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DATE

Thursday, Aug. 6, 2026 at 11:00 a.m. ET

CALL PARTICIPANTS

• Managing director, investor relations - Stephane Aka
• Chief Executive Officer - John J. Christmann
• Chief Financial Officer - Ben C. Rodgers
• President - Stephen J. Riney
• Executive vice president of exploration - Tracey K. Henderson

TAKEAWAYS

• Adjusted Production -- 347,000 BOE per day, exceeding management guidance for the quarter.
• U.S. Oil Production -- 123,500 barrels per day, reflecting drilling and completion efficiency gains in the Permian Basin.
• Net Income -- $747 million, or $2.11 per diluted common share, reported for the second quarter.
• Adjusted Net Income -- $669 million, or $1.89 per diluted share, excluding an unrealized gain of $92 million from basis hedges.
• Free Cash Flow -- $738 million for the quarter, bringing the first half of 2026 total to more than $1.2 billion.
• Cost Savings Target -- $500 million annualized run-rate savings expected by year-end, up from the previous $450 million goal.
• Net Debt -- $3.3 billion at quarter-end, with the company targeting a $3 billion level in 2027.
• Debt Reduction -- $752 million of bond debt repaid in the first half of the year, including $673 million in the second quarter.
• Annualized Interest Savings -- Approximately $175 million lower exiting the year compared to the end of 2024.
• Permian Rig Count -- Four rigs expected for the remainder of the year, down from an initial plan of five rigs.
• U.S. Oil Guidance -- 123,000 barrels per day for the full year, an increase from the original 120,000 barrels per day forecast.
• U.S. Capital Budget -- $1.3 billion maintained for the full year despite inflationary pressures.
• Egypt Gross Production -- 207,000 BOE per day, including 539 million cubic feet of gas per day.
• Egypt Gas Pricing -- Approximately 50% of gas production now benefits from the revised pricing agreement signed in 2024.
• Egypt Full-Year Outlook -- 118,000 barrels of oil per day and 535 million cubic feet of gas per day on a gross basis.
• Suriname GranMorgu -- First oil remains scheduled for mid-2028, with development progressing on budget.
• Alaska Exploration -- Two wells planned for 2027, comprising an appraisal of the Sockeye discovery and an exploration well on the Chinook prospect.
• Uruguay Partnership -- ENI will fund a significant portion of the initial exploration well in Block 6, with the company retaining a 60% interest.
• Lease Operating Expense -- $1.5 billion full-year guidance, a reduction of $25 million from previous estimates.
• Shareholder Returns -- $189 million returned in the second quarter through dividends and the repurchase of 2.8 million shares at an average price of $35.26.
• Gas Trading Cash Flow -- $950 million pretax cash flow expected in 2026 based on current strip pricing and basis hedges.
• Exploration Capital -- Slightly lower for the full year due to a shift in timing for Suriname Block 58 activity.
• Alaska Acquisition -- $70 million upfront consideration for Savant Alaska, securing pipeline and processing infrastructure.
• Permian Operating Cost Target -- $3.5 million per month run-rate savings target on track for achievement by year-end.
• Adjusted EBITDAX -- $1.8 billion reported for the second quarter.

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RISKS

• Christmann stated that performance from recent gas discoveries "resulted in the deferral of some lower pressure gas volumes at Khafre," which led to a reduction in the near-term gas production outlook for Egypt.
• Rodgers stated that structural efficiency gains in the United States and the North Sea are "offsetting inflationary pressures such as global diesel costs."

SUMMARY

APA Corporation (APA -1.60%) reported adjusted production of 347,000 barrels of oil equivalent (BOE) per day and net income of $747 million for the second quarter. Management increased its full-year oil production guidance for its Permian Basin assets while maintaining its capital investment forecast at $1.3 billion. The company reported a reduction in total debt of $2.3 billion since the end of 2024 and raised its annualized cost-savings target to $500 million. Strategic focus remained on advancing exploration in Alaska, Uruguay, and Suriname, with first oil from the GranMorgu project in Suriname scheduled for mid-2028.

• CEO Christmann noted that the company is "benefiting from a large carry in Suriname today," which supports development programs in Egypt and the Permian while maintaining shareholder returns.
• Tracey Henderson noted that interest in Uruguay was driven by proof of "source rock on the African side of the margin" in Namibia, which the company intends to test on the conjugate margin in South America.
• Ben Rodgers stated that because of its "unhedged transportation portfolio" being matched by Permian gas production, changes in Waha pricing have "very little impact" on the company's consolidated free cash flow.
• CEO Christmann described the acquisition of Savant Alaska as "strategic" because it provides infrastructure including an airstrip, a dock, and a 25-mile pipeline connection into the Trans Alaska pipeline system.
• Management indicated that Permian oil production is being sustained at approximately 123,000 barrels per day with four rigs, compared to the eight rigs initially estimated as necessary to hold production at 120,000 barrels per day.
• Executive Vice President Henderson clarified that the upcoming exploration well in Uruguay will be drilled "significantly deeper into the Cretaceous" than previous wells in the basin.

INDUSTRY GLOSSARY

• BOE: Barrels of oil equivalent, a unit used to combine oil and natural gas volumes based on energy content.
• Waha Pricing: A natural gas price index for the Waha hub in West Texas, which often trades at a discount to Henry Hub.
• Conjugate Margin: Corresponding geological features on opposite sides of an ocean basin that were once joined.
• PSC: Production Sharing Contract, an agreement between a government and an extraction company regarding the percentage of production each receives.
• FID: Final Investment Decision, the point at which a company commits to the full development of a project.
• Strip Pricing: The value of a commodity based on the average of futures prices over a specific period.
• Adjusted Production: A volume metric that excludes noncontrolling interest in Egypt and Egypt tax barrels.

Full Conference Call Transcript

Operator: Good day, and thank you for standing by. Welcome to APA Corporation's second quarter 26 Financial and Operational Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. During the session, please press 1-1 on your telephone. And you will hear an automated message advising your hand is raised. To withdraw your question, please press 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand it over to your first speaker, Stephane Aka, Managing director, investor relations.

Stephane Aka: Good morning. And thank you for joining us on APA Corporation's Second Quarter 26 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John J. Christmann. Ben C. Rodgers, CFO, will share further color on our results and outlook. Stephen J. Riney, President, And Tracey K. Henderson, executive vice president of exploration, are also on the call and available to answer questions. We will start with prepared remarks and allocate the remainder of the 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 noncontrolling interest in Egypt and Egypt tax barrels. I would 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 on 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 J. Christmann.

John J. Christmann: Good morning. And thank you for joining us. Today, I will review our second quarter 26 results, outline continued progress across our portfolio and share our updated outlook for the remainder of the year. Last quarter, I reviewed the pillars guiding APA strategy. Delivering top tier operational performance, building and growing a high quality portfolio, and maintaining financial discipline. Overarching all of this is our long term strategic commitment to oil and gas. Our second quarter results demonstrate continued momentum consistent with each of these priorities. Operational performance remains strong, costs are declining, both the scale and quality of our portfolio are improving, we continue to strengthen our balance sheet. At the core of our strategy is a simple objective.

Doing more with less. This is directly reflected in the quality of our execution during the quarter and the improvement in our forward outlook. It is further reinforced by the ongoing delivery of our cost-reduction initiatives. Execution has remained ahead of plan, and we now expect to exit the year with approximately $500 million of annualized run rate savings up from the $450 million target we established at the beginning of the year. More importantly, these improvements continue to strengthen the underlying economics of the business reinforcing the progress we have made over the past 2 years.

Turning to the second quarter, across our core Permian and Egypt assets, We met or exceeded production guidance while delivering capital investment below guidance. In the Permian, we have continued to build on the momentum established over the past several quarters. Oil production exceeded guidance while capital was in line with plan. Strong execution across drilling, completions, and field operations is reducing the level of capital investment required to sustain current production levels. At the same time, targeted investments to enhance base production reliability and lowering operating costs are delivering measurable results.

Based on the progress we have made to date, we remain on track to achieve our expected $3.5 million per month run rate operating cost savings target by year end. Taken together, these efforts are more than offsetting current inflationary pressures while improving the capital efficiency and overall economics of our Permian business. In Egypt, adjusted BOE production was in line with our guidance, reflecting higher gross volumes net of PSC impacts. Gross gas production grew meaningfully during the second quarter as we continue to execute our development strategy. Approximately half of our gas production is now benefiting from the revised pricing agreement improving the value of every incremental molecule we produce.

This underscores the growing value of our gas portfolio and supports a more sustainable cash flow profile for the EG business. In Suriname, the GranMorgu development continues to progress on budget and on schedule toward first oil in mid-2028. Shifting to our exploration portfolio, we also made further strides in building long term optionality. We recently announced an agreement to acquire Savant Alaska which secures critical infrastructure adjacent to our eastern north slope position and increases flexibility as we evaluate next steps. This includes a processing facility, a pipeline connection into the Trans Alaska pipeline system, and supporting field infrastructure we can leverage to appraise and potentially develop this highly prospective resource position.

Our upcoming program this winter will comprise an appraisal test to further delineate the Sockeye discovery as well as an exploration well targeting a larger separate prospect. In Uruguay, we are pleased to welcome ENI as a strategic partner in off 6 following a highly competitive process. This partnership underscores the quality of the block's prospectivity and our ability to attract top tier partners to progress large scale exploration opportunities. APA will retain a 60% working interest with ENI funding a significant portion of the initial exploration well, which we plan to spud in 2027. Turning to capital returns. We continued making progress toward our $3 billion net debt target while returning capital to shareholders through dividends and share repurchases.

Our long term capital allocation framework remains unchanged. Since introducing the framework in late 2021, we have consistently returned at least 60% of free cash flow to shareholders every year while also improving the balance sheet. We expect to achieve this again in 2026. Moving to our full year outlook. Our updated guidance reflects a broader improvement in the capital efficiency and durability of our 2 core assets. As a reminder, following the Callon integration, we initially estimated that sustaining Permian oil production around 120 thousand barrels per day would require 8 rigs and roughly $1.7 billion of capital. Since then, improvements in drilling, completions, and base management has significantly lowered capital intensity.

As a result of these structural efficiency gains and our strong operational execution, we now expect to operate 4 rigs for the remainder of the year while raising our full year oil production guidance to 123 thousand barrels per day. This is a significant increase relative to our original guidance of 120 thousand barrels per day. While our capital budget remains unchanged at $1.3 billion despite certain inflationary pressures. Egypt has followed a similar trajectory. Although the drivers have been different. Since signing the revised gas pricing agreement in 2024, we have maintained annual capital at roughly $500 million net to APA while progressively allocating a greater share of this investment towards attractive gas opportunities.

Even with this shift, gross oil production has continued along a modest and predictable decline trajectory. While gas production has grown meaningfully. Supported by a refocused exploration program and ongoing development activity. During the quarter, outperformance from recent rich gas discoveries resulted in the deferral of some lower pressure gas volumes at Khafre. While this slightly reduces our near term gas outlook, higher associated liquids offset the impact. Resulting in a similar BOE profile as originally anticipated. Accordingly, we now expect full year gross oil production of approximately 118 thousand barrels per day and gross gas production of 535 million cubic feet per day. While maintaining our original BOE production outlook.

We expect the impact on free cash flow to be minimal. More importantly, we remain excited about the significant gas potential across our Egypt acreage position. Our full year outlook also reflects slightly lower exploration capital. Primarily associated with the timing of exploration activity in Block 58. The next exploration well previously planned to spud late in the fourth quarter of 2026 is now expected in 2027. In closing, I would characterize the second quarter with 1 word: momentum. We are sustaining top-tier operational performance across our portfolio driving stronger production, lower costs, and lower capital intensity.

These results reflect the structural improvements we made over the past 2 years to become a cost leader and drive higher capital efficiency across our core assets in the Permian and Egypt. We are well on our way to achieving our $3 billion net debt target which will improve resilience across commodity price cycles and provide greater flexibility for the long term. Taken together, APA is entering its strongest position in several years. With a highly capital-efficient base business, multiple high quality investment opportunities in exploration, a strengthened balance sheet, and a clear path to organic oil production growth led by GranMorgu. With that, I will turn the call over to Ben C. Rodgers

Ben C. Rodgers: Thank you, John. For the second quarter, APA reported consolidated net income $747 million or $2.11 per diluted common share. Consistent with prior periods, these results include items outside of core earnings. The most significant after tax adjustment was an unrealized gain of $92 million related to our basis hedges. Excluding this and other small items, adjusted net income for the quarter was $669 million or $1.89 per diluted common share. 1 additional item to note is that deferred tax expense increased during the second quarter. Primarily due to higher US income, which accelerated the expected utilization of our U. S. Net operating losses.

This is a noncash item that had no impact on second quarter cash flow and only has a minimal impact on our current outlook for full year current tax expense. We generated $738 million free cash flow during the second quarter, and returned $189 million to shareholders through dividends and share repurchases. Underpinning these results was strong execution across production, capital and operating costs. Some of the cost variance was timing related. Particularly in the North Sea with a lifting schedule for our crude oil sales shifted a portion of LOE from late second quarter into early third quarter.

However, these results also reflect underlying efficiency gains and cost savings, particularly in the US, which have offset inflationary pressures such as global diesel costs. Through the first 6 months of 2026, we have generated more than $1.2 billion in free cash flow, which is more than we produced during each of the past 3 years. While higher prices have played a role, we are also benefiting from structural improvements we have made across the business over the past 2 years. Through sustained cost reductions, capital efficiency gains, and portfolio high grading, we have materially enhanced the cash generating capability of the company.

As a result, a greater share of every dollar of revenue is converted into free cash flow strengthening our capacity to reduce debt, return capital to shareholders, and invest in the long term future of APA. John covered the operational progress across the business. I will focus on how those improvements are translating into a stronger financial profile beginning with our updated full year outlook. We now expect to exit the year with $500 million of run rate savings up from the $450 million target we outlined in February. These higher savings reflect broad based improvements across the business that are now embedded in our cost structure.

While inflation will continue to fluctuate over time, these efficiencies provide a lasting free cash flow tailwind by improving margins, enhancing capital efficiency, and increasing resilience across commodity price cycles. that is exactly what we mean when we say we are doing more with less. Turning to our full year guidance, we now expect lease operating expense of $1.5 billion, $25 million below our prior guidance. This reduction reflects the continued execution of our cost reduction initiatives. With savings primarily in the US and North Sea, more than offsetting diesel inflation. This further demonstrates that the efficiency improvements we have implemented over the past 2 years are delivering durable margin and free cash flow benefits.

Shifting now to our gas trading portfolio, which remains a unique source of cash flow and an important competitive advantage for APA. Based on current strip, we expect to generate approximately $950 million of pretax cash flow in 2026, inclusive of our basis hedges. As a reminder, changes in Waha pricing have very little impact on APA's consolidated free cash flow, because our unhedged transportation portfolio is closely matched by our Permian equity gas production. Higher Waha prices increase gas production revenue, but reduced income from our transportation portfolio by a similar amount. While lower Waha prices have the opposite effect.

Taken together, our strong operating performance, structural cost improvements, and differentiated gas trading portfolio position us to generate approximately $2.3 billion of free cash flow this year at current strip pricing. This enables us to continue strengthening the balance sheet while returning meaningful capital to shareholders. Turning to the balance sheet, we repaid $752 million of bond debt during the first half of the year, including $673 million in the second quarter. As we discussed in May, stronger commodity prices prompted us to consider how we should allocate this year's incremental free cash flow. As a result, we will continue returning at least 60% of free flow to shareholders every year through dividends and share buybacks including this year.

We also expect to achieve our $3 billion net debt target in 2027 based on current strip pricing. That is well ahead of the 3- to 4-year time frame we outlined when we announced the target last year. In closing, we delivered a very strong second quarter. With production above guidance and lower capital and operating costs. The business today is fundamentally stronger than it was just 2 years ago. In the Permian, we have established a clear cost leadership position that is driving durable free cash flow. In Egypt, we have positioned the asset to generate stable free cash flow with attractive reinvestment rates.

Looking ahead, GranMorgu will provide a differentiated source of high margin oil production while driving free cash flow growth into the next decade. Together with our strong balance sheet, this portfolio positions APA to deliver durable free cash flow and long term shareholder value. With that, I will turn the call over to the operator for Q and A.

Operator: Thank you. At this time, we will conduct a question-and-answer session. We will allow time for 1 question as well as 1 follow-up. As a reminder, to ask a question, you will need to press 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press 1-1 again. Our first question comes from Doug Leggate of Wolfe. Your line is now open.

Doug Leggate: Thanks. Good morning, everybody. John, this is the first time that you have had a call since you acquired Savant, and I wonder if I could just ask you to maybe offer as much color as you can because your partner has been pretty open about the potential for a, you know, recoverable development north of 400 million barrels. You have now bought a pipeline, which I presume you would not have done if you were not at least aligned on the possibility of that. So can you share what your current thinking is Do you have a the semblance of a development with Sockeye as it stands today, or is it contingent on a successful appraisal program?

And any other color you can offer would be great. Thank you.

John J. Christmann: Well, Doug, I always appreciate you coming in. You know, we are we are super excited about our position in Alaska. You know, it is now close to 500 thousand acres. We are on state lands. it is something we entered into in, you know, in 2023. We have now drilled 2 successful discoveries. With Kingstreet and Sockeye. We were able to test Sockeye. You know, we took a break this last winter to reprocess because there were multiple surveys that needed to be stitched together. So we are very, very excited. We said we have got a high quality sand there. We can now confirm that we did not drill Sockeye in the thickest portion.

We have got, 2 key wells set up for, you know, for this upcoming winter. We will start building ice roads, late this year and then, you know, spud 2 wells in 2027. 1 will be an appraisal well of Sockeye, Hungry Horse, and then the second 1 is an even larger, independent prospect Chinook. They are both similar geology. Obviously, With the appraisal well, you are appraising the Sockeye discovery. And Chinook is a, you know, a similar prospect, but just much larger. You know, what Savant brings to us, Doug, it is strategic in that, you know, it is positioned right next to us. It obviously has a 25-mile you know, pipeline, with 80 thousand-barrel-a-day pipeline capacity.

But it also brings a large, you know, gravel pad there is 40 thousand barrels a day of processing. Equipment. And, you know, it has an airstrip as well as a dock, And so it will be, you know, advantageous to us even in the appraisal process. And, also, obviously, if we went on to you know, to a development. it is early for us to call any development plans at this point. But we are pretty confident we have got a lot to work with up here, and we are very, very excited.

I think the thing that we have always talked about that both Kingstreet and Sockeye proved is that we have got higher quality reservoir rock than some of the, you know, plays that are being developed, you know, quite a ways away. You know, to this. And so we are very excited about it. it is state lands. it is oil. The new processing of the seismic, it was really, really good call. So we are very, very excited about it, Doug. But, you know, our next step will be to appraise Sockeye, drill Chinook, and then, you know, come back and be in a position to talk more about it at that point.

Doug Leggate: Okay. I understand. Thanks, John. My follow-up, if I may take advantage of Ben being on the call, or whoever wants to take this, but the ENI deal, ANCAT has you know, has given quite a lot of detail on the prospect the prospectivity of the whole area. ENI is obviously a top 1 of the top, if not the top, global explorer in the last several years. I guess my question is simply this. there is 1 well in the deep water, Raya, that you know well. It looks to us that it did not go deep enough. Can you characterize what the expiration optionality is in Uruguay, and what happens beyond the first well?

John J. Christmann: Well, you know, we have got 2 blocks, block 6 which we had a 100%. We now have 60% in that. And we are really, really thrilled to welcome ENI as our partner. It was a very competitive process. And, you know, it Really Speaks To The Quality Of Our Position In Uruguay and how, you know, prospective that block is. But also a credit to our exploration team, in the work we have done, you know, now with Suriname bringing in Total, and we are less than 2 years away from, you know, first oil there with GranMorgu. And now bringing ENI into, you know, block 6 in Uruguay. So we are thrilled to have them here.

I will let Trey jump in. Obviously, the you know, the 1 well was to--you know, and we believe was not drilled deep enough. Our objectives will be much deeper. But I will let Tracey talk a little bit about the geology and, you know, what the concepts are and what we have got there.

Tracey K. Henderson: Sure. Hi, Doug. I think the--1 of the critical drivers for entry into Uruguay was the recent discoveries on the Namibian side in the Orange Basin in Africa. Which really proved source rock on the African side of the margin that before had not been proven. So that is driven our interest and a lot of the interest into Uruguay. And, you know, what we are looking at is basically the conjugate margin geology. that is worked on both sides of the Atlantic margin, up and down West Africa and Latin America. Now having proven Source Rock on the African side, we are looking to step over and test that on the conjugate margin on the Uruguay side.

And so really, it was that source rock data that drove interest that we are going to test on the Uruguay side. The interesting thing, as you pointed out, there is there is really only 1 well in the deep water in Uruguay, and that is the Raya-1 well. And you are correct in your statement that we do not believe it tested nearly deeply enough. it is quite a shallow well. Relative to where the source rock is. And what has worked on the African side is our reservoirs are very close to source. We are going to be testing the same concept where we see reservoirs very close to source and much deeper than the Raya-1 well tested.

So with the exploration well, we will be looking at that source rock, but also testing deposition, migration, and trap and seal on the So it will be a very, very big well. We have got a really high quality 3D seismic dataset over the prospects in block 6 and block 4 that we are looking at extending it in block 4. But we have seen some terrific prospect ivity on the 3 d very large prospects. And as John said, we will look at testing that in late 2027. Great. Appreciate the answers, Tracey. And thanks a lot. Thank you, Doug.

Operator: Thank you. Our next call comes from John Freeman of Raymond James. Your line is now open.

John Freeman: Thank you. Hi, guys. Good morning, John. Last quarter, you know, y'all maintained the flexibility between debt reduction of buybacks and now given just how strong the balance sheet is. Obviously, y'all are pretty explicit that the number 1 priority now that the free cash for the rest of the year is on is on the buybacks and kind of reiterating that minimum 60 annual return of free cash flow to shareholders. And just given that there was some maybe confusion in the market the prior couple of months, maybe just give you all the opportunity to kind of, readdress sort of that framework and how you all think about those allocation priorities going forward.

Ben C. Rodgers: Sure, John. This is Ben. Good question. And, yeah, back in May--and I referenced this in my prepared remarks, what we said was that we were going to take time to evaluate what, you know, the right use of the incremental free cash flow, between the debt and the equity. And, you know, through that process, really, where we landed was, you know, sticking to the commitment to the 60% because our balance sheet is continuing to strengthen. With the $2.3 billion of free cash flow this year, we expect to have net debt at $3.3 billion by the end of the year. We actually think gross debt actually is going to be pretty close to that as well.

Which is gonna just help with our fixed charges going into 2027. And, you know, having that so close, from when we outlined the target in August and here we are, you know, at the time in May, you are 9 months from that, and it, you know, was so close. Really just gave us the opportunity to look at, you know, balancing those 2 different commitments around the equity returns and reaching that $3 billion. But we are in a great position from a balance sheet, lowest debt balance that we have had at Apache. In over 15 years.

And, you know, just wanted to make it clear that we are we are still committed to the, at least 60% return. You know, we have not returned that much in the first half of the year. And so, yes, that implies that you know, we have got quite a bit of share buybacks to do in the second half of the year, and we are going to do that.

John Freeman: that is great. Thanks for that, Ben. And then, you know, y'all raised your cost savings target yet again to the $500 million Can you kind of clarify how much of that has actually been captured versus what still needs to be achieved between kind of now and year end? I know you all highlighted some projects in the Permian in the presentation, but just a little bit more clarity on what is captured and what is still left.

Ben C. Rodgers: Yeah. So, I will actually do from an annual basis. John. In earlier this year, what we said was we had actually captured $300 million of savings in 2025, and then that set up your run rate exiting 25 of the $350 million. And we said we were going to capture $400 million of savings this year, and that led to a $450 million run rate. As we have gone through the first half of the year, given the execution across our portfolio, in Permian, Egypt, and North Sea across LOE and capital, what we have seen is that captured amount which was $400 million, is actually closer to the high 400.

Call it $475 million Some of that is being offset with inflation, and we have talked about that. You have got, you know, higher diesel costs and a little bit higher service costs, across the lower 48 that I think all industry is starting to see. And so that captured amount putting aside inflation, would have been $4.75 when you count that inflation, it is it is probably closer to $425 million. But because we are capturing more true savings, that run rate is now higher than the $450 million, and it is now $500 million. And it is across all 3 of the buckets. We are seeing capital efficiencies in the Permian and in Egypt.

We are actually through field initiatives, across our portfolio, namely in the Permian and the North Sea, we are seeing, LOE savings. And then G and A continues to, trend in the right direction as well. So that incremental $50 million of run-rate savings exiting this year is across all 3 of those buckets. On top of that, you know, we have we have separated the controllable spend of those 3 buckets from interest expense savings. But we also now because and from my prior comments around gross debt and net debt, we think that, annualized interest savings exiting the year is going to be closer to $175 million lower.

So $675 million as we exit this year of true costs being lower than they were as we exited 24. And to put that in context, you know, we have outlined $2.3 billion of free cash flow this year. Had we not started this, 2 years ago, around controllable spend and really getting after the debt pay down that 2.3 billion would actually be closer to $1.7 billion. So a testament to the team and all of the hard work that is been done on the cost and enabled us to pay down debt and really position Apache very strongly as we exit this year, from a cost standpoint. And consider ourselves really a cost leader now. Perfect. Thanks again.

Operator: Thank you. Our next question comes from Joshua Silverstein of UBS. Your line is now open.

Joshua Silverstein: Hey. Thanks. Good morning, guys. You know, Ben, you highlighted some of the benefits of the gas trading portfolio and how there is limited free cash flow impacts from the change in Waha prices. And I believe some of this is due to the hedges that you guys have in place for this year. I was hoping directionally if you can kind of give us a view into next year Do you plan on adding some additional basis swaps to kind of have a similar kind of net zero impact and, how things may look, you know, for you guys next year?

Ben C. Rodgers: Sure. Good question. You know, actually, since we have, since those pipeline positions have been put in place and, starting in 2019 and 2020, and then the, Cheniere LNG contract. A few years ago We have not hedged LNG. We have talked about that, kind of given the volatility in that. And we like the exposure to the upside of LNG pricing, which has actually helped and benefited us a lot this year. So our hedging program around our gas trading book has been around the basis. And you look back over the past 5+ years, almost every year, we have had a hedge position in place. And so, would expect that trend to continue into next year.

We have not put any in place for 2027 yet. We do monitor that and we and we do like the position that we are in this year. Because it does provide that unique offset of higher Waha prices that benefits our equity gas production, and it is, you know, offset by the loss on the transport side net of hedges, It is unique. it is, you know, providing at least investors some stability and understanding of you know, that, that free cash flow that is coming from that business. So we have not put any hedges in for next year. We do look at that. And we will update folks through the year if we do.

Joshua Silverstein: Got it. And then, you know, John, you had mentioned your 2 years away from the start up of the GranMorgu Project, that is clearly a key differentiator for your growth profile into the future. And knowing you have this around the corner, how does this impact the development of the existing asset base and capital allocation strategy? Do you want to hold things steady with the existing production base? But how do think about different options there?

John J. Christmann: Yeah. I mean, I think, Joshua, it is a it is a great question. And, you know, first of all, things are on track with GranMorgu. You know, we have said mid-2028 first oil. And, you know, Total came out and said, you know, potentially first second quarter of 28. So we are going to stick with mid-2028. You know, what it is positioned us to where if we can just maintain volumes when, you know, when our core assets, Permian and Egypt, well, then you have got growth coming, right, through our exploration program and through GranMorgu. I think a couple of things.

So, you know, the big thing here is the way we structured our, joint venture with Total. You know, we are benefiting from a large carry in Suriname today, which has enabled us to continue to fund, you know, our programs domestically and internationally. With Egypt and you know, Permian. But it is also let us continue to make progress on the balance sheet and deliver on the returns framework while we are funding such a large scale capital project. And so you know, it really, really is, is work to our advantage. And quite frankly, without that, we would not be in the position we are in today.

So it is really set us up to, you know, run those businesses like we would like to run those. You know, we worked on adding durability inventory life you know, to Permian where we can run flat for, you know, more than 10 years. Which is kinda what we laid out earlier this year. We are obviously exceeding that with volumes and capital efficiency that we continue to have come through. And then, obviously, gas has changed our picture in Egypt as well. So we have been you know, growing our BOEs, gross BOEs in Egypt.

So you know, it puts us in a really, really unique place today with our exploration program where we can allocate to the projects and let the projects get the capital they need, and we are not having to constrain everything. All along bringing Suriname along. So know, it puts us in a really, really good place to continue doing what we are doing, and, you know, we are we are thrilled to be in the in the place we are in today. Thank you.

Operator: Our next question comes from Arun Jayaram of JPMorgan. Your line is now open.

Avram Jawram: Good morning, John and team. John, I was wondering if you could comment on how you think your sustaining requirement sustaining capital requirements in The US are evolving. This year, you guys have highlighted $1.3 billion of domestic capital for a 123 thousand barrels of oil, but then you did mention how your rig count now is going down to 4. And, obviously, you are you are generating some efficiencies. So I know you are probably not ready to give us a 2027 guide, but I wanted to see if you thought there is further potential to reduce sustaining capital based on efficiency gains?

John J. Christmann: Yeah, Arun, it is a it is a great a great question, and we are, you know, we are in a really dynamic period both for us and industry. And if you go back to, you know, post close of Callon and you know, we believed it was 8 rigs to hold a 120 thousand barrels a day flat. You know, as you mentioned, we are now currently at 4. We have guided to 23 for this year. it is been a stair step down as we, 1, changed our development philosophy and have really let the cost side, you know, drive a lot of things. Today, we are clearly under 6.

We have been running you know, we are at 4 rigs, you know, today. We started at 5. We dropped down to 5 last year. You know, we are clearly under 6 rigs to you know, to maintain at 21. We have been doing that for the last 2 years. So it does give us some flexibility in terms of how we think about that. And, know, I am not ready to dive into, to 27. You know, give a little bit of an insight today, talk a, you know, a little bit in November, and then, in February, we will come out with a plan.

But, the way the efficiencies have been running through and the team continues to make really, really meaningful progress. And know, very proud of that. And, you know, I think the, the 1 other thing I would say is you know, the number of rigs is not as critical of a number as it used to be because it ultimately boils down to wells you are drilling, footage drilling, and the turn in lines. But, you know, I do not know. Steve, anything you want to add to add to that?

Stephen J. Riney: Yeah. John, I will just you know, just to just to echo your last comment there. We started the year this year with a plan of 5 rigs and we are we are clearly gonna end up at 4.5 rigs. Those 4.5 rigs will drill more lateral feet and we will complete just as many wells as we planned with 5 rigs. And so we are down to 4 rigs the second half of the year. We are actually moderating frac activity in the back half of the year as well in order to meet our capital budget of $1.3 billion. And so it is just a--yeah.

Again, to your earlier comments, it is about the both the scale and the pace of change and efficiency gains that the team has gotten to, and it is continuing in 2026. 2025 was obviously a really big year where we started off with this notion that 8 rigs sustain a 120. And halfway through the year, we were at 6 rigs. Sustaining a 120. And I agree with you. Right now, we are we are we have been we have been delivering basically a 123 thousand barrels of oil a day And by the end of this year, it will be for 2 years straight. And we are doing that clearly with, fewer than 6 rigs.

We will average 4.5 this year. Not saying that it is 4.5, but as we as we do the planning for 2027, we will talk a bit about it in November and then obviously give the details in February after we have had the full discussions with the board and the full review of the plan.

Avram Jawram: Appreciate that. And maybe just a little bit of a follow-up. On Egypt. Where you guys mentioned that you are testing some new play concepts. Wondered if you could elaborate on some of the exploration type work you are doing in the Western Desert.

John J. Christmann: Yeah, Arun, We have been we have been in the Western Desert since 1.99 thousand. And, you know, until really, you know, late 24. All we focused on was, you know, oil and exploring for oil. Obviously, we entered into a new price agreement, you know, in November 2024. We started then to, you know, how do you translate what we know into gas? We knew there were some low hanging fruit that you saw us get after you know, last year, but we have really only been exploring now for gas. The Western Desert for, you know, call it, 12 to 18 months. So we are stepping out.

A lot of it is similar type rock, but you are looking deeper now. You know, the key to think about in Egypt is you know, we have got 20 thousand feet of sand effectively. So the exploration program there is much different than the offshore stuff where you have got your seismic tuned, it is either there. it is not, you know, Egypt. it is the nuances of can we predict you know, where we have got trap and seal. In a lot of places, you have too much sand. So the program has been very consistent. that is why you see kind of a steady diet of successes, as well as some dry holes.

Because at depth, it is hard to really differentiate know, sand versus pay. But, the good thing is when you have your discoveries like we have had, the follow ons are usually very predictable. And then we can take those and extrapolate into multiple wells. And so a lot of it is you know, stepping out into deeper parts of the basin. it is stepping into places that we avoided because we thought it might be more gas prone. So it is really, you know, putting a new lens on what we have done for 30 years and just thinking about it more from the gas perspective. But we have got a lot of key wells coming up.

We have drilled a lot of ice discoveries You know? So very pleased with the program. But, you know, it the key here is this it is conventional. it is not unconventional. And, you know, success has been set up, you know, 1- to 2- to 3- to 5-, you know, type well offsets. And so we have got a lot of a lot of concepts that are at play. Thanks, John. Thank you.

Operator: Thank you. Our next question is from Neal Dingmann of William Blair. Your line is now open.

Neal Dingmann: John, my first question is just a little bit more on your exploration program, specifically you have had, you know, been active in Alaska and Uruguay. I am just wondering, are those areas where you consider sort of at the front of the potential exploration line or you know, would you all also consider exploration activity, I do not know, maybe in Block 58 or other blocks in Suriname as well as you know, maybe in any other new areas you might see.

John J. Christmann: Yeah, Neal. I mean, I think the most important thing there is we have stayed committed to exploration. Know, we have tried to allocate approximately 10% to 15% of our capital, you know, to expiration. it is something we stuck with. You know, obviously, you know, going back to, 2019 when we spud the first well in block 58. And then we ran a rig during 2020 during COVID in block 58. From there, we went into appraisal in Suriname and continued to explore We recognized in 2022, we had what we needed to get to an FID in Suriname and really tasked the team for what else was out there.

And it was a you know, a very rare window in time where early 23, hardly anybody else was exploring. And so it let us step in to places like Uruguay with even success being announced in Namibia across the conjugate margin was very, very quiet. Right? So that was an easy enter into Uruguay for us. You know, we were able to do the deal with Armstrong in Alaska on state lands. For what is now a very large position. So, you know, I think the important thing is we were able to kinda build out our portfolio at a time when we knew we had expiration dollars to spend. We were able to attract high quality people.

And it got us kind of ahead as a lot of folks have started to think about exploration starting last year and now this year. And so you know, when you look at our portfolio today, you know, you have follow-on Block 58 success. There is more to do in block 58. You know, we will be back in there with, with Total next year. Exploring, and, we are looking to either add you know, to the plateau for GranMorgu or potentially more infrastructure So we are very excited about Suriname. We are very excited about, you know, Alaska as well.

I would put both the block 58 in Alaska at the top because we have derisked those now with success. We are very, very excited about Uruguay. It is a fantastic looking area. But it is frontier. You know, we do not have a well deep enough in that basin. So we need to go see. You have got, what Tracey described. You know, to Doug a little bit earlier in the you know, q and a. Across the conjugate margin in Namibia. But so we are very, very excited about it. And, of course, the team is always looking for other things.

But quite frankly, I think we have got a portfolio today that is very, very differentiated, very unique. And quite frankly, we have really derisked you know, both Suriname block 58 and Alaska through already what are successes. Yeah. I would agree on the deep portfolio and the and the derisking you guys have done a fantastic job.

Neal Dingmann: And then just a second question around the Permian natural gas takeaway. Maybe for you or Ben, just specifically looking at slide 19 for your presentation last night, would y'all consider adding further Feet or, I guess, maybe ask another way, is your gas takeaway capacity at all limiting potential future oil growth. Does not appear to me, but just wanna see how you are considering that? No.

Ben C. Rodgers: I would We are in a good spot right now. You know, we do have more capacity than we do equity production. You know? So there is there is potential room to fill that. But, you know, as we look at it right now, we are in a really good spot. It is paid. Very well dividends over the past, you know, 5 years since it is been in service. And, you know, we are it is 2026. The first expiration, comes from GCX in 2029, and we will make the assessment then.

We have got extension options on that and PHP 2 5-year extension options. that is great optionality as you think about our total US portfolio and what we would like to do really as we get into the next decade. Do we wanna keep that optionality or not? So, you know, it is it is we are in a really good position right now as we look at that. Thank you, Ben.

Operator: Thank you. Our next question is Chris Baker. Of Evercore ISI. Your line is now open.

Chris Baker: Hey, guys. Thanks. Just wanted to maybe step back for a second. Some know, some great progress in terms of the debt reduction we have seen year to date. Obviously, with the $3 billion target and expecting to end the year at $3.3 billion, you know, it does seem like we are coming up to a point where, you know, you will be at target. I am just curious, John or I do not know, Ben, you want to take this 1.

Just around the added flexibility that hitting that target provides in terms of you know, either incremental cash return to shareholders or if there is other things as you look out at the landscape in terms of exploration and frontier opportunities that kind of rise to the top of your list, we would love to get a sense just for how you are thinking about that.

John J. Christmann: You know, first off, Chris, in terms of how we are thinking about things, I think we are in a good place. I mean, 2027 will be an increased year. You know, 2026 has been light for us, and in terms of true exploration spend. That will kick up next year because we have got such a high quality portfolio. You know, the base business is running extremely well. And Suriname's coming down the pike, you know, quickly. So we are we are in a really, really good place. Which puts us in a nice position, and that is why we have been able to make such progress on the balance sheet and you know, stick with the returns framework.

So, Ben, I will let you comment more on, you know, specifically the 3 billion debt target.

Ben C. Rodgers: Yeah. I think it is it is a it is a fair question, Chris. And when you look at I said in my prepared remarks, we expect that strip to reach the $3 billion in 2027. I mean, we are a stone's throw away there. We sit here today and at the end of the year. And so, you know, 2027, you reached that. You will be, you know, likely within a year plus from Grand Morgue, that brings not only oil production growth, but growing free cash flow 2028 through 2030 on top of a business with, you know, the Permian and Egypt that will continue to sustain that free cash flow, generation ability.

And so, you know, what we can say now is, I think, once you hit the 3 billion net debt target, you likely put another 1 out there, to continue to delever the business. But that will be balanced with what we would like to do, with what we would like to do on the shareholder side is, between mix and also just total amount going to shareholders The good thing is we are gonna be very well positioned. We are well positioned because of what we have done on the costs. We are well positioned because of what we have done on the balance sheet. And you have got, you know, GranMorgu now less than 2 years away.

Next year would be less than 1 year away. And so it provides us a lot of optionality around that. And, and we do not have to cannibalize the investment opportunities on the exploration side that John outlined in order to still provide true cash value to our shareholders. So we will have a lot of options and as we get closer to that, we will, we will let folks know where we land.

Chris Baker: Great. Thanks. And then, you know, obviously, a lot of progress as well in terms of capital efficiency in the Permian. Getting down to the 4.5 rigs, obviously, is a big move from you all started after the merger. I am just curious, in terms of how you think about the biggest potential sources of further improvement there. I guess, where is the team's focus? We would love to get a sense of you know, where we could see continued progress on that front. Thanks.

John J. Christmann: Yeah. I think you look at the basin now and you look how long we have been in these plays and the progress you are making, you are at a point now where we have drilled a lot of wells, right, with more than 100 a year. So we are making great, great progress. A lot of the recent strides have been with really, you know, fine tuning your well designs and your you know, your slim hole You have gone to the simul, trimul, fracs. You know, all of those things. So, you know, I am going to continue working on the efficiencies.

And letting folks just continue to work on how do we eliminate you know, steps that cost you money as you work through those. But, I mean, they have got those down now where you look at the per foot numbers. You know, you really are benefiting from scale and you know, the repetitions that we have got. So you know, I think that is the big thing. You know? Some of the opening plays, a lot of what we are doing on the testing side to move the technical locations into economic You know, there is there is a lot to learn as you get into some of these other formations and things. Like the Barnett and others.

So I think you will continue to see progress there. But it is you know, you are at a point today where it is really more fine tuning, the machine and doing more and more you know, from the repetition standpoint. Thank you.

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

Bob Brackett: Good morning. I would like to return to Uruguay block 6 The Raya prospect was Cenozoic and was sitting out in a sort of record water depth, but it had prorated well out there. You mentioned chasing deeper objectives. Closer to the reservoir, so that suggests And that also suggests that you can drill in more palatable water depth. I guess, is that correct thinking? And can you talk about maybe the size of prospects and maybe the chance of success that you are targeting with that first well?

John J. Christmann: Yeah. Bob, I will I will I will say a few things. You know, 1, it is Frontier. The prospects are very, very large. You know, Tracey, I will let you jump in. They are Cretaceous. I will let you comment, a little further on that.

Tracey K. Henderson: Correct, John. They are they are Cretaceous. So we are looking at exactly the same age of source rock, for example, as we talked about in Namibia. And very similar, if not exactly the same reservoir ages that you see on the Namibian side. I think your comment about water depth is what we are really talking about is drilling deeper, not pushing into much deeper water. So we are still well inside 3 thousand-meter bathymetry in terms of drilling in the water depth.

So that is not really a factor in terms of where we are planning the well. it is not in a lot deeper water than the Raya well, but we will Be Drilling The Well Significantly Deeper Into The Cretaceous than the Raya Well tested. Great.

Bob Brackett: Quick follow-up. Would you be potentially testing multiple targets including Cretaceous and those younger Cenozoic targets? With a single well?

Tracey K. Henderson: I mean, we have got a lot of work to do, Bob, in terms of our partner. We have got some very strong views about the prospectivity, which we think is terrific. And we have got multiple options on what we are going to test. So I think we need to wait until we are a little further along with our new partner, ENI, who we are very much looking forward to as we have mentioned previously, I think they are a top tier explorer, and will bring a lot to the table technically. So we are going to engage with them, I think, on final decisions on drilling. But we have got some very good options. Very good.

Thank you.

Operator: Thank you. And our next question is from Leo Mariani of Roth. Your line is now open.

Leo Mariani: Yeah. Hi, guys. Yeah. Hi, guys. So I just wanted--you mentioned this a couple of times. I just wanted to clarify. I think you have said in the past that you are gonna step up you know, some of your capital commitments in the next couple years with more to do on the exploration side. Are you still going to be committed over the next handful of years to that 60% return of capital even if we get into a little bit of a weaker oil environment? And are having to kind of step up some of those capital commitments to some of these longer term projects?

John J. Christmann: Yes, Leo. I mean, that is something we have dialed into the how we, you know, define that 60%. You will not see us you know, stepping up beyond what we have really done in the past. it is just it is a step up from where we are this year, and I would characterize this year as more being a lighter year on the exploration spend. So, you know, it is something we have been we have stuck to, you know, over the last decade, and, you know, we will continue in the future. Okay.

Leo Mariani: And just on the exploration side, like you said, it is gonna step up in the next couple years. Is there kind of like a ballpark target? Is that kind of moving to kind of, you know, 15% plus you think of capital in the next few years? Just trying to get a sense of how meaningful that can be.

John J. Christmann: Yeah. It really is gonna vary from year to year. I think the takeaway as we kinda just give you a little bit of a preview into 2027. You know, we have got the 2 wells in the last we have talked about that. We have outlined those. So you are spending about $20 million this year for ice roads in Alaska. Those extra 2 wells. And by the way, we will firm all this up, later this year as we preview 2027 in February when we land on it. But you know, I think a decent assumption for that is kind of a $100 million to $120 million for those 2 wells in Alaska.

You know, 1 to 2 wells in Suriname. So I think those are you know, you could assume $50 million to $75 million a well net to us. And I just wanna remind folks that given where we expect to explore in Block 58, those exploration dollars are gonna be cost recoverable. But we are 50/50 with Total on those wells. And so, it is a decent proxy there. And, you know, the Uruguay well, it is it is 1 well, and likely in the back half of next year. And it is offshore, so probably a decent proxy for that is a similar Suriname well. But and we will outline the terms later on.

But you know, we are we are getting carried for most of that well. it is gonna be significantly less than the 60% working interest, that we retained there. So you kinda add all that up, Leo, and for next year, you are, you probably have a 2 handle on exploration spend. So, yeah, it is gonna be in that 10% to 15% You carry that forward, we will have to see how things go, for additional exploration, you know, Alaska and Block 58, etc. Past 2027, but there will be, you know, that increase from this year to next. And then we will take it from there as we get to the end of the decade. Okay. Thank you.

Very helpful.

Operator: Thank you. This concludes the question and answer session. I would now like to turn it back to John J. Christmann, CEO, for closing remarks.

John J. Christmann: In closing, let me leave you with 3 key thoughts. First, we are sustaining strong execution across the portfolio. With higher production lower capital intensity, and continued cost reductions. The improvements we have made across the Permian and Egypt are strengthening asset performance, increasing free cash flow resilience, and reinforcing our cost leadership position. Second, we continue to make progress towards our 3 billion net debt target and remain on track to return at least 60% of free cash flow to shareholders in 2026. Including significant returns in the second half of this year. Finally, with Grand Morgue, less than 2 years from first oil, we have a clear path to meaningful production growth.

Combined with our exploration opportunities in Suriname, Alaska, and Uruguay. This provides significant future upside and positions APA for strong free cash flow into the next decade. Thank you very much.

Operator: Thank you for your participation in today's conference. This concludes the program. You may now disconnect.