From: Culligan, Kevin [mailto:Culligan.Kevin@epa.gov] 

Sent: Friday, May 30, 2014 2:11 PM 

To: Higgins, Cortney 

Cc: Wayland, Robertj 

Subject: Resource Adequacy TSD 

Hopefully another TSD done 

<< TSD Resource Adequacy and Reliability Analysis.pdf >> 
1

Technical Support Document:

Resource Adequacy and Reliability Analysis 

This document describes resource adequacy and reliability impacts in 2020 for selected 

policy scenarios from this proposal, compared to a base case without the policy. As used here, 

the term resource adequacy means the provision of adequate generating resources to meet 

projected load and generating reserve requirements in each region, 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 policy, in the context of a base case 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.1 The EPA uses the 

Integrated Planning Model (IPM) to project likely future electricity market conditions with and 

without the proposed rule.

Although not the focus of this document, it is important to recognize that this proposal 

provides flexibility in the context of state plan development that preserves the ability of 

responsible authorities to maintain electric reliability. For example, relevant planning authorities 

(such as ISOs and RTOs) may consult with states during the formulation of a state plan. ISOs 

and RTOs have also expressed interest in discussing the facilitation of emission control 

requirements under multi-state approaches. The flexibility of meeting the state goal over time 

also allows short-term variation in CO2 emissions that may occur as certain generators run for 

short periods of time to maintain system reliability. While not discussed further here, these facts 

further support this document’s demonstration that the implementation of this rule can be 

achieved without undermining resource adequacy or reliability.

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 

 

1 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 2020. 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.
2

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.2

IPM is specifically 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, 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 power 

sector impacts of the proposed rule, see the Regulatory Impact Analysis. 

Overview

The EPA is proposing 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 state-specific rate-based goals for carbon dioxide emissions from the 

power sector, as well as guidelines for states to use in developing plans to attain the state-specific 

goals. This rule, as proposed, would set in motion actions to lower the carbon intensity of power 

generation in the United States. The agency is proposing one option (Option 1) for state-specific 

goals and requesting comment on a second option (Option 2).

3 For purposes of this resource 

adequacy and reliability assessment, estimates and projections are taken from the Option 1 State 

scenario. This option was chosen because it limits compliance choices more than the 

corresponding regional option, and is more likely than the regional option to pose challenges to 

resource adequacy.

4

 The Option 1 Regional scenario results are discussed relative to the results 

from the Option 1 State scenario.

 

2 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

3

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

4 For more detail on the economic impacts, and more discussion of the compliance scenarios, see Chapter 3 of the 

RIA for this proposal.
3

Option 1 (State) Policy Scenario

Summary of Changes in Operational Capacity

Total operational capacity is lower in the policy 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 over time. Operational capacity5changes from the 

base case in 2020 are summarized below:

Table 1. Operational Capacity Summary in 2020

Base case operational capacity (MW) 1,004,942

 Minus Retirements in Policy Case:

 (-) Coal -48,996

 (-) Oil-Gas Steam -16,131

 (-) Combustion Turbine -2,328

 (-) Combined Cycle -3,455

 Plus New Capacity 36,118

Equals Policy Case Operational Capacity 970,1506

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

operational capacity in the policy case is taken from reserves that currently exceed the target 

reserve margin and will not be needed in the future. In order to maintain resource adequacy in 

each region where existing resources retire, the model relies on this excess reserve reduction, 

additions of new capacity, and reduced total resource requirements from increases in energy 

efficiency. As the table shows, the reduced resource needs permit lower capacity additions even 

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

discussed further below.

 

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

6 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.
4

Reduction in Excess Reserves

IPM uses a target reserve margin in each region7as 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 2020 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 2020 will not need to be replaced. 

Table 1 above shows that operational capacity is reduced by approximately 3.5 percent 

nationwide in 2020 under the policy.8 The majority of this reduction is the result of decreases in 

load; in 2020 summer peak loads are reduced by around 3 percent nationwide, or approximately 

24 GW (see Table A1). At the projected reserve margins in 2020 of 19 percent in the base case, 

these reductions reduce reserve capacity needs by around 28 GW, or about 80 percent of the 

overall reduction in load of 35 GW shown in Table 1. 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 3.5 percent in 2020 will therefore have little overall 

impact. Moreover, retirements are distributed throughout the power grid, so there will be only 

small impacts at the regional level.

9

 Excess regional reserves above the target margin can be 

shared among sub-regions to ensure adequate reserve margins within a larger reliability region. 

IPM permits these transfers of reserves, but limits their level to ensure the reliability of the bulk 

power system. These interregional transfers are discussed further below.

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

regional capacities in 2020 to meet the specific target reserve margin in each region, through 

 

7 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.

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

9 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.
5

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 2020 projections is described below.

Changes in Retirements and New Capacity Additions in the Policy Case10

Although there are significant retirements of 49 GW of coal and 16 GW of Oil-Gas 

Steam plants in the policy case in 2020 compared to the base case, these are offset by 28 GW of 

capacity from load reductions discussed above and by changes in new capacity additions. 

Retiring coal units are generally older and smaller, and retiring oil/gas steam units are generally 

older, less efficient and infrequently used units. Where needed for reserve margin, this retiring 

capacity is replaced by 23 GW of Natural Gas Combined Cycle capacity, 2 GW of Combustion 

Turbine capacity and 10 GW of wind capacity (See Table A5). This new capacity of 35 GW

amounts to approximately 4% of the current reserve capacity (See Table A2 for current summer 

reserve capacity); adding this amount of capacity to replace retiring coal and oil/gas steam units

is unlikely to present resource adequacy concerns. Overall, combined generation from natural 

gas and coal is projected to fall by less than 5 percent at the national level in 2020 in the policy 

case compared to the base case; a shift this small in the total capacity of units capable of 

providing ancillary services to the grid should be entirely manageable within the normal

parameters required for maintaining reliable operation. 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 rule. 

The distribution of these retirements and additions across NERC Assessment regions is

shown in Appendix C.

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 

 

10 Retirement and additions in this section are all incremental to the base case in 2020; the GW 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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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 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. The results of this measurement are shown in Table A6. As the Table shows, 

only three regions are at or above a 5%. The EPA believes changes below 5% are unlikely to 

raise concerns over reliability; the three changes at or above 5% are discussed further below.

Using this measure, the largest change in reserves are in the Northeast in ISO-NE, and in 

the Southeast in SERC-SE and FRCC. In ISO-NE the change in reserves is additional receipts of 

1947 MW, increasing net reserves received from 938 MW to 2,885 MW. The majority of this 

change resulted from a net decrease of 1261MW in the reserves sent from ISO-NE regions to 

regions in the NYISO; the remainder resulted from a net increase in the reserves received from 

Canada and from NYISO. In projecting these shifts, IPM is constraining flows within the transfer 

limits between IPM regions, but also limiting the total flow between all the IPM regions in 

NYISO (New York State) and ISO-NE (all the states in New England).11 The modeling thus 

considers both basic line limits and broader transmission system limits on overall flows. The 

 

11 For details on these limits, see the IPM documentation.
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shifts in grid transfers exhibited in the IPM modeling suggest overall grid adjustment that is 

shared by these RTOs within manageable limits, and do not appear to be a cause for concern. 

In the Southeast, the largest percentage change occurs in SERC-SE. In the base case, 

SERC-SE sends a net 2,071 MW to other regions, while in the policy case it receives a net 2,092 

MW from other regions. This change amounts to a shift of in increased receipts relative to the 

base case of 4, 163 MW (8.3% of load in the base case). Although this shift is relatively large 

compared to other regions, there is little change in the absolute magnitude of transfers that need 

to be managed, since transfers shift from reserves sent to reserves received – in both cases the 

transfer is around 2,000 MW. The shift to receipts corresponds to the other large shift in the 

Southeast, as shift in FRCC from zero MW sent to 3,420 MW sent. All of these transfers are to 

SERC-SE, the only region to which FRCC is connected. When the larger SERC region is 

considered12, combining all the individual SERC regions, the shift as a percentage of load drops 

to 4.8% of the total SERC load. These overall changes fall within the planning areas of SERC 

and are related to the placement of new capacity; within this planning area the shifts of this 

magnitude should be manageable. 

Alternative Case: Option 1 (Regional)

As discussed above, the Option 1 (State) was chosen for the basic impact analysis 

because it provides a stricter test of potential reliability impacts. The EPA also examined the 

preferred Option 1 (Regional) case to identify differences with the State case and assess potential 

impacts. Tables B1 through B5 in Appendix B present results that correspond to Option 1 (State) 

Tables A1 through A5. As expected, both 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. Total operating capacity differs by less than one percent and 

regional operating capacities are within 5 percent except for MAPP.13 Reserve capacity and 

projected reserve margins for Option 1 (Regional) (Tables B2 and B3) follow a pattern similar to 

 

12 This the entire SERC region, consisting of SERC-SE, SERC-N, SERC-E and SERC-W. See map in Appendix for 

details.

13 MAPP has only 9 GW and the policy cases differ by 9.0 percent. An additional 848 MW of Wind capacity is 

added in the regional scenario compared to the state scenario.
8

operating capacity: totals are within 1% of the projections for the corresponding outputs from 

Option 1 (State) and regional reserve capacities are under 5 percent.

Differences between the cases develop in the types of capacity that are retired and in the 

amount and types of new capacity built in2020. The Regional results show fewer incremental 

retirements of coal capacity (46.1 GW compared to 49.0 GW) and in the total retired capacity 

(68.4 GW compared to 70.6 GW). Retirements of Oil-Gas capacity remain essentially unchanged 

between the two cases (16.3 GW) and other retirements are small (see Tables A4 and B4.) The 

decrease in retired coal capacity of 2.8 GW are offset by a decrease in new combined cycle 

capacity of the 2.1 GW. Overall, these results indicate a greater flexibility in the choice of which 

units are used to serve capacity needs, a result that indicates general flexibility over capacity 

choices. Managing these increases and decreases should raise no reliability issues. Retirements 

of Oil/Gas Steam capacity remain unchanged between the options and no further reliability 

issues arise in the regional case. 

A similar indication of greater flexibility is seen in the transfers. The two cases with the 

largest percentage shift examined above are reduced in magnitude. The shift in ISO-NE is 

reduced from -7.7% to -5.4%, and the shift in SERC-SE is reduced from -8.3% to -6.7%. 
9

Appendix A: Tables by IPM Region

Option 1 (State)

A1. Projected Operational Capacity in 2020

A2. . Summary of Summer Peak Loads and Reserve Capacity in 2020

A3. Summary of Target and Projected Reserve Margins in 2020

A4. Policy Case Retired Capacity Incremental to Base Case in 2020

A5. New Capacity in Policy Case Incremental to Base Case in 2020

A6. Net Reserves Sent by NERC Assessment Region in 2020
10

A1. Projected Operational Capacity in 2020(MW)

All Generation Sources Coal Only

Region Base Policy Change Base Policy

Basin (BASN) 14,163 12,864 -1,298 5,315 4,133

Desert Southwest (DSW) 42,191 39,847 -2,344 9,278 6,894

ERCOT 89,531 89,277 -255 19,052 10,734

FRCC 54,766 56,723 1,956 7,893 2,291

ISO-NE 30,239 28,533 -1,706 141 141

MAPP 9,176 9,090 -85 3,424 3,339

MISO 121,440 117,492 -3,948 50,983 45,646

Northern California (CALN) 32,878 31,092 -1,786 71 71

Northwest (NORW) 51,947 49,373 -2,574 2,354 2,354

NYISO 38,779 37,227 -1,552 443 594

PJM 180,193 175,676 -4,517 55,964 51,175

Rockies (Rock) 23,509 22,163 -1,346 10,584 9,239

SERC-E 52,311 52,086 -225 14,056 10,055

SERC-N 47,824 48,498 675 16,260 15,786

SERC-SE 60,084 55,023 -5,061 15,794 9,670

SERC-W 41,035 35,965 -5,069 6,909 3,224

Southern California (CALS) 43,004 40,920 -2,084 57 57

SPP 71,871 68,188 -3,683 23,704 17,877

Grand Total 1,004,942 970,037 -34,905 242,283 193,279
11

A2. Summary of 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) 11,893 11,487 13,739 12,935

Desert Southwest 

(DSW) 34,249 32,675 39,549 37,086

ERCOT 72,034 70,790 81,938 80,523

FRCC 45,199 44,260 54,595 53,131

ISO-NE 25,142 24,040 28,913 27,646

MAPP 5,383 5,304 6,943 6,099

MISO 90,613 87,001 106,325 101,182

Northern California 

(CALN) 22,308 21,295 28,451 26,667

Northwest (NORW) 25,442 24,350 40,590 37,994

NYISO 29,876 28,504 34,656 33,065

PJM 155,743 150,641 179,728 173,839

Rockies (Rock) 16,025 15,446 19,952 17,991

SERC-E 44,545 43,525 51,227 50,054

SERC-N 40,177 39,390 46,203 45,299

SERC-SE 50,246 49,465 57,783 56,885

SERC-W 29,834 29,514 37,940 33,941

Southern California 

(CALS) 29,514 27,866 36,244 32,798

SPP 51,336 50,440 62,225 57,300

US Total 779,558 755,995 927,000 884,435
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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% 15.52% 12.60% 0.0% -2.9%

Desert Southwest

(DSW) 13.50% 15.47% 13.50% 0.0% -2.0%

ERCOT 13.75% 13.75% 13.75% 0.0% 0.0%

FRCC 19.25% 20.79% 20.04% 0.8% -0.7%

ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0%

MAPP 15.00% 28.99% 15.00% 0.0% -14.0%

MISO 16.30% 17.34% 16.30% 0.0% -1.0%

Northern California 

(CALN) 14.71% 27.54% 25.23% 10.5% -2.3%

Northwest (NORW) 17.90% 35.58% 32.63% 14.7% -2.9%

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% 24.51% 16.48% 1.8% -8.0%

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% 27.17% 15.00% 0.0% -12.2%

Southern California 

(CALS) 15.14% 22.80% 17.70% 2.6% -5.1%

SPP 13.60% 21.21% 13.60% 0.0% -7.6%

Grand Total 15.29% 18.91% 16.99% 1.7% -1.9%
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A4. Policy Case Retired Capacity Incremental to the Base Case in 2020 (MW) 

CC Coal CT NU

OG 

Steam Total

Basin (BASN) 46 1,175 0 0 345 1,567

Desert Southwest (DSW) 0 2,392 0 0 0 2,392

ERCOT 0 8,358 0 0 0 8,358

FRCC 243 5,602 0 0 3,395 9,239

ISO-NE 1,029 0 0 0 2,671 3,700

MAPP 0 85 0 0 0 85

MISO 0 5,350 0 -261 0 5,089

Northern California (CALN) 209 0 1,592 0 0 1,800

Northwest (NORW) 1,885 0 690 0 0 2,574

NYISO 81 -151 0 0 1,656 1,586

PJM 0 4,622 0 0 0 4,622

Rockies (Rock) 0 1,349 0 0 0 1,349

SERC-E 0 4,004 0 0 0 4,004

SERC-N 0 468 0 0 0 468

SERC-SE 0 6,148 0 0 0 6,148

SERC-W -513 3,718 -7 0 4,417 7,615

Southern California (CALS) 766 0 54 0 1,493 2,313

SPP -292 5,874 0 0 2,154 7,737

Grand Total 3,455 48,996 2,328 -261 16,131 70,649
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A5. New Capacity Policy Case Incremental to Base Case in 2020 

(MW) 

Region CC CT Wind Other Total

Basin (BASN) 0 -8 4 271 267

Desert Southwest (DSW) 0 0 6 34 40

ERCOT 6,831 0 1,233 0 8,064

FRCC 11,196 0 0 -95 11,101

ISO-NE 99 -7 1,903 -33 1,961

MAPP 0 -110 0 0 -110

MISO 0 -65 1,161 -63 1,033

Northern California (CALN) 0 0 1 13 14

Northwest (NORW) -11 -17 0 -5 -33

NYISO 0 -14 -37 0 -52

PJM -912 -1,729 1,633 -295 -1,304

Rockies (Rock) -1,023 265 537 0 -221

SERC-E 2,242 -56 0 1,524 3,709

SERC-N 500 0 9 0 509

SERC-SE 1,062 0 0 0 1,062

SERC-W 2,512 -31 0 0 2,481

Southern California (CALS) 183 0 6 38 227

SPP 47 -283 3,961 -3 3,722

Grand Total 22,724 -2,056 10,416 1,385 32,470
15

A6. Net Reserves Sent by NERC Assessment Region in Base and Policy 

Scenarios in 2020 (MW)

NERC Assessment 

Region Base Policy

Change from 

Base to 

Policy

Change as 

Percent of 

Summer Peak

Basin (BASN) -1,430 -1,926 -496 -4.2%

Desert Southwest 

(DSW) 204 289 86 0.3%

ERCOT -1,942 -1,913 29 0.0%

FRCC 0 3,420 3,420 7.6%

ISO-NE -938 -2,885 -1,947 -7.7%

MISO 1,135 1,470 335 0.3%

Northern California 

(CALN) 0 0 0 0.0%

Northwest (NORW) 309 330 21 0.1%

NYISO 1,397 1,295 -102 -0.3%

PJM -12,061 -11,872 189 0.1%

Rockies (Rock) 208 426 217 1.4%

SERC-E -256 -570 -314 -0.7%

SERC-N 807 2,379 1,572 3.9%

SERC-SE 2,071 -2,092 -4,163 -8.3%

SERC-W 3,011 1,928 -1,084 -3.6%

Southern California 

(CALS) 251 1,622 1,371 4.6%

SPP 3,528 1,818 -1,709 -3.3%
16

Appendix B: Tables by IPM Region

Option 1 (Regional)

B1. Projected Operational Capacity in 2020

B2. Summer Peak Loads and Reserve Capacity in 2020

B3. Summary of Target and Projected Reserve Margins in 2020

B4. Policy Case Retired Capacity Incremental to Base Case in 2020

B5. New Capacity in Policy Case Incremental to Base Case in 2020
17

B1. Projected Operational Capacity in 2020(MW)

All Generation Sources Coal Only

Region Base Policy Change Base Policy Change

Basin (BASN) 14,163 13,467 -696 5,315 4,838 -478

Desert Southwest 

(DSW) 42,191 41,810 -382 9,278 8,433 -845

ERCOT 89,531 88,511 -1,020 19,052 13,246 -5,806

FRCC 54,766 56,372 1,606 7,893 3,094 -4,799

ISO-NE 30,239 27,928 -2,311 141 141 0

MAPP 9,176 9,972 796 3,424 3,372 -52

MISO 121,440 115,908 -5,532 50,983 45,609 -5,374

Northern California 

(CALN) 32,878 30,909 -1,969 71 17 -54

Northwest (NORW) 51,947 49,473 -2,474 2,354 2,354 0

NYISO 38,779 36,716 -2,063 443 55 -388

PJM 180,193 175,000 -5,193 55,964 50,082 -5,882

Rockies (Rock) 23,509 22,342 -1,167 10,584 9,889 -695

SERC-E 52,311 52,522 212 14,056 8,264 -5,792

SERC-N 47,824 48,516 692 16,260 15,119 -1,142

SERC-SE 60,084 55,797 -4,287 15,794 11,390 -4,404

SERC-W 41,035 35,710 -5,325 6,909 2,352 -4,557

Southern California 

(CALS) 43,004 40,091 -2,913 57 57 0

SPP 71,871 69,754 -2,117 23,704 17,853 -5,851

Grand Total 1,004,942 970,799

-

34,143 242,283 196,164 -46,118
18

B2. Summary of 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) 11,893 11,487 13,739 12,935

Desert Southwest 

(DSW) 34,249 32,675 39,549 37,765

ERCOT 72,034 70,790 81,938 80,523

FRCC 45,199 44,260 54,595 52,781

ISO-NE 25,142 24,040 28,913 27,646

MAPP 5,383 5,304 6,943 6,099

MISO 90,613 87,001 106,325 101,182

Northern California 

(CALN) 22,308 21,295 28,451 25,654

Northwest (NORW) 25,442 24,350 40,590 37,962

NYISO 29,876 28,504 34,656 33,065

PJM 155,743 150,641 179,728 173,839

Rockies (Rock) 16,025 15,446 19,952 18,722

SERC-E 44,545 43,525 51,227 50,054

SERC-N 40,177 39,390 46,203 45,299

SERC-SE 50,246 49,465 57,783 56,885

SERC-W 29,834 29,514 37,940 33,941

Southern California 

(CALS) 29,514 27,866 36,244 33,752

SPP 51,336 50,440 62,225 57,300

US Total 779,558 755,995 927,000 885,404
19

B3. 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% 15.52% 12.60% 0.0% -2.9%

Desert Southwest 

(DSW) 13.50% 15.47% 15.58% 2.1% 0.1%

ERCOT 13.75% 13.75% 13.75% 0.0% 0.0%

FRCC 19.25% 20.79% 19.25% 0.0% -1.5%

ISO-NE 15.00% 15.00% 15.00% 0.0% 0.0%

MAPP 15.00% 28.99% 15.00% 0.0% -14.0%

MISO 16.30% 17.34% 16.30% 0.0% -1.0%

Northern California 

(CALN) 14.71% 27.54% 20.47% 5.8% -7.1%

Northwest (NORW) 17.90% 35.58% 32.57% 14.7% -3.0%

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% 24.51% 21.21% 6.6% -3.3%

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% 27.17% 15.00% 0.0% -12.2%

Southern California 

(CALS) 15.14% 22.80% 21.12% 6.0% -1.7%

SPP 13.60% 21.21% 13.60% 0.0% -7.6%

Grand Total 15.29% 18.91% 17.12% 1.8% -1.8%
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B4. Policy Case Retired Capacity Incremental to the Base Case in 2020 

(MW) 

CC Coal CT NU

OG 

Steam Total

Basin (BASN) 104 479 0 0 244 827

Desert Southwest (DSW) 0 848 0 0 0 848

ERCOT 0 5,832 0 0 0 5,832

FRCC 135 4,799 0 0 2,248 7,182

ISO-NE 621 0 0 0 2,100 2,722

MAPP 0 52 0 0 0 52

MISO 21 5,405 0 -70 384 5,740

Northern California 

(CALN) 697 54 1,291 0 0 2,042

Northwest (NORW) 2,071 0 690 0 0 2,761

NYISO 254 388 0 0 1,903 2,545

PJM 0 5,730 0 0 0 5,730

Rockies (Rock) 0 696 0 0 0 696

SERC-E 0 5,796 0 0 0 5,796

SERC-N 0 1,145 0 0 0 1,145

SERC-SE 0 4,428 0 0 0 4,428

SERC-W -513 4,596 -7 0 4,036 8,112

Southern California 

(CALS) 963 0 -32 0 3,109 4,041

SPP -292 5,906 0 0 2,243 7,857

Grand Total 4,062 46,152 1,941 -70 16,268 68,353
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B5. New Capacity Policy Case Incremental to Base Case in 2020 

(MW) 

Region CC CT Wind Other Total

Basin (BASN) 0 -8 0 130 122

Desert Southwest (DSW) 0 0 277 186 463

ERCOT 4,661 0 125 0 4,786

FRCC 8,788 0 0 -95 8,693

ISO-NE 0 -7 418 -33 377

MAPP 0 -110 848 0 738

MISO 0 -65 199 -52 82

Northern California 

(CALN) 0 0 30 42 73

Northwest (NORW) -11 -17 162 119 254

NYISO 357 -14 53 0 396

PJM -677

-

1,729 1,832 -313 -887

Rockies (Rock) -1,210 370 147 0 -693

SERC-E 4,387 -56 0 1,606 5,937

SERC-N 1,183 0 11 0 1,194

SERC-SE 117 0 0 0 117

SERC-W 2,749 -31 0 0 2,717

Southern California 

(CALS) 263 0 812 52 1,126

SPP 171 -283 5,515 -3 5,401

Grand Total 20,777

-

1,951 10,430 1,638 30,894
22

B6. Net Reserves Sent by NERC Assessment Region in Base and Policy 

Scenarios in 2020 (MW)

NERC Assessment 

Region Base Policy

Change from 

Base to 

Policy

Change as 

Percent of 

Summer Peak

Basin (BASN) -1,430 -1,316 114 1.0%

Desert Southwest 

(DSW) 204 1,388 1,185 3.5%

ERCOT -1,942 -1,658 284 0.4%

FRCC 0 3,420 3,420 7.6%

ISO-NE -938 -2,305 -1,367 -5.4%

MISO 1,135 558 -577 -0.6%

Northern California 

(CALN) 0 808 808 3.6%

Northwest (NORW) 309 345 36 0.1%

NYISO 1,397 752 -645 -2.2%

PJM -12,061 -12,723 -662 -0.4%

Rockies (Rock) 208 163 -46 -0.3%

SERC-E -256 -192 64 0.1%

SERC-N 807 2,395 1,589 4.0%

SERC-SE 2,071 -1,318 -3,389 -6.7%

SERC-W 3,011 1,681 -1,330 -4.5%

Southern California 

(CALS) 251 -785 -1,036 -3.5%

SPP 3,528 2,238 -1,290 -2.5%
23

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
26