Good day, everyone, and Welcome to EOG Resources fourth quarter and full year 2024 earnings results conference call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Investor Relations Vice President of EOG Resources, Mr. Pearce Hammond. Please go ahead, sir. Good morning, and thank you for joining us for the EOG Resources fourth quarter 2024 earnings conference call. 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, some of the 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 CEO, Jeff Leitzell, Chief Operating Officer, Ann Janssen, Chief Financial Officer, Keith Trasko, Senior Vice President, Exploration and Production, and Lance Terveen, Senior Vice President, Marketing and Midstream. Here's Ezra. Thanks, Pierce. Good morning, everyone, and thank you for joining us. EOG's consistent execution of our value proposition delivered another year of outstanding performance. Oil and total company production exceeded our original 2024 forecast while capital expenditures were on target. We also reduced cash operating costs year over year and increased our regular dividends 7%. We earned $6.6 billion of adjusted net income for a 25% return on capital employed. In the four years since COVID, we have earned an average 28% return on capital employed and are outpacing the average of our peers. Finally, we returned 98% of free cash flow through a combination of our regular dividend and share repurchases. Looking forward to 2025, EOG has never been better positioned to deliver long-term shareholder value. Jeff will review our 2025 capital plan in more detail in a moment. However, at a high level, our plan builds on last year's success and is grounded in our commitment to, first, capital discipline: returns-focused investments at a pace that supports continuous improvement across each of our assets. Second, operational excellence: integrating organic exploration with best-in-class operational expertise, proprietary information technology, and self-sourced materials and marketing agreements to expand margins. Third, sustainability: a commitment to safe operations and leading environmental performance. And fourth, our culture: fostering a decentralized organization and recognizing that value is created in the field at the asset level by collaborative, multidisciplinary teams utilizing technology to drive real-time decisions and innovation. The depth and quality of EOG's diverse portfolio of unconventional resources is unmatched. EOG holds more than 10 billion barrels of oil equivalent and resource potential that earns among the highest returns in our industry, averaging more than a 55% average direct after-tax rate of return using our updated view on the bottom cycle pricing of $45 oil and $2.50 natural gas. We continue to evaluate returns, margins, and payback period under several price scenarios, remaining focused on optimizing half and full cycle returns with net present value to create shareholder value. The result of this comprehensive evaluation of investment across our portfolio is realized in the strong free cash flow generation and return on capital employed that we have delivered over the past few years and that we are positioned to deliver through the cycle. Our portfolio includes our core assets in the Delaware Basin and Eagle Ford, which remain the largest areas of activity in the company. After more than a decade of high-return drilling, both assets deliver exceptional returns and top-tier results while operating at a steady pace. Our emerging South Texas Dorado dry natural gas play and the Powder River Basin and Utica combo plays are not only contributing to EOG's success today but laying the groundwork for years of future free cash flow generation and high returns. Another area contributing to the foundation for future high-return investment is on the international front. In Trinidad, where we've been operating for over 30 years, we continue to identify high-return projects due to our extensive knowledge of the regional subsurface while also applying our cost-conscious culture to remain capital disciplined and deliver projects that compete with our domestic portfolio. In 2024, we successfully constructed and set one new offshore platform, sanctioned a new platform to be constructed, and were awarded two new offshore blocks in the shallow water bid round hosted by the Trinidad and Tobago Ministry of Energy. Also, on the international front, we are excited to begin working on a new joint venture in Bahrain. We expect this to be the beginning of a long-term partnership with Bapco Energies to explore and develop an onshore unconventional tight gas prospect in Bahrain. The formation has previously been tested using horizontal technology, delivering positive results. We are optimistic that applying our expertise in horizontal drilling and completions technology will enhance results and drive economics competitive with our domestic portfolio. Our partnership with Bapco Energies is a great example of stakeholder alignment and what we look for in international opportunities: exceptional partners, geopolitical stability, scale and economics to compete with our domestic portfolio, areas with existing oil field services, and ultimately reservoirs that can realize significant uplift through the application of horizontal drilling and completions. Shifting our outlook on the macro, for more than two years, oil prices have been remarkably range-bound at a fairly robust $65-$85 per barrel WTI. Looking forward, we expect increased demand and low global inventories to offset the pending return of global spare capacity. Barring unexpected supply and demand shocks, we expect oil prices to continue to be similarly range-bound this year. On the natural gas side, incremental reductions to gas inventories throughout the year were exacerbated this January when cold weather dramatically reduced inventories by approximately one TCF and drove inventories below the five-year average for the first time in more than two years. Prices have strengthened accordingly despite the modest return of shut-in volumes. For 2025, we expect additional support for prices from ongoing demand increases from natural gas power generation and the startup of several LNG facilities. The addition of our strategic marketing agreements over the past few years have positioned us to grow into these markets as they develop. Our cash flow priorities continue to focus on sustainable value creation. Disciplined capital investment and a pristine balance sheet support a growing regular dividend, countercyclical investments, and additional cash returns, all underpinned by a large resource base, providing long-term visibility for high returns and strong free cash flow generation through the cycle. Now, here's Ann with details on our financial performance. Thanks, Ezra. 2024 was an outstanding year for EOG that highlights our continued financial strength and record shareholder returns. In 2024, we invested $6.2 billion in CapEx, which drove annual production growth of 3% in oil and 8% in total company volume. In 2024, proved reserves increased by 6% to 4.7 billion barrels of oil equivalent, which represents a 201% reserve replacement, excluding price revisions. We also lowered finding and development costs, excluding price revisions, by 7% to $6.68 per BOE. Outstanding financial performance allowed us to return a record $5.3 billion to shareholders. This represented 98% of 2024 free cash flow, well in excess of our commitment to return a minimum of 70% of annual free cash flow to shareholders. Last year's record cash return was underpinned by our growing sustainable regular dividend, which remains the foundation of our cash return commitment. This commitment to our shareholders is based on our ability to continue to lower our cost structure and sustainably expand future free cash flow generation. We believe the regular dividend is the best indicator of the company's confidence in its future performance, confidence we have consistently demonstrated through our history of dividend growth. We have never cut or suspended the dividend in our history, and in fact, we have grown our dividend rate twice as fast as our peers' average since 2019. Last year, we increased our regular dividend 7% to an indicated annual rate of $3.90 per share. This $2.2 billion annual cash return commitment currently represents nearly a 3% dividend yield. In addition to our regular dividend, we repurchased a record $3.2 billion of shares in 2024 at an average price of $123 per share. Since we started buying back shares in 2023, we have reduced our share count by 5%. Entering 2025, we have $5.8 billion remaining on our existing buyback authorization for opportunistic share repurchases. In 2025, we will continue to work towards our balance sheet optimization targets of $5-$6 billion in cash and $5-$6 billion in debt, which we outlined last quarter. At the end of 2024, we had $7.1 billion in cash on the balance sheet, which included approximately $700 million of estimated tax payments postponed to 2025 under IRS storm-related tax relief. We also have the flexibility to remain opportunistic on issuing additional debt and will continue to monitor interest rates and the broader financial market as we approach our next maturities in April of this year and in January of 2026. EOG's balance sheet remains among the strongest in the sector and is a competitive advantage in a cyclical industry. It provides tremendous flexibility to support cash returns to shareholders as well as maintain our ability to invest in low-cost property bolt-ons and other countercyclical opportunities. For 2025, we have outlined a disciplined capital plan that keeps CapEx flat year over year at $6.2 billion. The cash flow break-even price to fund our capital budget and the regular dividend is in the low 50s. At $70 oil and $4.25 natural gas, we expect to earn a return on capital employed of 20% or greater. Now, here's Jeff to review 2024 operating results and detail the 2025 plan. Thanks, Ann. Consistent operational execution across our multi-basin portfolio during the fourth quarter capped off yet another outstanding year. Fourth quarter oil and gas production volumes beat targets, as did cash operating costs and DD&A. I'd like to thank our employees for their safe and efficient operational execution, delivering not only a strong quarter but another year of exceptional performance. For the full year 2024, we improved safety, reducing our workforce total recordable incident rate by 10%. We delivered more oil in total production for lower cash operating costs than we initially forecasted, while capital spending remained right on target. We improved productivity and base production performance through innovations in completion design and artificial lift automation. We lowered average well costs by 6%, primarily through extended laterals in EOG's in-house drilling motor program. Our marketing team continues to deliver top-tier price realizations, which has consistently outpaced our peers' performance, while also capturing two new natural gas agreements that expose us to premium pricing. First is our 364,000 MMBtu per day capacity on the Williams TLEP project along the Transco pipeline. And second is our 180,000 MMBtu per day gas sales agreement with Vitol that links sales prices to either Brent or U.S. Gulf Coast gas indices. We also progressed two strategic infrastructure projects last year, which we expect will continue to drive peer-leading realizations. The first is a 36-inch Verde pipeline, which runs from our Dorado natural gas asset in Agua Dulce and provides access to Gulf Coast market centers. Verde came into service during the fourth quarter last year and provides capacities for one BCF per day, expandable to 1.5 BCF per day with booster compression. The second project is our Janus natural gas processing plant in the Delaware Basin. The 300 million cubic feet per day facility will come into service in the first half of this year and connect to the Matterhorn pipeline, giving us access to multiple premium Gulf Coast markets. These projects and agreements demonstrate the ongoing value of our marketing strategy, which is to maintain diverse and flexible takeaway while maintaining control and limiting the duration of our commitments. This ultimately allows us to manage our end markets in real time and maximize our netback through dynamic market conditions. And finally, we maintained our GHG and methane emission intensity below our 2025 targets. Building off the momentum from our 2024 performance, we are excited about our 2025 plan. We forecast a $6.2 billion capital program to deliver 3% oil volume growth and 6% total production growth. Our growth in 2025 is more heavily oil-weighted due to the well mix in the Delaware Basin. Overall, the cadence of our capital spend will be slightly more than 50% in the first half of the year, peaking in the second quarter and tapering throughout the year. When looking at well costs in 2025, we expect oil field service pricing to be relatively flat year over year. So cost reductions will come from continuing to advance the sustainable efficiency gains captured across our entire operations portfolio last year, as illustrated on our slide eight of our investor presentation. Two of the primary drivers we expect to continue momentum with are longer laterals in our foundational plays and efficiency gains from consistent operations in our emerging plays. As a result, we are projecting a year-over-year percentage reduction in well cost in the low single digits. As always, EOG remains focused on progressing each one of our plays at the optimal pace to allow us to capture and implement valuable learnings while realizing continuous improvement. In the Delaware Basin, we are seeing improved year-over-year capital efficiency. The combination of longer laterals and our in-house drilling motor program helped increase drilled feet per day by 10% and completed feet per day by 20% last year. Our 2025 plan includes another increase in average lateral length of at least 20%, which will support continued efficiencies. In our emerging plays, the Utica in Ohio and Dorado in South Texas, we are realizing excellent operational efficiency gains and are excited to increase activity levels by 20% across these plays. In the Utica last year, we increased our drilled feet per day by 50% and our completed lateral feet per day by five. We anticipate efficiency gains in 2025 to be driven by higher activity levels and expect to average two full-time rigs and one full-time frac fleet in 2025, and in Dorado, we are also benefiting from efficiencies gained by maintaining a full rig program, increasing both drilled feet per day and completed lateral feet per day by 15% each in 2024. We plan to maintain one full-time drilling rig in Dorado, allowing us to build on last year's momentum to grow this low-cost gas asset into the emerging North American demand markets. This year, we will continue supplying the Texas Gulf Coast LNG market through our gas sales agreements with Cheniere. We have realized significant uplift in our natural gas revenues in the first five years of our agreement and are excited Cheniere has progressed their Corpus Christi Stage III project. Our forward guidance now reflects our Henry Hub-linked 300,000 MMBtu per day sales agreement tied to the completion of the project's Train 1, which we expect to start up in 2025. Furthermore, our strategic partnerships and pricing diversification continue to minimize our exposure to Waha, which we expect to be limited to 5%-7% of our total natural gas sales this year. On the international front, our 2025 plan includes a modest increase in capital expenditures to advance several discoveries in Trinidad and support our new partnership in Bahrain. In Trinidad, we are planning four net wells from our newly constructed Manta platform, and we will commence construction on the Coconut platform to support the JV and farm-out agreement for the Coconut field signed last year. We are excited about executing our 2025 plan. EOG remains focused on running the business for the long term, generating high returns through disciplined growth, operational execution, and investing in projects that lay the foundation for future returns and lowering the future cost basis of the company. Now, here's Ezra to wrap up. Thanks, Jeff. 2024 yielded outstanding results. We continue to generate significant free cash flow and deliver high returns on capital to shareholders. Capital discipline, operational excellence, commitment to sustainability, and ultimately our culture are at the core of our success as a company. You see the result in our consistent performance year after year. EOG is continuing to deliver in 2025. Our disciplined approach to investment across our foundational and emerging portfolio of assets, international expansion, strategic infrastructure, and unique marketing agreements continue to grow the free cash flow potential of the company both in the short and long term. Supported by a pristine balance sheet and a deep inventory of high-return projects, EOG continues to create shareholder value by focusing on being a high-return, low-cost producer committed to strong environmental performance and playing a significant role in the long-term future of energy. Thanks for listening. Now we will go to Q&A. 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 touch-tone telephone. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited, so one question and one follow-up question. We will take as many questions as time permits. And once again, please press star and one on your touch-tone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the star key followed by the digit two. We'll pause for just a moment to give everyone an opportunity to signal for questions. And the first question will come from Neil Mehta with Goldman Sachs. Please go ahead. Hey, good morning, Ezra and team. Thanks for the rundown here. Two questions. The first was just the free cash flow guide, the $4.7 billion at $70 WTI and $4.25 Henry Hub. It's a little softer than I think where we and some consensus had. And I think some of that just might be timing because there's some pre-productive capital in the plan. But maybe you could talk about that, some of the investments that you're making in the emerging plays and infrastructure might show up a little bit more in the 2026 free cash flow versus 2025, as that's been a focus of conversations this morning. Yes, Neal, this is Ezra. Good morning. Yeah, we kind of start with that 25 plan. It starts with capital discipline for us. As I said in the opening remarks, that's a core pillar of the value proposition that we have, and it's a key consideration in establishing the plan for each year, so as you talked about, it kind of portfolio specific with some of the moving parts here. The plan in general is pretty consistent with the commentary we provided last quarter. We're operating at an optimal level in both our foundational plays, and we've got opportunities to improve our emerging plays with higher activity. So when we look at the Delaware Basin, we've got flat activity there. We're delivering a more capitally efficient program this year. In the Eagle Ford, we've got just a little bit of moderation in activity, coupled with a little bit longer laterals. In the Eagle Ford, we're seeing, I'd say, strong and consistent capital efficiency year over year. As Jeff mentioned, there is more capital being allocated to our emerging assets, so 20% more completions in the Utica, 20% more completions in Dorado. In the Utica, we look to end the year with two rigs and one full-time frac fleet, and as we've talked about in those emerging plays, that's kind of the activity level we try to get each of our assets to so we can really start to capitalize on the economies of scale. And then the last moving part there, of course, is we've got a little more remaining investment in the strategic infrastructure, as you mentioned, and then some additional investment in both Trinidad and Bahrain, as we talked about on the opening remarks there, and so a bit of a step up in international spend. When all that kind of adds in, essentially our capital and volume growth is similar to 2024. And as you pointed out, the free cash flow is a little bit less. And the two drivers there really are increased cash taxes due to some expiring AMTs that we had in 2024 that we won't have in 2025. That's the biggest piece of it. And then we also have a little bit of an increase in operating expense that we're forecasting. Some of that's due to higher fuel and power in the field affecting LOE. And then we also have some initial transportation contracts that are increasing GPT a little bit this year. As you know, when you step into new transportation contracts, you usually have higher costs upfront, and then those kind of come down over time as you deliver the volumes. Essentially, stepping back, as we think about the 25 plan, we're extremely excited about the year ahead. From an operating perspective, we're continuing to drive strong results in those foundational plays and making the right investments to continue to improve the business going forward, supporting short and long-term free cash flow potential. Yeah, that's really helpful, Ezra. Some of those items that could have driven that, and then the follow-up is just on international. It sounds like there's a little bit more international spend in the portfolio, the capital program this year, so can you unpack that a little bit, Trinidad, Bahrain in particular, and what's got you excited? Hey, Neil, this is Jeff. Yeah, I'll just quickly touch on it and hand it over to Keith for a little bit of details. But yeah, you're exactly right. We've got about $100 million in the increase in the international capital that really just reflects our continued investment, as you talked about, in both Trinidad, which we've got to our Manta program that's going to be performed this year, and also we're going to be constructing our Coconut platform there. And then also the new entry in Bahrain, which what I'll say is the goal is to start drilling on that sometime in the second half of the year. The one note on both of these, though, is both programs, we won't really see any volumes necessarily come online this year. They'll be pushed probably more into 2026. So I'll hand it over to Keith for a little more detail. Yeah, good morning. This is Keith. Yeah, in Trinidad, we are really excited about the program there this year. As we mentioned, we have just set the Manta platform. So we're looking at four net wells in 2025. This is a discovery that was made a few years ago where we are the operating partner with BP, and this is the development phase of that. The wells come on later in the year in 2025, so that's why you're not seeing a volume impact on the roll-up. We also have our Coconut project that we're really excited about. We've had a consistent exploration effort in Trinidad since our entry into the country, and Coconut is the newest prospect in that long and successful history. So that was also an exploration well drilled a few years back, and we're commissioning the platform to access an estimated 500+ BCF of resource potential associated with that. That is also a joint venture project with BP, so we really value our ongoing relationship with them. We also value being a preferred partner in the shallow water in Trinidad due to our low-cost structure. So we're looking forward to the drilling program that will follow the successful setting of that platform. We also, this year, were awarded two new blocks in Trinidad. So I'm really proud of the team, how they continue to unlock new opportunities. We've been in Trinidad for 30 years, and we have a really long future there. The next question will come from Arun Jayaram with J.P. Morgan Securities. Please go ahead. Yeah, good morning. Just maybe, Ezra, a follow-up to the updated free cash flow outlook. I wondered if you could spend a little bit of time talking about your natural gas differential guidance, which is a bit wider than we expected and also wider on a year-over-year basis. We thought that may narrow just given the higher amount of coverage you have at Henry Hub, as well as the startup of Corpus Christi. So I was wondering if you could help us unpack that. Arun, hey, good morning, everyone. Yeah, let me unpack that for you. When you think about our guidance there, and really when you look back on 2024, I mean, you can see the peer-leading realizations, and we really expect that to kind of carry forward moving into 2025. Unpacking a little bit of the guidance, let's talk about that. As you think about the basis along the Gulf Coast, and kind of depending on when you're looking at those estimates, but primarily when you look at Houston Ship Channel along the Gulf Coast, we've really seen that weaken here getting into the first quarter. We've seen that be about 30 cents back, and that's kind of moved to about 55 cents back. Meanwhile, you've seen NYMEX. Obviously, it's moved up from the fourth quarter of 2024 into the first quarter of 2025. I mean, we've seen that move up almost $1, right? Almost like $0.86. So as you look at that and then think about, you're right, we have these new strategic agreements that are going to be starting up this year, but that kind of has to feather in, right? That's going to ramp up kind of as that comes into the year. So it really is, we will see an inflection point this year. We really feel with our realizations, but you just kind of have to take that into consideration with the startup of those agreements as well. I think if you look at the supplemental slide eight, Arun, I think that really does a very nice job of illustrating, especially when you look from 2024 into 2025, I mean, really how we're directing more of our molecules away from where there's the basis deducts and getting to places like that's more linkage to Henry Hub and also into the Southeast markets. That's helpful, Lance. Maybe my follow-up is just on Bahrain. It sounds like there has been some well control there. Ezra, could you talk about what type of capital a project like this could look like and just maybe the timeline to cash flows if things kind of play out based on your expectations? Yeah, it's Arun. This is Ezra. Right off the bat, it's probably a little bit early to start talking about cash flows and things like that. We haven't disclosed the capital for our program this year. While we're very excited about the JV partnership with Bapco Energies, at this point, we've entered into a participation agreement. We are awaiting a couple of additional government approvals. We do have some capital in the plan that includes some activity this year. In the partnership, what I can say is EOG is the operator. We'll be evaluating a tight gas sand, gas exploration prospect. The agreement does anticipate selling the production into the local market there, which is great. In this area, the formation has been tested. It's seen positive production results already with horizontal development. And as you guys know, this is Bahrain. It's not a significantly large island or anything. We do have existing infrastructure and midstream in the area, which would allow us to, if successful and competitive with our portfolio, would allow us to go to sales relatively quickly. We're optimistic really that applying our expertise in horizontal drilling and completion technologies should enhance the returns and the results and drive economics to be competitive with the domestic portfolio. And the next question will come from Josh Silverstein with UBS. Please go ahead. Hey, thanks. Good morning, guys. So you ended 2024 with $7 billion in cash following the 4Q debt offering. It sounds like you have the $700 million tax payment for this year. But how should we think about the pace of buybacks, given you talked about wanting to stay at a cash balance of $6 billion or less? Thank you. This is Ann, Josh. We remain committed to making our capital structure more efficient. We outlined for you last year what we wanted our debt and cash levels to be. So basically, we want to stay at less than 1x total debt to EBITDA target at $45 WTI. So if we take that metric, that would put our debt at approximately $5-$6 billion. We followed through on that commitment last year by starting by adding that $1 billion new issuance back in November of 2024, and we're going to work towards that $5-$6 billion debt level, and we have some flexibility on timing of that as we move forward over the next 12 to 18 months. Regarding our cash level, we still believe the appropriate level of cash for our business remains $5-$6 billion. That level for the last couple of years and allows us, in the normal course of business, to backstop our regular dividend. Kind of turn into 2025 and look at our free cash flow return. Part of that, of course, is our share return. We're going to target that 70% return cash flow to investors. And we have the potential to and are well positioned to return a higher percentage of that cash flow. However, the level of cash return is not working. Yeah, I'm sorry. We couldn't hear you that well. Okay. Do you want me to try to start over just to walk you through it? That'd be great. Yeah, sorry. Yeah, sorry about that. My apologies. Hey, on the debt side, when we're looking at the debt side, if you recall back in the end of 2024, we outlined our capital plans, our capital structure for going forward and what our commitment that we wanted to make our capital structure more efficient. As we outlined last quarter, we were focused on achieving a debt level of less than 1x total debt to EBITDA at $45 WTI. And if you look at that metric, that would be approximately $5-$6 billion. We followed through on that commitment back in November by raising $1 billion in 30-year paper at a 5.65% rate. And we're going to continue to work towards that $5-$6 billion debt level. And we have flexibility on the timing of when we achieve that amount. We'll do it over, of course, the next 12-18 months. If you look at our cash level, we believe the appropriate level of cash continues to be that $5-$6 billion. We have run at that level for the last couple of years. We think that's the right level to run our business, backstop our regular dividend, as well as supporting additional cash return and countercyclical investments. You're correct that $7 billion at year-end included that $700 million that we paid out in February of 2025. If you turn to the pace of our buybacks, it's really about our commitment to return free cash flow to shareholders. We're staying at that target of a minimum of 70%. We have the potential to, and are well positioned to return more, a higher percentage of free cash flow back to the shareholders in 2025 and going forward. And we've exceeded that minimum, as you saw in 2024. But we remain comfortable with that being our long-term target. So as far as share repurchases, we'll continue to be opportunistic. We're not putting in any type of programmatic plan. We'll just continue to watch where our share prices go, and we'll be opportunistic in our buyback program. Again, we're just committed to returning a significant portion of our free cash flow to our investors, and that cash return is anchored by that dividend. And then, in turn, we'll look to share repurchases and other returns of value back to the shareholders. Thanks, Ann. And then second, in Dorado, you've held back some activity over the past two years. We're now in a higher price environment. Your pipeline started up, and the new LNG facility is starting up around the corner. Are you guys just waiting on kind of confirmation of the $4 plus gas price environment to accelerate more activity, or just taking a more kind of modest pace of growth there? Yeah, Josh, this is Jeff. As we do with any of the other plays, we're just evaluating the activity levels there really more from a long-term perspective rather than just looking at the near-term commodity price volatility. So really, when we look at Dorado, we feel that the 20% increase in activity this year is a really good level and truly reflects what we believe is the optimum level of activity just to continue to push it forward year over year for operational improvements like we saw in 2024. And we saw about 15% improvement in drilled and completed feet per day. And we think with this current activity level, it really positions Dorado in a great position to improve year over year and continues to drive down the cost while we're taking advantage of where the proximity is. What we really look to do is not just invest necessarily at a particular price point, but we really look to invest to lower our costs through the cycles. The next question will come from Leo Mariani with Roth. Please go ahead. Hi, guys. Just wanted to follow up a little bit on the decision to dial back Eagle Ford activity. Looks like net completions are down around 25% year over year. I know your lateral lengths are going up, so presumably total completed feet aren't down quite that much. But just provide a little bit more color there. Are you just seeing incremental returns not being as competitive with your Delaware or the emerging plays, or are you obviously increasing activity here in 2025? Yeah, thanks, Leo. This is Keith. I think what we're really seeing is that we really leaned into the Eagle Ford in both 2023 and 2024. In 2023, we had stepped up activity levels in the wake of the persistent inflation in the Delaware Basin, and in 2024, we were sharing a frac crew between Dorado and the Eagle Ford. So consequently, there were more completions in the Eagle Ford when we deferred completion activity in Dorado due to weaker gas prices, and so I think what you're seeing is us getting back down to kind of our background levels there. You mentioned the longer laterals, so when we look at how much lateral feet we're completing in a year, this year is pretty average compared to the last several years, so the Eagle Ford is a core foundational asset for us. It continues to be. Despite operating in the play for 15 years, the consistent improvements and efficiencies have allowed us to realize some of the highest returns in the play we've ever seen, actually, in the last several years, and it supports a line of sight to maintain production for a decade or more, really. Okay. I appreciate that and wanted to just jump back over to the exploration side. I know you guys have been looking at a number of domestic oil exploration plays for the last handful of years. Just wanted to get a sense of what the activity levels there are. Are you still pursuing those type of lower-cost exploration plays domestically for oil here in 2025? Obviously, you've got the Bapco JV, which is international gas. So just trying to kind of get a sense there if there's still a number of these plays active and what should we expect in terms of activity in 2025. Yes, Leo, this is Ezra. That's a great question. With the Bapco announcement, you can see that we've obviously been active not only on the domestic exploration front, but also international. Like you said, Bapco is an international gas opportunity, and so I think that highlights really well where we're focused at with our exploration approach, and that's really not necessarily to focus on an oil versus gas, but really what we focus on for either domestic or international is the returns of the play and how additive to our existing inventory will the project be, and so as you highlighted, we've got an active domestic program. We drilled a few wells last year, and we've planned to drill a few more this year, but further than that, Leo, we typically don't comment or give additional details on our exploration programs more than that. We do remain optimistic that there are still resources in the U.S. that will continue to be additive to the overall inventory that we have. And the next question will come from Derrick Whitfield with Texas Capital. Please go ahead. Good morning, all, and thanks for taking my questions. From the outside, it appears you guys have experienced tremendous success with all three emerging trends. For my first question, I'd like to focus on the Utica and ask, how close is it to competing heads up with the Eagle Ford? Yeah, Derek, this is Ezra. You know it's interesting. The Eagle Ford we have is a very mature asset. And what I'd say is, as Keith alluded to, when we invest at the Eagle Ford at the right pace, we still generate significant returns there. And one of the reasons is because we've got all the infrastructure in place. We've got our marketing agreements dialed in. We've really captured the economies of scale. So that's really one of the things that right off the bat is still lacking with the Utica. We've been able to make good strides on the operational efficiency gains, as Jeff mentioned in the opening notes. But really, to get that thing to compete with either of our foundational assets, you really need to get it to a place where you can drive down the costs, sustainable costs through capturing the economies of scale of. And when I say infrastructure, it's not just midstream or takeaway. It's things like in-basin sand locations, getting our water infrastructure squared away, and then just having consistent frac and drilling operations to the point where we provide a safe and consistent operating environment where the guys in the field can really drive down costs. I would say that we've been very happy with the early-time results. We're exceptionally pleased with the results we've had over the first two years in this play. As we talked about, we're carrying a lot of momentum into 2025. I think we highlighted in November that over the next couple of years, while we focus on that volatile oil window, we're looking at a $6-$8 per BOE finding and development cost. That contemplates less than a $650 per foot well cost, which already on those types of metrics brings it very well in line with kind of where the Eagle Ford is. On a head-to-head comparison, when you think about how far we've made it with the Eagle Ford after year two, if you think about it that way, the Utica is significantly farther down the path of having lower well costs and, quite frankly, a better understanding of the subsurface reservoir quality. That's great. And for my second question, with the efficiency and productivity gains you've noted in the Niobrara, where do you think you could drive F&D costs with the benefit of both working? It seems like we're getting closer and closer to a breakthrough in the PRB. Yeah, this is Keith in the Powder River. Yeah, exactly. We've talked about how in the past, when we were developing the Mowry, we had gathered data on the Niobrara, which is shallower, and that we were shifting activity to be more focused on the Niobrara. So if you look at the Powder activity as a whole in 2025 plan, it's roughly flat to last year, but it's much more Niobrara-focused. So if you were just to look at Niobrara well counts year over year, significant uptick this year. In the play overall in 2024, being able to have all that data gathered and then put the focus on it, we were able to increase the well productivity 20% in the Niobrara year over year. That's 2024 to 2023. We also reduced the days to drill down 10% year over year. We're very happy with the strides in the Powder. And on the finding cost side, I'll kind of say this. We talk about how our company overall is a multi-basin portfolio. We kind of have a little multi-basin portfolio in the Powder itself. You have the Mowry, more of a combo play with good finding cost numbers. And then the Niobrara, a little more oil, which is a little bit higher return. And together, they do kind of mix to make a nice kind of holistic asset there. The next question will come from Nitin Kumar with Mizuho Securities. Please go ahead. Thanks for taking my question, guys. I want to focus on the Delaware. You're raising lateral length there quite significantly. But last year, we had talked about sort of stepping away from the core oil and into some other parts of the basin. How would you characterize the productivity of the Delaware program this year versus last year? Yes, Nitin. This is Jeff. And the productivity trends in the Delaware, they're going to vary in any given year just based on several factors. But we're fully confident in the development strategies we have out there and just the durability of the returns and the full-cycle economics that we're seeing. So with any of our plays, obviously including the Delaware, the first thing we leverage is rate of return at a flat bottom cycle pricing. And that's a pretty good starting point to underpin your evaluation. But there's a lot of other key metrics that we like to evaluate. And specifically, we really want to maximize the net present value, not just of the well, but really the sections out there. We want to make sure that we're expanding the margins. We really pay attention to what the payback period is just to make sure that we're delivering the greatest value and really capturing as much resource as possible. As you just hit on in the Delaware, a perfect example, and we've kind of talked about, is this year alone, we're seeing some variation in the well mix there where the productivity is slightly more oil-weighted in the first quarter. That really just has to do with that well mix where we move around the field back and forth from area to area, developing different benches. That's just part of our normal development. You'll continue to see this kind of variation in productivity and well mix throughout the development of the play. And then the other thing that I just really touch on there in the Delaware is over the last few years, we've made significant improvements in our shallow targets, really by lowering cost and improving the productivity by really just pushing forward our current best practices. So when you break it down by target and play there, if you look at the Leonard, the Bone Springs, the Wolfcamp targets, they're all delivering comparable returns at bottom cycle pricing. So when you roll it all up today, I think we're better positioned than ever to really optimally develop a given section from both a subsurface targeting perspective because of our geologic knowledge and then also the above-ground infrastructure perspective. And that really is what allows us to balance all of these things: return, NPV, payout margins, resource capture, and productivity to make sure we ultimately maximize value. Great. Thanks for the detail there, Jeff. Ezra, I'm going to try to take one more shot at the Bahrain opportunity. I know details are limited. Trinidad accounts for about 10% of your corporate gas production. Could Bahrain be the same scale or bigger over the years? And then for those of us who don't know what Bahrain local gas pricing looks like, are the returns as competitive as your domestic exploration? Yes, Nitin, this is Ezra. Thanks for revisiting Bahrain. Like I said, we're excited to talk about it. I think the first tell is that we want to take an opportunity international just to say that we have an international opportunity. For us to take this step, we need a couple of things, and the first is that we have pretty strong conviction from an exploration standpoint. I mean, we still need to test these wells a little bit more, but that we've got pretty strong conviction that we'll be able to turn this into something that's meaningful for our shareholders. So that means it's got the size and scale and the potential to deliver returns that are additive to our program, something that will actually command capital that we'll want to invest in. The second part of that, obviously, is to take a big step like this. We want to make sure that we have stakeholder alignment, and we found a good partner, and that's why I keep saying that we couldn't be more thrilled with the partnership that we found with Bapco Energies. As far as gas price in country, we haven't talked about that, but yes, you should think that when we look at the potential sales price and the market, that we would take that in consideration with the well productivity and the cost structure that we anticipate seeing there and roll that all up into something that could be additive and meaningful for the company. And the next question will come from John Freeman with Raymond James. Please go ahead. Good morning. I just wanted to circle back on the Utica. Last year, y'all tested well spacing from kind of 700 feet to 1,000 feet. And as y'all increase activity pretty meaningfully in the Utica, are you sort of, I guess, dialed in on a specific sort of spacing, or is testing still a big part of what you're doing this year to kind of understand that better? Yeah, John, this is Keith. So as far as just your question, development versus testing, where are we doing both? We pride ourselves in not being in a manufacturing mode ever in any of our plays. And so we don't really employ a set spacing or a completion design throughout an entire field. So it's a little difficult to draw a line between development and testing. So we're constantly incorporating new data and learnings to improve every well in every package across all the plays, foundational and emerging. As far as spacing goes, we've talked about in the past that we feel it's going to be 600-1,000, which is pretty standard for a North American unconventional oil play. But we've also said it depends on the area. And so in our last release, we showed tests between 800 and 1,000. We think that geology plays a significant portion or a significant factor in what your spacing should be. So an example would be in the south where we have thinner pay, but we also have better frac barriers we've talked about in the past. That could also mean that the frac reaches out further. So you might expect wider spacing in the south to work out better. Those sorts of things are the things that our team takes into account every time they drill a package and incorporate it into the next one going on. Thanks for that. And then as these emerging plays take on more activity, more capital, as do some of these international opportunities that y'all have been talking about today, do y'all start to take maybe a harder look at divestitures just as a way to unlock value given the pretty deep global portfolio you've got with maybe some areas having a tougher time kind of competing for capital that may be more valuable to somebody else? Yes, John, this is Ezra. Yeah, we continually review our inventory and continue to look for opportunities to bring value forward at any opportunity that we can. For the most part, we've done a good job over the last, I would say, going back almost the last decade. And we've been, not surprisingly, fairly active in the divestiture market. And so we've done a good job kind of high-grading our portfolio at the right times. And the next question will come from Neal Dingman with Truist Securities. Please go ahead. Morning, Ezra and team. Thanks for the time. Ezra, my first question is maybe on IPP or other power gen operations. I'm just wondering, a number of your peers have talked about how their surface water and natural gas resources would make for an ideal partner for transactions. And I'm wondering, y'all definitely seem to have those same high-asset qualities. And I'm wondering, with that said, are y'all actively speaking into some of these hyperscalers? And if so, do you think your opportunities to do something like that would be in the Appalachian, Delaware, Eagle Ford? Because you certainly have a lot of interesting areas where you could do something like that. Yes, it's a good question, Neal. This is Ezra, and you're right. With our investment in and utilization of technology, we have spent a lot of time looking at how data center development may progress and what role industry and EOG specifically would play in that. There's already a couple of different ways that we benefit today and a couple of different ways we can benefit in the future. Currently, if you look at where the data centers are found, they're typically in areas with dense and diverse fiber lines. That's obviously a bit more important than just surface and water. It's the diversity of the fiber lines and if it's in the ground, and as a result, oftentimes those data centers end up being a little bit closer to urban areas. The first thing is it's very nice. We've done a great job with our diverse marketing strategy, and that gives us exposure whenever you see a regional pricing uplift that's associated with just the increased electrical demand in those areas. A good example is the capacity along the Transco pipeline to deliver gas into the Southeast market that we captured last year. But more exciting maybe is the second way we think that EOG can benefit is if data center development outpaces infrastructure development. And so what I mean there is the current model requires transmitting energy either in the form of electrical, grid, or natural gas pipelines over long distances to deliver to these data centers. Another model then would be, and you're starting to see it develop, is constructing data centers closer to the power generation, closer to natural gas fields. But also, more important than surface and water is where there's enough fiber to make the investment worthwhile. When I think about that, I think, Neal, you hit the nail on the head there. We see the Gulf Coast and South Texas as having the potential to play a larger role in data center build-out. And obviously, Dorado would benefit greatly from that regional demand. Yeah, you definitely have some interesting areas. And maybe just a second, if I could ask maybe on the Utica a little bit differently. I'm curious, I don't know if you're able to discuss what part of the Utica you targeted the new 15,000 acres or maybe just looking at another way. I'm just curious how y'all are now thinking about maybe you've got a huge footprint, almost 500,000 acres now. I'm wondering how you think about the western side of the black oil window. I don't know, maybe like in Stark County versus the eastern side well over into Trumbull County. Yeah, Neal, this is Ezra again. Again, where we did most of our leasing, we're still focused in on the volatile oil window. We're kind of leasing and picking up leases out in front of our drilling opportunities at this point. As far as if you think about kind of the Wild West land grab and things like that, the majority of that has kind of ended in that play. And so we're doing a lot of our strategic leasing now, kind of coring up our areas. And since we'll be focusing for the next few years really in drilling in the volatile oil window, that's where the focus of the leasing. I think you can expect that dominantly going forward. As far as stepping out in the expansion, we're still a little ways. We're still talking about we need to get our seismic shot up there first. But ultimately, like any basin, if you go back, whether it's, gosh, even go back to Barnett, early days of the Haynesville, Eagle Ford, Permian, Bakken, things like that, you're really starting the areas where you've got the most data. And that certainly is the volatile oil window for us. We'll develop our wells there. As Keith alluded to earlier, we're making good progress on identifying things like the correct spacing across this almost 500,000 acres, as you said. And once you start to really collect a lot of data and understand more about the reservoir, that's when you can start to step out into these other areas once you have a better understanding of kind of what the value drivers are of the unconventional play. The next question will come from Doug Legate with Wolfe Research. Please go ahead. Good morning. This is John Abbott on for Doug Legate. And thank you very much for taking our questions. Ezra, at your scale, it's getting harder to move the needle on value of the resource. You have about 27 years of inventory. So it seems to us the dividend becomes a more important part of market recognition of value. So our question is, how do you think about the evolution of the dividend, the dividend growing rate, and the dividend break-even? Yeah, John, thanks for joining the call. It's good to hear from you. We're in complete agreement. We think the best marker for a blue chip stock or a company of our scale and size should be reflected in a sustainable and growing regular dividend. And that's really what we focus on and we feel is the foundation of our cash return strategy. We raised our regular dividend 7% last year, and we've actually raised our regular dividend 2x the peer average as a compound annual growth rate since 2019. We've got 27 years of sustainable growing regular dividend. And so we really covet that a lot. The way we think about how we grow that, the most important word I said is sustainable. So we grow it in concert with expanding margins. That means both growing top-line revenue, but also top-line cash flow from operations, but also lowering the cost basis of the company. So making sure that the company is continuing to improve. And then we also marry that up with a strong balance sheet just as a backstop on that regular dividend. And we agree with you, John. I think what we like to see is the dividend increasing and the yield decreasing. Appreciate it. And then for our second question, it's on cash taxes. At least for us, it was a little difficulty hearing in the beginning when Ann was speaking. But is the AMT? Could you talk about the AMT? We thought our impression that you were already a full cash taxpayer. Is that correct? Could you discuss a little bit more detail your cash tax outlook? Absolutely. This is Ann. Thanks for the question, John. The way that we look at the way we're modeling it out, our current tax provision in 2024 included $212 million in alternative minimum tax credits. And those were fully exhausted when we exited 2024. So you're not going to see any impact of that in 2025. So as a result, when you're looking at current tax provision, you're going to see about a 15% increase in current taxes as we move into 2025. And as we look forward, our current guidance for 2025 does not contemplate any material or unusual items. So all things being equal, 2025 is a good proxy as we move forward. This concludes our question and answer session. I would like to turn the conference back over to Mr. Yacob for any closing remarks. Yeah, thank you. I just want to say we appreciate everyone's time today. We're very excited for 2025. I think our plan reflects an appropriate pace of investment to improve each of our assets year over year, as well as the broader opportunities we see to build and improve our business. Disciplined reinvestment and the high-return multi-basin portfolio is how EOG continues to get better. It allows us to lower our break-evens as we add lower cost reserves and ultimately allows us to optimize both near and long-term free cash flow generation. As always, 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.