Q4 2025 Earnings Call Transcript

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. [Operator Instructions] 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.

Good morning. and 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; and Ben Rodgers, CFO, will share further color on our results and outlook; Tracey Henderson Executive Vice President of 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 noncontrolling interest 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. And 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 time frame 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. In addition, 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 multiyear strategic focus. On the oil side, strong reservoir management through targeted waterflood 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 confirm 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 to 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 1 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 million to 550 million cubic feet per day this year. This volume outlook includes a minor impact from our withdrawal from a small noncore 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, strengthen 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 in 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 2 years. That progress can be summarized in three key efforts. Portfolio actions, cost structure improvements, and refining our development approach. So 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 noncore 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 provide 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 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 averaged $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 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 reduced location counts oftentimes to zero until they are further derisked. 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 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'll 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 Springs. 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 4-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 as 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, and 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. And 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, and 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, strengthen the depth and quality of our inventory and 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 generally accepted accounting principles, 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 noncash 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, 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 run time and milder than normal weather. In the first quarter of 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.

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. Additionally, 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 2 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 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.

So 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 6- 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 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. 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 pretax income in 2026. From 2020 through the end of this year, we expect to have generated nearly $2 billion in cumulative pretax 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 continue 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.

[Operator Instructions] Our first question comes from the line of Doug Leggate with Wolf Research.

John or maybe this one is for Ben. But I'm trying to understand this Permian CapEx guidance, the $1.2 billion -- $1.3 billion to $1.2 billion. I wonder, 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. And then my follow-up, John, if I may hit exploration. There's been a number, it looks like EGPC has been announcing a series of recent gas discoveries, a quick hit stuff, if you like.

But 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. And specifically, I believe there's a potential game changer target in Alaska, if you could speak to the prospectivity around that as well, that would be great.

Yes. 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 is not yet set, but we expect it to be late fourth quarter. So that's how that $70 million breaks out. Clearly, we're also active in Egypt.

And just to spend a couple of seconds there, what you've seen and with the progress in Egypt, last year, when we -- or November 24, when we 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, some things we knew were there. But now we're really starting to work the exploration inventory, and I'm very, very excited about what's coming in Egypt. We've got some pretty key wells that we'll be drilling.

Some of the things you referenced. EGPC has been announcing some of the smaller things. But we're excited about that. And I can let Tracey talk about Alaska, but in general, we're prepping for a big winner.

Likely two wells in early '27, 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. But you'll likely see us drilling an exploration well and an appraisal well in early winter of '27 in Alaska.

So Tracey, you can comment a little bit just on the geology there.

Sure. We've got a really robust and diverse prospect inventory on the block. And as John said, we're focused right now on reprocessing the new seismic data and maturing that entire inventory. We've had success in the bottom set play at Tumbleweed and in the top set play at Sockeye.

And so 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 in the next drilling season. And as John said, we'll be looking to appraise the Suriname discovery as well. So 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.

Yes. And just to clarify, we'll start building ice roads this winter for the late '26, early '27 Alaska drilling season. So Ben, I'll go back to you now on the Permian Capital and the $100 million we're spending.

Sure. So Doug, 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. A lot of it is around compression and facilities consolidation. There's some artificial lift dollars in there as well.

But -- so it's a lot of different projects spread throughout the basin. And the way to think about it is, as you get to the back part of '26, we expect that our LOW will come down by somewhere around $3.5-plus million per month. And so when you annualize that number, you're kind of in the $40 million to $50 million of ongoing savings in LOE. So spending that $100 million gets you $40 million to $50 million of savings, which is pretty much in line with the kind of 1- to 2-year payback.

Ben, just to be clear, that -- so presumably, that's like rented equipment becoming capital equipment or something of that right?

That's a portion of it. But 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?

Yes. I just -- I wanted to add some color to the LOE investments because really, they have three purposes. Obviously, one is just -- it's $100 million of capital investment that will drive down costs. And actually, we -- our estimate is that we'll exit '26 on a monthly LOE run rate that's $3 million to $3.5 million lower than it otherwise would be.

So that's just the cost side, just investing to reduce costs. But 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 all the various sources of downtime that we have and we experienced and some of it is related, just the reliability and resilience of facilities and equipment.

And so there are 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. And then 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 some actual -- 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, it also will serve to bring some of the technical inventory onto that skyline plot. So there's lots of purposes for that LOE investment.

And last thing there. Some of that would be rental equipment that Callon had that we will be investing in. So -- but thank you.

Our next question comes from the line of John Freeman with Raymond James.

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

Yes. I mean, John, I'll take a cut at it and have Steve add some detail if we need to. But I mean, first of all, you look at fourth quarter, first quarter are historically are periods when you've got the most weather impact. And fourth quarter was almost flawless in terms of no downtime.

So that in itself is something we typically will bake in. Fourth quarter where there was virtually no weather, obviously, that changed in January. And we've had a lot of weather in the first 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 just cleaned up a little quicker than we expected them to. And that's going to drive a pretty big portion of it just because we had wells cleaning up, you had forecasted downtime. In fact, we were able to give the workover rigs both holidays off, both Christmas and Thanksgiving because the run times were so good fourth quarter.

Yes. We don't have -- I don't have exact numbers on any of that, John. But I would just say roughly 1/3 each, three big impacts virtually no weather downtime in the fourth quarter. the TILs and then the actual improvement in underlying run time was just phenomenal during the fourth quarter. So I would just say 130 each, probably.

Great. That's helpful. And then my follow-up, looking at Slide 11, we also show the really good progress on the D&C per foot down 30%. And then sort of looking at your development plan on Slide 14, and I don't quite have everything I probably need on there to back this exactly, but it just looks like back of the envelope, the D&C per foot looks like it's continued to go lower on your '26 program.

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

Yes. We're not prepared to do that on this call. You can maybe have a follow-up call, with Stephane and Ben and the team after this, John. What I would just say is that we made huge progress on drilling and completion costs in 2025. 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 fit. So we are continuing to make progress. We're not -- we're certainly not done with that. And the drillers, I know are anxious to get after other opportunities here in 2026. So we believe that will continue to improve.

There is a mix effect on all of that. But I think when you 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. But I'll let you guys do that off-line in a separate call.

Our next question comes from the line of Neal Dingmann with William Blair.

Sorry, guys, to the delight. Can you hear me?

Yes.

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

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

Yes. Just to kind of not maybe a bit of an overview on inventory. Yes, sorry. A bit of an overview on the inventory in general, 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 are maybe a bit on the conservative side. But 1,700 gross locations in economic inventory. What do we mean by economic inventory? We have -- it's got 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're going to 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 ped 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, as I said in my prepared remarks, it's stuff that it's the next -- it's the next best opportunity for bringing stuff through appraisal and development into the economic inventory bucket.

And 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. 40% to 50% of our entire technical upside inventory is shallow Delaware Basin. So it's the Avalon and first and second Bone Springs. And 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. And so this is stuff that falls right into the good end of the Skyline plot. That's all -- every bit of that stuff is in technical upside, not in inventory. And so we're going to be drilling a 4-well spacing test later this year in that area.

And those are the types of things that we're going to be doing to move technical upside into economic inventory. We actually -- 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 detail, Steve. And then just a second one just on Suriname. I just want to make sure I think this is the case. Is the 100% of that $230 million in suggested capital for the year strictly focused on the GranMorgu? Or are you assuming any other parts of -- would it be spent in any of the maybe parts of Block 58 or 52?

No. The $230 million 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.

If we can talk about Egypt and the 7.5 million acres you have there much of that -- some of that acreage is well connected with existing gas pipelines, but there's a whole lot of territory fairly far from gas pipelines that could hide some fairly large needs or prospects. Can you talk to your exploration philosophy for gas out there? Is it efficient from the peer? 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. We've 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, the 4-way closures to the 3-way migrated to the strat traps. And really, November 24, we enter into a new gas price environment, and it lets us start that process over on the gas side.

So 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 that we stayed away from. We've also added 2 million acres last year of new acreage. So we're stepping back and doing a regional look and Tracey 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, is it's bringing a lot of structures into play that historically, we knew were gas, we steered away from.

Yes. Thanks, John. No, I think as John said, we put a lot of effort in the last year of going back and building a better regional picture too with lookbacks over what we've been exploring for the last few decades. And as John said, we've got a lot of areas that we've historically avoided because we knew that they were going to be gas prone.

So we've reprocessed seismic data. We 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. So I think we've got -- we're in a really good place on that.

Our next question comes from the line of Michael Scialla with Stephens.

I wanted to follow up on the Permian inventories, Stephen, 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 could replace a year's worth of drilling inventory. Is that essentially saying this 4-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% to 50% of our 1,700 technical upside locations are in the Avalon first or second Bone Springs in Delaware Basin, mostly in Ward and Reeves County and a bit in Southern Winkler County.

And that test in the First Bone Spring won't prove up all of that, but we'll prove up concepts related to all of that because we believe, at least in some places, that's one big tank. So yes, it can prove up just in the First Bone Springs in that area up to another year worth of drilling, but there's a lot more at play there.

Got you. And then I wanted to follow up on Suriname. The $230 million of development. Is all that going toward the FPSO? Or is there actually a development drilling that's going to take place? I know you've got some exploration drilling plan on late '26, but is there any development drilling in that $230 million number? Or is that separate?

It's everything, Mike, and we will be starting the drilling. Those rigs coming on late next year, early '27. So there could -- some of that would fall in on the drilling side, too. But the whole $230 is for the GranMorgu development project. But yes, that's -- it's on the FPSO, the umbilicals, a little bit of everything, and we will start drilling development wells.

So you're contemplating two rigs running kind of late in the year there, exploration...

There will be multiple rigs, yes.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Yes. Could you give us a sense of in the $1.3 billion spending in the Permian, how much of that is going to run these various sets to look at the technical upside? And is that something that you plan on having sort of working into the budget in 2020 and beyond? Or 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're flowing back now a 4-well Barnett test. So you should just envision in that one. Two, we've got a steady diet of testing that we're doing, both delineation and appraisal.

And that's going to continue. I mean, that's the nature of the basin, right? So we've got the development piece that you're drilling off of those results, but you're going to constantly be drilling wells in that technical category that can move things up. So 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 path we're flowing back, and there's more Barnett we'll drill later this year.

Okay. Okay. Understood. And could you talk about your growing a little bit. It doesn't look like there's any exploration spend there you look initially farm down part of that right now. But like what is sort of the path? What are the next steps there? And what could be to start seeing some activity?

Yes. I mean our next step in Uruguay, we have had a data room open. There have been a lot of interest from the industry. We are looking to farm down. So at some point, we'll have something to say about that. And then we'd be looking at a well. It's probably likely '27, but it could be -- there's a chance it could be late this year, but it's likely '27.

Our next question comes from the line of Josh Silverstein with UBS.

The 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 '27 as 4-plus Bcf a day of new Permian pipeline capacity comes online, does that 650 start to come down? And then maybe do you offset any of that with some higher of your own volumes. So there's kind of no net reduction there.

Sure. Yes. So this year's $650 million, you look at next year, it does come down just based on strip there is quite a lot of takeaway coming online late this year, a little bit next year. We'll kind of see what happens to Waha.

This is a trend that we've seen over the last really 7 years, of deep discounts, and then you get an increase when the pipelines come on as they fill up and then it gets challenged again. So we'll see what industry activity and things do to continue to push gas production in the basin and where that lands. Some people say it will fill up pretty quick and others are skeptical. And that's just going to be driven on types of wells that are drilled, GORs, the amount that's flaring now that can be put on the pipes, et cetera.

So it does come down next year. It's still positive actually for 2 years out for us kind of through '28, and then our extension options on those begin in '29. And so we'll look at the market at that time and figure out what to do. But as you look for the next 3 years, it's positive for us across that and the LNG book. And to your point, if those spreads do compress and that is through Waha strengthening, then yes, we do get better prices than on our equity gas and it doesn't fully offset that because we have a little bit more capacity than our production, but it does mitigate that drop on the marketing side because you're making more on your equity gas that you're producing.

Got it. Maybe just sticking on the financial front. The balance sheet improvement efforts have been really good, now down to $4 billion at year-end '25. You still have the $3 billion kind of long-term target there. Is the goal to stick with that 60-plus percent 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're hitting that target this year?

Yes. I mean, we think that 60% is competitive. We've exceeded it every year since we outlined that in 2021. We've exceeded the 60% and we think that that's a prudent level right now. We also are using portions of our free cash flow to invest in exploration.

And I think a lot of our peers don't have the exploration portfolio that we have. We're thinking about that longer term as well. And so that 60% takes that into account as well as balance sheet management and managing our ARO and decommissioning spend and so we're managing all of that. The $3 billion target we put out, recall that was kind of at a mid-cycle price of $70, we'd get there in kind of 3 to 4 years.

Prices go higher than that. We can get there potentially by the '27, '28 time frame, and they're lower, then it will be end of the decade. The point is that we've made a lot of progress through cost savings, capital efficiency, execution in the field and all of that pulled together has increased free cash flow last year. You look at '25 free cash flow compared to '24 free cash flow.

It was up over 20% with lower prices. And so that's just a testament to what the team has done and we used a lot of that to return to shareholders, but we also paid down a lot of debt. So just -- we've got flexibility in our program, as outlined with the Permian inventory and the Egypt Gas, you take all that together, we still feel pretty good about reaching that $3 billion kind of at current prices in the next couple of years.

Our next question comes from the line of Leo Mariani with ROTH.

I just wanted to follow up a little bit on the Permian inventory. Just wanted to make sure I sort of understood it from a definition perspective here. when you guys kind of talk about a 10% or greater rate of return, is that like a field level sort of pretax return. Just wanted to make sure I sort of understood that. Does that not include like any kind of corporate burden or anything for G&A?

It doesn't include a corporate burden, but it does include full field cost burden. And it is before tax and after tax, we probably won't be paying tax for quite some time.

Okay. That's helpful. And I just wanted to follow up on Egypt. You guys spoke about this. I mean, you could give us a little bit of a quantification, you did speak about how Egypt gross oil was going to decline in 2026. Is there kind of a rough ballpark percentage on that in terms of the decline you're going to see?

Well, Leo, I mean, if you look at it, we've been able to with the waterfloods, hold oil volumes flat for the last 3 quarters. So we're still prioritizing oil we've just shifted the gas rigs up to 50% from we started last year at 25%. So we're just going to be drilling more gas wells on a relative basis. And so as a result, we're going to forecast gross BOEs, gross gas or gross oil to slightly decline.

But we've had a pretty good track record of being able to sustain that through the waterflood projects.

Well, and also quite a few of the gas fields. Our rich gas have condensate with them, and so that shows up as oil volume as well.

And some of the new exploration acreage also is perspective for oil as well. So -- but it's just how we steered gross oil.

Thank you. I would now like to turn the call back over to John Christmann, CEO for closing remarks.

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

With a structurally lower cost base and a stronger balance sheet, 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 a strong foundation, disciplined capital allocation, and a clear line of sight to incremental free cash flow from Suriname beginning in 2028. We are very well positioned going forward. With that, I will turn the call back to the operator. Thank you.

Thank you. This concludes today's conference. Thank you for your participation. You may now disconnect.