Logo of jester cap with thought bubble.

Image source: The Motley Fool.

DATE

Thursday, May 7, 2026 at 11 a.m. ET

CALL PARTICIPANTS

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

Need a quote from a Motley Fool analyst? Email [email protected]

TAKEAWAYS

  • Consolidated Net Income -- $446 million reported, or $1.26 per diluted share, under GAAP.
  • Adjusted Net Income -- $489 million, or $1.38 per diluted share, adjusting for $37 million in after-tax unrealized derivative losses and other small items.
  • Free Cash Flow -- $477 million was generated, with $88 million returned to shareholders.
  • Operational Spending -- Capital spend and operating costs came in below internal guidance, despite inflationary pressures.
  • Permian Oil Production -- Exceeded guidance due to operational efficiencies and improved uptime; gas volumes were curtailed in response to weak Waha pricing.
  • Egypt Adjusted Production Guidance -- Lowered to reflect Production Sharing Contract (PSC) impacts from higher commodity prices, though gross volumes exceeded prior expectations.
  • U.S. Oil Production Outlook -- Increased to 122,000 barrels per day for the full year.
  • Full-Year Upstream Capital Guidance -- Remains unchanged at $2.1 billion, with 55% of spend expected in the first half of the year.
  • Bond Repayments -- $634 million of near-term bond maturities repaid year to date, including $555 million in April.
  • Interest Expense Reduction -- Expected annual interest expense to decrease by $150 million compared to 2024, due to deleveraging and no debt maturities until December 2029.
  • Net Debt -- Ended the quarter at approximately $4.1 billion, up marginally from $4 billion at year-end 2025, mainly due to increased receivables and incentive compensation payout.
  • Cost Reduction Initiatives -- On track for $450 million cumulative run-rate savings by year-end 2026; run-rate cash costs expected to decline $600 million exiting 2026 versus 2024 levels, including interest savings.
  • Free Cash Flow Outlook -- Management expects approximately $2.2 billion for the full year.
  • Gas Trading Portfolio -- Anticipated to generate roughly $1.1 billion pretax cash flow in 2026, including about $300 million from LNG and the remainder from pipeline transport, with pipeline-driven profits concentrated in the summer.
  • Egypt Gas Price -- Company negotiated gas pricing geared toward $75-$80 Brent, with current gas activity averaging $4.25 per mmbtu according to remarks.
  • Egypt Workover Rigs -- Running in the mid-to-high teens, supporting both new wells and workover activity.
  • LOE Guidance -- Full-year Lease Operating Expense guidance reaffirmed at $15.25 per BOE; inflation pressures in Egypt offset by U.S. operating savings.
  • Exploration Spend -- 2026 guidance is $70 million, split between Alaska ice roads ($20 million) and Suriname exploration ($50 million).
  • Permian Asset Repositioning -- All unconventional, with more than a decade of economic inventory established.
  • Suriname Grand Morgue -- Project remains on track for first oil in mid-2028, seen as a future cash flow driver.

SUMMARY

APA Corporation (APA 5.38%) provided quantitative clarity on key profitability levers, notably attributing its first-quarter net income and elevated free cash flow to both cost discipline and supportive commodity pricing, while delivering operational results that outperformed guidance in Permian oil production. The company confirmed that all near-term bond maturities are now retired and highlighted improved financial flexibility, with significant interest savings anticipated and no additional debt maturities until late 2029. Discussions revealed that the sizable growth in free cash flow will be monitored for allocation between debt reduction, dividends, and share repurchases, as management navigates a volatile geopolitical and commodity environment. Exploration spend is slated to rise next year, particularly with additional wells planned in Alaska and Suriname, as long-cycle growth initiatives remain on the agenda.

  • CFO Ben C. Rodgers said, "expect 2026 U.S. and U.K. current tax expense to be approximately $230 million, nearly all of which is in the U.K, where we are subject to a 78% effective tax rate."
  • Egyptian production remains gas-weighted, with improved reliability from waterfloods, and offset by lower PSC-adjusted reporting due to higher Brent prices.
  • Run-rate cash costs are projected to be $600 million lower exiting 2026 versus 2024, aided by structural efficiencies and previous debt reductions.
  • Permian gas volumes are expected to remain curtailed through the second quarter, driven by depressed Waha prices, with no further price-related curtailments assumed in the second half of the year.

INDUSTRY GLOSSARY

  • PSC (Production Sharing Contract): A contractual agreement in which an oil company bears the exploration and development risks and costs, with production split between the company and government, impacting how reported volumes adjust at higher commodity prices.
  • LOE (Lease Operating Expense): The direct operating costs of producing oil and gas from leased properties.
  • Waha: A major natural gas pricing point in West Texas, often cited as a benchmark for Permian basin gas values.
  • LNG (Liquefied Natural Gas): Natural gas cooled to a liquid state for transportation and sale, often commanding pricing independent of regional gas benchmarks.
  • TTF (Title Transfer Facility): The main European gas price benchmark, referenced for LNG sales into Europe.

Full Conference Call Transcript

Stephane Aka: And thank you for joining us on APA Corporation’s first quarter 2026 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 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 we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today’s call are adjusted to exclude noncontrolling interest in Egypt and Egypt tax barrels. I 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. Good morning, and thank you for joining us.

John J. Christmann: Today, I will review our first quarter 2026 results, highlight our execution against APA Corporation’s strategic priorities, and share our outlook for the remainder of the year. I want to first acknowledge the ongoing events in the Middle East. The escalation in geopolitical tensions and the human impact of the conflict are deeply concerning. Our thoughts are with those affected. Our teams in Egypt continue to operate safely and without disruption. We remain in close coordination with our partners and government stakeholders. We have a long track record of operating in the country, and our priority remains the safety of our people and the reliability of our operations.

The increased volatility in global energy markets reinforces the importance of a sound long-term strategy. At APA Corporation, our strategy is very clear. We will deliver top-tier operational performance across our assets, we will build and grow a high-quality portfolio, and we will maintain financial discipline. These principles have guided our strategic direction and capital allocation priorities over the last several years and continue to shape our path forward. Our operational focus has never been stronger. In the Permian, we have significantly improved capital efficiency while delivering resilient oil production volumes, all with fewer rigs and lower capital intensity. Our improving execution is driving cost leadership across key operational categories, with great momentum and clear visibility to further progress ahead.

In Egypt, we have strengthened base production reliability through targeted waterflood investments, a more efficient workover program, and increased uptime, all of which have helped moderate effective base decline rates. At the same time, we are expanding our gas development activity to build a more durable total production foundation. Across the broader portfolio, we have continued to high-grade our key assets and build long-term optionality. First, in the Permian, we have repositioned the asset base to be entirely unconventional, establishing more than a decade of economic inventory with meaningful upside. Second, in Egypt, we have enhanced the value of our assets through improved fiscal terms and a more gas-weighted activity mix.

Third, in Suriname, we are advancing a world-class development toward first oil. And finally, we are building future growth opportunities through exploration. With respect to financial discipline, we have streamlined our corporate overhead to drive sustainable structural efficiencies. This lower cost base combined with disciplined capital allocation across our high-graded portfolio supports more steady free cash flow generation through commodity cycles. Alongside our highly profitable gas trading business, this positions us to deliver meaningful shareholder returns while accelerating progress toward the $3 billion net debt target we set just nine months ago. Together, these actions demonstrate consistent execution of our strategy, which is to drive strong operational performance, position the portfolio to deliver long-term value, and maintain balance sheet strength.

Turning to the specifics of our first quarter performance, I would like to highlight several notable achievements. Across the portfolio, our teams executed exceptionally well and delivered capital spend and operating costs below guidance, despite inflationary pressures. In the Permian, operational efficiencies and improved uptime drove oil production above guidance, while gas volumes were curtailed due to weak Waha pricing. In Egypt, continued success in the gas program, including on our newly acquired acreage, is underpinning the delivery of our ambitious 2026 targets. Longer term, we remain excited about the extensive prospectivity of the Western Desert. Robust asset performance, complemented by favorable commodity prices, generated nearly $500 million in free cash flow during the quarter.

Ben will discuss the steps we are taking to further strengthen our balance sheet in the current price environment. Looking ahead, we are carrying significant operational momentum into the balance of the year. In the U.S., we are raising our full-year oil production outlook to 122,000 barrels per day, reflecting our confidence in continued strong performance. In Egypt, despite gross production volumes above previous expectations, our adjusted volume guidance has been lowered to reflect the PSC impacts of higher commodity prices. We remain focused on capital discipline and cost management, with no change to our upstream capital or LOE guidance. In closing, our first quarter results reflect continued execution across our Permian and Egypt assets.

In the current higher commodity price environment, we are prioritizing free cash flow generation over incremental activity and maintaining a sustained focus on cost reductions to drive long-term value. We remain rigorous in our capital allocation across our foundational assets in the Permian and Egypt, which are poised to deliver consistent production volumes for the next several years, providing a stable and durable base for free cash flow generation. Organic high-margin oil production growth is expected to come from Suriname Grand Morgue, which remains on track for 2028 first oil. This is a clear differentiator relative to our peers, representing a significant free cash flow growth engine for the long term.

We remain committed to our capital returns framework with a clear path to further debt reduction and share repurchases supported by our current free cash flow outlook. I will now turn the call over to Ben.

Ben C. Rodgers: Thank you, John. For the first quarter, under generally accepted accounting principles, APA Corporation reported consolidated net income of $446 million or $1.26 per diluted common share. Consistent with prior periods, these results include items that are outside of core earnings. The most significant after-tax item impacting adjusted earnings was $37 million of unrealized derivative instrument losses. Excluding this and other small items, adjusted net income for the first quarter was $489 million or $1.38 per diluted share. APA Corporation generated $477 million of free cash flow in the first quarter, of which $88 million was returned to shareholders.

John already covered key elements of our outlook for the rest of the year, so I will focus on a few additional items. For the second quarter, our outlook for U.S. BOEs assumes continued natural gas curtailments through the end of the second quarter, driven by the current forward strip for Waha gas pricing. No price-related curtailments are assumed in our U.S. BOE production guidance for the second half of the year. For Egypt adjusted total production, about two-thirds of the second quarter decline from the first quarter is related to higher Brent prices.

As a reminder, while higher prices increase profitability, they reduce adjusted volumes under the PSC cost recovery mechanism—an accounting impact rather than a change in underlying gross production volumes. The remainder reflects the successful recovery of backlog costs from our 2021 PSC modernization, which was completed in the first quarter. As John mentioned, our full-year upstream capital guidance remains unchanged at $2.1 billion. We expect to incur approximately 55% of this spending in the first half of the year, largely driven by the cadence of activity in the U.S. We anticipate most of our Permian turn-in-lines to occur in the second and third quarters, sustaining oil production volumes through the second half of the year.

We have also updated our guidance for current taxes to reflect higher pricing assumptions relative to our prior outlook. We now expect 2026 U.S. and U.K. current tax expense to be approximately $230 million, nearly all of which is in the U.K., where we are subject to a 78% effective tax rate. Looking at our oil and gas trading portfolio, based on current strip pricing, we expect these activities to generate approximately $1.1 billion of pretax cash flow in 2026. This is inclusive of commodity hedges and reflects significantly wider Waha basis and higher LNG prices since our last update. Turning now to the balance sheet.

We ended the first quarter with approximately $4.1 billion in net debt, compared to $4 billion at the end of 2025. This slight increase is attributable to a large use of working capital, almost all of which was driven by two factors: first, an increase in total company receivables due to the significant rise in oil prices late in the quarter; second, the payout of incentive compensation accrued throughout 2025, consistent with our usual practice. As outlined on page 8 of our supplement, we have repaid $634 million of near-term bond maturities year to date, including $555 million in April.

Combined with the deleveraging steps taken in 2025, this results in interest savings of more than $60 million versus last year. Compared to 2024, we now expect annual interest expense to be approximately $150 million lower on a run-rate basis at the end of 2026. With no debt maturities until December 2029, we have significant financial flexibility to manage our decommissioning liabilities in a deliberate and efficient manner while maintaining our broader capital allocation priorities. Moving now to our cost reduction initiatives, where we are continuing to make progress across capital, LOE, and G&A. We remain on track to achieve our $450 million target for cumulative run-rate savings by the end of 2026, which is reflected in our current guidance.

Building on the significant strides made last year on capital and operational efficiencies, our focus this year will span all three categories, with the same discipline and focus that enabled the results we delivered in 2025. Including the previously noted interest savings, we expect run-rate cash costs to be $600 million lower exiting this year compared to 2024. While commodity prices have been volatile since the start of the conflict, the strength of our execution and contributions from our gas trading portfolio position us to generate significant free cash flow this year. Currently, as outlined on slide 9 of our supplement, we expect to generate approximately $2.2 billion of free cash flow for the full year.

This level of cash generation meaningfully advances our progress toward achieving our $3 billion net debt target in the near term while supporting shareholder returns. In closing, these results mark another quarter of consistent, predictable performance across our asset base, underscoring the disciplined execution we have demonstrated for more than a year. We remain well positioned to deliver significant free cash flow this year and beyond, supported by continued execution and structural cost improvements. We will continue to allocate capital with rigor, balancing shareholder returns, balance sheet strength, and investments in future growth through exploration. With that, I will turn the call over to the operator for Q&A.

Operator: Thank you. To ask a question, please press 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. We ask that you please limit yourself to one question and one follow-up. One moment while we compile our Q&A roster. Our first question will come from the line of Doug Leggate with Wolfe Research. Your line is open. Please go ahead.

Doug Leggate: Hello. Thanks. Good morning, guys. I guess, Ben, maybe for you first, the gas trading number is pretty meaningful. I think if I go back maybe about six or nine months ago, you talked about a $300 million kind of run rate, but now we have GCX expansion and a bunch of things going on in Midland coming online. With what you know today, given what has happened with 2026, what tools do you have to maybe protect some of that? That is my first question. My second question, if I may, is, John, a quick one on Alaska exploration. My understanding is you have been waiting on the seismic, and you now have the seismic.

I am just wondering what that informs for your views on the existing discoveries and what your running room is for the upcoming drilling program. Thanks.

Ben C. Rodgers: Sure. Thanks, Doug. When you look at the marketing book, the $1.1 billion this year, a lot of that is coming from the pipeline transport side. About $300 million is coming from LNG for the remainder of the year. And the bulk of the pipeline transport really is through the summer, where we see very wide basis differentials. To your point, that starts to compress, at least per the curve, given GCX expansion, the Blackcomb pipeline, and GCX Hidalgo coming online in the second half of the year.

We watch that, and we will see how the basis trades given the different dynamics with gas production in the basin—higher GORs, a lot deeper targets being drilled with more gas cut than other wells. Basis does, at least per the curve, continue to tighten into 2027. The good thing is that with the elevated LNG prices this year, that does carry through into next year, and, at current strip, we are just above $400 million of expected pretax cash flow in 2027, at strip for both basis and TTF. So still another good year expected next year. We will monitor that. We have hedges on just the basis for this year.

We do look at other options to hedge 2027 both on the LNG and the basis side. We have not done any of that, but we monitor that daily and, if we find the right opportunity, we will look to lock some of that in. But even next year, around $400 million, it is still looking to be another good year for us.

John J. Christmann: And on the Alaska question, yes, we took this winter off to reprocess the seismic. If you go back, when we drilled Sockeye, we said we went to Sockeye not because it was our biggest prospect, but because it was where we had the best seismic picture. Taking the results from Sockeye and King Street and integrating those into the new reprocessed seismic was really the right thing to do. We and our partners are all thrilled that we took that pause. It now looks like we did not drill Sockeye even in the thickest place, and we will be coming back this winter with a two-well program.

We are in the process of assuming operations, and you will see us come back with an exploration well and an appraisal well. We are very, very excited about Alaska.

Doug Leggate: Great stuff. Thanks, John.

Operator: Thank you. And one moment for our next question. Our next question will come from the line of John Freeman with Raymond James. Your line is open. Please go ahead.

John Freeman: Good morning. Hi, guys. The first question, obviously, it was nice to see you be able to take advantage of the macro backdrop and retire all those near-term maturities, and buybacks took a pause. When I think about the rest of the year, should we assume, given that the next maturity is not until 2029 and those are not callable yet, that the majority of the free cash flow goes toward buybacks? I know Ben mentioned the decommissioning obligations. I was not sure if that meant that maybe some of those get accelerated. Any color on uses of the free cash flow?

And then a follow-up on Egypt: the flexibility between gas and oil—given the roughly 50% gas-focused activity and the $4.25 gas price—how do oil versus gas prices influence the allocation of activity currently and into next year?

John J. Christmann: It is a great question and a good observation. I would start by saying we are living in unprecedented times. We remain committed to our 60% returns framework that we initially outlined in 2021. Since the inception of that framework, we have returned 71% of our free cash flow to shareholders. There have been times when we leaned in. We also, nine months ago, outlined a net debt target of $3 billion, and that is also a priority for us. The beauty of today is we have commodity exposure to WTI, Brent, LNG, and Waha basis. That puts us in a position where, rolling forward, we have a very robust free cash flow outlook for the remainder of the year.

While we have made progress on the balance sheet, we are going to continue to be very thoughtful about how we deploy that. We like where the valuation is, but we also want to be thoughtful.

Ben C. Rodgers: Sure. To reiterate, given the current price environment and the opportunity we have to improve the balance sheet, we took some of those steps through April. We think the responsible thing to do is evaluate how we deploy our free cash flow for the remainder of the year. We are committed to our framework, as John said. Starting from fourth quarter 2021 when we put the framework in place, cumulative through year-end 2025, we have returned more than 75% to shareholders through dividend and buybacks, and $3.2 billion of that was in buybacks. On the debt side, since year-end 2021, we have reduced debt by $3.6 billion.

Being only two months into the conflict, and given the immense volatility over the past two months, we are going to be patient. The responsible thing to do is evaluate how we deploy the significant amount of free cash flow we expect to generate this year. To be clear, this is not a view on the valuation of our equity; it is solely how we would deploy the free cash flow for the remainder of the year. We will pay down debt, we will pay our dividend, and we will buy back shares. The mix is what we are evaluating. At these prices, that is the right thing to do.

It is a great position to be in, where we have an increasing free cash flow picture and we are going to be thoughtful on how to deploy it. On decommissioning, we raised guidance on decommissioning spend this year by $20 million. To be really clear, that is not an increase in cost of planned activity; that is all increase in planned activity. There are some more platform wells in the Gulf of Mexico that we want to go ahead and get after, and we will do that this year.

John J. Christmann: On Egypt allocation, first, when we negotiated the increased gas price, we geared it towards a $75 to $80 Brent price inclusive of infrastructure investment. We have been fortunate to bring a lot of our new gas discoveries online without a lot of infrastructure spend. There have been some lines that we have laid. We are in a position today where it is still very attractive. With the new acreage we brought on last year, we have new wells to drill there. You are going to continue to see the program about fifty-fifty. They need gas. What we are providing right now is saving about two LNG cargoes a month on the gas side.

We are in a pretty good place and will monitor how things play out over time.

Stephen J. Riney: I would just add that we are basically splitting rig counts fifty-fifty between gas and oil. In a mid-cycle price environment, we are agnostic between gas and oil. We are not in a mid-cycle price environment today, and it is certainly more volatile, but we feel like this is the right split at this point in time. I would also remind people that while we are getting an average of $4.25 for gas, the actual marginal price on new gas is higher than that.

Operator: Thank you. And one moment for our next question. Our next question is going to come from the line of Chris Baker with Evercore ISI. Your line is open. Please go ahead.

Chris Baker: Hey, guys. My first question: clearly a lot of great progress on the cost-saving front. Some good first-quarter numbers around LOE and other costs. You mentioned inflationary pressures, I am presuming in the Permian. Any additional color you can add in terms of what you are seeing there? And second, as you make significant progress toward the $3 billion net debt target, what does that unlock in terms of strategic priorities—cash returns, buybacks, dividends, or longer-cycle investments?

John J. Christmann: I think the teams are doing a really good job. We came into the year in the Permian with higher power costs that we outlined. You are seeing diesel on the rise here and globally as well, but we came into the year with most of our services under contract, so we are in a pretty good place. You have seen a little bit on tubulars. Power and diesel would be the main items, but in general our teams have done a good job, which is why we did not raise the cost outlook due to those inflationary pressures.

Ben C. Rodgers: On the net debt target, last year when we outlined the $3 billion net debt target, we said that at mid-cycle prices we would expect to get there in three to four years. If we were below mid-cycle, it might take toward the end of the decade. If we were above, one to two years. It is now in the crosshairs of being achievable in the near term. Once we achieve that, we will look at our priorities. We have a strong debt maturity runway with no maturities due until the end of the decade, which allows flexibility to prudently manage ARO and decommissioning. We have exploration on the horizon, and we will continue to invest in the future.

Last year and this year, exploration spend was less than $75 million. This year’s guidance is still at $70 million—about $20 million for ice roads in Alaska and another $50 million for exploration in Suriname. In 2027, with additional exploration in Suriname and wells being drilled in Alaska, we will see more exploration spend and that number will tick up next year. We will balance all of those priorities if we reach the net debt target. In the near term, we will reevaluate at that time and likely set another target below that.

Operator: Thank you. And one moment for our next question. Our next question will come from the line of Neal Dingmann with William Blair. Your line is open. Please go ahead.

Neal Dingmann: Morning, John. Thanks for the time. My first question is on Suriname. I know first oil production you talked about from the Grand Magoo project in Block 58 is scheduled for mid-2028. You also mentioned there are various other exploration projects either in Block 58 or 53. Anything you would talk about here in the near term? And second, on Egypt, how many workover rigs are you currently running, and would you consider boosting the workover count to take advantage of higher oil prices?

John J. Christmann: Both us and our partner are excited about the additional exploration we have in Block 58. If you remember back when we announced the appraisal wells at Crab Dagu, I said those not only appraised Crab Dagu, but they derisked an entire exploration play from a seismic perspective. We have a number of prospects. The plan is, when we get the rigs out there, to start drilling some exploration wells that at a minimum could extend plateau or potentially even look for incremental infrastructure. We are very excited about getting back to exploring in Suriname. On Egypt workovers, we are in a pretty good place. We have been investing in secondary projects and waterflood performance.

We have maintained a pretty flat profile for several quarters, so in pretty good shape. Stephen, anything to add?

Stephen J. Riney: I do not know the exact count of workover rigs today. It is somewhere in the mid to high teens, as it has been for quite some time. It got higher than that for a while, but remember, we use workover rigs for completing new drilling wells as well as for workover activity.

Operator: Thank you. One moment for our next question. Our next question will come from the line of Kevin McGrude with Pickering Energy Partners. Your line is open. Please go ahead.

Kevin McGrude: Hey. Good morning. Thanks for taking my question. I wanted to touch on oil realizations. The international oil realizations were quite good in the first quarter. I realize we are in a very volatile environment right now, but is there any outlook you can provide for the second quarter and maybe the back half of the year for Egypt and North Sea realizations relative to Brent?

Ben C. Rodgers: Sure. On both of our oil commodities, Brent and WTI, the current market is giving a premium for spot prices. We sell on dated Brent for our North Sea oil as well as our Egypt cargoes. That dated Brent differential to the futures price you see on the screen has varied pretty widely in the first quarter and into the second quarter—kind of $8 to $10 in the second quarter. That compresses through the year. Based on current strip, it is about a $5 to $10 premium for dated Brent versus the futures Brent. Similar on WTI, there are a couple of factors that go into getting the forward price to a spot price.

When you put those together, it is about a $2 to $5 premium on WTI that producers are realizing for the barrels sold in Midland as well.

Operator: Thank you. And as a reminder, if you would like to ask a question, please press 11. Our next question will come from the line of Leo Mariani with Roth. Your line is open. Please go ahead.

Leo Mariani: I wanted to follow up on LOE. It looks like your LOE has come in below guide the last couple of quarters. Can you provide some color around the drivers there? And do you see inflationary pressures rolling through LOE the rest of the year as well? Also, on Egypt oil, you have talked about a modest decline in gross oil volumes. Looking at late 2025, you did not see a decline, though it ticked down a little in 1Q. Are we still looking at a modest decline for the rest of 2026, or can you stabilize it more? Finally, given energy security, could you consider doing a bit more Egypt oil in coming years if prices are supportive?

Ben C. Rodgers: In the first quarter, coming in below guidance on LOE was really cost savings in the U.S., with a little bit of timing. For the full year, keeping guidance at $15.25, we do see inflationary pressures mainly on diesel in Egypt—diesel usage and higher diesel prices pushing up Egypt LOE. Those are offset by other savings we are realizing and expect to continue to realize through the rest of the year, predominantly in the U.S. We have talked about the $100 million of spend this year on LOE uptime projects in the Permian.

Those are going according to plan, and when you bake in savings from that, as well as additional work the field is doing in the U.S., it offsets inflationary pressures in Egypt. So full-year LOE guidance is unchanged.

Stephen J. Riney: On Egypt gross oil, both are true: over the long term, we are on a slight decline, but recent performance has been stable. Adjusting for the small concession we exited earlier this year, we did four quarters in a row right around 121,000 barrels per day—basically flat. For the next three quarters of this year, you will see something closer to flat around 118,000 barrels of oil per day—about a 2.5% to 3% decline from the prior four-quarter average. That reflects a slight year-to-year decline. Quarter to quarter, you can have noise. We are drilling some very nice gas wells in Egypt; some of those are rich gas and come with condensate, which counts as oil volumes.

Some success on the gas side is helping with the oil decline rate. Also note: when we first talked about a slight oil decline several years ago, we were running basically 12 rigs drilling for oil. Today, we are running 12 rigs—half drilling for oil, half for gas—and we are still talking about only a slight annual decline. That speaks to oil that comes with gas and more efficiency on the oil drilling side.

John J. Christmann: [inaudible] Today, we are in a good place with what we are executing on the projects. We have new acreage where we are drilling prospects. We do have oil and gas prospects there, and more success in the program could drive what we do. Right now, they need both commodities, and we are doing what we can on both fronts.

Stephen J. Riney: I would echo that ending comment by John. Egypt is importing LNG now. From an energy security perspective for the country, they are just as interested in gas as they are in oil, because they can import both oil or refined products, which they do.

Operator: Thank you. I am showing no further questions at this time. I would like to hand the conference back over to John Christmann for closing remarks.

John J. Christmann: Thank you. In closing, we delivered an excellent first quarter, with continued execution across our asset base driving strong operational and financial performance. In this current price environment, our focus remains on free cash flow generation through disciplined capital allocation and continued cost reductions. We continue to make significant progress toward our $3 billion net debt target and will continue to balance further debt reduction and meaningful capital returns to shareholders through the cycle. Finally, we are well positioned to sustain production volumes across the Permian and Egypt over the next several years, providing a durable foundation for free cash flow generation.

Suriname Grand Morgue remains on track for first oil in mid-2028 and is expected to drive meaningful organic oil production and free cash flow growth over the longer term. With that, I will turn the call back over to the operator. Thank you.

Operator: This concludes today’s conference call. Thank you for participating, and you may now disconnect. Everyone have a great day.