The ongoing decline in active U.S. land rigs gathered pace again in the latest count by Baker Hughes Inc., with 14 units departing. However, along with a general slowing of declines in recent weeks comes talk by some analysts of what a comeback might look like.
In the previous week's count five natural gas rigs had departed and were offset by the return of one oil rig (see Shale Daily, March 18).
After losing 14 units, the U.S. land rig count ended at 432 active units on Friday. One rig was added in the inland waters and another in the offshore to make for a net U.S. decline of 12 units. Canada dropped 14 rigs (13 gas and one oil), as spring break-up season continued, to end at 55 actives on Friday. The overall North America count was down a net 26 units to end at 519.
In the United States, 15 oil rigs departed, offset by the return of three gas-directed units. Ten of the departing rigs were horizontals, joined by five verticals and offset by the return of three directional rigs.
The Eagle Ford Shale gave up four rigs and the Permian Basin lost five, making them the biggest losers among plays. Texas saw the loss of eight rigs, making it the biggest loser among states.
In a note Friday, BMO Capital Markets asked, "When does shale come back?" Analyst Phillip Jungwirth and colleagues said, "...we think $45-50/bbl WTI is the price in which E&Ps begin increasing activity, but not significantly. This conclusion is based on E&Ps being close to cash flow at $50/bbl and 2016 budgets."
Wunderlich Securities Inc. analyst Irene Haas and colleagues are looking for the inventory of drilled but uncompleted (DUC) wells to be worked off. As the downturn lingers, the "DUC count has likely peaked as 2016 looks like a year where the capital spending of E&Ps will shift to a more heavily focused completion budget while the drilling budget slows as [rig] contracts roll off," Wunderlich said.
"We think the current historically low and declining rig count shows that phenomenon to be true and expect the DUC discussion to subside as the inventory is worked off."
While DUCs totter off, natural gas output from some basins is declining, said analysts at Jefferies in a note published Tuesday. "Despite ephemeral gains in the Northeast from new infrastructure, production appears to be falling in the background," Jonathan Wolff and colleagues wrote. "The Fayetteville, East Texas, Barnett, Rockies (Piceance) combined to fall by about 160 Bcf/d sequentially in February.
"The Barnett has declined for 10 consecutive months, while the Piceance has decreased for seven months and the Fayetteville for five. Volumes from these four basins are down about 1.5 Bcf/d year over year. While the Haynesville saw a slight increase in volumes during February (about 35 Bcf/d), production remains down slightly year over year."
Last month, natural gas production from the Eagle Ford Shale fell by about 100 MMcf/d (1.3%) to about 7.3 Bcf/d, according to Jefferies, which said it was the largest absolute decline of the 21 basins it tracks.
And turning to the Permian Basin, which has provided operators with the most robust well economics during the downturn, it won't take much to bring rigs back, and they can return quickly, said Cowen and Company analyst Marc Bianchi and colleagues. "Overall, we think the industry can add at least 12 rigs/week in the early stages of recovery," they said. "We believe a few hundred drilling rigs and associated services could be added before service providers are able to gain pricing power.
"Based on indications from E&Ps, activity can begin to increase at the $45/bbl level."