The US onshore oil and gas outlook is somewhere between sinking and stagnant.
Oil and gas companies recently reported another quarter of slowing activity, according to the recent survey by the Kansas City branch of the Federal Reserve Bank.
Its survey covering exploration and production in New Mexico, Oklahoma, and Colorado showed slowing drilling, shrinking profits, and reduced business activity.
One plus: Workers don’t seem affected by the doldrums. The survey reported that the number of employees and the number of hours worked “remain positive.”
An anonymous commenter in the survey said, “Our company could do more and would do more if we could find quality people. The traders have believed the recession talk and have hurt commodity prices. The fundamentals still show energy use increasing.”
The report mirrored a run of recent reports from the US Energy Information Administration (EIA) predicting flat future oil prices, and gas prices recovering from awful to about average.
The number of drilling rigs working dropped by more than 100 during the first half of the year and has stabilized in the weeks since, according to the Baker Hughes report done by Enverus.
Fracturing capacity measured by the number of fleets is also flat and likely remain that way.
“There are approximately 290 active fleets and we do not see that increasing,” said Justin Mayorga, vice president for shale supply chain research for Rystad, adding, “No one wants to see any growth, even investors.
An exception to that observation: Operators have been willing to pay up for higher-horsepower pumps that allow them to maintain high pumping rates while going faster by fracturing multiple wells at the same time.
The Thrill Is Gone
The days when $75/bbl oil could drive a drilling boom are past.
That price is near the current benchmark for WTI, which is high enough to sustain drilling—comfortably above the $63/bbl breakeven price in the Fed survey—but well short of the $86 average its respondents said is needed for a substantial increase at a time when doing more requires paying more in a tight oilfield services market.
On the gas side, the survey said benchmark Henry Hub futures price, which remains around $2.60/Mcf, is below the average needed for drilling now—at $3.49/Mcf—or to trigger substantial growth—$4.67/Mcf.
Neither oil nor gas prices are expected to rise to levels needed to spur a significant jump in activity over the next couple years, according to the Kansas City Fed and the EIA short-term price outlook.
Those numbers are reducing drilling activity in every major US unconventional play except the Permian Basin, which is still looking attractive to companies wanting to add acreage to sustain their production as older wells rapidly decline.
But that is getting harder to do. Over the past 2 years, $60 billion in asset sales has sharply reduced the supply of operations for sale by private-equity investors, according to a recent weekly report from Enverus.
It took years longer than planned by investors who hoped to quickly flip those companies. But the flood of recent deals, including $14 billion in sales during the first half of this year, has shrunk the inventory to the point that sales are expected to drop during the second half.
That “comes not from a lack of buyer appetite, which looks to be stronger than ever as public E&Ps grapple with replacing drilled inventory, but from a lack of remaining opportunities to buy in the prolific region,” said Andrew Dittmar, senior mergers and acquisitions analyst for Enverus.
The remaining big potential targets in the Permian have been around for a while and are less likely to sell.
“There are about 15 private companies in the Permian with more than 100 locations, and most are established private companies such as Endeavor Energy Resources and Mewbourne Oil,” according to the Enverus’ energy database.
There are other US shale plays out there, but Dittmar said the sales trend has been extremely “Permian-centric,” accounting for 99% of the total private-equity sales value in 2023.
“Unless that shifts, which looks unlikely at this stage, that Permian concentration means the pace of sales is unlikely to be maintained through the back half of the year,” Dittmar said.
Except the Permian
At the end of June, the west Texas super basin was the only one with more rigs working than a year before, and that was up only 2%.
Nationwide, the number of rigs working was down 12%. The biggest declines were in the Anadarko Basin—down 36%—and the Haynesville Basin straddling Arkansas, Louisiana, and the east Texas border—down 28%.
While the surge in gas prices which pushed up drilling for gas in recent years has passed, production during the first half of the year is still well above the levels going back to 2021, according to an EIA report.
Permian gas output is steady because it flows along with more valuable oil. Gas-only production from the Marcellus and the Utica has been flat, according to EIA.
One sign of weakness: The output for four counties in Pennsylvania, which produce 40% of the gas from that huge gas region, declined by 3%. The EIA said the many stalled pipeline construction projects have put a lid on the output.
An EIA report on the recent slowdown in the Marcellus noted, “Until last year, output had increased every year since 2013 on the back of drilling efficiency gains. One measure of drilling efficiency is the average volume of natural gas produced in wells during the first 6 months of drilling. Drilling efficiency at Pennsylvania’s natural gas wells increased every year since 2013 before declining for the first time in 2022.”
