No recovery in sight for US shale
Barrels may have returned to the market, but lack of drilling and bearish conditions will likely see production fall sharply across Q4
The US shale patch is primed for a steep production decline in the fourth quarter that will likely spill over into 2021, the result of a lack of drilling and increasingly wary producers. WTI again fell below $40/bl in late September on fears that a second global wave of Covid-19 infections could further stall economic recovery.
Curtailed production from earlier in the year has now almost entirely returned to the market. But the sector’s recovery looks limited given hefty capex cuts, a focus on capital discipline and the lack of motivation that continuing low prices will engender.
Well completions and frack spreads have plunged through 2020. “The current frack spread is at 89, down by c.75pc year-on-year,” says Allyson Cutright, director of global oil at research consultancy Rapidan Energy. “This will not be enough to maintain current production. We assess the frack spread would need to average c.160 through to year-end to keep production flat at June’s level.”
“As you look at what is going to bring back activity, you are probably in that $50-60 world” Hamm, Continental Resources
The rig count has also slumped by a whopping 64pc since early January, despite rising marginally since July, according to data from US consultancy Enverus. Rather than finish wells, companies are building up their inventories of drilled-but-uncompleted (Duc) wells to prepare for a future price uptick.
Consultancy Rystad Energy estimates that domestic production would need 280-300 well completions to keep volumes flat into next year. But heading into the fourth quarter, current activity sits at just 50pc of that level. Ducs in the Permian have been stockpiled to the equivalent of 13 months of fracking, with that figure rising to 22 across the remaining US basins.
And while this implies ample potential for production recovery, producers will most likely continue to pull back spending until WTI improves. “Large, well-established operators will stay committed to capital discipline, only increasing their completion spend gradually in the current price environment,” says Artem Abramov, head of US shale at Rystad.
US independent Continental Resources adds that, for many firms, the oil price will need to rise above $50/bl before much change is seen. “As you look at what is going to bring back activity, you are probably in that $50-60 world,” says Continental chairman Harold Hamm. “Until that point, I think the industry will be pursuing pretty moderate growth rates.”
The Bakken shale play in particular faces headwinds going into the fourth quarter. In July, the Dakota Access crude pipeline was denied an environmental licence, a decision that will reduce exit capacity by 570,000bl/d unless overturned.
Rapidan estimates the decision will impact 200,000bl/d in curtailed output and encourage crude-by-rail as the only alternative, adding $5-10/bl to transportation costs. The result will likely see multi-basin producers switch capital away from the Bakken until pipeline capacity returns.
Production growth in Oklahoma could also slow because of a landmark Supreme Court ruling. In July, almost half of the state was deemed native American territory, split between five nations.
The ruling grants control of oil and gas acreage to the federal government rather than explicitly gifting it to indigenous groups. But the decision will likely see demand from indigenous groups for a share of taxation or more rigorous environmental legislation, complicating future drilling. Two of the highest producing counties in Oklahoma—Grady and Garvin—now fall within Chickasaw territory.
Federal land regulation is also a major headache for US shale producers heading into the November national election. A victory for Democrat Joe Biden would likely see a termination of new onshore leases, impacting all major basins.
Steep production declines in the Permian, particularly in the main counties of Eddy and Lea, make this problematic for future growth. Producers may be forced to pull funding out of New Mexico and reallocate it to Texas, where there is less federal land, to lift production. Rapidan estimate a Biden win could see shale production end 2021 at c.100,000bl/d less than December 2020 levels.
To offset the looming threat, producers are rushing to stockpile permits ahead of the election. “About 55pc of our acreage in the Delaware is federal—that is where some of our highest return opportunities are,” says David Harris, executive vice president of E&P at US indie Devon Energy. “And so, I would expect that you will continue to see us lean on that permit inventory, drill those wells and then supplement it with state wells where we can and need to.”
With production set to slide in the fourth quarter and likely to continue to do so until the end of the first quarter next year, another concern for the sector will be lack of sufficient hedging. “Only 38pc of the companies we track have outlined 2021 hedging programmes,” says Cutright. “These companies produced 1.7mn bl/d in Q1 but have only hedged 0.5mn bl/d in 2021.”
64pc – Rig count decline in 2020
The already struggling shale sector will be highly exposed if a second wave of Covid-19 infections knocks the oil price curve lower for longer. The result will be sustained downward pressure on production levels and likely further bankruptcies.
US law firm Haynes and Boone estimates that 36 US oil patch firms have so far filed for bankruptcy in 2020, with total debt valued at $50.9bn. But robust hedging has largely prevented anything like the levels of bankruptcy recorded in the wake of the oil price crash of 2014-16.
But heading into 2021, high debt maturities across US shale paint a different picture. More bankruptcies are expected until the Covid-19 pandemic is over, or at least until more normal economic conditions and demand levels return. “While the most efficient shale companies can do well at or slightly below $40/bl WTI, many will continue to struggle. Shale bankruptcies will likely continue through end-2020, if not longer,” adds Cutright.
Beyond US shale, Gulf of Mexico production has also been hit hard through the hurricane season in late August and September. Hurricanes Marco and Laura removed around 14.4mn bl from the market, according to Rystad, while Hurricane Sally was expected to cut roughly 3-6mn bl/d.
US agency the Bureau of Safety and Environmental Enforcement reported over a quarter of oil and gas was shut in and almost a quarter of platforms evacuated when Hurricane Sally struck the Gulf coast in mid-September.
In contrast, Hurricane Laura caused over 84pc of oil to be shut in and almost half of all platforms to be evacuated. Refinery capacity of c.2.34mn bl/d was also forced to be shut down as the Category 4 Atlantic hurricane made landfall in Texas and Louisiana.