APA Corporation (APA) Q3 2019 Earnings Report, Transcript and Summary

Good morning. My name is Nicole, and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2019 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks there will be a question-and-answer session. [Operator Instructions] It is now my pleasure to hand the conference over to Mr. Gary Clark. Please go ahead, sir.

Good morning and thank you for joining us on Apache Corporation’s third quarter financial and operational results conference call. We will begin the call with an overview by CEO and President, John Christmann. Due to a personnel matter, Tim Sullivan is unable to join us today, so Dave Pursell, Executive Vice President of Planning Reserves and Fundamentals will provide additional operational color. Following that Steve Riney, Executive Vice President and CFO will summarize our third quarter financial performance. Our prepared remarks will be approximately 20 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday’s press release, I hope you’ve had the opportunity to review our third quarter financial and operational supplement, which can be found on our Investor Relations website at investor.apachecorp.com. On today’s conference call, 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’s 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 discuss Apache’s approach to delivering value in the current environment, provide high level direction on our 2020 capital budget, and conclude with some comments on our third quarter performance and fourth quarter outlook. The market has come to view the lower oil and gas price environment that has been in place since 2014, a structural in nature and unlikely to improve for the foreseeable future. Compounding this, investors are frustrated with excessive capital investment by U.S. producers and pursued the growth which is common with expense of both return on and return of capital. For these and other reasons, the broad energy sector is out of favor and there is very little investor interest in publicly traded E&P companies. In response as an industry, we must generate more free cash flow and return it to investors on a more consistent basis while continuing to operate responsibly and increasing our focus on emissions reduction. In this regard, Apache’s primary objectives are simple and straight forward, deliver competitive risk adjusted returns with a long-term moderate pace of growth, improve our free cash flow yield to level consistent with mature industrial sectors, and progress our sustainability initiatives. As we have done for the last several years, Apache will budget using a conservative price tag, influx our capital program in response to price volatility. We have taken a number of steps to adapt to the lower commodity price environment of the last five years. These include streamlining our portfolio, making substantial improvements to our capital allocation process, and significantly reducing our head cost. Apache has historically employed a decentralized region focus approach to operations. In recent years, we have centralized certain key activities and today see an opportunity to capture greater efficiencies by taking further steps in that direction. To accomplish this, we have initiated a comprehensive redesign of our organizational structure and operations that will position us to be competitive for the long term. This process which began in late summer should be largely completed by the end of the first quarter. We are targeting at least a $150 million of combined annual savings and look forward to updating you on our progress in the future. As we look ahead to 2020, our capital planning process is underway and we will disclose a final budget with our fourth quarter results in February. Based on current strip prices, we anticipate a 2020 upstream capital budget that would be 10% to 20% below this year’s program of $2.4 billion. This will enable Apache to generate organic free cash flow that covers the dividend and puts us on pace to fund a multiyear debt reduction program while also delivering modest year-over-year oil production growth. We anticipate directing the vast majority of our Permian Capital in 2020 to more oil weighted projects in the Midland and Delaware Basins. In Egypt, we have taken significant steps to build and enhance our drilling inventory and assessing the potential for increase investment in the future. And in the North Sea, we intend to maintain a consistent level of activity year-over-year. Turning to Suriname, we have retained the Nobel Sam Croft drill the second and third wells on Block 58 in 2020, with an options still outstanding on a fourth well. We are planning to drill these wells at a 100%, but that might change should we choose the farm down our interest. As we progress through the 2020 planning process, we continue to monitor commodity fundamentals and evaluate multiple capital allocations scenarios under a number of different price tags across our diverse portfolio. We look forward to providing details on our outlook in February. Next, I will comment briefly on our third quarter performance and fourth quarter outlook before turning it over to Dave for more details. In the Permian Basin, our oil production in the second half of the year has been moderately impacted by some unplanned downtime events and to ways in our completion schedule and well maintenance timing. Consequently, we are now projecting fourth quarter Permian oil volumes of approximately 100,000 barrels per day. At Alpine High, we have reduced our drilling activity to two rigs and have chosen to defer some fourth quarter completions into 2020. This lower activity set combined with a decrease production outlook on one of our multi-well pads has results in an approximate 5% reduction in our fourth quarter Alpine High guidance. Internationally, third quarter production was in line with guidance and our outlook for the fourth quarter is unchanged. Egypt continues to deliver excellent well results and a high drilling success rate. In the North Sea, we have a significant exploratory success coming online at store this month and a second well at Garten coming online around year end. The log on the Garten well shows a much larger than expected hydrocarbon column and should generate positive production momentum as we enter 2020. In Suriname, we spud the market central number one in late September and expect to TD the well in November and a depth of approximately 6,325 meters as measured from the deck of the drillship. The well is designed to test multiple targets and is located roughly seven miles from the Suriname/Guyana maritime border. With the recent exercise of our option to drill a second and third well on Block 58, in conjunction, some optional future well commitments, Apache has the ability to retain the entirety of Block 58 with no relinquishment requirements until June of 2026. This provides sufficient time to execute a comprehensive exploratory program over this large block and initiate development activities as warranted. In closing, we are taking numerous decisive actions to improve our performance and positioning in this difficult macro environment. Apache has several key differentiators that enhanced our investment proposition. Our diversified portfolio affords the flexibility to allocate capital across to all three hydrocarbon streams and among conventional and unconventional assets as warranted by market conditions. We have a deep and diverse acreage position across the Permian Basin. Our international assets generate strong and stable free cash flow driven by premium pricing for oil, gas and NGLs. The returns generated by these assets are highly competitive within our portfolio and tend to be less sensitive to downside commodity price volatility. And lastly, Apache has excellent organic exploration opportunities in each of its three key regions as well as a potentially transformational position offshore Suriname. With that, I will turn the call over to Dave Pursell, who will provide some operational details on the quarter.

Thanks, John, and good morning. Our strong operational results for the third quarter reflect the benefits of the diversified portfolio. Adjusted production of 391,000 barrels of oil equivalent is nearly flat with the previous quarter, which included approximately 25,000 barrels of oil equivalent per day from assets in the Mid-Continent region that we divested during the second quarter. We are advancing a number of exploration programs both internationally and in the U.S., and development activities continue at a steady pace and our legacy U.S., North Sea and Egypt regions. During the third quarter, we drilled and completed 64 gross wells, 48 in the US, 14 in Egypt and two in the North Sea. U.S. third quarter production totalled 266,000 barrels of oil equivalent per day. In the Midland Basin, we continue to drill high productivity oil wells. Our third quarter activity included an 11 well, 1.5 mile pad at Azalea located in the Midland County. This pad produces from the Lower Spraberry shale, Wolf Camp A and B and Lower Cline formation. The Lower Cline well tested in new landing zone with favourable results, achieving an average 30 day IP of 1,270 barrels of oil equivalent per day at 72% oil. Plans are underway to drill future Lower Cline wells to further delineate the Cline potential across our Midland Basin acreage. In Reagan County, we drilled the five well 2 mile pad. In the Hartgrove area, producing from the Wolfcamp B1 and B4 formations, 30-day IP averaged 1,150 barrels of oil equivalent per day with 79% of oil with D&C cost averaging a very efficient $7.2 million per well. And in the Delaware Basin, we drill five wells with 1 mile laterals at Dixieland at an average cost per well of less than $5.3 million. As we outlined last quarter, we are still feeling the effects of completing timing on our Permian oil production. We are on pace to put all 88 plan Midland in Northern Delaware Basin wells online, but many of them pushed back throughout the year. We have 25 wells schedule with online dates in November or December, which based on their timing, will add only minimum production to the fourth quarter. At Alpine High, we brought 15 wells online during the quarter. This included several wells from our 14 well Blackfoot Barnett pad in the Northern Flank. We have now drilled four large multi-well pads in this area and this most recent Barnett pad has thus far underperformed relative to the adjacent Mont Blanc, Barnett pad. All 14 Blackfoot wells were completed sequentially before commencing flow back operations. As a result, the significant volume of frac water was pumped into the small areas of reservoir, which may have impacted well productivity. We took advantage of a shutting period to soak this pad for approximately 60 days. The wells have been return to production at higher rates, additional modelling is underway to better understand the performance of these wells. Moving to our international regions, adjusted production came in a little higher than projected at 125,000 barrels of oil equivalent per day. In Egypt, following up on the discovery announced last quarter in our new East Bahariya area, we have received the development lease and have drilled the second well the Cobra-2, which is producing approximately 3,000 barrels of oil per day. We are currently drilling a third well with plans for a fourth well later this year. In the Matruh Basin, the Biruni-1X well tested 5,000 barrels of oil per day from the AEB 6 reservoir plus 6 million cubic feet of gas and 228 barrels of condensate per day from the Safa reservoir. We are currently drilling and offsetting the future expansion potential. And in the Shushan Basin, we had a recent exploration success the Anti-1X which tested 47 million cubic feet and 1,700 barrels of condensate per day from the Shifa formation. Turning to the North Sea, third quarter production was impacted by annual turnaround maintenance from which we expect the significant production rebound in the fourth quarter. We have had extremely successful drilling campaign this year, having drilled 10 producers with no dry-holes. Our latest North Sea success at the Garten-2, which encountered approximately 1,200 feet of net pay, in the prolific Beryl reservoir across three fall blocks, this compares favourably to the Garten 1, which came online in November 2018 to the 30-day IP of 13,000 barrels of oil and 17 million cubic feet of gas per day from 700 feet of pay. The Garten-2 is expected to be online around year end. Apache holds the 100% working interest in the Garten complex, which will have several follow on wells. The first well at our store development is scheduled for initial production next month. This is a high rate gas condensate well which we anticipate will initially produce over 30% oil. The well will be tied back to the existing infrastructure that connects to the Beryl alpha platform. We plan to drill second production later next year. More detail drilling pad and well highlights can be seen in our third quarter financial and operational supplement. Thank you. And with that, I will now turn the call over to Steve.

Thank you, Dave. On today’s call, I will review third quarter financial results, provide a few updated to our 2019 guidance, and briefly share some thoughts on 2020. As noted in the press release issued last night under Generally Accepted Accounting Principles, Apache reported a third quarter 2019 consolidated net loss of $170 million or $0.45 per diluted common share. These results include a number of items that are outside of core earnings which were typically excluded by the investment community in their published earnings estimates. The most significant difference was a $53 million valuation allowance for deferred income tax benefits. Excluding this and other smaller items, adjusted earnings for the third quarter were a loss of $108 million or $0.29 per share. Production volumes were strong, but oil and NGL realizations weaken during the quarter. Gas prices increased a bit with some improvement at Waha hub, but generally remain very low. All major expense items were in line with or below our guidance for the quarter with the exception of DD&A, which rose to $17.30 per BOE. This was primarily due to reduced proved reserves at Alpine High associated with the recent deterioration in the NGL and natural gas prices. Both the GCX gas pipeline and the Shin Oak NGL pipeline were commissioned during the third quarter. With transport capacity on both of these pipelines, Apache now has access to attractive marketing margins over and above the pipeline test. In terms of full year 2019 guidance, we are increasing our annual DD&A to $15.25 per BOE for the impacts previously described. There are few other smaller changes to full year 2019 guidance, all of which can be found in our financial and operational supplement. As John indicated, we are deep into the planning process for 2020 and beyond. As in past years, we will take a conservative approach to pricing assumptions. We will plan for free cash flow over and above our normal dividend. At current strip pricing, this would indicate a 10% to 20% reduction in capital from 2019. Through the pricing cycle, we believe this approach can combine an attractive free cash flow yield with a moderate pace of production growth. For the next few years, most free cash flow will be used to reduce debt. Our debt maturity profile is now in good shape with just under $1 billion of debt maturating in the 2021 to 2023 timeframe. Our plan is to retire all of this debt as it comes due. As a reminder, for reporting purposes, Apache consolidates Altus' long-term debt. This debt non-recourse to Apache and amounted to $235 million at the end of the third quarter. So as we look forward to 2020, Apache is in a good situation, while the gas and NGL price environment will cause a slow down at Alpine High. We have a well diversified portfolio to allocate capital towards more oil focused opportunities. We will continue to be long-term returns focus with an appropriate balance of free cash flow and moderate growth. And with that, I will turn the call over to the operator for Q&A.

[Operator Instructions] The first question comes from the line of Doug Leggate with Bank of America.

John, I wonder if I could hit a couple of things first of all, at a high level, I understand you haven’t given guidance for 2020, but will you see modest growth, what is that mean?

We don’t see any modest any this point, Doug. We’re in the middle of the planning process, kind of pace, we’ve been on what is leave at the modest.

Okay. I thought that would be quick answer, but so appreciate you’re trying to at least no answering the question. My second one is on Suriname, much and you’re going to get low on this. But I wanted to ask a very specific issue around Suriname, you’ve said for sometime the Apache had a differentiated view of the block. My question is that, you've never released the result of the Popokai well, but a couple of your engineers did talk about the Popokai changed your view all to be thermal maturity of your block. So wonder if I could ask you to characterize, what are the type of targets you’re looking for and address specifically whether you believe this is our predominantly gas prone area that you’re testing? And any color around the spud specific issue would be really appreciated?

Well, the first thing I’ll say Doug is, the team was very impressed with the work that we did from the data that’s out there. So, we thought you do a fantastic job on your report. We said that we have seven different play types on Block 58. The Maka-1 Central well is going to be targeting two of those play types. They’re in the Cretaceous. And I will just suggest that we obviously feel like the, we would be in an oil window or we wouldn't be placing a well there.

I appreciate that. Last one very quickly, as I wonder if you could just address the recent management change and followed by price capabilities in Suriname, and I would note that I believe you saying the PSC before Mr. Kim and joined Apache. So if you could just over some clarification that would be great?

Actually, we picked this block up in 2015. Steve had been on board with us, but he was not working the conventional exploration stuff at that time. So, this is something that actually we did on my watch early in 2015, before any other results were down in Guyana or our wells. So, Steve did not have anything to do with us getting into Suriname or taking this block. Secondly, I want to thanks Steve for his time here. He made great contributions to the organization and is truly a world-class explore. As we disclosed on the call today, I have been thinking about a long-term vision for the Company and working on some significant organizational changes. Steve's remaining tenure was shorter than the time I was planning for. So that require he and I to have a conversation around succession. I propose an appropriate transition in very simply he just elected to resign, but it had nothing to do with Suriname.

The question is from the line of John Freeman with Raymond James.

Hi, John. The first one on, just sort of the initial commentary that you've provided on 2020, so just, it sounds like from I guess the high level when we think capital allocation, you basically said just assume kind of North Sea would be kind of flat year-over-year. Egypt based on the success you’ve had and I assume additional information you’re giving from the seismic shoot that you should see an increase investment there. And then it just sounded like in terms of kind of Permian/Alpine High just more of a shifting of capital there some of the more oiler areas at Midland, Delaware. So, when I think about just as overall region, when I think historically all kind of 70:30 kind of U.S. international. Just I guess how much that could kind of change, as it sounds like just really international the only kind of directionally going up?

Yes. I would say, John, first and foremost, we spent more money at Alpine High and that capital is going to come down, so that in itself will change those the parentages of pie. The exploration spend in Suriname could be a little larger as well, so that also would tilt the international. But -- and then, we stated that the Permian capital is going to come down, but in general the oil drillings is going to go up, so...

And then just the follow-up until we’re given any additional information, can we just contain to assume for these additional, these other two Suriname wells around that $60 million to $65 million per well somewhere to the first?

Yes. I mean the spread shouldn’t be changed in much. I mean we’ve got Nobel Sam Croft. Rates were negotiated and there is actually another extension we could take and have just preserved that option for the future. So, it's going be pretty similar. A lot of that will just depend on what we do and how long we’re on the wells and how much testing and all those things will drive that cost.

The next question is from the line of Brian Singer with Goldman Sachs.

I wanted to see, just a follow-up on John’s question there. More a bigger picture, if you could paint a picture of how Suriname success or lack of excess is going to impact your capital allocation strategy? So, in success case, would you finance development fully and entirely via selling down a stake? Would there be openness to outspending cash flow? Would you need to issue equity? Would you think about just reducing activity elsewhere in the portfolio? And in a lack of success case, what would be your interest for need for inorganic portfolio replenishment?

Well, Brian, we feel good about the portfolio with or without Suriname. So I think we got a very diverse portfolio, we’ve got great optionality, we’ve got lots of onshore unconventional inventory that is all weighted as well as some optionality on the rich gas side. We got good inventory both on our international areas and then obviously Suriname offers a new playground for us. So, we feel good about the inventory and feel good about the direction of the Company, I think that’s one thing. If you look back over the last four years from where we sit today, from where we were, we have a lot of more inventory than we have on all fronts. So, as far as financing or success case at Suriname, we still have a 100% equity in that block, and we made a very clear that our intent would be to likely bring in a partner, and we feel like it that would play a role and how that would be funded. So, I am not in a position to give you a lot more color than that, but I don’t see us having to stop some of the other things that would be doing or significantly stressing our balance sheet. Steve, do you want to add anything.

No, I think that’s good John.

And then, the follow-up is with regard to the onshore inventory you mentioned, some improved performance or economics on the Cline. Can you just talk to what you’re seeing in terms of supply cost coming down either by cost reduction or improve performance in the Permian? And then any update on exploratory efforts in the onshore?

At this point, we do not have anything that we prepared to update on the onshore exploratory side. I will say in general, cost are, it's kind of mix bag, some things are coming down and some of the services there has been some slowdowns. Some of it remains tight, so we’re managing that, so it's really a function of the individual services. I think what you’re seeing now is having been in kind of a development mode with those pads. A lot of the synergies and things were drive out or in the cost to really more function just the efficiencies that come with the larger scale, pad development where you have all the infrastructure in place. I’ll put it over to Dave to comment on the Cline.

Yes. So, thanks John. The Cline well just a little more color than in the prepared remarks. It's one well that it’s been online for 120 days. We’re happy with its performance. We look at our portfolio when we think we have opportunities under a couple of field at least. And so, you’ll be hearing more about that as we kind of get to the end of 2020.

The next question is from the line of Bob Brackett with Bernstein Research.

Good morning. I’m looking at that TVD of the Market Central at 6,325 meters, that's considerably, say, several thousand feet deeper than Haimara, which is maybe your closest offset well from the industry. Does that suggest you’re trying to tap the top of the Jurassic? Or is that landing somewhere in the Cretaceous?

I would just say at this point that would you know most of our targets, the two plays will be testing here are in the Cretaceous.

Bob here, but I appreciate the compliment. A quick question then, what about the Miocene? You didn’t mention that as one of the play types?

At this point where you've gone through a full evaluation of all of the play types, so, Bob that’s where we are I mean this is two in the Cretaceous in a very nice sticks section.

Yes, concurred. In terms of the modest oil production growth that you highlighted, should I stay specifically into focus on oil production growth and the gas will be sort flat or down or just gas track with that oil?

We would be emphasizing the modest oil plays.

Your next question is from the line of Charles Meade with Johnson Rice.

I wanted to understand that there is a lot of focus on this first well, but I wonder if I could get you to talk a little bit more about these next two wells that are going to come after. My guess would be that since you've already got the -- the rig going to drill these back-to-back that you already have those two locations mapped out and that they're going to be independent of your result on this first well. But can you talk about whether that's right? Or how you -- how those next 2 wells are going to go?

Charles, we actually permitted nine different wells. So, there is multiple, multiple target. I’ll just say since it is the first well in this area that we’ll be gathering data and there are some decision through things we’ll do based on the data we collect. So, we’ve got a pretty good idea where we want to go, but information and confirmation is certain things will drive the exact thoughts and process.

And then if I could go back to the Blackfoot pad in the Alpine High. Dave, I appreciate the comments you made about that in the prepared remarks, but I was curious you mentioned -- I believe, I heard you mentioned that you left the frac water soak on those -- on that pad for, I think, 60 days. Can you talk about -- is that -- has that been a standard procedure at Alpine High? Is that something new or different view you chose to do? Or maybe just -- maybe it was just the timing? Can you talk about whether that's the standard plan whether it's a one-off? And what you're going to learn going forward from this?

Yes, Charles, good question. We’ve had some opportunities in the past to soak wells, really do the facility constrain so what we found in some cases and well performance improve of soak. When we frac the 14 well Blackfoot pad remember that was, the wells were all completed sequentially. So, we put a lot of produced water into a relatively compact part of the reservoir. And we thought, well, let's taken the advantage of well commodity prices, initiate a 60-day soak. Really trying to understand is that relative permeability issue? Or what are the mechanisms for the underperformance? We’ve had the pad back online for about 30 days. The gas rate came back above. The pretty soak rate and it's actually holding in pretty flat, which say or was some impact in the condensate rate came up, higher than the pre-soak rate. So, what we’re doing Charles, we’re evaluating that, we have a team of folks doing some detail work on the Blackfoot and all of the multi-well pads that we've drilled and completed today.

The next question is from the line of Gail Nicholson with Stephens.

I am looking at Egypt, you guys had a really nice results there this quarter. When you guys look at cash 2020 and CapEx, do you guys have any idea -- an updated idea what maintenance CapEx is Egypt would be to keep adjusted 72,000 flat?

Gail, we’ve got results from the new 3D that we're starting to see from our prospect inventory should improve is what we’re excited about. So, we don’t really look at rig count to keep things flat because we’re just working on what’s project are going to be best in terms of the allocation. But as we’ve said, with the new inventory and the things we’re seeing, I think there is a potential to actually return Egypt on the oil side to grow and so, we’re tired about that.

And then just looking the recent exploration at the [indiscernible] G12 and the [indiscernible] condensate discovery. How does that I guess maybe change future potential gas development in Egypt?

Well, we’ve got a lot of infrastructure from Qasr. And so, there is the nice thing about some things is they can be tied in. Most of our drilling will be focused on oil, but we do have a lot of gas infrastructure and capacity. So, it’s not a big deal, and if we find it and it still very economic for us is as we get about 265 NIM for that.

The next question is from the line of Mike Scialla with Stifel.

Just wanted to see if there anything you could say about what you've seen so far in the Maka Central wells at this point?

I’d say we’re drilling ahead that we are now in the shallower targets. And Mike, the only thing I’ll say at this time point is, is that, we have not seen anything that would be unexpected.

And just wanted if you could give any more color on the organizational initiatives that you put in place?

Yes. I think we see an opportunity to reduce kind of take a $150 million out of the system. I think it's going to unable to deliver more proactive planning and improve capital allocation, which is something we strived to continually do. I think it's going to enable us to advance our resource progression from access to exploration to the development and operations is going to allow us to right size both the corporate and regional offices to more efficiently support the new organization. We’re going to minimize duplication, eliminate some redundancies and it also is going to help us really enable the collaboration on the value adding technology adoption.

The next question comes from the line of Neal Dingmann with SunTrust.

John, my question is based on the early strong Lower Cline test that you've seen in that Driver Schrock pad. Do you have plans to increase activity targeting this zone? Or I guess maybe I’ll ask a different way, could you all just maybe discuss your upcoming multi-zone development pad around the Midland Basin?

Yes. I think we’ve got our inventory so lined out, but it doesn’t impact the next couple of pads. But what it does is, we’re constantly dipping down and testing things that we can add in the future. And so, we can’t jump around next pad and move here. I mean we’ve really got this machine lined out and we’re in an execution mode. But we factor that in, we’re testing things that we think and add material inventory and then we will start planning that into our future pads is the way I think about that and is kind of where we approach things.

And then just one follow-up, could you all discuss any upcoming lease requirements that you might have at Alpine High as you slowdown activity in the play?

Yes, I mean that’s one of the big things where you've kind of challenged the team to do that is work through a plan that helped to determine what acreage we want to maintain for optionality purposes. So, that’s the process we’re working through, and we will be very deliberate and work through what it is, we think we have to maintain for optionality in the future.

The next question comes from the line of Leo Mariani with KeyBanc.

Just wanted to follow up a little bit there on Alpine High, obviously, you guys are kind of cutting back activity, but still looks like you have a pretty nice growth ramp here into fourth quarter. Just kind of wanted to get a sense with sort of 2 rigs out there in '20, how should we think about Alpine High production? Obviously, you've got significant production there. I mean is that's something that can kind of be maintained kind of at sort of year-end '19 levels? Or would you start to see some declines there with a couple of rigs?

Well, we’ll come back in February with the, when we have better view exactly what the plans is going to look like. But I do know we deferred some completions in early 2020 and we got some docs. So, it’s not going to drop massively, but we’ll come back with the shape for the curve next year that’s comments through with the activity level that we’ll go forward with.

And I guess, obviously, there's significant infrastructure there and clearly we'll get, I guess, another gas pipeline and Permian Highway coming sometime in early '21. I mean, I guess, what type of kind of future gas and NGL prices do you guys kind of want to see to where you may harvest kind of more of that resource? Any color on that would be helpful.

Yes. Thank you, just step back late 2018, we went in the more what I called the development stage and as Dave mentioned in prepared remarks we initiated pad drilling on four multi-well pads. Concurrently this spring we had a natural gas and NGL price is really materially lower and that happen as we started to bring on some of the infrastructure. So we’ve got the pads to evaluate and we’ll just come back with that view as well.

And I guess, just lastly on Egypt. Certainly, I noticed that your gross liquids volumes primarily on the oil side in the third quarter were kind of down versus 2Q kind of roughly 9% on my math here. Just wanted to get a sense if there was anything anomalous going on in 3Q on the gross oil volumes in Egypt that may have driven that reduction?

Yes, this is Dave Pursell, really what drove that were declines in Qasr and Berenice.

Okay.

Remember those -- just for some color, those fields have been producing for a wild now and it held much better than anticipated. So, we’re expecting declines at some point and we saw here in the third quarter.

The next question comes from the line of Richard Tullis with Capital One Securities.

Just a couple of more on the Alpine High, John, could you talk a little bit about reserve write-downs that you took in the quarter related to the lower commodity pricing?

Yes. This is Dave Pursell. So, we’ll -- there’ll be more color at the end of the year in the K and there maybe some commentary in the Q, but what you see any price revision was primarily on gas and NGLs in the Permian Basin. There were very modest or performance vision, so the price revision were due to low basin gas and NGL prices and primarily focusing on Permian Basin.

And Dave, do you expect any additional year end write-downs in addition to what you referenced in the 3Q?

Yes. I think, if you -- yes, it’s a good question. If you look at the trailing four quarter pricing, we’re still benefiting somewhat a high fourth quarter 2018 price. So, as we roll forward and if you look at the future prices for the fourth quarter of 2019, we lose the benefit of the one high quarter that’s in the averaging right now. So, if the forward prices hold we would envision there would be some additional price revision in the fourth quarter. Say again still so hard to quantify those to get the actual in, but that’s kind of where we see it now.

That’s helpful. Thank you. And just my last question also related to Alpine High. Do you have any sort of minimum volume commitments with Altus that you have to maintain?

No, acreage dedication.

The next question is from the line of Scott Gruber with Citigroup.

So circling back on the CapEx split between U.S. and international, just back of the envelope here, it appears that the 4Q shift will see the U.S. international split move towards 65:35 based upon the updated annual guide for 2019. Is that broadly how we should think about the split in 2020, overall, would yield the modest spending growth abroad, is that how we should think about it?

I mean what I would say, I hate that, you just look at the one quarter, right, because things move around. But I would say in general, our CapEx is going to come down as we set. You’re going to see last rich gas drilling at Alpine High and you’re liable to see pretty flat pace in the North Sea compared to where we are, and we actually have some exploration wells. So that number might come down a little bit. Egypt should be flat to slightly and our oil projects in the U.S. are going to be a little higher as well. So, we’ll give you more color in February when we come out with our final 2020 plans.

And then just on the UK given the production momentum heading into next year, what are you guys looking at in terms of production over the full course of 2020? Can you generate some growth from the UK next year?

Once, again, we’ll hold off on the 20s specifics until we come out with the plan, but we’re very excited about the program. They’ve done a tremendous job this year at Garten 2, absolutely exceeded our expectations. We’ve got an entire fault block there that looks just fantastic that we had upside at the Storr well. So, we’ve got some big things coming on and it sets up as Dave said in his prepared remarks, set ups some additional drilling at Garten in the future. So, the shape of the curve going into 2020 is going to have a lot of momentum for the North Sea.

The next question is from the line of Ryan Todd with Simmons Energy

Maybe a follow-up question on Alpine High and Altus in particular, I mean, given the reduction activity at Alpine High, I know you have MVC. But how do you think about the go forward options at Altus longer-term in terms of future capital to spend on the G&P side, potential options to address the value and/or structure of the entity?

Ryan, I’ll ask you it's not too bigger than inconvenient so just hop on the Altus call this afternoon at 1 o'clock, and we'll let Clay and team there handle all of those questions directly.

Maybe one follow-up on Egypt, I mean, you've mentioned the possibility to generate long-term growth as opposed to just holding volumes flat in the region. I mean, what would you need to see the move in that direction? Would you need to see continue the exploration success? Have seen enough already? And is there anything else that would dictate kind of how aggressive you would or could be there?

No, I mean, that's we got very large position, right; and we’ve got a very large base, I think the technology that we’re applying the new acreage we picked up with the new 3D puts us in a position for pretty interesting looking inventory. And I think it's going to be more driven off the inventory and the opportunity set than anything.

The next question is from the line of Jeanine Wai with Barclays.

Just wanted to follow up on some of the Egypt questions, I make sure I got some of your remarks correct. So, in your prepared you've indicated that you’re building and enhancing drilling inventory there. And so, can you provide us with an update on what the current capital efficiency looks like because that might have changed over the past couple of years as you're spending below maintenance? And then, how productive the first call and incremental capital sounds like, because it seems like there could be some exploration? I know you said there is already some gas facility there, but not sure what’s there on the oil side in order for you to increase production?

Yes, Jeanine, I thank if you look at Egypt, I don’t think we’ve been under investing. So, that’s the first thing I’d say, I think we’ve been investing in appropriate pace. We had a very large discovery in Qasr, many, many years ago, which is pretty unique. And so, if you take that out and look at the portfolio, we’ve been on a really good pace. You look at the Ptah and Berenice discoveries, we had in late 2014 early 2015; things have been going quite strong. So, we’ve got a big footprint. We’ve been there a long time. We spread out over a very, very large area. And my point on the other tie ends is, we just have a lot of capacity there for more gas yields. And so, I think things are going quite well and we do see the potential to improve our productivity with the new inventory.

My second question is on the Alpine High, in terms of giving away some Alpine High CapEx to other early play. At what commodity prices do you think that Alpine High can beat your capital? And I guess what we’re thinking is just that, you’re takeaway contracts specifically for Alpine High for NGLs and crude, those are acreage dedications so you have a ton of flexibility there. The gas takeaway I believe has that MVCs, but I’m pretty sure that you wouldn’t have an issue arbing those out. So, just trying to really figure out kind of what the push and pull is on CapEx allocation to that play?

I mean it's purely going to be forward look at the incremental economics.

Our final question will come from the line of Michael Hall with Heikkinen Energy Advisors.

Thanks. A lot of been address, I guess maybe going back to Suriname. Now, you’ve got the Mako Well location out there. Is there any additional color you can provide as to why this was the first of the test of the nine wells you’ve permitted and any additional color on the thought process there?

Well, I mean it’s first of all in the block, right. So -- and it’s a well that we like, some of the prospect there its ability to test two of them and that’s why we chose it.

And were there any risks in the other wells that you were mitigating with the selection of this well?

With the exploration and your first well in, it’s a process right. So, there is -- since it has the word exploration by, there's always risks that you're assessing and you learn from. And so, but this was the order of the first well we thought we should drill, and from there, we got numerous options to go. So, but there is -- as we said all along, there are seven different play types. There are many, many significant very good looking prospects, so we just had to get started somewhere.

And then I guess just to come back on the Alpine High economics side of thing, I think in the past you’ve talked about mid-$0.20 or 7 handle on propane as kind of the level to think about where Alpine High will compete for capital. Are those still fair levels to watch?

Michael, we’ll come back on that. I mean once again, we've got four pads that we’re evaluating, and it really is going to boil down to now that we have the infrastructure in place. It's more about the incremental economics relative to our other portfolio opportunities.

And with no further audio questions, I’ll hand the floor back to John Christmann for closing remarks.

So, thank you. In closing, Apache is taking significant steps to lower our cost structure and to further optimize our capital allocation. Our goal is to improve free cash flow yield inclusive of the dividend, increase returns, and continue our pace of modest oil growth. We have some very attractive exploration opportunities throughout the portfolio that make Apache a differential investment opportunity. Thank you and happy Halloween.

This does conclude today’s conference call. We thank you for your participation and ask that you please disconnect your line.