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 >> 

<< SummaryOfInteragencyCommentsUnder_EO12866_EO13563_CPP_CEIP.DOCX >> 

<< SummaryOfInteragencyCommentsUnder_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 

region1

, 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 flexibilities 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 maintaining 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 ensuring 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 scenarios 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 Model (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 CO2

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 this resource adequacy and reliability assessment, estimates 

and projections are taken from those 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 (v5.15), including all the underlying 

assumptions, data sources, and architecture parameters can be found on EPA’s website at: 

http://www.epa.gov/powersectormodeling/BaseCasev515.html 7 See Chapter 3 of the RIA for additional detail on the scenarios analyzed.

Deleted: ’s

Deleted: least-cost dispatch solution, 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

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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 capacity8

 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 988,7649

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 reserves 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 region10 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 capacity12 (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 is 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 Scenarios14

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 (shown 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 reserves can be transferred reliably. The transfer of 

reserves can occur, for example, if a region retires capacity that was used in the base case to meet 

reserve requirements, but a neighboring region has lower cost reserves that are not needed for its 

own reserve requirements. To examine these transfers, the EPA analyzed the change in net 

transfers from each region, where the net transfer for the base and policy cases is measured by 

the reserves sent to neighboring regions. In these cases, a positive value signifies the reserve 

capacity sent to other regions is larger than the reserve capacity received from other regions 

(sending and receiving regions can be different), while a negative value signifies that the 

capacity received is larger than the capacity sent. Thus, the value measures the degree to which 

resources in the region were reserved for use by other regions (positive value), or where the 

capacity to meet load in the region was served by resources in other regions (negative value). In 

each case these reserve transfers represent the use of the transmission system on a firm basis for 

at least a season. 

To look at the 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 these 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 

anypotential 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 their 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 (incremental 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 compared 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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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 (DSW 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 (CA 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 (CA 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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A2. Summer Peak Loads and Reserve Capacity in 2020

Projected Reserve Margins

Assessment 

Region

Peak 

Demand 

Base

Peak 

Demand 

Policy

Reserve 

Capacity 

Base

Reserve 

Capacity 

Policy

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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A3. Summary of Target and Projected Reserve Margins in 2020

Projected Reserve Margins

NERC Assessment 

Region

Target 

Reserve 

Margin Base Case Policy Case

Policy % 

Above Margin

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%

Southern 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%
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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 (DSW 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 (CA 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 (CA 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	Comments	on	Draft	Language	under

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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	Comments	on	Draft	Language	under

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A6.  Net Reserves Sent  by NERC Assessment Region(MW) in2020

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 (DSW 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 (CAL -3,761 -4,884 -1,124 -4.0%

SPP 2,191 2,872 682 1.3%
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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	Comments	on	Draft	Language	under

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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	Comments	on	Draft	Language	under

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B2. Summer Peak Loads and Reserve Capacity in 2025

Projected Reserve Margins

Assessment 

Region

Peak 

Demand 

Base

Peak 

Demand 

Policy

Reserve 

Capacity 

Base

Reserve 

Capacity 

Policy

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	Comments	on	Draft	Language	under

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B3. Summary of Target and Projected Reserve Margins in 2025

Projected Reserve Margins

NERC Assessment 

Region

Target 

Reserve 

Margin Base Case Policy Case

Policy % 

Above Margin

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%

Southern 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	Comments	on	Draft	Language	under

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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 (DSW 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 (CA 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 (CA 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	Comments	on	Draft	Language	under

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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	Comments	on	Draft	Language	under

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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 (DSW 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 (CAL -3,309 -4,091 -782 -2.7%

SPP 3,631 3,059 -572 -1.1%
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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	Comments	on	Draft	Language	under

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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	Comments	on	Draft	Language	under

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28

C2. Summer Peak Loads and Reserve Capacity in 2030

Projected Reserve Margins

Assessment 

Region

Peak 

Demand 

Base

Peak 

Demand 

Policy

Reserve 

Capacity 

Base

Reserve 

Capacity 

Policy

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	Comments	on	Draft	Language	under

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29

C3. Summary of Target and Projected Reserve Margins in 2030

Projected Reserve Margins

NERC Assessment 

Region

Target 

Reserve 

Margin Base Case Policy Case

Policy % 

Above Margin

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%

Southern 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	Comments	on	Draft	Language	under

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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 (DSW 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 (CA 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 (CA 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
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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	Comments	on	Draft	Language	under

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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 (DSW -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 (CAL -2,124 -3,120 -997 -3.2%

SPP 1,933 2,271 337 0.6%
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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 
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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
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D2. Summer Peak Loads and Reserve Capacity in 2020

Projected Reserve Margins

Assessment 

Region

Peak 

Demand 

Base

Peak 

Demand 

Policy

Reserve 

Capacity 

Base

Reserve 

Capacity 

Policy

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
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D3. Summary of Target and Projected Reserve Margins in 2020

Projected Reserve Margins

NERC Assessment 

Region

Target 

Reserve 

Margin Base Case Policy Case

Policy % 

Above Margin

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%

Southern 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%
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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 (DSW 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 (CA 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 (CA 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
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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	Comments	on	Draft	Language	under

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39

D6.  Net Reserves Sent  by NERC Assessment Region(MW) in2020

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 (DSW 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 (CAL -3,761 -4,543 -782 -2.8%

SPP 2,191 3,440 1,250 2.4%
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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 
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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	Comments	on	Draft	Language	under

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E2. Summer Peak Loads and Reserve Capacity in 2025

Projected Reserve Margins

Assessment 

Region

Peak 

Demand 

Base

Peak 

Demand 

Policy

Reserve 

Capacity 

Base

Reserve 

Capacity 

Policy

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
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E3. Summary of Target and Projected Reserve Margins in 2025

Projected Reserve Margins

NERC Assessment 

Region

Target 

Reserve 

Margin Base Case Policy Case

Policy % 

Above Margin

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%

Southern 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%
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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 (DSW 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 (CA 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 (CA 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
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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
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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 (DSW 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 (CAL -3,309 -3,860 -552 -1.9%

SPP 3,631 2,846 -785 -1.4%
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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 
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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	Comments	on	Draft	Language	under

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49

F2. Summer Peak Loads and Reserve Capacity in 2030

Projected Reserve Margins

Assessment 

Region

Peak 

Demand 

Base

Peak 

Demand 

Policy

Reserve 

Capacity 

Base

Reserve 

Capacity 

Policy

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	Comments	on	Draft	Language	under

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50

F3. Summary of Target and Projected Reserve Margins in 2030

Projected Reserve Margins

NERC Assessment 

Region

Target 

Reserve 

Margin Base Case Policy Case

Policy % 

Above Margin

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%

Southern 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%
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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 (DSW 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 (CA 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 (CA 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
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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	Comments	on	Draft	Language	under

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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 (DSW -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 (CAL -2,124 -1,859 264 0.9%

SPP 1,933 2,389 456 0.8%
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Appendix C: Maps 

C1. IPM Regions 

C2. . NERC Assessment Regions 
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C1: IPM v5.13 Regions
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C2: NERC Assessment Areas in Long Term Reliability Assessment.

Source: NERC 2012 Long Term Reliability Assessment
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Revised draft 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 CO2-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 

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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 CO2 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 

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EPA will match state-issued early action ERCs and allowances up 

to an amount that represents the equivalent of 300 million short 

tons of CO2 emissions. The EPA has determined that the size of 

this matching pool is an appropriate reflection of the CO2

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 of 

utility 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

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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 

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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

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 In order for a state that chooses to participate in the 

CEIP to be eligible for an allocation of allowances or ERCs from 

the 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 CO2

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 
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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 CO2 

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 
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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.

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 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 that 

states 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 
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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 CO2-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 
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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
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 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 states 

that 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, 

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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 bylow-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 
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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 CO2 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 NOx 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 CO2

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