E&P operators in the U.S. onshore are ramping up drilling activity to offset the shrinking drilled but uncompleted (DUC) well inventory.
Crude oil prices topping $100/bbl “have incentivized more rigs, especially from private companies, and the diminishing inventory of DUCs means more drilling is necessary just to maintain levels of production,” said ESAI upstream analyst Elisabeth Murphy.
According to the latest U.S. Energy Information Administration (EIA) Drilling Productivity Report (DPR), the Lower 48 DUC count dropped by 46 units to 4,249 from April to May.
Since peaking in June 2020, the DUC inventory has declined 60% as E&Ps maintained a cash-preservation stance and kept drilling subdued, ESAI noted.
The number of “viable DUCs will likely be depleted by year-end, leaving many producers with no choice but to accelerate drilling to keep production levels up,” said the Boston area-based consultancy.
Freeport Outage Effect?
With the Freeport liquefied natural gas (LNG) export facility in Texas offline for months, Murphy told NGI that she sees a potential midstream issue for the natural gas production that would otherwise be destined for the terminal.
“I think the bigger challenge for the feedgas supplying Freeport LNG might be how the pipeline shipment contracts are structured,” she said.
Murphy noted that Boardwalk Pipeline Partners LP’s Gulf South Pipeline ships about 75% of Freeport’s feed gas. Gulf South carries gas production directly from the Barnett, Eagle Ford, Haynesville shale plays, and from Oklahoma, according to Boardwalk.
“There may be limited ability from a contracting perspective to switch to other pipelines” to carry Freeport feedgas, said Murphy. “But if they can, shippers will be scrambling to find ways to get the natural gas to other pipes serving other LNG facilities or to other markets. If they can’t then I suppose any surplus would be injected into storage facilities.”
Goldman Sachs Commodities Research recently revised its end-of-October gas storage estimate upward but noted that storage levels remain low based on historical data.
“There is not much room for other LNG facilities to increase utilization to make up for the loss from Freeport as most areas are at or near capacity now,” said Murphy. “The exception may be for the new liquefaction trains that recently started commercial operations.”
New liquefaction plants include Train 6 at Cheniere Energy Inc.’s Sabine Pass facility and “about six of the total 18 trains” starting up at Venture Global LNG Inc.’s Calcasieu Pass facility, which should be fully operational by year’s end, said Murphy.
“Calcasieu Pass also takes natural gas from the Haynesville, for example, which also supplies Freeport LNG,” she said.
Accelerating Permian Growth
ESAI also predicted strong production growth in the Permian into 2023 “as the rate of new wells spud has recently begun to rise more than twice as fast as the number of well completions.”
Production growth in other basins, however, could be more subdued, ESAI added. It explained that barring more rapid rig deployments, the lack of DUCs in those basins could lower completion rates.
EIA’s most recent DPR projects nearly 800 MMcf/d in additional natural gas output month/month from the gassy Appalachian Basin and Haynesville Shale as well as the Permian and other plays.
Notwithstanding lingering supply chain bottlenecks and rising costs for E&Ps that “will continue to drag on growth,” ESAI projected that accelerated drilling would yield an 830,000 b/d increase year/year in U.S. onshore oil production by the end of 2022.
Should supply chain problems worsen, further limiting rig and equipment deployments, the low DUC inventory would add downside risk to growth in 2023, said Murphy.
Still, ESAI “currently sees another strong year of production growth from the Permian” next year, particularly if E&Ps raise drilling budgets for the new year.
The most recent Baker Hughes Co. (BKR) rig counts showed growth in the number of U.S. gas- and oil-directed drilling rigs.