Good day, everyone, and welcome to EOG Resources' Q4 and full year 2025 earnings results conference call. As a reminder, this call is being recorded. For opening remarks and introductions, I will turn the call over to EOG Resources Vice President of Investor Relations, Mr. Pearce Hammond. Please go ahead, sir. Good morning, thank you for joining us for the EOG Resources Q4 2025 earnings conference call. I'm Pearce Hammond, Vice President, Investor Relations. An updated investor presentation has been posted to the investor relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the investor relations section of EOG's website. In addition, any reserve estimates on this conference call may include estimated potential reserves, as well as estimated resource potential, not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and Chief Executive Officer; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Chief Financial Officer; and Keith Trasko, Senior Vice President, Exploration and Production. Here's Ezra. Thanks, Pearce. Good morning, and thank you for joining us. 2025 was a remarkable year for EOG. Overall, our year was characterized by disciplined capital allocation, strong execution across our operations, and robust free cash flow generation. We didn't just meet the targets set forth in our operational and capital plan, we exceeded them while expanding our business both domestically and internationally, laying a foundation for the future. We surpassed our original oil and total volume targets while delivering in-line capital expenditures. We continued driving down well costs through sustainable operating efficiency gains, and our differentiated marketing strategy delivered peer-leading U.S. price realizations, which, combined with lower cash operating costs, helped strengthen margins. Beyond extending our track record for excellent operational execution, 2025 was transformational. We completed the strategic Encino acquisition, entered exciting international exploration opportunities in the UAE and Bahrain, brought online the Janus gas processing plant in the Delaware Basin. We also continued leading on sustainability, publishing new emissions targets after achieving our prior targets ahead of schedule. Each of these developments fundamentally improves our business and better positions EOG going forward as being among the highest return and lowest cost producers with strong environmental performance. Operational excellence in 2025 drove outstanding financial results and top-tier cash returns to shareholders. We generated $4.7 billion in free cash flow, returned 100% to shareholders through our regular dividend, which increased by 8%, and $2.5 billion in share repurchases. Let me put our 2025 financial performance in a broader perspective. EOG has generated annual free cash flow every year since 2016. We've never cut nor suspended our dividend in 28 years. Further, over the past three years, we've generated $15 billion in free cash flow and returned $14 billion to shareholders while generating an average 24% Return on Capital Employed. We've done this all while maintaining a pristine balance sheet. This isn't luck. It's the result of consistent execution of our resilient business model and represents a fundamental differentiator versus peers. We expect more of the same in 2026. Modest oil production growth as we maintain capital discipline, further integration and optimization of the Utica acquisition, and continued natural gas growth into emerging North American demand. Looking ahead, we have a disciplined plan for 2026. Our strategy prioritizes activity in the Delaware Basin, the Utica, and the Eagle Ford, while increasing activity in Dorado alongside continued international investment. Our Utica asset provides a compelling opportunity for value creation as we continue to identify additional upside from the Encino acquisition, as well as advancing our technical understanding of the play. In the Delaware Basin, after adjusting our development strategy in 2025, we expect consistent well performance year-over-year. At guidance midpoints, our 2026 plan is expected to generate approximately $4.5 billion in free cash flow using strip pricing, delivering growth, exploration, a competitive regular dividend, and excess cash returns. Our breakeven price to cover the 2026 capital program and regular dividend is $50 WTI. Overall, the 2026 capital program balances both short- and long-term free cash flow generation while supporting future growth and maintaining our pristine balance sheet. Our 2026 plan is contemplated in our updated three-year scenario. The scenario reflects modest oil production growth aligned with current macro expectations. It maintains our current cost structure despite our persistent track record of driving costs lower through efficiency gains. Finally, the scenario is underpinned by our deep inventory of high return assets across our multi-basin portfolio. Using WTI price ranges of $55-$70 per barrel from 2026 through 2028, the updated three-year scenario delivers 5% cash flow and greater than 6% free cash flow compound annual growth rates, generating cumulative free cash flow of $10 billion-$18 billion and earning robust double-digit returns on capital employed. This updated three-year scenario demonstrates how EOG's relentless focus on returns, our diverse multi-basin portfolio, and industry-leading exploration capabilities provide clear visibility to sustain high returns and durable free cash flow generation for years to come. Overall, the three-year scenario delivers approximately 20% higher free cash flow in 2026 through 2028 than the actual results for the prior three-year period, assuming the same price deck. On commodity fundamentals, we expect total crude and product inventories to continue building over the next few quarters. However, increasing global demand, geopolitical factors, and stockpiling of petroleum reserves are providing price support. Beyond near-term dynamics, we remain constructive on medium to long-term oil prices being driven by steady demand growth and the need for additional supply. Importantly, global spare capacity is declining, which should provide an oil price floor, while geopolitical events will continue to drive upside price volatility. On natural gas, our outlook remains positive. U.S. natural gas enjoys two structural bullish drivers, record LNG feed gas demand and growing electricity demand. We expect U.S. gas demand to grow at a 3%-5% compound annual growth rate through the end of this decade. Our investments in building a premier gas business positions EOG to deliver supply into these expanding markets. We believe our premium gas business is an underappreciated asset, providing exposure to growing demand and with access to premium markets from geographically diverse sources. EOG's value proposition is clear. We're guided by our strategic priorities, capital discipline, operational excellence, sustainability, and culture. Our 2025 results demonstrate consistent execution across our premier multi-basin portfolio, while our cash return performance reflects our unwavering commitment to disciplined value creation through the cycles. EOG is better positioned than ever to execute on our value proposition and create shareholder value. Now, here's Ann with a detailed review of our financial performance. Thank you, Ezra. EOG's financial strategy remains steadfast: invest capital in a disciplined manner, pay a sustainable and growing regular dividend, return significant cash to shareholders, and maintain a pristine balance sheet. The Q4 2025 exemplifies this strategy in action. We generated adjusted earnings per share of $2.27 and adjusted cash flow from operations per share of $4.86, building free cash flow of nearly $1 billion. For 2025, EOG reported adjusted net income of $5.5 billion, or $10.16 per share, and free cash flow of $4.7 billion. For 2025, we delivered a 19% return on capital employed, maintaining our peer-leading ROCE. We continue to deliver on our commitment to return cash to shareholders. During the Q4, we returned $1.2 billion to shareholders, $550 million to our robust regular dividend, and $675 million in share repurchases. For the full year, we paid $2.2 billion in regular dividends or $3.95 per share, representing an 8% increase over 2024, and we repurchased $2.5 billion in shares. Our 2025 cash return was 8.2% of our market cap, which led our peers. With $3.3 billion remaining under our current share repurchase authorization, we have ample flexibility for additional opportunistic buybacks. In today's dynamic energy environment, share repurchases are especially compelling, and we expect to remain active on share buybacks, continuing to enhance returns through the cycles. Our peer-leading balance sheet provides an outstanding competitive advantage. We ended 2025 with $3.4 billion in cash and $7.9 billion in long-term debt. Combined with our undrawn $3 billion revolver, total liquidity stands at approximately $6.4 billion. Our leverage target of total debt at less than 1 x EBITDA at bottom cycle prices remains among the most stringent in the energy sector, providing both downside protection and the flexibility to invest strategically through cycles. We increased proved reserveses by 16% to 5.5 billion bbl of oil equivalent, continuing our long track record of reserve growth. Net proved reserve additions from all sources, excluding price revisions, replaced 254% of 2025 total production. Turning to 2026, we expect capital spending of $6.5 billion at the midpoint of guidance. At current strip prices and using guidance midpoints, this plan generates $4.5 billion in free cash flow. In the current environment, we anticipate returning 90%-100% of annual free cash flow to shareholders, consistent with recent years. In summary, EOG delivered another outstanding year. We strengthened our portfolio, maintained a pristine balance sheet, and positioned the company for sustainable value creation through commodity cycles. With that, I'll turn it over to Jeff for our operating results. Thanks, Ann. I want to start by recognizing the exceptional dedication of the entire EOG team. Consistent, safe, and outstanding execution is what converts operational strength into shareholder value. 2025 demonstrated that. Our teams met or exceeded expectations on nearly every operational metric. Production volumes outperformed guidance, driven largely by stronger performance in our foundational plays, while our disciplined capital investment remained in line with expectations, delivering strong free cash flow. Let me highlight several accomplishments throughout 2025 that have helped position EOG for long-term success. First, we made significant strides in lateral length optimization. Longer laterals means fewer vertical wellbores to drill, more productive time, both on surface and downhole, reducing surface footprint and improving capital efficiency. In addition, EOG's internal drilling motor program acts as a force multiplier on these longer laterals, improving downhole drilling performance and giving us the confidence to continue extending laterals across our portfolio. We are focused on drilling 2-3 mi laterals in the Delaware Basin and 3-4 mi laterals in the Utica and Eagle Ford plays. Second, extended laterals and sustainable efficiency improvements led to well cost reductions of 7% in 2025. Our focus on sustainable efficiency gains for drilling and completion operations creates meaningful value because they compound over time, leading to significant cost savings through the development of an asset. Third, cash operating costs came in under target, led by a meaningful reduction in LOE, due in part to our proprietary production optimizers program, which leverages machine learning to optimize base production, delivering better runtime and lower cost across the portfolio. Looking ahead, 2026 is positioned to be an outstanding year for EOG as we build on the strong momentum established in 2025. Given the macro environment, we're keeping oil production flat with Q4 2025 levels, which results in annual oil production growth of 5% and total production growth of 13%. We can deliver this disciplined plan for a capital budget of $6.5 billion. Throughout the year, we plan to complete 585 net wells across our multi-basin portfolio of high return inventory, with the majority of the capital being allocated to our foundational assets, the Delaware Basin, Utica, Eagle Ford, and our newest foundational asset, Dorado. We will also continue investment across our international portfolio. Capital cadence and activity should be relatively consistent through the year, with a roughly even capital split between the H1 and H2 and activity averaging approximately 24 rigs and 10 completion crews. Looking at the service cost environment, despite lower industry activity in the H2 of 2025, we're seeing a relatively stable market for high-spec equipment with minimal cost reductions. Support services have shown some softening and will continue monitoring the market for savings opportunities through 2026. We've locked in approximately 45% of our total well costs this year, giving us flexibility to capture any additional market softening. For 2026, we're targeting a low single-digit reduction in well costs driven by sustainable efficiency gains. In the Delaware, our team has consistently delivered innovations, including our EOG motor program, Super Zipper operations, high-intensity completions, and production optimizers. From 2023 to 2025, we increased lateral lengths by nearly 30% while reducing well costs by approximately 20%. We have also strategically invested in infrastructure, including facilities, gathering systems, water transfer stations, and the Janus gas processing plant, all of which deliver lower operating costs that complement our well cost reductions. Over the past few years, we have fundamentally improved the cost structure of our Delaware Basin assets. Because of this, our development program now includes additional zones that previously did not meet our stringent return hurdles. While per well productivity declined last year as we targeted these incremental opportunities, our economics did not. Our 2025 Delaware program continues to deliver over 100% direct after-tax returns at $55 WTI, while improving capital efficiency by 4%. For 2026, we expect consistent year-over-year well productivity and strong economic performance, while averaging 13 rigs and four completion crews in the Delaware. In the Utica, the Encino integration is ahead of schedule, has exceeded expectations and remains a significant focus for 2026. We achieved our $150 million synergy target ahead of our original one-year timeline from close. We continue capturing additional synergy opportunities. We have achieved several operational wins with the Encino asset since closing the acquisition in August. We've increased the drilled feet per day by over 35%. EOG scale and purchasing power has reduced casing costs over 30%. We've increased the completed feet per day over 10%, and our team has reduced on-site facility costs by 20%. These achievements has helped us to reduce our well costs below $600 a foot by year-end of 2025. We're planning to have in-basin, self-sourced sand in Ohio by the end of the year, which should further reduce completion costs. For 2026, we expect to run three rigs and three completion crews, completing 85 net wells. Our foundational Utica asset is positioned for continued improvement as we build upon the significant cost reductions achieved over the past few years. In the Eagle Ford, efficiency gains continue to improve economics. From 2023 to 2025, we increased drilled feet per day by 5%, while boosting completed lateral feet per day by 30%, driving a 15% reduction in well cost. Last year, we extended lateral lengths, highlighted by the record 24,000 ft lateral on the Whistler E5H. For 2026, we expect to run four rigs and one completion crew, completing 115 net wells, while continuing to leverage technology and efficiency gains. Turning to Dorado, we've made outstanding progress over the past few years and now have transitioned this world-class gas asset to our newest foundational asset. To be a foundational asset, the play must meet or exceed our high return hurdle, have significant running room, have a consistent level of activity which supports a full-time completions crew, and generate free cash flow. Dorado will meet these criteria this year and will stand beside our other foundational assets, the Delaware Basin, Utica, and Eagle Ford. In 2025, we met our exit gross production target of 750 million cu ft per day and are targeting an exit rate of 1 Bcf per day gross production in 2026. We significantly lowered well costs to approximately $750 per foot through operational efficiencies. From 2023 to 2025, we increased drilled feet per day by 30% and completed lateral feet per day by 20%. With a low break-even price of $1.40 per Mcf, Dorado is exceptionally well positioned to serve our growing LNG gas supply contracts and Gulf Coast gas demand. We'll run two rigs there this year and one completion crew, which will complete 40 net wells. Our Gulf States exploration programs are moving forward, and the teams are making exciting progress. We commenced operations in Bahrain and the UAE in the H2 of 2025. Will continue to test and delineate these plays throughout 2026. We anticipate having initial well results in the Q2 of this year. These opportunities leverage our technical expertise and extensive data set from thousands of unconventional wells across diverse plays, prime examples of EOG's commitment to organically expanding inventory through exploration. In closing, our 2025 performance demonstrates the strength of our multi-basin portfolio and operational excellence. As we execute our 2026 program, we're confident in our ability to deliver consistent results, maintain capital discipline, and generate strong returns for shareholders across all commodity price environments. With that, I'll turn it back to Ezra. Thanks, Jeff. As we close, I want to highlight why EOG represents a compelling investment opportunity and how we're positioned to deliver sustained shareholder value. First, our asset base differentiates EOG versus peers. With approximately 12 billion bbl of equivalents of high return, long-duration resources, we have diversified exposure across North American liquids, North American natural gas, and international, conventional and unconventionals. This creates multiple pathways for value creation as each of these markets grows over the medium and long term. Second, our unconventional and exploration capabilities are a long-time hallmark of EOG. This core competency doesn't just unlock significant upside in our current inventory, it allows us to build future inventory in a low-cost, high-return manner. Third, we're a low-cost, efficient operator with deep technical expertise. Our relentless focus on innovation in drilling and completion techniques continues to drive our cost structure lower. This reflects our decentralized model that effectively creates a portfolio of pure-play companies that can leverage knowledge and expertise across the entire company. Fourth, our disciplined capital allocation framework drives superior financial performance, generates robust free cash flow, and delivers peer-leading returns on capital employed. Finally, we remain committed to returning cash to shareholders through our regular dividend and opportunistic share buybacks, and our peer-leading balance sheet provides both protection and opportunity. We have the financial capacity and flexibility to invest opportunistically through any cycle. Thank you for your continued interest in EOG. We'll now open the line for questions. Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key, followed by the digit one on your touchtone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. You are allowed one question and one follow-up. We will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. To remove yourself from the queue, press star two. Our first question today is from Neil Mehta with Goldman Sachs & Co. Please go ahead. Yeah. Good morning, Ezra and team. Thanks for taking the time. Ezra, I wanted to start off on the composition of the wells this year and the activity. year-over-year, there is a slowdown in the Delaware. I think you're going from 390 to closer to 300 in terms of wells that you're gonna attack, and it looks like you're picking up in the Utica. Could you just talk a little bit about the composition? How do you think about the optimal level of activity in the Permian particular and the composition of activity over the course of the year? Yes, Neil, this is Ezra. Good morning. Good morning. It's a great question. This year, the plan really takes a step towards optimizing investment across our high return foundational plays. As you recall, we're really seeing pretty similar returns across all of our foundational plays now. Specific to the Delaware Basin, the activity level really optimizes utilization of existing infrastructure, across our acreage position, and that really helps support better capital efficiency. You know, we expect consistent Delaware Basin performance going forward. As Jeff talked about, our strategic shift in development strategy in 2025, has been an outgrowth of our dramatic cost savings the last few years, combined with investment in that infrastructure to help lower operating costs. The cost savings have allowed us to capture some of these additional landing zones that exceed our economic hurdle rates. We're now actively co-developing many of these targets. Some of the targets have lower productivity per foot, some have different GORs, but each, as Jeff highlighted, is delivering the high returns that our shareholders have come to expect. We expect the consistent well results you've seen quarter-over-quarter throughout 2025 to really continue through 2026, and really through the entire three-year scenario that highlights, you know, the strong returns and increasing free cash flow going forward. At this year's activity levels in the Delaware Basin, you know, we expect to deliver relatively flat production to Q4 2025, similar to the company level. Maybe, I think it's 3,000-5,000 bbl a day less, due to really outperformance in the Q4 there in 2025 by the Delaware Basin asset. Really, I think the big takeaway is that at this level of activity in the Delaware Basin, you know, we're confident we can maintain similar returns and free cash flows for longer than 10 years. It really comes back to the deep inventory of high return assets we've captured across multiple basins, Neil. Yeah, and appreciate that. Maybe that's a good follow-up, or you can address the Delaware question. It's something we get a lot from investors who look at some of the well results and are concerned that there's degradation in terms of quality of inventory and those well results. I think, I think you guys have a perspective on that. How do you address that case that's been out there? Neil, this is Jeff. You know, really, like we've talked about in the past, I'll give you a little bit of details. It just has to do with all the progression we've made there, because, as we've said, there's not just one variable that goes into economics you know, it's not just production. I mean, ultimately, you got to focus on rolling everything up to make sure you're maximizing returns, and that's what we're doing. In the Delaware, just taking a look over the last three years, you know, we've extended our laterals 30%. We've lowered the cost there by 20%, which has ultimately improved the capital efficiency by 4%. When you take all that and you roll it up, our cost right now is at or below $725 a foot. Because of this, you know, we've talked about, we've been able to unlock those additional targets up through the strat column, and that they meet our return hurdles now at bottom cycle pricing and deliver payouts, you know, much less than 12 months at current pricing. The other thing it also does is it really improves the overall recovery per acre, and it maximizes the NPV per acre across the asset, which is really what we're looking for. By design, you know, we're obviously seeing a little bit lower productivity on those targets, but not lower economics. They're matching any other target that we have in, and they've actually meet that hurdle. Now that we've fully implemented that new development approach, as Ezra said, you know, we aren't gonna see any major changes in productivity. It should be relatively consistent moving forward from here. You know, we're extremely excited about how the Delaware program has progressed and how our team has unlocked all this additional value there through the cost reductions. As Ezra said, you know, we've set it up for an extremely successful year and many years on to become. Thanks. The next question is from Steve Richardson with Evercore. Please go ahead. Hi, morning. Thanks for the time. I appreciate the update on Dorado and appreciate that the team's worked so hard to move it towards foundational. I was wondering, Ezra, if you could just talk about how you thought about increasing activity there versus some of your oilier basins, you know. I appreciate the $1.40 break even, but just how do you think about the gas macro and how this play kind of fits into that? I was wondering as a, you know, follow-on to that, if you could kind of address how your LNG take contracts gonna change in 2026 and 2027. Yeah, Steve, good morning. This is Ezra. Yeah, listen, we're, I appreciate the question about Dorado. As we've highlighted on slide 18 on our deck, we've had a fantastic couple of years. You know, we've dropped our well cost down to $750 per foot. We've increased drilled feet per day by 30%, completed feet per day by 20%. It's really dropped our breakeven down to about $1.40 per Mcf, and that includes F&D, LOE, GP&T, G&A, and production tax. We're still, highly confident that Dorado, you know, is the lowest cost gas supply in the U.S., with exceptional, you know, geographic location, with its proximity to the Gulf Coast and premium markets. I think Jeff has talked about that we exited 2025 at about 750 million a day, and we plan to exit 2026 at about 1 Bcf a day gross. That measured pace of investment, Steve, it continues along just kind of our cultural approach to each of our plays. We're investing in it with two things: One, to keep to make sure we don't outrun our pace of learnings. We can continue to drive down the costs associated with any of our plays, but especially here in Dorado being a gas play. The second thing is, we really are growing into not only the emerging North American natural gas demand that we see, but really some of the contracts that we have. Now we can supply many of our contracts from multiple basins, but as you brought up with our LNG specifically, as of Q1, we've actually increased our exposure to LNG by 140 MMBtu per day. That's on top of the preexisting 140 MMBtu per day that's linked to JKM or Henry Hub. We also have another 300 million a day that's already been going to LNG that's linked to the Henry Hub. That leaves us one additional tranche of 140 MMBtu per day, that we anticipate coming on later this year and will be linked, again, to JKM or Henry Hub. As we move into 2027, we have an additional contract, as you know, that's linked to Brent, or the U.S. Gulf Coast gas, for a total of 180 MMBtu per day. Again, when we think about, the first part of your question, Steve, how does Dorado compete for capital versus the liquids plays? You know, that's one of the strengths of being a multi-basin, company and having dedicated North American liquids plays and dedicated North American natural gas plays, is that we don't really see them competing against each other. They're really, able to service different parts of the market. What we see overall in the U.S. natural gas demand, much of it's coming from these longer cycle projects. Certainly, there's an increase in U.S. electricity demand, but when we think about data centers, behind the meter or LNG, oftentimes, when you sit across the table negotiating with the other stakeholders, they're really looking for the confidence in, you know, 10, 15, 20-year, multi-decade type of contracts. That's really the strength of having a dedicated North American gas, natural gas play, as opposed to associated gas. Really helpful. You know, great progress there, congrats to the team in Corpus. I was wondering, just to follow up, you know, this is the second year in a row that you've run more than 100% of free cash in terms of the buyback, or sorry, in terms of cash returns to shareholders. Can you maybe just talk about that? You know, the target is unchanged, but you've had a, you know, we'd probably say, a pretty, you know, squishy commodity price environment, but you've been able to do that and bolt on a pretty significant acquisition. How do you think about that going forward? Is this just the best use of cash, as the cash comes in? You know, just remind us, you know, how does your view of value of the stock or relative performance, or how do you kind of all think about, you know, that buyback lever, which seems like you really like at the, at the current time? Hey, Steve. Good morning. This is Ann. You know, to address the free cash flow, of course, we're looking at the best ways to create value for the shareholders. Our pristine balance sheet places us in an excellent position to reward shareholders with robust returns of free cash flow. We have demonstrated, as you said, a commitment to return significant cash to our shareholders, and we do expect this to continue, as we really don't see a need to build cash on the balance sheet. The current environment, as you noted, is dynamic and could provide the opportunity to re-return cash at similar levels as we have over the past few years. You know, we start our cash return anchored by our sustainable growing regular dividend. Then we'll supplement that by share repurchases and/or special dividends. Recently, we've had a focus on the opportunistic buybacks as a primary mode of additional cash return. In the current environment, we're very comfortable returning that 90%-100% of annual free cash flow that I outlined, and that's similar to what we've done over the past few years. Our focus just continues to invest our dollars to create long-term value for our shareholders. The next question is from Doug Leggate, with Wolfe Research. Please go ahead. Good morning, everybody. Ezra, I think you may have partially answered this is the first time you've given the new free cash flow visibility post Encino. Obviously, you've got a $6.5 billion capital budget. There's a lot in there that's not maintenance capital, you have also, and, you know, putting a $50 breakeven on this. Where I'm going with this was, if I heard you right, did you say that on a sustaining basis, you think you can hold your free cash flow flat for 10 years or sustain it for 10 years? I don't want to put words in your mouth, if I take the $6 billion high end at $70 oil, that gets you to about two-thirds of your market cap. In other words, it's not enough. Can you just clarify what you were meaning there? I've got a follow-up, please. Yeah, Doug, this is Ezra. Good morning. Yeah, my comments earlier were specific to the Delaware Basin. I'm sorry, I think that's where the disconnect is. Okay. the Delaware Basin. That's a relief. Yeah. Really, what we've seen with the three-year plan, the three-year scenario, quite frankly, is that. You know, at a, you know, the high-level takeaway, like I said, is comparing the past three years with the forward-looking three years at a similar price deck, we've actually increased the free cash flow potential there by 20%. Even with a low single-digit oil growth and modeling a mid-single-digit kind of total production growth, we're seeing 6%+ compound annual growth rate of that free cash flow year-over-year. Just to my follow-up, then, would just be a clarification. When you look at your sustaining capital, what do you think that level is for the post-Encino portfolio? What do you believe the duration of that is post the three years? I mean, are we talking about 20 years of inventory, 20 years of sustainable free cash flow? How do you define it, and I'll leave it there. Thanks. Yeah, there are kind of two different questions in there. Maybe I'll address the first one as far as the inventory life, and I'll let Jeff maybe follow up with the details on our maintenance capital number post-Encino. Doug, when we think about the resource potential, the inventory, the deep inventory of high return assets that we've captured, that I talk about, you know, slide eight in our inventory, in our deck, is probably one of the best ways to look at it. We've presented that 12 billion bbl in a way that... You know, it's two different things on that slide. You can think of it as kind of an R/P, a good old-fashioned R/P, which that 12 billion bbl, to your point, speaks to, you know, close to 20 years' worth of production. Then you can also see on that, and, you know, you're welcome to apply any type of risk to that as you deem necessary. The other thing you'll notice on that slide is the returns as a proxy to free cash flow. You can see that 12 billion bbl essentially generates greater than a 55% return at $45 and $2.50, greater than a 100% rate of return at $55 and $3 gas. What I would point out is, as we develop, you know, a program every single year, it's not that we're, you know, force ranking our rates of return inventory and drilling the, you know, the highest, you know, 400 or 500 wells first. There's always a mix in there, which is why we present our inventory as a, as kind of a kitchen sink effect on that rate of return. Because at different times, you're obviously drilling in different parts of the basins, you're trying to maximize infrastructure, you're trying to limit your indirects. So that's really the best way to look at it. I would say that we have great confidence, being able to deliver similar free cash flow, similar returns at the company level for many, many years to come, based on the deep inventory, of 12 billion bbl of equivalents. Jeff, with the maintenance capital, maybe? Good morning, Doug. Yeah, this is Jeff. Yeah, you're correct. It's been a handful of years since we've updated that maintenance capital, with it updated, its current range right now is from $4.8 billion-$5.4 billion, so midpoint around $5.1 billion. Really, what this range represents is the capital required to hold production flat for a period of three years, and it also assumes our current well costs right now, and that's consistent with our updated three-year scenario. The other thing I'd say is, the big changes that have really happened since the last update is, you hit on, obviously, the Encino acquisition, we built into that. There's the increase in production of the base business since the time of the previous disclosure, also there's the impact of the improvement across the, our portfolio since the time of the previous disclosure. Lastly, I just note that, you know, this maintenance capital, it really reflects a modest improvement in our base decline, which is now below 30% for oil and below 20% for BOE. The next question is from Scott Hanold with RBC Capital Markets. Please go ahead. Yeah, thanks. I was wondering if we could go back to Permian productivity. It seems like it's been a bit of a headwind for, you know, EOG share price. I appreciate the context you guys have provided on those, you know, we'll call it secondary zones, which is something, you know, other peers are talking more about that and surfactants and other things. You know, I don't want to lead your answer, but do you think some of the relative performance that people are being concerned about is because you all have been able to move faster to these secondary zones than peers? If you could give us a sense of, on some of the primary, you know, kind of activity that you've done, is the productivity over the last few years fairly static? Scott, this is Ezra. Thanks for the question. Over the primary targets, I'd say we're seeing relatively consistent performance there. Of course, even... You know, it's difficult to compare because even if you think about, say, an Upper Wolfcamp or a Wolfcamp A, you end up having multiple landing zones in there. Don't forget, you know, we're a pretty technical bunch here, and so we look at, you know, the permeability. Is it a little bit siltier? Is it more of a mud rock? Those are the types of things that, with just a little bit of savings on your cost side, all of a sudden, some of those targets really become, you know, more economic than what you'd previously, you know, counted them on. What I would say is, like for like, though, we're seeing pretty consistent well results in there. As far as, you know, pushback, I think, from the peers, you know, I don't want to speak to the peers. What I would say, what I think is going on with us, is that we made this shift. I think we figured that we had pretty well highlighted this and externally talked about adding nine additional landing zones over the last few years. In hindsight, Scott, I think we probably could have done a better job highlighting our change in development strategy heading into 2025, again, off of the really extreme cost reductions that we saw coming off of essentially the relative highs there in 2023. No, appreciate the context. You know, as my follow-up, you know, if we could move to natural gas, and you all have increased exposure to, you know, pricing on the water with some of your LNG contracts. Could you give a sense of, you know, other things that you all may be working on or considering, you know, supply agreements, you know, for industrial users or power data center users? Yeah, Scott, this is Ezra again. It's a good question. You know, we've spent time looking at, you know, really how data center development may progress and what role EOG might play. You know, I think there are a couple of different ways where we can benefit today, potentially benefit in the future. You know, the diverse marketing strategy gives us exposure to regional pricing uplift associated with increased electrical demand, in areas of data center development. Obviously, we've seen U.S. electricity demand grew last year, just shy of about 2%. Electricity prices obviously grew more than that, about 6.5%. I think going forward, U.S. electricity demand overall is forecast to grow between 1% and 3%, kind of compound annual growth rates. Obviously, we'll see, you know, we can benefit from our diverse exposure across our basins from there. A good example also is the capacity that we capture along our Transco pipeline to deliver gas into that southeast market, which is a big power pool demand center. Really, another way we think that EOG might be able to benefit much more directly, and we have had negotiations along this path, is if we begin seeing development of data centers closer to power gen or closer to natural gas fields. We see both, you know, especially South Texas and Ohio, as having great potential to play a larger role in data center build-out. Obviously, the position that we have in Dorado and the Utica would benefit from that regional demand. I think when you think about South Texas, there's, you know, especially Dorado, there's open space, there's water. You're far enough inland from any storm threats, there's a good amount of gas, a phenomenal amount of gas there, and there's also a good amount of fiber already in the ground. Right now, I'd say it's still surprisingly early on with a lot of the data center conversations. You see a lot of the construction is somewhat delayed or getting pushed out to the right a little bit as people, again, I think, really try to wrap their minds around a multi-decade contract. That's where we think that we've got a competitive advantage with Dorado, is that we've got the gas supply, low-cost gas supply, to stand up and support one of those longer term projects. The next question is from Derrick Whitfield with Texas Capital. Please go ahead. Good morning, guys, and thanks for your time. Regarding your three-year outlook, I wanted to focus on the role international could play over that period and beyond that period. While onshore will undoubtedly carry the load in your financial performance, how should we think about the increasing role international could play as we exit the three-year period? Derrick, appreciate the question on the three-year scenario. You know, the scenario does include capital for the Gulf States exploration and development. You know, beyond the capital that's really tied to the 2026 plan, we're basically forecasting a slight increase in the activity in the Gulf States. The associated production assumption is really minor, and we're doing that in the three-year scenario because those plays are still in the exploration phase right now. We do assume success and declaration of commerciality, but in the timeframe of the three-year scenario, I would say that the specifics to the international assets are relatively minor. With regards to Trinidad, we've got a bit more line of sight, slightly longer cycle projects, and we continue to have a pretty robust program there in Trinidad ongoing. Great. Then with regard to UAE and what you know about the subsurface today, how does that compare versus some of the premium U.S. unconventional oil basins? How should we think about your delineation plans for that in that area in 2026? Yeah. Good morning. This is Keith. You know, both in UAE and Bahrain, activity this year, we're gonna, you know, continue our drilling program to evaluate those exploration concessions. We're expecting activity to be higher in the UAE than Bahrain, just due to the relative size of the concessions. We're still in the early phases of that, so our plan for 2026 is a little bit dynamic. As Jeff mentioned, we expect to have production results in both countries in the Q2 of this year. In Bahrain, we drilled our first few wells, and we have started completing them. In the UAE, we've drilled the first couple wells. Those went very smoothly, and we plan to begin completing them here shortly. We're very excited about the opportunity that we see in both countries. Both areas have positive production results from prior horizontals. As far as delineation in 2026, we are just really working to refine our subsurface understanding to build off of ADNOC and Bapco's progress and positive momentum on cost reductions and help bring even more of the latest unconventional technology to the region. We think that there is a lot of technology and similarities between many of our domestic plays that we can borrow and apply to either country. The next question is from Charles Meade with Johnson Rice. Please go ahead. Good morning to the whole EOG team there. Jeff, Keith, maybe I'll just pick up on that, pick up on that thread and ask about in the UAE and Bahrain. Less about the well results, but how you guys are going to communicate there. You know, I think that at least in the lower 48, the EOG MO is kind of, you know, to quietly try something in a play, and then based on success or failure, either quietly exit or quietly build a position. That doesn't really, you know, it doesn't seem to be an option to just, you know, quietly exit in Bahrain and in UAE. Also, at the same time, there's not the same competitive considerations there, given the nature of these concessions. Can you know, not looking to commit you to anything, but can you give a broad outline of how you guys plan to share results and, you know, and what the consequent decisions to either ramp activity or curtail it? Yes, Charles, this is Ezra. I'll take a crack at that question. You know, it has been something that we've had to get used to, kind of our international strategy, and we saw this. You know, the best thing to do, I think, maybe, is to take a look back at what we did in Oman. Again, it is a little bit different from our domestic exploration portfolios or projects, where we can usually, you know, be a little bit stealthy and keep things quiet until we get, you know, material results or a material position in a play and can really start to discuss it. Typically, these days, when you internationally, when you sign an agreement, you know, there happens to be a press release and things like that. The first step is making sure that the agreement is something that checks the boxes for us for international, so that we have captured a sizable position, we have captured access to premium markets. Of course, we've been able to negotiate a contract, align the stakeholders, and partner with folks that we think will be able to, if we have success, really have success and really have captured something that is gonna be exceptionally competitive and additive to the corporate portfolio. Now, again, in Oman, you're right, there is no state data, there's no public reporting. I thought we were fairly transparent with the results that we had in Oman, and when we exited, we didn't try to, you know, sneak out the back door. We just made it known to everybody that we had drilled the wells. As you recall, we made a kind of an undeveloped discovery there, a natural gas discovery. We're really focused on oil because of the lack of infrastructure in the area, and so we did end up exiting. Bahrain and UAE, to be perfectly honest, will be, you know, very, very similar to that. Both of these international opportunities, we're currently in an exploration phase. That lasts a certain amount of time, and then there will come a point where, after we satisfy the, you know, terms of the exploration phase, there will be a decision on whether or not we go forward, casually called a declaration of commerciality, and that would then, you know, assign some sort of longer-term production license. You can assume that that would obviously be something public. That being said, at this point in the game, we feel very confident in all the plays. We're very excited about the size of the prize that we have in both the UAE, with our unconventional oil play and the unconventional gas play in Bahrain. Bahrain obviously is onshore, so you can imagine it's a little bit, as Keith said, a little bit smaller in scope. It is a gas play in a region where we see tremendous future gas demand, that probably is an area where we'd continue to look for the right partners. While we're very happy with what we've captured in the region, we'd be interested in continuing to look for, you know, adding a potential additional gas project in the region, under the right terms and with the right partners. The next question is from Phillip Jungwirth with BMO. Please go ahead. Yeah, thanks. Coming back to the multiyear scenario, recognizing it's not guidance, but the low single-digit oil growth is maybe a bit surprising, since organic volumes have been flattish here since Liberation Day, and that's continuing into 2026. Could you help us understand how you would resume oil production growth? Which assets drive that? Just one of the qualifications in here is that it assumes current cost structure. Just wondering, when you look back at 2023 through 2025 actuals, how much you actually outperformed here, and could you see similar run rate over the runway over the next 3 years? Yeah, Phillip, this is Ezra. That's a great question. Using current costs is just for line of sight. I do think with our consistent track record of lowering costs, you know, that's the best data points that we have. If you want to build in a little bit of conservatism, you know, I could understand. What I would point out is that we've made tremendous strides over the past three years in the Delaware Basin. Part of that was with our sustainable operational efficiency gains. Some of that, too, though, was in 2023, was relatively kind of a high industry, high watermark for costs across the industry. We've made tremendous progress lowering well costs across our two emerging assets as well. As you know, early in these assets, early in the play development, you have the opportunity to make greater strides there. As far as returning to low single-digit oil growth, you know, outside of the Liberation Day announcements that caused, you know, really a little bit of concern on really the line of sight on what may happen with demand, coupled with spare capacity reentering the market, we see that as a bit of an overhang for maybe the next couple of quarters. Certainly, there's a lot of commentary that the oil glut has been pushed to the right. We're seeing that as well. What we're also seeing is that when you look at total product, inventories have raised right to the five-year, roughly in line with the five-year average. There is some additional spare capacity that's scheduled to come back to the market. That being said, we continue to see global demand growing, you know, relatively strong, and consistent at roughly that 1 -1.2 MMbpd, roughly, maybe at right at 1%, a little bit less than 1% compound annual growth rate. That's really what gives us confidence in forecasting growth of low single-digit oil. Now, where that growth would come from, you know, in the three-year scenario, it contemplates a lot of growth out of the Utica, as a matter of fact, but quite frankly, we can grow from multiple basins if we, if we needed to, if we wanted to. Really, the growth at the company level will really be determined by optimizing across each of those basins, you know, the level of activity, the marketing agreements, where do we have infrastructure and things of that nature. Great. Then you met the $150 million in Encino synergies well ahead of schedule. I think you gave yourselves a year here. Could you just talk to the drivers, positive surprises now that you've operated the asset for six months? I assume you're not done here in terms of driving improvement. You mentioned in basin sand. Anything else you're working on to enhance returns? If you could also just touch on marketing initiatives here to improve netbacks. Yeah, Phillip, this is Jeff. As we kind of touched on in our opening remarks, obviously, we're extremely happy with how everything's progressed with the synergies there. You've heard kind of how much success we've had across the operational side, you know, with just drilling completions with our procurement side. Extremely happy and driven that cost down to 600 ft, $600 a foot in very short order. We really have only been developing there a handful of years. As I kind of look forward, I mean, I think there's a handful of things that we can really lean on. Full rollout of the EOG support services. I mean, you kind of touched on it there. I mean, once we implement self-source local sand, that's gonna be a big initiative to really drive down costs. Tying together a lot of our water infrastructure and maximizing reuse in the area, that's gonna be a pretty big driver that we can use our technology from around the rest of the portfolio. You know, it'll take a little while, and we're in process, but, you know, implementing additional automation and measurement across the, all of the acquired operations. We'll be able to, you know, remotely manage and monitor wells and, really take advantage of our 24/7 control room that monitors everything up there. What that will do is really improve a lot of our efficiencies and reduce man-hour times. Then, lastly, as you talked about, continuing to focus really on utilizing the scale now of the asset to reduce the GP&T and work on the differentials. I think the big ways we're gonna do that, as I stated, is first and foremost, you know, we like to control in-field infrastructure and gathering. We're gonna focus on building that out, which should help bring our differentials down. On the marketing agreements, obviously, just with the scale there, we have great relationships with the marketers. We're in contact with them regularly and continuing to look for options to be able to either extend out agreements and optimize those agreements to be able to lower the fees, just because we have so much more volume and scale up there. I really think, you know, we're just kind of tip of the iceberg. We've got a lot of upside in the play. We've still got upside in synergies. Our team continues to uncover, you know, opportunities every single week. The next question is from Matthew Portillo with TPH. Please go ahead. Good morning, all. Just a quick follow-up question on the Permian. Great to see in the remarks that you're expecting stable productivity trends for the basin this year, and also to hold production flat in 2026 on an exit-to-exit standpoint. I was just curious if you could maybe help us out a little bit on that last point for the outlook. Looking into 2025, I think you completed about 390 wells in the basin and drove about 10,000 bbl a day of growth. Obviously, you've highlighted a big drop in the well count this year, down to about 300 wells. I think the maybe missing piece around this might be the lateral length progression. I was curious if you might be able to help us out on that front. Yeah, Matthew, this is Jeff. You know, we've made great progress across our whole portfolio from a lateral length aspect, not just even in the Permian Basin. At last year alone, we increased our lateral length by 18% across the portfolio, and it really was driven by, as you're talking about, the momentum that we had with 3 mi laterals there in the Delaware Basin. We had a substantial increase there and a focus on that. We extended our laterals, you know, in the Eagle Ford, where, you know, in certain areas that were stranded, we were able to drill numerous 4+ mi laterals with, obviously, the record lateral that we had there on that Whistler E5H. The same thing in the Utica Shale. You know, we've got 3+ mi full program basically there across the board that's really helping push. If you look at the Delaware Basin, it's basically fairly flat, actually, from 25 to 26. The reason for that is just the huge jump that we had last year. Obviously, that has to do with a lot of our footprint and the leasehold that we have out there. Our team is always gonna look for opportunities to go ahead and continue to make trades, bolt on additional acreage, and extend those laterals wherever we can, because I think we've proven, you know, with our drilling technology, with the EOG motor program and our approach, that we're able to drill those longer laterals with great success. Great. Maybe just to follow up on Dorado. Looking at the state data, saw a really nice improvement in the productivity trends per foot in 2025. I was just curious if you might be able to comment on this improvement and what might be driving that. Maybe a bigger picture question, with your exit rate approaching a Bcf a day of gross production in 2026, I know you've talked about compression potentially taking the Verde pipeline to 1.5 Bcf of egress. I'm curious if there is a need down the road for potentially more pipeline capacity, just given the economics of the assets and the improving productivity trends we're seeing out of the basin in aggregate? Yeah, thanks for the question. No, we've been extremely excited with how Dorado has evolved down there. Really, it's kind of across the board from both drilling and completions and production, being able to increase the well performance there. Like everywhere else, you know, we look at our wellbore construction. We make sure that we're maximizing, you know, our high-intensity fracs and creating as much, you know, hydraulically, you know, created surface area downhole as possible with those things. As you stated, we are. We're seeing about a 13% year-over-year increase, and that's a sustainable increase on a per foot. It's really a recovery, you know, not just a lateral length increase. Extremely excited about that, and we're continuing to work it. On the second part of your question, yeah, we have the EOG Verde pipeline in service. As you talked about, it provides a Bcf of transport over to Agua Dulce, and it is expandable up to about 1.5 to 1.75 Bcf, with very minimal investment in booster compression. You know, that provides us an uplift that's very attractive, of about $0.50-$0.60 an Mcf, and that's just due to the lower GP&T and obviously, the higher netbacks that we have there. With that, you know, that will be able to, along with our other third parties, we won't need any other egress out of there. We've got plenty of egress with that pipe right there, and as I said, we don't just necessarily transport all down that pipe. We do have other third parties that we can actually, you know, market to in that area. We feel really comfortable for the long term there in Dorado with our takeaway. This concludes our question-and-answer session. I would like to turn the conference back over to Ezra Yacob for any closing remarks. Yeah, I'd just like to say we appreciate everyone's time today. Thank you to our shareholders for your support, and special thanks to our employees for delivering another exceptional quarter. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.