APA Corporation (APA) — Q4 2019 Earnings Call Transcript

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 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 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.

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 see so far 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. 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, 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 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.

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, 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 of 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.

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 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?

I'm unable to discuss specific pipelines. We have various contracts for transporting gas from the Permian Basin, which are not solely tied to Alpine High. Our primary focus is on selling our production within the basin, and the realized prices you see are for the Permian Basin at Waha or El Paso Permian. Our marketing team actively manages how we align basin prices with the larger market trends over time. One action they recommended was the construction of new pipelines from the Permian Basin to the Gulf Coast, and we supported the final investment decision for the two mentioned pipelines. This connection benefited us for a period. Our marketing team manages the risks linked to these assets by purchasing gas locally and transporting it to fulfill our obligations. We have decided to lower our long-term exposure and participated in the construction process for the pipelines. These obligations are related to Apache Corporation, not Altus Midstream, and we've started the process of reducing our exposure. As mentioned earlier, we've secured contracts with counterparties to assume our obligations of up to 310 million cubic feet per day. This transition won’t happen immediately, so we still have some short-term exposure, which is beneficial at this time. However, we are working towards decreasing our longer-term exposure with additional pipeline transport capacity in the Permian Basin, and we are looking to further reduce that soon.

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 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 in 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.

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 operating cash margins. Just to clarify, does the Permian cash margin include Alpine? And if so, if you remove Alpine from that number, what would the non-Alpine Permian cash margin be?

And yes, it does include that. And in terms of 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.

Good morning, John, and your whole team there.

Good morning, Charles.

I wanted to thank you for providing details on the Garten well. It seems like a strong rate. Could you share a specific data point regarding what your net would be based on 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 news media about 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, how would you characterize your appetite for more assets in Egypt?

What I would say, Charles, is that we don't usually comment on acquisition and divestiture activity. Given our current plan and the market conditions, you wouldn't expect us to make any out-of-pocket investments right now. However, there is an asset base there, and we have a solid presence. There might be a way to approach this creatively.

Okay. Thanks for that John.

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?

We currently have the Noble Sam Croft rig and have already exercised the option for one well, with another well available for drilling. While it's very likely we will proceed with that option, we don't need to decide right now. If we choose to move forward, we would complete the well we are currently working on, drill the third well, and possibly the fourth well before releasing the rig. Regarding the appraisal plan at Maka, we will return with a different rig and timeline once we are ready to discuss it further.

Great. Thanks. And then back to the North Sea when you kind of put together the recent well and Garten decline, 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's going to continue to be fairly lumpy based on when we bring these high-rate wells on.

Great. Thank you.

You bet.

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. Generally, if you look at our unconventional inventory, we have more activity in the Southern Midland Basin compared to New Mexico in the Delaware Basin. However, we have a strong inventory in both basins. We are currently drilling only a small portion of our total area, and we feel confident about the long-term inventory depth in both 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.

Good morning. John, in Total's fourth quarter update, they mentioned a $2 per barrel cost of acquisition. I assume you might have approved that type of statement. I'm curious if there's any implications regarding this. I understand we're very early in the delineation appraisal of Suriname, but what are the potential sizes of discovered resources at this point using that $2?

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

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, I want to clarify that there are agreements in place that outline the timeline we need to adhere to. We have a discovery declaration, followed by a period during which we must submit the discovery notice, then a time frame for submitting the appraisal plan, and finally, the development process. We are actively working through this timeline. Our team, along with our partner, will do our best to accelerate these processes based on the outcomes from the appraisal program.

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, 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 or 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.

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 very thoughtfully and methodically understanding how to develop and we got the pads early and really worked through that 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 lined out, and it gives us the ability to work the infrastructure and do all the things we need to do ahead of that. So I don't see any changes in terms of 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 at a level 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. My second question is about the North Sea. I'm curious about the potential for the same amount of downtime in the third quarter and the plan to continuously operate 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 that kind of drove us to have to wait to bring Garten-2 on. 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.

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?

Sure, Jeanine. First, I want to clarify our understanding of maintenance capital. We believe it’s important to define it correctly. For us, maintenance capital refers to maintaining production volumes and paying dividends, but it doesn't necessarily create free cash flow. It's crucial to consider how these definitions can shift over time. Some people view maintenance capital as a short-term concept, just focusing on the next year, which can lead to the question of sustainability. Our perspective is to think in terms of a five to ten-year timeframe, which accounts for ongoing asset integrity investments and inventory progression necessary for production maintenance during that period. Looking even longer, say over 20 years, exploration spending also becomes a part of that calculation. Therefore, we generally avoid defining maintenance capital on a one-year basis since we don't want to limit ourselves. Over the five to ten years, we’ve consistently indicated that at around $45 WTI, we can pay dividends and maintain oil production without retaining free cash flow. This range has been stable for several years, with a longer-term maintenance capital definition likely around $48 WTI, which allows us to allocate funds for exploration, including our $200 million budget for 2020. If we consider a long-term WTI price of $50 to $55, we can sustain dividends, contribute to debt reduction, maintain or slowly grow production, and support our Suriname project. Notably, success with Suriname may significantly reduce our maintenance capital needs due to our capital carry structure with Total, meaning that in the future, our maintenance capital could fall well below the $45 to $48 WTI range. Now, if we evaluate our 2020 capital options, at the low end of $1.6 billion, we anticipate WTI prices around $46 to $47. This means we can maintain our dividend and fund the $200 million exploration budget while keeping production flat year-over-year. At the higher end, with $1.9 billion allocated, we project WTI prices around $53 to $55, which still allows for dividends and exploration funding. In this scenario, we could expect to see low to mid-single-digit growth in oil production for 2020. I hope that provides a comprehensive overview of our thoughts on this matter.

I appreciate the detailed information you've provided; it's very helpful to understand your perspective. I just have a brief follow-up on what you mentioned earlier regarding the development process in Suriname. What are the main challenges related to medium-term capital expenditures in Suriname? You indicated that Suriname is a priority, and it seems from your comments that you intend to fund Suriname using free cash flow. We've observed situations in the past where companies have tried to pre-fund significant capital projects through asset sales. Can you confirm if you plan to fund Suriname solely with free cash flow, or will it include a mix of free cash flow and proceeds from any asset sales?

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 agree 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 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 dollar 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, it would mean 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.

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.

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, 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?

This is Dave Pursell. Regarding Alpine, we will not be adding any completions this year. As a result, you will observe a significant decline in the first year, followed by a gradual moderation in the subsequent years. For the first year, you can expect an annual decline in the mid-30% range, which will then stabilize in the second, third, and fourth years.

Got it. Thank you guys.

Thank you. Good morning. I have two questions. Regarding the $150 million in restructuring savings, do you have a rough estimate of how much will impact the P&L and how much will go toward capital costs?

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

Okay. In the Permian for 2020, you're planning to operate five to six rigs. Do you have a breakdown between the Midland and Delaware Basin?

Yes, Paul, this is David 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. 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 it looked like North Sea is probably not necessarily going to receive capital attention from that standpoint. So should we look at North Sea say five years from now you're still considered 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 essentially has seen some 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 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 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.

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, 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'll add that going back to the comments I made earlier, for the next several years at a price range of $50 to $55, which has generally been discussed aside from today, that seems to be the right price environment. At $50 to $55, we can do everything John mentioned. We can pay the dividend, fund Suriname to First Oil, retain sufficient free cash flow to reduce the $937 million in debt maturing over the next four years, and maintain or even increase production. In a $55 price environment, we could see a slight growth in oil production during that period.

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?

I would say, Josh, it's a matter of having your seismic ties and working with them. Maka was our first well in Block 58, and we learn things as we go. We have multiple target layers in that area, and we planned to drill what we believed would be optimal for some of them, which we validated. If we had chosen a different approach, we likely would have seen a different net fee to pay. However, we learn from these experiences, and that’s what our appraisal programs will reveal as we evaluate any potential discoveries.

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 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.