Good morning. My name is Lisa, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2018 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 Thank you.
Gary Clark, Investor Relations, you may begin your conference.
Good morning, and thank you for joining us on Apache Corporation's Q3 2018 financial and operational results conference call. We will begin the call today with an overview by Apache's 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 Q3 financial performance. Also available on the call to answer questions are Apache's Senior Vice Presidents, Brian Fried, Midstream and Marketing 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 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 data on our website. And with that, I will turn the call over to John.
Good morning and thank you for joining us. On the call today, I will discuss Apache's strategic positioning, provide a preview of 2019, comment on our strong Q3 performance and review our key focus areas. Apache is a very different and much improved company from 4 years ago when oil prices began their prolonged downturn in the fall of 2014. We acknowledge very early on that the industry, including Apache needed to make significant changes, not only in terms of reducing activity levels and overall cost structure, but equally to reestablish long term returns discipline in the capital program. At that time, we chose to significantly curtail our drilling program, allowing production to decline rather than pursue growth in an environment where commodity prices and costs were not properly aligned.
We refrained from participating in high cost acreage acquisitions in the heart of proven plays, choosing instead to build our unconventional exploration capabilities. An important outcome of this strategy was the discovery of Alpine High. We have frequently stated our philosophy that an E and P company should be capable of living within cash flow from operations, generating sustainable long term reserve and production growth, while also returning capital to shareholders. After significant upfront investment at Alpine High and the pending completion of our Altus Midstream transaction, Apache has turned the corner and is well positioned to deliver on this philosophy for many years to come. We continue to generate steady production growth on a flat activity set and are poised to deliver positive free cash flow in 2019.
This can be sustained over the long term through development of our extensive inventory. We'll be supplemented by organic exploration, including discoveries in hand today and a refreshed portfolio of new opportunities. Lower F and D costs, increasing returns and continual portfolio high grading will accompany our growth and drive sustainable shareholder value growth through time. This is the investment proposition Apache offers and it is one that we strongly believe in as evidenced by our decision to begin repurchasing shares in September under an existing authorization. Recently, our Board of Directors approved a new authorization for the repurchase of 40,000,000 shares, which represents more than 10% of shares outstanding.
Now, I would like to provide a preview of 2019. For more than a year, Apache has operated at a relatively constant upstream activity level, which has enabled us to deliver operational efficiencies, effectively control costs and generate sustainable liquids production growth. We anticipate maintaining a similar activity level next year, but on a lower capital budget. If changes in expected cash flow dictate, we have the flexibility to reduce our activity levels accordingly. In 2019, assuming commodity prices in line with the current strip, Apache expects upstream capital investment of approximately $3,000,000,000 which is consistent with our current guidance and is lower than 2018.
Adjusted production at the high end of our 410,000 to 440,000 BOEs per day guidance range, representing more than 15% growth in the U. S. And 10% growth overall, positive free cash flow and continued return of capital to shareholders. This is well aligned with the philosophy I outlined at the beginning of the call and we look forward to providing a more detailed 2019 outlook in February. Our performance to date in 2018 underpins our confidence in this outlook as we have demonstrated excellent growth and exceeded our guidance for 3 consecutive quarters.
In the Q3, we delivered very strong earnings and cash flow driven by our significant Brent and LLS oil price leverage, robust NGL realizations and solid production results. We have seen our positive production trends continue into the Q4 and are again raising our full year 2018 U. S. Guidance. Notably, we expect a meaningful increase in 4th quarter oil volumes.
Internationally, we delivered robust cash flow in the 3rd quarter on production that was in line with guidance. In Egypt, our drilling program continued to achieve a high success rate and gross production remains relatively steady. While net adjusted production was reduced by the impact of higher oil prices on our production sharing contracts, cash flow trended higher in the 3rd quarter on strong Brent oil prices. In the North Sea, production was impacted by routine seasonal maintenance, but was also in line with expectations. We anticipate significant growth in the Q4 with positive momentum continuing into 2019.
Turning now to midstream, we achieved an important milestone during the Q3 with the announcement of Altus Midstream Company. Altus accomplishes the primary objectives that we have previously articulated to the market. It enables Apache to maintain control of the midstream infrastructure build out and establishes an entity capable of funding all future midstream investment at a lower cost of capital. Since the announcement, we have spoken with many of our largest institutional shareholders. The feedback has been overwhelmingly positive and we look forward to the closing of the transaction in November.
Now, I would like to provide a strategic overview of Apache's key operating areas. In the Midland and Delaware Basins, the strategic testing we have conducted over the past 3 years is paying dividends as we shift a much greater percentage of our capital to full Pattern Development. This is generating significant improvements in cost and productivity and today we believe that we are drilling some of the best wells in both basins. In the Midland Basin, development drilling continues in the Powell, Wildfire and Azalea areas with excellent results. We recently expanded our activity outside of these areas as we focus on increasing Apache's inventory of high graded opportunities.
In the Delaware Basin, we are delineating acreage in the New Mexico Slope play and adding landing zones in our Dixie Land and Pecos Bend areas in Texas. Our drilling inventory in these areas continues to increase and will support a multi rig program for the foreseeable future. Moving on to Alpine High. While testing and delineation activity will continue for some time given the magnitude of the total resource, we are transitioning now to a multi well pad development designed to optimize spacing, pattern and completions configurations. We have previously discussed the framework for monitoring our progress at Alpine High in the context of well costs, well productivity and inventory.
On well costs, we have achieved an approximate 25% reduction in drilling, completion and equipment costs per lateral foot year over year through the 1st 3 quarters of 2019, which is in line with our goal. In terms of well productivity, we are beginning to extend our laterals where applicable and we're seeing a high correlation between productivity and lateral length in our Woodford and Barnett wells. We are also beginning to modify our completions design, including higher proppant loads, which is delivering a step change in well productivity. Turning to our delineation program in the Shower Wolf Camp and Bone Spring Para sequence formations, we recently began flow back on a 10 well pad, which incorporates larger frac geometries and is designed to test the productivity of patterns and spatial relationship. The pad is developing roughly a half section and contains 4 wells in the Wolfcamp A, 4 wells in the Wolfcamp B and 2 wells in the Bone Spring formation.
Aggregate production from the 8 Wolfcamp wells is currently around 3,300 barrels of oil per day. We are very encouraged by the performance of these wells, which are still cleaning up and have not reached peak IP rates. We are in the early stages of bringing the 2 Bone Spring wells online and will provide an update on the progress of this pad in the future. Tim will provide some more detail on our Alpine High program in his remarks. Turning now to the international region.
In Egypt, we have been investing at a pace that has maintained gross production at a relatively flat level. Our drilling success rate is very high and very consistent, while our inventory of opportunities is growing significantly through the addition of new acreage concessions and high density three d imaging. Egypt delivers some of the best returns in the portfolio and we are confident this region can return to growth and free cash flow for many years to come. Our current drilling program in the North Sea consists of 2 platform rigs and 1 semi submersible, which we believe is an appropriate pace to deliver our strategic objective of sustaining production and free cash flow generation. Capital efficiency has improved significantly in the North Sea and we anticipate delivering higher production in the Q4 and in 2019 with a flat capital profile.
Production growth will be driven by the tie in of 3 significant wells in the Barreld area, a development well at Calliver, a discovery well at Stohr and our discovery well at Garten, which we have now accelerated into 2018. Longer term, the Garten discovery has lowered the risk profile of several analogous exploration prospects, some of which we will likely test in 2019. Moving on to exploration. In Suriname, we continue to progress our technical evaluation and are working a multitude of prospects. We will initiate a drilling program next year on Block 58, where Apache currently owns 100%.
This block is untested and adjacent to the ExxonMobil operated Stabroek Block in neighboring Guyana. In the U. S, we have a strategy of expanding our portfolio through organic growth opportunities at a low entry cost. Onshore unconventional exploration teams are acquiring acreage in multiple perspective areas focusing on oil. Our 3rd and 4th quarter capital reflects some incremental activity in this regard.
Before turning it over to Tim, I'd like to address reports that Apache is actively marketing certain assets in our U. S. Portfolio. We regularly review the strategic value of holding assets in our portfolio. If another party is willing to fund assets that are not attracting capital from Apache, that an opportunity exists to increase value for our shareholders through a sale.
Our approach has always been to notify the market upon execution of a sale agreement for any material asset disposition and refrain from commenting prior to that. To the extent we do complete asset sales, return of capital to shareholders is a high priority use of proceeds. With that, I will turn the call over to Tim Sullivan, who will provide some operational
and operations performance, including drilling highlights and activity in our core regions. Operationally, we had another very good quarter and saw improvement in many key areas. We achieved company wide adjusted production of approximately 401,000 barrels of oil equivalent per day, a 13% increase from the same period a year ago and up 3% from the Q2 2018. The Permian Basin continues to drive our growth. Compared with the Q3 a year ago, oil production in the basin increased 16% and total production grew 38%.
These are impressive growth rates on a large production base, which reflect the success of our ongoing development in the Midland and Delaware Basins and the continued ramp up at Alpine High. We averaged 18 rigs and 5 frac crews in the Permian Basin during the quarter. Compared with the preceding period, we held our oil production steady, up 1%. And with the completion schedule skewed toward the back half of the year, there will be a larger contribution to oil growth in the Q4 and even more so in 2019. In the Midland Basin, we placed 13 wells online in the 3rd quarter, all of which were on multi well pads.
This includes a 9 well pad in our Powell field comprising a mix of mile and a half and 2 mile laterals. In addition, we drilled a 4 wall strategic pad in our Hargrove field in Reagan County, testing 4 separate Wolfcamp landing zones with very encouraging results. In the Delaware Basin at Dixieland, we placed on production 10 high rate wells with 1 mile laterals. 8 are producing from 2 proven Upper Wolfcamp zones, while the remaining 2 successfully tested 2 additional landing zones in the Lower Wolfcamp, adding inventory across the field. Please refer to the quarterly supplement for production details.
Production at Alpine High averaged approximately 49,000 BOE per day during the quarter. We are currently producing approximately 55,000 BOE per day on a net basis. For the full year 2018, we are tracking toward 44,000 BOE per day net, down slightly from our 45,000 BOE per day guidance. This reduction results primarily from a processing upset that sent moisture down the pipeline, requiring a 2 day field shutdown to pick the lines. At Alpine High, we placed 27 wells on production during the Q3.
We will remain on track to place more than 90 wells on production this year. John mentioned the results we've seen thus far on our 10 well Cypress pad, so I will note a few other results here. Recent Barnett completions during the quarter include the Mohican 201, which averaged a 30 day initial production rate of 7,700,000 cubic feet of rich gas and 3 19 barrels of oil per day the Lundy 201, which averaged a 30 day IP rate of 7,300,000 cubic feet of rich gas and 2.56 barrels of oil per day. Both wells were completed with laterals averaging 5,700 feet and standard proppant loads of £19.70 per foot. They produce extremely rich gas with an average BTU content of nearly 1300 and assuming cryo processing, we yield up to 160 barrels of NGLs per 1,000,000 cubic feet of gas.
We have many analogous Barnett wells scheduled for multi well pad development in our 2019 drilling program. I also wanted to provide an update on the 12 well Blackfoot pad, which we discussed last quarter. Recall that the Blackfoot tested 6 60 foot spacing in 3 Woodford landing zones. These wells were relatively small completions treated with only £1600 per foot of sand. The pad peaked at a 30 day IP rate of nearly 105,000,000 cubic feet of gas and 2.80 barrels of oil per day following our last quarterly call.
The majority of the gas is being recovered from the upper two Woodford landing zones. Based on our frac geometry and production results, we believe we can recover most of these reserves with fewer wells and larger fracs, which will significantly enhance pad economics. The strong performance from the Upper Woodford Landing Zones on tighter spacing has a positive impact on our location count. On the cost side, Apache is successfully navigating a challenging inflationary environment in the U. S.
Our initial 2018 budget contemplated a 10% to 15% average service cost increase. However, steel tariffs, rising fuel and chemical prices and higher labor costs, particularly trucking and construction have resulted in incremental inflation. We are managing these dynamics with improved wellbore and completion designs, longer laterals, multi well pad drilling and proactive investment in water management infrastructure. As we look into 2019, we are likely to see a continuation of higher labor, steel, fuel and chemical costs. However, as we move through the tender process, we are realizing reduced costs for rigs and pressure pumping crews.
Net net, believe these cost trends will roughly offset each other in 2019, and we plan to budget for a relatively flat or slightly down year over year service costs overall. Internationally, in Egypt, we drilled and completed 24 gross wells with an 83% success rate. Note where the results are included in our supplement. These are primarily high rate oil wells, all with Brent index pricing. Our seismic acquisition in the Western Desert continues.
To date, we have acquired close to 1,000,000 acres of a planned 2,600,000 acre seismic shoot, completing acquisition in our legacy West Kalopsha and Shushan areas. We have recently initiated seismic acquisition in our new Northwest Resac concession. Fast track processing is bringing very exciting results. We are seeing faults in geologic surfaces, especially in the deeper section that we could not image before. We have identified several new leads and prospects just from this initial data review.
Moving to the North Sea, production averaged approximately 51,000 BOE per day during the quarter as operations were impacted by maintenance turnarounds. Production has begun to rebound in the Q4 and should continue to ramp up. In late September, we brought on stream our 4th development well in our Callater field at Barrow. This well is having a positive impact both on production and reserves and is currently producing 3,500 BOE per day net to Apache. Apache owns a 55% working interest.
Also, as John noted, we have accelerated development at Garten. The barrel near field discovery announced in March with 1st oil expected later this month. By locating this test well near existing infrastructure, we have been able to reduce our cycle time, minimize development costs and bring this well into production in only 7 months for $80,000,000 which we expect will translate to a very attractive F and D cost of less than $10 per barrel. We anticipate achieving our highest average production rate for the year in the North Sea during the Q4. To sum up, operationally, we remain on track for a very good year with growing momentum heading into 2019.
We are focused on building on this success in quarters ahead. I will now turn the call over to Steve.
Thank you, Tim. As noted in the press release issued last night, under generally accepted accounting principles, Apache reported Q3 2018 net income of $81,000,000 or $0.21 per diluted common share. Results for the quarter included a number of items that are outside of core earnings, which are typically excluded by the investment community and published earnings estimates. The most significant of these is a $75,000,000 after tax loss we incurred as a result of the bond tender exercise in August. Excluding this and other smaller items, adjusted earnings for the quarter were $244,000,000 or $0.63 per share.
3rd quarter financial performance was good across the board. Production volumes were strong and we anticipate this will continue into Q4 2019. Our average realized oil price exceeded $69 per barrel in the Q3 as nearly 70% of oil production received Brent or Gulf Coast linked pricing. NGL realizations were also very strong, up 18% from 2nd quarter. Costs continue to trend well, both on a per unit basis for LOE and DD and A and on a gross basis for G and A and exploration expense.
All are tracking below previous full year guidance ranges, which we have reduced accordingly. Note that cash tax guidance has been increased for the year to reflect higher income levels internationally, primarily as a result of the strong Brent oil prices. Capital investment in the quarter was $966,000,000 which includes $122,000,000 for Alpine High and Midstream. As highlighted in our financial and operational supplement, upstream activity level for the prior 4 quarters have been remarkably consistent. Upstream capital investment has averaged between $700,000,000 $750,000,000 per quarter on a steady global rig count.
We plan to maintain a similar level of baseline activity through 2019, resulting in typical quarterly capital investment of around $750,000,000 As John indicated, this would result in a $3,000,000,000 capital program for 2019. We believe this is a prudent level of investment and remain prepared to reduce it further should industry conditions warrant. Through a combination of the timing of capital activity and some incremental lease acquisitions and extensions, 3rd quarter upstream investment was $844,000,000 4th quarter upstream investment will be approximately $800,000,000 which also includes some significant lease acquisition investments. With the combination of strong operational performance and recent price levels, financial returns have improved and will continue to do so. Our cash return on invested capital through the 1st 3 quarters of 2018 was 23% on an annualized basis.
We ended the Q3 with $593,000,000 of cash on hand. In terms of balance sheet management, in the Q3, we took certain steps to improve our debt portfolio. We issued $1,000,000,000 of new 10 year senior notes, repurchased $731,000,000 of outstanding debt and paid off $400,000,000 of maturing debt. These actions extended our debt maturity profile, reduced our average cost of debt, modernized our standard debenture terms and reduced debt by $131,000,000 This is in addition to the $150,000,000 debt reduction we affected earlier in the year. I will conclude with comments on midstream and marketing.
There continue to be many concerns about transport and now fractionation capacity to accommodate growing Permian Basin production volumes. For the upstream industry in general, these concerns are well founded and the underlying situation is likely to extend through much of 2019. The good news is that much of the midstream investment is already underway and Apache has taken the necessary steps to mitigate the short term impact of these issues. As an interim solution, we entered into swaps on Waha gas basis back in late 2017 early 2018 to lock in an average $0.51 differential on a significant quantity of gas production through much of 2019. As a part of the longer term solution, Apache's midstream business is contracted for transport on multiple pipeline projects across all three commodities.
In many cases, our contracting was critical to enabling FID on the project. As such, the midstream business was able to secure equity participation in those projects, will become an important piece of Alta's midstream company. We have talked extensively about the gas and oil transport projects. With the recent concerns around NGL transport and fractionation, let me share a few more details on our agreement with Enterprise. This agreement will accommodate NGL transport and fractionation ramping up to 205,000 barrels per day, beginning with the commissioning of the Shin Oak NGL Pipeline Waha Lateral.
The agreement has a 10 year primary term with a very attractive fixed transport and fractionation fee structure. At Apache's option, the agreement can be extended under the same terms for 2 additional 5 year periods of time. The pipeline's lateral is anticipated to be operational shortly after the completion of the 1st cryo facility at Alpine High. We are currently working with Enterprise and other parties on interim solutions in the event the cryo facility is operational before the pipeline lateral is commissioned. The enterprise agreement will access attractive Mont Belvieu pricing for our NGLs and contain certain options that enable further margin expansion possibilities.
In 2019, the value of the NGL margin uplift for Alpine High will become much more apparent. We are closing out 2018 and entering 2019 in a very strong financial position and with great momentum. Lower debt, robust cash flow and increasing returns, all goals we set at the beginning of the year. I look forward to reporting on our full year financial performance in February and further discussing our outlook for 2019. And with that, I will turn the call over to the operator for Q and A.
Thank
you. And our first question comes from the line of Gail Nicholson from Stephens. Your line is open.
Good morning, everybody. You guys had really strong Permian NGL price relations this quarter. I was curious, what percent of your Permian NGLs are ethane? And then how is that going to change post the cryo facilities coming online in Alpine next year?
Hey, Gail. So this is Steve. So I don't have at hand an exact number of the percent of NGLs that are ethane. I might see if we could get that before the end of this call. But that obviously will be impacted quite a bit as we actually bring on 3 cryo units in Alpine in 2019, the first one by the middle of the year and then 2 more before the end of the year.
We produce in aggregate, we produce about 60,000 barrels a day of NGLs in the U. S. And most of those are all basically priced based on netback Mont Belvieu type of pricing with a deduction for transportation and fractionation costs. And quick turnaround on the first part, about 42% is ethane in the Permian.
Okay, great. And then the market, we tend to be overly focused on your U. S. Onshore execution, but you had some really high quality international assets. Can you just talk about what could potentially be on the horizon in the North Sea in Egypt in 2019, specifically maybe in Egypt as maybe you return that asset more to a growth asset?
Yes, Gail, thank you. If you look at Egypt, we've got a big 3 d that's underway and we've added a lot of new concessions. And so it's a 2,600,000 acre shoot. We've shot over 1,000,000 of it. Things are progressing well.
And I can tell you the early looks on the seismic are very exciting. I mean, there's just a lot of rock to deal with out there. It's high productivity and we've got such a massive infrastructure backbone in place that it will be easy to bring things on. So we're very excited about Egypt and we're excited about getting more of the 3 d in and starting to high grade our inventory there, which really has become very robust. Historically, we had about 2 years of inventory that we could see because it just took so long to build it.
Today, we've got a much, much longer time horizon on our Egypt portfolio and it gives us the ability to we believe we're going to be able to grow the free cash flow as well as grow production over the next several years on the new acreage. So that's the first thing. If you look at the track record in the North Sea, Gartner this year was a big discovery for us. And as we said on the notes this morning, we're going to be accelerating that from early next year into the Q4. So we're excited about that.
It will be a very high rate well. It's a big structure. And there's potential in there. We'll just have to see how it performs to even add more wells. But most importantly, it also derisked several other structures that are very similar to Garten.
So we continue to have success in the barrel area with tiebacks. We've got STORE coming on as well in 2019. We brought on another well in calendar. So we've got a lot of momentum going into 2019 in the North Sea, not to mention the work we're doing at 40s as well on the water injection. We're really starting to see some stabilization of the decline rates there and flattening of that, which has big ramifications.
So the international portfolio has provided a tremendous amount of cash flow. It's Brent pricing and we get really high gas prices in the UK as well and we're excited about what that's going to continue to do for us for the foreseeable
future. Great. Thank you so much.
Thank you.
Our next question comes from the line of Charles Meade from Johnson Rice. Your line is open.
Good morning, John, to you and your whole team there.
Good morning,
Charles. Yes. I wanted to I feel like you guys talked a little bit about you talked about that parasequence test you have. And I think Tim said that was the Cypress state pad. Did I catch that right?
You did.
Okay. And so John, I recognize it's early days there, but can you give a little bit more color? I know you said the wells are still cleaning up, but I did the quick math. It looks like those 4 Wolfcamp tests are right now a little bit over 400 barrels a day of oil each. I wonder if you could talk about how much water you're seeing, where you think that what would be a good result in your view on where those wells go?
And also, I have to say, maybe you can talk a little bit about the decision to do all 8 wells at one time rather than just kind of weigh generally into that debt?
Well, I mean, first of all, Charles, we are very excited about it. It's a 10 well oil pad test. There are 4 Wolfcamp As or 4 Wolfcamp Bs and 2 Bone Springs. Really, really high productivity. It's very early.
I will tell you we are gas lifting all 8 of the Wolfcamp wells. There is extreme deliverability and productivity and they're really just starting to clean up. So they started cutting oil pretty early. There's a tremendous amount of fluid to move and we're very optimistic and encouraged by those. They were they're still short laterals, larger fracs, about £4,000 a foot.
This is really 10 wells and a little over a half section. So it's like we've talked about the name of the game is getting to pad development, understanding the spacing and the from a spatial and pattern position. And we're excited about these. They're going to continue to clean up. When we look at the IPR curves, there's a lot of room for these wells to come up and we expect them to hold in for quite a while.
So we're very encouraged. The 2 Bone Springs, we've just really started and we run sub pumps in those 2 wells. So and they're both cutting oil, but just really getting started. So it's early and it's 40 gravity oil, it's black oil and well costs were very reasonable for the size of jobs we pumped and we're very optimistic.
Got it. That sounds promising. We'll just have to stay tuned on that. And then if I could go back and touch on the you guys talked about CapEx outlook for 2019, but that's really a piece of the free cash flow outlook for 2019. And you guys also talked about the possibility of asset sales and that would be the scenario which you'd like to return more cash to share.
So as I think you guys already have a dividend, you've maintained it through the whole downturn, but can you give us a little bit of your thoughts? Are you thinking about how would you if you did have more free cash flow through an asset sale or just through sustained strength in the commodity price, how are you thinking about maintaining or increasing your dividend going with a special dividend? And then also you guys announced this $40,000,000 share repurchase authorization. Can you give us how those priorities sort out in your mind? Well, Charles, that's a lot of questions.
I'll try to summarize in a couple of points and then I'll give you a chance to come back if we didn't answer them. But first of all, as we look to 2019, we've been running a pretty flat activity set going back to the back half of twenty seventeen. So we're very comfortable with where the capital forecast is going into next year. We figure for $3,000,000,000 we can deliver a pretty flat activity set, which sets us up very nicely when you look at the corporate level and the U. S.
Growth, which of course will be driven by Permian. So we also believe that we will be in a position to generate some free cash flow and clearly a high priority with that free cash flow right now, especially with our share price is, would be to supplement our dividend policy, which we've maintained through the downturn. I mean, we're one of the few that did not cut our dividend. And so we see that buybacks is something we can do to supplement our dividend policy as we return incremental cash flow to the shareholders. So other thing I'll say about the capital program going into next year, it can easily be flexed up as we have significant inventory to do so.
But also, it will be very easy to ratchet back if things change in the environment. So we'll have more color on the call in February, but very comfortable with the rates and pace we've been running at. I think we're set up for a really strong 2019 after a really good 2018. And we do see us being able to increase the stuff back to shareholders. Yes.
And Charles, that's
the overview I was looking for. Go ahead. I'm sorry.
Yes. Sorry, Charles. I'd just add to that. We ended just in terms of what potential we might have on that. We ended the Q3 with $600,000,000 of cash with positive free cash flow planned at strip for 2019.
By the through the end of 2019 and after paying the dividend and after retaining a bit of cash on the balance sheet for operational purposes, you're probably looking at as much as $500,000,000 to $1,000,000,000 of cash available depending on price available for either debt reduction or further share buybacks. And that would exclude any proceeds from asset sales.
Thanks, Steve.
Our next question comes from the line of Brian Singer from Goldman Sachs. Your line is
open. Thank you. Good morning.
Good morning, Brian.
I wanted to touch on Alpine High well productivity. You talked to some of the success and endeavors you're taking, extending laterals and also greater proppant loads. Can you add a little bit more color on what you're seeing and more specifically whether when you talk about the improvement in productivity that is increasing EURs and recovery rates or that is just bringing forward production?
Yes, Brian, I mean, I think the thing we've determined and we now have substantial flow time on it is that the larger fracs are definitely increasing productivity. We're also seeing that on in the Woodford and the Barnett on a longer laterals are pretty much one to 1 in terms of lateral foot for the productivity. So in both cases, we're getting benefit from longer laterals as well as the bigger fracs. The last pad we brought on, the Blackfoot was the smaller fracs. We did that even though going into that, we knew the larger fracs are doing more, but we needed to see the data point in terms of the number of landing zones and the spatial placement between those.
And it's confirmed what we believe that we're probably going to be able to develop at Woodford with 2 landing zones, drop the As and Bs a little bit lower with a little larger fracs and then we've got to come back and pump the bigger fracs on those to then figure out optimal number of wellbores. But the good news is our location counts have had very conservative assumptions. We've proven that at less than £2,000 we can place the well 660 feet apart and our well count assumptions were 925 to 1,000. So well count is going to go up when we come back and quantify that, but we still got some more work to do in terms of the what's going to drive the greatest return in PV per capital dollar invested with how we develop these patterns. We've got the 12 wells in the Blackfoot.
We're going to come back right now. We're in the process of completing 10 wells in the Barnett. And at a later date, you'll see us come back with a pair of sequence. So at the Mont Blanc right now, we're in the process of flowing back or starting to flow back some Woodford and Barnett tests, which have a little larger fracs. So there's a lot of data that's coming that and it's been designed to help us yield what's going to be critical at the development scenario.
So a lot of good work and a lot of progress. And at some point, we'll come back and unfold a lot of that for you. Great.
Thank you for that. And then my follow-up is with regards to use of capital, Permian and M and A. Can you just kind of talk to what degree M and A opportunities are competitive or not competitive relative to share repurchase for use of free cash and where the Permian outside Alpine High plays into that if at all?
Well, I mean, I think if you look at us today, first of all, as I said on the in the closing part of my comments, if there's an asset that we're not funding and there's an opportunity for somebody else to put capital in that asset, then there may be an arbitrage and the ability to create some value for our shareholders. So we're constantly looking at the portfolio and you've seen that historically with us. We exited Canada last year. So it's something we're constantly looking at. Clearly, right now, if you look at our portfolio, we're very excited about where we are in the Midland Basin.
We've been predominantly working 3 areas. And as Tim mentioned, we branched out past those 3 areas in the Permian. But if you look at those three areas, it's less than 20% of what we'd call our core Midland Basin acreage. And we've really developed less than 20% of the locations we see in those. So there's tremendous amount of running room in our Wolfcamp and Spraberry locations in our Midland Basin.
And then if you look at our portfolio from an exploration standpoint, we believe today you're better served the best impact is going to be through organic well designed exploration and Alpine High was a result of that. We've put together a tremendous portfolio over the last few years. On the conventional side, we've got a block down in Suriname that we're very, very excited about. And we've also got some new plays that we've been working on the unconventional side. As you know, it's a depleting business and you have to continue to find areas.
And we think organically through the exploration, if you can do it with low cost, high impact areas, we think that's the best way to create value. And it's also why we also like our share price right now.
Thank you very much.
Our next question comes from the line of John Herrlin from Societe Generale. Your line is
open. Yes, thanks. Just one quick one for me.
Are you going to
be buying puts for next year's oil production?
Yes, John, I mean historically we've put things in place to protect our programs. And I think fundamentally, we like to stay away from hedging unless we feel like we need to do something. And at times when we felt like we had a capital program like the Midstream and Alpine High, we've done things to protect that cash flow or through acquisitions as ways to fund those. So I think as we go into 2019, we're in a position today where with the capital program we can ratchet that up or down if necessary. So it's just something we'll have to kind of look at.
Okay. No, that's fine. I didn't figure you'd be putting any on, but
I was just asking. And then Altus closes this month, end
of month, mid month or? Yes, Brian. Yes, this is Brian. The proxies were mailed out on October 22 and we've got the shareholder meeting scheduled for November 6 with the close and funding scheduled for November 9. And at that point in time, the ticker symbol will change to Altium and the name will change at closing to Altus Midstream from Kayne Anderson Acquisition Company.
Great. Thank you.
Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your line is open.
Thank you. Good morning, everybody. John, I wonder if you could help me with it's really a bit of a production visibility question for next year. And it's really about the how we should think about the fractionation startups and how that how we could see your liquids yield evolve from the wet gas you've got currently? Because obviously, that's going to be a pretty significant catalyst I think for your step change in cash flow as we go over the next year
or so. Yes. I mean I think Doug that clearly 2019 will be an inflection point year for the NGLs at Alpine High. If you look at 2018 to 2020, we showed a transition where NGLs would grow from 10% in 2018 to 30% in 2020. We've got 1 cryo coming on in the second half or in the back end of the second or first half of the year.
Then we've got 2 coming on in the second half. So it'll all happen kind of start happening 2nd Q3 of next year. Yes.
And Doug, I'd just add to that. Our contract with Enterprise provides for a ramp up of volumes to 205,000 barrels a day. And that's a fixed contract. They've got to take it. It's a fixed fee structure for transportation and fractionation.
And as I said in my prepared remarks, we actually have some options to even further enhance margins beyond just a Mont Belvieu mixed NGL barrel pricing netted back to Alpine High.
Steve, just to be clear, when would you expect to fill that capacity? I know it's a bit of a stretch question, but can you provide any visibility as when you would expect that to volume to be achieved?
No, not at this time, Doug. I think what I'd recommend is let's just wait until the next plan rollout in February and we could probably have a better view of that kind of stuff. But obviously, I'll just state the obvious and that is as we're bringing on 3 cryo facilities in 2019, 2 more in 2020. That won't be the end of it. But obviously, as we bring on cryo facilities, the goal would be to have a drilling schedule that fills those as quickly as possible.
Thank you. My follow-up, John, I don't know how you want to deal with this one, it's on Egypt. It's about, I guess, 7 or 8 years now since everything kind of went it goes up in the country and things have changed dramatically, as you know. I'm just curious, we haven't really had a formal update on your plans for Egypt with the new seismic program and so on, the visibility for the sustaining business or a growth plan going forward. And it strikes me that the market could probably benefit from getting a refresh on that.
I'm just wondering if you can update, do you have any intention of doing that and any high level plans that you can share as you think about the next several years?
Well, I mean, if you look back, we've been able to maintain our Egypt production level with a much lower rig count. We were running 28 rigs in Egypt in 2014 and we got down as low as 6 or 7. We've been running around 12 rigs and we've been able to really stabilize that. And that's with the COSR starting to get towards the point where it would go on decline. So we've done a really, really good job and I think our productivity and capital efficiency in Egypt has gone up significantly.
And that was really 2 discoveries, Piton and Bearnaise, which helped drive that, which we had in early 2015. If you look at the new seismic, I think as we with the new concessions and we get the new seismic back, we would be in a position, Doug, to kind of unfold some of that as well. So we've expanded a lot. Over the last 3 years, we've added a lot of acreage in Egypt. And as I mentioned earlier, we've got great infrastructure and a great track record.
And so we look at Egypt as an area that we can continue to grow the free cash flow. You can't underestimate what we've done with that and what it's been able to do for us over the last several years and grow our production. So Egypt is actually an improving position for us as well and we've got better there over the last couple of years. And I think once we get the new seismic back and then we would be in a position to unfold that a little bit.
Just one closing comment for me, John, if I may. It's just an observation more than anything else. This asset obviously throws off a lot of free cash. The market still seems to apply a dated discount to that asset. And if you could provide some visibility on the sustainability of that free cash, I think it would really pay dividends.
That's really what I was getting at. So I appreciate your answer. Thanks.
It's a great comment, Doug. Thank you.
Our next question comes from the line of Leo Mariani from Nat Alliance. Your line is open.
Hey, guys. Wanted to dig into the forward plans at Altus a little bit. Obviously, I know the folks a handful of days away. I guess you've got a potential closing coming up soon as well. But assuming everything closes as planned, how do you see sort of the progress over the next couple of quarters?
I know you guys have some significant options to purchase some equity interests and some rather large pipelines. I know you guys have talked about our other organic growth opportunities. Can you just kind of refresh everyone in terms of what you plan to do here in the short term at alt as post close?
Yes. This is Brian Fried. I'll address that a little bit. I mean, quite frankly, what we have in front of us, we've got a lot to say grace over in front of us in terms of the work we've got in front of us. We've got the cryos that John mentioned that need to come on in 2019 and the equity options that we will start exercising by the end of this year.
We've got a supplement out on the website that shows when some of those option exercise dates are, so you can dig into the details there. So I won't burden this call with all of that, but we do expect to start exercising these options by the end of the year. And then we have a lot of gathering and processing to continue to build out through the rest of this year and into 2019 as well too.
Okay. That's helpful. And I guess just jumping over to Suriname, obviously an area you guys are quite excited about here. Wanted to see if you can give us a little bit more color on sort of the capital plan there for 2019 in terms of how much money you plan to throw at it and how many potential wells you guys could drill?
Well, I mean, it's a large area. We've got about 1,400,000 acres. There are a number of prospects that are very high quality. We will drill at least one well in 2019 and there will be options to make that program much larger. So that's one of the things we're looking at, but we'll include at least one well.
Okay. That's helpful. And I guess, is that well likely to kind of come by mid year? What can you tell us on timing there?
I would probably say late second, early third quarter likely, but.
Okay. Thank you.
Our next question comes from the line of Richard Tullis from Capital One Securities. Your line is open.
Hey, thanks. Good morning, John. Just a couple of questions on the exploration side. I know that's not a topic discussed all that much in E and P land these days. But regarding the planned Suriname well next year, how are you able to use that data from the other recent unsuccessful unsuccessful wells drilled offshore Suriname by all the operators and then you had your own well there.
How useful was that data in trying to plan your 2019 well?
Well, I mean, I think if you go back and look in our Block 53, the 2 wells that we've drilled over the last, call it 3 years, we learned a lot from both of those. You look at 58, it's positioned differently. It's in a different part. It's a very large basin. It's a very large block.
So we feel like that Block 58 is ideally positioned and really the results outbound to Block 58 will not have an impact on our view of Block 58.
Okay, John. Thank you for that. And then just continuing with exploration, you talked a little bit about exploration potential in the portfolio. What areas globally look interesting to Apache at this point either as operator or non operator? And what percentage of the budget as you start to generate the excess cash flow moving forward 2019 plus, what percentage of the budget could exploration represent going forward?
Well, I mean, it's something you've got to keep in check. I mean, if you look at our on our international portfolio, we of our international capital, we spend some exploration dollars in both the North Sea and in Egypt, right? So and those are continual programs that we've had great results from. So there's a small portion there. Suriname is the one place outside where we operate today that we will be active next year.
And then on the unconventional side, it's more U. S. Focused and it's more oil focused. And those are things where we don't spend a lot of money because we're looking at things that are off the radar from other companies where we think we can add value, pick up meaningful acreage positions at low costs that could have a really high impact. And so that's how we approach the unconventional side, but you've got to keep it in check.
We've got to have the lion's share of your capital going into your development programs that are driving your returns and your volume growth and the cash flow.
That's it for me. Thanks a bunch, John.
Our next question comes from the line of Michael Hall from Heikkinen Energy Advisors. Your line is open.
Thanks. Good morning. Maybe following up a little bit on the last couple on Suriname and exploration. How are you thinking about ownership on Block 58? You currently have 100% on it.
Is that something you likely want to sell down? And is that probably something you do before? Or would you wait for the results after the first test on that block?
Michael, it's something we own 100% today. There is quite a bit of interest in the block. And so that's just something we'd have to see in the future.
Okay. But it sounds like you're up for taking the full interest on the first well?
I mean, we're definitely prepared. We like the risk to upside profile. Wells are not real expensive. You're probably $55,000,000 to $60,000,000 tops for one of the deeper water wells. So it's something we can easily do a couple of wells on.
So we'll just It's a block we're very excited about and we'll just kind of see how it unfolds.
Okay. That makes sense. That's helpful. Thanks. And then I guess bigger picture, just thinking about the 2019 outlook relative to the kind of back half experience here in 2018.
I know obviously we've been executing on production, taking that up, pointed at the high end of the 2019 production guide or prior guide. But at the same time, capital has also been moving higher in the last couple of quarters. How do we get comfortable with that planned ramp down in quarterly spending rate? What are the key drivers of giving you confidence in planning around that at this point?
No, I'll let Steve give you some specifics. But if you look at our last six quarters, we've been running a pretty flat activity set. And if you look at the actual E and P capital, it's been pretty flat. I mean, you saw a little bit of a rise in the back half this year and that's been towards acreage. But I'll let Steve give a little bit more color.
Yes. I think that's the story, Michael. I mean, for 4 quarters in a row, leading up to Q3, we've spent less than $750,000,000 per quarter on upstream capital, if you just set aside the midstream stuff in Alpine High. In the Q4 of 2018, we've guided to $800,000,000 but $65,000,000 of that is going to be exploration land acquisition, kind of a one off land acquisition. So really we're under $750,000,000 underlying kind of baseline upstream spending in the Q4 of 2018.
The Q3 is there's a bit of a lumpiness to it. Again, there's about $800,000,000 excluding land acquisitions in the Q3. And that's just a bit of lumpiness why that's over $750,000,000 There's a lot of lumpiness around activity on completions. You remember, we took the completion holiday and we had some backlog there. We upsized quite a number of those exception was the 3rd quarter at $800,000,000 on an underlying baseline upstream spend rate as opposed to the second half.
The other way to look at it is second half of twenty eighteen will spend 1 point in round numbers $1,650,000,000 or $1,000,000,000 We've got a little over $100,000,000 of land acquisitions, lease extensions and acquisitions. So we're just we're a little bit over $1,500,000,000 in the second half of twenty eighteen and running at about $1,500,000,000 on a half year basis going into 20 19. So I just I think that the number in the Q3 was the anomaly and the exception that's not underlying. We're spending at or even possibly slightly below for most of the last four quarters, dollars 750,000,000 a quarter in the upstream. And we're not meaningfully changing activity levels here.
Okay.
And I guess on that land acquisition side in the Q4 that $65,000,000 you highlighted, where is that roughly?
We have not disclosed that as part of our unconventional programs that would be areas that at some point in the future we talk about.
And some portion of that Michael is lease extension spending and some of that is new lease acquisition.
Okay. Thanks very much. Thank you.
There are no further questions at this time. I would now like to turn the conference back over to Mr. John Kirschmann.
Well, thank you all for joining us today. I would like to leave you with 3 key takeaways from today's call. First, Apache had an excellent quarter both operationally and financially. We significantly exceeded consensus earnings and cash flow estimates. We beat and raised our production guidance for the Q3 in a row and we outlined a strong 2019 view.
2nd, we are planning a year over year reduction in upstream capital in 2019 and upon closing Altus Midstream will fund our Alpine High infrastructure spend. This creates good visibility to free cash flow for which a high priority will be share repurchases. And lastly, we are realizing significant benefits from portfolio and strong leverage to oil prices. In 2019, as we ramp our wet gas volumes at Alpine High in conjunction with cryo installation, we will see a step function change in margins and cash flow from the play. I look forward to sharing our ongoing progress with you in the future.
This concludes today's conference call. You may now disconnect.