APA Corporation

Good day, and thank you for standing by. Welcome to APA Corporation's second quarter 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, you will need to press star 1 1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1 1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's second quarter 2024 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO John Christman. Steve Riney, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Tracy Henderson, Executive Vice President of Exploration, and Clay Breccias, Executive Vice President of Operations. Our prepared remarks will be less than 15 minutes in length, with the remainder of the hour allotted for 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 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 on today's call. A full disclaimer is located with the supplemental information on our website. Please note that the CALIN acquisition closed on April 1st. Accordingly, our full year 2024 guidance reflects first quarter APA results on a standalone basis, plus three quarters of APA and CALIN combined. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On the call today, I will review APA's second quarter performance, discuss the calendar integration, and review our activity plan and production expectations for the remainder of 2024. Our second quarter results were strong across the board, with higher than expected production in all three operational areas. CapEx was lower than expected, mostly due to timing of spend. In the U.S., oil volumes of 139,500 barrels per day were up 67% from the first quarter as we incorporated Cowan into our operations. Production and costs were significantly better than expected on a BOE basis after adjusting for asset sales and discretionary natural gas and NGL curtailments. Our Permian Basin continues to perform at a high level. and we marked our sixth quarter in a row of meeting or exceeding U.S. oil production guidance. On a BOE basis, oil now comprises 46 percent of our total U.S. production following the Callen transaction. With this increased exposure, APA's cash flow sensitivity to a $5 per barrel change in oil price is approximately $300 million annually. In Egypt, production also exceeded expectations. We saw positive contribution from new wells, improved results from recompletions, and continued strong base production. Base production is particularly benefiting from the implementation of several new water injection projects. We are also beginning to see a decrease in offline oil volumes waiting on work over, as we moderate the drilling rig count to free up work over rig resources. Turning to the North Sea, operations were relatively smooth in the second quarter, with better than forecast facility runtime driving higher production. Our ongoing focus in the North Sea is rightsizing our cost structure for late life operations. In Suriname, our partner, Total, recently announced that it has secured the FPSO hole for our first offshore development and we remain on track for FID before year end and first oil in 2028. And in Alaska, we are still working through options for the upcoming winter drilling season and look forward to returning to exploration activities. Turning now to the Cowan Acquisition. Note that in last night's release, we increased our estimate of annual Cal and cost synergies from 225 million to 250 million as we leverage economies of scale of the combined APA and Cal and Permian businesses. Steve will speak in more detail about some of the specific initiatives driving these cost reductions. More importantly, we are just beginning to implement drilling unit design and operational changes that we expect will create substantial value on the Callen acreage via improved well performance and capital efficiency. Our preliminary estimate is that we can drill a standardized two mile lateral for roughly $1 million less than Callen was spending in 2023. We recently spud our first APA designed drilling unit on Callen acreage the five-well Coleman unit in the Midland Basin and should begin to see initial flowback results in the fourth quarter. Turning now to our activity plans and outlook for the second half of 2024. In yesterday's release, we provided guidance for the third and fourth quarters, which contained some notable positives. In the U.S., we will average nine to 10 rigs for the remainder of this year, consisting of approximately five rigs in the Delaware and four rigs in the Midland. We plan to run three to four frack crews and complete about 90 wells by year end. This sets the stage for strong oil growth in the second half of the year. Accordingly, we are increasing fourth quarter U.S. oil guidance to 150,000 barrels per day, which is up 1,500 barrels per day after adjusting for the impact of asset sales closed in June. This represents organic production growth of roughly 8% compared to the second quarter. We also expect an increase in natural gas and NGL production, driven primarily by fewer discretionary curtailments than in the first half of the year. In Egypt, we expect a continuation of the operational progress that we made in our second quarter. There will be some volume impacts from the rig count decrease, but this should be mitigated by strong base production performance and increased work over capacity to remediate wells offline. By year end, we project that backlogged oil production will be closer to more normalized operating levels. On our May call, we said that adjusted production in Egypt would remain relatively flat in 2024, while gross oil production would be flat to slightly down through the remainder of the year. While there are a number of moving parts to the program in Egypt, we see no material variances to our May outlook, and therefore guidance is unchanged. Similarly, our four-year production guidance in the North Sea is unchanged. though we now expect a bit larger decrease in third quarter volumes associated with maintenance and turnaround activity at Barrel, and a slightly larger subsequent rebound in the fourth quarter. In closing, second quarter was an excellent quarter operationally, and we continue to execute at a high level in the Permian Basin. We are realizing greater than expected cost savings from the Cowan acquisition, and have a clear pathway and plan to improving capital efficiency on those assets. Egypt also had a very good quarter and is beginning to deliver significant capital efficiency improvements. Though our drilling rig count is coming down, continued strength in base production and the return of wells offline will help sustain volumes in the near term. At current strip pricing, the second half of the year is setting up to deliver a substantial increase in free cash flow compared to the first half. And lastly, I am very proud of our teams for delivering these results while remaining on track to achieve our safety and environmental goals for the year. For a detailed review of APA's safety and environmental performance, I encourage you to review our recently published 2024 sustainability report, which can be accessed via our website. And with that, I will turn the call over to Steve.

Thank you, John. For the second quarter, under generally accepted accounting principles, APA reported consolidated net income of $541 million, or $1.46 per diluted common share. As usual, these results include items that are outside of core earnings. the most significant of which were a $216 million after-tax gain on divestitures and $98 million of after-tax charges for transaction reorganization and separation costs, mostly associated with the Callan acquisition. Excluding these and other smaller items, adjusted net income for the second quarter was $434 million, or $1.17 per share. During the first half of the year, we generated roughly $200 million of free cash flow and returned $311 million to shareholders, nearly half of which consisted of share repurchases. That's a lot compared to the $200 million of free cash flow, but we liked buying at those share prices, and we anticipate free cash flow will be much higher in the second half of the year. That said, the balance sheet remains an important priority and I will talk about plans for further debt reduction in a few minutes. Now let me turn to progress on the Calend integration. As John noted, we increased our estimate of annual synergies to $250 million. Since we announced the Calend acquisition, we have categorized synergies into three buckets, overhead, cost of capital, and operational. We are now increasing our estimate of expected annual overhead synergies to $90 million. Most of this was captured by the end of the second quarter on a run rate basis, and the remainder will be done by year end. At this time, we anticipate that our quarterly core G&A run rate, as we enter next year, will be approximately $110 million. With that, we will have eliminated about 75 percent of calendar overhead cost, so no material further synergies are likely. Our cost of capital synergy estimate of $40 million annually Assume terming out Cowen's $2 billion debt at APA's lower long-term cost of borrowing. At the closing, we used cash from the revolver and a $1.5 billion three-year term loan to refinance this debt. Instead of terming this debt out, our current intention is to use asset sales and free cash flow to simply pay off the loan before the end of its three-year term. This would represent a significant step forward in the goal to strengthen the balance sheet and to fully realize these synergies. And lastly, we are increasing our operational synergies to $120 million annually, approximately 60 percent of which is associated with capital savings and 40 percent attributable to LOE. To reiterate, these cost synergies do not include capital productivity benefits associated with uplifting type curves and improving well economics through spacing, landing zone optimization, and frac size. We believe this will be a source of material long-term value accretion. Turning to our 2024 outlook, John has already discussed our activity plans and production guidance, so I will just add a few items of note. We now expect that our original full-year capital guidance of $2.7 billion may start trending down a bit. A number of factors could contribute to this, including further synergy capture from the Callen combination, lower service costs, improving capital efficiency, and potential minor reductions in the planned activity set, mostly in the U.S. For purposes of third quarter U.S. VOE production guidance, we are estimating further Permian gas curtailments of 90 million cubic feet per day. This would also result in the curtailment of 7,500 barrels per day of MGLs. As most of you are aware, our income from third-party oil and gas purchased and sold can change significantly from quarter to quarter. This is primarily driven by the volatility in differentials between Oaxaca and Gulf Coast gas pricing, regardless of the absolute pricing levels. It's important to note that APA's gas marketing and transportation activities are generally more profitable when Oaxaca gas price differentials are wider. For example, the Waha differential was very wide in the second quarter. While Gulf Coast gas prices averaged around $1.65, Waha gas prices averaged closer to negative 34 cents. Because of the nearly $2 differential, income from our third-party marketing and transportation activities was well above expectations. At current strip gas pricing, we expect a similar dynamic in the third quarter. Accordingly, we are raising our full-year estimate of income from third-party oil and gas purchased and sold by $120 million to around $350 million. Approximately half of the full-year estimate is attributable to the Chenier gas supply contract, and half is attributable to our marketing and transportation activities. Lastly, APA is now subject to the U.S. alternative minimum tax, And accordingly, we are introducing new guidance for current U.S. tax accruals of $95 million for the year. And 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. As a reminder, to ask a question, you will need to press star 1 1 on your telephone and wait for your name to be announced. To withdraw the question, please press star, one, one again. You may ask one question and one follow-up question. Please stand by while we compile the Q&A roster. Our first question comes from Doug Legette of Wolf Research. Your line is now open.

Hey, guys. I'm still getting new moniker, so... Bear with me. Thanks for having me on.

Welcome back into the frame, Doug.

Thanks, John. So I guess there's so many things on the quarter that I could go after. I'm going to just try a couple. But, Steve, it looks to us that your CapEx run rate exit, call it fourth quarter, looks like you're going to be around $600 million today. which would be about a 10% decline year over year if that held into 2025. Is the objective after you grow, you know, you've got the momentum from Callan, is the objective to hold that flat? In which case, should we be thinking something around 2024, 2025 for next year?

Yeah, Doug, I'd be careful just using fourth quarter. We're probably going to be a little longer on completion activity in the fourth quarter because a lot of that has been bunched into second quarter and third quarter this year just because of the timing of availability of wells for completion. So I think the easier way to do that would be to look at a full year spend take out the first quarter, which is just APA, and then, you know, I would probably first adjust that for the exploration spend, and then just divide it by three quarters, because the quarter was high. Third quarter is going to be about average-ish, and fourth quarter is probably going to be a little low.

And then I think you'll get a number of something close to around 700 per quarter.

Okay. All right. That's really helpful, guys. Sorry.

If you take out the exploration, you'll probably get something closer to 675 million a quarter of capital spend on basically the U.S. onshore and in Egypt. There's not a whole lot of capital activities going on in the North Sea.

Okay, that's what I was trying to get at. That's really helpful. John, I wonder if you've not wanted to be drawn on inventory depth since the Callen deal, but I'm guessing you're getting your hands around that now. So when you look at the drilling pace with, I guess, you're going to be at nine rigs in the second half. What are you thinking with the upspacing and so on? What are you thinking about your inventory depth looks like now in the lower 48? I'll leave it there.

Yeah, Doug, it's a great question. It's one we're, you know, we're working every day. What I would say is if you look at the existing, you know, U.S., Permian run rate we've always said kind of end of the decade with the rig rate we're at um and when we said we bring a calendar in pretty similar uh duration um i think there's one upside on the calendar is that if we can drive the productivity improvements that we think we can then there will be more inventory that comes into play that we did not you know pay for in our acquisition um so That's something we're currently working on. You know, if you look at where we sit today, we've got a lot of flexibility going into next year. We're going to grow Permian a very strong clip from second quarter to fourth quarter, you know, on nine to 10 rigs, about 8%. And so it gives us a lot of flexibility, you know, going into next year pace we want to go. And we've had plenty of, you know, inventory that we have visibility on now to carry us to the end of the decade. And, you know, we'll keep working that.

Yeah, just a bit to add on, Doug, to what John just said, just to enhance that a bit. You know, when we were working on the acquisition, of course, we were looking at a lot of outside service providers that look at inventory counts, and most of them probably would have said that Cowan had more running room, more inventory, more years of inventory than we did, based on our analysis, as John said, which is fairly significant. a fairly conservative view of the world. We said now it's probably more similar to ours in duration. And as John indicated, the more we can get capital efficiency, capital productivity into the right place on the Cowan acreage, the more that inventory quantum could grow back to what some of the other people thought it was, which is something that would extend beyond the end of this decade.

Got it. Thanks, guys. I'll see you next week. Thank you.

One moment for our next question. Our next question comes from John Freeman of Raymond James. Your line is now open.

Good morning, guys. Good morning, John. Just kind of following up on some of Doug's questions. I mean, the Permian and Egypt both exceeding guidance and you know, specifically on Egypt, you know, pretty solid job of getting that turned around. And I'm just trying to make sure that, you know, I'm thinking about this right where you've got, you know, you average 16 rigs in the first half of the year, you're going to drop down to 11 rigs in the second half of the year. And am I kind of reading it right that even at that lower rig cadence in the second half of the year, because of all the steps that y'all outlined in terms of the improved kind of base production management, uh catching up on the recompletions you know resolving kind of that backlog of oil offline um in the back half of the year is that 11 rigs sort of cadence in the second half of the year i mean is that like an acceptable number to kind of maintain volumes just trying to make sure i understand kind of what's the moving pieces it's a great question john and uh you know you're you're you're on the right track i'd say that uh

You know, the benefit we've had by dropping the rigs is it's been able to free up the work over rig time, which is critical because we have a lot of recompletions. And really, we also have a lot of CTIs, which are conversion to injection projects that we've been able to get to. And so, you know, when we were running, you know, 20 work over rigs and 18 drilling rigs, there's not much slack. By ratcheting that back, it's freed up the time and it's letting us get to some very meaningful, you know, projects that are making a huge impact. Is 11 rigged? You know, this year we kind of guided to flat to slightly down. Is 11 the right number? It's early to tell on that front. But, you know, just having gotten back from Egypt, there's also a lot of other projects that we're talking to Egypt about, you know, for example, some gas drilling and other things, too, which could be pretty impactful as well. So, you know, there's lots of flexibility there. And, you know, we'll be working through that as we work through the planning cycles.

Great. And then just my follow-up, John, you mentioned that you'd see the The gas volumes on the U.S. side actually grow some, and it had to do with sort of the – well, one of the drivers was the fact that you'd have less curtailed gas volumes potentially in 4Q. So in the current guidance, does it assume any curtailments in 4Q? I mean, obviously, y'all, you had some in 2Q. You have even more in 3Q. I'm just trying to get something that's built into that for your guidance.

Today, 4Q – you know, fourth quarter does not have any curtailments built in. But obviously, we had to up, you know, the third quarter with September with where Oaxaca sits.

Yeah, and just, you know, second quarter actuals, the amount that was curtailed, we had 78 million cubic feet per day of gas and 7.6 thousand barrels of NGLs curtailed during the quarter on an average day. You know, that's nearly 21,000 BOEs per day. Our forecast for third quarter, what we've effectively left out of our guidance is 90 million cubic feet per day of gas and 7.5 thousand barrels of NGLs. That's 22 and a half thousand BOEs per day. Those are really large numbers, as you might imagine.

Appreciate it, guys. Nice quarter.

Thank you, John.

One moment for our next question, which comes from Neil Dingman of Truist. Your line is now open.

Hi, morning, guys. Nice update. John, maybe sticking with on the Permian or the Callan, specifically the Callan acreage development, really just wondering here, you all talked about, I think pretty openly, potentially upspacing a little bit. I'm just wondering besides potentially future upspacing, is there any sort of material other changes either on the completion or other side? going forward you could see potentially doing in this point?

Yeah, as I said in the prepared remarks, Neil, that one of the advantages too is we're seeing impacts on the combined business just from the supply chain, how we design the wells. We think we can drill a standard two-mile lateral for about a million dollars less than what Calum was spending last year, which is 20%. So we're anxious to see those numbers start to come through. But, you know, excited about what we're seeing. And quite frankly, we're just now starting to spud some of the Apache plan pads on the Callan Acres. So, you know, excited to see those results. But things are going extremely well on the integration side.

Yeah. Go ahead, Steve.

Yeah, the only thing I would add to that on the completion side, you know, with the Callan drilled wells or Callan spud wells, since they were spaced, quite a bit tighter than we would space them. We haven't really changed the profit loading much on those. We did on a few, but not many. But we significantly increased the fluid loading on those fracks. As we get to our wells, the ones that we drill, obviously, the profit and fluid loading will be quite a bit larger.

Great, great. And then maybe, Steve, for you, just a second question on shareholder return. Specifically, your show return continues to be quite active. I think it was down a little bit sequentially this last quarter. I'm just wondering, can we anticipate a large step up for remainder of the year? How would you like to think about the program for remainder 24 to 25?

I tend to think of that on an annual basis, a calendar year basis. We've got at least 60% of free cash flow

through dividends and through share buybacks, both with April 1st acquisition using shares, the outlook of dividends and for free cash flows changed quite a bit. But the framework doesn't change. 60% at a minimum. We're obviously way ahead of that in the first half of the year. And You know, we'll see what the second half brings. We I think we've demonstrated in the past that we're not afraid to go over well over the 60% and work. But let's you know, we also recognize there's continued need for balance sheet strengthening way after the. And so we're going to we'll balance that on a, you know, quarter by quarter, really day by day basis.

We'll see where we are as we go from one year to the next. Very good. Thank you.