From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov> 

Sent: Wednesday, July 29, 2015 3:12 PM 

To: Vasu, Amy; Culligan, Kevin; Harvey, Reid 

Cc: Frey, Nathan J.; Grossman, Andrea 

Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- Clean Power Plan 

Documents 

Attached please find a summary of interagency comments under EO 12866 and 13563 on related 

documents to support EPA’s draft final rule entitled “Carbon Pollution Emission Guidelines for 

Existing Stationary Sources: Electric Utility Generating Units.” The summary of interagency 

comments are on the following related documents: 

1. Summary of Interagency Comments on the GHG Mitigation TSD; 

2. Summary of Interagency Comments on the New Source Complements TSD; 

3. Summary of Interagency Comments on the Resource Adequacy TSD; 

4. Summary of Interagency Comments on the CPP Regulatory Impact Analysis. 

 

Thank you and please let me 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 

<< Summary of Interagency Comments under 

EO12866_EO13563_CPP_GHGMitigationT....docx >> 

<< Summary of Interagency Comments under 

EO12866_EO13563_CPP_NewSourceCompl....docx >> 

<< Summary of Interagency Comments EO12866_EO13563_Resource Adequacy TSD.DOCX >> 

<< Summary of Interagency Comments under EO12866_EO13563_CPP_RIA.DOCX >> 
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GHG Mitigation TSD for EPA’s Clean Power Plan 

BB2 Section (Chapter 3): 

1. Page 3-2, sentence stating “Other generating technologies, like renewables, hydroelectric, 

and nuclear, have little or no variable costs and are generally dispatched to the extent 

possible.” Reviewer recommends clarifying including nuclear within the discussion as 

there are current economic concerns for merchant nuclear. Reviewer recommends 

providing a footnote discussing interim capital costs for upgrades and maintenance that 

can impact dispatch cost. 

2. Page 3-15. Reviewer recommends changing the sentence to state “According to EIA, 

natural gas proven reserves have doubled between 2000 and 2012.” 
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EPA’s New Source Complements to Mass Goals TSD for CPP Final Rule 

1. Excel Spreadsheet, New Source Complements Tab. Reviewer notes that the increase in the 

“Affected EGU and RE Generation Growth Incorporated in Mass Goal Calculation (GWh)” 

(found in columns AB-AJ) from 2027 to 2028 is equivalent to the increase from 2022 to 

2026. Reviewer recommends clarifying the reason for this yearly increase. 

2. Page 2. Reviewer recommends modifying the sentence to state: 

a. Convert state-level incremental generation to state-level incremental emissions by 

assuming the New Source Performance Standard emission rate for NGCC of 1,030 

lbs/MWh-net. 

3. Page 4. Reviewer recommends additional clarification to confirm that the 55% to 75% 

NGCC ratio relates to understand the concept of assigning some portion of an underconstruction EGU generation to past closings or need short-falls, and not the assumed BB2 

baseline and ramp-up potential applicable to under construction NGCC units. Is this 

coincidental? 

4. Page 8. Reviewer recommends adding a footnote in the sentence, “Each state-level new 

source complement generation level is multiplied by the NSPS NGCC emission rate standard 

of 1,030 lbs/MWh to produce a mass value” to state that the same mathematical concept can 

be applied partially or in full to future new coal units with CCS. 

a. Reviewer recommends: “This concept and the mathematical procedures can be modified 

in state plans to account for new 111(b) compliant fossil steam generation EGUs not yet 

planned, should these be constructed, in combination with the 111(b) compliant new 

NGCC units.” 
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Technical Support Document: 

Resource Adequacy and Reliability Analysis 

This document describes resource adequacy and reliability impacts of the two illustrative 

state plan scenarios that are reflected in the Regulatory Impact Analysis (RIA) that supports 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. 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

It is important to recognize that the final rule provides flexibility in the context of state 

plan development that preserves 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 electric reliability. 

For more detail on how the final CPP addresses reliability, see Section VIII of the final rule 

preamble. The results presented in this document show that power system impacts of the final 

rule on system operations, under conditions preserving resource adequacy, are modest and 

manageable. 

                                                            

1 As analyzed in this document, power regions correspond to aggregates of IPM regions corresponding to NERC

assessment areas. 2 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. 3 See final rule Regulatory Impact Analysis for more detail on the power sector impacts of the final CPP.
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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 

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.4

IPM’s least-cost dispatch solution, under any scenario, will 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. This document focusses on key regional results important to 

management of the power system. 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 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.5

 The scenarios include a base 

case (no CPP), a rate-based state plan scenario and a mass-based state plan scenario. For 

                                                            

4 Detailed information and documentation of EPA’s Base Case using IPM (v5.13), including all the underlying 

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

http://www.epa.gov/powersectormodeling/BaseCasev513.html

5 See Chapter 3 of the RIA for additional detail on the scenarios analyzed.

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purposes of the resource adequacy and reliability assessment, estimates and projections are taken 

from the same scenarios and years as shown in the RIA (2020, 2025, and 2030). 

CPP Rate-Based Scenarios 

Summary of Changes in Operational Capacity 

Total operational capacity is lower in the CPP scenario, primarily from 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 of, is discussed 

first, followed by discussion of 2020 and 2030. Operational generating capacity6

 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 988,7647

Since the model must maintain adequate reserves in each region, a portion of the reduced 

operational capacity in the CPP case is taken from reduced need for reserves compared to the 

                                                            

6

 Operational capacity is any existing, new or retrofitted capacity that is not retired. 

7

 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. 

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base case. In order to maintain resource adequacy in each region where existing resources retire, 

the model relies on any excess reserve 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 additions even 

though there are substantial increases in retirements. Each of these CPP case changes is 

discussed further below. 

Reduction in Reserve Requirements and Excess Reserves 

IPM uses a target reserve margin in each region8

 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.9

 The majority of this reduction is the result of 

decreases 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 capacity10 (see Table B1 

for regional detail). Moreover, these reductions are from energy efficiency that is available in all 

                                                            

8

 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. 

9

 Regional data on operational capacity is shown in Table A1 of the Appendix. 

10 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 in reduced by 100 MW 

and the reserve margin percentage in a region is 15%, the reduction in reserve capacity requirements is 115MW. 
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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 

available to plan for any system changes. Moreover, retirements are distributed throughout the 

power grid, so there will be only small impacts at the regional level.11 

Although there are substantial existing regional variations in reserve margin, IPM adjusts 

regional operating capacities in 2025 to meet the specific target reserve margin in each region, 

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 Scenarios12

There are significant levels of fossil steam – coal and oil/gas – retiring in 2025 in both the 

base and CPP scenario. The incremental final rule case retirements 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 new 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 of the retiring units shown in Table 1 above and in Table 

A4, these can be managed within the normal reliability planning and management time frames 

provided by the flexible resource options and time frames in the 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 might that do not occur in the policy scenario projections might, in 

                                                            

11 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. 

12 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. 
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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 

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 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%.13 

                                                            

13 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.

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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 

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 shifts under 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 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 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 are compared below 

with the 2025 results for purposes of illustration. 

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 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, 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 compared to 2025 

(24,567MW compared to 36,961MW in 2025), so that the modeling confirms that the major 

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 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 and policy 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 new of an 

incremental 4,338 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 

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CPP Mass-Based Scenarios 

The EPA also examined the mass scenario modeling results to identify differences with 

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. 

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 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 Deleted: 
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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 2030: only 

minor variations in total operating capacity, somewhat higher fossil steam retirements, and 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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Commented [A1]: Did you mean 2030?
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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 Commented [A2]: 1. The Appendices A following do not match

this order.

2. For all appendices, the titles of the appendices have strange

centering if they run to a second line.

3. Check titles for a space before (MW), some have it, some don’t.
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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
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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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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 (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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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	Comments	on	Draft	Language	under

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18

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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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 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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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21

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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22

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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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	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

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

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
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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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
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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35

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
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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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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
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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
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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
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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
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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 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	EO12866/13563	Interagency	

Review.		Subject	to	Further	Policy	Review.

55

C1: IPM v5.13 Regions
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	EO12866/13563	Interagency	

Review.		Subject	to	Further	Policy	Review.

56

C2: NERC Assessment Areas in Long Term Reliability Assessment.

Source: NERC 2012 Long Term Reliability Assessment
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	EO12866/13563	Interagency	

Review.		Subject	to	Further	Policy	Review.

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Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

EPA’s Clean Power Plan Regulatory Impact Analysis 

1. Reviewer recommends providing additional discussion related to the cost for EE on page 3-

15. Specifically, the costs for EE may be too high and thus overly conservative. To ensure 

completeness within the RIA, reviewer recommends providing a footnote after the sentence 

on 3-15: “The total levelized cost of saved energy was calculated based upon the same inputs 

and using a 3 percent discount rate resulted in national average values of 9.2 cents per kWh 

in 2020, 8.6 cents per kWh in 2025, and 8.1 cents per kWh in 2030.” 

a. The footnote should state: EPA has taken a conservative approach to avoid 

underestimating the costs of saved energy. This result is higher than what has been 

observed in many retrospective evaluations of energy efficiency cost effectiveness, 

implying actual costs may be significantly less. Estimates using the same method with 

large programs and the average of reviewed costs would result in lower estimated costs of 

saved energy. Additionally, historical studies reviewed in TSD Section 4.3.2 find 

program costs averaging between 2.1 - 3 cents/kWh (approximately 4.2 - 6 cents/kWh if 

individual costs are also included).