1 

Ensuring a Clean, Modern 

Electric Generating Fleet while 

Maintaining Electric System 

Reliability 

August 2010 
2 

Acknowledgements

The following report was prepared on behalf of the Clean Energy Group’s Clean Air Policy 

Initiative, a coalition of electric companies dedicated to responsible energy and environmental 

stewardship. The participating companies (listed below) are some of the nation’s largest 

generators of electricity, with over 170,000 megawatts of electric generating capacity (including 

110,000 megawatts of fossil generating capacity) throughout the U.S., and serve nearly a fifth of 

all U.S. electric customers. 

Calpine Corporation 

Constellation Energy 

Entergy Corporation 

Exelon Corporation 

NextEra Energy 

National Grid 

PG&E Corporation 

Public Service Enterprise Group 

REPORT AUTHORS 

Michael J. Bradley, M.J. Bradley & Associates LLC 

Susan F. Tierney, Analysis Group 

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

Paul J. Hibbard, Analysis Group 

Amlan Saha, M.J. Bradley & Associates LLC 

Carrie Jenks, M.J. Bradley & Associates LLC 

For questions or comments about this report, please contact: 

Christopher Van Atten 

M.J. Bradley & Associates LLC 

47 Junction Square Drive 

Concord, MA 01742 

Telephone: 978 369 5533 

E-mail: vanatten@mjbradley.com 
3 

Executive Summary

In the 20 years since the Clean Air Act (“CAA”) Amendments of 1990, electric power companies 

throughout the United States have deployed a wide range of pollution-control technologies, new power 

plants with relatively low emissions, and demand-side measures to reduce air emissions from electricity 

production. The Environmental Protection Agency (“EPA”) has found, however, that despite this 

significant progress in reducing emissions, in 2008 about 127 million Americans still lived in counties 

with unhealthy air—many of which are located along the Ohio River Valley, in the Middle Atlantic, and 

in the Southeast.1,2

To begin to address these issues, on August 2, 2010, EPA published its draft Clean Air Transport Rule 

(the “Transport Rule”), regulating emissions in 31 Eastern states and the District of Columbia where 

controlling emissions will produce the greatest public health benefit.3 EPA plans to implement the 

Transport Rule on January 1, 2012. Additional rulemakings are also underway to regulate hazardous air

pollutants (“HAPs”), with EPA under court order to promulgate its final “Utility MACT” rule by 

November 2011. According to EPA, compliance would be required by early 2015.4

 

These new rules regulating air emissions from fossil fuel-fired power plants will require certain 

uncontrolled plants to install pollution control equipment. Third-party analysts have concluded that some 

coal plant owners may choose to retire units in lieu of such installations. For example, two recent studies 

suggested that between now and 2015, the combination of low energy prices and EPA air regulations 

could result in the retirements of between 25 to 40 gigawatts (“GW”)5,6 of the nation’s 1,030 GW of 

electric generating capacity.7 

Although some of the nation’s less efficient power plants may be retired, many existing coal plants will 

be retrofit with new pollution controls. Approximately half of the nation’s coal-fired generating capacity 

(150 GW) has already installed SO2 scrubbers, another 55 GW plan to install scrubbers, and a significant 

number of coal units have already announced plans to retire,8

 leaving approximately one-fourth of the 

nation’s coal-fired generation to add pollution controls, switch to a cleaner fuel, or retire. Companies 

may also have the option to purchase allowances or adjust dispatch to comply with certain rules. 

 

1

 U.S. EPA, Draft FY 2011-2015 EPA Strategic Plan, at p. 7. Collectively, power plants are responsible for 66 percent of SO2

emissions, 19 percent of NOx emissions, and 39 percent of CO2

 emissions in the U.S. Also, in 2002, the EPA cataloged 

emissions in the United States and concluded that fossil-fuel-fired power plants were responsible for the following percentages of 

nationwide emissions for the following HAPs (all figures are approximate): hydrochloric acid (60%); mercury compounds 

(45%); arsenic compounds (35%); and nickel compounds (25%). U.S. EPA, 2002 National Emissions Inventory Booklet.

2

 According to the recent National Academy of Sciences, Hidden Costs of Energy: Unpriced Consequences of Energy Production 

and Use (2010), “after ranking all the [power] plants according to their damages, we found that the most damaging 10% of 

plants produced 43% of aggregate air-pollution damages from all plants, and the least damaging 50% of the plants produce less 

than 12% of aggregate damages” ...(and) the most damaging 10%...account for approximately one quarter of electricity 

generated at the 406 plants.” (at p. 88). 

3

 Office of Air and Radiation, U.S. EPA, Air Transport Rule Factsheet, at p. 1. 

4

 U.S. EPA, Proposed Rule: Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and 

Ozone. August 2, 2010. 

5

 PIRA Energy Group (“PIRA”), EPA’s upcoming MACT; Strict Non-Hg Can Have Far-Reaching Market Impacts, April 8, 

2010. 

6

 ICF International, EEI Preliminary Reference Case and Scenario Results. May 21, 2010. 

7

 Energy Information Administration (“EIA”), Electric Power Monthly, July 2010. (Based on preliminary 2009 capacity, capacity 

additions and retirements up through April 2010.) 

8

 PIRA, supra n.5.
4 

Some in the industry have raised concerns about the combined effects over the next five years of 

anticipated power plant retirements and outages required to install new pollution control equipment. 

Clearly, the nation must carefully consider how to maintain electric system reliability, while also 

improving our nation’s health and environmental quality. 

In this paper, we highlight the impact of EPA’s upcoming air regulations, with a focus on the issue of

possible power plant retirements on electric reliability. We conclude that, without threatening electric 

reliability, the industry is well-positioned to respond to EPA’s proposed road map to “help millions of 

Americans breathe easier, live healthier,”9

 provided that EPA, the industry and other agencies take 

practical steps to plan for the implementation of these regulations and adopt appropriate regulatory 

approaches. In particular, we conclude the following: 

1. Even though some units likely will retire in lieu of complying with the new regulations, 

electric system reliability will not be compromised if the industry and its regulators 

proactively manage the transition to a cleaner, more efficient generation fleet. 

o Power system reliability relates not only to generation capacity and availability, but 

also to consumption levels and patterns, and transmission capacity and use. As such, 

all these factors must be considered when assessing reliability impacts. Existing 

power system capacity well in excess of minimum reserve levels, relatively modest 

projections of load growth over the next several years, a large amount of proposed 

generating resources, and the availability of load management practices indicate the 

system can handle the level of projected retirements. 

o Each North American Electric Reliability Corporation (“NERC”) reliability region 

has excess capacity, totaling over 100 GW of excess capacity nationwide. Therefore, 

considering only the projected level of coal unit attrition relative to existing capacity 

resources, it appears there will be no capacity shortages even if projected retirement 

scenarios prove accurate. 

 

o Further, economic conditions have reduced the demand for electricity in recent years 

providing an additional capacity cushion to assist in managing any power plant 

outages required to install pollution controls. 

o The industry has a proven track record of adding new generating capacity and 

transmission solutions when and where needed and of coordinating effectively to 

address reliability concerns. In the three years between 2001 and 2003, the electric 

industry built over 160 GW of new generation—about four times what analysts 

project will retire over the next five years. 

o Notably, many of the regions of the country with organized wholesale markets, 

including many parts of the Midwest, Mid-Atlantic, and Northeast, have developed 

effective tools such as capacity markets and reserve sharing mechanisms enabling 

electric generators to access other companies’ available resources to assure regional 

reliability. 

o Additionally, the industry is deploying enhanced demand response actions, expanded 

energy efficiency programs, and new “smart grid” advances to manage consumption 

during the transition to cleaner, more efficient generation. 

 

9

 U.S. EPA, supra n.1, at p. 2. 
5 

 

2. Industry data counter concerns that it will cost the industry too much to comply with EPA’s 

proposed air regulations, that pollution controls cannot be installed soon enough, or that the 

EPA regulations will lead to the closure of otherwise economically healthy power plants. 

o The proven technologies for controlling air pollution emissions, such as NOx, SO2, 

mercury and acid gases, are commercially available and have already been, or soon 

will be, installed on the majority of the nation’s coal plants (65 percent with 

scrubbers; 50 percent with advanced NOx controls), demonstrating that the costs can 

be managed. 

o The industry has a demonstrated ability to schedule and sequence unit outages in an 

efficient and reliable manner and is capable of installing additional pollution control 

systems to comply with the Transport Rule and Utility MACT Rule. 

o Many of the coal units that are the most likely candidates to shut down are smaller, 

40 to 60 year old units, which are nearing the end of their design life expectancy and 

are already economically challenged. 

o Additionally, the retirement of some existing generating capacity will create room on 

the transmission grid to accommodate additional power flows, or new generating 

capacity, without requiring attendant upgrades in transmission, thus mitigating 

reliability concerns while reducing the cost of transitioning to a cleaner, more 

efficient generation fleet. 

3. EPA, the Federal Energy Regulatory Commission (“FERC”), the Department of Energy 

(“DOE”) and State utility regulators, both together and separately, have an array of tools to 

moderate impacts on the electric industry. 

o EPA may, and if needed, should exercise its statutory authority under the CAA to 

grant, on a case-by-case basis, extensions of time to complete pollution control 

installations where appropriate. 

o To the extent that its legal authority allows, EPA should adopt regulatory approaches 

that allow for cost-effective compliance, such as the emissions trading mechanism 

proposed in the Transport Rule. 

o In circumstances in which power plant retirements trigger localized reliability 

concerns, EPA and DOE should follow established precedent, including use of 

consent decrees, to permit continued operation for reliability purposes only, pending 

necessary upgrades or generation additions. Additionally, the various federal 

agencies and offices with responsibility for assuring reliability for the nation's 

electricity capability should work together to help support the industry and states in 

complying with EPA’s new air regulations. 

o Transparent, well-established market rules approved by FERC and overseen by 

independent market monitors, particularly the forward capacity markets relied on by 

some Regional Transmission Operators (“RTOs”), as well as state regulatory agency 

oversight, provide additional safety nets to help ensure adequate capacity. 
6 

o Although EPA is under court order to promulgate its air regulations, the Agency can 

and should coordinate the implementation of anticipated water regulations under 

Section 316(b) of the Clean Water Act (“CWA”) and new waste regulations to avoid 

possible reliability concerns.10

 

10 EPA should also consider the possible greenhouse gas emissions implications of its 316(b) regulations. In 2007, the U.S. 

Supreme Court found the EPA has clear statutory authority to regulate greenhouse gases under the CAA. Transitioning to a 

cleaner generating fleet will help EPA fulfill this obligation. 
7 

I. MANAGING ELECTRIC SYSTEM RELIABILITY WHILE IMPLEMENTING 

NEEDED ENVIRONMENTAL IMPROVEMENTS WITH SIGNIFICANT 

PUBLIC HEALTH BENEFITS 

A. The Electric System Has Substantial Excess Generating Capacity and Appropriate 

Processes in Place to Assure Reliable Electricity Supply to Consumers 

Currently, there are more than 17,000 electric generation units in the United States with a combined 

nameplate capacity of over 1,030 GW.11 In 2009, coal-fired generation produced 45 percent of the 

nation’s electricity, followed by natural gas (23 percent) and nuclear (20 percent), with the remaining 

amount produced through a combination of hydroelectric power, oil, wind and other miscellaneous fuel 

types.12

Power plant owners, transmission system owners, and power system operators plan and operate their 

systems according to numerous federal, state and local regulations, policies and protocols, applying 

planning requirements designed to ensure electricity suppliers have adequate resources to meet current

and future demand, and operational standards to ensure power is available when consumers turn on the 

lights. 

Power system reliability is tied to many things: generation plant capacity and availability, consumption 

levels and patterns, and transmission capacity and use. As such, electric system planners must consider 

all of these relevant system infrastructure and demand factors in assessing whether sufficient capacity will 

be available to maintain reliability. Existing power system capacity well in excess of minimum reserve 

levels, relatively modest projections of load growth over the next several years, a large amount of 

proposed generating resources throughout the country, and the availability of load management practices 

indicate the electric system should be able to handle the transition to a cleaner, more efficient generation 

fleet. 

Under FERC’s oversight, NERC sets standards to ensure the reliability of the nation’s electric system. 

NERC comprises eight regional reliability organizations (or “regions,” as shown below), whose members 

include grid operators, utilities, generating companies and others in the electric industry. 

 

11 EIA, supra n.7. 

12 EIA, Net Generation by Energy Source, http://www.eia.doe.gov/cneaf/electricity/epm/table1_1.html (accessed July 31, 2010). 
8 

Figure/Table 1 - NERC Electric Reliability Regions 

 FRCC – Florida Reliability Coordinating Council SERC – Southeast Reliability Corporation 

 MRO – Midwest Reliability Organization SPP – Southwest Power Pool, RE

 NPCC – Northeast Power Coordinating Council TRE – Texas Regional Entity

 RFC – Reliability First Corporation WECC – Western Electricity Coordinating Council

 Note: NERC regional results shown in this presentation include the continental US only 

Most of the nation’s regional reliability organizations cover multiple states and each manages and 

monitors compliance with NERC’s reliability standards, including maintenance of minimum target 

reserve margins, a key indicator of resource adequacy. Actual or expected reserve margins measure the

extent to which generating capacity exceeds (or falls short of) peak electricity demand. All regions must 

have capacity above expected demand to accommodate power plant outages, transmission failures, 

unexpectedly high demand, or other contingencies. Most regions have a minimum target reserve margin 

at or below 15 percent.13 In recent years, actual reserve margins around the country have been well above 

the minimum target levels, due not only to new power plant additions in most regions, but also to reduced 

demand attributable to the economic recession and increasingly robust load management programs.14

Table 2, below, illustrates that, in 2013, all NERC regions expect to have actual capacity levels well in 

excess of minimum reserve requirements. Although this provides only one metric of reliability, and each 

region will undertake more granular analysis in the months ahead, these capacity “cushions” indicate 

there should not be a capacity shortage even if projected retirement scenarios prove accurate. As the table 

further highlights, on an aggregate basis across all NERC regions, 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 retirements 

projected by PIRA Energy Group.15,16 Reliability First Corporation (“RFC”) and the Southeast Reliability 

Corporation (“SERC”) regions, for example, where most of the uncontrolled coal plants are located, are

 

13 Some regions are below 15%, such as TRE (12.5%), SPP (13.6%), WECC (14.7%). Regions that don’t establish a formal 

target are assigned one for planning purposes by NERC, with 15% for regions like the Midwest and 10% for regions with 

substantial hydroelectric power. NERC, 2010 Summer Reliability Assessment, May 2010. 

14 Id. 

15 NERC, 2009 Long-Term Reliability Assessment: 2009-2018, October 2009. 

16 PIRA, supra n.5. 
9 

expected to have high reserve margins at 24.3 percent and 26.3 percent, respectively.17 These regions 

could retire 17.1 GW (RFC) and 23.9 GW (SERC) of capacity and still maintain the 15 percent NERC 

reserve margin target. 

Table 2 - Estimated Reserve Margins in All NERC Regions: 

Adequate Generating Capacity

NERC Electric Reliability 

Region 

Projected Reserve Margin (1) 

in 2013 

Cushion Above NERC 

Target Reserve Margin (2)

 

In 2013 

TRE 23.9% 7.8 GW 

FRCC 28.6% 6.1 GW 

MRO 22.1% 3.2 GW 

NPCC 24.4% 5.9 GW 

RFC 24.3% 17.1 GW 

SERC 26.3% 23.9 GW 

SPP 30.3% 7.7 GW 

WECC 42.6% 35.6 GW 

Total 107.3 GW

1. Includes capacity defined by NERC as Adjusted Potential Reserve Margin, which is the sum of deliverable capacity 

resources, existing resources, confidence factor adjusted future resources and conceptual resources, and net provisional 

transactions minus all derates and net internal demand expressed as a percent of net internal demand. Source: NERC, 2009 

Long-Term Reliability Assessment: 2009-2018, October 2009, p. 396 (Summer Demand). 

2. Capacity in excess of what is required to maintain NERC Reference Margin or the regional target reserve levels. 

Source: NERC, 2009 Long-Term Reliability Assessment: 2009-2018, October 2009. 

Experience in the RFC region, which encompasses thirteen states in the Midwest and Mid-Atlantic 

regions, is illustrative of the electric system’s ability to tolerate retirements without jeopardizing

reliability. Generators in the PJM Interconnection (“PJM”) retired about 6,000 MW of capacity between

2004 and 2007, and over 3,000 additional MW of capacity have been announced for retirement in PJM by 

2012.18 Despite almost 10,000 MW of retirements over this seven year period, the RFC region is still 

forecast to have a reserve margin of over 24 percent in 2013, or an excess of 17,000 MW of generation 

above the 15 percent NERC target reserve margin target. 

Moreover, as a result of the economic recession, NERC projects “significant reductions in projected longterm energy use in North America” 19, which provide an additional capacity cushion. While total demand 

is still projected to increase in most regions, it will do so at a slower pace and from a lower starting point. 

See, for example, Figure 2 which shows the decrease in forecast energy use from NERC’s 2009 long-term 

reliability assessment as compared to its 2008 forecast. Additionally, summer peak demand has 

decreased over 10 GW per year for two consecutive years.20 Furthermore, in all regions of the country, 

well-established tools exist to analyze potential regional power system impacts, and to facilitate planning, 

managing and operating the system to ensure ongoing reliability. 

 

17 NERC, supra n.15. 

18 PJM, Generation Retirement Summaries, http://www.pjm.com/planning/generation-retirements/gr-summaries.aspx (accessed 

July 31, 2010). 

19 NERC, supra n.15, at p. 13.

20 NERC, supra n.13, at p. 1.
10 

Figure 2 

Source: NERC, 2009 Long-Term Reliability Assessment: 2009-2018, October 2009, p. 13. 

B. The Electric Industry Has Proven Its Ability to Avoid Capacity Problems in the 

Past—Through Power Plant Capacity Additions, Fuel Conversions, Transmission 

Solutions, and Load Management Techniques 

1. New Capacity is Already in the Pipeline 

Even with the robust reserve margins in all NERC regions, industry participants are pursuing various 

measures to safely and reliably transition to cleaner, more efficient electric supply resources. Plans are 

underway for a variety of new plants, even as less efficient ones are retired. While economics remains the 

major consideration in deciding whether to develop or expand generating capacity or to mothball older 

plants, other major drivers, including reliability and environmental improvements, are in play. For 

example, the implementation of forward capacity markets in certain Independent System Operators 

(ISOs) has provided more price transparency, enabling the industry to see the value of various generation 

resources. 

Moreover, the industry has shown previously that it can efficiently add capacity or respond adequately to 

potential reliability issues. Between 1999 and 2008, for example, in response to a variety of market,

regulatory and economic signals, the electric sector added almost 270 GW of natural gas-fired generating 

capacity, the equivalent of more than 80 percent of the entire existing U.S. coal fleet.21 (See Figure 3 

below, which shows the significant investment in new gas plants during the past decade.) Indeed, in just 

three years between 2001 and 2003, the electric industry built over 160 GW of new generation,22 about 

four times what analysts project will retire over the next five years. Although conditions a decade ago 

 

21 EIA, Annual Electric Generator Report: Form EIA-860, 2008. 

22 Id.

NERC 2009 to 2017 Projected 
11 

differ in several respects, this robust construction cycle suggests that developers and investors will

respond to strong signals if new capacity is needed. 

Figure 3 

Power Plant Capacity Added by Year It Entered Service 

Source: Ceres, et al., Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the 

United States, June 2010. 

There are also examples in which the industry responded quickly and effectively to resolve looming 

reliability problems. In the mid-1990s, for example, three large nuclear generating units in Connecticut, 

totaling almost 3,000 MW, were unexpectedly and simultaneously unavailable during lengthy outages23

, 

transforming Connecticut from a power exporter to a net importer. To avert any reliability problems over 

the extended outages, the regional grid operator, along with the region’s utilities and public officials, 

instituted a variety of measures including adjusting unit maintenance schedules, executing additional 

interruptible contracts with large commercial customers, installing new generation and transmission 

equipment, and coordinating closely with neighboring power systems to maximize out-of-state power 

purchases.24 If necessary, the industry could employ similar strategies in response to future coal plant 

retirements. 

Further, as indicated in Table 3 below, substantial new capacity build has been announced, planned or is 

seeking grid interconnection studies. Across the NERC regions, a recent report identified over 55 GW of 

proposed generation in advanced stages of development in the queue for 2013. Although, not all of these 

plants will be built, strong market incentives and signals from regulators that new capacity will be needed 

will promote generation development proposals beyond those announced to date.

 

23 Western Massachusetts Electric Company, Form 8K, November 25, 1996, “Other Events.” 

24 PRNewswire, NEPOOL: Power Supplies May be Tight in New England This Summer, June 11, 1996.
12 

Table 3 - Proposed New Build – 201325

NERC Region New Generation Proposed to Be Built 

(in Transmission Queues for 2013) 

TRE 4.3 GW 

FRCC 2.0 GW 

MRO 3.6 GW 

NPCC 7.5 GW 

RFC 8.7 GW 

SERC 10.3 GW 

SPP 2.8 GW 

WECC 16.3 GW 

Total 55.5 GW

Note: There are substantial additional generating facilities in the queue in each region. 

Numerous electric companies have already announced substantial new capacity additions, many at the 

sites of existing coal units that will be retired. Georgia Power, which recently demolished a coal plant in 

Georgia and stated its intention to retire another, announced it plans to build three 840 MW combined 

cycle gas turbines (“CCGTs”) in Georgia.26 Oglethorpe Power Corporation has proposed a 605 MW 

CCGT27 and a 100 MW biomass facility in Georgia.28 Also in the Southeast, Progress Energy plans to 

build a 950 MW CCGT at the site of three coal units, which will retire when the gas plant comes online.

29

 

In Tennessee, TVA is building an 878 MW CCGT at the site of its John Sevier coal plant, and the City of 

Vineland New Jersey plans to replace its 25 MW coal plant with a 60 MW gas plant.30,31

Also, although they do not operate in the same base load mode as do nuclear or many coal plants, low 

emission energy facilities have expanded rapidly over the past several years.32 For example, the total 

wind power capacity now operating in the U.S. is over 35,600 MW. In 2009 alone, the U.S. wind 

industry broke all previous records by installing nearly 10,000 MW of new generating capacity, enough to 

serve over 2.4 million homes. Additionally, over 400 MW of solar was installed throughout the nation in 

2009. Solar installations are poised to grow about 50 percent annually in the next three years, reaching 

1.5 GW to 2 GW of new installations in 2012.33

The retirement of inefficient coal units may spur further development of cleaner generating capacity. 

Regional transmission studies include capacity even if it runs infrequently. Freeing room for new 

capacity through retirements means some low emission generation resources, including gas plants, can be 

accommodated without having to invest in new transmission. 

 

25 ICF International, supra n.6. 

26 Georgia Power, From Coal to Natural Gas, http://www.georgiapower.com/generation/home.asp (accessed July 31, 2010). 

27 Oglethorpe Power, Oglethorpe Power to Build Gas-Fired Generating Plant, March 10, 2010. 

28 Power-Gen Worldwide, Oglethorpe plans a biomass plant, June 29, 2010. 

29 Energy Business Review, Progress Energy Wins Approval To Build 950MW Gas-fired Plant, October 2, 2009. 

30 Marketwire, TVA Prepares to Begin Construction on 880-Megawatt Combined-Cycle Unit, March 16, 2010. 

31 NJ Spotlight, NJ Coal Plants Face Cleanups and Closures, July 10, 2010. 

32 Wind and solar are intermittent resources; therefore, only part of their output is credited for reliability purposes. 

33 GTM Research, The United States PV Market Through 2013: Project Economics, Policy, Demand and Strategy, December 

2009. 
13 

2. Existing Gas Units Have Untapped Power Production Potential 

Given the significant addition of gas-fired capacity in the past decade, as detailed earlier in Figure 3, and 

the relative price advantage of coal versus natural gas in the period from 2007 to 2008, gas plants were 

not operated at their full design capability in many parts of the country. As detailed in Table 4 below, 

gas-fired CCGT power plants in 2008 had an average utilization rate of only 33 percent, as compared to

coal’s 56 percent. Despite declines in natural gas prices, existing gas units have significant untapped 

power production potential, which can be expanded during off peak periods without constructing new 

generation. This excess capacity can assist in managing power plant outages required to install pollution 

control systems. 

Table 4 – Estimated Utilization of U.S. Coal and Gas Plants (CCGT) by Region (2008) 

Region

Total Installed 

Capacity (MW) % Utilization

Total Installed 

Capacity (MW) % Utilization

> 500 7,981 67% 17,678 46%

200 - 500 1,628 64% 2,410 26%

< 200 199 53% 1,389 20%

> 500 18,113 73% 3,033 15%

200 - 500 4,915 59% 1,246 15%

< 200 3,111 42% 506 10%

> 500 2,407 79% 13,791 44%

200 - 500 2,548 70% 4,326 36%

< 200 1,079 47% 2,843 21%

> 500 99,474 61% 28,087 19%

200 - 500 11,479 54% 2,709 13%

< 200 4,664 48% 1,794 34%

> 500 91,188 66% 40,529 24%

200 - 500 10,699 57% 4,995 29%

< 200 4,109 36% 1,229 33%

> 500 17,970 71% 12,051 32%

200 - 500 2,361 72% 2,116 37%

< 200 647 44% 465 22%

> 500 15,193 80% 28,869 44%

200 - 500 1,213 82% 5,025 36%

< 200 1,020 24%

> 500 30,081 73% 37,435 47%

200 - 500 2,992 78% 6,835 40%

< 200 2,465 60% 5,042 49%

> 500 282,407 67% 181,473 35%

200 - 500 38,277 60% 30,136 32%

< 200 16,616 45% 15,966 30%

Plant Size (MW)

Coal Gas 

FRCC

MRO

NPCC

RFC

SERC

All US Plants

SPP

WECC

TRE

Source: MJB&A analysis based on U.S. Energy Information Administration’s Form EIA-860 (2008) and 

EIA-923 (2008)

Additionally, many coal plants have the potential to repower their units, by replacing conventional coalfired steam electric generating units with CCGTs, thus increasing the units’ efficiency and reducing air 

emissions—an approach already being used today by the industry. For example, Xcel Energy has 

replaced a 270 MW coal plant in Saint Paul, Minnesota with a 515 MW CCGT, reducing SO2 emissions 

by 99.7 percent, NOx emissions by 96.9 percent, and eliminating mercury emissions.34 It also repowered 

 

34 Utility Engineering, Twin Cities to breathe easier thanks to UE, Value Connection, Issue 2, 2007. 
14 

two coal units in Minneapolis.35 In New Jersey, Calpine has announced its intent to convert an 83 MW 

coal unit to a 158 MW gas unit.36

3. Enhanced Load Management Programs Can Be Deployed to 

Meet System Reliability Needs Economically 

Historically, grid operators have dispatched plants to meet customers’ electricity requirements. Over the 

years, the industry has recognized that decreasing load requirements can be more efficient and 

economical than increasing supply by dispatching generation. As a result, load management tools, such

as demand response (“DR”) and energy efficiency (“EE”) programs have been widely implemented 

across the nation. 

DR programs manage load by temporarily reducing or shifting electricity use by homes or businesses 

during critical times like hot summer days. EE programs, on the other hand, primarily seek to reduce 

consumers’ energy use on a permanent basis through the installation of energy efficient technologies and 

conservation measures. Both means of load management provide an additional tool for system operators 

to manage electric reliability. 

DR programs operate in all of the NERC Regions, as shown in Figure 4 below. In some regions, such as 

RFC, SERC, WECC, and MRO, a substantial fraction of the DR resources are available in the form of 

“contractually interruptible” or curtailable loads. These typically entail contracts between a utility and an 

industrial customer, in which the customer agrees to curtail part of its usage when requested for a 

specified number of times during a certain period, in exchange for electric rate discounts. The other

forms of DR—direct control load management, critical peak pricing with control, and load as a capacity

resource—are more dynamic forms of supply, in which the grid operator, in effect, dispatches the load to 

respond with a reduction or shift in load, much like a generating facility. 

Figure 4 

NERC Summer Peak Capacity Demand Response - 2009-2018 Comparison 

Source: NERC, Long-Term Reliability Assessment, 2009, Figure 7 (page 18).

In particular, these other forms of DR have increased steadily in organized wholesale competitive 

markets. In PJM, for example, DR has increased five-fold in the past five years and continues to grow.

37

 

 

35 North Dakota Home Town Times, Xcel Energy Switches Minneapolis Coal Plant to Natural Gas, October 13, 2009. 

36 NJ Spotlight, supra n.31. 
15 

In the most recent PJM capacity auction, DR offers increased 32 percent over last year and over 9,000 

MW cleared, which represents about six percent of total available capacity resources.38

 DR is expected to 

reduce the peak electricity use this summer in PJM by 8,525 MW, the equivalent output of ten large 

power plants.39

DR is not just increasing in PJM. According to the ISO/RTO Council, competitive markets are 

“shattering barriers” in terms of attracting DR resources.40 In FERC’s recently released National Action 

Plan on Demand Response, it highlighted that DR has tripled in recent years in the New England region41

and identified strategies to further enhance DR. Already, about half of electric utilities across the nation 

have some type of DR program. With continued support from regulatory agencies like FERC and the 

advancement of “smart grid” technologies, DR is expected to continue to grow as a viable supply 

alternative to traditional generation. 

As with DR, EE programs have increased dramatically in the past several years. According to 

information compiled by the Consortium for Energy Efficiency, and as highlighted in Figure 5, the total 

budget for all US ratepayer-funded EE and DR programs has increased 80 percent since 2006 to $4.4 

billion in 2009.42 These programs resulted in savings of almost 105,000 gigawatt hours (“GWh”) of 

electricity in 2008—the equivalent of the total electricity consumption in Tennessee in the same year.43 

By 2018, new EE programs alone are expected to reduce summer peak demands by almost 20,000 MW (a 

full year’s growth).44

 

37 PJM, Demand Response To Play Significant Role In Meeting PJM’s Higher Summer Peak Electricity Use, 

http://pjm.com/~/media/about-pjm/newsroom/2010-releases/20100505-summer-2010-outlook.ashx (accessed August 6, 2010) 

38 PJM, 2013/2014 RPM Base Residual Auction Results, at p. 1. 

39 PJM, supra n.37. 

40 ISO/RTO Council, 2009 State of the Markets Report, September 22, 2009. 

41 The Federal Energy Regulatory Commission Staff, National Action Plan on Demand Response, June 17, 2010, at p. 7. 

42 Consortium for Energy Efficiency (“CEE”), The State of the Efficiency Program Industry: Budgets, Expenditures, and Impacts, 

2009, at p. 7. 

43 Id.

44 NERC, supra n.15, at p. 12. 
16 

Figure 5 

Energy Efficiency and Demand Response Program Budgets, 2006-2009 

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2006 2007 2008 2009

Millions $USD

Commercial and Industrial

Residential

Low Income

Load Management

Other

Source: Consortium for Energy Efficiency, The State of the Efficiency Program Industry: 

Budgets, Expenditures, and Impacts, 2009 

Although California and the Northeast account for over half of the total, budgets for ratepayer-funded EE 

programs are expanding in all regions of the country. In 2009, EE budgets for Illinois, Wisconsin, and 

Iowa increased in 2009, year-on-year, by 60 percent, 40 percent, and 36 percent, respectively.45 In the 

Southeast, Alabama, Mississippi, North Carolina, and Louisiana reported ratepayer-funded EE budgets 

for the first time in 2009.46 EE’s use as a capacity resource is increasing in organized wholesale markets 

as well. For example, EE resources accounted for 757 MW of the resources offered into the most recent

PJM RPM auction, an increase of 33 percent over the prior year. Of those resources, 90 percent, or 680 

MW cleared the auction to serve as a firm capacity resource.47

NERC estimates that current levels of EE and DR will shave off certain portions of expected growth in 

demand, as shown in Figure 6, below, underscoring growing acceptance of these load-management tools. 

 

45 CEE, supra n.42, at p. 15. 

46 Id. at p. 16. 

47 PJM, supra n.38. 
17 

Figure 6 

Summer Peak Demand Growth Reduced by Demand-Side Management

Source: NERC, Long-Term Reliability Assessment, 2009, at p. 18. 

Based on the experience of states and organized competitive wholesale markets that have implemented 

EE and DR, it is clear these programs provide yet another cost-effective tool to help maintain reliability in 

the face of generation retirements. 
18 

II. THE INDUSTRY HAS THE CAPACITY TO TIMELY RESPOND TO EPA’S 

FUTURE AIR REGULATIONS 

A. The Majority Of Coal Plants Have Already Installed Air Pollution Controls 

Proven pollution control technologies are widely available to dramatically reduce emissions of NOx, SO2, 

mercury, and other HAPs from coal plants, which account for 98 percent of the electric sector’s SO2

emissions, 86 percent of its NOx emissions, and 98 percent of its mercury emissions.48,49

Over the last 20 years, the industry has deployed a number of different technologies to comply with 

federal and state SO2 and NOx regulations. The three basic options for reducing SO2 emissions from coal 

plants include: (1) switching from higher to lower sulfur coal; (2) blending higher sulfur coal with lower 

sulfur coal; or (3) installing flue gas desulfurization (“FGD”) control systems, commonly referred to as 

scrubbers. Wet scrubbers, which use a sorbent to capture SO2, can typically achieve at least 95 percent 

SO2 removal. Widely available NOx control technologies for coal generation can be grouped into two 

broad categories: combustion modifications and post-combustion controls. Post-combustion controls can

reduce NOx emissions by 90 percent or more by removing the NOx after it has been formed in the boiler. 

The most common post-combustion control is selective catalytic reduction (“SCR”) technology, in which 

ammonia (NH3) is injected, combining with the NOx in the flue gas to form nitrogen and water. 

The majority of coal plants have already installed such controls. Of the 310 GW of coal capacity in the 

United States, 150 GW have installed FGD systems and another 55 GW have FGD controls planned,50

representing 65 percent of the existing coal fleet. As detailed in Attachment A, numerous scrubber 

installations have been recently completed or soon will be completed. Additionally, about 50 percent of 

coal capacity in the U.S. has installed or soon will be retrofit with advanced NOx controls (SCR and 

selective non-catalytic reduction (“SNCR”) technologies).51

To date, most studies put a heavy emphasis on deploying scrubbers to comply with the new EPA air 

regulations. Retirements occur where the costs of installing scrubbers does not make economic sense 

based upon the unit’s characteristics. However, a number of companies have announced that they will 

use other less costly technologies in lieu of scrubbers. For example, on August 5, 2010, Edison Mission 

International, one of the nation’s largest merchant coal generators, announced it could achieve 

compliance without installing scrubbers by using trona injection technology.52

B. With Proper Planning, the Industry Can Install the Necessary Pollution Controls on 

a Timely Basis

EPA projects that about 14 GW of additional coal-fired generating capacity will need to be retrofit with 

scrubbers and less than 1 GW with SCR controls by 2014 to comply with the recently proposed Transport 

Rule. 53 This number of retrofits is significantly less than the industry has added in past construction 

 

48 EIA, U.S. Electric Power Industry Estimated Emissions by State (EIA-767 and EIA-906), Electric Power Annual 2008, 

http://www.eia.doe.gov/cneaf/electricity/epa/emission_state.xls (accessed July 30, 2010) 

49 U.S. EPA Office of Air Quality Planning and Standards, National Emissions Inventory for Hazardous Air Pollutants, 1999. 

50 PIRA, supra n5, at p. 7. 

51 U.S. EPA, National Electric Energy Data System (“NEEDS”), version 3.02. 

52 Trona is a naturally occurring sorbent that can be injected directly into boilers to remove harmful air toxics without the use of 

FGD scrubbers. Given that the PIRA and EEI analyses did not consider trona and other less costly compliance options, the 

predicted retirement scenarios are very likely overstated. Nonetheless, this report uses the predicted retirements as a conservative 

input to test all of the reliability considerations. 

53 U.S. EPA, Proposed Rule: Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and 

Ozone, August 2, 2010. 
19 

cycles. For example, during the peak of scrubber construction, between 2008 and 2010, approximately 60 

GW of coal capacity was retrofit with scrubber controls,54 highlighting the industry’s ability to complete a 

substantial number of retrofits over a short period of time. In 2009 and 2010, the industry completed 

between 50 and 60 scrubber retrofits each year.55

Moreover, the industry’s past successful installation of pollution controls on numerous units underscores 

its ability to schedule and sequence any required unit outages in an efficient and reliable manner. To help 

ensure reliability, generators and transmission owners provide reasonable advance notice of any planned 

outages to the respective transmission authorities. In turn, the transmission authorities develop a 

coordinated outage schedule to prevent any deliverability problems. This illustrates a key benefit of a 

fully integrated national transmission system. 

Further, the CAA allows three years for existing sources to comply with the Utility MACT rule with the

possibility of a one-year extension. EPA is under a court-imposed deadline to complete its regulations by 

November 2011, with compliance required by late 2014. As numerous states have adopted regulations 

limiting mercury emissions from coal-fired power plants, many companies have already begun to install 

mercury control technologies. Also, the scrubber and particulate control systems installed to comply with 

the Transport Rule and other EPA regulations will help companies to comply with future air toxics 

regulations. 

In the event, however, that any required retrofit construction schedules could not be completed within the 

pre-compliance period, EPA may, and should, exercise its authority under Section 112(i)(3)(B) of the 

CAA to provide up to one-year extensions to complete pollution control installations. In addition, to

protect the national security interest of maintaining adequate electrical grid reliability, the President has 

the authority under Section 112(i)(4) of the CAA to grant one or more compliance extensions of up to two 

years each. Any such extensions would be unit-specific and based on clear demonstration that the 

technology to implement such standards is not available. 

These federal tools combined with market rules and signals, industry reliability standards and 

enforcement mechanisms, and utility regulatory requirements and incentives, provide a robust portfolio of 

techniques to assure compliance with health-based air regulations while maintaining reliable electricity 

supply. 

C. The Coal Plants Most Likely To Retire Are Nearing The End Of Their Design Life 

Expectancies And Are Already Economically Challenged 

As indicated by Table 5 below, many of the uncontrolled coal units, which are the most likely to retire, 

are smaller (250 MW and below) and are 40 to 60 years old. Thus, the coal plants most likely to retire are 

already nearing the end of their design life expectancies, as confirmed in recent coal plant retirement 

announcements, detailed in Attachment B. 

 

54 M. J. Bradley & Associates analysis based on U.S. EPA NEEDS Database v. 3.02. 

55 Id.
20 

Table 5 - Characteristics of U.S. Coal Plants

Information included in the most recent annual State of the Market Report prepared by PJM’s 

Independent Market Monitor (“IMM”) suggests that fundamental economics, not the EPA regulations, are 

already challenging those units most likely to retire. In that report, the IMM identified over 11 GW of 

coal units at risk for retirement, since they “did not recover avoidable costs even with capacity 

revenues.”56 Of the 11 GW identified in the report, most operated less than 1,000 of the 8,760 hours in 

2009 and tended to be significantly smaller with an average installed capacity of only 73 MW.57 Of the 

122 coal units in PJM with capacity less than or equal to 200 MW, 35 failed to recover their avoidable

costs and another 52 were close to not recovering those costs. Therefore, in PJM, a region covering 13 

states and DC, in addition to approximately 10 GW of coal generation that has or will be retired during 

the seven years from 2004 to 2011, another 11 GW faces a troubling economic outlook. As such, the 

units’ economics already place them at risk of shutdown, regardless of EPA’s future air regulations.

In reducing the air pollution emissions from some of the nation’s most inefficient uncontrolled units, EPA 

will facilitate the development of cleaner, more efficient generation while improving air quality and 

reducing greenhouse gas emissions. The current levels of air pollution in certain regions of the country 

require industrial facilities and power plants to obtain emission offsets to expand their operations. This 

requirement discourages economic development due to the increased permitting and financial obligations

compared to areas that meet federal and state air quality standards. Significantly as well, as shown in 

Figure 7, because these non-attainment areas are concentrated in highly populated areas, reducing 

emissions there will facilitate the development of cleaner, more efficient generation near electric load 

centers where it is needed most. 

Additionally, the retirement of generating capacity that has been previously supported by transmission

investment could create room on the transmission grid to handle power flows both within and outside the 

regions, or the addition of new generating capacity, without requiring attendant transmission upgrades. 

These considerations, too, will help mitigate reliability concerns and reduce the cost of upgrading the 

nation’s power system infrastructure. 

 

56 PJM, State of the Market Report, Vol. 1, March 11, 2010, p. 21. 

57 Id. Vol. 2 at p. 176. 

Count % MW % SNCR SCR Scrubber Uncontrolled

> 60 years 46 5% 1,762 1% 38 2% 4% 11% 87%

51 - 60 years 313 31% 39,787 13% 127 21% 9% 19% 64%

41 - 50 years 233 23% 58,078 20% 249 15% 19% 33% 53%

31 - 40 years 229 23% 114,090 38% 498 4% 43% 65% 27%

11 - 30 years 163 16% 80,165 27% 492 6% 29% 66% 31%

10 years or younger 7 1% 2,444 1% 349 43% 29% 57% 29%

Total 1,004 297,639 13% 23% 41% 48%

Data Sources: 2007/2008 EPA IPM, ARP, NBP Databases & Commercial Sources, MJB&A Analysis

Pollution Control Installed

 (% of units)

Avg. Unit 

Size 

(MW)

Unit Age Units Capacity
21 

Figure 7 

Source: U.S. EPA (with city locations added by M.J. Bradley & Associates) 
22 

III. EPA, DOE, FERC AND STATE UTILITY REGULATORS HAVE THE TOOLS 

TO MODERATE IMPACTS ON THE ELECTRIC INDUSTRY AND MANAGE 

ELECTRIC SYSTEM RELIABILITY. 

A. Statutory, Regulatory and Market Safeguards Exist To Mitigate Risks of 

 Retirement On Reliability 

Assorted risk management procedures under the CAA, the Federal Power Act (“FPA”) and other statutes 

provide EPA, DOE, FERC, and the President tools to moderate potential impacts on electric system 

reliability. The procedures serve as a bridge, if necessary, to a permanent solution, helping ensure 

reliability while minimizing exposure to harmful air pollutants. EPA also has the authority to develop 

cost-effective regulatory approaches, such as the emissions trading mechanism proposed in the Transport 

Rule, that will enable greater compliance flexibility and flexibility in managing potential reliability issues. 

In addition to the EPA’s and President’s authority to extend deadlines for installation of pollution controls 

described in Section II B, where necessary to maintain electric system reliability, DOE has the power 

under Section 202(c) of the FPA to override CAA-derived control requirements in limited emergency 

circumstances. In such emergency situations, including extended periods of insufficient power supply as 

a result of shortage of electric facilities, DOE has the discretion to issue unit-specific orders designed to 

maximize CAA compliance and minimize health risks. 

Two examples of DOE’s exercise of this authority illustrate the point. In 2003, the Secretary of Energy 

ordered energizing a new underwater cable connecting New Haven, Connecticut to Long Island, which 

had previously been constructed but remained inoperable due to legal actions appealing permits. Citing 

August 2003’s massive electric service outage, the Secretary invoked his authority to alleviate the 

reliability emergency.58

DOE’s actions related to the Potomac River plant serving Washington, DC provide another example. In 

2005, the plant’s owner, Mirant, had decided to shut down all five generating units at its Potomac River 

plant located outside Washington, DC. The DC Public Service Commission requested that DOE issue an 

emergency order directing Mirant to continue to operate the units, as their shutdown would have 

“immediate” and “drastic” effects on DC’s electric system reliability. In conjunction with the EPA, 

which required Mirant to enter into a consent decree, DOE issued an Order59 requiring Mirant to operate 

the plants under specific and limited circumstances tailored to relieve the risk of a DC area blackout, 

while avoiding to the full extent possible exceedances of federal air quality standards. 

The well-established consent decree template, as used to address the Potomac River situation, provides

EPA yet another tool to synthesize reliability and environmental concerns. By restricting a unit to operate 

for reliability purposes only, pending completion of any required transmission upgrades or replacement

 

58 DOE, Order No. 202-03-2, August 28, 2003. “I hereby determine that an emergency continues to exist in the Northeast United 

States due to a shortage of electric energy, a shortage of facilities for [...] the transmission of electric energy and other causes. 

[...] On August 14, 2003, the Northeast and Upper Midwest areas in the United States, as well as portions of Canada, 

experienced the largest electric transmission grid failure and electric service outage ever to occur in North America. Tens of 

millions of people were affected by this outage, and it presented profound risks to the public health and safety throughout the 

affected areas. [...] Only hours after the outage occurred, and after considering the unanimous recommendation of the North 

American Electric Reliability Council, the New York Independent System Operator (NYISO), ISO New England, Inc. (ISO-NE), 

and electric utilities in both New York and Connecticut in support of the issuance of an emergency order, I issued an order 

directing the NYISO and ISO-NE to require the Cross-Sound Cable Company, LLC (CSC) to operate the Cross-Sound Cable and 

related facilities as necessary to alleviate the disruptions in electric transmission service. The Cable was energized a short time 

thereafter.” 

59 DOE, Order No. 202-05-03, December 20, 2005. 
23 

generation, such consent decrees can maintain reliability while minimizing adverse environmental 

impacts to the fullest extent possible. 

Many regional wholesale competitive markets also have well-established forward capacity markets such 

as PJM’s Reliability Pricing Model and New England’s Forward Capacity Market, which are approved by 

FERC and overseen by independent market monitors, to facilitate and provide advanced notice of the 

retirement of inefficient units while maintaining reliability. Reliability impact studies are conducted for 

units that have announced retirement or fail to clear the forward capacity auctions, and those identified as 

being needed for reliability may continue to operate past their planned retirement date pursuant to 

“reliability must run” (“RMR”) agreements. To help ensure reliability while minimizing adverse

environmental impacts, the RMR agreements can provide the units operate only to maintain reliability. 

For example, Exelon Generation recently coordinated with PJM and the Pennsylvania Department of 

Environmental Protection (“PA DEP”) to negotiate a consent decree and operating procedures related to 

an RMR agreement for its two retiring coal units, which require the units operate for reliability purposes 

only.60

In addition to these established ISO/RTO procedures, advance analysis in the long range reliability 

planning processes should lead to rational and timely investments in new transmission that will mitigate 

any service reliability issues associated with future generation retirements. The local transmission owners 

currently play an important supplemental role in accomplishing this objective. For example, 

Commonwealth Edison (“ComEd”), the local transmission owner in Chicago, proactively filed an 

application with the Illinois Commerce Commission61 seeking permission to enhance its transmission 

system. In its application, ComEd noted the identified upgrades would be required to maintain system 

reliability in the event that two of Midwest Generation’s at-risk coal units, Fisk and Crawford, were to 

retire.62

Procedures also exist to protect electric system reliability in regions where coal plants are not part of an 

organized wholesale competitive market, but are owned by vertically-integrated utilities in traditionally 

regulated monopoly regimes. Generators regulated by state regulatory commissions have a legal 

obligation to reliably serve their customers, and to conduct long range resource planning. Typically,

generators will have many options to meet their statutory obligation to serve including, but not limited to: 

(1) investing in existing plants; (2) building new plants; (3) decreasing load through DR and EE 

programs; (4) building transmission; or (5) a prudent combination of all those tools. Too, state regulators 

may adopt ratemaking policies to encourage such actions, including ones that address utilities’ financial 

disincentives where aggressive EE and DR programs would otherwise produce lower revenues. 

As such, FERC and other relevant agencies have a number of tools available to moderate the impacts of 

air emission regulations, while maintaining reliability and minimizing adverse environmental impacts. 

Moreover, EPA is also developing new water regulations under Section 316(b) of the Clean Water Act 

(“CWA”), new waste regulations, and greenhouse gas regulations affecting the electric power sector. 

EPA should consider efficiently coordinating these rules as it moves forward with its rulemakings to 

avoid possible reliability concerns. 

 

60 Commonwealth of Pennsylvania Department of Environmental Protection v. Exelon Generation Company, LLC., No. 382 MD 

2010 (Pa. Cmmw. April 16, 2010) included in Operating Procedures for Cromby Generating Station Unit No. 2 and Eddystone 

Generating Station Unit No. 2 as Required for Reliability Purposes at Appendix 1, http://pjm.com/planning/generationretirements/~/media/planning/gen-retire/must-run-operating-procedures.ashx (accessed August 6, 2010). 

61 Commonwealth Edison Company, Application for authorization under Section 4-101 of the Illinois Public Utilities Act 

(“Act”), 220 ILCS § 5/4-101, or alternatively, for a Certificate of Public Convenience and Necessity, pursuant to Section 8-406 

of the Act, to install, operate and maintain two new 345,000 volt electric transmission lines in Cook County, Illinois, No. 10-0385 

(Ill. Cir. June 11, 2010). 

62 Direct Testimony of Thomas W. Leeming, p. 2, Lines 25-35.
24 

IV. CONCLUSION

Current industry practice and a review of applicable system data indicate the industry is well-positioned 

to respond to EPA’s mission to “help millions of Americans breathe easier and live healthier” without 

threatening electric reliability. Generation plant capacity and availability, consumption levels and 

patterns, and transmission capacity and use must all be considered when judging the reliability impacts of 

environmental regulatory action. 

The existing substantial excess capacity, the industry’s proven track record to timely construct new 

generation and to efficiently coordinate the scheduling of planned outages, together with capacity 

upgrades, transmission enhancements, “smart grid” investments, fuel conversions, DR, and EE, should 

mitigate reliability concerns. 

The industry has already successfully employed these various strategies to reliably meet customers’ 

energy needs while reducing environmental impacts, and it will continue to do so in response to EPA’s 

new regulations. As a final backstop, existing statutory, market and regulatory safeguards will facilitate 

the retirement of inefficient units, and an orderly transition to cleaner, more efficient generation. 
25 

ATTACHMENT A 

Sampling of Recent Announcements of Scrubber Installations 

Plant Unit State Size 

(MW) 

Highlights 

Brandon 

Shores 

1 MD 643 

Brandon 

Shores 

2 MD 643 

This significant environmental upgrade supports Constellation Energy's environmental 

stewardship efforts by: Reducing Maryland's coal-fired power plant's SO2 emissions by an 

estimated 95 percent; Reducing existing mercury emissions by 90 percent; and Significantly 

reducing acid gases. 

http://www.constellation.com/portal/site/constellation/menuitem.38d5d085b395c0cb2adedd10

d66166a0/ 

Kingston 1 TN 135 

Kingston 2 TN 135 

Kingston 3 TN 135 

Kingston 4 TN 135 

Kingston 5 TN 177 

Kingston 6 TN 177 

Kingston 7 TN 177 

Kingston 8 TN 177 

Kingston 9 TN 178 

The two scrubbers added at Kingston will control sulfur dioxide from all nine boilers at the 

fossil plant, which can generate 10 billion kilowatt-hours of electricity per year. "We now have 

state-of-the-art control equipment on all of our units at Kingston, allowing us to generate the 

electricity needed by our customers," Kingston Plant Manager Leslie Nale said. "This 

translates into cleaner air in the Great Smoky Mountains and across the region." 

http://www.tva.gov/news/releases/aprjun10/kingston_scrubbers.html 

Miller 3 AL 750 

Miller 4 AL 750 

Gaston 5 AL 861 

Barry 5 AL 750 

During peak construction, Alabama Power’s $1.7 billion scrubber initiative was responsible 

for creating more than 2,300 jobs. “This investment is not only good for the environment, it’s 

also good for Alabama’s economy,” Charles McCrary, Alabama Power president and CEO, 

said. 

http://southerncompany.mediaroom.com/index.php?s=43&item=2074 

Coffeen 1 IL 340 

Coffeen 2 IL 560 

“Our investment in these technologies reflects our commitment to environmental stewardship 

and our support for the communities we serve,” says Chuck Naslund, AER chairman, 

president and chief executive officer. “Through these projects, we have not only offered 

continued permanent employment to hundreds of Illinoisans, but we have also provided jobs 

to contract employees who call Illinois home. Clearly these projects have had a positive 

impact on the economies of central and southern Illinois – areas hard-hit by tough economic 

conditions.” 

http://www.bloomberg.com/apps/news?pid=conewsstory&tkr=AEM:SP&sid=a.W8.1491R8g 

Cardinal 1 OH 600 

Cardinal 2 OH 600 

Cardinal 3 OH 630 

According to Buckeye Power, one of the owners of the Cardinal Plant, “the addition of these 

scrubbers means the Cardinal plant is able to reduce emissions while using Ohio coal, 

meaning jobs and economic benefits for eastern Ohio and the region.” The unit 3 scrubber is 

still under construction. 

http://www.buckeyepower.com/pages/buckeye-power-2 

Monroe 4 MI 775 

Monroe 3 MI 795 

DTE Energy will also be installing two additional FGD systems at Monroe units 1 and 2. 

According to DTE, “the $600 million project will create 900 jobs and be one of the largest 

construction projects in Michigan over the next few years.” 

http://www.prnewswire.com/news-releases/dte-energy-environmental-project-will-create-900-

jobs-78770632.html 

Cliffside 5 NC 550 According to Duke, the scrubber control installation at Cliffside Unit 5 will be completed by the 

Fall of 2010. Duke already has emission-control scrubbers on all its large Carolinas coal 

plants—Allen, Marshall and Belews Creek. According to Duke spokesman Andy Thompson, 

Duke has reduced its NOx emissions by 80% since 1997 and SO2 emissions have fallen 

70% since 2005. 

http://www.bizjournals.com/charlotte/blog/power_city/2010/07/duke_energy_assessing_new_

epa_rules.html 

Bowen 1 GA 713 Scheduled for completion in early 2010, according to Georgia Power. 

http://www.georgiapower.com/pluggedin/construction_2009_08.asp 

Crist 6 FL 302 

Crist 7 FL 477 

According to Gulf Power, since 1992, the company has reduced regulated emissions by more 

than 70 percent despite increased electricity demand from 120,000 new customers. With the 

scrubber system fully operational, Gulf Power will have reduced overall regulated emissions 

by more than 85 percent since 1992. 

http://www.renewablesbiz.com/article/09/12/gulf-power-begins-scrubber-startup 

Clifty Creek 1 IN 217 

Clifty Creek 2 IN 217 

Clifty Creek 3 IN 217 

Clifty Creek 4 IN 217 

Clifty Creek 5 IN 217 

Clifty Creek 6 IN 217 

Kyger Creek 1 OH 217 

"The addition of these FGD systems represents a major commitment to environmental quality 

in southeastern Ohio and southeastern Indiana," said David L. Hart, vice president and 

assistant to the president of OVEC-IKEC. "The projects will also produce an economic boost 

to the two regions." The scrubber installations at Clifty Creek and Kyger Creek are scheduled 

for completion in 2010. 

http://www.prnewswire.com/news-releases/ovec-ikec-to-invest-820-million-for-environmentalcontrols-at-kyger-creek-and-clifty-creek-power-plants-56325052.html 
26 

Plant Unit State Size 

(MW) 

Highlights 

Kyger Creek 2 OH 217 

Kyger Creek 3 OH 217 

Kyger Creek 4 OH 217 

Kyger Creek 5 OH 217 

Chalk Point 1 MD 342 

Chalk Point 2 MD 341 

Morgantown 1 MD 624 

Morgantown 2 MD 620 

Dickerson 1 MD 182 

Dickerson 2 MD 182 

Dickerson 3 MD 182 

"We are making a major investment in emission reduction technologies," said Edward R. 

Muller, Mirant chairman and CEO. "This equipment offers an excellent solution for 

substantially improving air quality while maintaining system reliability and efficient power 

generation for consumers and businesses." 

http://investors.mirant.com/releasedetail.cfm?releaseid=351567 

Brunner 

Island 

1 PA 344 

Brunner 

Island 

2 PA 397 

Brunner 

Island 

3 PA 754 

According to PPL’s website, “[t]he unit’s scrubber is now operating as designed, thanks to 

plant employees who safely made the final connections between the plant and the scrubber 

during a recent maintenance outage.” 

http://www.pplweb.com/ppl+generation/ppl+brunner+island.htm 

Hatfields 

Ferry 

1 PA 530 

Hatfields 

Ferry 

2 PA 530 

Hatfields 

Ferry 

3 PA 530 

According to an Allegheny Energy fact sheet, “[t]he ‘scrubbers’ will remove approximately 95 

percent of the sulfur dioxide (SO2) emissions and significantly reduce mercury emissions from 

the station...In addition to improving the environment, the scrubber system will enable 

Hatfield’s Ferry to purchase more local coal, which will preserve regional coal mining and 

related coal mining support jobs. The project will bring approximately 350 construction jobs 

to the region for a period of about three years. Additional full-time positions will be added to 

operate and maintain the scrubbers.” 

http://www.alleghenyenergy.com/Newsroom/Scrubber.Hat.2page.pdf 

Hudson 2 NJ 583 

Mercer 1 NJ 315 

Mercer 2 NJ 310 

According to PSEG Power, advanced emissions controls would be installed at Hudson by 

2010. Scrubbers at its Mercer plant are scheduled for completion in late 2010, 

http://www.reuters.com/article/idUSN1450072120080514 

Source: MJB&A analysis.
27 

ATTACHMENT B 

Recent Coal Plant Retirement Announcements

Source: MJB&A analysis based on U.S. EPA Acid Rain Program database and U.S. EIA File 860.

Name Owner State Installed Capacity 

(MW) 

Age 

(years) 

Advanced SO2/NOx 

Controls 

Weatherspoon Progress Energy NC 48 60 None 

Weatherspoon Progress Energy NC 49 59 None 

Weatherspoon Progress Energy NC 76 57 None 

L V Sutton Progress Energy NC 93 55 None 

L V Sutton Progress Energy NC 102 54 None 

L V Sutton Progress Energy NC 403 37 None 

H F Lee Progress Energy NC 74 57 None 

H F Lee Progress Energy NC 77 58 None 

H F Lee Progress Energy NC 248 47 None 

Cape Fear Progress Energy NC 172 51 SNCR 

Cape Fear Progress Energy NC 144 53 SNCR 

Cameo Xcel Energy CO 54 49 None 

Arapahoe Xcel Energy CO 47 58 None 

Arapahoe Xcel Energy CO 121 54 None 

Wabash River Duke Energy IN 95 53 None 

Wabash River Duke Energy IN 85 55 None 

Wabash River Duke Energy IN 85 56 None 

Wabash River Duke Energy IN 85 54 None 

Wabash River Duke Energy IN 318 41 None 

John Sevier TVA TN 176 53 SNCR 

John Sevier TVA TN 176 52 SNCR 

John Sevier TVA TN 176 54 SNCR 

John Sevier TVA TN 176 54 SNCR 

Cromby Exelon PA 144 55 SNCR + Scrubber 

Eddystone Exelon PA 309 49 SNCR + Scrubber 

Eddystone Exelon PA 279 50 SNCR + Scrubber 

Richard 

Gorsuch 

American Municipal Power OH 50 59 None 

Richard 

Gorsuch 

American Municipal Power OH 50 59 None 

Richard 

Gorsuch 

American Municipal Power OH 50 59 None 

Richard 

Gorsuch 

American Municipal Power OH 50 59 None 

Indian River NRG Energy DE 82 53 None 

Indian River NRG Energy DE 177 40 None 

Jack 

McDonough 

Southern Co GA 258 46 None 

Jack 

McDonough 

Southern Co GA 259 45 None 

Hunlock UGI PA 50 51 None 

Will County Midwest Generation IL 188 55 None 

Will County Midwest Generation IL 184 55 None 

Boardman Portland General Electric, 

Others 

OR 585 29 None 

Howard Down Vineland Municipal Electric 

Utility 

NJ 25 40 None 

TOTAL - - 4,939 - -