Good morning, and welcome to the Marathon Oil Q4 and full year 2023 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing 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 one on your telephone keypad. To withdraw your question, please press star two. Please note, this event is being recorded. I would now like to turn the conference over to Guy Baber, Vice President, Investor Relations. Please go ahead, sir. Thank you very much, and thanks as well to everyone for joining us on our call this morning. Yesterday, after the close, we issued a press release, a slide presentation, and an investor packet that addressed our fourth quarter 2023 results and our full year 2024 outlook. Those documents can be found on our website at marathonoil.com. Joining me on today's call are Lee Tillman, our Chairman, President, and CEO; Dane Whitehead, our Executive VP and CFO; Pat Wagner, Executive VP of Corporate Development and Strategy; and Mike Henderson, our Executive VP of Operations. As a reminder, today's call will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. I'll refer everyone to the cautionary language included in the press release and presentation materials, as well as to the risk factors described in our SEC filings. We'll also reference certain non-GAAP terms in today's discussion, which have been reconciled and defined in our materials. So with that, I'll turn the call over to Lee and the rest of the team, who will provide prepared remarks. After the completion of their prepared remarks, we'll move to a question-and-answer session, and in the interest of time, we ask that you limit yourselves to one question and a follow-up. Lee? Thank you, Guy, and good morning to everyone joining us on our call today. As I always start these calls, I wanna first and foremost thank our employees and contractors for their dedication and hard work in delivering the excellent results we have the privilege of discussing today. I especially want to thank our employees and contractors for their enduring commitment to our core values. On that front, we have a few notable accomplishments to highlight today. First, we delivered a record safety year in 2023, as measured by total recordable incident rate for both our employees and our contractors. This builds on a multiyear track record of top-quartile TRIR in our industry. Providing a safe, healthy, and secure workplace remains a top priority for us, with our safety performance a key element of our executive and employee compensation scorecards. Second, we continue to make progress in reducing our natural gas flaring, improving our total company gas capture to 99.5% in 2023, a new high for our company. We'll continue to work hard on our journey of continuous improvement, moving toward our ultimate objective of zero routine flaring. And third, we achieved our 2025 GHG intensity reduction goal of 50% relative to 2019 levels, a full two years ahead of schedule, consistent with our objective to help meet the world's growing demand for oil and natural gas while achieving the highest standards of environmental excellence. We are a results-driven company, but how we deliver those results matters, and I couldn't be more proud of our people and what they've accomplished. Yet this type of delivery isn't new for us. It's the continuation of a well-established trend. Before I get into our 2023 results and 2024 outlook, I'd like to reflect on what I believe is our unmatched track record of delivering on our framework for success. We're now more than three years into our more S&P, less E&P journey. My challenge to our company was to raise our game and compete head to head with not just the best companies in our sector, but with the best companies in the S&P 500, and to do so year in, year out, through the commodity cycle on the metrics that matter most: sustainable free cash flow generation, return of capital to shareholders, and capital and operating efficiency. For the last three years, we've consistently held true to our framework for success. We've prioritized corporate returns, sustainable free cash flow, meaningful return of capital, and we delivered differentiated execution quarter in, quarter out. We've continued to enhance our multi-basin portfolio, which has produced the best capital efficiency in the sector, and we've protected our investment-grade balance sheet while prioritizing all elements of our ESG performance. I believe our commitment to our strategy and the consistency of our execution over the last three years has successfully differentiated Marathon Oil in the marketplace. The proof points are summarized in slide six of our deck. First, sustainable free cash flow generation. Through disciplined, corporate returns-focused capital allocation, we've generated $8.4 billion of free cash flow over the trailing three years. That equates to over 60% of our current market cap, almost double that of our E&P peers, and 6x that of the S&P 500. Next, meaningful return of capital to shareholders. Over the last three years, we've consistently held true to our transparent, cash flow-driven return of capital framework that prioritizes our investors as the first call on cash flow, not the drill bit and not inflation. In total, we've returned $5.6 billion to our shareholders, equivalent to over 40% of our current market cap. Again, that's double that of our E&P peers and well in excess of the S&P 500. Capital and operating efficiency, a testament to the quality of our multi-basin portfolio and the extreme discipline inherent in both our capital allocation and cost structure. Over the trailing three years, we've delivered the lowest reinvestment rate in the E&P sector, below the S&P average, and our well level capital efficiency, according to independent third-party data, has been the best in the E&P's peer space, 35% superior to the peer average. 2023 was emblematic of these three proof points. Last year, we delivered $2.2 billion of adjusted free cash flow, $1.7 billion of shareholder distributions, equivalent to 41% of our CFO, providing a shareholder distribution yield of more than 12%, $1.5 billion of share repurchases that drove a 9% reduction to our outstanding share count, a 22% increase to our base dividend while maintaining our pure low free cash flow breakeven, $500 million of gross debt reduction, and 28% growth in our production per share, driven by our share repurchase program and the seamless integration of the Ensign-Eagle Ford acquisition. That's what comprehensive delivery on our key priorities looks like. If you like 2023, then you will not be disappointed in our 2024 business plan, which offers more of the same as we continue to build on our multi-year track record. We have confidence in our strategy and in our capital allocation and return of capital frameworks, and our focus will be on consistently executing our plan amidst all the volatility inherent in our sector. At the end of the day, I expect our plan to again benchmark with the very best companies in our sector, outperforming the S&P 500. More specifically, this year, we expect our $2 billion capital program to deliver approximately $1.9 billion of free cash flow, assuming $75 WTI, $2.50 Henry Hub, and $10 TTF. We fully recognize that we are a price taker, not a price predictor, and commodity price volatility impacts our financial outcomes. As such, we've provided cash flow sensitivities for each of the key commodities within our slide deck to help you model expectations based on your own commodity forecast. We'll stay true to our CFO return of capital framework, expecting to return at least 40% of our CFO to shareholders, again, providing visibility to a double-digit shareholder distribution yield. We expect the underlying capital efficiency of our 2024 capital program to improve as we maintain our well productivity leadership and work all avenues to improve capital efficiency, including further extending lateral lengths. Perhaps most importantly, we believe our results are sustainable. That's true for our U.S. Multi-basin portfolio, and that's true for our integrated gas business and EG. As you all know, our EG business now has no Henry Hub exposure, with the expiration of our legacy contract at the end of 2023. That business is now fully realizing global LNG pricing, which will drive improved financial performance this year. We believe this improvement is sustainable due to all the great work our team has done to advance the EG Gas Mega Hub concept. For example, over the next five years, we're expecting our EG business to generate cumulative EBITDAX of approximately $2.5 billion, assuming flat $10 TTF commodity pricing. With that, I'll turn it over to Dane, who will walk through our commitment to return of capital while also fortifying our investment-grade balance sheet. Thank you, Lee, and good morning, everybody. As Lee mentioned, in 2023, we continued building on a peer-leading track record of returning capital to shareholders as consistent with our differentiated cash flow-driven framework that prioritizes our shareholder as the first call on capital. Importantly, we did this while continuing to make progress on our balance sheet objectives through $500 million of gross debt reduction. We've built a track record of providing a truly compelling shareholder return proposition, while at the same time continuing to enhance our investment-grade balance sheet. We did both in 2023, and that's my expectation again for 2024. More specifically, on our 2023 return of capital delivery, total shareholder returns amounted to $1.7 billion, including more than $400 million during the fourth quarter. That translates to 41% of our CFO, consistent with our framework, and an annual distribution yield of over 12% on our current market cap, compelling relative to any investment opportunity in the market. Majority of shareholder returns came in the form of share repurchases, which reduced our share count by 9% last year. That's about double the share count reduction of our next closest competitor. For full year 2023, we grew our oil production per share by a peer-leading 28% due to our share repurchase program and the integration of the accretive Ensign acquisition in the... Looking to 2024, we expect to prioritize free cash flow via our disciplined capital allocation framework by holding our top line in oil production flat.... We also remain focused on driving significant per share growth and fully expect to maintain our long-held leadership position in the peer group. While the majority of our capital returns in 2023 came in the form of share repurchases, our base dividend remains foundational, and we remain committed to paying a competitive and sustainable base dividend to our shareholders. During 2023, we raised our base dividend by 22%, one of the strongest growth rates in our sector. Importantly, we did so with laser focus on sustainability, maintaining one of the lowest post-dividend free cash flow breakevens in the peer group. Our consistent and committed approach to shareholder returns over the last three years has positively differentiated our company, and our approach in 2024 will remain the same. Priority number one remains consistently delivering returns of at least 40% of our CFO in the form of share repurchases and base dividends. That minimum 40% level translates to about $1.6 billion of expected shareholder distributions at a reference price deck, again, providing visibility to a compelling double-digit shareholder distribution yield. With our stock trading in the low $20 per share range and at a free cash flow yield in the mid-teens at strip pricing, repurchases remain highly value accretive. They're also a very efficient means to continue driving our per share growth and are highly synergistic with continuing to grow our per share base dividend without negatively impacting our peer-leading free cash flow breakeven. To summarize, our 2024 return on capital plans, at least 40% of our CFO to shareholders, which will be near the top of our sector, driving peer-leading per share growth and competitive, sustainable growth in our base dividend. We're also committed to further improving our investment-grade balance sheet, and we plan to direct excess cash flow to continue reducing gross debt. We have tremendous financial strength and flexibility in our capital structure, with net debt to EBITDA approximately 1x at strip pricing. We have $400 million of tax-exempt bonds to mature this year. This is a really unique vehicle in our capital structure, and we'll likely remarket those at an advantaged interest rate relative to taxable debt, as we've done previously. We also have plenty of flexibility to manage the $1.2 billion remaining outstanding on our Ensign term loan, due at the end of this year. The markets are wide open for us to potentially re-refinance a portion of that debt. As a reminder, we have $2.1 billion of available capacity on our credit facility that matures in 2027. Even if we opt to refinance in total the maturing tax-exempt bonds and the term loan, we will retain capacity to pay off at par almost $1.5 billion of commercial paper and bonds, which would get us to our medium-term gross debt goal of $4 billion. One final comment from me on our 2024 outlook before I turn it over to Mike to walk through some of the details of our capital program. Consistent with our prior messaging, our 2024 financial guidance assumes we'll transition to becoming an alternative minimum tax, or AMT, cash taxpayer this year. The AMT tax rate is 15% on our pre-tax U.S. income. Our primary exposure here is domestic, as our EG income will largely be offset by current year foreign tax credits. The new information we're providing today involves research and development, or R&D, tax credits. We recently completed a study of capital spent in past years on organic enhancement activities that qualified for R&D tax credits. As a result, we expect to apply approximately $150 million of these R&D tax credits this year as a direct offset to a significant portion of our 2024 AMT cash payments. A direct benefit to our free cash flow is most likely not included in any sell-side models at this point. With that, I'll hand over to Mike, who will walk us through the finer points of our 2024 capital program. Thanks, Dane. As we highlighted earlier, we're a results-driven company, so I'll start with the expected bottom-line results of our 2024 capital program. We expect our $2 billion capital program to deliver $1.9 billion of free cash flow, with one of the lowest reinvestment rates and free cash flow breakevens in the sector. This will enable us to deliver our investors a truly compelling shareholder return profile. We fully anticipate these bottom-line financial outcomes and the underlying capital efficiency of our 2024 program to again benchmark at the very top of our high-quality E&P peer group. To deliver these outcomes, we'll operate approximately nine rigs and four frack crews on average this year. We expect our capital program to again be first half-weighted, with about 60% of our CapEx concentrated in the first half of the year, largely a function of the timing of our wells to sales. This should drive stronger production and underlying free cash flow over the second half of the year. At the midpoint of our full year guidance, we expect to deliver flat total company oil production of approximately 190,000 barrels of oil per day, consistent with what we previewed last quarter. Yet importantly, as Dane highlighted, we fully expect to continue driving significant growth in oil production on a per-share basis. We're guiding to a modest year-on-year decline in our oil equivalent production this year. This BOE decline is largely a function of well mix and our focus on value over volume. Given the extreme weakness in natural gas prices relative to oil, we're allocating capital to the oiliest, and thus highest value areas in each of our plays, consistent with our prioritization of corporate returns and free cash flow generation. We're also expecting some modest ongoing base decline in Equatorial Guinea. As is typical for our business and consistent with last year, there will be some quarter-to-quarter variability in our production. First quarter should mark the low point for the year, impacted by about 4,000 barrels of oil per day of winter weather-related outages, largely concentrated in the Bakken. We'll then grow from first quarter levels as we bring more wells to sales as the year progresses. Now to the more important details of our 2024 program. We expect to deliver our flat oil production guidance with 5%-10% fewer net wells to sales than last year. This is a function of improving underlying capital efficiency, driven by durable well productivity at peer-leading levels, an additional 5% increase to our average lateral lengths, and modest deflationary capture that is built on conservative underlying assumptions. Approximately 70% of our total capital will be allocated to our high-confidence Eagle Ford and Bakken programs, where we have a demonstrated track record of execution excellence. For 2023, external state data indicates we delivered six-month per-foot oil productivity, 60% better than the basin average in the Eagle Ford, and 40% better than the basin average in the Bakken. With our cost structure, we believe we're leading each basin in capital efficiency. We expect another year of leading performance in 2024 as we maintain our productivity advantage and find ways to continue enhancing our capital efficiency. The bulk of our remaining resource play spend will be dedicated to the Permian, where we're increasing our activity and capital investment in a disciplined manner. Since getting back to work with a consistent D&C program in the Permian a couple of years ago, we've delivered among the best well productivity in the basin with competitive drilling completion performance. We're transitioning to an almost exclusive two-mile plus lateral program. This year, over 20% of our Permian wells will be 3 mi laterals. We'll get into more details in EG in a minute, but our EG CapEx will be up modestly this year, with spend limited to long lead items in preparation for potential Alba infill program in 2025. Our non-development capital is higher this year, due largely to more environmental, regulatory, and emissions-related spending, as well as some non-recurring projects such as water infrastructure and pipeline additions. For context, a couple of years ago, this bucket represented about 5% of our total capital. It's about 10% this year. Importantly, however, we expect our non-D&C capital to peak this year and to trend lower in 2025. I would also add that many of those projects designated as emissions-related have the added economic benefit of enhancing our reliability and uptime performance. Now to Lee for EG and the wrap-up. Thank you, Mike. Focusing on slide 15 in our deck, with the expiration of our legacy Henry Hub linked LNG contract at the end of last year, our EG integrated gas business is now fully realizing global LNG pricing, and in January, we lifted our first cargo under these new contractual terms. Consistent with our prior disclosure, the majority of our Alba LNG sales are covered by the five-year sales contract we announced last year. That contract is TTF linked. The balance of our 2024 LNG cargoes have now all been contracted, but at a JKM price linkage. This will afford us a nice combination of both TTF and JKM price exposure this year. Although global LNG pricing has weakened somewhat on warmer winter weather, the arbitrage between global LNG and Henry Hub pricing is still significant, and therefore should still drive improved financial performance for our international operations. We're guiding to $550 million-$600 million of EG EBITDAX this year, assuming $10 TTF. That's a significant increase from actual 2023 EBITDAX generation of $390 million. Importantly, we don't expect this to be a one-year financial uplift. For some time, we've been focused on sustaining this improved financial performance by progressing all elements of the EG Gas Mega Hub concept, supported by the HOA signed with the EG government and our partner last year. The five-year EG EBITDAX outlook we're providing today is intended to demonstrate the sustainability of our EG cash flow generation. Over the next five years, we expect to deliver cumulative EG EBITDAX of approximately $2.5 billion, assuming $10 TTF and $80 Brent flat. Beyond realizing global LNG pricing, there are a few drivers of the strong performance over the duration of the five-year period. They include ongoing methanol volume optimization to maximize higher margin, higher working interest LNG throughput, an Alba infill well program, which will help mitigate Alba decline and maximize the amount of Alba equity gas through the LNG plant in coming years, and further monetization of third-party gas through the Aseng gas cap as we continue to take full advantage of our unique and highly valuable gas monetization infrastructure in one of the most gas-prone areas of the world. And while this five-year EBITDAX scenario reflects the life of our recent global LNG sales agreement, we fully expect to extend the life of EG LNG beyond the next five years, well into the next decade, as we continue to advance the longer-term gas mega hub concept. In summary, consistent with our more S&P mandate, for the last three years, we've been delivering financial performance, highly competitive with the most attractive investment alternatives in the market, as measured by corporate returns, free cash flow generation, and return of capital. I fully expect 2024 to build on this track record. Our compelling investment case is simple: a high-quality, multi-basin U.S. portfolio and integrated global gas business that delivers peer-leading free cash flow. A unique and differentiated return of capital framework that provides our shareholders with the first call on cash flow, the output of which is clear visibility to compelling shareholder distributions across a broad range of commodity prices. Sector-leading growth in per share metrics, and a multiyear track record of consistent execution and proven discipline. Perhaps most importantly, everything we're doing is sustainable through the commodity cycle. This is due to the quality and depth of our U.S. multi-basin portfolio, where we have over a decade of high return inventory and a disciplined and multifaceted approach to portfolio renewal. It's also due to our differentiated integrated gas business that's now fully realizing global LNG pricing as we continue progressing all elements of the regional gas mega hub concept. Rest assured, our commitment to our strategy is unwavering and is built upon our core values, resilience across the commodity cycle, and our long-term track record of success. With that, we can open the line for Q&A. Thank you. We will now begin the question and answer session. If you have a question, please press star one. Our next question comes from Arun Jayaram with JPMorgan Chase. Please proceed. Good morning, Lee. Lee, I wanted to start off with on M&A. Obviously, a significant level of industry M&A activity, including a large transaction announced in your Bakken backyard last night. You know, I was wondering if you could provide some perspective on how should we think about M&A for MRO post the Ensign transaction. And I did want to cite, you know, a recent example of a low-cost Permian producer as a low-cost structure, such as yourself, did announce a deal to get more scale in the Permian, adding more sticks on the map, and the multiple appears to have rerated on that deal. So again, just some thoughts on where the M&A landscape and what this means for MRO. Yeah. Yeah. Thank you, Arun. First of all, you know, size and scale are important, but it's not obviously just about getting bigger, it's about how do we get better. So any consolidation opportunity, fundamentally needs to enhance our ability to execute on the path that we've been on, really, for the last three years that I just described in my opening remarks. We have a very clear, very transparent framework for assessing M&A. That framework is unchanged, and if anything, the bar is even higher now with the successful addition of the Ensign asset that you mentioned. And just as a reminder, Arun, there are really five elements of that criteria. First and foremost, of course, is accretion to financial metrics. Secondly, accretion to our cash flow-driven return of capital framework. Third, accretion to our resource or inventory life, with inventory that competes for capital, from day one. Clear industrial logic, which to us means going into basins where we have a well-established level of execution, excellence, and credibility. And then finally, of course, doing all this without any harm to our investment-grade balance sheet. We know that's a challenging criteria, but we can be discerning, and we can be patient. As I mentioned, with over a decade plus of high-quality inventory, we can, we can wait for those opportunities like Ensign that ticks all the boxes. And, and that's what made Ensign so compelling. I mean, we integrated that asset into our operations in, essentially a couple of months. Mike and his team did a fantastic job doing that. We never missed a step, and we've seen others stumble in that very critical integration step. So can we be acquirer? Absolutely. Should you expect us to still apply our criteria and be discerning and be as disciplined as we are in our organic business? Absolutely. ... Great. My follow-up is on EG, Lee. You provided a five-year outlook, which, you know, suggests relatively stable earnings profile or EBITDAX, you know, relative to your 2024 guide. I was wondering if you could talk about, you know, opportunities to extend these financial outcomes in EG beyond the five-year threshold. As well as I was wondering if you could address the recent decision by a super major to exit EG, and does that open up any opportunities for you, given that, you know, that country exit? Absolutely. Well, first of all, I wanna be very clear. The five-year view we provided was really just a scenario that matched up with the LNG sales agreement that we just inked last year. And so you should not interpret that as a life of LNG kind of model. This was just to match up with that certainty that we now had around that five-year TTF-linked LNG sales agreement. The reality is that when we look at all of the things that we have active now in EG, whether that's methanol volume optimization, the future, you know, potential for Alba infill drilling, and even more third-party molecules like Aseng, we already see the path to extend well past 2030. Don't view that five-year view as anything other than just matching up with, in fact, that five-year sales agreement that we inked on TTF. In terms of, you know, exits, you know, out of EG, you know, by super majors, clearly that's a very, you know, unique set of circumstances where you have a concession that's kind of at the end of its PSC term. It's a very mature, you know, oil play there. And again, pretty much an end of field life that likely is going to be taken over by the government and run by the government. So very different set of opportunities than we would look like. Again, I would just take you back, Arun, to the criteria that we just talked about, and making sure that we look at any opportunity through that same lens when we're talking about doing something inorganically. But we do believe there's a lot of opportunity outside of that within EG, both from an equity molecule standpoint as well as a third-party molecule standpoint. The good news for us is when we were able to bring the Alba molecules to EG LNG, that was our first kind of third-party framework. We can now replicate that framework going forward, and that project constructed a very significant piece of infrastructure that we can now use for the future. Great. Thanks a lot. Thank you. Our next question comes from Neil Dingmann with Truist Securities. Please proceed. Morning, all. Nice update. First question's likely for Mike. On, you mentioned, Mike, you referenced the leading operational efficiencies, which are noted. I'm just wondering, could you maybe give a little more detail? Is it largely the longer laterals, or, you know, maybe what other key drivers would you point us to, that, that's really driving this, this remarkable upside? Yeah, we all, Neil, I can certainly answer that. So, yeah, underlying resource play, capital efficiency, as we noted, is improving in 2024, and I highlighted a few things there in my prepared remarks. But I think, you know, it probably starts with that consistently strong peer-leading well productivity. You know, when I look at our 2024 productivity by basin, compare it to 2023, Eagle Ford, I would say 2024 is looking very comparable to what we delivered in 2023. When I look at the Bakken, I would actually say our productivity is up marginally in 2024, really on the back of we are gonna go back into Myrmidon and complete a few wells there. And then the Permian, it looks pretty flat from 2023 to 2024. So I think that's the first thing I would point to. The second thing, as you noted, was the longer laterals. We mentioned in the prepared remarks there, we're up 5% at a company level. Eagle Ford, they're up about 10% year-on-year. Even Bakken is up just notionally a couple of percentage points, and then you look at the Permian, they're up by 10% as well. And that is a big part of that capital efficiency driver. And then the third part is we are forecasting a little bit of deflation, albeit very modest, kind of low single-digit numbers there. Makes, makes a lot of sense. Then, my second question, Lee, maybe for you or Dane, just on capital allocation. I'm just wondering, is there anything that would cause you to move towards more towards the, the variable dividends, or do you believe your active buyback program continues to be most strategic? And, you know, maybe around that, I mean, how should we continue to think about per share growth? Obviously, as you keep buying the shares back, it really continues to ramp that nicely. So I'd just love to hear your comments there. Yeah. Hey, Neil, this is... Good morning, this is Dane. I'll take a first cut at it. So, the bottom line is expect our framework and sort of the mix of return vehicles to remain unchanged in 2024. We've said all along, sort of variable dividend is a, is a third mechanism, that it's on the table, but it's not front and center for us at this point. You know, 40% return to shareholders- ... is a very firm commitment. That's our primary commitment for use of capital. Base dividend, I talked about the sustainability of that base dividend is critically important to us. So dividend increases will probably be driven by the pace of share repurchases as much as anything, because that kind of keeps the post-dividend break even flat. And it's-- right now, we're peer leading in the low to mid-40s. Share buybacks again at, at mid-teens, free cash flow yield, super efficient vehicle, and as you noted, they drive that per share growth on a pretty significant basis. The second use of CapEx or of ca- available cash for us, and you saw us do some of it this year, is pay down debt. We paid down $500 million worth of debt last year. Our leverage levels are, we're comfortable with. They're like 1x net debt to EBITDA at strip pricing, but I'd like to get them down. And we've stated, you know, what, we've got $5.4 million of gross debt today. We'd like to drive that down to $4 gross debt, which was the pre-Ensign debt level. And so we'll continue to allocate some excess free cash flow in excess of the 40% return to further improving the balance sheet. Great details. Thank you both. Oh, go ahead. Yeah, maybe I'll just add one thing to that, too. I think, you know, the power of a consistent and meaningful share repurchase program, you really see that, you know, showing up in the, in the growth and the per share metrics that really matter. If you just look at 2023, you know, we took out 9% of our outstanding shares. That was roughly double the next best in our peer group. And of course, that translated into tremendous value growth on a per share basis for our shareholders. So we still believe in that. I mean, again, we kind of look through the cycle. It's a program that we set in place and let it run. We dollar average, and we think it's very powerful. If you rewind all the way back to October of 2021, that 9% becomes 27% of our shares outstanding that we've retired. So it's been a very powerful program for us, and we remain extremely committed. We still have $2.3 billion of outstanding authorization against the repurchase program with our board of directors. Great point, Lee. Thank you all. Our next question comes from Matt Portillo with TPH. Good morning, all. Two asset level questions that I wanted to run by you. I guess first in the Bakken, looking at the early time results on Ajax, looks quite encouraging from a production and productivity perspective. Just curious if you could talk about potentially your learnings on the spacing design here, and then also, as you kind of look across your acreage position, how much of your Bakken acreage might be set up for 3 mi development moving forward? Yeah, I'll answer that one, Matt. In terms of the spacing pattern there, it was in a kind of five by zero spacing, so five wells in the Middle Bakken. There's no Three Forks opportunity down there. And as you probably know, that's kind of down to the southwest of the Hector area, where we've been pretty active the last couple of years. You know, what I'd say in terms of maybe a read-through, it probably feels a little bit early. Don't have a lot of data to share. Obviously, we've just brought three of the wells online. We've got some early production there. You know, what I'd probably tell you this quarter may well change next quarter. So, rest assured, we'll continue to work our land position there hard. If there are any opportunities to get more extended laterals, you could, you can expect us to be talking about those in the future. I think one of the things I would add, too, Mike, though, is that certainly, even though we're still waiting for a little bit more longitudinal production data to, you know, declare, you know, victory, when you look at the total well cost per foot and the savings that we've already captured there, it's very significant. So from an execution standpoint, we feel very good about the D&C performance. So as you said, early returns on the production side, very strong, but absolutely encouraging on the cost side, on the D&C side. No, I'll, Matt, I'll maybe provide a little bit, a little bit more color there. You know, the first of the wells that we did execute in a TWC per foot basis, we're looking at those be 24--25%, sorry, be a little comparable to Myrmidon. And, I think you couple that with the early production, couple thousand barrels of oil equivalent a day, 80% oil. You know, the IPs will probably be not as stout as you might expect up in Hector, but I think you'll get that volumes back over the long term. So as Lee pointed out, you take the well productivity with the well costs, I would like to think that that's gonna present a pretty compelling case for Ajax in the future. Great. Then just as a follow-up, looks like the Texas Delaware is gonna be about a third of your program, give or take, in 2024. Curious, one, on the development plan here, are you moving towards development, or are you still working on delineating the resource? I know that 2023 was still kind of a learning year for you. And then, two, just curious how well costs have progressed in this area. I think that was also kind of an initiative last year, is to get more reps on wells and get the cost down in that Texas Delaware play, given that there's high productivity trends, but the cost side of the ledger still needed some work. ... Matt, this is Pat. I'll take the development piece, and maybe I'll let Mike take the cost piece. Yeah, as you said, this—we moved this project into our development team last year, so it's no longer an exploration project. It is in our development program. As I think you probably know, we have 13 wells that have been online for some time, nine in the Woodford, four in the Meramec, and they continue to perform just as we expect. Excellent productivity, high oil cut, shallow declines, and low water oil ratios. We will be bringing on nine wells this year. Two of those are lease hold wells, and then there's two multi-well pads that we'll be bringing on. We've gone to longer laterals. We have this 57,000-acre blocky position, so that gives us the ability to drill really long laterals. The wells we're bringing on this year will average around 2 mi. Next year, for the wells we'll be drilling in the future will be up to 13,000 ft. From a development standpoint, we're still looking at four by four spacing in the Woodford and the Meramec. I think I hit it all there, maybe, yeah. Yeah, Matt, from a cost perspective, what I'd say is we're kinda still mid-program, so to speak. We've just completed drilling the wells, not completed them yet, so don't have all of the data to share. What I would say from a drilling perspective, costs are in line with kind of pre-drill expectations. What I would say, maybe the encouraging thing is, as we progressed through the drilling, it seemed that the efficiencies were getting better, and therefore, when we do get all of the costs, then I would expect that, you know, you would see that natural improvement in the costs as we get, quite frankly, we just get more reps. Yeah. One other thing I'll just mention, too, this is a little bit of a subtlety, but the fact that, you know, we brought the two asset teams, Permian and Oklahoma, together. Now that's under a single leadership structure, and this is one of the areas where we can benefit from learnings, because, of course, Woodford-Meramec drilling and completing in Oklahoma, that's something that, you know, we've already kind of cut our teeth in. So we're bringing a lot of those learnings and expertise now, into this, if you will, joint, asset team, now that we have this Texas Delaware play, with the Woodford-Meramec. Because it is, it is challenging drilling. Mm-hmm. I mean, let's be honest, it's deeper, it's hard pressure, it's more challenging hard rock drilling. But bringing that expertise in from Oklahoma is certainly allowing us to advance up the learning curve a bit more efficiently. Thank you. Our next question comes from Neil Mehta with Goldman Sachs. Yeah, good morning to Lee and team. First question I had was just post-2024, capital efficiency this year, another very strong year. But as you think about setting, setting the sticks for 2025 and ensuring that you're able to sort of continue at this capital efficiency pace, just some thoughts post-2024, and can you hold $190 of oil at $2 billion in CapEx? Yeah, well, it feels like we're just now releasing 2024, so jumping ahead to 2025 is a bit of a leap. But first of all, you know me, just saying, Neil, you know, we feel very good about our, I'll say, underlying well productivity. I think it's actually pretty remarkable when you think about the fact that we operate in two of what the market views as very mature basins, and we're still very much holding the line on productivity that is already at the top of the peer space. So I think you have to keep all of this in the proper context. And certainly, as we do our longer term modeling, clearly, Permian will start competing for a bit more capital. But we believe that from a productivity as well as a capital efficiency standpoint, certainly as we look out over the horizon, we see ways to continue to hold the line and certainly hold the line, if not improve on some metrics. And again, we have a lot of tools available to us, right? I mean, there's some of the things that Mike talked about. There's the fundamental well design, longer laterals, better completions. There's execution efficiency, you know, stages per day, our rate of penetration on the drilling side. We were just talking about the Woodford hard rock drilling. There's supply chain optimization. We continue to work on how best to integrate and manage our supply chain. And then finally, there's just the sheer commercial leverage. You know, you can kind of put that in the deflation, inflation bucket. But all of those things give us an opportunity to continue to work on overarching capital efficiency as we move forward in time. Even though we may be moving to different parts, different geology, we certainly see a path to continue, to protect our pure leading capital efficiency that we've worked very hard for. Thank you. Yeah, it definitely is notable. The question—the follow-up question is just on the natural gas outlook in the US. It's obviously a tough environment, as you referenced in your comments. So So how is your designing your plan for 2024, and you're thinking about which areas you wanna prosecute? Are you trying to maximize the value of your netbacks? Thank you. Yeah. I think Mike was pretty clear in describing the capital program that our program for 2024 already reflects the reality of where natural gas pricing sits today. So not surprisingly, you know, we're driving capital allocation to our three kind of black oil basins, Eagle Ford, Bakken and the Permian. Thus, you know, a combination play, essentially like Oklahoma, is struggling, obviously, to compete for capital because of where we are on the commodity cycle right now. It doesn't mean that it won't compete in the future, but today, because of the multi-basin model, we're able to take a hard look. You may—I think Mike said, you know, it's value over volumes. And even though we're taking a little bit of a downtick on BOE, that's by design. We're driven by returns and value optimization, which is making our oil program very efficient in 2024, and very much our focus, given where gas pricing sits today in North America. Thanks, team. Yeah. Our next question comes from Doug Leggate with Bank of America. Hey, good morning, guys. This is actually Kalei in for Doug, so I appreciate you taking the question. My first question goes to inventory depth. You guys obviously continue to show a very consistent capital program with the emphasis on harvesting those mature assets. Hoping that you can provide a view on how you see the resource depth evolving on each one of your four U.S. plays. And when you think about that program as you work into the future, do you ever see the Anadarko Permian carrying the load of that program? And if so, when do you see it? Okay, yeah, there's a lot in there, so let me maybe try to unpack a little bit of that. You know, first of all, maybe just let me deal with the inventory question. You know, our team has been very successful at replacing inventory over the last five years. And there are several ways that, you know, we're able to do that. One is organic enhancement, and that can include everything from cost reductions in places where we operate, extending laterals, refrack and redevelopment work like we have ongoing in places like the Eagle Ford. So that's helpful. We do small bolt-ons and even trades. One of the reasons that we're now having a primarily, you know, two-mile plus program in Delaware is because of all the good work around small acquisitions, small trades there, to allow us to get a more contiguous kind of position there. And then we just talked about the migration of the Delaware-- I'm sorry, the Texas Delaware play from kind of exploration into the development program. And then finally, there is, you know, large scale-- larger scale M&A, like we did with Ensign. We've got these four avenues to continue to replenish. And in some cycles, you lean on one more than another, but typically, you need to see all four of those to have a sustainable replenishment model. That's really what we've been able to prosecute over the last five years and hold that 10+, decade-plus of inventory relatively constant over that period of time. So you should expect us to use that same playbook going forward. I mean, every year is not going to have large-scale M&A, but certainly every year we're investing in things like organic enhancement. We're investing and still trying to progress some of our exploration plays. So those things are just part and parcel of how we address inventory replenishment. You know, at a basin level, you know, we allocate capital at an enterprise level. So when we look at our inventory, we're looking at it from a holistic standpoint. And that's why, for instance, today, you see Permian starting to compete for more capital allocation. And so when we think through that 10+ year inventory, we think through it with a mindset of managing it at an enterprise level, with basins coming in and out and receiving capital allocation based on the highest return and the best fit for us to continue to generate sustainable free cash flow generation. Thanks, Lee. I appreciate those comments. My quick follow-up just goes to EG. I'm just trying to get a sense of the ratability with respect to the commodity sensitivity. Not to be stupid about it, but let's say prices blew out to $30 per MMBtu in a very extreme scenario. I'm wondering if the earnings that you've shown here would exhibit the same linearity compared to the $10-$15 scenarios that you've laid out. Well, first of all, if it goes to $30, we're going to be very happy. But, you know, there is a bit of linearity there, though. And, you know, one of the reasons that, and I think I mentioned this in my opening comments, you know, we've provided some sensitivities at an enterprise level, you know, for all of the key products. So you can see how EG factors into the overall enterprise delivery. But certainly, the data that we've included, you know, in the deck, you should be able to test those sensitivities because it is a commercial framework. It's linked to global LNG pricing. So to the extent that we're delivering, you know, same level of volumes under the same cost structure, then that should be a pretty linear relationship with commodity pricing. I appreciate that. Thank you. I want to take that $30 as a prediction, too, by the way. Our next question comes from Paul Cheng with Scotiabank. Thank you. Good morning, guys. Good morning. Maybe this is for both Lee and Dane. You guys are changing a bit on the accounting in EG, shifting the transfer price. Just curious that with that, other than, say, the shift on earning between the equity affiliate and fully owned operation. Does it in any way change the way how your decision-making for that operation at all? That's the first question. The second question that want to maybe go back to the consolidation. In your operating region, because of that, we are going to see some bigger player. Do you foresee that going to change the landscape in terms of the service supply in terms of all that, because of the consolidation, people become more rational, so you actually think that the pricing on the service will become better for the rest of the payer? So just curious then, I mean, what your view on the competitive landscape that may have changed, if any, due to that consolidation in the operating regions that you are in? Great. Great. Well, again, lots to unpack there, you know, Paul. Well, let me maybe start off on the EG question. I'll get Dane to jump in here and help me out. But you're spot on in that under the new contractual structure, that we will be shifting some element of profitability from the equity companies over to the consolidated reporting. And in fact, we provided a very kind of detailed breakdown of that in our guidance in the deck, just to hopefully eliminate any confusion or lack of clarity around this point. I mean, we know EG still is complex, but in some ways, this will bring more transparency by migrating more of that profitability into the consolidated entity. It will also limit kind of this timing dislocation that we also have between when we generate the income or the earnings and when we receive, say, the dividend from an equity company, because in the consolidated entities, obviously, that step does not occur. The only other thing you said, well, would this change anything around our decision-making because of this new structure? And what I would tell you is, you know, the beauty we have in EG is that we're aligned from an equity percentage standpoint across the value chain. So there's really no impact to our decision-making or how we think about investments across that value chain, because we have alignment in every aspect of it, from the upstream all the way through the LNG plant. I don't know, Dane, if I missed anything there. No, I agree completely, Lee. I, I would just add, the guidance that we provided on page 15 of the slide deck is really sort of at a holistic EG business unit level, $550 million-$600 million EBITDA in 2024, assuming a $10 TTF, and we gave price sensitivity, so you can dial that how you want. But I will say, that's the best way to look at the business, is the aggregate EBITDA generation. That's how we think about it, so it doesn't really. To echo Lee's point, I don't think it drives our decision-making, which entity, whether it's consolidated or an equity affiliate, where that earning is coming from. We like it all. The other thing is that guidance is quite a bit stronger than what we've previously provided for 2024, and now we've actually gone out five years of giving you a five-year average. So this business is very strong, and it's improving with the, you know, the infill opportunities and bringing the same gas into the system. I mean, there's a lot of running room here and a lot that's not fully baked into the future model yet, so we're pretty bullish on EG. I think the last question you had was just around kind of the, I'll call it, the competitive landscape, certainly in some of the basins where we operate today. You know, consolidation is absolutely a factor in all basins. It's probably in some ways, it becomes a bit more challenging in mature basins as the best operators tend to be aggregating the, you know, the best assets, and many of them have already done so and have a material position. The other challenge I think you have in those assets is, it's the balancing act between PDP production versus forward inventory. And I would use the example, for instance, of Ensign, where we really struck that balance. It brought cash flow and EBITDA with it, but it also brought 600+ locations that was not only inventory life accretive to the Eagle Ford, but was inventory life accretive to the overall company. And those opportunities came in and competed immediately and continue to compete within our capital allocation today. And so there are some, you know, unique challenges as you look at the more mature basins, but ultimately, the high-quality assets will be run by the highest quality, you know, operators, and we certainly put ourselves in that category. Thank you. Our next question comes from Scott Gruber with Citigroup. Yes, thanks for squeezing me in. And just have one question here. Lee, I think your M&A framework is certainly a very prudent approach, but obviously there does seem to be an industry rush here to secure good rock and scale up. So the question we get from investors is, you know, do you worry about the opportunity set, you know, for acquisitions shrinking and the quality of the opportunity set fading? And does that, you know, warrant a tweak to your M&A strategy? I guess ultimately the question is, are you comfortable with the longer-term outlook for adding quality resource, whether that's organic or inorganic, you know, within the construct of your M&A approach or and in the context of this, you know, hyper consolidation phase? Yeah. Well, definitely there, we're in that phase, you know, today, but we see no upside to our shareholder to compromise our criteria today. Again, you know, all of these transactions are very bespoke. They reflect the attributes of the counterparties. Most of those counterparties are searching for something. They're searching for scale, they're searching for resilience, they're searching for balance sheet health. I mean, they're searching for sustainability and inventory. So they're trying to fill a void. And what that drives is this. I'll—I won't necessarily refer to it as desperation, but it drives a different kind of behavior. For us, we're sitting with 10+ years of inventory, so we can be patient, we can be thoughtful, we can exercise the same level of discipline that we do in our organic business and be very successful. And we've demonstrated that. We've got a track record. I talked about those four levers we have available for inventory replenishment. Large-scale M&A is just one of those levers that we can apply. And also keep in mind that even when transactions occur, the assets are still there, and so they're not going anywhere. And so there is still that aspect of ultimately, the best assets will find their hands into into being operated by the best operators. I appreciate the call. Thanks, Lee. Thank you, Scott. Thank you. This concludes our question and answer session. I would like to turn the conference back over to Lee Tillman for any closing remarks. Thank you for your interest in Marathon Oil, and I'd like to close by again thanking all of our dedicated employees and contractors for their commitment to safely and responsibly delivering the energy the world needs now more than ever. Could not be prouder of what they achieve each and every day. Thank you, and that concludes our call.