APA Corporation (APA) — Q3 2020 Earnings Call Transcript

Good morning and thank you for joining us on Apache Corporation’s third quarter 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 summarize our third quarter financial performance; Clay Bretches, Executive Vice President of Operations; and Dave Pursell, Executive Vice President Development will also be available on the call to answer questions. Our prepared remarks will be approximately 10 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 third quarter financial and operational supplement, which can be found on our Investor Relations website at investor.apachecorp.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 non-controlling interest in Egypt and Egypt tax barrels. Finally, I’d like to remind everyone that today’s discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

Good morning and thank you for joining us. On today's call I will review our third quarter performance, provide some preliminary color on our 2021 plan and update our progress in Suriname. While commodity prices improved and were less volatile during the third quarter, macro headwinds continue to persist. Apache's strategic approach to creating shareholder value, however, remains unchanged. We are prioritizing long-term returns over growth, generating free cash flow, strengthening our balance sheet through debt reduction, and advancing a large-scale opportunity in Suriname. We are allocating capital to the best return opportunities across our diversified portfolio, aggressively managing our cost structure, and continue progressing important safety and emissions reduction initiatives. Apache believes that energy underpins global progress, and we want to be a part of that conversation and solution as society works to meet growing global demand for reliable, affordable, and cleaner energy. As we work to help meet global energy needs, we are focused on developing innovative and more sustainable ways to operate. Our environmental, social, and governance framework continues to evolve, and early next year, we will communicate more on the enhancements we are making in these areas. We want to be a partner to the communities where we live and work and deliver shared value for all of our stakeholders. Turning now to the third quarter. Our upstream capital investment, lease operating expenditures, and G&A for the quarter were all below guidance. The organizational redesign we initiated a year ago is delivering combined cost savings in excess of our previous estimate of $300 million on an annualized basis. In terms of production, we exceeded our guidance in the U.S. and delivered in-line volumes internationally. U.S. oil volumes declined 11,000 barrels per day or 12% from the second quarter. This was the result of several factors. The most notable of which was our conscious decision to suspend Permian Basin drilling and completion activity back in April. Additionally, we implemented a series of intermittent shut-ins in the Southern Midland Basin to assess optimal well spacing. And lastly, we chose to leave approximately 4,000 barrels per day of oil shut-in during the quarter, primarily from the Central Basin platform, most of which we do not anticipate returning to production until prices warrant. By early July, most of our shut-in volumes at Alpine High had returned to production, which drove the increase in gas and NGL volumes compared to the second quarter. We are now seeing very compelling service costs in the Permian Basin. And as a result, have retained 2 frac crews to begin completing our backlog of drilled but uncompleted wells. We are mindful of price volatility and will take a flexible approach to the flow-back timing of these wells. Regardless, there will be no impact from this program on our fourth quarter Permian production and minimal impact on our full year 2020 capital guidance, which we have reduced to $1 billion. Looking ahead to 2021, we anticipate an upstream capital budget of $1 billion or less, which is based on a WTI oil price of approximately $40 per barrel and a Henry Hub natural gas price of $2.75. In this price environment, our capital allocation priorities will remain unchanged. We envision a stepped-up program in Suriname that will include both exploration and appraisal drilling, a 5 to 6 rig program in Egypt, 1 floating rig and 1 platform crew in the North Sea, and 2 frac crews in the Permian Basin. We do not envision a sustained drilling program in the Permian, but will monitor oil prices and service costs for the appropriate time that they serve. Let me be really clear. If NYMEX futures are materially below $40, we are prepared to reduce capital accordingly as we have demonstrated in the past. As previously noted, we plan to direct nearly all free cash flow in 2021 toward debt reduction. In terms of production trajectory next year, our DUC completion program should stabilize Permian oil volumes at a level consistent with fourth quarter 2020 levels while Egypt and the North Sea will likely see modest declines. Turning now to Suriname. During the third quarter, we completed operations on our third successful exploration test in Block 58, Kwaskwasi, which is our best well in the basin thus far. We are currently working with our partner, Total, on an appraisal plan, which will be submitted to Staatsolie before year-end. Following Kwaskwasi, we commenced drilling our fourth exploration well, Keskesi in mid-September. We have also selected our fifth exploration well, Bonboni, which will be situated in the North Central portion of Block 58. Apache is in the process of transitioning operatorship of Block 58 to Total, who will conduct all exploration and appraisal activities subsequent to Keskesi. I want to close by thanking our employees worldwide for maintaining safe operations, delivering on our key business goals and helping to minimize the spread of the coronavirus in our workplace and communities. Our field personnel have done an exceptional job instituting operational protocols that enable business continuity and our office staff successfully adapted to the remote work environment. That said, we look forward to returning Apache employees to the office in the future.

Thank you, John. On today's call, I will review third quarter 2020 results, discuss progress on our balance sheet initiatives, and provide a few thoughts on our fourth quarter guidance. As noted in our news release issued yesterday, under Generally Accepted Accounting Principles, Apache reported a third quarter 2020 consolidated net loss of $4 million or $0.02 per diluted common share. These results include items that are outside of core earnings, the most significant of which are an unrealized gain on derivatives and an impairment for unproved leasehold. Excluding these and other smaller items, the adjusted loss was $59 million or $0.16 per share. U.S. production increased slightly from the second quarter as the return of curtailed production volumes, most notably at Alpine High, more than offset the declines resulting from no drilling activity and only 1 well completion in the quarter. Internationally, adjusted production was down approximately 6% from the prior quarter, primarily driven by the impacts in Egypt of higher oil prices on cost recovery volumes and natural field declines. This was partially offset by the return of previously curtailed production in the North Sea. Apache's third quarter average realized price on a BOE basis recovered significantly from the prior quarter, up 45% as WTI oil prices averaged around $40 per barrel and Henry Hub natural gas prices trended up to nearly $3 per Mcf by the end of the quarter. G&A expense in the quarter was $52 million, well below our guidance of $80 million. Most of the variance reflects a mark-to-market change in the value of future cash settled stock awards and a reduction in the estimated value of our 2018 and 2019 performance share programs. Excluding these types of impacts, our underlying G&A expense runs around $75 million per quarter. As always, efforts will continue to lower our G&A costs as we identify more ways to run the company more efficiently. Lease operating expenses were also below guidance for the quarter. On a per unit basis, LOE declined nearly 25% from a year ago, mostly as a result of our corporate redesign and cost reduction efforts. I'll turn now to our balance sheet initiatives. In August, favorable market conditions provided an opportunity to refinance a portion of our debt at attractive rates. We issued $1.25 billion of new bonds. And including the debt repurchased in the second quarter, we will use all proceeds to reduce other long-term debt. Specifically in 3Q we used proceeds to tender for $644 million of existing debt at a slight discount to par. Additionally, this week, we called at par the remaining $183 million of notes scheduled to mature in 2021. Between now and the end of 2023, we have only $337 million of debt maturing, which we plan to retire with free cash flow. Apache's liquidity position remains in very good shape. At September 30, we had just over $3 billion of borrowing capacity available under our revolving credit facility. The vast majority of the consumed portion of the facility is for the letters of credit associated with future North Sea asset retirement obligations. Before wrapping up, I'd like to point out that we issued fourth quarter 2020 guidance yesterday and our financial and operational supplement which can be found on our website. As John noted, we expect our full year 2020 upstream capital investment to be around $1 billion. This implies an uptick in fourth quarter capital to around $200 million, which reflects some incremental capital associated with the DUC completion program that is beginning this month. While we continue to make good progress on our lifting costs, reported LOE is expected to rise a bit in the fourth quarter to around $270 million. This increase simply reflects the quarterly variations caused by timing impacts. In summary, Apache continues to make steady progress on the goals we set for the year. While the operating environment remains challenging from a commodity price and cash flow perspective, we continue to take every possible action to reduce our cost structure, protect the balance sheet, and retain asset value for the future.

Yes. For my first question regarding Suriname, I want to clarify that when you mentioned you're close to awarding the two rigs for 2021, it doesn't necessarily mean you'll only have one exploration and one appraisal rig next year. That's what you're currently planning, but there may be more activities planned as you move through 2021 in Suriname.

Yes, John, what we've got is we've said there'll be 2 programs, both an exploration and an appraisal program. We're currently on our last well, Keskesi, with the rig that we're operating, the Noble Sam Croft. That will be released once that well is concluded, but we're in the middle of the tender with Total, and they're going to be picking up 2 rigs early next year. And there will be a combination of exploration and appraisal with those 2 rigs.

And then as you go through the rest of '21, I guess, when you decide whether or not you and Total, if you're going to add additional rigs to the plan, is that driven in some ways just by the timing of receiving approval on these appraisal plans on the first three wells?

No, that will just be a decision we make based on which wells you want to pull forward and how you want to play it. So the 2 rigs are going to be a minimum for next year.

Okay. And then just the 1 follow-up on Suriname, maybe just some additional color on what went into choosing the other location on the Bonboni well. Obviously, up to this point, you've kind of been moving in kind of a West-East direction across the block. Does this now assume we're set up to kind of go from a North to South kind of direction?

John, looking at the bigger picture, our plan has always involved this approach. The initial four wells were strategically aligned to move in one direction, consistent with the trends observed in the surrounding wells to both the East and West, and there is currently a rig operating on the opposite side. It's important to appreciate the vastness of Block 58 and Block 53, which together are equivalent to over 250 blocks in the Gulf of Mexico. Moving in a single direction represents a significant step. We've mentioned the considerable depth, as there are multiple independent features extending outward. We're eager to proceed with the Bonboni well, which will be our fifth, slated for drilling early next year by Total. We are also looking forward to exploring the North Central section and demonstrating the full dimensions of the block. It's an exciting time, and we anticipate continuing our exploration pace next year. We're also keen to begin the appraisal process, so there's a lot to look forward to.

I just had a question in regards to Suriname. When you guys look at what you have done upward Block 53, can you just talk about what you learned there in those original 2 wells drilled and how that has helped you influence some of your decision process on the exploration activity?

Well, Gail, if you go back to early 2015, we were drilling our first well Popokai and it was actually drilled ahead of the Liza well in the Stabroek Block. So you go back in time, the main thing that Popokai did for us was it helped us inform us that, one, we wanted to go ahead and pick up Block 58. So that's the first thing. I would say secondly, we actually were able to drill the thing all the way down through the source interval and gain a lot of information with it. The second well, Kolibrie, was further outbound, really drilled some really, really high-quality sands and told us a lot about that. So I think Block 53 is highly prospective. I think the well that's being drilled next door to us will be very informative. I think our Keskesi well will be very informative and also Bonboni. So we've got 1 well commitment left at in Block 53, but I think it holds a lot of promise for the future. So it's sitting nice. I think with the work we've done since, there's a lot of potential in Block 53.

Great. And then just looking at those incremental cost savings that you guys have achieved with the portfolio optimization, where are you guys thinking that breakeven is today on the assets?

Yes, I mean if you go back to last quarter, we talked about where our volumes were. We have moved kind of from a $50 to low $30s kind of going forward this year. Next year, it will tick a little higher because our volumes are going to be down. But I think, generally, we're in a pretty good place, and we continue to surprise ourselves by what we're able to drive out of the cost structure. I mean we've driven another $100 million out. Steve, I'll let you hop in and provide a little bit more color.

Yes, Gail, I want to emphasize that we are still focusing on cost-cutting measures. What surprised us this year is the speed at which we've managed to achieve these savings. Currently, we have around $400 million in annual savings, and we expect to realize at least $300 million of that this year, possibly even more. As John mentioned, we are witnessing a decline in production volume as we approach 2021, which negatively impacts our cash flow breakeven, especially in the U.S. oil market. However, this may be balanced by the annual cost savings we are projected to realize next year. That said, the cash flow breakeven point of $30 per barrel is likely to rise slightly as we move into 2021.

John, just maybe a follow up to Gail’s question if I may on Popokai. Give me a minute to ask this. So Popokai as I understand that was a tight hole. But our discussions just solely suggest that the failure mechanism was reservoir quality, and it's kicked off some controversy given that we haven't got any data in the first 3 wells that you drilled. So I wonder if you could put that to rest and talk to us about reservoir quality of the 3 wells? And I'd like to remind you, obviously, that the Maka well, you did say you saw it capable of prolific oil. So any data you can give us to put that to rest on the 3 discoveries? I've got a follow-up, please.

We haven't released much data on Popokai, and it was limited. The critical aspect was recording the source interval, which indicated no issues with reservoir quality in any of the zones. There were other factors at play, but the data we obtained from the source interval was significant, allowing us to understand maturity and its implications for Block 58. As for the information shared with Total, both parties agreed on what has been released, including the net pay for both the Campanian and Santonian numbers. We are confident in those figures, and overall, the quality looks promising. However, to provide more detailed insights, we need to complete our appraisal work, and we will approach this cautiously, ensuring the information we release is reliable. Contrary to some notions we've heard, any errors would not arise from the logging suite or the detailed core analysis we are conducting. We are optimistic about the reservoirs but require further appraisal to share more insights. This is a conventional play, and there are reasons to progress to the next phases. We are in a super basin, which is extensive and contains very good rock, and we are satisfied with our position, yet it's still early in our fourth well to discuss matters typically addressed after thorough appraisal, when we can provide solid information.

No evidence from the logs. I guess, just a clarification point real quick. When you announced Kwaskwasi, you've obviously talked about the cementing problems. Could you lose circulation into the reservoir on that well?

What we mentioned was that we encountered higher pressure than our target in the lower Santonian. This was not due to losing circulation. The key issue was determining what we needed to do to place the cement plugs. We had to inject a significant amount of fluid into the well from the opposite direction. This action affected our ability to remove fluids from the Santonian because we had an open hole that needed to be sealed over time. The situation was primarily related to the drilling operations rather than cementing issues. To clarify, we had to set two cement plugs below the Santonian due to the pressure we were facing, and the open hole above us hindered our ability to manage fluids later on.

To be clear, the reason I'm asking the question, it was around about way you're trying to get that reservoir question answered because seems to me if you overpressured the reservoir and lost mud into the reservoir, is a very porous permeable reservoir, that's why I was asking the question. My follow-up real quick is Bonboni, I guess, that’s how you pronounce it. Any source or migration differences in the depositional setup there geologically compared to what your first 3 targets look like or first four targets look like? I'll leave it there.

Bonboni is indeed exciting. We will be targeting both the Campanian and Santonian formations. There is also a chance to delve deeper and explore additional aspects. These targets are located at a good distance, and I believe this will allow us to explore another dimension of this block, which we find very promising. The main targets will remain similar, and you will see these targets as we progress with the upcoming wells. Much of our focus will be on the Campanian and Santonian. However, I want to emphasize that we have other targets that we will address at some point.

Kind of repeating on a similar theme. If we think about Block 53, I note that you've included it back again into some of the materials, you've got a single well remaining to meet your commitment. Are your partners aligned with potentially drilling a well in '21 or 2022?

Yes. Bob, I'll say our partners would love for us to get back in there. And it's not that we ever excluded it, it's just we've been focused on 58. 53 is something we made a well commitment on that we've got to actually drill before the spud before the end of the second quarter of 2022, and it's something we're very excited about. We've got 45% of it. I can promise you 2 of our partners, 1 of them is in the well that's being drilled South of there right now. So yes, they're anxious, and we will get to it in due course, and we're anxious, too. But there's a lot of activity that's going to be very informative on the potential in Block 53.

Great. A quick follow-up. The water depth for Bonboni, I can probably look off the symmetry, but if you have that handy?

I don't have that information readily available. It's not too surprising. It will be more detailed, but it's not anything out of the ordinary. I'm looking at Clay, and he might have more insight. But I don't believe it's anything extreme. We can have Gary follow up on that.

In the Permian, how many DUCs do you have? How long can you keep 2 frac crews working without adding any rigs down there?

Yes, Scott, this is Dave Pursell. We have about 45 DUCs in the Permian. We'll pick 2 frac crews up here later in the quarter. And those will stay busy through the middle of next year.

Got it. And then you also mentioned a flexible approach to flowback timing on those completions. Obviously, post-completion, the well cost is basically sold. How do you think about flowback strategy on those? I assume there's more price threshold you're thinking about, but some color there would be great.

Yes. We will evaluate several factors as we bring the wells back online. We have five, three-mile wells that we are reactivating, and we will keep those facilities constrained for some time. Our focus will be on the future price trends and the flowback performance of the wells, which will inform how aggressive we choose to be with the chokes as we approach the end of 2021. We want to maintain some flexibility due to the volatility in oil prices.

John, for the Bonboni, what is the depth that you have to drill below the seabed to reach the TD?

Yes, the thing is that the targets will be a little shallower below the seafloor as we move in that direction, Paul. This shallowing is actually a positive development from a maturity standpoint.

Okay. And that for next year, the CapEx of $1 billion for maintaining the U.S. production spread and modest decline in loss in Egypt. But of course, that benefits on the top. So without the top benefit, what's that number may look like?

Well, there are two things to consider, Paul. First, we are investing a significant amount in exploration as part of our capital expenditures. We are consciously choosing to direct funds into Suriname instead of our base business. I can assure you that the investment in Suriname is greater than what it would cost to operate those two frac crews. If you step back and think about our decision regarding exploration investment, it's capital that we could be using for the base, but we are opting for a long-term strategy because we believe it will yield much greater benefits in three to four years.

No, fully understand the decision, but I'm just curious what that number if we're saying that in 2021 on the sustaining CapEx without the benefit of top. And also one on Suriname, I thought, Total carry you for 87.5%. So your CapEx to that shouldn't be that much, is it?

Well, but the Total carry actually kicks in on the appraisal work. And so we're going to have 2 rigs running. So there will be exploration activity at a pace. It's pretty similar to what we've been spending this year, right? And then the appraisal capital kicks in. And on that, we will be paying 12.5% on the appraisal work.

Okay. Two final questions. First, if the oil price end up next year swing much better than the $40 WTI base budget, how that may impact if it does on your 2021 CapEx and the activity level? And then last one...

Yes. I mean, clearly, our priority there is going to be debt repayment. I mean there's more with the $1 billion or less number we've kind of laid out for 2021, that's predicated on $40. If prices are higher, you're going to see us continue to prioritize debt repayment. But there are some things we'd like to get to, more capital in Egypt is something that would be a priority for us. But that's going to be the big thing. And then I think you'd have to get quite a bit higher before we start thinking about rig lines in the Permian. No. It's been a busy time, and we've seen a lot of transactions happen out there on the M&A front. I think as you alluded to with how we're trading, we're in a pretty unique position where we've got a potential company-changing exploration block that we feel like actually, there's a lot more potential there than is reflected on our share price. As we think about things, clearly, we're focused on paying down debt. You see we're really aggressively managing our cost structure, working on the breakevens. But I think from our perspective, we've got to make sure something would really makes sense for our shareholders and protect the shareholders because we see a lot of upside potential on a relative basis with our share price just because of the potential in Suriname. So you can't stick your head in the sand, you have to keep your eyes open, but we're going to be very cognizant of shareholder value.

I have 1 quick question and then maybe a bigger follow-up. John, I didn't hear you address it in your prepared comments. I apologize if I missed, but did you give a timeline when we expect a decision or announcement on your Keskesi well you're on right now?

We did not provide a timeline, Charles. We are making progress with our drilling. We encountered some stability issues in the upper section, but we have redirected our efforts and set the necessary equipment to continue. We have not yet reached the deeper zones, but the wells are performing well, and we're eager to proceed. Overall, things are going well.

Good. I appreciate that information, John. Regarding Bonboni, we have many more questions, and I’m sure you would like to address them now. However, you've already provided some insight that these are the same Campanian and Santonian intervals you are targeting, but at shallower depths due to some geological features. Can you elaborate on whether these are likely more like large basin floor features as you move northeast? Is that a reasonable assumption, or is there something else you can share about this play compared to what you've established with your series of four wells?

No, I can answer one of the questions about the water depth. I think we're in about 2,000 meters of water with Bonboni. What's happening is, as we mentioned, there are very significant independent features like turbidite fan systems. What you're giving up is a bit of water depth in exchange for the depth of the formation. They do become slightly shallower, which we believe will positively impact maturity. But they are large, Charles, and that's important to highlight at this stage. We need to go out and explore, and we are excited about these features. They look fantastic on seismic, are sizable, and there's plenty of area to cover between Maka, Kwaskwasi, Sapakara, and Keskesi as you move towards Bonboni. The Campanian and Santonian formations are a bit shallower, but they are very large features, and there are some deeper formations that we might also be able to access.

Hess mentioned on its call that there are 5 penetrations in the Santonian, in the basin, your 3 and then 2 on the Stabroek block. And it sounds like currently drilling Exxon exploration well and Guyana is expected to test both the Santonian and the Turonian. Just curious if you're sharing any data with your neighbors there? And if so, anything you can say about what you've learned there about those deeper zones?

Mike, at this point, we haven't found significant benefits from our work, aside from what Haimara might have contributed. This situation highlights the number and quality of targets we possess. The Guyana Basin is proving to be an exceptional area with mature and actively generating source rocks. We have multiple high-quality targets, and we've successfully explored both the companion and Santonian layers. A lot of our findings will inform our appraisal as we dive deeper into planning for the next steps after the appraisal phase. The data indicates substantial thickness and ample sand presence, as we recorded over 900 feet in the Kwaskwasi across two zones. This underscores the richness of targets available in this environment.

Very good. And can you talk about your decision to complete the DUCs in the Permian rather than to generate more free cash flow? And will all of those be in the Midland Basin? Or are you planning on completing any Alpine High if gas prices continue to improve?

I believe the first three wells will be in Alpine High. There will be three there and the majority in the Midland Basin. The main reason for starting this now is the opportunity we see in service costs, which have decreased significantly since the first quarter. We view this as a chance to get the wells completed, providing us flexibility in terms of how and when to bring them back. This decision is based on cost considerations, and these are wells we'll eventually complete, so we see it as a good time to utilize two frac crews and efficiently get the work done.

To follow up further on Suriname, you made a couple of references here deeper zone or zones below the Santonian. And I wondered if you could talk any more about that and whether what you would potentially down the road or as part of this well at Bonboni test. How applicable those ones are? How prospective those zones could be across Block 58? And then separately, as you think about 2021, can you just remind us on where you see the ratio of exploration wells versus appraisal wells?

It is likely to involve more appraisal work than exploration, but you can expect a similar pace with two rigs. There will be multiple exploration wells, but we will have the flexibility to conduct both types of work with those rigs. As we move forward, you will see the programs blend as we prioritize our activities. When we began our initial work, we identified eight different play types on Block 58, and so far, we have tested two: the Campanian and the Santonian. We have encountered both in the first three wells. We attempted to reach the Turonian but encountered excessive pressure in the Santonian at Maka. The Turonian is clearly one of our next targets, and we are deciding when and which well to focus on. We believe there is significant potential there. Additionally, there are five other play types, including pre and post unconformity and even deeper formations, but those are topics for future discussions. There is a lot of opportunity in this block.

Great. And then my follow-up is with regards to the cash costs. You talked about some of the volatility from quarter-to-quarter and how strong cash costs and LOE was this quarter, but that that's not necessarily sustainable. Can you just remind us again kind of where you see that path and what you kind of see as a sustainable LOE relative to this last quarter and your guidance for the fourth quarter?

Yes. Brian, regarding specific numbers, it's best to discuss those in more detail when we review 2021, usually in February. However, I can say that we addressed G&A costs promptly due to our organizational restructure, implementing most of it in the first quarter, which resulted in a significant decrease in G&A quickly. Adjusting LOE takes a bit longer, but we are seeing a notable reduction as we progress through the third quarter and into the future. There are still some ongoing costs to tackle, and you can expect continued benefits as we head into 2021 and beyond, particularly if the price environment remains stable. LOE can be unpredictable since it is influenced by factors like maintenance spending, turnarounds, and workover activity, which impact operating costs more than G&A, which tends to be more stable. Regarding G&A, we sometimes encounter unusual accruals, as we did this quarter. Instead of providing a precise quarterly OpEx or LOE figure at this moment, let's wait until February when we can offer more context and guidance for 2021.

I just wanted to follow up a little bit on Suriname here. You certainly talked about starting to get after an appraisal program in 2021. You also talked a couple of times about some of these deeper zones. Do you think that the deeper zones, in particular, the Turonian are going to be part of the appraisal plan already here as you look at a few of the wells, Maka, Sapakara, Kwaskwasi? Is that contemplated already for '21?

At this point, we haven't explored or reached the Turonian, so it would be premature to consider it an appraisal until we can successfully explore it. We may identify a location where we take an appraisal well, deepen it, and include an exploration component, but we'll see how we proceed with that. Currently, all our appraisal efforts will focus on already quantified discoveries.

Okay. That's helpful. And I guess you guys obviously laid out a plan to hold your 4Q '20 premium oil volumes flat next year. You talked about kind of modest declines in North Sea and Egypt. Just trying to get a sense, you are running quite a few rigs in Egypt there. If you can kind of help us out with any kind of order of magnitude of those declines? Are we talking kind of 10%, kind of single-digits? What are you guys thinking here for North Sea and Egypt next year?

Yes. If you look at our overall decline, both areas are around 25%. In North America, the decline comes from a mix of unconventional production, which is higher, and conventional production, which is lower. For the North Sea, declines are in the 40s, but the production is a bit higher, still around the 25% range. We will be active there, but it's a modest decline. Egypt has really good conventional rock, with an average decline rate close to 25%. We started the year with about 10 rigs in Egypt, which helps maintain or even grow production. However, after reducing capital expenditures, we dropped down to 5 rigs. Operating with 5 to 6 rigs is not much given the size of our position and the levels of production we have there. So, when we say modest, it means it’s less than what our natural base declines would typically be.

I want to avoid Suriname completely. My question is about Egypt. You have been operating with a 5 rig plan for some time now. Did the economics support this continuous approach? Is there a possibility of increasing activity there? Can you share some insights on the current operations in that area?

Yes. We started the year with 10 rigs, but we reduced that to 5 due to necessary capital cuts across the board. Currently, our cash flow is not sufficient to increase our activity in Egypt despite having the desire to do so. While we're focusing on generating free cash flow and paying down debt at the corporate level, Egypt is providing some free cash flow. There is potential to double our rig count there, but we need to consider how much we can allocate to Egypt within our overall strategy.

No. That makes sense. Regarding allocation, considering the current gas prices, do you have any thoughts or comments about possibly revisiting Alpine High, even if only at a minimal level?

Yes. As I mentioned, we plan to work on three DUCs at Alpine High first because the situation looks favorable from that perspective. In the U.S., this is where we would operate in a higher price environment. We have flexibility there, but it will ultimately depend on prioritizing debt repayment and free cash flow before we begin to reinvest additional capital, which we will outline early next year. There is undoubtedly a part of Alpine High that relies on Henry Hub or Waha pricing, which has shown improvement, as reflected in this quarter's numbers. Additionally, a significant portion is dependent on NGL prices. Therefore, having that flexibility in our portfolio is advantageous. We will need to assess if we increase activity in the Permian based on pricing scenarios and determine whether to focus on oil plays in the Midland Delaware or on gas or NGLs.

Most have been answered today. I just wanted to follow up a little bit just on the DUCs at Alpine High. Are those all in the lean gas window that you'll be completing in the first quarter here?

Yes.

Okay. And then just Altus has proposed a significantly higher dividend, pretty substantial payment back to Apache. Does any of that value creation change the way that you think about developing Alpine High as an operator over the next couple of years?

I think you need to take a step back and consider everything. Clearly, conditions have improved, and we will need to factor that into our calculations regarding where we should allocate capital. However, at this moment, we don't have any specific plans in place. As we previously mentioned for 2021 with projections of $40 and $2.75, it is unlikely that we will see any sustained rig activity in the U.S.

Thank you, operator. I'd like to leave you with the following key thoughts: Oil and gas, when produced and delivered in a safe and environmentally conscious manner, dramatically improves the quality of life around the world and lifts hundreds of millions of people out of poverty. As energy production systems continue to evolve, a robust competitive, innovative and cleaner U.S. energy industry will be necessary for decades to come. Apache plans to remain focused on its core business, and we will work continuously to deliver positive impacts on the air, water and communities in which we live and operate. While our industry continues to face many short-term macro headwinds, Apache's strategy has not changed. We are maintaining a flexible capital allocation approach across our diversified portfolio, generating free cash flow, reducing debt, and continuously working to lower our cost structure. And lastly, we are choosing to fund a differential large-scale opportunity in Suriname rather than invest in short-cycle projects that maintain or grow production in the short-term. As current commodity prices do not offer attractive enough returns to justify doing so. Thank you for joining our call. We look forward to sharing our progress in the future.