EOG Resources, Inc.

Operator: Good day, everyone. And welcome to EOG Resources, Inc. First Quarter 2026 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, Inc.'s Vice President of Investor Relations, Pearce Hammond. Please go ahead, sir. Pearce Hammond: Thank you, Cindy, and good morning, and thank you for joining us for the EOG Resources, Inc. First Quarter 2026 Earnings Conference Call. An updated investor presentation has been posted to the Investor 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 Resources, Inc.'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 Resources, Inc.'s website. In addition, any reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Ezra Y. Yacob, Chairman and Chief Executive Officer; Jeffrey R. Leitzell, Chief Operating Officer; Ann D. Janssen, Chief Financial Officer; and Keith P. Trasko, Senior Vice President, Exploration and Production. I will now turn the call over to Ezra Y. Yacob. Ezra Y. Yacob: Good morning, and thank you for joining us. EOG Resources, Inc. is off to an exceptional start in 2026. Our track record of consistent, high-quality execution continues to set us apart, delivering strong operational performance across our foundational assets while steadily advancing our emerging plays and exploration opportunities. The first quarter was a clear extension of that momentum. We exceeded expectations across key operating and financial metrics; production volumes, total per-unit cash operating costs, and DD&A all outperformed guidance midpoints, driving robust financial results. We generated $1.8 billion in adjusted net income and $1.5 billion in free cash flow. Consistent with our commitment to disciplined capital allocation and enhancing shareholder value, we returned nearly $950 million during the quarter through our regular dividend and opportunistic share repurchases. In today's macro environment, EOG Resources, Inc. is well positioned in realizing the benefits of decisions we made during a more challenging commodity price backdrop. Those actions were deliberate and are paying off. For example, we strengthened our portfolio through the acquisition of nCino, increasing our oil production by approximately 10%, and we complemented that with a strategic bolt-on acquisition in the Eagle Ford. We also enhanced our market exposure by securing LNG contracts linked to JKM and Brent, positioning us to capture premium pricing in global markets. Additionally, we expanded our international footprint with high-quality concessions in the UAE and Bahrain, opportunities that would be difficult to replicate in the current price environment. Finally, we continue to deepen our vertical integration across critical services. This differentiated approach further improves efficiencies, lowers costs, and strengthens execution across our operations. As a testament to investing capital at a disciplined pace, between 2022—which was the last period of very robust oil prices—and 2026, where we are in a similar oil price environment, we have added nearly 100 thousand barrels per day of oil, over 140 thousand barrels per day of NGLs, and nearly 1.6 billion cubic feet per day of gas to EOG Resources, Inc.'s net production. We did this while generating an average ROCE of 27%, returning approximately $20 billion to shareholders, and maintaining a pristine balance sheet. EOG Resources, Inc. continues to take a consistent approach to capital allocation in the current environment. Given robust oil prices and softness in natural gas, we have refined our plan for the balance of 2026. We are increasing oil and NGL production while maintaining our $6.5 billion capital budget by reallocating capital from gas to oil-weighted assets. This is a disciplined and pragmatic rebalancing that underscores the value and flexibility of our multi-basin portfolio. Our 2026 program includes production growth, domestic and international exploration, and a peer-leading regular dividend with a breakeven oil price below $50 WTI, leaving ample room for additional cash return to shareholders under current strip prices. This revised plan strikes the right balance between near-term free cash flow generation and long-term value creation, while preserving the strength of our balance sheet. Turning to the macro backdrop, the conflict involving Iran is the most significant development impacting our business and the broader energy markets. Disruptions to crude supply and flows through the Strait of Hormuz are estimated to remove approximately 900 million barrels from global markets through June 2026. Even in a scenario where the conflict is resolved relatively quickly, rebuilding global inventories back to five-year average levels will provide ongoing support for oil prices. Additionally, we expect the post-conflict outlook to include replenishing strategic petroleum reserves, limited remaining global spare capacity, and a higher geopolitical risk premium. Together, these dynamics point to a constructive oil price environment with geopolitical developments likely to continue driving periods of upside volatility. On natural gas, near-term pressure remains with Lower 48 storage levels above the five-year average. However, our medium- to long-term outlook remains positive. U.S. natural gas benefits from two durable structural tailwinds: rising LNG feed gas demand and increasing electricity consumption. We expect U.S. natural gas demand to grow at a 3% to 5% compound annual growth rate through the end of the decade and believe the previously forecasted potential for global LNG oversupply has been significantly reduced with the damage to LNG infrastructure abroad. Our investments in building a premium gas position to complement our oil business have us well positioned to supply these expanding markets. And while EOG Resources, Inc.'s share price has increased following the onset of the conflict, the move in oil prices has been even more pronounced. As a result, we continue to believe EOG Resources, Inc. represents a compelling investment opportunity for several reasons. First, we have a high-return domestic and international asset base with deep, long-duration inventory. Across our multi-basin portfolio, we estimate approximately 12 billion barrels of oil equivalent of resource potential generating greater than a 100% direct after-tax rate of return at $55 WTI and $3 Henry Hub. Our disciplined capital investment allows us to pace development appropriately and direct capital towards the highest-return opportunities across the portfolio. Second, we bring differentiated exploration capabilities and approximately 25 years of unconventional experience, an advantage we have consistently leveraged to identify and capture opportunities ahead of the market. Third, we have a demonstrated track record as a low-cost, highly efficient operator supported by strong technical expertise and operational execution. In the past year alone, we reduced average well cost by 7% and operating costs by 4%. Fourth, we generate durable free cash flow and consistently deliver a peer-leading return on capital employed. Fifth, we remain committed to a sustainable and growing regular dividend, complemented by meaningful additional cash returns. Notably, we have never reduced nor suspended our regular dividend in 28 years. Finally, our pristine balance sheet provides resilience and strategic flexibility through commodity cycles. All of this is underpinned by EOG Resources, Inc.'s distinctive culture: a decentralized, collaborative operating model that fosters innovation and drives performance at the asset level. In summary, we are off to a strong start in 2026 and are well positioned to execute in the current macro environment. We remain focused on delivering sustainable free cash flow, maintaining operational excellence, and creating long-term value for our shareholders. Now, I will turn it over to Ann D. Janssen for details on our financial performance. Ann D. Janssen: Thank you, Ezra. EOG Resources, Inc. delivered another quarter of outstanding financial performance, once again demonstrating the power of our consistent approach to capital allocation: invest with discipline, return cash, and maintain a pristine balance sheet. In the first quarter, we generated adjusted earnings per share of $3.41 and adjusted cash flow from operations per share of $5.85, building free cash flow of $1.5 billion. During the first quarter, we returned approximately $950 million to shareholders, nearly $550 million through our regular dividend and approximately $400 million in share repurchases. With $2.9 billion remaining under our current share repurchase authorization at March 31, we have substantial capacity for continued opportunistic buybacks. Our financial position remains exceptional. We ended the first quarter with over $3.8 billion in cash, an increase of approximately $450 million since year-end 2025, and net debt of $4.1 billion. Our leverage target, which is maintaining total debt at less than one times EBITDA at bottom cycle prices of $45 WTI and $2.50 Henry Hub, remains among the most stringent in the energy sector. This provides both downside protection during challenging periods and the financial flexibility to invest strategically through commodity cycles. Turning to 2026, our low-cost operations and financial strength allow us to be unhedged, providing shareholders full exposure to higher oil prices. At current strip pricing and using guidance midpoints, our 2026 plan generates a record $8.5 billion in free cash flow. Given the substantial increase in oil prices since late February, and the subsequent increase in our free cash flow, we expect to return at least 70% of free cash flow this year, which would represent a record annual cash return to shareholders. The foundation of our cash return remains our regular dividend. Historically, we supplement the regular dividend with share buybacks or special dividends. Over the past three years, we have favored share buybacks as our primary supplemental return mechanism as we believe the shares are attractively valued and we like the connection between repurchasing stock and dividend increases. We are committed to executing buybacks opportunistically. If market conditions warrant, we could build some cash on the balance sheet to provide future flexibility to maximize long-term value creation. Our track record speaks for itself. Whether through buybacks, special dividends, strategic bolt-on acquisitions, or infrastructure investments, we have consistently deployed capital to enhance shareholder value. EOG Resources, Inc.'s financial foundation has never been stronger. We are generating significant free cash flow, returning meaningful cash to shareholders, and maintaining financial flexibility to capitalize on opportunities as they arise. This combination of operational excellence and financial discipline positions us exceptionally well for long-term value creation. With that, I will turn it over to Jeffrey R. Leitzell for our operating results. Jeffrey R. Leitzell: Thanks, Ann. I would first like to thank all of our employees for their outstanding performance and efficient operational execution in the first quarter. Our quarterly volumes, total per-unit cash operating costs, and DD&A beat guidance midpoints. This was accomplished during the quarter with a significant winter storm event that impacted numerous operating areas and caused substantial third-party downtime. With the benefit of EOG Resources, Inc.-owned and operated infield gathering systems, the use of in-house production optimizers, area-specific control rooms, and our diverse marketing strategy, our teams were able to manage remote operations and minimize downtime during this event. These efforts have allowed us to get off to a strong start in 2026, and because of that, I would like to recognize our field teams for all their hard work and dedication. For the full year 2026, we are increasing oil production guidance by 2 thousand barrels per day and NGL production guidance by 6 thousand barrels per day while keeping total capital expenditures flat at $6.5 billion. The added oil and NGL volumes are driven by reallocating capital across the portfolio rather than increased activity levels. From a development standpoint, we are moderating near-term drilling and completions activity at Dorado in response to current gas prices. Dorado remains a large-scale, high-quality dry gas resource, and we continue to invest in this foundational asset at a pace to balance short- and long-term free cash flow, grow into emerging North American gas demand, and leverage our technical learnings and infrastructure to continue lowering breakevens and expand margins. Capital is being reallocated to our foundational oil plays to leverage current market conditions. This initiative underscores the strength of our multi-basin portfolio, which allows us to continually optimize capital allocation as commodity cycles evolve. This reallocation is weighted towards 2026 while maintaining capital discipline and preserving long-term value across the portfolio. Turning to costs, we have not seen any significant inflation with our services or cost increases on high-quality rigs or frac spreads. For 2026, approximately 50% of our well costs are already locked in, and we continue to rebid service to maintain pricing discipline. While some vendors have added fuel surcharges, our exposure to higher diesel prices is structurally lower than many peers. Approximately 70% of our drilling rigs can run on natural gas, and 100% of our frac fleets are e-frac or dual-fuel capable, both able to be powered by our low-cost fuel gas. This significantly mitigates exposure from rising diesel prices. On the operating cost side, the impact from higher diesel prices has been minor. Overall, we are insulated from a number of these potential inflationary pressures through our contracting strategy and self-sourced materials vertical integration. Long-term, staggered contracts limit exposure to spot market volatility, while our ability to source key inputs directly and leverage integrated infrastructure reduces risk to higher prices. Collectively, these actions allow us to maintain capital efficiency, drive execution, and focus on sustainable cost reductions, and are complemented through utilizing data and technology to reduce time on location. All of this delivered significant results across our portfolio in the quarter. First, on drilled feet per day, we realized the following increases in 2026 versus the full-year 2025 average: in the Utica, we increased by 22%; the Powder River Basin increased by 13%; and the Eagle Ford increased by 12%. We continue to make significant strides in capital through lateral length optimization, resulting in fewer vertical wellbores to drill, more productive time both on surface and downhole, as well as a reduced surface footprint. In addition, EOG Resources, Inc.'s internal drilling motor program acts as a force multiplier on these longer laterals, improving downhole drilling performance and giving us the confidence to continue extending laterals across the portfolio. We are focused on drilling two- to three-mile laterals in the Delaware Basin and three- to four-mile laterals in the Utica and Eagle Ford plays. Second, our completions teams are continuing to increase stimulation efficiency. Each of our foundational plays has increased completed feet per day, led by the Eagle Ford and Delaware Basin, at 12% and 17% increases during the first quarter, respectively. One major factor that has allowed us to accomplish these results is an increase in our maximum pumping rate capacity by approximately 20% per frac fleet since 2023. This has not only allowed our technical teams to decrease their total pump times but also allowed our engineers the flexibility to tailor each high-intensity completion design around the unique geological characteristics of every target. Additionally, our teams are applying real-time geology, drilling, and completions data to improve well performance across the portfolio through innovative completions and targeting strategies. For example, our Western Eagle Ford wells are benefiting from larger frac job designs, and we are seeing positive results in the Utica from staggering our landing zones. Third, I would like to highlight our Janus Natural Gas Processing Plant in the Delaware Basin. Since November 2025, this plant has averaged 300 million standard cubic feet per day of processing, representing 94% plant utilization. Janus had a record month in March 2026 with 100% utilization and 300 million standard cubic feet per day of processing. Strong operations at Janus help us reduce Delaware Basin GP&T costs while highlighting the advantage of strategic infrastructure investments. Delivering this level of consistent performance is impressive and is a testament to the execution of the teams on the ground. This is another example of EOG Resources, Inc.'s operational excellence delivering financial results. Lastly, our marketing strategy—built on flexibility, diversification, and control—continues to deliver significant value. A key and growing aspect to this is our access to international markets and exposure to premium pricing. On the crude side, we have access to 250 thousand barrels per day of export capacity out of Corpus Christi. We leverage this capacity to reach international markets, and it gives us the flexibility to price crude on a domestic-based or Brent-linked price. Regarding LNG gas supply agreements, our Cheniere contract expanded from 140 thousand BTUs per day to 280 thousand BTUs per day during 2026. An additional 140 thousand BTUs will start in the second quarter of this year, bringing us to the full 420 thousand BTUs per day. These volumes are linked to JKM or Henry Hub pricing at EOG Resources, Inc.'s election on a monthly basis. We also supply 300 thousand BTUs per day of LNG feed gas at Henry Hub-linked pricing. Together, these contracts highlight that our marketing strategy is a competitive advantage and demonstrate how targeted international pricing exposure is driving premium realizations and incremental value across both crude and natural gas. After a strong first quarter, EOG Resources, Inc. is well positioned to execute on its full-year plan, and we are excited about our operational team's ability to drive value through the cycles. Now here is Ezra to wrap up. Ezra Y. Yacob: Thanks, Jeff. I would like to note the following important takeaways. First, we have started 2026 with strong momentum and execution across the business. Second, capital discipline is a core pillar of our value proposition. We have updated our 2026 plan to increase oil production while keeping capital spending unchanged. Our portfolio is performing, our balance sheet is resilient, and our capital allocation remains firmly anchored in returns and shareholder value. Third, we expect to continue to deliver in 2026 and beyond for our investors. In a macro environment that demands both agility and rigor, we are well positioned not just to navigate volatility, but to capitalize on it. Our disciplined approach to investment across our foundational and emerging assets continues to grow the free cash flow potential of the company both in the short and long term. Overall, our success is grounded in our commitment to capital discipline, operational excellence, and sustainability, underpinned by our culture. Thanks for listening. Now we will go to Q&A. Operator: Thank you. The question and answer session will be conducted electronically. Please do so by pressing the star key followed by the digit one. If you are using a speakerphone, you are allowed one question and one follow-up. We will take as many questions as time permits. Once again, star one. Our first question comes from Arun Jayaram of JPMorgan Securities LLC. Go ahead, please. Arun Jayaram: Yes, good morning. First question is on marketing. You raised your full-year oil guidance by $3.25 a barrel. Can you remind us of the pricing mechanism on those waterborne barrels out of Corpus as well as the potential uplift you anticipate from the Cheniere marketing agreement as you are reaching 420 thousand BTUs in 2Q? Jeffrey R. Leitzell: Yes, Arun, thanks for the question. First off, on the waterborne volumes that you talked about, as I mentioned in my opening comments, we have about 250 thousand barrels per day of export capacity. Those barrels can be linked either to domestic pricing or Brent-linked pricing. We basically sell those cargo by cargo, on an each-ship basis. There has been a lot of price volatility recently with the conflict, so we have been able to sell numerous cargoes at attractive pricing. It has really been paying dividends to have that export capacity to diversify our marketing on the oil side. Over on the JKM side, when you look at LNG, you are starting to see a little bit of the benefit from that JKM linkage, but you are also seeing some of the volatility in the market that is counteracting that, so there is a little bit of noise. As you know, we came into the year producing 140 thousand MMBtu into that Cheniere contract. We increased that another 140 thousand in the middle of the first quarter, so you are not seeing the full realization flow through, and then we will have the additional 140 thousand come in during the second quarter, and you will continue to see it build into our overall guidance as you move forward. The other thing I would note on the actual price realization for gas is that although we have pretty minimal exposure in the Permian to Waha—less than 7%—you do see a little bit of an effect on the realization for the first quarter, especially with some of the lower pricing over there. I do not think you will see that alleviate until probably the last quarter, whenever we start bringing on some more egress in the Permian Basin and bring on that 4 million to 5 million a day of capacity. All in all, we are extremely happy with our overall international exposure. It is a great piece to diversify our overall marketing strategy, and especially at times of volatility, I think our teams are doing a great job taking advantage of it. Arun Jayaram: Great. And my follow-up is on the Middle East exploration program. I was wondering if you could provide a little bit of an update on what is going on on the ground and how, Ezra, you think about capital allocation given the geopolitical risk situation, although you could argue if the UAE does leave OPEC that perhaps provides a potential tailwind to growth. And perhaps you could give us a sense of when EOG Resources, Inc. may be in a position to share initial results either from Bahrain or UAE on your exploration program? Ezra Y. Yacob: Yes, Arun, good morning. There is a lot there, so let me unpack some of it and maybe I will let Keith P. Trasko address the current operations piece. On the UAE’s decision to leave OPEC, it does not really have any change or impact for EOG Resources, Inc. We just recently began operations in the country, so we have not felt any impact, and going forward, we certainly do not expect to. I think it shows some of the positive steps the UAE is taking within their country. From our perspective, our intention has always been that if the plays are successful, returns are going to drive the investment and growth in the oil play more so than any type of production quotas. As far as continued capital allocation given the geopolitical risk, longer term it is still early in the conflict to be making those types of decisions. During the exploration phase, we entered this trying to do a couple of different things—certainly evaluating the subsurface potential of the fields. We certainly wanted to evaluate the surface and operating environment: can we get access to high-quality equipment, can we build scale there, and things of that nature? We are also looking during the exploration phase to evaluate the geopolitics, the sanctity of contracts, our partners, things of that nature. With great confidence here during this conflict, we have definitely landed with strong partnerships with both ADNOC and BAPCO. There has been very clear communication and straightforward alignment on our operations, and that really gives us pretty good confidence going forward. It actually gives me confidence in the way that we approach or look at the potential for other international opportunities. Keith P. Trasko: On the operations side, we are closely monitoring the situation in both Bahrain and the UAE. It is pretty dynamic. We have some employees that remain in the region while others have been repositioned. Since the program is still in the exploration phase, our 2026 plan for Bahrain and UAE was designed with a lot of flexibility. On the timeline side, both projects are moving forward in line with our expectations for exploration plays. The near-term timeline has slipped slightly from the start of the year, so we anticipate having results in the second half of this year, and we will provide additional updates if there are material changes. Over the longer term, we remain very excited. We entered the UAE and Bahrain because we saw compelling subsurface opportunities, positive production results from prior horizontal development, and strong partners in both countries. In Bahrain, you have a tight gas sand. In the UAE, you have a carbonate mudrock; we are very used to dealing with those types of rocks. We believe they will benefit significantly from the drilling and completions technologies that we employ in our domestic unconventional plays every day. In the current exploration phase, we are gathering data on long-term well costs, evaluating our ability to access high-performing service equipment, and we started exploration activity with limited operations in both countries last year. Our goal remains to leverage our core competencies in onshore unconventional development to unlock resources competitive with the domestic portfolio. Operator: Our next question comes from Stephen I. Richardson of Evercore. Go ahead, please. Stephen I. Richardson: Hi, good morning. Ezra, it sounds like the decision to pivot a little bit more towards liquids is more to do with the opportunity of liquids than it is a change in your longer-term view in gas. Maybe you could talk about the value of keeping the capital flat and making that adjustment within the portfolio, and then what it does sound like you are thinking—that this is a longer-term impact to market, which I think we would agree with. So how does that set you up for 2027 and beyond from a liquids and potentially oil growth perspective? Ezra Y. Yacob: Yes, Steve, great question and good morning. I would start with the decision on the capital reallocation this year. It really is just looking at where the dynamics have played out and what has happened since the beginning of the year. There has been a dramatic upset on the liquids side, on the oil side, and you have seen a dramatic response in the oil price. Conversely, on the natural gas side, inventory levels—after starting the year off pretty strong supporting price—have climbed above the five-year average, and gas prices have pulled back a bit. For us, it is a pretty simple calculation of reallocating some of the activity in Dorado to some of our more oil-weighted assets, not just for returns, but quite frankly, there is a call across the globe right now for increased oil supply, and so that is what we are doing. In Dorado, we have made fantastic progress. We have reduced our well costs with our target down below $700 per foot, and we feel confident that we can hit that this year. As you know, we have a low breakeven price of about $1.40 per Mcf. The advantage of having a multi-basin portfolio with both geographic and product diversity is that we have the flexibility to move capital allocation around throughout the years if you see something as dramatic as we have this year. For 2027, this does set us up better to grow liquids—these maneuvers that we have done now—to grow liquids, maybe a little more oil, a little more aggressive in 2027. But really, it is too early to get there. We need to continue to see how the conflict proceeds. That is why we are confident in our plan today to maintain our capital budget because we want to see how these things start to play out a little bit longer. We are not quite there yet as far as making a call on picking up rigs or frac fleets and investing longer term. Just this morning, over the last 10 to 12 hours, you can see how volatile the situation remains. While we do think longer term this sets up an environment where there is a much higher floor for oil price than where we entered the year, we would like to have better line of sight and understand that a little bit more before we took any additional steps forward. Stephen I. Richardson: That is great. Very clear. Maybe I could also ask on the buyback. It looks like you stepped up on the buyback pretty significantly in the month of April here, and that is despite, I think we would agree, that oil price is above a view of mid-cycle when you just mentioned some of the volatility. I think Ann mentioned this in her script, but can you talk a little bit about how tactical you are willing to be around the buyback and how you think about that relative to the value of just a ratable program throughout the year? Because obviously there is a ton of volatility in the commodity and your stock price as we look forward. Ann D. Janssen: Yes. Good morning, Steve. Through the first four months of 2026, we have seen exceptional value in our stock, and that has been reflected in the buyback activity you referenced. It has put us in a good position to return at least 70% of annual free cash flow back to our shareholders this year. As reported in the first quarter, we repurchased 3.2 million shares. To dissect that a little, we did have some limitations on buybacks during the fourth-quarter earnings period because for the first two months of 2026, we were operating under the parameters of a 10b5-1, so the majority of those 3.2 million shares were repurchased in March. Then we leaned in, and from April 1 to April 28, we repurchased approximately 2.3 million additional shares. That is really a testament to us continuing to see a lot of value in our stock driven by tremendous positive momentum we see within the company. We believe those buybacks support sustainable growth of our regular dividend. Finally, if you look at the energy weighting in the S&P 500, despite the increase in stock prices, it is still very low at approximately 3.5%. You can also see free cash flow yields in the energy sector are close to historic highs. We have allocated over $7.1 billion to repurchases since we first started buying back stock in 2023, and that has allowed us to reduce our share count by more than 10% at compelling prices. That disciplined approach focuses on being opportunistic and positions us to create meaningful value for our shareholders, and we remain confident continued improvement in our business and growing intrinsic value will provide additional opportunities for us to buy back our stock going forward. Operator: The next question comes from Joshua Silverstein of UBS. Go ahead, please. Joshua Silverstein: Just a question on the shifting activity. I was curious about the decision process as to how you reallocated amongst the three different basins there. Why 10 more in the Utica versus five in the Delaware versus, say, 15 all in the Utica or Delaware? I was curious if there was something that drove this or if it was based on what you could do with the existing rigs and frac crews there? Thanks. Jeffrey R. Leitzell: Hey, Josh. Thanks for the question. There is nothing to read into there at all. It really just happens to be what flexibility we have in our activity schedules at this point in the year across all the assets. A couple of things I would state: in the Utica, where we are increasing 10, we have seen some of the easiest drilling in the company, and we have talked about that very openly, with really solid efficiency gains even in the first quarter where we increased our drilled feet per day by 22% versus 2025. Seeing outstanding results there has allowed us to build our working DUC count a little more than some of the other plays. In the Delaware, everything is going outstanding as well. We tend to be a little bit more efficient on the completion side there because we have full super-zipper operation across our fleets along with all of our sand logistics in place, so you really do not have delays there. We also saw a 17% increase in the first quarter on completed lateral feet per day, which was keeping the DUC count a little tighter. That is all it is—just the mechanics of how things were moving, the timelines we had between our rigs and completion fleets in each one of the divisions, and how it made sense to allocate that capital and keep each division healthy so we can keep improving each one. Joshua Silverstein: Got it. Thanks for that. And then I know you have not added any additional CapEx for exploration for this year, but I am curious with the additional cash you will now be building if there are new prospects you are teeing up for exploration for next year, both domestically and internationally. I know you guys are always out looking for new areas to go in—some resource upside. So curious for an update there. Thanks. Keith P. Trasko: Yes. We have a number of exploration plays, both domestic and on the international side. In fact, I would say maybe even more on the domestic side than international. Our teams are always utilizing data from our successful plays to revisit basins, look at new basins, and see what could be unlocked with the new technology we have applied to other plays and with the lower costs of today than in the years that the basin was first looked at. We are always on the lookout for what can make our inventory better. I cannot comment on specifics, but as you know, exploration has always been our preferred method of adding low-cost reserves. You look at DoradoCo, you look at Dorado, you look at our Utica first-movers, Trinidad exploration; even the Encino acquisition was born of organic exploration from the years prior. We expect all our asset teams to be exploring for inventory additions and/or something transformative. We have several prospects and leasing campaigns, and when we are ready to comment on specifics of a given program, we do so. Exploration is a big way that we deliver value to shareholders. Operator: The next question comes from Scott Michael Hanold of RBC. Go ahead, please. Scott Michael Hanold: Yes, thanks. If I could return to the shareholder return discussion, I am not sure if this is for Ann or Ezra, but could you give us a view of how you think about variable dividends? I know there have been a number of your peers who have shelved that concept. If your stock price does go at a point, do you still see variables having some value? And secondly, on shareholder returns, is there the ability or desire for you to push to, say, a 90% to 100% return versus the base 70% level like you have done in past quarters? Ezra Y. Yacob: Good morning, Scott. Thanks for the question. On the special dividend piece, that is still in our mix. We have been clear that the foundation of our cash return to shareholders is the regular dividend. That is the one that we love—sustainably growing that regular dividend. We think it sends a message of discipline to our investors; it shows increasing confidence in capital efficiency going forward. When we first started doing additional cash return three and a half to four years ago, we leaned in on special dividends a bit more than buybacks. We have always said that, in general, we are pretty agnostic to how we return that additional cash to shareholders, but we are committed, as far as buybacks go, to being opportunistic. We have really shifted in the last few years. Over just over three years now, we have shown a track record of consistently being in the market every day looking for opportunities. So opportunistic—not necessarily just holding out for a dramatic black swan event—but really looking at where we can create value for shareholders through the cycle. I think we have done a great job with that. We are also very cognizant not to let this program become procyclical, and that is one reason why we have that 70% minimum return commitment. Going to a 90% to 100% return at these elevated prices—I would not say nothing is impossible, but I would highlight that we would like to build a little more cash on the balance sheet in this part of the upcycle and prepare for a potential future pullback in prices where we could continue our track record of positive countercyclical investment. Some of the things I mentioned earlier—investment in the Janus processing plant, the Encino acquisition, the bolt-on in the Eagle Ford, some of our marketing agreements—are really when we create significant value for shareholders: being able to have the balance sheet to zig when maybe others are zagging. Scott Michael Hanold: Appreciate that context. My follow-up is on the premium pricing in the contracts. You all obviously have been a step ahead of other companies with signing these agreements and benefiting right now. As you look ahead, is there further opportunity to build on that, or are these more countercyclical decisions? Jeffrey R. Leitzell: Yes, Scott. Our marketing team looks day in and day out for new opportunities, new outlets, and diversifying the portfolio we have—both domestically, where we have emerging plays and are in new areas, and internationally. We are constantly adding new markets and trying to minimize differentials to maximize netbacks. On the international side, we have great exposure with our LNG agreements, as we have talked about, getting close to 1 Bcf a day. We continue to look for unique ways to price gas going offshore to try to take volatility out and get a premium price. As we have talked about, the Cheniere agreement is kind of a sweetheart deal, so it is tough to get those kinds of terms. But we are still in the market and looking at opportunities. With the size of the company we are now, we have a lot of scale in all these basins and internationally. With how low-cost we are, we are able to keep operations moving with consistent activity. That is an advantage to us in negotiations, along with our balance sheet—which counterparties know will be resilient through cycles—and we can lean on that. That tends to help in negotiations to get us better pricing. Our goal is to continue to improve our overall price realization and maximize netbacks, and we will continue to look for ways to do that. Operator: Our next question comes from Phillip J. Jungwirth of BMO. Go ahead, please. Phillip J. Jungwirth: We are coming up on almost a year since you announced the nCino acquisition. One of the things you noted at the time was EOG Resources, Inc.’s volatile oil wells being 8% to 10% more productive than Encino. I know we have talked a lot about lower well costs, but hoping you could update us on what you are seeing on the productivity side now that you have some EOG-drilled and completed wells on. And then also, could you expand on that staggered lateral comment that you had earlier and what exactly you are doing here? Keith P. Trasko: Morning. On the productivity side in the Utica, we are treating it all as one asset now. We see really consistent productivity in the program year over year. I would say we are even a little surprised to the upside in some of the step-out areas. On the staggering targets that Jeff mentioned, we have been testing that, especially in the north where you have a thicker section. We have been seeing good results. Our goal is always to increase recovery of each acre and each section, and we will take those learnings, integrate them with our detailed geologic mapping, and see where in the play we can apply it. Over the long term, there are a lot of opportunities to apply learnings from how Encino did things through to our other analog plays within the company to continue to improve well performance. Phillip J. Jungwirth: Okay, great. And then you also mentioned that Eagle Ford bolt-on earlier in the prepared remarks. You have done a really good job improving returns in the Western Eagle Ford through efficiencies, long laterals—four milers. It is an area we have not seen much industry consolidation. Based on the synergies you have realized in the Utica, does this make you more encouraged about pursuing additional bolt-ons in the Eagle Ford or elsewhere, given you can bring superior operating and marketing capabilities that can create value? Ezra Y. Yacob: Thanks, Philip. It is a good question. We always knew before doing the nCino acquisition that we should have an advantage in a lot of areas—assets we might be able to improve with our operations, cost structure, and marketing, like you mentioned. The challenge has always been getting these deals done at a price that allows the all-in returns to really compete. Anytime you are buying anything with a lot of production, that weighs on the returns profile of the overall project, so the upside really needs to be there to counteract a typical 10% to 12% bid-ask spread. That is always the challenge. Cyclically, like you pointed out, last year we were able to get a couple of deals done. The first was Encino, obviously with a lot of production, but Keith just talked about a tremendous amount of upside. We really got to prove to ourselves exactly what you are asking: that scale, our knowledge base, and our database from outside a single basin—and bringing data from other basins—can add tremendous value. We saw great margin expansion and great improvement on the well productivity side and, as you pointed out, on the well cost side. The other one we did was in the Eagle Ford. That was kind of a needle in a haystack. It essentially had zero production—very, very low production—and we were surrounding that acreage. It fit in like a jigsaw puzzle piece. It was fantastic for us. We immediately got the production that was there into some of our infrastructure. We immediately started to extend some laterals we were drilling surrounding the acreage onto the acreage, and very quickly, within this first year that we have had that bolt-on in our portfolio, we have already drilled a number of high-return wells on it. You are right—it has gone a long way toward telling us that continuing countercyclically and focusing on returns is a winning strategy for us when it comes to either bolt-ons or potential deals that come with a bit of production as well. Operator: The next question comes from Doug Leggate of Wolfe Research. Go ahead, please. Doug Leggate: Ezra, I wonder if I can go back to the liquids pivot, and I just wanted to understand a little bit more what you are actually doing there. Have you physically reallocated equipment, or was this—forgive me—a classic EOG beat-and-raise? What have you actually done differently? The reason I ask is, if you flex things that quickly, how do you maintain efficiency? I am wondering if this was underlying production and productivity beats that were going to happen anyway. Jeffrey R. Leitzell: Hey, Doug. The first thing I would say with the actual productivity raise for the year is that we did have a beat in the first quarter. Other than that, we are reacting to what we are seeing from a price standpoint and making very modest adjustments to the activity schedule around the portfolio—just shifting investment from gas to oil. What that really means is we are taking a little bit of capital out of Dorado. It is not a whole lot. We are going to drop them down to just less than a frac fleet, so they will still have plenty of activity to focus on the asset, continue to move it forward, and progress it. The only thing is the exit rate now in Dorado will drop a little bit; it will go from a Bcf target to just over 800 million a day. We actually do have a rig down there that is going to go up and drill just a couple of DUCs in San Antonio, actually. We are reallocating the rest of the capital to add five net completions in the Delaware Basin and then the 10 net in the Utica, which is very small and within rounding. Five wells in the Delaware are just additions to a package—it is not really any additional equipment. In the Utica, it is similar—where the rig has gotten out in front, it is just a couple of packages of DUC inventory. A lot of it, as I said, is due to the great performance and consistent efficiency, which has allowed us to do the raise on the whole year within the same CapEx of $6.5 billion. As we stated, it will add 2 thousand barrels per day on the year for oil and 6 thousand barrels per day on the NGL side. We keep hitting on it, but it is one of the benefits of having this multi-basin portfolio. We have multiple high-return assets across the company that all compete for capital, and it gives us a lot of flexibility to alter our plan in real time very quickly without much disturbance—and maximize shareholder value through the cycles. Doug Leggate: I appreciate that, Jeff. Ezra, maybe for you then—specifically, my follow-up is basically not a capital return question necessarily; it is more of a philosophical question. Remarkably, your yield is now higher than ExxonMobil, and we tend to think of them as using buybacks to manage their dividend burden. You have also got a pristine balance sheet. How do you think about that split between allowing the dividend burden to move up versus the risk—as you pointed out—of procyclical buybacks? And maybe as an add-on to that, are you prepared to let your balance sheet go back to net debt zero? Maybe you could touch on those issues. Ezra Y. Yacob: Those are good questions. On net debt zero, I would not say it is a target for us, but you clearly saw that we have been there before. I would not mind getting there again. With the 70% minimum commitment we have in place, it would be difficult to get there this year, but potentially in the next couple of years. One of the things to keep in mind is that we think having a pristine balance sheet is a competitive advantage. It allows you to move from a position of strength, and that includes cash on the balance sheet. With regards to the dividend, hopefully the dividend yield will move the other way and get lower. The way we think about share repurchases—this has been a bit of a learning experience—it is straightforward math that when you are buying back stock, that reduces your absolute dividend commitment. Having been in the market buying back stock for three years, we really have good experience with that, and we love it. Going back to Scott’s question, maybe we are not quite as agnostic anymore on special dividends versus stock buybacks because we do see the ongoing benefit and the correlation with our ability to continue to increase the regular dividend. The regular dividend is now about $4.80 annualized per share, and it has a yield that is competitive across the broad market. Over the three years we have been buying back stock—during a softer part of the cycle—we have a compound annual growth rate on the dividend of about 9%. That is something we are proud of and continue to look forward to discussing with the Board. Our dividend increases should reflect growth, margin expansion, and the ongoing capital efficiency of the company, and any share repurchases obviously help that as well. Operator: Next question comes from Analyst at Truist. Go ahead, please. Analyst: Thanks, Cindy. Good morning, everyone. Thanks for the time and prepared remarks. Ezra, I was hoping you could go back to your views on the macro. It certainly seems like maybe your bias, once all this ends, is mid-cycle oil is maybe higher than what we all anticipated prior to the Iran conflict. Can you talk a little bit about how this could change how you allocate capital on a go-forward basis? I am curious how you think about more growth in a supportive oil price environment and how you allocate across oil versus gas? Ezra Y. Yacob: That is a good question. I would say we are a little bit more bullish going forward. It might be a bit of semantics, but I am not sure we would say the mid-cycle price has changed dramatically. I would frame it as: for the next few years, we think we are going to be in an environment above mid-cycle prices. Historically, this is a cyclical business. When you look back at five-, 10-, 15-year runs, WTI usually ends up in the mid-$60s—around $65. The point now is that with inventory levels where they have gotten down to, it is going to take quite a while to get inventories back up to the five-year average. That would assume barrels flow pretty easily through the Strait of Hormuz, the committed SPR releases hit the market, and investment in the U.S. and non-OPEC is above where it was when we entered 2026. What does that mean for us? We put out a three-year scenario at the beginning of this year that contemplated an environment based on fundamentals where we were investing to grow the business on the oil side at about low single digits. If there was a real call going forward supported by fundamentals on shale, we could increase maybe to mid-single digits. Honestly, that low single-digit plan is a very compelling scenario. It is not guidance; it is a scenario. It delivers, on a conservative $60 to $80 WTI range, a 15% to 25% ROCE, $12 billion to $24 billion in free cash flow, and a compound annual growth rate of free cash flow of 6% plus. That is straight free cash flow, not per share—so any additional buybacks obviously increase that. The big takeaway is even at the same strip price as the past three years, our go-forward scenario would increase cumulative free cash flow by about 20% over the past three years. Leaning in a little more aggressively into growth not only needs to be supported by fundamentals, but we also need to be mindful of the cost environment. We do not want to lean into a higher-cost environment just to grow production if you are running into inflationary headwinds. Increasing inventory levels back to the five-year average is best for consumers and energy affordability, but to do it at an appropriate cost. We will be very thoughtful and deliberate before we did something like that. Analyst: Thanks, Ezra. That is really helpful. I will leave it there since we are at the hour. Really appreciate the time. Ezra Y. Yacob: Thank you. 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: I would just like to say that we appreciate everyone's time today. Thank you to our shareholders for your support and special thanks to our employees for delivering another exceptional quarter. Operator: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.