Good day, and welcome to the Marathon Oil Third Quarter 2023 earnings 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 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, please press star, then 1. To withdraw your question, please press star, then 2. Please note, this event is being recorded. I would now like to turn the conference over to Guy Baber, Vice President of Investor Relations. Please go ahead. Thanks, Danielle, and thanks also to everyone for joining us on the call this morning. Yesterday, after the close, we issued a press release, a slide presentation, and investor packet that addressed our third quarter 2023 results. Those documents can be found on our website at marathonoil.com. Joining me on today's call are Lee Tillman, our Chairman, President, and CEO; Dane Whitehead, Executive VP and CFO; Pat Wagner, Executive VP of Corporate Development and Strategy; and Mike Henderson, 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, including in the included in the press release and presentation materials, as well as the risk factors described in our SEC filings. We'll also reference certain non-GAAP terms in today's discussion, which have been reconciled and defined in our earnings materials. So with that intro, I'll turn the call over to Lee, and the rest of the team will provide prepared remarks today. After the completion of those remarks, we'll move to a question-and-answer session. Lee? Thank you, Guy, and good morning to everyone listening to our call today. First, I want to again start our call by expressing my thanks to our employees and contractors for another quarter of comprehensive execution against our framework for success. Well done on another great quarter, while continuing to stay true to our core values as you responsibly deliver the oil and gas the world needs. There are a few key takeaways I want to leave you with this morning. First, the third quarter results, we've continued to build on our track record of consistent operational execution that is translating to peer-leading financial results. Our strong execution culminated in $718 million of adjusted free cash flow at a reinvestment rate of just 38%. Truly exceptional delivery. I expect our free cash flow generation to further improve during fourth quarter from this already strong level. The first half-weighted nature of our 2023 capital program contributed to a significant increase in our third quarter production, above the top end of our full-year guidance, while capital spending declined. At the same time, we remain focused on managing our unit cash cost, which declined to the lower end of our annual guidance range, down more than 15% from the prior year quarter. We are well positioned to take advantage of any market-based deflation opportunities, but are ensuring that we are driving underlying efficiencies in all aspects of our business, both expense and capital. Second key takeaway this morning. Powered by this foundation of consistent execution, we continue to lead our peer group and the broader S&P 500 in returning capital to our shareholders through our transparent, cash flow-driven framework that prioritizes our shareholders as the first call on cash flow. And importantly, we're delivering on our shareholder return objectives while continuing to enhance our investment-grade balance sheet. During third quarter, we returned $476 million to shareholders, bringing total return of capital through the first three quarters to more than $1.3 billion, representing 41% of our top-line cash flow from operations, fully consistent with our framework. We're offering shareholders a double-digit annualized distribution yield and peer-leading per-share growth. Our consistent and committed approach to share repurchases has driven a 26% reduction to our outstanding share count over the trailing 8 quarters, far in excess of any peer company. We've also now reduced our gross debt by $450 million this year, including a $250 million October prepayment on our term loan. We are well on our way to our medium-term gross debt objective of about $4 billion that will further enhance our financial flexibility and lower our leverage metrics to less than 1x EBITDA at a conservative oil price assumption. Looking ahead, we remain steadfastly committed to both our return of capital program and further gross debt reduction. It is not an either/or proposition. Consistent with that focus, our board recently approved a 10% increase to our base dividend and an increase in our outstanding share repurchase authorization to $2.5 billion. Importantly, this dividend raise is fully funded by the synergy with our repurchase program. That also ensures we hold the line on our post-dividend free cash flow breakeven price, which is the lowest in the peer group. My third key takeaway this morning is that our unique EG, Integrated Gas, business is now set to realize a significant financial uplift in 2024, driven by a substantial increase in our global LNG price exposure. To this end, we recently signed a new TTF-linked LNG sales agreement for our equity Alba gas. This contract marks the conclusion of the legacy Henry Hub contract, which expires at the end of this year. In 2024, this new contract is expected to contribute to a year-on-year EBITDA increase of approximately $300 million-$500 million, assuming TTF pricing of $15-$20 per MMBtu. With all contractual agreements necessary to realize this uplift now formalized, our focus turns to further enhancing the longer-term free cash flow generation capacity in EG by optimizing our integrated gas operations, including diversion of a portion of the methanol feed gas to higher-margin LNG and progressing the additional phases of the EG Gas Mega Hub concept. Our final key takeaway is that we remain on track to deliver a 2023 business plan that benchmarks at the top of our high-quality E&P peer group on the metrics that matter most: free cash flow generation, reinvestment rate, capital efficiency, free cash flow breakeven, and production growth per share. These differentiated outcomes are underpinned by a high-quality and high-return inventory that is demonstrating durable productivity year-over-year and offers a decade plus of run rate. As I look ahead to 2024, I expect more of the same. Our framework for success and our core priorities won't change. Our objective will again be to maximize our sustainable free cash flow generation, an objective we believe is best accomplished by a maintenance oil program of 190,000 barrels of oil per day. We'll again strive to deliver peer-leading return on capital and per-share growth. I fully expect another year of very strong well productivity and operational execution across our high-quality multi-basin portfolio. We will benefit from the added tailwind of our growing exposure to the global LNG market and the associated financial uplift. With that, I'll turn it over to Dane, who will provide a brief financial update. Thank you, Lee, and good morning to all on the call today. As Lee mentioned, the third quarter was an exceptional financial quarter for us, highlighted by $718 million of adjusted free cash flow, a reinvestment rate of just 38%, and $476 million of capital returned back to shareholders. Importantly, we expect even stronger free cash flow generation during the fourth quarter as our capital spending continues to moderate. It should go without saying by now, but we continue to believe that returning significant capital back to our shareholders is foundational to our value proposition in the marketplace. We're successfully building a long-term track record of consistent shareholder returns through the cycle that can be measured in years, not just quarters. We're now two years into that journey, and the bottom line results our program has delivered are both compelling and differentiated. Over the trailing eight quarters, we've now returned $5.1 billion back to our shareholders. That's over 30% of our current market capitalization. We've repurchased $4.6 billion of our stock at attractive levels, driving a 26% reduction to our outstanding share count, contributing to peer-leading growth on our per-share metrics. The commitment and the consistency of our approach has paid off, and we remain committed to this powerful combination of material share repurchases, along with a competitive and sustainable base dividend. To that end, we raised our base dividend by 10% this quarter. That's the ninth increase in the last 13 quarters. This increase was fully funded by share count reduction from our buyback program, protecting our free cash flow breakeven, which is the lowest in our peer group. Additionally, we've increased our outstanding share repurchase authorization to $2.5 billion, which gives us plenty of runway to continue buying stock. But as I've said over the last few quarters, our plan is to maintain this return on capital leadership while also further improving our already investment-grade balance sheet through gross debt reduction. We can do both, and that's exactly what we're demonstrating. We've now paid down $450 million of gross debt year to date, including $250 million of term loan that we paid down in October. Looking to fourth quarter specifically, we aim to continue paying down the term loan. At current prices, we expect to be able to pay down $400 million-$500 million in the fourth quarter, and that's inclusive of the $250 million reduction already executed in October. With the variable interest rate that the term loan carries, aggressively reducing outstanding principal with free cash flow will make a meaningful dent in our annual cash interest expense. We expect to continue to hit our minimum 40% of CFO shareholder return objective. Our balance sheet's very strong, firmly in investment-grade territory, yet we'd like to be even stronger. Our current leverage at prevailing commodity prices is around 1x debt to EBITDA. Over the medium term, our objective is to reduce current gross debt of $5.5 billion down to around $4 billion. That would translate to a one-time debt to EBITDA, assuming a $50-$60 WTI price environment. It would return our gross debt level back to where it was before the Ensign acquisition. With that financial summary, I'll turn it over to Mike. ... Thanks, Dane. The strength and sustainability of our shareholder return and balance sheet initiatives are ultimately underpinned by the high quality of our U.S. multi-basin portfolio and our ability to consistently execute. Well highlights, we're delivering strong and durable well productivity, while also continuing to improve our drilling and completion efficiencies. Though we are positioning ourselves to take advantage of commercial leverage and potential deflation, we recognize that self-help is fully within our control. More specifically, our average oil productivity per foot this year is trending flat with 2020. And at those levels, we are 25% better on a 180-day cumulative basis than our high-quality peers. In Eagle Ford, the successful integration of the Ensign acquisition earlier this year has further enhanced both the quality and quantity of our inventory. Our fully integrated program is delivering another very strong year, with oil productivity flat to 2022 and oil equivalent productivity better. In the Bakken, we're consistently bringing online the best wells in the basin, wells that pay out in less than six months, with early oil productivity 40% better than the basin average. We're also just wrapping up the drilling of our first 3-mile laterals in the Ajax area. In the Permian, we've significantly improved our capital efficiency through our transition to a 2-mile lateral or longer program, now reliably delivering oil productivity consistent with the industry top quartile. Yet, while underlying well productivity gets most of the external attention, there are two components to the capital efficiency equation, and we're equally focused on both the numerator and the denominator. Field level operational execution matters and is a primary driver for well costs. I'm pleased to report that our year-to-date execution has been strong, with drilling and completion efficiencies continuing to improve. More specifically, our average drilling efficiency this year is on pace for a 10% improvement versus 2022, while our completion efficiency is set to improve 15%. We've taken advantage of an improved market by grading certain areas of our business where it's made sense. We've placed a greater emphasis on pre-planning efforts, which have reduced non-productive time on location, and we continue to work closely with our longer-term service providers to implement incremental changes that can drive quantifiable execution improvements. Turning to our integrated gas business in EG, great job by our teams in achieving all our targeted commercial milestones this year. With the signing of our new TTF-linked Alba LNG contract with Glencore, beginning January 1, 2024, Alba-sourced LNG will no longer be sold at a Henry Hub linkage. The current arbitrage between Henry Hub and European natural gas pricing is expected to drive a significant financial uplift for our company at current forward curve pricing next year. A year-over-year EBITDA increase of $300 million-$500 million, assuming a TTF price range of $15-$20/MMBtu. With the commercial framework now fully in place to realize this financial uplift, our focus now turns to further extending the longevity of a stronger financial performance. Next year, we'll begin diverting a portion of our Alba gas from the methanol facility to the higher margin, higher working interest LNG facility, highlighting the flexibility of our integrated EG operations, where we have alignment across the entire value chain. Additionally, we're continuing to assess up to a 2-well infill drilling program on the Alba block, targeting high confidence, low execution risk, shorter cycle opportunities that could partially mitigate Alba field decline beginning in 2025 and maximize the flow of our equity molecules through the LNG plant. Our Alba infill program is expected to compete with the risk-based returns generated from our U.S. resource base. Although any Alba infill capital spending is unlikely to make a significant impact on our overall 2024 capital program. And finally, we continue to advance the longer-term gas mega hub concept in EG, as more fully described in the heads of agreement signed between ourselves, the EG government, and our partner, Chevron, earlier this year. By fully leveraging our unique world-class infrastructure in one of the most gas-prone areas of West Africa, we expect to extend the life of EG LNG well into the next decade and further enhance our multi-year free cash flow capacity. The next phases of development will likely include the Aseng gas cap monetization, as well as potential cross-border opportunities. With that, I will turn it over to Lee, who will wrap up our call. Thank you, Mike. For years now, I've reiterated that for our company and for our sector to attract increased investor sponsorship, we must deliver financial performance competitive with other investment alternatives in the market, as measured by corporate returns, free cash flow generation, and return of capital. More S&P, less E&P. We've delivered exactly that type of performance over the last two years and counting, and not just competitive, but at the very top peer group. And looking ahead to 2024, I don't expect anything to change....To close, I would be remiss if I didn't address the competitive landscape for our sector. We've obviously seen significant consolidation in our peer space recently. While every transaction is unique, with its own set of facts and circumstances, a common takeaway is clear: low-cost, high-quality traditional oil and gas assets will have a critical role to play in helping meet global energy demand for decades to come. Within the oil and gas space, the short-cycle US shale opportunities, with their advantaged risk-adjusted returns and potential for further innovation, will continue to be highly valued and critical to meeting that long-term demand. Recently, you may have seen articles speculating on Marathon's involvement in M&A. While I won't address any specific market rumors or speculation on today's call, I will reiterate that it's our duty to always explore avenues to further enhance the long-term value for our shareholders, whether those opportunities are organic or inorganic. That's always been our objective and our responsibility to our shareholders, and nothing has changed. For Marathon Oil, our approach to M&A, small or large, has been consistent and will not be compromised, as exemplified by the Ensign transaction, which ticked all the boxes of our well-established criteria. It is about making our company better, not just bigger, and enhancing the delivery against our framework for success. Any transaction must meet our tried-and-true principles of financial and return of cash accretion, industrial logic within our existing basins, inventory life extension, and no harm to our investment-grade balance sheet. Our paradigm needs to shift from that of an energy transition to one of an energy expansion, and I continue to believe that an elite group of high-quality U.S. E&P companies are necessary to drive that energy expansion, to deliver strong financial results for shareholders, while also collectively defending U.S. energy security, playing our role in lifting billions out of energy poverty, and protecting the standard of living we've all come to enjoy. Marathon Oil is well-positioned to be one of those significant few companies. With over a decade of high-return U.S. unconventional inventory and a differentiated EG integrated gas business with unique and growing global LNG exposure. I'm proud of how our company is delivering for our shareholders. Our financial and operational leadership speaks for itself, and you can have confidence that our strategic framework will continue to guide all of our decisions by prioritizing strong corporate returns, sustainable free cash flow generation, significant return of capital to our shareholders, and ongoing resource-based enhancement, and all while protecting our investment-grade balance sheet. With that, we can open the line for Q&A. We will now begin the question-and-answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. The first question comes from Arun Jayaram of JP Morgan. Please go ahead. Hey, Lee, good morning. I wanted to follow up on your M&A comments, and wanted to get your thoughts on how you would view transactions that could potentially be viewed as more of an MOE for Marathon. And just maybe if you could address, you know, we got numerous buy-side pings and an 8-K filing from MRO, MRO last week that was filed under M&A or an asset disposition under Reg FD. Looks like you had an amendment earlier this week, but just wanted to see if you could touch upon what the deal was with that 8-K filing as well. Yeah, no worries, Arun. Yeah, good morning. Well, first of all, just around M&A and whatever flavor of M&A you want to talk about, whether that's MOE or a large bolt-on transaction like we did in Ensign, the criteria is still fully in play. I mean, we don't look at those really through any different lens. And I'll, you know, take you back to, you know, what I stated in the prepared, remarks, which is, you know, any transaction of scale is, is going to have to tick all the boxes in, in our criteria. It's gonna need to be, financially accretive. It's gonna need to be return of cash accretive. It needs to add to our already high-quality in, resource life and inventory life. It needs to have very clear industrial logic, meaning for us, that it exists in one of the basins where we have high execution confidence. And then finally, it can't do any harm to our investment-grade balance sheet and financial flexibility. So it, it's really irrespective of the scale. That's going to be the lens, the criteria that we're gonna evaluate any opportunity. Yeah, let me just, you know, maybe put to rest any of the noise created on the 8-K. We had not updated our corporate bylaws since back in 2016. This was just some cleanup on those bylaws. There was a little bit of a mistake on how those got classified, which prompted the amendment, but there's nothing more to it than that. Great. My follow-up is on EG. Lee, you mentioned in your press releases earlier in October, you had a long-term sales agreement by Glencore. Can you talk about why they were the right partner for you? And maybe you could talk about the new wrinkle, which is the ability to shift maybe some volumes from methanol but to back to LNG. Some thoughts on what the implications of that could be, and perhaps as well, you could outline kind of your development program at Alba later in 2024. Okay, you just packed a lot into that question. Let me, let me- Sorry about that. Hey, you're very clever. Let me start maybe with Glencore. You know, first, I want to say upfront that, you know, the team, the marketing team did an exceptional job of creating, you know, competitive tension in the marketplace. And you know, we had a lot of interest when we put out the RFP for those base load cargoes. So the positive, of course, is Glencore came in with a very competitive offer, with a five-year term, a TTF linkage, a fixed transportation element as well. They also have experience working and operating in EG. So from a lifting, scheduling standpoint, et cetera, they're very familiar with how we operate the business there. So first and foremost, it was about driving the best competitive offer. And I think an added bonus, of course, was just the fact that Glencore did have a lot of experience already in country. On the diversion, you know, question, you know, obviously there, you know, we've talked a lot about the arbitrage between Henry Hub and obviously TTF and Global LNG. But there's another element of arbitrage that we have available to us in EG as well, and that is the feed gas that we send to the methanol facility. And because of our alignment across the full value chain, we can look at optimization around that, where we can divert some of those volumes where we believe the highest value can be attained. As we look at where methanol pricing and where TTF pricing under the new contract terms, as well as just the market in general, we feel very strongly that redirecting those molecules and optimizing that flow will end up just adding some incremental value as we look ahead to 2024. And then finally, I think the last element of your question was really around just the Alba infill program and some of the opportunities that we're pursuing there. You know, the way we've described that thus far has been up to a two-well infill program. And as Mike mentioned in his comments, the reason we really like this. Well, first of all, it competes head-to-head from an economic return standpoint with our U.S. resource plays. Importantly, this is about as short cycle as you can get in the offshore space. You know, we have very high geologic certainty. This will all be jacked up drilling with dry trees. There's no facilities investment required. And so we're just working through that process, and I would just say, you know, just be patient with us. We'll have a lot more to say about the Alba infill program as part of February's budget release and work program. I think I caught everything. Thanks, Lee. Tell me if I didn't. All right. I think you did. Thanks again, Lee. The next question comes from Scott Gruber of Citi. Please go ahead. Yes, good morning. Hi, Scott. Just looking back at your drill schedule, you know, and how that's evolved over the course of the year, it looks like the targeted well count for the full year has ticked higher, you know, just a bit over the course of the year. So the question is, you know, as you look out at your maintenance program next year, do you think you can achieve the 190 or so in oil production at a flat well count from the 260 or so this year, if you include all the JV wells? Or would you anticipate the well count needing to tick higher a bit next year? Yeah. Well, first of all, I would just say that, you know, the well count, you know, there's a positive story in there, which is around execution efficiency. And obviously, we don't want to pump the brakes on that. When we're achieving that kind of efficiency that Mike talked about on both the drilling and completion side, we want to continue that momentum. And so, you know, so you saw that, again, that wells to sales count being a bit higher. It's still, you know, probably a little premature to talk specifically about the 2024 program. But I will tell you, even with a bit of capital, say, from some long lead kit in EG, we expect the capital program to essentially be flattish year-over-year. And so I, I think the subtext to that would be that we would on a—if you kind of move from maybe gross wells to net wells, we would expect on a net well basis to generally be in alignment with where we have been this year. Got it. And a lot of that, quite frankly, is driven by the productivity that we have seen, that underlying productivity that was in the deck. Which really shows you that as we moved from 2022 to 2023, there was really no downshift in productivity. And as we've just started our early planning for 2024, we believe that's a trend that we're going to be able to support even moving into next year. So we feel very good about the capital efficiency that we're going to be able to deliver in 2024. We set a pretty high bar this year, but we believe that we can continue that trend and that momentum going into 2024. Got it. Yeah, and those, you know, drilling completion efficiencies... look robust, and it's, it's obviously giving you some, some leverage, you know, on your, your service contractors. So what's, what's the latest thinking on, you know, kind of overall deflation potential into 2024? Yes, Scott, it's Mike here. I'll take that one. So it still feels a little bit early to make any definitive call on 2024 service costs. I mean, that said, I think we're likely trending towards that kind of low single-digit year-on-year deflation in 2024. But again, I think ultimately, it's gonna be dependent on what commodity prices do and probably more importantly, what kind of industry activity levels look like. I think for us, looking at 2024, largest contribution to any deflation is likely gonna be around steel and hydraulic horsepower. You know, maybe the counter to that, categories that have significant labor, any labor costs feel pretty sticky. So don't see much movement there. And, you know, when you think about D &C services, that's a big, big part of that is labour. So maybe an area where we don't see as much deflation, certainly absent any kind of material move in the commodities. Maybe just providing a little bit more detail on the various areas. For us, steel costs, they are trending down, as I've said, from kind of first half highs in 2023. We're kind of thinking about 20% there, and that's pretty consistent. Lower raw materials, mill capacity has opened up, and just a bit of decreased demand as well. Similar story in the frack space, hydraulic horsepower soften. Spot rates have come down. We're kind of looking at off at 25% from those highs. Now, what I would note is we were never contracted at those levels, so that's more just of an industry perspective. Similarly, high spec rig market availability has definitely improved. Again, pricing's kind of trended down. You're probably looking at 20% off peaks there, and again, we weren't, we weren't contracted at those levels. As I mentioned, anything that has got a labor component, so things like directional drilling, cement, coil, wireline, hauling, all of those kind of costs are probably gonna be a little bit stickier. I think it's worth recognizing that is not an insignificant component of your, your total well costs. Then maybe the last area is, is diesel, and, and that is a bit of a wild card. You know, supply, demand, fundamentals still feel pretty tight there. Got it. I appreciate all the color. Thank you. The next question comes from Umang Choudhary of Goldman Sachs. Please go ahead. Hi, good morning. Thank you for taking my questions. On EG- Hi. On EG, appreciate all of your response to Arun's questions. I guess one more, any update you can provide us on the progress on capturing the third-party Aseng volumes? Yeah, I mean, I would just say that right now that's a, you know, an active, you know, dialogue as we, you know, look to bring those third party... And maybe just as a little bit of a reminder, you know, we already have a commercial model in place that will, you know, guide that discussion. And obviously, the Aseng gas cap was also part and parcel of the heads of agreement that we signed earlier this year. But, you know, again, just to maybe lay out the opportunity here, this is a reservoir where the operator has been producing the oil rim. They're now looking to really turn that around and blow down the gas cap. There's already the existing Alba pipeline that connects in to our gas plant and LNG plant. So much of the infrastructure to get to our facility is already in place. And again, we have the commercial model, which is a tolling plus percentage of proceeds or profit-sharing model that we already have in place for the Alba methanol. So I would say that's just a continuing effort right now and a negotiation that's ongoing, and I would just say, stay tuned. But at the end of the day, this is really the only monetization route ultimately for that gas. Very helpful. Thank you. And then on slide 12, you've highlighted strong productivity and efficiency gains across your U.S. asset base. When you look across your assets, which areas are moving up from a return perspective and are probably gonna likely demand more capital deployment over time? And then, the housekeeping question which I have for you is that implied full Q guidance, oil guidance, calls for a bigger step down versus what we were expecting, if you plan to keep, if you plan to hit the midpoint of your FY guidance. So any color you can provide there? Yeah. Maybe let me let me start with what I think was kind of a little bit of a question around capital allocation and how we're thinking about that, certainly as we look ahead to 2024. I think, again, we're very, very early in the cycle, so it's a bit difficult to give specifics and more to come on this. But certainly the Eagle Ford and the Bakken are gonna continue to compete for the lion's share of capital. We do expect that because of the strong results that we've seen in the Permian, that it will start competing for a bit more capital as we finalize the 2024 plan as well. And then, of course, we've also talked about potentially the need to loop in some long lead items for the Alba infill program in 2024. So when you think about capital allocation next year, not any seismic shifts there. You know, you're looking at, again, $2 billion inclusive of a little bit of EG spend. But again, Bakken, Eagle Ford, the black oil plays, coupled with a little more incremental allocation to the Permian, is likely the case to be. On the 4Q, kind of I'll call it the 4Q squeeze against where we sit right now. You know, first of all, we don't get that fussed about quarter-to-quarter variations. That's just an output of our business plan. Our focus is really on delivering our annual guidance commitment. That's where we're really looking to drive the results. So if, if you just reflect, for instance, on this year, we started in the first quarter at about 186,000. Second quarter, we're about at 189,000 barrels of oil per day. Third quarter, we're at 198,000. We'll probably be in the upper kind of 180s in the fourth quarter. All that being driven by our business plan and that commitment to meet that 190 annual average. And we do expect, just like we saw this year, that there will be some quarter-to-quarter variation, going into 2024. It's likely that we'll once again have a bit of a first half weighted program, and that'll translate into a bit of a shape to our production volumes. But at the end of the day, we believe for a nominal $2 billion program, we're gonna nail that 190,000 barrels of oil per day because of the underlying productivity durability that we're seeing in our portfolio. Very helpful. Thank you so much. Yeah. The next question comes from Josh Silverstein of UBS. Please go ahead. Hey, thanks. Good morning, guys. Just on EG, now that you guys are linked to TTF pricing, you know, it's been pretty volatile over the last two years. Is there anything that you guys can do to lock in some of that $300+ million uplift, whether through some hedges or any other tools in the Glencore contract? Yeah, I'll maybe say a few things and let maybe Pat jump in as well. You know, our philosophy has been that we obviously want to protect the upside and the linkage to TTF for our investors. We have an investment-grade balance sheet. We have the lowest enterprise breakeven in the peer group. We have a very balanced portfolio from a product mix standpoint. And so when you couple all that together, we don't feel - we feel that we can hold some of that upside and not hedge that away for, for our investors. You know, TTF is a little bit different, maybe not quite as liquid as some of the other markers, as well. We believe because of the way we position this asset within a broader portfolio, that with the TTF linkage, that's going to give us the market-based upside, that's gonna give us the biggest value. I don't know, Pat, you want to add anything? You really hit it all. I mean, our contract is linked to TTF, so we're above that. And, we have a commodity risk committee that meets weekly and looks at our opportunities to hedge our, hedge, that volume. But you said there's not a lot of liquidity there. We'll continue to look at it. Yeah. Yeah, that, that's helpful. And then, yeah, thanks for, for the commentary on, on the, the thoughts around spending as well and the $190 for, for next year. Can you just talk about how much runway you guys see to kind of hold, you know, that, that level of, of oil and total production kind of around a, you know, a similar couple billion-dollar CapEx level? Thanks. Yeah, well, certainly, you know, in the past, you know, we've talked about, you know, a maintenance program that can take us out 5, even 10 years. And when you look at our inventory life and the quality of that inventory, you know, when we talk about a decade plus of inventory, it really is thinking about projecting that maintenance program out in time. There'll be some well mix effects, you know, as you move, you know, through the portfolio. But I believe our productivity and the durability of that productivity is pretty resilient. And, and the example I would use is, you know, when you look at places like the Bakken, where we've made the shift into the Hector area, that type of productivity and capital efficiency, that's the forward inventory there. Similarly, all the good work in Permian that's been done on extended laterals, two miles or beyond, you know, that's the type of capital efficiency that we see going forward. And with the addition of something like Ensign, which had capital efficiency at or above our legacy acreage, we see that also being very additive as we look forward in time and look at projecting that maintenance program out, like I said, across our over a decade of inventory. Great. That's good. Yeah. The next question comes from Doug Leggate from Bank of America. Please go ahead. Thank you. Good morning, guys. Thanks for taking my questions. Lee, I wonder if I could just address the balance sheet topic that, you know, you obviously touched on what your targets are there. But I want to kind of put it to you a little differently and say your capital structure today is still about 25% net debt. And if you think about market recognition of value, you've got a backwardated oil curve and a buyback program that is arguably buying back stock at the front of a very backwardated oil price. Why would it not make more sense to try and tackle the net debt formula to transfer value from debt to equity, rather than pursue the per-share growth metrics that obviously come with the buyback program? ... Yeah, well, I'll-- Doug, maybe I'll start it off, then I'll get Dane to jump in here. You know, first of all, this-- for us, this is not an either/or proposition. I mean, we are consistently delivering our minimum of 40% CFO back to our shareholders, while also continuing to work against that gross debt, kind of, midterm gross debt target. And I'll let Dane talk about that a little bit more. But, you know, on your-- on the stock repurchase question, you know, keep in mind that, you know, we're trying to look through the cycle. I mean, this is a different business model today. I mean, we're not trying to time the market or be opportunistic. We're putting $10B programs in place. We're getting dollar averaging. We're consistently doing free cash flow yield on our shares is still well into the double digits, which means that program is devastatingly efficient. And so because we can do both, that's what we, in essence, are doing. So, we don't have to make that choice, today. And we still believe when you look at some of the numbers that Dane shared on just how much dilution we have taken out of the share repurchase program, we've done that at a very attractive price point on our shares as well. So as long as we continue to have that free cash flow yield efficiency in our shares, it's still very competitive for us to focus on that per-share metric and drive that. Dane, you want to say anything a little bit more about kind of how we're approaching the gross debt? Yeah, and maybe how we think about prioritization. Hey, Doug. Yeah, it is—it, it's a both answer right now. We could—we feel like we've got the capacity to do both. I think about the investment grade balance sheet. We're on positive watch with one or more of the ratings agencies in our current state. We've got a ton of flexibility with regard to debt maturities, over $2 billion of liquidity. We just have all the tools in the toolkit we need to manage a glide path from $5.5 billion of gross debt down to $4 billion over time. And I think over the next 12 to 18 months, we're well positioned to do that while we meet that minimum 40% return to shareholders. So really, you know, if I was perceiving something a little more stressed than that or that that was showing up in our stock valuation, for example, maybe it would be a little more urgent pace to pay down the debt, but I don't feel like we're, we're in that situation at all. And in this current pricing environment, we're generating a bunch of free cash flow, and if we get a tailwind, it will just further accelerate things. And remember also, Doug, you know, our return of cash framework also does recalibrate as you move through price bands as well. So if we start seeing some of that backwardation, then obviously, you know, we can, we will adjust by virtue of the framework that we have, you know, put out to the market. It's very clear. Thanks, guys, on how you think about this. I guess my follow-up is, if you don't mind, on EG. You know, I think we all recognize the capacity, the potential of the legacy plant. And clearly, you're the only game in town, so I think it's inevitable that you find opportunities. I guess, to help frame the current situation, though, I wonder if you could just share with us, with what you have today, how long do you keep the plant full? In other words, to try and kind of risk what the future opportunity needs to be. If nothing else happened, what do you have today in terms of plant longevity? Yeah. No, I understand the question, Doug. Let me maybe describe it, you know, in financial terms, Doug. So, we've shown very clearly the potential uplift that's going to occur in 2024. That is a very durable uplift at a minimum for the duration of this five-year contract that we have with Glencore. So, you know, I can say with great confidence that that financial uplift that we're capturing in 2024 is very durable over the next five years. With just a few of these incremental items that we're talking about, the Alba infill program, as well as Aseng, which, as you say, we're the only game in town. Just those relatively modest projects are going to extend the EG LNG operating life well into the next decade. That's wonderful, and that gives us a much broader runway on cash flows and EBITDA, but it also provides some time for us to continue to work on things like the cross-border opportunities, some of the discovered undeveloped assets that could really be game changers for us, and they just take time to mature. You know, and so when we think back, you know, Ale n was kind of the first step. Now we've moved on to the next step, which is the recalibration of the commercial terms. From there, we're now looking at diversion options from methanol because it makes value sense to do so. And finally, you know, the Alba infill work is under evaluation right now between ourselves and our partners, and the commercial terms are, you know, being discussed with the same. So, just with those few incremental wins, and I hope you see that we've demonstrated a track record of actually capturing those wins, we'll extend EG LNG, like I said, well out into the next decade. Great. Thanks for the answers, guys. Appreciate it. Thank you. The next question comes from Neil Dingmann from Truist. Please go ahead. Morning, guys. Thanks for the time, Lee. My first question is on, maybe for John, just on the regional activity. Specifically, I'm just wondering, what's how do you view sort of upcoming quarterly plans for the Bakken and Permian? And it seems like the Bakken activity remains brisk with, you know, 20+ wells to sales quarterly, while the Permian, you know, incremental activity has gone back to a couple wells. Yeah, I, you know, I think naturally there's going to be some ebb and flow from a capital allocation standpoint. You know, first of all, I just want to recognize the Bakken team had a tremendous, you know, third quarter, and that was a, you know, as usual, that was a combination of things. We brought on some fantastic wells. Execution efficiency was strong, which we've already talked about, so we're getting more wells to sales days. The team did an amazing job of keeping our facilities, you know, up and running. I mean, our most profitable barrels are the ones that we've already invested in. Keeping them online, doing things like a very aggressive workover programs. All of these things are contributing to that very strong performance that you saw in the Bakken. But again, we're gonna balance, you know, capital allocation across. That's one of the beauties of the multi-basin model. And we're gonna move that capital and take advantage of the efficiencies that we have across all the basins. I don't know, Mike, if you want to add anything else. Yeah, maybe just the other, the only other thing I'd add, Neil, is don't interpret lack of wells to sales as lack of activity. You know, we've got 9 rigs running at the moment. We've got a couple of JV rigs running. We've got 3 rigs running in Bakken, 3 in Eagle Ford. We've actually got 3 running in between Oklahoma and Northern and Permian. So, you know, I think that's an indicator, I think of, you know, the value that we place in that asset and the potential future upside. I think it's gonna be, you know, a key contributor for us next year. It's just maybe wells to sales in the fourth quarter and third quarter, for that matter, just down a little bit, but I wouldn't read too much into it. Great details, Mike. And then, Lee, just to follow up, I'm just wondering, how does the broad M&A market look today in terms of just potential deals or quality of deals out there versus... It's interesting, I would say versus exactly a year ago today when you announced the Ensign deal? Yeah. Well, you know, the Ensign deal for us was a little bit of a unicorn in the sense that it did tick all the boxes, you know, in our criteria. And, you know, as we look at what's, you know, in the market today or rumored to be in the market today, I have to say, you know, frankly, that they really don't tick the boxes on our criteria. You know, they may tick one or two, possibly, but, but we can be patient. I mean, we have a tremendous amount of organic opportunity that was made only stronger with the addition of Ensign. Remember, Ensign added 600+ wells into the Eagle Ford. Very high quality wells. Keep in mind, there were already 700+ existing wells, but many of those with earlier, early designs for the completions, and we took no credit for redevelopment and refrac, which, based on our legacy experience in the Eagle Ford, we know will ultimately compete for capital as well. So when I look at what's out there today, Neil, we're just not seeing anything that would really fit our criteria, and there's just no need for us to compromise. No, I totally agree. Thanks, Lee, so much. Okay, Neil. Bye-bye. The next question comes from Phillips Johnston from Capital One. Please go ahead. Hey, guys. Thank you. Lee, you just touched on the $190 for next year and how there's some similarities to this year, just in terms of activity weighting. This might be too granular, but relative to the high $180s exit rate after a pretty flush Q3 here, can you maybe directionally talk about the sequential quarter-over-quarter trajectory from Q4 into Q1? Yeah. Well, I think you probably can be pretty well informed just by looking at what we have done in the past, right? If you go back and you kind of look at how we've trended, even from 2022 to 2023, that's probably a good indicator. I know Ensign may have muddied the waters a little bit, you know, this year, early in the year. But if you get down to the underlying legacy business, that profile where we come in probably a little bit lighter. Like I said, you know, just look at 2023, we're at 186,000, 189,000, now we're at 198,000, probably trending toward the high 180s in the fourth quarter. That kind of profile, because of the way that we weighed our capital, directionally, that's what you should expect to see in 2024. And again, we'll give a lot more color and granularity on that in February. But that shape and that concentration of capital in the first half, that's gonna feel very familiar relative to this year. Okay. The only thing I'd add to that, Lee, if... So if you look back to, to this time last year, fourth quarter last year, we brought 26 wells to sales. This quarter, sorry, fourth quarter last year, we brought 22. I'm getting my quarters mixed up. This time last year, we brought 22 wells to sales. Yeah. This quarter, fourth quarter, we're projecting 26. So there's a playbook there. There's a playbook there that we've tried and tested. It works well. Yeah, just really building on Lee's comments there. Okay, great. And then just, 1 more follow-up on EG, I guess. I think in the past, you guys have talked about sort of an 8%-10% natural PDP decline rate there. So I wanted to check to see if that's still a good number. And then, obviously, you're, you're still evaluating the 2 infill wells, but if you were to drill those, how might they impact your production trajectory in EG just over the next couple of years? You know, Yeah. I guess the question is, will those wells more than offset those declines, and they keep production relatively flat or just offset some of the declines? Yeah. First of all, your 10% decline number is in the right zip code in terms of thinking about our EG gas production there, for sure. With respect to the infill wells, obviously, we've talked about up to two wells. Even if we get to the two-well program, what we're talking about is partially mitigating the decline. And of course, those wells wouldn't even be coming online until 2025. But the beauty of those wells, they're very high-value molecules for us. Because of our alignment, again, across the value chain, from the Alba PSC all the way through the LNG plant, those are gonna be extremely valuable equity molecules. So if I accept the fact that, you know, we won't obviously offset all of the decline, but if you look at it through a financial lens and being able to extend the financial performance of the integrated asset, those wells are really going to help us there. All right, great. Thanks, Lee. This concludes our question and answer session. I would like to turn the conference back over to Lee Tillman for closing remarks. All right. Thank you for your interest in Marathon Oil, and I'd like to close by again thanking all our dedicated employees and contractors for their commitment to safely and responsibly deliver the energy the world needs now more than ever. I could not be prouder of what they achieve each and every day. Thank you, and that concludes our call. The conference is now concluded. 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