Proposals to limit production from Oklahoma natural gas wells made to regulator

Oklahoma is one gassy place.

Up for debate is a question about whether the state’s 8 billion cubic feet per day of production is wasting a precious natural resource.

Backers of a plan to crimp the allowable production from unallocated natural gas wells within Oklahoma argue that’s the case, suggesting that reducing chronic oversupplies of the product could help improve its price.

But not all Oklahoma energy producers agree.

During a technical conference held by the Oklahoma Corporation Commission last week to discuss the issue, differing views were expressed.

While the founder of one privately owned exploration and production company told representatives of the agency’s Oil and Gas Conservation Division the agency should curtail production, representatives of two publicly traded companies countered that allowable production limits should be left unchanged.

A representative from a third publicly traded company, meanwhile, indicated it supports a reduction of allowable flows, but to a lesser degree than what the private producer seeks.

The agency’s three elected commissioners also attended, asking plenty of questions.

It is their decision to make.

Debate nothing new

The commission has had the power to control the production of natural gas and (at one time) oil in Oklahoma since the 1930s under state law and rules enabling it to conserve natural resources, protect public safety and to promote economic development.

The issue dominated newspaper front pages across the state then, when Gov. Alfalfa Bill Murray declared martial law and sent the Oklahoma National Guard into the Seminole and Oklahoma City fields to force operators to shut in their wells.

Oklahoma, which at the time didn’t collect income taxes, relied even more heavily on gross production taxes to pay its bills than it does today, and overproduction of both oil and natural gas had pushed prices for the commodities to extreme lows.

While oil controls were dropped as daily production of that commodity declined off discovery-related highs, the commission’s ability to limit natural gas production remains.

The agency exerts that control by setting a proration formula it has revisited and revised many times throughout the years.

A no-limit limit

Since 1999, commissioners have routinely ordered operators to limit production from unallocated gas wells at either 65% of a well’s absolute open flow potential or 2 million cubic feet per day, whichever is greater.

But it effectively is no restriction at all, given its parameters exceed production capabilities on nearly all gas wells in the state. All gas producing wells have been considered "unallocated" since Oklahoma decades ago quit regulating its production basin-by-basin.

Public and proprietary industry records show there are between 40,000 and 50,000 operating unallocated gas wells in Oklahoma.

Duncan Woodliff, a production and compliance manager in the agency’s oil and gas conservation division, said this week the current limit affects production only from a few hundred of wells, and then only briefly.

That is because only newly drilled horizontal wells are that strong and because their production levels tail off rapidly.

But overall gas production in Oklahoma has climbed significantly over the past decade (about 1 trillion cubic feet more in 2018, compared to 2008), because of horizontal drilling and completion techniques.

While midstream companies have been building out gathering systems and processing plants to handle some of that increase, they haven’t been able to keep up.

As pipelines and plants have filled and global markets for the fuel have changed, supply has far exceeded demand and that has caused its price to fall to historic lows, said Jeff McDougall, founder of JMA Energy in Oklahoma City.

Changing conditions

McDougall said ups and downs in oil and gas prices once controlled the industry. Good pricing promoted drilling, while poor pricing caused a pullback in activity until supply and demand markets rebalanced.

But that model, he said, has been disrupted over the past decade by private equity funds’ investments in many private and some publicly funded companies.

Equity-backed companies need to keep drilling to produce enough to meet investors’ cash flow requirements, he said.

That has kept service company pricing more expensive, making it difficult for other companies to remain competitive.

Also, natural gas pricing no longer is tied to oil prices like it once was. While oil at times has reached record highs the past decade (also keeping service company costs high), natural gas pricing hasn’t followed suit.

Plus, midstream companies have begun using fixed pricing contracts with producers to handle their natural gas, unbundling that cost from the commodity’s value and tying it instead to capacity availability.

In basins where there is plenty of gas and a shortage of capacity, transport costs are considerably more expensive, McDougall said.

Outside of the Permian Basin, the western portion of the Anadarko Basin is the worst place in the nation to be a natural gas producer, McDougall said.

Because of that, the realized price JMA Energy has received per equivalent thousand cubic feet of production from its wells has fallen dramatically, even since 2016, he explained.

“We drill out of our back pocket,” said McDougall, who also told the agency he recently had to cut staff at his company because of current market conditions.

“We are a good canary in the mine shaft, because we are sensitized to all the issues that are surrounding our business.”

McDougall said data he gathered indicates the state could cut as much as 1 billion from its 8 billion cubic feet of daily production and still manage to only impact slightly more wells if it were to set a formula that would cut each well’s allowable production to 32.5% of absolute open flow or 1.5 million cubic feet daily, whichever is greater.

He also requested regulators to do a better job of requiring companies to document they aren’t violating the limit and suggested other changes in rules involving the drilling of horizontal wells to eliminate routine excess production allowances granted for multiple wells drilled within the same permitted unit.

“Cutting production would loosen the prices and allow more natural gas to get into the pipe,” he said.

Dicey terrain

Commissioner Bob Anthony, a member of the National Petroleum Council for more than a decade, said the commission has gotten heat in past years for setting meaningful natural gas production limits from critics who claimed the agency was taking steps to artificially push the commodity’s price higher.

Anthony said companies potentially would be violating antitrust laws if they worked together to set natural gas production limits among themselves to boost its price. He also observed that production limits usually are opposed by producers who need cash to meet financial obligations.

“It is kind of a no-win situation,” he said.

Representatives from Devon and Gulfport Energy told commissioners and staff they oppose any change to the formula.

“We think the lower allowable limit would create a disincentive to drill wells and could cause capital to move to other states” where flows aren’t restricted, Heather Lacy, a regulatory compliance professional with Devon Energy, told officials.

Lacy said limits also could prevent the company from meeting minimum volume commitments required by some of its existing contracts with midstream companies.

Josh Lawson, Gulfport Energy’s vice president of operations, indicated his company also opposes any change.

Space on interstate pipelines currently held by Oklahoma production likely would be filled by production from elsewhere if an artificial limit lowered the state’s production, he said.

Mike Mathis, a regulatory affairs adviser with Continental Resources, said his company supports changing the proration formula to limit a well’s absolute open flow to 50%, but also said it supports leaving the allowable production per day portion of the formula unchanged.

While he observed Continental Resources recognizes the change could hurt other operators, Mathis noted his company is the largest and would be impacted the most by any reduction. He asked that the commission revisit the issue in three months if any change is made.

The over-production of natural gas also is a significant problem in North Dakota and Texas, where producers often burn it off using on-location flaring systems, Mathis added.

“We hope as part of this, the commission sends a signal to other regulators in the country that there is an issue that needs worked on” throughout the country, Mathis said.

“We are willing to take a bigger hit on this to send the right signal to the market.”

Along with Anthony, Commissioners Dana Murphy and Commission Chairman Todd Hiett thanked the oil and gas conservation division staff for its work on the issue and company representatives for their comments, observing they were provided with a considerable amount of information to evaluate as they ponder the issue.

Another hearing before commissioners on the question is set for Feb. 18, officials said.