Ladies and gentlemen, thank you for standing by, and welcome to the Apache Corporation Q3 2020 Earnings Announcement W ebcast 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. To ask a question during the session, you will need to press star then the number one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. 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 Q3 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO and President, John Christmann. Stephen Riney, Executive Vice President and CFO, will then summarize our Q3 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 Q3 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. 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 Q3 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 Q3, macro headwinds continued 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 the 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. 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 Q3. 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. 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. As a result, have retained two 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 five to six-rig program in Egypt, one floating rig and one platform crew in the North Sea, and two 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 to do so. 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 Q3, 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. I will now turn the call over to Steve Riney.
Thank you, John. On today's call, I will review Q3 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 Q3 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 one 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. APA's Q3 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 the proceeds to reduce other long-term debt. Specifically, in Q3, 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 in 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. With that, I will turn the call over to the operator for Q&A.
Thank you. As a reminder, to ask a question, you will need to press star, then the number one on your telephone. To withdraw your question, please press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from the line of Mr. John Freeman of Raymond James. Your line is now open.
Hi, guys.
Good morning, John.
Yeah. The first question, just on Suriname, when y'all mentioned that you're nearing the award of the two 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 one exploration, one appraisal rig for next year. That's what you're currently in the process of, but there could be additional activity as you progress through 2021 in Suriname?
Yeah, John. What we've got is we've said there'll be two 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. We're in the middle of the tender with Total, and they're going to be picking up two rigs early next year, and there will be a combination of exploration and appraisal with those two rigs.
As you go through the rest of 2021, 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, it'll just be a decision we make based on which wells you want to pull forward and how you want to play it. The two rigs are going to be a minimum for next year.
Okay. Then just the one follow-up on Suriname on maybe just some additional color on what went into choosing the other location on the Bonboni well. Obviously, up to this point, you all kind of made moving in kind of a west to east direction across the block. Is this now, I assume we're set up to kind of go from a north to south kind of direction?
Yeah, John, if you step back, that's kind of been the plan from the get-go and was always the plan. The first four wells we had lined up to kind of go across just one direction. They're on trend with the wells that have been drilled in the blocks, both to our east and west, is there's now a rig running on the other side of us. You 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. Just working our way one direction is a big move. Obviously, we've said there's a lot of depth. These are all independent, separate features that run outward.
We're anxious to kind of get out, as we've announced Bonboni will be the fifth well. It'll be drilled early next year. Total will drill that well. We're anxious to move out more towards the north central part and start to show just that dimension of this in terms of the block. It's exciting. We've said there will be a continuation next year on the exploration pace. Obviously, we're anxious to start appraising. It's going to be fun.
Thanks, John. I appreciate it.
Thank you.
Our next question comes from the line of Gail Nicholson of Stephens. Your line is now open.
Good morning, everybody. Just a question in regards to Suriname. When you guys look at what you have done also in Block 53, can you just talk about what you learned there in those original two 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. It was actually drilled ahead of the Liza well in the Stabroek Block. 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. 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, Kolibri, was further outbound, really drilled some high-quality sands, and told us a lot about that.
I think, Block 53 is highly prospective. The well that's being drilled next door to us will be very informative. Our Keskesi well will be very informative, and also Bonboni. We've got one well commitment left in Block 53. It holds a lot of promise for the future. It's sitting nice. With the work we've done since, there's a lot of potential in Block 53.
Great, thank you. Then just looking at those incremental cost savings that you guys have achieved with the portfolio re-optimization, where are you guys thinking that breakeven is today on the assets?
If you go back to last quarter, we talked about with where our volumes were. We had moved from a 50 to low 30s go forward this year. Next year, it'll tick a little higher, because our volumes are going to be down. 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. We've driven another $100 million out. Steve, I'll let you hop in and provide a little bit more color.
Yeah. Gail, I'll just add to that we continue to make efforts on the cost-cutting and cost focus. The most surprising thing to us this year is the pace at which we're actually able to capture them in the current year. 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. As John says, we've got declining production volume as we round the corner into 2021, and that works against the cash flow break even, flattening in the U.S. oil, as we talked about. That will tend to be offset by the annualized benefit of the cost savings going into next year. The break even of $30 per barrel on a cash flow basis is gonna go up a bit as we round the corner into 2021.
Great. I appreciate the clarity. Thanks so much. Great quarter.
Thank you.
Our next question comes from the line of Mr. Doug Leggate of Bank of America. Your line is now open.
Thank you. Good morning, John. Good morning, everybody.
Good morning, Doug.
John, just maybe a follow-up to Gail's question, if I may, on Popokai. Give me a minute to ask this. Popokai, as I understand it, was a tight hole. Our discussions with Staatsolie 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 three wells that you drilled. I wonder if you could put that to rest and talk to us about reservoir quality in the three wells. I'd like to remind you, obviously, that the Maka well you did say you saw it capable of prolific oil wells. Any data you can give us to put that to rest on the three discoveries. I've got a follow-up, please.
Number one, we have not released a lot of data, or the data on Popokai, and it was tight. I'll tell you, the key to that was we cored the source interval. There was not an issue with reservoir quality in any of the zones. It had some other factors. 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. 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 two parties on everything we've released, the net pays for what have been both Campanian and Santonian numbers. They're not our estimate, not their estimate. They're agreed. We feel really good about those numbers.
I think in general, the quality is good. For us to really get into a lot of detail, we've got to get into the appraisal work. We're going to be very deliberate with the steps and the information that we put out. I can assure you that some of the rumblings we heard of porcellanites, that's not a mistake you'd make or not something you'd find with the logging suite and the detailed core analysis and all the work we're doing. We feel good about the reservoirs, but we really need to follow the appraisal work to be able to start putting out more information.
It's a conventional play, and there's a reason you go to those next phases. There's a lot of zones. 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. We're still on our fourth well. Across one 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 obviously talked about cementing problems. Did 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. Not a matter of losing circulation. The trick was what do we need to do to put the cement plugs in? We had to put a lot of fluid in the well from the other direction. 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. It was more a function of the drilling operations.
Thank you. Last one.
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 two cement plugs below the Santonian because of the pressure that we had, and we had the open hole above us, which compromised. 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 a roundabout way of trying to get that reservoir question answered, because it seems to me if you over pressured the reservoir and lost mud into the reservoir, it's a very porous, permeable reservoir. That's why I was asking the question.
Yeah.
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 three targets look like, or first four targets look like? I'll leave it there. Thank you.
Thank you, 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. Same setting. These are a good distance out, and I think it's gonna give us another ability to explore the other dimension of this block, which we're quite excited about. The primary targets are gonna be similar. You're gonna see those targets as we continue in these next several wells. A lot of it's gonna be about the Campanian and the Santonian. I do want to remind you, we've got some other targets that at some point we'll get to.
Great stuff. Look forward to next week, John. Thanks so much.
Yes. Thank you.
Our next question comes from the line of Mr. Bob Brackett of Bernstein Research. Your line is now open.
Good morning. Thanks for taking the question. 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 2021 or 2022?
Yeah, Bob, I'll say partners would love for us to get back in there. It's not that we ever excluded 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 they spud before the end of the second quarter of 2022. It's something we're very excited about. We've got 45% of it. I can promise you, two of our partners, one of them is in the well that's being drilled south of there right now. Yes, they're anxious and we will get to it in due course, and we're anxious too. There's a lot of activity that's going to be very informative on the potential in Block 53.
Great. Thanks for that. A quick follow-up. The water depth for Bonboni. I could probably look it up off the bathymetry, but if you have that handy.
I don't have that off top of my fingertips here.
Okay.
It's not real crazy. It's gonna be deeper. It's not something crazy. I'm looking down here at Clay, operationally, do you know yet? I don't think it's crazy.
Yeah, I don't think so.
Gary can follow up with that.
Okay. Thanks for that.
Thank you.
Our next question comes from the line of Mr. Scott Gruber of Citigroup. Your line is now open.
Yes, good morning.
Good morning, Scott.
In the Permian, how many DUCs do you have? How long can you keep two frac crews working without adding any rigs down there?
Yeah, Scott, this is Dave Pursell. We have about 45 DUCs in the Permian. We'll pick two frac crews up here later in the quarter, and those will stay busy through the middle of next year.
Got it. You also mentioned a flexible approach to flow back timing on those completions. Obviously, post-completion, the well cost is basically sunk. How do you think about flow back strategy on those? I assume there's core price thresholds you're thinking about, some color there would be great.
Yeah, we'll look at a number of factors as we bring the wells back online. Some of these, we have five three-milers that we're bringing back. We'll keep those facility constrained for a while. Really, we're going to look at the forward curve on price. How the wells are flowing back and just see how aggressive we want to be with the chokes through the end of 2021. We just want to keep some optionality out there given the volatility in the oil price.
Got it. Appreciate you calling. Thank you.
Yes.
Our next question comes from the line of Mr. Paul Cheng of Scotiabank. Your line is now open.
Thank you. Good morning.
Good morning, Paul.
John, for the Bonboni, what is the depth that you have to drill below the seabed to reach the TD?
Yeah, actually, I think shallow as we move that direction, Paul. The targets are actually going to be a little shallower below the seafloor than what we're sitting at Maka, Kwaskwasi, and even Keskesi. It's shallowing, which is actually a pretty good thing from a maturity standpoint.
Okay. That for next year, the CapEx of $1 billion for maintaining the U.S. production spread and modest decline in North Sea and Egypt, but of course, that benefit from the DUC. Without the DUC benefit, what's that number may look like?
Yeah, I mean.
To maintain.
There's two things, Paul. Number one, you have to look at, we're spending quite a bit of money on exploration in our CapEx. 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 will cost to run those two frac crews. You step back and think about the decision we're making on the exploration investment. That's capital we 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 three, four years out.
No, fully understand the decision. I'm just curious what that number, if we're saying that in 2021 on the sustaining CapEx without the benefit of DUC. Also on Suriname, I thought Total carry you for 87.5%, your CapEx to that shouldn't be that much, is it?
Well, the Total carry actually kicks in on the appraisal work. We're going to have two rigs running. There will be exploration activity at a pace that's pretty similar to what we've been spending this year, right? 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?
Well, I mean.
The last one. Yes, go ahead.
Yeah. Clearly, our priorities there is going to be debt repayment. There's more with the $1 billion or less number we've laid out for 2021. That's predicated on 40. If prices are higher, you're going to see us continue to prioritize debt repayment. There are some things we'd like to get to. More capital in Egypt is something that would be a priority for us. Debt's going to be the big thing. I think you'd have to get quite a bit higher before we'd start thinking about rig lines in the Permian.
Okay. Final one. That Apache 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 don't think you need to acquire company for growth. That may allow you to have additional room of cost reduction and also improve your balance sheet also in a more maybe accelerated rate.
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 allude 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.
I think from our perspective, we've got to make sure something would really make 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. You can't stick your head in the sand. You have to keep your eyes open. We're going to be very cognizant of shareholder value.
Thank you.
Our next question comes from the line of Mr. Charles Meade of Johnson Rice. Your line is now open.
Morning, John, to you and your whole team there.
Hello, Charles.
Hey, I have one 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 it, but did you give a timeline for when we expect a decision or announcement on your Keskesi well you're on right now?
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 the pay zones yet, but the well's in really good shape, and we're anxious to move forward. We're not going to lay out a timeline, but things are going well.
Good. I appreciate that color. That's helpful, John. The follow-up back to this Bonboni, and as you can imagine, we all have a lot more questions than you probably want to answer about it right now. 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 shallower because you've got some, I guess, basin thinning going that way. You also mentioned that they're kind of the same settings. I would expect these are more areally large basin floor features as you move in that northeast direction. Is that a fair inference to make, or is there anything else you could talk about the different kind of play versus what you've established already with your string of four wells?
No. I can answer one of the questions on the water depth. I think we're in about 2,000 meters of water with Bonboni. What you've got happening is, as we've said, they're very significant independent features. You've got turbidite fan systems. What you're giving up is you're trading some of the water depth for depth of the formation. They do shallow a little bit, which we think is going to be a positive for maturity. They're big, Charles, and that's what we want to say at this point.
We need to go out and explore. 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. Campanian, Santonian, a little shallower, very large features. There's some things down below that we might be able to get to as well.
Got it. That will be fun to watch. Thanks, John.
Our next question comes from the line of Michael Scialla of Stifel. Your line is now open.
Yeah. Hi, good morning. Hess mentioned on its call that there are five penetrations in the Santonian in the basin, you're three, and then two on the Stabroek Block. It sounds like currently drilling ExxonMobil exploration well in 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?
Michael, we have not at this point, just because other than what Haimara might've done for us, it hasn't been beneficial to us. I think it just shows you the depth and the number of targets we've got. The Guyana-Suriname Basin's turning out to be a super basin. You've got a maturity and multiple source rock that's working. You've got multiple targets. They're high quality and we've penetrated both the Campanian and the Santonian with all of ours. A lot of that work we'll 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. It just shows you the thickness. It shows you the sands. We had over 900 feet in Kwaskwasi between the two zones. It just shows you the depth and just how target-rich this environment is for both.
Very good. Excuse me, can you talk about your decision to complete the DUCs in the Permian rather than to generate more free cash flow, 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, the first three are gonna be Alpine High. There'll be three there and then mainly in the Midland Basin. I think the big reason to start this now is really we see an opportunity on the service costs. Costs are down significantly from where they were in the Q1. 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 and when you bring them back. This is driven off of the cost side, and they're wells that you ultimately are gonna complete. We just see it as a good window to commit, put two frac crews to work, and go knock these out.
Makes sense. Thanks, John.
Thank you.
Our next question comes from the line of Mr. Brian Singer of Goldman Sachs. Your line is now open.
Thank you. Good morning.
Good morning, Brian.
To follow up further on Suriname, you've made a couple of references here to deeper zone or zones below the Santonian, 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 zones or how prospective those zones could be across Block 58. Separately, as you think about 2021, can you just remind us on where you see the ratio of exploration wells versus appraisal wells?
It's likely going to be more appraisal than exploration, but you're going to see a similar pace with two rigs. There's going to be multiple exploration wells, is the best way to say it. We're going to have the flexibility with both those rigs to do both. You'll start to see the programs kind of blended as we go out and prioritize things. The other thing I would say is when we started out and did all of our early work, we've seen eight different play types on Block 58. To date, we've tested two. Two of those, the first two were the Campanian and the Santonian. We've seen both of those in all the first three wells. We attempted to get down to the Turonian, but we ran into too much pressure in the Santonian at Maka.
There's clearly, the Turonian would be one of the next targets that we'd like to get to. 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. There's really five other types. You start to get pre- and post-unconformity, and some other things that are even a little bit deeper. That's for a later conversation later down the road. There's just a lot here in this block.
Great, thanks. 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'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?
Yeah. 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. 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 the organizational restructure. We implemented the vast majority of that in the Q1, 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 costs and start to see the benefits of that showing up. Clearly, we're seeing a significant reduction in LOE as we went through the Q3 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 is it's just a bit lumpy. So you get the impacts of things like maintenance bin and turnarounds and pace of workover activity and things like that just affect operating costs a lot more than G&A, which tend to be more steady. On the G&A side, we just get the weird little accruals that we have, like this quarter. 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.
Great. Thank you.
Our next question comes from the line of Mr. Leo Mariani of KeyBank. Your line is now open.
Hey, guys. 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 2021?
At this point, Leo, 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. We'll find a place. Maybe you might take an appraisal well that we decide to deepen and put an exploration tail on it. We'll just see how we work through that. Right now, all the appraisal work is going to be in appraised discoveries, which we've already qualified.
Okay, that's helpful. I guess you guys obviously laid out a plan to hold your Q4 2020 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 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?
Yeah. I think you look at our base overall decline, both areas is kind of like where North America is. 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 is going to be lower. Barrel is a little higher, but it's in the 25% range. We will be active there, so it's modest, as we said. Egypt is also, it's really good conventional rock. On average, our decline rate's probably close to 25% in Egypt. We came into the year running about 10 rigs there. 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 five. Five to six 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's not a lot of activity just for the size, scale, scope of that business. When we say modest, that means it's less than what our natural base declines would be.
Okay. Thanks, guys.
Thank you.
Our next question comes from the line of Mr. Neal Dingmann of Truist Securities. Your line is now open.
Good morning. Tried to stay away from Suriname. I think we've covered it. John, my question's on Egypt. You've been running a five-rig plan now for some time. Did the 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 activity in that play?
Yeah. Actually, Neal, we came into the year with 10, so we dropped to five 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. The appetite would be for more. As we said, we're prioritizing free cash flow. We're prioritizing debt repayment, and we're doing that at the corporate level. Egypt is contributing some free cash flow. It's an area where we could easily double that rig count. It's going to have to fit into the big mix of how much can we free up to put into Egypt.
Yeah. Okay. Makes sense. Same thing with just allocation. I guess the way gas prices are running, any thoughts or just any comments you can make around potentially even minimally revisiting Alpine High?
Yeah. Like I said, on the DUCs, we're going to go knock out, I think, three DUCs at Alpine High first, because things look pretty good right now from that perspective. In the U.S., it's the place we would get to in a higher price environment. We have optionality there. 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.
Clearly, there's a portion of Alpine High that hinges on Henry Hub or the Waha pricing, which has definitely improved, and you've seen that in the numbers this quarter. There's a big chunk of it that really hinges on NGL prices as well. It's nice to have that optionality in the portfolio, and we'll just have to look at if we were to put more activity 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 the NGLs.
Okay. Thanks for the time, John.
Thank you.
Our next question comes from the line of Mr. David Deckelbaum of Cowen. Your line is now open.
Thanks, guys. Lots 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 Q1 here?
Yes.
Okay. Just Altus has proposed a significantly higher dividend, a 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 have improved out there. We'll just have to factor all that into our math of where we would put capital back to work. Right now, we don't have anything laid out. As we laid out the early look for 2021 at 40 and 275, you're not likely going to see any sustained rig programs in the U.S.
Appreciate it, guys. Thank you.
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.
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.