(a) For each affected EGU, your State plan must include the standard of performance that applies for the affected EGU. A standard of performance for an affected EGU may take the following forms:

(1) A rate-based standard of performance for an individual affected EGU that does not exceed the level calculated through the use of the methods described in § 60.5775b(c) and (d).

(2) A standard of performance in an alternate form, which may apply for affected EGUs in the long-term coal-fired steam generating unit subcategory or the medium-term coal-fired steam generating unit subcategory, as provided for in § 60.5775b(e).

(b) Standard(s) of performance for affected EGUs included under your State plan must be demonstrated to be quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected EGU. The State plan submittal must include the methods by which each standard of performance meets each of the following requirements:

(1) An affected EGU's standard of performance is quantifiable if it can be reliably measured in a manner that can be replicated.

(2) An affected EGU's standard of performance is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the State and the Administrator to independently evaluate, measure, and verify compliance with the standard of performance.

(3) An affected EGU's standard of performance is non-duplicative with respect to a State plan if it is not already incorporated as an standard of performance in the State plan.

(4) An affected EGU's standard of performance is permanent if the standard of performance must be met continuously unless it is replaced by another standard of performance in an approved State plan revision.

(5) An affected EGU's standard of performance is enforceable if:

(i) A technically accurate limitation or requirement, and the time period for the limitation or requirement, are specified;

(ii) Compliance requirements are clearly defined;

(iii) The affected EGUs are responsible for compliance and liable for violations identified;

(iv) Each compliance activity or measure is enforceable as a practical matter, as defined by 40 CFR 49.167; and

(v) The Administrator, the State, and third parties maintain the ability to enforce against violations (including if an affected EGU does not meet its standard of performance based on its emissions) and secure appropriate corrective actions: in the case of the Administrator, pursuant to CAA sections 113(a)-(h); in the case of a State, pursuant to its State plan, State law or CAA section 304, as applicable; and in the case of third parties, pursuant to CAA section 304.

(c) Methodology for establishing presumptively approvable standards of performance, for affected EGUs in each subcategory.

(1) Long-term coal-fired steam generating units

(i) BSER is CCS with 90 percent capture of CO2.

(ii) Degree of emission limitation is 88.4 percent reduction in emission rate (lb CO2/MWh-gross).

(iii) Presumptively approvable standard of performance is an emission rate limit defined by an 88.4 percent reduction in annual emission rate (lb CO2/MWh-gross) from the unit-specific baseline.

(2) Medium-term coal-fired steam generating units

(i) BSER is natural gas co-firing at 40 percent of the heat input to the unit.

(ii) Degree of emission limitation is a 16 percent reduction in emission rate (lb CO2/MWh-gross).

(iii) Presumptively approvable standard of performance is an emission rate limit defined by a 16 percent reduction in annual emission rate (lb CO2/MWh-gross) from the unit-specific baseline.

(iv) For units in this subcategory that have an amount of co-firing that is reflected in the baseline operation, States must account for such preexisting co-firing in adjusting the degree of emission limitation (e.g., for an EGU co-fires natural gas at a level of 10 percent of the total annual heat input during the applicable 8-quarter baseline period, the corresponding degree of emission limitation would be adjusted to 12 percent to reflect the preexisting level of natural gas co-firing).

(3) Base load oil-fired steam generating units.

(i) BSER is routine methods of operation and maintenance.

(ii) Degree of emission limitation is a 0 percent increase in emission rate (lb CO2/MWh-gross).

(iii) Presumptively approvable standard of performance is an annual emission rate limit of 1,400 lb CO2/MWh-gross.

(4) Intermediate load oil-fired steam generating units.

(i) BSER is routine methods of operation and maintenance.

(ii) Degree of emission limitation is a 0 percent increase in emission rate (lb CO2/MWh-gross).

(iii) Presumptively approvable standard of performance is an annual emission rate limit of 1,600 lb CO2/MWh-gross.

(5) Low load oil-fired steam generating units.

(i) BSER is uniform fuels.

(ii) Degree of emission limitation is 170 lb CO2/MMBtu.

(iii) Presumptively approvable standard of performance is an annual emission rate limit of 170 lb CO2/MMBtu.

(6) Base load natural gas-fired steam generating units.

(i) BSER is routine methods of operation and maintenance.

(ii) Degree of emission limitation is a 0 percent increase in emission rate (lb CO2/MWh-gross).

(iii) Presumptively approvable standard of performance is an annual emission rate limit of 1,400 lb CO2/MWh-gross.

(7) Intermediate load natural gas-fired steam generating units.

(i) BSER is routine methods of operation and maintenance.

(ii) Degree of emission limitation is a 0 percent increase in emission rate (lb CO2/MWh-gross).

(iii) Presumptively approvable standard of performance is an annual emission rate limit of 1,600 lb CO2/MWh-gross.

(8) Low load natural gas-fired steam generating.

(i) BSER is uniform fuels.

(ii) Degree of emission limitation is 130 lb CO2/MMBtu.

(iii) Presumptively approvable standard of performance is an annual emission rate limit of 130 lb CO2/MMBtu.

(d) Methodology for establishing the unit-specific baseline of emission performance.

(1) A State shall use the CO2 mass emissions and corresponding electricity generation or, for affected EGUs in the low load oil- or natural gas-fired subcategory, heat input data for a given affected EGU from the most representative continuous 8-quarter period from 40 CFR part 75 reporting within the 5-year period immediately prior to May 9, 2024.

(2) For the continuous 8 quarters of data, a State shall divide the total CO2 emissions (in the form of pounds) over that continuous time period by either the total gross electricity generation (in the form of MWh) or, for affected EGUs in the low load oil- or natural gas-fired subcategory, total heat input (in the form of MMBtu) over that same time period to calculate baseline CO2 emission performance in lb CO2 per MWh or lb CO2 per MMBtu.

(e) Your State plan may include a standard of performance in an alternate form that differs from the presumptively approvable standard of performance specified in § 60.5775b(a)(1), as follows:

(1) An aggregate rate-based standard of performance (lb CO2/MWh-gross) that applies for a group of affected EGUs that share the same owner or operator, as calculated on a gross generation weighted average basis, provided the standard of performance meets the requirements of paragraph (f) of this section.

(2) A mass-based standard of performance in the form of an annual limit on allowable mass CO2 emissions for an individual affected EGU, provided the standard of performance meets the requirements of paragraph (g) of this section.

(3) A rate-based standard of performance (lb CO2/MWh-gross) implemented through a rate-based emission trading program, such that an affected EGU must meet the specified lb CO2/MWh-gross rate that applies for the affected EGU, and where an affected EGU may surrender compliance instruments denoted in 1 short ton of CO2 to adjust its reported lb CO2/MWh-gross rate for the purpose of demonstrating compliance, provided the standard of performance meets the requirements of paragraph (h) of this section.

(4) A mass-based standard of performance in the form of an annual CO2 budget implemented through a mass-based CO2 emission trading program, where an affected EGU must surrender CO2 allowances in an amount equal to its reported mass CO2 emissions, provided the standard of performance meets the requirements of paragraph (i) of this section.

(f) Where your State plan includes a standard of performance in the form of an aggregate rate-based standard of performance (lb CO2/MWh-gross) that applies for a group of affected EGUs that share the same owner or operator, as calculated on a gross generation weighted average basis, your State plan must include:

(1) The presumptively approvable rate-based standard of performance (lb CO2/MWh-gross) that would apply under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section, to each of the affected EGUs that form the group.

(2) Documentation of any assumptions underlying the calculation of the aggregate rate-based standard of performance (lb CO2/MWh-gross).

(3) The process for calculating the aggregate gross generation weighted average emission rate (lb CO2/MWh-gross) at the end of each compliance period, based on the reported emissions (lb CO2) and utilization (MWh-gross) of each of the affected EGUs that form the group.

(4) Measures to implement and enforce the annual aggregate rate-based standard of performance, including the basis for determining owner or operator compliance with the aggregate standard of performance and provisions to address any changes to owners or operators in the course of implementation.

(5) A demonstration of how the application of the aggregate rate-based standard of performance will achieve equivalent or better emission reduction as would be achieved through the application of a rate-based standard of performance (lb CO2/MWh-gross) that would apply pursuant to paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(g) Where your State plan includes a standard of performance in the form of an annual limit on allowable mass CO2 emissions for an individual affected EGU, your State plan must include:

(1) The presumptively approvable rate-based standard of performance (lb CO2/MWh-gross) that would apply to the affected EGU under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(2) The utilization level used to calculate the mass CO2 limit, by multiplying the assumed utilization level (MWh-gross) by the presumptively approvable rate-based standard of performance (lb CO2/MWh-gross), including the underlying data used for the calculation and documentation of any assumptions underlying this calculation.

(3) Measures to implement and enforce the annual limit on mass CO2 emissions, including provisions that address assurance of achievement of equivalent emission performance.

(4) A demonstration of how the application of the mass CO2 limit for the affected EGU will achieve equivalent or better emission reduction as would be achieved through the application of a rate-based standard of performance (lb CO2/MWh-gross) that would apply pursuant to paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(5) The backstop rate-based emission rate requirement (lb CO2/MWh-gross) that will also be applied to the affected EGU on an annual basis.

(6) For affected EGUs in the long-term coal-fired steam generating unit subcategory, in lieu of paragraphs (g)(2), (4), and (5) of this section, you may include a presumptively approvable mass CO2 limit based on the product of the rate-based standard of performance (lb CO2/MWh-gross) under paragraph (a)(1) of this section multiplied by a level of utilization (MWh-gross) corresponding to an annual capacity factor of 80 percent for the individual affected EGU with a backstop rate-based emission rate requirement equivalent to a reduction in baseline emission performance of 80 percent on an annual calendar-year basis.

(h) Where your State plan includes a standard of performance in the form of a rate-based standard of performance (lb CO2/MWh-gross) implemented through a rate-based emission trading program, your State plan must include:

(1) The presumptively approvable rate-based standard of performance (lb CO2/MWh-gross) that applies to each of the affected EGUs participating in the rate-based emission trading program under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(2) Measures to implement and enforce the rate-based emission trading program, including the basis for awarding compliance instruments (denoted in 1 ton of CO2) to an affected EGU that performs better on an annual basis than its rate-based standard of performance, and the process for demonstration of compliance that includes the surrender of such compliance instruments by an affected EGU that exceeds its rate-based standard of performance.

(3) A demonstration of how the use of the rate-based emission trading program will achieve equivalent or better emission reduction as would be achieved through the application of a rate-based standard of performance (lb CO2/MWh-gross) that would apply pursuant to paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(i) Where your State plan includes a mass-based standard of performance implemented through a mass-based CO2 emission trading program, where an affected EGU must surrender CO2 allowances in an amount equal to its reported mass CO2 emissions, your State plan must include:

(1) The presumptively approvable rate-based standard of performance (lb CO2/MWh-gross) that would apply to each affected EGU participating in the trading program under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(2) The calculation of the mass CO2 budget contribution for each participating affected EGU, determined by multiplying the assumed utilization level (MWh-gross) of the affected EGU by its presumptively approvable rate-based standard of performance (lb CO2/MWh-gross), including the underlying data used for the calculation and documentation of any assumptions underlying this calculation.

(3) Measures to implement and enforce the annual budget of the mass-based CO2 emission trading program, including provisions that address assurance of achievement of equivalent emission performance.

(4) A demonstration of how the application of the CO2 emission budget for the group of participating affected EGUs will achieve equivalent or better emission performance as would be achieved through the application of a rate-based standard of performance (lb CO2/MWh-gross) that would apply to each participating affected EGU under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section.

(5) The backstop rate-based emission rate requirement (lb CO2/MWh-gross) that will also be applied to each participating affected EGU on an annual basis.

(j) In order to use the provisions of § 60.24a(e) through (h) to apply a less stringent standard of performance or longer compliance schedule to an affected EGU based on consideration of electric grid reliability, including resource adequacy, under these emission guidelines, a State must provide the following with its State plan submission:

(1) An analysis of the reliability risk clearly demonstrating that the particular affected EGU is critical to maintaining electric reliability such that requiring it to comply with the applicable requirements under paragraph (c) of this section or § 60.5780b would trigger non-compliance with at least one of the mandatory reliability standards approved by the Federal Energy Regulatory Commission or would cause the loss of load expectation to increase beyond the level targeted by regional system planners as part of their established procedures for that particular region; specifically, a clear demonstration is required that the particular affected EGU would be needed to maintain the targeted level of resource adequacy. The analysis must also include a projection of the period of time for which the particular affected EGU is expected to be reliability critical and substantiate the basis for applying a less stringent standard of performance or longer compliance schedule consistent with 40 CFR 60.24a(e).

(2) An analysis by the relevant reliability planning authority that corroborates the asserted reliability risk identified in the analysis under paragraph (j)(1) of this section and confirms that requiring the particular affected EGU to comply with its applicable requirements under paragraph (c) of this section or § 60.5780b would trigger non-compliance with at least one of the mandatory reliability standards approved by the Federal Energy Regulatory Commission or would cause the loss of load expectation to increase beyond the level targeted by regional system planners as part of their established procedures for that particular region, and also confirms the period of time for which the EGU is projected to be reliability critical.

(3) A certification from the relevant reliability planning authority that the claims of reliability risk are accurate and that the identified reliability problem both exists and requires the specific relief requested.