Ladies and gentlemen, thank you for standing by, and welcome to the APA Corporation's Second Quarter 2021 Results Conference Call. [Operator Instructions]. It is now my pleasure to introduce Vice President of Investor Relations, Gary Clark.

Good morning, and thank you for joining us on APA Corporation's Second Quarter 2022 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO and President, John Christmann; Steve Riney, Executive Vice President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Dave Pursell, Executive Vice President of Development; Tracey Henderson, Senior Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be around 20 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 second quarter 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 non-GAAP financial 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 today. A full disclaimer is located with the supplemental information on our website. And with that, I'll turn the call over to John.

Good morning, and thank you for joining us. On the call today, I will review our second quarter highlights and discuss key trends and performance in each of our core operational areas. Following that, I will provide some color on the 2022 guidance, which we updated last night in our earnings release and supplement. Over the past few months, fears of economic recession, a new wave of coronavirus outbreaks and concern about potential demand destruction have created substantial volatility in commodity prices and the value of energy equities. However, the pullback in oil prices from the second quarter peak is healthy for both consumers and producers. We continue to have a positive outlook on the long-term fundamentals for natural gas and oil and view APA stock as a compelling value today. As I look at our second quarter results, I see several key highlights. APA generated record free cash flow of $814 million. We repurchased 7 million shares of APA common stock, followed by an additional $6.9 million of share repurchases in July. Gross oil production in Egypt increased by more than 7,000 barrels per day versus the prior quarter, which was our first material quarterly increase in Egypt oil production since 2018. Our 40s field maintenance turnaround in the North Sea was executed safely and on budget. We advanced our program in Suriname with the successful flow test at Krabdagu, and we made excellent progress on upstream flaring reductions in Egypt and are on track to achieve our 40% reduction target by year-end. The second quarter was very good in many ways as our diversified unhedged portfolio benefited from rising oil and gas prices and high margins. However, we have encountered a few challenges. In Egypt, although we delivered strong oil production growth in the quarter, we are experiencing…

Thanks, John. For the second quarter of 2022, APA Corporation reported consolidated net income of $926 million or $2.71 per diluted common share. As is common, this quarter, our results include items that are outside of APA's core earnings. The most significant of these was $129 million related to the release of tax valuation allowance for the use of tax loss carryforwards to offset U.S. income tax expense. Excluding this and other such items, adjusted net income for the second quarter was $811 million or $2.37 per diluted common share. Our second quarter results underscore APA's robust free cash flow capacity. The $814 million we generated during the second quarter represents a 21% increase from the preceding quarter and more than double the same period in the prior year. Cost inflation has become a popular topic in quarterly earnings calls and for good reason. Oil and gas firms are subject to the same inflationary pressures on labor, materials, fuel and services as every other industry. We embedded a substantial amount of cost pressure into the budget we laid out in February. And for the most part, costs have tracked close to that plan for the first 2 quarters. For the second half, we anticipate a bit more inflationary pressure in LOE than originally planned, especially in fuel costs. As a result, our full year guidance has moved up a bit higher. Second quarter G&A of $89 million was considerably lower than first quarter and was also below our guidance. As we have discussed before, we use cash settled stock-based incentive compensation plans that require a quarterly mark-to-market based on movements in our share price. This introduces some volatility in our quarterly reported G&A expense, which we generally do not attempt to include in our guidance. For example, APA's share price…

[Operator Instructions]. And our first question comes from the line of Doug Leggate with Bank of America.

John, I wonder if I could hit the 800-pound gorilla in the room, which is in March, you laid out a 3-year plan. And a couple of quarters into it, were $555 million higher in spending and your production guidance is lower. How should we think about Apache management's ability to risk that outlook? And what would you say about the outlook for 2023 at this point?

Doug, thanks for joining us this morning. First of all, we feel good about our 3-year plan. there's been, as we laid out a couple of challenges, and we take responsibility for those and hit them head on. I think the programs are running well. We've got some work to do in Egypt and we're on it. But if you look at -- we did need to take this year's guidance down a little bit. A lot of that is shifting of Egypt to the right, but the well performance has been good. I think it's premature to look at our '23 and '24, and it would be premature to adjust those forecasts right now. But in general, I think we feel good about the overall delivery over the 3-year period. And I will say we baked in a lot of inflation on the cost side, and we have not had -- we've been able to manage that side really well. So I think in general, it would be early to do anything with the '23 and '24 years.

So the '23 guidance today, including the contribution from the acquisition, is that still intact? You haven't -- obviously, you haven't spoken to 2023, but is it intact? Is it higher? Is it lower? Because Street doesn't seem to believe it based on where consensus expectations are?

No, I would just say today, we go through a process every year in the fall, we're looking at the next 3 years. We will review that. We'll come out with a new 3-year look in February. But in general, we still feel pretty good about the 3-year plan we laid out. And we did pick up some properties in the U.S. The program has been running strong and I think as you look out with the 4 rigs in the Permian, we're going to be just fine in the U.S. and Egypt, we're confident in the well results. We've just got to work through some efficiencies there. So in general, we feel good, Doug, about the 3-year plan and -- but it would be premature right now to do anything. We've got some work to do in the short term, but we're on it, so.

All right. On a different number, my follow-up is on gas. Should we now think of the Alpine High having a dedicated rig in which case, what does that mean for the production trajectory there? And as a related follow-up, perhaps, my understanding is you guys have been kind of rethinking the potential implications of your Cheniere contract as it relates to the free cash flow outlook. So I'm just wondering if you could touch on those 2 things, and I'll leave it there.

Yes. No, great question. We did not -- and I'll let Steve comment on the Cheniere contract after I make a few comments on the U.S. rigs. We'll have 4 rigs. We've had 4 rigs running in the U.S., we'll maintain those 4 rigs. You're going to have all 4 of those in the Permian now. 2 in the Southern Midland Basin. We'll have 2 in the Delaware. We've got a rig that we recently moved to Alpine High. Following up the results of our Willow well. We're excited to drill some pads there. So I think it will be positive. So you'll see 2 rigs in that area. The nice thing is having those 4 rigs in the Permian now, we can move them around it based on pads and timing and things. But we do envision 1 of those pretty much stand at Alpine High with the near-term. Steve, anything you want to comment on the Cheniere contract, which is not in those 3-year free cash flow and cash flow numbers?

Yes. Thanks, Doug. So a reminder, the Cheniere contract is a 15-year term contract, 140 million cubic feet a day. Cheniere does have the option to start that early with 90 days' notice. They can do that at any time at this point. But at a minimum, that contract will begin on July 1, 2023. And obviously, the pricing of LNG, JKM and TTF pricing has been amazingly volatile in the last year or so and for that matter here recently, so as Houston Ship Channel. But basically, the contract is structured as a -- where we capture the margin of a mixture of JKM and TTF LNG pricing over Houston Ship Channel. So effectively, people can think of it as we're going to buy at Houston Ship Channel. We're going to sell at a mix of JKM and TTF and we're going to pay some costs associated with tolling through Cheniere's plant, and then we'll pay the cost of transport and fuel loss and things like that. So there's some costs in between that. But that would tell you what the margin structure is on that contract. Again, it will begin July 1, 2023. We believe that is the date that it will begin for the reason I'm about to tell you. And that is that to purchase a Houston Ship Channel on a -- if you look at the forward strip, not even today's prices, which are even higher. But if you look at the forward strip for second half of '23, this contract, the uplift of JKM and TTF over Houston Ship Channel less the cost would generate about $750 million of free cash flow in the 6 months the second half of '23.

And that is not in the free cash flow numbers in the 3-year plan, Steve.

And that is not in any of the free cash flow numbers that we put forward in February. We just assumed all of that, that there was 0 margin over Houston Ship Channel for that contract.

And our next question comes from the line of John Freeman with Raymond James.

First question I had a follow-up to Doug's first question. I realize you said it's kind of premature to look at '23, but we've had as we've gone through this earnings season, we've got more and more operators have talked about how they're having to secure next year as being 2023 kind of services and materials a lot sooner than they would have had to do in years past, just given the supply chain issues, cost inflation, et cetera. And I realize it's easier for some of the peers of yours that you have a single basin type portfolio versus a global diversified portfolio. But can you just sort of talk about like what you're able to do to try and secure something ahead of time, given you obviously have a lot more kind of unknown than many of your peers with the unknowns of what Suriname would look like next year. You got the windfall profit tax in the North Sea. Just I guess, sort of how you all manage in this environment, trying to secure things and kind of lock things in as far as advantage you can give kind of global portfolio you all have?

Well, John, great question. The thing I would say is we typically try to stay about a year ahead of our programs. And so we've been working on 20 -- started working on '23 as soon as the calendar turned. And we continue to do that, and they're starting to get pretty good visibility. The thing I would say about our guidance when we put it out our 3-year guidance, we bumped our capital quite a bit this year, as you'll recall, and took a pretty material increase. Most of that covered where we are today, and that's why you didn't see us have to bump our capital again this quarter. So I think we've got a pretty good handle on things. And I'll just say we built in quite a bit of inflation in '23 and '24 for next -- those next 2 years when we put out that outlook in February. So it's early to come back with hard numbers. for '23 and '24, but I think we've built in a lot of where we sit today on the inflation side.

And then a follow-up question for me on Suriname you've got the drill shift it will move back to -- or move to Block 58 after drilling the Baja prospect and then you end up having the 2 rigs in Block 58. Do you know following the Baja exploration prospect and Dikkop, where those wells would be located and I guess, more importantly, just from a financial modeling perspective, if those wells are likely to be -- continue to be exploration or appraisal some combination?

Yes. No, John, good question. What we typically do, and you can understand the those rig lines are dynamic. You've got some things that are dependent, some things that are independent in terms of wells and orders. And so because of that, we've typically waited until we're ready to move the rigs to tell you where they are going. Total has the value there drilling the Dikkop prospects right now. That is an exploration well. Clearly, we've got the Gerry De Souza in Block 53, where we're drilling an exploration well. That well will be moving back to Block 58 to Total. And I'll just say you're going to see a mix. There's appraisal to do at Sapakara South. There's also appraisal to do at Krabdagu, and there are also some other exploration wells. So when you see the rigs move, you're going to see probably a combination of exploration and appraisal with the 2 rigs. But I'm not in a position today to tell you which rig is going where with both of them right now.

And our next question comes from the line of Jeanine Wai with Barclays.

Our first question, maybe it's for Steve here on the balance sheet and cash returns. You ended the quarter with $275 million on the revolver and that kind of stands out relative to peers. So we were just wondering, can you talk about how you're thinking about balancing maybe upside to the 60% minimum payout this year versus paying down debt versus being opportunistic either with hitting the buyback pretty hard on stock dislocations or bolt-ons like what you kind of announced now?

Yes. Janine, there's -- obviously, there's a lot of embedded questions in that. We're focused on both of those things. We've still got, as I indicated in my prepared remarks, we've still got work to do on the balance sheet. And if you'll recall, we did the $1.1 billion debt tender earlier this year and put quite a bit of that on the revolver. So we use the revolver for things like that, and we use it quite a bit more than we have in the past. That's why you have the revolver, frankly. And we used it again this quarter for the Delaware Basin acquisition. And so -- again, that's the point of having a revolver. You use it from time to time to take some of those material type of steps. In this case, it was just a tuck-in acquisition. But we've got to be focused on continuing to pay down debt. We'd like to get the revolver balance as low as possible by the end of the year. There'll probably still be a bit left on it. But at the same time, we want to balance that with doing the share repurchases in a thoughtful manner. And again, as I said in my prepared remarks, we were in possession of material nonpublic information for quite a bit of the second quarter. So we couldn't be in the market using open market repurchases for shares. So we had to use the 10b5-1 programs. that we had set in place earlier in the year, and we let those run just to make sure that we had a continuing pace. Then when we announced the results of the Krabdagu flow test, we were able to reengage in open market repurchases and you saw what we did in the month of July. And so -- we're going to -- we're somewhat constrained a bit from time to time with material nonpublic information on what we can do on the share buybacks. But I think you're going to see us continue to focus on that and try to be as thoughtful as possible on that for the rest of this year while continuing to balance it with continue to strengthen the balance sheet. I don't know if all of that answered your question or not, hopefully.

It did. It did. Maybe moving to Suriname for our second question. John, your partner recently indicated that you all hope to have an answer on maybe how to incorporate or monetize the associated gas by year-end. And I think 1 of the prior options that was discussed was maybe targeting initial development that was maybe more black oil focused and that could help fast-track the project, get things online. Are there any updated thoughts on this from your end? And I know there's nothing special about reaching FID at year-end during the first half of the year or anything like that. But any update here?

No, Jeanine, I think we're on track today, I would say, we envision a hub that would really set up between Sapakara South, Krabdagu, in that area kind of a centralized hub. We're still targeting predominantly a black oil, lower GOR development today. I do believe we have found a significant amount of gas in the block as well. And I think longer-term, we will want to look at gas alternatives and gas options because there's quite a bit of resource there. But today, our focus has been predominantly on a hub that would be a lower GOR FPSO.

And our next question comes from the line of Bob Brackett with Bernstein Research.

A question on the Delaware Basin tuck-in. Could you give us some color? I'm thinking in terms of a larger acquisition where you might talk about the undrilled location, what does that inventory look like? What did you pay in terms of a free cash flow yield, those sorts of metrics that drove the deal and how they might inform future similar deals?

Doug, Bob, thanks. It's a nice tuck-in inside our Texas Delaware Basin. It has good inventory with long laterals and fits nicely. If you look strategically, we've been selling in the Permian I think we've sold over $1 billion. And so this is a nice ability to take and pick up some properties in an area that we know well where we've been running programs. It's got some production that comes with it. It's got a lot of wells that will be coming online and it's got some good inventory. Dave, anything you want to add?

Yes, I think it's just some follow-on. John talked about it. We've got some wells that have just come online. We have a handful that are coming online later this month. which will drive production through the end of this year. We also have 2 rigs finishing out a pad. It will add a substantial number of DUCs that we'll likely complete in the first quarter of '23. So there's a lot there. I think in the current -- I think when you think about the opportunity set here, -- we've got a number of intervals that this zone has that are low risk. We know the rock around existing infrastructure. So we think about high-quality, low-risk opportunities. Again, you get probably have several years of drilling just on those. And there's some upside potential. There's a number of zones that we're testing in our existing footprint, and we'll continue to test those and we'll likely test those zones here on our new acreage. And again, that's all upside that hopefully we'll be able to talk about as we go through 2023.

And the other thing I would add, Bob, is it brings a hot rig. I mean that's something that if you look a year ago, we were looking to add a rig in the Permian, and we started in the third quarter and really have showed up in April. And the nice thing about this is we've got a really high-quality rig. It's been performing well and a good crew.

Yes. And again, we're not going to talk about the development pace here, but if you can think about conceptually putting 1 rig on this for the next couple of years, this is free cash flow positive from day 1, and continues to generate free cash flow.

And I think that's intriguing the idea that an efficient rig ready to go in the Permian is actually an asset. My follow-up would be -- if I think about the Austin Chalk, and I might have misheard you, but was a 6-well program for 2022, and the revised production guidance was based on the mixed results was 4,500 barrels a day. Can you talk about sort of what the predrill expectations were and some of the learnings on why you didn't hit that number?

Yes. And I'm not -- we probably had more wells than that baked into the plan. But just to frame the Chalk to make sure everybody's familiar. We have a non-op and operated position in Washington County, which is West of College Station. What we've put the pause on was a 20,000-acre piece east of College Station on the Eastern edge of Brazos County. In that 20,000-acre piece, the first well we drilled was an outstanding result. We went into delineation mode as we were trying to delineate this 20,000-acre piece, and we ended up with a lot more variability in the results than we had anticipated. So the thought was, let's put pause on this. We've reduced the number of wells that we're going to put online this year. We're actually going to defer some completions as well while we study the results. And the point is this capital is better spent in the Permian. So we're going to pause it and we'll let you know what we come up with probably sometime in 2023.

[Operator Instructions]. Our next question comes from the line of Neal Dingmann with Truist.

My first question on EGF, I'm just wondering, John, if you -- maybe a bit more detail, just maybe talk about broad comments on what you're seeing on returns there. including maybe just an idea of how natural gas prices are trending the area as well.

Yes. Great question. First of all, our natural gas price is fixed, $2.65 per million per BTU. So gas price are fixed. As you know, we make our money through the profit oil in the split is the way the PSC is designed. So the other thing I would say is if you look at the overall market, here, we are increasing our rig count threefold at a time when the rig count in MENA has been growing at about a 20% clip. And so we found ourselves in a pretty unusual situation where there's been high demand for a lot of our trained Egyptian talent, national talent. And we're in the process at 1 point, I think we had 75 folks that we've had to replace effectively and backfill for. And so it's an interesting time, and it just gives you a little bit of a clue into the competition for national talent in the area today. And the good news is, as we're on it and addressing it. But what it's done is it's the safety statistics have been good, but it's manifested in just some delays in terms of getting wells drilled getting the rigs up and running and then getting wells connected. And so a lot of it, it's mainly just in the reactivation of the cold stacked rigs. And it's something we've done before. but it's just taking a little bit longer. And we'll get it ironed out, and we're working collectively with the folks on the ground there and this is something we'll sort out. You see it in our supplement. If you look at what we had planned to bring on in the second quarter, I think, 24 wells, we actually only got 11 on, but you see the pace with third quarter and fourth quarter picking back up. So it's kind of a short-term above-ground set back, but it's something we will recover from. In terms of the well performance has been good and kind of in line with performance. So no issues on the well performance side.

Okay. Great details. And then just moving to Alpine High. I think you moved to rig or moving a rig there. Will that rig stay? And maybe if you could just comment on what you think the overall pace of activity might be later this year and into next year?

Yes. For now, we see it there. We've got some pads lined out to drill with 1 rig. It takes some time to drill those pads. So I think it will be late, late this year, early next year before you might see some production from that. But the plan is to leave that rig in there for now and for the most part, stay there. It might, after a pad or 2 jump over and pick up a well or 2 in the Delaware. But for the most part, it's going to stay at Alpine High.

And our next question comes from the line of Leo Mariani with MKM Partners.

Just wanted to ask a little bit about the U.S. growth trajectory. I think previously, I think you guys had expected the oil volumes to kind of start to grow by the fourth quarter on an organic basis. I realized you made an acquisition, but you clearly took some volumes out of the Chalk. Just any updated thoughts when you resume organic oil growth again in the U.S. Is that still this year? Or is that maybe sliding into next year?

No. I think we'll get back on track pretty quick. We did pull out the Chalk, but that is greater than 50% gas there. So when you look at that 8,000 BOEs a day, you could think of that probably as being about 3 million or 3,000 barrels a day and about 30 million cubic feet of gas a day, right? So -- but with the addition of moving the rig back to the Permian, they're going to be a little more oily than what the chalk was. And I think we'll get back on track at -- here pretty quickly.

Okay. That's helpful. And then just wanted to ask on Egypt real quick. So you mentioned in your prepared comments, but your gross gas volumes were down quite a bit in the second quarter versus the prior quarter. I think you all had previously talked about several months back about trying to hold gas volumes kind of flattish in 2022. Was there anything anomalistic there, where maybe a plant went down for maintenance or something that caused the drop? Just trying to get a sense of some of those volumes are going to come back or maybe you just have some wells that maybe decline a lot or something?

No. I mean you've got 2 big things there. We've been focused on more oil-focused drilling with the current rig program. And then you've got [Kassar], which was a big gas field that we found along many, many years back, and it's been on a gradual decline. So there's time periods where you'll see the Kassar impact in those numbers.

I'll now hand the call back over to Chief Executive Officer, John Christmann, for any closing remarks.

Andrew, it looks like we have 1 more analyst who has a question.

Our next question comes from the line of Neil Mehta with Goldman Sachs. .

Yes. Thanks, team. I appreciate it. So 2 quick questions for me. First is in Suriname. There has been some talk of some -- I don't know, say, geopolitical tensions, but definitely political uncertainty down there. And so how does that affect the way that you and your partners are thinking about investing in the region? And the other is in the North Sea. Can you guys give us an update of how you're thinking about that basin and the profitability there? And particularly, in light of firm natural gas prices, but also around the risk of windfall taxes.

No. Two really good questions. I'll address Suriname first. Big picture, we feel really good about it. Neil, the offshore, which is a big plus in terms of where the operations are taking place. And I think it just underscores how important development of resource would be for the country of Suriname. And so Statoil's been there a long time. They've got a great track record, and we look forward to working with them and helping try to bring some energy and some GDP growth into the country. So I think it's a positive from that perspective. And it just shows you that in today's world, there are some challenges out there with inflation and other things going on and a lot of countries are addressing that, including Suriname. In the North Sea, I think we've got a very, very strong business there. We've always characterized our assets as kind of 2 different plays in 2 different -- 2 totally different assets. 40s, we're obviously managing it into the later phases of its life and looking to manage that margin. And as you see it wind down, we still see that happening early next decade. And you see the profits levy there starts to impact timing of some of those things. And so in the prepared remarks, my comments were this isn't helpful sometimes for future investment, and it may actually shorten the life of some things, but we're not facing that today with where it is. And then the other asset up there that we have still some great programs in and see some future development is in the tertiary at Beryl. And we've had some good strong programs and look forward to that. But I think you do have to just step back and look at your future capital, how it fits within the portfolio. But today, we see the North Sea playing a key role.

I am now showing no further questions. So with that, I'll hand the call back over to CEO, John Christmann, for any closing remarks.

Thank you for joining us today. I'd like to leave you with the following closing thoughts. We remain very focused on generating free cash flow. In 2022, this will be approximately $3 billion. We will return at least 60% or $1.8 billion to shareholders. Our new properties in the Delaware Basin are additive to this framework. It's an attractively priced tuck-in acquisition and cash flow accretive from day 1. In Egypt, well performance has been good, and we're actively addressing the above-ground inefficiencies to get well tie-ins back on schedule. Operator, I will now turn the call over to you.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating, and you may now disconnect.