EOG Resources Stock

Good day, everyone, and welcome to the EOG Resources Third Quarter 2026 Earnings Results Conference Call. As a reminder, this call is being recorded. For opening remarks and introductions, I will turn the call over to EOG Resources Vice President of Investor Relations, Mr. Pearce Hammond. Please go ahead, sir.

Good morning, and thank you for joining us for the EOG Resources Third Quarter 2026 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, any reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines.

Participating on the call this morning are Ezra Yacob, Chairman and Chief Executive Officer; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Senior Financial Officer -- excuse me, Chief Financial Officer; Jeff Hibbard, Senior Vice President, Finance; and Keith Trasko, Senior Vice President, Exploration and Production.

Here's Ezra.

Thanks, Pearce. Good morning, and thank you for joining us. 2026 has been an outstanding year for EOG, and I'm pleased to report that through 3 quarters, we delivered exceptional results that reflect the strength of our assets, the efficiency of our operations and the dedication of our teams across our portfolio.

Our third quarter results include record oil, NGL and natural gas production and excellent cost discipline as total per unit cash operating costs and DD&A came in below guidance midpoints. This operational execution, combined with price rate -- with strong price realizations, produced superb financial results.

EOG's business and the outlook for the company have never been stronger. As a testament to that, we are pleased to announce an 8% increase in our regular dividend for 2027. The increase reflects confidence in our business and EOG's pristine balance sheet, both of which support our ability to sustain the higher dividend through industry cycles.

EOG has grown its regular dividend at almost a 20% compound annual growth rate over 28 years without ever cutting or suspending it. This is a differentiated track record, reflecting our enduring commitment to the regular dividend as the primary means for cash return to shareholders. Beyond the regular dividend, cash return remains a priority, and we continue to expect to return a minimum of 70% of free cash flow to the investors this year.

The EOG culture is one of continuous improvement. As such, we remain focused on further strengthening our business for the long term and two recent developments illustrate this commitment. First, we signed a new long-term natural gas supply agreement with Engie, which expands our access to premium markets. Linked to JKM pricing, this agreement lifts our premium price exposure across LNG feed gas agreements to more than 1 billion cubic feet per day by 2030. This is a clear differentiator for EOG and a direct result of our marketing strategy, which is built on flexibility, diversification, control and appropriate management of contract duration to support strong margins and netbacks for our asset base. In addition, this new long-term agreement allows us to supply independently certified natural gas which reflects EOG's ability to access further differentiated markets.

Second, we approved the expansion of our Janus gas processing plant in the Delaware Basin. In the current environment, where we are starting to see a tighter market for gas processing, the investment in Janus provides outsized benefits to our netbacks. The expansion has strong operating synergies with our existing infrastructure, supporting robust returns and long-term value creation.

Turning to the oil macro outlook. Market fundamentals remain tight. Middle East exports have recovered from lows reached in the spring. However, the recovery has been uneven. While strategic petroleum reserve releases, and coordinated refinery measures across the G7 are providing some relief at the margin, they are not a substitute for consistent and reliable supply from the region. The security of these flows remains a key variable in shaping near-term market conditions.

While we expect oil prices to remain volatile, we continue to be constructive on oil market fundamentals for several reasons. First, oil demand has demonstrated considerable resilience. Despite elevated product prices, consumption has held firm and as suppliers return to the market, demand has recovered alongside it. This reinforces our view that demand reduction observed early in the conflict was temporary in nature rather than a structural shift.

Second, although the pace of inventory draws is beginning to moderate, global inventories remain well below their 5-year average. We expect the process of rebuilding stocks to those historic levels will take considerable time.

Third, the supply recovery remains fragile. As recent events have shown, the restoration of flows from the Middle East is subject to ongoing disruption risk. Taken together, we expect oil prices to remain above mid-cycle price levels in both the near and medium term, and we see the balance of risks supporting upside price volatility.

Turning to the natural gas outlook. We continue to see the North American market evolve from a seasonal commodity story into a strategic energy resource. While storage levels will continue to fluctuate year-to-year, underlying demand remains robust with LNG exports, electricity demand, industrial growth and grid reliability increasingly competing for domestic supply. Our medium to long-term outlook remains constructive in our deliberate investment in building a low-cost natural gas position with access to premium markets and as a complement to our core oil business, provides ample opportunity to capitalize on this demand growth.

Looking to 2027, we are well positioned with tremendous flexibility. Earlier this year, we redirected capital to oil assets, raising liquids production and setting a strong foundation for growth in 2027. If current oil supply/demand fundamentals persist, we believe the market needs more oil supply next year. Accordingly, we anticipate staying consistent with our 3-year scenario and expect to deliver low single-digit oil production growth in 2027.

Regardless of commodity prices, EOG's commitment is to deliver sustainable value creation through industry cycles by being among the highest return, lowest cost producers while maintaining strong environmental performance and playing a meaningful role in the long-term future of energy. This mission rests on four pillars: capital discipline, operational excellence, sustainability and culture.

Our decentralized non-bureaucratic structure enables value creation in the field at the asset level. It is our unique culture that drives a sustainable competitive advantage, and we expect to continue extending that advantage into the future.

In summary, we are performing at a high level in 2026 and are positioned to finish the year strong and carry significant momentum into 2027. We remain focused on delivering sustainable free cash flow, maintaining operational excellence and creating long-term value for our shareholders.

I'll now turn it over to Ann for details on our financial results.

Thank you, Ezra. EOG delivered another quarter of outstanding financial performance, underscoring the power of our consistent approach to capital allocation, which is invest with discipline, return cash and maintain a pristine balance sheet. In the third quarter, we delivered adjusted earnings per share of $4.87 and adjusted cash flow from operations per share of $7.23, yielding free cash flow of $2.2 billion.

We returned just over $1.5 billion to shareholders during the third quarter, approximately $540 million through our regular dividend and $1 billion in share repurchases. The foundation of our cash return remains the regular dividend, which we are raising by 8% to an indicated annual rate of $4.40 per share. This dividend increase is a reflection of EOG's ability to continue increasing the free cash flow potential of the company through our commitment to capital discipline and operational excellence, which deliver one of the industry's lowest breakeven oil prices.

Our 2026 plan funds production growth, domestic and international exploration and our regular dividend all at a WTI breakeven price below $50 per barrel. At strip pricing and using guidance midpoints, our 2026 plan generates $9.7 billion in free cash flow.

Our regular dividend yield remains attractive versus peers as well as the S&P 500, and we continue to supplement the regular dividend with opportunistic share repurchases. Since we started repurchasing shares in 2023, we have reduced our share count by 13%. With $10.6 billion remaining under our repurchase authorization at September 30, we have substantial capacity to act.

Our balance sheet remains a strategic asset. We ended the quarter with $5.7 billion in cash and net debt of approximately $2.2 billion. Our leverage target of total debt below 1x EBITDA at bottom cycle prices of $45 WTI and $2.50 Henry Hub remains among the most stringent in the sector. That strength gives us a stable foundation to navigate a dynamic macro environment with confidence. We are generating significant free cash flow, returning meaningful cash to shareholders and maintaining the flexibility to capitalize on opportunities as they emerge. Operational excellence, a low cost structure and financial discipline position us extremely well for sustained long-term value creation.

With that, I'll turn it over to Jeff to discuss our operating results.

Thanks, Ann. I'd like to begin by recognizing our employees for their outstanding performance and execution. In the third quarter, we delivered exceptional operational results highlighted by record oil, NGL and natural gas volumes with all three streams above our guidance midpoint. Total per unit cash operating costs and DD&A both came in below guidance midpoint, reflecting disciplined execution in the quarter. Third quarter capital expenditures also came in below the guidance midpoint, primarily driven by shifts in our operational timing.

For the full year 2026, we expect to deliver 5% oil production growth and 14% total production growth with capital expenditures, unchanged at $6.5 billion. The focus of our international activity continues to be applying EOG's operating model to unlock resources of significant scale while maintaining the capital discipline and return thresholds our shareholders expect. This isn't about international growth for its own sake. It's about taking what EOG does best to places where we believe we can create substantial value.

We remain very excited about the progress we are making on our UAE oil concession. Our first two 1-mile laterals continue to exceed our expectations. And during their first 30 days on artificial lift, have averaged stabilized production of 700 barrels of oil per day per well.

Our operations are running smoothly as we focus on drilling and completing 2-plus mile wells. We are assessing several items to move us towards a decision on commerciality. These include completing wells in different areas across the approximate 900,000 acre concession, testing new landing zones, assessing geo-steering and targeting execution, confirming the fluid mix relative to our initial model, evaluating options for artificial lift and appraising well performance over a longer time period.

In Bahrain, we remain extremely pleased with our partnership with Bapco. However, operations have remained intermittent due to the ongoing conflict. While we hope to have well results this year, our priority is the safety of our employees, contractors and partners in the region.

Turning to domestic operations. Our Delaware Basin team continues to execute on our development strategy with well performance this year above our expectations. We continue to develop this world-class asset at the right pace, delivering operational efficiencies, impressive well costs of less than $710 per foot and peer-leading average per-well rate of return.

We are pleased to announce the expansion of the Janus gas processing plant in the Delaware Basin. This strategic infrastructure project will double the current plant's capacity to 600 million cubic feet per day with targeted completion in the second half of 2028. The total cost should be approximately $300 million with 2/3 of that spending occurring in 2027.

Janus has added significant value since it's been online, delivering year-to-date netback uplift of greater than $0.65 per Mcf, while running at a greater than 99% utilization year-to-date. The expansion benefits from embedded synergies from our initial 300 million cubic feet per day processing capacity and is expected to deliver a rate of return in excess of 30%. This project will enhance our operational control and diversify our processing options at a time when processing capacity is tightening as more natural gas production comes online due to improved pipeline takeaway capacity. Given the proven performance of the existing facility, we believe this attractive, high-return investment represents a compelling opportunity to extend the value created by Janus for years to come.

In the Utica, operations continue to run at a high level. Year-to-date, we have improved drilled feet per day by 24% and completed lateral feet per day by 14% compared to the first half of 2025 with well costs at less than $600 per foot. We expect to have an in-basin sand mine open by the end of this year and anticipate cost savings in excess of $300,000 per well. The new Ohio sand mine underscores our operational excellence and use of self-sourced materials to reduce well costs and improve operational efficiencies.

In the Eagle Ford, operations are also performing strongly year-to-date, we have increased drilled feet per day by 4% and completed lateral feet per day by 15% compared to 2025. These efficiency gains have helped drive further cost reductions with Eagle Ford well costs at less than $525 per foot.

Further south in Dorado, this low-cost dry gas asset continues to improve. In 2026, we have increased average lateral length by 16% compared to last year, with well costs at less than $700 per foot. In addition, the countercyclical investment in the Verde Gas Pipeline continues to pay dividends as we are realizing netback uplifts of $0.50 per Mcf year to date.

Turning to service cost environment, diesel and steel prices remain elevated, but we have mitigated the impact and continue to expect a low single-digit reduction in well costs this year. We are seeing services tighten and expect modest inflation next year for drilling and completions.

Finally, I would like to touch on two non-core asset dispositions we executed this year. Taking advantage of a favorable market environment, we recently divested our legacy Barnett and Woodford positions for an aggregate $400 million. In the third quarter, these assets had total production of 16,000 barrels of oil equivalent per day, including 2,000 barrels of oil per day. We have been able to meet our annual production guidance we outlined earlier this year despite these divestitures.

This illustrates the strength and quality of our core assets to be able to deliver capitally efficient volumes. Overall, the divestitures were an efficient way to sharpen our focus on other high-return assets and exploration prospects in our portfolio.

With that, I'll turn it back to Ezra for closing remarks.

Thanks, Jeff. Before we open the line up for questions, I'd like to leave you with four key takeaways. First, EOG delivered an outstanding third quarter. We posted record oil, NGL and natural gas production and total per unit cash operating costs and DD&A both came in below guidance midpoints. Second, our commitment to shareholders is unwavering. We raised the regular dividend by 8%, extending our 28-year dividend payment track record.

Third, we continue to strengthen the portfolio for the long term, including our new LNG agreement with Engie that lifts our premium priced LNG feed gas exposure to more than 1 billion cubic feet per day by 2030, and the Janus gas processing plant expansion in the Delaware Basin.

Finally, we are constructive on oil fundamentals. If current oil supply/demand fundamentals persist, we are well positioned to deliver low single-digit oil production growth in 2027.

I'd like to finish by thanking Ann Janssen for her dedicated service to EOG over the past 31 years. Ann will be retiring next year, and Jeff Hibbard will be assuming the CFO role on January 1. Ann has long recognized the value of a peer-leading balance sheet, strong financial results, sustainable free cash flow and most importantly, developing EOG's next generation of leaders is the path to consistently creating long-term value for our shareholders. I'm grateful for Ann's leadership and her contributions to the financial strategy and the strength of EOG. I want to congratulate Jeff Hibbard on his new role and offer Ann Janssen and her family our best wishes in retirement.

With that, we'll turn it back to the operator for questions. .

[Operator Instructions] The first question today comes from Neil Mehta with Goldman Sachs.

Congratulations, Ann, and congratulations, Jeff, as well as you take on this new role. A couple of update questions for you guys. First is the long-term sales -- gas sales agreement that's been linked in to JKM here. Can you spend some time talking about this and how mechanically can work and give us a sense of the quantification of what it could mean for a cash flow uplift in a normalized JKM environment?

Yes. Neil, thanks for the question. It's Jeff Hibbard here. Maybe I'll start. So the gas sales agreement announced with Engie provides additional pricing diversification for our gas volumes with many similarities to our deal with Cheniere. So some of the specifics, 140,000 MMBtu per day is linked to JKM with deducts. It's a 10-year agreement. It starts by 2030. And the offtake is at U.S. Gulf Coast, which allows us to source gas from multiple basins.

The addition of the Engie agreement increases our LNG feed gas associated volumes to over 1 Bcf gross per day by 2030. Additionally, we increased exposure to premium price indices really linked to strong markets with growing long-term demand. Our ability to supply gas from across our low-cost multi-basin portfolio in combination with our strong balance sheet, make us a preferred partner for long-term agreements that support strong netback margins and returns.

We're really seeing those benefits today. As you saw, our LNG exposure, our gas realizations this quarter came out right at $3.73, and we expect that to continue as you see in our guidance really going forward.

Yes. And then Ezra, can you spend some time just talking about the M&A strategy here? Historically, there's been such an organic company, of course, you've done Encino and Yates over the years. But -- as commodity prices eventually normalize, are there -- how do you think about the potential for corporate M&A or larger scale M&A? Or is this more of a bolt-on type of story going forward?

Yes. Neil, it's Ezra. Listen, nothing has changed with our corporate strategy, our long-term strategy. I think over multiple decades here, a cornerstone of our company's value proposition has been our ability as an organic exploration outfit as a first mover, utilizing data and technology to continue to unlock resources and turn them into highly economic, high-return value opportunities, investment opportunities for our investors.

We do, as you said, at the right time cycle, are very interested in doing bolt-ons, small bolt-ons, things that typically don't come with a lot of production but offer us the ability to do what we do best, which is drill and complete horizontal wells and bring that value forward. Corporate M&A has typically never been something that we see a significant amount of value in when we look at the rest of our portfolio and inventory.

But again, we continue to evaluate opportunities through the cycles and try to determine the best way to create long-term shareholder value.

SP-3 The next question comes from Steve Richardson with Evercore.

I was wondering if I could follow up on Jeff's comments about expectations for some cost inflation in 2027. Could you maybe just walk us through where you're seeing that, be it consumables or other services? And then maybe just how well positioned are you to absorb that not only from the below-ground efficiencies you're talking about in the plays, but also either tubulars or all the things EOG normally does to kind of manage the inflationary environment, if you could?

Yes, Steve, this is Jeff. Let me give you a little bit of color on it. So kind of this year, we started seeing some modest well cost increases over the last few months as we've talked about. And the market for high spec equipment, it was stable at the beginning of the year, but it's really tightened after kind of the start of the Iran conflict. And we've seen service utilization at a fairly high level. So now we're starting to see that tighter service market translate into price increases.

And then just to note, that level of increase has not really been consistent across the basins, and it's varied regionally.

Also, as you talked about, we've seen cost increase for diesel and steel progressively over the course of the year, adding additional inflationary headwinds. But however, in aggregate, I'd say for 2026, we're still on track for that low single-digit average year-over-year well cost reduction just because of our efficiency gains have more than offset the rising costs that we're seeing in the value chain.

And then looking forward, for 2027, we're currently expecting some upward service pricing pressure as well as higher steel and diesel costs. Our main focus remains on really leveraging all of our operational capabilities, the scale of the company and our purchasing power to really manage through those inflationary headwinds. And just to give you a little bit more color, kind of breaking things down. I mean, starting on the service side, first, what we'll do is we'll look to offset some of those headwinds through our operational efficiencies, which we always say, typically, we see, on average, about 3% to 5% improvement in each year.

And then next, we'll look to leverage our strong relationships with all of our service partners. And what we've done is we've really staggered all of our contracts in both length and renewal timing to really help mitigate the impact of those leasing rates.

And then lastly, I'd say, currently, we have about 60% of our services contracted for 2027, which is really on the high end of our historical range. So we feel pretty good and well positioned on the service side.

When looking at steel costs, we expect continued upward pressure for the industry. But internally, what we've done is really lean on our direct sourcing and mill diversification to support keeping our prices really lower than the broader market. And at this point, we've already secured around half of our casing and tubular needs for 2027. So we continue to focus on just opportunistic inventory management with our supply chain group. So really, any exposure, I think, on the steel side really would be more towards the second half of the year if prices keep increasing.

And then lastly, just on the diesel side, while prices have increased meaningfully over the year, much of the impact of those higher prices on CapEx really have been pretty minimal since the 70% of our rigs, we run off natural gas, 100% of our frac fleets also do, too. And then any other diesel increases, we think we'll see will just be kind of in the form of fuel surcharges from some of our other service providers. So ultimately, I think we feel really, really good at where we're at. We're well ahead of schedule, preparing for next year, and we'll just look to continue to insulate ourselves from any potential inflation as we move forward towards the end of the year.

Great. I was wondering just quickly follow up on natural gas markets. I understand the point on how strong your realizations have been and the low-cost supply perspective that you have. I was just wondering if you could talk about willingness to take on additional be it pipeline projects or other things? I appreciate you're talking about Janus today on the processing side, but wondering if you could talk a little bit about to the -- beyond the wellhead if you have interest in other projects or other things as you look at the outlook here.

Thanks, Steve. This is Ezra. At times in the past, especially parts of the cycle where we are right now, we have taken on some of those strategic infrastructure opportunities where we see significant value. It's not a primary focus for us, though. Typically, we see the returns profile. Our investments are better spent, bringing low-cost oil and gas to the surface rather than moving it into the markets. We tend to prefer to partner with high-quality partners to be able to move our molecules to the market. But two things caused us to step into that space.

First, if we're unwilling to find a strong partner to be able to do that. And the second is, at times, which is usually like current times where you're at the top of the cycle or high above mid-cycle price ranges where the fees start to get a little bit higher. And there's enough value there for us to step in and capture that for our shareholders. Now that's really in line with how Jeff described it this morning in the script is, we're seeing an opportunity here with Janus not only to capture the synergies that we have with the Janus gas plant expansion, but really to expand the margins there in an environment where we're seeing processing capacity kind of get a little bit tighter and the fees have a little bit of upward pressure to them.

The next question comes from Doug Leggate with Wolfe.

Congratulations to you, Ann, especially when you're your balance sheet diligence, I'm sure we'll come back to that. Ezra, the earlier question from Neil was on inorganic growth in resource. I'd like to ask you about organic opportunities, particularly your exploration plays. And I wonder if you could touch on two specifically. The first one, obviously, Alaska. You've now got your acreage position, it looks like. What's your play concept? And any color you can offer on your recent permitting in Frio County around the Pearsall Shale in South Texas would be much appreciated.

Yes. Doug, this is Ezra. Appreciate the question. So let's start with Alaska. We've talked about it a little bit before. You had picked up on our Alaska activity kind of early on before anybody else. Before, in fact, we ended up leasing the -- put all the leases together. But we put together some state leases in that area. And so we've got a good long runway. Those are 10-year leases in Alaska. And this play is a conventional oil play. It is an analog to some of the other Alaska plays that have been in the news recently, Pikka and Willow. In general, what I'd say is Alaska is undergoing from an industry's perspective, a bit of renaissance by applying new technologies up there, especially on the seismic processing.

Our prospect was identified through some loose 2D seismic lines and some well control. It is seismically identified. It's got some amplitude support with the 2D data. It's a bit of a difference formation and what's in Pikka and Willow, it's a little bit younger sands. It's Schrader sands, which are Paleocene instead of kind of the Nanushuk formation because we are off to kind of the east side.

Going forward, the strategy going forward for Alaska, like I said, it will take a little bit of time. The next step for us is to get some 3D data we'll be purchasing some 3D data as it becomes publicly available later next year, and we'll reprocess that. And that will be kind of the next step in evaluating the prospect that we have.

And then going all the way down to South Texas for the Pearsall, that's a play that we haven't really talked about yet. It's -- as I think everybody knows, we have Pearsall exists underneath our entire Eagle Ford oil acreage position. But starting about 2 years ago, we identified a bit of a sweet spot outside of our area, adjacent to, I would say, we leased it up organically. We've drilled a handful of wells there. It's in the oil window, maybe a bit more of a combo play, but the well production looks pretty good. We've captured probably about 100 locations there. And to be perfectly honest, while the play benefits from sharing activity in our Eagle Ford area, we still have a little bit of work to do to get the cost down to make those wells competitive with our core inventory.

But like I said, we're excited by it. It's another kind of step-out organic opportunity that we were able to bring into the mix just because of our subsurface knowledge in the area.

20 years ago, I want to say, right? My follow-up is a quick one. It might be for you, maybe for Ann. It's really just a quick comment about the way the balance sheet is today, there seems to be a lot of focus still on EOG's duration of production. What I want to ask you about is the duration of free cash flow to support that dividend bump and the sustainable dividend growth that you expect. Do you have the portfolio today to sustain the free cash flow as opposed to sustain the production mix, I guess, is the core of my question.

Yes. Doug, maybe I'll just give you the brief answer there. I mean I think we think absolutely. And it really comes down to our low breakevens in that $12 billion BOE of resource in addition to the financial strength of the company. So we test our dividend across multiple scenarios. And really including bottom cycle price assumptions down even below $45. So -- yes, we feel very good about that dividend over the long term.

In addition, I would just add, I feel like the regular dividend is extremely competitive with both the industry and the broader S&P 500. I think we've established a differentiated record as Ezra said in his remarks of sustainable dividend growth. The company has grown our regular dividend at a compound annual rate of 20% over the last 28 years without any reduction or suspension of that dividend obligation. So we've got strong confidence in our ability to continue to improve and remain committed to returning a significant portion of our free cash flow to investors with the regular dividend as the primary mode of cash return over the long term.

The next question comes from Phillip Jungwirth with BMO.

You mentioned in the script, the 3-year scenario should be the base case for next year. I guess after year 1, how would you say you're tracking this? I mean, obviously, we can see the production guidance, but -- just also on the capital operating cost side, plus just corporate with interest, tax, given the stronger macro since we are growing cash flow, free cash flow more than oil. And then just to stay on track into '27, how much Utica or kind of elsewhere activity would you need to add to drive low single-digit growth for EOG?

Yes. Phillip, this is Ezra. It's really a pretty consistent activity levels going forward. As Jeff said in the opening script, you can kind of start with the Q4 run rate which means that activity level is pretty consistent. Of course, when you're looking at the CapEx, we do have the strategic infrastructure that we've talked about, the Janus expansion that would need to be contemplated on top of that. And then a little bit of increased growth, but it's really more on the margin than adding anything significant to capture that low single-digit. As we talked about before, we really took this year to kind of position ourselves to not only grow liquids production in '26, but actually to position ourselves to be able to grow into '27 as well. .

With regards to the 3-year scenario and where we're at here towards the end of year 1, obviously, in the first year, there's been a significant increase in the commodity price from what we had forecasted before. I think what we have is illustrated on a $60 to $80 range over that 3-year period and year 1 is obviously coming in at current strip somewhere right around $87 for the year 1. So that would lead us to know that ROCE is kind of on the high side, free cash flow generation is on the high side.

As far as the maybe capital expenditures that were contemplated or not contemplated in this 3-year scenario, really, the only one would be that Janus would be on top of it. That wasn't originally into the 3-year scenario. And again, that's a strategic option for us that at the top of the cycle, feels like a great time to layer that in. And for '27, it's essentially a $200 million capital investment that we're planning for.

Okay. That's great to hear. And then -- this might also be contributing, but you noted in the script, Permian well performance outperforming your expectations of steady year-on-year, probably all noticed this in the public data, but one thing that stood out to me was really across all your plays, the well performance looks better or at least consistent with last year. Just wondering if you could speak to some of the bigger drivers here on the productivity side, just whether it's some of the high-intensity completions, targeting or other items that you pursued operationally in 2026.

Yes. This is Keith. I'll start with the Delaware. Yes, we're very pleased with how our Delaware Basin development is progressing. We haven't really made any changes to our development plan relative to what we communicated earlier this year. Well productivity has been a little better than our expectations. The results are flat to slightly up versus 2025. And the important thing is that we expect similar consistency in productivity going forward.

So the 2026 plan reflects the changes that we made last year in our development strategy. So we continue to take advantage of the operational improvements to maximize the value of the asset. And that's really driven by our ability to drive down costs, allowing us to add new target zones that meets the strict return hurdles better maximize the value capture across the assets. So we're really happy with the Delaware. We expect consistent returns and cash flow for the next 10 years.

And yes, a lot of it is on the completion side. Like you said, our high-intensity fracs, adding horsepower and doing smart tests just on various things on the completion side. And that had its genesis in the Eagle Ford in the early days, and we've applied it to the Permian. We applied it to the Utica very early on. We're seeing improvements in Dorado associated with that. And as we take those learnings and iterate them, we've been able to apply that back to our Eagle Ford oil as kind of a revision 2 and 3 and 4, we've seen improvement there as well. So very happy with our well performance across the board.

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

Yes. If we could go back to where the Q&A started, and that's on the gas sales agreement. You have kind of a two-part question with that. Number one, the commercial terms, I understand there are a lot of confidentiality around it. But like in this market that we've seen for the past 9 months, like how are you all able to get a contract like that done at this point? And do you see the economics a little bit different from the -- ones. And as you look going forward, how much exposure to these international markets you want? Should we expect you guys to continue to layer on new types of contracts like these? Or is there a certain threshold you want to limit yourself to?

Sure, Scott. It's Jeff Hibbard. Maybe I'll take that one. So U.S. LNG projects continue to reach FID and operators are still seeking commitments to get additional capacity built. As the LNG market has expanded, both physically and financially over time, it's created really new and different opportunities to seek international price exposure for us. So look, we remain engaged with several potential partners and look for attractive win-win opportunities as they present themselves. So I would expect us to continue to look at those types of deals.

We really have a number of advantages. Again, it's -- that make us an attractive counterparty for folks. So it's our low-cost multi-basin portfolio. It's our extremely strong balance sheet and it's our track record with these types of deals. So yes, I think you can continue to see us always looking at those going forward.

Appreciate that. If I could pivot to shareholder returns, I appreciate your, again, commitment to hitting that annual 70% return. Based on, I guess, your $9.7 billion forecast and buybacks to date, including what you've done based on the 10-Q, it looks like there's probably another $1.5 billion to maybe $1.6 billion that needs to get done through the balance of the year. That seems like a lot. And given the volatility in commodity prices, how do you manage hitting that annual threshold when we're coming up on the end of the year?

Yes. Look, I mean, it's Jeff again. I would say Cash returns remain a priority for us. You heard Ezra mention it early on in the script, and we remain confident in our ability to meet our threshold commitment of 70% of our annual free cash flow. So you hit the numbers on the head at $88 WTI and $3.40 Henry Hub, we expect to return $6.8 billion of cash this year. And when you back off our dividend commitment, which is that $2.2 billion, I think your numbers are accurate. I think given the volume that we have in our stock, we feel very comfortable being able to achieve those amounts. And look, we continue to see a lot of value in our stock. So consequently, we favor buybacks for additional cash return and think we'll be able to get there.

The next question comes from Leo Mariani with ROTH.

I just wanted to touch base on your initial comments for 2027. You talked about low single-digit oil growth, that certainly seems to be reasonable in this price environment. I just wanted to kind of get a sense, do you see a contribution from the UAE there to get to those numbers for next year?

Yes. Leo, this is Jeff. You can actually see in our guidance, we did guide towards a little bit of volumes, but fairly minimal as far as that. We're still in the exploration phase, even though we're seeing outstanding strong results over there. before we really see meaningful amount of volumes, and we start getting closer to DOC, I wouldn't expect them to be a huge part of the overall 2026 volume. So Ultimately, we feel great about it. I think we're getting to a place where we're getting closer and closer to DOC with the results that we're seeing, and we're excited about it. So you'll just kind of see that in our guidance as we move forward, and we'll keep you posted on the results.

Okay. Appreciate that. And then I just wanted to also just ask, obviously, you announced a new gas sales agreement today, clearly made a commitment to expanding the Janus plant. Just can you provide a little bit more color just on your thoughts around gas. Is EOG making a larger pivot towards gas as we get later in the decade, do you see great opportunities for returns on the gas side in several years?

Leo, this is Ezra. Yes, I wouldn't say that EOG is making a big pivot to gas or a big call on gas. I mean what we -- this all starts with our organic exploration effort and the fact that we captured Dorado. We do continue to believe that Dorado is the lowest cost gas in North America. And then we're advantaged in the geographic position of it being close to multiple demand centers. What that's really allowed us to do is basically invest at the right pace, capitally disciplined to grow what we think is essentially a premium gas company underneath the umbrella of our premium oil company here at EOG. We continue to invest in gas as we develop and capture markets, we're not just growing or investing in gas to move a whole bunch of gas to the Gulf Coast and hope that it prices on gas because the margins oftentimes are so skinny and volatile, you've got to be very, very diligent and disciplined looking at the entire value chain.

It starts with low well costs, continues with low operating costs, including transportation. And then the last part of it is making sure that you're delivering your molecules to a demand center and getting yourself exposed to premium pricing.

The next question comes from Arun Jayaram with JPMorgan.

Your fourth quarter guide including better realizations than we're modeling. Clearly, the -- on the gas side, the contract has been a nice tailwind. But I was wondering if you could elaborate on how you're capturing the premium realizations on the oil side. I know you have dock capacity. But maybe walk us through the marketing and how you're able to capture that premium relative to...

Arun, this is Jeff Leitzell. So yes, great question. And really, I'd break it down into a couple of different things. I mean the first thing is just the way that our marketing team is just so ingrained in the business. They're in each one of our divisions. They're tied in and trying to find the absolute best contracts in each area, give us a lot of diversification, flexibility and control with our molecules to really maximize those netbacks. So I think that's one, and that's one of the reasons you've always seen our price realization throughout time really out kind of run the peers.

And then the second thing on that, which has really been a big mover here as of recent is our exports. We've talked about on previous calls, we're exporting anywhere from 200,000 to 250,000 barrels a day. And obviously, with the premiums that we're seeing overseas and stuff with those barrels it's really helping our overall price realizations and netbacks from that aspect. So really, it's just great work by our marketing team kind of staying ahead of things and making sure we've got a lot of flexibility to send those molecules to the best markets.

Great. And my follow-up is -- I'd love to hear your thoughts on your strategy for inventory renewal in the Delaware Basin. I know that producers have been focused on a ground game. We're doing a lot of small transactions, extending lateral lengths and things like that, but I'd love to hear some insights on how you're thinking about bolstering your Delaware Basin inventory position to offset wells that you drill and complete?

This is Keith. I touched a little bit on this on the productivity side. But what we've seen in the last several years is our teams continuing to increase efficiencies and drop costs and do some really nice detailed geologic work that has allowed us to add targets into our existing development, both as like a second phase and then when you're initially developing as well. Today, we have more targets than I ever imagined several years ago. That's what you're seeing on our development strategy and our consistent productivity that we've had this year compared to last year and going forward. So we see a lot of it just on the acreage that we already have. So our co-development strategy leverages all that deep knowledge of basin geology. We've identified up to 17-plus unique targets and our operational capabilities to develop them maintain the strong productivity and low cost. So that has really allowed us to maximize the value of the asset, be the leading Delaware Basin operator in terms of well costs and breakeven price and have that durable inventory associated with it as well.

The next question comes from Bob Brackett with Bernstein Research.

You've intrigued us around declaration of commerciality for the Aldafra concession. A question would be, as you convert that license from exploration to production. How does it work? Would you keep all 900,000 acres? Or is there an HBP scheme? Or is it negotiated between you and the host government? Any color would be helpful.

Yes. Bob, this is Ezra. As it works, the path to DOC and conversion from an exploration concession to a production concession includes a field development plan. And then essentially annual reviews are typically how these international agreements work. And so yes, you end up -- it's really to be negotiated if we wanted to turn less of the concession over into production or the entire 900,000 acre.

Today, where we're at, we're seeing very, very strong results in those initial 2 wells, as highlighted previously. They responded very, very well to the artificial lift. And then we brought a couple of additional wells on. We don't have 30-day rates. It's a little bit soon for that, but the wells look good. And quite frankly, with the efforts that we've seen the conversations we've had with oilfield service partners and their level of engagement to enter the country. At this point, I'd say we're -- I'd reiterate what Keith said before is that we're well on our way to targeting kind of a DOC probably long before the expiration of the exploration agreement.

Follow-up would be that field development plan, that's where you would finally sort of lock down sort of CapEx? How many rigs you get to run, what the production forecast would be in a conventional field, that would be pretty well constrained. But with unconventionals, you can dial up, dial down and grow. I guess there'll be flexibility in what your overfeed development plan would look like?

Yes. Bob, I think what you've hit on is something we've highlighted whenever we talk about going to international, whether it's conventional or in this case, unconventional, it's the importance of aligning yourself with the right partners. Folks that understand what it takes to make these plays work, what it takes to make unconventionals work. And as you touched on, the way these unconventional plays work, you essentially need to you almost have to build, construct a virtual manufacturing plant in the field before you can really step in and start to get the repeatability and the scale that makes these unconventional plays work.

So it does start with the field development plan. And yes, you should expect, as I've talked about it before, we've got great partners between BAPCO and ADNOC. And I think all of us are -- there's great alignment there that the field development plan will be a fixed yet flexible plan to go forward and best develop the resource for the stakeholders.

The next question comes from Kevin MacCurdy with Pickering Energy Partners.

You took advantage of the hot markets to sell some assets in the Woodford and Barnett this quarter. As I look across your portfolio, there are a couple of areas that are not getting a lot of capital. And just curious how those assets sales came about this quarter? And how you're thinking about further streamlining the portfolio, particularly in the U.S., if at all?

Sure, Kevin. I'll take that one. It's Jeff Hibbard. So as you mentioned, we took advantage of favorable market conditions really to divest those legacy Barnett and Woodford assets. I'd say we selectively divest noncore positions to lack the size and scale to meaningfully impact shareholders, allowing us really to high-grade our portfolio, pull value forward. If you look back over the last 5 or 10 years, we've divested several assets, including our legacy positions in the Marcellus in China, U.K., North Sea, among others. And we try to maintain a disciplined approach to portfolio management, continuously evaluating assets against our return hurdles and strategic priorities. These divestments of non-core assets are really just another example of our relentless focus on capital discipline. So I'd say we've got no current plans for additional asset sales at the moment. We generally think assets are worth more in our hands, but we continuously evaluate our portfolio with the goal to maximize shareholder value.

Great. I appreciate that. Maybe as a follow-up, you have a unique view on the Texas gas markets as you have kind of assets in several different basins there. Are there any opportunities that you see that may be in the form of supply and demand that the market is missing? Obviously, there's been a lot of attention on Permian, both from a supply factor takeaway and demand. But is there anything else that maybe you think is underappreciated? And how does that fit into your thoughts on ramping Dorado over the next couple of years?

Yes. Kevin, kind of like we touched on before. The way that we think about investing in gas growth really starts with knowing where our molecules are going to go and make sure that we're not just investing into a volatile market and leaving our gas exposed. It really comes back to where we've spent a lot of time talking today about our marketing strategy and making sure that we've got the flexibility and diversification even at an asset level to be able to make sure that we put gas into a premium market. And we've done a great job not only exposing ourselves to LNG and international offtake and LNG pricing, but also things like the Transco pipeline that allows us to move gas from the Texas Gulf Coast all the way up into Louisiana, expose ourselves to some different markets there, including the Station 65 power pool and things of that nature.

Ultimately, in gas, like we said, it's a fascinating time in the North American gas market because we really are seeing a transition from this seasonally driven by weather, driven by residential and commercial heating in the history of gas demand. And now it's really becoming much more where the future fundamentals are going to be driven by AI-powered electricity demand and global LNG exports, industrial reshoring, 24/7 baseload power to ensure grid reliability. And so all of those things, we think, will ultimately provide upward pressure on pricing, which is for a company like ours, with an asset like Dorado, puts us in a great position.

The next question comes from Josh Silverstein with UBS.

Maybe on that gas supply front, I was curious up in the Utica. If you guys are exploring some of these gas supply agreements, clearly, there's a lot of power generation demand growth coming to the area. I know you've signed these international agreements, but I was curious about some of the domestic agreements you guys may be looking at.

Yes, Josh. This is Ezra. We're in discussions with data centers and hyperscalers, and we feel we're very well positioned because of like you highlighted, not just Dorado, but really just our multi-basin portfolio in general. We've got production near several growing potential areas that are seeking direct gas supply, and you highlighted the Utica as well. We're also having discussions with power generators. And I'd say we continue to see growth in gas-fired generation as well. basically, it comes down to the immense gas transportation portfolio on intra and interstate pipelines that allow us to get -- to have the ability to serve power generators -- power generations in -- across our operations footprint. So we're very well poised for the demand growth story for both power gen demand to pull off transport serving utilities, our ability to connect directly with data centers. And the supply position is what gives us that advantage.

Got it. And then maybe lastly, just sticking with Utica. I think the gas processing capacity up there has been pretty good for you guys to grow into. But I know you guys were working some oil and liquid side, midstream infrastructure projects up there. I'm just curious to get an update on that front, too.

Yes, Josh, this is Jeff. Yes, everything does still look good on the gas processing side up there. We have plenty of capacity. And like we said, we're over in that liquid-rich window. So obviously, any of the just residue associated gas has a lot of that liquid-rich molecules in it that they're really looking forward to grab a hold up.

And then on the oil side, yes, we continue to have really constructive conversations. As I've stated, for the next handful of years, we've got really good oil takeaway, but we're going to focus on really focusing -- getting our net backs up. And as we said, we've got a little bit of a differential there. So there's a couple of things that we can do we can obviously blend some of our lighter molecules with our heavier molecules as we get infrastructure into play, which will actually help those differentials. And then we'll continue to get it on to pipe to try to get to additional markets. And like I said, we're having really constructive conversations, but really nothing to announce right now, but we'll definitely keep you abreast of our progress.

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

Appreciated. We'd also like to thank you to our shareholders for your support and special thanks, especially to our employees for delivering another exceptional quarter.

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

Well, welcome to day 2 of the Barclays 40th Energy and Power Conference. We have a full-packed schedule in the E&P track for the rest of the day. So a lot of great conversation to look forward to. Kicking off the E&P track today is EOG Resources. Jeff Leitzell, CFO (sic) [ COO ], really looking forward to the conversation to start. So Jeff, why don't you join me on stage? And as we've been doing with the conference, we're starting with the audience polling questions. So let's do 2 quick ones to start.

At what oil price do you expect to see a meaningful increase in U.S. shale activity: $70 to $80, $80 to $90, $90 to $100 and more than $100? We're seeing more increasing private activities. All right. $80 -- $90 to $100 -- I think that's pretty fair. It's -- we haven't -- we're seeing more from privates, but certainly not from publics. Next one. What do you see as the most attractive new frontier development area: Argentina, Canada, Middle East, conventional and unconventional or other? Argentina and unconventional and Canada. All right. Well, at least I picked the right one to go on that multiple choice. So thank you very much for participating.

Jeff, thank you so much for being here and having this conversation. I want to kick off with exploration. I think you guys have been talking about exploration and maintaining that expertise for a while, but I think the market is really catching up to it and growing enthusiasm around what you're doing, both in U.S. onshore and international in UAE as well. But before we go to UAE, I want to ask about how EOG's capabilities internally able to set up the company to identify these opportunities early? And what characteristics around these opportunities that make them worthwhile for EOG to pursue?

Yes, that's a great question. And it's -- exploration is near and dear to our heart. It's obviously a big part of the company. It's a core competency. And really, we like to tell people it's part of the actual company's DNA. So one of the things that we've always done since the inception of the company is we really honed that skill set. So it's something we've tried to hold on to. And as we have new generations come in, we try to pass down that information to them. So we have future explorers to continue that skill set.

The other thing is our decentralized structure really helps that out because we have 7 domestic divisions. We have a division in the GCC now. We have one in Trinidad, and then we have an international division in Houston. And each one of those are exploring in their areas, so they can really put a lot of focus and intention on finding what the next resource is in that area. And we've got a very structured way that we look at exploration. What we're trying to do is really look for 4 primary characteristics and at least check 3 of the boxes. I mean, the first one would be scale. It's got to have enough size. You want to have a high rate of return, you want to have low or potential for low F&D, and then you also want shallow decline, if possible.

And those are really the things we look for. And in order to really gauge those things, you have to have some data. So we go into areas. It's nice if there are obviously some penetration points. Maybe there's some geologic data, older vertical data, maybe some older cores, older logs, seismic that we can work on. Maybe there's a little bit of vertical production that we can go ahead and we can extrapolate out to what might happen in the horizontal. We like to see, if possible, maybe there's a little bit of services in the area that we can utilize, and then also infrastructure. If you have some infrastructure in the area, you can really keep your all-ins at the front of the actual play down. So it really makes the full cycle economics that much better.

I think a couple of great examples of what we've recently done. I mean, obviously, people know about the Utica organically exploring and finding that and then making the Encino acquisition. But even if we found that, it doesn't necessarily have to be a greenfield entry. I mean we've seen bypassed pay, step-out areas and extensions just with technology that you're able to explore for. And a couple of good examples of that would be the latest Austin Chalk sweet spot that we talked about there in the Eagle Ford. Just southeast of our Eagle Ford primary, we use that geologic data and reservoir data to find that. And then also, as we've talked about our entry into the GCC, we see a lot of opportunity in international unconventionals. And obviously, our entry into Bahrain, which is an unconventional gas play, and then the UAE, which we're excited about, which is a pure oil play over there with 900,000 acres.

And before we talk about the UAE, maybe how is the opportunity set that's out there in market -- out there in the world today different than what it used to be? We're hearing more and more about governments looking for partnership or opening resource access. So how -- do you think the opportunity set has also improved?

I think it's getting better. Yes, absolutely. I'd say the first thing is we see -- people think that there's inventory degradation and there's no more plays to find domestically. We don't believe that. We still see a lot of opportunity for exploration and to be able to find very economic resource here in the U.S. But yes, as you look internationally, there's been very little unconventional international operations. I mean, obviously, some in Argentina, there's been some up in Canada, but there's unconventional rock all around the world.

It's really just about having some of those boxes checked that I talked about as far as characteristics and hopefully having a little bit of data to get into them. But we have seen an evolution with a lot of the different governments out there where they're becoming much more knowledgeable in understanding not just how conventional operations and financials work, but also unconventional financials. So we've been able to see, we can get in and we can actually partner with some of these entities and get a piece of the actual resource and be able to go in with our technology to exploit it, but then also partner with them to where they can learn off of us from our unconventional technology.

Right. So talking about learning from your unconventional technology, your view is really to transport or export a lot of your capabilities in U.S. unconventional to international to UAE. What gives you the confidence that this can translate given region is different, the equipment might be different? Like -- so what gives you the confidence that what you do in the U.S. can be applied internationally?

Yes. I'd say the easiest thing to point to is the actual success we've had out the gates over there. I mean we knew there was going to potentially be some challenges, but we've been extremely happy with what's happened over there in the UAE. So what that is, is it's a 900,000-acre, first-of-its-kind unconventional concession there in the UAE. And we've went in, we started our exploration program. We have a 3-year exploration phase on it. We've drilled our first handful of wells. What I'd say is, operationally, we're very happy with what we're seeing there. We're able to apply some of the technologies out of the gates, not all of them, but at least initially to be able to look at the reservoirs.

We brought on our first 2 wells, and though they were just 1-mile laterals, not necessarily optimal casing designs or optimal completions, but really just to test the formation. And those wells, they produced each 25,000 barrels of oil in the first 30 days. So -- and with a caveat to that, I'll say, is we had about a week or so that we were having to optimize facilities within that. It's the first time that you're kind of stepping in and you're learning about it. And there's still a lot of upside that you can bring to it. Both of the wells were flowing natural with no artificial lift. And what we've seen is we see great pressure profiles on them, the fluid mix is matching exactly what we thought, and everything is really encouraging.

So I think the exciting thing is we see so much upside with this. There's a lot of improvements that we can continue to make by applying that unconventional technology. And what we're planning on doing now is we're going to move forward. We're going to drill some longer laterals, 2-plus miles, because we've seen the success from the drilling activity and then continue to hone in. We'll work on understanding exactly what's the best target, potentially what's the best spacing. We'll delineate the 900,000 acres to really understand what we have there, confirm the fluid mixes. And yes, we'll hopefully move towards a declaration of commerciality with success in all that, but extremely excited about the opportunity over there in the UAE.

Right. I was going to ask what characteristics do you want to derisk before you get to development plan, and you just gave me a list of the -- on the operational side, on the rock side. Is there anything else on the infrastructure side or on the commercial side that you need to derisk as well?

No. I think everything previous to making the agreement with ADNOC, we had checked a lot of those boxes to make sure that we would have adequate takeaway throughout the life of the play and be able to have that infrastructure in place in a timely manner. So really, what I would say is, we've been asked that multiple times, what are the challenges and what are the hurdles we see. I think, if anything, we see a lot of low-hanging fruit is where we're at. And I would also say ADNOC has been an absolute amazing partner so far out of the gate.

It's really been a hand-in-hand relationship there, complete transparency, sharing, and they've really been willing to work with us and help us remove roadblocks to continue to make that asset better. Some of the things that we're allowed to do, too, is we can bring that technology over, and they know that's very important. We have EOG motors over there on site right now drilling the wells. And actually, we've just started in-basin sand mining in the dunes, which normally, they're transporting in sand and super sacks and from many, many miles away, and we see all this very, very high-quality sand right there. So we're able to permit, and we're actually working with them to show them how to mine sand right there, and it really minimizes the cost and the transportation.

Great. Well, bringing it back home to the Delaware, EOG has continued to find zones and improve the overall recovery of the asset. Where do you think we are in the inning of that asset now? How -- are we -- is it fairly optimized at this point between return, maximizing NPV at a section level versus like return on the individual well level?

Yes. I'd say the Permian is a gift that keeps on giving. And we keep finding ways, whether it's through technology and our development approach, as we lower costs, that we're able to bring forward more and more value there. Now you are correct, it really is a balance of maximizing the total resource extraction with optimizing those economics. And that's something that we've had to kind of work our way through, as you know. And the one thing that we really base ourselves around and underpin everything on as we start kind of our 1A is going to be returns.

And we've got our stringent threshold of a 30% direct after-tax rate of return at $45 WTI and $2.50 Henry Hub gas. And as long as you meet that threshold, you can actually get investment. You have to actually hit that minimum criteria. But once you hit that minimum criteria, you have to continue to optimize the economics. So what we look at is we try to optimize the payout on a well basis. We'd like to have at least probably a payout of less than a year by a well basis. We want to have the ability to obviously drive cost down, improve performance to where you can lower that F&D cost, which obviously flows through to your DD&A rate, and it really helps for margin expansion from that aspect.

So I think that's one thing as technology continues to evolve. So that's pushing the limits out there in the Permian. But not only that, obviously, we drove down our cost over the last handful of years, we talked about 20%. And last year, we brought in numerous new unique targets that meet that threshold and that rate of return. So you're constantly evolving your development approach. You're working on your completions designs, your spacing, you're looking at different targets. So I would never count the Permian out. I think there's still a lot of value as far as different potential targets within the stacked pay and then also extensions in the step-out areas.

But what I'd say is with our Permian acreage, because of this technology and how it's moved forward and being able to really maximize that NPV per acre, that's why we've got such a robust inventory there. I mean we've got 10 years plus of total inventory still in the Permian at our current paces. It's going to have very similar economics and financials to what we have today.

Shifting to the Utica. That's your newest foundational asset in the U.S. You're gathering more and more data. There's more development on that asset. Is there new things that you're finding, operational advantages or new data that's influencing how you think about the development of that play going forward?

Yes, it's been a great progression there. And I'd say kind of out the gates, we haven't had a miss in the Utica all the way from exploration to delineation. And it really has to go back to understanding the rock. And really what makes the Utica work, which many have looked for it and tested it over the years, is you have to understand depositionally where you're actually at throughout the play. So if you look at the play and you start over to the east and you're over near Pennsylvania, you're deep in the basin. So you're in very mature gas.

But as you start to move into Ohio, you start moving updip, you get into a condensate window and then a volatile oil window and then up into an actual black oil window as you continue to shallow up in the section. And what we found was that volatile oil window is really the key point. You get to a point where you still have enough depth and pressure to really get good production rates and you also get enough associated gas along with that oil to help really energize and lift the well throughout its life. And that really seems to be one of the better productive areas. So that's really where we're focused on at this point.

And then as we got into continued delineation, we noticed there is differences within the rock as you move kind of from north to south. In the north, you tend to have maybe a little thicker section without an actual frac barrier. So it's very conducive to maybe stacks or staggers up there, and you can have a little bit tighter spacing because you don't have that barrier that you'll frac into and then frac out. Down in the south is a little different. We have a very robust frac barrier down there. So your spacing, you might have to space out just a little bit wider because you tend to frac up and actually hit that barrier there.

But just through our success here in the first handful of years, it's really given us the confidence to move forward, actually make the Encino acquisition, which we did last year, below mid-cycle pricing, which is normally kind of what our target would be for an acquisition like that. We're able to increase that volatile oil window by over double, to 485,000 acres. And then also, on top of it, we got about 300,000 of premium gas acreage, which we're not focused on the gas window. We really are focused on that volatile oil, but we did acquire a DUC package in there and went in. It was 3.5-mile wells, 3-well package. We just wanted to see what the performance was, and each one of the wells came on at 35-plus million a day. So very prolific gas that came along with it.

And then from an operational front, we've just had huge success, especially with the combined company between Encino and us. So on the drilling side, we've been able to reduce our feet per day drilled by 23%. On the completion side, we've been able to increase the feet per day, I should say, for both of those by 12%. We were able -- with our supply chain, we have a robust supply chain group that's really worked hard, and I think we've dropped our casing and tubular costs by about 30% there. And then on the facility side, just with doing much more centralized facilities and bringing our knowledge to that, we've reduced it by about 20%.

So when you roll all that up combined between the 2 companies, we're well below $600 a foot. And I think the exciting thing is we still have a long way to go because we actually are partnering with a third party, and we're going to be opening the first in-basin sand mine in Ohio, and it's right in the center of our field, prolific reserves for kind of the life of our play, and it's really going to minimize transportation and the overall cost of getting sand to our location.

Is that already accounted for in the $600?

No, that is all icing on the cake. The actual sand plant will be up and running, we hope, by the end of the year. So that will all just be extra potential savings that we can see.

I think it's one distinction that Utica is a liquids play for EOG that comes with a gas optionality and you explore that optionality with the gas pad. And -- but what you really -- the real gas asset is Dorado in South Texas, and you pulled activity back a bit this year given the lower gas price environment, but it still serves as a strategic gas asset. So how does the gas strategy fit into EOG's portfolio? There's a lot of -- certainly a lot of talks about data centers and adding more gas power plants in Texas. So just how do you exercise the gas assets in the portfolio?

Yes. I think Dorado, it was very strategic from the get-go. We knew gas was going to be a big part of the future. We wanted to look for prolific resource that was very, very close to the coast. And that's exactly what we found. It was close to the market center. We've got almost 20 Tcf of gas there. And really, what we've done is we've kind of stood up a whole separate gas company next to our actual oil company. We think it's the cheapest gas in the U.S., low cost at about $1.40 breakeven price. The wells come on very, very strong as we talked about. We keep them very choked back at kind of 20 million to 25 million a day. So it's prolific. You can bring on a lot of volumes very, very quickly.

And when we saw the early success in it, we knew we were going to have a large resource down there, and we're going to need a way to get it to market. So we actually went out to market and saw, asked third parties what it would cost to put the infrastructure in, didn't like what we were seeing for fees and stuff coming back. So we decided to go ahead and be opportunistic and lean in and build out the pipeline down there. So we actually fully own, it's all EOG's capacity, 100-mile, 36-inch pipeline that goes from basically the center of the field over to Agua Dulce, which is a market center. And it has a 1 Bcf base capacity, which, as I said, is all EOG's, but it's easily expandable up to about 1.7 Bcf a day just with some booster compression that take us very minimal time to set and put it in place. So we're extremely excited about it.

And then we can actually tie it in with all of our great marketing and the marketing strategy that we've had about diversification and flexibility there on the coast. We've got our LNG agreements where we've got close to 1 Bcf of offtake over there. All of our Cheniere agreements are on, which includes 420,000 MMBtu, which is monthly election, either JKM or Henry Hub linked. So we can elect that on a monthly basis. Also, we've got 300,000 MMBtu a day that's linked directly to Henry Hub without any differentials.

And then looking for more market exposure on the international front, we actually recently did a deal with Vitol for 140,000 MMBtu, which is Brent-linked, which helps take some of the volatility out and get more of that international linked pricing. And that comes along with, I think, 40,000 a day Houston Ship Channel. And then on top of that, we also took out about 360 million a day on Transco's TLEP line, which actually runs all the way around the coast, over to the Southeast market center, which is where you really have premium.

So yes, we can flex Dorado very, very quickly in response to the market whenever gas is needed. Obviously, we'll keep an eye on the gas market as LNG continues to pick up there on the coast. And then also, as you talked about, the opportunity for additional power demand in data centers as that continues to evolve with time.

Yes. I think the commercial strategy is worth highlighting because being able to think ahead of the time, ahead of the market and get these agreements in early really extract value long term. Are you -- is there a thing that you -- that opportunities in the market that -- on the commercialization side, on the marketing side as interesting or as we think ahead for the next 5-plus years?

Yes. I mean, I think there's still a lot of opportunities to get international pricing on the LNG side. Our initial Cheniere agreement was very unique. And it's tough to get another agreement like that, but we're getting creative. We're trying to link it to different international markets to make sure we have a premium, and it gives us lots of flexibility.

I mean, also, as you talked about here domestically, there is a lot of interest from the data center side. I think it's just a matter of it maturing a little bit more in that market and getting to a point where we would like a premium price, obviously, for our gas. And I think a lot of the data centers, they would like cheap, reliable gas. So finding the right price in the middle that makes the right choice for the company. And I think, really, you can kind of look at some of those deals almost as like a hedge if you were to do it. So I think it's strategic, and they work in areas where you have stranded gas, and there's potential opportunity, like I said, as that market evolves.

Okay. That makes sense. On technology, EOG has always been the technology leader. And in my seat, what I just find we're in this technology renaissance that they're seeing new different ideas and innovation that's making the assets better. Are you seeing -- like, where are you seeing the most change or competitive advantage where -- that technologies bring to EOG's assets?

Yes. Technology is constantly evolving. And I think we look at it from kind of a multifaceted lens because we're constantly innovating, trying different things. And I'd probably break it down into 3 categories for EOG. The first is well performance or really what we want to talk about is recovery factor because that's what the holy grail is. One of the things that we've done, I think, that's unique is we're really focused on what we call our ultra-high-intensity completions, which they're unique from a multitude of angles.

So the first thing is each well and wellbore, we designed specifically for what treatment we need to really maximize the overall productivity of it. And what we've also done is with our actual frac fleets -- I mean, the majority of our frac fleets can do 200, 240 barrels a minute. So we have a lot of energy that we're able to apply downhole. And the main focus there is to be able to uniformly distribute that energy along the rock within a stage to maximize your overall surface area. And ultimately, thereby introducing and creating as much fracture face that you can contact with the wellbore, that's what you're creating really there is that connectivity to the wellbore that increases your overall recovery factor and your performance.

And we've had a lot of success. We've talked about the success we've had over the last 5-plus years in the Permian, and we continue to test new iterations of that. And then most recently down in Dorado, where just last year alone, we've had upwards of 15% to 20% increase in productivity by applying those high-intensity completions. So I still see a long way to go there. Like I said, we're designing specific wellbores now to really remove any kind of limits or restrictions we have, and we're really seeing a lot of great progress with that technology.

The second, I would say, would be probably cost and efficiency side. One of the big things we always talk about, but we're only really kind of at 30% utilization in the company, is the EOG motor program. It's something where we stepped into the market. We tried to partner with some drilling motor companies. But what we saw was we wanted to push the motors to the limit, find out what would break and then redesign them to where we could understand on the metallurgy, on the connections, on the components, what needed to get better, so we could basically create the indestructible motor. It was tough to partner with anybody. So we said, "I guess we're getting into the motor business."

And it's just been a home run. We've seen great success all across the portfolio. And I'd say probably the greatest success to point to is even in Dorado. It's our toughest drilling. It's high pressure. It's high-temperature drilling down there. And the majority of the wells that we actually drill, we can actually drill the vertical, the curve and the lateral, all the way out multiple miles with one BHA, and those are mostly all EOG motors. So that's one of the technologies that I think we're really pushing has a lot of upside.

Another, I would say, is continuous pumping. We're to the point we don't even shut down on frac jobs. We basically will go ahead and lower our rate down to about 10 barrels a minute. We have auto valve systems that close the wells you're on, open the new wells and automatically redirect the rate, and you go ahead and ramp your rate back up. So there's really no downtime whatsoever in between stages. And we've also seen it has a huge effect on the maintenance side of it. We've actually created barriers withinside of our fleet. So you don't have to pull them out of line to work on them. You can basically take it offline, remove it from the pressure, but you don't have to move that pump, and you can continue pumping with the rest of it. So a lot of great stuff going on that.

And the last one I would say that's kind of hitting a lot of the industry in the world is data analytics. We have really 2 areas, I would say, sensors and in the AI realm. In the sensor realm, what we've done is we've started putting a lot of sensors downhole where we're able to capture very valuable geologic data, things like Poisson's ratio and Young's modulus, understanding where fractures are within the rock, and we can get that data and obviously apply it as we continue to drill the well, into our completions and onto the next wells on. We've also taken those sensors and we placed them on all sorts of surface equipment.

So we're constantly listening or recording the vibrations in it. And if you see any kind of change in the harmonics, you can identify failures of all sorts of equipment before it actually fails so you can minimize the damage to it, you can quickly shut it down, fix it and you don't have major downtime events. So that's been very, very big for the company, and we've really been rolling that out heavily over the last couple of years.

And then the last one is AI. What I'd say is it's becoming a big part of our business as it is with everybody's daily life. What I would say is this, it's not going to replace our people. Our people are truly our resource, and they're the innovators out there to push the limits on what's going to be next in the industry. But it's taking those monotonous tasks, whether it's documentation, reporting, whether it's the analytical side of it, whether it's even just software engineering and programming, it can take those monotonous tasks off, do them very quickly and allow our people on really focusing on innovation and adding more value for the company.

And I'm hearing better wells, lower cost and more efficient organization. We are hearing more about inflation commentaries here at the conference, particularly from services. I think for -- does that basically offset everything you're saying on the technology and efficiencies that basically can offset the inflation? Or where do you think the cost trend net of everything is trending?

Yes. I'd say on the services side and the cost side, there has been some slight inflation, but we really haven't seen a huge shift. We've got very strategic partners. We're one of those people where we don't gouge them for the lowest cost whenever it's a downturn, and they don't gouge us for the highest cost whenever it's an upturn. So I think that's one thing. The other thing is we're very insulated from the market. I mean diesel has been something that there's been huge inflation in across the board, and we're going to continue to have higher diesel costs. Well, the majority of all our field operations run off natural gas. 70-plus percent of our rigs run off natural gas, and 100% of our completion fleets run off natural gas. So that's been a great insulator.

The other thing I think we got to keep an eye on is steel has started to increase across the market. So we've leveraged our inventory where we normally keep kind of a 6- to 12-month inventory wherever it is, so we can opportunistically purchase ahead of time and really try to insulate ourselves from that. We've already started purchasing well into '27 to try to insulate ourselves. So yes, I think it's a multitude of things. You've got to be more efficient, utilize the technology, continue to drive your cost down those ways, but you also need to insulate yourself from the market by doing a lot of self-sourcing and making sure that you're going out and you're procuring the things that you need ahead of time at the right price.

Great. Well, unfortunately, we're running out -- we're out of time. But Jeff, thank you so much for this conversation. There's a lot going on with the portfolio. So thank you.

Yes. Thank you so much.

Good day, everyone, and welcome to EOG Resources Second Quarter 2026 Earnings Results Conference Call. As a reminder, this call is being recorded. For opening remarks and introductions, I will turn the call over to EOG Resources' Vice President of Investor Relations, Mr. Pearce Hammond. Please go ahead, sir.

Good morning, and thank you for joining us for the EOG Resources Second Quarter 2026 Earnings Conference Call. An updated investor presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today.

As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations section of EOG's website. In addition, any reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines.

Participating on the call this morning are Ezra Yacob, Chairman and Chief Executive Officer; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Chief Financial Officer; and Keith Trasko, Senior Vice President, Exploration and Production.

Here's Ezra.

Thanks, Pearce. Good morning, and thank you for joining us. EOG delivered exceptional second quarter results with adjusted earnings per share, adjusted cash flow per share and free cash flow all reaching record levels. Robust oil prices provided a meaningful tailwind, but these results reflect something more durable: consistent high-quality execution across the company. We expect that operational momentum to carry through the second half of the year. Our low-cost multi-basin asset base and peer-leading balance sheet place EOG in a strong position to navigate today's dynamic macro environment.

Consistent with our commitment to disciplined capital allocation and enhancing shareholder value and underscoring our confidence in the strength of EOG's business, we returned just over $1.8 billion to shareholders in the second quarter through our regular dividend and opportunistic share repurchases, reflecting our conviction in EOG's value and our growing opportunity set. Comparing our performance to a recent quarter with similar oil prices offers a useful lens for appreciating how substantially EOG's business has improved. Since the first quarter of 2022, when the Russia-Ukraine war broke out, EOG has grown oil production 22%, total production by 60%, adjusted cash flow per share by 44% and the regular dividend by 36%.

This impressive progress is underpinned by several achievements. Over the same period, we forged a stronger path to future value creation by improving our multi-basin portfolio with 2 additional foundational assets, expanding a deep exploration pipeline, including high-quality international unconventional opportunities and enhancing our marketing flexibility and end market diversification. We accomplished all of this while preserving a pristine balance sheet and paying a growing regular dividend, which has been stress-tested across a range of commodity price scenarios. Taken together, these accomplishments are a clear demonstration of EOG's business model in action.

Turning to the oil macro outlook. Supply disruptions associated with the Iran conflict continue to weigh on global inventories with the trajectory and duration of the conflict remaining key variables in shaping near-term market conditions. While we expect oil prices to remain volatile given the fluid nature of the war, we remain constructive on oil market fundamentals for several reasons. First, the disruption of crude and product supply from the Middle East has resulted in a meaningful reduction in commercial inventories and strategic petroleum reserves.

Second, while reduced demand has partially offset supply loss in the near term, we do not view this as a structural shift. Rather, it reflects temporary rationing that we expect to normalize over time. Third, energy security has emerged as a strategic priority across many nations, and we expect this to translate into structurally higher oil demand over time as countries look to strengthen their energy positions and restock both commercial and strategic petroleum reserves. Taken together, these factors support oil prices remaining above mid-cycle levels in both the near and medium term with price volatility likely skewed to the upside.

On natural gas, we continue to see the North American market evolve from a seasonal commodity story into a strategic energy resource. While storage levels will continue to fluctuate year-to-year, the underlying demand trajectory is strengthening as LNG exports, electricity demand, industrial growth and grid reliability increasingly compete for domestic supply. Our medium- to long-term outlook remains constructive, and our deliberate investment in building a low-cost natural gas position with access to premium markets and as a complement to our core oil business leaves us well positioned to capitalize on this demand growth.

Regardless of commodity prices, EOG's commitment is to deliver sustainable value creation through industry cycles. We pursue that by focusing on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy. This mission rests on four pillars: capital discipline, operational excellence, sustainability and culture. Today, I want to discuss in greater detail one area of our operational excellence pillar that is a significant differentiator versus peers: organic exploration.

Organic exploration has been central to EOG's success since the company's founding. By identifying opportunities early and building positions ahead of broader market interest, we are able to create significant long-term returns. Supported by a proprietary database and the knowledge gained from thousands of wells drilled across a wide range of geologic settings, EOG has a proven ability to discover and develop new resource opportunities. Today, that expertise is demonstrated in international unconventionals, where EOG is a first-mover working in close partnership with ADNOC in the UAE and Bapco in Bahrain.

For national oil companies looking to develop their unconventional resources, we offer a compelling partnership. EOG brings technical leadership, a proven track record and the ability to accelerate their development programs. Our UAE exploration program provides a convincing proof point. We drilled, completed and brought online 2 1-mile lateral wells in June and are extremely pleased with the results. During the first 30 days of production operations, the wells produced on average over 25,000 barrels of oil per well. Both wells are naturally flowing up casing and will be placed on artificial lift in the coming weeks.

Early well results are exceeding our expectations during the natural flow period. There is still meaningful work ahead in the UAE given the size of the 900,000-acre concession, but we are extremely encouraged by what we are seeing in the early days of this important project, confirming that EOG's competitive advantage is not confined to a specific geographical location. It is embedded in our technical expertise and resource development approach.

On the domestic side, we continue to run a robust exploration program, testing multiple plays across the U.S. Each domestic division is actively advancing its own pipeline of exploration prospects, and we look forward to sharing updates as those programs mature.

In summary, we're off to a strong start in 2026 and are well positioned to execute in the current macro environment and beyond. We remain focused on delivering sustainable free cash flow, maintaining operational excellence and creating long-term value for shareholders.

I'll now turn it over to Ann for details on our financial performance.

Thank you, Ezra. EOG delivered another quarter of outstanding financial results, which speak to the durability and discipline at the core of our business model. In the second quarter, we delivered adjusted earnings per share of $5.07 and adjusted cash flow from operations per share of $8.29, generating free cash flow of $2.8 billion, a record performance and a direct reflection of our low-cost operating structure and capital efficiency. We returned just over $1.8 billion to shareholders during the second quarter, $540 million through our regular dividend and $1.3 billion in share repurchases.

The foundation of our cash return remains our regular dividend, which we have not cut or suspended in 28 years. This is an impressive track record in any industry and demonstrates our commitment to return value back to shareholders. We continue to supplement the regular dividend with share buybacks. With $11.7 billion remaining under the share repurchase authorization at June 30, we have substantial capacity for continued opportunistic buybacks. Through the first half of the year, total shareholder returns stand at approximately $2.8 billion, and we reiterate our commitment to returning at least 70% of annual free cash flow to shareholders -- to investors in 2026.

Our balance sheet remains a strategic asset. We closed the quarter with $4.9 billion in cash, up approximately $1.1 billion from the end of the first quarter, and with net debt of $3 billion. This financial strength continues to provide a stable foundation as we navigate dynamic macro environment shifts. At strip pricing and using guidance midpoints, our 2026 plan generates $8 billion in free cash flow. Our 2026 program funds production growth, domestic and international exploration and a peer-leading regular dividend, all at a WTI breakeven price below $50 per barrel.

EOG's financial foundation has never been stronger. We are generating significant free cash flow, returning meaningful cash to shareholders and maintaining financial flexibility to capitalize on opportunities as they emerge. This combination of operational excellence, a low-cost structure and financial discipline positions us exceptionally well, not only for 2026, but for sustained long-term value creation.

With that, I'll turn it over to Jeff to discuss our operating results.

Thanks, Ann. I'd like to begin by recognizing our employees for their outstanding performance and execution. In the second quarter, we delivered strong operational results, highlighted by lower-than-expected LOE and GP&T expenses and total company volumes higher than our guidance midpoint. Total company volumes included nearly 500 barrels of oil per day, primarily from initial production from our UAE exploration wells as reported in our Other International segment. Second quarter capital expenditures came in below the guidance midpoint, primarily driven by shifts in operational timing, largely in the Gulf states.

For the full year 2026, we expect to deliver 5% oil production growth and 14% total production growth with capital expenditures unchanged at $6.5 billion. As Ezra previously highlighted, we are extremely pleased with our exploration efforts in the UAE. Along with strong initial well results, we also saw exceptional operational performance. For the balance of the year in the UAE, we are targeting lateral lengths in excess of 2 miles and will be completing additional wells.

We have also successfully replicated key elements from our domestic operations playbook to realize immediate cost reductions in the UAE. An example includes utilizing in-basin surface sand processing, which can be located directly adjacent to our well locations, thereby minimizing transportation and processing costs of our future completions. In Bahrain, operations have been intermittent due to the ongoing conflict. While we hope to have results in the second half of the year, our priority is the safety of our employees, contractors and partners in the region.

Turning to domestic operations. Our Delaware Basin team continues to execute well on their development strategy. Well performance has been in line with our expectations. We continue to develop this world-class asset at the right pace, resulting in continued operational improvements. We are realizing drilling and completion efficiencies relative to last year. Year-to-date drilling feet per day is up 13%, and year-to-date completed lateral feet per day is up 5%. These efficiency gains are contributing to well cost reductions as year-to-date, we have been able to reduce direct well costs by $15 per foot with direct well costs averaging less than $710 per foot.

In addition, our Janus gas processing plant continues to deliver outstanding results. This strategic infrastructure project came online last year with current capacity of 300 million cubic feet per day and is expandable by an additional 300 million cubic feet per day. Year-to-date, Janus plant utilization is averaging greater than 99%, and we are realizing a netback uplift of more than $0.65 per Mcf, helping support our strong margins in the Delaware Basin.

Eagle Ford operations are also performing strongly this year. Year-to-date, we have been able to increase drilled feet per day by 4% and completed lateral feet per day by 11% compared to 2025. These efficiency gains have helped drive further well cost reductions. We have reduced Eagle Ford direct well costs to less than $525 per foot, which is the lowest in our long history in the play. In the second quarter, we drilled the Aspen L 11H, which is the longest lateral drilled in the Eagle Ford to date with a drilled lateral of 24,115 feet or more than 4.5 miles.

Each year, we continue to unlock additional resource across the Eagle Ford oil trend through cost reductions as well as through organic leasing and strategic acquisitions. Last year, we acquired approximately 30,000 net acres in Atascosa County. We have since drilled 20 net wells on the acquired acreage with these wells achieving a less than 1-year payout at $65 WTI. This quarter, we are announcing an exciting Austin Chalk sweet spot in Lavaca County. We utilized our robust understanding of the regional geologic and reservoir model to identify this extension to our Eagle Ford acreage that also achieves a less than 1-year payout at $65 WTI.

We have organically leased 60,000 net acres for an average cost of $1,200 per acre and drilled over a dozen wells confirming this high-return prospect. These high-pressure wells offer high deliverability and benefit from our learnings in other basins. We have confidently identified 1 year's worth of 2-mile lateral inventories at current Eagle Ford activity levels. Furthermore, we continue to gather data and evaluate its extent.

Further south in Dorado, this low-cost dry gas asset continues to improve. In 2026, we have increased lateral lengths by approximately 16% compared to last year and are further lowering well cost. Year-to-date, direct well costs are less than $700 per foot or 7% lower than last year. In addition, the countercyclical investment in the Verde gas pipeline continues to pay dividends as we are realizing a netback uplift of $0.50 per Mcf year-to-date.

In the Utica, our Encino acquisition has been a home run. Number one, we have exceeded our $150 million synergy target ahead of schedule. We have driven direct well costs below $600 per foot and continued reductions in sight. Number three, we continue to push margin expansion through supply chain optimization, including in-basin sand, which should be secured by the end of this year. And number four, EOG's proprietary in-house production optimizers delivered a 5% improvement in base production and a 5% reduction in downtime. In summary, combining the scale of this asset with our technology, technical expertise and operating model has led to stronger capital efficiency and demonstrates the meaningful value created through successful integration and disciplined execution.

Turning to the broader service cost environment. There has been slight inflation across various services, but we have been able to mitigate most of it and are still expecting a low single-digit reduction in well costs this year. A perfect example of how we are able to dampen inflation is our in-house drilling motor program, which is generating meaningful value. Since 2023, we have achieved a 70% increase in average drilled footage per motor run.

Looking at year-to-date motor performance by basin, average footage per motor run has increased 34% in the Delaware Basin, 43% in the Utica, 20% in the Eagle Ford and 64% in Dorado, in each case compared to third-party motors. The potential savings by eliminating 1 motor failure ranges from $100,000 to $250,000, a meaningful contribution to our overall cost reduction efforts. We enter the second half of 2026 with strong momentum and are well positioned to execute on our full year plan.

With that, I'll turn it back to Ezra for closing remarks.

Thanks, Jeff. Before we open the line for questions, I want to leave you with 3 thoughts. First, EOG delivered record financial performance in the second quarter. Operations across our foundational assets are executing at a high level, and we expect that momentum to carry through the back half of the year.

Second, organic exploration is one of EOG's most important competitive advantages. We identify opportunities early, move decisively and apply the same rigorous data-driven approach that is expanding our U.S. business into new basins around the world. The international unconventional opportunity set is real, and our international operations demonstrate that the EOG model can be successfully applied beyond North America. Third, everything we've discussed today reflects how this company operates, grounded in capital discipline, operational excellence and sustainability, all underpinned by our culture.

We appreciate your time and continued interest in EOG. Now let's open it up for questions.

[Operator Instructions] The first question comes from Josh Silverstein from UBS.

On the first quarter update, you had made a shift towards more capital, towards liquids versus gas development, which was clearly the right move for this year. Ezra, in your comments, it sounds like you're still pretty constructive on oil prices. So as you're starting to plan for next year with the forward curve around $70 WTI and $3.35 for Henry Hub, are you continuing down this path and continue to push more capital towards the more oil-prone plays?

Josh, that's a great question. So our '26 plan, it remains unchanged from last quarter. We updated the volume guidance, obviously, to reflect year-to-date performance. Last quarter, as you said, we did take advantage of the flexibility across our multi-basin portfolio to reallocate some capital across our foundational assets, which resulted in incremental oil volumes this year, and it also better positioned us for '27. So while I think it's still a little too early to get into specifics on '27, I would say that as we assess oil market fundamentals, we do see the potential need for incremental supply.

This is where we sit today. And if this continues to be the case, I would expect our plan for next year to really be reflective of our 3-year scenario, which basically reflects a low single-digit oil growth, and we put some financial metrics on there, assuming kind of a WTI price range of $60 to $80 oil. I would say that we continue to preserve a lot of optionality, and we'll continue to assess all considerations, including the macros as we move throughout the rest of this year and further define our plan for 2027.

Got it. And then maybe just one on the UAE as well. I was hoping to get a little bit more color on next steps and maybe a time line here. I know you're bringing in some artificial lift and then have some longer laterals here. Is there any shot clock that you guys are under now, a certain number of wells that you need to drill to get to a certain point before kind of bringing this into more commercial development?

Yes, Josh, that's a great question. I love talking about the UAE this morning. We're extremely excited about our progress in the region. We entered the region because we saw pretty compelling subsurface opportunities with positive production results from prior horizontal development. We were able to partner to come up with some great partners there. And what we've accomplished early in the early stages here, particularly in the UAE, has really reinforced our conviction. Now we do have, I think we've talked about it before, a 3-year exploration phase, and it is a JV structure with where ADNOC has the option to back in.

But other than that, we consider this to be in an exploration phase. And so I wouldn't say we're holding ourselves to any strict time lines or strict results. We'll take the data in as it comes. We continue to be active there. And as we move forward, we are looking for some -- these are initial wells in a frontier basin, and so we are looking for not only well results, but how the wells produce over time, how they'll respond to the artificial lift. And then we're looking for some other things. We'd like to delineate a wider range across the 900,000-acre concession. Obviously, it would be difficult to delineate the entire 900,000 acres, but we do have some different geologic environments that we've captured with that concession. And so we'd like to test some repeatability through there.

And then we also would like to see how the service industry matures, if they respond as quickly as we're moving such that we can get some additional unconventional equipment into the region. I think the biggest takeaway here is what we've demonstrated so far is that it probably doesn't come to anyone as a big surprise that there is oil in the UAE. But I think most importantly, the way we think about this internally is this isn't just another shale play. What this demonstrates really is the real opportunity that exists for international unconventionals and the real opportunity and competitive advantage we have if we can successfully apply our operating model abroad.

The next question comes from Steve Richardson from Evercore.

Ezra, curious on the Chalk and how you think about -- I guess, two points. One was you're talking about it. So should we assume that you're kind of done leasing in this area because you're willing to talk about it? And two, how do you think about capital allocation in South Texas based on Chalk versus the more structural elements there versus what's going on in the legacy foundation in the Eagle Ford? And so maybe the starting point, just think about how you thinking about feathering the Chalk into the development program and what the broader resource opportunity is.

Yes, Steve, this is Jeff. I'll just kind of give you a quick update on the Chalk. And as we talked about in our opening remarks, we did. We identified and leased about 60,000 acres in the Austin Chalk. And what I would call that is it's truly a sweet spot. So we are still trying to figure out the extent of it, but we really feel like we've leased up the majority of the sweet spot, and that's why we're able to talk about it right now. And where it sits, it's actually just southeast of our Eastern Eagle Ford acreage, just to kind of give you where the position is on it.

So we acquired the acreage primarily through organic leasing, maybe some small acquisitions on average for around $1,200 an acre down there. And to date, so far, we've drilled about 12 really high rate of return wells that confirm that the play has really strong economics that meet our hurdle rates. Currently, we're seeing on the wells that we've drilled payouts of less than 1 year and the returns are over 100% at $65 WTI, which it's competitive. It's kind of right in the middle with our core Eagle Ford asset there.

The other thing I'll say to give more detail on the play is it is a little bit more down dip in the Eagle Ford. It does get a little bit more deeper and mature. So it tends to be a little bit more of a combo play with more associated gas. But when you look at total liquids yields, it's very comparable to the Eagle Ford proper there. We've identified in this 600,000 (sic) [ 60,000 ] acre sweet spot, about 125 remaining 2-mile locations. And what that really does is it adds about 1 additional full year of drilling inventory at current pace to our San Antonio division. And as far as from a capital allocation, I think they'll just kind of be equally within our core Eagle Ford development from that aspect.

Like I said, we're talking about a sweet spot. So it will just be pretty much in the mix of our standard Eagle Ford and Austin Chalk proper core development will develop over the next handful of years. And when you roll all this up, what I'd just like to say is this really is -- it shows the benefit of the company's decentralized culture and divisions. In each one of our divisions, we're always looking for these new opportunities, play extensions or bypass pay that they can continue to add value in each one of their areas. And then also, we look to leverage our technical and operational expertise. And we really did that in this Austin Chalk sweet spot because moving down south, we really got to lean on kind of our high-temperature, high-pressure operations from Dorado and apply a lot of our learnings there to really push it forward.

So it's just another great example of how we leverage our exploration expertise to continue to extend the resource life in each one of our divisions and continue to improve the returns profile of the company.

It's great. Thanks for the extra color, Jeff. Ezra, I wonder if I could follow up on international a little bit. It seems like what you're saying is EOG should be a partner of choice for countries or geographies looking at unconventional development. Is it fair to assume that you're in active discussions in other places? And I know EOG has a long history operating internationally, but maybe just give a scope of -- again, I know you're not going to talk about specific areas, but just in terms of those conversations and how they've picked up because I'm sure the well results today will -- people will take notice.

Yes, Steve, I appreciate that color. We've always maintained an international exploration program. As you know -- everyone on the call really has followed us for a number of years. We appreciate that support. And so you guys know that we've been in and out of a number of different international opportunity sets, including the Sichuan Basin in China. We had an exploration play a number of years ago in Oman as well. And those things really build upon one another. It was the relationships and some of the technical achievements we made in Oman that really helped kick off the relationship with both Bapco and ADNOC.

And I think you're right. I think this will continue to open up opportunities. That's not to say we're not exploring domestically. We actually still have a larger domestic exploration program than international. And part of that reason is because it is a bit of a heavier lift to get an international prospect across the kind of finish line for us. It begins with the quality of the subsurface. We've talked about this before. It needs to have the size and scale and certainly the economics to more than compete with our domestic portfolio. And I'd say that includes potential access to premium markets.

The other thing is exceptional partners, geopolitical stability. And if available, we really prefer areas that have existing oilfield services, areas where we can leverage our technologies and expertise and really build out, like I said a few minutes ago, really apply the EOG operating model. So ultimately, we are focused on pursuing additional opportunities that meet both the subsurface and above-ground considerations that ultimately have the scale and economics to compete.

The next question comes from Arun Jayaram from JPMorgan Securities.

Ezra, I was wondering if you could perhaps compare and contrast what you're seeing early on in the unconventional oil play in the UAE to U.S. resource plays. Obviously, you've been in quite a few, including the Eagle Ford, Delaware. But perhaps maybe compare what you're seeing from a geological perspective, quality of the rock. Are there any good analogies to talk to about with investors this morning?

Arun, this is Keith. Yes, we have seen -- I think we've talked about before that the big analog we see in the UAE is a comparison to the Eagle Ford. We see that on the rock type. We see that on the product mix. We had a model going into the UAE play. It was a black oil play and drew analogs from the Eagle Ford. And the well results from our first 2 wells are in line with those expectations, including the GOR and the API.

When you just look at what we see in the U.S., we're extremely excited about our domestic exploration efforts. We have multiple exploration projects working in all of our divisions. I think the Austin Chalk addition that we announced this quarter is a great example of how our teams are using successful play analogs and operational capabilities developed across the portfolio to better understand, enhance the economics of new basins like in the UAE and as well as older legacy basins. We also have several unconventional prospects in the Lower 48 working as well as a conventional sandstone prospect in Alaska.

So our organic exploration really has always been a core competency for EOG. We've built deep technical expertise, proprietary databases and amass learnings from drilling thousands of wells across multiple rock types. We focus our exploration really on adding to the top of our inventory, elevating the overall quality of the assets rather than just adding resource. I think our track record for exploration kind of speaks for itself. Over the last several years, we've improved the quality of our resource base, expanded our portfolio of foundational assets, including Utica and Dorado, while also expanding the exploration efforts in Bahrain and the UAE.

Great. And my follow-up is how -- could you maybe mention how deep these wells are? And one of the questions we've been getting last night was how does EOG see D&C costs in this place evolving over time relative to what we see in the Lower 48.

Arun, this is Jeff. I'll touch on the well cost side real quick. The first thing, obviously, we'll point out, which you're very well aware of, is we're real early on in the process here in the UAE. But as in any exploration play, our initial well costs, they'll tend to be a little bit higher starting out, and then we'll work them down over time as we do with all of our plays kind of through the process. A few things that I'd keep in mind is, for the exploration phase right now, we're using many of the service providers already in the region, and they tend to have adequate services and equipment for the exploration phase, but there's definitely many improvements that can be made by utilizing true unconventional services. So that's one thing that we'll kind of look to improve on over time.

And then also as we apply EOG's best practices and technical knowledge, we get high-spec rigs, EOG motors, high-rate frac fleets over there, in-basin sand. Once you really apply all these things over time and drill more and more wells, we'll continue to kind of drop down that well cost over time. And then on your overall total depth of this play, obviously, it's 900,000 total acreage, so it does vary a little bit. But I'd say somewhere around the 10,000-foot TVD would probably be a pretty good average to use.

The next question comes from Scott Hanold from RBC Capital Markets.

A lot of discussion around exploration today, and I'd like to take that maybe a little bit further. And when you look at domestic, I guess, Lower 48 opportunities, like how do you kind of compare and contrast opportunities up in Canada? I mean there's some discussion about EOG maybe looking up there. And what -- when you think about the Lower 48 in Canada specifically, what is your view? Is there too much egress issue? Is the resource good enough? Do you have an opinion there?

I'm sorry, can you hear me?

Sorry, Scott, that was my fault. This is Ezra. Yes, to your question on overall exploration, especially, I think you really referenced Canada there. Let me just say that Canada, I think you're right. You always need to enter with an eye on egress. It is really the challenging thing up in Canada. Now they've done some things on the regulatory side, and there's been some investment in the region that hopefully will clean some of that up in the future. I would say some of the well-known parts of the area, the Deep Basin and some of the areas where the Duvernay has started to show some potential over the last few years. There are a lot of Canadian junior companies up there that have done a lot of work.

I do think the region is one that would potentially benefit from some of the technologies that have been utilized more so here in the Lower 48 in the Permian, certainly in the Eagle Ford and some of the things that we're doing in the Utica. But overall, what I would say is comparing and contrasting international versus what's in the U.S. for domestic resource, as Keith alluded to, we still see a robust opportunity set in the Lower 48 as well. Everything these days is essentially some form of bypass pay, to be perfectly honest. I wouldn't say they're necessarily frontier basins in the Lower 48 left. But there are a lot of places where new technology needs to be reapplied to potentially some of the older resources, both conventional and unconventional that haven't been looked at in a little while.

As Keith alluded to, I think you're starting to see that kind of renaissance in Alaska as well, where whether it's new geologic models up there or new seismic processing is really starting to unlock a lot of resource in an area that historically, obviously, is well known to be resource abundant. And I think the same thing extends into Canada, certainly into Alberta.

Appreciate the context. And if we could chat a little bit on Permian well performance. I mean it was a big discussion point last quarter on how strong your early '26 wells have looked. It looks like it kind of continues that. I know you all discussed relative productivity year-over-year being somewhat flat, but you guys got a good head start. And is this a trend that you all see could continue? Or are you still expecting relatively flat year-over-year productivity?

Scott, this is Jeff. Yes, as we talked about on previous calls and we've highlighted, we had a shift in our development strategy there last year, added in multiple new high rate of return targets and really with the focus to continue to maximize value of that asset. And that's went outstanding. We continue to have excellent results deploying that same development strategy. So the first thing is no changes there, still applying that same strategy. And the well results that we're seeing are in line with our expectations from a forecast aspect. I mean, obviously, you will have some variability as you move around your acreage, you've obviously got a little bit difference of a well mix there.

But then on top of that, we're always innovating, and we're looking to push operations technically. So always looking to tweak our targets a little bit every single well to get better. We're always looking to optimize our frac design, whether it's tweaking different components. One of the big things we focused on is adding additional horsepower and focusing on rate. So all these little things help work towards well performance. And what I'd say is we don't go for a home run. Really, we make individual small iterative moves to try to get small improvements in performance that we can go ahead and spread out across the program.

So all in all, we're extremely happy with what we're seeing in the Delaware, and our plans are to continue forward with our development strategy as we have been.

The next question comes from Phillip Jungwirth from BMO.

When you come back to the UAE, when you say fiscal terms are competitive domestically, without getting into the specifics, but I was just hoping you could frame this a little bit more just because historically, Middle East onshore fiscals can be tougher as a low cost of supply region. Is there a tighter band around the return profile than what we typically see in the U.S.? So risk-adjusted returns look a bit more favorable? And then just any specifics on ADNOC back in if you ultimately move into development mode here?

Yes, Phillip, this is Ezra. There's not a whole lot that we can say about the specifics of the commercial terms. What I would say is what we've seen really globally and probably the best example, it began with our entry into Oman, is that we've seen some of the international -- the NOCs really do a little bit of unconventional drilling. And what that's done is it's basically brought the education level as to the capital intensity of these unconventional plays. It's essentially demonstrated it to them. And that has made the NOCs that we've engaged with much more willing to change some of the historical terms that they've had, which are more aligned with conventional development.

That's been the biggest change for us. And ultimately, that's what's made some of these entries possible into both Oman, Bahrain and the UAE, is that the recognition that these are capitally intensive projects and that the old PSC structures weren't necessarily a great way to go. And so both of these agreements that we've entered into are concessions. And concessions, as you know, typically, they do have a tax and royalty structure rather than that PSC, which makes it more attractive.

And then ultimately, what we want to have is line of sight that the subsurface quality and the surface environment as far as oilfield services and the way we structure the contract with our ability to bring in some of our own technology that if the model works the way we think it will, that we'll be able to make this competitive -- more than competitive with our existing domestic inventory. And that would be on both a rate of return, essentially an all-in rate of return and then on essentially an NPV. So both half-cycle, but really with an eye on full-cycle economics.

Okay. Great. And then this could be an analog to what you've done here with the Chalk in the quarter, but we've seen a bit more activity across the Delaware Woodford. Just wondering how you guys are viewing Woodford prospectivity across your New Mexico, Texas acreage or maybe some extension of it.

Yes, Phillip, as you know, the Woodford across most of the Delaware Basin is exceptionally deep, a bit more of a gas maturity up against the platform where I think publicly, it's been disclosed that there are a number of wells have been drilled up there. Amongst heavy faulting, but where there is some oil window. As most of our acreage is in the deeper part of the basin, Lea County and Loving County, where we see a great overpressure for much of the Permian section.

The Woodford would be pretty deep depths and quite frankly, very gassy. I think industry-wide over the next couple of years, I'm not sure if the Woodford will move quite as fast as the Barnett on the Midland Basin side of things because of that depth and phase maturity window. But it is something to, I think, for -- to pay attention to as the industry moves forward.

The next question comes from Gabe Daoud from Truist.

Ezra, I was hoping we can maybe go back to the Delaware. Just given the head start on the productivity side that was mentioned in the earlier question, is the basin expected to be the key driver of your low single-digit production growth this year, just given some of the other, obviously, opportunities within the portfolio?

Yes, Gabe, this is Ezra. In that 3-year scenario, this year, much of our oil growth year-over-year is really from the Encino acquisition as we bake that in. And then we do have growth coming dominantly out of the Utica for this year. And on our 3-year scenario, with our multi-basin portfolio, the growth that we see that we've kind of modeled in that for a low single-digit oil growth, it really comes -- it's driven dominantly from the Utica as a matter of fact. And the Delaware Basin, while it still can grow this year, it's actually decreasing just a little bit year-over-year. And then in the 3-year plan, it is probably more in line with being flat to maybe moderate growth.

That's helpful. And then maybe just as a follow-up, going back to exploration and maybe a macro question as well. Can we get your updated thoughts around the gas macro? And then from an exploration standpoint, is there a bias towards commodity maybe depending on your macro views on the gas side? Or is it commodity agnostic and just kind of focus on best resource, return potential, et cetera?

Yes, Gabe, that's a great question. On the gas side, our outlook, we do remain constructive. It's underpinned by rising LNG feed gas demand, growing electricity consumption as well as steady industrial demand growth and, to a lesser extent, maybe exports to Mexico. We forecast U.S. natural gas demand to grow between 3% and 5% on a compound annual growth rate through the end of the decade. We do expect storage levels to continue with increased volatility relative to that 5-year average just because of the increased demand.

So historically, what we're seeing is gas was seasonally driven by weather and residential and commercial heating, which created these swings in cyclical demand. We really feel that the future is driven with AI-powered electricity demand, global LNG exports, industrial reshoring and 24/7 baseload power to ensure grid reliability. So we do feel much more constructive going forward. And when it comes to our exploration program, we're probably slightly more biased to the oil side. But honestly, it really comes down to returns for us.

If we can find high-quality subsurface reservoir combined with an ability to scale up and drive down our cost and really flex our operational capabilities, as long as we can deliver high returns and it's competitive with the existing inventory that we have, we'll take a hard look at it. But ultimately, I think we cheat just a little bit towards being a little more optimistic or a little more exploration-focused on the liquid side of things just because the margins tend to be quite a bit greater than on the gas side.

The next question comes from Scott Gruber from Citigroup.

I want to come back to the Middle East returns question. Ezra, you mentioned terms have improved with the desire for host countries to unlock their unconventionals. But how do you think about the proper return hurdle for commerciality in the Middle East, especially relative to the U.S.? And has the conflict caused you to reassess the return hurdle at all?

Yes. It's an interesting question, Scott. It is still early in the project to be making decisions on DOC or FID or anything like that. So I'd phrase it maybe this way. We've -- since day 1, we've considered the exploration phase to be as much about measuring the subsurface potential as the operating environment. And that includes availability of services, the quality of equipment, access to premium markets, but it also includes the overall political environment, the rule of law, our relationships with partners. And so that's always been part of what I would say is to reference the question earlier, that's always been built into our risk-adjusted returns, is whether or not we can have a real sustained and ongoing high-return project there.

To date, this might be a little bit contrarian, but we've actually been very, very happy with the partners because of the conflict that's going on. We've actually experienced very clear, transparent communication. We've seen great strategic alignment between EOG and ADNOC and Bapco during a very, very challenging time. And I think the evidence is the fact that we've actually been able to continue operations in the UAE to a much lesser extent in Bahrain, but we've been able to continue operations there in the UAE with support from ADNOC. Of course, putting, as Jeff said, the safety of our employees, contractors and partners first and foremost.

But to be perfectly honest, Scott, this unfortunate circumstance has been an opportunity to stress test the relationship with our partners. And in these particular instances, we feel extremely fortunate to have entered the countries with the partnerships that we have in hand.

No, I appreciate that color. And then coming back to the improvement in Permian well productivity. There were some pads put on production earlier this year that showed a healthy uplift in sand loadings although there's been some debate around the accuracy of that data within the state data. So can you comment on that? Are there some areas where you're seeing a benefit from larger sand loadings in the Delaware? Or is that just one of the levers that may get tweaked and generally, you're not kind of driving a step change in sand loadings in any area?

Scott, this is Jeff. Yes, what I'd say is, no, there's not just one thing that we're really seeing there. It's not -- there's not a huge step change necessarily in our sand loadings over the last handful of years. I mean we do tweak, as I said. We'll make little single iterative one variable moves. But we aren't doing anything crazy with any of our well designs like doubling our overall fluid loadings or sand loadings across it.

What I'd say is it's a little bit more just kind of the standard, innovative blocking and tackling, small little moves to try to see improvements. And the biggest one that I've seen, we've really done across the portfolio, as I've talked about, is focusing more on high intensity, getting our horsepower up, giving our engineers the tools to be able to design the wells as they feel adequate to really maximize the overall productivity. So yes, we can't point really to one single reason for the well productivity out there. Like I said, I think it's very consistent from our standpoint. It's in line with our expectations. So yes, and we're just going to continue with our current development program, and we'll continue to iterate and try to optimize our overall designs.

The next question comes from Charles Meade from Johnson Rice.

I want to go back to the UAE and see if you can offer a little bit more detail. Were both of those wells testing the same concept and the same geologic setting? And how mature would you characterize your landing zone selection and your completion design at this point?

This is Keith. Yes, so the 2 wells that we brought on, they were 2 1-mile wells. They are next to each other. So they're a little small pattern, testing the same zone. Very happy with the first 30 days of production. Those wells averaged over 25,000 barrels of oil per well. So we don't look at just production. We're looking at the pressure dynamics, and we like what we see there for an oil well. The wells are naturally flowing up casing right now, and we're putting those in artificial lift in the coming weeks.

Generally speaking, kind of what we look for in the early stages of any exploration play, there's a few things that we look at. We assess our geosteering and targeting execution. We like to see the confirmation of the fluid mix relative to our initial model. We do like to flow those wells up casing without lift initially, just to assess the natural flow state. That helps us understand not only what the reservoir looks like, but how that responds to our completion design. Moving forward, we'll be evaluating different options for the artificial lift. But the results from the first 2 wells are encouraging on all these measures that I'm talking about here.

As we continue to assess the prospect, we will be looking to complete wells in different areas. These 2 wells are in the same area of the 900,000-acre concession. We will definitely be testing different landing zones. And then we'll be continuing to evaluate the well performance over a longer period of time to establish a decline curve there. And I'd say that the completion design, we've been able to bring over the best practices from the Eagle Ford and our other domestic plays. But I think we're still in the early innings there, too. We got to see how we think the formation responded to this and then make some tweaks to optimize.

That's great color, Keith. You got a lot of work to do there. And then if I could have a follow-up question on infrastructure in the Delaware Basin. You guys spent some time in your prepared remarks talking about the Janus gas plant. And of course, you also had the Verde pipeline in the past. And I'm curious, that basin continues to set production records. Do you guys see the necessity for EOG to kind of step into that -- to the breach to handle some disconnects that maybe the -- where the midstream or service industry are maybe falling behind? Or is that mostly behind you at this point in the Delaware?

Charles, this is Jeff. Thanks for the question. And it's a great one. It's one of the reasons that we originally built the gas processing plant, Janus, out there in the Permian, is we did see very tight markets. And actually, the fees had moved away from us, and we had to lean in and build that. But what I'd say right now is, obviously, no, there's been additional egress coming on here in the back half of the year. There's another 4 or 5 to 6 Bcf coming out of the basin. So that's going to cause some relief there.

And we're seeing right now, at least from processing fees that they're kind of status quo. So really, what I think is it's one of those projects that we can expand it another 300 million a day, but we don't have to, and we can kind of utilize it and leverage it to kind of play the market. If it does happen to move away from us again, then we can obviously lean in on that to go ahead and invest in that strategic infrastructure to reduce our overall fees in our GP&T.

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

We appreciate everyone's time today. I just want to say thank you to our shareholders for your support and special thanks to our employees for delivering another exceptional quarter.

The conference has now concluded. You may now disconnect.

Yes. Good morning. This is Arun Jayaram from JPMorgan's E&P OFS and Integrated Oil Research team. Welcome to day 1 of our conference. Delighted to have EOG Resources. This is our 11th Annual Conference, and I'm delighted to say that EOG has been here all 11 years.

Joining us today is Jeff Leitzell. He's the EVP and COO of EOG. He's a lifer. He spent your entire career at EOG, started off as a completions engineer, rising through the ranks, spent some time in Midland, and he got promoted to COO in late 2023. Jeff, how are you?

That's correct. I'm good.

Well, Jeff, I hate to start with the macro, but it's really, really important because at the end of the day, it really shapes how investors think about the investment in E&P stocks. So give us a sense, I know that EOG spends a lot of time thinking about supply-demand balances, how do you survey the geopolitical risk supply disruptions? How are you thinking maybe about the near-term and medium-term outlook for crude oil?

Yes, it's a great question. Obviously, things are extremely dynamic right now with the disruptions that we've seen with the Iran conflict. And what we really see is if you just kind of step back and you look at it from the 30,000-foot view is over the last 4 months, we've had about 1.3 billion to 1.5 billion with a B barrels of total capacity taken offline, which has obviously had a massive effect on the market. And so when you look at that and you really roll it all the way up, inventories, obviously, world inventories are extremely low at this point in time.

So the other thing that we see when you tie all this together is, obviously, to get some flush production back on, we got to get the Strait of Hormuz open back up. And what we really see is after a period like this is it's not all going to come back on at once. Probably you're looking at maybe about 50% coming back on in the first month and really in total, taking 3 to 4 months to get probably 90% to 95% of the total capacity that was going through the Strait back online. And then that additional kind of 5% to 10%, I think that's really a question mark. We don't know exactly how much damage has been done to infrastructure, what kind of difficulties are there going to be to bring wells back on and fields back on that maybe have been shut in. That's one thing that you got to take into context is a vast majority, if not all, is primarily conventional type reservoirs over there. So the majority of it is not on artificial lift, and you would need some kind of intervention for a lot of these wells to really be able to kind of kick the wells back off from that aspect. So major disruption.

And really, what we think we've seen is we haven't really seen demand destruction yet. It's only been 4 months. We've really seen what we would call demand displacement really. And we think as soon as the barrels do come back online, you're going to see them very quickly soaked back up. We think China obviously is going to pick right back up. You're not going to see them from a recession standpoint, pull back at all. Obviously, they have GDP marker numbers that they want to hit, and they're going to focus on hitting that. And ultimately, we think that if you look at kind of the medium to, I'd say, near to medium term, we see as if there's probably a floor on WTI of about $60. And really, I think that floor is going to be really created by the strategic petroleum reserve replacements that are going to be over there in the next 3 to 4 years.

If you see prices start getting at or below $60, I think you're going to see the U.S. and Europe and China start refilling those SPRs. And then when you look at the top side of it, I mean, you're going to have volatility. You'll have higher prices, lower prices. But on average, over the next couple of years, I think you're probably looking at a high-end average of around $80 is what we're expecting. So fairly robust market for the next handful of years based off this interruption.

Great. Jeff, I was wondering if you could talk a little bit about the U.S. supply situation. There's kind of an active investor debate whether U.S. oil production is nearing a plateau given Tier 1 inventory exhaustion and industry-wide productivity headwinds. Where does EOG stand on the debate where U.S. supply can go from here?

We've tried to make a call on this before, and we probably were wrong. So what I would say is this, we've kind of fallen back and we've seen, and you've seen it over the last 5 years, never count out unconventional industry, the technology and the innovation out there because just over the last 5 years, you've seen huge strides forward within the industry to be able to drive cost basis is much, much lower. Lateral lengths have extended immensely. The average lateral length used to be 1.5 miles to 2 miles and now operators are drilling 3, 4, 5-mile laterals. Efficiencies have gotten substantially better. And you can even see that on the service side where, yes, there's less equipment out there, but it all tends to be much higher spec, better equipment out there.

So ultimately, I think where we stand is the U.S., can it grow? Yes. I think it really -- you need to tell me what a price is going to be. If it's going to be $60 or $65 kind of mid-cycle, I would suspect the U.S. probably doesn't grow that much, flat to maybe just slight growth. But if you do have $85, $90 oil, the U.S. definitely can lean in, and they may leak a little bit of capital efficiency, but they can grow.

Got it. Let's talk a little bit about natural gas. EOG has been constructive on long-term natural gas fundamentals, LNG feedstock, rising power demand, which have been positive dynamics. How are you thinking about the 2026, 2027 supply-demand setup?

Yes. So on the gas side right now, obviously, from an inventory aspect, we're kind of at the 5-year high of levels right now. So inventories are fairly healthy. I think there's a handful of things that you got to continue to watch. And obviously, we knew we're going to move the market. The first one is obviously continued expansion and build-out of LNG on the coast. That's obviously going to be a huge demand center. And as long as everything stays on pace there and there's continued investment in the coast, that's obviously going to be a major demand draw there.

The second side of it is additional power gen demand, data centers, AI I mean from that aspect, you're starting to see it gain a little bit of steam as far as understanding what kind of capacity is. I think it's still the early innings there. But for instance, we just recently, I think in the last week, there was a data center that was announced out in the Permian, and that's going to take offline about 0.5 Bcf of gas, which just those kind of reliefs, I think, are really going to be good security in the market and help really stabilize that price over time.

And then lastly, what I'd say is gas is always weather dependent, right? They're talking about a super El Niño this year. So obviously, potential for a really hot summer again. So we'll see what the kind of droughts look like throughout summer. And then we'll get into winter, and we'll see what that really represents for how cold of a winter we really see across the U.S. And obviously, that's always the big needle mover in the near term on natural gas prices. But for the long term, extremely constructive on natural gas prices medium and long term, and we think we're outstanding positioned to be able to take advantage of it with our Dorado asset down there in South Texas.

Let's shift gears, talk a little bit about capital allocation. Let's talk a little bit about M&A. One of the things that's unique about the EOG culture has been the organic growth dynamic, which has been since Forrest Hoglund has been kind of CEO of the company back in the late 1990s. You have announced a couple of deals, Encino and in Eagle Ford bolt-on. What were unique about those kind of transactions?

Yes. So the one thing that I'd say is, and I'm sure we'll get a chance to talk about it is at the core, EOG, I mean, we truly are an explorer. We've been explorationist since day 1. We're going to continue to be explorationist, and we still see a long runway here in the U.S. and international. So -- with that being said, we do obviously see value with having others' acreage in our hands. So we have done some successful bolt-ons offset of the Eagle Ford and other areas in the Utica and has given us confidence that following up our organic exploration, we can lean in on some of these bolt-ons to really expand our acreage set and find value in that.

And then even more so, I would say, deals like Yates and Encino, just with the great success that we've had through the integration process, the synergies that we've seen have really just beat all expectations. I think that's given us confidence to be able to do more very strategic M&A like that. And by that, I mean, not M&A going into established basins where everybody understands exactly what the resource is, the prices have already been run up. We're talking about opportunities where maybe we're going in and we have an exploration play, and we're able to take out another operator or a portion of an operator to be able to accumulate that acreage and finish putting our acreage footprint together. More of those greenfield kind of newer opportunities. I think that really fits well with the portfolio. And those are some of the opportunities I think you'll see us look into as we move forward in the future.

Let's talk about the capital allocation process, maybe zero in on this year. Multi-basin platform levered to a lot of the core plays in North America. You have leverage to oil, gas, NGLs, so a lot of portfolio balance. You made some decisions to reallocate capital this year while keeping your budget flat at $6.5 billion. Could you talk a little bit about those moves that you made in the portfolio?

Yes. And we've talked about it quite a bit. Obviously, the first thing we do with capital allocation, we always focus on is capital discipline. That's the #1 thing that we focus on. We want to make sure we're investing in the right project, the right asset at the right time to maximize cash flow and returns. And that's kind of bar none. That's what we focus on.

The second thing is in order for us to allocate capital to any of our assets, it has to meet our minimum economic threshold, which is it has to have a direct after-tax rate of return of 30% at $45 oil, $2.50 gas, which is bottom cycle pricing. So that's our minimum hurdle for an investment. If you don't reach that, you don't get capital. So that's a pretty easy hurdle marker to look for.

And then next, once you actually do fall in line to actually acquire capital. At that point, we really look at where you are in the life cycle as a play. Are you early on in the play? How fast can we invest in it? If we invest too fast, we want to make sure that we're not leaking knowledge out of that play, and we're gaining everything and our learnings throughout that process. And that's one of the things we really take into account from a capital allocation standpoint.

So -- and that's just one of the huge flexibilities with having a multi-basin portfolio, we were able to really flex that whenever the conflict started up. We said, okay, look, we've got a little bit of a depressed gas price. Let's move a little bit of capital out of our dry gas Dorado asset is fairly minimal, just dropping below 1 frac fleet. And we put a little bit of capital in the Utica to complete 10 more net wells and a little bit more in the Permian to complete 5 more net wells. And ultimately, what that did for the balance of the year was we increased our oil volumes by 2,000 barrels a day, and we increased our NGLs by 6,000 barrels a day.

So those are the kind of things that it's great. If you're just a single basin player, you don't have that much optionality to be able to move around capital. But being a multi-basin, multi-country and obviously, multi-molecule having oil, combo and gas assets gives you a lot of flexibility to move that capital around and maximize free cash flows for the company.

Let's talk a little bit about kind of the exploration DNA of the company, can you talk a little bit about -- for the generalists in the audience a little bit about the culture of the operating model that has enabled your long-term exploration success?

Yes. That's -- as I said, that's something it's always been core to EOG. We've always nurtured our exploration knowledge all the way from the very get-go in the late 1990s when the company became independent. We took anybody that really had even good conventional exploration experience and made sure we passed along all that knowledge along to our younger staff. And then as we accumulated data over time and really honed in our unconventional understanding of these basins, make sure that we trickolate that out to our staff and continue to nurture it because we really knew that, that's going to be a big, big part of the company.

And how we've actually structured it, as you talked about, is we are a decentralized organization. So we have 7 divisions out across the U.S. along with international operations. And each one of those have their own strategic exploration group. They're looking within their regions and their assets for new exploration plays. And so we have lots of horsepower out there looking for the next thing. And really, what they're looking for is things that aren't just additive to the portfolio, but ultimately will be kind of at the higher end of the portfolio.

And what I say is, as a company, it's amazing the opportunities we have. But even just domestically, people think we're kind of at the end of the rope here as far as unconventional exploration. domestically, we have 30-plus prospects we're looking at, at any given time. And then every single year, we usually test on probably 3 to 5 of those. And the great thing about exploration is, I'd say, on those 30 prospects, they really don't cost any money. Not a whole lot of CapEx, a little bit of G&A, but outside of that, you're using existing data, penetration points, logs that are out there to really see if the play has a chance in the geologic model and the reservoir model work to compete within your portfolio.

So we just see huge advantages where we can get in entry costs extremely low in the hundreds of dollars, not the tens of thousands of dollars. And ultimately, that helps the play help throughout its whole life cycle and really helps margin expansion by keeping that DD&A rate low.

We'll come back to some of your exploration success in the Lower 48 in just a few minutes. I was wondering if you could help us or provide a little bit of an update on some of your international exploration opportunities. Maybe start with Bahrain, talk a little bit about your geological concept. And what have we learned thus far in terms of Bahrain?

Yes. I think the thing to start here is we see an exciting future for international unconventionals because they really haven't been explored. I mean you've got a little bit in Argentina, obviously, a little bit in Canada, but that's kind of the tip of the spear. Really, there's tons of great unconventional reservoirs, obviously, underneath all the conventional reservoirs that are out there. And we're just now getting to a point where we think those countries are really starting to understand the fiscal terms, how unconventionals work and there's the opportunity to head in and take advantage of those.

And one of the first places we see is the Middle East, where that opportunity has arisen. So in Bahrain, what we have there is this is an unconventional onshore, on island, I should say, gas play, very, very prolific. It's -- there's plenty of penetration points. There's lots of infrastructure on the island. And we really knew analog-wise, what we had there probably from a production aspect. Really, what we wanted to do is bring unconventional technology in both drilling and completions to really get cost down, optimize wellbore design and then maximize the overall productivity of the wells there. And the great thing about that, too, is even being a gas play, we're able to go ahead and sell the gas directly there local to the government for premium pricing compared to obviously domestic pricing there. So -- extremely excited about what's going on in Bahrain there.

Now obviously, we did have the conflict. So there's been a little bit of a delay, but not really much so much from the conflict, I'd say, if anything, it was more -- I've kind of explained it from the supply chain side, right, with the Strait being closed, being able to get in the necessary wellheads and the other things that you need. That was probably the biggest delay. But we're still on schedule right now to be able to bring on results for the second half of this year. And yes, we've been extremely happy with the partnership so far with Bapco and the results that we've seen through our operations thus far.

Okay. Let's talk a little bit about the UAE. This is probably one where I sense that investors are pretty excited about the opportunities. Maybe give us a sense of, again, your geological concept, where you're at with your test and maybe when you'll be able to give the market a fulsome update on your exploration and appraisal program.

Yes. We're extremely excited about the UAE, as you said. Now this one is unconventional oil and pure oil. And it's actually the first unconventional concession there in the UAE, and it was 900,000 acres. So massive scale, as you can imagine. This one is a little bit different. There is some infrastructure in the field. There was some penetration points. There is some production. So there's plenty to build your model out and understand what you really have from there. But this one, obviously, with the scale of it, it's going to take a little bit longer time from an exploration side to delineate and get to a point of FID.

But with that being said, obviously, we're in there currently with operations, drilling and completing. We are on pace, as we talked about, to be able to bring on results and be able to share those with you the second half of this year. And that's one of the ones that, obviously, if everything hits on that, we get to a point of FID, I mean, it obviously could be a very -- a big part of the portfolio and one of the larger growth engines that we would say for the company moving forward. And from a rock standpoint, if you kind of want an analog to it, I'd say the closest analog in the U.S. would probably be the Eagle Ford, to be honest with you. So very conducive to operations. It's fairly easy operationally to drill and very prolific from an overall resource standpoint.

Is it fair to say that the -- or not -- or the thing that you need to get over to make the UAE commercial success will be to get well cost at a level maybe consistent with what you see in the U.S.?

I think that's great. Now are you going to get cost over there, maybe over time to U.S. levels, but that is the key. They just -- there's not a whole lot of unconventional technology, unconventional equipment over there. So really, a lot of the unconventional drilling, they're still doing a conventional methods. Most of the wellbore designs when we entered countries, there are 5, 6 strings. Averages in the U.S. is 2, 3, maybe 4 strings. So just bringing those technologies, I think you can drive down costs very, very quickly. And then getting the supply chain, the logistics, just the thinking of unconventionals over there and get that culture ingrained, I think you'll see a huge price drop in the overall cost of those wells.

Well, SLB is presenting after you, Jeff, and then Halliburton is also here. So anyway, they'll be happy to help you. A little joke there. Let's talk a little bit about some of the exploration plays that are moving into kind of foundational asset territory. Give us a quick update on the Utica.

Yes. No, the Utica is -- man, it's going outstanding. We really haven't had a miss up there all the way from exploration to delineation to our first packages. Everything basically had met or exceeded all of our expectations and so much that we were able to make the transformational acquisition of Encino, which has just been outstanding. So obviously, over 1 million acres is what they had. We had really delineated our acreage. We actually did a deal with Encino, to be honest with you, in our northern part of our acreage to get a foothold to start. So we had good dealings with them. We understood kind of their areas and what they had done in the past.

And once we kind of got to a certain point in our program, we realized that quite a bit of their acreage still had really good liquid-rich oil underneath it. They had a lot of good runway for inventory, and they were just kind of glove and hand fit for us as far as an acquisition. And it went phenomenal as far as an integration standpoint. The people immediately day 1, we had all of their data input it into our systems and flowing through regularly. We had all their people onboarded very, very quickly, had all the EOG applications, brought them up to speed with the EOG culture. And we first came out with a synergies mark for -- in the first year, about $150 million of synergies with that acquisition.

And I'm happy to say we blew that out of the water. We had the $150 million well within 6 months. And primarily, you saw those through a lot of D&C. Obviously, through the acquisition, they were at about $750 a foot. We were at about $650 a foot. Combined today right now, we're at $600 a foot or less. And what that really entails over the period of time is we were able to increase our drilled feet per day by about 35%, increase our completed feet per lateral by about 10%. We took all of our supply chain and our purchasing power logistics and put that to work up there. We saw about a 30% reduction in our overall tubular and casing costs and about a 20% reduction in our facility costs there. So just huge cost reduction would be able to apply our scale and our technologies.

And then also just from a productivity standpoint, we acquired about 1,100 wells up there. And obviously, we're a data company, a technology company, and we've got a robust suite of what we call optimizers that use machine learning, AI to really optimize artificial lift in the productivity of the wells. Well, on all the applicable wells within that 1,100, we went ahead and very quickly put the optimizers on it, we saw great results. I mean, on average, you can see a 3% to 5% uplift in overall base production from those optimizers on those wells. And we really think we still got a long runway to go. We're in the early innings there. We still have a lot of synergies that we can go ahead and bring forward a lot of EOG automation, measurement and technical abilities.

And then the other thing I'd say, the next big hurdle cost mover you're going to see there is we are going to have in-basin sand, and it's probably the only in-basin sand mine in the Northeast, and we're going to have that coming on towards the end of this year, which, on average, can be a huge needle mover from a cost standpoint.

Great. I want to touch base a little bit on the Delaware Basin, which is a core foundational asset of the company. call it, after productivity dipped a little in 2025, we're seeing some better data in 2026. In fact, the well data looks like you're delivering a positive rate of change in well performance. I hate to get down in this level of detail, but it is kind of important for a lot of investors to look at the stock. Can you talk a little bit about what you're seeing in productivity in the Delaware, some of the drivers that you've been -- investors should be watching?

Yes. We love getting down in the details on it and stuff. We probably should got down in the details a little bit earlier. That's what we said. But basically, what you're seeing there is, yes, in 2025, we did see a step down in overall productivity per well in the Delaware Basin, and it was 100% by design. And what we've really seen through 2024 was we had lowered the cost basis so much there in the play that we were able to bring in additional high rate of return targets that now met our economic threshold of that 30% direct after-tax rate of return at bottom cycle pricing. So that's all it really was. It was an economic question of we lowered the cost basis, brought those in. And what you're seeing on the average across all the targets is a slight degradation in productivity. But if you look at the economics, you're not seeing any degradation what so all across that play.

So all of last year, you kind of saw the step change down. We were able to obviously enjoy the benefits of the economics and the free cash flow associated with that, but that was a onetime step down. And now as you move forward into '26, as you stated, you're actually seeing consistent, if not actually just a little bit better, which is kind of your normal iterations on your completions design and continuing to get better. Overall productivity very, very, very stable. And we plan on seeing that kind of for the continued future.

Now any other markers out there, I will leave an asterisk that if we continue to lower our cost basis out there, I mean, as I said, with technology for unconventionals, that's exactly what we're looking at. If we can lower the cost basis more, there's a good chance we're able to bring in more high rate of return targets. And if we do cross that bridge, we'll make sure that we pass along that information, and we give everybody a heads up before you see that flow through on the public data.

Great. I want to talk a little bit about technology, AI. How are you using AI to improve your overall kind of capital efficiency?

Yes. As I said, we're a data company, and we've always used machine learning, multivariable analysis and then obviously transitioning now into the generative AI side of things. And we've actually built out our own platform, which we're methodically rolling out across the company. And really, what I'd say right now is our most valuable resource by far is our people, thinking outside the box, being technical leaders, innovating, finding new ways to do things better. What AI is really going to do for us is it's going to take away all those monotonous tasks, those kind of easy, simple, time-consuming tasks. It's going to speed them up immensely from an analytics standpoint, from a databasing standpoint, from an actual data capture standpoint. And it's going to allow our people to really focus on the nuts and bolts of lowering cost and making the wells better.

And that's one thing that I'd say is if you talk to your ChatGPT and ask it to do something that's never been done before, show me how to innovate and how to get better, it's only going to be able to use the data that's out there and give you an answer forward from there. Our people are going to be able to think outside the box and find things that have never been done before in the industry to be able to move it forward and get it better. And that's what we want them focused on. And we'll let AI focus on kind of the low-hanging fruit, easier tasks and mundane tasks that take time away from our people.

Jeff, this is the last conference before you guys kind of move into the quiet period. Just any operational updates, how are you tracking versus 2Q expectations and just full year operational guidance?

Yes. Well, I mean, it's still obviously too early to talk about Q2 or the rest of the year. But what I can say is after Q1, as we announced, we had a phenomenal start to the year. And the company is doing just like they always do. They execute. They're hitting the marks and if not exceeding those. So we were under CapEx or pretty much at CapEx, I should say, within the first quarter. We were over on volumes. We are under on cash costs. Everything was kind of firing on all cylinders. And like I said, big focus is making sure the integration continues to go smooth there with Encino, and it has.

So yes, just extremely excited about the year and how everything is set up. Obviously, cash flows have went up immensely with the forward strip moving up. And yes, just excited about where the portfolio is at, both domestic and international and continuing to move forward all those opportunities.

Great. I think we have time for a question or two. Maybe I'll sneak in a last one is, how is EOG thinking about the improvement in Waha? We've obviously -- you're going to get better connectivity from the Permian. Just how is that -- how do you all think about that, going into kind of next year?

So the first thing I'd say is we have minimum exposure to Waha, which we're very proud of. We kind of less than 7%, normally less than 5% of volumes to Waha. And what you're going to see here is over the course of this year, you've got about 5, maybe 6 Bcf coming online. There was actually some capacity that just came online here about a week ago, and you saw Waha bump up about $3, $4 price. So you already see what kind of taking that weight off of it has really done.

So -- and then beyond this 5 or 6 you've got coming on, you've got another 6 Bcf or so of egress that's going to be coming out of the basin. So -- that on top of potential data center demand and other power demand draw there, we expect Waha to probably turn positive kind of come September, October time frame as strip pricing says shows, and you'll start to really see some relief from that aspect. So we're at minimum exposure with it right now, but I think you're going to see brighter days for Waha as we kind of move forward here and we get some more egress there out of the basin.

Jeff, let's cut it off there. Thank you so much.

Good morning. Welcome to the third session of the 42nd Annual Strategic Decisions Conference. I am Bob Brackett, Co-Head of Energy and Transition here at Bernstein. We are not expecting a fire drill or any sort of safety drill. So if an alarm rings, please take it seriously. The primary exit is out the door to the back down to my right to the escalator area where you came up. If for whatever reason that is blocked, there are internal stairways right behind us out of the door, choose 1 of them go down and follow the paths there.

This is your conversation around the room. We have QR codes printed on these little blue pieces of paper. That gets you to the Pigeonhole app. It allows you to type in your question, and I'll be seeing this on the screen. So absolutely encourage you to ask those questions. While I'm waiting for all your great questions to come in, I'm going to follow a pyramid principle, where we're going to start our conversation at a high level, talking about macro, we'll move on to strategy, and then we'll kind of dig down into parts of the portfolio and all the way into the operations. So that's how we'll proceed.

We'll kick it off by thanking Ezra Yacob, the Chairman and CEO of EOG Resources to be with us, and I'll adjourn to join in.

And so I was just checking my phone to see if there's a peace deal in the Strait of Hormuz, and there may or may not be. It's sort of Heisenberg piece deal, both is and isn't. But talk to the Strait of Hormuz -- how do you understand what's happening today? And then maybe we'll talk about what are some of those longer-term implications?

Yes. I think the only way to do it is to be patient, take a longer view, have a longer perspective on it because Otherwise, like you said, you're liable to get caught up and in what appears to be kind of every Monday and Friday difference of opinion and news flow. And so it's -- the conflict is certainly the most dramatic thing that's affecting our industry, quite frankly, since COVID, really, and it's spilling over into the broader market.

But -- the way to think through these things is to realize what it is. There's a lot of volatility associated with in the here and now, but trying to reflect on what does it mean for fundamentals kind of longer term. taking a longer-term view, being diligent, being thoughtful but also at the same time being proactive and realizing what does this mean for fundamentals and how do you orient your company to create additional shareholder value through the cycle.

It's been 90 days. It's a quarter, right? It's kind of -- are you surprised that prices not higher, not lower. -- that the world seems awfully complacent about the global petroleum system?

Yes. That's where I think our surprise with Liat is that after 90 days, I haven't seen a more dramatic kind of global coalition or cohort really responding to this. For a surprise to price, in particular, No, nothing really ever surprised me with price because you have so many nuances and speculations and things like that, that go on with it. The front month obviously, is moving around pretty volatile with a lot of volatility. The back of the curve has generally been more steeply backwardated.

I think when you look at fundamentals and what this means, you should probably see that firming up a little bit. The easy math, you say, 90 days now for the conflict and conservatively, if we just say that maybe 10 million barrels a day has been offline, which is conservative. If you do straight-line math and flip that, that means you've got 2.5, almost 3 years, where you need an excess of 1 million barrels per day to kind of fill in that hole.

Well, pre-conflict if you said that you were going to have an excess million barrels a day of demand or supply, that would have a dramatic effect on pricing, more to the tune of what you're seeing in the back half of the curve. So again, that's how we kind of frame it up, and that's why we continue to think about it. That's why I say you don't want to be reactionary in the moment, but you do want to start to piece it together and what does it mean for fundamentals and how do you incorporate that into a longer view.

And then longer view, last year, in a normal world, there's never a normal world for oil, you couldn't really push oil much into the mid-50s. Part of the reason was you had strategic buying Chinese, that looks genius now, buying -- we're going to come out of this crisis. We're going to have to refill in theory, strategic inventories and commercial inventories. Is that a $70 put, right? Do we have a point where oil gets into the 60s, states, nation states look and say, well, that's a bargain I need to rebuild. And that's a process that could take years.

Listen, coming on the heels of this conflict, I'm not sure if you have to see 60s to make that call. I think you're right, what China was able to do last year, put them in a great position right now. I think you're seeing the U.S. lean into our SBR saw a headline today that we'd actually sent -- so some of our shipments of SPR over to the Asian markets as well. And so no, I think strategically, what you have is countries will definitely be refilling their SBR.

Some countries will establish an -- and that's going to provide that along with a recognition of this convergence of energy affordability, energy reliability, national security is definitely going to provide a bit of an oil price floor, higher than mid-cycle prices, historic mid-cycle prices. And more than likely, we'll create an environment where you've got asymmetric volatility to the upside.

And I think that's some of what sets up. Obviously, you've got the whole of inventories to fill. You've got pretty conflict. You had a continuation of, let's say, strong consistent demand not anything crazy, but 1 million, 1 million or 2 million barrels per day per year. Not a significant amount of new supply. You had some spare capacity coming back, reentering the market.

And now you've got this extra layer of demand from the SPR. And so I do think it sets up, quite frankly, in the near to medium term, quite a strong pricing environment based off of fundamentals less just speculation.

And then that comes to how you think about allocating capital. It's almost we lived in this world of 40, 60, 80, right? Everything's got to earn a good in your case, double-digit return at $40 -- you can sort of plan around $60 and $80 is the dream, and now we're coming back down to the dream, given the volatility you hate to throw out processes all once, but how do you think about longer term what's the right planning price for oil? And what's the right program?

Yes. So again, it's -- this is a commodity business. It's a cyclical industry, though. So yes, you feel -- you feel good that you're seeing a line of sight where you've got some years now above mid-cycle pricing. But in any commodity price cycle, that means that if you're going to spend a few years above, at some point, it will come under. So I'm not sure if -- to your question, you actually -- we don't change the strategy of the company, which is measuring some investments at the bottom cycle, making sure we can create shareholder value through the cycle.

That doesn't necessarily mean that we don't change how we manage in the moment though. There are different things you want to do depending on if, let's just say, you're above or below mid-cycle pricing. Below mid-cycle pricing, it's a great time to expand the business. Last year, we were able to execute on acquisition a small bolt-on acquisition and expanded internationally for some concessions. We leverage our strong balance sheet, our low breakevens and stepped into some marketing agreements when others weren't available, and we didn't see the competition out there.

When you're above mid-cycle prices, you've got excess free cash flow. It's a great opportunity to maybe drill some of your exploration wells. The pricing makes that experiment a little more forgiving. It's an opportunity during the last up cycle, we invested in some strategic infrastructure to help lower our breakevens during the downturns. So you do recognize the moment that you're in and adjust some of the strategy to best position the company.

Whenever you enter a different part of the cycle, you want to make sure you're positioning yourself to exit it as a stronger company, but it doesn't necessarily affect the long-term investment criteria that we have. The last thing we want to do is see that we're in an up cycle and ramp up production growth. Production growth makes you bigger, it doesn't necessarily make you better.

What you want to do in these types of opportunity is continue to invest in a way. Investing in growth is fantastic right now, but you want to make sure that you're investing in a disciplined manner where you're still chasing margin expansion, not just from top line revenue growth, but true margin expansion where you're driving top line revenue growth, but you're also lowering your operating expense as well. That is where you can really carry value, deliver value to the shareholders through the cycle.

And you can commit capital to oil, committed to gas, mostly committed to a blend. Let's talk about Henry Hub. What is that range of outcomes for Henry Hub gas price and don't depress me.

Yes. So this year, we actually -- on the Q1 call, we actually announced that we are reallocating some of our gas investment this year, right off the bat. And so with the divergence of prices, seeing oil prices strengthen dramatically on the conflict. You've seen gas prices weaken a little bit throughout the year. And so we reallocated some of our dry gas drilling into some more liquids weighted. It delivers about 2,000 barrels a day, increased oil on the year and 6,000 barrels a day increased NGLs on the year.

That's not to say that we're not constructive or bullish longer term on natural gas. We've captured this natural gas asset named Dorado in Southern Texas. It's in Austin Chalk and the Eagle Ford play. And we think it's well positioned to supply both the upcoming LNG demand, which is coming on and increasing every day, but also just in general, North American increase in electricity demand, a lot of that on the back of coal-fired power retirements.

Those are two structurally bullish changes that go forward and provide a lot of upside to natural gas long-term. We think, historically, if you look at natural gas prices, Henry Hub, I should say, natural gas prices, mid-cycle price range, maybe 3.50, 3.60, 3.70. We think these structural changes should increase that historic mid-cycle price range by maybe $1 or $1.50 or so.

What we've done to orient ourselves as we have captured some LNG pricing through gas sales agreement to make sure we've got our gas going offshore. That's been increasing over the last few years. And by the time it gets to 2027, we have a mix of basket pricing options that gets us about a Bcf a day, just shy of about a Bcf a day going offshore by 2027.

The other thing I would point out on natural gas going forward is it is difficult to forecast just because I said natural gas mid-cycle price range, we feel is going to go up. It doesn't necessarily eliminate the volatility. When you think about natural gas, you need to think about natural gas plays and natural gas associated plays. You need to think about infrastructure, where that gas is versus where the demand is. You need to think about what is the oil price because that contemplates how much associated gas there is.

And when you're all said and done with that, you need to think about the weather, which makes it a bit complicated. And that's why when you're focused on natural gas, you need to make sure you're bringing for the lowest cost gas you possibly can.

In Dorado, we've been very strategic, very thoughtful and very disciplined about the investment there, building out different parts of the infrastructure -- so when we flow those molecules in draw to the cash operating costs are about $1 per Mcf. Total breakeven on the play is about $1.40 per Mcf. And that's why I say we think we've captured some of the best position and lowest cost gas in all of North America.

We had Kim Dang, CEO of Kinder Morgan, just before you, they're forecasting about '26 Bcf of gas demand growth out to 2030. My numbers within 1 of that, WoodMac within 5 or so of that. That's like adding to Haynesville, it's like adding a Permian dry gas worth, it's adding Appalachia. On the supply side, you see that resources out there. But -- and I like your mid-cycle pricing, adding $1.50 to where we've been.

Yes, the resource in the U.S. is there. Now the tricky thing is, is the infrastructure in place to get a place there's a tremendous amount of gas in the Northeast, not a tremendous amount of infrastructure to get that down to some different parts of the demand center.

Now when you talk about that increase in demand, which we're right there in the same kind of frame 3% to 5% compound annual growth rate in North American demand. It's LNG, it's electricity, electricity from coal-fired power electricity, some due to data centers and AI. You said coal twice before you say data centers -- so I think that's the first that 1 actually in our -- that's because 1 of the reasons is, in our base model, -- we have a range of what data centers and AI are responsible for. And it's actually not the main driver.

It actually becomes -- it ranges in our model from somewhere to 3 to maybe as much as 8 Bcf a day in demand, but it's not nearly as significant as LNG, even just residential air conditioning or heating or anything like that. But you also have another wave of petrochem and then you also have Mexico exports as well, which increases that demand. And so part of it is the U.S. does have a robust amount of source. We don't have a robust storage anymore. Storage hasn't kept up with North American gas demand over the last 10 or 15 years.

But you do have a resource there. It's funny, though, how much of that resource and you picked out the Haynesville earlier, is actually controlled or owned by North American E&P versus international companies that have purchased some of the Haynesville to backstop some of their own supply for LNG. And so the historic kind of on/off switch in the Haynesville over $4 per Mcf, it will be interesting to see if that continues into the future or if that changes with different operator incentives.

Desire or a better return through the cycle, sort of the discipline that the shale oil companies learned can be transmitted to the shale gas companies -- that's right.

Speaking of which, I went through 1Q results -- and the word units of barrels per day, BOE per day, doesn't show up to like Page 5, but lots of percentages and including commitments -- so I think the first number in your 1Q is we commit to return 70% of free cash flow to shareholders this year, right, kind of this idea, I hate the word windfall because of European regulators, but the idea, if there is a windfall, if we have a top of cycle price, let's give that back to shareholders.

So talk to that philosophy.

Yes. I think hopefully, what comes across that earnings deck is first title, first slide is shareholder value through the cycle. And part of that is capital discipline. Part of it is operational excellent commitment to sustainability and culture. Those are the competitive advantages to drive EOG. So it's driven us over the years to have a very low breakeven have a very competitive regular dividend and that extends into our overall cash return strategy, which, as Bob said, is a minimum 70% commitment to return free cash flow on an annual basis. above and beyond that regular dividend, either in the form of special dividends or more recently, we've been leaning on share repurchases.

In the last couple of years, in fact, at lower oil prices, that cash return was closer to about 90% to 100%. Some years 100% exactly. With these oil prices, we've kind of backed off of that a little bit, and we're saying 70%. If you look at the forecasted free cash flow and cash return at the strip price that we released in -- with the first quarter call there in May, that forecast about $6 billion of cash returned to shareholders, which would be a record year for cash return, which we're excited to be able to deliver back to the shareholders, again, on an annual basis.

And right now, when that cash return comes back, I think we still see a lot of avenue for share repurchases. I think the energy industry, while equities and the entire industry has moved up a little bit with the increase in oil prices due to the conflict. Still a relatively light weighting in S&P 500. Free cash flow yield still look very attractive at this point. And really, when we weigh our own measure of value kind of an intrinsic value of the company, we still see a lot of opportunities in the stock.

We've been -- when we're very cognizant, we don't want the share repurchase program to turn into a pro-cyclic model and remain very opportunistic. I think we've demonstrated over the past 3 years that we've been repurchasing stock that we're in the market every day looking for opportunities, and we've done quite well with it. In the last 3 years, we've retired about 10% of the stock. We've invested about $7.1 billion in share repurchases. And we've done it at a price that I think is very compelling investment and very compelling value for the shareholders.

I remember at times in the days of triple-digit oil and growth have everybody at the company checking their shares, like -- the irony here is we're in a high price environment. The shares have not responded to that. It's almost a blessing right? We've almost conquered the procyclical nature of buybacks, right? The market hasn't rewarded you the way it has, and that gives you a chance to go out there and buy back more aggressively than if this was sort of a speculative procyclical bubble.

Yes. I mean that's a silver lining to look at the share price not responding to the oil price market. But like I said, I think when we measure it, we try not to look at trading parameters or technical trading markers, we really look at it on more an intrinsic value basis. We try to look at -- we measure the value of the company at a series of different pricing mechanisms, we try to evaluate the company's multiple -- we look at industries multiple and see if there are dislocations that are occurring and continue to feel confident that when we are buying back stock, we can talk to the shareholder and say, listen, through the cycle, this is a compelling value and an investment opportunity for you.

Sort of a corollary question that came in. Your stock has lagged the broader E&P index. I haven't verified that. Why do you think this has been the case? And how does that change in the future?

Yes. I think the big thing for us is continue to drive down the breakeven costs continuing to expand our margins and proving up some of our exploration opportunities. The company has leaned in on building a natural gas opportunity, like I talked about earlier, a natural gas business underneath the umbrella of EOG. Some people have felt that we're leaning into changing the company from an oil company into a gas company. And that's not quite aligned with the strategy.

Quite frankly, what we're seeing is when we can invest in opportunities based on a bottom cycle pricing of $45 oil or $2.50 natural gas, and we can create compelling returns in excess of 30% direct after-tax return. That is a very compelling investment opportunity. And so we've been growing our natural gas business, again, into the emerging North American demand, while actually still growing our oil -- the oil side of our business, quite frankly, in excess of what global oil demand has been growing recently.

What we see is that puts us in rarefied area where we've got exposure to both North American dedicated natural gas plays, North American dedicated liquids plays and both international conventional and unconventional assets for exploration upside. And I think the strategy is working. When you look back at the last 5 years, we've been able to generate about $30 billion of free cash flow, we've returned about $25 billion of that free cash flow to shareholders and delivered over a 25% average return on capital employed.

In our mind, as long as we continue to focus on the business fundamentals, the macro environment, our market value will reflect the business value that we're creating over time.

And to some degree this year. Coming into this year with more debt than you wanted in January turned out to be a blessing, right? You get -- and so companies that were levered delivered quickly and outperformed, but that's a cyclical nature. That's not a structural nature.

Another question, which I'll modify a year ago, different hotel down the street. I asked you a question about how you think about M&A and then the next day you acquired Encino, which was a reasonably small acquisition relative to still your largest history. So I'll ask the -- there's 3 questions here. One, how do you think about M&A?

Yes. So it was a great question last year. So -- it was a.

I refused to play poker with you.

Yes. I would say it was a terrible answer, but for obvious reasons. Look, Ensino was fantastic for us. We executed this acquisition and an emerging asset for us. It's 1 where we had established an organic acreage position. We drilled enough wells and proven the resource to ourselves. And it wasn't widely recognized, I'd say, as to the value that we had actually captured there, which kept -- put us in an advantaged position when negotiating with Encino.

We're able to capture that asset, which kind of fit hand in glove with our pre-existing acreage position. It gives us the scale. They really fast track that play from being an emerging to what we call a foundational asset, which gives us the scale, the economies of scale, the ability to capture operating advantages, things like in-basin sand, leverage, water, leverage marketing agreements and things of that nature.

We did it in an area at a time where we were below mid-cycle prices, which gave us some confidence on the amount of production that we were paying for that maybe we didn't get it right in the short term, but over the long term, being able to step into some production at below mid-cycle prices would probably work out. We had identified a significant amount of upside, not only with the expansive acreage position, but with the operational momentum that we already captured.

To date, we've already captured and exceeded our target on synergies, which was about $150 million. We've already reduced our well costs. We exited last year with a well cost of less than $600 per foot, which exceeds both legacy EOG and the legacy Encino acreage. We've been able to utilize our technology, things like our production optimizers that we've rolled out to basically about 90% of the wells that we acquired in that transaction.

And we couldn't be happier with it. A lot of people have compared the way we executed that transaction to the Yates merger and acquisition about a decade ago. And I can't disagree with that. Both were emerging assets, both were slightly underappreciated at the time by -- the Street, both were privately negotiated, and we had a bit of a competitive advantage because of the data and knowledge base that we've put together beginning with an organic acreage footprint.

And I've always understood your M&A strategy is the market is going to pay for flowing barrels with the mark pays that any premium you pay on a combination of flowing barrels and acreage accrues to the acreage and then you've got a bunch of locations that are burdened. And then you could get away with it. And I would argue the flowing barrels you got from Encino were fairly priced. And so therefore, the premium was reasonable.

We just had last week, and we've got investors asking, BLM sale in New Mexico in your neighborhood, which was unproducing acreage, right? Just no flowing barrels -- and you saw companies pay up to $6 million of location to secure that stuff. What was your philosophy? You know that I'm sure you are involved in looking at all of that stuff, didn't see you winning many hybrids at $6 billion of location.

One, what was your philosophy for that lease sell? And two, what does that lease sell telling us about inventory?

Yes. So the way we evaluate acreage or the acquisitions or undrilled acreage or anything else is -- it starts with a returns framework. So when I look at that, to your point, on large-scale acquisitions, the bid-ask spread on producing barrels is low return. It's 10% to 12%, something like that. So that's kind of fixed. And so you really need to have either a low enough production that comes with an acquisition or a high enough upside -- and the ability to drill it quickly, you want to drill it quickly because it's such high return to really make a compelling return argument there.

The same thing applies for small bolt-ons or lease sales, quite frankly, is if you're going to spend money on it, I would think that you're going to want to drill it, you're going to need to drill it. It should be moving to the front of your inventory. Just to continue to buy acreage, especially at high dollar cost and say, you're going to get to it a few years from now, that's not the most exciting thing for us.

So when we look at things like this most recent lease sale, we would evaluate it through that lens of returns and not just direct cash-on-cash rate of return if I drill a single well, -- but how does that full cycle affect the corporate-level returns? How does adding $6 million of land cost to each and every well going to affect the DD&A pool and the ability to generate earnings and income longer term. $6 million per well at $100 per oil. And if you drill a $7 million well, you can make a good cash on cash return with an 87.5% NRI, but that's all embedded into the full cycle cost of your company. And so that's the level of details and the level of thought that we look at is on full cycle returns.

Now to the second part of your question, having a record setting -- a lot of different landing zones. But boy, that is a high dollar amount. I think what it keys into is how precious Tier 1 acreage is in any of these basins, how important it is to be in the sweet spots of basins and how -- especially in the Permian a significant amount of that Tier 1 acreage is really captured or held by only a handful of companies. And so that's why you're seeing such -- and I think more interesting, I think, is not just the high watermark of that lease sale.

But the wide range of pricing that was paid per acre because that really tells you how -- what the difference of quality is between Tier 1 to whatever you want to say, Tier 10 or something or that there is I hope I never have to write a you filing 10 years worth of stuff.

I've often described strategy as what companies refuse to do. What is EOG refused to do.

Yes. I don't think -- I think EOG refuses to be dogmatic even with saying that we were fused to do to refuse kind of a never say never type of mentality. I will say what we're committed to and what you can count on is a consistent strategy, a consistent observation of what's made a compelling investment opportunity, a successful company for over 30 years. And it starts with what we talked about earlier, capital discipline.

Capital discipline really is simple. Simple to say, it's difficult to execute on, but it's no more difficult than making sure that your investment in each asset, it improves that asset every year. If the asset quality is starting to reduce, then you just need to pull back -- pull back your investment there and allow your team time to work the problem and continue to increase the value of the assets.

The second thing is operational excellence. It's empowering your employees to use data and technology, giving them the tools that they need to actually work the problems. It's consistent commitment to exploration, organic exploration and innovation on the operations side. It's a commitment to sustainability and safety. That's a very important way to create shareholder value.

And last and probably the most important driver of everything is nurturing the culture of the company. The culture at EOG is truly 1 of decentralization. And that doesn't mean just physically having geographic offices and running satellite offices. What it means is empowering your employees in those offices to really -- the employees that are closest to the business, the value drivers of the business, really empowering them to make decisions and have responsibility and accountability to fix issues when they see issues arising to identify value drivers, opportunities to improve the value of the business and encouraging them, giving them the responsibility and make those decisions and really drive the value of the business forward.

That's -- that's what's driven EOG's success for 30 years, and I think that's what we'll continue to separate us in the future.

We've got a ton of different questions on growth opportunities, which -- and exploration, which pleases my heart I'll start with a macro one. The consensus narrative is that oil shale growth opportunities in the U.S. have peaked and growth while good will slow. Is that a fair assertion? Why, why not?

Yes. I think we've grown pretty aggressively in the last decade, 15 years. And so with any asset, whether it's conventional, but especially in unconventional, the more you grow, the steeper that decline rate is. And so what we've seen in recent years is the hole that you need to fill in on an annual basis is about 2.5 million barrels a day, plus or minus, just before you can start to maintain or grow above and beyond that.

What's happened in the U.S. is, well, EOG has continued to explore. Sorry about that. We've taken -- we've talked about that. It's a core piece of our culture. The rest of industry has kind of slowed down, starting to come back a little bit. But there is a long period of time where exploration was kind of on the back burner, and that's created a scenario where we, as an industry in the U.S. are a little bit behind the curve on being able to continue to grow aggressively.

That -- that is the first piece of it. Now is there the opportunity out there? Yes. I believe there fully is. I think -- I know for our company, we have a number of different domestic exploration opportunities that we're actually leasing and drilling on. We have been for the last couple of years, and we continue to do that. We continue to bring forth different projects.

But again, you need to be committed to exploration, and it doesn't need to be just on a company level, but it really needs to be on an industry level. And that continues to be in reaching deeper or further up the pipeline. So towards the university, towards new hires, new entry into the industry. You need to encourage those employees to think about this as an exploration industry.

At the end of the day, the oil business is or the natural gas business, it is depleting assets. And the only way to have a sustainable business model is to continue to drive exploration.

That brings us to EOG is getting extremely active in the pure sell. Can you share a bit on the revisiting of abandoned shale plays? How much runway does that give U.S. shale?

Yes. I don't know if I can speak to U.S. sale because, again, it kind of goes to the last question on 2 companies have the culture to do they understand how to explore anymore? Do they understand how to measure risk? Do they have the stomach to actually revisit areas and look for bypassed pay.

The Utica is probably a better example I could rely on where the UCA is a play that -- listen, this thing was initially identified back in 2012 and '13. And ourselves, we actually looked at the play. It was the third time we looked at the play that we actually started to take leases in it in late 2019. We looked at it back in 2013 and '14. We looked at it again in about 2016 and '17.

And finally, when we revisited in 2019, we revisited with a little bit of data, a little bit of technology and our approach that really was an outgrowth of a small Woodford oil play that we had at the time. It was a geomechanical model. So looking at the way that the rocks break as opposed to purely focusing on the porosity. And that actually unlocked the entire Utica for us.

So yes, I think there is potential -- listen, -- the best place is an old adage, right, the best place to explore for oil is where oil is producing because there's always going to be bypass pay there. And it's a matter of getting your cost structure right, utilizing new data and technology, continuing to reinvent some of these plays. And that is definitely going to be able to unlock historically, what's been bypass pay going forward into the future.

I think there's a lot of potential there.

You didn't say anything specific about the Pearsall. But -- moving on.

Yes, we have so many -- we have a number of different exploration opportunities, both domestic and international. And so trying to go down a checklist of exploration ideas for a company of our size, we potentially be here all day.

We'll be here at least 5 more minutes. Considering the geopolitical backdrop, has Canada become a potential long-term attractive region for EOG. I remember when you guys were in Horn River.

Yes, we were in Canada. Geopolitics is 1 of about 4 or 5 different variables, quite frankly. It's got to start with the subsurface, of course -- subsurface quality has to be -- and this isn't just Canada. This is really anywhere -- maybe we'll narrow it down into international for the moment. But really, it's got to start with subsurface quality. We've got to see identify some sort of subsurface well productivity that's going to be additive to what we can identify domestically.

The second piece is on the surface, is it going to have an established oilfield services sector. Now that's for us. We prefer to have that. We're not we're not of the size and scale where we're going to go into a frontier country and stand up an entire oilfield services sector there. We prefer to have access to high-quality equipment, high-quality oilfield services, personnel, things of that nature.

You need to have stable geopolitical that is 1 of the keys there. Need to have also rule of law and things like that, that you can count on. And then preferably, access to premium markets. That might be 1 of the headwinds for Canada in particular. But those are the things that we try to line up before we think about going international because to be perfectly honest, while there are rules and regulations here in the U.S., there is a fantastic or I should say, well-defined regulatory environment that you can navigate through, and we've been successful doing that.

So going abroad, you really need to line up a number of different things.

Premium prices, oil, it's hard to get a premium price on oil ultimately. Gas, you can. There are local gas markets where you're competing with someone bringing fuel oil, right? And suddenly, you get quite a nice price. One of the 2 international regions where you have shale or interventional assets as Bahrain, the other is UAE. We're on the cusp perhaps I'm hearing from you all on some of the early well results.

Talk to those 2 opportunities and when you get comfortable maybe with the subsurface.

Yes. Yes. So briefly, before I go to those, I'd say, even on oil, Bob, we've got exposure to roughly 250,000 barrels a day that goes offshore from the U.S. And so again, exposure to premium pricing there as well. It all depends on how strategic you are on the marketing. And again, those are opportunities that a lot of times we put together counters quickly.

Now as far as Bahrain and the UAE go, you're right, we entered both of those countries last year. Those again were some international concessions that we captured during a softer environment, which was great. Bahrain is a horizontal unconventional tight gas sand. And in the UAE, we've got a horizontal oil shale, maybe a little bit similar to the Eagle Ford as the way to think about that one.

We have drilled wells now in both plays. We anticipate having production sometime this year. and we're excited about the opportunities. The UAE is actually an opportunity similar -- not dissimilar from the Utica, it's an opportunity that we've been looking at for a number of years. We've been engaged with ADNOC off and on probably since about 2019, trading technical notes on the resource, and we're excited to have the concession that we received there.

It's a 900,000 acre concession, like I said, unconventional horizontal oil. And then Bahrain, a little bit different. Obviously, it's an island nation. It is an onshore play. So scale is 1 of the things that we're looking at there. In both countries, we've been happy with the access to oilfield services, infrastructure, especially in the Bahrain side as established producing. And we actually have production already established in Bahrain, legacy production that we're operating.

Our newer operated wells, again, I think we'll get some production on this year that we'll be able to talk about.

And there's 2 things you're extrapolating. You're going to take those early well results against the body of knowledge you have and think about where they could go, right? They're going to go up to the right. Those type curves will improve. The other thing you're extrapolating is the cost structure. The cost for these first 2 wells, it was Fortune, they were bespoke, they're one-off. That will come down. And if those intersect in a favorable place you move forward?

Along with the operating environment. During the exploration phase, you're right. we're testing our subsurface model, which both of these resources have been drilled horizontally and tested hydrocarbons to surface. So that's 1 thing that we're looking to confirm is what is our targeting our completions technology look like? Do we get the uplift that we anticipate. You're right, we're evaluating the access to the oilfield services and our ability to drill and complete in a costly manner.

But the other thing we're evaluating is just the operating environment, the regulatory environment, the rule of law, the relationship with the national oil companies. And in a lot of ways, the conflict has sped up the learning on that. Obviously, it's kind of stress tested our relationship with the national oil companies there. And we're going to be happier with it. It's been very good, very transparent communication with both companies. And so that's gone a long ways towards giving us the confidence that we selected the right partners.

So the UAE saw your early results and left OPEC?

Let's not get quoted on that. Yes. We don't really have any comments on that, quite frankly. I think that decision was maybe 1 that was speculated on by a number of people for the last few years. And certainly, they've identified they have a desire to grow some of their unconventional resources. And I think that's 1 reason we're able to partner with them.

And if I think your definition of a foundation asset, in my interpretation is you want to park a frac crew there year round and you want that frac crew pushing through roughly 100 wells, right? That's and therefore, probably supported by 3 to 4 drilling rigs. And if you're kind of putting through 100 wells, you're approaching $1 billion a year of CapEx in that asset roughly. Right? Is that the scale could -- is the goal for the international to become a foundational asset?

The goal is for the international players to become foundational assets. I'm not sure if the CapEx numbers work out that way for every 1 of our assets. But you're right, foundational is to have a consistent frac fleet is the easiest way to think about it. And we've talked about this before. In any of these unconventional resource plays, you get a step change in capital efficiency when you can run consistent drilling rigs.

And then you get another 1 when you can operate consistent frac fleets. Anything above that, there are obviously incremental gains, but that's why we can feel confident about putting in some infrastructure. And I don't necessarily mean midstream. I mean things like water lines and sand and things of that nature. And that's really what drives the economies of scale.

For any of these unconventional plays, including international, you essentially need to -- wells are short cycle, but these plays are relatively long cycle when you get a play up and running. You need to essentially build a virtual manufacturing plant in the field and then you can start to rinse and repeat and reiterate with data and technology and make the wells better and drive down costs through those economies of scale that I'm talking about.

And so that would be the hope that we can early on test our model, our forecasted model here and have line of sight to be able to turn these things into not just competitive, but really more than competitive, more than additive to the existing inventory base that we have in the company.

As a follow-up to your exploration comments is EOG likely to entertain the potential to go back to the Gulf of America and Deep Gulf?

Yes. Not the Deep Gulf, really. Definitely, what we've done in Trinidad over the 30 -- almost 34 years we've been there, is we have developed an expertise in that region as shallow water operators. We did used to be back in the '90s and the early outs involved in the Gulf of America in the shallow water offshore. It would be all, that would be a heavy ask, a heavy lift to get us to reenter there. We've maintained an area of expertise down in Trinidad. Not only do we have exceptional subsurface knowledge. But because of our cost structure and the way that we operate, we've got a bit of a competitive advantage in that region.

To try and step up into an area in the shallow water Gulf of America, I do think there's opportunities to bring technology that's been developed in the deepwater and the ultra-deepwater that hasn't been revisited necessarily or applied back to the shallow water in the Gulf of America, but that's probably right now better less suited to the operators that are in the region.

And think about Trinidad Tobago your adjacent to Venezuela. You've got the Orinoco River there piling sediments out into the basin. Any interest in Venezuela?

Yes. That goes back to geopolitical stability and rule of law. There is a lot of potential there. Everybody knows, obviously, it's a resource-rich country. But it's too early to tell for us. Quite frankly, we're very happy with where we're at in Trinidad. Like I said, we do have some shallow water expertise that would potentially translate over there. But at this point, we're a long ways from feeling that that's a compelling opportunity right now.

I want to come back to something we discussed in the past, which is well records in the U.S. are public data. Everybody with a couple of clicks can pull up a well result, AFEs well budgets or not. So unless you disclose well budgets, which you're not going to do, there's this tension between companies that drill for the best well, the best IRR and companies that are drilling for the best NPV of a block of cube section.

You've adjusted EOG strategy versus some of your predecessors focusing more on a blend of IRR plus NPV. Talk to that philosophy.

Yes, that's exactly right. The best example is in the Delaware Basin in the last few years. Since industry is kind of high-cost watermark of 2023, in the Delaware Basin, we've reduced our well cost about 20%. And so what that means is we need to drop your well cost about 20%, you can realize all that on just increased returns or especially in a basin like that, with an immense amount of resource potential. You can go back and reevaluate different landing zones, different spacing potentially and see if you're really optimized between returns and NPV.

And that's constantly what we do in these shale plays is we're constantly trying to balance between your returns and your resource or your NPV on really a per acre, per drilling unit basis. And I think that's exactly right. We still start with returns-focused investment focused on the bottom cycle pricing. We want to measure every 1 of our investments on the bottom cycle. That's how we have confidence that we can create shareholder value through the cycle.

But we also measure that investment. If you only do that, you might be leaving something on the table. Look at bottom cycle price and we use this $45 oil and $2.50. Well, we are roughly double that today, on the oil side, not on the gas side. And so -- is that the right development for where we're at today if you're in an established field or an established play? So we look at our investments. We begin with the bottom cycle pricing on a returns hurdle of 30% direct after-tax rate of return. But we also measure our development plans at a series of mid-cycle prices, less on strip prices, we look at NPV, we look at time to pay out versus, say, mid-cycle prices and, quite frankly, spot prices and just see.

To be perfectly honest, if you're drilling just a 50%, 60% rate of return well at that bottom cycle prices. At today's strip prices, those wells would pay out in a few months. Well, is that the right -- is that really the right approach. Again, in an area where you've got such rich resource, you're leaving so much behind no matter what you do. You need to think about those incremental barrels. What's the incremental finding and development cost on each of those barrels that you can bring forward.

And maybe in our last 2 minutes, what ultimately is the value proposition for owning EOG stock?

Yes. The value proposition is just what I alluded to. It's shareholder value through the cycle. That's where we're focused on. We're not a company that you should expect is just going to lean in heavily when you see a price signal. We're going to focus on the fundamentals what is supporting the pricing there? And what can we do to continue to improve each and every year in every single 1 of our assets.

We want to focus on expanding margins and lowering the breakeven costs. And the way that we do that is the things that I started with at the beginning, capital discipline. That's it, investing with an eye on returns, realizing that this is a commodity-based business. And so measuring returns not at strip prices, not at the high end, but you always need to be cognizant of what your returns are going to look like at the bottom cycle.

It doesn't mean that's the end all be all for your investment, but you definitely want to measure it and keep that front of mind. You want to invest in your assets to make sure that they're improving each and every year, and you want to backfill that inventory through exploration.

Utilizing the data and technology that you collect to drive operational excellence, not only on lowering sustaining well costs, but also on capturing new resources, which we have been able to do last year through a variety of ways, not only organic exploration, international concession capture, but also some strategic small bolt-on and large acquisitions.

The third thing is remaining committed to safety and environmental performance being a leader in sustainability. And the last, again, is nurturing the culture of the company. That's where it all begins. It's the culture of the company that is the real competitive advantage it has been for 30 years. It's really focused on organizing and running a decentralized company that allows the employees to focus on the task at hand, which is at the end of the day, pretty simple. It's creating more oil and gas for less cost. And that's it.

Thank you, Ezra. Thank you, audience.

Good day, everyone, and welcome to EOG Resources First Quarter 2026 Earnings Results Conference Call. As a reminder, this call is being recorded. For opening remarks and introductions, I will turn the call over to EOG Resources Vice President of Investor Relations, Mr. Pearce Hammond. Please go ahead, sir.

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

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

Thanks, Pearce. Good morning, and thank you for joining us. EOG is off to an exceptional start in 2026. Our track record of consistent high-quality execution continues to set us apart, delivering strong operational performance across our foundational assets while steadily advancing our emerging plays and exploration opportunities. The first quarter was a clear extension of that momentum. We exceeded expectations across key operating and financial metrics. Production volumes, total per unit cash operating costs and DD&A all outperformed guidance midpoints, driving robust financial results.

We generated $1.8 billion in adjusted net income and $1.5 billion in free cash flow. Consistent with our commitment to disciplined capital allocation and enhancing shareholder value, we returned nearly $950 million during the quarter through our regular dividend and opportunistic share repurchases. In today's macro environment, EOG is well positioned in realizing the benefits of decisions we made during a more challenging commodity price backdrop. Those actions were deliberate and are paying off. For example, we strengthened our portfolio through the acquisition of Encino, increasing our oil production by approximately 10%. And we complemented that with a strategic bolt-on acquisition in the Eagle Ford. We also enhanced our market exposure by securing LNG contracts linked to JKM and Brent, positioning us to capture premium pricing in global markets.

Additionally, we expanded our international footprint with high-quality concessions in the UAE and Bahrain, opportunities that would be difficult to replicate in the current price environment. Finally, we continue to deepen our vertical integration across critical services. This differentiated approach further improves efficiencies, lowers costs and strengthens execution across our operations. As a testament to investing capital at a disciplined pace between the first quarter of 2022, which was the last period of very robust oil prices and the first quarter of 2026, where we are in a similar oil price environment, we have added nearly 100,000 barrels per day of oil, over 140,000 barrels per day of NGLs and nearly 1.6 billion cubic feet per day of gas to EOG's net production.

We did this while generating an average ROCE of 27%, returning approximately $20 billion to shareholders and maintaining a pristine balance sheet. EOG continues to take a consistent approach to capital allocation in the current environment. Given robust oil prices and softness in natural gas, we have refined our plan for the balance of 2026. We are increasing oil and NGL production while maintaining our $6.5 billion capital budget by reallocating capital from gas to oil-weighted assets. This is a disciplined and pragmatic rebalancing that underscores the value and flexibility of our multi-basin portfolio. Our 2026 program includes production growth, domestic and international exploration and a peer-leading regular dividend with a breakeven oil price below $50 WTI, leaving ample room for additional cash return to shareholders under current Strip prices.

This revised plan strikes the right balance between near-term free cash flow generation and long-term value creation while preserving the strength of our balance sheet. Turning to the macro backdrop. The conflict involving Iran is the most significant development impacting our business and the broader energy markets. Disruptions to crude supply and flows through the Strait of Hormuz are estimated to remove approximately 900 million barrels from global markets through June 2026. Even in a scenario where the conflict is resolved relatively quickly, rebuilding global inventories back to 5-year average levels will provide ongoing support for oil prices. Additionally, we expect the post-conflict outlook to include replenishing strategic petroleum reserves, limited remaining global spare capacity and a higher geopolitical risk premium. Together, these dynamics point to a constructive oil price environment with geopolitical developments likely to continue driving periods of upside volatility.

On natural gas, near-term pressure remains with lower 48 storage levels above the 5-year average. However, our medium- to long-term outlook remains positive. U.S. natural gas benefits from 2 durable structural tailwinds, rising LNG feed gas demand and increasing electricity consumption. We expect U.S. natural gas demand to grow at a 3% to 5% compound annual growth rate through the end of the decade and believe the previously forecasted potential for global LNG oversupply has been significantly reduced with the damage to LNG infrastructure abroad. Our investments in building a premium gas position to complement our oil business have us well positioned to supply these expanding markets. And while EOG's share price has increased following the onset of the conflict, the move in oil prices has been even more pronounced.

As a result, we continue to believe EOG represents a compelling investment opportunity for several reasons. First, we have a high-return domestic and international asset base with deep long-duration inventory. Across our multi-basin portfolio, we estimate approximately 12 billion barrels of oil equivalent of resource potential, generating greater than a 100% direct after-tax rate of return at $55 WTI and $3 Henry Hub. Our disciplined capital investment allows us to pace development appropriately and direct capital towards the highest return opportunities across the portfolio. Second, we bring differentiated exploration capabilities and approximately 25 years of unconventional experience, an advantage we have consistently leveraged to identify and capture opportunities ahead of the market.

Third, we have a demonstrated track record as a low-cost, highly efficient operator, supported by strong technical expertise and operational execution. In the past year alone, we reduced average well cost by 7% and operating costs by 4% Fourth, we generate durable free cash flow and consistently deliver a peer-leading return on capital employed. Fifth, we remain committed to a sustainable and growing regular dividend, complemented by meaningful additional cash returns. Notably, we have never reduced nor suspended our regular dividend in 28 years. Finally, our pristine balance sheet provides resilience and strategic flexibility through commodity cycles.

All of this is underpinned by EOG's distinctive culture, a decentralized collaborative operating model that fosters innovation and drives performance at the asset level. In summary, we're off to a strong start in 2026 and are well positioned to execute in the current macro environment. We remain focused on delivering sustainable free cash flow, maintaining operational excellence and creating long-term value for our shareholders. Now I'll turn it over to Ann for details on our financial performance.

Thank you, Ezra. EOG delivered another quarter of outstanding financial performance, once again demonstrating the power of our consistent approach to capital allocation, invest with discipline, return cash and maintain a pristine balance sheet. In the first quarter, we generated adjusted earnings per share of $3.41 and adjusted cash flow from operations per share of $5.85, yielding free cash flow of $1.5 billion. During the first quarter, we returned approximately $950 million to shareholders, nearly $550 million through our regular dividend and approximately $400 million in share repurchases. With $2.9 billion remaining under our current share repurchase authorization at March 31, we have substantial capacity for continued opportunistic buybacks.

Our financial position remains exceptional. We ended the first quarter with over $3.8 billion in cash, an increase of approximately $450 million since year-end 2025 and net debt of $4.1 billion. Our leverage target, which is maintaining total debt at less than 1x EBITDA at bottom cycle prices of $45 WTI and $2.50 Henry Hub remains among the most stringent in the energy sector. This provides both downside protection during challenging periods and the financial flexibility to invest strategically through commodity cycles. Turning to 2026. Our low-cost operations and financial strength allow us to be unhedged, providing shareholders full exposure to higher oil prices. At current Strip pricing and using guidance midpoints, our 2026 plan generates a record $8.5 billion in free cash flow. Given the substantial increase in oil prices since late February and the subsequent increase in our free cash flow, we expect to return at least 70% of free cash flow this year, which would represent a record annual cash return to shareholders.

The foundation of our cash return remains our regular dividend. Historically, we supplement the regular dividend with share buybacks or special dividends. Over the past 3 years, we have favored share buybacks as our primary supplemental return mechanism as we believe the shares are attractively valued, and we like the connection between repurchasing stock and dividend increases. We are committed to executing buybacks opportunistically. If market conditions warrant, we could build some cash on the balance sheet to provide future flexibility to maximize long-term value creation.

Our track record speaks for itself, whether through buybacks, special dividends, strategic bolt-on acquisitions or infrastructure investments, we've consistently deployed capital to enhance shareholder value. EOG's financial foundation has never been stronger. We are generating significant free cash flow, returning meaningful cash to shareholders and maintaining financial flexibility to capitalize on opportunities as they arise. This combination of operational excellence and financial discipline positions us exceptionally well for long-term value creation. With that, I'll turn it over to Jeff for our operating results.

Thanks, Ann. I would first like to thank all of our employees for their outstanding performance and efficient operational execution in the first quarter. Our quarterly volumes, total per unit cash operating costs and DD&A beat guidance midpoints. This was accomplished during a quarter with a significant winter storm event that impacted numerous operating areas and caused substantial third-party downtime. With the benefit of EOG owned and operated infield gathering systems, the use of in-house production optimizers, area-specific control rooms and our diverse marketing strategy, our teams were able to manage remote operations and minimize downtime during this event. These efforts have allowed us to get off to a strong start in 2026. And because of that, I would like to recognize our field teams for all their hard work and dedication.

For the full year 2026, we are increasing oil production guidance by 2,000 barrels per day and NGL production guidance by 6,000 barrels per day while keeping total capital expenditures flat at $6.5 billion. The added oil and NGL volumes are driven by reallocating capital across the portfolio rather than increased activity levels. From a development standpoint, we are moderating near-term drilling and completions activity at Dorado in response to current gas prices. Dorado remains a large-scale, high-quality dry gas resource, and we continue to invest in this foundational asset at a pace to balance short- and long-term free cash flow, grow into emerging North American gas demand and leverage our technical learnings and infrastructure to continue lowering breakevens and expand margins.

Capital is being reallocated to our foundational oil plays to leverage current market conditions. This initiative underscores the strength of our multi-basin portfolio, which allows us to continually optimize capital allocation as commodity cycles evolve. This reallocation is weighted towards the second half of 2026 while maintaining capital discipline and preserving long-term value across the portfolio. Turning to costs. We have not seen any significant inflation with our services or cost increases on high-quality rigs or frac spreads. For 2026, approximately 50% of our well costs are already locked in, and we continue to rebid services to maintain pricing discipline. While some vendors have added fuel surcharges, our exposure to higher diesel prices is structurally lower than many peers.

Approximately 70% of our drilling rigs can run on natural gas and 100% of our frac fleets are e-frac or dual fuel capable, both able to be powered by our low-cost field gas, which significantly mitigates exposure from rising diesel prices. On the operating cost side, the impact from higher diesel prices has been minor. Overall, we are insulated from a number of these potential inflationary pressures through our contracting strategy, self-sourced materials and vertical integration. Long-term staggered contracts limit its exposure to spot market volatility, while our ability to source key inputs directly and leverage integrated infrastructure reduces risk to higher prices.

Collectively, these actions allow us to maintain capital efficiency, drive execution and focus on sustainable cost reductions and are complemented through utilizing data and technology to reduce time on location, all of which deliver significant results across our portfolio in the quarter. First, on drilled feet per day, we realized the following increases in the first quarter of 2026 versus the full year 2025 average. In the Utica, we increased by 22%. The Powder River Basin increased by 13% and the Eagle Ford increased by 12%. We continue to make significant strides in capital efficiency through lateral length optimization, resulting in fewer vertical wellbores to drill, more productive time both on surface and downhole as well as a reduced surface footprint.

In addition, EOG's internal drilling motor program acts as a force multiplier on these longer laterals, improving downhole drilling performance and giving us the confidence to continue extending laterals across the portfolio. We are focused on drilling 2- to 3-mile laterals in the Delaware Basin and 3- to 4-mile laterals in the Utica and Eagle Ford plays. Second, our completions teams are continuing to increase stimulation efficiency. Each of our foundational plays has increased completed feet per day led by the Eagle Ford and Delaware Basin at 12% and 17% increases during the first quarter, respectively. One major factor that has allowed us to accomplish these results is an increase in our maximum pumping rate capacity by approximately 20% per frac fleet since 2023.

This has not only allowed our technical teams to decrease their total pump times, but also allowed our engineers the flexibility to tailor each high-intensity completion design around the unique geological characteristics of every target. Additionally, our teams are applying real-time geology, drilling and completions data to improve well performance across the portfolio through innovative completions and targeting strategies. For example, our Western Eagle Ford wells are benefiting from larger frac job designs, and we are seeing positive results in the Utica from staggering our landing zones. Third, I would like to highlight our Janus natural gas processing plant in the Delaware Basin. Since November 2025, this plant has averaged 300 million standard cubic feet per day of processing, representing 94% plant utilization.

Janus had a record month in March 2026 with 100% utilization and 316 million standard cubic feet per day of processing. Strong operations at Janus help us reduce Delaware Basin GP&T costs while highlighting the advantage of strategic infrastructure investments. Delivering this level of consistent performance is impressive and is a testament to the execution of the teams on the ground. This is another example of EOG's operational excellence delivering financial results. And lastly, our marketing strategy, built on flexibility, diversification and control continues to deliver significant value. A key and growing aspect to this is our access to international markets and exposure to premium pricing.

On the crude side, we have access to 250,000 barrels per day of export capacity out of Corpus Christi. We leverage this capacity to reach international markets, and it gives us the flexibility to price crude on a domestic-based or Brent-linked price. Regarding LNG gas supply agreements, our Cheniere contract expanded from 140,000 million BTUs per day to 280,000 million BTUs per day during the first quarter of 2026. An additional 140,000 million BTUs will start in the second quarter of this year, bringing us to the full 420,000 million BTUs per day. These volumes are linked to JKM or Henry Hub pricing at EOG's election on a monthly basis.

We also supply 300,000 million BTUs per day of LNG feed gas at Henry Hub-linked pricing. Together, these contracts highlight that our marketing strategy is a competitive advantage and demonstrates how targeted international pricing exposure is driving premium realizations and incremental value across both crude and natural gas. After a strong first quarter, EOG is well positioned to execute on its full year plan, and we are excited about our operational team's ability to drive value through the cycles. Now here's Ezra to wrap up.

Thanks, Jeff. I'd like to note the following important takeaways. First, we started 2026 with strong momentum and execution across the business. Second, capital discipline is a core pillar of our value proposition, and we have updated our 2026 plan to increase oil production while keeping capital spending unchanged. Our portfolio is performing, our balance sheet is resilient and our capital allocation remains firmly anchored in returns and shareholder value. Third, we expect to continue to deliver in 2026 and beyond for our investors. In a macro environment that demands both agility and rigor, we are well positioned not just to navigate volatility, but to capitalize on it.

Our disciplined approach to investment across our foundational and emerging assets continues to grow the free cash flow potential of the company, both in the short and long term. Overall, our success is grounded in our commitment to capital discipline, operational excellence and sustainability, all underpinned by our culture. Thanks for listening. Now we will go to Q&A.

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

My first question is on marketing. You raised your full year oil guidance by $3.25 a barrel. Can you remind us of the pricing mechanism on those waterborne barrels out of Corpus as well as the potential uplift you anticipate from the Cheniere marketing agreement as you're reaching 420,000 BTUs in 2Q?

Yes, Arun, this is Jeff. Thanks for the question. First off, going with the waterborne volumes that you talked about. Yes, as I talked about in my opening comments, we got about 250,000 barrels there that we have export capacity on. And what I'd say is they can be linked either to domestic pricing or Brent-linked those sales. And what we do is we basically sell those cargo by cargo there. So it's basically on an each ship basis. And what I'd say is there's been obviously a lot of price volatility recently with the conflict. So we have been able to sell numerous cargoes, obviously, at a premium. So it's really been paying dividends to have that export capacity to really diversify our marketing on the oil side.

And then, yes, over on the JKM side, when you look at the LNG, I think what you're seeing is you're starting to see a little bit of the benefit from that JKM, but you're also seeing some of the volatility in the market that's kind of counteracting that, and it's a little bit of noise. So as you know, we came into the year, we were producing 140,000 MMBtu into that Cheniere contract. We increased that another 140,000 in the middle of this first quarter. So you're not seeing the full realizations flow through. And then we'll have the additional 140,000 come in, in the second quarter, and you'll continue to see it kind of build into our overall guidance as you move forward. And then the other thing that I'd note on the actual price realization for gas is although we have pretty minimal exposure out in the Permian with Waha, and we've got exposure less than 7%, you do see a little bit of an effect of that on the realizations for the first quarter, especially with some of the lower pricing that we've seen over there.

And I don't really think you'll see that alleviate until you get to the -- probably the last quarter whenever we start bringing on some more egress there in the Permian Basin, and we bring on that 4 million to 5 million a day capacity. So all in all, we're extremely happy with our overall international exposure. It's a great piece just really to diversify our overall marketing strategy and especially at times during volatility, I think our teams are doing a great job of taking advantage of it.

Great. And my follow-up is on the Middle East exploration program. I was wondering if you could provide us a little bit of an update on what's going on, on the ground? And how Ezra you think about capital allocation, just given the geopolitical risk situation, although you could argue if the UAE does leave OPEC that perhaps provides a potential tailwind to growth. And perhaps you could give us a sense of when EOG may be in a position to share initial results either from Bahrain or UAE on your exploration program?

Yes, Arun, this is Ezra. Yes, there's a lot there. So let me unpack some of it, and maybe I'll let Keith Trasko address kind of the current operations piece of it. But on the UAE's decision to leave OPEC, maybe we could start there. It doesn't really have any change or impact for EOG. We just recently began operations in the country. So we haven't felt any impact. And going forward, we certainly don't expect to. I think it shows just some of the positive steps UAE is taking within their country. But from our perspective, our intention has always been that if the plays are successful, returns are going to drive that investment and the growth in the oil play more so than any type of production quotas.

As far as continued capital allocation given the geopolitical risk, listen, longer term, it's still early in the conflict to be making those types of decisions. What I would say is during the exploration phase, we entered this trying to do a couple of different things, certainly evaluating the subsurface potential of the fields. We certainly wanted to evaluate the surface and operating environment, can we get access to high-quality equipment? Can we build scale there and things of that nature. But we're also looking during that exploration phase to evaluate the geopolitics, the sanctity of contracts, our partners, things of that nature.

And what I would say with great confidence here during this conflict, we've definitely landed with strong partnerships with both ADNOC and Bapco. It's been very clear communication, straightforward alignment on our operations. And so that really gives us pretty good confidence going forward. And actually, it gives me confidence in the way that we approach or look at the potential for other international opportunities.

This is Keith. On the operations side, we're kind of looking at it that we're closely monitoring the situation in both Bahrain and the UAE. It's pretty dynamic. We have some employees that remain in the region, while others have been repositioned. Since the program is still in the exploration phase, our 2026 plan for Bahrain and UAE was designed with a lot of flexibility. On the time line side, both projects are moving forward in line with our expectations for exploration plays. The near-term time line has slipped slightly a little from the start of the year. So we anticipate having results in the second half of this year, and we'll provide additional updates if there are material changes. On the longer term, we remain very excited.

We entered UAE and Bahrain because we saw compelling subsurface opportunities, positive production results from prior horizontal development and strong partners in both countries. And none of that has changed. In Bahrain, you have a tight gas sand. In UAE, you have a carbonate mud rock, both -- very used to dealing with those types of rocks. We believe they will benefit significantly from the drilling and completions technologies that we employ in our domestic and unconventional plays every day. So in the current exploration phase, we're gathering data on long-term well costs, evaluating our ability to access high-performing surface equipment. And we started exploration activity with limited operations in both countries last year. So our goal still remains to just leverage our core competencies in onshore unconventional development to unlock resource that's competitive with the domestic portfolio.

Our next question comes from Steve Richardson of Evercore.

Ezra, it sounds like the decision to pivot a little bit more towards liquids is more to do with the opportunity in liquids than it is a change in your longer-term view in gas. And maybe you could talk about that -- the value of keeping the capital flat and making that adjustment within the portfolio? And then what -- it does sound like you're thinking that this is a longer-term impact to markets, which I think we would agree with. So how does that set you up for 2027 and beyond from a liquids and potentially oil growth perspective?

Yes, Steve, great question. This is Ezra. Yes, I'd start with maybe the decision on the capital reallocation this year. Really, it's just looking at where the dynamics have played out and what's happened since the beginning of the year. Obviously, there's a dramatic upset on the liquids side, on the oil side, and you've seen a dramatic response in the oil price. Conversely, you started to see on the natural gas side, inventory levels after starting the year off pretty strong, supporting price, you've seen inventory levels climb above the 5-year average and gas prices pull back just a little bit. And so it's -- for us, it's a pretty simple calculation of just reallocating some of the activity in Dorado to some of our more oil-weighted assets, not just for returns, but quite frankly, there's a call across the world, across the globe right now for increased oil supply.

And so that's what we're doing. It's one of those things where in Dorado, actually, we've made fantastic progress. We've actually reduced our well costs down with our target is down below $700 per foot, and we feel confident that we can hit that this year. As you know, we've got a low breakeven price of about $1.40 per Mcf. But the advantage of having a multi-basin portfolio with both geographic and product diversity is that we have the flexibility that we can move capital allocation around throughout the years if you see something that is certainly as dramatic as we have this year. Now for 2027, this does set us up better to grow liquids, these maneuvers that we've done right now to grow liquids maybe a little more oil, a little more aggressive in 2027. But really, it's too early to get there.

We need to continue to see how the conflict proceeds. I think that's why we're confident in our plan today to maintain our capital budget is because we really want to see how these things really start to play out just a little bit longer. We're just not quite there yet as far as making a call on picking up rigs or frac fleets and investing longer term. Just this morning, over the last 12 hours, 10 hours, you can see just how volatile the situation remains. While we do think longer term, this sets up an environment where there's a much higher floor for oil price than where we entered the year, we'd like to have better line of sight and understand that just a little bit more before we took any additional steps forward.

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

Yes. Steve, this is Ann. Through the first 4 months of 2026, we have seen exceptional value on our stock. and that's been reflected in the buyback activity you referenced. And it put us in a good position to return that 70%, at least 70% of annual free cash flow back to our shareholders this year. As reported in the first quarter, we repurchased 3.2 million shares. And if we dissect that a little to your question, we did have some limitations on buybacks during the fourth quarter quarterly earnings period because for the first 2 months of 2026, we were operating under the parameters of a 10b5-1. So the majority of those 3.2 million shares were repurchased in March. But then we leaned in and from April 1 to April 28, we have repurchased approximately 2.3 million additional shares. And that's really a testament to us continuing to see a lot of value in our stock, and that's driven by tremendous positive momentum we see within the company.

We believe those buybacks support sustainable growth of our regular dividend, and finally, if you look at the energy weighting in the S&P 500, despite the increase in stock price, it's still very low at approximately 3.5% weighting. And you can also see free cash flow yields in the energy sector are also close to historic highs. So we've allocated over $7.1 billion to repurchases since we first started buying back stock in 2023, and that's allowed us to reduce our share count. That's been by more than 10% at compelling prices. That disciplined approach focuses on being opportunistic and positions us to create meaningful value for our shareholders. And we remain confident that continued improvement in our business and that growing intrinsic value will provide additional opportunities for us to buy back our stock going forward.

The next question comes from Josh Silverstein of UBS.

Just a question on the shifting activity. I was curious about the decision process as to how you reallocated amongst the 3 different basins there. Why 10 more in the Utica and versus 5 in the Delaware versus, say, 15 all in the Utica or the Delaware. I was curious if there was something that drove this or if it was based on what you could do with the existing rigs and frac crews there.

Josh, this is Jeff. Yes, thanks for the question. Yes, nothing to read into there at all. It really just happens to be what flexibility we have in our activity schedules at this point in the year kind of across all the assets. A couple of things that I'd state is in the Utica, where we are increasing 10, we've seen some of the easiest drilling in the company, and we've talked about that very openly and really solid efficiency gains here even just in the first quarter, where we increased our drilled feet per day by 22% versus 2025.

So seeing outstanding results there, and that's been able to allow us to build our working DUC count up there just a little bit more than some of the other plays. And then when you look at the Delaware, everything is going outstanding out there, we just tend to be a little bit more efficient on the completion side there because we've got full super zipper operation across our fleets, along with all of our sand logistics in place, you really don't have any kind of delays there. And then also, we've seen a 17% increase in the first quarter on completed lateral feet per day. So that was keeping the DUC count a little bit tighter. That's really all it is, just the mechanics of how things were moving, the time lines we had between our rigs and completion fleets in each one of the divisions and how it just made sense to kind of allocate that capital and keep each division healthy so we can keep improving each one.

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

Yes. This is Keith. Yes, we have a number of exploration plays, both domestic and on the international side. In fact, I'd say maybe even more of them on the domestic side than international. Our teams are always utilizing data from our successful plays to revisit basins, look at new basins, seeing what could be unlocked with the new technology that we apply to other plays and with the lower costs of today than the years that the basin was first looked at. We're always on the lookout for what can make our inventory better.

So I can't comment on specifics, but as you know, exploration has always been our preferred method of adding low-cost reserves. You look at Dorado, you look at our Utica first movers, Trinidad exploration, even the Encino acquisition was born of organic exploration from the years prior. So we expect all our asset teams to be exploring for inventory additions and/or something transformative. We have several prospects and leasing campaigns. And when we're ready to comment on specifics of a given program, we'll certainly do so. But exploration is a big way that we deliver value to shareholders.

The next question comes from Scott Hanold of RBC.

If I could return to the shareholder return discussion. I'm not sure if this is for Ann or Ezra, but -- can you give us a view of how you think about variable dividends? I know there's been a number of your peers who have "shelved" that concept. If your stock price does go at a point, do you still see variables having some value? And secondly, on shareholder returns, like is there the ability for you guys or desire for you guys to push to like, say, a 90% to 100% return versus the base 70% level like you've done in past quarters?

Scott, this is Ezra. Thanks for the question here. Yes, on the special dividend piece, that's still in our mix. What I would say is -- and we've been clear about this and go ahead and repeat it one more time, though, but the foundation of our cash return to shareholders is really that regular dividend. That's the one that we just love. sustainably growing that regular dividend. We think it sends a message of discipline to our investors. We think it shows the increasing confidence in the capital efficiency going forward. When we first started doing additional cash return 3.5, 4 years ago, we actually did lean in on the special dividends a bit more than buybacks.

We've always said that in general, we are pretty agnostic to how we return that additional cash to shareholders, but we are committed to, as far as buybacks go to being opportunistic. We've really shifted in the last few years, as you've kind of highlighted, I think really exactly just over 3 years now, I think. We've shown we've got a track record of consistently being in the market every day looking for opportunities is the way I would say it. So opportunistic, not necessarily just holding out for some sort of dramatic black swan event, but really looking at where can we make values -- value for the shareholders through the cycle. And I think we've done a great job with that. But we are very concerned or cognizant not to let this program become procyclical. And that's one reason why we have that 70% minimum return commitment.

I think going to a 90% to 100% return at these kind of elevated prices, I wouldn't say nothing is possible, but I'd also say that -- or nothing is impossible. But what I would heighten is that I think -- I think we'd like to build a little more cash on the balance sheet in this part of the up cycle and prepare ourselves for a potential future pullback in prices where we could continue our track record of positive countercyclic investment. Some of the things I mentioned in the call earlier, investment in the Janus processing plant, the Encino acquisitions, the bolt-on in the Eagle Ford, some of our marketing agreements. That's really when we create a significant amount of value for the shareholders is being able to have the balance sheet to kind of zig when maybe others are zagging.

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

Yes, Scott, this is Jeff. No, I mean, that's one thing our marketing team, I think they look to do is day in, day out, they're obviously looking for new opportunities, looking for new outlets and making sure they're diversifying the portfolio of markets that we have. So both domestically, whether we have emerging plays and we're in new areas, we're constantly adding in new markets, obviously, trying to minimize those differentials so we can maximize the netbacks there. And then the same thing on the international side. I mean, we've got great exposure with our LNG agreements, as we've talked about, getting close to 1 Bcf a day, but we continue to look for unique ways to be able to price that gas going offshore to try to take the volatility out and try to get a premium price with it.

So as we've talked about, obviously, our Cheniere agreement is kind of a sweetheart deal. So it's tough to get those kind of terms. But obviously, we're still in the market and looking at all the options there. And then the other thing is at the size of the company we are right now, we've got a lot of scale in all these basins and even international. And just with how low cost we are, we're able to keep operations moving and consistent activity, it really is an advantage to us in the negotiations, along with our balance sheet, which obviously, they know we're going to be resilient through these cycles, and we can lean on that, and that tends to help in the negotiations to give us a little better pricing. So yes, that's always what our goal is, is to continue to improve our overall price realizations and maximize those netbacks, and we'll continue to look for ways to do that.

Our next question comes from Phillip Jungwirth of BMO.

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

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

Okay. Great. And then you also mentioned the Eagle Ford bolt-on earlier in the prepared remarks. And yes, EOG, you have done a really good job here in improving returns in the Western Eagle Ford through efficiencies, long laterals, 4 milers. It's actually an area we haven't seen much industry consolidation. But just curious, based on the synergies you realized in the Utica, does this at all make you more encouraged about pursuing additional bolt-ons in the Eagle Ford or elsewhere just because obviously, you can bring superior operating and also marketing capabilities that can create value.

Thanks, Phillip. This is Ezra. It's a good question. I think we always knew before doing the Encino acquisition that we should have an advantage in a lot of areas, assets we might be able to improve upon with our operations, our cost structure and our marketing, like you had mentioned. The challenge has always been getting these deals done at a price that allows the all-in returns to really compete. Anytime you're buying anything with a lot of production, that weighs on the returns profile of the overall project. And so the upside really needs to be there to kind of counteract a production, let's call it, a 10% to 12% kind of bid-ask spread. So that's always been the challenge.

Now countercyclically, like you pointed out, last year, we were able to get a couple of deals done here. The first one was Encino, obviously, with a lot of production, but Keith just talked about a tremendous amount of upside. And we really got to prove to ourselves exactly what you're asking that scale, our knowledge base, our database from outside of a single basin and bringing data from other basins can add a tremendous amount of value. And we saw great margin expansion and great improvement on the well productivity side and as you pointed out, on the well cost side. The other one we did though was at Eagle Ford, and that was kind of a needle in a haystack really. It essentially had -- essentially 0 production really, very, very low production. And we were surrounding that, that acreage kind of fit in like a jigsaw puzzle piece. And so it was fantastic for us.

We immediately got the production that was there into some of our infrastructure. We immediately started to extend some laterals that we were drilling surrounding the acreage onto the acreage. And we very quickly actually moved in and have within this first year that we have had that bolt-on in our portfolio have already drilled a number of high-return wells on it. And so I think you're right, it's gone a long ways towards telling us that continuing countercyclically and focusing on returns is a winning strategy for us when it comes to either bolt-ons or potential deals that come with a little bit of production as well.

The next question comes from Doug Leggate of Wolfe Research.

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

Doug, this is Jeff. Yes, so the first thing I'd say with the actual productivity raise for the year, we did have a beat in the first quarter. So that's the first thing that I'd point to on that. And then obviously, other than that, really, it's just obviously reacting to what we're seeing out there from a price standpoint. We're just making very modest adjustments to activity schedule around the portfolio. And like we said, just shifting that investment from gas to oil. So what that really is going to do is we're just taking a little bit of capital out of Dorado. It's not a whole lot.

It's just going to drop them down to just less than a frac fleet. So they'll still have plenty of activity to where we can focus on the asset, continue to move it forward and progress it. The only thing is the exit rate now there in Dorado will drop a little bit. It will go from a Bcf target to just over 800 million a day. And with that, we actually do have a rig that's down there. It's going to go up and drill just a couple of DUCs in San Antonio actually. And then also, we're reallocating the rest of the capital to add 5 net completions in the Delaware Basin and then the 10 net there in the Utica, which it's very small and it's within rounding. I mean, really 5 wells in the Delaware, when you think about it, are just additions to a package. It's not even really any additional equipment.

And then in the Utica, it's very similar to how the rig has gotten out in front. It's just really a couple of packages of DUC inventory there. So -- and a lot of it, as I said, was really it is. It's due to the great performance that we've seen and the consistent efficiency gains has allowed us to be able to do that and do the raise on the whole year within the same CapEx of $6.5 billion. And as we stated, it will add 2,000 barrels on the year for oil and 6,000 barrels on the NGL side. So I think it's just -- we keep hitting on it, but it's one of the benefits to having this multi-basin portfolio. We obviously have multiple high-return assets across the company that all compete for capital, and it really gives us just a lot of flexibility to alter our plan real time, very quickly without much disturbance and we're able to really maximize that shareholder value through the cycles.

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

Yes, Doug, yes, this is Ezra. Those are good questions. So let's talk about the first one. We're not opposed. I want to say net debt 0 is a target for ours. But you clearly saw that we've been there before. I wouldn't mind getting there again. I think with the 70% minimum commitment that we have in place, it would be difficult to get there this year, but potentially in the next couple of years. But I do think that's one of the -- one of the things that when you think about EOG, just keep that in mind that we think having a pristine balance sheet is a competitive advantage. It allows you to move from a position of strength, and that includes cash on the balance sheet.

With regards to the dividend, yes, hopefully, the dividend yield will move the other way here pretty soon and get lower. But the way we think about our share repurchases, and this has been maybe a bit of a learning experience. It's straightforward math, straightforward enough that when you are buying back stock, that obviously reduces your absolute dividend commitment. But having been in the market now buying back stock for 3 years, we really have good experience with that. And we love it. I would say, going back to Scott's question before, maybe we're not quite as agnostic anymore on special dividends versus stock buybacks because of that. Because we do see the ongoing benefit and the correlation with our ability to continue to increase that regular dividend.

As you mentioned, the regular dividend or as we talked about, the dividend now is about -- it's $4.08 annualized per share. And so it's got a yield that is competitive across the broad market. And over the 3 years that we've been buying back stock, we've actually got a compound annual growth rate, and this is during a softer part of the cycle of about 9%. And so that's something we're proud of. It's something we continue to look forward to and discuss with the Board is that our dividend increases should reflect growth. They should reflect the margin expansion. They should really reflect the ongoing capital efficiency of the company. And then any share repurchases obviously help that as well.

The next question comes from Gabe Daoud of Truist.

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

Yes, Gabe, that's a good question. Yes, I would say we are a little bit more bullish going forward. I'm not -- it might be a little bit of semantics, but I think it's subtle, but it might be significant. I'm not sure if we would say the mid-cycle price has changed dramatically. The way I would frame it is that for the next few years, we think we've moved -- we're going to be in an environment above mid-cycle prices. I think historically, this is a cyclical business. When you look back at kind of 5, 10, 15-year runs, it's amazing, but WTI usually ends up right in that kind of mid- $60, $65 range. So the point of it now is that you're right, with inventory levels where they've gotten down to, it's going to take a number -- it's going to take quite a while to get inventory levels back up to the 5-year average.

And that would assume that barrels flow pretty easily through the Strait of Hormuz. I would assume that the committed SPR releases hit the market. And like we've said that investment in U.S. and non-OPEC is going to be above where it was when we entered in 2026. What does that mean for us? We put out a 3-year scenario at the beginning of this year. And it kind of contemplated an environment based on fundamentals where we were investing to grow the business on the oil side at about low single digits. If there was a real call going forward supported by fundamentals on shale, we could increase maybe to mid-single digits. But honestly, that low single-digit plan is a very, very compelling scenario.

Now it's not guidance. It is a scenario. But -- it delivers on just a conservative $60 to $80 WTI range, that 3-year scenario delivers 15% to 25% ROCE, $12 billion to $24 billion in free cash flow and a compound annual growth rate of free cash flow of 6-plus percent. And that's straight free cash flow, not per share. So any additional buybacks would obviously increase that. And the big takeaway, I think, is even at the same Strip price as the past 3 years, our go-forward scenario here would increase cumulative free cash flow by about 20% over the past 3 years. And so leaning in a little bit more aggressively into growth, not only does it need to be supported by fundamentals, but we also need to lean into an environment that you're not running into inflationary headwinds or anything like that.

We continue -- what's best is obviously increasing the inventory levels. What's best for the consumers for affordability of energy is to increase those inventory levels back up to the mid -- the 5-year average, but to do it at an appropriate cost. And so leaning in just to grow production, even though you're leaning into a higher cost environment, that's something where we need -- we will be -- you can consider us to be very thoughtful and deliberate before we did something like that.

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

I'd just like to say that we appreciate everyone's time today. Thank you to our shareholders for your support and special thanks to our employees for delivering another exceptional quarter.

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

Okay. We're going to get started with our next company. Next up, we've got EOG Resources. This has been an industry leader, kind of a bellwether for the group for several decades now, diversified portfolio, meaningful presence in several U.S. basins as well as an international portfolio as well. Presenting today on behalf of EOG is the COO, Jeff Leitzell. Jeff?

Well, thank you. I appreciate the introduction there. And as you said, my name is Jeff Leitzell. I'm the Executive Vice President and Chief Operating Officer of EOG. And we're going to run you through a little bit about the company here. We've got our earnings presentation. Obviously, we just had earnings here recently. A lot of great information on the company, talk a little bit about our plan and talk about our portfolio and some of the information associated with it.

So this first slide here really, this is our value proposition as a company. I mean our main focus is obviously sustainable value creation through the cycles. We don't chase commodity price. We want to make sure that we've got investments that have great returns through the cycle through multiple commodity prices. So it really has kind of these 4 pillars, I would say, our main focuses. The first one is capital discipline. We want to make sure that we're investing in the right project at the right time, and we're maximizing returns. We want to make sure that we maintain our pristine balance sheet, that we keep that healthy and that we're generating plenty of additional cash flow to where we can return that to shareholders. And you can see up there, we actually have a marker right now that's a minimum return to shareholders of 70% of our free cash flow. But you'll see throughout the presentation for the last 2 years, we've been right around 100%. And in this current environment, we plan on probably being pretty close to that 100% moving forward.

Second is operational excellence. It's basically doing what we say, making sure that we're executing, that we're improving the portfolio in each one of our assets day in and day out, that we have operational excellence. We continue to innovate. And then on top of that, what makes EOG unique is to make sure that we're exploring, looking for the next organic opportunity for the company to continue to improve the overall portfolio. Next, you can see sustainability. Obviously, we want to practice extremely safe operations. We want to be good stewards to the environment and obviously, great partners with our community. And then last but not least is culture. You'll hear culture a lot throughout this talk just because it's really what makes the company special. It's more decentralized culture. We're very non-bureaucratic. There's not a whole lot of red tape in it. People can get things done very, very quickly.

All of our people are business people first. What's very amazing about EOG is they're interdisciplinary. You might talk to a geologist and you might think they're an engineer or vice versa. And each one of them on their projects, they understand the decisions they make, not only how it affects just their personal asset, they understand how it flows through to the income statement, really affects the business because each one of them are business people first. And you'll see a lot of that throughout the slides. This is why we think EOG is an extremely compelling investment. It's like a tear sheet that we put in there to really kind of talk through EOG as a whole. So you can see up in the top left, the first one, we obviously have an extremely high-return inventory, both domestic and international, and it's got extreme long duration.

So the way we look at inventories, we've got about 12 billion barrels of total resource plus. And if you take that and you look at the economics of it at $55 oil, it's all greater than 100% direct after-tax rate of return. So extremely strong, strong portfolio. We obviously have a ton of experience in this. We've been operating unconventional for over 25 years, and we can really leverage that experience, both domestically in our operations and exploration and the same thing with international. We'll talk a little bit about international as we move, but we see a lot of opportunity on conventional because there really hasn't been a whole lot of exploitation of unconventional on the international front.

And then obviously, from an operations standpoint, we're a low-cost efficient operator. We really focus on improving operationally every single year and primarily through what I would say is sustainable efficiency gains, efficiency gains that can basically stand the test of time with the asset and be there for improvement the whole time. We also look for places that we can take control of the supply chain. So whether it's sand supply, whether it's water logistics, it could be cement services. We actually have EOG cement services. We have EOG motor programs, EOG Mud, anywhere that we can take control of the supply chain side of it, we feel like there's added efficiency and quite a bit of cost reduction. And you can see the performance we had in '25.

Now moving down to the bottom. Obviously, we want to make sure we've got durable cash flow. And you can see over the last 3 years, we've generated $15 billion in free cash flow. And you can see how that affects, obviously, the return on capital employed of the company, averaging 24% over the last 3 years. We're very, very focused on a sustainable regular dividend. We'll talk about it a little bit more in depth on another slide, but current dividend right now is $2.2 billion. That's $4.08 a share on an annual basis. And as I talked about before there, returning 100% of free cash flow back to shareholders. And then last but not least, just make sure that we're maintaining an industry-leading pristine balance sheet. And you can see currently right now, we're at 0.4x net debt to EBITDA. So extremely strong balance sheet, and we'll kind of walk through what we're focused on with the balance sheet here in a little bit.

For 2025, I mean, really, the summary of this slide is in 2025, we basically met or exceeded all of our operational or financial goals. You can see impressive financial results on the left-hand side, $5.5 billion of adjusted income, outstanding return on capital employed there, and then it flows over, obviously, to the free cash flow with $4.7 billion of free cash flow and 100% of that return to shareholders. And really, what I'd point you to is down on the bottom right, strengthening the portfolio. 2025, I would say, was truly a transformational year for EOG. We really had 3 things take place. We had the acquisition of Encino, as you guys know, for $5.6 billion that expanded our Utica footprint by 1.1 million acres, and it immediately moved that play to a foundational play where it's free cash flow positive. So we're going to have quite a bit of additional activity there.

We were awarded the first ever onshore concession in the UAE for unconventional oil. This is an area that has penetration points and a lot of data. So really, we just got to get in and operationally execute. And then we also executed on a JV partnership with BAPCO in Bahrain on an onshore unconventional gas play that's very similar, plenty of penetration points and data, a very exciting opportunity that we think we can bring our technology and knowledge to and really extract a lot of value out of.

Taking a look quickly at our plan. So how we look at plans is, as I talked about in the first slide, we really start with capital discipline. We want to look and see where every one of our assets is in the portfolio in the life cycle and make sure they're improving and they're generating the target returns that we're looking for. Then after that, we'll take the macro environment and considerations and make sure that the market needs the commodity based off where we're at in the cycle. And what we ended up doing with this plan is based off current environment right now, we're actually holding volumes flat to Q4 of 2025. And what that rolls up to is, as you can see here, $6.5 billion capital budget. It's 5% increase year-over-year in oil. And what that takes into account is obviously Encino acquisition, which closed in August of last year. So we have 5 months in last year of Encino and then a full year this year.

And total volume-wise, that's 13% year-over-year on a BOE basis. There's substantial free cash flow generation, as you can see with that. And some of the plan highlights, I'd say, is extremely capital-efficient plan. Our breakevens on it, if you look for the CapEx is about $40 WTI. If you take the CapEx and regular dividend into consideration, it's $50. And really, what we're doing with this year's program is the first thing is we're balancing the activity between our 3 foundational oil assets, which is the Delaware Basin, Eagle Ford and the Utica now, our new foundational asset. And then we have some additional investment to continue to grow our very prolific Dorado gas play down in South Texas. And then we have additional investment, obviously, in our international assets, which would be Trinidad and our new entries into the GCC.

We did update our 3-year scenario. So we came out with this 3 years ago. And obviously, it's been 3 years. And then also with the Encino acquisition, we wanted to kind of dust this off for you. This is not guidance by any means. This is not our plan. This just kind of gives you an idea of the resiliency of the cash flow of the company moving forward. You can see over on the left-hand side, outstanding ROCE and free cash flow, cash flow growth and cash -- free cash flow growth at varying commodity prices there. And when you look at it, basically, this is going to be kind of a low single-digit oil growth, mid-single-digit BOE growth. It's got a reinvestment rate of less than 60%, and we have no improvement in the company here.

There's no improvement in overall cost, efficiency, production whatsoever. It's basically maintaining the status quo. And you can see we've got a couple of different scenarios there at $55 and $70, but I really want to turn your attention to the right-hand side where you see the last 3 years at the actual price was about $15 billion. Well, with this scenario, if you move forward that exact same price for the next 3 years, we have about a 20% increase in free cash flow to $18 million. So very substantial and continued growth of free cash flow for the company.

All right. This is a quick look at our multi-basin portfolio, which we think is a huge benefit. You'll hear me say this multiple times, but we have 7 different divisions domestically, multiple divisions internationally. And really, what each one is, is they're a separate business unit. So each one is focused on their operations of their assets, continuing to improve that. They're focused. Each one has an exploration team within their division. So they are strategically exploring for a next organic opportunity within their asset there. And what that really does is they're almost like separate laboratories. So as one of them learn something new, they don't just keep it in-house. They go ahead and share it with each one of the other divisions. So really, you have 7 different learning areas here domestically that really accelerates our knowledge, and we're able to share that and move along each asset that much quicker.

So especially when we find a new asset or an emerging division or an exploration play, we're able to take all of our best practices from all of these divisions across and apply it directly there. So looking at the portfolio, we really started as an unconventional operator in the Barnett in the gas play. From there, we kind of moved up to the Williston Basin and the Bakken and had a large position there and have been active there ever since. Next, we discovered the Eagle Ford down in South Texas. We were able to and very lucky to acquire the majority of the acreage to the core in the Eagle Ford, which has been a very prolific asset for us. And then moving to the Delaware and the Powder River Basin, we had nice acreage holds there. But in 2016, we went ahead and we acquired Yates and greatly increased our overall footprint in both of those basins and really pushed them forward.

And then the last 2 domestic that I'll touch on here is obviously our Utica play, which I've talked about with the Encino acquisition. We are the largest producer of oil and have the largest footprint up in Ohio, and we are focused on the volatile oil window up there. And then we have our South Texas Dorado gas play, 21 Tcf down there, very close to the market center. We feel like it's going to be a huge value to the company as we move forward from a gas aspect. And then over on the right-hand side, we have our international assets, Trinidad Tobago, shallow offshore gas play. We've been there for over 30 years, great returns. We're able to sell to premium markets there in Trinidad, Tobago. And then our 2 new entries, we've got Bahrain, which -- that's the onshore gas unconventional asset and the UAE, which that's the onshore oil unconventional asset, 900,000 acres.

And obviously, these 2 are very topical at this point. We started exploration in the fourth quarter of last year, planning on results, Q2. Obviously, with everything happening in the events over there, I'm happy to say we had procedures and plans in place. Activity and everything is secure, all of our people are safe, and we're just monitoring the situation at this point. But excited about these assets once, obviously, things calm down over there in the Middle East.

Moving on. Really on this slide, I just want to hit. We've talked about the multi-basin portfolio of long-duration, high-return inventory. Really, what I want to hit on here is just how good the returns on that inventory is. So on the chart on the right there, you can see bottom cycle, what we call bottom cycle pricing, $45 oil and $2.50 gas. Our full portfolio averages around 55% or greater direct after-tax rate of return. And you can see what happens with that with commodity prices, just continues to improve exponentially as you improve the commodity price. And that's what we like to do with our portfolios. We like to pressure test it against very severe environments just because we know it's a very cyclic environment. We want something that's able to, like we said, generate solid returns through those cycles.

When you take that and you roll that up from a returns aspect from a company standpoint, return on capital employed, outstanding over the last 5 years. You can see EOG here in the dark blue versus our peer average, averaging close to 20%, if not higher for EOG and outpacing the overall peer average. So great results from an ROCE basis from a company. And then you look at that and you roll it forward into our cash flow priorities as a company. So first and foremost, our #1 cash flow priority is our regular dividend, as I talked about, $2.2 billion or $4.08 a share. We really think that a sustainable growing dividend is truly the hallmark and foundation of a really great company.

Obviously, maintaining the pristine balance sheet, as we talked about. Balance sheet is in great shape right now, but we do have a marker out there, and we have that at bottom cycle pricing that we want to maintain less than 1x total debt to EBITDA, which is obviously an extremely healthy balance sheet. We obviously have the capital investment in the company, both through our activity and opportunistic entries and bolt-ons and other marketing opportunities that we can have for the company. And then last but not least, we obviously have cash returns to shareholders outside of the regular dividend, which we'll talk about a little bit here in a second.

We have done special dividends in the past, but primarily here most recently in the last couple of years, we've really focused on buybacks. And I think you can plan on in the current environment, we'll focus primarily on buybacks moving forward and lean in that direction.

So for the dividend, this just really shows the history of it. We've got 28 years of sustainable and growing dividend, where we've never cut or suspended it in that whole time period. So pretty impressive growth since 1999. And you can see there really a lot of growth in the last 5 years from a dividend aspect, where we jumped up quite a bit in '22 after the pandemic and then continue to grow it up to where we're at, at the $4.08. And I think this just shows you the confidence that we have in the portfolio and really the resiliency that we have. We take for this dividend too, every single year before we increase it, we run it through numerous different scenarios, both market scenarios and portfolio development scenarios to make sure that it is sustainable. And that even if we do go into a downturn that there's no reason that we have to suspend or cut this dividend. So it is pressure tested, and it is very, very resilient.

And then we've talked about the cash flow returns to shareholders. I mean you can see what we've done over the last 3 years here as a company, significant returns there. You can see the regular dividend. We did do some special dividends back in 2023. But like I said, we've been focused more on the share repurchases, $6.7 billion in the last 3 years, and that's reducing our outstanding share count by about 10%. So substantial move there as far as buying back shares. And then you can see the breakdown down in the bottom, as I talked about, year-over-year, how that's been distributed between regular dividend, special dividend and share buyback. And then on the right-hand side, you can just see from an actual cash returns as a percentage of market cap, how we rank against the peers, obviously, being a peer leader there in cash returns.

Our pristine balance sheet. I'm proud to say we think we have one of the industry's best balance sheets right now. Like I said, it's 0.4x net debt to EBITDA. You can see peer-leading from that aspect. And I think really the point that I'd like to get across on this slide is the balance sheet is in great shape. We really don't need to put a lot of cash in this current environment on the balance sheet. We've got very robust cash flows. And I think our primary focus moving forward is to be opportunistic for the company wherever we may, whether that's opportunistic bolt-ons, marketing agreements, other opportunities for the company and then obviously, additional cash returns to shareholders to really balance out and be able to support that 100% return of cash to shareholders as we've talked about. And you can see the last couple of years, we've been right around that marker.

Okay. So I'll get into the assets here for a second. I mean this is really where the rubber meets the road, and this is really where our culture comes into play. As I said, that decentralized culture, the sharing, the innovative qualities being business people first. As I said, each one of these divisions is focused on their own asset. They've got boots on the ground. They can get to the asset every single day. So you really help -- that helps out see the improvement in the asset just from an efficiency standpoint and pushing forward innovation and then also from an overall exploration aspect. Instead of just having one exploration team and headquarters, each one of our divisions has an exploration team that is focused on organically growing.

So here, first, starting in the Delaware, we've made outstanding progress in the Delaware. And I know the Delaware has been very, very topical for us. It's been in the news for productivity reduction year-over-year. And what I'd say is that was completely strategic, and it was by plan and by design. So what we've done is, you can see here, we've increased our lateral lengths like much of industry a lot over the last 3 years, 30%. Well, what that equates to is we've really lowered the overall cost basis there in the Delaware. The well costs are down 20%, reducing cash costs. And what that does is it's given us the opportunity to where there were certain targets that didn't meet our very stringent bottom cycle hurdle rate, but now it does. And it goes up above that, and it's very additive to it. Not only that, what it does is it balances out our actual payout and improves the payout of it. It's improving the overall margins of it. And really, we're starting to look at the value and an NPV per acre out there and make sure we're extracting the maximum amount of value and improving our recovery per acre.

And where that puts us now is we're well over 20 unique targets across all of our Delaware acreage with just outstanding improvement there. And as far as the improvement, you can see here 4% improvement year-over-year in capital efficiency on that. And we feel very, very confident that now that we've set in this new actual development program, well productivity in the Permian will be consistent moving forward with this development program unless we have to have another step change where we're able to add more value because of cost reduction, which we will keep you guys apprised and abreast of that. But as far as our inventory, we did come out and we talked about it on the call that we can go at our current pace right now in the Delaware of over 300 wells, maintain the same economics, the same free cash flow and success for 10 years plus with the inventory we have out there. So very, very robust. And obviously, with adding in these additional targets, that just helps the inventory there in the Delaware.

This is just quick. I'll breeze over this. This is Rystad data over the last 3 years. You can see how we kind of stack up operationally and from an efficiency aspect and then how that rolls through versus the peers from a breakeven. So a leader as we've been there in the Permian.

Moving up to our Utica asset. Obviously, this is one that's a premier asset for us now, a new foundational one. We had the Encino acquisition last year, as we talked about. When we did announce that acquisition, we had put a target out there of about $150 million of synergies in the first year. And I'm happy to say we've reached that target early in about 5 or 6 months. So the majority of that, I would say, is obviously just in the well cost side and the efficiency side. You can see where Encino was at $750 a foot. EOG was at $650 or below a foot. And combined now after 6 months into the actual acquisition, we're pro forma under $600 a foot there. So just outstanding results across the board.

You see on the bottom, just some of the efficiencies from an overall operational aspect that we've been able to enjoy through the acquisition and improving the overall asset over the last 3 years. And this has really become one of those foundational assets for us with a lot, a lot of running room. You're going to see we're shifting, almost doubling the activity there. We'll be running 3 rigs and 3 frac fleets. And this will really be one of the big growth arms for the company as we move forward. So extremely excited about the Utica, and I think we still have a lot more upside even just with the acquisition and synergies as we move forward.

Next, we've got our Eagle Ford play. This is just one of those amazing assets that just keeps on giving after 15-plus years of development, where we've moved from -- the majority of our development was in the East where it's much more prolific, I would say, rock to the west through operational advancements through technology, through longer laterals, 15-plus years later, we're actually getting better economic results now than we did back at the beginning of the play. And you can see still improving our overall efficiencies, our capital efficiency there. We've got great operational performance even after the 15-plus years. So we continue to improve there. And you can see how that flows through to the breakeven price versus our peers there in the Eagle Ford being a leader and plan on continuing being a leader there.

And then moving down to South Texas to our Dorado dry gas play in Webb County. This is a 21 Tcf resource. That is 21 Tcf, so it's massive. It's very, very prolific wells. We keep them choke back. We bring them on over 20 million a day. We've just made outstanding progress down there. Like a lot of the other plays that I showed you in the portfolio, you can see we've rapidly dropped our costs there. We've optimized our operational efficiencies. And on top of that, we've actually just last year alone, through unique designs within our wellbore and our completions, we increased the overall productivity per foot, which is a recovery basis in this play 13%. So continuing to improve it there, and we still got a lot of upside. It's very early in its days. We exited last year at 750 million a day, and the plan for 2026 is to exit at 1 Bcf a day. And it is, we think, the lowest cost gas in the U.S.

We've got it currently with a breakeven price per Mcf of $1.40. And we're so excited in the play. We actually have installed a 100-mile 36-inch pipeline that goes from the center of the field, completely EOG-owned over to Agua Dulce. It has a capacity of 1 Bcf currently, and it's easily expandable up to 1.5-plus Bcf just by adding on some booster compression along the line for minimum capital, and that's completely controlled by EOG. So that allows us to get access over into the market center on the Gulf Coast and also take advantage of our LNG contracts, which we'll be able to talk about here in a minute.

So how does that all roll up? I mean, not just even in Dorado, but from a full portfolio's perspective, we're looking at to make sure we've got an extremely diverse, flexible marketing strategy, and we're really not worried anymore about flow assurance. It's not about getting the molecules to market. It's about having numerous markets to be able to select it and maximize our overall netbacks of each one of the molecules. And you can see that on this price realization chart versus our peers. And we've always prided ourselves of outpacing what the average is to our peers in the market. And that is a huge priority to us to continue to make sure that we optimize our markets and that we're maximizing our netbacks on every single molecule.

The great thing about this is it really has become a big part of technology, and we have control rooms in each one of our assets to where we're able to control where each molecule goes, move it from market to market as those markets move and make sure, like I said, we are maximizing that netback.

And then quickly, these are the gas sales agreements that we have over on the coast from an LNG aspect. What I'd say about these is they're not tied to any specific play by any means. We can move any kind of gas to them. But you can see over on the right-hand side, we currently right now of that 420,000 MMBtu wedge, we're producing 280,000 MMBtu, and that is linked to either JKM or Henry Hub on a monthly basis. We're able to elect that. So you can obviously imagine in recent years, we've been obviously electing to JKM. So that was really a sweetheart deal. The additional 140,000 of that agreement comes on here later this year, so we'll be at full capacity there. And then we're also -- the other stacked bar on top of that, we're currently producing 300,000 MMBtu that's directly linked to Henry Hub there on the offshore.

And then as we move into 2027, we have a Vitol agreement that's going to be coming online for 140,000 MMBtu, which is Brent-linked to take some of the volatility out of gas price. And then there's additional 40,000 that's either Brent-linked or linked to U.S. Gulf Coast.

And then moving on to the last couple of slides here. As we talked about, sustainability, it's really core to our DNA. What I'd say about this is we've had a lot of success over the last handful of years. We did have targets set in 2020 with a 5-year goal. We achieved that goal 2 years early. So we did come out and set new targets. You can see on the left-hand side. Obviously, reduce GHG emission intensity, maintain near zero methane emissions there and then obviously maintain our World Bank zero routine flaring across the company to make sure we're good stewards. And you can kind of see our strategy on the right-hand side. The big thing I'll point out there and the easiest thing is reduce.

Don't flare, make sure you get engineering controls in, engineer out any kind of venting or any kind of emissions from that aspect. And how we look at this is it's not only just being good stewards of the environment, but each one of these molecules, I mean, it's revenue. Why would we not want to capture that and go ahead and put it downstream to markets because a lot of the projects from an engineering aspect that you're able to apply here actually have returns to it. So this is a big piece of who we are as a company.

And then lastly, as we finish up here, this is the last slide. As I said, everything kind of really all rolls up to the culture of the company. It really has to do with, as I said, each one of our people, they're business people first. They understand how they're affecting the business and how each decision is affecting the business. They're focused on the actual financials, the returns. They really utilize our decentralized culture, which is unique within the industry. We're one of the only companies that actually has divisions in each one of our assets. So we're close and proximal to it, and we can be hands on. Every one of our people is multidisciplinary. We really promote them, not just focusing on their discipline, but understanding the full cycle of jobs and technology we have in our industry, making sure they continue to innovate and that they're extremely responsible from a sustainability aspect.

So with that, go ahead and hand it back over to John to see if we have any questions.

[indiscernible]

We prefer to invest in returns. This is -- that's what I would say. So we're not really -- we don't lean one way or the other. That's why we've got very stringent markers where at bottom cycle pricing, $45 oil, $2.50 gas, the minimum return that we look for is 30% direct after-tax rate of return at that bottom cycle pricing. So no matter if you're gas, no matter if you're oil, we're pretty agnostic to it. We're just about returns, and that's how we look at it. Obviously, as you look at where we stand right now with oil and gas, I mean, oil, we're obviously getting a little bit of a bump here with the unfortunate activities over in the Middle East.

We think it's going to be probably short-lived and really what we need to do is we need to see how spare capacity flows through OPEC+ and where that actually sits. And once that actually flows through the market at the end of the year, and our personal view is we think that demand is going to be very strong and the spare capacity is probably not quite as high as what is thought of out there. So we think we'll have pretty robust pricing as we move into the end of the year and into 2027.

And then on natural gas, obviously, we're pretty positive on natural gas for the foreseeable future. With all the additional demand, we see about a 3% to 5% compounded annual growth rate in demand over the next handful of years to 2030. And obviously, with all the LNG coming on, we think that there's going to be quite a bit of a support there, both domestically and international for the molecules.

With your 100% return of free cash flow to shareholders [indiscernible].

As far as -- I mean, when do we buy back and when do we not to make sure we're maximizing value of the buybacks?

I mean generally, not buy stock, increase your buyback and stock [indiscernible]

Yes. I think it's a great -- well, the one thing I'd say is what's the value of the company and where do we think the intrinsic value of it and stock price is. And I will say this wholeheartedly, we think we're undervalued. We've been undervalued for a while, extremely undervalued, I'd say, for the last couple of years. So we see so much value in the company right now based off how strong the portfolio and the inventory is. And then with some of the new opportunities that we've entered into, we see what the potential runway on those are and what they can mean to the company. So at this point right now, I mean, even with a little bit of surge in pricing, I'd say we still think we're undervalued and we're still at an attractive price.

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

Good morning, and thank you for joining us for the EOG Resources Fourth Quarter 2025 Earnings Conference Call. I'm Pearce Hammond, Vice President, Investor Relations. .

An updated investor presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings.

This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations section of EOG's website. In addition, any reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines.

Participating on the call this morning are Ezra Yacob, Chairman and Chief Executive Officer; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Chief Financial Officer; and Keith Trasko, Senior Vice President, Exploration and Production. Here's Ezra.

Thanks, Pearce. Good morning, and thank you for joining us. 2025 was a remarkable year for EOG. Overall, our year was characterized by disciplined capital allocation, strong execution across our operations and robust free cash flow generation. We didn't just meet the targets set forth in our operational and capital plan, we exceeded them while expanding our business both domestically and internationally, laying a foundation for the future.

We surpassed our original oil and total volume targets while delivering in-line capital expenditures. We continue driving down well costs through sustainable operating efficiency gains and our differentiated marketing strategy delivered peer-leading U.S. price realizations which combined with lower cash operating costs, helped strengthen margins.

Beyond extending our track record for excellent operational execution, 2025 was transformational. We completed the strategic Encino acquisition, entered exciting international exploration opportunities in the UAE and Bahrain and brought online [indiscernible] [ J&S ] gas processing plant in the Delaware Basin. We also continue leading on sustainability, publishing new emissions targets after achieving our prior targets ahead of schedule.

Each of these developments fundamentally improves our business and better positions EOG going forward as being among the highest return and lowest cost producers with strong environmental performance. Operational excellence in 2025 drove outstanding financial results and top-tier cash returns to shareholders. We generated $4.7 billion in free cash flow and returned 100% to shareholders through our regular dividend, which increased by 8% and $2.5 billion in share repurchases.

Let me put our 2025 financial performance on a broader perspective. EOG has generated annual free cash flow every year since 2016. We have never cut nor suspended our dividend in 28 years. Further, over the past 3 years, we've generated $15 billion in free cash flow and returned $14 billion to shareholders while generating an average 24% return on capital employed.

We've done this all while maintaining a pristine balance sheet. This isn't luck. It's the result of consistent execution of our resilient business model and represents a fundamental differentiator versus peers. And we expect more of the same in 2026. Modest oil production growth as we maintain capital discipline, further integration and optimization of the Utica acquisition and continued natural gas growth into emerging North American demand.

Looking ahead, we have a disciplined plan for 2026. Our strategy prioritizes activity in the Delaware Basin, the Utica and the Eagle Ford while increasing activity in Dorado alongside continued international investment. Our Utica asset provides a compelling opportunity for value creation as we continue to identify additional upside from the Encino acquisition as well as advancing our technical understanding of the play. And in the Delaware Basin, after adjusting our development strategy in 2025, we expect consistent well performance year-over-year.

At guidance midpoints, our 2026 plan is expected to generate approximately $4.5 billion in free cash flow using strip pricing delivering growth, exploration, a competitive regular dividend and excess cash returns. Our breakeven price to cover the 2026 capital program and regular dividend is $50 WTI. Overall, the 2026 capital program balances both short and long-term free cash flow generation while supporting future growth and maintaining our pristine balance sheet.

Our 2026 plan is contemplated in our updated 3-year scenario. The scenario reflects modest oil production growth aligned with current macro expectations. It maintains our current cost structure despite our persistent track record of driving costs lower through efficiency gains. Finally, the scenario was underpinned by our deep inventory of high-return assets across our multi-basin portfolio. Using WTI price ranges of $55 to $70 per barrel from 2026 through 2028, the updated 3-year scenario delivers 5% cash flow and greater than 6% free cash flow compound annual growth rates, generating cumulative free cash flow of $10 billion to $18 billion and earning robust double-digit returns on capital employed.

This updated 3-year scenario demonstrates how EOG's relentless focus on returns, our diverse multi-basin portfolio and industry-leading exploration capabilities provide clear visibility to sustain high returns and durable free cash flow generation for years to come. Overall, the 3-year scenario delivers approximately 20% higher free cash flow in 2026 through 2028 than the actual results for the prior 3-year period, assuming the same price deck.

On commodity fundamentals, we expect total crude and product inventories to continue building over the next few quarters. However, increasing global demand, geopolitical factors and stockpiling of petroleum reserves are providing price support. Beyond near-term dynamics, we remain constructive on medium to long-term oil prices being driven by steady demand growth and the need for additional supply. Importantly, global spare capacity is declining, which should provide an oil price floor while geopolitical events will continue to drive upside price volatility.

On natural gas, our outlook remains positive. U.S. natural gas enjoys 2 structural bullish drivers. Record LNG feed gas demand and growing electricity demand. We expect U.S. gas demand to grow at a 3% to 5% compound annual growth rate through the end of this decade. Our investments in building a premier gas business positions EOG to deliver supply into these expanding markets. We believe our premium gas business is an underappreciated asset, providing exposure to growing demand and with access to premium markets from geographically diverse sources.

EOG's value proposition is clear. We're guided by our strategic priorities, capital discipline, operational excellence, sustainability and culture. Our 2025 results demonstrate consistent execution across our premier multi-basin portfolio, while our cash return performance reflects our unwavering commitment to disciplined value creation through the cycles. EOG is better positioned than ever to execute on our value proposition and create shareholder value.

Now here's Ann with a detailed review of our financial performance.

Thank you, Ezra. EOG's financial strategy remains steadfast. Invest capital in a disciplined manner, pay a sustainable and growing regular dividend, returned significant cash to shareholders and maintain a pristine balance sheet. The fourth quarter 2025 exemplifies this strategy in action. We generated adjusted earnings per share of $2.27 and adjusted cash flow from operations per share of $4.86 yielding free cash flow of nearly $1 billion. .

For 2025, EOG reported adjusted net income of $5.5 billion or $10.16 per share and free cash flow of $4.7 billion. For 2025, we delivered a 19% return on capital employed, maintaining our peer-leading ROCE. We continue to deliver on our commitment to return cash to shareholders. During the fourth quarter, we returned $1.2 billion to shareholders, $550 million through our robust regular dividend and $675 million in share repurchases.

For the full year, we paid $2.2 billion in regular dividends or $3.95 per share, representing an 8% increase over 2024 and we repurchased $2.5 billion in shares. Our 2025 cash return was 8.2% of our market cap, which led our peers.

[indiscernible] returns through the cycles. Our peer-leading balance sheet provides an outstanding competitive advantage. We ended 2025 with $3.4 billion in cash and $7.9 billion in long-term debt. Combined with our undrawn $3 billion revolver, total liquidity stands at approximately $6.4 billion.

Our leverage target of total debt at less than 1x EBITDA at bottom cycle prices remains among the most stringent in the energy sector providing both downside protection and the flexibility to invest strategically through cycles. Finally, we increased proved reserves by 16% to 5.5 billion barrels of oil equivalent continuing our long track record of reserve growth.

Total production. Turning to 2026. We expect capital spending of $6.5 billion at the midpoint of guidance. At current strip prices and using guidance midpoints, this plan generates $4.5 billion in free cash flow. In the current environment, we anticipate returning 90% to 100% of annual free cash flow to shareholders, consistent with recent years.

In summary, EOG delivered another outstanding year. We strengthened our portfolio, maintained a pristine balance sheet and position the company for sustainable value creation through commodity cycles. With that, I'll turn it over to Jeff for our operating results.

Thanks, Ann. I want to start by recognizing the exceptional dedication of the entire EOG team. consistent, safe and outstanding execution is what converts operational strength into shareholder value, and 2025 demonstrated that. Our teams met or exceeded expectations on nearly every operational metric. Production volumes outperformed guidance, driven largely by stronger performance in our foundational plays.

While our disciplined capital investment remained in line with expectations, delivering strong free cash flow. Let me highlight several accomplishments throughout 2025 that have helped position EOG for long-term success. First, we made significant strides in lateral length optimization. Longer laterals means fewer vertical wellbores to drill, more productive time, both on surface and downhole reducing surface footprint and improving capital efficiency.

In addition, EOG's internal drilling motor program acts as a force multiplier on these longer laterals, improving downhole drilling performance and giving us the confidence to continue extending laterals across our portfolio. We are focused on drilling 2- to 3-mile laterals in the Delaware Basin and 3 to 4-mile laterals in the Utica and Eagle Ford place.

Second, extended laterals and sustainable efficiency improvements led to well cost reductions of 7% in 2025. Our focus on sustainable efficiency gains for drilling and completion operations creates meaningful value because they compound over time, leading to significant cost savings through the development of an asset. And third, cash operating costs came in under target, led by a meaningful reduction in LOE due in part to our proprietary production optimizers program, which leverages machine learning to optimize base production, delivering better run time and lower cost across the portfolio.

Looking ahead, 2026 is positioned to be an outstanding year for EOG as we build on the strong momentum established in 2025. Given the macro environment, we're keeping oil production flat with fourth quarter 2025 levels, which results in annual oil production growth of 5% and total production growth of 13%. We can deliver this disciplined plan for a capital budget of $6.5 billion.

Throughout the year, we plan to complete 585 net wells across our multi-basin portfolio of high-return inventory with the majority of the capital being allocated to our foundational assets, the Delaware Basin, Utica, Eagle Ford and our newest foundational asset, Dorado. We will also continue investment across our international portfolio. Capital cadence and activity should be relatively consistent through the year, with a roughly even capital split between the first and second half and activity averaging approximately 24 rigs and 10 completion crews.

Looking at the service cost environment, despite lower industry activity in the second half of 2025, we're seeing a relatively stable market for high-spec equipment with minimal cost reductions. Support services have shown some softening, and we'll continue monitoring the market for savings opportunities through 2026. We've locked in approximately 45% of our total well costs this year, giving us flexibility to capture any additional market softening.

For 2026, we're targeting a low single-digit reduction in well costs driven by sustainable efficiency gains. In the Delaware, our team has consistently delivered innovations, including our EOG motor program, Super Zipper operations, high-intensity completions and production optimizers. From 2023 to 2025, we increased lateral lengths by nearly 30%, while reducing well cost by approximately 20%. We have also strategically invested in infrastructure, including facilities, gathering systems, water transfer stations and the Janus gas processing plant, all of which deliver lower operating costs that complement our well cost reductions.

Over the past few years, we have fundamentally improved the cost structure of our Delaware Basin assets. Because of this, our development program now includes additional zones that previously did not meet our stringent return hurdles. While per well productivity declined last year as we targeted these incremental opportunities, our economics did not. Our 2025 Delaware program continues to deliver over 100% direct after-tax returns at $55 WTI, while improving capital efficiency by 4%.

For 2026, we expect consistent year-over-year well productivity and strong economic performance while averaging 13 rigs and 4 completion crews in the Delaware. In the Utica, the Encino integration is ahead of schedule, has exceeded expectations and remains a significant focus for 2026. We achieved our $150 million synergy target ahead of our original 1-year time line from close, and we continue capturing additional synergy opportunities.

We have achieved several operational wins with the Encino asset since closing the acquisition in August. We've increased the drilled feet per day by over 35%. EOG scale and purchasing power has reduced casing cost over 30%. We've increased the completed feet per day over 10%, and our team has reduced on-site facility costs by 20%. These achievements has helped us to reduce our well cost below $600 a foot by year-end of 2025.

In addition, we're planning to have in-basin self-source [indiscernible] in Ohio by the end of the year, which should further reduce completion costs. For 2026, we expect to run 3 rigs and 3 completion crews completing 85 net wells. Our foundational Utica asset is positioned for continued improvement as we build upon the significant cost reductions achieved over the past few years.

In the Eagle Ford, efficiency gains continued to improve economics. From 2023 to 2025, we increased drilled feet per day by 5% while boosting completed lateral feet per day by 30%, driving a 15% reduction in well cost. Last year, we extended lateral lengths highlighted by the record 24,000-foot lateral on the Whistler E5H. For 2026, we expect to run 4 rigs and 1 completion crew, completing 115 net wells while continuing to leverage technology and efficiency gains.

Turning to Dorado. We've made outstanding progress over the past few years and now have transitioned this world-class gas asset to our newest foundational asset. To be a foundational asset, the play must meet or exceed our high return hurdle, have significant running room, have a consistent level of activity, which supports a full-time completions crew and generate free cash flow.

Dorado will meet these criteria this year and will stand beside our other foundational assets, the Delaware Basin, Utica and Eagle Ford. In 2025, we met our exit gross production target of 750 million cubic feet per day and are targeting an exit rate of 1 Bcf per day gross production in 2026. We significantly lowered well cost to approximately $750 per foot through operational efficiencies.

From 2023 to 2025, we increased drilled feet per day by 30% and completed lateral feet per day by 20%. With a low breakeven price of $1.40 per Mcf, Dorado is exceptionally well positioned to serve our growing LNG gas supply contracts and Gulf Coast gas demand. We'll run 2 rigs there this year and 1 completion crew, which will complete 40 net wells.

Our Gulf states exploration programs are moving forward, and the teams are making exciting progress. We commenced operations in Bahrain and the UAE in the second half of 2025, and we'll continue to test and delineate these plays throughout 2026. We anticipate having initial well results in the second quarter of this year. These opportunities leverage our technical expertise and extensive data set from thousands of unconventional wells across diverse plays, prime examples of EOG's commitment to organically expanding inventory through exploration.

In closing, our 2025 performance demonstrates the strength of our multi-basin portfolio and operational excellence. As we execute our 2026 program, we're confident in our ability to deliver consistent results, maintain capital discipline and generate strong returns for shareholders across all commodity price environments. With that, I'll turn it back to Ezra.

Thanks, Jeff. As we close, I want to highlight why EOG represents a compelling investment opportunity and how we're positioned to deliver sustained shareholder value. First, our asset base differentiates EOG versus peers, with approximately 12 billion barrels of equivalents of high-return, long-duration resources, we have diversified exposure across North American liquids, North American natural gas and international conventional and unconventional. .

This creates multiple pathways for value creation as each of these markets grows over the medium and long term. Second, our unconventional and exploration capabilities are a long-time hallmark of EOG. This core competency doesn't just unlock significant upside in our current inventory, it allows us to build future inventory in a low-cost, high-return manner. Third, we're a low-cost, efficient operator with deep technical expertise.

Our relentless focus on innovation and drilling and completion techniques continues to drive our cost structure lower. This reflects our decentralized model that effectively creates a portfolio of pure-play companies that can leverage knowledge and expertise across the entire company. Fourth, our disciplined capital allocation framework drives superior financial performance, generates robust free cash flow and delivers peer-leading returns on capital employed.

Finally, we remain committed to returning cash to shareholders through our regular dividend and opportunistic share buybacks and our peer-leading balance sheet provides both protection and opportunity. We have the financial capacity and flexibility to invest opportunistically through any cycle. Thank you for your continued interest in EOG. We'll now open the line for questions.

[Operator Instructions] Our first question today is from Neil Mehta with Goldman Sachs & Company.

Thanks for taking the time. Ezra, I want to start off on the composition of the wells this year and the activity. And year-over-year, there is a slowdown in the Delaware. I think you're going from 390 to closer to 300 in terms of wells that you're going to attack and it looks like you're picking up in the Utica. So can you just talk a little bit about the composition, how do you think about the optimal level of activity in the Permian particular and the composition of activity over the course of the year?

Yes, Neil. This is Ezra. It's a great question. This year, the plan really takes a step towards optimizing investment across our high-return foundational plays. As you recall, we're really seeing pretty similar returns across all of our foundational plays now. Specific to the Delaware Basin, the activity level really optimizes utilization of existing infrastructure across our acreage position and that really helps support better capital efficiency.

We expect consistent Delaware Basin performance going forward. As Jeff talked about, our strategic shift and development strategy in '25 has been an outgrowth of our dramatic cost savings the last few years, combined with investment in that infrastructure to help lower operating costs. The cost savings have allowed us to capture some of these additional landing zones that exceed our economic hurdle rates.

And so we're now actively co-developing many of these targets. Some of the lower -- some of the targets have lower productivity per foot, some have different GORs. But each, as Jeff highlighted, is delivering the high returns that our shareholders have come to expect. And we expect the consistent well results you've seen quarter-over-quarter throughout 2025 to really continue through '26.

And really through the entire 3-year scenario that highlights the strong returns and increasing free cash flow going forward. So at this year's activity levels in the Delaware Basin, we expect to deliver relatively flat production to Q4 2025, similar to the company level. Maybe I think it's 3,000 to 5,000 barrels a day less due to really outperformance in the fourth quarter there in 2025 by the Delaware Basin asset. And really, I think the big takeaway is that at this level of activity in the Delaware Basin, we're confident we can maintain similar returns and free cash flows for longer than 10 years.

And it really comes back to the deep inventory of high-return assets we've captured across multiple basins, Neil.

Yes. And I appreciate that. And maybe that's a good follow-up, you can address the Delaware question. It's something we get a lot from investors who look at some of the well results and are concerned that there's degradation in terms of quality of inventory and those well results. And I think you guys have a perspective on that, how do you address that case that's been out there.

Yes, Neil, this is Jeff. Really, like we've talked about in the past, and I'll give you a little bit of detail. It just has to do with all the progression we've made there because as we've said, there's not just 1 variable that goes into economics. It's not just production. I mean, ultimately, you got to focus on rolling everything up to make sure you're maximizing returns, and that's what we're doing.

So in the Delaware, just taking a look over the last 3 years, we've extended our lateral 30%. We've lowered the cost there by 20%, which has ultimately improved the capital efficiency by 4%. So when you take all that and you roll it up, our cost right now is at or below $725 a foot. And because of this, we've talked about, we've been able to unlock those additional targets up through the strat column and that they meet our return hurdles now at bottom cycle pricing and deliver payouts much less than 12 months at current pricing.

The other thing it also does is it really improves the overall recovery per acre and it maximizes the NPV per acre across the asset, which is really what we're looking for. And so by design, we're obviously seeing a little bit lower productivity on those targets, but not lower economics. They're matching any other target that we have and they've actually meet that hurdle. And now that we've fully implemented that new development approach as Ezra said, we aren't going to see any major changes in productivity.

It should be relatively consistent moving forward from here. So we're extremely excited about how the Delaware program has progressed and how our team has unlocked all this additional value there through the cost reductions. And as Ezra said, we set it up for an extremely successful year and many years on to become.

The next question is from Steve Richardson with Evercore.

I appreciate the update on Dorado and I appreciate that the teams worked so hard to move it towards foundational. I was wondering, as you could just talk about how you thought about increasing activity there versus some of your oilier basins based -- appreciate the $1.40 breakeven. But just how do you think about the gas macro and how this play kind of fits into that? And I was wondering as a follow-on to that, if you could kind of address how your LNG take contracts going to change in '26 and '27.

Yes, Steve, this is Ezra. Listen, we're -- I appreciate the question about Dorado. As we've highlighted on Slide 18, our deck, we've had a fantastic couple of years. We've dropped our well cost down to $750 per foot. We've increased drilled feet per day by 30%, completed feet per day by 20% and so it's really dropped our breakeven down to about $1.40 per Mcf, and that includes F&D, LOE, GP&T, G&A and production tax.

So we're still highly confident that Dorado is the lowest cost gas supply in the U.S. with exceptional geographic location with its proximity to the Gulf Coast and premium markets. I think Jeff has talked about that we exited 2025 at about $750 million a day, and we plan to exit 2026 at about 1 Bcf a day gross. And that measured pace of investment, Steve, it continues along just kind of our cultural approach to each of our plays. So we're investing in it with 2 things. One, to keep -- to make sure we don't outrun our pace of learnings, we can continue to drive down the costs associated with any of our plays, but especially here in Dorado being a gas play.

But the second thing is, we really are growing into not only the emerging North American natural gas demand that we see, but really some of the contracts that we have. Now we can supply many of our contracts from multiple basins. But as you brought up with our our LNG specifically, as of Q1, we've actually increased our exposure to LNG by 140 MMBtu per day. So that's on top of the preexisting 140 MMBtu per day that's linked to JKM or Henry Hub.

We also have another 300 million a day that's already been going to LNG that's linked to the Henry Hub. And that has -- so that leaves us 1 additional tranche of 140 MMBtu per day that we anticipate coming on later this year and will be linked again to JKM or Henry Hub.

As we move into 2027, we have an additional contract, as you know, that's linked to Brent or the U.S. Gulf Coast gas for a total of 180 MMBtu per day. Again, when we think about the first part of your question, Steve, how does Dorado compete for capital versus the liquids plays. That's one of the strengths of being a multi-basin company and having dedicated North American liquids plays and dedicated North American natural gas plays is that we don't really see them competing against each other.

They're really able to service different parts of the market. And what we see overall in the U.S. natural gas demand, much of it is coming from these longer-cycle projects. Certainly, there's an increase in U.S. electricity demand. But when you think about data centers, behind the meter or LNG, oftentimes, when you sit across the table, negotiating with the other stakeholders, they're really looking for the confidence in 10-, 15-, 20-year multi-decade type of contracts. And that's really the strength of having a dedicated North American gas -- natural gas play as opposed to associated gas.

Really helpful. great progress there and congrats to the team [indiscernible]. I'm sorry, just a follow-up, second year in a row that you've run more than 100% of free cash in terms of the buyback -- sorry, in terms of cash returns to shareholders. Can you maybe just talk about that? The target is unchanged, but you've had -- we'd probably say a pretty squishy commodity price environment, but you've been able to do that and bolt-on a pretty significant acquisition.

So how do you think about that going forward? Is this just the best use of cash as the cash comes in? And just remind us how does your view of value of the stock or relative performance? Or how do you kind of think about that buyback lever, which seems like you really like at the current time?

Steve, this is Ann. To address the free cash flow, of course, we're looking at the best ways to create value for the shareholders. And our pristine balance sheet places us in an excellent position to reward shareholders with robust returns of free cash flow. We have demonstrated, as you said, a commitment to return significant cash to our shareholders. .

And we do expect this to continue as we really don't see a need to build cash on the balance sheet. The current environment, as you noted, is a dynamic and could provide the opportunity to return cash at similar levels as we have over the past few years. I mean we start our cash return anchored by our sustainable growing regular dividend, and then we'll supplement that by share repurchases and/or special dividends. And recently, we've had a focus on the opportunistic buybacks as a primary mode of additional cash return.

So in the current environment, we're very comfortable returning that 90% to 100% of annual free cash flow that I outlined. And that's similar to what we've done over the past few years. Our focus continues to invest our dollars to create long-term value for our shareholders.

The next question is from Doug Leggate with Wolfe Research.

Ezra, I think you may have partially answered this, but this is the first time you've given the new free cash flow visibility post Encino. Obviously, you've got a $6.5 billion capital budget. There's a lot in there that's not mean to this capital, but you have also -- you're putting a $50 breakeven on this. What I'm going with this was, if I heard you right, did you say that on a sustaining basis, do you think you can hold your free cash flow flat for 10 years or sustain it for 10 years? I don't want to put words in your mouth, but if I take the $6 billion high end at $70 oil that gets you to about 2/3 of your market cap. So in other words, it's not enough. So can you just clarify what you were meaning there? And I've got a follow-up, please.

Yes, Doug, this is Ezra. Yes. My comments earlier were specific to the Delaware Basin. I'm sorry. I think that's where the disconnect is in the Delaware phases. Yes, yes, yes. And so really, what we've seen with the 3-year plan the 3-year scenario, quite frankly, is that the high-level takeaway, like I said, is comparing the past 3 years with the forward looking 3 years at a similar price deck, we've actually increased the free cash flow potential there by 20%.

And even with low single-digit oil growth and modeling a mid-single-digit kind of total production growth, we're seeing 6-plus percent compound annual growth rate of that free cash flow year-over-year.

So just -- my follow-up, just a clarification. So when you look at your sustaining capital, what do you think that level is for the post-Encino portfolio? And what do you believe the duration of that is post the 3 years? I mean, are we talking about 20 years of inventory, 20 years of sustainable free cash flow, you define it?

Yes. So there are kind of 2 different questions in there. Maybe I'll address the first one as far as the inventory life, and I'll let Jeff maybe follow up with the details on our maintenance capital number post Encino.

So Doug, when we think about the resource potential, the inventory, the deep inventory of high-return assets that we've captured that I talk about, Slide 8 in our inventory in our deck is probably one of the best ways to look at it. And we presented that 12 billion barrels in a way that it's 2 different things on that slide. You can think of it as kind of an R over P, a good old-fashioned R over P, which that 12 billion barrels to your point, speaks to close to 20 years' worth of production.

And then you can also see on that and you can -- you're welcome to apply any type of risk to that as you deem necessary. But the other thing you'll notice on that slide is the returns as a proxy to free cash flow. And you can see that 12 billion barrels, essentially generates greater than 55% return at [ 45 and 250 ] greater than 100% rate of return at $55 and $3 gas. And so -- what I would point out is, as we develop a program every single year, it's not that we're force ranking or rates of return inventory and drilling the highest 400 or 500 wells first. There's always a mix in there, which is why we present our inventory as kind of a kitchen sink effect on that rate of return because at different times, you're obviously drilling in different parts of the basin.

You're trying to maximize infrastructure, you're trying to limit your indirects. And so that's really the best way to look at it. I would say that we have great confidence being able to deliver similar free cash flow, similar returns at the company level for many, many years to come based on that deep inventory of 12 billion barrels of equivalent. And then, Jeff, with the maintenance capital, maybe?

Doug, this is Jeff. Yes, you're correct. It's been a handful of years since we've updated that maintenance capital. And with it updated, current range right now is from $4.8 billion to $5.4 billion. So midpoint around $5.1 billion. And really what this range represents is the capital required to hold production flat for a period of 3 years. .

And it also assumes our current well costs right now. And that's consistent with our updated 3-year scenario. The other thing, I'd say, is the big changes that have really happened since the last update, as you hit on, obviously, the Encino acquisition we built into that. There's an increase in production of the base business since the time of the previous disclosure. And also, there's the impact of the improvement across our portfolio since the time of the previous disclosure. And then lastly, I'd just note that this maintenance capital, it really reflects a modest improvement in our base decline, which is now below 30% for oil and below 20% for BOE.

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

I was wondering if we could go back to Permian productivity. It seems like it's been a bit of a headwind for EOG share price. And I appreciate the context you guys have provided on those, we'll call it, secondary zones, which is something other peers are talking more about that and surfactants and other things.

And I'm not -- I don't want to lead your answer, but do you think some of the relative performance that people are being concerned about is because you all have been able to move faster to these secondary zones than peers? And if you could give us a sense of some of the primary kind of activity that you've done is the productivity over the last few years, fairly static.

Yes, Scott, this is Ezra. Thanks for the question. Yes, over the primary targets, I'd say, we're seeing relatively consistent performance there. Of course, even it's difficult to compare because even if you think about, say, an Upper Wolfcamp or a Wolfcamp A, you end up having multiple landing zones in there.

So don't forget, we're a pretty technical bunch here. And so we look at the permeability. Is it a little bit siltier? Is it more of a mudrock. And those are the types of things that with just a little bit of savings on your cost side, all of a sudden, some of those targets really become more economic than what you'd previously counted them on. So what I would say is like-for-like though, we're seeing pretty consistent well results in there.

As far as pushback, I think, from the peers, I don't want to speak to the peers. What I would say. What I think is going on with us is that we made this shift. I think we figured that we had pretty well highlighted this and externally talked about adding 9 additional landing zones over the last few years. But in hindsight, Scot, I think we could have done a better job highlighting our change in development strategy heading into 2025, again, off of the really extreme cost reductions that we saw coming off of essentially the relative highs there in 2023.

No, I appreciate the context. And as my follow-up, if we could move to natural gas, and you all have increased exposure to pricing on the water with some of your LNG contracts. Could you give a sense of other things that you all may be working on considering [ supply agreements ] for industrial users or power data center users

Yes, Scott, this is Ezra again. It's a good question. We've spent time looking at really how data center development may progress and what role EOG might play. And I think there are a couple of different ways where we can benefit today, potentially benefit in the future. The diverse marketing strategy gives us exposure to regional pricing uplift associated with increased electrical demand in areas of data center development. Obviously, we've seen the U.S. electricity demand grew last year, just shy of about 2%.

Electricity prices obviously grew more than that about 6.5%. And I think going forward, U.S. electricity demand overall is forecast to grow between 1% and 3% kind of compound annual growth rates. So obviously, we'll see -- we can benefit from our diverse exposure across our basins from there. A good example also is the capacity that we capture along our Transco pipeline to deliver gas into that Southeast market, which is a big power pool demand center.

But really, another way we think that EOG might be able to benefit much more directly, and we have had negotiations along this path is if we begin seeing development of data centers closer to power gen or closer to natural gas fields. We see both, especially South Texas and Ohio is having great potential to play a larger role in data center build out. Obviously, the position that we have in Dorado and the Utica would benefit from that regional demand.

I think when you think about South Texas, there's -- especially Dorado, there's open space, there's water, you're far enough inland from any storm threats. There's a good amount of gas, a phenomenal amount of gas there. And there's also a good amount of fiber already in the ground. And right now, I'd say it's still surprisingly early on with a lot of the data center conversations. You see a lot of the construction is somewhat delayed or getting pushed out to the right a little bit. As people, again, I think, really try to wrap their minds around a multi-decade contract. But that's where we think that we've got a competitive advantage with Dorado is that we've got the gas supply, low-cost gas supply to stand up and support one of those longer-term projects.

The next question is from Derek Whitfield with Texas Capital.

Regarding your 3-year outlook, I wanted to focus on the role international could play over that period and beyond that period. While onshore will undoubtedly carry the load in your financial performance, how should we think about the increase in role International could play exit the 3-year period?

Derrick. I appreciate the question on the 3-year scenario. The scenario does include capital for the Gulf States exploration and development. Beyond the capital that's really tied to the '26 plan, we're basically forecasting a slight increase in the activity in the Gulf states. The associated production assumption is really minor. .

And we're doing that in a 3-year scenario because those plays are still in the exploration phase right now. And we do assume success and declaration of commerciality. But in the time frame of the 3-year scenario, I would say that the specifics to the international assets are relatively minor. Now with regards to Trinidad, Trinidad, we've got a bit more line of sight, slightly longer-cycle projects, and we continue to have a pretty robust program there in Trinidad ongoing.

Great. And then with regard to UAE and what you know about the subsurface today, how does that compare versus some of the premium U.S. unconventional oil basins. And how should we think about your delineation plans for that in that area in 2026?

This is Keith. Both in UAE and Bahrain, activity this year, we're going to continue our drilling program to evaluate those exploration concessions. We're expecting activity to be higher in the UAE than Bahrain, just due to the relative size of the concessions. We're still in the early phases of that our plan for 2026, is a little bit dynamic. As Jeff mentioned, we expect to have production results in both countries in the second quarter of this year.

So in Bahrain, we drilled our first few wells, and we have started completing them. And in the UAE, we've drilled the first couple of wells, those went very smoothly, and we plan to begin completing them here shortly. So we're very excited about the opportunity that we see in both countries. Both areas have positive production results from prior horizontals.

As far as delineation in 2026, we are just really working to refine our subsurface understanding to build off of ADNOC and BAPCO's progress and positive momentum on cost reductions and help bring even more of the latest unconventional technology to the region. We think that there is a lot of technology and similarities between many of our domestic plays that we could borrow and apply to to either country.

The next question is from Charles Meade with Johnson Rice.

Jeff and Keith, maybe I'll just pick up on that thread and ask about in UAE and Bahrain, less about the well results, but how you guys are going to communicate there. And I think that at least in the Lower 48, the EOG MO is kind of quietly try something to play and then based on success or failure, you either quietly exit or quietly build a position. But that doesn't really -- it doesn't seem to be an option to just quietly exit in Bahrain and in the UAE. And also at the same time, there's not the same competitive considerations there, given the nature of these concessions.

So can you -- not looking to commit you to anything, but can you give a broad outline of how you guys plan to share results and what the consequent decision so you either ramp activity or curtail it?

Yes, Charles, this is Ezra. I'll take a crack at that question. So it has been something that we've had to get used to kind of our international strategy. And we saw this. The best thing to do, I think, maybe is to take a look back at what we did in Oman. Again, it is a little bit different from our domestic exploration portfolios or projects where we can usually be a little bit stealthy and keep things quiet until we get material results or a material position in a play and can really start to discuss it. .

Typically, these days, when you -- internationally, when you sign an agreement, there happens to be a press release and things like that. So the first step is making sure that the agreement is something that checks the boxes for us for international. So that we have captured a sizable position. We have captured access to premium markets. Of course, we've been able to negotiate a contract, align the stakeholders and partner with folks that we think we'll be able to -- if we have success, really have success and really have captured something that is going to be exceptionally competitive and additive to the corporate portfolio.

Now again, in Oman, you're right. There is no state data. There's no public reporting. I thought we were fairly transparent with the results that we had in Oman and when we exited we didn't try to sneak out the back door. We just made it known to everybody that we had drilled wells. As you recall, we made a kind of an undeveloped discovery there and natural gas discovery. We're really focused on oil because of the lack of infrastructure in the area.

And so we did end up exiting. Bahrain and UAE, to be perfectly honest, will be very, very similar to that. Both of these international opportunities. We're currently in an exploration phase. That lasts a certain amount of time, and then there will come a point where after we satisfy the terms of the exploration phase. There will be a decision on whether or not we go forward, casually called a declaration of commerciality and that would then assign some sort of longer-term production license.

And you can assume that, that would obviously be something public. Now that being said, at this point in the game, we feel very confident in all the plays. We're very excited about the size of the prize that we have in both the UAE with our unconventional oil play and the unconventional gas play in Bahrain. Bahrain, obviously, is onshore. So you can imagine it's a little bit, as Keith said, a little bit smaller in scope.

But it is a gas play in a region where we see tremendous future gas demand. And so that probably is an area where we continue to look for the right partners. While we're very happy with what we've captured in the region. We'd be interested in continuing to look for adding a potential additional gas project in the region under the right terms and with the right partners.

The next question is from Philip Jungwirth with BMO.

Yes, thanks. Coming back to the multiyear scenario, recognizing it's not guidance, but the low single-digit oil growth is maybe a bit surprising since organic volumes have been flattish here since Liberation Day, and that's continuing into '26. So could you help us understand how you would resume oil production growth, which assets drive that? And just one of the qualifications in here is that it assumes current cost structure. So just wondering, when you look back at '23 through '25 actuals, how much you actually outperformed here? And could you see similar run rate over the next 3 years?

Yes, Philip, this is Ezra. That's a great question. So using current cost is just for line of sight. I do think with our consistent track record of lowering costs, that's the best data points that we have. But if you want to build in a little bit of conservatism, I could understand. What I would point out is that we've made tremendous strides over the past 3 years in the Delaware Basin.

Part of that was with our sustainable operational efficiency gains. Some of that, too, though, was in 2023, was relatively kind of a high industry, high watermark for costs across the industry. And then we've made tremendous progress lowering well costs across our 2 emerging assets as well. And as you know, early in these assets, early in the play development, you have the opportunity to make greater strides there.

As far as returning to low single-digit oil growth, outside of the Liberation Day announcements that caused really a little bit of concern on really line of sight on what may happen with demand, coupled with spare capacity reentering the market, we see that as a bit of an overhang for maybe the next couple of quarters. Certainly, there's a lot of commentary that the oil glut has been pushed to the right. We're seeing that as well.

But what we're also seeing is that when you look at total product, inventories have raised right to the 5 year, roughly in line with the 5-year average. And there is some additional spare capacity that's scheduled to come back to the market. That being said, we continue to see global demand growing relatively strong and constant at roughly that 1 million to 1.2 million barrels per day, roughly maybe right at 1%, a little bit less than 1% compound annual growth rate. And that's really what gives us confidence in forecasting growth of low single-digit oil.

Now where that growth would come from? In the 3-year scenario, it contemplates a lot of growth out of the Utica as a matter of fact. But quite frankly, we can grow from multiple basins if we needed to, if we wanted to. Really, the growth at the company level will really be determined by optimizing across each of those basins the level of activity, the marketing agreements, where do we have infrastructure and things of that nature.

Great. And then you met the $150 million Encino synergies well ahead of schedule. I think you gave yourselves a year here. So could you just talk to the drivers, positive surprises now that you've operated the asset for 6 months. And I assume you're not done here in terms of driving improvement. You mentioned in-basin sand. Anything else you're working on to enhance returns? And if you could also just touch on marketing initiatives here to improve netbacks.

Yes, Philip, this is Jeff. Yes, as we kind of touched on it in our opening remarks, obviously, we're extremely happy with how everything's progressed with the synergies there. And you've heard kind of how much success we've had across the operational side, with just drilling completions with our procurement side, extremely happy and driven that cost down to $600 a foot in very short order. We really have only been developing there a handful of years.

As I kind of look forward, I mean, I think there's a handful of things that we can really lean on full rollout of the EOG Support Services, I mean, you kind of touched on it there. I mean once we implement self-sourced local sand, that's going to be a big initiative to really drive down costs. Also tying together a lot of our water infrastructure maximizing reuse in the area. That's going to be a pretty big driver that we can use our technology from around the rest of the portfolio.

Also, it will take a little while, and we're in process, but implementing additional automation and measurement across all of the acquired operations, we'll be able to remotely manage and monitor wells and really take advantage of our 24/7 control room that monitors everything up there. And what that will do is really improve a lot of our efficiencies and reduce man hour times.

And then lastly, as you talked about, continuing to focus really on utilizing the scale now of the asset to reduce the GP&T and work on the differentials. And I think the big ways we're going to do that, as I stated is, first and foremost, we like to control in-field infrastructure and gathering. So we're going to focus on building that out, which should help bring our differentials down. And then on the marketing agreements, obviously, just with the scale there, we have great relationships with the marketers.

We're in contact with them. and continuing to look for options to be able to either extend out agreements and optimize those agreements to be able to lower the fees just because we have so much more volume and scale up there. So I really think we're just kind of tip of the iceberg. We've got a lot of upside in the play. We still got upside in synergies and our team continues to uncover opportunities every single week.

The next question is from Matthew Portillo with TPH.

Just a quick follow-up question on the Permian. Great to see in the remarks that you're expecting stable productivity trends for the basin this year and also to hold production flat in 2026 on an exit-to-exit standpoint. I was just curious if you could maybe help us out a little bit on that last point for the outlook. Looking into 2025, I think you completed about 390 wells in the basin and drove about 10,000 barrels a day of growth.

And obviously, you've highlighted a big drop in the well count this year down to about 300 wells. So I think the maybe missing piece around this might be the lateral length progression. So I was curious if you might be able to help us out on that front.

Yes, Matthew, this is Jeff. We've made great progress across our whole portfolio from a lateral length aspect, not just even in the Permian. So last year alone, we increased our lateral length by 18% across the portfolio. And it really was driven by, as you're talking about the momentum that we had with 3-mile laterals there in the Delaware Basin. So we had a substantial increase there and focus on that.

We extended our laterals in the Eagle Ford where in certain areas that were stranded, we were able to drill numerous 4-plus mile laterals with, obviously, the record lateral that we had there on that [indiscernible] Whistler E5H. And then the same thing in the Utica. We've got 3-plus mile full program basically there across the board that's really helping push. If you look at the Delaware Basin, it's basically fairly flat actually from '25 to '26. And the reason for that is just the huge jump that we had last year.

But Obviously, that has to do with a lot of our footprint and the leasehold that we have out there. But our team is always going to look for opportunities to go ahead and continue to make trades, bolt-on additional acreage and extend those laterals wherever we can because I think we've proven with our drilling technology with the EOG motor program and our approach that we're able to drill those longer laterals with great success.

Great. And then maybe just a follow-up on Dorado. Looking at the state data saw a really nice improvement in the productivity trends per foot in 2025. I was just curious if you might be able to comment on this improvement and what might be driving that? And then maybe a bigger picture question.

With your exit rate approaching a Bcf a day of gross production in 2026, I know you've talked about compression potentially taking the Verde Pipeline to 1.5 Bcf of egress. But I'm curious if there is a need down the road for potentially more pipeline capacity, just given the economics of the assets and the improving productivity trends we're seeing out of the basin in aggregate?

Yes. Thanks for the question. No, we've been extremely excited with how Dorado has evolved down there. And really, it's kind of across the board from both drilling and completions and production being able to increase the well performance there. So like everywhere else, we look at our wellbore construction. We make sure that we're maximizing our high-intensity fracs in creating as much hydraulically created surface area downhole as possible with those things.

And as you stated, we are, we're seeing about a 13% year-over-year increase and that's a sustainable increase on a per foot. So it's really a recovery, not just a lateral length increase. So extremely excited about that. We'll continue to work it. And then on the second part of your question, yes, we have the EOG Verde pipeline in service.

As you talked about, it provides a Bcf of transport over to Agua Dulce. And it is expandable up to about 1.5 to 1.75 Bcf with very minimal investment in booster compression. And that provides us an uplift. It's very attractive of about $0.50 to $0.60 an Mcf, and that's just due to the lower G&PT and obviously, the higher netbacks that we have there. With that -- no, that will be able to, along with our other third parties, we won't need any other egress out of there. We've got plenty of egress with that pipe right there. And as I said, we don't just necessarily transport all down that pipe. We do have other third parties that we can actually market to in that area. So we feel really comfortable for the long term there in Dorado with our takeaway.

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

Yes. I'd just like to say, we appreciate everyone's time today, and thank you to our shareholders for your support and special thanks to our employees for delivering another exceptional quarter.

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

Well, it's been a very, very exciting morning. Thank you all for being here for this next session. One that we look forward to every year with Ann from EOG Resources, there's just so much to talk about. And I'm joined by my colleague, [ Yulia ] from the commodities research team, who does so much great work on the oil macro.

Ann, maybe give you the opening floor to talk about what is top of mind for you as we go into 2026. And then we have a lot of macro questions, a lot of micro questions for you.

Absolutely. First, thank you for having me. I'm excited to be here. It's always great to kick off our year here at the Goldman Conference. So thank you for having me. I mean, as we lean into 2026, 2025 was a pretty transformative year for EOG with all the activity we had in all our new projects. So it's really an exciting time. We have a lot of momentum moving into 2026. And so for us, it's really about digging in and figuring out the best ways we can have value creation.

Yes. Okay. So let's talk about your capital plans and activity plans for the year ahead. And I know we're going to get more color and details on that on the Q4 call, but any early breadcrumbs that you're willing to give as you think about the year? And what is a very dynamic price set, too?

Yes. As we look to 2026, when we released third quarter earnings, we said that the fourth quarter run rate -- the fourth quarter numbers would be kind of the run rate for 2026. And if you looked at that, that yielded about a $6.6 billion capital spend for 2026. What we are seeing is cost efficiency, cost improvements in the Delaware Basin. And we're also seeing the integration of the Encino acquisition going at a much faster clip than we expected.

So with those cost savings and the integration going faster, we're now thinking that we're going to land a little bit closer to the $6.5 billion level for 2026. And what that's going to allow us to do, of course, is to continue all our work in our foundational assets. We'll continue to be able to invest in gas. We will be able to -- our new exploratory plays in the UA and Bahrain and then it will also allow us to continue to pay out our regular dividend and as well as cash returns to shareholders.

And against $6.5 billion capital budget, oil growth of low singles?

Yes, low singles. I mean we're looking at the fourth quarter, it would be low to -- from no to low growth for -- so low to no growth '26 versus the fourth quarter 2025.

Perfect. That's a great pivot over the macro, and I'm going to jump in to talk a little bit about some the micro stuff. [ Yulia ]?

Yes. So I guess if we just look at the U.S. shale sector from a kind of a bird view, given your extensive expertise and history of EOGs in U.S. shale, where do you think we are just from the U.S. shale cycle perspective? Like do you start seeing some sort of signs of maturity that people start talking about? And given how the price environment is also changing and has been changing, how do you see your assets and EOG's position kind of like as a competitive edge over your competitors?

Yes, great. We do see some maturation in shale in the U.S., and there are some indicators of that. Of course, we're seeing -- there's been a little bit -- growing through the drill pit slowed down a little bit. We're seeing and returns -- that's allowing people to return value back through the form of shareholder returns.

We're also seeing a -- the way we're looking at it, we're seeing that the lost my train of thought, sorry. We're going in. We're seeing that that's slowing down. We're seeing that there's economies of scale. You're seeing a lot of consolidations in the industry. And because of those consolidations, people are doing that to get lower cost structures in place. And then we're also seeing people explore in basins that haven't been looked at in a while. So you see some increased activity in the Western Haynesville, the Uinta.

And quite frankly, we're seeing people exploring that haven't really been big explorers, done a lot of exploratory work. So we're seeing that as maturation for the shale. Also from an EOG perspective, we continue to look at innovation and technology as a great way for us to come up with new cost efficiencies, new cost savings and to drive value creation in the basin to get more out of the basin.

You look at two of our foundational assets, the Eagle Ford and the Delaware Basin, and we're continuing to see cost improvements there. And you would think that after a while, you kind of exhaust that, but it's quite the opposite. It's not happening by accident, it's by us investing infrastructure, investing learnings and trying to grow those and get better.

So for us, we view the shale and still has a lot of opportunity. The U.S. shale has a lot of opportunity. And as far as EOG and where we position ourselves, we think we really bring a unique approach to everything. We have -- we look at our value creation through four key pillars. We have capital discipline. We believe in investing in our assets at the right pace for each of those assets. That's backed up by a pristine balance sheet. And we want to be able to invest at bottom cycle prices so we can continue to offer returns and cash flow back to the shareholders in the long term. So that's our capital discipline pillar.

Second to that, you have operational excellence. So EOG is a leading -- is leading in our in-house technical expertise. We have a phenomenal information technology program in place. And then we are also looking at self-sourced materials at EOG, things like sand. So that's bring a real value that EOG brings. And then sustainability, we want to be a prudent operator in the areas in which we work. We want to keep our employees safe and obviously be very conscientious about our environmental footprint.

And then finally, all of that is based on culture. And it's one of the hardest things to describe about EOG. I've been here 30 years, and the EOG culture is really what invigorates the company. We're non-bureaucratic. We're decentralized. So what we're doing is putting the value creation down at the asset level. And that allows our employees at ingenuity, that ability to create new things is at the asset level.

And we're empowering all of our employees no matter where they're located to come up with new ideas and make them approach the business as being a businessperson first. So we think EOG offers a lot of value. And again, it's about creating high rates of return and being able to generate cash over the medium and long term.

Sticking to the oil macro for a bit. There's obviously, a lot of concerns that the prices can keep going lower and lower and investors are getting more kind of cautious about how much it can affect really spectacular steel growth in the U.S. shale production that we've been seeing this year despite prices decreasing.

Is it something that you worried about like looking at how much extra production is also coming from the LatAm, potentially higher Venezuela production, surplus is increasing? Or you kind of like think that's a bump on the road and the prices will rebound going forward and you kind of like keep your mind more in the long run price cycle. How in general, you think of prices when you make your decisions?

Yes. We agree that there's an oversupply. It's driving that price down. And we think that's going to last for several more quarters. So that's going to cycle through. And eventually, that oversupply is going to turn into an undersupply as that demand grows to meet that. As far as how EOG approaches it, though, is since we invest at that low cost at the low end of the cycle, not at the low end of the cycle, but at lower prices, what that allows us to do is really create value even when we hit these proverbial, as you said, bumps in the road, we're able to still, again, create value.

So for us, we manage the business consistently looking at that capital discipline, investing in our assets at the right pace for their development. And obviously, we're watching the macroeconomic and being conscientious of it, but it doesn't really impact how we're going to strategically position the business.

And before I pass to Neil, let me also ask about nat gas. right? Because there is kind of like worry that in 2028, 2029, we're going to be all flooded with the U.S. LNG, with the Qatari LNG. Is that something that's kind of like top of your mind? Or are you kind of like thinking about it more from a short cycle perspective? I guess, in general, what's your view on the Henry Hub going forward?

Yes. For EOG, the way we approach it, first, you got to look at winter weather, what's going to happen in the short term. There will be some price volatility based on where the winter weather plays out. But then as far as the the gas supply and demand, we're expecting that demand to grow. There's some kind of key drivers behind that. You talk about the LNG buildout. There's going to be a real demand for the LNG feed gas, so we think that's going to be a huge demand driver.

And then second to that, electricity is going to also be a huge demand driver. So we do see that position growing. Again, as we look at EOG, it's all about short and long-term approach stays the same, depending what the gas market is. It's all about reinvesting at the right pace for the asset.

As far as LNG, we do think at some point, all that buildup is going to could create kind of a glut. People are concerned what's that going to do to price in the future. And the way we look at it is it's probably going to be a little bit more regionalized as kind of areas settle into what are their supply and demand, what's the transportation options there. And also looking a little further for LNG, how are markets going to treat LNG as part of their energy mix. So that will all play into things as we move forward.

Ann, you started off by sharing your activity plan potentially for next year, which is at 6.5 low to flat oil production. what would it take that to actually shift it lower and move towards decline? It wouldn't -- preserve the barrels for a higher price. I would imagine it would take a real regime shift from where we are right now.

Yes. Again, I keep talking about this, but it's such an important part of how EOG approaches this business, and that's investing in assets at bottom cycle prices. So when we hit those low points, EOG is still able to deliver that value. And that's really kind of the ground rule of how we -- so if you start at that low-level pricing to invest into the business, what we can do then is we can shift within this multi-basin portfolio.

We can -- we bought -- we've got gas. We have oil now we have international locations. So we have some flexibility to shift into the different areas, the different assets. But really, it's got to take some pretty incredible event to happen before EOG is going to really change the course of the ship or do anything different in how we approach the business.

Planning, the assumptions are very wide.

Exactly.

Okay. So let's start with Encino because that's a big development since we're on the stage a year ago and talked to us about how the deal came together, early observations, and how would you characterize the Utica in your portfolio?

Yes. The Encino acquisition, that was privately negotiated. Very much a hand in glove acquisition for us because it directly aligned with the assets we already had in the region. I'm very excited about what we've acquired. The oil position. We're very active in the volatile oil window, and we were able to double our acreage position there.

Of course, along with that, we did get some gas acreage, and we're excited about taking our learnings and seeing what we can do with the gas acreage. But from an integration standpoint, from day 1, it's been very exciting. It's gone very smoothly. As I mentioned earlier, we're already seeing a lot of cost savings, a lot of synergies. We've announced. We've got about $150 million in synergies related to Encino and we're looking for more. But it's gone really well.

We've been able to put all our proprietary apps on it. Already been able to immediately make it be a part of our portfolio. We've integrated the Encino employees we brought over. We brought them into our culture. They're embracing our culture.

But again, putting our stamp on it, looking at reducing well costs immediately and really enthusiastic about how our employees have hit kind of the ground running to embrace the additional size of this asset. And then the Encino employees joining us as well.

We set up an office in Columbus. As I mentioned earlier, we're decentralized. We want to be running the asset, putting the value creation down at the asset level. So we did set up an office. That's going really well. It's exciting, a lot of hand shot up and wanted to go and be a part of that new Columbus office. So exciting for that.

And then how does the Utica fit in our total portfolio? It's a foundational asset. So as such, it's going to be competitive with our other foundational assets. It allows us flexibility. So again, we can shift between those foundational assets. But really, we just think it high-grades our portfolio, again, kind of that hand in glove, and we look for a lot of excitement, a lot of value creation in the Utica going forward.

And as you think about -- there's -- Utica, of course, there's a lot of dry gas there. There's a lot of liquids as well. Where are you thinking about attacking first here?

We continue, like I said, to focus on the volatile oil window. That's our primary reason, quite frankly, for adding Encino to our portfolio. And that's where we are focused on first. That's where we've done -- had the most activity. And we did acquire those gas assets.

The Peckens well came online. They had a 30-day IP of around 35 per day. So we're really excited about. And as we get in there and kind of unravel how everything is set up, we're really excited about looking at the gas package as well. But for now, our focus continues to be on the volatile oil window.

All right. Let's move south to Delaware. And that was a big focus of investor conversations I'm sure today and yesterday at the conference, but in general, over the last 6 months of we're shale getting more mature. Where are we in terms of the efficiencies?

Where are we in terms of some of the curves and some of the data that was out there showed some softening in the Delaware for you guys, but I know some of that data can be noisy, too. So -- how do you think about the execution in the Delaware as we go into '26? What do you think is probably misunderstood by the market as somehow arguing it's getting to its point of maturity?

Yes. Again, the Delaware Basin is we like to call it the gift that keeps on giving. It's been a high performer in the portfolio for a very long time, and we're really excited. It continues to generate strong returns, great economic results, great financial results, and we expect that going forward.

As you look at the well cost, we've seen our well cost in the last couple of years decrease by about 15%. And that lowering of those well costs has allowed us to go in and unlock new target zones and they're yielding great economic results. The way to kind of look at it is, although some of these wells don't have the same level of performance as historical, we are seeing lower cost and be able to drive those efficiencies.

So again, as you look at kind of the well economics, they're still producing at the same strong levels. So if you look at the Permian, if you look at the Delaware Basin for EOG, we've been able as a basin to -- we have well payouts that are just at a year for 2025.

We've been able to generate 60% -- greater than 60% after-tax rate of returns. If you look at it at a flat $45 WTI, we have greater than 100% rate of returns if you look at it on a strip price, -- we also are seeing some cost efficiencies coming into play as well as our direct and our all-in finding costs are all decreasing.

So again, you start coupling all that, all those lower costs on the well economics, the total delivery from that is actually extremely strong and very competitive what we've done in the basin for a long time. And I would never sell anybody short in the Delaware Basin. We continue to look for opportunities to drive that well cost down even further.

So yes, maybe we're not drilling the highest quality assets, of course, were drilled first. But the beauty of it is all the learnings we've had in the Delaware Basin over our history there has really allowed us to, again, continue to drive down this cost, unlock those new zones. Continues to create value, and we still see it as an extremely important value creator in our portfolio.

And then one of the challenges that's been talked about in a number of the panels operating in the Delaware is the amount of gas that's coming off these assets, but also as we move westward in the basin, the GORs just generally pick up, and that's natural as assets mature. And so how do you ensure that you keep your oil cut up in that basin?

Yes. Again, it's how we're approaching the basin. I was talking earlier, we talked about it from a capital discipline perspective, but we're also looking at it from how we're looking at the rock and how we're drilling, how we're approaching how we do things.

And what that's been able to deliver for us is continued great results. The oil cut is a byproduct of that hard work and the efforts that we put into it and how we're learning the rock and trying to continue to take those learnings from the historical activity and really drive that value forward and continue to focus on that as well.

I'm going to turn it to Yulia here in terms of exploration, but one more just in terms of technology, this is where EOG has always been the leader in terms of application of technology. And we've gone through a lot of different iterations of different shale phases, first, the lateral length and then more recently, changes in completion designs and simul-frac and trimul-frac and quadro-frac. So what's next? What's the next thing? I think there's a lot of talk about whether lightweight proppant works or not, maybe that's in surfactants. What's the next thing we're all going to be talking about?

Yes. Technology, EOG is a technology leader. We tend to be a first-mover advantage in technology improvements. And really, it's about -- going back to my initial comments about that culture, empowering our people to be creative and look at different ways to approach the business and to approach the basin.

As we look forward, what I think is exciting about technology in our company is we're talking to each other. Multidisciplines are talking to each other, trying to figure out creative ways to add more value through technology.

A couple of things maybe to focus on coming around the corner. We have our HiFi sensors. Those HiFi sensors are go down into subsurface, so subsurface. So as we're drilling those wells, we're able to collect data as we're drilling those. So we're able to look at the geomechanics of the rock. We're able to look at fractures. We're able to monitor what our equipment is doing, how it's performing. We're able to do that in real time.

So it's sending that data, if you will, back up to the surface and allowing us to capture that data, understand that data. And then when it comes time to complete that well, we have more knowledge. And then again, further taking all that knowledge and applying it into the next well. So that's an exciting opportunity for EOG. And then, of course, there's obviously discussion around AI and the technology improvements surrounding AI and what we can do there. And that's an exciting time for the company as well. We're a very data-driven company.

And so as we make those the information technology improvements that's allowing us to gather more data, understand that data better and reenergize and put it back into the company in the ways we're looking at things. It also allows kind of basic functions that people do every day. We're able to do that more efficiently. So as you have the drillers out there going out to all the different wells.

Now they're an app-based phone. They can just talk about the well as they're going out to the well and just put the data in there and it immediately transfers over. So a lot of technology improvements, again, from the cost-cutting efficiencies, all those things we're trying to do, it's really having our IT teams that multidisciplined approach those hallway conversations on how can we drive forward the business. It's been fantastic for the company. We see a lot of value creation and continue to see it.

That's an interesting observation because we've been talking a lot about techniques here. But what you're talking about is digitization at the next kind of wave of productivity improvement.

Yes. Yes. And you asked about surfactants. We've looked at surfactants. We -- for us, it hasn't been a real good cost benefit, but we're continuing to watch what other people are doing. So as we all know, the oil field is pretty small. So we all know what everybody is doing out in the oil field. So you have the technology improvements and how we can improve the cost and the functioning of the different things we're using in basin. And then, of course, you have the information technology side of it.

Any strong views on LWP lightweight proppant?

No, same thing. It's all about how is it going to -- we're looking at the best cost-effective things to be doing to make our wells productive. And again, monitoring what's happening around the industry.

Thank you. [ Yulia ]?

Yes. So you launched initial operations in Bahrain and the UAE, exciting new stage for EOG. How is the progress so far? How are you sort of navigating relationships with the local governments there? And also, if everything goes well, do you have any time frame in mind for when you'll be able to go to the full-scale development there?

Yes. We're really excited about our presence in the Gulf nations. We have the 2 areas we announced last year. We have Bahrain and the UAE and kind of taking them one by one, Bahrain, excellent working relationship with the Bahrain government. It's a joint venture partnership with Bapco, really have alignment of stakeholder ideas there. So we're really excited about that. It's a gas asset

We drilled our first well in the third quarter. You did see a little bit of production for the third quarter, that was really from legacy wells we brought over. But it's fixed pricing directly in country into the market. We see a growing demand there. I'm a little bit smaller scale asset. So we're thinking maybe like the next year, 1.5 years, we'll be able to see some real results from that and kind of can strategically look at what that package is going to do going forward.

On the UAE side, it's a much larger concession. It's 900,000 acres. Again, great working relationship with the UAE government. We were the first U.S. company to be awarded an unconventional concession in the country. So we're really excited. We were approached as we've been talking with them for a couple of years, and we're really excited about being invited to come in and look at that reservoir with them and use our expertise to help drive that reservoir forward, again, into a growing -- an area with a growing demand.

Again, an oil asset, we spud our first well in the fourth quarter. That has a 3-year time line to declare commerciality. So it will take some time to get that one to fully understand. But excited about both of the opportunities. We set up an office there as well.

Again, just like with Columbus, a lot of hands went in the air and said, "Wow, I want to go over and work in the Gulf Nations office." So that should show you, again, we're about decentralization, putting our multidisciplined asset teams on the ground locally so that they can really address the basin right there and be involved with it.

So it's not that it's located on the other side of the world. We're there and we're active and our teams are on the ground. But great alliance with both of the countries, great alliance of where we're going with the development stages. And for us, any time we look international, anything we do exploratory has got all these hurdles that has to go over. But when we look at international, we want to make sure that, obviously, it's of enough size and scale that we'd be interested in growing there.

And again, planning your flag there and growing the asset. We want to make sure we have good relationships, again, with the government and with the parties we'll work with and we want to have good oilfield services on the ground there. We don't want to have to start from scratch. And obviously, we want to go some place that has good geopolitical stability, which, of course, as we saw from this past weekend, is a very important characteristic. So really excited about our entry into the Gulf Nations and excited to have a presence there for a long term.

And going forward, where do you see more opportunities when it comes to exploration, both if we look at across different domestic basins, internationally, kind of what is more like falling under your radar as you start thinking of like what's next for EOG?

Yes. For exploration, that's in our DNA. We have grown through organic exploration. That's part of how EOG operates, how we built out our business. And that's allowed us to match 12 billion barrels of oil equivalent resource potential. And if you look at that, it's got about 25 years of drilling, producing and drilling, completing and producing. So we have a lot of that already in-house.

The good thing is we continue to always look at exploration opportunities. It's in -- all our divisions are charged with going out and looking for the next thing and what's going to come around the corner for EOG. We don't comment on any of our real exploration activity that we haven't historically done that. But I can tell you, it's exciting times. We're continuing to always be looking at things.

As far as where we are in kind of the macroeconomic cycle related to exploration, we're kind of a stage that kind of that exploratory drilling has slowed down a bit. It's really more now about going out and amassing small blocks of acreage to be ready to drill when we kind of -- the cycle turns back around. So always exciting opportunities at EOG and we're always looking at things.

Could UAE be a foundational asset?

We certainly hope so. We're excited, like I said, being in the country, and we'll have to wait to see how that plays out and how we get more understanding of the base and the reservoir and how they can grow and how we're going to add value and what the returns are going to look like.

Do we have a sense of when we'll know if we're tracking towards that?

Yes. That -- from the history of EOG, we don't like to comment early. We like to go in and truly understand the basin back to that pace of play, investing in the asset, growing the asset at the right pace. So we don't want to get ahead of our learnings.

We don't want to go drill a few wells, get really excited and start projecting that out. We really want to take the time and be thoughtful, invest in the next well, and that will allow us to kind of gather enough information that we'll be able to disclose something.

Again, we have 3 years to declare commerciality. So I'll give you that as kind of the outlook. 3 years, we'll have to determine what we want to be. But again, we'll continue to look at our learnings. And when we're ready to kind of announce what we've captured there, we'll do so. You'll be the first to know.

All right. We'll do it here at this conference.

There you go.

There you go. One of the things that you've evolved, you and Ezra has evolved and as you stepped into the seat as well, is a willingness to be opportunistic with share repurchases, but also have a more level-loaded repurchase.

Sometimes there was frustration with EOG because you only buy back stock if the world was $30 a barrel and $30 a barrel, nobody buys back stock, right? So I think that's been a positive -- it's been positively received by the market. And so as you approach this year, you've been now averaging 100% free cash flow return to shareholders. should we anchor back towards that 70% to 100% range? How should we think that you can continue at the 100 pace post-Encino? Any comments on that?

Yes. The exciting thing is I love sitting in my position, we have a pristine balance sheet that's allowed us to return robust returns back to our shareholders. And we've been running, like you said, kind of a 90% to 100% for the past several years. And that's where I expect us to -- going forward kind of that 90% to 100% range.

Keep in mind, as we look at free cash flow and what we want to return, we start obviously with anchoring with that sustainable regular growing dividend it's at $4.08 indicated annual rate now, we haven't cut or suspended it in 27 years and really excited about, and it's offering a 3.9% yield, which is not only competitive against our peer group. That's competitive against the broader S&P.

So we start there kind of at that cash return. And then on top of that, we opportunistically look at share repurchases and/or special dividends. We've leaned more into the share repurchases because we think stock price has been attractive for us to go in, buy it back and really create long-term shareholder value.

The -- in all my years of being around EOG, I can really only remember you in the modern era of EOG Yates and now Encino generally been an organic story. Is that a fair assumption on the go forward? Or do you think there'll be more Yapes, more Encinos out there?

Yes. Just like you said, I've been here 30 years, and we've only done 2 corporate M&As. So I wouldn't sit there and think that we have an appetite for a large-scale M&A. The way we approach M&A, nothing has changed in our strategy there. It's a pretty high bar, pretty high hurdle rate for us to do any level of M&A, whether it's a large scale and certainly the smaller scale because it's -- since we're an organic company, a lot of times those come burden with higher costs.

So we have -- for us to even look at it, it's got to come with low F&D cost, has a low base decline. It's got to -- again, not some burden with all those costs. So that's kind of the best way to look at it. And so again, we think we're creating more value by doing organic. We've got a higher return on capital employed by going out and doing organic growth. And any M&A we do, we did one in the Eagle Ford in 2025.

And what it's got to do is immediately meet all our economic hurdles and then it has to compete with the portfolio. We want to bring it immediately into the portfolio. We're not going to do any M&A that we're going to turn around and sit on a shelf somewhere. So it's got to be kind of a hand in glove for us fit as Encino was as the Eagle Ford opportunity was. And again, we immediately put it into our operations and started actively being there. So nothing's changed on our approach to M&A.

Thank you, [ Yulia ]. Thank you. It's a great conversation, as always. It's a great pleasure to have you.

Thank you so much for having me. Thank you, [ Yulia ].

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

Thank you, Betsy. Good morning, and thank you for joining us for the EOG Resources Third Quarter 2025 Earnings Conference Call. An updated investor presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today.

As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings.

This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations section of EOG's website.

In addition, any reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines.

Participating on the call this morning are Ezra Yacob, Chairman and Chief Executive Officer; Jeff Leitzel, Chief Operating Officer; Ann Janssen, Chief Financial Officer; and Keith Trasko, Senior Vice President, Exploration and Production.

Here's Ezra.

Thanks, Pierce. Good morning, and thank you for joining us. It's been a significant quarter for EOG, 1 that marks both a pivotal strategic milestone and a disciplined continuation of our financial framework. As you know, we have successfully closed the acquisition of Encino in early August. This transaction strengthens our portfolio, cementing a third high-return foundational asset, diversing our production base and accelerating our free cash flow generation potential even during a more dynamic commodity environment. This acquisition was part of an exceptional quarter where EOG once again delivered outstanding operational performance that has translated directly into strong financial results.

For the third quarter of 2025, oil, natural gas and NGL volumes exceeded the midpoint of our guidance, while capital expenditures, cash operating costs and DD&A all came in below guidance midpoints, resulting in $1.4 billion of free cash flow, $1.5 billion in net income and $1 billion of cash returned to shareholders through our regular dividend and share repurchases.

Through the first 3 quarters of this year, we have committed to return nearly 90% of our estimated 2025 free cash flow, including $2.2 billion in regular dividends and $1.8 billion of share repurchases. In today's dynamic energy equity environment, share repurchases are especially compelling, and we expect to remain active in our buyback program, further enhancing returns to shareholders through the cycles.

EOG's value proposition is guided by our strategic priorities of capital discipline, operational excellence, sustainability and culture. Our continued outperformance this quarter and throughout the year demonstrates consistent execution of our value proposition by teams across EOG's premier multi-basin portfolio, while our cash return performance highlights our unwavering commitment to disciplined value creation for our shareholders through industry cycles. I want to highlight 4 key differentiators that set us apart and position EOG to deliver value to our shareholders in a dynamic market.

First, our diverse high-return portfolio with a deep inventory of opportunities. We invest at a pace that generates high returns while optimizing both short- and long-term free cash flow generation. Our foundational assets in the Delaware Basin, Eagle Ford and Utica continue to underpin our activity driving strong full cycle returns, while our emerging plays, Dorado and the Powder River Basin, are making tremendous progress on improving well performance and lowering costs. And our consistent focus on exploration, both domestically and internationally, gives us confidence in our ability to continue improving one of industry's highest quality portfolios.

We are especially excited about the potential for international unconventional development through our entry into the UAE and Bahrain. Our differentiated exposure to both North American liquids and natural gas as well as international unconventionals positions EOG to benefit from medium- and long-term growth in all 3 areas, creating multiple avenues for future value creation. Second, our focus on lowering breakeven costs. Each year, EOG utilizes data and technology to drive continuous operational improvements, capturing incremental efficiency gains and identifying opportunities to reduce our cost structure. In addition, at times, we make strategic infrastructure investments that further lower costs. In the past year, we've brought online the Janus gas processing plant in the Delaware Basin and the Verde natural gas pipeline connecting Dorado to the Agua Dulce Hub. These high-return strategic infrastructure projects helped further reduce our breakeven costs by enhancing reliability, lowering operating expenses and improving price realizations.

Operational execution and investment focused on improving our broader asset base not only strengthens our resilience in a lower price environment, but also improves margins and returns for shareholders through industry cycles.

Third, our commitment to generating sustainable free cash flow. Our low-cost structure drives robust, sustainable free cash flow generation supporting EOG's regular dividend as well as additional cash return to shareholders. EOG has generated annual free cash flow every year since 2016 and has never cut nor suspended its dividend in 27 years, a remarkable track record that is a testament to our resilient business model and represents a key differentiator versus peers. And fourth, EOG's financial strength. Our pristine balance sheet is anchored by a leverage target of less than 1x total debt to EBITDA at bottom cycle prices of $45 WTI, $2.50 Henry Hub. With nearly $5.5 billion in total liquidity, we have tremendous capacity and flexibility to invest through the cycle, ensuring EOG emerges from any downturn an even stronger company than when it entered.

On commodity fundamentals, the impact of spare capacity returning to the oil market is slowly becoming evident. We expect inventories to continue to build as it will take a few quarters for growing demand to absorb spare capacity barrels reentering the market. Beyond near-term oversupply, evolving geopolitical risk, the rapid decline in spare capacity, reduced investment in new supply and further demand growth will remain key drivers of the oil price. Looking past the few -- the next few quarters, we see constructive support for oil prices.

And turning to natural gas, our outlook remains positive. U.S. natural gas enjoys 2 structural bullish drivers, record levels of LNG feed gas demand and growing electricity demand, which should provide price support. Our investments to build a premier gas business has EOG poised to deliver supply into these growing markets.

Looking to 2026, it's too early to provide specifics on activity and capital spending. Our capital allocation remains driven by returns-focused investments, our view on the outlook for supply-demand fundamentals and a reinvestment pace that supports continuous improvement across our multi-basin portfolio. This disciplined approach allows for optimal development of our assets while balancing both short and long-term free cash flows to drive higher cash returns to shareholders.

2025 has truly been a transformative year for EOG with the successful acquisition of Encino as well as our strategic entries into the UAE and Bahrain. And moving into 2026, EOG is better positioned than ever to execute on our value proposition and create shareholder value.

Now here's Ann with a detailed review of our financial performance.

Thank you, Ezra. Ezra mentioned, the closing of the Encino acquisition in early August is a significant event for EOG. The acquisition enhances the foundation of our value proposition, sustainable value creation through industry cycles, and our financial strategy remains unchanged, a pristine balance sheet to support a sustainable growing regular dividend, disciplined investment in high-return inventory and significant cash return to shareholders. The third quarter is an excellent example of this strategy at work. We generated adjusted earnings per share of $2.71 and adjusted cash flow from operations per share of $5.57.

In the third quarter, free cash flow totaled $1.4 billion, and through the first 3 quarters of this year, EOG has generated $3.7 billion in free cash flow.

Regarding our balance sheet, following the funding of the Encino acquisition, we ended the quarter with a robust cash position of $3.5 billion and $7.7 billion in long-term debt. Our balance sheet continues to serve as a pillar of our financial strength.

Our leverage target of total debt at less than 1x EBITDA at bottom cycle prices remains one of the most stringent in the energy sector, and we continue to view our pristine balance sheet as a competitive advantage providing both protection in volatile markets and the ability to strategically invest through the cycles.

During the third quarter, we continued our history of significant cash returns to shareholders anchored by our robust regular dividend of nearly $550 million and supplemented by nearly $450 million in share repurchases, demonstrating our commitment to both sustainable and opportunistic cash returns.

For calendar year 2025, we have paid regular dividends of $3.95 per share, representing an 8% increase over calendar year 2024. On October 31, we paid our latest regular dividend, which was $1.02 per share, equating to an annualized rate of $4.08 per share or 3.9% dividend yield at the current share price. This dividend yield significantly exceeds the S&P 500.

Our sustainable and growing regular dividend forms the foundation of our cash return strategy. We also have other incremental levers such as share repurchases, providing an avenue for further cash return through industry cycles. Since initiating buybacks in 2023, we have repurchased nearly 50 million shares or approximately 9% of shares outstanding. We have ample flexibility for additional share buybacks and with $4 billion remaining under our current buyback authorization. In the past 5 years, we have returned over $20 billion to investors through a mix of dividends and share repurchases.

For the full year 2025, we are forecasting a $4.5 billion in free cash flow, a $200 million increase in annual free cash flow versus our previous forecast at the midpoint of guidance. This increase is driven by outstanding performance through the first 3 quarters of 2025 and strong fourth quarter guidance that leaves us well positioned entering 2026.

In summary, EOG delivered another outstanding quarter. We strengthened our portfolio, maintained the robustness of our balance sheet and positioned the company for sustainable value creation through commodity cycles. As we look forward to next year, we remain focused on what we can control: operational excellence, cost discipline and capital returns.

With that, I'll turn it over to Jeff for an update on operating results.

Thanks, Ann. First, I want to recognize the exceptional dedication of the entire EOG team. Consistent outstanding execution across every part of the organization is what enables us to convert our operational strengths into value for shareholders. We had another strong quarter of execution across the business. Our teams continue to deliver consistent results, meeting or exceeding expectations on nearly every operational metric, Production volumes outperformed, largely driven by stronger-than-expected base production performance in our Utica asset, while capital expenditures were below target, supporting strong free cash flow while keeping us on track for full year guidance.

Cash operating costs also came in under target, dominantly driven by reductions in lease operating expenses and GP&T across our foundational assets. These strong quarterly results reflect the quality of our assets and the continued discipline of our operating culture.

In the Utica, the Encino integration is progressing exceptionally well. I want to thank all of our employees, including new employees from Encino for their efforts in efficiently integrating this asset and fast tracking the execution of high-return development. We have excellent line of sight to realize our $150 million of synergies target within the first year and lower well costs being the primary driver. We are extending EOG's culture and multi-basin portfolio of learnings, innovation and technology transfer to the acquired assets with excellent outcomes thus far. By applying EOG's drilling and completions technical expertise across the acquired Encino acreage, we have already realized strong efficiency gains. As a result, we can maintain the same targeted 65 net well completions for 2025, while reducing our Utica rig count from 5 rigs down to 4 for the remainder of the year.

With respect to production, over 80% of the applicable Encino wells have been placed on artificial lift optimization. Moving forward, we anticipate continued efficiency gains and strong field performance as we implement EOG's operational best practices and our suite of proprietary software applications.

During the third quarter, EOG brought online our first well in the Utica gas windows. The Petkins wells each had an average 30-day IP of 35 million cubic feet per day. This was a 3-well package with average lateral lengths of just under 20,000 feet. Our focus in the Utica will remain on the volatile oil window, but we are extremely pleased with the potential upside from the Utica gas window over time.

Turning to the Delaware Basin. We are pleased with our recent well results, which are on forecast and in line with our development strategy. Our teams continue to drive operational improvements that are helping us to unlock additional value from this already prolific asset. Over the last several years, innovations like our EOG motor program, super zipper operations, high-intensity completions and production optimizers have allowed us to lower cost and improve returns across our acreage.

Throughout our core areas, we have built out our surface locations, facilities and gathering systems, and we'll be able to take advantage of this infrastructure when we return to these areas to continue development. Another major driver in well cost reductions has been longer laterals where we have increased our average lateral length by over 20% in 2025 alone. Overall, we have lowered well costs more than 15% over the last 2 years. Due to this positive step change in capital efficiency, we continue to evolve our development approach to balance returns with resource recovery. This has enabled our team to unlock additional distinct landing zones that now meet or exceed our stringent economic hurdle rates and increase our total recovery per section. We see outstanding economics on these new targets with payback periods of less than 1 year and direct well level rates of return across both shallow and deep targets in excess of 100% at current prices.

In the Eagle Ford, economics continue to improve even after 15-plus years of development. For our 2025 program, we have reduced our breakeven price by 10% due to extended lateral lengths and reductions in both well costs and operating costs.

Moving forward, we will continue to leverage technology and efficiency gains to drive strong returns and margin enhancement across the Eagle Ford play.

In Trinidad, we have completed the first wells of our Mento program and are extremely pleased with the initial results. For 2026, we plan to commence installation of the coconut platform, reflecting further investment in our high-return Trinidad program. Finally, we are advancing the barrel oil discovery towards FID with our partners and look forward to giving you an update in the near future.

In the Gulf states, our exploration programs are moving forward, and we are pleased with our progress. We drilled our initial wells in Bahrain in the third quarter and will spud our first well in the UAE this quarter. We are excited about these opportunities that allow us to leverage our technical expertise and extensive data set from drilling thousands of unconventional wells across a wide variety of plays. The opportunities in the UAE and Bahrain are just another example of EOG's focus on exploration as we continue to look for organic ways to improve and expand our inventory.

Regarding service costs, as industry activity has decreased in the second half of 2025, we are seeing some softening in the market. The majority of these decreases have been associated with non-high-spec equipment since these are the first to be released and become available. For the high-spec services that EOG utilizes, we have observed much more resilient pricing with utilization remaining high. We have just recently started seeing a low single-digit reduction in spot rigs for high-spec equipment, but this has largely been offset by the impact from tariffs, primarily on noncasing steel products. As we look to the future, we currently have around 45% of our service costs locked in for 2026, and we'll look for opportunities throughout the next few quarters to take advantage of any additional softening in the market.

Regardless of how service costs shake out, we remain focused on delivering sustainable efficiency gains year in and year out. After an outstanding third quarter, we are poised to finish 2025 strong and enter next year with tremendous momentum. Now I'll hand it back to Ezra to wrap up.

Thanks, Jeff. In closing, let me highlight a few key messages. First, this has been an exceptional quarter for EOG. We strengthened our portfolio with the successful completion of the Encino acquisition, maintain a robust balance sheet and further position the company for long-term value creation. Second, today's dynamic market environment is exactly what EOG is built to excel in. Our diversified portfolio enables ongoing investment in high-return projects, while our low breakeven costs drive strong free cash flow that supports both our regular dividend and additional shareholder returns. Our industry-leading balance sheet remains the cornerstone of our financial strategy, ensuring value creation through every phase of the cycle. Third, EOG holds a distinctive position in the upstream sector with access to a deep inventory of growth opportunities spanning North American liquids, North American natural gas and international conventional and unconventional plays.

Our continuous data collection and development of proprietary technology reinforce EOG's culture of innovation and exploration, keeping us at the forefront of industry advancement. And finally, this quarter's results highlight the enduring strength of EOG's value proposition, anchored in capital discipline, operational excellence, sustainability and a high-performing culture.

Thank you for your continued interest in EOG. we will now open the line for questions.

[Operator Instructions] The first question today comes from Neil Mehta with Goldman Sachs.

One macro, one micro question. So the macro, as you guys do really good macro work, especially given the analytical department that you set up a couple of years ago, it sounds like, on oil, you guys got a pretty cautious near-term view, but a more constructive medium-term view. And on gas as well, you had some comments. So could you just unpack it, maybe put some numbers behind your viewpoint because I know everything you say is backed up by some analytics here.

Yes, Neil, this is Ezra Yacob. That's a great question. I like how you phrased that, cautious, near-term constructive, medium and long term. I think broadly, even in spite of a lot of rather daily or weekly volatility. I don't know if that much has changed in our broad view since we discussed it last quarter. We continue to see fairly consistent and what I would call moderate demand growth for 2025 and continuing into 2026. The volatility earlier this year with uncertainty around potential tariffs has generally eased as that policy -- as those policies have become a bit more transparent. And what we see, as I spoke to in the opening remarks, driving near-term fundamentals is the spare capacity returning to the market rather -- the spare capacity return to the market is really causing concern more so than investment in significant new supply. And that's an important distinction because what we forecast with continued growth in demand is while the near term looks to be oversupplied, like you mentioned, we have a potential where you could rapidly see us move from an undersupplied environment into -- from an oversupplied environment in the near term to an undersupplied environment really in the medium term.

And it actually sets up for us that we end up being quite bullish when we look out longer term on the supply/demand balances for liquids in light of the reduction in spare capacity and the reduction in investment that you see right now. In combination with there's always going to be ongoing geopolitical risks. And then we also see a continued long runway for demand growth to continue. That's on the oil side.

On the natural gas side, as I mentioned in the opening remarks, again, we see 2025 as being kind of that inflection point, and it's playing out that way. Well, you do have storage approaching the 5-year -- really about 5%, I think, above the 5-year average. We are seeing the increase from LNG demand for feed gas, and we're really starting to see the increase in electrical demand continue. Our forecast has always been that kind of the back half of the decade, we'll end up seeing somewhere around a 4% to 6% compound annual growth rate. And I think you're starting to see a number of forecasts actually even exceed that range for North American gas demand.

Ezra, Good perspective as always. And then the follow-up is a little bit more micro. We recognize well data can be super noisy, but we've got -- there's been a lot of attention on the Delaware, in particular, and some of the third parties around productivity data coming in a little bit softer and that times up well with people getting concerned about Permian maturity around some of the wells. And so I wanted to give you an opportunity to address that directly and help potentially comfort the market around that risk.

Yes, Neil, this Jeff. And as we just talked about in our opening remarks, our Delaware Basin wells, they're performing just as we have them designed. And it's really just a continued evolution of our development strategy out there, which, ultimately, our team is fully focused on taking that asset and maximizing the value. The first thing that I tell you, the team's focused on is they're always looking to balance returns with maximizing NPV per acre and the overall recovery of the acreage. And what we've really seen over the last handful of years just through innovation and efficiency gains as we've really lowered the cost there in the Delaware and seen a big step change in our capital efficiency of the play. A couple of examples of that is, we've increased our lateral length this year alone 20%, which has really helped cost. And when you look at that cost reduction, we've had about 15% reduction over the last 2 years.

And then on top of that, through all of our core areas, we've been able to build out our infrastructure. And whenever we return to these sections, we're able to use that infrastructure for a benefit. So when I -- when you take all this and you add it all up, what we've been able to do is unlock additional unique landing zones there in the Delaware that they're meeting right now are stringent economic hurdle rates at bottom cycle pricing. And what I'd say about these zones is they're really very all the way up and down the stratigraphic column they kind of vary from area to area. But really, if you look at this kind of development progression, it's very similar to what we've done in other plays. I mean, take the Eagle Ford, for example. We lowered well costs there. We applied new completion technology, and we were really able to unlock additional resource in that play. And you're seeing the same thing out here in the Delaware.

And then the important thing to really take away with this is that these new targets have just outstanding economics. With payback periods, they're less than a year. And then at the direct well level rates of return, I mean, they're greater than 100% at current prices right now. So I'd say our teams are really excited about the progress they're making with the program, and they're going to continue to look for innovative ways to drive down cost, keep improving well performance and unlock as much resource as we can out there in the Delaware.

The next question comes from Steve Richardson with Evercore ISI.

Ezra, I was wondering if you could -- if we could talk a little bit about '26. I know you said explicitly, it's too early to talk about '26. But I was wondering maybe you could -- if we take fourth quarter CapEx, which is a number you just guided to and annualize that, I know there's a whole bunch of problems with that framework, but I was wondering if you could kind of talk about activity levels today and what that may look like as you roll forward or even just some of the considerations up down international, Utica after you've had it under your belt for 3 months? So just wondering if you could just kind of go around the portfolio and maybe just give us a sense of how you're thinking about things with the macro backdrop you just outlined.

Yes, Steve, thanks for the question. I know usually, there is a lot of pushback on using a fourth quarter number as a run rate. I actually think, in our case right now with where we see the macro environment, under the current macro environment, which I appreciate you prefacing with that, I actually think the Q4 run rate is probably a pretty good spot for everyone to start with, to be honest because as you said, some of the puts and takes -- now again, it is a dynamic market, so you've got a lot of potential for things that can change. But as we see the market going forward on the oil side being likely oversupplied for the next couple of quarters, maybe that turns over pretty quickly next year, maybe it pushes out a little bit further. But really, on the oil side, we see next year as we sit here today as really probably being no to low oil growth. And low oil growth would really mean that in the next few months, we're seeing maybe the potential for some oil supply to increase in the back half of the year. But right now, it's pretty difficult to see the market asking for increased supply in the front half of the year.

So I think no to low oil growth. We obviously are going to continue to invest in our gas play as we've talked about at Dorado, as we've talked about trying to build a premier gas company basically inside of EOG. We're ramping up our LNG commitments over the next few years. We continue to see, as I talked about at the beginning, kind of 2025 being an inflection point for North American gas demand. So I think continued investment in Dorado. And then we have continued investment in the international at a pretty similar pace to what we're doing today. We do have another platform under construction there in Trinidad, but we've had an active drilling campaign there for this year. And then with the Q4 number, we've actually started investing in both the UAE and Bahrain, and we'll have some consistent activity going there as well.

I think, again, with the purview or the asterisk that it is a dynamic environment, I think those are kind of the puts and takes, Steve, that I'd be looking at. And I think, like I said, the Q4 run rate is probably a pretty good starting point.

That's great. We won't hold you to it, but that's a really good starting point, fourth quarter times 4, it is. if maybe one, a little bit more on the asset side on the Utica, but I was wondering if you could talk about how you're thinking about oil gathering and market access there, the movement in what the assets on to your corporate differentials is meaningful. And I know you've got a number of ways to solve that, either third party or like you've done yourself in other instances. So I was wondering if you could talk about that and to the time line, which we could see something there?

Yes, Steve, this is Jeff. When we think about the oil markets up there, first off, there's plenty of market molecules. That is not the issue. Really, what we focus on up there is going to be the differentials. And as you actually alluded to, our premium oil differentials, they did narrow slightly since the Encino differentials were a little bit wider. And that's to be expected. Encino, on that acreage, we were really active in the volatile oil window and they were a little bit more active east of us, which tends to be a little bit more condensate related. So that's really where you're seeing the difference. And the way I look at it is with any play, over time and maturity, we'll be able to improve those oil differentials there, especially with the added scale from the overall acquisition.

The next question comes from Josh Silverstein with UBS.

Yes. pretty big drop in the overall cost guidance this quarter, $0.25 here. Can you just talk about the drivers of this? Was it a function of adding the Encino assets, and how we should kind of think about the costs looking forward into next year?

Yes, Josh, this is Jeff. Yes, it's kind of right across the whole board with our operating expenses. We're seeing really good performance. So on the LOE side, we had about a $0.10 beat for midpoint, and that was primarily driven by lower-than-expected workover costs and compression costs across the whole company in most of our assets. And then also, we did see a little bit lower offshore LOE in Trinidad than what we had forecasted.

On the GP&T side, we were about $0.20 below midpoint. And what that had to do with was our natural gas gathering and processing fees in the Eagle Ford and the Powder came in a little bit lower than expected, which was good. And then also with us only having about a week under our belts before the last call, we had a slight forecast variance in the Utica due to the Encino acquisition. So that came in a little bit less on GP&T. And then also everything else was looking pretty good. G&A was about $0.08 below midpoint. That was somewhat tied to the Encino acquisition there coming in under and then also DD&A came in under, which primarily it's related to a little bit better performance across the portfolio from an overall reserve standpoint and really good costs flowing through there to the pools.

Got it. And then just going to the balance sheet and shareholder return profile. Now that you post the Encino acquisition, how should we start thinking about the free cash flow allocation going into next year? Do you want to start trimming away at the debt that you guys have taken on? Do you want to build the cash balance up to that kind of $5 billion, $6 billion level? And then should we still be thinking maybe of that 70% plus of the free cash flow to shareholders?

Josh, this is Ezra. Yes, I think maybe I'll start with the last point there, that 70% commitment. Don't forget that is a minimum commitment. The reason we came out with that 70% commitment to free cash flow return to shareholders that it's durable throughout the cycle. But as you know, you've seen basically exceeded that in the last few years, been closer to about 90%. I think low -- maybe 92% of free cash flow returned to shareholders. Going forward, we love where our balance sheet is right now. Our total debt is right at our target of total debt versus EBITDA at bottom cycle prices at about 1x. And I think we're in a great spot with our cash position. As we talked about in the opening remarks with $5.5 billion of liquidity, it gives us a lot of opportunities to continue to invest throughout the cycle or look for small bolt-ons or other opportunities to build value for the shareholders.

I wouldn't say that it's a priority to continue to build that cash balance at all. I think as Ann mentioned in the opening remarks, right now, we actually see continued return of cash to shareholders through stock buybacks as being a pretty opportunistic avenue that we have in front of us, not only for EOG, but really for the entire sector right now.

The next question comes from Doug Leggate with Wolfe Research.

Ezra, I wonder if I could try and hit the inventory question. I know you haven't given a lot of updates today on that or sustaining capital for 2026, but my question is really more philosophical about how you think about managing the business. There's been a lot of focus, for example, on what is the Delaware inventory depth. You've already addressed that. But it kind of -- it's almost like folks are looking at, well, that means you can't sustain the production. So my question is, are you looking -- are you running the business to optimize production at basin levels? Or are you running the business to sustain portfolio free cash flow? And in other words, the interplay of a different basis. So that's my first question.

My follow-up is a quick one on exploration because obviously, you've stepped out into the international arena in certain areas. But our understanding is that EOG may be starting to build a position in Alaska. And my question is, what is your view of business development? Is Alaska part of your portfolio? What are your plans there in terms of incremental spending? And how should we think about that going forward?

Thanks, Doug. Yes, this is Ezra. I appreciate that you can get on. I know you're traveling a little bit. But listen, to start with the kind of the total portfolio and how I think about the business, multi-basin operations has always been a strategic advantage for us. We've got flexibility, diversity of rock types. We continue to collect data and learn about different reservoirs. It also puts us and gives us diversity of product mix and direct diverse access to different markets. And we've been able, as a first mover, to really put together a high-return inventory of over 12 billion barrels of equivalents as we've talked about. And so I think with that, combined with our low-cost structure, really gives us a significant runway to continuing generating free cash flow in a very sustainable manner. As I mentioned in the opening remarks, we've actually generated free cash flow 10 years in a row now through a couple of different cycles. And I think it also demonstrates not only the sustainability of that inventory, but also our consistent focus on ultimately capital discipline, the company's commitment to capital discipline.

Resource depth by play is part of what you're asking, and I'd say that's a really dynamic question. And Jeff addressed that with specifics to the Delaware Basin and the Eagle Ford example. Because as we continue to build infrastructure, lower well costs, we lower operating costs, and we continue to actually learn about the reservoir, the normal life cycle of any of these unconventional plays is that you'll unlock additional resources. We've seen it in the Bakken, the Eagle Ford, the Permian to a certain extent in the Powder River Basin. So as far as assigning a static number, the Permian, obviously, with its stacked play potential and the high level of landing zones is probably our top resource base. Utica and Eagle Ford, based on sheer size, obviously, are very strong as well.

And that said, we do have a slide in our deck that highlights the payout, the returns the cost of all 3 of those foundational assets. And that slide actually does take into consideration the current differentials as well between the Utica, the Delaware and the Eagle Ford. And what you see is really all the economics are quite similar at the basin level in terms of the economics, which directionally points to the free cash flow generation of the potential of all 3 basins being pretty similar. And again, it's why we see a long runway for sustainable free cash flow generation of the current inventory.

The way we think about the business is investing in each asset at the right pace, at the right time. Part of that is a function of our learnings, part of it is a function of our infrastructure, and part of it is a function of generating free cash flow, Doug. So we really think about the individual basins individually, and then we roll them up to the company level. And at the company level, of course, we end up viewing the macro environment and then are, like I said, committed to capital discipline and generating free cash flow.

Now on the second part of your question, Doug, as far as exploration, you know as well as anyone that exploration is really nothing new for EOG. It's long been, I'd say, a cornerstone of our strategy is to use data and technology like I just talked about, the continued to unlock reserves that are typically overlooked. We're not necessarily frontier basin type of a company, we've really built the majority of our inventory with the strategy of using data and technology to look for bypassed reserves. And in fact, we've done that. We've invested in exploration in the last few years, at times when really it's been a little bit unpopular, but we continue to see that as the best way to improve the quality of our asset base. And we think it's key to our high full-cycle returns and our lower breakeven.

So I think the takeaway really should be that we do have a pretty strong pipeline of projects that span the spectrum of from initial ideas to leasing, to initial wells, to maybe delineation wells. And so we feel very good about our exploration efforts. That being said, in the last 12 months, we have expanded our inventory pretty dramatically with the Utica acquisition. And I think our near-term focus really is continuing to integrate that asset, continuing to drive down our breakevens across all of our plays, especially in the Utica, continuing to invest in growing our Dorado asset. And then, of course, our investment in unlocking the potential that we see internationally in both the UAE and Bahrain.

And you confirm Alaska position?

No, Doug. As you know, you've been following us for a number of years, Doug, and it would be a first, if we actually started talking about individual exploration plays. So we'll just leave that one for some time in the future.

The next question comes from Leo Mariani with ROTH.

I appreciate you all comments on '26. It's certainly helpful here. Clearly, it sounds like on oil, a little concerned near term makes sense. On gas, obviously, there, it seems like you're quite bullish as we roll into 2026. So just curious there, do you view '26 as maybe the year really can step up Dorado activity a little bit to take advantage of that bullish outlook?

Yes, Leo, it's Ezra again. It's a good question. I will -- so we are bullish on gas. And part of the reason is because we have captured some markets to grow into. We see the electrical -- electricity demand has continued to grow. We're taking advantage of that right now really with our -- especially our capacity along Transco that delivers our gas into the Southeast Power demand pool. But also, obviously, our commitments on the LNG side are increasing. The biggest thing with gas, though, as we saw last year, if we just look at the last 12 months, I might be off on this just a little bit, but we really exited last year's injection season right around the 5-year high. And then within about 6 or 7 weeks, we were at a 5-year low on the 5-year range with respect to storage levels due to a pretty cold winter, but I wouldn't say anything exceptionally out of the ordinary. And I think it shows the volatility of gas because here we sit today with storage levels again, about 5% above that 5-year inventory level. A little bit of background, Leo, on the ultimate answer where I say our pace for Dorado kind of like I just finished up with Doug is ultimately going to be governed by keeping our full cycle returns high, which means continuing to develop that at an appropriate pace where we can keep our costs very, very low.

Now we've talked about before how there are a couple of step changes for costs in any of these unconventional plays. The first is when you can really command a rig full time. The second is when you can get to a frac spread full time. And yes, '26 will probably get pretty close to that. But like I said, there is a little bit of flexibility still in the plan that we baked in. Let's see how it plays out, let's see where winter goes, and really see how the LNG demand continues to increase, and that will kind of determine again our investment rate at Dorado.

Growth, again, ends up being an output of our ability to kind of invest in these plays -- each of these plays at the right pace to drive those returns.

Okay. I appreciate that. And then just wanted to jump over to Bahrain here. So it looks like you guys showed in your results a little bit of international gas production outside of Trinidad on the quarter. I know you drilled some wells in Bahrain in 3Q, like you said. So it sounds like there's some production on those wells. Just any kind of early time kind of read, are those wells kind of hitting or beating expectations at this point? What are you guys seeing there in Bahrain?

Yes. This is Keith. We're very excited about the positive momentum we have in the Gulf States. And in Bahrain, we have a full team operating there. We've been granted that exploration concession in the partnership with PAPCO. That did allow us to take over a handful of legacy producing wells. That's the gas volumes that you see reported here in the quarter. As far as the expectations for those over the production on those, those are the same wells that led us to want to get into the concession in the first place. So they are a little bit older wells. They were part of the robust data set that we had before entering the country. So they're a little bit older.

We have drilled our first few wells, first few new wells, and we're going to look to start completing them on this quarter. So we'll say we're gaining a better understanding on both the geology and the operations side in Bahrain. It's early days, but we're very excited about the opportunity here.

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

Ezra, you were clear that you'd be willing to obviously extend above 70% of shareholder returns, especially at the attractive valuation right now. Looking -- obviously, it looks like you've already done about 1 million -- at least 1 million shares of buybacks in the fourth quarter to date. What's your temperature on at this valuation to potentially push to 100% or even more this year? I mean how compelling is the valuation today versus, say, a year or 2 ago when you were closer to 100%?

Yes, Scott. Thanks for the question. We've definitely got the flexibility and the strength of the balance sheet that would support going to higher levels than the 70% minimum and really going to the higher levels of the the 92% that we've done in the past. Like I said, I think it's very compelling, not just for EOG, but really for all the sector. I think currently, energy is waiting is around 3% of the S&P 500. And so we see a large dislocation in valuations. And we see a large dislocation and valuation of EOG. And so I think it's a fantastic opportunity for us here. When we -- when you look at the near term, where it looks like there's the potential to -- for continued oversupply, spare capacity to be entering the market, we're focused on capital discipline and continuing to generate free cash flow. And at this point, like I said, building cash is not -- on the balance sheet is not a priority for us. Our balance sheet is in a very pristine state where we like it. And so there is opportunities to return close to 100%.

Okay. That's clear. And my follow-up, I think for you, Jeff. You mentioned obviously better base production performance in the Utica. Can you give us a little color on that? Was it some of the artificial lift efforts you did? Or was it just better performance of the reservoir as you all got into the Encino assets?

Yes, Scott, thanks for the question. And it's really kind of a magnitude of the whole integration. And really, over just a few months, we realized significant operational momentum just by putting all of our drilling completion and production expertise out there into the asset. So we talked about the efficiency gains we saw on the drilling side. So we're actually dropping down 1 rig going from 5 to 4. So we're seeing really good performance on the efficiency side there. And then over on the production side, I think we've implemented the high-intensity completion design there now with scale. So we're starting to see some benefit from all of that. And then as you alluded to, too, as far as some of the legacy wells, we've moved over the full 1,100 wells to the [indiscernible] suite of proprietary applications, and that includes 80% of them that are applicable wells, we've got them on the EOG artificial lift optimizers. So we're starting to see the uplift benefits from that.

And as you alluded to, that's part of the reason that we see the beat there in Q3 out of the Utica. So still have a long ways to go, though. There's still technologies that we can unveil. There are still things from the efficiency aspect. But we're doing really well there in the Utica, and we're realizing a lot of the synergies and the production uplift that we expected.

The next question comes from David Deckelbaum with TD Cowen.

I wanted to ask a little bit more about the optimization and lower operating costs. I think you cited lower workover expense for this year. And I'm curious is that really just specific to the integration that you're seeing in the Utica? Or is this broad based around, I guess, just better reservoir productivity? Or are you just seeing better responses from reservoir performance across your assets that requires less workover intervention?

Yes, David, this is Jeff. What I'd say is it's really across the whole portfolio. We're really seeing an improvement where we're focusing on where major failures are. So a lot of it is going to be with our data and our analytics, understanding where failures are in each 1 of these wellbores and the different artificial lift systems, and how to go ahead and alleviate those failures out of the front end. And then some of the additional technologies we actually talked about on our last call with some of these HiFi sensors where we're able to put it on subsurface and surface equipment, we're able to monitor vibrations and other data real time to understand when failures may happen or even understand prior to failure. So we're able to catch them and be able to minimize the overall expense. So I really think it's just a credit to all of our teams out there that they're not leaving any stone unturned. We're making sure we take all of our data and apply it to all of our wells that are producing to make sure that we're minimizing the downtime and really maximizing the overall production across the portfolio.

I appreciate that. And Ezra, just given some of the commentary, particularly around spare capacity dwindling in the ensuing years ahead, how do you put that in the context of your appetite for just expanding in the areas where you're at? Or overall, I guess, your appetite for trying to hoard as much resource as you can sort of in the next, call it, 12- to 24-months period, either through M&A or just trying to organically focus on expanding resource?

Yes, David, it's a great question. And downturns are a fantastic time to explore because, typically, a lot of companies, if companies are exploring in a downturn, that's 1 of the things that's typically easy. That's a program that's easy for them to pull back on and reduce. As far as the inorganic, I think at this point, small bolt-ons or really some of the more fundamental blocking and tackling of trades to continue to shore up our acreage position is what you should be expecting from us. The Encino acquisition was very reminiscent of the Yates acquisition, which we did 10 years ago now. It was a bit of a unicorn that came along in an emerging asset with hand in glove acreage positions and fit. It's a very, very high return prospect for us, and we got it at a price because it was really an emerging asset that made it very, very compelling.

Typically, in these emerging assets, you don't really have the opportunity to do something like that because as competition starts to see your well results, those prices -- those entry points, the price points really start to increase. And for us, we look at any of these opportunities, inorganic or organic, through a returns-focused lens. And so what I mean by that is any of our exploration opportunities really need to compete, and this calls back a little bit to Doug's question, it really needs to compete with the existing portfolio. We aren't really interested in just grabbing more inventory, quite frankly. We're continuing to have interest in expanding the quality of our inventory and continuing to improve the returns, really the full cycle returns that we can deliver to our shareholders.

The next question comes from Betty Jones with Barclays.

I wanted to ask about technology. EOG has always been on the forefront of integrating technology and big data. We're hearing a lot about AI models. So just want to get your take on the materiality of AI integration on your operations and exploration efforts and whatnot? And do you still see advantage of building these your capabilities in-house?

Yes. Betty, this is Ezra. AI at EOG, yes, we definitely see advantages and advantages -- significant advantages to building a lot of our proprietary apps and software developments in-house. -- typically because we couple them directly with the field operations, things like Jeff has talked about, I think, on the last call with regard to our our high-fidelity sensors, some of our downhole tools that we've got real-time measurement that's really making a big impact on the way that we operate and driving down costs.

I'd say, broadly speaking, AI, and you've heard it throughout this earnings season, everybody mentioned something on their call. So I think it's clear that AI really is transforming the entire industry, the oil and gas industry. And it really is happening, I'd say, at every stage of operation from, as you pointed out, exploration, throughout the field, including safety. And as you know, our journey has been maybe a little bit longer in the tooth than others. We started with smart technology really prior to COVID. And that's some of the technology that we put out on our centralized gas lift systems. I mean, we're coming up on almost 10 years of utilizing that, really, which really manages and optimizes the amount of injection gas versus the production that you're seeing out of it. And we've, since that time, developed some machine learning algorithms now that we utilize for, not only that production optimization, but for other aspects of our operations as well. And it's just recently that we've started to develop some of the deep learning tools where you're really collecting, organizing and using significantly more types of data, including human observation and experiences really experiential learning.

And so while we're not quite to true agentec intelligence, we are using quite a bit of generative AI, not only to organize geologic data and attempt to uncover hidden trends, but we've got real-time drilling optimization. We're improving efficiency and equipment reliability. We've got predictive maintenance, process optimization, really some autonomous operations going on in the field. And then like I said, maybe I'll just finish up on the safety side. Safety is crucial in oil and gas, and AI is definitely helping our efforts in that regard as well, helping to detect anomalies both on the emissions, spills and safety side throughout our different operation disciplines.

Great. That's very helpful color. A follow-up probably for Jeff. Just curious on the dry gas Utica well drilled, what was [indiscernible] to drill that well? And clearly, I see that as more as a dry gas option in the portfolio. So what would it take, whether market or price related to trigger that option?

Yes, Betty, this is Jeff. Yes, we're extremely excited about those Pekin's wells. As we said, they came on, each one had individual 30-day IPs of around 30 million a day. So very, very strong, and they actually -- those were wells that we acquired. So we just completed those wells and brought them on production. So they were already drilled when we acquired them. But what I'd say is we're excited about those results, but we also know we've got a multi-basin portfolio all around the country. So we have a lot of flexibility to take advantage all of the different markets. be very strategic in how we're maximizing our price realizations and netbacks. And in the Utica, as in-basin demand continues to increase and we get some additional pipeline capacities in there and built out, we feel like we'll be well positioned to take advantage of it. But ultimately, I mean, when we're talking about gas growth within the company, we have Dorado, which is the lowest cost gas in the U.S. It's located right next to the Gulf Coast market center. There's a growing LNG market, as you know, an increasing demand growth. We've got a 21Tcf resource down there. And we're just excited about the opportunities that gives the market.

So realistically, up in the Utica, as we said, we're going to focus on the volatile oil window. We have opportunities to grow the gas in the future there, but really with gas growth, I'd say our focus is on Dorado.

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

Yes. We appreciate everyone's time this morning, and I want to thank our shareholders for your continued support, and a special thanks to all of our employees and partners for delivering another outstanding quarter. Thank you.

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