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spk08: 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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Guy Faber, Vice President of Investor Relations. Please go ahead.
spk05: 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 packets that address our fourth quarter and full year 2022 results, as well as our 2023 outlook. These 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, 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'll refer everyone to the cautionary language included in the press release and presentation materials, as well as the risk factors described in our SEC filings. We'll also reference certain non-GAAP terms in today's discussion, which have been reconciled and defined in our earnings materials. With that, I'll turn the call over to Lee and the rest of the team, who will provide prepared remarks. After the completion of these remarks, we'll move to a question and answer session.
spk06: Lee? 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. have 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 I've championed for the last few years. We're delivering financial and operational outcomes, not just at the top of our high-performing E&P peer groups, 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 protects shareholder distributions from capital inflation. During 2022, we 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 percent shareholder distribution yield, the highest distribution yield in our E&P peer space and one of the top 10 distribution yields 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 accreted 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 Eagleford scale. The Ensign acquisition makes us a stronger company, checking every box of our disciplined acquisition criteria. It's accreted to key financial metrics. It's accreted to our return of capital framework. It's a creative 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 in short, 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 50 cent per MMBTU change in Henry Hub only impacts our annual cash flow by just over $100 million, while a dollar change in WTI moves cash flow by about $70 million. reflecting continued leverage to oil pricing in 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 operation metrics that matter most, free cash flow generation, capital and operating efficiency, and shareholder distributions. And while our 2023 outlook is compelling, we're even better positioned for 2024 as our unique integrated gas business in Equatorgan A will benefit from an increase to global LNG price exposure. Just as a reminder, the current Henry Hub Index contract for equity ALBA gas through EGLNG expires at the end of 2023, and we will move to a market-based 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. He'll provide more detail around our return of capital performance and output. Dane?
spk05: Dane Cook- Thank you, Lee. Good morning, all.
spk11: Lee hit the return of capital high points, but given the importance of the topic, I'll further elaborate on our framework, our execution, and our outlook. As I stated before, returning a significant amount of capital to shareholders through the 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 returned 55 percent of our CFO to shareholders, significantly exceeding our 40 percent of CFO framework commitment. Total shareholder distributions amounted to $3 billion, good for a total shareholder distribution yield of 17 percent. 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 purchases 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 keynes. Repurchases are value accretive, a very efficient means to drive per share growth, and are synergistic to growing our base dividend. During 2022, we reduced our share count by 15%, And since reinitiating our share purchase program in October of 2021, we've reduced our share count by more than 20 percent, by far the most significant share count reduction in our peer space, as shown on the bottom right graphic on slide seven. Another benefit of our IBAC program is the capacity it creates for ongoing growth in our per-share base dividend. We recently raised our quarterly base dividend by 11 percent to 10 cents per share. the seventh increase in the trailing eight quarters. While this most recent increase is more than fully funded by incremental cash flow from the inside acquisition, ongoing share cap reductions from our buyback program create clear potential for further based 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 end sign acquisition makes our framework even more shareholder-friendly, adding close to 20 percent to our pre-acquisition operating cash flow, and therefore adding 20 percent to our shareholder distribution capacity. In addition, with the 2022 financial actual financial results in hand, along with the December close of Ensign, we anticipate we'll be able to defer U.S. cash alternative minimum taxes to 2024. Our objective for 2023 is to firmly adhere to our return of capital framework, continuing to return at least 40 percent of CFO while also paying down debt, including some of the Ensign-related acquisition financing. We believe we can do both. maintain 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 USX debt maturing, and we plan to pay that off with cash on hand to reduce gross debt and interest expense. We also have $200 million of the low-cost tax-exempt bonds maturing in 2023. These tax-exempt bonds are a unique and very flexible component of our capital structure. We plan to leverage the cost advantage of our tax-exempt credit capacity to enhance 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 percent return to capital commitment in 2023 provides visibility to $1.8 billion of minimum shareholder distributions at our reference price deck. That's a double-digit return of capital yield, one of the highest in our peer space. We've been executing share purchases 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 reductions. We 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 will briefly walk us through an update on the Ensign acquisition.
spk14: 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 accretion, consistent with Dane's comments, prescient to inventory life and quality, and industrial logic with enhanced scale, all while maintaining our financial strength and investment-grade balance sheet. And we based our inside valuation on a one-rig maintenance program with no credit for potential upside associated with redevelopment or refracs. 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 now 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 confidence that comes with an acquisition in an established basin that has a track record of success. On the execution side, As highlighted on slide 11 of 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 Eagle Creek, and therefore in 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 EGLEFORD program. The inside wells are expected to deliver creative capital efficiency and financial returns for comparable oil productivity to those in our LEED legacy EGLEFORD program. I will now hand over to Mike to provide more color on our 2023 capital program. Thanks, Pat.
spk02: Turning to slide 12 of our deck, I'll provide a brief overview of the high points of our 2023 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 of 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 to $2 billion capital budget to deliver $2.6 billion adjusted free cash flow at just over a 40 percent reinvestment rate. As we 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 regs and three to four 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 Welsh sales, along with a very modest negative carryover impact from winter storm Elliot, concentrated in the back end. 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 2025. Overall, our 2023 plan is a disciplined and high-confidence program designed to deliver strong financial and operational outcomes. In the Eagleford, we'll run a four-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 three rigs on average, again, focusing our activity in our high-quality hectare area of the plain, where the average well pays out in less than six months at current commodity prices. In the Permian, we expect to continue improving our capital efficiency by increasing, on average, lateral lengths 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 completion performance that we've delivered since getting back to work over the second half of 2022 supports a higher level of capital allocation. We therefore plan to spot between 25 and 30 wells this year, inclusive of at least one multi-well pad in our Texas, Delaware, Merrimack Woodford place. which will support a higher level of wealth sales in early 2024. Our Texas-Delaware position is no longer an exploration plate. 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 environments, we aren't exposing much capital to the asset this year. Rather, near-term activity is limited to a one-and-a-half-rig joint venture program that will allow us to efficiently defend our acreage position and delineate some lower-priority acreage with 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.
spk06: Thank you, Mike. 2022 was an exceptional year for our unique, world-class integrated gas business, NEG. 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 assumed 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. By 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 an 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 to lend gas volumes on a toll 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, AlbaSource 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 MMBTUTTF, 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 ullage through EG LNG. 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 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 protects distributions from capital inflation. For 2023, we're providing clear visibility to double-digit shareholder distribution yields. 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 . We have delivered per share growth across all the metrics that matter via consistent share repurchase program that leads our peers, in addition to a durable and competitive-based 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 InSign 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, lifting billions out of energy poverty, and protecting the standard of living we have all come to enjoy.
spk12: With that, we can open the line for Q&A.
spk08: We will now begin the question and answer session. To ask a question, you may press star, then one on your touchdown zone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. Please limit yourself to one question and one follow-up. If you have further questions, you may re-enter the question, too. The first question today comes from Janine Y. with Barclays. Please go ahead.
spk01: Hi. Good morning, everyone. Thanks for taking our questions. Our first question... Good morning. Our first question may be 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 for 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 nth in 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 Eagleford in 23, and we were just wondering if you could share any further details about the implied improved capital efficiency in the Eagleford, because it seems to be pretty meaningful. So, for example, if Is the Eagleford 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.
spk02: Hi, Janine. It's Mike here. I'll take that call. So to maybe answer part of your question there, yes, I think it is safe to assume that the Eagleford is in maintenance mode, oil maintenance mode this year. I think it's also correct, you're also correct, in that the legacy position, we are holding volumes flat on a lower wealth 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 wealth online in the year. We are going to be bringing close to 60% of our legacy wealth to sales online. 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 in to this year's business plan and the ultimate volumetric outlook. So, you know, we were already setting up for a strong year in Eagleford 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 four wells. Nine wells from the two pads that we brought online in the condensate window. You know, very strong productivity, top decile in all oil really consistent with our belief that this is some of the highest capital efficiency inventory in Eagleford. And that only adds to what was already a highly capital efficient business. So, you know, very, very excited about the opportunities that the acquisition brings us this year and even beyond.
spk01: Okay, great. Fame fractured on Les Wells is always a good thing. Thank you for all that 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 for 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, you know, if oil is 85 or 90, you start going after that more? Can you provide any more color? Thank you.
spk12: Good morning, Janine.
spk11: Yeah, definitely. Let me kind of go back to our return of 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 that. One, as I stated, we're firmly committed to our return of capital framework, minimum of 40% of operating cash flow to shareholders, as long as WTI is above $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 purchases. So, significant return in the form of share purchases, and that's how we're thinking about 2023 as well. The Ensign acquisition really enhances our shareholder return capability, added about 20 percent to both our pre-acquisition operating cash flow and our shareholder distribution capacity. So another way to think about that is 40% minimum shareholder return post-ensign would have equaled 50% pre-ensign. So at our 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're intent to continue that. Too soon to give you more guidance to model on that, but that's our bias. Now, 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's really strong. Ratings 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 that $1.5 billion two-year term loan, paid off within that window. 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, restate it, our primary goal, our number one goal is return to shareholders, and that will not take a backseat 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. It's like 8.5% to 9% coupon, so it would 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 with 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 an aggregate $1 billion in tax-exempt bonds. They mature somewhat relatively over 23, 24, and 26. And under that tax-exempt bond arrangement, we can refinance these as they come due in any 10 or 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 they, you know, things normalize as we go forward here a little bit from an interest rate perspective. You know, the coupon on this one retiring out is 2%, and that's kind of apart from 400. We really like that flexibility. And the last thing I'll say is we extended recently our $2.5 million credit facility out to July of 2027. So kind of flexibility there. Bottom line, shareholder returns first, payback debt second. We have capacity to do both. I'm not going to give you a bright line formula how we're thinking about it, but that's our commitment.
spk12: And that's how we're going to proceed.
spk01: Great.
spk12: Thank you, gentlemen. Okay.
spk08: The next question comes from Neil Dingman, Truist Securities. Please go ahead.
spk13: Mordeal, 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 it favors the dividend payout? Just wondering, I mean, do you all Think about some mid-cycle prices used when looking at the metrics, or is there any other details you're dating to provide on kind of how you're looking at that buyback versus the diff?
spk11: Yeah. Yeah, go ahead, Dan. I'll take a cut at it, Neil. Yeah, 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 try and not get too far above, say, 10 percent 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 purchases that is surprisingly how quickly you can buy back enough stock to pay for another penny increase. And we'll definitely be in that window again, you know, sometime this year. So that's how we think about the dividend share repurchases. Obviously, we're getting the 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, you know, buy back stock.
spk06: Yeah, I think, Neil, you know, if you look at the, you know, aggregate efficiency of our share repurchase program, you know, 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 those mechanisms, we believe, are still the case to be as we look ahead into 2023.
spk13: Yeah, 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. I'm just curious on how volatile you all believe the cost Let's say for the next two, three, maybe even four quarters will continue to be. And, you know, 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 just wondering when you guys look at that, how you're thinking about costs here for the call the newer term and locking in.
spk06: Yeah, maybe I'll just provide a couple of comments and 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 two 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 as a 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 to $2 billion number fully contemplates that full year impact of those inflationary pressures. I think the team has done an outstanding job of being very disciplined about how we lock in both capacity and cost from our service providers. And maybe I'll let Mike just expand a little bit on that point.
spk02: Yes, thanks. Thanks, Liz. Mike here, Neil. You know, maybe a couple of things. How I'd maybe characterize 23 at a high level, We've kind of assumed similar service costs to 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 10-15% inflation. That is built into our 2023 budget. That's relative to 2022. As we mentioned in the past, we've been working this one hard. Really, our objective was to to really base load the maintenance program and kind of really try to minimize the need for going out to the spot for spot work. A lot of benefits in doing that from a safety execution and commercial perspective. We've taken what I'd maybe 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 we've been successful there. The majority of the folks that we're working with in 23 are the same folks that we were working with in 22. As I think about the year, for the first half of the year, the majority of our rig, pressure pumping, sands, steel leads, all fully secured, Most of the price is locked in. There's a little bit of open pricing, but not a lot. And where we can try to index link that to the pricing mechanisms. And then maybe for the second half of the year, that's where we've been a little bit more patient. That feels like the right call, 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 you know, potentially that could work to our advantage later in the year, particularly if you see some of this commodity price weakness that would be seen recently if that persist, especially in the natural gas side of the business, that could potentially lead to less drilling completion activity, particularly in some of those higher cost gas plays.
spk06: Yeah, and maybe one just kind of closing comment as well, Neil. You know, 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, you know, 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. Obviously a lot of great work by the teams, 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 left this question.
spk13: That's a great add. Thanks, Lee. Thanks, Mike.
spk00: Thanks, Neil.
spk08: The next question comes from Doug Liggett with Bank of America. Please go ahead.
spk03: Good morning, guys. Thanks for getting me on. So, Lee, tremendous acquisition in the Eagleford. 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 ego for today is more than 15 years, and that's about half the 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. I've got to follow up, please.
spk06: Yeah, 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. You know, 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 four or five 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 companies. in any form or fashion when it comes to quality inventory life with exceptionally low break-evens. 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 Eagleford. But as you know, capital allocation and consumption rates ultimately set The inventory-like 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. You said, well, you know, how do you think about growing that inventory life, you know, 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? 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 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 and But if anything, Ensign has actually raised that bar and raised and elevated that criteria because it was so accretive to the overall enterprise and specifically the Eagle for metrics.
spk03: I appreciate the answer, Lee. I mean, good assets in the hands of great management with a lot of cash. 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, or 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 five 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, you know, in terms of whether it might require capital or third-party owners of that gas to spend capital, which, you know, 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 bike fill it?
spk06: Yeah, well, I think in the, first of all, in the decline rate, you know, on the equity, the equity ALBA gas condensate field, you know, 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, Doug. You know, first of all, As I said in my opening comments, we have this world-class, very unique infrastructure sitting in one of the most gas-prone areas of West Africa. And quite frankly, those molecules will not get monetized unless they probably flow through EGLNG. 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, is a if you will, an others 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 Elend pipeline. And that was obviously critical for the Elend 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, We're 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 ALEND project. In aggregate, when I think about all of those opportunities, when I think about our already demonstrated success at Elen, we have a 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 EGLNG out to 2030 and beyond.
spk12: Appreciate the full answer, Lee. Thanks so much.
spk05: And, Nina, maybe we could do one question per analyst to try to make our way through the remainder of the queue here.
spk08: Okay. The next question comes from Matt Portillo with TPH. Please go ahead.
spk07: Just to 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.
spk14: Yeah, I'll take this one. Morning, Matt. This is Pat. Yeah, as you said, we just completed three wells on our most recent pad. The wells are performing well. to date, consistent with our pre-drill expectations. All three wells have achieved at least 1,000 barrels of oil per day on flowback. 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-oil ratios and a low decline, so positive outcome there. You may recall that we deliberately downspaced this pad in Woodford to check our spacing for development. We collected a lot of fiber data and other data to try and look at the optimal spacing, both vertically and horizontally. The key takeaway so far has been there's no communication we've seen between the Woodford and the Merrimack, which gives us strong evidence that we can successfully co-develop those two reservoirs without any interference. With regard to future development spacing, I'd say early learnings from this pad appear to confirm our original view that optimally we'll probably go with a 4x4 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 wood per oil well ever drilled, and that well continues to just be a really strong well. We now have about 12 wells online across the 5,000-acre position that we have, eight in the Woodford, four in the Merrimack. Again, very confident in all their performance, very high oil productivity, low water oil 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 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 that goes. We'll go from there.
spk12: Thanks, Matt.
spk08: As a reminder, please limit yourself to one question. The next question comes from Subhash Chandra with Benchmark Company.
spk04: Yeah, hi, thanks. Just curious on your gas views. Yesterday we might have seen a company that targets gas oil and sees gas as derivative and the risks of that strategy given, you know, what's happened in the macro world. I think in your commentary, you are more cautious on gas, you know, 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, well, I should, well, follow up, no follow up, sorry, Bakken is getting gas here and how you, you know, kind of look at that going forward.
spk06: Yes, this is Ty. 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. Even though prices will inevitably, you know, 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 full 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 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 don't anticipate any major shifts in capital allocation as a result of gas volatility. On your other question just around the BAC, and, you know, obviously, you know, typically as we have moved into, you know, the Hector area, et cetera, you know, 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.
spk02: Yeah, I think I'll just chime in as well in the back. And what you're seeing there is maybe just the improving gas capture situation in the basin as well and for ourselves. You know, 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.
spk06: Yeah. And that's been, you know, 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.
spk12: Thanks, Subesh.
spk08: The next question comes from Nitin Kumar with Mizzou Securities. Please go ahead.
spk10: 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 plays going forward? As Janine 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 four plays?
spk06: Well, maybe I'll say a couple of things and I'll let maybe Mike fill in, you know, some of the details. But in this year's, you know, capital allocation, about 80% of the capital allocation is flowing to the Eagleford 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, you know, So that's what we're looking at this year. I would expect that as we move March forward in time, the Eagle Heart 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-Merrimack, is going to start stepping up and competing more directly for capitals. 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.
spk02: Hey, Nitin, it's Mike here. Yeah, just a little bit more detail on 23. We provided the rig splits and the wells to sales and the deck, so nine to ten rigs in total. That's excluding the JV activity. Four rigs in the Eagleford, and that'll be one on the Ensign We've got three in Bakken and then two and a half in Permian and then one and a half JV rigs in Oklahoma. I think Lee mentioned there roughly 80% of the capital is going to Eagleford and Bakken. Eagleford is obviously now the highest capital asset with the addition of Ensign. And maybe a little bit surprising, well, maybe, maybe not, was Permian just grabbing the majority of the remaining capital. And, you know, 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 Eagleford and the Bakken, which, you know, is no small mean feat. Making a strong case for even more capital in 2024. 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 bottles of oil equivalent per day and a 70% oil cut. You know, extended production history in Lee County is looking really good as well. One of the Thunderbird 4H well in Red Hills, that achieved an IP120 of over 2,100 bottles of oil per day. And I think you then couple that with the GNC performance that we've seen the teams really excelling there. You know, completion activities, we're probably pumping for over 19 hours a day combined. Combine all of that together and you see the capital efficiency. You know, a lot to like about the 2022 performance. You then just factor in the 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. Yeah, that's probably it.
spk12: Anita, we'll take one more question.
spk08: Thank you. Our next question comes from Neil Mehta with Goldman Sachs. Please go ahead.
spk09: Yeah, thanks for sneaking me in here. Just a quick question on capital efficiency. Obviously provided the 23 guide here, but are you seeing any signs 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.
spk06: Well, I think that there's no doubt that the rate of change on inflation is certainly slowing. And as Mike said earlier, what we have embedded in this year's budget, the $1.9 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 costs as well. Mike, I don't know if you want to say anything else on that.
spk02: I think, I mean, the other thing probably you look at, look at rate count, broadly speaking, that's definitely flattened off. So from an activity perspective, that should be helpful as well. You know, I kind of alluded to this in maybe one of my previous answers. You, You know, with commodity prices, particularly gas, being where they are, potentially some of the gas basins, maybe in particular, start to see activity tailing off. And, you know, that potentially could lead to, you know, a little bit of a weakening in the market as well. And that will probably start with rigs, but then there's a knock-on effect on completion crews and everything else that comes into the oilfield service sector. So, you know, I think when, again, I touched on this a few minutes ago, and I think terms of blocking in pretty much most of our prices in the first half of the year and then that flexibility in the second half of the year. I think we feel pretty good about the broad macro situation.
spk12: Thanks, Neil.
spk08: This concludes our question and answer session. I would now like to turn the conference back over to Lee Tillman for any closing remarks.
spk06: Well, thank you for your interest in Marathon Hall, and 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.
spk08: This conference is now concluded. Thank you for attending today's presentation.
spk06: You may now disconnect.
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