Environmental 

Regulation and

Electric System 

Reliability

from the staff of the bipartisan policy center
Authors

Jennifer Macedonia, Senior Advisor

Joe Kruger, Director for Energy & Environment

Lourdes Long, Senior Policy Analyst

Meghan McGuinness, Associate Director for Energy & Environment

Disclaimer

This report was prepared by the staff of the Bipartisan Policy Center 

to promote a better understanding of the possible impacts of U.S. 

Environmental Protection Agency regulation of the electric power sector and 

to identify a range of strategies for managing associated reliability concerns. 

The views expressed here do not necessarily reflect those of the BPC Energy 

Project or our workshop co-sponsors, presenters, and participants.

Acknowledgements

The Bipartisan Policy Center would like to express its thanks for the strong 

support of its funders. In addition, we are grateful to the National Association 

of Regulatory Utility Commissioners and Northeast States for Coordinated 

Air Use Management for co-sponsoring the workshop series. Thanks also to 

each of the experts, listed in Appendix A, that participated in the workshop 

series and informed this report. Special appreciation is due to Marika 

Tatsutani for editing the report. 
Table of Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Section I. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Section II. Overview of Challenges Facing the U.S. Electricity Sector . . . 10

A. The Impact of Natural Gas Prices

B. Current and Potential Future Energy Policies

C. Forthcoming EPA Regulations for the Electric Power Sector

Section III. Results of Power Sector Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

A. Current Trends in the Power Sector

B. Studies on the Impact of EPA Regulations

C. Impacts of Retirements on Resource Adequacy

D. The Staging of Retrofits

Section IV. Addressing Reliability Concerns:

The Roles of Federal, State, and Regional Authorities . . . . . . . . . . . . . . . . . 28

A. Federal Agencies

B. Interagency Cooperation

C. State Authorities

D. Regional Organizations

E. Coordination of Federal, State, and Regional Authorities

Section V. Conclusions and Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

A. Flexibilities in the Clean Air Act and Clean Water Act

B. Planning and Coordination

C. Siting and Permitting for New Infrastructure

D. Legislative Opportunities

Appendix A -List of Expert Speakers from BPC Workshops 

on Environmental Regulation and Electric System Reliability . . . . . . . . . . 42

Appendix B - BPC Modeling using ICF’s Integrated Planning Model . . . . . . 44

A. Assumptions for Analysis

B. Description of Scenarios

C. Select Results of BPC Analysis
1 These rules are being proposed under the Clean Air Act and other statutory authorities, which require 

EPA to protect public health, welfare, and the environment from adverse impacts of power plants.

2 For example, EPA estimates the health and environmental benefits of the proposed Transport Rule 

range from $120 to $290 billion in 2014, while compliance costs for that year are estimated to be $2.8 

billion (estimates are in 2006 dollars). See United States Environmental Protection Agency. Proposed 

Air Pollution Transport Rule: Reducing Pollution, Protecting Public Health. http://www.epa.gov/

airquality/transport/pdfs/TRPresentationfinal_7-26_webversion.pdf.

The electric power sector in the United States faces 

a changing market environment, one that 

features reduced or flattened demand, low natural 

gas prices, new environmental regulations, and 

continued uncertainty about the future regulation 

of carbon. Among the regulations recently 

proposed or currently under development by the 

U.S. Environmental Protection Agency

(EPA) are rules to address air pollution transport, 

air toxics, coal ash, and cooling water intake

structures at existing plants.1

 These regulations are 

expected to result in significant public health and 

environmental benefits that, when monetized, 

are well in excess of compliance costs.2

Executive

Summary
Environmental Regulation and Electric System Reliability 3

3 BPC gratefully acknowledges NARUC and NESCAUM as co-conveners of the workshop series. However, the report is solely a product of the 

staff of the Bipartisan Policy Center and does not necessarily represent the views of NARUC, NESCAUM, or any of the workshop participants.

4 Information from each of the workshops, including video and presentations, is available at www.bipartisanpolicy.org.

5

 For example, demand response and energy efficiency programs, energy storage, and transmission upgrades.

6 Although many gas turbines have been built within 3 years in the recent past, some in industry have raised concern that the permitting 

process for new construction, including greenhouse gas best available control technology (BACT) determinations, might take up to two to 

three years, added on top of two year construction for a new gas turbine. BPC modeling projects only 200 MW of new gas capacity would 

be needed, beyond the 1200 MW of new gas turbines expected in the business as usual scenario to be built by 2015.

Key benefits of the suite of EPA regulations include the 

avoidance of tens of thousands of premature deaths 

annually, reductions in pollution-related illnesses, and 

improved visibility and ecosystem health. These new 

conditions in the power sector are expected to increase the 

number of coal-fired power plants that will be retired in 

the next several years; in fact, a number of plant shutdowns 

have recently been implemented or announced. 

Environmental compliance deadlines are likely to have 

a strong influence on the timing of these retirements, as 

plant owners will not want to make significant capital 

investments in some older, marginal units that might 

otherwise be shut down soon for economic reasons. 

This has led to concerns that the power sector could face 

reliability issues as utilities comply with new regulations. 

Others have argued that power companies and regional, 

state, and federal authorities have recourse to a range of 

technology options and planning approaches that can 

help them avoid reliability impacts from the impending 

suite of environmental regulations. 

To shed light on these complex issues, the Bipartisan 

Policy Center (BPC), together with the National 

Association of Regulatory Utility Commissioners 

(NARUC) and Northeast States for Coordinated Air Use 

Management (NESCAUM), hosted a series of workshops 

to assess the possible impacts of regulation and identify 

a range of strategies for managing associated reliability 

concerns.3

 The three workshops featured presentations 

by leading experts on electric power system reliability, 

electricity market operations, power sector technology, 

and pollution control policies and regulations (see 

Appendix A).4

 Building on the presentations and public 

dialogue at these workshops, our review of a range of 

existing analyses, and our own analytic work, BPC has 

developed a number of findings and recommendations. 

Our main conclusions are summarized below.

Impacts on the reliability of the

electric system due to EPA regulations

are manageable. 

BPC analysis indicates that scenarios in which electric 

system reliability is broadly affected are unlikely to occur. 

Previous national assessments of the combined effects 

of EPA regulations reach different conclusions, in part 

because they make quite different assumptions about 

the stringency 

and timing of 

new requirements 

and about 

the availability 

and difficulty of 

implementing control 

technologies. In some cases 

these assumptions deviate 

from the specifics of EPA’s recent 

proposals in meaningful ways. Moreover, market factors, 

such as low natural gas prices, are as relevant as EPA 

regulations in driving coal plant retirements. A number 

of recent developments are especially relevant from the 

standpoint of addressing reliability concerns: 

• EPA’s proposed cooling water regulations are far 

less stringent than assumed in the vast majority 

of analyses, many of which considered worst-case 

scenarios in which cooling towers would be required 

on all existing units. 

• Some commercially available, lower-cost technologies 

(e.g., dry sorbent injection) for treating hazardous 

air pollutants were not factored into most previous 

analyses. Including them significantly reduces 

retirement projections. 

• Most of the units projected to retire are small, 

older units that are already operating infrequently. 

Some of these units may be needed to meet peak 

demand on the hottest and coldest days or to 

provide volta ge support. In some cases, there may be 

viable mechanisms, other than one-to-one capacity 

replacement, available to serve these needs.5

• The industry has significant amounts of existing 

natural gas generating capacity that is currently underutilized and may be available to take up the slack, 

depending on the region.

• Some previous assessments do not account for market 

responses to future retirements, specifically to the 

potential for adding new capacity to meet reserve 

margins. Assuming timely permitting, the need for 

modest new capacity resources could be met with 

quick-to-build natural gas turbines, as well as demand 

side resources.6
A number of tools for addressing

reliability concerns are available to

industry and to state and federal

regulators.

EPA should take advantage of its existing statutory 

authorities to structure clear regulations that include 

sensible timelines and encourage cost-effective 

compliance strategies. Specifically, EPA should 

finalize the flexibilities proposed in its Utility Air 

Toxics Rule (which sets “maximum achievable control 

technology” standards for hazardous air pollutants) 

and 316(b) cooling water rule. Where needed and 

allowed by statute, EPA and state permitting agencies 

should grant utilities time extensions – with as much 

advance notice as possible – to install pollution 

control technologies and to build the new capacity 

required to achieve compliance.10

Regional, state, and utility analyses should continue 

to examine the potential localized impacts of 

retirement and retrofit schedules, as well as 

opportunities to attract non-conventional capacity 

resources, such as demand resources, distributed 

generation, and grid-scale energy storage capacity. 

While most studies have taken a national approach 

to reliability assessments, more study is warranted 

to assess localized reliability impacts in the most 

vulnerable regions, and efforts should be made to 

refine and improve analytical tools.

If specific issues are identified, federal and state 

agencies should consider implementing strategies to 

assure reliability while utilities complete upgrades or 

bring new generation online. As a backstop, DOE 

has emergency powers to keep essential generation 

on-line, and the President has emergency powers 

to delay requirements in order to protect national 

security. In addition, EPA may enter into consent 

decrees – which set forth the steps needed to resolve 

non-compliance – to enforce the provisions of the 

Rule. Such consent decrees, however, should aim to 

eliminate any economic advantage that companies 

may otherwise have as a result of operating out of 

compliance. Consent decrees are negotiated once a 

company is deemed in violation, and stakeholders 

may not view this legal mechanism as an acceptable 

option that could be built into company planning. 

However, consent decrees do offer an additional 

means of backstop reliability protection.

10 Some stakeholders endorse efforts to preempt reliability 

concerns and provide extra time up front in the process, 

rather than wait for problems and rely on emergency powers 

and consent decrees. 

Summary of Forthcoming EPA Regulations

Transport Rule – On July 6, 2010, EPA proposed the Transport 

Rule, a replacement for the Clean Air Interstate Rule (CAIR) which 

was previously remanded in a 2008 court decision.7 The newly 

proposed Transport Rule would require 31 states and the District 

of Columbia to meet state pollution limits for sulfur dioxide (SO2) 

and nitrogen oxides (NOX) as a means to ensure compliance with 

National Ambient Air Quality Standards (NAAQS) for ground-level 

ozone and fine particulate matter (PM). 

Utility Air Toxics Rule – On March 16, 2011, EPA proposed 

its Utility Air Toxics Rule under a court-ordered deadline to control 

hazardous air pollutants, including mercury, acid gases and nonmercury metals.8

 As specified by the Clean Air Act, the Utility Air 

Toxics Rule provides that plants must com ply with emission 

limitations for hazardous air pollutants within three years, but allows 

an additional year for plants to come into compliance if such time is 

necessary to install pollution controls. 

Coal Combustion Waste Disposal Regulations – 

On June 21, 2010, EPA published a proposed rule to take comment 

on whether or not coal combustion waste should be regulated as 

hazardous waste.9

 These wastes, which primarily consist of coal ash, 

are generated in large quantities by the power sector. According to 

the proposal, ash could be regulated as “special waste” under the 

Clean Air Act’s hazardous waste provisions (Subtitle C). Alternatively, 

EPA could deem the coal ash non-hazardous and regulate under 

Subtitle D, with self-implementing requirements that are not subject 

to federal enforcement.

Clean Water Act Section 316(b) Cooling Water 

Intake Structures – To protect fish and aquatic ecosystems, 

EPA proposed regulations on March 28, 2011 for cooling water intake 

structures at electric generating units (EGU) and other industrial 

facilities that draw large amounts of water out of rivers, lakes, 

and oceans. This proposed regulation responds to a settlement 

agreement that was reached after EPA’s earlier cooling water 

proposals were litigated. 

Greenhouse Gas Performance Standards – On 

December 23, 2010, EPA announced that it will propose greenhouse 

gas performance standards for power plants by July 2011 and finalize 

standards by May 2012. This action is being taken under a settlement 

agreement. At public “listening sessions” to inform this rulemaking 

process, EPA indicated that its greenhouse gas performance standards 

would not be designed to induce “game-changing” technology 

improvements; rather the Agency aims to bring older plants up to 

modern standards of efficiency.

7 State of North Carolina v. Environmental Protection Agency, Et.al. (D.C. Cir. 2008)

8 U.S. Environmental Protection Agency. Proposed Utility Air Toxics Rule. National Emission 

Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam 

Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam 

Generating Units. Signed March 16, 2011. Page 59. Available at //www.epa.gov/ttn/atw/

utility/pro/proposal.pdf. 

9 For additional information and the proposed rule see: http://www.epa.gov/wastes/

nonhaz/industrial/special/fossil/ccr-rule/index.htm.

4 Environmental Regulation and Electric System Reliability
Nevertheless, the electric power sector

and its regulators face planning

challenges if the aim is to avoid

localized reliability problems and

minimize impacts on electric rates. 

A rapidly shifting market and regulatory environment 

will create planning challenges for the electric power 

industry. The compliance deadlines of the Utility Air 

Toxics Rule, in particular, will accelerate and concentrate 

the decision-making timeframe for plant retirements, 

retrofits, and new infrastructure into a short period 

over the next few years. At the same time, many states 

are weighing new or stronger approaches to incentivize 

clean energy, energy efficiency, and/or non-conventional 

capacity resources. This convergence of issues and 

planning needs offers an opportunity for the industry 

and its regulators to work together to optimize policies 

and investment decisions so as to minimize consumer 

costs, avoid stranded assets, and maximize the benefits 

achieved by modernizing the nation’s electric power 

infrastructure. At the same time, it will undoubtedly also 

present challenges, particularly in heavily affected regions 

where the resources available to support thoughtful 

planning and regulatory processes—both in terms of 

people and funding—are already under severe pressure.

Compliance planning can and should begin early and 

should take into account existing regulations as well as 

the expected regulations. If plant owners begin planning 

now and obtain a one year extension from their permitting 

authority, they will have almost five years from the date of 

the proposed rule to the date of the extended compliance 

deadline. Multi-pollutant planning and efforts to integrate 

non-conventional capacity resources and transmission 

planning will help to minimize rate impacts for electric 

consumers. At the same time, federal, regional, and state 

entities have appropriate roles to play in supporting 

planning efforts and mitigating anticipated reliability 

challenges and costs. 

Specifically, state public utility commissions (PUCs) 

and regional transmission organizations or independent 

system operators (RTO/ISOs) should coordinate closely 

with power companies to ensure early multi-pollutant 

compliance planning and to coordinate retrofit outage 

schedules. To help with the pacing of control retrofits, 

states should continue to look for incentives and 

opportunities to encourage retrofit installations that 

begin well in advance of compliance deadlines. 

Federal agencies, including the Department of Energy 

(DOE), the Federal Energy Regulatory Commission 

(FERC), and EPA, should provide analytic and 

technical support and coordinate with state and regional 

authorities to facilitate a smooth transition. 

In light of the tight timeframes involved, state 

legislatures as well as EPA, DOE, and FERC should 

pursue strategies to help state utility regulators deal 

with increased workloads, particularly in the years 2012 

through 2014, in order to facilitate timely decisions and 

allow the design and building of pollution controls and 

infrastructure, as needed.

Due to differences among the states, 

there is no single approach to

compliance and reliability that will

work everywhere. However, a number of

strategies are already being employed

to support early planning in different

types of markets.

In regulated states, the integrated resource planning (IRP) 

process informs state utility regulators who approve 

rate plans. State policy makers should consider a multipollutant approach for rate recovery and planning 

decisions. States should also advance policies that 

encourage and place responsibility with utilities for long 

term decision-making that avoids stranded assets and 

minimizes consumer costs. In addition, state regulators 

should recognize the value of long-term natural gas supply 

contracts to provide price stability and facilitate project 

financing. Finally, traditionally regulated states should 

encourage the development of non-conventional capacity 

resources as one means to help preserve a reliable bulk 

electricity system and minimize consumer costs. 

In restructured states, the transparency of regional or 

state wholesale markets makes it easier to anticipate 

planned retirements and outages; in addition, 

competitive markets create financial incentives for 

timely investment in new transmission, generation, and 

non-conventional capacity. In these states, RTOs and 

ISOs typically facilitate orderly planning for power plant 

retirements by requiring utilities to provide advance 

notice if they intend to retire a unit and by conducting 

reliability impact studies. In light of the large number of 

pollution control equipment installations expected under 

upcoming EPA regulations, these regional entities should 

also play a more active role in coordinating outages, 

including between neighboring regions that might rely 

on each other to meet electricity demand during this 

transition period. 

 Environmental Regulation and Electric System Reliability 5

This convergence of issues and planning needs 

offers an opportunity for the industry and its 

regulators to work together to minimize consumer 

costs, avoid stranded assets, and maximize the 

benefits achieved by modernizing the nation’s 

electric power infrastructure.
6 Environmental Regulation and Electric System Reliability

11 According to EPA, for units projected to retire from the Utility Air Toxics rule, the average capacity factor is 56 percent, the average age is 

51 years, and the average size is 109 Megawatts.

12 U.S. Environmental Protection Agency. Power Plant Mercury and Air Toxics Standards: Overview of Proposed Rule and Impacts. http://

www.epa.gov/airquality/powerplanttoxics/pdfs/overviewfactsheet.pdf.

13 See Section III and Appendix B for details on BPC analysis of the impacts of EPA regulations.

Ensuring a smooth transition to a

cleaner electric power sector will

require new investments in supply 

and demand-side capacity, as well as

transmission and other infrastructure. 

State and federal agencies should

look for opportunities to streamline

the siting and permitting of new

infrastructure.

A smooth transition to a cleaner and more efficient 

generation system will require investments in energy 

efficiency, demand response strategies, and cleaner new 

generation capacity along with associated transmission and 

pipeline infrastructure. Fortunately retired capacity will not 

need to be replaced on a one-to-one basis to meet energy 

needs, simply because many of the units likely to be 

retired are not operating at full capacity now and many 

other existing units are under-utilized.11 In 

some instances, of course, the retirement 

of an existing generator may give rise 

to new capacity or transmission 

needs within a relatively brief 

period of time. And while 

the industry has generally 

been able to add capacity 

on the scale and within 

the timeframes needed 

in the past, policy 

makers at the state 

and federal levels 

should explore 

approaches to 

facilitate this process 

by streamlining 

procedures for siting 

and permitting new 

infrastructure.

There may be a short window of

opportunity to enact a legislative

fix that could guarantee the

environmental benefits of the Clean Air

Act and provide a lower cost transition

for the power sector.

Although BPC believes that the benefits of power sector 

regulation, including new regulations such as the Utility 

Air Toxics Rule, far outweigh the cost, we also recognize 

that associated compliance costs will not be trivial. EPA 

estimates that compliance costs for the Utility Air Toxics 

Rule alone will total $10.9 billion annually. For the 

average electricity consumer, this translates to an increase 

of $3 to $4 per month.12 BPC estimates annual costs 

of $14.5 billion in 2015 and $18.1 billion in 2025 to 

comply with the suite of EPA air, water, and waste rules.13

Some workshop participants suggested that a legislative 

fix could provide equivalent or greater environmental 

benefits at a lower cost than regulatory approaches 

under existing law, particularly for air pollutants. To 

be successful, multi-pollutant legislation would need 

to provide certainty on requirements and timing, and 

encourage rational and timely investment decisions in 

pollution controls and new capacity. Further, multipollutant legislation should ultimately guarantee the 

environmental benefits available under current authority, 

while offering a smoother transition. Several marketbased, multi-pollutant legislative proposals have been 

debated in recent years. While recognizing that it would 

be politically difficult to advance new legislation, the 

BPC believes that this approach could provide public 

health and economic benefits and should be explored in 

the coming months.
Environmental Regulation and Electric System Reliability 7
There continues to be debate about the effect 

of upcoming EPA regulations on power plant 

retirements and on the relative impact of these 

regulations compared to other factors, such as low 

natural gas prices and the continuing uncertainty

surrounding carbon dioxide (CO2

) control. This is 

reflected in the range of conclusions reached by 

different analyses and in the spectrum of views

that exists regarding whether compliance with the new 

regulations will present a challenge for the industry or 

not. Analysts disagree about how many existing 

coal plants are likely to be retired rather than 

retrofitted with new pollution controls. They also 

make different assessments about the ability of underutilized existing generation, new capacity resources, 

and transmission upgrades to compensate for 

retired plants.

Introduction

Section

I
Environmental Regulation and Electric System Reliability 9

Further, some analysts predict that the need to retrofit 

large numbers of power plants with pollution control 

equipment within a short timeframe could leave some 

plants unavailable for a period after the deadline until 

their compliance obligations are met. This is particularly 

a concern for Air Toxics requirements, which will take 

effect in 2015. 

The result, according to some analysts, could be 

power shortages in some regions of the country that 

would create hardships for consumers and damage the 

economic recovery. However, other analysts contend 

that reliability concerns are unfounded or at the least 

overstated because under-utilized natural gas capacity, 

transmission from neighboring regions, and other 

resources are sufficient to compensate for the expected 

coal retirements. According to this view, even if there are 

legitimate localized reliability concerns, these concerns 

can be mitigated through a variety of technical, policy, 

and regulatory approaches. 

Several of the EPA regulations that may have the greatest 

impact on coal plant retirements have not yet been 

finalized. However, with the issuance of recent EPA 

proposals for air, 

water, and waste 

regulations, including the 

March 16, 2011 Utility Air Toxics Rule proposal and the 

March 28, 2011 proposal on cooling water intake structures, 

the details are becoming clearer. These recent proposals 

provide some additional clarity on how new environmental 

regulations will affect power generation planning. 

This report summarizes the current state of knowledge 

about challenges facing the electric power sector as 

it seeks to maintain reliability without jeopardizing 

important progress on public health and environmental 

protections. Section II of this report describes major 

market factors and regulations affecting the power sector 

and Section III summarizes and provides insights on 

key studies that attempt to predict the impact of EPA 

regulation and other variables. Section IV identifies 

strategies for mitigating reliability concerns and discusses 

the roles of regulators and stakeholders in facilitating a 

smooth power sector transition. The report concludes 

with a series of findings and recommendations on how 

best to meet these challenges.

This report summarizes the current 

state of knowledge about challenges 

facing the electric power sector as 

it seeks to maintain reliability without 

jeopardizing important progress 

on public health and environmental 

protections.
Section

II

Overview of 

Challenges

Facing the U.S. 

Electricity Sector 

In the next decade, our nation’s electric power 

system is expected to transition to a more modern 

fleet of generators. A key element of this anticipated 

transformation is the retirement of a significant 

amount of older and increasingly uneconomic

coal-fired capacity. The transition itself will be driven 

by a range of factors, including low natural gas 

prices, state renewable portfolio standards, and the 

possibility of some form of future regulation

of greenhouse gases. In addition, many coal plants 

already face economic challenges as they near the 

end of – and in some cases, exceed – their design life 

expectancies. 
Environmental Regulation and Electric System Reliability 11

14 U.S. Energy Information Administration. Annual Energy Outlook (AEO) 2011. Natural Gas Supply, Disposition, and Prices. The EIA AEO 

2011 projects natural gas prices will be nearly $1.24/MMBtu lower, on average through 2030, than their AEO2010 estimate.

15 Colorado School of Mines. Potential Gas Committee. Potential Supply of Natural Gas in the United States. 2009.

16 U.S. Energy Information Administration. Natural Gas Consumption by End Use. Data released April 29, 2011.

17 Massachusetts Institute of Technology. The Future of Natural Gas: An Interdisciplinary MIT Study. Xii.

18 ICF International. 2010 Natural Gas Market Review, prepared for the Ontario Energy Board. August 2010.

Finally, forthcoming EPA regulations for air quality, 

cooling water, and coal combustion waste will put 

additional pressure on plants that don’t yet employ stateof-the-art pollution controls. It is difficult to determine the 

relative impacts of these factors, but a new era of low and 

stable natural gas prices—the result of a substantial increase 

in domestic supply—is expected to be an influential driver 

of electric power sector market conditions and resource 

choices for the next several decades. 

A. The Impact of 

Natural Gas Prices

The discovery of vast shale gas basins in the United 

States, combined with technological advances in 

horizontal drilling and hydraulic fracturing that make 

it possible to access these resources, has dramatically 

changed the domestic natural gas supply outlook 

(see Figure 1). As new shale gas resources have been 

developed in recent years, natural gas prices have 

declined (see Figure 2). They are now projected to remain 

at levels lower than during the previous decade.14

Domestic reserves of natural gas are projected to support 

more than 100 years of demand at present levels of 

consumption.15 Annual U.S. consumption of natural 

gas across all sectors currently totals approximately 22 

trillion cubic feet (Tcf); the electric sector accounts for 

roughly one-third of this total, or nearly 7 Tcf of annual 

demand.16 To give some sense of the current supply 

context, a recent MIT study titled The Future of Natural 

Gas estimates that approximately 400 Tcf of shale gas in 

the United States could be developed economically with 

gas prices at or below $6 per million British thermal units 

(MMBtu) at the well-head.17 ICF International, Inc. also 

recently estimated that almost 1,500 Tcf of total gas can 

be produced at prices below $5/MMBtu and that the 

same volume of shale gas alone could be produced at 

prices below $8/MMBtu.18

Natural gas plays an interesting role in the power sector’s 

changing supply outlook, as both a driver of coal plant 

retirements and a solution to potential resource and 

reliability concerns. Lower gas prices will make some 

existing coal-fired capacity uneconomic. They may also 

encourage utilities to increase capacity utilization at 

existing natural gas-fired plants and, where both types of 

units are available, dispatch natural gas plants in place 

of some coal plants. Natural gas has already increased 

$16

$14

$12

$10

$8

$6

$4

$2

$0

Jan-05

Aug-05

Mar-06

Oct-06

May-07

Dec-07

Jul-08

Feb-09

Sep-09

Apr-10

Nov-10

Jun-11

Jan-12

Aug-12

Historical Henry 

Hub Price

EIA Forecast 

Henry Hub Price

NYMEX Futures 

Henry Hub 

May 11, 2011

Figure 2: Projected Natural Gas Prices

Sources: U.S. Energy Information Administration. Short Term Energy 

Outlook. May 10, 2011. NYMEX Henry Hub Natural Gas Futures. 

May 11, 2011.

0

5

10

15

20

25

30

11%

14%

20%

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28%

2%

9%

8%

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45%

8%

8%

22%

1%

7%

7%

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035

Net Imports

Shale Gas

Non-associated Onshore

Non-associated Offshore

Tight Gas

Coalbed Methane Alaska Associated with oil

History Projections

Figure 1: Forecasted 

U.S. Natural Gas Production

Source: U.S. Energy Information Administration. History: Annual 

Energy Review 2009. Projections: Annual Energy Outlook 2011.
12 Environmental Regulation and Electric System Reliability

19 U.S. Energy Information Administration. Annual Energy Outlook 2011. Electricity Supply, Deposition, Prices, and Emissions.

20 Database of State Incentives for Renewables & Efficiency. Summary map of RPS policies. www.dsireusa.org. Accessed May 2011.

its share of the generation fuel mix during the past few 

years, displacing some coal generation.19 In addition, as 

coal plants retire due to changing economics, low gas 

prices may provide strategic opportunities to transition to 

gas-fired capacity at a relatively low cost. 

Projections of future low natural gas prices are also changing 

the market dynamics for investment in renewable and 

nuclear power technologies, which have relatively higher 

capital costs. In an environment of low and stable gas 

prices, these low- and no-carbon sources may have difficulty 

competing with natural gas absent further incentives or 

policy interventions (e.g., renewable portfolio standards). 

B. Current and Potential 

Future Energy Policies

State renewable electricity standards have spurred 

continued growth in clean energy resources, despite low 

natural gas prices. Such standards, together with federal 

policies to incentivize clean energy, also impact electric 

sector investment decisions. As of January 2011, twentynine states and the District of Columbia have a Renewable 

Electricity Standard (RES) or similar policy to promote 

utility investment in renewable energy, energy efficiency, 

or other clean resources.20 Legislation to establish a 

national renewable electricity standard or clean energy 

standard has also been introduced at the federal level. 

Some of these proposals would include nuclear and 

advanced fossil fuel-based systems with carbon capture 

and sequestration. The Obama Administration has 

proposed this latter type of clean energy standard, which 

would incorporate a broader portfolio of generation 

resources, including natural gas (as opposed to a portfolio 

standard that is limited to renewables).

C. Forthcoming EPA

Regulations for the Electric 

Power Sector

EPA has already proposed multiple regulations for 

the power sector. These regulations will lead to capital 

investments in new technologies and pollution controls 

over the next fifteen or so years. The four rules that are 

expected to have the greatest impact are the Transport 

Rule, the Utility Air Toxics Rule to ensure compliance with 

National Emission Standards for Hazardous Air Pollutants 

(NESHAP), Coal Combustion Waste Disposal Regulations 

(known as the coal ash rule), and Clean Water Act Section 

316(b) regulations for Cooling Water Intake Structures. 

With the exception of the ash rule, EPA has been directed 

by the courts to conduct these rulemakings in response to 

litigation over earlier rulemakings. 

Clean Air Transport Rule

On August 2, 2010, EPA proposed a replacement for 

the Clean Air Interstate Rule (CAIR), which had been 

previously remanded in a 2008 court decision. The 

new Clean Air Transport Rule (CATR), which EPA 

expects to finalize in the summer of 2011, will require 

31 states and Washington, DC to meet new state-level 

pollution limits for sulfur dioxide (SO2

) and nitrogen 

oxides (NOX). Specifically, power plant emissions of 

SO2

 will have to be reduced by 71 percent from 2005 

levels by 2014 and power plant NOX emissions will have 

to be reduced by 52 percent from 2005 levels. These 

reductions are intended to ensure compliance with ozone 

and fine particulate matter (PM) National Ambient Air 

Quality Standards (NAAQS). The new Transport Rule 

limits interstate trading of emission allowances, while 

the remanded CAIR had allowed unrestricted trading 

between states. The new Transport Rule also differs from 

the CAIR proposal in that it precludes previously banked 

allowances from being used to demonstrate compliance 

with its new caps.
Environmental Regulation and Electric System Reliability 13

21 U.S. EPA. Clean Air Interstate Rule. http://www.epa.gov/cair.

22 Fozard, Colette. “Interstate Air Pollution Rule Granted Temporary Stay of Execution.” Energy Legal Blog. http://www.energylegalblog.com/

archives/2009/01/05/1311.

23 Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone. 75 Fed. Reg. 45,210 (Aug. 2, 2010).

(Transport Rule).

24 Clean Air Act Section 112(n)(1)(A)

25 65 FR 79,825

26 70 FR 15,994 

27 U.S. EPA. Clean Air Mercury Rule. http://www.epa.gov/camr/basic.html.

28 State of New Jersey v. EPA, 517 F.3d 574, 583 (D.C. Cir. 2008), cert. denied, 129 S. Ct. 1308, cert. dismissed, 129 S. Ct. 1313 (2009).

29 Davis, Tracy. “DC Circuit Orders Immediate Tightening of Mercury Control Rules.” Energy Legal Blog. http://www.energylegalblog.com/

archives/2008/03/25/1354.

The previous CAIR proposal, which EPA issued on March 

10, 2005, would have permanently capped power sector 

emissions of SO2

 and NOX in the eastern United States. 

The purpose of CAIR was to reduce the interstate transport 

of pollutants that contribute to non-attainment of fine 

PM and ozone NAAQS. At the time it was proposed, the 

health and environmental benefits of this rule were valued 

at 25 times the estimated cost of compliance.21

In July 2008, the US Court of Appeals ruled that CAIR’s 

tradable emission allowance scheme was “fatally flawed” 

and violated the Clean Air Act (CAA) because it could 

not ensure that trading would not contribute to another 

state’s non-attainment of the NAAQS. In other words, 

the Court found that CAIR’s trading provisions did not 

guarantee the ambient air quality improvements needed 

to achieve the NAAQS in downwind areas. While the 

court remanded CAIR, it ruled that CAIR would remain 

in effect until the EPA developed a lawful alternative.22

As proposed on August 2, 2010, the Transport Rule would 

regulate NOX and SO2

 emissions from electric generating 

units in the East under a regional cap-and-trade program 

with limited interstate trading.23 New NOX and SO2

 caps 

would first become binding in 2012 (called “Phase I” in the 

Transport Rule), and power plants in a limited subset of 

states would become subject to more stringent “Phase II” 

caps on SO2

 emissions beginning in 2014. 

The compliance options expected to be deployed under 

the Transport Rule’s SO2

 caps include low-sulfur coal, 

wet and dry scrubbers—known as flue gas desulfurization 

(FGD) systems—and dry sorbent injection (DSI) with 

sodium-based sorbents, such as sodium bicarbonate 

or Trona. Expected options for compliance with the 

Transport Rule’s NOX caps include low NOX burners, 

selective catalytic reduction (SCR), and selective noncatalytic reduction (SNCR). The Transport Rule is 

intended to address interstate contributions to violations 

of three specific NAAQS: the 1997 ozone NAAQS and 

the 1997 and 2006 NAAQS for PM2.5. EPA may soon 

issue updated and more stringent NAAQS for both of 

these criteria pollutants, and subsequently may issue 

additional Transport Rules for the control of interstate 

NOX and SO2

 emissions after 2014. These successors 

to the Transport Rule could be implemented within a 

range of deadlines around 2016-2018, depending on 

how quickly EPA makes key determinations and how the 

agency interprets certain timing provisions of the CAA. 

Utility Air Toxics Rule

The 1990 Clean Air Act Amendments include a section 

(Section 112) on hazardous air pollutants that require 

EPA to regulate the sources of 90 percent of such 

emissions by 2000.24 Because electric generating units 

were also to be regulated under other sections of the 

Act in ways that would provide some co-benefits in 

hazardous air pollutant reductions, Congress required 

a study and finding to determine if air toxics from 

electric generating units remained a significant source of 

concern. In December of 2000, EPA determined that it 

was “appropriate and necessary” to regulate coal and oilfired power plants under Section 112.25

In 2005, however, EPA reversed course and found that it 

was neither appropriate nor necessary to regulate power 

plants under Section 112. At that point EPA removed 

electric generating units from the list of sources subject 

to 112.26 In a March 15, 2005 rulemaking known as the 

Clean Air Mercury Rule (CAMR), mercury was delisted 

as a hazardous air pollutant (HAP) and a cap-and-trade 

policy was enacted under Section 111 of the Clean 

Air Act with the aim of reducing mercury emissions 

from coal-fired power plants by 70 percent (i.e., from a 

national baseline of 48 tons to 15 tons by 2018).27 On 

February 8, 2008, the US Court of Appeals for the DC 

Circuit found that EPA violated the CAA by delisting 

electric generating units from the Act’s toxics provisions 

and vacated the CAMR.28,29

EPA has already proposed multiple 

regulations for the power sector and 

has been directed by the courts to 

conduct these rulemakings in response 

to litigation over earlier rules.
14 Environmental Regulation and Electric System Reliability

30 EPA modeling of the Utility MACT rule using IPM runs “ToxR Base Case” and “ToxR Policy Case”. Found at http://www.epa.gov/airmarkt/

progsregs/epa-ipm/toxics.html. Accessed March 22, 2011.

Relevant Air Pollution Control Technologies

• Activated Carbon Injection (ACI): ACI 

is a commercially available technology that, in 

combination with particulate controls, removes 

mercury from the exhaust stack of a power plant. ACI 

is currently employed at many units to comply with 

state regulations for mercury control. 

• Dry Sorbent Injection (DSI): DSI is a 

commercially available technology (similar to ACI 

for mercury) that, in combination with particulate 

controls, has been shown to significantly reduce 

emissions of acid gases, as well as sulfur dioxide 

(SO2), without a more expensive scrubber. DSI has 

significantly lower capital cost than a scrubber, but 

its operating costs are non-trivial due to the cost of 

sorbent (e.g., Trona). This feature may make DSI 

best suited for certain fuels (e.g., coals with lower 

sulfur and chlorine content) and/or for smaller, 

less frequently operated units. DSI is currently 

employed on a number of existing power plants 

and power companies have announced further 

installation plans. Although there is not a large 

body of performance data on acid gas removal with 

DSI, commercial and demonstration projects have 

shown that this technology can achieve significant 

reductions in acid gas emissions, at levels on par 

with Toxics Rule standards.

• Particulate controls: Particle pollution can 

be captured by particulate controls installed on the 

exhaust stack of a power plant. Existing power plants 

generally have some particulate controls, usually 

electrostatic precipitators (ESP) or fabric filters/

baghouses. Depending on the other controls in use 

and on the type of fuel burned, compliance with the 

PM limit in the Toxics Rule may require upgrades or 

the addition of a polishing or full fabric filter.

• Scrubber or Flue Gas Desulfurization 

(FGD): FGD is a commercially available technology 

that removes SO2

 as well as acid gases from power 

plant exhaust. More than half of existing coal-fired 

generating units currently have a scrubber installed 

for SO2 control. Variations include wet scrubbers 

and dry scrubbers. Wet scrubbers are the most 

expensive pollution control technology expected to 

be used for the new air rules.

• Selective Catalytic Reduction (SCR): SCR is 

a commercially available technology that removes 

nitrogen oxides (NOX) from power plant exhaust. It 

is currently installed at many facilities, particularly 

in the eastern states. In combination with a wet 

scrubber, SCR also removes mercury.

Add DSI Existing Scrubbers

Acid Gas MACT Compliance

Add Dry Scrubber

Retrofits regardless

 of MACT

Figure 3: Projected Control Strategies for Achieving 

Acid Gas Limits

Source: U.S. Environmental Protection Agency IPM Data Files for Utility Air Toxics Rule Base and 

Policy Cases30
Environmental Regulation and Electric System Reliability 15

On March 16, 2011, EPA proposed emission standards 

for electric generating units under Section 112, consistent 

with the court ruling. The court ordered a final rule to be 

issued by November 16, 2011. 

The proposed Utility Air Toxics Rule sets emission 

limitations for three pollutants: mercury, particulate 

matter, and hydrogen chloride (HCl) based on the 

average emission rates actually achieved by the top 12% 

of performers. The standards were designed to assure the 

achievement of required reductions in the larger category 

of air toxics. For dioxin/furan, EPA proposed work 

practice standards based on good combustion practices.

To comply with the Utility Air Toxics Rule, it may be 

necessary to upgrade or retrofit particulate controls 

and add activated carbon injection to reduce metallic 

toxics at many units. In addition, to meet the acid gas 

HCl limit at uncontrolled plants, it may be necessary 

to choose between a wet scrubber, dry scrubber, and 

dry sorbent injection.31 Specifically, in order to meet 

the requirements of the Utility Air Toxics Rule, EPA’s 

modeling projects 56 GW of DSI installed in addition 

to the 9 GW in the base case (for a total of 65 GW) and 

that 22 GW of Dry FGD will be installed in addition to 

the 4 GW projected to retrofit in the base case (for a total 

of nearly 27 GW of dry scrubber installs). EPA projects 

the Utility Air Toxics Rule will not require installation 

of any additional Wet FGD beyond 6 GW projected to 

retrofit in the base case to meet the Transport Rule.32 If 

existing pollution controls are included in the count, 

EPA projects a total of 175 GW of wet scrubbers, 53 GW 

of dry scrubbers, and 65 GW of DSI will be in place 

when compliance with the Air Toxics Rule is achieved.33

In terms of capital costs, the most expensive control 

technology for compliance with the Utility Air Toxics 

Rule is a wet scrubber, as seen in Figure 5 (page 18). 

Capital costs for an alternative, dry sorbent injection, are 

significantly lower. On a levelized cost basis, however, 

the difference is far less significant. Figure 4 shows that 

the on-going costs for dry sorbent injection, including 

costs to ship and store large amounts of chemical 

sorbent, approach the annualized cost of a wet scrubber. 

EPA estimates the average annualized cost of compliance 

with the Utility Air Toxics Rule at $10.9 billion. 

Estimated net benefits for this rule—taking into account 

health and other benefits, as well as compliance costs—

are estimated to range from $48 billion to $129 billion 

per year (in 2007 dollars), according to EPA.34

Coal Combustion Wastes (Ash) 

Disposal Regulations

On June 21, 2010, EPA published a proposed rule to take 

comment on whether or not coal combustion wastes 

should be treated as hazardous waste.35 One option 

would regulate ash as a special waste under subtitle C of 

the Resource Conservation and Recovery Act (RCRA), 

which sets guidelines for the management of solid waste. 

(Currently, coal combustion waste is not covered by 

subtitle C.) Within the hazardous waste regulations, 

the coal ash would be classified as a “special waste” to 

31 Some companies suggest that DSI is not a proven option for HCl MACT compliance because there is still limited public data on HCl 

removal from full-scale DSI applications. On the other hand, a recent study by a national engineering firm endorsed DSI for HCl removal. 

See Lipinski, G., J. Leonard, C. Richardson. Assessment of Technology Options Available to Achieve Reductions of Hazardous Air 

Pollutants. URS Corporation. April 2011.

32 U.S. EPA Base Case pollution control installations include those retrofits projected to occur in the period 2010 through 2013 to comply 

with the 2012 and 2014 SO2 and NOX caps in the Transport Rule.

33 Data on the number of retrofits and existing controls was calculated from EPA data files from EPA IPM runs to support the Utility Air 

Toxics Rule. Files: ToxR Base Case and ToxR Policy Case. Found at http://www.epa.gov/airmarkets/progsregs/epa-ipm/toxics.html. Accessed 

April 1, 2011.

34 U.S. Environmental Protection Agency. Fact Sheet: Proposed Mercury and Air Toxics Standards. http://www.epa.gov/airquality/

powerplanttoxics/pdfs/proposalfactsheet.pdf.

35 Unofficial proposals were issued May 4, 2010. For additional information and the proposed rule see: http://www.epa.gov/osw/nonhaz/

industrial/special/fossil/ccr-rule/index.htm

300 MW

500 MW

700 MW

16

14

12

10

8

6

4

2

0

Wet Scrubber DSI

Levelized Cost (2006$/kW)

Retrofit Levelized Costs

Figure 4: Comparison of Annual Costs of 

a Wet Scrubber vs. Dry Sorbent Injection 

Source: Technology cost assumptions used in BPC modeling of 

EPA regulation scenarios, with levelized capital, fixed and operating 

costs of flue gas desulfurization (wet scrubber), compared with 

representative cost of dry sorbent injection. Site-specific costs are 

dependent on various factors including location, fuel-type, and 

complement of controls. DSI costs are shown for units less than or 

equal to 300 MW, based on BPC conservative modeling assumption 

to only offer DSI for such smaller units burning low sulfur coal.
16 Environmental Regulation and Electric System Reliability

avoid the stigma associated with a hazardous designation 

and to allow continued beneficial uses of coal ash.36

This option would regulate ash disposed in landfills 

and surface impoundments from all electric utilities 

and independent power producers. Coal ash would be 

regulated from the point where it is generated to final 

disposal. This means generators and transporters, as well 

as facilities that manage, treat, or store coal combustion 

waste would be subject to regulation. 

A second option would instead regulate coal ash under 

subtitle D of RCRA. Under this proposal, EPA would 

establish performance standards for landfills and surface 

impoundments where coal combustion waste is disposed, 

but it would not regulate its generation, transport, or predisposal treatment. Under subtitle D, EPA does not have 

authority to enforce its requirements. 

In practice, regulation under either subtitle C or subtitle 

D will require many of the same control technologies 

(see Table 1) including modifications to remove solids, 

line surface impoundments, and improve wastewater 

treatment. The main difference is whether or not the 

requirements are state vs. federally enforceable. While 

subtitle C would establish federally enforceable “special 

waste” provisions, the subtitle D option would establish 

self-implementing requirements for “non-hazardous 

waste” that are not federally enforceable. In the latter 

case, enforcement actions could only be triggered by 

citizen suits (including suits brought by states). 

The proposed rule estimates a range of regulatory costs: 

$3–$20 billion over the life of the program or average 

annualized costs ranging from $236 million to $1.5 

billion. There is some concern that designating coal 

36 Presently, coal combustion waste is used for a number of beneficial uses. Coal ash has a number of agricultural and highway applications 

and gypsum products are frequently used in wallboard production.

Table 1. Key Differences between Subtitle C and Subtitle D Options

SUBTITLE C SUBTITLE D

Effective Date Timing will vary from state to state, 

as each state must adopt the rule 

individually-can take 1 - 2 years or more 

Six months after final rule is 

promulgated for most provision: 

certain provisions have a longer 

effective date

Enforcement State and Federal enforcement Enforcement through citizen suits; 

States can act as citizens.

Corrective Action Monitored by authorized States and EPA Self-implementing

Financial Assurance Yes Considering subsequent rule using 

CERCLA 108 (b) Authority

Permit Issuance Federal requirement for permit issuance 

by States

No

Requirements for Storage, 

Including Containers, Tanks, 

and Containment Buildings

Yes No

Surface Impoundments Built 

Before Rule is Finalized

Remove solids and meet land disposal 

restrictions; retrofit with a liner within five 

years of effective date. Would effectively 

phase out use of existing surface 

impoundments

Must remove solids and retrofit with 

a composite liner or cease receiving 

ash within 5 years of effective date and 

close the unit

Surface Impoundments Built 

After Rule is Finalized

Must meet Land Disposal Restrictions 

and liner requirements. Would 

effectively phase out use of new surface 

impoundments.

Must install composite liners. No Land 

Disposal Restrictions

Landfills Built Before Rule is 

Finalized

No liner requirements, but require 

groundwater monitoring

No liner requirements, but require 

groundwater monitoring

Landfills Built After Rule is 

Finalized

Liner requirements and groundwater 

monitoring

Liner requirements and groundwater 

monitoring

Requirements for Closure and 

Post-Closure Care

Yes; monitored by States and EPA Yes; self-implementing

Source: U.S. Environmental Protection Agency
Environmental Regulation and Electric System Reliability 17

combustion waste as “special waste” may further increase 

costs if it has the effect of constraining beneficial 

uses of coal ash, such as in wallboard and concrete. 

Materials that cannot be put to use will require disposal 

and, instead of representing a source of revenue, will 

contribute to additional costs. When factoring in the 

environmental benefits of the regulation, EPA estimates 

the average annualized net benefits of its rule will range 

from approximately $193 million to $18 billion. 

Clean Water Act Section 316(b) Cooling

Water Intake Structures

Section 316(b)of the Clean Water Act (CWA) requires 

EPA to develop regulations on cooling water intake 

structures at electric generating units (EGU) and other 

industrial facilities that use large amounts of cooling 

water for purposes of reducing the mortality of aquatic 

species due to impingement and entrainment.37,38

Specifically, the Act requires EPA to demand that 

cooling intake structures use the “best technology 

available for minimizing adverse environmental 

impact.”39 EPA originally promulgated these regulations 

in three phases: Phase I (covered in a 2001 rulemaking) 

regulates new facilities (both EGUs and industrial 

facilities); Phase II (issued in 2004) regulates 

existing EGUs that use large amounts of cooling 

water; Phase III (issued in 2006) establishes 

requirements for other facilities that use cooling 

water intake structures.40

The Phase I regulations require the use of 

closed-cycle cooling systems on new facilities. 

The Phase II regulations on existing facilities did 

not, however, establish a similar requirement. 

Instead, EPA set performance standards based 

on mortality rates. These standards could be met 

through a variety of technologies and would be 

chosen by cost-benefit analysis.41

In Entergy Corp. v. EPA, environmental groups and 

several states filed suit against the Phase II regulation 

alleging that the decision to not require closed-cycle 

cooling violated the Clean Water Act. In 2007, the 

Second Circuit Court ruled that the use of cost–benefit 

analysis to determine best technology available (BTA) is 

inadmissible under Section 316(b) and remanded several 

provisions of the rule. EPA subsequently suspended the 

Phase II regulations.42

After appeals by EPA and industry, the case went to 

the Supreme Court, which in April 2009 reversed and 

remanded the Second Circuit’s decision, allowing the 

BTA to be determined by cost–benefit analysis.43 The 

Supreme Court ruling did not hold that 316(b) requires

cost–benefit analysis, only that it could be used. 

At present, EPA’s earlier regulations remain suspended, 

which means that compliance determinations are 

being decided on a case-by-case basis by the permitting 

authority, usually the state. EPA’s new proposed 

rulemaking on March 28, 2011 will address these and 

other issues from court rulings on the earlier Phase I, 

II, and III rulemakings. Under the Clean Water Act’s 

Section 316(b), EPA has considerable discretion with 

respect to the application of cooling water constraints 

that minimize entrainment and impingement, and the 

Agency’s recent proposal draws on this flexibility. 

37 33 U.S.C. § 1326(b).

38 Impingement is when fish are pinned against water intake screens or other parts at the facility. Entrainment is when aquatic organisms are 

drawn into cooling water systems.

39 For more information see U.S. EPA. Water: Cooling Water Intakes (316b). Basic Information. http://www.epa.gov/waterscience/316b/basic.htm.

Phase II addresses large existing power plants that are designed to withdraw 50 million gallons per day or more and that use at least 25 

percent of their withdrawn water for cooling purposes only.

40 Affected facilities have a design intake flow threshold of greater than 2 million gallons per day and withdraw at least 25 percent of water for 

cooling purposes. See http://www.epa.gov/waterscience/316b/phase3/ph3-final-fs.html.

41 Entergy Corp. v. Riverkeeper, Inc. 556 U.S. (2009)

42 72 FR 37107

43 Ibid. 
18 Environmental Regulation and Electric System Reliability

Facilities with design intake above 2 million gallons 

per day, that withdraw at least 25 percent of their 

water from an adjacent water body for cooling, must 

submit information and limit the number of fish killed 

by being pinned against intake screens or equipment 

(impingement) and sucked into the water intake 

system (entrainment). Many existing facilities may 

have to install screens, make modifications to existing 

technology or take measures to reduce intake velocity. 

The EPA proposal includes additional requirements 

for facilities that use very large quantities of water 

(i.e., actual water intake above 125 million gallons per 

day). Facilities that exceed this threshold must submit 

additional information regarding entrainment, including 

a study that compares the costs and benefits of installing 

a cooling tower versus alternative technology. Lastly, the 

proposed water rule requires the use of cooling towers, 

or their equivalent, for any new unit capacity additions 

built at an existing facility (the requirement does not 

apply to capacity replacements).

Relevant Pollution Control

Technologies

Although many existing plants will comply with some or 

all of the various EPA regulations based on their current 

configuration and already installed controls, some will 

require new pollution controls. Table 2 identifies some 

of the control technologies expected to be used for 

compliance with upcoming EPA regulations.44 Figure 5 

compares the relative capital cost to install such 

technologies on existing electric generating units. 

EPA Regulations and Reliability Concerns

The timeline for forthcoming EPA regulations has 

prompted concern that grid reliability issues could arise 

in some parts of the country as utilities comply with 

pollution regulations. These concerns center on the 

combined effects of new EPA rules on plant retrofits and 

retirements and on the condensed compliance timeline 

for the Utility Air Toxics Rule, in particular. Figure 6 

lays out a likely timeline for compliance with these 

regulations. The figure shows that 2014 and 2015 are 

likely to be the most constrained years as power plant 

owners prepare to comply with the Air Toxics Rule. 

44 For additional information about control technologies see Lipinski, G., J. Leonard, C. Richardson. Assessment of Technology Options 

Available to Achieve Reductions of Hazardous Air Pollutants. URS Corporation. April 2011. 

Staudt, James E. and M.J. Bradley & Associates. Control Technologies to Reduce Conventional and Hazardous Air Pollutants from CoalFired Power Plants. March 31, 2011.

Fessenden, Jamie. NESCAUM (Boston, MA). Multi-pollutant Emission Reduction Technology for Small Utility Boilers. Presentation to 

Lake Michigan Air Directors Consortium, Innovative Industrial Source Control and Measurement Technologies Workshop. March 24, 2010.

Under the Clean Water Act’s Section 316(b), 

EPA has considerable discretion with respect to 

the application of cooling water constraints 

that minimize entrainment and impingement.

Figure 5. Estimated Retrofit Capital Costs of Relevant Technologies

0

100

200

300

400

500

600

Wet

scrubber

DSI Baghouse SCR ACI Ash Cooling

Tower

Alternate

Water

Capital Cost (2006$/kW)

Retrofit Capital Costs

300 MW

500 MW

700 MW

Note: The capital cost of a dry scrubber is estimated to be 10-20% lower than that of a wet scrubber. 

DSI costs are shown for units less than or equal to 300 MW, based on BPC conservative modeling assumption to only offer DSI for such 

smaller units burning low sulfur coal. 

Source: Technology capital cost assumptions used in BPC modeling of EPA Regulation scenarios.
Environmental Regulation and Electric System Reliability 19

45 The acid gases hydrogen chloride (HCl) and hydrogen fluoride (HF) are regulated under Section 112 of the Clean Air Act. By contrast, SO2

is regulated as a conventional “criteria” pollutant under the NAAQS provisions of the Act.

Figure 6. Timeline of EPA Regulations Impacting the Power Sector 

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

AIR

TRANSPORT RULE

AIR TOXICS

GHG STANDARDS

WATER

316(B) INTAKE

WASTE

COAL WASTE/ASH

PHASE I PHASE II

CAPS

EXISTING UNITS: PENDING EPA/STATE RULEMAKINGS NEW UNITS,

PENDING

POSSIBLE PHASE III, PENDING REVISED NAAQS

NATIONAL EMISSION STANDARDS

FIVE YEAR PHASE-IN, PENDING RULE

PENDING FINAL RULE

Table 2. EPA Regulation and Expected Control Technologies

Pollutant/Issue Control Technologies/Measures 

Acid Gases:45 Air Toxics HCl & HF, 

plus Sulfur Dioxide (SO2

) 

Wet scrubber 

or Dry scrubber + Particulate Controls 

or Dry Sorbent Injection (DSI) + Particulate Controls

Metallic Toxics/Particulate Matter Baghouse/Fabric Filter or Electrostatic Precipitator (ESP) 

Mercury Activated Carbon Injection (ACI) + Particulate Controls

or Wet scrubber + Selective Catalytic Reduction (SCR)

NOX Selective Catalytic Reduction (SCR)

or Selective Non-Catalytic Reduction (SNCR), low-NOX

 burners, etc

Coal Ash Dry ash handling + ash pond liners, etc

Cooling Water Intake Screens, barrier nets, low velocity caps, etc 

or Cooling Tower

GHG Performance Standards Efficiency upgrades or, potentially, biomass co-firing
a. Current Trends in the Power Sector

As has already been noted, a number of market 

factors are likely to lead to the retirement of a 

significant number of coal-fired power plants, 

even absent EPA regulation. These include:

• Aging coal-fired power plants. About 33 

percent of the existing coal-fired fleet is over 40 

years old, and most of this aging capacity lacks 

environmental controls. These units tend to be 

small and relatively inefficient, and therefore do 

not operate near full capacity. These units are likely 

to become increasingly uneconomic. 

Results of 

Power Sector 

Analysis

Section

III
Environmental Regulation and Electric System Reliability 21

46 North American Reliability Corporation. 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. 

Environmental Regulations. October 2010. Page 8.

47 See Appendix B for additional information about BPC modeling using ICF’s Integrated Planning Model.

• Low gas price projections. Recent advances in drilling 

technology for natural gas have lead to a dramatic 

reassessment of the magnitude of potentially available 

U.S. natural gas resources, and an associated decline 

in projected prices. Although coal-fired power plants 

have historically enjoyed a cost advantage over natural 

gas-fired plants, this cost advantage is diminishing, and 

older, inefficient plants are likely to become increasingly 

uneconomic as a result of gas prices alone. 

• Ongoing uncertainty about the future regulation of 

carbon dioxide (CO2

) makes it even less likely that 

companies will invest in aging plants. 

Consideration of these factors alone has led some 

analysts to project significant coal plant retirements 

over the next decade, even absent EPA regulation. 

For example, EEI’s January 2011 analysis projected 

22 GW of coal retirements in the reference case (i.e., 

with no new regulation) by 2015. In its October study, 

NERC reported that 13 GW of upcoming retirements 

were already announced or committed, prior to EPA’s 

proposals for Utility Air Toxics and cooling water rules.46

This section summarizes the projected impacts of 

forthcoming EPA regulations on retirements in the 

power sector. In particular, it reviews findings from 

several existing studies along with some key underlying 

assumptions, with a focus on results pertaining to plant 

retirements and implications for resource adequacy. 

BPC review of existing studies and our own modeling 

suggests that the actual number of retirements due to 

EPA regulations will be at the lower end of the range of 

published projections.47 This is primarily because most 

analyses assume that the EPA regulations (particularly 

316(b) and Utility Air Toxics) will require much more 

costly controls than EPA’s recent proposals indicate. 

Analyses of resource adequacy also tend to use these 

retirement projections in combination with capacity 

projections that do not reflect how market drivers will 

influence the construction of additional capacity (or 

demand side management). As a result, these studies are 

likely to overstate risks to resource adequacy. 

B. Studies on the Impact of EPA

Regulations

A number of studies, compared in Table 3, have 

evaluated the potential retirements that are likely to 

result from market conditions and forthcoming EPA 

regulations. These studies vary in terms of the regulations 

they cover; the assumptions they make about the 

stringency, timing, and cost of regulations; and the 

general methodology and other market assumptions they 

apply. It is important to consider the implications of 

each of these factors.

Because some studies do not include an estimate of 

“business-as-usual” (BAU) retirements in the absence of 

EPA regulations, and because the studies make different 

assumptions about electricity demand, fuel prices, and 

other variables that impact the number of retirements 

in the baseline case, it is not possible in many cases to 

determine the incremental number of retirements being 

projected as a result of EPA regulations. Therefore, BAU 

retirements are included in the total coal retirements 

reported in the table below. 

Regulations covered

Studies have also differed with respect to the scope 

of environmental regulations examined. A number of 

studies look only at the potential impact of upcoming 

air emissions rules (e.g., the Transport Rule and Utility 

Air Toxics Rule), while others also evaluate the impact of 

regulatory scenarios for cooling water, coal ash, tighter 

NOX requirements to incorporate NAAQS revisions, and/

or future greenhouse gas constraints. EPA’s modeling for 

the Utility Air Toxics Rule, the CRA and PIRA studies, 

and some of the EIA AEO2011 EPA regulation sensitivity 

runs, are all limited to the Transport Rule and Utility 

Air Toxics Rule. The Credit Suisse analysis and an EIA 

AEO2011 run include tighter NOX requirements beyond 

the Transport Rule, while the Brattle Group also looks at a 

scenario that includes the water rules. The modeling from 

BPC and EEI referenced in Table 3 includes EPA rules 

on air (Transport Rule, Utility Air Toxics Rule, and future 

NOX), water, and ash. The ICF analysis quoted in the table 

includes air, water, and ash, plus a CO2

 price. 

Based on a review of studies and internal BPC analysis, 

as well as recent EPA proposals, we conclude that the 

most important regulatory driver of projected coal plant 

retirements, and hence of possible reliability concerns, 

is the Utility Air Toxics Rule. But other non-regulatory 

factors, including low natural gas prices, may be as 

important. The uncertainty regarding future carbon 

constraints, even without an immediate regulatory driver, 

is also significant as it may lead some plant operators to 

forego life-extending pollution control investments on 

inefficient coal plants. Cooling water and ash regulations 

will increase costs for some facilities, but are not expected 
22 Environmental Regulation and Electric System Reliability

Table 3. Comparison of Coal Retirements from Selected Studies and Scenarios

Study Regulations Included Projected Retirements Details

EIA AEO2011

April 2011

TR, Mercury

TR, Air Toxics, NOX

14-18 GW total

19-45 GW total

The high ends represent retrofit cost recovery in 5 yrs vs 

20. “TR, Air Toxics, NOX

” assumes wet FGD & SCR on 

each unit. Nat gas price below AEO2011 (≈$4/mmBtu) 

brings second case retirements up to 40-73 GW. 

EPA

March 2011

TR, Toxics 23 GW total 

(including 10 GW 

incremental)

Modeling for Utility Air Toxics Rule (Toxics) proposal; 

Transport Rule (TR) included in the baseline and not 

in the incremental retirements.

BPC

March 2011

TR, Toxics, 

Coal Ash, 316(b), NOX

29-35 GW total 

(15-18 GW incremental)

Assumes ACI, Fabric Filter and either wet FGD or DSI 

for Utility Air Toxics Rule. DSI only for units <300 MW 

with low sulfur coal. Cooling towers if >500 MGD 

design intake. Stricter NOX

 by 2018. Low end of the 

range results from higher AEO2010 natural gas price. 

EEI

January 2011

TR, Toxics, 

Coal Ash, 316(b), NOX

46-56 GW total 

(24-34 GW incremental)

Low end estimates reflect availability of lower cost 

compliance strategies for some units. EEI scenarios 

that include CO2

 price are excluded.

CRA

December 2010

TR, Toxics 39 GW total 

(includes 6 GW planned 

retirements)

Assumes ACI, fabric filter, and FGD for Utility Air 

Toxics Rule. Assumes AEO2010 natural gas price.

Brattle Group

December 2010

TR, Toxics

TR, Toxics, 316(b), NOX

40-55 GW total

(34-49 GW 2020 incremental)

 50-66 GW total

(44-60 GW 2020 incremental)

Doesn’t identify specific assumptions for each rule, but 

assumes SCR and scrubber on every coal unit by 2015. 

Cooling towers on all coal units by 2015 for 316(b).

ICF

December 2010

TR, Toxics, 

Coal Ash, 316(b), NOX

, 

+CO2

 price

70 GW total by 2018

(including 10 GW of 

announced retirements)

For Utility Air Toxics Rule, scrubber, ACI, and baghouse 

assumed for all units. For 316(b), cooling towers 

on units drawing from coastal and estuarine water 

bodies. Retirement estimates also reflect cap-and-trade 

program for CO2

 emissions that begins in 2018. 

NERC

October 2010

TR, Toxics, 316(b), 

Coal Ash

10-35 GW by 2018

(excludes 13 GW committed/

announced retirements, which 

may include non-coal units) 

Range reflects ‘Moderate’ and ‘Strict’ scenarios. Both 

assume cooling tower required for 316(b) the primary 

driver of retirements. For Utility Air Toxics Rule, both 

assume FGD (with SCR, or ACI + baghouse).

Credit Suisse

September 2010

TR, Toxics, NOX 60 GW total Assumes retirement of all small plants without SCR or 

FGD, and half of small plants with SCR but no FGD.

PIRA

April 2010 

TR, Toxics 30-40 GW total This analysis was quoted in a study by MJ Bradley/

Analysis Group.

Note: Coal retirement estimates are reported for 2015 if available. Total coal plant retirements, including those already announced and projected in the reference case, 

even absent EPA regulations, are reported, where available. Where available, incremental retirements resulting from the EPA rules are reported in parentheses. 

Sources: 

• U.S. Energy Information Administartion. Annual Energy Outlook 2011 With Projections to 2035. DOE/EIA-0383(2011). April 2011. Page 4. http://www.eia.gov/

forecasts/aeo/pdf/0383(2011).pdf

• U.S. Environmental Protection Agency. Regulatory Impact Analysis for the Utility MACT Proposed Rule. March 2011. http://www.epa.gov/ttn/atw/utility/

utilitypg.html

• Edison Electric Institute, with analysis performed by ICF International. Potential Impacts of Environmental Regulation on the U.S. Generation Fleet. January 2011.

• Charles River Associates. A Reliability Assessment of EPA’s Proposed Transport Rule and Forthcoming Utility MACT. December 2010.

• Brattle Group. Potential Coal Plant Retirements Under Emerging Environmental Regulations. December 2010.

• ICF International. ICF 2010 Quarter 4 Integrated Energy Outlook: Summary of Analysis Results. December 2010.

• North American Reliability Corporation. 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. Environmental Regulations. 

October 2010. (page 63 coal retirements plus page 8 committed/announced.)

• Credit Suisse. Growth from Subtraction: Impact of EPA Rules on Power Markets. September 2010.

• PIRA. EPA’s Upcoming MACT: Strict Non-HG Can Have Far-Reaching Market Impacts. April 2010.
Environmental Regulation and Electric System Reliability 23

48 EEI. Potential Impacts of Environmental Regulation on the U.S. Generation Fleet. January 2011. Page 13.

49 Federal Register Notice pre-publication. U.S. EPA Proposed Rule for Cooling Water Intake Structures, Section 316(b), Clean Water Act. 

March 28, 2011. Page 86.

50 However, industry sources have expressed concern that site-specific factors or permitting decisions may lead to cooling towers to reduce 

impingement and entrainment mortality at facilities below the threshold.

51 EEI specifies water policy assumptions of cooling towers required by 2022 for fossil and 2027 for nuclear. However, the IPM version 

supporting their analysis does not include a model year for 2022 and EEI chose to map the 2022 compliance date to the years 2020. EEI. 

Potential Impacts of Environmental Regulation on the U.S. Generation Fleet. January 2011. Page 12.

to have a strong influence on reliability because of long 

compliance periods and low numbers of retirements, 

beyond those units expected to retire due to other factors. 

For example, in their most stringent scenario, the NERC 

study estimates that only 388 additional MW retire as a 

result of the ash rule alone; EEI’s most stringent scenario 

for ash retires an incremental 6 GW by 2020.48 The impact 

of future NOX rules, which are yet to be proposed, will 

depend on how those rules are designed.

Strength and Timing of Regulations

Generally, the available studies assume that EPA will 

promulgate regulations at the stringent end of the 

spectrum of what is possible. This assumption proved 

least accurate in the case of the 316(b) cooling water 

proposed requirements, which were signed March 28, 

2011, after the referenced studies were undertaken. 

Those studies generally assumed that EPA’s rule would 

require all units to install cooling towers and move to 

closed cycle cooling systems. This assumption—which 

was not borne out in EPA’s actual proposal—adds as 

much as 40 GW of plant retirements to the projected 

outcome in some analyses. 

According to EPA, an estimated 70 percent of existing 

facilities are not expected to require a cooling tower 

under the new rule because their actual intake flow 

is below the threshold of 125 million gallons per day 

(MGD) and EPA expects lower cost screens and intake 

velocity measures to allow compliance with impingement 

mortality limits.49,50 Even for facilities with actual intake 

above 125 MGD, EPA’s proposed rule would require a 

cooling tower only if the state permitting authority made 

a site-specific determination that alternatives would not 

be adequate and also demonstrated that the benefits 

of a cooling tower outweigh the costs. Given typical 

valuations of fish death and ecosystem damage, it may 

prove difficult for states to demonstrate that benefits 

outweigh the cost of a new cooling tower, particularly if 

such a requirement would lead a plant to retire. 

Furthermore, the proposed rule requires states to 

consider the remaining useful life of the affected facility 

and any electric reliability impacts. Considering that the 

units most vulnerable to retirement are generally well 

past 40 years old, it seems even less likely that a caseby-case determination would require a cooling tower 

installation (with a deadline of 2022 for fossil units) on 

plants that would be, by then, another decade older than 

they are today. Thus, many of the remaining 30 percent 

of units which are subject to a cooling tower study may 

comply with less expensive alternatives and the 316(b) 

rule may not lead to significant retirements. 

The EEI study includes a sensitivity run “Alternative 

Water Case,” which requires cooling towers on a subset 

of existing units with design intake flow above 125 MGD 

that draw water from oceans, estuaries, and tidal rivers. 

Even this case, however, is likely more stringent than 

the EPA water rule. First, the EPA threshold is based on 

actual intake flow. By contrast, the EEI study used design 

intake flow—which is often considerably higher—as the 

threshold to determine which units might be affected. 

Second, even for facilities with actual intake flows above 

the EPA threshold, the state case-by-case determination 

is likely to avoid a cooling tower requirement for at least 

some, if not most, facilities. 

The referenced analyses also vary in terms of their 

assumptions about when cooling towers would be required. 

The NERC study appears to have the most aggressive 

timing assumptions. It assumes 316(b) will require cooling 

towers on all nuclear and fossil units by 2018. NERC 

projected that the 316(b) rule alone would result in about 

40 GW of retirements by 2018. The EEI study maintains 

the assumption that cooling towers are broadly required 

on existing units, but delays compliance until 2020 for 

fossil units and 2027 for nuclear units.51 As actually 

proposed, the EPA rule requires impingement controls, 

such as screens to be in place by 2020. If cooling towers are 

required, compliance is required by 2022 or 2027 for fossil 

and nuclear plants, respectively. 

An additional variable related to regulatory stringency 

involves the expectation of deeper NOX reductions 

beyond the first and second phases of the Transport Rule. 

Some analyses (including EIA, Brattle Group, Credit 

Suisse, and most EEI scenarios) assume that all units will 

be required to install selective catalytic reduction (SCR), 

the most costly control technology for NOX. However, 

many units are expected to meet their compliance 

obligations—under the Transport Rule for units in the East 

and under Best Available Retrofit Technologies (BART) 

requirements in the West — using lower cost technologies, 

such as selective non-catalytic reduction (SNCR) or low 
24 Environmental Regulation and Electric System Reliability

52 Sargent & Lundy. IPM Model – Revisions to Cost and Performance for APC Technologies: Dry Sorbent Injection Cost Development 

Methodology. August 2010. Found at http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/append5_4.pdf.

NOX burners. Beyond the current Transport Rule, future 

NAAQS revisions are expected to tighten NOX control 

requirements, but there is little indication that SCR would 

be required on all units nationwide. 

Technology and cost assumptions

Existing studies make different assumptions about 

the capital and operating costs of pollution control 

technologies and about the costs of providing replacement 

capacity. Moreover, these assumptions are not always 

clearly and explicitly identified even though they play an 

important role in determining the number of retirements 

projected. All else equal, studies that assume higher 

control costs predict higher levels of retirements.

A major discrepancy between various analyses is the 

assumed cost of compliance with Utility Air Toxics Rule 

limits for acid gases. This has a notable effect on their 

findings with respect to number of retirements, retrofits, 

and price impacts. With the exception of EPA, BPC, 

and two sensitivity runs in the EEI analysis, all other 

studies assume that compliance with acid gas limitations 

in the Utility Air Toxics Rule will require a scrubber—the 

most expensive control technology related to the suite 

of upcoming EPA regulations—by 2015. By contrast, 

EPA’s analysis in support of its Utility Air Toxics Rule 

includes DSI, in combination with particulate controls, 

as a compliance option to achieve acid gas limits. 

EPA’s assumed costs for DSI are based on a detailed 

engineering cost analysis.52

BPC analysis also assumes that DSI, in combination with a 

fabric filter, is an option to comply with the acid gas Utility 

Air Toxics Rule standard, but BPC makes a conservative 

assumption to limit DSI to smaller units less than 300 MW 

that burn low sulfur coal. The NERC analysis as well as 

the main policy scenarios in EEI’s January 2011 analysis 

do not allow compliance with DSI and instead require a 

scrubber on every unit for compliance with the Utility Air 

Toxics Rule. EEI does include a sensitivity run “Alternative 

Air Case” that allows dry sorbent injection to comply 

with the acid gas limit for smaller units less than 200 MW. 

According to the EEI analysis, the availability of DSI as 

a compliance option reduces expected cumulative coal 

retirements in 2015 by 10 GW. 

Fuel price assumptions

Fuel price assumptions for coal and natural gas will also 

impact the economics of individual plants. Because 

natural gas-fired capacity competes with coal-fired 

capacity, lower natural gas prices lead to the displacement 

of coal-fired generation in the reference case, and result 

in older, less-efficient coal plants becoming uneconomic. 

Market response

Studies vary in how they simulate the electricity market. 

Some studies (e.g., NERC, Brattle) do a static analysis 

of facilities that are at risk of retirement, comparing 

projected operating costs under the regulation (using 

generic cost factors and fuel price projections) with 

expected revenue based on forward electricity price 

projections. However, these studies do not account for 

the impact of the regulations themselves on electricity 

or fuel prices. For example, electricity prices are expected 

to rise as a result of the regulations, such that expected 

revenues will likely be higher than projected. This 

feedback effect would likely reduce the number of 

expected retirements. Other studies (EEI, EPA, and BPC) 

utilize dynamic power sector models that attempt to 

capture the effect of changing electricity and fuel prices 

on the cost of generation. 

Combined scenarios

With the exception of the BPC analysis, EEI’s sensitivity 

scenarios—the “Alternate Air Case” and the “Alternative 

Water Case”—come closer to modeling the actual 

requirements and technology options for recently 

proposed EPA regulations than do the other referenced 

studies. However, EEI’s analysis does not include a 

scenario that approximates the actual proposals for 

both the Utility Air Toxics Rule and the cooling water 

proposals together. Instead, the “Alternative Air Case” 

includes more stringent water requirements and the 

“Alternative Water Case” does not allow for lower cost 

air controls consistent with EPA’s new regulations as 

recently proposed. Thus, most of the referenced studies 

probably overstate the cost and number of retirements likely to be 

associated with forthcoming EPA regulations. 

BPC analysis using ICF’s Integrated Planning Model 

used many assumptions similar to the EEI study (see 

Appendix B). The BPC analysis includes a scenario 

that allows for some of the lower cost Utility Air Toxics 

Rule controls (i.e., dry sorbent injection instead of a 

scrubber for units less than 300 MW) and less stringent 

water requirements (i.e., cooling towers on facilities 

which draw more than 500 MGD and operate above 

35% capacity factor). These BPC assumptions, result in 

20-25 GW of DSI installations instead of scrubbers as 

well as cooling tower installations on 93 facilities (no 
Environmental Regulation and Electric System Reliability 25

53 For comparison, EPA modeling for the proposed water rule includes scenarios of cooling tower installations ranging from 46 facilities – 

affecting only baseload and load-following facilities – to 76 facilities, including the largest fossil plants that draw from tidal waters.

54 The reserve margin is calculated as the difference between available generation capacity and expected peak demand, divided by peak 

demand. Sometimes calculated reserve margins are compared against region-specific North American Electric Reliability Corporation 

(NERC) Reference Reserve Margin levels or, if a regional reference level is not provided, against reserve margins assigned by NERC based 

on capacity mix. LOLE measures the number of days per year that available resources will be insufficient to serve peak daily demand; this is 

typically assessed through probabilistic modeling. NERC recommends an LOLE of 0.1, which implies that the system may fail to serve peak 

load no more than 1 day in 10 years. 

55 EPA, EEI, and BPC all use ICF’s Integrated Planning Model to make these assessments. The ICF planning model assumes that all necessary 

capacity resources will be constructed as needed to meet reserve margins.

56 These numbers are incremental to the capacity additions that are projected under the reference case by 2015. The projections cited here do 

not include EEI scenarios that included a price on CO2 emissions. 

57 U.S. EPA. Regulatory Impact Analysis for the Utility Air Toxics Rule proposed rule. March 29, 2001. Found at: http://www.epa.gov/ttn/atw/

utility/utilitypg.html. Page 234-236.

57 U.S. EPA. Utility Air Toxics Rule Information Collection Request. Regulatory Impact Analysis for the Utility MACT proposed rule. Found 

at: http://www.epa.gov/ttn/atw/utility/utilitypg.html. March 29, 2011. Page 234-236.

incremental retirements are projected from the water 

rule).53 BPC assumptions result in a projected 15-18 GW 

of incremental coal plant retirements by 2015 from the 

suite of EPA regulations, with no additional incremental 

retirements through 2030. When factoring in BAU 

retirements in the reference case (14 GW of coal and 

23 GW of oil/gas BAU retirements), the BPC analysis 

results in 57-58 GW of overall retirements by 2030. 

C. Impacts of Retirements

on Resource Adequacy

Plant retirements alone are not the only factor to 

consider in evaluating the system reliability impacts of 

environmental regulation. Another relevant issue is resource 

adequacy, or the extent to which expected available 

generation resources will be capable of meeting forecasted 

demand. Planning authorities evaluate resource adequacy 

periodically, generally by assessing reserve margin levels and 

loss of load expectation (LOLE) for the relevant location.54

Resource adequacy is a useful metric for planning purposes, 

though it provides limited insight into operational reliability 

(operational reliability is the ability to serve all customers 

at all locations at all times of day). Operational reliability 

depends not only on capacity availability, but on conditions 

in local transmission and distribution systems. 

Where existing capacity surpluses are not sufficient to 

maintain reserve margin requirements in the presence 

of retirements, new capacity will have to be added to 

maintain resource adequacy. This new capacity could be in 

the form of new generation or demand side resources. In 

competitive markets, higher spot market prices and forward 

capacity markets will provide an incentive to construct new 

capacity. In regulated markets, the requirement to submit 

integrated resource plans for approval serves as a vehicle for 

identifying new capacity needs and planning accordingly. 

Existing analyses vary in the way that they assess the issue 

of new capacity and apply the methodology and analytical 

tools at hand. For example, some electricity sector models 

inherently assume that all of the necessary capacity 

resources will be constructed in order to meet reserve 

margin requirements.55 While such modeling cannot be 

used to directly draw conclusions about resource adequacy 

or reliability, the amount of new capacity projected to be 

built in response to retirements and other market changes 

can be instructive. This type of modeling can shed light on 

how much capacity will be needed, and in what timeframe, 

to maintain resource adequacy. For example, the January 

2011 EEI analysis projects that 7 to 18 GW of incremental 

new capacity will be required nationally by 2015 due 

to the suite of EPA regulations—this is in addition to 66 

GW of new capacity in the base case.56 These capacity 

projections fall well within the realm of what the industry 

has constructed in recent periods. A CRA study found that 

over the period 1999–2004, the industry constructed 177 

GW of natural gas-fired capacity alone. 

A handful of the studies discussed in the table above 

attempt to make the link between projected retirements 

and implications for resource adequacy. By comparing 

projected retirements in specific regions against projected 

reserve margins, these studies attempt to highlight areas 

where there could be capacity shortfalls if adequate 

planning and new capacity construction does not occur. 

• With respect to the Utility Air Toxics Rule, EPA 

concludes that projected coal plant retirements “are 

not expected to raise broad reliability concerns” and 

points to the existence of sufficient excess capacity 

to take up the slack for projected retirements, which 

the Agency estimates will total less than 10 GW. EPA 

calculates that the Utility Air Toxics Rule will reduce 

the national weighted average reserve margin by just a 

few percent below the 25 percent reserve margin level 

projected in the baseline scenario. This compares to 

a NERC recommended reserve margin of 15 percent. 

According to EPA modeling, resource adequacy is 

maintained in each region where coal retirements 

occur primarily by using excess reserve capacity 

and by “reversing base case retirements of non-coal 

capacity, building new capacity, or importing excess 

reserve capacity from other regions.”57 For the water 
26 Environmental Regulation and Electric System Reliability

58 Federal Register Notice pre-publication. U.S. EPA Proposed Rule for Cooling Water Intake Structures, Section 316(b), Clean Water Act. 

March 28, 2011. Page 55.

59 For a map of NERC regions, see http://www.eia.doe.gov/cneaf/electricity/chg_str_fuel/html/fig02.html.

60 In both the moderate and strict cases, NERC assumes cooling towers on all facilities, 25 percent higher costs are assumed for the strict scenario. 

61 NERC compares potential retirements in individual regions against Summer Peak Deliverable capacity Resources and Summer Peak 

Adjusted Potential Capacity Resources. The former is the more conservative estimate.

62 NERC. 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. Environmental Regulations. October 

2010. Page V.

63 M.J. Bradley & Associates LLC and Analysis Group. Ensuring a Clean, Modern Electric Generating Fleet While Maintaining Electric System 

Reliability. August 2010. Referencing NERC. 2009 Long-Term Reliability Assessment: 2009-2018. October 2009. And PIRA Energy Group 

(“PIRA”). EPA’s upcoming MACT: Strict Non-Hg Can Have Far Reaching Market Impacts. April 8, 2010.

rule, EPA made an overall determination that none 

of the technology options would cause unacceptable 

reliability concerns at the national level. But to avoid 

concern at individual sites, the rule will require 

permitting authorities to consider reliability impacts in 

their case by case determinations.58

• A December 2010 analysis by The Brattle Group, which 

assumes that scrubbers, SCR, and cooling towers are 

required on all plants by 2015, finds that reserve margins 

would fall below NERC reference levels in 2018 in 

the Reliability First Corporation (RFC) region (which 

includes parts of the Mid-Atlantic and the eastern 

Midwest) and in the Electric Reliability Council of Texas 

(ERCOT) region if new resources are not added.59

• CRA evaluated expected 2015 capacity at the level of 

regional transmission organizations (RTOs), NERC 

regions, and NERC sub-regions in comparison with 

reserve margin requirements for that year. At the RTO 

level, the study found that all regions with projected 

retirements were expected to meet and exceed reserve 

margin requirements in that year. At the NERC region 

level, the CRA study found modest reserve margin 

shortfalls in the Midwest Reliability Organization 

(MRO) region, and de-minimis shortfalls in the RFC 

and Southeast Reliability Corporation (SERC) regions. 

Looking at the NERC sub-region level, CRA found 

that the greatest potential resource adequacy impact 

was likely to occur in the Virginia-Carolinas (VACAR) 

subregion of SERC. However, nearly half of the 

projected capacity needed for this region is already in 

planning stages, but was excluded from the analysis. 

The CRA study concluded that a combination of 

coal-to-gas conversions, new gas-fired generation, 

load management, and existing market and regulatory 

safeguards would be sufficient to maintain reliability. 

• The NERC study estimated that 10 to 35 GW of 

coal-fired capacity could be at risk of retirement by 

2018, when factoring in the Transport Rule, Utility 

Air Toxics Rule, Coal ash, and 316(b) rules. It is 

important to note that NERC’s aggressive assumption 

for 316(b) is the biggest driver of retirements, even 

in NERC’s ‘moderate’ case.60 Comparing projected 

retirements under its moderate case against NERC 

region-level estimates of capacity resources, the NERC 

study identified SERC as the region most at risk of 

capacity shortfalls. The study also identified potential 

capacity shortages in Arizona and New Mexico, and 

in the southern Nevada sub-region of the Western 

Electric Coordination Council (WECC). When more 

conservative (lower) estimates of available capacity 

resources are used, NERC projects potential shortages 

in those regions, as well as in the MRO region, New 

England, Texas, and the Rocky Mountain Power 

Area.61 According to NERC, building new capacity, 

or advancing in-service dates of planned capacity 

additions, could help to alleviate projected losses.62 In 

addition, NERC’s updated 2010 demand forecasts and 

planned new capacity additions were not incorporated 

into their special assessment of EPA regulations and 

would have trended toward greater capacity reserves.

• The MJ Bradley and Analysis Group report notes that 

“the electric sector is expected to have over 100 GW of 

surplus generating capacity in 2013, about three times 

the 30 to 40 GW of total retirements projected by PIRA 

Energy Group” (in its analysis of the impact of the CATR 

and the Utility Air Toxics Rule ).63 This is largely due to 

much slower than expected demand growth resulting 

from the recession. The report further notes that the 

RFC and SERC regions, where expected retirements are 

greatest, are projected to have reserve margins of 24.3 

percent and 26.3 percent respectively. Again, these figures 

are well above the 15 percent Reference Margin Level 

that NERC assigns to most regions. 

While most studies have taken a national approach to 

the reliability assessment, it is clear that some regions will 

be more vulnerable during this transition period. More 

study is warranted to assess localized reliability impacts 

in the most vulnerable regions. 

D. The Staging of Retrofits

Although reliability concerns have mostly focused on 

plant retirements, there are also concerns about the 

ability of affected sources to install control technologies 

in time to meet compliance deadlines—particularly for 

the Utility Air Toxics Rule —and about the implications 
Environmental Regulation and Electric System Reliability 27

64 U.S. Environmental Protection Agency. Regulatory Impact Analysis for the Utility Air Toxics proposed rule. March 29, 2011. Found at: 

http://www.epa.gov/ttn/atw/utility/utilitypg.html. Page 8-13.

65 Ibid.

66 See Lipinski, G., J. Leonard, C. Richardson. Assessment of Technology Options Available to Achieve Reductions of Hazardous Air 

Pollutants. URS Corporation. April 2011. Particulate upgrades can be completed in 12-24 months with an outage of less than 2 weeks, or 

up to 4 weeks if a new fan is required for a Fabric Filter upgrade (page A-3). ACI requires up to eighteen months, but no outage time (page 

A-9). DSI requires nine to twelve months from design to start-up, but no additional outage (page A-11).

67 Because the formula for the Air Toxics regulation was mandated in the 1990 Clean Air Act, many companies have already begun the 

planning, design and, in some cases permitting and construction for pollution control equipment, in advance of the final rulemaking. 

Companies will have 45 months, with the opportunity to ask for a one year extension that allows 57 months, from the March 2011 Utility 

Air Toxics Rule proposal until the compliance deadline. Some companies say it takes an average of 54 months to install a scrubber and 4-5 

years to install a baghouse, including planning, design, permitting/regulatory approval, constructing, and start-up of the control device.

for consumer costs. Some fear that the need to install 

large numbers of controls on a system-wide basis in a 

relatively short timeframe could lead to constraints in 

financing or materials, which in turn could drive up the 

cost of compliance. 

In its Regulatory Impact Analysis for the proposed Utility 

Air Toxics Rule, EPA predicts the rule will lead to the 

installation of scrubbers on an additional 24 GW of 

capacity; the application of DSI to an additional 56 GW 

of capacity; the application of ACI to an additional 93 

GW of capacity; and the use of SCR on an additional 

3 GW of capacity.64 In addition, EPA predicts that 

additional fabric filter retrofits will be installed on 49 

GW of capacity to comply with the Utility Air Toxics 

Rule —this is on top of fabric filter installations to meet 

other Clean Air Act requirements, for a total of 165 GW 

of capacity with new fabric filters by 2015.65 Because 

EPA’s assessments project fewer retirements than other 

studies, they generally project the highest number of 

control installations. However, installations required 

before the 2012 and 2014 Transport Rule caps take place 

are not included in the cited EPA Utility Air Toxics 

Rule retrofit estimates. In addition, because EPA has 

more bullish assumptions about DSI, they project fewer 

scrubbers and more DSI than either the BPC or EEI 

analyses assume. BPC projects up to 51 GW of scrubbers 

may be constructed in 2013, 2014, and 2015, in addition 

to 24 GW of DSI.

Once permitted, most pollution control projects can 

be implemented in less than two years from design to 

start-up without the need for outage or with the final 

step occurring during a regularly scheduled maintenance 

period, so as to avoid additional outage time. According 

to a recent report, installing scrubber systems can 

require from two to three years for a dry system and 24 

to 44 months for a wet system from the design through 

construction stage.66, 67 The high end of the range is 

typically associated with more challenging installations 

due to site-specific limitations. Plants generally continue 

to operate throughout most of this time, but the final 

step of “tying in” or connecting the scrubber system 

typically requires that the plant be shut down for four to 

eight weeks. Often this step can be completed during a 

regularly scheduled maintenance outage. 

Rate recovery determinations and permitting processes 

can add to these timeframes. A number of states have 

avoided a time crunch by passing legislation and/or by 

entering into agreements with power companies that 

provide for early planning, timely rate recovery decisions, 

and a schedule for control installations and retirements. 

In areas that have not taken such anticipatory steps, 

however, waiting until after the final Utility Air Toxics 

Rule is signed in November 2011 to begin a lengthy 

approval process may be problematic, particularly if 

site-specific challenges have the effect of complicating 

scrubber installations and extending the time required 

to complete needed pollution control retrofits. This 

highlights the need for plants to immediately begin 

planning and designing for pollution controls.

None of the economic analyses undertaken to date 

have directly addressed the issue of staging retrofits. 

Nevertheless, insufficient planning and coordination 

between generating companies and state, regional, and 

federal institutions could result in higher than necessary 

costs for consumers. For example, if a large number of 

companies delay retrofits until close to the deadline in 

order to defer capital costs as long as possible or waiting 

for state approvals, numerous retrofits may be scheduled 

in close proximity, leaving the grid potentially vulnerable 

to supply disruptions if multiple plants go off line at the 

same time. This could result in higher electricity prices 

as more costly generation resources are dispatched to 

supply electricity. Section IV of this report discusses 

some possible strategies that could be used to manage the 

timing and coordination of pollution control retrofits.
Addressing 

Reliability 

Concerns: The

Roles of Federal, 

State, and Regional 

Authorities

Section

IV

Federal, regional, and state institutions will play a 

key role in ensuring reliability as the electricity 

sector transitions to a new regulatory regime. These 

organizations have a variety of authorities and 

tools at their disposal to ease the transition and 

to help avoid significant impacts on reliability. 

This section describes the roles of various authorities in 

addressing reliability issues associated with new 

environmental requirements. 
Environmental Regulation and Electric System Reliability 29

68 The Utility Air Toxics Rule proposes a definition of “fossil-fuel fired” for purposes of determining if an electric generating unit is subject to 

the rule. According to this proposal, the unit must have fired coal or oil for more than 10 percent of the annual average heat input during 

the last 3 calendar years or for more than 15 percent during any one of those calendar years to be subject to the Utility Air Toxics Rule.

69 42 U.S.C. § 7412(i)(3)(A).

70 In most cases, the permitting authority has been devolved to states that administer their own operating permit programs under Title V of 

the CAA. In a few instances, such as tribal lands, EPA retains this permitting authority. 

71 42 U.S.C. § 7412(i)(3)(B).

72 U.S. Environmental Protection Agency. Proposed Utility Air Toxics Rule. Signed March 16, 2011. Page 443. www.epa.gov/ttn/atw/utility/

pro/proposal.pdf.

A. Federal Agencies

Environmental Protection Agency 

EPA provides analytical and technical support to 

regulated entities, state authorities, and other federal 

agencies in planning for and implementing new 

environmental regulations. In addition, Congress usually 

grants the Agency specific authorities and discretion in 

the implementing legislation for each major rulemaking, 

which are described below.

EPA Discretion on the Utility Air Toxics Rule

Although the Utility Air Toxics Rule is largely 

prescriptive, EPA does have some discretion to provide 

flexibility on certain provisions. The following provisions 

were included in the March 15, 2011 proposed Utility 

Air Toxics Rule and should be included in the final rule: 

• Emissions averaging among units at a facility within 

the same sub-category. 

• Provisions for units that infrequently burn oil, based on 

the proposed limited-use subcategory for infrequently 

operated oil-fired units, as well as the exemption for 

units that burn oil less than 10 percent of the time 

under the definition of fossil fuel-fired unit.68

• Work practice standards for dioxins/furan. EPA 

chose not to specify emissions limits for these 

pollutants, but simply required units to employ good 

combustion practices. 

• Alternative performance standards that reduce 

monitoring requirements for some types of technologies. 

• The use of surrogates for certain hazardous air pollutants.

• A 30 day averaging period in demonstrating compliance 

with the standards for coal-fired power plants.

For the proposed Utility Air Toxics Rule, EPA’s discretion 

on the timing of implementation is limited by the 

explicit text in Section 112 of the Clean Air Act, which 

requires that sources come into compliance within three 

years of the promulgation of the rule.69 This results in 

an expected deadline of January 2015. However, Section 

112 also allows the permitting authority to extend 

this compliance deadline by one year, if 

companies demonstrate that, despite good 

faith efforts, more time is needed to install 

pollution controls.70,71 In its March 15, 2011 

proposal, EPA indicated a willingness to apply 

this extension in order to stagger installations 

for reliability or constructability purposes or for 

other site-specific construction issues, permitting, or 

local manpower or resource challenges.72 EPA encouraged 

companies to begin early discussions with the permitting 

authority to facilitate extensions, where warranted. 

EPA should encourage permitting authorities to make 

timely decisions and grant extensions in advance, with 

appropriate conditions, where warranted. 

EPA also requested comment on whether such an 

extension could be granted to complete on-site 

replacement capacity, rather than install controls, at 

an affected facility. BPC agrees that this would be an 

appropriate and beneficial interpretation of the Clean 

Air Act waiver authority. The states or EPA, as applicable, 

could and should use this waiver authority to allow an 

extra year for those electric generating units unable to 

complete control installation or build on-site replacement 

capacity in time, particularly where reliability is a concern.

As a backstop, EPA has the ability to exercise enforcement 

discretion and negotiate consent decrees with regulated 

entities in order to allow for their continued operation. 

Any such consent decrees, however, should eliminate 

economic advantages a plant might otherwise obtain as 

a result of operating out of compliance. Consent decrees 

are negotiated once a company is deemed in violation, 

and stakeholders may not view this legal mechanism as 

an acceptable option that could be built into company 

planning. However, consent decrees do offer an additional 

means of backstop reliability protection.

Presidential Authority to Delay Utility Air Toxics Rule

As a backup to the other tools and flexibilities available 

to smooth the phase-in of new regulations, the President 

also has the ability to delay Utility Air Toxics Rule 

requirements for some facilities, if warranted. Although 

this authority has never been invoked, the President is 

explicitly permitted under Section 112 of the Clean Air 

Act to grant an additional exemption from compliance 

(beyond the one year extension from states) for up to two 
30 Environmental Regulation and Electric System Reliability

73 42 U.S.C. § 7412(i)(4). 

74 See Hazardous and Solid Waste Management System, 75 Fed. Reg. 35,128 (June 21, 2010). 

75 This date is based on the following assumptions: 1) EPA promulgates the final CCW rule in September 2011; 2) RCRA regulations, including 

the coal combustion waste rule, generally take effect six months after promulgation—in this case, March 2012; 3) EPA’s proposed Subtitle D 

regulations require retrofit within five years of the effective date of the regulation. Thus, retrofit would be required before April 2017. 

76 Under RCRA, Subtitle C regulations are subject to the same effective date provisions as Subtitle D regulations. However, most states administer 

RCRA requirements in lieu of EPA pursuant to a delegation of authority from the agency. In these states, certain core RCRA requirements 

included in new EPA regulations do not take effect until the state itself adopts a regulation reflecting the new EPA requirements—a process that 

RCRA usually requires to take place within one year of a new EPA regulation. Thus, the retrofit requirements under the proposed Subpart C 

regulations would not take effect in most states until one year later than the compliance deadline in the Subpart C regulations (April 2018). 

years if the “technology to implement such a standard 

is not available” and if the exemption is found to be in 

the “national security interests of the United States.”73

This exemption may be renewed an unlimited number of 

times provided the requisite findings are made. 

Presumably, the President could interpret the term 

“available” to encompass both technological and 

economic feasibility, consistent with the interpretation 

of that term in the context of “best available control 

technology” for Prevention of Significant Deterioration 

permitting. In addition, a threat to electric reliability 

could presumably serve as grounds for determining that 

it is in the “national security interests” of the United 

States to extend the Section 112 compliance deadline. 

EPA Discretion on Cooling Water Rule

The Clean Water Act provides EPA with extensive 

discretion on the compliance timing and stringency 

of regulations for power plant cooling water intake. In 

its proposal, EPA relied on this flexibility and on cost/

benefit considerations with respect to entrainment 

provisions to allow alternative technologies where 

appropriate, to accommodate site-specific constraints, 

and to allow sufficient time for retrofits. 

EPA’s March 2011 proposal requires the largest water 

users to conduct a study to determine whether cooling 

towers or alternative technologies are needed to limit 

damage from aquatic life being sucked into cooling 

water intake systems (entrainment). Study results 

would be considered along with other factors—such 

as the useful life of the facility, reliability concerns, 

and the benefits versus costs of installing a cooling 

tower–to make a site-specific determination of the 

“best technology available” for a particular facility. In 

addition, EPA’s proposed cooling water rule requires 

facilities to meet impingement mortality limits or 

reduce intake velocity. In its final rulemaking, EPA 

should exercise its authority to allow the consideration 

of site-specific factors and cost-benefit analysis with 

respect to impingement requirements. 

In addition, EPA has proposed and should finalize 

compliance deadlines that provide sufficient time for 

planning, coordination, and installations. For example, 

under the proposed rule, plant owners are allowed eight 

years to install technologies such as screens, low velocity 

caps, and barrier nets. The installation of cooling towers 

is allowed to take five to ten years in the case of existing 

fossil plants, or ten to fifteen years in the case of existing 

nuclear plants. 

EPA Discretion on Coal Ash Rule

EPA also has significant flexibility to establish 

compliance deadlines for its proposed RCRA regulations 

governing the disposal of coal combustion waste, 

including coal ash. In its proposal, EPA took comment 

on whether or not coal ash should be treated as 

hazardous waste.74 One option would regulate coal ash 

as a “special waste” under the hazardous waste Subtitle 

C of RCRA, whereas an alternative option would 

regulate the ash as non-hazardous waste under Subtitle 

D. The primary difference between the alternatives is 

that EPA retains enforcement authority under Subtitle 

C, whereas Subtitle D requirements would be selfimplementing with no federal enforcement authority. 

Aside from enforcement, the actual requirements are 

quite similar for the two proposed options. For example, 

both alternatives would eventually require that surface 

impoundments for coal combustion waste have leachate 

collection and removal systems; alternatively, the 

impoundments would have to be closed. EPA’s proposed 

Subtitle D regulation would require these controls to be 

installed by April 2017, whereas the proposed Subtitle C 

regulation would allow states until 2018 to implement 

retrofit requirements.75,76

However, neither RCRA subtitle requires EPA to 

mandate compliance by any particular deadline. Subtitle 

D does not require that waste storage standards be 

implemented in any particular timeframe. And even if 

EPA adopts substantially more stringent requirements 

under Subtitle C, Section 3004(x) of RCRA also allows 

EPA to modify Subtitle C requirements for coal ash sites 

where justified by “practical difficulties.” EPA may also 

allow site-specific variances from Subtitle C regulations 

for sites with distinctive geological, climatic or chemical 

In addition, EPA has proposed and should finalize 

compliance deadlines that provide sufficient time for 

planning, coordination, and installations.
Environmental Regulation and Electric System Reliability 31

77 42 U.S.C. § 6924(x).

78 FR Vol 75, No 118 June 21, 2010. Coal combustion waste proposed rulemaking.

79 In several organized markets, including Midwest ISO and California ISO, contractual or tariff requirements obligate the generator to 

negotiate RMR contracts to remain in operation if the RTO/ISO concludes that continued operation of the unit is necessary for reliability. 

In other markets, including PJM and ISO New England, the generator’s decision to accept an RMR contract is voluntary.

80 Devon Power, LLC, 103 FERC ¶ 61,082 (2003).

characteristics.77 This authority could be exercised to craft 

appropriate tailored deadlines for sites that are unusually 

difficult to retrofit, or to provide an across-the-board 

deferral in RCRA compliance deadlines (as EPA already 

proposed to do in its Subpart C regulation by changing 

the RCRA compliance deadline to five years from four 

years pursuant to its Section 3004(x) authority). 

In its June 21, 2010 proposed rulemaking, EPA highlighted 

the environmental benefits, and lack of damages, from the 

beneficial reuse of coal combustion wastes in encapsulated 

uses such as wallboard, concrete, and bricks.78 EPA should 

continue its efforts to support such beneficial reuses and 

finalize the Bevill exemption for encapsulated beneficial 

reuse of coal combustion waste. 

Department of Energy and Federal

Energy Regulatory Commission

The Department of Energy (DOE) and the Federal 

Energy Regulatory Commission (FERC) have specific 

authorities under the Federal Power Act to ensure the 

stability or reliability of the transmission grid. DOE 

and FERC authorities can be applied to avoid potential 

reliability issues or emergencies in the near term and, 

perhaps more effectively, to support long-term planning.

Addressing Near-Term Reliability Issues

While an emergency reliability issue is unlikely and 

should be preventable with proper planning and 

oversight, DOE and FERC have authority to address 

such situations if they arise. Under Section 202 of the 

Federal Power Act, the DOE can issue emergency orders 

to temporarily require a unit to generate and deliver 

electricity. In the past, this authority has been used to 

address a few, short-term reliability concerns.

FERC’s relevant authority stems from its mission to 

ensure just and reasonable rates. FERC has authority to 

review the rates, terms, and conditions of “reliability-mustrun” (RMR) contracts between a regional transmission 

organization or independent system operator (RTO/

ISO) and a unit intended for retirement. These types of 

contracts are used in RTO/ISO markets when an RTO/

ISO determines that a unit proposed for retirement is 

necessary to ensure system reliability. In such cases, the 

RTO/ISO can propose or enter into a RMR agreement to 

compensate the generator for continued operation based 

on cost-of-service rates or other rate agreements.79 Through 

a number of recent rate reviews, FERC has indicated that 

RMR contracts should be considered a solution of last 

resort to maintain reliability.80

Both DOE’s emergency orders and FERC-approved 

RMR contracts allow generators needed for reliability 

to be compensated for above-market costs of continued 

operation. If keeping such units online requires 

significant capital investments in pollution controls, the 

associated cost-of-service may be quite high. This would 

be the case, for example, if a unit were kept online at 

cost-of-service rates, retrofitted with pollution controls, 

and then retired well before the capital investment 

could be repaid. The generator might seek to 

amortize the relatively high costs of the 

retrofit investments over a short period (e.g., 

the term of the RMR contract or the DOE 

order) at the expense of ratepayers. 

Alternatively, an RMR unit might 

operate for a period without pollution 

controls. This could be a lower cost 

solution, although the rate tariff could 

still provide for above-market payments. 

However, operation without compliant 

controls would violate emissions limits, as 

FERC’s RMR authority does not supersede Clean 

Air Act requirements. As discussed below, such a situation 

would require coordination with EPA and enforcement 

discretion, such as the negotiation of a consent decree to 

continue operating for a period without controls.

FERC reviews RTO tariff provisions relating to RMR 

contracts under its general rate review authority (Sections 

205 and 206 of the Federal Power Act), which requires 

that the rates, terms and conditions for provision 

of jurisdictional transmission service and wholesale 

sales must be just and reasonable and not unduly 

discriminatory or preferential. In some instances where 

FERC has found that an RTO/ISO violated its tariff 

provisions, FERC has intervened in RMR determinations 

(an example involving ISO New England and Dominion 

power company is discussed in the text box). 

Long-Term Planning

DOE and FERC both have broad authorities to gather 

information and require public utilities to file reports. In 

addition, DOE has specific authority under Section 202 

to require utilities to report on anticipated shortages of 

electricity or capacity, as well as on their plans to manage 
shortages. In addition, FERC has broad authority to 

conduct investigations, including subpoenaing witnesses 

and requiring companies to produce relevant materials.

Expanded Role for FERC

In the future, FERC could play an expanded role in 

monitoring RTO forward capacity markets. State PUCs 

have little authority to manage resource planning 

and generation adequacy in restructured states, where 

regulated utilities do not own generation resources 

but rather purchase electricity from wholesale markets 

under relatively short-term contracts. In lieu of resource 

planning, several RTOs have established forward capacity 

markets to attract new generation capacity and provide 

a price signal for economic retrofits of existing capacity. 

However, there is some concern that these markets may 

not provide sufficient price signals to ensure an adequate 

response to significant retirements of coal-fired capacity.

Thus, FERC could undertake an effort to consider: (1) 

whether some or all of the RTOs face resource adequacy 

FERC Oversight of RMR Contracts: ISO-NE and Salem Harbor

81 ISO New England, Inc., 133 FERC ¶ 61,230

82 Conservation Law Foundation Press Release. Federal Energy Regulatory Commission Orders ISO-NE to Plan for Close of Salem Harbor 

Station. December 17, 2010.

Using its authority under the Federal Power Act, 

FERC recently intervened in an ISO-New England 

proceeding related to a reliability-must-run type 

contract for Dominion’s Salem Harbor 3 and 4 coalfired generating units. In December 2010, FERC’s 

review of ISO-NE’s fourth Forward Capacity Auction 

determined that ISO-NE had violated its tariff 

provisions in failing to identify alternatives to the 

reliability need for Salem Harbor.81

Available surplus capacity contributed to several 

existing power plants and demand resources—a 

combined 1.2 GWs of capacity—opting out of the 

fourth ISO-NE forward capacity market auction by 

submitting de-list bids. However, ISO-NE determined 

that Dominion’s Salem Harbor Units 3 and 4, in 

addition to Entergy’s Vermont Yankee Station, could 

not withdraw from the market due to reliability 

concerns that would violate NERC, Northeast Power 

Coordinating Council (NPCC), and ISO-NE standards.

When ISO-NE rejects a de-list bid, their Forward 

Capacity Auction rules require them to look for ways 

to allow the generating unit to withdraw under an 

established timeline or, if no alternatives are available, 

provide compensation to retain the resource in a 

reliability-must-run type agreement. ISO-NE’s Tariff 

requires that this process to identify alternatives must 

occur in advance of the new capacity qualification 

period for the subsequent Forward Capacity Auction.

Following ISO-NE’s rejection of Salem Harbor’s delist bid, the Conservation Law Foundation (CLF) filed 

a protest which stated that ISO-NE failed to meet 

these procedural requirements and that this would 

result in unjust and unreasonable rates. ISO-NE 

responded by providing evidence that it repeatedly 

presented the specific reliability need for the Salem 

Harbor Units to the NEPOOL Stakeholders, including 

the Reliability Committee. ISO-NE also stated that 

because Dominion submitted a static de-list bid 

rather than a permanent de-list bid, Dominion did 

not indicate a permanent exit from the market that 

would trigger the need for a transmission solution. 

Resources that wish to withdraw from the market 

for a one-year period can submit either a static 

or a dynamic de-list bid. A permanent de-list bid 

withdraws the resource from all future auctions.

In December 2010, FERC concluded that ISO-NE’s 

presentations did not satisfy the Tariff’s procedural 

requirements. FERC ordered ISO-NE to submit a 

compliance filing within 60 days that either identifies 

alternatives to resolve the reliability need and the 

time to implement those solutions, or include an 

expedited timeline for identifying and implementing 

alternatives. According to CLF, such alternatives 

could include “energy efficiency, conservation, electric 

transmission line upgrades, and renewable energy.”82

In October 2010, Dominion submitted a permanent 

de-list bid for Salem Harbor.

32 Environmental Regulation and Electric System Reliability
Environmental Regulation and Electric System Reliability 33

83 This rule may be subject to additional hearings and judicial review because Commissioner Moeller dissented from the Final Rule and there 

is likely to be divergent stakeholder views as RTOs and ISOs adjust key analytic features for the net benefits test.

84 Twenty eight states, including most in the Midwest and South, remain traditionally regulated even though some have undertaken 

restructuring studies and/or pilot programs. Seven states have suspended efforts at restructuring and are left with either partially restructured 

markets (e.g., Arizona, California, and Nevada) or traditionally regulated utilities. The remaining fifteen states, largely in the New England 

and Mid-Atlantic regions, are actively restructuring and sit on a spectrum of partially to fully de-regulated, offering retail choice and 

competitive rates for some or all customers. For example, Oregon offers retail choice to large commercial and industrial customers only, 

while areas of Texas are fully competitive with separate companies for generation, transmission and distribution, and retail sales. See http://

ftp.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html.

concerns driven by EPA regulations; (2) whether capacity 

markets are a useful tool for assuring resource adequacy 

in markets facing such problems; and (3) whether Section 

206 of the Federal Power Act should require the reform of 

existing capacity markets, or the establishment of capacity 

markets in RTOs where they do not now exist. In essence, 

the FERC review would consider how capacity markets in 

the organized markets could and should be used to address 

the issue of plant retirements. FERC could undertake such 

a review on an RTO-specific basis or on a generic basis 

covering all RTOs. FERC could act to amend current RTO 

tariffs to provide for capacity market reforms under Section 

206 of the Federal Power Act, and could take such action 

in RTO-specific orders or in a generic notice and comment 

rulemaking. Although such actions may require more 

time than is available for dealing with reliability issues that 

arise in the 2015 Air Toxics Rule timeframe, they could 

potentially bolster the system to address future situations. 

Supporting Alternative Capacity Resources

FERC is also involved in efforts to encourage the 

participation of alternative resources in wholesale energy 

markets administered by RTOs or ISOs. On March 15, 

2011, FERC issued a Final Rule that attempts to level the 

playing field for alternatives to traditional generation by 

requiring competitive rates for demand response resources. 

The term ”demand response” generally refers to load 

management programs in which electricity customers 

volunteer to reduce their electricity consumption during 

periods of peak demand in exchange for lower rates. 

These programs can reduce costs for all consumers 

because electricity is more expensive during periods of 

peak demand, when higher cost generators that seldom 

operate are required to start-up. FERC’s rule requires that 

cost-effective dispatch of demand response resources, 

as determined by a new “net benefits” test, must be 

compensated at the locational marginal price (LMP). To 

comply with the rule, each RTO and ISO must file a net 

benefits analysis and proposed tariff revisions by July 2011.83

The Final Rule also requires that the cost of obtaining 

demand response resources must be spread among all 

entities that purchase energy at the times and at the 

locations where those demand response resources were 

committed or dispatched. 

B. Interagency Cooperation

Although neither DOE nor FERC appear to have 

authority to waive environmental regulations when 

they issue emergency orders for a unit to continue uneconomic operation for reliability reasons, EPA might 

exercise enforcement discretion and negotiate consent 

decrees that establish the terms of such operation in the 

absence of compliant pollution controls. Coordination 

of this sort between the relevant federal agencies might 

allow for the continued operation of coal-fired electric 

generating units without compliant pollution controls, 

if deemed necessary for reliability. Of course, such 

arrangements and accommodations must be reserved 

for true emergency situations—they should not be 

relied upon as the primary mechanism for ensuring 

reliability during the transition to a more stringent set of 

environmental regulations. Further, these consent decrees 

should ensure that plants operating out of compliance 

are not economically advantaged. 

C. State Authorities

In the United States, electricity is regulated largely at 

the state level and there is considerable variation in the 

authorities exercised and roles played by regulators from 

state to state. In particular, the role of state authorities is 

determined by the extent to which the state has retained 

traditional regulation of electric utilities or has restructured 

its wholesale generation markets (see Figure 7).84 In 

regulated states, where electric utilities remain vertically 

integrated, state public utility commissions (PUCs) retain 

oversight of resource additions, retrofits, and retirements. 

Utilities in regulated states have the obligation to serve 

load reliably, and many regulated states require that 

integrated resource planning be conducted periodically 

Coordination between the relevant federal agencies 

might allow for the continued operation of coal-fired 

electric generating units without compliant pollution 

controls, if deemed necessary for reliability. Such 

arrangements and accommodations must be 

reserved for true emergency situations—they should 

not be relied upon as the primary mechanism for 

ensuring reliability during the transition.
34 Environmental Regulation and Electric System Reliability

85 For example, North Carolina’s 2002 Clean Smokestacks Act requires coal-fired power plants to reduce NOX emissions by 77 percent by 

2009 and SO2 emissions by 73 percent by 2013. The Illinois Multi-Pollutant Standard (MPS) and Combined Pollutant Standard (CPS) 

allow utilities flexibility in complying with state mercury standards in exchange for commitments to also significantly reduce SO2 and NOX

emissions. New Hampshire’s 2002 Clean Power Act requires emission reductions from the state’s three largest coal-fired plants: 75 percent 

in SO2 by 2006 and 70 percent in NOX by 2006. Massachusetts regulation requires the six largest facilities to meet output-based emission 

standards for SO2, NOX, and CO2. Maryland’s 2007 Healthy Air Act requires larger reductions in NOX, SO2, and mercury in a shorter 

timeframe than previous federal rules.

86 Bipartisan Policy Center and American Clean Skies Foundation. Task Force on Ensuring Stable Natural Gas Markets. March 2011.

as a way to provide a built-in process for understanding 

and addressing future capacity needs. However, utility 

investments in retrofits and new capacity are subject to 

prudency reviews and cost recovery is not guaranteed. 

Uncertainty about cost recovery may cause utilities to be 

less proactive in making these investments. 

In states that have undertaken electricity market 

restructuring, electric utilities have generally divested 

themselves of their generation resources, and may remain 

regulated by the state PUC only with respect to the 

rates they charge to retail customers. The electric utility 

serves load by purchasing electricity from independent 

producers. Because generation assets are not owned by 

regulated utilities, the state PUCs retain little, if any, 

direct authority over resource investments or operating 

decisions. In restructured markets, grid operators—that 

is, RTOs and ISOs—play an important role in fostering 

market conditions that encourage new investment 

in capacity, demand side management (DSM), or 

transmission when issues of resource adequacy arise. 

Figure 7: Status of State

Electricity Regulation/Restructuring

Source: U.S. Energy Information Administration.

In regulated states, the integrated resource planning (IRP) 

process informs state utility regulators who approve rate 

plans. State regulators should consider a forward-looking, 

multi-pollutant approach for planning and rate recovery 

decisions and require utilities to submit multi-pollutant 

compliance plans that include planning for forthcoming 

air, water, and waste rules. State regulators can encourage 

utilities to minimize cost by denying automatic cost 

recovery if, for example, a utility proposes to retrofit 

an aging plant that faces an uncertain future and is 

unlikely to remain competitive as future requirements 

are phased in. State utility commissions could also 

facilitate a smooth transition by making timely decisions 

on rate approvals, as well as proposed retirements 

and new capacity additions, so that utilities can begin 

construction as soon as possible, where appropriate. 

Further, several states have passed laws that require 

utilities to plan for the installation of air pollution 

controls to protect public health. For example, North 

Carolina, Illinois, New Hampshire, Delaware, Maryland, 

and Massachusetts all adopted state laws prior to EPA’s 

Transport Rule and Utility Air Toxics Rule that require 

multi-pollutant reductions. As a result, power companies 

in these states are in a good position for timely compliance 

with a new round of air quality regulations under the 

federal Clean Air Act.85 The text box on page 35 describes 

Colorado’s Clean Air-Clean Jobs Act, which encourages 

comprehensive, multi-year compliance planning.

State utility regulations also have an important role to 

play in integrating non-conventional capacity resources, 

such as demand-side resources, into planning for a 

reliable bulk electricity system. Incentives and fair rate 

policies for demand resources, distributed generation, 

and energy storage create a level playing field and 

provide meaningful incentives for new resources that 

could help the electricity system deliver reliable power 

and minimize consumer costs. Many states have enacted 

renewable portfolio standards and energy efficiency 

programs to spur the deployment of these nonconventional capacity resources. 

To the extent that new environmental regulations 

prompt a shift to natural gas generation, either 

through the utilization of existing capacity or through 

the construction of new capacity, state PUCs could 

encourage long-term contracts for natural gas supply 

and the use of hedging instruments to manage the risk 

of gas price volatility. A report recently issued by the 

BPC’s Task Force on Ensuring Stable Natural Gas Markets

addresses this issue as one part of its comprehensive 

recommendations for bolstering consumer, policymaker and investor confidence in the stability of future 

gas markets and for improving the tools available for 

effective price risk management.86

• Most of Midwest 

+ South

• Vermont, 

Washington

• Regulated: Arkansas, 

New Mexico, 

Montana, Virginia

• Partial restructure: 

Arizona, California, 

Nevada 

• Most of New England

and Mid-Atlantic

• Illinois, Michigan, Ohio

• Oregon 

(non-residential only)

• Fully Competitive: Texas

28

Traditionally

Regulated

7

Suspended

Restructuring

15

Restructured
State Environmental Agencies

As the permitting authority under the Clean Air Act, states 

generally have authority to grant a one-year waiver that 

extends the Utility Air Toxics Rule compliance deadline 

for electric generating units that need more time to 

install pollution controls. With this one-year extension, 

compliance would not be required until four years after 

promulgating the final Utility Air Toxics Rule. States, 

which have typically been lenient in granting this extra 

year, should draw on this authority as needed to allay 

reliability concerns. EPA has encouraged the use of this 

one-year extension in its proposed Utility Air Toxics Rule.

In addition to allowing retrofits to be scheduled past 

the compliance deadline, states should look for ways 

to encourage retrofits to be scheduled well before the 

deadline. This would help avoid a pile-up of control 

installations in the maintenance season or year prior to the 

deadline. Specifically, states should aim to reward plants 

that start pollution retrofit projects as soon as possible 

and are able to install and operate their pollution controls 

in advance of the compliance deadline. Such early action 

would not only provide early emission reductions, it 

would take pressure off the grid during the heaviest period 

of pollution retrofits, when new infrastructure is also 

coming online to take up the slack from retired plants. 

Early decisions made by states to grant extensions should 

require plants to submit a detailed schedule for installation 

of pollution controls and specify consequences in the 

event interim deadlines are not achieved.

D. Regional Organizations

Regional Transmission Organizations/

Independent System Operators

In restructured states, regional wholesale markets provide 

greater transparency about anticipated supply changes 

(including planned retirements) and create a financial 

incentive for timely investment in new transmission, 

generation, and non-conventional capacity. In these 

states, RTOs and ISOs typically facilitate orderly 

planning of power plant retirements by requiring advance 

notice of the intent to retire a unit and by conducting 

reliability impact studies. More advance notice could be 

helpful in identifying potential issues and allowing more 

time for their resolution.

RTOs and ISOs administer day-ahead and real-time 

electricity markets, manage transmission, and play 

an important role in assessing resource adequacy and 

ensuring operational reliability. These organizations 

emerged in response to FERC orders 888 and 889, which 

were both issued in 1996 and were intended to remove 

Case Study: Colorado’s Clean Air–

Clean Jobs Act

Colorado’s Clean Air–Clean Jobs Act, signed 

into law by Governor Bill Ritter on April 19, 

2010, is an example of state action to encourage 

comprehensive, multi-year planning for 

compliance with environmental regulation. In 

anticipation of a number of challenges facing 

the state’s coal-fired utilities, the Clean Air–

Clean Jobs Act directs the state’s regulated 

utilities to work with state agencies to create 

proactive and comprehensive emission 

reduction plans. 

A main driver for the legislation was that 

the Denver metropolitan area was in noncompliance with several air quality requirements 

and faced the threat of EPA-mandated 

compliance beginning in 2011. Therefore, the 

Colorado law requires each regulated utility 

to develop a multi-year plan to reduce NOX

emissions by more than 70 percent by 2018. 

The legislation also allows integrated planning 

for compliance with a full range of known 

and anticipated environmental regulations, 

including federal requirements under the Clean 

Air Act, rather than planning for one standard 

at a time and risking stranded assets. Each 

utility’s plan is reviewed, by the Colorado 

Department of Public Health and Environment 

for its attainment of emissions standards and 

by the Public Utilities Commission in terms of 

projected impacts on consumers. 

The Act’s stated goal is to reduce costs to 

consumers by removing legislative and 

regulatory barriers to proactive, comprehensive 

planning. Utilities are encouraged to employ 

a range of methods to achieve emission 

reductions, but are given incentives to consider 

replacing coal-fired generation with natural gasfired generation or other low-emission sources. 

Once its emission reduction plan is approved, 

the utility is given broad assurances for full 

recovery of costs to execute the plan. The law 

also provides flexibility for utilities to enter into 

long-term natural gas contracts to manage costs 

for plants that are refueled from coal to gas.

Environmental Regulation and Electric System Reliability 35
36 Environmental Regulation and Electric System Reliability

87 In several organized markets, including Midwest ISO and California ISO, contractual or tariff requirements obligate the generator to 

negotiate RMR contracts to remain in operation if the RTO/ISO concludes that continued operation of the unit is necessary for reliability. 

In other markets, including PJM and ISO New England, the generator’s decision to accept an RMR contract is voluntary.

88 PJM. Open Access Transmission Tariff. §§ 113.1-.2. September 17, 2010. Available at http://pjm.com/documents/agreements/~/media/

documents/agreements/tariff.ashx.

barriers to competitive wholesale markets by requiring 

open access to transmission lines. In some regions 

FERC approved the development of ISOs as a means 

of facilitating the transition to competitive wholesale 

markets. In 1999, FERC issued Order No. 2000, which 

encouraged the development of RTOs, and established 

criteria for them. While their activities vary somewhat 

by region, RTOs and ISOs serve similar functions: 

namely, they develop rules to govern power market and 

transmission market operations and operate and oversee 

regional wholesale markets, including coordinating the 

delivery of generation and transmission services. 

As part of their market operations, RTOs and ISOs 

analyze generation and transmission resource adequacy, 

undertake transmission planning, review plant notices 

of intent to retire, and coordinate outage schedules. As 

noted earlier, when a generator proposes to retire a unit, 

the RTO/ISO assesses the reliability impact. If the RTO/

ISO determines that the unit is necessary to ensure system 

reliability, the RTO/ISO can enter into a reliability-mustrun (RMR) agreement to compensate the generator for 

continued operation based on cost-of-service rates.87

Advance notice of retirement can allow sufficient time 

for new resources to join the market, reducing the need 

to rely on RMR contracts as an interim measure to 

assure grid security, and mitigating the stress of assuring 

grid reliability in the face of retirements and retrofits. 

Different RTOs have different requirements with respect 

to the amount of notice generators must give for a 

proposed unit retirement. For example, PJM requires 

90-day notice; NYISO requires 90 days for smaller plants 

and 180 days for units that are 80 MW or larger; while 

WA

OR

CA

NV

ID

MT

WY

UT CO KS

OK

MO

AR

LA

MS AL GA

FL

TN

KY

VA MD

DE

WV

NC

SC

TX

NM AZ

NE

IA

SD

ND MN

WI MI

IL IN OH

PA

NJ

NY

ME

MA

CT

VT

NH

RI

Alberta Electric

System Operator

(AESO)

Ontario

Independent Electricity

System Operator ISO-NE

NY ISO

California

ISO

ERCOT

MISO RTO

SPP

PJM

Interconnection

Figure 8. Map of RTOs/ISOs in the U.S. 

Source: The ISO/RTO Council.
Environmental Regulation and Electric System Reliability 37

89 NYISO. Technical Bulletin 185. September 19. 2009. Available at http://www.nyiso.com/public/webdocs/documents/tech_bulletins/tb_185.pdf.

90 MISO Open Access Transmission Tariff. §§ 38.2.7. January 6, 2009. Available at http://www.midwestmarket.org/publish/

Document/1d44c3_11e1d03fcc5_-7cf90a48324a/Modules.pdf?action=download&_property=Attachment.

91 Synapse Energy Economics, Inc. Prepared for Earthjustice. Public Policy Impacts on Transmission Planning. December 2010. In addition, 

FERC has found that RMR agreements weaken the incentive for new generation development by suppressing spot market prices and 

allowing inefficient existing units operating under RMRs to receive a higher price than new units. Devon Power LLC, et al. ER03-563-00.

92 Electricity Advisory Committee Memorandum to Secretary Steven Chu. March 10, 2011. Recommendations to Address Power Reliability 

Concerns Raised as a Result of Pending Environmental Regulations for Electric Generation Stations. Available at http://www.oe.energy.gov/

DocumentsandMedia/EAC_Memorandum_to_Secretary_Chu_and_Assistant_Secretary_Hoffman_3-11-11.pdf

93 National Association of Regulatory Utility Commissioners. Resolution on the Role of State Regulatory Policies in the Development of 

Federal Environmental Regulations. February 16, 2011.

the Midwest ISO (MISO) requires a longer, 26-week 

notice.88,89,90 These advance notification requirements 

can be revised by RTOs/ISOs or FERC under existing 

RTO/ISO tariffs through a demonstration that the 

existing notice period is unjust or unreasonable, or 

unduly discriminatory or preferential. In other words, 

RTOs and ISOs can consider extending the notification 

requirement as a way to improve regional planning and 

reduce reliance on RMR agreements.

Some RTOs have established forward capacity markets 

as a mechanism to encourage the capacity investments 

needed to ensure continued reliability over time. In the 

mid-Atlantic region and New England, for example, the 

two ISOs—PJM and ISO New England, respectively—

have well-developed forward capacity markets that allow 

existing and new generation resources, as well as demandside measures, to compete alongside each other to serve 

future demand. As unit retirements are scheduled, the 

price in forward capacity market auctions increases, 

encouraging the development of new resources. 

However, the continued use of RMR contracts in both 

regions has led some to question whether forward 

capacity markets are sufficiently effective.91

E. Coordination of Federal, 

State, and Regional Authorities

 The overlapping jurisdictions of environmental and 

electricity regulators have prompted efforts to ensure that 

there is coordination on reliability issues. This section 

discusses several examples of recent efforts to initiate or 

improve this coordination.

For example, DOE’s Electricity Advisory Committee 

has issued recommendations to the Secretary of Energy 

for addressing power reliability concerns related to 

pending environmental regulations for electric generating 

stations.92 The Committee advised DOE to coordinate 

with FERC, NERC, EPA, and state regulatory authorities 

to address these concerns. The Committee also put 

forward two specific recommendations: first, that DOE, 

EPA, and FERC engage in a senior-level consultative 

process to commit to open and active communication 

on reliability issues, while recognizing the existing 

authorities of each agency; second, that DOE 

advance a recommendation to FERC to improve the 

planning process for replacing retiring units. The latter 

recommendation suggests that DOE and FERC support 

power system “planning coordinators” who would 

undertake proactive planning studies, including scenario 

analyses, to understand the impact of retirements on the 

need for new generation capacity, transmission system 

additions, or demand-side resources. To the extent 

that planning coordinators can better anticipate likely 

retirements under different scenarios, RTOs and ISOs 

will have more time, information, and flexibility to take 

necessary action to ensure reliability.

Similarly, the Board of Directors of the National 

Association of Regulatory Utility Commissioners 

(NARUC) adopted a resolution on the role of state 

regulatory policies in the development of federal 

environmental regulations at its 2011 Winter Meeting.93

The resolution enumerated several factors that 

NARUC believes EPA should consider in developing 

its regulations and urged state utility regulators to 

engage with state and federal environmental regulators. 

Specifically, the resolution outlined ten factors for EPA 

to consider, including several aimed at improving statefederal coordination and addressing reliability concerns:

• “Engage in timely and meaningful dialog with State 

energy regulators in pursuit of these objectives;”

• “Recognize the needs of States and regions to deploy 

a diverse portfolio of cost-effective supply-side 

and demand-side resources based on the unique 

circumstances of each State and region;” 

• “Encourage the development of innovative, multipollutant solutions to emissions challenges as well 

as collaborative research and development efforts in 

conjunction with the U.S. Department of Energy;” and

• “Recognize and account for, where possible, State 

or regional efforts already undertaken to address 

environmental challenges.”
Section

V

Conclusions and 

Recommendations

It is clear that the U.S. electric power sector is in 

a period of transition and that EPA regulations will 

influence the timing and scale of future changes 

in the nation’s electricity supply mix. Coal-plant 

retirements are already occurring and are likely 

to continue because of market conditions such as low 

natural gas prices. EPA regulations, particularly 

the Utility Air Toxics Rule, will likely advance 

retirement timelines for these vulnerable plants.
Environmental Regulation and Electric System Reliability 39

94 M.J. Bradley & Associates LLC and Analysis Group. Ensuring a Clean, Modern Electric Generating Fleet While Maintaining Electric System 

Reliability. August 2010.

The large numbers 

of retrofits and 

retirements expected 

to result from the 

EPA regulations raise 

significant challenges 

for the power sector. 

Nevertheless, based on the 

recently released proposed Utility 

Air Toxics Rule and 316(b) cooling water rule, it appears 

that EPA is making an effort to work with industry to 

ease the transition to a new regulatory regime. As a result, 

it appears that the scenarios that predicted the largest 

numbers of retirements will not be realized. 

Moreover, even at the higher end of current estimates, the 

magnitude of new construction and investment would 

not be unprecedented, even in light of a relatively short 

timeframe. Between 1999 and 2004, U.S. generating 

capacity nationwide increased by 177 GW, almost all of 

which was natural gas capacity. By comparison, projected 

retirements between now and 2015 range from 10 to 

70 GW—a much smaller change. Moreover, not all of 

the capacity that will be retired will need to be replaced 

because there is under-utilized existing generation, 

demand has flattened, and energy efficiency continues to 

improve. The industry has also demonstrated the ability to 

orchestrate substantial control technology retrofits. During 

the peak of the last retrofit construction cycle, scrubbers 

were installed on nearly 60 GW of coal capacity during the 

three-year period from 2008 through 2010.94

In the areas that may be most vulnerable to reliability 

problems, BPC believes that power companies, federal 

and state regulators, and ISO/RTOs have authorities 

or strategies at their disposal to ensure continued 

reliability. In light of these findings, we offer the following 

recommendations to ensure the smoothest possible 

transition to a cleaner, more efficient electric power system.

A. Flexibilities in the Clean Air 

Act and Clean Water Act

Where appropriate, EPA should use flexibility inherent 

in its existing authority to address cost and reliability 

concerns. EPA’s March 15, 2011 proposed Utility Air 

Toxics Rule includes several provisions that can help 

minimize costs and the potential for system disruptions. 

These include work practice standards in lieu of limits for 

dioxin and furans, emissions averaging among units at a 

facility in the same sub-category, the use of surrogates for 

particular hazardous air pollutants, exemptions for units 

that infrequently burn oil, a 30 day averaging period 

for demonstrating compliance with emission standards, 

and alternative standards that could reduce monitoring 

requirements. In addition, although the Clean Air Act 

generally allows only three years to comply with the 

Utility Air Toxics Rule, EPA’s proposal emphasizes that 

states can provide waivers to allow a fourth year for 

facilities to install controls if plants are unable to do so 

in three years despite good faith efforts.

Similarly, the proposed cooling water rules provide 

important flexibility with respect to the timing and 

choice of compliance technologies. Facilities will have 

up to eight years to implement lower-cost compliance 

measures, such as screens or velocity reduction. For the 

largest water users, EPA’s proposed rule will require a 

case-by-case evaluation—one that considers site-specific 

constraints, the useful life of the facility, electric 

reliability impacts, and weighs cost against benefits—to 

determine which control technologies, if any, will be 

required. If a cooling tower is required, fossil-fired 

facilities are provided 5–10 years and nuclear facilities are 

provided 10–15 years to come into compliance.

Additional options are available that can address 

unexpected reliability impacts as a last resort. These 

include authorities to delay compliance deadlines under 

the Federal Power Act, authorities for the President 

to delay implementation, and the ability to exercise 

enforcement discretion through the use of consent 

decrees to address specific, special circumstances. While 

it is unlikely that these authorities will be needed, 

government agencies should make it clear that they will 

avail themselves of these tools if necessary.

B. Planning and Coordination

A number of planning tools and authorities are available 

and should be used to help smooth the transition to a 

new suite of environmental regulations in the coming 

decade. Although attention has focused on reliability 

concerns related to plant retirements, BPC believes that 

managing a large number of pollution control retrofits 

in a relatively short period could also be a challenge. If 

many plant owners delay retrofits to near the end of the 

Air Toxics compliance period, scheduling problems could 

arise that would increase the need for compliance waivers 

and reliability-must-run agreements, potentially driving 

up costs. Plant owners should be encouraged—including 

through concrete incentives, to the extent possible—to 

start the process of installing controls immediately. State 

policy makers should look for opportunities to influence 

the timing of retrofits and to help spread out scheduled 

installations within the compliance window. In addition, 
40 Environmental Regulation and Electric System Reliability

95 There are currently differing requirements in PJM, MISO, NYISO.

96 National Commission on Energy Policy. Clean Energy Technology Pathways: An Assessment of the Critical Barriers to Achieving a LowCarbon Energy Future. March 2010.

neighboring RTO/ISOs that share transmission corridors 

and may rely on each other to provide adequate reserve 

margins should consider coordinating their outage 

schedules as well. 

To play a more proactive role, FERC could consider 

extending the length of the required notification period 

for proposed plant retirements to allow more time 

for reliability assessments.95 If FERC acted to increase 

advance notice requirements for unit retirements, the 

need to rely on RMR contracts as an interim measure 

to assure grid security would be reduced, and the stress 

of assuring grid reliability in the face of retirements and 

retrofits may be mitigated. 

Finally, DOE and FERC should look to additional 

authorities under the Federal Power Act that can be used 

to support long-term planning for a smoother, more costeffective transition. For example, DOE and FERC could 

collaborate to use their information gathering authorities to 

conduct assessments for decision making and coordinated 

planning. This type of coordination could help identify 

regions with potential resource adequacy problems and 

provide a mechanism for aggregating and disseminating 

information about the regulatory and market tools that are 

available for addressing potential problems. A stakeholder 

process involving federal agencies, RTOs/ISOs, and 

utilities could be used to develop strategies for addressing 

challenges posed by retirement and retrofit scheduling and 

to share best practices.

C. Siting and Permitting 

for New Infrastructure

The transition to a cleaner, more efficient generation 

system will require investment in energy efficiency, 

demand response strategies, and new generation 

capacity along with associated transmission and pipeline 

infrastructure. Additional generation capacity will be 

needed to replace retired coal generation and, potentially 

to ensure reliability during retrofit outages. Energy 

efficiency and demand response strategies can help lower 

overall demand for electricity and better manage demand 

during peak periods. Some additional transmission 

infrastructure will be necessary to address shifts in 

generation capacity and demand, and pipelines may be 

necessary to transport natural gas to new gas-fired plants. 

Previous BPC reports have noted that siting energy 

facilities in the United States has evolved into a complex, 

multi-jurisdictional, and often contentious process 

that is in need of reform.96 Although a full discussion 

of potential reforms is beyond the scope of this 

report, it is worth noting that the upcoming period of 

transition in the power sector provides an opportunity 

for policy makers at the state and federal levels to seek 

improvements in the siting and permitting process.

D. Legislative Opportunities

There may be a short window of opportunity for a 

legislative change that could guarantee the environmental 

benefits of the Clean Air Act and provide a smoother 

transition for the power sector. To be successful, multipollutant legislation would need to provide certainty 

and encourage rational and timely investment decisions, 

so that plant owners begin adding pollution controls 

immediately at facilities that will remain economically 

viable; while also planning and coordinating the 

retirement and replacement of plants that will have 

to be shut down. For the minority of plants where 

the outcome is unclear, it will be important to get the 

information needed to make a determination in time to 

comply. Further, multi-pollutant legislation should aim 

to guarantee equivalent or greater environmental benefits 

than available under current authority. 

Well-crafted legislation could also provide greater certainty 

about environmental outcomes and provide the incentives 

and the regulatory clarity to get started sooner. Absent new 

legislation, litigation over the upcoming rulemakings could 

prolong uncertainty over what will ultimately be required 

and when. In addition, the current structure provides little 

incentive to begin retrofits early and to turn on installed 

controls before the compliance deadline. Legislation 

could introduce such incentives and provide a backstop 

requirement that would be applicable if EPA is not able 

to promulgate regulations in time or if those regulations 

are tied up in litigation. This was the approach used in 

the successful, market-based Acid Rain Program, which is 

widely acknowledged to have achieved significant public 

health environmental benefits at lower than expected cost.

BPC continues to believe that addressing multiple 

pollutants in an integrated way can provide certainty, 

and encourage rational and timely investment decisions 

in pollution controls and new capacity. Several marketbased, multi-pollutant legislative proposals have been 

developed in recent years. The BPC believes that the 

public health and economic benefits of these types 

of coordinated approaches are worth exploring in the 

coming months.

Well-crafted legislation could provide greater 

certainty about environmental outcomes and 

provide the incentives and the regulatory 

clarity for utilities to begin retrofits early.
Environmental Regulation and Electric System Reliability 41
Appendix 

A

The Bipartisan Policy Center, together with 

the National Association of Regulatory Utility 

Commissioners (NARUC) and Northeast States for 

Coordinated Air Use Management (NESCAUM), 

hosted a three-part workshop series from October 

2010 through January 2011 exploring how to ensure

the reliability of our nation’s electric system 

without jeopardizing important progress on 

public health and environmental protection. Materials 

from each of these workshops, including video and 

presentations, can be found on our website.97

The three workshops featured presentations by leading 

experts on electric power system reliability, electricity 

market operation, power sector technology, and 

pollution control policies and regulations.

List of Expert Speakers

from BPC Workshops

on Environmental 

Regulation and Electric 

System Reliability

97 See http://www.bipartisanpolicy.org.
Environmental Regulation and Electric System Reliability 43

Workshop I: Power Sector Environmental Regulations

Jason Grumet, President, Bipartisan Policy Center 

Jennifer Macedonia, Senior Advisor, Bipartisan Policy Center 

Daniel Greenbaum, President, The Health Effects Institute 

Scott Segal, Partner, Bracewell & Guiliani 

Dr. Susan Tierney, Principal, The Analysis Group 

Commissioner Rick Morgan, DC Public Service Commission

Joseph Goffman, Senior Counsel to Asst. Administrator, 

Office of Air, US EPA 

Dr. James Staudt, Principal, Andover Technology Partners 

Dr. Larry Monroe, Senior Research Consultant, Southern Company 

David Hawkins, Director of Climate Programs, Natural Resources 

Defense Council 

Dave Foerter, Executive Director, Institute of Clean Air Companies 

David Conover, Senior Vice President, Bipartisan Policy Center

Alex Livnat, Ph.D, US EPA Office of Resource Conservation 

and Recovery 

Dr. Julie Hewitt, Branch Chief, US EPA Office of Water 

John Novak, Ex. Director, Federal and Industry Activities, 

Electric Power Research Institute 

Lisa Evans, Senior Administrative Counsel, Earthjustice

Joseph Stanko, Jr., Partner, Hunton and Williams 

Reed Super, Attorney, Super Law Group, LLC 

Workshop II: Reliability Impacts of Power Sector Developments

David Conover, Senior Vice President, Bipartisan Policy Center

Tom Wilson, Senior Program Manager, Electric Power Research 

Institute

Howard Gruenspecht, Ph.D., Deputy Administrator, US Energy 

Information Administration 

Joseph Chaisson, Research and Technical Director, Clean Air Task 

Force 

Steve Fine, Vice President, ICF International 

Frank Huntowski, Director, The Northbridge Group 

John McManus, Vice President of Environmental Services, 

American Electric Power

John Shelk, President and CEO, Electric Power Supply Association 

Chairman Ron Binz, Colorado Public Utilities Commission

John Moura, Technical Analyst, North American Electric 

Reliability Corporation 

Paul Sotkiewicz, Ph.D, Chief Economist, Markets, PJM 

Interconnection 

Ira Shavel, Vice President, Charles River Associates 

Bill Tyndall, Senior Vice President, Government and Regulatory 

Affairs, Duke Energy 

Mark Brownstein, Deputy Director, Energy Program, 

Environmental Defense Fund 

Joe McCartin, Deputy Director, Building and Construction 

Trades Department 

Joe Kruger, Policy Director, Bipartisan Policy Center 

Workshop III: Local, State, and Regional and Federal Solutions

Jason Grumet, President, Bipartisan Policy Center 

Chairman Jon Wellinghoff, Federal Energy Regulatory Commission 

Vice Chairman James Gardner, Kentucky Public Service Commission

Commissioner Rick Morgan, DC Public Service Commission

Chairman Edward Finley, Jr., North Carolina Utilities Commission 

Pamela Faggert, Vice President and Chief Environmental Officer, 

Dominion

John Hanger, former Secretary, PA Department of Environmental 

Protection

Sonny Popowsky, Consumer Advocate of Pennsylvania 

Paul Miller, Deputy Director, NESCAUM

Sue Tierney, Managing Principal, Analysis Group, Inc 

Paul Sotkiewicz, Ph.D, Chief Economist, Markets, PJM 

Interconnection

John Lawhorn, Sr. Director, Midwest Independent System Operator 

Kathleen Barron, Vice President, Exelon Corporation

Garey Rozier, Resource Planning Manager, Southern Company

Chris James, Senior Associate, Regulatory Assistance Project

Linda Stuntz, Founding Partner, Stuntz, Davis, & Staffier, PC 

Peter Tsirigotis, Division Director, US Environmental Protection 

Agency

Doug Smith, Member, Van Ness Feldman

Jeff Holmstead, Head of Environmental Strategies, Bracewell 

& Guiliani

David Hawkins, Director of Climate Programs, Natural Resources 

Defense Council

David Conover, Senior Vice President, Bipartisan Policy Center

Maryam Brown, Majority Staff, House Energy and Commerce 

Committee

Alexandra Teitz, Senior Counsel, House Energy and Commerce 

Committee

Michael Catanzaro, Deputy Staff Director, Senate Environment 

& Public Works

Jonathan Black, Professional Staff, Senate Energy and Natural 

Resources Committee 
BPC modeled the impacts of pending EPA 

regulations for the power sector using ICF 

International’s Integrated Planning Model (IPM). IPM 

is a model designed to simulate the behavior of 

the U.S. and Canadian wholesale electricity markets. 

To do so it uses an extensive database that 

contains information on every boiler and 

generator in the nation. 

BPC Modeling 

using ICF’s

Integrating 

Planning Model

Appendix

B
Environmental Regulation and Electric System Reliability 45

98 Based on Utility Solid Waste Activities Group. 2010. Cost estimates for the mandatory closure of surface impoundments used for the 

management of coal combustion byproducts at coal-fired electric utilities. Prepared by The EOP Group, Inc., Washington, DC.

IPM is a multi-region model that endogenously 

determines capacity and transmission expansion 

plans, unit dispatch and compliance decisions, and 

power, coal, and allowance price forecasts, all based 

on power market fundamentals. To utilize the model, 

it is necessary to make a number of assumptions 

concerning key market parameters, including electricity 

demand growth, fuel prices, cost and performance of 

new generating capacity, and cost and performance of 

pollution controls and other options for complying 

with environmental regulations. This appendix 

discusses the assumptions and regulatory compliance 

scenarios included in the BPC analysis.

A. Assumptions for Analysis

BPC based most of the assumptions for this analysis 

on information from the Energy Information 

Administration’s Annual Energy Outlook (EIA AEO 

2010) and the Environmental Protection Agency’s 

IPM Base Case 2009 ARRA (EPA ARRA). In some 

cases, BPC selected alternative assumptions to reflect 

recent market conditions. Assumptions for electricity 

demand growth, cost and performance of new capacity, 

and costs of regulatory compliance options were held 

constant across all the scenarios analyzed. Natural gas 

and coal prices varied by scenario based on the relative 

fuel demand from scenario to scenario. Table B-1 below 

summarizes the sources of key assumptions in the 

analysis. Tables B-2 through B-4 summarize our detailed 

assumptions for select parameters.

Table B-1: Sources of Key Input Assumptions

Input Parameter Source of Assumption Notes

Electric demand growth EIA AEO 2010

Cost and performance of new 

generation capacity, including 

new project financing 

EIA AEO 2010 New coal capacity without carbon capture 

technology included a risk premium in 

financing costs, consistent with the approach 

used by EIA

Natural gas prices EIA AEO 2010 (BPC Base Case)

Gas price sensitivity at minus 

$1/MMBtu below the AEO2010-

based supply curve

To realize gas price response in scenarios 

other than the BPC Base Case, ICF derived 

a measure of supply elasticity from multiple 

AEO 2010 scenarios and applied it to the BPC 

Base Case price and gas demand projections 

to generate a supply curve

Coal prices ICF coal supply curves calibrated to 

EIA AEO 2010 prices and quantities

Cost and performance of air 

pollution controls

EPA ARRA (SCR, SNCR, ACI), 

BPC (FGD, fabric filter, DSI)

BPC assumed higher capital costs for fabric 

filters and wet scrubbers (FGD) than those 

used in EPA ARRA to reflect costs closer to 

recent market experience 

Cost of compliance options 

for coal ash and water intake 

regulations

NERC (cooling towers),

EOP Group (ash)98

BPC (alternative water intake 

compliance)
46 Environmental Regulation and Electric System Reliability

99 NERC. 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential US Environmental Regulations. October 

2010. Available at http://www.nerc.com/files/EPA_Scenario_Final.pdf

100 Based on Utility Solid Waste Activities Group. Cost estimates for the mandatory closure of surface impoundments used for the 

management of coal combustion byproducts at coal-fired electric utilities. Prepared by The EOP Group, Inc., Washington, DC. 2010

Table B-2: BPC Assumptions for the Cost and Performance of Air Pollution Controls

Capacity 

(MW) Wet FGD DSI SCR SNCR Fabric Filter ACI

Capital Cost 

(2006$/kW)

300 564 37 168 20 131 Bit - H 3.65

Bit - L 2.72

Lig 25.11

Sub 3.86

500 487 NA 147 15 123

700 442 NA 140 NA 118

Variable O&M

(2006$/MWh) 1.80

Bit 8.46

Sub & Lig 

3.83

0.64 0.79

Bit - H 0.10

Bit - L 0.05

Lig 0.11

Sub 0.10

Bit - H 0.41

Bit - L 0.27

Lig 0.50

Sub 0.35

Energy Penalty 2.1% 0.02% 0.5% 0% 0.5% 0%

% Removal SO2

 - 95% SO2 - 70% NOX - 85% NOX - 30% PM - 99.95% Hg - 90%

First Year Allowed 2013 2013 2013 2011 2011 2011

Source BPC BPC EPA EPA EPA EPA

Bit = Bituminous coal; Sub = Subbituminous coal; Lig = Lignite; O&M = Operating and Maintenance Costs.

Note: The 70% SO2

 removal rate for DSI assumes a fabric filter is present. As a conservative modeling assumption to account for site-specific 

challenges, BPC assumed that DSI was only an option for units ≤ 300MW and that units projected to install DSI are restricted to burning low 

sulfur coals (2 lb SO2

/MMBtu). 

Table B-3: BPC Assumptions for 316(b) Water Rule Compliance

Water 

(2006$/kW) Capacity (MW) Cooling Tower Alternate Compliance

Capital Costs

300 184 18

500 138 14

700 138 14

Note: Cooling tower costs derived from North American Electric Reliability Corporation.99 Alternative compliance costs based on 

BPC assumption of 10% of cooling tower cost.

Table B-4: BPC Assumptions for Coal Combustion Waste Rule Compliance

Ash 

(Million 2006$)

Fly Ash 

Conversion

Bottom Ash 

Conversion

Wet Ash 

Conversion

Landfill 

Expansion

Capital Costs 23 20 200 30

Fixed O&M - - 4.5 3.0

Note: Ash related costs derived from EOP Group, Inc.100
Environmental Regulation and Electric System Reliability 47

101 CAIR has since been replaced with the Transport Rule, proposed in July 2010. The latter provides for more stringent caps on SO2

 and NOX, 

as well as trading restrictions and limits on the use of “banked” allowances from past years of over-compliance with the SO2 Acid Rain 

Trading Program. Other analyses indicate that the incremental changes between CAIR and the Transport Rule are not a significant driver 

in the context of the suite of EPA regulations. Thus, the policy scenario does not reflect incremental changes from CAIR, other than to 

restrict the use of allowances banked prior to 2012.

102 Some studies indicate that upgrades to existing electrostatic precipitators may be sufficient to comply. (Lipinski, 2011).

103 Studies and EPA analysis of the Air Toxics Rule indicate that lower cost dry scrubber technology combined with particulate controls would 

be an alternative option for acid gas compliance and that DSI may also be an option for larger units. (Lipinski, 2011)

B. Description of Scenarios

For this analysis, BPC defined three cases to examine the 

impacts of EPA’s proposed regulations on the U.S. power 

sector. BPC had ICF analyze these cases using IPM 

based on the assumptions described above. The three 

cases included a base case, a regulatory scenario, and a 

regulatory scenario with lower natural gas prices. The 

cases are described in more detail below.

BPC Base Case

The BPC Base Case represents a business-as-usual 

(BAU) projection in that it includes only existing 

federal and state regulations. It assumes regional cap 

and trade programs for SO2

 and NOX in the eastern 

U.S., as promulgated under Phases I and II of the Clean 

Air Interstate Rule (CAIR).101 It does not include any 

federal mercury or carbon dioxide emission reduction 

requirements. The BPC Base Case includes existing state 

mercury, SO2

 and NOX requirements, as well as state 

renewable portfolio standards. Pollution control and 

retirement decisions reflected in completed New Source 

Review consent decrees and public announcements are 

also included in the BPC Base Case and the other cases. 

Regulatory Case

The second case includes requirements under EPA’s 

proposed suite of new regulations, including the Utility 

Air Toxics Rule, transport, and proposed water intake and 

coal ash rules. BPC assumed the following requirements 

for each of the proposed rules:

Clean Air Transport Rule (CATR) – The 

case includes CAIR Phases I and II as a proxy for 

CATR. However, BPC assumes no banking of SO2

allowances from the Title IV Acid Rain Program 

and CAIR into 2012, reflecting the start of the new 

program under CATR. The Phase II caps under 

CAIR have been modified for NOX to reflect tighter 

standards expected under the new ozone NAAQS. The 

CAIR Phase II caps were scaled in 2018 to reflect a 

0.10 lb/MMBtu standard in place of the CAIR 0.125 

lb/MMBtu standard. To reflect Best Available Retrofit 

Technology (BART) requirements in states not subject 

to CAIR, units were required to control for NOX with 

SCR so long as the cost of control was equivalent to 

less than $5000 per ton of NOX avoided.

Utility Air Toxics Rule – BPC assumes that 

all coal-fired electric generating units (EGUs) must be 

controlled with a suite of controls intended to meet 

emissions standards to continue operating past the 

2015 compliance deadline. If units do not control by 

2015, they must retire. As a conservative assumption, 

control of metals is assumed to require a fabric filter 

for every unit.102 The analysis assumes that units greater 

than 300 MW meet the standard for acid gases (HCl) 

with a wet scrubber (flue gas desulfurization, FGD) 

and that units less than 300 MW in size may meet 

the standard for acid gases with either dry sorbent 

injection (DSI) combined with the fabric filter and 

low sulfur coal or, alternatively, with a wet scrubber.103

Although a dry scrubber, estimated at 10-20% lower 

cost than a wet scrubber, would be an option in 

combination with particulate controls to comply with 

the HCl limit, it is not an assumed option in this 

Figure B-1: BPC Natural Gas Supply Curves

(for Gas Supplied to Power Sector) 

10

9

8

7

6

5

4

3

2

1

0

0 2000 4000 6000 8000 10000

Price Step (2006$/MMBtu)

TBtu

2015

2020

2025

TBtu: Trillion British thermal units
48 Environmental Regulation and Electric System Reliability

104 For mercury removal, the scenario assumes that a plant burning primarily bituminous coal with installed FGD, baghouse, and selective 

catalytic reduction (SCR) (for NOX) controls will meet the Utility Air Toxics Rule 90% mercury removal requirement with no carbon 

injection. This is a simplified estimate based on an assumption that, for a bituminous coal plant with a baghouse, any additional cost for 

carbon injection (polishing ACI) would be modest. All other plants are assumed to require activated carbon injection.

105 Data on wet and dry ash handling are taken from EIA Form 923 reporting.

106 U.S. EIA Annual Energy Outlook (AEO) 2011 projection averages nearly $1.24/MMBtu lower than the AEO 2010 projection over the 

period 2011 to 2030. 

analysis. To meet mercury standards, units may be 

controlled with activated carbon injection (ACI) or, for 

units burning bituminous coals, with a combination of 

wet scrubber and SCR controls.104

Water Intake (316(b)) – BPC assumes water 

intake structure compliance by 2022 (fossil) and by 

2027 (nuclear), both reflected as 2025 in the modeled 

scenario. Facilities with a weighted average capacity 

factor of at least 35 percent in 2009 and flow design 

intake greater than 500 million gallons per day (MGD) 

are assumed to require cooling towers to operate past 

the compliance date. Facilities that do not meet those 

two conditions must install alternative compliance 

measures, estimated by BPC to cost one-tenth the cost 

of a cooling tower at the facility. 

Ash Handling (coal combustion waste) – 

BPC assumes that coal-fired facilities must fully 

convert to dry ash handling in order to continue 

operating in 2015 and later. The case assumes 

implementation consistent with EPA’s proposal 

under Subtitle D. Ash is not classified as hazardous 

and may continue to be used for beneficial purposes. 

For facilities that already manage some ash using dry 

handling systems, the retrofit costs shown above were 

prorated by the share of total ash managed using wet 

handling systems.105

Regulatory Case with Low Gas Prices

Natural gas price levels are critical to determining 

the projected impacts of EPA’s regulations on the 

power sector. As noted earlier, the BPC Base Case and 

Regulatory Case relied on natural gas price projections 

based on EIA’s AEO 2010. Since the publication of AEO 

2010 in early 2010, expert projections of future natural 

gas prices have continued to fall as they incorporate 

growing resource projections for shale gas.106 To reflect 

this expectation of lower future natural gas prices, BPC 

includes a sensitivity case that assumes prices $1/MMBtu 

lower in each year compared to the projected price in the 

Regulatory Case.

c. Select Results of BPC Analysis

The following charts present select results for the three 

BPC cases described in the previous section. Unless 

specified otherwise, the results are presented for the 

continental United States as a whole, not including 

Hawaii and Alaska. 

70,000

60,000

50,000

40,000

30,000

20,000

10,000

0

2015 2020 2025 2030

Million 2006$

BPC Base 

Case (BAU)

Regulatory Case

Low Gas Prices

Regulatory Case

Figure B-2: Projected Annualized Capital Expenditures for Regulatory 

Compliance and New Generating Capacity 
Environmental Regulation and Electric System Reliability 49

Figure B-2 shows annualized capital expenditures 

on all new air pollution control equipment, water 

intake and ash handling compliance retrofits, and new 

generating capacity. The 2015 value includes compliance 

investments for the Utility Air Toxics Rule and ash 

handling requirements. Water intake costs are incurred 

in 2025. Expenditures on new capacity take place over 

the entire period to meet demand growth and, in the 

EPA Regulatory cases, to replace capacity that retires in 

response to the regulations. 

Capital expenditures, which do not include fuel and 

other costs to generate and distribute electricity, are 

about $10 billion higher in the Regulatory Cases 

compared to the BPC Base Case in 2015. The differential 

increases over time as costs are incurred for water intake 

compliance and incremental capacity additions. Costs 

in the Low Gas Price case are slightly lower due to lower 

compliance investments.

The assumed compliance requirements in the EPA 

Regulatory Cases drive up retirements of coal-fired 

capacity relative to the BPC Base Case. The regulations 

increase coal unit retirements by 15 GW and 21 GW in 

the Regulatory Case and in the Regulatory Case with Low 

Gas Prices, respectively, by 2030. Retirements of oil and gas 

steam capacity change very little from the BPC Base Case.

60

50

40

30

20

10

0

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2015

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2020

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2025

BPC Base Case (BAU)

Suite of EPA Rules

Low Gas Prices Regulatory Case

2030

GW

Oil/Gas

Steam

Coal

Figure B-3: Projected Unit Retirements by Type
50 Environmental Regulation and Electric System Reliability

107 The BPC analysis assumes costs for compliance with the ash handling requirements for coal-fired facilities that are proportional to the 

current share of wet ash handling at the facility. For example, a facility that currently relies on wet handling for one-half of its total ash 

handling needs is assumed to incur a cost equivalent to one-half the cost of a facility that is the same size and must convert all of its 

handling from wet to dry methods. BPC analysis projects that 98 facilities will be affected, either in whole or in part, by the ash handling 

requirements in the Regulatory Case.

Tables B-5 (a) and (b): Projected Compliance Expenditures and Units Controlled

(Additional to BPC Base Case) 

Table B-5(a): BPC Regulatory Case

2015 2020 2025 2030

Incremental Annualized Capital Expenditures (Million $): Change from BPC Base Case

FGD 3,170 3,170 3,170 3,165

DSI 282 282 282 282

ACI 165 161 160 160

FF 3,463 3,432 3,432 3,432

SCR 525 691 703 731

Ash 2,897 2,897 2,897 2,897

Cooling Towers 0 0 1,626 1,626

Incremental Number of Units Controlled: Change from BPC Base Case

FGD 85 85 85 84

DSI 199 199 199 199

ACI 392 385 381 381

FF 541 536 536 536

SCR 34 47 48 48

Ash (Facilities, in whole or in part)107 98 98 98 98

Cooling Towers (Facilities) 0 0 93 93

Table B-5(b): BPC Regulatory Case with Low Gas Prices

2015 2020 2025 2030

Incremental Annualized Capital Expenditures (Million $): Change from BPC Base Case

FGD 3,124 3,124 3,124 3,119

DSI 245 245 245 245

ACI 157 154 153 153

FF 3,331 3,300 3,300 3,300

SCR 411 582 587 650

Ash 2,797 2,797 2,797 2,797

Cooling Towers 0 0 1,610 1,610

Number of Units Controlled: Change from BPC Base Case

FGD 84 84 84 83

DSI 181 181 181 181

ACI 368 360 356 356

FF 516 511 511 511

SCR 28 41 40 44

Ash (Facilities, in whole or in part) 96 96 96 96

Cooling Towers (Facilities) 0 0 92 92
Environmental Regulation and Electric System Reliability 51

Figure B-4 shows projected natural gas prices at Henry 

Hub for the three cases. Prices in the BPC Base Case 

climb over time as demand for gas increases with electric 

demand growth. In the Regulatory Case, natural gas 

prices increase in 2015 and beyond in response to coal 

retirements and increased demand for gas to replace 

some part of that generation. As new coal capacity is 

brought online, gas demand and prices in the two cases 

approach each other and end up converging by 2030.

Figure B-5 shows cumulative U.S. capacity additions by 

type. In the BPC Base Case, the build mix is dominated 

by gas-fired capacity and renewable capacity, with the 

latter required to meet state RPS requirements. Higher 

natural gas prices in the Regulatory Case make new coal 

capacity an economic option, even with a financing risk 

premium to reflect potential carbon liabilities. Lower gas 

price assumptions in the Low Gas Price sensitivity case 

shift the economics back toward gas capacity, but some 

new coal capacity is also built.

Figure B-4: Projected Natural Gas Prices at Henry Hub 

9

8

7

6

5

4

3

2

1

0

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

2006$/MMBtu

BPC Base 

Case (BAU)

Regulatory Case

Low Gas Prices 

Regulatory Case

Figure B-5: Cumulative Projected Capacity Additions by Type

160

140

120

100

80

60

40

20

0

GW

Biomass

Other 

Renewables

Wind

Nuclear

CT

CC

Coal

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2015

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2020

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2025

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2030
52 Environmental Regulation and Electric System Reliability

Figure B-6 shows the U.S. generation mix by type across 

the three cases. Generation from coal declines by 5–7 

percent in the Regulatory Cases relative to the Reference 

Case due to retirements motivated by EPA’s new 

regulatory requirements. Increased gas-fired generation 

makes up for the majority of that decline. In the 

Regulatory Case, generation from gas makes up roughly 

three-quarters of the decline in coal generation. With 

lower gas prices in the Low Gas Price Case, higher output 

from gas-fired generators makes up nearly 90 percent 

of the reduction from coal. In both cases, increased 

generation from renewables also contributes to meeting 

overall electricity demand growth over time.

Figure B-6: Projected Generation Mix by Fuel Type

5000

4500

4000

3500

3000

2500

2000

1500

1000

500

0

Thousand GWh

Other

Biomass

Other 

Renewables

Wind

Hydro

Nuclear

Oil/Gas

CT

CC

Biomass 

Co-firing

Coal

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2015

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2020

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2025

BPC Base Case (BAU)

Regulatory Case

Low Gas Prices Regulatory Case

2030
The savings below are achieved when PC recycled fiber is used in place of 

virgin fiber. This project uses 1340 lbs of paper, which has a post consumer 

recycled percentage of 20%.

2 trees preserved for the future

7 lbs water-borne waste not created

956 gal wastewater flow saved

106 lbs solid waste not generated

208 lbs net greenhouse gases prevented

1,594,600 BTUs energy not consumed

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