NERC | Potential Reliability Considerations from EPA’s Proposed Clean Power Plan | October 2014

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Potential Reliability Impacts of 

EPA’s Proposed Clean Power Plan 

Initial Reliability Review

November 2014 
NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan | November 2014

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Table of Contents

Preface ................................................................................................................................................................................ii

Executive Summary .............................................................................................................................................................1

Summary of the Proposed Clean Power Plan.......................................................................................................................5

Clean Power Plan Building Blocks............................................................................................................................................6

Clean Power Plan – Assumption Review..............................................................................................................................8

Building Block 1 – Coal Unit Heat Rate Improvement .............................................................................................................8

Building Block 2 – Gas Unit Re-Dispatching .............................................................................................................................9

Building Block 3 – Clean Energy.............................................................................................................................................11

Building Block 4 – Energy Efficiency.......................................................................................................................................14

Reliability Impacts Potentially Resulting from the CPP ......................................................................................................17

Direct Impacts to Resource Adequacy and Electric Infrastructure....................................................................................17

Impacts Resulting from the Changing Resource Mix .........................................................................................................24

Conclusions .......................................................................................................................................................................27
NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan | November 2014

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Preface

The North American Electric Reliability Corporation (NERC) has prepared the following assessment in accordance with the 

Energy Policy Act of 2005, in which the United States Congress directed NERC to conduct periodic assessments of the 

reliability and adequacy of the bulk power system (BPS) in North America.1NERC operates under similar obligations in many 

Canadian provinces, as well as a portion of Baja California Norte, Mexico.

NERC is an international regulatory authority established to evaluate and improve the reliability of the BPS in North America. 

NERC develops and enforces Reliability Standards; annually assesses seasonal and long-term (10-year) reliability; monitors 

the BPS through system awareness; and educates, trains, and certifies industry personnel. NERC is the electric reliability 

organization (ERO) for North America, subject to oversight by the U.S. Federal Energy Regulatory Commission (FERC) and 

governmental authorities in Canada.2

NERC Regions and Assessment Areas

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

 

1 H.R. 6 as approved by of the One Hundred Ninth Congress of the United States, the Energy Policy Act of 2005. The NERC Rules of Procedure, 

Section 800, further detail the Objectives, Scope, Data and Information requirements, and Reliability Assessment Process requiring annual 

seasonal and long-term reliability assessments.

2 As of June 18, 2007, FERC granted NERC the legal authority to enforce Reliability Standards with all U.S. users, owners, and operators of the BPS 

and made compliance with those standards mandatory and enforceable. Equivalent relationships have been sought and for the most part realized 

in Canada and Mexico. Prior to adoption of §215 in the United States, the provinces of Ontario (2002) and New Brunswick (2004) adopted all 

Reliability Standards that were approved by the NERC Board as mandatory and enforceable within their respective jurisdictions through market 

rules. Reliability legislation is in place or NERC has memoranda of understanding with provincial authorities in Ontario, New Brunswick, Nova 

Scotia, Québec, Manitoba, Saskatchewan, British Columbia, and Alberta, and with the National Energy Board of Canada (NEB). NERC standards 

are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law. Manitoba has adopted legislation, and standards are 

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

certain Reliability Standards have been approved in that jurisdiction; others are pending. NERC standards are now mandatory in British Columbia 

and Nova Scotia. NERC and the Northeast Power Coordinating Council (NPCC) have been recognized as standards-setting bodies by the Régie de 

l’énergie of Québec, and Québec has the framework in place for Reliability Standards to become mandatory. NEB has made Reliability Standards 

mandatory for international power lines. In Mexico, the Comisión Federal de Electricidad (CFE) has signed WECC’s reliability management system 

agreement, which only applies to Baja California Norte.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating Council

RF ReliabilityFirst 

SERC SERC Reliability Corporation

SPP-RE Southwest Power Pool Regional Entity

TRE Texas Reliability Entity

WECC Western Electricity Coordinating Council
NERC | Potential Reliability Impacts from EPA’s Proposed Clean Power Plan | November 2014

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Executive Summary

The Environmental Protection Agency (EPA), on June 2, 2014, issued its proposed Carbon Pollution Emission Guidelines for 

Existing Stationary Sources: Electric Utility Generating Units, commonly referred to as the proposed Clean Power Plan (CPP),

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

August 14, 2014, the NERC Board of Trustees directed NERC to develop a series of special reliability assessments to examine

the proposed CPP. This report is NERC’s initial reliability review of the potential risks to reliability, based on the assumptions 

contained in the proposed CPP. 

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 bulk power system (BPS). Reliability assessments conducted while the EPA is 

finalizing the CPP can inform regulators, state officials, public utility commissioners, utilities, and other impacted stakeholders 

of potential resource adequacy concerns, impacts to system characteristics (such as essential reliability services (ERSs)), and, 

to some degree, areas that are more likely to require power-flow-related transmission enhancements to comply with NERC 

Reliability Standards. The goals of this review are listed in more detail below:

 Provide an evaluation and comparison of the assumptions supporting the CO2 reduction objectives in the proposed 

CPP against other reported projections available within NERC assessment reports.

 Provide insight into planned generation retirements, load growth, renewable resource development, and energy 

efficiency measures that might impact CO2 emissions and the EPA’s target-driven assumptions.

 Provide insight into the potential reliability consequences of either the target-driven emission assumptions or the 

NERC projection-based assumptions and, in particular, the potential reliability implications if the EPA assumptions 

cannot be realized.

 Identify potential reliability impacts resulting from the expected resource mix changes, such as coal resource 

displacement or retirements, the impacts on regional planning reserve margins, the shifts in resource mix and ERS

characteristics, the increase in variable resources, the concentration of resources by fuel source (especially natural 

gas), transmission and large power transfers, and other reliability characteristics, including regional differences.

 Support the electric power industry and NERC stakeholders by providing an independent assessment of reliability 

while serving as a platform to inform policy discussions on BPS reliability and emerging issues.

This report and its findings are not intended to: (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; or (5) represent a final and conclusive 

reliability assessment.

The objective of this review is to identify the reliability implications and potential consequences from the implementation of 

the proposed CPP and its underlying assumptions. The preliminary review of the proposed rule, assumptions, and transition 

identified that detailed and thorough analysis will be required to demonstrate that the proposed rule and assumptions are 

feasible and can be resolved consistent with the requirements of BPS reliability. This assessment provides the foundation for 

the range of reliability analyses and evaluations that are required by the ERO, RTOs, utilities, and federal and state policy 

makers to understand the extent of the potential impact. 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.

Herein, NERC examines the assumptions made in the EPA’s four Building Blocks:

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Building Block 1: Heat rate improvements

Building Block 2: Dispatch changes among affected electric generating units (EGUs)

Building Block 3: Using an expanded amount of less-carbon-intensive generating capacity

 

3 Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units. 
Executive Summary

NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan | November 2014

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Building Block 4: Demand-side energy efficiency 

NERC identified the following factors as requiring additional reliability consideration:

Implementation of the CPP reducesfossil-fired generation: The proposed CPP aims to cut CO2 emissions from existing power 

plants to 30 percent below 2005 levels by 2030. Under the EPA proposal, substantial CO2 reductions are required under the

State Implementation Plans(SIPs) as early as 2020. According to the EPA’s Regulatory Impact Assessment, generation capacity 

would be reduced by between 108 and 134 GW by 2020 (depending on state or regional implementations of Option 1 or 2).

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The number of estimated retirements identified in the EPA’s proposed rule may be conservative if the assumptions prove to 

be unachievable. Developing suitable replacement generation resources to maintain adequate reserve margin levels may 

represent a significant reliability challenge, given the constrained time period for implementation.

Assumed heat rate improvements for existing generation may be difficult to achieve: NERC is concerned that the assumed 

improvements may not be realized across the entire generation fleet since many plant efficiencies have already been realized

and economic heat rate improvements have been achieved. Multiple incentives are in place to operate units at peak 

efficiency, and periodic turbine overhauls are already a best practice. Site-specific engineering analyses would be required to 

determine any remaining opportunities for economic heat rate improvement measures.

Greater reliance on variable resources and gas-fired generation is expected: The CPP will accelerate the ongoing shift toward 

greater use of natural-gas-fired generation and variable energy resources (VERs) (renewable generation). Increased 

dependence on renewable energy generation will require additional transmission to access areas that have higher-grade wind 

and solar resources (generally located in remote areas). Increased natural gas use will require pipeline expansion to maintain 

a reliable source of fuel, particularly during the peak winter heating season. Pipeline constraints and growing gas and electric 

interdependency challenges impede the electric industry’s ability to obtain needed natural gas services, especially during 

high-use horizons.

Rapid expansion of energy efficiency displaces electricity demand growth through 2030: In its rate calculation for best 

practices by state, the EPA assumes up to a 1.5 percent annual retail goal for incremental growth in efficiency savings. The 

EPA assumes that the states and industry would rapidly expand energy efficiency savings programs from 22 TWh/year in 

2012, to 108 TWh/year in 2020, and reach 380 TWh/year by 2029. With such aggressive energy efficiency expansion, the EPA 

assumes that energy efficiency will grow faster than electricity demand, with total electricity demand shrinking after 2020. 

The implications of this assumption are complex. If the EPA-assumed energy efficiency growth rates cannot be attained, 

additional carbon reduction measures would be required, primarily through reduced fossil-fired generation.

Essential Reliability Services may be strained by the proposed CPP: The anticipated changes in the resource mix and new 

dispatching protocols will require comprehensive reliability assessments to identify changes in power flows and ERSs. ERSs

are the key services and characteristics that comprise the following basic reliability services needed to maintain BPS reliability: 

(1) load and resource balance; (2) voltage support; and (3) frequency support. New reliability challenges may arise with the 

integration of generation resources that have different ERS characteristics than the units that are projected to retire. The 

changing resource mix introduces changes to operations and expected behaviors of the system; therefore, more transmission 

and new operating procedures may be needed to maintain reliability.

More time for CPP implementation may be needed to accommodate reliability enhancements: State and regional plans 

must be approved by the EPA, which is anticipated to require up to one year, leaving as little as six months to two years to

implement the approved plan. Areas that experience a large shift in their resource mix are expected to require transmission 

enhancements to maintain reliability. Constructing the resource additions, as well as the expected transmission 

enhancements, may represent a significant reliability challenge given the constrained time period for implementation. While 

 

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Regional implementation of Option 2 assumes 108 GW of retirements (includes CC, Coal, CT, Nuclear, O/G, and IGCC) by 2020. State 

implementation of Option 1 assumes 134 GW of retirements (includes CC, Coal, CT, Nuclear, O/G, and IGCC) by 2020. For additional information, 

see: Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and 

Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.
Executive Summary

NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan | November 2014

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the EPA provides flexibility for meeting compliance requirements within the proposed time frame, there appears to be less 

flexibility in providing reliability assurance beyond the compliance period.

A summary of NERC’s initial reliability review recommendations is provided below:

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. 

3. If the environmental goals are to be achieved, policy makers and the EPA should consider a more timely 

approach that addresses BPS reliability concerns and infrastructure deployments.

Recommendations to Address Direct Impacts to Resource Adequacy and Electric Infrastructure

Fossil-Fired Retirements and Accelerated Declines in Reserve Margins

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

Transmission Planning and Timing Constraints

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 the rule provides 

sufficient time for the industry to take the steps needed to significantly change the country’s resource mix and 

operations without negatively affecting BPS reliability.

Regional Reliability Assessment of the Proposed CPP

Other ISO/RTOs, states, and Regions should prepare for the potential impacts to grid reliability, taking into 

consideration the time required to plan and build transmission infrastructure.

Reliability Assurance

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, such as a “reliability back-stop.” These mechanisms include timing 

adjustments and granting extensions where there is a demonstrated reliability need.

Recommendations to Address Impacts Resulting from the Changing Resource Mix

Coal Retirements and the Increased Reliance on Natural Gas for Electric Power

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).

The Changing Resource Mix and Maintaining Essential Reliability Services

ISO/RTOs, utilities, and Regions (with NERC oversight) should analyze the impacts to ERSs in order to maintain reliability. 

Additionally, system operators and ISO/RTOs need to develop appropriate processes, tools, and operating practices to 

adequately address operational changes on the system.

NERC should perform grid-level performance expectations developed from a technology-neutral perspective to ensure 

ERS targets are met.

The development of technologies (such as electricity storage) help support the reliability objectives of the BPS, and 

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

Increased Penetration of Distributed Energy Resources (DERs)

ISO/RTOs and system planners and operators should consider the increasing penetration of DERs and potential 

reliability impacts due to the limited visibility and controllability of these resources.
Executive Summary

NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan | November 2014

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Plan for NERC Reliability Assessments

After the proposed CPP is finalized, specific transmission and resource adequacy assessments—including resulting reliability 

impacts—will be essential for supporting the development of SIPs that are aligned with system reliability needs. NERC’s plan 

for reviewing and assessing the reliability impacts of the EPA proposal is included in Figure 1. This review includes a 

preliminary review of the assumptions and potential reliability impacts resulting from the implementation of the EPA’s 

proposed CPP. As the EPA is scheduled to finalize its rule by June 2015, NERC will develop a specific reliability assessment in 

early 2015 that will focus on evaluating generation and transmission adequacy and reliability impacts. After the EPA rule is 

finalized, the states, either individually or in multi-state groups, are required to develop their SIPs by 2016 and 2018, 

respectively. NERC plans to provide a more specific and comprehensive reliability assessment before SIPs are submitted to 

the EPA. Additionally, a Phase III approach is tentatively planned for December 2016, which will examine finalized SIPs.

Figure 1. NERC’s Assessment Actions and Schedule Timeline
Summary of the Proposed Clean Power Plan

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Summary of the Proposed Clean Power Plan

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

CO2 reductions are required under State Implementation Plans. Under the EPA proposal, CO2 reductions are required as early 

as 2020. According to the EPA’s reliability assessment included in the proposed rule, these existing generation rules would 

result in between 108 and 134 GW of generation retirements by 2020 (depending on state or regional implementations of 

Option 1 or 2).

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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;6(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.

7 Given these criteria, the EPA 

estimates that approximately 3,000 U.S. fossil-fired electric generation units representing over 700,000 MW of existing 

nameplate generating capacity will be subject to the rule limitations.8 NERC estimates that this magnitude represents 

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

The EPA-proposed draft regulations would, for the first time, limit CO2 from existing power plants, thus addressing risks to 

health and the economy posed by climate change. These proposed regulations are intended to provide implementation 

flexibility and maintain an affordable, reliable energy system while cutting CO2 and protecting public health and the 

environment.9

The EPA regulations propose implementation through a state-federal partnership under which states identify plans to meet 

the emission reduction goals. The EPA provides guidelines for states to develop implementation plans to meet state-specific 

CO2 reduction goals and provides states the flexibility to design requirements suited to their unique situations. These plans 

may include generation mix changes using diverse fuels, energy efficiency, and demand-side management, and they allow 

states to work individually or to develop multi-state plans. The primary driver for realizing the EPA’s 111(d) objectives is that 

SIPs need to produce significant CO2 reductions starting as early as 2020.

As currently proposed, states have a flexible timeline for submitting plans to the EPA. Within one year of finalizing the rule—

expected in June 2015—state environmental agencies must submit implementation plans to the EPA for approval. Submitted 

state-specific plans, due in June 2016, must outline requirements and enforceable limitations for affected generating units to 

meet the rule’s average CO2 emission rate goal for each state within two compliance periods: (1) an initial 10-year average 

interim emission rate limit for the period 2020–2029, and (2) a final annual emission rate limit starting in 2030.

The EPA provides states with an option to convert CO2 emission rate limitation into an annual mass-based limitation. It is 

likely that most states will pursue this option due to the challenges state permitting agencies have in developing unit-specific 

emission rate limitations. The simpler mass-based CO2 emission cap program also negates the need for state legislative action 

to authorize agencies to limit plant output and enact an enforceable program for compliance with average emission rates.

The EPA’s proposed Clean Power Plan timeline is outlined in Figure 2.

 

5 State implementation of Option 1 assumes 134 GW of retirements (includes CC, Coal, CT, Nuclear, O/G, and IGCC) by 2020. For additional 

information, see: Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for 

Modified and Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data. Regional implementation of Option 2 

assumes 108 GW of retirements (includes CC, Coal, CT, Nuclear, O/G, and IGCC) by 2020.

6 All sources starting construction after January 8, 2014, would be subject to new source performance standards and exempt from the EPA Clean 

Power Plan requirements.

7 79 FR 34854 https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-stationarysources-electric-utility-generating page 34854.

8 EPA CPP TSD – 2012 Unit-Level Data Using EGrid – Methodology, June 2014. Generation, Emissions, Capacity data used in EPA’s State Goal 

Computation TSD.

9 EPA Fact Sheet: Clean Power Plan – Why we Need A Cleaner, More Efficient Power Sector “The proposed Clean Power Plan will cut hundreds of 

millions of tons of carbon pollution and hundreds of thousands of tons of harmful particle pollution, sulfur dioxide and nitrogen oxides. Together 

these reductions will provide important health protections to the most vulnerable, such as children and older Americans.” 

http://www2.epa.gov/sites/production/files/2014-05/documents/20140602fs-benefits.pdf.
Summary of the Proposed Clean Power Plan

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Figure 2. EPA Proposed Clean Power Plan Timeline

The EPA would have one year to review and approve implementation plans for each state by June 2017. Under this schedule, 

impacted generating units would have two and a half years to develop respective compliance strategies and potentially 

permit, finance, and build needed replacement capacity and transmission. In its current form, this implementation schedule 

would be a challenge for states to implement and for affected sources to comply with, especially given the expected legal 

challenges to both the EPA and state rules. In recognition of these challenges, the EPA would provide states with a one-year 

extension to June 2017 to submit a SIP if justification is provided, and a two-year extension (June 2018) for states that elect 

to develop multi-state (regional) programs (e.g., Regional Greenhouse Gas Initiative (RGGI)). While the EPA extensions apply 

to state plan submissions, the January 1, 2020, program start date for affected sources would not be extended under the 

proposed CPP. Therefore, the impacted fossil-fired units may be left with as little as six months to develop and implement 

compliance plans. Considering the number and variety of 

outcomes for each of the proposed scenarios, the states 

and industry should initiate planning immediately upon 

finalization of the CPP.

The proposed Clean Power Plan, which is based on EPA 

analysis of historical data about emissions and the power 

sector, isintended to create a consistent national formula 

for reductions that reflects their Building Block 

assumptions. The formula applies the four Building Blocks 

to each state’s specific information, yielding a carbon 

intensity rate for each state.10 There is a wide range of 

potential proposals, including individual state and multi-state groupings, each with different implementation schedules. The 

range of potential submitted SIPs and changes to the proposed timeline create significant uncertainties for industry and 

resource planners.

Clean Power Plan Building Blocks

According to the proposed plan, this can be achieved through the development of state-specific emission rates to limit CO2

by applying four different BSER Building Blocks.

11 Each Building Block represents a different approach for achieving the 

proposed targets. According to the EPA, the proposed plan considers impacts to system reliability and electricity prices. The 

BSER is not intended to impact resource planning and does not dictate retirements, additions, or operating practices for 

individual units. Instead, it would provide state emission rate limits that would shape the future resource mix through state 

and market processes in subsequent years as SIPs and multi-state plans are developed and implemented.

 

10 EPA Fact Sheet: Clean Power Plan - National Framework for States.

11 EPA Clean Air Act: Section 111(d) authorizes EPA to apply “best system of emission reduction” to this section’s affected sources.

EPA’s Proposed Clean Power Plan: Options 

The EPA is proposing a Best System of Emission Reduction (BSER) 

goal, referred to as Option 1, and is taking comment on a second 

approach, referred to as Option 2.

Option 1: Involves higher deployment of emission reduction but 

allows a longer time frame (2030).

Option 2: Has a lower deployment of emission reductions over a 

shorter time frame (2025) by each state. Proposed guidelines allow 

states to collaborate and demonstrate emission performance on a 

multi-state basis, in recognition that electricity is transmitted across 

state lines.
Summary of the Proposed Clean Power Plan

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The EPA’s Proposed Clean Power Plan: Four Building Blocks

Make fossil fuel power plants more efficient by implementing a 6 percent (on average) unit heat rate 

improvement for all affected coal-fired units. The EPA suggests that some plants could further improve 

process efficiency by 4 percent through the adoption of best operational practices, and an additional 2 

percent through capital upgrade investments. 

Use low-emitting power sources more by redispatching existing natural gas combined-cycle (NGCC) units 

before the coal and older oil-gas steam units. EPA draft rate limitations include CO2 reduction assumptions 

from the ongoing increases in the use of NGCC capacity (with up to a 70 percent capacity factor). This 

additional NGCC capacity (440 TWh/year) displaces coal (376 TWh/year) and oil-gas steam generation (64 

TWh/year) by 2020, compared to 2012 levels.

Use more zero- and low-emitting power sources through building capacity by adding both non-hydro 

renewable generation and five planned nuclear units. EPA calculations assume qualifying non-hydro 

renewable generation can grow rapidly from 218 TWh/year in 2012, to 281 TWh/year by 2020, to reach 

523 TWh/year by 2030.

Use electricity more efficiently by significantly expanding state-driven energy efficiency programs to 

improve annual electricity savings by up to 1.5 percent of retail sales per year. The calculation assumes 

the states and industry can rapidly expand energy efficiency programs to increase savings from 22 

TWh/year in 2012, to 108 TWh/year in 2020, and to 380 TWh/year by 2029. Ultimately, EPA energy 

efficiency assumptions suggest that electric power savings will outpace electricity demand growth, 

resulting in negative electricity usage from 2020 through 2030.
Clean Power Plan – Assumption Review

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Clean Power Plan – Assumption Review

This section provides a critical review of the EPA’s assumptions for state-specific CO2 emission rates and presents possible 

reliability challenges that need to be considered.

Building Block 1 – Coal Unit Heat Rate Improvement

The EPA’s heat rate assessment analyzed gross data for 884 coal-fired electric generating units (EGUs) during a

10-year period.

12 The regression analysis examined the effects of the capacity factor and the ambient 

temperature on the gross heat rate efficiencies of coal-fired EGUs. The EPA’s assessment concluded that instate coal units can achieve up to a 4 percent rate of improvement through the use of best operational practices. An additional 

2 percent of efficiency improvements would be achieved through capital upgrade investments.

Review of EPA Assumptions and Potential Reliability Impacts

The EPA calculated unit-specific heat rates using gross generation data from the Continuous Emission Monitoring Systems

(CEMSs). With this approach, the EPA excluded generation-reducing effects from post-combustion environmental controls,

such as selective catalytic reduction and flue-gas desulfurization controls. The EPA then used net generation data, without 

consideration for these retrofits, for coal-fired EGUs when calculating the state CO2 emission rate goals. These retrofits will 

reduce the net output of these units, as well as their associated net heat rate efficiency. Not considering these reductions 

creates an inconsistent approach, especially considering that most coal-fired EGUs will require control retrofits to comply 

with environmental regulations, such as the Mercury Air Toxic Standards (MATS) and Section 316(b) of the Clean Water Act.

The EPA’s regression analysis does not adjust for the following factors that have profound effects on the process efficiency 

of a coal-fired EGU:13 (1) subcritical versus supercritical boiler designs; (2) fluidized bed combustion, integrated gasification 

combined-cycle (IGCC), and pulverized coal; (3) unit size and age; and (4) coal quality variations in moisture and ash (i.e.,

every 5 percent change in coal moisture results in a 1 percent change in boiler heat rate efficiency).

Impacts on Coal-Fired Unit Efficiency Rates

Lower-capacity factors will cause an increase in heat rates, particularly if the lower-capacity factors are due to the cycling of 

the coal units. As a result of Building Block 2, coal units will cycle more often; therefore, assumed heat rate improvements 

across the entire coal fleet are unlikely. While recognizing capacity effects in the regression analysis, the EPA did not evaluate 

the effects of lower-capacity factors resulting from the dispatching of natural gas generation before coal generation.

Periodic Turbine Overhauls

Turbine overhauls are referenced as a major heat rate improvement method in an EPA Clean Power Plan technical support 

document.

14 Regular turbine overhauls are generally not practical or economical, because these procedures require the unit 

to be out of service for an extended period of time. As well, the power industry already has multiple incentives to operate 

units at peak efficiency (i.e., profit maximization and competitive advantage).

Overall, improving the existing U.S. coal fleet’s average heat rate by 6 percent may be difficult to achieve. Possible options 

and considerations for attaining a portion of this target may include the following:

 Site-specific engineering analyses are required to determine if there are remaining opportunities for heat rate 

improvement measures through implementation of operational best practices or capital investments.

 If the U.S. coal fleet does not achieve target heat rates, more CO2 reductions would be required from other CPP 

Building Block measures. 

 This can result in some coal-fired power plants retiring earlier than anticipated, which creates additional uncertainty 

in future generation resources.

 

12 GHG Abatement Measures (EPA June 2014) (EPA-HQ-OAR-2013-0602) pg. 2-18.

13 These differences are illustrated in Figure 2-2 of GHG Abatement Measures (EPA June 2014). 

14 Coal-Fired Power Plant Heat Rate Reductions (January 2009).
Clean Power Plan – Assumption Review

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Building Block 2 – Gas Unit Re-Dispatching

The EPA assumes that reductions in CO2 emissions from existing power plants can be achieved by dispatching

existing NGCC units ahead of coal units. In particular, the EPA assumes existing NGCC units can achieve a 70 

percent utilization rate with avoided incremental costs of less than $33/metric ton CO2.

15 In its state-specific 

goal computation, the EPA calculated that 440 TWh/year of additional NGCC generation could potentially displace 376 

TWh/year of coal and 64 TWh/year of oil-gas steam units of 2012 generation.16

Review of EPA Assumptions and Potential Reliability Impacts

Upon reviewing the EPA’s Building Block 2 assumptions, NERC found a number of reliability concerns regarding increased 

reliance on natural-gas-fired generation that should be evaluated. 

Historically, the primary function of the NGCC unit is to follow the load of energy throughout the day (i.e., the intermediate, 

or midrange, part of the load duration curve). While some NGCC units are capable of operating at a high capacity factor, the 

vast majority of this type of generation is used for load following. Due to lower gas prices, NGCC units are currently being 

dispatched as a baseload resource, displacing baseload coal-fired EGUs. Unlike baseload coal-fired generation, NGCC units 

are better suited to follow load. As mentioned earlier, cycling coal-fired EGUs reduces heat rate efficiencies, causing their CO2

emission rates (lbs/MWh) to deteriorate, and further offsetting the Building Block 1 assumptions.

Generally, the power industry relies upon diversification of fuel sources as a mechanism to offset unforeseen events (e.g.,

abnormal weather, regional transfers, labor strikes, unplanned outages); ensure reliability; and minimize cost impacts. Fuel 

diversification is also a component of an “all-hazards” approach to system planning, which inherently provides resilience to 

the BPS. The EPA estimates that an additional 49 GW of nameplate coal capacity will retire by 2020 due to the impacts of the 

proposed CPP.17 When including the 54 GW of nameplate coal capacity already announced to retire by 202018 (mostly due to 

MATS), the power industry will need to replace a total of 103 GW of retired coal resources by 2020, largely anticipated to be 

natural-gas-fired NGCC and CTs. Considering the current and ongoing shift in the resource mix, the EPA proposes to further 

accelerate the shift, lessening the industry’s diversification of fuel sources.

As observed during the 2014 polar vortex,

19 the relationship between gas-fired generation availability and low temperatures 

challenges the industry’s ability to manage extreme weather conditions—particularly when conditions affect a wide area and 

less support is available from the interconnection. The polar vortex served as an example of how extended periods of cold 

temperatures had direct impacts on fuel availability, especially for natural-gas-fired capacity. Higher-than-expected forced 

outages were observed during the polar vortex, particularly for natural-gas-fired generators, as a result of fuel delivery issues

and low temperatures. Overall, extreme weather conditions have the potential to strain BPS reliability and expose risks 

related to natural-gas-fired generation availability (Figure 3). With greater reliance on natural-gas-fired generation, the 

resiliency and fuel diversification that is currently built into the system may be degraded, which NERC has highlighted in 

recent gas-electric interdependency assessments.

 

15 GHG Abatement Measures (EPA June 2014) (EPA-HQ-OAR-2013-0602) pg. 3-26.

16 Clean Power Plan Proposed Rule: Goal Computation – Technical Support Document http://www2.epa.gov/carbon-pollution-standards/cleanpower-plan-proposed-rule-goal-computation.

17Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and 

Reconstructed Power Plants (EPA June 2014 pg. 3-32).

18 Energy Ventures Analysis maintains a complete list of announced power plant retirements in the contiguous United States, retirements as of 

10/02/2014.

19 NERC 2014 Polar Vortex Review: 

http://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014_Final.pdf
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Figure 3. Causes for Generator Outages Observed during the 2014 Polar Vortex 

Pipeline Capacity Constraints

During its assessment of Building Block 2, the EPA concludes that the power industry in aggregate can support higher gas 

consumption without the need for any major investments in pipeline infrastructure. However, there are a few critical areas 

that likely will need additional capital investments. As an example, current and planned pipeline infrastructures in Arizona 

and Nevada are inadequate for handling increased natural gas demand due to the CPP. Pipeline capacity in New England is 

currently constrained, and more pipeline capacity additions will be needed as more baseload coal units retire—this is 

generally occurring as projected and independent of the CPP. Timing of these investments is also critical as it take three to 

five years to plan, permit, sign contract capacity, finance, and build additional pipeline capacity, in addition to placing

replacement capacity (e.g., NGCC/CT units) in service. The proposed CPP timelines would provide little time to add required 

pipeline or related resource capacity by 2020.

Due to abundant availability of natural gas, the power industry is generally able to accommodate increased demand from 

NGCC plants that operate as baseload capacity. This higher dependence on natural gas can expose additional reliability risks, 

including pipeline transportation constraints that could result as more gas-fired generation is built. Overall, the increase in 

natural gas use and capacity expansion increases gas-electric interdependency issues and raises the following concerns:

 NGCC units could displace coal-fired generating units as baseload units, forcing less-efficient coal units out of service, 

further increasing demand for natural gas. 

 Adequate timing is required to add new pipeline and generation resource capacity where it is needed to offset coal 

plant retirements and supply natural gas to new generation. 

 As gas-electric dependency significantly increases, unforeseen events like the 2014 polar vortex could disrupt natural 

gas supply and delivery for the power sector in high-congestion regions, increasing the risk for potential blackouts. 

Fuel Supply and Delivery

• Natural gas interruptions

• supply injection 

• compressor outages

• one pipeline explosion

• Oil delivery problems

• Inability to procure gas

• Fuel oil gelling 

Extended Low Temperatures

• Low temperature limits for wind turbines

• Icing on hydro units

• Failed auxiliary equipment

• Stress of extended run times

• Frozen instrumentation (drum level sensors, 

control valves, and flow and pressure sensors)
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Building Block 3 – Clean Energy 

Building Block 3 describes the EPA’s method to reduce CO2 emissions by investing in zero-CO2-emitting energy 

sources (i.e., nuclear and non-hydro renewable generation).

Review of EPA Assumptions and Potential Reliability Impacts

Building Block 3 includes the assumption about the preservation of nuclear generating units that are currently at risk of being 

retired within the next two decades due to (1) age, (2) an increase in fixed operation and maintenance costs, (3) relatively 

low wholesale electricity prices, and (4) additional capital investment associated with ensuring plant security and emergency 

preparedness. The EPA assumesthat 5.7 percent of each state’s nuclear generating capacity is at risk of retirement. However, 

the EPA included this generation as well as the five new nuclear units currently under construction (Watts Bar Unit 2 (TN), 

Summer Units 2-3 (SC), and Vogtle Units 3-4 (GA)) in its state-by-state CO2 emission rate goal calculations.20 The nuclear 

retirement assumptions add pressure to states that will need to retire nuclear units. For these states, more CO2 reductions 

from other measures than originally estimated by the EPA may be required.

Under its draft CPP, the EPA also proposes significant expansion of non-hydro renewable generation as part of its BSER 

determination. The EPA adopted a methodology to estimate non-hydro renewable generation by state and year and applied 

these estimates in their calculation of individual state emission rate limitations. The greater the EPA’s assumed non-hydro 

renewable generation in a given state, the lower the state’s calculated CO2 emission rate limit.

The EPA assumes that qualifying non-hydro renewable generation will grow from 213 TWh/year in 2012, to 281 TWh/year by 

2020, reaching 523 TWh/year by 2030. These projections exceed the Energy Information Administration (EIA) non-hydro 

renewable generation forecast in their Annual Energy Outlook 2013 (AEO 2013) that grows from 202 TWh/year in 2012, to 

275 TWh/year by 2020, to reach 317 TWh/year by 2030 for all sectors.21 The EPA-assumed rapid growth in non-hydro 

renewable generation exceeds its own forecast in the EPA’s Regulatory Impacts Assessment (356 TWh/year by 2030).

22

To calculate the state target levels of renewable energy performance, the EPA examined mandatory state Renewable 

Portfolio Standard (RPS) requirements from the Database for State Incentives for Renewables and Efficiency (DSIRE).23 RPS 

requirements vary widely by state; many states include resource-specific percentage requirements (i.e., set-asides) that 

promote development of certain resources in addition to their general requirements. The database distinguishes the complex 

web of state policies by applying them to a standardized tier system which, according to DSIRE, helps “to compare RPS policies 

on equal footing.”24 To determine the state effective levels in 2020, the EPA added each state’s tiers together and excluded 

secondary and tertiary tiers that include energy efficiency or qualified fossil fuels (waste coal, carbon capture sequestration, 

etc.). The only RPS “type” considered was the primary type, referring to requirements for investor-owned utilities (IOUs).

Significant regional differences exist in the availability of renewable resources and their power production costs across the 

United States. In order to quantify these regional differences, the EPA divided the lower 48 states into six regions, based on 

designations by NERC Regions and ISO/RTOs. After the regions were assigned, the EPA averaged the 2020 effective levels for 

states that have mandatory RPS percentage standards. By applying the average regional renewable energy (RE) percentages 

to each region’s aggregate 2012 generation, the EPA derived a new RE target generation level for 2030. The EPA notes that 

Alaska and Hawaii were assigned RE generation target percentages equal to the lowest value of the six regions, equivalent to 

the Southeast’s target. The EPA assumes that RE generation will begin increasing in 2017 and continue through 2029.

Moreover, they assume no growth occurs in between 2012 and 2016. The EPA derived the annual growth factor by 

determining “the amount of additional renewable generation (in megawatt-hours) that would be required beyond each 

 

20 GHG Abatement Measures (EPA June 2014) (EPA-HQ-OAR-2013-0602) pg. 4-33.

21 Annual Energy Outlook 2013 (EIA April 2013) reference case data.

22 Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and 

Reconstructed Power Plants (EPA June 2014) Table 3-11 pg. 3-27.

23 http://www.dsireusa.org/.

24 DSIRE. DSIRE RPS Field Definitions. April 2011. http://www.dsireusa.org/rpsdata/RPSFieldDefinitionsApril2011.pdf p.1.
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region’s historic (2012) generation to reach that region’s RE target”25 by 2030. This constant growth rate is then applied to 

each state to obtain annual state RE target levels.

The EPA’s reliance on state RPS standards to compute the regional performance targets poses a variety of issues. States’ 

main-tier RPS qualifications vary significantly and, in addition to in-state non-hydro renewable generation, also often include: 

hydroelectric generation, municipal solid waste (MSW), combined heat and power (CHP), clean coal, carbon capture and 

sequestration, and energy efficiency measures. As an example, New York has an RPS percentage of 30 percent.

26 According 

to the New York Renewable Portfolio Standard Cost Study Report produced by the New York State Department of Public 

Service, hydroelectricity contributes 18.25 percent of total generation and is included under baseline renewables.27 New 

York’s RPS percentages, therefore, include the state’s hydroelectric generation as qualifying renewable resources, which is 

different from what the EPA assumed in its methodology. 

In addition to hydroelectric power, energy efficiency plays an important role in various states’ RPSs. North Carolina’s RPS 

includes a provision that allows up to 25 percent of its target to be met by energy efficiency gains. This provision, if it were 

properly excluded by the EPA, would reduce North Carolina’s RPS target to 7.5 percent from 10 percent, thereby lowering 

targets for the entire Southeast region, Alaska, and Hawaii. When establishing 2012 non-hydro renewable generation 

performance levels, the EPA excluded all hydroelectric generation and energy efficiency programs used in the state CO2 

emission rate calculations. The adjusted state RPS targets, as well as 2012 non-hydro RE performance levels, are used to 

determine the regional RE targets and regional annual growth rates.

NERC notes several other concerns with the CPP’s assumption for Building Block 3, such as:

 Multipliers given to select resources’ options (e.g., in-state, wind, solar, etc.). Six states (CO, DE, MI, NV, OR, and

WA) give extra credit (up to 3.5 renewable energy credits per 1 MWh of energy produced) for using these 

resources.28 Excluding the multiplier suggests a target that is ultimately higher than what may actually be attainable.

 The use of qualifying out-of-state renewable generation resources in effective RPS target calculations. Most RPS 

programs allow out-of-state qualifying renewable resources toward RPS compliance. For example, several Indiana 

wind projects account for nearly 50 percent of the Ohio RPS requirement. This issue is important since states realize 

that much of the lower-cost renewable resources may come from outside the state in locations more suitable for 

VERs. The underlying assumption—that the state RPS reflects in-state renewable capability that can be matched by 

the other states in their census region—appears incorrect and could only be dealt with via a regional state approach 

similar to a regional greenhouse gas initiative. In order to properly account for regional renewable resource 

potential, the EPA should consider including only in-state renewable resource portions of the state RPSs.

 The EPA method of assigning renewable regions is questionable. Of the six renewable regions created in the lower 

48 states, targets for two regions (South Central and Southeast) were set based upon a single-state RPS. For example, 

the South Central state region (AR, KS, LA, NE, OK and TX) was set based upon only the Kansas RPS. Kansas accounts 

for only 6 percent of this region’s retail power sales and has the third-best wind resources in the country. Given the 

combination of a low population, large land area, and very high wind resource availability, Kansas has relatively low 

costs to meet its RPS. However, Louisiana (ranked #48 in wind resources and double the retail sales) is assigned the 

same non-hydro renewable target. To put these two states in the same region sets unattainable targets for Louisiana.

 The EPA’s determination of state goals for renewable generation does not fully reflect the economic aspects of 

renewable resources. Resource limitations exist due to permitting, market saturation, transmission access, and 

project financing issues. Many prime wind locations have difficulty obtaining the necessary permits and are often 

objected to at the local level. Many high-grade wind sites are also located in remote areas. Energy generated from 

 

25 GHG Abatement Measures (EPA June 2014) (EPA-HQ-OAR-2013-0602) pg. 4-18.

26 http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=NY03R&re=0&ee=0.

27 http://www.dps.ny.gov/rps/Appendix-B-2-19-04.pdf.

28 DSIRE http://www.dsireusa.org/.
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these locations requires large capital investments to build transmission infrastructure to interconnect to the BPS. 

Location matters, and sites with high capacity factors are limited.

 The expiration of the production tax credits (PTCs) and potential reduction of the investment tax credits (ITCs) for 

RE resources in the coming years will impact investment decisions and the economics of new resources. As a result, 

the marginal cost of new RE generation increases, which could impact the long-term development of RE resources. 

There is also the implicit need to increase ancillary services as a result of the increased variable resource output.

Moreover, there are higher production costs associated with more non-hydro renewable generation due to a 

combination of increased capital costs and low-capacity operating factors. Overall, significant cost uncertainties will 

directly impact the electric industry’s plan to quickly adapt to the CPP requirements. 

Finally, grid reliability issues associated with increased variable resources are not directly addressed in the EPA’s proposed 

Building Blocks. Conventional generation (e.g., steam and hydro), with large rotating mass, has inherent operating 

characteristics, or ERSs,

29 needed to reliably operate the BPS. These services include providing frequency and voltage support, 

operating reserves, ramping capability, and disturbance performance. Conventional generators are able to respond 

automatically to frequency changes and historically have provided most of the power system’s essential support services. As 

variable resources increase, system planners must ensure the future generation and transmission system can maintain 

essential services that are needed for reliability.

A large penetration of VERs will also require maintaining a sufficient amount of reactive support and ramping capability. More 

frequent ramping needed to provide this capability could increase cycling on conventional generation. This could contribute 

to increased maintenance hours or higher forced outage rates, potentially increasing operating reserve requirements. While 

storage technologies may help support ramping needs, successful large-scale storage solutions have not yet been 

commercialized. Nevertheless, storage technologies support the reliability challenges that may be experienced when there 

is a large penetration of VERs, and their development should be expedited. 

Based on industry studies and prior NERC assessments,30 as the penetration of variable generation increases, maintaining 

system reliability can become more challenging. Additional assessments, including interconnection-wide studies, will be 

needed as the resource plans unfold to better understand the impacts.

If the states fall short of meeting the renewable energy targets established by the EPA, more CO2 reductions from other 

measures may be required than were estimated by the EPA. These measures include more coal unit retirements, expanded

natural gas-fired generation plants, or energy efficiency deployment.

The CPP proposes reductions in CO2 emissions by investing in zero-CO2-emitting energy sources (i.e., nuclear and non-hydro 

renewable generation). However, increased reliance on VERs creates reliability challenges that take considerable time to 

implement and require substantial changes in BPS planning and operations. Most notably, the challenges with this Building 

Block are:

 The CPP analysis relies on resource projections that may overestimate reasonably achievable expansion levels and 

exceed NERC and industry plans and do not fully reflect the reliability consequences of renewable resources.

 Increased reliance on VERs can significantly impact reliability operations and requires more transmission and 

adequate ERSs to maintain reliability.

 With a greater reliance on VERs, transmission and related infrastructure expansion lead times may not align with 

the CPP implementation timeline.

 

29 See NERC’s Essential Reliability Services Task Force website for more information: 

 http://www.nerc.com/comm/Other/Pages/Essential-Reliability-Services-Task-Force-(ERSTF).aspx.

30 NERC-CAISO Joint Report: Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources – CAISO Approach; other 

industry reports include those developed by the Integration of Variable Generation Task Force (IVGTF); Integrating Variable Renewable Energy in 

Electric Power Markets: Best Practices from International Experience (Appendix D).
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Building Block 4 – Energy Efficiency

Electricity savings from enhanced energy efficiency measures are assumed as a major reduction in U.S. power 

generation requirements and thereby lower U.S. power industry CO2 emissions. In calculating individual state 

CO2 emission rate limits, the EPA assumes that existing state energy efficiency programs can be significantly 

expanded to achieve 108 TWh in cumulative savings in 2020, continue to grow to 283 TWh by 2025, and reach 380 TWh by 

2030.31 The EPA’s estimated future energy efficiency program performance will have significant effects on state compliance 

measures and costs. 

Review of EPA Assumptions and Potential Reliability Impacts

In its Regulatory Impact Assessment, the EPA assumes that energy efficiency will grow faster than electricity demand, with 

total electricity demand shrinking beyond 2020. The implications of this assumption are complex. If such energy efficiency 

growth cannot be attained, more carbon reduction measures would be required, primarily from reduced coal generation in 

most states. More low-emitting or new NGCC/CT generating capacity (not regulated under the CPP) would need to be built. 

Construction of new replacement capacity, as well as related infrastructure, would take time to plan, permit, finance, and 

build. If these needs are not identified at an early enough stage, either grid reliability or state CO2 emission goals could be 

compromised.

The EPA relied on 12 state studies to set its expanded annual program target savings improvement rate at 1.5 percent per 

year. However, the EPA appears to overestimate most states’ energy efficiency savings potential versus prior energy efficiency 

projections, resulting in setting performance targets too high for individual states.

32 Savings potentials are highly state specific 

in their consumer mix, credit for measures already taken, and levels of subsidies provided. The EPA applies one national 

energy efficiency growth factor to all state situations and does not consider energy efficiency program performance or cost. 

The discrepancies are subsequently compounded by extrapolating these annual energy efficiency performance targets as 

incremental improvements that can be sustained through 2030—beyond the 12 studies evaluated.

Out of 12 studies, 11 contain multiple scenarios with different sets of assumptions to demonstrate wide ranges of what is 

achievable under alternative financial, technological, and behavioral environments. There is no documentation on how each 

study’s respective average annual improvement rate was calculated, which was used as the foundation to calculate the 

incremental performance improvement target of 1.5 percent per year. 

The assumed base year is of critical importance when comparing multiple studies’ achievable potential for energy efficiency.

When drawing comparisons between percentages, the baseline level of electricity demand must be the same; otherwise, the 

total amount of energy avoided due to energy efficiency measures would be different. Under the CPP, all energy efficiency 

savings are applied to Business As Usual (BAU) sales forecasts generated from EIA-861 data.33 Base years used in the 12 

studies range from as early as 2007 to as recently as 2013 and are not consistent throughout the sample.34 Comparing 

achievable energy efficiency potential percentages is therefore difficult, since BAU electricity demand levels are inconsistent 

between the studies.

Study length is another important assumption regarding the sustainability of achievable savings. It is uncertain whether the 

level of annual energy efficiency savings could be sustained after the expiration of the program, as the most cost-effective 

and impactful measures would have been utilized already—leaving only increasingly expensive incremental energy efficiency 

measures. The cited studies vary significantly in length: from as few as four years, to as many as 21 years. 

The CPP assumes that dividing cumulative potential by the study length provides an adequate estimation for an average 

annual achievable potential that is sustainable over a much longer (13-year) period (2017–2030). However, there is a 

discrepancy in the longitudinal application of cross-sectional studies.

 

31 EE savings estimates calculated using EPA’s methodology, EE savings %, BAU sales estimates. Source: GHG Abatement Measures (EPA June 

2014) (EPA-HQ-OAR-2013-0602) Chapter 5.

32 Electric Power Research Institute (EPRI) and EIA.

33 Annual Electric Power Industry Report (EIA 2012) (EIA 861 Data).

34 GHG Abatement Measures (EPA June 2014) (EPA-HQ-OAR-2013-0602) pg. 5-65.
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The CPP assumes an average life of 10 years for energy efficiency measures. This average does not fully capture the unique 

distribution of the length of measures when analyzing regionally available energy efficiency measures. Key assumptions when 

determining energy efficiency potential are “breadth of sectors and end uses considered, study period, discount rate, pattern 

of technology penetration, whether economically justified early replacement of technologies is allowed for, whether 

continued improvement in efficiency technology is provided for,”

35 yet the EPA applies a broad average rather than 

determining individual measure life curves. Most of the source studies perform bottom-up approaches and evaluate 

thousands of permutations of measures, building types, climate zones, market penetration factors, and measure lives to 

determine which energy efficiency technologies to include and exclude. By approximating thousands of measure lives using 

one average, the CPP does not capture measure life disparities and possibly underestimates the amount of energy efficiency

savings that expire throughout the compliance period. 

While the studies on energy efficiency consider different potentials for the three main sectors (residential, commercial, and 

industrial), the CPP uses one number across all sectors in its emission rate calculation. Industrial processes are designed to 

use as little energy as possible in order to maximize profits of daily operations and may have already invested in energy 

efficiency programs, leaving minimal and costly opportunities remaining for incremental improvement. Applying the same 

energy efficiency potential percentage for all three sectors indirectly provides incentives for industrial utility customers to 

reduce their energy load proportional to residential customers, but by a much greater magnitude per capita. 

The underlying state and regional studies used as the base for calculating the 1.5 percent potential include the full range of 

financial incentives from 25 to 100 percent, when considering base, low, and high cases. Since the EPA uses an averaging 

method in translating from the observed studies’ sector and scenario findings to the final average annual projected potential, 

it is difficult to evaluate the financial incentives that are assumed in both the Building Block calculations and study results.

The EPA used the EIA’s AEO 2013 baseline forecast to estimate its BAU electricity sales forecast. Growth rates calculated by

the National Energy Modeling System (NEMS) region were applied to state-level 2012 retail sales from the EIA-861 survey to 

arrive at an annual BAU sales forecast. These growth figures include the net effect of implicit forms of energy efficiency, as 

that information is not explicitly presented in AEO 2013 reference case. Because the EIA does not explicitly model energy 

efficiency as a forecast line item, the retail sales growth is skewed for the purposes of calculating the energy efficiency Building 

Block. 

The EIA presents some metrics to gauge energy efficiency in the AEO 2013 model results. Energy intensity, defined as energy 

use per dollar of GDP, represents the aggregate effects of energy consumption trends and a rising national output. Electricity 

energy intensity, in particular, has been on a steady decline in both consumption per dollar of GDP and consumption per 

capita. This is due in large part to energy efficiency, but its contribution is difficult to isolate. The EIA’s AEO 2013 energy load 

growth projections include implicit forms of energy efficiency measures, and the proposed CPP does not appear to account 

for these savings. This effectively double counts the savings of some energy efficiency measures and results in state-specific 

energy efficiency targets that are too high to be considered reasonably achievable. 

With potentially overstated expectations for energy efficiency savings, the EPA’s demand forecast results in a decline in 

electricity use between 2020 and 2030. While other major power market forecasters’ electricity sales compounded annual 

growth rates (CAGRs) for the period between 2020 and 2030 are strictly positive (AEO 2013: 0.7 percent, EPRI: (achievable 

potential) 0.4 percent, NERC average of assessment studies: 1.5 percent), the EPA assumes a CAGR of -0.2 percent for the 

same time period. Between 2020 and 2030, the EPA assumes incremental year-over-year reductions from energy efficiency 

to be almost 41 TWh nationally on average, outpacing year-over-year national electricity sales growth of 31.6 TWh, on 

average.

The main reason for this result is the EPA’s assumption of states being able to sustain an annual incremental growth rate in 

energy efficiency savings of 1.5 percent once achieved. As mentioned above, this sustainability is not supported by any peerreviewed or technical studies of energy efficiency potential.

 

35 GHG Abatement Measures (EPA June 2014) (EPA-HQ-OAR-2013-0602) pg. 5-22.
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By overestimating efficiency savings resulting in declining electricity retail sales, the results of the EPA’s entire Regulatory 

Impact Assessment are concerning from a reliability perspective and have implications to electric transmission and generation 

infrastructure. Underlying electricity demand forecasts directly influence the required level of generation—and hence, CO2

emissions—from existing and affected generating units under the CPP. They also affect the required new construction of 

generating units that are needed to meet expected electricity demand, which is projected to increase during the next 10

years.36

The EPA projection for energy efficiency growth at a 1.5 percent annual increase is substantially greater compared to what 

NERC examined in its current and prior long-term reliability assessments (LTRAs). NERC collects energy efficiency program

data that is embedded in the load forecast for each LTRA assessment area. Projected annual energy efficiency growth as a 

portion of Total Internal Demand since 2011 has ranged from only 0.12 to 0.15 percent, as shown in the table below.

Table 1. 2011–2014 LTRA Energy Efficiency Growth

LTRA 10-Year Growth of EE (%)

Portion of Total Internal Demand (%) Annual Growth in Relation

Year 1 Year 10 to Total Internal Demand (%)

2011 10.7 0.59 1.63 0.12

2012 12.2 0.72 1.88 0.13

2013 11.6 0.92 2.02 0.12

2014 13.4 0.87 2.25 0.15

In summary, the CPP assumes energy efficiency gains outpace electricity demand growth through the compliance period. 

However, this assumption does not reasonably reflect energy efficiency achievability and is a departure from normalized 

forecasts. If states are unable to achieve the EPA target savings, additional CO2 reduction measures beyond BSER measures 

would be needed to meet the proposed rate limits—primarily through further reductions in existing generation or expansion 

of natural gas and VERs. The energy efficiency assumptions underpin the CPP proposal and present the following reliability 

issues:

 The EPA appears to overestimate the amount of energy efficiency expected to reduce electricity demand over the 

compliance time frame. The results of overestimation have implications to electric transmission and generation 

infrastructure needs.

 Substantial increases in energy efficiency programs exceed recent trends and projections. Several sources, 

including but not limited to NERC, EIA, EPRI, and various utilities, have published reports, analysis, and forecasts 

for energy efficiency that do not align with the CPP’s assumed declining demand trend.

 The CPP assumption appears to underestimate costs and may underestimate the capital investments that would 

be required by utilities to sustain energy efficiency performance through 2030.

 The offsetting requirements in more coal retirements, along with expansions in natural gas and VERs, in a 

constrained time period could potentially result in reliability or ERS constraints.

 

36 NERC 2014 Long-Term Reliability Assessment.
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Reliability Impacts Potentially Resulting from the CPP 

To meet the proposed CPP emission reduction levels, the states are expected to select the mass-based limitation approach 

over the emission rate approach due to its greater flexibility, as well as ease to enforce and implement. The power industry 

has been successful in complying with prior mass-based emission cap and trade programs (e.g., Acid Rain program, Clean Air 

Interstate Rule, and RGGI) without creating reliability impacts. The CPP introduces potential reliability concerns that are more 

impactful than prior environmental compliance programs due to the extensive impact to fossil-fired generation. Additionally, 

there is potential for an accelerated decision-making period for the implementation of the CPP’s Building Blocks. It is also 

important to consider the ongoing transformation to the resource mix and corresponding impacts on ERSs required to 

maintain a reliable BPS. State-specific carbon intensity targets create potential reliability concerns in two major areas: (1) 

direct impacts to resource adequacy and electric infrastructure, and (2) impacts resulting from the changing resource mix

that occur as a result of replacing retiring generation, accommodating operating characteristics of new generation, 

integrating new technologies, and imposing greater uncertainty in demand forecasts. 

Figure 4. Summarized Reliability Challenges

Most importantly, generation (along with other system resources) and transmission must provide specific capabilities to 

ensure the BPS can operate securely under a myriad of potential operating conditions and contingencies, in compliance with 

a wide range of NERC planning and operating Reliability Standards. The above challenges warrant further consideration by 

policy makers. The following sections discuss these key reliability challenges in detail.

Direct Impacts to Resource Adequacy and Electric Infrastructure

Fossil-Fired Retirements Result in Accelerated Declines of Reserve Margins

In recent long-term assessments, NERC has highlighted resource adequacy concerns, particularly in ERCOT, NPCC-New York, 

and MISO, as projections continue to reflect declining reserve margins that fall below each area’s Reference Margin Level 

over the next five years, despite low demand growth rate (Figure 5). As most LTRA assessment areas attribute stagnant 

demand growth to the ongoing projected economic indicators (typically based on either employment levels or GDP) in the 

Impacts Resulting from the Changing Resource Mix

As a result of generation retirement, replacement resources must replenish reliability needs including capacity, energy, and ERSs. 

Accomodating resources with different operating characteristics requires enhancements to BPS planning and operations. Fuel 

availability and energy limitations must be considered in reliability planning. 

Increased reliance on naturalgas-fired generationOperating reserves and 

ramping capability Voltage and frequency support Emerging resources – DR and DERs

Direct Impacts to Resource Adequacy and Electric Infrastructure 

Planning Reserve Margins quantify what is needed to deliver and meet expected demand with a target reserve margin that considers

both planned and unplanned availability of resources and deviations from a normal demand forecast. Due to long lead times for

resources and infrastructure, long-term planning is required—transmission is also considered. 

Amount of installed and future 

planned generation

Adequate planning reserve 

margins – primary metric used 

for resource adequacy 

assessment

Conventional generation 

retirement Transmission planning
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residential, commercial, and industrial sectors, total capacity additions have paralleled the ongoing declines in load growth.

The trend of declining margins in a number of NERC assessment areas is rooted primarily from a general reduction in 10-year 

capacity additions observed over the past several years. Total capacity additions continue to fall behind the ongoing declines 

in load growth rates (Figure 6).

37

*Due to changes to the WECC subregional boundaries, resulting in four subregions instead of nine, the 2014 Anticipated Reserve Margins are not 

shown for WECC-BASN and WECC-ROCK for this comparison.

Figure 5. Short-Term (Year 2 Forecast) Anticipated Reserve Margins Show Declining Trends for Some Assessment Areas

Figure 6. NERC-Wide 10-Year Projected Capacity Additions Declining Since 2011

The EPA’s supporting documents estimate that up to 19 percent of the nation’s coal plants will become “uneconomical” as a 

result of the proposed CPP. Although the CPP may not become enforceable until 2020, its effect may overshadow and change 

large retrofit capital decisions needed to comply with earlier EPA regulations—primarily MATS. 

According to the EPA, the state implementation would result in a reduction in coal to 193 GW by 2025. The EPA finalized 

MATS, which is factored into 2014 LTRA and identifies capacity retirements through 2016. In its Technical Support Document

– Resource Adequacy and Reliability Analysis, the EPA used the Integrated Planning Model (IPM) to project likely future 

electricity market conditions with and without the proposed CPP. The IPM assumed that adequate transmission capacity 

exists to deliver any resources located in, or transferred to, the individual regions. Additionally, since most regions currently 

have capacity above their target reserve margins, the EPA assumed most of the retirements are absorbed by a reduction in 

excess reserves over time. However, uncertainty remains for a large amount of existing conventional generation that may be 

vulnerable to retirement resulting from additional pending EPA regulations. These retirements reduce reserve margins over 

the course of the CPP implementation.38

 

37 2011, 2012, and 2013LTRA data includes Future-Planned capacity additions http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx.

38 EPA Technical Support Document –Resource Adequacy and Reliability Analysis http://www2.epa.gov/sites/production/files/2014-

06/documents/20140602tsd-resource-adequacy-reliability.pdf.

0%

5%

10%

15%

20%

25%

30%

35%

40%

11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14

MISO MAPP NPCC-New

England

NPCC-New

York

NPCC-Ontario SERC-E SERC-N WECC-BASN* WECC-ROCK*

LTRA Year by Assessment Area

60 65 70 75 80 85 90 95 100 105 110 115 120 125 130 135 140 145 150 155

2014LTRA

2013LTRA

2012LTRA

2011LTRA

Gigawatts

On-Peak Nameplate
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19

The EPA’s analysis assumes the electric system will maintain resource adequacy, even with the ongoing retirements from 

existing regulations, including MATS. In addition, because the proposed CPP will require the development of significant 

amounts of new generation in a short period, additional time for infrastructure development will be needed to support these 

new resources. The EPA’s modeling of a potential implementation scenario predicts an additional 40–48 GW of fossil-fired

EGU retirements, and the addition of 21 GW of new NGCC resources.

With existing environmental regulations, the EPA’s base case projections indicate that total coal-fired capacity will decline 

rapidly from 309.6 GW in 2013 to just 245 GW by 2016, and 243 GW by 2025. The EPA’s base case—without implementation 

of the proposed CPP—assumes a significant reduction in coal-fired capacity by 2016: 27.2 GW beyond what is currently 

projected in the 2014LTRA reference case. According to the 2014LTRA reference case, an additional 44.2 GW of fossil-fired 

and nuclear capacity is projected to retire between 2014 and 2024.39 These projections are based on the assumption that 

current environmental regulations will remain and do not account for potential impacts from the proposed CPP (Figure 7).

Figure 7. Cumulative Fossil-Fuel and Nuclear Retirements between 2011 and 2024 Total 83 GW

According to the EPA, the state implementation of Option 1 would result in a reduction in coal to 193 GW by 2025. Option 1 

and the 2014LTRA reference case are shown in Figure 8 and Table 2.

40

Figure 8. 2014LTRA Reference Case & EPA Power Plan Assumptions: Coal-Fired Capacity

 

39 While the assessment period for the 2014LTRA is 2015–2024, projected retirements for 2014 are included in NERC’s 2014LTRA analysis.

40 Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and 

Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.

0

10

20

30

40

50

60

70

80

90

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Actual 2014 LTRA Reference Case

Gigawatts

Coal Natural Gas Nuclear Petroleum

190

200

210

220

230

240

250

260

270

280

290

300

310

320

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Gigawatts

2014LTRA Reference Case* EPA Base Case Option 1 (State Implementation)
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Table 2. 2014LTRA Reference Case & EPA Power Plan Assumptions

NERC 2014LTRA Reference Case - Total On-Peak Capacity (GW) 2016 2018 2020 2025*

Total Coal (Existing-Certain and Tier 1 Capacity Additions) 271.8 266.4 264.9 261.3

EPA Analysis of the Proposed Clean Power Plan - Total Coal Generating Capacity (GW) 2016 2018 2020 2025

Base Case 244.6 243.3 243.6 243.3

Option 1 (State Implementation) 219.7 210.4 195.1 193.1

EPA Assumed Coal Reduction Beyond NERC 2014LTRA Reference Case (GW) 2016 2018 2020 2025

Base Case 27.2 23.1 21.3 18.0

Option 1 (State Implementation) 52.1 56.0 69.8 68.2

Transmission Planning and Timing Constraints 

Long lead times for transmission development and construction require long-term system planning—typically a 10–15-year 

outlook. In addition to designing, engineering, and contracting transmission lines, siting, permitting, and various federal, 

state, provincial, and municipal approvals often take much longer than five years to complete. The CPP analysis assumes that 

adequate transmission capacity is available to deliver any resources located in, or transferred to, the region.41 Given the 

significant changes and locations anticipated to occur in the resource mix, it is likely that additional new transmission, or 

transmission enhancements, will be necessary in some areas. New transmission lines will be required to transport the amount 

of renewable generation coming online, particularly in 

remote areas, and that creates additional timing 

considerations. Further, as replacement generation is 

constructed, new transmission may be needed to 

interconnect new generation. Mitigating transmission 

constraints identified from the proposed EPA regulations in 

a timely way, consistent with CPP targets, presents a

potential reliability concern. Construction of new interstate 

high-voltage lines would require transmission owners to 

confer to state and federal laws with respect to 

environment impacts, siting, and permitting. A construction 

timeline for a new high-voltage line can range from 5 to 15 

years depending on the voltage class, location, and 

availability of highly skilled construction crews. The 

construction of transmission assetsis a very lengthy process 

starting from planning to the actual physical construction. It 

is recommended that any policies that could potentially 

impact the reliable operation of the transmission system 

also consider the associated timeline for implementing

plans.

The location of additional transmission resources will be informed by the outcome of the transmission planning studies. The 

transmission planning process will not be able to fully incorporate the impacts of potential retirements until those resource 

addition requirements are made known to the system operator. For ISO/RTOs, this will likely not happen until the final state 

plans are developed. 

To support variable generating capacity increases, the power industry would need to invest heavily to expand transmission 

capacity to access more remote areas with high-quality wind resources. Developing a resource mix that has sufficient ERSs to 

support integration and reliable BPS operation is also a consideration. Given the natural wind variability in these locations, 

incremental wind project resources would have relatively low capacity factors (20–35 percent) that would require complex 

financial decisions to support transmission capacity.

 

41 Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and 

Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.

Transmission Considerations with Additional VERs

The projected 30.8 GW of additional wind and solar resources 

will require additional transmission to reliably integrate these 

resources. VERs are often built in parts of North America that 

are distant from the point of interconnection to the 

transmission system. In many cases, the location of these 

variable resources only meets the minimum voltage support 

requirements. According to the 2014LTRA Reference Case, 16 

percent of new transmission projects (under construction, 

planned, or conceptual) identify variable resource integration as 

a primary driver.

New Transmission Project Drivers

Other 

Drivers

84%

Variable 

Integration

16%
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NERC anticipates that after the CPP guidelines are finalized in 2015, and SIPs are developed and approved by the EPA in 

2016/2017, entities will work with their state utility commissions or other appropriate governing entities to assess resource 

and system options. Extensive transmission reliability screening assessments will be performed to support these decisions 

and will include comprehensive local and regional reliability analyses, which must be coordinated with states and neighboring 

entities. As resource decisions are made, reliability screening will transition into the established NERC reliability assessment 

processes. Consistent with the NERC Reliability Standards, transmission enhancements to address reliability constraints will 

be identified, incorporated into transmission expansion plans, and coordinated with other projects locally and regionally.

Because committed transmission projects typically require three to five years to be completed, and often longer for major 

projects with significant right-of-way needs, NERC is concerned that reliability-related enhancements may not be able to be 

completed for a 2020 implementation.

Initial Regional Reliability Assessment of the Proposed CPP 

Some regions started an initial reliability assessment of the proposed CPP focused on their respective footprints to better 

understand the plan’s potential impacts. The initial analyses are slightly different in focus and are in varying stages of 

development. The key findings from recent MISO and SPP studies are provided below.

MISO

MISO focused primarily on generation capacity impacts. MISO, which is based on a 14.8 percent reserve margin requirement 

determined by the 1-day-in-10-year loss-of-load event, projects that in in 2016 it will operate at the reliability level of 

approximately 2-days-in-10-year loss-of-load event, increasing the likelihood that resources will not be sufficient to serve 

peak demand. The number of expected days per year of a loss-of-load event is projected to increase throughout the 

assessment period. The proposed CPP could further exacerbate resource adequacy concerns in the MISO footprint unless 

additional replacement capacity is built in a timely fashion.42 Additionally, the analysis showed that the EPA’s carbon proposal 

could put an additional 14,000 MW of coal capacity at risk of retirement. This amount is beyond the 12,600 MW within MISO’s 

footprint that is slated to retire by the end of 2016 to comply with MATS.

43 The contributing factors driving the projected 

deficit include:

 Increased retirements and suspensions (temporary mothballing) due to EPA regulations and market forces and low 

natural gas prices

 Exclusion of low-certainty resources that were identified in the resource adequacy survey

 Exclusion of surplus of capacity in MISO South above the 1,000 MW transfer from the Planning Reserve Margin 

requirement (PRMR)

44

 Increased exports to PJM and the removal of non-Firm imports45

 Inadequate Tier 1 capacity additions 46

 

42 Anticipated Reserve Margin includes operable capacity expected to be available to serve load during the peak hours with firm transmission. 

Prospective Reserve Margin operable capacity that could be available to serve load during the peak hour, but lacks Firm transmission and could 

be unavailable for a number of reasons.

43 MISO GHG Regulation Impact Analysis – Initial Study Results.

44 For this assessment, 1,000 MW of capacity is transferred from the MISO South to the MISO North/Central Region pending the outcome of 

regulatory issues currently under FERC review.

45 Capacity sales (imports and exports) in MISO depend on decisions of the respective resource owners, assuming that the tariff requirements are 

met (including planning of necessary transmission of both the buying and selling areas). Regarding the removal of non-Firm imports, the MISO 

market monitor double-counted non-Firm imports in the 2013LTRA reference case. These imports are accounted for in the Reference Margin Level 

(PRMR).

46 In the MISO footprint, 91 percent of the load is served by utilities with an obligation to serve customers reliably and at a reasonable cost. Resource 

planning and investment in resources are part of state and locally jurisdictional integrated resource plans that only become certain upon the receipt 

of a Certificate of Public Convenience and Necessity (CPCN).
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SPP

SPP looked at both generation capacity and transmission reliability impacts of the proposed CPP.

47 The initial study indicated 

that compliance with the carbon regulations, if implemented as modeled by the EPA, will not be possible without significant 

investment in new generation and associated major improvements to both the electric transmission and natural gas 

infrastructure to accommodate new generation. The results indicate that by 2020, SPP’s anticipated reserve margin would 

be 5 percent, representing a capacity margin deficit of approximately 4,500 MW. By 2024, 10,000 MW beyond current plans 

would be needed to maintain their reserve margin. Given the 8- to 10-year timeline needed to plan for and construct these 

additional resources, SPP has concluded that there is not sufficient time to achieve compliance with the EPA’s interim goals, 

and that widespread reliability impacts are likely.

The reliability issues identified in the initial studies will require significant upgrades to the transmission infrastructure to 

maintain system reliability, accommodate new generation or, when new generation is not warranted, to support the dispatch 

of the system in a manner significantly different from historical operations. Other ISO/RTOs, states, and Regions should 

prepare for the potential impacts to grid reliability, especially related to the time required to plan and build transmission 

infrastructure.

Reliability Assurance

NERC Reliability Standards and Regional Entity criteria must be met at all times to ensure reliable operation and planning of 

the BPS. Therefore, NERC supports policies developed by the EPA, FERC, the DOE, and state utility regulators that include a

“reliability assurance mechanism,” such as a reliability back-stop, to preserve BPS reliability and manage emerging and 

impending risks to the BPS.

Many utilities and ISO/RTOs have discussed a possible reliability safety valve similar to the one-year compliance extension 

that has been used to avoid retirement-related reliability impacts from the MATS compliance deadline. A reliability safety 

valve will be of limited utility if the EPA’s proposal is implemented as currently designed, and it appears the EPA has far more 

flexibility under Section 111(d) than was available under the Section 112 program. Accordingly, a set of reliability assurance 

provisions that may include a reliability backstop, as well as other measures, would be recommended to maintain BPS

reliability.

Stakeholders expressed to NERC staff their concerns regarding the need for additional time to mitigate the impacts of the 

carbon regulation. The proposed timeline does not provide enough time to develop sufficient resources to ensure continued 

reliable operation of the electric grid by 2020. To attempt to do so would increase the use of controlled load shedding and 

potential for wide-scale, uncontrolled outages. Additionally, policy changes may be required to ensure the Planning 

Coordinators and Transmission Planners perform the necessary studies and exercise the authority to implement transmission 

and related infrastructure solutions and assure that ERSs are provided in a timely manner.

 

47 SPP Reliability Assessment of EPA 111(d) Clean Power Plan Rule http://www.spp.org/publications/SPC%20Materials%20081914.pdf.
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Direct Impacts to Resource Adequacy and Electric Infrastructure

Summary and Recommendations

Fossil-Fired Retirements and Accelerated Declines in Reserve Margins: Despite low demand growth, NERC has 

highlighted resource adequacy concerns as projections continue to reflect declining reserve margins that fall below the 

Reference Margin Level in three assessment areas within the next five years. 

 The Regions, ISO/RTOs, and states should perform further analysis to examine the potential resource adequacy 

concerns.

Transmission Planning and Timing Constraints: The proposed CPP implementation is currently scheduled to begin in 

mid-2016. Some reliability impacts could be mitigated by the construction of new (or enhancement of existing) 

transmission facilities; however, long lead times (e.g., 10 years) are required for transmission planning and construction. 

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

enhancements and additions necessary to address impacts of the proposed CPP.

Regional Reliability Assessment of the Proposed CPP: To better understand its potential impacts, some Regions have 

started an initial reliability assessment of the proposed CPP focused on their respective footprints. The initial analyses 

are slightly different in focus and are in varying stages of development.

 Other ISO/RTOs, states, and Regions should prepare for the potential impacts to grid reliability, especially 

related to the time required to plan and build transmission infrastructure.

Reliability Assurance: NERC Reliability Standards and Regional Entity criteria must be met at all times to ensure reliable 

operation and planning of the BPS.

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

regulatory authority to develop reliability assurance mechanisms such as a reliability back-stop. These 

mechanisms include timing adjustments and granting extensions where there is a demonstrated reliability need. 
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Impacts Resulting from the Changing Resource Mix

Coal Retirements Increase Reliance on Natural Gas for Electric Power

The electricity sector’s growing reliance on natural gas raises concerns regarding the electricity infrastructure’s ability to 

maintain system reliability when facing a constrained natural gas capacity for delivering natural gas to electric power 

generators. These concerns are already being articulated in light of gas-electric dependency studies and analyses, and include 

ISO/RTOs, electricity market participants, industrial consumers, national and regional regulatory bodies, and other 

government officials.48 The extent of these concerns varies from region to region; however, concerns are most acute in areas 

where power generators rely on interruptible pipeline transportation as the natural gas use for generation rapidly grows. 

Under the CPP, an accelerated shift in the power generation mix from coal to natural gas is expected to ensue. The EPA’s 

state limitation calculations assume a 440 TWh/year shift to existing NGCC generation from coal (376 TWh/year) and older 

oil-gas steam (64 TWh/year) generators due to redispatched NGCC units up to a 70 percent capacity factor. In its Regulatory 

Impact Assessment, the EPA projects that the natural gas market portion of total U.S. power generation will grow from 29 

percent energy in 2013 to 33–34 percent from 2020 to 2030. In an analysis of the CPP prepared by Energy Ventures Analysis 

(EVA), natural gas generation is found to increase by an additional 400–450 TWh/year and increase the gas generation energy 

market share to reach 35 percent in 2020, 39 percent in 2030, and 49 percent in 2040.49

As reliance increases more on natural gas for both baseload and on-peak capacity, it is important to also examine potential 

risks associated with reduced diversity and increased dependence on a single fuel type. Currently, natural-gas-fired resources 

account for large portions of both the total and on-peak resource mix in several assessment areas when considering both 

existing capacity and planned additions (Table 3).

Table 3. Assessment Areas with Natural-Gas-Fired Capacity Accounting for Over One-Third of Existing Nameplate Capacity50

Nameplate Capacity (GW) On-Peak Capacity (GW) 10-Year Nameplate Capacity Additions (GW)

Assessment Area Gas-Fired Portion of Total Gas-Fired Portion of Total Tier 1 Tier 2 Tier 3

FRCC 40.2 64% 33.9 63% 10.1 0.0 0.0 

MISO 69.0 39% 58.7 41% 2.8 0.0 10.0 

NPCC-New England 18.6 54% 13.3 43% 1.1 3.3 0.0 

NPCC-New York 21.0 55% 14.2 40% 0.0 3.5 0.0 

PJM 80.0 43% 56.5 32% 10.0 47.5 0.0 

SERC-SE 31.2 47% 28.4 46% 0.0 0.0 2.6 

SPP 32.3 40% 30.2 47% 1.1 0.7 5.7 

TRE-ERCOT 48.4 54% 45.2 63% 4.9 21.5 0.0 

WECC-CA/MX 47.7 61% 43.9 70% 5.5 6.2 0.9 

WECC-RMRG 7.2 36% 6.2 41% 1.2 0.0 0.0 

WECC-SRSG 19.5 47% 16.3 50% 0.6 1.0 3.0 

With this shift toward more natural gas consumption in the power sector, the power industry will become increasingly 

vulnerable to natural gas supply and transportation risks. Extreme conditions, although rare, must be studied and integrated 

in planning to ensure a suitable generating fleet is available to support BPS reliability. While there are several plants with 

dual-fuel capability, the capability to switch to a secondary fuel can be limited during certain operating conditions.

Overdependence on a single fuel type increases the risk of common-mode or area-wide conditions and disruptions, especially 

during extreme weather events. Disruptions in natural gas transportation to power generators have prompted the gas and 

electric industries to seek an understanding of the reliability implications associated with increasing gas-fired generation. For 

example, adverse winter weather, such as that experienced during January 2014, provided signs of natural gas supply and 

deliverability risks.51 This can be a local issue in areas where there is already a heavy concentration of natural gas generation.

 

48 See NERC’s Special Reliability Assessments on electric and gas interdependencies for more information and recommendations: Phase I and

Phase II.

49 Energy Ventures Analysis: FUELCAST – The Long-Term Outlook 2014, October 2014. 

50 Tier 1, 2, and 3 Capacity Category Definitions are provided in the 2014 Long-Term Reliability Assessment.

51 NERC Polar Vortex Review Report 

http://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014_Final.pdf
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While several gas pipeline construction projects are underway to increase gas deliverability, the CPP proposal accelerates the 

shift toward more natural gas generation and could create additional pipeline needs. The increased demand can be addressed 

with sufficient lead time (i.e., more than three years), which is needed to plan, collect contracts, permit, procure, and build 

new pipeline. To the extent that the CPP assumptions regarding natural-gas-fired capacity expansion and existing coal-fired 

generation retirements are achieved, the gas and electric sectors will lean more heavily on each other.

The Availability of Essential Reliability Services Is Strained by a Changing Resource Mix

The proposed CPP provides states and developers additional incentives to rapidly expand their non-hydro renewable capacity 

to displace existing coal generation. The state calculations assume that non-hydro renewable capacity could grow rapidly by 

5 percent per year, from 218 TWh/year in 2012 to reach 523 TWh/year by 2030. This incremental renewable generation 

represents well over twice the energy currently supplied by VERs and would be dominated mostly by new wind, and to a 

lesser extent, new solar capacity. 

In addition, wind projects will significantly increase the demand for reactive power and ramping flexibility. Ramping flexibility 

will increase cycling on conventional generation and often results in either increased maintenance hours or higher forced 

outage rates—in both cases, increased reserve requirements may result. While storage technologies may help support 

ramping needs, successful large-scale storage solutions have not yet been commercialized.52 Storage technologies support 

the reliability challenges that may be experienced when there is a large penetration of VERs, and their development should 

be expedited.

Based on industry studies and prior NERC assessments,53 as the penetration of variable generation increases, maintaining 

voltage stability can be more challenging. Additional studies will be needed to further understand potential challenges that 

may indirectly result from the proposed CPP. In its role of assessing reliability, NERC commissioned the Essential Reliability 

Services Task Force (ERSTF) with members from NERC’s Planning Committee and Operating Committee to study, identify, and 

analyze the planning and operational changes that may impact BPS reliability. NERC, under the ERSTF work plan and activities, 

has issued an initial assessment of ERSs that identifies ERS reliability building blocks as a foundational approach for further 

assessment and studies.54

Increased Penetration of Distributed Energy Resources

The EPA projects that retail electricity prices will increase by $1/MWh to $18/MWh under the CPP55 as a result of a 

combination of higher natural gas prices and the implementation of new carbon penalties on impacted fossil-fired 

generators.56 As retail power prices increase, some existing customers may install DERs, when economically advantageous. 

Depending on the price advantage, the market penetration of DERs could be substantial, creating potential reliability impacts 

for grid operators that lack visibility and control of these resources. Given that DERs displace grid retail sales, DERs could 

become a larger grid capacity planning challenge since the grid will remain responsible for being the DER site’s back-up power 

supplier. Reliability issues with large onsets of non-dispatchable resources have already created operational challenges in 

California, Hawaii, and Germany. Such experienced reliability challenges are:

 The loss of inertia and the loss of generating units used to control transient instability driven by the significant noncontrollable generation and lack of sufficient attention to ERSs—Hawaii.

 

52 Pumped storage offers fast and large ramping capabilities to the BPS; however, increases in this technology is not likely due to land restrictions, 

permitting limitations, and environmental opposition. Less than 1 GW of pumped storage capacity is projected over the next 10 years.

53 NERC-CAISO Joint Report: Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources – CAISO Approach; other 

industry reports include those developed by the Integration of Variable Generation Task Force (IVGTF); Integrating Variable Renewable Energy in 

Electric Power Markets: Best Practices from International Experience (Appendix D)

54 NERC Essential Reliability Services Task Force - A Concept Paper on Essential Reliability Services that Characterize Bulk Power System Reliability

http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF_Draft_Concept_Paper_Sep_2014_Final.pdf

55 Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and 

Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.

56 According to EIA, closing coal plants will drive up natural gas prices by 150 percent over 2012 levels by 2040, this cost rise will cause electricity 

prices to jump seven percent by 2025 and 22 percent by 2040. Because natural gas prices are a key determinant of wholesale electricity prices, 

which in turn are a significant component of retail electricity prices. Accordingly, the cases with the highest delivered natural gas prices also show 

the highest retail electricity prices. 2014 Annual Energy Outlook.
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 DERs only operate within frequency ranges that are in many cases close to nominal frequency and, therefore,

frequency and voltage ride-through capabilities are needed—Germany.

 Increased wind and solar levels that mandate increased ramping, load-following, and regulation capability—this 

applies to both expected and unexpected net load changes. This flexibility will need to be accounted for in system 

planning studies to ensure system reliability—California.

Studies and Assessments Needed to Support Reliability

The following assessments are needed to form a complete reliability evaluation. Table 4 provides a list of the types of studies 

and analysis that must be done to demonstrate reliability, recognizing that the industry does not operate the grid without a 

thorough and complete analysis.

Table 4. Study and Assessment Types Needed for a Complete Reliability Evaluation

Local Reliability Assessments Area/Regional Reliability Assessments

 Specific generator retirement studies

 Specific generator interconnection studies

 Specific generator operating parameters

 Power flow (thermal, voltage)

 Stability and voltage security

 Offsite power for nuclear facilities

 Resource adequacy

 Power flow (regional)

 Stability and voltage security (regional)

 Gas interdependencies; pipeline constraints

 Operating reserves and ramping

 System restoration/blackstart

Impacts Resulting from the Changing Resource Mix

Summary and Recommendations

Coal Retirements and the Increased Reliance on Natural Gas for Electric Power: As the industry relies more on naturalgas-fired capacity to meet electricity needs, close examination will be necessary to ensure risks have been fully identified 

and evaluated. Potential issues are most acute in areas where power generators rely on interruptible natural gas 

pipeline transportation.

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

and integrated partnership. Coordinated planning processes should include considerations for pipeline 

expansion to meet the increased reliance on natural gas for electric generation—especially during the extreme 

weather events (e.g., polar vortex).

The Changing Resource Mix and Maintaining Essential Reliability Services: The proposed CPP provides states and 

developers additional incentives to rapidly expand their non-hydro renewable capacity to displace existing coal 

generation. Resource adequacy assessments do not fully capture the ERSs needed to reliably operate the BPS and are 

generally limited to identifying supply and delivery risks.

 ISO/RTOs, utilities, and Regions, with NERC oversight, should analyze the impacts to ERSs in order to maintain 

reliability. Additionally, system operators and ISO/RTOs need to develop appropriate processes, tools, and 

operating practices to adequately address operational changes on the system.

 NERC should perform grid-level performance expectations developed from a technology-neutral perspective to 

ensure ERS targets are met.

 The development of technologies (such as electricity storage) help support the reliability objectives of the BPS,

and these technologies should be expedited to support variability and uncertainty on the BPS.

Increased Penetration of Distributed Energy Resources: A potential risk in additional DERs is the temporary 

displacement of utility-provided service, which could create additional planning challenges, considering utilities must 

act as a secondary supplier of electricity.

 ISO/RTOs and system planners and operators should consider the market penetration of DERs and potential 

reliability impacts due to the limited visibility and controllability of these resources.
NERC | Potential Reliability Impacts of EPA’s Proposed Clean Power Plan | November 2014

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Conclusions

Thisreport represents NERC’s initial review of reliability concerns regarding the EPA’s proposed Clean Power Plan (CPP) under 

Section 111(d) of the Clean Air Act. As the CPP is finalized and implemented, NERC will develop special reliability assessments 

in phases. This initial evaluation highlights the underlying CPP assumptions and identifies a range of potential reliability

impacts of the CPP on the BPS. 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.

The Building Block assumptions in the EPA’s proposed CPP are critical to NERC’s evaluation of the reliability impacts. NERC 

will provide independent assessments of the BPS under a wide range of conditions that reflect the implications of the 

proposed policy, varied resource mixes, and impacts to transmission and will share the results with the industry and states 

as they develop their implementation plans.

Recommendations 

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

evaluations to stakeholders and policy makers. 

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 Board meeting. The NERC Planning Committee should lead NERC and industry efforts in 

conducting the reliability assessments and scenario analyses as identified in this report. NERC will work through its 

stakeholder process to solicit industry input on assessment approaches and assumptions as further special 

assessments and evaluations are developed.

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.

Given the potential reliability concerns of the EPA’s 2020 proposed implementation date, 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 SIPs 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. 

3. If the environmental goals are to be achieved, policy makers and the EPA should consider a more timely approach 

that addresses BPS reliability concerns and infrastructure deployments.

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 initial review, more time would be needed in certain areas to ensure resource 

adequacy, reliability requirements, and infrastructure needs are maintained. The EPA, FERC, the DOE, and state 

utility regulators should consider their regulatory authority to make timing adjustments and to grant extensions to 

preserve BPS reliability. 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 reliability 

assurance mechanism is included in the rule’s implementation.