My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation First Quarter 2019 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. I will now turn the call over to Gary Clark, Vice President of Investor Relations.
Mr. Clark, you may begin your conference.
Good morning, and thank you for joining us on Apache Corporation's 1st quarter financial and operational results conference call. We will begin the call with an overview by CEO and President, John Christmann. Tim Sullivan, Executive Vice President of Operations Support, will then provide additional operational color and Steve Riney, Executive Vice President and CFO, will summarize our Q4 and full year financial performance. Also available on the call to answer questions are Apache Executive Vice Presidents, Mark Meyer, Energy Technology, Data Analytics and Commercial Intelligence and Dave Purcell, Planning Reserves and Fundamentals. Our prepared remarks will be approximately 25 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 Q1 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 data 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 provide an overview of Apache's Q1 results, discuss our production outlook and comment on our first exploration well in Suriname, review our upstream capital budget and Apache's commitment to return incremental cash flow to investors and highlight our progress on non core asset sales. Apache had an excellent Q1 in terms of execution, well performance and delivery against our production and capital guidance. We exceeded our U. S.
Production target by 5,000 BOEs per day and our international target by 7,000 BOEs per day on a capital budget of less than $600,000,000 In the Permian Basin, we maintained oil production near 4th quarter levels despite placing 1 of our 2 completion crews on a frac holiday for the entire Q1. At Alpine High, where we also had a relatively low number of completions, production was up significantly from the 4th quarter and was in line with our guidance of 70,000 BOEs per day. Overall, we delivered a 5% sequential quarterly increase in Permian Basin volumes. This is an impressive accomplishment given that we placed only 39 wells online in the first quarter compared to 60 wells during the Q4. Strong operational execution and well performance coupled with minimal facilities downtime drove these results.
International production was up 6% compared to the 4th quarter. In the North Sea, we benefited from strong early production rates from 2 wells at Garten and Callater, a continuation of good results from our revamped waterflood program in the 40s field and high facilities uptime across our operations. In Egypt, gross production was down slightly in the quarter, but adjusted production net to Apache was up, primarily due to the timing of cost recovery around year end. Looking ahead, 2nd quarter Permian oil production is projected to be down slightly due to completions timing with growth anticipated in the back half of the year as the number of completions increases significantly. At Alpine High, production volumes will be impacted in the 2nd quarter by the voluntary gas deferrals we discussed in our press release last week.
I would note, however, that temporary deferral of this production is expected to improve our short term net cash flow. Construction of Altus Midstream's first two cryogenic plants is proceeding ahead of schedule with the first plant currently commissioning and expected to flow gas this month. The second plant is expected to be fully in service during July and a third plant remains on schedule for the Q4. By year end, Altus will have a total 600,000,000 cubic feet of nameplate rich gas processing capacity capable of producing more than 60,000 barrels of NGLs per day. Kinder Morgan's GCX pipeline is also expected to be in service beginning in October, which will give Apache access to Gulf Coast pricing on 550,000,000 cubic feet per day of gas from the Permian.
These processing and transportation catalysts will drive a significant uplift in Alpine High liquids production, revenue and cash flow, on which Steve will provide more detail in a few minutes. On the international side, production will decrease in the Q2 as planned. The North Sea will experience natural declines from high production wells at Garten and Callater, while only one new well is being brought online during the quarter. In Egypt, we expect gross oil production to increase as we ramp up activity in our new East Bahariya concession. However, the impact of higher oil prices on our production sharing contracts coupled with natural gas production declines will result in lower volumes net to Apache.
Looking out to the end of the year, our projected growth rate guidance from 4th quarter 2018 to Q4 2019 is unchanged. We continue to expect 6% to 10% growth on a total company adjusted basis consisting of 12% to 16% growth in the U. S. And a 2% to 4% decline internationally. Permian oil production is still expected to grow 5%.
In Suriname, we have contracted a drillship and continue to anticipate spudding the first well on Block 58 in Suriname around mid year. The Noble Sam Croft, which is working in the Gulf of Mexico, will deploy to Suriname upon completion of its current assignment. We have secured this drillship for a one well commitment and have an option on 3 additional wells. While Apache is preparing to drill the first well on Block 58 at 100%, we have received and are evaluating numerous proposals from potential partners. Turning now to CapEx.
Our 1st quarter upstream capital investment was below guidance and was down 27% from 4th quarter levels. We began preparing for an activity reduction back in November, which was critical to enabling such a material change in our activity pace in less than 1 quarter. As planned, our 2nd quarter CapEx will increase slightly from the Q1 as a result of increased completion spending in the Permian associated with the return of our 2nd frac crew in the Midland Basin and the timing of large pad completions at Alpine High. The timing of exploration spending mostly in Suriname, but also related to some activities in the Lower forty eight and lease payments at Alpine High, where we are exercising some extension options due to the slower drilling activity. Despite some inflationary headwinds related to the rise in oil prices, we remain on track to deliver our 2019 planned activity set for $2,400,000,000 We are experiencing cost increases in labor, trucking, fuel and chemicals, but have thus far been able to offset these through efficiency gains.
We previously stated Apache's commitment to returning at least 50% of our incremental cash generation from all sources to investors before increasing our planned activity set. In keeping with this commitment, our 2019 planned capital activity and budget remains unchanged and we will begin returning incremental cash to investors in the coming months. This is of course in addition to our current regular dividend. Steve will elaborate further. With the success of our organic growth and exploration program, we find ourselves with some assets in the portfolio that we do not envision funding over the next several years.
These assets will be more valuable in the hands of different owners. Accordingly, we recently entered into sales agreements totaling approximately $300,000,000 most of which is related to an exit of the SCOOPSTACK, which will close in the Q2. In summary, 2019 is progressing very well. Overall production was strong in the Q1 and we are demonstrating excellent capital discipline and cost control. The North Sea and Egypt continue to deliver robust free cash flow with their leverage to premium Brent crude prices and higher natural gas and NGL netbacks.
In the Permian, we are poised to deliver attractive oil growth and a substantial cash flow uplift at Alpine High in the second half of the year. We will also be advancing our differential exploration initiatives, most notably in Suriname. In closing, Apache continues to deliver on the strategy we established 4 years ago, which is to fund a capital program capable of delivering long term returns and sustainable growth, live within cash flow at reasonable oil prices, and continue to return meaningful capital to shareholders. We can accomplish this due to our high quality drilling inventory and attractive exploration portfolio, relatively low base decline rate and continuous focus on improving capital productivity and efficiency. With that, I will turn the call over to Tim Sullivan, who will provide some operational details on the quarter.
Good morning. My prepared remarks on this call will cover Q1 2019 region highlights and a review of the excellent progress we are making at Alpine High on cost reduction initiatives and rich gas pad optimization. Operationally, we are off to a very good start with all regions performing well. Company wide adjusted production was up 4% from the Q4 2018 and up 19% from the same period in the prior year. The Permian was the largest growth driver with production up 5% and 36% respectively over the same time periods.
As John noted, these results are particularly impressive given our reduced activity during the quarter. Our well completions in the U. S. Were down 35% from the 4th quarter, which was the result of timing and a frac holiday in the Permian Basin. We have recently added back a cleaner, cheaper natural gas fueled hydraulic frac fleet.
In the Midland Basin, where we continue to drill high productivity oil wells, our primary activity in this quarter was an 8 well Wolfcamp B pad at Powell and a 6 well Lower Spraberry pad at Wildfire. In the Delaware Basin, we completed and brought online a 4 well Wolfcamp pad at Dixieland and at Alpine High, we brought online 17 wells with the primary focus on rich gas in the Northern Flank. In Egypt, as a result of our recently awarded concessions and our ongoing broadband seismic acquisition program, we have generated several 100 leads and prospects in both legacy and new concession areas. In the new East Bahariya concession, we brought online 3 exploration wells that achieved a combined peak rate of nearly 4,500 barrels of oil per day and have cumed more than 125,000 barrels of oil. These are low cost, short cycle wells that typically pay out very quickly.
We also continue to have exploration success on our legacy acreage. One notable well on our Seawall concession in the Fagore Basin achieved a 30 day average flow rate of 5,200 barrels of oil per day. In the Matrua Basin, our Tango North exploration well tested at a rate of 4,000 barrels of oil per day and will go online around mid year. We also had a very successful Q1 development drilling campaign in Egypt with 14 producers, 9 of which have tested in excess of 1,000 BOE per day. As we continue our GNG work, we expect to identify and drill many low cost, high rate oil prospects throughout the Western Desert, such as the ones we drilled this quarter.
Turning to the North Sea, we drilled our 1st development well at Storr, which was the site of our 2016 exploration discovery. This well encountered 232 feet of net pay in the Nansen and Erickson formations similar to the results from the discovery well. As we explored deeper, this well also encountered an additional 84 feet of net pay in the Kolmorant formation, which is the same sand that is highly productive at Callater. First production at store is expected late in Q4. At Alpine High, we will reach a significant milestone this month with the start up of Altus' first cryogenic plant in the next 2 to 3 weeks.
Before Steve walks you through the significant cash generation and margin uplift we will receive, I wanted to highlight the significant progress we have made with both costs and our rich gas optimization initiatives on the upstream side. Since Alpine High's delineation phase began in 2017, Apache has made steady efficiency gains. Drilling costs per foot are down approximately 20% from 2017 through the end of the Q1. Over the same time period, we realized a 30% reduction in completion cost per lateral foot. These cost improvements have come with only a modest increase in average lateral lengths.
We expect to generate further efficiencies as lateral lengths increase over time and the average number of wells drilled per pad increases. Multi well pad optimization has now begun at Alpine High. We are evaluating optimal pattern and spacing relationships within a section to recover larger volumes of hydrocarbons with fewer wells and less capital. As an example, we recently conducted spacing and pattern tests on 2 rich gas pads in the Northern Flank situated in adjacent sections. By adjusting the horizontal spacing between wells, the vertical location within target zones and in improving our frac design, we are seeing cumulative recoveries from our 6 well Mont Blanc pad significantly outperform our 8 well Blackfoot pad.
Six wells producing from the Woodford AMB formations on the Mont Blanc pad achieved 150 day gross cumulative production of 10.5 Bcf of rich gas compared to 9.7 Bcf from the 8 well Blackfoot pad in the same Woodford A and B formations. In combination with cryogenic processing, each pad would also have cumed in excess of 800,000 barrels of NGLs. With 2 fewer wells, the Mont Blanc pad has not only outperformed, but has also realized cost savings of $12,700,000 as a result of fewer wellbores. Capital efficiency is vital to success in resource play development and the trends are certainly positive for Alpine High. We believe there are substantial additional cost savings to be realized through ongoing optimization initiatives, which include longer laterals and larger pads.
Apache has also made considerable upfront investments in water handling and reuse facilities at Alpine High, which will drive cost savings for many years to come. Our primary target formations, the Woodford and the Barnett produced very little in situ water, thereby eliminating the need to contract costly water handling trucks and saltwater disposal services. We believe Alpine High is well on its way to being the lowest cost, most efficient and most environmentally friendly rich gas play in the country. With that, I will now turn the call over to Steve.
Thank you, Tim. On today's call, I will review Q1 financial results, update the status of gas production deferrals at Alpine High, provide a few guidance changes for 2019, highlight the cash generation capacity of our rich gas production at Alpine High following cryo startup later this month and GCX startup later this year and outline our current thinking around capital return to investors. As noted in the press release issued last night, under generally accepted accounting principles, Apache reported a Q1 2019 consolidated net loss of $47,000,000 or $0.12 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. On an after tax basis, the most significant items include a $35,000,000 unrealized loss on derivatives, a $31,000,000 tax adjustment related primarily to a valuation allowance on deferred tax assets and $18,000,000 of leasehold impairments.
None of these items impacted cash flow in the quarter. Excluding these and other smaller items, adjusted earnings for the quarter were $38,000,000 or $0.10 per share. Highlights for the quarter include upstream capital investment of less than $600,000,000 which demonstrates our commitment to running a disciplined program and meeting our full year upstream capital budget of $2,400,000,000 For 2019, we have locked in pricing on much of our capital costs such as drilling rigs, pressure pumping services and sand. However, as John indicated, trucking, labor, fuel and chemical costs are trending higher with oil prices. 1st quarter operating costs were generally in line with guidance.
LOE per BOE costs came in a bit higher than expectations, primarily driven by Egypt. Offsetting this, gathering, processing and transportation costs were less than guidance. As we look at the remainder of 2019, let me first discuss our temporary production deferrals at Alpine High. Beginning in late March for a variety of reasons, Permian Basin natural gas dipped to extremely low and at times negative pricing. In response, Apache chose to defer a portion of our gas production at Alpine High.
In the month of April, these deferrals averaged approximately 230,000,000 cubic feet per day of gross wellhead gas. The deferred volumes are comprised of both lean and rich gas. And though we anticipate a continuation of weak gas prices until more transport capacity comes online later in the year, we currently plan to restore all of our rich gas production as we commission our first two cryo facilities over the next 8 to 10 weeks. Apache is cognizant of the impact that gas deferrals have on Altus Midstream Company and has agreed to reduce certain shared overhead costs. We believe this is in the best interest of both companies.
It has a negligible net impact to Apache and ensures that Altus remains in a good position to deliver on the critical near term infrastructure build out at Alpine High. With this situation and other impacts in mind, we have updated our forward looking guidance on a number of items. Taking into account a range of potential production deferrals for the remainder of the quarter, our 2nd quarter Alpine High production outlook is 45,000 to 55,000 BOEs per day. This is projected to increase 85,000 to 95,000 BOEs per day in the Q3, which still includes the potential for some deferred volumes. Our 2019 rig schedule and completions activity is not impacted by the deferrals.
As a result, we still expect that 4th quarter year end exit rates from Alpine High will exceed 100,000 BOEs per day. In addition to issuing 2019 quarterly guidance at Alpine High, we have also introduced quarterly Permian oil guidance and international guidance, the details of which can be found in the supplement on our website. For upstream capital investment, we are expecting the 2nd quarter to be in the $650,000,000 to $700,000,000 range and full year capital investment remains at $2,400,000,000 as originally planned. For LOE, we are increasing our guidance to recognize some additional costs in Egypt as well as the impact of lower volumes in Alpine High. Our full year LOE is now expected to average around $8 per BOE.
Next, I would like to review some upcoming changes, which will significantly improve the cash flow generation from Alpine High. While we have been clear that Alpine High is a diversified resource with all 3 hydrocarbon phases, at its core, it is an enormous rich gas play and the key to value which are not very efficient, so we don't recover the full NGL stream. The resulting small volumes of NGLs are currently trucked to a facility where they can be transported to Mont Belvieu and fractionated. This temporary setup is relatively high cost and significantly squeezes the cash margin. Finally, we are selling most of the residue gas at Waha, which as we spoke about previously prices at around 0 today.
The result is extremely low margins and minimal cash flow net to Apache. That is the reality of Alpine High today. But that is all about to start changing because of the preparations that have been underway for nearly 2 years. By the end of this quarter, we will generate much higher NGL yields as we transition to cryoprocessing. We will receive much better NGL margins through transport and fractionation under our long term fixed price contract with Enterprise.
And in a few months, when GCX is placed in service, we will transport residue gas out of the basin and receive Gulf Coast pricing. In our supplement, we have included a slide illustrating the cash generating potential at Alpine High, assuming full utilization of a single cryo unit with 200,000,000 cubic feet per day of nameplate processing capacity. To summarize the key takeaways, 200,000,000 cubic feet per day of gross wellhead gas processed through Altus' cryo facilities is capable of generating $270,000,000 to $300,000,000 of annualized revenue under a very reasonable range of commodity price assumptions. Note, this is net revenue to Apache after royalties. After further netting out all gathering, processing, fractionation and transportation fees, as well as projected operating costs and state severance taxes, Apache's annualized net cash flows from a single cryo facility are expected to range from $135,000,000 to $165,000,000 So this transition will begin in the next few weeks and will carry on through the rest of 2019.
By the end of this year, we will have 3 of these cryo facilities in service with all three of them expected to be operating at full capacity sometime in 2020. Before moving to Q and A, I would like to address our thoughts on returning cash to investors. Coming into 2019, we committed to returning at least 50% of excess free cash to investors before increasing capital activity. With the stronger than planned year to date oil prices and the coming proceeds from asset sales, we will soon be in a position to begin that process. We will accomplish this through debt reduction, share repurchases or most likely a combination thereof.
To the extent we choose to include some debt reduction that would likely begin with retiring $150,000,000 of debt that matures in July. All of this is of course in addition to our ongoing dividends. Also just to be clear, we have no plans to change our capital activity set. In conclusion, we have begun the year well, building on the momentum from 2018. We continue to execute on our strategy of delivering returns focused short cycle growth in the Permian Basin, sustaining our international businesses for long term free cash flow generation and building growth opportunities for the long term through exploration.
2019 will be a promising step forward. Alpine High is on the doorstep of generating significant cash flow with the startup of cryoprocessing and transported gas to the Gulf Coast. And we will commence exploration activities on Block 58 in Suriname this summer. While we are prepared to proceed on a sole risk basis, we are actively considering proposals from numerous would be partners. And with that, I will turn the call over to the operator for Q and A.
And your first question comes from Bob Brackett of Bernstein Research.
Hey, good morning. I had a question on Block 58 in Suriname. Looks like the lease expires the initial exploration term June 24 next year. Can you talk about the renewal process or the extension process on that lease?
Bob, at this point, we've worked with the government of Suriname. We've got a one rig or one well commitment kicks us into the next phase. So and obviously, we will commence that well ahead of that time schedule. So it will kick us into the next phase. And that's all we've shared publicly at this time.
And the next phase is a 2 to 3 year extension and is there any relinquishment involved?
It kicks us well into Phase 2. And at this point, we have not given any more color on Phase
Okay. Appreciate it.
Thank you.
And your next question comes from John Freeman of Raymond James.
Following up on Suriname, given the unsolicited sort of interest you've had from potential partners, and while you talked about you'd be willing to proceed on an individual basis. Does this in any way sort of possibly delay when you spud the well while you kind of review all these proposals before you spud it?
Not at all. I mean, we're on a path. We're prepared to we'll be prepared to drill multiple wells. And as we've said, we've got a one well commitment with the rig and 3 optional wells and we're prepared to head down the path we're on. So we're not at all.
Okay. And then just on the follow-up for me on Slide 11 on Alpine High and the cost improvements that you all broke out when you look at sort of pad development versus the other wells. Can you remind me what percentage of the activity right now is on pads versus the rest of the wells?
I mean the bulk of it is shifting to pads. What you've got in there is just the quarter numbers. It was kind of 194 versus what it would have been in terms of the pads, a 153 type number. So we're shifting into pads, but it's some of the testing and some of the other wells would drive that. But you're seeing us move predominantly into pad development with some larger pads coming.
Great. Thanks guys. Appreciate it.
Thank you.
And your next question comes from Doug Leggate of Bank of America.
Thanks. Good morning everyone. Thanks for taking my question. John, I wonder if I could probe just a little bit on Suriname. Our understanding is that when the well was drilled in the adjacent block, there was a down or an up dip oil lobe that was tagged by that well, which obviously bodes very well for your block.
So my question is, have you chosen the location of the well and given that assuming that's correct, why wouldn't you drill the location right up against the Guyana border?
Well, I mean, the first thing is we know we've got an active hydrocarbon system, Doug. We've got 7 plays when you look at our block. I mean, it's just an unbelievable block. And as we've said, more than 50 very large prospects. So we obviously have chosen our first well location.
We have not disclosed that. But clearly, we've taken into account any information we have through public means that's out there.
Would it be reasonable to assume that that would be a how could I put it, one of the top 2 or 3 targets on the block to basically try and make sure you risk your side of it?
I wouldn't want to assume anything about the top three targets on the block, but clearly you've got a discovery that is on the lease line and that sure bodes well for us. But I hate assuming anything.
I understand. My follow-up is also about Cunanan, if you don't mind, and it really goes to your point about 100%. These wells in the adjacent block are quite inexpensive, relatively speaking, dollars 50,000,000 to $100,000,000 Given the potential impact on farm down value in the block, why wouldn't you drill it 100%?
Well, I mean, as of today, we still own the block 100% and that's the path we're marching down. So, I mean, the reason we wouldn't is because somebody talked us out of doing that.
Fair point. Forgive me. I was going to try one final one. I understand you've been on the road talking a little bit about this on the prospect backlog. Can you just share with everybody what you see as your risk prospect backlog in the block?
And then I will leave it there. Thank you so much.
I mean, I just think it's a phenomenal block. Our timing and when we picked it up, we were just fortunate that we picked this up the middle of 2015 when there was not a lot of activity, a lot of interest. We were able to do it before Exxon drilled Liza and before we drilled our first well. And it was a really, really low price in terms of the commitment at the time. And it is very well positioned as we've said.
There's multiple plays. We've got both shallow and deepwater targets that we can get to. And I mean, when you look at the size of this 1,440,000 acres, I mean, that's larger than Ridge County, just for a perspective. And there's more than 7 different plays and 50 plus very large prospects. So we're anxious to kind of get going.
We'd love to. I appreciate the answers. Thank you. Thank you.
And your next question comes from Gail Nicholson of Stephens.
Good morning, everybody. Can you talk about where the decline rate is at the 40 field now in North Sea with the waterflood management you're doing and how that has changed maybe any near term P and A you would have at 40s?
Gale, I mean, I think what you've seen is we've changed philosophically how we're approaching that. And we really are managing the water flood. I do not have the particulars off the cuff, but we are seeing long term trends that are flattening that decline. If you look at the abandonment timeframe, even prior, it's been in the 2,032 to 2,035 time frame. I think this pushes that back.
And most importantly, it just provides stability to the rates out there. So but I don't have those, they were not quantified what's been done. I would say you can look at some of the work that WoodMac, I think, has recently updated some of their work that's starting to reflect some of that, but I don't even think their report captures all of what we see.
Okay, great. And then just looking at the improvement you guys seen in the Alpine high well cost, you've only done a slightly longer laterals. Can you just talk about how you envision lateral progression over the next, I guess, several years and what you think that could further redo from a cost improvement standpoint on the drilling aspect?
Well, I mean, the big thing we've got down there is you don't have a lot of shallow production you're having to deal with. We also don't have a lot of chert and hard rock like you have up in the Oklahoma area. So you can get down quickly. We've been able to eliminate some casing strings. Clearly, the land position will dictate some of lateral lengths.
The other big factor we've got in the source interval is you do not have water. And so with your longer laterals, you're going to get north because that's where our been shorter in the north because that's where our land retention has been. And so that's what you're seeing. But clearly, as we get the opportunity to drill longer laterals, you'll see us transitioning there. I think you're going to continue to see costs come down.
If you look at our numbers, we've had great progress and we continue to see progress as those programs have continued this quarter. So, a lot of really good things happening on the at Alpine High.
And your next question comes from Mike Scialla of Stifel.
Yes, good morning. Steve, walked us through some pretty good detail on the uplift you was there any discussion with Altus to maybe potentially delay ramping up that first cryo plant until the GCX line goes into service in October. Can you just talk about that? And if not, how does that ramp at the first cryo plant look in terms of the timing?
Yes. So the back part of your question first. The cryo number 1 is it is being commissioned now and it should be full by the end of May. In terms of well, cryo number 2 will be it's actually moved up in the schedule, it will be commissioning in June. It will be full by the end of July.
In terms of considering the possibility of moving those back in the schedule, no, we did not consider that at all. We want to get those things up and running. We want to get the rich gas flowing again and we want to get those things working to the full extent possible of extracting that NGL content out of that rich gas stream. We've got enough gas today to fill cryo number 1 and we will have enough gas by the end of July to fill cryo number 2. So those will be fully functional and full of rich gas on the day they're ready to go full.
The primary reason why we didn't, as you can look at that slide in the pack that we gave out, you can see that gas is certainly an important part of the full operating cash margin from the rich gas at Alpine High, but it's not the dominant piece. There's some oil content in those rich gas wells and there's the NGL yields. And there's even if gas is selling at 0, you can see that that's still above a breakeven cash flow situation once we get those things full. So we want to get them operational, we're going to get them up and running and GCX is not far away. It's official startup date is October 1 and that's not too long away.
Thanks for that. And then maybe a follow-up. You just talk about your outlook for NGL prices over the next couple of years? Obviously, a key component as you said to the economics at Alpine High?
Yes. Hi, this is Dave Purcell. If you look at Y Grade today and you look at Slide 12, we're running about current spot prices in the strip. It's about $24 a barrel. That's really suppressed mainly by the light ends, particularly ethane.
If you look at the ethane fundamentals going through the end of this year and into 2020, 2 things are going to happen. There's going to be more cracker capacity added on the Gulf Coast. There'll also be more dock capacity for exports added. So as you look through the next 18 months, we think there's much more upside than downside to the current ethane price. We think that'll start to move the overall Y grade higher.
Thank you. Thanks, Mike. And
your next question comes from Charles Meade of Johnson Rice.
Good morning John, you and your whole team there.
Good morning Charles.
If I could ask 2 questions on Alpine High. One, just a quick one real quick, just clarifying. So when you have this cryo startup in July, you may still have some issues with the natural gas pricing, but your NGL pricing at that point, you're connected at a tailpipe to get Gulf Coast pricing at that point for your NGL?
Yes. It will start moving to Mont Belvieu through our enterprise agreement. So we'll start seeing immediate uplift.
Got it. And then the second question, this gets more on the well spacing and those kind of intriguing results you guys put out with the Mont Blanc and the Blackfoot pad. Are there I recognize this early, but are there does this suggest that there's going to be any changes to the type curve for individual well type curve in the number of locations that you guys have in the Woodford? Or is this perhaps instead just something that's going to be localized to these areas?
No, I mean, I think it shows you the process and the methodical process we've taken to kind of break the rock down and get to what we think is the optimal development scenarios. In both cases, we drilled some Woodford Cs because we needed to see as thick as the column is as much rock as we have to deal with, we needed to see how the As, Bs and Cs performed together. We clearly went a little wider spacing, a little larger fracs at the Mont Blanc and you're seeing some pretty impressive results. So some of that's also about changing. So as we've said in the future, you're probably going to see us drop the As a little deeper, drop the Bs a little deeper, eliminate the Cs and a little wider spacing and then we'll continue to learn on the fracs.
But I think the big thing is the last location count we put out was fall of 2017, I think October 2017. And we're still in a position where location count would go up given the assumptions we've got in place. And that's why we've been very careful to do our testing and understand it. We never assume more than 2 in the Woodford and 1 in the Barnett. And we're very confident in those numbers and you're seeing strong performance.
That's helpful context. Thank you, John. You bet, Charles.
And your next question is from Brian Singer of Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
Wanted to touch base on a couple of items. The first on exploration outside of Suriname, can you just give us an update on how that's progressing and any expectations for making any of the ideas you're pursuing open to the public market? And then also a follow-up on the comments you made on asset sales, to what degree are you pursuing and how meaningful could further asset sales be?
Well, I mean, I think from the get go, we've always said we were going to differentiate ourselves through exploration and we do have a lower forty eight program that's focused U. S, it's focused more oil, it's focused more unconventionally. And our strategy has always been to try to build positions of scale and size where there was an opportunity and low cost, where there was an opportunity to try to create meaningful value for our shareholders. So we have a program there At the appropriate time, we'll talk more about that. As far as your second question on the asset sales, clearly, we have over $300,000,000 now that's under contract.
As we said, the bulk of that is our SCOOPSTACK position. And I think the point there, Brian, is as we look at our portfolio and we look at the things that we will be funding to the extent there's things that we will not fund in the future. And if there's an opportunity for somebody else to own those and create value by purchasing those, then we're not afraid to do that. And that's where we find ourselves today with the success we've had through our organic exploration program. We continue to take a long term view through our portfolio model at our areas and what's going to attract capital.
And we did not see the SCOOPSTACK as an area where we would be putting capital and therefore we have it under contract.
Great, thanks. And if I
could ask one more, on Slide 8, you highlighted the trajectory in the Permian relative to the timing of completions. And as you show in both 2018 2019, you've had a couple of quarters of frac holidays. Is that kind of the way you're planning going forward to achieve desired growth there to basically try to batch completions into 2 quarters of the year or is
that just the way it's ended up?
No, it's just really coincidental with the way the programs are lined up. When you go to larger pads, it becomes a little more lumpy. I think the key here for us is early in 2018, we had to put a crew on a frac holiday because we had the drilling efficiencies had picked up. And in terms of the on the well, I'll say the completion efficiencies have picked up and the drilling rates hadn't picked hadn't caught up yet. And so we had to set a frac crew down and what you saw is the timing of that.
The one going into this year was really as prices drop to November. We anticipated that we needed to drop a couple of rigs. We put a frac crew on holiday. It's really so we could deliver the capital budget that we have set for this year. So I think those are actions we've taken to level load the activity set to where we need to be for this price environment.
And so we dropped a couple of rigs and put a crew on holiday. The trade off there is, is your 2nd quarter production will dip a little bit, but we think in the grand scheme of things, I would rather have more of a level loaded program throughout the year, which is how we positioned ourselves.
Just adding to that a little bit, Brian, John commented on the lumpiness of the activity set. That just becomes a lot more visible when your capital program is reduced to the size of what where we are today. The lumpiness of an efficient drilling and completion pad level activity set just becomes a bit more visible. That's all.
Great. Thank you.
And your next question comes from Scott Hanold of RBC Capital Markets.
Thanks. My first question, hopefully pretty quick, on the NGLs once the cryos are on, could you remind us like what the product breakdown of that NGL basket is going to be for you guys?
Yes. I don't think the NGL yield in Alpine High is going to be any different than the NGL yield anywhere else. We haven't operated these types of cryo units before. So that would probably be a good question for 2nd or third quarter results when we've actually operated a couple of them for a bit.
Okay. Understand. Thank you. And is that sort of the so just certain average barrels which you're basing that $24 a barrel assumption right now that you put out there?
Well, we just stuck an assumption out there on the pricing at $24 We just said 40% of WTI. That's about where it's trading today. That's a reasonable assumption. We think that's conservative for the long term for the multiple reasons that Dave Purcell laid out earlier. And just on a mixed NGL barrel basis, 40% of WTI is probably, especially if you look back in time, it moves around a lot obviously, but 40% is probably a conservative assumption.
Okay, fair enough. And my follow-up question is regarding the free cash flow you all talked about once these cryos start coming on online or at least the cash flow generation and also the asset sale proceeds and utilizing that. When you step back and look at, I mean, Apache stock is compared to say the last, call it 5 years, it's at a pretty low point. Does it make sense like as you look to return cash to shareholders to be a little bit more focused on share buybacks right now? Or and how does that's potential Suriname well sort of play into that decision?
Well, I don't think the Suriname well plays into that decision for 2019. Let's get the transactions closed, which will happen in the Q2. We'll proceed slowly, but we said we would return the excess free cash, at least 50% of that to shareholders before we changed our activity level. I think we said it a couple of times in the prepared remarks, we'll say it again. There's no change in activity level for 2019.
We're still on the $2,400,000,000 capital program. And I just remind everybody that the start up of the cryo facilities and the cash flows from those were in the plan for this year. So those aren't necessarily delivering excess free cash flow. They're delivering the planned free cash flow extent that NGL prices improve, to the extent that they give us a greater yield, than we may have planned and those types of things deliver excess free cash flow, but not just the startup from them. And we will look at, I think as we get to the second half of the year, which is going to be upon us pretty quickly, That's when we'll get into the discussions about how do we use that excess cash flow.
And I can assure you that both debt reduction and share buybacks will be on that agenda and in that conversation. We're likely to do some of both. There's some debt maturing, dollars 150,000,000 of debt maturing in July. If we choose to pay down any debt, then that would probably be where we would start.
Understood. Thank you.
And our next question is from John Aschenbeck from Seaport Global.
Good morning, everyone, and thank you for taking my questions.
You bet, John.
So there's been a lot of commentary around 2019 spending. So I apologize if I missed this, but just thinking about the remainder of the year, if I run an admittedly over simplified exercise and take your Q1 spend and your Q2 guidance, it would just indicate that spending is coming down in future quarters. So is that an accurate assessment? And then secondly, just how should we think about the cadence of spending in the second half of the year? Thanks.
Well, I mean, I think the first thing is, we're down 27% over the 4th quarter and we actually came in right at 25% of what we guided for the year. So Q1 was pretty evenly run for how the year would pan out. We walked through in the prepared remarks some things that could cause 2nd quarter to be a little higher, which is kind of why we guided there, but they're more exploration driven. So I think from our perspective, we took the bigger decision in November December to drop some rigs and put a crew on holiday to kind of do that now. And it puts us in a nice position for the back half of the year.
So we're very confident in the capital number. We will come in under or at the $2,400,000,000 for this activity set and feel really good about it.
Okay, great. That's helpful, John. So just to make sure I clarify there, Q2 has some one time spending, a lot of it exploration activity that you just wouldn't expect to repeat in future quarters. Is that fair?
I would just say that in terms of the timing of how we what we have budgeted for Suriname and exploration, a big chunk of that is in Q2. And the other thing you need to look at is if you look at our Q1 numbers, we do have some asset sales. We've had a couple of rigs running up there too. So our run rate for Q1 would have even been a little lower on what our going our existing asset base remaining will be.
Okay, great. I'll go ahead and leave it there.
Thanks for the time.
And your next question comes from Richard Tullis of Capital One Securities.
Thanks. Good morning, John. Good morning. Going back to the M and A, I know you touched on this a bit a little earlier. But as you look at the North Sea, I know the market there seems a little more active.
How do you view those assets in your portfolio today, given the healthy margins there, but balancing that with maybe a more healthy M and A market in the North Sea?
Well, I
mean, I think the big difference with us is, as opposed to what's being divested by some of the other parties is we invested in the infrastructure. If you look at our efficiency and our uptimes and our run rates and our LOE, we're very competitive. I mean, we typically lead in production efficiencies and low cost. And it's because we were fortunate that after we bought these properties in the 2,003 with BP for 40s and then 2011 with barrels, we invested heavily in rebuilding the infrastructure, which really puts us in a nice position. So you look at those 2 assets, they're fantastic assets.
They're different. 40s, we've just got a massive of 5,000,000,000 barrel in place. Field is produced over 2.5 and it just continues to give. And so it's real easy to manage that for the long term with the water flood work we're doing. And we love the Brent pricing, we love the margins and it's not like we have a lot of stuff looming that would require you to want to move out of it.
You look at barrels, a totally different asset, very prolific in its own right as you've seen the way we've been able to leverage the infrastructure with the subsea tiebacks by bringing on Callater and bringing on Beryl or Garten and now into the Beryl facility and now you look at the store well we just announced, I mean, we found a whole another section there in the cormorant that we were not expecting. So there's a lot to do up in the barrel area and we've got nice Your gas receives a higher price. So it's an asset that we quite frankly, I like the cash flow profile from.
Good insight, John. Appreciate that. And just lastly, what's the current outlook for Alpine High Natural Gas to be sold into the Mexican market, say, over the next year or 2?
Well, I mean, I think the first thing is, if you look at how we're positioned physically for gas to flow, we couldn't be better. But I think we recognize from the get go that you don't want to be trying to develop a resource play and waiting on Mexico or dependent on Mexico for your gas deliveries. And so that's why we work the options of the Gulf Coast. And what you'll find is, is Mexico will be an option for on down the road, which I think can become a premium. But today, it's not something we're counting on.
I mean, that's why we work the Gulf Coast options. We will be mainly insulated from Waha here pretty quick, which is going to put us in a differential advantage on our gas. And really, it's the NGLs that really make this thing fly. The NGLs, cost structure and the lack of water are the things that really differentiate the rich gas play at Alpine High.
Yes. Richard, if I could just add to that. I don't know the exact numbers, but today Mexico takes about 4 Bcf a day from the U. S. Via pipeline and 3 to 3.5 of that comes along the Gulf Coast.
And so while we've got these great pipelines running by Alpine High, those are for the future more than the current. And so I think your question was related to the near term. The near term is we get gas to the Gulf Coast with the startup of GCX this year and Permian Highway next year, you can easily access the Mexican market and you might imagine that we probably have been considering that or working on that.
Okay. Thank you.
And your next question comes from Jeffrey Lambujon of Tudor, Pick.
Good morning. Thanks. First question is just on gas coverage with Gulf Coast Express. Once that system comes online and thinking about your capacity there, can you speak to how long you're able to receive Gulf Coast pricing for 100% of your Alpine
high volumes? Sorry, Jeff. Can you just repeat that question?
Yes. So just once GCX comes online, just trying to get a sense for how long you expect to receive Gulf Coast pricing for your Alpine High production?
How long before we receive it or how long will we receive it?
How long will you receive coverage for 100% of your
production? Well, with Gulf Coast Express, we'll pretty much be selling all of the residue gas at Gulf Coast pricing with the startup of GCX and then Permian Highway comes a year later. So Gulf Coast Express, we have $550,000,000 a day of capacity. And then with Permian Highway, we have another $500,000,000
dollars Got it. And then just a follow-up on the liquids front. Appreciate the color on ethane, Dave, and sorry if I missed any follow on comments on the LPG outlook. But could you just speak to what you're seeing there over the near term?
Yes. So Jeff, are you talking about define near term for me?
Next 12 to 18 months.
Yes. So again, if you think about the NGL barrel, the bottom end of the barrel is going to trade with crude and gasoline and gasoline has been much improved over the last 3 or 4 months. So we're really thinking about butane and pentane, that's a call on crude and gasoline. So I'll leave that to you. Propane and ethane, we're going to see improvements in the Q4 in dock capacity through this and really through the summer.
And we think that will help relieve some of the congestion with better exports. And then on ethane, in addition to better export capacity, we're seeing later this year and into 2020 more cracker capacity coming online and significant percentages of total of current capacity. So at least in the next 18 months, I can envision a much more robust NGL pricing environment, particularly given improvements in ethane and propane.
Thank you. Yes.
And your next question comes from Arun Jayaram of JPMorgan.
Hey, good morning. Just a couple of quick questions. One, have you guys quantified the production impact from the planned SCOOP STACK asset sales, just wanted to know and is that already included in the guidance?
Really, it's not included once it closes. But if we look at the 1st quarter numbers, it would have been about 10,000 BOEs a day and about 13% oil, mainly it's mainly gas.
Mainly gas. Okay, that's helpful. And just a question But
more importantly, Arun, our lease level income was about $14,000,000 We spent half of that just in CapEx. So I mean it's
It's not a big free cash
flow again. Not a big impact on the EBITDA.
Fair enough. Fair enough. And just a question for the participation on the equity on the pipes, do you guys have an estimate of what the cost would be to Altus to participate in the pipes, Just the CapEx?
I think at 1 o'clock when the Altus call is on Arun, you got to pop on and you can get Mr. Bruches at that time and he'll fill that one, so.
Okay. All right. Fair enough. Thanks a lot,
John. Appreciate it.
And we have passed the top of the hour. I will now turn the call back to John Christmann for closing remarks.
Well, thank you for joining us. I just want to end with a couple of points. We're executing extremely well, delivering on both capital and production and are reiterating our $2,400,000,000 capital budget for the year. Alpine High will hit an inflection point in the very near future as the 3 Altus cryos come online and will generate a substantial cash flow uplift. And lastly, we are looking forward to the initiation of our exploration program at Suriname very soon.
And thank you all for joining today's Apache Corporation First Quarter 2019 Earnings Conference Call. You may now disconnect.