APA Corporation (APA) — Q1 2023 Earnings Call Transcript

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 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, Executive Vice President of Exploration; and Clay Bretches, 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 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 will turn the call over to John.

Good morning, and thank you for joining us. On today's call, we will review our 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, which 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 at 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 the 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 semisubmersible in the North Sea. In the U.S., 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 planned 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 of approximately $100 million 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 1,200 barrels per day compared to the fourth quarter. New well connections, recompletion activity, and exploration success were all consistent with our expectations, and we are beginning to see positive contributions from 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 as scheduled platform maintenance and expected return to more normalized facility operating efficiency will be mostly offset by contributions 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 Krabdagu. 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 Krabdagu 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 1 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 field gas, which will reduce both cost and net emissions. In closing, APA has the portfolio and the operational flexibility to respond quickly to near-term commodity price volatility, and 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 Riney.

Thanks, John. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $242 million or $0.78 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 remeasurement of our deferred tax liability in the U.K. 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% 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 remained 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 towards 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 full-year capital budget has been reduced to $1.9 billion 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 Cheniere 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 purchased 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 Cheniere agreement, which will commence on August 1, 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 Cheniere 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 paydown of accrued liabilities from December 31, 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.

I believe the original plan was after the three-well pad gap brought on in Alpine High in the first quarter, there was going to be those kind of a break, and then there were going to be five additional wells that were going to come 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?

Yes, John. This is Dave Pursell. We may have initially planned more than five wells for the middle of the year. There are some adjustments in the Permian budget, but essentially, the $100 million reduction is primarily attributed to the costs associated with drilling, completing, and constructing facilities at Alpine, which totals around $100 million.

Perfect. I have a follow-up question. There were discussions about the Ocean Patriot's release next month possibly leading to increased activity, such as adding another rig in the Permian. Is that the plan? If you were to boost activity in your portfolio, would it likely be in the Permian? Additionally, what kind of commodity environment would you need to see to consider adding another rig there 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 drop some of the gas weighted drilling at Alpine. So two effects there.

Sorry, guys, can you hear me now?

Can be.

All right. Sorry about that. I'm sitting in an airport. I have my new boss in on. I apologize, John. 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 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 upfront and ask if you can walk us through what you're seeing currently and whether that working capital build is in fact reversible.

Yes, Doug. Let me start by discussing the working capital level and how the receivables from Egypt impact it. In my prepared remarks, I mentioned that we experienced around a $500 million increase in working capital in the first quarter, with $300 million of that resulting from a decrease in accrued compensation and benefits. As you can imagine, throughout the year, we accrue incentive compensation, both short-term and long-term, and this is a regular process we follow each year, with payments made in the first quarter of the next year. This year, the transition was slightly larger than usual due to performance metrics and share price fluctuations impacting long-term incentives. The remaining $100 million decrease came from general accounts payable related to operating expenses and capital expenditures, accounting for $400 million of the total $500 million increase in working capital. These variations are typical when moving from the fourth quarter of one year to the first quarter of the next. Additionally, there were several smaller items, mainly around $50 million, impacting working capital, including a $50 million increase in accounts receivable. In the interest of transparency regarding the situation in Egypt, I noted that accounts receivable there increased by $180 million. Our supplemental report shows a working capital increase for Egypt of $224 million, which factors in other elements like inventory. So the $180 million pertains specifically to Egypt. John, would you like to add any insights about the situation in Egypt?

On Egypt, just a couple of minutes here, Doug. One, we've been in the country for 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 has 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 aftereffects 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, 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 have a long track record here.

Yes, and Doug, I would like to add to John's comments. Receivables increased by $180 million in the first quarter, and it's clear that our receivables from Egypt are above historical averages. This is due in part to pricing and delays in payments. However, as John mentioned regarding our 30 years of history, we have faced this situation before. The current level of receivables from Egypt is not unusual. While it's never an ideal situation, it is not overly concerning at this time. Egypt's credit rating has remained stable since its upgrade in 2015. We monitor the situation very closely, and as John noted, we are engaged in active discussions about this issue at the highest levels of the country. Therefore, we feel confident about the situation.

Just to clarify, are you able to extract cash from the country regarding the balance in receivables? Or has this situation arisen mainly because it's currently the highest free cash flowing asset in your portfolio? Are you able to access cash out of the country right now?

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

Okay. My follow-up is, John, there are a few teasers in the deck about the status of Suriname moving toward potential hub development, and you mentioned you've got the results of at least the first appraisal well at Krabdagu. 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 regarding resource upside to the more than 800 that you identified in the deck today?

I want to mention that we're still seeing results from Krabdagu and are currently in the buildup phase. While I won't provide a pre-drill expectation, the well performed as anticipated. It's important to note that Krabdagu 2 is 4.9 kilometers from the discovery well, and Krabdagu 3 is 10.3 kilometers away. This illustrates the vast area we're dealing with. We're pleased with the early data and results from the appraisal well, but as we've done in the past, we need to gather more connected volumes, and we're not quite ready to share that information yet since we're still gathering pressure data.

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 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?

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

The capital program is performing as expected, with new wells and recompletes on track. We have experienced slightly lower base production due to several factors, including unplanned downtime at a gas plant that will impact condensate production and some ESP failures in our larger oil producers. These are temporary issues. We have also converted some producers to waterflood injection, which takes time before we see the benefits in oil production. Additionally, one of our mature fields has seen an increase in water cut, reducing its daily output from 3,000 barrels to around 1,000 barrels. Although this isn't a major producer, the loss of 2,000 barrels a day affected the second quarter and slightly impacted the first quarter as well. Given these circumstances, we felt it was prudent to guide conservatively for flat production, although the team expects to exceed that guidance. As we progress through the quarter, we anticipate that some of these temporary issues will resolve. It's also worth noting that due to the pace of new well drilling and the quality of those wells and recompletes, we remain confident in our ability to grow production in the latter half of the year. There are no changes to guidance for 2023.

John, could we discuss the timeline for the Krabdagu appraisal wells? I was under the impression that we would receive some appraisal results sooner than this. I'm curious if the wells are designed to be future producers, which might explain the longer drilling time. Can you provide insight on the timeline, whether it aligns with your expectations, and if these wells will be producers? Additionally, when do you anticipate sharing the connected volume investment?

Yes, Charles, I don't know where you got any ideas on timeline because it wouldn't have been from us, but just because Total is operating. I would say the Krabdagu 2 moved on 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 Krabdagu 3 well is running a little behind, but that also was a brand-new rig that was brought in the 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 is taking a little longer than anticipated.

Okay, returning to the U.S. onshore natural gas segment, I want to emphasize this point before moving on. I understand that it may appear easier to discuss from my perspective than it actually is for you. Considering your positive outlook on the long-term future of natural gas, could you share what price levels or timeframes at certain prices would lead you to increase your U.S. lean gas activity?

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. And so I think we want to see the infrastructure kind of get resolving it 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.

Yes. If I can remind everyone, we sell all the gas we produce in the Permian Basin in the Permian Basin. Therefore, we receive Waha or El Paso Permian prices for that gas. We have transportation obligations to the Gulf Coast, but we also buy gas and sell it there, allowing us to profit regardless of whether we produce any gas in the Permian. Everything should be assessed based on our sales at Waha, not at the Gulf Coast.

Right. But is there anything you're able to share about what Waha needs to achieve for a certain period before you decide to invest 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.

Can we return to the Permian? It appears that you plan to keep five rigs operational and will not drill additional wells in Alpine High. Should we expect that in the second half of the year, the number of wells you plan to bring online in the Permian will exceed your earlier estimates? Based on your fourth-quarter presentation, it looks like we could see around 22 wells in the third quarter and 10 wells in the fall. Is that assumption correct? Additionally, with 21 wells in the second quarter, we anticipated higher production than what has been reported. Is this related to the timing of when the wells come online?

Yes, 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 will be pretty similar because we're dropping 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...

Yes. 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. And I think when you look at the 21 wells in the second quarter, 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 will 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 then 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 gross production for that?

Yes. Paul, we had talked about 10% exit to exit on gross in Egypt, and the goal would be to, in the next couple of years, think about something in that range.

What is the biggest risk that could prevent you from achieving that this year?

For this year?

Yes. certainly the first quarter second quarter is definitely, I suppose that is below what you've been looking at. And so you need to step up. And some of the challenge seems it's 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?

Yes. I think we have strong visibility on the program, which includes new well drilling and recompletions. Both of these factors significantly influence our ability to increase production. Therefore, we remain confident in our capacity to achieve that growth rate.

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

We haven't shared that yet, Paul.

John, my first question is about capital discipline. I'm curious about how you approach managed capital. Is the focus primarily on generating cash flow in the current volatile market, or are you more concerned with avoiding the completion of wells that won't meet high return thresholds?

You're narrowing down the question a bit. It's really about capital discipline, and overall, we're feeling positive about our current position. Most of our capital costs are secured under contract, so the focus is on cost control and execution. We've made some adjustments, and you're seeing the results of those changes. This is part of the flexibility that our portfolio offers. Everything is on track, and we don't intend to drill wells that we wouldn't want to complete, which is why we've decided to limit drilling in the gas-weighted 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 something in some of your international areas.

I would just say it's early, right? Everything is still under contract. I think where you'd start to see that as we start looking at, 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.

Maybe, Steve, I want to ask you a little bit about the working capital build 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?

Yes, Arun. As I mentioned earlier, there was a $500 million increase in working capital. Of that, $300 million was due to the paydown of accrued compensation obligations from the 2022 calendar year, and $100 million was from the paydown of other accounts payable. Additionally, there were several minor items that contributed to the total of $500 million. I also noted that included in this amount was an increase of $180 million in accounts receivable from Egypt, which I believe will largely reverse throughout 2023. Every quarter, we accrue the incentive compensation that will be payable in the first quarter of the following year, so much of that will reaccrue as we progress through 2023.

Great. And for a follow-up, maybe for David. David, to reach the midpoint of the full-year oil guidance, the business would need to average oil production in the upper 160s for the second half of the year. It seems that your second-quarter guidance might be a bit conservative. Could you explain and assure us about achieving those production levels since the midpoint is 159 for oil?

Are we discussing the gross for Egypt?

No, just full-year oil or the component.

Yes, I believe we are confident in our ability to exit Egypt successfully. The U.S. is projected to grow, with 21 wells coming online in the second quarter and even more in the third quarter. Many of the wells brought online in the first quarter were 3 milers added towards the end of that quarter, so we are optimistic about U.S. execution. Regarding the North Sea, despite the EPL overshadowing it, our operating performance has been quite good this year. We've improved platform operating efficiency and successfully brought a strong well online at the end of the first quarter, with another well from the Ocean Patriot soon to follow. This well will have a higher gas mix, which is favorable in the North Sea at this time. Overall, we are very comfortable with our ability to achieve our portfolio growth targets.

Just a question here on Suriname. Obviously, you guys are still going through the appraisal process at Krabdagu, but perspective on oil there, if you look at it in the radio and what you've already done appraisal wise at Sapakara are kind of enough to move forward with the development of a nice pool of oil here?

Yes, you're cutting out for most of your questions. So I think it's about whether we have enough. The answer, as we've mentioned regarding Krabdagu, is that we're considering it as an oil hub that includes both Sapakara and Krabdagu. Our focus has been on the right scope and scale. At this point, I can say that the connected original in place we submitted in the documents this morning does not yet include the appraisal work from Krabdagu. However, we're making good progress.

Okay. That's helpful. And then just on the U.S. side, Alpine High, you got three wells. You kind of mentioned that you're pleased with the progress. I was hoping to maybe get little 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 Chalk for APA?

At this point, no update on the Chalk. 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.

Yes. I guess maybe follow up a little bit on some of the oilfield 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 the 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 cost with the devaluation that'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, kind of devaluation issues.

No, not big. Not big.

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 is the next time we should see any potential for an inflection up or down in terms of the next contract rollover as 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 some are multiyear. And so it's a constant process of rejigging those, and that'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 of this year's capital program. So it will really start to show up in the '24 next year.

I just wanted to follow up a little bit on 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 Cheniere 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 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 Cheniere 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 Krabdagu delineation and appraisal work in combination with we already know at Sapakara 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. 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 as there's an incentive for everybody to size upwardly. But we'll know when we get there.

There's been much discussion in 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?

In general, we don't have much competition for services in Egypt. It mainly aligns with the rise in commodity fuel prices, particularly for chemicals. In the North Sea, we are preparing to deploy the Ocean Patriot. While capital spending is decreasing there, it is not significant or surprising regarding the international service sector.

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 midyear at the start of the year.

John, as you started off in your remarks, there's a lot of uncertainty in the near 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 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 route.

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'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 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.

Yes. I'd just add that in the last two years, we've reduced debt by $3.2 billion while also buying back $2.4 billion worth of equity. The most significant achievement in this debt reduction is that in the near term, around 30% of our bond debt matures between now and 2030, with only about $350 million maturing in the next five years. So we don’t have much to worry about in terms of runway. Additionally, 70% of our debt matures in 2037 and beyond, giving us a strong profile for debt maturities. Lastly, regarding cost management, we've been very disciplined in managing our cost structure, which helps build resiliency.

Can you 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...

Yes. Perhaps you could assist us the next time we discuss with the rating agencies, and I appreciate that. We engage with the rating agencies at least twice a year. Currently, we hold an investment-grade rating from Fitch and are on a positive outlook for an upgrade to investment grade from S&P and Moody's. We have had recent discussions with them, and we'll see how it unfolds. As you hinted, I believe we are due for an upgrade, which we hope will occur in 2023. Additionally, we benchmark quite well compared to some of our peers who already have investment-grade ratings, so I think we're on track for that.

Maybe a few on the Permian ex-Alpine High. First one is just on what your outlook is for productivity out of your Midland and Delaware this year just relative to the last few 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, 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.

Yes, Jeffrey, those are good questions. This is Dave. Regarding the three mile question, we typically prefer to drill three mile wells when the land is suitable, as it's very cost-effective. We've executed these wells well in terms of both drilling and completion. Where feasible, we will continue this practice, but most of our portfolio consists of two-mile laterals. The standard well we drill is usually a two-mile lateral. Concerning productivity, our team is constantly working to enhance productivity on every site, and we've been seeing positive results. We have a solid and systematic approach to drilling and completions, and we are satisfied with our current pace.

Great, Dave. My next one is just on the sustainability of that productivity that you're seeing today, 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 how to think about steady state quarterly run rate activity as we 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.

Yes. So inventory, we've consistently said we've got line of sight kind of through the end of the decade. And we keep adding things to it. And that number will 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 kind of hold serve on productivity gains. But again, the aspiration is to continue to squeeze more out of each completion.

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 keenly focused on cost control. Second, we continue to make good progress on our appraisal program in Suriname 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.