# 2010 Special Reliability Scenario Asses s ment: 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 

# October 2010

### to ensure the 

## reliability of the bulk power system 

# N E R C ’ s M i s s i o n

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. user s, owners, and operators of the BPS, a nd made compliance with those standards mandatory and enforceable. In Canada , NERC presently has memorandums of unde rstanding 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 Onta rio and New Brunswick as a ma tter of provincial law. NERC has an agreement with Manitoba Hydro making reliability st andards 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 “elec tric 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 work ing 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 Reliability First Corporation WECC Western Electricity Coordinating Council2010 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 Us ed 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 Hazar dous 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 Hazar dous 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 .............................................. 87ExecutiveSummary Executive Summary

Page I 2010 Special Reliability Assessment Scenario 

# E x e c u t i v e S u m m a r y
In the United States, several regulations are in the process of being proposed by the U.S. Environmental Protection Agency (EPA) that dir ectly affect the electric industry. Depending on the outcome of any or all of these potential regula tions, 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 supplie rs to either invest in retrof itted environmental controls at existing generating plants or retire them. The mo st significant pr oposed EPA rules have been in development for over ten years and are currently undergoing court-ordered revisi ons 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 relia bility 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 significan tly 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-w ide environmental control retrofit effort. This assessment examines four potential EPA ru lemaking 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 (ref erred 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 Pl anning 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 regul ations individually and in aggregate. Additionally, this assessment considers the number of generating units requiring retrofitting by NERC Region and subregion to demonstrate the ma gnitude 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 th e additional environmenta l controls. For each

2 A 19 percent reduction represents the resu lts of the total capacity loss in the Strict Case for 2018 as a percentage of the to tal coal, gas, and oil steam units included in the 2009 Long-Term Reliability Asse ssment Reference Case. Refer to Appendix III and IV for details values.ExecutiveSummary 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 Ca se) provide a range of sensitivities, with the Strict Case incorporating more stringent rule assumptions a nd 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 rule s 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 ma nner 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 Assessed 5

3 Unit is retired if (CC+FC+VC) / (1-DR) > RC, where: CC = requ ired 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 potentia l 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 retrofitExecutiveSummary Executive Summary

Page III 2010 Special Reliability Assessment Scenario ERCOT 2015/2018 New England 2015/2015

AZ/NM/SNV 2015/2015 California 2018/>2018 RMP A 2015/>2018

SPP 2015/>2018

MRO-US 2013/2015

RFC 2015/2015

Central 2015/2015

V ACAR 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 be y ond 2018. ERCOT 2015/2018 New England 2015/2015

AZ/NM/SNV 2015/2018 California >2018/>2018 RMP A 2015/>2018

SPP 2015/>2018

MRO-US 2013/2018

RFC 2015/2018

Central >2018/>2018 V ACAR 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 NE RC’s Reference Margin Level

Figure C: Strict Case Deliverable a nd Adjusted Potential Resources Reserve Margins Compared to NERC’ s Reference Margin LevelExecutiveSummary Executive Summary

2010 Special Reliability Assessment Scenario Page IV 

### Without additional power production or demand-si de resources beyond thos e in current regional plans, the combined effects of the four EPA ru les (Combined EPA Regulation Scenario) are shown to significantly affect Planning Reserve Margins and, in most Re gions/subregions, more resources would be required to maintain NERC Reference Ma rgin 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 significantl y affects projected Planning Reserve Margins for a majority of the NERC Re gions and subregions. Potentially significant reductions in capacity within a five-year period may require the additi on 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 Regulati ons May Have Signifi cant Impacts on Forecast Planning Reserve Margins

Overall, impacts on Planning Reserv e 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 mo re 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 convergen ce of overlapping replacement/retrofit generation capacity projects and heavy U.S. infr astructure projects in other sectors. Pote ntial 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 Shoul d 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 approximate ly 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 conti nue operations. The remaining capacity may also be converted assuming it is una ffected 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 MarginsExecutiveSummary Executive Summary

Page V 2010 Special Reliability Assessment Scenario 

### Summary of Capacity Impacts

Ranked in descending order of impact severity , the regulatory impact s of MACT, CATR and finally CCR on retirements, individually also acce lerate 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 Ca ses) 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 potential ly problematic.

 The CATR could have significant impacts as s oon as 2015 should EPA require emission limits with no offset trading, resulting in po tentially 3-7 GW of pot ential retirements and derated capacity, requiring retrofitting of 28-57 6 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 im pact, triggering the retirement of up to 12 coal units (388 MW). Cost sensitivity asse ssment for CCR reveals that retirements could reach capacity of 2 GW (53 units) should co sts 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 Comb ined EPA Regulation Scenario. The MACT, CATR, and CCR Rules Also C ontribute to Reductions in Capacity

This report also identifies a number of tools th e 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 addi tion of new resources not yet proposed could help partially alleviate projected capacit y losses in severely affected regions. Price signaling for the need of new resources will be important. Industry coordination will be vita l to ensure retrofits are completed in a way that does not diminish reliability. In addition, statutory an d regulatory safeguards al so allow the EPA, the President of the United States, and the Depart ment of Energy to extend or waive compliance under certain circumstances. Implementing these indu stry and regulatory tool s may be critical to maintain the reliability of the bulk power system. Second tier effects, including generation deliverab ility or stability impacts, must also be considered. For example, transmission system c onstruction, enhancements, reconfiguration and development of new operating procedures may be n ecessary in some areas, all of which can create additional timing considerations. EPA Regulations Create a Need for Prompt Industry Response and ActionExecutiveSummary 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 45,000MW 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 90,000MW Figure E: Potential Capacity Reduction Due to the Combined EPA Regulation ScenarioExecutiveSummary 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 th e current fuel mix, to one that includes generation that can meet proposed EPA regulations. The pace and aggressiveness of these envi ronmental 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 arra y of tools at their disposal to moderate reliability impacts, incl uding, among other things, granting required extensions to inst all emission controls. Regulators, system operators, and in dustry 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 market s 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 implica tions 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 assessm ent should include impacts to operating reliability and second tie r impacts (e.g., deliverability, stability, localized issues, outage scheduling, operating procedures, and industry coordination) of fo rthcoming EPA regulations.

Note: The results in this report are based on a ssumptions of potential EPA regulations. The regulations discussed in this report are not yet final and all complian ce deadlines, emission limitations, and retrofit costs may differ once the rules are finaliz ed. 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 re source loss from these pot ential rules represent the loss of capacity should no more resources be added beyond the reference case.RegulatorsIndustryNERCIntroduction Introduction

2010 Special Reliability Assessment Scenario Page 1 

# I n t r o d u c t i o n
In the United States (U.S.), the electric power industry has made significan t capital investment in air pollution control technologies to remove sulfur dioxide (SO 2 

### ), particulate matter and nitrogen oxide (NO x 

### ) emissions at fossil-fired pow er plants. The bulk of th ese capital investments were made to existing coal plants in order to comp ly with evolving environmental regulations. Several regulations are in the process of bei ng proposed by the U.S. Environmental Protection Agency (EPA) requiring additional retrofits. Depending on the fina l determinations, the cost to comply with the final regulations may result in retirements of generation. This assessment is designed to consider four poten tial 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 C ontrol Technology (MACT) Standards; 3. Clean Air Transport Rule (CATR); and 4. Coal Combustion Residuals (CCR) Assumptions (described in detail later in this s ection) have been made in this assessment to measure the potential impacts on Planning Reserv e 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 co st, FC = current fixed O&M, VC = variable O&M including fuel cost, RC = replacement cost all in $/MWH, and DR = derate fact or 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 gene rating electricity and therefore, they are located on large water bodies or high flow-rate rivers. Many of th ese facilities use oncethrough cooling systems that draw large volum es of water from the ocean, lake, or river used to condense steam, re turning the warmer water ba ck into the body of water immediately after use. Sec tion 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 CO 2 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. EP A 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 cooli ng 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 a nd EPA subsequently suspended its Phase II implementation 9 

### and is in process of developing a new rule to address the court concerns. Steam generating units employing once-throu gh cooling systems could be required to replace their cooling water systems w ith 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 equipmen t. This resource assessment and its implications for responses in the power ge neration market should inform and affect power plant owner’s choices a bout plant retirement s, plant additions, and unit retrofits.

2. Title I of Clean Air Act – National Emission Standards for Hazardous Air Pollutants for the electric power indus try, or Maximum Achievable Control Technology (MACT) Standards NESHAP or MACT requires coal -fired plants to reduce thei r 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 mercur y is “appropriate and necessary” for coal- and o il-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 co al-based power plants. The CAMR used a market-based cap-and-trade approach to requ ire emissions reductions in two phases: 1) a cap of 38 tons in 2010 and 2) fifteen tons af ter 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 regul ation of nickel emissions fr om 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 EP A's decision to "de-list" mercury as a hazardous air pollutant (HAP). The Court he ld that EPA's reversal of the December 2000

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

2010 Special Reliability Assessment Scenario Page 3 

### regulatory finding was unlawful. 10 

### The Court vacated both th e reversal and the CAMR. In February 2009, the acting Solici tor General, on behalf of EPA, filed a motion with the Supreme Court to dismiss the CAMR case. The motion states une quivocally that EPA will develop MACT standards for the utility industry under section 112 of the Clean Air Act. EPA is now obligated under a consen t 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 me rcury control requirements.

Section 112 in Title I of th e 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 co al- and oil-fired power plants. This could require significant additional emissions cont rol equipment beyond what is necessary for compliance with mercury-only regulations. Unde r the Clean Air Act, EPA is obligated to implement the stricter standards within three years after the regulati on becomes final.

3. Clean Air Transport Rule (CATR) On July 6, 2010, EPA proposed a CATR prog ram to reduce long-range transport of pollutants significantly contributing to dow nwind state ground-leve l ozone and fine particle non-attainment problems. This pr ogram 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 nitroge n 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 inte rstate trading am ong power plants; 2) the EPA Alternative 1 option which sets state emission budget caps and allows intrastate trad ing 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 reliabili ty 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 Com bustion 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 dispos al and triggered calls for tighter regulation. 12 

### In May 2010, EPA proposed two options to re gulate 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 al so being developed for proposal by the EP A that would require more environmental

controls not covered by CATR, regulating NOx in particular. Th is 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 contro l technologies needed. 12 Disposal cells are used for settling and storing the coal fly as h. This accident occurred at TVA’s Kingston Fossil Plant Eas t

Tennessee. http://www.tva.gov/k ingston/index.htm 13 http://www.epa.gov/wastes/nonh az/industrial/speci al/fossil/ccr-rule/ccr-rule-prop.pdfIntroduction Introduction

Page 4 2010 Special Reliability Assessment Scenario 

### 1) Regulate the coal fly ash as a special wast e under subtitle C (hazar dous waste) of the Resource Conservation and Recovery Act (RCRA). Under this option, facilities would need to close their surface ash impound ments within five years and dispose of the ash (past and future) in a regulate d 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 lin ers for new landfills and groundwater monitoring of existing landfills. Beyond regulating coal-ash and residuals be ing 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 su ch 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 as h as a hazardous material, potentially resulting in lost revenue from the recycling market. Furthermore, EPA is also considering a poten tial modification to the subtitle D option, called “D prime.” Under the “D prime” op tion, existing surface impoundments would not have to close or install composite liners but co uld continue to operate for their useful life. Also in the “D prime” option, the other elem ents of the subtitle D option would remain the same. However, because no proposal ha s been made, this option is not included. Timeline for Potential EPA Regulations
EPA has some flexibility in setting its complian ce schedule for all potential rules except MACT (see Figure 1). Based upon curren t 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 regul ations are expected to be finalized in July 2012. It is anticipated that at least fi ve 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 c ould cause potential bottl enecks and delays in engineering, permitting and construction. The risk of project delay increa ses if EPA decides on a compressed compliance schedule. The timing for scheduling unit outages to tie-in the environmental equipment becomes critical. Furt her, demand for critical equipment and supplies could potentially exceed production capacity and result in shorta ges and price escalations. However, surveys of labor or manufacturing were not conducted bey ond 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 Scenar io reflects the effects of the outcomes from the individual regulation cases working in aggreg ate. 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 EP A proposed rules are not ye t final, the Moderate Case and the Strict Case requ ire expert judgment and sound a ssumptions 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 

### CCRIntroduction Introduction

Page 6 2010 Special Reliability Assessment Scenario 

### In this reliability assessment, “economically vulne rable” generation capacity identifies units that would retire because of a specifi c potential environmental regulation. Unit retirement is assumed when the generic required cost of complianc e with the proposed environmental regulation exceeds the cost of replacement power. In some cases, the costs imposed by the potential EPA regulations may cause “accelerate d” or “early” retirement of unit generation capacity for an unknown time period. For the purpose of this a ssessment, replacement power costs were based on new natural gas generation capacity. 14 

### If the unit’s retrofit cost s are less than the cost of replacement power, then the unit is marked to be upgraded and retr ofitted to meet the requirements of the potentia l environmental regulation, i.e. , it is not considered “economically vulnerable” for retirement. More discu ssion 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, re placement generation projects may encounter scheduling difficulties and scheduled retrofits ma y 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 ba sed 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 c onstruction 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 measuri ng the potential resource implications through impacts on Planning Reserve Margins and identifi cation of Regions/subregions where additional Regional resources may be required. The reference case for this study is based on resource projections contai ned in NERC’s 2009 Long-Term Reliability Assessment. 17


### The impacts of potential EPA regulations may al so have second tier effects on reliability, beyond resource adequacy. Resource deliverability, out age scheduling/constructi on constraints, local pockets of retirements, and transmission needs ma y also affect bulk power system reliability. While these issues were not studied in this asse ssment, the industry will need to resolve these
concerns.

14 The model does not consider potenti al natural gas price fluctuations. 15 Using a different retirement method may produce different results. For in stance, assessing genera tion on future asset performance may potentially incr ease 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 environm ental 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.pdfIntroduction 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 Rese rve Margins for two sensitivity cases (Moderate Case and Strict Case) for each re gulation (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 Regi ons and Subregions (see Figure 3); and 4. provide the results to NERC’s stakeholders, industry leader s, policymakers, regulators, and the public. Figure 3: NERC US Subregions Assessed in this Report

Cost factors affect generating units as a “snapsho t” 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 ec onomical replacement power alternatives available for compliance. Therefore, modeled years illust rate 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-Re trofit_of_Once-Through_Generation_090908.pdf 19 DOE provided NERC a listing of vulnerable un its (totaling approximately 240 GW). Th is information was supplemented by

identifying those units that were expected to retire during th e study timeframe, along with perm itting dates. NERC reviewed the impact of either retrofit ting units with existing once-through-cooling system s 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 th at there are only two basic choices to consider when complying with the potential EP A regulations. The two choices are:

1. retrofit the generation unit and continue operations; or 2. retire the generation unit and re place 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 factor s 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 generi c required cost of compliance with the proposed environmental regulation exceeds the cost of re placement power. As mentioned before, replacement power was considered to be gas-fired capac ity. 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 additiona l 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 carbo n reduction requirements. In practice, however, power suppliers are likely to consider the additi onal risk from uncertain future actions/rules in the U.S., such as future CO 2 

### legislation, when making plant inve stment decisions. Depending on how power suppliers quantif y these risks, unit retirements may be higher than t hose projected in this assessment. Additionally, the report did not address a ny other climate change legislation. Other assumptions affecting this reliab ility assessment include the following:

o Excludes plant retirements already comm itted or announced (13 GW) and excludes generation units not included in the NERC 2009 Long Term Reliability Assessment 23 

### 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, transportati on companies, energy marketing companies and

traders, industry organizations, etc. http://evainc.com/ 21 Ibid. 11 22 The analysis also did not address Na tional Ambient Air Quality Standards (N AAQS) [ June 2010 1-hour sulfur dioxide

standard, February 2010 1-hour nitrogen dioxide standard, Octo ber 2010 revised 8-hour ozone stan dards (primary and possibly secondary), November 2011 revise d particulate matter standards (primary and possibly secondary), the mid-2012 Transport Rule II following the October 2010 revi sed ozone standards, and the 2013 Transport Rule III following the November 2011 revised particulate matter standard s], 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 requi red 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 m odified sources emitting 75,000 t ons per year (tpy) will be subject to Best Available Control Technology (BACT) requirement s. 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.pdfIntroduction Introduction

2010 Special Reliability Assessment Scenario Page 9 

### commitments based on the 2009 Long Term Reliability Assessment. Therefore, any capacity reduction from these units ha s 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 environmen tal 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 co mpliance 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 gene ration 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 s hortages, and escalation of compliance costs could present challenges to meet the compressed time schedule.

o Compliance costs (capital, O&M and perf ormance changes) are based upon current average retrofit costs with existing technology. The assess ment does not evaluate the compliance cost increases resulting from a r un-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 underest imate 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 cont rols. 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 wide ly based upon land availa bility, geology, and state disposal permit requirements. In th is assessment, an EPA assumption of onsite disposal is adopted, and the EPA calculated di sposal costs are simila r to those employed. However, if onsite disposal were prohibite d, the plant would incur additional costs to transport the ash and residuals to a prope rly permitted landfill. These costs could be significant, but cannot be estimat ed without a site-specific as sessment. For these reasons, sensitivity comparisons were co mpleted for CCR disposal costs.

o Power suppliers will need to bring their units offline to inte rconnect their new or retrofitted environmental contro ls. During these periods, s uppliers will lose potential revenues and require use of replacement powe r. While the capital and O&M costs are incorporated into the compliance decision criteria, the replacement purchased power costs during these integration shutdowns ha ve not been included and are unlikely to change or accelerate unit retirement decisi ons. However, these impacts would have the greatest effect on the nuclear plants that w ould 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-th rough-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 characteristics 26 

### of nuclear generation versus tr aditional 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 reti rement, additional generation capacity loss may result.

o Generating units identified in this assessm ent 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 suita ble 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 ge neration mix from environmental compliance measures ( e.g. , a shift from coal to natural gas fuel). Delivered natural gas and coal pr ices are fixed and do not change based on the level of retirements or the level of new repl acement 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 us e of other sorbent in jection technologies ( e.g., trona) as an alternative. For trona, capital costs would be lower, but higher operating costs would result. Limestone sc rubbers are the norm in the United States, although, this technology has been used at ol der plants where owners did not want to make the larger capital invest ment. Further, while some futu re plants may opt for trona vs. a limestone scrubber, a majority of plants (greater than 97 percen t) will use limestone.

o Delivered natural gas, coal and oil prices we re based on the forecasts of EVA as of May 2010. Ten-year forward averages are appl ied for 2013, 2015 and 2018. Varying these price assumptions may produce diffe rent results. The base wholesale fuel price forecasts are depicted in Figure 4 on an undelivered basis.

24 http://www.snl.com/InteractiveX/a rticle.aspx?CDID=A-10616386-10806&KPLT=2 25 http://www.swrcb.ca.gov/water _issues/programs/npdes/docs/cwa 316may2010/otcpolicy_final050410.pdf 26 e.g., Lower GHG emissions, longer in-s ervice operations, higher avai lability, baseload resource 27 DOE, 2008 http://www.oe.energy.gov/Documentsa ndMedia/Cooling_Tower_Report.pdfIntroduction Introduction

2010 Special Reliability Assessment Scenario Page 11 

### Figure 4: Wholesale Fuel Price Assu mptions 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% $ per MMBtu (constant 2010$)

S=Sulfur ContentIntroduction Introduction

Page 12 2010 Special Reliability Assessment Scenario 

### Some Unit Retirements Spread Through Time
Because the implementation of multiple EPA regula tions 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 exp ected outcome, in certain instances, some of the retirement and waivers were simulated earlier in tim e, 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 th eoretically 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 re tire, each designated plant’s economics are ranked from the most expensive to least expe nsive production costs. The units with the most expensive plant costs we re retired first for Section 316(b) and CCR. Conversely, the units with the lowest cost plan t economics were upgraded first.

 MACT: For the Moderate Case only, 60 percent of units that are designated to upgrade environmental controls by 2015 receive wa ivers 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 economic s 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.ScenarioResults Scenario Results

2010 Special Reliability Assessment Scenario Page 13 0 ‐ 2 % REDUCTION 2 ‐ 4 % REDUCTION 4 ‐ 6 % REDUCTION 6 ‐ 9 % REDUCTION
> 9 % REDUCTION 

# S c e n a r i o R e s u l t s
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 poten tial EPA rules may have significant economic impacts on generating units, potentially affectin g the reliability of bulk power system as measured by significant declines in Planning Re serve 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 accelerate d 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 un its 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 ma ny Regions/subregions, Planning Reserve Margins fall below the NERC Reference Margin Level, indicating the need for more
resources. The potential retirement and deratings affect re source portfolios in all eight NERC Regions, but especially in the ERCOT, MRO, NPCC, SE RC, and NPCC Regions. The most significant individual impacts are due to the Section 316 (b) regulation, then MA CT, CATR and finally CCR. However, the Combined EPA Regulation Scen ario has the greatest im pact to reliability.
Figure 5: 2018 Reduction in Adjusted Potential Capacity Resources due to the Combined EPA Regulation ScenarioScenarioResults 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 c ould potentially increase the unit production costs above replacement power costs at 347 stations, retiring 33 GW of current generating capacity. This retired generating cap acity 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”. Th e 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 aff ect the NERC subregions for th e 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 un it retirements.

Should the cooling tower conversion costs be 25 percent higher than prio r engineering studies indicated ($300/gpm versus $240/gpm), an additiona l 17 units (four GW) could retire resulting in a total of 37 GW. Section 316(b) marginally affects coal units in comparison to its effect s on oil/gas steam units ( i.e. , 92–93 percent of capacity). In the Strict Case, most of th e 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 “econo mically 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 10,432ScenarioResults 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 Mandat ory Cooling Tower Rule for Ex isting Steam Generating Units that resulted in approximately 40 GW of pot ential retirements. Some differences may be attributable to this study ex cluding more already announced ge nerating unit retirements (more than 28 GW) and incorporating a more compre hensive 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 41,214ScenarioResults Scenario Results

Page 16 2010 Special Reliability Assessment Scenario 

### National Emissions Standards for Haza rdous Pollutants (NESHAP) or Maximum Achievable Control Technology (MACT)
National Emissions Standards for Hazardous Po llutants (NESHAP) or Maximum Achievable Control Technology (MACT) will apply to all existing and future coal and oil fired steam capacity. The Moderate Case scenario rulema king varies for MACT emission rate limitations by coal type. This assessment assumes that th e 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 two 28 

### conditions must occur:

 the EPA Administrator (or state with program approval) grants an extension of one additional year, finding more time is “neces sary 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 s o. 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 capaci ty (59 units) “economically vulne rable” for retirement; another 0.8 GW may be derated. The figu re 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 grante d and all electric genera tion units must be in compliance by January 1, 2015. Obta ining 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 th e two years leading up to the deadline, i.e. , during 2013 and 2014, with none as of January 1, 2013. The Stri ct 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. Distri bution 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 gene rating facilities, or other caus es,” to order such temporary interconnection of facilities or generation, delivery, interchange, or transmission of el ectric energy as in his/her judgment “ will best meet the emergency and serve the public interest.” Howe ver, section 202(c) does not sp ecifically mention EPA or the Clean Air Act.ScenarioResults Scenario Results

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 17,611ScenarioResults Scenario Results

Page 18 2010 Special Reliability Assessment Scenario 

### The impacts could be more severe if costs esca late due to tighter implementation timelines of three years and the large number of plants (840 units) that may ne ed to upgrade their environmental controls at the same time. Th is 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 upgr ades or generation additions. A sensitivity comparison was completed for th e 2015 Strict Case for MACT accounting for the compressed implementation timeline (see Figure 6) . The risk that gene ration units will retire simply due to insufficiently available third part y 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 comp leted 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%GWofRetired+DeratedCapacity

Effective Cost Increase
Total At

‐ Risk Retirements DeratesScenarioResults Scenario Results

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. Alt hough 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 st ate utilities that relied heavily upon purchased allowances for compliance with their Acid Ra in 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 st eam units would remain largely untouched because of their limited emissions. As described earli er in this report, th ese reductions would be concentrated to a few states. The extent of retirements triggere d 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 emitt ing 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 ambien t 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 a nd 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, an d 2018 were assessed.ScenarioResults Scenario Results

Page 20 2010 Special Reliability Assessment Scenario 

### Alternatively, EPA could elect to pursue emission rate limitations on the co al-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 co al-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 cu rrent levels. Overall, 86 coal units (5,221 MW) would have their operating costs pushed a bove 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 CATRScenarioResults Scenario Results

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 M oderate 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 un its with capacity of 287 MW in the Moderate Case and 12 units with capacity of 388 MW in the St rict 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 dispos al, whereas the Strict Case assumes that all coal plants will need to store coal combustion byproduc ts 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 un it retirements (more than 28 GW) and incorporating a more comprehensive retirement replacement cost met hod (versus applying a unit size criterion). Because of the large difference in results, sens itivity comparisons were conducted to determine how the number of “economically vulnerable” units would vary under higher disposal cost assumptions. Disposal costs can vary significan tly 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 th eir residuals to appropriately permitted offsite landfills and pay tipping fees that could increase disposal costs.ScenarioResults 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 upw ard 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 containe d within the flat slope portion of the line on the far left side. However, th e additional costs that may beco me associated with distance removal of the hazardous substance to existing ce rtified landfills could drive costs upward.

Figure 7: Sensitivity of Retirements as a F unction 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 AshGWofRetiredCapacity

GW of Retired CapacityScenarioResults Scenario Results

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 w ill 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 expect ed to be additive between the different EPA rules. The cumulative effect of the four potential EPA ru les is provided in Tables 8, 9, and 10 for each of the three years assessed. In 2015, anywhere from 31–70 GW of existi ng fossil fuel capacity (351–678 generation units; beyond the 28 GW of retirements already announced and not included in NERC’s Long Term Reliability Asse ssment) are “economically vulnerable” for retirement from these four potential EPA rule s. Additionally the 273– 700 units of continuing operation will be derated by a total of 2.4-7.3 GW from the increased para sitic loads from the control operation. The projected retirements ar e 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 highe st to lowest. For th e 2015 Strict Case, the rank order is SERC, RFC, WECC, NPCC, and finally ERCOT.ScenarioResults Scenario Results

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 76,327ScenarioResults Scenario Results

2010 Special Reliability Assessment Scenario Page 25 

### This assessment models both coal and oil/gas-s team 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 wi th the same unit size (MW) may overlap and be hidden. The blue and red bars (Left Y-Axis) s how the total retired capacity by subregion. Overall, a majority of the reti red units are less than 200 MW.

The Strict Case (see Figure 9) has a significan t 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 12,000GenerationCapacityofRetiredUnit(MW)TotalGenerationCapacityRetired(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)ScenarioResults 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 opera ting/ongoing costs for any new inve stment 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 12,000GenerationCapacityofRetiredUnit(MW)TotalGenerationCapacityRetired(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)ReplacementCostMinusTotalPlantCost(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 RetrofitsReliabilityAssessment Reliability Assessment

2010 Special Reliability Assessment Scenario Page 27 

# R e l i a b i l i t y A s s

e s s m e n t
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. Th is 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 res ources, flexibility is reduced and the risk of a capacity shortage may increase, unless additi onal resources are available. Where Planning Reserve Margins fall below zero, there is a basic in ability to serve load wi th available resources.
For this assessment, NERC studied the effect s on Planning Reserve Margins from both unit retirement (assuming retired capacity is not re placed) and retrofits, which cause capacity reductions due to increased station loads to suppor t emission controls or new intake structures. Planning Reserve Margins are pr esented 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 powe r industry to replace retired ca pacity. 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 th at the potential EPA regulations have little to no eff ect on Existing-Other, Future Othe r, 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 redu ced to form the scenario cases (Moderate Case and Strict Case—previously desc ribed 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

30 Planning Reserve Margin is designed to m easure the amount of generation capacity avai lable 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-Cert ain and Net Firm Transactions plus Future-Planned capacity

resources plus net transactions—and Adjusted Potential Capa city Resources (APCR)—defined as the sum of Deliverable Capacity Resources, Existing-Other Resour ces, 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 tw o ways: 1) Conceptual resour ces measure industry’s future response towards maintaining Planning Rese rve Margins and 2) APCR represents the portion of the interconnection queue that is historically built. A range of resource projections is iden tified and evaluated from these two values in this assessment.ReliabilityAssessment 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 ca tegories 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 re garding supply/resource categories.

Overall, impacts on Planning Rese rve Margins and the need for mo re resources is a function of the compliance timeline associated with the potential EPA regulati ons. Up to a 78 GW reduction of coal, oil, and gas-fired gene ration 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 si gnificantly affects projected Planning Reserve Margins for a majority of th e NERC Regions and subregions. Potentially significant reductions in capacity within a five-y ear period may require he ightened concentration towards the addition of resources. For the Un ited States as a whole, the Planning Reserve Margin is significantly reduced up to 9.3 pe rcentage points in the Strict Case. Additionally, more transmission resources may be needed as the industry responds to resolve identified capacity deficiencies. As replacem ent 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 n eed enhancements to the transmission system in order to allow firm and relia ble transmission service.

While NERC did not model delivera bility or stability impacts to the transmission system (second tier effects) in this assessment, constructing new transmission or refurbishing existing transmission may be required. Transmission syst em enhancements and reconfiguration may be necessary in some areas, which may create additi onal timing issues as transmission facilities will take relatively longer to c onstruct than generation.

32 NERC's Reference Reserve Margin Level is equivalent to the Ta rget 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 per cent Reserve Margin for thermal systems and 10 percent for predominately hydro systems. Table 11: NERC Reference Margin Levels ERCO T 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%ReliabilityAssessment Reliability Assessment

2010 Special Reliability Assessment Scenario Page 29 

### Resource Adequacy Assessment Results: 2013 There are virtually no impacts to Planning Reserv e Margins in the short term (2013). CATR is the only regulation that affect s units in 2013. MRO, New England, RFC, SERC-Gateway, and SERC-Southeastern are the only Regions/subregi ons 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 Combin ed EPA Regulation Scenario, the Strict Case results in a coal-fired capacity reduction of 8,391 MW by 2013 (see Figur e 12). Overall, this amount does not appear to be significant and repres ents 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 th e increased costs being considered by generator owners, not only to comply w ith CATR, but with the 316( b), MACT, and CCR regulations. Because of these reductions, Planning Reserve Ma rgins are reduced slightly in the affected Regions/subregions. The MRO Planning Reserv e Margin decreases the most (about 2.7 percentage points when considering both the De liverable and Adjusted Potential Planning Reserve Margins) to approximately 19 perc ent (see Figure 13 and 14). Other affected Regions/subregions include NPCC-New England a nd RFC, which result in a net Planning Reserve Margin reduction of less than two percenta ge points. There is no ch ange to the Moderate Case when comparing the results of CATR modeled separately and the Combined EPA Regulation Scenario.

0 50,000 100,000 150,000 200,000 250,000MW 

### Figure 11: 2013 Summer Peak Deliverable Capacity Resources (DCR) Impacts of Combined EPA Regulation Scenario

(DCR) ‐ Reference Case (DCR) ‐ Moderate Case (DCR) ‐ Strict CaseReliabilityAssessment Reliability Assessment

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 tw o subregions must rely on Adjusted Potential Capacity Resources to meet the NERC Reference Margin Level in 2013.

0 50,000 100,000 150,000 200,000 250,000MW 

### 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%ReserveMargin(%) 

### 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 LevelReliabilityAssessment Reliability Assessment

2010 Special Reliability Assessment Scenario Page 31 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55%ReserveMargin(%) 

### 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 MarginReliabilityAssessment Reliability Assessment

Page 32 2010 Special Reliability Assessment Scenario 

### Resource Adequacy Assessment Results: 2015 For the modeled year 2015, the assessment result s have a greater impact on Planning Reserve Margin. Most notably, the Combined Proposed EP A Regulations Scenario shows considerable reductions, reducing Planning Reserve Margins acr oss the United States during the next five years. As previously discussed, the Moderate Case an d the Strict Case differ in key assumptions. In 2015, capacity reductions range fr om 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 50,000 100,000 150,000 200,000 250,000MW 

### Figure 15: 2015 Summer Peak Deliverable Capacity Resources (DCR) Impacts of Combined EPA Regulation Scenario

(DCR) ‐ Reference Case (DCR) ‐ Moderate Case (DCR) ‐ Strict CaseReliabilityAssessment Reliability Assessment

2010 Special Reliability Assessment Scenario Page 33 

### For the Moderate Case, a 3.2 percent reduction in overall capacity results in Planning ReserveMargin 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 Rese rve 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 cas es. 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 pe rcent (Adjusted Potential—see Figure 18). In this scenario, more resources will be needed in the SERC-Delta subregion under the Moderate Case assumptions. 0 50,000 100,000 150,000 200,000 250,000MW 

### 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%ReserveMargin(%) 

### 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 LevelReliabilityAssessment Reliability Assessment

Page 34 2010 Special Reliability Assessment Scenario 

### For the Strict Case, a 7.2 percen t 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 Deliv erable 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 Refe rence 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-Ne w England, SERC-Gateway, and SERC-VACAR result in Planning Reserve Margins below 10 percent. In these Re gions/subregions, more resources will be needed for this scenario. The impacts to Planning Reserve Margins are hi ghly 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 Leve l. However, as indicated above, even these additional resources may not be sufficient. 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55%ReserveMargin(%) 

### 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 LevelReliabilityAssessment 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 MarginReliabilityAssessment Reliability Assessment

Page 36 2010 Special Reliability Assessment Scenario 

### Resource Adequacy Assessment Results: 2018
Further reductions in capacity resources and Pl anning Reserve Margins are the results in 2018. Most notably, the Combined EPA Regulations Scenario shows considerable reductions, effectively reducing Planning Rese rve Margins across the United St ates 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 re ductions 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, follo wed 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 s how 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 perc ent 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 Ca se (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 repla cement generation. Each modeled year port rays a “snapshot” of potential effects caused by the EPA regulations, rather than an ongoing timeline of retrofits and retirements. 0 50,000 100,000 150,000 200,000 250,000MW 

### Figure 19: 2018 Summer Peak Deliverable Capacity Resources (DCR) Impacts of Combined EPA Regulation Scenario

(DCR) ‐ Reference Case (DCR) ‐ Moderate Case (DCR) ‐ Strict CaseReliabilityAssessment 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 pe rcent 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 s how 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 ERCO T, 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 Reso urces, ERCOT, MRO, NPCC-New England, and SERC-Delta fall below zero. With Adjusted Po tential Capacity Resources, the SERC-Delta Planning Reserve Margin is reduced 18.7 percen tage points to -0.5 percent because of a 16 percent reduction in SERC-Delta resources. The Strict Case shows that a 7.2 percent reduc tion in overall capacity results in significant Planning Reserve Margin reducti ons 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 per cent 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 Refere nce 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, capac ity reductions in ERCOT, NPCC-New England, RFC, SERC-Gateway, SERC-Southeastern, SE RC-VACAR, and SPP result in Planning Reserve Margins below10 percent. 0 50,000 100,000 150,000 200,000 250,000MW 

### Figure 20: 2018 Summer Peak Adjusted Potential Capacity Resources (APCR) Impacts of Combined EPA Regulation Scenario

(APCR) ‐ Reference Case (APCR) ‐ Moderate Case (APCR) ‐ Strict CaseReliabilityAssessment Reliability Assessment

Page 38 2010 Special Reliability Assessment Scenario ‐ 10%

‐ 5% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45%ReserveMargin(%) 

### 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%ReserveMargin(%) 

### 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 LevelReliabilityAssessment 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 ‐ 2018ReliabilityAssessment Reliability Assessment

Page 40 2010 Special Reliability Assessment Scenario 

### Industry Actions: Tools and Solutions fo r Mitigating Resource Adequacy Issue
In addition to the potential for waivers or extens ions, a variety of tools and solutions can help mitigate significant reliability impacts resulting fro m 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 i ndustry should closely monitor the EPA regulation process as well as continued generator pa rticipation/ea rly-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 GenerationConclusionsandRecommendations Conclusions and Recommendations

2010 Special Reliability Assessment Scenario Page 41 

# C o n c l u s i o n s & R e c o m m e n d a t i o n s

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 concer ns unless prompt industry action is taken. Planning Reserve Margins appear to be significan tly impacted, deteriorating resource adequacy in a majority of the NERC Regions/subreg ions. Additionally, co nsiderable 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, t he 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 nucl ear capacity may be affected. Because of this scenario, Planning Reserve Margins are decr eased as much as 18 percentage points in the SERC-Delta subregion where the margin falls belo w zero (available generation will be unable to serve load), unless additional resources are adde d. Other Regions/subre gions 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 requi re 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.ConclusionsandRecommendations 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 vulne rable” 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 th e next four to eight years that could reduce bulk power system reliab ility, unless additional resources are constructed or acquired. It is essential that projected Co nceptual supply resource s 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 t ogether and separately, should employ the array of tools at their disposal to moderate reliability impacts, including, among other things, granting required extens ions to install emission controls. Industry participants should employ av ailable 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 cap acity 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 impli cations 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 impact s to operating reliability and second tier impacts (e.g., deliverability, stability, localized issues, outage scheduling, operating procedures, and i ndustry coordination) of forthcoming EPA regulations.RegulatorsIndustryNERCAppendixI:AssessmentMethods Appendix I: Assessment Methods

2010 Special Reliability Assessment Scenario Page 43 

# A p p e n d i x I : A s s

e s s m e n t M e t h o d s

Method for This Assessment
Some studies completed by various organizations have made assumptions that environmental regulations will cause all units that meet a certain cr iteria to retire, for example, all units less than 230MW that have a capacity factor below 35 pe rcent. 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 aff ect 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 un it versus the operating cost of replacement capacity 5. Management’s attitude towa rd 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 Planni ng Reserve Margins commitments, reliabilitymust-run factors or transmission c onstraints. 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-fi red 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 cred its that have accumulated and allows them to be used as an offset in lie u 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 includi ng fuel cost in $/MWH RC = replacement cost in $/MWH DR = derate factor that accounts for th e incremental energy loss due to any new environmental controlsAppendixI:AssessmnentMethods 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, capaci ty 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 additi onal 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, lin ear interpolation be tween [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.AppendixI:AssessmentMethods Appendix I: Assessment Methods

2010 Special Reliability Assessment Scenario Page 45 

### RC = Replacement cost is a function of the capacity fact or, 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 co st of a new GT unit in the NERC Region in $/MWh@ 10% CF wi th 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 wi th 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 typi cal 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

‐ 202 2 2018

‐ 202 7 2013

‐ 202 3 2018

‐ 202 8 $/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

C om bi ne d C yc l e Natural Gas Price in $/MMBtu G as T ur bi ne N atura l Gas Price in $/MMBtuAppendixII:PotentialEnvironmentalRegulations Appendix II: Potential Environmental Regulations

Page 46 2010 Special Reliability Assessment Scenario 

# A p p e n d i x I I : P o t e n t i a l E n v i r o n m e n t a l R e g u l a t i o n s

Section 316(b) Cooling Water Intake Structures
The typical power plant uses a fuel (coal, gas or nuclea r) 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, la ke or river) pass through the h eat exchanger to condense steam in a single pass before the majority returns to the source. Closed-loop cooli ng is an alternative to open-loop cooling (see Figure II-2). Closed-l oop cooling systems circulate a similar total volume of water as open-loop syst ems 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 conductiv e heat transfer using a high flow rate of ambient air bl own 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 c ooling 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 de veloped the Section 316(b) rule fo r existing genera tion facilities using greater than 50 million ga llons 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 per cent of 2008 U.S. generation. Power sources such as combustion turbines, hydroelectric facilitie s, wind turbines, and so lar PV panels use no cooling water and therefore will not be subject to the propos ed rule. Major EPA proposed making policy issues directly affect ing Planning Reserve Margins are:AppendixII:PotentialEnvironmentalRegulations 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 exis ting facilities rule (ove rturned by the U.S. Cour t of Appeals in 2007), EPA set significant new national technology-based performance standards. The standards are intended to minimize adverse environmental imp acts of cooling water intake structures by reducing the number of aquatic or ganisms 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 s ite-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 ar e expected to favor performance commensurate with cooling towers. In additi on, 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 wate r 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 recirculati ng cooling water systems or acceler ation of their retirement. For those units opting to retrofit, the stations w ould increase onsite electri city consumption (1-4 percent) from station loads because of increas ed 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 cap acity 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 wate r systems operating at capacity factors less than 35 percent would be retire d and retrofitted plant output capacity was reduced by four percent to represent increas ed station loads. The 1,200 affected units with once through cooling water systems and their cooling water intake power suppliers identifie d rates through the U.S. Energy Info rmation 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/Document sandMedia/Cooling_Tower_Report.pdf 36 http://www.eia.doe.gov/cneaf/ electricity/page/eia906_920.htmlAppendixII:PotentialEnvironmentalRegulations 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 thr ee 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 cost s 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 pe r minute (gpm) with an average capital conversion cost of $240/gpm. The average convers ion costs were applied for most locations, except for known urban locations having constrai ned site conditions for which a 25 percent higher capital cost estimate of $300/gpm (2010 dollars) was applied. The base case costs applied in this reliability assessment are shown in Figure II-3. Figure II-3: Base Case Retrofit Co st Curve for Section 316(b)($/kW)

In addition to the capital conversion costs, the station would lose both cap acity 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 th is assessment are shown in Table II-1.

37 EPRI is expected to issue a new revised report that will incl ude detailed cost information not only for installing cooling tow ers,

but also for retrofitting plants on sensitive water bodies, and operations and maintenance costs. 100 200 300 400 500 600 700RetrofitCost$/kW

Size of Generation Unit (MW)AppendixII:PotentialEnvironmentalRegulations Appendix II: Potential Environmental Regulations

2010 Special Reliability Assessment Scenario Page 49 

### Table II-1: Capacity Derating/Energy Pe nalties Due to Cooling Tower Conversion

However, these referenced compliance costs an d 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 conversi ons 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 plan t layout can have signi ficant impacts on conversion costs that are not reflected by applying industrial average estimates. Although an adjustment was made for known cons trained urban sites, several more sites likely exist that may have similar (but unknown) site constraint problems.

 Finally, given the short potential rule implem entation period and the large affected power plant population, demand for labor and construc tion 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 pe rcent 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. Alternat ively, EPA could consider severa l policy options th at could reduce the rule’s impact. These options include (1) narrowing the rule sc ope 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 technol ogy options for existing cooling systems ( e.g. retrofitting fine mesh screens pe r the 2004 rule). Any narrowing of the regul ation scope or cost would reduce the rule’s reliability impacts. Thes e 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)AppendixII:PotentialEnvironmentalRegulations Appendix II: Potential Environmental Regulations

Page 50 2010 Special Reliability Assessment Scenario 

### National Emissions Standards for Haza rdous 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 fo r 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 cos ting curves to develop unit-specific compliance cost estimates, with the increased unit producti on costs of new pollution controls compared to unit production costs of replacemen t power. EPA is expected to adopt different MACT emission rate limitations, which implies that new investme nts 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 pres ent or planned, dependi ng 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 b ituminous coal only. In addition, fabric filter systems with halide-treated activated carbon inj ection (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 specificat ions at the refinery. By contrast, Strict Case assume s 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)AppendixII:PotentialEnvironmentalRegulations Appendix II: Potential Environmental Regulations

2010 Special Reliability Assessment Scenario Page 51 

### Representative base case costs for b ituminous coal are shown in Figure II-4. Figure II-4: Bituminous Coal Base Ca se 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 4000BaseCaseCosttoRetrofit$/kW

Size of Generation Unit (MW)AppendixII:PotentialEnvironmentalRegulations Appendix II: Potential Environmental Regulations

Page 52 2010 Special Reliability Assessment Scenario 

### Clean Air Transport Rule (CATR)
EPA developed its Clean Air Interstate Rule (CAI R) program to address the long-range emission transport contribution to fine particulate non-attainment and to take the first co mpliance step by reducing contributions from major fossil combustion stationary sources. Its original proposed program created a new annual NO x 

### cap-and-trade program and modified the existing Title IV SO 2 

### cap-and-trade program for 28 states for wh ich 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 SO 2 

### /NO x 

### emissions that significantly contributed to non-attainment of fine particulate and ozone ambient air quality standards in do wnwind 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 s hown in Figure II-5 . Figure II-5: Clean Air Transpor t 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=1AppendixII:PotentialEnvironmentalRegulations Appendix II: Potential Environmental Regulations

2010 Special Reliability Assessment Scenario Page 53 

### The potential EPA rule will regulate SO 2 

### and NO x 

### emissions under three new cap-and-trade programs (SO 2 

### , annual NO x 

### and seasonal NO x 

### ) 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 SO 2 

### and NO x 

### allowance credits and allocati ons created under the Acid Rain and CAIR programs cannot be used for compliance under the new program. For SO 2 

### , affected states are organized into Group 1 or Group 2, as shown in Figure II-6. Figure II-6: Clean Air Transp ort Rule Designated States

CATR applies to fossil power plant sources loca ted 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 rule 39 

### :

 The EPA preferred option;

 Alternative 1 - the no inters tate trading option; or

 Alternative 2 - the strict emission rate option. EPA proposal is soliciting comments on its prefe rred option with limited interstate trading and intrastate trading, as well as the two altern ative options. Further complicating compliance planning by electric generators, the agency r ecognizes that the proposed state emission budgets

39 Described in the Introduction section of this reportAppendixII:PotentialEnvironmentalRegulations 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 particul ate and ozone air quality standards are adopted, potential ly 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, EP A 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 nati onal emissions cap with unrestricted trading and banking, the new proposal also makes greater coordination essential between utilities within each stat e in order to optimize emission reductions. However, concerns over competition may limit coordination and re sult in less optimal compliance plans. The new program is likely to require some elect ric generation units to retrofit additional FGD and selective catalytic reduction (S CR) controls by 2014, or retire. St rict emission limits that can only be met with post combustion FGD and SCR controls will dir ectly affect 163 GW of coalfired capacity that currently does not have FGD, or the 180 GW without post combustion NO x 

### 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

SO 2 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 NO x 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.AppendixII:PotentialEnvironmentalRegulations 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 olde r cost data and exclude owner and financing costs.

Figure II-7: Moderate Case Average Post Co mbustion Control Retrofit Costs for CATR ($/kW)

This assessment examines the impacts of th e 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 st ates must reduce their aggregated in-state SO 2 

### 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 thei r future emission rate alternative that has no provisions for any trading between units and will force more coal units to have post combustion SO 2 

### and NO x 

### controls in the selected stat es. The assessment evaluates the available state credits to meet th e state’s limits and selects genera ting units for reti rement 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 1600BaseCaseCosttoRetrofit$/kW

Size of Generation Unit
Wet FGD Dry FGD SCRAppendixII:PotentialEnvironmentalRegulations 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 cha nging 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 Recove ry 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 pe r year (tpy) of coal-a sh and solid byproducts currently produced by the coal-fired stations. Po licy issues that will imp act 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 hand ling 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 diffe rent types of waste dis posal standards, and to close/cap existing ash ponds. Such a ruling re quires the 359 coal units (128.5 GW) to convert their wet ash handling systems to dry based system s, incur greater ash disposal costs for the 136 million tons of ash disposal each year, and cl ose and cap the existing 500 ash/sludge ponds in operation.
In addition, a hazardous waste de signation under Subtitle C coul d eliminate the market for 20 million tons of ash that is currently resold in to the market, although the EPA is considering a “special waste” designation, which would allow “ben eficial” reuse of the s ubstance 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 Manda tory 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 assu mption 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 f acilities ranging, per facility, fro m $80 million without a flue gas desulfurization system (FGD) to $120 million w ith FGD per facility to provide storm water and/or FGD scrubber sludge tr eatment currently handled by the ash ponds. Ash pond closure

40 http://www.whitehouse.gov//sites/defau lt/files/omb/assets/oira_2050/2050_102809-2.pdf 41 A revised EOP report is currently under review, reference report upon completion. Pr eliminary values i ndicate a 20 percent

increase in cost.AppendixII:PotentialEnvironmentalRegulations 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 grea test potential risk of ceasing operations if required to undertake mandatory closure of CCB surface impoundments .” These “economically vulnerable” coal units totaled 35 GW of existi ng capacity and represen ted 18 percent of 2005 U.S. coal generation. However, the 2009 EOP Study contained some defici encies 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 exis ting ash pond closures. These re mediation costs will vary significantly based upon the extent of any gr oundwater contamination, site geology and aquifer use. However, any remediation might be considered as a s unk cost since it would be incurred independently of the future ope rating decision. If these costs were indeed considered sunk, they should not be incorpor ated into unit retirement decisions.

A total of 359 coal-fired units (128.5 GW) of coal-fired capac ity 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 estimat es for bottom ash conversion and wastewater treatment upgrades are applied on a unit basis. Th e additional EOP ash waste disposal costs of $15 per ton (2010 dollars) were added for handli ng 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. Therefor e, only incremental costs asso ciated with ongoing operations are accounted for in the decision to invest or re tire the unit. When these incremental power production costs exceeded new replacement capacity costs, the units became potential retirement candidates.
However, as outlined above, th e EOP Group study may have unde restimated compliance costs and thereby underestimated potential grid reliability impacts. Ba sed 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 u nder 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 complete d across a wide range of ash disposal costs from $37.50 to $1,250 per ton.AppendixIII:CapacityAssessedbyNERCSubregion Appendix III: Capacity Asse ssed by NERC Subregion

Page 58 2010 Special Reliability Assessment Scenario 

# A p p e n d i x I I I : C a p a c i t y A s s

e s s

e d b y N E R C S u b r e g i o n

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/SubregionAppendixIV:DataTables Appendix IV: Data Tables

2010 Special Reliability Assessment Scenario Page 59 

# A p p e n d i x I V : D a t a T a b l e s

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 Capac ity Resources on the high-end. Refer to the Terms Used in this Report section for detailed definitions re garding 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 72,20 4 15.8% 15.8% FRCC 42,531 51,870 51,87 0 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 FiguresAppendixIV:DataTables 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 ProjectionsAppendixIV:DataTables 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 ProjectionsAppendixIV:DataTables Appendix IV : Data Tables

Page 62 2010 Special Reliability Assessment Scenario ERCO T 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

ERCO T 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 TotalAppendixIV:DataTables 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 34,601AppendixIV:DataTables 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 MarginAppendixIV:DataTables 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 CaseAppendixIV:DataTables 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 MarginAppendixIV:DataTables 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 ‐ 2015AppendixIV:DataTables 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 ‐ 2015AppendixIV:DataTables 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 MarginAppendixIV:DataTables 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 CaseAppendixIV:DataTables 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 CaseAppendixIV:DataTables 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 ‐ 2018AppendixV:RelatedStudyWorkandReferences Appendix V: Related Study Work and References

2010 Special Reliability Assessment Scenario Page 73 

# A p p e n d i x V : R e l a t e d S t u d y W o r k a n d R e f e r e n c e s

Related Study Work For 316(b)
The U.S. Senate Committee on Appropria tions, Subcommittee on Energy and Water Development, requested the Office of Electric ity Delivery and Energy Reliability of the Department of Energy (DOE or Department) to ex amine the impacts to electricity reliability of requiring generators with once-through cooling syst ems to be replaced with closed-cycle cooling towers. DOE provided NERC with a list of steam generation units that woul d be required to retrofit to cooling towers. DOE requested NERC to model th e reliability impacts of the cooling tower mandate using certain assumptions. NERC provide d 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 th e deadline for the cooling tower retrofits has passed, the generation losses resulting from the re quirement would exacerbat e a potential decline in electric Planning Reserve Margins needed to en sure reliable delivery of electricity. Generally, the goal for NERC Regions is to have the equivale nt of between 10 and 15 percent of their peak generation demand available to meet continge ncies. 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 percen t 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 wa s 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 capaci ty shortfalls due to plant shutdowns.

 Plants with a zero capacity factor (inactiv e or not yet built) are not assessed. These plants are not included in the Region’s Reference Case

.AppendixV:RelatedStudyWorkandReferences Appendix V: Related Study Work and References

Page 74 2010 Special Reliability Assessment Scenario 

### Assumptions specified by NERC:

 The NERC Reference Margin Level adopt ed 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 al l 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 retrofi tting units with existing once-through-cooling systems to closed-loop cooling systems (resu lting in four percent reduction in nameplate capacity) or unit retirements ( capacity factor less than 35 pe rcent) 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, reduc ing the Adjusted Pote ntial 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 sy stem. Some subregions, such as WECC-CA, NPCCNE, ERCOT, SERC-Central and NPCC-NY, experience significant impacts.

Table V-1: 2015 US Summer Peak Pote ntial Retrofit/Ret irement Effects

In comparing the results of the prior collaborati ve DOE/NERC assessment to the results in this report, impacts of similar magnitudes were fou nd. Further, the areas (Regions/subregions) of concern highlighted in the prior assessment are a ligned with those identified in this assessment. A djusted Potential Resources (MW) Reduction due to Retirement (MW) Derate due to Retrofi t (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%AppendixV:RelatedStudyWorkandReferences 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 pot ential impact of EPA’s expected proposals for management of CCR prior to pub lication of th e 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 si gnificant 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 EP RI’s analysis in 2009, several utilities have announced plans to retire older coal-fired generati ng units. Combined, the units included in EPRI’s analysis, but excluded from the NERC asse ssment, represent 20 GW of capacity. Definition of “at risk” Coal Capacity The EPRI study was a screening-level economi c analysis, intended to identify individual generating units that were predic ted 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 re liability cannot be comp romised and that for many units shutdown is not an option (particularl y base-load units) without major disruption to the power grid. Thus, NERC’s assessment compar ed 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 ge nerating 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 regulati on on power plants, EPRI considered costs that NERC did not include in its asse ssment. One was the cost of off- site disposal at a commercial facility. NERC’s assessment assumed all power pl ants would locate and construct Subtitle C landfills on or near th e power plant property. While so me states do not currently allow establishment of hazardous wast e 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/Corporat eDocuments/SectorPages/Portfolio/Enviro nment/Ken%20Ladwig%20Written%20Testi mony%20USHouse-E%26E%2010Dec2009%20FINAL.pdfAppendixV:RelatedStudyWorkandReferences Appendix V: Related Study Work and References

Page 76 2010 Special Reliability Assessment Scenario 

### would be made to facilitate permitting of these S ubtitle C facilities. Based on current disposal patterns, interviews with severa l utilities, and site-specific condi tions such as land availability and watershed restrictions, EPRI a ssumed that a percentage of plan ts would be forced to dispose of CCRs in off-site commercial facilities, at higher costs for both tran sportation and disposal. The EPRI analysis also included special handli ng costs at the power pl ant to meet Subtitle C requirements. The NERC assessment did not incl ude 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 cu rrent 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 additi onal information on both off-site disposal costs and “upstream” management and storage costs associ ated with Subtitle C regulation. In response to the EPA’s request for additional cost data, EP RI 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 engineerin g and cost data in 4Q 2010 that will be publicly available.TermsUsedinthisReport Terms Used in This Report

2010 Special Reliability Assessment Scenario Page 77 

# T e r m s U s e d i n T h i s R e p o r t

Adjusted Potential Capacity Resources — The sum of Deliverable Capacity Resources, Existing Other Resources, Future Other Resources (r educed by a confidence factor), Conceptual Resources (reduced by a confidence factor), an d net provisional transacti ons 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 gene ration resources that are not included in Existing Generation Resources or Future Generation Resources , but have been identified and/or announced on a resource planni ng 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 interconnec tion (or other) queue for study 4. “Place-holder” generation for use in modeli ng, 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 adju sted using a confidence factor (%) to reflect uncertainties associated with siting, project development or queue position. Deliverable Capacity Resources — Existing, Certain and Net Fi rm 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 electr icity, 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 cap acity that is expected to be unavailable on seasonal peak. Existing, Certain (Existing Generation Resources) — Exis ting generation resources available to operate and deliver power within or into the Region during th e period of analysis in the assessment. Resources included in this categ ory may be reported as a portion of the full capability of the resource, plant, or unit. Th is category includes, but is not limited to the following:TermsUsedinthisReport Terms Used in this Report

Page 78 2010 Special Reliability Assessment Scenario 

### 1. contracted (or firm) or other similar resour ce confirmed able to serve load during the period of analysis in the assessment; 2. where organized markets exist, designated market resource 43 

### that is eligible to bid into a market or has been designated as a firm network resource; 3. a Network Resource 44 

### , as that term is used for FERC pro forma or other regulatory approved tariffs; 4. energy-only resources 45 

### confirmed able to serve load dur ing 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 categ ories that have been confirmed able to serve load and not to be curtailed 47 

### during the period of anal ysis in the assessment. Existing, Certain & Net Firm Transactions — Existing, Certain capac ity 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 Dema nd 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 contai ns 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 retu rn to service at some point in the future. This value may vary for future seasons and can be reported as zero. Th is includes all existing generation not included in categories Existing, Certain or Existing, Ot her, but is not limited to, the following: 1. mothballed generation (that cannot be retu rned to service for the period of the assessment); 2. other existing but out-of-service generation (t hat cannot be returned to service for the period of the assessment); 3. does not include behind-the-meter generati on 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) — Existi ng 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 interr upted 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 res ources 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 resource s that are counted towards capacity. 46 Energy only resources with transmission service constrai nts are to be considered in category Existing, Other. 47 Energy only resources with transmission service constrai nts are to be considered in category Existing, Other.TermsUsedinthisReport Terms Used in This Report

2010 Special Reliability Assessment Scenario Page 79 

### 2. energy-only resources that have been conf irmed 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 return ed to service for the period of the assessment); 4. portions of variable generation not count ed 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 Ex isting, Certain or derated; and 6. generation resources constr ained for other reasons. Expected (Transaction Category) — A cat egory of Purchases/Imports and Sales/Exports with the following clarification: 1. Expected implies that a contract has not b een executed, but is in negotiation, projected or other. These Purchases or Sales are expected to be firm. 2. Expected Purchases and Sales should be cons idered in the reliability assessments. Firm (Transaction Category) — A category of Purc hases/Imports and Sales/Exports with the following clarification c ontract including: 1. Firm implies a contract has been signed and may be recallable. 2. Firm Purchases and Sales should be report ed in the reliability assessments. The purchasing entity should count such capacity in margin calculations. Care should be taken by both entities to appropr iately 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 reasonabl e 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 receiv ed 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 th e Conceptual category. This category includes, but is not limited to, gene ration 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 duri ng the assessment period; or 4. is hydro generation not counted in category Future, Planned or derated. Resources included in this category may be ad justed using a confidence factor to reflect uncertainties associated with siting, project development or queue position.TermsUsedinthisReport 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 resource 48 

### that is eligible to bid into a market or has been designa ted as a firm network resource. 3. A Network Resource 49 

### , as that term is used for FE RC 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 curtailed 50



### . 5. Where applicable, is included in an in tegrated 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 regul atory requirements. If provided in the data submittals, the Regional/subregi onal Target Reserve Margin le vel is adopted as the NERC Reference Reserve Margin Level. If not, NERC assigned a 15 percent Reserve Margin for predominately thermal systems and 10 pe rcent for predominately hydro systems. Net Internal Demand : Total Internal Demand reduced by th e total Dispatchable, Controllable, Capacity Demand Response equaling the sum of Direct Control Load Management, Contractually Interruptible (Curtail able), Critical Peak Pricing (CPP) with Control, and Load as a Capacity Resource. On-Peak (Capacity ) — The amount of capacity th at is expected to be available on seasonal peak. Potential Capacity Resources — The sum of Deliverable Cap acity Resources, Existing Other Resources, Future Other Resources, Conceptual Resources, and net provi sional transactions minus all derates. (MW) Potential Reserve Margin (%) — The sum of Deliverable Capac ity Resources, Existing Other Resources, Future Other Resources, Conceptual Resources, and net pr ovisional transactions minus all derates and Net Internal Demand show n 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 de ratings (including derates from variable resources, energy only resources, scheduled outag es 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 constrai nts are to be considered in category Future, Other.TermsUsedinthisReport 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 Rese rve Margin by the Region or subregion. Not all Regions re port 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 repor ting 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 res ource 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 purc hase, but does not report the capacity of such resource. Transmission must be availabl e for all reported Purchases and Sales.AbbreviationsUsedinthisReport Abbreviations Used in This Report

Page 82 2010 Special Reliability Assessment Scenario 

# A b b r e v i a t i o n s U s e d i n T h i s R e p o r t

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 NO x 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 Reliability First 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 SO 2 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 CouncilReliabilityAssessmentSubcommitteeRoster Reliability Assessment Subcommittee Roster

2010 Special Reliability Assessment Scenario Page 83 

# R e l i a b i l i t y A s s

e s s m e n t S u b c o m m i t t e e R o s t e r

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 Represen tatives — Members of the Electric Reliability Organization: Reliability Assessment and Pe rformance 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.bizReliabilityAssessmentSubcommitteeRoster Reliability Assessment Subcommittee Roster

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.caReliabilityAssessmentSubcommitteeRoster 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.govReliabilityAssessmentSubcommitteeRoster 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.orgNorthAmericanElectricReliabilityCorporationStaffRoster North American Electric Reliability Corporation Staff Roster

2010 Special Reliability Assessment Scenario Page 87 

# N o r t h A m e r i c a n E l e c t r i c R e l i a b i l i t y C o r p o r a t i o n S t a f f R o s t e r

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