Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | SUMMER 2011 UPDATE

M. J. Bradley & Associates LLC 1 Analysis Group

 

Ensuring a Clean, Modern Electric 

Generating Fleet while Maintaining 

Electric System Reliability 

June 2011 

SUMMER 2011 UPDATE
Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability | SUMMER 2011 UPDATE

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 

146,000 megawatts of electric generating capacity (including 93,000 megawatts of fossil generating capacity) 

throughout the U.S.  

Calpine Corporation 

Constellation Energy 

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 

Amlan Saha, 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 | SUMMER 2011 UPDATE

M. J. Bradley & Associates LLC 3 Analysis Group

Executive Summary

In August 2010, M.J Bradley & Associates and Susan Tierney of the Analysis Group were commissioned to 

prepare a study on the impact of two major U.S. Environmental Protection Agency (“EPA”) air regulations 

affecting the electric power sector: (1) the Clean Air Transport Rule (“Transport Rule”) and (2) the national 

emission standards for hazardous air pollutants from coal­ and oil­fired electric utility steam generating units 

(“Utility Toxics Rule”).  The study concluded that the electric industry is well­positioned to comply with EPA’s 

proposed air regulations without threatening electric system reliability. 

This “Summer 2011 Update” supplements the original analysis in light of new information and reaffirms the 

major conclusion of the prior report that the electric industry can comply with EPA’s air pollution rules without 

threatening electric system reliability provided that EPA, the industry and other agencies take practical steps to 

plan for the implementation of these rules and adopt appropriate regulatory approaches.  Proper planning and 

implementation can secure important public health benefits, reliable electric service, and efficient market 

outcomes. 

Since our analysis was released in August 2010, EPA has published its proposed Utility Toxics Rule and should 

be close to issuing the final Transport Rule. 

1.  EPA has proposed achievable standards for coal­fired power plants for mercury, acid gases, and 

other hazardous air pollutants.  The proposed emission limits are well within the capability of existing 

pollution control technology, and allow options for cost­effective compliance strategies. 

o The Utility Toxics Rule proposes emissions standards for existing coal­fired power plants for mercury,

particulate matter ("PM"), and hydrochloric acid ("HCl").  Companies can choose any combination of 

control systems or operational changes that enable them to achieve the proposed limits. 

o Nearly 60 percent of all coal­fired boilers that submitted stack test data to EPA are currently achieving 

the Utility Toxics Rule's proposed mercury emissions standard.1   This translates to more than 100 

boilers (out of a total of 178).  These power plants are meeting the proposed standard with a wide 

variety of pollution control systems and configurations (e.g., wet scrubbers, dry scrubbers, baghouses, 

and carbon injection systems). 

o Many states already impose more stringent mercury emissions limits on coal­fired power plants than 

have been proposed by EPA; these states, where plants are already in compliance with those stricter 

standards, include Illinois, Massachusetts, New Jersey, Connecticut, Delaware, and New York.  

o About 70 percent of all coal­fired boilers that submitted stack test data to EPA are currently achieving 

the proposed standards for PM and HCl.  Close to 160 coal­fired generating units report emissions 

below the level of the proposed HCl standard (out of 217), and close to 120 units report emissions 

below the proposed PM standard (out of 172). All of the proposed standards (mercury, PM, and HCl) 

allow companies to average their emissions across multiple boilers at a single facility.  Smaller boilers, 

which may only operate a limited number of hours each year, may comply without any major capital 

upgrades if co­located with a better­controlled boiler.  Almost 20 percent of existing coal capacity that 

currently lacks "scrubbers" is co­located at plants with existing scrubbers.  These units can potentially 

 

1

 Based on EPA’s revised standard of 1.2 pounds per trillion British thermal units (lb/TBtu).
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benefit from the averaging provisions of the rule, reducing the costs and potential retirements from the 

Utility Toxics Rule, as well as avoiding any related reliability issues. 

o EPA has proposed a "work practice standard" to control emissions of dioxins and furans, rather than 

setting a numeric emissions limit.  The work practice standard requires "good combustion practices" to

limit the formation of organic HAPs. 

o Several studies, published before EPA issued its Utility Toxics Rule, have projected widespread coal 

plant retirements in the U.S.  The higher end projections are likely overstating future levels of 

retirements given what we now know about EPA's proposed approach and the market response to date. 

2. Recent corporate financial statements and other recent announcements confirm that at least some of 

the nation’s largest coal­fired generating companies are well positioned to comply with EPA’s 

proposed air quality rules.   

o Benjamin G.S. Fowke, III, President and Chief Operating Officer of Xcel Energy, said: "Like many of 

our peers, we are in the process of evaluating what if any impact [EPA's Utility Toxics Rule] may have

on our operations.  Based on our preliminary review we do not anticipate that the rule will require 

extensive changes to our plans at [Northern States Power] and [Public Service Company of 

Colorado]...Our proactive steps to reduce emissions through the MERP project in Minnesota and our 

plans for the Clean Air­Clean Jobs Act in Colorado put us in good position to comply with these rules."  

April 28, 2011, Xcel Energy Inc. 1st Quarter 2011 Earnings Call

o Jim Rogers, President and CEO of Duke Energy, said: "[T]he anticipation of more stringent 

environmental rules has long been part of our business plan.  Over the past 10 years, we have spent $5

billion retrofitting existing units with updated emissions controls...Today, approximately 75% of our 

current coal generation capacity has scrubbers in operation.  This will increase to approximately 90%,

once our fleet modernization program and related retirements are completed...We have really mitigated 

a lot of the risk and the cost associated with this program by the early steps that we took."  May 3, 2011, 

Duke Energy 1st Quarter 2011 Earnings Call

o According to Gale Klappa, Chairman, President and CEO of Wisconsin Energy: "We really see very 

little impact on customer electric rates or our capital plan between now and 2015 as a result of all the 

new EPA regulations that have been proposed...We might see 1% to 2% increase our best guess [sic].  

So that gives you an example of how well we are positioned from the environmental standpoint in terms 

of complying with even the new proposed rule."  May 3, 2011, Wisconsin Energy Corporation 1st 

Quarter 2011 Earnings Call

o Reacting to EPA's proposed Utility Toxics Rule, Theodore Craver, chairman, president and CEO of 

Edison International said: "We installed the necessary equipment back in 2009 and are already 

achieving these [mercury] limits.  U.S. EPA's rule contained other draft provisions covering acid gases 

and non­mercury metals, which we can meet by installing the pollution control equipment we have been 

planning to use at Midwest Gen to meet our SO2 emissions commitments to the Illinois EPA."  May 2, 

2011, Edison International 1st Quarter 2011 Earnings Call

o William Spence, Chief Operating Officer, Executive Vice President and President of PPL Generation, 

said: "Our proactive approach to environmental compliance positions the PPL fleet favorably for future

EPA regulation.  Ninety­six percent of the competitive coal generation is scrubbed, 88 percent has NOx

controls already installed."  February 4, 2011, PPL 4th Quarter 2010 Earnings Call
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o Mauricio Gutierrez, Executive Vice President and Chief Operating Officer of NRG reports that: "The 

proposed [Utility Toxics Rule] provides flexibility in that compliance can be achieved through facility 

averaging and company selected control technology.  It also recognizes the inherent differences in 

mercury emissions from lignite coal...[t]he key takeaway is that we do not expect at this time any 

additional environmental CapEx beyond what we have previously announced."  May 5, 2011, NRG 

Energy 1st Quarter 2011 Earnings Call

o The Tennessee Valley Authority ("TVA"), which owns 17,000 megawatts ("MW") of coal­fired 

generating capacity, announced plans in April 2011 to retire 18 older coal­fired generation units at three 

power plants ( 2,700 MW) as part of the utility's vision of being one of the nation's leading providers of 

low­cost and cleaner energy by 2020.  The utility will replace "older and less­economical generation 

with cleaner sources."  Tom Kilgore, TVA's President and CEO, said that a "variety of electricity 

sources, rather than heavy reliance on any single source, reduces long­term risks and helps keep costs

steady and predictable....In the longer term, these actions reinforce our vision to keep bills low, keep

our service reliability high and further improve air quality as we modernize the TVA power system."  

TVA Press Release, April 14, 2011.

3. The results of PJM’s most recent Reliability Pricing Model (“RPM”) forward capacity auction clearly 

indicate the industry can meet future electricity demand while maintaining electric system reliability

in one of the most coal­dependent regions of the country.    

o On May 13, 2011, PJM announced the results of its RPM forward capacity auction for the period from 

May 31, 2014 through June 1, 2015.  Both the Transport Rule and the Utility Toxics Rule will be in 

effect by the beginning of 2015.  These results provide up­to­date information about how the region's 

reliability organization will ensure sufficient capacity to meet peak demand conditions after the 

proposed EPA air regulations go into effect. 

o PJM operates the nation's largest integrated power market, serving 54 million customers in 13 midAtlantic and Midwestern states, including all or parts of Delaware, Illinois, Indiana, Kentucky, 

Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 

Virginia, and the District of Columbia. 

o To ensure future electric system reliability, PJM's forward capacity auction requires power plant 

operators and other participating companies to offer (i.e., commit) resources, including both generating 

capacity and demand­side resources, three years in advance of when they are needed.2   

o The results of the most recent auction confirm that the 13­state PJM region will have ample electricity 

supply after EPA's Transport and Utility Toxics Rules take effect.  The market response represents a 

20.6 percent reserve margin for the region.  The energy resources selected to serve the region included 

new generating resources, capacity upgrades to existing power plants, new demand response resources, 

and new commitments to energy efficiency. 

o The resources that bid into but fail to "clear the auction" (i.e., to be selected as the lowest­cost capacity 

resources) are not needed for reliability purposes.  Generating units that did not clear have the option to 

retire.  In the most recent auction, existing fossil generating units that failed to clear were offset by new 

generating resources, energy efficiency, and demand response that offered their capacity at lower prices. 

o Numerous analyst reports have attempted to predict future levels of coal plant retirements with 

estimates ranging from 10 to 70 GW.  The PJM forward capacity auction is where the "rubber­meets­

 

2

 There are exceptions to this requirement (e.g., when a company relies on its own generating resources to satisfy its load requirements).  See infra n.21. 
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M. J. Bradley & Associates LLC 6 Analysis Group

the­road," reflecting actual market investment behavior, signaling that sufficient power will be available 

after EPA's air rules take effect. 

4. EPA has the statutory authority under the Clean Air Act to grant, on a case­by­case basis, extensions 

of time to complete the installation of pollution control systems.    

o EPA emphasizes in its proposed Utility Toxics Rule that it has the discretion to grant, on a case­by­case 

basis, extensions of time to complete the installation of pollution control systems where appropriate.

o This provision provides companies with the flexibility to schedule the installation of controls across

multiple outage periods—maintaining electric system reliability while facilitating the expeditious 

installation of modern pollution control systems. 

o Permitting authorities have used this provision in the past under previous MACT rules. 

o If four years is still not enough time to install the necessary controls, EPA and the Department of 

Energy have the authority to enter into administrative orders of consent or consent decrees with power

plants, allowing them to run under specific and limited circumstances to maintain reliability.  This 

approach ensures that reliability standards are maintained without an across­the­board delay in the 

implementation of the rules. 

   
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A.  EPA has proposed achievable standards for coal­fired generating units for mercury, acid gases, 

and other hazardous air pollutants 

In December, 2000, the U.S. Environmental Protection Agency (“EPA”) issued a formal notice concluding 

that it was “appropriate and necessary” to regulate hazardous air pollutants (“HAPs”) from the electric 

power sector under Section 112 of the Clean Air Act.  The finding specifically referenced concerns 

associated with mercury, arsenic, chromium, nickel, cadmium, dioxin, hydrogen chloride, and hydrogen 

fluoride.  Almost 11 years later, EPA has issued its proposed rule.3

The proposed standards for existing coal­fired generating units are summarized in Table 1 below. 

Table 1 – Proposed Standards for Existing Coal­Fired Generating Units

HAP or HAP Surrogate  Proposed Standard

Particulate matter  0.030 lb/MMBtu

Hydrogen chloride  0.0020 lb/MMBtu

Mercury (units designed for coal ≥ 8,300 Btu/lb)  1.2 lb/TBtu4

Mercury (units designed for coal < 8,300 Btu/lb)  4.0 lb/TBtu

Note: The Utility Toxics Rule also proposes “output-based” emissions standards for coal-fired generating units (i.e., standards 

expressed in pounds per megawatthour “MWh”). Companies can demonstrate compliance based on either the “input-based” standards 

listed above (in million Btu “MMBtu” of heat input) or the output-based limits. 

Coal­fired generating units emit over 100 chemicals on EPA’s list of HAPs—pollutants that are known or

suspected to cause cancer or other serious health effects, such as reproductive problems or birth defects, and 

that adversely affect the environment.5   Rather than requiring companies to comply with standards for each 

individual HAP emitted from coal­fired generating units, however, EPA has proposed the use of 

“surrogates,” simplifying the monitoring and compliance requirements of the rule.  For example, particulate 

matter (“PM”) has been proposed as a surrogate for all non­mercury metal HAPs, including arsenic, 

cadmium, chromium, and lead.  Hydrogen chloride (“HCl”) is being used as a surrogate for all acid gas 

HAPs.  No surrogate was used for mercury. 

EPA’s proposed standards were calculated based on an extensive data collection effort, involving hundreds 

of stack tests at coal­fired generating units throughout the country.  The Clean Air Act requires that EPA’s 

standards reflect the performance of the “best performing” facilities within the category or subcategory. 

Figure 1 compares the proposed standard for mercury6 with the stack test results from 178 coal units that 

conducted stack emissions testing in 2010 as part of EPA’s Information Collection Requests (“ICR”) 

emissions testing program.  The results show that nearly 60 percent of all coal­fired generating units that 

submitted stack test data to EPA are currently achieving the proposed mercury emissions standard.   This 

translates to more than 100 units (out of a total of 178).   

 

3

 U.S. Environmental Protection Agency (“EPA”), National Emission Standards for Hazardous Air Pollutants From Coal and Oil­Fired Electric Utility 

Steam Generating Units and Standards of Performance for Fossil­Fuel­Fired Electric Utility, Industrial­Commercial­Institutional, and Small IndustrialCommercial­Institutional Steam Generating Units,  Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011. 

4

 EPA’s proposed mercury emissions standard for existing electric generating units designed for coal ≥ 8,300 Btu/lb was revised on May 18, 2011.  The 

standard was adjusted from 1.0 lb/TBtu to 1.2 lb/TBtu. 

5

 EPA, Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units —Final Report to Congress, EPA–453/R–98–004a, 

February 1998. 

6

 Only about 30 coal­fired generating units in the U.S. would be subject to the mercury standard for units designed for coal with a heat content of less than 

8,300 British thermal units per pound (Btu/lb); therefore, we focus our analysis on the mercury standard for units designed for coal ≥ 8,300 Btu/lb. 

I. EPA’S PROPOSED UTILITY TOXICS RULE
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M. J. Bradley & Associates LLC 8 Analysis Group

Figure 1 also shows that the power plants meeting the proposed standard have a wide variety of pollution 

control systems and configurations that are reducing their mercury emissions.  Many of the units that are 

below the level of the standard have been retrofit with a scrubber (wet or dry) or activated carbon injection 

(“ACI”).  Virtually all of the units with a “baghouse” or fabric filter (“FF”) report emissions well below the 

level of the proposed mercury standard.  In many cases, these mercury reductions are being achieved as a 

co­benefit of existing state and federal pollution control programs aimed at reducing SO2 and other air 

pollutants.  In some cases, states have adopted mercury control requirements because of the slow pace of the 

federal rulemaking process.  Appendix A provides details on the existing state mercury control 

requirements.  Several states already impose more stringent mercury emissions limits on coal­fired power 

plants than what has been proposed by EPA, including: Illinois, Massachusetts, New Jersey, Connecticut, 

Delaware, and New York.

Figure 1 – Proposed Mercury Emissions Standard and ICR Stack Test Results

Note: In order to better reflect the detail of the graph, the lower portion of the figure highlights a narrow band of the upper bar graph 

(i.e., the area below 2 lb/Tbtu). 

Figure 2 compares the proposed standard for PM with the stack test results from 172 coal­fired generating 

units that conducted stack emissions testing in 2010.  The results show that nearly 70 percent of all coalfired generating units that submitted stack test data are currently achieving the proposed PM emissions 

standard.  This translates to more than 119 units (out of a total of 172).  

Figure 3 compares the proposed standard for HCl with the stack test results from 217 coal­fired generating 

units that conducted stack emissions testing in 2010.  The results show that 73 percent of all coal­fired 

generating units that submitted stack test data are currently achieving the proposed HCl emissions standard.   

This translates to 158 units (out of a total of 217). 

0.00E+00

5.00E-07

1.00E-06

1.50E-06

2.00E-06

100% 89% 78% 66% 55% 44% 33% 21% 10%

0.00E+00

5.00E-06

1.00E-05

1.50E-05

2.00E-05

2.50E-05

3.00E-05

3.50E-05

4.00E-05

4.50E-05

100% 89% 78% 66% 55% 44% 33% 21% 10%

Bituminous & Sub-bituminous Coal-fired Units in ICR Dataset (%)

EPA Proposed Limit: 1.2

45

40

35

30

25

20

15

10

5

2

1.5

1

0.5

Reported 

Mercury 

Emission 

(lb/TBtu)

Summary of Source Units

No. of total sources in subcategory1,061

No. of source units in subcategory in ICR database178

No. of source units in ICR 

database that reported 

emission rates below the EPA 

proposed limit

101

Neither Scrubber nor ACI

Scrubber + ACI

ACI (No Scrubber)

Dry Sorbent Injection

Scrubber - Wet

Scrubber - Dry

PM Type ESP

PM Type FF
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Figure 2 – Proposed PM Emissions Standard and ICR Stack Test Results 

Figure 3 – Proposed HCl Emissions Standard and ICR Stack Test Results 

Note: In order to better reflect the detail of the graph, the lower portion of the figure highlights a narrow band of the upper bar graph 

(i.e., the area below 0.004 lb/MMBtu).

0.000

0.001

0.002

0.003

100% 90% 81% 72% 63% 54% 44% 35% 26% 17% 8%

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0.160

0.180

100% 90% 81% 72% 63% 54% 44% 35% 26% 17% 8%

Reported 

HCl 

Emission 

(lb/MMBtu)

Coal-fired Units in ICR Dataset (%)

EPA Proposed: 0.0020

Neither Scrubber nor ACI

Scrubber + ACI

ACI (No Scrubber)

Dry Sorbent Injection

Scrubber - Wet

Scrubber - Dry

PM Type ESP

PM Type FF

Summary of Source Units

No. of total sources in subcategory1,091

No. of source units in subcategory in ICR database217

No. of source units in ICR 

database that reported 

emission rates below the EPA 

proposed limit

158

Reported 

Total PM 

Emission 

(lb/MMBtu)

Coal-fired Units in ICR Dataset (%)

EPA Proposed: 0.030

0.000

0.050

0.100

0.150

0.200

0.250

100% 88% 77% 65% 53% 42% 30% 19% 7%

Neither Scrubber nor ACI

Scrubber + ACI

ACI (No Scrubber)

Dry Sorbent Injection

Scrubber - Wet

Scrubber - Dry

PM Type ESP

PM Type FF

Summary of Source Units

No. of total sources in subcategory1,091

No. of source units in subcategory in ICR database172

No. of source units in ICR 

database that reported 

emission rates below the EPA 

proposed limit

119

Total PM = PM (filterable) + PM2.5 (Condensible)
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B.  The averaging provisions of the Utility Toxics Rule, and work practice standards for dioxins 

and furans, reduce the costs and potential retirements from the rule 

Most coal­fired power plants have multiple boilers and electric generating units at a single plant location.  

The Utility Toxics Rule would allow companies to demonstrate compliance by averaging their emissions 

across multiple units at an affected source.  This flexible compliance option is particularly helpful to smaller 

generating units that are co­located with larger generating units, but may not be economic to retrofit with 

pollution control systems. 

Smaller boilers, which may only operate a limited number of hours each year, may comply without any 

major capital upgrades if co­located with a better­controlled boiler.  Almost 20 percent of existing coal 

capacity that currently lacks “scrubbers” is co­located at plants with existing scrubbers.  These units can 

potentially benefit from the averaging provisions of the rule, reducing the costs and potential retirements 

from the Utility Toxics Rule, as well as avoiding any related reliability issues. 

EPA has proposed a “work practice standard” to control emissions of dioxins and furans, rather than setting 

a numeric emissions limit.  The work practice standard requires “good combustion practices” to limit the 

formation of organic HAPs.  Companies would perform an annual performance test to ensure efficient fuel 

combustion. 

C.  The majority of U.S. coal plants have already installed air pollution controls 

As highlighted in our August 2010 report, many coal plants have already installed pollution control 

technologies to dramatically reduce their air pollution emissions, including NOx, SO2, mercury, and other 

HAPs.   

• About 60 percent of the U.S. coal fleet (192 GW) has scrubbers installed or under construction.  

Scrubbers capture sulfur dioxide (“SO2”), mercury, HCl, and PM emissions.7   Among large coal‐

fired generating units—units greater than 400 megawatts (“MW”)—more than 70 percent have 

scrubbers installed.  Scrubbers are the most capital intensive technology that a company would 

potentially need to install to comply with the Utility Toxics Rule. 

• About 35 percent of the U.S. coal fleet (112 GW) has fabric filters installed.  Fabric filters (or 

baghouses) can dramatically reduce PM and mercury emissions.8  

• About 50 percent of the U.S. coal fleet (158 GW) has advanced post­combustion NOx controls 

installed—selective catalytic reduction (“SCR”) or selective non­catalytic reduction (“SNCR”).9

    

• More than 70 percent of the U.S. coal fleet has electrostatic precipitators (“ESPs”) installed for PM 

control, although many are older systems designed for lower levels of performance.10   Companies 

may need to upgrade their ESPs or replace them with baghouses to comply with the PM limits 

proposed in the Utility Toxics Rule. 

Additionally, new technologies are available that companies will be using to comply with EPA’s new air

rules.  In particular, dry sorbent injection (“DSI”) has emerged as a low­capital­cost alternative to installing 

a scrubber.  DSI can be used to control SO2 and other acid gases through the injection of a chemical reagent, 

including sodium bicarbonate, hydrated lime, and a natural occurring mixture of sodium carbonate and 

 

7

 Northeast States for Coordinated Air Use Management (“NESCAUM”), Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal­Fired Power Plants, March 31, 2011. 

8

Id.

9

Id.

10 Id.
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sodium bicarbonate called Trona.  Relative to a scrubber, DSI not only has low capital costs but can also 

generally be installed within 12 months.  DSI costs have been estimated at $55 per kilowatt (“kW”).11   

Midwest Generation estimates that it can retrofit its entire coal fleet with DSI and fabric filters within 12 to 

24 months (of decision) at a cost of $232/kW.12   By contrast, a scrubber alone can cost over $400/kW.13  

Generally, DSI will be considered for coal units burning low sulfur Powder River Basin (“PRB”) coal.  

Other factors that will drive the deployment of DSI include unit size, percentage reduction of emissions 

required, plant economics, and site specific characteristics.  DSI has been deployed at several coal­fired 

generating units in the U.S., including: 

• In 2010, NRG’s Dunkirk and Huntley power plants installed DSI systems that simultaneously inject 

Trona and powder­activated carbon (“PAC”).  Performance tests indicate that emissions of SO2

have been reduced by over 55 percent, mercury levels have been reduced by over 90 percent, and 

particulate levels have been reduced to less than 0.010 lb/MMBtu.  NRG considers these 

installations sufficient and expects no additional environmental capex requirements to comply with 

the Utility Toxics and Transport rule.14

• Duke Energy installed DSI systems in 2010 at its Gallagher generating station.  According to the 

company, the estimated total cost of the DSI system, installed at Units 2 and 4, was $11.6 million or 

about $41/kW.  The system will reduce SO2 emissions by 50 percent.  Duke Energy expects the DSI 

system to help the company comply with the requirements of the Utility Toxics Rule and Transport 

Rule.15

• GenOn operates a DSI system at its Potomac River Generating Station in Alexandria, Virginia. 

According to the company, the Potomac River plant has seen up to 80 percent reduction in SO2

emissions since introducing the trona­based system.16  

• Midwest Generation is seeking to retrofit its coal fleet (12 coal­fired units in the Midwest with total 

capacity of about 5 GW) with DSI technology and upgrade its particulate control systems at a total 

estimated cost of $1.2 billion.17   In November 2010 and February 2011, Midwest Generation 

obtained construction permits from the Illinois Environmental Protection Agency to install DSI 

systems at its Waukegan and Powerton generating stations.18  

• Conectiv Energy installed a Trona based DSI system at its Edge Moor plant (Units 3 and 4) and 

operated it from 2009 to mid­2010 on bituminous coal.  The plant has since been converted to run 

on natural gas obviating the need for the DSI system.19

 

 

11 EPA, Documentation Supplement for EPA Base Case v4.10_PTox­ Updates for Proposed Toxics Rule, March 2011. 

12 Bernstein Research, U.S. Utilities: The EPA’s Mercury and Air Toxics Standards Are Tougher Than They Appear, March 2011. 

13 NESCAUM, supra n.7. 

14 NRG Energy, Q1 2011 Earnings Conference Call, May 5, 2011. 

15 Duke Energy Indiana, Inc., Petition for issuance of a Clean Coal Technology Certificate of Public Convenience and Necessity ("CPCN") pursuant to 

Ind. Code § 8­1­8.7 for the use of a Dry Sorbent Injection System at its Gallagher Generating Station Units 2 and 4, No. 43873 (Indiana Utility 

Regulatory Commission, Sep 8, 2010).

16 GenOn, http://www.genon.com/company/company­environmental­technology.aspx (accessed June 3, 2010) 

17 Edison International, Q2 2010 Earnings Call Transcript, http://www.morningstar.com/earnings/16355020­edison­international­eix­q2­2010.aspx 

(accessed June 4, 2011) 

18 Midwest Generation LLC, Form 10­K, February 2011. 

19 NESCAUM, supra n.7.
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A.  Financial statements confirm that at least some of the nation’s largest coal­fired generating 

companies are well positioned to comply, reflecting the progress throughout the U.S. coal fleet 

in adding modern pollution control systems 

A survey of recent corporate earnings statements shows that several of the companies that own significant 

quantities of coal­fired generating capacity are well positioned to comply with EPA’s proposed air quality 

rules because of earlier investments in their fleets.  The following quotes, from a sampling of electric 

company executives, highlight several important themes: (1) companies have long anticipated these rules; 

(2) early investments have positioned these companies well for compliance; and (3) the impact on electricity 

rates can be managed. 

• Benjamin G.S. Fowke, III, President and Chief Operating Officer of Xcel Energy, said: “Like many of 

our peers, we are in the process of evaluating what if any impact [EPA’s Utility Toxics Rule] may have

on our operations.  Based on our preliminary review we do not anticipate that the rule will require 

extensive changes to our plans at [Northern States Power] and [Public Service Company of 

Colorado]...Our proactive steps to reduce emissions through the MERP project in Minnesota and our 

plans for the Clean Air­Clean Jobs Act in Colorado put us in good position to comply with these rules.”  

April 28, 2011, Xcel Energy Inc. 1st Quarter 2011 Earnings Call

• Jim Rogers, President and CEO of Duke Energy, said: “[T]he anticipation of more stringent 

environmental rules has long been part of our business plan.  Over the past 10 years, we have spent $5

billion retrofitting existing units with updated emissions controls...Today, approximately 75% of our 

current coal generation capacity has scrubbers in operation.  This will increase to approximately 90%,

once our fleet modernization program and related retirements are completed...We have really mitigated 

a lot of the risk and the cost associated with this program by the early steps that we took.” May 3, 2011, 

Duke Energy 1st Quarter 2011 Earnings Call

• According to Gale Klappa, Chairman, President and CEO of Wisconsin Energy: “We really see very 

little impact on customer electric rates or our capital plan between now and 2015 as a result of all the 

new EPA regulations that have been proposed...We might see 1% to 2% increase our best guess [sic]. 

So that gives you an example of how well we are positioned from the environmental standpoint in terms 

of complying with even the new proposed rule.”  May 3, 2011, Wisconsin Energy Corporation 1st 

Quarter 2011 Earnings Call

• Reacting to EPA’s proposed Utility Toxics Rule, Theodore Craver, chairman, president and CEO of 

Edison International said: “We installed the necessary equipment back in 2009 and are already 

achieving these [mercury] limits.  U.S. EPA’s rule contained other draft provisions covering acid gases 

and non­mercury metals, which we can meet by installing the pollution control equipment we have been 

planning to use at Midwest Gen to meet our SO2 emissions commitments to the Illinois EPA.”  May 2, 

2011, Edison International 1st Quarter 2011 Earnings Call

• William Spence, Chief Operating Officer, Executive Vice President and President of PPL Generation, 

said: “Our proactive approach to environmental compliance positions the PPL fleet favorably for future

EPA regulation.  Ninety­six percent of the competitive coal generation is scrubbed, 88 percent has NOx

controls already installed.”  February 4, 2011, PPL 4th Quarter 2010 Earnings Call

• Mauricio Gutierrez, Executive Vice President and Chief Operating Officer of NRG reports that: “The 

proposed [Utility Toxics Rule] provides flexibility in that compliance can be achieved through facility 

II. COMPANY REACTIONS TO EPA RULES
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M. J. Bradley & Associates LLC 13 Analysis Group

averaging and company selected control technology.  It also recognizes the inherent differences in 

mercury emissions from lignite coal...[t]he key takeaway is that we do not expect at this time any 

additional environmental CapEx beyond what we have previously announced.”  May 5, 2011, NRG 

Energy 1st Quarter 2011 Earnings Call

• The Tennessee Valley Authority (“TVA”), which owns 17,000 MW of coal­fired generating capacity, 

announced plans in April 2011 to retire 18 older coal­fired generation units at three power plants ( 2,700 

MW) as part of the utility’s vision of being one of the nation’s leading providers of low­cost and cleaner 

energy by 2020.  The utility will replace “older and less­economical generation with cleaner sources.”  

Tom Kilgore, TVA’s President and CEO, said that a “variety of electricity sources, rather than heavy 

reliance on any single source, reduces long­term risks and helps keep costs steady and predictable....In

the longer term, these actions reinforce our vision to keep bills low, keep our service reliability high and 

further improve air quality as we modernize the TVA power system.”  TVA Press Release, April 14, 

2011

 
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M. J. Bradley & Associates LLC 14 Analysis Group

A.  Results from PJM’s RPM forward capacity auction show that the industry is able to meet 

future electricity demand while maintaining electric system reliability 

Recent market information from one region of the country with a large concentration of coal­fired power 

plants provides up­to­date information and insights about how various players in the industry plan to 

respond to the EPA’s future air pollution regulations.  Market participants not only include owners of power 

plants affected by the EPA air pollution regulations, but also owners of other power plants and providers of 

demand­side resources, all of whom are critical to ensure regions have access to diverse, reliable, efficient, 

and environmentally compliant electric resources.  

PJM provides reliability and wholesale power market functions for the nation’s largest  integrated power 

market, serving 54 million customers in 13 Mid­Atlantic and Midwestern states including all or parts of 

Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, 

Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.  In addition to operating a 

centrally dispatched, competitive wholesale electric power market, PJM coordinates and directs the 

operation of the transmission grid and plans transmission expansion improvements to maintain grid 

reliability in the region.  Much of the generating capacity in PJM’s footprint is at coal­fired power plants, 

some of which are old and relatively inefficient.  At the end of 2010, coal units comprised 41 percent of 

capacity in PJM.20

    

Keeping the Lights On at the PJM Control Room 

Source: PJM. PJM 2010 Annual Report. 

To secure adequate capacity to meet future projected power demand, PJM recently conducted its latest 

round of market­based bidding through its Reliability Pricing Model (“RPM”) forward capacity auction. On 

May 13, 2011, PJM announced the results of that auction, which covers the period from May 31, 2014 

through June 1, 2015 – a time when the Utility Toxics Rule and the Transport Rule will both be in effect.  

PJM’s forward capacity auction requires owners of power plants and other participating companies21  to 

offer (i.e., commit) resources including both power plants and demand­side resources, three years in 

 

20 Monitoring Analytics, State of the Market Report for PJM, March 10, 2011. 

21 There are exceptions to this requirement for companies that provide their own generating resources to meet their own loads.  Power companies in PJM 

that do not participate in the capacity auction, like AEP and Duke‐Ohio, are required to certify that they have adequate capacity to ensure reliable service.  

These companies have confirmed that they have sufficient electric capacity to meet their needs through June 1, 2015 – more than five months after the 

EPA rules are expected to take effect.

III. PJM FORWARD CAPACITY AUCTION
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M. J. Bradley & Associates LLC 15 Analysis Group

advance  so as to maintain electric system reliability.  Resources that “clear” the auction receive capacity 

payments; those that do not clear receive no compensation for their capacity. 

The results of the May 13th 2011 auction show that while some coal plants22 were unable to clear the auction 

and may choose to retire, the region was still able to secure an ample supply of energy resources to maintain 

reliability.  In fact, the market secured resources sufficient to maintain a 20 percent reserve margin for the 

region. 

Out of a total of nearly 150,000 MW of capacity selected in the recent PJM auction,23  nearly 4,200 MW of 

new capacity plans to enter the market by 2014/2015, including the addition of new generation capacity

resources, capacity upgrades to existing generation capacity resources, new demand resources, upgrades to 

existing demand resources, and new energy efficiency resources. 

The PJM Service Territory 

“MAAC” is the Mid­Atlantic Area Council Region which is the eastern part of PJM.  Within MAAC are the Eastern (“EMAAC”) 

area which includes parts of New Jersey, Eastern Pennsylvania, Delaware and Eastern Maryland – in the areas served by PSE&G, 

JCP&L, PECO, AE, DPL & RECO); the Southwestern MAAC (parts of Maryland and the District of Columbia, served by PEPCO 

and BG&E); and the Western MAAC (parts of Pennsylvania served by Penelec, MetEd, PPL).  There is also “Western PJM” – in 

parts of Illinois, Indiana, Ohio, Kentucky and other states (ComEd, AEP, Dayton, APS, Duquesne, ATSI, Duke). 

Source: PJM, http://pjm.com/documents/~/media/about-pjm/pjm-zones.ashx (accessed June 3, 2011) 

The price of capacity, which accounted for less than 20 percent of PJM wholesale power prices in 2010 

when prices were at historic highs, increased and decreased in different parts of the region.24   As 

summarized in the chart below, in the Eastern part of PJM (the subregions called “MAAC” and “EMAAC”), 

prices fell more in line with past price levels.  The “RTO” price—representing the price in the portions of 

the PJM region not constrained by transmission (which effectively is the western portion of the PJM 

system)—increased to levels that were still below prices in 2010/2011 although slightly above prices in 

2009/2010 and 2011/2012. 

 

22 Note that PJM’s market monitor had provided guidance to participants in the auction that they should develop their bids assuming compliance with the 

EPA Utility Toxic Rule: “Question 1: If a participant determines that the costs to meet the proposed MACT rules will be prohibitive, do they need to 

submit a request for deactivation so that they would not have to offer a unit into the 2014/2015 Base Residual Auction (BRA)?  Answer 1: The MMU 

expects participants to offer units based on their calculated costs of compliance and based on their own economic decisions.  If the units do not clear, 

participants have the option to retire the units.” See Monitoring Analytics, Clarification on ACR Data and Pending EPA Regulations, April 28, 2011. 

23 This amount is lower than PJM’s 2010 generating capacity of 167,362 MW (See PJM, Annual Report, 2010), or its projected capacity requirements for

2014/2015, because some distribution companies are permitted to satisfy their capacity requirements through their own generating resources, as noted 

previously. 

24 Monitoring Analytics, State of the Market Report for PJM, March 10, 2011.   
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M. J. Bradley & Associates LLC 16 Analysis Group

The generating units that failed to clear the auction—including fossil generating units that may eventually 

be slated for retirement—were largely offset by these new generating, energy efficiency, and demand 

response resources.  In its auction results, PJM reported a reduction in committed coal capacity in 

2014/2015 equal to 6,900 MW, and suggested that the decrease is likely related to some coal capacity 

reflecting the costs of environmental retrofits in their offer prices.25   These costs would make some coal 

units uneconomic relative to lower cost resources.  In contrast to the reduction in committed coal capacity, 

however, demand response resources increased by 4,836 MW.26   Commitments to conserve energy through 

energy efficiency increased by 142.7 MW.27   The auction also procured 695 MW of wind power and 45.6 

MW of solar power.28

Figure 4 – PJM Base Residual Auction Resource Clearing Prices

Source: PJM, 2014/2015 RPM Base Residual Auction Results, PJM DOCS #645284 (May 2011). 

Notes: 

RPM – Reliability Pricing Model, with the “Base Residual Auction” being the initial auction each year to select basic resources for a 

future period. 

“RTO” – Regional Transmission Organization—effectively these are the capacity prices in the western portion of PJM. 

“MAAC” – Mid-Atlantic Area Council 

“EMAAC” – Eastern Mid-Atlantic Area Council region 

“SWMAAC” – Southwest Mid-Atlantic Area Council region 

As indicated by the results of PJM’s most recent forward capacity auction, the region will have more than 

enough capacity to meet federal reliability standards set by NERC when the Utility Toxics Rule and the

Transport Rule will both be in effect.  Notably, more than 5 GW of new capacity came into the market with 

this auction, including new generation and new demand side resources such as energy efficiency and 

demand response.  This outcome illustrates the diversity of ways that market participants can provide 

reliable power supplies while meeting future environmental requirements.   

B.  The results of the PJM forward capacity auction suggest that some projections of future coal 

plant retirements may be overstated 

Numerous analyst reports have been issued since the beginning of 2010, predicting varying levels of coal 

plant retirements in the U.S.  Some of the factors contributing to these retirement projections include lower 

 

25 PJM, 2014/2015 RPM Base Residual Auction Results: Addendum, PJM DOCS #648604 (May 2011). 

26 Id. 

27 PJM, 2014/2015 RPM Base Residual Auction Planning Period Parameters, PJM DOCS #631095 (May 2011) 

28 PJM, Demand Resources and Energy Efficiency Continue to Grow in PJM’s RPM Auction, May 13, 2011. 
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M. J. Bradley & Associates LLC 17 Analysis Group

electricity demand, lower natural gas prices, the advanced age of many coal­fired generating units, and the 

increased costs associated with EPA’s environmental rules.  Many of these reports included impacts from 

EPA’s air regulations as well as other rules (e.g., 316(b) cooling water standards, coal ash rules, and some of 

the studies have modeled a price on greenhouse gas emissions).  Most of these studies were developed prior 

to the issuance of the Utility Toxics Rule in March 2011.  Examples of some of these analyst reports are 

summarized below, including projected coal capacity retirements. 

The results of the recent PJM forward capacity auction, which reflect actual market investment decisions 

rather than modeled predictions, suggest that the level of coal plant retirements will be more modest than 

some have predicted and that the 13­state PJM region will have ample electricity supply after EPA’s air 

regulations go into effect in the middle of the decade. As EPA’s proposed air pollution regulations are more 

flexible than had been anticipated by some of those studies’ “worst­case” scenarios and given the industry 

can supply needed capacity through a variety of resources, the recent PJM auction results suggest that coal 

plant retirements will likely fall at the lower range of prior estimates.29

   

Study by  Release 

Date 

Nationwide Projected 

Capacity Retirement 

(denotes coal capacity only)

Incremental 

Retirements (excludes 13 

GW of already announced 

retirements/idlings)

Report Title 

CERA March 

2011

35 GW

(by 2020) 22 GW

Staying Power Can US Coal Plants 

Dodge Retirement for Another Decade? 

(Private Report)

Bernstein 

Research

March 

2011

54 GW

(by 2014/15)

41 GW

U.S. Utilities: The EPA’s Mercury and 

Air Toxics Standards Are Tougher 

Than They Appear

FBR 

Capital

December 

2010

45 GW

(by 2018) 32 GW Coal Retirements in Perspective: 

Quantifying the Upcoming EPA Rules

The Brattle 

Group

December 

2010

40­55 GW

(by 2020)

34 GW

Potential Coal Plant Retirements 

Under Emerging Environmental 

Regulations

NERC October 

2010

15­35 GW

(by 2018) 12 GW

2010 Special Reliability Scenario 

Assessment: Resource Adequacy 

Impacts of Potential U.S. 

Environmental Regulations

Credit 

Suisse

September 

2010

60 GW

(by 2017) 47 GW Growth from Subtraction: Impact of 

EPA Rules on Power Markets

PIRA 

Energy 

Group

April 

2010

30­40 GW

(by 2015) 22 GW

EPA’s Upcoming MACT: Strict NonHg Regs Can Have Far­Reaching 

Market Impacts

   

 

29 See also S. Tierney and C. Cicchetti, The Results in Context: A Peer Review of EEI’s “Potential Impacts of Environmental Regulation on the U.S. 

Generation Fleet,” May 2011; and S. Tierney, Electric Reliability under New EPA Power Plant Regulations: A Field Guide, January 18, 2011, 

http://www.wri.org/stories/2011/01/electric­reliability­under­new­epa­power­plant­regulations­field­guide  
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M. J. Bradley & Associates LLC 18 Analysis Group

A.  EPA has the statutory authority under the Clean Air Act to grant, on a case­by­case basis, 

extensions of time to complete the installation of pollution control systems 

In general, under the Clean Air Act, Congress requires existing, affected sources to comply with standards for 

hazardous air pollutants “as expeditiously as practicable, but in no event later than 3 years after the effective 

date of such standard.”  As a result, affected coal­fired power plants will need to comply with the emissions 

limits of the Utility Toxics Rule by the beginning of 2015.  However, there are exceptions under the law, which 

allow additional time for the installation of controls, and, in fact, EPA emphasizes in its proposed Utility Toxics 

Rule that the Agency and state regulatory authorities have the discretion to grant, on a case­by­case basis, an 

additional 12 months for the installation of pollution control systems where appropriate.  Permitting authorities 

have used this provision in the past under previous air toxics rules. 

This provision provides companies with the flexibility to schedule the installation of controls across multiple 

outage periods—maintaining electric system reliability while facilitating the expeditious installation of pollution 

control systems.  Companies will typically construct pollution control systems while a power plant continues to 

operate.  The equipment is then connected or “tied­in” to the plant during a scheduled outage period, 

coordinated with other generating facilities to ensure reliability.  This will typically occur during a month or 

month(s) when the demand for electricity is relatively low—avoiding the hottest summer months and the coldest 

winter months.  A 12­month extension would provide plant operators with an additional two shoulder periods to 

schedule outages and stagger the installation of controls. 

If four years is still not enough time to install the necessary controls, EPA and the Department of Energy have 

the authority to enter into administrative orders of consent or consent decrees with power plants, allowing them 

to run under specific and limited circumstances to maintain reliability.  This approach ensures that reliability 

standards are maintained without an across­the­board delay in the implementation of the rules. 

 

IV.  EPA AUTHORITY TO GRANT ADDITIONAL TIME FOR THE INSTALLATION OF CONTROLS
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M. J. Bradley & Associates LLC 19 Analysis Group

These new findings support the conclusion that we reached in our August 2010 study on EPA’s air regulations 

and their implications for electric system reliability.  The flexible nature of EPA’s regulations, the readiness 

reported by leaders of many of the companies owning affected coal plants, the recent results of the forward 

capacity auction in PJM, and the various authorities of EPA and other federal agencies all indicate we can  

modernize and clean the nation’s electric fleet to enhance public health while maintaining electric system 

reliability.   

V.  CONCLUSION
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M. J. Bradley & Associates LLC 20 Analysis Group

APPENDIX A 

State Mercury Regulations 

State Year Enacted  Policy/Rule 

New Hampshire  2002  Requires 75% reduction in annual mercury emissions from coal plants compared to 1996/97 emissions. 

Connecticut  2003  Requires coal­fired power plants to achieve either an emissions standard of 0.6 lb/tBtu or a 90% efficiency 

in technology installed to control mercury emissions. 

New Jersey  2004 

Requires a 90% reduction of mercury emissions from coal­fired power plants by the end of 2007. Plants 

have the option of meeting the standards in 2012 if they also make major reductions in their emissions of 

sulfur dioxide, nitrogen oxides, and fine particulates. 

Delaware  2006  Requires power plants to capture at least 80% of mercury beginning in 2009 and 90% beginning in 2013. 

Maryland  2006  Requires power plants to capture at least 80% of mercury beginning in 2010 and 90% beginning in 2013. 

Illinois  2006  Requires power plants to reduce mercury emission by 90% starting in July of 2009. 

North Carolina  2006 

Requires power plants submit by January 1, 2013 detailed plans and timetables for achieving maximum 

technically and economically possible mercury reductions at each unit.  Units that are not controlled by 

2017 must be shut down. 

Montana  2006 

Requires mercury emitting EGUs to achieve an emission rate lower than 0.9 lb/TBtu by January 1, 2010. 

EGUs unable to meet this limit after installing an approved control strategy may apply for an alternative 

limit by July 1, 2011. 

Minnesota  2006  Requires MN’s largest coal­fired power plants to cut mercury emissions by 90% by 2015. 

Massachusetts  2007  Requires power plants to capture at least 85% of mercury (or achieve a rate of 0.0075 lb/GWh) by 2008 

and 95% of mercury (or achieve a rate of 0.0025 lb/GWh) by 2012. 

New York  2007 

Phase I (2010): Power plants must reduce mercury emissions by 50%.  Phase II (2015):  Implementation 

of unit­based limits for each facility to reduce mercury emissions by 90% using Maximum Available 

Control Technologies 

Colorado  2007  Requires new or reconstructed units to achieve a minimum mercury capture rate of 90% and implement 

BACT. 

Georgia  2007 

Multi­pollutant Control for EGUs (steam) requires four specific power plants to carry out feasibility 

studies for mercury controls by 2018.  

Mercury emissions from new EGUs require the use of BACT to control mercury emissions. 

Wisconsin  2008 

Requires large (>150 MW) coal­fired power plants to either – a) achieve a 90 percent reduction in mercury 

emissions from coal by the year 2015; or b) reduce multiple pollutants, including nitrogen oxides (NOx) 

and sulfur dioxide (SO2), and achieve 90 percent reduction in mercury emissions six years later 

Requires small (> 25 MW and < 150 MW) coal­fired power plants reduce their mercury emissions to 

BACT level. 

South Carolina  2008  Requires power plants to install mercury emission monitoring equipment by June 2009. 

Michigan  2009  Requires EGUs to reduce mercury emissions by 90%, or achieve 75% mercury emission reductions along 

with nitrogen oxides (NOx) and sulfur dioxide (SO2) reductions. 

Oregon  2010 

Caps mercury emissions from new EGUs and requires installation of mercury controls at existing ones. 

Total statewide mercury emissions limited to 60 lb/year after 2018.  New coal plants cannot emit more 

than 25 lb/year. 

Source: Environmental Defense Fund, Mercury Alert: Cleaning up Coal Plants for Healthier Lives, March 2011.