Good day, and thank you for being here. Welcome to the APA Corporation First Quarter 2022 Earnings Conference Call. I would now like to turn the call over to Gary Clark, Vice President of Investor Relations. Please go ahead, sir.

Good morning, and thank you for joining us on APA Corporation's First Quarter 2022 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO and President, John Christmann; Steve Riney, Executive Vice President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Dave Pursell, Executive Vice President of Development, Tracey Henderson, Senior Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be around 20 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you've 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'll turn the call over to John.

Good morning, and thank you for joining us. The first quarter brought a strengthening in both oil and gas prices to levels unseen since 2014. This quickly shifted the prevailing energy narrative to questions about spare capacity, energy security, and whether producers could realistically deliver more reliable and affordable oil and natural gas. These are all very good questions and hopefully represent a more thoughtful outlook for our energy dialogue. At APA, we significantly increased our capital activity coming out of 2021, and we will remain squarely focused on executing on our 3-year plan, generating strong free cash flow, delivering on our shareholder return framework, and continuing to deleverage our balance sheet. Since the beginning of 2021, we have made tremendous progress with debt reduction, which enabled the initiation of our capital return framework. In that time frame, we have reduced our outstanding bond debt by $3 billion, repurchased $1.1 billion of APA stock or roughly 10% of shares outstanding, and increased annualized dividend to $0.50 per share. At current strip prices, we expect to generate approximately $2.9 billion of free cash flow in 2022. Based on our capital return framework, this would imply a minimum of $1.8 billion of return to shareholders. Thus, if commodity prices sustain at these levels, you should expect an acceleration in the pace of share buybacks through the rest of the year. With regard to our operational strategy and 3-year capital activity plan, we anticipate no material changes at this time. In Egypt, we have been increasing our rig count over the past year, investing in shorter cycle projects designed to deliver 8% to 10% compounded gross oil production growth over the next 3 years. In the U.S., a fourth rig, which was contracted in September, recently arrived and has begun operations. This should help return U.S. oil production to a modest rate of growth as planned. Given the substantial supply chain bottlenecks and scarcity of oil service equipment and field personnel, any attempt to increase activity in the U.S. would be logistically challenging and capital inefficient. In the North Sea, our plan calls for a stable drilling program with 1 floater and 1 platform rig, which should be capable of broadly sustaining production over the next 3 years. And lastly, we continue to explore and appraise our 2 large blocks offshore Suriname, which we believe have the potential to deliver a significant new source of lower carbon intensity oil production. Of equal importance to this investment activity is continuing to reduce emissions throughout our global operations and improving the health and welfare of our employees and the people in the communities where we operate. Turning now to some details of the first quarter. Our results continue to demonstrate the power of our unhedged diversified global upstream oil and gas portfolio. Some of the key highlights for the quarter include: free cash flow generation of $675 million, up 39% compared with $485 million in the preceding quarter. In addition to strong operational cash flows, we realized approximately $1 billion in proceeds from the sale of selected minerals acreage in the Delaware Basin and the monetization of a portion of our shares in Kinetic. We continue to return cash to shareholders through the dividend and ongoing share buybacks. During the first quarter, we repurchased $261 million of APA shares. Since initiating the buyback last October, we have repurchased more than 10% of the company's shares through the end of March at an average price of $29. We believe our stock is a compelling value and remain committed to this program as an important part of our returns framework. We also took another significant step forward in strengthening the balance sheet with $1.3 billion of bond debt reductions during the quarter. In terms of operational highlights, we exceeded our oil production target in the Permian Basin and continue to deliver significant productivity improvements in both the Delaware and Southern Midland Basins. We also announced an exploration discovery at Krabdagu on Block 58 in Suriname. Upstream capital investment in the quarter was approximately $360 million or $30 million below guidance, which was mostly driven by the delay of some activity into the second quarter. Despite the lower first quarter spend, we are increasing full year capital investment guidance by about 8% to $1.725 billion. Approximately half of this increase is associated with Suriname as we now plan to keep the Noble Jerry Desouza drillship in country following conclusion of operations at the Rasperwell in Block 53. Non-operated spending as well as some changes in our U.S. activity mix account for most of the remaining capital increase. Total adjusted production in the first quarter was 322,000 BOE per day, which was down about 3% from the fourth quarter and in line with expectations. Total U.S. volumes decreased 7% from the fourth quarter, driven primarily by well completion timing in the Delaware Basin minerals divestiture in early March. U.S. oil production was nearly 70,000 barrels per day and continues to exceed expectations with Permian Basin wells demonstrating excellent performance. This offset some softness in natural gas and NGL production caused by weather events and unplanned third-party downtime. We have been consistent in noting that U.S. production will bottom in the second quarter as an increase in the number of wells placed on production in the second half of the year and incremental activity from a fourth rig should drive volumes higher. That fourth rig is now running in the Delaware Basin, where it is drilling out a previously unfinished 6-well pad at DXL in Reeves County. Following this, the rig will mobilize to Alpine High to resume gas and NGL development drilling in the summer. Outside the Permian Basin, 1 rig is currently delineating the Austin Chalk in Brazos County, where we are in the early stages of flowback on the first 3-well pad. Moving to international. First quarter adjusted volumes increased 8% compared to the fourth quarter driven by the positive impacts of our recently modernized PSC terms in Egypt. Adjusted production in Egypt was just over 68,000 BOEs per day consisting of 57% oil. We deferred a number of high rate uphole recompletions from the first quarter into the second quarter as the producing zones in these targeted wells were still delivering at economic rates. As a result, first quarter Egypt oil production was a bit below expectations. However, we are now seeing a significant uptick as this recompletion work is performed. We are in the process of adding our 13th rig in the Western Desert, with the 14th and 15th rigs expected by midyear as planned. Dave Pursell can provide more color on our Egypt operations during Q&A. In the North Sea, production of 43,000 BOE per day was impacted by unplanned downtime at the Forties Echo platform. This resulted in the loss of 2,300 barrels of oil per day for approximately half of the first quarter, and we expect required repair work will keep these volumes offline through the end of the second quarter. Scheduled turnaround repair and maintenance work will also be conducted at both barrels and Forties through the summer. So we expect North Sea production to decrease for the next 2 quarters before rebounding in the fourth quarter. Moving on to Suriname. In Block 53, we spread the Rasper exploration well in late March and are drilling above the target zones at this time. We will update the status of this prospect at the appropriate time. In Block 58, we are focused on drilling a prioritized list of exploration and appraisal wells in the central portion of the block to assess and appraise resource scope and scale to underpin and optimize a potential first development. At the previously announced Krabdagu discovery, flow testing is complete and we are now in the buildup stage in both tested zones. After we have obtained and analyze this data, we will provide more details. Following conclusion of operations at Krabdagu, the Maersk Valiant will mobilize to the nearby Dico exploration prospect. Before turning the call over to Steve, I'd like to make a few remarks about our ESG progress. We have multiple initiatives underway within our focus areas of air, water and people, and we are piloting and investing in a number of technologies to support the measurement, understanding and reduction of our emissions footprint. In Egypt, we recently completed 2 projects that are making an immediate and material contribution toward our goal this year of reducing upstream flaring in our Western Desert operations by 40%. I will close by commenting on a frequent question that E&P companies are receiving from industry watchers. That is how will capital investment programs and capital return frameworks change in the context of sustained higher oil and gas prices. As I noted at the beginning of the call, we do not currently anticipate any significant changes to the activity levels set forth in our 3-year program. APA remains committed to safe and steady and efficient operations in all of our regions and returning a minimum of 60% of our free cash flow to shareholders through dividends and share repurchases. And with that, I will turn the call over to Steve Riney.

Thanks, John. For the first quarter of 2022, under generally accepted accounting principles, APA Corporation reported consolidated net income of $1.88 billion or $5.43 per diluted common share. As is commonly the case, our results include several items that are outside of APA's core earnings. The most significant of these was $1.1 billion of after-tax gains on the divestments of Altus Midstream and the Delaware Basin minerals package. Other material items included a $187 million benefit related to a release of tax valuation allowance to offset deferred U.S. income tax expense or a $53 million charge for early extinguishment of debt associated with our March bond tender. Excluding these and some other smaller items, adjusted net income for the first quarter was $668 million or $1.92 per diluted common share. In our financial and operation supplement, you can find detailed tables for all of our non-GAAP financial measures, including one for adjusted earnings. Our first quarter results underscore APA's strong free cash flow generating capacity. The impact of the Egypt PSC modernization on production volumes, combined with the higher commodity price environment, drove a 39% increase in first quarter free cash flow compared to the preceding quarter. Cost inflation has become a popular topic in quarterly earnings calls and for good reason. We embedded a good amount of cost pressure into the budgets we laid out in February. And for the most part, costs are tracking close to that plan. However, one cost issue in the first quarter that was not fully captured in guidance is related to equity-linked compensation. So let me go through a few details on that with you. You may recall that we have multiple equity-linked compensation plans that are denominated in APA shares. As these plans vest, some are paid out in actual shares and some are paid out in cash, we accrue the anticipated cost of these plans each calendar quarter through their various vesting periods. For the payers that pay out in cash, the accounting is a little more complicated. In the fourth quarter of 2021 and now, again, in the first quarter of 2022. These plans had a significant impact on our results for three key reasons, all related to improved underlying business performance and share price performance over the last several months. First, since we accrue the cost of these plans at the quarter-end share price, our quarterly cost accrual has been increasing substantially with the near doubling of our share price since the beginning of October. Second, the cumulative number of shares that are accrued but not yet paid out must be marked-to-market at the end of each quarter. The first quarter results include a large mark-to-market impact again due to the significant share price increase since January 1. Third, as a result of the improved business performance and relative share price, the variable payout plans now appear likely to pay out at a higher level than previously anticipated. So we are increasing the accrual levels accordingly. These stock plans apply to nearly the entire employee base. So some costs will flow to LOE and some to CapEx, but most will flow through G&A. As a result, G&A is notably above our previous guidance and market expectations. We have revised our G&A guidance for the remainder of this year accordingly. That said, stock price movement due to its unpredictable nature will continue to impact quarterly results beyond our revised guidance. We achieved a significant milestone during the first quarter with the closing of the Altus Midstream Eagle Claw business combination and the monetization of a portion of our ownership in the resulting entity Kinetic Holdings. Accounting rules require that we consolidate Altus' profit and loss through the February 22nd merger date. So you will see a partial quarter for these items reflected on our income statement. From a balance sheet perspective, upon closing of the transaction and reduction of our ownership to a minority interest, we will no longer consolidate Altus' balance sheet. As a result, $1.4 billion of debt and redeemable preferred equity from the 2021 year-end balance sheet are no longer consolidated. This could have a significant positive impact on various APA debt metrics, depending on how you calculate it. Subsequent to the completion of the transaction, APA sold 4 million shares of our Kinetic common stock holdings in March for net proceeds of $224 million. At quarter end, the market value of APA's remaining 8.9 million Kinetic shares was approximately $580 million. At this point, we view Kinetic as a non-core holding, and following the expiry of our lockup period in February of 2023, we will evaluate the potential for further monetization of our position. In the meantime, we continue to see this as an attractive investment with a leading Delaware Basin footprint, stable cash flows, a strong dividend, and attractive near-term growth potential. Turning now to the progress we've made during the quarter on our balance sheet. In addition to the deconsolidation of Kinetic, APA completed 2 important steps on the path to reducing leverage and maintaining strong liquidity. First, we initiated a tender offer in March for $500 million of outstanding bonds. We upsized the tender to $1.1 billion with a focus on repurchasing shorter maturity bonds. This extended our average maturity to approximately 16 years and reduced our annual bond interest expense by approximately $50 million. To accommodate the upsized tender, we temporarily drew on our revolver, which ended the quarter with a balance of $880 million. By the end of April, however, we reduced the revolver balance to $680 million. By the end of the year, we plan to use a portion of free cash flow to pay off the revolver and to call at par $123 million of bonds maturing in January 2023. We also recently refinanced Apache Corporation's revolving credit facility. The new facilities, which have been moved up to the APA corporation level and had 5-year primary terms, consist of a $1.8 billion revolving credit facility and a GBP 1.5 billion letter of credit facility, which will be used for LC postings related to the abandonment obligations in the North Sea. These efforts, along with our robust cash flow generation and deconsolidation of Kinetic have already been recognized by one rating agency. Fitch recently upgraded Apache to investment grade with a BBB- rating and a stable outlook. I would like to close by discussing some changes to our 2022 production guidance, which can be seen in our financial and operational supplement. Our full year U.S. production guidance is unchanged at this time, with oil volumes continuing to perform well. Reported production guidance for Egypt is down roughly 4%, the majority of which is associated with the impact of higher oil prices on our PSC cost recovery volumes. In the North Sea, we have reduced our full year production outlook by 1,000 BOEs per day, primarily to reflect first half unplanned downtime. Outside of these production impacts and the activity changes that John spoke of, the only other material change to our full year guidance is an $85 million increase in G&A expense, which reflects the equity-linked compensation-related accrual impacts previously discussed. Please refer to our financial and operational supplement or follow up with Gary and his team for any questions related to our updated guidance. And with that, I will turn the call over to the operator for Q&A.

Your first question comes from Doug Leggate from Bank of America.

I believe you asked me about Suriname and the buyback. You mentioned that the 60% of free cash flow target was not met in the first quarter. However, I understand that when there's non-public information regarding the well test, you can't be active in the market. So I would like to know if you could provide a more comprehensive update on whether you are still making progress toward a development and FID this year. Additionally, are you currently in a position to capitalize on today's share price weakness? I also have a follow-up question.

Thank you for your question, Doug. We remain committed to returning at least 60% of our free cash flow to shareholders for the calendar year of 2022. There are times when we have material nonpublic information, which necessitates the use of alternative strategies as we plan ahead. We have successfully completed the flow test at Krabdagu and are currently in the crucial buildup stage. It's important to note that this buildup phase can be just as significant, if not more so, than the flow tests themselves. We're pleased with our current status, and we won't be sharing incremental information on Krabdagu until the right time. So far, there have been no surprises. As we look towards a final investment decision in Suriname, we're moving towards a central area hub concept, which we're excited to explore with Total. We view Sapakara South as a foundational piece and see potential in Krabdagu as well, but I'll hold off on further comments until we're ready to discuss more. We have prioritized exploration and appraisal targets that require drilling, as the appraisal targets help us identify connected volumes essential for scope and scale, while sizable exploration targets also need to be drilled to ensure we accurately assess the potential for the first FID. Overall, everything is on track, and we are encouraged by the progress. We mentioned that the Maersk Valiant will soon shift to an exploration target at DCP, which we are looking forward to. Additionally, in Block 53, we are drilling Rasper. As stated in our prepared remarks, we are currently above the target zones and are eager to share more details when we can. We also plan to retain the Noble Jury for SUSA in Suriname, which is part of the reason for the increase in capital expenditures.

And Doug, this is Steve. I want to address the second part of your question regarding the pace of buybacks and cash usage. As John mentioned earlier, we expect around $2.9 billion in free cash flow this year, leading to at least $1.8 billion in returns to shareholders. In the first quarter, we used just over $300 million for dividends and share buybacks, which puts us slightly above a 15% payout based on the annual projection. Some activities may have been restricted due to MNPI, and typically, we approach the start of the year conservatively. We also made decisions on the debt front. However, as John confirmed, we remain devoted to achieving a full-year payout of 60% of free cash flow, and we plan actively around MNPI periods. We are aware of its implications for us, and we have additional strategies we can employ to buy back shares when necessary.

I want to follow up on the trajectory in Egypt, especially since this is the first quarter after the normal modernization. There are a few mixed results that might have surprised some, including me, particularly in terms of gas. What do you foresee for your adjusted volumes after accounting for minorities and tax issues? Can you provide some insight into that?

Yes. And I think if you step back big picture in Egypt, Doug, we've been declining gross operated production for a number of years. And the key to modernization was it facilitates the investment levels. And so you've seen us really ramp the rig count, really in the back half of last year, second half, we went from 5 to 11 rigs. We're at 12 today. We're in the process of picking up a 13th and 14th rig fairly soon and will likely go 1 or 2 higher than that. I think when you look at modernization, you have to look at the net. So despite a rising oil price, our net production was up 13% in Q1, and that's really the benefits of modernization. And that's with growth staying relatively flat as you're now starting to see that curve turn. April production is moving up quite a bit. And I'll let Mr. Pursell jump in and provide some more details here.

Yes, Doug. We will address your question about the mix shortly, but it's important to start with some context. As John mentioned, our production in April has increased significantly, showing an 8% rise compared to the first quarter. This aligns with our desired trajectory for oil production, which is primarily supported by a rising drilling rig count. We expect to have 15 rigs operational by mid-year, primarily focusing on oil exploration and production. We've had some exploration successes, particularly at Pita and Hazem Northwest. Our development drilling is progressing as planned, although we did encounter some delays in recompletions in the first quarter that have now shifted to the second quarter. Despite this, we are confident in our ability to grow oil production. Over time, the oil production mix will continue to improve compared to gas. Gary will provide detailed insights separately, but regarding modernization, we believe the adjusted and reported mix will closely align with the gross mix, eliminating any uncertainty in how the adjustments are reflected in the numbers. Moving forward, we expect growth to be the primary focus, and the gross oil mix is set to improve as we prioritize oil development in the coming years.

Your next question comes from John Freeman from Raymond James.

The first question I have is regarding the fact that about half of the CapEx increase is attributed to the higher activity in Suriname, particularly the decision to keep the Desousa drillship operational. I'm curious if you could provide more clarity on how you estimate the additional CapEx in this situation, considering that your CapEx obligations can vary significantly between appraisal and exploration-related activities in Block 58, as well as how the rig split time between Block 58 and Block 53 affects this. There are many different scenarios at play, so I'm wondering how you arrived at the risk-adjusted CapEx number.

We will retain the Desousa. You might consider an exploration well in Block 58, where we have a 50% interest, or another well in Block 53, where we have a 45% interest, both relatively comparable. If we pursue appraisal wells in Block 58, the costs will be lower due to carry considerations. Additionally, we could keep the Desousa for possibly more than one well. For now, I’ll just say that it will remain in the country, and we are still finalizing the details. However, we felt it was appropriate to increase our estimates, and we believe it reflects a solid figure.

Is it reasonable to say that if all the additional activity with Desousa turned out to be appraisal, the CapEx figure might decrease somewhat?

Potentially could. But I would anticipate we have risked exploration and appraisal wells. So it's going to be both.

Okay. Okay. And then just my follow-up, kind of sticking with the CapEx side. So on the U.S., where it was due to the increased non-op activity, and then you mentioned the mix change in your activity, some higher working interest, is it possible at all to sort of say, of the incremental CapEx associated in the U.S. kind of the split between it being due to increased activity/higher working interest stuff versus just cost inflation that we've been hearing about these calls the last few days.

Yes, John, I think, as you know, we built in quite a bit of inflation into our capital numbers with what we laid out first quarter. So the majority of this is we do have some wells that are going to be higher working interest than what we had originally planned, and that's just a function of shifting some pads and moving some pads forward. So there will be some higher working interest. And then we do have some increased non-op capital; some of that could be increased activity, and then some of that could be some inflation on the other operators too. It's hard to dig in and understand that, but it's really what we're just seeing on the non-op side moving up. And so those 2 factors kind of come to play together there on that. But I think we've done a pretty good job of anticipating the inflation and the increases in our 2022 plan. And I think that's playing out kind of as we budgeted and forecasted.

And your next question comes from the line of Arun Jayaram from JPMorgan Chase.

Yes. John, I was wondering if you could give us an update on your marketing agreement with Cheniere on Stage 3, I believe you have the ability to sell 140,000 MMBtu to them. Obviously, a very, very good pricing environment. So I was wondering if you could give us some details the timing of when that could kick in and perhaps the operating leverage there between your leverage to this and the North Sea exposure to global gas?

I'll let Steve dive in. I wish it was a bigger contract, but I'll let Steve dive in on the details.

We wish the contract was larger and initiated sooner. This is a 15-year contract that begins on July 1, 2023. Cheniere has the option to start the contract early with a 30 or 90-day notice, but they have not given us that notification yet. We are eager to activate this contract whenever possible, and if they proceed, we would begin at the agreed timeframe of 90 days or another mutually acceptable period. We cannot disclose the contract terms, but we choose a combination of Asian and European pricing for our gas sales on the Gulf Coast. We deliver gas at this pricing mix for a year, and then we account for liquefaction fees, transport fees, and a marketing fee. Essentially, we are fully vulnerable to the pricing fluctuations of the European and Asian LNG markets throughout the duration of the 15-year contract.

Great. And that starts mid of next year unless Cheniere elects to early stress that.

Exactly.

Okay, great. My follow-up is on Egypt. John, you have indicated that you expect to grow your oil volumes there by 8% to 10% annually. Could you talk a bit about how your early results are trending? It seems like as you began the recompletions, you started to see some growth. Can you provide more details on the trajectory of growth and any supply chain challenges in the country? You are rapidly increasing your activity, so please share what you're observing on the ground in Egypt.

No. It's good to be back at work and increase our activity levels to grow our production base. We have a couple of key discoveries to build on, including Pita West, which is a positive early win. It will provide us with opportunities that we can pursue fairly quickly. We have started some recompletions, and as Dave mentioned, we are already up about 8% in April compared to the first quarter. Progress is being made, although it takes some time. There are a few other discoveries that have also been promising. Our focus will be on oil drilling, which we are prioritizing. We have conducted seismic on the Northwest Razak concession, which represents a new frontier for us. We are excited about several exploration wells. We have plenty of inventory, and we feel confident about the plans we have established. We are getting settled and ready to move forward. Do you have anything to add, Dave?

John provided a solid response to the supply question. We remain confident in the path we established. Regarding supply chain issues, it's important to note that in Egypt, we are drilling fairly conventional vertical wells with minimal hydraulic fracturing involved. These wells are more commodity-based. That being said, our supply chain team is actively managing the situation to avoid delays in obtaining parts. As we increase our operations, having clarity on our plans allows the supply chain team ample time to ensure we have all necessary equipment to keep our program progressing. So far, we have been successful in this regard.

Your next question comes from the line of Michael Scialla from Stifel.

You're getting close to 1x debt leverage now. Stevie, you said one of the agencies upgraded the debt rating to investment grade. Stock's also done well this year, but it sounds like you're still focused on debt reduction and share buybacks. So I guess with that in mind, I want to see how you view the intrinsic value of the company relative to the current stock price and how you weigh that versus potentially increasing the dividend?

Yes, Michael. There are several points in your question. The main takeaway is that we believe our share price remains undervalued, and we have a strong appreciation for the buyback program. Regarding the debt reduction, we have successfully eliminated $3 billion in bonds over the past nine months, which is impressive compared to what we could have achieved 12 to 18 months ago. Our balance sheet is significantly stronger now, and Fitch has recognized that. We are actively engaging with all three rating agencies to improve our debt rating. While we will keep strengthening our balance sheet, it’s unlikely we will see large debt tenders exceeding $1 billion. In this price environment, we anticipate substantial free cash flow over the next three years, allowing us to focus on both balance sheet enhancement and share buybacks, particularly while our share price is undervalued. We frequently discuss the dividend and have increased it twice in the latter half of last year. We will continue to evaluate it, and as our balance sheet improves and if the share price rises, we will consider the dividend more seriously. For now, we are pleased with the buyback program.

Great. That helps. Second question was a marketing question. I guess, with the deconsolidation of Altus, I believe you retained your firm transportation for gas out of the Permian. I want to see if you plan to use all of that or if you have thoughts on monetizing any excess capacity there?

We previously monetized some of our capacity and currently have just over $670 million a day of transport capacity on PHP and Gulf Coast Express. Looking ahead for the rest of this year and into next year, we estimate we have about $200 million to $225 million a day of excess capacity. We are open to discussing the possibility of marketing some of that capacity. However, the differentials appear favorable for the next two years, and we have locked in those differentials on approximately 90% of that excess capacity through the end of 2023. We utilized a mix of hedges, some of which were not as appealing when we implemented them, but we have made substantial recent commitments. We have secured nearly $50 million in cash margin on the transport capacity, and we will utilize all of it. Essentially, it will receive Gulf Coast pricing for our equity volumes. All of our equity volumes are sold in-basin, and our marketing team buys 670 million a day, transports it, and then resells it on the Gulf Coast.

Your next question comes from the line of Charles Meade from Johnson Rice.

John, I have a question for you or possibly for Tracey. Can you provide us with some background on the new tick up prospect and whether its rise is related to your central area hub development concept?

Yes, Charles, I will tell you, it is something that would fall in that area. It's an exploration well, and I'm happy to have Tracey say a few things about it, so.

Sure Charles. As John mentioned in the original comments, we're going to be testing sort of a range of different prospects with different attributes in a list in support of looking at appraisal and exploration prospects. So I would say, the Diku wells at the front of the schedule. It's a well that Total really likes with some potential meaningful reserves. So we see it, I think, is a bit higher risk, higher reward because it does have some different seismic attributes than we've tested, but it has the potential to unlock, I would say, some additional follow-on prospectivity, that could incrementally and substantially but more reserves. So I think it's one we're anxious to see, but it is a bit of a different beast than what we've seen before, but has potential to be meaningful for the appraisal.

Your next question comes from the line of Scott Hanold from RBC Capital Markets.

A quick question on the Desousa rig that's in Block 53. If it stays in country. It sounds like it's going to move to Block 58. Would you all continue to be the operator of that rig? Or would you hand that over to Total?

It could remain in Block 53 or be moved to 58, allowing Total to take over. There are options available, and I will stop there for now.

Okay. But just to clarify, if it did go to 58, they would take over operatorship. Is that right?

They are the operator in Block 58, and we are the operator in Block 53. There are many factors to consider, but we won't be making any changes since they already hold the value from their operations.

Okay. Understood. And then Alpine High, obviously, with where gas prices are, looks a lot more interesting. You guys are moving a rig there and going to resuscitate those volumes. Can you think about big picture? Obviously, Steve talked about the potential excess capacity you all have with your FT. And I know in past – in the beginning of the Alpine High history, I guess, you all talked about Mexico being an option there to descend gas. But like as you think about gas prices, optionality between LNG, maybe Mexico still yet? How do you think about that longer term? Are you guys going to keep a rig there? Do you – could you move more on there? Do the economics really warrant ramping up much? Just give a little bit color on that, that would be great.

No. We’ve – we started last September picking up a rig in the U.S. It’s going to be a Delaware Basin focused rig. It’s now working in our DXL area. We had a pad there that was partially drilled. And so we wanted to drill that out first, and then it will be moving to Alpine High. We’re excited about what those economics look like, right? If you look back at the Willow well, and we had some details in our supplement there. It was one of the best wells we brought on last year of all of our DUCs. I think it has cumed over 9 Bcf, and it’s been on since really January of ‘21. So we are excited about those economics. I think they compete well, and we’re anxious to get a rig back to work as there’s plenty of infrastructure.

Your next question comes from the line of Bob Brackett from Bernstein Research.

I'll try fishing off Suriname a bit. In terms of the Jerry DeSousa, when did the decision to keep that rig occur? Did it occur after you'd spudded RASPER? And a related question, is there an obvious sidetrack to RASPER?

We're above target zones at RASPER, Bob. So I'll just leave it at that.

How about a follow-up. If we talk about the Krabdagu flow test, the fact that you went on to the next step of buildup suggests that you flowed oil through a sufficiently permeable reservoir that it makes sense to do a longer-term test. Am I getting the engineering right on that?

We're doing a buildup. So we're in the buildup phase, and I said there were no surprises. So I'll leave it at that.

A final question would just be about the restricted flow test at Sapakara South, which flowed 4,800 barrels of oil. Is that in the realm of no surprises?

I'll just say there were no surprises, and we may not have expected there to be a restricted flow test, but I'll leave it at that. Your questions are always fun, Bob, and creative.

Your next question comes from the line of Paul Cheng from Scotiabank.

Two quick questions, John. Two quick questions. Can you tell us that how many wells do you expect to grow in Alpine High this year? And secondly, that I know it's really early, but given the inflationary environment and the activity level, what is your preliminary give and take, different component in the 2023 budget may look like? Any direction that you can point to?

In terms of number of wells, Dave?

Yes, Paul, this is Dave Pursell. The number of wells at Alpine later this year will only be a few because, as John mentioned, we're completing an undrilled uncompleted pad at DXL before moving to Alpine. These wells will all feature longer laterals and relatively large stimulation treatments. So, we will have only a few wells ready to come online by the end of the year.

Your second part of your question, Paul, it was hard to hear.

I was saying that. I know it's early, but for 2023, any kind of direction you can point to on the preliminary budget and activity levels?

Yes. I mean, I would say today, as we look at 2023, our 3-year plan we laid out this year looks pretty darn good to us, right? We've added the fourth rig in the U.S. we'll be at 15 rigs in Egypt. So right now, we're not envisioning any increases to the 3-year plan that we laid out at the start of this year.

Okay. And how about in the budget given the inflation, I mean, how much additional costs that we should be taking into consideration?

Yes. I mean, we'll wait until next February to come out with a hard number for '23. We did have an increased dial in for additional inflation in '23, but I'm not in a position to really give you that number right now. A little early.

Your next question comes from Neil Mehta from Goldman Sachs.

John and team, the first question is about the North Sea. I would like to get your views on the production timeline there. As you've mentioned, there will be a significant turnaround schedule throughout the summer. How do you feel about the exit rate of 50,000 BOE a day and any updates on activity plans?

Yes, Neil, we are still focused on the North Sea. We have a significant turnaround period ahead that we are eager to complete. I believe we are performing well, and that will be crucial. It's encouraging to see that the Ocean Patriot is either back in the field or arriving today. We essentially lost an entire quarter due to the drilling of the Ocean Patriot, which is impactful when operating only one floater; it required maintenance after a large anchor chain broke. We are optimistic about the prospects for that rig line and the upcoming work, including the repairs. We anticipate that the exit rate will be around 50,000.

All right. And then the follow-up is, you operate a global portfolio here. Talk about the inflationary forces that you're seeing in the U.S. relative to international, fair to say, thus far, a lot of your peers have reported more inflation in their U.S. business relative to international. But how do you see that playing out over the next 12 months?

We operate a global portfolio and focus on staying ahead. Many of our 2022 programs were already contracted, which we integrated in the last quarter when we announced the budget. We feel confident about our positioning. The dynamics depend largely on location and the demand for equipment. Typically, we observe greater price increases in the U.S. and more stability in international prices, but this time the situation is somewhat different because we're not solely competing for rig counts, which often leads to hyperinflation. Nonetheless, there is a clear upward trend in commodity prices, including fuel, steel, and sand. As we look ahead, costs will likely continue to rise. Moreover, in recent years, there hasn't been much new equipment manufactured, leading to older rigs and frac crews relying on parts cannibalized from other equipment. Therefore, if current price trends persist, we should expect to see higher prices in the coming years. Dave, do you have anything to add?

Yes. When considering inflation, it primarily involves labor, steel, chemicals, and diesel, which are issues faced globally. In the Permian region, compared to our global portfolio, we are using more specialized and high-end equipment, increasing the competition for that equipment. Both of these factors contribute to added pressure, especially with pressure pumping and large fracturing components of the wells in the Permian, which can drive up costs significantly—something we don't experience in Egypt or the North Sea. This summarizes the key differences.

Your next question comes from the line of Leo Mariani from KeyBanc.

I just wanted to follow up on some of the prepared comments here. You all kind of describe Safacura South as a potential kind of foundational part of a project and said kind of stay tuned on Krabdagoe. I mean, I think there's a plan for Total as kind of talked about maybe hitting FID at the end of the year. But am I reading some pretty good confidence out of you guys in terms of what you've seen so far that you think there's certainly a sizable, viable economic project here?

At this point, Leo, we have not announced a project or an FID. I think we've said from the get-go that Sapakara South is a foundational piece. We've shown it's gotten bigger with the extended buildup time as we raised that original estimate from the connected volume just to the 1 well, and I want to emphasize again, that's just via the 1 initial well was 325 million to 375 million barrels. We raised that to greater than 400 million. And that area continues to get bigger and there's more appraisal to do at Sapakara South. So I think we have confidence in what we have found, and we like the program, but there's still more work to do.

Okay. And then just on the North Sea, you all certainly said you've got confidence on this 50,000 BOE per day exit rate. I guess are there some particular wells that you all need to kind of tie in. I know there's a bunch of downtime of turnarounds here this summer. But are there a project or 2 that are kind of chunky that you guys are going to be bringing on, on the well side that gives you confidence in that number?

Yes, there's a Garden well that the Ocean Patriot was scheduled to drill, and we've had to slide that back. But those Garden wells have been high rate, and it's a very, very good location.

And there are no further questions over the phone line. I'd like now to hand the call over to John Christmann, CEO. Please go ahead, sir.

Yes. Thank you for participating on our call today. I'd like to leave you with the following closing thoughts. Financially, we have become a much stronger company. We will remain disciplined, both financially and operationally. Lastly, we are committed to our shareholder returns framework, returning a minimum of 60% of our free cash flow to shareholders through dividends and buybacks. Operator, I will now turn the call over to you. Thank you.

Thank you, sir. Thank you, presenters. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.