Midstream infrastructure buildout will determine the near-term success for Apache Corp.’s No. 1 target, the Alpine High in West Texas, CEO John Christmann said Thursday.
The Permian Basin discovery is changing Apache’s course, and the midstream “is a critical piece to the story for the near-term,” he said during a conference call to discuss fourth quarter and 2017 results.
The Houston operator “in short order expects to bring forth the capacity to deliver oil, gas and natural gas liquids at scale to the rapidly growing market on the U.S. Gulf Coast.”
It’s necessary, for now anyway, to “strategically control” the buildout, but Apache doesn’t need to own 100% of the midstream assets long-term. It now is studying “strategic alternatives” that would free up cash flow.
Progress is being made on multiple fronts to build Alpine High midstream prowess, CFO Stephen Riney said. Apache now is operating 110 miles of gathering lines, 45 miles of 30-inch diameter trunk line, 21 central tank batteries and five central processing facilities, with inlet capacity of 330 MMcf/d.
“By the end of 2018, we anticipate reaching 830 MMcf/d of inlet processing capacity,” Riney said. This year installation is to begin on centralized cryogenic processing facilities that would add another 600 MMcf/d of capacity in 2019.
Apache also has begun implementing a natural gas takeaway strategy through an agreement clinched in December with Kinder Morgan Inc. to access capacity on its proposed Gulf Coast Express long-haul project from the Waha Hub to Agua Dulce near the Texas Gulf Coast.
“Similar arrangements” are in the works to transport natural gas liquids (NGL) and oil from the play.
“Numerous parties have approached us with some very interesting ideas of how they might join us in the build-out of the midstream business,” Riney said. “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.”
Because Apache has a stout Permian portfolio in the Delaware and Midland sub-basins beyond Alpine High, there’s optionality to direct investments as needed to produce oil, gas or NGLs, Christmann said.
Over the next three years, Apache plans to invest $1 billion in the midstream build-out at Alpine High alone, with $500 million this year and then split evenly in 2019 and 2020.
“I cannot overstate the strategic importance of the midstream solution to Alpine High,” he said. “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.”
To understand how valuable the Permian production pie is to the company, Apache is projecting for the next three years a compound annual growth rate (CAGR) of 11-13% for its global portfolio. For the U.S. piece, CAGR is forecast at 19-22%. For the Permian, including Alpine High, growth of 26-28% is anticipated.
First production from Alpine High began ahead of schedule last May, and volumes have steadily increased as wells are connected and infrastructure is commissioned.
To date, Apache has boosted its inventory of risked locations to more than 5,000 and initiated its first “true multi-well pads and pattern tests, which will drive increasing capital efficiencies into the 2018 program and beyond,” said Christmann.
The fifth central processing facility at Alpine High was commissioned at the Hidalgo site during the fourth quarter, giving Apache the ability to hit its year-end production target of 25,000 boe/d. Production during the three-month period averaged 20,000 boe/d.
Operations chief Tim Sullivan did a deep dive on some of the wells, including from the two-well Elbert State pad drilled in the Woodford formation.
“These wells produce wet gas and oil, and averaged a 30-day peak initial production of 1,175 boe/d with an oil-base ratio greater than 60 bbl/MMcf, Sullivan said. “As we move to pad operations at Alpine High, we are realizing the benefit of reducing cost and increasing efficiencies,” he said.
Efforts so far have reduced spud to total depth times to under 15 days in some cases. On the completion side, pad operations in Alpine High also have led to pumping more fracture stages per day, optimizing sand loading to pattern size, recycling water use and higher pump rates.
Apache’s investment plan for the upstream portion of Alpine High development assumes an average of 6.5 rigs in 2018 and increasing to 10 in 2020.
This year, about half of the drilling program is to focus on completing the primary phase of delineation and testing. The rest of the three-year drilling program is 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,” Christmann said. “We have already made great progress on drilling costs.” Over time, optimizing well designs should reduce costs even further.
“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.”
Total Permian gas volumes during 4Q2017 climbed 42% year/year and 15% sequentially to nearly 320 MMcf/d, while oil volumes increased 10% to 85,448 b/d. NGL volumes from the Permian totaled 38,193 b/d, up 12% year/year and 4% higher than in the third quarter.
In terms of production mix, volumes at Alpine High during the fourth quarter were 83% weighted to natural gas, 10% to NGLs and 7% to oil.
“Investing in Alpine High is arguably a gas and NGL proposition for the near-term investment horizon,” Christmann said. “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 valuation of this play is the right approach…
“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 gamechanger for Apache and provide a powerful complement to the rest of our portfolio.”
In the context of today’s commodity prices, Apache management acknowledges “that funding a wet gas play is a bit contrarian,” said the CEO. “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…and generally over-pressured true organic shale formations, the potential of the play is very compelling.”
Apache is hedging to protect cash flows to fund the capital program for Alpine High, Riney said.
“For 2018, an average of 85,500 b/d of oil production currently has some form of hedging protection,” said the CFO. Forty-seven percent is in the form of puts, 37% is in collars, some with upside call options and 16% is in the form of swaps.
“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,” Riney added. As such, Apache entered New York Mercantile Exchange (Nymex) gas-price swaps and Waha basis swaps to eliminate some uncertainty.
To date, Apache has swapped an average of 237 million Btu/d of Nymex gas-price exposure for 2018 at a weighted average price of $3.07. For Waha through 2018 and the first half of 2019, it has entered swaps for an average of 156 million Btu/d at an average basis differential of 51 cents.
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