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.

Yes. 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, Pearce. 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 dividend by 7%. We earned $6.6 billion of adjusted net income for a 25% return on capital employed. In the 4 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 that support 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. 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 capitally 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 to our outlook on the macro for oil prices, they have been remarkably range bound at a fairly robust $65 to $85 per barrel WTI. Looking forward, we expect increased demand and low global inventories to offset the pending return of global spare capacity. Given unexpected 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 1 Tcf and drove inventories below the 5-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 start-up of several LNG facilities. The addition of our strategic marketing agreements over the past few years has 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, countercyclic investments, and additional cash returns, all underpinned by a large resource base, providing long-term visibility for higher return 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. In fact, we have grown our dividend rate twice as fast as our peers' average since 2019. Last year, we increased our regular dividend by 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've already been 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 billion to $6 billion in cash and $5 billion to $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 we'll continue to monitor interest rates in 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 breakeven 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 and 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 cost 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 have 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. 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 1 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 netbacks through dynamic market conditions. 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 oilfield 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 8 of our investor presentation. Two primary drivers, we expect to continue momentum with our longer laterals and 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 drill 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 5%. We anticipate efficiency gains in 2025 to be driven by higher activity levels and expect to average two full-time rigs in one full-time frac fleet in 2025. 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 to their Corpus Christi Stage 3 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% to 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 Mento 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 base of the company.

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, and 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.

The first question will come from Neil Mehta with Goldman Sachs.

Two questions. The first was just the free cash flow guide, the $4.7 billion at $70 WTI and $4.25 Henry Hub was 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 pretty 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 '26 free cash flow versus '25? That's been a focus of conversations this morning.

Yes, Neil, this is Ezra. 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 establishing the plan for each year. So as you talked about portfolio specifics 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, and 20% more completions in Dorado. In the Utica, we look to end the year with two rigs and one full-time frac fleet. As we've talked about in those emerging plays, that's the kind of activity level we try to get each of our assets to so we can really start to capitalize on the economies of scale. 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. 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 '24, and as you pointed out, the free cash flow is a little bit less. 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. 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. We also have some initial transportation contracts that are increasing GP&T a little bit this year. 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. 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 improve the business going forward, supporting short and long-term free cash flow potential.

Yes. That's really helpful as some of those items that could have driven that. And 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?

Hi, Neil. This is Jeff. Yes, I'll just quickly touch on it and hand it over to Keith for a little bit more details. But yes, you're exactly right. We've got about $100 million in their 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 Mento program that's going to be performed this year, and also we're going to be constructing our coconut platform there. 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 probably more into 2026. So I'll hand it over to Keith for a little more detail.

Yes, this is Keith. Yes, in Trinidad, we are really excited about the program there this year. As we mentioned, we had just the Mento 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. That's why you're not seeing a volume impact on the roll-up. Also, we 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 that has a long and successful history. It was also an exploration well drilled a few years back, and we are commissioning the platform to access an estimated 500-plus Bcf of resource potential associated with that. That is also a joint venture project with BP. We're really excited about the drilling program that will follow the successful setting of that platform. We also, this year, awarded two new blocks in Trinidad. I'm really proud of the team for how they continue to unlock new opportunities. We've been in Trinidad for over 30 years, and we have a really bright future there.

And the next question will come from Arun Jayaram with JPMorgan Securities.

Just maybe as 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, it's Lance. Yes, let me unpack that for you. When you think about our guidance there and really when you look back on '24, I mean, you can see the peer-leading realizations and we really expect that to carry forward into '25. So unpacking a little bit of the guidance, let's talk about that. If you think around like the basis along the Gulf Coast and 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 as we get into the first quarter. We've seen that be about $0.30 back, and that's kind of moved to about $0.55 back. Meanwhile, you've seen NYMEX obviously, it's moved up where from the fourth quarter of '24 into the first quarter of '25, I mean we've seen that move up almost $1, right, almost like $0.86. As you look at that and consider, 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? It's going to ramp up as that comes into the year. So it really is, we will see an inflection point this year. We feel with our realizations, but you just kind of have to take that into consideration with the start-up of those agreements as well. If you look at the supplemental Slide 8, Arun, I think that really does a very nice job of illustrating how we are directing more of our molecules away from where there's basis deductions into places more linked to Henry Hub and 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?

Yes, 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're evaluating a tight gas sand, gas exploration prospect. The agreement doesn't anticipate selling the production into the local market there, which is great. In this area, the formation has been tested and has seen positive production results already with horizontal development. This being Bahrain, it's not a significantly large island or anything, and we do have existing infrastructure and midstream in the area, which would allow us to, if successful and competitive with our portfolio, to go to sales relatively quickly. We're optimistic that applying our expertise in horizontal drilling and completion technologies should enhance the returns and results, driving economics to be competitive with the domestic portfolio.

And the next question will come from Josh Silverstein with UBS.

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 have been committed to making our capital structure more efficient, as we outlined last year, what we wanted our debt and cash levels to be. We want to stay at less than 1x total debt-to-EBITDA target of $45 WTI. If we take that metric, that would set our debt at approximately $5 billion to $6 billion. We followed through on our commitment last year by starting by adding that $1 billion, new issuance back in November 2024. We're going to work towards that $5 billion to $6 billion debt level, and we have some flexibility on timing that as we move forward over the next 12 to 18 months. As for our cash level, we still believe the appropriate level of cash for our business remains $5 billion to $6 billion. That level has been the target for the last couple of years. Remaining at that level ensures we can backstop our regular dividend as well as support 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. So regarding the pace of our buybacks, it's really about our commitment to return free cash flow to shareholders. We're staying at a target of a minimum 70%. We have the potential to, and are well positioned to return more, a higher percentage of free cash flow back to shareholders in 2025 and going forward. And we've exceeded that minimum, as you saw in 2024. However, we remain comfortable with that being our long-term target. Regarding share repurchases, we'll continue to be opportunistic. We're not 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 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 second, in Dorado, you scaled 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 just waiting on kind of confirmation of the $4-plus gas price environment to accelerate more activity or just taking a more modest pace of growth there?

Yes, Josh, this is Jeff. As we do with any of our 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. We saw about a 15% improvement in drilled and completed feet per day. We think with this current activity level, it really positions Dorado in a great position to improve year-over-year and continue to drive down costs 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.

And the next question will come from Leo Mariani with ROTH.

Just wanted to follow up a little bit on the decision to dial back Eagle Ford activity. It looks like net completions are down around 25% year-over-year. I know your lateral lengths are going up. Presumably, total completed feet are 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 obviously increasing activity here in '25?

Yes. 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. In 2024, we were sharing a frac crew between Dorado and the Eagle Ford. Consequently, there were more completions in the Eagle Ford when we deferred completion activity in Dorado due to weaker gas prices. 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. The Eagle Ford is a core foundational asset for us. It continues to be, despite operating in the play for only 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 I 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 get a sense there and there's still some of these plays active? And what should we expect in terms of activity in '25?

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. You see Bapco is an international gas opportunity. I think that highlights really well where we're focused at with our exploration approach. That's really not necessarily to focus on an oil versus gas, but really what we focus on, whether for either domestic or international, is the returns of the play and how additive to our existing inventory the project will be. As you highlighted, we've got an active domestic program. We drilled a few wells last year, and we plan 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 Derek Woodfield with Axis Capital.

From the outside, it appears you guys have experience and success with all three emerging trends. For my first question, I'd like to focus on the Utica and ask how close it is to competing heads-up with the Eagle Ford?

Yes, Derek, this is Ezra. It's interesting. The Eagle Ford, we have is a very mature asset. What I'd say is, as Keith alluded to, when we invested in the Eagle Ford at the right pace, we still generate significant returns there. One of the reasons is that we've got all the infrastructure in place, we've got our marketing agreements dialed in, and we've really captured the economies of scale. That's one of the things that is still lacking with the Utica. We've made good strides on operational efficiency gains, as Jeff mentioned in the opening notes. But really, to get to that point where we can compete with either of our foundational assets, we need to drive down costs, capturing the economies of scale. I'm very happy with the early-time results, and we are 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 the volatile oil window, we should be looking at a $6 to $8 per BOE finding and development cost. That contemplates less than a $650 per foot well cost, which already on those metrics brings it very well in line with where the Eagle Ford is. When you think about how far we've come in the Eagle Ford, the Utica is significantly further down the path of having lower well costs and a better understanding of the subsurface reservoir quality.

That's great. 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, as it seems like we're getting closer and closer to a breakthrough in the PRB?

Yes, this is Keith. In the Powder River, yes, we've talked about how in the past, when we were developing the Mowry, we gathered data on the Niobrara, which is shallower, and now we are shifting activity to focus more on the Niobrara. If you look at the Powder activity as a whole in the 2025 plan, it is roughly flat compared to last year. But it's much more Niobrara focused. If you were to just look at Niobrara well count year-over-year, significant uptick is anticipated this year. We were able to increase well productivity by 20% in the Niobrara year-over-year, and we also reduced the days to drill down 10%. We're very happy with these strides in the Powder. Our company operates on a multi-basin portfolio. We have a multi-basin portfolio in the Powder itself, where you have the Mowry as a combo play with good finding cost numbers, and then in Niobrara, a little more oil, which typically yields a higher return. Together, they create a holistic asset here.

The next question will come from Nitin Kumar with Mizuho Securities.

I want to focus on the Delaware. You're increasing lateral lengths there quite significantly. Last year, we had talked about stepping away from the core oil and into 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. The productivity trends in Delaware will vary in any given year based on several factors. However, 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. With any of our plays, including the Delaware, the first thing we leverage is rate of return at flat bottom cycle pricing, which is a good starting point to underpin your evaluation. There are a lot of other key metrics that we evaluate as well. Specifically, we want to maximize the net present value, not just of the well but really of the sections out there. We want to ensure we're expanding the margins, and we really pay attention to what the payback period is to deliver the greatest value and capture as much resource as possible. In the Delaware, a perfect example, we're seeing some variation in the well mix this year. We're productivity is slightly more oil-weighted in the first quarter; that really just has to do with the well mix where we move around the field back and forth from area to area, developing different flow benches. This will continue to happen throughout the development of the play. Additionally, we’ve made significant improvements in our shallow targets over the last few years by lowering costs and improving productivity through our current best practices. When you break it down by target in play, the Leonard, Bone Springs, and Wolfcamp targets are all delivering comparable returns at bottom-cycle pricing. Overall, I think we're better positioned than ever to optimally develop a section from both a sub-surface targeting perspective and an above-ground infrastructure perspective, maximizing value.

Great. 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? 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. 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. The first is we have pretty strong conviction from an exploration standpoint; I mean, we still need to test these wells a bit more, but we've got a strong conviction that we'll be able to turn this into something meaningful for our shareholders. That means it has the size and scale and the potential to deliver returns that are additive to our program, something that will command capital that we'll want to invest in. The second is stakeholder alignment, and we found a good partner. That's why I keep saying that we couldn't be more thrilled with the partnership we found with Bapco Energies. As far as the gas price in the country, we haven't talked about that. You should think that when we look at the potential sales price in the market, we will take that into consideration along with the well productivity and the cost structure we anticipate in Bahrain, rolling that all up into something that could be additive and meaningful for the company.

The next question will come from John Freeman with Raymond James.

I just wanted to circle back on the Utica. Last year, you all tested well spacing from about 700 feet to 1,000 feet and ramped up activity pretty meaningfully in the Utica. Are you sort of, or I guess, dialed in on a specific spacing? Or is testing still a big part of what you're doing this year to kind of understand that better?

Yes, John, this is Keith. As far as your question on development versus testing, we are doing both. We pride ourselves on not being in a manufacturing mode in any of our plays. We do not employ a set spacing or completion design throughout an entire field. It's a bit difficult to draw a line between development and testing. We're constantly incorporating new data and learnings to improve every well and package across all plays, foundational and emerging. As far as spacing goes, we feel it's going to be 600 to 1,000, which is pretty standard for North American unconventional oil play, but it really depends on the area. In our last year lease, we showed tests between 800 and 1,000, influenced by geography. In the south, where we have thinner pay but better frac barriers, that could then mean wider spacing in the south could work out better. These are the factors that our teams incorporate every time they drill and help optimize future drilling programs.

And then as these emerging plays take on more activity and more capital, and as some of these international opportunities that you have been talking about today, do you 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 competing for capital that might be more valuable to somebody else?

Yes, John, this is Ezra. Yes, we continuously review our inventory and look for opportunities to bring value forward whenever we can. For the most part, we've done a good job over the last decade, and we've been fairly active in the divestiture market. So we've high-graded our portfolio at the right times.

The next question will come from Neal Dingmann with Truist Securities.

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 service water and natural gas resources would make for an ideal partner for transactions. I'm wondering you all definitely seem to have those same high asset qualities. Are you all actively reaching out to some of these hyperscalers? If so, do you think your opportunities to do something like that would be in the Appalachian, Dell, Eagle Ford? You certainly have a lot of interesting areas where you could do something like that.

Yes, it's a good question, Neil. This is Ezra. You're right; with our investment in 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 are already a couple of different ways that we benefit today and others that we can benefit in the future. Currently, if you look at where data centers are found, they're typically in areas with dense and diverse fiber lines, which is more critical than just surface and water. As a result, those data centers often end up being a little closer to urban areas. It's nice; we've done a great job with our diverse marketing strategy, which gives us exposure to regional pricing uplift associated with 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. More exciting is if data center development outpaces infrastructure development, where power generation must be transmitted over long distances to deliver to these data centers. Another model would be constructing data centers closer to the power generation sources or natural gas fields, but also more importantly, where there's enough fiber to make that investment worthwhile. I think, Neil, you hit the nail on the head. We see the Gulf Coast in South Texas as potentially playing a larger role in data center buildout. Obviously, Dorado would benefit greatly from that regional demand.

Yes, you definitely have some interesting areas. Maybe just a second. If I could ask about 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 target, the new 15,000 acres, or maybe just looking at it another way. I'm just curious how you all are now thinking about maybe you've got a huge footprint, almost 500,000 acres. I'm wondering how you think about the western side of the black oil window. I don't know, maybe I can start versus the eastern side, well over into like Trimble County.

Yes, Neil, this is Ezra again. With the Bapco announcement, you can see that we've obviously been active not only on the domestic exploration front, but also international. Bapco is an international gas opportunity, and that highlights really well where we're focused with our exploration approach. That's really not necessarily to distinguish between oil and gas but to focus on the returns of the play. We're still focused in on the volatile oil window. We're kind of leasing and picking up leases ahead of our drilling opportunities at this point. The majority of the land grab has ended in that play. We're doing a lot of strategic leasing now, focusing on the volatile oil window, which is where the focus of our leasing will be. We still need to get our seismic shots up there first, but ultimately, like any basin, you start in areas where you have the most data. That certainly is the volatile oil window for us. We will develop those wells there, and as Keith alluded to, we're making good progress on identifying the correct spacing across our enormous footprint of almost 500,000 acres. Once we collect more data and better understand the reservoir, we can begin stepping out into other areas.

And the next question will come from Doug Leggate with Wolfe Research.

This is John Abbott on for Doug Leggate. Ezra, as your scale is getting more significant, it appears to be getting harder to move the needle on the value of the resource. You have about 27 years of inventory. The dividend seems to become a more critical part of market recognition and value. So our question is, how do you think about the evolution of the dividend, the dividend growth rate, and the dividend breakeven?

Yes, John, thanks for joining the call. It's good to hear from you. We are 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. That’s what we focus on, and we feel is the foundation of our cash return strategy. We raised our regular dividend by 7% last year. We've raised our regular dividend 2x the average as a compound annual growth rate since 2019. We've got 27 years of sustainable growing regular dividends. We grow it in concert with expanding margins. This means both growing top-line revenue and cash flow from operations while lowering the cost basis of the company. We also align this with a strong balance sheet as a backstop on that regular dividend. We agree with you, John. We want to see the dividend increasing and the yield decreasing.

Appreciate it. For my second question, on cash taxes. At least for us, it was a little difficult hearing in the beginning when Ann was speaking. Could you talk about the AMT? Our impression was that you were already a full cash taxpayer. Is that correct? Could you discuss a little bit more detail on your cash tax outlook?

Absolutely. This is Ann. Thanks for the question, John. Our current tax revision 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. As a result, when you're looking at current tax increases, you’re going to see about a 15% increase in current taxes moving into 2025. Our 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.

Yes. 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 in the high-return multi-basin portfolio is how EOG continues to improve. It allows us to lower our breakevens as we add lower-cost reserves and ultimately enables us to optimize both near-term 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 has now concluded. Thank you for attending today's presentation. You may now disconnect.