APA Corporation (APA) — Q1 2024 Earnings Call Transcript

Good morning, and thank you for joining us on APA Corporation's First Quarter 2024 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann. Steve Riney, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Tracey Henderson, Executive Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be about 15 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our 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 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 on today's call. A full disclaimer is located with the supplemental information on our website. Please note that the first quarter 2024 results reflect APA Corp. only as the Callon acquisition was subsequently closed on April 1. Accordingly, our full year 2024 guidance reflects first quarter APA results on a stand-alone basis, plus 3/4 of APA and Callon combined. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On the call today, I will review our first quarter performance, discuss the compelling opportunities we are seeing after the closing of the Callon acquisition and review our activity plan and production expectations for the remainder of 2024. During the first quarter, Upstream capital investment of $568 million was below guidance due primarily to the deferral of some planned facility, leasehold, and exploration spend. We continue to deliver excellent results in the Permian Basin with the first quarter marking our fifth consecutive quarter of meeting or exceeding U.S. oil production guidance. U.S. oil volumes were up an impressive 16% compared to the first quarter of 2023, and we expect organic growth to continue through the year as we integrate talent. On the natural gas side, we chose to curtail a substantial amount of production at Alpine High, primarily in March, in response to extreme Waha basis differentials. This dynamic has continued into the second quarter. In Egypt, gross production was in line with our expectations, while adjusted volumes were just shy of guidance due to the PSC impact of higher-than-planned oil prices. As discussed previously, we are in the process of rebalancing our drilling rig to workover rig ratio in Egypt to further optimize capital efficiency. In the first quarter, we averaged 17 drilling rigs and 21 workover rigs. While the workover rig count will remain flat, we will reduce the drilling rig count over the next 3 quarters, allowing workover rigs to be redirected. The amount of oil production temporarily offline and waiting on workover remained at around 12,000 barrels per day during the quarter. We expect to make progress on this as the drilling rig count comes down and frees up workover resources. The challenges we experienced in the fourth quarter of 2023 with faulty new electrical submersible pumps have now been fully remediated through vendor change-out and design modifications. Turning to the North Sea. First quarter production was impacted by a decrease in average facility run time at barrel in March. As a reminder, this type of downtime tends to occur more frequently and is less predictable when managing late-life assets like those we have in the North Sea. On the exploration front, we recently concluded our 3-well Alaska exploration drilling program. As a reminder, our 275,000 acre position lies on state lands, roughly 70 to 90 miles east of analogous industry discoveries. Our King Street #1 well confirmed a working petroleum system on our acreage, discovering oil in 2 separate zones. The other 2 wells, Sockeye #1 and Voodoo #1 were unable to reach their target objectives in the allotted seasonal time window due to a number of weather and operational delays. We are currently analyzing all the data and will come back later with more commentary on next steps in Alaska. Lastly, in Suriname, we are progressing the FID study on our first development project, which we hope to FID before the end of the year. Turning now to the Callon acquisition, which closed on April 1. We are 1 month into the integration process and are making very good progress. As anticipated, we are finding tremendous opportunities to reduce costs, improve efficiencies, leverage economies of scale, and create value by applying our operational expertise and unconventional development workflows to the Callon acreage. Accordingly, we have increased our estimate of annual cost synergies by 50% from $150 million to $225 million. Steve will comment further on the timing and nature of these synergies in his remarks. The most exciting and compelling value capture opportunity we see with Callon still lies ahead. That will come from capital efficiency improvements which will enhance overall development economics and potentially expand the development inventory that form the basis of our transaction value. For the remainder of 2024, we will be revising most of Callon's operational practices and workflows. This includes everything from contracting and logistics to well planning and design, drilling and completions, facility construction, and many aspects of daily operations. At a high level, you will see wider well spacing, fewer discrete landing zones, and larger fracture stimulations. Improvements in capital efficiency will manifest in fewer wells to deliver the same amount of incremental production volumes. While it will take some time to realize the full benefit of these changes, the implementation has already begun. In the meantime, we are modifying many aspects of Callon's previous 2024 plan to capture as much near-term benefit as possible. Turning now to our activity plans and outlook for 2024. In yesterday's release, we provided guidance for the second quarter and full year 2024, along with our expected oil production rates for the fourth quarter. In the U.S., we have been running 11 rigs in the Permian since April 1. We expect to average approximately 10 for the remainder of this year as we actively manage changes to the combined rig fleet. You will see the rig count change as we drop some rigs when their term ends and pick up other rigs more suitable for the planned drilling program. Similarly, we will be making a number of adjustments to our combined frac schedule. In terms of oil volumes, we noted in our first quarter materials that we expect U.S. oil production in the fourth quarter to be around 152,000 barrels per day which represents an 11% growth rate from our second quarter guide of 137,000 barrels per day. Switching now to Egypt. In February, we commented that adjusted production would remain relatively flat in 2024. Today, we anticipate adjusted production will decrease slightly as a function of the PSC impacts of higher-than-planned oil prices. And in the North Sea, production guidance for the full year is unchanged with an expected dip mostly in the third quarter as we conduct scheduled platform maintenance. In closing, we continue to manage our business with a clear and consistent strategy and deliver on our capital return commitments and financial objectives. The Callon acquisition is complete and the path to value creation is clear and well underway. Post Callon, our Permian Basin unconventional acreage footprint has increased by approximately 45% and our Permian Basin oil production has increased by more than 65%. The Permian Basin will represent an estimated 73% of APA's total company adjusted production in the second quarter and will approximate 75% of our Upstream capital this year. Notably, our oil production weighting in the U.S. will increase to a projected 46% in the second quarter from 39% on a stand-alone basis in the first quarter. Finally, Steve will discuss our priorities around debt reduction, but I want to emphasize that our shareholder return framework has not changed, and we will continue to return at least 60% of our free cash flow via dividends and share repurchases. And with that, I will turn the call over to Steve Riney.

Thank you, John, and good morning. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $132 million or $0.44 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $52 million after-tax addition to the provision for costs associated with Gulf of Mexico abandonment liabilities. Excluding this and other smaller items, adjusted net income for the fourth quarter was $237 million or $0.78 per share. The resulting adjusted earnings for the quarter include some significant exploration dry hole expenses, specifically, we took a $59 million charge for the 2 exploration wells in Alaska, which were unable to reach their targets. Additionally, we wrote off the remaining $42 million we were carrying for the Bonboni exploration well in Suriname, which was drilled in 2021, as we now have no active plans for further exploration in the Northern portion of Block 58. The total after-tax impact of these items on adjusted earnings was $88 million or $0.29 per share. In the first quarter, we returned $176 million through dividends and share repurchases. As John indicated, we remain committed to returning a minimum of 60% of free cash flow to shareholders. We are also cognizant of the need to strengthen the balance sheet, and we are looking at non-core asset sales as a source of debt reduction in addition to the 40% of free cash flow not designated for shareholder return. Our priorities for debt reduction will be the 3-year term loan we used to refinance the Callon debt and the revolver. Finally, we incurred roughly $20 million of costs associated with the Callon transaction in the first quarter and expect to incur an additional $90 million of such costs, the vast majority of which will be in the second quarter for professional services, departing Callon employees, and other closing costs. Now let me turn to progress on the Callon integration. One month into the process, we are on track to realize more cost savings than originally projected. As John noted, we have revised our annual synergies from $150 million up to $225 million. Recall, we put expected synergies into 3 categories: overhead, cost of capital, and operational. Annual overhead synergies have been revised up from $55 million to $70 million. This is moving quickly, and we will capture approximately 75% of this on a run rate basis by the end of the second quarter. We expect by year-end, nearly all of these synergies will be realized and our go-forward G&A run rate will be around $110 million per quarter. Expected annual cost of capital synergies are unchanged at $40 million. The initial refinancing of the Callon debt realized a portion of these synergies, and they will be fully realized when the debt is termed out or paid off. We are seeing the greatest amount of opportunity in operational synergies. Our original estimate for this category was $55 million, which we have revised upward to $115 million. We are making extremely good progress in this area, some of the more impactful items that we are working on include recontracting of frac services in rig high-grading, artificial lift optimization which will lower LOE and reduce downtime, supply chain synergies for casing and tubing, sand, chemicals, and other items, compression fleet optimization and economies of scale and well design improvements that eliminate extra casing strings and reduce drilling days. Further down the road, we see additional potential in areas like gas marketing and transportation and water handling disposal and recycling. To reiterate, these cost synergy estimates do not include capital productivity effects associated with improvements in well type curves and economics through well spacing, landing zone optimization, and frac size. Turning to our 2024 outlook. John has already discussed our activity plans and production guidance, so I will just touch on a few other items of note. Other than reflecting the Callon acquisition and our outlook, the most material change to guidance is associated with gas pricing in the Permian and its impact on expected near-term production and third-party gas marketing activities. As most of you are aware, Waha experienced severe basis differentials in March and April. We expect this will continue through much of May. As a result, we have continued to curtail gas into the second quarter, and our 2Q guidance now reflects an estimated impact on the quarter of 50 million cubic feet per day of gas and 5,000 barrels per day of NGLs related to the weakness at Waha Hub. Our income from third-party oil and gas purchased and sold, including the Cheniere gas supply contract, is expected to be around $230 million for the full year, which is up significantly from our original guidance of $100 million. You will also see that we have removed DD&A from our guidance at this time. We are still working on the Callon purchase price allocation and aligning our reserve booking practices. We will reinstate DD&A guidance with the second-quarter results. Finally, as a reminder, APA will be subject to the U.S. alternative minimum tax starting in 2024. We incurred no AMT in the first quarter and do not expect to in the second quarter. Based on current strip prices, we will likely incur these costs in the second half of the year. And with that, I will turn the call over to the operator for Q&A.

The first question I had, just to make sure that I understand sort of the moving parts in Egypt. So last quarter had about 13,000 that was offline. I think normally, you all cited that it would be closer to probably 5,000 offline. So you've worked it down a little bit, and I see how the rigs keep coming down, while the workover rig level stays level. But I think historically, John you all said that used to be sort of 2x to 3x the number of workover rigs to drilling rigs. So even as the rig cadence goes down the rest of the year, you still stay well below that level. So maybe just help me understand how you can get that backlog or what's offline worked down despite still being a good bit below that historical ratio? Like maybe why that historical ratio doesn't apply anymore? Or just any additional color there?

No, it's a great question. And as you acknowledge, historically, we have run a higher ratio of workover rigs to drilling rigs. Today, we're going to average 13 to 15 on the drilling rig side this year, and we're going to run right at 20 workover rigs. So it's going to take a little bit more time to kind of chisel away at that, but we're on it. It's coming down a little bit. There's also things we're doing with the drilling rigs to be able to complete some wells, which will also help some of that pressure. So it's just going to take a little bit longer, which is why you'll see a gradual move down on that number.

Got it. And then just shifting gears. Nice to see the 50% increase in the Callon synergies and obviously making a lot of progress on the cost side. You all put out previously a presentation just sort of showing all Permian results relative to legacy Callon results. I guess it won't be until 4Q, and we get to see basically wells that you all kind of started design drill completed from the get-go show up in your numbers, and you mentioned some of the things that could drive to the better well productivity, wider spacing, et cetera. Just to be clear, your guidance just assumes legacy Callon well results right? Like it doesn't assume any uplift. Is that correct in your current guidance?

Today, our guidance reflects our current situation and will depend on the wells drilled by Callon. We're making immediate adjustments on the completion side as much as possible. There are more wells drilled per section than we would typically drill, and there are additional landing zones. Consequently, we will be pumping similarly sized fracs in terms of sand loads. The main change will be an increase in fluid volumes, and we're currently working on this. We are starting with what Callon has and making modifications that we believe will be impactful. By the fourth quarter, you will see how we plan to implement full Apache workflows. Regarding our current rig count, we are operating 11 rigs—4 in the Delaware and 7 in Midland. We've moved one of the Callon rigs to Apache acreage that is ready for drilling, which has allowed us to accelerate our operations there. This process will be dynamic as we move forward, but we are eager to establish a fully planned Apache workflow and execution. There will be a transition over the next two quarters until we reach the fourth quarter.

I just had a quick one first on the Permian gas play. It's interesting the acreage and the potential returns there. I'm just wondering what would it take for you to bring some of that back? Is it just strictly that it needs to compete against your now more oily play given that Callon and the larger footprint?

Well, I mean, that is the big driver. It needs to compete internally on the oil side. And really, we measure that through Waha. So right now, you've had very, very weak Waha. Obviously, we've got Matterhorn coming on, but we're going to need to see much stronger Waha and it's going to need to compete internally with our oil projects.

No, that totally makes sense. And then just, again, maybe last one for you or Steve, just when it comes to shareholder return, you guys have continued and maybe sometime towards the end of the year, stepped a bit more into the buybacks and all. I'm just wondering, will that plan change? Or should we just think sort of more of the same when it comes to shareholder return?

No. I mean, I think big picture. We're committed to the 60%, right? We've shown that it's a minimum of 60%. And we will lean into that when we believe there's weakness, which we've historically done, and we'll continue to do in the future. That gives us the other 40% for debt reduction. We do have some non-core asset sales that we're targeting as we do believe we need to make some progress on the debt side with what we brought on with Callon, but you'll see us aggressively approaching both.

I wanted to ask a couple of questions around the capital program this year and your preliminary thoughts getting into '25 as you further integrate the Callon assets. One, can you just talk about, in this year, how many DUCs you're intending to work down and what you would carry going into next year? And as a follow-up to that, if we think about the combined company this year, should we be assuming improved capital efficiencies into next year that would sort of have you on this glide path of combined companies spending in and around $3 billion a year?

Yes, this is Steve. In relation to the capital program and the management of DUCs, we have incorporated additional frac capital to reach the $2.7 billion in our plan for this year. We merged the final three quarters of Callon's remaining capital program with ours and included more frac capital in the latter half of the year since both companies were increasing DUCs. At this moment, I think it's prudent not to discuss specific numbers, as the program is still evolving for the second half of the year. We're currently assessing our approach. As John mentioned, we are modifying much of the planned activity on Callon acreage for later this year. After four weeks, things remain somewhat unsettled. We might provide more clarity during the second quarter earnings call in August, which would allow us to finalize the remaining plan for the year. Generally speaking, we think it's not capital efficient to maintain a large number of DUCs. While having some DUCs can be beneficial due to the need to align frac and drilling schedules, we do not support carrying excessive DUC inventory.

And the only thing I would add is, obviously, we believe the capital productivity will improve on the Callon portion especially as we go to our modifications and our workflows in the back half of the year. So combined companies going to improve and we're seeing that productivity on the Apache side right now, and we'll get the Callon assets there towards the back half of the year.

No, we don't have any specific targets in mind. But what we recognize is that even after the progress that we made in '21 and '22 on debt, for Apache Corp. We knew that we needed to make more progress and we didn't make as much as we might have wanted to during the intervening time, and we just feel like we need to get on with that and get debt down. And now that we've added some debt through the Callon acquisition, we're going to just try to focus on that this year. We think it's a good time to be doing that. The market seems to be strong for some of these non-core assets and we'll see if we can get some of those off and get some good prices, and they will be focused on debt reduction.

And do you think there's a path to getting there within the next couple of years?

That's what we're trying to achieve. Yes. I think it's possible, and we're going to certainly give it a try.

I really appreciate the color or the guidance that you have given for 4Q pro forma production for U.S. oil. If we think out to 2025, like Apache is delivering double-digit organic growth in the Permian this year. Do you expect to see continued growth on the combined assets going forward? Just thinking about the overall strategy, like approach from a growth outlook perspective?

Yes. Betty, what I'll say is, post the Callon merger, our Permian now makes up roughly 75% of the company. And we've been executing at a high rate on the Apache side. We're anxious to provide those workflows on the Callon side. We have added a little bit of capital, which is going to work down some of the DUCs in the fourth quarter of this year. So, I mean, it's early to comment on 2025, but it's going to give us a lot of strong momentum as we exit 2024 with a very strong fourth quarter. So we're very anxious to demonstrate that, and we're very confident in what we can deliver from the Permian.

I wanted to add one thing to that. One of the reasons we increased frac capacity in the second half of this year is that frac services are quite affordable right now, making it a good time to invest. Additionally, given our scale of operations in the Permian Basin, which now accounts for 75% of our company, we should be able to manage our activities better to avoid significant fluctuations in completions and production. Our goal is to enhance capital efficiency while creating a more consistent production volume profile. By increasing frac capacity in the latter half of this year, we aim to smooth out potential volume dips, particularly to avoid any downturn in the first quarter, which we want to prevent as we move forward.

Great. I appreciate that color. Shifting gears to Egypt, a similar question. This year, seeing that growth of Egypt volume is down a little bit, but a lot of that related to the workover rig shortage. If we look out post the PSC contract renegotiation, there was an expectation of Egypt growing in the single-digit range. Do you expect to go back to that type of profile? When do you think that asset will be ready to do that?

Yes. I mean you've got one factor in Egypt is costs are a big picture gas has been declining. So the gross BOEs have been declining because of that, and we've been growing the oil. We're in a place today where we're working to rebalance the workover rigs and the drilling rigs and find a good level in there where we can drive that production base. So we'll monitor that over the year and come back later this year with projections in terms of what we'll do next year. And quite frankly, how Egypt continues to compete with what we're doing in the Permian will play into that as well.

I wanted to follow up a little bit here on Egypt. I wanted to just kind of get a sense from you folks what the situation is with the receivables there in country. I saw that Egypt recently got an IMF loan a little bit ago. I'm not sure if that's kind of improved the state financial well-being there. So maybe you could just kind of speak to that? And then also, could you speak a little bit to kind of your expectations for gross Egyptian oil volumes? I know you talked a lot about sort of net, but it looks like growth has come down in the last few quarters. How do you expect the growth trajectory on the gross volumes to trade over the next couple of quarters?

Okay. This is Steve. Regarding receivables, we have been closely collaborating with the Egyptian Government. We received two payments in the first quarter of this year. However, receivables slightly increased in the first quarter of 2024, particularly due to oil prices. We made significant progress in reducing receivables throughout 2023. While there was a slight increase in the first quarter of 2024, it remains below last year's average. More importantly, Egypt is currently on a positive trajectory. They have floated and devalued their currency and raised interest rates to manage inflation. As a result, bond values are rising, and the ratings outlook is becoming more favorable. The IMF has expanded its loan program from $3 billion to $8 billion, and there has been a substantial influx of investment from Gulf states, mostly in real estate. Support from both the World Bank and the EU has also been pledged. While the journey won't be easy or quick, the overall situation is improving. Liquidity is getting better, which is a positive development for us going forward. The Egyptian government has indicated we can expect a large payment in the second quarter of this year, and we plan to visit Egypt around that time. The situation with receivables has remained relatively stable in the first quarter, but the indicators within Egypt are encouraging. As for gross volumes, we haven't seen a decline for two consecutive quarters. Gross oil volume was fairly flat in 2023 before it began to rise. We are experiencing a decline from the fourth quarter to the first quarter, largely due to the timing of completions. Last year, we completed 27 new wells in the third quarter, 26 in the fourth quarter, and 17 in the first quarter of this year. Therefore, a slight decline in oil volume this quarter is not unexpected. We are reducing the drilling rig count, which will impact the number of wells available for completion. We will monitor the situation on a quarterly basis. Additionally, we need to balance the use of workover rigs and workover capacity with our drilling capacity, as it's not a cost-effective strategy to drill new wells when workovers yield better returns. While drilling new wells is necessary, workovers are more economical and typically restore significant production volumes. We must ensure we have the capacity to manage the workover program effectively. We have several strategies to address this and might consider bringing in additional workover rigs in the long term, but we have many options to explore before reaching that point. In 2024, we have a lot of work to do to achieve a proper balance between drilling new wells and performing workovers. As we approach 2025, we will provide a clearer outlook on Egypt's progress.

All right. That was very helpful, very good explanation there. And I guess just maybe turning to Suriname very quickly here. Just wanted to kind of get a better sense of kind of where things stand. I know you're still working towards FID. What's your confidence level with your partner on achieving that later this year? And it sounds like there's still no drilling happening in '24, but does Apache anticipate some drilling there in '25?

Yes, I'd just say we're very confident it will still be underway, and we would anticipate an FID by year-end. So it's all moving forward there. And then that's going to dictate timing in terms of drilling we've got till 2026 to start the exploration program. So there's nothing pressing on the '25 side, but we could be back to drilling in '25.

John, I wanted to spend a little bit of time talking about the Callon cost synergies. Specifically on the operational side, you're talking about high-grading the service providers. Can you just spend some time getting us on the ground and giving us a little bit more granularity around some of those cost synergies on the operational side?

Yes, I'll jump in, and I'll let Steve add a little bit more color. But in general, we're changing the program. So you're going to see fewer wells per section, fewer landing zones, larger fracs in general. The other thing is when you look at the well count in terms of how they complete their wells, Callon was putting 1/3 of their new wells on ESPs and 30% on gas lift. We've been running outside of Alpine High about 3% ESP and 60% gas lift. So that's the other place in terms of just how we're equipping the wells, how we're flowing the wells and producing the wells, and then obviously, the power then that is needed to drive those sub pumps is another big factor. I'll also say that they turnkeyed a lot of their stuff. I mean they turnkeyed a lot of their frac operations, and we're going to self source and do a lot of stuff there. So there's a lot of low-hanging fruit on the operations side. So those are some of the big ticket items. And we've already seen a lot of that, which is why you've seen us increase a lot on the operational side.

Yes. Neil, I want to point out that if you review the Permian slide deck we published in February, we highlighted three areas where we think Callon is significantly off track regarding their LOE per BOE, workover costs per BOE, and downtime percentages. They have a history of a much higher well failure rate, particularly for new wells, and experience more ESP failures than we do. We believe this is linked to their equipment choices, and we are proactively addressing this, even with some of the wells they have already drilled, completed, and equipped. There has been a lot of inefficiency concerning compression and their compression fleet utilization. We can achieve better economies of scale through compression optimization and negotiate improved rates for compression costs across a broader range of operations. As John mentioned, they tend to rely heavily on ESPs for which they incur high power costs, a significant contributor to their LOE per BOE. They also use a lot of contract labor and miss out on the advantages of our supply chain, including using APA rates for services and products, and benefiting from volume discounts across our larger operations, which helps reduce overall usage. Their water handling and disposal costs are very high, and we believe we can improve that significantly. They also have a high rate of rentals for ESPs and compression equipment, where we see opportunities for better management. On the capital side, we will employ more technology to shorten average drilling days per well, secure better rig rates, and handle rig moves more efficiently, so we’re not shifting rigs between the Delaware and Midland Basins. We plan to use spudder rigs for many of our wells, a practice they typically do not follow. We will enhance frac rates and proppant costs through better supply chain strategies. In terms of facilities, while they usually build to specification, we prefer to modularize. We typically use multiphase flow through a single line, whereas they often opt for test separators and separate products into three different lines. Overall, we see numerous areas for improvement that will help us reduce LOE per BOE, lower downtime, and decrease workover costs.

Steve, I apologize. When you mentioned dry holes, I missed that part. Could you please repeat it? I believe you're referring to a share value on Block 52 that's around 40 million. What about the remaining driver expense at 123? The second question is yes, please proceed.

I'll jump in. There is one dry hole in Suriname, which was related to Bonboni in the north. We held off for a while because we were uncertain how the northern area would influence future exploration. That's why we made that decision now. Then, in Alaska, we decided not to proceed with two wells that didn't reach total depth since we found it easier to return and redrill those prospects with new wells. That's what the dry hole expenses were for.

I see. John, regarding Alaska in the King Street discovery, can you share the thickness of the data you have? Do you have any information about permeability or anything else you can provide?

Well, it's very preliminary, Paul. But we're excited about both. These are not shallow wells in the Brookie play; they are high-quality oils. We were also very pleased with the early data, but we need to analyze the rock data in the lab before sharing more details. I think one of the important takeaways from King Street is that it was the smallest and riskiest of the three prospects, even though we were able to complete it. However, there is a very positive indication in the Upper Zone at King Street for the larger target in Voodoo, which is exciting. If anything, this makes us feel even better about the program and the acreage moving forward. We've moved 70 to 90 miles east of an active hydrocarbon system into a truly wildcat area, and now we've demonstrated the presence of a petroleum system. We've confirmed oil, and there's also very high-quality sand present. So there's a lot to be excited about going forward in Alaska.

Right. And John, you're saying that you're going to drill the 2 new wells for Sockeye and Voodoo. Is that going to be done? Or is that going to be drilled in the next drilling season? Or that you guys have not decided and may get pushed out further?

It's highly likely that we will redrill both prospects, but we need to coordinate with our partners, and decisions regarding the 2025 drilling program are not urgent at this time. We will be discussing this with our partners over the next several weeks. While it's possible that the work could take place in 2025, it's not necessary for it to happen that year, and we will continue to collaborate with our partners on this matter.

Yes. Thank you. In closing, our Permian is performing extremely well, and we have just bolstered it with the addition of Callon and is now approximately 75% of the company. We will be integrating Callon over the next couple of quarters. And by the fourth quarter, you should start to get a good picture of what we can do with the Callon assets. We have pulled from some frac capital into the second half of the year, which should really give us strong momentum as we head into 2025. On the cost synergy side, we have increased our expectation by 50%, and we'll capture most of these by year-end and we believe there is even more to do beyond that. And lastly, we'd like to make more progress on debt reduction by the end of the year while also meeting our 60% shareholder return commitment. Thank you very much for joining us today.