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. If you would like to ask a question at that time, simply press star and the number one on your telephone keypad. 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 personal 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 have 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 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. 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 as structural in nature and unlikely to improve for the foreseeable future. Compounding this, investors are frustrated with excessive capital investment by U.S. producers in pursuit of growth, which has come at the 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 straightforward: deliver competitive risk-adjusted returns with a long-term moderate pace of growth, improve our free cash flow yield to levels consistent with other mature industrial sectors, and progress our sustainability initiatives. As we have done for the last several years, Apache will budget using a conservative price deck and flex 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 overhead costs. Apache has historically employed a decentralized, region-focused 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 $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%-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 are assessing the potential for increased investment in the future. In the North Sea, we intend to maintain a consistent level of activity year-over-year. Turning to Suriname, we have retained the Noble Sam Croft to drill the second and third wells on Block 58 in 2020, with an option still outstanding on a fourth well. We are planning to drill these wells at 100%, but that may change should we choose to farm down our interest.
As we progress through the 2020 planning process, we continue to monitor commodity fundamentals and evaluate multiple capital allocation scenarios under a number of different price decks 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 delays 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 decreased production outlook on one of our multi-well pads, has resulted 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 Storr 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 Maka Central-1 in late September and expect to TD the well in November at 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 with 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 enhance our investment proposition. Our diversified portfolio affords the flexibility to allocate capital across 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. 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. Good morning. Our strong operational results for the third quarter reflect the benefits of a 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're advancing a number of exploration programs, both internationally and in the U.S., and development activities continue at a steady pace in our legacy U.S., North Sea, and Egypt regions. During the third quarter, we drilled and completed 64 gross wells, 48 in the U.S., 14 in Egypt, and two in the North Sea. U.S. third-quarter production totaled 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 Midland County.
This pad produces from the Lower Spraberry Shale, Wolfcamp A and B, and Lower Cline formations. The Lower Cline well tested a new landing zone with favorable 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 a five-well, two-mile pad in the Hartgrove area, producing from the Wolfcamp B1 and B4 formations. 30-day IPs averaged 1,150 barrels of oil equivalent per day with 79% oil, with D&C costs averaging a very efficient $7.2 million per well. In the Delaware Basin, we drilled five wells with one-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 completion timing on our Permian oil production. We are on pace to put all 88 planned Midland and Northern Delaware Basin wells online, but many have been pushed back throughout the year. We have 25 wells scheduled with online dates in November or December, which, based on their timing, will add only minimal 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 flowback operations.
As a result, a significant volume of frac water was pumped into a small area of the reservoir, which may have impacted well productivity. We took advantage of a shut-in period to soak this pad for approximately 60 days. The wells have been returned to production at higher rates. Additional modeling 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 a development lease and have drilled a second well, the Cobra number 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, plus 6 million cubic feet of gas and 228 barrels of condensate per day from the Saphur reservoir. We are currently drilling an offset and have future expansion potential. In the Shushan Basin, we had a recent exploration success, the Ante-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 a significant production rebound in the fourth quarter. We have had an extremely successful drilling campaign this year, having drilled 10 producers with no dry holes.
Our latest North Sea success is the Garten No. 2, which encountered approximately 1,200 feet of net pay in the prolific Beryl reservoir across three fault blocks. This compares favorably to the Garten #1, which came online in November 2018 with a 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 No. 2 is expected to be online around year-end. Apache holds 100% working interest in the Garten complex, which will have several follow-on wells. The first well at our Storr 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 existing infrastructure that connects to the Beryl Alpha platform. We plan to drill a second production well at Storr later next year.
More detailed drilling pad and well highlights can be seen in our third quarter financial and operational supplement. Thank you. 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 updates 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 are 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 weakened during the quarter.
Gas prices increased a bit with some improvement at Waha Hub, generally remained 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 NGL and natural gas prices. Both the GCX gas pipeline and the Chinook 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 tariffs. 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 a 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%-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 maturing in the 2021-2023 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 is non-recourse to Apache and amounted to $235 million at the end of the third quarter. As we look forward to 2020, Apache is in a good situation. While the gas and NGL price environment will cause a slowdown at Alpine High, we have a well-diversified portfolio to allocate capital toward more oil-focused opportunities. We will continue to be long-term returns focused with an appropriate balance of free cash flow and moderate growth. With that, I will turn the call over to the operator for Q&A.
At this time, if you'd like to ask an audio question, you may do so by pressing star and the number 1 on your telephone keypad. Again, that is star 1. The first question comes from the line of Doug Leggate with Bank of America.
Thank you. Good morning, everybody. 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 yet. When you say modest growth, what does that mean?
We're going to say modest at this point, Doug. We're in the middle of our planning process, kind of a pace we've been on. We'll just leave it at modest.
Okay. I thought that would be a quick answer, but so I appreciate you trying to, or at least not answering the question. My second one is on Suriname. I imagine you're going to get a lot on this, but I want to ask a very specific issue around Suriname, John. You've said for some time that Apache had a differentiated view of the block. My question is that you never released the result of the Popokai-1 well, but a couple of your engineers did talk about that Popokai-1 changed your view of the thermal maturity of your block. I 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 a predominantly gas-prone area that you're testing. Any color around that specific issue would be really appreciated.
The first thing I'll say, Doug, is the team was very impressed with the work that you did from the data that's out there. We thought you did a fantastic job on your report. We've said that we have seven different play types on Block 58. The Maka number one central well is going to be targeting two of those play types. They're in the Cretaceous. I would just suggest that we obviously feel like we would be in an oil window, or we wouldn't be placing the well there.
I appreciate that. Last one very quickly is, I wonder if you could just address the recent management change and whether that impacts your capabilities in Suriname. I would note that I believe you signed the PSC before Mr. Keenan joined Apache, so if you could just offer some clarification, that'd be great. I'll leave it there.
Well, two things. 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. This was something that actually we did under my watch early in 2015, before any of the results were down in Guyana or our wells. Steve did not have anything to do with us getting into Suriname or taking this block. Secondly, I want to thank Steve for his time here. He made great contributions to the organizations and is truly a world-class explorer. 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. That required he and I to have a conversation around succession.
I proposed an appropriate transition, and very simply, he just elected to resign, but it had nothing to do with Suriname.
Appreciate the answer to the tough question. Thanks, John.
The next question is from the line of John Freeman with Raymond James.
Hi, everyone.
Good morning, John.
Hi, John. The first one on just sort of the initial commentary that you provided on 2020. Just it sounds like from, I guess, a high level, when we think about capital allocation, you basically said, just assume North Sea would be flat year-over-year. Egypt, based on the success you've had, and I assume additional information you're getting from the seismic shoot, that you should see an increased investment there. It just sounded like in terms of the Permian/Alpine High, it's just more of a shifting of capital to some of the more oilier areas Midland-Delaware. When I think about just as an overall region, when I think historically you all are 70/30 kind of U.S. international, just, I guess how much that could change, as it sounds like just really international is the only one kind of directionally going up.
Yeah. I would say, John, first and foremost, we spent more money at Alpine High, and that capital's going to come down. That in itself will change the percentages of that pie. The exploration spend in Suriname could be a little larger as well. That also would tilt the international. We stated that the Permian capital is going to come down, but in general, the oil-based drilling is going to go up.
Great. Just the follow-up, until we're given any additional information, can we just continue to assume for these other two Suriname wells around that $60 million to $65 million per well, similar to the first?
Yeah. The spread shouldn't be changing much. The Noble Sam Croft rates were negotiated. There actually is another extension we could take and have just preserved that option for the future. Going to be pretty similar. A lot of that'll just depend on what we do and how long we're on the wells and how much testing and all of those things will drive that cost.
Great. I appreciate it, John. Thanks.
The next question is from the line of Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
Wanted to see, just to follow up on John's question there, more bigger picture, if you could paint a picture of how Suriname's success or lack of success is going to impact your capital allocation strategy. In a success case, would you finance development solely 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? In a lack of success case, what would be your interest or need for inorganic portfolio replenishment?
Well, Brian, we feel good about the portfolio with or without Suriname. I think we've got a very diverse portfolio. We've got great optionality. We've got lots of onshore unconventional inventory that is oil weighted, as well as some optionality on the rich gas side. We've got good inventory both in our international areas and then obviously Suriname offers a new playground for us. 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 more inventory than we had on all fronts.
As far as financing or a success case at Suriname, we still have 100% equity in that block, and we've made it very clear that our intent would be to likely bring in a partner, and we feel like that would play a role in how that would be funded. 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 we'd be doing or significantly stressing our balance sheet. Steve, do you want to add anything?
Nope. I think that's good, John.
Great. The follow-up is with regards 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 costs coming down, either by cost reduction or improved performance in the Permian, any update on exploratory efforts in the onshore?
At this point, we do not have anything that we're prepared to update on the onshore exploratory side. I will say in general, It's kind of a mixed bag. Some things are coming down. Some of the services there's 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, though, is having been in a development mode with those pads, a lot of the synergies and things we're driving out are in the cost are really more a function of just the efficiencies that come with the larger scale pad developments where you have all the infrastructure in place. And I'll flip it over to Dave to comment on the Cline.
Yeah. Thanks, John. The Cline well, just a little more color than in the prepared remarks. It's one well, but it's been online for 120 days. We're happy with its performance. We look at our portfolio, and we think we have opportunities under a couple of the fields at least, and so you'll be hearing more about that as we get through the end of 2020.
Thank you.
The next question is from the line of Bob Brackett with Bernstein Research.
Good morning. I'm looking at that TVD of the Maka Central-1 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 will just say at this point, Doug, most of our targets, the two plays we'll be testing here are in the Cretaceous.
Okay. It's Bob here, but I appreciate the compliment. A quick question. What about the Miocene? You didn't mention that as one of the play types.
At this point, we haven't gone through a full evaluation of all the play types. Bob, that's where we are. This is two in the Cretaceous.
Okay. A quick follow-up.
A very nice thick section.
Yeah. I concur. In terms of the modest oil production growth that you highlighted, should I say specifically it's a focus on oil production growth and that gas would be sort of flat or down? Or does the gas track with that oil?
We would be emphasizing the modest oil pace.
Got you. Thanks much.
You bet. Thank you.
Your next question is from the line of Charles Meade with Johnson Rice.
Good morning, John, to you and your team there.
Good morning, Charles.
Understandably, there's a lot of focus on this first well. I wondered 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 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. Can you talk about whether that's right or how those next few wells are going to go?
Well, Charles, we actually permitted nine different wells. There's multiple targets. I'll just say since it is the first well in this area that we'll be gathering data, and there are some decision tree things we'll do based on the data we collect. We've got a pretty good idea where we want to go, but information and confirmation of certain things will drive the exact selection process.
Got it. That's helpful. If I could go back to the Blackfoot pad in the Alpine High, and Dave, I appreciate the comments you made about that, the prepared remarks, but I was curious that you mentioned, I believe I heard you mention that you let the frack water soak on that pad for I think 60 days. Has that been a standard procedure at Alpine High, or is that something new or different you chose to do? Maybe it was just the timing. Can you talk about whether that's the standard plan, whether it was a one-off, and what you're going to learn going forward from this?
Charles, good question. We've had some opportunities in the past to soak wells really due to facility constraints, and what we've found in some cases, the well performance improved post-soak. When we fracked the 14-well Blackfoot pad, remember, the wells were all completed sequentially. We put a lot of produced water into a relatively compact part of the reservoir, and we thought, "Well, let's take the advantage of low commodity prices, initiate a 60-day soak," really trying to understand is it a relative permeability issue or what are the mechanisms for the underperformance. We've had the pad back online for about 30 days now. The gas rate came back above the pre-soak rate, and it's actually holding in pretty flat, which says there was some impact, and the condensate rate came up higher than the pre-soak rate. What we're doing, Charles, we're evaluating that.
We have a team of folks doing some detailed work on the Blackfoot and all of the multi-well pads that we've drilled and completed to date.
Got it. Thank you for the color.
The next question is from the line of Gail Nicholson with Stephens.
Good morning, everybody. Looking at Egypt, you guys had really nice results there this quarter. When you guys look at kind of 2020 and CapEx, do you guys have an updated idea what maintenance CapEx in Egypt would be to keep adjusted product or the 72,000 barrels flat?
Gail, we've got results from the new 3D that we're starting to see. Our prospect inventory should improve is what we're excited about. We don't really look at rig count to keep things flat because we're just working on which projects are going to be the best in terms of the allocation. As we've said, with the new inventory and the things we're seeing, I think there's the potential to actually return Egypt on the oil side to growth. We're excited about that.
Just looking at the recent exploration success with that Matruh deep well and the gas condensate discovery, how does that, I guess, maybe change future potential gas development in Egypt?
Well, we've got a lot of infrastructure from Khalda, and so the nice thing about some of those things is they can be tied in. Most of our drilling will be focused on oil. We do have a lot of gas infrastructure and capacity, so it's not a big deal. If we find it and it's still very economic for us, we get about $265 an M for that.
Great. Thanks, and great quarter.
Thank you.
The next question is from the line of Michael Scialla with Stifel.
Hey, good morning, John.
Good morning, Mike.
Just want to see if there's anything you can say about what you've seen so far in the Maka Central wells at this point.
I'd say we're drilling ahead. We are now in the shallower targets. Mike, the only thing I'll say to this point is that we have not seen anything that would be unexpected.
Okay. We'll stay tuned there.
Thank you.
I want to see if you could give any more color on the organizational initiatives that you've put in place?
Yeah, I think we see an opportunity to reduce or take $150 million out of the system. I think it's going to enable us to deliver more proactive planning and improve capital allocation, which is something we strive to continually do. I think it's going to enable us to advance our resource progression from access to exploration to development and operations. It's going to let us 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 and adoption.
Great. Thanks, John.
Thank you, Mike.
Your next question is from the line of Neal Dingmann with SunTrust.
Morning, John and team. John, my question is based on the early strong Lower Cline test that you've seen in that Driver-Schrock pad, do y'all have plans to increase activity targeting this zone? I guess maybe I'll ask a different way, could y'all just maybe discuss your upcoming multi-zone development plans around the Midland Basin?
Yeah, I think we've got our inventory so lined out that it doesn't impact the next couple of pads. What it does is, we're constantly dipping down and testing things that we can add in the future. We can't jump around next pad and move here. We've really got this machine lined out, and we're in an execution mode. We factor that in. We're testing things that we think can add material inventory, and then we will start planning that into our future pads, is the way I think about that, and it's kind of the way we approach things.
Okay, just one follow-up. Could y'all discuss any upcoming lease requirements that you might have at Alpine High as you slow down activity in the play?
I think that's one of the big things we've challenged the team to do, and that is work through a plan to help determine what acreage we want to maintain for optionality purposes. That's the process we're working through, and we will be very deliberate and work through what it is we think we ought to maintain for optionality in the future.
All right. Very good. Thanks, John.
The next question is from the line of Leo Mariani with KeyBanc.
Hey, guys.
Hey, Leo.
Hey, how are you? 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 two rigs out there in 2020, how should we think about Alpine High production? Obviously, you've got significant production there. Is that something that can be maintained at sort of year-end 2019 levels, or would you start to see some declines there with a couple of rigs?
Well, we'll come back in February when we have a better view exactly what the plan's going to look like. I do know we've deferred some completions into early 2020, and we've got some ducks, so it's not going to drop massively. We'll come back with a shape for the curve next year that's commensurate with the activity level that we'll go forward with.
Okay. That's helpful. 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 2021. I guess, what type of future gas and NGL prices do you guys want to see to where you may harvest more of that resource? Any color around that would be helpful.
I think if you step back, late 2018, we went into more of what I call development stage. As Dave mentioned in the prepared remarks, we initiated pad drilling on four multi-well pads. Concurrently, this spring, we had the natural gas and NGL prices really move materially lower. That happened as we started to bring on some of the infrastructure. We've got the pads to evaluate, and we'll just come back with that view as well.
Well, that's helpful. 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 there in Egypt that may have driven that reduction.
Yeah. Leo, this is Dave Pursell. Really what drove that were declines in Khalda and Berenice.
Okay.
Remember, just for some color, those fields have been producing for a while now and have held up much better than anticipated. We were expecting declines at some point, and we saw them here in the third quarter.
All right. Thank you.
Your next question comes from the line of Richard Tullis with Capital One Securities.
Hey, good morning. Thanks for taking my questions. Just a couple more on Alpine High. John, could you talk a little bit about the reserve write-down that you took in the quarter related to the lower commodity pricing?
Yeah. This is Dave Pursell. There'll be more color at the end of the year in the K, and there may be some commentary in the Q. What you see, any price revision was primarily on gas and NGLs in the Permian Basin. There were very modest or performance revisions, so the price revisions were due to the low basin gas and NGL prices, and primarily focused in the Permian Basin.
Dave, do you expect any additional year-end write-downs in addition to what you referenced in the 3Q?
Yeah, it's a good question. If you look at the trailing four quarter pricing, we're still benefiting somewhat from a high fourth quarter 2018 price. As we roll forward, and if you look at the futures prices for the fourth quarter of 2019, we lose the benefit of the one high quarter that's in the averaging right now. If the forward prices hold, we would envision there'd be some additional price revisions in the fourth quarter. Again, still hard to quantify those till we get the actuals in. That's kind of where we see it now.
That's helpful. Thank you. 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.
Okay. All right. That's all for me. Thank you.
Thank you.
The next question is from the line of Scott Gruber with Citigroup.
Yes, good morning.
Good morning, Scott.
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 it yield modest spending growth abroad year-over-year? Is that how we should think about it?
What I would say is, I hate to have you look just at one quarter, right? Things move around. I would say, in general, our CapEx is going to come down, as we said. You're going to see less rich gas drilling at Alpine High. You're liable to see pretty flat pace in the North Sea compared to where we are. We actually have some exploration wells that are going to get carried, so that number may come down a little bit. Egypt should be flat to slightly higher, and our oil projects in the U.S. are going to be a little higher as well. We'll give you more color in February when we come out with our final 2020 plans.
Got it. Just on the U.K., 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 U.K. next year?
Once again, we'll hold off on the '20 specifics until we come out with a plan. 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. We had upside in the Storr wells. We've got some big things coming on, and it sets up, as Dave said in his prepared remarks, sets up some additional drilling at Garten in the future. The shape of the curve going into 2020 is going to have a lot of momentum for the North Sea.
Very good. Appreciate the color. Thank you.
Thank you.
The next question is from the line of Ryan Todd with Simmons Energy.
Yeah, thanks. Maybe a follow-up question on Alpine High and Altus in particular. Given the reduction in activity in Alpine High, I know you don't have MVCs, but how do you think about the go-forward options at Altus longer term in terms of future capital spend on the G&P side, potential options to address the value and/or structure of the entity?
Ryan, I'll ask you if it's not too big of an inconvenience to just hop on the Altus call this afternoon at 1:00, and we'll let Clay and the team there handle all of those questions directly.
Okay. Got you. Maybe one follow-up on Egypt then. You mentioned the possibility to generate long-term growth as opposed to just holding volumes flat in the region. What would you need to see to move in that direction? Would you need to see continued exploration success? Have you seen enough already? Is there anything else that would dictate how aggressive you would or could be there?
We've got a very large position, right? We've got a very large base. I think the technology that we're applying and the new acreage we picked up with the new 3D puts us in a position for some pretty interesting-looking inventory. I think it's going to be more driven off of the inventory and the opportunity set than anything.
Okay, great. Thanks for the help.
The next question is from the line of Jeanine Wai with Barclays.
Hi, good morning, everyone.
Good morning, Jeanine.
Just wanted to follow up on some of the Egypt questions and make sure I got some of your remarks correct. In your prepared remarks, you indicated that you're building and enhancing drilling inventory there. 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 with you spending below maintenance. How productive the first call on incremental capital sounds like, because it seems like there could be some exploration. I know you said there was already some gas facilities there, but not sure what's there on the oil side in order for you to increase production.
Yeah, Jeanine, I think if you look at Egypt, I don't think we've been under-investing. As the first thing I'd say, I think we've been investing at an appropriate pace. We had a very large discovery in Khalda many, many years ago, which is pretty unique. 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. We've got a big footprint. We've been there a long time. We're spread out over a very, very large area. My point on the other tie-ins is we just have a lot of capacity there for more gas yields.
I think things are going quite well, and we do see the potential to improve our productivity with the new inventory.
Okay, great. That's really helpful. My second question is on the Alpine High. In terms of pivoting away some Alpine High CapEx to other more oily plays, at what commodity prices do you think that the Alpine High competes for capital? I guess what we're thinking is just that your 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 MVCs, but I'm pretty sure that you wouldn't have an issue arbing those out. We're just trying to really figure out what the push and pull is on the CapEx allocation to that play.
It's purely going to be the forward look at the incremental economics.
Okay, great. Thanks very much.
Thank you.
Our final question will come from the line of Michael Hall with Heikkinen Energy Advisors.
Thanks. A lot have been addressed. I guess maybe going back to Suriname, now that we've got the Maka well location out there, is there any additional color you can provide as to why this was the first of the tests of the nine wells you've permitted? And any additional color on the thought process there?
Well, it's the first well on the block, right? It's a well that we liked some of the prospects. There's its ability to test two of them, that's why we chose it.
Okay. Were there any risks in the other wells that you were mitigating with the selection of this well?
With exploration and your first well in, it's a process, right? Since it has the word exploration by it, there's always risks that you're assessing, and you learn from. This was the order of the first well we thought we should drill, and from there we've got numerous options to go to. As we've said all along, there's seven different play types. There are many, many significant, very good-looking prospects. We just had to get started somewhere.
Okay, fair enough. Helpful color. Then I guess just to come back on the Alpine High economic side of things, I think in the past you've talked about mid-$0.20 ethane or $7 handle on propane as the level to think about where Alpine High would compete for capital. Are those still fair levels to watch?
Michael, we'll come back on that. Once again, we've got four pads that we're evaluating. 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.
Okay. Thank you.
Thank you.
With no further audio questions, I'll hand the floor back to John Christmann for closing remarks.
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 a 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.