Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units

Finally, the EPA is finalizing the determination that a degree of emission limitation based on 40 percent natural gas co-firing is not achievable because it is unlikely the necessary pipeline infrastructure can be deployed by the compliance date of January 1, 2030. In the 2024 CPS, the EPA estimated the maximum aggregate amount of pipeline capacity at nearly 14.7 billion cubic feet per day for implementing 40 percent natural gas co-firing, which would require approximately 3,500 miles of pipeline.\279\ The 2024 CPS further assumed that sources could obtain the permits necessary to construct these pipelines in one year and that the actual construction would require one year or less.\280\ While the timelines in the 2024 CPS were based on average permitting, approval, and construction timeframes,\281\ the EPA now believes that projects facing reasonably foreseeable adverse conditions could take up to five years for approval and construction.\282\

\279\ 89 FR 39798, 39893 (May 9, 2024).

\280\ Id. at 39893 n.682.

\281\ Id. at 39893.

\282\ Documentation for the Lateral Cost Estimation (2024), ICF International, p. 42. Attachment to Greenhouse Gas Mitigation Measures for Steam Generating Units. Document ID No. EPA-HQ-OAR- 2023-0072-9095.

Further, the EPA now projects that much more coal-fired capacity will remain in operation than previously anticipated, meaning that more natural gas pipeline projects would have to be undertaken to support 40 percent natural gas co-firing at a nationwide level.\283\ This increase would strain existing permitting, planning, and implementation resources and make completion of these projects by the January 1, 2030, compliance date less likely. Furthermore, the involvement of external parties in deploying such a large amount of infrastructure would necessarily include its own complications and delays. Additionally, the EPA did not consider that the large number of these projects, or that the new pipelines necessary to support co-firing, would be in addition to pipeline projects necessary to meet the increasing demand for natural gas for other purposes (e.g., liquified natural gas exports and other domestic uses like powering AI). Specifically, updated EPA power sector modeling that incorporates higher demand and the impacts of the OBBBA estimates 100 GW installed coal capacity by 2035,\284\ almost twice as much as projected in the final 2024 CPS analysis.\285\ This would require an estimated 90 percent more gas by volume to meet the 40 percent co-firing standard. By that same year, modeling projections estimate an overall gas demand of 16.4 trillion cubic feet with an average delivered price of $4.92/MMBtu.\286\ Under the earlier analysis, the lower demand environment and the impact of the IRA resulted in falling natural gas consumption over time in the power sector. The updated analysis, driven by the current higher demand environment and the impacts of the OBBBA, projects increasing natural gas consumption over the forecast period. As a result, the updated forecast projects total gas consumption in 2035 will be 77 percent higher as compared to the forecast used for the 2024 CPS.

\283\ See memorandum entitled Trends Relating to Fossil Fuel- fired Electric Generating Units in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2025-0124).

\284\ Id.

\285\ U.S. EPA. RIA for 2024 CPS. Document ID No. EPA-HQ-OAR- 2023-0072-8913. Table 3-14.

\286\ See memorandum entitled Trends Relating to Fossil Fuel- fired Electric Generating Units in the docket for this rulemaking (Document ID No. EPA-HQ-OAR-2025-0124).

The EPA now believes that these factors make it unlikely for the necessary additional pipeline infrastructure for 40 percent natural gas co-firing to be deployed by the January 1, 2030, compliance date. Therefore, the EPA is finalizing the determination that the degree of emission limitation in the 2024 CPS for medium-term coal-fired steam generating EGUs is not achievable.

Comments: Commenters supporting the EPA's determination generally expressed concern with the feasibility of the January 1, 2030, compliance deadline for 40 percent natural gas co-firing in the 2024 CPS, stating that this deadline was not achievable because of the required time for permitting and construction of natural gas pipelines, particularly interstate pipelines. These commenters explained that the EPA's assumptions in the 2024 CPS about the amount of time it takes to design, permit, and construct natural gas lateral pipelines were unrealistically optimistic. Other commenters, however, supported the compliance deadline for the 40 percent natural gas co-firing based on the examination of national averages in 2024.

EPA Response: The EPA agrees with the former and disagrees with the latter commenters. As detailed in this section of the preamble, the EPA now believes that projects facing reasonably foreseeable adverse conditions could require up to five years for approval and construction, particularly in light of increased demand for natural gas that could further extend approval and construction periods.\287\

\287\ Documentation for the Lateral Cost Estimation (2024), ICF International, p. 42. Attachment to Greenhouse Gas Mitigation Measures for Steam Generating Units. Document ID No. EPA-HQ-OAR- 2023-0072-9095.

As noted by supportive commenters, a longer approval and construction timeline for pipelines would be more appropriate based on the longest project approval timeline for any project reviewed (Carty Lateral Project) combined with the longest construction timeline for any project reviewed (Coastal Bend Header), which totals to 49 days short of five years. Such an implementation timeframe would, in contrast to the timeframe the EPA promulgated in the 2024 CPS, ensure that regulated entities facing reasonably foreseeable delays in both project approval and construction could still timely comply with the applicable requirements. Furthermore, assuming the longer timeline is reasonable because the increase in the use of natural gas for other purposes will likely necessitate additional pipeline buildout for these purposes, which will further delay pipeline approval and construction time for the electric power sector.

The EPA now believes that these factors make deployment of the necessary additional pipeline infrastructure for 40 percent natural gas co-firing by the January 1, 2030, compliance date unlikely. Therefore, the EPA is finalizing the determination that the degree of emission limitation in the 2024 CPS for existing medium-term coal-fired steam generating EGUs is not achievable. d. Conclusion

In summary, the EPA is finalizing the repeal of the requirements of the emission guidelines pertaining to medium-term coal-fired steam generating units because natural gas co-

firing in a coal-fired steam generating EGU is impermissible generation shifting, the energy requirements associated with 40 percent natural gas co-firing are unreasonable, and the degree of emission limitation specified in the 2024 CPS is not achievable. As discussed in this section of the preamble, the EPA is addressing only 40 percent natural gas co-firing and implementation by January 1, 2030, because those were the requirements under the 2024 CPS. This action does not address any potential alternative BSERs or implementation timeframes such as lower rates of co-firing or a later implementation date. The EPA considered whether to analyze and promulgate potential alternatives and determined it is not necessary to do so under the circumstances presented here. 3. Requirements for Existing Natural Gas- and Oil-Fired Steam Generating Units

The EPA is finalizing the repeal of the requirements of the emission guidelines pertaining to natural gas- and oil-fired steam generating units. In the 2024 CPS, the EPA finalized routine methods of operation and maintenance as the BSER for intermediate load and base load natural gas- and oil-fired steam generating units and uniform fuels as the BSER for low load natural gas- and oil-fired steam generating units. Because those BSERs were consistent with the current operations at most sources (i.e., business-as-usual), there was no associated additional cost. In addition, those BSERs resulted in a degree of emission limitation that would have led to few, if any, emission reductions for any of the units. The EPA did not propose to repeal the BSER determinations and degrees of emission limitation for those sources. However, the EPA proposed to repeal the requirements in the emission guidelines for natural gas- and oil-fired steam generating units because requiring States to develop, submit, and implement state plans solely for natural gas- and oil-fires steam generating units would be an inefficient use of State resources, as these sources comprise a relatively small part of the source category and regulating them would have little environmental benefit.

Comments: Several commenters supported the EPA's proposal in the June 2025 NPRM to repeal the portions of the emission guidelines applicable to oil- and natural gas-fired steam generating units. These commenters generally agreed that requiring States to develop and submit state plans for these units alone would be an inefficient use of limited State resources that would present an undue administrative burden. Commenters further asserted that, if regulating these sources would have no significant benefit in terms of emission reductions, then such regulation would not be of reasonable cost. Additionally, some commenters explained that there is no need for the EPA to retain the emission guidelines for these units because the BSERs for oil- and natural gas-fired steam generating units are consistent with business- as-usual operation.

Other commenters opposed repealing the emission guidelines for these units for several reasons. Those commenters asserted that CAA section 111(d) requires the EPA to promulgate emission guidelines for existing sources if the Agency has promulgated standards of performance for the corresponding new sources. Commenters argued that standards of performance currently exist for GHG emissions from new oil- and natural gas-fired steam generating units, and that the EPA cannot override the statutory directive to have regulations for existing units based only on the Agency's judgment that state plans would not be prudent. Commenters stated that this is particularly the case because the EPA has not identified any flaw with the BSER determinations or emission guidelines for oil- and natural gas-fired steam generating units. The commenters further asserted that the EPA's justification for repealing the emission guidelines under CAA section 111 (i.e., requiring States to submit plans covering just these units would be “imprudent” and an inefficient use of State resources) is not legally cognizable and that, regardless, the presumptive standards for these units would be straightforward and the EPA has not explained why business-as-usual standards would require expenditure of resources on engineering analyses. Commenters suggested that the 2024 CPS standards cover approximately 200 natural gas-fired steam generating units and 30 oil- fired units, that these units contribute an outsized amount of pollution as compared to electricity generation, and that the emission guidelines provide important protections against increased emissions as these units age. Finally, commenters asserted that it is not, in fact, a significant burden for States to prepare plans to regulate these units and that the EPA has not provided evidence to the contrary. Commenters stated that if a State finds preparing a plan too burdensome or otherwise chooses not to submit a plan, the EPA will issue a federal plan instead.

EPA Response: The EPA acknowledges these comments but continues to believe that it is not a reasonable use of States' resources, nor the Agency's (in the case of a federal plan), to develop and submit plans for oil- and natural gas-fired steam generating units while the Agency is repealing the requirements for all other existing fossil fuel-fired power plants. Natural gas- and oil-fired steam generating units represent a very small portion of the source category from both a generation and an emissions perspective. In 2023, natural gas- and oil- fired steam generating units accounted for 1.2 percent of total electric generation and 3.5 percent of power sector CO2 emissions in the U.S.\288\ The EPA's forecasts of power sector behavior using the Integrated Planning Model in the 2025 Reference Case projects that this share of both generation and emissions in the U.S. will decrease even further over the forecast period.\289\

\288\ Based on eGRID2023 data. Available at: https://www.epa.gov/egrid/detailed-data.

\289\ EPA 2025 Reference Case. Available at: https://www.epa.gov/power-sector-modeling.

Although the EPA is not finding that the BSERs or presumptive standards in the 2024 CPS were unreasonable or inappropriate for these sources, the Agency believes that it would be unreasonable to require States to develop state plans solely for these units. Throughout the more than 50-year period that the EPA has promulgated CAA section 111 regulations establishing NSPS for new sources and emissions guidelines for existing sources,\290\ the EPA's regulatory approach has been to apply a rule of reason in determining which air pollutants and which source categories to regulate. This approach is consistent with CAA section 307(d)(9)(A), which provides that promulgation of standards of performance under CAA section 111 is subject to the CAA section 307(d)(9)(A) arbitrary and capricious standard for judicial review. See American Electric Power Co. v. Connecticut, 564 U.S. 410, 424, 427 (2011). For example, in 1977, EPA listed the stationary gas turbine source category,\291\ and proposed standards of performances for NOX and SO2 because the source category emitted those pollutants in large quantities and reasonably priced controls for them

were available, but did not propose standards for HC or CO because those emissions were “relatively low” when the turbines were operated at peak capacity or PM because those emissions were “minimal.” \292\ In 1979, EPA finalized the standards for NOX and SO2.\293\ EPA has similarly applied a rule of reason in determining whether to regulate particular source categories. For example, after enactment in the 1977 CAA Amendments of CAA section 111(f), which directed EPA to list source categories of major stationary sources and promulgate NSPS for them on a specified schedule, EPA promulgated a list of source categories and assigned each one a priority for action. However, EPA noted that “if further study indicates that an NSPS would have little or no effect on emissions, or that an NSPS would be impractical, a source category would be given a lower priority or removed from the list.” \294\

\290\ The EPA first listed source categories and promulgated standards of performance for them in 1971, 36 FR 5931 (March 31, 1971) (listing initial source categories); 36 FR 24876 (December 23, 1971) (promulgating initial standards of performance).

\291\ 42 FR 53657 (October 3, 1977).

\292\ 42 FR 53782, 53783 (October 3, 1977).

\293\ 44 FR 52792 (September 10, 1979). As another example, the EPA promulgated standards for lime manufacturing plants for particulate matter, but not for NOX, CO, or SO2, due to their small amount of emissions or concerns about the available controls. See 42 FR 22056, 22507 (May 3, 1977); Nat'l Lime Ass'n, 627 F.2d at 426 & n.27.

\294\ 44 FR 49223 (August 21, 1979).

In applying a standard of reasonableness here, the EPA anticipates that the business-as-usual BSERs and presumptive standards finalized in the 2024 CPS would result in little to no emission reductions, while at the same time the development of state plans involves an expenditure of resources by States and regulated entities, including time and money for developing compliance strategies, conducting public hearings and meaningful engagement, drafting permits or other legal instruments, and getting necessary legislative or other approvals.\295\ Therefore, the pragmatic considerations outweigh any potential regulatory benefit: requiring state plans to address only these sources at the same time the Agency is repealing the requirements for all other existing sources, and when the BSERs and presumptive standards of performance in the 2024 CPS would not, in general, have resulted in changes in operations or emissions, would not be reasonable.\296\ Thus, the EPA is finalizing the repeal of the requirements of the emission guidelines pertaining to natural gas- and oil-fired steam generating units.

\295\ The EPA's Information Collection Request analysis for the emission guidelines promulgated in the CPS indicates that developing state plans (and negative declarations) would entail a collective cost to the 48 States subject to the rule of approximately $35 million over three years. See Document ID No. EPA-HQ-OAR-2023-0072- 8836.

\296\ One commenter asserted that the presumptive standards of performance, which the EPA determined in the CPS, may not be appropriate given how oil and natural gas-fired steam generating units may operate in the future. Comments of Talen Energy at 16-17, Document ID No. EPA-HQ-OAR-2025-0124-0904. Although the EPA is not repealing the emission guidelines for these sources on the basis of the achievability of the presumptive standards of performance, the Agency does note this concern.

Moreover, as discussed in this section of the preamble, the EPA is simultaneously issuing a supplemental proposal soliciting comment on additional reasons beyond those on which the EPA solicited comment in the primary proposal in the June 2025 NPRM to repeal the legal basis for regulating GHG emissions from fossil fuel-fired power plants under CAA section 111. If finalized as proposed, this subsequent action would abrogate the need to regulate GHG emissions from natural gas- and oil- fired steam generating EGUs entirely. If the EPA does not finalize the determination that the Agency lacks authority to regulate GHG emissions from fossil fuel-fired power plants under CAA section 111 as proposed, the EPA would revisit the need for requirements for natural gas- and oil-fired steam generating EGUs. 4. Conclusion

Because the EPA is finalizing the repeal of the BSER determinations and related requirements for existing long-term and medium-term coal- fired steam generating units and is further finalizing the repeal of the requirements for existing oil- and natural gas-fired steam generating units, the Agency is finalizing repeal of the emission guidelines for steam generating units in 40 CFR part 60, subpart UUUUb, in their entirety.

The EPA is finalizing the repeal of the phase 2 CCS-based standards for new base load stationary combustion turbine EGUs in 40 CFR part 60, subpart TTTTa. The EPA's basis for this action is that 90 percent CCS has not been adequately demonstrated, and the costs are not reasonable for new base load combustion turbines. The EPA is finalizing the determination that the CCS-based standards are not achievable as it is unlikely that the infrastructure necessary can be deployed by the January 1, 2032, compliance date. In the June 2025 NPRM, the EPA solicited comment in general on the efficiency-based standards for intermediate load and base load turbines. While the EPA received substantial comments that affected sources may not be able to achieve these standards, the EPA is not addressing these comments at this time. 1. Phase 2 CCS-Based Requirements for New Base Load Combustion Turbines

In the 2024 CPS, the EPA determined the second component of the BSER for new base load combustion turbines to be 90 percent CCS. The EPA determined that 90 percent CCS, including the 90 percent CO2 capture component, was adequately demonstrated based on extrapolation from the evidence for 90 percent CCS on coal-fired steam generating units and additional examples and planned projects on combustion turbines. The EPA also argued the costs were reasonable and that the other considerations for BSER were satisfied. Based on application of the 90 percent CCS BSER to new base load combustion turbines, the EPA established standards of performance and argued these standards were achievable by the compliance date of January 1, 2032, considering the time necessary to deploy capture equipment, transport, and sequestration.

The EPA proposed to repeal the phase 2 CCS-based requirements for new base load combustion turbines based largely on a reassessment of the record underlying the determinations in the 2024 CPS. The EPA proposed that 90 percent CCS is not the BSER for new base load combustion turbines because it has not been adequately demonstrated and the costs are unreasonable. The EPA further proposed that the standards of performance are not achievable because it is unlikely that the infrastructure

(including capture equipment, pipelines for transport, and sequestration sites) for 90 percent CCS for new base load combustion turbines can be deployed by the January 1, 2032, compliance date.

The EPA is finalizing the determination that CCS with 90 percent capture is not the BSER for base load combustion turbine EGUs because it has not been adequately demonstrated and the costs are not reasonable. Furthermore, because it is unlikely that the infrastructure necessary for CCS can be deployed by the January 1, 2032, compliance date, the EPA is finalizing the determination that the associated standards of performance in the 2024 CPS for new base load combustion turbines are not achievable. Consequently, the EPA is finalizing repeal of the phase 2 standards for base load combustion turbine EGUs. a. Adequately Demonstrated

For many of the same reasons described in section IV.A.1.a of this preamble for coal-fired steam generating units, CCS with 90 percent capture has not been adequately demonstrated for new combustion turbine EGUs. The 2024 CPS based the 90 percent capture BSER for new base load combustion turbines on the same capture technology as for coal-fired steam generating units. i. Translation of Experience at Coal-Fired EGUs

The 2024 CPS relied on the translation of amine-based capture at coal-fired EGUs as evidence to support the determination that 90 percent capture on new natural gas-fired combustion turbine EGUs has been adequately demonstrated. However, as noted in section IV.A.1.a of this preamble, the determination for coal-fired EGUs in the 2024 CPS relied on an extrapolation that, on review, fails to show 90 percent capture is adequately demonstrated. Consequently, the EPA has re- assessed the evidence and is finalizing the determination that 90 percent capture and, therefore, 90 percent CCS have not been adequately demonstrated for existing coal-fired steam generating units. Therefore, the record for 90 percent capture on existing coal-fired steam generating units also does not show that 90 percent capture, or 90 percent CCS, is adequately demonstrated for new base load combustion turbine EGUs.

Additionally, the 2024 CPS argued that fewer contaminants (particulates, trace metals, sulfur dioxide (SO2)) in the post-combustion flue gas of natural gas-fired stationary combustion turbines would result in fewer challenges with CO2 capture than those experienced with capture at coal-fired steam generating units. However, the exhaust gas composition for natural gas-fired combustion turbines is different in other ways than for coal-fired units (i.e., lower CO2 concentrations and higher oxygen concentrations), which makes CO2 capture more challenging. Furthermore, combustion turbines can change loads more rapidly and start and stop more frequently than coal-fired steam generating units. These factors could create additional challenges for operating CO2 capture equipment, and demonstrated capture rates from coal-fired EGUs do not necessarily demonstrate that base load combustion turbines could achieve the same capture rates. For example, the startup of the CO2 capture system may be slower than the startup of a combined cycle combustion turbine EGU, so that the system would not capture CO2 emitted during startup. This shows that directly applying the record for CO2 capture at coal- fired EGUs to the evaluation of CO2 capture as adequately demonstrated for natural gas-fired combustion turbine EGUs, without accounting for the differences between these types of units, is inappropriate. ii. Capture Projects on Combustion Turbine EGUs

The examples of CO2 capture applied directly on combustion turbine EGUs are also insufficient to conclude that 90 percent capture has been adequately demonstrated. Primarily, there have been limited examples of applications of CCS to combustion turbine EGUs, none of which have been at sufficient scale to demonstrate the specified BSER based on a 90 percent total capture efficiency.

In the 2024 CPS, the argument that 90 percent capture was adequately demonstrated at combustion turbine EGUs relied in part on the capture plant at the Bellingham combined cycle turbine.\297\ This capture plant was only 40 MWe, which is smaller than most base load combined cycle turbine EGUs that would have potentially been subject to the requirements of that rule, and processed only approximately 10 percent of the maximum flue gas volume. The project began operation in 1991 before shutting down in 2005 after the host combined cycle unit switched to peak shaving operation.\298\ Publicly available data for this project is limited, so that the performance cannot be accurately assessed. The EPA otherwise cited pilot studies.\299\ However, such short-duration demonstrations may not be subject to the same variations in conditions that occur in commercial operation. Boundary Dam Unit 3 remains the only relevant commercial scale attempt at applying 90 percent CCS on a fossil fuel-fired power plant. Reasonable extrapolation from the experience at Boundary Dam Unit 3 shows that commercial scale deployments of CO2 capture solvent technologies on post-combustion flue gas of fossil fuel-fired EGUs will underperform. Similar to coal-fired steam generating units, a capture system on a gas-fired combined cycle unit would achieve far less than 90 percent capture.\300\

\297\ 89 FR 39925-26 (May 9, 2024).

\298\ Fluor. The U.S. Carbon Capture and Storage Market. Available at: https://newsroom.fluor.com/featured-stories/blog-details/2025/The-U-S--Carbon-Capture-and-Storage-Market-Fluors-Role-45Qs-Influence-Challenges-for-New-and-Existing-Technologies-and-Which-Projects-Can-Succeed/default.aspx.

\299\ 89 FR 39798, 39927 (May 9, 2024).

\300\ Using the same calculation detailed in section IV.A.1.a.i of this preamble, a system could achieve at best 63 to 82 percent capture.

The EPA also previously cited planned projects.\301\ However, the planned projects are neither operational nor provide measured data. While the equipment for those planned projects may have been designed for 90 or even 95 percent CO2 capture, simply designing a project for a certain percentage capture does not ensure that the project will achieve that percentage capture in practice. Boundary Dam Unit 3 did not achieve its design percentage capture, as detailed in section IV.A.1.a.i of this preamble. Therefore, because those hypothetical projects have not yet produced any data, they do not mitigate the potential underperformance of CO2 capture, and, therefore, are not sufficient to show 90 percent CO2 capture is adequately demonstrated. The EPA also noted the NET Power Cycle (i.e., CO2 capture based on oxy-combustion) as a potential technology for meeting the standard based on 90 percent capture. However, the technology provider has not operated the technology at scale and a planned project is facing delays.\302\ More recently, the technology provider has deprioritized their efforts on oxy-combustion, and acknowledged it requires further development.\303\

Similarly, none of the other projects that the EPA cited have yet commenced construction, either on new NGCC units or on retrofits to existing plants.

\301\ 89 FR 39798, 39927 (May 9, 2024).

\302\ Net Power, Press Release: Net Power Reports Fourth Quarter 2024 Results and Provides Business Update (March 10, 2025). Available at: https://ir.netpower.com/resources/press-releases/detail/37/net-power-reports-fourth-quarter-2024-results-and-provides-business-update.

\303\ Net Power, Press Release: Net Power Reports Third Quarter 2025 Results and Provides Business Update (November 13, 2025). Available at: https://ir.netpower.com/resources/press-releases/detail/44/net-power-reports-third-quarter-2025-results-and-provides-business-update.

Comments: Many commenters agreed with the EPA's proposed determination that 90 percent CCS is not adequately demonstrated for new base load natural gas-fired combustion turbines. Other commenters asserted that 90 percent capture is adequately demonstrated for those sources. Those commenters largely reiterated arguments made in the 2024 CPS, which the EPA has refuted in the preceding sections of this preamble. Those commenters also cited references to some new projects that were not in the record for the 2024 CPS and asserted those projects supported the conclusion that 90 percent CCS has been adequately demonstrated for new base load combustion turbine EGUs. One of the projects cited by commenters was the Ravenna CCS project in Italy, a small-scale capture project at a gas processing facility. Commenters argued this project supported the determination that 90 percent CCS was adequately demonstrated for new base load combustion turbines. Commenters similarly cite small-scale pilot projects, such as the pilot plant at the Himeji No. 2 gas-fired power plant in Japan (five metric tons per day), testing on NGCC flue gas at Los Medanos Energy Center (Contra Costa County, California) (1 MWe), and testing on NGCC flue gas at Technology Centre Mongstad (Mongstad, Norway) (10 MWe). In addition, some commenters cited other projects that are not operational, including the Net Zero Teeside Power project (United Kingdom).

EPA Response: The EPA disagrees with commenters' assertions as those projects are insufficient, for various reasons, to conclude that 90 percent CCS has been adequately demonstrated for base load natural gas-fired combustion turbine EGUs. The EPA finds the Ravenna project is insufficient to conclude 90 percent is adequately demonstrated. The project at Ravenna uses an amine solvent to capture CO2 from the flue gas of a small 5 MW simple cycle combustion turbine, which drives a compressor for natural gas transmission. A heat recovery steam generator produces process steam and renewable generation provides electricity for the capture process. The combustion turbine is therefore not subject to the electricity and steam requirements of the capture process. This is distinct from the premise of the BSER in the 2024 CPS, where the EGU is a combined cycle unit and the capture system uses heat and power from the host EGU, such that changes in operation of the host EGU may impact the capture facility. Moreover, the 2024 CPS applied to units greater than 25 MW, at least five times the size of the project at Ravenna. Considering those factors, the system at Ravenna has limited relevance to the capture system at issue in the 2024 CPS and this action. In addition, from startup in August 2024 through February 2025, the reported monthly average capture efficiency of the treated flue gas (when operating) was 91.8 percent with a peak of 96.1 percent. However, while reports claimed that the GHG emissions of the project were minimal, reports did not specify the amount of flue gas treated relative to the amount emitted from the facility and the amount of time the capture facility was operational. Lacking that information, it is impossible to evaluate the total capture efficiency and the performance of the project in practice. Because of the limited relevance of the Ravenna project to the capture system at issue here, and because of the incomplete information on the performance of the capture system, the EPA concludes that the experience at Ravenna is insufficient to conclude that 90 percent CCS is adequately demonstrated.

Furthermore, for the reasons detailed in section IV.A.1.a.i of this preamble, the EPA reasonably expects that a new capture system would underperform to a similar degree as Boundary Dam Unit 3. Such short term and small-scale projects cited by the commenters are insufficient to mitigate that potential underperformance, and therefore insufficient to show 90 percent capture is adequately demonstrated. Additionally, projects cited by the commenters that are not yet operational have not provided any data on capture performance and are therefore insufficient to that 90 percent capture is adequately demonstrated.

Considering these factors, the EPA is finalizing the determination that CCS with 90 percent capture has not been adequately demonstrated for new base load combustion turbine EGUs. b. Cost

The EPA has re-evaluated the assumptions underlying the cost analysis of 90 percent CCS on new base load combustion turbines and is finalizing the determination that the costs are not reasonable. i. Smaller Combustion Turbines

As part of the phase 1 BSER analysis for combustion turbines, the EPA reviewed the performance and costs of efficient generation for combustion turbines with base load ratings ranging from 490 to 6,100 MMBtu/h. Based on the phase 1 BSER analysis, the EPA established higher emission standards for base load turbines with base load ratings of less than 2,000 MMBtu/h. However, when evaluating the phase 2 BSER based on the use of CCS, the EPA evaluated the reasonableness of the cost based only on combustion turbines with base load ratings of 4,600 and 6,100 MMBtu/h.\304\ The costs of the capture equipment and the costs to transport and store the captured CO2 increase on a $/ton basis for smaller base load combustion turbines. The costs of control on a $/MWh and $/ton basis for the smaller model combustion turbine facilities used in the phase 1 analysis are approximately double the highest costs that the EPA reported in the technical support document. Specifically, the estimated compliance costs for the primary case for the 490 and 1,000 MMBtu/h model combined cycle plants are $73/ MWh and $200/ton and $55/MWh and $140/ton, respectively, which are significantly higher than the highest costs presented in the 2024 CPS-- $19/MWh and $57/ton.\305\ Consequently, the EPA now finds that, in the 2024 CPS, the Agency did not establish that the cost of 90 percent CCS is reasonable for smaller base load combustion turbines.

\304\ The technical support document entitled Greenhouse Gas Mitigation Measures Carbon Capture and Storage for Combustion Turbines included estimated costs for combined cycle turbines with base load ratings of 2,400 and 3,400 MMBtu/h in figures 11 through 13. The costs for the primary case are $29/MWh and $95/ton and $22/ MWh and $75/ton respectively--approximately 50 percent higher than the costs presented in the CPS. Document ID No. EPA-HQ-OAR-2023- 0072-9099.

\305\ See memorandum entitled Updated Evaluation of Best System of Emission Reduction Costs of Carbon Capture and Sequestration/ Storage at New and Reconstructed Natural Gas-Fired Combustion Turbine Electric Generating Units in the docket for this rulemaking (Document ID No. EPA-HQ-OAR-2025-0124).

ii. Operating/Availability, Capacity Factor, and Other Assumptions

Even without factoring in the previously cited omissions, the primary costs of 90 percent CCS for combustion turbines were a best- case scenario.\306\ As described in section IV.A.1 of this preamble, the EPA assumed in the 2024 CPS that capture equipment has 100 percent operating-availability. Reducing the operating-availability of the capture equipment to 75 percent reduces the CO2 emission reductions and increases the cost by approximately $2/MWh and $18/ton compared to the estimated costs

presented in the 2024 CPS.\307\ While CCS may achieve potential CO2 emission reductions, these costs exceed the thresholds that the EPA cited as reasonable in previous Agency rulemakings.

\306\ The EPA discussed multiple advances that could lower the costs of a BSER based on the use of CCS, but currently none of these technologies are commercially available.

\307\ See memorandum entitled Updated Evaluation of Best System of Emission Reduction Costs of Carbon Capture and Sequestration/ Storage at New and Reconstructed Natural Gas-Fired Combustion Turbine Electric Generating Units in the docket for this rulemaking (Document ID No. EPA-HQ-OAR-2025-0124).

In addition, when conducting the BSER analysis, the EPA assumed that the long-term capacity factors of new combined cycle turbines would be the same as historical long-term capacity factors with and without 90 percent CCS (51 percent capacity factor).\308\ In the primary policy case, the EPA compared the costs and emissions impacts assuming a new combined cycle turbine with CCS that operates at an 80 percent capacity factor for the first 12 years and a 31 percent capacity factor for the next 18 years.\309\ The EPA compared the levelized cost of electricity of this model facility to a combined cycle without CCS that operates at a 62 percent capacity factor for the first 12 years, a 47 percent capacity factor for the next 13 years, and a 37 percent capacity factor for the final five years.\310\ However, the capacity factor assumptions in the 2024 CPS do not account for differences in incremental generating cost affecting dispatch. Based on cost information from NETL and EIA's Annual Energy Outlook, and assuming the full value of the IRC section 45Q tax credit, the incremental generating costs of combined cycle turbines with carbon capture are generally higher than those of nuclear EGUs but lower than those of coal-fired EGUs without carbon capture.\311\ While the capacity factors of nuclear EGUs are higher (approximately 90 percent) than the 80 percent used by the EPA, the recent capacity factors of coal-fired EGUs are much lower (approximately 40 percent). While these provide an upper and lower bound of what capacity factors could be from a combined cycle turbine with CCS while the tax credit is available, the EPA selected the upper end of the range without conducting a dispatch analysis. Furthermore, even when counting the full value of the IRC section 45Q tax credit as a reduction, the estimated incremental generating costs of the 490 MMBtu/h combined cycle turbine with carbon capture are higher than the incremental generating costs of the model plant without CCS. Generally, combined cycle facilities without CCS that have recently commenced operation have not maintained capacity factors of 80 percent, this calls the capacity factor assumptions into question for smaller combined cycle facilities with CCS.\312\ Additionally, during periods when the IRC section 45Q tax credit is not available after the 12-year period of the credit has expired, it is unlikely that combined cycle turbines with carbon capture would operate at the 31 percent capacity factor used in the 2024 CPS costing analysis. The incremental generating costs of all the model combined cycle turbines with carbon capture exceed the incremental generating costs of simple cycle turbines. Simple cycle turbines generally operate at capacity factors of less than 10 percent. A dispatch modeling analysis would likely result in lower capacity factors and higher costs, which does not support the costs of 90 percent CCS as reasonable.

\308\ Based on data submitted to the Clean Air Markets Program, the median annual capacity factor of combined cycle turbines begins at a high of 68 percent and steadily declines to 34 percent in year 30. The median 30-year capacity factor is 51 percent. To avoid impacting the costs due to changes in the overall capacity factors with the base case, the EPA kept the overall 30-year capacity factor at the historical average of 51 percent.

\309\ The EPA selected 80 percent to account for the lower variable operating costs when the 45Q tax credits are available. The capacity factor during the final 18 years was adjusted to maintain a 30-year average capacity factor of 51 percent.

\310\ The 62/47/37 operating scenario is based on the averaged reported median capacity factors for combined cycle turbines during the three periods of operation--62 percent during years 1 to 12, 47 percent during years 13 to 25, and 37 percent during years 26 to 30.

\311\ T. Schmitt, S. Leptinsky, M. Turner, A. Zoelle, M. Woods, T. Shultz, and R. James Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 4a, U.S. DOE. National Energy Technology Laboratory (NETL). (October 14, 2022). Available at: https://netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9; Capital Cost and Performance Characteristics for Utility-Scale Electric Power Generating Technologies. U.S. DOE. U.S. Energy Information Administration (EIA). (January 2024). Available at: https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capital_cost_AEO2025.pdf.

\312\ Based on information submitted to the EPA's Clean Air Markets Program Data, the 2025 average annual capacity factor of combined cycle turbines that commenced operation between 2020 and 2024 is 65 percent.

Further, the EPA only conducted the BSER analysis using capacity factors for the average combined cycle facility. The average combined cycle facility has a 30-year capacity factor of 51 percent. On average, new combined cycle facilities operate at a 65 percent capacity factor that steadily decreases to less than 40 percent by year 30. However, a combustion turbine that ever exceeds the base load threshold (40 percent in the 2024 CPS) for a single 12-operating month period would, effectively, have to install 90 percent CCS to comply with the base load emissions standard. Therefore, while the EPA was correct in using the average capacity factor to determine if the costs of 90 percent CCS are reasonable, the maximum 12-calendar month capacity factor is the appropriate value for subcategorization purposes. A base load subcategorization threshold of 65 percent would subject the average combined cycle turbine to the CCS-based BSER. However, the EPA set a base load subcategorization capacity factor threshold of 40 percent. In doing this, the Agency subjects combustion turbines with lifetime capacity factors of less than 51 percent to a 90 percent CCS-based BSER. However, in the 2024 CPS, the EPA did not analyze whether 90 percent CCS qualifies as the BSER at lower capacity factors. For example, the 12-operating month capacity factor will vary over the life of the facility, even assuming a combined cycle facility operates at a relatively constant capacity over the entire 30-year life. If the absolute difference between the maximum 12-operating month and 30-year average capacity factors is five percent, the EPA should have determined whether CCS is the BSER for a combined cycle operating at a 30-year capacity factor of 35 percent. At a capacity factor of 35 percent, the costs of CCS are clearly not reasonable ($36/MWh and $110/ ton), and costs are even higher for smaller units ($56/MWh and $170/ ton).\313\ In addition, if the EPA accounted for both the declining capacity factors as combustion turbines age and the 12-operating month variability, the 30-year capacity factor of a combined cycle turbine with a maximum 12-operating month capacity factor of 40 percent would be less than 35 percent, which calls into question whether the cost of 90 percent CCS at a 40 percent subcategorization threshold is reasonable since the costs are three times higher than the cost ($18.5/ MWh) the EPA previously determined to be reasonable.\314\

\313\ The costs for the combustion turbine model plant with a 6,100 MMBtu/h base load rating is $36/MWh ($110/ton) at a 35 percent capacity factor. The costs for the combustion turbine model plant with a 2,400 MMBtu/h base load rating is $56/MWh ($170/ton) at a 35 percent capacity factor.

\314\ Assuming an initial capacity factor of 40 percent that declines to 22 percent at year 30 results in an overall capacity factor of 30 percent. Costs are similar to the constant 35 percent capacity factor case.

When conducting the BSER analysis, the EPA failed to account for additional factors that would increase the costs of CCS. First, the Agency did not account for lost revenue due to lower capacity

payments that result from the lower net output of combined cycle facilities with CCS relative to combined cycle facilities without CCS.\315\ Assuming a capacity payment of $65/kW, a 1x1 F-class combined cycle facility would lose almost $3 million per year in capacity payments, and a 1x1 H-class combined cycle facility would lose almost $4 million per year in capacity payments.\316\

\315\ The capacity markets pay owners of generating units based on the ability to provide firm power regardless of if any electricity is actually delivered to the electric grid.

\316\ The EPA notes that when the Agency finalized subpart TTTTa, only the most efficient combustion turbines with base load ratings of greater than 850 MMBtu/h would have required the installation of a selective catalytic reduction (SCR) to comply with the criteria pollutant NSPS (subpart KKKK). Less efficient simple cycle turbines could comply with the criteria pollutant NSPS using advanced combustion controls. Since subpart TTTTa is based on the use of the most efficient combustion turbines, the EPA should have accounted for the costs of SCR as part of the BSER evaluation. While the new criteria pollutant NSPS (subpart KKKKa) does not require the use of SCR for any non-base load combustion turbines as a procedural matter, the EPA should have addressed the issue in the final subpart TTTTa rulemaking.

iii. The IRC Section 45Q Tax Credit

As noted above in connection with the costs of CCS for existing coal-fired plants, the 2024 CPS accounted for the IRC section 45Q tax credits by reducing the direct costs to the source for every ton of CO2 captured. However, the EPA no longer believes that counting the IRC section 45Q tax credit as a reduction in determining BSER is appropriate, as discussed in section IV.A.1.b of this preamble. Rather, the tax credit shifts the costs of CCS to taxpayers, and in the 2024 CPS, the EPA failed to account for those costs. Removing the tax credit as a reduction in the costs for the 2024 CPS 90 percent CCS case increases the costs for combustion turbines with base load ratings of 4,600 and 6,100 MMBtu/h to $37/MWh ($110/ton) and $32/MWh ($100/ton), respectively. Even using the 2024 CPS primary model plants, the costs of 90 percent CCS for base load stationary combustion turbines are clearly unreasonable.\317\

\317\ The costs for the 1x1 F-class and 1x1 H-class are $47/MWh ($140/ton) and $39/MWh ($120/ton) respectively.

Consistent with the arguments presented in section IV.A.1.c of this preamble regarding CCS infrastructure for existing coal-fired steam generating units, the necessary infrastructure to meet the requirements for the phase 2 CCS-based requirements for base load combustion turbines cannot likely be deployed by the January 1, 2032, compliance date. While new combustion turbines do not have the additional timeline requirement of state plan development, the timeline in the 2024 CPS for the design, permitting, and installation of capture equipment, pipelines, and sequestration for new combustion turbines assumes an unrealistic best-case scenario. Furthermore, pipeline and sequestration infrastructure remain limited. In the 2024 CPS, the EPA argued that new combustion turbines could site preferentially near potential storage sites. However, the EPA did not consider the availability of sufficient quantities of natural gas or the availability of sufficient transmission capacity (i.e., to transmit power to end users) for new base load combustion turbines specifically located near potential storage sites.\318\ In addition, the analysis ignores the associated line loss (i.e., inefficiency) due to potentially longer transmission lines.\319\ The analysis further ignores the requirements of siting electricity generating sources in locations necessary to meet local grid reliability considerations. Considering these factors, it is unlikely that the infrastructure necessary for CCS can be deployed by the January 1, 2032, compliance date, and the EPA has therefore determined that phase 2 standards of performance in the 2024 CPS for new base load combustion turbines are not achievable. Additionally, similar to coal-fired steam generating units, much of the necessary CCS infrastructure would likely be developed by external parties over whom the owners and operators of regulated facilities have limited control. This complicates deployment and has the potential to cause or exacerbate delays, providing further support for the conclusion that the January 1, 2032, compliance date and the degree of emission limitation are unachievable.

\318\ If a storage site does not have enough available natural gas to fuel a new base load combustion turbine, or enough transmission capacity to deliver the generated electricity to end users, infrastructure would have to be developed prior to the new combustion turbine commencing operation. Developing that infrastructure could result in additional costs to the owner or operator of the new base load combustion turbine.

\319\ Although transmission lines conduct electricity, they have some resistance that results in dissipation of the electrical energy in other forms (e.g., heat). As a result, when transmitted over long distances, the electric energy delivered to an end user is less than the electric energy produced at the generating source (in this case, a stationary combustion turbine).

The EPA is finalizing the determination that 90 percent CCS has not been adequately demonstrated nor shown to have reasonable costs and thus is not the BSER for base load stationary combustion turbines. Furthermore, because it is unlikely that the infrastructure necessary for CCS can be deployed by the January 1, 2032, compliance date, the EPA is finalizing the determination that the phase 2 standards of performance in the 2024 CPS for new base load combustion turbines are not achievable. Accordingly, the Agency is finalizing repeal of the phase 2 requirements for base load combustion turbines. e. Implications for Evaluation of Best Available Control Technology (BACT) for Prevention of Significant Deterioration (PSD) Permitting

Sources subject to 40 CFR part 60, subparts NSPS TTTT and NSPS TTTTa may be subject to a component of the major NSR program known as the PSD program.

Part C of title I of the CAA contains the requirements for the PSD program. This program sets forth procedures for the preconstruction review and permitting of new and modified stationary sources of air pollution locating in areas meeting the NAAQS (“attainment” areas) and areas for which there is insufficient information to classify an area as either attainment or nonattainment (“unclassifiable” areas). Sources subject to PSD must, among other requirements, demonstrate that construction or modification will not cause or contribute to a violation of any NAAQS or PSD increment,\320\ and comply with the emission limitations that reflect the BACT “for each pollutant subject to regulations” under the CAA.\321\ The EPA regulations for the PSD program are contained in 40 CFR 51.166 (applicable to air agencies that issue permits under EPA-approved SIPs) and 40 CFR 52.21 (the federal PSD program applicable to permits issued by the EPA or air agencies to which the EPA has delegated authority to implement the federal PSD program). Most PSD permits are issued by State and local air agencies, subject to federally enforceable rules in State Implementation Plans. There are a smaller number of programs where State, local, or Tribal permitting authorities have delegated federal authority to issue permits on behalf of the EPA or where the EPA directly issues PSD permits.

\320\ CAA section 165(a)(3), 42 U.S.C. 7475(a)(3).

\321\ CAA sections 165(a)(4) and 169(3), 42 U.S.C. 7475(a)(4), 7479(3).

Revisions to the emissions standards in this rulemaking pursuant to CAA

section 111 will impact the minimum requirements of BACT in the PSD program. The BACT requirement is the maximum degree of emission reduction a specific source can achieve on a case-by-case basis considering the energy, environmental, and economic impacts of available control measures. The definition of “best available control technology” in CAA section 169(3) states that, “In no event shall application of `best available control technology' result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 7411 [CAA section 111] or 7412 [CAA section 112] of this title.” \322\ In other words, the CAA specifies that BACT cannot be set at an emission control level that is less stringent than that which any applicable standard of performance under the NSPS requires. An applicable NSPS must always be met and provides a “floor” for the BACT requirement; however, a BACT determination could be more stringent than the NSPS. As such, the GHG emission limits the EPA is repealing in this NSPS rulemaking, including the standards for new base load combustion turbines based on 90 percent CCS, will no longer be the “BACT floor” for GHG emissions from sources in the applicable category. The EPA acknowledges that sources and air agencies have some flexibility in implementation of BACT and may continue to consider certain limits and/or controls that are more stringent than the BACT floor. The EPA acknowledges that changing applicable standards under the NSPS can result in implementation impacts in the context of PSD and BACT. The EPA provides additional discussion in chapter 5.3 of the RTC on implications to BACT for PSD permitting related to the 2024 efficiency-based standards in 40 CFR part 60, subpart TTTTa.

\322\ See also 40 CFR 51.166(b)(12), 52.21(b)(12) (defining BACT).

In the June 2025 NPRM, the EPA broadly solicited comment on the BSER determinations and standards of performance for all new and reconstructed combustion turbines. While the EPA is not finalizing changes to the requirements for new or reconstructed combustion turbines other than removing the phase 2 CCS-based requirements for new base load combustion turbines as discussed in section IV.C.1 of this preamble, the Agency notes that commenters specifically raised several concerns on the achievability of the 2024 efficiency-based standards for new intermediate load and base load combustion turbines. Those comments are summarized in this section of the preamble. Additional comments are summarized in the RTC.

Comments: Several commenters raised concerns over the achievability of the efficiency-based standards for new combustion turbines. Commenters cited issues including the need to account for variability in operating load and ambient conditions affecting performance and that many combustion turbine models that could be intermediate load or base load would be unable to meet the standards. Commenters also raised concerns about the limited availability of combustion turbines that could meet the standards, particularly considering load growth. Commenters also stated that efficiency can degrade over time due to normal wear. Commenters also cited uncertainty in how turbines will operate in the future.

Response: The EPA acknowledges the commenters' concerns regarding the 2024 efficiency-based standards for new combustion turbine EGUs. While the EPA is not repealing or otherwise revising the 2024 efficiency-based standards in this action, the Agency notes that it is simultaneously issuing a supplemental proposal soliciting additional public comment on the underlying question raised in the primary basis of the June 2025 NPRM: Whether the EPA lacks statutory authority to regulate GHG emissions from fossil fuel-fired power plants under CAA section 111. That action, if finalized as proposed, would repeal all GHG standards for the fossil fuel-fired EGU source category, including the 2015 and 2024 GHG standards, and would thus resolve commenters' concerns. 3. Conclusion

Based on the EPA's review of the BSER and the achievability of the standards, and for the reasons detailed in this section of the preamble, the EPA is repealing the 2024 phase 2 CCS-based emission standards finalized in the 2024 CPS for new base load stationary combustion turbines, codified in 40 CFR part 60, subpart TTTTa.

The EPA is determining that it is not necessary to analyze and promulgate alternatives to the repeal of the emission guidelines and standards of performance in this action. The purpose of this rule is to provide near-term relief from the 2024 CPS requirements that the EPA now considers unlawful, infeasible, or otherwise unreasonable. This action is not intended to establish replacement standards. Although CAA section 111 generally requires the EPA to regulate existing sources once the EPA has set standards for new sources, the statute does not require the Agency to do so within a particular timeframe. For that reason, the EPA is not legally obligated to promulgate replacement standards in this rulemaking. Nor is it appropriate to do so, for the following reasons:

First, the EPA's approach in this rulemaking is consistent with the incremental way agencies often proceed, and courts have recognized that agencies may act in steps rather than all at once.\323\ The EPA's decision not to immediately move forward with alternatives is also supported by its simultaneous proposal to find that it lacks authority under CAA section 111 to regulate GHG emissions from fossil fuel-fired power plants. If that proposal is finalized, any replacement BSER determinations, standards of performance, or compliance schedules would become unnecessary. Thus, promulgating alternatives now could prove to be futile and wasteful. If the EPA does not finalize that separate proposal, the Agency could revisit whether alternatives to the standards repealed in this action should be developed and promulgated. For now, however, the EPA believes it is reasonable to proceed without doing so.

\323\ Fox Television Stations, 556 U.S. at 522; see also Pub. Safety Spectrum All., supra (it was reasonable for the FCC to defer making relevant decisions to a subsequent action).

The EPA also notes that it already considered and rejected several alternatives in the 2024 CPS. For long-term coal-fired steam generating units, the EPA evaluated 90 percent CCS, partial CCS at lower capture rates, natural gas co-firing, and heat-rate improvements. The EPA rejected partial CCS because it would produce substantially smaller reductions at higher cost, and because it considered 90 percent CCS achievable. In addition, the IRC section 45Q tax credit might not be available to offset partial CCS costs. In this final rule, the EPA now rejects the conclusion that 90 percent CCS is adequately demonstrated and achievable, and it further concludes that the IRC section 45Q tax credit should not be counted in evaluating the BSER costs of CCS. As a result, the EPA believes partial CCS would be even more expensive than previously thought. The EPA likewise determined

that natural gas co-firing would amount to impermissible generation shifting and therefore cannot serve as BSER. Heat-rate improvements were also rejected because they would provide only limited reductions and could create a rebound effect.

For medium-term coal-fired EGUs, the EPA similarly considered and rejected CCS and heat-rate improvements in the 2024 CPS. That prior analysis reinforces the EPA's conclusion that further consideration of alternatives is unnecessary here. For new baseload combustion turbines, the EPA considered lower-emitting fuels, highly efficient generation, and hydrogen co-firing. The EPA has not changed its prior conclusion that highly efficient generation remains an appropriate BSER for those units. The Agency previously found that lower-emitting fuels would reduce emissions only modestly and that uncertainties about the cost of low-GHG hydrogen prevented the EPA from treating hydrogen as part of the BSER at that time. Taken together, these prior evaluations support the EPA's view that additional alternatives to the repealed standards do not need to be analyzed and promulgated in this rulemaking.

This action is a significant regulatory action under E.O. 12866 section 3(f)(1) that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in the course of E.O. 12866 review have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, Regulatory Impact Analysis for the Final Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units, is available in the docket.

The EPA presents the estimated present value (PV) and equivalent annualized value (EAV) of the projected cost savings for the power sector of this final repeal for the years 2026 to 2047 in 2024 dollars, discounted to 2025. In addition, the EPA presents the results for specific snapshot years, consistent with historical practice. These snapshot years are 2030, 2035, 2040, and 2045. The benefit-cost analysis, which is in the RIA for this rulemaking, is available in the docket.

The analysis considers the power industry's compliance costs as the change in electric power generation costs due to this final repeal. Table 1 presents the estimates of compliance cost savings of this final rule for the power sector.

Table 1--Present Value (PV) and Equivalent Annualized Value (EAV) of the

Compliance Cost Savings

[Billion 2024$, discounted to 2025]

3% Discount rate 7% Discount rate

PV EAV PV EAV

160 10 95 8.6

Note: For the reasons the EPA describes in section 4 of the RIA, the

Agency has not monetized several impact categories, including the

potential health and welfare impacts of changes in emissions.

Therefore, this table does not include those impact categories.

The compliance cost savings in Table 1 are the estimated change in expenditures by the power sector due to this final repeal, which include changes in taxes paid and credits received. The analysis also considers the real resource cost savings due to this final repeal, which are the change in the total avoided cost of resources used by the power sector, which includes capital, labor, fuel, and material inputs, that would have been used for compliance. In contrast to the compliance cost savings in Table 1, the real resource cost savings do not include transfers, such as taxes paid or tax credits, that shift who is paying for the inputs for compliance but do not reduce the social cost. The use of tax credits would have reduced costs from the perspective of firms in the power sector but would have led to a use of resources that are a cost from a societal perspective. These societal costs will now be avoided because of this final action. Over the 2026 to 2047 period, the PV of the estimated real resource cost savings is $280 billion using a three percent discount rate and $180 billion using a seven percent discount rate discounted to 2025. Over this same timeframe, the EAV of the estimated real resource cost is $18 billion using a three percent discount rate, and $16 billion using a seven percent discount rate.

Changes in resources used by the power sector may cause economic interactions in other markets that affect other sectors and households. To evaluate the economy-wide social costs and economic impacts of the action, the EPA used the peer-reviewed CGE model SAGE. The PV of the social cost savings estimated in SAGE for the action is approximately $310 billion (2024 dollars) between 2026 and 2047 (discounted to 2025). The EAV is $23 billion. Note that SAGE does not account for the effects of changing environmental quality as a result of this action. The RIA further describes the methodology and the distinctions between compliance costs, real resource costs, and social costs.

The EPA is obligated to present the agency's best scientific understanding and the implications of that science when developing policies and regulations. However, historically, the EPA's analytical practices may not have presented the full range of uncertainties and associated confidence level regarding the potential benefit estimates from reduction in exposure to particulate matter (PM2.5) and ozone. In addition, the science regarding the exposure, health effects from exposure and valuation of reduction in health effect are evolving with better data and methods, especially at low concentrations of PM and ozone. Some of the sources of uncertainties include the set of assumptions used in projecting the health impact of reducing PM. These projections are based on a series of models that take into account emissions changes, resulting distributions of changes in ambient air quality, the estimated reductions in health effects from changes in exposure, and the composition of the population that will benefit from the reduced exposure. Each component includes assumptions, each with varying degrees of uncertainty.

In addition, the EPA historically provided point estimates rather than just ranges of emission-related effects or only quantifying emissions when monetizing proved to be too uncertain. Therefore, to address these concerns, the EPA is refraining from providing primary estimates resulting from

changes in PM2.5 and ozone exposure resulting from changes in direct PM2.5, NOX and VOC emissions but will continue to quantify the emissions until the Agency is confident enough in the modeling to robustly monetize those impacts.

To illustrate the impacts of the final repeal, including the cost savings of not deploying CCS as a control strategy and the resultant impact on real resource costs through diminished uptake of the IRC section 45Q tax credit, the EPA assumes that 90 percent CCS is allowed in the model's solution set in the modelling supporting the current RIA. However, to illustrate the sensitivity of the results to the viability of 90 percent CCS as a control strategy, the EPA also developed a modeling scenario assuming 90 percent CCS is not allowed in the model's solution set. These model runs and a memorandum describing key results are available in the docket for this action.\324\

\324\ See memorandum entitled “IPM Sensitivity Runs Memo” in the docket for this rulemaking.

The information collection activities in this final action have been submitted for approval to the OMB under the PRA. The EPA is finalizing amendments to the information collection request (ICR) for 40 CFR part 60, subpart UUUUb. Details on the amendments for this subpart are described below. The EPA is not finalizing amendments to the ICRs for 40 CFR part 60, subparts TTTT and TTTTa.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves the ICR, the Agency will announce that approval in the FR and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule. 1. 40 CFR Part 60, Subpart TTTT

This action does not impose any new information collection burden under the PRA. OMB has previously approved the information collection activities contained in the existing regulations and has assigned OMB control number 2060-0685. 2. 40 CFR Part 60, Subpart TTTTa

This action does not impose any new information collection burden under the PRA. 3. 40 CFR Part 60, Subpart UUUUb

The ICR document that the EPA prepared has been assigned EPA ICR number 2770.04. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.

This action repeals requirements on state governments with existing fossil fuel-fired steam generating units. The information collection requirements are based on the recordkeeping and reporting burden reduction associated with developing, implementing, and enforcing a state plan to limit GHG emissions from these existing EGUs.

Respondents/affected entities: States with one or more designated facilities covered under subpart UUUUb.

Respondent's obligation to respond: No longer mandatory.

Estimated number of respondents: 43.

Frequency of response: No response required.

Total estimated burden reduction: 89,000 hours (per year). Burden is defined at 5 CFR 1320.3(b).

Total estimated cost savings: $11.7 million, includes $35,000 annualized capital or operation & maintenance costs.

I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the EPA concludes that the impact of concern for this rule is any significant adverse economic impact on small entities and that the Agency is certifying that this final rule will not have a significant economic impact on a substantial number of small entities because this action relieves regulatory burden on the small entities subject to the rule. Emission guidelines established under CAA section 111(d) do not impose any requirements on regulated entities and, thus, will not have a significant economic impact upon a substantial number of small entities. After emission guidelines are promulgated, States establish emission standards on existing sources, and it is those requirements that could potentially impact small entities. Thus, the repeal of the requirements in the emission guidelines will not impose any requirements on small entities. The repeal of requirements for new, modified, and reconstructed fossil fuel-fired EGUs will relieve regulatory burden on the small entities subject to the rule. As outlined in section 5.3 of the RIA for this rulemaking, the EPA identified 14 potentially affected small entities that own NGCC units considered in the analysis. Under the repeal, the EPA projected compliance cost savings of $143 million for these small entities in 2035. Consequently, the EPA expects that this deregulatory action will relieve the regulatory burden for facilities that, absent this repeal, would be affected by the provisions from the 2024 CPS. As a result, this action will not have a significant economic impact on a substantial number of small entities under the RFA. We have therefore concluded that this action will relieve regulatory burden for all directly regulated small entities.

0 2. Amend Sec. 60.17 by revising paragraph (d)(1) to read as follows:

Sec. 60.17 Incorporations by reference.

* * * * *

(d) * * *

(1) ANSI No. C12.20-2010 American National Standard for Electricity Meters--0.2 and 0.5 Accuracy Classes (Approved August 31, 2010); IBR approved for Sec. Sec. 60.5535(d); 60.5535a(d). * * * * *

Subpart TTTT--Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units

0 3. Revise Sec. 60.5508 to read as follows:

Sec. 60.5508 What is the purpose of this subpart?

This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit or an integrated gasification combined cycle (IGCC) facility that commences construction after January 8, 2014, commences reconstruction after June 18, 2014, or commences modification after January 8, 2014. This subpart also establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction after January 8, 2014, but on or before May 23, 2023, or commences reconstruction after June 18, 2014, but on or before May 23, 2023. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU).

0 4. Amend Sec. 60.5580 by revising the definition of System emergency to read as follows:

Sec. 60.5580 What definitions apply to this subpart?

* * * * *

System emergency means periods when the Reliability Coordinator has declared an Energy Emergency Alert level 2 or 3 which should follow NERC Reliability Standard EOP-011-2, its successor, or equivalent. * * * * *

Subpart TTTTa--Standards of Performance for Greenhouse Gas Emissions for New Construction and Reconstruction Stationary Combustion Turbine Electric Generating Units

0 5. Revise the heading of subpart TTTTa to read as set forth above.

0 6. Revise Sec. 60.5508a to read as follows:

Sec. 60.5508a What is the purpose of this subpart?

This subpart establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction or reconstruction after May 23, 2023. An affected stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU).

0 7. Amend Sec. 60.5509a by: 0 a. Revising the introductory text of paragraph (a); 0 b. Removing and reserving paragraph (b)(1); 0 c. Revising paragraph (b)(4); and 0 d. Removing and reserving paragraph (b)(7).

The revisions read as follows:

Sec. 60.5509a Am I subject to this subpart?

(a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any stationary combustion turbine that commences construction or reconstruction after May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. * * * * *

(b) * * *

(4) Your EGU serves a generator along with other stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each stationary combustion turbine) is 25 MW or less. * * * * *

0 8. Amend Sec. 60.5525a by revising paragraphs (a)(3) and (c)(2) and (3) to read as follows:

Sec. 60.5525a What are my general requirements for complying with this subpart?

* * * * *

(a) * * *

(3) Owners/operators of a base load combustion turbine with a base load rating of less than 2,110 GJ/h (2,000 MMBtu/h) and/or an intermediate or base load combustion turbine burning fuels other than natural gas may elect to determine a site-specific emissions rate using one of the following equations. Combustion turbines firing fuels with a lower CO2 emissions rate than natural gas (e.g., hydrogen) are not required to use the fuel adjustment parameter.

(i) For base load combustion turbines: Equation 2 to Paragraph (a)(3)(i) [GRAPHIC] [TIFF OMITTED] TR17SE26.000

Where:

CO2 emission standard = the emission standard during the compliance period in units of kg/MWh (or lb/MWh). BLERL = Base load emissions standard for natural gas- fired combustion turbines with base load ratings greater than 2,110 GJ/h (2,000 MMBtu/h). 360 kg CO2/MWh-gross (800 lb CO2/MWh-gross) or 370 kg CO2/MWh-net (820 lb CO2/MWh-net). BLERS = Base load emissions standard for natural gas- fired combustion turbines with a base load rating of 260 GJ/h (250 MMBtu/h). 410 kg CO2/MWh-gross (900 lb CO2/ MWh-gross) or 420 kg CO2/MWh-net (920 lb CO2/ MWh-net). BLRL = Minimum base load rating of large combustion turbines 2,110 GJ/h (2,000 MMBtu/h). BLRS = Base load rating of smallest combustion turbine 260 GJ/h (250 MMBtu/h). BLRA = Base load rating of the actual combustion turbine in GJ/h (or MMBtu/h). HIERA = Heat input-based emissions rate of the actual fuel burned in the combustion turbine (lb CO2/MMbtu). Not to exceed 69 kg/GJ (160 lb CO2/MMBtu). HIERNG = Heat input-based emissions rate of natural gas 50 kg/GJ (120 lb CO2/MMBtu).

(ii) For intermediate load combustion turbines: Equation 3 to Paragraph (a)(3)(ii) [GRAPHIC] [TIFF OMITTED] TR17SE26.001

Where:

CO2 emission standard = the emission standard during the compliance period in units of kg/MWh (or lb/MWh). ILER = Intermediate load emissions rate for natural gas-fired combustion turbines. 530 kg/MWh-gross (1,170 lb CO2/MWh- gross) or 540 kg CO2/MWh-net (1,190 lb CO2/ MWh-net). HIERA = Heat input-based emissions rate of the actual fuel burned in the combustion turbine (lb CO2/MMBtu). Not to exceed 69 kg/GJ (160 lb CO2/MMBtu). HIERNG = Heat input-based emissions rate of natural gas 50 kg/GJ (120 lb CO2/MMBtu). * * * * *

(c) * * *

(2) For a reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as defined in Sec. 60.5580a) after the calendar month in which emissions reporting is required to begin under Sec. 60.5555a(c)(3)(iii).

(3) Emissions of CO2 emitted by your affected facility and the output of the affected facility generated when it operated during a system emergency as defined in Sec. 60.5580a are excluded for both applicability and compliance with the relevant standards of performance if you can sufficiently provide the documentation listed in Sec. 60.5560a(i). The relevant standard of performance for affected EGUs that operate during a system emergency depends on the subcategory, as described in paragraph (c)(3)(i) of this section.

(i) For intermediate and base load combustion turbines that operate during a system emergency, you must comply with the standard for low load combustion turbines specified in table 1 to this subpart.

(ii) [Reserved]

0 9. Amend Sec. 60.5535a by revising paragraphs (b)(1) and (g) to read as follows:

Sec. 60.5535a How do I monitor and collect data to demonstrate compliance?

* * * * *

(b) * * *

(1) For affected EGUs, you may install, certify, operate, maintain, and calibrate a CO2 continuous emission monitoring system (CEMS) to directly measure and record hourly average CO2 concentrations in the affected EGU exhaust gases emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, according to 40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of CO2 concentration, provided that your EGU does not use carbon separation (e.g., carbon capture and storage), you may use data from a certified oxygen (O2) monitor to calculate hourly average CO2 concentrations, in accordance with 40 CFR 75.10(a)(3)(iii). If you measure CO2 concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to 40 CFR 75.11(b). Alternatively, you may either use an appropriate fuel-specific default moisture value from 40 CFR 75.11(b) or submit a petition to the Administrator under 40 CFR 75.66 for a site-specific default moisture value. * * * * *

(g) In accordance with Sec. Sec. 60.13(g) and 60.5520a if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this

section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO2 mass emissions and the “stack operating time” (as defined in 40 CFR 72.2) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in table 1 to this subpart by summing the CO2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU.

0 10. Amend Sec. 60.5540a by: 0 a. Revising paragraphs (a)(5)(i) and (a)(8); and 0 b. Removing paragraph (c).

The revisions read as follows:

Sec. 60.5540a How do I demonstrate compliance with my CO2 emissions standard and determine excess emissions?

(a) * * *

(5) * * *

(i) Calculate Pgross/net for your affected EGU using the following equation. All terms in the equation must be expressed in units of MWh. To convert each hourly gross or net energy output (consistent with Sec. 60.5520a) value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time. Equation 1 to Paragraph (a)(5)(i) [GRAPHIC] [TIFF OMITTED] TR17SE26.002

Where:

Pgross/net = In accordance with Sec. 60.5520a, gross or net energy output of your affected EGU for each valid operating hour (as defined in paragraph (a)(1) of this section) in MWh. (Pe)ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (Pe)IE = Electric energy output plus mechanical energy output (if any) of your affected EGU's integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe)A = Electric energy used for any auxiliary loads in MWh. Not applicable for determining Pgross. (Pt)PS = Useful thermal output of steam (measured relative to standard ambient temperature and pressure (SATP) conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. (Pt)HR = Non steam useful thermal output (measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. (Pt)IE = Useful thermal output (relative to SATP conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh. TDF = Electric Transmission and Distribution Factor of 0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating-month rolling average basis, or 1.0 for all other affected EGUs. * * * * *

(8) You may exclude CO2 mass emissions and output generated from your affected EGU from your calculations for hours during which the affected EGU operated during a system emergency, as defined in Sec. 60.5580a, if you can provide the information listed in Sec. 60.5560a(i). While operating during a system emergency, your compliance determination depends on your subcategory or unit type, as listed in paragraph (a)(8)(i) of this section.

(i) For affected combustion turbines in the intermediate or base load subcategory, your CO2 emission standard while operating during a system emergency is the applicable emission standard for low load combustion turbines.

(ii) [Reserved] * * * * *

0 11. Amend Sec. 60.5555a by: 0 a. Revising paragraphs (a)(2)(v) and (c)(3)(iii); and 0 b. Removing paragraphs (f) and (g).

The revisions read as follows:

Sec. 60.5555a What reports must I submit and when?

(a) * * *

(2) * * *

(v) Consistent with Sec. 60.5520a, the CO2 emissions standard (as identified in table 1 to this subpart) with which your affected EGU must comply; and * * * * *

(c) * * *

(3) * * *

(iii) For reconstructed units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energy output data. * * * * *

0 12. Amend Sec. 60.5560a by revising paragraph (f) to read as follows:

Sec. 60.5560a What records must I maintain?

* * * * *

(f) You must keep records of the calculations you performed to assess compliance with each applicable CO2 mass emissions standard in table 1 to this subpart. * * * * *

0 13. Amend Sec. 60.5580a by: 0 a. Removing the definition of Coal-fired Electric Generating Unit; 0 b. Revising the definitions of Electric Generating Units or EGU and Gross energy output; 0 c. Removing the definition of Integrated gasification combined cycle facility or IGCC; and 0 d. Revising the definitions of Intermediate load combustion turbine, Low load combustion turbine, Net-electric sales, and System emergency.

The revisions read as follows:

Sec. 60.5580a What definitions apply to this subpart?

* * * * *

Electric Generating Units or EGU means any stationary combustion turbine that is subject to this rule (i.e., meets the applicability criteria). * * * * *

Gross energy output means:

(1) For stationary combustion turbines, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output.

(2) [Reserved]

(3) For combined heat and power facilities, where at least 20.0 percent of

the total gross energy output consists of useful thermal output on a 12-operating-month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps, that difference divided by 0.95, plus 100 percent of the useful thermal output. * * * * *

Intermediate load combustion turbine means a stationary combustion turbine that is not a low load or base load combustion turbine. An intermediate load combustion turbine supplies more than 20 percent of its potential electric output as net-electric sales on both a 12- operating month and a 3-year rolling average basis and supplies 40 percent or less of its potential electric output as net-electric sales on either a 12-operating month or a 3-year rolling average basis. * * * * *

Low load combustion turbine means a stationary combustion turbine that supplies 20 percent or less of its potential electric output as net-electric sales on either a 12-operating month or a 3-year rolling average basis. * * * * *

Net-electric sales means:

(1) The gross electric sales to the utility power distribution system minus purchased power; or

(2) For combined heat and power facilities, where at least 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating month basis, the gross electric sales to the utility power distribution system minus purchased power and the applicable percentage of purchased power of the thermal host facility or facilities. The applicable percentage of purchased power for CHP facilities is determined based on the percentage of the total thermal load of the host facility supplied to the host facility by the CHP facility. For example, if a CHP facility serves 50 percent of a thermal host's thermal demand, the owner/operator of the CHP facility would subtract 50 percent of the thermal host's electric purchased power when calculating net-electric sales.

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.

(4) Electric sales during a system emergency are not included when calculating net-electric sales. * * * * *

System emergency means periods when the Reliability Coordinator has declared an Energy Emergency Alert level 2 or 3 which should follow NERC Reliability Standard EOP-011-2, its successor, or equivalent. * * * * *

0 14. Revise table 1 to subpart TTTTa to read as follows:

Table 1 to Subpart TTTTa of Part 60--CO2 Emission Standards for Affected

Stationary Combustion Turbines That Commenced Construction or

Reconstruction After May 23, 2023 (Gross or Net Energy Output-Based

Standards Applicable as Approved by the Administrator)

[Note: Numerical values of 1,000 or greater have a minimum of 3

significant figures and numerical values of less than 1,000 have a

minimum of 2 significant figures]

Affected EGU category CO2 emission standard

Base load combustion turbines 360 to 560 kg CO2/MWh (800 to 1,250 lb

CO2/MWh) of gross energy output; or 370

to 570 kg CO2/MWh (820 to 1,280 lb CO2/

MWh) of net energy output as determined

by the procedures in Sec. 60.5525a. Intermediate load combustion 530 to 710 kg CO2/MWh (1,170 to 1,560 lb

turbines. CO2/MWh) of gross energy output; or 540

to 720 kg CO2/MWh (1,190 to 1,590 lb CO2/

MWh) of net energy output as determined

by the procedures in Sec. 60.5525a. Low load combustion turbines. Between 50 to 69 kg CO2/GJ (120 to 160 lb

CO2/MMBtu) of heat input as determined

by the procedures in Sec. 60.5525a.

Table 2 to Subpart TTTTa of Part 60 [Removed and Reserved]

0 15. Remove and reserve table 2 to subpart TTTTa.

0 16. Revise table 3 to subpart TTTTa to read as follows:

Table 3 to Subpart TTTTa of Part 60--Applicability of Subpart A of This Part to This Subpart

Applies to subpart

General provisions citation Subject of citation TTTTa Explanation

Sec. 60.1....................... Applicability........... Yes.................... Sec. 60.2....................... Definitions............. Yes.................... Additional terms defined

in Sec. 60.5580a. Sec. 60.3....................... Units and Abbreviations. Yes.................... Sec. 60.4....................... Address................. Yes.................... Does not apply to

information reported

electronically through

ECMPS. Duplicate

submittals are not

required. Sec. 60.5....................... Determination of Yes....................

construction or

modification. Sec. 60.6....................... Review of plans......... Yes.................... Sec. 60.7....................... Notification and Yes.................... Only the requirements to

Recordkeeping. submit the notifications

in Sec. 60.7(a)(1) and

(3) and to keep records

of malfunctions in Sec.

60.7(b), if applicable. Sec. 60.8(a).................... Performance tests....... No..................... Sec. 60.8(b).................... Performance test method Yes.................... Administrator can approve

alternatives. alternate methods. Sec. 60.8(c)-(f)................ Conducting performance No.....................

tests.

Sec. 60.9....................... Availability of Yes....................

Information. Sec. 60.10...................... State authority......... Yes.................... Sec. 60.11...................... Compliance with No.....................

standards and

maintenance

requirements. Sec. 60.12...................... Circumvention........... Yes.................... Sec. 60.13 (a)-(h), (j)......... Monitoring requirements. No..................... All monitoring is done

according to part 75. Sec. 60.13 (i).................. Monitoring requirements. Yes.................... Administrator can approve

alternative monitoring

procedures or

requirements. Sec. 60.14...................... Modification............ No..................... Sec. 60.15...................... Reconstruction.......... Yes.................... Sec. 60.16...................... Priority list........... No..................... Sec. 60.17...................... Incorporations by Yes....................

reference. Sec. 60.18...................... General control device No.....................

requirements. Sec. 60.19...................... General notification and Yes.................... Does not apply to

reporting requirements. notifications under Sec.

75.61 of this chapter

or to information

reported through ECMPS.