EPA’s long-awaited proposal would set aggressive emission reduction targets with many different approaches and timelines to achieve them.
On May 11, 2023, the US Environmental Protection Agency (EPA) released its proposed rule[1] to regulate carbon dioxide (CO2) emissions from electric generating units (EGUs) at power plants under Section 111 of the Clean Air Act (CAA) (the Power Plant GHG Rule or the Proposed Rule).
The Power Plant GHG Rule consists of five proposed actions:
- determinations and updates to current CO2 standards of performance (promulgated in 2015) for new and reconstructed stationary combustion turbines (generally natural gas-fired) pursuant to Section 111(b) of the CAA;
- determinations and updates to current CO2 standards of performance (promulgated in 2015) for modified fossil fuel-fired steam-generating EGUs (generally coal-fired) pursuant to Section 111(b) of the CAA;
- determinations and CO2 emission guidelines for existing fossil fuel-fired steam-generating EGUs (generally coal-fired) pursuant to Section 111(d) of the CAA;
- determinations and CO2 emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired) pursuant to Section 111(d) of the CAA; and
- a repeal of the Trump-era Affordable Clean Energy (ACE) Rule.
EPA is also soliciting comment on a number of topics, including potential options and emission guidelines for existing fossil fuel-fired stationary combustion turbines not otherwise covered by the Proposed Rule (generally natural gas-fired units that are either smaller or less frequently used).
Although CO2 emission performance standards for new and reconstructed EGUs have been in place since 2015,[2] existing EGUs have remained unregulated at the federal level because two EPA rulemakings under Section 111(d) of the CAA to regulate existing EGU CO2 emissions have been mired in litigation. In 2015, the Obama Administration EPA’s Clean Power Plan (CPP) finalized a CO2 emissions regulation for existing EGUs under Section 111(d) by determining a “best system of emission reduction” (BSER) that was based in large part on generation shifting to lower-carbon energy sources. However, in February 2016, the US Supreme Court stayed implementation of that rule, pending litigation challenges in federal court. And while that litigation was pending, EPA — then under the Trump Administration — replaced the CPP with the ACE Rule, which rejected generation shifting in favor of heat rate improvements as the BSER for CO2 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 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 generation shifting as BSER in the CPP exceeded the agency’s statutory authority under the CAA. However, the Court’s decision left open questions regarding the scope of EPA’s statutory authority to interpret BSER.
Against this long and complicated backdrop, EPA has taken another shot at regulating CO2 emissions from existing EGUs and has proposed ratcheting down the CO2 emission standards of performance for new, modified, or reconstructed EGUs.
Here are five things to know about the Power Plant GHG Rule.
1. The Power Plant GHG Rule would set CO2 limits, but most existing sources would have compliance options
The Power Plant GHG Rule does not mandate that a specific EGU adopt a specific technology or control measure. Rather, EPA’s proposal sets CO2 limits — emission 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, based on generating technology, size of unit, level of operations, and anticipated remaining operational life of the unit, resulting in multiple proposed compliance paths for many EGUs. Here is a brief overview of this unique regulatory framework under Section 111 and how it has translated into the Proposed Rule.
New, modified, or reconstructed EGUs — §111(b)
Under Section 111(b) of the CAA, EPA establishes standards of performance governing the emission of air pollutants from new, modified,[3] or reconstructed[4] stationary sources. A “standard of performance” means “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [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.”[5]
Therefore, under the CAA, EPA first identifies a BSER and then sets a standard of performance (an emission standard) that reflects the emission reductions achievable through application of that BSER. New, modified, or reconstructed sources must then meet that emission standard on a timeline identified by EPA.
In the Power Plant GHG Rule, EPA has proposed to revise the current New Source Performance Standard (NSPS), promulgated in 2015, with separate BSER determinations and resulting emission standards for three subcategories of new and reconstructed fossil fuel-fired combustion turbines primarily operating on natural gas.
1 the upper bound of the intermediate load subcategory, and threshold for the base load subcategory, is source-specific, based on the design efficiency of the unit, and expected to generally be around 50%.
EPA is also proposing to revise the 2015 NSPS for modified coal-fired EGUs, applicable only to those modifications that increase the EGU’s hourly emission rate by more than 10%. This standard will now be the equivalent of the proposed emission guidelines for existing coal-fired EGUs, as described below. However, EPA is not revising the 2015 NSPS for new and reconstructed coal-fired units, as it does not anticipate such new units coming online.
The Proposed Rule’s requirements for new and reconstructed fossil fuel-fired combustion turbines primarily operating on natural gas apply to “affected facilities,” which are defined by the Proposed Rule as any source that commences construction or reconstruction after the date the Proposed Rule is published in the Federal Register. All affected facilities must comply with Phase 1 for the relevant subcategory by the date the final rule is promulgated or upon initial startup of the facility, if construction commences after promulgation.
Existing EGUs — § 111(d)
Section 111(d) of the CAA is a rarely used provision that directs EPA to establish procedures enabling states to establish plans for implementing and enforcing performance standards for existing sources of an air pollutant, once EPA has established a standard of performance for new sources of that pollutant. EPA determines what constitutes the BSER for existing sources within the source category, again with the ability to distinguish subcategories and develop different emission guidelines, and then states must develop and submit to EPA for approval a State Plan setting standards of performance and providing for implementation and enforcement of such standards. If EPA disapproves a state’s submittal, or a state fails to timely submit a State Plan to comply with the Power Plant GHG Rule, EPA may impose on that state a Federal Plan that achieves compliance with the emission guidelines and imposes requirements on sources within the state.
In the Power Plant GHG Rule, EPA is proposing separate emission guidelines applicable to the fossil fuel-fired stationary combustion turbine category (generally natural gas-fired) and applicable to the fossil fuel-fired steam-generating EGUs category (generally coal-fired). Further, EPA has proposed extensive subcategorization within the coal-fired EGU category.
Existing fossil fuel-fired stationary combustion turbines (primarily natural gas)
This category applies only to existing large turbines over 300 MW that operate frequently, with a capacity factor greater than 50%. EPA has determined two BSERs for this group: (1) CCS with 90% capture of CO2 by 2035 (with an associated 89% reduction in emission rate), or (2) co-firing low-GHG hydrogen, at 30% by volume by 2032 (12% reduction in emission rate), and increasing to 96% by volume in 2038 (88.4% reduction in emission rate). EPA is also soliciting comment on how it should establish emission guidelines for smaller frequently used EGUs and less frequently used EGUs (e.g., existing “peaking units”) in this subcategory. While emission guidelines for those sources are not included in the Proposed Rule, EPA references a legal obligation to establish emission guidelines for this set of sources.
Existing fossil fuel-fired steam-generating EGUs (primarily coal)
This category applies to all existing fossil fuel-fired steam-generating EGUs, with subcategories based on fuel combusted and capacity factor. For coal-fired EGUs, EPA further subcategorizes with different BSER depending on how long the unit intends to operate (subject to the condition that the commitment is included in the State Plan and federally enforceable), with less stringent reductions with earlier retirement dates and the strictest emission guidelines for units that intend to operate past December 31, 2039:
This set of proposed emission guidelines also includes a subcategory applicable to natural gas- and oil-fired steam-generating EGUs, with BSER consisting of routine methods of operation and maintenance.
2. Emission standards for existing units will be set forth in State Plans
States must prepare State Plans to determine how the affected existing EGUs in the state will comply with the Power Plant GHG Rule. The State Plans must include specific emission standards for EGUs that achieve the same stringency as the emission guidelines in the Proposed Rule. State Plans must include increments of progress for each facility to achieve compliance within the required timeline.
EPA anticipates and intends that most states will adopt EPA’s “presumptively approvable standards of performance” for most types of affected EGUs. EPA outlines a mechanism for states to establish a baseline emission rate for each affected EGU and then apply the degree of emission reduction that EPA has determined is achievable through application of the BSER (see above for anticipated reduction in emission rates).
In order to rely on the “presumptively approvable standards of performance,” State Plans must include certain requirements detailed in the Proposed Rule, such as milestones for all coal-fired imminent-, near-, and medium-term units to ensure those EGUs are on schedule to retire when they have committed to doing so. Additionally, State Plans must require that imminent- and near-term units cannot exceed their baseline emission performance prior to retirement. For combustion turbines (primarily natural gas-fired) that do not intend to operate at a capacity factor above 50%, the EGU can commit to an enforceable annual capacity factor less than or equal to 50% in the State Plan, and the state is not required to include a standard of performance for that EGU in the State Plan.
In their State Plan, states may invoke the Remaining Useful Life of Facility (RULOF) to apply a less stringent standard of performance to a particular facility, if the state demonstrates that the particular EGU cannot reasonably apply the BSER to achieve the emission limitation determined by EPA. This determination must be based on: (1) unreasonable cost of control resulting from plant age, location or basic process design; (2) physical impossibility or technical infeasibility of installing necessary control equipment; and (3) other circumstances specific to the facility that are fundamentally different from the information considered in the determination of the BSER in the emission guidelines. States must also consider the impact of applying RULOF on potential disparate impacts to vulnerable communities. EPA signals in the Proposed Rule that it expects states’ use of RULOF would be limited to very unique circumstances of a given EGU, and specifies that any costs EPA has determined are reasonable cannot be the basis for a RULOF demonstration.
3. The timing of implementation will vary for different subcategories
The Power Plant GHG Rule has a long road ahead — particularly before any existing source will be directly subject to its requirements. First, EPA must complete the rulemaking process. At a minimum, the Proposed Rule will be subject to a 60-day public comment period beginning when it is published in the Federal Register. And it seems likely that the public comment period will be extended, given the rule’s complexity and length (the Notice of Proposed Rulemaking is 681 pages) and an early request for extension from members of the House Energy and Commerce’s Environment, Manufacturing, and Critical Materials Subcommittee. Then EPA must consider and respond to public comments, send the final rule to the White House Office of Management and Budget for interagency review, and publish the final rule in the Federal Register. While EPA states in the Proposed Rule that it expects to finalize emission guidelines by June 2024, that is a very challenging timeline. Most likely, the Proposed Rule will not be finalized for over a year — and potentially longer than that.
For new and reconstructed EGUs, compliance deadlines depend on the unit’s subcategory and compliance pathway. Units must comply with Phase 1 requirements as of the date the final rule is promulgated or when the unit commences construction, whichever is later. Intermediate and base load units must meet Phase 2 and (if applicable) Phase 3 requirements by 2032-2038, as detailed above.
For existing sources, the timeline for implementation is even longer. States will have up to 24 months after finalization of the rule to submit a State Plan and EPA will have a year to review and act on the plan. The State Plan will require compliance by existing steam-generating (coal-fired) EGUs no sooner than January 1, 2030. This timeline is based on EPA’s assumption that adding infrastructure for natural gas co-firing will take three and a half years, and adding CCS capability will take five years. For combustion turbines (natural gas-fired) utilizing CCS, these units must comply by 2035. EPA has assumed that coal-fired EGUs installing CCS may take up significant CCS capacity, and so proposed a compliance deadline for these EGUs of five years after coal-fired EGUs. Combustion turbines utilizing low-GHG hydrogen co-firing must comply by 2032 and 2038, with EPA determining these deadlines based on its assumptions regarding the availability of low-GHG hydrogen.
If EPA does not approve a given state’s plan or a state does not submit a plan, then EPA will have a year to impose a Federal Plan. The compliance deadlines are dependent on EPA finalizing the rule in June 2024; if the rule is not finalized by then, EPA will adjust the State Plan and EGU compliance deadlines accordingly.
4. Existing EGUs may have compliance flexibilities to contain costs, depending on State or Federal Plans
EPA is taking comment in the Power Plant GHG Rule on multiple potential measures in State or Federal Plans to provide regulated entities with compliance flexibility and to contain costs of complying with the rule. For existing sources, EPA is proposing to allow states to include compliance flexibilities such as averaging and market-based allowance trading mechanisms into their State Plans, so long as the emission performance of EGUs in that state is equivalent to each EGU individually achieving its standard of performance.
However, states would not be compelled to include those compliance flexibilities in State Plans; rather it would be up to each state to decide whether to include these mechanisms, assuming EPA finalizes a rule that would allow for them. Although EPA has not proposed a specific scope of these compliance flexibility measures, EPA notes that there are units that it believes may not be appropriate to include in a trading program, such as units for which EPA has identified routine methods of operation and maintenance as BSER.
EPA describes the potential forms of trading programs, including a rate-based trading program, a mass-based trading program, and the fact that programs can be intra- or inter-state in nature. EPA takes comments on all of those trading program design considerations and also takes comment on whether EPA should allow State Plans to permit allowance banking by an affected EGU.
5. Uncertainty looms
The Power Plant GHG Rule will almost certainly be litigated, but challenges cannot be filed until the rule is final. At that point (likely more than a year from now), 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 the day it was finalized on October 23, 2015. Although the D.C. Circuit denied petitioners’ request for a stay of the CPP, the Supreme Court on February 9, 2016, granted a stay of the CPP pending the legal challenge, so, 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 once again seek to overturn the Power Plant GHG Rule on that ground. Additionally, the Supreme Court’s May 1, 2023 decision to hear a case challenging the Chevron doctrine and agency discretion to interpret statutory language could also come into play when the Power Plant GHG Rule is challenged in court.
Any change in administration would create added uncertainty, threatening another change of course from EPA, similar to when the CPP was repealed and replaced with the less-stringent and far more narrow ACE Rule.
EPA plans to host virtual trainings on the Power Plant GHG Rule on June 6 and 7, 2023, and will host two public hearings with dates to be determined (21 and 22 days after the Proposed Rule is published in Federal Register). Latham & Watkins will continue to monitor the many issues involved in this rulemaking and the ongoing status of the Power Plant GHG Rule.
Endnotes
[1] “New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule.”
[2] At that time, EPA did not finalize standards of performance for modified stationary combustion turbines, as it concluded it needed more information. EPA stated in the Notice that it is not aware of any evidence that facility operators intend to modify these EGUs and EPA is not proposing standards of performance for modifications of stationary combustion turbines in the Proposed Rule. See Proposed Rule at p. 327.
[3] A modified source is an existing source that undergoes a physical or operational change that increases the amount of an air pollutant emitted by the source, or which results in the emission of an air pollutant not previously emitted.
[4] A reconstructed source is an existing source that replaces components at a capital cost exceeding 50% of the fixed capital costs of an entirely new facility, and for which compliance with the standards is technologically and economically feasible.
[5] 42 U.S.C. § 7411(a)(1).
