J.Pollock Blog

EPA Power Plant Rule: Part 2

In a prior blog, I observed that EPA’s “go-it-alone” policies to force carbon emission reductions from existing power plants would likely have untended consequences, such as less reliable, less affordable electricity.  I also questioned EPA’s reliance on nascent carbon capture technology to bolster its claim that many existing plants can remain in operation.  

These concerns were affirmed in the comments recently submitted to the EPA by the RTO/ISO community. Specifically, the increasing amounts of weather-dependent generation coming online may not be sufficient to replace retiring dispatchable generation. The comments also questioned EPA’s reliance on technologies that have yet to be demonstrated as cost-effective at the scale necessary to keep these needed plants in operation.  

Other commenters raised a very practical concern: specifically, carbon capture is neither timely nor feasible at all power plant sites.  This is because the carbon captured will have to be removed, transported, and stored.  Considerable infrastructure will have to be developed, permitted and built.  The permits alone will require significant time for submission, review and approval.  We all know about the growing and significant opposition to pipelines, including natural gas and CO2.  Even assuming carbon capture is cost-effective and there are reasonably accessible storage sites, implementation will require long lead times.   

Let’s hope that the agencies in charge of reliability will help to dissuade EPA to rethink its policies.  Quoting the idiom: Hope for the best, but prepare for the worst.  

US EPA power plant proposal sparks debate over feasibility EXTRA

Thursday, August 10, 2023 5:45 AM CT

By  Zack Hale
Market Intelligence

By Maya Weber
Commodity Insights

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.

This article was published by S&P Global Market Intelligence and not by S&P Global Ratings, which is a separately managed division of S&P Global.

Grid operators warn US EPA proposal could lead to ‘significant power shortages’ EXTRA

Wednesday, August 9, 2023 9:42 AM CT

By  Zack Hale
Market Intelligence

Regional grid operators outlined a range of reliability and market concerns with the US Environmental Protection Agency’s proposal to require new and existing fossil fuel-fired power plants to implement carbon capture or green hydrogen blending.

The EPA’s proposal, unveiled in May, would effectively require existing coal-fired power plants without 90% carbon capture to cease operating by 2035. It would also require new and existing gas-fired generating units with a nameplate capacity of 300 MW or larger and an annual capacity factor greater than 50% to co-fire with 30% green hydrogen by 2032, ramping up to 96% by 2038, or achieve 90% carbon capture by 2035.

The proposed rule was designed with an eye toward a 2022 ruling by the US Supreme Court in West Virginia v. EPA, which stated that the Clean Air Act does not permit the EPA to require broad shifts in the nation’s generation mix without explicit authorization from Congress.

The rulemaking represents the third attempt under the last three presidential administrations to set the first-ever CO2 limits for the nation’s second-largest source of climate pollution.

In its proposal, the EPA took into account the generous tax credits for carbon capture and sequestration and green hydrogen production in the Inflation Reduction Act. The agency’s regulatory impact analysis also projected a relatively modest impact on the existing US generation fleet, with only 37 GW of existing natural gas-fired capacity expected to be implicated by the proposed rule by 2035.

However, the 13-state PJM Interconnection LLC, 15-state Midcontinent ISO, 15-state Southwest Power Pool and the Electric Reliability Council of Texas Inc. expressed alarm with the EPA’s proposed requirements in joint comments submitted Aug. 8. The ISO New England also flagged potential reliability concerns for its six-state region, while the single-state California ISO urged the EPA to provide additional compliance flexibilities in a final rule.

4 grid operators voice retirement concerns

PJM, MISO, SPP and ERCOT noted that they are responsible for ensuring reliable electric service to 154 million customers in geographic footprints that collectively cover all or parts of 30 states and the District of Columbia.

With that in mind, the four grid operators warned that the EPA’s proposed rule “could result in material, adverse impacts to the reliability of the power grid.”

“If the technology and associated infrastructure fail to timely materialize, then the future supply of compliant generation — given forced retirements of non-compliant generation — would be far below what is needed to serve power demand, increasing the likelihood of significant power shortages,” the grid operators said.

PJM, for example, noted that 40 GW of dispatchable thermal generation, representing 21% of its current installed capacity, is at risk of retiring by 2030. New capacity additions made up almost entirely of weather-dependent resources may not be sufficient to keep pace with retirements by the end of the decade, according to PJM.

The EPA’s proposed rule could force an incremental 15 GW of coal-fired capacity in PJM to retire early, pushing the overall level of at-risk generation to 29%, PJM said. Roughly 22% of PJM’s installed capacity comprising “the most-efficient, dispatchable gas-fired generation” would also be forced to “undertake expensive control options or significantly reduce operations under the proposed rule,” the grid operator said.

SPP also warned that the ongoing retirement of thermal generators within its footprint is straining its system.

Nearly 2,800 MW of thermal generation in SPP retired between 2019 and 2022. Those retirements coincided with an increase of 257 system alert hours in 2022, amounting to nearly 11 days, compared to 2019, SPP said. If SPP’s historical gross load were to increase by only 3%, the region would have “no margin for additional retirements,” SPP said.

Citing the results of its own reliability analysis, MISO noted that dispatchable, non-weather-dependent capacity may need to triple by 2031 and quadruple by 2041 to compensate for days when solar generation is unavailable.

ISO-NE analysis finds proposal would ‘shift the generation burden’

The ISO-NE used Energy Exemplar’s PLEXOS power market simulation platform to quantify the impacts of the EPA’s proposal by 2032. The model assumed “significant increases” in power demand from vehicle and heating electrification.

Under the proposal, annual generation output from gas-fired units 300 MW or larger with capacity factors of greater than 50% would decline 19%, while smaller combustion turbines would increase 119% in operation, according to the ISO-NE’s simulation.

“It can be concluded that the enforcement of the proposed EPA rule would not reduce fossil generation; rather, the proposed EPA rule would shift the generation burden from larger, more efficient natural gas plants to smaller and less efficient” natural gas- and oil-fired generators, the ISO-NE said.

Moreover, the grid operator found that the proposed rule would significantly increase active demand response in New England. Active demand response, a term used to describe voluntary reductions in customer demand when energy prices hit $1,500/MWh, would increase from 4 GWh annually to 37 GWh, according to the analysis.

“Seeing [active demand response] dispatch more frequently when the EPA rules are simulated is indicative of a system that is running out of dispatchable resources,” the ISO-NE said.


To help address their concerns, PJM, MISO, SPP and ERCOT proposed an additional “reliability-based subcategory.”

“This subcategory would be populated with specific units or locations as identified by the [grid operators] where unit retirement would cause significant reliability challenges until other longer-term solutions, such as transmission, demand response, or new generation resources, would obviate the need for those units,” they said.

As proposed, each grid operator “would provide a public explanation of the methodology it would use to determine which units, or classes of units, qualify for inclusion in this subcategory and the process for identification of such units.” The identified units would then be exempt from compliance until they are no longer needed to maintain grid reliability.

CAISO backed that idea in its own brief comments. “EPA should also consider establishing additional pathways in any final rule to allow resources to operate on a temporary basis notwithstanding compliance schedules, if needed to support electric grid reliability,” CAISO said.

PJM, MISO, SPP and ERCOT also recommended a “complementary approach” under which the remaining useful life of a generating unit could be considered in a manner similar to the EPA’s coal ash regulations.

In addition, the four grid operators urged the EPA to further clarify that states can include emission allowance trading in their compliance plans. Although the proposed rule would allow voluntary allowance trading, it “does not provide sufficient guidance on how effective interstate trading could be utilized as a compliance strategy,” they said.

The ISO-NE asked the EPA to consider the use of other low-carbon fuels in its current proposal and a future rulemaking covering the remaining natural gas fleet.

“For example, low-carbon fuels such as synthetic methane and synthetic/renewable natural gas can be used as a direct replacement for fossil gas and are compatible with existing natural gas infrastructure,” the ISO-NE said.

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

This article was published by S&P Global Market Intelligence and not by S&P Global Ratings, which is a separately managed division of S&P Global.