Earnings Call Transcript - EOG Q2 2025

Operator, Operator

Good day, everyone, and welcome to EOG Resources Second Quarter 2025 Earnings Results Conference Call. As a reminder, this call is being recorded. For opening remarks and introductions, I will turn the call over to EOG Resources Vice President of Investor Relations, Mr. Pearce Hammond. Please go ahead, sir.

Pearce Wheless Hammond, Vice President, Investor Relations

Good morning, and thank you for joining us for the EOG Resources Second Quarter 2025 Earnings Conference Call. I'm Pearce Hammond, Vice President, Investor Relations. An updated investor presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations section of EOG's website. In addition, 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 Chief Executive Officer; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Chief Financial Officer; and Keith Trasko, Senior Vice President, Exploration and Production. Here's Ezra.

Ezra Y. Yacob, CEO

Thanks, Pearce. Good morning, and thank you for joining us. EOG delivered another quarter of outstanding results, reflecting the focused execution of our employees across our multi-basin portfolio. In the second quarter, oil, natural gas and NGL volumes came in above the midpoint of our guidance. At the same time, we drove our capital expenditures, cash operating costs and DD&A below guidance midpoints, demonstrating the efficiency and operational excellence that is a hallmark of EOG. Our teams continue to find ways to optimize operations, improve well performance and safely deliver volumes while maintaining capital discipline. Strong operational performance once again translated directly into impressive financial results. We generated nearly $1 billion of free cash flow during the quarter. And between our regular dividend and $600 million of opportunistic share repurchases, we returned more than $1.1 billion to our shareholders. Consistent with our long-standing cash return commitment, we have committed to return at least $3.5 billion in cash during 2025, inclusive of our regular dividend and nearly $1.4 billion of year-to-date share repurchases, reflecting our confidence in the growing value of our business. Our confidence in the future of the company is also reflected in the 5% increase in our regular dividend, which we announced in connection with the Encino acquisition in May. This marks another step forward in our remarkable dividend growth track record. Over the past decade, we have increased our regular dividend at a 19% compound annual growth rate, far outpacing the peer group average. More importantly, we have never cut nor suspended the dividend in 27 years. This sustained record of dividend growth highlights both the durability of our business and our unwavering focus on delivering shareholder value. Last week, we closed the accretive Encino acquisition, marking a major milestone for EOG. With a total core acreage position of 1.1 million net acres and associated resource potential net to the company of over 2 billion barrels of oil equivalent, the Utica has become a foundational EOG asset alongside the Delaware Basin and Eagle Ford. In aggregate, EOG has net resource potential totaling over 12 billion barrels of oil equivalent across our multi-basin portfolio. This top-tier resource base generates a greater than 55% average direct after-tax rate of return at bottom cycle prices and over 200% after-tax rate of return at mid-cycle prices, providing our investors one of the deepest and highest quality inventory positions. We are focused on the safe and rapid integration of the Encino assets into our portfolio. We remain highly confident in the value creation opportunity before us in the Utica and believe that through effective integration and the application of EOG's operating model and proprietary technology, the Utica will be a major contributor to both growth and returns. We look forward to sharing more as we capitalize on the advantages this transaction brings to shareholders. On the international front, in the second quarter, we were awarded an onshore concession to explore and appraise an approximately 900,000-acre unconventional oil exploration prospect in the UAE. We are very excited about this new opportunity that will allow us to leverage our technical expertise and extensive data set from drilling thousands of unconventional wells across a wide variety of plays. The UAE and our Bapco joint venture in Bahrain form an exciting long-term business opportunity for EOG in the Gulf States. Our results through the first half of 2025 serve as a powerful affirmation of EOG's enduring value proposition. We're committed to being among the highest return, lowest cost producers, recognized for leading environmental performance and a steadfast role in meeting the world's long-term energy needs. Four pillars underpin our differentiated strategy: capital discipline, operational excellence, sustainability and culture. As we look at new opportunities in our portfolio from the Encino acquisition to the expansion in the Gulf States, we believe operational excellence will be a key differentiator to enhance returns as we utilize our in-house technical expertise, proprietary information technology and self-sourced materials to drive superior well performance and reduce costs. Turning now to supply and demand fundamentals. While first quarter oil demand was stronger than forecast and second quarter oil demand also benefited from delays in the implementation of tariffs, growth in demand for the second half of 2025 is expected to moderate before beginning to increase throughout 2026. On the supply side, we expect spare capacity returning to the market to allow inventory levels to build from historically low levels. This reduction in spare capacity, coupled with current demand forecasts, paves the way for pricing to strengthen on the back of a more fundamentally driven market. On natural gas, 2025 is an inflection year driven by an uptick in U.S. LNG feed gas demand. We expect a 4% to 6% compound annual growth rate for U.S. natural gas demand through 2030, driven primarily by LNG and power demand. Our investment in Dorado to develop a stand-alone gas asset that complements our oil assets positions EOG to deliver supply into these growing markets. EOG is better positioned than ever before to create value for our shareholders. Our portfolio expansion, including Encino, the UAE, Bahrain and additional exploration opportunities, is adding significant new resource potential for our shareholders, while we simultaneously continue to improve and expand our existing resource through applying technology to reduce costs, improve well performance and unlock additional well locations. And at the same time, delivering robust cash returns to our shareholders and maintaining a pristine balance sheet, allowing for continued investment in high-return projects, generating strong current and future free cash flow. Now here's Ann with a detailed review of our financial performance.

Ann D. Janssen, CFO

Thanks, Ezra. We delivered another strong quarter with adjusted earnings per share of $2.32 and adjusted cash flow per share of $4.57. Second quarter free cash flow was $973 million. We provided robust cash returns to our shareholders in the second quarter, anchored by our sustainable regular dividend of over $500 million and complemented by share buybacks of $600 million. In the second quarter, in connection with our Encino acquisition announcement, we declared a 5% increase in our regular dividend. The new indicated annual dividend rate is $4.08 per share, which is a 3.5% dividend yield at our current share price, far in excess of the average dividend yield for the S&P 500. Regarding future cash returns, we expect to return a similar level of free cash flow as we have the last couple of years. We continue to favor buybacks as a source of additional cash return beyond our regular dividend, and we'll monitor the market for opportunities to step in and repurchase shares. Since initiating buybacks in 2023, we have repurchased over 46 million shares, which is approximately 8% of shares outstanding or a total of $5.5 billion. We have $4.5 billion remaining on our buyback authorization. In May, we announced the $5.6 billion acquisition of Encino, which was funded at closing on August 1 with cash on hand and debt. On July 1, we issued $3.5 billion of senior notes, with proceeds directed towards the Encino acquisition. This issuance consisted of 4 tranches: $500 million due in 3 years, $1.25 billion due in 7 years, $1.25 billion due in 10.5 years and $500 million due in 30 years. The weighted average maturity of the senior notes is approximately 11 years with a weighted average coupon of 5.175%. We were extremely pleased with the investor response to the notes offering as it demonstrates their confidence in EOG's long-term outlook. Our updated guidance reflects ownership of Encino for the 5 remaining months of 2025. At assumed prices of $65 WTI and $3.50 Henry Hub, we expect to generate $4.3 billion in free cash flow in 2025, which adjusted for commodity price changes is 10% higher than our forecast last quarter. This higher free cash flow reflects not only the Encino acquisition, but also modest efficiency gains and lower cash taxes due to recent tax legislation. The last few months have been transformational for EOG, and the company is exceptionally well positioned from a balance sheet and cash generation standpoint to further reward shareholders in the future. Now here's Jeff to review operating results.

Jeffrey R. Leitzell, CFO

Thanks, Ann. Let me begin by thanking every member of our team for the outstanding execution across the organization this quarter. Your dedication and diligence were especially evident both in our core operations and in preparing for the successful acquisition and the work on integrating Encino. This marks another quarter where our operational excellence was a driving force, positioning us to capture new opportunities and deliver meaningful results for our shareholders. Our performance in the second quarter stands out across nearly every operational metric. Once again, we outperformed both our production and cost expectations. Oil, gas and NGL volumes exceeded forecast, powered by continued momentum across our foundational assets. Additionally, we saw better-than-expected gas and NGL volumes in the Powder River Basin. Cash costs were below the midpoint of guidance. Lease operating expense was the largest contributor with beats across all basins. This was a direct result of enhanced efficiencies in workover execution and overall lease and well maintenance. The incremental barrels associated with our volume beat further supports lower unit costs, underscoring our operational leverage and the collective impact of strong execution throughout the organization. On capital spending, we delivered lower-than-expected capital CapEx this quarter, primarily driven by efficiency gains across our operating areas as well as the deferral of some indirect spending into the back half of the year. We're seeing the benefit of careful planning, disciplined execution and real-time efficiency measures that are translating directly into tangible savings. With the closing of the Encino acquisition just a week ago, we have updated our 2025 CapEx and production guidance to include Encino's planned activity for the last 5 months of 2025 and the underlying improvements in our business. Our new full year 2025 CapEx guidance is $6.3 billion with forecasted full-year average oil production of 521,000 barrels of oil per day and average total production of 1,224,000 barrels of oil equivalent per day. Relative to the midpoint of our guidance last quarter, full-year 2025 CapEx is increasing by 5%, while full-year 2025 average daily total production is increasing by 9%. Our operating teams are working swiftly and efficiently to fold the Encino team into the EOG organization. The initial transition is progressing better than anticipated, and we're highly encouraged by the early collaboration between teams and the utilization of technology to increase data integration, both in the office and across the field. Looking at our pro forma Utica activity, we are layering Encino's activity on top of our existing program, and we plan to run 5 rigs and 3 completion crews in the basin through the remainder of the year. This tempo will maximize value for Encino's high-quality acreage while leveraging the best practices and technical expertise from both companies. We expect at least $150 million in annual run-rate synergies within the first year post-close. These savings are largely attributed to well cost with a smaller contribution from targeted G&A reductions. For context, EOG's average well cost in the Utica is less than $650 per foot compared to Encino's $750 per foot. We see clear line of sight to bring well costs in line with EOG's leading-edge D&C costs quickly and efficiently. We're optimistic about the upside potential as our teams begin to work on the Encino assets and apply EOG's operational model. We see incremental opportunities from further optimizing location construction costs, enhancing infrastructure utilization, optimizing marketing agreements and deploying innovations from in-basin sand to advanced water recycling and evaporation technologies as well as employing our optimizer technology on the combined production base. We are confident in our ability to unlock additional synergies and drive sustained value creation. In our investor deck, on Slide 8, we highlight just how attractive the Utica is and why we are excited to add this play to our current foundational assets, the Delaware Basin and Eagle Ford. With just 50-plus net wells developed in the Utica, we are already realizing payback periods of less than a year, driven by low total well costs and highly productive results. While it's too early to discuss specifics on 2026 plans, the Utica is now part of our foundational operating areas, and we will continue to invest at a pace to improve the asset. Turning to Dorado. Our high-intensity completion designs are continuing to deliver superior results with individual well production outpacing our forecast. The team is also continuing to drive efficiencies through success with the EOG drilling motor program and most recently by eliminating a string of casing in many of our Austin Chalk targets. This has helped to increase drilled feet per day by more than 20% in the first half of the year versus 2024 and reinforces our view of Dorado as the lowest cost dry gas asset in the U.S. We expect our Dorado production on a gross basis to reach approximately 750 million cubic feet per day exiting 2025. With our Verde Pipeline in service, which has a 1 Bcf per day capacity and is easily expandable to 1.5 Bcf per day, our Dorado asset is well positioned to capture incremental gas demand in 2026 and beyond. Focusing on the Eagle Ford and Permian, our teams continue to push extended laterals and are realizing the benefit in both efficiencies and well cost. In the Eagle Ford, we drilled the longest lateral in Texas history in the second quarter. The Whistler E #5H had 24,128 feet of treatable lateral or nearly 4.6 miles. In the Permian, we have increased our average lateral length by over 20% year-over-year, and this has helped us realize a 10% increase in drilled footage per day versus 2024. These are just a few examples of how our teams are focused on driving sustainable efficiencies to lower well costs, further enhancing returns. With regards to well costs, as activity levels have moderated across the industry, we're now seeing some softening in the service cost environment, more so for lower quality equipment. As a reminder, we focus on contracting high-quality crews and equipment where pricing has been more stable. As we turn to the back half of the year, we will look for opportunities within our current services to take advantage of any potential softening in the market with a focus on retaining top-tier high-spec services to continue to drive operational efficiencies. We continue to advance our business through technology, and I'm excited to discuss 2 new proprietary technology platforms for EOG. The first platform uses high-frequency sensors that capture and process subsurface data while drilling wells. These sensors allow us to calculate geomechanical rock properties, identify faulting, local stresses, and also monitor downhole equipment performance to minimize downtime. Also, we are able to improve our completion designs through fracture identification, maximizing our frac efficiency within the zone of interest. By integrating this high-resolution data with our traditional data sets, we've achieved improvements in well performance and cost efficiency. This year, over 50 wells have already benefited from this higher resolution data, and we will look to expand its use across our portfolio. The second platform centers on our enhanced AI capabilities. Building on years of utilizing machine learning for production optimization and cost savings, we have now deployed our proprietary generative AI system. This platform is already enabling field and division staff to collaborate more efficiently, automate and capture data more easily, and gain operational insights across all operations. After a strong first half of the year, EOG is well positioned to execute on its full year plan, and we're excited about the opportunities in front of us. Now I'll hand it back to Ezra to wrap it up.

Ezra Y. Yacob, CEO

Thanks, Jeff. Let me highlight a few key points from the second quarter. First, our team delivered outstanding execution with operational results exceeding expectations. Second, our strong operational performance translated directly into impressive financial results and strong cash returns. Through the first half of the year, we have committed to return more than $3.5 billion of free cash flow to investors through our regular dividend, which we have increased by 5%, and through share buybacks. Third, with the Encino transaction now closed, we are updating our 2025 guidance to reflect both the expanded portfolio and momentum across the basins. We are confident in the transformative impact of the Utica, which we believe will serve as a foundational asset for years to come. In addition, we are excited about our ongoing exploration efforts, both domestic and especially in the new international concessions we have captured this year. Fourth, looking ahead, our performance in the first half of 2025 reflects the enduring strength of EOG's value proposition, capital discipline, operational excellence, sustainability, and a high-performing culture. Our business is better positioned than ever to create value for our shareholders. Thanks for listening. We'll now go to Q&A.

Operator, Operator

The first question is from Arun Jayaram with JPMorgan.

Arun Jayaram, Analyst

My first question is on the Utica. Ezra, when you provided the acquisition deck, you highlighted, call it, pro forma production at 275 MBoe per day for both EOG and Encino. My question is if you could talk about the sustaining capital requirements to sustain that level of production from a capital or activity standpoint? And would you expect a, call it, a 5-rig, 3 completion crew cadence to deliver growth from the Utica?

Ezra Y. Yacob, CEO

Yes, Arun, thank you for the question. We are very excited that we were able to close the deal a bit earlier than expected. As you mentioned, we closed last week. Regarding pro forma sustaining capital for the remainder of this year, we are adding to our activity levels with the ongoing Encino plan. However, I think it is still a bit early for us to provide insights on what the activity will look like. We have lower well costs compared to Encino, primarily due to operational efficiency gains rather than contracts. This should provide some incremental synergies and savings. Ultimately, we want to operate the asset for longer than just a week before making any definitive statements. Since bringing the asset in-house and starting to implement our technologies, such as our production optimizers, we have already begun to see significant potential that we can tap into in the field. I’d prefer not to jump the gun too early. Last November, we provided our sustaining capital guidance, which was around $4.3 billion to $4.9 billion. This range is crucial to consider because, for a multi-basin company like ours that operates in both oil and associated gas as well as stand-alone gas assets, determining maintenance capital can be tricky. Are we looking at just maintaining flat oil or natural gas volumes? Are we still investing in exploration? The new Utica asset is relevant here. We remain focused on the volatile oil window, which is key for our returns, but the asset also has an appealing dry gas position that offers options as demand rises. Therefore, carefully evaluating where to invest and the overall macro environment will be essential in deciding how much we invest and what our activity levels will be.

Arun Jayaram, Analyst

Great. My follow-up is, Ezra, I was wondering if you could give us a sense of your geological concept and potential path to commercial development in the UAE. And do you view the risk here more on the geological front, cost front or a little both?

Ezra Y. Yacob, CEO

Yes, fantastic, Arun. We couldn't be more excited about this concession in the UAE. This is actually a reservoir we’ve been working on for several years. Over the last 12 months, we were able to align all stakeholders and finalize commercial contract terms that work for everyone. It’s a shale play, specifically a carbonate shale, which shares some geological similarities with the Eagle Ford play. Drilling has been conducted both vertically and horizontally in parts of the basin where our concession lies, providing us with solid geological data. However, we lack substantial production data. There have been tests where oil reached the surface, and we believe we can enhance production by leveraging our data from North American unconventional plays, as well as our petrophysical models and understanding of geomechanical properties, particularly how our horizontal completions align with targeted landing zones. The primary challenge we face is not geological but rather in scaling up an international unconventional play. It’s widely recognized that the key to success in these plays is having a well-organized infrastructure, supply chain, and logistics. Scale is critical in these ventures, and we certainly have access to that here. Our focus as we move forward with this significant unconventional resource play in the UAE will be on how quickly we can achieve the production increases we anticipate by applying our techniques, as well as how swiftly we can reduce costs.

Operator, Operator

The next question is from Steve Richardson with Evercore ISI.

Stephen I. Richardson, Analyst

I was wondering if you could talk a little bit about how you think about the gas market, Ezra and your marketing strategy. I mean we're seeing counterparties willing to sign what seems to be multiyear contracts. You seem to be accepting of where the market is on the demand outlook being really robust here. So how does that play into how you're thinking about your marketing strategy? Are we likely to see EOG enter into those types of contracts now that you've got the Utica dry gas volumes that you just mentioned in-house? Like are you likely to do that? Or are we likely to see more of the same of you just being really thoughtful about what markets you want to get your gas to and continue to realize really high realizations?

Ezra Y. Yacob, CEO

Yes, Steve, it's a great question. It's very topical right now because I think everyone is seeing the increased demand for natural gas coming not only from power, which is maybe a little bit more of what you're referencing, but also just LNG in general. And as I said in the opening remarks, and we've been saying for a while, 2025 is kind of the inflection point on that. So I like that you pointed out, we have 2 kind of dedicated gas assets, and that's where some of these agreements begin, whether it's LNG or power demand. Because when you're making these long-term commitments, I think what we've seen in discussions with LNG and discussions with hyperscalers is sometimes it's a little bit difficult to get comfortable with a 10, 15, or 20-year agreement if you're only talking about associated gas. And so right off the bat, this tremendous gas business that we've built internal to EOG and alongside our oil business is very well positioned to service that out of Dorado and the Utica. I do think we'll continue to be thoughtful. I appreciate how you phrased that. I think what we look for with any marketing agreement is we start with good partners. We look for agreements that align all the parties involved, so good stakeholder alignment. And then we're always focused on getting exposure to premium pricing. Just signing up a takeaway for essentially a differential based or a pricing mechanism that includes a differential. There's some value there to have diverse markets. But really, what we think we've captured is assets that can deliver low cost consistently to these projects. And so I think we deserve to be paid at least a bit of a premium to that. As we've done with our LNG terms, we like the diversity of different pricing mechanisms, and we can get creative with that. But yes, Steve, as we look at some of these opportunities, whether it's hyperscalers or increased LNG, we think we're very well positioned to capture the upside with either of our 2 assets.

Stephen I. Richardson, Analyst

Great. And then maybe just staying on midstream strategy, Utica, now you have more curious on the oil side and the liquids side. But can you maybe talk about the opportunity to come up with a better solution for those barrels, improve pricing and maybe what we should expect from a time line of when you might have one of those solutions in place?

Jeffrey R. Leitzell, CFO

Yes, Steve, this is Jeff. We are really excited to enhance our marketing team’s efforts because that’s where we believe we can make significant progress in advancing the asset and Utica production. We have a strong history of improving realizations across all our assets, and that will be our main focus once we are up there. One important aspect to consider is the differentials in the area, which are somewhat narrower compared to those of EOG and Encino. This primarily indicates the wider oil dips in Utica as opposed to our legacy operations in places like Eagle Ford and Delaware, where we have been active for quite some time. A great example of our ability to make improvements can be seen in Delaware, where we have successfully reduced our oil differentials by nearly $6 over the last decade. With time and maturation of any play, we expect to enhance those differentials, particularly with the additional scale from this acquisition. I also want to highlight a new slide in our presentation, Slide 8, which illustrates the Utica payout period at approximately 9.3 months, aligning with what we see in Permian. This metric incorporates all the differentials and operating expenses, demonstrating it to be competitive within our portfolio and against other conventional plays. Another area where we can effect change is in GP&T. We plan to collaborate closely with our midstream providers to secure better rates in Utica and leverage our position across our multi-basin portfolio. We have established strong long-term relationships with midstream companies in that region, aiming for mutually beneficial agreements. Over the past few years, the approximately 50 wells we’ve drilled in Utica enabled us to successfully reduce GP&T costs in a short timeframe. Therefore, with the added scale and larger footprint, we anticipate significant benefits. It’s also important to recognize that the increase in GP&T is counterbalanced by declines in LOE, G&A, and DD&A, where we have observed notable reductions. Additionally, some GP&T increases stem from the firm gas transportation secured from Encino, which transports Utica gas to premium markets, leading to higher price realizations. Lastly, Ohio is a highly favorable business environment, and the Utica taxes, aside from income taxes, are below the average of EOG’s multi-basin portfolio, helping to offset some of the elevated GP&T. We believe we have ample opportunity ahead, and expect improvement in our marketing strategy in Utica.

Operator, Operator

The next question is from Neil Mehta with Goldman Sachs & Company.

Neil Singhvi Mehta, Analyst

I just want to start off on cash tax benefits with changes in legislation. You indicated that it's supporting the free cash flow, but can you help us quantify the impact over the next couple of years?

Ann D. Janssen, CFO

Yes. Thanks, Neil. This is Ann. The recent tax legislation is going to help us out. The one big, beautiful bill has some positive impact for EOG. The bill restores 100% of the bonus depreciation permanently and additionally, restores 100% deductibility of the research and experimental cost, again, permanently. For 2025, the impact of the one big, beautiful bill for EOG is approximately $200 million, and we expect that amount to be a recurring benefit in future years. So penciling $200 million is reasonable. Always keep in mind that there are numerous variables that can impact our tax rates and our profiles in any given period. But we expect that kind of a $200 million is going to be a run rate for the next couple of years.

Neil Singhvi Mehta, Analyst

Ezra, I always appreciate your insights on the oil market, and you've been appropriately cautious. Can you share your perspective on how the balances are expected to shift through the end of this year and into 2026, particularly regarding crude oil? There are many factors at play, especially concerning Russia right now. It would be great to hear your thoughts from your Market Intelligence group.

Ezra Y. Yacob, CEO

Yes, Neil. It's very relevant at the moment. There are many factors at play, as you mentioned. Regarding Russia or India, it's uncertain how that will unfold. However, the data we have indicates that demand in Q1, which usually sees a slight seasonal decline, was quite strong. Demand was volatile due to announcements about potential tariffs and their implementation details, similar to any policy changes, which caused some fluctuations. Ultimately, the implementation was not only delayed but also came in at levels that were somewhat anticipated. Demand in Q2 remained strong, with revisions for 2025, including some improvements from China. There are signs that China is performing better year-over-year, although we do expect modest declines, or rather, growth based on historical figures for year-over-year growth in 2025. Demand growth is projected to increase into 2026, with stronger demand growth expected in 2026 compared to 2025. While the latter half of the year may see demand stabilizing with potentially less growth, demand overall remains robust. On the supply side, there's been much speculation about spare capacity and its timing. An important point to mention is that inventory levels are historically very low. We believe that the spare capacity will first help to raise inventory levels back to or slightly above the five-year average, since we've been in a deficit the last few years with higher-than-usual spare capacity. After the next quarter or two, possibly experiencing seasonal demand weakness in Q1, we could see a more balanced market ahead. We anticipate slower non-OPEC supply growth in the coming years compared to prior trends. This is why I stated in the opening remarks that by 2026, pricing is likely to be driven more by fundamentals, with less spare capacity out of operation, leading to a more balanced market in 2026 than what we currently see.

Operator, Operator

The next question is from Douglas Leggate with Wolfe Research.

Douglas George Blyth Leggate, Analyst

Ezra, I sometimes have trouble recognizing my name, but there you go. I wonder if I could come back to the Utica and just ask the question a little differently. Arun already addressed the maintenance capital question. My question is, when you outline the synergies as you discussed, the $100 per foot, clearly, you're going to manage the midstream differently. What is your objective for the Utica, and what are the constraints associated with that? Specifically, what could it grow if you maintained the 5 rigs? Do you have the midstream takeaway capacity to support that? I'm trying to understand if it seems you can achieve more with less and still grow the business with lower spending. Am I thinking about that correctly?

Ezra Y. Yacob, CEO

Yes, Doug Leggate, this is Ezra. It's good to hear from you. Thank you for the question. I believe you are correct. We view the Utica as a growth asset for the company moving forward, with potential for significant growth in the years ahead. The midstream infrastructure is in place. As with any of our plays, we will need to continue enhancing in-basin gathering and seek midstream agreements, just like we do in our other operations. However, there are no major bottlenecks to report. The legacy rig and frac contracts are aligned with ours. Encino has handled the asset well, focusing on high-quality rigs and personnel, similar to our approach. Our advantage comes from our extensive data gained from drilling numerous horizontal wells across the U.S., which helps us reduce costs. Regarding the synergies we've mentioned, the anticipated $150 million has the potential for even greater upside. Concerning immediate growth, as you know, growth must be incremental, influenced by fluctuating market conditions and available spare capacity. Therefore, our investment decisions in the Utica will reflect the state of the macroeconomic environment. Currently, with considerable spare capacity returning and solid demand, it's uncertain whether the upcoming year will present the ideal chance to make aggressive investments in growth. However, the market is dynamic, and we will assess accordingly.

Douglas George Blyth Leggate, Analyst

That's a great answer. My follow-up is a philosophical question, perhaps for you or for Ann. Your dividend yield is 3.5%. Most of the analysts on this call focus on exploration and production. You possess the financial strength, scale, and asset depth of a major company, and you have adopted a major's dividend policy. How should we consider translating the free cash flow from Encino and your overall portfolio towards your priorities for free cash, particularly regarding your policy on dividend growth per share? I'll leave it at that.

Ezra Y. Yacob, CEO

Doug, that's a great question. When we consider increasing the regular dividend, I appreciate the metrics you've shared. It's important for us to ensure our dividend is competitive not just within our peer group but also against the broader market. We believe EOG is becoming one of the few pure upstream exploration and production companies that can truly function like a blue-chip stock. Our primary focus is on our commitment to a regular dividend and increasing it in a disciplined way. We back this up with a strong balance sheet, which remains robust even after our recent acquisition. Our total debt levels relative to EBITDA are around 1x at $45 oil and $2.50 natural gas, indicating recovery at the bottom of the cycle. This supports our consistent record of returning excess cash through special dividends or, more recently, buybacks, which we plan to continue. We see potential for our stock at this moment, and across the industry as well. It's unclear if the earnings or profitability of the sector, particularly in this earnings season, is accurately reflected in the energy sector's weight in the S&P 500. Specifically for EOG, we have quality inventory and depth that provide high returns and free cash flow generation in the short and long term, alongside a strong balance sheet, competitive regular dividends, and a solid track record on excess cash returns. Additionally, we have exciting new exploration opportunities both domestically and internationally, along with transformative projects we've discussed today in the Utica, particularly with the Encino acquisition, and the advancements in our gas business at Dorado and the Utica dry gas. I'm not convinced these aspects are being appropriately valued in the company's current valuation, which presents us with opportunities as we consider buybacks, instilling confidence in our decisions to repurchase shares.

Operator, Operator

The next question is from Scott Hanold with RBC Capital Markets.

Scott Michael Hanold, Analyst

Can I ask about the Utica quickly? Based on your discussions, it seems you have incorporated Encino's plans for the second half of the year into your guidance. I'm interested to know if there are any immediate opportunities you can pursue. You have better operational costs and similar factors. Could there be a potential for improved performance and efficiency as you move forward? What are those immediate opportunities? Additionally, when can we expect the fully engineered, drilled, and completed EOG wells to start coming online?

Jeffrey R. Leitzell, CFO

Scott, this is Jeff. Yes, we see a lot of upside. It's primarily related to well costs and production performance. I can provide several examples. On the logistics and planning side, we have team members out there with the former Encino employees now at EOG, and we're identifying numerous opportunities for shared infrastructure, including pads, gathering systems, and wellsite facilities. We typically consolidate facilities, which will be advantageous. Additionally, as I mentioned earlier, there’s significant potential on the midstream side. Utilizing EOG technology will be a major benefit, including EOG motors and mud cutters. Our supply chain will also benefit greatly from this approach. We plan to replicate our successful strategies from other basins, focusing on local in-basin sand sourcing and water recycling. Furthermore, we'll be able to drill longer laterals due to our new acreage footprint, which will lower costs. As Ezra noted earlier, there’s considerable upside in production optimization. By utilizing our data and quickly implementing our optimizers, we expect to see tangible results in the next few months. Leveraging our expertise and technology from outside the basin while sharing knowledge across divisions will also contribute to significant improvements in the Utica.

Scott Michael Hanold, Analyst

Okay. Sounds exciting. My follow-up, and it's probably again for you, Jeff. You talked about 50 wells that you all drilled and completed utilizing the higher resolution data and sensors and whatnot. Can you give us a sense of what does that translate into, right? So what is the cost to implement that versus maybe D&C savings and improved EURs? So the bottom line is how meaningful can this be if you expanded it to your entire asset base?

Jeffrey R. Leitzell, CFO

Yes. It's very early in the game with the HiFi sensors. But I will say we're extremely excited about it. We're just kind of scratching the surface right now, and we're finding ways every single day that we can probably apply it kind of across the whole portfolio. So just from a cost side, we actually did acquire this IP at the end of last year, and it just included some software and some patents from a commercial company. And then we've just taken that technology. We've cheapened it up. It doesn't cost very much to run per well. So the costs are pretty low on it. And we've improved the algorithms within the system. We've integrated all of our EOG data and basically just started applying it to all of our wells out there. And what it really allows us to do is more than just our precision targeting using gamma ray and kind of staying in zone, we're able to calculate geomechanical properties of the actual rock that we're drilling through. On different downhole drilling parameters and what we're seeing, identifying faults and fractures, which obviously is going to be huge through the drilling and completion process and then even equipment failures downhole. If we start to get some kind of vibration downhole, we can identify it and we can basically have an ability to be able to trip and minimize any kind of downtime there. So I mean, the upside on this, it's very, very early days, but we see a long, long runway with this. And I think the longer that our team has it in their hands and we're able to see different areas in the field that we're able to apply it and our IS team is to work with it. I think this is going to be a really big needle mover for us from an efficiency standpoint moving forward.

Operator, Operator

The next question is from Phillip Jungwirth with BMO.

Phillip J. Jungwirth, Analyst

In the Delaware, you mentioned adding 9 distinct targets to the development program over the last 5 years. I was just hoping you could give some detail here on the delineation. And in Lea County specifically, what's the maximum wells per DSU you think you can get to now and still meet your premium return hurdle?

Keith P. Trasko, Senior Vice President, Exploration and Production

This is Keith. So yes, the zones and targets that we develop in the Delaware Basin, they are going to vary in any given year as we continue to execute our co-development strategy. So one thing we've noticed is we've made significant improvements that support the competitiveness of the shallow targets by lowering the costs and improving the productivity. So that includes the Leonard and the Bone Spring. We're starting to see that they deliver comparable returns greater than 55% at bottom cycle pricing similar to what the Wolfcamp has done. So yes, we noted that we've, in the last 5 years, unlocked 9 additional targets. Those are within all 3 of those main zones, the Leonard, Bone Spring, and Wolfcamp in a mixture of those, and there are things that we experiment with all the time on our team to not have that one-size-fits-all development program. So these are things we were able to unlock with lower costs and improved subsurface learnings, and the targets themselves are outperforming our expectations. So I think it's important to note that productivity is just kind of one dimension of what we do. We really invest for returns rather than just productivity.

Phillip J. Jungwirth, Analyst

Okay. Great. And then just following up on that. In the past, you've had this great slide showing the multiyear trend in lower Eagle Ford F&D just as you've driven those efficiency gains. Wondering if you were to replicate this analysis for the Delaware, how similar do you think it would look also considering the 20% longer laterals this year?

Keith P. Trasko, Senior Vice President, Exploration and Production

In the Eagle Ford, we have been developing for the past 15 years, giving us a bit of a head start compared to the Delaware. Our teams have successfully reduced costs while applying their experiences from production and well drilling, resulting in some of the best economics the play has seen in recent years after extensive development. Looking ahead to the Delaware, we have drilled a significant number of wells and still have several years of drilling left. By using the Eagle Ford as a reference, we are continuing to see a decrease in well costs in the Delaware Basin. Our high-intensity completion design is also enhancing well production; in fact, we've mentioned that this has improved a certain portion of our wells with favorable geological conditions by approximately 20%. Combining these factors will further reduce our finding costs.

Operator, Operator

The next question is from Leo Mariani with ROTH.

Leo Paul Mariani, Analyst

Obviously, you guys, in your sort of macro overview described perhaps a bit of a squishy oil outlook over the next handful of quarters before some improvements can kind of take place in 2026. Just wanted to kind of get a sense of how you would approach that strategically. It sounded like on the call, you guys were talking about perhaps the opportunity to step up the buyback a bit. Obviously, you've done a little bit of M&A here recently with Encino and I guess, a small Eagle Ford bolt-on. Do you think there could be other opportunities for bolt-ons as well if we do get a bit of an oil downturn over the next handful of quarters where EOG might be able to take advantage of some of that?

Ezra Y. Yacob, CEO

Thanks, Leo. Good question. I think as we absorb this rather large-scale corporate M&A, I mean, I think we feel outstanding with where we're positioned. We've got 3 real core foundational plays now between the Eagle Ford, the Delaware, and the Utica and really a fourth just nipping at their heels there in Dorado. And so even if we see a pullback, I think we'd be well positioned to continue to be opportunistic on things. But I think in general, our foundational plays, at this point, the playbook is typically more to core up and block up acreage kind of via trades and things of that nature. And then to the degree that there might be some small bolt-on packages out there that we could take a look at. But really, the strategy for us hasn't changed. We are dominated by organic exploration opportunities and being a first mover to get an established position in the sweet spots of these plays for low cost of entry. When we find opportunities to do small bolt-on acquisitions, or a large scale as we have done now with Encino, we'll be active to do that. And it's one of the reasons that we keep such a pristine balance sheet so that we can be counter-cyclical and strategic, whether it's bolt-ons, acquisitions, leasing and new organic plays, starting to fund some of these international opportunities or leveraging that into stronger marketing agreements. So I think you should look for us if we see a weaker market to continue to be thoughtful and counter-cyclical on how we invest in the company to improve shareholder value long term.

Leo Paul Mariani, Analyst

Okay. Appreciate that. And then just I wanted to follow up a little bit on gas macro. If I heard you guys right, obviously, you think there's tremendous growth in demand over the rest of the decade, which certainly seems to be right. But it sounded like you were perhaps maybe a little bit more cautious on the near term. You kind of mentioned not really willing to push the pedal maybe too hard on some of the gas growth in the near term. Obviously, it looks like domestic production has come in higher than I think a lot of folks expected over the last month. So maybe could you kind of talk a little bit more about your near-term thoughts on gas macro heading into the end of the year and into '26?

Ezra Y. Yacob, CEO

I appreciate your point, Leo. I might have misspoken a bit earlier. Regarding our dedicated gas business, which we've been investing in for several years, we have been strategically aligning it with growth in demand. Part of this involves our LNG exposure, which has increased significantly over the past few years to about 140 million a day in LNG agreements. This year, it will ramp up to over 400 million a day and eventually reach 1 Bcf a day within the next couple of years. This is crucial for our cash flow generation potential. In the first four years, we have delivered 140 million a day to that market and have achieved a cumulative revenue uplift of $1.3 billion. As we continue to increase our delivery close to 1 Bcf a day, we see substantial upside from that. Additionally, we’ve made some strategic marketing arrangements that enable us to invest in our gas assets, such as securing capacity along the Transco Line on the Texas Louisiana Energy Pathway, which allows us to transport gas from Dorado to the Zone 3 hub in Louisiana to serve some of the Southeast's power demand. We are well-positioned to continue developing our gas assets at an appropriate pace. However, I want to emphasize that while we are witnessing a strong demand for gas, volatility in the market is likely to persist. This is why we are committed to investing in these assets at a measured pace to create value throughout those cycles and ensure that we provide the lowest-cost gas to the market.

Operator, Operator

We can take 1 more question from Paul Cheng with Scotiabank.

Yim Chuen Cheng, Analyst

Ezra, over the past, I think that in this earnings season, a lot of your peers have announced some pretty significant cost reduction or business optimization program. EOG did not. But of course, I mean, you guys are doing a lot of things, like Jeff, gave 2 examples this morning. Can you help us maybe to frame it saying that while you are not officially announcing a program, but what is the potential you see from the new technology? How you transform your business? And how much is the potential upside in your free cash flow can generate from those initiatives or what you are doing, say, over the next 2 or 3 years? That's the first question.

Ezra Y. Yacob, CEO

Yes, Paul, this is Ezra. Thanks for the question. I agree that we haven't announced an official cost reduction plan. However, we are consistently focused on maintaining low cycle prices and leveraging technology to help our employees reduce costs, whether in drilling, completion, or operating expenses, which ultimately expands our margins. To understand the implications for future cash flow generation, it's helpful to look at our achievements over the last few years. We've seen a compound annual growth rate in our regular dividend that exceeds our peers, maintained a strong balance sheet, and established a solid history of returning excess cash. These results stem from our daily efforts to create value in the field through collaboration among diverse teams. Jeff mentioned specific initiatives, such as our motor program and Super Zipper simul-frac operations, which have both contributed to lowering costs. Additionally, we are drilling exceptionally long laterals across our portfolio, and technology plays a critical role in this process. Our generative AI has been particularly beneficial, enabling us to harness human intelligence effectively. We've also used it to expedite the integration of Encino. Beyond that, it's the smaller details, like how we organize and collect data, that empower our engineers, geologists, and field employees to interact with that data and drive real impact. These individuals are crucial for affecting the business daily and delivering value to our shareholders.

Yim Chuen Cheng, Analyst

Great. My second question is that there's a lot of debate about the industry inventory and whether U.S. shale oil is going to reach the peak production or may have already reached peak production as one of your peers believes. And you have said, I mean, as your track record in the Delaware Basin that you have unlocked 9 different new benches to be economically produced over the past 5 years. So just curious that from EOG standpoint, if you're looking at the U.S. shale oil industry, at a $65 to $70 WTI price, do you think we are running out of inventories?

Ezra Y. Yacob, CEO

Yes, that's a valid question, Paul, and I appreciate your focus on pricing. It's undeniable that with current prices around $65 or $70, the rig count has dropped significantly. While some of this is due to increased efficiencies, the data suggests that the U.S. lacks a strong incentive to grow under these price conditions. When we assess the situation within the U.S. and look at individual companies, it's clear that we're seeing a divide between those who have invested in infrastructure, scale, and data collection to lower their breakevens and a number of others that, for various reasons, may not have that capacity. These other companies tend to have higher breakeven points. We recognize the value of our employees and the technology we enable them to use. The U.S. has abundant resources, and as I've mentioned regarding our exploration efforts, U.S. unconventional or upstream sectors can continue to grow, influenced by both pricing and technology. We’ve made strides in lowering our breakeven points through innovations like simul-fracs, longer laterals, and faster drilling. At EOG, we are specifically enhancing our motor performance and leveraging that as a significant advantage for longer laterals. Looking ahead, we are excited about applying generative AI. This has been a journey starting with smart technology around 2018, moving to machine learning, and now to deep learning and generative AI. This progression captures human intelligence, allowing us to translate experiential insights into a searchable database that can uncover previously hidden trends. I believe in our team's ability to utilize technology, reduce breakeven points, and tap into new resources.

Operator, Operator

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Yacob for closing remarks.

Ezra Y. Yacob, CEO

We appreciate everyone's time today, and thank you to our shareholders for your support. And special thanks goes out to our employees for delivering another exceptional quarter.

Operator, Operator

This concludes the conference. Thank you for attending today's presentation. You may now disconnect.