Good day, and thank you for standing by. Welcome to the APA Corporation First Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. If you require any further assistance, please press star zero. I'll now like to hand the conference 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 make forward-looking statements today. A full disclaimer is located with the supplemental information on our website. 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 three-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 the 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 for 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 three-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 three 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 one floater and one platform rig, which should be capable of broadly sustaining production over the next three years.
Lastly, we continue to explore and appraise our two 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 Kinetik. 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 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 continued 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 Gerry de Souza drillship in country following conclusion of operations at the Raspar well 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 and 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 six-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, one rig is currently delineating the Austin Chalk in Brazos County, where we are in the early stages of flow back on the first three-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 BOE 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 mid-year 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 Beryl and Forties through the summer. We expect North Sea production to decrease for the next two quarters before rebounding in the fourth quarter. Moving on to Suriname. In Block 53, we spud 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 build-up stage in both tested zones. After we have obtained and analyzed this data, we will provide more details. Following conclusion of operations at Krabdagu, the Maersk Valiant will mobilize to the nearby Dikkop 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 two 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 three-year program. APA remains committed to safe, steady, and efficient operations in all of our regions, and to returning a minimum of 60% of our free cash flow to shareholders through dividends and share repurchases. 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, and 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 operations 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 a 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. 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 plans 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 EagleClaw business combination and the monetization of a portion of our ownership in the resulting entity, Kinetik 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 them. Subsequent to the completion of the transaction, APA sold 4 million shares of our Kinetik common stock holdings in March for net proceeds of $224 million. At quarter end, the market value of APA's remaining 8.9 million Kinetik shares was approximately $580 million. At this point, we view Kinetik as a non-core holding, and following the expiry of our lock-up 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 Kinetik, APA completed two 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 have five-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 Kinetik, 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 BOE 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 a $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. With that, I will turn the call over to the operator for Q&A.
Thank you, sir. Again, to ask a question, please press star one on your telephone keypad. To ask a question, simply press star one on your telephone keypad. Your first question comes from the line of Doug Leggate from Bank of America. Your line is open. Please go ahead.
I think that was me. Good morning, everybody.
Good morning, Doug.
John, I'm gonna start with. Maybe I'll try for a twofer here, on Suriname and the buyback. The 60% of free cash flow, you obviously fell quite a bit below that in the first quarter. My understanding is when you have non-public information on the well test, that you can't actually be in the market. I wonder, my twofer is, I wonder if you could give us a more fulsome update as to whether you feel like you are still making progress towards a development in FID this year, and whether at this point, you are able to be back in the market, taking advantage of, for example, today's share price weakness. I've got a follow-up, please.
Okay. No, Doug, great question. You know, first off, I'll say we are committed to the return framework of a minimum of 60% of our free cash flow to shareholders. We are committed to that for the calendar year of 2022. We do have periods where you have material non-public, and we have to use other vehicles and have planned ahead with 10b5-1s and so forth. You know, there are periods where you know, we have to rely on those and think ahead. We have completed the flow test at Krabdagu. We are now in the important build-up stage.
As you know, Doug, and appreciate, you know, sometimes the build-up can be as important as a flow test or more important. You know, we're excited about where we are. You know, at this point, we're not gonna dribble information out on Krabdagu. We'll wait and come back with a you know, a report at the appropriate time. But I would say there have been no surprises. You know, as we think about a path to FID in Suriname, you know, we're kinda moving more towards a what I'll call a central area hub concept. You know, it's something that we're excited about and starting to think about with Total. You've got a foundational piece at Sapakara South.
You know, we think Krabdagu can also be a foundational piece, but I'm gonna hold comments there until we're ready to talk about that. We've prioritized a list of both exploration and appraisal targets that we need to drill. Obviously, the appraisal targets are helping us find connected volumes, which are critical to scope and scale. The exploration targets that are sizable, we also need to drill to make sure you would get the scope and scale right of that potential first FID. You know, things are on track. We're excited about you know, how things are progressing. We did say the Maersk Valiant will be moving to an exploration target next, which is Dikkop. We're excited about that and you know, quite frankly, things are progressing nicely.
In Block 53, while I'm on Suriname, we're drilling Rasper. As we said in the you know, the prepared remarks, we're above the target zones. You know, we are excited about Rasper, and we'll come back on it when we can talk about it. We also said we will be retaining the Noble Gerry de Souza in country in Suriname, which is one of the reasons why the CapEx is going up.
Doug, this is Steve. If I could weigh in on the second part of your question about the pace of buybacks and uses of cash. You know, so as John said in his prepared remarks, we anticipate at strip about $2.9 billion of free cash flow this year. That would imply at least $1.8 billion, as he said, in returns to shareholders. In the first quarter, we between dividends and share buybacks did just a little over $300 million. So we're a little bit above a 15%, payout at that implied pace of annual payouts. You know, I think there was some activity that may have been limited due to MNPI. But I think also, you know, you don't start the year with guns a-blazing. You start probably on a conservative pace.
We also, as you know, chose to do something on the debt side. As John said, we absolutely remain committed to the full year payout of 60% of free cash flow. We actively plan around periods of MNPI. We understand what that does to us, and there are other mechanisms we can use from time to time to be able to be in the market and buying back shares.
All right. Thank you for that, fellas. Hopefully, my follow-up, I'll let someone else dig into the Suriname. I think there's two tests going on, so I'm sure others will get into that. I wanna ask you about the trajectory in Egypt. This is the first quarter since the normalization. There's a few mixed changes in there that I think might have surprised some people, so certainly surprised me with a little bit more gas. What is the trajectory to how you see your adjusted volumes after royalties and taxes? Can you give an idea what that looks like?
Sure.
I'll leave it there. Thanks.
Yeah. I think if you step back big picture in Egypt, Doug, you know, we've been declining gross operated production for, you know, a number of years. The key to modernization was it facilitates the investment levels. You've seen us really ramp the rig count, you know, really in the back half of last year, second half, we went from 5 to 11 rigs. We're at 12 today. You know, we're in the process of picking up a 13th and 14th rig fairly soon, and we'll likely go one or two higher than that. I think when you look at modernization, you have to look at the net. Despite a rising oil price, you know, our net production was up 13% in Q1. That's really the benefits of modernization.
That's with growth staying relatively flat as you're now starting to see that curve turn. April production's moving up quite a bit, and I'll let Mr. Pursell jump in and provide some more details here.
Doug, we'll get to your mix. We'll answer the mix question, but it's important to give you the preamble before that. As John said, you know, April production is moving higher. We're up, too, you know, we're up 8% as we've exited April here relative to the first quarter. We've got the oil production trajectory the way we like it, and really that's driven by a couple things. Continue to increase drilling rig count. We talked about we'll be up to 15 rigs by the middle of the year. Those drilling rigs really focus on oil, have an oil focus. It's both exploration and production.
You know, we talked in the supplement. We've had a couple nice exploration successes at Ptah and Hazem Northwest or Ptah West and Hazem Northwest . Our development drilling is on track. We did have some delays on recompletions in the first quarter, moved into the second quarter, but we think we're on track to continue to grow oil production and that the oil production mix will continue to improve or increase over time relative to gas. I think, and I'll let Gary kind of offline walk you through the blood, guts, and feathers of this. But when you think about the modernized terms, it's also a simplified structure. We think going forward that the adjusted and reported mix should mimic and track the gross mix very closely.
There won't be that ambiguity in how you roll up into the adjusted and reported numbers. We think, you know, gross is what you should focus on, and that gross oil mix is gonna improve as we continue to focus on oil development here over the next several years.
Thank you very much indeed.
Thank you, Doug.
Thank you. Just a reminder to ask a question, simply press star one on your telephone. Please do limit your question to one question and one follow-up. Your next question comes from the line of John Freeman from Raymond James. Your line is open. Please go ahead.
Hi, guys.
Hello, John.
The first question I had, when you know, you mentioned that about half the CapEx increase was related to the increased activity in Suriname, with the decision to keep the de Souza drillship, you know, in Suriname following Rasper. I'm just wondering if there's a way to maybe give a little bit more color on how exactly y'all go about estimating the incremental CapEx there, given you know, obviously your CapEx obligations are materially different, whether it's appraisal or exploration-related activity in Block 58, as well as whether that rig, drillship may split time between Block 58 and Block 53? Obviously, there's just a lot of different scenarios, and I'm just wondering kinda how y'all kind of came up with some risked kinda CapEx number.
Well, John, we're gonna keep the de Souza. There's, you know, you could think about an exploration well in Block 58 where we've got 50% or, you know, another well in Block 53 where we've got 45%. Pretty similar. Obviously, if it's appraisal wells in Block 58, they're gonna be less because of the carry. There's also the ability to keep the de Souza for maybe more than one, you know, one well. I'll just leave it at that. It will stay in country, and we're still working through details, but we felt like we ought to at least move it up from the amount we've moved it up, and we think it's a good number.
Is it not to try and put words in your mouth, John, but is it fair to say that if all of the incremental activity with de Souza ended up being appraisal that CapEx number might come down some?
It potentially could. I would anticipate we've got risked exploration and appraisal wells, so there's gonna be both.
Just my follow-up, kind of sticking with the CapEx side. On the U.S., where it was due to the increased non-op activity, and then you mentioned the mix change in your activity with some higher working interest. Is it possible at all to sort of say of the incremental CapEx associated in the U.S., you know, kind of a split between it being due to kind of increased activity, higher working interest stuff versus just cost inflation that we've been hearing about on a lot of these calls these last few days?
Yeah, John, I think as you know, we built in quite a bit of inflation into our capital numbers, you know, with what we laid out first quarter. The majority of this is we do have some wells that are gonna be higher working interest than what we had originally planned, and that's just a function of, you know, shifting some pads and moving some pads forward. There will be some higher working interest. We do have some increased non-op capital. You know, 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. Those, you know, two factors kind of come into play together there on that.
Thanks, John.
I think we've done a pretty good job of anticipating the inflation and the increases in our 2022 plan. I think that's playing out kinda as we had budgeted and forecasted.
That's what I was looking for. Thanks, John. I appreciate it.
Mm-hmm. Thank you.
Thank you. Your next question comes from the line of Arun Jayaram from JPMorgan Chase. Your line is open. Please go ahead.
Yeah, good morning. John, I was wondering if you could give us an update on, you know, your marketing agreement with Cheniere on Stage III. I believe you have the ability to sell 140,000 MMBtu to them. Obviously, a very, very good pricing environment. I was wondering if you could give us some details on 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.
Yeah, I'll let Steve dive in. I wish it was a bigger contract, but I'll let Steve dive in, you know, on the details.
Yeah, we wish it was bigger, and we wish it was sooner. That contract, that's a 15-year contract. You got the basic terms right, Arun. That one contractually begins on July first of 2023. At any point in time now, Cheniere does have the option with 30 days notice or 90 days notice, sorry, to elect to start that contract early. They haven't given us that notice. We, you know, we would like to obviously get that one at any point in time. If, you know, if we do, we'll start it 90 days later or any other timeframe that we might agree with them within that. It's at their option to be able to do that.
You know, we obviously can't disclose the terms of that contract. You know, suffice it to say, what we do is we select a mix of Asian versus European pricing. We effectively sell our gas. We deliver gas on the Gulf Coast. We sell it at this mix for a full year, a mix of Asian and European pricing. We net back through liquefaction fees, transport fees, and a marketing fee that we pay. We're in effect fully exposed to the European and Asian LNG market pricing for that 15-year period.
Great. That starts mid of next year, unless Cheniere elects to early start that.
Exactly.
Okay, great. And just my follow-up is on Egypt. John, you guys have highlighted the expectation to grow your oil volumes there by 8% to 10% per annum. I was wondering if you could maybe talk a little bit about, you know, how your early results are trending. It does sound like things are, you know, when you get the recompletions going, that you are starting to see some growth there. But I was wondering if you could maybe dig down and give us a sense of, you know, the trajectory of growth, any supply chain headwinds in country. Obviously, you guys are rapidly expanding activity, but give us a sense of what you're seeing on the ground in Egypt.
No, it's you know number one, it's good to get back to work and kinda you know move our activity levels up to where we can grow that production base. I think we've got a couple of key discoveries to build on. I think the Ptah West you know in between Ptah and Berenice is a nice early win. It's gonna give us some things that we can get on fairly quickly. We did get some of the recompletions underway, and as Dave you know mentioned, I think we're up about 8% in April over the first quarter already. It just takes a little bit of time but things are progressing. There's a couple other you know discoveries that have been nice. We're gonna be focused on oil drilling.
We're kind of prioritizing that. You know, we've got the Northwest Razzak concession that we're, you know, we shot seismic on, and it's kind of a new frontier for us. We've got some nice exploration wells that we're also excited about. You know, lots of inventory around, and we feel good about, you know, the plans that we've laid out, and, you know, we're kinda getting our feet under us and getting going. Anything you wanna pile on Dave?
John answered the supply question really well. The trajectory, we're very, you know, so confident in the path that we laid out. I think on the supply chain questions, remember in Egypt, we're drilling relatively conventional. These are conventional wells or vertical. We don't have, you know, much of any hydraulic fracturing activity in country. So these are. I would call it kinda commodity sort of wells. But that said, our supply chain team is all over it. They're making sure that we're not waiting on parts.
as we ramp up, one of the nice things about having a visibility on a plan is it gives the supply chain folks lead time to really make sure that we have all the equipment necessary to keep the program moving forward. So far, that's been the case.
Great. Thanks a lot, Dave.
Mm-hmm.
Thank you. Your next question comes from the line of Michael Scialla from Stifel. Your line is open. Please go ahead.
Good morning, everybody. You're getting close to 1x debt leverage now, and Steve, you said one of the agencies upgraded their 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 buyback. I guess with that in mind, I wanna 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?
Yeah, Michael. Hey, how are you? So, a number of questions in there. I think that the key answer to your question would be, or the key part of your question would be that we still see our share price as undervalued, and we like the buyback program, and we like it quite a bit. You know, your reference to the amount of debt reduction that we've done, just to step back from it a bit. In the last nine months, we've done $3 billion of bond elimination, which is just phenomenal compared to what you think we might have been able to do just 12 to 18 months ago.
Certainly, the balance sheet is much, much stronger today, and you know, Fitch was the first one to recognize that and acknowledge it. We you know are in conversations with all three rating agencies and we continue to work the debt rating hard with all three of them. I think we'll continue along the lines of balance sheet strengthening, but I think it's unlikely that you're gonna see the large chunks of you know debt tender activity that you know the $1 billion+. You know, as long as we stay in this price environment, we're gonna have a significant amount of free cash flow over the next three years.
There will be continued balance sheet strengthening, but there will be a significant focus on share buybacks as well as long as the share price, in our view, stays undervalued, which is what it is now. You know, we talk about the dividend all the time. We talk about it often and, you know, we've raised it twice in the back half of last year. We'll continue to look at that. As the balance sheet gets stronger, as prices continue to play out the way they are, and as share price improves on an absolute and relative basis, then we'll certainly think more seriously about the dividend. For right now, we're quite happy 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. Wanted to see if you plan to use all of that or if you have thoughts on monetizing any excess capacity there.
Well, as you know, we did monetize some of that in prior years. You know, we have about, you know, in round numbers, a little over 670 million a day of transport capacity on PHP and Gulf Coast Express. As we look forward to the next, you know, the remainder of this year and into next year, we have, you know, on average, somewhere in the 200 to 225 million a day of excess capacity. Would we be open to potentially marketing some of that? Yeah, I mean, we would entertain a conversation on that for sure. At the same time, the differentials look good for the next two years.
As you'll probably see in our results, in our postings, that we have actually gone and we've now locked in those differentials on about 90% of that excess capacity all the way through the end of 2023. In doing so, there's a mixture. We put in some hedges in earlier time periods that were not quite as attractive as they are these days, but we've put in quite a bit just recently, and we've locked in about a little under $50 million of cash margin on that transport capacity. You know, the rest of the capacity will be used, you know, we use all of it, and effectively it gets you know, Gulf Coast pricing on our equity volumes. We sell all of our equity volumes in basin, and then our marketing group buys 670 million a day, and transports it and then resells it on the Gulf Coast.
Appreciate that, Steve.
Thank you. Moving on, your next question comes from the line of Charles Meade from Johnson Rice. Your line is open. Please go ahead.
Good morning, John, to you and the rest of your team there.
Good morning, Charles.
John, I imagine this is a question for you or perhaps for Tracy. Can you give us the kind of the background and the provenance of this Dikkop, or I don't know exactly the way to pronounce it, the new, you know, Dikkop prospect? Perhaps wrap into it whether it kind of rises to the top of the pile here is connected to your Central Area Hub development concept.
Yeah, Charles, I will tell you know, it is something that would fall in that area. It's an exploration well, and I'm happy to have, you know, Tracy, you know, say a few things about it.
Sure. Morning, Charles. You know, as John mentioned in the original comments, you know, we're gonna be testing sort of a range of different prospects with different attributes in a list in support of looking at appraisal and exploration prospects. I would say the Dikkop Well is at the front of the schedule. It's a well that Total really likes with some potentially meaningful reserves. We see it, I think, as 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, you know, incrementally and substantially book more reserves. I think it's, you know, 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.
Great. That's helpful detail. Thanks. Thanks, and that's it for me.
Thank you, Charles.
Thank you. Your next question comes from the line of Scott Hanold from RBC Capital Markets. Your line is open. Please go ahead.
Yeah, thanks. A quick question on the de Souza rig that's in Block 53. If it stays in country, it sounds like it's gonna move to Block 58. Would you all continue to be the operator of that rig, or would you hand that over to Total?
Scott, it could stay in Block 53 or we could, you know, move it to 58 and let Total take it. There's optionality there, and I'll just leave it at that for now.
Okay. Just to clarify, if it did go to 58, they would take over operatorship. Is that right?
They are the operator in 58, and we're the operator in 53. You know, there's a lot of things you could work out, but.
Yep, understood.
You know, wouldn't be changing. You know, they've got the Valiant working, so.
Okay, understood. Alpine High, obviously, you know, with where gas prices are, you know, looks a lot more interesting. You guys are moving a rig there and gonna resuscitate those volumes. You know, can you think about big picture? Obviously, Steve talked about the potential excess capacity you all have with your FT. I know in past, in the beginning of the Alpine High history, I guess, you all talked about Mexico being an option there too to send gas. Like, as you think about gas prices optionality between LNG, maybe Mexico still yet, you know, how do you think about that longer term? Are you guys gonna keep a rig there? Could you move more on there? Do the economics really warrant ramping up much? Just give a little color on that. That'd be great.
No, we've you know, we started last September picking up a rig in the U.S. It's gonna be a Delaware Basin-focused rig. You know, 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. You know, we're excited about you know, what those economics look like, right? If you look back at the Willow well, and we had some details in our supplement there, you know, it was one of the best wells we brought on last year of all of our areas. I think it's cummed over 9 Bcf, and it's been on since really January of 2021. You know, we are excited about those economics. I think they compete well, and you know, we're anxious to get a rig back to work as there's plenty of infrastructure.
Thank you. Your next question comes from the line of Bob Brackett from Bernstein Research. Your line is open. Please go ahead.
Good morning. I'll try fleshing out Suriname a bit. In terms of the Gerry de Souza, when did the decision to rebook that rig occur? Did it occur after you'd spudded Rasper? A related question, is there an obvious sidetrack to Rasper?
We're above target zones in 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 a build-up 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?
You know, we're doing a build-up, so we're in the build-up phase, and I said there were no surprises, so I'll leave it at that.
A final question would just be the restricted flow test at Sapakara South flowed 4,800 barrels of oil, I think. Is that in the realm of no surprises?
I'll just say there were no surprises. We may not have expected there to be a restricted flow test, but I'll leave it at that.
Thank you much.
Thank you. Your questions are always fun, Bob. Thank you. Creative.
Your next question comes from Paul Cheng from Scotiabank. Your line is open. Please go ahead.
Hey, guys. Good morning.
Morning, Paul.
John, two quick questions. Can you tell us how many wells you expect to flow in Alpine High this year? Secondly, I know it's really early, but given the inflationary environment and the activity level, what is your preliminary give and take, different components in the 2023 budget may look like? Any direction that you can point to? Thank you.
In terms of number of wells, Dave?
Yeah, Paul, this is Dave Pursell. Number of wells at Alpine later this year, it'll just be a handful 'cause we're, as John said, we're finishing up an undrilled, uncompleted pad at DXL, then we'll move to Alpine. You know, these are all gonna be longer laterals with relatively large stimulation treatments. It'll be a handful of wells that are, you know, ready to come online at the end of the year.
Your second part of your question, Paul, it was hard to hear.
Oh, 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?
Yeah, I mean, I would say today as we look at 2023, our three-year plan we laid out this year looks pretty darn good to us, right? We've added the 4th rig in the U.S. We'll be at 15 rigs in Egypt. Right now, we're not envisioning any increases to the three-year plan that we laid out at the start of this year.
Okay. Will do. How about in the budget, you know, given the inflation? I mean, how much additional cost that we should be taking into consideration?
Yeah, I mean, we'll wait till you know next February to come out with a hard number for 2023, but we did have an increase dialed in for additional inflation in 2023, but I'm not in a position to really give you that number right now.
Okay. Will do. Thank you.
It's a little early.
Thank you.
You bet.
Your next question comes from Neil Mehta from Goldman Sachs. Your line is open. Please go ahead.
Good morning, John and team. The first question is around the North Sea. Just want to get your perspective on the production cadence there. As you've already indicated, it's gonna be a heavy turnaround schedule through the summer, but how are you feeling about the exit rate of 50,000 BOE a day and just any update around activity plans there? Thank you.
Yeah, Neil, you know, we're still with the North Sea. We've got a heavy turnaround period coming up that we're anxious to get on and get through. I think it's you know, executing that's gonna be key. I think we've got good news that the Ocean Patriot is back in the field or arriving today. So, you know, that's been one of the other items that we basically lost an entire quarter with the drilling of the Ocean Patriot. Which when you're only running one floater and you lose it for a quarter, it had to go in. It had a large anchor chain that had broke, you know, and had to be repaired.
you know, I think we feel good about the you know, the prospects that are on that rig line and the work that's ahead of us and the repair works. you know, we feel good about the exit rate, which you know, should be around 50,000, so.
All right. Thanks, John. The follow-up is, you know, you operate a global portfolio here. Talk about the inflationary forces that you're seeing in the U.S. relative to international. I think 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?
Well, I mean, I think, you know, we do operate a global portfolio. I think it's a function of staying ahead. You know, we had a lot of our 2022 program under contract. You know, we had cranked a lot of that into last quarter when we announced the budget. We feel good about what we dialed in and where that sits. I think a lot of it just depends on where you are and what the demand for that equipment is. You typically do see higher increases in the U.S. and then more volatility and more stable prices internationally.
I think the thing that's a little bit different this time is, you know, we're not all just fighting over rig count, you know, rigs and which drives that hyperinflation. There's no doubt, you know, commodities are going up, fuel is going up, steel, sand, you know, so as you look out, you know, costs are going up. The other thing, if you look back over the last few years, there's not been a lot of equipment that was, you know, built. A lot of the parts that were needed to keep, you know, rigs running and frac crews running have been cannibalized off of older equipment. You know, there's no doubt as you look out over the next couple of years, if the price deck holds, you know, you're gonna see, you know, some higher prices.
Makes a ton of sense. Thanks, John.
Dave, anything you wanna add to that?
Yeah. I think when you look at inflation, it's people, steel, chemicals, and diesel. I mean, that's ubiquitous around the world. When you look at the Permian relative to the rest of the global portfolio, you're running higher spec and kinda higher end equipment in the Permian, and there's more competition for that equipment. Both those things create more pressure, and you've got the pressure pumping and big frac component of the wells in the Permian that can be fairly relentless or significantly inflationary, which we don't see in either Egypt or the North Sea. I think that's the real kinda categorical breakdown.
Yep. Makes a ton of sense. Thanks, guys.
Thank you. Your next question comes from the line of Leo Mariani from KeyBanc. Your line is open. Please go ahead.
Hey, guys. Just wanted to follow up on some of the prepared comments here. You all kinda described Sapakara South as a potential kinda foundational part, you know, of a project and instead kinda stay tuned on Krabdagu. 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?
I mean, at this point, you know, 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. You know, we've shown it's gotten bigger with the extended build-up time, as we raised that original estimate from, you know, the connected volume just to the one well, and I wanna, you know, emphasize again, that's just, you know, the one initial well was 325 to 375 million barrels. We raised that to greater than 400. And you know, that area continues to get bigger, and there's more appraisal to do at Sapakara South. You know, I think we have confidence in what we have found and we like the program, but we, you know, there's still more work to do.
Okay. Just on the North Sea, y'all certainly said you've got confidence on this 50,000 BOE per day exit rate. I guess are there some particular, you know, wells that y'all need to kinda tie in? I know there's a bunch of downtime and turnarounds here this summer, but, you know, are there, you know, a project or two that are kinda chunky that you guys are gonna be bringing on the well side that gives you confidence in that number?
Yeah, there's a Garten well that, you know, the Ocean Patriot was scheduled to drill, and we've had to slide that back. Those Garten wells have been high rate and, you know, it's a very, very good location.
Okay, thanks.
Mm-hmm. Thank you.
Thank you. 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.
Yeah, 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.