NGI Mexico GPI / Infraestructura

Apache Building Infrastructure to Carry Alpine High Natural Gas to Gulf Coast, Mexico

Apache Corp.’s U.S. production, led by the Alpine High in the West Texas Permian Basin, should hit the high end of guidance for the fourth quarter, helping in long-range plans to carry new stores of natural gas to the Texas Gulf Coast and Mexico markets.

In the United States, quarterly output is expected to be 218,000-224,000 boe/d, nearly all the result of strong growth from the Permian, the Houston-based super independent said Tuesday.

“In the Permian, we delivered our second quarter in a row of strong oil production growth; and, at Alpine High, we achieved our production target of more than 25,000 boe/d by the end of December,” said CEO John J. Christmann IV.

Alpine High debuted in September 2016 and within two months, it had become Apache’s top priority. At the end of September, net output from 34 wells was 101 MMcf/d of natural gas, 1,425 b/d of oil and 2,025 b/d of natural gas liquids (NGL).

At the end of December, Apache’s net volumes from Alpine High’s 42 producing wells included 125 MMcf/d of gas, 1,900 b/d of oil and 3,000 b/d of NGLs. Apache at the end of last year expected to have gross inlet capacity of 330 MMcf/d available for Alpine High, up from 200 MMcf/d at the end of September.

However, the “backbone” of the infrastructure is a natural gas trunkline being built through the pay to flow processed gas from the field to market, CFO Steve Riney told analysts during the third quarter conference call. Apache plans to lay around 70 miles of 30-inch diameter trunkline to move gas to north and south, offering two export routes.

The export routes would have the combined capacity to flow 2-2.25 Bcf/d of gas to market, according to Riney. The trunkline is being constructed in five segments, with the first sales connection flowing gas since last May. Processing capacity mostly has been built in 50 MMcf/d modular increments, with double capacity at some locations.

Last month, Apache also secured 500 MMcf/d of transport capacity via the proposed Gulf Coast Express (GCX) pipeline, a $1.7 billion project designed to carry 1.92 Bcf/d from the Permian to the Texas Gulf Coast. GCX is expected to provide Apache with access to domestic industrial and utility users, as well as incremental demand for liquefied natural gas exports and Mexican markets.

All of the Alpine High gas is being moved through the northern sales connection into the Comanche Trail pipeline, which went into service last spring.

The gas headed to Mexico is priced at a slight premium to Waha Hub daily basis, Riney said. In addition, multiple projects are competing to move gas to the Texas Gulf Coast, “where demand is strong and growing.”

BMO Capital Markets analysts led by Phillip Jungwirth last fall conducted a deep dive on Alpine High. Excluding concept wells, Jungwirth said the average Alpine High wet gas well after six months was performing in line with the Utica Shale and Oklahoma’s STACK, i.e., the Sooner Trend of the Anadarko Basin, mostly in Canadian and Kingfisher counties.

The average dry gas well in Alpine High after four months was performing in line with the Marcellus Shale and Oklahoma’s SCOOP, aka the South Central Oklahoma Oil Province. 

Wet gas internal rates of return appeared to compete with the Eagle Ford Shale, SCOOP and STACK. Dry gas wells are “slightly below”  the Marcellus, Utica and Haynesville shales, Jungwirth said.

“We model Alpine High production reaching 500 MMcfe/d by mid-2019, which we estimate compares with the company’s original guidance of 550MMcfe/d by 4Q2018,” he said. Alpine High should reach free cash flow breakeven by 2021 at a $3.25/Mcf Henry Hub price and a $60/bbl West Texas Intermediate (WTI) price, or by 2020 with $3.00 Henry and $55 WTI.

Meanwhile, Apache said its international volumes captured in the final three months of 2017 are coming in lower than anticipated, reflecting unscheduled downtime at the Forties Pipeline System in the UK, which suffered an outage last month. The system provides about 30% of UK’s oil and 10% of its natural gas.

Apache also reported underperforming North Sea wells and lower-than-expected volumes from Egypt assets primarily from improving Brent oil prices on the cost recovery mechanisms in production sharing contracts.

“As a result of these factors, the company expects fourth quarter adjusted international production in the range of 138,000 to 140,000 boe/d and base-level production volumes to be lower than planned going into 2018,” management said.

Christmann said, “Robust Brent crude prices enabled our international operations to generate strong free cash flow during the fourth quarter despite the reduction in production volumes.”

Apache expects to report a $49 million loss in 4Q2017 for realized losses on oil and gas price derivatives, as well as $45-50 million for dry hole costs. For Egypt, estimated tax barrels are expected to be 32,000-36,000 boe/d.

Fourth quarter and full-year 2017 results are scheduled to be issued on Feb. 22.

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