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F500-2021-185-EOG Resources

Founded in 1999 after a split from Enron Oil &amp; Gas, the Houston company specializes in procuring, producing, and marketing petroleum and other natural gases.

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EOG Resources (EOG): Company Profile, Stock Price, News, Rankings

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EOG Resources

eog resources

Good day, everyone, and welcome to EOG Resources Second Quarter twenty twenty five 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. Pierce Hammond. Please go ahead, sir.

Good morning, and thank you for joining us for the EOG Resources second quarter twenty twenty five earnings conference call. I'm Pearce Hammond, Vice President, Investor Relations. An updated investor presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward looking statements.

Factors that could cause our actual results to differ materially from those in our forward looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call may also contain certain historical and forward looking non GAAP financial measures. Definitions and reconciliation schedules for these non GAAP measures and related discussion can be found on the Investor Relations section of EOG's website. In addition, some of the reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and Chief Executive Officer Jeff Leitzel, Chief Operating Officer Anne Jansen, Chief Financial Officer and Keith Trasko, Senior Vice President, Exploration and Production. Here's Ezra.

Thanks, Piers. Good morning and thank you for joining us. EOG delivered another quarter of outstanding results, reflecting the focused execution of our employees across our multi basin portfolio. In the second quarter, oil, natural gas and NGL volumes came in above the midpoint of our guidance. At the same time, we drove our capital expenditures, cash operating costs and DD and A below guidance midpoints, demonstrating the efficiency and operational excellence that is a hallmark of EOG.

Our teams continue to find ways to optimize operations, improve well performance and safely deliver volumes while maintaining capital discipline. Strong operational performance once again translated directly into impressive financial results. We generated nearly $1,000,000,000 of free cash flow during the quarter and between our regular dividend and $600,000,000 of opportunistic share repurchases, we returned more than $1,100,000,000 to our shareholders. Consistent with our long standing cash return commitment, we have committed to return at least $3,500,000,000 in cash during 2025, inclusive of our regular dividend and nearly $1,400,000,000 of year to date share repurchases, reflecting our confidence in the growing value of our business. Our confidence in the future of the company is also reflected in the 5% increase in our regular dividend, which we announced in connection with the nCino acquisition in May.

This marks another step forward in our remarkable dividend growth track record. Over the past decade, we've increased our regular dividend at a 19% compound annual growth rate, far outpacing the peer group average. More importantly, we've never cut nor suspended the dividend in twenty seven years. This sustained record of dividend growth highlights both the durability of our business and our unwavering focus on delivering shareholder value. Last week, we closed the accretive Encino acquisition, marking a major milestone for EOG.

With a total core acreage position of 1,100,000 net acres and associated resource potential net to the company of two plus billion barrels of oil equivalent, the Utica has become a foundational EOG asset alongside the Delaware Basin and Eagle Ford. In aggregate, EOG has net resource potential totaling over 12,000,000,000 barrels of oil equivalent across our multi basin portfolio. This top tier resource base generates a greater than 55 average direct after tax rate of return at bottom cycle prices and over 200% after tax rate of return at mid cycle prices, providing our investors one of the deepest and highest quality inventory positions. We are focused on the safe and rapid integration of the nCino assets into our portfolio. We remain highly confident in the value creation opportunity before us in The Utica and believe that through effective integration and the application of EOG's operating model and proprietary technology, The Utica will be a major contributor to both growth and returns.

We look forward to sharing more as we capitalize on the advantages this transaction brings to shareholders. On the international front, in the second quarter, to explore and appraise an approximately 900,000 acre unconventional oil exploration prospect in The UAE. We are very excited about this new opportunity that will allow us to leverage our technical expertise and extensive data set from drilling thousands of unconventional wells across a wide variety of plays. The UAE and our BAPCO joint venture in Bahrain form an exciting long term business opportunity for EOG in The Gulf States. Our results through the 2025 serve as a powerful affirmation of EOG's enduring value proposition.

We're committed to being among the highest return, lowest cost producers, recognized for leading environmental performance and a steadfast role in meeting the world's long term energy needs. Four pillars underpin our differentiated strategy: capital discipline, operational excellence, sustainability and culture. As we look at new opportunities in our portfolio from the Encino acquisition to the expansion in The Gulf States, we believe operational excellence will be a key differentiator to enhance returns as we utilize our in house technical expertise, proprietary information technology and self sourced materials to drive superior well performance and reduce costs. Turning now to supply and demand fundamentals. While first quarter oil demand was stronger than forecast and second quarter oil demand also benefited from delays in the implementation of tariffs, growth in demand for the 2025 is expected to moderate before beginning to increase throughout 2026.

On the supply side, we expect spare capacity returning to the market to allow inventory levels to build from historically low levels. This reduction in spare capacity coupled with current demand forecasts paves the way for pricing to strengthen on the back of a more fundamentally driven market. On natural gas, 2025 is an inflection year driven by an uptick in U. S. LNG feed gas demand. We expect a 4% to 6% compound annual growth rate for U.

S. Natural gas demand through 02/1930, driven primarily by LNG and power demand. Our investment in Dorado to develop a standalone gas asset that complements our oil assets has EOG prime to deliver supply into these growing markets. EOG is better positioned than ever before to create value for our shareholders. Our portfolio expansion, including Encino, The UAE, Bahrain and additional exploration opportunities is adding significant new resource potential for our shareholders, while we simultaneously continue to improve and expand our existing resource through applying technology to reduce costs, improve well performance and unlock additional well locations.

And at the same time, delivering robust cash return to our shareholders and maintaining a pristine balance sheet, for continued investment in high return projects, generating strong current and future free cash flow. Now here's Anne with a detailed review of our financial performance.

Thanks Ezra. We delivered another strong quarter with adjusted earnings per share of $2.32 and adjusted cash flow per share of $4.57 Second quarter free cash flow was $973,000,000 We provided robust cash returns to our shareholders in the second quarter anchored by our sustainable regular dividend of over $500,000,000 and complemented by share buybacks of $600,000,000 In the second quarter, in connection with our nCino acquisition announcement, we declared a 5% increase in our regular dividend. The new indicated annual dividend rate is $4.8 per share, which is a 3.5% dividend yield at our current share price, far in excess of the average dividend yield for the S and P five hundred. Regarding future cash returns, we expect to return a similar level of free cash flow as we have the last couple of years. We continue to favor buybacks as a source of additional cash return beyond our regular dividend and will monitor the market for opportunities to step in and repurchase shares.

Since initiating buybacks in 2023, we have repurchased over 46,000,000 shares, which is approximately 8% of shares outstanding or a total of $5,500,000,000 We have $4,500,000,000 remaining on our buyback authorization. In May, we announced the $5,600,000,000 acquisition of nCino, which was funded at closing on August 1 with cash on hand and debt. On July 1, we issued $3,500,000,000 of senior notes with proceeds directed towards the nCino acquisition. This issuance consisted of four tranches $500,000,000 due in three years, dollars 1,250,000,000.00 due in seven years, 1,250,000,000.00 due in ten point five years and $500,000,000 due in thirty years. The weighted average maturity of the senior notes is approximately eleven years with a weighted average coupon of 5.175%.

We were extremely pleased with the investor response to the notes offering as it demonstrates their confidence in EOG's long term outlook. Our updated guidance reflects ownership of nCino for the five remaining months of 2025. At assumed prices of $65 WTI and $3.5 Henry Hub, we expect to generate 4,300,000,000 in free cash flow in 2025, which adjusted for commodity price changes is 10% higher than our forecast last quarter. This higher free cash flow reflects not only the nCino acquisition, but also modest efficiency gains and lower cash taxes due to recent tax legislation. The last few months have been transformational for EOG and the company is exceptionally well positioned from a balance sheet and cash generation standpoint to further reward shareholders in the future. Now here's Jeff to review operating results.

Thanks, Ann. Let me begin by thanking every member of our team for the outstanding execution across the organization this quarter. Your dedication and diligence were especially evident both in our core operations and in preparing for the successful acquisition and the work on integrating nCino. This marks another quarter where our operational excellence was a driving force, positioning us to capture new opportunities and deliver meaningful results for our shareholders. Our performance in the second quarter stands across nearly every operational metric.

Once again, we outperformed both our production and cost expectations. Oil, gas and NGL volumes exceeded forecast powered by continued momentum across our foundational assets. Additionally, we saw better than expected gas and NGL volumes in the Powder River Basin. Cash costs were below the midpoint of guidance. Lease operating expense was the largest contributor with beats across all basins.

This was a direct result of enhanced efficiencies and workover execution and overall lease and well maintenance. The incremental barrels associated with our volume beat further supports lower unit costs underscoring our operational leverage and the collective impact of strong execution throughout the organization. On capital spending, we delivered lower than expected capital or CapEx this quarter, primarily driven by efficiency gains across our operating areas as well as the deferral of some indirect spending into the back half of the year. We're seeing the benefit of careful planning, disciplined execution and real time efficiency measures that are translating directly into tangible savings. With the closing of the nCino acquisition just a week ago, we have updated our twenty twenty five CapEx and production guidance to include nCino's planned activity for the last five months of 2025 and the underlying improvements in our business.

Our new full year 2025 CapEx guidance is $6,300,000,000 with forecasted full year average oil production of 521,000 barrels of oil per day and average total production of one million two and twenty four thousand barrels of oil equivalent per day. Relative to the midpoint of our guidance last quarter, full year 2025 CapEx is increasing by 5%, while full year 2025 average daily total production is increasing by 9%. Our operating teams are working swiftly and efficiently to fold the nCino team into the EOG organization. The initial transition is progressing better than anticipated and we're highly encouraged by the early collaboration between teams and the utilization of technology to increase data integration both in the office and across the field. Looking at our pro form a Utica activity, we are layering Encino's activity on top of our existing program and we plan to run five rigs and three completion crews in the basin through the remainder of the year.

This temple will maximize value for Encino's high quality acreage while leveraging the best practices and technical expertise from companies. We expect at least $150,000,000 in annual run rate synergies within the first year post close. These savings are largely attributed to well cost with a smaller contribution from targeted G and A reductions. For context, EOG's average well costs in The Utica are less than $650 per foot compared to Encino's $750 per foot. We see clear line of sight to bring well costs in line with EOG's leading edge D and C cost quickly and efficiently.

We're optimistic about the upside potential as our teams begin to work on the Encino assets and apply EOG's operational model. We see incremental opportunities from further optimizing location construction costs, enhancing infrastructure utilization, optimizing marketing agreements and deploying innovations from in basin sand to advanced water recycling and evaporation technologies as well as employing our optimizer technology on the combined production base. We are confident in our ability to unlock additional synergies and drive sustained value creation. In our investor deck on slide eight, we highlight just how attractive The Utica is and why we are excited to add this play to our current foundational assets, the Delaware Basin and Eagle Ford. With just 50 plus net wells developed in The Utica, we are already realizing payback periods less than a year driven by low total well costs and highly productive results.

While it's too early to discuss specifics on 2026 plans, The Utica is now part of our foundational operating areas and we will continue to invest at a pace to improve the asset. Turning to Dorado, our high intensity completion designs are continuing to deliver superior results with individual well production outpacing our forecast. The team is also continuing to drive efficiencies through success with the EOG drilling motor program and most recently by eliminating a string of casing in many of our Austin Chalk targets. This has helped to increase drilled feet per day by more than 20% in the first half of the year versus 2024 and reinforces our view of Dorado as the lowest cost dry gas asset in The U. S.

We expect our Dorado production on a gross basis to reach approximately seven fifty million cubic feet per day exiting 2025. With our Verde pipeline in service, which has a one Bcf per day capacity and is easily expandable to 1.5 Bcf per day, our Dorado asset is well positioned to capture incremental gas demand in 2026 and beyond. Focusing on the Eagle Ford and Permian, our teams continue to push extended laterals and are realizing the benefit in both efficiencies and well cost. In the Eagle Ford, we drilled the longest lateral in Texas history in the second quarter. The Whistler E5H had 24,128 feet of treatable lateral or nearly 4.6 miles.

In the Permian, we have increased our average lateral lengths by over 20% year over year and this has helped us realize a 10% increase in drilled footage per day versus 2024. These are just a few examples of how our teams are focused on driving sustainable efficiencies to lower well cost further enhancing returns. With regards to well cost, as activity levels have moderated across the industry, we're now seeing some softening in the service cost environment, more so for lower quality equipment. As a reminder, we focus on contracting high quality crews and equipment where pricing has been more stable. As we turn to the back half of the year, we will look for opportunities within our current services to take advantage of any potential softening in the market with a focus on retaining top tier high spec services to continue to drive operational efficiencies.

We continue to advance our business through technology and I'm excited to discuss two new proprietary technology platforms for EOG. The first platform uses high frequency sensors that captures and processes subsurface data while drilling wells. These sensors allow us to calculate geomechanical rock properties, identifying faulting, local stresses and also monitor downhole equipment performance to minimize downtime. Also, we are able to improve our completion designs through fracture identification, minimizing our frac maximizing our frac efficiency within the zone of interest. By integrating this high resolution data with our traditional data sets, we've achieved improvements in well performance and cost efficiency.

This year over 50 wells have already benefited from this higher resolution data and and we will look to expand its use across our portfolio. The second platform centers on our enhanced AI capabilities. Building on years of utilizing machine learning for production optimization and cost savings, we have now deployed our proprietary generative AI system. This platform is already enabling field and division staff to collaborate more efficiently, automate and capture data more easily and gain operational insights across all operations. After a strong first half of the year, EOG is well positioned to execute on its full year plan and we are excited about the opportunities in front of us.

Now I'll hand it back to Ezra to wrap it up.

Thanks, Jeff. Let me highlight a few key points from the second quarter. First, our team delivered outstanding execution with operational results exceeding expectations. Second, our strong operational performance translated directly into impressive financial results and strong cash returns. Through the first half of the year, we have committed to return more than $3,500,000,000 of free cash flow to investors through our regular dividend, which we have increased by 5% and through share buybacks.

Third, with the Encino transaction now closed, we are updating our 2025 guidance to reflect both the expanded portfolio and momentum across the basins. We are confident in the transformative impact of the Utica, which we believe will serve as a foundational asset for years to come. In addition, we are excited about our ongoing exploration efforts, both domestic and especially in the new international concessions we've captured this year. Fourth, looking ahead, our performance in the 2025 reflects the enduring strength of EOG's value proposition, capital discipline, operational excellence, sustainability and a high performing culture. Our business is better positioned than ever to create value for our shareholders.

Thanks for listening. We'll now go to Q and A.

Thank you. The question and answer session will now begin. It will be conducted electronically. You.

The first question is from Arun Jayaram with JPMorgan. Please go ahead.

Yes, good morning. My first question is on the Utica. Ezra, when you provided the acquisition deck, you highlighted, call it, pro form a production at two seventy five MBOE per day for both EOG and Encino. My question is if you could talk about the sustaining capital requirements to sustain that level of production from a capital or activity standpoint? And would you expect a, call it, five rig, three completion crew cadence to deliver growth from the Utica?

Yes. Good morning, Arun. Thanks for the question. So you're right. We are very excited that we were able to close a little bit earlier than anticipated.

As you mentioned, we closed last week. And so with regard to pro form a sustaining capital, for the rest of this year, we are layering on top of our activity levels, the ongoing Encino plan. But to be honest, I think it's going to be just a little bit early for us to kind of lean in on what the activity looks like. We do have lower well cost than Cino and dominantly that's not necessarily contracts that's dominantly from operational efficiency gains. And so there should be a little bit of incremental synergies and savings with regard to that.

But ultimately when it comes to our sustaining CapEx, we'd like to get in there and operate the asset for just a little bit longer than a week. In the first rollout, we've already seen, as we brought the asset in house, when we started to roll out some of our technologies, things like our production optimizers as a matter of fact, we've actually already started to see a lot of upside that we can capture in the field. And so I'd hate to speak a little bit too early. What I will point out is last November we released our sustaining capital for what I guess now would be kind of legacy EOG and that capital range was about 4,300,000,000.0 to $4,900,000,000 And that range is something important to think about because it for a multi basin company like ours that has not only oil and associated gas, but also standalone gas assets, maintenance capital is a little bit difficult to pin down. And what I mean is, are we talking about just keeping oil volumes flat or natural gas volumes flat?

Are we still investing in exploration and things of that nature? And the new Utica asset falls right into that. As you know, we're very focused on the volatile oil window, which really drives the returns for us. But that asset does come with a very attractive dry gas position, which gives us a great option as the demand increases there. And so really thinking through where our investments are, what the macro environment looks like, that's going to be kind of the more important thing that will contemplate how much we invest and what the activity levels would be.

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

Yes, fantastic Arun. We couldn't be more excited about this concession in The UAE. This is actually a reservoir that we've been working on for a number of years really. And the path to getting commercial contract terms that kind of work for everybody and getting stakeholder alignment really came together here in the last twelve months. So it's shale play.

It's a carbonate shale, maybe similar geologically in some regards to the Eagle Ford Play. It has been drilled and delineated both vertically and horizontally throughout the basin, not throughout the entire basin, but throughout a portion of the basin where our concession is. And so we've got good geological data on it. We don't have significant production data. They have tested oil to the surface.

But that is something that we think we can improve upon with the combination of our data set from the North American unconventional plays, our petrophysical models, our combination of log and core data, but then also combining that with our understanding of geomechanical properties and how horizontal completions really match up with the landing zones that we target. I would say the challenge that we have in front of us, is not necessarily on the geologic side. It's going to be more on bringing an international unconventional play up to scale. I think everyone has seen that what really makes these plays attractive and what makes them work is, having your infrastructure, your supply chain, your logistics worked out. That's really scale is important in each of these plays and we certainly have the exposure to scale here.

But as an initial large scale unconventional resource play in UAE, that's the one that we'll be focused on is how quickly can we get the production uplift that we think from our applying our techniques, but then also how quickly can we drive down those costs.

The next question is from Steve Richardson with Evercore ISI. Please go ahead.

Good morning. Thanks. I was wondering if you could talk a little bit about how you think about the gas market, Ezra, and your marketing strategy. I mean, we're seeing counterparties willing to sign what seems to be multiyear contracts. You seem to be accepting of where the market is on the demand outlook being really robust here.

So how does that play into how you're thinking about your marketing strategy? Are we likely to see EOG enter into those types of contracts now that you've got the Utica dry gas volumes that you just mentioned in house? Like are you likely to do that? Or are we likely to see more of the same of you just being really thoughtful about what markets you want to get your gas to and continue to realize really high realizations?

Yes, Steve. It's a great question. It's very topical right now because I think everyone's seen the increased demand for natural gas coming not only from power, which is maybe a little bit more of what you're referencing, but also just LNG in general. And like I said in the opening remarks and we've been saying for a while, 2025 is kind of the inflection point on that. So, I like that you pointed out, we have two kind of dedicated gas assets and that's where some of these agreements begin with, whether it's LNG or power demand.

Because when you're making these long term commitments, I think what we've seen in discussions with LNG and discussions with hyperscalers is sometimes that's a little bit difficult to get comfortable with a ten or fifteen or twenty year agreement if you're only talking about associated gas. And so right off the bat, this tremendous gas business, if you will, that we've built internally to EOG and alongside our oil business is very well positioned to service that out of Dorado and the Utica. I do think we'll continue to be thoughtful. I appreciate how you phrase that. I think what we look for with any marketing agreement is we start with good partners.

We look for agreements that align all the parties involved, so good stakeholder alignment. And then we're always focused on getting exposure to premium pricing. Just signing up a takeaway for essentially a differential based or a pricing mechanism that includes a differential. There's some value there to have diverse markets. But really when we what we think we've captured is assets that can deliver low cost consistently, to these projects.

And so I think we deserve to be paid, at least a bit of a premium to that. As we've done with our LNG terms, we like the diversity of different pricing mechanisms and we can get creative with that. But yes, Steve, as we look at some of these opportunities, whether it's hyperscalers or increased LNG, we think we're very well positioned to capture the upside with either of our two assets.

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

Yes, Steve. This is Jeff. Yes, we really we're excited to get our marketing team up there because I think that's really where we're going to make the most headway so they can start working on the asset and that Utica production. We have a superb track record of improving the realizations over time in all of our assets and that's going be our primary focus when we get up there. So I think one of the big things that we need to look at is the differentials in the area.

Obviously, they are slightly more narrow than what EOG consolidated are, the Encino was. So what that really just reflects is the wider Utica oil disks versus kind of our legacy stuff. I mean when you look at the Eagle Ford and the Delaware where we've been operating for quite a while, a really good example of how we can improve that is I mean take a look at the Delaware. I mean over the last decade I think we've improved our old differentials close to $6 So we definitely got a track record of being able to do that. And then with any play, I think with time and maturity, we'll be able to improve those differentials, especially with the scale that we get from acquisition.

And then one last thing that I just point out, I talked about a new slide in our deck in our opening remarks, Slide eight. And, what that shows is it shows the Utica payout period and it's about nine point three months, which is right with the Permian. And what I'd say is that all of this is actually built into that, all of the diffs and the other operating expenses. So that's in the metrics and it's obviously extremely competitive within the portfolio and other conventional plays. I'd say another place that we can really move the needle is going to be on the GP and T side.

Obviously, primarily we'll work with our midstream providers up there who will make sure we're capturing better rates, both in the Utica as well as we'll utilize our position in our multi basin portfolio. The Utica, we've got fantastic long term relationships with the midstream companies that are up there. So ultimately our goal will be to really seek for win win deals for both parties. And over the last handful of years just the 50 wells or so that we've drilled there in the Utica, we've had great success in lowering the GP and T cost in a short period of time. So as I said, same with the diffs.

With this kind of scale and the larger footprint, we really think that's going to help out a lot. Another few notes just to kind of take into account, I mean with the increased GP and T that we have with the asset, it's offset really by, the LOE, the G and A and the DD and A, if you look at it. They're actually quite a big reduction across the board there. And then also, just keep in mind that some of the increases in GP and T really reflects the firm gas transportation that we got from Encino, which that firm transport moves Utica gas to premium markets really resulting in much higher price realizations. And then lastly, just Ohio as a whole, they're an outstanding place to do business and very, very friendly from that aspect.

And the Utica taxes other than income we call it TODI, they're actually lower than the average of EOG's multi basin portfolio. And that right off the bat really helps offset some of those higher diffs in GP and T. So I think we've got a long runway and we'll have a lot of improvement when it comes to the marketing strategy up there in the Utica.

The next question is from Neil Mehta with Goldman Sachs and Company. Please go ahead.

Hey, good morning, Ezra and team. Thanks for all this. I just want to start off on cash tax benefits with changes in legislation.

You indicated that it's supporting the free cash flow, but can you help us quantify the impact over the next couple of years?

Yes. Thanks, Neil. This is Anne. The recent tax legislation is going to help us out. The one big beautiful bill has some positive impact for EOG.

The bill restores 100% of the bonus depreciation permanently and additionally restores 100% deductibility of the research and experimental cost again permanently. For 2025, the impact of the One Big Beautiful bill for EOG is approximately $200,000,000 and we expect that amount to be a recurring benefit in future years. So penciling $200,000,000 in is reasonable. Always keep in mind that there are numerous variables that can impact our tax rates and our profiles in any given period. But we expect that kind of a $200,000,000 is kind of going to be a run rate for the next couple of years.

Yes. Thanks, Ann. And then Ezra, just I always value your views on the oil macro and you guys have been rightly cautious here. Just your perspective about the how the balances build through the balance at the back end of the year and into 2026 on the crude side in particular, a lot of moving pieces particularly around Russia right now, but your perspective, from your Market Intelligence Group would be great.

Yes, Neil. Yes, it's very topical right now. There are a lot of moving parts as you discussed. And I'm not sure with regards to Russia or India, I'm not sure if anyone knows exactly how that's going to play out. But the data that we do have in front of us shows that if I start on the demand side, as I said in the opening remarks, demand in Q1, which is typically a little bit seasonally softer, was really pretty strong.

And then demand too, well, it was volatile with some of the announcements on potential tariffs and how those would implement, where they would exactly land. Just like any change in policy, you saw a little bit of volatility in there. But ultimately, the implementation, not only was it delayed, but I think it was at levels that were somewhat more priced in. And so you saw, even demand in Q2 was a bit strong. And you started to see demand revisions throughout the year for '25 and some of that coming out of China as well.

So indications that you've got China doing a bit better year over year. We still have modest decline based on or I'm sorry, demand growth based on historical levels for year over year growth in 2025. And then we continue to see the demand growth increasing into 2026. So a little bit stronger demand growth in 2026 than over 2025. So the demand side looks, the back half maybe flattening out, maybe not as much demand growth, but still strong demand.

And then that brings us to the supply side, which there has been a lot of speculation on how and when and how is the spare capacity going to hit. And I think the most important thing to touch on is where we're at with inventory levels, historically, very, very low. And so we think the first thing for that spare capacity is obviously it's going to fill into, the inventory levels and bring those up, back to more of a in line along the five year average or slightly above the five year average since we've been running at deficit the last couple of years with the spare capacity being higher than usual. But ultimately, once we get through the next quarter or two, maybe seasonally demand weakness in Q1, we actually find ourselves looking at a potentially balanced market going forward. And what we see is less non OPEC supply growth coming on in the next couple of years than what we've seen.

And so it really sets up that's why I said in the opening remarks that we start to see in 2026, you arrive at a spot where pricing is likely more driven by fundamentals without as much spare capacity offline and a market in general that looks more balanced in 2026 than it does today.

The next question is from Doug Legantine with Wolfe Research. Please go ahead.

Good morning. Ezra, I sometimes have trouble recognizing my name, but there you go. I wonder if I could come back to the Utica and just ask the question a little differently. Arun already hit the maintenance capital question or sustaining capital question. My question is, when you lay out the synergies the way you talked about it, dollars 100 per foot, obviously your manager going to manage the midstream differently.

My question is what is your objective for the Utica and what are the constraints around that? In other words, what would it grow if you kept the five rigs in place? Do you have the midstream takeaway to make that happen? And I guess I'm really trying to get to it sounds like you can do a lot more with less and still grow the business on lower spending. Am I thinking about that right?

Yes, Doug. Good morning, Doug Leggett. This is Ezra. It's good to hear from you. Yes, thanks for the question.

I think you're right. The Utica in general, we consider it to be a growth asset for the company going forward and one that can grow for years to come. We have the midstream there just like any of our plays, we'll need to continue to build out in basin gathering and continue to look at midstream agreements the same as any other play. But no, there are no large bottlenecks or anything like that. The legacy rig or frac contracts or anything else that might be there, those are really in line with ours.

Encino, as we've talked about, I think I talked about in May, Encino did a good job with the asset. They had some of the same focuses that we had as far as focusing on high quality rigs and high quality people. It's just the fact of the matter that we're bringing a little bit more of our supply chain knowledge, our own technical abilities in house really stems from the data that we have from drilling so many horizontal wells across The U. S. That we can drive down those costs.

And so when we look at the first year kind of synergies that we talked about that $150,000,000

I think there's a lot of upside to that number. Now as far as do we turn that thing immediately into growth, Doug, I think you know better than anyone that output really does need to be the growth needs to be the output of a capital disciplined investment in any of our assets because too often the fundamental markets are being driven by spare capacity offline and things like that. So part of what we'll contemplate how much we invest in the activity levels in the Utica comes back to what does the macro environment look like. Right now, as I just finished up talking about so much spare capacity coming back online and demand looking solid. I'm not sure quite yet, even if maybe in the next year, if it's going to be the right opportunity to really hammer the gas and invest pretty aggressively in growth. But it's a dynamic market and we'll see.

Great answer. Thank you, Ezra. My follow-up is, want to it's a philosophical question. I just want to maybe it's for you or for Anne. But look, your dividend yield, as you pointed out, is 3.5.

Most everybody on this call asking questions today is an E and P analyst. You have the balance sheet of a major, you have scale of a major, you have the asset debt of a major, now you've got the dividend policy of a major. So my question is, how should we think about translating that free cash flow from and seeing one from the portfolio generally towards your priorities for free cash, specifically your policy on dividend growth per share? I'll leave it there. Thanks.

Doug, that's a good question. When we look at growing the regular dividend, I appreciate the metrics you just put out there because it is something that we focus on is making it not only competitive across our peer group, competitive with the majors in our peer group, but we also look at it competitive with the broad market. We do think that EOG is quickly turning into just about one of the only pure upstream E and Ps that can really act like a blue chip stock. And so our commitment to that regular dividend and growing it in a disciplined manner is the number one priority. Now we support that obviously with a pristine balance sheet, which even after this acquisition, we still maintain.

We maintain our total debt levels versus EBITDA at roughly one times, at $45 oil and $250 natural gas, so at the bottom of the cycle. What that means for our excess cash return is, which we've developed a pretty solid track record now of returning that excess cash return through special dividends or more recently through buybacks is that we can continue down that same policy. And I think we see opportunities for that in our stock right now and opportunities not only in ours, but really across the industry. I'm not sure if the earnings or the profitability of the industry, especially through this earnings season has been really reflected in energy's weighting in the S and P 500. But especially with respect to EOG, our inventory quality and depth that supports high returns and free cash flow generation both in the short and long term, our strong balance sheet, our competitive regular dividend, our track record on excess cash return, some of our new exciting exploration potential both domestically and internationally.

And then these two new transformative items for the company that we've talked about today in The Utica, especially with the acquisition of Encino. And then really the coming out party here for our gas business in Dorado and the Utica dry gas, I'm not sure if we're those things are being correctly valued in the current valuation of the company. And so those are the things that provide us the opportunities when we look at buyback stock such confidence to step in and buy back those shares.

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

Yes, thanks. Good morning all. Can I touch on Utica real quick and it sounds like based on your conversations that you all layered on and seen those plans for the effectively the second half of the year in terms of how you guided? I'm curious, are there going to be some quick wins that you guys can take on? You certainly have better operational costs and stuff like that. Could there be some upside in performance and cost as you get in there? So what are the quick wins? And if you can give us a sense of when are the fully first fully engineered drilled and completed EOG wells, when do those start coming online?

Hey, Scott. This is Jeff. Yes, we as far as the upside, I mean, we see a ton of it. It's obviously on the well cost side. It's on the production performance side.

I can give you just a handful of kind of examples here. But just on the logistics and planning, we've got boots on the ground out there with the former Encino employees now with EOG and we're seeing a lot of opportunities as far as shared infrastructure with pads and gathering systems, facilities. There's a lot of wellsite facilities. We tend to do consolidated facilities, which is going to help a lot. And then I talked a lot about the upside on the midstream.

So that's going to be big. On the operations side, I think utilizing EOG technology is going to be huge. We'll get in there, the EOG motors, EOG mud, cutters, our supply chain, obviously, that's going to be a big benefit there. We're looking to do exactly what we've done in all the other basins too with a lot of our sourcing. We're going to have close to the well, in basin sand sourcing.

We're going to have water recycling. And then obviously we'll be able to drill longer laterals just with the new acreage footprint that we have that will obviously push a lot lower cost. And then as Ezra talked about earlier on the production optimization side, we've got a lot of upside there, just utilizing our data, implementing our optimizers, which are going in very, very quickly. And so that's something I think we'll see in the next couple of months. And just applying our expertise and technology from outside the basin, how we share across from each one of our divisions, getting that up to scale, we just see a lot, a lot of upside there in the Utica.

Okay. Thanks. Sounds exciting. My follow-up and it's probably again for you Jeff. You talked about 50 wells that you all drilled and completed utilizing the higher resolution data and sensors and whatnot.

Can you give us a sense of what does that translate into, right? So what is the cost to implement that versus maybe D and C savings and improved EUR? So the bottom line is how meaningful can this be if you expanded it to your entire asset base?

Yes. It's very early in the game with the HiFi sensors. But I will say we're extremely excited about it. We're just kind of scratching the surface right now and we're finding ways every single day that we can probably apply it kind of across the whole portfolio. So just from a cost side, so what we actually did is we acquired this IP at the end of last year and it just included some software and some patents from a commercial company.

And then we've just taken that technology. We've cheapened it up. It doesn't cost very much to run per well. So the costs are pretty low on it. And we've improved the algorithms within the system.

And, we've integrated all of our EOG data, and then basically just started applying it to all of our wells out there. And what it really allows us to do is, more than just our precision targeting using gamma ray and kind of staying in zone, we're able to calculate geomechanical properties of the actual rock that we're drilling through. Different downhole drilling parameters on our bottom hole assembly and what we're seeing, identifying faults and fractures, which obviously is going to be huge through the drilling and completion process. And then even equipment failures downhole, if we start to get some kind of vibration downhole, we can identify it and we can basically have an ability to be able to trip and minimize any kind of downtime there. So I mean, the upside on this, it's very, very early days, but we see a long, long runway with this.

And I think the longer that our team has it in their hands and we're able to see different areas in the field that we're able to apply it and our IS team is to work with it, I think this is going to be a really big needle mover for us from an efficiency standpoint moving forward.

The next question is from Philip Youngworth with BMO. Please go ahead.

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

Good morning. This is Keith. So, zones and targets that we develop in the Delaware Basin, they are going to vary in any given year as we continue to execute our co development strategy. So one thing we've noticed is we've made significant improvements that support the competitiveness of the shallow targets by lowering the costs and improving the productivity. So that includes the Leonard and the Bone Spring.

We're starting to see that they deliver comparable returns, greater than 55% at bottom cycle pricing similar to what the Wolfcamp has done. So yes, we noted that we've, in the last five years, unlocked nine additional targets. Those are within all three of those main zones of Leonard Bone Spring and Wolfcamp intermixed to those. And there are things that we experiment with all the time on our team to not have kind of a one size fits all development program. So these are things we were able to unlock with lower costs and improved subsurface learnings and the targets themselves are outperforming our expectations.

So I it's important to note that productivity is just kind of one dimension of what we do. We really invest for returns rather than just productivity.

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

Okay. Yes. So in the Eagle Ford, we are just a few years ahead of the Delaware as far as we've been developing there for the last fifteen years. And yes, you're right, our teams, over the last several years have been able to not only drive costs down, but also understand, leverage their learnings from the production and some of the wells they've drilled. To where we have some of the best economics in the history of the play in the last several years, and that's after fifteen years of development.

So if you just take that forward, to the Delaware and you think about how many wells we've drilled there, how many years we've been drilling there, we still have several years to go, to and kind of use the Eagle Ford as an example there. So we're seeing well costs continuing to go down in the Delaware Basin. Our completions design that we, our high intensity completions design is continuing to uplift well production. We've talked in the past that that has uplifted some subset of our wells that have the right geologic properties up to 20% or so. So you combine those together and that is going to be continuing to drop our finding cost.

EOG Resources (EOG) Q2 2025 Earnings Call Transcript

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