Guiding Principles for Reliability 

Assessments Under EPA’s Clean Power Plan

JUNE 2015
Guiding Principles for Reliability Assessments Under EPA’s Clean Power Plan

M. J. Bradley & Associates LLC

ACKNOWLEDGEMENTS

The following whitepaper was prepared by M.J. Bradley and Associates. The authors would like to 

acknowledge the following industry experts for their review and valuable insights: Mark Ahlstrom, 

Lauren Azar, David Hilt, Brian Parsons, and Eric Svenson. Though the authors are indebted to their 

contributions, this whitepaper reflects the views of the authors alone. 

REPORT AUTHORS

Paul J. Allen, M.J. Bradley & Associates LLC

Christopher E. Van Atten, M.J. Bradley & Associates LLC

Grace Vermeer, M.J. Bradley & Associates LLC

For questions or comments about this report, please contact:

M.J. Bradley & Associates LLC

47 Junction Square Drive

Concord, MA 01742

Telephone: 978 369 5533

E-mail: pallen@mjbradley.com
Guiding Principles for Reliability Assessments Under EPA’s Clean Power Plan

M. J. Bradley & Associates LLC ES-1 June 2015

Executive Summary

A robust discussion and healthy debate has emerged in recent months regarding the interplay of 

electric system reliability and the implementation of the U.S. Environmental Protection Agency’s 

(EPA’s) Clean Power Plan (CPP). The CPP will, for the first time, establish nationwide standards for 

emissions of carbon dioxide from existing power plants. During the course of the policy development, 

a common proposal has emerged through stakeholder dialogue: to institute a process to study the 

potential reliability impacts of state plans under the CPP before and as they are implemented. Many 

organizations have already begun to conduct such assessments. 

We believe that the electric grid is more than capable of supporting a transition to a lower carbon mix 

of generation. The United States electricity system is in the midst of transformative change. We have 

seen meaningful changes in competitive energy markets, increased investment in grid modernization 

and development, and advances in renewable and natural gas generation. These changes have been 

driven by technological advancements, changes in public policy, customer expectations, and practical 

necessity. Throughout this period, and indeed, since the institution of the Clean Air Act nearly a half 

century ago, environmental standards and controls have coexisted with electric reliability. As our grid 

undergoes update and change, our toolkit to maintain reliability continues to improve. Recent 

experience under the Mercury and Air Toxics Standards has shown how existing reliability practices, 

combined with proactive and commonsense policymaking, have maintained reliability through the start 

of a new regulation. The CPP, through its flexible design, can take advantage of existing and emerging 

practices to support reliability on the path toward a clean, more efficient, electric industry. 

To assist in this continuing transition, we must have a clear way to identify, plan for, and address 

reliability issues. Crucial to this will be reliability assessments conducted on a national and regional 

level that provide a consistent, productive, and comprehensive view of reliability. We, like the Federal 

Energy Regulatory Commission, do not call for new requirements or statutory changes to achieve this 

reliability review, and we agree that existing procedures are a strong foundation for assessments so 

long as they are conducted thoroughly. To that end, we encourage the industry and its stakeholders to 

utilize a standardized set of guiding principles for use in undertaking these important assessments. We 

recommend the following six guiding principles: 

1. Utilize a transparent process. Organized and focused stakeholder involvement will help 

incorporate up-to-date assumptions, create consistency across assessments, sanity check initial 

results, and ensure that reliability assessments are based in objective facts and data. 

2. Reflect existing status of the grid in modeling assumptions. In setting the assumptions for the 

analysis, both in a reference case and CPP compliance scenarios, a reliability assessment must 

incorporate key elements of the electric grid’s ongoing transformation that will drive 

assumptions on, for example, renewable development, ongoing generation and infrastructure 

improvement, and energy demand and energy efficiency.

3. Clearly identify base case and context. Actions to comply with the CPP will build upon 

existing electric sector trends and will take advantage of already in progress planning and 

infrastructure development to address reliability needs. Policymakers must understand the 

portion of activity that they can directly affect through their CPP compliance activities. 
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M. J. Bradley & Associates LLC ES-2 June 2015

Reports must clearly indicate if the conclusions are based on combining the impacts of the CPP 

with the ongoing changes reflected in the reference case, or if they are based on only the 

incremental impacts of the CPP.

4. Conduct sensitivity/probabilistic analyses where possible. Reliability studies should 

incorporate multiple sensitivities or a probabilistic analysis around key inputs of future 

conditions that are based on forecasts, including electricity demand, fuel prices, and 

development costs. Assessments should be careful to avoid only focusing on a low 

probability/high risk scenario. 

5. Reflect the flexibility of compliance options under the CPP. The proposed CPP provides 

significant flexibility that will allow states to adjust their compliance approaches to maximize 

reliability and minimize cost. Assessments should reflect this flexibility in model design 

through methods such as allowing a range of compliance options (e.g., natural gas dispatch, 

increased renewable development, or additional energy efficiency) as outputs of models, 

indicating trading within (or outside of) the modeled region, and examining options for phasedin compliance.

6. Provide realistic but reliability-focused results. The focus of these assessments should be on 

identifying reliability concerns that result from realistic projections of compliance options. 

While cost projections provide crucial bounding of assumptions and scenarios, “reliability” 

should not be equated with “cost effectiveness.” The added value of reliability assessments is 

to identify key electric system risks, vulnerabilities, and opportunities that arise from various 

compliance options. 

Following these principles will help create reliability assessments that provide practical, realistic 

results that recognize and address both EPA’s imperative to reduce greenhouse gas emissions and 

the shared interest in maintaining and enhancing affordable, reliable electricity. 
Guiding Principles for Reliability Assessments Under EPA’s Clean Power Plan

M. J. Bradley & Associates LLC

Contents

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

Reliability Dynamics of Today’s Electric Grid....................................................................................................... 3

Maintaining Reliability Under Environmental Regulations.................................................................................... 6

The Existing Reliability Toolkit.......................................................................................................................... 6

Reliability Under MATS: New and Existing Tools............................................................................................ 8

Reliability Under the CPP: Building on Flexibility ............................................................................................ 9

Reliability Assessment Guiding Principles........................................................................................................... 11

Guiding Principle: Utilize a Transparent Process............................................................................................. 13

Guiding Principle: Reflect Existing Status of the Grid in Modeling Assumptions........................................... 13

Guiding Principle: Clearly Identify Base Case and Context............................................................................. 15

Guiding Principle: Conduct Sensitivity/Probabilistic Analyses Where Possible.............................................. 16

Guiding Principle: Reflect the Flexibility of Compliance Options Under the CPP.......................................... 17

Guiding Principle: Provide Realistic But Reliability-Focused Results............................................................. 19

Conclusions........................................................................................................................................................... 20
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Introduction

A robust discussion and healthy debate has emerged in recent months regarding the interplay of 

electric system reliability and the implementation of the U.S. Environmental Protection Agency’s 

(EPA’s) Clean Power Plan (CPP). The CPP will, for the first time, establish nationwide standards for 

emissions of carbon dioxide (CO2) from existing power plants. EPA released a proposed CPP rule on 

June 2, 2014, setting state-by-state CO2 performance goals; states can meet these targets through a 

broad range of activities including increasing efficiency of existing generating facilities, switching 

from coal to natural gas, advancing the development of renewables, nuclear, and energy efficiency, and 

trading emissions “credits” with other states.

In addition to the EPA rulemaking process, the Federal Energy Regulatory Commission (FERC or the 

Commission) held a multi-day series of “technical conferences” in early 2015 to hear from industry 

and market experts on the subject of maintaining reliability through implementation of the CPP. 

Though EPA has stated unequivocally that the CPP will not diminish electric system reliability, and 

that EPA would not tolerate implementation of its rule in a manner that would harm reliability,1 some 

parties to FERC’s technical conferences expressed skepticism that this was possible—at least as the 

rule is currently drafted. Many parties hope that EPA will make changes, some of them significant, to 

incorporate a more deliberate consideration of reliability in the final rule to be issued later this year. 

However, many parties believe that the CPP can be implemented while maintaining a reliable electric 

system. In April, after the last of the FERC technical conferences, a trio of industry experts issued a 

whitepaper explaining their reasons for confidence in the electricity system planners and operators to 

adapt to a carbon-constrained future while providing a reliable supply of electricity.2 This sentiment 

has been echoed by others throughout the stakeholder dialogue on the CPP, both at the FERC technical 

conferences and other forums.

3

During the course of this dialogue, however, a common proposal has emerged: to institute a process to 

study the potential reliability impacts of state plans under the CPP before and as they are 

implemented. For example, the industry experts referenced above recommend that FERC help scope 

and guide assumptions for up-front and ongoing reliability assessments that will inform the design and 

eventual implementation of states’ individual or joint plans. Many organizations have already begun 

 

1

 See, e.g. Prepared Statement of Janet McCabe, Acting Assistant Administrator of the Office of Air and Radiation, 

EPA, February 19 2015, FERC Docket No AD15-4. Available at http://www2.epa.gov/sites/production/files/2015-

02/documents/20150219-ferc.pdf. 

2

 Tierney, S., Parsons, B., and Svenson, E., “Ensuring Electric Grid Reliability Under the Clean Power Plan: Addressing 

Key Themes from the FERC Technical Conferences,” April 2015 (“Tierney, Parsons, Svenson 2015”). Available at: 

http://www.westerngrid.net/2015/04/20/additional-comments-on-the-clean-power-plan/.

3

 See, e.g., Prepared Statements from the FERC Technical Conferences of Seattle City & Light, Exelon Corporation, 

Brian Parsons and John Jimison, John Moore, and Susan Tierney, as well as comments submitted in EPA Docket 

OAR-2013-0602 of numerous parties including Calpine Corporation. 
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to conduct such assessments. The North American Electric Reliability Corporation (NERC), an 

international organization with regulatory authority over bulk electric system reliability under the 

oversight of FERC, has issued both an “Interim” and “Phase I” assessment of issues it considers to be 

possible reliability challenges stemming from its analysis of how the CPP might impact the electric 

system. NERC’s Interim assessment preceded the FERC technical conferences and contained 

pessimistic warnings of potentially serious or even catastrophic impacts to reliability; it was also 

subject to a detailed rebuttal prepared by the Brattle Group, a leading energy industry consulting firm 

commissioned by Advanced Energy Economy to analyze NERC’s work.

In order to ensure a consistent, productive, and comprehensive view of reliability, we would encourage 

the electric industry and its stakeholders to develop a standardized set of guiding principles for use in 

undertaking these important assessments. This will not only ensure a more thorough and useful 

assessment of potential reliability issues, it will allow for more coordinated responses to issues that 

may cross state and reliability area boundaries. 

The following whitepaper provides a brief background on electric reliability through the lens of past 

environmental programs and then uses this context, as well as a review of already-conducted CPPfocused reliability assessments, to identify possible common elements and guiding principles for use in 

ongoing and future studies. Like FERC, we are not calling for new requirements or statutory changes; 

rather, we believe that existing procedures provide a strong foundation for such assessments, so long as 

they are conducted thoroughly. FERC has indicated in a recent letter to EPA that, concerning “a 

process to review state plans for potential reliability concerns,” it believes that existing reliability 

modeling and planning processes, conducted by regional transmission organizations (RTOs), 

independent system operators (ISOs), and other planning authorities, are “generally adequate,” 

although “increased effort” may be required as state plans are developed.4 FERC suggested, and we 

agree, that the Commission should use its stated authority to “review the analyses [and] suggest or 

request additional or modified analyses.”

5 We believe these reviews could be guided by the principles 

described below. We strongly support the adoption of a common set of guiding principles and a 

critical view of all existing and ongoing reliability assessments to be sure they comport with these 

principles.

 

4

 FERC Letter to Janet McCabe, acting Assistant Administrator of the Office of Air and Radiation at EPA, dated May 15

2015 (“FERC Letter to Janet McCabe”) at p. 3. Available at http://www.ferc.gov/media/headlines/2015/ferc-letterepa.pdf.

5

 Id. at p. 4. 
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Reliability Dynamics of Today’s Electric Grid

The electric system in the United States is built on a familiar model, one that has been replicated 

around the world. Large electricity generators, typically powered by coal, nuclear fuel, or natural gas, 

produce electricity that is delivered over a massive system of transmission and distribution lines. By 

any measure it is an impressive system: over 7,000 operational power plants, with a combined capacity 

of 1,060 GW, serve nearly 150 million separate residential, commercial, and industrial customers over 

642,000 miles of transmission lines and 6.3 million miles of distribution lines. In 2013, 303 GW of 

this generation was fired by coal, 99 GW by nuclear facilities, while another 425 GW was fired by 

natural gas, which in turn is supported by 2.6 million miles of natural gas pipeline. In 2013, this 

system successfully delivered over 4 million GWh of electricity to homes and businesses.6,7

However, the United States electricity system is in the midst of transformative change, driven by 

technological advancements, changes in public policy, customer expectations, and practical necessity. 

Some of the key changes include:

 Change in generation source and capability: though a majority of national electricity needs are 

still served by fossil fuel-fired generators (with significant regional distinctions—for example, 

in the Pacific Northwest, the primary generation source is hydroelectric facilities), the past 

decade has witnessed an unprecedented shift in resource type. Technology advancements have 

dramatically increased domestic natural gas production, reducing prices from over $9/MMBtu 

at their 2008 peak to $4.33 in 2013. This price decrease, coupled with significant 

advancements in combined cycle unit efficiencies and other factors, has led to a 73 percent 

increase in natural gas-fired energy between 2003 and 2013.8 At the same time, the industry 

has seen an upsurge in renewable generation driven by significant decreases in technology 

costs as well as increases in state policies supporting renewables. In 2013, renewables 

(including large hydroelectric facilities) served nearly 10 percent of total electricity demand in 

the U.S., nearly double the output in 2001. Between 2008 and 2013 alone, non-hydro 

renewable generation more than doubled. Combined, these factors have driven a shift away 

from coal-fired generation, which decreased from over 50 percent of total generation in 2003 to 

39 percent in 2013. The increase in renewables has also led to changing grid management 

practices to incorporate their variable output, which has been aided by significant advances in 

the fast-ramping capabilities of natural gas fired turbines.

 

6

 U.S. Energy Information Administration, “Electric Power Annual,” March 23 2015 (“2015 Electric Power Annual”).

Available at: http://www.eia.gov/electricity/annual/. 

7

 Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure,” April 2015 at 

Chapter 1. Available at: http://energy.gov/sites/prod/files/2015/04/f22/QER-ALL%20FINAL_0.pdf. 

8

 See 2015 Electric Power Annual. 
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 Expansion of markets: for the past 

century, most electricity was delivered 

by vertically-integrated utilities that 

owned and operated power plants and 

transmission/distribution systems to 

bring electricity to customers. This 

model began to change in response to 

the energy crises of the 1970s, starting 

with the enactment of the Public 

Utility Regulatory Policies Act 

(PURPA), which aimed to encourage 

domestic energy investment and 

opened the door to independent (nonutility) power producers while 

promoting energy conservation and 

new technologies such as cogeneration. The move toward “deregulation” accelerated in earnest at the federal level with 

passage of the 1992 Energy Policy Act, followed shortly thereafter by FERC Order 888 and its 

pro forma Open Access Transmission Tariff, which opened the wholesale market to 

competition among generators through access to the bulk power system on a nondiscriminatory basis across utility regions. Concurrently, many states opened their electricity 

generation models to restructuring and unbundling of generation assets. In the last 30 years, 

restructured markets have emerged in which numerous parties own generation that then 

contract with utilities or sell into organized markets. These markets cover roughly half of the 

country by area and around two thirds of total electric demand (see Figure 1). Though there 

have been growing pains and the operations of markets vary significantly by jurisdiction, 

overall, markets have been proven to stimulate technological innovation and increase the 

flexibility of the system while maintaining reliable and cost-effective service.

 Grid development, replacement, and modernization: as electricity demand and sources change, 

so too must the system of wires and pipes that serve it. The time is ripe: 70 percent of the 

grid’s transmission lines and transformers are over 25 years old,9 and many systems still 

operate using equipment not significantly updated since the 1950s. Due partially to an 

investment lag beginning in the 1990s, the electric industry predicts that it will invest between 

 

9

 Executive Office of the President, “Economic Benefits Of Increasing Electric Grid Resilience To Weather Outages,” 

August 2013 at p. 7 (“Economic Benefits Of Increasing Electric Grid Resilience To Weather Outages”). Available at 

http://energy.gov/sites/prod/files/2013/08/f2/Grid%20Resiliency%20Report_FINAL.pdf

Figure 1. North American Regional Transmission Organizations 

and Independent System Operators

Source: FERC
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$1.5 and $2.0 trillion in total infrastructure development between 2010 and 2030.10 Beyond 

replacing outdated systems, however, this development will also focus on adapting to the 

increased use of renewables and demand-side resources. Twenty-five states have already 

adopted policies relating to smart grid technology, 11 which aim to improve communication and 

responsiveness of the grid and improve grid resiliency.

12

 One large related outcome from a 

more interactive grid has been significant improvements in the methods of measuring and 

trimming the use of energy on the customer side of the meter, leading to much greater energy 

efficiency savings. This last development may explain, in part, why demand growth has 

remained below historical norms even as the U.S. economy has recovered since the recessiondriven lows of 2008 and 2009.

 Adapting and responding to environmental issues: energy production remains a significant 

source of environmental impact—on air quality, land management, and water use. As we 

better understand these impacts, regulation to address these issues have increased, leading to 

changes in the generation mix. Though the CPP is the first nationwide climate change policy 

aimed at addressing greenhouse gas emissions from existing power plants, it follows a long line 

of air regulations covering sulfur dioxide (SO2), nitrogen oxides (NOx), fine particulates, 

mercury, and numerous other pollutants—all of which have changed the way electricity is 

produced and delivered. Additionally, as industry has recognized, climate change itself is 

changing the conditions in which the electric sector operates, due to increased incidence of 

severe weather events, higher average temperatures, and other factors that require investments 

in infrastructure to strengthen electricity generation and distribution systems. 

Hundreds of federal, state, and regional organizations, corporations, and governmental agencies work 

together to ensure that this energy delivery system operates reliably, safely, cleanly, and costeffectively. Chief among these on the federal level are EPA and FERC; the former regulates the 

environmental impacts of energy production and transmission, and the latter is tasked with assisting in 

guaranteeing “reliable, efficient and sustainable energy services at a reasonable cost” through 

regulating competitive energy markets and the interstate transport of electricity and natural gas.13 

Reporting to FERC, NERC assists in maintaining national bulk power system reliability by developing 

and enforcing reliability standards, assessing seasonal and long‐term reliability, and helping train local 

operators to monitor the bulk power system through system awareness. On a regional level, reliability 

coordinators, RTOs, and ISOs help monitor, design, and track local systems, including any electricity 

 

10

 See Chupka et al., prepared on behalf of The Edison Foundation, “Transforming America’s Power Industry: The 

Investment Challenge 2010-2030” at p. 2. Available at 

http://www.eei.org/ourissues/finance/Documents/Transforming_Americas_Power_Industry_Exec_Summary.pdf. 

11

 See http://www.infrastructurereportcard.org/a/#p/energy/overview. 

12

 See Economic Benefits Of Increasing Electric Grid Resilience To Weather Outages. 

13

 See http://www.ferc.gov/about/about.asp. 
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services markets.14 Each of these parties plays a vital role in maintaining current operating reliability 

as well as planning for future threats and changes to the grid. These RTOs and ISOs, among others, 

establish electric system wholesale markets under FERC-approved rules and plan the bulk electric 

system based on FERC and NERC regulations.

Maintaining Reliability Under Environmental Regulations 

History has shown that the electric power industry is capable of reducing air and water pollution 

without threatening reliability. For example, the industry has reduced NOx and SO2 emissions by more 

than 70 percent without causing diminished service or power outages. The many levels of flexibility 

and multiple options for compliance contained in the proposed CPP suggest that this will continue to 

be the case, provided that sensible resource planning, with rigorous oversight from FERC, RTOs, state 

utility regulators, and other reliability organizations continues as it should.

The CPP reflects (and in many ways depends upon) the technological transformation already underway 

in the electric sector. Trends that have already started reducing emissions, such as increasing 

renewables and natural gas generation and greater investment in energy efficiency are jump starting 

efforts to comply with the rule. Additionally, expansions in infrastructure and markets are 

strengthening the ability of grid managers to incentivize, track, and respond to further emissions 

reductions while maintaining reliability. These tools, and others, have helped the industry maintain 

reliability under environmental regulations such as the Mercury and Air Toxics Standards (MATS) and 

will serve a similar function under the CPP.

The Existing Reliability Toolkit

Throughout the CPP rulemaking process, a broad range of stakeholders have catalogued the tools that 

are currently available to grid operators and reliability coordinators and planners.

15

 Covering both 

well-established and emerging technologies and practices that span both grid systems under markets as 

 

14

 There are also a number of non-FERC jurisdictional entities who manage reliability and bulk power system operations, 

including the Bonneville Power Administration, Western Area Power Administration, and the Electric Reliability 

Council of Texas. However, each of these entities must still comply with NERC reliability standards. 

15

 Useful resources providing more detail on this reliability toolkit include: Tierney et al., “Electric System Reliability 

and EPA’s Clean Power Plan: Tools and Practices,” February 19 2015, available at 

http://www.analysisgroup.com/uploadedFiles/Publishing/Articles/Electric_System_Reliability_and_EPAs_Clean_Pow

er_Plan.pdf; Prepared Statement of Brian Parsons, Director Western Grid Group, and John Jimison, Managing 

Director Energy Future Coalition, March 11 2015, FERC Docket No AD15-4, available at 

http://www.ferc.gov/CalendarFiles/20150224084400-Parsons,%20Jimison%20joint%20comments.pdf; Weiss et al., 

The Brattle Group, “EPA’s Clean Power Plan and Reliability: Assessing NERC’s Initial Reliability Review,” February 

2015, available at http://info.aee.net/brattle-reliability-report; and Tierney, Parsons, Svenson 2015. Practices referenced 

here are drawn from this collection. 
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well as those in vertically-integrated regions, these tools and trends should continue to ensure grid 

reliability under the CPP. They include:

 Engaging stakeholders, state regulators, and reliability entities through methods such as:16

o conducting forward-looking assessments of potential impacts on system reliability of 

CPP implementation;

o incorporating all potential short- and long-term measures (supply and demand; 

generation and transmission) to address significant changes during the CPP transition 

period; 

o engaging in coordination with neighboring utilities around local concerns tied to CPP 

implementation; and

o in areas with vertically-integrated utilities, developing or expanding long-term 

integrated resource planning processes for timely and practical incorporation of CPP 

compliance requirements.

 Where relevant, adding technology- and competitively neutral market rules/products and 

operating practices, to capture and add incentives for new reliability attributes, including:

o local (zonal/load pocket) capacity and energy market pricing; changes to reflect scarcity 

pricing;

o modifying forward capacity markets;

o valuing and providing for reliability attributes for system security (e.g., appropriate 

quantities of spinning and non-spinning reserves, regulation reserves, ramping/loadfollowing, reactive power, on-site fuel sufficiency, frequency response, black start 

capability);

o shortening dispatch intervals and updating processes to incorporate unit operations 

capabilities and limitations (including emission limits and ramping periods) and 

examining how similar operational restrictions (if any) from CPP compliance would be 

incorporated in system operations; and

o establishing or clarifying, where needed, provisions for the creation of reliability must 

run (RMR) contracts for generators need for reliability that would otherwise retire.

 Examining all options17 and improving assessment techniques to value resources that can 

provide reliability services:

 

16

 This may be especially useful in areas with vertically-integrated utilities, cooperatives, municipal power companies, 

and states without competitive markets (outside of RTOs) that will not be able to access the market-based tools 

referenced below.

17

 These include but are not limited to: demand control, distributed generation with smart grid features, inverter-based 

generation advanced capabilities, incenting future flexibility capabilities, synchronous condensers, FACTS devices, 

energy storage, and accessing existing system physical capabilities.
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o for resource adequacy determinations, use of Effective Load Carrying Capacity (ELCC) 

methods to incorporate site-specific resources and weather patterns and correlate that 

data with electric demand;

o for normal operations and load balancing, using production cost modeling with accurate 

representation of geographic diversity among renewables, with sub-hourly resolution to 

capture granular variability; and

o for disturbance response (including load flow, frequency response and dynamic stability 

study), capturing control settings of conventional plants to validate them against actual 

disturbance events; accurately representing gas and hydro units when evaluating the 

absence of large coal units, and capturing advanced grid features of inverter-based 

generation (as is being done by the WECC Renewable Energy Modeling Task Force).

Reliability Under MATS: New and Existing Tools

Concerns about electric system reliability have been raised in the past in response to new 

environmental policies. Although the policy is still unfolding, the system’s recent experience under 

MATS is one recent example of how common sense policy, combined with emerging technologies and

utilization of reliability management tools, has resulted in less air pollution while maintaining a 

reliable electricity grid.

MATS establishes air toxic emission standards for all existing and new coal- and oil-fired power plants 

(larger than 25 MW). Facilities were given three years from the final issuance of the rule to install 

pollution control technologies to bring facility emissions below the allowable levels. When the 

regulation was finalized in late 2011 (with an effective date of April 16, 2012), EPA included measures 

to address the possibility that specific individual coal-fired generating units might need additional time 

to either come into compliance with the rule or retire. Specifically, EPA made clear that states could 

provide, on a case-by-case basis, up to an additional 12 months for individual units to implement their 

compliance plans. Also, a process was put in place for plants to petition EPA for an Administrative 

Order (AO) to receive a fifth year extension if the facility could make a clear showing that this 

additional time was needed for reliability purposes. 

As part of this process, EPA and FERC established an oversight framework whereby EPA, in effect,

consults with FERC on these requests for fifth year reliability extensions. Under this framework, EPA 

maintains sole decision-making authority over whether to grant any reliability waiver or extension to a 

facility owner for any documented instance of a potential violation of a reliability standard—and EPA 

relies on the expertise of FERC, the RTOs or NERC when it makes these assessments and issues its 
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decisions.18 Per the interagency agreement between FERC and EPA, the Commission does not insist 

on any particular modeling, data sets, or information to be provided with the generator’s request for an 

extension, but FERC does suggest that information pertinent to potential violations of any FERCapproved Reliability Standards be included (such as regional or state transmission planning and 

operations studies, system restoration plans, operating procedures, and mitigation plans). FERC then 

provides public comments to EPA regarding whether the absence of an extension or waiver could 

jeopardize its Reliability Standards. FERC stops short of giving a specific recommendation to approve 

or disapprove the generator’s request, leaving this determination to EPA.19

This framework has strengthened the process for evaluating reliability needs without diminishing the 

environmental integrity of the MATS policy. Compliance officially began April 16, 2015, with 

approximately 40 percent of all covered coal-fired units requesting the fourth year extension (and 99

percent of those receiving it). However, out of approximately 1,100 affected coal-fired generators, we 

have identified to date only two generating facilities that have requested (and received) a fifth-year 

extension. When it has been necessary, generation planners and the market have responded in the vast 

majority of cases to replace the retiring power plants with other generation sources or transmission 

solutions. 

Reliability Under the CPP: Building on Flexibility

This coordinated approach between EPA and FERC on MATS may serve as a template for future 

efforts to ensure that the CPP is implemented in a manner that anticipates changes in the resource mix 

and helps the industry, the markets, and state and federal regulators respond accordingly. In its letter 

to EPA on May 15, 2015, FERC envisioned that if EPA adopted a measure to maintain facilities 

necessary for reliability that may otherwise be shut down due to the CPP, FERC’s role would be 

“[reviewing] a petitioner’s claims that unforeseen or emergency system conditions will result in 

violation of a Commission-approved Reliability Standard or reserve margin deficiency, unless a 

compliance obligation is adjusted.” FERC notes that similar to the MATS process, the Commission 

could help “identify issues...[and] review the petition’s proposed mitigation.” FERC expects that the 

information provided in such a request “could be similar to the information required of applicants 

seeking a fifth year [compliance extension] under MATS, with any modifications needed for the 

context of the Clean Power Plan.”20

 

18

 See “Policy Statement on the Commission’s Role Regarding the Environmental Protection Agency’s Mercury and Air 

Toxics Standards,” 139 FERC P 61,131 (2012). Available at http://www.ferc.gov/whats-new/comm-meet/2012/051712/E5.pdf.

19

 See Environmental Protection Agency, “The EPA’s Enforcement Response Policy For Use Of Clean Air Act Section 

113(a) Administrative Orders In Relation To Electric Reliability And The Mercury and Air Toxics Standard,” 

December 16 2011. Available at http://www.epa.gov/mats/pdfs/EnforcementResponsePolicyforCAA113.pdf. 

20

 See FERC Letter to Janet McCabe. 
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The CPP is, of course, a very different rule than MATS, and addresses a broader scope of resources 

and a more flexible set of compliance options. We believe that this flexibility dramatically reduces the 

likelihood of needing to rely on a safety valve-type mechanism for the CPP. Regardless of what EPA 

decides on this issue, we believe that reliability entities and relevant state regulators have a critical role 

in conducting effective reliability analyses that can inform the development of state plans to 

proactively avoid any potential reliability problems. 

One of the key flexibilities afforded by the CPP is its long lead time for compliance. In the case of 

MATS, EPA’s new rules were statutorily required to be met in a relatively short timeline of three or 

four years for full implementation and compliance. In contrast, in the case of the CPP—as it is now 

proposed—the timeline is much longer, starting with a window of two years (or three in the case of 

states that agree to enter into multi-state agreements) in which states will establish and gain approval 

for their compliance plan, followed by the onset of plan implementation, which then phases in across 

an interim period from 2020 through 2029 before the final targets go into effect in 2030.21 

Additionally, even in the existing proposal there is the built-in flexibility in the form of emissions 

averaging across sources and across time. This averaging feature would allow, for example, that an 

otherwise soon-to-be uneconomic coal facility that provides an important reliability function could 

continue to operate during the hours of the year when it was most needed for reliability or until an 

alternate generation or transmission solution can be put in place. In many cases, this generation could 

even continue for a number of years before the state plan requirements would need to see the generator 

in question replaced by a lower emitting facility or put a transmission upgrade in place to alleviate the 

reliability impact of the retirement. Regional compliance, which has been encouraged by market 

operators, would further extend this flexibility. This averaging thus provides an ability to maintain 

reliability-critical generating resources, results in longer lead times to develop alternative sources of 

generation or other infrastructure (alleviating what some have called a “cliff” effect starting in 2020), 

and allows for real-time adaptation of plans if these lead times are extended due to factors not 

considered in the original state compliance plan.

Of course, states also have broad flexibility to achieve emissions reductions through a variety of 

measures not limited to changes in their fleet of fossil fuel-fired generators’ dispatch. For example, 

increasing renewable generation or energy efficiency can reduce state emissions while maintaining 

 

21

 Furthermore, the CPP is not yet final and there is reason to think that the EPA intends to modify the draft rule in 

important ways. In particular, the EPA Administrator and other senior EPA staff have signaled repeatedly in 

congressional testimony and in meetings with the states and industry that the Agency has heard clearly from 

stakeholders that a glide path or phase-in of the assumptions about the level of re-dispatch from coal to gas in the early 

years of the interim phase would ease the transition for states and companies.
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M.J. Bradley & Associates LLC 11 June 2015

headroom for emissions from coal or natural gas-fired units. Furthermore, these resources can provide 

many reliability services if necessary. In addition, states have the option to trade emissions or 

emissions credits with other states, meaning that one state could conceivably exceed its emissions 

target and acquire credits from another state that is below its own target. Given the range of state 

targets, this may allow for states with more challenging targets to ease into compliance by taking 

advantage of low-hanging fruit in other states with more economic options for meeting their targets.

As others before us have shown, this flexibility is a primary way to maintain reliability through a 

transition to a lower-emitting fleet. In order for states to take advantage of this flexibility, however, 

state stakeholders and policymakers must take proactive steps to coordinate with potential partners 

(both within and outside their state) and explore available options. A crucial tool to guide this process 

will be a series of well-conducted reliability assessments. We strongly believe that reliability entities 

and relevant state regulators can undertake effective reliability analyses that can proactively inform 

planning and assess options throughout CPP compliance.

Reliability Assessment Guiding Principles

To all users of the bulk electricity grid, maintaining electric system reliability through ongoing 

industry changes, including the implementation of the CPP, is of utmost importance. Indeed, this is 

part of the mission of all reliability coordinators, planners, and ISOs/RTOs. We are encouraged by 

proactive initiatives that industry members and regulators alike have undertaken to prepare for and 

respond to this change. 

However, the dialogue around the CPP has revealed shortcomings and pitfalls of assessment processes 

that can skew findings in unhelpful ways. All parties in the debate about reliability and the CPP share 

the goal of maintaining and improving reliability. Nevertheless, we have seen some studies that 

significantly discount or ignore important considerations and information in their assessments, leading 

to conclusions that are used as arguments to forestall or prevent the CPP from going forward, rather 

than offering constructive adjustments and solutions. In some instances, it has seemed as though 

preservation of the grid’s status quo has been equated with maintaining reliability. 

This discrepancy has manifested most obviously in the wide range of studies and assessments that 

hope to inform the reliable and safe implementation of the CPP. In addition to NERC’s Initial and 

Phase I studies, the following Regional Entities, RTOs, and ISOs have released assessments of the 

proposed CPP: PJM Interconnection;22 Southwest Power Pool (SPP);23 Midcontinent Independent 

 

22

 See PJM Interconnection Inc., “PJM Interconnection Economic Analysis of the EPA Clean Power Plan Proposal,” 

March 2 2015 (“PJM Assessment”). Available at 

http://www.pjm.com/~/media/4CDA71CBEC864593BC11E7F81241E019.ashxc.
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M.J. Bradley & Associates LLC 12 June 2015

System Operator (MISO);24 Electric Reliability Council of Texas (ERCOT);25 and the Western 

Electricity Coordinating Council (WECC).26 Each of these organizations has valuable insight into how 

the CPP may affect their region, and their input can provide useful information for state and national 

regulators in designing the program and compliance plans.27 Furthermore, we recognize that an 

examination of each aspect of grid reliability requires different types of modeling—assessing resource 

adequacy can be done through capacity expansion planning, operational reliability typically is 

analyzed through production cost simulations, and disturbance response is measured through load flow 

and dynamic response models. However, not all studies have utilized each of these methods. Indeed, 

to date, every assessment represents a vastly different approach to considering the CPP, and many 

contain problematic assumptions and methods that call into question their conclusions. These 

differences result in a set of studies whose findings are not mutually comparable and present 

conflicting and, in many cases, misleading results. 

Instead, a useful reliability assessment must seek practical, realistic solutions that recognize and 

address both EPA’s imperative to reduce greenhouse gas emissions and the shared interest in 

maintaining and enhancing affordable resource adequacy, operational viability, disturbance response 

stability, and other attributes that support the reliable and economic operation of the power system. 

Given the highly interconnected nature of the grid and the critical need for productive and actionable 

reliability assessments to guide state compliance with the CPP, these studies should be conducted 

following a set of common guiding principles. Though specific assumptions and models utilized will 

vary by region—and should, in order to best reflect local conditions—we believe there are six guiding 

principles that each study, regardless of method or assumptions, should follow. Taken together, these 

principles are a roadmap to a reliability assessment that realistically and methodically analyzes a range 

of potential CPP compliance pathways, highlighting impacts on multiple aspects of reliability in a way 

 

23

 See Southwest Power Pool, “SPP’s Reliability Impact Assessment of the EPA’s Proposed Clean Power Plan,” October 

8 2014 (“SPP Assessment”). Available at 

http://www.spp.org/publications/CPP%20Reliability%20Analysis%20Results%20Final%20Version.pdf. 

24

 See Midcontinent Independent System Operator, “Analysis of EPA’s Proposal to Reduce CO2 Emissions from Existing 

Electric Generating Units,” November 2014 (“MISO Assessment”). Available at 

https://www.misoenergy.org/Library/Repository/Communication%20Material/EPA%20Regulations/AnalysisofEPAsP

roposaltoReduceCO2EmissionsfromExistingElectricGeneratingUnits.pdf. 

25

 See Electric Reliability Council of Texas, “Impacts of Environment Regulations in the ERCOT Region,” December 16 

2014 (“ERCOT Assessment”). Available at 

http://www.ercot.com/content/news/presentations/2014/Impacts%20of%20Environmental%20Regulations%20in%20th

e%20ERCOT%20Region.pdf. 

26

 See Western Electricity Coordinating Council, “EPA Clean Power Plan: Phase 1 – Preliminary Technical Report,” 

September 19 2014 (“WECC Assessment”). Available at https://www.wecc.biz/Reliability/140912_EPA111%28d%29_PhaseI_Tech-Final.pdf. 

27

 Additionally, we note that a number of other entities, such as NREL and many utilities and public utilities 

commissions, have conducted reliability assessments that, while not specifically CPP-focused, provide good examples 

of processes and practices that conform with our principles. We focus our discussion here on reliability entityconducted assessments but strongly encourage input of these third-party stakeholders. 
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M.J. Bradley & Associates LLC 13 June 2015

that can be pressure-tested by stakeholders and utilized by state policymakers. In this whitepaper, we 

assume that the party conducting the reliability assessment is a regional reliability planner, though 

most, if not all, of these principles would apply to a state- or utility-led process as well.

Guiding Principle: Utilize a Transparent Process

The CPP is subject to intense industry scrutiny and has elicited a broad range of positive and negative 

reactions among stakeholders. Organized and focused stakeholder involvement will help incorporate 

up-to-date assumptions, create consistency across assessments, and ensure that reliability assessments 

are, to the extent possible, based in objective facts and data. These processes can also help sanity 

check initial results. Organizations such as the Utility Variable Generation Integration Group have 

developed “principles for technical review” that should be followed for each reliability assessment.28 

In addition, to provide ongoing feedback as states incorporate results into compliance plans and 

reliability planners and/or coordinators plan for ongoing assessments, detailed results and assumptions 

should be discussed as part of the technical review process and be released in concurrence with each

final report. 

WECC’s assessment stands out as a good example in this regard, clearly articulating the goals of the 

analysis, technical assumptions (and reasoning behind them), and model methodologies and 

limitations. As explained throughout the report, WECC also utilized cases based on stakeholder input. 

By comparison, other assessments have been less transparent about their assumptions and have limited 

stakeholder involvement. NERC, for example, delayed the release of its assumptions and provided 

only a narrow window for stakeholder review of the modeling results and draft reports. 

Guiding Principle: Reflect Existing Status of the Grid in Modeling Assumptions

In setting the assumptions for the analysis, both in a reference case and CPP compliance scenarios, a 

reliability planner and/or coordinator must recognize key elements of the electricity grid’s ongoing 

transformation. It is neither realistic nor useful to presume that the grid will revert to pre-market and 

pre-technological advancement conditions. Though we do not advocate for a specific set of 

assumptions, we urge careful consideration of the following factors:

 Renewable development: even without the CPP, renewable output under EIA’s Annual Energy 

Outlook 2015 (AEO 2015) Reference Case continues to grow through 2040.29 Other estimates 

 

28

 Utility Variable Generation Integration Group & National Renewable Energy Laboratory, “Principles for Technical 

Review Committee (TRC) Involvement in Studies of Variable Generation Integration into Electric Power Systems,” 

June 2012. Available at: http://uvig.org/wp-content/uploads/2009/05/TRCPrinciplesJune2012.pdf. 

29

 U.S. Energy Information Administration, “Annual Energy Outlook 2015,” April 2015 (“AEO 2015”). Available at: 

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. 
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M.J. Bradley & Associates LLC 14 June 2015

show renewable build alone in 2015 expected to exceed 18 GW, mostly from wind and solar.30 

Reliability assessments must incorporate renewable energy assumptions and modeling that 

reflect these trends—but numerous studies to date have not. The NERC Assessment, for 

example, shows particularly limited renewable growth. It uses two renewable cases, “Carbon” 

and “No Carbon,” as inputs to gauge the impact of the CPP as compared to business-as-usual

activities. However, as compared to third-party projections showing 18 GW of build in 2015, 

the NERC Assessment assumes only half as much new renewables build in 2015—9 GW—

with annual additions actually decreasing to between 2 and 2.5 GW per year between 2020 and 

2029. Indeed, NERC’s 2020 renewable generation projected under the CPP, 281 TWh, is 

actually below the amount of renewable energy generated in 2014.31 Additionally, there is very 

little difference between the two cases. The “Carbon” case assumes only a 6 percent increase 

in solar output under the CPP, as compared to the “No Carbon” case, by 2030 in states such as 

Arizona, Florida, Utah, Texas, Nevada and New Mexico; similarly, it assumes only a 1 percent 

change in wind development by 2030 in Iowa and the Dakotas, and only a 6-7 percent change 

in Wyoming and Colorado. These baseline assumptions must be scrutinized, and likely 

improved, in order to result in assessments containing realistic views of capacity retirements 

and resulting reliability and energy management services available on the grid. One possible 

way to improve these build out estimates would be to closely consider renewable development 

costs—we note that NERC used 2013 data (which is readily available, and understandable), but 

prices have fallen so quickly that these data no longer reflect reality. Furthermore, as we 

discuss below, renewables—and other non-fossil emissions reduction strategies—should 

ideally be an output of an assessment to reflect the optionality of the CPP. 

 Ongoing generation and infrastructure improvement: as we have presented throughout this 

whitepaper, the electricity sector is already undergoing significant infrastructure development 

and expansion. In many ways, this provides a “running start” to those who are looking to 

further strengthen energy infrastructure and may help cut down timelines as many important 

projects are already in the pipeline. For example, the Edison Electric Institute forecasted in 

January of this year that between 2014 and 2017, investor-owned utilities alone (not including 

other public utilities, co-ops, or merchant developers) will invest a total of $78 billion in 

transmission,32 and FERC estimates that over 10,500 miles of currently proposed transmission 

 

30

 Bloomberg New Energy Finance, “Medium-term outlook for US power: 2015,” April 8, 2015. Available at: 

http://about.bnef.com/content/uploads/sites/4/2015/04/BNEF_2015-02_AMER_US-Power-Fleet-De-CarbonisationWP.pdf. 

31

 Total net energy produced from solar, wind, geothermal and waste in 2014 totaled 281.1 TWh. See U.S. Energy 

Information Administration, Monthly Energy Review Data, Table 7.2. Reports available at 

http://www.eia.gov/totalenergy/data/monthly/previous.cfm. 

32

 Edison Electric Institute, “Actual and Planned Transmission Investment By Shareholder-Owned Utilities (2008–

2017),” January 8 2015 at p. 1. Available at 

http://www.eei.org/issuesandpolicy/transmission/documents/bar_transmission_investment.pdf. 
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M.J. Bradley & Associates LLC 15 June 2015

lines will be in place by 2017.33 Similarly, FERC approved over 400 miles of new natural gas 

pipelines with a combined capacity of over 8 billion cubic feet per day in 2014.34 To the extent 

that analyses consider infrastructure development as a limiting factor to providing reliability 

services, they should attempt to incorporate build out timelines that reflect this activity in 

electric transmission and distribution, natural gas pipeline, and generation development already 

underway. Many studies ignore the “pipeline” of infrastructure projects that will be in various 

stages of development at the start of the CPP.

 Energy demand and energy efficiency: the AEO 2015 projects growth at an annual rate of 0.8 

percent between 2013 and 2040, not including any increase in energy efficiency that is driven 

by the CPP or other not yet operational programs. In comparison, NERC assumes load growth 

ranging from 0.5 to 1.2 percent in 2030, even after accounting for energy efficiency under the 

CPP. While exact demand is impossible to predict (see principle concerning sensitivities to 

address these unknowable inputs), scenarios should be based around realistic assumptions. 

Furthermore, to the extent that modeling is able to adjust demand as an output in response to 

electricity prices, assessments should incorporate transparent and accurate assumptions around 

the elasticity of demand.

Guiding Principle: Clearly Identify Base Case and Context

Without proper contextualization, some stakeholders have used reliability assessments as 

reinforcement for exaggerated claims of the impact of the CPP. It is true that actions to comply with 

the CPP will build upon and, in some cases, accelerate existing trends, such as natural gas pipeline 

expansion and coal plant retirements. However, as explained above, the ongoing nature of these 

activities means that much of the needed planning and infrastructure development to address reliability 

is already in progress. This “base case” must be clearly delimited and explained, with results placed in 

this context. To the extent that reliability studies indicate that more time is needed to comply with the 

CPP, they must correctly acknowledge existing conditions and activity, which in many cases would 

significantly trim development timelines and requirements. 

The WECC Assessment again provides a good example of this guiding principle, providing context in 

numerous places to help stakeholders interpret study results. This assessment shows coal retirements 

under the CPP as compared to a well-defined base case,35 for example, and three different natural gas 

dispatch scenarios compared to a clear “common case” that is also further explained in an Appendix to 

 

33

 FERC Office of Energy Projects, “Energy Infrastructure Update for March 2015,” posted April 23 2015 at p. 5. 

Available at http://www.ferc.gov/legal/staff-reports/2015/mar-infrastructure.pdf. 

34

 FERC, “Approved Major Pipeline Projects (2009-Present),” Data as of March 31 2015. Available at 

http://www.ferc.gov/industries/gas/indus-act/pipelines/approved-projects.asp. 

35

 See WECC Assessment at p. 15. 
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M.J. Bradley & Associates LLC 16 June 2015

the report.36 MISO’s assessment also clearly shows the impact of projected coal retirements through 

using a base case against which incremental retirements associated with the CPP are compared. In 

comparison, SPP and NERC provide little to no context throughout their studies. NERC’s assessment 

is especially concerning, with executive level conclusions and all graphs indicating that the CPP will 

trigger a wave of coal retirements that, upon examining the data provided deeper in the report, are 

proven to actually be largely already planned or underway due to other regulations or economic 

decisions. Similarly, it presents power flows and capacity margins under the CPP but gives no 

indication of how much the CPP has changed these values. While in some cases it is useful to 

understand these total results for reliability planning purposes, it is misleading and ultimately 

regressive to indicate that all changes are due to a single policy such as the CPP. Policymakers must 

understand the portion of activity that they can directly affect through their CPP compliance activities. 

Reports must clearly indicate if the conclusions are based on combining the incremental impacts of the 

CPP with the ongoing changes reflected in the reference case or if they are based on only the 

incremental impacts of the CPP.

Guiding Principle: Conduct Sensitivity/Probabilistic Analyses Where Possible

Reliability studies, by design, are forward-looking assessments that must incorporate forecasts of 

future conditions. Though we have numerous models for forecasting inputs such as electricity 

demand, fuel prices, and development costs, no forecast can ever be entirely reliable. As such, a good 

analysis will incorporate multiple sensitivities or a probabilistic approach around these key inputs to 

gain a clearer picture of what variables may drive concerns, and how likely they are to occur. 

However, some existing studies focus almost exclusively on a “worst case” scenario of high gas prices, 

high demand, and high technology costs. To the extent that resources allow, assessments should 

examine a broad range of cases that are more likely to encompass future conditions. While examining 

a low probability/high risk scenario does have some value, it should not be the sole driver of planning 

considerations or become the dominant “strawman” for policymakers to consider as the possible 

outcome of the CPP.

The NERC Assessment, for example, focuses primarily on a worst-case scenario, and would be more 

valuable to stakeholders if it included additional scenarios or sensitivities around demand growth, 

natural gas prices, retirement/development timelines, and compliance through mechanisms other than 

replacing coal with natural gas. As currently conducted, the study’s results are primarily limited to 

showing how natural gas prices affect costs of increasing natural gas-fired facility dispatch, which does 

not help policymakers evaluate a balanced emissions-reduction strategy that best maintains reliability 

at least cost. The SPP Assessment, which the authors acknowledge as “cursory,” provides another 

example of a study based on a limited range of assumptions. For example, rather than examining 

 

36

 Id. at pp. 16-17, 32-36. 
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M.J. Bradley & Associates LLC 17 June 2015

retirements from an SPP system-wide policy perspective, this assessment uses EPA’s IPM retirements 

under their state-by-state compliance case as retirement inputs. While this is a reasonable starting 

point for an assessment, it is unnecessarily restrictive, eliminating the ability of the modelers to 

optimize emissions reductions through on-the-ground decisions and updated assumptions and instead 

assumes that only those actions output from a different model will occur. Furthermore, it uses EPA’s 

worst-case retirement outputs (from the state compliance case). To improve this assessment, SPP 

should develop alternative compliance scenarios including sensitivities where applicable. 

On the other end of the spectrum, the MISO Assessment shows the benefit of exploring sensitivities—

indeed, 1,296 individual scenarios. This sensitivity analysis helps show, for example, that a “medium” 

level of coal retirements may be most optimal for limiting compliance costs, and that in some cases, 

already-planned coal retirements would be sufficient to reach regional emissions targets (though at 

higher cost).37 Similarly, the PJM Assessment conducted an assessment of multiple scenarios differing 

across variables such as natural gas prices, renewable resource and energy efficiency availability, new 

natural gas development, and others. PJM also focused a section of its report on the impact each of 

these sensitivities had on a range of model outputs, including resource redispatch, capacity at risk for 

retirement, and energy and CO2 prices.38

Guiding Principle: Reflect the Flexibility of Compliance Options Under the CPP

EPA has designed the CPP with significant flexibility that will allow states to adjust their compliance 

approaches to maximize reliability (and minimize cost). The proposed rule’s state-specific interim and 

final goals reflect differences in each state’s current mix of resources used to generate electricity, 

coupled with each state’s potential to increase the use of lower-carbon and zero-carbon resources. In 

designing a compliance plan, and potentially using the insight from a reliability assessment, a state 

may address reliability implications of potential temporary or permanent outages of specific units in a 

variety of ways, including making deeper reductions at other units or instituting “outside-the-fence” 

options such as renewable energy or energy efficiency development. States may also enter into 

emissions crediting/trading within their state borders or in partnership with all or portions of other 

states. Finally, as a long-term emissions reduction program, the proposed CPP establishes a ten-year 

interim target that states will have to meet on an average basis; in other words, a state may plan for 

higher emissions early in the program to allow for infrastructure or generation development (so long as 

those emissions are balanced out by reductions in later years), or may plan for an emissions “buffer” 

that would allow higher-emitting units to operate in short periods of reliability need, driven perhaps by 

peak demands or unforeseen weather events or unit outages. 

 

37

 See MISO Assessment at p. 15. 

38

 See PJM Assessment at pp. 24-76. 
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M.J. Bradley & Associates LLC 18 June 2015

Perhaps not all states will be able to take full advantage of this flexibility due to institutional 

challenges such as in-state political climate, infrastructure development procedures, or other planning 

considerations. However, reliability assessments must consider scenarios in which these flexible 

approaches are included. Ways this could be shown include:

 Allowing all, or a majority, of compliance options (e.g., natural gas dispatch, increased 

renewable development, or additional energy efficiency) as outputs of models, not input: a 

number of the reliability studies we examined are structured such that emissions reductions 

actions—such as increases in renewable penetration or energy efficiency—are limited as inputs 

of cases into assessment models. In many cases this effectively assumes that these activities 

will continue along business-as-usual trajectories, and that the only lever that policymakers 

may pull to reduce emissions is re-dispatch from coal to natural gas. In many areas, this 

severely and artificially limits the options a state may have to reliably and cost-effectively 

reduce the emissions intensity of its fleet. Moreover, it is an illogical assumption that the levels 

of such emissions reducing technologies will not be driven in part by a carbon-constraining 

program such as the CPP, and a model should be able to reflect this economic reality. This 

concern helps illustrate the need for different models for different reliability questions. First, 

capacity planning models can help evaluate least-cost resource adequacy generation mix 

scenarios; then, a postulated future generation mix can be input to a production cost model to 

analyze dispatch; finally, dispatch snapshots are inputs to load flow and dynamic stability 

models. A good process iterates and does “round-trip” modeling that can work toward more 

practical and realistic end cases and can protect against rigid acceptance of a set of inputs into 

any one of the models resulting in erroneous conclusions (essentially hardwired by the input 

assumptions). Alternatively, if an assessment cannot incorporate this complexity due to 

resource or time constraints, it should at least include multiple renewable, energy efficiency, 

and other compliance option build-out scenarios for comparison (see, for example, the MISO 

Assessment three renewable scenarios). 

 Indicating trading within (or outside of) the modeled region: broad coordination among 

utilities and states has emerged as a centerpiece of the national discussion about the CPP and 

how it may best be implemented. Several studies, including notably the PJM Assessment, have 

found that multi-state coordination for the purpose of trading of emissions allowances increases 

the array of resource options for compliance, which can in turn allow for increased optionality 

to maintain reliability. Numerous states are in active discussion to explore ways that they could 

facilitate limited or modular allowance trading without necessitating legislated agreements or 

complicated multi-state CPP compliance plans—often called “common elements” approaches. 

It should also be noted that these trading mechanisms may extend beyond borders of modeled 

areas, and may not even follow electricity flow patterns. Assessments such as SPP’s and 

NERC’s could significantly improve the usefulness and accuracy of their results if they 

explored cases that included varying levels of trading. 
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 Examining options for phased-in compliance: as detailed above, the CPP sets fairly long-term 

compliance pathways, with “interim” compliance calculated over an average of several years 

and not starting until over four years from when a final rule is released. In reviewing a number 

of assessments and claims that the interim target is too aggressive, it appears that some may 

have assumed the year 2020 as a binding compliance year. Infrastructure development can be a 

critical path element in maintain reliability, and establishing assumptions around what amounts 

to premature compliance will exacerbate these infrastructure timelines, leading to misleading 

signs of reliability issues.

Guiding Principle: Provide Realistic But Reliability-Focused Results

Though many reliability planners have joint missions of maintaining reliability and ensuring welloperating and efficient electricity markets, the focus of these assessments should be on identifying 

reliability concerns that result from realistic projections of compliance options. In designing 

compliance plans, states and their stakeholders will no doubt pursue lowest cost actions that will vary 

by region. However, “reliability” should not be equated with “cost effectiveness” or a least-cost 

solution to compliance. The added value that reliability assessments can provide is to identify key 

electric system risks, vulnerabilities, and opportunities that arise from compliance options that fall 

across the cost spectrum. 

Certainly, economic considerations are crucial in understanding how market players will react to given 

policies (such as energy efficiency programs or carbon prices), and we are not suggesting that these 

assessments be conducted absent any consideration of cost. Indeed, it is crucial that realistic 

assumptions of cost are built in to develop a forecast of, on one hand, the speed at which development 

and expansion will occur and, on the other, the rate of retirement or down-rating of existing facilities. 

Factoring cost and the likelihood of investment into reliability assessments needs to be done with 

sufficient impartiality such that the assessment skews toward neither over-built systems (by assuming 

high, out-of-market incentives) nor maintaining the status quo resource mix (by assuming any 

consumer price impact must be avoided). However, the primary output of a reliability assessment 

should not be a cost figure but instead a technical view of the electricity grid’s capabilities. Though 

impossible to remove bias from any assessment, this will help focus these studies. It should not be 

within the scope of a reliability assessment, as it seems to be in the NERC and MISO cases, to opine 

on whether states may, or may not, be willing to pay a bit more than the cheapest possible compliance 

option in order to achieve a more optimal long-term solution, public policy consideration, or 

maintenance and development of reliability services. States and stakeholders will be in a better 

position to evaluate compliance options when they are given full information about both the reliability 

and cost impacts of compliance options that can serve local electricity customers. We point to the PJM 

and WECC Assessments as good examples of how economic factors are inputs that drive possible 

assumptions and cases under which to examine reliability.
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Conclusions

As we have seen throughout the last half century, environmental standards can coexist with electric 

reliability. As our grid undergoes update and change, the toolkit to maintain reliability continues to 

improve. The CPP, through its flexible design, can take advantage of existing and emerging practices 

to support reliability on the path toward a clean, more efficient, electric industry. 

To assist in this continuing transition, we must have a clear way to identify, plan for, and address 

reliability issues. Crucial to this will be reliability assessments conducted on a national and regional 

level that provide a consistent, productive, and comprehensive view of reliability. To that end, we 

encourage the industry and its stakeholders to utilize a standardized set of guiding principles for use in 

undertaking these important assessments. We recommend the following six guiding principles: 

1. Utilize a transparent process. Organized and focused stakeholder involvement will help 

incorporate up-to-date assumptions, create consistency across assessments, sanity check initial 

results, and ensure that reliability assessments are based in objective facts and data. 

2. Reflect existing status of the grid in modeling assumptions. In setting the assumptions for the 

analysis, both in a reference case and CPP compliance scenarios, a reliability assessment must 

incorporate key elements of the electric grid’s ongoing transformation that will drive 

assumptions on, for example, renewable development, ongoing generation and infrastructure 

improvement, and energy demand and energy efficiency.

3. Clearly identify base case and context. Actions to comply with the CPP will build upon 

existing electric sector trends and will take advantage of already in progress planning and 

infrastructure development to address reliability needs. Policymakers must understand the 

portion of activity that they can directly affect through their CPP compliance activities. 

Reports must clearly indicate if the conclusions are based on combining the incremental 

impacts of the CPP with the ongoing changes reflected in the reference case, or if they are 

based on only the incremental impacts of the CPP.

4. Conduct sensitivity/probabilistic analyses where possible. Reliability studies should 

incorporate multiple sensitivities or a probabilistic analysis around key inputs of future 

conditions that are based on forecasts, including electricity demand, fuel prices, and 

development costs. Assessments should be careful to avoid only focusing on a low 

probability/high risk scenario. 

5. Reflect the flexibility of compliance options under the CPP. The proposed CPP provides

significant flexibility that will allow states to adjust their compliance approaches to maximize 

reliability and minimize cost. Assessments should reflect this flexibility in model design

through methods such as allowing a range of compliance options (e.g., natural gas dispatch, 
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M.J. Bradley & Associates LLC 21 June 2015

increased renewable development, or additional energy efficiency) as outputs of models, 

indicating trading within (or outside of) the modeled region, and examining options for phasedin compliance.

6. Provide realistic but reliability-focused results. The focus of these assessments should be on 

identifying reliability concerns that result from realistic projections of compliance options. 

While cost projections provide crucial bounding of assumptions and scenarios, “reliability” 

should not be equated with “cost effectiveness.” The added value of reliability assessments is 

to identify key electric system risks, vulnerabilities, and opportunities that arise from various 

compliance options. 

Following these principles will help create reliability assessments that provide practical, realistic 

results that recognize and address both EPA’s imperative to reduce greenhouse gas emissions and 

the shared interest in maintaining and enhancing affordable, reliable electricity.