Good morning. My name is Jennifer, and I will be your conference operator today. At this time, I would like to welcome everyone to the first 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 that time, you may simply press star and 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. I would like to turn the conference over to Mr. Gary Clark, Vice President of Investor Relations. Sir, you may begin.
Good morning, and thank you for joining us on Apache Corporation's first quarter 2018 financial and operational results conference call. Speakers making prepared remarks on today's call will be Apache's CEO and President, John Christmann; Executive Vice President of Operations Support, Tim Sullivan; and Executive Vice President and CFO, Steve Riney. Also available for the Q&A session are Mark Meyer, Senior Vice President, Energy Technology Strategies, and Dave Pursell, Senior Vice President, Planning and Energy Fundamentals. 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 first quarter financial and operational supplement, which can be found on our investor relations website at investor.apachecorp.com.
Please note the supplement was updated this morning to include information on our Permian Basin oil and gas marketing positions, which can be found on pages 22 and 23. 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's 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. Before I get to the results, I want to take a moment to recognize a longtime Apache who has recently announced his plans to retire later this year. Kregg Olson, our Executive Vice President of Corporate Reservoir Engineering. During his 26 years with Apache, Kregg's leadership and expertise have been significant contributors to our long-term success. On behalf of all of Apache, I want to thank Kregg for his years of service and wish him well in retirement. In light of this change, we have announced David Pursell, Senior Vice President, Planning and Energy Fundamentals, will lead our corporate reservoir engineering function upon Kregg's retirement. This transition is already underway, we look forward to introducing you all to David in the months ahead.
On today's call, I will review Apache's first quarter progress and provide highlights from some of our key operating areas. Tim Sullivan and Steve Riney will provide a brief review of our operational and financial performance during the quarter. Before moving to Q&A, I will conclude with our perspective on a few themes we have been hearing recently from the investment community. Apache is off to a strong start this year. In the U.S., we exceeded our first quarter production guidance through solid operational execution, shorter completion cycle times, improving efficiencies, and continued outperformance from new wells placed online over the last two quarters. The positive impact of these items more than offset volume losses we incurred from unplanned facilities downtime and adverse weather.
As noted in yesterday's press release, we delivered record production in the Permian Basin, the excellent progress we made during the first quarter has prompted us to raise our U.S. production guidance for both the second quarter and full year 2018. Internationally, our leverage to Brent oil pricing contributed to improving margins, higher cash returns, and strong free cash flow. Production was in line with guidance, which remains unchanged for the full year. Moving now to specific region performance, beginning with the Permian Basin. Our results continue to improve as we strive for best-in-class execution, leveraging the best technology advancements and insightful data analytics. In the Midland Basin, our current drilling program is focused on section and half section testing and development in the Wolfcamp and Spraberry formations.
We are delineating additional landing zones within our core fields and assessing other parts of our acreage where we are seeing positive early results. In the Delaware Basin, outside of Alpine High, we are generating solid growth from our Wolfcamp and Bone Spring drilling program. We are drilling multi-well development pads, testing incremental landing zones, and evaluating additional prospect areas. Our plan is to sustain the three-rig drilling program outside of Alpine High in the Delaware Basin. We have made excellent progress reducing well costs, increasing productivity, and driving higher returns in the Midland and Delaware Basins. We are deliberately operating at a measured pace, which is enabling timely integration of key learnings into our capital program. On many occasions, we have stated that production growth will be the outcome of our disciplined, returns-focused investment program.
We are certainly seeing that in the Midland and Delaware Basins, where daily oil production has increased 37% since the second quarter of last year, and in the Permian Basin as a whole, where daily oil production has increased 19% over the same time period. Turning now to Alpine High, where progress toward a value-optimized full field development plan is continuing as planned. As I indicated on last quarter's call, you can monitor Alpine High progress on three key fronts: well cost reductions, well productivity, and inventory expansion. First, we are making substantial improvements on well costs. Our objective is to decrease average well cost by 25% from 2017. During the first quarter alone, we delivered an average 20% reduction. Having already achieved 80% of the target, we have clear visibility into further well cost reductions for the remainder of the year.
Second, we are focused on enhancing well productivity at the section level, which is the true economic unit we are seeking to optimize. We are now gathering data from two important half-section multi-well pad tests, which Tim will provide details on in his remarks. Third, in terms of drilling inventory, recall that we increased our risk location count to more than 5,000 locations in our October webcast update. At the time, we characterized this as a conservative view based on only six landing zones and relatively wide spacing assumptions. We have now confirmed hydrocarbon production from 11 distinct landing zones, and we are continuing to delineate these and other landing zones across Alpine High. We are also testing tighter well spacing and have seen some encouraging initial results.
While we are not updating our location count today, we are confident that as field delineation and development progresses, the risk location count will increase substantially over the next several years. Alpine High is also making great progress on lease operating expenses. LOE was approximately $4.50 per BOE in the first quarter, and we are targeting a decrease to less than $3 per BOE by year-end. As previously indicated, we are on target to drive LOE per BOE below $2 by the end of 2020. One of the primary factors behind our low cost structure is that the transgressive source interval in the Woodford, Barnett, and Penn produces very little water, resulting in minimal handling and disposal costs. On the midstream side, our build-out at Alpine High continues, with additional infrastructure coming online as expected.
Our strategic objectives this year include finalizing a JV or partial monetization of the midstream enterprise and reaching agreements for future oil, gas, and NGL takeaway capacity. Moving on to Egypt, we are continuing with a high-density seismic acquisition and processing program across our expansive acreage position, which will greatly enhance our subsurface imaging capabilities. We believe this will uncover numerous meaningful opportunities to grow future oil production on both new and legacy acreage. In the second half of this year, we plan to commence drilling on our new concessions, which comprise 1.6 million acres. We are very excited about these concessions, which are geologically similar to our producing acreage in the Western Desert and are virtually unexplored. In the North Sea, we recently announced an impactful discovery at Garten in the Beryl area.
We believe this discovery will yield a minimum of 10 million barrels of oil, with potential to move significantly higher. Apache owns 100% of Garten, which will be a relatively quick and inexpensive tieback to existing facilities. This should have a positive impact on our 2019 and 2020 international production guidance, which we will revisit later in the year. In summary, we are off to a great start in 2018. Execution is very strong, and we are investing capital efficiently and strengthening Apache's overall capabilities to deliver more sustainable, higher returns over the long term. Now 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 first quarter 2018 production performance and capital efficiency, 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 first quarter company-wide adjusted production of approximately 367,000 barrels of oil equivalent per day, a 6% increase from the same period a year ago, and up slightly from the fourth quarter 2017. The Permian Basin remains the primary driver of our growth, where oil production increased 14% and total production increased 24% from the first quarter a year ago. This reflects the ongoing development of oil production in the Midland and Delaware Basins and the startup of Alpine High. We averaged 16 rigs and four frack crews in the Permian Basin during the quarter, with seven rigs and one frack crew dedicated to Alpine High.
In the Midland Basin, we have implemented a new completion design with more optimal stage and cluster spacing, which is contributing to improved early time well performance. We are fracture-stimulating more lateral feet per day, completing wells faster and more efficiently, and realizing significant cost savings. For the quarter, we brought online 12 wells in the Wolfcamp formation with an average peak 30-day IP exceeding 1,100 BOE per day, consisting of 75% oil. Notably, we tested our first Wolfcamp C producer, which achieved a very encouraging 30-day IP of nearly 1,150 BOE per day, 70% oil. These positive results could open up hundreds of additional Wolfcamp C locations across our acreage position. Moving to the Delaware Basin, production at Alpine High averaged 26,300 BOE per day.
Of note, we brought online our first multi-well pad in the wet gas window, the four-well Chinook pad, which delivered peak 30-day IPs averaging 5.2 million cubic feet of gas and 170 barrels of oil per day. The Chinook gas has an average BTU content of 1350 and is currently recovering 50 barrels of NGLs per million cubic feet of gas. This yield is expected to increase to 150 with the addition of cryo. We are pleased with these early results, which will yield attractive economics as well cost average only $6.4 million. A year ago, drilled on a one-off basis, these wells would have cost more than $8 million per well. We have made significant progress on our cost reduction goal at Alpine High, targeting an average completed well cost of $6.2 million for 2018.
As we move to pad operations, we are realizing the benefit of increasing efficiencies and reducing well costs. On the drilling side, these include the use of less expensive spudder rigs to drill surface and intermediate holes, standardized casing programs, and in many wells, the elimination of a casing string, and optimized bits and bottom hole assemblies for specific areas. Completion savings include the ability to pump more frac stages per day, optimize sand loading to pattern size, and the use of recycled and brackish water. At the end of 2017, we placed on production the Dogwood pad, our first multi-well development pad in Alpine High's dry gas window. This pad has been producing for 119 days with cumulative production of 6.4 BCF.
The stabilized production rate from the six-well pad is currently 62 million cubic feet per day, compared to the initial peak 30-day IP of more than 70 million cubic feet per day. Importantly, we have seen no interference between these wells at 660 spacing, which is a very encouraging indicator for tighter well spacing during full field development. Keep in mind that our current 5,000 well location count assumes 925 foot spacing in the dry gas window and 800 foot spacing in the wet gas window. Other down-spacing tests are in progress. Elsewhere in the U.S., production for the Midcontinent region increased from the preceding quarter as a result of the recent completion of approximately eight net wells over the last two quarters in the SCOOP. These are showing strong performance, and this production uplift will allow us to hold Midcontinent production flat or grow slightly year-over-year.
Internationally, Apache remains the largest oil producer and most active driller in Egypt. For the quarter, Egypt-adjusted production averaged approximately 80,000 BOE per day, down slightly from the fourth quarter 2017. We drilled and completed 28 operated wells with an 86% success rate. Of particular note, the Apries-1X, a discovery in the Shushan Basin, found 280 feet of pay in the Shifa formation. The gas condensate reservoir flow tested 20 million cubic feet of gas per day and 2,400 barrels of condensate. This success sets up several development and follow-on exploration wells in the area. Our seismic acquisition is ahead of schedule. To date, we have acquired 710,000 acres of a planned 2.6 million acre seismic shoot spanning 4 different basins in the Western Desert. Early results indicate the data will deliver a paradigm shift in imaging capability and reservoir characterization.
Moving to the North Sea, production averaged 54,000 BOE per day during the quarter and was impacted by a number of items, including downtime associated with inclement weather, unscheduled maintenance, and repair on compressors in the Beryl area, and periodic interruptions on the Forties Pipeline System. No new wells were placed on production during the quarter, which contributed to a sequential decline from the fourth quarter. As we have stated before, production in the North Sea tends to be lumpy on a quarter-to-quarter basis, but we are seeing some of the above conditions abate thus far in the second quarter. As John noted, an important highlight for the quarter was our discovery at Garten, which is located only 6 kilometers from the Beryl Alpha facilities. The discovery well encountered more than 700 foot of net pay for multiple zones.
Drilling, completion, and tieback costs are estimated at approximately $60 million, with minimum reserve estimate of 10 million barrels of oil, we expect very low F&D costs. To sum up, operationally, we are up to a very good start to the year and are focused on building this momentum in the quarters ahead. I'll now turn the call over to Steve.
Thank you, Tim. Let me start with first quarter results. As noted in our press release issued last night, under generally accepted accounting principles, Apache reported first quarter 2018 net income of $145 million, or $0.38 per diluted ton share. Adjusted earnings for the quarter were $124 million, or $0.32 per share. The most significant adjustment being a $39 million after-tax unrealized gain on our derivative positions. As John outlined, our U.S. production exceeded guidance by 4%, while international production was in line with guidance. Capital investment of approximately $850 million was above guidance due to accelerated activity in the Permian Basin, primarily driven by more efficient completion times. There was also additional spending on our Garten discovery in the North Sea due to a higher working interest than previously planned. Despite inflationary pressures, costs remained under control during the quarter.
Nearly all categories of costs ended the quarter consistent with or better than latest guidance. Two specific areas of costs included accounting impacts for one-off type changes. First, G&A for the quarter includes approximately $10 million of non-cash charges related to a change in retirement policy. Second quarter G&A will include a similar amount of non-cash charges. Second, gathering transmission and processing costs for the quarter reflect the reclassification of certain charges under the new revenue recognition rules adopted for 2018. This change has no net effect on results. In the past, these costs were netted against revenue. Now they are recognized as an expense, thus our reported revenues have increased by the same amount. Our effective tax rate for the quarter was approximately 47% on a GAAP basis. This is higher than most would expect due to the accounting treatment of U.S. taxes.
We operate at a profit in Egypt and the U.K. and accrue taxes at the average effective tax rates of 45% and 40% respectively. In the U.S., we operated at a small loss, which would normally bring the average effective tax rate down. However, uncertainty in realizing these benefits precludes us from recognizing them on an ongoing basis today. The result is that the GAAP effective tax rate is a bit high, but there is no impact on cash flow. Moving now to guidance. Following strong first quarter results, we are increasing full year U.S. production guidance to a range of 250,000-258,000 BOEs per day, up from 245,000-255,000 BOEs. Most of this increase is attributable to the Permian Basin. Our 2018 international guidance remains unchanged at this time.
On the full year guidance for other items, we are making only one change, increasing cash taxes to a range of $175 million-$225 million. This reflects the anticipated income uplift from improving realizations for North Sea crude oil production. For the second quarter, we anticipate U.S. production will be approximately 248,000 BOE per day. Adjusted international production is expected to average 135,000 BOEs per day. This would result in 7% quarter-on-quarter U.S. production growth and 4% overall growth worldwide. We have provided second quarter guidance for a number of other items. I will not cover those in detail. You can find them in our financial and operational supplement. Turning now to Alpine High Midstream, we are currently operating 121 miles of gathering line, 33 miles of 30-inch trunk line, 34 central tank batteries, and 780 million cubic feet per day of inlet gas processing capacity.
An additional 50 million cubic feet per day processing capacity expansion was planned for later this year. We are now looking at options to eliminate this expansion by bringing forward the mid-2019 plan startup of the first cryo facility. We are actively working design and procurement for 3 200 million cubic feet per day cryo plants. Once fully operational, these facilities will significantly increase our NGL volumes out of Alpine High, boosting overall liquids production from the play. Plans to joint venture or partially monetize the Alpine High Midstream are on track. A formal process is underway. That process has drawn a significant amount of interest from a broad range of potential partners. We are confident we'll put some form of venture in place during 2018. I'd like to close by commenting on the steps we have taken to mitigate the impact of widening Permian Basin differentials.
We recognized the potential issue over a year ago and have been proactive in addressing it through various strategies. We have in place a combination of basis hedges, sales contracts, and firm transportation to access other pricing points. We anticipate a relatively tight market situation will last through much of 2019. That is the timeframe we have targeted for mitigation efforts. While we have some exposure to both price risk and product flow risk, we are taking actions. Looking for opportunities to further mitigate both of these risks. I'll turn the call back to John for some final remarks before moving to Q&A.
Thank you, Steve. Before we open the call to Q&A, I would like to comment on a couple of recurring topics we have heard during recent interactions with shareholders and the broader investment community. With oil prices well above the baseline for 2018 planning, there is a lot of focus on what industry will be doing with the extra cash flows. For Apache, the answer to that question has to be based on the key elements of our plan for the year. Our 2018 base plan showed an approximate outspend of $700 million at $58 WTI, which was primarily driven by the Alpine High Midstream investment program of $500 million.
In conjunction with that plan, we outlined our desire to transact the midstream business in a way that would eliminate our ongoing funding obligation while still leaving us significantly invested in the future value add from the growth that will come from the upstream. As Steve outlined, we are well into that process, and we are confident that we will execute such a transaction in 2018. That said, the timing and structure of this event are not finalized, and we will plan and respond accordingly. As such, our first priority for any extra cash flows in 2018 will be to close the cash flow gap with our overall capital program, including Alpine High Midstream. When we have better visibility to full-year cash flows and certainty around the midstream outcome, we will then consider other options, including the return of additional capital to shareholders and incremental capital investment.
Another common topic is Permian Basin supply growth, takeaway capacity, and the resulting impact on oil and gas basis differentials. Both oil and gas takeaway capacity is tightening as we move through the year and into late 2019. Basin offtake capacity is the main concern in this situation, and Apache is well-protected through a combination of firm sales contracts and firm transportation solutions for the majority of our projected volumes. A related concern is the widening basis differentials that accompany a constrained market. Here again, we have taken proactive steps through basis hedges and firm transportation commitments that will help mitigate the price risk. I won't go into the details here, but we have included a few slides in our first quarter supplement that describe our current Permian marketing position and hedges. Pipeline offtake constraints and differential widening will be a relatively short-lived condition.
The industry has been there before in the Permian, these issues were quickly resolved as Permian Basin intrastate pipeline capacity is comparatively easy to build. Over the longer term, the Permian Basin provides a tremendous opportunity for Apache to deliver attractive growth at high rates of return. We have the fourth largest acreage footprint and plan to commit 70% of our capital to the basin over the next three years. That said, accelerating industry activity is creating significant competition for oil field services and non-trivial operational challenges. In this environment, our priority is to protect and grow returns. We are operating at a disciplined pace with the objective to be the returns leader in the Permian with growth as an outcome. With that, we are ready to move to Q&A.
As a reminder, if you would like to ask a question, please press star and the number 1 on your telephone keypad. Our first question comes from the line of John Freeman with Raymond James.
Thank you. When I'm looking at the impressive cost reductions at Alpine High, you've already achieved 80% of the target that you had. You're really just starting to get the impacts or the benefits from the pad development. I guess, what's been the biggest surprise relative to your initial expectations?
John, I think it's just a matter of moving into pads. The drilling analytics, the things we've been able to do. We've originally said we thought we could get down to four to six. Getting to the six-two target this year, we knew we would be able to achieve it. I think probably just being able to get there as quickly as we have given the inflation we've had on some of the small services. I'm really pleased with where we are. I can tell you, we see pacesetters daily coming out of there, with all the analytics and technical tools we're applying, and I expect us to continue to drive those costs down. It's a great story and is going to only get better.
Great. When I look at Alpine High with basically you all averaging seven rigs and the one frac crew, once all the midstream is taken care of, can you give me an idea how that ratio of rigs to frac crews would you see changing in 2019 and beyond?
Well, we're at a period right now where you're working both your frac crews and your rig counts, and they will be dynamic. We've actually got two crews in that region. One of them kind of bounces back and forth between there and the Delaware. It's really not just directly, I would say, one. A lot of that's a function of the pad and the timing and how we're scheduling that. Over time, we would expect both, we've seen significant efficiencies on the completion side in the Midland, and I think you, in general, are going to see ratios similar to what we have, but probably in that same line.
Great. Just the last one for me, following on the really impressive discovery at Garten. You all said you're going to revisit the international guidance on 2019 and 2020. Just maybe sort of an idea of when you think you'd have enough information to at least preliminarily give some idea on how that changes numbers.
Garten is a very exciting discovery for us. It will be material to our North Sea. Part of this will hinge on getting the well on and testing it, as well as evaluating how many other wells there might be there. This structure is more subtle and could be significantly bigger than the 10 million barrels that we've disclosed. As the year progresses and we get to do more technical work, we'll come back with that sometime later this year. It's going to have an impact positively in 2019 and 2020.
I appreciate it. Thanks.
Your next question comes from the line of Bob Brackett with Bernstein.
Hi. Thanks for the disclosure on the gas positioning in the Permian. Can you talk, and you guys have thought about this clearly, what are tactically some of the things you would do if gas production flow risk emerged?
Yeah. Hey, Bob, this is Steve. Well, the thing is we are continuing daily with a contracting strategy for gas out of the Permian Basin and Alpine High. You see in the supplement, we have 91% of our gas production plan for 2018 that's either on firm transport or is into gas sales contracts that require taking that gas. Really only 9% of our production volume that we have planned for this year on the gas side and all of the Permian is at risk to any type of a takeaway capacity constraint. We work on that daily. We're looking at more firm transport, more opportunity to get product out of Alpine High and get it into other basins. As you know, there's a lot of activity out there in the market on that, and we're very active in all of those types of conversations.
I would anticipate there'll be more activity on that as we go through 2018 and into 2019. We're also looking at-
If you-
There are options. We do have two large pipes going to Mexico that run to the north and to the south of Alpine High, we are looking at options and possibilities on moving product on those as well.
I heard your approach that by 2021, this is a pro or 2020, 2021, this is something that the industry typically solves. How are you set up for 2019? Because you are growing gas fairly prolifically through 2019.
Yeah, we're still working on that. We've got the Gulf Coast Express that'll be coming online in the third quarter of 2019. That'll take care of a lot of the growth after that point. Then we're continuing to work the contracting side of this. As long as we have firm contracts to move our product with customers, then they have the transport capacity, then our product will move.
Great. Thanks.
Your next question comes from the line of Bob Morris with Citi.
Thank you, and congratulations, John, on some nice well results in the Permian and on the Wolfcamp C discovery.
Thank you.
You're welcome. You mentioned that at Alpine High, you've now delineated 11 distinct landing zones, and you've had nice results from the pilots targeting the Woodford and Barnett formations so far. Can you say what other formations you'll be targeting this year with your drilling activity?
Bob, as we've said, we'll have about half of our program over the next 3 years will be in primarily going towards retention, which is going to be predominantly Woodford and some Barnett. The other portion of that will be is discretionary or what we call impact, and we will be testing and drilling some other wells. You'll see us start to work up the column. You'll see us start to work the Woodford in the shallower areas. The areas where it's going to be more oily and more liquids rich. We're excited about those and there's stuff that's ongoing now, and we'll continue.
Okay. My follow-up, Steve, you mentioned pulling forward one of the cryogenic processing plants into this year, and maybe I missed it, but how are you able to do that and what is the timing? Obviously that'll have a big impact on the liquids mix once that plant is in place. If you can give any color on now what the timing of that'll be to be in place and how you're able to pull that forward.
Yeah. Sorry, Bob. I may have misled you on that on the comment. To be clear, our original timeline for starting up the first cryo unit was mid-2019. We're simply looking at an option for bringing that forward in 2019, earlier in 2019. We won't have a cryo unit online before the end of 2018, that's for sure.
Okay, that still has to pull forward. Okay, great. Thank you.
Your next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering.
Good morning. Thanks for taking my questions. Looking at the overall opportunity set in the Midland, Delaware, and Alpine High, and just thinking about long-term activity levels, what's the right rig count or well count to keep in mind that gets you again, to the long-term balance of optimally developing the resource, managing inventory levels, and also appropriately capitalizing when it comes to the infrastructure?
Yeah, Jeff, I think what we've stated is today we like our pace in both places. We've done some strategic tests at the half section level in the Midland Basin, and you're seeing the results of those that we're now integrating into the wells we're drilling now. It's making a big impact by being able to incorporate the learnings and the data and the work we're doing. Ultimately, it boils down to how do you develop these sections? We've got to get the completions fully optimized. You've got to get your patterns right, numbers of wells, and those things. Taking the time to do it, taking the time to analyze the data, and then coming back, because you can always drill more wells, but you can't take away any that you drill. We like the pace we're on there.
I think we're going to be able to accelerate into that As time progresses, the second thing we're doing, as you've seen by getting out and testing the Wolfcamp C, we're testing other benches, and we're also testing other portions of our acreage that, when we've given our location counts in the past, we've been very conservative. We've got a lot of acreage in the Southern Midland Basin there that's highly prospective and others would consider core. Some of that's continuing to test those. You'll see us continue to ramp that activity over time. We could handle many more rigs than we're running there today, but we like the pace. Similarly at Alpine High. What's unique about it is we've got 6,000 feet of rock over a 70-mile area.
Obviously, we're doing what we need to do to earn and hold the acreage as well as build the infrastructure. A lot of that pace has been driven by the wet gas side early on, because that's what we need the infrastructure for, is to process the wet gas. The oil is easier, and it's also in the shallower zones. From a pace standpoint, we like where we are. I think when we get something done with the midstream, which we're confident we will do, it's going to give us some more flexibility. We like the balance we have, and what the whole portfolio brings.
Thanks for that. My follow-up is just on the completions optimization you mentioned. Is there any additional detail you can give us on the Midland spacing and stage design sides? Any comments on that? If there's anything else to watch for in terms of testing in the near term would be helpful.
In general, I'd say just keep watching our results. We've done a lot of work with fiber and a lot of technology that is helping us with things we're doing. We're working on the optimization side. A lot of it has to do with the clusters and some things there, so, and spacing. Not necessarily just more sand, it's just placing it in the right places, doing things to understand our frack geometry and understand the reservoir. I think once you align those two, you get smarter, and it helps you optimize. I don't know, Tim, if there's anything you want to add?
Yeah, just a little color to add to that. Really, it's allowing us to maximize our available pump time and the cost reduction. We're seeing about a $220,000 cost reduction per mile of lateral length, so it's very significant. Of course, that reduces the time it takes to get our wells back online. We've done early results. We've done dip in fiber, and we've done some modeling work, and we're seeing equivalent or better inflow from these wells. Another thing that we've done also is we've paid very close attention to our pad moves, and we've been able to take 20 hours off our pad moves from rigging down to moving to rigging back up. With 42 pads a year, that's about two months of frack crew time that we can eliminate.
Great. Appreciate the detail.
Your next question comes from the line of John Herrlin with Societe Generale.
Yeah. Hi. I have some unrelated ones. With respect to the monetization of the Alpine High Midstream, are you still planning to keep a large equity stake? You had mentioned that, I think, in the past.
Yes, John. Clearly, when you look at, Steve alluded to it in his comments, I had mentioned it, we are deep in a process. It is going very well, there's a tremendous amount of interest. I think the thing that we recognize is that this asset is unique because of the column that we have. We've got 6,000 feet of pay. Really, the value of this infrastructure is going to grow significantly over the next five, six, seven, eight years. Unlike other midstream assets where you're developing one or two zones, this has a built-in set of wells and capital that's going to drive value. We will want to hang on to a large piece of the equity and keep that exposure, because ultimately, it's our upstream capital that's going to be driving that. We're very encouraged.
I think we're going to be able to maintain control. I think we're going to be able to eliminate the future spend, and I think it's something that's going to be value accretive for our shareholders.
Okay, great. Next one is on the improvements in the fracking that were mentioned. How much of it was development-related versus how much of it was design related to the wells specifically?
Well, that question, they go hand in hand because your design is impacted by your development. I think that's the point is by getting into the pads with the pattern and the spacing tests, I'll say it again, we're doing a lot of things with fiber and a lot of high-end things with the microseismics and others and the tracers, which is letting us better understand the frack geometries, and what you're doing there. I think those are the keys, is understanding the rock, understanding the well spacing, understanding the number of landing zones. As we've said, you take the rock, it's not as generic as everybody wants you to believe. You can move over in some areas, Wolfcamp A and Wolfcamp B are separate. Some areas are going to communicate. You have to go in and do the work and test the rock and understand it.
I think once you start to grasp where the geometries are, then you can optimize those. It really goes hand in hand, and it's why we stress the importance of the section and pad-level development and return metrics.
Great. Last one on Egypt. When do you think you'll have all the seismic done and processed?
We're making good progress. This is going to be ongoing for quite some time. We've got two brand-new concessions. We're highly excited about what it's going to bring on the new acreage, as well as what the new technology brings on our existing acreage. If you go back and look, Ptah and Berenice were two discoveries we had in late 2014, which really enabled us with a 25-30 wells to pretty much keep our production flat on the old side and grow it. That's really a stratigraphic trap sitting right under our nose out there. We're really excited about what the new broadband's going to do. It's something we're going to be doing for a while.
It's going to go on into 2019, 2020 potentially before we get all of it shot, but we're getting a lot of it back right now. We've hydrated the areas, and it's going to have an immediate impact on our drilling programs.
Great. Thanks, John.
Thank you.
Your next question comes from the line of Charles Meade with Johnson Rice.
Good morning, John, to you and your team there.
Good morning, Charles.
Yeah. I wanted to ask, to go back to these, the four-well Chinook pad, and that looks like it was one of the encouraging results out of Alpine High, and I'm wondering if you can elaborate a bit on how those well results fit with what you expected going in. I imagine you guys are still learning new things at Alpine High, and will be for a while, and I'm wondering if you could talk about if your results at Chinook changed anything about the way you guys are seeing the resource there.
Well, the thing I would say about the Chinook pad, number 1 is, in industry vernacular, those would be child wells because we've already had parent wells in the section. We're really pleased. It shows you the spacing assumptions. It shows with us getting into the pads. The cost is the big thing. We've always talked about Woodford, I think everyone acknowledges it's the best source rock in the world. The key here with us and what's going to differentiate Alpine High is going to be the cost structure. I think getting the well cost down, starting to be able to put the patterns in place, and then seeing the results. Quite frankly, we still are working through the infrastructure build-out and bring up. We got a lot of things on last quarter, but we still don't have everything opened up fully.
The well results, they look very good. They're very encouraging. I think spacing, we've been conservative. It kind of confirms we've been conservative on our spacing assumptions, and there's just a lot of rock and a lot of landing zones, and we're thrilled with the results. Those are short laterals too.
Got it. That's helpful detail, John. Secondly, this might be going a little bit further down the line. I appreciate your comments about how you guys are going to look at what you're going to do with extra cash if and when it shows up. When you get to the point where you're evaluating adding to capital spending or adding to your activity levels, do you have any thoughts you can share now about where in your portfolio those added dollars and added activity would go?
Clearly it's going to go into returning those dollars to shareholders. Then two, it's going to go into the discretionary or what we'll call the impact areas, and those are going to be the oilier, and more liquids-rich portions of Alpine High or into our Midland Basin or Delaware Basin. Those are the areas. We've got a lot of very encouraging results, and we're going to have a pretty big pick menu to choose from. Very excited.
Thank you, John.
Your next question comes from the line of Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
Wanted to ask on the CapEx trajectory for the rest of the year. I think you highlighted that one of the reasons for first quarter CapEx being a little higher was some of the efficiencies that you're seeing. You maintain the full year budget. How do you see the rest of the year playing out, and is there a decision that would need to be made if those efficiencies continue in terms of letting that lead to higher CapEx versus potentially reducing activity?
Well, first of all, we did come in a little hot. We ended up keeping 100% of Garten. That was the last well we drilled with the WilPhoenix, and I think we all celebrated when we finally ended that three-year rig contract. It's going to be very helpful going forward in the North Sea on our CapEx numbers. Honestly, one of the other factors has been the completion time, and as Tim alluded to, we've eliminated a lot of time in terms of between pad moves and things. One of the things is you're always seeking to strive that balance, completion crews with rigs and rig count. Efficiencies, they don't run in parallel all the time. Our completions have taken a step forward. It's enabled us to choose some days off and pull some wells forward.
We will have a decision to make if on the drilling side, the pace doesn't quicken there, which that could happen as well, then we will have a decision to make on do we add another rig or two with our frack crews? It gives you some flexibility. We've got some time in the schedules right now, and later this year we'll have to make a decision on that.
Great. Thanks. Then my follow-up is back to the midstream monetization. Can you talk at all about the type of long-term contracts or commit-
intuitive there to be successful with your monetization plans?
Well, I think, first and foremost is it's a very thoughtful process where there's a lot of due diligence being done on us, and we're doing a lot of due diligence on the potential partners. You won't see big volume commitments. You'd see acreage dedication. Quite frankly, you'll see us controlling. We're open to what the structure looks like. We recognize that infrastructure investment really should sit in a different structure where there is a different true cost of capital. We also recognize that we want to maintain as much of that equity as we can because of the value we're going to create with our capital spend from the upstream side. I think very creative and the parties we're talking with, and the potential structures vary. I'm very encouraged by where we are. We're very deep into the process.
There's a tremendous amount of interest, we're very confident that we will do something very attractive, in 2018.
Great. Thank you.
Thank you.
Your next question is from the line of Leo Mariani with NatAlliance Securities.
Hey, guys. Just wanted to follow up quickly on the Garten discovery. You guys talked about having 700 feet of net pay there in multiple reservoirs. Obviously, that's a very significant number. Is there any type of ballpark contribution that we should think about here? Can this thing do 10,000 barrels a day of oils or work our way into 2019? Anything you can sort of say along those lines?
Leo, it's very material. We have 700 feet of pay. This is in the Beryl sands, which is some of your most prolific sands there. It's got a lot more scope to the structure than something like Callater has. We did not find water saturations. We kept drilling, and quite frankly, we could've kept drilling deeper. It's going to be pretty material, and we'll come back with that. We just haven't given any color or any guidance, but you see very high-rate wells come on. This will be light oil, and it'll be pretty impactful to our Beryl area. I think the important thing is we own 100% of it.
All right. That's helpful. I guess just jumping on in here. Obviously, you guys talked about your methodical plan to really focus a lot on the wet gas and Alpine High in the short term. You got to get those volumes up to get the infrastructure sort of working. As you think through the three-year plan, just trying to get a sense of whether or not you start to see more of a shift to oil. Is that a more of a 2019 move than Alpine High, or is it more 2020? What can you sort of say about the way you progress the development in terms of phase?
Well, I think the important thing is we've got a very rigorous plan. As we've stated, we've kind of put Alpine High in three settings. There's actually a couple more than that, but we put it in the northern flank, the crest, and the southern flank. Two things I'll say. Number 1, the northern flank, the acreage is more checkerboarded, so we're drilling shorter laterals, and we have more near-term lease obligations. Also is where the dry gas window is at the bottom of the Woodford. You've seen some of our early capital tilted there. As we move to the crest and to the southern flank, we move up the column and actually at Alpine High, if you remember, it gets a little cooler in the southern flank, which will also yield more liquid and potential for oil.
I think you're going to see just the Woodford and the Barnett as time moves on. They're going to get more oily. They're going to get more liquid rich, and they're going to get more rich gas. Secondly is, as we've stated, there is a lot of proven oil. We've shown that. We had five pair sequence wells. There will be more, and quite frankly, with our discretionary capital, we will continue to advance those. We've said all along that we plan conservatively with Alpine High, and it will get more oily as time progresses. You'll see more from us.
All right. Thanks, guys.
Thank you.
Your next question is from the line of Douglas Leggate with Bank of America.
Thanks. Good morning, John. Good morning, everybody.
Good morning.
John, I got one in the Permian and one on Egypt, if I may. Starting with the Permian, the comment you made about Wolfcamp C and expanding the inventory, obviously you're clearly doing the right thing delineating and securing your acres in Alpine High. At what point would you have greater flexibility? Obviously when you started this process, oil wasn't trading where it is with the kind of differentials we're seeing. I'm just curious how you think about on a sort of one, two, three-year view, how your incremental spending will switch between the Midland Permian versus the Delaware Permian, given the potential increase in location count.
There's no doubt over time you will see more from us on the incremental side. It's going to be going in two places. It's going to be going into the oil zones, at Alpine High. It'll also be going into the Midland Basin. Part of that, Doug, is making sure we have the infrastructure in place in both places where we are maximizing the returns. In the end, it's the returns that matter more than the top-line oil production. The beautiful thing about Alpine High is that we have exposure to Dry gas, wet gas, and obviously oil and a lot of rich gas.
Clearly, as we get the infrastructure in place, and we get more of the infrastructure in the Midland Basin in place, we're going to have the flexibility to toggle and put that in incrementally where we think it's going to drive the best returns.
I don't want to labor the point, but obviously oil's up a bit. You've been extremely capital disciplined, but it seems you have a lot, like you did today, it seems you've got a lot more flexibility to pivot to the oil opportunities you have today. Are you sticking with your spending budget or were you tempted to pivot a little bit more to oil in the near term?
Today, what we reiterated is our spending budget. We came in a little hot, as we said, on the completion side. If we were to change that, we would obviously come back and give you some guidance on that. Today, we increased our guidance on our current CapEx budget. It is going to be a little more oily because of the performance that we're seeing. Clearly, we've got things that we can do. It is a good situation.
My follow-up, and hopefully I won't take too much time on this, but a few years ago, actually probably seven or eight years ago, we published a detailed report on Egypt talking about how you'd cracked the code with seismic and the legacy you had there and so on. My question's really about, in this oil price environment, I think most people think of Egypt as a cash cow to feed the onshore U.S. I'm just curious how you think about Egypt's relative competitiveness as potentially a more meaningful growth area. We don't normally think about conventional location count, at least I don't think U.S. investors do in the context of the Permian. What is the opportunity set like, and why wouldn't you accelerate given the very favorable PSC you have over there? I'll leave it there. Thanks.
Well, clearly, Doug, you hit on all the key points. Egypt is great rock. It's kind of Permian with conventional delivery. Clearly with two discoveries, Ptah and Berenice, we're producing tremendous volumes over a three-year period and still are today, about 30,000 barrels a day. We think we see Egypt as a place where we can continue to grow the oil volume, and grow the cash flow. We think it's a place we can have our cake and eat it, too. That's why we're investing in the new state-of-the-art 3D, and I think it will uncover many opportunities that we can tie back into infrastructure. We see Egypt as an area that in the future we can do both grow and grow the free cash flow.
John, how quickly do you get your money back from the PSC?
Depends on the well. Some of those are very short.
Great. Thank you.
Our final question comes from the line of Michael Hall with Heikkinen Energy Advisors.
Thanks. Good morning. Just a couple quick ones on my end. I guess first on the Wolfcamp C result in the Midland Basin, commentary there of several hundred additional potential locations from that well. I'm just curious what other work you've done on your acreage to assess the Wolfcamp C and what sort of follow-up activity we should expect on that front?
Yeah, Michael, first of all, we're very excited about the well. There have not been a lot of Wolfcamp C wells drilled to date. Keep in mind that this is just a mile lateral, and had good 30-day IP. We've mapped the Wolfcamp C, and we've got tens of thousands of acres underlying it. We feel very comfortable that we're going to have quite a bit of inventory that will spin off from this. As I mentioned, it's very early days and we're still evaluating.
Any plans in the near term to follow up that initial result with additional tests?
Yeah. We're going to evaluate this well right now. This is at Azalea, and we've got other areas that we do want to test the Wolfcamp C as well.
Okay. Then another topic, I guess, just following up on the infrastructure, or the marketing detail you provided on the gas side. I'm just curious, those percentages that you provided, are those on current volumes, planned volumes, or how should we think about those?
Those are planned annualized volumes for 2018, for the full year.
Okay. What are the term lengths on the contracts and dedicated sales? Any color you can provide there?
Yeah. They're all over the place. It's a whole portfolio of contracts, because this is the entire Permian Basin.
Sure.
What we provided in this, and just to be really clear, is that any contract that expired or would expire during this year is included in the uncommitted. That portion of it is included in the uncommitted production wedge.
Okay. That's helpful. Appreciate it. Thanks, guys.
Thank you.
This does conclude our Q&A portion for today's call, and I would like to turn the call back over to CEO, John Christmann, for any closing remarks.
Finally, I'd like to thank you all for joining us today. I want to leave you with three key takeaways. First, Apache's off to a great start in 2018. We established a new Permian Basin production record, exceeded U.S. production guidance in the first quarter, and raised our outlook for the remainder of the year. Second, we're realizing greater capital efficiency through cost control and continuous productivity improvement. This is a direct outcome of our methodical approach to delineation and development, our application of technology, and our measured activity pace in the Permian Basin. Lastly, we are very pleased with our progress toward completion of an Alpine High Midstream transaction, which will enable us to return additional capital to shareholders and/or increase our upstream investment program. That will conclude today's call.
If you have any follow-up questions, please reach out to Gary and his team. We look forward to reporting on our progress next quarter.
Thank you for your participation. This does conclude today's conference call. You may now disconnect.