IHS CERAWeek: US shale resilience a product of innovation, CEOs say

Feb. 25, 2016
Two chief executives who contributed to the US shale boom came together on Feb. 24 to lament the current oversupplied, low-price environment they helped create, and explain how their respective firms have remained resilient in spite of it all.

Two chief executives who contributed to the US shale boom came together on Feb. 24 to lament the current oversupplied, low-price environment they helped create, and explain how their respective firms have remained resilient in spite of it all.

“This is the worst I’ve seen it from a balance sheet standpoint,” said Scott Sheffield, chairman and chief executive officer of Pioneer Natural Resources Co. (PNR), during an exploration and production-themed panel discussion at IHS CERAWeek in Houston.

Sheffield has worked 37 years at PNR and its predecessor company. He noted that hedges and equity kept the industry afloat in 2015 when crude oil prices began the year down by more than half compared with 6 months earlier. Now, with capital running out and continued price volatility, US E&P firms are reeling.

Dave Hager, Devon Energy Corp. president and chief executive officer, seconded Sheffield’s observations, stating that “30 and 2 doesn’t work” in reference to the current oil and gas prices that are hovering around $30/bbl and $2/MMbtu, respectively.

Sheffield was adamant that oil prices need to be much higher for an eventual, meaningful rebound in output. “US shale production will not grow at $40-45[/bbl],” he asserted. “It won’t grow at $50[/bbl], in my opinion. There’s not enough cash flow in the business to grow US shale. US shale needs $60-70[/bbl] to grow production.”

PNR has built its asset base around the Spraberry-Wolfcamp, where big returns have enabled the firm’s production to increase at a rate of 10%/year, Sheffield noted. Of the firm’s $2-billion capital budget set for 2016, $1.71 billion will target the northern portion of the Spraberry-Wolfcamp (OGJ Online, Feb. 11, 2016).

PNR’s results in West Texas contrast with that of South Texas, where the “returns were so poor” in the Eagle Ford that the firm cut its rig count to 0 at the beginning of the year.

“The Eagle Ford has gone from [production of] 1.6 million b/d to 1.3 [million b/d],” Sheffield said. “I think it will be down to 1 million b/d by the end of this year.” He believes the play’s overall rig count will soon shrink to 25, compared with 200 at the beginning of 2015.

“The Permian hasn’t dropped that much because it’s mostly oil and the returns are much, much better,” he explained, noting there are 70 rigs in the Midland basin and 70 in Delaware basin because “the economics are still there.” Output from the Permian is currently flat at 2 million b/d and will likely remain that way, he said.

Sheffield expects additional output declines this year of roughly 600,000 b/d from the Eagle Ford, 200,000 b/d from the Bakken, and 200,000 b/d from other shales.

Hager likened dramatic shifts in overall US shale production—from increases to losses and vice versa—to “turning an aircraft carrier” given all the variables involved. The timing of a rebound “depends on how long this [decline] extends,” he said. “The longer it extends, then the greater the depth. The more difficult it will be to come back.”

Improved completions

Hager explained that the industry has been able to stave off a dramatic production decline because of reduced costs. Service providers have lowered their rates, and operators, such as PNR, have maximized their rig counts.

Completion technologies have also dramatically improved. “We’re essentially [on] ‘Frac 2.0,’” he said, adding that Devon is using “a lot more proppant than a year or two ago.” The firm is now using about 1,500 lb/lateral ft of sand and has used up to 3,000 lb/lateral ft, he said. As a result, Devon has improved 30-90-day initial production rates from large plays by 75-100%.

He concluded that improved completions are making rig counts “kind of an obsolete measure” because of the greater efficiencies seen from both rigs and wells.

Similar efficiencies have been reported by PNR. “We’re adding more sand. We’re adding more fluid—water,” Sheffield said. “We’re reducing cluster spacing from 60 ft to 30 ft to 15 ft to 10 ft. We’re taking laterals in the Permian basin where we started at 5,000 ft—we’re all the way up to 12,500 ft now.”

Estimating that services companies were making 300% returns on frac stimulation at the top-end, Sheffield noted that PNR “was probably one of the largest companies to go into vertical integration,” and now employees who “know how to frac wells” are hired from services companies.

PNR has since built its own frac fleets and acquired its own sand mines. “When we got into the frac business it paid off in 12 months,” he stated.

Sheffield stressed the importance of maintaining a stable, talented workforce in surviving the downturn, as PNR is yet to report large-scale layoffs. “If the industry loses too many people over the next 2-3 years, it’s going to be hard to come back,” he said. “And I saw that in [the downturn of] 1999.”

Although Devon slashed its 2016 capital expenditures by 75% (OGJ Online, Feb. 17, 2016), which includes a workforce reduction of 20%, Hager noted that “you cannot cut your costs to success in this environment.” Companies have to find ways to keep the “true value creators and innovators.”

Shedding downtime

Lorenzo Simonelli, GE Oil & Gas president and chief executive officer, provided perspective from the services side of the industry. He emphasized the necessity of collaboration between the supply base and operators to ensure the best outcomes.

A primary obstacle he’s noticed the industry experience is unplanned downtime. “On average our industry runs 2-3 times a higher rate of unplanned downtime vs. the average industry in the United States,” he said. “So there’s a lot of efficiency we can gain by going after that 2-3 times higher rate.”

PNR and Devon on their own have implemented separate solutions to dramatically reduce their respective downtimes.

PNR is now entirely employing gas lift for horizontal wells, reducing downtime to 1.5%. All of Devon’s wells are remotely monitored, enabling immediate action should an issue arise. “We have seen where we have actually decreased the decline rate of the company by 2-3% by having this approach, and 2-3% is a pretty significant number in terms of value,” Hager stated.

Contact Matt Zborowski at [email protected].