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 speakers' presentation, there will be a question and answer session. To ask a question during this 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.
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 Pursell, 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. Please note that we may discuss certain non-GAAP financial measures.
A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. 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. A number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental information on our website. With that, I will turn the call over to John.
Good morning. 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. 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% from 2018. 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. 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 100% drilling success rate and achieved first production from our Storr discovery, which was on time and on budget. 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. 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, solid returns, and an attractive oil production growth rate in the Permian. This year, we plan to reduce our Permian operated rig count and deliver a low-to-mid single-digit oil growth rate. At Alpine High, results were disappointing on a few fronts. In our second quarter 2019 earnings release, we spoke about the impact of the natural gas and NGL price collapse on the economic competitiveness of further investment in Alpine High.
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. 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 Storr discovery in November. Startup of the Garten II 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-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, Staatsolie, in the coming months.
In January, the Noble Sam Croft drillship moved from Maka to our second exploration prospect, Sapakara West. As we noted in last night's press release, the Sapakara 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 high-quality investment opportunities in the Permian Basin, Egypt, and the North Sea. In Suriname, we have a very large-scale asset in Block 58, which may be transformational and capable of driving long-term volume growth at a very attractive return on capital.
We have made the strategic decision to prioritize funding Suriname over the next few years with a portion of the capital that would otherwise be directed towards 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 Suriname. One of the primary financial objectives is to reduce debt over the next several years. 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 billion-$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 exploration, and invest $1.6 billion-$1.9 billion of capital, including exploration, which will result in flat to low double-digit corporate oil production growth year-over-year.
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 right-sizing and reorganizing our technical, operational, and corporate support functions. The right-sizing 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. 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. With that, I will turn the call over to Steve Riney, who will provide additional details on our 2019 results and 2020 outlook.
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 in light of the changing capital plan for Alpine High. As noted in our news release issued yesterday, under generally accepted accounting principles, Apache reported a fourth quarter 2019 consolidated net loss of $3 billion or $7.89 per diluted common share. These results include a number of items that are outside of core earnings. 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.
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 $0.08 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. 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. 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 1 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. To date, we have eliminated approximately 310 million cubic feet per day of take-or-pay obligations. We have more in progress. As John noted, we're 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. 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. 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 Suriname Block 58, while at the same time investing in nearer-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 billion-$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 BOEs-60,000 BOEs per day by the end of the year. 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 G&A, 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 DD&A.
We expect DD&A per BOE for 2020 will be around $13.50. With that, I will turn the call over to the operator for Q&A.
Thank you. Ladies and gentlemen, as a reminder, to ask the question, you will need to press star, then one on your telephone. To withdraw your question, press the pound 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 Douglas Leggate with Bank of America. Your line is open.
Good morning. It's actually John Abbott for Douglas Leggate. 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?
Well, thanks for the question. In general, we don't like to comment on specifics about a well while it's drilling. What I will say is we have drilled through the Campanian. As I said, we are encouraged by what we have seen. We are headed on to the Santonian. As we put in the materials last night, the plan would be to run open-hole logs, capture fluid samples, cores, pressure tests, and so forth.
All right. For our follow-up question, on the appraisal of Maka 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?
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 Staatsolie, 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.
Hey, appreciate it, and thank you for taking our questions.
You bet.
Thank you. Our next question comes from the line of Bob Brackett with Bernstein Research. Your line is open.
Yeah, I'll try a different tact at the former question. You mentioned fluid sampling on the Sapakara West. Do you routinely fluid sample formation water?
Bob, that is not something we would typically do. It all depends on what we've seen and running the right test according to what we've seen in the well.
Okay. Appreciate that. A 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?
I will say the lion's share of that is Suriname. We do have some things on the unconventional side that we're slowly watching and working, but the majority of that will go to Suriname.
Great. Appreciate it.
Thank you.
Thank you. Our next question comes from the line of Mike Scialla with Stifel. Your line is open.
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.
It was a good question, Mike.
It definitely was. Steve, you had said you're reducing your commitments from Alpine High. Just wondering 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 the Gulf Coast Express and Permian Highway?
Yeah, Mike. I'm not going to be able to speak to specific pipelines. We've got multiple contractual arrangements for moving gas out of the Permian Basin. 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 Fast Facts that you receive 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.
An example of an action that they might recommend and did was we need to get some pipelines built from the Permian Basin to the Gulf Coast. We helped FID the two pipelines that you talked about in doing that. 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.
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. We're taking away the longer-term exposure on some of the pipeline transport capacity that we have in the Permian Basin. At this point, we're still working on a bit more of that. We would like to bring that down just a bit more.
That's great. Thanks for all that detail. 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 divestiture there at some point?
What I'll say, Mike, I'll go back and just take a few minutes here. 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 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.
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. We anticipated a meaningful uplift in well productivity and a significant decrease in well cost 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. Today, we've got about 240,000 acres. There's about 200 of it that will kind of expire over the next three years. There's some optionality there. If you look at the macro environment today, if we got back to an NGL market where we were late 2018, there's definitely some things that would be economic.
How does it compete in our portfolio is another question. That's why we made the decision we made today.
Very good. Thank you.
You bet. Thank you for the question.
Thank you. Our next question comes from the line of Gail Nicholson with Stephens. Your line is open.
Good morning. Thanks for taking my question. Two things. One, in Egypt, 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?
Yeah, Gail, what gets lost in the shuffle is you've got conventional rock that has the stratigraphic column and the aerial extent of greater than the Permian. We have over 6.2 million acres. I think with the new acreage that we've added since 2016 and the new 3D that we're shooting, 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 work, could be game changers. 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.
As we said in the prepared remarks, they drilled some really nice wells Q4, and we've got some very interesting things to test. 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.
Great. Thank you. On slide 13, you guys showed the 4Q 2019 operating cash margins. Just to clarify, does the Permian cash margin include Alpine? If so, if you remove Alpine from that number, what would the non-Alpine Permian cash margin be?
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.
Great. Thanks, guys.
Thank you. Our next question comes from the line of Charles Meade with Johnson Rice & Company. Your line is open.
Good morning, John, to you and your whole team there.
Good morning, Charles.
First off, thanks for giving us that detail on the Garten well. I believe that's slide 12 of your presentation there, and looks like a really stout rate. I wonder if you could just give us one discrete data point, which is what would your net be off of that gross rate?
Charles, this is Dave Pursell. That's 100%. We have that prospect. We have eight eighths of it.
Got it. Thanks for that, Dave. John, there's been some discussion or 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 Egypt?
Well, what I would say, Charles, is that we don't typically comment on A&D activity. I think today with the plan we have and the market where it is today, you wouldn't see us coming out of pocket for something. There's an asset base over there. We have a very nice footprint. There might be a way to do something on a creative side.
Okay. Thanks for that, John.
Thank you. Our next question comes from the line of Brian Singer with Goldman Sachs. Your line is open.
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 rig and decision-making perspective for further exploratory testing?
Well, with the rig we've got today, the Noble Sam Croft, we've got one well we've already exercised the option on, 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. It's an option we just haven't pulled the trigger on. If we were to elect that option, which I said is likely, we finish the current well we're on, we would drill the third well, then potentially the fourth well, then we will release the rig. I'll just say that any of the appraisal plan at Maka will come back with a different rig and a different timeline when we're in a position that we can talk about that.
Great, thanks. Back to the North Sea. When you put together the recent well and Garten declines, et cetera, how do you expect your production trajectory for oil to look over the course of the year?
It's going to be early. The first quarter's going to be strong with Garten. We delayed from Q4 into Q1. At the Garten II, I think it's going to continue to be lumpy. We've got more wells to drill at Garten. We've got some other prospects that are interesting as we tie back. North Sea is going to continue to be fairly lumpy based on when we bring these high-rate wells on.
Great. Thank you.
You bet.
Thank you. Our next question comes from the line of Leo Mariani with KeyBanc. Your line is open.
Yeah. Hey, guys. I know it's a bit difficult to sort of know for sure, I guess I was just looking to get a high-level timeline in terms of when you guys might finish drilling and then some of your analysis that you talked about on the Sapakara well. 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?
Yeah, Leo, as I said, we don't typically like to comment on a well while it's drilling. We did learn our lesson in December, at least to give you a little bit of an idea in terms of a comment. That's why we've said we're encouraged. We're through the Campanian. We've got the Santonian to drill. After that, we'll have some time to do the evaluation. 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.
Got it. Understood. Okay. I guess just with respect to the Permian, seemed like you had some very strong wells in Lea County, New Mexico, that you guys had reported through supplemental information. Just wanted to get a sense of what the depth of your inventory is in that general area there in New Mexico.
Yeah, Leo, this is Dave Pursell. 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. We have deep inventory across 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.
Okay. I guess a lot more inventory in Southern Midland versus New Mexico. Is that the way to interpret that?
Yeah, I would interpret it that way.
Okay, thanks.
Thank you. Our next question comes from the line of Arun Jayaram with JPMorgan. Your line is open.
Yeah, good morning. John, in Total's 4Q update, they talked about a $2 per barrel cost of acquisition. Presumably, you guys maybe approved that type of language. I was wondering if there's any read-through. I know we're very early in the delineation appraisal of Suriname, but of sizes of potential discovered resource at this point using the $2.
I would just say that is the language they put in and how they characterized it. I'll just leave it at that.
Got it. Fair enough. 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? Can we make any clues regarding when we could achieve first oil if your delineation efforts prove successful? Or the path to first oil?
Arun, what I'll say is there's the agreements with the concession terms laying out a timeline that you have to follow. 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. 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.
Okay. Thanks a lot, John.
Mm-hmm. Thank you.
Thank you. Our next question comes from the line of Richard Tullis with Capital One Securities. Your line is open.
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?
Yeah, I think today we look at the portfolio, we really like the balance. We've done a lot of that over the last couple of years. 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 Midcontinent sold last year. 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. We're constantly looking at that. 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.
That's helpful, John. Just to follow up, how many wells were drilled to date in the Alpine High? How many of those wells are online currently?
Yeah, Richard, this is Dave Pursell. I don't have the exact numbers, but it's kind of in the low 200 s that we've drilled and around 200 that are online.
Okay. Thank you. That's helpful. I appreciate it. That's all for me.
Thank you. Our next question comes from the line of Neal Dingmann with SunTrust. Your line is open.
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 there in the play. 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?
No, I think the key for us was, we spent really 2016 and 2017 really very thoughtfully and methodically understanding how to develop, and we got the pads early, and really worked through that work at that time. What you've seen is a very steady plan. We've got about nine months of rig activity just kind of lined out, and it gives us the ability to work the infrastructure, do all the things we need to do ahead of that. I don't see any changes in terms to our development approach. What we have the luxury of doing, though, is backing off that capital, because it's short cycle in nature. It's not something we have to drive forward, in this price environment. The only thing you might see, as we mentioned, the price is down where they are today, even below the range we talked about.
You might see a little further slowdown, just because we have the luxury and can do that. I think it's also important to keep frack crews working and a couple of rigs working. I'll call where we maintain our execution fitness, and we continue to work on the continuous improvement to drive those results. 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.
Yeah. Great details. My second question is on the North Sea. I'm just wondering, maybe you've already said, but I'm just wondering about will you have potentially the same amount of downtime, and I think it's 3Q, and then the plan to continuously run the three rigs.
I think if you look today, we've had a platform rig running both at Beryl and Forties, 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 Beryl area, which helps a little bit on the capital this year. Similar program is what we would envision for 2020. You do have your traditional maintenance season, which we usually get in the third quarter, summer months when the weather gets a little better.
That'll just be the typical maintenance you think, John?
Yes.
Okay.
Really weather. It was weather is what kind of drove us to have to wait to bring Garten #2 on. You came out of maintenance turnaround, we got into some pretty rough weather in the fourth quarter, that was what kind of had us kick some things back.
Thanks so much.
Thank you. Our next question comes from the line of Jeanine Wai with Barclays. Your line is open.
Hi. Good morning, everyone.
Good morning.
Good morning. My first question, it's on maintenance CapEx, maintenance mode. At the 2020 CapEx budget level, you're around maintenance mode at the low end, I believe. Looking forward to 2021, are you able to maintain flat year-over-year production at a similar $1.6 billion CapEx budget? Are there some one-offs this year that are kind of driving that number lower? I guess what I'm 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.
Jeanine, this is Steve. 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. I think we like to think about things like that in a purist way, 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. It's equally important that you look at how those definitions vary over a time frame. You can have a maintenance capital. Some people think of maintenance capital as well, it's just the next year. The next year, that's one of those cases of, well, how long can you hold your breath? Maintenance capital for a year can be pretty darn low.
We like to think of maintenance capital at least in a five to 10-year time frame. That includes ongoing asset integrity spend, and that includes spending on inventory progression so that you can maintain production over that five to 10-year period. You can also think of maintenance capital over a longer term, 20+ years, you need to start introducing exploration spend as well. 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 spend program. In a five to 10-year time frame, we've been pretty consistent for the last five years saying we're somewhere around $45 WTI. We can pay the dividend, maintain oil production volume, with no free cash flow retention. 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, that'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. That's the way we like to think of it. Another way to think of it for us is that if you're in a $50-$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. We can sustain oil production volume or grow it slowly over that four-year period, and we can fund Suriname to first oil.
I think that's an interesting way to be thinking about maintenance capital as well. 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. You get out a few years from now, the maintenance capital falls way below that $45-$48 WTI price environment because of that capital carry. In terms of specifically, there are a lot of different ways you can look at what we've talked about for 2020. If you go to the $1.6 billion capital range, the low end of our range, that's contemplating a $46-$47 WTI price.
It means we still pay the dividend. We fund the $200 million of exploration spend out of that $1.6 billion, 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-$55 range. You're paying the dividend and spending $200 million on exploration. You're retaining $150 million-$200 million of free cash flow for future debt paydown. In that case, you're growing oil production in the low to mid-single digits for 2020.
Okay, great.
A long-winded answer, but I hope that ticks all the boxes for you.
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. What are the governors for pacing kind of medium-term Suriname CapEx? You mentioned prioritizing Suriname. It sounds like from what you just said, you're committed to funding Suriname out of free cash flow. We've seen prior precedents where folks try to pre-fund big major capital projects like this with asset sales. I just wanted to clarify whether you're committed to funding Suriname out of free cash flow or a combination of free cash flow plus any sale proceeds.
Yeah, Jeanine. 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. In terms of funding the activity in Suriname, first of all, by our joint venture agreement with Total, it should be clear. 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. When you get into appraisal and development, that's where the capital carry kicks in. Starting with the appraisal of Maka, and any development spend that might come from that, and appraisal from any further exploration successes.
The $0.875 of every dollar will be spent by Total and $0.125 by Apache. 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 means we're doing a heck of a lot of appraisal and development, and that would be a great problem to have.
Okay, great. Thank you for taking my questions.
Thank you. Our next question comes from the line of Scott Gruber with Citigroup. Your line is open.
Yes, good morning. Thanks for taking my questions.
You bet.
Turning to the cost-out program, how should we think about the $150 million roughly split in between overhead and ops? Do you think you'll be able to achieve the full run rate of savings by year-end?
I think at a run rate base, we'll be able to get there. The lion's share of that is likely going to come out of the overhead piece. We're well on our way and working through that, and we should be able to get to that type of run rate later this year.
Got it. 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?
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. 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.
Okay, that was it for me. Thank you.
You bet.
Thank you. Our next question comes from the line of David Deckelbaum with Cowen. Your line is open.
Morning, guys, and nice job and 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 GPT by the fourth quarter of 2020 relative to that $825 and $75 million in the first quarter?
Yeah, David, we intentionally just gave one quarter of guidance on that. 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 focus program and the pace of change of that program. Let us do that as we go through the next few quarters.
Sure. I'll be patient, but appreciate it. If I could ask, I guess secondarily to that other add-in on that, what are you all assuming, I guess, for the annualized decline out of Alpine High and those total volumes that you have in the U.S. that are only down slightly on that annualized basis?
Yeah. This is Dave Pursell. When you think about Alpine, we're not adding any completions this year, so you're going to see effectively the unconventional blowdown. You'll have a steep decline in the first year, and then every year after that, the decline will moderate. Think about something 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. Thank you, guys.
Thank you. Our next question comes from the line of Paul Cheng with Scotiabank. Your line is open.
Thank you. Good morning. Two question. On the $150 million on the restructuring saving, do you have a rough estimate between how much is on the P&L side and how much in the capital cost?
No, we don't have an estimate of that at this point in time.
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?
Yeah, Paul, this is Dave Pursell. If you think about it in terms of gross completions, it's about 60% Southern Midland Basin and 40% on the Delaware side.
Okay. My final one for me. If we look at your portfolio, say, over the next five years, Suriname is very exciting, and Egypt look like you guys have some high hope. Look like North Sea is probably not necessarily going to receive enough capital attention from that standpoint. Should we look at North Sea, 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?
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. 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.
Okay. Are you going to put more capital into that or that essentially is in somewhat of the maintenance mode?
We're definitely spending capital. In terms of, is it an area we're going to go out and try to consolidate and buy more properties and add that? No. 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. Steve, you have something you want to add?
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 Forties field, it was scheduled for abandonment in 2012.
Yeah.
Today it's scheduled for abandonment in the 2030s, and that keeps moving out. There's a lot to do in the North Sea, and I wouldn't worry too much about the next three to five years.
All right. Thank you.
Thank you. Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Your line is open.
Thanks. A lot's been addressed. I guess I just want to circle back to the comment in the prepared remarks around the longer-dated growth outlook being moderated as you're trying to bring Suriname on. Is it right then to just think about basically, what we're seeing with the 2020 program 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?
Michael, it's really going to depend on what the prices do in between, because we gave a range on the capital. At $1.6, you're closer to that mode. At $1.9, we're going to show a little bit of growth. Quite frankly, if we need to go lower, we will. If we needed to let things move down a hair, we're not afraid to do that because we're going to prioritize paying the dividend, funding Suriname and paying down some debt. We're very comfortable with where we are. We've got a differential asset base. We've got lower decline rates because of the conventional assets in a lot of our areas. We feel very comfortable with where we are over the next three to five years with that.
Yeah. Michael, I'd just add, this is Steve. Just going back to the comments I just made a few minutes ago. For the next several years at $50-$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 appropriate recognition of where prices are today and where they're headed. At $50-$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'll mature over the next four years. We can sustain or even grow. You get to the $55 price environment, we can grow oil production slightly over that time period.
Okay. That's helpful. That's contemplating a similar four well per year type exploration program? Is that reasonable?
Well, that's assuming $200 million a year spent on exploration.
Okay. On a more near term basis, just 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 timeframe before you bring things back up in the back of the year? Just curious.
It's a steady program, right? We've got our unconventional program growing, we've got some of the CVP and some of those things slightly declining. It's a pretty steady program. That's the one thing, if you go back to mid 2017, we've been real steady with the program, as a result, it puts us in a pretty even cadence.
Great. No, that's helpful. Appreciate it, guys.
Thank you. Our next question comes from the line of Josh Silverstein with Wolfe Research. Your line is open.
Yeah, thanks. Two quick questions for you guys on Suriname here. On the Maka you mentioned that the drilling design wasn't to optimally place t he well in the thickest zones there. I was wondering if that was the same thing at Sapakara or if you guys are trying to target somewhat differently there.
Well, I would just say, Josh, it's a function of you've got your seismic ties and you're working in. Maka was our first well into Block 58. You learn things as you go. What we've got is we have multiple stack targets in there. We lined it up to drill what we thought would be optimal on a few of them, and we validated that. The point was, had we moved over, we would've probably had a different number in terms of net feet of pay and so forth. 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.
Got it. Thanks for that. Then maybe, we haven't talked much about the rest of Suriname, and obviously Block 53 is a smaller working interest. I think you're at 45%. 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?
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. 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.
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 anchored block with a world-class partner and have created an advantageous capital structure for appraisal and development. We're 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.
Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect. Everyone, have a wonderful day.