The Permian basin may be the first Lower 48 region to show signs of recovery as the oil and gas industry seeks to emerge from a first-half 2020 marred with dramatic cuts to budgets, operations, and production. Entering the year’s still-questionable second half, there are signs of activity, but at a much slower pace.
Hydrocarbon output from the region had been a driver of US onshore production going back to 2013. Companies sought ways to increase continuous acreage for larger scale operations allowing for longer laterals and more recovery, even through the previous downturn. A pandemic and the Saudi Arabia-Russia oil price war changed this landscape. In relatively short order, the $60-70/bbl range bound West Texas Intermediate (WTI) futures contract price at Cushing, Okla., plummeted [assuming we’re talking about the WTI futures price vs. physical spot pricing]. Before the headline-making, all-time front-month contract low of negative $38/bbl, a downturn to $20/bbl and below coupled with a bleak forecast pushed producers in all regions to cut budgets and curtail production, including those in the Permian.
Many of the cuts were set to begin in May and extend into June. Volumes in the Permian basin are expected to fall by 87,000 b/d month-over-month to 4.3 million b/d in June.
With unpredictable market conditions, operators left open the possibility for additional cuts or curtailment extensions. But a strong start to the historic 9.7-million b/d production cut by the Organization of Petroleum Exporting Countries and others (OPEC+) —the group delivering a 9.4-million b/d cut in May—coupled with the easing of certain restrictions implemented due to COVID-19, helped buoy prices into the mid-$30/bbl range as of late June.
For some, the change in market conditions has been a catalyst for a shift in near-term operations.
In an early June interview with IHS Markit Vice Chairman Daniel Yergin, ConocoPhillips chairman and chief executive officer Ryan Lance was asked about the company’s overarching US shale production curtailments. “I would say we’re probably thinking of slowly coming back into the market over the next few months and reducing the amount we’ve got curtailed because we’re seeing some strengthening in the price,” he said.
The company holds some 800,000 net acres in the Permian basin, including 88,000 unconventional net acres in Delaware basin, 58,000 unconventional net acres in Midland basin, and an additional 21,000 unconventional net acres in various other plays in Northwest Shelf. ConocoPhillips’ net Permian production 2019 was 86,000 boe/d, which included 56,000 boe/d of unconventional production. Its Permian unconventional production in first-quarter 2020 was 70,000 boe/d.
Absent Permian-specific curtailment numbers, a June 30 company statement noted second-quarter 2020 companywide curtailments—primarily related to oil production—averaged 225,000 boe/d on a net basis. Of the total net curtailments, 65% were in the Lower 48, where the company said it expects to begin bringing some curtailed volumes back on line in July, while continuing to make production decisions in the months ahead. The company will report second-quarter operational and financial results on July 30.
EOG Resources and Parsley Energy, too, will reactive certain shut-in wells during second-half 2020. EOG curtailed a quarter of its oil volumes in May. A mid-June investor presentation outlined a 2020 Delaware basin plan to bring 220 net planned wells online using a nine-rig, four-fracturing crew program. The company produced 174,000 b/d of oil from the region in 2019.
Activity detected by Enervus and RS Energy Group (RSEG) showed the Delaware basin as the most active for Lower 48 fracture crews, with 16 at work as of June 12. EOG was the most active operator in the basin, with seven working crews at the time. RSEG uses a combination of high-frequency satellite imagery and telemetry data to pinpoint well life-cycle events, including pad construction, spud, and fracture treatments.
“Actively fracturing pads are a leading indicator for fracture fleet demand and wells expected to be turned onto production,” RSEG noted in a release at the time.
In early June, Parsley said it planned a June restart of most of the wells it had shut in to create a 28,000-30,000-boe/d curtailment in May. First-quarter 2020 production was 197,000 boe/d.
While shut-in wells may be reactivated in the year’s second half, neither company announced plans for new drilling activity.
A June 14 blogcast by Jason Ferguson, director at RBN Energy LLC, highlighted these developments. “Permian producers have already begun looking at $35/bbl WTI as a positive development,” spurring some exploration and production companies in the region to end curtailments in June, “while others have been more veiled, saying wells would be coming back later this year.”
Given price volatility, the cautious rhetoric isn’t a surprise, Ferguson said. But if prices stay near current levels, RBN expects “Permian curtailments to shrink to only 275,000 b/d [in June], roughly half of the May level. That would bring June production up to just over 4.22 million b/d, a gain of about 150,000 b/d over [May].” The full 275,000 b/d of production that was “uncurtailed” in June is partially offset by natural declines from May to June of about 130,000 b/d, he said. “Should prices hold steady through June, then July could see shut-in production curtailments fall further, as there is little economic reason at these price levels to suppress field volumes,” he said.
RBN estimated curtailments in the basin averaged about 550,000 b/d in May, reducing its Permian production estimates for the month to 4.08 million b/d, down from 4.75 million b/d in April.
While curtailments are expected to fall, don’t expect record-high oil production from the Permian anytime soon, Ferguson said. In fact, “base production had already been declining, even without the shut-ins…because rig counts and well completions have been severely reduced and aren’t likely to rise quickly. While there may be a few bold producers willing to add to their rig count at today’s prices, we think most will remain focused on maintaining current activity levels until prices start to approach $50/bbl.”
In a June investor presentation, Permian pure player Concho Resources said it would decrease its rig count to eight for second-half 2020, down from 10 in the second quarter, and 18 in the year’s first half. The company expects to complete and put on production 190-210 gross operated wells for the year with total year production and total year oil production in line with 2019 divestiture-adjusted volumes of 310,000 boe/d and 197,000 bo/d, respectively. The numbers include voluntary curtailments, but no future potential curtailments. Second-quarter 2020 results are to be reported July 30.
Diamondback Energy ceased all completion operations in early March and planned to average less than one completion crew in second-quarter 2020, noting commodity prices would dictate future activity. The company said it would cut its operated rig count to seven by October. The number is down from 14 in May and 20 in January. The company cited plans to slow production without adding operational expenses that included curtailing 10-15% of May oil production.
A return to $30/bbl WTI isn’t enough to end curtailments in and of itself, said Ryan Duman, Wood Mackenzie principal analyst, Lower 48. “At $30/bbl, roughly 95% of onshore US Lower 48 production can cover its short-run marginal cost. That would signal barrels coming back online. But shutting-in wells isn’t costless and many times the technical things that can go wrong will. Price uncertainty plays a role too. Producers won’t want to turn the taps off, on, off, on, and off again,” he told OGJ via email. “Production shut-ins of this magnitude are uncharted territory, he said, “and how the wells respond when producers turn pumps back on isn’t fully understood.”
Capital and output from the Lower48 are likely to be focused on the Permian basin in the coming years as the industry recovers, beginning with the restart of shut-in wells. But supply costs, inventories, and balance sheets will be important factors. An uptick in the spread of COVID-19 and uncertainties about the pace of economic recovery leave companies reluctant to provide production guidance for the remainder of the year.
While the Permian basin is expected to be the first to recover, the road to pre-2020 production levels may be long, Duman said. “We do expect the Permian to recover first and growth to begin towards the very end of 2021. While the region is expected to grow through 2030, it’ll be at a much slower pace than what we experienced pre-2020.”
