Legal & Regulatory

EPA Unleashes Four-Pronged Assault on Fossil Fuel Power Pollution

In an unprecedented move, the U.S. Environmental Protection Agency (EPA) on April 25 simultaneously finalized four major environmental rules covering greenhouse gases (GHG), air toxics, wastewater discharges, and coal combustion residuals from fossil fuel-fired power plants.

Among the rules is the EPA’s final Carbon Pollution Standards, which marks the agency’s third attempt to broadly curb GHG emissions from the nation’s fleet of coal plants and its first to regulate GHG emissions from new natural gas-fired power plants. The agency also issued an updated and strengthened Mercury and Air Toxics Standards (MATS), which targets coal power emissions. Separately, the EPA finalized the Effluent Limitations Guidelines and Standards (ELGs), which aim to drastically reduce pollutants discharged by steam power plants through wastewater. Finally, the suite of regulations includes a final rule governing legacy coal combustion residuals, addressing the long-delayed mandate from the DC Circuit to implement oversight on coal ash regulation.

EPA Administrator Michael Regan on Wednesday told reporters the agency’s regulatory sweep is part of an integrated, coordinated and economically efficient approach aimed at streamlining regulatory processes and delivering predictability. The approach, he explained, stems from a pledge made during CERAweek 2022.

“I stood before industry stakeholders and outlined a clear plan for EPA as an approach to addressing harmful pollution from the power sector. On that day, I committed to maintaining transparency and open dialogue so that state and federal energy regulators, power companies, and grid operators would have the information they needed to make long-term investments in the transition to a cleaner energy economy,” he said. “And today, I’m proud to announce that we’re following through on that commitment.”

However, the EPA’s suite of final regulations immediately elicited strong criticism from parts of the U.S. power industry, which had urged the agency to heed their concerns about technology feasibility, stringent compliance timelines, and reliability impacts.

Legal experts have cautioned the GHG rule, prominently, will likely encounter legal challenges. “We can also expect a fierce political and legal fight ahead,”  Mona Dajani, global co-chair of Energy Infrastructure & Hydrogen at law firm Baker Botts, told POWER. “Specifically on the legal front, industry opponents will challenge the new rule as a violation of the major questions doctrine, as defined in the U.S. Supreme Court’s decision in West Virginia v. EPA. That decision effectively limited EPA’s reach,” she noted.

The following is a detailed technical overview of the final rules released today. 

Final Carbon Pollution Standards for Existing Coal-fired and New Gas-fired Power Plants

The EPA finalized several actions under Section 111 of the Clean Air Act (CAA) covering existing coal-, oil-, and gas-fired steam generating units (under Section 111[d]) and new and reconstructed gas-fired combustion turbines and modified coal-fired steam generating units (under Section 111[b)]):

  • Final emission guidelines for GHG emissions from existing coal-fired and oil/gas-fired steam-generating electric generating units (EGU),
  • Finalized revisions to the new source performance standards (NSPS) for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs,
  • Finalized revisions to the NSPS for GHG emissions from fossil fuel-fired steam generating units that undertake a large modification based upon the 8-year review required by the CAA.

The EPA, in addition, finalized its repeal of the  Trump-era Affordable Clean Energy (ACE) rule, but it refrained, as it had indicated in February, from finalizing emissions guidelines for GHG emissions from existing gas-fired power plants. The agency has said it will address emissions from the “entire fleet of natural gas-fired turbines” as part of a more “comprehensive approach” to regulate “climate, toxic, and criteria air pollution.”

Consistent with the statutory command of CAA Section 111, the final NSPS and emission guidelines of the EPA’s actions “reflect the application of the best system of emission reduction (BSER) that, taking into account costs, energy requirements, and other statutory factors, is adequately demonstrated,” the EPA said on Thursday.

The EPA finalized several actions under Section 111 of the Clean Air Act (CAA) covering existing coal-, oil-, and gas-fired steam generating units (under Section 111[d] and new and reconstructed gas-fired combustion turbines and modified coal-fired steam generating units (under Section 111[b)]) Source: EPA
The EPA finalized several actions under Section 111 of the Clean Air Act (CAA) covering existing coal-, oil-, and gas-fired steam generating units (under Section 111[d]) and new and reconstructed gas-fired combustion turbines and modified coal-fired steam generating units (under Section 111[b)]). Source: EPA

But, keeping with the EPA’s contentious  May 2023 proposal, the EPA determined that the BSER for the longest-running existing coal units (units that plan to operate after January 2039) and for new baseload combustion turbines is carbon capture and sequestration (CCS). The standards require existing coal units to meet a standard of performance based on the implementation of 90% CCS.

However, the rules notably extend compliance dates for coal units from January 2030 (as required in the proposal) to January 2032. They also provide an applicability exemption for coal units that plan to cease operation by January 2032.

But for new combustion turbines, the final rules appear to apply more stringently compared to the proposal. The EPA expanded the applicability of the most stringent baseload standard to units operating above a 40% capacity factor (compared to 50% in the proposal). It also moved back compliance deadlines for the 90% CCS-based standard for baseload units from 2035 (in the proposal) to 2032.

New baseload units will be subject to an initial “phase one” standard based on efficient design and operation of combined cycle turbines and a “phase two” standard based on 90% capture of CO2. New intermediate load turbines (with a 20-40% capacity factor) are subject to a standard based on the efficient design and operation of simple cycle turbines, while new low-load turbines (with a capacity factor of less than 20%) are subject to a standard based on low-emitting fuel. 

Notably, the EPA in its final Carbon Pollution Standards scuttled its highly contested proposed effort to include hydrogen co-firing as a BSER pathway for baseload and intermediate units. A senior administration official, however told reporters in a briefing on Wednesday that power generators could still consider hydrogen co-firing as a compliance option for new natural gas and even coal plants.

Finally, compared to the proposed rule, the final rules pay specific attention to reliability impacts. The EPA notably adopted two optional reliability-related mechanisms that states may choose to incorporate into their plans: A short-term reliability mechanism for new units or units responding to declared grid emergencies and a “reliability assurance mechanism” for units with “cease operations” dates that may be needed to stay online longer than anticipated due to documented reliability needs.

Still, because “states are afforded the flexibility to implement the final carbon pollution rule in state plans,” the rule’s impact on power plant retirements “could be different to the extent states and power companies make different choices than those assumed in the illustrative analysis [laid out in the rules’ Regulatory Impact Analysis (RIA)],” the EPA told POWER on Wednesday.

The agency’s illustrative analysis takes into account that the power sector is already in the midst of change, it noted. “In 2023, the power sector included ~181 GW of operational coal-fired EGUs,” it said. So far, an estimated 56% of this fleet (101 GW) has publicly announced plans to retire or convert to gas prior to 2039 and another 8 GW by 2040, leaving approximately 73 GW of operational coal-fired EGUs in 2040, it noted.

The illustrative analysis suggests the final rule could result in another 14 GW of coal retirements in 2040, along with 6 GW of coal-to-gas conversion and 3 GW of derated capacity. “This results in 19 GW of coal-fired capacity remaining in place,” the EPA said. By comparison, without the rule, the EPA’s baseline economic projections suggest that only 42 GW of operating coal capacity could be operational by 2040, a figure that also factors in additional projected retirements, capacity derates, and conversions to gas.

Final Rule to Strengthen and Update the Mercury and Air Toxics Standards (MATS) for Power Plants

The EPA on Thursday announced a significant update to the  2012–finalized National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired Electric Utility Steam Generating Units—a rule more commonly known as the Mercury and Air Toxics Standards (MATS). The final rule substantially reflects the EPA’s April 2023 proposed rule.   

MATS limits coal- and oil-fired power plant emissions of mercury and acid gas hazardous air pollutants (HAPs)—such as hydrogen chloride (HCl) and hydrogen fluoride. The standards also cover non-mercury HAP metals such as nickel, lead, and chromium, and organic HAPs such as formaldehyde and dioxin/furan.

The new final rule tightens numeric emission limits for filterable particulate matter (fPM)—a surrogate for total non-mercury HAP metals. While existing coal plants were previously required to meet fPM standards of 0.030 pounds per million British thermal units (lb/MMBtu) of heat input, the final MATS revises that standard to 0.010 lb/MMBtu (as proposed in April 2023).  “Currently, 93% of coal-fired capacity without known retirement plans before the compliance period has already demonstrated an fPM emissions rate at or below 0.010 lb/MMBtu,” the EPA noted on Thursday.

The EPA also tightened mercury emission standards for lignite-fired power plants, requiring they meet the same standard as existing bituminous and subbituminous plants: 1.2 pounds per trillion British thermal units (lb/TBtu) or 1.3E-2 lb/GWh. The previous standard required 4 lb/TBtu. “EPA’s review of information on current mercury emission levels and controls for lignite-fired EGUs shows that lignite-fired EGUs can achieve the more stringent mercury emission rate using available control technologies and/or improved methods of operation at reasonable costs,” the agency noted.

While coal and oil plants previously had the choice of demonstrating compliance for non-mercury HAP metal emissions limits by monitoring fPM via quarterly sampling or particulate matter (PM) monitoring continuous emissions monitoring systems (CEMS), the final rule will make it mandatory to require demonstrating compliance using PM CEMS. “PM CEMS confer significant benefits, including increased transparency regarding emissions performance for sources, regulators, and the surrounding communities; and real-time identification of when control technologies are not performing as expected, allowing for quicker repairs,” the EPA noted 

Finally, the final rule also sets down a firm definition of startup  as either “the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose.” 

The EPA’s RIA for the MATS rule suggests about 5 GW of operational EGU capacity will need to comply with the rule in 2028. Another 11.6 GW would either need to improve existing PM controls or install new PM controls to comply with the rule. For now, “EPA projects that no coal-fired capacity would retire under the final rule,” it said.

Final Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

On Thursday, the EPA also finalized revisions to its technology-based effluent limitations guidelines and standards (ELGs) for the steam electric power generating point source category, which the EPA proposed in March 2023. Steam power generators employ a steam-water system as a thermodynamic medium and include coal, oil, and gas power plants, as well as nuclear plants.

The final rule finalizes zero-discharge effluent limitations for all pollutants in flue gas desulfurization (FGD) wastewater and bottom ash transport water (BATW) starting in 2025. It also proposes numeric discharge limitations for mercury and arsenic in combustion residual leachate (CRL) and legacy wastewater, which is discharged from certain surface impoundments. Finally, the rule eliminates less stringent requirements for two subcategories of facilities (high flow facilities and low utilization energy generating units) that were contained in the 2020 regulation.

For the final rule, EPA evaluated three regulatory options as summarized in Table ES-1. The agency established best available technology (BAT) effluent limitations and pretreatment standards based on the technologies described in Option B. For more about these technologies, see the EPA’s newly released Technical Development Document. Source: EPA
For the final rule, EPA evaluated three regulatory options as summarized in Table ES-1. The agency established best available technology (BAT) effluent limitations and pretreatment standards based on the technologies described in Option B. For more about these technologies, see the EPA’s newly released Technical Development Document. Source: EPA

According to the EPA, the final ELG rule considers flexibilities where appropriate. “For example, recognizing that some coal-fired power plants are in the process of closing or switching to less polluting fuels such as natural gas, the regulation includes flexibilities to allow these plants to continue to meet the 2015 and 2020 regulation requirements instead of the requirements contained in this final regulation,” it notes. “This is done by creating a new subcategory for [EGUs] that permanently cease coal combustion by 2034.”

The final rule means EGUs in the new subcategory are now required to meet the 2020 rule requirements for FGD wastewater and BATW rather than the new, more stringent zero-discharge requirements that apply to other facilities, the EPA explained. “The subcategory also contains requirements for CRL discharges that vary based on whether the EGU is still combusting coal or not.”

EPA estimated about 232 plants of the nation’s 858 steam power plants generate the wastestreams covered by the regulatory options. It also acknowledged the rule will be costly during the compliance years (2025-2029), though it suggests. “On an after-tax basis, the final rule has estimated incremental annualized compliance costs ranging from $479 million to $956 million,” it notes. That includes capital costs of up to $415 million and operations and maintenance costs of up to $541 million.

However, these costs represent small projected increases in total electricity market costs, the net effect of decreases in fuel costs, variable O&M, and fixed O&M, and increases in capital and CCS costs, it said. 

Legacy Coal Combustion Residuals Surface Impoundments and CCR Management Units Final Rule

On Thursday, the EPA announced final changes to the CCR regulations for inactive surface impoundments at inactive electric utilities under the Resource Conservation and Recovery Act (RCRA).

These so-called “legacy CCR surface impoundments” refer to areas at power plants where coal ash has been stored in surface impoundments that were operational but are no longer in use and have not been regulated under federal laws up to this point.

The rule responds to an August 2018 opinion by the U.S. Court of Appeals for the District of Columbia Circuit (Utility Solid Waste Activities Group et al. v. EPA) that vacated and remanded the provision that exempted inactive impoundments at inactive facilities from EPA’s April 2015 CCR rule.

“These new regulations are also driven by the record, which clearly demonstrates that regulating legacy CCR surface impoundments will have significant public health and environmental benefits. This is because legacy CCR surface impoundments are more likely to be unlined and unmonitored, making them more prone to leaks and structural problems than units at utilities that are currently in service,” the EPA said.

In the final rule, EPA establishes mandatory groundwater monitoring, corrective action, closure, the requirement for corrective actions if contamination is detected, and the proper closure and post-closure care of these impoundments to mitigate ongoing environmental impact.

The EPA estimated annualized monetized costs of the action will be about $214 million to $240 million per year, mostly for legacy CCR impoundments. However, the agency also noted that it does not expect the rule to affect current operations at power plants and, therefore, anticipates no impacts to electricity or grid reliability. “This rule reflects the Administration’s commitment to reduce pollution from the power sector while providing long-term regulatory certainty and operational flexibility,” it said.

Sonal Patel is a POWER senior editor (@sonalcpatel@POWERmagazine).

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