EOG Resources, Inc. (NYSE:EOG) Q1 2025 Earnings Call Transcript

EOG Resources, Inc. (NYSE:EOG) Q1 2025 Earnings Call Transcript May 2, 2025

Operator: Good day, everyone, and welcome to EOG Resources First Quarter 2025 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Investor Relations, Vice President of EOG Resources, Mr. Pearce Hammond. Please go ahead, sir.

Pearce Hammond: Good morning, and thank you for joining us for the EOG Resources first quarter 2025 earnings conference call. I am Pearce Hammond, Vice President, Investor Relations. An updated Investor Presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today’s discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG’s SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP financial measures.

Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations section of EOG’s website. In addition, some of the reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC’s reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Chief Financial Officer; and Keith Trasko, Senior Vice President, Exploration and Production. Here’s Ezra.

Ezra Yacob: Thanks, Pearce. Good morning, everyone, and thank you for joining us. EOG is off to an exceptional start in 2025. In the first quarter, we delivered outstanding results across our diverse multi-basin portfolio, positioning the company to achieve an even greater success this year. Our production and total per unit cash operating costs and DD&A all exceeded targets, driving strong financial performance. We earned $1.6 billion in adjusted net income and generated $1.3 billion in free cash flow, underscoring our commitment to value creation. True to our track record of rewarding shareholders, $1.3 billion was returned to shareholders through our regular dividend and opportunistic share repurchases. EOG’s operational excellence continues to translate into robust returns and a steady stream of cash flow generation, setting the company up for further success in 2025 and beyond.

Quarter-after-quarter, year-after-year, EOG has consistently delivered exceptional operational performance across our core assets, while also advancing new opportunities in our emerging plays. Our disciplined approach to capital allocation, strategically investing across our portfolio at the right pace, has generated free cash flow every year since 2016 and established a strong foundation for a sustainable, growing regular dividend and a balance sheet that stands out not just within our industry, but across the broader market. EOG is well-positioned for the cycles with a strong financial position, low cost structure and the ability to flex activity across multiple high-return investments. Our success is anchored by one of the industry’s most diverse high-return and deep multi-basin portfolios with over 10 billion barrels of oil equivalent of high-quality resources.

The depth and quality of our resource portfolio positions EOG for long-term sustainable growth and value creation. Capital discipline at EOG means more than just focusing on high-return assets. It’s about being agile and responsive to the broader macro environment. In light of our strong first quarter performance and potential near-term impacts on global demand due to ongoing discussions regarding tariffs, we are proactively optimizing our 2025 capital investment while maintaining first quarter oil production levels throughout the year. At the midpoint of guidance, this $200 million reduction in capital investment is expected to enhance 2025 free cash flow, while still delivering approximately 2% year-over-year oil growth. The first quarter saw strong global oil demand, moderating U.S. supply growth and inventory levels below the five-year range, supportive of the medium-term and long-term outlook for both oil and gas.

We remain constructive on both oil and gas playing a significant role in the long-term need for reliable low cost energy. The near-term, however, is reflecting speculation on oil demand impacts associated with tariff announcements, which has softened prices. We expect to see a return to market fundamentals and pricing firming up as more transparency is applied to the tariffs and negotiation turns to implementation. Regarding natural gas, our 2025 plan remains consistent with investments delivering approximately 12% year-over-year growth at the midpoint of guidance. A cold start to winter and increases in LNG feedstock coupled with a subdued supply response has left current inventory levels near the five-year average in a year that we believe is an inflection point for North American demand.

Led by LNG and increased power demand, we see the potential for 4% to 6% compound annual growth rate in natural gas demand between now and the end of the decade and are well-positioned to deliver natural gas into multiple markets and demand centers across our portfolio. EOG’s multi-basin strength, in-house operational excellence, proprietary technology and self-sourced materials uniquely position us as a low cost, highly efficient operator with exposure to diverse products and pricing. Backed by our rigorous investment standards and rock solid balance sheet, we are continuing to make strategic investments that drive both near-term performance and long-term value for shareholders. Our opportunities continue to grow, both domestically and internationally.

We’re actively pursuing an exciting organic exploration program, driving expansion in our inventory across existing assets by reducing well costs, improving productivity and strategically adding bolt-on acquisitions. For example, after active development for over a decade, our Eagle Ford asset continues to deliver high-returns as we apply best practices developed both in and out of basin. Recently, we have added a strategic bolt-on acquisition in the Eagle Ford, further strengthening the quality and quantity of our Eagle Ford inventory. This contiguous acreage immediately benefits from long laterals and existing EOG infrastructure, offering both operational efficiency and high-returns. Internationally, yesterday, we announced an oil discovery in our Trinidad asset, capping off a successful 2024 drilling campaign and continuing over 30 years’ success in the region.

This is a fantastic development, and Jeff will provide additional details shortly. In addition, our international exploration team is preparing for our entry into Bahrain, where we plan to start drilling an onshore unconventional tight gas sand prospect in the second half of 2025. To wrap up, I want to emphasize EOG’s core value proposition. We’re committed to sustainable value creation throughout the industry cycle, driven by a disciplined focus on high-return investments, optimizing both short-term and long-term free cash flow, along with a pristine balance sheet and strong regular dividend that sets us apart from our peers. Our operational excellence, combined with our dedication to sustainability, is fueled by EOG’s unique culture, a decentralized collaborative approach that drives innovation at the asset level.

By leveraging technology to make real-time decisions, we continuously improve efficiency, lower costs and boost margins, ensuring long-term visibility for strong returns and free cash flow generation no matter where we are in the cycle. Now, here’s Ann with details on our financial performance.

Ann Janssen: Thanks, Ezra. In the first quarter, we delivered adjusted earnings per share of $2.87, and adjusted cash flow per share of $5.09. First quarter free cash flow was $1.3 billion. We had a strong quarter of cash return to our shareholders anchored by our sustainable regular dividend of over $500 million and share buybacks of nearly $800 million. Our share repurchases are a clear demonstration of our commitment to shareholders. To-date, we have repurchased nearly $5 billion of stock over the course of nine consecutive quarters, reducing our share count by 7%. Our assets continue to improve, and by repurchasing shares, we are able to increase shareholder interest in our world class multi-basin portfolio. We remain committed to opportunistic share buybacks, and our balance sheet provides the ability to return greater than 100% of annual free cash flow in the near-term.

We have optimized our 2025 plan and are reducing capital investments by $200 million. At the midpoints of guidance, we now expect to generate $4 billion in free cash flow at $65 WTI and $3.75 Henry Hub. We can fund our $6 billion CapEx program this year as well as the regular dividend at WTI oil prices averaging in the low-50s. We remain committed to optimizing our balance sheet and reaffirm our targets of $5 billion to $6 billion in cash and total debt to EBITDA at less than 1 times at bottom cycle prices of $45 WTI. At the end of the first quarter, our cash balance was $6.6 billion with long-term debt at $4.7 billion. Subsequently, we repaid a $500 million debt maturity in April from cash on hand and executed on the bolt-on acquisition in the Eagle Ford.

This $275 million bolt-on adds over a full-year of drilling inventory that is immediately competitive with our current drilling program. EOG is exceptionally well-positioned given our returns focused investments at bottom cycle prices, peer-leading balance sheet, low cost production and history of exceptional operational execution. Now, here’s Jeff to review operating results.

Jeff Leitzell: Thanks, Ann. I would first like to thank all of our employees for their outstanding performance and efficient operational execution. Our first quarter volumes, total per unit cash operating costs and DD&A beat targets. First quarter CapEx was slightly lower than guidance largely due to timing. Q1 volume outperformance was due to better than expected well productivity across our portfolio and specifically improved productivity from our Dorado dry gas asset in South Texas. For the remainder of 2025, we are optimizing our activity levels and resetting full-year CapEx to $6 billion. This updated plan will hold oil production flat compared to the first quarter throughout the remainder of the year, revising our 2025 oil production and total production growth to 2% and 5% respectively.

Capital for the year is essentially split evenly between the first half and the second half. Regarding cadence, we still expect capital to peak in the second quarter with a modest decline in the third quarter. For our updated plan, we have modestly reduced activity in the Delaware Basin, the Eagle Ford and the Powder River Basin, while keeping activity unchanged in Utica and Dorado. In regards to well cost, we still anticipate a year-over-year low-single-digit percentage reduction and do not expect any impact to our 2025 program from tariffs. We are assuming flat service pricing for high spec rigs and frac equipment throughout the year, but maintain flexibility to capture reduced market rates should they materialize. We continue to make significant strides on operational efficiency gains, well cost reductions and productivity improvements across the entire portfolio including the emerging plays.

A good example of this is in our South Texas Dorado Play, where we continue to build on our operational successes by maintaining at least one full rig program. With this consistent activity, we are realizing an additional 15% increase in drill feet per day compared to 2024. In addition, we continue to increase our pumping rates for high intensity completions and are observing a sustained improvement in well performance as well as driving efficiencies. Through the first quarter, we are realizing a 10% increase in well productivity on a per foot basis, boosting the returns of these already prolific gas wells. This is why we believe Dorado is the lowest cost dry gas play in North America with a direct breakeven price of approximately $1.40 per Mcf with access to multiple demand centers.

In the Eagle Ford, we have been able to reduce our well cost per foot with increased efficiencies by continuing to extend lateral lengths. For 2025, we have plans to test four plus mile laterals and are targeting a direct total well cost for the Eagle Ford program of $515 per foot. Also in the Eagle Ford, we are pleased to announce a bolt-on acquisition of approximately 30,000 net acres that is the largest remaining undeveloped core Eagle Ford acreage tract. This bolt-on acquisition includes the ability to extend laterals in adjacent EOG leases, boosting returns and lowering finding cost. Also, it will benefit from existing surface infrastructure in the area to help minimize indirect investment. The acreage immediately competes for capital with our existing portfolio and we will begin drilling operations this year.

This Eagle Ford acquisition is another great example of the type of bolt-on deals that we pursue as they add tremendous value to the play and for our shareholders. In the Delaware Basin, we are pleased to announce that our Janus Gas Processing Plant has been commissioned and brought online. This completes the second of our strategic infrastructure projects and follows the Verde Natural Gas Pipeline, which commenced service last year connecting our Dorado asset to the market center in Agua Dulce with 1 billion cubic feet per day of capacity. We are extremely pleased with the results of both of these projects which will enhance EOG’s long-term margin expansion. In addition, the Williams Texas Louisiana Energy Pathway, TLEP project has commenced service.

EOG has 364 million cubic feet per day of capacity reserved on TLEP which provides access to premium price gas markets in the Southeast. It is projects like these and proactive work by our marketing team that allows EOG to deliver superior gas realizations versus peers. In our Trinidad asset, we continue to create significant shareholder value, having been in the Columbus Basin for over 30 years, our sub-surface knowledge, operations expertise and strong partnerships in the region are unlocking additional resource potential. Last year, we successfully set the Mento platform which we are currently drilling on. We sanctioned another platform named Coconut and yesterday announced we have drilled a successful discovery well named Beryl. The Beryl well is located in approximately 170 feet of water in the TSP deep area and countered 125 plus feet of high-quality oil bearing net pay.

We are currently progressing this project to final investment decision with our partner. And finally, on the sustainability front, after meeting our 2025 targets originally set in 2020, we’ve updated our goals in-line with new EPA reporting standards. We are pleased to announce two new near-term targets. The first goal is to reduce our GHG emissions intensity rate by 25% from our 2019 based year levels by 2030. And second is to maintain near-zero methane emissions for 2025 through 2030 of 0.2% or less. We have made outstanding progress in our emissions reductions efforts over the last five years and still see ample opportunities to make continued progress with a variety of detection, measurement and capture tools. Technologies and processes like iSense, our in-house continuous methane monitoring system, tank vapor capture and compression optimization have driven company-wide improvements and given us confidence in our ability to execute on further reductions.

These updated targets demonstrate EOG’s continued commitment to sustainability, focusing on reducing our emissions intensity and advancing our strong environmental performance. After a strong first quarter EOG is well-positioned to execute on its full-year plan, and we are excited about the opportunities in front of us. Now, here’s Ezra, to wrap up.

Ezra Yacob: Thanks, Jeff. I’d like to note the following important takeaways. First, we are off to an exceptional start in 2025 and our multi-basin portfolio is firing on all cylinders. Second, capital discipline is a core pillar of our value proposition, and we have optimized our 2025 capital investment to protect shareholder returns and support higher free cash flow generation. Third, we expect to continue to deliver in 2025 and beyond for our investors. 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-term 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.

Q&A Session

Operator: Thank you. [Operator Instructions] And, your first question today will come from Arun Jayaram with J.P. Morgan. Please go ahead.

Arun Jayaram: Yes, good morning. Ezra, EOG is a bit of a canary in the coal mine, given your decision to pull back a little bit on capital. I guess some of the questions we got from the buy side is on Slide 7, you highlight, call it, returns above 100% at $55 and $3 and some investors wondering if maybe higher cost producers that sit at the higher-end of the U.S. shale cost curve should be the first ones to cut. And, I was wondering if you could just maybe elaborate on this decision and thoughts on what would cause you to further reduce CapEx as the macro picture evolves?

Ezra Yacob: Yes, Arun, good morning. Thanks for the question. I’m not going to speculate or comment on other producers higher on the cost curve. What I would say is our decision to reduce CapEx doesn’t reflect any deterioration to the economics of reinvestment at the current prices. It’s really a function of capital discipline to protect our shareholder returns and free cash flow. We’re more focused on generating returns and free cash flow than on delivering volume growth in what looks like could be a potentially oversupplied market in the near-term. So, the important thing to take away, I think, is that the updated plan still allows each asset to improve year-over-year, takes advantages of broader opportunities we see to improve our business.

The focus on capital discipline for EOG over years, that’s what’s really helped support and create EOG’s low cost structure and our industry-leading balance sheet. We’ve got strong confidence that we can continue to get better, allow us to continue to lower breakevens as we add lower cost reserves and ultimately remain focused on optimizing both short-term and long-term free cash flow generation.

Arun Jayaram: Great. Makes total sense to us. My follow-up is the company returned 100% of free cash flow in 1Q. I was wondering if you could talk about thoughts on cash return in a tougher macro pictures. Looking at the 10-Q, it does appear that EOG is quite active in April. Looks like you bought back maybe up to 5 million shares, but give us your thoughts, Ezra and Ann, around cash return in a more challenging macro picture?

Ann Janssen: Hi, good morning, Arun. This is Ann. EOG’s approach to our cash return remains unchanged to what we’ve laid out previously. Our strong balance sheet is giving us the ability to return more than 100% of our free cash flow generation to shareholders in the near-term. We’re off to a great start through the first quarter of 2025, and we continue to remain opportunistic with regards to buybacks. Given the current market conditions and the potential we see in our business today, we expect additional cash returns to continue to be through the share repurchase program.

Operator: Your next question today will come from Doug Leggate with Wolfe Research. Please go ahead.

Doug Leggate: Thank you. Good morning, everybody. You know, Ezra, I think you might have just answered the question I had, but I’m going to try and ask it anyway. On Slide 19, you so long standing slide you’ve had you showed a $12 billion to $22 billion three-year cumulative free cash flow. And, the comments you made earlier $4 billion is the number for this year by cutting the capital back. And, what I’m trying to figure out is, you never gave us a capital number along with Slide 19. So, is this how we should think about it that you’re ultimately flexing your capital to protect that $12 billion to $22 billion target, or is it not as formulaic as that?

Ezra Yacob: Yes, Doug. Good morning. Thanks for the question. I would say let me remind everyone that the three-year scenario was never intended to be guidance per se. I think directionally though, it is still accurate. And, there were some assumptions in that scenario, low-single-digit year-over-year oil growth, high-single-digit year-over-year total production growth. And, we actually assumed a cost structure that was basically static from the 2024 levels. With regards to your question, I think you’re headed down the right path, Doug, and I’d say, in general, I agree with you. What you’ve seen today is a step to protecting shareholder value and shareholder returns by taking a step that really builds off of our strong first quarter performance.

And, then we also see potential near-term impacts like I talked about with global oil demand due to the ongoing discussions regarding tariffs. So, we’ve proactively taken the step to optimize our plan, pull-back on $200 million capital, which actually, again, going back to the strong first quarter performance delivers a more capital efficient plan. It protects free cash flow and ultimately reflects shareholder returns throughout this year.

Doug Leggate: It keeps you right in-line with that target. I guess my follow-up is, I’ll be candid some of the feedback we got after results last night was well. If EOG is not growing oil production and they’re spending $6 billion, how does that jive with the $4.5 billion, $4.7 billion sustaining capital number? And, I guess my question is, there’s obviously a lot of other things in that $6 billion. Where would the next area of capital flexibility come? Would it be drilling activity, or would it be some of the peripheral issues like infrastructure and exploration and so on?

Ezra Yacob: Yes, Doug. It’s a little bit difficult to answer without speculating what type of environment we’re specifically in. So, maybe start at the top. Last November, we did talk about a range of maintenance capital cases, kind of in the range of [4.3 to 4.9] (ph). And, the reason for the range is some of the stuff that you’re hitting on. It contemplates, are we trying to keep oil flat? Are we trying to keep equivalents flat? Are we in an environment, quite frankly, similar to 2020, where we’ve really high-graded the business just to a point to keep volumes relatively flat and we’re not investing in exploration or investing in anything else? The way to think about where we’re at today is, clearly, it’s not a maintenance case.

We have grown year-over-year about 11,000 barrels a day at the midpoint. And again, we are continuing to invest in the business. We’re continuing to invest in our emerging assets. We’re continuing to invest in pretty significant gas growth. And, where we’ve actually reduced some of the capital investment has really been on the plays where we have the absolute most flexibility, and those are in some of our legacy assets. So, without trying to frame up exactly what environment it is, if we were to take the next step on further reduction in capitals, it’s certainly hard to imagine an environment where we would let our volumes drop. That would have to be something as dramatic as 2020. Again, I think it’s the only time I can remember us letting that happen.

But again, we would have to monitor. It’s always a balance between optimizing your near-term free cash flow generation and your long-term. And, what that means is investing in some of those emerging assets and exploration to continue to drive forth the longer-term future free cash flow generation potential of the company.

Operator: Your next question today will come from Paul Cheng with Scotiabank. Please go ahead.

Paul Cheng: Thank you. Good morning, guys. I also have two questions. First, in the commodity business, particularly like oil and gas, what we have seen in the past that, at the downturn of the cycle, typically that for the well-positioned companies such as you guys with a very strong balance sheet, that’s a way that you can make the differences and drastically widen your competitive edge, either that by buying a huge amount of the stock or that doing some transformative acquisition. And so, I guess my question is that for you guys, when you’re looking out, it looks like a lot of the easy target, good quality asset is already being picked off. Do you still see a lot of opportunity from an acquisition target standpoint out there, that from a quality standpoint that can well fit into your portfolio, or that you say, look, the most of the best asset that is already being picked.

So at this point, it’s really better off for us to continue to buy back. So, that’s the first question. So, I want to see how the management is thinking on those areas? The second question is on your international asset or particular name, Trinidad. I think after being pretty steady, you are doing a lot of activity over there. So, how should we look at that business in, say, five years’ time? What is the size of the business you can grow to? And, does the management, from a regional diversification standpoint, have any desire saying that international become a much bigger portion of your overall portfolio? If you do, any kind of target you have in mind? Thank you.

Ezra Yacob: Yes. Paul, this is Ezra. There’s a lot there. So, let me try to dissect it piece-by-piece and we’ll get through the questions. I think the first one really centered around, in a downturn environment with a strong position company like ours, kind of buyback versus M&A opportunities. And, it’s a great question because we’ve talked about before how our company with the low cost of operations, the pristine balance sheet and our multi-basin portfolio, we’re really set up for counter-cyclic opportunities. And, it’s one reason we like to keep some excess cash on the balance sheet. The first thing I would say is, we don’t consider those things to be mutually exclusive. I think we’re focused on creating shareholder value and doing it in whatever way we think is the most optimal at the time.

I think the first quarter is a great example of this where we did buyback a significant amount of stock, roughly $800 million repurchased in shares, but we also were able to execute on a small bolt-on acquisition that really ticks off all of the criteria when we talk about M&A and some of the challenges with M&A competing internally for our capital. And, what I mean by that is and we should add, it’s not just M&A, I would say exploration opportunities as well. We consider them the same. We look at them through a returns focused lens and which one will generate the most returns for our shareholders, which is really competitive with our existing portfolio. If we look at the Eagle Ford as an example, this bolt-on acquisition that we did, it’s largely undrilled, it comes with very, very little PDP.

And so, the nice thing about it is, it competes for capital immediately. Even though at a corporate level, we’ve pulled back some drilling activity, we’re actually drilling on this acquisition this year. And so, it speaks to the quality and the addition of it. So Paul, in a downturn environment, I think that’s how you should be considering our ability to invest counter-cyclically and make the company better. With regards to the international investment in specifically Trinidad, I believe, was the second question. We’ve actually had pretty consistent investment there for a number of years. In Trinidad, while it’s an exciting program and we continue to see margin expansion there because the quality of the reservoirs and platforms that we continue to drill, I would point out that we do have partners.

So typically, the net impact is usually a little bit less than what we’re used to seeing with our onshore. But ultimately, when you think about the returns profile that those assets give to us, they’re very competitive with the portfolio. And, one of the things that really allows us to continue to have success there is the fact that we’ve had such a long relationship, long-term position in the country. We’ve been active in the Columbus Basin, as we talked about in the opening comments, for over 30 years. And so, it really comes back to our sub-surface knowledge and our operational expertise in the shallow water there, they continue to open up opportunities for us.

Operator: Your next question today will come from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold: Thanks. Ezra, you’ve given a pretty good overview on why you look to optimize your activity levels in light of the macro environment. But if there is a persistent weak oil market, but gas remains firm, how do you think about like capital allocation changing to more gassy areas like Dorado and maybe even targeting more of the gassy intervals in the Permian Basin?

Ezra Yacob: Yes, Scott. We remain very optimistic and very bullish on the long-term outlook for natural gas. Like I said in the opening remarks, we think ‘25 is an inflection point. You’re starting to see some of the LNG come online. I think LNG nameplate capacity is up 2.5 Bcf a day year-over-year already. We continue to see strong increases in natural gas for power demand. And ultimately, where we see ourselves even today here kind of in shoulder season with inventory levels at the five year average, very well-positioned to progress into the summer months and throughout the rest of 2025. As far as chasing inventory levels or commodity price, on gas, that’s never really been part of our focus, right, because we do recognize that while we see ‘25 as an inflection point and demand increasing, we do think gas, just by nature of how tied it is to weather, is that gas always has a bit of a higher volatility related to oil.

So, our most important focus with developing Dorado has been maintaining our low cost structure and making sure that we’re investing in that asset at the right pace so that we can continue to have value creation on the gas side through the cycle. By keeping activity going there, you can see that we’ve been able to increase our drilled feet per day by 15%. In recent times, we’ve made completed feet per day increase by 15% as well. And, you can see on our recent slide disclosure there the breakevens that we’ve highlighted there is we’ve driven the breakevens in Dorado down to the $1.40 level. So, we’re very happy with our progress there in Dorado. I think we’re investing in that asset at a pace commensurate with our gas takeaway position.

And, I’m not sure if we would lean in on that any more aggressively. It’s not a play where we want to get into a position where we outrun our pace of learnings.

Scott Hanold: Okay. Appreciate that. And yes, that $1.40 number was definitely a pleasant surprise to see. It’s pretty impressive. As my follow-up then too is, you did highlight cost improvements across your asset base. You talked about like Eagle Ford $1 per foot. The Utica dropped now below what you’d previously seen. In light of I’d say kind of some pushes and pulls with tariff risk on some costs, but obviously potentially some softer [OFS] (ph) costs and continued efficiencies. What do you think about 2026, and maybe any kind of thoughts on ‘27 in terms of like where do well cost trends go for EOG?

Jeff Leitzell: Yes, Scott, this is, Jeff. I mean looking out towards ‘26 and ‘27 right now with the volatility and the uncertainty with tariffs, it’s pretty tough to see exactly how that’s going to play out. What I would say is we feel really confident this year that first off, we’re not going to have any impact from tariffs and on our well costs. I think our supply chain teams have done an outstanding job of proactively purchasing an inventory in our necessary needs. And, we feel really good about where those costs are going to sit. We still think we’re going to be kind of at that low-single-digit percentage this year. But, what I will say about that is, I think it’s primarily going to be, as you talked about, be driven by the sustainable efficiency gains that we’ve seen.

When you’re looking at the drilling side, the EOG technology and the motors continues to push forward efficiencies. The longer laterals have had a big move and you can see us rolling that out across the portfolio. And then, even on the completion side, we’ve talked about just adding the horsepower. I mean, not only getting better well-performance out of it, we’re also getting better efficiencies. So, outward is really it’s tough to any kind of resolution, kind of beyond this year, but we feel really confident about where we’re at this year. And, if I look even too at service cost, just to give you a little color there, we don’t see a whole lot of pullback right now even from service costs. The high spec services that we use, we see that they’re still in pretty high utilization across the industry.

So, we’ll keep an eye on the market though and we’ll kind of evaluate any impactable pull-back and we’ll just look for areas that we can take advantage on the well cost side as we move forward.

Operator: Your next question today will come from Leo Mariani with Roth. Please go ahead.

Leo Mariani: Hi, wanted to just ask a little about more about the Dorado Play here. So, just kind of wanted to get a sense of kind of what the returns are on that asset, say, at kind of $4 gas, which is, I guess, fairly close to what strip prices are in 2026? And, what are the kind of the similar returns on some of the core oil plays, Delaware, Eagle Ford, let’s say, $55 oil. I was hoping you could just kind of do a little bit of a compare and contrast on the returns of those two assets here?

Ezra Yacob: Yes, Leo, this is Ezra. Yes, at $4 gas, you can see with the breakeven that we’ve talked about today, Dorado is very, very it’s a very compelling investment. The key, of course, is making sure that, that investment continues to have the high rates of return if we see a pull-back from that $4 strip, right? And so, it speaks again to investing in each of these emerging assets at the right pace to make sure from Day 1, we’re delivering low cost reserves into our portfolio. As far as comparing it to a $55, one way to look at it is on Slide 7, where we talk about our multi-basin portfolio in general. At $55 and $3 gas, we’re talking about $10 billion barrels of equivalence resource that delivers over 100% after tax rate of return.

So, at $55 in general, our oil plays have deliver a very competitive return as well. One thing to keep in mind, obviously, is across our portfolio of assets, those returns fluctuate with not only well cost but the shape of the curves and the type of reservoir that we’re talking about as well. So, it’s one of the reasons that while returns are still kind of the primary form that we evaluate our wells by, our consideration of what creates value has evolved. We begin with returns, but we really look at things like net present value. We look at returns of multiple price decks. We look at margin expansion and payback period and some other key metrics to make sure that we’re doing the best that we can to create value for our shareholders.

Leo Mariani: Okay. Appreciate that. And then just obviously, you guys made the decision to cut some capital out of the program here this year. Basically you’re kind of flattening out oil for the rest of the year here. But, just with respect to kind of some of the timing, is that $200 million of CapEx and activity reductions kind of more in the second half of the year? And then I guess presumably could there be a bit more production impact in 2026? And, you also mentioned tariffs don’t impact 2025, but would you guys have exposure there in 2026?

Jeff Leitzell: Yes, Leo, this is Jeff. Yes, the majority of the $200 million I mean, it’s really kind of spread through the rest of the year. I mean, obviously, with the full second half still out there, the majority of it is in the second half of the year. And, what I’d really kind of point out about how we pulled back and I think Ezra really hit on it is, we’re really focused more on our more active areas, the Delaware Basin and the Eagle Ford. And, the reason is we’ve got plenty of activity there. They’re kind of finely oiled machines I would say and these plays can continue to drive the improvements in the efficiency gains that we’ve seen. So, that’s really where we pulled back about 15 wells there in the Delaware and 10 less in the Eagle Ford.

And then, the real focus is maintaining our activity in our emerging plays, basically the Utica and the Dorado. So, no changes with those at all. We’re still going to have 20% more completions in both of those. And when looking at the Utica, we’ll end with two full rigs and one frac fleet. Then in Dorado, we’ll maintain that one rig. And then lastly, on the international front, just to kind of round it out so you know, there’s no changes there. We’re going to still execute on our Mento program down there in Trinidad and continue building the Coconut facility. And then in Bahrain, no changes on the exploration side there. And then when we built this plan, we strategically put it together and optimized it to make sure we had a lot of flexibility heading into ‘26.

So, we don’t expect any effects on capital efficiency or our ability to execute on really a wide range of potential plans in ‘26. So, we’ll just have to see how the macro plays out before we have any more commentary on where we go for ‘26.

Operator: And, your next question today will come from Derrick Whitfield with Texas Capital. Please go ahead.

Derrick Whitfield: Good morning, all, and thanks for your capital discipline leadership. From a CapEx perspective, you highlighted flat service prices for high spec equipment in your prepared remarks and an earlier question. If we were to experience a more protracted period of depressed prices in the low-50s, could you broadly speak to your views on service prices in that environment and the structure of your service contracts as they stand today?

Jeff Leitzell: Yes, Derrick, this is Jeff. It’s hard to tell. Obviously, there’s a certain point where it will break over and you’ll have enough activity that drops off on the high spec services. I don’t exactly know where the line on the sand is with that, but obviously we’ll keep an eye on it. We’ll watch how the market evolves and we’ll be consistently working with our suppliers and rebidding to make sure that we have the ultimate flexibility and we can take advantage of any kind of pricing drops there. So, as far as flexibility though, the great thing about it is we built a lot of flexibility into what we have contracted in our agreements out there with our service providers and really don’t have any issues with either stepping up or stepping down activity.

I think we’ve kind of demonstrated that in the past with multiple times when we’ve been able to manage activity and move. And, I think that’s one of the great benefits as we’ve talked about our multi-basin portfolio and the consistent returns around it that we’re able to really move activity very, very quickly and have a lot of flexibility with all those agreements.

Derrick Whitfield: Great. Regarding gas marketing, we’re continuing to see demand outlets along the Gulf Coast, with Woodside being the latest LNG project to reach FID. As you look out beyond 2027 on Slide 10 of your 1Q earnings deck, how are you broadly thinking about the amount of exposure you’d like to have in the LNG markets versus domestic markets?

Jeff Leitzell: Yes, Derrick. Appreciate the question. Yes, I’d say we’ve done a great job being a first mover kind of lining up our gas sales agreements to first be able to get our gas offshore and then second be able to expose ourselves to kind of a portfolio of different pricing mechanisms. As you mentioned, Slide 10 illustrates some of those different mechanisms where we have some sales that are Brent linked, some sales that are linked to JKM and then some that are straight to Henry Hub. So, I’d continue to think about it that way. We have structured each of our agreements to be a gas sales agreement. So, we FOB stateside there. We don’t take any risk overseas or have any gas on water or anything like that. And, we would look to continue to be more than likely counter-cyclic when looking for opportunities to step into favorable contract negotiations.

The two things that we continue to focus on is exposure of our gas to get it offshore. And then, the second thing is to continue to expose ourselves to diverse pricing indices. That’s the biggest thing is that being able to be exposed to different prices with low cost gas at the right time because as the world becomes a little bit smaller with respect to LNG and North America continues to get our LNG offshore, you’re going to have the opportunity to be exposed to global arbitrages wherever they may occur. And, having your gas there and exposed to the pricing indices at that time is the only way to capitalize on it.

Operator: And, your next question today will come from Scott Gruber with Citigroup. Please go ahead.

Scott Gruber: Yes, good morning. We’ve always thought of Trinidad as primarily a gas play, but you discovered oil at Beryl. What’s your view of additional oil opportunities around Trinidad? And, are there any other oil targets in the exploration plan?

Jeff Leitzell: Yes, Scott, this is Jeff. Primarily, Trinidad obviously has been more gas than oil. But what I will say is at least on this prospect with Beryl, we knew going into it that there was a potential of an oil bearing target there. I think the questions really were just how prolific it was going to be and whether or not it was going to be large enough to be economic. So, obviously, whenever you’re looking at gas and oil, there’s several geologic factors that really influence that, whether it’s a depth, a source rock, the position within structure. But ultimately what we really use to identify this is just the advanced seismic tools, to really see the accumulations and try to really tell whether it’s gas or oil.

And then, what we ultimately did is confirm the fluid type from an exploration aspect. So, what I’d say is on this particular prospect, we did have a good line-of-sight that we did have an oil bearing sand, and we’ll continue to look for those opportunities as we move forward. And, we feel obviously there’s still a lot of upside as Ezra has talked about in the future just with our shallow offshore expertise there in Trinidad and a lot of our very aligned partnerships down there. We think there’s going to be a lot of additional entries that we can have to continue to explore additional gas and oil opportunities.

Scott Gruber: I appreciate that. And then, turning to OpEx, cash costs be here in 1Q, you flex down your full-year guide. Can you provide some color on what drove the beat in 1Q? And, just given lower oil prices, is there more to go on potentially reducing OpEx even further?

Jeff Leitzell: Yes, Scott, this is Jeff again. I think there is still a lot of room to go because just like on our well cost, OpEx is no difference. We’re continuing to drive forward and look for ways to optimize there and get more efficient and that’s really what our teams are doing. So, just a little bit of color on the variance there from an expense standpoint. On the LOE side, yes, we were a little bit lower in forecast in Q1, had a little bit of volumes beat there, but really we just had some lower workover expense across our divisions. And that really carries through also to our full-year guide there where we’ve got some less labor costs and workover expense. And, that’s really just due to the strong base production and less downtime we’re seeing across the portfolio.

And, a lot of that has to do obviously with our teams in the field, but it also has to do with the technology that we utilize and we deploy out there with our control rooms and as we’ve talked about some of the optimizers. Continuing on GP&T, we were a little higher there in the first quarter, but nothing really out of line. And then, full-year obviously is down a little bit just because of some anticipated compression related costs. And also, you see with gas prices being a little bit reduced, we potentially could see some fuel savings there on the GP&T side. And then lastly, I just hit on maybe G&A. We were just few little minor cleanup things there. We were a little lower in the first quarter on headquarter benefits and then full-year right now, we’re really just looking at a decrease in overall employee related cost and headcount.

We’re just not needing to add as many people just with how efficient the company is running at this point in time. So, really happy with how things are rolling up for the year and we’re continuing to look for ways to drive down those operating expenses.

Operator: Your next question today will come from Neil Mehta with Goldman Sachs. Please go ahead.

Neil Mehta: Hey, good morning, Ezra and team. Just two quick ones here. The South Texas Eagle Ford bolt-on, its building out looks like an incremental 30,000 acres here. So, just talk a little bit about it, what brings to the table and how you’re thinking about that?

Keith Trasko: Yes, good morning, Neil. This is Keith. We feel it’s a great transaction for EOG. We’ve been active in the Eagle Ford for 15 years now. So, we’re very familiar with the acreage held and what’s available in the area. This essentially was a hole in our acreage and it’s the largest remaining block of largely undeveloped core Eagle Ford acreage out there. So, there was strong stakeholder alignment between both parties, so we were able to transact on the block. What we love about it is that it immediately competes with our existing portfolio. We have drilling activity that’s going to be going on there this year. We’re very familiar with the geology of the area. We have geologic data, seismic well results on both sides of the acreage.

We understand the area very well. It’s nearby EOG gathering systems and infrastructure. So, you’re talking about less indirect dollar investment that’s needed in there. The block itself is very well set up for long laterals. So, the transaction itself adds 123 mile locations. And, it also allows us to extend wells that we had previously planned on our former acreage footprint. So, there’s 35 of those wells that we’re able to increase by one mile on average. We also love that it has a high net revenue interest. And so overall, yes, it’s a 30,000 net acre position. The PDP that is on it is fairly modest. It’s $2,000 to $3,000 Boe per day. 85% of that is oil, but we do have to do some facilities upgrades on those wells to get them kind of up to EOG spec.

So, that oil is not coming on until later in the year and it’s not a material effect on our plan. So overall, we’re very happy with the transaction. This adds to our long and successful track record of adding low cost resources across the multi-basin portfolio, including foundational assets like the Eagle Ford. So, the acquisition is a great example of the type of bolt-on deals that we look for and it was underwritten by a high-return threshold. It adds duration to a world-class asset and the transaction creates great value for the shareholders.

Neil Mehta: Thank you. That’s helpful. And then, as we’ve been through down cycles before most notably 2020 although that was an extreme. But, if you look back to that experience in the oil sell off that we had five years ago and if in a scenario where things get materially worse on front month oil which is not our base case but it’s certainly in the realm of possibility here over the next couple of days. What are the lessons that you learned from your 2020 experience that you would carry forward here, things like maybe having a little bit more capacity to buy back stock counter cyclically than you did back then or be more aggressive on them from an M&A perspective. Just your own perspective of how that experience could inform the future experience if things go wrong way?

Ezra Yacob: Yes, Neil, it’s a good question. It’s a little bit of what we can do today, but it’s really how we built the company over the last few years. It’s the low cost structure that we have. It’s the way that we contract with our agreements to allow us to have flexibility to move equipment between basins or even slow down our activity if we need to. It’s the strong balance sheet, as you said. It’s the cash on hand and the low total debt that we keep. And, we’ve talked about our total debt versus EBITDA target of being less than 1 times at bottom cycle prices or $45. Those are the things that we continue to do to position the company opportunities. The biggest thing about looking at the downturn before is the first thing is protecting your free cash flow and being able to protect your cash return to your shareholders and being committed to capital discipline.

I think we’ve taken a big step in that today in letting our shareholders recognize that especially on the coming off of such a strong first quarter that we are focused on being capitally disciplined and that it is a core pillar of our value proposition. The second thing I would say is that we can take out of 2020 is that we do have an advantage to look for some counter-cyclic opportunities. In 2020, as you recall, that’s when we were able to put together some of the acreage in these exploration opportunities that we’re developing today as emerging assets. We were also able to counter-cyclically purchase some pipe that was able to go into the ground as part of our Dorado gas sales strategy. And back then, we did a number of small bolt-on acquisitions that added some 25,000 acres, if I’m recalling correctly, in the Permian Basin.

So, those are the type of opportunities we look at, but it’s really about all the decisions you’re making on a day-to-day basis of how you want the company to be positioned, what’s important to the company’s value proposition and how your management team executes on that. That’s going to determine how flexible or how advantageous you can be in times of a pullback or a downturn.

Operator: Your next question today will come from Charles Meade with Johnson Rice. Please go ahead.

Charles Meade: Good morning, [Ezra] (ph) to you and your whole team there. I wanted to pick up the discussion thread on barrel a bit more. You guys, I think it was Jeff who mentioned that you weren’t sure whether you’re going to get oil or gas there. But, I wonder if you could talk more about how this 125 feet that you saw came in versus pre-drill and whether that’s one zone or two zones or anything you care to share along those lines? And then, also can you give us a sense what the major steps towards FID are or will be? And should we be thinking 2,000 barrels a day net or 20,000 just order magnitude?

Jeff Leitzell: Yes, Charles, this is Jeff and thanks for the question. Well, the first thing I’d preface is obviously it’s real early in this. So, there’s not a lot of information, but as you said, it’s about 125 foot of consistent oil bearing sands and it was in about 170 foot of water. And the thing right now is we’re currently really refining all of our reservoir models to really understand the ultimate size of the prospect. And then also we’ve got our operations teams. They’re working through a lot of the other decisions like facility size, the specs of the platform and finalizing our completion and production design. And then, also I’d say the economics on our initial estimates that we talked about, I mean, it definitely justifies setting the platform.

So, to move forward into the FID side of it, we’re really just engaging with the partners and getting to a final decision from that aspect. So, I mean, we’re obviously really excited about the discovery, but I’d like to reiterate it is still early. So, we’ll continue to kind of assess it. And then once we do work closer to that FID and work through it with our partners, we’ll have a lot more detail to be able to share with you then.

Charles Meade: Okay. That makes sense. And then, my follow-up on the Eagle Ford bolt-on, that looks like a great deal for you guys and it kind of seems like it’s maybe the unicorn left in the play with that big undeveloped position. Also but it looks different from a lot of the other deals we’ve seen in the Eagle Ford lately, which have been more PDP focused. Obviously, you guys paid a good amount for locations, but they’re fabulous locations. So, my question is, are there other deals like this out there? And is this the kind of thing that we should be expecting more from EOG either in the next year or in the next 18 or 24 months?

Keith Trasko: Yes, good morning. This is Keith. I’ll address the second part of your question first. I mean, we are always looking for bolt-on acquisitions, but they really need to compete with the existing portfolio and on a returns basis and on several of the other metrics that Ezra talked about. This one just really checked all the boxes and as you noted, it is largely undeveloped and it’s a fabulous piece of acreage that we are really confident in because we have results and data on all sides of it. I think that any we will always be looking but I wouldn’t expect something to be quite this large and undrilled as far as any future bolt-ons.

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

Ezra Yacob: Yes. Thank you for joining us today. I would just like to thank 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.