NERC |Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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Potential Reliability 

Impacts of EPA’s Proposed 

Clean Power Plan

Phase I

April 2015
NERC |Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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Table of Contents

Preface.......................................................................................................................................................................iii

Executive Summary ....................................................................................................................................................v

Chapter 1 – Introduction and Background.................................................................................................................1

Overview of Initial Reliability Review .....................................................................................................................1

Part 1: NERC Resource Adequacy Scenarios and Analyses.....................................................................................3

Part 2: Transmission Adequacy and Infrastructure Upgrade .................................................................................4

Part 3: Summary of Existing Studies.......................................................................................................................5

Chapter 2 – Modeling Assumptions for Resource Adequacy and Power System Analysis........................................7

Chapter 3 – Resource Adequacy Assessment ............................................................................................................9

Scenario Modeling Cases..................................................................................................................................... 10

Key Results from the Resource Adequacy Assessments...................................................................................... 13

Chapter 4 – Steady-State Power System Analysis................................................................................................... 29

Power Flow Cases and Evaluation Approach....................................................................................................... 29

Generation Retirements...................................................................................................................................... 30

Generation Additions........................................................................................................................................... 31

Transmission Addition Requirements.................................................................................................................. 32

Reactive Power .................................................................................................................................................... 33

Lead Time and Timing Implications..................................................................................................................... 34

Chapter 5 – Timing Implications.............................................................................................................................. 36

Chapter 6 – NERC’s Assessment on Analysis Conducted by Selected NERC Regions and ISO/RTOs ...................... 42

ERCOT .................................................................................................................................................................. 44

MISO .................................................................................................................................................................... 46

PJM....................................................................................................................................................................... 47

SPP ....................................................................................................................................................................... 49

WECC.................................................................................................................................................................... 50

Chapter 7 – Reliability Assurance Mechanism ........................................................................................................ 52

Chapter 8 – Recommendations, Conclusions, and Future Steps ............................................................................ 56

Appendix A – AURORAxmp Model vs. IPM Model .................................................................................................. 58

Appendix B – Steady-State Power System Analysis Methods................................................................................. 59
NERC |Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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Preface

The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission 

is to assure the reliability of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; 

annually assesses seasonal and long‐term reliability; monitors the BPS through system awareness; and educates, trains, and 

certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern 

portion of Baja California, Mexico. NERC is the electric reliability organization (ERO) for North America, subject to oversight 

by the Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes 

users, owners, and operators of the BPS, which serves more than 334 million people. The North American BPS is divided into 

several Assessment Areas within the eight Regional Entity (RE) boundaries, as shown in the map and corresponding table 

below. 

NERC Regions and Assessment Areas

 

1 FRCC Region and Assessment Area boundaries are the same.

2 The MISO footprint is primarily located in the MRO Region, with smaller portions in the SERC and RF Regions. For NERC’s assessments, 

the MRO Region oversees the collection of data and information from MISO.

3 The PJM footprint is primarily located in the RF Region, with smaller portions in the SERC Region. For NERC’s assessments, the RF Region 

oversees the collection of data and information from PJM.

FRCC – Florida Reliability 

Coordinating Council

FRCC1

MRO – Midwest Reliability 

Organization

MISO2

MRO-Manitoba Hydro

MRO-MAPP

MRO-SaskPower

NPCC – Northeast Power 

Coordinating Council

NPCC-Maritimes

NPCC-New England

NPCC-New York

NPCC-Ontario

NPCC-Québec

RF – ReliabilityFirst

PJM3

SERC – SERC Reliability 

Corporation

SERC-East

SERC-North

SERC-Southeast

SPP RE – Southwest Power 

Pool Regional Entity

SPP

TRE – Texas Reliability Entity

TRE-ERCOT

WECC – Western Electricity 

Coordinating Council

WECC-CA/MX

WECC-NWPP 

WECC-RMRG 

WECC-SRSG 

The Regional boundaries in this map are approximate. The highlighted area between SPP and SERC denotes overlap as some 

load-serving entities participate in one Region while associated Transmission Owners/Operators participate in another.
Preface

NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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The North American Electric Reliability Corporation

Atlanta

3353 Peachtree Road NE, Suite 600 – North Tower

Atlanta, GA 30326

404-446-2560

Washington, D.C.

1325 G Street NW, Suite 600

Washington, DC 20005

202‐400‐3000

Questions

Please direct inquiries to NERC staff (assessments@nerc.net).

NERC Reliability Assessment Staff

Name Position

Mark G. Lauby Senior Vice President and Chief Reliability Officer

Thomas C. Burgess Vice President and Director, Reliability Assessment and Performance Analysis

John N. Moura Director, Reliability Assessment

Thomas H. Coleman Director, Reliability Assessment

Ganesh Velummylum Senior Manager, Reliability Assessment

Noha Abdel-Karim Senior Engineer, Reliability Assessment

Elliott J. Nethercutt Senior Technical Advisor, Reliability Assessment

David A. Calderon Engineer, Reliability Assessment

Michelle Marx Executive Assistant, Reliability Assessment and Performance Analysis

Amir Najafzadeh Engineer, Reliability Assessment
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Executive Summary

The Environmental Protection Agency (EPA) issued its proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units on June 2, 2014, commonly referred to as the proposed Clean 

Power Plan (CPP). The proposed rule is issued under Section 111(d) of the Clean Air Act and establishes limits on 

CO2 emissions for existing electric generation facilities. The proposed rule is currently anticipated to be finalized 

during summer 2015. 

In its role as the Electric Reliability Organization in the United States, NERC has responsibility under Section 215 

of the Federal Power Act to conduct periodic assessments of the reliability and adequacy of the nation’s bulk 

power system (BPS)—the high-voltage transmission and generation system (as opposed to local distribution 

facilities). NERC’s single focus is BPS reliability. NERC fulfills its responsibility in the public interest through 

conservative analyses and assessments that highlight reliability risks resulting from various possible future 

circumstances, given the severe consequences of an operationally unreliable or inadequate BPS for public health, 

safety and well-being, and our nation’s economy and security.

On August 14, 2014, NERC’s Board of Trustees directed NERC staff to develop a series of special reliability 

assessments to examine the potential risks to reliability that may arise from the implementation of the CPP rule 

and potentially accelerate the transformation of the resource mix in North America. NERC began development of 

this series of reports with its Initial Reliability Review,

4 published in November 2014, which examined the approach 

outlined in the proposed CPP and provided a high-level view of potential reliability risks. 

NERC maintains a reliability-centered focus on the potential implications of environmental regulations and other 

shifts in policies that can impact the reliability of the BPS. Reliability assessments conducted while the EPA is 

finalizing the CPP can inform regulators, state officials, public utility commissioners, electric industry leaders, and 

other stakeholders of potential resource adequacy concerns, impacts to system characteristics (such as the 

straining of essential reliability services (ERSs)), and areas that may require transmission enhancements to ensure 

reliability. 

This report is NERC’s Phase I special assessment. It provides an analysis of scenarios and identifies the potential 

risks to reliability resulting from the resource transformation called for in the proposed CPP. This assessment and 

its findings do not: (1) advocate a policy position in regard to the environmental objectives of the proposed CPP; 

(2) promote any specific compliance approach; (3) advocate any policy position for a utility, generation facility 

owner, or other organization to adopt as part of compliance, reliability, or planning responsibilities; (4) support 

the policy goals of any particular stakeholder or interests of any particular organization; (5) represent a final and 

conclusive reliability assessment; or (6) represent an actual system expansion plan. 

NERC’s Phase I assessment consists of a three-part analysis: (1) a scenario and sensitivity analysis driven by gas 

prices and state or regional implementation approaches to identify resource adequacy and the range of potential 

timelines associated with reliability reinforcement needed to meet CPP requirements; (2) a transmission adequacy 

analysis to determine a comparable range of transmission needs along with lead times required to build that 

transmission (natural gas pipeline reinforcements are also examined); and (3) summaries of existing studies by 

NERC reliability authorities (such as Reliability Coordinators, Transmission Planners and Operators, and Regional 

Reliability Organizations) related to the potential impacts of the CPP rule, with a focus on the relevant reliability 

impacts. NERC leveraged key information from these studies to identify cumulative impacts on a region-wide or 

interconnection-wide basis. Throughout this special assessment, a stakeholder advisory group formed by the 

NERC Planning Committee provided advice, input, and vetting of the underlying assumptions and publicly available 

data.

 

4 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/Potential_Reliability_Impacts_of_EPA_Proposed_CPP_Final.pdf.
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Goals and Objectives

The goals and objectives of this assessment are to: 

 Provide a resource and transmission adequacy evaluation given a number of potential scenarios that are 

driven by gas prices and state (as well as potential regional) implementation plans using different models 

to understand possible outcomes.

 Identify potential reliability risks and implications resulting from the projected resource mix changes to 

ERS characteristics, the increase in variable resources, the concentration of resources by fuel type 

(especially natural gas), the impacts on transmission requirements due to increased and potentially large 

power transfers, and other reliability characteristics, including Regional Entity planning reserve margins.

 Determine potential lead-time constraints associated with the electric and gas infrastructure 

enhancements needed to support the implementation of the proposed CPP.

 Assess industry analysis and studies from NERC reliability authorities (such as Transmission Planners and 

Operators and Reliability and Planning Coordinators) to determine if unique reliability issues may occur

as a result of implementing the CPP requirements.

 Provide an independent assessment of reliability that informs policy discussions on risks to BPS reliability 

and related emerging issues. 

Qualification

Significant uncertainty remains in the parameters of the final CPP rule, including compliance timeline flexibility;

CO2 targets and target calculation modifications; determination of whether groups of states (in addition to the 

Regional Greenhouse Gas Initiative (RGGI) states5) are able to coordinate to develop timely regional plans; details 

and coordination of the specific state implementation plans; federal model implementation plans or regional 

implementation plans; impacts of state selection of mass-based or rate-based limits; inclusion of regulatory 

reliability assurance mechanisms within the rule, etc. NERC recognizes that changes to any one of these 

parameters will have an effect on the analysis and results presented herein. As these uncertainties are resolved, 

further reliability impact analyses and assessments will be necessary to assess potential reliability implications. 

Notably, the approach to formulate internally consistent assumptions, which are then formed into key scenarios, 

is designed to provide benchmarks and guidance about potential reliability implications during the 

implementation of the CPP rule. The model results illustrate potential scenarios and outcomes at a specific point 

in time based on input assumptions also applicable to a specific point in time. Therefore, the results are 

representative of a range of potential outcomes used to assess potential reliability impacts, but may not be 

indicative of what will necessarily happen as other modeling based on different decisions or changes to the 

proposed rule would alter the results. 

NERC’s modeling is designed to mathematically solve for lowest cost options. It was conducted with the premise 

that new utility-scale generation will be constructed to replace existing generation and meet electricity demand 

in the future. From NERC’s perspective, the path to achieve the significant reductions in CO2 emissions is through 

resource mix changes on the BPS. NERC’s modeling is a conservative approach that does not rely on new 

technologies that are not yet widely integrated into the BPS or major changes in consumer choices and behaviors; 

however, NERC recognizes that significant additional conservation and distributed generation would have an 

impact on the results. 

 

5 Regional Greenhouse Gas Initiative: http://www.rggi.org/ (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, 

New York, Rhode Island, and Vermont).
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Assessment Approach 

NERC focused on providing insight and guidance about potential reliability aspects from implementing the 

proposed CPP and specifically did not assess effectiveness, desirability, or optimal alternative CO2 reduction 

methods. NERC’s role is to evaluate the composite framework of plans and implementation changes that can 

potentially impact the BPS, using technically sound long-term, seasonal, and special reliability assessments and 

known parameters, assumptions, scenarios, engineering judgment, and practicality based on historical 

performance. For its resource adequacy analysis, NERC used two generator dispatch models: AURORAxmp and 

IPM.6For its transmission adequacy analysis, NERC used the static power flow models for the Eastern and Western 

Interconnections. 

NERC retained three consultants to employ resources and transmission planning models to develop scenario 

results based on NERC’s input assumptions. The findings and conclusions are based on the independent analysis 

of NERC’s Reliability Assessment and Performance Analysis staff.

Key Findings

A transformative shift in resource use (or energy) leads to the need for transmission and gas infrastructure 

reinforcements, which will require additional time beyond currently proposed targets. This transformative change 

in the reliability characteristics of the resources supplying bulk power electricity places much greater emphasis on 

the need for adequate ERSs to be in place. The following key findings are components of NERC’s overall 

assessment:

1. Consistent with NERC’s Initial Reliability Review, the proposed CPP is expected to accelerate a 

fundamental change in electricity generation mix in the United States and transform grid-level 

reliability services, diversity, and flexibility. 

The anticipated changes in the generation mix and modified dispatch of resources driven by the proposed

CPP will require comprehensive reliability analysis to identify grid-level reliability needs to accommodate 

the resource mix and flexibility requirements. Generating resource changes that are already underway 

would be accelerated by the implementation of the CPP and are prompting the need for much greater 

understanding of the ERSs (e.g., frequency response, voltage support, and ramping capability) needed to 

support BPS reliability. Implementation of the CPP would accelerate an ongoing fundamental shift in the 

generation resource mix toward greater use of gas and renewables, which presents reliability challenges 

as new resources have different ERS characteristics than the current generation fleet. For example, the 

reliability characteristics of a synchronous coal-fired steam turbine vary greatly from those of 

asynchronous, inverter-based machines. 

Importantly, this transformation introduces changes to operations and expected behaviors of the system.

Finally, extensive power system studies and planning analysis need to occur to address expected changes 

in power flows and large multi-regional transfers. The power flow changes represented in NERC’s analysis 

demonstrate the continued evolution of resource deployment and use of renewable and natural gas 

generation. Over the next several years, these resource changes will require more transmission to 

integrate the new resources, meet increasing electricity demand, and enable new exports and imports to 

accommodate a new resource mix. Consistent with NERC’s conclusion in its overall assessments, power 

flow changes represent a significant planning and operational challenge, and sufficient time and 

coordination is needed to determine region-specific solutions.

2. Industry needs more time to develop coordinated plans to address shifts in generation and 

corresponding transmission reinforcements to address proposed CPP CO2 interim and other emission 

targets.

 

6 For further information on the AURORAxmp and IPM models please see Appendix A.
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NERC’s evaluations of the potential reliability implications of the proposed CPP and associated 

implementation plans by state or regional groups have identified fundamental changes in both the electric 

generation mix and corresponding transmission and gas pipeline infrastructure needed to accommodate 

these changes. Multi-regional and entity coordination is necessary to accommodate the long lead times 

for electric infrastructure and to ensure reliability during the implementation periods. A coordinated 

process not only ensures that stakeholders and consumers are provided sufficient time to review and 

respond to changes to the electricity grid, but it would also take into consideration NERC’s mandatory 

Reliability Standards and FERC orders on operation and planning coordination (such as FERC Order 10007). 

Geographic and resource diversity and a complex regulatory environment present challenges to the longterm development of electric power infrastructure. The time required for new facilities to be developed 

and placed in service may likely exceed the CPP’s proposed compliance targets. Because the industry will 

be implementing plans simultaneously, it is uncertain whether adequate equipment (e.g., generators, 

solar panels, wind facilities, transformers, and conductors) and resources (e.g., engineering, procurement, 

and construction) will be available to support those plans.

The interim target date within the EPA’s CPP proposal requires notable reductions of CO2 (approximately 

80 percent of the total reductions) by 2020. It is likely that infrastructure to support the required interim 

reduction in CO2 emissions at this pace will not be in service by 2020 for the following reasons:

Generation: Between 2015 and 2020, over 33.5 GW of generation capacity (e.g., coal, oil, gas, and 

nuclear) is expected to retire, based on NERC’s Reference Case from the 2014 Long-Term 

Reliability Assessment (2014LTRA). An additional 7 GW is expected to retire between 2021 and 

2025. In NERC’s modeling of the CPP, State and Regional Cases yielded approximately 43 GW and 

41 GW of retirements, respectively, between 2016 and 2020. Between 2020 and 2030, State and 

Regional Cases yielded an additional 42 GW and 44 GW of retirements, respectively. While 

replacement capacity may be able to repower coal to gas generation, others will require 

greenfield development, which on average will take between four and five years. From a Regional 

Entity perspective, areas with the greatest amount of resource retirements are ERCOT, SPP, NPCC,

and MISO, with approximately 10, 7, 11, and 9 GW of retirements, respectively, between 2016 

and 2020. Approximately 35 GW of non-hydro renewable energy (i.e., mostly wind and solar) is 

added due to the proposed CPP in all scenario results, in addition to planned variable energy 

resources (VERs).

Transmission: Based on NERC’s analysis, transmission-deficient areas have been identified. On 

average, transmission projects require between six and 15 years to engineer, site, permit, and 

construct, depending highly on the geography, length, and voltage class. From a Regional Entity 

perspective, areas needing the most transmission reinforcements are located in RF, NPCC, and 

the southwest area of WECC. As part of NERC’s CPP Phase I study, NERC requested information 

from industry on new generation and transmission facility construction lead times. The results 

represent perspectives from 110 different transmission and generation companies on timing 

requirements for additional new transmission and generation capacity. 

3. Implementation plans may change the use of the remaining coal-fired generating fleet from baseload 

to seasonal peaking, potentially eroding plant economics and operating feasibility.

A significant finding of the analysis points to an expected shift of existing coal-fired generation from 

baseload to seasonal peaking operations. According to NERC’s modeling analysis, between 14 and 22 GW 

of coal generation resources remain online through 2030; however, these units are considered at risk of 

retiring due to the plant economics associated with operating the units infrequently. To operate this 

 

7 FERC - Docket No. RM10-23-000; Order No. 1000.
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capacity on a seasonal peaking basis, the approximate capacity factors—a measure of their utilization—

would average between 11 and 19 percent after 2020. As capacity factors decline and operational 

functions transition from baseload to cycling, or peaking operations, maintenance and fixed costs to 

support a plant’s operation rise significantly. Based on industry experience, very low capacity factors for 

traditionally baseloaded plants will significantly increase overall costs due to required upgrades, repairs, 

staffing needs, and expected increased forced-outage rates. Under these conditions, the eroding plant 

economics of such generation resources renders their continued operation at risk and subject to potential 

retirement. In a wholesale electricity market structure, generators may need additional incentives (e.g., 

capacity payments) to keep low capacity factor fossil generation economic and in service.

4. Energy and capacity will shift to gas-fired generation, requiring additional infrastructure and pipeline

capacity. 

The implementation of the CPP final rule is expected to accelerate an ongoing shift toward greater use of 

natural-gas-fired generation. Increased dependence on natural gas use will require pipeline capacity, 

particularly during the winter season when natural gas use for electric power competes with residential 

heating. Approximately 60 GW of additional gas-fired capacity is estimated to be in service by 2020, and

approximately 80 GW by 2030. The additional capacity plus the higher use of gas-fired generation is 

expected to increase gas demand in the United States from 39 Bcf/d to 50 Bcf/d—an increase of 

approximately 30 percent. Local and regional pipeline infrastructure will be needed to relieve pipeline 

constraints and fuel firming for the electric industry. 

Recommendations 

1. NERC should continue to update and expand the assessments of the reliability implications of the 

proposed CPP and provide independent evaluations to stakeholders, states, regulators, and policy makers. 

NERC should continue to conduct a phased assessment strategy, recognizing that the proposed rule is not 

yet final and may change. These assessments will continue to provide insight and guidance as the CPP rule 

is finalized and state, regional, and federal implementation plans begin to materialize. 

2. Coordinated regional and multi-regional industry planning and analysis groups should continue to conduct 

detailed system evaluations to identify areas of reliability concern and work in partnership with states, 

regions, and policy makers to provide clear guidance of the complex interdependencies resulting from the 

CPP rule’s implementation.

3. Policy makers, states, regions, and regulators (including the EPA) should develop implementation plans

that allow for more time to address potential BPS reliability risks and infrastructure deployment

requirements during the transition period. 

4. The EPA should include a formal reliability assurance mechanism in the final rule that provides the 

regulatory certainty and explicit recognition of the need to ensure reliability during both the plan 

development and the implementation period through 2030—and potentially beyond. NERC has outlined 

a specific series of roles for providing reliability guidance and independent assessments, in the form of a 

reliability assurance mechanism.

5. State and regional plans should be developed in consultation with reliability authorities—Planning 

Coordinators and Transmission Planners—to review plans and demonstrate their reliability through 

established planning analyses and processes. 
NERC |Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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Chapter 1 – Introduction and Background

The intent of this assessment is to inform regulators, state officials, public utility commissioners, utilities, 

stakeholders, and other electric organizations of potential resource adequacy concerns and reliability risks of 

implementing the EPA’s CPP rule. This Phase I assessment can help stakeholders (1) make informed decisions 

about the reliability ramifications of the final rule, and (2) prepare imminent state and regional plans—as well as 

the requisite infrastructure—necessary to ensure the reliability of the BPS. NERC will continue to provide 

assessments of the CPP at various stages in the process, including as state and regional plans emerge and are 

submitted.

This chapter provides a background of NERC’s Initial Reliability Review, bridging that report with this study and 

setting the stage for future NERC reliability assessments of the CPP.

Overview of Initial Reliability Review

On June 2, 2014, the EPA issued its proposed Carbon Pollution Emission Guidelines for Existing Stationary Sources: 

Electric Utility Generating Units, referred to as the proposed Clean Power Plan (CPP).8 The CPP was issued under 

Section 111 (d) of the Clean Air Act, which introduces CO2 emission limits for existing electric generation facilities. 

The proposed CPP aims to cut CO2 emissions from existing power plants to 30 percent below 2005 levels by 2030. 

As part of the CPP, initial reductions will be mandated beginning in 2020 and will continue in subsequent years 

until the full amount of emission reductions are achieved by 2030. The CPP proposal would apply to fossil-fired 

generating units that meet four combined qualification criteria: (1) units that commenced construction prior to 

January 8, 2014; (2) units with design heat input of more than 250 MMBtu/hour (approximately a 25 MW unit); 

(3) units that supply over one-third of their potential output to the power grid; and (4) units that supply more than 

219,000 MWh/year on a three-year rolling average to the power grid. Given these criteria, the EPA estimates that 

3,104 U.S. fossil-fired electric generating units (EGUs), representing 702,381 MW of existing nameplate capacity, 

will be subject to the proposed rule’s limitations. NERC estimates that this magnitude represents approximately 

65 percent of the total existing nameplate capacity in the United States. 

According to the proposed plan, this can be achieved by developing state-specific emission rates that limit CO2 by 

applying four different building blocks for the Best System of Emission Reduction (BSER). The building blocks

provide options to reduce emissions by (1) improving coal unit heat rates, (2) using more natural-gas-fired 

generating facilities, (3) increasing the penetration of renewable resources, and (4) expanding energy efficiency 

measures. These building blocks provide some options to attain CPP compliance, but other methods to achieve 

the specified reductions can be employed. In itsInitial Reliability Review, NERC conducted a preliminary evaluation 

of the CPP. This involved, in particular, studying the implications of the building blocks and the overall potential 

effects of the proposed CPP on BPS reliability. The Initial Reliability Review concluded that the implementation of 

the CPP had the potential to impact the reliability of the BPS.

NERC made the following general recommendations:

1. NERC should continue to assess the reliability implications of the proposed CPP and provide independent 

evaluations to stakeholders and policy makers.

2. Coordinated regional and multi-regional industry planning and analysis groups should immediately begin 

detailed system evaluations to identify areas of concern and work in partnership with policy makers to 

ensure there is clear understanding of the complex interdependencies resulting from the rule’s 

implementation.

 

8 Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units.
Chapter 1 – Introduction and Background

NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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3. If the environmental goals are to be achieved, policy makers and the EPA should consider BPS reliability 

concerns around the requisite timing for associated infrastructure deployments.

In addition, NERC made the following recommendations to industry, regulators, and stakeholders:

 The Regional Entities, Independent System Operators and Regional Transmission Organizations

(ISO/RTOs), and states should perform further analyses to examine potential resource adequacy concerns.

 The EPA and states, along with industry, should consider the time required to integrate potential 

transmission enhancements and additions necessary to address impacts to reliability from the proposed 

CPP. The EPA and policy makers should recognize the complexity of the reliability challenges posed by the 

rule and ensure that sufficient time is provided for industry to make the necessary changes in order to 

achieve compliance.

 ISO/RTOs, states, and Regional Entities should prepare for the potential impacts to grid reliability, taking 

into consideration the time required to plan and build infrastructure.

 The EPA, FERC, the DOE, and state utility regulators should employ the array of tools and their regulatory 

authority to develop a reliability assurance mechanism.

 Further coordinated planning between the electric and gas sectors will be needed to ensure a strong and 

integrated system of fuel delivery and generation adequacy.

 ISO/RTOs, utilities, and Regional Entities (with NERC oversight) should analyze the impacts to ERSs in order 

to maintain reliability.

 NERC should determine grid-level performance expectations by employing a technology-neutral 

perspective to ensure ERS targets are met.

 The development of technologies (such as electricity storage) helps support the reliability objectives of 

the BPS, and these technologies should be expedited to support the additional variability and uncertainty 

on the BPS.

 ISO/RTOs and system planners and operators should consider the increasing penetration of distributed 

energy resources (DERs) and potential reliability impacts due to the limited visibility and controllability of 

these resources.

In its Initial Reliability Review, NERC also highlighted its objective of publishing assessments on the CPP as the EPA 

prepares to issue its final rule, which the EPA has indicated will be released midsummer 2015. Additionally, NERC 

will perform assessments as state implementation plans and regional implementation plans emerge, as well as 

once those implementation plans have been finalized. Please see Figure 1 for the scheduled timeline of additional 

NERC assessments.
Chapter 1 – Introduction and Background

NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

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Figure 1: NERC’s Multiple-Phase Approach to Reliability Assessment

NERC’s Phase I analysis is conducted in three parts:

Part 1: NERC Resource Adequacy Scenarios and Analyses 

The CPP offers flexibility to the states on how to most effectively achieve the CO2 reductions through the use of 

the four building blocks. As highlighted in NERC’s initial assessment, if reductions are not achievable in certain 

building blocks, offsetting reductions will be needed in the other building blocks. Because the building blocks are 

interdependent, additional information and assessment is needed to understand what reductions are within the 

range of moderately to highly likely, what regional options exist for meeting the state-mandated reductions, and 

what technologies, infrastructure, and resources are needed to achieve compliance. 

This assessment is similar to the analysis conducted by the EPA in its Regulatory Impact Analysis.

9 NERC 

established assumptions and parameters based on industry input and publicly available data to gain a better 

understanding of the range of potential outcomes. NERC used these input assumptions to model results using two 

different electric generator dispatch models: AURORAxmp and the Integrated Planning Model (IPM).

The key objectives of Part 1 are to:

 Determine how achieving the CO2 reduction goals as established by the proposed CPP will impact the U.S. 

generation mix and resource adequacy, based on a set of model input assumptions. 

 Conduct sensitivity analysis to examine the range of potential outcomes between state and regional 

implementations, as well as a range of projections for natural gas prices.

 Compare the AURORAxmp and IPM model outputs.

Approach to Modeling Resource Adequacy

NERC conducted a quantitative assessment that included an analysis of both regional and state implementation, 

as well as gas price scenarios. NERC staff and industry subject matter experts reviewed the model assumptions 

and inputs.

10 Table 1 provides an overview of these analyses. 

 

9 Regulatory Impact Study.

10 NERC Advisory Group comprised of NERC’s Planning Committee members and industry representatives.
Chapter 1 – Introduction and Background

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NERC analyzed five scenarios, as outlined below:

1. Reference Case – No CPP: Business as usual used as a study benchmark for the EPA’s state and regional 

cases. 

2. CPP State Case – No Interstate Trading: Rate-to-mass translation proposal for mass-based conversions 

(using affected unit limitations only) with state implementation. 

3. CPP Region Case – Interstate Trading: Rate-to-mass translation proposal for mass-based conversions 

(using affected unit limitations only) with regional implementation.

4. Reference Low-Gas Case – No CPP and Low-Gas-Price Scenario: Used as a study benchmark for the EPA’s 

state and regional cases using NERC’s low-gas price scenarios. 

5. CPP State Low-Gas Case – No Interstate Trading and Low-Gas-Price Scenario: Rate-to-mass translation 

with a state implementation scenario.

Part 2: Transmission Adequacy and Infrastructure Upgrade

In its Initial Reliability Review, NERC recommended that the EPA and policy makers ensure the rule provides 

sufficient time for the industry to address the accelerated change in resource mix. These changes to the system 

will require transmission additions, enhancements, and operational adjustments to avoid reliability impacts to the 

BPS. In response to this recommendation, the evaluation of generation and transmission adequacy includes a 

steady-state (power flow) analysis of the Eastern and Western Interconnections.11 Generation retirements and 

projected additions from the Resource Adequacy section of this report are used as inputs for this power system 

analysis.

The key objectives of Part 2 are to:

 Provide a high-level analysis of transmission reinforcement required to meet the EPA emission reduction 

proposal.

 Identify major shortfalls of reactive power support on a regional basis.

 

11 ERCOT was analyzed separately in their study, as summarized in Part 3.

Table 1: Summary of Proposed CPP Cases

Modeling Case

Reference 

Case

(NO CPP)

CPP State

Case

CPP Region

Case

Reference 

Low Gas

(No CPP)

CPP State

Low Gas

Modeling Case Number 1 2 3 4 5

Implementation 

Assumptions

Rate-to-Mass 

Translation N/A Yes Yes N/A Yes

Gas Price Input EIA AEO 2014 EIA AEO 

2014

EIA AEO 

2014

EIA AEO 

2014 Low

EIA AEO 

2014 Low

Implementation N/A State Regional N/A State
Chapter 1 – Introduction and Background

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Approach to Transmission Impacts

NERC analyzed two scenarios based on state and regional implementation of the proposed CPP. In both cases, the 

analysis centered on a 2020 summer loading condition.

Part 3: Summary of Existing Studies 

In its initial reliability assessment, NERC highlighted the need for more industry studies to evaluate reliability. 

Some ISO/RTOs and utilities have conducted studies that identify reliability challenges associated with the 

proposed CPP, while other studies indicate less risk. NERC has leveraged key information from these studies to 

identify cumulative impacts on a region-wide basis. The objectives of this section of the report are to (1) provide 

a summary of industry studies, highlighting specific areas of concern, and (2) identify parallels between industry 

studies and NERC’s analysis.

Approach to Summarizing Existing Studies

NERC conducted a survey with stakeholders requesting studies of CPP implementation. This section includes a 

representative number of industry studies and highlights their key issues. It then interconnects them with NERC’s 

overall Phase I assessment. 

NERC also analyzed data from stakeholders, who provided additional insight into infrastructure on both 

transmission and generation, and the necessary lead times to construct, plan, and permit new transmission and

new natural gas pipeline infrastructure. These data become important as requisite transmission and natural gas 

pipeline infrastructure needed to meet the requirements of the CPP within the stipulated time framesisidentified.

Resource Adequacy and Transmission Adequacy Study and Scenario Background 

In its analysis on both resource and transmission adequacy, NERC retained consultants to employ resource and 

transmission planning models to study scenarios based on NERC input assumptions. NERC retained BBA Inc. to 

conduct transmission adequacy modeling and ICF International (ICF) and Energy Ventures Analysis Inc. (EVA) to 

conduct resource adequacy modeling. Both ICF and EVA were retained so that results and trends could be 

compared by employing two widely used resource modeling tools in the industry, the IPM and AURORAxmp 

models.

A graphical representation of the key components of the NERC analysis approach, reliability elements, and relation 

to NERC’s Phase I study is depicted in Figure 2.
Chapter 1 – Introduction and Background

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Figure 2: Overview of NERC Analysis Approach for Parts 1 and 2
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Chapter 2 – Modeling Assumptions for Resource Adequacy and 

Power System Analysis

NERC ran a series of resource adequacy models to examine a range of potential outcomes as the electric industry 

responds to mandates and timeline requirements as stipulated in the proposed CPP. Specifically, the models

employed assume that the CO2 reduction goals as outlined by the CPP will be achieved, providing potential insights 

to resource adequacy and reliability impacts. The model results illustrate potential scenarios and outcomes at a 

specific point in time based on input assumptions also applicable to a specific point in time. Therefore, the results 

are representative of a range of potential outcomes used to assess potential reliability impacts, but are not 

indicative of what will necessarily happen. Both the AURORAxmp and IPM electric power dispatch models were 

used in this assessment. All inputs and assumptions were thoroughly reviewed by NERC staff and peer reviewed 

by industry subject matter experts. An overview of these model inputs for the resource adequacy and power 

system analysis is presented below.

12

 Emission-Reduction Goals: CO2 reduction goals achieved, as designated by the proposed CPP.

 Rate-to-Mass-Based: NERC utilized the “rate-to-mass translation” proposal as contained in the EPA’s 

November 6, 2014 Guidelines for Existing Stationary Sources.

13

 Shadow Prices: Shadow prices for carbon penalties per pound were developed economically so the 

carbon penalties became high enough to retire or reduce output accordingly,such that the CO2 reductions 

would be attained in each state or region.14

 Demand: Annual electricity hourly demand projections of 1.0 percent growth when averaged over the 25-

year period and incorporating energy efficiency growth.15 This load-growth rate was compared with other 

load projections, including NERC’s 2014LTRA and the EIA’s 2014 Annual Energy Outlook (AEO), and it aligns 

with these projections.

16

 Energy and Capacity: By fuel technology, as well as prices by NERC Assessment Area.

 Capacity Additions: A power plant tracking database was used that consists of a detailed list of planned 

electric power plants with likelihood of construction. Gas-fired additions based on distance from existing 

natural gas pipelines; renewable additions are assumed to occur in areas abundant in wind and solar.

 Capacity Retirements: Based on cost-optimization analysis. 

 Nuclear Capacity: All facilities currently under construction will be in service as scheduled; at-risk facilities 

will remain in service through the time frame of this analysis.

 Capacity Costs: New generators will be built and existing generators retired or derated based on 

economics (i.e., capital costs and operating parameters for existing and new units by fuel type and 

technology). Both models optimize resources based on the lowest cost to meet electricity demand and 

maintain reserve margin requirements.

 Natural Gas Prices: The EIA’s 2014 AEO Henry Hub natural gas price curves, with an application of prices 

calibrated on a regional level, using the applicable basis differentials.

 Transmission Facilities: Existing substation, transmission, and reactive power facilities taken into account 

to maximize the use of current facilities.

 

12 Detailed data input assumptions and model results for both the AURORAxmp and IPM models are published with this report and available 

at: http://www.nerc.com/Pages/default.aspx. 

13 Additional Information Regarding The Translation Of Emission Rate Based CO2 Goals To Mass Based Equivalents.

14 A shadow price is the estimated price of a good or service for which no market price exists.

15 Electric Power Research Institute’s U.S. Energy Efficiency Potential Through 2035 Report.

16 NERC’s 2014 LTRA and EIA’s 2014 Annual Energy Outlook (AEO).
Chapter 2 – Modeling Assumptions for Resource Adequacy and Power System Analysis

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 Renewable Energy: Publicly available data from EIA and NREL, as well as other data from trade group 

databases, was used as model inputs for existing and projected renewable energy. For projected 

renewable resources with a 1–5-year in-service time frame, the assumptions were as follows: nearly 100 

percent completion of projects under construction, 50–75 percent of capacity under advanced 

development (varies by projected online date and technology), and 5–30 percent of capacity under early 

development. For long-term renewable capacity additions, the following factors were also taken into 

consideration: (1)state renewable resource quality and potential, (2)state renewable portfolio standards,

(3) historical/forecast future renewable generation growth trends, and (4) data from the DOE’s 2014 

Annual Energy Outlook.

The following assumptions were used for the scenario cases:

 Low-Gas-Price Scenario: EIA’s Low-Gas-Price Case was used with an application of prices calibrated on a 

regional level, using the basis differentials. 

 Regional Implementation Scenario: For multi-state implementation, NERC developed emission-trading

regions, leveraging existing market areas, FRCC and SERC, and the existing RGGI states. 

Mass- vs. Rate-Based Limitation Approach

The proposed EPA CPP allows the states to select between CO2 rate-based limitations (lbs CO2/MWh) or a 

mass-based limitation (tons/year) in their state implementation plans. To be approved, the state plan must 

demonstrate that it is enforceable and compliant with the proposed EPA state CO2 emission rate limitation. 

Subsequent to its proposal, the EPA issued guidance to states that outlined state mass-based cap limits for 

the affected sources within each state, which the EPA would automatically approve. 

Based on discussions with states and utilities, there is an overwhelming consensus that a majority of states 

may adopt a mass-based cap that would be much simpler to implement and enforce through an administered 

cap-and-trade program, such as the one used by the nine states within the RGGI or California. The other 39

contiguous states would need to develop similar legislation and regulations to allocate or auction a set 

number of allowances each year. The affected sources must hold and retire a sufficient number of allowances 

to cover their annual emissions each year beginning in 2020. This study incorporates these preapproved stateby-state mass limitations. It would be far more complex for states to pursue the alternative state CO2 ratebased limitation as states would be required to develop individual unit CO2 rate limitations and net output 

power restrictions for each affected source that can be enforceable by integrating these conditions into their

operating air permit. The expertise to develop such CO2 rate limitations to adjust for the normal changes in 

heat-rate efficiency through the operating cycle would require detailed unit-specific engineering design and 

historical operating data. Such data takes time and resources to collect and evaluate.
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Chapter 3 – Resource Adequacy Assessment

The CPP offers flexibility to the states on how to most effectively achieve the CO2 reductions through the use of 

the four building blocks or other means. NERC used two models to assess the sensitivity impact of varying factors.

The objectives of the resource adequacy study are listed below.

Objectives

 Assess how the heat-rate assumptions, gas use, renewable energy, and energy efficiency assumptions 

impact generation retirements and renewable- and gas-generation needs. 

 Conduct sensitivity analysis to understand the range of potential outcomes between state and regional 

options.

 Compare the results to the IPM model output.

 Identify resource adequacy trends and results using NERC’s 2014 LTRA as a starting point. 

Background

NERC used the commercially available AURORAxmp electric power market forecasting tool. AURORAxmp is a 

fundamentals-based power market model that economically dispatches generation capacity to simulate the 

operations of each power market in the continental United States. The model optimizes generator dispatch by 

using the lowest-cost resources to meet electricity demand in a given region at the hourly level and builds the 

most economic new resources to meet reserve margin targets and future load growth. This model examined the 

following cases: (1) Reference Case (no CPP), (2) CPP state implementation, (3) CPP regional implementation, (4) 

Low Gas (no CPP), and (5) Low Gas with CPP state implementation. 

These multiple scenarios were selected to assess the sensitivity impacts of varying factors. Specifically, the EPA 

provides potential implementation options using either state or multi-state compliance approaches. Assessing 

each approach provides a range of resource adequacy implications to inform stakeholders and policy makers.

Similarly, a lower natural gas price scenario was modeled to isolate and examine the effects of this component on 

both energy and capacity.

Additionally, NERC performed modeling with the IPM model (the EPA’s analysis also used the IPM model) by

applying the input assumptions described in Chapter 2. IPM was chosen as a modeling platform to complement

the results of the AURORAxmp modeling effort, and also as a comparison to the EPA’s analysis.

The model assumes that the market will reduce emissions to a level that exactly meets CPP compliance. In 

practice, resource planners target a rate of emissions that is well within the necessary compliance requirements 

to avoid any risk of noncompliance—a condition referred to as “over-compliance.” Accordingly, plans will likely 

be developed to accommodate a specific compliance strategy.
Chapter 3 – Resource Adequacy Assessment

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Scenario Modeling Cases

NERC conducted a resource adequacy analysis by running two different models—AURORAxmp and IPM—with the 

application of the input assumptions described in Chapter 2. These models examined the following cases: (1) 

Reference Case (no CPP), (2) CPP state implementation, (3) CPP regional implementation, (4) Low Gas (no CPP), 

and (5) Low Gas with CPP state implementation.

NERC-assumed compliance regions are shown 

in Figure 3. NERC scenarios that reflect possible 

outcomes of the CPP are specified in Figure 4.

CPP State, Regional, and Low-Gas scenarios 

assume that states implement the CPP 

standards as mass-based (or tonnage-based)

caps on CO2 emissions rather than as emissionrate standards, as the EPA modeled the 

program in its Regulatory Impact Analysis. 

NERC’s assumed mass caps were based on the

EPA’s calculated caps, as presented in the EPA’s 

November 2014 Rate-to-Mass Technical 

Support Document. In all CPP scenarios, the 

mass caps were imposed on existing emitting sources only. Capacity coming online after 2014 was not assumed 

to be subject to the caps as it falls under the requirements of the EPA’s New Source Performance Standards 

(NSPSs). The CPP state scenarios assume that states achieve the standards individually, without any mechanism 

for contributing to each other’s compliance needs other than through existing transmission resources. Within 

each state, affected sources meet the state mass limit through CO2 allowance trading, resulting in an allowance 

price in dollars per ton emitted for each state. The CPP regional scenario assumes that states meet the standards 

as part of regional (multi-state) groups, assuming trading of allowances across state borders and regional CO2

allowance prices. Lower natural gas price scenarios were modeled to isolate and examine the effects of this 

component on both energy and capacity.

NERC’s Initial Reliability Review focused significantly on the EPA building block assumptions and the achievability 

of those building blocks, as well as the potential implications to BPS reliability. Phase I assumes that the building 

blocks, as well as any other attainable methods, will be used by industry to develop a BSER and, as a result, that

CO2 emission reductions are met as stipulated in the proposed CPP. 

Figure 3: NERC Regional Trading Map Assumptions
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Figure 4: Summary of NERC Clean Power Plan Scenario Cases

The EPA CPP proposes state-specific limitations based on the application of four building blocks (process efficiency 

improvements, gas redispatching, clean energy, and energy efficiency) and assumed performance for each 

element. This approach results in a wide range of state requirements and compliance costs. The gas redispatching 

building block contributes most directly to state rate differences. States with large amounts of underutilized gas 

combined-cycle capacity in 2012 were given strict limitations, assuming that all of this capacity could displace coal 

unit generation. As a result, the limits assume existing coal generation would be completely displaced in 11 states 

(AK, AZ, CA, CT, MA, MS, NV, NH, NJ, OR, and WA) and by more than 90 percent in two other states (FL and NY). 

In these cases, the state CO2 rates are very close to the natural gas combined-cycle (NGCC) CO2 emission rates. On 

the other hand, 12 states (HI, IN, KS, KY, MD, MT, NE, ND, OH, TN, WV, and WY) had little to no underused natural 

gas combined-cycle capacity, so the final state rate limitation was set to be closer to the average coal limitation. 

The differences in state limitations directly contribute to significant differences in the CO2 penalties between 

states and can change power flows between states. Under the CPP, the costs include CO2 allowances (i.e., shadow 

prices) as shown in Figures 5 and 6. The models assumed trading of carbon emissions would occur in regional 

groupings across typical RTO/ISOs and contiguous regions. Whereas carbon shadow prices among states indicate 

differing economic values, NERC’s model assumes trading would occur using physical power flows, which may not 

capture the same level of value that other potential trading mechanisms might provide as a result of a CPP final 

rule. 
Chapter 3 – Resource Adequacy Assessment

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Figure 5: AURORAxmp Model CPP State, Region, and CPP State Low-Gas Case Shadow Prices in 2020

Figure 6: AURORAxmp Model CPP State, Region, and CPP State Low-Gas Case Shadow Prices in 2030
Chapter 3 – Resource Adequacy Assessment

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If a unit retires, it reduces emissions under the cap for a state or region, thereby freeing up space for other units, 

such as lower-emitting gas units, to operate. Both IPM and AURORAxmp can add new generation capacity to 

replace generation and capacity lost by retirements and meet growing demand where necessary. New capacity is 

not covered by the CPP emission caps; models can add capacity with any level of emissions, as long as the unit 

emits at a rate that complies with the assumed NSPS requirements. The models must balance retirements with 

new capacity and capacity transfers via transmission resources to meet specified NERC reserve margin 

requirements in every year.

Key Results from the Resource Adequacy Assessments

The following section provides a summary of key results of the NERC Reference Case, CPP State Case, and CPP 

Regional Case. For the purposes of this summary, the discussion focuses on national-level results, along with select 

results for multi-state regions, where appropriate.

CPP Impact on Capacity

All scenarios indicate modest acceleration of retirements but project a large shift in use and operational behavior 

of coal-fired generation:

 Approximately 18 GW of coal-fired generation retires between 2016 and 2020, and an additional 18 GW 

retire between 2020 and 2030 under the CPP State Case. Nearly 40 GW of coal-fired generation retires in 

the CPP Low-Gas State Case—20 GW between 2016 and 2020, and 20 GW between 2020 and 2030. In 

addition to retirement of coal-fired plants, remaining coal runs at significantly lower capacity factors 

(which is further detailed in the CPP Impact on Coal Generation (Energy) section). 

Non-Hydro Renewable Capacity 

Non-hydro renewable generation resources increase—but only moderately—due to the expiration of Production 

Tax Credits (PTCs), the reduced Investment Tax Credits (ITCs), and the lower cost of natural gas generation.

 Approximately 8 GW of wind and 5 GW of solar are built between 2016 and 2020, and 15 GW of wind and 

7 GW of solar between 2020 and 2030.

 Based on NERC’s modeling assumptions, State and Regional Cases were not significantly different from a 

generation capacity perspective. This similarity is a result of non-hydro renewable resources primarily 

being built to accommodate renewable portfolio standards (RPSs), which are equivalent in both state and 

regional scenarios.

 While generation use and ability to trade varied, the economic benefits in the regional scenario did not 

significantly affect retirement decisions.
Chapter 3 – Resource Adequacy Assessment

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Table 2 shows capacity changes among generation types. 

Table 2: NERC-AURORAxmp CPP State and Regional Cases (GW) Capacity Change17

CPP State CPP Regional

2016-2020 2020-2030 2016-2020 2020-2030

Coal Retirements 18 18 17 20

Net Oil and Gas Retirements 25 24 24 24

Natural Gas Additions 61 73 63 79

Wind Capacity Additions 8 15 8 15

Solar Additions 5 7 5 7

Total Additions 74 95 76 101

Total Retirements 43 42 41 44

 

17 Cumulative Oil and Gas retirements include peaking units, steam gas units, and steam oil units. Cumulative Natural Gas (NG) additions 

include Gas Turbine (GT) and Combined-Cycle Gas Turbine (CCGT) units. 
Chapter 3 – Resource Adequacy Assessment

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Figure 7 shows the capacity mix of the Reference (no CPP), CPP State, CPP Regional, and CPP State Low-Gas Cases 

modeled using AURORAxmp. Coal capacity as a percentage of total market share drops by 5.1 percent in the CPP 

State Case in 2030 from its reference 2016 level and by 5.5 percent in the CPP State Low-Gas Case in 2030

compared to its reference 2016 level. Natural gas makes up for most of the coal decline, increasing its total 

capacity share by nearly 5 percent in the CPP State Case in 2030 compared to the Reference Case in 2016, and by 

5.5 percent in the CPP State Low-Gas scenario in 2030. State and Regional Cases yield similar results for coal 

retirements as well as natural gas and non-hydro renewable additions. However, a final CPP rule could incorporate 

different emissions trading scenarios outside of the regional scenarios modeled by NERC, which modeled trading 

around typical ISO/RTO regions.

Figure 7: Percent Capacity Mix for NERC Scenario Cases
Chapter 3 – Resource Adequacy Assessment

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The changes in capacity (GW) for all fuel types from 2016 to 2020 and from 2016 to 2030 are shown in Figure 8. 

The total change of natural gas capacity is nearly doubled after the year 2020 when the CPP starts to take effect, 

and decreases in coal capacity double.

Figure 8: AURORAxmp Change (GW) in Capacity Mix for CPP State Case from 2016 to 2030
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Changes in coal generation in terawatt hours are shown in Figure 9, comparing the Reference Case to the CPP 

State Case, CPP Regional Case, and CPP State Low Gas Case. The figure shows the decline in coal generation in 

terawatt hours as a result of the CPP.

Figure 9: AURORAxmp Projected Coal Generation (TWh) – NERC Reference and Scenario Cases
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Conceptual Example Demonstrating “At Risk” Coal Generation due to Low Capacity Factors

NERC assumes that a carbon trading market will emerge; however, coal capacity retirements could increase by an 

additional 14 to 22 GW if additional incentives (e.g., capacity payments) do not develop in certain markets. As part of 

a lowest-cost generation mix, some coal generation would be operated on a seasonal basis. Should the capacity market 

not develop to cover the fixed costs for these coal assets, they could retire and be replaced by higher-cost, new-peaking, 

gas-fired capacity.

Baseload power plants (specifically coal plants for this illustration) are designed to run at high capacity factors and at 

high output levels. A plant running at 100 percent capacity factor would operate 8,760 hours per year—operating at 

200–500 hours per year, the capacity factor would be under 6 percent. This lower capacity factor would cause the 

plants to operate on a much higher $/MWh output cost.

Fixed Costs: The fixed costs for a power plant are significant. Since these costs will not change whether the unit is 

operated at 100 percent or 6 percent, that will impact the $/MWh calculation dramatically. 

 Fixed costs include certain operations and maintenance expenses, administrative expenses, property taxes, 

carrying charges, and corporate overheads. For a 600 MW unit, these might be approximately $25M annually 

(this is an estimate for illustrative purposes).

 $25M/600 MW/8760 hours of run time would equate to a fixed cost of $4.75/MWh.

 $25M/600/500 hours of run time would equate to a fixed cost of $83/MWh.

 In addition, the unit incurs auxiliary power expenses for minimum heating, lighting, and other minimal running 

expenses. 

Start-up Costs: If a unit is operated at only 500 hours per year, the unit is likely either (1) only needed during peak load 

days or (2) used as a cycling unit to meet daily short-term load needs.

 Depending on the size of the unit, it can cost over $100,000 each time a unit is started from a cold start 

position. Even if the 600 MW unit used in the example were run for 24 hours after starting up, it would cost 

an additional $6.90/MWh ($100,000/600/24). This makes it uneconomical in most cases to utilize a baseload 

coal unit as a cycling unit.

 This $/MWh example ignores the additional structural damage done to a unit each time it is started. This 

increases the need for more frequent maintenance outages.

 Just being idle also increases the potential for forced outages. This was the main reason PJM re-implemented 

a winter testing procedure for units that had not operated for several weeks before the winter period.

Heat Rate: Another reason a unit might operate at a low capacity factor is when it is needed in reserve for voltage 

support, black start, or transmission congestion. In these situations, when a unit is not needed at full load, it will operate 

at a suboptimal heat rate factor. This causes inefficiencies in the plant’s operation and higher $/MWH costs.

 The heat rate for units operating at minimum load is approximately 20 percent higher (i.e., less efficient) than 

a unit’s heat rate operating at maximum output.

 Coal pile inventories sitting unused tend to collect moisture, causing further inefficiencies and higher heat 

rates. 

Additionally, retirement decisions, to some extent, are also driven by whether the plant is in the market or in a vertically 

integrated regulatory structure. Units with low capacity factors in a market may succumb to the cost structure 

challenges highlighted above. However, in a vertically integrated environment, the plant is already in the rate base and 

may be kept in service for various reasons, including local politics or the impact on the local economy. Vertically 

integrated utilities may have to prove to the state utility commission that there are soft benefits to keeping the asset 

in the rate base. 
Chapter 3 – Resource Adequacy Assessment

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Table 3 shows the IPM capacity changes in GW between 2016 and 2020 and between 2020 and 2030 for the CPP 

State and Regional Cases. The model shows that most of the coal retirements, approximately 31 GW in both the 

State and Regional Cases, happen between 2016 and 2020 and about 2 to 3.5 GW retires between 2020 and 2030. 

Similarly, non-hydro renewable capacity increased between 2016 and 2020; nearly 24 GW for wind and about 7 

GW for solar capacity.

Table 3: NERC-IPM Model GW Capacity Change18

CPP State CPP Regional

2016-2020 2020-2030 2016-2020 2020-2030

Coal Retirements 31 2 31 3

Net Oil and Gas Retirements 16 8 14 10

NG Additions 83 52 82 51

Wind Capacity Additions 24 2 22 2

Solar Additions 7 13 7 13

Total Additions 114 67 111 66

Total Retirements 47 10 45 13

 

18 Cumulative Oil and Gas retirements include peaking units, steam gas units, steam oil units, and Combined Cycle Gas Turbine (CCGT) units. 

Cumulative Natural Gas (NG) additions include Gas Turbine (GT) and Combined Cycle Gas Turbine (CCGT) units. 
Chapter 3 – Resource Adequacy Assessment

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CPP Impact on Coal and Gas Generation (Energy)

One of the underlying causes for the decline in coal capacity and generation is the carbon penalty component of 

the new dispatch. To reduce carbon emissions to meet the proposed EPA program state mass limitations, the 

generation dispatch shifts away from coal toward a greater mix of lower-emitting resources. Overall, the 

AURORAxmp model shows that the CPP would cause a 27 percent drop in coal generation in 2020 from the 

Reference (no CPP) Case and a 33 percent drop by 2030. This decline in coal generation as a result of the CPP 

implementation will largely be replaced by NGCC generation.

Figure 10 shows coal consumption declining by 41 TWh between 2016 and 2020 and by an additional 20 TWh 

between 2020 and 2030 in the Reference (no CPP) Case. However, in the CPP State Case, there is a 479 TWh 

decline in coal consumption from 2016 to 2020 and an additional 113 TWh decline from 2020 to 2030.

Figure 10: AURORAxmp Energy (TWh) Coal and Natural Gas Generation Change from 2016 to 2020 and from 

2016 to 2030

The continuing shift to natural gas will require additional pipeline capacity to support fuel needs.

 In the CPP State Case, natural gas generation increased from approximately 970 TWh in 2016 to 1,770 

TWh in 2030. When employing the CPP State Low-Gas scenario, natural gas generation increased from 

approximately 1,390 TWh in 2016 to 1,970 TWh in 2030.

 Approximately 11 Bcf/d of additional natural gassupply is needed to support the new gas-fired generation 

by 2030.

The IPM model confirms this same trend for the period between 2020 and 2030. The CPP requirements force a 

change in the generation mix, as the system must increase the dispatch of new resources and lower-emitting 

existing resources to displace higher-emitting resources under the emission cap limits. 
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Figure 11 shows the IPM share of generation mix by type for 2020 and 2030 by case. The impacts of the CPP are 

very similar in both the CPP State and CPP Regional Cases. In both cases, gas increases its share to over 35 percent 

at the expense of coal, as compared to 28 percent in the Reference Case. Coal generation declines to 

approximately 28 percent, as compared to over 36 percent in the Reference Case. Generation shares of other 

technologies remain equivalent across the Reference and CPP Cases.

Figure 11: IPM Generation (Percentage of Total GWh) Mix by Type, 2020 and 203019

Impact of Increased Use of Natural-Gas-Fired Generation on Infrastructure

The implementation of the proposed CPP will cause a shift in the resource mix due to the retirement of higheremitting CO2 units being displaced by lower-emitting CO2units. The higher-emitting units are predominantly coalfired generation being replaced by natural gas and renewable generation. The AURORAxmp model demonstrates 

a 13 percent decline in coal generation capacity and a 36 percent increase in natural-gas-fired generation capacity 

by 2030 from the reference 2016 levels, including gas turbine and steam turbine units. In addition, about 22 GW 

of at-risk coal generation could potentially retire. The AURORAxmp model shows a significant shift in the use of 

natural gas generation to make up for the decrease in coal-fired generation. Natural gas electricity generation 

increased by approximately 300 TWh in 2020 and 2030 when comparing the Reference Case to the CPP State Case. 

This results in an approximate 7 Bcf/d increase in natural gas use.

 

19 Non-hydro renewable GW capacity includes existing and planned biomass and landfill resources and existing and planned wind and solar 

capacity resources. 
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In the CPP State Low-Gas scenario, the results demonstrate additional natural gas usage compared to the CPP 

State and Regional Cases. In 2020 and 2030, there are increases of 459 TWh and 495 TWh, respectively, in natural 

gas from the Reference (no CPP) Case, as shown in Figure 12.

Figure 12: AURORAxmp Projected Natural Gas Generation (TWh) – NERC Reference and Scenario Cases

As a result of the CPP, there is an increased use of natural gas resources. Figures 13 and 14 demonstrate the 

increased reliance on natural-gas-fired generation. 

Figure 13: AURORAxmp Average Gas Demand (Bcf/d) Between 2016 and 2020
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Figure 14: AURORAxmp Average Gas Demand (Bcf/d) Between 2020 and 2030

As shown, the natural gas use increases from 39 Bcf/d in the Low-Gas CPP State between 2016 and 2020 (Figure 

13) to 50 Bcf/d in the Low-Gas CPP State for 2020–2030 (Figure 14) for the month of July. This represents an 

approximate 30 percent increase in gas use of existing and planned natural-gas-fired generation to support the 

proposed CPP target. This 30 percent of extra capacity needed to support CPP would have to compete with existing 

firm gas capacity procured for residential heating and industrial needs. In addition to electric infrastructure, gas 

infrastructure would also need to be enhanced to accommodate the increased consumption of gas. As delineated 

in Chapter 5, natural gas pipeline projects require approximately three years from conception to inception. 

Additional time will be required if the project is larger and complications arise during construction.

Non-Hydro Renewable Generation and Capacity Reliability 

The North American BPS is currently undergoing a significant change in the mix of generation resources. Driven 

by a combination of factors, the rate of change in certain areas is having a tremendous impact on the planning 

and operation of the BPS. For example, current environmental regulations are contributing to substantial 

retirement of conventional coal-fired generation, while RPSs and other factors are driving the development of 

VERs. The CPP rule, as proposed, will further challenge BPS reliability as a result of increased coal retirements, the 

increased utilization of natural gas generation, and non-hydro renewable energy sources such as wind and solar 

energy. This resource shift has impacted and will continue to impact BPS operational characteristics and long-term 

resource planning. The additional renewable power will not only increase the need for ancillary services (e.g.,

frequency response and reserves) but also create additional planning and operational needs as its market share

continues to grow. The model showed that given the projected increases in wholesale power costs, higher retail 

prices will spur some incremental renewable power from distributed generation resources not under grid 

operator control—especially in areas with good solar and wind resources and state incentives. To accommodate 

the higher penetration of VERs, operators need to adjust their practices and rely on more flexible resources to 

ensure voltage and frequency support are maintained within acceptable margins while maintaining frequency.

Non-Hydro Cases Model Results: NERC evaluated the reliability impacts of the increased renewable generation 

resulting from the implementation of the proposed CPP carbon emission reduction goals as follows:

Non-Hydro Capacity Impact: Using the AURORAxmp model, approximately 35 GW of non-hydro 

renewable capacity additions are reflected in the CPP State, Regional, and Low-Gas Cases. These are 

added to maintain NERC’s reserve margin reliability levels. The CPP State, Regional and Low-Gas Cases 
Chapter 3 – Resource Adequacy Assessment

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24

very closely mirror the Reference (no CPP) Case, which demonstrates limited non-hydro energy growth 

levels. This is due to the lower cost of natural gas generation combined with the expired PTC and the 

reduced ITC for renewable energy resources. The additional renewable energy could strain ERSs and

create additional planning and operational challenges. Chapter 4 on transmission adequacy providesmore 

details on transmission reinforcement necessary to meet the EPA emission reduction targets as a result 

of increased wind and solar penetration levels.

Table 4 shows the IPM reference, CPP state, and CPP regional non-hydro renewable gigawatt capacity. Both 

models show slight renewable additions for the CPP cases due to no PTC and the assumptions of a 30 percent ITC 

for 2016 and a 10 percent ITC for 2017 and beyond. Renewable additions could increase accordingly if states set 

increased renewable targets or if other economic incentives are implemented. Additionally, if PTC and ITC are 

extended or increased, renewable additions could increase. NERC cannot count on such extensions. 

Table 4: Non-Hydro Renewable GW Capacity – IPM Model

Modeled Cases 2016 2018 2020 2025 2030

Reference (No CPP) 96 103 116 126 135

CPP State 91 103 124 135 144

CPP Region 91 102 121 132 141

Resource Adequacy Scenario

An important element of this analysis is that reserve margin targets were maintained in order to serve as a 

reliability signal that more capacity is needed. Current approximate reserve margin targets of up to 20 percent

were applied for each area and assumed to remain constant for the entire period assessed. However, given the 

changes to the generation mix, resource availability is likely to be negatively impacted. Uncertainty and variability 

of renewable resources (such as wind and solar) will need to be accounted for in establishing new target reserve 

margins. Higher forced-outage rates would also result in higher reserve margin targets, as each area would need 

to carry more reserve capacity to balance the uncertainty. 

An important assumption of this analysis is that the reference margin levels, as reported for year 1 in the 2014 

LTRA, are applied for each Assessment Area. Accordingly, reserve margin projections would trigger the 

AURORAxmp model to add capacity as needed to maintain resource adequacy. However, the likelihood of lower

capacity factors resulting from the redispatching of resources could lead to higher forced-outage rates, which 

could ultimately result in higher reference margin levels to account for additional reserve capacity needed.

NERC ran a scenario to compare the 2014 LTRA Reference Case with the AURORAxmp results. Peak demand and 

resource projections (existing and Tier 1 capacity additions20) from the Reference Case were reduced by the 

retirements projected by the AURORAxmp (applying both state and regional implementation). The results 

indicated that certain Assessment Areas—particularly NPCC-US, TRE-ERCOT, and MISO—will face the most 

significant resource adequacy concerns in 2020, as shown in Figure 15. 

 

20 Tier 1 capacity additions: includes capacity that is either under construction or has received approved planning requirements.
Chapter 3 – Resource Adequacy Assessment

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Figure 15: Impacts of CPP Cases on Regional Reserve Margins – 2020 Scenario

The capacity additions needed in these areas to maintain the current reference reserve margin levels align with 

these results. In ERCOT and NPCC-US, the AURORAxmp model indicates that over 11 GW and 7 GW, respectively, 

of capacity additions will be needed by 2020.

Power Transfer Changes across Major Power Market Areas

Based on NERC’s modeling, the CPP will likely change the power flows in many major power areas. Since importing 

power is one option that can displace regional CO2 emissions, similar to a transmission component of the building 

blocks, it will likely increase in many areas with high-reduction targets. In regional trading cases, areas with lower 

incremental CO2 reduction options can displace higher-cost options in adjoining states or power pools. Overall, 

net transmission flow activity between regions is expected to increase by 19,230 MW under the state compliance 

plan (versus no CPP). Based on NERC’s modeling, net transmission interchange flows were higher under a regional 

trading case, reaching 26,150 MW higher than the Reference Case. Table 5 and Figure 16 show the annual average 

transmission flows in megawatts for 20 major regions in the United States and Canada—average net MW imports 

(+) and net MW exports (-) from 2020 through 2030.
Chapter 3 – Resource Adequacy Assessment

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Table 5: Transmission Interchanges between 2020 and 2030—Average MW Imports 

(Positive) and Exports (Negative)

Area

MW 

Interchanges

No CPP

MW 

Interchanges

CPP State

MW 

Interchanges

CPP Regional

Percent Flow Changes of 

the CPP State Case from a 

Reference (No CPP) Case

Percent Flow Changes of the 

CPP Regional Case from a 

Reference (No CPP) Case

CAN -5,461 -13,699 -14,828 150.3 171.5

ISONE 2,595 2,935 2,949 13.1 13.6

NYISO 2,805 3,156 2,737 12.5 -2.4

PJM East 1,561 -5,167 -3,021 -430.9 -293.5

PJM West -6,001 -2,125 -750 -64.6 -87.5

SERC North 1,524 -266 1,177 -117.5 -22.8

SERC East 1,745 3,742 2,394 114.5 37.2

SERC SE -153 -390 -804 154.3 424.8

FRCC 2,726 3,238 2,489 18.8 -8.7

MISO North -767 3,126 898 -507.4 -217.1

MISO Central -8,159 -325 933 -96.0 -111.4

MISO South 6,472 3,424 4,301 -47.1 -33.5

MRO MAPP -2,488 -1,675 -2,139 -32.6 -14.0

SPP 4,000 4,505 4,061 12.6 1.5

ERCOT 170 372 105 119.1 -37.8

WECC NW -4,445 -5,220 -5,660 17.5 27.3

WECC CAL 8,185 7,005 10,809 -14.4 32.1

WECC SW -2,571 -2,262 -3,538 -12.0 37.6

WECC RMPA -1,379 72 -1,575 -105.2 14.2

MX -360 -475 -540 31.8 49.7
Chapter 3 – Resource Adequacy Assessment

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Figure 16: Change in Regional Power Transfers Comparing Reference Case to CPP State Case

Observations

Based on NERC’s modeling, a significant adjustment of expected transmission flow occurs. Transmission flows that 

change in direction and magnitude as a result of a new generation dispatch require significant coordination and 

reliability analysis, particularly across transmission seams. As a result of CPP implementation in NERC’s State and 

Regional Cases, NERC observed the following:

 Canada exports three times more power to the United States, mainly NPCC and MISO North. 

 PJM-East shifts from being a net importer of power to a net exporter of power (mainly into PJM-West and 

NPCC) due to renewed competitiveness of generating units in RGGI states that were previously 

handicapped by RGGI CO2 allowance prices (with carbon penalties in place in non-RGGI states as well).

 MISO-Central reduces power exports significantly due to cheaper generation imports from Canada into 

MISO-North.

 Power transfers increased into MISO South from MISO Central and SERC North.

 Major power flow changes unique to the CPP state scenario were also observed:

 SERC North reduces imports and becomes a net exporter of power, mainly into SERC East.

 WECC RMPA (CO and WY) reduces power exports from Colorado due to higher carbon penalties than 

in surrounding states.
Chapter 3 – Resource Adequacy Assessment

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Reliability Considerations

The change in the power flow, both in direction and magnitude, could present challenges in planning and 

operation of the BPS. In addition, timing implications could possibly impact reliability due to inadequate resources 

in certain areas. These changes in power transfers between areas require extensive power system studies and 

planning to ensure existing transmission lines are capable of such transfers. In addition, dynamic reactive power 

resources may be needed to maintain voltage stability to support normal operation of the system as well as to 

ensure the system’s resiliency against contingencies. Dynamic stability also needs to be taken into consideration 

with the addition of new resources and requisite transmission lines, especially in cases where generation is farther 

away from demand centers than they are currently. The location of new resources could be impacted based on 

the proximity of the resources to natural gas pipelines as well as their proximity to wind and solar-rich areas. 

Although all of the additions and retirements will not happen simultaneously, protection systems should be 

studied, tested, and coordinated to ensure reliable operation of the BPS. As mentioned in NERC’s 2014LTRA, 

necessary maintenance and upgrades as a result of aging electric infrastructure can also introduce additional 

challenges as the resource mix change accelerates due to the CPP.

The power flow changes represented in NERC’s analysis demonstrate the continued evolution of resource 

deployment and use of renewable and natural gas generation. Over the next several years, these resource changes 

will require more transmission to integrate the new resources, meet increasing electricity demand, and enable 

exports and imports. Consistent with NERC’s conclusion on its overall assessments, power flow changes represent 

a significant planning and operational challenge. Sufficient time and coordination is needed to determine regionspecific solutions.

Conclusions

 The AURORAxmp and IPM models show similar trends between 2020 and 2030 for coal unit retirements 

and natural gas unit additions. Although the timing of retirements and additions differs between models, 

the overall level of natural gas additions and coal capacity retirements is roughly equal between 2016 and 

2030.

 The AURORAxmp model determines that some coal units will remain operational but at much lower load 

factors. These units (14–22 GW) are considered “at risk” and may retire based on resource planning 

outside of the model results.

 State and Regional Cases produce similar results in terms of the amount of capacity that was added and 

retired. This is partly due to the fact that the models assumed trading of carbon emissions would occur in 

regional groupings across typical RTO/ISO and contiguous regions. More optimization among noncontiguous regions could potentially produce different regional results not contemplated in NERC 

modeling inputs (which assume trading based on physical power flows). Additionally, thermal 

transmission line capabilities in both models limit the transfer of power between regions at the same level 

in both State and Regional Cases. Additional transmission would be necessary to optimize trading 

capabilities among regions. Whereas carbon shadow prices among states indicate differing economic 

values, NERC’s model assumes trading would occur using physical power flows. A final rule by the EPA 

could contemplate different trading mechanisms to capture the value of carbon trading across regions.

 The shift in resources from both a capacity standpoint and resource utilization (energy dispatch) 

standpoint indicate a need for transmission and gas infrastructure additions to maintain BPS reliability. 

Chapter 5 discusses infrastructure needs and lead times in more detail. 
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Chapter 4 – Steady-State Power System Analysis

The proposed CPP introduces resource adequacy concerns as identified in Chapter 3, but it also presents the

potential new challenge of industry needing to ensure that transmission facilities are in place to integrate new 

resources—in addition to adjustments—necessary to address new interchanges. Accommodating necessary 

transmission line additions and upgrades may represent significant reliability challenges due to extensive planning 

and construction requirements. The proposed time period for CPP compliance adds additional challenges from a 

reliability perspective. New dispatch patterns will require comprehensive assessments to identify reliability 

impacts resulting from the changes to power flows. With additional variable resources projected, along with the 

retirements of baseload capacity, maintaining ERSs will become a priority. The characteristics that comprise ERSs

must be considered in resource planning, specifically load and resource balancing, ramping capability, voltage 

support, and frequency support.

This chapter assesses the North American BPS’s ability to accommodate the accelerated change in generation mix, 

transmission facility requirements, and reactive power support needs resulting from the implementation of the 

proposed CPP. The lead times necessary for planning, permitting, and construction of generation and transmission 

facilities are also discussed and are examined further in Chapter 5.

Power Flow Cases and Evaluation Approach

The power flow case in this assessment examines summer loading conditions for 2020 to align with the initial 

implementation of the proposed CPP. The Eastern and Western Interconnection planning base cases for this study 

were prepared by the Eastern Interconnection Reliability Assessment Group’s (ERAG) Multiregional Modeling 

Working Group (MMWG) 21 and WECC’s Modeling Working Group (MWG)22 and were used for the Reference 

Case.23 State and regional results from the AURORAxmp model, as described in Chapter 3, were used as input for 

this evaluation to identify generation retirements and additions for both the Eastern and Western 

Interconnections (CPP State Case and CPP Regional Case).

24 The projected resource availability, load, and losses

in the Eastern and Western Interconnections are provided in Figure 17. ERCOT performed a separate study25 that 

examines the ERCOT Interconnection on the implications of the CPP along with other environmental regulations, 

which is summarized in Chapter 6.

Figure 17: Generation Capacity, Load, and Losses in Eastern and Western Interconnections

 

21 Eastern Interconnection Modeling Working Group.

22 WECC Modeling Working Group.

23 Transmission and generation additions and retirements planned by 2020 are reflected in these cases. Both models incorporate impacts 

of existing regulations.

24 NERC conducted power flow analyses for both the CPP State Case and the CPP Regional Case. However, from a capacity perspective, the 

results of the dispatch model (AURORAxmp) were very close. Therefore, the figures and maps included in this chapter are based on the 

CPP State Case from the AURORAxmp model output. 

25 Impacts of Environmental Regulations in the ERCOT Region.
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This model was created using the following input to identify areas of potential generation and transmission 

constraints as a result of capacity retirements and additions:

 Type of generation 

 Location of capacity retirements

 Location of gas-fired capacity additions (proximity to existing sites (brownfields), existing transmission 

facilities, and existing gas pipelines)

 Location of new wind and solar resources (proximity to areas with abundant wind and sunlight)

 Location of existing reactive power resources to support voltage requirements

Transmission facilities were added to the model to tie in greenfield unit locations to transfer the new generation 

to the point of interconnection. 

Generation Retirements 

Generation retirements shown in Figure 18 include announced generation retirements due to other regulations 

and end of life of the units, in addition to the projected retirements due to the proposed CPP. Texas, California, 

New York, and Massachusetts are projected to have the largest natural gas resources retirements, while Kentucky, 

Alabama, Georgia, and Indiana are projected to retire the largest amounts of coal-fired generation among the 

lower 48 states.

Figure 18: Generation Retirements by Fuel Type and Size26

 

26 Maps created using Velocity Suite, ABB Enterprise Software.
Chapter 4 – Steady-State Power System Analysis

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Generation Additions 

In order to compensate for the retirement of generating units, additional generation resources will be required to 

serve load in the Eastern and Western Interconnections. With the changes in the resource mix—mostly the shift 

from coal to natural gas and increased penetration of renewable resources—some assumptions were required to 

approximate the location of these additions. The location of new generation was selected based on a computer 

model algorithm that used the following attributes to determine logical power plant sites:

 Proximity to the site of the retired unit (brownfield)

 Proximity to available resources (natural gas units located close to gas pipelines, wind resources close to 

wind-rich areas, etc.)

 Proximity to existing high-voltage transmission substations and other transmission facilities

From the total capacity additions in the Eastern and Western Interconnections, 23 percent of the total generation 

capacity additions were positioned on the brownfield sites, and the remaining 77 percent require new sites. The 

greenfield sites were selected to maximize the use of existing transmission facilities. 

Generation additions shown in Figure 19 include announced generation additions in addition to the generating 

resources required to serve load while maintaining planning reserve margins. The majority of generating unit 

additions, analogous to the retirement of coal-fired resources, are natural gas and renewable. Pennsylvania,

Texas, Florida, and California are projected to add the largest amounts of gas-fired generation among the 48 

contiguous states.

Figure 19: Generation Additions by Fuel Type and Size27

 

27 TRE’s natural gas and renewable addition locations are based on estimates only. 
Chapter 4 – Steady-State Power System Analysis

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Transmission Addition Requirements

Following the determination of locations for the new generating units, the most appropriate transmission voltage 

levels (230 kV, 345 kV, or 500 kV) were selected in order to accommodate the amount of added generation while 

minimizing the amount of power transfer losses. The selection criteria of new transmission facilities included

economic factors such as a higher cost of increased voltage facilities. 

To address system contingencies, additional transmission lines and facilities—as well as upgrades to existing lines 

and facilities—may be required. This would be necessary to ensure stability following a system event on the BPS.

28

Figure 20 shows transmission addition requirements as a result of NERC analysis. Appendix B provides more 

information on methods and requirements for system stability and security used in this study.

Figure 20: Transmission Line Additions in Eastern and Western Interconnections by Voltage Class and Length

 

28 NERC did not conduct a contingency analysis for its transmission adequacy analysis. However, contingency planning is required, and 

additional transmission facilities (beyond what is identified in NERC’s analysis) may be needed to satisfy reliability requirements. 

Therefore, NERC considers its results to be on the “low end” of transmission needs compared to what would be needed to satisfy 

reliability and contingency analysis requirements.
Chapter 4 – Steady-State Power System Analysis

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Reactive Power 

Where power is transferred over longer distances to the point of interconnection, higher amounts of reactive 

resources are required to maintain voltage stability and voltage support from generators, especially renewable 

resources (see Figure 21). With the accelerated change in the resource mix, additional transmission resources 

(such as shunt capacitors, synchronous condensers, SVCs, STATCOMs, etc.) will be needed to maintain adequate 

voltage levels.

29

Figure 21: Reactive Power Support Needed in Eastern and Western Interconnections

 

29 Reactive power losses of generator step-up transformers (GSUs) were modeled by reducing generating unit reactive power output.
Chapter 4 – Steady-State Power System Analysis

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Lead Time and Timing Implications 

Generating unit additions and the accelerated change in resource mix will require permitting, planning, and 

construction of other facilities to support the voltage profile as well as transmission of power to the point of 

interconnection. Lead time for the delivery of each facility (generating plant, tie-in substation, and transmission) 

depends on many factors that should be individually evaluated for each type of addition, such as:

 Permitting process and the project’s social acceptance

 Typical facility capacity, location, and interconnection voltage level

 Manufacturing capability and delivery lead time

 Construction capability and duration

The average lead time per facility type (Chapter 5 discusses these lead times in more detail) is used to estimate 

the required power timeline needed to support the load in the Eastern and Western Interconnections. For added 

generation capacity, only approximately 20 percent of the capacity required will be available by 2020. The 

generation and transmission additions and upgrades necessary to fulfill the capacity requirements, as indicated in 

the AURORAxmp results, would not be completed until 2031 (Figure 22). The timeline may vary with consideration 

of the following assumptions and factors:

 The model assumes that planning and permitting for new facilities will begin in 2015.

 A greater number of transmission facilities would be required if contingency analysis were considered.

Conclusions

NERC’s modeling of the CPP yielded approximately 43 GW of additional retirements by 2020 (based on NERC’s 

CPP State Case). As a result of these retirements, generation capacity replacement is required to serve existing 

and forecast load. The accelerated change in generation mix by fuel type and location would introduce challenges

associated with constructing transmission facilities needed in order to transfer power to a point of 

interconnection. The transmission projects are comprised of engineering, siting, permitting, and constructing,

which are highly dependent on geography and right-of-way. The change in the flow of power and area transfer 

interchanges should be extensively studied, and the need for transmission facility additions or upgrades should 

be identified. These efforts will all require more in-depth and system-specific analysis, which includes evaluating 

Figure 22: Total Power Available With Projected Facilities Required
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NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan – Phase I | April 2015

35

transmission adequacy under various contingency scenarios, examining voltage and transient stability caused by 

system disturbances, and determining interchange power transfer capabilities between systems.

The identified transmission needs are representative of a solution set that corresponds to NERC’s resource 

adequacy analysis in Chapter 3 (therefore, the same assumptions apply for this analysis). In terms of timing, 

NERC’s analysis identified transmission needs that would require approximately 16 years to complete. However, 

to be clear, NERC is not advocating that the CPP be delayed 16 years. While NERC recognizes that this specific 

implementation may not materialize, it is clear from the analysis that additional transmission will be needed to 

support the new generation mix. Because of the uncertainties associated with the proposed CPP rule, NERC cannot 

make a specific determination of timing; however, meeting a 2020 interim target date that requires transmission 

as part of the solution may not be feasible. 

Additional analysis in the following chapter provides details on infrastructure lead times.
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Chapter 5 – Timing Implications

Electric Infrastructure Upgrade Timing Implications

Electric transmission and resource adequacy planning is a lengthy and rigorous process, mainly due to the 

implication of the investments and need to carefully coordinate system improvements throughout an area. In 

anticipation of long lead times for developing new transmission, transmission planners and resource planners plan 

the system over a 10-to-15-year time horizon to identify transmission constraints, resource constraints, and other 

reliability concerns to ensure the system is compliant with all applicable NERC Reliability Standards and resilient 

enough to maintain reliability.

As part of NERC’s CPP Phase I study, NERC requested information from industry on new generation and 

transmission facility construction lead times. The results represent the perspectives from 110 different 

transmission and generation companies on timing requirements (in months) for additional new transmission and 

generation capacity. Naturally, the timing needs are highly dependent on the scope of a project, length of 

transmission, and geography. Entities in different regions of the country face different challenges in building new 

transmission and generating facilities. The results report the average time in months necessary to complete each 

phase. Results are based on recent historical performance (i.e., projects in service within the last two to three

years) and any future projects with known schedules. 

Lead Times for Generation Construction 

NERC requested information on combined-cycle gas turbines (CCGTs), which consist of combustion turbines (CTs)

and steam turbines (STs) of three different sizes; wind turbines based on a typical plant size; and utility-scale solar 

projects. The information NERC received from industry was based on commercially available generators by fuel 

type and capacity class.

The information request only took into consideration lead time associated with constructing a new generator. 

NERC considered every phase it takes to build a power plant from conception to inception. While the amount of 

time to construct any given project is unique and any number of local, regional, or federal factors could influence 

the project timeline, these lead times provide a relative indication for policy makers to better understand lead 

times associated with specific solution sets. Table 6 shows the commensurate timelines for potential capacity 

additions. 
Chapter 5 – Timing Implications

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Table 6: Combined-Cycle Generation Construction Timeline in Months

Turbine Type 

2 Combustion 

Turbines and 1 

Steam Turbine 

3 Combustion 

Turbines and 1 

Steam Turbine

4 Combustion 

Turbines and 1 

Steam Turbine

Approval in Planning 

Stage/Interconnection Agreement 17 18 16

Permitting 17 17 16

Construction 30 30 32

Total 64 64 64

Gas-Fired Generation Construction Timeline In Months (Plant Size GT)

Size (MW) 200–500 501–700 701–800

Approval in Planning 

Stage/Interconnection Agreement 15 15 16

Permitting 16 15 16

Construction 23 25 26

Total 53 55 58

Coal Generator (Plant Size) Timeline in Months

Generator (MW) 200–500 501–700 701–800

Extended outages for unit retrofit to 

improve heat rate 8 8 7

Wind Generation (Plant Size) Timeline in Months

Generator (MW) 0–50 51–100 101–150

Approval in Planning 

Stage/Interconnection Agreement 16 16 16

Permitting 13 12 12

Construction 9 12 12

Total 37 40 40

Utility-Scale Solar Generation (Plant Size) Timeline in Months

Generator (MW) 0–50 51–100 101–150

Approval in Planning 

Stage/Interconnection Agreement 13 14 15

Permitting 9 10 11

Construction 9 13 17

Total 31 37 42
Chapter 5 – Timing Implications

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Based on the responses, it historically takes an average of 64 months, or just over five years, to complete all 

necessary planning, permitting, and construction for a new CCGT facility. Size of the generation units does not 

appear to be a major factor. The average for a utility-scale solar generation project is 36 months. The average for 

wind is 39 months. The proposed CPP target implementation dates raise concerns when compared to generation 

facility construction—particularly CCGT—and lead times needed to replace retiring units and respond to 

increasing electricity demand. 

Lead Times for Electric Transmission Projects

Transmission companies must plan upgrades to transmission facilities on the BPS several years in advance to 

accommodate necessary lead times. In the transmission expansion planning process, transmission planners 

conduct ongoing power flow analyses to identify thermal constraints on the BPS and develop solutions. Any 

changes in load or generation in a given area may result in changes to the power flow on those respective 

transmission lines—particularly retirement and addition of new generation. Any transmission lines exceeding their 

conductor ratings are further analyzed to ascertain possible solutions, which could include reconductoring or 

building new transmission facilities. Depending on the complexity, severity, and urgency of the transmission issue, 

this process could take several years to complete. The request for electric transmission projects was delineated 

for transmission lines less than 100 miles and transmission lines greater than 100 miles. NERC also sought

information on line construction and substation construction considerations, whether the line is in an urban 

setting, and if the line crosses interstate lines—all of which could increase the amount of time it takes to complete

the project.
Chapter 5 – Timing Implications

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The results NERC received are from Transmission Owners who had transmission projects that went into service 

within the last two to three years or who have plans to build new facilities in their long-term study plans. The 

results are shown in Table 7.

Table 7: Electric Transmission Facility Construction Timeline in Months

Line 

Length

100 kV–

199 kV

200 kV–

299 kV

300 kV–

399 kV

400 kV

DC

500 kV–

599 kV

1–100 

miles

Surveying 8 9 10 9 19

Land & Right-of-Way 

Acquisition 15 15 17 14 17

Permitting 13 13 15 7 20

Construction Line (New) 19 21 22 24 41

Construction Line 

(Reconductoring)

15 23 20 26 34

Construction Substation 

(New) 18 26 19 24 32

Construction Substation 

(Upgrade) 12 16 16 23 24

Additional months needed 

for urban setting 9 8 13 14 9

Additional months needed 

for interstate versus 

intrastate

6 10 11 6 14

>100 

miles

Surveying 10 11 12 10 12

Land & Right of Way 

Acquisition 26 21 24 20 31

Permitting 20 21 26 18 32

Construction Line (New) 38 34 39 44 79

Construction Line 

(Reconductoring)

24 28 36 49 65

Construction Substation 

(New) 17 20 20 24 32

Construction Substation 

(Upgrade) 12 15 16 23 24

Additional months needed 

for urban setting 9 10 19 27 18

Additional months needed 

for interstate versus 

intrastate

6 9 12 6 14
Chapter 5 – Timing Implications

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The results indicate that it takes several years to complete most projects. Although there is some overlap between 

right-of-way acquisition and permitting, the majority of each project’s timeline is taken up during the construction

phase. An example would be a reconductoring of a rural 100 mile, 230 kV transmission line averaging 81 months,

or just under seven years. It can take up to 15 years to build a new 500 kV line from planning to energization. The 

15-year timeline to build a 500 kV line assumes some work can be accomplished in parallel, such as constructing 

a substation when constructing a new line.

Lead Times for Natural Gas Pipeline Projects

The process of siting, constructing, and installing additional pipeline capacity is complex and requires sufficient 

lead time in order for necessary studies, approvals, and construction to take place. Though the complications can 

be considerable for each pipeline project, their approval process is very much the same for enhancements that 

occur on the system--whether the project is a new pipeline, converting an oil pipeline to a natural gas pipeline,

looping a parallel pipeline, or upgrading facilities along an existing route.

30 Each project can be segmented into 

the stages shown in Figure 23. 

Figure 23: Timeline for Natural Gas Pipeline Projects

A natural gas pipeline project requires approximately three years from conception to a finished product that has 

been placed into service. The lead times shown above represent a 20-mile project that crosses state boundaries, 

does not include resubmittals, requires the average time to obtain all necessary permitting and clearance, and 

does not accrue major construction delays. Additional time will be required if the project is larger and 

complications arise during construction. 

 

30 Process and Timeline for Development of Additional Natural Gas Pipeline Infrastructure.
Chapter 5 – Timing Implications

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Constructing new natural gas pipeline can also create operational challenges. As capacity needs for gas pipelines 

increase, enhancements to the pipeline system are likely to occur in the form of increasing pipeline sizes or 

diameters. Therefore, as pipelines are constructed, existing pipelines may need to come out of service to 

accommodate the upgrade. Because these outages will likely occur in the shoulder and summer seasons when 

use of gas-fired generation is expected to increase, this can create some short-term issues and require tight 

coordination between the gas and electric industries. 

Conclusions

It is evident, based on the feedback from NERC’s information request, that reinforcing the system to comply with 

the CPP would present challenges. Based on the 6-to-15-year projected construction timeline to build various 

transmission facilities, as well as approximately five years on average to build a new NGCC, timing issues pose 

challenges to meeting the proposed CPP targets. 

To support the significant amount of new gas-fired generation expected over the next several years, new pipeline 

capacity will be needed. Based on NERC’s analysis, construction of even small interstate pipeline projects can

require three years to complete.
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Chapter 6 – NERC’s Assessment on Analysis Conducted by 

Selected NERC Regions and ISO/RTOs

As part of its Phase I study, NERC has reviewed publicly available industry analysis directly related to CPP 

compliance. The studies NERC reviewed are not all-inclusive; they represent a cross section of Regional Entities 

and ISO/RTOs that face unique dispositions and challenges with existing system infrastructure. ERCOT, MISO, PJM, 

SPP, and WECC conducted and reviewed the studies; each study examined the impacts from the proposed CPP. 

These studies were conducted by industry stakeholders, and the information they contain is not the result of a 

NERC analysis. The studies are linked in Table 8 and summarized below.

Table 8: CPP-Related Studies

Reliability 

Authority Reliability Role (Major) Link to Study

ERCOT Transmission Planner and 

Operator, Planning and 

Reliability Coordinator

Impacts of Environmental Regulations in the ERCOT Region: 

http://www.ercot.com/content/news/presentations/2014/I

mpacts%20of%20Environmental%20Regulations%20in%20t

he%20ERCOT%20Region.pdf

MISO Transmission Planner and 

Operator, Planning and 

Reliability Coordinator

Analysis of EPA’s Proposal to Reduce CO2 Emissions from 

Existing Electric Generating Units: 

https://www.misoenergy.org/Library/Repository/Communic

ation%20Material/EPA%20Regulations/AnalysisofEPAsPropo

saltoReduceCO2EmissionsfromExistingElectricGeneratingUni

ts.pdf

PJM Transmission Planner and 

Operator, Planning and 

Reliability Coordinator

PJM Interconnection Economic Analysis of the EPA Clean 

Power Plan Proposal: 

http://www.pjm.com/~/media/4CDA71CBEC864593BC11E7

F81241E019.ashx

SPP Transmission Planner and 

Operator, Planning and 

Reliability Coordinator

SPP’s Reliability Impact Assessment of the EPA’s Proposed 

Clean Power Plan:

http://www.spp.org/publications/CPP%20Reliability%20An

alysis%20Results%20Final%20Version.pdf

WECC Regional Reliability 

Organization (Regional 

Entity Responsible for 

Enforcing NERC 

Standards)

EPA Clan Power Plan: Phase I – Preliminary Technical Report

by WECC Staff: 

https://www.wecc.biz/Reliability/140912_EPA111%28d%29_PhaseI_Tech-Final.pdf
Chapter 6 – NERC’s Assessment on Analysis Conducted by Selected NERC Regions and ISO/RTOs

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Observations 

In its assessment of the individual analyses performed by five NERC Regional Entities and RTO/ISOs, NERC 

observed the following:

 The studies reflect shifts from coal-fired generating units to natural-gas-fired generating units and 

renewable resources in concurrence with the results from the AURORAxmp and IPM models.

 Findings generally differ among areas as well as within zones of those areas. This is largely spurred by a 

resource mix that is widely different across the country and different motivations from a policy and state 

perspective.

 These analyses did not assume changes in their neighboring systems due to the significant complexity 

associated with the flexibility within the proposed CPP. 

 The studies are inconclusive, given that a final rule has not yet been issued and there are significant 

unknowns.

 The studies indicate generally higher electricity production costs, which drives the significant resource mix 

changes from both a capacity and energy perspective, consistent with NERC’s analysis. 

 The timing of the CPP implementation is addressed in all the studies, but in varying degrees. Some of the 

studies raised concerns, but others implied that compliance will not be difficult to achieve. 

 The majority of studies addressed the timing of retirement announcements. This could create 

compounded issues if significant retirements occur simultaneously. This is a major challenge, particularly 

in market areas where established long-term planning horizons conflict with the plans that will be

developed by states.

NERC Conclusions

As plans are being developed, it is important that reliability authorities continue to conduct the reliability analysis 

needed to plan and operate the BPS as required by NERC Reliability Standards. 

Given the focus on state and regional variability, concerns with timing of retirement announcements, and resource 

shifts, a reliability assurance mechanism could further assist in addressing issues, including those that might arise 

across operating boundaries.
Chapter 6 – NERC’s Assessment on Analysis Conducted by Selected NERC Regions and ISO/RTOs

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ERCOT

Overview

ERCOT is the independent organization established by the Texas Legislature to be responsible for the reliable 

operations and planning of the electric grid for the ERCOT Interconnection. Several proposed or recently finalized 

U.S. EPA regulations could have an impact on grid reliability in ERCOT. These rules include the MATS, the CrossState Air Pollution Rule (CSAPR), the Regional Haze program, the Cooling Water Intake Structures rule, the Steam 

Electric Effluent Limitation Guidelines (ELG) rule, the Coal Combustion Residuals (CCR) Disposal rule, and the Clean 

Power Plan. ERCOT conducted studies to assess the individual and cumulative impact of these regulations on the 

ERCOT Interconnection.

Modeling and Input Assumptions

ERCOT undertook two study efforts. First, a survey was distributed to fossil-fuel-fired generators on the impacts 

of relevant environmental regulations. The survey asked questions about plans for unit retirements, suspended 

operations, and planned modifications to comply with environmental regulations. No resource owners responded 

with plans for retirements or suspended operations except for any previously announced plan to mothball. 

Second, ERCOT conducted a modeling analysis of the impacts of CSAPR, the Regional Haze program, and the CPP 

on generation resources and energy costs in ERCOT. The study uses Energy Examplar PLEXOS Integrated Energy 

Model mixed integer programming to model the power sector. In this study, ERCOT used the long-term modeling 

capability in PLEXOS to estimate unit retirements and capacity additions over the 2015 to 2029 time frame.

ERCOT conducted six scenarios that included a base case and five scenarios that reflected impacts considering 

CSAPR, Regional Haze, and CPP. The scenario analysis conducted by ERCOT was not meant to be a comprehensive 

study of all regulatory impacts and potential compliance pathways.

Resource Adequacy Findings

The implementation of the proposed CPP will cause a shift in the resource mix due to the retirement of higheremitting CO2 units being displaced by lower-emitting CO2units. The higher-emitting units are predominantly coalfired generation, which is being replaced by natural gas and renewable generation. Coal units are the most 

affected by environmental regulations. These results indicate that not taking into account the CPP, 3,000 to 8,500 

MW of coal-fired capacity in ERCOT can be considered to have a moderate to high risk of retirement—due 

primarily to the costs of the EPA’s proposed requirements for the Regional Haze program. The implementation 

and regulatory timeline of the CPP will impact decisions that resource owners make about whether to retrofit or 

retire impacted units. Additionally, the CPP itself may cause unit retirements, due to the need to meet stringent 

CO2 emission limits on a state-wide basis. ERCOT’s modeling analysis suggests that the CPP, in combination with 

the other regulations, will result in the retirement of up to 8,700 MW of coal-fired capacity.

The CPP will also result in increased wholesale and consumer energy costs in ERCOT. Based on ERCOT’s analysis, 

energy costs for consumers may increase by up to 20 percent in 2020, without accounting for the associated costs 

of transmission upgrades, higher natural gas prices caused by increased gas demand, procurement of additional 

ancillary services, energy efficiency investments, capital costs of new capacity, and other costs associated with 

the retirement or decreased operation of coal-fired capacity in ERCOT. 

Transmission Adequacy Findings

It takes at least five years for a new major transmission project to be planned, routed, approved, and constructed 

in ERCOT. As such, in order for major transmission constraints to be addressed in a timely fashion, planning must 

occur at least five years in advance. The load growth in the ERCOT urban centers like Houston, Austin, and Dallas 

results in the need for new transmission infrastructure. As the units that are at risk of retirement from the 

proposed rule are located near these load centers, future transmission needs would be increased or accelerated 

by the likely retirements. For example, a new 345 kV transmission line is currently planned to be in place by 2018 
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to serve customers in the Houston area. Long-term studies indicate a potential need for further upgrades in the 

mid-2020s. The retirement of generation resources within the Houston area prior to 2018 would likely result in 

grid reliability issues prior to completion of the proposed reinforcement project. Therefore, the need for this new 

transmission project would be accelerated to the near-term horizon (one to six years) from the long-term horizon 

(six to 15 years).

Conclusions and Key Findings 

 Based on the study results, the Regional Haze requirements and the CPP will have significant impacts on 

the planning and operation of the ERCOT grid. Both are likely to result in the retirement of coal-fired 

capacity in ERCOT. 

 Currently, resource owners are required to notify ERCOT no less than 90 days prior to the date that the 

unit is retired or mothballed. Given the competitiveness of the ERCOT market and the current uncertainty 

surrounding environmental regulations, it is unlikely that generators would notify ERCOT of potential 

retirements or unit suspensions before the minimum notification deadline. If ERCOT does not receive 

early notification of these retirements, and if multiple unit retirements occur within a short time frame, 

there could be periods of reduced system-wide resource adequacy and localized transmission reliability 

issues due to the loss of generation resources in and around major urban centers. 

 The loss of reliability services (i.e., ERSs) previously provided by units that are now retiring will strain 

ERCOT’s ability to integrate new intermittent renewable generation resources. The need to maintain 

operational reliability (i.e., sufficient ramping capability) could require the curtailment of renewable 

generation resources. This would limit or delay the integration of renewable resources, leading to a delay 

in achieving compliance with the proposed CPP limits. 

 Complying with these regulations in the near term could lead to concurrent unit outages and increased 

seasonal mothballing of capacity. If these changes result in impacts to grid reliability and transmission 

constraints, and there is not sufficient time to mitigate these issues, there could be challenges to ERCOT’s 

management of the grid.
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MISO

Overview

MISO undertook a study to help stakeholders understand the impact of the EPA proposal to reduce CO2 emissions 

from existing fossil-fired generation. MISO’s analysis is not exhaustive in its assessment of the impact of the rule 

across MISO’s footprint, but is an initial look at the potential impacts to help stakeholders prepare comments to 

the EPA. MISO’s analysis is independent; MISO does not make recommendations on what compliance solutions 

are best: those decisions will need to be made by regulating entities and state officials once a final rule is in effect.

Modeling and Input Assumptions

MISO modeled the compliance costs of CO2 emission reductions achieved through the application of the building

blocks as outlined in the EPA proposal. The building blocks include making efficiency upgrades at coal units and 

increasing the use of combined-cycle gas units, among other things. MISO also evaluated alternative compliance 

options to those outlined in the building blocks. MISO modeled nearly 1,300 different combinations of a range of 

policy and economic conditions to calculate compliance costs and also modeled actions beyond the scope of the

EPA’s building blocks. Modeled sensitivities included: a range of coal unit retirements, renewable portfolio 

standards, energy efficiency levels, nuclear unit retirements, carbon costs, gas prices, and demand and energy 

growth rates. 

Resource Adequacy Findings

According to MISO’s analysis, the most cost-effective means of complying with EPA’s rule may be to retire more 

coal generation than what is already projected to retire due to the EPA’s MATS regulation. Specifically, MISO found 

that the EPA’s proposal could put up to an additional 14 GW of coal capacity at risk of retirement (in addition to 

the 12.6 GW of capacity already projected to retire).

Conclusions and Key Findings 

 MISO’s review indicates that the rule’s “interim performance period” will require significant CO2 cuts to 

be made in the 2020 time frame. This is based on the need for immediate action to meet the 10-year 

average identified in the proposed rule. 

 It is possible that state plans will not be finalized until the 2018–19 time frame, leaving little time for 

decisions on infrastructure changes before 2020. MISO is concerned that this short timeline will not allow 

for cost-effective, long-term planning to occur.

 If coal plant retirements are part of the compliance strategy for 2020, capacity additions in a two-year 

window may be difficult. MISO’s experience is that new gas plant construction typically requires a longer 

period. If new transmission and gas pipeline additions are needed to accommodate the capacity 

expansion, this timeline is typically longer.
Chapter 6 – NERC’s Assessment on Analysis Conducted by Selected NERC Regions and ISO/RTOs

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PJM

Overview

The PJM Interconnection analyzed potential economic impacts on electric power generation in the PJM footprint 

resulting from the CPP. The Organization of PJM States, which represents state utility regulators in the region 

served by PJM, requested analyses of several scenarios, including a comparison of regional compliance versus 

state-by-state compliance. PJM included additional scenarios with different assumptions in the analyses to 

provide modeled results covering a wide range of possible outcomes. In total, PJM analyzed 17 distinct scenarios—

each was evaluated with and without the implementation of the CPP. The scenarios covered varying combinations 

and levels of renewable resources, energy efficiency, natural gas prices, nuclear generation, and new entry of 

natural gas combined-cycle resources.

PJM analyzed potential economic impacts, including the identification of fossil-fueled steam generation capacity 

thought to be at risk for retirement based only upon energy market simulation results. In the near future, PJM will 

use the results of the economic analysis to conduct a reliability analysis to determine transmission needs resulting 

from potential generator retirements.

Modeling and Input Assumptions

PJM ran five assumption scenarios under a regional mass-based approach for the years 2020, 2025, and 2029 to 

get a glimpse of compliance over the 10-year interim period. The years 2020, 2025, and 2029 were chosen so that 

PJM could examine the effects of the CPP at the start of the interim compliance period and a year halfway through 

the interim period, and then observe the effects of reaching the final targets. Although the rule permits averaging 

emissions rates over the 2020–2029 period, PROMOD is not a suitable tool for modeling such dynamic compliance 

options. As a result, each model year assumes compliance with the stated emissions target. PJM also ran one of 

the five OPSI-requested scenarios under a state-by-state mass-based approach to provide a comparison under the 

same scenario assumptions between a regional and a state-by-state approach for the year 2020.

In addition, PJM ran eight other assumption scenarios under a regional mass-based approach to provide a wider 

range of possible future scenarios and outcomes that could occur for CPP compliance for the years 2020, 2025, 

and 2029. PJM then ran two of the eight scenarios under a state-by-state compliance approach to provide 

additional comparisons of state-by-state and regional approaches for the year 2020. PJM also used one of the 

eight scenarios to run an emission-rate-based regional approach to compare outcomes and glean insights into the 

differences between a mass-based approach and an emission-rate-based approach for the years 2025 and 2029.

Resource Adequacy Findings

PJM’s analysis shows that nearly 11,000 MW of capacity are considered at risk for retirement in at least half the 

scenarios, about 14,500 MW in the worst-case scenario, and only about 6,200 MW at risk in all scenarios. PJM 

concluded that fossil steam unit retirements (e.g., coal, oil and gas) probably will occur gradually. As the CO2

emission limits decline over time, the financial positions of high-emitting resources should become increasingly 

less favorable, with lower-emitting resources displacing them more often in the competitive energy market.

Timing concerns are presented in PJM’s analysis, particularly as they relate to the 2020 target compliance period. 

It would be prudent to examine the year 2020 since decisions by Generator Owners would likely be made at the 

time the base residual auctions would be held in 2016 or 2017 for the 2019–2020 or 2020–2021 delivery years, 

respectively—and at a time when state compliance plans would not likely be known by Generator Owners. This 

represents an obvious conflict between established industry planning processes and the requirements of the CPP. 
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Conclusions and Key Findings 

 Fossil steam unit retirements (coal, oil, and gas) probably will occur gradually. As the CO2 emission limits 

decline over time, the financial positions of high-emitting resources should become increasingly less 

favorable, with lower-emitting resources displacing them more often in the competitive energy market.

 The price of natural gas likely will be a primary driver of the cost of reducing CO2 emissions if natural gas 

combined-cycle units become a significant source of replacement generation for coal and other fossil 

steam units.

 Adding more energy efficiency and renewable energy and retaining more nuclear generation would likely 

lead to lower CO2 prices; this could result in fewer megawatts of fossil steam resources at risk of 

retirement, because lower CO2 prices may reduce the financial stress on fossil steam resources under this 

scenario.

 State-by-state compliance options—compared to regional compliance options—likely would result in 

higher compliance costs for most PJM states, because there are fewer low-cost options available within 

state boundaries than across the entire region. However, results will vary by state given differing state 

targets and generation mixes. PJM modeled regional versus individual state compliance only under a 

mass-based approach. State-by-state compliance options would also increase the amount of capacity at 

risk for retirement because some states would likely face higher CO2 prices in an individual compliance

approach.
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SPP

Overview

On October 8, 2014, SPP published an internal study that it conducted on the impacts the CPP would have on its 

system. The EPA IPM assumptions for SPP include retirements of approximately 9,000 MW of capacity associated 

with existing coal- and gas-fired units currently relied upon to serve load obligations in SPP. The EPA’s projected 

electric generating unit (EGU) retirements represent approximately 6,000 MW of additional capacity being retired 

in SPP beyond that currently expected by 2020. The EPA projections represent approximately a 200 percent 

increase in retired generating capacity compared to SPP’s current expectations.

SPP’s assessment evaluated the impacts of the EPA’s projected EGU retirements within SPP. Reliability impacts 

were evaluated by identifying BPS equipment overloads and low voltages both during system intact conditions 

and during loss of a single element and by determining impacts to SPP’s reserve margin. SPP evaluated the impacts 

of the EGU retirements projected by the EPA that would result from implementing the carbon emission reduction 

goals proposed in the CPP, but due to time constraints did not evaluate the viability or reliability impacts of any 

of the building blocks used to establish those proposed goals.

Modeling and Input Assumptions

SPP assumed the retired capacity would be replaced by existing unused capacity remaining within the SPP 

footprint and surrounding areas. Then, SPP assumed the retired capacity would be replaced by a combination of 

existing unused capacity and new gas-fired and wind resources in the SPP footprint as needed to address capacity 

deficiencies. Both parts include performance of steady-state power flow analyses using models developed as 

described below to evaluate transmission system performance when all transmission elements are in service 

(“system intact”) and during conditions after which any single transmission element, including a generator, is 

taken out of service (“first contingency” or “N-1”).

Resource Adequacy Findings

SPP found in its analysis that it has a reserve margin requirement of 13.6 percent that every SPP member with 

load-serving responsibilities must plan to meet with appropriate generation capacity. The assessment showed 

that by 2020, SPP’s reserve margin would fall to 4.7 percent and that in 2024, the reserve margin would fall to -4

percent. The anticipated reserve margins represent a generation capacity deficiency of approximately 4.6 GW in 

2020 and 10.1 GW in 2024.

Transmission Adequacy Findings

In the analysis, SPP concluded that the SPP network would be severely stressed by large reactive deficiencies 

indicative of voltage collapse and blackout conditions. The analysis indicated approximately 5,200 MVar of 

reactive deficiencies in the SPP footprint during system intact conditions resulting from the modeled EPA 

generator retirements. The N-1 assessment revealed 38 overloaded elements. 

Conclusions and Key Findings 

 As a result of this assessment, SPP concludes that new generation and transmission expansion will be 

necessary to maintain reliability during summer peak conditions.

 SPP expresses concern about the timing needed for upgrades that would be required to maintain system 

reliability and cites a need for broader system assessments around natural gas pipeline and storage 

systems.

 SPP warns that outages to accommodate cut-ins of new equipment, as well as shifts in the operating 

characteristics of existing baseload units to more seasonal dispatch, would have a profound impact on 

system reliability.
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WECC

Overview

WECC issued by its analysis on September 19, 2014. Through the initial efforts summarized in this document, 

WECC has performed preliminary analyses to provide a starting point for additional discussions and more detailed 

assessments. This analysis leverages WECC’s new cross-functional analytical approach, where the focus is on a 

single reliability issue—in this case the proposed CPP—and studying it from different perspectives. Unlike the 

analyses performed by the ISO/RTO, WECC was able to conduct an analysis around the impacts from a pure 

reliability perspective.

WECC approached its analysis by performing the following:

1. Resource Adequacy Assessment: The resource adequacy perspective is essential to ensuring that there 

will be enough resources to serve peak load under various compliance scenarios. Resource adequacy 

assessments look at forecast load and expected resources and apply reserve margin calculations to 

determine if resources meet demand. 

2. Production Simulation Modeling: Also known as production cost simulation, this perspective gives insight 

into operational, economic, and emission impacts the system might face under particular circumstances 

in the future. 

3. System Stability Studies: This perspective provides a check on whether potential compliance scenarios 

create stability issues. These studies take a snapshot of the grid and investigate how the unexpected loss 

of equipment could impact grid reliability. 

Resource Adequacy Findings

WECC’s contribution to NERC’s 2014 LTRA shows that planning reserve margins are currently in excess of their 

targets and, based on the current assumptions posed by the EPA building blocks, impacts to resource adequacy 

may be minimal for the western states. WECC plans to further investigate resource adequacy in the coming 

months as compliance scenarios are identified by states. Like other reliability assessments, resource adequacy 

cannot be properly assessed absent realistic or proposed compliance scenarios.

An added value to WECC’s assessment was an analysis of resource performance during frequency disruptions. In 

the frequency response study, 7,000 MW of coal resources were replaced by less-responsive inverter-based 

resources. In this analysis, the system responded to a large contingency nearly the same as it did before the coal 

units were replaced. This study represents a strong first-step reliability assessment, but additional scenarios must 

be studied across varying operational and load conditions in order to draw meaningful conclusions about system 

reliability. More importantly, frequency response is only one aspect of reliability, and the removal of coal 

resources could impact other areas, such as remedial action schemes, path ratings, and voltage stability, among 

others. Central to all of these studies are the assumptions on replacement generation posed by potential 

compliance scenarios. 

Conclusions and Key Findings

 WECC’s initial frequency response analysis showed that for the specific condition studied (peak summer 

condition only), the system was able to recover from a large contingency, and frequency response was 

not significantly compromised. It is important to note that these initial studies focused only on frequency 

response, which is one aspect of the broader system reliability picture. Reliability concerns outside this 

narrow area of study include remedial action schemes, path ratings, and voltage stability. 

 Western states are already taking actions to reduce emissions, prior to the CPP implementation. WECC’s 

preliminary analysis showed that states planning to retire carbon-intensive generation, implement energy 
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efficiency, and build out robust levels of renewable resources could make strides toward achieving the 

EPA goals in the next 10 years. 

 Although it is still early to consider the impact of state compliance plans, preliminary WECC results have 

shown that decisions made regarding the CPP compliance in a state can impact grid operations, system 

resiliency, and potentially compliance opportunities for a neighboring state. While changes in the resource 

mix and forecast load in one or two states may not drastically impact the system, significant changes in 

four, five, or all western states at once is exponentially more concerning for a system that is inherently 

interconnected. 
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Chapter 7 – Reliability Assurance Mechanism

Maintaining Reliability Assurance

NERC’s Initial Reliability Review31 recommended that the EPA, FERC, the DOE, and state utility regulators employ 

a wide array of tools and regulatory authority to formulate a reliability assurance mechanism. Such a reliability 

back-stop could include timing adjustments and the granting of extensions to an entity’s implementation of and 

compliance with its CPP implementation plan where there is a demonstrated reliability need. The key findings and 

conclusions presented in this Phase I assessment confirm that a reliability assurance mechanism is needed to 

ensure the reliability of the BPS during both the plan’s development and implementation periods.32 A defined 

reliability assurance mechanism, integrated within the EPA’s final CPP rule, would recognize the respective roles 

of regulated entities, states or regions, FERC, the DOE, the EPA, and NERC while preserving BPS reliability and 

managing emerging and impending reliability risks. 

These materials provide an overview of the rationale for why a reliability assurance mechanism is needed and 

additional detail regarding the ways in which a reliability assurance mechanism could work in concert with other 

efforts. While NERC’s potential role would not be to propose certifying or approving the validity of implementation 

plans, reliability assessments and technical guidance on whether a specific plan could create or have the potential 

to create a reliability issue could be of assistance. 

A NERC assessment of the overall potential impacts of the proposed CPP plans on state, multi-state, and regional 

grid reliability as plans are being developed and submitted to the EPA is also important for understanding the 

infrastructure and solutions that would need to be deployed to meet CPP requirements. Reliability assessments 

would (1) serve as a reliability resource to evaluate either state implementation plans during their development 

or aggregate entity plans once formulated, (2) enable interested stakeholders to identify grid reliability challenges 

and develop mitigation strategies, and (3) enhance the effectiveness and efficiency of plans by ensuring that they

account for transmission and generation availability and performance, and other relevant operational and 

planning information from system operators and planners.

Identifying a Need for a Reliability Assurance Mechanism

The FERC-approved NERC Reliability Standards provide for the reliable operation of the BPS and help ensure that 

instability, uncontrolled separation, or cascading failures of the system will not occur as a result of a sudden 

disturbance or the unanticipated failure of system elements. Because the NERC Reliability Standards must be 

complied with at all times, the availability of a defined reliability assurance mechanism in the CPP would provide 

protection or relief to states, regions, and industry entities as reliability challenges occur in CPP development or 

during the plan’s implementation.

A wide range of factors, both anticipated as well as those that could emerge during the CPP’s implementation 

period, could impact a state’s or region’s conformance with the proposed CPP implementation plans. Some of 

these factors include the following: 

 variability and uncertainty of infrastructure lead times (both generation and transmission);

 

31 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/Potential_Reliability_Impacts_of_EPA_Proposed_CPP_Final.pdf.

32 Other entities have also argued that a reliability assurance mechanism is needed to ensure that reliability is maintained during the CPP’s 

implementation. For example, the ISO/RTO Council, in its February 19, 2015 statement, provides four mechanisms, in which states will 

provide a foundation to assure reliability during both the planning process and implementation. These four mechanisms are:

1. Regional and multi-regional reliability assessments of the CPP plans to evaluate reliability and timing needs;

2. Established criteria for the EPA to evaluate CPP plan reliability impacts;

3. “Glide path” flexibility where it is needed due to the timing of necessary electric infrastructure development; and 

4. Adoption of a safety valve process to address grid reliability impacts during the plan’s implementation.
Chapter 7 – Reliability Assurance Mechanism

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 the complexity of multi-regional coordination, which will require time to develop and can only be 

accomplished once definitive plans are in place;

 the technical and logistical feasibility of infrastructure development; 

 NERC’s mandatory transmission planning and adequacy standards, which establish BPS reliability 

performance requirements that must be maintained;

 unanticipated issues that could significantly alter and delay construction plans; and

 the CPP implementation period through 2030, which could introduce economic, policy, regulatory, 

legislative, technological, or other drivers that affect reliability plans.

NERC, as a recognized reliability authority, is capable of evaluating the reliability implications of these anticipated 

factors, system conditions, and infrastructure changes. In both CPP plan development among the states and 

implementation by industry entities, technical assessments that help determine projected reliability constraints 

and alignment with other reliability criteria (i.e., as required by state, ISO/RTO, or interconnection rules) would 

be of benefit. Additionally, system simulation and analyses to demonstrate potential reliability issues (e.g.,

resource adequacy, power flow and dynamics modeling, voltage stability assessment, and frequency response 

analysis) could also be performed.

Elements of a Reliability Assurance Mechanism

The principal elements of an effective reliability assurance mechanism should include alignment of reliability, 

implementation plans, regulation, and overall certainty. For the CPP, these elements will involve the regulated 

entities, states or regions, FERC, the DOE, the EPA, and NERC. An effective reliability assurance mechanism should 

also include the following elements: 

 state or regional CPP plans with state and federal regulatory alignment;

 a reliability assessment by NERC of CPP plans;

 an evaluation against distinct reliability criteria and inter-area coordination; 

 consideration of other reliability assurance mechanism options, including:

 infrastructure implementation options and target impacts;

 adjustments to implementation targets;

 reliability-must-run generation;

 entity- or state-specific implementation plan modifications; and

 reliability-specific adaptations and provisions to maintain reliability.

During the CPP development stage, states or regions will be responsible for developing plans that support the

CPP’s targets. In developing those plans, reliability assessments and evaluations by NERC, as requested by states,

would help support efforts to ensure that reliability can be maintained during the CPP implementation period as 

planned infrastructure is built. Based on these reliability evaluations, states could then determine whether a plan 

could be implemented to meet the CPP requirements. If more time is needed to support a demonstrated reliability 

need, a reliability assurance mechanism could be used to provide relief and align the plan with CPP targets. 

During the plan implementation stage, an approved state or regional plan well underway may experience 

unexpected and unplanned challenges in deploying infrastructure and resources during the plan’s 

implementation. As described in this report, external factors contribute to planning challenges and uncertainty 

and could impact reliability, including the siting and permitting of electric facilities (generation and transmission), 

the effects of neighboring areas implementing their plans, the price of fuel, and changes in customer behavior 
Chapter 7 – Reliability Assurance Mechanism

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and electricity demand. As a result, some states or regions may not meet their plan targets while maintaining 

reliability. In these circumstances, a reliability assurance mechanism could be used to ensure that there are no 

adverse reliability impacts in implementing the CPP.

A reliability assurance mechanism should recognize the need for flexibility in meeting overall CPP target objectives 

by providing flexibility to address unique state and local reliability impacts during implementation. A reliability 

assurance mechanism would also provide overall regulatory certainty for states and entities and reliability 

assurance for the BPS.

NERC’s role in an effective reliability assurance mechanism, described in more detail below, would be to provide 

the context for conducting reliability evaluations and assessments during the CPP’s development and 

implementation periods. As the CPP rule and corresponding implementation plans developed by entities, states, 

and regions are finalized, reliability assurance requirements and guidance could be identified. In cases where plans 

have identified an adverse state, regional, or inter-regional reliability impact that has not been adequately 

mitigated or addressed, the final rule should provide regulatory certainty that a reliability assurance provision is 

available to adequately address infrastructure and resource needs without penalizing the states or industry 

entities.

NERC’s Role in a Reliability Assurance Mechanism

There are three primary periods during which NERC could provide a reliability assessment and guidance for states 

and entities as plans are developed to implement and comply with the CPP. These reliability-focused steps could 

serve to support reliability assurance during refinement of state or regional plans as well as during implementation 

of plan elements. They are:

1. During the CPP Plan Development Period: As states are developing their state implementation plans or 

regional implementation plans, NERC could serve as a resource in assessing reliability or identifying 

potential reliability concerns. While NERC’s role would be advisory and non-binding, NERC could develop 

written guidance and criteria by which plans may be developed, reviewed, and evaluated.

2. During the Plan Review and Approval Period: After the CPP final rule has been issued and prior to the 

initial submittal dates for state and regional implementation plans, NERC plans to undertake its Phase II 

assessment of the CPP, currently anticipated by mid-2016. Additionally, NERC would continue to conduct 

its long- and short-term reliability assessments, which would reflect aggregate entities’ implementation 

plans within state or regional CPP plans. Reliability assessments and review of the plans before they are 

finalized could identify areas where there may be a reliability issue. 

3. During the Plan Implementation Period: As actual, emerging, or anticipated reliability issues are 

identified, factors that might impact an entity’s ability to ensure reliability while satisfying the CPP may 

occur. Those factors include: 

a. insufficient time to implement infrastructure additions or modifications needed to maintain 

reliability;

b. unanticipated conditions or circumstances directly affecting implementation plans, leading to 

reliability issues;

c. an entity identifying an impending conflict between assuring reliability and satisfying the CPP 

implementation plan; or 

d. an entity determining that meeting the requirements of the CPP implementation plan will require 

load to be shed. 
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The proposed framework outlined in Figure 24 offers more detail on how reliability-focused steps throughout all 

stages of the CPP’s implementation—including during CPP plan development, CPP plan review and approval, and 

CPP plan implementation—could be pursued. 

Figure 24: A Framework for NERC’s Advisory Role and the Reliability Assurance Mechanism

In the framework proposed above, NERC is available to work with states, FERC, the DOE, the EPA, and others 

throughout the process to ensure this reliability information is available to them as progression toward 

environmental plans and CPP requirements is being made. 

Conclusions

NERC recommends adoption of a reliability assurance mechanism in the CPP final rule that could be based on the 

specific roles described above. Further, NERC recommends that policy makers help ensure that state or regional 

implementation plans that are developed to meet the CPP requirements provide assurances that reliability can 

be sustained during the CPP’s implementation period. Plans that require greater infrastructure development of 

either gas pipelines, transmission, supply resources, or other assets will require time to ensure these 

infrastructure accommodations can be made with reliability certainty. A reliability assurance mechanism, along 

with sufficient timelines to accommodate infrastructure development, can facilitate a reliable transition and

ensure BPS reliability. 
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Chapter 8 – Recommendations, Conclusions, and Future Steps

This report represents NERC’s continuing efforts to identify concerns regarding the EPA’s proposed CPP. As the 

CPP is finalized and implemented, NERC will continue to develop special reliability assessments in phases. It is 

NERC’s intention that this document be used as a platform by industry stakeholders and policy makers to discuss 

technically sound information about the potential reliability impacts of the proposed CPP. Together, industry 

stakeholders and regulators will need to develop an approach that accommodates the time required for 

infrastructure deployments, market enhancements, and reliability needs if the environmental objectives of the 

proposed rule are to be achieved.

Recommendations 

1. NERC should continue to update and expand the assessments of the reliability implications of the 

proposed CPP and provide independent evaluations to stakeholders, states, regulators, and policy 

makers. NERC should continue to conduct a phased assessment strategy that provides insight and 

guidance as the CPP rule is finalized and implementation plans begin to be formalized.

The NERC Board of Trustees endorsed a plan for the review and assessment of the reliability impacts of

the EPA proposal at its August 2014 meeting. Additionally, as part of its normal course of duty and 

responsibility, NERC annually conducts seasonal and long-term reliability assessments. Each year, NERC 

evaluates aggregated and regional system plans that cover the entire BPS in North America. Over the next 

several years, these assessments will incorporate the CPP rule’s implementation. 

2. Coordinated regional and multi-regional industry planning and analysis groups should continue to 

conduct detailed system evaluations to identify areas of reliability concern and work in partnership with 

states, regions, and policy makers to provide clear guidance of the complex interdependencies resulting 

from the CPP rule’s implementation.

Given the approaching 2020 interim target date identified in the proposed CPP, NERC encourages the 

states to begin operational and planning scenario studies, including resource adequacy, transmission 

adequacy, and dynamic stability, to assess economic and reliability impacts. A number of studies and 

analyses must be performed to demonstrate reliability, and industry must closely coordinate with the 

states to ensure the state or regional plans are aligned with what is technically achievable within the 

known time constraints. Additionally, industry should review system flexibility and reliability needs while 

achieving the EPA’s emission reduction goals. As a result, states that largely rely on fossil fuel resources 

might need to make significant changes to their power systems to meet the EPA’s target for carbon 

reductions while maintaining system reliability. Further, coordinated planning between the electric and 

gas sectors will be needed to ensure a strong and integrated system of fuel delivery and generation 

adequacy. Coordinated planning processes should include considerations for pipeline expansion to meet 

the increased reliance on natural gas for electric generation, especially during extreme weather events 

(e.g., polar vortex). Finally, ISO/RTOs, utilities, and Regional Entities should analyze the impacts to ERSs

through the ongoing efforts of NERC’s ERS Task Force. 

3. Policy makers, states, regions, and regulators (including the EPA) should develop implementation plans 

that allow for more time to address potential BPS reliability risks and infrastructure deployment 

requirements during the transition period. 

NERC Reliability Standards and Regional Entity criteria must be met at all times to ensure reliable 

operation and planning of the BPS. Based on NERC’s Phase I assessment, more time would be needed in 

certain areas to ensure that resource adequacy, reliability requirements, and infrastructure needs are 

maintained. The EPA, FERC, the DOE, and state utility regulators should consider it their regulatory 

authority to make timing adjustments and to grant extensions to preserve BPS reliability, considering lead 

times for infrastructure as a critical path. Regulators should also consider developing approaches to 

expedite project approval processes as a mitigation strategy for reliability issues that may emerge.
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4. The EPA should include a formal reliability assurance mechanism in the final rule that provides the 

regulatory certainty and explicit recognition of the need to ensure reliability during both the plan 

development and the implementation period through 2030—and potentially beyond. NERC has 

outlined a specific series of roles for providing reliability guidance and independent assessments, in the 

form of a reliability assurance mechanism.

NERC supports policies that include a reliability assurance mechanism to manage emerging and impending 

risks to the BPS and urges policy makers and the EPA to ensure that a flexible and effective mechanism is

included in the rule’s implementation. Further, NERC recommends that policy makers ensure that state 

or regional implementation plans provide demonstrated assurances that reliability can be sustained 

during the CPP’s implementation period. Plans that require greater infrastructure development of either 

gas pipelines, transmission, supply resources, or other assets will require time to ensure these 

infrastructure accommodations can be made with certainty. A reliability assurance mechanism, along with 

sufficient timelines to accommodate infrastructure development, can facilitate a reliable transition and 

ensure BPS reliability.

5. State and regional plans should be developed with consultation from reliability authorities (Planning 

Coordinators and Transmission Planners).

System-specific analysis will be needed to evaluate the effects of the proposed CPP and demonstrate 

reliability. These efforts will require more in-depth and system-specific analysis, which includes evaluating 

transmission adequacy under contingency scenarios, examining voltage and transient stability caused by 

system disturbances, and determining interchange power transfer capabilities between systems.

Reliability authorities have the tools and subject matter expertise to conduct these analyses and

determine explicit reliability.

Next Steps for NERC Reliability Assessments 

Over the next several months, NERC intends to coordinate with federal and state regulatory authorities to provide 

guidance and insights about the results and conclusions of NERC’s Phase I assessment. The CPP is expected to be 

finalized during the summer of 2015. Once the CPP is finalized, NERC will conduct an additional review and 

assessment (Phase II) to support state and regional plan development.
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Appendix A – AURORAxmp Model vs. IPM Model

Background

The AURORAxmp electric power market forecasting tool is a fundamentals-based power market model that 

economically dispatches generation capacity to simulate the operations of each power market in the continental 

United States. The model optimizes dispatch by using the lowest-cost resources to meet electricity demand in a 

given region at the hourly level and builds the most economic new resources to meet reserve margin targets and 

future load growth.

The Integrated Planning Model (IPM) analyzes the projected impact of environmental policies on the electric 

power sector in the 48 contiguous states and the District of Columbia. Developed by ICF Consulting, Inc. and used 

to support public- and private-sector clients, IPM is a multi-regional, dynamic, deterministic linear programming 

model of the U.S. electric power sector. It provides forecasts of least-cost capacity expansion, electricity dispatch, 

and emission control strategies for meeting energy demand and environmental, transmission, dispatch, and 

reliability constraints.

IPM and AURORAxmp typically are used to support resource planning, regulatory analysis, commodity price 

forecasting, and asset valuation, and both seek to determine the least-cost method to meet electricity demand 

given various exogenous inputs and constraints.

Even though IPM and AURORAxmp have similar goals, there are several significant differences between the 

models.

1. IPM aggregates similar types of capacity (fuel and technology type) and applies weighted-average 

operating parameters to the grouped capacity, as opposed to populating the model with each generating

unit and applying its real-life operating parameters. Therefore, IPM aggregates the 16,330 existing 

generating units in the electric power sector into 4,971 “model units” to simplify the analysis and reduce 

run time.

2. The AURORAxmp database was populated by information from individual power plant generators and 

does not aggregate multiple or different plants together. Therefore, the AURORAxmp model simulates

how each power plant operates in real life on an hourly basis.

3. Regarding dispatch logic, IPM breaks up each model year into two seasons: winter and summer. The 

hourly demand in each season is then ordered from highest to lowest to develop a load-duration curve.

IPM’s aggregated units are then dispatched to create generation and power prices. IPM’s method solves 

for the entire season at once, rather than dispatching units in each hour.

Rationale for Model Selection

The AURORAxmp dispatch logic economically dispatches each generation unit against electricity demand for each 

chronological hour. AURORAxmp closely mimics the actual power markets’ day-ahead and real-time dispatch 

practices and captures many of the unintended re-dispatch inefficiencies introduced by the CPP that a loadduration-curve-based approach would not. The input assumptions for each model have differing effects. For 

example, the IPM model retires coal units that the AURORAxmp model assumes will continue to run but at much 

lower load factors (considered at-risk for sustained operation). Therefore, the results achieved were different for 

projected unit retirements and the timing of these retirements. However, both models indicated close to the same 

results in both capacity and energy shifts of all resource types between 2020 and 2030. 
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Appendix B – Steady-State Power System Analysis Methods

Study Methods

To implement unit retirements in the power flow models, a small group of units (i.e., a few units at a time) were 

retired and new units were added to compensate for the generation deficiency. The reason for this approach was 

ease of obtaining a power flow solution (experience proved that retiring all the units at once caused power flow 

to diverge). 

Following the selection of locations for new units, a transmission voltage level was selected that most 

appropriately accommodates the amount of added generation. Next, a power flow simulation was performed for 

generation displacement and transmission facility addition. The aforementioned process was repeated until all 

required unit retirements and additions were implemented.

Steady-State Analysis; Contingency Considerations

Bulk power systems must provide adequate generation and transmission capacity to meet the demand while 

satisfying system operating constraints, but also be capable of maintaining system stability following faults, facility 

switching, and other disturbances. Reliability of a bulk system can be evaluated by two attributes: adequacy and 

security. Adequacy refers to the ability of the system to supply the aggregate electric energy requirements of 

loads within equipment ratings and voltage limits when planned and unplanned component outages occur. 

Adequacy assessment involves system steady-state conditions of post-contingencies; i.e., the system is assumed 

to always reach a stable equilibrium point after equipment outages, and the dynamics of the transition from one 

state to another are neglected. The second attribute, system security, refers to the ability of the power system to 

withstand disturbances arising from faults or equipment outages. Security assessment involves modeling systemtransient responses and potential cascading sequences after a disturbance. Transient responses include the 

fluctuations of both the frequency and voltage.

Contingency

A contingency is an unexpected event that could result in the loss of one or more BPS facilities. The following 

contingency categories are defined by NERC:

 All facilities in service (Category A); i.e., system intact N-0

 Event resulting in loss of a single element (Category B), N-1

 Event(s) resulting in the loss of two or more (multiple) elements (Category C), N-2 or multiple

 Extreme events resulting in the loss of two or more elements (Category D), N-2 or multiple

Power System Model

Power system models of the North American power system are created on an annual basis by ERAG, WECC, and 

TRE and are required for power system planning studies. Power flow and dynamic models for the current year and 

future years are assembled by NERC Regional Entity members. ERAG-MMWG regional members, on a yearly basis,

assemble power system models (power flow and dynamic model) for future years (e.g., the 2015 power flow base

case series span from 2015 to 2025 for a total of 15 cases). Subsequently, NERC Regional Entities and MMWG 

coordinators produce complete ERAG models. WECC and TRE follow a similar approach. 
	






	






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