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 of 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 three quarters, we've 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 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 supply has returned 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 five-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, 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 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 three-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 to 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 break-even oil prices. Our 2026 plan funds production growth, domestic and international exploration, and our regular dividend, all at a WTI break-even 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 30th, 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 one times 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 mi laterals continue to exceed our expectations, and during their first 30 days on artificial lift, have averaged stabilized production of 700 BOPD per well. Our operations are running smoothly as we focus on drilling and completing two-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 geosteering 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 two-thirds of that spending occurring in 2027.
Janus has added significant value since it has been online, delivering year-to-date netback uplifts 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 wells 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 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 BOE per day, including 2,000 BOPD . 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 other high-return assets and exploration prospects in our portfolio. With that, I will 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 1st. 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 as 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.
Thank you. The question-and-answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touch-tone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. You are allowed one question and one follow-up. We will take as many questions as time permits. Once again, please press star one on your touch-tone telephone to ask a question. To remove yourself from the queue, press star two. The first question today comes from Neil Mehta with Goldman Sachs. Please go ahead.
Hey, Ezra. Congratulations, Ann, and congratulations, Jeff, as well, as you take on this new role. A couple update questions for you guys. First is the long-term gas sales agreement that's been linked into JKM here. Ezra, can you spend some time talking about this and how mechanically it 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?
Yeah, Neil. Thanks for the question. It's Jeff Hibbard here. Maybe I'll start. The gas sales agreement announced with ENGIE provides additional pricing diversification for our gas volumes, with many similarities to our deal with Cheniere. 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- we increase exposure to premium prices, 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.
Yeah. Ezra and team, can you spend some time just talking about the M&A strategy here? Historically, this has been such an organic company. Of course, you've done Encino and Yates over the years. But as commodity prices eventually normalize, 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 of the 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.
The next question comes from Steve Richardson with Evercore. Please go ahead.
Hey, good morning. I was wondering if I could follow up on Jeff's comments about expectations for some positive 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 an inflationary environment, if you could?
Yeah, Steve, this is Jeff. Let me give you a little bit of color on it. So, 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 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.
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. 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. Just to give you a little bit more color, 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%-5% improvement in each year.
Next, we'll look to leverage our strong relationships with all of our service partners. 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 raising rates. 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 cost, 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. 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. 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 70% of our rigs we run off natural gas, 100% of our frac fleets also do too. 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. Thanks for the fulsome question. I was wondering if we could quickly follow up on natural gas markets. Understand the points 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. Appreciate you talking about Janus today on the processing side, but wondering if you could talk a little bit about 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. Yeah, at times in the past, especially at 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 cause us to step into that space. It's first, if we're unwilling to find a strong partner to be able to do that.
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. 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 Processing 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. Please go ahead.
Thank you, everybody. Good morning, Ezra, and congratulations to you, and especially on your balance sheet diligence. I am sure we will come back to that. Ezra, the earlier question from Neil was on inorganic growth and resource. I would 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 have now got your acreage position. What is your play concept? Any color you can offer on your recent permitting in Frio County around the Pearsall Shale in South Texas would be much appreciated. Thank you.
Yes, Doug, this is Ezra. Appreciate the question. Let us start with Alaska. We have 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 have got a good long runway. Those are 10-year leases in Alaska. 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 would say is, Alaska is undergoing, from industry's perspective, a bit of a 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 has got some amplitude support with that 2D data. It is a bit of a different formation than what is in Pikka and Willow. It is a little bit younger sands. It is Schrader Bluff 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 will be purchasing some 3D data as it becomes publicly available later next year, and we will reprocess that, and that will be kind of the next step in evaluating the prospect that we have. Then, going all the way down to South Texas for the Pearsall, that is a play that we have not really talked about yet.
As I think everybody knows, we have Pearsall exists underneath our entire Eagle Ford oil acreage position. But starting about two 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 have drilled a handful of wells there. It is in the oil window, maybe a bit more of a combo play. But the well production looks pretty good. We have captured probably about 100 locations there. 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 are 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? Thanks, Ezra. My follow-up is a quick one. It might be for you, it might be for Ann Janssen. It's really just the 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? Thanks.
Yeah, Doug, maybe I'll just give you the brief answer there. I mean, I think we think absolutely. It really comes down to our low breakevens and that 12 billion BOE of resource, in addition to the financial strength of the company. We test our dividend across multiple scenarios, including bottom cycle price assumptions down even below $45. So yeah, we feel very good about that dividend over the long term. In addition, I would just add, I feel like the regular dividend's 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's 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.
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. Please go ahead.
Yeah, good morning, and thanks for taking the question. You mentioned in the script that the three-year scenario should be the base case for next year. I guess after year one, how would you say you're tracking this? I mean, obviously, we can see the production guidance, but it is also on the capital operating cost side, plus just corporate with interest tax, given the stronger macro, since you are growing cash flow, free cash flow more than oil. Then just to stay on track into 2027, how much Utica or kind of elsewhere activity would you need to add to drive low single- digit growth for EOG?
Yeah, Phillip, this is Ezra. It is really a pretty consistent activity levels going forward. As Jeff said in the opening script, you can kind of start with a Q4 run rate, which means that activity level is pretty consistent. Of course, when you are looking at the CapEx, we do have the strategic infrastructure that we have 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 is 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 2026, but actually to position ourselves to be able to grow into 2027 as well.
With regards to the three-year scenario and where we are at here towards the end of year one, obviously in the first year, there has been a significant increase in the commodity price from what we had forecasted before. I think what we have is illustrated on a $60-$80 range over that three-year period, and year one is obviously coming in at current strip, somewhere right around $87 for the year one. 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 three-year scenario, really the only one would be that Janus would be on top of it. That was not originally in the three-year scenario.
That's a strategic option for us that at the top of the cycle feels like a great time to layer that in. For 2027, it's essentially a $200 million capital investment that we're planning for.
Okay, that's great to hear. This might also be contributing, but you noted in the script Permian well performance outperforming your expectations of steady year-on-year. We've probably all noticed this in the public data, but one thing that stood out to me was really across all your plays, 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've pursued operationally in 2026.
Yeah, good morning. This is Keith. I'll start with the Delaware. We're very pleased with how our Delaware Basin development's 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. The important thing is that we expect similar consistency in productivity going forward. 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. That's really driven by our ability to drive down costs, allowing us to add new target zones that meet the strict return hurdles and better maximize the value capture across the assets. We're really happy with the Delaware.
We expect consistent returns and cash flow for the next 10 years. 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. 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. As we take those learnings and iterate them, we've even been able to apply that back to our Eagle Ford oil as kind of a revision two and three and four, and 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. Please go ahead.
Yeah, thanks. If we could go back to where the Q&A started, and that's on the gas sales agreement. It's kind of a two-part question with that. Number one, the commercial terms, I understand there are a lot of confidentiality around it, but in this market that we've seen for the past nine months, how are you all able to get a contract like that done at this point? You see the economics a little bit different from the original ones. As you look going forward, how much exposure to these international markets do you want? Should we expect you guys continuing 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. 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. 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, 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. Yeah, I think you can continue to see us always looking at those going forward.
Appreciate that. If I could pivot to shareholder returns, 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, what, $1.5 billion to maybe $1.6 billion that needs to get done through the balance of the year. That seems like a lot. Given the volatility in commodity prices, how do you manage hitting that annual threshold when we're coming up on to the end of the year?
Yeah. 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. 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. 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. Please go ahead.
Hey, good morning. 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?
Yeah, Leo, this is Jeff. You can actually see in our guidance, we did guide towards a little bit of volumes, but it's 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. 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. Just wanted to also ask, obviously you announced a new gas sales agreement today. Clearly made a commitment to expanding the Janus plant. Could 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?
Hey, Leo, this is Ezra. I wouldn't say that EOG's making a big pivot to gas or a big call on gas. I mean, 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. Please go ahead.
Yeah, good morning, team. Your fourth quarter guide included better realizations than we are modeling. Clearly, on the gas side, the Cheniere contract has been a nice tailwind. I was wondering if you could elaborate on how you are capturing the premium realizations on the oil side. I know you have dock capacity, but maybe walk us through the marketing and how you are able to capture that premium relative to WTI.
Hey, Arun, this is Jeff Leitzell. So yeah, great question, and really, I would break it down into a couple different things. I mean, the first thing is just the way that our marketing team is just so ingrained in the business. They are in each one of our divisions. They are 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 is one, and that is one of the reasons you have always seen our price realizations throughout time really out kind of run the peers. Then the second thing on that, which has really been a big mover here as of recent, is our exports. We have talked about on previous calls, we are exporting anywhere from 200,000 bbl- 250,000 bbl .
Obviously, with the premiums that we are seeing overseas and stuff with those barrels, it is really helping our overall price realizations and netbacks from that aspect. So, really, it is just great work by our marketing team, kind of staying ahead of things and making sure we have got a lot of flexibility to send those molecules to the best markets.
Great. My follow-up is, Ezra, I would 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 where doing a lot of small transactions, extending lateral lengths and things like that. But I would love to hear some insights on how you are thinking about bolstering your Delaware Basin inventory position to offset wells that you drill and complete.
Yeah, good morning. 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 just 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. We see a lot of it just on the acreage that we already have. Our co-development strategy leverages all that deep knowledge of basin geology.
We've identified up to 17+ unique targets, and our operational capabilities to develop them maintain the strong productivity and low cost. That has really allowed us to maximize the value of the asset, be the leading Delaware Basin operator in terms of well costs and break-even price, and have that durable inventory associated with it as well.
The next question comes from Bob Brackett with Bernstein Research. Please go ahead.
Good morning. You've intrigued us around declarations of commerciality for the Al Dhafra 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.
Yeah, 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. Then essentially annual reviews are typically how these international agreements work. 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 two wells, as highlighted previously. They responded very, very well to the artificial lift. 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.
Quite frankly, with the efforts that we've seen, the conversations we've had with oil field service partners and their level of engagement to enter the country, at this point, I'd say I'd reiterate what Keith said before, is that we're well on our way to targeting a DOC, probably long before the expiration of the exploration agreement.
Fascinating. Follow-up would be, that field development plan, that's where you would finally sort of lock down CapEx, how many rigs you're going 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.
We've highlighted whenever we talk about going 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. 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 a field development plan. Yeah, you should expect, as I've talked about it before, we've got great partners between Bapco and ADNOC.
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 Kev MacCurdy with Pickering Energy Partners. Please go ahead.
Hey, good morning. 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 areas that are not getting a lot of capital. 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. 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 non-core positions that 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 five or 10 years, we've divested several assets, including our legacy positions in the Marcellus, in China, U.K. North Sea, among others. 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. 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 assets in several different basins there. Are there any opportunities that you see that maybe 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. 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?
Yeah, Kevin. 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.
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. 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.
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. Please go ahead.
Yeah, thanks. Good morning, guys. 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.
Yeah, 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 have the ability to serve power generators, power generations 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.
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 am just curious to get an update on that front too.
Yeah, Josh, this is Jeff. Everything does still look good on the gas processing side up there. We have plenty of capacity, and like we said, we are over in that liquid-rich window. So obviously, any of the residue-associated gas has a lot of that liquid-rich molecules in it that they are really looking forward to grab ahold of. On the oil side, yeah, we continue to have really constructive conversations. As I have stated, for the next handful of years, we have got really good oil takeaway, but we are going to focus on really focusing getting our netbacks up. As we said, we have got a little bit of a differential there, so there is a couple 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 will continue to get it onto pipe to try to get to additional markets. Like I said, we are having really constructive conversations, but really nothing to announce right now, but we will 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.
Appreciate it. Would 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.