

We feel good about our ability to access high-quality providers and equipment, but we’ve maybe been a little bit more thoughtful in terms of how much prices we lock in. Potentially, that could work to our advantage later in the year, particularly if you see some of this commodity price weakness that we seen recently, if that persists, especially on the natural gas side of the business. That could potentially lead to less drilling and completion activity, particularly in some of those higher cost gas, please.

Lee Tillman: Yes. And maybe one just kind of closing comment as well, Neal. I know we spend a lot of time talking about inflationary pressures on the CapEx side of our business. I don’t want us to forget that our operating expenses are also a critical element of our business model. And if you look at our guidance, particularly for the U.S. business this year, the U.S. unit production expense is actually going down by circa 10% year-over-year. A lot — obviously, a lot of great work by the team, but also it reflects some of the implicit efficiency that we’re gaining through the scale and the performance from the Ensign acquisition. So I just don’t want to focus all of our time just on CapEx, OpEx is still a very key element of delivery of our financial metrics. And so I just wanted to highlight that before we let these questions.

Neal Dingmann: That’s a great. Thanks, Lee, thanks, Mike.

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

Douglas Leggate: Good morning, guys. Thanks for getting me on. So Lee tremendous acquisition in the Eagle Ford. My question is whether you have line of sight or any thoughts about how you address the balance of the portfolio. And let me frame my question like this. On Slide 20, you’re showing about a 13-year inventory in the Lower 48, but you’re also suggesting the Eagle Ford today is more than 15 years, and that’s about half of production. So I guess I’m coming to a conclusion that the rest of the portfolio is probably sub-10. So I’m wondering if you could give us some thoughts as to whether that sounds reasonable, maybe break it down by asset, but how you think about extending the asset life on those other parts of the portfolio? And I’ve got a follow-up, please.

Lee Tillman: Yes. No. Thank you, Doug. Well, first of all, I appreciate you pointing out the inventory life because I do think this is an important topic. This is third-party data. This is — that we showed in the pack. It’s also kind of sub-$50 WTI breakeven data. So you just have to keep in mind that this is a very specific slice of inventory life. To me, one of the key takeaways is that we’re clustered in with 4 or 5 other companies that are really sitting in that 12- to 15-year inventory life. And so we’re in a very good ZIP code there. So I want to start with that as a premise. We’re not disadvantaged in any form or fashion when it comes to quality inventory like with exceptionally low breakeven. Getting beyond that and talking about inventory life for the portfolio, but also at a basin level.

You’re right in the sense that Ensign has been very accretive specifically to the Eagle Ford. But as you know, capital allocation and consumption rates ultimately sits the inventory life calculation, that’s why we tend to look at it at a portfolio level as opposed to a basin level. But you can take comfort in the fact that when we look across our basins, in aggregate, they are all at that kind of 10-year or better inventory like when we look at that from an internal perspective. We said, well, how do you think about growing that inventory life moving forward. Well, I think right now, we’re just wanting to integrate and digest the Ensign acquisition, which, to us, was very much representative of the type of acquisition that makes sense for a company like Marathon, right?

If you — we talked extensively about the criteria we would use to evaluate any acquisition. And it was obviously financial accretion. It was obviously industrial logic. But a big component of that was to look for assets or opportunities that would also have a net positive effect on inventory life. And not just long-dated inventory, but inventory that can compete right now today, and that’s exactly what we’re seeing from the Ensign acquisition. So to the extent that we continue to screen and look at opportunities here in the U.S. And they — and we find some that meet that criteria. I will take a very hard look at that Pat and his team are constantly looking at the opportunities within our core basins. But if anything, Ensign has actually raised that bar and raise and elevated that criteria because it was so accretive to the overall enterprise and specifically the Eagle Ford metrics.

Douglas Leggate: I appreciate the answer, Lee. I mean, good assets and hands great management with a lot of cash and you can kind of see where I’m going with that. So thank you for the answer. My follow-up is kind of a similar question on EG. And you know we’ve been kind of struggling with this a little bit because I realize that the step change in the 18-year contract is extraordinary. The problem we’re facing is that on our numbers at least on third-party data, in particular, the $900 million of EBITDA more or less on the production, it looks like it’s about $600 million gross going through the plant. That production looks to decline about 70% over the next 5 years, and you don’t have any capital associated with the uplift this coming year.

So my question is, how do you maintain — what are the opportunities that in terms of whether it might require capital or third-party on that gas to spend capital, which brings questions over what kind of margin you can actually maintain on that. So I guess I’m looking for confirmation. Is that really the decline rate? And how do you backfill it?

Lee Tillman: Yes. Well, I think the — first of all, on the decline rate, on the equity Alba gas time and safe, we’re kind of 8% to 10% annual decline rate. So that’s kind of the decline rate that we would typically experience within that asset. In terms of future opportunities, let me describe it like this. First of all, as I said in my opening comments, we have this world-class very unique infrastructure sitting in 1 of the most gas prone areas of West Africa. And quite frankly, those molecules will not get monetized unless they probably flow through EG LNG. We are the route to monetization. And we’ve already demonstrated success in that. If you look at the Alen project, which, as you said, if you will, another molecule, a non-equity project.

But with that, we were able to participate both from a tolling as well as a percentage of proceeds on the profit sharing side of that. Not only that, but when you talk about capital, we had more infrastructure built out on someone else’s capital, i.e., the Alen pipeline. And that was obviously critical for the Alen project but it also subsequently now connects us to additional discovered undeveloped gas that we know ultimately will come to market. Remember, we’re in the Atlantic Basin, where transportation and geographically advantaged to European markets. There is no other monetization route for those molecules. So I have a very high confidence that between third-party opportunities as well as the fact that we continue to assess both on-block Alba and off block opportunities ourselves.

Now there could be some capital requirements there. But for third-party molecules, those are going to come to us, and we’re going to be able to participate in the upside, just like we have in the Alen project. So in aggregate, when I think about all of those opportunities, when I think about our already demonstrated success at Alen, we have commercial framework that works and that framework can be replicated. The fact that these molecules have to find a home or they’re going to be stranded gas. I have a lot of confidence that we’ve got a very strong trajectory for EG LNG out to 2030 and beyond.

Douglas Leggate: Appreciate the answer. Lee, thanks so much.

Lee Tillman: Anita, maybe we can do on question per analyst to try to make our way through remaining a key there.

Operator: Okay. The next question comes from Matt Portillo with TPH. Please go ahead.

Matthew Portillo: Just a follow-up to Doug’s question. Great to see the Texas Delaware making its way into the development program. Just curious if you can give us an update on the delineation plan for this year? What you’ve learned so far? And how this might impact kind of your inventory views for the Permian kind of moving forward?

Patrick Wagner: I’ll take this one. Matt, this is Pat. Yes, as you said, we just completed three wells on our most recent pad. The wells are performing well to date, consistent with our predrill expectations. All three wells and achieve at least 1,000 barrels of oil per day on flow back. It’s still early. We’re still watching the wells. We need some time to look at longer-term performance, but early indications that are good, they’re exhibiting high oil cuts, they’re showing low water on ratios and a low decline, some positive outcome there. You may recall that we deliberately down-spaced this pad in Woodford and check our spacing development. We collected a lot of fiber data and other day to try and work in the optimal spacing, both vertically and horizontally.

The key takeaway so far is that there’s no communication we’ve seen between the Woodford and the Meramec, which gives us strong evidence that we can successfully co-develop those two reservoirs without in the period. With regard to future development spacing, I’d say early learnings from this pad appear to confirm our original view that optimally will probably go with a 4×4 co-development. That will be the most capital-efficient way to develop the acreage. I’ll remind you that the previous pad, we had the strongest Woodford oil well average drilled and that well continues to just be a really strong well. We now have about 12 wells online across the 55,000-acre position that we have 8 in the Woodford or in the Meramec. Again, very confident in all their performance very high oil productivity, low water ratio and shallow decline.

And we think ultimately, this play is going to generate very high returns. As Mike said in his opening remarks, no longer an exploration play fully integrated into the team. It will compete with cap for capital with the rest of the portfolio. That said, we will drill another multi-well pad this year to continue the development, and we’ll see how it goes. We’ll help in that.

Operator: The next question comes from Subhasish Chandra with Benchmark Company.

Subhasish Chandra: Just curious on your gas views. Yesterday, we might have seen a company that targets oil and see gas as a derivative. And the risk of that strategy, given what’s happened in the macro world. I think in your commentary, you are more cautious on gas, at least in Mid-Con, et cetera. But could you talk more specifically to how you might adjust activity at all based on gas prices? And secondly, I should — well, a follow-up — no follow-up on the Bakken. Bakken is getting gassier, and how you kind of look at that going forward?

Lee Tillman: Yes, Subhasish, this is Lee. Just in terms of gas views, we’re not in the business of predicting pricing. We’re a price taker. We do have, though, however, a very natural hedge by virtue of our portfolio. I want to keep in mind that our portfolio is about 50% oil, about 50% gas and NGL. So even though prices will inevitably exhibit volatility. We’ve seen that on the gas side, we don’t anticipate radical changes within our capital allocation program for this year. Could we see some small optimization here and there, well absolutely? But again, we’re not going to try to predict or chase pricing because inherently, we have a very balanced portfolio that gives us a very broad exposure across the whole commodity deck.

So we feel very good about that. We talked about some of the sensitivities within our portfolio. We still are very leveraged to oil. We like that. We think that, that is — I’m very constructive on oil now and in the future. And I like the fact that for every dollar change in WTI, that’s a $70 million uplift in cash flow for us. So I don’t anticipate any major shifts in capital allocation as a result of gas volume. On your other question just around the Bakken, obviously, typically, as we have moved into the Hector area, et cetera, we will see some natural variation in GOR. But again, we’re driven by profitability. I won’t say we’re fully agnostic to commodities. But again, we’re going to be driven by economics.

Michael Henderson: Yes. I think, Subhash, I’ll just chime in as well on the Bakken. What you’re seeing there is maybe just the improving gas capture situation in the basin as well and for ourselves. We’ve progressively each year got better and better and expect that to continue. So there’s probably an element of that playing into it as well.

Lee Tillman: Yes. And that’s been a conscious investment on our part to improve that gas capture to capture that value in the field as well as obviously the emissions benefits that come with that.

Operator: The next question comes from Nitin Kumar with Mizuho Securities. Please go ahead.

Nitin Kumar: Hi, good morning. And thanks for taking my question. I’ll limit myself to one question, one-part question. Can you talk a little bit about how do you see capital allocation amongst your four key U.S. resource base going forward? As you did pointed out, you had fewer wells in the Eagle Ford, but you’re also doing a few more in the Bakken than we expected for 2023. So just how should we think about the allocation of capital between the 4 plays?

Lee Tillman: Well, maybe I’ll say a couple of things, and I’ll let maybe Mike fill in some of the details. But — and this year’s capital allocation, about 80% of the capital allocation is flowing to the Eagle Ford and the Bakken. But we also have an uplift year-over-year in allocation to the Permian as well based on the outstanding results that we experienced in 2022. And so that’s what we’re looking at this year. I would expect that as we march forward in time, the Eagle Ford and the Bakken are still going to compete very, very heavily for capital allocation. But there’s no doubt that Permian now coupled not only with the Northern Delaware position, but with the Texas Delaware, Woodford, Meramec is going to start stepping up and competing more directly for capital.

There are obviously some other subtleties within each basin in terms of how the capital allocation is flowing. And maybe I’ll let Mike give a little bit of color on specifically what’s happening at a basin level.

Michael Henderson: It’s Mike here. Yes, just a little bit more detail on ’23. We provided the reg splits and the wells to sales in the deck. So 9 to 10 rigs in total, that’s excluding the JV activity, 4 rigs in the Eagle Ford, and I’ll be 1 on the Ensign acreage with 3 in Bakken and then 2.5 in the Permian then 1.5 JV rigs in Oklahoma. I think Lee mentioned that roughly 80% of the capital is going to Eagle Ford and market Eagle Ford is acute capital asset with the addition of Ensign. And maybe a little bit surprised well, maybe not, it was Permian just grabbing the majority of the remaining capital. And really, that’s driven by the excellent results that we’ve had in Permian last year. That asset is now effectively competing for capital against the Eagle Ford and the Bakken, which is no small mean feat, making a strong case for even more capital in 2024.

And a couple of elements to that well productivity is a big part of it, seen some very, very strong results there in aggregate. The 19 wells that we brought online last year averaged IP30s of over 2,200 barrels of oil equivalent per day and a 70% oil cut. Extended production history in the county is looking really good as well. One of the Thunderbird 4H well in Red Hills, that achieved an IP 120 over 2,100 barrels of oil per day. And I think you then couple that with the team. We’ve seen the teams really excel in their completion activities, we’re probably pumping for over 19 hours a day. I think you can combine all of that together and you see the capital efficiency, a lot to like about 2022 performance then. Just paint great job that the teams have done as well with acreage trades and kind of adding to our average lateral length, it just causes that asset to become even more capital efficient.

Yes, that’s probably.

Lee Tillman: Anita, we’ll take one more question.

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

Neil Mehta: Thanks for squeezing me in. Just a quick question on capital efficiency. Obviously, you provided the ’23 guide here, but are you seeing any signs of real time of the second derivative of inflation improving with diesel coming off, chemicals getting a little bit better. Just talk about what is sticky and what might actually be moving back into your direction?

Lee Tillman: Well, I think that there’s no doubt that the rate of change on inflation is certainly slow. And we — as Mike said earlier, what we have embedded in this year’s budget to $1.9 billion to $2 billion is basically the inflation levels that we saw as we exited 2022. So from our perspective, to the extent that we see inflation and commodities like diesel, et cetera, start to moderate. We would expect that to be basically a tailwind for us relative to not only our capital program, but also obviously our operating cost as well. Mike, I don’t know if you want to say anything else on that?

Michael Henderson: I think — I mean the other thing probably you look at rig count, broadly speaking, that’s definitely flattened also from an activity perspective that should be helpful as well. I kind of alluded to this in maybe one of my previous answers with commodity prices, particularly gas being where they are potentially some of the gas basins, maybe in particular, start to see activity and tailing off and that potentially could lead to a little bit of a weakening in the market as well. And I’ll probably start with rigs, but then there’s a non-current effect on contribution crews and everything else that comes in the oilfield service sector. So I think when — again, I touched on a few minutes ago when I think about our strategy, our approach to the year in terms of locking in, pretty much most of our prices in the first half of the year and then the flexibility in the second half of the year, I think we feel pretty good about the broad macro situation.

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

Lee Tillman: Well, thank you for your interest in Marathon Oil. I’d like to close by again thanking all of our dedicated employees and contractors for their commitment to safely and responsibly deliver the energy the world needs now more than ever. Thank you very much.

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