© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good afternoon. My name is Thea, and I will be the conference operator today. At this time, I would like to welcome everyone to the Apache Corporation fourth quarter 2017 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.
Thank you. At this time, I would like to turn the conference over to Gary Clark. Please go ahead.
Good afternoon and thank you for joining us on Apache Corporation's fourth quarter 2017 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.
In conjunction with this morning's press release, I hope you have had the opportunity to review our fourth 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 noncontrolling interest in Egypt and Egypt tax barrels. Also please note that with our exit from Canada, forward guidance and future quarterly reporting will refer to the United States or the U.S., and we will no longer use the term North America.
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.
Our prepared remarks will run a bit longer today, as we have a lot of information to cover with fourth quarter and full year results, as well as our three-year outlook. So we will extend this call past 2 o'clock in order to accommodate 30 minutes of Q&A.
And I will now turn the call over to John.
Good afternoon, and thank you for joining us. On today's call, I will begin by discussing Apache's approach to the current environment. Then I will highlight our 2017 accomplishments and provide an overview of the fourth quarter before turning it over to Tim and Steve for more details. And finally, I will close with commentary on our 2018 to 2020 outlook.
Early in 2015, we focused Apache on a path that creates real value for our shareholders over the long term and through the commodity cycles. The foundation was underpinned by cost and capital discipline. And we linked our compensation plans accordingly. This approach has driven our actions through a very challenging period. Specifically, we have streamlined our portfolio, reduced capital investment, increased capital productivity and efficiency, and reset the corporate and operating cost structure.
By choice, we allowed production to decline rather than chase growth in an environment that was mostly value destructive. This disciplined approach enabled us to cost effectively lease and quietly discover a world-class unconventional resource of scale and to direct our limited additional investments to improving long-term returns. We were also able to maintain our dividend, while many in the industry were reduced or eliminated.
Moreover, we strengthened our balance sheet by reducing debt and avoided diluting our shareholders' long-term value by electing not to issue equity to pursue expensive acreage acquisitions or to fund an outsized capital program.
We have been clear in our belief that an E&P company, over the long term and through the commodity cycles, must be able to do the three things that leading companies in mature industries do, live within cash flows, grow the enterprise through prudent investment, and return capital to shareholders through a competitive dividend and/or share repurchases. This is the path that Apache is on now. And we have assembled the team and the portfolio to do so for decades to come.
Our current investment programs are directed at building the optionality over the next few years to maximize the value of that portfolio. Specifically, at Alpine High we are building out a world class resource play that will change the course of Apache.
The expanse of the opportunity in terms of acreage and hydrocarbon column will drive capital investment and very soon, free cash flow for decades to come. The capital program in short order will bring forth the capacity to deliver oil, gas, and NGLs at scale to the rapidly growing market on the U.S. Gulf Coast.
The midstream infrastructure capital program at Alpine High is a critical piece to the story for the near term. We must strategically control the build-out of the infrastructure to meet the needs of the upstream. We do not need to own 100% of these assets for the long term though. And we are studying strategic alternatives that will ensure we capture the value we are creating and will free up cash flow by eliminating future capital.
In the Permian Basin, outside of Alpine High, we have proven the quality of our inventory and are now well-positioned to profitably grow oil volumes for many years to come.
Internationally, the North Sea and Egypt are very well-positioned to serve their primary strategic purpose, provide free cash flows back to the corporation for many years to come. And we still have a tremendous amount of running room.
In Egypt, we've increased our acreage footprint by 40% with two new concessions and are conducting a large scale broadband 3D seismic survey that will set up growth opportunities for the future. In the North Sea, we have a sizable inventory of development locations and exploration prospects around our existing infrastructure. And in Suriname, we have two highly prospective blocks that are on trend with recent discoveries in an emerging world class oil basin.
In the relatively near future, we will have significant optionality across the portfolio, especially in the Permian Basin, to direct investment across an extensive highly economic portfolio to produce oil, gas, or NGLs.
At that time, the Permian Basin will be generating substantial free cash flow, which will bring another dimension of optionality. Those cash flows could be directed to any of the following, further accelerate the pace of Permian development, fund growth opportunities outside of the Permian, which may have been deferred due to Alpine High funding requirements, and return of capital to our shareholders.
The future allocation and prioritization of how those cash flows will be utilized will be determined by what we deem to be in the best long-term interest of our shareholders. This is the strategic direction of Apache today.
2018 promises to be a very interesting year. Our industry is at a critical inflection point following three years of depressed commodity prices and disappointing returns in terms of both return on and return of capital.
Today, we are in a more constructive oil price environment. And the market is watching carefully to determine whether E&P companies will maintain discipline and focus on long-term returns or revert to the historical norm of a singular focus on top line growth. For the industry to adopt a more rational approach to balancing optimal risk adjusted returns and growth, management incentives must be appropriately aligned.
Consistent with that, investors are now seeking key changes to executive incentive compensation programs. Shareholders are advocating for the inclusion of absolute return metrics and programs historically more heavily weighted toward relative returns performance. They are also insisting that growth related metrics be calculated on a debt adjusted per-share basis.
As I indicated, Apache restructured its compensation philosophy three years ago that clearly linked our long-term compensation as closely as possible with long-term shareholder value. It was also the best way to align our entire organization with our strategic direction.
Specifically, our long-term incentive program has taken a balanced approach, with 50% based on relative TSR and the other 50% based on two metrics, which are highly correlated with absolute returns. The targets for these latter metrics are agreed with the board on an annual basis and reflect corporate objectives that are consistent with the economic environment at the time and the context of the long-term strategy of the company. We align those metrics every year. And therefore, they have no inherent bias for subjective growth targets.
Turning now to our 2017 highlights. It was a great year of progress for Apache, marked by several important advancements that position us for strong performance in the years ahead.
Following two years of curtailed capital investment, our Permian Basin production volumes entered 2017 in decline. Notwithstanding this slowdown, we have made and continue to make significant progress on many fronts, consolidating our land position; investing in science, data collection, and strategic testing; improving our drilling and completion capabilities; confirming additional landing zones; conducting important pattern and spacing tests at the section or half-section level; and testing shallow zones at Alpine High and other unconventional oil opportunities in the U.S.
In 2017, we returned the Permian Basin to a growth trajectory, exclusive of Alpine High, with a relatively limited capital program. And clearly demonstrated that Apache possesses high-quality acreage and can deliver leading well results.
Notably, our total Permian Basin production reached a record high in the fourth quarter, exceeding the previous high set two years ago in the fourth quarter of 2015. This achievement occurred just two quarters after Permian production reached a four-year low in mid-2017.
As a result of the operational progress we made and the now proven quality of our inventory, we anticipate sustained, high return growth from the Permian for many years to come.
In the Midland Basin, we have both a technology and execution success story. We are applying state-of-the-art capabilities to reduce drilling and completion time, locate wells more effectively within landing zones, and more efficiently stimulate the productive interval.
In the second half of 2017, we began to significantly increase our average lateral length, which will continue into 2018, as 85% of our wells are planned for 1.5-to-2-mile laterals. We are very excited about our recent Midland Basin results and will continue to advance and leverage these key learnings for the future.
At Alpine High, we initiated first production ahead of schedule in May and ramped production volumes steadily through the year, as we commissioned infrastructure and connected wells. We increased our inventory of risk locations to more than 5,000 and initiated our first true multi-well pads and pattern tests, which will drive increasing capital efficiencies into the 2018 program and beyond.
We are pleased with these results and have begun to climb the learning curve with our development program, which will deliver well cost and productivity improvements in the future.
Internationally, as I mentioned earlier, we added significant new acreage in Egypt. And we are moving forward with our exploration program in Suriname. Both of these areas bring significant future prospectivity to Apache.
In 2017, we implemented a number of cutting edge technology initiatives across our operational footprint. The continued evolution and application of technology is vital to our industry. It will drive efficiency gains, inventory expansion, higher returns, and performance differentiation among E&P companies.
Apache has long been a leader in technological innovation. And the recent addition of Mark Meyer as Senior Vice President of Energy Technology Strategies underscores the strategic importance of these initiatives.
Lastly, I note the excellent progress we made in the ongoing reshaping of our portfolio. We took advantage of the active market for leasehold in the Permian by divesting some non-core acreage packages at very attractive prices. We also completed our strategic exit from Canada.
These actions, combined with the ongoing investment at Alpine High, represent a large scale, multiyear portfolio rotation that will be extremely accretive to capital efficiency, recycle ratios, and most importantly, long-term returns.
Moving now to fourth quarter results, Apache finished the year on a positive note with its second consecutive quarter of profitability. In the fourth quarter, we delivered strong adjusted EBITDA and cash flow, demonstrating our leverage to improving oil prices. Operating and G&A costs decreased from the third quarter on a unit basis. Capital spending was on plan. And U.S. production was at the high end of our guidance range.
Internationally, we had some mixed results. Both Egypt and the North Sea benefited from improved Brent pricing and delivered combined cash flow from operations of nearly $0.5 billion and significant free cash flow. In Egypt, we continued to deliver excellent drilling results and achieved more than a 90% success rate during the quarter on 25 new wells.
In the North Sea, following a long run of success, we encountered a few challenges. An unscheduled shutdown of the Forties Pipeline System, an unexpectedly tight producing formation in our CB1 Callater offset well, and an exploration dry hole on a long standing obligation well combined for a disappointing quarter. The result was lower production volumes in the quarter and a lower trajectory going into 2018.
Despite these setbacks, the North Sea remains a vital, high return business for Apache. We have two existing discoveries in development planning and a deep inventory of attractive tie-back prospects.
In the U.S., we had a very strong quarter. All of our growth came from the Permian Basin, where production increased 10% over the third quarter. At Alpine High, we commissioned our fifth central processing facility at the Hidalgo site and achieved our year-end production target of 25,000 BOEs per day.
This flow rate was temporary, as we subsequently shut-in some production for a scheduled expansion at the Dakota central processing facilities.
For the quarter, production averaged 20,000 BOEs per day. Midland and Delaware Basin oil production exceeded the high end of the guidance range we established a year ago. This was driven by a combination of strong well performance, a significant number of new wells placed online in the Delaware Basin, and timing of some high impact, half-section spacing tests in the Midland Basin.
With that summary of our fourth quarter results, I will now turn the call over to Tim, who will discuss operational details of the fourth quarter and our 2018 activity plans.
Thank you, John. My remarks today will include operational activity in key wells in our U.S. and international regions, planned activity levels by play for 2018, and I'll conclude with commentary about the use of new technology throughout the organization.
Operationally, we had a good year and continue to improve in key areas. Our fourth quarter production results continue the growth trajectory established in the third quarter.
In the U.S., fourth quarter production averaged 222,000 barrels of oil equivalent per day, up 7% from the third quarter. U.S. oil production increased to 98,000 barrels of oil per day, an 8% increase from the preceding period. Much of this growth was driven by continued success in the Midland Basin.
At the Powell field in Upton County, we brought online 20 wells from three pads with an average 30-day peak IP of nearly 1,400 BOE per day. These wells were drilled to the Wolfcamp B formation and are comprised of 1.5- and 2-mile laterals, producing in excess of 75% oil. These are half-section spacing and pattern tests, designed to methodically and scientifically determine the optimal development plan for the area.
We continued to make good progress on drilling, completion, and cost optimization, as we use capital more efficiently with larger well pads and longer laterals.
In the Midland Basin, we have reduced drilling and completion costs 20% over the last 12 months on a treated lateral foot basis, while production volumes improved 17%. These results give us confidence that we can continue to improve here and elsewhere in the Permian Basin.
As John mentioned, we are moving to more pad operations at Alpine High. The Dogwood State pad is a six-well spacing test located in the northern flank and was selected due to retention requirements. These are dry gas wells on 660-foot spacing drilled in the Barnett and the Woodford formations to a total vertical depth below 13,000 feet. This pad has produced more than 2 Bcf in just 49 days and is currently producing approximately 75 million cubic feet per day.
In the Central Crest, the two-well Elbert State pad drilled the Woodford formation at a TVD of approximately 9,800 feet, nearly 4,000 feet shallower than the Dogwood [State] pad. As projected from our thermal maturity model, these wells produce wet gas and oil and averaged a 30-day peak IP of 1,175 BOE per day with an oil-gas ratio greater than 60 barrels per million cubic feet. Drill, complete, and equip costs for this two-well pad averaged $6.2 million per well.
As we move to pad operations at Alpine High, we are realizing the benefit of reducing cost and increasing efficiencies. On the drilling side, these include using less expensive spudder rigs to drill the surface and intermediate hole; batch drilling operations with walking rigs; casing design optimization with standardized production casing, and in some areas, the elimination of an intermediate casing string; substituting oil-based muds with less expensive brine drilling systems; customized bit and bottom hole assemblies; and the use of rotary steerable equipment to increase penetration rates in the lateral section. These efforts have reduced spud-to-TD times in some cases to under 15 days.
On the completion side, pad operations have also led to the following cost and performance benefits, pumping more frac stages per day, optimized sand loading to pattern size, recycled and brackish water use, higher pump rates allowing for gel elimination requiring lower horsepower, and pads also allow us to verify confined stimulation intervals with tracers and micro-seismic.
Through these efforts, we have brought down our costs considerably, and we expect costs to continue to decrease from an average of $8 million last year, where we were heavily invested in science and data collection, to $6 million this year. Ultimately, we anticipate well costs will be closer to the lower end of the $4 million to $6 million range we provided in 2016.
Elsewhere in the Delaware Basin, we brought online seven wells in our Dixieland field in Reeves County and five wells in Eddy County. These wells have targeted four separate landing zones in the Bone Springs and Wolfcamp formations with impressive peak 30-day IPs ranging from 1,100 to nearly 2,200 BOE per day.
And in the Anadarko Basin, we completed the Scott 33, a five-well pad in the Woodford SCOOP play. These mile laterals are producing in excess of 1,700 BOE per day with an oil-gas ratio in excess of 50 barrels per million cubic feet. Drill, complete, and equip costs for this pad averaged approximately $8 million per well.
Internationally, our Egypt and North Sea regions continued to generate excellent free cash flow, benefiting from the recent price increase for Brent Index crude oil. In Egypt, highlights for the quarter include the Ptah 18, a development well in the Faghur Basin with a 30-day IP in excess of 3,400 BOE per day, all oil. Also, two exploration tests in the Matruh Basin, the Herunefer West-4X and the Chelsea-1X, were both discoveries in the upper Safa formation with a combined test rate in excess of 14,000 BOE per day, producing 58% oil. Both wells set up additional development and step-out exploration opportunities.
For the full year, Egypt delivered a success rate greater than 80%, completing 88 net wells, of which 40 had test rates greater than 1,000 BOE per day with 87% oil. These are low-cost vertical completions and generate very attractive returns.
In the North Sea, fourth quarter production averaged 58,000 BOE per day, as volumes from the Forties field were impacted by the unscheduled shutdown at the third-party operated Forties Pipeline System.
The Callater field, a subsea tieback to the Beryl facilities, came online in mid-2017, and with the addition of the recently drilled CB1 well is currently producing on a gross basis 17,000 BOE per day, 43% oil. Please refer to our financial and operational supplement for more details on the fourth quarter.
Now I will move to our 2018 capital program, beginning with the U.S. The Permian Basin remains the focus of our activity in the year ahead, with approximately $1.6 billion being directed to this region, or roughly two-thirds of our annual upstream budget. We plan to operate 13 to 15 rigs during the year, with six to seven at Alpine High, three elsewhere in the Delaware Basin, and four to five in the Midland Basin. We also expect to run four to six frac crews during the year, split primarily between Alpine High and in the Midland Basin.
At Alpine High, we plan to drill 85 to 95 wells during 2018. And this will comprise approximately 50% development retention wells and 50% delineation wells. For perspective, to date we have drilled a total of 118 wells at Alpine High, of which 48 were online and producing at year end. Our retention program is crucial, as competitor activity around us has increased significantly, with more than 170 wells drilled or permitted by other operators since we announced Alpine High in September 2016.
Importantly, drilling to the deeper Woodford formation allows Apache to retain drilling rights for all zones above it. Additionally, the wells drilled to the deeper source rock provide data needed to optimize the build-out of our infrastructure and shape the full field development plan at Alpine High.
In the Permian Basin outside of Alpine High, we are planning a balanced drilling program of approximately 55 to 60 wells in the Midland Basin and 45 to 50 wells in the Delaware Basin. While we plan to drill a similar number of wells as last year, our average laterals will be increasing. And we expect to drill 15% more total lateral footage. These plays are predominantly oil.
Our capital program for the international regions reflect their role in our portfolio as free cash flow generators to fund reinvestment in the Permian Basin. Our 2018 planned capital investment here is approximately $690 million. This will provide for continued cash flow generation from Egypt and the North Sea regions, though we expect some natural field decline at this investment level.
Our 2018 capital program anticipates a moderate level of service cost inflation, approximately 10%, and we are managing this carefully. We have already contracted most of our rigs, pumping services, and sand required to execute the plan in the year ahead, avoiding the premium being paid currently with ramped up activity for many services. Higher costs are more likely to be seen in ancillary services in the Midland and Delaware Basins and will be more difficult to offset because of industry-wide activity levels.
In spite of the inflationary trends, we are well-positioned at Alpine High for a step-change reduction in our cost profile as we scale up our business. Throughout our organization, we are applying new technologies and creating new tools that are improving how we work. These apply to subsurface, drilling and completions, production, and supply logistics groups.
We are increasingly applying big data analytics across the company. We continue to lead the way in the development and application of simultaneous seismic sources, both onshore and offshore, the result of which has allowed us to save millions of dollars in exploration costs, greatly reduce the time to collect, process, interpret data, and realize large improvements in data quality.
We have developed a drilling intelligence guide app that gathers high-frequency data from sensors on the rig for use in prediction and avoidance of downhole issues. We have also developed workflows and developed technologies that allow us to rapidly characterize thousands of feet of core and quickly get this information into the hands of the project geologists and reservoir engineers for rapid characterization of our shale plays and landing zones.
Along with our ongoing efforts on oil fingerprinting, we are building a far more robust understanding of our shale plays and their performance. We're using multiple sources, such as fiber optics, micro-seismic, and 4D seismic, all of which are providing unprecedented insight into our formation stimulations, leading to optimized reservoir development.
We've built new state-of-the-art water treatment facilities, including highly engineered water storage pits, both in the Midland Basin and Alpine High areas, that directly add value to our projects by reducing water costs and in increasing both reliability and flexibility in our operations.
We're using remote operating centers that utilize real-time data to optimize well performance, allowing immediate reactions to changing circumstances. These data-driven decisions help deliver operational improvements and increase efficiency.
The combination of data analytics technologies and advanced machine learning inform and validate our decision-making processes and operational strategies. As John mentioned, we expect technology will play an increasingly vital role in our future exploration and development progress.
In conclusion, 2017 was a very good year. We achieved 124% production replacement rate from E&D adds net of engineering revisions. We returned to growth in the Permian Basin, advanced Alpine High, and generated robust free cash flow from our international regions. 2018 will be an extension of these efforts, as we continue our operating and capital cost discipline and our commitment to returns-focused growth.
I will now turn the call over to Steve.
Thank you, Tim. Today I will highlight Apache's fourth quarter and full year 2017 financial results, discuss our 2018 outlook, comment on cash returns and return on capital employed, update our Alpine High midstream progress, and briefly review our hedge positions.
Before I get to these details, let me first review a few of the company's key financial achievements in 2017. Apache returned to profitability in 2017, both on a GAAP reported basis and on an adjusted earnings basis. We reduced our absolute level of debt and our net debt, ending the year with more cash on hand than we began with. We retained our investment-grade credit rating.
We returned nearly $400 million of capital to shareholders through the dividend. And asset sales generated $1.4 billion of proceeds and eliminated approximately $800 million of future asset retirement obligations.
In 2018, we will continue to maintain a strong balance sheet, direct our capital investments for value and long-term returns, and take important next steps to progress Alpine High into full operational mode, so we can return to living within cash flows as we prefer.
Through all of this, we will also continue to return capital to our shareholders, which is an underappreciated aspect of Apache. Over the last three years, we've returned over $1.1 billion to shareholders through the dividend. For the next three years, we plan to return at least this amount, and possibly more, through the dividend or through share buybacks.
Turning to our fourth quarter and full-year results, as noted in our press release this morning, under Generally Accepted Accounting Principles, Apache reported fourth quarter 2017 net income of $456 million or $1.19 per diluted common share.
Results for the quarter include a number of items that are outside of core earnings and are typically excluded by the investment community in published earnings estimates. The most significant of these is a $306 million deferred income tax benefit from U.S. tax reform. Excluding this and other less material items, our adjusted earnings for the quarter were $126 million or $0.33 per share.
For the full year 2017, Apache reported GAAP net income of $1.3 billion or $3.41 per share. And adjusted earnings of $92 million or $0.24 per share.
With respect to U.S. tax reform, the $306 million tax benefit recorded in the fourth quarter reflects the impact of the Tax Cuts and Jobs Act enacted in 2017. This represents the combined impact from the deemed repatriation provision and the reduction in the corporate income tax rate from 35% to 21%.
This is a provisional assessment of the U.S. tax reform. And we continue to assess its full impact. Importantly, as we have indicated in the past, Apache is not currently a cash taxpayer in the U.S. And given the carryforward of certain tax attributes, we do not anticipate this changing in the foreseeable future.
In terms of operational and financial results, key items such as North American and international production volumes, capital expenditures, LOE, DD&A, and G&A were consistent with or better than our latest guidance. Capital spending was $862 million for the fourth quarter and $3.1 billion for the full year. Throughout 2017, we further strengthened our balance sheet and liquidity position, ending the year with net debt of $6.8 billion and cash on hand of $1.7 billion.
Let me turn now briefly to 2018. We have provided more detailed guidance for the year in today's fourth quarter financial and operational supplement. I won't go through each component, but would like to highlight a few key items.
Our capital budget for 2018 is $3 billion, which is down slightly from 2017. We plan to invest $2.5 billion in the upstream and $500 million in Alpine High midstream. At current pricing, the upstream will be approximately cash flow neutral, inclusive of the current company dividend of $380 million. The midstream will operate at a cash flow deficit of approximately $500 million. This deficit could be significantly reduced or even completely eliminated in the event of a funding transaction involving the Alpine High midstream assets. It is anticipated that any cash flow deficit for 2018 will be funded through cash on hand.
For the year, Apache's adjusted production is expected to increase by 7% to 13%, consisting of 19% to 24% growth in the U.S. and a 3% to 10% decline internationally. Oil production in the Permian Basin is projected to grow by approximately 9%.
For the first quarter of 2018, U.S. production is expected to be around 223,000 barrels of oil equivalent per day. Adjusted international production is expected to average 135,000 barrels of oil equivalent per day.
So the first quarter will be flat to slightly down from the fourth quarter, before we return to a growth profile that will deliver the 7% to 13% increase for the full year that I just mentioned. This is the result of several factors, including timing of pad completions in the Midland Basin, as we placed three pads into production during the fourth quarter of 2017, but we only have one pad planned for the first quarter of 2018; mechanical compression issues on one of our Beryl facilities and further temporary outages at the Forties Pipeline System in the North Sea; production curtailment in the Permian Basin due to weather impacts and a temporary shutdown to rebuild a tank battery in the Midland Basin; and Brent crude pricing impacts on our Egypt volumes as a result of our production sharing contracts.
From a capital and expense perspective, first quarter should generally run at a quarterly pace of around 25% of the full year dollar guidance ranges. Exceptions to this would be capital expenditures will be around $800 million, cash exploration costs will be around $50 million, G&A expense will be around $120 million, and financing costs will be around $105 million.
Let me turn now to a discussion of returns, which as you know, is integral to how we manage our business. For three years now, we have been consistent in our approach to capital allocations. We fund opportunities that we believe will maximize long-term value and optimize long-term returns.
To reinforce this, we added a cash return on invested capital metric to our annual incentive compensation plan. We outline the specifics of how we intend to calculate this metric in our financial and operational supplement.
For 2018, we have established a cash return on invested capital target of 18%. Our performance against this target accounts for 20% of the entire company's annual incentive compensation. This measure of returns should improve by about 2% per year for the next few years.
Another important measure of returns we watch closely is return on capital employed. Just like the cash return on invested capital goal, we have added a strategic goal related to ROCE on our 2018 incentive compensation plan. That goal is to implement a long-term plan that returns the company to sustainable double digit ROCE.
Everybody has a preferred methodology for calculating ROCE with the most significant differences arising from the use of pre- versus post-tax income in the numerator and gross versus net debt in the denominator. Our preferred method is a numerator using adjusted earnings before interest and taxes and a denominator using average debt plus average shareholder equity.
Using this methodology, at flat pricing from today, our 2020 ROCE is projected to be around 10%. And this will continue to improve for the next several years after 2020. With the required start-up investment at Alpine High, improving ROCE will take some time.
Embedded in our forecasted ROCE is the assumption we continue to own, operate, and fund 100% of the Alpine High midstream infrastructure.
Although strategically critical and valuable, these investments tend to hold back returns as measured by accounting metrics. A transaction involving these assets could materially improve these ROCE estimates.
The upstream investment in due course will become the long-term engine for dramatically improving ROCE. While Alpine High may take a bit of time to attain critical mass, with its extremely low entry cost and attractive recycle ratios, it will drive significantly improved ROCE for Apache Corporation for many years to come.
Next I would like to provide some color on our Alpine High midstream operations, where we continue to make steady progress on multiple fronts.
Construction on these facilities began in November 2016. And the progress we have made in a little over a year is remarkable. Currently, we are operating 110 miles of gathering line, 45 miles of 30-inch trunk line, 21 central tank batteries, and 5 central processing facilities with inlet capacity of 330 million cubic feet per day. By the end of 2018, we anticipate reaching 830 million cubic feet per day of inlet processing capacity.
During the year, we plan to commence installation of centralized cryogenic processing facilities, which will add another 600 million cubic feet per day of capacity in 2019.
We have also begun implementing a takeaway strategy with the signing of an agreement with Kinder Morgan to access capacity on their Gulf Coast Express long-haul gas project from the Waha Hub to Agua Dulce near the Texas Gulf Coast. This agreement includes an option to participate in the project on an equity basis, which we believe will prove valuable to the midstream enterprise for the long term.
You can anticipate similar arrangements on the NGL and oil sides in the future. We recognize there is a wide variety of long-term strategic options for the Alpine High midstream assets, and we are giving these careful consideration. The inherent value of these assets comes from the massive long-term flow of hydrocarbons from Alpine High and the optionality that will create along the value chain.
Numerous parties have approached us with some very interesting ideas of how they might join us in the build-out of the midstream business. While it is likely these assets will end up in an enterprise separate from Apache, for both funding and for value optimization reasons, we currently anticipate owning a significant share of this enterprise for the long term.
Before turning the call back to John, I'll comment briefly on our hedging program. As a reminder, we do not engage in hedging to speculate on price. The purpose of our hedging program is to protect cash flows to fund the capital program at Alpine High.
For 2018, an average of 85,500 barrels of oil production per day currently have some form of hedging protection. 47% is in the form of puts, 37% is in collars, some with upside call options, and 16% is in the form of swaps. All of these hedge positions give the desired downside protection, and nearly 70% retain some form of upside potential, which we generally prefer.
While our cash flow sensitivity to natural gas price movements is considerably less than for oil, we did recognize risks associated with certain types of gas exposure. As such, we entered into both NYMEX gas price swaps and Waha basis swaps to eliminate some of the uncertainty.
To date, we have swapped an average of 237 million BTUs per day of NYMEX gas price exposure for 2018 at a weighted average price of $3.07. With respect to Waha basis, for all of 2018 and the first half of 2019, we have entered into swaps for an average of 156 million BTUs per day at an average basis differential of $0.51. We have also entered into a small number of Waha basis swaps for the second half of 2019. The details on all of our hedge positions can be seen in our financial and operational supplement.
This time of year, we also typically provide updated guidance on our cash flow sensitivity to changes in commodity prices. For 2018, we estimate that a $5 change in oil price impacts cash flow by approximately $350 million. A $0.30 change in gas price impacts cash flow by approximately $65 million. Both of these estimates exclude the effect of our hedge positions.
I would like to conclude by noting Apache's continued financial strength and flexibility. We entered 2018 with $1.7 billion of cash, $150 million of which we used to fund debt maturities earlier this month. We have an additional $400 million of debt maturing in September, which we will also retire using cash on hand.
We will continue to balance the great confidence we have in our current investment programs with our overarching desire to live within cash flows. We have purposefully created the liquidity to fund the near-term outspend because it will maximize long-term value for our shareholders. While this will be a small and short-lived outspend, we are exploring all options for minimizing or eliminating it entirely.
We will also continue to take advantage of the flexibility our portfolio provides on the capital program outside of Alpine High. We will maintain the planning and operational flexibility to manage these programs as market conditions dictate.
I'll now turn the call back over to John for a discussion of our three-year outlook.
Thank you, Steve.
Before we move on to Q&A, I'd like to comment on the 2018 to 2020 outlook we provided in this morning's press release. Over the next three years, we plan to invest a total of approximately $7.5 billion in the upstream, with just under $2.5 billion budgeted for 2018 and increasing slightly through to 2020. Additionally, we expect to invest $1 billion in the midstream build-out at Alpine High over the next three years. This will include around $500 million in 2018 and another $500 million split evenly between 2019 and 2020.
As we have made clear, we are exploring funding alternatives for our midstream assets and are working to eliminate some or all of this capital from our three-year plan. I cannot overstate the strategic importance of the midstream solution at Alpine High. The optimal outcome requires a deliberate and thoughtful approach, highly integrated with the upstream development plan, and we are investing the necessary time and resources to get it right.
The outcome of this capital program is a projected compound annual growth rate of 11% to 13% for Apache as a whole and 19% to 22% in the U.S. over the next three years, which will be accompanied by very solid returns. This growth will be driven almost entirely by the Permian, which we project to grow at a compound rate of 26% to 28%.
Our international operations in Egypt and the North Sea will continue to be free cash contributors. For the last two years, we have been investing below our $700 million to $900 million maintenance capital rate. As a result, we have seen international production volumes decline. And for now, we anticipate they will continue on a shallow decline rate, given our planned investment levels. In the North Sea, however, we do anticipate improving capital efficiency, as our high day rate contract on the Ocean Patriot semi-submersible rolls down to a significantly lower rate in mid-2018. We feel good about the long-term strategic direction of Egypt and the North Sea, and industry activity is picking up in both regions.
I'd like to take a few minutes now and focus specifically on our three-year Permian Basin investment plan. As you know, Apache has one of the largest acreage footprints in the Permian, and it is our largest-producing region. From 2018 to 2020, we plan to invest approximately two-thirds of our upstream capital in the Permian, consisting of $2.5 billion in Alpine High and $2.5 billion in the Midland Basin, other Delaware Basin, and Central Basin Platform combined. Outside of Alpine High, we will focus our capital program on horizontal oil drilling in the Midland and Delaware Basins and on moderating our Central Basin Platform decline rate through water flood and EOR projects.
With the advancements made over the last three years that Tim discussed, the capital program in these areas is becoming both more efficient and more productive. We have the inventory to significantly increase this investment level, especially in the Midland Basin, if our objective was to simply maximize short-term oil growth. However, a deeper understanding of multi-zone reservoir dynamics on a section level will lead to much more economic full development decisions for the long term. This section-level approach requires the collection and analysis of massive amounts of data to fully understand the complex, inter-well, inter-zone physics.
Our current rig and completion pace allow sufficient time to collect and analyze this data and design and implement optimal spacing and pattern configurations across our acreage position. After we complete this important work, then we will look to accelerate our Permian development pace in the context of available cash flow.
With nearly all of our key Midland Basin acreage held by production, we have the luxury of utilizing time and technology to ensure long-term value maximization of our Permian acreage. The industry is just beginning to understand the dynamics of downspacing, inter-well and cross-landing zone communications, and long-term reservoir performance of multi-well pads. Apache's goal is to stay at the forefront of that understanding.
Turning to Alpine High, Apache has the unique opportunity to advance a low-cost greenfield play of enormous scale. We are confident it will become a long-term, high -return, free cash flow generating asset for decades to come. In the context of today's commodity price, we acknowledge that funding a wet gas play is a bit contrarian, but it is justified by the long-term scale and return potential, even at lower gas prices.
With 340,000 contiguous net acres, up to 6,000 feet of hydrocarbon columns spanning the full range from dry gas to oil, relatively high permeability, low clay content, and generally over-pressured true organic shale formations, the potential of the play is very compelling.
Our investment plan for Alpine High upstream over the next three years assumes an average of 6.5 rigs in 2018, increasing to 10 rigs in 2020. During 2018, approximately 50% of the drilling program will focus on wrapping up the primary phase of delineation and testing. The rest of the three-year drilling program can be roughly split 50:50 between retention drilling and impact development drilling.
The key to success for Alpine High will be its cost structure, both on a capital and operational basis. We have already made great progress on drilling costs. But over time, well design optimization, pad drilling, and pattern development are expected to drive Alpine High's average completed well cost down into the $4 million to $6 million range, resulting in very attractive F&D costs.
The Woodford, Barnett, and Pennsylvanian source rock are also true shales, which means they contain little to no in situ formation water. With minimal water handling costs, Alpine High will have extremely low operating costs.
We are projecting a steady decrease in lease operating expenses over the next three years to less than $2 per BOE by the end of 2020, excluding gathering, processing, and transport fees. This is a major difference between Alpine High and other sweet spot Delaware Basin plays that we believe is vastly underappreciated.
In addition to low costs, revenue uplift from oil and liquids in the wet gas portion of the play will contribute to strong cash margins. Together with the low F&D costs, this will drive very competitive recycle ratios compared to those generated by other Permian Basin operations.
2018 will be another key step in the transition of Alpine High from delineation and testing to full development mode. The build-out of the infrastructure backbone will continue through 2018 and into 2019. There will be times when we need to shut in production to commission new facilities, to upgrade or expand existing facilities, or to reroute product flows. The infrastructure build-out also comes with inherently unpredictable timing risks associated with weather, surface use agreements, and third-party engineering, procurement, and construction vendor delays.
Drilling at Alpine High will progress at a steady and increasingly efficient pace as we transition to more pad development, while the turn-in line schedule for larger pads will periodically drive significant waves of new production capacity.
Midstream installation and commissioning, in parallel with the drilling program migrating to more multi-well pads, will create significant lumpiness to the near-term production profile. As I mentioned earlier, Alpine High production in the fourth quarter of 2017 was 20,000 BOEs a day net to Apache. By 2020, average daily production is expected to be between 160,000 and 180,000 BOEs a day, which represents a compound annual growth rate in excess of 150%.
Our forecast has certain embedded assumptions for improved capital efficiency and productivity that are common with new resource plays. We believe these assumptions are conservative relative to improvements the industry has seen in other unconventional plays such as the SCOOP/STACK, Utica, and Marcellus, so there is meaningful upside from this forecast. We are still very early in the unfolding of Alpine High, and there is much learning still to occur.
In terms of production mix, fourth quarter 2017 volumes at Alpine High were comprised of 83% gas, 10% NGLs, and 7% oil. In our three-year outlook, we are conservatively forecasting the oil percentage to remain relatively flat, as our drilling program will be weighted toward deeper drilling for retention purposes. However, there are many avenues by which the oil mix should increase. And I anticipate we will see many updated views on the oil mix in the future.
In terms of the NGL mix, our first cryogenic processing facility will be commissioned in 2019. At that point the percentage of NGLs in the production stream will begin to ramp up. And in 2020 should be around 30% of total Alpine High volumes on a BOE basis.
Going forward, there are three primary program milestones to monitor. The first is well cost reductions in the development program. As we transition more of the drilling program to pads and patterns, completed well costs should improve over time and eventually land in our $4 million to $6 million target range.
Second is improving well productivity in the development program. As we drill and complete more wells, you should see the learning curve benefit of more productive wells over time.
And the third is expansion of the drilling inventory through the delineation and testing program. As we further test the Crest, Southern Flank, and the shallower zones of the play, we anticipate increasing the number of wet gas and oil locations significantly.
Alpine High has all the makings of a great resource play. And Apache is fortunate to have such a commanding acreage position. Investing in Alpine High is arguably a gas and NGL proposition for the near-term investment horizon. We realize we are often held to the comparative conventional wisdom of Permian Basin, especially Delaware oil plays. But we believe that a hydrocarbon agnostic evaluation of this play is the right approach.
Full cycle returns will be determined not only by top line revenue, but importantly, by cost structure as well. With respect to the former, we believe the macro environment is setting up very nicely for gas and NGL producers, as the important drivers like the Gulf Coast pet-chem build-out, LNG exports, and Mexican demand accelerate as we enter the next decade.
In terms of costs, we are confident the geological attributes, such as continuous and contiguous transgressive sequence, high organic content, over-pressured geologic settings, and the operating simplicity that comes from low water cuts will result in Alpine High being highly competitive with, if not ultimately superior to, other leading Permian Basin plays from a full cycle return standpoint. And ultimately, that is what Apache is about, generating and sustaining leading full cycle returns.
It will take time to bring clarity to the full potential of Alpine High in terms of resource and production profile. And this clarity will only come through investment. We are confident though that it will be a game changer for Apache and provide a powerful complement to the rest of our portfolio.
I will now turn the call over to the operator for questions.
We'll pause for just a moment. The first question will come from John Herrlin with Société Générale.
Yes. Thanks. Regarding your Midland well pads, John, how many wells per pad? And is the 1.5 to 2-mile length ideal? Is that your optimal horizontal length for those wells?
Yeah, John. Thank you. First off, we brought on three half-section pads. And a lot of those were 8 and 10 wells, so we're testing multiple zones and the patterns there, and it's really important. I mean we'll be watching those wells now over time. We've got a couple of other – we've got a pad coming on in the first quarter, as we said, of 2018. And some others planned in 2018, which will help us with that.
Right now, 1.5-to-2-mile is probably optimal. And a lot of that hinges on your land position. So we've had to do some work to kind of be able to block up some trades, to be able to drill those longer laterals.
But I do think that the 1.5-to-2-mile laterals are going to be optimal for now. And obviously we're watching the spacing. I think that's one of the big keys is getting this spacing right. As you know, you can't take back wells you drill. And we've seen some instances where others have plowed ahead and are over-drilling. And now you're seeing a lot of interference.
And so I think it's important to take the time, effort, collect the data, and do the science to make sure you get those patterns and spacing tests right to maximize the long-term returns.
With respect to the data gathering and all that, how much incrementally or how much has that been for the well costs or the pad development costs, the technology that you're focused on?
Well, we had a pad where we ran fiber on all the wells. We ended up spending a couple million dollars there ultimately, because of how we collected it. We also had seismic crews out there. And we actually collected true seismic data in between each stage.
So we've done a lot of things, John, where we've invested that money. But when you look at the grand scheme of things, that relative to just one well that you over-drill is money well spent. So I mean it's worth taking the time and making sure we do this right.
Great. That's really it for me. Thanks.
Thank you.
The next question will come from Bob Brackett with Bernstein.
Hi, guys. Question on the U.S. non-Permian, non-Alpine High. If I kind of take your guidance and back out what it implies for U.S. non-Permian, it's kind of under-investment, like a decline. If I look at the Permian outside of Alpine High, it looks like you guys basically keep it flat through 2020. Is that about right?
When you look at the capital program with where we are today, Bob, yes. We are spending very little outside the non-Permian capital. I think you're actually going to see though, that it's – with the investment that's come off of the last three years, it's not going to decline a whole lot. In fact, our Mid-Continent stuff will actually grow with just the five wells we brought on in the SCOOP this year. So we're in a pretty good spot there. But, yes, very little capital there for 2018.
Now as we get out past a couple of years and we start generating a lot of free cash flow from Alpine High, we see that changing quickly. And so we like having the optionality there in those assets.
And right now in the other Permian, it's close, a little more than maintenance. But it's really more designed at going at the right pace there. As I mentioned too in the Midland Basin, I mean we've shown – if you look at the results, the back half of 2017, as I mentioned in the script, we peaked in the fourth quarter of 2015. And then we really shut the programs down, reset the cost structure. Bottomed second quarter of last year. And then quickly in a matter of two quarters made a new production high.
So really it's an off/on switch. It takes a couple of quarters. But it shows you the quality and the progress that we've made in terms of being able to apply that capital to the other Permian assets.
And if you have those assets that other people would voraciously drill, at what point do you say that those belong in somebody else's hands? Or to your point, do you keep them for future optionality?
Well, we just have to weigh the value of that. I mean we look at the portfolio. We work the portfolio very hard. Last year we made a strategic decision to exit Canada, which we're very glad we did. I think one of the things that gets lost in there is that we eliminated $800 million of ARO, but that was a big strategic decision for us.
We also unloaded some acreage that we felt like we got some very – prices for. And is exactly that. Something that somebody placed a high enough premium on that we felt like it would be better in their hands. So you're always looking at those things and weighing those things. And we continue to do that in the future.
Okay, thanks.
Thank you.
[Technical Difficulty] (59:22 – 59:31)
Jeffrey, your line is open.
Thanks. On the multi-year plan, you mentioned the 10% service cost inflation. Can you talk through some of the other assumptions, specifically what commodity prices you're underwriting? And if you're including any expected efficiencies or productivity improvements?
On the service side, yes. As Tim said, we have most of our big ticket items – rigs, frac crews, sand – under contract and tied up for the foreseeable future. So we feel good about the main services.
But we are seeing the smaller things that drive the day to day, trucking, simple as the backhoes, pads. Everybody is wanting to raise costs everywhere. So we did bake in, in general, a 10% rise. Now when you look at some efficiencies at – and then we kind of took each play, play by play. As Tim told you, in 2017 we were able to reduce our Midland Basin well cost by 20% on a treated lateral foot basis and increase productivity by 17%.
So we've taken those kind of play by play into account. The greatest efficiencies we'll see at Alpine High is we're early in that play and really starting to move into pads. And then less in the more mature plays, where we've drilled more wells.
And so we've got a pretty conservative forecast on the capital side going into this year. And what I don't want to be is in a couple quarters, having to raise my capital, because I assumed that we could keep things down when the reality is there's a lot of pressure out there on a lot of different fronts.
I appreciate that detail. And then I guess on the commodity price assumptions through the three-year timeframe. Just trying to get a good sense of what's under-written, when Steve talked about cash flow neutrality and the upstream piece this year, for example, and just how that might evolve over time.
Yeah, Jeff. So obviously, there's lots of conversation out there today about cash flow neutrality and pricing assumptions and what pricing assumptions people ought to use. And obviously I think that the last few years have demonstrated how important we believe cash flow neutrality is. And we've said that many, many times that we ought to be able to live within our means.
I think it's important that we actually acknowledge there are lots of different definitions out there about cash flow neutrality. There are lots of different methods that people use to talk about that. Some include dividends, some don't include dividends. Some actually go so far as to include asset sales. And some have some capital structure changes, all contributing to cash flow neutrality.
Just to be clear, we take a very, maybe extremely pure approach, because we believe cash flow neutrality means that with no asset sales and with no changes to debt or equity, that you should end the year with the same amount of cash on hand that you began the year with. And that's a very pure definition. I'm not sure there's a more accurate definition of cash flow neutrality. If there is, I'd like to know what that is.
So with that said, our plan for 2018 and beyond, what we talked about today around – or I talked about around 2018, is so the midstream is obviously operating at an out-spend, about a $500 million deficit. That doesn't – that's regardless of what price assumption that you might use. And there's obviously – there's some reasons that some of that might go away.
And what I talked about is that the upstream, which is everything else in Apache, including dividends, that that would be cash flow neutral at current pricing is what I said, which is about $60. $60 $61, WTI's current pricing I believe, unless something's happened on the call.
So we would be cash flow neutral at around that type of price assumption. We believe we could also be cash flow neutral down into the upper $50s. We're working on a number of things that could help us do that.
In terms of pricing in our plan, we've actually run numerous price scenarios, all of them lower than $60. We've reviewed many of these with the board. And just a couple weeks ago, we actually agreed our plan for this year with the board, and that was at a price of $58 WTI. Obviously at that price there would be a small cash flow deficit in the upstream to go with the midstream deficit.
And I think that – I think with the information that we've now provided around the plan and with the supplement around price sensitivity, around the hedge positions, we've given you lots of details. You understand cash flow sensitivity relative to movements in oil price or gas price. You see the details on our hedge positions, which obviously affect cash flow sensitivity as cash flow – as price moves down.
And I think – so I think most of the data there, to meet any modeling requirements that you might have, to understand how cash flow changes as commodity prices move up or move down.
The only word of warning that I would give you on that is that if you start moving too far off of this, our plan at $58 or current pricing at around $60, you start moving too far off of that either to the upside or the downside, then the current plan, all of the other elements of the plan actually begin losing relevance. Number one, we have our hedges in place, so you've got that.
Number two, I think the simple math on cash flows due to price isn't really adequate. Because when you start moving well below that $58 or $60 current pricing or well above it, then all of the other assumptions inherent in the plan begin to change. All of the things around cost inflation assumptions that we've made, the actual activity set that we would engage in, the actual capital allocations that we would make, all of those change as you move far off of that plan.
So we set ours at – we set the plan with the board at $58. And we think that's actually somewhat irrelevant. The current pricing, $60 to $61, we would be cash flow neutral in that upstream or everything outside of the Midland – or the midstream, which is about a $500 million deficit.
Thank you.
Yeah, all of that, just to be clear, again, that all includes the dividend.
Understood. Appreciate all the color there as well. Thanks.
The next question is from Charles Meade with Johnson Rice.
Good afternoon, John, to you and your whole team there.
Good afternoon, Charles.
Thank you, John. I want to go back to something that you spent some time on in your prepared comments. And I'm hoping you can perhaps add a little bit more. And that's the discussion around the – said maybe the balance of returns between your Alpine High and say your Midland asset. And it sounded like you were saying in the short term, perhaps a better return is available in the Midland Basin. But if you widen the perspective a bit and look at the longer term trajectory in Alpine High, that actually that's going to deliver better returns to Apache shareholders.
I wonder is that the right way to interpret your comments? And if so what is the timeframe where maybe there's a breakover that Alpine...
Well, first thing is the returns in both programs are excellent, so it's really not a return difference thing, Charles. The point was we could increase short-term oil by going much quicker in the Midland Basin today or some of the other Delaware Basin stuff today.
The point was in the Midland and the Delaware, we're gathering a bunch of data by moving to the pads and the pattern spacing tests. And that's really, really important data that we're collecting right now.
And quite frankly, you want to – the market has gotten conditioned to thinking that early performance in IPs is a direct correlation to EURs, which is just not the case. You have to look at how these wells perform and how these pads perform over a longer time, and especially as you start to look at the inside wells and so forth.
So in our Midland program, we've actually brought on three brand new half-section pads late last year, which we're going to critically watch. And they're a little different configurations and we collected a lot of data. So there are two elements there. What my point was is we could accelerate the short-term oil over the longer-term investment at Alpine High.
At Alpine High, you have a totally different animal, though. You have 6,000 feet of hydrocarbon column. We've got a 70-mile fairway, 340,000 acres that we control, multiple zones. We've now proven over 11 different landing zones across just the vertical column, and there's many, many more as we work through that. So it takes time. We're moving the infrastructure forward. And most of that's geared to the wet gas infrastructure that we have to have to process that and get put in place.
And so when we look at advancing that over time and then you just look at the velocity at which we'll be able to reinvest that capital because of the F&D and because of the turnover and the returns, from a longer-term perspective, what's in our best interest now is advancing the Alpine High at this pace and the Midland Basin at the pace we're at.
Okay, got it. I think that makes sense, John. And then this is more just a rifle shot question. The Dogwood and Elbert State pads, your Alpine High pads that you gave us some results on, I believe you gave us the oil cut. But what was the – if you could, give us an idea of the NGL yield on those.
No, the Dogwood pad we said is in the dry gas. I think the thing that's very exciting about that is that's a six-well pad that's on 660-foot spacing. And quite frankly, that's a heck of a lot tighter than what our location counts would be today. So the performance there is very encouraging. And it could lead to an increase in numbers of well counts, because it's performing very, very nicely.
But the Dogwood is in the dry gas. And as we mentioned, we've got six wells on. They're 660-foot spacing, and they're currently making over 75 million [cubic feet] a day, and have already made 2 Bcf in a very short term while they were cleaning up. So it's really the first true pad and pattern. And it's validating the organics. This is a true shale. And so you're seeing great response from the first pad.
The Elberts are shallower. And there you see the liquid yield goes up. Those are still cleaning up as well. It's a two-well pad. I think the key there was we got the cost down. And what you're seeing there is the liquid yield. And that will be wet gas too as it moves up. So I don't know, Tim, do you have the NGL yield on the Elberts?
This is high BTU gas. And under the cryo, it's going to be in the 140 barrel per million range of a typical wet gas well.
And it's about 60 barrels a million right now of oil too, correct?
Correct.
Great, that's what I was looking for. Thanks, Tim, and thanks, John.
Thank you, Charles.
The next question will come from Michael Hall with Heikkinen Energy.
Thanks. I guess first on the trajectory of Alpine High in the three-year outlook, I'm just curious. Should we think about that as basically filling up infrastructure as you go, or do you have remaining infrastructure capacity to continue growth beyond that timeframe?
No, Michael, it's a pretty conservative plan. It's really based on retention, half the capital going to retention. We will be ahead of that. I said we would end the year at about 830 million a day of inlet processing capacity at the end of this year. And the volumes we have on that outlook don't fill that up. So we've got a lot of capacity there. And quite frankly, I think there's room for the picture to improve greatly as time marches on this year, both in terms of the volumes as well as the liquid content and the oil content as we test more of the zones and go forward there.
And in what timeframe does the Alpine High project as a whole go from being in an investment phase where there's an outspend, including the midstream, to – let's just set aside monetization, but to a free cash flow phase where you're actually harvesting the cash flows from the program?
We look at it – probably the best way to put this to you is on a rig line basis. A single rig line is going to turn cash flow positive in less than two years. And so if we hold the rig lines constant, you'll see it turn pretty quickly. So that's how we think about it.
We laid out the capital on the midstream was (1:14:04) $500 million last year. We said $500 million this year and then $250 million, $250 million. So it starts scaling down. So then it really comes down to the pace on those rig lines.
But you're going to see this thing start throwing off a tremendous amount of cash in less than a two-year window per rig line.
Okay. And then last on my end is just around the cost structure. I was just looking year on year at the LOE cost guide. It's up despite adding a pretty large wedge of what I would think is pretty low-cost gas. What's going on there that's not driving a reduction in LOE per unit? And should we anticipate a reduction over the longer timeframe within the three-year outlook?
There's no doubt that, as we mentioned in there, the per-barrel numbers are going to come down on Alpine High. Some of that's with starting to put various things in the LOE lines that hadn't been there prior. Some of it is when we pored our plan, our guys have taken a pretty conservative approach for what LOE looks like right now just because of the pressure we're getting for everywhere to raise the small things.
So I think there's room, as we have historically done, to work on those numbers and beat those numbers. But it's probably just a little bit with this price environment changing so dynamically, that and the timing of some pads and some things coming on that is driving that. But there's no doubt over time the LOE per BOE for the Permian is going to come down significantly as Alpine High ramps up.
And at the corporate level, should we see that by 2019 you think, or more time?
Yes, this is Steve. So I think that a lot of that will depend on what happens with the midstream at Alpine High. Because John made reference to what we believe the LOE per BOE at Alpine High will be in his prepared remarks. That was excluding the midstream costs.
And today, all of the midstream costs show up, or the operating costs for that show up as LOE. And obviously, as you're building that out, you're building out capacity and starting it up and operating it below its actual true capacity, in some cases and for some periods of time well below its true capacity. You're going to have a pretty high cost per BOE going through that.
Two things will change that, number one, just ramping it up to a larger scale and really getting it ramped up to efficient activity. But also eventually what's going to happen, or at least I would anticipate will happen, is that the midstream assets become part of a midstream enterprise separate from Apache. And depending on the accounting treatment of that, the structure of it and control and ownership, you could see all those costs move over to gathering and transportation, which will be more of a typical third-party type of transport and processing fee as opposed to LOE. But that's going to have a meaningful impact, especially on 2018, the startup and operations of that midstream enterprise.
All right. Look forward to seeing how it all progresses. Thank you.
The next question is from Brian Singer with Goldman Sachs.
Good afternoon.
Hey, Brian.
With the three-year outlook on Alpine High to get to 160,000 to 180,000 BOE a day, fully recognizing that production mix is different from value, can you just give us the update on your expectations for the oil versus NGLs versus gas split in 2020?
And then on the gas piece, what are your expectations for how much will go beyond the local market in 2020? I think you referenced the Gulf Coast Express Pipeline as one option, but maybe you could quantify that a little bit more.
in the prepared remarks, we said fourth quarter, you were 83% gas, 10% NGLs, and 7% oil. And we said in my prepared remarks by 2020 that the oil, we assume the oil will remain about constant. And the NGL volume's going to grow to about 30%.
So you're going to be more like 63% gas, that's probably then going to be two-thirds to – or more wet gas to dry gas with a heavy 30% NGL. And then we've assumed a 7% oil mix. But I believe that's pretty conservative. And that's – as I mention right now, our plan is geared more towards retention and what we see without the ability to be able to drill more at the other locations. So that's how that'll transition. And...
And on the marketing side, we've got a lot of activities actually underway here, a lot of parts that we're working on. We're continuing to contract gas at or around Waha or near our assets. We're continuing to work on contracting gas down on the Gulf Coast, where we now have the capacity to transport 500 million a day starting in 2019. So we're working on marketing contracts at the Gulf Coast from that point forward.
And then we're continuing to look at more gas opportunities as well as – for the longer term, as well as oil and NGLs. And so I think there's still a lot of work to do on the marketing side, both physically moving product and also selling that product or downstream products from those products.
Great. Thank you. And then shifting to the other side of the world, there was some news earlier this week of some contracts signed to move natural gas into Egypt in a couple years out, at a price ostensibly greater than what Apache receives for its gas. I realize that Apache's price is probably a blend of a number of contracts and concessions. But how prominent are the opportunities to grow gas production on your concessions? And how interested would you be in investing or monetizing that in some other way?
I mean there are definitely opportunities to move that forward. I mean I think we just added 40% to our acreage footprint. Most of our revenue comes from the oil side, quite frankly. And the way a lot of our concessions are structured and so forth, some of those prices are set.
The Egyptian government has been very flexible and willing to step in and structure things that would encourage some development of some different types of things. So I think you'll see us continue to do that. And if it makes economic sense in relation to the oil that we're developing over there, we will do that.
In general, we applaud the contracts to bring the gas in. I think it's a good thing for Egypt and the country and actually, it's very beneficial to us. So we're happy to see what's happening, both in the deepwater with the gas developments there as well as bringing in the gas that was recently announced.
Great, thank you.
The next question is from Leo Mariano with MetAlliance (1:21:37).
Yes, hey guys. Just in terms of the Alpine High midstream monetization, recognize that it sounds like you guys are still contemplating various avenues here. But just try and think of it from a high level perspective. Is this likely to be an event you think that's going to come later in 2018, or more of a 2019 event?
It could come any time in 2018 I would guess. I'll be honest with you. We made a lot of progress. We've had some inbound proposals that are fairly attractive. There's a tremendous amount of interest. And quite frankly, I think there's a lot of folks out there that realize this is going to be one of the most critical pieces of infrastructure in the Delaware Basin. And so I'm very optimistic that we'll be able to get something done and something that'll be very, very strategic for Apache.
All right, that's very helpful. And then just looking at kind of the Alpine High project and thinking about some of the splits that you threw out there in terms of hydrocarbon mix. You certainly talked about strong rates of return for your shareholders here.
Just wanted to kind of think about some sensitivities there. Have you guys looked at kind of some of the downside cases, where if say you're getting $2 for the gas over the next three years and $20 for the NGLs, does the project still have kind of the right hurdle rates for Apache?
It – the beauty of it is, is with the wet gas, you don't need the gas. Now you got a scenario where you have really low NGL prices and really – I mean obviously, as under a scenario where all commodity prices go way down, then it's a different story.
But this thing's going to really hum below $2 on the gas side. And I think with what's going on on the Gulf Coast, with the expansion that's taken place in the petrochemical end, we look out to 2019, 2020, 2021, and we see a pretty robust NGL market, as well as the ability to get the gas to the Gulf Coast.
So it's what sets this play apart is the cost structure. And ultimately, it's the cost to drill the wells that's going to be superior and the deliverability. And it's that combination with the liquid yields and the oil production is what makes it unique. And quite frankly that's what we know makes it differential.
And the other factor is you're not going to have to move a lot of water in the lower zones. And that's another very differentiating fact.
But, yes, we've run many cases on the downside. We would not be making this type of investment on the midstream or the upstream side if we thought there was a sensitivity that was close to anything that would come into making it not work under very, very low gas and NGL and oil prices.
Thanks, guys.
The final question is from Doug Leggate with Bank of America Merrill Lynch.
Oh, hi. Good afternoon, everybody. Thanks for squeezing me in. John, you've given a fairly robust defense of the Alpine High in terms of the returns, the cost structure, and so on. And certainly, the production growth looks pretty impressive.
Can you give us an idea of what you anticipate the cash flow growth to look like under your planning assumptions matching that? Because obviously it's going to be a function of basis differential and the prevailing gas price at that time. So what are your planning assumptions as you see going through 2020 in terms of cash flow growth?
I think as you get out longer term and you see the expansion in the infrastructure that we see as being built and will be built, we don't see Waha continuing to trade at a big discount on down the road, because that will be solved. Part of it starts with the Kinder [Morgan] Gulf Coast Express Pipeline in 2019 and so forth.
So I mean historically, Waha has traded at a, call it, $0.10 to $0.20 discount. Over the long haul, you're probably going to be in a $0.35 to $0.50 transportation cost differential at worst. You could – some scenarios actually see Waha become a premium, depending on what happens ultimately with Mexico and so forth and the West Coast.
So we think, try to think, longer term with a project like this. We realize it's a little disruptive. If you look at last year when we were putting in a lot of our hedges, we were a lot of the market at Waha. And a lot of the reason why that differential is where it is today. We recognize that.
So any time you bring on a world class play that's going to be a little bit disruptive, you've got to go through that time period till you can see through it. But I think as we get out to the timing, when we start to see the cash flows really ramp up here, the beauty of it is we will be solving some of the short-term obstacles that would stand in its way initially.
I appreciate the answer. My follow-up, I'm afraid, is a midstream question also. Because obviously this is a fairly pivotal event if you are able to get something done this year. Your CapEx guide assumes $500 million for midstream. And forgive me if I'm wrong. I think you had indicated you might see the same spend next year also. Are you pretty much done after that in terms of midstream build-out? And if you did manage to find a structure for the midstream, would that capital move off your balance sheet onto another entity, let's say?
Yeah. Well, first of all, next year's spend, we didn't guide to $500 million. We said it would be $500 million this year and $500 million in 2019 and 2020, split evenly amongst those two years. So you're really $500 million, $250 million, $250 million is terms of how we see it.
But absolutely, Doug. We envision moving the future CapEx spend into the entity, where it will be able to do its own thing. So that would be the plan. And we're very confident we're going to be able to do something. I mean it...
Really helpful. Thanks a lot, John. Thanks, guys.
There are no further questions at this time. Are there any closing remarks?
No, thanks, Thea. That'll conclude the call. If anybody has any questions, please call myself or Patrick Cassidy. And we'll look forward to speaking with you next quarter. Thanks.
Ladies and gentlemen, thank you for participating in today's conference call. You may now disconnect.