EPA’s action finalizes aggressive emission reduction targets for certain subcategories of fossil fuel-fired power plants, based on implementation of carbon capture and sequestration.

By Stacey L. VanBelleghem, Karl A. Karg, and Phil Sandick

This post is the first in a series on four key power plant rules that the Environmental Protection Agency recently released. It discusses the rule to regulate greenhouse gas emissions from certain electric generating units.

On April 25, 2024, the US Environmental Protection Agency (EPA) released its final rule (the Power Plant GHG Rule or the Final Rule) to regulate greenhouse gas (GHG) emissions from electric generating units (EGUs) at power plants under Section 111 of the Clean Air Act (CAA). This significant new regulation was part of a suite of four power sector rules EPA finalized on the same day. The Power Plant GHG Rule accompanied updates to the technology-based Effluent Limitations Guidelines for Steam Electric Power Generating Units under the Clean Water Act, updates to the mercury and air toxics standards for oil- and coal-fired power plants under the CAA, and the final regulation for legacy coal combustion residuals surface impoundments and management units under the Resource Conservation and Recovery Act.

The Power Plant GHG Rule codifies four primary EPA actions:

  1. Updates to current GHG emissions standards (promulgated in 2015 under CAA Section 111(b)) for new and reconstructed stationary combustion turbines (generally natural gas-fired), in which EPA continues to rely upon carbon capture and sequestration (CCS) for baseload units and no longer relies on co-firing low-GHG hydrogen
  2. GHG emission guidelines under CAA Section 111(d) for existing fossil fuel-fired steam-generating EGUs (generally coal-fired) that rely upon EGU retirements or CCS
  3. Updates to current GHG emissions standards (promulgated in 2015) for modified fossil fuel-fired steam-generating EGUs (generally coal-fired) that mirror guidelines for existing EGUs
  4. A repeal of the Trump-era Affordable Clean Energy (ACE) Rule

Background to the Power Plant GHG Rule

This is the third time EPA has finalized a power plant GHG emissions rule. Although GHG emission performance standards for new and reconstructed EGUs have been in place since 2015, existing EGUs have remained unregulated at the federal level because two EPA rulemakings under Section 111(d) of the CAA to regulate existing EGU GHG emissions have been mired in litigation. In 2015, the Obama Administration EPA’s Clean Power Plan (CPP) finalized a GHG emissions regulation for existing EGUs under Section 111(d) of the CAA by determining a “best system of emission reduction” (BSER) that was based in large part on power generation shifting to lower-carbon energy sources. However, in February 2016, the US Supreme Court stayed implementation of that rule pending the outcome of challenges in federal court. And while that litigation was pending, the Trump Administration EPA replaced the CPP with the ACE Rule, which rejected power generation shifting in favor of heat rate improvements as BSER for GHG emissions from existing EGUs.

Opponents then challenged the ACE Rule, and the US Court of Appeals for the District of Columbia Circuit overturned the ACE Rule and EPA’s repeal of the CPP. The Supreme Court then took up the question of EPA’s authority under the CAA to regulate CO2 from existing power plants under the CPP. As discussed in this Latham blog post, in June 2022 the Supreme Court ruled that EPA’s identification of power generation shifting as BSER in the CPP exceeded the agency’s statutory authority under the CAA. However, the Court’s decision raised questions regarding the scope of EPA’s statutory authority to interpret BSER.

Against this long and complicated backdrop, EPA has, once again, finalized a regulation of power plant GHG emissions.

This blog post summarizes five key takeaways from the Power Plant GHG Rule.

  1. The Final Rule Subcategorizes Sources and Continues to Rely on CCS and Retirements, but No Longer on Hydrogen Co-Firing, as BSER

CAA Section 111(a)(1) requires EPA to identify a standard of performance that “reflects the degree of emission limitation achievable through the application of [BSER] which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.”

EPA’s proposal sets GHG emissions standards under Section 111(b) of the CAA for new, modified, or reconstructed sources and emission guidelines under Section 111(d) for existing sources for numerous subcategories of sources, which are based on generating technology, size of unit, level of operations, and anticipated remaining operational life of the unit.

While EPA’s proposed Power Plant GHG Rule identified both CCS and co-firing hydrogen as BSER for the most stringent emissions cuts, the Final Rule no longer identifies hydrogen co-firing as BSER that forms the basis of EPA’s standards. Nonetheless, EPA recognizes that “a standard based on application of CCS could be achieved by co-firing hydrogen.”

Other notable changes for new gas-fired combustion turbines include EPA’s expansion of “baseload” units to include those operating above 40% capacity factor and EPA accelerating the CCS compliance deadline for baseload gas units to 2032, rather than the originally proposed 2035 deadline.

For coal-fired units, notable changes in the Final Rule include an exemption for units that plan to permanently retire by January 1, 2032, and pushing back the CCS compliance date for coal-fired units from 2030 to 2032.

SubcategoryDescriptionBSER, standard of performance, and compliance timeline
Low load (“peaking”) combustion turbineCapacity factor of less than 20%BSER: Use of lower emitting fuels (e.g., natural gas and distillate oil)
Standard of performance: Less than 160 lb. CO2/MMBtu
Compliance required by the rule effective date or EGU startup, whichever is later
Intermediate load combustion turbineCapacity factor ranging between 20% and 40%BSER: Highly efficient generation and best operating and maintenance practices
Standard of performance: 1,170 lb. CO2/MWh-gross
Compliance required by the rule effective date or EGU startup, whichever is later
Base load combustion turbineCapacity factor above 40%Phase 1 (Later of Effective Date or Startup):
BSER: Highly efficient generation
Standard of performance:
800 lb. CO2/MWh-gross for EGUs with a base load rating of 2,000 MMBtu/h or more;
800 lb. to 900 lb. CO2/MWh-gross for combustion turbines with a base load rating of less than 2,000 MMBtu/h

Phase 2 (Beginning January 1, 2032):
BSER: Highly efficient generation and CCS with 90% capture of CO2
Standard of performance: 100 lb. CO2/MWh-gross. EPA notes sources may comply with that standard by co-firing hydrogen
Coal-fired EGUs: Retire before January 1, 2032Ceasing operations before January 1, 2032Exempt from the Power Plant GHG Rule if State plans include a federally enforceable permanent retirement date before January 1, 2032
Coal-fired EGU: Medium-term operationOperating on or after January 1, 2032, but demonstrating plan to permanently cease operating before January 1, 2039BSER: Based on co-firing 40% natural gas (heat input basis)
Standard of performance: 16% reduction in emission rate (lb. CO2/MWh-gross basis)
Compliance by January 1, 2030
Coal-fired EGU: long-term operationOperating past January 1, 2039BSER: Based on 90% capture of CO2 combined with the use of CCS
Standard of performance: 88.4% reduction in emission rate (lb. CO2/MWh-gross basis)
Compliance by January 1, 2032
Natural gas and oil-fired steam generating units BSER: Routine methods of operation and maintenance
Standard of performance: An emission limitation of:
1,400 lb. CO2/MWh-gross for base load units (annual capacity factor greater than 45%).
1,600 lb. CO2/MWh-gross for intermediate load units (annual capacity factors greater than 8% and less than or equal to 45%).
For low load units (annual capacity factors less than 8%), a presumptive input-based standard of 170 lb. CO2/MMBtu for oil-fired sources and a presumptive standard of 130 lb. CO2/MMBtu for natural gas-fired sources.
Compliance by January 1, 2030
  1. EPA Has Deferred Finalizing GHG Emissions Guidelines for Existing Gas-Fired Units

Although EPA’s proposed rule included emissions guidelines for existing gas-fired EGUs (based on CCR and co-firing hydrogen as BSER), the Final Rule deferred promulgating emissions guidelines for existing gas-fired EGUs. At the time of EPA’s proposal, many observers suggested that the proposition for existing gas-fired EGUs appeared rushed and lacked the level of technical analysis EPA included for other proposed standards and guidelines. News reports indicated that the proposed guidelines were added at a late stage during White House review of the draft proposed rule.

In the months leading up to EPA’s Final Rule, EPA announced its intention to undertake a separate, in-depth analysis of not only potential GHG emissions standards, but also hazardous and criteria air pollutant standards, for existing gas combustion turbines under Section 111(d). EPA has opened a non-regulatory docket and is soliciting comment until May 28, 2024 on EPA framing questions for stakeholder input.

  1. New Reliability Mechanisms Offer Compliance Flexibilities Depending on State or Federal Plans

The Final Rule allows States to include mechanisms in their plans that give some flexibility for certain EGUs under certain circumstances when facing compliance issues with State plan requirements or grid emergencies. For example, EPA allows a one-year compliance extension possibility for sources installing control technologies if they experience unanticipated delays outside of their control, e.g., supply chain issues or permit delays.

State plans may also allow EGUs to comply with an emission limitation set at their baseline emission rate during grid emergencies, for example, during extreme weather events, when electricity demand surges and outages frequently occur in parts of the grid. This flexibility, if included in the relevant State plan for existing sources, would allow both (1) the State to respond quickly to emergencies and (2) affected facilities to assist without fear of being out of compliance. This short-term reliability mechanism is also available to new sources by providing requisite documentation at the end of the annual compliance period.

A further flexibility States may choose to incorporate is a mechanism by which units ceasing operation can remain online for up to one year beyond the planned cease operation date if they can adequately show reliability need. This is intended to allow States to maintain grid reliability when they lack sufficient time to complete a formal revision to the State plan.  

States are also permitted to include compliance flexibilities such as emission trading, averaging, and unit-specific mass-based compliance in their State plans for units in the medium- and long-term coal-fired EGU subcategories. A mass-based compliance limit would require a backstop emission limitation be applied to individual sources. EPA provided a presumptively approvable methodology for unit-specific, mass-based compliance for affected EGUs in the long-term coal-fired subcategory. Whether or not this methodology would be available to particular EGUs will depend entirely on the State’s approach.

  1. Emission Standards for Individual Existing Coal-Fired Units to Be Included in State Plans

States are required to submit their plans to EPA within 24 months of publication of the Final Rule in the Federal Register. Each State plan must include, for each affected EGU in the State: (1) a standard of performance, (2) measures for the implementation and enforcement of that standard, (3) a compliance schedule, and (4) the applicable increments of progress (IoPs). The standards of performance that States establish in their plans must generally be as stringent as EPA’s presumptive standards, described in Section 1 above. States are not, however, prevented from applying standards of performance that are more stringent.

For affected EGUs in the long- and medium-term coal-fired subcategories, the Final Rule requires that State plans include legally enforceable IoPs that serve as “implementation checkpoints” to ensure progress is being made toward compliance with State plans. CAA Subpart Ba, the implementing regulations for Section 111(d) emissions guidelines, requires IoPs when a compliance schedule extends more than a specified length of time from the State plan submission date. In such cases, IoPs address the lengthy planning and construction processes associated with the CCS and natural gas co-firing BSERs. For affected EGUs that plan to permanently cease operations, the Final Rule requires that State plans contain legally enforceable reporting obligations and milestones toward shutdown to ensure that affected EGUs can complete the steps necessary to qualify for the applicable subcategory with a less stringent standard of performance.

State plans may provide variances for individual EGUs based on “remaining useful life and other factors” (RULOF). “Other factors” typically can include, among other things, unreasonable cost of control resulting from plant age, location, or basic process design and physical impossibility, or technical infeasibility of installing necessary control equipment. In this instance, EPA has said that a variance based on RULOF requires a “fundamental difference” between the circumstances of the affected EGU and the information the EPA considered in determining the compliance schedule in the emission guidelines. Facilities seeking such a variance should therefore be prepared to demonstrate that “fundamental difference.”

Finally, CAA Subpart Ba includes provisions for meaningful engagement with pertinent stakeholders, including community members, industry, reliability coordinators, and small businesses. Stakeholders should keep an eye out for notices of stakeholder meetings and presentations.

  1. Uncertainty Looms Amid Likely Litigation

The Power Plant GHG Rule will be litigated once it is published in the Federal Register. The key question is whether opponents will succeed in getting a stay of the rule, pending the outcome of the case, or whether the court will let the rule take effect. The CPP was immediately challenged in court when it was published. Although the US Court of Appeals for the D.C. Circuit denied petitioners’ request for a stay of the CPP, the Supreme Court granted a stay of the CPP on February 9, 2016, pending the legal challenge. Therefore, as a practical matter for the regulated entities, the CPP never went into effect.

Even if the Power Plant GHG Rule takes effect after EPA finalizes it, ongoing litigation may create significant uncertainty. As we saw with the CPP and ACE Rule, litigation timelines are long and unpredictable. And the Supreme Court’s reliance on the “major questions doctrine” in its recent decision regarding the CPP raises questions regarding whether potential challengers will seek to overturn the Power Plant GHG Rule on that ground. Additionally, the Supreme Court’s anticipated decision in a case addressing deference to agency interpretation of statutory language could also come into play.

Any change in administration would create more uncertainty, threatening another change of course from EPA, similar to when the CPP was repealed and replaced with the less-stringent and more narrow ACE Rule.

Latham & Watkins will continue to monitor the many issues involved in this rulemaking and the ongoing status of the Power Plant GHG Rule.

Read our second post in the series: EPA Extends CCR Regulations to Previously Exempt CCR Units