EOG Resources 2026年第三季法說會：產量創新高，股利調升 8%

重點摘要

• EOG Resources 公布 2026 年第三季調整後每股盈餘 (EPS) 為 4.87 美元，來自營運的調整後每股現金流為 7.23 美元，自由現金流達 22 億美元。
• 原油、天然氣凝析液 (NGL) 及天然氣產量均創下歷史新高，且超越公司財測中位數。每單位現金營運成本以及折舊、折耗及攤銷 (DD&A) 均低於財測中位數。
• EOG 向股東回饋超過 15 億美元，包括約 5.4 億美元的常態股利及 10 億美元的股票買回。
• 該公司將 2027 年預計年度股利調升 8% 至每股 4.40 美元。管理層仍預期將 2026 年自由現金流的至少 70% 回饋給股東。
• 2026 全年財測維持不變，預估原油產量成長 5%、總產量成長 14%，資本支出為 65 億美元。
• 管理層預期，若當前原油供需基本面持續，2027 年原油產量將呈現低個位數成長。

核心財務數據

EOG 表示，其 2026 年計畫在 WTI 損益平衡點低於每桶 50 美元的水準下，即可支應產量成長、國內外探勘及常態股利所需資金。在週期底部假設（WTI 每桶 45 美元、Henry Hub 2.50 美元）下，該公司目標將總負債維持在 EBITDA 的 1 倍以下。

業務與營運表現

德拉瓦盆地（Delaware Basin）仍是核心營運驅動力。EOG 指出每英尺油井成本低於 710 美元，並表示 2026 年油井生產力與 2025 年持平至微幅提升。在多達 17 個以上已確認目標層的支撐下，管理層預期該資產將帶來穩定的生產力與回報。

EOG 批准了 Janus 天然氣處理廠的擴建案，該廠處理能力將翻倍至每日 6 億立方英尺，預計於 2028 年下半年完工。該專案預計耗資約 3 億美元，其中三分之二的支出安排在 2027 年。管理層預期投資報酬率將超過 30%。現有處理廠今年以來的產能利用率超過 99%，帶來每千立方英尺 (Mcf) 超過 0.65 美元的淨回值增益。

在尤蒂卡（Utica），相較於 2025 年上半年，每日鑽井英尺數提升 24%，每日完井水平段英尺數增加 14%。每英尺油井成本低於 600 美元。俄亥俄州盆地內的一處砂礦預計於年底前投產，每口井可節省超過 30 萬美元。

在伊格佛特（Eagle Ford），每英尺油井成本低於 525 美元，每日鑽井英尺數較 2025 年成長 4%，每日完井水平段英尺數成長 15%。在多拉多（Dorado），平均水平段長度年增 16%，每英尺油井成本低於 700 美元，且 Verde 天然氣管線今年以來貢獻了每千立方英尺 (Mcf) 0.50 美元的淨回值增益。

在阿聯酋，EOG 最初兩口一英里水平井在採用人工舉升的前 30 天內，單井平均穩定日產量為 700 桶原油。該公司目前仍處於探勘與評估階段，正評估約 90 萬英畝特許權區的商業可行性。

EOG 以總計 4 億美元出售其傳統的巴奈特（Barnett）與伍德福德（Woodford）資產。這些資產第三季日產量為 1.6 萬桶油當量，其中包括每日 2,000 桶原油。該公司表示，在資產出售後仍能達成其年度產量財測。

天然氣與行銷策略

EOG 與 Engie 簽署了一項為期 10 年的天然氣供應協議，每日供應 14 萬 MMBtu，價格與 JKM 定價掛鉤並扣除合約約定扣減金額。該協議預計於 2030 年前生效，交割地點位於美國墨西哥灣沿岸。

該合約將使 EOG 截至 2030 年與液化天然氣 (LNG) 進料氣相關的供應量提升至每日超過 10 億立方英尺 (Bcf)。管理層表示，墨西哥灣沿岸的交割地點為多個盆地提供了氣源靈活性。第三季天然氣實現價格為 3.73 美元。

該公司也正與資料中心、超大規模雲端業者及發電業者洽談潛在供應安排。管理層形容天然氣是 EOG 低成本投資組合的紀律性延伸，而非全面脫離石油業務的重大轉向。

原油行銷亦支撐了實現價格。EOG 目前每日出口約 20 萬至 25 萬桶原油，使該公司得以進軍溢價更高、淨回值更佳的市場。

管理層財測

邁入 2027 年，EOG 預期營運活動將保持相對平穩，僅需漸進式增加投入即可支撐低個位數的原油產量成長。管理層表示，Janus 的支出將額外計入先前公布的三年情境規劃資本假設中。

該公司已簽約鎖定約 60% 的 2027 年服務需求，並確保了約半數的 2027 年套管與油管需求。EOG 預期每年約 3% 至 5% 的營運效率提升將有助於抵銷通膨壓力。

風險與關注領域

• 伊朗衝突爆發後，油田服務市場趨緊，導致高規格設備價格上漲。鋼材與柴油成本亦居高不下。
• 由於衝突持續，巴林的營運作業仍處於斷續狀態，員工與承包商的安全優先於產井成果的時程。
• 中東原油出口的復甦仍容易受到干擾中斷。儘管管理層對市場基本面持建設性看法，但仍預期油價將持續波動。
• 阿聯酋特許權區仍處於評估階段。商業可行性取決於進一步鑽井、著陸層測試、流體成分確認、人工舉升評估以及更長期的油井產能表現。
• 皮爾索爾（Pearsall）的開採機會包含約 100 個已確認井位，但管理層表示成本仍需降低，這些油井才能與 EOG 的核心儲備競爭。

分析師問答重點

管理層表示，企業併購的優先順序仍低於有機探勘及小型補強型收購。EOG 依然偏好能夠增加鑽井儲備的收購，而非單純承接大量既有產量。

在股東回饋方面，管理層重申有信心達成至少回饋 70% 年度自由現金流的門檻。在常態股利發放後，該公司預期股票買回仍是額外現金分配的首選途徑，並表示市場交易流動性應足以支持其完成所需的庫藏股買回。

EOG 將德拉瓦、尤蒂卡、多拉多及伊格佛特油井生產力的提升，歸功於成本降低、高強度完井、額外馬力投入以及持續的反覆測試。管理層預期德拉瓦盆地在未來 10 年內將帶來穩定的回報與現金流。

在阿拉斯加方面，EOG 將其探勘遠景描述為針對古新世 Schrader 砂層的傳統原油開採機會。該公司計劃在 2027 年稍晚 3D 震測資料公開後購買並重新處理該數據。

管理層表示，基礎設施投資將維持審慎挑選。EOG 通常偏好與第三方夥伴合作，但在產能受限或費用結構創造出具吸引力的機會時可能會直接投資，例如 Janus 擴建案。

完整財報電話會議逐字稿

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完整財報電話會議逐字稿

管理層陳述

Operator

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.

Pearce Hammond

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

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

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

Here's Ezra.

Ezra Yacob

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Ann Janssen

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

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

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

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

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

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

Jeffrey Leitzell

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Ezra Yacob

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

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

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

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

Pearce Hammond

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

Operator

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

分析師問答

Neil Mehta

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

Jeffrey Hibbard

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

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

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

Neil Mehta

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

Ezra Yacob

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

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

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

Operator

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

Stephen Richardson

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

Jeffrey Leitzell

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

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

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

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

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

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

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

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

Stephen Richardson

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

Ezra Yacob

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

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

Operator

The next question comes from Doug Leggate with Wolfe.

Douglas George Blyth Leggate

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

Ezra Yacob

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

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

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

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

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

Douglas George Blyth Leggate

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

Unknown Executive

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

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

Operator

The next question comes from Phillip Jungwirth with BMO.

Phillip Jungwirth

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

Ezra Yacob

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

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

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

Phillip Jungwirth

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

Keith Trasko

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

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

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

Operator

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

Scott Hanold

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

Jeffrey Hibbard

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

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

Scott Hanold

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

Jeffrey Hibbard

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

Operator

The next question comes from Leo Mariani with ROTH.

Leo Mariani

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

Jeffrey Leitzell

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

Leo Mariani

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

Ezra Yacob

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

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

Operator

The next question comes from Arun Jayaram with JPMorgan.

Arun Jayaram

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

Jeffrey Leitzell

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

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

Arun Jayaram

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

Keith Trasko

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

Operator

The next question comes from Bob Brackett with Bernstein Research.

Bob Brackett

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

Ezra Yacob

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

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

Bob Brackett

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

Ezra Yacob

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

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

Operator

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

Kevin MacCurdy

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

Jeffrey Hibbard

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

Kevin MacCurdy

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

Ezra Yacob

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

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

Operator

The next question comes from Josh Silverstein with UBS.

Joshua Silverstein

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.

Ezra Yacob

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

Joshua Silverstein

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

Jeffrey Leitzell

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

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

Operator

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

Ezra Yacob

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

Operator

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