November 22, 2013

EPA permitting seen as high hurdle for carbon capture project

From: E&E Publishing

Jean Chemnick and Manuel Quiñones, E&E reporters

On one hand, U.S. EPA is promoting carbon capture and storage technologies for all new coal-fired power plants. On the other — would-be project developers say — are confusing, budget-busting permit requirements that hamstring the technology’s development.

The bottom line, some energy industry officials say: Carbon capture, utilization and storage (CCUS) technologies aren’t ripe for a rulemaking.

“If not, we wouldn’t be spending [research and development money] on it,” said Charles McConnell, executive director of Rice University’s Energy and Environment Initiative and former chief of the Department of Energy’s Office of Fossil Energy. “Why spend a nickel on R&D? That’s what’s so stupid about the whole thing.”

EPA, he said — echoing a theme of coal and electric utilities — is fundamentally against coal and isn’t interested in CCUS becoming commercially viable. “EPA knows for a fact that it is unproven and undemonstrated, and that’s why they are making it so difficult to get the injection permit,” McConnell said. “It’s just doublespeak.”

But environmental advocates, even those who support carbon capture, say EPA is grappling with the unknowns surrounding the permanent underground storage of carbon dioxide.

“I don’t question that some folks would like to take some shortcuts, but that’s not necessarily the right thing to do,” said George Peridas, a scientist with the Natural Resources Defense Council.

EPA completed two key rules to govern carbon capture and storage activities in 2010 — three years before the release in September of a draft rule that would require new coal-burning power plants to use CCUS. The agency has touted all its actions as promoting the technology.

One of the CCUS rules created the Class VI designation under the Underground Injection Control Program with distinct construction, monitoring and testing requirements from other wells. Another outlines reporting requirements for facilities that trap carbon dioxide underground.

Archer Daniels Midland Co. is still waiting for an EPA Class VI injection permit for a DOE-backed project to capture emissions from an ethanol plant. ADM applied in 2011.

“This is the first permit of its kind,” ADM said in a statement, “and we continue to work with the U.S. EPA toward finalizing the permit.”

Another project waiting for Class VI permitting is FutureGen 2.0, which aims to retrofit a shuttered power plant in Illinois with carbon capture technology and store it underground.

Kipp Coddington, an attorney for Kazmarek Mowrey Cloud Laseter LLP and the North American Carbon Capture and Storage Association, said the Class VI rules are “noncommercial.”

“By that, I mean … that a company doing Class VI injections is liable for infinity and beyond for that activity,” he said, emphasizing that he is not speaking on behalf of clients.

EPA regulations set a default requirement for a post-injection monitoring period of 50 years, though the agency allows operators to make the case that a shorter monitoring period would be appropriate for some projects.

Coddington worries EPA is improperly concluding that it lacks authority to transfer liability to a federal or state entity even after that monitoring period ends. That, he said, leaves project operators on the hook for any residual risk associated with their site.

In the September draft rule, EPA proposes allowing power plant operators to sequester a share of injected CO2 but also requiring them to prepare a monitoring, reporting and verification plan that would then be approved by EPA and subject to litigation.

“Anybody with a grudge against coal or oil and gas could litigate until the cows come home about the sufficiency of the storage operations,” Coddington said.

Robert Van Voorhees, an attorney with Bryan Cave LLP, said the Class VI rule establishes a framework for regulation, “but there are a lot of uncertainties right now about what it’s going to take to get through that process.”

“There’s a lot of flexibility and adaptability built into the rule, in some ways more than EPA itself is willing to acknowledge,” he said in an interview on the sidelines of the recent Carbon Sequestration Leadership Forum in Washington, D.C. “It has been contested as companies actually go through the permitting process and try to get permits issued.”

For one thing, he said, there is nothing in the 2010 rule that precludes EPA from issuing permits to small, demonstration-scale CCUS projects under another, potentially simpler permitting program that would saddle those projects with fewer application requirements and eliminate the 50-year default requirement for post-injection monitoring.

“I, along with a lot of other people, think that EPA created a problem when using that 50-year number, which is unnecessary,” he said.

If an operator is proposing to run a demonstration project for only three years, for example, it should not either face the default 50-year monitoring requirement or demonstrate through extensive modeling that a shorter time period would be warranted.

This is especially true, he said, because many of these demonstration projects are backed by the Energy Department and must comply with its monitoring requirements, making the EPA-mandated ones duplicative.

The effect of all these rules on CCUS deployment?

“I would say the barrier is not so much the regulations themselves,” Van Voorhees said. “I think the biggest barrier right now is uncertainty. How are these things going to be applied? If you want to do a pilot or demonstration project, what is going to be required?

“It’s an unusual process for the [Underground Injection Control] program in the sense that they’re regulating an industry that has not yet been created,” he said.

Environmental concerns

Environmentalists believe EPA is being appropriately cautious in requiring industries to monitor what they put under the ground, especially with their relatively novel and not fully tested goals.

NRDC’s Peridas said that while there is “an initial implementation and teething” period for phasing in a new rule, EPA’s Class VI rule for geological sequestration of CO2 is the product of extensive public comment already.

“We believed that these were good, well-thought-out rules, and they were much needed when they came,” he said. NRDC was part of a green coalition that pressed the George W. Bush administration to promulgate the rules.

The permitting process has been slowed not by hang-ups in the agency, he said, but by applicants who have sought a way around the more extensive Class VI process rather than simply submitting a completed application.

Sarah Forbes, World Resources Institute carbon capture specialist, noted that EPA had pledged to review the Class VI permitting process when there was more information available.

“I think we need to be honest about what we do and do not know about CCS, and I think the first several projects are going to be learning experiences with respect to how to best regulate and make sure that appropriate safeguards are in place,” Forbes said.

But early adopters of carbon injection won’t be penalized for completing the application process before EPA has refined it, she said, because many are receiving federal assistance to build their projects that might not be available to operators after the technology becomes more established.

Enhanced oil recovery

Underground sequestration is not the only option for captured CO2 from industry or power plants. Advocates, including at DOE, have been stressing the benefits of using the CO2 for enhanced oil recovery (EOR), an activity already taking place.

That’s why the carbon capture jargon once referred to the efforts as CCS but now many advocates prefer CCUS, with the “U” being the utilization component.

Selling CO2, they say, can help make carbon-capture efforts more economical.

EPA’s slowness to issue Class VI permits has encouraged many CCS projects to look for ways to partner with enhanced oil recovery operations that may already have permits in place.

Southern Co.’s Kemper County, Miss., project, which may be complete next year, is touted by both EPA and DOE as an example of power plants including an EOR component.

But with drilling not prevalent everywhere in the United States, many carbon capture advocates say industries and agencies shouldn’t focus on EOR to the detriment of geologic sequestration. Advocates also worry about EPA making EOR permitting for captured carbon as difficult as for geologic sequestration.

Adam Kushner, a partner at Hogan Lovells’ environmental practice, said during a recent talk on carbon capture that he had “deep concern” that EPA rules will make EOR “so cost-ineffective.”

EPA’s September greenhouse gas proposal says EOR wells may be permitted under the traditional Class II or the new Class VI well injection program. Companies would rather fall under the first than the latter.

EPA said in the rule text that “the designation of the appropriate well class depends, principally, on the risks posed or changes in the risks posed to underground sources of drinking water by a specific injection operation.”

Fred Eames, CCS Alliance attorney and partner at the firm Hunton & Williams LLP, said one top concern was EPA’s proposal to require EOR operations that use CO2 from power plants to report their greenhouse gas intake under the Subpart RR rather than Subpart UU scheme.

Eames said Subpart RR requires broader reporting, including how much CO2 a company injects. Plus EPA must approve a measurement, reporting and verification (MRV) plan, which he says is not friendly to enhanced oil recovery activities.

“You have to file an MRV plan amendment each time you materially change your operations, which according to the oil and gas operators is nearly constant, so you’d constantly be seeking EPA approval,” Eames wrote in an email. “You also would have to keep reporting until EPA tells you to stop, which could be some years after injections stop.

“All of this may interfere with State laws that require diligent development of the resources,” he added. “Further, in an EOR operation, you have to keep the site pressurized, and if you have to interrupt operations waiting for EPA to approve a new MRV plan because you’ve changed things, that just doesn’t work.”

After the Class IV and monitoring rules, in 2011 EPA proposed a third measure to exempt CO2 injected under a Class VI permit from Resource Conservation and Recovery Act (RCRA) hazardous waste regulations.

While many environmentalists don’t want to see that exemption, energy companies and industry groups think the rulemaking may do more harm than good. For one, they don’t want injected CO2 to be considered a solid waste, something that would carry stigma and liability.

Plus, some CCUS interests worry about the proposal harming not only underground sequestration but also EOR activities.

“Additional RCRA regulation is redundant, not necessary, and will likely lead to unintended consequences that would undermine beneficial uses of CO2 streams for carbon capture and sequestration and enhanced recovery of oil and gas,” the American Petroleum Institute wrote on a 2011 comment letter.

Other groups, including the National Mining Association and the CCS Alliance, expressed general support for EPA’s action under RCRA but urged the agency to fine-tune the language.

Earlier this year, the White House Office of Management and Budget met with various interests on the rule, including enhanced oil recovery driller Denbury Resources Inc. and Occidental Petroleum Corp.

OMB has finished reviewing EPA’s proposed rule, according to several sources and OMB’s website, but EPA has yet to issue the final standard.

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