Technical Support Document (TSD) for the Final Federal Good Neighbor Plan for the 2015 Ozone National Ambient Air Quality Standards Docket ID No. EPA-HQ-OAR-2021-0668 Resource Adequacy and Reliability Analysis Final Rule TSD U.S. Environmental Protection Agency Office of Air and Radiation March 2023 ------- This document supports the EPA's final Federal Good Neighbor Plan for the 2015 Ozone National Ambient Air Quality Standards and describes projected resource adequacy and reliability impacts of the final rule. As used here, the term resource adequacy is defined as the provision for adequate generating resources to meet projected load and generating reserve requirements in each power region1, while reliability includes the ability to deliver the resources to the loads, such that the overall power grid remains stable. This document is meant to serve as a resource adequacy assessment of the impacts of the final rule and how projected outcomes under the final rule compare with projected baseline outcomes in the absence of the IRA. The final rule establishes emissions-trading budgets for electric generating units (EGUs) in the covered states. The stringency of these budgets is set through assuming the installation and/or optimization of various conventional nitrogen oxides (NOx) emissions control technologies. Covered sources would therefore be able to comply with the rule with these technologies and are not required to reduce utilization or shift generation. Nonetheless, in light of the transition of the power sector toward lower-emitting generating resources, as highlighted by commenters, it is anticipated that EGU owners and operators may pursue alternative compliance strategies. Should those strategies involve the curtailment or retirement of existing generating resources, commenters have separately raised concerns that this could impact the reliability of the power grid. While such potential impacts would not be a direct result of this rule but rather of the compliance choices source owners and operators may pursue, we have analyzed whether the projected effects of the rule would in this regard pose a risk to resource adequacy, a key planning metric that informs grid reliability. It is important to recognize that the final rule provides multiple flexibilities that preserve the ability of responsible authorities to maintain electric reliability. For more detail on how the final rule addresses reliability concerns, see Section VI of the final rule preamble. The results presented in this document show that the projected impacts of the final rule on power system operations, under conditions preserving resource adequacy, are modest and manageable. The results presented in this document further demonstrate, for the specific cases illustrated in the Regulatory Impact Analysis (RIA), that the implementation of this rule can be achieved without undermining resource adequacy or reliability. The focus of the analysis is on comparing the illustrative final rule scenario from the RIA to a base case (absent the rule requirements) that is assumed to be adequate and reliable. In this framework, the emphasis is on the incremental changes in the power system that are projected to occur under the presence of the rule in the 2023, 2025 and 2030 model run years. The EPA uses the Integrated Planning Model (IPM) to project likely future electricity market conditions with and without the proposed rule.2 IPM's least-cost dispatch solution is designed to ensure generation resource adequacy, either by using existing resources or through the construction of new resources. IPM addresses reliable delivery of generation resources for the delivery of electricity between the 78 IPM regions, based on current and planned transmission capacity, by setting limits to the ability to 1 As analyzed in this document, power regions correspond to aggregates of IPM regions corresponding to NERC assessment areas. 2 See final rule Regulatory Impact Analysis for more detail on the power sector impacts of the final rule. ------- transfer power between regions using the bulk power transmission system. Within each model region, IPM assumes that adequate transmission capacity exists to deliver any resources located in, or transferred to, the region. This document focusses on key regional results important to management of the power system. For a more complete presentation of the projected power sector impacts of the proposed rule, see the Regulatory Impact Analysis. Overview This rule establishes NOx emissions budgets requiring fossil fuel-fired power plants (EGUs) in 22 states to participate in an allowance-based ozone season (May 1 through September 30) trading program beginning in 2023. The EGUs covered by the FIPs and subject to the budget are fossil-fired EGUs with >25-megawatt (MW) capacity. For details on the derivation of these budgets, please see Section V.C. of the preamble. This TSD uses the same scenarios and years of analysis contained in the RIA.3 The scenarios include a base case, and the final rule scenario. For purposes of this resource adequacy and reliability assessment, estimates and projections are taken from those same scenarios and years as shown in the RIA (2023, 2025, and 2030). Summary of Changes in Operational Capacity Total operational capacity remains similar between the base and policy scenarios. The model is constrained to disallow any incremental retirements, retrofits or builds beyond those that occur in the base case in 2023. This constraint is relaxed in future years. Operational generating capacity4 changes from the base case in 2025 are summarized below: Table 1. Operational Capacity Summary (2023, 2025, 2030) Capacity (GW) 2023 2025 2030 Base Case Operational Capacity 1,211 1,209 1,262 Minus Retirements Coal 0.0 -1.5 -12.9 Oil/Gas 0.0 -0.1 -0.1 NGCC 0.0 0.0 0.0 NGCT 0.0 0.0 0.0 Nuclear 0.0 0.0 0.5 Plus Additions NGCC 0.0 0.0 0.0 NGCT 0.0 0.3 9.0 Wind 0.0 0.0 0.3 Solar 0.0 3.0 3.0 Storage 0.0 0.0 0.0 Other 0.0 0.0 0.0 Policy Case Operational Capacity 1,211 1,211 1,261 3 See Chapter 4 of the RIA for additional details on the scenarios examined. 4 Operational capacity is any existing, new or retrofitted capacity that is not retired. ------- Since the model must maintain adequate reserves in each region, projected retirements must be offset by reliance on existing baseline excess reserves, incremental builds, and the ability to shift transmission flows between regions in response to changing generation mix. In response to tightening budgets, a first wave of incremental coal retirements is projected to occur in the model's 2025 run year5 (which includes representation of calendar year 2026 by which the final rule begins incorporating SCR-retrofit-related emission reduction potential into emission budgets), offset by increases in solar and NGCT builds. In 2030, the model projects that a larger wave of large coal units lacking SCR elect to retire in lieu of retrofitting SCR when subject to the tighter emission budgets and the backstop rate; this retiring capacity is offset primarily by incremental NGCT and builds. Reserve Requirements IPM uses a target reserve margin in each region6 as the basis for determining how much capacity to keep operational in order to preserve resource adequacy. IPM retires capacity if it is no longer needed to provide energy for load or to provide capacity to meet reserve margin during the planning horizon of the projections. Since current regional reserves may be higher than the target reserve margin for a region, IPM may retire reserve capacity if it is not economic to use it to maintain adequate reserve margins. Existing resources may also be more expensive, compared to alternatives such as building new capacity or transferring capacity from another region. As a result, some of the plants that are projected to retire will not need to be replaced. Because some existing plants eventually retire in most regions, and IPM builds no more than what it needs to maintain a target reserve margin in each region, the actual reserve margins tend to approach the target reserve margins over time. For details on projected reserve margins under the base and policy scenarios, please see Appendix A-3, B-3 and C-3.7 Changes in Retirements and New Capacity Additions under the Final Rule The incremental retirements in the final rule case are shown above in Table 1; the 13 GW of retirements in 2030 are in addition to 69 GW of coal and 15 GW of oil/gas retirements already occurring in the base case. By 2030, the final rule scenario as compared to the base case leads to higher levels of overall existing coal retirements and new capacity additions (shown regionally in Table A5, B5 5 IPM uses model years to represent the full planning horizon being modeled. By mapping multiple calendar years to a run year, the model size is kept manageable. For this analysis, IPM maps the calendar year 2023 to run year 2023, calendar years 2024-2026 to run year 2025 and calendar years 2027-2029 to run year 2028. For model details, please see Chapter 2 of the IPM documentation, available at: https://www.epa.gov/system/files/documents/2021 -09/epa-platform-v6-summer-2021 -reference-case-09-11-21- v6.pdf. 6 In IPM, reserve margins are used to represent the reliability standards that are in effect in each NERC region. Individual reserve margins for each NERC region are derived from reliability standards in NERC's electric reliability reports. The IPM regional reserve margins are imposed throughout the entire time horizon. 7 See maps of IPM regions and NERC Assessment Regions, and the table of target and projected reserve margins in Appendix D. IPM regions are based on the regions NERC uses for regional assessments. These regions are used for the Appendix tables in this document ------- and C5). Renewable additions are higher under the policy case. The largest increases in new capacity are in NGCT (9 GW), followed by solar and wind (3 GW). These retirements and additions in the projections are the result of the model's optimization of economic planning for energy and capacity needs ; they do not represent required outcomes for any individual units, which will be able to consider multiple compliance options in response to the final rule. In particular, new additions in a base case scenario that do not occur in the policy scenario projections might, in reality, be retained under a policy if local reliability conditions rendered this development the most appropriate choice. This rule does not prevent generation owners from shifting retirements and additions among specific sources to ensure reliability in such circumstances. Reserve Transfers In cases where it is economic to transfer reserves from a neighboring region, rather than supply reserves from within a region, IPM will transfer reserves, subject to summer and winter limits that are designed to ensure that these reserves can be transferred reliably. The transfer of reserves can occur, for example, if a region retires capacity that was used in the base case to meet reserve requirements, but a neighboring region has lower cost reserves that are not needed for its own reserve requirements. To examine these transfers, the EPA analyzed the change in net transfers from each region, where the net transfer for the base and policy cases is measured by the reserves sent to neighboring regions. In these cases, a positive value signifies the reserve capacity sent to other regions is larger than the reserve capacity received from other regions (sending and receiving regions can be different), while a negative value signifies that the capacity received is larger than the capacity sent. Thus, the value measures the degree to which resources in the region were reserved for use by other regions (positive value), or where the capacity to meet load in the region was served by resources in other regions (negative value). In each case these reserve transfers represent the use of the transmission system on a firm basis for at least a season. To look at the projected impact of the policy case on transfers, the measure used was the change in the summer reserves sent in the policy case compared to the base case. To develop a relative measure of the impact of the policy, the change in reserves was measured as a percentage of load in the sending region. This percentage gives an indication of the significance of the policy for changes in the grid. In general, the percentage changes in the final rule are below 2%. For details on projected transfers under the base and policy scenarios, please see Appendix A-6, B-6 and C-6. ------- Appendix A: Tables by IPM Region for Final Rule in 2023 (Note: All Results Cumulative through Projection Year) Al. Projected Operational Capacity in GW (2023) Region All generation sources Base Policy Change from Base Coal Only Base Policy Change from Base US 1,211 1,211 0 192 192 0 ERCOT 132 132 0 14 14 0 FRCC 64 64 0 5 5 0 MISO - South 45 45 0 7 7 0 MISO - North 48 48 0 11 11 0 MISO - Central 85 85 0 31 31 0 ISONE 44 44 0 1 1 0 NYISO 45 45 0 0 0 0 PJM 207 207 0 38 38 0 SERC 183 183 0 43 43 0 SPP 94 94 0 21 21 0 WECC - non CAISO 183 183 0 22 22 0 CAISO 82 82 0 0 0 0 A2. Summary of Summer Peak Loads and Reserve Capacity in GW (2023) Projected Reserve Margins Region Peak Demand Base Peak Demand Policy Reserve Capacity Base Reserve Capacity Policy US 783 783 958 958 ERCOT 72 72 83 83 FRCC 48 48 60 60 MISO South 35 35 43 43 MISO North 26 26 30 30 MISO - Central 65 65 76 76 ISONE 25 25 34 34 NYISO 33 33 38 38 PJM 147 147 184 184 SERC 135 135 170 170 SPP 52 52 61 61 WECC - non CAISO 94 94 121 121 CAISO 50 50 57 57 ------- A3. Summary of Target and Projected Reserve Margin % (2023) Region Target Reserve Margin Base Case Policy Case Policy % Above Margin Policy Change from Base US 15% 22% 22% 7% 0% ERCOT 14% 15% 15% 2% 0% FRCC 19% 26% 26% 7% 0% MISO - South 17% 24% 24% 7% 0% MISO - North 17% 17% 17% 0% 0% MISO - Central 17% 17% 17% 0% 0% ISONE 18% 36% 36% 18% 0% NYISO 15% 15% 15% 0% 0% PJM 16% 25% 25% 9% 0% SERC 15% 25% 26% 11% 0% SPP 12% 18% 18% 6% 0% WECC - non CAISO 14% 28% 28% 15% 0% CAISO 14% 14% 14% 0% 0% A4. Policy Case Retired Capacity Incremental to Base Case in GW (2023) Region CC Coal CT Nuclear OG Steam Total US 0 0 0 0 0 0 ERCOT 0 0 0 0 0 0 FRCC 0 0 0 0 0 0 MISO - South 0 0 0 0 0 0 MISO - North 0 0 0 0 0 0 MISO - Central 0 0 0 0 0 0 ISONE 0 0 0 0 0 0 NYISO 0 0 0 0 0 0 PJM 0 0 0 0 0 0 SERC 0 0 0 0 0 0 SPP 0 0 0 0 0 0 WECC - non CAISO 0 0 0 0 0 0 CAISO 0 0 0 0 0 0 ------- A5. New Capacity in Policy Case Incremental to Base Case in GW (2023) Region CC CT Wind Solar Storage Other Total US 0 0 0 0 0 0 0 ERCOT 0 0 0 0 0 0 0 FRCC 0 0 0 0 0 0 0 MISO - South 0 0 0 0 0 0 0 MISO - North 0 0 0 0 0 0 0 MISO - Central 0 0 0 0 0 0 0 ISONE 0 0 0 0 0 0 0 NYISO 0 0 0 0 0 0 0 PJM 0 0 0 0 0 0 0 SERC 0 0 0 0 0 0 0 SPP 0 0 0 0 0 0 0 WECC - non CAISO 0 0 0 0 0 0 0 CAISO 0 0 0 0 0 0 0 A6. Net Reserves Sent by NERC Assessment Region in GW (2023) Region Base Policy Change from Base to Policy Change as a percent of summer peak US 1.2 1.2 0.1 0% ERCOT 0.2 0.2 0.0 0% FRCC 0.0 0.0 0.0 0% MISO - South 1.1 1.1 0.0 0% MISO - North -1.0 -1.0 0.0 0% MISO - Central -0.6 -0.6 0.0 0% ISONE 0.2 0.3 0.1 0% NYISO 0.0 0.0 0.0 0% PJM 2.5 2.8 0.3 0% SERC -1.5 -1.8 -0.3 0% SPP 0.0 -0.1 0.0 0% WECC - non CAISO 3.9 3.9 0.0 0% CAISO -3.6 -3.6 0.0 0% ------- Appendix B: Tables by IPM Region for Final Rule in 2025 (Note: All Results Cumulative through Projection Year) Bl. Projected Operational Capacity in GW (2025) Region All generation sources Change Coal Only Change Base Policy from Base Base Policy from Base US 1,209 1,211 2 146 145 -1 ERCOT 139 139 0 13 13 0 FRCC 63 63 0 3 3 0 MISO - South 43 44 1 6 6 -1 MISO - North 50 50 0 10 10 0 MISO - Central 87 87 0 22 22 0 ISONE 43 43 0 0 0 0 NYISO 48 48 0 0 0 0 PJM 208 208 0 26 26 0 SERC 174 175 1 31 32 0 SPP 91 91 0 19 19 0 WECC - non CAISO 181 182 0 14 14 0 CAISO 82 82 0 0 0 0 B2. Summary of Summer Peak Loads and Reserve Capacity in GW (2025) Projected Reserve Margins Region Peak Peak Reserve Reserve Demand Demand Capacity Capacity Base Policy Base Policy US 790 790 917 918 ERCOT 72 72 82 82 FRCC 48 48 58 58 MISO South 35 35 41 42 MISO North 26 26 30 30 MISO - Central 65 65 77 76 ISONE 25 25 32 32 NYISO 33 33 38 38 PJM 148 148 174 174 SERC 137 137 158 158 SPP 53 53 59 59 WECC - non CAISO 96 96 109 109 CAISO 51 51 58 58 ------- B3. Summary of Target and Projected Reserve Margin % (2025) Region Target Reserve Margin Base Case Policy Case Policy % Above Margin Policy Change from Base US 15% 16% 16% 1% 0% ERCOT 14% 14% 14% 0% 0% FRCC 19% 21% 21% 2% 0% MISO - South 17% 17% 19% 3% 2% MISO - North 17% 17% 17% 0% 0% MISO - Central 17% 17% 17% 0% 0% ISONE 18% 27% 27% 9% 0% NYISO 15% 15% 15% 0% 0% PJM 16% 18% 18% 2% 0% SERC 15% 15% 15% 0% 0% SPP 12% 13% 13% 1% 0% WECC - non CAISO 14% 14% 14% 0% 0% CAISO 14% 14% 14% 0% 0% B4. Policy Case Retired Capacity Incremental to Base Case in GW (2025) Region CC Coal CT Nuclear OG Steam Total US 0.0 1.5 0.0 0.0 0.1 1.6 ERCOT 0.0 0.4 0.0 0.0 0.0 0.4 FRCC 0.0 0.0 0.0 0.0 0.0 0.0 MISO - South 0.0 0.6 0.0 0.0 0.1 0.6 MISO - North 0.0 0.0 0.0 0.0 0.0 0.0 MISO - Central 0.0 0.3 0.0 0.0 0.0 0.3 ISONE 0.0 0.0 0.0 0.0 0.0 0.0 NYISO 0.0 0.0 0.0 0.0 0.0 0.0 PJM 0.0 0.3 0.0 0.0 -0.1 0.2 SERC 0.0 0.0 0.0 0.0 0.1 0.1 SPP 0.0 0.0 0.0 0.0 0.0 0.0 WECC - non CAISO 0.0 0.0 0.0 0.0 0.0 0.1 CAISO 0.0 0.0 0.0 0.0 0.0 0.0 ------- B5. New Capacity in Policy Case Incremental to Base Case in GW (2025) Region CC CT Wind Solar Storage Other Total US 0 0 0 3 0 0 3 ERCOT 0 0 0 0 0 0 0 FRCC 0 0 0 0 0 0 0 MISO - South 0 0 0 1 0 0 1 MISO - North 0 0 0 0 0 0 0 MISO - Central 0 0 0 1 0 0 1 ISONE 0 0 0 0 0 0 0 NYISO 0 0 0 0 0 0 0 PJM 0 0 0 0 0 0 0 SERC 0 0 0 1 0 0 1 SPP 0 0 0 0 0 0 0 WECC - non CAISO 0 0 0 0 0 0 0 CAISO 0 0 0 0 0 0 0 B6. Net Reserves Sent by NERC Assessment Region in GW (2025) Region Base Policy Change from Base to Policy Change as a percent of summer peak US 0.3 0.3 0.0 0% ERCOT 1.6 1.2 -0.4 -1% FRCC 0.0 0.0 0.0 0% MISO - South 0.0 0.0 0.0 0% MISO - North -1.9 -1.9 0.0 0% MISO - Central -2.7 -2.4 0.4 1% ISONE 0.0 0.0 0.0 0% NYISO 0.3 0.3 0.0 0% PJM 3.2 2.9 -0.3 0% SERC 0.2 0.5 0.2 0% SPP -0.9 -0.9 0.0 0% WECC - non CAISO 7.6 7.6 0.0 0% CAISO -7.1 -7.1 0.0 0% ------- Appendix C: Tables by IPM Region for Final Rule in 2030 (Note: All Results Cumulative through Projection Year) CI. Projected Operational Capacity in GW (2030) Region All generation sources Base Policy Change from Base Coal Only Base Policy Change from Base US 1,262 1,261 0 124 111 -13 ERCOT 139 139 0 11 9 -2 FRCC 65 65 0 3 3 0 MISO - South 43 42 -1 3 1 -2 MISO - North 51 50 0 9 9 0 MISO - Central 92 94 1 18 17 -1 ISONE 45 45 0 0 0 0 NYISO 48 48 0 0 0 0 PJM 221 221 0 22 20 -2 SERC 183 183 0 25 23 -1 SPP 95 95 0 19 15 -4 WECC - non CAISO 191 191 0 14 13 -1 CAISO 87 87 0 1 1 0 C2. Summary of Summer Peak Loads and Reserve Capacity in GW (2030) Projected Reserve Margins Region Peak Demand Base Peak Demand Policy Reserve Capacity Base Reserve Capacity Policy US 818 818 942 942 ERCOT 74 74 84 84 FRCC 51 51 60 60 MISO South 37 37 43 43 MISO North 27 27 31 31 MISO - Central 67 67 78 78 ISONE 27 27 31 31 NYISO 33 33 38 38 PJM 152 152 176 176 SERC 143 143 164 164 SPP 54 54 61 61 WECC - non CAISO 102 102 116 116 CAISO 53 53 60 60 ------- C3. Summary of Target and Projected Reserve Margin % (2030) Region Target Reserve Margin Base Case Policy Case Policy % Above Margin Policy Change from Base US 15% 15% 15% 0% 0% ERCOT 14% 14% 14% 0% 0% FRCC 19% 19% 19% 0% 0% MISO - South 17% 17% 17% 0% 0% MISO - North 17% 17% 17% 0% 0% MISO - Central 17% 17% 17% 0% 0% ISONE 18% 18% 18% 0% 0% NYISO 15% 15% 15% 0% 0% PJM 16% 16% 16% 0% 0% SERC 15% 15% 15% 0% 0% SPP 12% 12% 12% 0% 0% WECC - non CAISO 14% 14% 14% 0% 0% CAISO 14% 14% 14% 0% 0% C4. Policy Case Retired Capacity Incremental to Base Case in GW (2030) Region CC Coal CT Nuclear OG Steam Total US 0.0 12.9 0.0 -0.5 0.1 12.5 ERCOT 0.0 2.1 0.0 0.0 0.0 2.1 FRCC 0.0 0.0 0.0 0.0 0.0 0.0 MISO - South 0.0 2.2 0.0 0.0 0.1 2.3 MISO - North 0.0 0.0 0.0 0.0 0.0 0.0 MISO - Central 0.0 0.5 0.0 0.0 0.0 0.5 ISONE 0.0 0.0 0.0 0.0 0.0 0.0 NYISO 0.0 0.0 0.0 0.0 0.0 0.1 PJM 0.0 1.9 0.0 -0.5 -0.1 1.4 SERC 0.0 1.4 0.0 0.0 0.1 1.5 SPP 0.0 3.9 0.0 0.0 0.0 3.8 WECC - non CAISO 0.0 0.8 0.0 0.0 0.0 0.8 CAISO 0.0 0.0 0.0 0.0 0.0 0.0 ------- C5. New Capacity in Policy Case Incremental to Base Case in GW (2030) Region CC CT Wind Solar Storage Other Total US 0 9 0 3 0 0 12 ERCOT 0 2 0 0 0 0 2 FRCC 0 0 0 0 0 0 0 MISO - South 0 1 0 0 0 0 1 MISO - North 0 0 0 0 0 0 0 MISO - Central 0 2 0 0 0 0 2 ISONE 0 0 0 0 0 0 0 NYISO 0 0 0 0 0 0 0 PJM 0 2 0 0 0 0 1 SERC 0 1 0 0 0 0 1 SPP 0 0 0 4 0 0 4 WECC - non CAISO 0 1 0 0 0 0 1 CAISO 0 0 0 0 0 0 0 C6. Net Reserves Sent by NERC Assessment Region in GW (2030) Region Base Policy Change from Base to Policy Change as a percent of summer peak US -3.5 -3.6 -0.1 0% ERCOT -0.7 -1.0 -0.3 0% FRCC -0.2 0.0 0.2 0% MISO - South -1.3 -2.1 -0.8 -2% MISO - North -2.5 -2.5 0.0 0% MISO - Central 0.4 1.5 1.1 2% ISONE -0.7 -0.7 0.0 0% NYISO -0.1 -0.1 -0.1 0% PJM 0.4 0.4 0.0 0% SERC 2.0 1.8 -0.2 0% SPP 1.0 1.1 0.1 0% WECC - non CAISO 5.5 5.5 0.0 0% CAISO -7.4 -7.4 0.0 0% ------- Appendix D: Maps IPM v6 Map ------- D2: NERC Assessment Areas in Long Term Reliability Assessment. NPCC Cntarin nkc Quebec NKC Mirihmei NPCC New England NPCC New "Xorx wtcc CA/MX Inn RE ESJGOT Source: NERC 2022 Long-Term Reliability Assessment ------- |