EOG Resources (EOG) Q4 2025 Earnings Transcript

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Date

Wednesday, Feb. 25, 2026 at 10:00 a.m. ET

Call participants

• Chief Executive Officer — Ezra Y. Yacob
• Chief Financial Officer — Ann D. Janssen
• Chief Operating Officer — Jeffrey R. Leitzell
• Executive Vice President, Exploration and Production — Keith P. Trasko

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Takeaways

• Free cash flow -- $4.7 billion in 2025, sustaining the company's multi-year track record and driving direct shareholder returns.
• Adjusted net income -- $5.5 billion, or $10.16 per share for 2025, with adjusted earnings per share of $2.27 for the fourth quarter.
• Cash returns to shareholders -- $4.7 billion in 2025, consisting of $2.2 billion in dividends (8% growth over 2024, $3.95 per share) and $2.5 billion in share repurchases; 8.2% of market cap returned.
• Well cost reduction -- 7% decrease in 2025, achieved through operational efficiencies and extended lateral lengths across key basins.
• Return on capital employed (ROCE) -- 19% for 2025, with a three-year average of 24%.
• Proved reserves -- Increased by 16% to 5.5 billion barrels of oil equivalent; net proved reserve additions replaced 254% of total 2025 production (excluding price revisions).
• Delaware Basin performance -- Well costs are at or below $725 per foot with 30% longer laterals and 20% cost reduction from 2023 to 2025; capital efficiency improved 4% over same period.
• Utica operational gains -- Drilling speed increased by over 35%, completed feet per day up more than 10%, casing cost down 30%, on-site facility cost reduced 20%. Well cost dropped below $600 per foot by year-end 2025.
• Dorado asset -- Exited 2025 at 750 million cubic feet per day gross production, targeting 1 Bcf per day by end of 2026; well cost cut to $750 per foot, breakeven price $1.40 per Mcf.
• 2026 guidance -- Planned capital spending at $6.5 billion, targeting 5% oil production growth and 13% total production growth; expected free cash flow of $4.5 billion at strip pricing.
• Maintenance capital -- Updated range is $4.8 billion to $5.4 billion (midpoint $5.1 billion) required to hold production flat for three years post-Encino integration.
• Cash position and liquidity -- 2025 year-end cash of $3.4 billion, long-term debt of $7.9 billion, and $6.4 billion in total liquidity including a fully undrawn $3.0 billion revolver.
• Share repurchase authorization -- $3.3 billion remaining under current program, supporting ongoing buybacks.
• International expansion -- Entered new exploration in UAE and Bahrain, with initial well results anticipated in the second quarter of 2026.
• Three-year scenario -- Projected $10 billion to $18 billion cumulative free cash flow (2026-2028), 5% cash flow and greater than 6% free cash flow compound annual growth rates using $55 to $70 WTI assumptions.
• Gulf Coast gas/LNG exposure -- Q1 2026 LNG-linked exposure increased by 140 MMBtu/d, totaling 280 MMBtu/d linked to JKM/Henry Hub, plus 300,000 MMBtu/d Henry Hub-linked, with an additional 140 MMBtu/d (JKM/Henry Hub) expected in 2026 and 180 MMBtu/d (Brent/Gulf Coast-linked) in 2027.
• 2025 well performance -- Portfolio lateral lengths increased 18% year over year, with nearly 30% gain over three years; sustainable 13% uplift in Dorado productivity per foot in 2025.

Summary

EOG Resources (NYSE:EOG) delivered a year characterized by disciplined capital allocation, record free cash flow, and material well cost reductions, all directly supporting shareholder returns and margin improvement. Strategic moves included integrating the Encino acquisition ahead of schedule, significantly expanding international exploration, and bringing major infrastructure—such as the Janus gas plant—online to support portfolio efficiency. Reserve replacement was notable at 254% (excluding price effects), and capital efficiency gains were attributed to longer laterals and proprietary drilling technologies. For 2026, the company projects $4.5 billion in free cash flow and 5% oil production growth while maintaining a low $50 WTI breakeven for the capital plan and regular dividend. Management cited deep high-return inventory and maintenance capital needs of $4.8 billion to $5.4 billion as giving EOG Resources a multiyear runway for returns and reiterated a commitment to 90%-100% free cash flow returns to shareholders.

• The company expects capital discipline to maintain oil production at late-2025 levels in the Delaware Basin, with planned expansion in Utica and Dorado supporting broader portfolio growth.
• Efficiency gains such as proprietary drilling motors and production optimizers reduced lease operating expense (LOE), improved overall cost structure, and underpinned double-digit capital returns.
• Management indicated that approximately 45% of 2026 well costs are locked in, allowing capture of future market softening in service costs.
• Self-sourced in-basin sand in Ohio and expanded automation in Utica are expected to drive further cost reductions and operational efficiencies.
• Ongoing investment in Gulf States (UAE and Bahrain) remains exploratory, with limited near-term production impact but potential long-term upside should commerciality be achieved.
• Diversification into LNG markets provides flexibility for gas marketing and enhances the monetization options as global demand and U.S. electricity demand rise.

Industry glossary

• LOE (Lease Operating Expense): Direct costs incurred to operate and maintain oil and gas wells and related equipment after initial drilling and completion.
• JKM: Japan Korea Marker; benchmark Asian liquefied natural gas (LNG) spot price.
• Bcf: Billion cubic feet, a volumetric measure used for large quantities of natural gas.
• MMBtu: One million British thermal units; standard energy measurement for natural gas deliveries and pricing.
• GP&T: Gathering, processing, and transportation, representing midstream costs borne by the producer.

Full Conference Call Transcript

Ezra Y. Yacob: Thanks, Pearce. Good morning and thank you for joining us. 2025 was a remarkable year for EOG Resources, Inc. Overall, our year was characterized by disciplined capital allocation, strong execution across our operations, and robust free cash flow generation. We did not just meet the targets set forth in our operational and capital plan, we exceeded them while expanding our business both domestically and internationally, laying a foundation for the future. We surpassed our original oil and total volume targets while delivering in-line capital expenditures. We continued driving down well costs through sustainable operating efficiency gains, and our differentiated marketing strategy delivered peer-leading U.S. price realizations. Combined with lower cash operating costs, we helped strengthen margins.

Beyond extending our track record for excellent operational execution, 2025 was transformational. We completed the strategic Encino acquisition, entered exciting international exploration opportunities in the UAE and Bahrain, and brought online the Janus gas processing plant in the Delaware Basin. We also continued leading on sustainability, publishing new emissions targets after achieving our prior targets ahead of schedule. Each of these developments fundamentally improves our business and better positions EOG Resources, Inc. going forward as being among the highest return and lowest cost producers with strong environmental performance. Operational excellence in 2025 drove outstanding financial results and top-tier cash returns to shareholders.

We generated $4.7 billion in free cash flow and returned 100% to shareholders through our regular dividend, which increased by 8%, and $2.5 billion in share repurchases. To put our 2025 financial performance in a broader perspective, EOG Resources, Inc. has generated annual free cash flow every year since 2016. We have never cut nor suspended our dividend in 28 years. Further, over the past three years, we have generated $15 billion in free cash flow and returned $14 billion to shareholders, generating an average 24% return on capital employed. We have done this all while maintaining a pristine balance sheet.

This is not luck, it is the result of consistent execution of our resilient business model, and represents a fundamental differentiator versus peers. And we expect more of the same in 2026. Modest oil production growth as we maintain capital discipline, further integration and optimization of the Encino acquisition, and continued natural gas growth into emerging North American demand. Looking ahead, we have a disciplined plan for 2026. Our strategy prioritizes activity in the Delaware Basin, the Utica, and the Eagle Ford, while increasing activity in Dorado alongside continued international investment.

Our Utica asset provides a compelling opportunity for value creation as we continue to identify additional upside from the Encino acquisition as well as advancing our technical understanding of the play. And in the Delaware Basin, after adjusting our development strategy in 2025, we expect consistent well performance year over year. At guidance midpoints, our 2026 plan is expected to generate approximately $4.5 billion in free cash flow using strip pricing, delivering growth, exploration, a competitive regular dividend, and excess cash returns. Our breakeven price to cover the 2026 capital program and regular dividend is $50 WTI.

Overall, the 2026 capital program balances both short and long-term free cash flow generation while supporting future growth and maintaining our pristine balance sheet. Our 2026 plan is contemplated in our updated three-year scenario. The scenario reflects modest oil production growth aligned with current macro expectations. It maintains our current cost structure despite our persistent track record of driving costs lower through efficiency gains. Finally, the scenario is underpinned by our deep inventory of high-return assets across our multi-basin portfolio.

Using WTI price ranges of $55 to $70 per barrel from 2026 through 2028, the updated three-year scenario delivers 5% cash flow and greater than 6% free cash flow compound annual growth rates, generating cumulative free cash flow of $10 billion to $18 billion and earning robust double-digit returns on capital employed. This updated three-year scenario demonstrates how EOG Resources, Inc.'s relentless focus on returns, our diverse multi-basin portfolio, and industry-leading exploration capabilities provide clear visibility to sustain high returns and durable free cash flow generation for years to come. Overall, the three-year scenario delivers approximately 20% higher free cash flow in 2026 through 2028 than the actual results for the prior three-year period assuming the same price deck.

On commodity fundamentals, we expect total crude and product inventories to continue building over the next few quarters. However, increasing global demand, geopolitical factors, and stockpiling of petroleum reserves are providing price support. Beyond near-term dynamics, we remain constructive on medium to long-term oil prices being driven by steady demand growth and the need for additional supply. Importantly, global spare capacity is declining, which should provide an oil price floor while geopolitical events will continue to drive upside price volatility. On natural gas, our outlook remains positive. U.S. natural gas enjoys two structural bullish drivers: record LNG feed gas demand and growing electricity demand.

We expect U.S. gas demand to grow at a 3% to 5% compound annual growth rate through the end of this decade. We are investing in building a premier gas business, positioning EOG Resources, Inc. to deliver supply into these expanding markets. We believe our premium gas business is an underappreciated asset, providing exposure to growing demand and with access to premium markets from geographically diverse sources. EOG Resources, Inc.'s value proposition is clear. We are guided by our strategic priorities: capital discipline, operational excellence, sustainability, and culture. Our 2025 results demonstrate consistent execution across our premier multi-basin portfolio, while our cash return performance reflects our unwavering commitment to disciplined value creation through the cycles.

EOG Resources, Inc. is better positioned than ever to execute on our value proposition and create shareholder value. Now here is Ann with a detailed review of our financial performance.

Ann D. Janssen: Thank you, Ezra. EOG Resources, Inc.'s financial strategy remains steadfast: invest capital in a disciplined manner, pay a sustainable and growing regular dividend, return significant cash to shareholders, and maintain a pristine balance sheet. The fourth quarter 2025 exemplifies this strategy in action. We generated adjusted earnings per share of $2.27 and adjusted cash flow from operations per share of $4.86, building free cash flow of nearly $1 billion. For 2025, EOG Resources, Inc. reported adjusted net income of $5.5 billion, or $10.16 per share, and free cash flow of $4.7 billion. For 2025, we delivered a 19% return on capital employed, maintaining our peer-leading ROCE. We continue to deliver on our commitment to return cash to shareholders.

During the fourth quarter, we returned $1.2 billion to shareholders, $550 million through our robust regular dividend and $675 million in share repurchases. For the full year, we paid $2.2 billion in regular dividends, or $3.95 per share, representing an 8% increase over 2024, and we repurchased $2.5 billion in shares. Our 2025 cash return was 8.2% of our market cap, which led our peers. With $3.3 billion remaining under our current share repurchase authorization, we have ample flexibility for additional opportunistic buybacks. In today's dynamic energy environment, share repurchases are especially compelling. We expect to remain active on share buybacks, continuing to enhance returns through the cycles. Our peer-leading balance sheet provides an outstanding competitive advantage.

We ended 2025 with $3.4 billion in cash and $7.9 billion in long-term debt. Combined with our undrawn $3.0 billion revolver, total liquidity stands at approximately $6.4 billion. Our leverage target of total debt at less than one time EBITDA at bottom cycle prices remains among the most stringent in the energy sector, providing both downside protection and the flexibility to invest strategically through cycles. Finally, we increased proved reserves by 16% to 5.5 billion barrels of oil equivalent, continuing our long track record of reserve growth. Net proved reserve additions from all sources, excluding price revisions, replaced 254% of 2025 total production. Turning to 2026, we expect capital spending of $6.5 billion at the midpoint of guidance.

At current strip prices and using guidance midpoints, this plan generates $4.5 billion in free cash flow. In the current environment, we anticipate returning 90% to 100% of annual free cash flow to shareholders, consistent with recent years. In summary, EOG Resources, Inc. delivered another outstanding year. We strengthened our portfolio, maintained a pristine balance sheet, and positioned the company for sustainable value creation through commodity cycles. With that, I will turn it over to Jeff for our operating results.

Jeffrey R. Leitzell: Thanks, Ann. I want to start by recognizing the exceptional dedication of the entire EOG Resources, Inc. team. Consistent, safe, and outstanding execution is what converts operational strength into shareholder value, and 2025 demonstrated that. Our teams met or exceeded expectations on nearly every operational metric. Production volumes outperformed guidance, driven largely by stronger performance in our foundational plays, while our disciplined capital investment remained in line with expectations, delivering strong free cash flow. Let me highlight several accomplishments throughout 2025 that have helped position EOG Resources, Inc. for long-term success. First, we made significant strides in lateral length optimization.

Longer laterals mean fewer vertical wellbores to drill and more productive time both on surface and downhole, reducing surface footprint and improving capital efficiency. In addition, EOG Resources, Inc.'s internal drilling motor acts as a force multiplier on these longer laterals, improving downhole drilling performance and giving us the confidence to continue extending laterals across our portfolio. We are focused on drilling 2- to 3-mile laterals in the Delaware Basin and 3- to 4-mile laterals in the Utica and Eagle Ford plays. Second, extended laterals and sustainable efficiency improvements led to well cost reductions of 7% in 2025.

Our focus on sustainable efficiency gains for drilling and completion operations creates meaningful value because they compound over time, leading to significant cost savings through the development of an asset. And third, cash operating costs came in under target, led by a meaningful reduction in LOE due in part to our proprietary production optimizers program, which leverages machine learning to optimize base production, delivering better run time and lower cost across the portfolio. Looking ahead, 2026 is positioned to be an outstanding year for EOG Resources, Inc. as we build on the strong momentum established in 2025.

Given the macro environment, we are keeping oil production flat with fourth quarter 2025 levels, which results in annual oil production growth of 5% and total production growth of 13%. We can deliver this disciplined plan for a capital budget of $6.5 billion. Throughout the year, we plan to complete 585 net wells across our multi-basin portfolio of high-return inventory, with the majority of the capital being allocated to our foundational assets: the Delaware Basin, Utica, Eagle Ford, and our newest foundational asset, Dorado. We will also continue investment across our international portfolio.

Capital cadence and activity should be relatively consistent through the year, with a roughly even capital split between the first and second half and activity averaging approximately 24 rigs and 10 completion crews. Looking at the service cost environment, despite lower industry activity in 2025, we are seeing a relatively stable market for high-spec equipment with minimal cost reduction. Support services have shown some softening and we will continue monitoring the market for savings opportunities through 2026. We have locked in approximately 45% of our total well costs this year, giving us flexibility to capture any additional market softening. For 2026, we are targeting a low single-digit reduction in well costs driven by sustainable efficiency gains.

In the Delaware, our team has consistently delivered innovations, including our EOG motor program, Super Zipper operations, high-intensity completions, and production optimizers. From 2023 to 2025, we increased lateral lengths by nearly 30% while reducing well cost by approximately 20%. We have also strategically invested in infrastructure, including facilities, gathering systems, water transfer stations, and the Janus gas processing plant, all of which deliver lower operating costs that complement our well cost reductions. Over the past few years, we have fundamentally improved the cost structure of our Delaware Basin assets. Because of this, our development program now includes additional zones that previously did not meet our stringent return hurdles.

While per-well productivity declined last year as we targeted these incremental opportunities, our economics did not. Our 2025 Delaware program continues to deliver over 100% direct after-tax returns at $55 WTI while improving capital efficiency by 4%. For 2026, we expect consistent year-over-year well productivity and strong economic performance while averaging 13 rigs and four completion crews in the Delaware. In the Utica, the Encino integration is ahead of schedule, has exceeded expectations, and remains a significant focus for 2026. We achieved our $150 million synergy target ahead of our original one-year timeline from close, and we continue capturing additional synergy opportunities. We have achieved several operational wins with the Encino asset since closing the acquisition in August.

We have increased the drilled feet per day by over 35%. EOG Resources, Inc.'s scale and purchasing power has reduced casing cost over 30%. We have increased the completed feet per day over 10%, and our team has reduced on-site facility costs by 20%. These achievements have helped us to reduce our well cost below $600 a foot by year-end 2025. In addition, we are planning to have in-basin self-sourced sand in Ohio by the end of the year, which should further reduce completion costs. For 2026, we expect to run three rigs and three completion crews, completing 85 net wells.

Our foundational Utica asset is positioned for continued improvement as we build upon the significant cost reductions achieved over the past few years. In the Eagle Ford, efficiency gains continue to improve economics. From 2023 to 2025, we increased drilled feet per day by 5% while boosting completed lateral feet per day by 30%, driving a 15% reduction in well cost. Last year, we extended lateral lengths, highlighted by the record 24,000-foot lateral on the Whistler E5H. For 2026, we expect to run four rigs and one completion crew, completing 115 net wells, continuing to leverage technology and efficiency gains.

Turning to Dorado, we have made outstanding progress over the past few years and now have transitioned this world-class gas asset to our newest foundational asset. To be a foundational asset, the play must meet or exceed our high return hurdle, have significant running room, have a consistent level of activity which supports a full-time completions crew, and generate free cash flow. Dorado will meet these criteria this year and will stand beside our other foundational assets, the Delaware Basin, Utica, and Eagle Ford. In 2025, we met our exit gross production target of 750 million cubic feet per day and are targeting an exit rate of 1 Bcf per day gross production in 2026.

We significantly lowered well cost to approximately $750 per foot through operational efficiencies. From 2023 to 2025, we increased drilled feet per day by 30% and completed lateral feet per day by 20%. With a low breakeven price of $1.40 per Mcf, Dorado is exceptionally well positioned to serve our growing LNG gas supply contracts and Gulf Coast gas demand. We will run two rigs there this year and one completion crew which will complete 40 net wells. Our Gulf States exploration programs are moving forward, and the teams are making exciting progress. We commenced operations in Bahrain and the UAE in 2025 and will continue to test and delineate these plays throughout 2026.

We anticipate having initial well results in the second quarter of this year. These opportunities leverage our technical expertise and extensive data set from thousands of unconventional wells across diverse plays, prime examples of EOG Resources, Inc.'s commitment to organically expanding inventory through exploration. In closing, our 2025 performance demonstrates the strength of our multi-basin portfolio and operational excellence. As we execute our 2026 program, we are confident in our ability to deliver consistent results, maintain capital discipline, and generate strong returns for shareholders across all commodity price environments. With that, I will turn it back to Ezra.

Ezra Y. Yacob: Thanks, Jeff. As we close, I want to highlight why EOG Resources, Inc. represents a compelling investment opportunity and how we are positioned to deliver sustained shareholder value. First, our asset base differentiates EOG Resources, Inc. versus peers. With approximately 12 billion barrels of equivalent of high-return, long-duration resources, we have diversified exposure across North American liquids, North American natural gas, and international conventional and unconventionals. This creates multiple pathways for value creation as each of these markets grows over the medium and long term. Second, our unconventional and exploration capabilities are a long-time hallmark of EOG Resources, Inc.

This core competency does not just unlock significant upside in our current inventory, it allows us to build future inventory in a low-cost, high-return manner. Third, we are a low-cost, efficient operator with deep technical expertise. Our relentless focus on innovation in drilling and completion techniques continues to drive our cost structure lower. This reflects our decentralized model that effectively creates a portfolio of pure-play companies that can leverage knowledge and expertise across the entire company. Fourth, our disciplined capital allocation framework drives superior financial performance, generates robust free cash flow, and delivers peer-leading returns on capital employed.

Finally, we remain committed to returning cash to shareholders through our regular dividend and opportunistic share buybacks, and our peer-leading balance sheet provides both protection and opportunity. We have the financial capacity and flexibility to invest opportunistically through any cycle. Thank you for your continued interest in EOG Resources, Inc. We will now open for questions.

Operator: Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, if you are using a speakerphone, please make sure your mute function is off. You are allowed one question and one follow-up. We will take as many questions as time permits. Our first question today is from Neil Singhvi Mehta with Goldman Sachs. Please go ahead.

Neil Singhvi Mehta: Good morning, Ezra and team. Thanks for taking the time. Ezra, I want to start off on the composition of the wells this year and the activity. And year over year, there is a slowdown in the Delaware. I think you are going from 390 to closer to 300 in terms of wells that you are going to attack. And it looks like you are picking up in the Utica. Could you just talk a little bit about the composition? How do you think about the optimal level of activity in the Permian in particular, and the composition of activity over the course of the year?

Ezra Y. Yacob: Yes, Neil, this is Ezra. Good morning. It is a great question. This year, the plan really takes a step towards optimizing investment across our high-return foundational plays. As you recall, we are really seeing pretty similar returns across all of our foundational plays now. Specific to the Delaware Basin, the activity level really optimizes utilization of existing infrastructure across our acreage position, and that really helps support better capital efficiency. We expect consistent Delaware Basin performance going forward. As Jeff talked about, our strategic shift in development strategy in 2025 has been an outgrowth of our dramatic cost savings the last few years combined with investment in that infrastructure to help lower operating costs.

The cost savings have allowed us to capture some of these additional landing zones that exceed our economic hurdle rates, so we are now actively co-developing many of these targets. Some of the targets have lower productivity per foot, some have different GORs, but each, as Jeff highlighted, is delivering the high returns that our shareholders have come to expect. And we expect the consistent well results you have seen quarter over quarter throughout 2025 to really continue through 2026 and really through the entire three-year scenario that highlights the strong returns and increasing free cash flow going forward.

So, at this year's activity levels in the Delaware Basin, we expect to deliver relatively flat production to Q4 2025 similar to the company level, maybe I think it is 3,000 to 5,000 barrels a day less due to really outperformance in the fourth quarter there in 2025 by the Delaware Basin asset. And really, I think the big takeaway is that at this level of activity in the Delaware Basin, we are confident we can maintain similar returns and free cash flows longer than 10 years. And it really comes back to the deep inventory of high-return assets we have across multiple basins, Neil.

Neil Singhvi Mehta: Yes, and appreciate that. Maybe that is a good follow-up where you can address the Delaware question. It is something we get a lot from investors who look at some of the well results and are concerned that there is degradation in terms of quality of inventory and those well results, and I think you guys have a perspective on that. How do you address that case that has been out there?

Jeffrey R. Leitzell: Yes, Neil, this is Jeff. Really, like we have talked about in the past, I will give you a little bit of details. It just has to do with all the progression we have made there. As we have said, there is not just one variable that goes into economics. It is not just production. Ultimately, you have to focus on rolling everything up to make sure you are maximizing returns, and that is what we are doing. So in the Delaware, just taking a look over the last three years, we have extended our laterals 30%. We have lowered the cost there by 20%, which has ultimately improved the capital efficiency by 4%.

So when you take all that and you roll it up, our cost right now is at or below $725 a foot. And because of this, we have talked about being able to unlock those additional targets up through the strat column, and they meet our return hurdles now at bottom cycle pricing and deliver payouts much less than 12 months at current pricing. The other thing it also does is it really improves the overall recovery per acre and it maximizes the NPV per acre across the asset, which is really what we are looking for. And so, by design, we are obviously seeing a little bit lower productivity on those targets but not lower economics.

They are matching any other target that we have, and they actually meet that hurdle. And now that we have fully implemented that new development approach, as Ezra said, we are not seeing any major changes in productivity. It should be relatively consistent moving forward from here. So, we are extremely excited about how the Delaware program has progressed and how our team has unlocked all this additional value there through the cost reductions. As Ezra said, we have set it up for an extremely successful year and many years to come. So thanks.

Operator: The next question is from Stephen I. Richardson with Evercore. Please go ahead.

Stephen I. Richardson: Hi, morning. Thanks for the time. I appreciate the update on Dorado and appreciate that the team has worked so hard to move it towards foundational. I was wondering if we could just talk about how you thought about increasing activity there versus some of your oilier basins. I appreciate the $1.40 breakeven, but just how do you think about the gas macro and how this play kind of fits into that? And I was wondering, as a follow-on to that, if you could kind of address how your LNG take contracts are going to change in 2026 and 2027?

Ezra Y. Yacob: Yes, Steve. Good morning. This is Ezra. Listen, I appreciate the question about Dorado. As we have highlighted on Slide 18, we have had a fantastic couple of years. We have dropped our well cost down to $750 per foot, drilled feet per day by 30%, completed feet per day by 20%, and so it has really dropped our breakeven down to about $1.40 per Mcf, and that includes F&D, LOE, GP&T, G&A, and production tax. So, we are still highly confident that Dorado is the lowest cost gas supply in the U.S. with exceptional geographic location with its proximity to the Gulf Coast and premium markets.

I think Jeff has talked about that we exited 2025 at about 750 million cubic feet per day, and we plan to exit 2026 at about 1 Bcf a day gross. Our cultural and measured pace of investment, Steve, continues along our approach to each of our plays. We are investing in it with two things. One, to make sure we do not outrun our pace of learnings so we can continue to drive down the costs.

But the second thing is, associated with any of our plays, but especially here in Dorado being a gas play, we really are growing into not only the emerging North American natural gas demand that we see, but really some of the contracts that we have. As you brought up with our LNG, now we can supply many of our contracts from multiple basins. Specifically, as of Q1, we have actually increased our exposure to LNG by 140 MMBtu per day. So that is on top of the preexisting 140 MMBtu per day that is linked to JKM or Henry Hub.

We also have another 300,000 MMBtu per day that has already been going to LNG that is linked to the Henry Hub. And so that leaves us one additional tranche of 140 MMBtu per day that we anticipate coming on later this year and will be linked again to JKM or Henry Hub. As we move into 2027, we have an additional contract, as you know, that is linked to Brent or U.S. Gulf Coast gas for a total of 180 MMBtu per day. Again, when we think about the first part of your question, Steve, how does Dorado compete for capital versus the liquids plays?

That is one of the strengths of being a multi-basin company and having dedicated North American liquids plays and dedicated North American natural gas plays. We do not really see them competing against each other. They are really able to service different parts of the market. And what we see overall in the U.S. natural gas demand, much of it is coming from these longer-cycle projects. Certainly, there is an increase in U.S. electricity demand. When we think about data centers behind the meter or LNG, oftentimes when you sit across the table negotiating with the other stakeholders, they are really looking for the confidence in 10-, 15-, 20-year, multi-decade type of contracts.

And that is really the strength of having a dedicated North American natural gas play as opposed to associated gas.

Stephen I. Richardson: Really helpful. Great progress there and congrats to the team in Corpus. I was wondering, just a follow-up. The second year in a row that you have run more than 100% of free cash in terms of the buyback, or sorry, in terms of cash returns to shareholders. Can you maybe just talk about that? The target is unchanged, but you have had a, you know, we would probably say a pretty squishy commodity price environment, but you have been able to do that and bolt on a pretty significant acquisition. So how do you think about that going forward? Is this just best use of cash as cash comes in?

And, you know, just remind us, you know, how does your view of value of the stock or relative performance, or how do you kind of all think about that buyback lever, which seems like you really like at the current time?

Ann D. Janssen: Hi, Steve. Good morning. This is Ann. To address the free cash flow, of course, we are looking at the best ways to create value for the shareholders, and our pristine balance sheet places us in an excellent position to reward shareholders with robust returns of free cash flow. We have demonstrated, as you said, a commitment to return significant cash to our shareholders. We do expect this to continue as we really do not see a need to build cash on the balance sheet. The current environment, as you noted, is dynamic and could provide the opportunity to return cash at similar levels as we have over the past few years.

We start our cash return anchored by our sustainable, growing regular dividend, then we will supplement that by share repurchases and/or special dividends. And recently, we have had a focus on the opportunistic buybacks as a primary mode of additional cash return. In the current environment, we are very comfortable returning that 90% to 100% of annual free cash flow that I outlined, and that is similar to what we have done over the past few years. Our focus just continues to invest our dollars to create long-term value for our shareholders.

Operator: Next question is from Doug Leggate with Wolfe Research. Please go ahead.

Doug Leggate: Good morning, everybody. Ezra, I think you may have partially answered this, but this is the first time you have given the new free cash flow visibility post Encino. Obviously, you have got a $6.5 billion capital budget. There is a lot in there that is not maintenance capital, but you have also, you know, put a $50 breakeven on this. Where I am going with this is, if I heard you right, did you say that on a sustaining basis, do you think you can hold your free cash flow flat for 10 years or sustainable for 10 years?

I do not want to put words in your mouth, but if I take the $6 billion high end at $70 oil, that gets you to about two-thirds of your market cap, in other words, it is not enough. So can you just clarify what you were meaning there? And I have got a follow-up, please.

Ezra Y. Yacob: Yes, Doug. This is Ezra. Good morning. Yes, my comments earlier were specific to the Delaware Basin. I am sorry, I think that is where the disconnect is. The Delaware Basin. That is correct. Yes, and so really what we have seen with the three-year plan, the three-year scenario quite frankly, is that, you know, the high-level takeaway, like I said, is comparing the past three years with the forward-looking three years at a similar price deck, we have actually increased the free cash flow potential there by 20%.

And even with low single-digit oil growth and modeling a mid single-digit kind of total production growth, we are seeing 6%+ compound annual growth rate of that free cash flow year over year.

Doug Leggate: So just my follow-up, I mean, just a clarification. So when you look at your sustaining capital, what do you think that level is for the post Encino portfolio and what do you believe the duration of that is post the three years? I mean, are we talking about 20 years of inventory? 20 years of sustainable free cash flow? How do you define it? And I will leave it there. Thanks.

Ezra Y. Yacob: Yes, so there are kind of two different questions in there. Maybe I will address the first one as far as the inventory life, and I will let Jeff maybe follow up with the details on our maintenance capital number post Encino. So, Doug, when we think about the resource potential, the deep inventory of high-return assets that we have captured that I talked about, Slide 8 in our inventory in our deck is probably one of the best ways to look at it. And we presented that 12 billion barrels in a way that it is two different things on that slide.

You can think of it as kind of a good old-fashioned R over P, which that 12 billion barrels, to your point, speaks to close to 20 years worth of production. And then you can also see on that, and you are welcome to apply any type of risk to that as you deem necessary, but the other thing you will notice on that slide is the returns as a proxy to free cash flow. And you can see that 12 billion barrels essentially generates greater than 55% return at $45 and $2.50, greater than 100% rate of return at $55 and $3 gas.

And so what I would point out is as we develop a program every single year, it is not that we are force-ranking our rates of return inventory and drilling the highest 400 or 500 wells first. There is always a mix in there, which is why we present our inventory as kind of a kitchen sink effect on that rate of return, because at different times you are obviously drilling in different parts of the basins, you are trying to maximize infrastructure, you are trying to limit your indirects, so that is really the best way to look at it.

I would say that we have great confidence being able to deliver similar free cash flow, similar returns at the company level, for many, many years to come based on that deep inventory of 12 billion barrels of equivalents. And then, Jeff, with the maintenance capital maybe?

Jeffrey R. Leitzell: Good morning, Doug. Yes, this is Jeff. Yes, you are correct. It has been a handful of years since we have updated that maintenance capital. And with it updated, its current range right now is from $4.8 billion to $5.4 billion, so midpoint around $5.1 billion. And really what this range represents is the capital required to hold production flat for a period of three years, and it also assumes our current well costs right now. And that is consistent with our updated three-year scenario. The other thing I would say is the big changes that have really happened since the last update, as you hit on, obviously, the Encino acquisition we built into that.

There is the increase in production of the base business since the time of the previous disclosure. And also there is the impact of the improvement across our portfolio since the time of the previous disclosure. And then lastly, I would just note that this maintenance capital really reflects a modest improvement in our base decline, which is now below 30% for oil and below 20% for BOE.

Operator: The next question is from Scott Michael Hanold with RBC Capital. Please go ahead.

Scott Michael Hanold: Yes, thanks. I was wondering if we could go back to Permian productivity. It seems like it has been a bit of a headwind for EOG Resources, Inc. share price, and I appreciate the context you guys have provided on those, we will call it, secondary zones. It is something, you know, other peers are talking more about that and surfactants and other things. And, you know, I am not, I do not want to lead your answer, but do you think some of the relative performance that people are being concerned about is because you all have been able to move faster to these secondary zones than peers?

And if you could give us a sense of, on some of the primary kind of activity that you have done, is the productivity over the last few years fairly static?

Ezra Y. Yacob: Yes, Scott. This is Ezra. Thanks for the question. Yes, over the primary targets, I would say we are seeing relatively consistent performance there. Of course, it is difficult to compare because even if you think about, say, an Upper Wolfcamp or a Wolfcamp A, you end up having multiple landing zones in there.

So do not forget, we are a pretty technical bunch here, and so we look at the permeability, is it a little bit siltier, is it more of a mud rock, and those are the types of things that with just a little bit of savings on your cost side, all of a sudden, those targets really become more economic than what you had previously counted them on. So what I would say is, like for like, we are seeing pretty consistent well results in there. As far as pushback, I think from the peers, you know, I do not want to speak to the peers.

What I would say, what I think is going on with us, is that we made this shift. I think we figured that we had pretty well highlighted this and externally talked about adding nine additional landing zones over the last few years. But in hindsight, Scott, I think we probably could have done a better job highlighting our change in development strategy heading into 2025, again, off of the really extreme cost reductions that we saw coming off of the relative highs there in 2023.

Scott Michael Hanold: Appreciate the context. And, you know, as my follow-up, you know, if we can move to natural gas, and you all have increased exposure to pricing on the water with some of your LNG contracts. Could you give a sense of other things that you all may be working on or considering, supply decrements, industrial users, or power data center users?

Ezra Y. Yacob: Yes, Scott. This is Ezra again. It is a good question. We have spent time looking at really how data center development may progress and what role EOG Resources, Inc. might play in it. I think there are a couple of different ways where we can benefit today and potentially benefit in the future. The diverse marketing strategy gives us exposure to regional pricing uplift associated with increased electrical demand in areas of data center development. Obviously, we have seen U.S. electricity demand grow last year just shy of about 2%. Electricity prices obviously grew more than that, about 6.5%. I think going forward, U.S. electricity demand overall is forecast to grow between 1% and 3% compound annual growth rates.

So obviously, we can benefit from our diverse exposure across our basins from there. A good example also is the capacity that we capture along our Transco pipeline to deliver gas into that Southeast market, which is a big power pool demand center. But really, another way we think that EOG Resources, Inc. might be able to benefit much more directly, and we have had negotiations along this path, is if we begin seeing development of data centers closer to power generation or closer to natural gas fields. We see both, especially South Texas and Ohio, as having great potential to play a larger role in data center buildout.

Obviously, the position that we have in Dorado and the Utica would benefit from that regional demand. I think when you think about South Texas, especially Dorado, there is open space, there is water, you are far enough inland from any storm threats, there is a phenomenal amount of gas there, and there is also a good amount of fiber already in the ground. And right now, I would say it is still surprisingly early on with a lot of the data center conversations. You see a lot of the construction is somewhat delayed or getting pushed out to the right a little bit as people, again, I think, really try to wrap their minds around a multi-decade contract.

But that is where we think we have got a competitive advantage with Dorado, that we have got the gas supply, low-cost gas supply, to stand up and support one of those longer-term projects.

Operator: The next question is Derrick Whitfield with Texas Capital. Please go ahead.

Derrick Whitfield: Good morning, guys, and thanks for your time. Regarding your three-year outlook, I wanted to focus on the role international could play over that period and beyond that period. While onshore will undoubtedly carry the load in your financial performance, should we think about the increasing role international could play as we exit the three-year period?

Ezra Y. Yacob: Yes, Derrick. I appreciate the question on the three-year scenario. The scenario does include capital for the Gulf States exploration and development. Beyond the capital that is really tied to the 2026 plan, we are basically forecasting a slight increase in the activity in the Gulf States. The associated production assumption is really minor. And we are doing that in the three-year scenario because those plays are still in the exploration phase right now. We do assume success and declaration of commerciality, but in the time frame of the three-year scenario, I would say that the specifics to the international assets are relatively minor. Now, with regards to Trinidad, we have got a bit more line of sight.

Those are slightly longer-cycle projects, and we continue to have a pretty robust program there in Trinidad ongoing.

Derrick Whitfield: Great. And then with regard to UAE and what you know about the subsurface today, how does that compare versus some of the premium U.S. unconventional oil basins? And how should we think about your delineation plans for that area in 2026?

Keith P. Trasko: Good morning. This is Keith. Both in UAE and Bahrain, activity this year, we are going to continue our drilling program to evaluate those exploration concessions. We are expecting activity to be higher in the UAE than Bahrain just due to the relative size of the concessions. We are still in the early phases of that, so our plan for 2026 is a little bit dynamic. As Jeff mentioned, we expect to have production results in both countries in the second quarter of this year. So in Bahrain, we drilled our first few wells and we have started completing them.

And in the UAE, we drilled the first couple of wells, those went very smoothly, and we plan to begin completing them here shortly. So we are very excited about the opportunity that we see in both countries. Both areas have positive production results from prior horizontals. As far as delineation in 2026, we are just really working to refine our subsurface understanding, to build off of ADNOC and BAPCO's progress and positive momentum on cost reductions, and help bring even more of the latest unconventional technology to the region. We think that there is a lot of technology and similarities between many of our domestic plays that we could borrow and apply to either country.

Operator: The next question is from Charles Meade with Johnson Rice. Please go ahead.

Charles Meade: Yes. Good morning to the whole EOG Resources, Inc. team there. Jeff and Keith, maybe I will just pick up on that thread and ask about in UAE and Bahrain, less about the well results, but how you guys are going to communicate there. And, you know, I think that at least in the Lower 48, the EOG Resources, Inc. MO is kind of, you know, to quietly try something in a play, and then based on success or failure, either quietly exit or quietly build a position. But that does not really, you know, it does not seem to be an option to just, you know, quietly exit in Bahrain and in UAE.

And also at the same time, there are not the same competitive considerations there given the nature of these concessions. So can you, not looking to commit you to anything, but can you give a broad outline of how you guys plan to share results and what the consequent decisions to either ramp activity or curtail it would be?

Ezra Y. Yacob: Yes, Charles. This is Ezra. I will take a shot at that question. So it has been something that we have had to get used to, kind of our international strategy. And we saw this, the best thing to do I think maybe is to take a look back at what we did in Oman. Again, it is a little bit different from our domestic exploration portfolios or projects where we can usually be a little bit stealthy and keep things quiet until we get material results or a material position in a play and can really start to discuss it.

Typically, these days, internationally, when you sign an agreement, there happens to be a press release and things like that. So the first step is making sure that the agreement is something that checks the boxes for us for international, so that we have captured a sizable position, we have captured access to premium markets, of course, and we have been able to negotiate a contract to align the stakeholders and partner with folks that we think will be able to, if we have success, really have success and really have captured something that is going to be exceptionally competitive and additive to the corporate portfolio. Now, again, in Oman, you are right.

There is no state data, there is no public reporting. I thought we were fairly transparent with the results that we had in Oman. When we exited, we did not try to, you know, sneak out the back door. We just made it known to everybody that we had drilled the wells. As you recall, we made kind of an undeveloped discovery there, a natural gas discovery. We were really focused on oil because of the lack of infrastructure in the area. And so we did end up exiting. Bahrain and UAE, to be perfectly honest, will be, you know, very, very similar to that. Both of these international opportunities, we are currently in an exploration phase.

That lasts a certain amount of time, and then there will come a point where after we satisfy the terms of the exploration phase, there will be a decision on whether or not we go forward, casually called a declaration of commerciality, and that would then assign some sort of longer-term production license. And you can assume that would obviously be something public. That being said, at this point in the game, we feel very confident in all the plays. We are very excited about the size of the prize that we have in both the UAE with our unconventional oil play and the unconventional gas play in Bahrain.

Bahrain is onshore, so you can imagine it is a little bit, as Keith said, a little bit smaller in scope. But it is a gas play in a region where we see tremendous future gas demand. And so that probably is an area where we continue to look for the right partners. While we are very happy with what we have captured in the region, we would be interested in continuing to look for adding a potential additional gas project in the region under the right terms and with the right partners.

Operator: The next question is from Phillip J. Jungwirth with BMO. Please go ahead.

Phillip J. Jungwirth: Yes, thanks. Coming back to the multiyear scenario, recognizing it is not guidance, but the low single-digit oil growth is maybe a bit surprising since organic volumes have been flattish here since Liberation Day, and that is continuing into 2026. So could you help us understand how you would resume oil production growth? Which assets drive that? And just one of the qualifications in here is that it assumes current cost structure. So just wondering when you look back at 2023 through 2025 actuals, how much you actually outperformed here? And could you see similar runway over the next three years?

Ezra Y. Yacob: Phillip, this is Ezra. That is a great question. So using current cost is just for line of sight. I do think with our consistent track record of lowering costs, that is the best data point that we have. But if you want to build in a little bit of conservatism, I could understand. What I would point out is that we have made tremendous strides over the past three years in the Delaware Basin. Part of that was with our sustainable operational efficiency gains. Some of that too, though, was in 2023, which was relatively kind of a high industry high watermark for costs across the industry.

And then we made tremendous progress lowering well costs across our two emerging assets as well. And as you know, early in these assets, early in the play development, you have the opportunity to make greater strides there. As far as returning to low single-digit oil growth, outside of the Liberation Day announcements that caused, you know, really a little bit of concern on really the line of sight on what may happen with demand coupled with spare capacity reentering the market, we see that as a bit of an overhang for maybe the next couple of quarters. Certainly, there is a lot of commentary that the oil glut has been pushed to the right.

We are seeing that as well. What we are also seeing is that when you look at total product, inventories have raised right to roughly in line with the five-year average. There is some additional spare capacity that is scheduled to come back to the market. That being said, we continue to see global demand growing, relatively strong and consistent at roughly that 1.0 to 1.2 million barrels per day, roughly maybe right at 1%, a little bit less than 1% compound annual growth rate. That is really what gives us confidence. Now, where that growth would come from in forecasting growth of low single-digit oil?

In the three-year scenario, it contemplates a lot of growth out of the Utica, as a matter of fact. But quite frankly, we can grow from multiple basins if we needed to, if we wanted to. Really, the growth at the company level will be determined by optimizing across each of those basins the level of activity, the marketing agreements, where we have infrastructure, and things of that nature.

Phillip J. Jungwirth: Great. And then you beat the $150 million Encino synergies ahead of schedule. I think you gave yourselves a year here. So could you just talk to the drivers, positive surprises now that you have operated the asset for six months? And I assume you are not done here in terms of driving improvement. You mentioned in-basin sand. Anything else you are working on to enhance returns? And if you could also just touch on marketing initiatives here to improve netbacks?

Jeffrey R. Leitzell: Yes, Phillip, this is Jeff. Yes, as we have touched on in our opening remarks, obviously, we are extremely happy with how it has progressed with the synergies there. And you have heard kind of how much success we have had across the operational side with just drilling, completions, with our procurement side. Extremely happy, and we have driven that cost down to $600 a foot. In very short order, we really have only been developing there a handful of years. As I kind of look forward, I think there is a handful of things that we can really lean on. Full rollout of the EOG Resources, Inc. support services. I mean, you kind of touched on it there.

Once we implement self-sourced local sand, that is going to be a big initiative to really drive down costs. Also tying together a lot of our water and infrastructure and maximizing reuse in the area, that is going to be a pretty big driver that we can use our technology from around the rest of the portfolio. Also, it will take a little while, we are in process, but implementing additional automation across all of the acquired operations. We will be able to remotely manage and monitor wells and really take advantage of our 24-hour control room that monitors everything up there. And what that will do is really improve a lot of our efficiencies and reduce man-hour times.

And then lastly, as you talked about, continuing to focus really on utilizing the scale now of the asset to reduce the GP&T and work on the differentials. I think the big ways we are going to do that, as I stated, is first and foremost, we like to control in-field infrastructure and gathering. So we are going to focus on building that out, which should help bring our differentials down. And then, on the marketing agreements, obviously, just with the scale there, we have great relationships with the marketers.

We are in contact with them regularly and continuing to look for options to be able to either extend out agreements and optimize those agreements to be able to lower the fees just because we have so much more volume and scale up there. So I really think, you know, we are just kind of the tip of the iceberg. We have got a lot of upside in the play. We have still got upside in synergies. Our team continues to uncover, you know, opportunities every single week.

Operator: The next question is from Matthew Portillo with TPH. Please go ahead.

Matthew Portillo: Good morning all. Just a quick follow-up question on the Permian. Great to see in the remarks that you are expecting stable productivity trends for the basin this year and also to hold production flat in 2026 on an exit-to-exit standpoint. I was just curious if you could maybe help us out a little bit on that last point for the outlook. Looking into 2025, I think you completed about 390 wells in the basin and drove about 10,000 barrels a day of growth. And obviously, you have highlighted a big drop in the well count this year down to about 300 wells. So I think the maybe missing piece around this might be the lateral length progression.

So I was curious if you might be able to help us out on that front.

Jeffrey R. Leitzell: Yes, Matthew. This is Jeff. We have made great progress across our whole portfolio from a lateral length aspect, not just even in the Permian. So last year alone we increased our lateral length by 18% across the portfolio. And it really was driven by, as you are talking about, the momentum that we had with three-mile laterals there in the Delaware Basin. So we had a substantial increase there and focused on that. We extended our laterals in the Eagle Ford where, in certain areas that were stranded, we were able to drill numerous four-plus-mile laterals with, obviously, the record lateral that we had there on that Whistler E5H. Then the same thing in the Utica.

We have got a three-plus-mile full program basically there across the board that is really helping push. If you look at the Delaware Basin, it is basically fairly flat from 2025 to 2026. And the reason for that is just the huge jump that we had last year. But obviously, that has to do with a lot of our footprint and the leasehold that we have out there.

But our team is always going to look for opportunities to go ahead and continue to make trades, bolt on additional acreage, and extend those laterals wherever we can, because I think we have proven with our drilling technology, with the EOG Resources, Inc. motor program, and our approach, that we are able to drill those longer laterals with great success.

Matthew Portillo: Great. And then maybe just a follow-up on Dorado. Looking at the state data, I saw a really nice improvement in the productivity trends per foot in 2025. I was just curious if you might be able to comment on this improvement and what might be driving that. And then maybe a bigger picture question. With your exit rate approaching a Bcf a day of gross production in 2026, I know you have talked about compression potentially taking the Verde pipeline to 1.5 Bcf of egress.

But I am curious if there is a need down the road for potentially more pipeline capacity just given the economics of the assets and the improving productivity trends we are seeing out of the basin in aggregate?

Jeffrey R. Leitzell: Yes. Thanks for the question. We have been extremely excited with how Dorado has evolved down there and really it is kind of across the board from both drilling and completions and production, being able to increase the well performance there. So like everywhere else, we looked at our wellbore construction. We make sure that we are maximizing our high-intensity fracs and creating as much hydraulically created surface area downhole as possible with those things. And as stated, we are seeing about a 13% year-over-year increase, and that is a sustainable increase on a per-foot basis. So it is really a recovery increase, not just a lateral length increase. So extremely excited about that. We are continuing to work it.

And then on the second part of your question, yes, we have the EOG Resources, Inc. Verde Pipeline in service. As you talked about, it provides 1 Bcf of transport over to Agua Dulce, and it is expandable up to about 1.5 to 1.75 Bcf with very minimal investment in booster compression. And, you know, that provides us an uplift that is very attractive of about $0.50 to $0.60 per Mcf, and that is just due to the lower GP&T and obviously the higher netbacks that we have there. And with that, that will be able to, along with our other third parties, we will not need any other egress out of there.

We have got plenty of egress with that pipe right there. And as I said, we do not just necessarily transport all down that pipe. We do have other third parties that we can actually market to in that area. So we feel really comfortable for the long term there in Dorado with our takeaway.

Operator: This concludes our question and answer session. I would like to turn the conference back over to Ezra Y. Yacob for any closing remarks.

Ezra Y. Yacob: Yes, I would just like to say we appreciate everyone's time today. And thank you to our shareholders for your support and special thanks to our employees for delivering another exceptional quarter.

Operator: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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