APA Corporation

Ladies and gentlemen, thank you for standing by, and welcome to the APA Corporation's second quarter 2022 results conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. 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 Christman. 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 Purcell, Executive Vice President of Development, Tracy Henderson, Senior Vice President of Exploration, and Clay Breches, 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 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 discussed 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 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 tests at Crab Dago, 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 some delays and inefficiencies as we scale our active rig count from 5 to 15. These include supply chain, equipment, and infrastructure-related delays, longer-than-expected time to staff and reactivate cold-stacked rigs, extended drill times, which are primarily a function of new rig and new crew inefficiencies, and increased regional competition for experienced national employees. Well performance in Egypt has been in line with expectations. so these are mostly short-term, above-ground challenges. We have identified and are swiftly taking appropriate actions that will bring us back up to pace. In the Austin Chalk, our delineation program has generated mixed results thus far, so we have chosen to pause most of our planned drilling and completion activities. I will talk more about the impact of these items on our second half guidance in a few minutes. Turning now to some of the details of our second quarter results. Our largest spend categories, capital investment, operating costs, and GNA were in line or less than expected for the quarter, despite a challenging overall supply chain and cost environment. Total adjusted production of 305,000 BOE per day was down compared to the first quarter, primarily driven by our early March Permian Basin minerals divestiture, the impact of high oil prices on our Egypt PSC volumes, the timing of well connections across the portfolio, and seasonal maintenance in the North Sea. We continue to expect our global adjusted production volumes will return to a growth path this year as our activity has now reached a level that we have not seen since 2019 prior to the COVID pandemic. In the U.S., we continue to run a steady two-rig program in the southern Midland Basin and recently initiated drilling at Alpine High with a third rig. In Egypt, we averaged 12 rigs, brought online a number of quality wells, and achieved a high drilling success rate. Our strong oil production growth in the quarter was partially offset by a decline in lower-margin natural gas production. In the North Sea, we were in the midst of summer turnaround season. We completed the maintenance turnaround at 40s on schedule and on budget and have brought that field back into production. At Beryl, we are wrapping up a platform turnaround and will return to production in the near future. On Block 58 in Suriname, our partner's hotel is drilling the Dickop Exploration Prospect, which sits roughly 8 kilometers northwest of our Sapakara South Discovery. On the adjacent Block 53, we are drilling the Baja exploration prospect with our partners Petronas and SEPSA. On July 29th, we closed on an acquisition of properties around our active development areas in the Texas-Delaware Basin. This is an attractively valued tuck-in acquisition that comes with PDPs, a number of wells in the drilling and completion process, and a nice inventory of undrilled locations. It also brings a high quality drilling rig and experienced crew to continue development in this very tight service environment. There are currently two rigs running on the new acreage. One will be released in the fourth quarter and we will retain the other as our fourth U.S. development rig. These assets compete well within our portfolio and integrate nicely into our Permian operations. Turning now to our outlook for the second half of the year, which we included in our financial and operations supplement last night. Our CapEx program of $1.725 billion remains unchanged for the year. Steve will have some comments on a few minor changes in other P&L guidance items. In terms of adjusted production, our new four-year guidance range for Egypt is 63,000 to 65,000 BOEs per day, which is down about 7% from prior expectations. More than half of this decrease is a result of fewer wells being drilled and completed due to the operational challenges I spoke of earlier. The remainder is attributable to the PSC impact of higher oil prices. In the U.S., we have a number of moving parts affecting our outlet for the remainder of the year. First, we have removed roughly 8,000 BOEs a day of Austin chalk production from the second half of the year following the decision to defer most of our near-term drilling incompletions. Second, we expect the Texas Delaware Basin acquisition properties will average 12,000 to 14,000 BOEs per day of production for the remaining five months of the year. We've also encountered some completion delays on Permian-operated and non-operated wells and recently divested a small package of Permian properties. The net effect of these items is a slight downward revision to our four-year 2022 U.S. production guidance. In the U.K., our near-term activity plan and four-year 2022 production guidance remains unchanged. Later this month, the Garten 3 development well will commence production, which should generate a significant volume uplift in the fourth quarter. I will note that the new energy profits levy recently became effective in the UK. This reduces our free cash flow outlook going forward, and while it won't affect our 2022 drilling program, we are evaluating the longer-term impacts of the tax on our planned investment in the UK. But in general, new taxes are not effective incentives for increased investment. Steve will share more details about the tax impact in his remarks. Turning now to an update on our ESG initiatives. APA's top priorities are reducing GHG emissions throughout our global operations and supporting our employees and the people in the communities where we operate. We have completed several projects across the portfolio, most notably in Egypt, that enable us to compress and direct previously flared gas to sales, thereby increasing revenue and improving our emissions profile. This puts us well on our way to achieving our goal of reducing upstream routine flaring in Egypt by 40% by year-end. I am very pleased with our progress on this and many other fronts, and there is much more to come. Also, in late July, we issued our 2022 sustainability report. I hope you will take a moment to review the report and learn more about our strategy and initiatives to provide affordable, reliable energy to the world, while also delivering on rigorous near and medium-term ESG goals. In closing, APA remains committed to returning 60% of free cash flow through buybacks and dividends, as well as strengthening our balance sheet, including paying down debt as it matures. At current strip prices, we expect to generate approximately $3 billion of free cash flow in 2022, of which at least $1.8 billion would be returned to shareholders through dividends and share buybacks. Through July, we have returned just under 50% of this amount. And finally, I would like to extend a personal thank you to John Lowe, APA's chairman, who recently announced his retirement after serving nine years on the board. John has been a great friend and colleague. We have benefited greatly from his experience and insights, and we wish him all the best. Lamar McKay has been elected to serve as APA's new board chairman and will formally take over for John in September. Lamar has a wealth of experience that I know will be a tremendous asset to the boardroom and my leadership team. We are all looking forward to working with him and welcome him into his new role. And with that, I will turn the call over to Steve Reine.

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 carry-forwards 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 two 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 share price increase into the end of the first quarter resulted in higher reported G&A expense, and the declining share price into the end of the second quarter resulted in the opposite. As a baseline, our underlying quarterly G&A expense runs around $100 million, and our full-year guidance reflects this for the remaining two quarters of the year. With the higher commodity prices, you will note that both sales and costs related to purchased oil and gas have increased substantially. As a reminder, where possible, we sell all of our production in Basin, and our marketing organization fulfills obligations on various commercial agreements, such as long-haul transport contracts, using purchased product. The net impact of these two lines will mostly track the basis differential, less transport costs on the GCX and PHP pipelines. Finally, exploration expense was higher during the quarter, as we recorded $32 million in dry hole costs related to the Rasper Exploration Well in Block 53 offshore Suriname. Turning now to the progress we made during the quarter on the balance sheet. In the second quarter, we paid down $605 million on our revolving credit facility, which brought our balance down to $275 million on June 30. Last week, we drew on the revolver to fund the closing of our Delaware Basin acquisition. so that balance will rise again in the third quarter. In the fourth quarter, we will pay off the January 2023 bond maturity of $123 million at par. While we have made great progress strengthening the balance sheet over the last year, we have more to do. That said, it is nice to see the rating agencies recognizing the improvement. Our long-term desire is to return to investment grade through a continued steady pace of debt reduction paying off bonds at their maturity, combined with the occasional debt tender or open market repurchases. A couple of other things before we turn to Q&A. With respect to our full year 2022 guidance, there are a few minor changes. We increased our guidance for LOE and decreased guidance for GNA to reflect some of the impacts I spoke of previously. We have also updated our guidance for our latest view on the net impact from purchased oil and gas I mentioned earlier. Our guidance for UK tax expense has increased to reflect $130 million incremental cost for the energy profits levy. We will pay this additional 2022 tax in two parts, approximately half during the fourth quarter of this year and the remainder in the first quarter of next year. As John noted previously, we are committed to our capital returns framework, which means material share buybacks will continue in the second half of 2022. Ideally, all of this would be delivered in a day-by-day open market repurchase program. However, there has been and will continue to be periods of time where the possession of material nonpublic information will preclude open market repurchase of our shares. During such times, we expect to utilize 10 programs to maintain a minimum underlying pace of buybacks. This was the case for much of the second quarter, and we have established similar plans for the rest of the year. As always, please refer to our financial and operational supplement or follow up with Gary and his team with any questions or if you need any help related to our updated guidance. And with that, I will turn the call over to the operator for Q&A.

Thank you. As a reminder, to ask a question, you will need to press star 1 1 on your telephone. And we ask that you please limit yourself to one question and one follow-up. Please stand by while we compile the Q&A roster.

And our first question comes from the line of Doug Leggett with Bank of America.

Thanks. Good morning. Good morning, everyone. John, I wonder if I could hit the 800-pound gorilla in the room, which is in March you laid out a three-year plan, and a couple of quarters into it, we're $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 three-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, you know, 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, you know, 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 three-year period. And I will say we baked in a lot of inflation on the cost side, and we have not had the, you know, we've been able to manage that side really well. So, you know, I think in general, it would be early to do anything with the 23 and 24 years.

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

No, I would just say today, you know, we go through a process every year in the fall. You know, we're looking at the next three years. You know, we will review that. We'll come out with a new three-year look in February, but in general, You know, we still feel pretty good about the three-year plan we laid out. And, you know, we did pick up some properties in the U.S. The program's been running strong. And, you know, I think as you look out with the four rigs and 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 three-year plan. 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.

All right. On a different note, 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 Chenier contract as it relates to the free cash flow outlook. So I'm just wondering if you could touch on those two things, and I'll leave it there. Thanks.

Yeah. No, great question. You know, we did not, and I'll let Steve, you know, comment on the Chenier contract. After I make a few comments on the U.S. rigs, you know, we'll have four rigs. We've had four rigs run in the U.S. We'll maintain those four rigs. You're going to have all four of those in the Permian now, two in the southern Midland Basin. We'll have two in the Delaware. We've got a rig that we recently moved to Alpine High, you know, following up the results of our willow well. We're excited to drill some paths there, so I think it will be positive. So you'll see two rigs in that area. The nice thing is having those four rigs in the Permian now, we can move them around based on pads and timing and things, but we do envision one of those pretty much staying at alpine high for the near term. Steve, anything you want to comment on the Chenier contract, which is not in those three-year free cash flow and cash flow numbers?

Yeah, thanks, Doug. So, reminder, the Chenier contract is a 15-year term contract, 140 million cubic feet a day. Chenier 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 1st of 2023. And obviously, you know, the... 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 has Houston Ship Channel. But basically, the contract is structured as 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 Chenier's plant, and then we'll pay the costs 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 of 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 at 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 costs, would generate about $750 million of free cash flow in the six months of the second half of 23.

That's not in the free cash flow numbers in the three-year plan, Steve.

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

All right. Thanks so much for the quality. I appreciate it, guys.

Thank you, Doug.

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

Good morning, guys. Good morning, John.

Yeah, 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 the starting season, we've got more and more operators that have talked about how they're having to secure next year, this 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, etc., And I realize it's easier for some of the peers of yours that just have a, you know, single basin type portfolio versus y'all with a global diversified portfolio. But can you just sort of talk about, like, what y'all are able to do to try and secure some things ahead of time, given, you know, you obviously have a lot more kind of unknowns than many of your peers with, you know, the unknowns of what CERN will look like next year. You know, you've got the windfall profit tax and the North Sea. Just I guess sort of how y'all manage, you know, in this environment, trying to secure things and kind of lock things in as far in advance as you can, given kind of global portfolio y'all have.

Well, John, great question. You know, 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, you know, 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 three-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 those next two years when they put out that outlook in February. You know, 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.

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

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 that they're drilling the Dickop Prospect right now. That is an exploration well. Clearly, we've got the Jerry D'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 Crab Dago. And there are also some other exploration wells. So, you know, when you see the rigs move, you're going to see probably a combination of exploration and appraisal with the two rigs. But I'm not in a position today to tell you which rig is going where, you know, with both of them right now.

That's great. I appreciate the answers, John.

You bet. Thank you.

Thank you. And our next question comes from the line of Janine Y. with Barclays.

Hi. Good morning, everyone. Thanks for taking our questions.

Good morning.

Good morning, John. 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?

Yeah, Janine, obviously there's a lot of embedded questions in that. You know, 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, you know, 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. You know, that's why you have the revolver, frankly. And, you know, we used it again this quarter for the Delaware Basin acquisition. And so, you know, again, that's the point of having a revolver. You use it from time to time to take, you know, 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 10b51 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 Crab Dagu flow test, we were able to re-engage in open market repurchases, and you saw what we did in the month of July. And so, you know, we're going to We're somewhat constrained a bit from time to time with the 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, you know, 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. Thank you for all that color. 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 one 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 or in the first half of the year or anything like that, but any update here? Thank you.

No, Janine, I think we're on track. Today I would say we envision a hub that would really, you know, set up between Sapakara South, Crab Dagu, and that area, kind of a centralized hub. You know, we're still targeting predominantly a black oil, lower GOR development today. I do believe, you know, we have found a significant amount of gas in the block as well, and I think a longer term You know, 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.

Great. Thank you.

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

Good morning. Thanks. 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.

Bob, thanks. It's 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 a billion dollars. And so this is a nice ability to 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. And, Dave, anything you want to add?

Yeah, I think it's just some follow-on. You know, 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 two rigs finishing out a pad that will add a substantial number of ducks that will 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 Think about high-quality, low-risk opportunities. Again, you 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.

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 it showed up in April. And the nice thing about this is, you know, we've got a really high-quality rig. It's been performing well with a good crew.

Yeah, and again, we're not going to talk about the development pace here, but if you can think about conceptually putting one rig on this,

the next couple years this is free cash flow positive from day one and continues to generate free cash flow and i think that that's uh intriguing the idea that an efficient rig ready to go in the permeate is actually an asset my my follow-up would be if i think about the austin shock and i might have misheard you but it was a six well program for 2022 and the revised production guidance was based on the mixed results was four and a half thousand barrels a day. Can you talk about sort of what the pre-drill expectations were and some of the learnings on why you didn't hit that number?

Yeah, 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. And 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 – what we come up with probably sometime in 2023. Thanks.

Thank you.

And as a reminder, to ask a question, what we come up with probably sometime in 2023.

Thanks. Thank you. And as a reminder, to ask a question, you will need to press star 11 on your telephone. Our next question comes from the line of Neil Dingman with Truist.

Morning, all. Morning, all. My first question on EGIF, 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 in the area as well.

Yeah, great question. You know, first of all, our natural gas price is fixed, $2.65 an M per BTU. So, you know, gas price there is fixed. As you know, we make our money through the profit oil and the splits is the way the PSC is designed. So, you know, the other thing I would say is if you look at the overall market, you know, here we are increasing our rig count threefold. at a time when the the rig count in MENA has been growing at about a twenty percent clip and so you know we found ourselves in a pretty unusual situation where there's been high demand for a lot of our trained Egyptian you know, talent, national talent. And, you know, we're in the process at one 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, you know, for national talent in the area today. And good news is, is we're on it and, you know, addressing it. But, you know, what it's done is 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, you know, a lot of it's mainly just in the reactivation of the cold stack rigs. And it's something we've done before, but it's just taken a little bit longer. And, you know, we'll get it ironed out, and we're working collectively with, you know, the folks on the ground there, and something we'll sort out. You see it. in our supplement, you know, 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, you know, setback, but it's something we'll recover from. In terms of the well performance, it's 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've moved a rig or moving a rig there. Will that rig stay? And maybe if you could just comment on, you know, what you think the overall pace of activity might be, you know, later this year and into next year.

Yeah, for now, we see it there. We've got some pads lined out to drill with one 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 two, jump over and pick up a well or two in the Delaware. But for the most part, it's going to stay at Alpine High.

Thanks for the time, John. Thank you.

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

Hey, guys. Just wanted to ask a little bit about the U.S. growth trajectory. I think, you know, previously, I think you guys had expected the oil volumes to kind of start to grow, you know, by the fourth quarter on an organic basis. I realize you made an acquisition, but you clearly took some volumes out of the chalk. Just any updated thoughts when you resumed 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 can think of that probably as being about 3,000 barrels a day and about 30 million cubic feet of gas a day. 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, you know, I think we'll get back on track here pretty quickly.

Okay. That's helpful. And then just wanted to ask on Egypt real quick. So you mentioned this 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 have 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 had some wells that maybe declined a lot or something.

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

Okay. Thanks, guys. Thank you.

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

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

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

Thanks, team. I appreciate it. Two quick questions for me. First is in Suriname, there has been some talk of 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, particularly in light of firm natural gas prices, but also around the risk of windfall taxes? So thank you.

No, two really good questions. I'll address CERNOM first. You know, big picture, we feel really good about it, Neal. We're 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 CERNOM. And so, you know, Statsoli has 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, you know, I think we've got a very, very strong business there. You know, we've always characterized our assets as kind of two different plays in two totally different assets. 40s were obviously managing it into the later phases of its life and looking to manage that margin. As you see it wind down, we still see that happening early next decade. You see the profits levy there starts to impact timing of some of those things. In the prepared remarks, You know, 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, you know, with where it is. And then the other asset up there that we have, you know, still some great programs in and see some future development, is in the tertiary at Barrel. 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, you know, we see the North Sea playing a key role.

Yeah. Thank you.

I am now showing no further questions. So with that, I'll hand the call back over to CEO John Chrisman 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 one. 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.

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