## From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov> Sent: Thursday, July 30, 2015 9:08 AM To: Vasu, Amy; Culligan, Kevin; Harvey, Reid Cc: Frey, Nathan J.; Grossman, Andrea Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- Resource Adequacy TSD and CEIP for CPP and FP

Attached please find a summary of interagency comments under EO 12866 and 13563 the following three documents: 1. Summary of Interagency Comments on the Resource Adequacy TSD 2. Summary of Interagency Comments on the CPP preamble language related to the CEIP 3. Summary of Interagency Comments on the FP preamble language related to the CEIP Thank you and please let know if you have any questions. Aaron L. Szabo Policy Analyst Office of Management and Budget 202-395-3621 Aaron_L_Szabo@omb.eop.gov << SummaryOfInteragencyCommentsUnder_EO12866_EO13563_Resource Adequacy TSD.....docx >> << SummaryOfInteragencyCommentsU nder_EO12866_EO13563_CPP_CEIP.DOCX >> << SummaryOfInteragencyComment sUnder_EO12866_EO13563_FP_CEIP.DOCX >>

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### Technical Support Document: Resource Adequacy and Reliability Analysis
This document describes resource adequacy and reliability impacts of the final rule emission guidelines issued under section 111(d) of the Clean Air Act, also known as the Clean Power Plan. 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 region 1 

### , while reliability includes the ability to deliver the resources to the loads, such that the overall power grid remains stable. It is important to recognize that the final rule provides multiple flexibilit ies that preserve the ability of responsible authorities to maintain electric reliability, as well as a provision to ensure that electric reliability is adequately maintained in the case of extreme circumstances, amongst other changes to the final rule that will assist states and other authorities with ensuring adequate supplies of electricity and maintain ing electric reliability. First, the final rule includes critical timing adjustments in response to comment about resource adequacy and reliability. In particular, the start date for the first compliance period was moved from 2020 to 2022. In addition, building block 2 and building block 3 are both gradually phased in starting in 2022 to give EGUs additional time to make adjustments, including any investments needed for the purpose of ensuri ng resource adequacy and reliability. Second, the EGs were set with multiple levels of conservatism. For example, many potential compliance technologies such as readily scalable clean distributed generation were excluded from rate setting. Also, rates were determined based on the least stringent targets out of the three interconnects. Third, as with the proposal, the final rule offers considerable flexibility to both states and EGUs. States are given broad latitude to design plans that fit their unique circumstances, including taking into account any resource adequacy or reliability constraints they may face. One particularly important example of this latitude is that states are encouraged to implement

1 As analyzed in this document, power regions correspond to aggregates of IPM regions corresponding to NERC assessment areas. Commented [A1]: The analysis in this TSD leans heavily on energy efficiency. Suggest emphasizing that this analysis is based on the illustrative scenarios from the RIA and that states have broad flexibility to implement the rule in ways that cater to their specific needs while maintaining reliability. Also suggest broadening the discussion on the flexibility provided in the final rule and the RSV provision for maintaining reliability in case of extreme circumstances Deleted: two illustrative state plan scen arios that are reflected in the Regulatory Impact Analysis (RIA) that supports the Commented [A2]: Suggest making broader points about flexibility of rule and RSV for all cases in addition to focusing on the details of the particular illustrative scenarios from the RIA. Moved down [1]: The focus of the analysis is on the impact of the illustrative scenarios, in the context of 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. 2 The EPA uses the Integrated Planning Model (IPM) to project likely future electricity market conditions with and without the proposed rule. 3 Deleted: y Deleted: in the context of state plan development Deleted: s

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### mass-based or rate-based plans that allow EGUs to take advantage of trading both within each state and across states. Moreover, states are given additional flexibility to manage any near-term resource adequacy constraints by taking advantage of averaging provisions during the interim multi-year compliance steps. Finally, the Reliability Safety Valve (RSV) provisions in the final rule provide additional flexibilities and provisions that assure states can adequately manage any specific reliability challenges that may arise. In sum, states can choose different ways of implementing the guidelines to meet their targets while catering to their specific needs and maintaining electric reliability. For more detail
on the RSV and other ways in which the final CPP addresses reliability, see Section VIII of the final rule preamble. The results presented in this document further demonstrate, for the specific cases illustrated in the Regulatory Impact Assessment (RIA ), that the implementation of this rule can be achieved without undermining resource adequacy or reliability. The focus of the analysis compares these two illustrative state plan scenarios 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. 4 

### The EPA uses the Integrated Planning Mode l (IPM) to project likely future electricity market conditions with and without the proposed rule. 5 

### IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. The model is designed to reflect electricity markets as accurately as possible. The EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis

4 Both the base and policy cases start from input data on the expected state of the fleet of power plants in 2016 and assume certain planned retirements and additions happen by the end of 2015; the analysis focuses on the impacts of retirements that are projected by the IPM model in the 2025 and 2030. See the documentation of the NEEDS data base at epa.gov/powersectormodeling for information on what retirements and additions are assumed to occur by the end of 2015. 5 See final rule Regulatory Impact Analysis for more detail on the power sector impacts of the final CPP. Deleted: period from 2022-2029

Deleted: rule

Deleted: how the

Deleted: show that power system impacts of the final rule on system operations, under conditions preserving resource adequacy, are modest and manageable. Moved (insertion) [1] Deleted: is on the impact of the Deleted: , in the context of

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### for the detailed power sector modeling in IPM. The model documentation provides additional information on the assumptions discussed here as well as all other model assumptions and inputs. 6


### IPM 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 64 IPM regions, based on current and planned transmission capacity, by setting limits to the ability to 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. For a more complete presentation of the broad power sector impacts of the proposed rule, see the Regulatory Impact Analysis. Overview In the final rule, the EPA is establishing emission guidelines for states to use in developing plans to address greenhouse gas emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing category-specific performance rates for CO 2 

### emissions from power plants, as well goals for states to use in developing plans to meet the guidelines. See final rule preamble for more detail on the final CPP structure and rule requirements. This TSD uses the same scenarios and years of analysis contained in the RIA. 7 

### The scenarios include a base case (no CPP), a rate-based state plan scenario and a mass-based state plan scenario. For purposes of th is resource adequacy and reliability assessment, estimates and projections are taken from th ose same scenarios and years as shown in the RIA (2020, 2025, and 2030). 

### CPP Rate-Based Scenarios Summary of Changes in Operational Capacity

6 Detailed information and documentation of EPA’s Base Case using IPM (v5.1 5 ), including all the underlying assumptions, data sources, and architecture parameters can be found on EPA’s website at: http://www.epa.gov/powersectormodeling/BaseCasev51 5 .html 7 See Chapter 3 of the RIA for additional detail on the scenarios analyzed. Deleted: ’s Deleted: least-cost dispatch soluti on, under any scenario, will

Deleted: This document focusses on key regional results important to management of the power system.

Deleted: Deleted:

Deleted: e Deleted: e

Deleted: 3 Deleted: 3 Formatted: Font: (Default) Times New Roman, Complex Script Font: Times New Roman

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### Total operational capacity is lower in the CPP scenario, primarily from the reduced need for existing and new capacity as a result of increases in energy efficiency. These increases in energy efficiency make possible increases in retirements compared to the base case. Since most regions currently have capacity above their target reserve margins, most of these retirements are absorbed by a reduction in excess reserves in the early years. For illustrative purposes, the 2025 projection period, the first period to fall entirely within the compliance period, is discussed first, followed by a discussion of 2020 and 2030. Operational generating capacity 8 

### changes from the base case in 2025 are summarized below:

Table 1. Operational Capacity Summary in 2025 Base case operational capacity (MW) 1,037,223

Minus Retirements in CPP Rate Case: (-) Coal -22,984 (-) Oil-Gas Steam -9,264 (-) Combustion Turbine -1,942 (-) Combined Cycle -1,643 (-) Nuclear -1,128

Plus New Capacity Change from EE Reduction -12,626 Equals Policy Case Operational Capacity 988,764 9


### Since the model must maintain adequate reserves in each region, a portion of the reduced operational capacity in the CPP policy case is taken from reduced need for reserves compared to the base case. In order to maintain resource adequacy in each region where existing resources retire, the model relies on any excess reserve s that are available from continuing to operate existing capacity, additions of new capacity, reduced total resource requirements from increases in energy efficiency, and the ability to shift transmission among regions as the generating capacity mix changes. As the table shows, the reduced resource needs permit lower capacity

8 Operational capacity is any existing, new or retrofitted capacity that is not retired. 9 Numbers in this table may not sum to numbers in Table A1 due to independent rounding and small classification differences between the base and policy cases. Deleted: of

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### additions even though there are substantial increases in retirements. Each of these CPP policy case changes is discussed further below. Reduction in Reserve Requirements and Excess Reserves IPM uses a target reserve margin in each region 10 

### 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 are generally higher than the target reserve margin for the region, and increased energy efficiency will reduce the need for reserves, IPM may retire reserve capacity in 2025 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, many of the plants that are projected to retire in 2025 will not need to be replaced. Because 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. Table 1 above shows that operational generating capacity is reduced by 48,459MW (4.7 percent) nationwide in 2025 under the policy. 11 

### The majority of this reduction is the result of decreases in the reserve requirements from energy efficiency under the final rule; in 2025 new energy efficiency under the final rule contributes 45,085 MW to reserve capacity 12 

### (see Table B1 for regional detail). Moreover, these reductions are from energy efficiency that is available in all hours, not just at peak, so it can substitute for existing or new baseload capacity. A reduction of 4.7 percent in 2025 will therefore have little overall impact, particularly given the length of time

10 Reserve margin targets are generally based on the NERC 2010 10 Year Assessments for the region, except in cases where there are more stringent state requirements or other exceptions. 11 Regional data on operational capacity is shown in Table A1 of the Appendix. 12 The reserve contribution to reserve capacity requirements from energy efficiency is determined by the reduced peak demand and the target reserve margin in each region. For example, if peak demand i s reduced by 100 MW and the reserve margin percentage in a region is 15%, the reduction in reserve capacity requirements is 115MW. Deleted: n

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### available to plan for any system changes. Moreover, retirements are distributed throughout the power grid, so any impacts are expected to be small at the regional level. 13 

### Although there are substantial existing regional variations in reserve margin, IPM adjusts regional operating capacities in 2025 through changes in the level of retirements, construction of new generating capacity, or transfers of capacity among regions to meet the specific reserve margin in each region. Each of these adjustments in the 2025 projections is described below. Changes in Retirements and New Capacity Additions in the CPP Scenarios 14


### The incremental retirements in the final rule are shown above in Table 1; the 36,931 MW of retirements are in addition to 69,254MW of coal and 12,973MW of oil/gas retirements already occurring in the base case. By 2025, the increased level of energy efficiency in the CPP case, compared to the base case, leads to lower levels of overall new capacity additions ( s hown regionally in Table A5). Renewable additions are approximately the same in both the base and policy cases. The largest decreases are in NGCC (7,808MW) and CT (3,131MW). Although there can be local grid reliability issues in replacing some units , these can be managed within the normal reliability planning and management time frames provided by the flexible resource options and time frames in the final rule. These retirements and additions in the projections are the result of economic planning for energy and capacity needs modeled in the projections, they are not forced on individual units. 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 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

13 See maps of IPM regions and NERC Assessment Regions, and the table of target and projected reserve margins in the Appendix C. IPM regions are based on the regions NERC uses for regional assessments. These Assessment Regions are used for the Appendix tables in this document. 14 Retirement and additions in this section are all incremental to the base case in 2025; the MW values represent model projections of responses to the imposition of the policy, not currently announced retirements or additions that are currently planned or under construction. Deleted: there will Deleted: only Deleted: impacts Deleted: to meet the specific target reserve margin in each region,

Deleted: There are significant levels of fossil steam – coal and oil/gas – retiring in 2025 in both the base and CPP scenario. Deleted: final rule case

Deleted: new Deleted: S

Deleted: of the retiring units shown in Table 1 above and in Table A4

Deleted: might

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### 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 rese rves can be transferred re liably. 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 impact of the CPP 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 the changes in the proposed rule, and all are below 5%. 15 

### Using this measure, the largest percentage changes in reserve transfers are in the Northwest (4.3%), SERC-North (-3.5%), and FRCC (3.1%). The change in the Northwest is attributable primarily to change in transfers from the Pacific Northwest IPM region to California, where an additional 2000MW are transferred to Northern California, including 1000MW shifted from Southern California (LADWP). The net change of 1,134(MW) occurs, in part, as a result of additional operating capacity made available by increased energy efficiency in the policy case compared to the base case. This shift does not indicate any reliability challenges, as the total

15 See the Resource Adequacy and Reliability Analysis for the proposed rule. A level of 5% was used as a screen in that analysis; there were three regions above 5% identified in the proposed rule TSD. Deleted: in the Commented [A3]: Anything else that could be said about the 5% threshold? e.g. unlikely to raise concerns over reliability?

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### transfers of 3,499MW in the policy case remain substantially below the transfer limit of 4,200MW. The SERC regions and FRCC have shifts around three percent, with some areas increasing net transfers and others decreasing. These areas also saw shifts in transfers in the modeling for the proposed rule, but the changes in this final rule have reduced th ese shifts to modest transfers compared to the the proposal. In general, the shifts under the final rule show transfers from the Southeastern areas with greater natural gas resources available – FRCC and SERC-SE – toward northern areas with greater amounts of coal -- TVA and Kentucky. These transfers in the modeling remain well below the interregional transfers limits and 3 percent or less of the regional load in each case, and it is reasonable to expect them to be manageable, if needed, given the length of time available. CPP Rate -Based Scenario in 2020 and 2030 There are other model projection periods that include years that fall in the period for compliance with the rule. The 2020 projections include the years 2019 through 2022, so one of the years in the period falls in the compliance period. EPA examined the information for the rate scenario for 2020 corresponding to the rate scenario in 2025. This information is shown in the tables in Appendix A, which correspond to the tables for the 2025 case in Appendix B. Since the projections are representative of the entire four year period, it is difficult to draw conclusions with regard to firm impacts on reliability resulting from the rule. This is because most of the period is outside the compliance period of the final rule, and there can be no direct conflict with the rule except in the very last year of the projection period. The results can be compared below with the 2025 results for purposes of illustration. The differences between 2020 and 2025 in the CPP rate scenario are driven by the fact that IPM modeling retires capacity from the start of the modeling period in 2016, based on projections that assume complete information about the future and precise economic planning. It thus assumes that capacity retires at the earliest possible moment that it becomes economic to do
so , so that excess reserves are used up and reserve margins can fall to target levels earlier than expected in practice. Nevertheless, in 2020, seven regions maintain margins above their levels in 2025 (See Table A3). This is consistent with the lower level of overall retirements in 2020 Deleted: is Deleted: shifts under

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### compared to 2025 (24,567MW compared to 36,961MW in 2025), so the modeling confirms that any potential resource adequacy pressures from the final rule are not seen until the projections for 2025. Results for the rate scenario in 2030 are contained in Appendix C. Reserve margins in the policy case in 2030 are essentially unchanged (less than 0.5% difference in all regions) from 2025, reflecting the fact that most regions were already at thei r target margins in the 2025 rate scenario. Base case margins decline from 2025 to 2030, as margins above targets are reduced, so that the base case and policy case overall national margins are less than 1 percent different (Table C3). There continue to be more retirements in the policy case relative to the base case in 2030 ( i ncremental retirements of 41,009MW in 2030 compared to 36,961MW in 2025, an increase of 5,048 MW). These retirements are offset by a corresponding combination of new energy efficiency and changes in new capacity. In 2025, there were 12,626 MW fewer new capacity additions in the CPP case; in 2030 there were 16,964 MW fewer: a net decrease of4,338 MW (over the base case) in the 2030 case compar ed to the comparable 2025 figure. However, the increase in the contribution of energy efficiency to reserve margin capacity was considerably greater than the combined decrease in new capacity additions and increase in retirements in 2030: the contribution of new energy efficiency to reserve margin in 2030 was 77,741 MW compared to 45,085 MW in 2025 (See Tables B1 and C1 in the Appendices), an increase of 22,656 MW. Given the long planning horizon of 2030, there will be adequate time to plan for potential shifts in the mix of demand and supply resources as these evolve over time. None of these results suggest there will be reasons for concern over the management of resource adequacy



### CPP Mass-Based Scenarios The EPA also examined the mass scenario modeling results to identify differences with the rate scenario potential impacts. The results for the CPP mass-based scenarios are contained in Appendices D through F for the projection years 2020, 2025 and 2030. These tables correspond to the tables for the CPP Rate-Based scenarios in Appendices A through C. Deleted: that Deleted: the major

Deleted: I

Deleted: new Deleted: an incremental

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### As expected, rate and mass cases showed very similar patterns in total operating and reserve capacity, since the IPM model must serve the same loads and ensure the same reserve margins in each case. In 2025, total operating capacity between rate and mass cases differs by less than one percent and regional operating capacities are within 5 percent except for the BASN regions, where the percentage difference is 8.6%, the result of retirement of a resource (coal) in Utah, which is offset by increased transmission capacity transfers. Reserve capacity and projected reserve margins for the mass scenario (Tables E2 and E3) follow a pattern similar to operating capacity: totals are within 1% of the projections for the corresponding outputs rate scenario and regional reserve capacities are under 5 percent. Differences between the scenarios develop in the types of capacity that are retired and in the amount and types of new capacity built in 2025. The mass scenario results show more incremental retirements of coal capacity (29,319 MW compared to 22,984 MW in the rate scenario) and in Oil-Gas capacity (10,421 MW compared to 9,264 MW). The mass scenario also results in more new NGCC and CT capacity, and less new wind and solar capacity. The mass scenario still is projected to have a decrease in new capacity compared to the base case, but the decrease is only 9,971 MW compared to the 12,626 MW in the rate scenario. No reliability concerns are raised by these differences. The patterns of transfers are also similar. In the mass scenario, there is somewhat more variation in net transfers than in the rate case. In particular there are two regions with shifts of more than 5% in the mass scenario: the Northwest and BASN, both in WECC. These two shifts are linked. The Northwest reserve transfers include the transfers in the rate scenario discussed above, plus additional transfers from the Northwest to BASN to compensate for the coal retirements in BASN discussed above. The two cases with the largest percentage shift examined above are reduced in magnitude. These transfers in the mass scenario remain below the interregional transfer limits in the modeling and do not appear to present significant reliability related concerns. The same general patterns noted here for 2025 are also present in 2020 and 2025: only minor variations in total operating capacity, somewhat higher fossil steam retirements, more NGCC and CT capacity. These differences do not raise further issues of resource adequacy. Details can be found in the Appendices.

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### Appendix A: Tables by IPM Region for CPP Rate-Based Scenario in 2020 A1. Projected Operational Capacity A2. . Summary of Summer Peak Loads and Reserve Capacity A3. Summary of Target and Projected Reserve Margins A4. Policy Case Retired Capacity Incremental to Base Case A5. New Capacity in Policy Case Incremental to Base Case A6. Net Reserves Sent by NERC Assessment Region

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13 A4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2020
CC Coal CT NU OG Steam Total Basin (BASN) 180

‐ 179 0 0 108 109 Desert Southwest (DS W 616 162 0 0 513 1,290 ERCOT 0 0 0 0 0 0 FRCC 59 317 0 0 288 664 ISO

‐ NE 0 0 0 0 1,725 1,725 MAPP 0 679 0 0 0 679 MISO 0 2,822 0 0 0 2,822 Northern California (C A 0 0 1,898 0 0 1,898 Northwest (NORW) 1,465 52 0 867 0 2,383 NYISO 81

‐ 68 0 0 1,674 1,687 PJM 0 408 0 0 29 437 Rockies (Rock) 39 963 0 0 55 1,057 SERC

‐ E 0 434 0 0 0 434 SERC

‐ N 0 1,443 0 0 0 1,443 SERC

‐ SE 0 2,171 0 0 0 2,171 SERC

‐ W

‐ 434 1,328 0 0

‐ 92 802 Southern California (C A 0 0 43 0 2,440 2,484 SPP

‐ 362 2,619 0 0 226 2,483 Grand Total 1,643 13,149 1,942 867 6,966 24,567 Commented [A4]: Please remove as this same table appears later on in the document

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14 A2. Summer Peak Loads and Reserve Capacity in 2020 Projected Reserve Margins
Assessment Re g io n Peak Demand

Base Peak Demand

Polic y Reserve Capacity

Base Reserve Capacity

Polic y Basin (BASN) 11,953 11,880 13,926 13,567 Desert Southwest ( 29,612 29,352 34,074 33,314 ERCOT 73,948 73,806 84,116 83,955 FRCC 44,324 44,253 56,200 55,193 ISO-NE 26,475 26,248 30,446 30,185 MAPP 5,330 5,324 6,603 6,123 MISO 90,719 89,895 106,505 104,548 Northern California 21,282 21,090 25,399 24,193 Northwest (NORW ) 25,414 25,175 39,507 34,859 NYISO 30,058 29,744 34,868 34,503 PJM 150,553 149,437 173,738 172,450 Rockies (Rock) 14,156 14,042 17,609 16,654 SERC-E 42,195 41,966 48,524 48,261 SERC-N 38,518 38,398 44,296 44,158 SERC-SE 48,110 48,014 55,327 55,217 SERC-W 29,095 29,052 37,890 34,798 Southern California 28,108 27,797 33,588 32,085 SPP 51,995 51,865 63,790 60,946 US T otal 761,845 757,338 906,407 885,008

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15 A3. Summary of Target and Projected Reserve Margins in 2020 Projected Reserve Margins
NERC Assessment Re g io n Target Reserve Mar g in Base Case Polic y Case Policy % A bove Mar g i n Policy Change from Base Basin (BASN) 12.60% 16.51% 14.21% 1.6% -2.3% Desert Southwest (DSW) 13.50% 15.07% 13.50% 0.0% -1.6% ERCOT 13.75% 13.75% 13.75% 0.0% 0.0% FRCC 19.25% 26.79% 24.72% 5.5% -2.1% ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0% MAPP 15.00% 23.87% 15.00% 0.0% -8.9% MISO 16.30% 17.40% 16.30% 0.0% -1.1% Northern California ( CALN ) 14.71% 19.35% 14.71% 0.0% -4.6% Northwest (NORW) 17.90% 31.61% 25.25% 7.4% -6.4% NYISO 16.00% 16.00% 16.00% 0.0% 0.0% PJM 15.40% 15.40% 15.40% 0.0% 0.0% Rockies (Rock) 14.65% 24.39% 18.60% 3.9% -5.8% SERC-E 15.00% 15.00% 15.00% 0.0% 0.0% SERC-N 15.00% 15.00% 15.00% 0.0% 0.0% SERC-SE 15.00% 15.00% 15.00% 0.0% 0.0% SERC-W 15.00% 30.23% 19.78% 4.8% -10.5% S outhern California ( CALS ) 15.14% 19.50% 15.42% 0.3% -4.1% SPP 13.60% 22.69% 17.51% 3.9% -5.2% Grand Total 15.30% 18.98% 16.86% 1.6% -2.1%

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16 A4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2020
CC Coal CT NU OG Steam Total Basin (BASN) 180

‐ 179 0 0 108 109 Desert Southwest (DS W 616 162 0 0 513 1,290 ERCOT 0 0 0 0 0 0 FRCC 59 317 0 0 288 664 ISO

‐ NE 0 0 0 0 1,725 1,725 MAPP 0 679 0 0 0 679 MISO 0 2,822 0 0 0 2,822 Northern California (C A 0 0 1,898 0 0 1,898 Northwest (NORW) 1,465 52 0 867 0 2,383 NYISO 81

‐ 68 0 0 1,674 1,687 PJM 0 408 0 0 29 437 Rockies (Rock) 39 963 0 0 55 1,057 SERC

‐ E 0 434 0 0 0 434 SERC

‐ N 0 1,443 0 0 0 1,443 SERC

‐ SE 0 2,171 0 0 0 2,171 SERC

‐ W

‐ 434 1,328 0 0

‐ 92 802 Southern California (C A 0 0 43 0 2,440 2,484 SPP

‐ 362 2,619 0 0 226 2,483 Grand Total 1,643 13,149 1,942 867 6,966 24,567

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

17 A5. New Capacity Policy Case Incremental to Base Case(MW) Year= 2020 Region CC CT Wind Solar Other Total Basin (BASN) 0 0 0 0 0 0 Desert Southwest (DSW) 0 0 3 0 0 3 ERCOT

‐ 196 0 323 0 0 127 FRCC 0 0 0 0 0 0 ISO

‐ NE 0 0 334 0 0 334 MAPP 0 0 247 0 0 247 MISO 320 0

‐ 38

‐ 6 305 581 Northern California (CALN) 0 0 12 0 0 12 Northwest (NORW) 0 0 10 0 0 10 NYISO 0 0

‐ 386 0

‐ 213

‐ 599 PJM 767

‐ 1,692 175 12

‐ 115

‐ 852 Rockies (Rock) 0 0 0

‐ 54 0

‐ 54 SERC

‐ E 612 0 0

‐ 29 0 583 SERC

‐ N 1,203 0 3 0 23 1,229 SERC

‐ SE 0 0 0 0 0 0 SERC

‐ W 0 0 0 00 0 Southern California (CALS) 0 0

‐ 270 0 0

‐ 270 SPP 0 0 1,110 0 0 1,110 Grand Total 2,705

‐ 1,692 1,523

‐ 78 0 2,459

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

18 

### A6. Net Reserves Sent by NERC Assessment Region(MW) i n 2020

NERC Assessment Region Base Policy Change from Base to Policy Change as Percent of Summer Peak Basin (BASN) -1,772 -1,522 251 2.1% Desert Southwest (DS W 3,869 3,340 -529 -1.8% ERCOT -1,942 -1,942 0 0.0% FRCC 0 342 342 0.8% ISO-NE -1,823 -3,212 -1,388 -5.2% MISO -2,775 -3,249 -474 -0.5% Northern California (CAL 0 -692 -692 -3.3% Northwest (NORW) 407 2,675 2,268 8.9% NYISO 320 -1,303 -1,623 -5.4% PJM -4,614 -4,702 -88 -0.1% Rockies (Rock) 1,417 1,298 -118 -0.8% SERC-E -981 -547 434 1.0% SERC-N 1,502 1,435 -67 -0.2% SERC-SE 3,800 1,739 -2,061 -4.3% SERC-W 1,112 3,416 2,304 7.9% Southern California (CA L -3,761 -4,884 -1,124 -4.0% SPP 2,191 2,872 682 1.3%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

19 

### Appendix B: Tables by IPM Region for CPP Rate-Based Scenario in 2025 B1. Projected Operational Capacity B2. Summary of Summer Peak Loads and Reserve Capacity

B3. Summary of Target and Projected Reserve Margins B4. Policy Case Retired Capacity Incremental to Base Case B5. New Capacity in Policy Case Incremental to Base Case B6. Net Reserves Sent by NERC Assessment Region Deleted:

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

20 

### B1. Projected Operational Capacity Year= 2025

All Generation Sources EE Capacity Overall Coal Only Region Base Policy Contribution Change Base Policy Basin (BASN) 14,293 13,888 687 282 4,802 4,685 Desert Southwest (DSW) 42,265 40,855 2,300 890 8,380 8,096 ERCOT 99,864 96,751 3,345 232 17,937 17,647 FRCC 56,336 55,672 2,080 1,417 7,479 7,162 ISO

‐ NE 32,685 31,294 1,644 252 0 0 MAPP 9,627 8,993 207

‐ 428 3,007 2,190 MISO 125,625 118,165 6,127

‐ 1,333 45,036 39,567 Northern California (CALN ) 29,389 27,503 1,321

‐ 565 71 71 Northwest (NORW) 51,181 48,711 2,036

‐ 434 2,406 2,354 NYISO 38,484 36,082 2,173

‐ 229 0 0 PJM 188,212 179,396 9,367 551 50,144 44,546 Rockies (Rock) 23,663 22,284 1,041

‐ 339 9,216 8,363 SERC

‐ E 55,904 52,022 2,556

‐ 1,326 11,045 9,478 SERC

‐ N 50,217 46,755 2,051

‐ 1,411 13,141 11,557 SERC

‐ SE 57,354 56,571 2,192 1,409 11,655 10,871 SERC

‐ W 40,012 37,823 1,069

‐ 1,121 4,733 3,418 Southern California (CALS) 43,405 39,826 2,159

‐ 1,420 57 50 SPP 78,704 75,121 2,733

‐ 850 22,966 19,113 Grand Total 1,037,223 987,713 45,085

‐ 4,425 212,075 189,169

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

21 B2. Summer Peak Loads and Reserve Capacity in 2025 Projected Reserve Margins
Assessment Re g io n Peak Demand

Base Peak Demand

Polic y Reserve Capacity

Base Reserve Capacity

Polic y Basin (BASN) 12,466 11,856 14,036 13,349 Desert Southwest ( 31,887 29,861 36,192 33,892 ERCOT 77,606 74,665 88,276 84,932 FRCC 46,355 44,611 55,279 53,199 ISO-NE 26,701 25,272 30,706 29,063 MAPP 5,539 5,360 6,370 6,164 MISO 93,625 88,356 108,885 102,758 Northern California 22,305 21,155 25,592 24,301 Northwest (NORW ) 26,489 24,955 36,672 33,098 NYISO 30,051 28,179 34,860 32,687 PJM 154,841 146,724 178,686 169,319 Rockies (Rock) 15,223 14,315 17,676 16,412 SERC-E 44,263 42,040 50,902 48,346 SERC-N 40,450 38,666 46,517 44,466 SERC-SE 50,430 48,524 57,994 55,802 SERC-W 30,589 29,660 35,644 34,109 Southern California 29,473 27,605 34,006 31,922 SPP 54,332 51,926 62,673 58,988 US T otal 792,624 753,693 920,969 872,809

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

22 B3. Summary of Target and Projected Reserve Margins in 2025 Projected Reserve Margins
NERC Assessment Re g ion Target Reserve Mar g in Base Case Polic y Case Policy % A bove Mar g i n Basin (BASN) 12.60% 12.60% 12.60% 0.0% Desert Southwest (DSW) 13.50% 13.50% 13.50% 0.0% ERCOT 13.75% 13.75% 13.75% 0.0% FRCC 19.25% 19.25% 19.25% 0.0% ISO-NE 15.00% 15.00% 15.00% 0.0% MAPP 15.00% 15.00% 15.00% 0.0% MISO 16.30% 16.30% 16.30% 0.0% Northern California ( CALN ) 14.71% 14.74% 14.87% 0.2% Northwest (NORW) 17.90% 27.05% 25.71% 7.8% NYISO 16.00% 16.00% 16.00% 0.0% PJM 15.40% 15.40% 15.40% 0.0% Rockies (Rock) 14.65% 16.12% 14.65% 0.0% SERC-E 15.00% 15.00% 15.00% 0.0% SERC-N 15.00% 15.00% 15.00% 0.0% SERC-SE 15.00% 15.00% 15.00% 0.0% SERC-W 15.00% 16.52% 15.00% 0.0% S outhern California ( CALS ) 15.14% 15.38% 15.64% 0.5% SPP 13.60% 15.35% 13.60% 0.0% Grand Total 15.29% 16.19% 15.80% 0.5%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

23 B4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2025
CC Coal CT NU OG Steam Total Basin (BASN) 180 118 0 0 108 405 Desert Southwest (DS W 616 284 0 0 513 1,412 ERCOT 0 291 0 0 0 291 FRCC 59 317 0 0 288 664 ISO

‐ NE 0 0 0 0 1,725 1,725 MAPP 0 817 0 0 0 817 MISO 0 5,484 0 0 0 5,484 Northern California (C A 0 0 1,898 0 0 1,898 Northwest (NORW) 1,465 52 0 867 0 2,383 NYISO 81 0 0 261 1,674 2,016 PJM 0 5,601 0 0 19 5,620 Rockies (Rock) 39 855 0 0 55 949 SERC

‐ E 0 1,566 0 0 0 1,566 SERC

‐ N 0 1,603 0 0 0 1,603 SERC

‐ SE 0 783 0 0 0 783 SERC

‐ W

‐ 434 1,328 0 0 1,309 2,203 Southern California (C A 0 7 43 0 2,514 2,565 SPP

‐ 362 3,878 0 0 1,060 4,576 Grand Total 1,643 22,984 1,942 1,128 9,264 36,961

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

24 B5. New Capacity Policy Case Incremental to Base Case(MW) Year= 2025 Region CC CT Wind Solar Other Total Basin (BASN) 0 0 0 0 0 0 Desert Southwest (DSW) 0 0 3 0 0 3 ERCOT

‐ 2,003

‐ 1,142 323 0 0

‐ 2,823 FRCC 0 0 0 0 0 0 ISO

‐ NE 0 0 334 0 0 334 MAPP 0 0 182 0 0 182 MISO

‐ 1,534 0

‐ 404

‐ 53 0

‐ 1,991 Northern California (CALN) 0 0 12 0 0 12 Northwest (NORW) 0 0 10 0

‐ 96

‐ 86 NYISO 0 0

‐ 386 0 0

‐ 386 PJM

‐ 382

‐ 1,988

‐ 696

‐ 133 0

‐ 3,199 Rockies (Rock) 0 0 0

‐ 432 0

‐ 432 SERC

‐ E

‐ 2,008 0 0

‐ 308 0

‐ 2,316 SERC

‐ N

‐ 1,881 0 3 0 0

‐ 1,878 SERC

‐ SE 0 0 0 0 0 0 SERC

‐ W 0 0 0 00 0 Southern California (CALS) 0 0

‐ 270

‐ 706

‐ 39

‐ 1,015 SPP 0 0 965 4 0 969 Grand Total

‐ 7,808

‐ 3,131 75

‐ 1,628

‐ 135

‐ 12,626

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

25 

### B6. Net Reserves Sent by NERC Assessment Region(MW) in 2025

NERC Assessment Region Base Policy Change from Base to Policy Change as Percent of Summer Peak Basin (BASN) -2,052 -1,769 283 2.3% Desert Southwest (DS W 1,846 2,734 888 2.8% ERCOT -1,931 -1,942 -11 0.0% FRCC 838 2,254 1,417 3.1% ISO-NE -2,009 -1,999 10 0.0% MISO -2,502 -4,017 -1,515 -1.5% Northern California (CAL -1,490 -2,095 -606 -2.7% Northwest (NORW) 3,345 4,480 1,134 4.3% NYISO 249 296 47 0.2% PJM -6,877 -5,637 1,240 0.8% Rockies (Rock) 1,419 1,619 201 1.3% SERC-E -402 -1,492 -1,091 -2.5% SERC-N 2,141 728 -1,413 -3.5% SERC-SE -1,213 196 1,409 2.8% SERC-W 3,806 3,149 -657 -2.1% Southern California (CA L -3,309 -4,091 -782 -2.7% SPP 3,631 3,059 -572 -1.1%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

26 

### Appendix C: Tables by IPM Region for CPP Rate-Based Scenario in 2030 C1. Projected Operational Capacity C2. Summary of Summer Peak Loads and Reserve Capacity

C3. Summary of Target and Projected Reserve Margins C4. Policy Case Retired Capacity Incremental to Base Case C5. New Capacity in Policy Case Incremental to Base Case C6. Net Reserves Sent by NERC Assessment Region

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

27 

### C1. Projected Operational Capacity Year= 2030

All Generation Sources EE Capacity Overall Coal Only Region Base Policy Contribution Change Base Policy Basin (BASN) 14,346 13,942 1,135 731 4,802 4,685 Desert Southwest (DSW) 42,265 40,855 3,911 2,501 8,380 8,096 ERCOT 107,231 111,864 6,856 11,490 17,937 17,339 FRCC 61,471 55,847 4,357

‐ 1,267 7,414 6,325 ISO

‐ NE 32,688 31,294 2,518 1,124 0 0 MAPP 9,627 9,322 464 159 3,007 2,190 MISO 126,164 119,045 9,389 2,269 45,036 39,567 Northern California (CALN ) 29,389 27,503 1,976 90 71 71 Northwest (NORW) 51,415 49,030 3,171 786 2,406 2,354 NYISO 39,032 35,323 3,220

‐ 489 0 0 PJM 203,408 185,630 15,258

‐ 2,519 50,129 43,483 Rockies (Rock) 24,105 22,666 1,777 337 9,216 8,363 SERC

‐ E 59,039 53,920 4,304

‐ 814 11,045 7,952 SERC

‐ N 52,505 48,091 3,916

‐ 498 13,141 11,084 SERC

‐ SE 60,658 60,265 4,470 4,076 11,655 10,692 SERC

‐ W 40,602 40,391 2,247 2,037 4,733 3,418 Southern California (CALS) 49,260 44,898 3,238

‐ 1,124 57 50 SPP 79,238 74,663 5,534 958 22,506 18,653 Grand Total 1,082,444 1,024,551 77,741 19,847 211,536 184,322

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

28 C2. Summer Peak Loads and Reserve Capacity in 2030 Projected Reserve Margins
Assessment Re g io n Peak Demand

Base Peak Demand

Polic y Reserve Capacity

Base Reserve Capacity

Polic y Basin (BASN) 12,961 11,953 14,594 13,459 Desert Southwest ( 34,589 31,144 39,259 35,348 ERCOT 82,455 76,428 93,793 86,936 FRCC 49,145 45,491 58,606 54,248 ISO-NE 27,433 25,243 31,547 29,029 MAPP 5,732 5,329 6,592 6,128 MISO 96,428 88,354 112,145 102,756 Northern California 23,372 21,650 26,810 24,834 Northwest (NORW ) 27,515 25,023 33,947 31,852 NYISO 30,694 27,918 35,605 32,385 PJM 160,273 147,051 184,955 169,696 Rockies (Rock) 16,419 14,869 18,824 17,047 SERC-E 46,801 43,058 53,821 49,517 SERC-N 42,204 38,799 48,534 44,619 SERC-SE 52,944 49,057 60,886 56,416 SERC-W 32,436 30,482 37,301 35,054 Southern California 30,929 28,127 35,684 32,494 SPP 57,092 52,221 64,857 59,323 US T otal 829,421 762,176 957,760 881,143

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

29 C3. Summary of Target and Projected Reserve Margins in 2030 Projected Reserve Margins
NERC Assessment Re g io n Target Reserve Mar g in Base Case Polic y Case Policy % A bove Mar g i n Policy Change from Base Basin (BASN) 12.60% 12.60% 12.60% 0.0% 0.0% Desert Southwest (DSW) 13.50% 13.50% 13.50% 0.0% 0.0% ERCOT 13.75% 13.75% 13.75% 0.0% 0.0% FRCC 19.25% 19.25% 19.25% 0.0% 0.0% ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0% MAPP 15.00% 15.00% 15.00% 0.0% 0.0% MISO 16.30% 16.30% 16.30% 0.0% 0.0% Northern California ( CALN ) 14.71% 14.71% 14.71% 0.0% 0.0% Northwest (NORW) 17.90% 23.38% 25.07% 7.2% 1.7% NYISO 16.00% 16.00% 16.00% 0.0% 0.0% PJM 15.40% 15.40% 15.40% 0.0% 0.0% Rockies (Rock) 14.65% 14.65% 14.65% 0.0% 0.0% SERC-E 15.00% 15.00% 15.00% 0.0% 0.0% SERC-N 15.00% 15.00% 15.00% 0.0% 0.0% SERC-SE 15.00% 15.00% 15.00% 0.0% 0.0% SERC-W 15.00% 15.00% 15.00% 0.0% 0.0% S outhern California ( CALS ) 15.14% 15.37% 15.53% 0.4% 0.2% SPP 13.60% 13.60% 13.60% 0.0% 0.0% Grand Total 15.28% 15.47% 15.61% 0.3% 0.1%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

30 C4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2030
CC Coal CT NU OG Steam Total Basin (BASN) 180 118 0 0 108 405 Desert Southwest (DS W 616 284 0 0 513 1,412 ERCOT 0 600 0 0 0 600 FRCC 59 1,089 0 0 288 1,436 ISO

‐ NE 0 0 0 0 1,725 1,725 MAPP 0 817 0 0 0 817 MISO 0 5,484 0 0 0 5,484 Northern California (C A 0 0 1,898 0 0 1,898 Northwest (NORW) 1,465 52 0 867 0 2,383 NYISO 81 0 0 1 1,674 1,756 PJM 0 6,652 0

‐ 1 19 6,669 Rockies (Rock) 39 855 0 0 55 949 SERC

‐ E 0 3,093 0 0 0 3,093 SERC

‐ N 0 2,076 0 0 0 2,076 SERC

‐ SE 0 962 0 0 0 962 SERC

‐ W

‐ 434 1,328 0 0 1,309 2,203 Southern California (C A 0 7 43 0 2,514 2,565 SPP

‐ 362 3,878 0 0 1,060 4,576 Grand Total 1,643 27,294 1,942 867 9,264 41,009

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

31 C5. New Capacity Policy Case Incremental to Base Case(MW) Year= 2030 Region CC CT Wind Solar Other Total Basin (BASN) 0 0 1 0 0 1 Desert Southwest (DSW) 0 0 3 0 0 3 ERCOT

‐ 6,330

‐ 4,182 323 15,421 0 5,232 FRCC

‐ 4,189 0 0 0 0

‐ 4,189 ISO

‐ NE 0 0 331 0 0 331 MAPP 0 0 497 0 15 511 MISO

‐ 1,234 0

‐ 330

‐ 86 0

‐ 1,650 Northern California (CALN) 0 0 12 0 0 12 Northwest (NORW) 0 0

‐ 2 00

‐ 2 NYISO

‐ 1,567 0

‐ 386 0 0

‐ 1,953 PJM

‐ 6,179

‐ 2,899

‐ 864

‐ 1,172 0

‐ 11,114 Rockies (Rock) 0 0 0

‐ 529 37

‐ 492 SERC

‐ E

‐ 1,838 0 0

‐ 188 0

‐ 2,026 SERC

‐ N

‐ 2,360 0 3 0 0

‐ 2,357 SERC

‐ SE

‐ 3,304 0 0 3,873 0 569 SERC

‐ W

‐ 589 0 0 2,569 0 1,979 Southern California (CALS)

‐ 1,603 0

‐ 270 79

‐ 3

‐ 1,797 SPP

‐ 887 0 859 4 0

‐ 24 Grand Total

‐ 30,080

‐ 7,081 177 19,970 50

‐ 16,964

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

32 

### C6. Net Reserves Sent by NERC Assessment Region(MW) in 2030

NERC Assessment Region Base Policy Change from Base to Policy Change as Percent of Summer Peak Basin (BASN) -2,563 -1,826 738 5.7% Desert Southwest (DS W -1,245 1,269 2,514 7.3% ERCOT -40 -389 -349 -0.4% FRCC 2,646 1,379 -1,267 -2.6% ISO-NE -2,848 -1,949 900 3.3% MISO -5,473 -3,076 2,397 2.3% Northern California (CAL -2,709 -2,630 80 0.3% Northwest (NORW) 6,225 5,945 -279 -1.0% NYISO 26 -63 -90 -0.3% PJM -5,123 -6,100 -977 -0.6% Rockies (Rock) 399 1,097 698 4.3% SERC-E -506 -1,177 -670 -1.4% SERC-N 2,412 1,912 -500 -1.2% SERC-SE -800 326 1,126 2.1% SERC-W 2,732 2,844 112 0.3% Southern California (CA L -2,124 -3,120 -997 -3.2% SPP 1,933 2,271 337 0.6%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

33 

### Appendix D: Tables by IPM Region for CPP Mass-Based Scenario in 2020 D1. Projected Operational Capacity D2. Summary of Summer Peak Loads and Reserve Capacity

D3. Summary of Target and Projected Reserve Margins D4. Policy Case Retired Capacity Incremental to Base Case D5. New Capacity in Policy Case Incremental to Base Case D6. Net Reserves Sent by NERC Assessment Region

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

34 

### D1. Projected Operational Capacity Year= 2020

All Generation Sources EE Capacity Overall Coal Only Region Base Policy Contribution Change Base Policy Basin (BASN) 14,448 14,475 84 111 5,064 5,244 Desert Southwest (DSW) 42,114 40,168 296

‐ 1,650 8,380 7,501 ERCOT 95,496 95,339 162 4 17,937 17,550 FRCC 56,419 55,636 88

‐ 695 7,479 7,131 ISO

‐ NE 32,558 30,383 262

‐ 1,914 0 0 MAPP 9,545 9,022 7

‐ 516 3,007 2,545 MISO 122,247 118,757 958

‐ 2,533 45,045 39,926 Northern California (CALN ) 30,690 28,522 220

‐ 1,948 71 71 Northwest (NORW) 51,014 49,408 330

‐ 1,276 2,406 2,354 NYISO 38,484 36,626 365

‐ 1,494 0 0 PJM 183,187 181,488 1,288

‐ 411 50,144 49,784 Rockies (Rock) 23,250 22,246 135

‐ 869 9,327 8,407 SERC

‐ E 52,103 52,109 262 269 11,045 11,176 SERC

‐ N 47,143 47,672 138 667 13,722 12,696 SERC

‐ SE 59,679 57,662 110

‐ 1,907 14,035 12,018 SERC

‐ W 39,074 38,826 52

‐ 196 4,733 3,918 Southern California (CALS) 40,576 38,137 358

‐ 2,082 57 57 SPP 77,768 75,481 153

‐ 2,135 22,966 20,139 Grand Total 1,015,797 991,956 5,267

‐ 18,575 215,416 200,515

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

35 D2. Summer Peak Loads and Reserve Capacity in 2020 Projected Reserve Margins
Assessment Re g io n Peak Demand

Base Peak Demand

Polic y Reserve Capacity

Base Reserve Capacity

Polic y Basin (BASN) 11,953 11,878 13,926 13,375 Desert Southwest ( 29,612 29,352 34,074 33,314 ERCOT 73,948 73,806 84,116 83,955 FRCC 44,324 44,253 56,200 55,045 ISO-NE 26,475 26,248 30,446 30,185 MAPP 5,330 5,324 6,603 6,123 MISO 90,719 89,895 106,505 104,548 Northern California 21,282 21,090 25,399 24,193 Northwest (NORW ) 25,414 25,181 39,507 35,702 NYISO 30,058 29,744 34,868 34,503 PJM 150,553 149,437 173,738 172,450 Rockies (Rock) 14,156 14,045 17,609 16,994 SERC-E 42,195 41,966 48,524 48,261 SERC-N 38,518 38,398 44,296 44,158 SERC-SE 48,110 48,014 55,327 55,217 SERC-W 29,095 29,053 37,890 35,696 Southern California 28,108 27,797 33,588 32,053 SPP 51,995 51,864 63,790 60,300 US T otal 761,845 757,343 906,407 886,072

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

36 D3. Summary of Target and Projected Reserve Margins in 2020 Projected Reserve Margins
NERC Assessment Re g io n Target Reserve Mar g in Base Case Polic y Case Policy % A bove Mar g i n Policy Change from Base Basin (BASN) 12.60% 16.51% 12.60% 0.0% -3.9% Desert Southwest (DSW) 13.50% 15.07% 13.50% 0.0% -1.6% ERCOT 13.75% 13.75% 13.75% 0.0% 0.0% FRCC 19.25% 26.79% 24.39% 5.1% -2.4% ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0% MAPP 15.00% 23.87% 15.00% 0.0% -8.9% MISO 16.30% 17.40% 16.30% 0.0% -1.1% Northern California ( CALN ) 14.71% 19.35% 14.71% 0.0% -4.6% Northwest (NORW) 17.90% 31.61% 28.79% 10.9% -2.8% NYISO 16.00% 16.00% 16.00% 0.0% 0.0% PJM 15.40% 15.40% 15.40% 0.0% 0.0% Rockies (Rock) 14.65% 24.39% 21.00% 6.4% -3.4% SERC-E 15.00% 15.00% 15.00% 0.0% 0.0% SERC-N 15.00% 15.00% 15.00% 0.0% 0.0% SERC-SE 15.00% 15.00% 15.00% 0.0% 0.0% SERC-W 15.00% 30.23% 22.87% 7.9% -7.4% S outhern California ( CALS ) 15.14% 19.50% 15.31% 0.2% -4.2% SPP 13.60% 22.69% 16.27% 2.7% -6.4% Grand Total 15.30% 18.98% 17.00% 1.7% -2.0%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

37 D4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2020
CC Coal CT NU OG Steam Total Basin (BASN) 43

‐ 179 0 0 108

‐ 28 Desert Southwest (DS W 553 881 0 0 513 1,948 ERCOT 0 391 0 0 0 391 FRCC 148 348 0 0 288 784 ISO

‐ NE 0 0 0 0 1,910 1,910 MAPP 0 462 0 0 0 462 MISO 0 5,146 0

‐ 1,112 0 4,034 Northern California (C A 141 0 1,898 0 0 2,039 Northwest (NORW) 675 52 0 860 0 1,588 NYISO 81 0 0 0 1,330 1,411 PJM 0 363 0 0 377 740 Rockies (Rock) 0 921 0 0 0 921 SERC

‐ E 0

‐ 132 0 0 0

‐ 132 SERC

‐ N 0 1,042 0 0 0 1,042 SERC

‐ SE 0 2,017 0 0 0 2,017 SERC

‐ W

‐ 434 823 0 0

‐ 92 297 Southern California (C A 2 0 75 0 2,942 3,019 SPP

‐ 206 2,845 0

‐ 554 98 2,184 Grand Total 1,004 14,981 1,974

‐ 806 7,474 24,627

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

38 D5. New Capacity Policy Case Incremental to Base Case(MW) Year= 2020 Region CC CT Wind Solar Other Total Basin (BASN) 0 0

‐ 1 00

‐ 1 Desert Southwest (DSW) 0 0

‐ 1 00

‐ 1 ERCOT 233 0

‐ 3 0 0 230 FRCC 0 0 0 0 0 0 ISO

‐ NE 0 0

‐ 265 0 0

‐ 265 MAPP 0 0

‐ 62 0 0

‐ 62 MISO 905 0

‐ 688

‐ 6 305 516 Northern California (CALN) 0 0

‐ 19 0

‐ 110

‐ 128 Northwest (NORW) 0 0

‐ 19 0 0

‐ 19 NYISO 0 0

‐ 448 0 0

‐ 448 PJM 1,380

‐ 1,797

‐ 292

‐ 16

‐ 237

‐ 962 Rockies (Rock) 0 0 0

‐ 84 0

‐ 84 SERC

‐ E 0 00

‐ 125 0

‐ 125 SERC

‐ N 1,554 0 0 0 0 1,554 SERC

‐ SE 0 0 0 0 0 0 SERC

‐ W 0 0 0 0 41 41 Southern California (CALS) 834 0

‐ 255 0 0 580 SPP 0 0

‐ 121 0 0

‐ 121 Grand Total 4,906

‐ 1,797

‐ 2,172

‐ 231 0 706

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

39 

### D6. Net Reserves Sent by NERC Assessment Region(MW) i n 2020

NERC Assessment Region Base Policy Change from Base to Policy Change as Percent of Summer Peak Basin (BASN) -1,772 -1,194 579 4.8% Desert Southwest (DS W 3,869 2,684 -1,185 -4.0% ERCOT -1,942 -1,942 0 0.0% FRCC 0 371 371 0.8% ISO-NE -1,823 -3,534 -1,710 -6.5% MISO -2,775 -3,958 -1,183 -1.2% Northern California (CAL 0 -909 -909 -4.3% Northwest (NORW) 407 2,617 2,210 8.7% NYISO 320 -906 -1,226 -4.1% PJM -4,614 -4,697 -84 -0.1% Rockies (Rock) 1,417 1,091 -325 -2.3% SERC-E -981 -616 365 0.9% SERC-N 1,502 2,169 667 1.7% SERC-SE 3,800 1,893 -1,907 -4.0% SERC-W 1,112 3,043 1,931 6.6% Southern California (CA L -3,761 -4,543 -782 -2.8% SPP 2,191 3,440 1,250 2.4%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

40 

### Appendix E: Tables by IPM Region for CPP Mass-Based Scenario in 2020 E1. Projected Operational Capacity E2. Summary of Summer Peak Loads and Reserve Capacity

E3. Summary of Target and Projected Reserve Margins E4. Policy Case Retired Capacity Incremental to Base Case E5. New Capacity in Policy Case Incremental to Base Case E6. Net Reserves Sent by NERC Assessment Region

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

41 

### E1. Projected Operational Capacity Year= 2025

All Generation Sources EE Capacity Overall Coal Only Region Base Policy Contribution Change Base Policy Basin (BASN) 14,293 12,687 687

‐ 919 4,802 3,345 Desert Southwest (DSW) 42,265 40,374 2,300 409 8,380 7,501 ERCOT 99,864 96,691 3,345 171 17,937 16,950 FRCC 56,336 55,647 2,080 1,391 7,479 7,131 ISO

‐ NE 32,685 30,497 1,644

‐ 545 0 0 MAPP 9,627 9,028 207

‐ 393 3,007 2,407 MISO 125,625 118,290 6,127

‐ 1,209 45,036 37,169 Northern California (CALN ) 29,389 27,278 1,321

‐ 791 71 17 Northwest (NORW) 51,181 48,752 2,036

‐ 393 2,406 1,513 NYISO 38,484 36,517 2,173 205 0 0 PJM 188,212 178,002 9,367

‐ 843 50,144 43,013 Rockies (Rock) 23,663 21,906 1,041

‐ 717 9,216 7,797 SERC

‐ E 55,904 52,622 2,556

‐ 727 11,045 10,907 SERC

‐ N 50,217 48,098 2,051

‐ 68 13,141 11,405 SERC

‐ SE 57,354 56,885 2,192 1,722 11,655 11,185 SERC

‐ W 40,012 38,007 1,069

‐ 936 4,733 3,918 Southern California (CALS) 43,405 39,745 2,159

‐ 1,501 57 57 SPP 78,704 74,286 2,733

‐ 1,685 22,966 18,522 Grand Total 1,037,223 985,310 45,085

‐ 6,828 212,075 182,836

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

42 E2. Summer Peak Loads and Reserve Capacity in 2025 Projected Reserve Margins
Assessment Re g io n Peak Demand

Base Peak Demand

Polic y Reserve Capacity

Base Reserve Capacity

Polic y Basin (BASN) 12,466 11,856 14,036 13,349 Desert Southwest ( 31,887 29,861 36,192 33,892 ERCOT 77,606 74,665 88,276 84,932 FRCC 46,355 44,611 55,279 53,199 ISO-NE 26,701 25,272 30,706 29,063 MAPP 5,539 5,360 6,370 6,164 MISO 93,625 88,356 108,885 102,758 Northern California 22,305 21,155 25,592 24,301 Northwest (NORW ) 26,489 24,909 36,672 32,084 NYISO 30,051 28,179 34,860 32,687 PJM 154,841 146,724 178,686 169,319 Rockies (Rock) 15,223 14,315 17,676 16,412 SERC-E 44,263 42,040 50,902 48,346 SERC-N 40,450 38,666 46,517 44,466 SERC-SE 50,430 48,524 57,994 55,802 SERC-W 30,589 29,660 35,644 34,109 Southern California 29,473 27,604 34,006 31,897 SPP 54,332 51,927 62,673 58,997 US T otal 792,624 753,649 920,969 871,777

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

43 E3. Summary of Target and Projected Reserve Margins in 2025 Projected Reserve Margins
NERC Assessment Re g io n Target Reserve Mar g in Base Case Polic y Case Policy % A bove Mar g i n Policy Change from Base Basin (BASN) 12.60% 12.60% 12.60% 0.0% 0.0% Desert Southwest (DSW) 13.50% 13.50% 13.50% 0.0% 0.0% ERCOT 13.75% 13.75% 13.75% 0.0% 0.0% FRCC 19.25% 19.25% 19.25% 0.0% 0.0% ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0% MAPP 15.00% 15.00% 15.00% 0.0% 0.0% MISO 16.30% 16.30% 16.30% 0.0% 0.0% Northern California ( CALN ) 14.71% 14.74% 14.87% 0.2% 0.1% Northwest (NORW) 17.90% 27.05% 25.96% 8.1% -1.1% NYISO 16.00% 16.00% 16.00% 0.0% 0.0% PJM 15.40% 15.40% 15.40% 0.0% 0.0% Rockies (Rock) 14.65% 16.12% 14.65% 0.0% -1.5% SERC-E 15.00% 15.00% 15.00% 0.0% 0.0% SERC-N 15.00% 15.00% 15.00% 0.0% 0.0% SERC-SE 15.00% 15.00% 15.00% 0.0% 0.0% SERC-W 15.00% 16.52% 15.00% 0.0% -1.5% S outhern California ( CALS ) 15.14% 15.38% 15.55% 0.4% 0.2% SPP 13.60% 15.35% 13.62% 0.0% -1.7% Grand Total 15.29% 16.19% 15.67% 0.4% -0.5%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

44 E4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2025
CC Coal CT NU OG Steam Total Basin (BASN) 43 1,458 0 0 108 1,609 Desert Southwest (DS W 553 881 0 0 513 1,948 ERCOT 0 991 0 0 0 991 FRCC 148 348 0 0 288 784 ISO

‐ NE 0 0 0 0 1,910 1,910 MAPP 0 600 0 0 0 600 MISO 0 7,895 0

‐ 1,112 0 6,783 Northern California (C A 141 54 1,898 0 0 2,093 Northwest (NORW) 675 893 0 860 0 2,429 NYISO 81 0 0 109 1,330 1,520 PJM 0 7,134 0 0 367 7,501 Rockies (Rock) 0 1,421 0 0 0 1,421 SERC

‐ E 0 137 0 0 0 137 SERC

‐ N 0 1,753 0 0 0 1,753 SERC

‐ SE 0 470 0 0 0 470 SERC

‐ W

‐ 434 823 0 0 1,957 2,346 Southern California (C A 2 0 75 0 3,016 3,093 SPP

‐ 206 4,462 0

‐ 554 932 4,635 Grand Total 1,004 29,319 1,974

‐ 697 10,421 42,021

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

45 E5. New Capacity Policy Case Incremental to Base Case(MW) Year= 2025 Region CC CT Wind Solar Other Total Basin (BASN) 0 0 3 0 0 3 Desert Southwest (DSW) 0 0 55 0 0 55 ERCOT

‐ 52

‐ 2,134 0 0 0

‐ 2,185 FRCC 94 0 0 0 0 94 ISO

‐ NE 0 0

‐ 265 0

‐ 13

‐ 278 MAPP 0 0 0 0 0 0 MISO

‐ 948 0 416

‐ 48 0

‐ 581 Northern California (CALN) 0 0

‐ 19 0 0

‐ 19 Northwest (NORW) 0 0 73 0

‐ 73 0 NYISO 0 0

‐ 448 0 0

‐ 448 PJM 1,447

‐ 2,094

‐ 1,933

‐ 133 0

‐ 2,713 Rockies (Rock) 0 0 0

‐ 375 37

‐ 338 SERC

‐ E

‐ 2,620 0 0

‐ 525 0

‐ 3,145 SERC

‐ N

‐ 383 0 0 0 0

‐ 383 SERC

‐ SE 0 0 0 0 0 0 SERC

‐ W 333 0 0 0 0 333 Southern California (CALS) 834 0

‐ 255

‐ 1,114

‐ 32

‐ 567 SPP 0 0

‐ 66

‐ 1 267 200 Grand Total

‐ 1,295

‐ 4,228

‐ 2,439

‐ 2,197 187

‐ 9,971

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

46 

### E6. Net Reserves Sent by NERC Assessment Region(MW) in 2025

NERC Assessment Region Base Policy Change from Base to Policy Change as Percent of Summer Peak Basin (BASN) -2,052 -2,971 -919 -7.4% Desert Southwest (DS W 1,846 2,219 372 1.2% ERCOT -1,931 -1,760 172 0.2% FRCC 838 2,229 1,391 3.0% ISO-NE -2,009 -2,345 -337 -1.3% MISO -2,502 -4,422 -1,920 -1.9% Northern California (CAL -1,490 -2,298 -808 -3.6% Northwest (NORW) 3,345 5,486 2,141 8.1% NYISO 249 834 585 1.9% PJM -6,877 -6,098 779 0.5% Rockies (Rock) 1,419 1,175 -243 -1.6% SERC-E -402 -727 -325 -0.7% SERC-N 2,141 2,074 -68 -0.2% SERC-SE -1,213 509 1,722 3.4% SERC-W 3,806 3,330 -476 -1.6% Southern California (CA L -3,309 -3,860 -552 -1.9% SPP 3,631 2,846 -785 -1.4%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

47 

### Appendix F: Tables by IPM Region for CPP Mass-Based Scenario in 2020 F1. Projected Operational Capacity F2. Summary of Summer Peak Loads and Reserve Capacity

F3. Summary of Target and Projected Reserve Margins F4. Policy Case Retired Capacity Incremental to Base Case F5. New Capacity in Policy Case Incremental to Base Case F6. Net Reserves Sent by NERC Assessment Region

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

48 

### F1. Projected Operational Capacity Year= 2030

All Generation Sources EE Capacity Overall Coal Only Region Base Policy Contribution Change Base Policy Basin (BASN) 14,346 13,573 1,135 361 4,802 3,172 Desert Southwest (DSW) 42,265 40,844 3,911 2,490 8,380 7,115 ERCOT 107,231 113,686 6,856 13,312 17,937 16,619 FRCC 61,471 57,489 4,357 375 7,414 6,324 ISO

‐ NE 32,688 30,510 2,518 340 0 0 MAPP 9,627 9,288 464 125 3,007 2,171 MISO 126,164 117,707 9,389 931 45,036 35,626 Northern California (CALN ) 29,389 27,278 1,976

‐ 136 71 17 Northwest (NORW) 51,415 48,834 3,171 589 2,406 1,332 NYISO 39,032 35,605 3,220

‐ 207 0 0 PJM 203,408 185,441 15,258

‐ 2,709 50,129 39,667 Rockies (Rock) 24,105 24,184 1,777 1,855 9,216 7,657 SERC

‐ E 59,039 53,149 4,304

‐ 1,585 11,045 10,405 SERC

‐ N 52,505 49,374 3,916 785 13,141 10,953 SERC

‐ SE 60,658 56,487 4,470 298 11,655 10,221 SERC

‐ W 40,602 38,739 2,247 385 4,733 3,918 Southern California (CALS) 49,260 46,137 3,238 114 57 57 SPP 79,238 75,215 5,534 1,510 22,506 18,036 Grand Total 1,082,444 1,023,537 77,741 18,833 211,536 173,291

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

49 F2. Summer Peak Loads and Reserve Capacity in 2030 Projected Reserve Margins
Assessment Re g io n Peak Demand

Base Peak Demand

Polic y Reserve Capacity

Base Reserve Capacity

Polic y Basin (BASN) 12,961 11,953 14,594 13,459 Desert Southwest ( D 34,589 31,144 39,259 35,348 ERCOT 82,455 76,428 93,793 86,936 FRCC 49,145 45,491 58,606 54,248 ISO-NE 27,433 25,243 31,547 29,029 MAPP 5,732 5,329 6,592 6,128 MISO 96,428 88,354 112,145 102,756 Northern California 23,372 21,652 26,810 24,867 Northwest (NORW ) 27,515 25,057 33,947 32,335 NYISO 30,694 27,918 35,605 32,385 PJM 160,273 147,051 184,955 169,696 Rockies (Rock) 16,419 14,869 18,824 17,047 SERC-E 46,801 43,058 53,821 49,517 SERC-N 42,204 38,799 48,534 44,619 SERC-SE 52,944 49,057 60,886 56,416 SERC-W 32,436 30,482 37,301 35,054 Southern California 30,929 28,127 35,684 32,494 SPP 57,092 52,245 64,857 59,639 US T otal 829,421 762,235 957,760 881,975

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

50 F3. Summary of Target and Projected Reserve Margins in 2030 Projected Reserve Margins
NERC Assessment Re g io n Target Reserve Mar g in Base Case Polic y Case Policy % A bove Mar g i n Policy Change from Base Basin (BASN) 12.60% 12.60% 12.60% 0.0% 0.0% Desert Southwest (DSW) 13.50% 13.50% 13.50% 0.0% 0.0% ERCOT 13.75% 13.75% 13.75% 0.0% 0.0% FRCC 19.25% 19.25% 19.25% 0.0% 0.0% ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0% MAPP 15.00% 15.00% 15.00% 0.0% 0.0% MISO 16.30% 16.30% 16.30% 0.0% 0.0% Northern California ( CALN ) 14.71% 14.71% 14.85% 0.1% 0.1% Northwest (NORW) 17.90% 23.38% 25.23% 7.3% 1.9% NYISO 16.00% 16.00% 16.00% 0.0% 0.0% PJM 15.40% 15.40% 15.40% 0.0% 0.0% Rockies (Rock) 14.65% 14.65% 14.65% 0.0% 0.0% SERC-E 15.00% 15.00% 15.00% 0.0% 0.0% SERC-N 15.00% 15.00% 15.00% 0.0% 0.0% SERC-SE 15.00% 15.00% 15.00% 0.0% 0.0% SERC-W 15.00% 15.00% 15.00% 0.0% 0.0% S outhern California ( CALS ) 15.14% 15.37% 15.53% 0.4% 0.2% SPP 13.60% 13.60% 14.15% 0.6% 0.6% Grand Total 15.28% 15.47% 15.71% 0.4% 0.2%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

51 F4. Policy Case Retired Capacity Incremental to the Base Case (MW) Year= 2030
CC Coal CT NU OG Steam Total Basin (BASN) 43 1,630 0 0 108 1,782 Desert Southwest (DS W 553 1,267 0 0 513 2,334 ERCOT 0 1,321 0 0 0 1,321 FRCC 148 1,089 0 0 288 1,525 ISO

‐ NE 0 0 0 0 1,910 1,910 MAPP 0 836 0 0 0 836 MISO 0 9,437 0

‐ 521 0 8,916 Northern California (C A 141 54 1,898 0 0 2,093 Northwest (NORW) 675 1,074 0 860 0 2,610 NYISO 81 0 0 1 1,330 1,412 PJM 0 10,469 0

‐ 1 367 10,835 Rockies (Rock) 0 1,561 0 0 0 1,561 SERC

‐ E 0 639 0 0 0 639 SERC

‐ N 0 2,205 0 0 0 2,205 SERC

‐ SE 0 1,433 0 0 0 1,433 SERC

‐ W

‐ 434 823 0 0 1,957 2,346 Southern California (C A 2 0 75 0 3,016 3,093 SPP

‐ 206 4,488 0

‐ 554 932 4,660 Grand Total 1,004 38,328 1,974

‐ 215 10,421 51,512

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

52 F5. New Capacity Policy Case Incremental to Base Case(MW) Year= 2030 Region CC CT Wind Solar Other Total Basin (BASN) 479 0 6 523 0 1,008 Desert Southwest (DSW) 0 0 57 853 0 911 ERCOT

‐ 4,378

‐ 5,173 0 17,325 0 7,773 FRCC

‐ 2,458 0 0 0 0

‐ 2,458 ISO

‐ NE 0 0

‐ 268 0 0

‐ 268 MAPP 0 0 497 0 0 497 MISO

‐ 543 0 1,054

‐ 80 0 431 Northern California (CALN) 0 0

‐ 19 0 0

‐ 19 Northwest (NORW) 0 0 28 0 0 28 NYISO

‐ 1,567 0

‐ 448 0 0

‐ 2,015 PJM

‐ 325

‐ 3,004

‐ 2,207

‐ 1,602 0

‐ 7,139 Rockies (Rock) 0 0 0 1,601 37 1,638 SERC

‐ E

‐ 4,418 0 0

‐ 833 0

‐ 5,250 SERC

‐ N

‐ 943 0 0 0 0

‐ 943 SERC

‐ SE

‐ 2,739 0 0 0 0

‐ 2,739 SERC

‐ W 476 0 0 0 0 476 Southern California (CALS) 117 0

‐ 255 79 29

‐ 30 SPP

‐ 505 0 859

‐ 2 267 619 Grand Total

‐ 16,804

‐ 8,177

‐ 696 17,864 334

‐ 7,479

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

53 

### F6. Net Reserves Sent by NERC Assessment Region(MW) in 2030

NERC Assessment Region Base Policy Change from Base to Policy Change as Percent of Summer Peak Basin (BASN) -2,563 -2,563 1 0.0% Desert Southwest (DS W -1,245 631 1,877 5.4% ERCOT -40 260 301 0.4% FRCC 2,646 3,021 375 0.8% ISO-NE -2,848 -2,282 567 2.1% MISO -5,473 -5,470 2 0.0% Northern California (CAL -2,709 -2,864 -154 -0.7% Northwest (NORW) 6,225 5,246 -979 -3.6% NYISO 26 301 275 0.9% PJM -5,123 -4,891 232 0.1% Rockies (Rock) 399 1,114 715 4.4% SERC-E -506 -1,455 -948 -2.0% SERC-N 2,412 3,197 785 1.9% SERC-SE -800 -503 298 0.6% SERC-W 2,732 3,122 390 1.2% Southern California (CA L -2,124 -1,859 264 0.9% SPP 1,933 2,389 456 0.8%

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

54 

### Appendix C: Maps

C1. IPM Regions C2. . NERC Assessment RegionsSummary	of	Interagency	Working	Comments	on	Draft	Language	underEO12866/13563	InteragencyReview.		Subject	to	Further	Policy	Review.55C1: IPM v5.13 RegionsSummary	of	Interagency	Working	Comments	on	Draft	Language	underEO12866/13563	InteragencyReview.		Subject	to	Further	Policy	Review.56C2:NERCAssessmentAreasinLongTermReliabilityAssessment.Source:NERC2012LongTermReliabilityAssessmentSummary	of	Interagency	Working	Comments	on	Draft	Language	underEO12866/13563	InteragencyReview.		Subject	to	Further	Policy	Review.57

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. Revised draf t CEIP language for the CPP Final Rule, 7/29/15

2. Provisions to encourage early action Many commenters supported providing incentives for states and utilities to deploy CO 2 

### -reducing investments, such as RE and demand-side EE measures, as early as possible. In the proposal, the EPA requested comment on an approach that would recognize emission reductions that existing programs provide prior to the initial plan performance period starting from a specified date. We also requested comment on options for that specified date and on conditions that should apply to counting those pre-compliance emission reductions toward a state goal. The EPA received many comments requesting that the agency recognize early actions for the emission reductions they provide prior to the performance period, that the EPA allow those pre-compliance impacts to be counted toward meeting requirements under the rule, and that certain conditions should be applied to recognition of early reductions so as to ensure the emission reductions required in the rule. We also received comments from stakeholders regarding the disproportionate burdens that some communities already bear, and stating that all communities should have equal access to the benefits of clean and affordable energy. The EPA recognizes the validity and importance of these perspectives, and as a result has determined to provide a program – called the Clean Energy Deleted: e

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. Incentive Program (CEIP) – in which states may choose to participate. This section describes this program. The CEIP is designed to reward investment in certain RE and demand-side EE projects that commence construction following the submission of an complete state plan, or after August 2018 for states that choose not to submit a complete state plan by that date, and that generate MWh (RE) or reduce end-use energy demand (EE) during 2020 and 2021. State participation in the program is optional; the EPA is establishing this program as an additional flexibility to facilitate achievement of the CO 2 

### emission reductions required by this final rule, regardless of the type of state plan a state chooses to implement. Under the CEIP, a state may set aside allowances from its interim target or generate early action emission rate credits (ERCs, as defined in section VIII.K.2), and allocate early action allowances or ERCs to eligible projects for the MWh those projects generate or avoid in 2020 and 2021. A state implementing a mass-based plan approach, as described in section VIII.C, may issue early action allowances; a state implementing a rate-based plan approach, also described in section VIII.C, may issue early action ERCs. For each early action allowance or ERC a state allocates to such projects, the EPA will provide the state with an appropriate number of matching allowances or ERCs, as outlined below, for the state to allocate to the project. The Deleted: effective date Deleted: approved or conditionally approved
Deleted: final state plan

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. EPA will match state-issued early action ERCs and allowances up to an amount that represents the equivalent of 300 million short tons of CO 2 

### emissions. The EPA has determined that the size of this matching pool is an appropriate reflection of the CO 2 

### emission reductions that could be achieved by the additional early investment in RE and demand-side EE the agency expects will be incentivized by the CEIP. For example, in 2012 13 GW ofutility scale wind deployed, and, in 2014, 3.4 GW of utilityscale solar plus 2-3 GW of distributed solar deployed according to industry estimates. Assuming 19 GW per year of renewables from 2017-2020 based on these historic maximums yields an installed base of 76 GW of renewables potentially eligible for CEIP incentives in 2020 and 2021. Assuming an average capacity factor of 30%, this would translate into approximately 200 TWh/year of generation, eligible for approximately 300 million short tons of CEIP allowances over the two year period, if the renewable MWh were converted to allowances based on the 2012 carbon intensity of 0.8 short tons per MWH. This would leave the remaining half of the cap available for low-income efficiency projects and additional growth in renewables deployment beyond these historic maximums as potentially enabled by reductions in cost and improvements in performance. For a state to be eligible for a matching award of allowances or ERCs from the EPA, it must demonstrate that it Deleted: would

Deleted: , would yield

Deleted:

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. will award allowances or ERCs only to “eligible” projects. These are projects that:

 Are located in or benefit a state that has submitted a final state plan that includes requirements establishing its participation in the CEIP;

 Are implemented following the submission of a complete state plan or after September 6, 2018 for states that choose not to submit a complete state plan by that date ;

 For RE: Generate metered MWh from any type of wind or solar

resources;

 For EE: Result in quantified and verified avoided generation through demand-side EE implemented in low-income communities; and

 Generate or avoid MWh in 2020 and 2021. The following provisions outline how a state may award early action ERCs and allowances to eligible projects, and how the EPA will provide matching allowances to states.

 For RE projects that generate metered MWh from any type of wind or solar resources: for every two MWh generated, the project will receive one early action ERC (or the equivalent number of allowances) from the state, and the EPA will provide one matching ERC (or the equivalent number Deleted: effective date
Deleted: of that state’s approved final

Deleted: , and that directly benefit Commented [A1]: Edit reflects concern about gaming

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. of allowances) to the state to award to the project or another eligible project
.

 For EE projects implemented in low-income communities: for every two MWh in end-use demand savings achieved, the project will receive two early action ERCs (or the equivalent number of allowances) from the state, and the EPA will provide two matching ERCs (or the equivalent number of allowances) to the state to award to the project or another eligible project
. Early action allowances or ERCs awarded by the state, and matching allowances or ERCs awarded by the EPA pursuant to the CEIP, may be used for compliance by an affected EGU with its emission standards and are fully transferrable prior to such

use. The EPA discusses the CEIP in the proposed federal plan rule, and will address design and implementation details of the CEIP, including the appropriate factor for determining equivalence between allowances and MWh and the definition of a low-income community for project eligibility purposes , in a subsequent action. Before doing so, the EPA will engage states and stakeholders to gather additional information concerning implementation topics, including the provisions outlined below, and to solicit information about the concerns, interests and priorities of states, stakeholders and the public. Deleted: that benefit

Deleted: how to determine Deleted:

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. In order for a state that chooses to participate in the CEIP to be eligible for an allocation of allowances or ERCs fromthe EPA, a state must include in its initial submittal a nonbinding statement of intent to participate in the program. In the case of a state submitting a final plan by September 6, 2016, the state plan would either include in its plan requirements establishing the necessary infrastructure to implement such a program and authorizing its affected EGUs to use early action allowances or ERCs as appropriate, or would include a non-binding statement of intent as part of its supporting documentation and revise its plan to include those requirements at a later date. Following these state plan submittals in 2016, the agency will create an allowance or ERC account for each participating state that reflects the pro rata share – based on the amount of the reductions from 2012 levels the affected EGUs in the state are required to achieve relative to those in the other participating states – of the 300 million short ton CO 2 

### emissions-equivalent pool that the state is eligible to receive. Thus, states whose EGUs have greater reduction obligations will be eligible to secure a larger proportion of the federal allocation upon demonstration of quantified and verified MWh of RE generation or demand side-EE savings realized in 2020 and 2021 from projects that commence construction after submission

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. of a final state plan or after September 6, 2018 for states that choose not to submit plans
. In its final state plan submission, due no later than September 6, 2018, or state plan revision if applicable, the state must include requirements for implementing the CEIP. If a state that indicated CEIP participation in its 2016 submittal either decides not to include the CEIP in its final plan, or includes state plan requirements for the CEIP that the EPA determines to be unapprovable, the EPA will redistribute the matching allowances or ERCs allocated to that state in 2016 to other qualifying states participating in the CEIP. Unused matching allowances or ERCs remaining in state accounts on January 1, 2023 will be retired by the EPA. For purposes of establishing a state plan program eligible for an award of matching allowances or ERCs from the EPA, such a program must include a mechanism for awarding early action emission allowances or ERCs for actions that reduce or avoid CO 2 

### emissions in 2020 and 2021, and that is implemented in a way such that the early action allowances or ERCs allocated by the state would maintain the stringency of the state’s goal for emission performance from affected EGUs in the performance periods established in this rule. Specifically, the state must demonstrate in its plan that it has a mechanism in place that enables issuance of ERCs or allowances from the state to parties

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. effectuating reductions in 2020 and 2021 in a manner that would have no impact on the aggregate emission performance of affected EGUs required to meet rate-based or mass-based emission standards during the compliance periods. 1 

### This demonstration is not required to account for matching ERCs or allowances that may be issued to the state by the EPA. Participation in this program is entirely voluntary, and nothing in these provisions would have the effect of requiring any particular affected EGU to achieve reductions prior to 2022, or requiring states to offer incentives for reductions achieved prior to 2022. 2 

### These and other details will be developed in the subsequent action.

1 

### For example, under a mass-based implementation, the state plan could include a set-aside of early action allowances from an emissions budget that itself reflects the state goals. Allocation of those early action allowances to parties effectuating reductions in 2020 and 2021 would have no impact on the total emissions budget, which sets the total allowable emissions in the compliance periods. Alternatively, under a rate-based implementation, the state plan could require that early action ERCs issued to parties effectuating reductions in 2020 and 2021 would be “ borrowed ” from a pool of ERCs created by the state during the interim compliance period. For every early action ERC awarded for actions in 2020 and 2021, the state would retire one ERC from the pool of ERCs created as a result of reductions achieved from 2022 onward. States could limit the size of the “ borrowed ” pool of credits to be equivalent to the size of the federal match pool, and could take into consideration the potential for each state ’ s federal match pool to expand after a redistribution of unused credits. 2 

### In addition to the Clean Energy Incentive Program, states may also offer credit for early investments in RE and demand-side EE according to the provisions of section VIII.K.1 of this final rule: a state may award ERCs to qualified providers that implement projects from 2013 onward that realize quantified and verified MWh results in 2022 and subsequent years. Deleted: the

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. The EPA is providing the CEIP as an option for states implementing plans – and is including a similar program for the Federal Plan proposal being issued concurrently – for several reasons. Chief among them are those offered by commenters to the effect that the overall cost of achievement of the emission performance rates or state goals could be reduced by an approach that granted some form of beneficial recognition to emissions reduction investments that both occur and yield reductions prior to the first date on which the program imposes emissions standards. Other commenters pointed out that to the extent thatstates and utilities would benefit from the availability of lowcost RE and other zero-emitting generation options during the interim and final periods, the EPA should include in the final guidelines provisions that accelerate deployment of RE resources, since in so doing the program would speed achievement of expected reductions in the cost of those technologies commensurate with their accelerated deployment. In addition, the he incentives and market signal generated by the CEIP can help sustain the momentum toward greater RE investment in the period between now and 2022 so as to offset any dampening effects that might be created by setting the compliance period start date two years later than at proposal. The specific criteria the EPA is establishing for eligible RE projects reflect a variety of considerations. First, the EPA Deleted: mandates reductions or

Deleted: EPA believes the CEIP can play an important role in supporting one of the critical policy benefits of this rule. In our analysis, we observed that by initiating the emission reduction mandate for EGUs in 2022, the rule created an investment environment that favored greater increases in the development and deployment of RE than we projected under the proposal. T Deleted: mandatory

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. seeks to preserve the incentive for project developers to execute on planned investments in all types of solar and wind technologies. Commenters raised concerns that the fast pace of reductions underlying the emission targets in the proposed rule could potentially shift investment from renewables to natural gas, thus dampening the incentive to develop wind and solar projects, in particular. Second, the EPA, consistent with the Clean Air Act’s directive to incentivize technology and to accelerate the decline in the costs of technology, seeks to drive the widespread development and deployment of wind and solar, as these broad categories of renewable technology are essential to longer term climate strategies. Third, in contrast to other CO 2 

### -reducing technologies – including other zeroemitting or RE technologies – solar and wind projects often require lead times of shorter duration, which would allow them to generate or avoid MWh beginning in 2020. The specific criterion the EPA is establishing for eligible EE projects – namely that these projects are implemented in lowincome communities - is also consistent with the technologyforcing and development purposes of section 111. The EPA believes it is appropriate to offer an additional incentive to remove current barriers to implementing demand-side EE programs in low-income communities. While the EPA acknowledges that a number of states have demand-side EE programs focused on these Deleted: required by early period reductions required in the proposed rule these guidelines Deleted:

Deleted: it is

Deleted: Finally, the EPA notes that these guidelines provide significant incentives for other zero-emitting technologies, particularly nuclear power, and as a result we do not have the same basis for including them in the CEIP as we do for wind and solar generation. Deleted: provide benefits Deleted: to

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. communities, 3 

### the agency also recognizes that there have been historic economic, logistical, and information barriers to implementing projects in these communities. As a result, the costs of implementing demand-side EE projects in these communities are typically higher than in other communities and stand as barrier to harvesting potentially cost effective reductions and advancing these technologies. The EPA intends for the CEIP to help incentivize increased deployment of projects that will deliver demand-side EE benefits to these communities, which will in turn lower the costs of these approaches . These lower costs will help new technologies and delivery mechanisms penetrate in the future, thus improving the cost of implementation for the program overall, consistent with Congress’ goals in the New Source Performance Standard provisions of the Act. Further, reducing barriers to demand-side EE in low-income communities will help ensure that the benefits of the Clean Power Plan are shared broadly across society and that potential adverse impacts on low-income ratepayers are avoided. It complements other steps the federal government is taking to bring clean energy technologies to these communities, as we discuss in section IX of this preamble.

3 

### Several of these programs are discussed in section IX of this preamble, including, for example, Maryland’s EmPOWER Low Income Energy Efficiency Program (LIEEP) and New York’s EmPower New York program. Deleted: technologies

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. More broadly, the CEIP responds to the urgency of meeting the challenge of climate change in two key ways. First, of course, it fosters reductions before 2022. Second, in targeting investments in wind, solar and low-income EE, it focuses on the kinds of measures and technologies that are the essential foundation of longer term climate strategies, strategies that inevitably depend on the further development and widespread deployment of highly adaptable zero-emitting technologies. We are not requiring that projects demonstrate to statesthat they are “additional” or surplus relative to a business-asusual or state goal-related baseline in order to be eligible. At the same time, we believe that including an incentive to develop projects that benefit low-income communities will increase the likelihood of investments being made that would not have been made otherwise. In order to be awarded matching ERCs or allowances by the EPA for projects that meet the eligibility criteria, a final state plan must have requirements establishing the appropriate infrastructure to issue early action ERCs and allowances to eligible project providers by 2020. The state must require that the state or its agent will, in accordance with state plan requirements approved as meeting the ERC issuance and EM&V requirements included in section VIII.K: (1) evaluate project proposals from RE and demand-side EE project providers, Deleted: demand-side

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. including the EM&V plans that must accompany such proposals; (2) evaluate monitoring and verification reports submitted by providers following project implementation, which contain the quantified and verified MWh of RE generation or energy savings achieved by the project in 2020 and 2021; (3) issue ERCs (or their equivalent in allowances) to eligible providers for these MWh results; (4) ensure that no MWh of renewable or avoided generation receives early action or matching ERCs (or their equivalent in allowances) more than once. The CEIP will provide a number of benefits. First, the program will provide incentives designed to reduce energy bills early in the program through earlier and broader application of energy saving technologies, and help ensure that these benefits

are fully shared by low-income communities. Second, the EPA believes that stimulating or supporting early investment in RE generation technologies could accelerate the rate at which the costs of these technologies fall over the course of the interim performance period. In addition, the CEIP will provide affected EGUs and states with additional resources to help them achieve their state plan obligations. Finally, the program will improve the liquidity, in the early years of the program, of the ERC and allowance markets we expect to emerge for compliance with the Commented [A2]: Can we require use of the federal tracking system for this purpose

Deleted: with

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view. requirements of these guidelines. 4 

### The EPA is establishing this program as an option for states that wish to drive investments in RE and low-income EE that will result in actual, early reductions in CO 2 

### emissions from affected EGUs. States are also authorized to set their own glide path, or interim step performance rates or goals, so long as the interim and final performance rates or goals are met, and could do so in a way that takes into account the availability of the CEIP to assist affected EGUs in meeting the applicable glide path and performance rates or goals. While the EPA is not requiring states to take advantage of this program, its availability simply enhances these already-existing implementation and compliance flexibilities while at the same time delivering meaningful benefits, particularly for low-income communities. The EPA looks forward to an upcoming public dialogue about the implementation details of the CEIP.

4 

### The Clean Energy Incentive Program is expected to provide states and affected EGUs additional flexibility in complying with the guidelines, and bears similarity in both design and purpose to the Compliance Supplement Pool, which the agency established as a part of the NO x 

### SiP Call. See 63 FR 57356, 57428-30 (Oct. 27, 1998). Certain aspects of the Compliance Supplement Pool were challenged in litigation and upheld by the D.C. Circuit Court of Appeals. See Michigan v. EPA , 213 F.3d 663, 694 (D.C. Cir. 2000). Deleted: The CEIP does not modify the CO 2 emission performance rates or the final goals. Commented [A3]: Modification of goals may be desirable to offset borrowed ERCs in rate
‐ based states...

Deleted: demand-side