The US oil and gas rig count inched up by just one for the week ending March 15 to 839, an analysis of S&P Gkobal Commodity Insight showed, although the Permian Basin – the US' biggest oil-weighted play – registered a seven-rig slide in the same period.
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The Permian's drop in rigs put its rig count on the week at 355. But most of the eight largest domestic unconventional oil and gas plays picked up one to two rigs on the week.
Even though some market watchers feared an unexpected drop in NYMEX oil prices to below $70/b in recent days would cause some upstream producers to cut back their domestic rig fleets, those jitters appeared unfounded so far.
"I think that as this is a fairly recent and unexpected price drop, producers aren't going to have knee-jerk reactions," Reed Olmstead, executive director of North American Upstream Research for S&P Global Commodity Insights, said. "Rigs haven't shown any meaningful changes, and I suspect [they] won't," at least not significantly.
The oil rig count shed six rigs on the week leaving 638, but rigs chasing natural gas gained seven rigs for a total 201.
However, the biggest gas-weighted basins, the Marcellus Shale and the Haynesville Shale, each lost two rigs on the week. That left the Haynesville at 82 rigs and the Marcellus with 33.
Otherwise, the Eagle Ford Shale, and Utica Shale gained two rigs each, making 73 and 12 rigs, respectively, in those regions. Also, the SCOOP-STACK, Williston Basin and DJ Basin all gained a rig apiece, for totals of 43, 42 and 21,
Markets have been keeping an eye on gas-prone basins this year as natural gas prices dropped below the $3/MMBtu level. Some rigs in those regions, particularly the Haynesville, have been transferred to the Permian.
Gas players began 2023 below 'planning prices'
"The bigger changes are coming from gas producers, as they started the year below 'planning prices;," Olmstead said. "Gas producers were expecting prices holding above $3/MMBtu, but given the warmer weather we've had this year, storage is on track to hit fairly high levels, which will continue to drag prices down."
Evercore ISI oilfield service analyst James West, noting the advent of the official spring season in the northern hemisphere along with longer daylight, also said mid-March is a period where capex budgets set earlier in the year "begin to ramp into their full stride of drilling and completion programs."
"After declining for most weeks in the first quarter, the Baker Hughes US land rig count posted its strongest weekly gain last week since early November," West said in his monthly Onshore Oracle report March 22, providing further evidence that US producers have more or less sloughed off the recent drop in oil prices which for NYMEX by mid-week had again nested above $70/b.
The Baker Hughes land rig count totaled 737 on March 17, up five on the week.
"Also, the Primary Vision active frac spread count rebounded March 17 to its highest level since early December," West said -- to 290 -- after mostly lingering in the 270s the last couple of months.
"Financial markets' volatility is clearly weighing on oil prices as the market wrestles with the potential for a recession later in the year," West said. "We expect to continue to debate the impact of oil price volatility on US onshore activity. The expectation coming into this year had been for North American activity to moderate."
At least for rig count data West has calculated over the past month, much of the decline in the rig count was driven by private operators which "typically respond faster to commodity price volatility," he said.
Pressure pumping market still tight
Meanwhile, the pressure pumping market remains "tight" given higher hydraulic fracturing intensity, which requires more pumps at the well site and rebuild cycles occurring at increased frequency, he added.
In addition, lower commodity prices present another issue: oilfield service costs that have become relatively expensive, investment bank Tudor Pickering Holt noted.
"It will be interesting to see if upstream operators in both oil and gas basins are going to be willing to continue to pay service costs that are more akin to $80/b oil and $5/MMBtu gas," TPH said in its March 23 daily investor note. "But as things stand the combination of skyrocketing service cost inflation since 2020 and a plunge in natural gas prices has decimated well level returns in basins like the Haynesville."
"For context, the last time gas prices were at these levels (2020), we estimate the cost to drill and complete wells for select operators was 30%-40% cheaper" in the Haynesville, the bank added. "From a returns perspective, wells in the basin are sensitive to the move in the near-term gas strip given lack of liquids production, with about 25%-30% of the life of estimated ultimate well returns [EURs] produced in year one and around 40%-45% by the end of year two."
EURs across the play vary depending on depth, pressure and reservoir quality, TPH said, generally ranging from 1.3Bcfe/1,000 feet to 2 Bcfe/1,000 feet which, overlaying current well costs, suggest operators need roughly a flat gas price of $3.50/MMBtu to generate well level internal return rates in the 30% range.
While corporate slide decks typically quote breakeven at 10% IRRs, "we believe investors would need to see better returns to justify capital allocation that would keep corporate level ROCE [return on capital employed] in the 10%-20% range," the bank said.