The Colorado Sun


Western Slope commissioners say rules designed to pull the Front Range into federal ozone compliance are an “economic risk” for northwest Colorado

Colorado is moving to tighten air emissions from a range of oil and gas activities – including hydrofracturing or fracking – with a general consensus among industry, environmental and community groups.

In two days of testimony before the state’s Air Quality Control Commission there was general support for proposed rules covering fracking and drilling, internal combustion engines and the unloading of drilling wastes into storage wells.

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To be sure, sharp differences remain with the industry seeking more flexibility in implementing the rules and environmental and community groups pressing for more monitoring and oversight.

And differences between the Front Range, which is not in compliance with federal health standards for ozone pollution, and the Western Slope also remain.

Deliberations on the new rules are expected to wrap up on Wednesday.

Matt Jones, a Boulder County commissioner, noted that these proposed regulations were in response to Senate Bill 181, which requires the AQCC to “minimize emissions of methane and other hydrocarbons, volatile organic compounds, and oxides of nitrogen” from oil and gas operations.

“Everything you are proposing and more should be passed until you get there,” Jones said, addressing the commission Thursday during hearings that occurred on Zoom. “The people in the state are counting on you to have the strongest rules to protect them.”

The proposals, however, were seen as an economic risk by Moffat County Commissioner Ray Beck.

Natural resource extraction industries, including mining and oil and gas drilling, are “the back bones of our economy and they have been gutted,” Beck said. Senate Bill 181 was passed, he said “without concern for the Western Slope.”

The proposed regulations not only address Senate Bill 181 but also the need to meet ozone standards, reduce regional haze and curb the deposition of nitrogen in Rocky Mountain National Park, where the element jeopardizes natural ecosystems.

The major rulemaking initiative would add controls and emissions monitoring to the so-called pre-production activities – the drilling and fracking of wells. Fracking pumps liquids down the well to fracture rock and release oil and gas.

The proposed regulations would require the control of flowback tank emissions, which hold the fracking fluids coming back out of the well. The flowback vessels would have to be covered and attached to a combustion device to flare fugitive emissions. Flaring gets rid of volatile organic chemicals which contribute to ozone pollution.

“Flowback during completions was found to be one of the higher sources of emissions,” Mike Paules, associate director of API-Colorado, a trade group, said in an interview.  “Requiring enclosed tanks and vapor-control systems, we believe that is going to help mitigate the emissions around flowback.”

The draft rule calls for air quality monitoring before, during and for six months after pre-production activities are completed. Operators would have to submit an air quality monitoring plan for each site to the Air Pollution Control Division for approval.

The industry has pressed for flexibility in choosing its air quality monitoring technology, while a number of local officials and community groups are seeking widespread continuous monitoring and questioned leaving it up to drillers to do their own monitoring plans.

Jean Lim, a member of the Broomfield City Council, called the regulations “a step in the right direction,” but called for requirements for a number of “sensitive monitoring stations.”

Offering flexibility is a key element of plan, said Air Pollution Control Division Director Garry Kaufman. “There is a certain level of discomfort with that, I get it.”

The regulation doesn’t specify a required technology nor the time frame for monitoring. “Not every technology has the ability to collect on a one-minute time frame,” said Leah Martland, a regulatory supervisor for the Air Pollution Control Division. “It wasn’t appropriate to specify the time frame for collecting.”

Matt Sura, an attorney representing Conservation Colorado and environmental groups, called allowing operators to choose which technologies they will use and what chemicals they will monitor a “scattershot air quality approach that will not lead to quality data.”

Dan Haley, president of the Colorado Oil and Gas Association, a trade group, said in an email that his group agrees with most of the proposed regulations.

“But COGA members support continued monitoring for a period of 90 days following the commencement of production, not six months,” Haley said. “Ninety days is more than sufficient for the pre-production and early production phases.”

Another proposed rule would tighten emission levels for engines of 1,000 horsepower or more. Such engines are used at drill sites to collect product through gathering lines, at storage facilities, and to move oil and gas through pipelines.

The rules will affect 62 companies that operate about 900 motors at 277 facilities and require at least 223 engines to be retrofitted. All new engines would have to meet the standards. The Air Pollution Control Division estimates that the rule will cut emissions of nitrogen oxides, or NOx, by 2,361 tons a year.

Nitrogen oxides are one of the compounds that go into the creation of ozone pollution and deposit nitrogen in Rocky Mountain National Park

The rule also allows companies that need five or more engines retrofitted to implement a companywide plan that will achieve the total reductions required, but necessarily from each engine.

Jennifer Biever, an attorney for the Joint Industrial Working Group, which represents companies affected by the rule, said that companywide rule would be needed by five or six companies. “But for those companies it is critical.”

A proposal from the National Parks Conservation Association suggesting that the commission require the use of electric engines, except where it is not feasible, drew opposition from both the industry and Xcel Energy, the state’s largest electricity provider.

Jim Hill, Xcel’s director of resource planning, said the utility has enough generating capacity to cover demand through 2025 but an all-electric engine proposal would require new generation and transmission sooner than planned. He estimated that going all-electric could boost the peak demand by as much as 14% or 1,000 megawatts.

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