APA Corporation

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 speaker's 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 third quarter financial and operational results conference call. We will begin the call with an overview by CEO and President John Christman. Steve Reine, Executive Vice President and CFO, will then summarize our third quarter financial performance. Clay Breches, Executive Vice President of Operations, and Dave Purcell, 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 interests 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 discussed 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 Surlum. While commodity prices improved and were less volatile during the third quarter, 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 CERN. 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 an 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 two frack 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 flowback timing of these wells. Regardless, there will be no impact from this program on our fourth quarter Permian production, and minimal impact on our four-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 frack 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 debt 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, Kwas Kwasi, 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 Satsoli before year end. Following Quas Quasi, 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 Reine.

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 two cents 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 16 cents 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. 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 second quarter, we will use all of the 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 PARC. 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 duct 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.

Thank you. And 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 sound 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 CERNOM, when you 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 expiration, one appraiser rig for next year. That's what you're currently in the process of, but there could be additional activity as you progress through 21 in CERNOM?

Yeah, John, what we've got is, you know, we've said there will 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. But 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.

And then as you go through the rest of 21, I guess, when you decide whether or not you, in total, if you're going to add additional rigs to the plan, is that driven, you know, 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, you know, the two rigs are going to be a minimum for next year.

Okay. And then just the one follow-up on CERNOM on maybe just some additional color on what went into choosing the location on the Bonboni. Well, obviously, up to this point, you all have kind of been 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, you know, from a north-to-south kind of direction?

Yeah, John, if you step back, I mean, 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, you know, to our east and west. There's now a rig running, you know, 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. You know, it's the equivalent of over 250 Gulf of Mexico blocks. So just working our way one direction is pretty, you know, a big move. Obviously, we've said there's a lot of depth. These are all, you know, independent, separate features that run outward. And, you know, so we're anxious to kind of get out, as we've announced, Bombani 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, you know, kind of the north central parts. and start to show just that dimension of this, you know, in terms of the block. So it's exciting. You know, we've said there will be a continuation next year on the, you know, the expiration pace, and obviously we're anxious to start appraising. So it's, you know, it's going to be fun.

Thanks, John. I appreciate it.

Thank you.

Our next question comes from the line of Gail Nicholson of Stevens. Your line is now open.

Good morning, everybody. I just had 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-row drills and how that has helped you influence some of your decision process on the exploration activity? Sure.

Well, Dale, if you go back to early 2015, we were drilling our first well, Popakai, and it was actually drilled ahead of the Leza well on the Stabrick block. So, you know, you go back in time, the main thing that Popakai did for us was it helped inform us that, one, you know, 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. You know, the second well, Calibre was further outbound, you know, really drilled some really, really high-quality sands and told us a lot about that. So I think, you know, Block 53 is highly prospective. you know i think uh the the well that's being drilled next door to us will be very informative i think our keskesi well will be very informative uh and also bombani so you know we've got one um well commitment um left at uh you know in block 53 but um you know i think it holds a lot of promise uh you know for the future so it's it's sitting nice i think with the work we've done since there's there's a lot of potential in block 53

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

You know, I mean, if you go back to last quarter, we talked about with where our volumes were. We had moved kind of from a 50 to, you know, low 30s kind of go forward. this year. Next year, it'll tick a little higher because our volumes are going to be down. But, you know, 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.

Yeah, Gail, I'll just add to that that, you know, 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, you know, 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, you know, we've got – You know, 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. But that will tend to be offset by the annualized benefit of the cost savings going into next year. But the break-even of $30 per barrel on a cash flow basis is going to 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 Leggett of Bank of America. Your line is now open.

Thank you. Good morning, John. Good morning, everybody. Good morning, Doug. John, 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 about Our discussions with Stutz always 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. So 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 Macca well, you did say you saw it capable of prolific oil wells. data you can give us to put that to rest on the three discoveries. I've got to follow up, please.

Well, number one, we have not released a lot of data or, you know, the data on Popakai, and it was tight. And I'll tell you, the key to that was record the source interval. So, you know, there was not an issue with reservoir quality, you know, in any of the of the zones that uh you know had some other factors but it was the key for there was it gave us a lot of the key data uh and was you know we're able to core the source interval which helped us with the maturity which played back into block 58 so that was the key there yeah i think that uh you know doug from our perspective the uh the information that we've released with Total has been, you know, agreed between the two parties on everything we've released, the net pays for what have been, you know, both Campanian and San Antonio numbers. You know, they're not our estimate, not their estimate. They're agreed. So we feel really good about those numbers. I think in general, you know, the quality is good. But, you know, for us to really get into a lot of detail, we've got to get into the appraisal work. And that's, you know, we're going to be very deliberate with the steps and the information that we put out. But I can assure you that, you know, some of the rumblings we heard of – you know, porcelainites, that's not a mistake you'd make or not something you'd find, you know, with the logging suite. and the detailed core analysis and all the work we're doing. So, you know, we feel good about the reservoirs, but we really need to, you know, to follow the appraisal work to be able to start putting out more information. This isn't, you know, it's a conventional play, and there's a reason you go to those next phases. But, you know, there's a lot of zones. I mean, we're in the Superbasin. It's large. We've got a lot of really, really good rock, and, you know, we're very pleased with where we are. I mean, but we're still on our fourth well across one, you know, dimension, and it's just really early to start talking about things you typically do after you've gone into your full appraisal when you can come back with concrete information. There's no evidence from the logs.

I guess just a clarification point real quick. When you announced cross quasi, you obviously talked about cementing problems. Did you lose circulation into the reservoir in that well?

What we said was we got into higher pressure. below our target in the lower San Antonio. Not a matter of losing circulation. The trick was, what do we need to do to put the cement plugs in? So we had to put a lot of fluid in, in the well from the other direction. So that's why we compromised the ability to actually get the fluids out of the San Antonio because we had an open hole that we had to balloon um you know over time so um you know it was more a function of the uh the drilling operations thank you 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, you know, which compromised other, you know, we'd already run logs on it, but it compromised, you know, 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 overpressure the reservoir and lost mud into the reservoir, it's 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, you know, compared to what your first three targets look like or first four targets look like? And I'll leave it there. Thank you.

No, thank you, Doug. No, Bombani is exciting. You know, we'll have, you know, both the Campanian and the San Antonio targets. There's also an opportunity to go a little bit deeper and test some other things. So Same setting. These are, you know, at a good distance out. And I think it just, you know, it's going to give us another ability to explore the other dimension of this block, which we're quite excited about. But, you know, the primary targets are going to be similar. And you're going to see those targets as we continue in these, you know, next several wells. A lot of it's going to be about the Campanian and the San Antonio. But I do want to remind you, we've got some other targets that at some point we'll get to. Great stuff.

We look forward to next week, John. Thanks so much.

Yep, 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 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?

Yeah, Bob, I'll say partners would love for us to get back, you know, in there. And it's not that we ever excluded it. It's just we've been focused on 58. uh you know 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 um that is something we're very excited about you know we've got 45 of it uh i could promise you you know two of our partners one of them's in the well that's being drilled but you know south of there right now um so yes they're anxious and um You know, we will get to it in due course, and we're anxious, too. But there's a lot of, you know, 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 symmetry, but if you have that handy?

I don't have that off the top of my fingertips here. It's not. Okay. it's not real crazy it's going to be deeper um but it's not something crazy i'm looking down here clay if you know operationally do you know yet but uh it's not i don't think it's crazy okay thanks for that thank you our next question comes from the line of mr scott gruber of city group your line is now open yes good morning good morning scott

In the Permian, how many ducks do you have? How long can you keep two frat crews working without adding any rigs down there?

Yes, Scott, this is Dave Purcell. We have about 45 ducks in the Permian. We'll pick two frat 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, you know, post-completion, the well cost is basically sunk. How do you think about flowback strategy, you know, on those? Yeah, I assume there's oil price thresholds you're thinking about, but 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, 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 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.

Got it. Appreciate the call. Thank you.

Our next question comes from the line of Mr. Paul Chang of Scotiabank. Your line is now open.

Thank you. Good morning. Good morning, Paul. John, for the Bonbonni Do you have, what is the depth that you have to drill below the seabed to reach the TD?

Actually, the thing is shallow. You know, as we move that direction, Paul, so the targets are actually going to be a little shallower, you know, below the C4 than what we're sitting at, you know, at Maka, Kwas Kwasi, and even Keskesi. So it's shallowing, which is actually a, Yeah, pretty good thing from a maturity standpoint.

Okay. And for next year, the cap is of $1 billion for maintaining the U.S. production spread and modest decline in North Sea and Egypt. Of course, that benefits from the duck. So without the duck benefit, what's that number may look like?

Yeah, I mean, it's...

Well, there's two things, Paul. Number one, you have to look at we're spending, you know, quite a bit of money on exploration in our capex. And so we're making a conscious decision to put the money into CERNOM, which we could be putting into that base business. I can assure you the money going into CERNOM is more than what it will cost to run the street track cruise. So, you know, you step back and think about the decision we're making on the exploration investment, you know, you know, that's capital we're putting in, 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, you know, three, four years out.

No, fully understand the decision, but I just feel that what that number, if we're saying that in 2021 on the subsisting CapEx without the benefit of that, and also on CERN name, I thought total carry review for 87 and a half, so your topics 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 two rigs running. So there will be expiration activity. 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. Okay. Two final questions. First, if the oil price end up next year swing much better than the $40 WTI-based budget, how that may impact, if it does, on your 2021 ethics and activity level? And then the last one, Nick. Yeah, go ahead.

Yeah, I mean, you know, clearly our priority there is going to be debt repayment. I mean, there's more, you know, with the billion dollars or less number we've kind of laid out for, you know, 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 debt's going to be the big thing, and then I think you'd have to get, you know, quite a bit higher before we start thinking about rig lines in the Permian. Okay.

A final one. The Apache, actually, even though the price looks very depressed, but they trade at a higher multiple compared to most of your EMP peers. Does it make sense from that standpoint to use this relative premium currency to acquire a company with a maybe better near-term cash flow and balance sheet? I mean, I don't think you need to acquire a company for growth, but that may allow you to have additional room of cost reduction and also improve your balance sheet also in a more maybe accelerate way.

No, it's been a busy time, and we've seen a lot of transactions happen out there on the M&A front. You know, I think, you know, as you allude to with how we're trading, we're in a pretty unique position where we've got a potential, you know, company changing expiration block that, you know, we feel like actually there's a lot more potential there than is reflected on our share price. You know, as we think about things, clearly we're focused on paying down debt. You see we're really aggressively managing our cost structure, you know, working on the break-evens. But I think from our perspective, you know, we've got to make sure something really makes sense for our shareholders. and protect the shareholders because we see a lot of upside potential, you know, on a relative basis with our share price just because of the potential in Suriname. So, you know, you can't stick your head in the sand. You have to keep your eyes open. But, you know, we're going to be, you know, very cognizant of shareholder value. Thank you.

Our next question comes from the line of Mr. Charles Mead of Johnson Rise. Your line is now open.

Morning, John. To you and your whole team there. Hello, Charles. 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 casting while you're on right now?

We did not, Charles. You know, we're drilling ahead. We did run into some hole stability problems in the upper portion. You know, we've since sidetracked. We've set, you know, pipe, and, you know, 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. But, you know, we're not going to lay out a timeline yet. But, you know, things are going well.

Good. I appreciate that, Connor. That's helpful, John. And then the follow-up, back to this Bon Boni. And as you can imagine, we all have a lot more questions than 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 campaign in San Antonio, California. intervals you're targeting there, but they're in a shallower, they're shallower because it's, you know, you've got some, I guess, basin thinning going that way. Can you talk about, you also mentioned that they're kind of the same settings. Can you talk about whether these are, I would expect these are more aridly large basin floor features as you move in that northeast direction, but is that a fair inference to make, or is there anything else we could talk about, the different kind of play versus what you've established already with your string of four wells?

No, I mean, and I can answer, you know, one of the questions on the water depth. I think we're at about 2,000 meters of water with Bombani. So, you know, what you've got happening is, as we said, they're very significant independent features. You've got, you know, turbidite, you know, fan systems. But, you know, so what you're giving up is a little bit of the – you're kind of trading some of the water depth you know, for depth of the formation. So they do shallow a little bit, which we think is going to be a positive for maturity. But, you know, they're big, Charles, and, you know, 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, you know, there's just a lot of ground to cover between Maka, Kwas Kwasi, Sapakar, and Keskesi, and as you start to move out just that direction, you know, to Bombani. But Campanian, Santonian, a little shallower, you know, very large features, and then there's some things down below that, you know, we might be able to get to as well.

Got it. That'll be fun to watch. Thanks, John.

Mm-hmm.

Our next question comes from the line of Michael Ciala of CISO. Your line is now open.

Yeah, hi, good morning. Hess mentioned on its call that there are five penetrations in the San Antonio, in the basin, your three, and then two on the Stabrick block. And it sounds like currently drilling Exxon exploration well, and Guyana is expected to test both the San Antonio and the Toronio. I'm 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 it, you know, after other than what HIMARA might have done for us, you know, it hasn't been beneficial to us. You know, I think it just shows you the depth and the, you know, the number of targets we've got. I mean, it's, you know, the Guyana Basin is turning out to be a super basin. You've got a, you know, a maturity and multiple source rock that's working. You've got multiple targets. You know, they're high quality and, you know, we've penetrated, you know, both the Campanian and the San Antonio, you know, with all of ours. And I think a lot of that work will come back with, you know, through appraisal when we start to really get into more details about, you know, what would be our plans. you know, as you move, you know, post the appraisal plan. But it just shows you the thickness. It shows you the sands. You know, we had over 900 feet and, you know, cross quasi between the two zones. So it just shows you the depth and just what, you know, how target rich this environment is for both.

Very good. And, excuse me, can you talk about, you know, your decision to complete the Ducks and the Permian rather than the generate more free cash flow, and will all those be in the Midland Basin, or are you planning on completing any at Alpine High if gas prices continue to improve?

Well, actually, I think the first three are going to be Alpine High. So, you know, there will be three 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 costs. I mean, costs are down significantly now. from where they were in the first quarter. And, you know, I think it's just, you know, 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, you know, 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, you know, we just see it as a good window to commit, put two frack crews to work, and go knock these out. Makes sense.

Thanks, Jonathan. 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 CERNAM, you made a couple of references here to deeper zone or zones below the San Antonio, 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 Bomboni test, how applicable those zones 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, you know, it's likely going to be more appraisal than exploration, but you're going to see a similar pace, you know, with two rigs and You know, so there's going to be multiple exploration wells is the best way to say it. But, you know, we're going to have the flexibility with both those rigs to do both. So you'll start to see the programs, you know, kind of blended as we kind of go out and, you know, prioritize things. Another thing I would say is when we started out and did all of our early work, you know, we've seen eight different play types on Block 58. And to date we've tested two. uh two of those the first three were the campanian and the santonian um you know we've seen all both of those and all the first three wells we attempted to get down to the tyronean but we ran into too much pressure in the santonian um you know at maca um and so there's clearly the you know the tyronean would be one of the next targets that we'd like to to get to, and it's just a matter of figuring out, you know, when and which well we want to do that with. We think there's great potential there. And then 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. But, you know, that's for a later conversation, you know, later down the road. But there's just a lot here in this block.

Great, thanks. 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?

Yeah, Brian, I think that's question that's probably in terms of specific numbers best left for when we talk about 2021 and more detail typically in February but you know what I would say is that you know we've got after the G&A costs pretty quickly because we knew what we were going to do on organizational restructure and we 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 costs 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 spin and turnarounds and pace of work over activity and things like that. They just affect operating costs a lot more than G&A, which tend to be more steady. And then on the G&A side, we just get the weird little accruals that we have like this quarter. But 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.

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 times about some of these deeper zones. Do you think that the deeper zones, in particular the Toronian, are going to be part of the appraisal plan already here as you look at, you know, a few of the wells, Maka, Sapakura, Kwasi Kwasi. Is that contemplated already for 21?

At this point, you know, Leo, we don't have, you know, we haven't explored or gotten down to the Toronian. So, you know, it would be early to call it appraisal until we can get down and actually, you know, successfully explore. So we'll find a place. Maybe, you know, you might take an appraisal well that we decide to deepen and put an expiration tail on it. but we'll just see how we work through that. But, you know, right now all the appraisal work is going to be in appraised discoveries, you know, which we've already quantified.

Okay, that's helpful. And I guess you guys obviously laid out a plan to hold your 4,220 per million oil volumes flat, you know, 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, you know, order of magnitude of those declines. I'll be talking kind of 10%, kind of single digits. What are you guys thinking here for North Sea and Egypt next year?

Yeah, I mean, I think, you know, you look at our base overall decline, both areas, it's kind of like where North America is. You know, it's all around 25%. You know, North America is a combination of the – 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. But we will be active there, so it's modest, as we said. And then Egypt is also, you know, it's really good conventional rock. On average, our decline rate is probably close to 25% in Egypt. You know, we came into the year running about 10 rigs there, and 10 years is, you know, 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. So, you know, five to six is not a lot for when you consider the size of our position, how much production we're making there, you know, in terms of the volumes and so forth. It really is not a lot of activity just for the size, scale, scope of that business. But, you know, 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. Neil Dingman of QS Securities. Your line is now open.

Good morning. I'm going to cover it. So my question is on Egypt. You've been running the five-week plan now for some time. Did economics sort of favor that continuous plan? Could you see maybe even adding more activity there? You talked a little bit about just activity in that plan.

Yeah, actually, Neil, we came in the year with 10. So we dropped to five when we had to cut capital because we cut everywhere, right? 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 said, we're prioritizing free cash flow. We're prioritizing capital. You know, debt repayment, and we're doing that at the corporate level. So, you know, Egypt is contributing some free cash flow. It's very where we could, you know, 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, that makes sense. And then same thing with just allocation. I mean, I guess the way gas prices are running, any thoughts or just any comments you can make around that? potentially even minimally revisiting the alpine high.

Yeah, I mean, like I said, we've got, you know, on the ducks, we're going to go knock out, I think, three ducks 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-priced 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, You know, there's a portion of Alpine High that is, you know, 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, you know, really hinges on NGL prices. you know, as well. So it's nice to have that optionality in the portfolio. And we'll just have to kind of look at, you know, if we were to put more activity to work in the Permian, you know, based on price decks where it would go into the oil plays in our Midland Delaware or, you know, 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 Cohen. Your line is now open.

Thanks, guys. Lots to answer today. I just wanted to follow up a little bit just on the ducks 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, you know, 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've just got to step back and factor everything in. Clearly things have improved out there. And, you know, we'll just have to kind of factor all that into our math of where we would put capital back to work. But, you know, right now we don't have anything laid out. As we laid out the early look for 2021, at 40 and 275, you know, you're not likely going to see, you know, any sustained, you know, 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 Crisman 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 CERNOM 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.

Thank you.