Ladies and gentlemen thank you for standing by and welcome to the Apache Corporation Fourth Quarter 2019 Earnings Announcement Webcast. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker 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. Finally I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental information on our website. And with that I will turn the call over to John.

Good morning and thank you for joining us. On today's call, I will 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 and 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 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. 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 onetime 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 midyear. 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 two 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 number one 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 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 exploration and invest $1.6 billion to $1.9 billion of capital including exploration which will result in flat- to low-single-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 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. 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.

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 noncash 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 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. 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. 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 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 billion 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. 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. And with that, I will turn the call over to the operator for Q&A.

Thank you. [Operator Instructions] Our first question comes from the line of Doug Leggate with Bank of America. Your line is open.

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

All right. And then 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 time line 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.

I appreciate, and thank you for taking our questions.

Your 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 tactic to the former question. You mentioned fluid sampling on the Sapakara West. Do you routinely fluid sample formation water?

Bob, we would -- that is not something we would typically do. But I mean, it all depends on what we've seen in running the right tests 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?

Yeah. 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 heard.

It was a good question Mike.

Yeah. It definitely was. Steve, you had said you're reducing your commitments on 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's transportation that you've taken on Gulf Coast Express and Permian Highway.

Yeah. Mike, so 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. And so, it's not -- 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 vast 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-terms? And 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. And that did well, 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 that 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. 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.

That's great. Thanks for the 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?

I mean, 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. And 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. 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. Fourth, we anticipated a meaningful uplift in well productivity and a significant decrease in well cost as we move to pad and pattern development as is the case in almost all unconventional resource plays. We were able to drive cost down below our goals but the uplift in productivity did not materialize. So today it – 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 NGL market, where we were late 2018 then there's definitely some things that would be economic but how does it compete in our portfolio is another question. And so 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 that you guys have identified post the seismic analysis in Egypt?

Yes Gail, what gets lost in the shuffle is you've got conventional rock what 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 and 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 work could be game changers. And so 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 it drove some really nice wells, Q4 and 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.

Great. Thank you. And then on Slide 13, you guys show the 4Q 2019 on 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 be non-Alpine Permian cash margin be?

And yes, it does include that. And in terms of with all the reorgan 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 you some insight.

Great. Thanks, guys.

Thank you. Our next question comes from the line of Charles Meade of Johnson Rice & Company. Your line is open.

Good morning, John, you, your whole team there.

Good morning, Charles.

I wanted to -- first off thanks for bringing -- or for giving us the detail on the Garten well. I believe that's slide 12 of your presentation there. And it looks like 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 growth rate?

Charles, this is David Pursell. That's 100%. We have that prospect we have well.

Got it. Got it. And -- 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 in that direction because of the attractiveness you see there what how would you characterize your appetite for more assets in Egypt?

Well, I mean, 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 in the market where it is today you wouldn't see us coming out-of-pocket for something. But there's an asset base over there. We have a very nice footprint. And there might be a way to do something creativity-- 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 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 -- if we were to elect that option which I said is likely you would -- we would 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 in the appraisal plan at Maka will come back with a different rig and a different time line when we're in a position that we can talk about that.

Great. Thanks. And then back to the North Sea when you kind of put together the recent well and Garten declined 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. I mean the first quarter is going to be strong with Garten we delayed from Q4 into Q1. So it -- Garten 2 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. So 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. But I guess I was just looking to kind of get a high level time line in terms of when you guys might kind of 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?

Yes, Leo as I said 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 to give you a little bit of an idea in terms of a comment so that's why we've said we're encouraged. We're through the Campanian we've got the Santonian to drill. And then after that we'll have some time to do the evaluation. So not also going to give you a definitive time line but we'll get to that as soon as we can after we TD the well.

Got it. Understood. Okay. And I guess just with respect to the Permian 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?

Yes, 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 in the Delaware Basin generally. But we have deep inventory across both basins. And as you look out we've -- 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. So I guess a lot more inventory in Southern Midland versus New Mexico? Is that the way to interpret that?

Yes, 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 kind of cost of acquisition. Presumably, you guys maybe approved that type of language. So I was wondering if there's any read through? I know that we're very, very early in the delineation appraisal of Suriname, but of -- sizes of potential discovered resource at this point, using that $2?

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

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 forward to first oil?

Arun, what I'll say is, there's -- the agreements with the concession terms lining out a time line 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. So there's a time line that we're on there. And we're working through it expeditiously. And I think, the -- 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.

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 the -- maybe, the better to monetize category?

Yes. 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, if 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, we're -- 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 were 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.

That's helpful, John. And just a follow-up. How many wells were drilled to date in the Alpine High? And how many of those wells are online currently?

Yes, Richard. This is Dave Pursell. I don't have the exit numbers, but it's kind of in the low-200s 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.

Good 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?

No. I mean, 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 work through that work 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 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. So 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. 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, 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 frac crews working and a couple of rigs working. So I'll call where we maintain our execution fitness and we continue to work on the 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.

Great details. And then, my second question, just on the North Sea. I'm just wondering -- maybe you've already said, but I'm just wondering about, well, your potentially the same amount of downtime and I think it's 3Q and then the plan to run -- continuously run the three rigs?

Yes. 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 of wells in the North Sea out there in the Barrel area which helps a little bit on the capital this year, but a similar program is 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.

So that will just be the typical maintenance you think, John?

Yes. And then really weather. I mean, it was weather is what kind of drove us to have to wait to bring Garten-2 on. So you came out of maintenance turnaround, and then we got into some pretty rough weather in the fourth quarter and 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 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 at is that next year there could be some incremental cash flow from Altus with the pipelines, so that can help fund Suriname CapEx?

Yeah, Jeanine, this is Steve. So I think the first thing we got 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 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 all the 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're going to have a maintenance capital, some people think of maintenance capital as well it's just the next year. And the next year that's one of those cases of well, how long can you hold your breath. And maintenance capital for a year can be pretty darn low. We like to think of maintenance capital at least in a five-year to 10-year time frame and so that includes ongoing asset integrity spend and that includes spending on inventory progression so that you can maintain production over that five-year to 10-year period. But 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 -- maintenance spend program. In the five-year 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. And 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. And so 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 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 are 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. 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 that maintenance capital falls way below that $45 to $48 WTI price environment, because of that capital carry. In terms of specifically looking at -- 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 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 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 to $55 range. You're paying the dividend and spending $200 million on exploration. You're retaining $150 million to $200 million of free cash flow for future debt pay down. And in that case you're growing oil production in the low to mid single-digits for 2020. That's 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 had the opportunity to do so. So what are the key -- what of the governors are facing 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 have 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 Suriname out of free cash flow? Or a combination of free cash flow plus any sale proceeds?

Yeah, Jeanine. 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 will be between us and our partner as we agreed to that. So 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 and that's where the capital carry kicks in and starting with appraisal of Maka and any development spend that might come from that and appraisal from any further exploration successes, the $0.875 of every $1 will be spent by Total and $0.125 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 in development and that would be a great problem to have.

Okay, great. Thank you for taking my questions.

Thank you. Out 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.

So turning to the cost out program, how should we think about the $150 million roughly splitting between overhead and ops? And 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. I mean, lion 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 run rate later this year.

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?

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 million 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.

Okay, that’s it from me. Thank you.

You bet.

Thank you. Our next question comes from the line of David Deckelbaum with Cowen. Your line is open.

Good morning guys, and nice job and nice update. Thanks for the time. I just wanted to ask you, 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 2020 relative to that $825 million and $75 million in the first quarter?

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 focus program and the pace of change of that program. So 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 the other adding on to 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 an annualized basis?

Yeah. So 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. 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 the -- in years two, three and four.

Got it. Thank you guys.

Thank you. Our next question comes from the line of Paul Cheng with Scotia. Your line is open.

Thank you. Good morning. Two questions. On the $150 million 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 in the capital cost?

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

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

Yes, Paul, this is David Pursell. On a -- if you think about it in terms of gross completions, it's about 60% Southern Midland Basin and 40% on the Delaware side.

Okay. A final one for me. North Sea if we look at your portfolio say over the next five years I mean Suriname is very exciting and Egypt looked like you guys have some high hopes. And look like North Sea is probably not necessarily going to receive a no capital attention from that standpoint. So, should we look at North Sea say five years from now you're still consider as a core part of your long-term portfolio? Or that you may need to be revisiting that?

And I think today if you look at what we're doing in the North Sea, I'm quite proud. I mean 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 kind of our infrastructure there. 40s 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.

Okay. But I mean are you going to put more capital into that? Or that the essentially has seen some one of the maintenance mode?

I mean 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. But I think we've got a lot of left -- life left in these assets and there's a lot we can do on the cost side. And Steve you'd something you want to add?

Yes, I'd just requote 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, 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.

Thanks. A lot's been addressed. I guess I just want to kind of circle back to the comment in the prepared remarks around just 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 billion you're closer to that mode at $1.9 billion. We're going to show a little bit of growth. And so and quite frankly if we need to go lower we will. And if we needed to let things move down a hair we are not afraid to do that because we're going to prioritize paying the dividend funding Suriname and paying down some debt. So, 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. And so we feel very comfortable with kind of where we are over the next three to five years with that.

Yes. I just Michael I'll 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 to $55, which other than today people have been generally talking about that's kind of the right price environment, should be posting 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. And 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. And that's kind of contemplating like a similar four-well per year type exploration program. Is that reasonable?

Well that's just that's assuming $200 million a year spent on exploration.

Okay. And then on a more near-term basis just kind of curious on the kind of cadence I guess in the Permian on the oil program there. I mean 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 kind of bring things back up in the back of the year? Just curious.

No, it's a steady program, right? So we've got our unconventional program growing and we've got some of the CBP and some of those things slightly declining. So – but 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 and as a result it puts us in a pretty even cadence.

Great. 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.

Two quick questions for you guys on Suriname here. On the Maka well you mentioned that the – I guess, the joint design wasn't to optimally place the well in the thicker zones there. I was wondering if that was the same thing at Sapakara? Or if you guys are trying to target somewhat differently there?

Yeah I would just say, Josh, it's a function of – you've got your seismic ties and you're working in. This was really our -- Maka was our first well and two Block 58. And so you learn things as you go. And what we've got is we have multiple stack targets in there and we lined it up to kind of drill what we thought would be optimal on the few of them and we kind of validated that. So just – so – just 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. And – 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.

Got it. Thanks for that. And 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%. 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?

No. And 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.

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 anchor 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.