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F500-2020-465-Apache

The oil and gas exploration and production company operates in the U.S., Egypt, and the U.K. and has exploration activities offshore of Suriname.

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APA, best known through its Apache subsidiary, is an independent energy company specializing in the exploration, development, and production of oil and natural gas. Operating primarily in the Permian Basin, as well as in Egypt, the North Sea, and Suriname, APA focuses on delivering reliable and affordable energy to meet global demand. The company is committed to sustainable practices and leverages advanced technologies, including artificial intelligence, to enhance operational efficiency and reduce environmental impact.

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APA (APA): Company Profile, Stock Price, News, Rankings

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Good day, and thank you for standing by. Welcome to the APA Corporation Fourth Quarter and Full Year 2025 Financial and Operational Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Stephane Aka, Managing Director of Investor Relations. Please go ahead.

Thank you for joining us on APA Corporation's fourth quarter and full year 2025 financial and operational results conference call. We will begin the call with an overview by CEO, John Christmann. Steve Riney, President, will then provide an update on our Permian inventory. Ben Rodgers, CFO, will share further color on our results and outlook. Tracey Henderson, Executive Vice President, Exploration, is also on the call and available to answer questions. We will start the call with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our financial and operational supplement, which can be found on our investor relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures.

A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interests in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss in today's call. A full disclaimer is located with the supplemental information on our website. With that, I will turn the call over to John.

Good morning, and thank you for joining us. On today's call, I will review our full year 2025 results, outline our continued progress across key strategic initiatives, and discuss our outlook and plans for 2026. 2025 was a highly successful year for APA, defined by continued progress against our strategic priorities and strong execution across our asset base. We entered the year with a clear objective to materially reduce our overall cost structure, part of which was to make significant further strides in terms of operational excellence. We set a goal to reduce our controllable spend by $350 million on a run-rate basis by the end of 2027 without compromising safety, asset integrity, or our commitment to exploration.

Through the dedication of our employees and strong leadership alignment, we exceeded this target over a significantly shorter timeframe and have line of sight to exiting 2026 at a $450 million run-rate. Ben will provide more details on this topic. During the year, we also met or exceeded oil production guidance in the Permian every quarter in 2025 on a lower than planned capital budget. We also made significant progress on a comprehensive assessment of our Permian Basin inventory, incorporating our improved cost structure. This effort confirmed the depth and quality of our drilling opportunities and validated substantial upside potential. Additionally, it increased our confidence in sustaining long-term oil production while delivering competitive capital efficiency. Steve will provide further color on our Permian inventory position shortly.

Moving to Egypt, our focused activity under the new gas pricing framework drove meaningful production growth, establishing the foundation for a sustained multi-year strategic focus. On the oil side, strong reservoir management through targeted water flood activity has helped stabilize gross volumes over the past three quarters. In Suriname, our partner, Total, continues to execute at a high level as we advance toward a mid-2028 first oil date. On the exploration front, our Sockeye discovery in Alaska further confirmed the prospectivity of our approximately 325,000-acre position, providing a strong basis for future exploration and appraisal activity. In summary, the disciplined execution across our asset base and strong delivery of our cost reduction initiatives drove more than $1 billion in free cash flow generation in 2025, of which we returned approximately $640 million to shareholders.

We also significantly strengthened our balance sheet, ending the year with less than $4 billion in net debt. Turning to 2026, our strategic priorities are clear, and our capital plan is disciplined. We will sustain operational momentum, further reduce our cost structure, continue strengthening our balance sheet, and invest in the future through exploration. In the United States, our $1.3 billion capital program is designed to maintain relatively flat oil production year-over-year at approximately 120,000-122,000 barrels per day despite significant weather-related downtime in the first quarter. This represents an improvement relative to our preliminary outlook discussed in November, reflecting continued gains in operational and capital efficiency. In Egypt, we will invest approximately $500 million to slightly grow BOE production year-over-year.

As our activity becomes increasingly gas-weighted, gross oil production is expected to decline slightly, while gross gas volumes continue on a growth trajectory year over year. After just one year of focused, successful gas drilling, we now have visibility into a runway of new development inventory and near-field exploration opportunities. This has laid the foundation to support continued growth, and we expect to deliver approximately 540 to 550 million cubic feet per day this year. This volume outlook includes a minor impact from our withdrawal from a small, non-core concession, which Ben will address shortly. Under our new pricing framework, increased gas production strengthens free cash flow and further establishes Egypt as a key value driver within our portfolio. For the GranMorgu development in Suriname, we will allocate approximately $230 million in capital.

On the exploration front, we are investing approximately $70 million to advance high-impact opportunities across our portfolio. This includes a return to exploration drilling in Suriname, Block 58, in the fourth quarter, and planning and readiness spend ahead of an active first quarter 2027 drilling season in Alaska. In aggregate, our total portfolio spend is $2.1 billion, roughly 10% lower than last year. This plan is operationally manageable and preserves flexibility to scale activity in response to commodity price movements. In closing, the progress we delivered in 2025 reflects a fundamental transformation of APA's base business over the past several years. We have high-graded the portfolio, significantly reduced our cost structure, strengthened the balance sheet, and further advanced our exploration efforts, resulting in a more focused, resilient, and capital-efficient company.

These actions have translated into stronger free cash flow generation and a structurally more competitive asset base in both the Permian and Egypt. In the Permian, 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 form the foundation for sustained free cash flow generation for the next several years.

Starting in 2028, the addition of Suriname will provide a meaningful step change and continued growth in free cash flow through at least the early 2030s. I will now turn it over to Steve, who will provide more details on our Permian inventory.

Thank you, John. The Permian Basin is Apache's foundational asset. It's 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. In the Permian, 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. Let's 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.

This was enabled through the Callon acquisition and exits from non-core assets like the conventional Central Basin Platform and our fragmented position in New Mexico. We now hold approximately 450,000 net acres across the Midland and Texas-Delaware Basins, with more than 95% of that acreage held by production. Our position is now concentrated in a few key areas, presenting two primary benefits. It enables economies of scale in our operations and provides significant flexibility in the pacing of activity. Turning to our progress on the cost side, our momentum has been evident over the last several quarters. Beginning in 2024, the successful delivery of Callon synergies significantly lowered break-even 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. Our development approach has historically involved wider well spacing with larger completions. That approach drove very strong per well productivity. As our cost structure improved, it enabled us to drill more wells on tighter or denser spacing and to moderate completion intensity. This translated to more economic inventory, greater recoverable reserves, and a higher overall net asset value. There is a reinforcing mechanism at play here as well. Lower cost enables more dense development.

Increasing density accesses economies of scale, 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, there has to be a high level of confidence in the production forecast. Where further appraisal or delineation is required, we reduce location counts, oftentimes to zero, until they are further de-risked. 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 locations 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. Continued delineation success and ongoing efficiency gains remain key drivers for advancing these locations into economic inventory. Approximately 2/3 of our technical upside today is in the Delaware Basin, with the vast majority in shallow landing zones, the Avalon and the First and Second Bone Spring. 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 hasn't 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. 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. Most of our DSUs there carry locations in economic inventory. By comparison, in areas like Upton County, there has been very little Barnett activity.

As a result, the vast majority of our DSUs carry Barnett locations only as technical upside. In our view, this reflects a need for further appraisal, not a lack of prospectivity. 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 a 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, some of these leads may underpin future upside. In closing, as we see things today, we are confident we can sustain oil production volumes at today's levels for at least the next 10 years. We see meaningful potential to extend that further. The scale of the technical upside characterized in actual location counts is at least as large as the economic inventory we are presenting today. We believe the future will bring more locations from technical upside into economic inventory. Locations will continue to move to the left on the skyline plot with improving economics and lower breakeven prices. Our progress in 2025 demonstrated our standing as a leading operator in the Permian Basin. We improved capital efficiency, strengthened the depth and quality of our inventory. Increased confidence in long-term performance.

Our Permian position is anchored by a long runway of inventory with a sustainably improved cost structure and a competitive development approach. All of this is underpinned by a cored up asset base that is largely held by production. 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.

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

For the full year, free cash flow was more than $1 billion. 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 the first quarter of 2026, we've 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. Operations have since resumed to normal. LOE came in below guidance, driven by progress across our portfolio from ongoing cost-saving initiatives, namely in the North Sea and Permian.

Net debt ended the year just below $4 billion, down approximately $1.4 billion 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 billion. Interest expense was approximately $80 million lower compared to 2024. Wrapping up 2025, our proved reserves increased approximately 9% year-over-year, surpassing 1 billion barrels of oil equivalent, and our all-in reserve replacement ratio exceeded 160% for the year. The team's execution in the Permian and in Egypt enabled us to grow reserves despite a 13% year-over-year decline in SEC oil prices, underscoring the quality of our inventory and the capital efficiency of our development program.

Turning to our cost reduction initiatives, 2025 marked a year of remarkable progress across the entire company. We captured over $300 million of savings and exited the year at a $350 million 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 seven of the supplement, we expect controllable spend to decline by another $200 million. Only half of this reduction is incremental savings, with the remainder driven by lower Permian activity relative to 2025. All of this is incorporated in our annual guidance for capital, G&A, and LOE. Each category is below 2025 levels, with the exception of LOE.

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. We will work throughout the year to mitigate these pressures, but at this point, we expect 2026 LOE to be slightly above 2025. 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 million. 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, I will focus on a few additional items. Starting with the Permian, 2026 development capital is expected to be around $1.2 billion. In addition, we plan to invest approximately $100 million for base capital projects aimed at structurally reducing LOE and improving uptime. These projects offer attractive six to 24 month paybacks and enhance the durability of the asset, with LOE benefits starting in the back half of 2026 and building into 2027. As a result, total Permian capital will be approximately $1.3 billion for 2026. Moving to Egypt, we recently elected to withdraw from a small non-core 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. 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 million in 2026. This reflects lower spending in the Gulf of America, 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 impacts, we expect net spend for 2026 to be approximately $225 million. Shifting now to our oil and gas trading portfolio, which continues to be a meaningful contributor to free cash flow.

Based on current strip pricing, we expect these activities to generate approximately $650 million of pre-tax income in 2026. From 2020 through the end of this year, we expect to have generated nearly $2 billion 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 billion of free cash flow, reduced net debt by more than $1.4 billion, 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. With that, I will now turn the call over to the operator for Q&A.

Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. We ask that you please limit yourself to one question and one follow-up. Please stand by while we compile the Q&A roster. Our first question comes from the line of Doug Leggate with Wolfe Research. Your line is now open.

Thank you. Good morning, everyone. John, or maybe, this one is for Ben, but I'm trying to understand this Permian CapEx guidance, the $1.2, $1.3 total, $1.2. I'm wondering, can you offer any color on the impact of this $100 million? What's the nature of that spend? How does it show up in the payback you talked about? Any kind of color on the LOE, for example, impact would be appreciated. My follow-up, John, if I may hit exploration. It looks like EGPC has been announcing a series of recent gas discoveries, a quick hit stuff, if you like. You've also put new exploration numbers in the budget for this year, presumably Alaska and Suriname.

I wonder if you could offer any color on what the program looks like in those three areas. Specifically, I believe there's a potential game changer target in Alaska. If you could speak to the, you know, the prospectivity around that as well, that'd be great. Thanks.

Thank you, Doug. What I'll do first is just address the exploration, maybe have Tracey chime in, and then I'll have Ben come back on the LOE and the capital question. In general, we've got $70 million in the budget this year. $20 million of that is really prep work in Alaska for ice roads. There's another $50 million that's late in the year for predominantly Suriname, as we will be returning to exploration in Block 58 with a well. The exact spud date's not yet set, but we expect it to be late fourth quarter. That's how that $70 million breaks out. Clearly, we're also active in Egypt and, you know, just to spend a couple seconds there.

You know, what you've seen and with the progress in Egypt, you know, last year when we, you know, or November of 2024 when we, you know, updated our new price mechanism, it really shifted a gear for us and let us start focusing on gas in the western desert of Egypt. You saw last year with the progress in terms of what we're able to do in growing our gas volumes. We went after some low-hanging fruits and things we knew were there. You know, now we're really starting to work the exploration inventory, and I'm very, very excited about what's coming, you know, in Egypt. We've got some pretty key wells that we'll be drilling. Those are some of the things you referenced. EGPC's been announcing some of the smaller things, but we're excited about that.

I can let Tracey talk about Alaska, but in general, we're prepping for a big winter. You know, likely two wells in early 2027, likely an appraisal at Sockeye. We're still in the process of getting back the seismic that we're having reprocessed, so that's still coming in. You'll likely see us drilling an exploration well and an appraisal well in early, you know, winter of 2027 in Alaska. Tracey, you can comment a little bit just on the geology there.

I'm sure. You know, we've got a really robust and diverse prospect inventory on the block. As John said, you know, we're focused right now on reprocessing the new seismic data and maturing that entire inventory. You know, we've had success in the bottom set play at Tumbleweed and in the top set play at Sockeye. We're going to be focusing really in the near term on maturing a lot of what we see as analogous prospects to the Sockeye discovery, and that will be a focus for the near term and the next drilling season. As John said, we'll be looking to appraise the Sockeye discovery as well. We've got a lot going on in the background, getting ready for the next season in terms of defining the inventory and next steps.

Yeah. Just to clarify, we'll start building ice roads this winter for the late 2026, early 2027, Alaska drilling season. Ben, I'll go back to you now on the Permian capital and the $100 million we're spending.

Sure. Doug, you know, we started spending some capital last year. We talked about in August and November on some of these LOE projects. As we did that, we identified some additional opportunities going into 2026. You know, a lot of it is around compression and facilities consolidation. There's some artificial lift dollars in there as well. It's a lot of different projects spread throughout the basin. The way to think about it is, as you get to the back part of 2026, we expect that our LOE will come down by, you know, somewhere around $3.5+ million per month. When you annualize that number, you're kind of in the $40 million-$50 million of ongoing savings in LOE.

Spending that $100 million, you know, gets you $40 million-$50 million of savings, which is pretty much in line with the kind of one- to two-year payback.

Ben, just to be clear, that, so presumably, that's like rented equipment becoming capital equipment or something of that nature. Does that sound about right?

That, that's a portion of it. you know, it really, it spans across a lot of different pieces in the basin. Steve, I don't know if you want to add some color.

Yeah, I wanted to add some color to the LOE investments, 'cause really, they have three purposes. Obviously, one is just a, you know, it's $100 million of capital investment that'll drive down costs. Actually, our estimate is that we'll exit 2026 on a monthly LOE run-rate that's $3 million-$3.5 million lower than it otherwise would be. That's just the cost side, just investing to reduce cost. We're also investing in things that will increase the reliability and the resilience of production volume.

As John said, we had an amazing fourth quarter on uptime, and we've been looking at what are the all the various sources of downtime that we have and we experience, and some of it is related just to the reliability and resilience of facilities and equipment. There's some investments that could be made there that could improve uptime for the future. Maybe not as good as fourth quarter, but maybe better than what we've experienced in the past. Thirdly, there are some opportunities on the inventory side. I'm sure we'll talk about inventory in a bit, Permian inventory, but there are actually some high LOE areas where if we can invest in some of the facilities, we can drive down LOE.

That moves some of, maybe some of the high breakeven, inventory that you see on that inventory skyline plot to the left, but also will serve to bring some of the technical inventory onto that skyline plot. There's lots of purposes for that LOE investment.

Yep, some of that would be rental equipment that Callon had that we will be investing in. Thank you.

That's what I was getting at. Thanks very much indeed. Appreciate it.

Thank you. Our next question comes from the line of John Freeman with Raymond James. Your line is now open.

The first question, you know, y'all had a huge beat on US oil volumes, and, you know, y'all cited a few different items that drove that improved runtime, incremental completion activity, and more moderate weather. This may be difficult to answer, but if you sort of went back and, I guess, did, like, a postmortem, you looked at your original guidance versus, you know, the big beat, can you sort of flush out a little bit for us, sort of the impact that each of those had, like the improved runtime versus, you know, a few incremental completions versus the moderate weather? Just trying to flush that out a little more.

Yeah, I mean, John, I'll take a, you know, a cut at it and then have Steve, you know, add some detail if we need to. I mean, first of all, you look at, you know, fourth quarter, first quarter, are historically our periods when you've got the most weather impact. Fourth quarter was almost flawless in terms of no downtime. That in itself is something we typically will bake in. Fourth quarter, there was virtually no weather. Obviously, that changed in January, we've had a lot of weather in the first quarter. When you look at fourth quarter versus first quarter, that is a big chunk of it. Secondly, we were able to bring some tills earlier into the year, some of those just cleaned up a little quicker than we expected them to.

That's gonna drive a, you know, a pretty big portion of it just because, you know, we had wells cleaning up. You'd had forecasted downtime. In fact, you know, we were able to give the workover rigs both holidays off, both Christmas and Thanksgiving, because, you know, the runtimes were so good fourth quarter.

Yeah, I don't have exact numbers on any of that, John, I would just say, you know, roughly one-third each, you know, three big impacts. Virtually no weather downtime in the fourth quarter. The tills, and then the actual improvement in underlying runtime, was just phenomenal during the fourth quarter. I would just say one-third each, probably.

Great. That's helpful. My follow-up, you know, looking at slide 11, we also, you know, the really good progress on the D&C per foot, you know, down 30%. Sort of looking at your development plan on slide 14, I don't quite have everything I probably need on there to back into this exactly, but, you know, just looks like back of the envelope, the D&C per foot looks like it's continuing to go lower on your 26 program.

Would it be possible to maybe get sort of a just rough breakdown of those 130 completions in the Permian between Midland and Delaware, and then just sort of a rough idea of what y'all are baking into the plan on a D&C per foot basis?

Yeah, we're not prepared to do that on this call. You can maybe have a follow-up call with Stefan and Ben and the team after this, John. What I would just say is that, you know, we made huge progress on drilling and completion costs in 2025. You know, the, at the end of the year, especially, in 2025, if you looked at some of the shallow wells that we were drilling in both basins, we actually got to a point where in the Midland Basin, we were under $500 a lateral foot, and in the Delaware Basin, we were under $700 a foot. We are continuing to make progress. We're not, certainly not done with that.

The drillers I know are anxious to get after other opportunities here in 2026. We believe that'll continue to improve. There is a mix effect on all of that, I think when you do go through the math, you'll find that it's pretty in line with what we've been doing, as we went through 25 and ended 2025. I'll let you guys do that offline in a separate call.

That's great. Thanks a lot, guys. Well done.

Our next question comes from the line of Neal Dingmann with William Blair. Your line is now open.

Sorry, guys, for the delay. Can you hear me?

Thank you. John, for you or Steve, just wondering, could you talk a little bit about the, just Permian inventory, you know, how the potential sensitivity is, especially around some of your gassy assets?

Yeah, I mean, if you look, today, what we looked at was really the oil inventory, so you're not gonna have any of our pure gas in, you know, location counts in there. Those will be, you know, separate. Steve, you can, you know, you can jump in a little bit on.

Just kind of, just maybe a bit of an overview on in-inventory. Sorry. A bit of an overview on inventory in general is, as we said, economic inventory. I'd say the cutoff that we have between economic inventory and technical upside is probably, I would say, and you probably imagine this to be true for us, we err maybe a bit on the conservative side. 1,700 gross locations in economic inventory. What do we mean by economic inventory? You know, it's got to have a very high confidence in terms of being able to draw a type curve for it. We have that confidence either from our own experience or offset operators that have good analogs to what we're gonna be drilling.

The economics include all drilling, completion, equipping, and facilities costs, and it's actually burdened with central facilities, which some people don't do. They just stop at pad-level facilities, but we include the gathering system, saltwater disposal. We include central tank batteries, and it has to have a 10% rate of return to make it into economic inventory. The technical upside inventory is, you know, as I said in my prepared remarks, it's stuff that it's the next best opportunity for bringing stuff through appraisal and development into the economic inventory bucket. You know, I don't want people walking away from the call thinking, okay, this is kind of like pie in the sky stuff. Actually, it's not at all. You know.

40%, 40%-50% of our entire technical upside inventory is shallow Delaware Basin, so it's the Avalon and First and Second Bone Spring. In my prepared remarks, I talked about there were two wells that we drilled that had pretty promising results. Well, if we drilled those two wells today at our current cost structure for drilling wells, those wells would be breaking even at $41 WTI. This is, this is stuff that falls right into the good end of the, of the skyline plot. Every bit of that stuff is in technical upside, not in inventory. We're gonna be drilling a four-well spacing test later this year in that area. You know, those are the types of things that we're gonna be doing to move technical upside into economic inventory.

We actually have several appraisal tests or spacing tests going on, both in the Delaware Basin and in the Midland Basin this year, for that very purpose, moving quantum of inventory out of technical upside into economic inventory.

Great details, Steve. Then just a second one, just on Suriname, you know, I just wanna make sure I think this is the case. Is 100% of that $230 million in suggested capital for the year strictly focused on the GranMorgu, or, you know, are you assuming any other parts of, you know, would it be spent in any other, maybe parts of Block 58 or 52?

No, the $230 there is for GranMorgu, and then the exploration capital would be covered in the exploration side.

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

Good morning. If we could talk about Egypt and the seven and a half million acres you have there. Some of that acreage is well connected with existing gas pipelines. There's a whole lot of territory fairly far from gas pipelines that could hide some fairly large leads or 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?

No, Bob, I mean, I think the big thing to think about there is we've been in the Western Desert for 30 years. You know, we've shot multiple versions of 3D seismic as we learned to try to see deeper, searching for oil. You know, we started out drilling the big bumps on the oil side, the four-way closures to the three-way, migrated to the strat traps. Really, you know, November of 2024, we enter into a new gas price environment, and it lets us start that process over on the gas side. You know, as I mentioned, we went after some things we knew were close that we could tie in, and now the exploration team is stepping back and really looking in the pockets that are deeper, where we knew there was gas, and we stayed away from.

We've also added 2 million acres last year of new acreage. You know, we're stepping back and doing a regional look, and Tracey Henderson can comment a little bit on that, but we're taking a regional approach on the gas side, and that's what I'm excited about, is it's bringing a lot of, you know, structures into play that historically we knew were gas, and we steered away from.

Yeah. Thanks, John. No, I think as John said, we've put a lot of effort in the last year of going back and building a better regional picture, too, with look backs over what we've been exploring for the last few decades. As John said, we've got a lot of areas that we've historically avoided because we knew that they were gonna be gas-prone. We've reprocessed seismic data. We've 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, of some of which of those wells we will start to see this year. I think we're in a really good place on that.

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

Good morning. wanted to follow up on the Permian inventory. Steven, I think you said in your prepared remarks, that if the test, I think you were referring to on the Bone Spring, were to be successful, that that could replace a year's worth of drilling inventory. Is that essentially saying this four-well spacing test in the Bone Spring could add like, could move 130 locations from the technical to the economic inventory? Is that a correct read?

Yes, that's a correct read, and that's just for the First Bone Spring. As I said just a few minutes ago, actually 40%-50% of our 1,700 technical upside locations are in the Avalon First or Second Bone Spring in Delaware Basin, mostly in Ward and Reeves County and a bit in southern Winkler County. That test in the First Bone Spring won't prove up all of that, but will prove up concepts related to all of that because we believe, at least in some places, that's one big tank. Yes, it can prove up just in the First Bone Spring in that area, up to another year of worth of drilling, but there's a lot more at play there.

Gotcha. I wanted to follow up on Suriname, the $230 million of development. Is all that going toward The FPSO, or is there actually development drilling that's gonna take place? I know you said you've got some exploration drilling you plan on late 2026, but is there any development drilling in that $230 number, or is that separate?

It's everything, Michael. We will be starting the drilling. Those rigs coming on late next year, early 2027. You know, some of that would fall in on the drilling side too. The whole $230 is for the GranMorgu development project. Yeah, it's on the, you know, the FPSO, the umbilicals, a little bit of everything, and we will start drilling development wells.

You're contemplating two rigs running kinda late in the year there, one exploration.

Our next question comes from the line of Scott Hanold with RBC Capital Markets. Your line is now open.

Yeah, thanks. Could you give us a sense of, in the $1.2 billion spending in the Permian, how much of that is going to, you know, run these various tests to look at the technical upside? Is that something that you plan on having, you know, sort of working into the budget in 2027, 2028 beyond? Will there be a point where we see a little bit of drop-off in Permian spend because you've kind of done most of that work?

No, Scott. I mean, we've got a steady diet. I mean, last year, we, you know, we're flowing back now a four-well Barnett test. You should just envision in that one, too, we've got a steady diet of testing that we're doing, both delineation and appraisal. That's gonna continue. I mean, that's the nature of the basin, right? We've got the development piece that you're drilling at, you know, off of those results, but you're gonna constantly be drilling wells in that technical category that can move things up. A pretty steady diet. We've got several we did last year, the last several years, and several more this year. We've got a pad we're flowing back, and there's more Barnett we'll drill later this year.

Okay, understood. Could you talk about Uruguay a little bit? It doesn't look like there's any exploration spend there. I know you're looking to be farmed on part of that right now, but, like, what is sort of the path? What are the next steps there, and, you know, when could we potentially start seeing some activity?

Yeah, I mean, our next step in Uruguay, we have had a data room open. There's been a lot of interest from the industry. You know, we are looking to farm down. At some point, you know, we'll have something to say about that, and then we'd be looking at a well. It's probably likely 2027, but could be, there's a chance it could be late this year, but it's likely 2027.

APA (APA) Q4 2025 Earnings Call Transcript

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