Apache Corp.’s ballyhooed Alpine High field in West Texas should have four additional midstream processing facilities coming online through the end of the year, with the southern trunkline to the Waha Hub scheduled to ramp in September, opening key delivery points and reducing bottlenecks, management said Thursday.
The Houston-based executive team outlined not only its priorities for the No. 1 prospect, but progress in projects worldwide during a conference call to discuss second quarter performance.
Apache achieved first natural gas production from Alpine High in early May, exceeding a June 30 target of 50 MMcf/d of processed natural gas, CEO John Christmann told analysts.
“Currently, our net sales gas exceeds 60 MMcf/d, and we anticipate this will increase to more than 100 MMcf/d by the end of September.”
Because of the timing of infrastructure buildout and gas takeaway, most of Apache’s Alpine High production to date has been from the northern-most acreage in the West Texas formation, which sits within the Delaware sub-basin.
“The drilling in this area has primarily been lease retention-focused,” Christmann said, “and these wells were generally deeper and, thus, have a lower liquids content. The liquids ratio should increase as we drill and connect more wells in other areas of the play, and as we commission additional processing facilities.”
Alpine High 90% Weighted to NatGas
During June, total Alpine High sales averaged 7,400 boe/d net, 90% weighted to natural gas.
“On the midstream side, we invested $270 million in the first half of 2017,” the CEO said. “Managing midstream internally provides Apache with operational flexibility and cost control benefits as we delineate the upstream and move into early stage development. By retaining 100% ownership, we are investing in an asset that we believe will significantly increase in value as the upstream production and reserve potential are further demonstrated.”
Apache’s operational midstream facilities now consist of 35 miles of 30-inch diameter trunkline for gas takeaway, more than 40 miles of smaller diameter gathering lines, two central processing sites and eight central tank batteries.
Several “significant” midstream infrastructure milestones are coming up in the second half of the year. In August, Apache si to bring online its third central processing site followed by a fourth and fifth site in September, one of which would be located in the southern portion of the play.
“Also in September, we will connect our 30-inch trunkline to a market pipeline in the southern portion of the play, which will be capable of moving gas south to Mexico or north to the Waha Hub,” Christmann said. “Around year-end we plan to have our sixth central processing site operational.”
Apache also continues to drill appraisal wells on its acreage, including four new wells in the oil window of one of the Wolfcamp/Bone Spring pair sequences. Vertical depths were 9,000-10,000 feet.
“One of the wells, an approximate 4,500-foot lateral drilled in the Wolfcamp formation, recorded a 30-day average rate in excess of 1,000 boe/d,” he said. “With an oil cut of 70%, this well has cumulative production of approximately 37,000 bbl in 75 days. A second well in the Wolfcamp is still cleaning up and producing around 400 b/d. The third and fourth wells will be completed and begin flowing back shortly.”
Early results from mapping and testing the zones “give us confidence at a minimum in hundreds of drilling locations and there is still a considerable amount of acreage in numerous landing zones to be tested,” the CEO said.
Permian Costs Receding
Alpine High testing is underway on several different perimeters across multiple formations to determine the best patterns, spacing, wellbore placement and completion designs. The process is “multifaceted and continuous.”
Costs in the play also are coming down, with average drilling/completions running $4-6 million/well, even in a rising oilfield service cost environment.
From the wells connected and flowing thus far, Apache is seeing decline curves and pressure data consistent with its estimated ultimate recovery projections, said Christmann. “In addition to the Wolfcamp and Bone Spring parasequences...we continue to be very confident in our more than 3,000 wet gas well location count, which remains highly economic at current or even lower prices.”
In the twin Midland sub-basin, activity primarily is focused on multi-pad drilling in the Wolfcamp and Spraberry formations. During April Apache brought online the nine-well Schrock 34 pad in the Azalea field in Glasscock County, TX.
The pad achieved 60-day cumulative production that exceeded expectations, Christmann said. Average well costs were $4.3 million, underscoring the efficiencies in pad operations. Five more multi-well pads are scheduled to come online by the end of the year.
North American production averaged 244,000 boe/d in 2Q2017, down 3% from the first quarter, in part because of asset sales, which included the divestiture of its Canadian operations. Permian output was responsible for the bulk of output, averaging 146,000 boe/d, flat sequentially.
Between April and June, 17 of the 35 rigs Apache was running worldwide were in the Permian, operations chief Tim Sullivan noted. There also was one rig running in the Midcontinent, 13 in Egypt and four in the North Sea.
The value of the Permian, and in particular, Alpine High, cannot be overemphasized for the super independent. Six rigs are running in Alpine High today. At the end of June, 11 wells were connected and producing into the midstream facilities, five of which were constrained to control flow as newly installed equipment was commissioned the reservoir performance evaluated.
“Six wells were in various stages of flowback in testing, and 17 wells were waiting on completion, or shut-in waiting on infrastructure,” Sullivan said. “Subsequent to quarter-end, we have connected additional wells, and production continues to impress.”
Rising GORs No Surprise
During the question-and-answer period of the conference call, management was quizzed about the rising gas-to-oil ratios (GOR) in the Permian that were emphasized by Pioneer Natural Resources Inc. during the quarterly conference call a few days ago. Increasing GORs over the life of Permian wells have been seen since the 1950s, Pioneer noted. While it’s normal for reservoirs driven by solution gas to experience increasing GORs over time, horizontal wells contact more surface area and drawdown pressures faster. Thus, Pioneer noted that GORs on the wells are increasing faster than the increase experienced on vertical wells.
Christmann said the higher GORs haven’t come as a surprise to Apache engineers, as they always forecast oil and gas streams separately.
“It's just fundamental petroleum engineering.” Because of changing dynamics in forecasting boe curves, “you have to model it...You do your core work, you do your fluid analysis, you look at your pressure and temperature data. And we can model that. We've got a lot of history and we do a lot of time modeling that. So our wells are producing as our type curves are laid out. And we have not had any surprises in terms of the forecasted volumes with how they are performing.
“Areas behave differently. And if we go back to some of our earlier areas where we drilled some wells in 2010 and 2011, they were in a little less mature area, with a little higher GORs. They're going to behave differently.”
Apache, he said, a lot of history and a deep understanding of the rocks, so no one was surprised by the GORs. “You have to examine those very carefully. But every rock, every area, the rocks are different depending on the play, and that's why it takes time to collect the data properly, do the core work, do the fluid work, do the pressure work and create your material balance just like you would in conventional rock.”
Owning Data, Not Just Gathering It
Apache also is building out water treatment and recycling facilities across the Permian to help reduce water costs and expand infrastructure capabilities. In addition, the producer is developing “new work flows and technologies that allow for rapid characterization of thousands of feet of core and quickly getting this into the hands of geologists and engineers for faster characterization of shale plays and landing zones,” Sullivan said.
“Overall, we are building a far more robust understanding of our conventional and unconventional plays and their performance than was previously possible. Instead of just gathering data, we are owning, maintaining, validating and optimizing the use of the data to add value to our assets.”
Apache reported second quarter earnings of $572 million ($1.50/share), reversing a year-ago loss of $244 million (minus 65 cents). Net operating cash was $751 million.
The company expects to complete its exit from Canada in August. In addition to the total $713 million sales price, the Canadian exit is expected to cut $800 million in asset retirement obligations from the balance sheet.
Capital expenditures (capex) totaled $738 million in the quarter, with two-thirds focused on Permian investments. Apache ended the quarter with $1.7 billion in cash from $1.5 billion at the end of March. Net debt was $6.8 billion, a decrease of $144 million sequentially.
“We have structured our business to adapt and thrive in a lower-for-longer price environment,” Christmann said.
Planned capex for 2018 is $3.1 billion, based on $55/bbl West Texas Intermediate (WTI) and $3.00/Mcf New York Mercantile Exchange.
“Our 2018 budget is flexible and can be adjusted in response to macro conditions, as every $5/bbl change in oil prices impacts our cash flow by roughly $350 million,” Christmann said. “If necessary, we have numerous options available next year to manage a lower oil price environment.
“To begin with, we are maintaining the operational flexibility to reduce planned activity across most if not all of our regions. Second, we believe costs in a sub-$55 oil price world would be lower than what we have estimated in our plan. Hence, the same overall activity set could be delivered for less than the $3.1 billion budget. Third, we could continue with the small asset package divestitures.”
There also are “multiple options with respect to our Alpine High midstream assets, possibly initiating a monetization process or seeking third-party funding....What you can count on is that we will enter 2018 well prepared to manage a capital program commensurate with the prevailing price environment.”
Apache had anticipated rising service costs once operators began accelerating, but so far, so good, Sullivan said.
“We continue to see costs inflation for certain services and supplies, primarily for pressure pumping and sand in West Texas, where spot market prices continue to trend upward,” he said. “Hoping to offset this, we are sourcing low-cost sands that are delivered from local mines in the Permian Basin, reducing transportation costs considerably. We also entered into contracts with pricing index to WTI, which protects against a portion of those increases.”