EOG Resources, Inc. ($EOG)

Good day, everyone and welcome to EOG Resources 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 Vice President of Investor Relations, Mr. Pearce Hammond. Please go ahead, sir.

Thank you, Cindy, and good morning, and thank you for joining us for the EOG Resources First Quarter 2026 Earnings Conference Call. An updated investor presentation has been posted to the Investor Relations section of our website and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations section of EOG's website. In addition, 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 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 is Ezra.

Thanks, Pearce. Good morning, and thank you for joining us. EOG 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 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 Encino, 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 the first quarter of 2022, which was the last period of very robust oil prices, and the first quarter of 2026, where we are in a similar oil price environment, we have added nearly 100,000 barrels per day of oil, over 140,000 barrels per day of NGLs and nearly 1.6 billion cubic feet per day of gas to EOG'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 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 5-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 5-year average. However, our medium- to long-term outlook remains positive. U.S. natural gas benefits from 2 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'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 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's distinctive culture, a decentralized collaborative operating model that fosters innovation and drives performance at the asset level. In summary, we're 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'll turn it over to Ann for details on our financial performance.

Thank you, Ezra. EOG 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, yielding 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 1x 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 3 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've consistently deployed capital to enhance shareholder value. EOG'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'll turn it over to Jeff for our operating results.

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 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 2,000 barrels per day and NGL production guidance by 6,000 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 the second half of 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 services 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 field gas, which 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, self-sourced materials and vertical integration. Long-term staggered contracts limit its 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 which deliver significant results across our portfolio in the quarter. First, on drilled feet per day, we realized the following increases in the first quarter of 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 efficiency 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'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 2- to 3-mile laterals in the Delaware Basin and 3- to 4-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 completion 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 316 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's operational excellence delivering financial results. And 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 250,000 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 140,000 million BTUs per day to 280,000 million BTUs per day during the first quarter of 2026. An additional 140,000 million Btus will start in the second quarter of this year, bringing us to the full 420,000 million BTUs per day. These volumes are linked to JKM or Henry Hub pricing at EOG's election on a monthly basis. We also supply 300,000 million BTUs per day of LNG feed gas at Henry Hub link pricing. Together, these contracts highlight that our marketing strategy is a competitive advantage and demonstrates how targeted international pricing exposure is driving premium realizations and incremental value across both crude and natural gas. After a strong first quarter, EOG is well positioned to execute on its full year plan, and we are excited about our operational team's ability to drive value to the cycles. Now here's Ezra to wrap up.

Thanks, Jeff. I'd like to note the following important takeaways. First, we've started 2026 with strong momentum and execution across the business. Second, capital discipline is a core pillar of our value proposition, and 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, all underpinned by our culture. Thanks for listening. Now we will go to Q&A.

[Operator Instructions] Our first question comes from Arun Jayaram of JPMorgan Securities LLC.

My 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're reaching 420,000 BTUs in 2Q?

Yes, Arun, this is Jeff. Thanks for the question. First off, going with the waterborne volumes that you talked about, yes, as I talked about in my opening comments, we got about 250,000 barrels there that we have export capacity on. And what I'd say is they can be linked either to domestic pricing or Brent-linked those sales. And what we do is we basically sell those cargo-by-cargo there. So it's basically on an each ship. And what I'd say is there's been obviously a lot of price volatility recently with the conflict so we have been able to sell numerous cargoes, obviously, at a premium. So it's really been paying dividends to have that export capacity to really diversify our marketing on the oil side. And then, yes, over on the JKM side, when you look at the LNG, I think what you're seeing is you're starting to see a little bit of a benefit from that JKM, but you're also seeing some of the volatility in the market that's kind of counteracting that and it's a little bit of noise. So as you know, we came into the year, we were producing 140,000 MMBtu into that Cheniere contract, we increased at another 140,000 MMBtu in the middle of first quarter. So you're not seeing the full realizations flow through. And then we'll have the additional 140,000 MMBtu coming in the second quarter, and you'll continue to see it kind of build into our overall guidance as you move forward. And then the other thing that I'd note on the actual price realization for gas is, although we have pretty minimal exposure out in the Permian with Waha and we've got exposure less than 7%, you do see a little bit of an effect of that on the realizations for the first quarter, especially with some of the lower pricing that we've seen over there. And I don't really think you'll see that alleviate until you get to the probably the last quarter whenever we start bringing on some more egress there in the Permian Basin, and we bring on that 4 million to 5 million a day capacity. So all in all, we're extremely happy with our overall international exposure. It's a great piece just really to diversify our overall marketing strategy. And especially at times during volatility, I think our teams are doing a great job of taking advantage of it.

Great. And my follow-up is on the Middle East exploration program. I was wondering if you could provide us a little bit of an update on what's going on, on the ground? And how, Ezra, you think about capital allocation, just 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 may be in a position to share initial results either from Bahrain or UAE on your exploration program?

Yes, Arun, this is Ezra. Yes, there's a lot there. So let me unpack some of the -- some of it, and maybe I'll let Keith Trasko address kind of the current operations piece of it. But on the UAE's decision to leave OPEC, maybe we could start there. It doesn't really have any change or impact for EOG. We just recently began operations in the country. So we haven't felt any impact. And going forward, we certainly don't expect to. I think it shows just some of the positive steps UAE is taking within their country. But from our perspective, our intention has always been that if the plays are successful, returns are going to drive that investment and the growth in the oil play more so than any type of production quotas. As far as continued capital allocation given the geopolitical risk, listen, longer term, it's still early in the conflict to be making those types of decisions. What I would say is 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? But we're also looking during that exploration phase to evaluate the geopolitics, the sanctity of contracts, our partners, things of that nature. And what I would say with great confidence here during this conflict, we've definitely landed with strong partnerships with both ADNOC and Bapco. It's been very clear communication, straightforward alignment on our operations. And so that really gives us pretty good confidence going forward. And actually, it gives me confidence in the way that we approach or look at the potential for other international opportunities.

And on the -- this is Keith. On the operations side, we're kind of looking at it that we're closely monitoring the situation in both Bahrain and the UAE. It's 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 time line side, both projects are moving forward in line with our expectations for exploration plays. The near-term timeline has slipped slightly a little from the start of the year. So we anticipate having results in the second half of this year, and we'll provide additional updates if there are material changes. On the longer term, we remain very excited. We entered UAE and Bahrain because we saw the compelling subsurface opportunities, positive production results from prior horizontal development and strong partners in both countries and none of that has changed. In Bahrain, you have a tight gas sand; in UAE, you have a carbonate mudrock, we're both -- we're 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 and unconventional plays every day. So in the current exploration phase, we're gathering data and 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. So our goal still remains to just leverage our core competencies in onshore unconventional development to unlock resource that's competitive with the domestic portfolio.

Our next question comes from Steve Richardson of Evercore.

Ezra, it sounds like the decision to pivot a little bit more towards liquids is more to do with the opportunity in liquids than it is a change in your longer-term view in gas. And maybe you could talk about that -- the value of keeping the capital flat and making that adjustment within the portfolio? And then what -- it does sound like you're 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?

Yes, Steve, great question. This is Ezra. Yes, I'd start with maybe the decision on the capital reallocation this year, really, it's just looking at where the dynamics have played out and what's happened since the beginning of the year. Obviously, there's a dramatic upset on the liquid side, on the oil side, and you've seen a dramatic response in the oil price. Conversely, you've started to see on the natural gas side, inventory levels after starting the year off pretty strong supporting price, you've seen inventory levels climb above the 5-year average and gas prices pull back just a little bit. And so it's -- for us, it's a pretty simple calculation of just reallocating some of the activity in Dorado to some of our more oil-weighted assets, not just for returns, but quite frankly, there's a call across the world, across the globe right now for increased oil supply. And so that's what we're doing. It's one of those things where, in Dorado, actually, we've made fantastic progress, have actually reduced our well costs down -- with our target is down below $700 per foot, and we feel confident that we can hit that this year. As you know, we've got a low breakeven price of about $1.40 per Mcf. But the advantage of having a multi-basin portfolio with both geographic and product diversity is that we have the flexibility that we can move capital allocation around throughout the years. If you see something that certainly is dramatic as we have this year. Now for 2027, this does set us up better to grow liquids. These maneuvers that we've done right now to grow liquids, maybe a little more oil, a little more aggressive in 2027. But really, it's too early to get there. We need to continue to see how the conflict proceeds. I think that's why we're confident in our plan today to maintain our capital budget is because we really want to see how these things really start to play out just a little bit longer. We're just 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 12 hours, 10 hours, you can see just how volatile the situation remains. And while we do think longer term, this sets up an environment where there's a much higher floor for oil price than where we entered the year. We'd like to have a better line of sight and understand that just a little bit more before we took any additional steps forward.

That's great. Very clear. Maybe if I could just also ask on the buyback. It looks like you stepped up on the buyback pretty significantly in the month of April here. And that's despite I think we'd agree that oil price is above a view of mid-cycle and you just mentioned some of the volatility. And I think Ann mentioned this in her script. But can you talk a little bit about how tactical you're willing to be around the buyback and how you think about that relative to kind of the value of kind of just a ratable program throughout the year? Because obviously, there's a ton of volatility in the commodity and your stock price as we look forward.

Yes. Steve, this is Ann. Through the first 4 months of 2026, we have seen exceptional value on our stock, and that's been reflected in the buyback activity you referenced, and it's put us in a good position to return that 70% -- at least 70% of annual free cash flow back to our shareholders this year. It was reported in the first quarter, we repurchased 3.2 million shares. And if we dissect that a little to your question, we did have some limitations on buybacks during the fourth quarter quarterly earnings period because for the first 2 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. But then we leaned in and from April 1 to April 28, we have repurchased approximately 2.3 million additional shares, and that's really a testament to us continuing to see a lot of value in our stock and that's driven by tremendous positive momentum we see within the company. We believe those buybacks support sustainable growth of our regular dividend. And finally, if you look at the energy weighting in the S&P 500 despite the increase in stock price, it's still very low at approximately 3.5% weighting and you can also see free cash flow yields in the energy sector are also close to historic highs. So we allocated over $7.1 billion to repurchases since we first started buying back stock in 2023, and that's allowed us to reduce our share count that's been 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 that continued improvement in our business and that growing intrinsic value will provide additional opportunities for us to buy back our stock going forward.

The next question comes from Josh Silverstein of UBS.

Just a question on the shifting activity. I was curious about the decision process as to how you reallocate amongst the 3 different basins there? Why 10 more in the Utica and first 5 of the Delaware versus, say, 15 all in the Utica or the 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?

Josh, this is Jeff. Yes, thanks for the question. Yes, 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, kind of across all the assets. A couple of things that I'd state is, in the Utica, where we are increasing 10, we've seen some of the easiest drilling in the company, and we've talked about that very openly and really solid efficiency gains here even just in the first quarter, where we increased our drilled feet per day by 22% versus 2025. So seeing outstanding results there, and that's been able to allow us to build our working DUC count up there just a little bit more than some of the other plays. And then when you look at the Delaware, everything is going outstanding out there, we just tend to be a little bit more efficient on the completion side there because we've got full super zipper operation across our fleets, along with all of our sand logistics in place, you really don't have any kind of delays there. So -- and then also, we've seen a 17% increase in the first quarter on completed lateral feet per day. So that was keeping the DUC count a little bit tighter. That's really all it is, just the mechanics of how things were moving the time lines we had between our rigs and completion fleets in each one of the divisions and how it just made sense to kind of allocate that capital and keep division healthy so we can keep improving each one.

Got it. And then I know you haven't added any additional CapEx for exploration for this year. But I'm curious what the additional cash you'll now be building if there are new prospects you're teeing up for exploration for next year, both domestically and international? I know you guys are always out looking for new areas to go in and have some resource upside. So curious for an update there.

Yes, this is Keith. Yes, we have a number of exploration plays, both domestic and on the international side. In fact, I'd say maybe even more of them on the domestic side than international. Our teams are always utilizing data from our successful plays to revisit basins, look at new basins, seeing what could be unlocked with the new technology that we apply to other plays and with the lower costs of today than the years that the basin was first looked at. We're always on the lookout for what can make our inventory better. So I can't comment on specifics. But as you know, exploration has always been our preferred method of adding low-cost reserves. You look at Doratico -- you look at Dorado, you look at how we're Utica first movers, Trinidad exploration, even the Encino acquisition was born of organic exploration from the years prior. So 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're ready to comment on specifics of a given program, we'll certainly do so. But exploration is a big way that we deliver value to shareholders.

The next question comes from Scott Hanold of RBC.

If I could return to the shareholder return discussion. I'm not sure if this is for Ann or Ezra. But can you give us a view of how you think about variable dividends? I know there's 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, like is there the ability for you guys or desire for you guys to push to, like, say, a 90% to 100% return versus the base 70% level like you've done in past quarters?

Scott, this is Ezra. Thanks for the question here. Yes, on the special dividend piece, that's still in our mix. Now what I would say is -- and we've been clear about this and go ahead and repeat it one more time, though. But the foundation of our cash return to shareholders is really that regular dividend. That's the one that we just love. Sustainably growing that regular dividend. We think it sends a message of discipline to our investors. We think it shows the increasing confidence in the capital efficiency going forward. When we first started doing additional cash return 3.5, 4 years ago, we actually did lean in on the special dividends a bit more than buybacks. We've always said that in general, we're pretty agnostic to how we return that additional cash to shareholders. But we are committed to as far as buybacks go to being opportunistic. We've really shifted in the last few years, as you've kind of highlighted, I think, really exactly just over 3 years now, I think we've shown we've got a track record of consistently being in the market every day looking for opportunities is the way I would say it. So opportunistic, not necessarily just holding out for some sort of dramatic black swan event, but really looking at where can we make value for the shareholders through the cycle. And I think we've done a great job with that. But we are very concerned or cognizant not to let this program become procyclical. And that's one reason why we have that 70% minimum return commitment. I think going to a 90% to 100% return at these kind of elevated prices. I wouldn't say nothing is possible, but I'd also say that -- or nothing is impossible, but what I would heighten is that I think we'd like to build a little more cash on the balance sheet in this part of the up cycle and prepare ourselves for a potential future pullback in prices where we could continue our track record of positive countercyclic investment. Some of the things I mentioned in the call earlier, investment in the Janus processing plant, the Encino acquisitions, the bolt-on in the Eagle Ford, some of our marketing agreements, that's really when we create a significant amount of value for the shareholders is being able to have the balance sheet to kind of zig when maybe others are zagging.

Appreciate that context. My follow-up is on the premium pricing and the contracts. You all obviously have been a step ahead of other companies with signing these agreements and obviously benefiting right now. But as you look ahead, is there a further opportunity to build on that? Or are these more countercyclical decisions?

Yes, Scott, this is Jeff. No, I mean, that's one thing our marketing team, I think they look to do is day in, day out, they're obviously looking for new opportunities, looking for new outlets and making sure they're diversifying the portfolio of markets that we have. So both domestically, whether we have emerging plays and we're in new areas, we're constantly adding in new markets, obviously, trying to minimize those differentials so we can maximize the [ netbacks ] there. And then the same thing on the international side. I mean, we've got great exposure with our LNG agreements as we've talked about getting close to 1 Bcf a day, but we continue to look for unique ways to be able to price that gas going offshore to try to take the volatility out and try to get a premium price with it. So as we've talked about, obviously, our Cheniere agreement is kind of a sweetheart deal. So it's tough to get those kind of terms. But obviously, we're still in the market and looking at all the options there. And then the other thing is at the size of the company we are right now, we've got a lot of scale in all these basins and even international. And just with how low cost we are, we're able to keep operations moving and consistent activity, it really is an advantage to us in the negotiations along with our balance sheet, which obviously they know we're going to be resilient through these cycles, and we can lean on that, and that tends to help in the negotiations to get us a little better pricing. So that's always what our goal is, is to continue to improve our overall price realizations and maximize those netbacks, and we'll continue to look for ways to do that.

Our next question comes from Phillip Jungwirth of BMO.

Yes. We're kind of coming up on a year since you announced, almost a year, since you announced Encino acquisition One of the things you noted at the time was EOG's volatile oil wells being 8% to 10% more productive than Encino. I know we've talked about a lot about lower well costs. But just was hoping you could update us on what you're seeing on the productivity side now that you have some EOG drilled and completed wells on? And then also just could you expand on that staggered lateral comment that you had earlier and what exactly you're doing here?

This is Keith. Yes, on the productivity side, in the Utica, we're treating it all as one asset now. We see really consistent productivity in the program and year-over-year. I'd say we're even maybe a little surprised to the upside and some of the step-out areas that we've had. On the staggering targets that Jeff mentioned, yes, we've been testing that, especially in the north, where you have a little thicker section. We've been seeing good results. So our goal is always to increase recovery of each acre of each section, and we'll take those learnings, integrated in with our detailed geologic mapping and see where in the play that we can apply it. But I think just for the long term, there's a lot of opportunities to apply learnings from what we saw from how Encino did things all the way through to our other analog plays within the company to continue to improve well performance.

Okay. Great. And then you also mentioned the Eagle Ford bolt-on earlier in the prepared remarks. And yes, you have done a really good job here in improving returns in the Western Eagle Ford through efficiencies, long laterals, four-milers. It's actually an area we haven't seen much industry consolidation. But just curious, based on the synergies you realized in the Utica, does this at all make you more encouraged about pursuing additional bolt-ons in the Eagle Ford or elsewhere? Just because, obviously, you can bring superior operating and also marketing capabilities that can create value.

Thanks, Phillip. This is Ezra. It's a good question. I think we always knew before doing the Encino acquisition that we should have an advantage in a lot of areas, assets, we might be able to improve upon with our operations, our cost structure and our marketing, like you had mentioned. The challenge has always been getting these deals done at a price that allows the all-in returns to really compete. Any time you're buying anything with a lot of production that weighs on the returns profile of the overall project. And so the upside really needs to be there to kind of counteract production, let's call it, a 10% to 12% kind of bid-ask spread. So that's always been the challenge. Now countercyclically, like you pointed out last year, we were able to get a couple of deals done here. The first one was Encino, obviously, with a lot of production, but Keith just talked about a tremendous amount of upside. And we really got to prove to ourselves exactly what you're asking that scale, our knowledge base, our database from outside of a single basin and bringing data from other basins can add a tremendous amount of value. And we saw a 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, though, is that Eagle Ford, and that was kind of a needle in a haystack really. It essentially had essentially 0 production, really, very, very low production. And we were surrounding that acreage kind of fit in like a jigsaw puzzle piece. And so 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 that we're drilling surrounding the acreage onto the acreage. And we very quickly actually moved in and have, within the first year that we have had that bolt-on in our portfolio have already drilled a number of high-return wells on it. And so I think you're right. It's gone a long ways towards 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 little bit of production as well.

The next question comes from Doug Leggate of Wolfe Research.

Ezra, I wonder if I can go back to the liquids pivot. And I just wanted to understand a little bit more what you're actually doing there. Have you physically allocated, reallocated equipment? Or was this, forgive me, a classic EOG beat-and-raise? What have you actually done differently? And I guess the root of my question is, if you flex things that quickly, how do you maintain efficiency? And I'm wondering if this was underlying production and productivity beats that were going to happen anyway?

Doug, this is Jeff. Yes, so the first thing I'd say with the actual productivity raise for the year, we did have a beat in the first quarter. So that's the first thing that I'd point to on that. And then obviously, other than that, really, it's just obviously reacting to what we're seeing out there from price standpoint, we're just making very modest adjustments to activity schedule around the portfolio. And like we said, just shifting that investment from gas to oil. So what that really is going to do is we're just taking a little bit of capital out of Dorado. It's not a whole lot. It's just going to drop them down to just less than a frac fleet. So they'll still have activity to where we can focus on the asset, continue to move it forward and progress it. The only thing is the exit rate now there in Dorado will drop a little bit. It will go from a Bcf target to just over 800 million a day. And with that, we actually do have a rig that's down there. It's going to go up and drill just a couple of DUCs in San Antonio, actually. And then also, we're reallocating the rest of the capital to add 5 net completions in the Delaware Basin and then the 10 net there in the Utica, which is very small and it's within rounding. I mean, really 5 wells in the Delaware, when you think about it, are just additions to a package. It's not even really any additional equipment. And then in the Utica, it's very similar to how the rig has gotten out in front. It's just really a couple of packages of DUC inventory there. So -- and a lot of it, as I said, was really it is, it's due to the performance that we've seen and the consistent efficiency gains has allowed us to be able to do that and do the raise on the whole year within the same CapEx of $6.5 billion. And as we stated, it will add 2,000 barrels on the year for oil and 6,000 barrels on the NGL side. So I think it's just -- we keep hitting on it, but it's one of the benefits to having this multi-basin portfolio. We obviously have multiple high-return assets across the company that all compete for capital, and it really gives us just a lot of flexibility to alter our plan real time, very quickly without much disturbance and we're able to really maximize that shareholder value through the cycles.

I appreciate that, Jeff. Ezra, maybe for you and specifically, my follow-up is on your -- basically on your -- it's not a capital return question necessarily, it's 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've also got a pristine balance sheet. So I guess my question is, how do you think about that split between allowing the dividend burden to move up versus the risk, as you pointed out, procyclical buybacks? And maybe this is an add-on to that. Are you -- it sounds like you're prepared to let your balance sheet go back to net debt 0. Maybe you could just touch on those issues.

Yes, Doug. Yes, this is Ezra. That's -- those are good questions. So let's talk about the first one. We're not opposed. I wouldn't say net debt 0 is a target for ours. But you clearly saw that we've been there before [indiscernible] getting there again. I think with the 70% minimum commitment that we have in place, it would be difficult to get there this year, but potentially in the next couple of years. But I do think that's one of the things that -- when you think about EOG, just keep that in mind 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, yes, hopefully, the dividend yield will move the other way here pretty soon and get lower. But the way we think about our share repurchases, and this has been maybe a bit of a learning experience. It's straightforward math, straightforward enough that when you are buying back stock, that obviously reduces your absolute dividend commitment. But having been in the market now buying back stock for 3 years, we really have good experience with that. And we love it. I would say, going back to Scott's question before, maybe we're not quite as agnostic anymore on special dividends versus stock buybacks because of that because we do see the ongoing benefit and the correlation with our ability to continue to increase that regular dividend. As you mentioned, the regular dividend or as we talked about, the dividend now is about -- it's $4.08 annualized per share. And so it's got a yield that is competitive across the broad market. And over the 3 years that we've been buying back stock, we've actually got a compound annual growth rate, and this is during a softer part of the cycle of about 9%. And so that's something we're proud of. It's something we continue to look forward to and discuss with the board is that our dividend increases should reflect growth. They should reflect the margin expansion. They should really reflect the ongoing capital efficiency of the company. And then any share repurchases obviously help that as well.

The next question comes from Gabe Dodd of Truist.

Thanks for the time and the prepared remarks. Ezra, I was hoping could maybe just go back to your views on the macro. So it certainly seems like maybe your bias once all the [indiscernible] is mid-cycle oil's maybe higher than what we all anticipated prior to the Iran conflict. So can you maybe talk a little bit about how this could change how you allocate capital on a go-forward basis? And I guess what I'm curious about is how you think about more growth in the supportive oil price environment and how you allocate across oil versus gas?

Yes, Gabe, that's a good question. Yes, I would say we are a little bit more bullish going forward. I'm not -- it might be a little bit of semantics, but I think it's subtle, but it might be significant. I'm not sure if we would say the mid-cycle price has changed dramatically. The way I would frame it is that for the next few years, we think we've moved -- we're going to be in an environment above mid-cycle prices. I think historically, this is a cyclical business. When you look back at kind of 5, 10, 15 years runs, it's amazing, but WTI usually ends up right in that kind of mid $60, $65 range. So the point of it now is that you're right, with inventory levels where they've gotten down to -- it's going to take a number -- it's going to take quite a while to get inventory levels back up to the 5-year average. And that would assume that barrels flow pretty easily through the Strait of Hormuz. I would assume that the committed SPR releases hit the market. And like we've said that investment in U.S. and non-OPEC is going to be above where it was when we entered in 2026. What does that mean for us? We put out a 3-year scenario at the beginning of this year. And it kind of 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. But honestly, that low single-digit plan is a very, very compelling scenario. Now it's not guidance. It is a scenario, but it delivers on just a conservative $60 to $80 WTI range. That 3-year scenario delivers 15% to 25% ROCE, $12 billion to $24 billion in free cash flow and a compound annual growth rate of free cash flow is 6-plus percent. And that's straight free cash flow, not per share. So any additional buybacks would obviously increase that. And the big takeaway, I think, is even at the same strip prices the past 3 years, our go-forward scenario here would increase cumulative free cash flow by about 20% over the past 3 years. And so leaning in a little bit more aggressively into growth, not only does it need to be supported by fundamentals. But we also need to lean into an environment that you're not running into inflationary headwinds or anything like that. We continue -- what's best is obviously increasing the inventory levels. What's best for the consumers for affordability of energy is to increase those inventory levels back up to mid -- the 5-year average, but to do it at an appropriate cost. And so leaning in just to grow production even though you're leaning into a higher cost environment, that's something where we need -- we will be -- you can consider us to be very thoughtful and deliberate before we did something like that.

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

I'd 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.

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