2010 Special Reliability

Scenario Assessment: Resource Adequacy Impacts of 

 Potential U.S. Environmental Regulations

116-390 Village Blvd., Princeton, NJ 08540

609.452.8060 | 609.452.9550 fax

www.nerc.com

the reliability of the

to ensure

bulk power system

October 2010
to ensure 

the reliability of the 

bulk power system

   

NERC’s Mission

The North American Electric Reliability Corporation (NERC) is an international regulatory authority

established to evaluate reliability of the bulk power system in North America. NERC develops and

enforces Reliability Standards; assesses adequacy annually via a 10‐year forecast and winter and

summer forecasts; monitors the bulk power system; and educates, trains, and certifies industry

personnel. NERC is the electric reliability organization for North America, subject to oversight by the U.S.

Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.1

  

NERC assesses and reports on the reliability and adequacy of the North American bulk power system,

which is divided into eight Regional areas, as shown on the map below and listed in Table A. The users,

owners, and operators of the bulk power system within these areas account for virtually all the

electricity supplied in the U.S., Canada, and a portion of Baja California Norte, México.  

Note: The highlighted area between SPP and SERC 

denotes overlapping Regional area boundaries. For 

example, some load serving entities participate in one 

Region and their associated transmission 

owner/operators in another. 

 

1

 As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce 

Reliability Standards with all U.S. users, owners, and operators of the BPS, and made compliance with those standards 

mandatory and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial 

authorities in Ontario, New Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the Canadian National Energy 

Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law. NERC 

has an agreement with Manitoba Hydro making reliability standards mandatory for that entity, and Manitoba has recently 

adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators in the 

province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s Transportation 

Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending. NERC and NPCC 

have been recognized as standards-setting bodies by the Régie de l’énergie of Québec, and Québec has the framework in place 

for reliability standards to become mandatory. Nova Scotia and British Columbia also have frameworks in place for reliability 

standards to become mandatory and enforceable. NERC is working with the other governmental authorities in Canada to 

achieve equivalent recognition. 

Table A: NERC Regional Entities

FRCC

Florida Reliability

Coordinating Council

SERC

SERC Reliability  

Corporation

MRO

Midwest Reliability

Organization

SPP RE

Southwest Power Pool

Regional Entity

NPCC

Northeast Power

Coordinating Council

TRE

Texas Reliability Entity

RFC

ReliabilityFirst  

Corporation

WECC

Western Electricity

Coordinating Council
2010 Special Reliability Assessment Scenario Page i 

Table of Contents 

NERC’s Mission ........................................................................................................................... i

Executive Summary ..................................................................................................................... I

Introduction ................................................................................................................................. 1

Timeline for Potential EPA Regulations ............................................................................. 4

Reliability Assessment Design ........................................................................................... 5

Summary of Assumptions Used in This Report ................................................................. 8

Some Unit Retirements Spread Through Time ................................................................. 12

Scenario Results ....................................................................................................................... 13

Section 316(b) Cooling Water Intake Structures .............................................................. 14

National Emissions Standards for Hazardous Pollutants (NESHAP) or Maximum 

Achievable Control Technology (MACT) ........................................................................ 16

Clean Air Transport Rule (CATR) ................................................................................... 19

Coal Combustion Residuals (CCR) Disposal Regulations ............................................... 21

Combined EPA Environmental Rulemaking .................................................................... 23

Reliability Assessment ............................................................................................................. 27

Resource Adequacy Assessment Results: 2013 ................................................................ 29

Resource Adequacy Assessment Results: 2015 ................................................................ 32

Resource Adequacy Assessment Results: 2018 ................................................................ 36

Industry Actions: Tools and Solutions for Mitigating Resource Adequacy Issue ............ 40

Conclusions & Recommendations ....................................................................................... 41

Appendix I: Assessment Methods .......................................................................................... 43

Appendix II: Potential Environmental Regulations ................................................................ 46

Section 316(b) Cooling Water Intake Structures .............................................................. 46

National Emissions Standards for Hazardous Pollutants (NESHAP) or Maximum 

Achievable Control Technology (MACT) ........................................................................ 50

Clean Air Transport Rule (CATR) ................................................................................... 52

Coal Combustion Residuals (CCR) .................................................................................. 56

Appendix III: Capacity Assessed by NERC Subregion ......................................................... 58

Appendix IV: Data Tables ......................................................................................................... 59

Appendix V: Related Study Work and References ................................................................ 73

Related Study Work For 316(b) ........................................................................................ 73

EPRI Study Work For CCR: ............................................................................................. 75

Terms Used in This Report ...................................................................................................... 77

Abbreviations Used in this Report .......................................................................................... 82

Reliability Assessment Subcommittee Roster ....................................................................... 83

North American Electric Reliability Corporation Staff Roster .............................................. 87
Executive Summary

Executive Summary 

Page I 2010 Special Reliability Assessment Scenario 

Executive Summary

In the United States, several regulations are in the process of being proposed by the U.S. 

Environmental Protection Agency (EPA) that directly affect the electric industry. Depending on 

the outcome of any or all of these potential regulations, the results could accelerate the retirement 

of a significant number of fossil fuel-fired power plants. EPA is currently developing rules that 

would mandate existing power suppliers to either invest in retrofitted environmental controls at 

existing generating plants or retire them. The most significant proposed EPA rules have been in 

development for over ten years and are currently undergoing court-ordered revisions that must be 

implemented within mandatory timeframes. 

The results of this assessment show a significant potential impact to reliability should the four 

EPA rules be implemented as proposed. The reliability impact will be dependent on whether 

sufficient replacement capacity can be added in a timely manner to replace the generation 

capacity that is retired or lost because of the implementation of these rules. Implementation of 

the rules must allow sufficient time to construct new capacity or retrofit existing capacity. 

Planning Reserve Margins appear to be significantly impacted, deteriorating resource adequacy 

in a majority of the NERC Regions/subregions. In this scenario, reduced Planning Reserve 

Margins are a result of a loss of up to 19 percent of fossil fuel-fired steam capacity in the United 

States by 2018.2

 Additionally, considerable operational challenges will exist in managing, 

coordinating, and scheduling an industry-wide environmental control retrofit effort. 

This assessment examines four potential EPA rulemaking proceedings that could result in unit 

retirements or forced retrofits between 2013 and 2018. Specifically, the rules under development 

include: 

1. Clean Water Act – Section 316(b), Cooling Water Intake Structures 

2. Title I of the Clean Air Act – National Emission Standards for Hazardous Air Pollutants 

(NESHAP) for the electric power industry (referred to herein as Maximum Achievable 

Control Technology (MACT) Standard) 

3. Clean Air Transport Rule (CATR) 

4. Coal Combustion Residuals (CCR) Disposal Regulations 

This assessment is designed to evaluate the potential impacts on Planning Reserve Margins, 

assuming that there would be no industry actions in the near term to address compliance issues or 

market response, and identify the need for additional resources that may arise in light of industry 

responses to each of these environmental regulations individually and in aggregate. 

Additionally, this assessment considers the number of generating units requiring retrofitting by 

NERC Region and subregion to demonstrate the magnitude of construction planning necessary 

for compliance in a timely fashion. The assessment relies on two separate scenario cases for each 

proposed rule, calculating the amount of capacity reductions due to accelerating unit retirements 

and increased station loads needed to power the additional environmental controls. For each 

 

2

 A 19 percent reduction represents the results of the total capacity loss in the Strict Case for 2018 as a percentage of the total 

coal, gas, and oil steam units included in the 2009 Long-Term Reliability Assessment Reference Case. Refer to Appendix III 

and IV for details values. 
Executive Summary

Executive Summary 

2010 Special Reliability Assessment Scenario Page II 

proposed EPA rule and in aggregate, units were retired for this assessment based on an agreed 

upon cost calculation.3 

Two scenario cases (Moderate Case and Strict Case) provide a range of sensitivities, with the 

Strict Case incorporating more stringent rule assumptions and higher compliance costs. The 

potential impacts of greenhouse gas (GHG) legislation are not considered in this assessment, but 

have been discussed separately in a recent NERC report.4 Overall, the impact on reliability is a 

function of the timeline for finalizing the rules and ensuring compliance with the potential EPA 

regulations. The reliability impact of these rules will be dependent on whether sufficient 

replacement capacity can be added in a timely manner to replace the generation capacity that is 

retired or lost because of the implementation of these rules. This assessment does not account 

for industry’s ability to acquire, construct, or finance replacement resources; however, 

implementation of the rules must allow sufficient time to construct new capacity or retrofit 

existing capacity. 

Figure A: Summary and Highlights of the Four EPA Regulations Assessed5

 

3

 Unit is retired if (CC+FC+VC) / (1-DR) > RC, where: CC = required compliance cost in $/MWH, FC = current fixed O&M in 

$/MWH, VC = variable O&M including fuel cost in $/MWH, RC = replacement cost in $/MWH and DR = derate factor that 

accounts for the incremental energy loss due to any new environmental controls. See Appendix I, Assessment Methods. 4 http://www.nerc.com/files/RICCI_2010.pdf 5

 Individual EPA Regulations are listed in order of greatest potential impact to least top to bottom, left to right. 

3

316(b)

•Likely to have the greatest capacity impacts of

all four regulations.

•Resulting impacts cause the early retirement of  

mostly oil/gas‐fired steam generation units.

•Smaller units are most likely to be retired as a

result of the high retrofitting costs.

•All nuclear generation is assumed to retrofit,

resulting in up to a 3.5  percent capacity

derate.                                                                               

MACT

•Moderate Case and Strict Case  impact

estimates  show a high degree of capacity

variation in different time periods, due to the

implementation rules assumed to be enforced

by the EPA.

•Resulting impacts highly dependent on waiver

extensions past the 2015

"hard stop" compliance deadline.

•Individually, MACT affects coal ‐fired units.

CATR

•Only regulation to start affecting  capacity in

the Regions by 2013.

•Emission limitations and trading  options will

largely  affect the amount of overall                   

capacity reductions.

•Effects mainly felt by RFC and SERC‐Gateway.

CCR

•Relatively minimal capacity impact in only a            

. few Regions.

•Large‐scale retrofit projects  must be                      

. coordinated

• Cost plays larger role in the Combined EPA         .

. Regulations Scenario.

Combined EPA Regulations

‐Potential impacts approximately 33‐70 GW (retrofit plus retired) capacity  by 2015.

‐ Aggregate effects of multiple regulations increases unit retirement.

‐ Estimates predict the majority of retirements occur by 2015.

‐More units predicted to be retired rather than retrofit
Executive Summary

Executive Summary 

Page III 2010 Special Reliability Assessment Scenario 

ERCOT 

2015/2018 

New England

2015/2015 

AZ/NM/SNV 

2015/2015 

California 

2018/>2018 

RMPA

2015/>2018 

SPP 

2015/>2018

MRO-US 

2013/2015 

RFC

2015/2015 

Central

2015/2015

VACAR

2015/2015

Southeastern

2013/>2018

Delta

2015/2015

FRCC

>2018/>2018

New York

2015/2015 

Gateway

2015/2015

NWPP 

>2018/>2018 

(Winter) 

Years listed above represent the first modeled year when 

deliverable/adjusted potential capacity reserve margins fall 

below NERC reference margins. >2018 means that Planning 

Reserve Margins fall below the NERC Reference Margin Level 

at a time beyond 2018. 

ERCOT 

2015/2018 

New England

2015/2015 

AZ/NM/SNV 

2015/2018 

California 

>2018/>2018 

RMPA

2015/>2018 

SPP 

2015/>2018

MRO-US 

2013/2018 

RFC

2015/2018 

Central

>2018/>2018

VACAR

2015/2018

Southeastern

2013/>2018

Delta

2015/2015

FRCC

>2018/>2018

New York

2018/>2018 

Gateway

2018/>2018

NWPP 

>2018/>2018 

(Winter) 

Years listed above represent the first modeled year when 

deliverable/adjusted potential capacity reserve margins fall 

below NERC reference margins. >2018 means that Planning 

Reserve Margins fall below the NERC Reference Margin Level 

at a time beyond 2018. 

Deliverable Reserve Margin – Existing and Future-Planned Resources 

Adjusted Potential Reserve Margin – Existing, Future-Planned, and Adjusted Potential Resources 

(Conceptual resources adjusted by a confidence factor) 

Figure B: Moderate Case Deliverable and Adjusted Potential Resources 

Reserve Margins Compared to NERC’s Reference Margin Level 

Figure C: Strict Case Deliverable and Adjusted Potential Resources Reserve 

Margins Compared to NERC’s Reference Margin Level 
Executive Summary

Executive Summary 

2010 Special Reliability Assessment Scenario Page IV 

Without additional power production or demand-side resources beyond those in current regional 

plans, the combined effects of the four EPA rules (Combined EPA Regulation Scenario) are shown 

to significantly affect Planning Reserve Margins and, in most Regions/subregions, more resources 

would be required to maintain NERC Reference Margin Levels. Up to a 78 GW reduction of coal, 

oil, and gas-fired generating capacity is identified for retirement during the ten-year period of this 

scenario. For the Moderate Case, this occurs in 2018; however, in the Strict Case a similar 

reduction occurs in 2015. The reduction in capacity significantly affects projected Planning 

Reserve Margins for a majority of the NERC Regions and subregions. Potentially significant 

reductions in capacity within a five-year period may require the addition of resources. For the 

United States as a whole, the Planning Reserve Margin is significantly reduced by nearly 9.3 

percentage points in the Strict Case, significantly deteriorating future bulk power system reliability. 

Proposed EPA Regulations May Have Significant Impacts on Forecast 

Planning Reserve Margins 

Overall, impacts on Planning Reserve Margins and the need for more resources is a function of the 

compliance timeline associated with the potential EPA regulations. The Combined EPA Regulation 

Scenario affects a large amount of units, affecting some Regions more significantly than others. 

Based on the assessment’s assumptions, the greatest risk to Planning Reserve Margins occurs by 

2015 in the Combined EPA Regulation Scenario. The majority of the impacts will be seen within 

the next five years, requiring additional resources in a short timeframe. This situation is 

compounded by the large number of electric generation units that are likely to retrofit with 

environmental controls, as well as the convergence of overlapping replacement/retrofit generation 

capacity projects and heavy U.S. infrastructure projects in other sectors. Potential constraints of 

skilled construction labor, material shortages, financing, and escalation of compliance costs 

coupled with coordination of overlapping outages resulting in congestion expenses could present 

challenges in meeting the compressed time schedule. 

Rule Implementation Timeline Should Consider Reliability Impacts 

Implementation of this rule will apply to 252 GW (1,201 units) of coal, oil steam, and gas steam 

generating units across the United States, as well as approximately 60 GW of nuclear capacity 

(approximately a third of all resources in the U.S.). Of this capacity, 33-36 GW (see Figure D) may 

be economically vulnerable to retirement if the proposed EPA rule requires power suppliers to 

convert to recirculating cooling water systems in order to continue operations. The remaining 

capacity may also be converted assuming it is unaffected by other proposed rules, resulting in a 5 

GW derating across the United States. Therefore, the total capacity vulnerable to retirement 

increases to 37-41 GW. Planning Reserve Margins in almost half of NERC Regions/subregions are 

below the NERC Reference Margin Level by 2015. For example, in this scenario, Planning 

Reserve Margins are decreased by 18 percentage points in the SERC-Delta subregion, where the 

margin falls below zero. Other Regions/subregions significantly affected subregions include 

NPCC-New England and New York. 

Individually, the Section 316(b) Cooling Water Intake Structures Rule Has the 

Greatest Potential Impact on Planning Reserve Margins 
Executive Summary

Executive Summary 

Page V 2010 Special Reliability Assessment Scenario 

 

Summary of Capacity Impacts 

Ranked in descending order of impact severity, the regulatory impacts of MACT, CATR and 

finally CCR on retirements, individually also accelerate retirements and will mostly affect 

existing coal-fired capacity: 

 The MACT Rule considered alone could drive Planning Reserve Margins of 8 

regions/subregions below the NERC Reference Margin Levels standards and trigger the 

retirement of 2-15 GW (Moderate to Strict Cases) of existing coal capacity by 2015. To 

comply, owners of the remaining capacity need to retrofit from 277 to 753 units with added 

environmental controls. The “hard stop” 2015 compliance deadline proposed by the MACT 

Rule makes retrofit timing a significant issue and potentially problematic. 

 The CATR could have significant impacts as soon as 2015 should EPA require emission 

limits with no offset trading, resulting in potentially 3-7 GW of potential retirements and 

derated capacity, requiring retrofitting of 28-576 plants with environmental controls by 2015 

(Moderate to Strict Cases). Planning Reserve Margins are affected most in the SERCGateway subregion with reductions starting in 2013. 

 The CCR Rule alone is projected to have the least impact, triggering the retirement of up to 

12 coal units (388 MW). Cost sensitivity assessment for CCR reveals that retirements could 

reach capacity of 2 GW (53 units) should costs exceed the assessment’s Strict Case 

expenditure estimate by a factor of ten. While the resulting impacts of the CCR scenario 

may not have significant impacts to capacity by themselves, the associated compliance costs 

of CCR contribute to the Combined EPA Regulation Scenario. 

The MACT, CATR, and CCR Rules Also Contribute to Reductions in Capacity 

This report also identifies a number of tools the industry has for mitigating potential reliability 

impacts from the implementation of EPA regulations. For example, advancing Future or 

Conceptual resource in-service dates or the addition of new resources not yet proposed could help 

partially alleviate projected capacity losses in severely affected regions. Price signaling for the 

need of new resources will be important. 

Industry coordination will be vital to ensure retrofits are completed in a way that does not 

diminish reliability. In addition, statutory and regulatory safeguards also allow the EPA, the 

President of the United States, and the Department of Energy to extend or waive compliance 

under certain circumstances. Implementing these industry and regulatory tools may be critical to 

maintain the reliability of the bulk power system. 

Second tier effects, including generation deliverability or stability impacts, must also be 

considered. For example, transmission system construction, enhancements, reconfiguration and 

development of new operating procedures may be necessary in some areas, all of which can create 

additional timing considerations. 

EPA Regulations Create a Need for Prompt Industry Response and Action 
Executive Summary

Executive Summary 

2010 Special Reliability Assessment Scenario Page VI 

 

M Case S Case M Case S Case M Case S Case M Case S Case M Case S Case M Case S Case M Case S Case M Case S Case

2015 2018 2015 2018 2015 2018 2015 2018

CCR CATR MACT 316(b)

Derate (MW) 0 0 0 0 142 1,952 142 1,952 806 2,746 1,750 2,746 2,575 2,551 4,954 4,848

Retired (MW) 130 287 287 388 2,740 5,221 2,740 5,221 2,061 14,879 6,617 14,879 7,597 7,880 32,522 36,366

‐

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

MW

Figure D: Potential Capacity Reduction Impacts Due to Each Potential EPA Regulation

Moderate Case Strict Case Moderate Case Strict Case Moderate Case Strict Case

2013 2015 2018

Derate (MW) 17 1,934 2,394 7,289 6,479 7,348

Retired (MW) 538 6,457 30,563 70,059 39,867 68,979

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

MW

Figure E: Potential Capacity Reduction Due to the Combined EPA Regulation Scenario
Executive Summary

Executive Summary 

Page VII 2010 Special Reliability Assessment Scenario 

Recommendations 

In the future, a variety of demands on existing infrastructure will be 

made to support the evolution from the current fuel mix, to one that 

includes generation that can meet proposed EPA regulations. The pace 

and aggressiveness of these environmental regulations should be 

adjusted to reflect and consider the overall risk to the bulk power 

system. EPA, FERC, DOE and state utility regulators, both together 

and separately, should employ the array of tools at their disposal to 

moderate reliability impacts, including, among other things, granting 

required extensions to install emission controls. 

Regulators, system operators, and industry participants should employ 

available tools to ensure Planning Reserve Margins are maintained 

while forthcoming EPA regulations are implemented. For example, 

regional wholesale competitive markets should ensure forward 

capacity markets are functioning effectively to support the 

development of new replacement capacity where needed. Similarly, 

stakeholders in regulated markets should work to ensure that 

investments are made to retrofit or replace capacity that will be 

affected by forthcoming EPA regulations. 

NERC should further assess the implications of the EPA regulations as 

greater certainty or finalization emerges around industry obligations, 

technologies, timelines, and targets. Strategies should be 

communicated throughout the industry to maintain the reliability of the 

bulk power system. This assessment should include impacts to 

operating reliability and second tier impacts (e.g., deliverability, 

stability, localized issues, outage scheduling, operating procedures, and 

industry coordination) of forthcoming EPA regulations. 

Note: The results in this report are based on assumptions of potential EPA regulations. The 

regulations discussed in this report are not yet final and all compliance deadlines, emission 

limitations, and retrofit costs may differ once the rules are finalized. This is a scenario of 

potential bulk power system impacts based on what is known today about the potential 

implementation of these rules. The resulting resource loss from these potential rules represent 

the loss of capacity should no more resources be added beyond the reference case. Regulators Industry NERC
Introduction

Introduction

2010 Special Reliability Assessment Scenario Page 1 

Introduction

In the United States (U.S.), the electric power industry has made significant capital investment in 

air pollution control technologies to remove sulfur dioxide (SO2), particulate matter and nitrogen 

oxide (NOx) emissions at fossil-fired power plants. The bulk of these capital investments were 

made to existing coal plants in order to comply with evolving environmental regulations. 

Several regulations are in the process of being proposed by the U.S. Environmental Protection 

Agency (EPA) requiring additional retrofits. Depending on the final determinations, the cost to 

comply with the final regulations may result in retirements of generation. This assessment is 

designed to consider four potential EPA regulations and their potential impacts on Planning 

Reserve Margins individually and in aggregate.6

 The four regulations assessed are: 

1. Clean Water Act – Section 316(b), Cooling Water Intake Structures; 

2. Title I of the Clean Air Act – National Emission Standards for Hazardous Air Pollutants 

(NESHAP), or Maximum Achievable Control Technology (MACT) Standards; 

3. Clean Air Transport Rule (CATR); and 

4. Coal Combustion Residuals (CCR) 

Assumptions (described in detail later in this section) have been made in this assessment to 

measure the potential impacts on Planning Reserve Margins from these potential regulations 

before knowing how companies will actually respond to these requirements and market 

conditions. The goal is to provide industry and regulators additional information regarding the 

scope of generating units financially affected by the potential EPA Regulations and about the 

necessity for replacement capacity to maintain reliability during the implementation process—it 

is a hypothetical set of scenarios employing agreed upon assumptions.7 Ultimately, plant owners 

will determine the costs of compliance and make decisions about investment versus unit 

retirement. For this assessment, a unit is assumed to retire if (CC+FC+VC) / (1-DR) > RC, 

where: CC = required compliance cost, FC = current fixed O&M, VC = variable O&M including 

fuel cost, RC = replacement cost all in $/MWH, and DR = derate factor that accounts for the 

incremental energy loss due to any new environmental controls. See Appendix I: Assessment 

Methods for more details.8

Below is a summary of the aforementioned regulations, listed in order of magnitude: 

1. Clean Water Act – Section 316(b), Cooling Water Intake Structures 

A significant number of thermal (coal, nuclear, oil and gas steam) generation plants use 

cooling water to support the process of generating electricity and therefore, they are 

located on large water bodies or high flow-rate rivers. Many of these facilities use oncethrough cooling systems that draw large volumes of water from the ocean, lake, or river 

used to condense steam, returning the warmer water back into the body of water 

immediately after use. Section 316(b) of the Federal Water Pollution Control Act 

(FWPCA), more commonly known as the Clean Water Act, regulates intake structures 

for surface waters in the U.S. and calls for Best Technology Available (BTA) to 

 

6

 Analysis performed by Energy Ventures Analysis, Inc. (http://www.evainc.com) for NERC in February-July 2010 serves as the 

basis for this report. Detailed status of the assessed regulations can be found in Appendix II, Environmental Regulations 7

 NERC vetted assumptions used in this assessment with the Reliability Assessment Subcommittee and multiple industry groups. 8

 The potential effects of pending CO2 regulations were not included. 
Introduction

Introduction 

Page 2 2010 Special Reliability Assessment Scenario 

minimize adverse environmental impact (AEI). EPA has interpreted that to mean 

impingement mortality of fish and shellfish and entrainment of their eggs and larvae. 

EPA’s rulemaking is expected to set significant new national technology-based 

performance standards to minimize AEI. EPA is revising its rules for cooling water 

intake structures at “existing” facilities – including electric power generating stations. 

EPA has moved to combine the Phase II (large existing generators) and Phase III (small 

existing generators, offshore oil & gas facilities and other manufacturing facilities) rules 

into one proceeding and plans to propose a revised rulemaking by February 2011 and a 

final rule is to be promulgated by July 2012. 

In 2004, EPA originally adopted Phase II regulations to minimize impingement and 

entrainment of aquatic life in the water intake structures that applied to large existing 

power plants withdrawing 50 million or more gallons per day and using at least 25 

percent of the water withdrawn for cooling purposes. Sources could comply using 

several alternatives. 

However, a January 2007 ruling by the Second U.S. Circuit Court of Appeals remanded 

several provisions of the Phase II rule and EPA subsequently suspended its Phase II 

implementation9 and is in process of developing a new rule to address the court concerns. 

Steam generating units employing once-through cooling systems could be required to 

replace their cooling water systems with closed-loop cooling systems. 

This can affect Planning Reserve margins in two ways: 1) the cost of such retrofits may 

result in accelerated unit retirements and 2) closed-loop cooling retrofitting results in 

derating a unit’s net output capacity, due to additional ancillary or station load 

requirements to serve generator equipment. This resource assessment and its 

implications for responses in the power generation market should inform and affect 

power plant owner’s choices about plant retirements, plant additions, and unit retrofits. 

2. Title I of Clean Air Act – National Emission Standards for Hazardous Air 

Pollutants for the electric power industry, or Maximum Achievable Control 

Technology (MACT) Standards 

NESHAP or MACT requires coal-fired plants to reduce their emissions of air toxics, 

including mercury. In December 2000, the U.S. EPA issued a “regulatory determination” 

under the 1990 Clean Air Act Amendments that regulation of mercury is “appropriate 

and necessary” for coal- and oil-fired power plants. Title I of the Amendments required 

EPA to adopt MACT standard for air toxic control. In March 2005, EPA issued its 

final Clean Air Mercury Rule (CAMR) for coal-based power plants. The CAMR used a 

market-based cap-and-trade approach to require emissions reductions in two phases: 1) a 

cap of 38 tons in 2010 and 2) fifteen tons after 2018, for a total reduction of 70 percent 

from current levels. Facilities were to demonstrate compliance with the standard by 

holding one "allowance" for each ounce of mercury emitted in any given year. In the 

final rule, EPA stated the regulation of nickel emissions from oil-fired plants is not 

"appropriate and necessary." In February 2008, the U.S. Court of Appeals for the District 

of Columbia Circuit issued an opinion in a case, which was initiated by 15 states and 

other groups, challenging the CAMR and EPA's decision to "de-list" mercury as a 

hazardous air pollutant (HAP). The Court held that EPA's reversal of the December 2000 

 

9 http://www.epa.gov/waterscience/316b/phase2/implementation-200703.pdf
Introduction

Introduction

2010 Special Reliability Assessment Scenario Page 3 

regulatory finding was unlawful.10 The Court vacated both the reversal and the CAMR. 

In February 2009, the acting Solicitor General, on behalf of EPA, filed a motion with the 

Supreme Court to dismiss the CAMR case. The motion states unequivocally that EPA 

will develop MACT standards for the utility industry under section 112 of the Clean Air 

Act. EPA is now obligated under a consent decree to propose a MACT rule by March 

16, 2011 and to finalize the rule by November 16, 2011. In the interim, 19 states have 

already adopted their own mercury control requirements. 

Section 112 in Title I of the Clean Air Act requires EPA to develop MACT standards for 

all the other listed air toxics emitted by coal- and oil-fired power plants. Based on an 

Information Collection Request (ICR), EPA is likely to set MACT standards for mercury, 

acid gases, heavy metals, and organics for coal- and oil-fired power plants. This could 

require significant additional emissions control equipment beyond what is necessary for 

compliance with mercury-only regulations. Under the Clean Air Act, EPA is obligated to 

implement the stricter standards within three years after the regulation becomes final. 

3. Clean Air Transport Rule (CATR) 

On July 6, 2010, EPA proposed a CATR program to reduce long-range transport of 

pollutants significantly contributing to downwind state ground-level ozone and fine 

particle non-attainment problems. This program would replace EPA’s earlier Clean Air 

Interstate Rule that was overturned by the U.S. Court of Appeals in 2008 and temporarily 

reinstated until a replacement program was developed. As drafted, CATR would sharply 

reduce emissions of sulfur dioxide and nitrogen oxide from power plants in 31 states and 

the District of Columbia. EPA proposed three program options for public comment: 

1) the EPA preferred option which sets state emission budget caps and allows 

intrastate trading and limited interstate trading among power plants; 

2) the EPA Alternative 1 option which sets state emission budget caps and 

allows intrastate trading among power plants within a state; and 

3) the EPA Alternative 2 option which sets a pollution limit for each state and 

specifies the allowable unit-specific emission limit 

Each of these options poses different reliability impacts. EPA will revise future state 

emission budgets as new stricter ozone and fine particulate ambient air quality standards 

are implemented. Depending on the outcome of the final regulation, power plant owners 

will likely need to retrofit additional emissions controls and, in some cases, retire units.11

4. Regulations on Coal Combustion Residuals (CCR) 

Coal-fired power plants currently dispose of more than 130 million tons per year of coalash and solid byproducts. The failure of an ash disposal cell in December 2008 

highlighted the concerns of coal-ash disposal and triggered calls for tighter regulation.12 

In May 2010, EPA proposed two options to regulate coal combustion residual disposal.13 

 

10 http://pacer.cadc.uscourts.gov/docs/common/opinions/200802/05-1097a.pdf 11 A follow-on rule “Transport Rule 2” is also being developed for proposal by the EPA that would require more environmental 

controls not covered by CATR, regulating NOx in particular. This would apply to a majority of the states in the Eastern 

Interconnection plus Texas. This rule is not assessed in this report, but may contribute to more investments in required control 

technologies needed. 12 Disposal cells are used for settling and storing the coal fly ash. This accident occurred at TVA’s Kingston Fossil Plant East 

Tennessee. http://www.tva.gov/kingston/index.htm 13 http://www.epa.gov/wastes/nonhaz/industrial/special/fossil/ccr-rule/ccr-rule-prop.pdf 
Introduction

Introduction 

Page 4 2010 Special Reliability Assessment Scenario 

1) Regulate the coal fly ash as a special waste under subtitle C (hazardous waste) of the 

Resource Conservation and Recovery Act (RCRA). Under this option, facilities 

would need to close their surface ash impoundments within five years and dispose of 

the ash (past and future) in a regulated landfill with groundwater monitoring. 

2) Regulate ash disposal as a non-hazardous waste under subtitle D of RCRA. This 

alternative would require the facility to remove the solids and retrofit the 

impoundment pond with a liner to protect against groundwater contamination. Any 

landfill CCR disposal would require liners for new landfills and groundwater 

monitoring of existing landfills. 

Beyond regulating coal-ash and residuals being landfilled or placed into a surface 

impoundment, the EPA regulation may also affect the use of the remaining coal-ash and 

reused or recycled residuals in products such as cement, concrete, roadbed material, 

drywall, etc. The EPA has indicated it will not prevent beneficial uses of the coal fly ash; 

however, there would be a higher cost for added ash disposal volume and a potential 

stigma created by regulating ash as a hazardous material, potentially resulting in lost 

revenue from the recycling market. 

Furthermore, EPA is also considering a potential modification to the subtitle D option, 

called “D prime.” Under the “D prime” option, existing surface impoundments would not 

have to close or install composite liners but could continue to operate for their useful life. 

Also in the “D prime” option, the other elements of the subtitle D option would remain 

the same. However, because no proposal has been made, this option is not included. 

Timeline for Potential EPA Regulations 

EPA has some flexibility in setting its compliance schedule for all potential rules except MACT 

(see Figure 1). Based upon current EPA schedules and historic implementation deadlines, EPA’s 

air and solid waste regulations will likely be finalized by the end of 2011 with full compliance 

being anticipated by 2015–2016. The 316(b) water regulations are expected to be finalized in 

July 2012. It is anticipated that at least five years will be provided for compliance. 

The overlapping compliance schedules for the air and solid waste regulations, along with 

required compliance for rule 316(b) following shortly thereafter, may trigger a large influx of 

environmental construction projects at the same time as new replacement generating capacity is 

needed. Such a large construction increase could cause potential bottlenecks and delays in 

engineering, permitting and construction. The risk of project delay increases if EPA decides on a 

compressed compliance schedule. The timing for scheduling unit outages to tie-in the 

environmental equipment becomes critical. Further, demand for critical equipment and supplies 

could potentially exceed production capacity and result in shortages and price escalations. 

However, surveys of labor or manufacturing were not conducted beyond the 25 percent cost 

increase in the Strict Case in this assessment. 

 
Introduction

Introduction

2010 Special Reliability Assessment Scenario Page 5 

Figure 1: Timeline for Potential U.S. EPA Regulations Impacting the Electric Industry

Reliability Assessment Design 

This reliability assessment used a plant-by-plant assessment. The cost factors for each unit were 

generic, based on its size and location and did not include engineering-level cost factors. 

Potential retirements and Planning Reserve Margin impacts are assessed for two cases (Moderate 

Case and Strict Case), for three different years (2013, 2015 and 2018), and for each regulation 

individually. The Combined EPA Regulation Scenario reflects the effects of the outcomes from 

the individual regulation cases working in aggregate. The Moderate Case assumes the costs as 

identified in Appendix I: Assessment Methods and Appendix II: Environmental Regulations. The 

Strict Case scenarios reflect the coupled effects of a higher increase in costs with more stringent 

requirements for the proposed rules. As the EPA proposed rules are not yet final, the Moderate 

Case and the Strict Case require expert judgment and sound assumptions on potential outcomes 

of the potential EPA rules. 

Figure 2: Differences in Scenario Cases 

Moderate

Case

•Conversion

cost curve

for retrofit

•Ranges from

$170‐440 /

gpm

Strict Case

•25%

increased

cost

316(b) Moderate

Case

•Conversion

cost curve

for emission

controls

•60% of

upgraded

units will

receive

waivers

Strict Case

•25%

increased

cost

•No waivers‐

all units

must

comply by

2015

MACT Moderate

Case

•EPA

preferred

option

•No

interstate

trading

•No rate

limitations

Strict Case

•No trading

•Strict rate

limitations

CATR Moderate

Case

•$30 M per

unit

•Disposal

costs ‐

$15/ton

Strict Case

•Disposal

costs

increased to

$37.50/ton

CCR
Introduction

Introduction 

Page 6 2010 Special Reliability Assessment Scenario 

In this reliability assessment, “economically vulnerable” generation capacity identifies units that 

would retire because of a specific potential environmental regulation. Unit retirement is assumed 

when the generic required cost of compliance with the proposed environmental regulation 

exceeds the cost of replacement power. In some cases, the costs imposed by the potential EPA 

regulations may cause “accelerated” or “early” retirement of unit generation capacity for an 

unknown time period. For the purpose of this assessment, replacement power costs were based 

on new natural gas generation capacity.14 If the unit’s retrofit costs are less than the cost of 

replacement power, then the unit is marked to be upgraded and retrofitted to meet the 

requirements of the potential environmental regulation, i.e., it is not considered “economically 

vulnerable” for retirement. More discussion of the approach can be found in Appendix I, 

Assessment Methods.

15 

The assessment does not examine the possibility that the industry may be unable to meet its tight 

compliance deadlines. The Strict Case for 316(b) and MACT imposes a 25 percent cost increase 

to account for potential impacts if industry is unable to engineer, permit, build, or finance 

required retrofit environmental controls within the tight EPA compliance periods. Should 

multiple regulations phase-in simultaneously, replacement generation projects may encounter 

scheduling difficulties and scheduled retrofits may not be completed before deadlines. Where 

timing issues exist, waivers and extensions may be needed in order to complete a retrofit project 

instead of retiring the plant. 

The assessment develops compliance costs based upon current average retrofit costs with 

existing technology market conditions. It does not assess the compliance cost risk from a run-up 

in labor and/or material costs caused by a construction boom from environmental control and 

replacement power projects. By applying average retrofit control costs by size in lieu of a detail 

engineering study, capital retrofit costs may be underestimated for sites with design, tight 

physical footprint and/or poor geologic considerations.16 

 

This reliability assessment focused on measuring the potential resource implications through 

impacts on Planning Reserve Margins and identification of Regions/subregions where additional 

Regional resources may be required. The reference case for this study is based on resource 

projections contained in NERC’s 2009 Long-Term Reliability Assessment.17 

The impacts of potential EPA regulations may also have second tier effects on reliability, beyond 

resource adequacy. Resource deliverability, outage scheduling/construction constraints, local 

pockets of retirements, and transmission needs may also affect bulk power system reliability. 

While these issues were not studied in this assessment, the industry will need to resolve these 

concerns. 

 

14 The model does not consider potential natural gas price fluctuations. 15 Using a different retirement method may produce different results. For instance, assessing generation on future asset 

performance may potentially increase the amount of capacity ‘vulnerable’ to retirement when economics are unprofitable, 

depending on the model input assumptions. 

16 This assessment did not include implementation. Because the compliance deadlines are short, generation owners may be 

challenged to engineer, permit, finance and build all required retrofit environmental controls within the proposed compliance 

periods. This may be especially challenging due to the phase-in of multiple regulations simultaneously. Further, some 

generation replacement projects also face similar risk of scheduling difficulties and may shutdown awaiting control 

completion, unless EPA grants waivers. 17 http://www.nerc.com/files/2009_LTRA.pdf 
Introduction

Introduction

2010 Special Reliability Assessment Scenario Page 7 

The assessment objectives were: 

1. identify potential future outcomes of EPA’s active rulemaking for each of the Clean 

Water Act Section 316(b),18,19 CCR, CATR, MACT and other air toxics individually and 

in aggregate (Combined EPA Regulation Scenario); 

2. quantify and project impacts on Planning Reserve Margins for two sensitivity cases 

(Moderate Case and Strict Case) for each regulation (Clean Water Act Section 316(b), 

CCR, CATR, MACT and other air toxics), as well as their combined projected impacts 

for the years 2013, 2015, and 2018; 

3. examine the impacts of potential unit retirement on future Regional reliability. 

Specifically, assess the impacts on Planning Reserve Margins to measure the relative 

impacts to resource adequacy across NERC Regions and Subregions (see Figure 3); and 

4. provide the results to NERC’s stakeholders, industry leaders, policymakers, regulators, 

and the public.

Figure 3: NERC US Subregions Assessed in this Report 

Cost factors affect generating units as a “snapshot” in time, requiring unit operators to make the 

decision to finance retrofits for existing units or retire the units, replacing them with natural gas 

generation. Units “retire” if there are more economical replacement power alternatives available 

for compliance. Therefore, modeled years illustrate the scope of the U.S. bulk power industry 

that may be affected and the magnitude of attention required for nationwide compliance. 

 

 

18 http://www.nerc.com/files/NERC_SRA-Retrofit_of_Once-Through_Generation_090908.pdf 19DOE provided NERC a listing of vulnerable units (totaling approximately 240 GW). This information was supplemented by 

identifying those units that were expected to retire during the study timeframe, along with permitting dates. NERC reviewed 

the impact of either retrofitting units with existing once-through-cooling systems to closed-loop cooling systems (4 percent 

reduction in nameplate capacity) or unit retirements (capacity factors less than 35 percent) on NERC-U.S. and Regional 

capacity margins for 2012-2015.
Introduction

Introduction 

Page 8 2010 Special Reliability Assessment Scenario 

Summary of Assumptions Used in This Report 

The approach used in this assessment assumes that there are only two basic choices to consider 

when complying with the potential EPA regulations. The two choices are: 

1. retrofit the generation unit and continue operations; or 

2. retire the generation unit and replace it with a natural gas unit, 

It was beyond the scope of this assessment to complete in-depth, individual plant assessment 

using site-specific cost factors to comply with each of the proposed EPA regulations. NERC 

contracted Energy Ventures Analysis Inc. (EVA)20 to model potential reliability impacts. This 

model does not consider Planning Reserve Margin commitments, reliability-must-run conditions 

or transmission constraints. Instead, the model applied generic cost factors related to unit size 

and location to each unit as it was assessed. An economic approach is used that identifies which 

units may retire if the generic required cost of compliance with the proposed environmental 

regulation exceeds the cost of replacement power. As mentioned before, replacement power was 

considered to be gas-fired capacity. A more detailed discussion of the approach can be found in 

Appendix I: Assessment Methods of This Report.

21 

This assessment does not examine the additional impacts of adopting future greenhouse gas 

(GHG) control legislation, or other Clean Air Act requirements, including NAAQS, Regional 

haze/visibility, and GHG regulation,22 national renewable portfolio standards, or other future 

EPA environmental rules that may lead to carbon reduction requirements. In practice, however, 

power suppliers are likely to consider the additional risk from uncertain future actions/rules in 

the U.S., such as future CO2 legislation, when making plant investment decisions. Depending on 

how power suppliers quantify these risks, unit retirements may be higher than those projected in 

this assessment. Additionally, the report did not address any other climate change legislation. 

Other assumptions affecting this reliability assessment include the following: 

o Excludes plant retirements already committed or announced (13 GW) and excludes 

generation units not included in the NERC 2009 Long Term Reliability Assessment23

published in October 2009 (15 GW). Together these are equal to nearly 28 GW of 

capacity. These units were not included in this assessment because these units are not 

relied on to meet resource adequacy requirements nor do they have capacity 

 

20 EVA is contracted by domestic and international power producers, transportation companies, energy marketing companies and 

traders, industry organizations, etc. 

http://evainc.com/ 21 Ibid. 11 

22The analysis also did not address National Ambient Air Quality Standards (NAAQS) [ June 2010 1-hour sulfur dioxide 

standard, February 2010 1-hour nitrogen dioxide standard, October 2010 revised 8-hour ozone standards (primary and possibly 

secondary), November 2011 revised particulate matter standards (primary and possibly secondary), the mid-2012 Transport 

Rule II following the October 2010 revised ozone standards, and the 2013 Transport Rule III following the November 2011 

revised particulate matter standards], which could all force compliance actions by approximately 2015. The analysis also did 

not address regional haze. The Best Available Retrofit Technology (BART) controls in regional haze State Implementation 

Plans may be implemented could be required around 2015-16. The analysis did not address GHG regulation under the Clean 

Air Act, which will proceed in 2011 for new sources and modified sources. In step 1, starting on January 2, 2011, for sources 

subject to permitting for pollutants other than GHGs, new and modified sources emitting 75,000 tons per year (tpy) will be 

subject to Best Available Control Technology (BACT) requirements. In step 2, from July 2011 through June 2013, all sources 

above these thresholds – 100,000 tpy for new and 75,000 tpy for modified sources for CO2 - emissions – will be subject to 

Best Available Control Technology (BACT) requirements. 23 http://www.nerc.com/files/2009_LTRA.pdf 
Introduction

Introduction

2010 Special Reliability Assessment Scenario Page 9 

commitments based on the 2009 Long Term Reliability Assessment. Therefore, any 

capacity reduction from these units has already been considered in the 2009 Long Term 

Reliability Assessment (reference case). The base generation capacity for each NERC 

Region/subregion is located in Appendix III, Capacity Assessed by NERC Subregion. 

o Excludes a detailed assessment of the ability of generation owners to permit, engineer, 

finance, and build the required environmental controls within the short compliance 

timeframe. However, implementation will pose a large challenge to the equipment and 

construction sectors since multiple EPA programs are phased-in over the same 

timeframe. Compliance costs could escalate beyond the 25 percent increase of the high 

case (Strict Case), should the EPA require compliance within three years of the final 

rulemaking dates for some of the proposed rules (i.e., 2014 or 2015). This situation is 

compounded by the large number of electric generation units that are likely to retrofit 

environmental controls, as well as from the competition created by replacement 

generation capacity projects and other heavy U.S. infrastructure projects in other sectors. 

A potential shortage of skilled construction labor, material shortages, and escalation of 

compliance costs could present challenges to meet the compressed time schedule. 

o Compliance costs (capital, O&M and performance changes) are based upon current 

average retrofit costs with existing technology. The assessment does not evaluate the 

compliance cost increases resulting from a run-up in labor and material costs caused by 

demand increase for environmental control and replacement power projects. By applying 

average retrofit control costs by size in lieu of a detailed engineering study, capital 

retrofit costs may also underestimate the cost for sites with design, tight layout and/or 

poor geologic considerations. The assessment also assumes that each unit must make a 

decision on whether or not to retrofit with environmental controls. For example, if a plant 

has two units, the cost of two SCRs are used, not just one, as this is the most reliable 

option. 

o Increased CCR disposal costs can vary widely based upon land availability, geology, and 

state disposal permit requirements. In this assessment, an EPA assumption of onsite 

disposal is adopted, and the EPA calculated disposal costs are similar to those employed. 

However, if onsite disposal were prohibited, the plant would incur additional costs to 

transport the ash and residuals to a properly permitted landfill. These costs could be 

significant, but cannot be estimated without a site-specific assessment. For these reasons, 

sensitivity comparisons were completed for CCR disposal costs. 

o Power suppliers will need to bring their units offline to interconnect their new or 

retrofitted environmental controls. During these periods, suppliers will lose potential 

revenues and require use of replacement power. While the capital and O&M costs are 

incorporated into the compliance decision criteria, the replacement purchased power 

costs during these integration shutdowns have not been included and are unlikely to 

change or accelerate unit retirement decisions. However, these impacts would have the 

greatest effect on the nuclear plants that would incur the largest replacement power costs 

due to the duration of the retrofit outage. 
Introduction

Introduction 

Page 10 2010 Special Reliability Assessment Scenario 

o For retrofit of once-through-water cooling units, all nuclear plants are assumed to become 

exempted,24 be subjected to alternative requirements as in the case of California’s two 

operating nuclear plants,25 or will be able to make the required investments due to the 

characteristics26 of nuclear generation versus traditional fossil-fired generation.27 

Therefore, this assessment does not include any derate effects for nuclear capacity from 

Section 316(b). However, the maximum loss of capacity due to derate is estimated to be 

about 1.8 GW due to retrofit. Should 316(b) cause nuclear unit retirement, additional 

generation capacity loss may result. 

o Generating units identified in this assessment may choose to wait until immediately prior 

to the compliance deadline before retiring the generation unit. This ability to delay 

retirement may act as a binary option causing many units to retire on December 31 prior 

to a January 1 deadline, and in some cases, may wait until January 1, 2018. The 

assumptions used for decision-making timing in this study are described in the Some Unit 

Retirements Spread Through Time section. 

o All combined-cycle plants are assumed to make required investments to avoid being 

forced into early retirement. This may not be the case. For MACT, oil-fired units are 

assumed to meet emission limits through availability of suitable quality specifications of 

refined oil products. 

o The assessment excludes any fossil-fuel market price or supply risks that are created by a 

large shift in the power generation mix from environmental compliance measures (e.g., a 

shift from coal to natural gas fuel). Delivered natural gas and coal prices are fixed and do 

not change based on the level of retirements or the level of new replacement capacity that 

may be required. 

o If a coal plant is retired under this method, there is nothing to prevent a secondary, afterthe-fact decision. For instance, a coal unit may convert into a biomass-based unit, or 

convert to natural gas burners and continue operating as a steam plant. In addition, plant 

owners may decide to invest in construction at existing construction sites after retirement. 

Such decisions are beyond the scope of this assessment. 

o The assessment did not examine or model the use of other sorbent injection technologies 

(e.g., trona) as an alternative. For trona, capital costs would be lower, but higher 

operating costs would result. Limestone scrubbers are the norm in the United States, 

although, this technology has been used at older plants where owners did not want to 

make the larger capital investment. Further, while some future plants may opt for trona 

vs. a limestone scrubber, a majority of plants (greater than 97 percent) will use limestone. 

o Delivered natural gas, coal and oil prices were based on the forecasts of EVA as of May 

2010. Ten-year forward averages are applied for 2013, 2015 and 2018. Varying these 

price assumptions may produce different results. The base wholesale fuel price forecasts 

are depicted in Figure 4 on an undelivered basis. 

 

24 http://www.snl.com/InteractiveX/article.aspx?CDID=A-10616386-10806&KPLT=2 25 http://www.swrcb.ca.gov/water_issues/programs/npdes/docs/cwa316may2010/otcpolicy_final050410.pdf 26 e.g., Lower GHG emissions, longer in-service operations, higher availability, baseload resource 27 DOE, 2008 http://www.oe.energy.gov/DocumentsandMedia/Cooling_Tower_Report.pdf 
Introduction

Introduction

2010 Special Reliability Assessment Scenario Page 11 

Figure 4: Wholesale Fuel Price Assumptions Used for This Assessment 

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026

New York Harbor Residual Fuel Oil (0.3% S) Henry Hub Natural Gas

N. Appalachian Coal, Pittsburg Seam, Rail, 13,000 Btu/lb, 4.0 S, 8% Central Appalachian Coal, NYMEX Spec, Barge, 12000 Btu/lb, 1.0 S, 10%

IL Basin Coal, IL Rail, 11,500 Btu/lb, 5.0 S, 10% Powder River Basin Coal, 8800 Btu/lb, 0.8 S, 5%

$ perMMBtu (constant 2010$)

S=Sulfur Content 
Introduction

Introduction 

Page 12 2010 Special Reliability Assessment Scenario 

Some Unit Retirements Spread Through Time 

Because the implementation of multiple EPA regulations is tightly stacked through time, a large 

number of retirements may occur in the same year, requiring new resources to offset the capacity 

reductions. To simulate a more realistic and expected outcome, in certain instances, some of the 

retirement and waivers were simulated earlier in time, rather than reflecting all retirements in one 

year, such as in 2015 or 2018, depending on the regulation. These results are included in the 

scenario of the four potential regulations. In addition: 

 Section 316(b) and Coal Combustion Residuals: As the EPA implementation deadlines 

are expected to be January 1, 2018, no units theoretically would need to be retired until 

2018. However, this assessment assumes that 20 percent of designated units are retired in 

each year from 2013 through 2017 for the Moderate Case and the Strict Case. To select 

which individual units are simulated to retire, each designated plant’s economics are 

ranked from the most expensive to least expensive production costs. The units with the 

most expensive plant costs were retired first for Section 316(b) and CCR. Conversely, 

the units with the lowest cost plant economics were upgraded first. 

 MACT: For the Moderate Case only, 60 percent of units that are designated to upgrade 

environmental controls by 2015 receive waivers as of January 1, 2015. The most 

expensive 20 percent of units are retired by 2014 (no effects as of January 1, 2013), and 

then the next most expensive 20 percent of units are retired by 2015. Also conversely, 

the units with the lowest cost plant economics are upgraded first when the highest cost 

plants are retired. 

 CATR: The Strict Case simulated the highest 40 percent of units were retired by 2013 

and the 40 lowest cost units were retrofitted by 2013. 
Scenario Results

Scenario Results

2010 Special Reliability Assessment Scenario Page 13 

0 ‐ 2 % REDUCTION

2 ‐ 4 % REDUCTION

4 ‐ 6 % REDUCTION

6 ‐ 9 % REDUCTION

> 9 % REDUCTION

Scenario Results

U.S. power suppliers will assess the impact of all future environmental requirements when 

making their environmental compliance decisions. Even in the absence of future GHG 

legislation, the combination of the four potential EPA rules may have significant economic 

impacts on generating units, potentially affecting the reliability of bulk power system as 

measured by significant declines in Planning Reserve Margins. Based on the design of this 

assessment, the overall total compliance cost impact would place between 40 and 69 GW of 

existing capacity (441-761 units) as “economically vulnerable” for accelerated retirement due to 

more cost efficient compliance alternatives by 2018. On-site stations loads for equipment 

operation derate the net generating capacity of the retrofitted units by 6.7-7.4 GW. The overall 

affect would be a total of 46-76 GW of capacity reductions significantly affecting Planning 

Reserve Margins if no additional resources are built beyond what is included in the 2009 NERC 

Long-Term Reliability Assessment plans (see Figure 5). In many Regions/subregions, Planning 

Reserve Margins fall below the NERC Reference Margin Level, indicating the need for more 

resources. 

The potential retirement and deratings affect resource portfolios in all eight NERC Regions, but 

especially in the ERCOT, MRO, NPCC, SERC, and NPCC Regions. The most significant 

individual impacts are due to the Section 316(b) regulation, then MACT, CATR and finally 

CCR. However, the Combined EPA Regulation Scenario has the greatest impact to reliability. 

Figure 5: 2018 Reduction in Adjusted Potential Capacity Resources due to the Combined  

EPA Regulation Scenario
Scenario Results

Scenario Results 

Page 14 2010 Special Reliability Assessment Scenario 

Section 316(b) Cooling Water Intake Structures 

In the Moderate Case scenario, the Section 316(b) rule alone could potentially increase the unit 

production costs above replacement power costs at 347 stations, retiring 33 GW of current 

generating capacity. This retired generating capacity was spread across the rule implementation 

period (2014-2018). The majority of the “economically vulnerable” units are older oil/gas steam 

units (253 units with 30 GW of capacity). An additional 94 coal steam units (capacity of 2.5 

GW) are also “economically vulnerable”. The remaining 688 would also incur a five GW 

capacity derating to support increases in station loads. Table 1 shows how these retirements and 

capacity derating penalties affect the NERC subregions for the year 2015 while 2018 impacts are 

shown in Table 2. For this assessment, no units were affected in 2013. As shown, SERC-Delta, 

RFC, WECC-CA, and ERCOT account for 65 percent of the unit retirements. 

Should the cooling tower conversion costs be 25 percent higher than prior engineering studies 

indicated ($300/gpm versus $240/gpm), an additional 17 units (four GW) could retire resulting in 

a total of 37 GW. 

Section 316(b) marginally affects coal units in comparison to its effects on oil/gas steam units 

(i.e., 92–93 percent of capacity). In the Strict Case, most of the incremental retirements are older 

oil/gas steam units located in WECC-CA, NPCC, SERC-Delta, ERCOT, and RFC, ranked from 

highest to lowest. For the coal units, most “economically vulnerable” capacity is in RFC. The 

“economically vulnerable” capacity in the Strict Case is 12 percent greater than in the Moderate 

Case. 

Table 1: 316(b) Impacts ‐ 2015

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 187   556 743 187 752   939

FRCC 69   68 137 69 68   137

MRO 340   450 789 338 479   817

NPCC‐NE 0   1,061 1,061 0 1,061   1,061

NPCC‐NY 22   958 980 22 958   980

RFC 988   763 1,751 954 763   1,717

SERC‐Central 275   0 275 275 0   275

SERC‐Delta 82   1,774 1,856 82 1,774   1,856

SERC‐Gateway 288   266 555 288 266   555

SERC‐Southeastern 60   224 284 52 224   276

SERC‐VACAR 101   92 193 120 92   212

SPP 113   501 614 113 531   644

WECC‐CA 0   786 786 0 786   786

WECC‐AZ‐NM‐SNV 0   24 24 0 25   25

WECC‐NWPP 36   39 75 36 39   75

WECC‐RMPA 13   36 49 13 64   77

   TOTAL 2,575   7,597 10,172 2,551 7,881   10,432
Scenario Results

Scenario Results

2010 Special Reliability Assessment Scenario Page 15 

These estimates are slightly less, but comparable, to the October 2008 DOE study, Electricity 

Reliability Impacts of a Mandatory Cooling Tower Rule for Existing Steam Generating Units

that resulted in approximately 40 GW of potential retirements. Some differences may be 

attributable to this study excluding more already announced generating unit retirements (more 

than 28 GW) and incorporating a more comprehensive retirement replacement cost method 

(versus applying a capacity factor criterion). 

 

Table 2: 316(b) Impacts ‐ 2018

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 322   5,055 5,377 316 5,295   5,611

FRCC 177   862 1,039 164 1,367   1,531

MRO 400   1,259 1,659 400 1,264   1,664

NPCC‐NE 194   2,504 2,698 180 2,904   3,084

NPCC‐NY 347   3,011 3,357 327 3,618   3,946

RFC 1,532   5,503 7,035 1,526 5,661   7,187

SERC‐Central 388   71 459 388 71   459

SERC‐Delta 282   5,524 5,806 282 5,524   5,806

SERC‐Gateway 296   526 822 295 543   838

SERC‐Southeastern 209   469 678 209 469   678

SERC‐VACAR 378   664 1,042 377 689   1,066

SPP 143   933 1,076 141 994   1,135

WECC‐CA 227   5,055 5,283 182 6,881   7,063

WECC‐AZ‐NM‐SNV 5   773 778 5 773   778

WECC‐NWPP 40   129 169 40 129   169

WECC‐RMPA 16   184 200 16 184   200

   TOTAL 4,954   32,522 37,476 4,848 36,366   41,214
Scenario Results

Scenario Results 

Page 16 2010 Special Reliability Assessment Scenario 

National Emissions Standards for Hazardous Pollutants (NESHAP) or Maximum 

Achievable Control Technology (MACT)

National Emissions Standards for Hazardous Pollutants (NESHAP) or Maximum Achievable 

Control Technology (MACT) will apply to all existing and future coal and oil fired steam 

capacity. The Moderate Case scenario rulemaking varies for MACT emission rate limitations 

by coal type. This assessment assumes that the EPA deadline is January 1, 2015. However, in 

the Moderate Case, only 40 percent of units that will eventually retire do so by January 1, 2015. 

As EPA has no authority under the Clean Air Act to grant waivers for a MACT standard, one of 

these two28 conditions must occur: 

 the EPA Administrator (or state with program approval) grants an extension of one 

additional year, finding more time is “necessary for the installation of controls”–

§112(i)(3)(B). This may occur on a case-by-case basis; or 

 a Presidential exemption for a period of not more than two years is granted, assuming the 

President finds (1) the technology to implement such standard is not available and (2) it is 

in the national security interests to do so. Additional one year extensions are also 

available –§112(i)(4). 

The Moderate Case outcome is that there are no forced retirements as of January 1, 2013. 

Twenty percent of units retire by January 1, 2014, reaching 40 percent of units retired by January 

1, 2015 followed by an additional 20 percent in each subsequent year, such that all designated 

units are retired by January 1, 2018. In 2015, the impact of the Moderate Case is roughly 2.1 

GW of existing coal-fired capacity (59 units) “economically vulnerable” for retirement; another 

0.8 GW may be derated. The figure triples by 2018 to 6.6 GW of coal capacity that may be 

retired and 1.8 GW derated for a total impact of 8.4 GW. 

The Strict Case assumes that no waivers are granted and all electric generation units must be in 

compliance by January 1, 2015. Obtaining these waivers appears difficult; the EPA granted a 

sector-wide extension of one year only once, in a marine MACT rule. The Strict Case also 

assumes that all retirements occur in the two years leading up to the deadline, i.e., during 2013 

and 2014, with none as of January 1, 2013. The Strict Case also increases compliance costs by 

25 percent. These two assumptions significantly change the assessment results, such that by 

2015 there is 14.9 GW of existing coal-fired capacity (228 units) “economically vulnerable” for 

early retirement and 2.8 GW derated for a total of 17.6 GW. The 2015 result carries over into 

2018. 

MACT depicts the greatest variation between the two cases of all the EPA regulations. There is 

a 12 GW difference in capacity loss between the Moderate Case and the Strict Case by 2015. 

There is a nine GW difference by 2018. Distribution of this capacity by Region/subregion for 

2015 and 2018 are shown in Table 3 and Table 4. 

 

28 Under section 202(c) of the Federal Power Act, the Secretary of Energy has authority when an emergency exists “by reason of 

a sudden increase in the demand for electric energy, or a shortage of electric energy or of facilities for the generation or 

transmission of electric energy, or of fuel or water for generating facilities, or other causes,” to order such temporary 

interconnection of facilities or generation, delivery, interchange, or transmission of electric energy as in his/her judgment “will 

best meet the emergency and serve the public interest.” However, section 202(c) does not specifically mention EPA or the 

Clean Air Act. 
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2010 Special Reliability Assessment Scenario Page 17 

Table 3: MACT Impacts ‐ 2015

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 73   0 73 73 0   73

FRCC 0   0 0 78 121   199

MRO 125   202 327 144 764   908

NPCC‐NE 0   0 0 32 616   647

NPCC‐NY 0   0 0 16 694   710

RFC 103   1,061 1,164 1,060 5,493   6,553

SERC‐Central 61   71 132 305 1,000   1,305

SERC‐Delta 69   18 87 69 95   164

SERC‐Gateway 84   35 119 110 365   475

SERC‐Southeastern 33   140 173 337 1,208   1,545

SERC‐VACAR 0   465 465 255 2,649   2,905

SPP 127   0 127 130 52   181

WECC‐CA 0   0 0 3 0   3

WECC‐AZ‐NM‐SNV 49   0 49 49 1,580   1,629

WECC‐NWPP 72   39 111 73 129   202

WECC‐RMPA 10   0 10 10 100   110

   TOTAL 806   2,032 2,838 2,746 14,865   17,611

Table 4: MACT Impacts ‐ 2018

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 73   0 73 73 0   73

FRCC 16   0 16 78 121   199

MRO 144   708 853 144 764   908

NPCC‐NE 25   0 25 32 616   647

NPCC‐NY 16   58 74 16 694   710

RFC 514   2,540 3,055 1,060 5,493   6,553

SERC‐Central 167   184 351 305 1,000   1,305

SERC‐Delta 70   46 116 69 95   164

SERC‐Gateway 100   96 196 110 365   475

SERC‐Southeastern 227   140 367 337 1,208   1,545

SERC‐VACAR 132   970 1,102 255 2,649   2,905

SPP 130   52 181 130 52   181

WECC‐CA 3   0 3 3 0   3

WECC‐AZ‐NM‐SNV 49   1,580 1,629 49 1,580   1,629

WECC‐NWPP 73   129 202 73 129   202

WECC‐RMPA 10   100 110 10 100   110

   TOTAL 1,750   6,602 8,352 2,746 14,865   17,611

 
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Page 18 2010 Special Reliability Assessment Scenario 

The impacts could be more severe if costs escalate due to tighter implementation timelines of 

three years and the large number of plants (840 units) that may need to upgrade their 

environmental controls at the same time. This could require additional new generation and 

expanded use of existing lower emission generation like natural gas. In circumstances in which 

power plant retirements trigger localized reliability concerns, EPA can follow established 

precedent, including use of consent decrees, to permit continued operation for reliability 

purposes only, pending necessary upgrades or generation additions. 

A sensitivity comparison was completed for the 2015 Strict Case for MACT accounting for the 

compressed implementation timeline (see Figure 6). The risk that generation units will retire 

simply due to insufficiently available third party engineering services is not modeled in the 

sensitivity test. Because the 2015 Strict Case already includes a 25 percent cost premium, the 

sensitivity comparisons were completed at cost increase intervals of 25 percent from 0 percent up 

to 200 percent. As a result, retirements increased at an approximate linear rate from a low of 

11.4 GW (retirements of 8.5 GW and derated capacity of 2.9 GW) at no cost increase up to 63 

GW (retirements of 61.2 GW and derated capacity of 1.8 GW) at a 200 percent cost increase. 

Figure 6: Sensitivity of Retirements Plus Derated Capacity as a Function of Higher 

Assumed Costs due to the MACT Regulation 

 

0

10

20

30

40

50

60

70

+0% +25% +50% +75% +100% +125% +150% +175% +200%

GW of Retired + Derated Capacity

Effective Cost Increase

Total At‐Risk Retirements Derates
Scenario Results

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2010 Special Reliability Assessment Scenario Page 19 

Clean Air Transport Rule (CATR)

Starting in 2012, the CATR will apply to fossil fuel units with greater than 25 MW capacity that 

are located in 31 states. Although EPA provided three different options in July 2010, the EPA 

preferred option was selected for the Moderate Case. An analysis of this option found that the 

rule would have the greatest impact in the state utilities that relied heavily upon purchased 

allowances for compliance with their Acid Rain program and CAIR program obligations. By 

significantly limiting the use of out-of-state utility purchases and/or banked allowances after 

2013, some utilities would be forced to retrofit FGD and SCR emission controls on their larger 

units or retire to comply. The oil and gas steam units would remain largely untouched because 

of their limited emissions. As described earlier in this report, these reductions would be 

concentrated to a few states. 

The extent of retirements triggered by CATR is heavily linked to: 

1. the flexibility provided to affected sources to avoid reductions in smaller emitting stations 

by retrofitting controls in larger emitting units (through allowance trading); and 

2. the final budget state cap (the July 2010 draft emission caps are interim limits that will be 

reduced further as stricter future ambient fine particulate and ozone standards are 

adopted). The EPA preferred option (Moderate Case) would result in the retirement of 

five coal-fired units (538 MW) by 2013 and 18 coal-fired units (2,740 MW) by 2015 (see 

Tables 5 and 6).29

Table 5: CATR Impacts ‐ 2013

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 0   0 0 64 0   64

FRCC 0   0 0 4 0   4

MRO 0   0 0 162 155   318

NPCC‐NE 0   162 162 1 0   1

NPCC‐NY 0   0 0 0 0   0

RFC 1   376 377 191 781   972

SERC‐Central 11   0 11 87 71   158

SERC‐Delta 0   0 0 99 29   128

SERC‐Gateway 0   0 0 94 35   129

SERC‐Southeastern 5   0 5 145 130   275

SERC‐VACAR 0   0 0 47 548   594

SPP 0   0 0 110 26   136

WECC‐CA 0   0 0 0 0   0

WECC‐AZ‐NM‐SNV 0   0 0 0 0   0

WECC‐NWPP 0   0 0 0 0   0

WECC‐RMPA 0   0 0 0 0   0

   TOTAL 17   538 555 1,004 1,775   2,779

 

29 Impacts from CATR would begin in 2014. For this report, only 2013, 2015, and 2018 were assessed. 
Scenario Results

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Page 20 2010 Special Reliability Assessment Scenario 

Alternatively, EPA could elect to pursue emission rate limitations on the coal-fired units. This 

approach would provide no ability to trade at all and units would be forced to retrofit the needed 

controls or retire. With the impending changes in NAAQS unknown, the Strict Case assumes that 

EPA will adopt much stricter rate limits on all coal-fired capacity that only can be met through 

post combustion controls. Given the large demand created for emission controls, the capital cost 

will likely increase by 25 percent or more from current levels. Overall, 86 coal units (5,221 

MW) would have their operating costs pushed above new replacement capacity and force their 

retirement. Although tied to the changing of the NAAQS, these retirements would likely occur 

in or before 2015. Further impacts, past 2015, are not expected to materialize. 

Table 6: CATR Impacts ‐ 2015

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 0   0 0 91 0   91

FRCC 0   0 0 16 0   16

MRO 0   33 33 216 1,007   1,223

NPCC‐NE 0   162 162 14 370   384

NPCC‐NY 0   0 0 22 50   73

RFC 67   1,667 1,734 552 2,192   2,744

SERC‐Central 15   0 15 154 136   290

SERC‐Delta 0   0 0 127 29   155

SERC‐Gateway 0   878 878 171 35   206

SERC‐Southeastern 60   0 60 258 230   488

SERC‐VACAR 0   0 0 130 1,056   1,186

SPP 0   0 0 202 115   317

WECC‐CA 0   0 0 0 0   0

WECC‐AZ‐NM‐SNV 0   0 0 0 0   0

WECC‐NWPP 0   0 0 0 0   0

WECC‐RMPA 0   0 0 0 0   0

   TOTAL 142   2,740 2,882 1,952 5,221   7,173

The analysis affects coal units only and the most significant impact of the Strict Case occurs in 

RFC, SERC and MRO, which have the most remaining coal plants that require upgrading in the 

31 states and the District of Columbia affected by CATR 
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2010 Special Reliability Assessment Scenario Page 21 

Coal Combustion Residuals (CCR) Disposal Regulations

A distribution of the coal units “economically vulnerable” from the potential coal combustion 

byproducts rule is shown in Table 7 for both the Moderate Case and the Strict Case scenarios in 

2018. As shown, the additional capital and annual operating cost increases under both scenarios 

would trigger the retirement of only four coal units with capacity of 287 MW in the Moderate 

Case and 12 units with capacity of 388 MW in the Strict Case. This “economically vulnerable” 

coal-fired capacity is located in three to four SERC subregions and MRO. Under the estimated 

compliance timeline, these coal unit retirements would likely not occur until the 2015—2018 

period. A larger number of coal units are affected in the Strict Case, since the Moderate Case 

affects only those plants using ponds for ash disposal, whereas the Strict Case assumes that all 

coal plants will need to store coal combustion byproducts in a lined landfill. 

Table 7: CCR Impacts ‐ 2018

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 0   0 0 0 0   0

FRCC 0   0 0 0 0   0

MRO 0   0 0 0 83   83

NPCC‐NE 0   0 0 0 0   0

NPCC‐NY 0   0 0 0 0   0

RFC 0   0 0 0 0   0

SERC‐Central 0   71 71 0 71   71

SERC‐Delta 0   0 0 0 18   18

SERC‐Gateway 0   86 86 0 86   86

SERC‐Southeastern 0   130 130 0 130   130

SERC‐VACAR 0   0 0 0 0   0

SPP 0   0 0 0 0   0

WECC‐CA 0   0 0 0 0   0

WECC‐AZ‐NM‐SNV 0   0 0 0 0   0

WECC‐NWPP 0   0 0 0 0   0

WECC‐RMPA 0   0 0 0 0   0

   TOTAL 0   287 287 0 388   388

These estimates are substantially less than the EOP Group Study titled Cost Estimates for the 

Mandatory Closure of Surface Impoundments Used for the Management of Coal Combustion 

Byproducts at Coal Fired Utilities that resulted in 35 GW of “economically vulnerable” coalfired capacity. Some differences are likely to be attributable to this assessment excluding 

already announced generating unit retirements (more than 28 GW) and incorporating a more 

comprehensive retirement replacement cost method (versus applying a unit size criterion). 

Because of the large difference in results, sensitivity comparisons were conducted to determine 

how the number of “economically vulnerable” units would vary under higher disposal cost 

assumptions. Disposal costs can vary significantly based upon suitable land availability and state 

landfill requirements. Like EPA, this assessment assumed that suitable landfill sites could be 

found, permitted and operated near to existing coal plants. If no suitable sites can be permitted, 

power suppliers may be forced to transport their residuals to appropriately permitted offsite 

landfills and pay tipping fees that could increase disposal costs. 
Scenario Results

Scenario Results 

Page 22 2010 Special Reliability Assessment Scenario 

In lieu of conducting site-specific assessment, a sensitivity comparison was completed across a 

wide range of ash disposal costs from $37.50 up to $1,250 per ton (see Figure 7). The economic 

retirements slope gradually upward from 0.3 to 2.1 GW as costs increase from $37.50 to $500 

per ton, then retirements begin to jump significantly with amounts reaching 22 GW at $1,000 

per ton, and exponentially increase to 49 GW at $1,125 and nearly 88 GW at $1,250 per ton. 

However, the costs are believed to be well contained within the flat slope portion of the line on 

the far left side. However, the additional costs that may become associated with distance 

removal of the hazardous substance to existing certified landfills could drive costs upward. 

Figure 7: Sensitivity of Retirements as a Function of Higher Assumed Coal-Ash Disposal 

Costs due to Coal Combustion Residuals regulations 

0

10

20

30

40

50

60

70

80

90

100

$38$63

$125$188$250$313$375$438$500$625$750$875

$1,000$1,125$1,250

Effective Disposal Cost Per Ton of Coal Ash

GW of Retired Capacity

GW of Retired Capacity
Scenario Results

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2010 Special Reliability Assessment Scenario Page 23 

Combined EPA Environmental Rulemaking

The reliability impact of each rule outlined above reflects the cost and retirement decisions for 

each individually. However, power suppliers will likely make their retirement decisions based 

upon compliance costs for the combination of all future environmental requirements. Although 

some environmental control overlap exists between the CATR and MACT (i.e., for FGD and 

SCR retrofits), most compliance costs are expected to be additive between the different EPA 

rules. 

The cumulative effect of the four potential EPA rules is provided in Tables 8, 9, and 10 for each 

of the three years assessed. In 2015, anywhere from 31–70 GW of existing fossil fuel capacity 

(351–678 generation units; beyond the 28 GW of retirements already announced and not 

included in NERC’s Long Term Reliability Assessment) are “economically vulnerable” for 

retirement from these four potential EPA rules. Additionally the 273–700 units of continuing 

operation will be derated by a total of 2.4-7.3 GW from the increased parasitic loads from the 

control operation. The projected retirements are significantly lower in 2013 and significantly 

higher for the Moderate Case in 2018. 

Table 8: Combined EPA Regulations Impacts ‐ 2013

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 0   0 0 91 0   91

FRCC 0   0 0 16 0   16

MRO 0   0 0 216 1,007   1,223

NPCC‐NE 0   162 162 12 532   545

NPCC‐NY 0   0 0 19 258   278

RFC 1   376 377 541 2,876   3,418

SERC‐Central 11   0 11 153 211   364

SERC‐Delta 0   0 0 127 29   155

SERC‐Gateway 0   0 0 171 35   206

SERC‐Southeastern 5   0 5 258 230   488

SERC‐VACAR 0   0 0 128 1,163   1,291

SPP 0   0 0 58 89   147

WECC‐CA 0   0 0 144 26   170

WECC‐AZ‐NM‐SNV 0   0 0 0 0   0

WECC‐NWPP 0   0 0 0 0   0

WECC‐RMPA 0   0 0 0 0   0

   TOTAL 17   538 555 1,934 6,457   8,391

For the combined potential EPA rulemaking, the retirement and derating penalties are 

concentrated in five NERC Regions/subregions for the 2015 Moderate Case -- SERC, NPCC, 

RFC, ERCOT, and WECC, ranked in order of highest to lowest. For the 2015 Strict Case, the 

rank order is SERC, RFC, WECC, NPCC, and finally ERCOT. 
Scenario Results

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Page 24 2010 Special Reliability Assessment Scenario 

Table 9: Combined EPA Regulations Impacts ‐ 2015

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 246   5,055 5,301 480 5,295   5,775

FRCC 71   862 933 239 1,488   1,727

MRO 319   1,259 1,578 612 4,424   5,036

NPCC‐NE 0   2,504 2,504 169 3,938   4,107

NPCC‐NY 35   3,011 3,046 309 4,759   5,068

RFC 607   4,890 5,497 2,224 16,423   18,648

SERC‐Central 237   71 308 509 4,546   5,055

SERC‐Delta 113   5,524 5,636 465 5,803   6,268

SERC‐Gateway 113   526 639 413 3,902   4,315

SERC‐Southeastern 140   469 609 537 3,132   3,669

SERC‐VACAR 132   915 1,047 515 5,042   5,557

SPP 198   831 1,029 428 2,149   2,577

WECC‐CA 0   3,560 3,560 195 6,452   6,647

WECC‐AZ‐NM‐SNV 49   773 822 54 2,353   2,407

WECC‐NWPP 108   129 237 113 129   242

WECC‐RMPA 25   184 208 25 225   251

   TOTAL 2,394   30,563 32,957 7,289 70,059   77,349

Table 10: Combined EPA Regulations Impacts ‐ 2018

   Moderate Case Strict Case

  

Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

(MW) Total

ERCOT 366   5,055 5,421 480 5,295   5,775

FRCC 188   983 1,171 239 1,488   1,727

MRO 534   1,553 2,087 612 4,424   5,036

NPCC‐NE 196   2,970 3,166 169 3,938   4,107

NPCC‐NY 353   3,239 3,592 309 4,759   5,068

RFC 1,965   7,848 9,813 2,266 15,451   17,717

SERC‐Central 541   445 986 509 4,546   5,055

SERC‐Delta 352   5,541 5,892 465 5,803   6,268

SERC‐Gateway 390   694 1,084 442 3,299   3,741

SERC‐Southeastern 423   781 1,204 537 3,132   3,669

SERC‐VACAR 476   2,066 2,542 515 5,042   5,557

SPP 271   972 1,243 428 2,149   2,577

WECC‐CA 230   5,055 5,285 182 6,947   7,130

WECC‐AZ‐NM‐SNV 54   2,353 2,407 54 2,353   2,407

WECC‐NWPP 113   129 242 113 129   242

WECC‐RMPA 27   184 210 25 225   251

   TOTAL 6,479   39,867 46,346 7,348 68,979   76,327
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2010 Special Reliability Assessment Scenario Page 25 

This assessment models both coal and oil/gas-steam unit capacity retirement. Figures 8 and 9 

depict total capacity loss for both unit types, as well as the size of individual retired units by 

Region for the 2018 Moderate and Strict Case assessments. 

In Figures 8 and 9, each retired unit is plotted on the scatter chart based on unit size (Right YAxis). In some cases, data points for units with the same unit size (MW) may overlap and be 

hidden. The blue and red bars (Left Y-Axis) show the total retired capacity by subregion. 

Overall, a majority of the retired units are less than 200 MW. 

 

 

The Strict Case (see Figure 9) has a significant impact on coal units in the MRO, RFC, SERCCentral, SERC-Gateway, SERC-Southern, and SERC-VACAR Regions/subregions. 

0

100

200

300

400

500

600

700

800

900

0

2,000

4,000

6,000

8,000

10,000

12,000

Generation Capacity of Retired Unit (MW)

Total Generation Capacity Retired (MW)

Figure 8: 2018 Moderate Case   

Units Retired for Combined Scenario

Total Retired Coal Capacity (MW) Total Retired O/G‐ST Capacity (MW)

Retired Coal Unit Retired O/G‐ST Unit

(Left Y‐Axis)

(Right Y‐Axis)
Scenario Results

Scenario Results 

Page 26 2010 Special Reliability Assessment Scenario 

 

Figure 10 illustrates the model’s representation of the differential between two items: the cost of 

a new gas plant and today’s operating/ongoing costs for any new investment that has incremental 

costs, regardless of its source or mandate. 

0

100

200

300

400

500

600

700

800

900

0

2,000

4,000

6,000

8,000

10,000

12,000

Generation Capacity of Retired Unit (MW)

Total Generation Capacity Retired (MW)

Figure 9: 2018 Strict Case

Units Retired for Combined Scenario

Total Retired Coal Capacity (MW) Total Retired O/G‐ST Capacity (MW)

Retired Coal Unit Retired O/G‐ST Unit

(Left Y‐Axis)

(Right Y‐Axis)

Replacement Cost

Minus Total Plant Cost

(2010$ $/MWh)

($50)

($25)

$0

$25

$50

$75

$100

$125

$150

$175

$200

0 50 100 150 200 250 300 350 400

Cumulative Capacity (GW)

Figure 10:  Replacement Cost Minus

Plant Cost Before Any Retrofits
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2010 Special Reliability Assessment Scenario Page 27 

Reliability Assessment

Impacts on Bulk Power System Adequacy 

Early retirement of multiple units in the short-run can stress the bulk power system if plans are 

not in place to add resources. This can affect both short- and long-term planning strategies and 

reduce Planning Reserve Margins.30 Sufficient Planning Reserve Margins must be maintained to 

provide reliable electric service. With fewer resources, flexibility is reduced and the risk of a 

capacity shortage may increase, unless additional resources are available. Where Planning 

Reserve Margins fall below zero, there is a basic inability to serve load with available resources. 

For this assessment, NERC studied the effects on Planning Reserve Margins from both unit 

retirement (assuming retired capacity is not replaced) and retrofits, which cause capacity 

reductions due to increased station loads to support emission controls or new intake structures. 

Planning Reserve Margins are presented using Deliverable Capacity Resources and Adjusted 

Potential Capacity Resources.31 The assessment of effects to Planning Reserve Margins does not 

consider the ability of the electric power industry to replace retired capacity. Each modeled year 

portrays a “snapshot” of potential effects caused by the potential EPA regulations, rather than an 

ongoing timeline of retrofits and retirements. Models do not account for units coming out of 

retirement due to future conditions. The demand and resource projections from the 2009 LongTerm Reliability Assessment are used as the reference case and can be found in Appendix III, 

Data Tables. 

Models for each year in all cases show identical Planning Reserve Margin reductions for 

Deliverable and Adjusted Potential Capacity Resources, indicating that the potential EPA 

regulations have little to no effect on Existing-Other, Future Other, and Conceptual Resources. 

Therefore, comparative analysis of Deliverable Capacity Resources and Adjusted Potential 

Capacity figures indicates the magnitude of future resource additions required to maintain future 

reserve requirements. 

Resources from these ten-year projections are reduced to form the scenario cases (Moderate Case 

and Strict Case—previously described in the report) and calculate the resulting Planning Reserve 

Margins. This reliability assessment includes a comparison of the impacts on Planning Reserve 

Margin for the years 2013, 2015, and 2018 based on the 2009 reference case. The resulting 

Planning Reserve Margin was compared to the NERC Reference Margin Level to determine if 

 

30Planning Reserve Margin is designed to measure the amount of generation capacity available to meet expected demand in the 

planning horizon. Coupled with probabilistic analysis, calculated planning reserve margins have been an industry standard 

used by planners for decades as a relative indication of resource adequacy. Planning Reserve Margin is the difference between 

available capacity and peak demand, normalized by peak demand (as a percentage) needed to maintain reliable operation while 

meeting unforeseen increases in demand (e.g. extreme weather) and/or unexpected outages of existing capacity. From a 

planning perspective, Planning Reserve Margin trends identify whether capacity additions are keeping up with demand growth. 31 Deliverable Capacity Resources (DCR)—defined as Existing-Certain and Net Firm Transactions plus Future-Planned capacity 

resources plus net transactions—and Adjusted Potential Capacity Resources (APCR)—defined as the sum of Deliverable 

Capacity Resources, Existing-Other Resources, Future-Other Resources (reduced by a confidence factor), Conceptual 

Resources (reduced by a confidence factor), and net transactions—account for future generation capacity planned for in the 

reference case.31 DCR represents existing generation that has been identified as “Certain” plus future firm resources. APCR 

prevents this assessment from being overly conservative in two ways: 1) Conceptual resources measure industry’s future 

response towards maintaining Planning Reserve Margins and 2) APCR represents the portion of the interconnection queue that 

is historically built. A range of resource projections is identified and evaluated from these two values in this assessment. 
Reliability Assessment

Reliability Assessment 

Page 28 2010 Special Reliability Assessment Scenario 

more resources are needed in the scenario case (see Table 11).32 For the resource adequacy 

assessment, NERC chose a range of resource categories to evaluate Planning Reserve Margins 

for this scenario. The range includes Deliverable Capacity Resources on the low-end and 

Adjusted Potential Capacity Resources on the high-end. Refer to the Terms Used in This Report

section for detailed definitions regarding supply/resource categories. 

Overall, impacts on Planning Reserve Margins and the need for more resources is a function of 

the compliance timeline associated with the potential EPA regulations. Up to a 78 GW reduction 

of coal, oil, and gas-fired generation capacity is identified for retirement during the ten-year 

period of this scenario. For the Moderate Case, this occurs in 2018; however, in the Strict Case 

similar reduction occurs in 2015. The reduction in capacity significantly affects projected 

Planning Reserve Margins for a majority of the NERC Regions and subregions. Potentially 

significant reductions in capacity within a five-year period may require heightened concentration 

towards the addition of resources. For the United States as a whole, the Planning Reserve 

Margin is significantly reduced up to 9.3 percentage points in the Strict Case. 

Additionally, more transmission resources may be needed as the industry responds to resolve 

identified capacity deficiencies. As replacement generation is constructed, new transmission 

may be needed to interconnect new generation. Additionally, existing generation that may not be 

deliverable due to transmission limitations may need enhancements to the transmission system in 

order to allow firm and reliable transmission service. 

While NERC did not model deliverability or stability impacts to the transmission system (second 

tier effects) in this assessment, constructing new transmission or refurbishing existing 

transmission may be required. Transmission system enhancements and reconfiguration may be 

necessary in some areas, which may create additional timing issues as transmission facilities will 

take relatively longer to construct than generation. 

 

32NERC's Reference Reserve Margin Level is equivalent to the Target Reserve Margin Level provided by the Region/subregion’s 

own specific margin based on load, generation, and transmission characteristics as well as regulatory requirements. If not 

provided, NERC assigned 15 percent Reserve Margin for thermal systems and 10 percent for predominately hydro systems. 

Table 11: NERC Reference Margin Levels

ERCOT 12.5%

FRCC 15.0%

MRO 15.0%

NPCC

New England 15.0%

New York 16.5%

RFC 15.0%

SERC

Central 15.0%

Delta 15.0%

Gateway 12.7%

Southeastern 15.0%

VACAR 15.0%

SPP 13.6%

WECC

AZ‐NM‐SNV 17.8%

CA‐MX US 22.3%

NWPP 16.3%

RMPA 17.1%
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2010 Special Reliability Assessment Scenario Page 29 

Resource Adequacy Assessment Results: 2013 

There are virtually no impacts to Planning Reserve Margins in the short term (2013). CATR is 

the only regulation that affects units in 2013. MRO, New England, RFC, SERC-Gateway, and 

SERC-Southeastern are the only Regions/subregions affected by CATR in the Moderate Case—

ERCOT, FRCC, and all SERC subregions are affected in the Strict Case. 

However, when CATR is modeled in the Combined EPA Regulation Scenario, the Strict Case 

results in a coal-fired capacity reduction of 8,391 MW by 2013 (see Figure 12). Overall, this 

amount does not appear to be significant and represents less than one percent of total capacity 

resources across the United States, but represents just fewer than 100 electric generation plants. 

The increased capacity reduction is a result of the increased costs being considered by generator 

owners, not only to comply with CATR, but with the 316(b), MACT, and CCR regulations. 

Because of these reductions, Planning Reserve Margins are reduced slightly in the affected 

Regions/subregions. The MRO Planning Reserve Margin decreases the most (about 2.7 

percentage points when considering both the Deliverable and Adjusted Potential Planning 

Reserve Margins) to approximately 19 percent (see Figure 13 and 14). Other affected 

Regions/subregions include NPCC-New England and RFC, which result in a net Planning 

Reserve Margin reduction of less than two percentage points. There is no change to the Moderate 

Case when comparing the results of CATR modeled separately and the Combined EPA 

Regulation Scenario. 

0

50,000

100,000

150,000

200,000

250,000

MW

Figure 11: 2013 Summer Peak Deliverable Capacity  Resources

(DCR) Impacts of Combined EPA Regulation Scenario

(DCR) ‐ Reference Case (DCR) ‐ Moderate Case (DCR) ‐ Strict Case
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Page 30 2010 Special Reliability Assessment Scenario 

In MRO and the SERC-Southeastern subregion, Deliverable Planning Reserve Margin is below 

the NERC Reference Margin Level in both scenario cases. However, this is also true when 

considering the Reference Case. This indicates more resources may be needed regardless of 

impacts from potential EPA regulations. These two subregions must rely on Adjusted Potential 

Capacity Resources to meet the NERC Reference Margin Level in 2013. 

0

50,000

100,000

150,000

200,000

250,000

MW

Figure 12: 2013 Summer Peak Adjusted Potential Capacity Resources

(APCR) Impacts of Combined EPA Regulation Scenario

(APCR) ‐ Reference Case (APCR) ‐ Moderate Case (APCR) ‐ Strict Case

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

Reserve Margin (%)

Figure 13: 2013 Summer Peak Deliverable  Capacity Resources

(DCR) Planning Reserve Margin Impacts of Combined EPA Regulation

Scenario

(DCR) Reserve Margin ‐ Reference Case (DCR) Reserve Margin ‐ Moderate Case

(DCR) Reserve Margin ‐ Strict Case NERC Reference Margin Level
Reliability Assessment

Reliability Assessment

2010 Special Reliability Assessment Scenario Page 31 

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

Reserve Margin (%)

Figure 14: 2013 Summer Peak Adjusted Potential Capacity Resources

(APCR) Planning Reserve Margin Impacts of Combined EPA Regulation

Scenario

(APCR) Reserve Margin ‐ Reference Case (APCR) Reserve Margin ‐ Moderate Case

(APCR) Reserve Margin ‐ Strict Case NERC Reference Margin Level

ERCOT 16.5% ―23.9% 0.0 ―0.0 16.3% ―23.8% ‐0.1 ―‐0.1

FRCC 28.6% ―28.6% 0.0 ―0.0 28.5% ―28.5% 0.0 ―0.0

MRO 12.9% ―22.1% 0.0 ―0.0 10.1% ―19.3% ‐2.7 ―‐2.7

NPCC‐NE 18.0% ―25.9% ‐0.6 ―‐0.6 16.7% ―24.6% ‐1.9 ―‐1.9

NPCC‐NY 28.1% ―29.8% 0.0 ―0.0 27.3% ―29.0% ‐0.8 ―‐0.8

RFC 19.2% ―24.0% ‐0.2 ―‐0.2 17.6% ―22.4% ‐1.9 ―‐1.9

SERC‐Central 23.6% ―27.2% 0.0 ―0.0 22.8% ―26.4% ‐0.9 ―‐0.9

SERC‐Delta 27.5% ―30.9% 0.0 ―0.0 27.0% ―30.4% ‐0.5 ―‐0.5

SERC‐Gateway 24.0% ―28.0% 0.0 ―0.0 22.9% ―27.0% ‐1.0 ―‐1.0

SERC‐Southeastern 13.0% ―29.8% 0.0 ―0.0 12.1% ―28.9% ‐0.9 ―‐0.9

SERC‐VACAR 17.5% ―20.3% 0.0 ―0.0 15.5% ―18.3% ‐1.9 ―‐1.9

SPP 15.9% ―30.3% 0.0 ―0.0 15.9% ―30.3% 0.0 ―0.0

WECC‐CA 48.6% ―48.6% 0.0 ―0.0 48.4% ―48.4% ‐0.3 ―‐0.3

WECC‐AZ‐NM‐SNV 22.1% ―23.7% 0.0 ―0.0 22.1% ―23.7% 0.0 ―0.0

WECC‐NWPP 29.9% ―30.1% 0.0 ―0.0 29.9% ―30.1% 0.0 ―0.0

WECC‐RMPA 24.7% ―30.3% 0.0 ―0.0 24.7% ―30.3% 0.0 ―0.0

   TOTAL 22.3% ―27.7% ‐0.1 ―‐0.1 21.4% ―26.7% ‐1.0 ―‐1.0

Table 12: Combined Impacts ‐ 2013

Moderate Case Strict Case

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin
Reliability Assessment

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Page 32 2010 Special Reliability Assessment Scenario 

Resource Adequacy Assessment Results: 2015 

For the modeled year 2015, the assessment results have a greater impact on Planning Reserve 

Margin. Most notably, the Combined Proposed EPA Regulations Scenario shows considerable 

reductions, reducing Planning Reserve Margins across the United States during the next five 

years. 

As previously discussed, the Moderate Case and the Strict Case differ in key assumptions. In 

2015, capacity reductions range from 33 GW (Moderate Case) to 77 GW (Strict Case). For the 

Moderate Case, ERCOT, RFC, and the SERC-Delta Regions/subregions are the most affected, 

each with approximately a 5,500 MW reduction in capacity (Figure 16). For the Strict Case, 

RFC capacity is reduced by 16.4 GW. 

0

50,000

100,000

150,000

200,000

250,000

MW

Figure 15: 2015 Summer Peak Deliverable Capacity  Resources

(DCR) Impacts of Combined EPA Regulation Scenario

(DCR) ‐ Reference Case (DCR) ‐ Moderate Case (DCR) ‐ Strict Case
Reliability Assessment

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2010 Special Reliability Assessment Scenario Page 33 

For the Moderate Case, a 3.2 percent reduction in overall capacity results in Planning Reserve 

Margin reductions for a majority of the NERC Regions/subregions. Accordingly, the SERCCentral, SERC-Southeastern, SERC-VACAR, WECC-NWPP, and WECC-RMPA subregions 

show less than a two percentage point reduction in Planning Reserve Margin. When considering 

the Deliverable Planning Reserve Margin a majority of the Regions/subregions fall below the 

NERC Reference Margin Level in 2015 for both cases. In MRO, Deliverable Planning Reserve 

Margins fall below zero in the Strict Case (Figure 17). Additionally, because of a 15 percent 

reduction in SERC-Delta capacity resources, the Planning Reserve Margin is reduced to 1.9 

percent (Deliverable—see Figure 17) and 5.2 percent (Adjusted Potential—see Figure 18). In 

this scenario, more resources will be needed in the SERC-Delta subregion under the Moderate 

Case assumptions. 

0

50,000

100,000

150,000

200,000

250,000

MW

Figure 16: 2015 Summer Peak Adjusted Potential Capacity Resources

(APCR) Impacts of Combined EPA Regulation Scenario

(APCR) ‐ Reference Case (APCR) ‐ Moderate Case (APCR) ‐ Strict Case

‐5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

Reserve Margin (%)

Figure 17: 2015 Summer Peak Deliverable  Capacity Resources

(DCR) Planning Reserve Margin Impacts of Combined EPA Regulation

Scenario

(DCR) Reserve Margin ‐ Reference Case (DCR) Reserve Margin ‐ Moderate Case

(DCR) Reserve Margin ‐ Strict Case NERC Reference Margin Level
Reliability Assessment

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Page 34 2010 Special Reliability Assessment Scenario 

For the Strict Case, a 7.2 percent reduction in overall capacity results in significant Planning 

Reserve Margin reductions for all NERC Regions and subregions, except the WECC subregions 

of NWPP and RMPA. Planning Reserve Margins are significantly due to over a nine percent of 

capacity resources in MRO, NPCC-New England, NPCC-New York, SERC-Central, SERCDelta, and SERC-Gateway. When considering Deliverable Planning Reserve Margins, nearly all 

Regions/subregions fall below the NERC Reference Margin Level (see Figure 17).Additionally, 

these Regions/subregions are below NERC’s Reference Margin Levels under the Strict Case 

assumptions, indicating reductions in those Regions’/subregions’ ability to maintain sufficient 

reserve levels. Most notably, SERC-Delta has a 3.1 percent Planning Reserve Margins in 2015. 

Additionally, capacity reductions in NPCC-New England, SERC-Gateway, and SERC-VACAR 

result in Planning Reserve Margins below 10 percent. In these Regions/subregions, more 

resources will be needed for this scenario. 

The impacts to Planning Reserve Margins are highly dependent on which resources are projected 

to be in-serving in the Reference Case. As such, Adjusted Potential Capacity Resources Planning 

Reserve Margins are not as impacted as Deliverable Capacity Resources Planning Reserve 

Margin. Therefore, in order to help mitigate resource adequacy issues, Adjusted Potential 

Resources (which include Conceptual Resources), which carry a level of uncertainty, may be 

needed to meet the NERC Reference Margin Level. However, as indicated above, even these 

additional resources may not be sufficient. 

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

Reserve Margin (%)

Figure 18: 2015 Summer Peak Adjusted Potential Capacity Resources

(APCR) Planning Reserve Margin Impacts of Combined EPA Regulation

Scenario

(APCR) Reserve Margin ‐ Reference Case (APCR) Reserve Margin ‐ Strict Case

(APCR) Reserve Margin ‐ Strict Case NERC Reference Margin Level
Reliability Assessment

Reliability Assessment

2010 Special Reliability Assessment Scenario Page 35 

ERCOT 7.5% ―15.4% ‐7.7 ―‐7.7 6.8% ―14.7% ‐8.4 ―‐8.4

FRCC 23.0% ―23.0% ‐2.0 ―‐2.0 21.3% ―21.3% ‐3.7 ―‐3.7

MRO 5.9% ―15.5% ‐3.5 ―‐3.5 ‐1.7% ―7.9% ‐11.0 ―‐11.0

NPCC‐NE 7.2% ―16.2% ‐8.3 ―‐8.3 1.8% ―10.8% ‐13.6 ―‐13.6

NPCC‐NY 17.4% ―19.5% ‐8.9 ―‐8.9 11.5% ―13.6% ‐14.8 ―‐14.8

RFC 14.2% ―19.4% ‐2.9 ―‐2.9 7.2% ―12.4% ‐9.9 ―‐9.9

SERC‐Central 21.0% ―24.5% ‐0.7 ―‐0.7 10.1% ―13.6% ‐11.6 ―‐11.6

SERC‐Delta 1.9% ―5.2% ‐18.6 ―‐18.6 ‐0.2% ―3.1% ‐20.6 ―‐20.6

SERC‐Gateway 19.6% ―23.6% ‐3.1 ―‐3.1 1.5% ―5.5% ‐21.3 ―‐21.3

SERC‐Southeastern 11.3% ―27.9% ‐1.1 ―‐1.1 5.7% ―22.4% ‐6.6 ―‐6.6

SERC‐VACAR 11.1% ―14.2% ‐1.5 ―‐1.5 4.6% ―7.6% ‐8.0 ―‐8.0

SPP 12.7% ―27.1% ‐2.2 ―‐2.2 9.3% ―23.8% ‐5.5 ―‐5.5

WECC‐CA 44.3% ―44.3% ‐5.8 ―‐5.8 39.3% ―39.3% ‐10.8 ―‐10.8

WECC‐AZ‐NM‐SNV 17.3% ―20.6% ‐2.4 ―‐2.4 12.6% ―15.9% ‐7.1 ―‐7.1

WECC‐NWPP 26.5% ―27.6% ‐0.5 ―‐0.5 26.5% ―27.6% ‐0.5 ―‐0.5

WECC‐RMPA 14.9% ―23.2% ‐1.7 ―‐1.7 14.6% ―22.9% ‐2.1 ―‐2.1

   TOTAL 16.1% ―21.7% ‐4.0 ―‐4.0 10.8% ―16.4% ‐9.3 ―‐9.3

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table 13: Combined Impacts ‐ 2015

Moderate Case Strict Case

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin
Reliability Assessment

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Page 36 2010 Special Reliability Assessment Scenario 

Resource Adequacy Assessment Results: 2018 

Further reductions in capacity resources and Planning Reserve Margins are the results in 2018. 

Most notably, the Combined EPA Regulations Scenario shows considerable reductions, 

effectively reducing Planning Reserve Margins across the United States within the next eight 

years. 

The Combined Regulation Scenario shows the most notable capacity resources reductions. As 

previously discussed, the Moderate Case and the Strict Case differ in key assumptions that have 

been made to the model. In 2018, capacity reductions range from 46 GW (Moderate Case) to 76 

GW (Strict Case).33 For the Moderate Case, RFC is the more affected Region with just under a 

10 GW reduction in capacity resources, followed by ERCOT, SERC-Delta, and the WECC-CA 

Regions/subregions, each with approximately a 5.5 GW capacity reduction (Figure 15). 

For the Strict Case, RFC capacity is reduced by 17.7 GW. With the exception of FRCC, WECCNWPP, and WECC-RMPA, all Regions/subregions show at least a five percent reduction in 

capacity resources. MRO, NPCC-New England, NPCC-New York, SERC-Central, SERC-Delta, 

and SERC-Gateway all show at least a nine percent reduction in capacity resources; SERC-Delta 

shows a 17 percent reduction, suggesting more resources will be needed in these areas. 

 

33 The total reductions for the 2018 Combined Regulation-Strict Case (76 GW) is less than the total reductions for the 2015 

Combined Regulation-Strict Case (77 GW) due to slightly higher gas prices assumed for the year 2018. Therefore, plants may 

opt to retrofit rather than purchase replacement generation. Each modeled year portrays a “snapshot” of potential effects 

caused by the EPA regulations, rather than an ongoing timeline of retrofits and retirements. 

0

50,000

100,000

150,000

200,000

250,000

MW

Figure 19: 2018 Summer Peak Deliverable Capacity  Resources

(DCR) Impacts of Combined EPA Regulation

Scenario

(DCR) ‐ Reference Case (DCR) ‐ Moderate Case (DCR) ‐ Strict Case
Reliability Assessment

Reliability Assessment

2010 Special Reliability Assessment Scenario Page 37 

The capacity reductions identified in this scenario significantly reduce Planning Reserve 

Margins. The Moderate Case depicts a 4.4 percent reduction in overall capacity resulting in 

sizeable Planning Reserve Margin reductions for a majority of the NERC Regions/subregions. 

The WECC-NWPP and WECC-RMPA subregions show less than a two percentage point 

reduction. When considering the Deliverable Planning Reserve Margin a majority of the 

Regions/subregions fall below the NERC Reference Margin Level in 2018 for both cases (Figure 

21). Significant capacity reductions in ERCOT, MRO, NPCC-New England, and SERC-Delta 

result in Planning Reserve Margin below 10 percent (see Figure 22) when considering the 

Adjusted Potential Planning Reserve Margin. 

When considering Deliverable Capacity Resources, ERCOT, MRO, NPCC-New England, and 

SERC-Delta fall below zero. With Adjusted Potential Capacity Resources, the SERC-Delta 

Planning Reserve Margin is reduced 18.7 percentage points to -0.5 percent because of a 16 

percent reduction in SERC-Delta resources. 

The Strict Case shows that a 7.2 percent reduction in overall capacity results in significant 

Planning Reserve Margin reductions for almost all NERC Regions and subregions, except the 

WECC subregions of NWPP and RMPA. Planning Reserve Margins are significantly reduced as 

a result of capacity resource reductions greater than 10 percent in MRO, NPCC-New England, 

NPCC-New York, SERC-Delta, and SERC-Gateway (see Figure 22). A majority of the NERC 

Regions/subregions are below NERC’s Reference Margin Level under the Strict Case 

assumptions. Most notably, MRO and SERC-Delta Planning Reserve Margin in 2018 are 3.7 and 

-1.7 percent, respectively. Additionally, capacity reductions in ERCOT, NPCC-New England, 

RFC, SERC-Gateway, SERC-Southeastern, SERC-VACAR, and SPP result in Planning Reserve 

Margins below10 percent. 

0

50,000

100,000

150,000

200,000

250,000

MW

Figure 20: 2018 Summer Peak Adjusted Potential Capacity Resources

(APCR) Impacts of Combined EPA Regulation

Scenario

(APCR) ‐ Reference Case (APCR) ‐ Moderate Case (APCR) ‐ Strict Case
Reliability Assessment

Reliability Assessment 

Page 38 2010 Special Reliability Assessment Scenario 

‐10%

‐5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

Reserve Margin (%)

Figure 21: 2018 Summer Peak Deliverable Capaity  Resources

(DCR) Planning Reserve Margin Impacts of Combined EPA Regulation

Scenario

(DCR) Reserve Margin ‐ Reference Case (DCR) Reserve Margin ‐ Moderate Case

(DCR) Reserve Margin ‐ Strict Case NERC Reference Margin Level

‐5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

Reserve Margin (%)

Figure 22: 2018 Summer Peak Adjusted Potential Capacity Resources

(APCR) Planning Reserve Margin Impacts of Combined EPA Regulation

Scenario

(APCR) Reserve Margin ‐ Reference Case (APCR) Reserve Margin ‐ Strict Case

(APCR) Reserve Margin ‐ Strict Case NERC Reference Margin Level
Reliability Assessment

Reliability Assessment

2010 Special Reliability Assessment Scenario Page 39 

ERCOT ‐1.2% ―6.0% ‐7.2 ―‐7.2 ‐1.7% ―5.6% ‐7.7 ―‐7.7

FRCC 24.6% ―24.6% ‐2.3 ―‐2.3 23.5% ―23.5% ‐3.5 ―‐3.5

MRO ‐0.3% ―9.9% ‐4.4 ―‐4.4 ‐6.5% ―3.7% ‐10.6 ―‐10.6

NPCC‐NE 1.2% ―10.0% ‐10.2 ―‐10.2 ‐1.8% ―6.9% ‐13.3 ―‐13.3

NPCC‐NY 14.9% ―16.9% ‐10.2 ―‐10.2 10.7% ―12.7% ‐14.4 ―‐14.4

RFC 8.7% ―14.1% ‐5.1 ―‐5.1 4.7% ―10.0% ‐9.2 ―‐9.2

SERC‐Central 18.0% ―21.3% ‐2.2 ―‐2.2 9.0% ―12.3% ‐11.2 ―‐11.2

SERC‐Delta ‐3.7% ―‐0.5% ‐18.7 ―‐18.7 ‐4.9% ―‐1.7% ‐19.9 ―‐19.9

SERC‐Gateway 14.5% ―18.4% ‐5.2 ―‐5.2 1.7% ―5.6% ‐18.0 ―‐18.0

SERC‐Southeastern 13.9% ―29.6% ‐2.1 ―‐2.1 9.7% ―25.4% ‐6.3 ―‐6.3

SERC‐VACAR 5.0% ―7.6% ‐3.5 ―‐3.5 0.9% ―3.4% ‐7.6 ―‐7.6

SPP 7.4% ―21.4% ‐2.6 ―‐2.6 4.6% ―18.7% ‐5.3 ―‐5.3

WECC‐CA 31.1% ―31.1% ‐8.3 ―‐8.3 28.2% ―28.2% ‐11.2 ―‐11.2

WECC‐AZ‐NM‐SNV 12.6% ―16.6% ‐6.6 ―‐6.6 12.6% ―16.6% ‐6.6 ―‐6.6

WECC‐NWPP 21.5% ―22.6% ‐0.5 ―‐0.5 21.5% ―22.6% ‐0.5 ―‐0.5

WECC‐RMPA 15.7% ―23.8% ‐1.6 ―‐1.6 15.4% ―23.5% ‐1.9 ―‐1.9

   TOTAL 11.0% ―16.5% ‐5.3 ―‐5.3 7.6% ―13.1% ‐8.8 ―‐8.8

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Moderate Case Strict Case

Table 14: Combined Impacts ‐ 2018
Reliability Assessment

Reliability Assessment 

Page 40 2010 Special Reliability Assessment Scenario 

Industry Actions: Tools and Solutions for Mitigating Resource Adequacy Issue 

In addition to the potential for waivers or extensions, a variety of tools and solutions can help 

mitigate significant reliability impacts resulting from resource adequacy concerns created by this 

scenario assessment. They include, but are not limited to: 

The enhancements listed are all options for consideration to offset potential reliability concerns 

identified in this scenario assessment. The industry should closely monitor the EPA regulation 

process as well as continued generator participation/early-retirement announcements. 

•Generation resources may be able to advance their in‐service dates where sufficient lead time is given.

•Accelerated construction may be possible.

•Existing market tools, such as forward capacity markets and reserve sharing mechanisms, can assist in signaling

resource needs. Price signalling will be important in developing new resources.

Advancing In‐service Dates of Future or Conceptual Resources

•Smaller, combustion turbines or mobile generation units can be added to maintain local reliability where

additional capacity is needed.

•Additional distributed generation may also mitigate local reliability issues.

Addition of New Resources Not yet Proposed

•Increased Energy Efficiency may offset future demand growth.

•Increasing available Demand Response resources can provide planning and operating flexibility by reducing

peak demand.

Increased Demand‐Side Management and Conservation

•Planning and constructing retrofits immediately will aid in preventing the potential for construction delays and

overflows, mitigating the risk of additional unit loss.

•Managing retrofit timing on a unit basis will keep capacity supply by region stable..

Early Action to Mitigate Severe Losses

•Regions\subregions that have access to a larger pool of generation may be able to increase the amount of

import capacity from areas with available capacity, transfer capability is sufficient. and deliverability is

confirmed.

•Additional transmission or upgrades may enable additional transactions to provide additional resources across

operating boundaries.

Increase in Transfers

•Other technologies exist, such as trona injection, that will allow companies to comply with EPA air regulations

without installing more scrubbers.

Developing or Exploring Newer Technologies

•Existing gas units may have additional power production potential, which can be expanded during off peak

periods.  This capacity can assist in managing plant outages during the installation of emission control systems.

Use of More Gas‐Fired Generation

•Some coal‐fired generation have the potential to repower their units with combined‐cycle gas turbines and

reducing emmisions.

Repowering of Coal‐Fired Generation
Conclusions and Recommendations

Conclusions and Recommendations 

2010 Special Reliability Assessment Scenario Page 41 

Conclusions & Recommendations

Conclusions

The results of this assessment show a significant impact to reliability should the four potential 

EPA rules be implemented as assumed in this assessment. Impacts to both bulk power system 

planning and operations may cause serious concerns unless prompt industry action is taken. 

Planning Reserve Margins appear to be significantly impacted, deteriorating resource adequacy 

in a majority of the NERC Regions/subregions. Additionally, considerable operational 

challenges will exist in managing, coordinating, and scheduling an industry-wide environmental 

control retrofit effort. 

The remaining three selected EPA rules assessed will mostly affect existing coal-fired capacity, 

ranked in descending order: 

Of the four selected EPA rules, the Section 316(b) Cooling Water Intake Structures rule

individually has the greatest potential impact on Planning Reserve Margins. Implementation of

this rule will apply to 252 GW (1,201 units) of coal, oil steam, and gas steam generating units

across the United States resulting in total “vulnerable” capacity of 37-41 GW by 2018.

Additionally, approximately 60GW of nuclear capacity may be affected. Because of this

scenario, Planning Reserve Margins are decreased as much as 18 percentage points in the

SERC-Delta subregion where the margin falls below zero (available generation will be unable to

serve load), unless additional resources are added. Other Regions/subregions affected include

NPCC-New England and New York.

MACT

• The EPA MACT Rule alone could trigger the retirement of 2-15 GW (Moderate

Case and Strict Case) of existing coal capacity by 2015. The “hard stop” 2015

compliance deadline proposed by the EPA MACT Rule makes retrofit timing a

significant issue and potentially problematic.

CATR

• The CATR also could have significant impacts as soon as 2015, should EPA

require emission limits with no offset trading, resulting in potentially 3-7 GW

of retired and derated capacity and require retrofitting of 28-576 plants with

environmental controls by 2015.

CCR

• The CCR Rule alone is projected to have the least impact, triggering the

retirement of up to 12 coal units (388 MW). While the resulting impacts of the

CCR scenario may not have significant impacts to capacity by itself, the

associated compliance costs of CCR contribute to the Combined EPA

Regulation Scenario.
Conclusions and Recommendations

Conclusions and Recommendations 

Page 42 2010 Special Reliability Assessment Scenario 

Based on the assessment’s assumptions, the greatest risk to Planning Reserve Margins occurs in 

2015 for the Combined EPA Regulation Scenario. The overall total impact could make 46-76 

GW of existing capacity “economically vulnerable” for retirement or derating by 2015. 

Additionally, the scenario cases assessed in this report indicate capacity reductions evident as 

early as 2013, resulting from the retirements of coal-fired plants and derate effects associated 

with plant retrofits. Impacts to Planning Reserve Margins can occur during the next four to eight 

years that could reduce bulk power system reliability, unless additional resources are constructed 

or acquired. It is essential that projected Conceptual supply resources be developed as one 

source of capacity replacement. 

Recommendations 

In the future, a variety of demands on existing infrastructure will be made to 

support the evolution from the current fuel mix, to one that includes 

generation that can meet proposed EPA regulations. The pace and 

aggressiveness of these environmental regulations should be adjusted to 

reflect and consider the overall risk to the bulk power system. EPA, FERC, 

DOE and state utility regulators, both together and separately, should employ 

the array of tools at their disposal to moderate reliability impacts, including, 

among other things, granting required extensions to install emission controls. 

Industry participants should employ available tools to ensure Planning 

Reserve Margins are maintained while forthcoming EPA regulations are 

implemented. For example, regional wholesale competitive markets should 

ensure forward capacity markets are functioning effectively to support the 

development of new replacement capacity where needed. Similarly, 

stakeholders in regulated markets should work to ensure that investments are 

made to retrofit or replace capacity that will be affected by forthcoming EPA 

regulations. 

NERC should further assess the implications of the EPA regulations as 

greater certainty or finalization emerges around industry obligations, 

technologies, timelines, and targets. Strategies should be communicated 

throughout the industry to maintain the reliability of the bulk power system. 

This assessment should include impacts to operating reliability and second 

tier impacts (e.g., deliverability, stability, localized issues, outage 

scheduling, operating procedures, and industry coordination) of forthcoming 

EPA regulations. 

Regulators Industry NERC
Appendix I: Assessment Methods

Appendix I: Assessment Methods 

2010 Special Reliability Assessment Scenario Page 43 

Appendix I: Assessment Methods

Method for This Assessment 

Some studies completed by various organizations have made assumptions that environmental 

regulations will cause all units that meet a certain criteria to retire, for example, all units less than 

230MW that have a capacity factor below 35 percent. This simplified approach does not 

consider other important factors: 

1. Regulated versus deregulated plant (can affect the ability to finance capital improvements 

as well as the cost of capital) 

2. Unit ownership that can affect the cost of capital 

3. Regional reserve margin, i.e., the need to build new capacity to replace retired capacity 

4. Operating cost of the unit versus the operating cost of replacement capacity 

5. Management’s attitude toward fossil fuel generation 

6. State specific implementation 

7. Other local and unit specific issues 

In developing this report, NERC used a contracted model from Energy Ventures Associates 

(EVA), which does not consider Reference Planning Reserve Margins commitments, reliabilitymust-run factors or transmission constraints. Instead, the model applied generic costs factors, 

related to unit size and unit location, to each unit. An economic approach is used to identify 

units to retire when the generic required cost of compliance with the proposed environmental 

regulation exceeds the cost of replacement power. For the purpose of this assessment, 

replacement power was considered to be gas-fired capacity. This assessment was completed in 

constant 2010 U.S. dollars. 

EVA used its delivered natural gas and coal price forecasts. All gas prices were assessed at the 

point of delivery to the electric generation plant. In addition, coal supply costs were adjusted for 

any savings resulting from the ability to burn a different quality of coal, e.g., higher BTU coal. 

One deviation from this general method occurs specifically for the expected outcome of the 

CATR regulation, such that the model considers the surplus credits that have accumulated and 

allows them to be used as an offset in lieu of installing additional environmental controls. 

A brief description of the method follows: 

Retirement criteria: retire if (CC+FC+VC) / (1-DR) > RC, where: 

CC = required compliance cost in $/MWH 

FC = current fixed O&M in $/MWH 

VC = variable O&M including fuel cost in $/MWH 

RC = replacement cost in $/MWH 

DR = derate factor that accounts for the incremental energy loss due to any new 

environmental controls 
Appendix I: Assessmnent Methods

Appendix I: Assessment Methods 

Page 44 2010 Special Reliability Assessment Scenario 

CC = function(incremental capital, incremental fixed O&M cost, incremental 

variable O&M, cost of capital, capacity factor, remaining life without new 

regulation) 

 

(IC * CRF +IFOM) / (8.76*CF) + IVOM, where: 

IC = Incremental capital cost ($/kW) that is plant specific for each 

regulation, i.e., can range from zero if the plant is already in 

compliance to the cost of any additional capital to comply with the 

proposed regulation. This cost is a function of the size of the plant 

and its location. 

 CRF = Capital recovery factor = i * (1 + i)n

 / ((1 + i)n -1) 

 i = Pre-tax cost of capital: 

 Deregulated IOU = 17.5% 

 Regulated IOU = 12.7% 

 Coop = 7% 

 Municipality = 6% 

 n = Remaining life in years, linear interpolation between [CF=0, n=3], 

and [CF=100%, n=30], i.e., if CF=30% then 

n = (1-30%)*3 + 30%*30 = 11.1 years 

 IFOM = Incremental increase in the fixed O&M cost ($/kW-yr) 

 CF = Capacity factor of the plant in 2008 

 IVOM = Incremental increase in the variable O&M cost ($/MWh) 

 

 FC = Current fixed O&M cost in $/kW-yr / (8.76*CF)34

 0 MW 100MW >300 MW 

 Coal = $30.00/kW-yr $21.00/kW-yr $18.00/kW-yr 

 O/G Steam = $22.50/kW-yr $15.75/kW-yr $13.50/kW-yr 

 VC = Variable O&M cost in $/MWH 

 0 MW 100MW >300 MW 

 Coal = $5.00/MWh $4.00/MWh $3.75/MWh 

 O/G Steam = $3.33/MWh $2.67/MWh $2.50/MWh 

 Plus fuel cost

 = Delivered fuel cost ($/MMBtu) * heat rate (1000 Btu/kWh) 

 

 

34 Fixed Brownfield construction costs may be lower than the Greenfield costs assumed in this assessment. 
Appendix I: Assessment Methods

Appendix I: Assessment Methods 

2010 Special Reliability Assessment Scenario Page 45 

RC = Replacement cost is a function of the capacity factor, cost of new 

combined cycle plants, cost of new peaking capacity, and natural gas price 

If CF between 10% and 90%, 

RC = [(1 - (CF - 10%)/80%) * RC10 + (CF- 10%)/80% * RC90] 

If CF <=10%, RC = RC10 

If CF >=90%, RC = RC90 

RC10 = Full capital and operating cost of a new GT unit in the NERC 

Region in $/MWh@ 10% CF with the capital and delivered 

natural gas cost varying by region 

RC90 = Full capital and operating cost of a new CC unit in the NERC 

Region in $/MWh@ 90% CF with the capital and delivered 

natural gas cost varying by region 

A capacity factor of 90 percent was selected for the combined cycle unit as a proxy for the 

practical, maximum, annual operating rate of a typical fossil fuel unit. A capacity factor of 10 

percent was selected for peaking gas plants as the upper limit of what is typically observed under 

actual operating conditions. 

New gas plant cost assumptions illustrated by Table I-1 are: 

Capital Fixed O&M Var O&M Capital Fixed O&M Var O&M Pre‐Tax CRF

2013‐20222018‐20272013‐20232018‐2028$/kW $/kW‐yr $/kWH $/kW $/kW‐yr $/kWH WACC $30.00

ERCOT $6.35 $6.94 $6.26 $6.84 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

FRCC $7.75 $8.36 $6.78 $7.36 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

MRO $6.40 $6.98 $6.30 $6.88 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

NPSS‐NE $7.10 $7.69 $6.99 $7.57 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

NPCC‐NY $6.79 $7.34 $6.68 $7.22 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

RFC $6.68 $7.25 $6.39 $6.94 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

SERC‐Central $6.46 $7.02 $6.29 $6.85 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

SERC‐Delta $6.27 $6.85 $6.18 $6.75 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

SERC‐Gateway $6.34 $6.96 $6.11 $6.73 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

SERC‐Southeastern $6.65 $7.21 $6.48 $7.04 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

SERC‐VACAR $6.86 $7.42 $6.59 $7.14 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

SPP $6.76 $7.32 $6.54 $7.09 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

WECC‐AZ‐NM‐SNV $6.23 $6.80 $6.08 $6.64 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

WECC‐CA $6.46 $7.06 $6.31 $6.89 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

WECC‐NWPP $6.35 $6.94 $6.20 $6.77 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 19.1% 0.192

WECC‐RMPA $5.99 $6.54 $5.84 $6.38 $1,200.00 $19.50 $6.00 $600.00 $7.50 $4.00 12.7% 0.130

Table I‐1: Model Assumptions ‐ New Gas Plant

Average Ten Year Outlook for NG Price New Combined Cycle Plant New Gas Turbine Other Parameters

Combined Cycle

Natural Gas Price in

$/MMBtu

Gas Turbine Natural

Gas Price in

$/MMBtu
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

Page 46 2010 Special Reliability Assessment Scenario 

Appendix II: Potential Environmental Regulations

Section 316(b) Cooling Water Intake Structures 

The typical power plant uses a fuel (coal, gas or nuclear) to heat water into steam, which then 

turns a turbine connected to a generator, which produces electricity. The steam then condenses 

back into water to continue the process again. This condensation requires cooling either by 

water, air, or both. In open-loop cooling, (see Figure II-1), large volumes of water withdrawn 

from a water source (reservoir, lake or river) pass through the heat exchanger to condense steam 

in a single pass before the majority returns to the source. Closed-loop cooling is an alternative to 

open-loop cooling (see Figure II-2). Closed-loop cooling systems circulate a similar total 

volume of water as open-loop systems for a given plant size, but only withdraw a limited amount 

of water to replace evaporative loss and blow-down. There is also “dry” or air-cooling which 

requires little to no water and is cooled directly or indirectly via conductive heat transfer using a 

high flow rate of ambient air blown by fans across the condenser. 

 Figure II-1: Open-Loop Cooling Figure II-2: Closed-Loop Cooling 

 

Section 316(b) of the Clean Water Act regulates cooling water intake structures and requires that 

cooling water intake structures reflect the BTA for minimizing adverse environmental impacts. 

In defining BTA, EPA has, for more than 30 years, considered the cost and benefits of control 

alternatives. EPA originally developed the Section 316(b) rule for existing generation facilities 

using greater than 50 million gallons per day (mgd) in 2004-2007. However, parts of the rule 

were overturned in the U.S. Court of Appeals in 2007 and remanded to EPA for reconsideration. 

EPA is planning to issue a new draft rule for public comment by September 2010. Rule 

implementation is likely to start during 2014 and be fully implemented over a five-year 

compliance period. 

This proposed water rule will likely apply to all existing and new nuclear and fossil steam 

generating units, which contributed over 93 percent of 2008 U.S. generation. Power sources 

such as combustion turbines, hydroelectric facilities, wind turbines, and solar PV panels use no 

cooling water and therefore will not be subject to the proposed rule. Major EPA proposed 

making policy issues directly affecting Planning Reserve Margins are: 
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

2010 Special Reliability Assessment Scenario Page 47 

o implementation period; 

o applicability to existing structures and; and 

o EPA BTA retrofit technology selection. 

In its original 2004 existing facilities rule (overturned by the U.S. Court of Appeals in 2007), 

EPA set significant new national technology-based performance standards. The standards are 

intended to minimize adverse environmental impacts of cooling water intake structures by 

reducing the number of aquatic organisms lost. The performance standards prescribed ranges of 

reductions based on several factors and provided multiple compliance alternatives including the 

use of economic tests to properly implement site-specific regulatory BTA determinations. 

 

However, EPA’s expected draft replacement rule (Phase II) is expected to be substantially 

different due in part to the fact that the performance standards are expected to favor performance 

commensurate with cooling towers. In addition, despite a 2009 Supreme Court ruling that EPA 

has the discretion to use cost-benefit analyses when setting performance standards, EPA has 

signaled concerns associated with the use of cost-benefit analyses. 

For example, if EPA defines BTA for cooling water systems such as recirculating cooling water 

systems with a reach-back provision to cover existing cooling water systems, up to 312 GW of 

existing steam electric power stations that use once-through cooling water systems may require 

additions to retrofit recirculating cooling water systems or acceleration of their retirement. For 

those units opting to retrofit, the stations would increase onsite electricity consumption (1-4 

percent) from station loads because of increased power needs for cooling water pumping. 

In its October 2008 report titled Electricity Reliability Impacts of a Mandatory Cooling Tower 

Rule for Existing Steam Generating Units, the U.S. Department of Energy (DOE) estimated that 

a tougher mandatory recirculating cooling water requirement, now being considered by EPA, 

would accelerate the retirement of 39.6 GW of existing fossil capacity and derate retrofitted 

control units by an additional 9.3 GW.35 The DOE study made a simplifying assumption that 

existing steam units with once through cooling water systems operating at capacity factors less 

than 35 percent would be retired and retrofitted plant output capacity was reduced by four 

percent to represent increased station loads. 

The 1,200 affected units with once through cooling water systems and their cooling water intake 

power suppliers identified rates through the U.S. Energy Information Administration (EIA) Form 

923 and older Form 767 (Steam Electric Plant Operation and Design Report) data filings.36 The 

affected units include 754 coal units, 405 oil/gas steam units and 42 units of nuclear capacity. 

 

 

35 http://www.oe.energy.gov/DocumentsandMedia/Cooling_Tower_Report.pdf 36 http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html 
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

Page 48 2010 Special Reliability Assessment Scenario 

For these units, capital cost estimates to convert from once through cooling water to recirculating 

cooling water systems are derived from three engineering studies and cost surveys: 

o EPRI: Issues Analysis of Retrofitting Once Through Cooled Plants with Closed Cycle 

Cooling (10/07);37

o Maulbetsch Consulting: EPRI Survey of 50 plant estimates (7/2002); and 

o Stone & Webster: Study for Utility Water Assessment Group (7/2002). 

These studies found that capital conversion costs are directly tied to the once-through cooling 

water pumping rate and heavily influenced by site layout and local conditions. Conversion costs 

ranged from $170-440 (2010 dollars) / gallons per minute (gpm) with an average capital 

conversion cost of $240/gpm. The average conversion costs were applied for most locations, 

except for known urban locations having constrained site conditions for which a 25 percent 

higher capital cost estimate of $300/gpm (2010 dollars) was applied. The base case costs applied 

in this reliability assessment are shown in Figure II-3. 

Figure II-3: Base Case Retrofit Cost Curve for Section 316(b)($/kW) 

In addition to the capital conversion costs, the station would lose both capacity and energy due to 

increased power consumption from the cooling water pump. The capacity and energy losses 

estimated in the 2008 DOE study and applied in this assessment are shown in Table II-1. 

 

37 EPRI is expected to issue a new revised report that will include detailed cost information not only for installing cooling towers, 

but also for retrofitting plants on sensitive water bodies, and operations and maintenance costs. 

100

200

300

400

500

600

700

RetrofitCost $/kW

Size of Generation Unit (MW)
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

2010 Special Reliability Assessment Scenario Page 49 

Table II-1: Capacity Derating/Energy Penalties Due to Cooling Tower Conversion 

However, these referenced compliance costs and reliability impacts may be underestimated for 

the following reasons: 

 First, the published studies used to develop the average capital cost estimates are based 

upon surveys done in 2002 and 2007. Such conversions are rare; no historic costing data 

have been published. Since these surveys, environmental project construction costs have 

escalated rapidly. 

 Second, the site-specific conditions and plant layout can have significant impacts on 

conversion costs that are not reflected by applying industrial average estimates. 

Although an adjustment was made for known constrained urban sites, several more sites 

likely exist that may have similar (but unknown) site constraint problems. 

 Finally, given the short potential rule implementation period and the large affected power 

plant population, demand for labor and construction materials for conversions could be in 

high demand and result in real cost escalation. Such capital cost run-ups have occurred in 

pollution control projects. 

The Strict Case provides a 25 percent real price escalation in the average conversion cost to 

$300/gpm at most locations and $400/gpm at known constrained urban site locations to capture 

these potential risks. Alternatively, EPA could consider several policy options that could reduce 

the rule’s impact. These options include (1) narrowing the rule scope to the largest cooling water 

consumers (e.g., EPA’s original rule applied only to water intakes greater than 50 million gallons 

per day), and (2) applying lower cost technology options for existing cooling systems (e.g.

retrofitting fine mesh screens per the 2004 rule). Any narrowing of the regulation scope or cost 

would reduce the rule’s reliability impacts. These alternative EPA regulatory options were not 

modeled for this assessment. 

ERCOT 0.80% 2.50%

FRCC 0.90% 2.50%

MRO 1.40% 3.10%

NPCC 1.30% 3.40%

NYPP 1.20% 3.20%

RFC 1.60% 3.40%

Entergy 0.90% 2.60%

Gateway 1.20% 3.10%

Southeastern 0.80% 2.40%

TVA 0.90% 2.60%

VACAR 1.00% 2.80%

SPP 1.00% 2.80%

AZ‐NM‐SNV 1.40% 2.70%

CA 0.90% 2.50%

NWPP 1.40% 3.00%

RMPA 0.00% 2.50%

Total 1.20% 2.90%

NERC Regions/

Subregions Average Energy Loss % Capacity Derating Penalty (%)

Source:  DOE Electric Reliability Impacts of a Mandatory Cooling Tower

Rule for Existing Steam Generating Units(10/2008)
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

Page 50 2010 Special Reliability Assessment Scenario 

National Emissions Standards for Hazardous Pollutants (NESHAP) or Maximum 

Achievable Control Technology (MACT) 

Under Title I of the 1990 Clean Air Act, EPA is obligated to develop an emission control 

program for listed air toxics for sources that emit at or above prescribed threshold values, 

including mercury. The Clean Air Act defines MACT for existing sources as “the average 

emission limitation achieved by the best performing 12 percent of the existing sources.” EPA is 

obligated under a consent decree to propose a MACT rule by March 16, 2011 and to finalize the 

rule by November 16, 2011. The Clean Air Act mandates a three-year compliance timeframe: 

2014 or 2015. 

The potential EPA MACT rule will apply to all 1,732 existing and future coal and oil fired 

capacity (415.2 GW of existing plus another 26 GW of new planned coal units). The only 

flexibility for compliance is for EPA to grant a one-year extension, granted on a case-by-case 

basis, and a Presidential exemption of no more than 2 years based on availability of technology 

and national security interests. 

This assessment uses environmental control costing curves to develop unit-specific compliance 

cost estimates, with the increased unit production costs of new pollution controls compared to 

unit production costs of replacement power. EPA is expected to adopt different MACT emission 

rate limitations, which implies that new investments required will vary by coal type. 

The Moderate Case assumes that MACT is not fully implemented until 2018, as waivers are 

provided, largely for reliability reasons, to units that have committed and scheduled 

environmental upgrade projects but which may not be completed by the 2015 deadline. Further, 

investments are made when equipment is not present or planned, depending on the coal type, as 

shown in Table II-2. If wet or dry FGD are not present, then wet FGD is added for all coal 

types. SCR control retrofits are added for bituminous coal only. In addition, fabric filter 

systems with halide-treated activated carbon injection (HACI) systems are added for all coal 

types, if not already present. Oil stations (109.7 GW) are assumed to meet their air toxic limits 

through tighter oil specifications at the refinery. 

By contrast, Strict Case assumes no waivers are granted and all upgrades must be complete by 

January 1, 2015, or units would retire. Investment costs are also projected to increase by 25 

percent in Strict Case as shown by Table II-3. 

Bituminous Sub‐bituminous Lignite

Wet FGD

Dry FGD

SCR Add

Activated Carbon Injection Add Add

Baghouse (Fabric Filter) Add Add

Table II‐2: Moderate Case Assumptions for MACT

Moderate Case

If no wet or dry FGD,

add wet FGD

If no wet or dry FGD,

add wet FGD

If no wet or dry FGD,

add wet FGD

Air Toxics (includes CAMR and Acid Gases)
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

2010 Special Reliability Assessment Scenario Page 51 

Representative base case costs for bituminous coal are shown in Figure II-4. 

Figure II-4: Bituminous Coal Base Case Cost Curves for MACT ($/kW) 

Bituminous Sub‐bituminous Lignite

Wet FGD 25% 25% 25%

Dry FGD 25% 25% 25%

SCR 25%

Activated Carbon Injection +25% Add 25% 25%

Baghouse (Fabric Filter) +25% Add 25% 25%

Table II‐3: Strict Case Assumptions for MACT

Air Toxics (includes CAMR and Acid Gases)

500

1000

1500

2000

2500

3000

3500

4000

Base Case Cost to Retrofit $/k

W

Size of Generation Unit (MW)
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

Page 52 2010 Special Reliability Assessment Scenario 

Clean Air Transport Rule (CATR) 

EPA developed its Clean Air Interstate Rule (CAIR) program to address the long-range emission 

transport contribution to fine particulate non-attainment and to take the first compliance step by 

reducing contributions from major fossil combustion stationary sources. Its original proposed 

program created a new annual NOx cap-and-trade program and modified the existing Title IV 

SO2 cap-and-trade program for 28 states for which upwind out-of-state contributions to nonattainment areas were considered significant. In 2008, the U.S. Court of Appeals overturned the 

EPA program due to concerns that NAAQS would not be met if sources complied through an 

unlimited amount of emission allowance purchases. 

In July 2010, EPA proposed a draft CATR to control long-range transport of power plant 

SO2/NOx emissions that significantly contributed to non-attainment of fine particulate and ozone 

ambient air quality standards in downwind states—CATR will replace CAIR.38 EPA anticipates 

issuing the final rule by March 2011. The draft program would apply only to fossil fuel electric 

generating units greater than 25 MW located in a designated state as shown in Figure II-5 . 

Figure II-5: Clean Air Transport Rule Designated States 

 

38 EPA CATR Homepage: http://www.gpo.gov/fdsys/pkg/FR-2010-08-02/pdf/2010-17007.pdf#page=1 and proposed rule 

http://www.gpo.gov/fdsys/pkg/FR-2010-08-02/pdf/2010-17007.pdf#page=1 
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

2010 Special Reliability Assessment Scenario Page 53 

The potential EPA rule will regulate SO2 and NOx emissions under three new cap-and-trade 

programs (SO2, annual NOx and seasonal NOx) starting January 1, 2012. EPA will set a state 

emissions budget cap for each pollutant, issue new allowances, and propose to significantly limit 

interstate allowance trading and banking after 2013. Previously banked surplus SO2 and NOx

allowance credits and allocations created under the Acid Rain and CAIR programs cannot be 

used for compliance under the new program. For SO2, affected states are organized into Group 1 

or Group 2, as shown in Figure II-6. 

Figure II-6: Clean Air Transport Rule Designated States

CATR applies to fossil power plant sources located within the 31 states and District of 

Colombia. The impact on the electric grid will vary depending on which of three EPA proposals 

becomes the final rule39: 

 The EPA preferred option; 

 Alternative 1 - the no interstate trading option; or 

 Alternative 2 - the strict emission rate option. 

EPA proposal is soliciting comments on its preferred option with limited interstate trading and 

intrastate trading, as well as the two alternative options. Further complicating compliance 

planning by electric generators, the agency recognizes that the proposed state emission budgets 

 

39 Described in the Introduction section of this report 
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

Page 54 2010 Special Reliability Assessment Scenario 

caps are likely to change again in the near term when new fine particulate and ozone air quality 

standards are adopted, potentially later in 2010. These NAAQS will trigger new air quality 

modeling to determine the allowable pollutant loadings and allocations between contributing 

sources. Upon completion of this modeling, EPA will propose new state emission budget caps. 

The rule also gives the power industry a greater planning challenge than CAIR, since compliance 

must be on an aggregate state-by-state basis. In lieu of the current national emissions cap with 

unrestricted trading and banking, the new proposal also makes greater coordination essential 

between utilities within each state in order to optimize emission reductions. However, concerns 

over competition may limit coordination and result in less optimal compliance plans. 

The new program is likely to require some electric generation units to retrofit additional FGD 

and selective catalytic reduction (SCR) controls by 2014, or retire. Strict emission limits that can 

only be met with post combustion FGD and SCR controls will directly affect 163 GW of coalfired capacity that currently does not have FGD, or the 180 GW without post combustion NOx

controls. EPA’s preferred option is summarized in Table II-4 below. 

Table II-4: High Level Summary of Proposed CATR Regulation – EPA Preferred Option 

SO2 Cap & Trade Program

   Group 1 Group 2

   2012 Deadline 2014 Deadline 2012 Deadline 2014 Deadline

Number of          

States Affected 15 15 12 & DC 12 & DC

Emissions Cap

(TPY)* 3,117,288 1,723,412 776,582 776,582

Emissions Credit

Trading

EPA issues new

allowances and

surplus acid rain

allowances

become

worthless.  

Trading allowed

within Group 1.

Very strict annual

state emission

limitations on

interstate trading

and use of

carryover

allowances.

EPA issues new

allowances and

surplus acid rain

allowances

become

worthless.  

Trading allowed

within Group 2.

Very strict annual

state emission

limitations on

interstate trading

and use of

carryover

allowances.

*EPA resets each state’s budget at onset. State budget caps are likely to be revised once fine particulate 

NAAQS is implemented and modeling is completed. 

Annual NOx Cap & Trade Program

   27 States and District of Colombia

   2012 Deadline 2014 Deadline

Number of            

States Affected 28 28

Emissions Cap (TPY) 1,317,312 1,317,312

Emissions Credit

Trading

EPA issues new allowances and surplus

CAIR ones become worthless.  Trading

allowed between all states.

Very strict annual state emission

limitations on interstate trading

and use of carryover allowances.
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

2010 Special Reliability Assessment Scenario Page 55 

The costs for retrofitting post combustion controls are shown in Figure II-7. These capital costs 

are from utility project engineering estimates and recent projects. They are significantly higher 

than EPA study estimates that rely upon much older cost data and exclude owner and financing 

costs. 

Figure II-7: Moderate Case Average Post Combustion Control Retrofit Costs for CATR 

($/kW) 

This assessment examines the impacts of the EPA’s preferred option – limited cap-and-trade 

program -- as the Moderate Case. This option increases pressure to reduce emissions beyond 

current plans, particularly for sources in the six states of Indiana, Kentucky, Massachusetts, 

Missouri, Ohio and Pennsylvania. These six states must reduce their aggregated in-state SO2

emissions by more than 250,000 tons per year by 2014. It may prove difficult to engineer, 

finance, permit and construct sufficient environmental controls in less than the three years 

required under the draft program. This assessment examines the economic decision at current 

control prices. The Strict Case assumes that EPA elects to adopt their future emission rate 

alternative that has no provisions for any trading between units and will force more coal units to 

have post combustion SO2 and NOx controls in the selected states. The assessment evaluates the 

available state credits to meet the state’s limits and selects generating units for retirement in 2012 

and 2014 that will be required to meet the emissions cap. 

$0.00

$200.00

$400.00

$600.00

$800.00

$1,000.00

$1,200.00

$1,400.00

$1,600.00

$1,800.00

0 200 400 600 800 1000 1200 1400 1600

Base Case Cost to Retrofit $/kW

Size of Generation Unit

Wet FGD Dry FGD SCR
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

Page 56 2010 Special Reliability Assessment Scenario 

Coal Combustion Residuals (CCR) 

Concerns raised by the December 2008 Kingston ash spill and its widespread environmental 

impact triggered EPA consideration of changing regulating coal-ash and waste byproduct (e.g., 

scrubber sludge) disposal from its current special waste designation to Subtitle C Hazardous 

Waste under the Resource Conservation and Recovery Act. EPA developed a draft rule in 

September 2009 that was reviewed by the Office of Management and Budget and was issued in 

May 2010. A final rule is expected in 2011, with implementation expected to start in 2013–2015 

and full compliance by 2018. 

 

These EPA rules will regulate 136 million tons per year (tpy) of coal-ash and solid byproducts 

currently produced by the coal-fired stations. Policy issues that will impact decision making the 

most include: 

 hazardous waste designation of coal-ash, 

 impoundment design standards, 

 groundwater protection standards, and 

 rule implementation period. 

EPA has proposed conversion of all coal-ash handling systems from utility-boilers to dry based 

systems, with two options proposed for disposal of all ash and coal byproducts in a landfill 

meeting either Subtitle C or D, which entails different types of waste disposal standards, and to 

close/cap existing ash ponds. Such a ruling requires the 359 coal units (128.5 GW) to convert 

their wet ash handling systems to dry based systems, incur greater ash disposal costs for the 136 

million tons of ash disposal each year, and close and cap the existing 500 ash/sludge ponds in 

operation. 

In addition, a hazardous waste designation under Subtitle C could eliminate the market for 20 

million tons of ash that is currently resold into the market, although the EPA is considering a 

“special waste” designation, which would allow “beneficial” reuse of the substance to continue. 

Hazardous waste designation without exceptions would vastly expand the existing hazardous 

waste disposal market from its current size of 2 million tpy. 

Prior public studies examining the ash disposal issue on power plant operation are limited. A 

2009 EOP Group Study titled Cost Estimates for the Mandatory Closure of Surface 

Impoundments Used for the Management of Coal Combustion Byproducts at Coal fired Utilities

was reviewed.40,

41 This 2009 study concluded that EPA’s draft rule could directly affect 

operations at 397 coal generating units (175 GW). The EOP Group study estimated bottom ash 

conversion costs of $30 million per unit, and this assumption is used in the Moderate Case of this 

assessment. In addition, at some stations, the ash ponds also dispose of fly ash (15 million tons 

per year or tpy) that would require an additional $3 billion investment to convert to dry handling 

systems. Outside of conversion costs, stations would have to build alternative wastewater 

treatment facilities at 155 facilities ranging, per facility, from $80 million without a flue gas 

desulfurization system (FGD) to $120 million with FGD per facility to provide storm water 

and/or FGD scrubber sludge treatment currently handled by the ash ponds. Ash pond closure 

 

40 http://www.whitehouse.gov//sites/default/files/omb/assets/oira_2050/2050_102809-2.pdf 41 A revised EOP report is currently under review, reference report upon completion. Preliminary values indicate a 20 percent 

increase in cost. 
Appendix II: Potential Environmental Regulations

Appendix II: Potential Environmental Regulations 

2010 Special Reliability Assessment Scenario Page 57 

costs were estimated to be $30 million per pond. The EOP Group study concluded, “Units with 

below 230 MW of generating capacity have the greatest potential risk of ceasing operations if 

required to undertake mandatory closure of CCB surface impoundments.” These “economically 

vulnerable” coal units totaled 35 GW of existing capacity and represented 18 percent of 2005 

U.S. coal generation. 

However, the 2009 EOP Study contained some deficiencies that could underestimate compliance 

costs as follows: 

 First, the study excluded any land acquisition costs for landfill or expanded wastewater 

treatment facilities. 

 Second, the study excluded the increased disposal cost if ash was designated as hazardous 

waste. 

 Third, it excluded costs for existing ash pond closures. These remediation costs will vary 

significantly based upon the extent of any groundwater contamination, site geology and 

aquifer use. However, any remediation might be considered as a sunk cost since it would 

be incurred independently of the future operating decision. If these costs were indeed 

considered sunk, they should not be incorporated into unit retirement decisions. 

A total of 359 coal-fired units (128.5 GW) of coal-fired capacity reported using wet pond based 

systems for their ash and/or byproduct handling systems in their EIA Form 767 and 923 filings. 

For these units, the 2009 EOP study cost estimates for bottom ash conversion and wastewater 

treatment upgrades are applied on a unit basis. The additional EOP ash waste disposal costs of 

$15 per ton (2010 dollars) were added for handling in a regulated non-hazardous onsite landfill 

to the unit operating costs in the Moderate Case of this study. The pond closure and remediation 

costs are assumed to become sunk costs that would be incurred independently of the future 

power plant operations. Therefore, only incremental costs associated with ongoing operations 

are accounted for in the decision to invest or retire the unit. When these incremental power 

production costs exceeded new replacement capacity costs, the units became potential retirement 

candidates. 

However, as outlined above, the EOP Group study may have underestimated compliance costs 

and thereby underestimated potential grid reliability impacts. Based on discussions with various 

subject-matter experts, the capital compliance cost uncertainty is likely to be plus/minus 25 

percent. To account for potentially higher costs under stricter Subtitle C guidelines, landfill costs 

are assumed to be much higher at $37.50 per ton (2010 dollars) in the Strict Case, which is also 

similar to the EPA study’s estimated disposal costs. In lieu of conducting site-specific 

assessments, sensitivity comparisons are completed across a wide range of ash disposal costs 

from $37.50 to $1,250 per ton. 
Appendix III: Capacity Assessed by NERC Subregion

Appendix III: Capacity Assessed by NERC Subregion 

Page 58 2010 Special Reliability Assessment Scenario 

Appendix III: Capacity Assessed by NERC Subregion

No. Units

Coal Units

ERCOT 31 17,685

FRCC 22 9,444

MRO 157 25,231

NPCC‐NE 13 2,634

NPCC‐NY 21 2,812

RFC 309 97,302

SERC‐Central 99 24,487

SERC‐Delta 21 9,317

SERC‐Gateway 51 13,998

SERC‐Southeastern 65 24,223

SERC‐VACAR 109 24,147

SPP 62 19,111

WECC‐CA 10 2,182

WECC‐AZ‐NM‐SNV 29 11,911

WECC‐NWPP 39 12,097

WECC‐RMPA 45 6,419

   TOTAL 1080 302,998

O/G ‐ ST Units

ERCOT 55 14,418

FRCC 23 6,841

MRO 25 691

NPCC‐NE 23 6,040

NPCC‐NY 34 11,181

RFC 43 8,942

SERC‐Central 0 0

SERC‐Delta 88 16,519

SERC‐Gateway 13 561

SERC‐Southeastern 8 506

SERC‐VACAR 6 2,012

SPP 92 10,955

WECC‐CA 56 15,439

WECC‐AZ‐NM‐SNV 28 2,142

WECC‐NWPP 8 705

WECC‐RMPA 7 175

   TOTAL 509 97,124

Capcity

(MW)

Figure III-1: Base Fossil-Fired Generation Capacity Assessed by NERC Region/Subregion 
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 59 

Appendix IV: Data Tables

For the resource adequacy assessment, NERC chose a range of resource categories to evaluate 

Planning Reserve Margins for this scenario. The range includes Deliverable Capacity Resources 

on the low-end and Adjusted Potential Capacity Resources on the high-end. Refer to the Terms 

Used in this Report section for detailed definitions regarding supply/resource categories.

Net Internal

Demand ‐ 

Reference

Case (MW)

Deliverable

Capacity Resources ‐

Reference Case

(MW)

Adjusted

Potential

Capacity

Resources ‐ 

Reference Case

(MW)

Deliverable

Capacity

Resources

Reserve Margin ‐ 

Reference Case

Adjusted

Potential

Capacity

Resources

Reserve Margin ‐ 

Reference Case

ERCOT 62,376 72,204 72,204 15.8% 15.8%

FRCC 42,531 51,870 51,870 22.0% 22.0%

MRO 41,306 50,308 51,098 21.8% 23.7%

NPCC‐NE 27,875 33,703 33,921 20.9% 21.7%

NPCC‐NY 33,233 42,968 43,658 29.3% 31.4%

RFC 169,900 215,800 217,904 27.0% 28.3%

SERC‐Central 40,874 50,828 51,196 24.4% 25.3%

SERC‐Delta 27,178 38,466 38,602 41.5% 42.0%

SERC‐Gateway 18,947 20,306 21,117 7.2% 11.5%

SERC‐Southeastern 47,789 58,745 67,788 22.9% 41.8%

SERC‐VACAR 62,083 75,663 77,426 21.9% 24.7%

SPP 43,696 50,127 56,648 14.7% 29.6%

WECC‐CA 58,421 71,334 71,334 22.1% 22.1%

WECC‐AZ‐NM‐SNV 29,843 35,076 35,076 17.5% 17.5%

WECC‐NWPP 41,391 56,705 56,710 37.0% 37.0%

WECC‐RMPA 10,939 13,517 13,517 23.6% 23.6%

   TOTAL 758,382 937,619 960,070 23.1% 26.1%

Table IV‐1: 2009 Long‐Term Reliability Assessment Reference Case ‐ 2009 Figures
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 60 2010 Special Reliability Assessment Scenario 

Net Internal

Demand ‐ 

Reference

Case (MW)

Deliverable

Resources ‐ 

Reference Case

(MW)

Adjusted

Potential

Resources ‐ 

Reference Case

(MW)

Deliverable

Resources

Reserve Margin ‐ 

Reference Case

Adjusted

Potential

Capacity

Resources

Reserve Margin ‐ 

Reference Case

ERCOT 68,284 79,521 84,617 16.50% 23.90%

FRCC 44,697 57,464 57,464 28.60% 28.60%

MRO 44,482 50,218 54,299 12.90% 22.10%

NPCC‐NE 29,365 34,827 37,122 18.60% 26.40%

NPCC‐NY 33,861 43,381 43,957 28.10% 29.80%

RFC 183,900 219,600 228,502 19.40% 24.30%

SERC‐Central 42,437 52,473 53,990 23.60% 27.20%

SERC‐Delta 29,406 37,499 38,505 27.50% 30.90%

SERC‐Gateway 20,032 24,834 25,645 24.00% 28.00%

SERC‐Southeastern 53,099 59,987 68,949 13.00% 29.80%

SERC‐VACAR 66,926 78,611 80,494 17.50% 20.30%

SPP 46,153 53,477 60,149 15.90% 30.30%

WECC‐CA 60,073 89,293 89,293 48.60% 48.60%

WECC‐AZ‐NM‐SNV 32,060 39,157 39,663 22.10% 23.70%

WECC‐NWPP 44,076 57,240 57,353 29.90% 30.10%

WECC‐RMPA 11,616 14,483 15,131 24.70% 30.30%

   TOTAL 810,467 992,063 1,035,134 22.40% 27.70%

Table IV‐2: 2009 Long‐Term Reliability Assessment Reference Case ‐ 2013 Projections

Net Internal

Demand ‐ 

Reference

Case (MW)

Deliverable

Resources ‐ 

Reference Case

(MW)

Adjusted

Potential

Capacity

Resources ‐ 

Reference Case

(MW)

Deliverable

Resources

Reserve Margin ‐ 

Reference Case

Adjusted

Potential

Capacity

Resources

Reserve Margin ‐ 

Reference Case

ERCOT 69,057 79,523 84,967 15.20% 23.00%

FRCC 46,579 58,235 58,235 25.00% 25.00%

MRO 45,675 49,952 54,312 9.40% 18.90%

NPCC‐NE 30,115 34,777 37,487 15.50% 24.50%

NPCC‐NY 34,264 43,281 43,977 26.30% 28.30%

RFC 187,700 219,800 229,546 17.10% 22.30%

SERC‐Central 43,432 52,882 54,399 21.80% 25.30%

SERC‐Delta 30,369 36,582 37,588 20.50% 23.80%

SERC‐Gateway 20,300 24,916 25,727 22.70% 26.70%

SERC‐Southeastern 55,225 62,050 71,237 12.40% 29.00%

SERC‐VACAR 69,198 77,941 80,046 12.60% 15.70%

SPP 46,554 53,480 60,210 14.90% 29.30%

WECC‐CA 61,564 92,405 92,405 50.10% 50.10%

WECC‐AZ‐NM‐SNV 33,836 40,519 41,622 19.80% 23.00%

WECC‐NWPP 45,306 57,546 58,061 27.00% 28.20%

WECC‐RMPA 12,097 14,110 15,116 16.60% 25.00%

   TOTAL 831,271 997,997 1,044,936 20.10% 25.70%

Table IV‐3: 2009 Long‐Term Reliability Assessment Reference Case ‐ 2015 Projections
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 61 

Net Internal

Demand ‐ 

Reference

Case (MW)

Deliverable

Resources ‐ 

Reference Case

(MW)

Adjusted

Potential

Capacity

Resources ‐ 

Reference Case

(MW)

Deliverable

Resources

Reserve Margin ‐ 

Reference Case

Adjusted

Potential

Capacity

Resources

Reserve Margin ‐ 

Reference Case

ERCOT 75,019 79,525 84,969 6.00% 13.30%

FRCC 49,885 63,336 63,336 27.00% 27.00%

MRO 47,534 49,469 54,317 4.10% 14.30%

NPCC‐NE 30,960 34,499 37,209 11.40% 20.20%

NPCC‐NY 35,231 44,081 44,777 25.10% 27.10%

RFC 193,100 219,800 230,054 13.80% 19.10%

SERC‐Central 45,288 54,410 55,927 20.10% 23.50%

SERC‐Delta 31,438 36,161 37,167 15.00% 18.20%

SERC‐Gateway 20,817 24,916 25,727 19.70% 23.60%

SERC‐Southeastern 58,505 67,860 77,047 16.00% 31.70%

SERC‐VACAR 72,814 79,025 80,880 8.50% 11.10%

SPP 48,500 53,319 60,141 9.90% 24.00%

WECC‐CA 63,916 89,054 89,054 39.30% 39.30%

WECC‐AZ‐NM‐SNV 36,382 43,381 44,819 19.20% 23.20%

WECC‐NWPP 47,292 57,687 58,200 22.00% 23.10%

WECC‐RMPA 12,874 15,102 16,146 17.30% 25.40%

   TOTAL 869,554 1,011,624 1,059,770 16.30% 21.90%

Table IV‐4: 2009 Long‐Term Reliability Assessment Reference Case ‐ 2018 Projections
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 62 2010 Special Reliability Assessment Scenario 

ERCOT 0 0 0 0 0 8 10 7 3 28

FRCC 0 1 0 0 1 5 1 2 0 8

MRO 57 0 0 0 57 24 1 0 0 25

NPCC‐NE 2 0 1 0 3 5 4 0 4 13

NPCC‐NY 6 1 0 0 7 5 3 0 3 11

RFC 36 10 1 0 47 19 8 3 3 33

SERC‐Central 6 1 0 0 7 0 0 0 0 0

SERC‐Delta 3 0 0 0 3 31 5 4 6 46

SERC‐Gateway 5 1 0 0 6 12 0 0 0 12

SERC‐Southeastern 5 2 0 0 7 4 1 0 0 5

SERC‐VACAR 28 4 0 0 32 3 0 1 0 4

SPP‐N 4 0 0 0 4 15 0 0 0 15

SPP‐S 1 0 0 0 1 17 1 0 0 18

WECC‐AZ‐NM‐SNV 0 0 0 2 2 9 3 0 0 12

WECC‐CA 0 0 0 0 0 2 7 6 3 18

WECC‐NWPP 4 0 0 0 4 0 0 0 0 0

WECC‐RMPA 6 0 0 0 6 5 0 0 0 5

Total 163 20 2 2 187 164 44 23 22 253

ERCOT 0 0 0 0 0 8 10 8 3 29

FRCC 0 1 0 0 1 5 1 2 1 9

MRO 88 7 1 0 96 24 1 0 0 25

NPCC‐NE 4 3 1 0 8 5 4 0 5 14

NPCC‐NY 10 3 1 0 14 5 3 0 4 12

RFC 56 44 4 1 105 19 8 3 3 33

SERC‐Central 6 32 0 0 38 0 0 0 0 0

SERC‐Delta 4 2 0 0 6 31 5 4 6 46

SERC‐Gateway 13 9 3 0 25 12 0 0 0 12

SERC‐Southeastern 5 10 5 0 20 4 1 0 0 5

SERC‐VACAR 34 23 0 0 57 3 0 1 0 4

SPP‐N 19 0 0 0 19 16 0 0 0 16

SPP‐S 1 2 0 0 3 17 1 0 0 18

WECC‐AZ‐NM‐SNV 0 0 0 2 2 9 3 0 0 12

WECC‐CA 3 0 0 0 3 2 7 9 5 23

WECC‐NWPP 4 0 0 0 4 0 0 0 0 0

WECC‐RMPA 9 0 0 0 9 5 0 0 0 5

Total 256 136 15 3 410 165 44 27 27 263

Strict Case

>400

(MW)

Gas/Oil Steam

Table IV‐5: Combined Impacts ‐ Number of Units Retired by Region and Size ‐ 2018

Moderate Case

Coal

0‐99

(MW)

100‐

199

200‐

399

200‐

399

>400

(MW) Total

0‐99

(MW)

100‐

199 Total
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 63 

Table IV‐6: Combined Impacts ‐ 2018

   Moderate Case Strict Case

   Derated

(MW)

Retired

(MW) Total

Derated

(MW)

Retired

   (MW) Total

Coal Units                  

ERCOT 231 0 231 351 0 351

FRCC 124 121 245 187 121 308

MRO 534 862 1,397 612 3,733 4,345

NPCC‐NE 92 466 558 79 1,034 1,113

NPCC‐NY 92 302 394 68 1,214 1,282

RFC 1,965 3,285 5,250 2,266 10,888 13,154

SERC‐Central 541 445 986 509 4,546 5,055

SERC‐Delta 151 46 197 265 308 573

SERC‐Gateway 390 289 679 442 2,894 3,336

SERC‐Southeastern 423 452 875 537 2,803 3,340

SERC‐VACAR 453 1,658 2,111 492 4,634 5,126

SPP 252 91 342 411 1,207 1,618

WECC‐CA 12 0 12 10 81 90

WECC‐AZ‐NM‐SNV 49 1,580 1,629 49 1,580 1,629

WECC‐NWPP 109 129 239 109 129 239

WECC‐RMPA 27 100 126 25 141 167

   TOTAL 5,445 9,825 15,270 6,414 35,312 41,726

        

O/G‐ST Units      

ERCOT 135 5,055 5,190 129 5,295 5,424

FRCC 65 862 927 52 1,367 1,419

MRO 0 691 691 0 691 691

NPCC‐NE 104 2,504 2,608 90 2,904 2,995

NPCC‐NY 261 2,937 3,198 241 3,544 3,786

RFC 0 4,563 4,563 0 4,563 4,563

SERC‐Central 0 0 0 0 0 0

SERC‐Delta 200 5,495 5,695 200 5,495 5,695

SERC‐Gateway 0 405 405 0 405 405

SERC‐Southeastern 0 329 329 0 329 329

SERC‐VACAR 23 408 431 23 408 431

SPP 19 881 901 17 942 960

WECC‐CA 218 5,041 5,259 172 6,867 7,039

WECC‐AZ‐NM‐SNV 5 773 778 5 773 778

WECC‐NWPP 3 0 3 3 0 3

WECC‐RMPA 0 84 84 0 84 84

   TOTAL 1,033 30,027 31,061 934 33,667 34,601
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 64 2010 Special Reliability Assessment Scenario 

ERCOT 16.5% ―23.9% 0.0 ―0.0 16.5% ―23.9% 0.0 ―0.0

FRCC 28.6% ―28.6% 0.0 ―0.0 28.6% ―28.6% 0.0 ―0.0

MRO 12.9% ―22.1% 0.0 ―0.0 12.9% ―22.1% 0.0 ―0.0

NPCC‐NE 18.6% ―26.4% 0.0 ―0.0 18.6% ―26.4% 0.0 ―0.0

NPCC‐NY 28.1% ―29.8% 0.0 ―0.0 28.1% ―29.8% 0.0 ―0.0

RFC 19.4% ―24.3% 0.0 ―0.0 19.4% ―24.3% 0.0 ―0.0

SERC‐Central 23.6% ―27.2% 0.0 ―0.0 23.6% ―27.2% 0.0 ―0.0

SERC‐Delta 27.5% ―30.9% 0.0 ―0.0 27.5% ―30.9% 0.0 ―0.0

SERC‐Gateway 24.0% ―28.0% 0.0 ―0.0 24.0% ―28.0% 0.0 ―0.0

SERC‐Southeastern 13.0% ―29.8% 0.0 ―0.0 13.0% ―29.8% 0.0 ―0.0

SERC‐VACAR 17.5% ―20.3% 0.0 ―0.0 17.5% ―20.3% 0.0 ―0.0

SPP 15.9% ―30.3% 0.0 ―0.0 15.9% ―30.3% 0.0 ―0.0

WECC‐CA 48.6% ―48.6% 0.0 ―0.0 48.6% ―48.6% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 22.1% ―23.7% 0.0 ―0.0 22.1% ―23.7% 0.0 ―0.0

WECC‐NWPP 29.9% ―30.1% 0.0 ―0.0 29.9% ―30.1% 0.0 ―0.0

WECC‐RMPA 24.7% ―30.3% 0.0 ―0.0 24.7% ―30.3% 0.0 ―0.0

   TOTAL 22.4% ―27.7% 0.0 ―0.0 22.4% ―27.7% 0.0 ―0.0

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐7: 316(b) Impacts ‐ 2013

Moderate Case Strict Case

ERCOT 16.5% ―23.9% 0.0 ―0.0 16.5% ―23.9% 0.0 ―0.0

FRCC 28.6% ―28.6% 0.0 ―0.0 28.6% ―28.6% 0.0 ―0.0

MRO 12.9% ―22.1% 0.0 ―0.0 12.9% ―22.1% 0.0 ―0.0

NPCC‐NE 18.6% ―26.4% 0.0 ―0.0 18.6% ―26.4% 0.0 ―0.0

NPCC‐NY 28.1% ―29.8% 0.0 ―0.0 28.1% ―29.8% 0.0 ―0.0

RFC 19.4% ―24.3% 0.0 ―0.0 19.4% ―24.3% 0.0 ―0.0

SERC‐Central 23.6% ―27.2% 0.0 ―0.0 23.6% ―27.2% 0.0 ―0.0

SERC‐Delta 27.5% ―30.9% 0.0 ―0.0 27.5% ―30.9% 0.0 ―0.0

SERC‐Gateway 24.0% ―28.0% 0.0 ―0.0 24.0% ―28.0% 0.0 ―0.0

SERC‐Southeastern 13.0% ―29.8% 0.0 ―0.0 13.0% ―29.8% 0.0 ―0.0

SERC‐VACAR 17.5% ―20.3% 0.0 ―0.0 17.5% ―20.3% 0.0 ―0.0

SPP 15.9% ―30.3% 0.0 ―0.0 15.9% ―30.3% 0.0 ―0.0

WECC‐CA 48.6% ―48.6% 0.0 ―0.0 48.6% ―48.6% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 22.1% ―23.7% 0.0 ―0.0 22.1% ―23.7% 0.0 ―0.0

WECC‐NWPP 29.9% ―30.1% 0.0 ―0.0 29.9% ―30.1% 0.0 ―0.0

WECC‐RMPA 24.7% ―30.3% 0.0 ―0.0 24.7% ―30.3% 0.0 ―0.0

   TOTAL 22.4% ―27.7% 0.0 ―0.0 22.4% ―27.7% 0.0 ―0.0

Table IV‐8: MACT Impacts ‐ 2013

Moderate Case Strict Case

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 65 

ERCOT 16.5% ―23.9% 0.0 ―0.0 16.4% ―23.8% ‐0.1 ―‐0.1

FRCC 28.6% ―28.6% 0.0 ―0.0 28.6% ―28.6% 0.0 ―0.0

MRO 12.9% ―22.1% 0.0 ―0.0 12.2% ―21.4% ‐0.7 ―‐0.7

NPCC‐NE 18.0% ―26.4% ‐0.6 ―0.0 18.6% ―26.4% 0.0 ―0.0

NPCC‐NY 28.1% ―29.8% 0.0 ―0.0 28.1% ―29.8% 0.0 ―0.0

RFC 19.2% ―24.3% ‐0.2 ―0.0 18.9% ―23.7% ‐0.5 ―‐0.5

SERC‐Central 23.6% ―27.2% 0.0 ―0.0 23.3% ―26.9% ‐0.4 ―‐0.4

SERC‐Delta 27.5% ―30.9% 0.0 ―0.0 27.1% ―30.5% ‐0.4 ―‐0.4

SERC‐Gateway 24.0% ―28.0% 0.0 ―0.0 23.3% ―27.4% ‐0.6 ―‐0.6

SERC‐Southeastern 13.0% ―29.8% 0.0 ―0.0 12.5% ―29.3% ‐0.5 ―‐0.5

SERC‐VACAR 17.5% ―20.3% 0.0 ―0.0 16.6% ―19.4% ‐0.9 ―‐0.9

SPP 15.9% ―30.3% 0.0 ―0.0 15.6% ―30.0% ‐0.3 ―‐0.3

WECC‐CA 48.6% ―48.6% 0.0 ―0.0 48.6% ―48.6% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 22.1% ―23.7% 0.0 ―0.0 22.1% ―23.7% 0.0 ―0.0

WECC‐NWPP 29.9% ―30.1% 0.0 ―0.0 29.9% ―30.1% 0.0 ―0.0

WECC‐RMPA 24.7% ―30.3% 0.0 ―0.0 24.7% ―30.3% 0.0 ―0.0

   TOTAL 22.3% ―27.7% ‐0.1 ―0.0 22.1% ―27.4% ‐0.3 ―‐0.3

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐9: CATR Impacts ‐ 2013

Moderate Case Strict Case

ERCOT 16.5% ―23.9% 0.0 ―0.0 16.5% ―23.9% 0.0 ―0.0

FRCC 28.6% ―28.6% 0.0 ―0.0 28.6% ―28.6% 0.0 ―0.0

MRO 12.9% ―22.1% 0.0 ―0.0 12.9% ―22.1% 0.0 ―0.0

NPCC‐NE 18.6% ―26.4% 0.0 ―0.0 18.6% ―26.4% 0.0 ―0.0

NPCC‐NY 28.1% ―29.8% 0.0 ―0.0 28.1% ―29.8% 0.0 ―0.0

RFC 19.4% ―24.3% 0.0 ―0.0 19.4% ―24.3% 0.0 ―0.0

SERC‐Central 23.6% ―27.2% 0.0 ―0.0 23.6% ―27.2% 0.0 ―0.0

SERC‐Delta 27.5% ―30.9% 0.0 ―0.0 27.5% ―30.9% 0.0 ―0.0

SERC‐Gateway 24.0% ―28.0% 0.0 ―0.0 24.0% ―28.0% 0.0 ―0.0

SERC‐Southeastern 13.0% ―29.8% 0.0 ―0.0 13.0% ―29.8% 0.0 ―0.0

SERC‐VACAR 17.5% ―20.3% 0.0 ―0.0 17.5% ―20.3% 0.0 ―0.0

SPP 15.9% ―30.3% 0.0 ―0.0 15.9% ―30.3% 0.0 ―0.0

WECC‐CA 48.6% ―48.6% 0.0 ―0.0 48.6% ―48.6% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 22.1% ―23.7% 0.0 ―0.0 22.1% ―23.7% 0.0 ―0.0

WECC‐NWPP 29.9% ―30.1% 0.0 ―0.0 29.9% ―30.1% 0.0 ―0.0

WECC‐RMPA 24.7% ―30.3% 0.0 ―0.0 24.7% ―30.3% 0.0 ―0.0

   TOTAL 22.4% ―27.7% 0.0 ―0.0 22.4% ―27.7% 0.0 ―0.0

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐10: CCR Impacts ‐ 2013

Moderate Case Strict Case
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 66 2010 Special Reliability Assessment Scenario 

ERCOT 16.5% ―23.9% 0.0 ―0.0 16.3% ―23.8% ‐0.1 ―‐0.1

FRCC 28.6% ―28.6% 0.0 ―0.0 28.5% ―28.5% 0.0 ―0.0

MRO 12.9% ―22.1% 0.0 ―0.0 10.1% ―19.3% ‐2.7 ―‐2.7

NPCC‐NE 18.0% ―25.9% ‐0.6 ―‐0.6 16.7% ―24.6% ‐1.9 ―‐1.9

NPCC‐NY 28.1% ―29.8% 0.0 ―0.0 27.3% ―29.0% ‐0.8 ―‐0.8

RFC 19.2% ―24.0% ‐0.2 ―‐0.2 17.6% ―22.4% ‐1.9 ―‐1.9

SERC‐Central 23.6% ―27.2% 0.0 ―0.0 22.8% ―26.4% ‐0.9 ―‐0.9

SERC‐Delta 27.5% ―30.9% 0.0 ―0.0 27.0% ―30.4% ‐0.5 ―‐0.5

SERC‐Gateway 24.0% ―28.0% 0.0 ―0.0 22.9% ―27.0% ‐1.0 ―‐1.0

SERC‐Southeastern 13.0% ―29.8% 0.0 ―0.0 12.1% ―28.9% ‐0.9 ―‐0.9

SERC‐VACAR 17.5% ―20.3% 0.0 ―0.0 15.5% ―18.3% ‐1.9 ―‐1.9

SPP 15.9% ―30.3% 0.0 ―0.0 15.9% ―30.3% 0.0 ―0.0

WECC‐CA 48.6% ―48.6% 0.0 ―0.0 48.4% ―48.4% ‐0.3 ―‐0.3

WECC‐AZ‐NM‐SNV 22.1% ―23.7% 0.0 ―0.0 22.1% ―23.7% 0.0 ―0.0

WECC‐NWPP 29.9% ―30.1% 0.0 ―0.0 29.9% ―30.1% 0.0 ―0.0

WECC‐RMPA 24.7% ―30.3% 0.0 ―0.0 24.7% ―30.3% 0.0 ―0.0

   TOTAL 22.3% ―27.7% ‐0.1 ―‐0.1 21.4% ―26.7% ‐1.0 ―‐1.0

Table IV‐11: Combined Impacts ‐ 2013

Moderate Case Strict Case

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 67 

ERCOT 14.1% ―22.0% ‐1.1 ―‐1.1 13.8% ―21.7% ‐1.4 ―‐1.4

FRCC 24.7% ―24.7% ‐0.3 ―‐0.3 24.7% ―24.7% ‐0.3 ―‐0.3

MRO 7.6% ―17.2% ‐1.7 ―‐1.7 7.6% ―17.1% ‐1.8 ―‐1.8

NPCC‐NE 12.0% ―21.0% ‐3.5 ―‐3.5 12.0% ―21.0% ‐3.5 ―‐3.5

NPCC‐NY 23.5% ―25.5% ‐2.9 ―‐2.9 23.5% ―25.5% ‐2.9 ―‐2.9

RFC 16.2% ―21.4% ‐0.9 ―‐0.9 16.2% ―21.4% ‐0.9 ―‐0.9

SERC‐Central 21.1% ―24.6% ‐0.6 ―‐0.6 21.1% ―24.6% ‐0.6 ―‐0.6

SERC‐Delta 14.3% ―17.7% ‐6.1 ―‐6.1 14.3% ―17.7% ‐6.1 ―‐6.1

SERC‐Gateway 20.0% ―24.0% ‐2.7 ―‐2.7 20.0% ―24.0% ‐2.7 ―‐2.7

SERC‐Southeastern 11.8% ―28.5% ‐0.5 ―‐0.5 11.9% ―28.5% ‐0.5 ―‐0.5

SERC‐VACAR 12.4% ―15.4% ‐0.3 ―‐0.3 12.3% ―15.4% ‐0.3 ―‐0.3

SPP 13.6% ―28.0% ‐1.3 ―‐1.3 13.5% ―28.0% ‐1.4 ―‐1.4

WECC‐CA 48.8% ―48.8% ‐1.3 ―‐1.3 48.8% ―48.8% ‐1.3 ―‐1.3

WECC‐AZ‐NM‐SNV 19.7% ―22.9% ‐0.1 ―‐0.1 19.7% ―22.9% ‐0.1 ―‐0.1

WECC‐NWPP 26.8% ―28.0% ‐0.2 ―‐0.2 26.8% ―28.0% ‐0.2 ―‐0.2

WECC‐RMPA 16.2% ―24.6% ‐0.4 ―‐0.4 16.0% ―24.3% ‐0.6 ―‐0.6

   TOTAL 18.8% ―24.5% ‐1.2 ―‐1.2 18.8% ―24.4% ‐1.3 ―‐1.3

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Moderate Case Strict Case

Table IV‐12: 316(b) Impacts ‐ 2015

ERCOT 15.0% ―22.9% ‐0.1 ―‐0.1 15.0% ―22.9% ‐0.1 ―‐0.1

FRCC 25.0% ―25.0% 0.0 ―0.0 24.6% ―24.6% ‐0.4 ―‐0.4

MRO 8.6% ―18.2% ‐0.7 ―‐0.7 7.4% ―16.9% ‐2.0 ―‐2.0

NPCC‐NE 15.5% ―24.5% 0.0 ―0.0 13.3% ―22.3% ‐2.2 ―‐2.2

NPCC‐NY 26.3% ―28.3% 0.0 ―0.0 24.2% ―26.3% ‐2.1 ―‐2.1

RFC 16.5% ―21.7% ‐0.6 ―‐0.6 13.6% ―18.8% ‐3.5 ―‐3.5

SERC‐Central 21.5% ―24.9% ‐0.3 ―‐0.3 18.8% ―22.2% ‐3.0 ―‐3.0

SERC‐Delta 20.2% ―23.5% ‐0.3 ―‐0.3 19.9% ―23.2% ‐0.5 ―‐0.5

SERC‐Gateway 22.2% ―26.1% ‐0.6 ―‐0.6 20.4% ―24.4% ‐2.3 ―‐2.3

SERC‐Southeastern 12.0% ―28.7% ‐0.3 ―‐0.3 9.6% ―26.2% ‐2.8 ―‐2.8

SERC‐VACAR 12.0% ―15.0% ‐0.7 ―‐0.7 8.4% ―11.5% ‐4.2 ―‐4.2

SPP 14.6% ―29.1% ‐0.3 ―‐0.3 14.5% ―28.9% ‐0.4 ―‐0.4

WECC‐CA 50.1% ―50.1% 0.0 ―0.0 50.1% ―50.1% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 19.6% ―22.9% ‐0.1 ―‐0.1 14.9% ―18.2% ‐4.8 ―‐4.8

WECC‐NWPP 26.8% ―27.9% ‐0.2 ―‐0.2 26.6% ―27.7% ‐0.4 ―‐0.4

WECC‐RMPA 16.5% ―24.8% ‐0.1 ―‐0.1 15.7% ―24.0% ‐0.9 ―‐0.9

   TOTAL 19.7% ―25.4% ‐0.3 ―‐0.3 17.9% ―23.6% ‐2.1 ―‐2.1

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Moderate Case Strict Case

Table IV‐13: MACT Impacts ‐ 2015
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 68 2010 Special Reliability Assessment Scenario 

ERCOT 15.2% ―23.0% 0.0 ―0.0 15.0% ―22.9% ‐0.1 ―‐0.1

FRCC 25.0% ―25.0% 0.0 ―0.0 25.0% ―25.0% 0.0 ―0.0

MRO 9.3% ―18.8% ‐0.1 ―‐0.1 6.7% ―16.2% ‐2.7 ―‐2.7

NPCC‐NE 14.9% ―23.9% ‐0.5 ―‐0.5 14.2% ―23.2% ‐1.3 ―‐1.3

NPCC‐NY 26.3% ―28.3% 0.0 ―0.0 26.1% ―28.1% ‐0.2 ―‐0.2

RFC 16.2% ―21.4% ‐0.9 ―‐0.9 15.6% ―20.8% ‐1.5 ―‐1.5

SERC‐Central 21.7% ―25.2% 0.0 ―0.0 21.1% ―24.6% ‐0.7 ―‐0.7

SERC‐Delta 20.5% ―23.8% 0.0 ―0.0 19.9% ―23.3% ‐0.5 ―‐0.5

SERC‐Gateway 18.4% ―22.4% ‐4.3 ―‐4.3 21.7% ―25.7% ‐1.0 ―‐1.0

SERC‐Southeastern 12.3% ―28.9% ‐0.1 ―‐0.1 11.5% ―28.1% ‐0.9 ―‐0.9

SERC‐VACAR 12.6% ―15.7% 0.0 ―0.0 10.9% ―14.0% ‐1.7 ―‐1.7

SPP 14.9% ―29.3% 0.0 ―0.0 14.2% ―28.7% ‐0.7 ―‐0.7

WECC‐CA 50.1% ―50.1% 0.0 ―0.0 50.1% ―50.1% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 19.8% ―23.0% 0.0 ―0.0 19.8% ―23.0% 0.0 ―0.0

WECC‐NWPP 27.0% ―28.2% 0.0 ―0.0 27.0% ―28.2% 0.0 ―0.0

WECC‐RMPA 16.6% ―25.0% 0.0 ―0.0 16.6% ―25.0% 0.0 ―0.0

   TOTAL 19.7% ―25.4% ‐0.3 ―‐0.3 19.2% ―24.8% ‐0.9 ―‐0.9

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Moderate Case Strict Case

Table IV‐14: CATR Impacts ‐ 2015

ERCOT 15.2% ―23.0% 0.0 ―0.0 15.2% ―23.0% 0.0 ‐ 0.0

FRCC 25.0% ―25.0% 0.0 ―0.0 25.0% ―25.0% 0.0 ‐ 0.0

MRO 9.4% ―18.9% 0.0 ―0.0 9.4% ―18.9% 0.0 ‐ 0.0

NPCC‐NE 15.5% ―24.5% 0.0 ―0.0 15.5% ―24.5% 0.0 ‐ 0.0

NPCC‐NY 26.3% ―28.3% 0.0 ―0.0 26.3% ―28.3% 0.0 ‐ 0.0

RFC 17.1% ―22.3% 0.0 ―0.0 17.1% ―22.3% 0.0 ‐ 0.0

SERC‐Central 21.8% ―25.3% 0.0 ―0.0 21.6% ―25.1% ‐0.2 ‐ ‐0.2

SERC‐Delta 20.5% ―23.8% 0.0 ―0.0 20.5% ―23.8% 0.0 ‐ 0.0

SERC‐Gateway 22.7% ―26.7% 0.0 ―0.0 22.3% ―26.3% ‐0.4 ‐ ‐0.4

SERC‐Southeastern 12.1% ―28.8% ‐0.2 ―‐0.2 12.1% ―28.8% ‐0.2 ‐ ‐0.2

SERC‐VACAR 12.6% ―15.7% 0.0 ―0.0 12.6% ―15.7% 0.0 ‐ 0.0

SPP 14.9% ―29.3% 0.0 ―0.0 14.9% ―29.3% 0.0 ‐ 0.0

WECC‐CA 50.1% ―50.1% 0.0 ―0.0 50.1% ―50.1% 0.0 ‐ 0.0

WECC‐AZ‐NM‐SNV 19.8% ―23.0% 0.0 ―0.0 19.8% ―23.0% 0.0 ‐ 0.0

WECC‐NWPP 27.0% ―28.2% 0.0 ―0.0 27.0% ―28.2% 0.0 ‐ 0.0

WECC‐RMPA 16.6% ―25.0% 0.0 ―0.0 16.6% ―25.0% 0.0 ‐ 0.0

   TOTAL 20.0% ―25.7% 0.0 ―0.0 20.0% ―25.7% 0.0 ‐ 0.0

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Moderate Case Strict Case

Table IV‐15: CCR Impacts ‐ 2015
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 69 

ERCOT 7.5% ―15.4% ‐7.7 ―‐7.7 6.8% ―14.7% ‐8.4 ―‐8.4

FRCC 23.0% ―23.0% ‐2.0 ―‐2.0 21.3% ―21.3% ‐3.7 ―‐3.7

MRO 5.9% ―15.5% ‐3.5 ―‐3.5 ‐1.7% ―7.9% ‐11.0 ―‐11.0

NPCC‐NE 7.2% ―16.2% ‐8.3 ―‐8.3 1.8% ―10.8% ‐13.6 ―‐13.6

NPCC‐NY 17.4% ―19.5% ‐8.9 ―‐8.9 11.5% ―13.6% ‐14.8 ―‐14.8

RFC 14.2% ―19.4% ‐2.9 ―‐2.9 7.2% ―12.4% ‐9.9 ―‐9.9

SERC‐Central 21.0% ―24.5% ‐0.7 ―‐0.7 10.1% ―13.6% ‐11.6 ―‐11.6

SERC‐Delta 1.9% ―5.2% ‐18.6 ―‐18.6 ‐0.2% ―3.1% ‐20.6 ―‐20.6

SERC‐Gateway 19.6% ―23.6% ‐3.1 ―‐3.1 1.5% ―5.5% ‐21.3 ―‐21.3

SERC‐Southeastern 11.3% ―27.9% ‐1.1 ―‐1.1 5.7% ―22.4% ‐6.6 ―‐6.6

SERC‐VACAR 11.1% ―14.2% ‐1.5 ―‐1.5 4.6% ―7.6% ‐8.0 ―‐8.0

SPP 12.7% ―27.1% ‐2.2 ―‐2.2 9.3% ―23.8% ‐5.5 ―‐5.5

WECC‐CA 44.3% ―44.3% ‐5.8 ―‐5.8 39.3% ―39.3% ‐10.8 ―‐10.8

WECC‐AZ‐NM‐SNV 17.3% ―20.6% ‐2.4 ―‐2.4 12.6% ―15.9% ‐7.1 ―‐7.1

WECC‐NWPP 26.5% ―27.6% ‐0.5 ―‐0.5 26.5% ―27.6% ‐0.5 ―‐0.5

WECC‐RMPA 14.9% ―23.2% ‐1.7 ―‐1.7 14.6% ―22.9% ‐2.1 ―‐2.1

   TOTAL 16.1% ―21.7% ‐4.0 ―‐4.0 10.8% ―16.4% ‐9.3 ―‐9.3

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐16: Combined Impacts ‐ 2015

Moderate Case Strict Case

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 70 2010 Special Reliability Assessment Scenario 

ERCOT ‐1.2% ―6.1% ‐7.2 ―‐7.2 ‐1.5% ―5.8% ‐7.5 ―‐7.5

FRCC 24.9% ―24.9% ‐2.1 ―‐2.1 23.9% ―23.9% ‐3.1 ―‐3.1

MRO 0.6% ―10.8% ‐3.5 ―‐3.5 0.6% ―10.8% ‐3.5 ―‐3.5

NPCC‐NE 2.7% ―11.5% ‐8.7 ―‐8.7 1.5% ―10.2% ‐10.0 ―‐10.0

NPCC‐NY 15.6% ―17.6% ‐9.5 ―‐9.5 13.9% ―15.9% ‐11.2 ―‐11.2

RFC 10.2% ―15.5% ‐3.6 ―‐3.6 10.1% ―15.4% ‐3.7 ―‐3.7

SERC‐Central 19.1% ―22.5% ‐1.0 ―‐1.0 19.1% ―22.5% ‐1.0 ―‐1.0

SERC‐Delta ‐3.4% ―‐0.2% ‐18.5 ―‐18.5 ‐3.4% ―‐0.2% ‐18.5 ―‐18.5

SERC‐Gateway 15.7% ―19.6% ‐3.9 ―‐3.9 15.7% ―19.6% ‐4.0 ―‐4.0

SERC‐Southeastern 14.8% ―30.5% ‐1.2 ―‐1.2 14.8% ―30.5% ‐1.2 ―‐1.2

SERC‐VACAR 7.1% ―9.6% ‐1.4 ―‐1.4 7.1% ―9.6% ‐1.5 ―‐1.5

SPP 7.7% ―21.8% ‐2.2 ―‐2.2 7.6% ―21.7% ‐2.3 ―‐2.3

WECC‐CA 31.1% ―31.1% ‐8.3 ―‐8.3 28.3% ―28.3% ‐11.1 ―‐11.1

WECC‐AZ‐NM‐SNV 17.1% ―21.1% ‐2.1 ―‐2.1 17.1% ―21.1% ‐2.1 ―‐2.1

WECC‐NWPP 21.6% ―22.7% ‐0.4 ―‐0.4 21.6% ―22.7% ‐0.4 ―‐0.4

WECC‐RMPA 15.8% ―23.9% ‐1.6 ―‐1.6 15.8% ―23.9% ‐1.6 ―‐1.6

   TOTAL 12.0% ―17.6% ‐4.3 ―‐4.3 11.6% ―17.1% ‐4.7 ―‐4.7

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐17: 316(b) Impacts ‐ 2018

Moderate Case Strict Case

ERCOT 5.9% ―13.2% ‐0.1 ―‐0.1 5.9% ―13.2% ‐0.1 ―‐0.1

FRCC 26.9% ―26.9% 0.0 ―0.0 26.6% ―26.6% ‐0.4 ―‐0.4

MRO 2.3% ―12.5% ‐1.8 ―‐1.8 2.2% ―12.4% ‐1.9 ―‐1.9

NPCC‐NE 11.3% ―20.1% ‐0.1 ―‐0.1 9.3% ―18.1% ‐2.1 ―‐2.1

NPCC‐NY 24.9% ―26.9% ‐0.2 ―‐0.2 23.1% ―25.1% ‐2.0 ―‐2.0

RFC 12.2% ―17.6% ‐1.6 ―‐1.6 10.4% ―15.7% ‐3.4 ―‐3.4

SERC‐Central 19.4% ―22.7% ‐0.8 ―‐0.8 17.3% ―20.6% ‐2.9 ―‐2.9

SERC‐Delta 14.7% ―17.9% ‐0.4 ―‐0.4 14.5% ―17.7% ‐0.5 ―‐0.5

SERC‐Gateway 18.8% ―22.6% ‐0.9 ―‐0.9 17.4% ―21.3% ‐2.3 ―‐2.3

SERC‐Southeastern 15.4% ―31.1% ‐0.6 ―‐0.6 13.3% ―29.1% ‐2.6 ―‐2.6

SERC‐VACAR 7.0% ―9.6% ‐1.5 ―‐1.5 4.5% ―7.1% ‐4.0 ―‐4.0

SPP 9.6% ―23.6% ‐0.4 ―‐0.4 9.6% ―23.6% ‐0.4 ―‐0.4

WECC‐CA 39.3% ―39.3% 0.0 ―0.0 39.3% ―39.3% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 14.8% ―18.7% ‐4.5 ―‐4.5 14.8% ―18.7% ‐4.5 ―‐4.5

WECC‐NWPP 21.6% ―22.6% ‐0.4 ―‐0.4 21.6% ―22.6% ‐0.4 ―‐0.4

WECC‐RMPA 16.5% ―24.6% ‐0.9 ―‐0.9 16.5% ―24.6% ‐0.9 ―‐0.9

   TOTAL 15.4% ―20.9% ‐1.0 ―‐1.0 14.3% ―19.8% ‐2.0 ―‐2.0

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐18: MACT Impacts ‐ 2018

Moderate Case Strict Case
Appendix IV: Data Tables

Appendix IV: Data Tables 

2010 Special Reliability Assessment Scenario Page 71 

ERCOT 6.0% ―13.3% 0.0 ‐ 0.0 5.9% ‐ 13.1% ‐0.1 ‐ ‐0.1

FRCC 27.0% ―27.0% 0.0 ‐ 0.0 26.9% ‐ 26.9% 0.0 ‐ 0.0

MRO 4.0% ―14.2% ‐0.1 ‐ ‐0.1 1.5% ‐ 11.7% ‐2.6 ‐ ‐2.6

NPCC‐NE 10.9% ―19.7% ‐0.5 ‐ ‐0.5 10.2% ‐ 18.9% ‐1.2 ‐ ‐1.2

NPCC‐NY 25.1% ―27.1% 0.0 ‐ 0.0 24.9% ‐ 26.9% ‐0.2 ‐ ‐0.2

RFC 12.9% ―18.2% ‐0.9 ‐ ‐0.9 12.4% ‐ 17.7% ‐1.4 ‐ ‐1.4

SERC‐Central 20.1% ―23.5% 0.0 ‐ 0.0 19.5% ‐ 22.9% ‐0.6 ‐ ‐0.6

SERC‐Delta 15.0% ―18.2% 0.0 ‐ 0.0 14.5% ‐ 17.7% ‐0.5 ‐ ‐0.5

SERC‐Gateway 15.5% ―19.4% ‐4.2 ‐ ‐4.2 18.7% ‐ 22.6% ‐1.0 ‐ ‐1.0

SERC‐Southeastern 15.9% ―31.6% ‐0.1 ‐ ‐0.1 15.2% ‐ 30.9% ‐0.8 ‐ ‐0.8

SERC‐VACAR 8.5% ―11.1% 0.0 ‐ 0.0 6.9% ‐ 9.4% ‐1.6 ‐ ‐1.6

SPP 9.9% ―24.0% 0.0 ‐ 0.0 9.3% ‐ 23.3% ‐0.7 ‐ ‐0.7

WECC‐CA 39.3% ―39.3% 0.0 ‐ 0.0 39.3% ‐ 39.3% 0.0 ‐ 0.0

WECC‐AZ‐NM‐SNV 19.2% ―23.2% 0.0 ‐ 0.0 19.2% ‐ 23.2% 0.0 ‐ 0.0

WECC‐NWPP 22.0% ―23.1% 0.0 ‐ 0.0 22.0% ‐ 23.1% 0.0 ‐ 0.0

WECC‐RMPA 17.3% ―25.4% 0.0 ‐ 0.0 17.3% ‐ 25.4% 0.0 ‐ 0.0

   TOTAL 16.0% ―21.5% ‐0.3 ‐ ‐0.3 15.5% ‐ 21.1% ‐0.8 ‐ ‐0.8

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐19: CATR Impacts ‐ 2018

Moderate Case Strict Case

ERCOT 6.0% ―13.3% 0.0 ―0.0 6.0% ―13.3% 0.0 ―0.0

FRCC 27.0% ―27.0% 0.0 ―0.0 27.0% ―27.0% 0.0 ―0.0

MRO 4.1% ―14.3% 0.0 ―0.0 3.9% ―14.1% ‐0.2 ―‐0.2

NPCC‐NE 11.4% ―20.2% 0.0 ―0.0 11.4% ―20.2% 0.0 ―0.0

NPCC‐NY 25.1% ―27.1% 0.0 ―0.0 25.1% ―27.1% 0.0 ―0.0

RFC 13.8% ―19.1% 0.0 ―0.0 13.8% ―19.1% 0.0 ―0.0

SERC‐Central 20.0% ―23.3% ‐0.2 ―‐0.2 20.0% ―23.3% ‐0.2 ―‐0.2

SERC‐Delta 15.0% ―18.2% 0.0 ―0.0 15.0% ―18.2% ‐0.1 ―‐0.1

SERC‐Gateway 19.3% ―23.2% ‐0.4 ―‐0.4 19.3% ―23.2% ‐0.4 ―‐0.4

SERC‐Southeastern 15.8% ―31.5% ‐0.2 ―‐0.2 15.8% ―31.5% ‐0.2 ―‐0.2

SERC‐VACAR 8.5% ―11.1% 0.0 ―0.0 8.5% ―11.1% 0.0 ―0.0

SPP 9.9% ―24.0% 0.0 ―0.0 9.9% ―24.0% 0.0 ―0.0

WECC‐CA 39.3% ―39.3% 0.0 ―0.0 39.3% ―39.3% 0.0 ―0.0

WECC‐AZ‐NM‐SNV 19.2% ―23.2% 0.0 ―0.0 19.2% ―23.2% 0.0 ―0.0

WECC‐NWPP 22.0% ―23.1% 0.0 ―0.0 22.0% ―23.1% 0.0 ―0.0

WECC‐RMPA 17.3% ―25.4% 0.0 ―0.0 17.3% ―25.4% 0.0 ―0.0

   TOTAL 16.3% ―21.8% 0.0 ―0.0 16.3% ―21.8% 0.0 ―0.0

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Table IV‐20: CCR Impacts ‐ 2018

Moderate Case Strict Case
Appendix IV: Data Tables

Appendix IV: Data Tables 

Page 72 2010 Special Reliability Assessment Scenario 

ERCOT ‐1.2% ―6.0% ‐7.2 ―‐7.2 ‐1.7% ―5.6% ‐7.7 ―‐7.7

FRCC 24.6% ―24.6% ‐2.3 ―‐2.3 23.5% ―23.5% ‐3.5 ―‐3.5

MRO ‐0.3% ―9.9% ‐4.4 ―‐4.4 ‐6.5% ―3.7% ‐10.6 ―‐10.6

NPCC‐NE 1.2% ―10.0% ‐10.2 ―‐10.2 ‐1.8% ―6.9% ‐13.3 ―‐13.3

NPCC‐NY 14.9% ―16.9% ‐10.2 ―‐10.2 10.7% ―12.7% ‐14.4 ―‐14.4

RFC 8.7% ―14.1% ‐5.1 ―‐5.1 4.7% ―10.0% ‐9.2 ―‐9.2

SERC‐Central 18.0% ―21.3% ‐2.2 ―‐2.2 9.0% ―12.3% ‐11.2 ―‐11.2

SERC‐Delta ‐3.7% ―‐0.5% ‐18.7 ―‐18.7 ‐4.9% ―‐1.7% ‐19.9 ―‐19.9

SERC‐Gateway 14.5% ―18.4% ‐5.2 ―‐5.2 1.7% ―5.6% ‐18.0 ―‐18.0

SERC‐Southeastern 13.9% ―29.6% ‐2.1 ―‐2.1 9.7% ―25.4% ‐6.3 ―‐6.3

SERC‐VACAR 5.0% ―7.6% ‐3.5 ―‐3.5 0.9% ―3.4% ‐7.6 ―‐7.6

SPP 7.4% ―21.4% ‐2.6 ―‐2.6 4.6% ―18.7% ‐5.3 ―‐5.3

WECC‐CA 31.1% ―31.1% ‐8.3 ―‐8.3 28.2% ―28.2% ‐11.2 ―‐11.2

WECC‐AZ‐NM‐SNV 12.6% ―16.6% ‐6.6 ―‐6.6 12.6% ―16.6% ‐6.6 ―‐6.6

WECC‐NWPP 21.5% ―22.6% ‐0.5 ―‐0.5 21.5% ―22.6% ‐0.5 ―‐0.5

WECC‐RMPA 15.7% ―23.8% ‐1.6 ―‐1.6 15.4% ―23.5% ‐1.9 ―‐1.9

   TOTAL 11.0% ―16.5% ‐5.3 ―‐5.3 7.6% ―13.1% ‐8.8 ―‐8.8

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Resulting Reserve

Margin (%)      

(DCR to APCR)

Percentage Point

Change in

Reserve Margin

Moderate Case Strict Case

Table IV‐21: Combined Impacts ‐ 2018
Appendix V: Related Study Work and References

Appendix V: Related Study Work and References 

2010 Special Reliability Assessment Scenario Page 73 

Appendix V: Related Study Work and References

Related Study Work For 316(b) 

The U.S. Senate Committee on Appropriations, Subcommittee on Energy and Water 

Development, requested the Office of Electricity Delivery and Energy Reliability of the 

Department of Energy (DOE or Department) to examine the impacts to electricity reliability of 

requiring generators with once-through cooling systems to be replaced with closed-cycle cooling 

towers. 

DOE provided NERC with a list of steam generation units that would be required to retrofit to 

cooling towers. DOE requested NERC to model the reliability impacts of the cooling tower 

mandate using certain assumptions. NERC provided DOE with its results in a white paper, 2008-

2017 NERC Capacity Margins: Retrofit of Once-Through Cooling Systems at Existing 

Generating Facilities.

In the white paper, NERC concluded that once the deadline for the cooling tower retrofits has 

passed, the generation losses resulting from the requirement would exacerbate a potential decline 

in electric Planning Reserve Margins needed to ensure reliable delivery of electricity. Generally, 

the goal for NERC Regions is to have the equivalent of between 10 and 15 percent of their peak 

generation demand available to meet contingencies. NERC projects overall capacity reserve 

margins to fall to 14.7 percent by 2015, assuming only planned generation is built. However, 

upon assessing the impact of a cooling tower mandate, NERC projects that, “U.S. resource 

margins will drop from 14.7 percent to 10.4 percent when both the retired units and auxiliary 

loads due to retrofitting were compared to the Reference Case.” 

The following assumptions were used for this assessment: 

Assumptions specified by DOE: 

 Close-loop cooling systems will be added to all nuclear units. Capacity factors can be 

used as a proxy for economic suitability for retrofit 

 Unit Retirements/Retrofits were based on the following capacity factors from 2006: 

- Units with a capacity factor less than 35 percent are assumed to be retired. 

- Units with a capacity factor greater than or equal to 0.35 were derated by four 

percent of maximum rated (nameplate) capacity. 

- 60 percent of retirements/retrofits was projected to begin in 2013, 20 percent 

in 2014 and 20 percent in 2015. 

 Plants deemed “difficult to retrofit” due to geographical limitations (e.g. land-locked, 

space and permitting constraints) could result in early retirement. This assessment 

does not assume their early retirement. 

 No new plants are built to replace capacity lost to retired units or auxiliary loads. 

 Retrofits are instantaneous, with no capacity shortfalls due to plant shutdowns. 

 Plants with a zero capacity factor (inactive or not yet built) are not assessed. These 

plants are not included in the Region’s Reference Case. 
Appendix V: Related Study Work and References

Appendix V: Related Study Work and References 

Page 74 2010 Special Reliability Assessment Scenario 

Assumptions specified by NERC: 

 The NERC Reference Margin Level adopted the Regional/subregional Target 

Capacity Margin. If not available, the NERC Reference Margin Level is based on 

supply-side fuel: 13 percent for thermal systems and 9 percent for hydro (Capacity 

Margin). 

 Unit Retirement/Retrofit capacity reduction comparison is based against “Adjusted 

Potential Resources”, calculated with all Existing Capacity and probable Planned 

Additions, Proposed Additions, and Net Transactions. 

 Units already expected to retire between 2010 and 2015 were not considered part of 

the capacity reduction as they are already factored into the Region’s projections.

NERC reviewed the impact of either retrofitting units with existing once-through-cooling 

systems to closed-loop cooling systems (resulting in four percent reduction in nameplate 

capacity) or unit retirements (capacity factor less than 35 percent) on NERC-US and Regional 

capacity margins for 2008–2017. Based on a worst-case view, NERC-US Adjusted Potential 

Resources may be impacted up to 49,000 MW, reducing the Adjusted Potential Resource Margin 

by 4.3 percent and some areas may require more resources to offset capacity reductions and 

maintain the reliability of the bulk power system. Some subregions, such as WECC-CA, NPCCNE, ERCOT, SERC-Central and NPCC-NY, experience significant impacts. 

Table V-1: 2015 US Summer Peak Potential Retrofit/Retirement Effects 

In comparing the results of the prior collaborative DOE/NERC assessment to the results in this 

report, impacts of similar magnitudes were found. Further, the areas (Regions/subregions) of 

concern highlighted in the prior assessment are aligned with those identified in this assessment.

Adjusted 

Potential 

Resources 

(MW)

 Reduction

due to 

Retirement

(MW) 

Derate due

to Retrofit

(MW) 

NERC

Reference

Margin

Level

Adjusted

Potential

Resources

Margin

 Margin 

Reduction 

Reduced

Margin 

United States

WECC - CA-MX US 72,293 10,137 289 13.2% 12.7% 14.7% -2.0%

NPCC - New England 31,673 2,827 428 13.0% 10.0% 10.3% -0.3%

ERCOT 86,436 10,919 542 11.1% 15.9% 12.9% 3.0%

NPCC US 72,750 6,481 990 13.0% 13.3% 9.9% 3.4%

WECC US 176,944 10,177 314 12.3% 11.1% 5.6% 5.5%

NPCC - New York 41,077 3,654 561 13.0% 15.9% 9.6% 6.3%

SERC - VACAR 78,182 553 1,032 13.0% 11.0% 1.8% 9.2%

WECC - RMPA 15,609 40 0 10.5% 10.2% 0.2% 10.0%

SERC - Central 54,548 0 949 13.0% 12.6% 1.5% 11.0%

SERC - Delta 41,259 4,266 466 13.0% 21.5% 10.2% 11.4%

RFC 230,062 3,339 2,863 12.8% 14.5% 2.4% 12.1%

SERC 269,599 6,054 3,307 13.0% 15.6% 3.0% 12.5%

SERC - Southeastern 66,675 675 357 13.0% 13.9% 1.4% 12.6%

MRO US 55,582 529 612 13.0% 15.1% 1.8% 13.3%

FRCC 63,170 1,267 454 13.0% 18.7% 2.3% 16.4%

WECC - NWPP 51,861 0 25 11.9% 16.9% 0.0% 16.8%

SPP 63,700 817 257 12.0% 24.1% 1.3% 22.8%

SERC - Gateway 28,935 560 502 13.0% 28.8% 2.7% 26.1%

Total-NERC US 1,018,243 39,583 9,339 13.0% 14.7% 4.3% 10.4%
Appendix V: Related Study Work and References

Appendix V: Related Study Work and References 

2010 Special Reliability Assessment Scenario Page 75 

EPRI Study Work For CCR: 

EPRI conducted a screening assessment of the potential impact of EPA’s expected proposals for 

management of CCR prior to publication of the draft rule.42 This assessment indicated that 40 to 

97 GW of coal-fired capacity could be “at risk” for retirement based on the increased costs 

associated with such a rule. The methods for estimating compliance costs at the generating unit 

level are similar to methods discussed in this report, with three significant differences: 

 the sample of coal-fired generating units included in the assessment; 

 the definition of the term “at risk” capacity; and 

 some aspects of the cost assignment logic for Subtitle C (hazardous waste) management 

of CCRs. 

Coal-Fired Capacity Assumptions

The total capacity represented by the units included in the EPRI analysis differed from the total 

capacity of the units included in the NERC assessment. Included in the EPRI analysis--but 

excluded from NERC’s--are smaller units not in the bulk power system, planned coal-fired units 

not currently operating but scheduled to come online during the 20-year EPRI study horizon, and 

units that have recently announced early retirements. Since EPRI’s analysis in 2009, several 

utilities have announced plans to retire older coal-fired generating units. Combined, the units 

included in EPRI’s analysis, but excluded from the NERC assessment, represent 20 GW of 

capacity. 

Definition of “at risk” Coal Capacity

The EPRI study was a screening-level economic analysis, intended to identify individual 

generating units that were predicted to be no longer profitable under a Subtitle C regulation. 

Any unit that would no longer be profitable was defined as “at risk.” “At risk” in this context 

means that a decision would have to be made with respect to the generating unit: early 

retirement, repower, purchase power, or continue operation at a loss or at higher market prices. 

NERC, however, starts with the premise that reliability cannot be compromised and that for 

many units shutdown is not an option (particularly base-load units) without major disruption to 

the power grid. Thus, NERC’s assessment compared the cost of compliance with Subtitle C 

requirements to the cost of natural gas-fired replacement power in order to determine which 

decision would be the most economical for a generating unit; only those units where compliance 

costs exceeded repowering costs were considered candidates for shutdown and thus deemed “at 

risk” for retirement. 

Subtitle C Cost Assumptions

In assessing the cost of hazardous waste regulation on power plants, EPRI considered costs that 

NERC did not include in its assessment. One was the cost of off-site disposal at a commercial 

facility. NERC’s assessment assumed all power plants would locate and construct Subtitle C 

landfills on or near the power plant property. While some states do not currently allow 

establishment of hazardous waste landfills within the state, NERC assumed that provisions 

 

42 EPRI, 2009, Testimony at the House Subcommittee on Energy and Environment Hearing on “Drinking Water and Public 

Health Impacts of Coal Combustion Waste Disposal,” Washington DC, December 10, 2009. 

http://mydocs.epri.com/docs/CorporateDocuments/SectorPages/Portfolio/Environment/Ken%20Ladwig%20Written%20Testi

mony%20USHouse-E%26E%2010Dec2009%20FINAL.pdf 
Appendix V: Related Study Work and References

Appendix V: Related Study Work and References 

Page 76 2010 Special Reliability Assessment Scenario 

would be made to facilitate permitting of these Subtitle C facilities. Based on current disposal 

patterns, interviews with several utilities, and site-specific conditions such as land availability 

and watershed restrictions, EPRI assumed that a percentage of plants would be forced to dispose 

of CCRs in off-site commercial facilities, at higher costs for both transportation and disposal. 

The EPRI analysis also included special handling costs at the power plant to meet Subtitle C 

requirements. The NERC assessment did not include any special handling costs at the plant nor 

engineering retrofits that may be necessary for meeting Subtitle C standards. Finally, the NERC 

assessment assumed continued CCR utilization at current rates; EPRI ran simulations with both 

continued CCR use at the same rate and no CCR use. 

Follow-on Steps

In their regulatory proposal, EPA requested additional information on both off-site disposal costs 

and “upstream” management and storage costs associated with Subtitle C regulation. In response 

to the EPA’s request for additional cost data, EPRI is in the process of developing detailed 

engineering costs for Subtitle C regulation at the power plant as well as at CCR disposal sites. 

EPRI will share the engineering information and cost data with NERC when it is available. EPRI 

will prepare a technical report with the engineering and cost data in 4Q 2010 that will be publicly 

available. 
Terms Used in this Report

Terms Used in This Report 

2010 Special Reliability Assessment Scenario Page 77 

Terms Used in This Report

Adjusted Potential Capacity Resources — The sum of Deliverable Capacity Resources, 

Existing Other Resources, Future Other Resources (reduced by a confidence factor), Conceptual 

Resources (reduced by a confidence factor), and net provisional transactions minus all derates. 

(MW) 

Adjusted Potential Reserve Margin (%) — The sum of Deliverable Capacity Resources, 

Existing Other Resources, Future Other Resources (reduced by a confidence factor), Conceptual 

Resources (reduced by a confidence factor), and net provisional transactions minus all derates 

and Net Internal Demand shown as a percent of Net Internal Demand. 

Capacity Categories — See Existing Generation Resources, Future Generation Resources, 

and Conceptual Generation Resources. 

Conceptual Generation Resources — This category includes generation resources that are not 

included in Existing Generation Resources or Future Generation Resources, but have been 

identified and/or announced on a resource planning basis through one or more of the following 

sources: 

1. Corporate announcement 

2. Entered into or is in the early stages of an approval process 

3. Is in a generator interconnection (or other) queue for study 

4. “Place-holder” generation for use in modeling, such as generator modeling needed to 

support NERC Standard TPL analysis, as well as, integrated resource planning resource 

studies. 

Resources included in this category may be adjusted using a confidence factor (%) to reflect 

uncertainties associated with siting, project development or queue position. 

Deliverable Capacity Resources — Existing, Certain and Net Firm Transactions plus Future, 

Planned capacity resources plus Expected Imports, minus Expected Exports. (MW) 

Deliverable Reserve Margin (%) — Deliverable Capacity Resources minus Net Internal 

Demand shown as a percent of Net Internal Demand. 

Demand — See Net Internal Demand, and Total Internal Demand

Demand Response — Changes in electric use by demand-side resources from their normal 

consumption patterns in response to changes in the price of electricity, or to incentive payments 

designed to induce lower electricity use at times of high wholesale market prices or when system 

reliability is jeopardized. 

Derate (Capacity) — The amount of capacity that is expected to be unavailable on seasonal 

peak.

Existing, Certain (Existing Generation Resources) — Existing generation resources available to 

operate and deliver power within or into the Region during the period of analysis in the 

assessment. Resources included in this category may be reported as a portion of the full 

capability of the resource, plant, or unit. This category includes, but is not limited to the 

following: 
Terms Used in this Report

Terms Used in this Report 

Page 78 2010 Special Reliability Assessment Scenario 

1. contracted (or firm) or other similar resource confirmed able to serve load during the 

period of analysis in the assessment; 

2. where organized markets exist, designated market resource43 that is eligible to bid into 

a market or has been designated as a firm network resource; 

3. a Network Resource44, as that term is used for FERC pro forma or other regulatory 

approved tariffs; 

4. energy-only resources45 confirmed able to serve load during the period of analysis in 

the assessment and will not be curtailed;46 

5. capacity resources that cannot be sold elsewhere; and 

6. other resources not included in the above categories that have been confirmed able to 

serve load and not to be curtailed47 during the period of analysis in the assessment. 

Existing, Certain & Net Firm Transactions — Existing, Certain capacity resources plus Firm 

Imports, minus Firm Exports. (MW) 

Existing, Certain and Net Firm Transactions (%) (Margin Category) – Existing, Certain and 

Net Firm Transactions minus Net Internal Demand shown as a percent of Net Internal Demand. 

Existing Generation Resources — See Existing, Certain, Existing, Other, and Existing, but 

Inoperable.

Existing, Inoperable (Existing Generation Resources) — This category contains the existing 

portion of generation resources that are out-of-service and cannot be brought back into service to 

serve load during the period of analysis in the assessment. However, this category can include 

inoperable resources that could return to service at some point in the future. This value may vary 

for future seasons and can be reported as zero. This includes all existing generation not included 

in categories Existing, Certain or Existing, Other, but is not limited to, the following: 

1. mothballed generation (that cannot be returned to service for the period of the 

assessment); 

2. other existing but out-of-service generation (that cannot be returned to service for the 

period of the assessment); 

3. does not include behind-the-meter generation or non-connected emergency generators 

that normally do not run; and 

4. does not include partially dismantled units that are not forecasted to return to service. 

Existing, Other (Existing Generation Resources) — Existing generation resources that may be 

available to operate and deliver power within or into the Region during the period of analysis in 

the assessment, but may be curtailed or interrupted at any time for various reasons. This 

category also includes portions of intermittent generation not included in Existing, Certain. This 

category includes, but is not limited to the following: 

1. a resource with non-firm or other similar transmission arrangements; 

 

43 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this 

category, but rather must be subtracted from the appropriate category in the demand section. 44 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this 

category, but rather must be subtracted from the appropriate category in the demand section. 45 Energy Only Resources are generally generating resources that are designated as energy-only resources or have elected to be 

classified as energy-only resources and may include generating capacity that can be delivered within the area but may be 

recallable to another area (Source: 2008 EIA 411 document OMB No. 1905-0129).” Note: Other than wind and solar energy, 

WECC does not have energy-only resources that are counted towards capacity. 46 Energy only resources with transmission service constraints are to be considered in category Existing, Other. 47 Energy only resources with transmission service constraints are to be considered in category Existing, Other. 
Terms Used in this Report

Terms Used in This Report 

2010 Special Reliability Assessment Scenario Page 79 

2. energy-only resources that have been confirmed able to serve load for any reason 

during the period of analysis in the assessment, but may be curtailed for any reason; 

3. mothballed generation (that may be returned to service for the period of the 

assessment); 

4. portions of variable generation not counted in the Existing, Certain category (e.g., wind, 

solar, etc. that may not be available or derated during the assessment period); 

5. hydro generation not counted as Existing, Certain or derated; and 

6. generation resources constrained for other reasons. 

Expected (Transaction Category) — A category of Purchases/Imports and Sales/Exports with 

the following clarification: 

1. Expected implies that a contract has not been executed, but is in negotiation, projected 

or other. These Purchases or Sales are expected to be firm. 

2. Expected Purchases and Sales should be considered in the reliability assessments. 

Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports with the 

following clarification contract including: 

1. Firm implies a contract has been signed and may be recallable. 

2. Firm Purchases and Sales should be reported in the reliability assessments. The 

purchasing entity should count such capacity in margin calculations. Care should be 

taken by both entities to appropriately report the generating capacity that is subject to 

such Firm contract. 

Future Generation Resources (See also Future, Planned and Future, Other) — This category 

includes generation resources the reporting entity has a reasonable expectation of coming online 

during the period of the assessment. As such, to qualify in either of the Future categories, the 

resource must have achieved one or more of these milestones: 

1. Construction has started. 

2. Regulatory permits being approved, are any one of the following: 

a. site permit; 

b. construction permit; or 

c. Environmental permit. 

3. Regulatory approval has been received to be in the rate base. 

4. There is an approved power purchase agreement. 

5. Resources is approved and/or designated as a resource by a market operator. 

Future, Other (Future Generation Resources) — This category includes future generating 

resources that do not qualify in Future, Planned and are not included in the Conceptual category. 

This category includes, but is not limited to, generation resources during the period of analysis in 

the assessment that: 

1. may be curtailed or interrupted at any time for any reason; 

2. are energy-only resources that may not be able to serve load during the period of 

analysis in the assessment; 

3. are variable generation not counted in the Future, Planned category or may not be 

available or is derated during the assessment period; or 

4. is hydro generation not counted in category Future, Planned or derated. 

Resources included in this category may be adjusted using a confidence factor to reflect 

uncertainties associated with siting, project development or queue position. 
Terms Used in this Report

Terms Used in this Report 

Page 80 2010 Special Reliability Assessment Scenario 

Future, Planned (Future Generation Resources) — Generation resources anticipated to be 

available to operate and deliver power within or into the Region during the period of analysis in 

the assessment. This category includes, but is not limited to, the following: 

1. Contracted (or firm) or other similar resource; 

2. Where organized markets exist, a designated market resource48 that is eligible to bid 

into a market or has been designated as a firm network resource. 

3. A Network Resource49, as that term is used for FERC pro forma or other regulatory 

approved tariffs. 

4. Energy-only resources confirmed able to serve load during the period of analysis in the 

assessment and will not be curtailed50. 

5. Where applicable, is included in an integrated resource plan under a regulatory 

environment that mandates resource adequacy requirements and the obligation to serve. 

NERC Reference Reserve Margin Level (%) — Either the Target Reserve Margin provided by 

the Region/subregion or NERC assigned based on capacity mix (e.g., thermal/hydro). Each 

Region/subregion may have their own specific margin level based on load, generation, and 

transmission characteristics as well as regulatory requirements. If provided in the data 

submittals, the Regional/subregional Target Reserve Margin level is adopted as the NERC 

Reference Reserve Margin Level. If not, NERC assigned a 15 percent Reserve Margin for 

predominately thermal systems and 10 percent for predominately hydro systems.

Net Internal Demand: Total Internal Demand reduced by the total Dispatchable, Controllable, 

Capacity Demand Response equaling the sum of Direct Control Load Management, 

Contractually Interruptible (Curtailable), Critical Peak Pricing (CPP) with Control, and Load as a 

Capacity Resource. 

On-Peak (Capacity) — The amount of capacity that is expected to be available on seasonal 

peak. 

Potential Capacity Resources — The sum of Deliverable Capacity Resources, Existing Other 

Resources, Future Other Resources, Conceptual Resources, and net provisional transactions 

minus all derates. (MW) 

Potential Reserve Margin (%) — The sum of Deliverable Capacity Resources, Existing Other 

Resources, Future Other Resources, Conceptual Resources, and net provisional transactions 

minus all derates and Net Internal Demand shown as a percentage of Net Internal Demand. 

Prospective Capacity Reserve Margin (%) — Prospective Capacity Resources minus Net 

Internal Demand shown as a percentage of Net Internal Demand. 

Prospective Capacity Resources — Deliverable Capacity Resources plus Existing, Other 

capacity resources, minus all Existing, Other deratings (including derates from variable 

resources, energy only resources, scheduled outages for maintenance, and transmission-limited 

resources), plus Future, Other capacity resources (adjusted by a confidence factor), minus all 

Future, Other deratings. (MW) 

Provisional (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract 

including Purchases and Sales that are expected to be provisionally firm. Provisional implies 

 

48 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this 

category, but rather must be subtracted from the appropriate category in the demand section. 

49 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this 

category, but rather must be subtracted from the appropriate category in the demand section. 50 Energy only resources with transmission service constraints are to be considered in category Future, Other. 
Terms Used in this Report

Terms Used in This Report 

2010 Special Reliability Assessment Scenario Page 81 

that the transactions are under study, but negotiations have not begun. Provisional Purchases and 

Sales should be considered in the reliability assessments. 

Reference Reserve Margin Level — See NERC Reference Reserve Margin Level

Reserve Margin (%) —Roughly, Capacity minus Demand, divided by Demand or (CapacityDemand)/Demand. Replaced Capacity Margin(s) (%) for NERC Assessments in 2009. 

Target Reserve Margin (%) — Established target for Reserve Margin by the Region or 

subregion. Not all Regions report a Target Reserve Margin. The NERC Reference Reserve 

Margin Level is used in those cases where a Target Reserve Margin is not provided. 

Transfer/Transaction (See also Firm, Non-Firm, Expected and Provisional) — Contracts for 

Capacity are defined as an agreement between two or more parties for the Purchase and Sale of 

generating capacity. Purchase contracts refer to imported capacity that is transmitted from an 

outside Region or subregion to the reporting Region or subregion. Sales contracts refer to 

exported capacity that is transmitted from the reporting Region or subregion to an outside Region 

or subregion. For example, if a resource subject to a contract is located in one Region and sold 

to another Region, the Region in which the resource is located reports the capacity of the 

resource and reports the sale of such capacity that is being sold to the outside Region. The 

purchasing Region reports such capacity as a purchase, but does not report the capacity of such 

resource. Transmission must be available for all reported Purchases and Sales. 
Abbreviations Used in this Report

Abbreviations Used in This Report

Page 82 2010 Special Reliability Assessment Scenario 

Abbreviations Used in This Report

316(b) Clean Water Act – Section 316(b), Cooling Water Intake Structures 

APCR Adjusted Potential Capacity Resources 

AZ-NM-SNV Arizona-New Mexico-Southern Nevada (subregion of WECC) 

BTA Best Technology Available 

CA California (subregion of WECC) 

CA-MX-US California-México (subregion of WECC) 

CAIR Clean Air Interstate Rule 

CAMR Clean Air Mercury Rule 

CATR Clean Air Transport Rule 

CCB Coal Combustion Byproducts 

CCR Coal Combustion Residuals 

DOE U.S. Department of Energy 

EIA Energy Information Agency (of DOE) 

EPA Environmental Protection Agency 

EPRI Electric Power Research Institute 

ERCOT Electric Reliability Council of Texas 

EVA Energy Venture Associates 

FERC U.S. Federal Energy Regulatory Commission 

FGD Flue gas desulfurization 

FRCC Florida Reliability Coordinating Council 

GHG Greenhouse Gas 

gpm Gallons per minute 

GW Gigawatt 

GWh Gigawatt hours 

HACI Halide-treated Activated Carbon Injection 

HAP Hazardous Air Pollutants 

MACT Maximum Achievable Control Technology 

mgd Million gallons per day 

MRO Midwest Reliability Organization 

MW Megawatts (millions of watts) 

MWH Megawatt hours 

NAAQS National Ambient Air Quality Standards 

NERC North American Electric Reliability Corporation 

NESHAP National Emissions Standards of Hazardous Air Pollutants 

NOx Nitrogen Oxide 

NPCC Northeast Power Coordinating Council 

NWPP Northwest Power Pool Area (subregion of WECC) 

NYPP New York Power Pool 

PV Photovoltaic 

RCRA Resource Conservation Recovery Act 

RFC ReliabilityFirst Corporation 

RMPA Rocky Mountain Power Area (subregion of WECC) 

RMR Reliability Must Run 

RMRG Rocky Mountain Reserve Group 

RP Reliability Planner 

SCR Selective Catalytic Reduction 

SERC SERC Reliability Corporation 

SO2 Sulfur Dioxide 

SPP Southwest Power Pool 

tpy Tons per year 

TRE Texas Regional Entity 

TVA Tennessee Valley Authority 

VACAR Virginia and Carolinas (subregion of SERC) 

WECC Western Electricity Coordinating Council 
Reliability Assessment Subcommittee Roster

Reliability Assessment Subcommittee Roster 

2010 Special Reliability Assessment Scenario Page 83 

Reliability Assessment Subcommittee Roster

 Chair Mark J. Kuras 

Senior Engineer 

PJM Interconnection, L.L.C. 

955 Jefferson Ave 

Valley Forge Corporate Center 

Norristown, Pennsylvania 

19403 

610-666-8924 

610-666-4779 Fx 

kuras@pjm.com 

Regional Entity Representatives — Members of the Electric Reliability Organization: 

Reliability Assessment and Performance Analysis Group (ERO-RAPA Group)

Vice 

Chair, 

FRCC 

Vince Ordax 

Manager of Planning 

Florida Reliability Coordinating 

Council 

1408 N. Westshore Blvd 

Tampa, Florida 33607 

813-207-7988 

813-289-5646 Fx 

vordax@frcc.com 

MRO John Seidel 

Principal Engineer 

Midwest Reliability Organization 

1970 Oakcrest Avenue 

Roseville, Minnesota 55113 

651-855-1716 

651-855-1712 Fx 

ja.seidel@midwestreliability.org 

NPCC John G. Mosier, Jr. 

AVP-System Operations 

Northeast Power Coordinating 

Council, Inc. 

1040 Avenue of the Americas10th floor 

New York, New York 10018 

212-840–4907 

212-302 –2782 Fx 

jmosier@npcc.org 

RFC Jeffrey Mitchell, P.E. 

Director, Engineering 

ReliabilityFirst Corporation 

320 Springside Dr. 

Suite 300 

Akron, Ohio 44333 

330-247-3043 

330-456-3648 Fx 

jeff.mitchell@rfirst.org 

SERC Herbert Schrayshuen 

Director, Reliability 

Assessment 

SERC Reliability Corporation 

2815 Coliseum Centre Drive 

Charlotte, North Carolina 28217 

704-940-8223 

315-439 1390 Fx 

hschrayshuen@serc1.org 

SPP David Kelley 

Manager, Engineering 

Administration 

Southwest Power Pool 

16101 La Grande Drive 

 Little Rock, Arkansas 72225 

501-688-1671 

501-821-3245 Fx 

dkelley@spp.org 

TRE William C. Crews, P.E. 

Regional Planning 

Assessment Engineer, Sr. 

Texas Regional Entity 

2700 Via Fortuna 

Suite 225 

Austin, Texas 78746 

512-275-7533 

curtis.crews@texasre.org 

WECC David J. Godfrey 

Director, Standards 

Development and Planning 

Services 

Western Electricity Coordinating 

Council 

155 North 400 West, Suite 200 

Salt Lake City, Utah 84103 

801-883-6863 

801-582-3918 Fx 

dgodfrey@wecc.biz 

 
Reliability Assessment Subcommittee Roster

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Page 84 2010 Special Reliability Assessment Scenario 

 

TRE, 

ISO/RTO 

Dan M. Woodfin 

Director, System Planning 

Electric Reliability Council of 

Texas, Inc. 

2705 West Lake Dr. 

Taylor, Texas 76574 

512-248-3115 

512-248-4235 Fx 

dwoodfin@TRE.com 

 

MRO Hoa V. Nguyen 

Resource Planning 

Coordinator 

Montana-Dakota Utilities Co. 

400 North 4th Street 

Bismarck, North Dakota 58501 

701-222-7656 

701-222-7872 Fx 

hoa.nguyen@mdu.com 

 

ISO/RTO Peter Wong 

Manager, Resource 

Adequacy 

ISO New England, Inc. 

One Sullivan Road 

Holyoke, Massachusetts 01040-

2841 

413-535-4172 

413-540-4203 Fx 

pwong@iso-ne.com 

 

RFC Bernie M. Pasternack, P.E. 

Managing Director - 

Transmission Asset 

Management 

American Electric Power 

700 Morrison Road 

Gahanna, Ohio 43230-8250 

614-552-1600 

614-552-1602 Fx 

bmpasternack@aep.com 

 

RFC, 

IOU 

Esam A. F. Khadr 

Manager - Delivery 

Planning 

Public Service Electric and Gas 

Co. 

80 Park PlazaT-14A 

Newark, New Jersey 07102 

973-430-6731 

973-622-1986 Fx 

Esam.Khadr@pseg.com 

 

SERC Hubert C. Young 

Manager of Transmission 

Planning 

South Carolina Electric & Gas 

Co. 

220 Operations Way 

MC J37 

Cayce, South Carolina 29033 

803-217-2030 

803-933-7264 Fx 

cyoung@scana.com

 

SERC, 

IOU, 

DCWG 

Chair 

K. R. Chakravarthi 

Manager, Interconnection 

and Special Studies 

Southern Company Services, Inc. 

Southern Company Services, 

Birmingham, Alabama 35203 

205-257-6125 

205-257-1040 Fx 

krchakra@southernco.com 

 

WECC, 

State/ 

Municipal 

Utility 

James Leigh-Kendall 

Regulatory Compliance 

Officer 

Sacramento Municipal Utility 

District 

6002 S Street 

b303 

Sacramento, California 95852 

916-732-5357 

916-732-7527 Fx 

jleighk@smud.org 

 

ISO/RTO Jesse Moser 

Manager, Regulatory 

Studies 

Midwest ISO, Inc. 

P.O. Box 4202 

Carmel, Indiana 46082-4202 

612-718-6117 

jmoser@midwestiso.org 

 

ISO/RTO John Lawhorn, P.E. 

Director, Regulatory and 

Economic Standards 

Transmission Asset 

Management 

Midwest ISO, Inc. 

1125 Energy Park Drive 

St. Paul, Minnesota 55108 

651-632-8479 

651-632-8417 Fx 

jlawhorn@midwestiso.org 

 

CanadaAt-Large, 

ISO/RTO 

Dan Rochester, P. Eng. 

Manager, Reliability 

Standards and Assessments 

Independent Electricity System 

Operator 

Station A, Box 4474 

Toronto, Ontario M5W 4E5 

905-855-6363 

905-403-6932 Fx 

dan.rochester@ieso.ca 

 
Reliability Assessment Subcommittee Roster

Reliability Assessment Subcommittee Roster 

2010 Special Reliability Assessment Scenario Page 85 

FERC Keith N. Collins 

Manager, Electric Analysis 

Group 

Federal Energy Regulatory 

Commission 

888 First Street, NE 

Washington, D.C. 20426 

202-502-6383 

202-219-6449 Fx 

keith.collins@ferc.gov

 

FERC Sedina Eric 

Electrical Engineer 

Federal Energy Regulatory 

Commission 

888 First Street, NE, 92-77 

Washington, D.C. 20426 

202-502-6441 

202-219-1274 Fx 

sedina.eric@ferc.gov 

 

RFC, 

LFWG 

Chair 

Bob Mariotti 

Supervisor – Short Term 

Forecasting 

DTE Energy 

2000 Second Avenue 

787WCB 

Detroit, Michigan 48226-1279 

313-235-6057 

313-235-9583 Fx 

mariottir@dteenergy.com 

 

FRCC 

Alternate 

John Odom, Jr. 

Vice President of Planning 

and Operations 

Florida Reliability Coordinating 

Council 

1408 N. Westshore Blvd., Suite 

1002 

Tampa, Florida 33607-4512 

813-207-7985 

813-289-5646 Fx 

jodom@frcc.com 

 

MRO 

Alternate 

Salva R. Andiappan 

Manager – Reliability 

Assessment and 

Performance Analysis 

Midwest Reliability Organization 

2774 Cleveland Avenue N. 

Roseville, Minnesota 55113 

651-855-1719 

651-855-1712 Fx 

sr.andiappan@midwestreliability.org 

 

RFC 

Alternate 

Paul Kure 

Senior Consultant, 

Resources 

ReliabilityFirst Corporation 

320 Springside Drive 

Suite 300 

Akron, Ohio 44333 

330-247-3057 

330-456-3648 Fx 

paul.kure@rfirst.org 

 

SPP 

Alternate 

Alan C Wahlstrom 

Lead Engineer, 

Compliance 

16101 La Grande Dr. 

Suite 103 

Littlerock, Arkansas 72223 

501-688-1624 

501-664-6923 Fx 

awahlstrom@spp.org 

 

WECC 

Alternate 

Bradley M. Nickell 

Renewable Integration and 

Planning Director 

Western Electricity Coordinating 

Council 

155 North 400 West, Suite 200 

Salt Lake City, Utah 84103 

801-455-7946 

720-635-3817 

bnickell@wecc.biz 

 

OC 

Liaison 

Jerry Rust 

President 

Northwest Power Pool 

Corporation 

7505 NE Ambassador Place, St R 

Portland, Oregon 97035 

503-445-1074 

503-445-1070 Fx 

jerry@nwpp.org 

 

OC 

Liaison 

James Useldinger 

Manager, T&D System 

Operations 

Kansas City Power & Light Co. 

PO Box 418679 

Kansas City, Missouri 64141 

816-654-1212 

816-654-1189 Fx 

jim.useldinger@kcpl.com 

 

Observer 

DOE 

Patricia Hoffman 

Acting Director Research 

and Development 

Department of Energy 

1000 Independence Avenue 

SW 6e-069 

Washington, D.C. 20045 

202-586-1411 

patricia.hoffman@hq.doe.gov 

 
Reliability Assessment Subcommittee Roster

Reliability Assessment Subcommittee Roster

Page 86 2010 Special Reliability Assessment Scenario 

Observer 

DOE 

Peter Balash 

Senior Economist 

U.S. Department of Energy 

626 Cochrans Mill Road 

P.O. Box 10940 

Pittsburgh, Pennsylvania 15236 

412-386-5753 

412-386-5917 Fx 

balash@netl.doe.gov 

 

Observer 

DOE 

Erik Paul Shuster 

Engineer 

U.S. Department of Energy 

626 Cochrans Mill Road 

P.O. Box 10940 

Pittsburgh, Pennsylvania 15236 

412-386-4104 

erik.shuster@netl.doe.gov 

 

Observer 

DOE 

Maria A. Hanley 

Program Analyst 

U.S. Department of Energy 

626 Cochrans Mill Road 

MS922-342C 

P.O. Box 10940 

Pittsburgh, Pennsylvania 15236 

412-386-5373 

412-386-5917 Fx 

maria.hanley@netl.doe.gov 

Observer C. Richard Bozek 

Director, Environmental 

Policy 

Edison Electric Institute 

701 Pennsylvania Avenue, NW 

Washington, D.C. 20004 

202-508-5641 

rbozek@eei.org 

 

Observer Erick Hasegawa 

Engineer 

Midwest ISO, Inc. 

Carmel Office 

PO Box 4202 

Carmel, Indiana 46082 

317-910-8626 

ehasegawa@midwestiso.org 
North American Electric Reliability Corporation Staff Roster

North American Electric Reliability Corporation Staff Roster 

2010 Special Reliability Assessment Scenario Page 87 

North American Electric Reliability Corporation

Staff Roster

116‐390 Village Boulevard   

Princeton, New Jersey 08540

609‐452‐8060

609‐452‐9550 Fax

Reliability Assessment and Performance Analysis Group 

Mark G. Lauby Director of Reliability

Assessment and

Performance Analysis

mark.lauby@nerc.net

John Moura

Eric Rollison

Matt Turpen

Technical Analyst,

Reliability Assessment

and Performance Analysis

Engineer,

Reliability Assessment

and Performance Analysis

Technical Analyst,

Reliability Assessment

and Performance Analysis

john.moura@nerc.net

eric.rollison@nerc.net

 matt.turpen@nerc.net
the reliability of the

to ensure

bulk power system reliability of the