APA Corporation (APA) — Q4 2021 Earnings Call Transcript

Good morning, and thank you for joining us on APA Corporation's Fourth Quarter 2021 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 2022 outlook. Also on the call and available to answer questions are Dave Pursell, Executive Vice President of Development; Tracey Henderson, Senior Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be approximately 25 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you've had the opportunity to review our fourth 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 difference 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's 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. At the beginning of each year, I'd like to look back and reflect on our progress and 2021 marked an important turning point for APA Corporation. While there is clearly much more to accomplish, I believe we made outstanding progress on six specific fronts last year. First, we demonstrated the robust cash flow capacity of our base business. We entered 2021 with a plan to generate around $350 million of free cash flow assuming $45 WTI. By being mostly unhedged and with the benefit of a $68 average WTI price tailwind, free cash flow exceeded our plan by nearly $1.5 billion and came in at $1.8 billion for the year. This represents the highest annual free cash flow in more than a decade and is one of the highest in the company's 67-year history. Keep in mind, these results do not include any free cash flow uplift that will come following the Egypt PSC modernization we completed in late December. The free cash flow capacity of our base business has significantly improved over the past few years. We have accomplished this improvement through multiple initiatives focused on portfolio enhancement, improved capital allocation and capital productivity, per barrel margin expansion and relentless overhead cost rationalization. Although we are getting some traction in the market, we believe our free cash flow capacity is still not fully appreciated. Second, we strengthened the company financially. By maintaining capital discipline and investing at a level slightly below our plan, we let the strengthening oil price flow directly through to the balance sheet reducing upstream net debt in 2021 by $1.2 billion. In one year, we accomplished what we thought would take multiple years and made great progress toward our goal of returning to investment-grade status. Third, we initiated a capital return framework for our shareholders. In the fourth quarter, on the back of a strengthening balance sheet we implemented a robust long-term framework for returning capital to shareholders. Reducing debt was and continues to be important. However, we reached a point in 2021 where it became appropriate for equity holders to participate more directly and materially in cash returns. We feel our 60% return framework is a good balance, providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening. Thus far, we have returned capital under the new framework, primarily through share repurchases as we bought back nearly 8.5% of outstanding shares during the fourth quarter. We felt this was appropriate given the sizable gap in the free cash flow yield at which our stock was trading relative to our peer group. We are committed to returning capital under the 60% framework for the long term and anticipate a progressively larger dividend component as we see improvement in our relative share price performance, further strengthening of our balance sheet and reduced oil and gas price volatility. Fourth, we refreshed the economic foundation for our business in Egypt. At the end of December, we finalized our agreement to modernize the terms of our production sharing contracts in Egypt. We have a long history with Egypt, and this agreement sets the foundation for many years of mutually beneficial partnership. The improved PSC terms return Egypt to the best long-term investment opportunity in our portfolio. In turn, this incentivizes increased capital spending and a return to long-term production growth. This is a tremendous outcome for both Egypt and APA. Fifth, we continue to streamline our Permian portfolio. In 2021, we sold $256 million of noncore assets in the Permian Basin, and we plan to close on the sale of an $805 million minerals rights package in the Delaware Basin within the next week. You should anticipate continued noncore Permian asset sales. And finally, we made good progress toward a potential FID in Suriname. In November, we announced a successful flow test and pressure build-up at our Sapakara South appraisal well. With further information and analysis, we are increasing our estimate of the connected resource in place in a single zone at Sapakara South-1 to more than 400 million barrels. We look forward to additional appraisal that should further increase the estimated resource in place at Sapakara South. We also announced a follow-on discovery at Krabdagu, which lies approximately 18 kilometers to the east of Sapakara South. We will initiate flow testing at Krabdagu in the coming days, and we'll share more details at the appropriate time. 2021 was also a transformational year for Altus. This week, we plan to close the previously announced merger with privately held EagleClaw Midstream, which will significantly scale the business and reduce APA's ownership to a minority interest. The combination creates the largest and best-in-class gathering, processing and transportation company in the Delaware Basin with capacity for product delivery to the Gulf Coast. The outlook for the new company is strong, and their plan is to maintain and ultimately grow the $6 per share dividend. For APA, this transaction enables deconsolidation of the midstream business and its associated debt. It also provides APA an opportunity for near-term liquidity of almost 1/3 of our 12.9 million Altus shares. 2021 was also a year of significant progress on our ESG initiatives and safety performance. We firmly believe that being proactive with respect to ESG is one of the most important strategic imperatives facing our industry. Our collective ability to meet much needed energy demand while also reducing emissions will determine our long-term success and viability. APA is committed to being part of the solution and part of the future, and we plan to demonstrate that commitment through a strong bias for near-term actions that will make a real difference. In 2021, we set an ambitious goal of eliminating routine flaring in the Permian Basin by year-end, which we accomplished three months ahead of schedule. APA is the first amongst its publicly traded peers in the Permian to end routine flaring, and we applaud the numerous companies that are now taking measures to do the same. APA also seeks continuous improvement in our safety performance and protocols. In 2021, we achieved a significant improvement in the three key safety indicators that impact the annual incentive compensation of every employee in the company. I am proud of our teams for delivering these results. The task now is to build on these successes in the future. In summary, 2021 was a year of outstanding progress for APA. The achievements I just highlighted along with several important ongoing initiatives will improve our operational and financial performance and sustainability for years to come. Turning now to the fourth quarter results. APA generated $1.3 billion of adjusted EBITDAX, making it our best quarter of the year. Upstream capital spending was $334 million for the quarter and $1.06 billion for the full year, both of which were below guidance. U.S. production exceeded guidance again in the fourth quarter as we continue to deliver good performance from our Permian oil plays and at Alpine High. Our focus was on increasing efficiencies through longer laterals, optimal well spacing and enhanced completion design. The success of these initiatives was recently recognized by JPMorgan analyst, Arun Jayaram, who named APA as a top performer in his analysis of 2021 Midland Basin Well Performance. As we noted in prior calls, U.S. well connections in the second half of 2021 were significantly lower than in the first half due to the timing of our DUC completion program. Accordingly, we placed only 13 wells online in the U.S. during the fourth quarter, 11 of which were in the Southern Midland Basin. The remaining two completions were in the East Texas Austin Chalk. In October, a dedicated rig arrived in the Austin Chalk and initiated a drilling program that is expected to run through 2022. Internationally, gross production was up in the fourth quarter. However, adjusted volumes were below guidance due to unplanned downtime in the North Sea during the month of December. On the cost side, LOE increased again in the fourth quarter and was higher than our guidance. We have begun to see the impacts of inflation, particularly in fuel, chemicals, labor and steel costs. These pressures are showing up in all areas of spend. In yesterday's earnings materials, we set forth some high-level guidance on APA's 3-year outlook which I would now like to provide a bit more color around. With the onset of the pandemic at the beginning of 2020 and the resulting oil price collapse, we cut capital investment to protect the balance sheet. As a result, our base production levels have been in decline for the last two years. With the stronger oil price environment and an improved financial situation, our overarching goal for the next few years is to return to pre-pandemic production levels and then invest at a pace that will sustain or modestly grow those production volumes. Our capital program for 2022 will be approximately $1.6 billion, a slight increase from our prior view. This includes some small changes to the timing of the rig count increases in Egypt and in the U.S. as well as an updated view of inflation. This amount also includes $200 million for exploration and appraisal activities, mostly in Suriname. In 2023 and 2024, capital increases a little further despite a mostly unchanged activity set as we expect continued inflationary pressures. Over the 3-year period, we're planning on an aggregate capital investment of around $5 billion. Based on this planned level of capital activity, we should exit 2024 at production levels similar to 2019 after adjusting 2019 for divestments. Most of the growth will come from Egypt, with some modest improvement in the U.S. and declining volumes in the North Sea. At current strip pricing, we expect to generate approximately $6.5 billion of free cash flow over the next three years. By any measure, this is a strong free cash flow yield relative to market cap or enterprise value, and it would be even stronger, if not for the heavily backwardated strip pricing. I would remind everyone that these numbers assume no production volumes from Suriname but do include continued capital investment for exploration and appraisal. If we FID any discoveries on Block 58 during the next three years, planned CapEx would increase modestly since 75% of our appraisal and development spend will be funded by our partner. Additionally, this outlook does take into account the pending Delaware Basin minerals package sale but assumes no further portfolio changes. Finally, our commitment to return capital to shareholders over the next three years will remain unchanged. We will return a minimum of 60% of our free cash flow to shareholders through dividends and share repurchases. Before turning the call over to Steve, I'd like to wrap up with a few remarks about our ESG goals and initiatives. We have established several rigorous goals for 2022 designed to move the ESG needle as quickly as possible. We remain focused on our key pillars of air, water and communities and people. Our short-term incentive compensation plan for 2022 includes three specific ESG-related goals. We will reduce upstream routine flaring in Egypt by 40%. We will initiate new programs to promote and deliver increased supplier diversity, and we will implement a new workplace ecosystem that recognizes the changing dynamics of technology and work schedules for our employees. We have also established rigorous new safety compliance protocols and metrics as we pursue continuous improvement in the health and well-being of our workforce and for the communities in which we operate. As we look to the longer term, we will invest a minimum of $100 million over the next three years in ESG initiatives, much of which will be focused on global emissions reductions programs. To underscore our commitment to these efforts, for the first time, we have added an emissions-related goal to our long-term incentive compensation plan. By the end of 2024, our goal is to deliver emissions-focused projects that eliminate at least one million tons of CO2 emissions per year. To provide added transparency, we plan to have these projects and their associated CO2 reductions externally verified. And with that, I will turn the call over to Steve Riney.

Thank you, John. So let me start with further details related to our fourth quarter results. As noted in our news release yesterday, under generally accepted accounting principles, APA Corporation reported fourth quarter 2021 consolidated net income of $382 million or $1.05 per diluted common share. These results include several items that are outside of APA's core earnings, the largest of which was associated with noncash impairments, primarily on Altus Midstream's interest in the EPIC Crude Pipeline. Net of tax and noncontrolling interest, this reduced APA earnings by $123 million. The partial reversal of prior tax valuation allowances and other tax adjustments had a $42 million benefit to earnings. Please see our detailed table of non-GAAP financial measures in our financial and operations supplement for a full reconciliation of adjusted earnings. Excluding these and other smaller items, adjusted net income for the fourth quarter was $468 million or $1.29 per diluted common share. Lease operating expenses in the quarter were above guidance as a result of increasing inflationary pressures and higher-than-expected emissions costs in the North Sea. In the U.K., the price of emission credits has nearly doubled since credit auctions were initiated in May of 2021. G&A expenses were also significantly above guidance, primarily due to the fourth quarter strength in our stock price and the resulting impact on noncash stock-related compensation expenses. Costs were also impacted by a higher-than-planned incremental incentive compensation accrual in the quarter. Due to these higher costs and lower oil, gas, and NGL prices in November and December, free cash flow for the quarter was $485 million below our guidance of $600 million, which we provided in early November. As John noted, the modernized production sharing contract in Egypt was ratified in late December. If you haven't already done so, please refer to the Egypt PSC Modernization Investor Presentation on our website for more details related to the updated terms and their anticipated impacts. The new agreement became effective on April 1, 2021. From that date to the end of 2021, the true-up of revenue sharing net of some small closing-related costs was a $245 million benefit to the APA, Sinopec joint venture. The agreement also included a signature bonus payable to EGPC of $100 million, half of the signature bonus was payable upon signing and was offset against outstanding receivables. The other half of the signature bonus is payable to EGPC over the next five years. Given the timing of the PSC signing late in December, our fourth quarter operational results include no impact from the PSC modernization. Turning to Altus Midstream, the business combination with EagleClaw Midstream is expected to close shortly. As a result, fourth quarter 2021 should be the final quarter for APA to consolidate Altus Midstream's balance sheet. This will eliminate the consolidation of approximately $1.4 billion of Altus' debt and redeemable preferred equity. Depending on how you model them, this could have a significant impact on APA's debt metrics and multiples related to enterprise value. Now I would like to turn to the outlook for 2022. We are planning for a capital program of around $1.6 billion with $1.4 billion in development capital and $200 million of exploration and appraisal, mostly in Suriname. This level of activity should deliver company-wide annual adjusted production similar to that of 2021. In Egypt, increased drilling activity in 2021 has already halted the decline in gross production volumes. With more drilling activity being added in 2022, gross production will turn to a growth trajectory through the year and into 2023. On an adjusted basis, you will see an immediate uplift in production in the first quarter given the revised terms of the modernized PSC. From that point, adjusted production should grow in line with gross production, excluding PSC-related impacts from changes in Brent oil price. In the North Sea, we anticipate a similar production level compared to 2021 as we will again have another lengthy turnaround season at Beryl. Additionally, the Ocean Patriot drilling rig is expected to be offline for approximately three months to repair damage incurred to its anchor system during a recent weather event. Production volumes in 2022 will be impacted by the reduced amount of rig activity. In the U.S., average production this year will be modestly below 2021 after adjusting for asset sales. However, we will exit 2022 in a position of sustaining to slightly growing U.S. production. There are three reasons for the decline compared to 2021. First, about 7,000 BOE per day of production is lost due to the Delaware minerals package sale that John mentioned earlier. Second, the DUC program largely completed in the first half of 2021 provided a significant production boost that will not be replicated in 2022. Finally, the underlying drilling program in the U.S. will only get to a maintenance level of activity around midyear after we have added the fourth drilling rig. On the cost side, inflationary pressures are real in our sector, and we are seeing that across many forms of cost. In particular, LOE is rising with everything from labor and trucking to fuels and chemicals under pressure. Our guidance for 2022 costs includes these impacts. That said, we see risks of further pressures on these and other costs as we look to 2022 and beyond, especially if the current price environment prevails. All of the details around our 2022 full-year and first-quarter guidance can be found in our quarterly supplement on our website. Our 2022 guidance around certain costs may be difficult to reconcile to 2021 actuals due to the impact of the Altus deconsolidation. Please reach out to Gary and his team for further support. From a free cash flow perspective, 2022 looks very robust. At current strip prices, we anticipate free cash flow well in excess of $2 billion. In addition to strong cash flow from operations, we also expect $805 million in cash proceeds from the Delaware Basin mineral rights sale, and we anticipate a sell-down of up to four million shares of our ownership in Altus Midstream during the three-month period following the closing of its combination with EagleClaw. All of that should provide a significant amount of available cash in the next few months. First priority for that cash will be to pay off the revolver. Beyond that, remaining available cash will be used in some combination to buy back shares, further reduce debt and to fund the dividend. I would note that in January we utilized the early call option feature on the $214 million of bonds that mature in April. So that debt effectively sits on the revolver today. Finally, I'd like to make a few remarks about steps taken on our new capital returns framework. In the fourth quarter, we returned well in excess of 100% of our free cash flow to shareholders, mostly through stock buybacks. We had to fund a portion of this on our revolver and had the confidence to do so given the robust price environment coupled with our expectation of significant near-term divestment proceeds. Obviously, we cannot repurchase shares this aggressively every quarter, but we feel it was a good decision at that time. While relative valuation for APA has improved, we continue to believe our stock is a good value on both a relative and absolute basis. We are committed to our capital returns framework, so the share buybacks will continue in 2022. And with that, I will turn the call over to the operator for Q&A.

John, could you provide an update on Suriname, particularly regarding Krabdagu? Last time we spoke at the conference in November, it seemed like Krabdagu was an important factor for decisions regarding the Board's size. The recent press release seemed somewhat neutral. Are there any concerns you have? Can you clarify if there are multiple sands involved or if there's a flow test that needs to be completed first? What do you see as the next steps?

Thank you for the question. Firstly, we have clearly indicated that Krabdagu was the next well we needed to drill. Although it was technically an exploration well, we had a strong confidence in it because we are beginning to understand what is effective and what we can visualize. Discovering 90 meters of light oil pay and high-quality rock, mainly through the Campanian, is an excellent result. We are very excited about it and are gaining confidence in our findings. The crucial next step is to conduct the flow test and the pressure build-ups, and the great thing is that we can proceed with that now, which we are eager to do. We just need some time to validate this and gather further information, and we will provide more detailed insights once we have confirmed our findings.

You still see Sapakara Keskesi Krabdagu as a combination development?

The positive aspect at Sapakara South is that the connected volume to the Sapakara South-1 well has increased, which is encouraging because, over time, fields tend to grow. More appraisal work is needed at Sapakara South, and while it could be connected given its proximity, it’s not a requirement. There are many options to consider. We need to conduct the flow test at Krabdagu and then re-evaluate our strategy. While we perform the flow test, we have flexibility regarding where to send the rig next. We could either appraise Krabdagu, focus on the second well at Sapakara South-1, or explore some promising prospects in the area. There are many possibilities to explore, and we just need time to gather additional data and continue our analysis.

Okay. My follow-up, hopefully a quick one, Steve. On the last call, you mentioned a strip pricing before the modernization of Egypt, forecasting more than $2 billion of free cash flow in 2022. I believe that was discussed during the third quarter call. You have provided the same figure today, which I think might be one reason your stock is underperforming. Can you explain why that number has not been revised upward? Also, what do you estimate is the duration of the free cash flow capacity of the portfolio today?

Yes, Doug. I would refer to a chart we included in our supplement that provides a clear view over the past three years, which should address your last question regarding the duration of cash flows and the expected production volume along with its cash flow under the February 7 strip, which is above our current position today, and in an $86 flat WTI price environment, reflecting the '22 strip from February 7. In my remarks, I noted that free cash flow is projected to be more than $2 billion, and from the chart, it appears closer to approximately $2.2 billion. I’m not certain about the strip price environment when I initially estimated it at $2 billion. We can revisit that. Additionally, we've divested the minerals package, which accounts for roughly $100 million of cash flow that will impact 2022's free cash flow. We are also using the February 7 strip, which is slightly below our actual position today. The comparison with the previous strip I referenced and the cost aspects we discussed, including what's happening with costs, are reflected in the guidance assumptions, indicating increases in LOE and G&A. Costs are rising, impacting our capital program as well. As mentioned in my comments, we have factored inflation into the capital program, making it somewhat higher than our discussions in November. Multiple factors contribute to this situation, some of which may involve a conservative approach, particularly regarding costs as we factored in a reasonable amount of inflation. We believe this is appropriate given the current price environment, but costs are fluctuating rapidly. We want to ensure we have an accurate perspective in our plan at this point and will continue to monitor this throughout the year.

Okay. I'll let someone ask about the use of proceeds.

The first question I have is related to Suriname, following up on Doug's inquiries. About the $200 million, which may not be directly from Suriname but is allocated for it, it seems that in your comments, John, you haven't finalized the exact distribution of the plan this year between appraisal and exploration. Is the $200 million more of a conservative estimate or placeholder until you have a clearer understanding of the balance between appraisal and exploration? This is important since the commitments can differ significantly between the two.

No, John, it's a great question. I think we've got some optionality and flexibility in there. And I think we've tried to just conservatively handle the $200 million out of covered both between Block 53 and 58, right? So I think it's a good estimate and there's very important to a well or two to swing either way.

Okay. Last year, you ended up significantly lower than the initial budget for Suriname. So that's my first question. My second question is regarding the mineral sales. Last quarter, you mentioned targeting $500 million in noncore U.S. sales for 2022, primarily from the Permian. Does the $805 million from the mineral divestiture mean that this is in addition to what you had previously planned? I believe you had also considered further deals in the Central Basin Platform. I just want to understand how to view the recent minerals deal, which generated proceeds that exceeded your earlier expectations for the entire year.

No. I would just say, John, we said we'd sell a minimum of $500 million. Clearly, we've met that through the sale. But as I said in my prepared remarks, there's still opportunity out there for some potential additional pruning if we choose to do so. But I mean, we view it as we've met that goal and we've exceeded that goal.

I want to follow up on Suriname as well. You said the discovery derisks some additional prospects. So is Krabdagu a different play type than the prior four discoveries? And thinking in particular, are you feeling like you're able to identify black oil versus higher GOR prospects at this point? Just looking for more color there.

Mike, it's a great question. And even with your background, I think you probably have some insights into what we're getting a handle with. But I think from the geophysical side and the geologic model side, it's derisking and becoming a lot more predictive, which gives us confidence. And it's the same play type. I mean we're in Maastrichtian and Campanian. We did not drill on down to the San Antonio in here. So this was really just the upper two targets. But I think it's just confidence in what we're being able to see and image and put into the models. So it's a positive from that perspective.

Very good. I wanted to see, Steve, you mentioned, I think, previously that you plan to retire another $337 million of long-term debt this year at par. I think you mentioned in your prepared remarks, but I missed it. There may be some plans to go beyond that. Anything you can talk about there?

Yes. The $337 million consists of the April 2022 bonds and the January 2023 bonds. The April 2022 bonds were called early in January of this year. As I mentioned earlier, $214 million of that debt is currently on the revolver. The rest, which are the January maturities, will be called in the fourth quarter of this year at par, as we typically exercise the three-month early call option. This means we will pay down at least those amounts of debt. Also, with the cash coming in during the first quarter, we plan to pay down the revolver, which had $542 million at the end of last year, plus the $214 million from the April maturities. There have been various transactions on the revolver during the quarter, but it will end the quarter at zero, which will be our priority for cash usage. Over the quarter, with the operating free cash flow and the sale of the royalty package, which we expect to finalize before the quarter ends, if we do not account for any sale of Altus shares, all that cash from operations and the royalty package sale will be used to pay off the revolver. We would still have around $500 million to $600 million left, which could be used for share buybacks or repurchasing other debt to further reduce liabilities. We’ll keep discussing our plans for any excess cash at each quarterly results rather than having unplanned discussions during conference calls.

I wanted to go back to the Sapakara South1. So obviously, that's a positive result from the flow test, 400 million barrels in place. But should what should we be thinking about in terms of recoverable there? And can you frame or refresh for us? I know this is maybe overly simplistic. But what do you need to get to in terms of total recoverable resources before you're within striking distance across the finish line on FID?

There are a couple of different questions, Charles, so I'll provide some insight, and then Dave Pursell can add to it. First, regarding Sapakara South, it's important to know that we have a continuous thick block of sand with one point four Darcy rock, which means we can expect very efficient reservoir performance and high recovery rates. Additionally, one important aspect of conducting a flow test is collecting data on the build-up and its characteristics. Most of the data from the build-up indicates that there is even more resource available than we initially mapped out in Sapakara South, which suggests further appraisal is warranted and it's a promising sign. Dave, please feel free to elaborate on the second part of the question.

Thank you, John. Charles, that's a great question. John is correct regarding the build-up test. We initially conducted it for a few days before shutting it in to perform a long-term build-up analysis. The extended shut-in period has allowed us to better assess recoverable volumes, leading us to raise the original estimate range of 325 to 375. As we continue to analyze the data from the extended shut-in, we're optimistic about the recovery factor, although it's still dependent on the development scheme we ultimately pursue. The 1.4 Darcy Rock is a world-class reservoir, characterized by its thickness and blocky nature. Any recovery factor estimates should focus on the high end because this rock is among the best available. We're confident and excited about the potential recoveries, but it's still too early to provide a specific number.

And Dave, any comment or just kind of a guidepost on what to think about as far as recoverable to meet the FID threshold?

It's a good question. I suspect other folks will try to ask that. We'll work with our partner to try to get to development, and there's a number of factors, including recoverable resource that factor into that. So I'll just leave it there.

Got it. Yes, I know it's a simple way to ask about a complex sum. But I have another question regarding the Delaware Basin mineral sale. Was that related to the original BP acquisition from the BP Permian acquisition, where those assets originated?

Some of it came from that, Charles. It's just a Delaware Basin package, and there's a few different pieces of it that came in there, but some of that was part of the old BP.

A two-parter. One is, I think in the verbal comments I heard light oil at Krabdagu versus not seeing that in the press release. Could you kind of confirm the quality of the oil?

Yes, Bob, it's a great question. It's early. We've got samples and they're on their way to the lab. But we can confirm it's light oil in all 90 meters of pay that we released.

Perfect. And the second one might be a bit pick and knits, but you've mentioned in the release and in your words a minute ago, the world-class reservoir quality sitting there at Sapakara South1. And I think the language in the release on the reservoir quality of Krabdagu was middle of the fairway. Anything there? Or is that just you're being vague until you actually get core sample and get some real measurements?

Yes, Bob, this is Dave Pursell. We want to see the flow test. I think before we flow tested Sapakara, we were probably using the same language. We want to see the data and whether it's the core data and/or the flow test. We're going to wait to see what the results are from those before we get out of the fairway on that.

Maybe our first question is just on cash returns, our favorite subject. In your prepared remarks, John or Steve, I think you mentioned a progressively larger dividend. And I think also your prior commentary on that was that your base dividend needs to be just meaningfully higher on a yield basis versus the S&P. So we're just wondering how you're thinking about where the base dividend can grow, whether it's a yield or some of your peers have, for example, a cap on the post-breakeven dividend or they have like a maximum percentage of CFO that the base dividend will be at some mid-single price?

Yes. Jeanine, and I can let Steve jump in here as well. But I think in general, just over the three-year period, we are laying out with the amount of free cash flow that we're going to generate, you could see us progressively increase that dividend. I think we're a believer in wanting as much in the base dividend. And today, by our actions you've seen, we've had a desire to buy back more shares because of where we trade on a free cash flow yield. But I think we're just laying a framework there that over time, we do anticipate we will be able to raise the dividend. Steve, anything you want to add?

Yes, I believe the best strategy for APA right now is to focus on buybacks using any excess cash flow due to the discount at which we are trading. That being said, it's important for our base dividend to be competitive not only with our peers but also with the broader market. We acknowledge this, and I think long-term, dividend yields in our sector need to increase from the current average of around 2%. To provide some perspective, if we applied our 60% capital returns framework entirely to dividends, our yield would exceed 10% today. However, we are not distributing all of that as dividends; the majority is allocated to buybacks. John previously mentioned factors that could lead us to raise the base dividend. The key aspect of improving the base dividend over time is ensuring that it is resilient. We have previously discussed the significant challenges we faced when we cut the dividend by 90% in early 2020 in anticipation of upcoming difficulties. When we decide to raise the dividend, we want to ensure its stability. The factors that could lead to a dividend increase include sustained improvement in our share price, a stronger balance sheet, and potentially a less volatile price environment than we have experienced in recent years. Any combination of those factors will provide the confidence needed to raise the dividend and ensure its resilience over time. Therefore, while we need to increase the dividend, we are committed to doing so gradually.

Okay. Great. Our second question is just maybe heading back to the three-year outlook, which we appreciate you all giving us. Can we maybe dig in a little bit more on some of the assumptions? For example, I think you clarified. Can you just clarify whether the plan is only valid at certain price outlook? We know you showed free cash flow estimates at the strip and higher. You also mentioned that inflation was built into the outlook. So maybe any commentary on what level of inflation you've assumed along with anything on U.S. cash taxes.

Jeanine, I think in general, we've set the activity levels and have confidence in those. We've been planning around those. And I think that's why there's a lot of confidence in this year's plan. In terms of inflation, we're seeing more right now probably in the U.S. than we are in the international market. But those would be the two factors. But I think we've got a lot of confidence in the plan. It's a relatively stable plan over the next three years, and we are going to be growing oil, I think, at about 5%, driven primarily by Egypt.

Yes. I want to provide a bit more detail on that. The capital program remains strong across a wide range of prices. If prices increase, the planned activities will stay the same, although costs could rise due to potential inflation in a higher price environment. However, the activity plan is also solid in a lower price environment. In fact, I believe it's effective even at $50 WTI because it's a sustaining capital program we intend to maintain. We can easily afford this while still generating free cash flow, even below $50 WTI. Therefore, we will continue with this capital program, which is reliable and won’t be significantly affected by fluctuations in price. Regarding taxes, we do not expect to be a U.S. cash taxpayer for a significant amount of time. If prices were to remain extremely high for several years, we could be. We have two main forms of tax loss carryforwards. One is grandfathered tax losses that can fully offset taxable income. The other consists of non-grandfathered tax losses due to recent tax changes, which can offset up to 80% of taxable income. We would utilize the grandfathered losses first, and once those are exhausted, using the non-grandfathered losses could result in paying taxes on 20% of taxable income, but this would likely take quite a while at the current price levels.

My first question is on the, John, really just on the ease of activity. You all have laid out nice plans to increase the rig count. It's about 15% by midyear this year given the high economics of the place. So I'm just wondering when you look on a go forward, what are the limiting factors on how much further you could push the activity of this play? Just wanted obviously given the great economics there.

No, Neal, you're spot on to kind of what the plan is. We're currently at 12 rigs today. I think we had the 13th rig next month, and then we'll be at 15 midyear. We think that's a good place. I think one of the keys with Egypt is while we were working the modernization, we've been building inventory and putting together a pretty robust drilling line. So we're excited about the program there. I just was over in Egypt, and I can tell you, Egypt is excited about it as well. And we've got a lot of work to do in terms of merging the concessions and the JVs while executing but we're off to a good start and a lot of momentum and a lot of anticipation. We're excited about it.

I'd say really look forward to activity there. And then secondly, just on domestic pressures, I notice you've continued to mention even on this call, the domestic OFS inflation along with some difficulty, maybe procuring pipe and other equipment. I'm just wondering do you see the same challenges on this. I'm just wondering how much long do you think this to go forward? Or do you anticipate this mitigating a bit in the coming quarters?

No. I mean I think the key with us is in the luxury we've had is we set our activity sets and we plan those. I mean we've been planning to add the fourth rig in the U.S. since last fall. And so I think we've got good line of sight on our services and activities. Supply chain is working several quarters out, and we find ourselves in a pretty good place. But I also say it takes time, right? I mean that fourth rig will come in midyear, and we couldn't have added it any sooner in the U.S. So it just takes a lot of rigor and a lot of planning and a lot of stability in the activity sets. And I think that's where we've landed everything in a place where we've got a lot of confidence around those. But let's not kid ourselves, there are pressures in the system. Truck drivers out in West Texas. Chemicals, fuel, there are pressures in the system and steel and everything else that's going up, especially on some of our longer-dated things.

Circling back on the balance sheet, I may have missed this, but is there a leverage target at some normalized crude price that you'll target over the medium-to-longer term, gross debt level that you'll target over the medium term post the Altus deconsolidation? How are you guys thinking about targets for the balance sheet from here?

Yes, we don't have a specific target in mind. Our goal is to return to investment grade. While this is important, it is not urgent to accomplish it immediately. However, it is essential to work towards it now. We do not have a specific target for long-term debt. Ultimately, the rating agencies will determine the level of long-term debt and the debt-to-EBITDA metrics necessary for us to attain investment grade. We aim to do whatever is needed to reach that goal. I believe it will likely require a debt-to-EBITDA ratio of one or below, particularly in the current price environment. We made substantial progress in 2021 and plan to continue in 2022. If we do not reduce any additional debt this year beyond our planned payments and the debt remaining on the revolver at the end of 2021, and if we allocate all remaining free cash flow for share buybacks, we would end the year with a debt-to-EBITDA ratio of 1.1 at the current strip. We are getting closer to the desired range, and we will see how the rating agencies evaluate that.

Got it. And then just a quick one on Alpine High. The 4 million share early sell-down option associated with Altus EagleClaw combo, I believe it came with the stipulation that you invest the first $75 million in new Alpine High development activities over the subsequent 18 months. Is that spend in the budget for '22? And can you talk about the plan for Alpine High at these commodity prices within the multiyear plan?

Yes, Scott, this is Dave Pursell. Yes, it's in the budget. We have the fourth rig in the U.S. that we're adding. Think of this as focusing on Delaware Basin rigs. It will drill in Alpine as well as at our DXL field, which connects to the Altus Midstream assets. It will be moving around the basin over the next couple of years, but it will conduct a significant amount of drilling specifically at Alpine.

Just curious that can you talk about that, the CapEx how that is going to spread throughout the quarters? Are they going to be pretty ratable or that one particular quarter is going to be heavier than usual?

I think there will be a gradual increase in the schedules as the Egypt rigs come online. By midyear, we expect to have 15 rigs operational, up from the current 12. We plan to add another rig in the Permian by midyear, which will mean the latter half of the year will be busier. The only current change is that the Ocean Patriot will undergo some repairs, as mentioned earlier. Other than that, we anticipate steady operations based on our program's design.

Yes. And the second question is that, I think previously, when you guys use complete PSC modernization, talking about this year will be a mid-teen type of growth in the oil production. If we're looking at 2023 and forward, with a 15-rig program, what kind of growth that you would be able to generate over there on the basis?

Egypt is going to drive the primary growth in the portfolio of oil over the next three years. And so I think we've outlined approximately 5% for Apache total to get us back to kind of the pre-COVID levels. And Egypt is going to be the driver. So that's probably going to put that more in the 10% range.

I'm just kind of curious on maybe following up that question from Paul. Like when I look at the chart on Page 9 of the outlook through 2024, you do have a nice step-up in oil '21, '22 and '23. But '23, '24 looks a little flatter with gas going up a lot more. Can you give us a sense of the dynamic around there because I know the Qasr field in Egypt is on probably a pretty good decline at this point? So like where does the gas pick up in '23 and '24 in your outlook?

Yes, Dave, can you provide some clarity?

Yes. I think if you look at the portfolio wide, the growth in Egypt is going to be really driven by oil. There will be obviously gas growth as well, but it will be oil. The gas growth in the portfolio will likely come from the Delaware Basin and Alpine.

Okay. So it's more of Alpine High, great. Okay. And then as my follow-up, turning to the Permian and ex-Alpine High. Can you give us a sense of where you think your depth of your core Tier 1 inventory is so when you think about your outlook over the 3 years and maybe a little beyond what kind of depth do you see there at a, say, 3 to 4-rig cadence.

Yes, we're well beyond the 3-year program. We get out towards the end of the decade easily.

Okay. And is that sort of Delaware or Midland? Or just kind of a combination of both?

It's a combination of both, Scott. Our SMB program has been the main driver, and that's where we see the core. However, we're adding an extra rig in the Delaware because we are confident that we have longer-term inventory there as well.

I wanted to ask a little bit on the North Sea here. I know that you clearly have been plagued with some unplanned downtime. And of course, you have turnarounds in that area. But as I'm just looking at the production, you guys were around 62,000 BOE per day in the fourth quarter of '20. It looks like it's down about 30% to the fourth quarter of '21. It sounds like a lot of that was maintenance downtime related. I just wanted to get a sense. You have a comment in here that you can get back close to 50,000 by the end of 2022. In terms of how you view that asset. Do you see that 50 is kind of being a little bit more stable in that outlook? Or do you see the 50 probably continuing to trend down? And is it just kind of always anticipation of that kind of 2-rig program in the North Sea?

It's a valid point. When we consider the North Sea, we have two different assets, Forties and Beryl. For Forties, we have the Ocean Patriot rig working on subsea tiebacks. This rig has been operational for a while, but we've experienced two breakdowns that have delayed our schedule. One issue involved the blowout preventer, and we also faced severe weather, which caused one of the anchors on the tie-down lines to break. We still need to send the rig to the shipyard for repairs. Running a single floating rig alongside these unusual events has pushed back the timeline for a key well like Garten 4, which was expected to be operational in the latter part of this year. We are confident that we can get back to producing 50,000 barrels, but looking at Forties, we're adjusting our operational strategy. Currently, we have one platform rig operating, and we are transitioning our focus, reducing capital investment in Forties. In the past, we conducted drilling campaigns, but that will no longer be the case. When we acquired this asset from BP in 2003, it was set to be abandoned in 2012, and now, ten years later, we anticipate it remaining operational for another decade. However, we will begin to plan for the eventual decline of Forties rather than continuing capital investments in Beryl and expanding subsea tiebacks.

Okay. That's very informative. I wanted to ask about Suriname. There was a time when we discussed a two-rig program on Block 58, but it appears that it has now shifted to just one rig. Has there been a change in the partnership's perspective regarding this asset? Do you think it might be better to proceed more cautiously, considering that it's still early in the appraisal program? If you continue to have success with the appraisal and reach a final investment decision, do you foresee the possibility of returning to a two-rig setup in your three-year plan?

Yes, I believe it's related to equipment and timing. A total of two rigs were brought in, and the developer was scheduled to leave, which they did. However, we still have the Valiant. If you follow their remarks, they are committed to drilling three more wells this year in Block 58, which suggests that more activity will be necessary to achieve that. We also have options on the Gerry de Souza rig coming to Block 53, providing us with additional choices. Therefore, we have some flexibility in how we proceed.

Thank you, operator. I'd like to close with the following comments. We've outlined a 3-year overview based on a heavily backwardated strip that delivers much stronger production and free cash flow than currently modeled by the Street. With $6.5 billion of projected free cash flow, we will return $4 billion to shareholders under our current framework that leaves $2.5 billion for debt reduction or additional shareholder returns through buybacks and/or dividend increases. Clearly, we will make material returns to shareholders, and we will continue to strengthen the balance sheet. Lastly, we are very pleased with how Suriname is progressing and look forward to the data that is coming from the flow test at Krabdagu. Operator, back to you.