Pressure by state officials on oil producers and pipeline companies is likely needed to address the flaring problem in the Permian Basin, the head of a large Permian pure-play company said.

Though natural gas pipelines providing additional takeaway capacity are welcomed, low natural gas prices, pipeline takeaway commitments and other economic factors remain an issue when it comes to flaring of gas, according to Pioneer Natural Resources Co. CEO Scott Sheffield.

“That’s the biggest issue we have to solve with the producers and with the pipeline companies,” Sheffield said during a recent Permian-focused event hosted by the Center for Strategic & International Studies. “And the states probably need to do a better job of putting more pressure on both groups of people, in my opinion, to solve that problem.”

The amount of gas flared has steadily increased, for the most part, in the Permian Basin as oil production has risen in recent years. In Texas, flaring of associated gas from initial completion beyond 10 producing days is prohibited. But that state routinely grants exemptions to the rule.

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Pioneer, which has about 20,000 drilling locations and more than 10 billion barrels of defined resource in the Permian Basin, doesn’t start producing from a horizontal well until the well is connected to a pipeline or a gathering system, Sheffield said. But he pointed out there are a lot of companies, mainly in the Permian’s Delaware sub-basin, that start producing oil and flaring gas immediately with no gas pipelines in place, he said.

Sheffield, who spoke as part of a panel with Chevron and Kayrros, singled out small- and mid-sized independent producers and private equity-backed companies for not signing up for the minimum volume pipeline commitments. Generally, most pipeline companies want about 75% commitment from producers before they move forward on building pipelines; however, such commitments go on oil companies’ balance sheets and smaller companies might not be able to cope if rig counts fall, Sheffield said, impacting production and ultimately, profits.

“Most independent producers are not signing up for takeaway capacity because they are getting very little,” Sheffield said. “What’s driving the slowness of these new pipelines is that … they cannot get the 75% commitment.”

He added, “We should be adding 21 Bcf/d [billion cubic feet per day] of natural gas lines. We’re only adding six, so this flaring issue is not going away with these three new pipelines.”

‘Economic Sense’

Speaking during a different panel, Rusty Brazil, president and principal energy markets consultant for RBN Energy, said it makes economic sense for producers to flare when they can break even on a typical Delaware well—even with a $45/bbl oil price and negative $2 for gas.

“Now again, nobody wants to get a negative $2 price for the gas but it certainly does mean that economically flaring is not such a bad idea,” Brazil said. “Bad idea for the environment, for sure, but not necessarily economically.”

He put the amount of gas flared in the Permian at between 450-500 million cubic feet per day (MMcf/d) based on data from the Texas Railroad Commission (RRC).

Earlier in September, energy consultant Rystad Energy reported flaring in the Permian dropped in first-quarter 2019 for the first time in 1.5 years to 613 MMcf/d, down 7% from its previous estimate.

“A lot of these producers do have pipeline capacity out of the Permian; therefore, they’re getting pretty good prices for their product even on natural gas,” Brazil said.

However, with few exceptions, the amount of flared gas has been trending up.

Andrew Gould, advisory board chairman for Kayrros and a board member for Saudi Aramco, showed a heat map illustrating how much flaring has increased in the Permian since 2012.

“This is a No. 1 problem that the industry has to address,” Gould said later explaining how flaring is linked to the acceleration of new production. “But some people can’t afford to wait to take care of gas before they have to produce [oil].”

Putting monthly limits on flaring in the Permian would have “a dramatic effect on the economics of the independents almost immediately,” he said.

Seeing Value

Yet other companies, particularly the majors and large E&Ps, are looking at the entire value chain—gas included—when forming field development plans.

Chevron Corp. has had a no-flaring company policy since 2008, according to Stephen Green, president of Chevron North America E&P.

“That doesn’t mean you won’t ever see a Chevron facility that has a flare. We do have to use them for safety and operational issues,” Green said. “But we don’t bring on production with flaring as a routine part of the operations.”

As an industry, flaring needs to be addressed, he said, challenging his industry colleagues.

Part of the answer lies in infrastructure and takeaway capacity to bring those molecules to market, he said. It is also part of the field development strategy.

Chevron aims to grow its Permian production to 900,000 barrels per day by year-end 2023.

“When we consider a development area, we consider not just how many rigs it’ll take, how many wells we can drill, what the production volume is,” Green said, later noting how attention is paid to the oil-gas ratio—something Sheffield also touched on. “But how do we access markets whether it’s gas or oil. That is why we’ve had a purposeful strategy of focusing on ultimate recovery resource but also an integrated strategy of the entire value chain.”

Gas is seen by Chevron as potential feedstock for petrochemicals, LNG, heating, power generation, powering drilling rigs or pumping fleets.

Both Green and Sheffield acknowledged economic challenges surrounding the flaring issue and how it impacts operators differently.

“But as an industry this is an issue that we have to come to grips with and figure out how to address for the long term,” Green said.

Looking Back

During the panel discussion, a highly watched move by the RRC was discussed. In August, the RRC gave Exco Operating Co. permission in a 2-1 vote to flare in the Eagle Ford Shale despite opposition—the first in the state’s history—by The Williams Cos. Inc. The midstream company has a pipeline nearby but no contract with Exco.

The decision essentially shows that the state wants the producer and pipeline company to solve issues themselves, Sheffield said.

“That’s their current state of mind,” he said of the RRC. “We’re taking a little bit different role. We’re going to create more slides publicly on our IR [investor relations] deck to talk about a lot of our practices such as not tying in wells until they are connected. We install [like Chevron] vapor recovery units on every new well. We’re going to be more public about the slides, and that’ll help pressure other companies to do so.”

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