APA Corporation

Good morning, and thank you for joining us.

Good day, and thank you for standing by.

Welcome to the APA 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 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. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Gary Clark, Vice President of Investor Relations.

Good morning, and thank you for joining us on APA Corporation's first quarter 2023 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO and President John Chrisman. 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, Executive Vice President of Exploration, and Clay Breches, Executive Vice President of Operations. Our prepared remarks will be approximately 12 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 first 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 will turn the call over to John.

Good morning, and thank you for joining us. On today's call, we will review your first quarter highlights, update our operational progress, and comment on our outlook for the remainder of the year. For the last several years, we have been navigating a volatile price environment and this has been amplified recently with the ups and downs of global oil prices, extreme moves in global LNG pricing, and the rapid decline in U.S. natural gas prices. Despite this volatility, we are constructive on long-term prices for oil, natural gas, and LNG. Based on this fundamental belief, we plan to invest over the long term for sustainable low single-digit production growth and attractive returns. That said, we cannot ignore price volatility and will therefore seek to moderate our investment plans during periods of significant price weakness. We must also be responsive to changing governmental tax and regulatory regimes within our countries of operations. Fortunately, our diversified portfolio provides us optionality and we maintain the flexibility to adjust our investment plans relatively quickly. In 2023, we have demonstrated this by reducing natural gas-directed activity and even curtailing production in response to extreme Waha price dislocations. We also made the decision to reduce spending in the North Sea as a recently enacted energy profits levy has resulted in less competitive return opportunities than in the U.S. and Egypt. So while you should generally expect us to invest at a steady pace for long-term returns and moderate growth, you will also see periods where we respond to external influences by adjusting or redirecting capital activity. Turning now to our first quarter results, which are characterized by strong operational performance and good cost control. APA met or exceeded production guidance in each of our three regions. Total adjusted production was 4,000 BOEs per day above the top end of our guidance range. Adjusted oil production also exceeded expectations, led by performance in the Permian and the North Sea. Capital investment during the period was slightly below guidance, and our average operating drilling rig count remained steady in the quarter, with 17 in Egypt, 5 in the Permian Basin, and 1 semi-submersible in the North Sea. In the US, we connected 17 new wells, and as planned, most of these went online in the back half of the quarter. While timing of well connections can drive production variances on a quarter-to-quarter basis, we are continuing to see significant benefits from the steady pace of our drilling program. As expected, first quarter oil production declined sequentially from the fourth quarter. However, we remain on track to deliver a significant uptick in the second and third quarters. Permian activity this year will be concentrated primarily on oil development in the Southern Midland Basin and oil-weighted development in the Delaware Basin. At Alpine High, we are currently testing a new three-well pad at a constrained rate. Beyond this, we are ramping down our plan 2023 lean gas drilling activity in the Permian due to the prevailing weakness in Waha natural gas prices. This will result in an upstream capital reduction approximately 100 million dollars but should have no material impact on our full year u.s production guidance we are pleased with the results at alpine high and will return when waha prices improve in egypt gross oil production increased by approximately 1200 barrels per day compared to the fourth quarter new well connections recompletion activity and exploration success were all consistent with our expectations we are beginning to see positive contribution our higher activity pace for the second quarter however we are forecasting that egypt gross volumes will be roughly unchanged as we have recently experienced some production disruptions most of which are temporary despite this our full year egypt production guidance has not changed turning now to the north sea our production exceeded expectations in the first quarter driven by strong facility operating efficiency We are projecting second quarter average daily production will be in line to slightly below the first quarter, and scheduled platform maintenance and expected return to more normalized facility operating efficiency will be mostly offset by contribution from a new well, which was placed online in late March. In Suriname, we continue to progress toward an oil hub development project with activity in the first half of 2023 focused on appraising Crab Dagoot. We have completed the flow test on the first appraisal well and are currently in the pressure buildup phase. Results of this well thus far are in line with expectations. The second Crab Daggy appraisal well is currently drilling and we will provide more information on next steps in the future. On the ESG front, we delivered another excellent quarter of safety performance and are making good progress toward our longer term emissions goal of implementing projects to eliminate one million tons of CO2 equivalent emissions by year-end 2024. We reduced routine upstream flaring in Egypt by 40% last year, which gave us an excellent start on this goal. In 2023, we plan to further reduce flaring in Egypt and focus on converting diesel combustion for power generation to fuel gas, which will reduce both costs and net emissions. In closing, APA has the portfolio and the operational flexibility to respond quickly to near-term commodity price volatility. We are managing our capital activity accordingly. We remain committed to returning a minimum of 60% of our free cash flow to shareholders this year via dividends and share repurchases. Longer term, despite many cross-currents, we believe the investment case for APA and the E&P industry is strong and the outlook for hydrocarbon prices and fundamentals is very constructive. And with that, I will turn the call over to Steve Reine.

Thanks, John. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $242 million, or 78 cents per diluted common share. As usual, these results include items that are outside of core earnings. The most significant of these items was a $174 million charge related to the re-measurement of our deferred tax liability in the UK, caused by the most recent increase in the energy profits levy. This was partially offset by the release of a valuation allowance on U.S. deferred tax assets. Excluding these and other smaller items, adjusted net income for the first quarter was $372 million, or $1.19 per diluted common share. Free cash flow as we define it, which excludes changes in working capital, was $272 million in the quarter. 81 percent of which we returned to shareholders through dividends and share repurchases. As John noted, it was a strong quarter for production, and costs were a good bit under plan. G&A expense was $65 million, significantly below both the prior quarter and the same quarter last year. This is a result of APA's lower stock price at quarter end and the mark-to-market impact on previously accrued share-based compensation. Excluding this mark-to-market impact, underlying quarterly G&A costs remain stable at roughly $100 million. LOE also came in a good bit below expectations, primarily due to the previously mentioned mark-to-market impact of stock-based compensation programs, as well as foreign currency impacts in Egypt. Switching to forward-looking guidance items, in the U.S., oil production growth is expected to return in the second quarter and should ramp further in the third quarter in conjunction with completion cadence. Our U.S. natural gas production outlook is more muted as we are responding to weak Waha pricing with lean gas drilling reductions. In addition, we could see further lean gas production curtailments, but to be clear, further curtailments are not contemplated in our U.S. production guidance. All of this is consistent with our bias toward managing for cash flow and long-term returns, not production growth. The $100 million reduced drilling activity John noted will occur mostly in the second half of this year. With that, our four-year capital budget has been reduced to $1.9 to $2 billion. Next, I would like to highlight our two material gas trading activities that are truly differential for APA. our gas transport obligations, and our Chenier gas supply contract. Our gas transport contracts provide significant cash flow benefits during periods of dislocated Permian gas prices. We hold just over 670 million cubic feet per day of Permian Basin takeaway capacity. We purchase third-party gas in Basin for resale on the Gulf Coast. realizing a trading margin whenever the price differentials are greater than the transport cost. In the first quarter, this activity generated a net profit of $23 million. Based on current strip prices, we have increased our full-year guidance for net profit from such activity to $100 million. The Chenier Agreement, which will commence on August 1st, is another important commercial trading activity. This arrangement provides upside exposure to world LNG margins over Houston Ship Channel on 140 million cubic feet of natural gas per day. For 2023, projected cash flow from this contract has come down a bit from our prior guidance due to the decline in European and Asian LNG prices. Over the past few months, we have provided potential outcomes of annualized free cash flows at different price levels related to this contract. You can find those in the appendix of our financial and operational supplement. At current strip prices, the Chenier contract will generate an expected $175 million of free cash flow for the last five months of 2023. All of our guidance for both the second quarter and updated full year 2023 can be found in our financial and operational supplement. One final item I'd draw your attention to. Looking at the balance sheet, you will notice that our revolver debt increased by a little over $400 million in the first quarter. This was driven by an approximate $500 million increase in working capital, primarily due to the pay down of accrued liabilities from December 31st. But it also includes increasing accounts receivable in Egypt. Overall, we had a very good quarter to start the year. We're benefiting from relatively stable activity levels within a portfolio that allows us to generate free cash flow and invest in the long-term sustainability of our business. 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 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster.

Our first question comes from John Friedman of Raymond James.

Good morning, guys.

Good morning, John.

I believe the original plan was after the three-well pad got brought on at Alpine High in the first quarter, there was going to be those kind of a break, and then there was going to be five additional wells that were going to come on at the end of the year. So is the $100 million reduction in the budget basically just coming from the removal of those five Alpine High wells, or is there more to it?

Yeah, John, this is Dave Purcell. We may have had more than five wells planned for the middle of the year, but there's some moving parts in the Permian budget, but the effect is, yeah, the net $100 million is essentially all the alpine drilling completion and facilities capital rounds up to $100.

Perfect. And then just my follow-up question, I know... some point there was some discussions about kind of following the release of the Ocean Patriot next month that if there was going to be some use of that kind of freed up copper, it might have been to add an additional rig in the Permian. I'm just, I guess, first of all, would that be the case if you were going to increase activity anywhere in the portfolio? Is that likely where it would go? And sort of what commodity environment would you likely need to see to potentially add another rig in the Permian at some point in the future.

Well, John, I mean, we did add some more weighted drilling in the Permian with that. That was contemplated. And then you're seeing us, you know, drop some of the gas weighted drilling at Alpine. So, you know, two effects there.

One moment as we go to our next question. Our next question comes from Doug Leggett of Bank of America.

Oh, hi. Sorry, guys. Can you hear me now?

Okay, I'm back.

All right, sorry about that. I'm sitting in an airport. I had my mute button on. I apologize, John. Guys, my first question is for Steve, actually. Steve, I wonder if you could just elaborate a little bit on your comments about the increase in receivables in Egypt. There's obviously, I think, some concern that events over there, the devaluation and so on, might have an impact on your ability to get cash out of the country. So I'm just going to hit that right up front and ask if you can walk us through what you're seeing currently and whether that working capital build is in fact reversible.

Yeah, let me just start at the working capital level and we'll work into the Egypt receivables impact on working capital. So I said in my prepared remarks that we've got about a $500 million increase in working capital in the first quarter. $300 million of that was a decrease in accrued compensation and benefits. So as you might imagine, through the year, we accrue primarily incentive compensation, both short term and long term. And we accrue that through the year. We do that every year. And then we pay it off in the first quarter of the following year. And so that's exactly what happened. We do that every year. It was a little bit larger going from the end 22 accrued liability to what was paid off in 2023 because of the performance, number one, but also because of the share price, because it does include the long-term incentive comp, which is share price-based, and because of the three years of programs and because the share price had improved over those years, that raised the cost of that. That's $300 million of the $500 million. There was another $100 million decrease in general accounts payable, stuff for operating expense and capital expenditures, things like that. And so that's $400 million out of the $500 million increase in working capital. And all of those things are very common as we go from fourth quarter of one year to the first quarter of the next. Now, there were a number of other small, mostly kind of $50 million in smaller items moving in and out of working capital. And that includes a $50 million increase in accounts receivable. And again, I provided this in my prepared remarks just to be completely transparent with folks because I know there's probably some amount of concern over what's going on in Egypt. So in the spirit of transparency, I indicated that Accounts receivable in Egypt had increased $180 million. If you look at our supplement, you'll see a working capital increase for Egypt of $224 million. That includes a number of other things like inventory and stuff like that. So $180 million in Egypt. And I know, John, you want to talk about the kind of situation in Egypt?

In Egypt, just a couple minutes here, Doug. One, we've been in the country for more than almost 30 years. And we've partnered with Egypt and EGPC and the highest levels of government the whole time. I'd say over that time period, Egypt's been through a number of challenges and successful reforms. The best thing that we can do to help Egypt and our stakeholders is to deliver oil production growth. And that's what we're doing while reducing our emissions. Egypt like many other places in the world today is going through a challenging economic time with inflation this does have some flow through to us but not anything that we haven't had to work through in the past and in fact there's been more difficult times in the past specifically they are dealing with the after-effects of a currency devaluation in January and we are currently helping our Egyptian national employees through this as we have also done in the past We maintain very deep and long-standing relationships with our Egyptian stakeholders, you know, both at EGPC and within the government at the highest levels, I'll say. And we are confident that they will work through this. And we are also having very constructive conversations on how to address the receivables over time currently. So we feel good and, you know, a long track record here.

Yeah. And, Doug, if I could just. going to add to John's comments there a bit. So it did go up $180 million in the first quarter. And I'd say that the receivables we have from Egypt are higher than historical averages, no doubt. Some of that is price, and some of it is the delay in payment. But I'd just comment that John talked about the 30 years of history. We've been in this position several times. This level of receivables from Egypt is not unprecedented. It's never a good time to have this happen, obviously. But I would say it's not overly concerning at this point. Egypt's credit rating has been pretty stable since it got upgraded in 2015. We watched the situation extremely closely. And as John said, we're in active conversations about this specific issue. And we're doing that at the very highest levels in the country. So we feel confident about this.

Just to be clear, guys, that balance you talked about in receivables, are you able to get cash out of the country or was that an accumulation of basically, because it's the highest free cash flowing asset in your portfolio currently. Are you able to get cash out of the country currently?

Yes, we are still able to get cash out of the country. That's not the problem.

Okay, thank you. My follow-up is, John, there's a few teasers in the deck about the status of Suriname moving towards potential hub development, I think was the expression, and you said you've got the results of at least the first appraisal well at Krabdagio. I wonder if I could ask a question like this. You said the result is in line with expectations, so what were the expectations? And what would you need to move forward by way of resource upside to the more than 800 that you identified in the deck today?

I would just say, Doug, we're still getting results from Crab Dagu 2. We're in the build-up phase. To put things in perspective, I'm not going to give you our pre-drill expectations, but the well was in line. But I will remind you that the Crab Dagu 2 is 4.9 kilometers from the discovery well. And Crab Dago 3 is 10.3 kilometers from the discovery well. So when you look at that map, sometimes you forget just how large of an area that is. And obviously, we're very pleased with the early data and the results we have from the appraisal well. But you know our history has been able to come back with connected volumes And we're not ready to do that yet because we're still collecting pressure data. Okay. Fair enough, guys.

Thanks so much for taking my questions.

Thank you. Please stand by for our next question. Our next question comes from Bob Brackett at Bernstein Research.

Good morning. I'll stick on the Egypt topic. One is just to refresh my memory that in Egypt, natural gas flows domestically sort of toward the Cairo Basin area, whereas oil tends to flow north, and you export it and capture those revenues. Am I remembering that correctly?

Yes.

Okay. The follow-up would be, you mentioned that to expect Egypt to be flattish, 2Q versus 1Q. You mentioned production disruptions, some of which are temporary. Am I being too much of a lawyer to suggest then that some of those are not temporary? And could you maybe give some color in terms of the cadence of getting oilier through the year? You've guided 60% oil for Q1 rising towards 64% for a full year average.

Bob, I'd say the first thing is we've got a very large asset base there that stretches really from Cairo almost to the Libyan border, and we've got a number of fields. I'll let Dave walk through some of the temporary things and then another minor issue.

Yeah, so, Counselor, when we think about this, the capital programs performing as expected, so new wells and recompletes, those are on track. We've had slightly lower base production. It's a series of things, and we'll highlight a couple of the big ones. We have unplanned downtime at a gas plant, which will impact condensate production. We've had some ESP failures on some of our larger oil producers. Those are the temporary issues. We've done some injection conversions, taking producers to water flood injection, and that takes some time to see the oil production benefit from those. And then one of our mature fields, our Kepri Deep field, experienced an increase in water cut late first quarter. And put that in perspective, it's a 3,000 barrel a day field that's now producing close to 1,000 barrels a day. So it's not a big producer, but on the margin, that loss of 2,000 barrels a day impacted second quarter. It actually had a slight impact on the first quarter as well. So when we look at the second quarter, we just felt like given those events it was probably appropriate to guide conservatively flat. I'll tell you, the team is expecting to beat that, so we'll see. But we want to guide conservatively, and we'll see as we go through the quarter some of the temporary issues we'll get back. I think it's important to highlight, given the pace of new well drills, the quality of those wells, the recompletes, we remain confident in our ability to grow production in the back half of the year. So no change to guidance for 23. Very clear.

Thank you.

Thank you. Please stand by for our next speaker. Our next question comes from Charles Mead at Johnson Rice.

Good morning, John, to you and the whole APA team there.

Good morning, Charles.

John, I wondered if we could talk a little bit about the timeline for these crab-to-goo appraisal results. Maybe I was off on the wrong track, but I thought we were going to get some of these appraisal results a little earlier, but I found myself wondering, maybe... maybe these wells, you've designed them to be eventual producers, and so they took longer to drill. So could you comment on, I guess, both of those things, what the timeline is and whether the current timeline fits with what you expected and whether these are going to be producers and when you think you'll be in a position to share that connected volume estimate?

Yeah, Charles, I don't know where you got any ideas on timeline because it wouldn't have been from us, but just because Total's operating. I would say the Crab Dagu 2 well moved along pretty much as expected. We're just in a period now where we're gaining data through the buildup, and so that is the most important information in terms of connected volumes. I will say the Crab Dagu 3 well is running a little behind, but that also was a brand-new rig that was brought into Basin. and so there's been some fits and starts on the drilling of the third well. So I wouldn't read too much into that other than it just has taken a little longer than anticipated.

Okay. Thank you for that detail. And then going back to U.S. Onshore in natural gas specifically, I want to commend you guys for turning the dial back on that. I know it maybe sometimes seems easier to do from – seats like mine than the actual reality of it for you guys. But if we, to your comments about being bullish on the longer-term outlook for natural gas, can you give us a sense of what kind of price or how long at a certain price you would need to see natural gas before you would want to turn the dial back up on U.S. lean gas activity?

You know, as we said in the prepared remarks, we're seeing good results on the program there. There's no reason to invest the capital today into this price environment. I think we want to see the infrastructure get resolved and get through this and feel like we're in a good place because we're making long-term investment decisions here. I'm very pleased with the results, but we want a clear pathway on a more constructive price environment for gas.

If I can just remind people also, John, we sell all of our gas produced in the Permian Basin in the Permian Basin. And so we're getting Waha or El Paso Permian prices for that gas. And we have our transport obligations to the Gulf Coast, but we buy gas and sell that on the Gulf Coast. We make that margin regardless of whether we produce a molecule of gas in the Permian or not. So everything has to be evaluated on the basis of We're selling this at Waha, not at the Gulf Coast.

Right, but nothing you're prepared to share about what Waha needs to be for some duration before you decide to put dollars back there?

Well, I think the simple thing would be to say that Waha has to be attractive enough to compete with more oil drilling right next door.

Thank you for that, Steve. Thank you, John.

Thank you.

Please apply for our next question.

Our next question comes from Paul Chang at Scotiabank.

Good morning. Thanks. Gentlemen, can we go back into Permian? It seems that you're going to maintain five rigs and you're not going to cure additional well in . Should we assume in the second half the number of well you're going to bring on in the permit is going to be higher than what you previously assumed? I think previously based on your fourth quarter presentation, it looked like we may be talking about 22 well in the third quarter and 10 well in the fall. Should we assume it's going to be higher? Also, then in the second quarter, with 21 wells, one we thought the production would be higher than what you show here. You said the timing of the well coming on stream is really in the late in the quarter. Thank you.

Yeah, Paul, I'll let Dave jump in, but it is timing. We said most of the wells came on late in the first quarter in the Permian, and then effectively your well counts are going to be pretty similar because we're dropping a you know, the gas-weighted drilling in the Permian and we're adding some oil weighting. So it shouldn't have a big impact on the numbers, I wouldn't believe. But Dave, I'll let you.

Yeah, in calendar year 23, it won't have a big number. The numbers we're looking at are a little bit higher than what you have, Paul, but not materially. I think when you look at the 21 wells in the second quarter, you know, they're big pads and those pads come online. The Delaware pad, for example, is 11 wells on our Titus acquisition, and so we'll be bringing that online. It'll come on at pace, but back-end weighted towards the end of the quarter, not the beginning.

Okay. And on the second question, the gross production for Egypt, can you just remind us that what is your full-year expectation now, and also over the next several years, what kind of budget And what kind of growth rate that you have in mind on the growth production for the field?

Yeah, but Paul, we had talked about 10% exit to exit on growth in Egypt. And the goal would be to, in the next couple of years, think about something in that range.

And what's the biggest risk that you will not be able to achieve that for this year?

For this year?

Yeah. Because certainly the first quarter and second quarter is definitely, I suppose, what you've been looking at. And so you need to step up. And some of the challenges seem to be going to totally go away. So, I mean, how big is the cushion when you're talking about a 10% year-over-year exit rate?

Yeah, I think for us, Paul, we have pretty good visibility on, we have really good visibility on the program, and that program consists of new well drilling as well as recompletions, and both those have a significant impact on the ability to grow production. So we have, again, we still have confidence in our ability to hit that growth rate.

And do you have a budget that you can share for the next several years related to Egypt to achieve your plan?

We haven't shared that yet, Paul.

Okay. All right. We do. Thank you.

Thank you. Please stand by for our next question.

Our next question comes from Neil Payton at Truist Securities.

Hi, Mornell. Thanks for the time. John, my first question is on capital discipline specifically. I'm really just in broad strokes wondering how you all think about managing options. Is this more to ensure you're generating sort of a cash flow and a bottle of tape like we're in? Or do you think more about maybe like insurance? that you're not completing any wells that don't meet a high return threshold?

You're cutting out a little bit on the question, so I think it's about capital discipline. I'd say I think in general we feel good about where we are. Most of our capital costs are under contract, so it's about cost control and execution. We've made some choices to move some things around, and you're seeing the impacts of those. And that's some of the flexibility of the portfolio. But, you know, everything's within line. And really, we don't plan to drill wells that we wouldn't want to complete. And that's why you see us, you know, kind of curtailing the drilling, you know, in the gas-weighted, you know, programs in the U.S.

Great details. And then my second, just on OFS inflation, we've heard a number of people talk about domestic softness. Just wondering if you've seen the same thing, some of your international areas.

I would just say it's early, right? Everything's still under contract. I think where you'd start to see that as we start looking at, you know, thinking about the 24 pricing and so forth, as you start pricing that in towards the middle of the year into next year. But right now, as you know, the cost structure always lags. And so we haven't seen any real direct softness today. Thank you.

Thank you. please stand by for our next question.

Our next question comes from Arun Jaram at JPMorgan Securities.

Yeah, good morning. Maybe, Steve, I want to ask you a little bit about the working capital bill in the quarter in Egypt in the U.S., and just thoughts on the drivers of that, and would you expect that to reverse in 2Q over the balance of the year?

Yeah, Arun. Yeah, as I indicated earlier, there was a $500 million working capital increase. 300 of that was because of a pay down of accrued compensation obligations that were accrued through the 2022 calendar year. And 100 of that was due to the pay down of other payables, other accounts payable. And then there were a bunch of other small items, ups and downs, that amounted to the full $500 million. And I did indicate that buried within that was the $180 million increase in Egypt accounts receivable. I think that, you know, most of that is going to reverse during 2023 as, you know, every quarter we accrue the incentive compensation that will be payable in the first quarter of the following year. So a lot of that's just going to re-accrue as we go through calendar year 2023.

Great. And just my follow-up maybe for David. You know, David, in order to hit, call it the midpoint of the full-year oil guide, you know, the business would have to average, you know, oil production in the upper 160s for the back half of the year. It sounds like your 2Q guy is a little conservative, but maybe if you could help us walk through and give us comfort on hitting those levels because the midpoint is 159 for oil.

We're talking Egypt grows?

No, just four-year oil for the company.

Yeah, so I think there's a – without getting into the granularity of each – of each asset. We feel confident in the ability to hit the Egypt exit to exit. The U.S. is going to grow. We have 21 wells coming online in the second quarter. We have more than that in the third quarter. A fair number of the wells that were brought online in the first quarter were three milers that were brought on towards the end of the quarter. So we feel good about the U.S. ability to And then on the North Sea, which is kind of because of the EPL, everyone's kind of forgot about that, but we're actually having pretty good operating success so far this year in the North Sea, both with platform operating efficiency, but we also brought on a really nice well at the end of the first quarter, and we have another well to store. It's the last subsea well that the Ocean Patriot drilled recently. It'll be online here relatively quickly. That's going to be a little bit higher gas mix, which in the North Sea is not a bad thing right now. So we feel really comfortable with our ability to hit the portfolio growth targets. Great. Thanks a lot.

Thank you.

Please stand by for our next question. Our next question comes from Leo Mariani at Ross MKM.

Hi, guys. Just a question here on Suriname.

Obviously, you guys are still going through the appraisal process at Crab to Goo, but in perspective, if you look at it in

say Crab Degout and what you've already done appraisal-wise at Safakara are kind of enough to move forward with the development of a nice pool of oil here?

You're cutting out for most of your questions. I think it's do we have enough? I think the answer is we've said all along with Crab Degout, we're looking at an oil hub which incorporates both Safakara and Crab Degout And the thing we've been focused on is trying to get scope and scale right. So at this point, that's all I'll say. The connected original in place we put in the documents this morning does not include the appraisal work from Crabdago yet. So we're making good progress.

Okay, that's helpful. And then just on the U.S. side, alpine high, you've got three wells. You kind of mentioned that you're pleased with the progress. I was hoping to maybe get a little bit more color on those three wells in terms of maybe how long you've been flow testing. And then I guess, is there any update on the Austin shock for APA?

At this point, no update on the shock. And on the alpine wells, we're flowing them back at constrained rates. but we're very pleased with the deliverability and the early results.

Okay. Thank you.

Thank you. Please stand by for our next question.

Our next question comes from Roger Reed at Wells Fargo Securities.

Thank you. Good morning. I guess maybe follow up a little bit on some of the oil field inflation deflation issues and broaden it beyond the U.S. to take a look at what the currency issues might portend for the cost structure in Egypt, or does that not matter given the overall structure of the contract there in terms of a net barrel performance?

Well, number one, there's not a lot of competition for rigs or services in Egypt, right? So We've seen pretty stable costs. With the devaluation, it's actually helped cost structure now. But as I said earlier, we are assisting our nationals and doing some things to help with the inflation.

So you wouldn't expect a net reduction given, like you said, devaluation issues. And then in the U.S., Okay, and then in the U.S., you mentioned, obviously, contract structure in place, but I was just curious, are you looking at indexed contracts? When's the next time, you know, we should see any potential for an inflection up or down in terms of the next contract rollovers, if we think about the rigs and the services?

We kind of keep a portfolio where some are on long-term, some are on short, and, you know, some are, you know, multi-year, and so... It's a constant process of rejigging those, and it's kind of underway now and will continue, but it's not going to have a near-term material impact on our current cost structure or this year's capital program.

Okay.

So it will really start to show up in the $24 next year.

Appreciate it.

Thank you. Please stand by for our next questions. Our next question comes from David Deckelbaum at TD Cowen.

Thanks for taking my questions, John, Steve, and Genk. You bet. I just wanted to follow up a little bit on just Alpine High. The decision, obviously, to reduce activity there makes sense in light of commodity pricing, but as we think about fulfilling contracts like the Chenier contract and others, Are you content to just fill with third-party gas, or is there a certain level of organic gas that you'd like to maintain out of Alpine High as you get into 24?

No, for quite some time. Our practice is that every molecule of gas we produce in the Permian Basin is sold in the Permian Basin, and our trading organization will take care of both the long-haul transport obligations through purchasing and selling gas, and we'll also take care of the Chenier contract with purchased gas.

Got it. And then maybe if I could just wrap up on Suriname. I guess as we think about moving towards an investment decision, do you anticipate that we'll have enough data points just given some of the Crab-to-Goo delineation and appraisal work? in combination with what we already know at Sapecara to reach a decision this year? Is that in line with your internal thinking?

I would just say we're waiting to see results, right? I mean, we're making good progress. You know, as I've said a number of times, we're kind of focused on potential scope and scale of what that first project would look like. There's incentive for everybody to size upwardly, but We'll know when we get there.

Thanks, John. Best of luck.

Thank you.

Please stand by for our next question. Our next question comes from Kevin McCurdy at Pickering Energy Partners.

Hey, good morning. There's been... Much discussion this earnings season about potential deflation on shale well costs, but I'm curious what you're seeing on the international side. Outside of the increased receivables, what is your view on raw materials and services in Egypt and the North Sea, and how is that trending relative to last year?

Well, in general, like I said a few minutes ago, we don't have a lot of competition for services in Egypt, so it really kind of goes with the commodity, you know, fuels up. for the most part, chemicals. In the North Sea, we're going to be dropping the Ocean Patriot. So, if anything, capital spending is dropping there. But, you know, nothing major, nothing surprising in the way of, you know, the international service side.

Great. And congratulations on reducing your 2023 CapEx budget. Kind of going back to the Ocean Patriot rig, Are the savings from dropping that rig already built into your updated budget you released yesterday? Or have those savings effectively been redirected to the Permian?

They were in the plan from early on because we plan to drop that rig mid-year at the start of the year.

Got it. So it's in your budget. Thank you.

Thank you. Please stand by for our next question. Our next question comes from Neil Mehta at Goldman Sachs & Co.

Thank you. Good morning, John, team. John, as you started off in your remarks, there's a lot of uncertainty in your term as it relates to the commodity price and the global economy. And so I'd love your perspective on how you as an organization are building downside resilience if there is a harder landing. And what are the lessons learned from your experiences in 2015 and 2020 that you can carry forward? And one of the things that I think you guys have made terrific progress on since COVID has been really cleaning up the balance sheet and taking out $3 billion worth of debt. So maybe you could speak to where you are in that scenario.

Well, I'll say a few comments, and I'll let Steve jump in on the balance sheet. But I'd say first and foremost, the best flexibility you have is being able to reduce your activity. And, you know, you've seen us do that with the lean gas drilling in the U.S. You've seen us do that in the North Sea. So when it's time to stop investing, you need to stop investing. And, you know, those are the lessons we've learned. Stay focused on cost. and maintain that flexibility to invest in the projects that are going to continue to generate the long-term returns.

Yeah, I'd just add that in the last two plus a quarter years, we've reduced fund debt by $3.2 billion, while also paying back $2.4 billion worth of equity. The biggest thing I think we accomplished in the bond reduction, the debt reduction, was in the near term, managing the near-term maturities. We've got only 30% of our bond debt that matures here in the next, well, between now and 2030. And only around $350 million of that matures in the next five years. So we don't have much of a runway to worry about. And then 70% of our debt is 2037 and beyond. We've got a really good profile for debt maturities as well. And then the last thing I would add is cost management. You know, John talked about the ability to reduce the capital budget, but we've been very disciplined on managing our cost structure as well. Keeping that low helps certainly build resiliency.

And remind us where you are in terms of getting to investment grade with all the agencies. And given what you've done with the balance sheet, I feel like you're getting close. So any perspective on that?

Yeah, maybe you could come and help us next time we go talk to the rating agencies. But we'd appreciate that. But we feel like, well, we talk to the rating agencies at least twice a year. We are investment grade with Fitch now, and we're on positive outlook for an increase to investment grade with S&P and Moody's. We have talked to them recently. We'll see what happens. You know, I think we, as you kind of alluded to there, I think we are due for an upgrade. Hopefully that comes in 2023. And I think we trade, I mean, we benchmark very well compared to some of our peers that are already investment grade. So I think we are due for that.

Yeah, it makes a lot of sense. Thanks, guys. Thank you.

Thank you.

Please stand by for our next question. Our next question comes from Jeffrey Lambougeon.

Good morning, everyone, and thanks for taking my questions. Maybe a few on the Permian exalpine high. My first one is just on what your outlook is for productivity out of your Midland and Delaware this year, just relative to the last two years and relative to internal expectations for what's left on inventory. And then what aspects of the program operationally you're spending the most time on today from a design perspective? I think you noted the three milers earlier, so I'd be curious on how you think about the mix of those in the program over time and how much inventory that might apply to. And again, if you're thinking about any other areas we're spending time on.

Yeah, so Jeffrey, good questions. This is Dave. On the three miler question first, we tend to like to drill three milers where the acreage is set up for that. It's very capital efficient. We've been able to execute those really well, both on the drilling and the completion. So where it's possible, we'll do that. But I think you should think about the majority of our portfolio are two mile laterals. So the typical well is going to be a two miler. you know, on productivity, we continue to, the teams work and study and try to squeeze out productivity gains, you know, on every pad we get on. And we continue to have pretty good results with that. So, you know, we're, you know, I don't know how you think about that externally. If, you know, we've got some a pretty good process in place and feel comfortable with it. We've got a good methodical pace of drilling in completions and are pleased with that pace at this point.

Great, Dave. Appreciate that detail. My next one is just on the sustainability of that productivity that you're seeing today. If you could frame inventory depth as you look at the Midland and Delaware individually, if we just kind of assume maybe the current pace for starters on an annual basis. And then I'd also be interested in, you know, how to think about steady state, quarterly run rate activity as you think about next year, just given the shape of the program this year that was referenced earlier in the Q&A with that dynamic of Q3 completion count in the low 20s and Q4 going into the low teens or a little bit lower exiting the year.

Yeah, so inventory, we've consistently said we've got line of sight, you know, kind of through the end of the decade. And, you know, we keep adding things to it, and, you know, that number – we'll move around over time. At the current cadence, I think you could look at the second and third quarter activity pace and roll that through into 24, but we haven't really given guidance yet on 24 on what the capital program and activity would look like. We're assuming that we've we kind of hold serve on productivity gains. But again, the aspiration is to continue to squeeze more out of each completion.

Great. Appreciate it.

Thank you. I would now like to turn it back to John Chrisman for closing remarks.

Thank you. Before closing the call, I want to leave you with the following thoughts. First, Our asset teams are executing well, safety performance continues to be good, and contributions from our drilling programs are strong. We are managing the portfolio to optimize returns and near-term cash flow and are keenly focused on cost control. Second, we continue to make good progress on our appraisal program in CERNOM and look forward to sharing more information in the future. Lastly, we remain committed to returning at least 60% of annual free cash flow to investors through dividends and buybacks and believe our stock is a compelling investment. We plan to participate in a number of investor events over the next two months and look forward to seeing you. Thank you.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.