To calculate CO2 mass emissions at a fossil fuel-fired boiler, the EGU typically measures CO2 concentration and flue gas flow rate as the exhaust gases from combustion pass through the stack (or duct). Under 40 CFR part 75, EGUs must complete regular performance tests on the flue gas flow monitor based on EPA Reference Method 2 or its allowable alternatives that are provided in 40 CFR part 60, appendices A-1 and A-2. In general, the allowable alternative measurement methods reduce or eliminate the potential overestimation of stack gas flow rate that results from the use of EPA Reference Method 2 when the specific flow conditions (e.g., angular flow) are present in the stack. However, EGUs with stack gas flow monitors are not required to use the allowable alternative measurement methods and EGUs may change methods at any time. The EPA requests comment on the following questions related to the use of EPA Reference Method 2 and its allowable alternatives for stack gas flow monitors under 40 CFR part 75: a) should or under what conditions should EGUs be required to conduct a flow study and choose the appropriate EPA reference method for each stack gas flow monitor based on the results of the study, b) once an EGU selects the use of an EPA reference method for a stack gas flow monitor, regardless of the basis for that selection, should the EGU be required to continue using the same EPA reference method until a flow study or other engineering justification is made to change the EPA reference method, and c) what additional monitoring plan, quality assurance, and emissions data should be reported to the EPA to support evaluation and ensure consistent and accurate data as it relates stack gas flow rate and performance of the stack gas flow monitor.
Compliance Flexibilities
In developing these proposed emission guidelines, the EPA has heard from stakeholders seeking compliance flexibility in light of the rapidly evolving and dynamic nature of the power sector. In particular, stakeholders have requested that the EPA allow states to include flexibilities such as averaging and market-based trading in their state plans, as has been permitted under prior EPA rules. This section discusses considerations related to potential compliance flexibilities in the context of this particular rule and set of regulated sources, and solicits comment on the appropriateness of averaging and trading for these emission guidelines.
Overview
In the proposed subpart Ba revisions, "Adoption and Submittal of State Plans for Designated Facilities: Implementing Regulations Under Clean Air Act Section 111(d)" (87 FR 79176; December 23, 2022), the EPA explained that under its proposed interpretation of CAA section 111, each state is permitted to adopt measures that allow its sources to meet their emission limits in the aggregate when the EPA determines, in any particular emission guideline, that it is appropriate to do so given, inter alia, the pollutant, sources, and standards of performance at issue. Thus, the EPA has proposed to return to its longstanding position that CAA section 111(d) authorizes the EPA to approve state plans that achieve the requisite emission limitation through aggregate reductions from their sources, including through trading or averaging, where appropriate for a particular emission guideline and consistent with the intended environmental outcomes of the guideline. See 87 FR 79208 (December 23, 2022).
Consistent with the return to this longstanding position, the EPA is taking comment on whether trading and averaging are appropriate under these emission guidelines. If permitted, states would not be required to allow for such compliance mechanisms in their state plans but could provide for trading and averaging at their discretion. This section discusses considerations related to the appropriateness of trading and averaging in the context of these emission guidelines and solicits comment on these considerations. This section also takes comment on how trading and averaging programs, if permitted, could be designed to ensure that state plans maintain the level of emission performance by affected EGUs that is required under these proposed emission guidelines, and it includes illustrative program design methods.
As discussed in section XI.C of this preamble, state plans must demonstrate that they achieve a level of emission performance by affected EGUs that is consistent with the application of the BSER. If a state plan was to include trading or averaging, it would need to provide a demonstration that affected EGUs complying through such flexible mechanisms would still achieve an equivalent level of emission performance consistent with the application of the BSER. In the case of averaging, discussed in section XI.E.3 of this preamble, an equivalence demonstration would be relatively straightforward. For emission trading programs, ensuring equivalent emission performance in the aggregate may be more difficult, especially given the current rapid evolution of the affected source category for these emission guidelines. In section XI.E.2 of this preamble, the EPA discusses program design examples as well as potential design elements and takes comment on whether they could ensure that use of emission trading does not erode the emission performance improvements that these emission guidelines are designed to achieve.
The EPA also notes that, if trading and averaging are permitted under these emission guidelines, states that incorporate trading or averaging into their state plans would need to conduct meaningful engagement on this aspect of their plans with pertinent stakeholders, just as they would need to do for any other part of a plan. As discussed in greater detail in section XI.F.1.b of this preamble, meaningful engagement provides an opportunity for communities most affected by and vulnerable to the health and environmental impacts of a plan to provide input, including input on any impacts resulting from trading or averaging.
Emission Trading
The EPA is seeking comment on whether it is appropriate to allow state plans to include emission trading programs as a compliance flexibility for affected EGUs under these emission guidelines, including whether certain types of trading programs may be more appropriate than others. This section discusses considerations related to whether the EPA should permit emission trading, as well as how, if emission trading is allowed, states could potentially incorporate a rate-based trading program or a mass-based trading program in a way that preserves the stringency of these emission guidelines. The EPA is seeking comment on these potential methods, as well as on other methods that could maintain the required level of emission performance under the proposed emission guidelines.
Considerations for Emission Trading in State Plans
Emission trading has been used to achieve required emission reductions in the power sector for nearly 3 decades. In Title IV of the Clean Air Act Amendments of 1990, Congress specified the design elements for the Acid Rain Program, a 48-state allowance trading program to reduce SO2 emissions and the resulting acid precipitation. Building on the success of that first allowance trading program as a tool for addressing multi-state air pollution issues, the EPA has promulgated and implemented multiple allowance trading programs since 1998 for SO2 or NOX emissions to address the requirements of the CAA's good neighbor provision with respect to successively more stringent NAAQS for fine particulate matter and ozone. The EPA currently administers eight power sector emission trading programs that differ in pollutants, geographic regions, covered time periods, and levels of stringency. Annual progress reports demonstrate that EPA trading programs have been successful in mitigating the problems they were designed to address, exhibiting significant emission reductions and extraordinarily high levels of compliance. In addition, several states have implemented intrastate or regional CO2 emissions trading programs to address GHG emissions from the power sector (the RGGI and California trading programs, respectively).
In general, emission trading programs provide flexibility for EGUs to secure emission reductions at a lower cost relative to more prescriptive forms of regulation. Emission trading can allow the owners and operators of EGUs to prioritize emission reduction actions where they are the quickest or cheapest to achieve while still meeting electricity demand and broader environmental and economic performance goals. These benefits are heightened where there is a diverse set of emission sources (e.g., variation in technology, fuel type, age, and operating parameters) included in an emission trading program. This diversity of sources is typically accompanied by differences in marginal emission abatement costs and operating parameters, resulting in heterogeneity in economic emission reduction opportunities that can be optimized through the compliance flexibility provided through emission trading. In addition, the EPA has observed, with the support of multiple independent analyses, that there is significant evidence that implementation of trading programs prompted greater innovation and deployment of clean technologies that reduce emissions and control costs.
Emission trading may provide important benefits as the fleet of EGUs affected by these emission guidelines is rapidly evolving. Having flexibility to prioritize the most cost effective emission reductions among affected EGUs may reduce the cost of compliance as well as provide flexibility for fleet management, while achieving the requisite level of emission performance. In particular, emission trading may provide short-term operational flexibility to meet reliability needs.
At the same time, a rapidly evolving fleet of affected EGUs may pose challenges for implementing an emission trading program, especially in the context of the emission guidelines that the EPA is proposing here. The EPA notes that the proposed emission guidelines only include steam generating units and that the fleet of affected EGUs is expected to shrink significantly under BAU projections (see section IV.F of this preamble). As a result, there is unlikely to be as much diversity in cost and emission performance among affected emission sources (resulting in less diversity in emission reduction opportunities and marginal abatement costs) as seen in prior emission trading programs for the electric power sector. The projected BAU contraction of the fleet over the next 10 to 15 years also means there may be few affected emission sources in a state that could be included in an emission trading program.
The utility of trading under these emission guidelines may also be obviated by subcategories the EPA has proposed to establish. The specific subcategories proposed under these emission guidelines are designed to provide for much of the same operational flexibility as trading; as a result, the EPA believes that it would not be appropriate to allow affected EGUs in certain subcategories to comply with their standards of performance through trading. As discussed in section X.D.3 of this preamble, the BSER determinations for the imminent- and near-term coal-fired steam generating unit subcategories are designed to take into account factors such as operating horizon and load level (expressed as annual capacity factor). In addition, states may invoke RULOF, where appropriate, when establishing standards of performance for certain affected EGUs. An emission trading program that includes affected EGUs that have BSERs and resulting standards of performance based on limited expected emission reduction potential--affected EGUs in the imminent- and near-term coal-fired subcategories, as well as natural gas- and oil-fired steam generating units--or a less stringent standard of performance established through a state invoking RULOF, may introduce the risk of undermining the intended stringency of the emission guidelines for other facilities that would not otherwise meet the RULOF criteria. In addition, affected EGUs in the long-term subcategory that receive the IRC section 45Q tax credit for permanent sequestration of CO2 may have an overriding incentive to maximize both the application of the CCS technology and total electric generation, leading to source behavior that may be non-responsive to the economic incentives of a trading program.
The EPA requests comment on these challenges and on whether, in light of these and other considerations, emission trading should be permitted as a compliance flexibility under these emission guidelines. In particular, the EPA is soliciting comment on whether there is utility in permitting trading for any of the proposed subcategories of affected EGUs, after considering the operational flexibility already provided by the structure of those subcategories and their proposed BSERs. The EPA is also soliciting comment on whether trading could or should be permitted for certain subcategories and not others, and why. In the following sections, the EPA discusses potential rate-based and mass-based emission trading program approaches that, if trading is permitted, could potentially be included in a state plan and solicits comment on applied implementation issues in the context of these proposed emission guidelines and the considerations discussed earlier in this preamble.
Rate-based Emission Trading
A rate-based trading program allows affected EGUs to trade compliance instruments that are generated based on their emission performance. This section describes one method of how states could establish a rate-based trading program as part of a state plan. The EPA requests comment on whether this or another method of rate-based trading could ensure the level of emission performance required under these emission guidelines.
In this example, affected EGUs that perform at a lower emission rate (lb CO2/MWh) than their standard of performance would be issued compliance instruments that are denominated in one ton of CO2. A tradable instrument denominated in another unit of measure, such as a MWh, is not fungible in the context of a rate-based emission trading program. A compliance instrument denominated in MWh that is awarded to one affected EGU may not represent an equivalent amount of emissions credit when used by another affected EGU to demonstrate compliance, as the CO2 emission rates (lb CO2/MWh) of the two affected EGUs are likely to differ. This may pose challenges for states trying to demonstrate equivalence with the intended stringency of the BSER.
These compliance instruments could be transferred among affected EGUs, making them "tradable." Compliance would be demonstrated for an affected EGU based on a combination of its reported CO2 emission performance (in lb CO2/MWh) and, if necessary, the surrender of an appropriate number of tradable compliance instruments, such that the demonstrated lb CO2/MWh emission performance is equivalent to the rate-based standard of performance for the affected EGU.
Specifically, each affected EGU would have a particular standard of performance, based on the degree of emission limitation achievable through application of the BSER, with which it would have to demonstrate compliance. Under a rate-based trading program, affected EGUs performing at a CO2 emission rate below their standard of performance would be awarded compliance instruments at the end of each control period denominated in tons of CO2. The number of compliance instruments awarded would be equal to the difference between their standard of performance CO2 emission rate and their actual reported CO2 emission rate multiplied by their generation in MWh. Affected EGUs performing worse than their standard of performance would be required to obtain and surrender an appropriate number of compliance instruments when demonstrating compliance, such that their demonstrated CO2 emission rate is equivalent to their rate-based standard of performance. Transfer and use of these compliance instruments would be accounted for with a rate adjustment as each affected EGU performs its compliance demonstration.
In general, rate-based emission trading can by design assure achievement of the requisite level of emission performance for affected sources, because reduced utilization and retirements are automatically accounted for in the award of the compliance instrument. By default, only operating steam generating units could receive or participate in the trading of compliance instruments.
The EPA is seeking comment on whether rate-based emission trading might be appropriate under these emission guidelines. In particular, the EPA requests comment on whether there is utility in permitting rate-based emission trading and whether such program could be designed to preserve the intended stringency of these emission guidelines given the structure of the proposed subcategories, their proposed BSERs, and the dynamic nature of the power sector. The EPA also requests comment on any other methods of rate-based trading that would preserve the intended stringency of these emission guidelines.
Mass-based Emission Trading
A mass-based trading program establishes a budget of allowable mass emissions for a group of affected EGUs, with tradable instruments (typically referred to as "allowances") issued to affected EGUs in the amount equivalent to the emission budget. Each allowance would represent a tradable permit to emit one ton of CO2, with affected EGUs required to surrender allowances in a number equal to their reported CO2 emissions during each compliance period. This section describes one method of how states could establish a mass-based trading program as part of a state plan. The EPA requests comment on whether this or another method of mass-based trading could ensure the level of emission performance required under these emission guidelines.
As previously discussed, mass-based emission trading has been used in the power sector at the Federal, regional, and state levels for nearly 3 decades. Owners and operators of EGUs, utilities, and state agencies thus have extensive familiarity with mass-based emission trading, which could make the design and implementation of a mass-based trading program as part of a state plan relatively straightforward. However, this familiarity comes with an awareness on the part of states and the EPA of the need to tailor the design of a mass-based emission trading program to the situation in which it is applied. This is especially important in instances where a sector is rapidly evolving. Past experience shows that emission budgets have often been overestimated when set many years in advance of the start of a program, as economic and technological conditions have changed significantly between the time the program was adopted and when compliance obligations begin. Projecting affected EGU fleet composition and utilization beyond the relative near term has become increasingly challenging in light of the aforementioned rapid evolution of the electric power sector, driven by factors including changes in relative fuel prices and continued rapid improvement in the cost and performance of wind and solar generation, along with new incentives for technology deployment provided by the IIJA and the IRA. Without a regular adjustment to the mass budget, if enough affected EGUs cease operations or reduce utilization, the source category could reach a point at which none of the remaining affected EGUs have to do anything to improve their emission performance. In this case, the mass budget would be established at a level such that the sources would not be collectively meeting a level of emission performance commensurate with each source's achieving its rate-based standard of performance. This outcome would be contrary to the statutory purpose of mitigating emissions from the source category to an extent that reflects application of the BSER. Such an outcome would be likewise contrary to EPA's long-standing requirement, reflected in its implementing regulations for section 111(d), that state plans establish standards of performance that are at least as stringent as EPA's emission guidelines.
States would thus need to ensure that affected EGUs participating in a mass-based trading program continue to meet the level of emission performance prescribed by category-wide, source-specific implementation of the rate-based standards of performance. This could be done by regularly adjusting emission budgets to account for sources that cease operations or change their utilization. One budget adjustment method that the EPA has developed is dynamic budgeting, as applied in the Good Neighbor Plan, in which budgets are updated annually based on recent historical generation. States could apply a similar dynamic budgeting process to mass-based trading implemented under these emission guidelines. In this context, states could establish an emission budget based on the unit-specific standards of performance of the participating affected EGUs, as described in section XI.D of this preamble, multiplied by each affected EGU's recent historical generation. The emission budgets would be updated periodically to account for units that reduce utilization or cease operation. This is one way that states could assure achievement of the requisite level of emission performance for affected EGUs through mass-based trading, though the EPA acknowledges that state or regional mass-based trading programs may have developed other regular budget adjustment methods that could provide similar assurance.
The EPA is seeking comment on whether mass-based emission trading might be appropriate under these emission guidelines. In particular, the EPA requests comment on whether there is utility in permitting mass-based emission trading and whether such program could be designed to preserve the intended stringency of these emission guidelines given the structure of the proposed subcategories, their proposed BSERs, and the dynamic nature of the power generation sector. The EPA is also seeking comment on whether the method of mass-based emission trading using dynamic budgeting, as discussed in this section, might be appropriate under these emission guidelines. The EPA is also seeking comment on other approaches or features that could ensure that emission budgets reflect the stringency that would be achieved through unit-specific application of rate-based standards of performance.
General Emission Trading Program Implementation Elements
The EPA notes that state plans would need to establish procedures and systems necessary to implement and enforce an emission trading program, whether it is rate-based or mass-based. This would include, but is not limited to, establishing compliance timeframes and the mechanics for demonstrating compliance under the program (e.g., surrender of compliance instruments as necessary based on monitoring and reporting of CO2 emissions and generation); establishing requirements for continuous monitoring and reporting of CO2 emissions and generation; and developing a tracking system for tradable compliance instruments. Additionally, for states implementing a mass-based emission trading program, state plans would need to specify how allowances would be distributed to participating affected EGUs.
The EPA is requesting comment on whether and to what extent there would be a desire, if emission trading is permitted under these emission guidelines, to capitalize on the EPA's existing reporting and compliance tracking infrastructure to support state implementation of an emission trading program included in a state plan.
Banking of Compliance Instruments
The EPA requests comment on whether, if emission trading is permitted under these emission guidelines, state plans should be allowed to provide for banking of tradable compliance instruments (hereafter referred to as "allowance banking," although it is relevant for both mass-based and rate-based trading programs). Allowance banking has potential implications for a trading program's ability to maintain the requisite environmental performance of the standards of performance. The EPA recognizes that allowance banking (that is, permitting allowances that remain unused in one control period to be carried over for use in future control periods) may provide incentives for early emission reductions, promote operational flexibility and planning, and facilitate market liquidity. However, the EPA has observed that unrestricted allowance banking from one control period to the next (absent provisions that adjust future control period budgets to account for banked allowances) may result in a long-term allowance surplus that has the potential to undermine a trading program's ability to ensure that, at any point in time, the affected sources are achieving the required level of emission performance. In addition to requesting comment on whether the EPA should allow allowance banking if emission trading is permitted under these emission guidelines, the EPA requests comment on the treatment of banked allowances, specifically whether all or only some portion of an allowance bank could be carried over for use in future control periods or if additional program design elements would be necessary to accommodate allowance banking.
Interstate Emission Trading
The EPA is requesting comment on whether, if emission trading is permitted under these emission guidelines, it should allow for interstate emission trading. Given the interconnectedness of the power sector and given that many utilities operate in multiple states, interstate emission trading may increase compliance flexibility. For interstate emission trading programs to function successfully, all participating states would need to, at a minimum, use the same form of trading and have identical program requirements. If interstate emission trading were allowed, there are many other requirements for program reciprocity and approvability that would need to be established in the emission guidelines, in addition to providing mechanisms for submission and EPA review of state plans that include interstate trading mechanisms. Given the increased level of program complexity that would be necessary to accommodate interstate trading, the operational flexibilities already provided by the structure of the proposed subcategories and their proposed BSERs, and the dynamic nature of the power sector, the EPA requests comment on whether there is utility in providing for it under these emission guidelines. In the event it is permitted, the EPA is requesting comment on the information, guidance, and requirements the EPA would need to provide for states to implement successful interstate emission trading programs.
Rate-based Averaging
The EPA is seeking comment on whether it is appropriate to allow state plans to include rate-based averaging as a compliance flexibility for affected EGUs under these emission guidelines. This section discusses considerations related to this question as well as how, if permitted under these emission guidelines, states could potentially incorporate a rate-based averaging program in a way that preserves the stringency of these emission guidelines. The EPA is seeking comment on one potential method, as well as other methods that could maintain the required level of emission performance under the proposed emission guidelines.
   Averaging allows multiple affected EGUs to jointly meet a rate-based emission standard. Affected EGUs participating in averaging could, for example, demonstrate compliance through an effective CO2 emission rate that is based on a gross generation-based weighted average of the required standards of performance of the affected EGUs that participate in averaging. The scope of such averaging could apply at the facility level or the owner or operator level. This method for calculating a composite rate could demonstrate equivalence with the intended emission performance under these emission guidelines.
Averaging can provide potential benefits. First, it offers some flexibility for sources to target cost effective reductions at any affected EGUs. For example, owners or operators of affected EGUs might target installation of emission control approaches at units that operate more. Second, averaging at the facility level provides greater ease of compliance accounting for affected EGUs with a complex stack configuration (such as a common- or multi-stack configuration). In such instances, unit-level compliance involves apportioning reported emissions to individual affected EGUs that share a stack based on electricity generation or other parameters.
However, the EPA notes that the subcategory approach in these emission guidelines already provides significant operational flexibility for affected EGUs, potentially making the provision of further flexibility through averaging redundant or inappropriate, especially at the owner or operator level.
The EPA is seeking comment on whether rate-based averaging should be permitted as a compliance flexibility, as well as on the illustrative method for developing a composite standard of performance for the purposes of rate-based averaging. The EPA is also seeking comment on any other considerations related to rate-based averaging, including whether the scope of averaging should be limited to a certain level of aggregation (e.g., to facility-level rate-based averaging).
Relationship to Existing State Programs
The EPA recognizes that many states have adopted binding policies and programs under their own authorities (with both a supply-side and demand-side focus) that have significantly reduced CO2 emissions from EGUs, that these policies will continue to achieve future emission reductions, and that states may continue to adopt new power sector policies addressing GHG emissions. States have exercised their power sector authorities for a variety of purposes, including economic development, energy supply and resilience goals, conventional and GHG pollution reduction, and generating allowance proceeds for investments in communities disproportionately impacted by environmental harms. The scope and approach of EPA's proposed emission guidelines differs significantly from the range of policies and programs employed by states to reduce power sector CO2 emissions, and this proposal operates more narrowly to improve the CO2 emission performance of a subset of EGUs within the broader electric power sector. The Agency recognizes the importance of state programs and their potential to reduce power sector CO2 emissions through a range of strategies broader than those proposed here pursuant to CAA section 111(d). To help facilitate the continued operation of existing state programs and to preserve opportunities for states to set and pursue their own power sector CO2 emission reduction goals, the EPA seeks comment on whether there are any elements of the proposed emission guidelines that might interfere with the implementation of state policies and programs that are designed to reduce power sector CO2 emissions, including those that apply CO2 emission limitations to fossil fuel-fired EGUs that may be subject to the proposed emission guidelines.
State Plan Components and Submission
This section describes the proposed requirements for the contents of state plans, the proposed timing of state plan submissions, and the EPA's review of and action on state plan submissions. This section also discusses issues related to the applicability of a Federal plan and timing for the promulgation of a Federal plan.
As explained earlier in this preamble, the requirements of 40 CFR part 60, subpart Ba, govern state plan submissions under these emission guidelines. Where the EPA is proposing to add to, supersede, or otherwise vary the requirements of subpart Ba for the purposes of state plan submissions under these particular emission guidelines, those proposals are addressed explicitly in section XI.F.1.b on specific state plan requirements and throughout this preamble. Unless expressly amended or superseded in these proposed emission guidelines, the provisions of subpart Ba would apply.
Components of a State Plan Submission
The EPA is proposing that a state plan must include a number of discrete components. These proposed plan components include those that apply for all state plans pursuant to 40 CFR part 60, subpart Ba. In addition, the EPA is proposing that other plan components would apply under these emission guidelines based on the type of plan submitted. For example, these required plan components may relate to the specific types of standards of performance for affected EGUs that are adopted by a state and incorporated into their state plan.
General Components
The CAA section 111 implementing regulations provide separate lists of administrative and technical criteria that must be met in order for a state plan submission to be deemed complete. The EPA's proposed revisions to subpart Ba would add one item to the list of administrative criteria related to meaningful engagement. If finalized, the applicable administrative completeness criteria for state plan submissions are: (1) A formal letter of submittal from the Governor or the Governor's designee requesting EPA approval of the plan or revision thereof; (2) Evidence that the state has adopted the plan in the state code or body of regulations; or issued the permit, order, or consent agreement (hereafter "document") in final form. That evidence must include the date of adoption or final issuance as well as the effective date of the plan, if different from the adoption/issuance date; (3) Evidence that the state has the necessary legal authority under state law to adopt and implement the plan; (4) A copy of the official state regulation(s) or document(s) submitted for approval and incorporated by reference into the plan, signed, stamped, and dated by the appropriate state official indicating that they are fully adopted and enforceable by the state. The effective date of the regulation or document must, whenever possible, be indicated in the document itself. The state's electronic copy must be an exact duplicate of the hard copy. For revisions to the approved plan, the submission must indicate the changes made to the approved plan by redline/strikethrough; (5) Evidence that the state followed all applicable procedural requirements of the state's regulations, laws, and constitution in conducting and completing the adoption/issuance of the plan; (6) Evidence that public notice was given of the plan or plan revisions with procedures consistent with the requirements of 40 CFR 60.23, including the date of publication of such notice; (7) Certification that public hearing(s) were held in accordance with the information provided in the public notice and the state's laws and constitution, if applicable and consistent with the public hearing requirements in 40 CFR 60.23; (8) Compilation of public comments and the state's response thereto; and (9) Evidence of meaningful engagement, including a list of pertinent stakeholders, a summary of the engagement conducted, and a summary of stakeholder input received.
The technical criteria required for all plans must include each of the following: (1) Description of the plan approach and geographic scope; (2) Identification of each designated facility (i.e., affected EGU); identification of standards of performance for each affected EGU; and monitoring, recordkeeping, and reporting requirements that will determine compliance by each designated facility; (3) Identification of compliance schedules and/or increments of progress; (4) Demonstration that the state plan submission is projected to achieve emission performance under the applicable emission guidelines; (5) Documentation of state recordkeeping and reporting requirements to determine the performance of the plan as a whole; and (6) Demonstration that each emission standard is quantifiable, permanent, verifiable, and enforceable.
Specific State Plan Requirements
Consistent with the requirements in subpart Ba, the EPA is proposing in the regulatory text that applies for these emission guidelines specific requirements that demonstrate that standards of performance for affected EGUs included in a state plan are quantifiable, verifiable, permanent, and enforceable. Consistent with CAA section 302(k), emission standards or limitations must be continuous in nature. This includes requirements that apply for all affected EGUs subject to a standard of performance under a state plan pursuant to these proposed emission guidelines, as well as requirements that apply for affected EGUs within a specific subcategory. These proposed requirements include:
       Identification of affected EGUs;
       Identification of standards of performance for each affected EGU in lb CO2/MWh-gross basis over an extended period of time (e.g., an annual calendar year), including provisions for implementation and enforcement of such standards;
       Enforceable increments of progress and milestones, as required for affected EGUs within a specific subcategory, included as enforceable elements of a state plan; and
       Identification of applicable monitoring, reporting, and recordkeeping requirements for affected EGUs.
The proposed emission guidelines include requirements pertaining to the methodologies states must use for establishing a presumptively approvable standard of performance for an affected EGU within a respective subcategory. These proposed methodologies are specified for each of the subcategories for affected EGUs.
The EPA notes that standards of performance for affected EGUs in a state plan must be representative of the level of emission performance that results from the application of the BSER in these emission guidelines. As discussed in section XI.C of this preamble, in order for the EPA to find a state plan "satisfactory," that plan must achieve the level of emission performance that would result if each affected source was achieving its presumptive standard of performance, after accounting for any application of RULOF. That is, while states have the discretion to establish the applicable standards of performance for affected sources in their state plans, the structure and purpose of CAA section 111 require that those plans achieve an equivalent level of emission performance as applying the EPA's presumptive standards of performance to those sources (again, after accounting for any application of RULOF).
The proposed emission guidelines also include requirements that apply to states when they invoke RULOF in applying a less stringent standard of performance for an affected EGU than result from the proposed methodology for establishing a presumptively approvable standard of performance. Such requirements include a demonstration by the state of why an affected EGU for which the state invokes RULOF cannot reasonably apply the BSER. The state must also demonstrate where and how it considered communities that may be affected by the establishment of a less stringent standard of performance for the identified affected EGU. This demonstration must include an identification of the affected communities, how the state considered the potential overall impact on the identified communities, a summary of feedback from meaningful engagement with the identified communities, and a demonstration of how the state considered the health and environmental impacts to the identified communities that would result from the establishment of a source-specific BSER for the identified affected EGU for which the state is invoking RULOF.
In addition to meaningful engagement with affected communities in the context of invoking RULOF, the proposed revisions to the CAA section 111 subpart Ba implementing regulations include requirements for public engagement on state plan development to ensure that communities most affected by and vulnerable to the health and environmental impacts of a plan will share in the benefits of the plan and are protected from being adversely impacted. These proposed requirements are in addition to the existing public notice requirements under subpart Ba and, if finalized, would apply to state plan development in the context of these emission guidelines. While the existing state plan development process provides opportunities for stakeholder input through notice and public hearing, the proposed revisions addressing meaningful engagement are designed to go further to ensure that such community concerns are heard in a more robust way than in the past and at critical junctures in the state plan development process, with state plan approval at stake.
The fundamental purpose of CAA section 111 is to reduce emissions from categories of stationary sources that cause, or significantly contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, a key consideration in the state's development of a state plan is the potential impact of the proposed plan requirements on public health and welfare. A robust and meaningful engagement process is critical to ensuring that the full range of health and environmental impacts of a proposed plan are understood and considered in the state plan development process.
In the subpart Ba revisions of December 2022, the EPA proposed to define meaningful engagement as:
      [T]timely engagement with pertinent stakeholder representation in the plan development or plan revision process. Such engagement must not be disproportionate in favor of certain stakeholders. It must include the development of public participation strategies to overcome linguistic, cultural, institutional, geographic, and other barriers to participation to assure pertinent stakeholder representation, recognizing that diverse constituencies may be present within any particular stakeholder community. It must include early outreach, sharing information, and soliciting input on the state plan.

The EPA proposed to define that pertinent stakeholders "include but are not limited to, industry, small businesses, and communities most affected by and/or vulnerable to the impacts of the plan or plan revision." The preamble to the proposed revisions to subpart Ba notes that "increased vulnerability of communities may be attributable, among other reasons, to both an accumulation of negative and lack of positive environmental, health, economic, or social conditions within these populations or communities."
In the context of these emission guidelines, the air pollutant of concern is greenhouse gases and the air pollution is elevated concentrations of these gases in the atmosphere, which result in warming temperatures and other changes to the climate system that are leading to serious and life-threatening environmental and human health impacts. These impacts can have a disproportionate impact on communities and populations depending on, inter alia, accumulation of negative and lack of positive environmental, health, economic, or social conditions. The Agency therefore expects states' pertinent stakeholders to include not only owners and operators of affected EGUs but also communities vulnerable to the impacts of climate change, including those exposed to more extreme drought, flooding, and other severe weather impacts, including extreme heat and cold (states should refer to section III of this preamble, on climate impacts, to assist them in identifying their pertinent stakeholders). It is important for states to recognize and engage these communities, particularly as these communities may not have had a voice when the affected EGUs were originally constructed. Pertinent stakeholders should be able to provide input on how affected EGUs in their state comply with these emission guidelines. Providing input in this context means allowing communities to comment on the overall comprehensive compliance plan for all affected EGUs in a state, in contrast to permitting and other actions that focus on particular affected EGUs. Because these emission guidelines address air pollution that becomes well mixed and is long-lived in the atmosphere, pertinent stakeholders may include communities and populations that will be most affected by the overall stringency of state plans. (Note that the EPA addresses meaningful engagement in the context of RULOF for these emission guidelines in section XI.D.2.c of this preamble.)
In engaging with stakeholders in the development of these proposed emission guidelines, the EPA has heard concerns expressed over the use of CCS technology, including concerns related to the potential for steam generating units to prolong their lifespans through its use. While the EPA endeavored to address those concerns in part by basing the BSER on CCS only for those units that intend to operate in the long-term,the EPA is proposing to require that, if states are considering assigning affected EGUs to the long-term subcategory, the state must explicitly include CCS as part of meaningful engagement to ensure that concerns regarding CCS in particular can be voiced and heard through meaningful engagement. States would be required to demonstrate that they have designed meaningful engagement to elicit input from pertinent stakeholders on issues related to CCS. While the existing state plan development process provides opportunities for stakeholder input through notice and public hearing, the proposed revisions addressing meaningful engagement are designed to go further to ensure that such community concerns are heard in a more robust way than in the past and at critical junctures in the state plan development process, with state plan approval at stake.
If the revisions to subpart Ba are finalized as proposed, states would need to demonstrate in their state plans how they provided meaningful engagement with the pertinent stakeholders. This includes providing a list of the pertinent stakeholders, a summary of engagement conducted, and a summary of the stakeholder input provided. As previously noted, the state must allow for balanced participation, including communities most vulnerable to the impacts of the plan. States must consider the best way to reach affected communities, which may include but should not be limited to notification through the Internet. Other channels may include notice through newspapers, libraries, schools, hospitals, travel centers, community centers, places of worship, gas stations, convenience stores, casinos, smoke shops, Tribal Assistance for Needy Families offices, Indian Health Services, clinics, and/or other community health and social services as appropriate. The state should also consider any geographic, linguistic, or other barriers to participation in meaningful engagement for members of the public. If a state plan submission does not meet the required elements for notice and opportunity for public participation, including requirements for meaningful engagement, this may be grounds for the EPA to find the submission incomplete or to disapprove the plan. As discussed in section XI.F.2 of this preamble, the EPA is proposing an extension of the state plan submission timeline from 15 months to 24 months, which should allow states adequate time to conduct meaningful engagement.
The EPA is requesting comment on its proposal that CCS be a required part of meaningful engagement, as well as on whether there are any other specific technologies or aspects of state plan development around which the EPA should provide requirements for meaningful engagement. The EPA is also requesting comment on what assistance states and pertinent stakeholders may need in conducting meaningful engagement in the EGU context, including tools and methodologies for identifying communities that are most affected by and vulnerable to emissions from affected EGUs under these emission guidelines.
Specific State Plan Requirements for Transparency and Compliance Assurance
The EPA is proposing or requesting comment on several requirements designed to help states ensure compliance by affected EGUs with standards of performance, as well as to assist the public in tracking increments of progress toward the final compliance date.
First, the EPA is requesting comment on whether to require that an affected EGU's enforceable commitment to permanently cease operations, when that commitment is relied on for subcategory applicability (e.g., an affected coal-fired steam-generating unit intends to rely on a committed date to permanently cease operations by December 31, 2034, to meet the applicability requirements for the near-term subcategory), must be in the form of an emission limit of 0 lb CO2/MWh that applies on that date. Such an emission limit would be included in a state regulation, permit, order, or other acceptable legal instrument and submitted to the EPA as part of a state plan. If approved, the affected EGU would have a federally enforceable emission limit of 0 lb CO2/MWh that would become effective as of the date that the EGU permanently ceases operations. The EPA is requesting comment on whether such an emission limit would have any advantages or disadvantages for compliance and enforceability relative to a federally enforceable commitment to cease operation by a date certain.
Second, the EPA is proposing that state plans that cover affected EGUs within any subcategory that is based on the date by which a source chooses to permanently cease operations(i.e., imminent-term, near-term, medium-term) must include, in conjunction with an enforceable date, the requirement that each source comply with applicable state and federal requirements for permanently ceasing operation of the EGU, including removal from its respective state's air emissions inventory and amending or revoking all applicable permits to reflect the permanent shutdown status of the EGU.
Third, the EPA is proposing that each state plan must provide for the establishment of publicly accessible websites by the owners or operators of affected EGUs, referred to here as a "CAA Section 111(d) EGU Rule Website," to which all reporting and recordkeeping information for each affected EGU subject to the state plan would be posted. Although this information will also be required to be submitted directly to the EPA and the relevant state regulatory authority, the EPA is interested in ensuring that the information is made accessible in a timely manner to all pertinent stakeholders. The EPA anticipates that the owners or operators of affected EGUs may already be posting comparable reporting and recordkeeping information to publicly available websites under the EPA's April 2015 Coal Combustion Residuals Rule such that the burden of this additional website requirement could be minimal.
In particular, the EPA is proposing that the owners or operators of affected EGUs would be required to post their subcategory designations and compliance schedules, including for increments of progress and milestones, leading up to full compliance with the applicable standards of performance. Owners/operators would also be required to post any information or documentation needed to demonstrate that an increment of progress or milestone has been achieved. Similarly, the EPA is proposing that emissions data and other information needed to demonstrate compliance with a standard of performance would also be required to be posted to the CAA Section 111(d) EGU Rule Website for an affected EGU in a timely manner. The EPA is proposing that all information required to be made publicly available on the CAA Section 111(d) EGU Rule Website be posted within 30 business days of the information becoming available to or reported by the owner/operator of an affected EGU. Information would have to be retained on the website for a minimum of 10 years. The EPA solicits comment on these timeframes for posting and information retention, as well as on any concerns related to confidential business information.
The EPA proposes that owners/operators of affected EGUs that are also subject to similar website reporting requirements for the Coal Combustion Residuals Rule may use an already established website to satisfy its CAA Section 111(d) EGU Rule Website requirements. The EPA solicits comment on other ways to reduce redundancy and burden while satisfying the objective of making it easier for pertinent stakeholders to access affected EGUs' reporting and recordkeeping information.
Fourth, to promote transparency and to assist the EPA and the public in assessing increments of progress under a state plan, the EPA is proposing that state plans must include a requirement that each affected coal-fired EGU must report any deviation from any federally enforceable state plan increment of progress or milestone within 30 business days after the owner or operator of the affected EGU knew or should have known of the event. In the report, the owner or operator of the affected EGU would be required to explain the cause or causes of the deviation and describe all measures taken or to be taken by the owner or operator of the EGU to cure the reported deviation and to prevent such deviations in the future, including the timeframes in which the owner or operator intends to cure the deviation. The owner or operator of the EGU must submit the report to the state regulatory agency and post the report to the affected EGU's CAA Section 111(d) EGU Rule Website.
Fifth, to aid all affected parties and stakeholders in implementing these emission guidelines, the EPA is explaining its intended approach to exercising its enforcement authorities to ensure compliance while addressing genuine risks to electric system reliability. The EPA has designed these proposed emission guidelines to accommodate the transitions that are currently occurring in the electric power sector, including through the structure of subcategories and provision of relatively long planning and compliance timeframes. The Agency therefore does not anticipate that either the need for certain coal-fired steam generating units to install controls or affected EGUs' preexisting decisions to permanently cease operations will result in resource constraints that would adversely affect electric reliability.
Nonetheless, the EPA acknowledges that there may be isolated instances in which unanticipated factors beyond an owner/operator's control, and ability to predict and plan for, could have an adverse, localized impact on electric reliability. In such instances, affected EGUs could find themselves in the position of either operating in noncompliance with approved, federally enforceable state plan requirements or halting operations and thereby potentially impacting electric reliability.
CAA section 113 authorizes the EPA to bring enforcement actions against sources in violation of CAA requirements, seeking injunctive relief, civil penalties and, in certain circumstances, other appropriate relief. The EPA also has the discretion to agree to negotiated resolutions, including administrative compliance orders ("ACOs") for achieving compliance with CAA requirements, that include expeditious compliance schedules with enforceable compliance milestones. The EPA does not generally speak to the intended scope of its enforcement efforts, particularly in advance of a violation's actually occurring. However, the EPA is explaining its intended approach to ACOs here to provide confidence both with respect to electric reliability and that emission reductions under these emission guidelines will occur as required under CAA section 111(d).
The EPA would evaluate each request for an ACO for an affected EGU that is required to run in violation of a state plan requirement for reliability purposes on a case-by-case basis. However, as a general matter, the EPA anticipates that to qualify for an ACO, the owner/operator would need to demonstrate, as a minimum, that the following conditions have been satisfied:
The owner/operator of the affected EGU requesting an ACO has requested, in writing and in a timely manner, an enforceable compliance schedule in an ACO.
The owner/operator of the affected EGU requesting an ACO has provided the EPA written analysis and documentation of reliability risk if the unit were not in operation, which demonstrates that operation of the unit in noncompliance is critical to maintaining electric reliability and that failure to operate the unit would result in violation of the reliability criteria required to be filed with FERC and, in the case of the Electric Reliability Council of Texas, with the Texas PUC, or cause reserves to fall below the required system reserve margin.
The owner/operator of the affected EGU requesting an ACO has provided the EPA with written concurrence with the reliability analysis from the relevant electric planning authority for the area in which the affected EGU is located.
The owner/operator of the affected EGU requesting an ACO has demonstrated that the need to continue operating for reliability purposes is due to factors beyond the control of the owner/operator and that the owner/operator of the affected EGU has not contributed to the purported need for an ACO.
The owner/operator of the affected EGU requesting an ACO demonstrates that it has met all applicable increments of progress and milestones in the state plan.
It can be demonstrated that there is insufficient time to address the reliability risk and potential noncompliance through a state plan revision.
If deemed appropriate to do so, the EPA would issue an ACO that includes a compliance schedule and milestones to achieve compliance as expeditiously as practicable. The ACO would also include any operational limits, including limits on utilization reflecting the extent to which the unit is needed for grid reliability, and/or work practices necessary to minimize or mitigate any emissions to the maximum extent practicable during any operation of the affected EGU before it has achieved full compliance. The EPA reiterates that it would not be appropriate to request an ACO to address reliability risk and anticipated noncompliance in circumstances in which a state plan revision is possible.
The EPA requests comment on whether to promulgate requirements in the final emission guidelines pertaining to the demonstrations, analysis, and information the owner/operator of an affected EGU would have to submit to the EPA in order to be considered for an ACO.
Timing of State Plan Submissions
The EPA's proposed subpart Ba revisions would require states to submit state plans within 15 months after publication of the final emission guidelines. For the purpose of these particular emission guidelines, the EPA is proposing to supersede that timeline and is proposing a state plan submission deadline that is 24 months from the date of publication of the final emission guidelines. The EPA is superseding the proposed subpart Ba 15-month plan development and submission deadline for three reasons. First, these proposed emission guidelines apply to a complex and evolving source category. Making the decisions necessary for state plan development will require significant analysis, consultation, and coordination between states, utilities, ISOs or RTOs, and the owners or operators of individual affected EGUs. The power sector is subject to many layers of regulatory and other requirements under many authorities, and the decisions states make under these emission guidelines will necessarily have to accommodate many overlapping considerations and processes. States' plan development may be additionally complicated by the fact that, unlike some other source sectors to which the general CAA section 111 implementing regulations apply, decision-making regarding control strategies and operations for affected EGUs may not be solely within the purview of the owners or operators of those sources; at the very least, affected EGUs often must obtain permission before making significant or permanent changes. The EPA does not believe it is reasonable to expect states and affected EGUs to undertake the coordination and planning necessary to ensure that their plans for implementing these emission guidelines are consistent with the broader needs and trajectory of the power sector in the space of 15 months.
Second, and relatedly, the EPA believes that states and utilities need time to determine which subcategory and corresponding BSER is applicable for each affected EGU. Again, unlike some other source categories to which the CAA section 111 implementing regulations apply, the applicable subcategory for an affected EGU would depend on operational characteristics that are within the control of the EGU's owner/operator, subject to input from and requirements of ISO and RTOs and other authorities. Because an affected EGU may choose to change its operation in light of these emission guidelines, the process of determining the appropriate subcategory for each affected EGU is more complex than that for other source sectors to which subpart Ba applies. For any coal-fired EGU that chooses to permanently cease operations prior to 2040, the EPA anticipates that the owner or operator will be required to coordinate a date to cease operations with the corresponding RTO or ISO or other balancing authority to ensure proper retirement sequences and reliability. While the EPA expects that a number of affected EGUs already intend to cease operations at some point prior to 2040, under these emission guidelines states would require owners or operators to commit to an enforceable date to permanently cease operations for those EGUs. RTOs or ISOs or other balancing authorities will have to analyze potential impacts on the power sector and make decisions regarding these intended dates to permanently cease operations for the affected EGUs that are interested in committing to an enforceable date by which to permanently cease operations within a state plan submission. The EPA reiterates that, due to the rapid transition currently occurring in the power sector and due to the marginal nature of many affected EGUs, such changes in operation would be expected regardless of the particular requirements of these emission guidelines.
Third, prior to an owner or operator providing a suggestion for a subcategory and standard of performance for an affected EGU to a state, that owner or operator will likely need to analyze the potential feasibility of applying the applicable BSER for the subcategory. The EPA anticipates that EGUs that intend on operating beyond 2040 will do feasibility and FEED studies to ensure that CCS is appropriate prior to committing to that subcategory in a state plan. As discussed in section XI.B of this preamble and in the GHG Mitigation Measures  -  111(d) TSD, FEED studies take approximately 12 months to complete, after which additional time is necessary to allow the conclusions from that study to be integrated into a state's planning process for certain affected EGUs. For sources that intend to permanently cease operations before January 1, 2040, and that do not qualify for the imminent- or near-term subcategories, there are also planning, design, and permitting exercises that will be necessary for utilities to undertake prior to committing to a subcategory based on natural gas co-firing. While any boiler modifications required for affected EGUs that intend to co-fire natural gas are relatively straightforward, the owners/operators of EGUs in the medium-term subcategory may also be required to construct new pipelines to enable co-firing of 40 percent natural gas. Pipeline projects also require an initial planning and design process to determine feasibility and, in some cases, could involve FERC approval. Again, it may take 12 or more months for the owner/operator of an affected EGU to ascertain the feasibility of committing to the medium-term subcategory and to natural gas co-firing. Based on the approximately 12-month period that states and the owners/operators of affected EGUs will likely take to determine the feasibility of BSER control strategies for the long-term and medium-term subcategories, the EPA does not believe it is reasonable to require state plans to be submitted 15 months after promulgation of these emission guidelines.
In the proposed subpart Ba timelines for state plan submission, the EPA justified the generally applicable timelines in the context of public health and welfare impacts by proposing timelines that are as quick as is reasonably feasible for a generic set of emission guidelines under CAA section 111(d). The EPA is proposing 24 months for state plan timelines for these emission guidelines because 24 months is the quickest time that the EPA believes to be reasonably feasible for a state to submit a state plan based on the work and evaluation needed to establish the viability of CCS and co-firing at a given coal-fired EGU. Additionally, the EPA does not believe providing a longer timeline for the submission of state plans would ultimately impact how quickly the affected EGUs can comply with their standards of performance. As explained in section XI.B of this preamble and in the GHG Mitigation Measures  -  111(d) TSD, the EPA anticipates that CCS projects will take roughly 5 years to complete, assuming some steps are undertaken concurrently. If the EPA were to promulgate these emission guidelines in June 2024 and require state plan submissions in September 2025, the EPA anticipates that the soonest compliance could commence is in the third quarter of 2029. However, in this case, it is likely that at least some owners/operators of affected EGUs would have to commit to subcategories or control technologies before completing feasibility and FEED studies, which could result in the need for plan revisions and delayed emission reductions. In contrast, providing 24 months for state plan submission would mean that although plans would be due June 2026, owners/operators of affected EGUs would have had time to complete their feasibility and FEED studies and some initial planning steps before then. The EPA anticipates that owners/operators would need approximately another 3.5 years to reach full compliance, meaning that emission reductions would commence in the first quarter of 2030. The EPA does not believe that a difference of three months will adversely impact public health or welfare, especially when it is considered that providing more time for state plan development in this instance is more likely to ultimately result in certainty and timely emission reductions.
The EPA solicits comment on the 24-month state planning period. The EPA specifically requests comments from owners/operators of affected EGUs regarding the steps, and amount of time needed for each step, that they would have to undertake to determine the applicable subcategories and to plan and implement the associated control strategies for each of their affected EGUs. Additionally, the EPA requests comment on the 24-month planning period from states, including on any unique characteristics of the fossil fuel-fired EGU source category that they believe merit planning timeframes longer than 15 months. Through outreach, many states have expressed a need for longer planning periods and the EPA solicits comment on whether this 24-month planning period accommodates that need. The EPA also requests comment from potentially impacted communities and other pertinent stakeholders on any considerations related to providing a longer state plan submission timeframe under these emission guidelines.
State Plan Revisions
The EPA expects that the state plan submission deadline proposed under these emission guidelines would give states, utilities, and stakeholders sufficient time to determine in which subcategory each of the affected EGUs falls and to formulate and submit a state plan accordingly. However, the EPA also acknowledges that the power sector is rapidly evolving and that, despite states' best efforts to accurately reflect their utilities' intended paths forward at the time of plan submission, affected EGUs' plans may subsequently change. In general, states have the authority and discretion to submit revised state plans to the EPA for approval. State plan revisions are generally subject to the same requirements as initial state plans under these emission guidelines and the subpart Ba implementation regulations, including meaningful engagement, and the EPA reviews state plan revisions against the applicable requirements of these emission guidelines in the same manner in which it reviews initial state plan submissions pursuant to 40 CFR 60.27a.
Approved state plan requirements remain federally enforceable unless and until the EPA approves a plan revision that supersedes such requirements. States and affected EGUs should plan accordingly to avoid noncompliance.
The EPA is proposing a state plan submission date that is 24 months after the publication of final emission guidelines and is proposing a compliance date of January 1, 2030. A state may choose to submit a plan revision within this period (i.e., after it has submitted its initial state plan under these emission guidelines); however, the EPA reiterates that any already approved federally enforceable requirements, including milestones, increments of progress, and standards of performance, will remain in place unless and until the EPA approves the plan revision. The EPA requests comment on whether it would be helpful to states to impose a cut-off date for the submission of plan revisions ahead of the January 1, 2030, compliance date. Such a cut-off date, e.g., January 1, 2028, would in effect establish a temporary moratorium on plan submissions in order to provide a sufficient window for the EPA to act on them ahead of the final compliance date. State plan revisions would again be permitted after the final compliance date. As an alternative to a cut-off date for state plan revisions ahead of the compliance date, the EPA requests comment on the dual-path standards of performance approach discussed in section XI.F.4 of this preamble.
Under these proposed emission guidelines, states would place their affected coal-fired EGUs into one of four subcategories based on the time horizons over which those EGUs intend to operate. These subcategories are static -- affected EGUs would not be able move between subcategories absent a plan revision. However, the EPA acknowledges that there may be instances in which a change in subcategory will be necessary. For affected coal-fired EGUs that are switching into the imminent-term, near-term, or medium-term subcategories, the EPA proposes to require that the state include in its state plan submission documentation of the affected EGU's submission to the relevant RTO or balancing authority of the new date it intends to permanently cease operations, any responses from and studies conducted by the RTO or balancing authority addressing reliability and any other considerations related to ceasing operations, any filings with the SEC or notices to investors in which the plans for the EGU are mentioned, any integrated resource plan, and any other relevant information in support of the new date. This documentation must be published on the CAA Section 111(d) EGU Rule Website. These proposed requirements are modeled on the proposed milestones for sources committing to permanently ceasing operations and are intended to help states, stakeholders, and the EPA ensure that the affected EGU's change in circumstances is sufficiently certain to warrant a state plan revision. Because of the long lead times for planning and implementation of control systems for affected EGUs, revising a state plan after the submission deadline has the potential to significantly disrupt states' and affected EGUs' compliance strategies. The EPA therefore believes it is reasonable to require affected EGUs and states to provide evidence that a source's circumstances have in fact changed, in order for the EPA to approve a plan revision. Affected EGUs switching into the imminent-term, near-term, or medium-term subcategories would also be required to comply with the proposed enforceable milestones applicable to those subcategories.
Some changes between subcategories, including from the long-term into the medium-term subcategory and from the imminent-term or near-term into the medium-term or long-term subcategory, would entail new standards of performance reflecting a different add-on control strategy than initially anticipated. In order to avoid undermining the stringency of these proposed emission guidelines, the EPA expects affected EGUs changing subcategories before the January 1, 2030, compliance deadline to make every reasonable effort to meet that compliance deadline. However, the EPA acknowledges that, in some circumstances, it may not be possible to complete the necessary planning and construction within a shortened timeframe. Additionally, unforeseen circumstances could require some affected EGUs to change subcategories after the final compliance deadline has passed (e.g., to ensure reliability).
In these circumstances, the EPA is proposing that states may use the RULOF mechanism described in section XI.D.2 of this preamble to adjust the compliance deadlines for affected EGUs that cannot comply with their applicable standards of performance by the January 1, 2030, deadline. The EPA expects that states may be able to demonstrate that the change in subcategory constitutes an "other circumstance[] specific to the facility . . . that [is] fundamentally different from the information considered in the determination of the best system of emission reduction in the emission guidelines." In order to invoke RULOF to change a compliance deadline for an affected EGU that has switched subcategories, the EPA proposes that the state must first demonstrate that the affected EGU cannot meet the applicable presumptive standard of performance by the compliance deadline in these emission guidelines. As part of this demonstration the state would be required to provide evidence supporting the affected EGU's need to switch subcategories. The state would also be required to demonstrate that the need to invoke RULOF and to provide a different compliance deadline or less stringent standard of performance was not caused by self-created impossibility. Documentation related to these demonstrations must also be posted to the CAA Section 111(d) EGU Rule Website. For example, it would not be reasonable for a state that has been notified that an RTO requires an affected EGU to switch subcategories to wait to revise its SIP until the remaining useful life of that EGU is so short as to preclude otherwise reasonable systems of emission reduction. To this end, the EPA is proposing to consider when a state knew or should have known that an affected EGU would need to switch subcategories when evaluating the approvability of state plans that include RULOF demonstrations. The EPA is additionally proposing to consider whether an affected EGU has been complying with its applicable milestones and increments of progress when evaluating RULOF demonstrations. The EPA encourages states to consult with their EPA Regional Offices as early as possible if they believe it may become necessary for an affected EGU to switch subcategories. The EPA requests comment on whether to set a deadline for states to provide plan revisions within a certain timeframe of knowing that an affected EGU needs to switch subcategories and on what timeframe would be appropriate.
The EPA is proposing that states invoking RULOF because an affected EGU cannot comply with its newly applicable presumptive standard of performance by the final compliance deadline first evaluate whether the affected EGU is able to comply with that standard by a different, later-in-time deadline. If a state can demonstrate that an affected EGU cannot reasonably comply with the applicable presumptive standard of performance under any reasonable compliance deadline, it may then evaluate different systems of emission reduction according to the proposed RULOF mechanism described in section XI.D.2 of this preamble.
Dual-Path Standards of Performance for Affected Coal-Fired Steam Generating Units
Under the structure of these emission guidelines as proposed, states would assign affected coal-fired EGUs to subcategories in their state plans and an EGU would not be able to change its applicable subcategory without a state plan revision. This is because, due to the nature of the BSERs for coal-fired EGUs, an EGU that switches between subcategories may not be able to meet compliance obligations for a new and different subcategory without considerable lag time and thus the switch would result in noncompliance and a loss of emission reductions. Therefore, as a general matter, states must assign each affected EGU to a subcategory and have in place all the measures necessary to implement the requirements for that subcategory by the time of state plan submission.
However, the EPA acknowledges that there may be circumstances in which a coal-fired EGU wishes to retain the option to choose between two different subcategories ahead of the proposed January 1, 2030, compliance date. The EPA is therefore soliciting comment on the following dual-path approach that may result in an additional flexibility for owners/operators of affected coal-fired EGUs that want additional time to commit to a particular subcategory without the need for a state plan revision.
The EPA is soliciting comment on an approach that allows coal-fired EGUs to have two different standards of performance submitted to the EPA in a state plan based on potential inclusion in two different subcategories. A state plan would be required to have all the associated components for each subcategory. For example, for an affected EGU that wants the option to be part of either the long-term or imminent-term subcategory, the state plan would include a standard of performance based on implementation of CCS and associated requirements, including increments of progress; as well as an enforceable requirement to permanently cease operations before January 1, 2033, and a standard of performance based on routine operation and maintenance. The affected EGU would be required to meet all compliance obligations for both subcategories, including increments of progress and/or milestones for federally enforceable commitments to cease operations, leading up to the compliance date of January 1, 2030. The state and affected EGU would be required to choose a subcategory for the affected EGU ahead of that date. Specifically, the EPA is proposing that the state must notify the EPA of its final applicable subcategory and standard of performance at least 6 months prior to the compliance date (i.e., the state would have to notify the EPA of the applicable standard by July 1, 2029). If the state has not notified the EPA by July 1, 2029, of the final applicable subcategory for the affected EGU, the EPA is proposing that that EGU would automatically be subject to the requirements of the subcategory that corresponds to the longer remaining life of the EGU. Additionally, if the affected EGU misses an enforceable increment of progress, milestone (as described in section XI.D.3 of this preamble), or any other requirement for one of the two subcategories, the EGU will automatically be subject to the requirements of the other subcategory. If the EGU misses submissions for increments of progress/milestones for both subcategories, the EGU will automatically be subject to the requirements of the subcategory that corresponds to the longer remaining life of the EGU and will additionally be found to be out of compliance for the increment of progress or milestone that it has missed.
The EPA is soliciting comment on this approach to provide flexibility to states and affected EGUs. In some instances, owners of affected EGUs may wish to have additional time to decide on a control strategy; this proposed dual-path approach should provide utilities an additional 3 years to commit to a subcategory. However, with this additional time comes additional burden on owners and operators to demonstrate compliance with each of the requirements associated with two different subcategories that would be included in a state plan. As an example, a coal-fired EGU intends to cease operations between 2038 and 2041. The state plan is submitted and contains two different enforceable dates to permanently cease operations, e.g., December 31, 2038, with a standard of performance based on natural gas co-firing and December 31, 2041, with a standard of performance based on CCS, as well as an enforceable commitment by the state to choose one path or the other by July 1, 2029. The affected EGU would then be required to comply with the increments of progress for both the long-term (CCS) and medium-term (co-firing) subcategories, until the point at which the state decides which of the two paths in its plan it will require for the unit.
The EPA solicits comment on whether this proposed dual-path flexibility would have utility and on whether it could be implemented in a manner that ensures that states and affected coal-fired EGUs would be able to comply with applicable requirements in a timely manner. Additionally, the EPA solicits comment on whether July 1, 2029, is the appropriate date for a final decision between the two potential standards of performance and why.
EPA Action on State Plans
Pursuant to proposed subpart Ba, the EPA would use a 60-day timeline for the Administrator's determination of completeness of a state plan submission and a 12-month timeline for action on state plans. The EPA's review of and action on state plan submissions would be governed by the requirements of revised subpart Ba. First, the EPA would review the components of the state plan to determine whether the plan meets the completeness criteria of 40 CFR 60.27a(g). The EPA must determine whether a state plan submission has met the completeness criteria within 60 days of its receipt of that submission. If the EPA has failed to make a completeness determination for a state plan submission within 60 days of receipt, the submission shall be deemed, by operation of law, complete as of that date.
Proposed subpart Ba would require the EPA to take action on a state plan submission within 12 months of that submission's being deemed complete. The EPA will review the components of state plan submissions against the applicable requirements of subpart Ba and these emission guidelines, consistent with the underlying requirement that state plans must be "satisfactory" per CAA section 111(d). If the EPA finalizes the revisions to subpart Ba as proposed, the Administrator would have the option to fully approve, fully disapprove, partially approve, partially disapprove, and conditionally approve a state plan submission. Any components of a state plan submission that the EPA approves become federally enforceable.
The EPA requests comment on the use of the timeframes provided in subpart Ba, as the EPA has proposed to revise it, for EPA actions on state plan submissions and for the promulgation of Federal plans for these particular emission guidelines.
Federal Plan Applicability and Promulgation Timing
The provisions of subpart Ba, including any revisions the EPA finalizes pursuant to its December 2022 proposal, will apply to the EPA's promulgation of any Federal plans under these emission guidelines. The EPA's obligation to promulgate a Federal plan is triggered in three situations: where a state does not submit a plan by the plan submission deadline; where the EPA determines that a state plan submission does not meet the completeness criteria and the time period for state plan submission has elapsed; and where the EPA fully or partially disapproves a state's plan. Where a state has failed to submit a plan by the submission deadline, the EPA has 12 months from the state plan submission due date to promulgate a Federal plan; otherwise, the 12-month period starts from the date the state plan submission is deemed incomplete, whether in whole or in part, or from the date of the EPA's disapproval. The EPA may approve a state plan submission that corrects the relevant deficiency within the 12-month period, before it promulgates a Federal plan, in which case its obligation to promulgate a Federal plan is relieved. As provided by 40 CFR 60.27a(e), a Federal plan will prescribe standards of performance for affected EGUs of the same stringency as required by these emission guidelines and will require compliance with such standards as expeditiously as practicable but no later than the final compliance date under these guidelines. However, upon application by the owner or operator of an affected EGU, the EPA in its discretion may provide for a less stringent standard of performance or longer compliance schedule than provided by these emission guidelines, in which case the EPA would follow the same process and criteria in the regulations that apply to states' provision of RULOF standards. Under the proposed revisions to subpart Ba, the EPA would also be required to conduct meaningful engagement with pertinent stakeholders prior to promulgating a Federal plan.
As described in section XI.F.2 of this preamble, the EPA is proposing to allow states 24 months for a state plan submission after the promulgation of the final emission guidelines. Therefore, the EPA would be obligated to promulgate a Federal plan for all states that fail to submit plans within 36 months of the final emission guidelines. Note that this will be the earliest obligation for the EPA to promulgate Federal plans for states and that different triggers (e.g., a disapproved state plan) will result in later obligations to promulgate Federal plans contingent on when the obligation is triggered.
Under the Tribal Authority Rule (TAR) adopted by the EPA, tribes may seek authority to implement a plan under CAA section 111(d) in a manner similar to that of a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to that of a state for purposes of developing a Tribal Implementation Plan (TIP) implementing the emission guidelines. If a tribe obtains approval and submits a TIP, the EPA will generally use similar criteria and follow similar procedures as those described for state plans when evaluating the TIP submission and will approve the TIP if appropriate. The EPA is committed to working with eligible tribes to help them seek authorization and develop plans if they choose. Tribes that choose to develop plans will generally have the same flexibilities available to states in this process. If a tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for areas of Indian country where designated facilities are located. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves an applicable TIP applicable to those facilities.
Solicitation of Comments on Emission Guidelines for Existing Fossil Fuel-fired Stationary Combustion Turbines
Overview
Because the EPA has established NSPS for GHG emissions from new fossil fuel-fired stationary combustion turbines under CAA section 111(b), it has an obligation to also establish emission guidelines for GHG emissions from existing fossil-fuel fired stationary combustion turbines under CAA section 111(d). The EPA intends to fulfill that obligation as expeditiously as practicable. In addition to the CAA obligation, the EPA believes that it is important to address emissions from existing fossil-fuel fired stationary combustion turbines expeditiously, because they are quickly becoming the biggest source of GHG emissions from EGUs. As other fossil-fuel EGUs reduce utilization or retire, at least some of this generation may shift to the existing combustion turbine fleet, particularly if the latter is not subject to limits on GHG emissions. Indeed, the EPA's modeling for these proposed rules indicate that GHG emissions from these units may increase by a material amount in the 2030 to 2035 timeframe in part as a result of a shift in generation to existing combustion turbines associated with the NSPS and emission guidelines proposed in these actions.
In considering how to address this problem, the EPA believes there are at least two key factors to consider. The first is that determining the BSER and issuing emission guidelines covering these units sooner rather than later is important to address the GHG emissions from this growing part of the inventory. The second is related to the size of the affected fleet and the implications for the feasibility and timing of implementing potential candidates for BSER. As discussed later in this section, there are at least three technologies that could be applied to reduce GHGs from existing combustion turbines (CCS, hydrogen co-firing, and heat rate improvements), all of which are available today and are being pursued to at least some degree by owners and operators of these sources. Although the EPA believes that these technologies are available and adequately demonstrated at the level of individual existing combustion turbines, emission guidelines for these sources must also consider how much of the fleet could reasonably implement one or more of these potential BSER approaches in a given time frame.
To provide a sense of scale, the EPA projects that there will be 60 GW of coal-fired steam generating units and 60 GW of oil-/natural gas-fired steam generating units operating in 2030 that will be subject to the CAA section 111(d) requirements for existing fossil fuel-fired steam generating units and 47 GW of new turbines subject to the CAA section 111(b) standards of performance that are proposed in this document. In other words, in 2030, the EPA anticipates there would be nearly three times as many units (414 GW) subject to a emission guidelines for existing fossil fuel-fired combustion turbines as would already be covered by the proposed NSPS and emission guidelines in these actions.
Furthermore, the EPA is aware that grid operators and power companies currently rely on existing fossil fuel-fired combustion turbines as a flexible and readily dispatchable resource that plays a key role in fulfilling resource adequacy and operational reliability needs. Although advancements in energy storage and accelerated deployment of renewable resources may diminish reliance on existing fossil fuel-fired combustion turbines for reliability purposes over time, it is imperative that emission guidelines for these sources not impair the reliability of the bulk power system. For these reasons, the EPA believes that it is important that a BSER determination and associated emission guidelines for existing fossil fuel-fired combustion turbines rely on GHG control options that can be feasibly and cost-effectively implemented at a scale commensurate with the size of the regulated fleet, and provide sufficient lead time to allow for smooth implementation of the GHG emission limitations that preserves system reliability. Given the large size of the existing combustion turbine fleet and the lead time required to develop CCS and hydrogen-related infrastructure, the EPA believes it would be particularly challenging to implement a BSER that requires near-term, wide-scale deployment of CCS or low-GHG hydrogen co-firing at these sources.
As a result, the EPA is considering breaking the existing turbine category into two segments and focusing an initial rulemaking effort on the most frequently operated and highest-emitting turbines, to be followed by a separate rulemaking at a later time that addresses emissions from the remaining turbines as well as additional opportunities to reduce emissions from those units regulated in the first rulemaking. In this notice, the EPA is soliciting comment on the general concept of conducting two rulemakings and developing a BSER for the most frequently operated and highest emitting turbines in a timeframe that would allow for emission reductions in the 2030-2035 window, potentially mitigating the emissions increases in that timeframe. If the BSER for those units were based on the use of CCS, establishing emission guidelines that required limits on GHG emissions in the 2030-2035 timeframe would also allow those units to take advantage of the IRC section 45Q tax credits to make these controls more cost-effective. In the rest of this section, the EPA outlines what such an approach might look like and solicits comment on specific elements of the approach. This section also briefly discusses what BSER might look like for units in the second rulemaking, noting that under this approach, the EPA would likely develop a rulemaking defining BSER for those units at a later date.
The EPA's approach for units covered by the first rulemaking would be on a schedule similar to the proposed schedule for requirements for existing fossil fuel-fired steam generating units (i.e., with compliance deadlines falling in or not long after 2030), with emissions limitations based on heat rate/efficiency improvements, co-firing low-GHG hydrogen, or use of CCS for the most frequently operated and highest-emitting units. For units covered by the second rulemaking, requirements based on one or more of these technologies would also apply. As part of this follow-up rulemaking, the EPA could also consider establishing more stringent emission guidelines for certain units that are covered in the first rulemaking, but which are not required to significantly reduce emissions by that rulemaking due to concerns over the lead time required to build out CCS and hydrogen infrastructure. This approach would allow time for the infrastructure to implement CCS and co-firing low-GHG hydrogen to further develop. The EPA may implement this approach by subcategorizing combustion turbines based on their efficiency, the frequency with which they operate, their size, and whether they are located close to sequestration sites.
Section XII.B provides background information concerning the composition of the current fossil fuel-fired stationary combustion turbine fleet and how it is expected to change in the near future. In section XII.C the EPA outlines the potential approach for units covered in the first rulemaking and in section XII.D, outlines a potential approach for units covered in the second rulemaking. In section XII.E, the EPA discusses potential state plan requirements. Finally, in section XIII.F, the EPA summarizes the key topics for which we are soliciting comment relative to existing combustion turbines.
The Existing Stationary Combustion Turbine Fleet
In 2021, existing combustion turbines represented 37 percent of the GHG emissions from the power sector and 40 percent of the generation from the power sector. In the EPA's updated baseline projections for the power sector, they represent 64 percent of the GHG emissions and 34 percent of the generation in 2030. In EPA's modeling of the 2030 control case, in which both existing fossil fuel-fired EGUs and new stationary combustion turbine EGUs are subject to the emissions limitations proposed in this actions, load shifting from those two categories of sources to the existing combustion turbines s results in an increase in the share of the emissions from existing combustion turbines to 68 percent and an increase in their share of generation to 36 percent. Moreover, in that control case, existing combined cycle combustion turbines are responsible for 65 percent of the CO2 emissions from existing stationary combustion turbines.
In the EPA's modeling in support of these rules, we see two trends that are important relative to existing combustion turbines. First, the EPA's analysis of the reference case (which includes the impacts of IRA without considering the GHG limitation requirements proposed in these rules) projects a long-term decline in generation and emissions from existing combustion turbines. In this reference case, combined cycle generation falls in each model run year from 2028 through 2050, and it falls by more than 50 percent between 2030 and 2045. Generation from existing simple cycle combustion turbines is projected to peak in 2030 before declining by more than 70 percent by 2045.
Historical data shows a wide range of variation in both the heat rate and the GHG emission rates among both existing combined cycle combustion turbines and existing simple cycle combustion turbines. The GHG emission rates for existing combined cycle units range from as low as 644 lb CO2/MWh-gross to as high as 1,891 lb CO2/MWh-gross and annual capacity factors range from as low as 1 percent to as high as 85 percent. While there is some correlation between units with low-GHG emission rates (e.g., more efficient units) and utilization, some low efficiency combined cycle units have historically operated at very high capacity factors. For instance, two of the highest operating units (at 85 percent capacity utilization) have GHG emission rates of nearly 1,200 lb/MWh-gross.
BSER for Frequently-Operated Existing Combustion Turbines
	The EPA is soliciting comment on a potential approach for regulating GHG emissions from existing combustion turbines in two rulemakings, with a BSER based on heat rate/efficiency improvements, CCS, and co-firing low-GHG hydrogen. This approach recognizes the imperatives (the urgent need to reduce greenhouse gases), the opportunities (including the availability of IRC section 45Q tax credits incentivizing CCS installation, as long as sources commence construction by January 1, 2033), and the obstacles (the need for infrastructure for CCS and co-firing low-GHG hydrogen to more fully develop).
As part of this approach, the EPA would subcategorize combustion turbines based on characteristics that are relevant for the types of controls that the EPA may identify as the BSER. These characteristics could include the level of efficiency with which the combustion turbines operate, their size, their level of utilization, their announced retirement date (if any), and whether they are located near sequestration sites.
For units covered in the first rulemaking, the EPA would establish emission guidelines specifying the BSER and the level of emission reduction that sources could comply with during an approximately 2029-2035 timeframe, consistent with the requirements for new combustion turbines. In establishing applicability requirements for sources covered in this first rulemaking, the EPA would focus primarily on the most frequently operated units (e.g., those above a capacity factor threshold of 50 to 60 percent). Such units would likely be combined cycle units, which account for the vast majority of generation and GHG emissions from existing fossil fuel-fired combustion turbines. At a 50 percent capacity factor threshold, approximately 68 percent of the current combined cycle capacity would be covered. At a 60 percent capacity factor threshold, approximately 62 percent of the capacity would be covered. In the second rulemaking, the EPA would address all units that were not covered in the initial rulemaking and could also establish more stringent requirements for certain units covered in the first rulemaking.
The EPA believes this approach would ensure that GHG emissions limitations are implemented first at the subset of existing fossil fuel-fired combustion turbines that contributes the most to GHG emissions, and where the benefits of implementing GHG controls would be greatest. In 2030, more than half of the generation and emissions from existing fossil fuel fired combustion turbines are projected to come from units that operate at a capacity factor greater than 50 percent.
The EPA believes there are three sets of controls that could potentially qualify as the BSER for the group of large and frequently-operated combustion turbines covered in the first rulemaking. Those controls are heatrate/efficiency improvements, co-firing low-GHG hydrogen, and use of CCS.
The EPA believes that heat rate improvements for existing combustion turbines are broadly applicable today. Heat rate/efficiency improvements can be divided into two types. The first type involves smaller scale improvements to existing combustion turbines. The second type involves more comprehensive upgrades of the combustion turbines.
Smaller scale efficiency improvements can include measures such as inlet fogging and inlet cooling. Both of these techniques can achieve about 2 percent improvements in heat rate. Inlet chilling costs approximately $19/kW and is also accompanied by a capacity increase of 11 percent. Inlet fogging is approximately $0.93/kW and is accompanied by a capacity increase of 6 percent. The EPA believes that if it did develop a subcategory for which small-scale efficiency improvements were identified as the BSER, it would likely result in an average 2 percent improvement in the heat rate of affected existing combustion turbines.
More comprehensive efficiency upgrades to combustion turbines are also possible. There is growing evidence that companies are interested in retrofitting existing combustion turbines. An upgrade to the combustion turbine can result in a heat rate improvement of 3.0 percent and a capacity increase of 13 percent for $172/kW, while an upgrade to the steam turbine can result in a heat rate improvement of 3.2 percent with a capacity increase of 3 percent for $130/kW. The EPA believes that if it did develop a subcategory for which more comprehensive efficiency improvements was identified as the BSER, it would likely result in an average efficiency improvement of 6 percent for affected existing stationary combustion turbines.
Although the EPA has proposed to reject efficiency/heat rate improvements (HRI) as the BSER for coal-fired steam generating units, it did so for two reasons that do not apply in the case of combustion turbines. First, for coal-fired steam generating units, HRI achieves only a small amount of emission reductions. In contrast, for combustion turbines, HRI could constitute an important first step for units that may ultimately adopt co-firing with low-GHG hydrogen or use of CCS as these technologies become more widely implemented and deployed. Because co-firing low-GHG hydrogen and adopting CCS are most cost effective at units that are operating at peak efficiency, combustion turbines that plan to ultimately adopt these controls are likely to implement HRI as well.
Second, for coal-fired steam generating units, HRI could lead to a rebound effect that would result in increased emissions. HRI for combustion turbines could also result in a rebound effect, but that would not necessarily increase emissions and, in fact, could decrease them. Coal-fired steam generating units are the highest GHG intensity units; so if such a unit increases its utilization, it is almost certainly offsetting generation from a unit with similar GHG emissions, such as another coal-fired steam generating unit, or a unit with lower GHG emissions, such as a natural gas-fired combustion turbine or some other low-GHG emitting generation. This is not necessarily the case with a combined cycle unit. If a combined cycle unit becomes more efficient and operates more, it is likely to offset emissions from a higher emitting unit, such as a coal-fired unit, or even an efficient simple cycle turbine. This is especially true because many efficiency improvements also increase capacity, and with increased capacity, combined cycle units will have an even larger ability to displace other generation.
The second potential BSER that the EPA is considering is co-firing low-GHG hydrogen. As discussed in section VII, co-firing with low-GHG hydrogen is feasible in combustion turbines that are currently being produced and can achieve meaningful reductions in GHG emissions from these sources. In section VII, the EPA proposes the use of low-GHG hydrogen as BSER for certain new base load turbines, but the EPA also solicits comment on whether limiting the use of low-GHG hydrogen to less frequently operated turbines should be considered for the following reason. Low-GHG hydrogen may be used across wide swaths of the economy, including in the transportation sector, industrial applications, and power generation. Some stakeholders in the power generation sector have suggested that low-GHG hydrogen use in that sector should be focused on energy storage applications, rather than base load applications, in light of the likely large overall demand for low-GHG hydrogen and the large energy demands associated with its production. For this reason, the EPA is considering whether co-firing with low-GHG hydrogen should be considered as a BSER option for less-frequently operated existing fossil fuel-fired combustion turbines, rather than for the most frequently operated units for which the EPA would initially be establishing emission guidelines. The EPA takes comment on whether it should consider a BSER subcategory including hydrogen co-firing for frequently used turbines.
The third set of controls that the EPA is considering is the use of CCS. The EPA believes that CCS could be a potentially effective mitigation measure for existing combustion turbines and that it would be most cost-effective for units that are frequently operating and that are in geographic locations with access to sequestration. As discussed in section VII, multiple companies are considering adding CCS to existing fossil fuel-fired power plants. The EPA believes that a number of existing combined cycle units are likely to be able to install and operate CCS within the costs that the EPA found to be reasonable for new stationary combustion turbines and existing coal-fired steam generating units. These are units that are large, have higher capacity factors, and are located close sequestration sites. The EPA estimates that there are approximately 18 GW of combined cycle facilities that are over 500 MW in size, operate at a capacity factor of over 50 percent, and are located in a state with identified deep saline reservoir sequestration sites. There are approximately 10 GW of units that meet those criteria and operate at a capacity factor of over 60 percent.
Based on the above discussion, the EPA is soliciting comment on whether in its first rulemaking to define a subcategory of units and establish emission guidelines based on CCS as the BSER for that subcategory. The EPA is also taking comment on what the appropriate characteristics for such a category should be. Above, the EPA describes one potential subcategory definition. The EPA anticipates that such a subcategory would likely represent only a small percentage of the units with projected capacity factors of over 50 percent. For the remaining frequently operated units, the EPA is seeking comment on whether it would be appropriate to consider one or more additional subcategories for which BSER would be based on efficiency improvements or co-firing with low-GHG hydrogen. For the reasons explained above, the EPA is soliciting comment on whether it would be appropriate to have two subcategories where efficiency improvement is identified as the BSER. The first subcategory would be for units with high capacity factors and relatively high heat rates. For such units, the EPA is requesting comment on the BSER being a major combustion turbine overhaul that would result in a heat rate improvement of at least 6 percent. The EPA is soliciting comment on defining this subcategory to include units operating at a capacity factor over 50 percent and with a heat rate higher than 8,300 Btu/kwh. At this level, the most efficient units in the subcategory would be required to achieve a new heat rate of 7,800 Btu/kwh, slightly higher than the heat rate requirement for new stationary combustion turbines. For units above a capacity factor of 50 percent (or 60 percent) that are not subject to a BSER of CCS or major efficiency improvements, the EPA would likely consider a BSER of minor heat rate improvements that would require a heat rate improvement of 2 percent. The EPA is also taking comment on whether this heat rate improvement should include a floor of 7,800 Btu/kwh.
BSER for Remaining Combustion Turbines
While the EPA believes that emission guidelines for units covered in the first rulemaking, described above, can achieve important emission reductions from the most frequently operating turbines, limited infrastructure prevents widespread adoption of co-firing low-GHG hydrogen or CCS in that rulemaking. In this section, the EPA discusses how developing a BSER for units in the second rulemaking could address additional units that do not install CCS or co-fire significant amounts of low-GHG hydrogen under the emission guidelines for frequently operating turbines, as well as units that do not meet the applicability requirements for the first rulemaking. In this follow-up rulemaking, the EPA could also consider establishing emission guidelines for sources that are covered by the new source standards that are being proposed but that would continue to emit relatively large amounts of CO2 on a lb/MWh basis including intermediate units subject to a BSER based on 30 percent hydrogen co-firing and low load units that are meeting a clean fuels standard. This second rulemaking might impose requirements on sources beginning in 2035. The second rulemaking would extend CCS and co-firing low-GHG hydrogen to additional combustion turbines.
As noted in section XII.C, the EPA believes that a first rulemaking for existing turbines would apply to units most amenable to CCS, which ensures that any limits on the amount of CCS that could be installed during the relatively short timeframe of the first rulemaking, that is, by 2032, are taken into account. The second rulemaking would provide an opportunity for the EPA to consider whether CCS could be considered BSER for a larger number of frequently used turbines due to the further development of CCS infrastructure, including pipelines and sequestration sites and cost reductions in capture equipment. For example, based on updated information, the EPA could consider whether CCS is the BSER for facilities that meet somewhat lower size or capacity thresholds, or are located somewhat more distant from sequestration sites, than units for which CCS is determined to be the BSER in the first rulemaking.
Furthermore, in the second rulemaking, the EPA would establish emission guidelines for any existing combustion turbines that are not covered by the emission guidelines promulgated in the first rulemaking  -  namely, less frequently operated turbines. The EPA anticipates that these less frequently operated turbines would consist principally of simple cycle combustion turbines. As explained above in section XII.C, the EPA believes that, absent significant further reductions in the cost of CCS, it is unlikely that CCS would meet the cost criteria used in these proposed actions as a reasonable cost for BSER for less frequently used turbines. Therefore, the EPA believes the second rulemaking would likely consider whether expanding co-firing low-GHG hydrogen is BSER for less frequently operated turbines. This could entail some combination of including more units in a co-firing low-GHG hydrogen based BSER (e.g., peaking turbines) and/or expanding the co-firing percentage to an amount greater than 30 percent. This concept of moving from 30% co-firing of hydrogen to larger amounts of hydrogen over time is consistent with many companies' stated plans. For instance, the developers of the Intermountain Power Project indicate that they intend to combust 30 percent hydrogen when their unit (currently under construction) commences operation in 2025. They intend to transition to use of 100 percent hydrogen by 2045 as technology improves. Most turbine manufacturers are developing technologies to co-fire amounts of hydrogen that are substantially larger than 30 percent. Many of these manufacturers are developing retrofit options for existing turbines to run on large percentages of hydrogen, even up to 100 percent. Given these rapid advancements in combustion turbine technology, the EPA believes that the key driver for how much hydrogen could be co-fired in turbines, particularly those operating at less than base load (e.g., 50 percent), is more likely related to how quickly low-GHG hydrogen production and distribution will expand to provide the needed low-GHG hydrogen, rather than the physical capabilities of turbines to combust it.
State Plan Requirements for Existing Turbines
This section focuses on three specific state plan requirements: 1) setting emission standards consistent with BSER; 2) Remaining Useful Life and Other Factors (RULOF) and 3) Flexibilities and State Equivalency. It also has a brief discussion of other state plan requirements.
In the emissions guidelines, the EPA would require state plans to establish emission standards consistent with application of the BSER, similar to what section XI describes for fossil fuel-fired steam generating units. The first step would involve setting a baseline emission rate using historical data. The second step would be to adjust that emission rate to reflect the level of reductions expected with implementation of BSER. For example, if the BSER for a major turbine upgrade was based on a 6 percent heat rate improvement, the state would be required to establish emission standards that reduce the baseline emission rate by 6 percent.
The application of the RULOF provision could be important for states with respect to certain turbines. The useful life of a combined cycle unit is approximately 25 to 30 years, and because more than 151 GW of combined cycle units came on-line in the 2000 to 2010 time-frame, many could potentially be at or nearing the end of their remaining useful life in the 2030 to 2040 timeframe. The EPA anticipates that states would be required to apply the RULOF provision similar to the way that the EPA is proposing it be applied for existing fossil fuel-fired steam generating units. Thus, any retirement date that was considered in establishing a less stringent standard for the facility would need to be made federally enforceable. In addition, the state would be required to determine the source-specific BSER for the facility by evaluating the same factors that the EPA considered. For example, for a unit subject to a presumptive standard based on CCS pursuant to the emission guidelines, the state would first consider alternative standards based on CCS with a lower carbon capture rate, then co-firing with low-GHG hydrogen, then comprehensive turbine upgrades, and finally smaller scale efficiency improvements.
There are at least two areas where we anticipate states and sources being interested in additional flexibilities beyond those available through the RULOF provisions. First, states and sources have expressed significant interest in emission trading. As the EPA has explained earlier in this preamble, the Agency believes that, because so many coal-fired units are likely to cease operations in the 2030 to 2040 timeframe in the baseline, an emission trading program for those units would have significantly less utility. However, because many turbines have come on-line since 2015, have remaining useful lives that extend past 2040, and are covered by existing trading programs, the EPA anticipates more interest in emission trading under combustion turbine emission guidelines. The principles discussed earlier in this notice related to emission trading, under which any such program should ensure emission reductions equivalent to or greater than the emission reductions that would be achieved with unit-by-unit implementation of BSER, would likely be the starting point for the EPA's consideration of emissions trading for an existing combustion turbine rule.
In addition, the EPA is aware of states and utilities that have comprehensive plans to reduce GHG emissions from their turbines to zero, which do not involve either emission trading or installation of CCS. NextERA has a plan to convert 16 GW of natural gas-fired capacity to fire 100 percent hydrogen by 2045. The Illinois "Climate and Equitable Jobs Act", sets dates (ranging from 2030 to 2045) by which individual gas-fired power plants must reduce their emissions to zero. The EPA solicits comment on whether and how to assure that the emission guidelines for combustion turbines provides opportunities for states to develop plans that build upon these state programs.
In addition, the EPA also solicits comment on other key issues relating to state plan requirements that are specific to existing combustion turbines, including timing for state plan submittals, compliance deadlines, and meaningful engagement.
Areas that the EPA is Seeking Comment on Related to Existing Turbines
The EPA is seeking comment on four general areas related to developing BSER for existing turbines. First, the EPA is soliciting comment on general assumptions about potential future utilization of turbines. Second, the EPA is soliciting comment on assumptions about sub-categorization and timing of BSER requirements for existing turbines. Third, the EPA is soliciting comment related to specific BSER assumptions for existing turbines. And finally, the EPA is soliciting comment on state plan provisions for existing turbines.
The EPA is seeking comment on a number of issues related to how its consideration of projected future utilization of combined cycles informed its consideration of a potential BSER for existing combustion turbines. First, the EPA is taking comment on its projections of how turbines will operate in the future and the key factors that influence those changes in operation. While EPA modeling shows that there is some increase in emissions from these units in all years following imposition of CAA section 111 standards on existing coal-fired steam generating units and new stationary combustion turbines, that increase is much smaller in the later years. The EPA believes the magnitude of these trends is significantly impacted by the rate at which new low emitting generation comes on-line, in part incentivized by IRA and BIL. The EPA is taking comment on all aspects of these assumptions including: the speed at which new low-emitting generation will come on-line and the impact that it has on likely capacity factors for combined cycle units (in particular the projection that capacity factors will grow in the 2028/30 timeframe but decrease in later years).
The EPA is also taking comment on how its assumptions about the potential operation of turbines in future years coupled with considerations about the availability of infrastructure should inform its BSER determination. More specifically, the EPA is requesting comment on how to consider the rate of CCS (and potentially hydrogen) infrastructure development in determining a BSER that could potentially impact hundreds of sources.
With regards to the BSER itself, the EPA is taking comment on the applicability of CCS retrofits to existing combustion turbines and its focus on base load turbines (e.g., those with a capacity factor of greater than 50 percent). The EPA is also requesting comment on appropriate parameters to use in the design of a potential subcategory for which CCS would be identified as the BSER. The EPA is also taking comment on the role of low-GHG hydrogen as part of BSER and whether EPA should focus any BSER determination on units with lower capacity factors. The EPA also requests comment on a BSER that could include requirements to co-fire more than 30 percent low-GHG hydrogen and up to 100 percent low-GHG hydrogen. Further, the EPA is soliciting comments on applying such requirements to units that would be covered under the CAA section 111(b) provisions being proposed in this preamble under a potential future CAA section 111(d) rule. Finally, the EPA requests comment on whether heat rate improvements are an appropriate BSER. This includes consideration of whether efficiency improvements make sense as a first step towards firing some amount of low-GHG hydrogen or installing CCS. It also includes consideration of the two types of efficiency subcategories discussed above, one for major turbine upgrades for more inefficient units and one for minor efficiency improvements for more efficient units.
The EPA is also taking comment on state plan requirements for a CAA section 111(d) rule for existing fossil fuel-fired turbines. Specifically, the EPA is taking comment on considerations related to an approach for setting emission standards, implementation of RULOF, and additional flexibilities beyond RULOF. With regards to RULOF, the EPA is specifically seeking comment on the likely remaining useful life of a typical combined cycle unit and simple cycle turbine, how RULOF might factor into a unit whose utilization is projected to change in the future (e.g., how should a state factor in the utilization pattern identified in the EPA's modeling where some units operate at well above 50 percent in the early 2030s, but see a significant increase in capacity factors in the later years.) With regards to flexibility measures, the EPA is seeking comment on the role of trading in implementation of a turbine BSER and how a state could ensure that under a trading program, sources achieved the same level of reductions expected under unit specific implementation of the BSER. Finally, the EPA is taking comment on if and how the EPA should provide flexibility for states who may have already developed, or who may be interested in developing approaches to reduce emissions that are very different than the BSER the EPA might develop and how one could evaluate whether such programs achieve the same or greater emission reductions than unit-by-unit implementation of the BSER.
Implications for Other EPA Programs
Implications for New Source Review (NSR) Program
CAA section 110(a)(2)(C) requires that a state implementation plan (SIP) include a New Source Review (NSR) program that provides for the "regulation of the modification and construction of any stationary source ... as necessary to assure that [the NAAQS] are achieved." Within the NSR program, the "major NSR" preconstruction permitting program applies to new construction and to modifications of existing sources that emit "regulated NSR pollutants" at or above certain established thresholds. New sources and modifications that emit regulated NSR pollutants under the established thresholds may be subject to "minor NSR" program requirements or may be excluded from NSR requirements altogether. The NSR program for a state or local permitting authority with an approved SIP is implemented through 40 CFR 51.160 to 51.166, while the NSR program applying in areas for which the EPA or a delegated state, local or tribal agency is the permitting authority is implemented through 40 CFR part 49 and 40 CFR 52.21.
NSR applicability is pollutant-specific and, for the major NSR program, the permitting requirements that apply to a source depend on the air quality designation at the location of the source for each of its emitted pollutants at the time the permit is issued. Major NSR permits for sources located in an area that is designated as attainment or unclassifiable for the NAAQS for its pollutants are referred to as Prevention of Significant Deterioration (PSD) permits. In addition, PSD permits can include requirements for specific pollutants for which there are no NAAQS. Sources subject to PSD must, among other requirements, comply with emission limitations that reflect the Best Available Control Technology (BACT) for "each pollutant subject to regulation" as specified by CAA sections 165(a)(4) and 169(3). Major NSR permits for sources located in nonattainment areas and that emit at or above the specified major NSR threshold for the pollutant for which the area is designated as nonattainment are referred to as Nonattainment NSR (NNSR) permits. Sources subject to NNSR must, among other requirements, meet the Lowest Achievable Emissions Rate (LAER) pursuant to CAA sections 171(3) and 173(a)(2) for any pollutant subject to NNSR. Due to the pollutant-specific applicability of the NSR program, it it conceivable that a source seeking to newly construct or modify may have to obtain multiple types of NSR permits (i.e., NNSR, PSD, or minor NSR) depending on the air quality designation at the location of the source and the types and amounts of pollutants it emits.
A new stationary source is subject to major NSR requirements if its potential to emit (PTE) a regulated NSR pollutant exceeds statutory emission thresholds, upon which the NSR regulations define it as a "major stationary source." For PSD permitting, once a new stationary source is determined to be subject to major NSR for one regulated NSR pollutant (with the exception of GHG), the source can be subject to major NSR requirements for any other regulated NSR pollutant if the PTE of that pollutant is at least the "significant" emissions rate ("SER"), as defined in 40 CFR 52.21(b)(23). In the case of GHG, the EPA has not promulgated a GHG SER but applies a BACT applicability threshold of 75,000 TPY CO2e.
For an existing source, it can be subject to major NSR requirements if it is a major stationary source and its emissions increase resulting from a modification (i.e., physical change or change in the method of operation) are equal to or greater than the SER for a regulated NSR pollutant, upon which the NSR regulations define it as a "major modification." As with new sources, the one exception to this applicability approach is GHG, which currently applies a BACT applicability threshold in lieu of a SER and can only be subject to major NSR if another pollutant is also subject to major NSR for the modification. Generally, an existing major stationary source triggering major NSR requirements for a regulated NSR pollutant would have both a significant emissions increase from the modification and a significant net emissions increase at the stationary source, and the calculation of the significant emissions increase differs depending on whether the modification is to an existing emissions unit, or the addition of a new emissions unit, or if it involves multiple types of emission units. An existing major stationary source would trigger PSD permitting requirements for GHGs if it undertakes a modification and: (1) the modification is otherwise subject to PSD for a pollutant other than GHG; and (2) the modification results in a GHG emissions increase and a GHG net emissions increase that is equal to or greater than 75,000 TPY CO2e and greater than zero on a mass basis.