Industry trade groups and environmental organizations are sharply divided over the feasibility of the US Environmental Protection Agency's proposal to require new and existing fossil fuel-fired generators to implement 90% carbon capture or begin co-firing with green hydrogen by the next decade.

In lengthy comments submitted Aug. 8, the Edison Electric Institute (EEI) said the EPA's proposal runs afoul of the Clean Air Act's requirement that control technologies established under Section 111 of the statute be "adequately demonstrated." Oil and gas trade groups echoed those concerns.

But a coalition of environmental groups led by the Natural Resources Defense Council (NRDC) said Section 111 does not require the EPA to show that nascent technologies such as carbon capture and sequestration (CCS) and green hydrogen have been proven within the US power sector at scale. Constellation Energy Corp., the nation's leading producer of carbon-free energy, also broke with EEI by arguing the EPA's proposal is well supported.

The EPA issued its proposed rule in May, nearly a year after the US Supreme Court held in its West Virginia v. EPA decision that the agency cannot set emission standards under Section 111 that would force broad shifts in the US energy mix. The feasibility of standards that require CCS or green hydrogen blending is likely to be central in legal challenges to a final EPA rule.

Power sector concerns

EEI expressed support for some aspects of the EPA's proposal, such as subcategories for existing coal-fired plants based on future retirement plans. But the trade group also argued the proposed rule fails to account for the role existing gas-fired units will play as weather-dependent solar and wind resources produce a growing share of electricity.

"One of the most glaring omissions is EPA's complete failure to grapple with the significant role that existing natural gas-based generation plays in overall system reliability and the challenges associated with retrofitting existing natural gas-based units," EEI said.

Under the EPA's proposal, existing gas-fired units with a nameplate capacity of 300 MW or larger and an annual capacity factor greater than 50% would be required to co-fire with 30% green hydrogen by 2032, ramping up to 96% by 2038, or achieve 90% carbon capture by 2035.

In justifying the standards, the EPA noted that the Inflation Reduction Act provides a $3-per-kilogram production tax credit for green hydrogen. The law also provides up to $85 per metric ton of CO₂ captured and stored by industrial facilities such as power plants, as well as $60 per metric ton of CO₂ used for other processes.

However, implementing CCS or hydrogen co-firing at existing gas-fired units will require pipeline and storage infrastructure, creating siting and permitting challenges, EEI noted.

"EPA has not shown how those issues can be overcome by the time this rule is finalized, and it is therefore impossible to see how EPA can lawfully conclude that either CCS or hydrogen blending are adequately demonstrated now," the trade group said.

In particular, EEI faulted the EPA for citing a dismantled gas-fired unit in Massachusetts that captured CO₂ and piped it directly to a food and beverage facility located adjacent to the plant. "This is not sufficient to conclude that 90% capture at natural gas-based units is adequately demonstrated," EEI said.

Although EEI members are experimenting with hydrogen blending, the group noted that those projects "are at most at pilot stage and have not been utilized at load, at scale, or cross different grid scenarios, not to mention the lack of hydrogen-related infrastructure to produce, transport and utilize hydrogen in the power sector."

If the EPA were to finalize its proposal as written, US annual green hydrogen production may need to increase by more than seven times — from less than 1 million metric tons today to more than 7 MMt — just to satisfy a 30% green hydrogen blending requirement, Duke Energy Corp. said in separate comments. Production would need to increase again "by at least sevenfold" above projected levels for 2032 for affected gas-fired units to achieve a 96% blend, Duke Energy said.

On a similar note, the National Rural Electric Cooperative Association contended the EPA has not shown that federal support for green hydrogen production in the Inflation Reduction Act and 2021 bipartisan infrastructure law will lead to sufficient supplies.

"This assertion is highly speculative, as the regulations defining clean hydrogen for the purposes of the [Inflation Reduction Act's] incentives are not finalized — and have proved controversial," the trade group said.

Oil and gas groups doubt timelines

The American Petroleum Institute (API) also questioned the EPA's assumptions that CCS and hydrogen infrastructure could be added in time to meet compliance deadlines. The oil and gas trade group asserted that EPA's plan would require 20,000 miles to 25,000 miles of additional CO₂ pipelines.

In comments joined by the Natural Gas Supply Association, API detailed challenges at the federal, state and local levels. Those included ambiguities around siting authority for interstate CO₂ pipelines, long timelines for National Environmental Policy Act reviews, local opposition, a lack of geological storage across much of the East Coast and the time needed for underground storage permitting processes.

The groups also argued the EPA's green hydrogen definition is at odds with the one established by US Congress and could result in a mismatch of supply and demand, driving hydrogen prices to a level that "makes power generation uneconomic."

Raising similar doubts about the timelines, a coalition led by the US Chamber of Commerce argued the EPA fell short of the statutory standard needed to set the CCS and clean hydrogen co-firing technologies as the best system of emission reduction. The group also submitted an analysis contending that the EPA's position that most emissions reductions will occur even without the rule led to a "remarkable underestimation of power sector changes" and compliance costs.

Split views in support of CCS, hydrogen blending for gas plants

In contrast, the NRDC submitted joint comments with the Clean Air Task Force and Nature Conservancy arguing that CCS represents the best control technology for larger existing gas-fired units. The groups used the results of a National Energy Technology Laboratory study to estimate that the cost of retrofitting an existing gas plant with CCS would increase its levelized cost of electricity by $5.60/MWh to $8.60/MWh. That would be roughly in line with the historical cost of flue gas desulfurization retrofits required under the Clean Air Act, they said.

Moreover, the groups cited a Clean Air Task Force analysis that found 98% of existing gas-fired units 300 MW or larger have access "to sufficient land for carbon capture retrofit."

Constellation Energy argued that the EPA should only finalize hydrogen blending as the best system of emission reduction for existing gas-fired units. The power producer said hydrogen co-firing at power plants will be spurred by the bipartisan infrastructure law's $8 billion program for at least four regional hydrogen hubs. So far, the US Department of Energy has received at least 21 completed applications in response to the funding opportunity, Constellation Energy noted.

In May, the company announced a new hydrogen blending record of 38.8% at its gas-fired Hillabee Energy Center, which uses Siemens Energy turbine technology.

"Co-firing at this level did not cause any mechanical or operational problems with the equipment, and only minor modifications were required for this blending level," Constellation Energy said.

The company is also piloting green hydrogen production at its Nine Mile Point nuclear plant in New York.

Addressing permitting and siting challenges, Constellation Energy cited a national hydrogen strategy report from the DOE predicting that early co-firing at facilities such as gas-fired units will be "frequently co-located, meaning they can capitalize on low-cost hydrogen production without incurring midstream distribution/storage cost."

"As a result, it will not be necessary to duplicate the expansive network that currently exists for natural gas," Constellation Energy said.

The company said EPA could further support "the rapid development of clean hydrogen" by considering "further phasing its proposal to require gas-fired units to meet a standard consistent with blending lower levels of clean hydrogen before the currently contemplated 2032 and 2038 compliance dates."

"To build confidence, familiarity, and expertise with clean hydrogen technology among a broad base of gas-fired generators, EPA could require incremental co-firing requirements," Constellation Energy said.

S&P Global Commodity Insights reporter Maya Weber produces content for distribution on Platts Dimensions Pro. S&P Global Commodity Insights is a division of S&P Global Inc.

S&P Global Commodity Insights produces content for distribution on S&P Capital IQ Pro.