APA (APA) Q4 2025 Earnings Call Transcript

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DATE

Thursday, Feb. 26, 2026 at 11 a.m. ET

CALL PARTICIPANTS

• Chief Executive Officer — John J. Christmann
• President & Chief Financial Officer — Stephen J. Riney
• Executive Vice President, Development — Ben C. Rodgers
• Executive Vice President, Exploration — Tracey K. Henderson

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TAKEAWAYS

• GAAP net income -- $279 million, or $0.79 per diluted share, including non-core items.
• Adjusted net income -- $324 million, or $0.91 per diluted share, excluding non-cash impairments, unrealized hedge losses, and a gain on decommissioning contingency.
• Free cash flow [Q4] -- $425 million, with $154 million returned to shareholders.
• Free cash flow [full year] -- More than $1 billion, with 63% returned via dividends and share repurchases.
• Net debt -- Ended just below $4 billion, down approximately $1.4 billion from the prior year through free cash flow, asset sales, and Egyptian payments.
• Interest expense -- Approximately $80 million lower than 2024.
• Permian production -- Oil volumes significantly exceeded guidance in Q4 due to incremental completions, improved runtime, and milder weather.
• Egypt gas production -- Gross production of 501 million cubic feet per day, below guidance due to unplanned pipeline disruptions; operations have since normalized.
• Proved reserves -- Increased by about 9% year over year, surpassing one billion barrels of oil equivalent.
• Reserve replacement ratio -- All-in ratio exceeded 160% for 2025.
• Cost savings [2025] -- Exceeded $300 million, with a $350 million run-rate achieved two years ahead of plan.
• Planned cost reductions [2026] -- Expect $200 million lower controllable spend, half from incremental savings and half from reduced Permian activity, with sustainable margin benefits projected into 2027.
• Permian capital [2026] -- Targeting $1.2 billion for development and $100 million for base capital projects, totaling $1.3 billion; base capital intended to reduce LOE and improve uptime, with six- to twenty-four-month paybacks.
• Decommissioning & asset retirement spend [2026] -- Anticipated gross spend of $280 million, netting to $225 million after tax benefits.
• Oil & gas trading income [2026] -- Forecast pretax income of $650 million, with cumulative pre-tax trading income from 2020 through year-end 2025 reaching nearly $2 billion.
• Permian economic inventory -- About one thousand seven hundred gross locations classified as economic inventory, requiring at least a 10% rate of return on current cost structure with high production confidence.
• Technical upside inventory -- Roughly one thousand seven hundred additional locations categorized as technical upside, with around two-thirds in the Delaware Basin and the majority of potential in shallow zones.
• Development & completion costs [Permian] -- Drilling and completion costs averaged $595 per lateral foot in Midland Basin and $750 per foot in Delaware Basin during 2025; at the end of 2025, costs were under $500 per lateral foot in Midland and under $700 per foot in Delaware Basin.
• Grand Moergue development [Suriname] -- $230 million budgeted for 2026 covering FPSO, development drilling, and infrastructure; development drilling initiates late 2026 to early 2027 using multiple rigs.

SUMMARY

APA Corporation (NASDAQ:APA) reported a year of significant operational and financial progress, highlighted by a reduction in net debt of $1.4 billion and a run-rate cost savings of $350 million achieved two years ahead of schedule. Management emphasized the durability of the Permian inventory, with a clear distinction between economic and technical upside locations, and outlined a disciplined capital allocation strategy that prioritizes both shareholder returns and long-term asset development. The company’s Egypt portfolio is being high-graded through strategic exits from non-core concessions, and the Grand Moergue project in Suriname is positioned for a step-change in free cash flow beginning in 2028. Oil and gas trading income is expected to remain a meaningful contributor through 2028, though management anticipates some moderation as new Permian pipeline capacity comes online.

• The Egypt portfolio is being high-graded through strategic exits from non-core concessions, aiming to concentrate capital on core acreage benefiting from improved gas pricing frameworks.
• Gross oil production in Egypt is expected to slightly decline as gas-directed drilling increases, although gross BOEs and total gas volumes are forecast to rise marginally.
• Management stated, "We improved capital efficiency and increased confidence in long-term performance, strengthened the depth and quality of our inventory, and we are confident we can sustain oil production volumes for at least the next ten years, with meaningful potential to extend that further."
• Anticipated decommissioning and asset retirement obligations in 2026 will rise to $280 million (gross), with North Sea activity offsetting lower Gulf of Mexico spend and 40% tax offsets in the U.K.
• Planned Permian appraisal and spacing tests may convert a substantial portion of the one thousand seven hundred technical upside locations to economic inventory, representing as much as a year's worth of future drilling if successful.
• Ongoing cost reductions are expected to lower controllable spend by another $200 million in 2026, half through continued efficiency improvements and half via reduced Permian activity levels.
• Grand Moergue in Suriname will deploy $230 million toward FPSO and development activities, positioning for a step-change in free cash flow contribution starting in 2028.
• Oil and gas trading performance is seen as sustainable through 2028, with potential moderation in 2027 as new Permian pipeline capacity affects spread-based earnings.

INDUSTRY GLOSSARY

• LOE (Lease Operating Expense): Ongoing expenditures required to operate and maintain oil and gas properties, exclusive of drilling and capital investments.
• FPSO (Floating Production, Storage, and Offloading vessel): A ship used in offshore oil fields to process and store hydrocarbons prior to tanker loading or pipeline transfer.
• DSU (Drilling Spacing Unit): A regulatory unit designating the area assigned to a well or group of wells for resource development and spacing compliance.
• TIL (Turn-in-Line): A well that is completed and connected for production.
• EGPC (Egyptian General Petroleum Corporation): Egypt's state oil company, APA's partner in Western Desert operations and gas price frameworks.

Full Conference Call Transcript

John J. Christmann: We have enhanced returns through disciplined capital allocation and significant efficiency gains while building depth and durability in our inventory, which is expected to sustain oil production and deliver competitive capital efficiency for the next decade. In Egypt, we continue to strengthen asset durability through both commercial and operational initiatives. This includes a focused gas strategy supported by an improved pricing framework that complements our established oil base. Our high-quality development and near-field exploration program is expected to drive gas growth and support a strong long-term outlook. Together, the strength of these base businesses forms the foundation for sustained free cash flow generation.

In the Permian, the addition of Suriname starting in 2028 will provide a meaningful step change and continued growth in free cash flow for the next several years, through at least the early 2030s. The Permian Basin is APA Corporation’s foundational asset. It is our largest source of both production and free cash flow, and it consistently attracts the largest amount of capital. One of our strategic objectives is to build and grow a high-quality portfolio of assets. We have made great progress on this over the past two years, and our momentum has been evident over the last several quarters. I will now turn it over to Stephen J. Riney, who will provide more details.

Stephen J. Riney: Thank you, John. It is our largest source of both production and free cash flow, and it consistently attracts the largest amount of capital. One of our strategic objectives is to build and grow a high-quality portfolio of assets, and we have made great progress on this over the past two years. That progress can be summarized in three key efforts: portfolio actions, cost structure improvements, and refining our development approach. So let us take a quick look at each of these three key efforts. Throughout my remarks, I will reference slides from our financial and operational supplement, which is available on our website.

In terms of portfolio actions, we have high-graded our Permian asset base, leveraging scale and localized knowledge to maximize economic inventory. Acreage held by production provides significant flexibility in the pacing of activity and enables economies of scale in our operations. Beginning in 2024, our position is now concentrated in a few key areas. Turning to our progress on the cost side, the successful delivery of Callon synergies significantly lowered breakeven oil prices from what Callon experienced in 2023. In 2025, we made further strides in drilling, completions, equipping, and facilities costs on a per lateral foot basis.

As shown on page 11 of our supplement, our current drilling and completion costs average $595 per foot in the Midland Basin and $750 per foot in the Delaware Basin. These costs reflect a mix of landing zone depths and compare very favorably to both public and private peers. We have also significantly reduced facilities costs as we have moved to more brownfield expansions. Finally, our development approach has historically involved wider well spacing with larger completions. That approach drove very strong per-well productivity. However, as our cost structure improved, it enabled us to drill more wells on tighter spacing and to moderate completion intensity. Increasing density accesses economies of scale and enables more economic inventory.

There is a reinforcing mechanism at play here as well. Lower cost enables more dense development, and economies of scale reduce costs even further. Taken together, these three efforts—portfolio actions, cost structure improvements, and a refined development approach—have significantly improved both the quantum and the quality of our economic drillable inventory. Importantly, these are not temporal improvements resulting from macro drivers. These are sustainable improvements, and we expect to see more in the future. Before I dive into the details of Permian inventory, let me share our perspective on how we classify locations. Every location or opportunity in our Permian portfolio falls into one of three categories: economic inventory, technical upside, and prospective leads.

The first category is what we call economic inventory. On page 12 of the supplement, you will find a skyline plot of how we currently view Permian economic inventory. This includes only operated locations expected to generate at least a 10% rate of return. At this point in the characterization process, there are two factors driving a naturally conservative outcome. First, this is entirely based on our current cost structure, assuming no future efficiency gains or technology improvements. Secondly, we reduce location counts where further appraisal or delineation is required until they are further derisked. There has to be a high level of confidence in the production forecast to be included in economic inventory.

We currently carry around 1,700 locations in economic inventory, which is a baseline that we will continue to refine and build upon. We are confident this will continue to improve both in quantity and in quality through advances in resource understanding, technology, and capital and operational efficiencies. We refer to the second category of location as technical upside. Technical upside represents locations in established or emerging Permian Basin plays that we believe will be the next subset of locations to progress to economic inventory. As you will see on page 13 of the supplement, we believe there is significant technical upside potential, with the vast majority in shallow landing zones.

Continued delineation success and ongoing efficiency gains remain key drivers for advancing these locations into economic inventory. Approximately two-thirds of our technical upside today is in the Delaware Basin. There has been significant activity in these zones in the Northern Texas Delaware, and we have recently drilled two first Bone Spring wells in Ward County. While there has not been much industry activity that far south, early performance is promising. Therefore, we are planning a four-well appraisal test later this year. Opportunities like this are largely unrepresented in our economic inventory, but this appraisal could advance a full year of drilling activity from technical upside into economic inventory.

The best part of having this much upside in the shallow zones is this should be some of the lowest-cost development in the Delaware Basin. With less geologic complexity and a longer track record of development, our subsurface understanding is much more advanced in the Midland Basin. Despite this, we continue to see technical upside through spacing refinement and further delineation of both established and emerging zones, with roughly half of this technical upside residing in the deeper benches. For example, there has been extensive industry activity in the Barnett in Western Midland County. By comparison, in areas like Upton County, there has been very little Barnett activity.

In our view, this reflects a need for further appraisal, not a lack of prospectivity. As a result, the vast majority of our DSUs carry Barnett locations only as technical upside. In aggregate, we have roughly 1,700 additional locations within our technical upside. The boundary between economic inventory and technical upside is not a function of economics, but of technical maturity. As these opportunities advance, we expect many to compete favorably with the economic inventory illustrated in the skyline plot on page 12. It is equally important to understand we have not attempted to characterize all potential locations in the first two categories. The third category—prospective leads—are those which we have not yet characterized at all.

These opportunities are not currently included in our technical upside. They carry subsurface or completion-related risk and have limited or no historical development. As the basin continues to mature, with improving economics and lower breakeven prices, we believe the future will bring more locations from technical upside into economic inventory. Some of these leads may underpin future upside. As we see things today, the scale of the technical upside characterized in actual location counts is at least as large as the economic inventory we are presenting today. Our Permian position is anchored by a long runway of inventory that is largely held by production.

We improved capital efficiency and increased confidence in long-term performance, strengthened the depth and quality of our inventory, and we are confident we can sustain oil production volumes for at least the next ten years, with meaningful potential to extend that further. With a sustainably improved cost structure and a competitive development approach, the Permian is well positioned to underpin robust free cash flow generation for the company for the next decade and beyond. I will now turn the call over to Ben C. Rodgers.

Ben C. Rodgers: Thank you, Stephen. For the fourth quarter, under generally accepted accounting principles, APA Corporation reported consolidated net income of $279,000,000, or $0.79 per diluted common share. Consistent with prior periods, these results include items that are outside of core earnings. Excluding these and other small items, adjusted net income for the fourth quarter was $324,000,000, or $0.91 per diluted share. The most significant after-tax items impacting adjusted earnings include $36,000,000 of non-cash impairments, $29,000,000 for unrealized losses on hedges, offset by a $47,000,000 gain on our decommissioning contingency. APA generated $425,000,000 of free cash flow in the fourth quarter, of which $154,000,000 was returned to shareholders.

For the full year, free cash flow was more than $1,000,000,000, and APA returned 63% to shareholders through both common dividends and share repurchases. Permian oil production significantly exceeded our fourth-quarter guidance, primarily driven by incremental completion activity, improved runtime, and milder-than-normal weather. In 2026, we have already experienced 3,000 barrels per day of weather-related downtime, which is reflected in our guidance. In Egypt, gross gas production of 501 million cubic feet per day was below guidance due to unplanned temporary pipeline disruptions late in the quarter. This was remediated, and operations have since resumed to normal.

Net debt ended the year just below $4,000,000,000, down approximately $1,400,000,000 from year-end 2024 through a combination of free cash flow generation, asset sales, and payments from Egypt. This progress brings us closer to our long-term net debt target of $3,000,000,000. Additionally, interest expense was approximately $80,000,000 lower compared to 2024. Wrapping up 2025, our proved reserves increased approximately 9% year over year, surpassing 1,000,000,000 barrels of oil equivalent, underscoring the quality of our inventory and the capital efficiency of our development program. Our all-in reserve replacement ratio exceeded 160% for the year. Turning to our cost reduction initiatives, 2025 marked a year of remarkable progress across the entire company.

We captured over $300,000,000 of savings and exited the year at a $350,000,000 run rate, achieving our original target two years ahead of schedule. This reduction in controllable spend improved margins, expanded free cash flow, and strengthened the resilience of our base business. For 2026, as outlined on page 7 of the supplement, we expect controllable spend to decline by another $200,000,000. Only half of this reduction is incremental savings, with the remainder driven by lower Permian activity relative to 2025. While we expect operating expense savings to continue through the year, they are being offset by various market-related headwinds primarily in the Permian and North Sea.

Each category is below 2025 levels with the exception of LOE, and at this point, we expect 2026 LOE to be slightly above 2025. All of this is incorporated in our annual guidance for capital, G&A, and LOE. The progress achieved in 2025, combined with the additional savings we expect to capture in 2026, positions us for a structurally lower spend profile as we move into 2027. By year-end 2026, we now estimate our run-rate savings will reach $450,000,000. These savings are sustainable and position us to be a cost leader as we continue to drive efficiency and long-term value creation.

Turning to our outlook for 2026, John already outlined our high-level capital investment plans and expected production trajectory, so I will focus on a few additional items. Starting with the Permian, 2026 development capital is expected to be around $1,200,000,000. In addition, we plan to invest approximately $100,000,000 for base capital projects aimed at structurally reducing LOE and improving uptime. These projects offer attractive six- to twenty-four-month paybacks, with LOE benefits starting in 2026 and building into 2027. Total Permian capital will be approximately $1,300,000,000 for 2026. Moving to Egypt, we recently elected to withdraw from a small noncore concession as part of our ongoing portfolio high-grading efforts.

These assets fall outside of the merged concession area established in 2021 and do not benefit from the new gas pricing framework. While the concession did not generate free cash flow, our exit will reduce oil and gas production volumes and enhance the durability of the asset. The quantified impact is detailed on page 16 of our supplement. Shifting to decommissioning and asset retirement obligations, we expect combined gross spend to increase to approximately $280,000,000 in 2026. This reflects lower spending in the Gulf of Mexico, offset by higher planned activity in the North Sea. As a reminder, all North Sea decommissioning expenditures receive a 40% tax benefit.

After incorporating these tax benefits, we expect net spend for 2026 to be approximately $225,000,000. Shifting now to our oil and gas trading portfolio, which continues to be a meaningful contributor to free cash flow, we expect to generate $650,000,000 of pretax income in 2026 based on current strip pricing. From 2020 through the end of this year, we expect to have generated nearly $2,000,000,000 in cumulative pre-tax income from our trading activities, underscoring the scale, consistency, and value of this business within our portfolio. In closing, 2025 was a strong year for APA.

We significantly exceeded our cost savings targets, generated over $1,000,000,000 of free cash flow, reduced net debt by more than $1,400,000,000, and continued to high-grade our portfolio. Our focus remains on disciplined capital allocation, further cost efficiencies, continued balance sheet improvement, and advancing our high-return development program and exploration opportunities. We will now open for questions. I will now turn the call over to the operator for Q&A.

Operator: Thank you. We ask that you please limit yourself to one question and one follow-up. To withdraw your question, please press 11 again. Our first question comes from the line of Doug Leggate with Wolfe Research. Your line is now open.

Doug Leggate: Thank you. Good morning, everyone. This one is for Ben, but I am trying to understand the Permian CapEx guidance: the $1.2 billion development and $1.3 billion total, and the incremental $100,000,000 for base capital projects. Can you offer any color on the impact of this $100,000,000? What is the nature of that spend? How does it show up in the payback you talked about? And then my follow-up, John, if I may hit exploration. It looks like EGPC has been announcing a series of recent gas discoveries—more of the quick-hit stuff, if you like—but you have also put an emphasis on growing your gas volumes. Any color there would be appreciated.

John J. Christmann: On the LOE projects, we have been looking at all the various sources of downtime that we experience, and some of it is related to the reliability and resilience of facilities and equipment. There are some high-LOE areas where, if we can invest, we can drive down LOE. Some of that would be rental equipment that Callon had that we will be investing in. These investments could improve uptime in the future—maybe not as good as the fourth quarter, but better than what we have experienced in the past.

That also moves some of the higher-breakeven inventory that you see on the inventory skyline plot to the left, and it will serve to bring some of the technical inventory onto that skyline plot. So there are multiple purposes for that LOE investment. On exploration, we went after some low-hanging fruit and things we knew were there. Now we are really starting to work the exploration inventory, and I am very excited about what is coming in Egypt. We have some key wells that we will be drilling. EGPC has been announcing some of the smaller things, but we are excited about that.

And I can let Tracey talk about Alaska, but I am sure we will talk about inventory in a bit.

John J. Christmann: On your second question regarding the U.S. oil volumes, fourth quarter was almost flawless in terms of no downtime. Historically, fourth and first quarters are when you have the most weather impact. Fourth quarter, there was virtually no weather. Obviously, that changed in January, and we have had a lot of weather in the quarter. So when you look at fourth quarter versus first quarter, that is a big chunk of it. Secondly, we were able to bring some TILs earlier into the year, and some of those cleaned up a little quicker than we expected them to. You had forecasted downtime. In fact, we were able to give the workover rigs both Thanksgiving and Christmas holidays off.

That is going to drive a pretty big portion of it because you had wells cleaning up. The actual improvement in underlying runtime was just phenomenal during the fourth quarter. We do not have exact numbers on any of that, but I would say roughly one-third each: moderate weather, TILs, and runtime improvements.

Doug Leggate: Great. That is helpful. And then my follow-up—looking at slide 11, you show really good progress on D&C per foot, down 30%. Looking at your development plan on slide 14, back-of-the-envelope, it looks like D&C per foot continues to go lower on your 2026 program. Would it be possible to get a rough breakdown of those 130 completions in the Permian between Midland and Delaware, and a rough idea of what you are baking into the plan on a D&C per foot basis?

John J. Christmann: We are not prepared to do that on this call. You can have a follow-up call with Stefan and Ben and the team after this. What I would say is that we have made huge progress on drilling and completion costs in both basins. In the Midland Basin, we were under $500 per lateral foot, and in the Delaware Basin, we were under $700 per foot. We are continuing to make progress.

We actually got to a point where at the end of 2025 you looked at the mix effect on all of that, but when you do the math, you will find that it is pretty in line with what we have been doing as we went through 2025 and ended 2025. The drillers are anxious to get after other opportunities in 2026, and we believe that will continue to improve. We can follow up offline in a separate call.

Doug Leggate: That is great. Thanks a lot, guys. Well done.

Operator: Thank you. Our next question comes from the line of Neil Dingmann with William Blair. Your line is now open.

Neil Dingmann: Can you hear me? Sorry for the delay. John, for you or Steve, could you talk a little bit about the Permian inventory and how the potential sensitivity looks, especially around some of your gassy assets? Just maybe a bit of an overview on inventory in general.

John J. Christmann: Today, what we looked at was really the oil inventories—location counts in there. You are not going to have any of our pure gas in economic inventory. Those will be separate. Steve, you can jump in a little bit on the definitions and the cutoff.

Stephen J. Riney: I would say the cutoff that we have between economic inventory and technical upside is probably on the conservative side, as you would imagine for us. We have 1,700 gross locations in economic inventory. What do we mean by economic inventory? It has to have a very high confidence in terms of being able to draw a type curve for it, and we have that confidence either from our own experience or offset operators that have good analogs to what we are going to be drilling. The economics include all drilling, completion, equipping, and facilities costs, and it is burdened with central facilities, which some people do not do.

They just stop at pad-level facilities, but we include the gathering systems, our water disposal, and central tank batteries. It has to have a 10% rate of return to make it into economic inventory. The technical upside inventory is the next best opportunity, and, as I said in my prepared remarks, it is for bringing stuff through appraisal and development into the economic inventory bucket. I do not want people walking away from the call thinking this is pie-in-the-sky stuff. It is not at all. Forty to fifty percent of our entire technical upside inventory is shallow Delaware Basin—Avalon and first and second Bone Springs. In my prepared remarks, I talked about two wells that we drilled with promising results.

If we drilled those two wells today at our current cost structure, those wells would be breaking even at $41 WTI. This falls right into the good end of the skyline plot. Every bit of that is in technical upside, not in economic inventory today. We are going to be drilling a four-well spacing test later this year in that area. We actually have several appraisal or spacing tests going on in both the Delaware Basin and the Midland Basin this year to move technical upside into economic inventory. That is for the very purpose of moving quantum of inventory out of technical upside into economic inventory.

Neil Dingmann: Great details, Steve. And then just a second one on Suriname. Is 100% of the $230,000,000 in suggested capital for the year strictly focused on the Grand Moergue, or are you assuming any other parts of Block 58 or 52?

John J. Christmann: No. The $230,000,000 is for Grand Moergue. The exploration capital would be covered in the exploration line.

Neil Dingmann: Very good. Thank you all.

Operator: Our next question comes from the line of Bob Brackett with Bernstein Research. Your line is now open.

Bob Brackett: Good morning. If we can talk about Egypt and the 7,500,000 acres you have there. Some of that acreage is well connected with existing gas pipelines, but there is a whole lot of territory fairly far from gas pipelines that could hide some fairly large prospects. Can you talk to your exploration philosophy for gas out there? Is it fishing from the pier, or is there some appetite to step out to some of the more distant opportunities?

John J. Christmann: Bob, we have been in the Western Desert for 30 years. We have shot multiple versions of 3D seismic as we learned to try to see deeper, searching for oil. We started out drilling the big bumps on the oil side, four-way closures to the three-way, then migrated to the strat traps. In November 2024, we entered into a new gas price environment. It lets us start that process over on the gas side. As I mentioned, we went after some things we knew were close that we could tie in. Now the exploration team is stepping back and really looking in the pockets that are deeper where we knew there was gas that we stayed away from.

We also added 2,000,000 acres last year of new acreage. We are taking a regional approach on the gas side. Tracey can comment a little bit on that.

Tracey K. Henderson: Thanks, John. We put a lot of effort in the last year into building a better regional picture with lookbacks over what we have been exploring for the last few decades. We have a lot of areas that we historically avoided because we knew they were going to be gas prone. We have reprocessed seismic data. We have stood up teams to really focus on this specifically and are currently building out more of an inventory of what we see as our longer-term gas portfolio, some of which we will start to test this year. We are in a really good place on that.

Bob Brackett: Very clear. Thank you.

Operator: Thank you. Our next question comes from the line of Michael Stephen Scialla with Stephens. Your line is now open.

Michael Stephen Scialla: Hi, good morning. I wanted to follow up on the Permian inventories. Stephen, I think you said in your prepared remarks that if the test you were referring to on the Bone Spring were to be successful, that could replace a year’s worth of drilling inventory. Is that essentially saying this four-well spacing test in the Bone Spring could move about 130 locations from the technical to the economic inventory? Is that a correct read?

Stephen J. Riney: Yes, that is a correct read, and that is just for the first Bone Spring. As I said a few minutes ago, 40% to 50% of our 1,700 technical upside locations are in the Avalon, first, or second Bone Springs in the Delaware Basin, mostly in Ward and Reeves County, and a bit in southern Winkler County. That test in the first Bone Spring will not prove up all of that, but it will prove up concepts related to all of it because we believe, at least in some places, that is one big tank.

It can prove up, just in the first Bone Spring in that area, up to another year’s worth of drilling, but there is a lot more at play there.

Michael Stephen Scialla: Got it. Then I want to follow up on Suriname. The $230,000,000 of development—does all that go toward the FPSO, or is there actually development drilling that is going to take place? I know you said you have some exploration drilling you plan late 2026, but is there any development drilling in that $230,000,000 number?

John J. Christmann: It is everything, Mike, and we will be starting the drilling. Those rigs are coming on late next year, early 2027, so some of that would fall on the drilling side too. The whole $230,000,000 is for the Grand Moergue development project: the FPSO, the umbilicals, a little bit of everything, and we will start drilling development wells.

Michael Stephen Scialla: So you are contemplating two rigs running late in the year there—one exploration, one development?

John J. Christmann: There will be multiple rigs, yes.

Operator: Thank you, Mike. Our next question comes from the line of Scott Hanold with RBC Capital Markets. Your line is now open.

Scott Hanold: Thanks. Can you give us a sense of how much of the $1,300,000,000 in the Permian is going to run these various tests to look at the technical upside? Is that something that you plan on having worked into the budget in 2027–2028 and beyond, or will there be a point where we see a little bit of a drop-off in Permian spend because you have done most of that work?

John J. Christmann: No, Scott. We have a steady diet. Last year, we were flowing back a four-well Barnett test. You should envision a steady diet of delineation and appraisal. That is going to continue. That is the nature of the basin. We have the development piece that you are drilling off those results, but you will constantly be drilling wells in that technical category that can move things up. We have had several we did last year and over the last several years.

Scott Hanold: Understood. And did you talk about Uruguay a little bit? It does not look like there is any exploration spend there. I know you are looking to farm down part of that right now, but what are the next steps and timing?

John J. Christmann: In Uruguay, we have had a data room open. There has been a lot of interest from the industry. We are looking to farm down. There is a chance it could be late this year, but it is likely 2027 before we would be looking at a well. At some point, we will have something to say about that.

Operator: Our next question comes from the line of Josh Silverstein with UBS. Your line is now open.

Josh Silverstein: The FC capacity and the trading benefit continues to be a positive driver for you guys and clearly still a big beneficiary of wide spreads in 2026. Can you talk about how you see this trending next year, in 2027, as 4-plus Bcf per day of new Permian pipeline capacity comes online? Does that $650,000,000 start to come down? And do you offset any of that with some higher volumes of your own, so there is no net reduction there?

Stephen J. Riney: This year is $650,000,000. Next year, it does come down just based on strip. There is quite a lot of takeaway coming online late this year and a little bit next year. This is a trend that we have seen over the last seven years: you get deep discounts, then an increase when the pipelines come on, and then it gets challenged again as they fill up. We will see what happens to Waha and where that lands. Some people say it will fill up pretty quick, and others are skeptical. It does come down next year. It is still positive for us two years out, through 2028.

That is going to be driven by the types of wells that are drilled, GORs, the amount that is flaring now that can be put on the pipes, industry activity, and production in the basin. Our extension options on those begin in 2029, and we will look at the market at that time and figure out what to do. For the next three years, it is positive for us across that and the LNG book. To your point, if those spreads compress through Waha strengthening, then we do get better prices on our equity gas that we are producing.

It does not fully offset that because we have a little bit more capacity than our production, but it does mitigate the drop on the marketing side because you are making more on your equity gas.

Josh Silverstein: Got it. Thanks for that. Maybe just sticking on the financial front, the balance sheet improvement efforts have been really good—now down to $4,000,000,000 at year-end 2025. Still have the $3,000,000,000 long-term target there. Is the goal to stick with that 60%-plus of free cash flow going to shareholders until you meet that target? Is there any sort of flex to this, or do you want to make sure you are hitting that target this year?

Stephen J. Riney: We think that 60% is competitive. We have exceeded it every year since we outlined that in 2021. We also are using portions of our free cash flow to invest in exploration. A lot of our peers do not have the exploration portfolio that we have, so we are thinking longer term as well. That 60% takes exploration into account as well as balance sheet management and managing our ARO and decommissioning spend, and we are managing all of that. The $3,000,000,000 target we put out was at a mid-cycle price of $70. We would get there in three to four years. If prices go higher than that, we can potentially get there by the 2027–2028 timeframe.

If they are lower, then it will be the end of the decade. The point is that we have made a lot of progress through cost savings, capital efficiency, and execution in the field. Free cash flow increased last year by over 20% with lower prices. We used a lot of that to return to shareholders, but we also paid down a lot of debt. At current prices, we still feel pretty good about reaching that $3,000,000,000 in the next couple of years. You look at the Permian inventory and the Egypt gas, and we have flexibility in our program as outlined.

Operator: Our next question comes from the line of Leo Mariani with ROTH. Your line is now open.

Leo Mariani: Hey, guys. I just wanted to follow up a little bit on the Permian inventory—just wanted to make sure I understood it from a definition perspective. When you talk about a 10% or greater rate of return, is that a field-level, pretax return? Does that include any kind of corporate burden for G&A?

Ben C. Rodgers: It does not include a corporate burden, but it does include full field cost burden. It is before tax, and after tax we probably will not be paying tax for quite some time.

Leo Mariani: That is helpful. And just wanted to follow up on Egypt. You spoke about gross oil going to decline in 2026. I was hoping you could give us a bit of a quantification. Is there a rough ballpark percentage on that?

John J. Christmann: If you look at it, we have been able, with the waterfloods, to hold oil volumes flat for the last three quarters. We have had a pretty good track record of being able to sustain that through the waterflood projects. We have shifted the gas rigs up to 50% from where we started last year at 25%. We are still prioritizing oil, so we are just going to be drilling more gas wells on a relative basis. As a result, we are going to forecast gross BOEs and gross gas slightly up, and gross oil to slightly decline.

Ben C. Rodgers: Also, quite a few of the gas fields are rich gas and have condensate with them, and that shows up as oil volume as well. Some of the new exploration acreage also is prospective for oil as well. It is just how we steered gross oil.

Leo Mariani: Okay. Very helpful. Thank you.

Operator: I would now like to turn the call back over to John J. Christmann for closing remarks.

John J. Christmann: In closing, let me leave you with the following thoughts. 2025 was an excellent year for APA. We delivered substantial cost reductions ahead of schedule, generated over $1,000,000,000 of free cash flow, grew gas volumes in Egypt, continued to advance the Grand Moergue development in Suriname, and significantly strengthened the balance sheet—reflecting strong execution and meaningful progress towards cost leadership. At the same time, we sustained Permian oil production on lower capital with a structurally lower cost base and a stronger balance sheet.

With a strong foundation, disciplined capital allocation, and a clear line of sight to incremental free cash flow from Suriname beginning in 2028, we are well positioned to unlock the full value of our high-quality Permian inventory and expect to deliver sustainable production and competitive returns for the next decade and beyond. With that, I will turn the call back to the operator. Thank you.

Operator: Thank you. This concludes today’s conference. Thank you for your participation. You may now disconnect.

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