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 speakers' remarks, there will be a question and answer 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 3rd 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 Purcell, 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 Q3 financial performance.
Our prepared remarks will be approximately 20 minutes in length, with the remainder of the hour allotted for Q and A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our Q3 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. 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 3rd quarter performance and 4th quarter outlook. The market has come to view the lower oil and gas price environment that has been in place since 2014 is 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 and 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 5 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 Q1. We are targeting at least $150,000,000 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 4th 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 $2,400,000,000 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. And 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 2nd and third wells on Block 58 in 2020 with an option still outstanding on a 4th well. We are planning to drill these wells at 100%, but that may change should we choose 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 3rd quarter performance and 4th 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 4th quarter Permian oil volumes of approximately 100,000 barrels per day.
At Alpine High, we have reduced our drilling activity to 2 rigs and have chosen to defer some 4th quarter completions into 2020. This lower activity set combined with a decreased production outlook on 1 of our multi well pads has resulted in an approximate 5% reduction in our 4th quarter Alpine High guidance. Internationally, 3rd quarter production was in line with guidance and our outlook for the Q4 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 Maca 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 7 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 3 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 3 key regions as well as a potentially transformational position offshore Suriname. With that, I will turn the call over to Dave Purcell, who will provide some operational details on the quarter.
Thanks, John, and good morning. Our strong operational results for the 3rd 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 Q2. 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 Q3, we drilled and completed 64 gross wells, 48 in the U. S, 14 in Egypt and 2 in the North Sea. U. S.
3rd quarter production totaled 266,000 barrels of oil equivalent per day. In the Midland Basin, we continue to drill high productivity oil wells. Our Q3 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 Klein formations. The Lower Klein well tested a new landing zone with favorable results, achieving an average 30 day IP of 12 70 barrels of oil equivalent per day at 72% oil.
Plans are underway to drill future Lower Klein wells to further delineate the Klein potential across our Midland Basin acreage. In Reagan County, we drilled a 5 well, 2 mile pad in the Heart Grove area producing from the Wolfcamp B1 and B4 formations. 30 day IPs averaged 11.50 barrels of oil equivalent per day with 79% oil with D and C cost averaging a very efficient $7,200,000 per well. And in the Delaware Basin, we drilled 5 wells with 1 mile laterals at Dixie Land at an average cost per well of less than $5,300,000 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 Q4. 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 4 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, the 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 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 Cobre No. 2, which is producing approximately 3,000 barrels of oil per day. We are currently drilling a 3rd well with plans for a 4th well later this year. In the Matru Basin, the Buruni 1X well tested 5,000 barrels of oil per day from the AEB-six reservoir plus 6,000,000 cubic feet of gas and 228 barrels of condensate per day from the Saffa reservoir.
We're currently drilling an offset net future expansion potential. And in the Shushan Basin, we had a recent exploration success, the Anti-1X, which tested 47,000,000 cubic feet and 1700 barrels of condensate per day from the Sheifa formation. Turning to the North Sea, 3rd quarter production was impacted by annual turnaround maintenance from which we expect a significant production rebound in the Q4. 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 1200 feet of net pay in the prolific barrel reservoir across 3 fault blocks. This compares favorably to the Garten I, which came online in November 2018 with a 30 day IP of 13,000 barrels of oil and 17,000,000 cubic feet of gas per day from 700 feet of pay. The Garten number 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 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 existing infrastructure that connects to the Barrell Alpha platform. We plan to drill a second production well at STORE later next year. More detailed drilling pad and well highlights can be seen in our 3rd 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 Q3 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 3rd quarter 2019 consolidated net loss of $170,000,000 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 $53,000,000 valuation allowance for deferred income tax benefits.
Excluding this and other smaller items, adjusted earnings for the Q3 were a loss of $108,000,000 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, but generally remained very low. All major expense items were in line with or below our guidance for the quarter, with the exception of DD and 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 Shin Oak NGL pipeline were commissioned during the Q3. 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 and 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 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 $1,000,000,000 of debt maturing 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 is non recourse to Apache and amounted to $235,000,000 at the end of the 3rd quarter. So 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. And with that, I will turn the call over to the operator for Q and A.
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, but when you say modest growth, what does that mean?
We're going to say modest at this point, Dave, Doug. We're in the middle of our planning process, kind of a pace we've been on and I will 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 wanted 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 well, but your a couple of your engineers did talk about the Popokai changed your view of the thermal maturity of your block. So 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.
Well, 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. So we thought you did a fantastic job on your report. We've said that we have 7 different play types on Block 58. The Maka number 1 central well is going to be targeting 2 of those play types. They're in the Cretaceous and I would just suggest that we obviously feel like the we would be in an oil window or we wouldn't be placing the well there.
I appreciate. Last one very quickly is I wonder if you could just address the recent management change and whether that impacts your capabilities in Suriname. And I would note that I believe you signed the PSC before Mr. Keenan joined Apache. So if you could just offer some clarification, that would
the conventional exploration stuff at that time. So this was something that actually we did under my watch early in 2015 before any of the results were down in Guyana or Orwell. So 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. So that required he and I to have a conversation around succession. I proposed an appropriate transition I proposed an appropriate transition and very simply he just elected to resign, but it had nothing to do with Suriname.
Appreciate the answer, 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. So just it sounds like from, I guess, a high level, when we think about 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 getting from the seismic shoot that you should see an increased investment there. And then it just sounded like in terms of kind of the PermianAlpine High, it's just more of a shifting of capital to so many more oilier areas, Midland, Delaware. So when I think about just as an overall region, when I think historically you all are kind of seventythirty kind of U.
S. International, just I guess how much that could kind of change? As it sounds like just really international is the only one kind of directionally going up.
I would say, John, 1st 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 percentages of that 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 based drilling is going to go up.
Great. And then just the follow-up, until we're given any additional information, can we just continue to assume for these additional these other 2 Suriname wells around that $60,000,000 to $65,000,000 per well somewhere to the first?
Yes. I mean, the spread shouldn't be changing much. I mean, we've got the Noble Sam Croft rates were negotiated and there's actually is another extension we could take and have just preserve that option for the future. So it's going to 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.
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.
I wanted to see just a 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. So 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? And 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. So I mean, 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.
So we feel good about the inventory and feel good about company. I think that's one thing. If you look back over the last 4 years from where we sit today, from where we were, we have a lot more inventory than we had on all fronts. So 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. So 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?
No, I think that's good, John.
Great. And then the follow-up is with regards to the onshore inventory. You mentioned some improved performance or economics on the Klein. Can you just talk to what you're seeing in terms of supply cost coming down either by cost reduction or improved performance in the Permian? And then 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, costs are it's kind of a mixed bag. Some things are coming down. Some of the services are 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 kind of a development mode with those pads, a lot of the synergies and things we're driving out are in the costs 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 decline.
Yes. So 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 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 kind of 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 at 6,325 meters. That's considerably, say, several 1000 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 2 plays we'll be testing here are in the Cretaceous.
It's Bob here, but I appreciate the compliment. Quick question then. 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. So, Bob, that's where we are. I mean, this was 2 in the Cretaceous. Okay. And a very nice thick section.
Yes, 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, you and your team there.
Good morning, Charles.
I wanted to understand that there's 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 rig going to drill these back to back that you already have those 2 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're how those next few wells are going to go?
Well, Charles, we actually permitted 9 different wells. So there's multiple, 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. So 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. And then if I could go back to the Blackfoot pad in the Alpine Eye. And Dave, I appreciate the comments you made about that in the prepared remarks. But I was curious that you mentioned I believe I heard you mentioned that you let the frac water soak on those on that pad for I think 60 days.
And can you talk about is that a has that been a standard what whether that's the standard plan, whether it was 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 due to facility constraints of what we found in some cases, the well performance improved post Soak. When we fracked the 14 well Blackfoot pad, remember it 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 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. So 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. Thanks 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 in CapEx, do you guys have an idea an updated idea what maintenance CapEx in Egypt would be to keep adjusted for the 72,000 barrels flat?
Gail, we've got results from the new three d that we're starting to see. So 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 which projects are going to be the best in terms of the allocation. But 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. And so we're excited about that.
And then just looking at the recent exploration stuff with that Baccarat deep well in the gas content discovery, how does that, I guess, maybe change future potential gas development in Egypt?
Well, we've got a lot of infrastructure from Kosser. And so there's the nice thing about some of those 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's still very economic for us as we get about 265 and M for that.
Great. Thanks and great quarter.
Thank you.
The next question is from the line of Mike Scialla with Stifel.
Hey, good morning, John.
Good morning, Mike.
Just want to
see if there's 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. We are now in the shallower targets. And Mike, the only thing I'll say to this point is that we have not seen anything that would be unexpected.
See if you I want to see
if you can give any more color on the organizational initiatives that you've put in place.
Yes. I think we see an opportunity to reduce kind of or take $150,000,000 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 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.
Good morning, John and team. John, my question is based on the early strong lower climb test that you've seen in that driver shock pad, do you all 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 plans around the Midland Basin?
Yes. I think we've got our inventory so lined out that 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.
So but 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. And then just one follow-up. Could you all discuss any upcoming lease requirements that you might have at Alpine High as you slow down activity into play?
Yes. I mean, I think that's one
of the big things we've kind of challenged the team to do and that is work through a plan to help 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 ought to maintain for optionality in the future.
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 so it looks like you have a pretty nice growth ramp here into 4th quarter.
Just kind of want to get a sense with sort of 2 rigs out there in 2020, how should we think about Alpine High production? Obviously, you've got significant production there. I mean, is that something that can kind of be maintained kind of 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 with when we have a better view exactly what the plan is going to look like. But I do know we've deferred some completions into early 2020 and we've got some DUCs. So it's not going to drop massively, but 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. And I guess, obviously, there's significant infrastructure there and clearly we'll get I guess another gas pipeline in Permian Highway coming sometime in early 2021. 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 around that would be helpful.
Well, I think if you step back late 2018, we went into more of what I call development stage. And as Dave mentioned in the prepared remarks, we initiated pad drilling on 4 multi well pads. Concurrently, this spring, we had the natural gas and NGL prices really move materially lower and that happened 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.
Well, that's helpful. And I guess just lastly on Egypt, certainly I noticed that your gross liquids volumes primarily on the oil side in the Q3 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?
Yes. Leo, this is Dave Purcell. Really what drove that were declines in Kosser and Bearnese.
Okay.
Remember those just for some color, those fields have been producing for a while now and have held up much better than anticipated. So we're expecting declines at some point and we saw them here in the Q3.
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
Mel? Yes. This is Dave Purcell. So you'll we'll there'll be more color at the end of the year on the in the K and there may be 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 revisions. So, the price revisions were due to the low basin gas and NGL prices and primarily focused in the Permian Basin.
And Dave, do you expect any additional year end write downs in addition to what you've referenced in the 3Q?
Yes. I think if you yes, it's a good question. If you look at the trailing 4 quarter pricing, we're still benefiting somewhat from a high Q4 2018 price. So as we roll forward and if you look at the future prices for the 4th 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'd be some additional price revisions in the Q4.
So again, still hard to quantify those till we get the actuals 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.
Okay. 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.
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 60 five-thirty 5 based upon the updated annual guide for 2019.
Is that broadly how we should think about the split in 2020 overall would yield a modest spending growth abroad year on year? Is that how we should think about it?
I mean, what I would say is I hate to have you look just at 1 quarter, right? Because things move around, but 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 and 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 have 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. So we'll give you more color in February when we come out with our final 2020 plans.
Got it. 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 2020 specifics until we come out with a plan, but we're very excited about the program. They've done a tremendous job this year. Garten II absolutely exceeded our expectations. We've got an entire fault block there that looks just fantastic. We had upside in the store wells.
So 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 Gartner in the future. So 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 Brian Todd with Simmons Energy.
Yeah, thanks. Maybe a follow-up question on Alpine High and Altus in particular. I mean, 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 and P side, potential options to address the value and 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 o'clock 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. I mean, you mentioned the possibility
to
to see continued exploration success? Have you seen enough already? And is there anything else that would dictate kind of how aggressive you would or could be there?
No, I mean, it's we've got a very large position, right? And 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 three d puts us in a position for some pretty interesting looking inventory. And 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 Wang with Barclays.
Hi, good morning everyone.
Good morning, Jim.
I just wanted to follow-up on some of the Egypt questions and make sure I got some of your remarks correct. So in your prepared remarks, you indicated that you're building and enhancing drilling inventory there. And so can you provide us with an then then 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 in the oil side in order for you to increase production.
Yes, Janine, I think if you look at Egypt, I don't think we've been under investing. So as the first thing I'd say, I think we've been investing in appropriate pace. We had a very large discovery in Kosar 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 Piton and Bearanese 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 were spread out over a very, very large area. And my point on the other tie ins 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.
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 place, at what commodity prices do you think that the Alpine High competes your capital? And I guess what we're thinking is just that your takeaway contract 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. So we're just trying to really figure out kind of what the push and pull is on the CapEx allocation to that play?
I mean, 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 you've got the we'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 tests of the 9 wells you've permitted and any additional color on the thought process there?
Well, I mean, it's 1st well on the block, right? So and it's a well that we liked some of the prospects. There's its ability to test 2 of them and 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? So there's since it has the word exploration, but there's always risks that you're assessing and you learn from. And so but this was the order, the first well we thought we should drill. And from there, we've got numerous options to go to. So but there's a as we've said all along, there's 7 different play types.
There are many, many significant very good looking prospects. So we just had to get started somewhere.
Okay, fair enough. It's helpful color. And 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-twenty percent ethane or 7 handle on propane as kind of 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. I mean, once again, we've got 4 pads that we're evaluating. I mean, 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.
And with no further audio questions, I'll hand the floor back to John Kirschmann 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 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.