APA Corporation (APA) Earnings Call Transcript & Summary

Good day, and thank you for standing by. Welcome to APA Corporation's Second Quarter 2026 Financial and Operational Results Conference Call. [Operator Instructions] 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, and 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. Steve Riney, President; and Tracy Anderson, 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 noncontrolling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss in today's call. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. 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 remained 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, 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've 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 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 GranMorgu development continues to progress on budget and on schedule towards 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 Saki 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 box 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 Cowen integration, we initially estimated that sustaining Permian oil production around 120,000 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 123,000 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 Caser. 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 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'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 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 of free cash flow during the second quarter and returned $189 million to shareholders through dividends and share repurchases, underpinning these results with 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 U.S., which have offset inflationary pressures such as global diesel costs. Through the first 6 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 3 years. While higher prices have played a role, we are also benefiting from structural improvements we've made across the business over the past 2 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 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 increased 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 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 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'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, 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&A.

[Operator Instructions] Our first question comes from Doug Leggate of Wolfe.

John, this is the first time that you've 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 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. So can you share what your current thinking is? Do you have a semblance of a development with Sakai as it stands today? Or is it contingent on a successful appraisal program? And any other color you can offer would be great.

Well, Doug, I 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 2 successful discoveries with King Street and Sakai, we were able to test sake. We took a break this last winter to reprocess seismic because there were multiple surveys that needed to be stitched together. So we're very, very excited. We said we've got a high-quality sand there. We can now confirm that we did not drill Sachi in the thickest portion. We've got 2 key wells set up for this upcoming winter. We'll start building ice roads late this year and then spud 2 wells in '27. One will be an appraisal well sake Hungry Horse. And then the second one is an even larger independent prospects, Chinook. They're both similar geology. Obviously, with the appraisal well, you're appraising the sake discovery. And 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 of pipeline capacity, but it also brings a large gravel pad. There's 40,000 barrels a day of processing equipment, and it has an air strip as well as a dock. And so 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 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, very excited. I think the thing that we've always talked about that both King Street and Sockai approved is that we've got higher quality reservoir rock than some of the plays that are being developed quite a ways away to this. And so we're very excited about it. It's state lands. It's oil. The new processing and the seismic was a really, really good call. So we're very, very excited about it, Doug, but our next step will be to appraise sake, drill Chinook and then come back and be in a position to talk more about it at that point.

Okay. I understand. My follow-up, if I may take advantage of pace been on the call or whoever wants to take this. But the ENI deal, NCAP has given quite a lot of detail on the prospectivity of the whole area. ENI is obviously a top -- one of the top, if not the top global Explorer in the last several years. And I guess my question is simply this. There's 1 well in the deepwater, John, RA that you know well. It looks to us that they 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 2 blocks, Block 6, which we had 100%. We now have 60% of that. And we are really, really thrilled to welcome ENI as our partner. It was a very competitive process, and it really speaks to the quality of our position in Uruguay and how prospective that block is, but also a credit to our exploration team. And the work that we've done now with Suriname, bringing in total, and we're less than 2 years away from first oil there with GranMorgu and now bringing E&I into Block in Uruguay. So we're thrilled to have them here. I'll let Tracy jump in. Obviously, the 1 well was to -- and 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. 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. So that's driven our interest in a lot of the industry interest into Uruguay. And 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. And so really, it was that source rock data that drove interest that we're going to test on the Uruguay side. The interesting thing, as you pointed out, there's really only one well in the deepwater in Uruguay, and that is the Ria well. And 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. And 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 Ria well tested. So with the exploration well, we'll be looking at that source rock but also testing deposition, migration and trap and seal on the side. So it will be a very, very big well. We've got a really high-quality 3D seismic data set over the prospects in Block 6 and Block 4 that we are looking at extending it in Block 4. But we've seen some terrific prospectivity on the very large prospects. And as John said, we'll look at testing that in late 2027.

Our next call comes from John Freeman of Raymond James.

Last quarter, you've all emphasized maintaining the flexibility between debt reduction and buybacks and now given just how strong the balance sheet is. Obviously, you all are pretty explicit that the the #1 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 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.

Sure, John. This is Ben. Good question. And yes, 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 the right use of incremental free cash flow between the debt and the equity. And 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. And having that so close from when we outlined the target in August and here we are at the time in May, you're 9 months from that and it was so close, really just gave us the opportunity to look at balancing those 2 different commitments around the equity returns and reaching that $3 billion, but we're in a great position from a balance sheet, lowest debt balance that we've had at Apache in over 15 years. And 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. And so 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. And then you 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's captured on what's still left?

Yes. So I'll actually do it from an annual basis, John. And 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 million 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'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 million is actually closer to the high $400 million, call it, $475 million. Some of that's being offset with inflation, and 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. And so that captured amount, putting aside inflation, would have been $475 million. But when you encount that inflation, it's probably closer to $425 million. But because we're capturing more true savings, that run rate is now higher from the $450 million, and it is now $500 million, and it's across all 3 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 savings and then G&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, we've separated the controllable spend of those 3 buckets from interest expense savings. But we also now because -- and from our 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, we've 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 paydown, 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'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.

Our next question comes from Josh Silverstein of UBS.

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. 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 0 impact? And how things may look for you guys next year?

Sure. Good question. Actually, since we've -- since those pipeline positions have been put in place and 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 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-plus years, almost every year, we've had a hedge position in place. And so I would expect that trend to continue to next year. We've not put any places for '27 yet. We do monitor that. And 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. So 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. And then, John, you mentioned you're 2 years away from the start-up of the GranMorgu project. And it's clearly a key differentiator for your growth profile into the future. Knowing you have this around the quarter 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 you think about different options there?

Yes. I mean I think, Josh, it's a great question. And first of all, things are on track with GranMorgu. We've said mid-'28 first oil and Total came out and said potentially first or second quarter of '28. So we're going to stick with mid-'28. What has positioned us to where we can just maintain volumes on our core assets to Permian and Egypt, well, then you've got growth coming, right, through our exploration program and through [indiscernible]. I think a couple of things. So the big thing there is the way we structured our joint venture with Total, we're benefiting from a large carry in turn of today, which has enabled us to continue to fund our programs domestically and internationally with Egypt and Permian. But 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. And so it really, really has worked to our advantage. And quite frankly, without that, we wouldn't be in the position we're in today. So 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. And then obviously, gas has changed our picture in Egypt as well. So we've been growing our BOEs -- gross BOEs in Egypt. So 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. So 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.

Our next question comes from Aram Jayaram of JPMorgan.

John, I was wondering if you could comment on how you think your sustaining requirement -- 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, but then you did mention how your rig count now is going down to 4. And obviously, you're generating some efficiencies. So 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?

Yes, Arun, it's a great question, and we're in a really dynamic period, both for us and industry. And if you go back to post close of Cowen, we believed it was 8 rigs to hold 120,000 barrels a day flat. As you mentioned, we're now currently at 4. We've guided to 123 for this year. And it's been a stair step 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 6. We've been running -- we're at 4 rigs today. We started at 5. We dropped down to 5 last year. We're clearly under 6 rigs to maintain at 120. We've been doing that for the last 2 years. So it does give us some flexibility in terms of how we think about that. And I'm not ready to dive in to '27. We'll give a little bit of an insight today, talk a little bit in November and then obviously, in February, we'll 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 very proud of that. And 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, feature drilling, in the turn-in lines. But I don't know, Steve, anything you want to add to add to that.

Yes, John, I'll just -- just to echo your last comment there, we started the year -- this year with a plan of 5 rigs, and we're clearly going to end up at 4.5 rigs. Those 4.5 rigs will drill more lateral feet and will complete just as many wells as we planned with 5 rigs. And so we're down to 4 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. And so it's just -- again, to your earlier comments, it's about the -- both the scale and the pace of change and efficiency gains that the team has gotten to. And it's continuing in '26. '25 was obviously a really big year where we started off with this notion that 8 rigs would sustain 120 and halfway through the year, we were at 6 rigs, sustaining 120. And I agree with you, right now, we're -- we've been delivering basically 123,000 barrels of oil a day. And by the end of this year, it will be for 2 years straight. And we're doing that clearly with fewer than 6 rigs. We'll average 4.5 this year. Not saying that it's 4.5, but as we do the planning for 2027, we'll talk a bit about it in November and then obviously give the details in February after we've had the full discussions with the Board and the full review of the plan.

Appreciate that. And maybe just a little bit of a follow-up. On Egypt, 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.

Yes. Arun, we've been in the Western Desert since 1994. And until really late '24, all we focused on was oil and exploring for oil. Obviously, we entered into a new price agreement in November of '24. We started then to how do you translate what we know into gas. We knew there were some low-hanging fruit that you saw us get after last year. But we've really only been exploring now for gas in the Western Desert for, call it, 12 to 18 months. So we're stepping out. A lot of it's similar type rock, but you're looking deeper now. The key to think about in Egypt is we've got 20,000 feet of sand effectively. So the exploration program there is much different than the offshore stuff where you've got your seismic tuned. It's either there, 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. So the program has been very consistent. That's why you see kind of a steady diet of successes as well as some dry holes because at depth, it's hard to really differentiate sand versus pay. But 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. And so a lot of it is stepping out in the deeper parts of the basin. It's stepping into places that we avoided because we thought it might be more gas prone. So 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. But we've got a lot of key wells coming up. We've drilled a lot of nice discoveries. So very pleased with the program. But the key here is it's conventional, it's not unconventional. And success has been set up 1 to 2 to 3 to 5 type well offsets. And so we've got a lot of concepts that are at play.