Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 1 Analysis Group

Ensuring a Clean, Modern Electric 

Generating Fleet while Maintaining 

Electric System Reliability 

August 2010 
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 2 Analysis Group

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 

E­mail: vanatten@mjbradley.com 
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 3 Analysis Group

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 pollution­control technologies, new power plants with 

relatively low emissions, and demand­side 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 fuel­fired power plants will require certain uncontrolled 

plants to install pollution control equipment.  Third­party 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 coal­fired 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 one­fourth of the nation’s coal­fired 

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. 

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 

 

1

 U.S. EPA, Draft FY 2011­2015 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 fossilfuel­fired 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 air­pollution 

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 Non­Hg Can Have Far­Reaching 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.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 4 Analysis Group

industry is well­positioned 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, Mid­Atlantic, 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. 

  

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. 

 

9

 U.S. EPA, supra n.1, at p. 2.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 5 Analysis Group

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 case­bycase 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 costeffective 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, well­established 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. 

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. 
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 6 Analysis Group

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, coal­fired 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 in Figure 1), whose 

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

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 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

 

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). 

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 Long­Term Reliability Assessment: 2009­2018, October 2009. 

I. MANAGING ELECTRIC SYSTEM RELIABILITY WHILE IMPLEMENTING NEEDED 

ENVIRONMENTAL IMPROVEMENTS WITH SIGNIFICANT PUBLIC HEALTH BENEFITS
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 7 Analysis Group

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

Figure /Table 1 ­ NERC Electric Reliability Regions

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 Long­Term Reliability Assessment: 2009­2018, 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 Long­Term Reliability Assessment: 2009­2018, October 2009. 

 

16 PIRA, supra n.5. 

17 NERC, supra n.15.

  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 
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 8 Analysis Group

Experience in the RFC region, which encompasses thirteen states in the Midwest and Mid­Atlantic 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 long­term 

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, wellestablished tools exist to analyze potential regional power system impacts, and to facilitate planning, 

managing and operating the system to ensure ongoing reliability. 

Figure 2 – Annual Energy Use (2008 LTRA and 2009 LTRA Forecast Comparison) 

Source: NERC, 2009 Long­Term Reliability Assessment: 2009­2018, October 2009, p. 13. 

 

18 PJM, Generation Retirement Summaries, http://www.pjm.com/planning/generation­retirements/gr­summaries.aspx (accessed July 31, 2010).

    

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

20 NERC, supra n.13, at p. 1.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 9 Analysis Group

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 gas­fired generating 

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

Further, as indicated in Table 3, 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.

 

21 EIA, Annual Electric Generator Report: Form EIA­860, 2008. 

22 Id.

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

1940 1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Renewable

Hydro

Nuclear

Other

Oil

Gas

Coal

Nameplate 

Capacity (MW)
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 10 Analysis Group

Table 3 ­ Proposed New Build – 201323

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.24  Oglethorpe Power Corporation has proposed a 605 MW CCGT25 and a 

100 MW biomass facility in Georgia.26  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.27  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.28,29

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.30   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 2012.31

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.    

2. Existing Gas Units Have Untapped Power Production Potential 

Given the significant addition of gas­fired 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, gas­fired CCGT 

power plants in 2008 had an average utilization rate of only 33 percent, as compared to coal’s 56 percent.  

 

23 ICF International, supra n.6. 

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

25 Oglethorpe Power, Oglethorpe Power to Build Gas­Fired Generating Plant, March 10, 2010. 

26 Power­Gen Worldwide, Oglethorpe plans a biomass plant, June 29, 2010. 

27 Energy Business Review, Progress Energy Wins Approval To Build 950MW Gas­fired Plant, October 2, 2009.  

28 Marketwire, TVA Prepares to Begin Construction on 880­Megawatt Combined­Cycle Unit, March 16, 2010. 

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

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

31 GTM Research, The United States PV Market Through 2013: Project Economics, Policy, Demand and Strategy, December 2009.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 11 Analysis Group

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) 

Source: MJB&A analysis based on U.S. Energy Information Administration’s Form EIA­860 (2008) and EIA­923 (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.32  It also repowered two coal 

units in Minneapolis.33  In New Jersey, Calpine has announced its intent to convert an 83 MW coal unit to a 

158 MW gas unit.34

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.   

 

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

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

34 NJ Spotlight, supra n.29.

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

200 ­ 500 38,277 60% 30,136 32%

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

Plants

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

200 ­ 500 2,992 78% 6,835 40%

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

WECC

< 200 1,020 24%

200 ­ 500 1,213 82% 5,025 36%

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

TRE

< 200 647 44% 465 22%

200 ­ 500 2,361 72% 2,116 37%

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

SPP

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

200 ­ 500 10,699 57% 4,995 29%

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

SERC

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

200 ­ 500 11,479 54% 2,709 13%

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

RFC

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

200 ­ 500 2,548 70% 4,326 36%

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

NPCC

< 200 3,111 42% 506 10%

200 ­ 500 4,915 59% 1,246 15%

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

MRO

< 200 199 53% 1,389 20%

200 – 500 1,628 64% 2,410 26%

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

FRCC

Region Total Installed Capacity (MW) % Utilization Total Installed Capacity (MW) % Utilization

Coal Gas (Combined Cycle)

Plant Size (MW)

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

200 ­ 500 38,277 60% 30,136 32%

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

Plants

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

200 ­ 500 2,992 78% 6,835 40%

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

WECC

< 200 1,020 24%

200 ­ 500 1,213 82% 5,025 36%

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

TRE

< 200 647 44% 465 22%

200 ­ 500 2,361 72% 2,116 37%

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

SPP

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

200 ­ 500 10,699 57% 4,995 29%

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

SERC

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

200 ­ 500 11,479 54% 2,709 13%

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

RFC

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

200 ­ 500 2,548 70% 4,326 36%

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

NPCC

< 200 3,111 42% 506 10%

200 ­ 500 4,915 59% 1,246 15%

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

MRO

< 200 199 53% 1,389 20%

200 – 500 1,628 64% 2,410 26%

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

FRCC

Region Total Installed Capacity (MW) % Utilization Total Installed Capacity (MW) % Utilization

Coal Gas (Combined Cycle)

Plant Size (MW)
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 12 Analysis Group

DR programs operate in all of the NERC Regions, as shown in Figure 4.  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. 

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

In PJM, for example, DR has increased five­fold in the past five years and continues to grow.35  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.36  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.37

Figure 4 – NERC Summer Peak Capacity Demand Response ­ 2009­2018 Comparison 

Source: NERC, Long­Term Reliability Assessment, 2009, Figure 7 (page 18).

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

barriers” in terms of attracting DR resources.38  In FERC’s recently released National Action Plan on 

Demand Response, it highlighted that DR has tripled in recent years in the New England region39 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 ratepayer­funded EE and DR programs has increased 80 percent since 2006 to $4.4 billion in 2009.40  

These programs resulted in savings of almost 105,000 gigawatt hours (“GWh”) of electricity in 2008—the

 

35 PJM, Demand Response To Play Significant Role In Meeting PJM’s Higher Summer Peak Electricity Use,  http://pjm.com/~/media/aboutpjm/newsroom/2010­releases/20100505­summer­2010­outlook.ashx (accessed August 6, 2010) 

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

37 PJM, supra n.35. 

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

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

40 Consortium for Energy Efficiency (“CEE”), The State of the Efficiency Program Industry: Budgets, Expenditures, and Impacts, 2009, at p. 7.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 13 Analysis Group

equivalent of the total electricity consumption in Tennessee in the same year.41  By 2018, new EE programs 

alone are expected to reduce summer peak demands by almost 20,000 MW (a full year’s growth).42

Figure 5 – Energy Efficiency and Demand Response Program Budgets, 2006­2009

Source: Consortium for Energy Efficiency, The State of the Efficiency Program Industry: Budgets, Expenditures, and Impacts, 2009 

Figure 6 – Summer Peak Demand Growth Reduced by Demand­Side Management 

Source:  NERC, Long­Term Reliability Assessment, 2009, at p. 18.

Although California and the Northeast account for over half of the total, budgets for ratepayer­funded EE 

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

increased in 2009, year­on­year, by 60 percent, 40 percent, and 36 percent, respectively.43  In the Southeast, 

Alabama, Mississippi, North Carolina, and Louisiana reported ratepayer­funded EE budgets for the first

 

41 Id.

42 NERC, supra n.15, at p. 12. 

43 CEE, supra n.40, at p. 15.

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2006 2007 2008 2009

Commercial and Industrial

Residential

Low Income

Load Management

Other

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2006 2007 2008 2009

Commercial and Industrial

Residential

Low Income

Load Management

Other

million $
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 14 Analysis Group

time in 2009.44  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.45

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

demand, as shown in Figure 6, underscoring growing acceptance of these load­management tools. 

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 cost­effective tool to help maintain reliability in the 

face of generation retirements. 

 

44 Id. at p. 16. 

45 PJM, supra n.36.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 15 Analysis Group

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.46,47

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 post­combustion controls.  Post­combustion 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 post­combustion 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,48

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 non­catalytic reduction (“SNCR”) technologies).49

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.50

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

Basis 

EPA projects that about 14 GW of additional coal­fired 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. 51  This number of retrofits is significantly less than the industry has added in past construction cycles.  

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

coal capacity was retrofit with scrubber controls,52 highlighting the industry’s ability to complete a 

 

46 EIA, U.S. Electric Power Industry Estimated Emissions by State (EIA­767 and EIA­906), Electric Power Annual 2008, 

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

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

48 PIRA, supra n.5, at p. 7.  

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

50 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.

51 U.S. EPA, supra n.4.  

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

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

REGULATIONS
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 16 Analysis Group

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.53

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 one­year extension.  EPA is under a court­imposed deadline to complete its regulations by 

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

limiting mercury emissions from coal­fired 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 

pre­compliance period, EPA may, and should, exercise its authority under Section 112(i)(3)(B) of the CAA 

to provide up to one­year 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 unit­specific 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 health­based 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, 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. 

Table 5 ­ Characteristics of U.S. Coal Plants 

 

53 Id.

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

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

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

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

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

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

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

Count % MW % SNCR SCR Scrubber Uncontrolled

Pollution Control Installed

(% of units)

Avg. Unit 

Size 

(MW)

Units Capacity

Unit Age

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

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

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

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

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

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

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

Count % MW % SNCR SCR Scrubber Uncontrolled

Pollution Control Installed

(% of units)

Avg. Unit 

Size 

(MW)

Units Capacity

Unit Age

Data Sources: 2007/2008 EPA IPM, ARP, NBP Databases & Commercial Sources, MJB&A Analysis 
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 17 Analysis Group

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.”54  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.55  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 non­attainment 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. 

Figure 7 – Worst Air Pollution Near Population Centers 

 

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

55 Id. Vol. 2 at p. 176. 

Counties in red are in 

violation of one or 

more of the following 

NAAQS in the 

periods 2003-2005, 

2004-2006, and/or 

2005-2007:

-1997 PM2.5

-1997 Ozone

-2006 PM2.5

New York Metro

Philadelphia

Washington, DC

Atlanta

Houston

Dallas

St. Louis

Chicago

Detroit Cleveland

Pittsburgh

Counties Violating 

Air Quality 

Standards in the 

Proposed 

Transport Rule 

Region 

(based on 2003­07 air 

quality monitoring data)

Source: U.S. EPA (with city/urban center locations added by MJB&A)
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 18 Analysis Group

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 cost­effective 

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 CAA­derived 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 unit­specific 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.56

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 Order57 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 well­established 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 

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

to the fullest extent possible. 

Many regional wholesale competitive markets also have well­established 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

 

56 DOE, Order No. 202­03­2, 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. 

(ISO­NE), 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 ISO­NE to require the Cross­Sound Cable Company, LLC (CSC) to operate the Cross­Sound Cable and related facilities as necessary to 

alleviate the disruptions in electric transmission service.  The Cable was energized a short time thereafter.”  

57 DOE, Order No. 202­05­03, December 20, 2005.

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

IMPACTS ON THE ELECTRIC INDUSTRY AND MANAGE ELECTRIC SYSTEM RELIABILITY
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 19 Analysis Group

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.58

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 Commission59 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 at­risk coal units, Fisk and Crawford, were to retire.60

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 vertically­integrated 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. 

 

58 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/gen­retire/must­run­operatingprocedures.ashx (accessed August 6, 2010). 

59 Commonwealth Edison Company, Application for authorization under Section 4­101 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 8­406 of the Act, to install, operate and maintain 

two new 345,000 volt electric transmission lines in Cook County, Illinois, No. 10­0385 (Ill. Cir. June 11, 2010). 

60 Direct Testimony of Thomas W. Leeming, p. 2, Lines 25­35.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 20 Analysis Group

Current industry practice and a review of applicable system data indicate the industry is well­positioned 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. 

IV.  CONCLUSION
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 21 Analysis Group

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 coal­fired 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.38d5d085b395c0cb2adedd10d661

66a0/ 

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 kilowatt­hours of electricity per year.  "We now have state­ofthe­art 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 hard­hit 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/buckeye­power­2 

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/news­releases/dte­energy­environmental­project­will­create­900­jobs78770632.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 emission­control 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_r

ules.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/gulf­power­begins­scrubber­startup 

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 

Kyger Creek  2  OH  217 

Kyger Creek  3  OH  217 

Kyger Creek  4  OH  217 

Kyger Creek  5  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 OVEC­IKEC. "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/news­releases/ovec­ikec­to­invest­820­million­for­environmentalcontrols­at­kyger­creek­and­clifty­creek­power­plants­56325052.html 
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 22 Analysis Group

Plant  Unit  State  Size 

(MW)  Highlights  

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 full­time 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.
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | August 2010 

M. J. Bradley & Associates LLC 23 Analysis Group

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 
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