APA (NASDAQ:APA) Q4 2019 Earnings Call

0:00 Ladies and gentlemen, thank you for standing by and welcome to the Apache Corporation fourth quarter 2019 earnings announcement webcast. At this time, all participants are on a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask the question during the session, you will need to press star then one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star then zero. I would now like to hand the conference over to your speaker for today, Gary Clark, Vice President, Investor Relations. You may begin.

0:39 Good morning, and thank you for joining us on Apache Corporation's fourth quarter financial and operational results conference call. We will begin the call with an overview by CEO and President John Christmann. Steve Riney, Executive Vice President and CFO, will then summarize our fourth quarter and full year financial performance. Dave Purcell, Executive Vice President of Development, Planning, Reserves, and Fundamentals, will also be available on the call to answer questions. Our prepared remarks will be approximately 15 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our fourth quarter financial and operational supplement, which can be found on our investor relations website at investor.apachecorp.com.

1:26 Thank you for joining us. 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.

2:16 And with that, I will turn the call over to John.

2:20 Good morning and thank you for joining us. On today's call, I will recap Apache's 2019 accomplishments, discuss our fourth quarter performance, and conclude with an overview of our strategic approach for the next few years. For Apache, 2019 was a year of both progress and challenges. Our most significant challenges were associated with Alpine High, which I will discuss in a few minutes. Our progress, however, was on many fronts. We took steps to advance key environmental, social and governance initiatives, met our corporate goals around capital spending reduction and cash returns, further streamlined and repositioned our portfolio, and strengthened our balance sheet.

3:07 Specifically, over the last year, we enhanced our global sustainability efforts by linking ESG goals directly to short-term incentive compensation initiated alignment of ESG disclosures with SASB and TCFD recommendations and began to earmark capital specifically for ESG projects. We launched a comprehensive corporate redesign to further align our organization, work processes, and cost structure with lower long-term planned activity levels, and we reduced upstream capital investment by 23% We also delivered cash return on invested capital consistent with our corporate incentive compensation target of 19% and continued to streamline our portfolio with the divestment of assets in Oklahoma and the Texas Panhandle.

4:05 Internationally, we generated a substantial inventory of new, drill-ready prospects in Egypt through our recent seismic and acreage evaluation initiatives. We sustained production levels in the North Sea with a 100% drilling success rate and achieved first production from our store discovery, which was on time and on budget. And at year end, we signed a joint venture agreement with Total in Block 58, Suriname, which brought in a world-class offshore operator and established a substantial capital access framework. This enabled Apache to retain a 50% working interest in the block while significantly reducing our exposure to potential large-scale appraisal and development spending.

4:54 Moving now to the fourth quarter, oil production in the Permian Basin exceeded guidance and averaged the highest quarterly rate in Apache's history. Since mid-2017, we have operated our unconventional oil-focused program at a relatively steady and deliberate pace. This has generated highly competitive well results Thank you for joining us. A further investment in Alpine High.

5:47 In the second half of 2019, extended flow data from key spacing and landing zone tests indicated disappointing performance of our multi-well development pads. While these tests are not fully conclusive for the entirety of Alpine High, given the prevailing price environment, further testing is not warranted at this time. As a result, we dropped the remainder of our drilling rigs in the fourth quarter and chose to defer some previously planned completions. In Egypt, gross production in the fourth quarter was relatively flat with the third quarter. Adjusted production volumes in the quarter were adversely impacted by a one-time cost recovery settlement agreed to by our partner in one of our non-operated concessions.

6:35 This should have no ongoing impact on future production volumes. Strong drilling results in Egypt during the quarter position us well for 2020 and we look forward to testing some high-impact oil prospects on both new and legacy acreage beginning around mid-year. Production in the North Sea increased significantly following seasonal platform maintenance turnarounds in the third quarter and first production from our store discovery in November. Startup of the Garten 2 well was delayed into the first quarter as previously disclosed. This well is now online and will drive a further production increase in the first quarter of 2020. Turning now to Suriname, we drilled our first well in Block 58, the Maka Central No. 1, during the fourth quarter, and subsequently announced a significant oil discovery in January. We are now working with our partner, Total, on an appraisal plan which will be submitted to the state-owned oil company Stazzoli in the coming months.

7:39 In January, the noble Sam Croft drill ship moved from Macca to our second exploration prospect, Sapacara West. As we noted in last night's press release, the Sapacara well is drilling ahead to the Santonian interval as planned and we are encouraged by what we have seen thus far. Following Sapakara, we will drill a third and likely a fourth exploration test in Block 58. Looking longer term, Apache's differentiated asset portfolio and disciplined approach gives us confidence in our ability to continue to improve returns and deliver competitive share price performance relative to our peers. As demonstrated over the last few years, we clearly have a significant inventory of Thank you for joining us.

8:54 that would otherwise be directed toward shorter cycle growth opportunities elsewhere in the portfolio. As a result, our near-term production growth will be a bit slower than it otherwise could be, but we believe the long-term potential far outweighs any short-term impacts. Over the coming years, our strategic approach will center around retaining free cash flow in excess of the dividend for the purpose of reducing debt, Continuing to prioritize long-term returns over growth, aggressively managing our cost structure, and advancing our exploration and appraisal activities in CERNOP. One of the primary financial objectives is to reduce debt over the next several years.

9:41 We will do this with cash that is primarily sourced from operating cash flow. As a result, our upstream capital investment will be determined by the oil price environment. For 2020, we are budgeting $1.6 to $1.9 billion, which allows for an uncertain price environment centered around a $50 WTI oil price. In terms of capital allocation, Alpine High will receive minimal to no funding, and we are shifting some capital from Permian Oil Projects to Egypt, which is better insulated from weak oil prices due to the production sharing contracts. With this plan, in 2020, we expect to maintain our current dividend payment, which is yielding approximately 3.5%, retain free cash flow to initiate progress on our debt reduction goals, allocate approximately $200 million to expiration, and invest $1.6 to $1.9 billion of capital, including expiration, which will result in flat to low single-digit corporate oil production growth year over year.

10:52 To the extent oil prices continue to fall, capital will be reduced, as will our near-term production outlook. That said, if oil prices move materially higher, we will prioritize further debt reduction over increasing capital activity. Moving now to our corporate redesign initiative. We are well down the road with the process of both rightsizing and reorganizing our technical, operational, and corporate support functions. The rightsizing is a recognition that we will not be returning to past levels of capital activity and need to make a permanent reduction in headcount. The new model, which is enabled by a more focused portfolio, is more centralized and will tie incentives to asset team performance rather than to regions.

11:43 It is designed to enhance collaboration and enable greater mobility of technical personnel as capital is redirected across the portfolio. We expect to achieve at least $150 million of annual savings from overhead and operating cost reductions associated with this initiative. Over the coming months we will provide more information around the structure of the new organization. And with that I will turn the call over to Steve Riney who will provide additional details on our 2019 results and 2020 outlook.

12:20 Thank you, John. My remarks this morning will provide a few more details covering Apache's fourth quarter and full year 2019 results, the progress to date on our organizational redesign, and our 2020 financial objectives and guidance. I will also comment on our recent efforts to reduce long-term gas transportation commitments Thank you for joining us. The most significant of these are non-cash impairments of $1.4 billion related to Alpine High wells, facilities, leasehold, and other upstream assets, and $1.3 billion for Altus Midstream gathering, processing, and transmission assets.

13:22 We also recorded a $528 million impairment of Alpine High unproved leasehold assets, which is included in exploration expense. Excluding these and other smaller items, adjusted earnings for the quarter were $31 million, or 8 cents per share. During the fourth quarter and throughout 2019, Apache maintained a very steady pace of capital activity and spending. Upstream capital investment was less than $600 million in each quarter of the year, putting us below our full-year budget of $2.4 billion. Total production during the fourth quarter exceeded our guidance, Most notably for Permian Oil, which benefited from good well performance and the timing of pad completions.

14:09 From a financial perspective, during 2019, we continued to fund our $376 million dividend payment, which is one of the highest yields in our peer group. We generated full-year cash return on invested capital consistent with the corporate incentive compensation goal of 19%. We paid off $150 million of debt and we refinanced a portion of our long-term debt significantly extending our maturity profile while lowering our average borrowing rate. As you may recall, anticipating alpine high volume growth, we contracted for around one BCF per day of long-term natural gas transportation capacity out of the Permian Basin. Consistent with our decision to substantially curtail investment in alpine high, we are taking steps now to reduce those commitments.

15:01 To date, we have eliminated approximately 310 million cubic feet per day of take-or-pay obligations, and we have more in progress. As John noted, we are also making good progress with respect to our organizational redesign. We will substantially complete the redesign for our technical functions by the end of the first quarter, while work on the corporate support functions and field operations will likely continue through much of 2020. We remain on target to achieve our goal of at least $150 million of annual savings, and we'll get to this run rate of savings sometime in the second half of 2020. This effort will, of course, result in some one-off costs. $28 million of these costs were recognized in 2019 and make up the majority of the $33 million of transaction reorganization and separation costs in the fourth quarter results.

15:57 The remainder of these costs will be recognized in 2020. Turning now to 2020, one of our key financial goals for the year is to retain free cash flow after the dividend. This will be used to begin funding our longer term objective of paying down $937 million of debt maturing over the next four years. While the softening price environment is making this increasingly difficult, debt reduction is a key priority and we are committed to flexing the size of the capital program to ensure progress in 2020. To conclude my remarks, I would like to provide some commentary on full year 2020 and first quarter guidance, the specifics of which can be found in our fourth quarter earnings supplement.

16:43 For the full year, the allocation of our capital budget is intended to balance two competing objectives, funding a proper pace of activity to test the significant long-term potential of CERN on Block 58 While at the same time, investing in near-term development to sustain or grow total oil production. As John noted, we expect to deliver on both of these objectives with our $1.6 to $1.9 billion upstream capital program this year. Natural gas and NGL production will decline year over year, primarily due to the activity reduction at Alpine High. In the first quarter, alpine high volumes will be slightly below fourth quarter 2019 levels of 95,000 BOEs per day, and we expect this to decline to around 50,000 to 60,000 BOEs per day by the end of the year.

17:36 These numbers do not include the impact of potential production curtailments due to negative Waha Hub pricing. Turning to the cost side, because the organizational redesign will impact both the level and timing of cost savings, We are providing only first quarter estimates for GNA, LOE, and exploration expense. We will update our guidance on these items as we progress through the year. On a final note, primarily as a result of the fourth quarter impairment charge, we are projecting a material decrease in DDNA. We expect DDNA per BOE for 2020 will be around $13.50. And with that, I will turn the call over to the operator for Q&A.

18:22 Thank you. Ladies and gentlemen, as a reminder to ask a question, you will need to press star then one on your telephone. To withdraw your question, press the phone key. Again, it's star one to ask your question. Please stand by while we compile the Q&A roster. Our first question comes from the line of Doug Liggett with Bank of America. Your line is open.

18:46 Good morning. It's actually John Abaddon for Doug Liggett. He's on a plane right now and he's listening in on the webcast. Good morning, John. Yeah, we just have a couple of questions here. Staying with Suriname, you said that you like what you so far see from the shallower target, but you're also planning multiple tests. Can you elaborate on what you have seen so far? For example, have you encountered hydrocarbon-bearing reservoir sands?

19:14 Well, thanks for the question. In general, we don't like to comment on specifics about a well while it's drilling. So, you know, what I will say is we have, you know, drilled through the Campanian. And as I said, we are encouraged by what we have seen. We are headed on to the Samptonian. And as we, you know, as we put in the materials last night, you know, the plan would be to run open hole logs, capture fluid samples, cores, pressure tests, and so forth.

19:46 All right, and then for our follow-up question, on the appraisal of Mocca Central, what's the expected timing? Should we see a result in 2020? Can you provide any context on lateral footprint, sand thickness, as we're trying to confirm our view that the Block 58 might be the deposition center of the basin?

20:05 At this point, what I will say is we are working very closely with our partner, Total, I'm not in a position to give any color because we have to work up that plan. There's a timeline where we need to deliver that to Stasoli, which we will do. We're excited about it. We're working on it jointly, and we'll be able to talk about that more in the future.

20:28 Hey, appreciate it, and thank you for taking our questions.

20:31 You bet. Thank you. Our next question comes from the line of Bob Brackett with Bernstein Research. Your line is open.

20:42 I'll try a different tack to the former questions. You mentioned fluid sampling on the Sapacaro West. Do you routinely fluid sample formation water?

20:57 Bob, that is not something we would typically do, but it all depends on what we've seen and running the right tests according to what we've seen in the well.

21:08 Okay, appreciate that. Quick follow-up. You mentioned $200 million of exploration. I imagine that's dominantly Suriname, but could you break out any other interesting aspects to that exploration budget?

21:19 I will say the lion's share of that is Suriname. You know, we do have some things on the unconventional side that we're slowly watching and working, but the majority of that, you know, will go to Suriname. Great. Appreciate it. Thank you. Thank you. Our next question comes from the line of Mike Schala with Stiefel. Your line is open.

21:47 Yeah, good morning, everybody. I don't normally do this, but I have to give Bob kudos. That was, in my 20 years, probably the best-asked question I've ever heard.

21:59 It was a good question, Mike.

22:01 It definitely was. Steve, you had said you're reducing your commitments from Alpine High. I just wonder what that looks like. Does that take place at the Altus level, and are you able to actually sell some of the firm transportation that you've taken on Gulf Coast Express and Permian Highway?

22:25 Yeah, Mike. So I'm not going to be able to speak to specific pipelines. We've got multiple pipelines. contractual arrangements for moving gas out of the Permian Basin. And so it's also not specifically related to Alpine High in terms of the gas evacuation. It's just gas evacuation from the Permian Basin. Let me just step back from that a little bit. We mostly sell our equity production actually in basin, and therefore, like on the blast facts that you received with our earnings announcement, what you see is the realized price in the Permian Basin at Waha or at El Paso Permian. We have a marketing team that then recommends and implements taking actions around how do we make sure that basin prices are connected to the broader market over the long term. And an example of an action that they might recommend and did was we need to get some pipelines built to the Permian Basin, from the Permian Basin to the Gulf Coast, and we helped FID The two pipelines that you talked about in doing that.

23:33 And that will, and it did for a while, and it will help connect the Permian Basin to the Gulf Coast. Our marketing organization then manages the exposures associated with those assets. And so we typically manage that by purchasing gas in basin and transporting it to meet our obligations on those pipes. We have chosen now to reduce our longer-term exposure. We've accomplished getting those built by participating in the FID process. Those are obligations that do not involve Altus Midstream. That's an obligation of Apache Corporation, and we've decided we want to start reducing some of those exposures, and we have initiated that process.

24:20 As I said in my prepared remarks, We've contracted away. Basically, we've contracted with counterparties to take over our obligation of up to 310 million cubic feet a day. That doesn't start immediately, so we still maintain some exposure to that in the short term, and that's probably a good thing at this point in time, but we're taking away the longer-term exposure on some of the pipeline transport capacity that we have in the Permian Basin. And at this point, we're still working on a bit more of that. We would like to bring that down just a bit more.

25:01 That's great. Thanks for all that detail. And I guess, sticking with Alpine High, John, how are you thinking about it now? Do you keep that as a long-term option on gas, or do you think it makes sense to consider a divestiture there at some point?

25:22 What I'll say, Mike, I'll go back and just take a few minutes here, but when Alpine High was announced in 2016, we had great hope for what it could mean for Apache. It had all the key ingredients of an impact play, large scale, low cost of entry, and we had acquired the heart of the play. In the end, a number of factors were problematic at Alpine High. First, as you just recognized, gas and NGL prices fell to less than half of the prices we anticipated for long-term economics. Second, the lack of infrastructure prolonged the period to test full development. And this, along with the sheer stratigraphic size and aerial extent, increased the cost and time to do so. Third, the lack of cryogenic processing capacity did not allow us to test the NGL mix and yields until the middle of 2019 when we actually got the cryos on through Altus.

26:20 Fourth, we anticipated a meaningful uplift in well productivity and a significant decrease in well costs as we moved to pad and pattern development, as is the case in almost all unconventional resource plays. We were able to drive costs down below our goals But the uplift in productivity did not materialize. So today, we've got about 240,000 acres. There's about 200 of it that will kind of expire over the next three years. and there's some optionality there. But if you look at the macro environment today, if we got back to an NGO market where we were late 18, there's definitely some things that would be economic.

27:06 But how does it compete in our portfolio is another question. And so that's why we made the decision we made today.

27:15 Very good. Thank you.

27:17 You bet. Thank you for the question. Thank you. Our next question comes from the line of Gail Nicholson with Stevens. Your line is open.

27:27 Good morning. Thanks for taking my question. Two things. One, in Egypt, you know, in my opinion, the market still continues to discount the Egyptian asset. Can you talk about the inventory running room you guys have identified post the seismic analysis in Egypt?

27:43 You know, what gets lost in the shuffle is you've got conventional rock, What has the stratigraphic column and the aerial extent greater than the Permian? We have over 6.2 million acres. I think with the new acres that we've added since 2016 and the new 3D that we're shooting, and then you look at our operational footprint, we have a very large business over there which gives us a nice backbone to kind of fill in off of. What I'm excited about is we used to be maybe six months of inventory Today we see years of inventory and we've really high graded some very interesting things that if they were, could be game changers. And so, you know, we're very optimistic about where we are with Egypt and some of the things we've got on the drill schedule. They're off to a really good start.

28:32 As we said in the prepared remarks, they drilled some really nice wells, Q4. And, you know, we've got some very interesting things to test. But it's Brent. The PSC really insulates you, which is another nice factor. As we mentioned today, we're going to be shifting a little more capital into Egypt. but I think it's through the productivity and the opportunity set that we've identified and quite frankly we just have a lot more inventory that's kind of drill ready that we can prioritize and get after.

29:01 Great, thank you. And then on slide 13 you guys show the 4Q19 operating cash margins. Just to clarify, does the Permian cash margin include Alpine? And if so, if you remove Alpine from that number, what would the non-Alpine Permian cash margin be?

29:19 Yes, it does include that. In terms of with all the reorg and stuff we're doing, our numbers are going to be reported that way, so we didn't really want to break it out, but Gary can probably get back with you on a follow-up or something and give some insight.

29:36 Great. Thanks, guys. Thank you. Our next question comes from the line of Charles Mead with Johnson Rice & Company. Your line is open.

29:47 Good morning, John, to you and your whole team there.

29:50 Good morning, Charles.

29:52 I wanted to, first off, thanks for bringing, or for giving us that detail on the garden well. I believe that's slide 12 of your presentation there. And it looks like a really stout rate. I was wondering if you could just give us one discrete data point, which is what would your net be off of that gross rate?

30:12 Charles, this is David Purcell. That's 100%. We have that prospect. We had that at 887.

30:19 Got it. Got it. And then, thanks for that, Dave. And then, John, there's been some discussion in the reports in the news media about, I guess, A&D opportunities in Egypt. And particularly in light of you guys reallocating some capital that direction because of the attractiveness you see there. How would you characterize your appetite for more assets in

30:46 Well, I mean, what I would say, Charles, is that we don't typically comment on A&D activity. You know, I think today with the plan we have and the market where it is today, you know, you wouldn't see us coming out of pocket for something. But, you know, there's an asset base over there. We have a very nice footprint, and there might be a way to do something, you know, on a creative side.

31:12 Okay, thanks for that, John. Thank you. Our next question comes from the line of Bryant Singer with Goldman Sachs. Your line is open.

31:22 Thank you. Good morning. Good morning, Brian. Moving back to Suriname, you mentioned the fourth exploration test would be likely. Can you just talk about the timing for making that decision and then what next steps would be from a Reagan decision-making perspective for further exploratory testing?

31:43 Well, with the rig we've got today, the Noble Sam Croft, we've got one well we've already exercised the option on, and then there is another well we can drill. As I said, it's very likely we will do that, but we don't have to make that decision yet, and so it's an option we just haven't pulled the trigger on. But after, you know, if we were to elect that option, which I said is likely, you would, you know, we'd finish the current well we're on, we would drill the third well, and then potentially the fourth well, and then we will release the rig. And I'll just say that, you know, any of the appraisal plan at MACA will come back with a different rig and a different timeline when we're in a position that we can talk about that.

32:29 Great, thanks. And then back to the Back to the North Sea, when you put together the recent well and garden declines, et cetera, how do you expect your production trajectory for oil to look over the course of the year?

32:47 It's going to be early. I mean, the first quarter is going to be strong with, you know, Garten we delayed from Q4 into Q1. So with the Garten 2, I think it's going to continue to be lumpy. You know, we've got more wells to drill at Garten. We've got some other prospects that are interesting as we tie back. So North Sea is going to continue to be, you know, fairly lumpy based on when we bring these high-rate wells on.

33:11 Great. Thank you.

33:13 You bet. Thank you. Our next question comes from the line of Leo Moraney with Key Bike. Your line is open.

33:24 Yeah, hey guys. I know it's a bit difficult, you know, to sort of know for sure, but I guess I was just looking to kind of get a high-level timeline in terms of when you guys might kind of finish drilling and then some of your analysis that you talked about on the Sapa Currowell. Is that... kind of a roughly one-month type of thing, 45-day type of thing. Can you just give us maybe a high level in terms of when you might be able to give us a full suite of information on that?

33:50 Yeah, Leo, as I said, you know, we don't typically like to comment on a well while it's drilling. But we did learn our lesson in December at least to not, you know, to give you a little bit of an idea in terms of a comment. So that's why we said we're encouraged. You know, we're through the Campadian. We've got the San Antonio to drill. and then after that we'll have some time to do the evaluation. So not also going to give you a definitive timeline but we'll get to that as soon as we can after we TD the well.

34:25 Got it. Understood. Okay. And I guess just with respect to the Permian, it seemed like you had some very strong wells in Lee County, New Mexico that you guys had reported supplemental information. Just wanted to get a sense of what the depth of your inventory is in that general area there in New Mexico.

34:49 Yeah, Leo, this is Dave Purcell. I think generally if you look at our unconventional inventory, we have more activity in the southern Midland Basin side than when you look at New Mexico and the Delaware Basin generally. But we have deep, deep inventory across both areas. both basins, and as you look out, we're just drilling a small fraction of our total footprint, and we feel good about the long-term inventory depth both in the southern Midland Basin and the Delaware Basin.

35:22 Okay, so I guess a lot more inventory in southern Midland versus New Mexico. Is that the way to interpret that?

35:29 Yeah, I would interpret it that way.

35:31 Okay, thanks. Thank you. Our next question comes from the line of a room, Jay Aram with JPMorgan. Your line is open.

35:42 Yeah, good morning. John, in Total's 4Q update, they talked about a $2 per barrel kind of cost of acquisition. Presumably, you guys maybe improved that type of language. So I was wondering if there's any Read through, I know we're very, very early in the delineation appraisal of Suriname, but of sizes of potential discovered resource at this point.

36:12 I would just say that is the language they put in and how they characterized it. I mean, I'll just leave it at that.

36:21 Got it. Got it. Fair enough. And then just maybe my follow-up, could you maybe elaborate, John? You talked about an appraisal plan that you'd be working on. What goes into that? And can we make any clues regarding when we could achieve first oil if your delineation efforts prove successful? Or the path to getting first oil?

36:49 You know, what I'll say is there's, you know, the... The agreements with the concession terms line out a timeline that you have to follow. So you have a discovery declaration, and then we have a window where we have to submit the discovery notice, and then we have a window where we have to submit the appraisal plan, and then the development process. There's a timeline that we're on there, and we're working through it expeditiously. And I think us and our partner will try to accelerate those things as quickly as we can based on the results that you get from the appraisal program.

37:28 Okay. Thanks a lot, John.

37:30 Thank you. Thank you. Our next question comes from the line of Richard Tulis with Capital One Securities. Your line is open.

37:39 Hey, thanks. Good morning, everyone. John, Given the lower CapEx budget that kind of fits the current times and the allocation for the Suriname activity, of course, any assets that you see in the portfolio that may slip into maybe the better to monetize category?

37:59 Yeah, I think today we look at the portfolio and we really like the balance. We've done a lot of that over the last couple of years. I mean, you look at the, I'll call them gas-rich or gas-heavy assets we divested in Canada. I'm very glad we got our scoop stack and our mid-continent sold last year. So you look at the portfolio today, it's tight. We're in nice areas. There's always some small little things that we do from time to time. Even within the Permian, either trades and swaps and acreage here and there that we're willing to monetize if people are interested. So we're constantly looking at that. But I don't think there's anything that's big that we'd say today we need to move or would move right now in this price environment.

38:47 That's helpful, John. And just to follow up, how many wells were drilled to date in the Alpine High and how many of those wells are online currently? Yeah, Richard, this is Dave Persaud. I don't have the exit numbers, but it's coming to the low 200s that we've drilled and around 200 that are online.

39:11 Okay, thank you. That's helpful. I appreciate it. That's all for me. Thank you. Our next question comes from the line of Neil Dingman with Frontrack. Your line is open.

39:23 Morning, John and team. Congrats on bucking this disastrous energy trend right now. My First question is on your Permian. You all continue to do a great job of having one of the more stable plans that are in the play. And I'm just wondering, while I assume the change in oil prices probably won't impact your pace, I'm just wondering, John, will that have an impact on how you think about spacing some of these multi-zone developments?

39:46 No, I mean, I think the key for us was, you know, we spent really 16 and 17 really very thoughtfully and methodically understanding how to develop. And we got the pads early. and really work through that work, you know, at that time. And so what you've seen is a very steady plan. I mean, we've got about nine months of rig activity just, you know, kind of lined out. And it gives us the ability to work the infrastructure, do all the things we need to do, you know, ahead of that. So I don't see any changes in terms of, you know, to our development approach. You know, what we have the luxury of doing, though, is backing off that capital because it's short cycle in nature. This is not something we have to drive forward in this price environment. So the only thing you might see, as we mentioned, the price is down where they are today, even below the range we talked about.

40:39 You might see a little further slowdown just because we had the luxury and can do that. I think it's also important to keep frack crews working and a couple of rigs working. So I'll call where we maintain our execution fitness and we continue to work on a continuous improvement to drive those results. But it's been all about getting the pads, doing the testing, looking at the long extended flow periods, and really unlocking that so we understand how the wells can perform so you can really invest that capital as efficiently as possible.

41:14 Great, great details. And then my second question is on the North Sea. I'm just wondering, maybe you've already said, but I'm just wondering about we have potentially the same amount of downtime, and I think it's 3Q, and then the plan to run, continuously run the three rigs.

41:28 I mean, I think if you look today, we've had a platform rig running both at barrel and 40s, and we've had the Ocean Patriot. We will have the Ocean Patriot this year. We actually... did an exploration arrangement where we're getting carried on a couple wells in the North Sea up there in the barrel area, which helps a little bit on the capital this year, but similar program as what we would envision for 2020. And you do have your traditional maintenance season, which we usually get in the third quarter, summer months when the weather gets a little better.

42:03 So that'll just be the typical maintenance, you think, John?

42:06 Yes. And then really weather, I mean... It was weather is what kind of drove us to have to wait to bring, you know, Garden 2 on. So you came out of maintenance turnaround, and then we got into some pretty rough weather, you know, in the fourth quarter, and that was what kind of, you know, had us kick some things back.

42:24 Thanks so much. Thank you. Our next question comes from the line of Janine Wade with Barclays. Your line is open.

42:32 Hi. Good morning, everyone. Good morning. Good morning. Good morning. My first question is on maintenance, CapEx maintenance mode. at the 2020 CapEx budget level you're around maintenance mode at the low end I believe and so looking forward to 2021 are you able to maintain flat year-over-year production at a similar 1.6 billion CapEx budget or are there some one-offs this year that are kind of driving that number lower so I guess what I'm getting that getting at is that next year there could be some incremental cash flow from Altus with the pipelines and so that could help fund Suriname CapEx.

43:08 Yeah, Janine, this is Steve. So, you know, I think the first thing we ought to do is there's a lot of people out there like to talk about maintenance capital and lots of uses of that terminology. And I think, you know, we like to think about things like that in a purist way. And so we need to be clear what we're talking about. For us, maintenance capital means we maintain oil volumes and we pay the dividend, but not necessarily any free cash flow creation. You know, it's equally important that you look at how those definitions vary over a timeframe. You know, you can have a maintenance capital. Some people think of maintenance capital as, well, it's just the next year. And the next year, you know, that's one of those cases of, well, how long can you hold your breath?

43:58 And maintenance capital for a year can be pretty darn low. We like to think of maintenance capital at least in a five to ten year timeframe. And so that includes ongoing asset integrity spend and that includes spending on inventory progression so that you can maintain production over that five to ten year period. You can also think of maintenance capital over a longer term, 20 plus years, and then you need to start introducing exploration spend as well. And so we don't bother with the one year definition because we don't want to test how long we can hold our breath. We just wouldn't bother with a one-year maintenance program or a maintenance spend program. In a five- to ten-year timeframe, we've been pretty consistent for the last five years saying we're somewhere around $45 WTI.

44:51 We can pay the dividend, maintain oil production volume with no free cash flow retention. And, you know, is it $44? Is it $46? It's somewhere around the $45 WTI range. It's been there for a number of years now. If you go to the 20-year plus definition, it's probably in the $48 WTI range. That gives us enough money to spend on exploration like we're doing now, and we've specifically budgeted for 2020 $200 million of exploration capital. And so that's the way we like to think of it. Another way to think of it for us is that, you know, if you're in a $50 to $55 world for the long term, for the next several years, We can continue to fund the dividend. We can fund some cash to pay down debt as we were talking about.

45:39 We can sustain oil production volume or grow it slowly over that four-year period. And we can fund Suriname to First Oil. And I think that's an interesting way to be thinking about maintenance capital as well. And, of course, success in Suriname. is going to significantly lower that maintenance capital level on WTI prices because of the structure of the capital carry that we have in our joint venture agreement with Total. So you get out a few years from now, then maintenance capital falls way below that $45 to $48 WTI price environment because of that capital carry. In terms of specifically looking at, you know, there are a lot of different ways you can look at what we've talked about for 2020.

46:26 If you go to the $1.6 billion capital range, the low end of our range, that's contemplating a $46 to $47 WTI price. It means we still pay the dividend and we fund the $200 million of exploration spend out of that $1.6, and we're probably sustaining production volume at that level pretty flat for 2020, year over year. At the high end, the $1.9 billion capital, you're probably in the $53 to $55 range. You're paying the dividend and spending $200 million on exploration. You're retaining $150 to $200 million of free cash flow for future debt pay down.

47:13 And in that case, you're growing oil production in the low to mid-single digits for 2020. So a long-winded answer, but I hope that ticks all the boxes for you.

47:26 Oh, no, I think I definitely appreciate all the detail there. That's very helpful to know how you're thinking about it. Maybe just a short follow-up on that, following up on some of the other questions and some of the things that you just mentioned. You said potentially earlier in the call about accelerating the development process in Suriname if you have the opportunity to do so. So what are the governors who are pacing kind of medium-term Suriname CapEx? You mentioned prioritizing CERNOM. It sounds like from what you just said, you're committed to funding CERNOM at a free cash flow. We've seen prior precedents where folks try to pre-fund big major capital projects like this with asset sales. So I just wanted to clarify whether you're committed to funding CERNOM at a free cash flow or a combination of free cash flow plus any sale proceeds.

48:12 Yeah, Janine, so number one, hopefully I didn't say anything earlier that would lead anyone to the conclusion that we're trying to accelerate development in Suriname. I think it'll take its proper pace, and that's what it'll be between us and our partner, as we agree to that. So in terms of funding the activity in Suriname, first of all, by our joint venture agreement with With Total, it should be clear, you know, we were willing to spend 50-50 heads up on exploration because we are very excited about the exploration opportunities in Suriname. And we believe, obviously, that they'll continue to be successful.

48:59 When you get into appraisal and development, that's where the capital carry kicks in. And, you know, starting with appraisal of MACA, and any development spend that might come from that and appraisal from any further exploration successes. The 87.5 cents of every dollar will be spent by Total and 12.5 cents by Apache. And so we intend to fund any of that for the next four years out of operating cash flow. We don't think we'll have any problem doing that. If we have a problem doing that, that means we're doing a heck of a lot of appraisal and development, and that would be a great problem to have.

49:45 Okay, great. Thank you for taking my questions. Thank you. Our next question comes from Ilana Scott-Grover with Citigroup. Ilana, it's open.

49:57 Yes, good morning. Thanks for taking my questions. You bet. So turning to the cost out program, how should we think about the $150 million roughly split in between overhead and ops? And do you think you'll be able to achieve the full run rate of savings by year end?

50:16 I think at a run rate base, we'll be able to get there. I mean, a lion's share of that is likely going to come out of the overhead piece. But we're well on our way and working through that. and we should be able to get to that type of runway later this year.

50:34 Got it. And then you took some upfront charges associated with the program in 4Q. How do you think about upfront charges they potentially hit in 2020 as you restructure the business?

50:49 Yeah, we'll obviously be taking the one-off costs associated with that. We'll be recognizing those on a quarterly basis. We did recognize some of that. I think the number was $28 million in the fourth quarter out of the 33 that were in that one line item on our P&L. And we haven't put out an estimate of the total cost, but we'll probably do that as we go through the next few quarters.

51:16 Okay, that was it for me. Thank you. You're good. Thank you. Our next question comes from the line of David Deffenbaum with Cowan. Your line is open.

51:30 Morning, guys, and nice job, nice update. Thanks for the time. I just wanted to ask, you outlined what the cost guidance was in the first quarter, just in terms of your margins, as I guess the year progresses here and you have growth coming from several other areas and alpine high declining. How do you look at those cash costs, I guess, on LOE and GP&T by the fourth quarter of 20 relative to that $825 and $75 million in the first quarter?

52:06 Yeah, David, we intentionally just gave one quarter of guidance on that, and I'd prefer not to get into any more than that at this point in time. We'll give more guidance as we go through the year, as we get more Clarity on what those costs are going to be given the ongoing cost-focused program and the pace of change of that program. So let us do that as we go through the next few quarters.

52:31 Sure. I'll be patient, but appreciate it. If I could ask, I guess, secondarily to the other item on that, what are you all assuming, I guess, for the annualized decline out of Alpine High and and those total volumes that you have in the U.S. that are only down slightly on an annualized basis.

52:55 This is Dave Purcell. When you think about Alpine, we're not adding any completions this year, so you're going to see effectively the unconventional blowdown. So you'll have a steep decline in the first year, and then every year after that the decline will moderate. So think about something in the on an annual basis in the mid-30% for the first year, and then it will moderate in years two, three, and four. Got it.

53:28 Thank you, guys. Thank you. Our next question comes from the line of Paul Chen with Scotia. Your line is open.

53:37 Thank you. Good morning. Two questions. On the 150 minutes on the restructuring, do you Restructuring saving, do you have a rough estimate between how much is on the P&L side and how much is the capital cost?

53:55 No, we don't have an estimate of that at this point in time.

53:58 Okay. On Permian, in 2020, you're going to be five to six rigs. Do you have a split between the Midland and Delaware Basin?

54:12 Yeah, Paul, this is David Purcell. If you think about it in terms of gross completions, it's about 60% Southern Midland Basin and 40% on the Delaware side.

54:23 Okay. My final one for me, Law C, if we look at your portfolio, say, over the next five years, I mean, surname is very exciting, and Egypt look like you guys have some high hope. And look like Law C is probably not necessarily going to receive a lot of Capital attention from that standpoint. So should we look at loss, say five years from now, you still consider as a core part of your long-term portfolio or that you may need to be revisiting that?

54:58 I think today, if you look at what we're doing in the North Sea, I'm quite proud. We can look out and have three years of pretty stable production between the two. The volumes at barrel are lumpy as we're bringing on subsea tiebacks into our infrastructure there. Forties is all about the water management program and flattening that decline and managing our cost side. So I think today we look out, and quite frankly, we've made a lot of progress over the last three to four years on North Sea, and the outlook for the next several years looks as good as it's looked from a planning perspective as I've seen in a while.

55:39 Okay. But, I mean, are you going to put more capital into that, or that the sensory is in somewhat of the maintenance mode?

55:48 Well, I mean, we're definitely spending capital. You know, in terms of is it an area we're going to go out and try to consolidate and buy more properties and add that? You know, no. But I think we've got a lot of life left in these assets, and there's a lot we can do on the cost side. And, Steve, you had something you want to add?

56:07 Yeah, I'd just re-quote that famous quote of, rumors of my demise have been greatly exaggerated when it comes to the North Sea. In 2003, when Apache bought the North Sea assets, the 40s field, it was scheduled for abandonment in 2012. Today, it's scheduled for abandonment in the 2030s, and that keeps moving out. So, you know, there's a lot to do in the North Sea, and I wouldn't worry too much about the next three to five years.

56:40 Thank you. Thank you. Our next question comes from the line of Michael Hall with Heisigan Energy. Your line is open.

56:52 Thanks. A lot has been addressed, I guess. I just want to kind of circle back to the comment in the prepared remarks around the longer dated growth outlook being moderated as you're trying to bring CERNM on. Is it right then to just think about basically what we're seeing with the 2020 program is is basically what we should hold flat until we think about Suriname coming on and basically the businesses are in maintenance mode and with that you can then fund the work that's required to bring Suriname to fruition. Is that the right way to think about it, big picture?

57:34 Michael, it's really going to depend on what the prices do in between because we gave a range on the capital. You know, at 1.6, you're closer to that mode. At 1.9, we're going to show a little bit of, you know, growth. And so, you know, quite frankly, if we need to go lower, we will. And if we needed to let things move down a hair, we're not afraid to do that because we're going to prioritize, you know, paying the dividend, funding CERNOM, and paying down some debt. So, you know, we're very comfortable with where we are. We've got a differential asset base here. We've got lower decline rates because of the conventional assets in a lot of our areas. And so we feel very comfortable with kind of where we are over the next three to five years with that.

58:19 Yeah, I just – Michael, I'll just add, this is Steve. Just going back to the comments I just made a few minutes ago, you know, for the next several years at $50 to $55, which – Other than today, people have been generally talking about that's kind of the right price environment to be planning on with all recognition, appropriate recognition of where prices are today and where they're headed. At $50 to $55, we can do all of those things John just talked about. We can pay the dividend. We can fund Suriname to First Oil. We can Retain enough free cash flow to pay down debt, the $937 million of debt that will mature over the next four years.

59:10 And we can sustain or even grow. You get to the $55 price environment. We can grow oil production slightly over that time period.

59:19 Okay. That's helpful. And that's kind of contemplating like a similar four-well-per-year type exploration program. Is that reasonable? Yes.

59:30 Well, that's assuming $200 million a year spent on exploration.

59:36 Okay. And then on a more near-term basis, just kind of curious on the cadence, I guess, in the Permian on the oil program there. Is it basically just flat all year, or is there a low point that we ought to be considering in the 2Q, 3Q time frame if we bring things back up in the back of the year?

59:59 It's a steady program. We've got our unconventional program growing, and we've got some of the CBP and some of those things slightly declining, but it's a pretty steady program. That's the one thing. If you go back to mid-17, we've been real steady with the program, and as a result, it puts us in a pretty even cadence.

1:00:20 Great. No, that's helpful. Appreciate it, guys. Thank you. Our next question comes from the line of George Silverstein with Wolf Research. Your line is open.

1:00:32 Thanks. Two quick questions for you guys on Saranamp here. On the Makawa, you mentioned that the drilling design wasn't optimally placed and placed the well in the thickest zones there. I was wondering if that was the same thing at Sapakara or if you guys were trying to target somewhat differently there.

1:00:50 I would just say, Josh, it's a function of, you know, you've got your seismic ties, and you're working in, this was really our, Maka was our first well into Block 58, and so you learn things as you go, and what we've got is we have multiple stack targets in there, and, you know, we lined it up to kind of drill what we thought would be optimal on a few of them, and, you know, we kind of validated that, so... The point was, had we moved over, we would have probably had a different number in terms of net fee to pay and so forth. But you learn that, and that's what the appraisal programs will tell you as you start to work through any potential discovery that you have.

1:01:35 Got it. Thanks for that. And then maybe we haven't talked so much about the rest of Suriname, and obviously Block 53 is a smaller working interest. I think you're at 45%. But Let's just say you guys have additional success in the second, third, and fourth wells on Block 58. Any reason why you guys wouldn't go and test Block 53 next year as part of the exploration program?

1:02:00 No, we'll have a decision to make on Block 53. We have a 45% working interest in there with our two partners, and we do believe there's potential in Block 53, and it's something we'll talk about in the future. Thanks, guys. Thank you. I'm not showing any further questions. I will now turn the call over to John Christmann for closing remarks.

1:02:28 Thank you for joining us on our call this morning. In closing, I'd like to leave you with these final thoughts. If you look at Apache today, we have a diversified portfolio and are able to shift capital as appropriate for the commodity price environment. We are foregoing short cycle near-term growth and prioritizing long-term returns Sustaining the Dividend and Debt Paydown. Guyana Suriname is proving to be a super basin where we hold an anchor block with a world-class partner and have created an advantageous capital structure for appraisal and development. We are encouraged by what we have seen so far in our second well, and we have a third and likely fourth well to follow in 2020. We look forward to sharing more information in the future. Thank you.