(Seeking Alpha, 5.Nov.2020) — Apache Corporation CEO John Christmann led the company’s third quarter of 2020 conference call to discuss results with analysts. What follows is the complete transcript of the call.
Gary Clark – Vice President of Investor Relations
John Christmann – Chief Executive Officer & President
Steve Riney – Executive Vice President & Chief Financial Officer
Dave Pursell – Executive Vice President of Development
Conference Call Participants
John Freeman – Raymond James
Gail Nicholson – Stephens
Doug Leggate – Bank of America
Bob Brackett – Bernstein Research
Scott Gruber – Citigroup
Paul Cheng – Scotiabank
Charles Meade – Johnson Rice
Michael Scialla – Stifel
Brian Singer – Goldman Sachs
Leo Mariani – KeyBanc
Neal Dingmann – Truist Securities
David Deckelbaum – Cowen
Ladies and gentlemen, thank you for standing by, and welcome to the Apache Corporation Third Quarter 2020 Earnings Announcement Webcast Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today’s conference is being recorded. [Operator Instructions]
I would now like to hand the conference over to your speaker today, Mr. Gary Clark, Vice President of Investor Relations. Thank you and please go ahead, sir.
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 Surinam 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.
And I will now turn the call over to Steve Riney.
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 of 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.
And with that, I will turn the call over to the operator for Q&A.
[Operator Instructions]. Our first question comes from the line of Mr. John Freeman of Raymond James.
Yes. The first question, just on Suriname, when you all mentioned that you’re nearing the award of the 2 rigs for 2021, I just want to make sure that I’m thinking about this the right way. That doesn’t necessarily imply that you’re just going to have the 1 exploration, 1 appraisal rig for next year. That’s just — that’s what you’re currently in the process of, but there could be additional activity as you progress through ’21 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’ll 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, if you step back, I mean that’s kind of been the plan from the get-go and it was always the plan. The first 4 wells, we had lined up to kind of go across just 1 direction. They’re on trend with the wells that have been drilled in the blocks, both to our East and West, there’s now a rig running in on the other side of this. We just got to step back and realize just the perspective and just how big Block 58 is and even Block 53. It’s the equivalent of over 250 Gulf of Mexico blocks. So just we’re working our way, one direction is pretty — a big move. Obviously, we’ve said there’s a lot of depth. These are all independent separate features that run outward. And so we’re anxious to kind of get out, as we’ve announced Bonboni, it will be the fifth well. It will be drilled early next year. Total will drill that well. And we’re anxious to move out more towards the — kind of the North Central part and start to show just that dimension of this in terms of the block. So it’s exciting. We’ve said there will be a continuation next year on the exploration pace. And obviously, we’re anxious to start appraising. So it’s going to be fun.
Our next question comes from the line of Gail Nicholson of Stephens.
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’ll just add to that, we have — we continue to make efforts on the cost cutting and cost focus. And the most surprising thing to us this year is the pace at which we’re actually able to capture them in the current year. So we’re around $400 million now of annualized savings, and we’ll get at least $300 million of that and probably more in the current year. And so as John says, as you know, we’ve got declining production volume as we round the corner into 2021, and that works against the cash flow breakeven, flattening in the U.S. oil, as we talked about. But the — that can — will tend to be offset by the annualized benefit of the cost savings going into next year. But the breakeven of $30 per barrel on a cash flow basis is going to go up a bit as we round the corner into ’21.
Our next question comes from the line of Mr. Doug Leggate of Bank of America.
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.
Well, number 1, we have not released a lot of data, the data on Popokai, and it was tight. And I’ll tell you the key to that was record the source interval. So there was not an issue with reservoir quality in any of the zones. It had some other factors. But it was — the key for there was it gave us a lot of the key data and we were able to core the source interval, which helped us with the maturity, which played back into Block 58. So that was the key there.
I think that, Doug, from our perspective, the information that we’ve released with Total has been agreed between the 2 parties on everything we’ve released, the net pays for what have been the — both Campanian and Santonian numbers. They’re not our estimate, not their estimate, they’re agreed. So we feel really good about those numbers. I think in general, the quality is good. But for us to really get into a lot of detail, we’ve got to get into the appraisal work, and that’s — we’re going to be very deliberate with the steps and the information that we put out, but I can assure you that some of the rumblings we heard of [indiscernible] that’s not a mistake you’d make or it’s not something you’d find with the logging suite and the detailed core analysis and all the work we’re doing. So we feel good about the reservoirs, but we really need to follow the appraisal work to be able to start putting out more information. This isn’t — it’s a conventional play, and there’s a reason you go to those next phases. But there’s a lot of zones. I mean we’re in a super basin. It’s large. We’ve got a lot of really, really good rock, and we’re very pleased with where we are. I mean, it’s — but we’re still on our fourth well across 1 dimension, and it’s just really early to start talking about things you’d typically do after you’ve gone into your full appraisal when you can come back with concrete 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 said was we got into higher pressure below our target in the lower Santonian. It’s not a matter of losing circulation. The trick was, what do we need to do to put the cement plugs in. And so we had to put a lot of fluid in, in the well to — from the other direction. And so that’s why we compromised the ability to actually get the fluids out of the Santonian because we had an open hole that we had to balloon over time. So it was more a function of the drilling operations.
It wasn’t cementing problems, Doug. It was that we had to set two cement plugs, let me just be real clear on that. There were no cementing problems. We just had to set 2 cement plugs below the Santonian because of the pressure that we had, and we had the open hole above us, which compromised other — we’d already run logs on it, but it compromised the ability later to get fluids.
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.
Doug, Bonboni is exciting. We’ll have both the Campanian and the Santonian targets. There’s also an opportunity to go a little bit deeper and test some other things. So same setting. These are — it’s a good distance out. And I think it just — it’s going to give us another ability to explore the other dimension of this block, which we’re quite excited about. But the primary targets are going to be similar. And you’re going to see those targets as we continue in these next several wells. A lot of it is going to be about the campaign and the Santonian. But I do want to remind you, we’ve got some other targets that at some point we’ll get to.
Our next question comes from the line of Mr. Bob Brackett of Bernstein Research.
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 off the top of my fingertips here. It’s not real crazy. It’s going to be deeper. But it’s not something crazy. I’m looking down here at Clay. Operationally, he’d know yet. But it’s not — I don’t think it’s crazy. We can — Gary can follow up with that.
Our next question comes from the line of Mr. Scott Gruber of Citigroup.
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’ll look at a number of factors as we bring the wells back online, some of these — we have 5, 3 milers that we’re bringing back, and we’ll keep those facility constrained for a while. But really, we’re going to look at the forward curve on price and how the wells are flowing back and just see how we want to — how aggressive we want to be with the chokes through the end of ’21. So we just want to keep some optionality out there given the volatility in the oil price.
Our next question comes from the line of Mr. Paul Cheng of Scotiabank.
John, for the Bonboni, do you have — what is the depth that you have to drill below the seabed to reach the TD?
Yes. It’s actually — the thing is shallow, as we move that direction, Paul. So the targets are actually going to be a little shallower below the seafloor than what we’re sitting at Maka, Kwaskwasi and even Keskesi. So it’s shallowing which is actually a pretty good thing 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’s 2 things, Paul. Number one, you have to look at we’re spending quite a bit of money on exploration in our CapEx. And so we’re making a conscious decision to put the money into Suriname, which we could be putting into that base business. I can assure you the money going into Suriname is more than what it would cost to run those 2 frac crews. So you step back and think about the decision we’re making on the exploration investment, that’s capital we’re putting in the — which could be putting into the base, but we’re making a long-term decision because we think there’s going to be much, much greater benefit when you get 3, 4 years out.
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.
Okay. And final one, that partly, actually, even though the price looks very depressed, but they trade at a higher multiple compared to most of your E&P peers. Does it make sense from that standpoint to use this relative premium currency to acquire company with a maybe better near-term cash flow and balance sheet? I mean I don’t think you need to acquire company for growth. But that may allow you to have additional room of cost reduction and also improve your balance sheet also more maybe at serving rigs.
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.
Our next question comes from the line of Mr. Charles Meade of Johnson Rice.
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?
Well, we did not, Charles. We’re drilling ahead. We did run into some hole stability problems in the upper portion. We’ve since sidetracked. We’ve set pipe and we’re getting ready to move ahead. We have not got down into any of deeper zones yet but the wells are in really good shape, and we’re anxious to move forward. So — but we’re not going to lay out a timeline, but it’s — things are going well.
Good. I appreciate that color. That’s helpful, John. And then the follow-up, back to this Bonboni. And as you can imagine, we all have a lot more questions and you probably want to answer about it right now, but you’ve already painted a little bit of the picture here, in that it’s the same Campanian, Santonian intervals you’re targeting there, but they’re in a shallower — they’re shallower because it’s — you’ve got some, I guess, basin thing going away. Can you talk about — you also mentioned that they’re kind of the same setting. So can you talk about whether these are — I would expect these are more eerily large basin floor features as you move in that Northeast direction, but is that a fair inference to make? Or is there anything else you can talk about the different kind of play versus what you’ve established already with your string of 4 wells?
No. I mean — and I can answer 1 of the questions on the water depth. I think we’re in about 2,000 meters of water with Bonboni. So what you’ve got happening is as we said, they’re very significant independent features. You’ve got turbidite fan systems. But — so what you’re giving up is a little bit of — you’re kind of trading some of the water depth for depth of the formation. So they do shallow a little bit, which we think is going to be a positive for maturity. But they’re big, Charles, and that’s what we want to say at this point. We need to go out and explore, right? But we’re excited about them. They look fantastic on seismic. They’re sizable and there’s just a lot of ground to cover between Maka, Kwaskwasi, Sapakara and Keskesi and as you start to move out just that direction to Bonboni. So — but Campanian, Santonian, a little shallower, very large features, and then there are some things down below that we might be able to get to as well.
Our next question comes from the line of Michael Scialla of Stifel.
Hess mentioned on it’s 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, we have not at this point just because after — other than what Haimara might have done for us, it hasn’t been beneficial to us. The — I think it just shows you the depth and the number of targets we’ve got. I mean, it’s — the Guyana Basin is turning out to be a super basin. You’ve got a maturity and source — multiple source rock that’s working. You’ve got multiple targets. They’re high quality, and we’ve penetrated both the companion and the Santonian with all of ours. And I think a lot of that work will come back with through appraisal when we start to really get into more details about what would be our plans as you move post the appraisal plan. But it just shows you the thickness. It shows you the sand. We had over 900 feet in a Kwaskwasi between the 2 zones. So it just shows you the depth and just what — how a target-rich this environment is for both.
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?
Well, actually, I think the first 3 are going to be Alpine High. So there’ll be 3 there and then mainly in the Midland Basin. But I think the big reason to start this now is really we see an opportunity on the service cost. I mean, costs are down significantly from where they were in the first quarter. And I think it’s just — we see it as an opportunity to go ahead and get out there and get them completed, and then it gives us a little bit of flexibility in terms of how you — how and when you bring them back. So this is driven off of the cost side and their wells that you ultimately are going to complete, and we just see it as a good window to commit, put 2 frac crews to work and go knock these out.
Our next question comes from the line of Mr. Brian Singer of Goldman Sachs.
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?
Well, it’s the likely going to be more appraisal than exploration, but you’re going to see a similar pace with 2 rigs. And so there’s going to be multiple exploration wells the best way to say it. But we’re going to have the flexibility with both those rigs to do both. So you’ll start to see the programs kind of blended as we kind of go out and prioritize things. One other thing I would say is when we started out and did all of our early work, we’ve seen 8 different play types on Block 58. And to-date, we’ve tested 2. Two of those, the first 2 were the Campanian and the Santonian. We’ve seen all — both of those and all the first 3 wells. We attempted to get down to the Turonian, but we ran into too much pressure in the Santonian at Maka. And so there’s clearly — the Turonian would be 1 of the next targets that we’d like to get to. And it’s just a matter of figuring out when and which well we want to do that with. We think there’s great potential there. And then there’s really 5 other types. You start to get pre and post unconformity and some other things that are even a little bit deeper. But that’s for a later conversation later down the road. But there’s just a lot here 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, I think that’s a question that’s probably, in terms of specific numbers, best left for when we talk about 2021 in more detail, typically in February. But what I would say is that we got after the G&A costs pretty quickly because we knew what we were going to do on an organizational restructure, and we implemented the vast majority of that in the first quarter. And so you saw a significant drop in G&A pretty quickly. LOE takes a bit longer to get organized around that to start attacking the cost and start to see the benefits of that showing up. But clearly, we’re seeing a significant reduction in LOE as we’re going through — as we went through the third quarter and into the future, you’re going to see more of that. There are some more run rate type of costs that we need to get after. And I think you’ll see continued benefit of that as we round the corner into 2021 and even beyond, especially if we stay in this type of price environment.
The thing about LOE, as you know, it’s just a bit lumpy. And so you get the impacts of things like maintenance spend and turnarounds and pace of workover activity and things like that, that just affect operating costs a lot more than G&A, which tend to be more steady. And on the G&A side, we just get the weird little accruals that we have like this quarter.
But I just — I think instead of giving an accurate number of where we’re going on OpEx, LOE on a quarterly basis. Let’s see where we’re at in February, and we’ll give some good context and guidance on 2021 at that point.
Our next question comes from the line of Mr. Leo Mariani of KeyBanc.
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, Leo, we don’t have — we haven’t explored or gotten down to the Turonian. So It would be early to call it appraisal until we can get down and actually successfully explore. So we’ll find a place. Maybe you might take an appraisal well that we decide to deepen and put an exploration tail on it. But we’ll just see how we work through that. But right now, we’re — all the appraisal work is going to be in appraised discoveries, which we’ve already quantified.
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. I mean I think you look at our base overall decline, both areas is kind of like where North America. It’s all around 25%. North America is a combination of our unconventional which is higher and our conventional, which is lower. North Sea is 40s, it is going to be lower. barrels a little higher, but it’s in the 25% range. But we will be active there. So it’s modest, as we said.
And then Egypt is also — it’s really good conventional rock. On average, our decline rate is probably close to 25% in Egypt. We came into the year running about 10 rigs there and 10 years is — 10 rigs, you’re closer to kind of keeping it, maybe growing it. When we went through the capital cuts, we dropped down to 5. So 5 to 6 is not a lot for when you consider the size of our position, how much production we’re making there in terms of the volumes and so forth, it really is — it’s not a lot of activity just for the size, scale, scope of that business. But when we say modest, that means it’s less than what our natural base declines would be.
Our next question comes from the line of Mr. Neal Dingmann of Truist Securities.
Got to stay away from Suriname like COVID. So my question is on Egypt. You’re running pretty — been running a 5 rig plan now for some time. Is that — did economics sort of favor that continuous plan? Could you see maybe even adding more activity there? Can you talk maybe a little bit about just the activity in that play?
Yes. Actually, Neal, we came in the year with 10. So we dropped to 5 when we had to cut capital because we cut everywhere, right? It’s — clearly, we’ve got more activity than we’ve got cash flow right now to put into Egypt. So the appetite would be for more. But as we’re going to — as we said, we’re prioritizing free cash flow, we’re prioritizing debt repayment, we’re doing that at the corporate level. So Egypt is contributing some free cash flow. It’s an area where we could easily double that rig count. But it’s going to have to fit into the big mix of how much can we free up to put into Egypt.
No. Okay. Makes sense. And then same thing with just allocation. I mean, I guess, the way price — gas prices are running any thoughts or just any comments you can make around potentially even minimally revisiting Alpine High?
Yes. I mean like I said, we’ve got — on the DUCs, we’re going to go knock out, I think, 3 DUCs at Alpine High first because things look pretty good right now from that perspective. But I think in the U.S., it’s the place we would get to in a higher price environment. We have optionality there, but it’s going to boil down to, once again, prioritizing debt repayment and free cash flow before we start to put incremental capital back to work over what we’ll lay out early next year. But clearly, there’s a portion of Alpine High that is — hinges on Henry Hub or Waha pricing, which has definitely improved, and you’ve seen that in the numbers this quarter. There’s a big chunk of it that’s really hinges on NGL prices as well. So it’s nice to have that optionality in the portfolio. And we’ll just have to kind of look at if we were to put more activity work to work in the Permian, based on price decks where it would go into the oil plays in our Midland Delaware or into the gas or NGLs.
Our next question comes from the line of Mr. David Deckelbaum of Cowen.
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?
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 just got to step back and factor everything in. Clearly, things are — have improved out there, and we’ll just have to kind of factor all that into our math of where we would put capital back to work. But right now, we don’t have anything laid out. As we laid out the early look for 2021 at $40 and $2.75, you’re not likely going to see any sustained rig programs in the U.S.
There are no further questions at this time. I would now like to turn the call over to Mr. John Christmann for the concluding remarks.
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.
Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect.