Good morning. My name is Natalia, and I will be your conference operator today. At this time, I would like to welcome everyone to the second quarter 2018 earnings call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Please limit your question to 1 question and a follow-up. Thank you. I will now turn the call over to Mr. Gary Clark, Vice President of Investor Relations. You may begin, sir.
Good morning. Thank you for joining us on Apache Corporation's second quarter 2018 financial and operational results conference call. Speakers making prepared remarks on today's call will be Apache's Chief Executive Officer and President, John Christmann, Executive Vice President of Operations Support, Tim Sullivan, and Executive Vice President and Chief Financial Officer, Steve Riney. Our prepared remarks will be approximately 25 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our second quarter financial and operational supplement, which can be found on our investor relations website at investor.apachecorp.com. On today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. Finally, I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental data on our website. With that, I will turn the call over to John.
Good morning. Thank you for joining us. On today's call, I will begin with commentary on Apache's second quarter production results and our outlook for the second half of 2018. I will provide an overview of the progress we are making in our key regions. Tim Sullivan and Steve Riney will then provide some additional operational details and summarize our second quarter financial performance and guidance before turning it back to me for closing remarks and a comment on the status of our midstream transaction. 2018 has been a year of continued progress on important strategic initiatives and operational performance. On the operational side, we have made several significant advances, including drilling efficiencies, strong operational runtime, base decline mitigation, new well outperformance, and a step change reduction in Permian Basin completion costs and cycle times. All of these have contributed to our positive production trends year to date.
This is most evident in our strong second quarter U.S. results, where solid execution and an increasing pace of activity enabled us to exceed guidance by 7,000 BOEs per day. The Permian Basin was the primary growth driver in the quarter, with oil production in the Midland and Delaware Basins up almost 6,000 barrels per day from the first quarter. As highlighted in last night's press release, based on this performance, we are raising our full year 2018 U.S. production guidance to 260,000 barrels of oil equivalent per day, and we are raising full year 2018 Permian Basin guidance to approximately 210,000 barrels of oil equivalent per day. Both of these are above the high end of our prior guidance, which was increased in May. In our international operations, second quarter production was roughly in line with expectations.
We are updating full year 2018 guidance to approximately 134,000 barrels of oil equivalent per day from a previous range of 130,000-140,000 barrels of oil equivalent per day. Despite a relatively limited capital expenditure program, we have made tremendous progress this year in preparation for long-term growth in Egypt and sustainability in the North Sea. As we look further ahead, our progress this year brings a significant upside bias to our 2019 and 2020 production guidance, both in the U.S. and internationally. We will provide more detailed updates on this in the coming months. During the first half of 2018, we invested $1.45 billion in our upstream operations and approximately $230 million in Alpine High midstream.
We anticipate maintaining an investment pace in the second half of the year that will bring our full year 2018 capital outlook to approximately $3.4 billion versus our prior guidance of $3 billion. The majority of this incremental capital is being directed to the Permian Basin, where we are increasing investment to align and optimize our drilling and completion programs. Production growth will be an outcome of this investment. However, the primary objective is to deploy capital in the most efficient manner and improve rates of return. I will discuss these points a bit more in my regional commentary. The combination of higher production volumes and higher than budgeted oil prices this year provides more than enough cash flow to fund the incremental capital. Moving now to region performance, beginning with the Permian Basin. In the Midland Basin, we remain focused on pad development in the Wolfcamp and Spraberry formations.
Results are exceeding expectations as strategic testing continues to enable efficient and optimized full field development. Apache continues to make great strides on capital efficiency. We have implemented a significant change in our Midland Basin completion program, which is delivering a step function reduction in both costs and cycle times. This saves about $400,000 on the average completion and has reduced cycle times to the point where we need to rebalance our drilling rig to frac crew ratio. We address this in the immediate term with a temporary holiday in June and July for one frac crew. As that crew returns in the third quarter, we will also bring two additional drilling rigs into the Midland Basin to rebalance our drilling and completions pace. This will primarily benefit production volumes in 2019.
Addition of these rigs is the most operationally efficient, cost-effective and return maximizing approach to development and represents a significant portion of our incremental capital investment this year. In the Delaware Basin, outside of Alpine High, we are developing the Wolfcamp Bone Spring formations in our Dixieland area and delineating acreage in a slope play further to the north. The strong well performance we are seeing from this program is also driving the need for incremental capital to expand production facilities. Turning now to Alpine High, where progress towards a value optimized full field development program is continuing as planned. As we described in the February earnings call, our 2018 Alpine High drilling program consists of pad and pattern development tests, ongoing geographic delineation, and some required acreage retention drilling.
We have chosen to effect a more material transition from one and two well tests to larger pad drilling this year. This has created longer lead times to first production and a completion schedule that is weighted more heavily to the back half of the year, it is clearly the most efficient way to deploy capital into the drilling program. It is also accelerating our learnings, which we are incorporating into full field development. We've spoken in previous quarters about evaluating our progress at Alpine High through a framework of well cost reductions, well productivity, and inventory expansion. I would like to update you on those now. Beginning with well costs, we continue to drive well costs down despite ongoing upward pressure on service costs. We previously stated our goal of reducing average drilling and completion costs by approximately 25% in 2018.
Year to date, our average cost for treated lateral foot is down by approximately 25%, we are on track to beat our goal. In terms of well productivity, the next phase of optimization at Alpine High is underway and involves testing spatial positioning within and between target intervals. We are also making tactical refinements to landing zone targeting, drilling longer laterals where practical, and increasing the use of larger stimulations based on positive results we have seen from tests conducted last year. Results from these optimization efforts have been very good. You can see that in the productivity of some of our recent wells. We will have more to say about this in the future. Lastly, in terms of drilling inventory, our location count today stands at more than 5,000 wells.
Landing zone and spacing tests thus far have confirmed this inventory count is conservative based on original assumptions. We will update this inventory periodically as strategic testing and optimization progresses. We are moving up the learning curve quickly at Alpine High, the transition to more pad drilling is accelerating this process. In 2018, we plan to place approximately 90 wells on production. As I previously indicated, our completion schedule is back-end loaded this year and will result in a steep production ramp in 3Q and 4Q. This ramp is now well underway. At the end of July, net production at Alpine High was approximately 54,000 barrels of oil equivalent per day, representing a nearly 70% increase from the second quarter average. For 2018, our Alpine High production is on track to achieve 45,000 barrels of oil equivalent per day, which is the midpoint of our previous guidance range.
The benefits of pad drilling, coupled with continual progress on well cost and well productivity, are driving a positive bias to our production outlook for next year. As a result, we anticipate that 2019 production from Alpine High will trend towards the high end of the 85,000 to 100,000 barrels of oil equivalent per day guidance range that was established back in February. Turning now to our international operations, beginning with Egypt. Apache Corporation continues to generate strong drilling results and maintain relatively flat gross production rates in Egypt. We recently added a third new concession consisting of 650,000 acres in the East Bahariya area, bringing our total Egypt footprint to more than 6 million acres. Activity has already begun on our new concession, as we are currently drilling our first two wells and have planned drilling activity on all three concessions before year-end.
Apache Corporation is the largest oil producer in Egypt, and our objective is to grow production and free cash flow there for many years to come. In the North Sea, we had a good quarter despite fairly limited activity. We are currently running two platform rigs, one at Beryl, along with one floater, the Ocean Patriot, which recently reset to a substantially lower day rate. Given the timing of our capital spending and well completion cadence, we placed only one new well on production during the second quarter, which led to flat production in the North Sea. With the implementation of an integrated water flood management program, we're seeing improvements in our underlying base decline rate in the Forties Field. It is still early, but there is tremendous potential for improved recovery from this massive oil field. Every 1% improvement in EUR represents 50 million barrels.
Looking ahead, our next development well at Callater is scheduled to be on production early in the fourth quarter, and our initial well at Garten is expected early in the first quarter. These two high-volume wells will bring a significant increase in oil production and provide tremendous momentum as we enter 2019. Before turning it over to Tim, I would like to conclude with a few brief comments on our exploration activities. In Suriname, we have ordered long lead items in preparation for initiating a drilling program in Block 58, which is on trend with recent industry discoveries offshore Guyana. We also have a portfolio of exploration projects in various stages of evaluation, where we are seeking large-scale, highly economic opportunities in the Lower 48, consistent with our organic growth strategy.
With that, I will turn the call over to Tim Sullivan, who will provide some operational details on the quarter.
Good morning. My remarks will briefly cover second quarter 2018 production and operation performance, including drilling highlights and activity in our core regions. Operationally, we had a very good quarter and saw improvement in many key areas. We achieved second quarter company-wide adjusted production of approximately 390,000 barrels of oil equivalent per day, a 16% increase from the same period a year ago, and up 6% from the first quarter 2018. The Permian Basin remains the primary driver of our growth, where oil production increased 25% and total production grew 39% from the second quarter a year ago. These increases reflect the ongoing development of oil production in the Midland and Delaware Basins and the continued ramp-up at Alpine High. We averaged 17 rigs and four frack crews in the Permian Basin during the quarter.
In the Midland Basin, we placed 22 wells online in the second quarter, all of which were on multi-well pads. Results are exceeding our expectations, and the information we are gathering is critical to optimizing full field development plans. During the quarter, we've drilled a number of notable pads, and I would refer you to our financial and operational supplement for more details on these results. Moving to the Delaware Basin in our Wolfcamp development in the Dixieland area, we placed on production 11 high-rate oil wells that are also in our supplement. We are seeing impressive results with only one-mile laterals. We have two proven targets in the Upper Wolfcamp and plan to test two additional targets later this year. At Alpine High, our well connections are heavily weighted to the last seven months of the year.
We have included a chart in our quarterly supplement that illustrates this cadence by month, which, as John noted, will lead to a sharp production increase in the back half of the year. Also, in our quarterly supplement, we have provided a slide that shows some impressive recent well results from key tests at Alpine High. Recent completions include a 12-well pad at Blackfoot, which is testing 660-foot spacing and three landing zones, all within the Woodford. The pad is currently flow testing 93 million cubic feet of gas and 200 barrels of oil per day gross and is still improving as it continues to clean up. A three-well Woodford pad at Fox Stake, testing longer laterals near the Central Crest with early flowback test rates of 19 million cubic feet and 321 barrel of oil per day gross.
The Mohican 201, a Barnett wet gas test in the Northern Flank, which recently flowed at 9.4 million cubic feet of gas and 420 barrels of oil per day. On the last call, we noted the impressive production profile at our six-well Dogwood pad. This was our first multi-well development pad designed to assess down spacing potential at Alpine High. The Dogwood wells went online around the beginning of the year and continue to deliver at a stabilized gross rate of nearly 50 million cubic feet per day. This pad has been producing for more than 180 days with cumulative production of 11 Bcf, and we see no signs of interference. We believe that this performance on 660-foot spacing in the dry gas window has positive implications for future additional inventory in the source interval, where we have assumed 800 to 1,000 foot spacing in our current location count.
We continue to make progress on our cost reduction goals at Alpine High. In the Northern Flank and Central Crest, we are moving from single well appraisal drilling to pad development with a focus on cost reduction, lateral length, and completion optimization to maximize net present value. For this year, we are targeting well costs below $1,380 per lateral foot, which is an approximate 25% reduction from 2017 costs. Our recent second quarter drilled and completed wells at Alpine High were ahead of target, averaging less than $1,260 per treated lateral foot. On the operating cost side, we are making great progress building out our water handling infrastructure. To supply our frack water needs, we have installed an extensive network of facilities throughout the northern half of Alpine High, which significantly reduces our need for incremental new water sources and dramatically reduces our dependence on expensive trucking services.
This includes 43 miles of water gathering and distribution facilities with five water recycling centers that are currently handling 90% of the produced water from Alpine High. During the second half of 2018, we plan to conduct tests in the Southern Flank of Alpine High to further delineate the play. Internationally, in Egypt, we drilled and completed 35 gross wells with an 83% success rate. Noteworthy results are included in our supplement. These are high-rate oil wells with Brent-index pricing. Our seismic acquisition in the Western Desert continues, with the first surveys completed over the West Kalabsha and Shushan Basin. To date, we have acquired close to 1 million acres of a planned 2.6 million acre seismic shoot. Early processing indicates a considerable uplift in imaging capability and reservoir characterization.
Moving to the North Sea, production averaged approximately 54,000 BOE per day during the quarter and was temporarily constrained by maintenance on compressors in the Beryl area . Quarter-to-quarter production was flat as we brought online only one well. During the third quarter, North Sea operations will be impacted by annual turnaround maintenance, which will reduce our production approximately 3,000 BOEs per day. This is planned activity which occurs every year at this time. Production is expected to bounce back and accelerate in the fourth quarter, with the benefit of new wells scheduled to come online. We anticipate achieving our highest average production rate for the year in the North Sea during the fourth quarter. We just TD-ed our fourth development well in the Callater field at Beryl. This well logged over 580 feet of Cormorant pay with virgin pressure. We anticipate an online date in early Q4.
This well should have a positive impact both on production and reserves. Apache owns 55% working interest. To sum up, operationally, we remain on track for a good year and are focused on building on the 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 second quarter 2018 net income of $195 million or $0.51 per diluted common share. Adjusted earnings for the quarter were $192 million or $0.50 per share. Second quarter financial performance was good across the board. Production volumes were strong, as John outlined previously. Average realized oil price was over $69 per barrel, as nearly 70% of our global oil production received Brent or Gulf Coast-linked pricing. Costs remained under control as LOE, G&A, DD&A, and cash taxes were all consistent with or better than latest guidance. Capital investments in the quarter were $833 million, bringing the first-half total to $1.69 billion.
As John noted, we plan to invest at a similar pace in the second half of the year, which will bring our total planned capital in 2018 to approximately $3.4 billion. This represents about $400 million of increased investment relative to prior guidance, which can be characterized as follows. The majority of the increase, roughly two-thirds, is attributable to incremental drilling completions and facilities investment in the Permian Basin, including Alpine High. This reflects the two Midland Basin rigs we are adding in third quarter, the cost for longer laterals and larger stimulations in Alpine High, and a slightly higher well count throughout the Permian due to the efficiencies in our drilling program. Approximately $145 million of the incremental investment will be at Alpine High, and $120 million will be elsewhere in the Permian.
For all of the reasons John outlined previously, these increases will maximize capital deployment efficiencies and will help drive incremental production in late 2018, but more materially into 2019 and beyond. Approximately $75 million of the additional capital is attributable to general service cost inflation in excess of what we budgeted for the year. The remainder is associated with a number of smaller items. This includes incremental investment at Garten due to a 100% retained working interest and upsizing the topside facility to handle larger production volumes. It also comprises long lead items for our anticipated Suriname exploration program and various other investments, mostly associated with our unconventional exploration portfolio. With the combination of higher production volumes and improved oil prices, cash flows have been very strong.
Our cash return on invested capital for the first half of 2018 was 20% on an annualized basis, and we ended the second quarter with nearly $1 billion of cash on hand. We anticipate the recent price environment and our outperformance on production volumes will continue. Both will contribute to a strong cash flow performance for the year, with full-year free cash flow being better than originally planned, even with the increase in capital investment. We will also likely see some small non-strategic asset divestments in the second half of 2018, which will further strengthen year-end liquidity. To summarize and expand on our production guidance, estimates for our third quarter volumes are as follows. Total Apache adjusted production of 398,000 barrels of oil equivalent per day, up 8,000 from second quarter.
International adjusted production of 128,000 barrels of oil equivalent per day, down 6,000 from second quarter, primarily due to routine maintenance activity in the North Sea. U.S. production of 270,000 barrels of oil equivalent per day, up 15,000 from second quarter. Permian Basin production of 220,000 barrels of oil equivalent per day, up 18,000 from second quarter, and Alpine High production of 50,000 barrels of oil equivalent per day up 18,000 or more than 50% growth from second quarter. We have also updated all of our full-year production guidance. John referenced much of this in his remarks. I will not repeat them. One thing I would note, clearly our U.S. production guidance reflects strong trends in performance. It could easily go unnoticed. Our international production has also done very well. Our updated guidance for international production is at the midpoint of our original guidance for the year.
This includes a negative impact that the strong Brent pricing has had on our Egypt volumes. Without that price impact, our international volumes would have been near the top end of our original guidance range. Please refer to our quarterly supplement for information on all guidance updates. I will conclude with some views on how we are dealing with Permian takeaway and realization issues. We are clearly in a period of tightening takeaway capacity, therefore widening differentials. Ultimately, more takeaway capacity is the only solution. The entire industry is working on that situation. Apache is certainly playing our part. We have recently announced material participation in projects involving oil, gas, and NGLs. Good progress is being made. Relief will start showing up next year. For the time being, we focus on the current situation day by day in a very pragmatic way.
We take steps to make sure our product flows to market and gets the best possible realized price. We have included in our quarterly supplement a summary of our Permian oil and gas marketing positions for 2018, now for 2019 as well. Let me touch on just a few things quickly. On the oil side, we had some success in second quarter by moving 12% of our Permian oil volumes from evergreen contracts subject to cancellation to term contracts. We now have 50% of our Permian oil for both 2018 and 2019 on term sales contracts that are backed by firm transport arrangements. As we outlined previously, approximately 30% of our production is West Texas sour. We continue to see very little flow risk with these volumes, as they are sold to regional refineries specifically equipped to run sour crude.
We manage the remaining 20% of oil production very closely and do not currently believe it will result in any production shutdowns. With respect to differentials, we added some Midland oil basis hedges in the second quarter. We are currently exposed to Midland oil basis movements for just under 60% of our 2018 Permian oil volumes. In 2019, absent any further hedging, that will increase by about 10%. With respect to Permian gas, our risk related to takeaway and basis differentials did not materially change in the second quarter. Nearly 90% of 2018 volumes and over 80% of 2019 volumes are on term contracts or have access to firm transport to other markets. 65% of our 2018 Permian gas volumes are subject to movements in Waha or El Paso Permian differentials. In 2019, this falls to just under 60% as new transport capacity becomes accessible.
In summary, we see the current situation as transitory and are participating in some of the key solutions. We have heard the discussions and, in some cases, seen decisions to reduce Permian rig count. We see this as a logical choice for those at risk of materially curtailed production. We do not anticipate that situation for Apache. To the contrary, we believe the long-term value created by advancing progress at Alpine High and other Apache assets in the Permian Basin more than offsets the potential impact of short-lived, weaker basis differentials. Consequently, absent a significant change in the basis differential outlook, we will not materially revise our planned capital investment, and we will most likely stay the course. Now I'll turn the call back over to John.
Thank you, Steve. I would like to sum up by emphasizing that 2018 has been an exceptional year thus far in terms of strategic progress and operational execution. The capital efficiency of our drilling and completion programs is improving throughout the Permian Basin. We are running at an optimized activity level and pace, demonstrating good cost discipline and generating high rates of return. At Alpine High, now we have our primary infrastructure in place and are in the early stages of a significant long-term value-accretive production ramp. We are seeing some excellent well results, and our cryogenic processing is on track for a mid-2019 startup, which will drive a significant increase in liquids production, cash margins, and returns. In the Midland and Delaware Basins, our wells are outperforming, and unconventional oil production is the primary driver of our U.S. production guidance increase this year.
Notably, in less than one year, we have completely replaced the 50,000 barrels of oil equivalent per day of divested Canadian production with Permian volumes. The strategic portfolio rotation is positively impacting our margins and is a great example of Apache's returns-focused portfolio approach. We continue to generate substantial free cash flow in Egypt and the North Sea as these regions benefit from premium Brent crude prices, as well as higher realized NGL and natural gas prices than the U.S. Lastly, I know that many of you are curious about the status of our midstream business. We have been engaged in a very thoughtful and deliberate process with regard to creating and realizing value for our Alpine High midstream assets.
As you have seen in our recent announcements, we have secured equity options in five transportation projects that will move oil, gas, and NGL to the Gulf Coast from the Permian Basin. These options are very strategic for Alpine High, Apache, and the Delaware Basin in general. We have worked the timing of these options to coincide with consummation of a larger midstream transaction to leverage their fully integrated value potential. We are in the advanced stages of a transaction that we anticipate will close before year-end, and we'll come back to you with more details on this as soon as practical. With that, we will turn the call over to Q&A.
Ladies and gentlemen, at this time, if you would like to ask a question, please press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key.
Please limit your question to one question and a follow-up. Again, press star one to ask a question. Your first question is from the line of Bob Brackett with Bernstein Research.
Hi. A question on the Alpine High. In the past, in recent past, you've guided toward the typical Alpine High well at, say, nine to 15 Bcfe, that upper range 16-21 Bcfe, but those were at 4,400-foot laterals. My question is two-part. One, how should we think about these more recent 8,000-foot laterals in terms of EURs? Two, can you guide us directionally toward the typical well versus the upper range well? Where are the error bars on what those EURs could ultimately be?
Bob, good morning. That's a great question. I will tell you that we are early in changing the completions, as we've alluded to. That's one of the reasons on the capital side. We now have enough data going back to last year that confirms some of the strategic testing on the larger fracs is making a bigger impact as well. We're kind of shifting gears, and we're early in those, and for now, I want to leave those because our location counts all kind of tie back to that.
We will be coming back with, as we get some more of these wells on and we do some more testing, you're going to see numbers go up as the productivity improves. We'll come back to you with those and update, in general, the whole impact of that.
Should I think of things in terms of EUR per foot, or should I just wait?
EUR per foot, I can tell you, we're seeing is translating pretty equivalently. The longer laterals are going up on the lateral side, but I think where the opportunity to see even more changes is going to be on the completion designs, which we're about to start doing on some of these pads. For now, lateral foot, you can probably translate to what we've shown. We'll come back to you when we've got more data to prove it.
Okay. Thank you. Quick follow-up.
What are you doing exactly to save $400,000 on the completion side? Is it efficiencies or technology or some combination?
Bob, a lot of it is just operational efficiencies. On the completion side, we've really been able to reduce our pump time substantially. We're drilling out our plugs even quicker, and we've even made progress just on frac crew moves. It's given us a 20% reduction in our cycle time, which is on a mile-and-a-half lateral, is about a $400,000 savings. It's primarily just completion efficiencies.
Bob, I'll add to what Tim just said. If you go back, it was going to create some challenges. The good news is, we set a frac crew down in the Midland Basin for two months, both June and July, and still been able to come in ahead of guidance on the numbers. I really got to give a lot of credit to the operational folks and the teams for the progress that we're making. We said this would happen. This goes back to the strategic testing we did last fall when we started doing pads on half-section tests in the Midland Basin. You're seeing those results, and now you're seeing us also doing similar things at Alpine High. Really credit to the field folks.
Great.
The engineers and technical support.
Your next question is from the line of John Freeman with Raymond James.
Hi, guys.
Good morning, John.
The first question related to Alpine High midstream, and I'm just wondering if you can talk about how you sort of think about the trade-off with any potential deal where you're trying to remove future CapEx while also trying to retain as much equity as possible, given the knowledge that as Alpine High volumes ramp pretty dramatically in the next few years, the value of the Alpine High midstream goes up considerably as well.
In a lot of ways, you just kind of answered your question. I'll say a few words here, a little more than in the prepared remarks. We're deep in the process, and we are very confident that we will get something done by year-end. Clearly, the number one objective has been to remove capital from where it's competing directly with our upstream capital, and move it into a separate funding vehicle, which we will do. The second thing, as you pointed out, we want to maintain as much of this enterprise as possible, purely because, number one, I think everybody's going to figure out that it's much more valuable to Alpine High, to Apache, and even the whole Delaware Basin than people realize. Secondly, we see that value as growing and accreting significantly over the next several years.
We'd like to hang on to as much of it as possible from that standpoint. On the timing, we've had to kind of coincide this with some of the equity options that we've been announcing, and as we alluded to in the comments, there's now five of them. We've kind of had to run those in parallel paths. We're now deep into the throes and clearly we want to be able to hang on to as much of it as possible.
Thanks, John. My follow-up just on looking at the revised CapEx budget. The changes on the U.S. side makes perfect sense. When I'm looking at the international CapEx number, which actually didn't change despite the increased kind of fast-tracking on Garten and then what's happening with Suriname, is there some other areas internationally that either are getting less capital than previous, or you're just doing better on some costs? Just what allowed international to stay flat despite what's happening with Garten and Suriname?
I think that's just kind of in the round off. The big thing is, capital's actually going up in the North Sea with Garten as we now have 100% of it. The other thing is some of it's timing of the Ocean Patriot and we've reset that rig contract now to a significantly lower number than we've been burdened with the last three years. It's kind of getting caught in the round off there, but it actually has gone up as we accelerate Garten on the capital side.
Great. Thanks, John. Nice quarter.
Thank you.
Your next question is from the line of Charles Meade with Johnson Rice.
Good morning, John, to you and your team there.
Good morning, Charles.
I wanted to ask a question about the Blackfoot pad and what you guys are seeing on the early flowback there. I know you've talked a little about your prepared remarks, and you put some stuff in your slide presentation. I wonder if you could share any more color on where you are on the flowback of that pad, if you're almost done cleaning up or you're still in the early stages of cleaning up on some of those wells. What, if anything, you're seeing between what kind of variation you may be seeing between the Upper Woodford landing zones and the Lower Woodford landing zones?
Well, Charles, I'll say it's dynamic. First thing is, as you know, this is 12 wells in the Woodford in a half section. This would translate into a full section of 24 Woodford wells only, which is a lot. They're on 660-foot spacing. We are not seeing any interference. I will tell you, it's very dynamic and we're very early. In fact, we went to print and yesterday with our numbers, and this morning, the Blackfoot now is at 102 million a day from the 93 that we had in there. That shows you the trajectory that it's on. We still do not have everything unloaded. It's climbing very well. It's performing very strongly. We're very excited about what we're seeing. Changing quickly. Tomorrow I'd have a different answer for you.
Okay. Thank you, John. Then on the other side of the Permian, I wondered if Tim went through a lot of detail on how you've changed not just your designs, but also your operational pace on that side. I wondered if you could talk about the Lynch pad, which is that eight-well pad in the Wildfire area that you guys brought online. It had some good rates. Is that benefiting from these new designs and this new approach? Maybe just add a little color to what was happening there.
Yeah. On the Lynch pad, it's an eight-well pad. It's in the Wolfcamp B. This was really a spacing test. We did some 10 bys and 8 bys in this pad, 7,300-foot lateral length. You can see the rates are good, 1,275 barrels of oil equivalent per day, and mostly oil from the IP. We continue to do spacing tests. We've got another 10 wells that are online, and some of them are Wildfire as well. Very early stages of flowback, but they're on a 6-by spacing. We'll share results with you about that next quarter. These are spacing test wells in the Wolfcamp B, and we're going to compare them to 6 by next quarter.
I'm sorry, just real quick clarification, Tim. The 10 by spacing, that's spacing equivalent to 10 wells across the section?
That's correct. Part of the pad is 10 wells per section spacing, and part of it's 8 by.
Got it. Thank you, Tim.
You bet.
Your next question is on the line of Scott Hanold with RBC Capital Markets.
Thanks. Good morning, guys.
Good morning, Scott.
Hey. Can you talk about how you're looking to go about Alpine High right now? It sounds like you're starting to move into some optimization based on what you've seen. I know early on you were trying to do things like separate various factors, right? Lateral length, frack that you're putting on this to get a good sense of really what's driving performance. Where are we with that, and how does that sort of drive you for these 60, 70 completions you've got at the end of this year and maybe into 2019?
Well, it's exciting because now we've got data. We've been deliberate on those tests. As you've correctly noted, we weren't moving many dials except one usually for a reason. We have a good baseline. It's clear to us now that we're going to be increasing the frack size. It's clear to us that we can go tighter with the current frack designs. Now we're moving into the pattern and spacing test where we're testing things between zones, between formations, both aerially, spatially, and so forth. Now you'll see us start to move some of those dials as we crank up the completion. We'll continue the very deliberate process. It just takes time to do it right.
If you jump out there and go drill too many wells and pump too big a fracks and you get a lot of interference, then you got to go back and try to figure out how you unwind that. What we've been is very deliberate with it, and we're moving into that next phase. We've got a plan. We've stuck to it, and you're starting to see the benefit come, and we're really excited about the results and the learnings that we continue to incorporate.
All right, great. Appreciate that. A follow-up on Egypt. With some of this enhanced seismic imagery you've gotten back, it sounds like you got some of it back. How much of it have you had it in your hands to take a look at it, and what are you seeing now versus maybe what you had thought of it going into it?
Well, I've seen snippets of the new data, and then we've actually compared it to some of the '13 vintage stuff. I'm looking at one of my ops guys over here, but I will tell you, I've heard now we're seeing some fault lines in some of our existing fields, which probably sets up more drilling. You could see some things at Ptah and Berene. I'll be over there, in the fairly near future, we'll get to review some things. We're excited about it. It's what we thought it would be. It helps us see image better, the subsurface, which is going to lead to more wells, stronger results, and a better understanding. Plus, we're going to have a better handle on some of the recoveries and things. It's a whole new lens, and it's going to be very helpful.
Thanks for that.
Your next question is on the line of Jeoffrey Lambujon with Tudor, Pickering, Holt.
Good morning. Thanks for taking my questions. My first one's on what a, I guess, a midstream monetization could mean for the budget this year. Are you able to eliminate some of the planned incremental spend with the deal? For parts of the budget that have been spent ahead of an announcement or a closing, is there an opportunity for rebates or reimbursements for at least the Alpine High piece?
Jeff, obviously we could make it look however we want to look. I mean, we could take a lot of cash out. We could eliminate capital. We can make the effective date whenever we want that date to be. We've made pretty clear in here that our CapEx guide for the year-end still includes 100% of the midstream spend. We made it clear that getting something done could pull some of that back, and there's opportunity there. I'll just say wait with us. It's going to have an impact, but wait with us until we're in a position to disclose more, because we're deep in the process.
Got it. Just digging into the incremental Alpine High piece by itself, should we think of that as all or I guess maybe primarily longer laterals and completion enhancements? Or is there a portion related to midstream spend that was accelerated into this year from next year's plan initially?
There's a little bit of the midstream that we're looking at trying to accelerate cryo. As we've said, most of the two-thirds of the CapEx increase is going into drilling completions. It's new activity. We made very clear that two-thirds of its new activity that will be incremental. Most of it is this back half of the year, which is why it'll impact 2019 and 2020. There's a little bit of impact on 2018, not much. There has been a little bit of inflation, about I'd say just under 20%. We budgeted a 10%-15% rise. Anything that has to do with trucking, people, steel, or chemicals, there are some headwinds out there. There's a portion of it that's tied to that. We mentioned some on the exploration side.
Most of it's new activity and two-thirds of it in Permian. It's new activity.
Thank you.
Your next question is on the line of John Herrlin with Societe Generale.
You're gathering a lot of water at Alpine High. Are you going to be able to recycle any of it?
John, everything we're gathering, we're recycling. The beauty of our transgressive source interval is it doesn't produce very much. It's really the frack water that we're gathering. We produce it back as load, then we recycle it and reuse it. I'll let Tim jump in on some more details.
Yeah. We've currently got five water recycling facilities out there, and we are currently recycling about 90% of our produced water right now. That really is only about half of our frack water needs currently. We do have to have makeup water, and we do use brackish source for that. By year-end, we feel like we'll be able to utilize about 80% of recycled water for our fracs.
Okay, great. Next one for me is on Dixieland. You had slightly stronger well results in the first quarter at Burnside and one other, and I was wondering how much heterogeneity do you have? Like Burnside and Bull Run were a little bit stronger than some of the other wells. I'm not worried about everything always staying at the same level, but I was wondering how much heterogeneity do you see since you're basically doing similar type completions?
Well, John, as you know, that's why we talk about Bone Spring and Wolfcamp as being parasequences. Geologically, you have heterogeneity. Tim, do you want to add anything specifically to that area?
Yeah. I mean, we only have seven sections there. It's not like it's a big area. It's fairly consistent. We've got two proven landing zones. We will be testing two additional landing zones out there. We brought 20 wells online here in the first half, 11 in the second quarter, and they're about 1,500 BOE per day. These are just mile laterals, actually 4,400-foot laterals. It's been a very economically attractive program for us. We think we've still got a pretty bright future for the next couple of years.
Okay, great. Thank you.
Thanks, John.
Your next question is on the line of Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
In Alpine High, how do the results of some of the efficiencies, lateral length, and spacing tests in areas like Dogwood change the relative rates of return and prioritization of the wet gas versus dry gas drilling? How, if at all, does that influence your focus areas over the next few quarters?
If you look at the wet gas, dry gas, the breakevens on the wet gas are still going to be much better just because of the amount of the liquid. It won't really change the pecking order there. What it really changes is the number of wells we need to drill and some of those things in terms of the plan. It can change the cadence and the sequence as you look at the capital that's going to what we'll call retention wells versus the impact wells.
Got it. Thank you. Then you've highlighted across the portfolio, but particularly in the Alpine High various efficiencies, and I wonder if you could talk about where you see these efficiencies going from here, whether we've just had a surge or whether you think this pace is going to continue. How do you draw the line on when you let those efficiencies play through to higher CapEx versus just choose to become more narrowly focused within the portfolio?
I think if you look at our Permian, Brian, we've been running 17 rigs since the second quarter of last year. We're at what we think is a pretty darn good base load. Clearly, the frack efficiencies took a step function forward. We've seen that. Now we're seeing the drilling time and the footage take a step function move forward. This is a continual ebb and flow as you continue to get better, reduce cycle times, and so forth. If you step back and look at our program, then you look at the results over the last year, Permian's up 39% year-over-year, and oil's up 25% year-over-year. We've been pretty steady on the program. What's changing at Alpine High is the completion design, and more on the spacing test.
When you look at the size program we're running, you look at the size cash engine that we're building to fund it, those are the things you have to factor in. You have to continue to integrate your learnings and the continuous improvement. We stress to our folks to continue to get better in everything we do. You're going to have times where we're going to have to make adjustments as we continue to incorporate learnings. It was a pretty easy call here as we look at what the engine for this thing looks like going in to 2019.
Is it fair to say that if there is a free cash buffer to offset efficiency-driven or even inflation-driven increases in CapEx, with no further change in activity, that that would be sufficient for you to further increase your budget?
I don't think you can assume everything on the free cash side goes to budget, right? What we're trying to do with our efficiency programs, and what you've seen with the size is ultimately it's returns and value driven. That's the big factor. You look at our activity, it really hadn't changed, and it's not going to change much going into the fall. We've got to sprinkle a few rigs in to kind of keep it there with the frack crews and so forth. We're getting to a point, we get the midstream deal done in the very near future with the engine that we built, that we actually see free cash flow. It puts us in a position where we can start to truly, for the first time since coming out of this downturn, we can look now at other things to do.
Those are things that we're very excited about because we can see a pathway to it pretty near future.
Thank you.
Your next question is from the line of Leo Mariani with National Alliance Securities.
Hey, guys. I was hoping that you could delve a little bit more into some of the exploration efforts that you guys alluded to on the call. You guys did mention kind of an unconventional U.S. exploration program. Just trying to get a sense of maybe what the dollars are that are exposed to that in this year's budget. Also was hoping for a little bit more detail on Suriname, in terms of when you guys might spot a well there, what's your work interests there, and what do you see as the potential in Suriname?
Well, a couple of things, Leo, and thanks for the question. Number one, I'll address them kind of in the order. On the unconventional side, in the U.S., there's not a lot of dollars. What we're looking for there is large impact, large scale opportunities that are in various stages that we could acquire at low cost. Much like when we put something like Alpine High together, we put together 350,000 acres out there for less than $1,300 an acre. It would be those types of things, but there's not a lot of capital at this stage. If you're looking in the right places, it doesn't take a lot of capital to go a long way. Not in a position to say a lot more than that, but we do have some things we're working on on the unconventional side.
As it relates to Suriname, clearly what we've said, we've got two blocks in the offshore there. Block 58, we own 100%, it's about 1.4 million acres. We have 45% of Block 53. We will definitely commence a program in 2019, and we've started to purchase the long lead items. We got the 3D back. We're very, very excited about the potential. We're on trend with the success that's happened across the water boundary in Guyana, and it's exploration, but could be very, very impactful for Apache. Currently today, we own 100% of it.
All right, guys. Thanks.
Thank you.
Your final question on the line of Douglas Leggate with Bank of America Merrill Lynch.
Thanks, John. Good morning. I got a couple to close us out here, it looks like. My first one is on Egypt. As we understand it, in the last six or nine months, the government's gone through quite a lot of change in deregulating its gas market. It's removed subsidies from local industrial prices. Everything that's going on there, it's incentivizing exploration. I'm curious if any of that is filtering through to what you're doing, especially in your new concession, how you see the prognosis for seeing us maybe starting to see an uplift in your exploration activity translating to higher price realizations. I've got a quick follow-up, please.
Well, I think the key for us, Doug, is number one, all the activity, all the gas coming on has been very beneficial for Egypt, which is a good thing, and that translates into the country's just financial wherewithal. Things are going extremely well. I think the key for us is, we've been able to pick up new concessions for the first time since 2006. We're shooting a large 3D. We're in between areas where we know there are big structures and really, really fertile ground. We're very excited about that. We're excited about the opportunity to continue to grow the free cash flow. We think we can be in a position to also grow our volumes in Egypt, and especially on the oil side.
I think in general, it's a very promising environment for Apache and things are going extremely well, and we're very excited about the future.
Just to be clear, has the new exploration acreage come with different terms as it relates to realized gas pricing?
All the concessions, you bid those. The thing I will say is, we've kind of stuck to our guns historically, which is why you went through a drought where others came in and picked up other concessions. We've stuck to our guns in terms of how we've approached it. We feel good about that. We feel good about the new concessions, and we like the terms.
Understood. My follow-up, if I may, is just jumping back to Alpine High very quickly. It's kind of a follow-up to Bob's question earlier about the four and half thousand foot laterals and getting bigger and so on. Clearly it seems that there's upside risk to the guidance you gave us a couple of years ago. How would you think about how that translates to your production profile through 2020? Do you have lower decline rates by choking back the wells, for example? Do you have faster acceleration? Just if you could characterize how all of that plays into the infrastructure plan and so on. I'll leave it there. Thanks.
Well, we have just a tremendous resource. As we've said on today's call, we would tend to the high side of the previous guidance that we gave early this year. Clearly productivity's improving. Wells are performing extremely well. We're shifting to pads. I would just steer to the high side numbers, as it relates to 2019, is what we've said now. We'll come back with some updated numbers as the year moves along.
Great stuff. Thanks, fellas. Appreciate you taking my questions.
Thank you all. I just want to wrap up and like to leave you with three key takeaways from today's call. First, Apache had another great quarter. We exceeded guidance and raised our 2018 outlook. Second, looking ahead to 2019 and 2020, there is a significant upside bias to our production outlook due to the added capital, which will benefit primarily 2019 and 2020, the capital efficiency improvements, and strong well performance, all in our Permian Basin. Additionally, total capital spending is likely to come down in 2018 to 2020 with the completion of our midstream transaction. Lastly, at Alpine High, we are seeing very good results from our strategic tests and production growth has entered the acceleration phase. I look forward to sharing our ongoing progress with you in the future.
This concludes today's conference call. You may now disconnect.