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.
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.
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