With a combined revenue of $21 trillion and $2.1 trillion in profits, the 2026 Fortune 500 is the definitive list of America's largest companies.

Fortune 500

The 300 companies on this year’s list brought in over $12.5 trillion in revenue for the latest 12 months, with the median revenue figure at $24 billion.

America's Most Innovative Companies

Almost $20 trillion in revenue—and a record-breaking $1.87 trillion in profits. Introducing the 2025 Fortune 500, the definitive list of the biggest companies in America.

The Fortune 500, in its 70th year in 2024, ranks the biggest U.S. companies by revenue.

The 25th Fortune World’s Most Admired Companies list suggests that tech giants’ peers respect them as much as ever.

World's Most Admired Companies

The Fortune 500, in its 69th year in 2023, ranks the biggest U.S. companies by revenue.

This year’s Fortune 500 marks the 68th running of the list.

After a year in which humanity leaned more heavily than ever on tech giants, see which companies topped Fortune's ranking of corporate reputation.

This year’s Fortune 500 marks the 67th running of the list.

For an astounding 13th straight year, Apple claims the top spot in Fortune’s annual ranking of corporate reputation, based on a survey of almost 3,800 executives, directors, and analysts.

This year's Fortune 500 marks the 66th running of the list.

F500-2020-465-Apache

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

Here are the World's Most Admired Companies for 2019 as ranked in their industries. See who made the list.

This year's Fortune 500 marks the 65th running of the list.

Here are the World's Most Admired Companies for 2018 as ranked in their industries. See who made the list.

This year's Fortune 500 marks the 64th running of the list.

This year's Fortune 500 marks the 63rd running of the list.

This year's Fortune 500 marks the 62nd running of the list.

Business insiders have spoken: Asked which companies they most admire, more than 4,100 executives, directors, and analysts chose these top 50 All-Stars.

This year's Fortune 500 marks the 61st running of the list. Wal-Mart claims the top spot again. See who made the list.

Wal-Mart stayed on top as its sales crept closer to half-a-trillion dollars. Apple moved into the top five. And UnitedHealth Group continued its steady climb. 

Sector

Industry

Industry Rank

Previous Industry Rank

Overall Score

Innovation

People Management

Use of Corporate Assets

Social Responsibility

Quality of Management

Financial Soundness

Long-Term Investment Value

Quality of Products/Services

Global Competitiveness

Strongest Dimension

Years on list

Previous rank

State

Key Financials (last Fiscal Year)

Revenues ($M)

Profits ($M)

Assets ($M)

Total Stockholder Equity ($M)

Profit Ratios

Profit as % of Revenues

Profits as % of Assets

Profits as % of Stockholder Equity

Earnings Per Share (last Fiscal Year)

Earnings Per Share ($)

EPS % Change (from prior fiscal year)

EPS % Change (5 year annual rate)

EPS % Change (10 year annual rate)

Total Return

Total Return to Investors (last year)

Total Return to Investors (5 year, annualized)

Total Return to Investors (10 year, annualized)

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

Q2 2026

Q1 2026

Q4 2025

Q3 2025

Q2 2025

Q1 2025

Q4 2024

Q3 2024

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

legacy

Good day. Thank you for standing by. Welcome to APA Corporation's second quarter 2026 financial and operational results conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, please press star one one on your telephone and you will hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand it over to your first speaker, Stephane Aka, Managing Director, Investor Relations.

Good morning. Thank you for joining us on APA Corporation's second quarter 2026 financial and operational results conference call. We will begin the call with an overview by CEO John Christmann. Ben Rodgers, CFO, will share further color on our results and outlook. Stephen Riney, President, and Tracey 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 time to Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our financial and operational supplement, which can be found on our investor relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interests in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. 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. With that, I will turn the call over to John.

Good morning. Thank you for joining us. Today, I will review our second quarter 2026 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's 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, and 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. 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've made over the past two 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 operational 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've 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 Egypt business.

In Suriname, the Gran Morgu 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're 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 two core assets.

As a reminder, following the Callon integration, we initially estimated that sustaining Permian oil production around 120,000 barrels per day would require eight rigs and roughly $1.7 billion of capital. Since then, improvements in drilling, completions, and base management have significantly lowered capital intensity. As a result of these structural efficiency gains and our strong operational execution, we now expect to operate four rigs for the remainder of the year while raising our full-year oil production guidance to 123,000 barrels per day. This is a significant increase relative to our original guidance of 120,000 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 Qasr. 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 118,000 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'd characterize the second quarter with one word, momentum. We're sustaining top-tier operational performance across our portfolio, driving stronger production, lower costs, and lower capital intensity. These results reflect the structural improvements we've made over the past two 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 and exploration, a strengthened balance sheet, and a clear path to organic oil production growth led by Gran Morgu. With that, I'll turn the call over to Ben.

Thank you, John. For the second quarter, APA reported consolidated net income of $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. One additional item to note is that deferred tax expense increased during the second quarter, primarily due to higher U.S. income, which accelerated the expected utilization of our U.S. net operating losses. This is a non-cash 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 of 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, where the 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 U.S., which have offset inflationary pressures such as global diesel costs. Through the first six months of 2026, we've generated more than $1.2 billion in free cash flow, which is more than we produced during each of the past three years. While higher prices have played a role, we are also benefiting from structural improvements we've made across the business over the past two years.

Through sustained cost reductions, capital efficiency gains, and portfolio high grading, we've 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's 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 U.S. and North Sea, more than offsetting diesel inflation. This further demonstrates that the efficiency improvements we've implemented over the past two 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 pre-tax 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 reduce 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 cash 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 three to four-year timeframe 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 two years ago.

In the Permian, we've established a clear cost leadership position that is driving durable free cash flow. In Egypt, we've positioned the asset to generate stable free cash flow with attractive reinvestment rates. Looking ahead, Gran Morgu 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&A.

Thank you. At this time, we will conduct the question and answer session. We will allow time for one question as well as one follow-up. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from Doug Leggate of Wolfe. Your line is now open.

Thanks. Good morning, everybody. John, this is the first time that you've had a call since you acquired Savant. 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 recoverable development north of 400 million barrels. You've now bought a pipeline, which I presume you wouldn't have done if you weren't at least aligned on the possibility of that. Can you share what your current thinking is? Do you have the semblance of a development with Sockeye as it stands today, or is it contingent on a successful appraisal program? Any other color you can offer would be great. Thank you.

Well, Doug, always appreciate you coming in. We are super excited about our position in Alaska. It's now close to 500,000 acres. We're state lands. It's something we entered into in 2023. We've now drilled two successful discoveries with King Street and Sockeye. We were able to test Sockeye. We took a break this last winter to reprocess seismic because there were multiple surveys that needed to be stitched together. We're very excited. We said we've got a high-quality sand there. We can now confirm that we did not drill Sockeye in the thickest portion. We've got two key wells set up for this upcoming winter. We'll start building ice roads late this year, spud two wells in 2027. One will be an appraisal well of Sockeye, Hungry Horse. The second one is an even larger independent prospect, Chinook. They're both similar geology.

Obviously, with the appraisal well, you're appraising the Sockeye discovery. Chinook is a similar prospect, but just much larger. What Savant brings to us, Doug, it is strategic in that it's positioned right next to us. It obviously has a 25-mile pipeline with 80,000 barrels a day pipeline capacity. It also brings a large gravel pad. There's 40,000 barrels a day of processing equipment. It has an airstrip as well as a dock. It will be advantageous to us even in the appraisal process and also, obviously, if we went on to a development. It's early for us to call any development plans at this point, but we're pretty confident we've got a lot to work with up here, and we're very excited.

I think the thing that we've always talked about that both King Street and Sockeye proved is that we've got higher quality reservoir rock than some of the plays that are being developed quite a ways away to this. We're very excited about it. It's state lands. It's oil. The new processing of the seismic was a really good call. We're very excited about it, Doug. Our next step will be to appraise Sockeye, drill Chinook, then come back and be in a position to talk more about it at that point.

Okay, understand. Thanks, John. My follow-up, if I may take advantage of Tracey being on the call, or whoever wants to take this, but the Eni deal. ANCAP has given quite a lot of detail on the prospectivity of the whole area. Eni is obviously one of the top, if not the top global explorer in the last several years. I guess my question is simply this. There's one well in the deep water, John, Raya that you know well.

It looks to us that it didn't go deep enough. Can you characterize what the exploration optionality is in Uruguay and what happens beyond the first well?

Well, we've got two blocks. OFF-6, which we had 100%. We now have 60% in that. We are really thrilled to welcome Eni as our partner. It was a very competitive process. It really speaks to the quality of our position in Uruguay and how prospected that block is, but also a credit to our exploration team and the work that we've done now with Suriname bringing in TotalEnergies. We're less than two years away from first oil there with Gran Morgu, and now bringing Eni into OFF-6 in Uruguay. We're thrilled to have them here. I'll let Tracey jump in. Obviously, the one well we believe was not drilled deep enough. Our objectives will be much deeper, but I'll let Tracey talk a little bit about the geology and what the concepts are and what we've got there.

Sure. Hi, Doug. I think one 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. That's driven our interest and a lot of the industry interest into Uruguay. What we're looking at is basically the conjugate margin geology that's worked on both sides of the margin up and down West Africa and Latin America. Now, having proven source rock on the African side, we're looking to step over and test that on the conjugate margin on the Uruguay side. Really it was that source rock data that drove interest that we're going to test on the Uruguay side.

The interesting thing is, as you pointed out, there's really only one well in the deep water in Uruguay, and that is the Raya well. You're correct in your statement that we don't believe it tested nearly deeply enough. It's quite a shallow well relative to where the source rock is. What has worked on the African side is your reservoirs are very close to source. We're going to be testing the same concept where we see reservoirs very close to source and much deeper than the Raya well tested. With the exploration well, we'll be looking at that source rock, but also testing deposition, migration, and trap and seal on the side. It'll be a very, very big well.

We've got a really high-quality 3D seismic data set over the prospects in Block VI and Block IV, though we are looking at extending it in Block IV. We see some terrific prospectivity on the 3D, very large prospects. As John said, we'll look at testing that in late 2027.

Great. I appreciate the answers, Tracey and John. Thanks a lot.

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

Morning. Last quarter, y'all emphasized maintaining the flexibility between debt reduction and buybacks. Now given just how strong the balance sheet is, obviously, y'all are pretty explicit that the number one priority now that the free cash for the rest of the year is on the buybacks and kind of reiterating that minimum 60% annual return of free cash flow to shareholders. 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.

Sure, John. This has been a good question. 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 the right use of the incremental free cash flow between the debt and the equity. Through that process, really where we landed was 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 going to just help with our fixed charges going into 2027.

Having that so close from when we outlined the target in August, and here we are, at the time in May, you're nine months from that, and it was so close, really just gave us the opportunity to look at balancing those two different commitments around the equity returns and reaching that $3 billion. We're in a great position from a balance sheet, lowest debt balance that we've had at Apache in over 15 years. Just wanted to make it clear that we're still committed to the at least 60% return. We've not returned that much in the first half of the year. Yes, that implies that we've got quite a bit of share buybacks to do in the second half of the year, and we're going to do that.

That's great. Thanks for that, Ben. Then, 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 now and year-end? I know y'all highlighted some projects in the Permian in the presentation, but just a little bit more clarity on what's captured and what's still left.

Yeah. I'll actually do it from an annual basis, John. Earlier this year, what we said was we had actually captured $300 million of savings in 2025. Then that set up your run rate exiting 2025 of the $350 million. We said we were going to capture $400 million of savings this year. That led to a $450 million run rate. As we've 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've seen is that that captured amount, which was 400, is actually closer to the high 400s, call it $475 million. Some of that's being offset with inflation, we've talked about that.

You've got higher diesel costs and a little bit higher service costs across the lower 48 that I think all industry is starting to see. That captured amount Putting aside inflation would have been $475, but when you count that inflation, it's probably closer to $425. Because we're capturing more true savings, that run rate is now higher from the $450 and it is now $500, and it's across all three of the buckets. We're seeing capital efficiencies in the Permian and in Egypt. We're actually, through field initiatives across our portfolio, namely in the Permian and the North Sea, we're seeing LOE savings. G&A continues to trend in the right direction as well. That incremental $50 of run rate savings exiting this year is across all three of those buckets.

On top of that, we've separated the controllable spend of those three buckets from interest expense savings. 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. $675 million as we exit this year of true costs being lower than they were as we exited 2024. To put that in context, we've outlined $2.3 billion of FCF this year. Had we not started this two years ago around controllable spend and really getting after the debt paydown, that $2.3 billion would actually be closer to $1.7 billion.

A testament to the team and all of the hard work that's been done on the costs 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.

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

Hey, thanks. Good morning, guys. Ben, you highlighted some of the benefits of the gas trading portfolio and how there's limited free cash flow impacts from the change in Waha prices. 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 give us a view into next year. Do you plan on adding some additional basis swaps to have a similar net zero impact and how things may look for you guys next year?

Sure. Good question. Actually, since those pipeline positions have been put in place starting in 2019, 2020, and then the Cheniere LNG contract a few years ago, we've not hedged LNG, and we've talked about that, just 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. Our hedging program around our gas trading book has been around the basis. You look back over the past five plus years, almost every year we've had a hedge position in place. Would expect that trend to continue to next year. We've not put any places for 2027 yet. We do monitor that.

We do like the position that we're in this year, because it does provide that unique offset of higher Waha prices that benefits our equity gas production, and it's offset by the loss on the transport side, net of hedges. It is unique. It's providing at least investors some stability and understanding of that free cash flow that's coming from that business. We've not put any hedges in for next year. We do look at that, and we'll update folks through the year if we do.

Got it. John, you had mentioned you're two years away from the startup of the Gran Morgu project, and it's clearly a key differentiator for your growth profile into the future. 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? How do you think about different options there?

Yeah. I think, Josh, it's a great question. First of all, things are on track with Gran Morgu. We've said mid 2028, first oil. TotalEnergies came out and said potentially first or second quarter of 2028. We're going to stick with mid 2028. What it's positioned us to where if we can just maintain volumes in our core assets of Permian and Egypt, you've got growth coming right through our exploration program and through Suriname. I think a couple of things. The big thing there is the way we structured our joint venture with TotalEnergies. We're benefiting from a large carry in Suriname today, which has enabled us to continue to fund our programs domestically and internationally with Egypt and the Permian.

It's also let us continue to make progress on the balance sheet and deliver on the returns framework while we're funding such a large-scale capital project. It really is worked to our advantage. Quite frankly, without that, we wouldn't be in the position we're in today. It's really set us up to run those businesses like we would like to run those. We worked on adding durability and inventory life to Permian, where we can run flat for more than 10 years, which is kind of what we laid out earlier this year. We're obviously exceeding that with volumes and capital efficiency that we continue to have come through. Obviously gas has changed our picture in Egypt as well. We've been growing our gross BOEs in Egypt.

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're not having to constrain everything, all along, bringing Suriname along. It puts us in a really, really good place to continue doing what we're doing, and we're thrilled to be in the place we're in today.

Thank you. Our next question comes from Arun Jayaram of JPMorgan. Your line is now open.

Good morning, John and team. John, I was wondering if you could comment on how you think your sustaining capital requirements in the U.S. are evolving. This year you guys have highlighted $1.3 billion of domestic capital for 123,000 barrels of oil. You did mention how your rig count now is going down to four. Obviously, you're generating some efficiencies. I know you're probably not ready to give us a 2027 guide, but I wanted to see if you thought there's further potential to reduce sustaining capital based on efficiency gains.

Yeah, Arun, it's a great question. We're in a really dynamic period both for us and industry. If you go back to post-close of Callon, we believed it was eight rigs to hold 120,000 barrels a day flat. As you mentioned, we're now currently at four. We've guided to 123 for this year, and it's been a stairstep down as we, one, changed our development philosophy and have really let the cost side drive a lot of things. Today, we're clearly under six. We're at four rigs today. We started at five. We dropped down to five last year. We're clearly under six rigs to maintain at 120. We've been doing that for the last two years. It does give us some flexibility in terms of how we think about that. I'm not ready to dive into to 2027.

We give a little bit of an insight today, talk a little bit in November, and obviously in February we'll come out with a plan. The way the efficiencies have been running through, and the team continues to make really, really meaningful progress. Very proud of that. I think the one other thing I'd say is, the number of rigs is not as critical of a number as it used to be because it ultimately boils down to wells you're drilling, feet you're drilling, and the turn-in lines. I don't know, Stephen, anything you want to add to that?

Yeah, John, just to echo your last comment there. We started this year with a plan of five rigs, we're clearly gonna end up at 4.5 rigs. Those 4.5 rigs will drill more lateral feet, we'll complete just as many wells as we planned with five rigs. We're down to four rigs for the second half of the year. We're actually moderating frac activity in the back half of the year as well in order to meet our capital budget of $1.3 billion. It's just, again, to your earlier comments, it's about both the scale and the pace of change and efficiency gains that the team has gotten to, it's continuing in 2026.

2025 was obviously a really big year where we started off with this notion that eight rigs would sustain 120, halfway through the year, we were at six rigs sustaining 120. I agree with you. Right now, we've been delivering basically 123,000 barrels of oil a day. By the end of this year, it'll be for two years straight. We're doing that clearly with fewer than six rigs. We'll average 4.5 this year. Not saying that it's 4.5. As we do the planning for 2027, we'll talk a bit about it in November then obviously give the details in February after we've had the full discussions with the board and a full review of the plan.

Appreciate that. 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're doing in the Western Desert.

Yeah, Arun, we've been in the Western Desert since 1994, until really late 2024, all we focused on was oil and exploring for oil. Obviously, we entered into a new price agreement in November of 2024. We started then to, how do you translate what we know into gas? We knew there was some low-hanging fruit that you saw us get after last year. We've really only been exploring now for gas in the Western Desert for, call it 12-18 months. We're stepping out. A lot of it's similar type rock, you're looking deeper now. The key to think about in Egypt is, we've got 20,000 feet of sand, effectively. The exploration program there is much different than the offshore stuff, where you've got your seismic tuned. It's either there or it's not.

Egypt, it's the nuances of can we predict where we've got trap and seal? In a lot of places, you have too much sand. The program has been very consistent. That's why you see a steady diet of successes, as well as some dry holes. At depth, it's hard to really differentiate sand versus pay. The good thing is, when you have your discoveries like we've had, the follow-ons are usually very predictable, and then we can take those and extrapolate into multiple wells. A lot of it is stepping out into deeper parts of the basin. It's stepping into places that we avoided because we thought it might be more gas-prone. It's really putting a new lens on what we've done for 30 years and just thinking about it more from the gas perspective.

We've got a lot of key wells coming up. We've drilled a lot of nice discoveries. Very pleased with the program. The key here is, it's conventional. It's not unconventional. Success has been set up one to two to three to five type well offsets. We've got a lot of concepts that are at play.

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

Morning, John team. John, my first question's just a little bit more on your exploration program. Specifically, you've been active in Alaska and Uruguay. Just wondering, are those areas where you consider sort of at the front of the potential exploration line, would you all also consider exploration activity, I don't know, maybe in Block 58 or other blocks in Suriname as well as maybe any other new areas you might see?

Yeah, Neal, I think the most important thing there is we've stayed committed to exploration. We've tried to allocate approximately 10%-15% of our capital to exploration. It's something we stuck with. Obviously, going back to 2019 when we spud the first well in Block 58. 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. It was a very rare window in time where early 2023, hardly anybody else was exploring. It let us step in to places like Uruguay with even success being announced in Namibia across the conjugate margin was very quiet, right?

That was an easy enter into Uruguay for us. We were able to do the deal with Armstrong in Alaska on state lands for what's now a very large position. I think the important thing is we were able to build out our portfolio at a time when we knew we had exploration dollars to spend. We were able to attract high-quality people, and it got us ahead, as a lot of folks have started to think about exploration starting last year and now this year. When you look at our portfolio today, you follow on Block 58 success. There is more to do in Block 58. We will be back in there with Total next year, exploring and with looking to either add to the plateau for Gran Morgu or potentially more infrastructure. We're very excited about Suriname.

We're very excited about Alaska as well. I would put both the Block 58 and Alaska at the top because we've de-risked those now with success. We're very excited about Uruguay. It is a fantastic looking area, but it's frontier. We don't have a well deep enough in that basin, so we need to go see. You've got what Tracey described to Doug a little bit earlier in the Q&A across the conjugate margin in Namibia. We're very excited about it. Of course, the team's always looking for other things, but quite frankly, I think we've got a portfolio today that's very differentiated, very unique. Quite frankly, we've really de-risked both Suriname Block 58 and Alaska through already what are successes.

I would agree on the deep portfolio and the de-risking. You guys have done a fantastic job. 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 you all consider adding further FT or I guess maybe asking another way, is your gas takeaway capacity at all limiting potential future oil growth? Doesn't appear to be, but just want to see how you're considering that.

No. We're in a good spot right now. We do have more capacity than we do equity production, so there's potential room to fill that. As we look at it right now, we're in a really good spot that has paid very well dividends over the past five years since it's been in service. It's 2026, the first expiration comes from GCX in 2029, and we'll make the assessment then. We've got extension options on that and PHP, two five-year extension options. That's great optionality as you think about our total U.S. portfolio and what we'd like to do really as we get into the next decade. Do we want to keep that optionality or not? We're in a really good position right now as we look at that.

Thank you. Our next question is Chris Baker of Evercore ISI. Your line is now open.

Hey, guys. Thanks. Just wanted to maybe step back for a second. Some great progress in terms of the debt reduction we've seen year to date. Obviously, with the $3 billion target and expecting to end the year at $3.3 billion, it does seem like we're coming up to a point where you'll be at target. I'm just curious, John, or I don't know, Ben, if you want to take this one, just around the added flexibility that hitting that target provides in terms of either incremental cash return to shareholders or if there's other things as you look out at the landscape in terms of exploration and frontier opportunities that rise to the top of your list. Would love to get a sense just for how you're thinking about that.

First off, Chris, in terms of how we're thinking about things, I think we're in a good place. I mean, 2027 will be an increase year. 2026 has been light for us in terms of true exploration spend. That'll kick up next year because we've got such a high-quality portfolio. The base business is running extremely well, and Suriname's coming down the pipe quickly. We're in a really, really good place, which puts us in a nice position, and that's why we've been able to make such progress on the balance sheet and stick with the returns framework. Ben, I'll let you comment more on, specifically the $3 billion debt target.

Yeah, I think it's a fair question, Chris. When you look at, I said in my prepared remarks, we expect it strip to reach the $3 billion in 2027. We're a stone's throw away there as we sit here today and at the end of the year. 2027, you reach that you'll be likely within a year plus from Gran Morgu. That brings not only oil production growth, but growing free cash flow 2028, 2029, 2030, on top of a business with the Permian and Egypt that will continue to sustain that free cash flow generation ability. What we can say now is I think that once you hit the $3 billion net debt target, you likely put another one out there, to continue to deliver the business.

That'll be balanced with what we'd like to do on the shareholder side as between mix and also just total amount going to shareholders. The good thing is we're going to be very well-positioned. We're well-positioned because of what we've done on the costs. We're well-positioned because of what we've done on the balance sheet. You've got Gran Morgu now less than two years away, next year it'll be less than one year away. It provides us a lot of optionality around that. We don't have to cannibalize the investment opportunities on the exploration side that John outlined, in order to still provide true cash value to our shareholders. We'll have a lot of options, and as we get closer to that, we'll let folks know where we land.

Great. Thanks. Obviously a lot of progress as well in terms of capital efficiency in the Permian. Getting down to the four and a half rigs obviously is a big move from where you all started after the merger. I'm just curious, in terms of how you think about the biggest potential sources of further improvement there. I guess, where's the team's focus? Would love to get a sense of where we could see continued progress on that front. Thanks.

I think you look at the basin now and you look how long we've been in these plays and the progress you're making, you're at a point now where we've drilled a lot of wells, right, with more than 100 a year. We're making great progress. A lot of the recent strides have been with really fine-tuning your well designs and your slim hole. You've gone to the simul-frac, trimul-fracs, all of those things. You're going to continue working on the efficiencies and letting folks just continue to work on how do we eliminate steps that cost you money as you work through those. They've got those down now where you look at the per foot numbers, you really are benefiting from scale and the repetitions that we've got. I think that's the big thing.

Some of the opening plays, a lot of what we're doing on the testing side to move the technical locations into economic. There's a lot to learn as you get into some of these other formations and things like the Barnett and others. I think you'll continue to see progress there. You're at a point today where it's really more fine-tuning the machine and doing more and more from the repetition standpoint.

Thank you. Our next question is from Bob Brackett of Bernstein Research. Your line is now open.

Good morning. I'd like to return to Uruguay Block 6. The Raya prospect was Cenozoic and was sitting out in sort of record water depth, but it has prorated well out there. That suggests Cretaceous. That also suggests that you can drill in more palatable water depths. I guess, is that correct thinking? Can you talk about maybe the size of prospects and maybe the chance of success that you're targeting with that first well?

Yeah. Bob, I'll say a few things. One, it is frontier. The prospects are very, very large. Tracey, I'll let you jump in. They are Cretaceous. I'll let you comment a little further on that.

Correct, John. They are Cretaceous, so we're 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're really talking about is drilling deeper, not necessarily pushing into much deeper water. We're still well inside 3,000-meter bathymetry in terms of drilling in the water depth. That's not really a factor in terms of where we're planning the well. It's not in a lot deeper water than the Raya well. We will be drilling the well significantly deeper into the Cretaceous than the Raya well tested.

Great. Quick follow-up. Would you be potentially testing multiple targets, including Cretaceous and those younger Cenozoic targets with a single well?

I think we've got a lot of work to do, Bob, in terms of our partner. We've got some very strong views about the prospectivity, which we think is terrific, and we've got multiple options on what we're going to test. I think we need to wait until we're a little further along with our new partner, Eni, who we're very much looking forward to. As we've mentioned previously, I think they're a top-tier explorer, and will bring a lot to the table technically. We are going to engage with them, I think, on final decisions on drilling. We've got some very good options.

Thank you. Our next question is from Leo Mariani of Roth. Your line is now open.

Yeah. Hi, guys. You mentioned this a couple times, I just wanted to clarify. I think you've said in the past that you're going to step up some of your capital commitments in the next couple of 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, if you are having to kind of step up some of those capital commitments to some of these longer-term projects?

Yes, Leo. That's something we've dialed into how we define that 60%. You won't see us stepping up beyond what we've really done in the past. It's just, it's a step up from where we are this year. I would characterize this year as more being a lighter year on the exploration spend. It's something we've stuck to over the last decade and we'll continue in the future.

Okay. Just on the exploration side, like you said, it's going to step up in the next couple of years. Is there kind of like a ballpark target? Is that kind of moving to 15% plus, you think, of capital in the next few years? Just trying to get a sense of how meaningful that can be.

Yeah. It really is going to vary from year to year. I think the takeaway as we kind of just give you a little bit of a preview into 2027. We've got the two wells in Alaska. We've talked about that, we've outlined those. You're spending about $20 million this year for Ice Roads in Alaska, those extra two wells. By the way, we'll firm all this up later this year as we preview 2027 in February when we land on it. I think a decent assumption for that is kind of $100 million-$120 million for those two wells in Alaska. One to two wells in Suriname. I think those are, you could assume $50 million-$75 million a well net to us.

I just want to remind folks that given where we expect to explore in Block 58, those exploration dollars are going to be cost recoverable. We are 50/50 with TotalEnergies on those wells, it's a decent proxy there. The Uruguay well, it's one well and likely in the back half of next year. It's offshore, probably a decent proxy for that is a similar Suriname well. We'll outline the terms later on, we're getting carried for most of that well. It's going to be significantly less than the 60% working interest that we retained there. You kind of add all that up, Leo, for next year, you probably have a two handle on exploration spend. Yeah, it's going to be in that 10%-15%.

You carry that forward, we'll have to see how things go for additional exploration, Alaska and Block 58, et cetera, past 2027. There will be that increase from this year to next, we'll take it from there as we get to the end of the decade.

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

In closing, let me leave you with three 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 Gran Morgu less than two 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.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

APA (APA) Q2 2026 Earnings Call Transcript

Company Participants