Unit

Env

Do

EP

U

ted States 

vironmental P

ocum

PA Ba

pdate

Protection A

entati

ase Ca

s for P

i

Agency 

Air

(62

ion Su

ase v4

Propo

r and Radiati

204J) 

upplem

4.10_P

osed T

on Marc

ment f

PTox −

Toxics

h 2011 

for 

−

s Rule

 Documentation Supplement for 

EPA Base Case v4.10_PTox −

Updates for Proposed Toxics Rule

U.S. Environmental Protection Agency 

Clean Air Markets Division 

1200 Pennsylvania Avenue, NW (6204J) 

Washington, D.C. 20460 

(www.epa.gov/airmarkets) 

March 2011 

 

1

This report documents enhancements and updates that were made in EPA Base Case v4.10_PTox 

Mar20111 to provide capabilities required to perform modeling for the Proposed Toxics Rule. 

Specifically, the capability to model HCl emissions and controls was added. Existing coal units were 

given the option to burn natural gas by investing in a coal-to-gas retrofit. The cost and performance 

assumptions were updated for Activated Carbon Injection (ACI), the emission control particularly 

designated for mercury emission reductions. In addition, updates were made to the tables of state 

regulations and NSR and state settlements to reflect changes that had occurred since the previous 

base case 

The current report takes the form of a supplement to the documentation report “Documentation for EPA 

Base Case v4.10 Using the Integrated Planning Model” (August 2010) that can be found on the web at 

www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html. Exhibit 1 contains an abbreviated 

version of the table of contents of the v4.10 Documentation. Additions and changes found in this 

Documentation Supplement are shown in red. 

 

 

1

 EPA Base Case v4.10_PTox Mar2011 refers to EPA’s application of the Integrated Planning Model 

(IPM) of the U.S. power sector that was developed and used in analysis of the Proposed Toxics Rule. 

For brevity it is often referred to as v4.10_PTox in subsequent pages of this documentation supplement. 

IPM® is a registered trademark of ICF International. 
2

Exhibit 1: Abbreviated table of contents for EPA Base Case v4.10 showing (in red) additions and 

changes covered in this Documentation Supplement 

1 INTRODUCTION 

2 MODELING FRAMEWORK 

3 POWER SYSTEM OPERATION ASSUMPTIONS 

Appendix 3-2 State Power Sector Regulations 

Appendix 3-3 New Source Review (NSR) Settlements 

Appendix 3-4 State Settlements 

4 GENERATING RESOURCES 

5 EMISSION CONTROL TECHNOLOGIES 

 ● ● ●

5.3 COAL-TO-GAS CONVERSIONS 

5.3.1 Boiler Modifications for Coal-to-Gas Conversions 

5.3.2 Natural Gas Pipeline Requirements for Coal-to-Gas Conversions

 ● ● ●

5.4 MERCURY CONTROL TECHNOLOGIES 

 ● ● ● 

5.4.3 Mercury Control Capabilities 

Mercury Control through SO2 and NOX Retrofits 

Activated Carbon Injection (ACI) Í Replaced based on current engineering assessment 

5.5 Hydrogen Chloride (HCl) Control Technologies 

5.5.1 Chlorine Content of Fuels 

5.5.2 HCl Removal Rate Assumptions for Existing and Potential Units 

5.5.3 HCl Retrofit Emission Control Options 

5.5.3.1 Dry and Wet FGD 

5.5.3.2 Dry Sorbent Injection 

5.5.4 Fabric Filter (Baghouse) Cost Development 

 ● ● ●

Appendix 5-3 Example Cost Calculation Worksheets for 3 ACI Options

Appendix 5-4 Example Cost Calculation Worksheets for DSI 

Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filter (Baghouse) 

6 CO2 CAPTURE, TRANSPORT, AND STORAGE 

7 SET-UP PARAMETERS AND RULES 

8 FINANCIAL ASSUMPTIONS 

9 COAL 

9.1 COAL MARKET REPRESENTATION IN EPA BASE CASE V4.10 

● ● ●

9.1.3 Coal Quality Characteristics 

9.1.4 Emission Factors 

● ● ●

10 NATURAL GAS 

11 OTHER FUELS AND FUEL EMISSION FACTOR ASSUMPTIONS 

 

ے

ۑ

ۑ

ۑ

ۑ

ۑ

ۑ

ې

ÍNew HCl modeling 

቏ Í Updated

቏ Í New fuel retrofit option

൨ Í Enhanced to include HCl content of coals
3

Documentation Supplement to Chapter 3 (“Power System Operation Assumptions”)

The tables of State Power Sector Regulations (Appendix 3-2), New Source Review Settlements (Appendix 

3-3), and State Settlements (Appendix 3-4) were updated to reflect changes that had occurred since the 

provisions had been incorporated in EPA Base Case v4.10. The updated tables are included below. 

************************************************************************************************************* 

Appendix 3-2 State Power Sector Regulations included in EPA Base Case v4.10_PTox, Mar2011 

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Alabama 

Alabama 

Administrative Code 

Chapter 335-3-8 

NOx

0.02 lbs/MMBtu annual PPMDV for combined cycle 

EGUs which commenced operation after April 1, 

2003 

2003 

Arizona Title 18, Chapter 2, 

Article 7 Hg 

90% removal of Hg content of fuel or 0.0087 

lb/GWH-hr annual reduction for all non-cogen coal 

units > 25 MW 

2017 

California CA Reclaim Market 

NOx

9.68 MTons annual cap for list of entities in 

Appendix A of "Annual RECLAIM Audit Market 

Report for the Compliance Year 2005" (304 entities) 1994 

SO2

4.292 MTons annual cap for list of entities in 

Appendix A of "Annual RECLAIM Audit Market 

Report for the Compliance Year 2005" (304 entities) 

Colorado 40 C.F.R. Part 60 Hg 

2012 & 2013: 80% reduction of Hg content of fuel or 

0.0174 lb/GW-hr annual reduction for Pawnee 

Station 1 and Rawhide Station 101 

2014 through 2016: 80% reduction of Hg content of 

fuel or 0.0174 lb/GW-hr annual reduction for all coal 

units > 25 MW 

2017 onwards: 90% reduction of Hg content of fuel 

or 0.0087 lb/GW-hr annual reduction for all coal 

units > 25 MW 

2012 

Connecticut 

Executive Order 19 

and Regulations of 

Connecticut State 

Agencies (RCSA) 

22a-174-22 

NOx

0.15 lbs/MMBtu rate limit in the winter season for all 

fossil units > 15 MW 

2003 

Executive Order 19, 

RCSA 22a-198 & 

Connecticut General 

Statues (CGS) 22a198 

SO2

0.33 lbs/MMBtu annual rate limit for all Title IV 

sources > 15 MW 

0.55 lbs/MMBtu annual rate limit for all non-Title IV 

sources > 15 MW 

Public Act No. 03-72 

& RCSA 22a-198 Hg 90% removal of Hg content of fuel or 0.0087 lb/GWhr annual reduction for all coal-fired units 2008 

Delaware 

Regulation 1148: 

Control of Stationary 

Combustion Turbine 

EGU Emissions 

NOx

0.19 lbs/MMBtu ozone season PPMDV for 

stationary, liquid fuel fired CT EGUs >1 MW 

0.39 lbs/MMBtu ozone season PPMDV for 

stationary, gas fuel fired CT EGUs >1 MW 

2009 

Regulation No. 1146: 

Electric Generating 

Unit (EGU) MultiPollutant Regulation 

NOx

0.125 lbs/MMBtu rate limit of NOx annually for all 

coal and residual-oil fired units > 25 MW 

2009 

SO2

0.26 lbs/MMBtu annual rate limit for coal and 

residual-oil fired units > 25 MW 
4

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Hg 

2012: 80% removal of Hg content of fuel or 0.0174 

lb/GW-hr annual reduction for all coal units > 25 MW 

2013 onwards: 90% removal of Hg content of fuel or 

0.0087 lb/GW-hr annual reduction for all coal units > 

25 MW 

Georgia 

Multipollutant Control 

for Electric Utility 

Steam Generating 

Units 

SCR, FGD, 

and 

Sorbent 

Injection 

Baghouse 

controls to 

be installed 

The following plants must install controls: Bowen, 

Branch, Hammond, McDonough, Scherer, Wansley, 

and Yates 

Implementation 

from 2008 

through 2015, 

depending on 

plant and control 

type 

Illinois 

Title 35, Section 

217.706 NOx

0.25 lbs/MMBtu summer season rate limit for all 

fossil units > 25 MW 2004 

Title 35, Part 225, 

Subpart B: Control of 

Hg Emissions from 

Coal Fired Electric 

Generation Units 

NOx

0.11 lbs/MMBtu annual rate limit and ozone season 

rate limit for all Dynergy and Ameren coal steam 

units > 25 MW 

2012 

SO2

2013 & 2014: 0.33 lbs/MMBtu annual rate limit for all 

Dynergy and Ameren coal steam units > 25 MW 

2015 onwards: 0.25 lbs/MMBtu annual rate limit for 

all Dynergy and Ameren coal steam units > 25 MW 

2013 

Hg 

90% removal of Hg content of fuel or 0.08 lbs/GW-hr 

annual reduction for all Ameren and Dynergy coal 

units > 25 MW 

2015 

Title 35 Part 225; 

Subpart F: Combined 

Pollutant Standards 

NOx

0.11 lbs/MMBtu ozone season and annual rate limit 

for all specified Midwest Gen coal steam units 2012 

SO2

0.44 lbs/MMBtu annual rate limit in 2013, decreasing 

annually to 0.11 lbs/MMBtu in 2019 for all specified 

Midwest Gen coal steam units 

2013 

Hg 

90% removal of Hg content of fuel or 0.08 lbs/GWh 

annual reduction for all specified Midwest Gen coal 

steam units 

2015 

Kansas 

NOx Emission 

Reduction Rule, 

K.A.R. 28-19-713a. 

NOx

0.20 lbs/MMBtu annual rate limit for Quindaro Unit 2 

and 0.26 lbs/MMBtu annual rate limit for Nearman 

Unit 1. 

2012 

Louisiana 

Title 33 Part III - 

Chapter 22, Control of 

Emissions of Nitrogen 

Oxides 

SO2

1.2 lbs/MMBtu ozone season PPMDV for all single 

point sources that emit or have the potential to emit 

5 tons or more of SO2 into the atmosphere 

2005 

Title 33 Part III - 

Chapter 15, Emission 

Standards for Sulfur 

Dioxide 

NOx

Various annual rate limits depending on plant and 

fuel type for facilities within the Baton Rouge 

Nonattainment Area that collectively have the 

potential to emit 25 tons or more per year of NOx or 

facilities within the Region of Influence that 

collectively have the potential to emit 50 tons or 

more per year of NOx 

2005 

Maine 

Chapter 145 NOx

Control Program NOx

0.22 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW built before 1995 with a heat input 

capacity < 750 MMBtu/hr 

0.15 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW built before 1995 with a heat input 

capacity > 750 MMBtu/hr 

0.20 lbs/MMBtu annual rate limit for all fossil fuel 

fired indirect heat exchangers, primary boilers, and 

resource recovery units with heat input capacity > 

250 MMBtu/hr 

2005 

Statue 585-B Title 38, 

Chapter 4: Protection 

and Improvement of 

Air 

Hg 25 lbs annual cap for any facility including EGUs 2010 
5

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Maryland Maryland Healthy Air 

Act 

NOx

3.6 MTons summer cap and 8.3 MTons annual cap 

for Mirant coal units 

0.5 MTons summer cap and 1.4 MTons annual cap 

for Allegheny coal units 

3.6 MTons summer cap and 8.03 MTons annual cap 

for Constellation coal units. 

SO2 2009 

2009 through 2012: 23.4 MTons annual cap for 

Constellation coal units, 24.2 MTons annual cap for 

Mirant Coal units, and 4.6 MTons annual cap for 

Allegheny coal units. 

2013 onwards: 17.9 MTons annual cap for 

Constellation coal units, 18.5 MTons annual cap for 

Mirant Coal units, and 4.6 MTons annual cap for 

Allegheny coal units. 

Hg 

2010 through 2012: 80% removal of Hg content of 

fuel for Mirant, Allegheny, and Constellation coal 

steam units 

2013 onwards: 90% removal of Hg content of fuel 

for Mirant, Allegheny, and Constellation coal steam 

units 

Massachusett

s 310 CMR 7.29 

NOx

1.5 lbs/MWh annual GPS for Bayton Point, Mystic 

Generating Station, Somerset Station, Mount Tom, 

Canal, and Salem Harbor 

2006 

SO2

3.0 lbs/MWh annual GPS for Bayton Point, Mystic 

Generating Station, Somerset Station, Mount Tom, 

Canal, and Salem Harbor 

Hg 

2012: 85% removal of Hg content of fuel or 

0.00000625 lbs/MWh annual GPS for Brayton Point, 

Mystic Generating Station, Somerset Station, Mount 

Tom, Canal, and Salem Harbor 

2013 onwards: 95% removal of Hg content of fuel or 

0.00000250 lbs/MWh annual GPS for Brayton Point, 

Mystic Generating Station, Somerset Station, Mount 

Tom, Canal, and Salem Harbor 

Michigan 

Part 15. Emission 

Limitations and 

Prohibitions - Mercury 

Hg 90% removal of Hg content of fuel annually for all 

coal units > 25 MW 2015 

Minnesota 

Minnesota Hg 

Emission Reduction 

Act 

Hg 90% removal of Hg content of fuel annually for all 

coal units > 250 MW 2008 

Missouri 10 CSR 10-6.350 NOx

0.25 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW in the following counties: Bollinger, 

Butler, Cape Girardeau, Carter, Clark, Crawford, 

Dent, Dunklin, Gasconade, Iron, Lewis, Lincoln, 

Madison, Marion, Mississippi, Montgomery, New 

Madrid, Oregon, Pemiscot, Perry, Phelps, Pike, 

Ralls, Reynolds, Ripley, St. Charles, St. Francois, 

Ste. Genevieve, Scott, Shannon, Stoddard, Warren, 

Washington and Wayne 

0.18 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW the following counties: City of St. 

Louis, Franklin, Jefferson, and St. Louis 

0.35 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW in the following counties: Buchanan, 

Jackson, Jasper, Randolph, and any other county 

not listed 

2004 

Montana 

Montana Mercury 

Rule Adopted 

10/16/06 

Hg 

0.90 lbs/TBtu annual rate limit for all non-lignite coal 

units 

1.50 lbs/TBtu annual rate limit for all lignite coal 

units 

2010 

New 

Hampshire RSA 125-O: 11-18 Hg 

80% reduction of aggregated Hg content of the coal 

burned at the facilities for Merrimack Units 1 & 2 and 

Schiller Units 4, 5, & 6 

2012 
6

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

ENV-A2900 Multiple 

pollutant annual 

budget trading and 

banking program 

NOx

2.90 MTons summer cap for all fossil steam units > 

250 MMBtu/hr operated at any time in 1990 and all 

new units > 15 MW 

3.64 MTons annual cap for Merrimack 1 & 2, 

Newington 1, and Schiller 4 through 6 

2007 

SO2

7.29 MTons annual cap for Merrimack 1 & 2, 

Newington 1, and Schiller 4 through 6 

New Jersey 

N.J.A.C. 7:27-27.5, 

27.6, 27.7, and 27.8 Hg 

90% removal of Hg content of fuel annually for all 

coal-fired units 

95% removal of Hg content of fuel annually for all 

MSW incinerator units 

2007 

N.J. A. C. Title 7, 

Chapter 27, 

Subchapter 19, Table 

1 

NOx

2009 - 2012 annual rate limits in lbs/MMBtu for the 

following technologies: 

Coal Boilers (Wet Bottom) - 1.0 for tangential and 

wall-fired, 0.60 for cyclone-fired 

Coal Boilers (Dry Bottom) - 0.38 for tangential, 0.45 

for wall-fired, 0.55 for cyclone-fired 

Oil and/or Gas or Gas only: 0.20 for tangential, 0.28 

for wall-fired, 0.43 for cyclone-fired 

2013 & 2014 annual rate limits in lbs/MWh for the 

following technologies: 

All Coal Boilers: 1.50 for all 

Oil and/or Gas: 2.0 for tangential, 2.80 for wall-fired, 

4.30 for cyclone-fired 

Gas only: 2.0 for tangential and wall-fired, 4.30 for 

cyclone-fired 

2015 onward annual rate limits in lbs/MWh for the 

following technologies: 

All Coal Boilers: 1.50 for all 

Oil and/or Gas: 2.0 for fuel heavier than No. 2 fuel 

oil, 1.0 for No. 2 and lighter fuel oil 

Gas only: 1.0 for all 

2009 

N.J. A. C. Title 7, 

Chapter 27, 

Subchapter 19, Table 

4 

NOx

2.2 lbs/MWh annual GPS for gas-burning simple 

cycle combustion turbine units 

3.0 lbs/MWh annual GPS for oil-burning simple 

cycle combustion turbine units 

1.3 lbs/MWh annual GPS for gas-burning combined 

cycle CT or regenerative cycle CT units 

2.0 lbs/MWh annual GPS for oil-burning combined 

cycle CT or regenerative cycle CT units 

2007 

New York 

Part 237 NOx

39.91 MTons non-ozone season cap for fossil fuel 

units > 25 MW 2004 

Part 238 SO2

131.36 MTons annual cap for fossil fuel units > 25 

MW 2005 

Mercury Reduction 

Program for CoalFired Electric Utility 

Steam Generating 

Units 

Hg 

786 lbs annual cap through 2014 for all coal fired 

boiler or CT units >25 MW after Nov. 15, 1990. 

0.60 lbs/TBtu annual rate limit for all coal units > 25 

MW developed after Nov.15 1990 

2010 

North Carolina 

NC Clean 

Smokestacks Act: 

Statute 143-215.107D 

NOx

25 MTons annual cap for Progress Energy coal 

plants > 25 MW and 31 MTons annual cap for Duke 

Energy coal plants > 25 MW 

2007 

SO2

2012: 100 MTons annual cap for Progress Energy 

coal plants > 25 MW and 150 MTons annual cap for 

Duke Energy coal plants > 25 MW 

2013 onwards: 50 MTons annual cap for Progress 

Energy coal plants > 25 MW and 80 MTons annual 

cap for Duke Energy coal plants > 25 MW 

2009 

Oregon 

Oregon Administrative 

Rules, Chapter 345, 

Division 24 

CO2

675 lbs/MWh annual rate limit for new combustion 

turbines burning natural gas with a CF >75% and all 

new non-base load plants (with a CE <= 75%) 

emitting CO2

1997 
7

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Oregon Utility 

Mercury Rule - 

Existing Units 

Hg 90% removal of Hg content of fuel reduction or 0.6 

lbs/TBtu limitation for all existing coal units >25 MW 2012 

Oregon Utility 

Mercury Rule - 

Potential Units 

Hg 25 lbs rate limit for all potential coal units > 25 MW 2009 

Pacific 

Northwest 

Washington State 

House Bill 3141 CO2

$1.45/Mton cost (2004$) for all new fossil-fuel power 

plant 2004 

Texas 

Senate Bill 7 Chapter 

101 

SO2

273.95 MTons cap of SO2 for all grandfathered units 

built before 1971 in East Texas Region 

2003 

NOx

Annual cap for all grandfathered units built before 

1971 in MTons: 84.48 in East Texas, 18.10 in West 

Texas, 1.06 in El Paso Region 

Chapter 117 NOx

East and Central Texas annual rate limits in 

lbs/MMBtu for units that came online before 1996: 

Gas fired units: 0.14 

Coal fired units: 0.165 

Stationary gas turbines: 0.14 

2007 

Dallas/Fort Worth Area annual rate limit for utility 

boilers, auxiliary steam boilers, stationary gas 

turbines, and duct burners used in an electric power 

generating system except for CT and CC units 

online after 1992: 

0.033 lbs/MMBtu or 0.50 lbs/MWh output or 0.0033 

lbs/MMBtu on system wide heat input weighted 

average for large utility systems 

0.06 lbs/MMBtu for small utility systems 

Houston/Galveston region annual Cap and Trade 

(MECT) for all fossil units: 

17.57 MTons 

Beaumont-Port Arthur region annual rate limits for 

utility boilers, auxiliary steam boilers, stationary gas 

turbines, and duct burners used in an electric power 

generating system: 0.10 lbs/MMBtu 

Utah 

R307-424 Permits: 

Mercury 

Requirements for 

Electric Generating 

Units 

Hg 90% removal of Hg content of fuel annually for all 

coal units > 25 MW 2013 

Wisconsin NR 428 Wisconsin 

Administration Code NOx

Annual rate limits in lbs/MMBtu for coal fired boilers 

> 1,000 MMBtu/hr : 

Wall fired, tangential fired, cyclone fired, and 

fluidized bed: 2009: 0.15, 2013 onwards: 0.10 

Arch fired: 2009 onwards: 0.18 

Annual rate limits in lbs/MMBtu for coal fired boilers 2009 

between 500 and 1,000 MMBtu/hr: 

Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 2013 

Tangential fired: 2009 onwards: 0.15 

Cyclone fired: 2009: 0.20; 2013 onwards: 0.15 

Fluidized bed: 2009: 0.15; 2013 onwards: 0.10 

Arch fired: 2009 onwards: 0.18 
8

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Annual rate limits for CTs in lbs/MMBtu: 

Natural gas CTs > 50 MW: 0.11 

Distillate oil CTs > 50 MW: 0.28 

Biologically derived fuel CTs > 50 MW: 0.15 

Natural gas CTs between 25 and 49 MW: 0.19 

Distillate oil CTs between 25 and 49 MW: 0.41 

Biologically derived fuel CTs between 25 and 49 

MW: 0.15 

Annual rate limits for CCs in lbs/MMBtu: 

Natural gas CCs > 25 MW: 0.04 

Distillate oil CCs > 25 MW: 0.18 

Biologically derived fuel CCs > 25 MWs: 0.15 

Natural gas CCs between 10 and 24 MW: 0.19 

Chapter NR 446. 

Control of Mercury 

Emissions 

Hg 

2012 through 2014: 40% reduction in total Hg 

emissions for all coal-fired units in electric utilities 

with annual Hg emissions > 100 lbs 

2015 onwards: 90% removal of Hg content of fuel or 

0.0080 lbs/GW-hr reduction in coal fired EGUs > 

150 MW 

80% removal of Hg content of fuel or 0.0080 

lbs/GW-hr reduction in coal fired EGUs > 25 MW 

2010 

 

Notes:

 

Updates to the EPA Base Case v4.10_PTox from EPA Base Case 4.10 include the following: 

1) An update of the modeling of SO2 rate limits in Connecticut 

2) An update of the modeling of the effective dates of various controls on units in Georgia 

3) Addition of two Kansas State Law unit-specific constraints 

4) An update of the modeling of NOx rate limits in Louisiana 

5) An update of the modeling of the NOx annual and summer caps and SO2 annual cap in Maryland 

6) An update of the modeling of the NOx rate limits in New Jersey 
9

Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v4.10_PTox, Mar2011 

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Alabama Power 

James H. 

Miller Alabama Units 3 & 4 

Install and 

operate 

FGD 

continuously 

95% 12/31/11 

Operate 

existing SCR 

continuously 

0.1 05/01/08 0.03 12/31/06 

With 45 days of settlement entry, APC must retire 7,538 SO2emission allowances. 

APC shall nosell, trade, or otherwise exchange anPlant Miller excess SO2emission allowances outside of the APC system 

Minnkota Power Cooperative Beginning 1/01/2006, Minnkota shall not emit more than 31,000 tons of SO2/year, no more than 26,000 tons beginning 2011, no more than 11,500 tons beginning 1/01/2012. If Unit 3 is not operational by 12/31/2015, then beginning 1/01/2014, the plant wid

Milton R. 

Young 

Minnesot

a 

Unit 1 

Install and 

continuously 

operate 

FGD 

95% if 

wet FGD, 

90% if dry 

12/31/11 

Install and 

continuously 

operate 

Over-fire 

AIR, or 

equivalent 

technology 

with 

emission 

rate < .36 

0.36 12/31/09 

0.03 if 

wet FGD, 

.015 if 

dry FGD 

Plant will surrender 4,346 allowances for each year 2012 – 2015, 8,693 allowances for years 2016 –2018, 12,170 allowances for year 2019, and 14,886 allowances/year thereafter if Units 1 – 3 are operational by 12/31/2015. If only Units 1 and 2 are operational by12/31/2015, the plant shall retire 17,886 units in 2020 and thereafter. 

Minnkota shanot sell or trade NOxallowances allocated to Units 1, 2, or that would otherwise be available for sale or trade as a result of the actions taken by the settling defendants to comply with the requirements 

Unit 2 

Design, 

upgrade, 

and 

continuously 

operate 

FGD 

90% 12/31/10 

Install and 

continuously 

operate 

over-fire 

AIR, or 

equivalent 

technology 

with 

emission 

rate < .36 

0.36 12/31/07 0.03 Before 2008 

SIGECO 

FB Culley Indiana 

Unit 1 

Repow

er to 

natural 

gas (or 

retire) 

12/31/06 

The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. 

Unit 2 

Improve and continuously 

operate existing 

FGD 

(shared by 

Units 2 and 

3) 

95% 06/30/04 

Unit 3 Improve and continuously 95% 06/30/04 Operate Existing 0.1 09/01/03 Install and continuously 0.015 06/30/07 
10

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

operate existing 

FGD 

(shared by 

Units 2 and 

3) 

SCR 

Continuously 

operate a 

Baghouse 

PSEG FOSSIL 

Bergen New Jersey Unit 2 

Repow

er to 

combin

ed 

cycle 

12/31/02 

The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. 

Hudson New Jersey Unit 2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/06 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 05/01/07 

Install 

Baghouse 

(or approved 

technology) 

0.015 12/31/06 

Mercer New Jersey Units 1 & 2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/10 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.13 05/01/06 

TECO 

Big Bend Florida 

Units 1 

& 2 

Existing 

Scrubber 

(shared by 

Units 1 & 2) 

95% 

(95% or 

.25) 

09/1/00 

(01/01/13) Install SCR 0.1 05/01/09 

The provision 

did not specify 

an amount of 

SO2 allowances 

to be 

surrendered. It 

only provided 

that excess 

allowances 

resulting from 

compliance with 

NSR settlement 

provisions must 

be retired. 

Unit 3 

Existing 

Scrubber 

(shared by 

Units 3 & 4) 

93% if 

Units 3 & 

4 are 

operating 

2000 

(01/01/10) Install SCR 0.1 05/01/09 

Unit 4 

Existing 

Scrubber 

(shared by 

Units 3 & 4) 

93% if 

Units 3 & 

4 are 

operating 

06/22/05 Install SCR 0.1 07/01/07 

Gannon Florida Six units 

Retire 

all six 

coal 

units 

and 

repow

er at 

least 

550 

MW of 

coal 

capacit

y to 

natural 

gas 

12/31/04 

WEPCO WEPCO shall comply with the following system wide average NOx emission rates and total NOx tonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and by 1/1/2013 an emissiotons. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an emission rate of 0
11

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Presque Isle Wisconsi n 

Units 1 

– 4 

Retire 

or 

install 

SO2

and 

NOx

control

s 

12/31/12 

Install and 

continuously 

operate 

FGD (or 

approved 

equiv. tech) 

95% or 

0.1 12/31/12 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 12/31/12 

The provision 

did not specify 

an amount of 

SO2 allowances 

to be 

surrendered. It 

only provided 

that excess 

allowances 

resulting from 

compliance with 

NSR settlement 

provisions must 

be retired. 

Units 5 

& 6 

Install and 

operate low 

NOx burners 

12/31/03 

Units 7 

& 8 

Operate 

existing low 

NOx burners 

12/31/05 Install Baghouse 

Unit 9 

Operate 

existing low 

NOx burners 

12/31/06 Install Baghouse 

Pleasant 

Prairie 

Wisconsi

n 

1 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/06 

Install and 

continuously 

operate SCR 

(or approved 

tech) 

0.1 12/31/06 

2 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/07 

Install and 

continuously 

operate SCR 

(or approved 

tech) 

0.1 12/31/03 

Oak Creek Wisconsi

n 

Units 5 

& 6 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/12 

Install and 

continuously 

operate SCR 

(or approved 

tech) 

0.1 12/31/12 

Unit 7 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/12 

Install and 

continuously 

operate SCR 

(or approved 

tech) 

0.1 12/31/12 

Unit 8 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/12 

Install and 

continuously 

operate SCR 

(or approved 

tech) 

0.1 12/31/12 

Port 

Washington 

Wisconsi

n 

Units 1 

– 4 Retire 

12/31/04 

for Units 1 

– 3. Unit 4 

by entry of 

consent 

decree 

Valley Wisconsi n Boilers 1 – 4 Operate existing low NOx burner 30 days after entry of consent decree 

VEPCO The Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 – 2010, 54,000 in 2011, 50,000 in 2012, and 30,250 each year thereafter. Beginnia system wide emission rate no greater than 0.15 lb/mmBtu. 
12

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Mount Storm West Virginia Units 1 – 3 Construct or improve FGD 95% or 0.15 01/01/05 Install and continuously operate SCR 0.11 01/01/08 

On or before 

March 31 of 

every year 

beginning in 

2013 and 

continuing thereafter, 

VEPCO shall 

surrender 

45,000 SO2

allowances. 

Chesterfield Virginia 

Unit 4 

Install and 

continuously 

operate SCR 

0.1 01/01/13 

Unit 5 

Construct or 

improve 

FGD 

95% or 

0.13 10/12/12 

Install and 

continuously 

operate SCR 

0.1 01/01/12 

Unit 6 

Construct or 

improve 

FGD 

95% or 

0.13 01/01/10 

Install and 

continuously 

operate SCR 

0.1 01/01/11 

Chesapeake 

Energy Virginia Units 3 & 4 Install and continuously operate SCR 0.1 01/01/13 

Clover Virginia Units 1 & 2 Improve FGD 95% or 0.13 09/01/03 

Possum 

Point Virginia Units 3 & 4 

Retire 

and 

repow

er to 

natural 

gas 

05/02/03 

Santee Cooper Santee Cooper shall comply with the following system wide averages for NOx emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000 tons, by 1/1/2007 an emission rate of 0.18 and 25,0emission rate of 0.15 and 20,000 tons. For SO2 emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85,000 tons, by 1/1/2009 an emission ratby 1/1/2011 and emission rate of 0.5 and 65 tons. 

Cross South Carolina 

Unit 1 

Upgrade 

and 

continuously 

operate 

FGD 

95% 06/30/06 

Install and 

continuously 

operate SCR 

0.1 05/31/04 

The provision 

did not specify 

an amount of 

SO2 allowances 

to be 

surrendered. It 

only provided 

that excess 

allowances 

resulting from 

compliance with 

NSR settlement 

provisions must 

be retired. 

Unit 2 

Upgrade 

and 

continuously 

operate 

FGD 

87% 06/30/06 

Install and 

Continuously operate SCR 

0.11/0.1 

05/31/04 

and 

05/31/07 

Winyah South Carolina 

Unit 1 

Install and 

continuously 

operate 

FGD 

95% 12/31/08 

Install and 

continuously 

operate SCR 

0.11/0.1 

11/30/04 

and 

11/30/04 

Unit 2 

Install and 

continuously 

operate 

FGD 

95% 12/31/08 

Install and 

continuously 

operate SCR 

0.12 11/30/04 

Unit 3 

Upgrade 

and 

continuously 

operate existing 

FGD 

90% 12/31/08 

Install and 

continuously 

operate SCR 

0.14/0.12 

11/30/2005 

and 

11/30/08 

Unit 4 

Upgrade 

and 

continuously 

operate existing 

FGD 

90% 12/31/07 

Install and 

continuously 

operate SCR 

0.13/0.12 

11/30/05 

and 

11/30/08 

Grainger South Carolina Unit 1 Operate low NOx burner 

or more 

06/25/04 
13

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

stringent 

technology 

Unit 2 

Operate low 

NOx burner 

or more 

stringent 

technology 

05/01/04 

Jeffries South Carolina Units 3, 4 

Operate low 

NOx burner 

or more 

stringent 

technology 

06/25/04 

Ohio Edison Ohio Edison shall achieve reductions of 2,483 tons NOx between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1 – 3 during the months of October thremitting fewer tons than the Plant-Wide Annual Cap for NOx required for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2 by 12/31/2010. No later than 8/11/2005, Ohio Edison shall install and operate low NOx burners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization with softwemissions from Sammis Units 1 – 5. 

W.H. 

Sammis 

Plant 

Ohio 

Unit 1 

Install 

Induct 

Scrubber (or 

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/mmBtu 

12/31/08 

Install SNCR

(or approved

alt. tech) & 

operate 

continuously 

0.25 10/31/07 

Beginning on 

1/1/2006, Ohio 

Edison may 

use, sell or 

transfer any 

restricted SO2

only to satisfy 

the Operational 

Needs at the 

Sammis, Burger 

and Mansfield 

Plant, or new 

units within the 

FirstEnergy 

System that 

comply with a 

96% removal for SO2. For 

calendar year 

2006 through 

2017, Ohio 

Edison may 

accumulate SO2

allowances for 

use at the 

Sammis, 

Burger, and 

Mansfield 

plants, or 

FirstEnergy 

units equipped 

with SO2

Emission 

Control 

Standards. 

Beginning in 

2018, Ohio 

Edison shall 

surrender 

unused 

restricted SO2

allowances. 

Unit 2 

Install 

Induct 

Scrubber (or 

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/mmBtu 

12/31/08 

Operate 

existing 

SNCR 

continuously 

0.25 02/15/06 

Unit 3 

Install 

Induct 

Scrubber (or 

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/mmBtu 

12/31/08 

Operate low 

NOx burners 

and overfire 

air by 

12/1/05; 

install SNCR(or approved

alt. tech) & 

operate 

continuously 

by 12/31/07 

0.25 

12/01/05 

and 

10/31/07 

Unit 4 

Install 

Induct 

Scrubber (or 

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/mmBtu 

06/30/09 

Install SNCR

(or approved

alt. tech) & 

operate 

continuously 

0.25 10/31/07 

Unit 5 

Install Flash 

Dryer 

Absorber 

or ECO2 (or 

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/mmBtu 

06/29/09 

Install SNCR

(or approved

alt. tech) & 

Operate 

Continuously 

0.29 03/31/08 
14

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

& 

operate 

continuously 

Unit 6 

Install FGD3

(or 

approved 

equiv. 

control tech) 

& 

operate 

continuously 

95% 

removal 

or 0.13 

lb/mmBtu 

06/30/11 

Install SNCR

(or approved

alt. tech) & 

operate 

continuously 

"Minimum 

Extent 

Practicabl

e" 

06/30/05 

Operate 

Existing 

ESP 

Continuously 

0.03 01/01/10 

Unit 7 

Install FGD 

(or 

approved 

equiv. 

control tech) 

& 

operate 

continuously 

95% 

removal 

or 0.13 

lb/mmBtu 

06/30/11 

Operate 

existing 

SNCR 

Continuously 

"Minimum 

Extent 

Practicabl

e" 

08/11/05 

Operate 

Existing 

ESP 

Continuously 

0.03 01/01/10 

Mansfield 

Plant 

Pennsylv

ania 

Unit 1 

Upgrade 

existing 

FGD 

95% 12/31/05 

Unit 2 

Upgrade 

existing 

FGD 

95% 12/31/06 

Unit 3 

Upgrade 

existing 

FGD 

95% 10/31/07 

Eastlake Ohio Unit 5 

Install low 

NOx

burners, 

over-fired 

air and 

SNCR & 

operate 

continuously 

"Minimize 

Emissions 

to the 

Extent 

Practicabl

e" 

12/31/06 

Burger Ohio 

Unit 4 Repow er with 

at least 

80% 

biomas

s fuel, 

up to 

20% 

low 

sulfur 

coal. 

12/31/11 

Unit 5 12/31/11 

MirantI1,6System-wide NOx Emission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NOx Emission Ozone Season Caps: 14,700 tons 2004; 13tons 2006; 10,190 tons 2007; 6,150 tons 2008 – 2009; 5,200 tons 2010 thereafter. Beginning on 5/1/2008, and continuing for each and every Ozone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Emission Rate of 0

Potomac 

River Plant Virginia 

Unit 1 Unit 2 Unit 3 

Install low 

NOx

burners (or 

more 

effective 

tech) & 

05/01/04 
15

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

operate 

continuously 

Unit 4 

Install low 

NOx

burners (or 

more 

effective 

tech) & 

operate 

continuously 

05/01/04 

Unit 5 

Install low 

NOx

burners (or 

more 

effective 

tech) & 

operate 

continuously 

05/01/04 

Morgantown 

Plant Maryland 

Unit 1 

Install SCR 

(or approved 

alt. tech) & 

operate 

continuously 

0.1 05/01/07 

Unit 2 

Install SCR 

(or approved 

alt. tech) & 

operate 

continuously 

0.1 05/01/08 

Chalk Point Maryland 

Unit 1 

Install and 

continuously 

operate 

FGD (or 

equiv. 

technology) 

95% 06/01/10 

For each year 

after Mirant 

commences 

FGD operation 

at Chalk Point, 

Mirant shall 

surrender the 

number of SO2

Allowances 

equal to the 

amount by 

which the SO2

Allowances 

allocated to the 

Units at the 

Chalk Point 

Plant are 

greater than the 

total amount of 

SO2 emissions 

allowed under 

this Section 

XVIII. 

Unit 2 

Install and 

continuously 

operate 

FGD (or 

equiv. 

technology) 

95% 06/01/10 

Illinois Power System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 tons 2011; 49,500 tons onward. 

Baldwin 

Illinois Units 1 & 2 

Install wet 

or dry FGD 

(or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

0.1 12/31/11 

Operate 

OFA & 

existing SCR 

continuously 

0.1 08/11/05 

Install & 

continuously 

operate 

Baghouse 

0.015 12/31/10 

By year end 

2008, Dynergy 

will surrender 

12,000 SO2

emission 

allowances, by 

year end 2009 it 

will surrender 
16

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Unit 3 

Install wet 

or dry FGD 

(or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

0.1 12/31/11 

Operate 

OFA and/or 

low NOx

burners 

0.12 until 

12/30/12; 

0.1 from 

12/31/12 

08/11/05 

and 

12/31/12 

Install & 

continuously 

operate 

Baghouse 

0.015 12/31/10 

18,000, by year 

end 2010 it will 

surrender 

24,000, any by 

year end 2011 

and each year 

thereafter it will 

surrender 

30,000 

allowances. If 

the surrendered 

allowances 

result in 

insufficient 

remaining 

allowances 

allocated to the 

units 

comprising the 

DMG system, 

DMG can 

request to 

surrender fewer 

SO2

allowances. 

Havana Illinois Unit 6 

Install wet 

or dry FGD 

(or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

1.2 

lb/mmBtu 

until 

12/30/201

2; 0.1 

lb/mmBtu 

from 

12/31/201

2 onward 

08/11/05 

and 

12/31/12 

Operate 

OFA and/or 

low NOx

burners & 

operate 

existing SCR 

continuously 

0.1 08/11/05 

Install & 

continuously 

operate 

Baghouse, then install ESP or alt. 

PM equip 

For Baghouse: 

0.015 

lb/mmBtu

; For 

ESP: 

0.03 

lb/mmBtu 

For 

Baghouse: 

12/31/12; 

For ESP: 

12/31/05 

Hennepin Illinois 

Unit 1 1.2 07/27/05 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum 

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/06 

Unit 2 1.2 07/27/05 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum 

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/06 

Vermilion Illinois Units 1 & 2 1.2 01/31/07 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum 

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/10 

Wood River Illinois Units 4 & 5 1.2 07/27/05 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum 

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/05 

Kentucky Utilities Company 

EW Brown 

Generating 

Station 

Kentucky Unit 3 Install FGD 97% or 0.100 12/31/10 

Install and 

continuously 

operate SCR 

by 

12/31/2012, 

continuously 

operate low 

NOx boiler 

and OFA. 

0.07 12/31/12 Continuously operate ESP 0.03 12/31/10 

KU must 

surrender 

53,000 SO2

allowances of 

2008 or earlier 

vintage by 

March 1, 2009. 

All surplus NOx

allowances 

must be 

surrendered 

through 2020. 

SO2 and NO

allowances 

may not be 

used for 

compliance

and emission

decreases fo

purposes o

complying w

the Consen

Decree do n

earn credits

Salt River Project Agricultural Improvement and Power District (SRP) 

Coronado 

Generating 

Station 

Arizona 

Unit 1 

or Unit 

2 

Immediately 

begin 

continuous 

operation of 

existing 

FGDs on 

both units, 

install new 

95% or 

0.08 

New FGD 

installed 

by 

1/1/2012 

Install and 

continuously 

operate low 

NOx burner 

and SCR 

0.32 prior 

to SCR 

installation

, 0.080 

after 

LNB by 

06/01/2009

, SCR by 

06/01/2014 

Optimization 

and 

continuous 

operation of 

existing 

ESPs. 

0.03 

Optimizatio

n begins 

immediately, rate limit 

begins 

01/01/12 

(date of 

new FGD 

Beginning in 

2012, all 

surplus SO2

allowances for 

both Coronado 

and 

Springerville 

Unit 4 must be 

SO2 and NO

allowances 

may not be 

used for 

compliance

and emission

decreases fo

purposes o
17

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

FGD. installation

) 

surrendered 

through 2020. 

The allowances 

limited by this 

condition may, 

however, be 

used for 

compliance at a 

prospective 

future plant 

using BACT 

and otherwise 

specified in par. 

54 of the 

consent decree. 

complying w

the Consen

Decree do n

earn credits

Unit 1 

or Unit 

2 

Install new 

FGD 

95% or 

0.08 01/01/13 

Install and 

continuously 

operate low 

NOx burner 

0.32 06/01/11 

Optimizatio

n begins 

immediately, rate limit 

begins 

01/01/13 

(date of 

new FGD 

installation

) 

American Electric Power 

Eastern System-Wide 

Annual 

Cap 

(tons) 

Year Annual Cap (tons) Year 

NOx and SO2

allowances that 

would have 

been made 

available by 

emission 

reductions 

pursuant to the 

Consent 

Decree must be 

surrendered. 

NOx and SO

allowances 

may not be 

used to comp

with any of th

limits impose

by the Conse

Decree. Th

Consent 

Decree 

includes a 

formula for 

calculating 

excess NO

allowances 

relative to th

CAIR 

Allocations

and restrict

the use of 

some. See p

74-79 for 

details. 

Reducing 

emissions 

below the 

Eastern 

System-Wid

Annual 

Tonnage 

Limitations f

NOx and SO

earns 

supercomplia

ce allowance

450,000 2010 96,000 2009 450,000 2011 92,500 2010 420,000 2012 92,500 2011 350,000 2013 85,000 2012 340,000 2014 85,000 2013 275,000 2015 85,000 2014 260,000 2016 75,000 2015 235,000 2017 72,000 2016 and thereafter 184,000 2018 174,000 

2019 and 

thereafter 

At least 

600MW from 

various units 

West 

Virginia 

Sporn 

1 – 4 

Retire, 

retrofit, 

or repower Virginia 12/31/18 

Clinch 

River 

1 – 3 

Indiana 

Tanner

s 

Creek 

1 – 3 
18

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

West 

Virginia 

Kamm

er 

1 – 3 

Amos West Virginia 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/09 

Install and 

continuously 

operate SCR 

01/01/08 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/10 

Install and 

continuously 

operate SCR 

01/01/09 

Unit 3 

Install and 

continuously 

operate 

FGD 

12/31/09 

Install and 

continuously 

operate SCR 

01/01/08 

Big Sandy Kentucky 

Unit 1 

Burn only 

coal with no 

more than 

1.75 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/15 

Install and 

continuously 

operate SCR 

01/01/09 

Cardinal Ohio 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/08 

Install and 

continuously 

operate SCR 

01/01/09 Continuously operate ESP 0.03 12/31/09 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/08 

Install and 

continuously 

operate SCR 

01/01/09 Continuously operate ESP 0.03 12/31/09 

Unit 3 

Install and 

continuously 

operate 

FGD 

12/31/12 

Install and 

continuously 

operate SCR 

01/01/09 

Clinch River Virginia Units 1 – 3 

Plantwide 

annual 

cap: 

21,700 

tons from 

2010 to 

2014, 

then 

16,300 

after 

1/1/2015 

2010 –

2014, 

2015 and 

thereafter 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Conesville Ohio 

Unit 1 

Retire, 

retrofit, 

or repower 

Date of 

entry 

Unit 2 

Retire, 

retrofit, 

or repower 

Date of 

entry 

Unit 3 

Retire, 

retrofit, 

or repower 

12/31/12 

Unit 4 

Install and 

continuously 

operate 

12/31/10 

Install and 

continuously 

operate SCR 

12/31/10 
19

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

FGD 

Unit 5 

Upgrade 

existing 

FGD 

95% 12/31/09 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Unit 6 

Upgrade 

existing 

FGD 

95% 12/31/09 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Gavin Ohio 

Unit 1 

Install and 

continuously 

operate 

FGD 

Date of 

entry 

Install and 

continuously 

operate SCR 

01/01/09 

Unit 2 

Install and 

continuously 

operate 

FGD 

Date of 

entry 

Install and 

continuously 

operate SCR 

01/01/09 

Glen Lyn Virginia 

Units 

1 – 3 

Units 

5, 6 

Burn only 

coal with no 

more than 

1.75 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Kammer West Virginia Units 1 – 3 

Plantwide 

annual 

cap: 

35,000 

01/01/10 

Continuously 

operate 

over-fire air 

Date of 

entry 

Kanawha 

River 

West 

Virginia 

Units 

1, 2 

Burn only 

coal with no 

more than 

1.75 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Mitchell West Virginia 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/07 

Install and 

continuously 

operate SCR 

01/01/09 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/07 

Install and 

continuously 

operate SCR 

01/01/09 

Mountaineer West Virginia Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/07 

Install and 

continuously 

operate SCR 

01/01/08 

Muskingum 

River Ohio 

Units 

1 – 4 

Retire, 

retrofit, 

or repower 

12/31/15 

Unit 5 

Install and 

continuously 

operate 

FGD 

12/31/15 

Install and 

continuously 

operate SCR 

01/01/08 Continuously operate ESP 0.03 12/31/02 

Picway Ohio Unit 9 

Continuously 

operate low 

NOx burners 

Date of 

entry 
20

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Rockport Indiana 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/17 

Install and 

continuously 

operate SCR 

12/31/17 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/19 

Install and 

continuously 

operate SCR 

12/31/19 

Sporn West Virginia Unit 5 

Retire, 

retrofit, 

or repower 

12/31/13 

Tanners 

Creek Indiana 

Units 

1 – 3 

Burn only 

coal with no 

more than 

1.2 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuously 

operate low 

NOx burners 

Date of 

entry 

Unit 4 

Burn only 

coal with no 

more than 

1.2% sulfur 

content 

annual 

average 

Date of 

entry 

Continuously 

operate 

over-fire air 

Date of 

entry 

East Kentucky Power Cooperative Inc. By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOx controls at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012. 

System-wide 

Systemwide 12-

month 

rolling 

tonnage 

limits apply 

12-month 

rolling 

limit 

(tons) 

Start of 

12-month 

cycle 

All units 

must 

operate low 

NOx boilers 

12-month 

rolling limit 

(tons) 

Start of 12-

month 

cycle 

PM control 

devices 

must be 

operated 

continuously 

systemwide, ESPs 

must be 

optimized 

within 270 

days of entry 

date, or 

EKPC may 

choose to 

submit a PM 

Pollution 

Control 

Upgrade 

Analysis. 

0.03 

1 year 

from entry 

date 

All surplus SO2

allowances 

must be 

surrendered 

each year, 

beginning in 

2008. 

SO2 and NO

allowances 

may not be 

used to comp

with the 

Consent 

Decree. NO

allowances 

that would 

become 

available as 

result of 

compliance 

with the 

Consent 

Decree ma

not be sold o

traded. SO

and NOx

allowances 

allocated to 

EKPC must 

used within t

EKPC system

Allowances 

made availab

due to 

supercomplia

ce may be so

or traded. 

57,000 10/01/08 11,500 01/01/08 40,000 07/01/11 8,500 01/01/13 28,000 01/01/13 8,000 01/01/15 
21

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Spurlock Kentucky 

Unit 1 

Install and 

continuously 

operate 

FGD 

95% or 

0.1 6/30/2011 Continuously operate SCR 

0.12 for 

Unit 1 until 

01/01/201

3, at 

which 

point the 

unit limit 

drops to 

0.1. Prior 

to 

01/01/201

3, the 

combined 

average 

when both 

units are 

operating 

must be 

no more 

than 0.1 

60 days 

after entry 

Unit 2 

Install and 

continuously 

operate 

FGD by 

10/1/2008 

95% or 

0.1 1/1/2009 

Continuously operate SCR 

and OFA 

0.1 for 

Unit 2, 0.1 

combined 

average 

when both 

units are 

operating 

60 days 

after entry 

Dale Plant Kentucky 

Unit 1 

Install and 

continuously 

operate low 

NOx burners 

by 

10/31/2007 

0.46 01/01/08 

EKPC must 

surrender 1,000 

NOx allowances 

immediately 

under the ARP, 

and 3,107 

under the NOx

SIP Call. EKPC 

must also surrender 

15,311 SO2

allowances. 

Unit 2 

Install and 

continuously 

operate low 

NOx burners 

by 

10/31/2007 

0.46 01/01/08 

Unit 3 

EKPC 

may 

choose 

to 

retire 

Dale 3 

and 4 

in lieu 

of 

installi

ng 

control

s in 

Coope

r 2 

12/31/2012 

Unit 4 

Cooper Kentucky 

Unit 1 Unit 2 

If EKPC 

opts to 

install 

controls 

rather than 

retiring 

Dale, it must 

95% or 

0.10 

If EKPC 

elects to 

install 

controls, it 

must 

continuously 

operate SCR 

0.08 (or 

90% if 

non-SCR 

technolog

y is used) 

12/31/12 
22

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

install and 

continuously 

operate 

FGD or 

equiv. 

technology 

or install 

equiv. 

technology 

Nevada Power Company Beginning 1/1/2010, combined NOx emissions from Units 5,6,7, and 8 must be no more than 360 tons per year. 

Clark 

Generating 

Station 

Nevada 

Unit 5 

Units 

may 

only 

fire 

natural 

gas 

Increase 

water 

injection 

immediately, 

then install 

and operate 

ultra-low 

NOx burners 

(ULNBs) or 

equivalent 

technology. 

In 2009, 

Units 5 and 

8 may not 

emit more 

than 180 

tons 

combined 

5ppm 1-

hour 

average 

12/31/08 

(ULNB 

installation

), 01/30/09 

(1-hour 

average) Allowances 

may not be 

used to comp

with the 

Consent 

Decree, and 

no allowance

made availab

due to 

compliance 

with the 

Consent 

Decree may 

traded or sol

Unit 6 

5ppm 1-

hour 

average 

12/31/09 

(ULNB 

installation

), 01/30/10 

(1-hour 

average) 

Unit 7 

5ppm 1-

hour 

average 

12/31/09 

(ULNB 

installation

), 01/30/10 

(1-hour 

average) 

Unit 8 

5ppm 1-

hour 

average 

12/31/08 

(ULNB 

installation

), 01/30/09 

(1-hour 

average) 

Dayton Power & Light Non-EPA Settlement of 10/23/2008 

Stuart 

Generating 

Station 

Ohio Station -wide 

Complete 

installation 

of FGDs on 

each unit. 

96% or 

0.10 07/31/09 

Owners may 

not purchase 

any new 

catalyst with 

SO2 to SO3

conversion 

rate greater 

than 0.5% 

0.17 

stationwide 30 days after entry 0.030 lb 

per unit 07/31/09 

NOx and SO

allowances 

may not be 

used to comp

with the 

monthly rate

specified in t

Consent 

Decree. 

0.17 

stationwide 

60 days 

after entry 

date 

82% 

including 

data from 

periods of 

malfuncti

ons 

7/31/09 

through 

7/30/11 

Install 

control 

technology 

on one unit 

0.10 on 

any single 

unit 

12/31/12 Install 

rigid-type 

electrodes in 

each 

unit's 

ESP 

12/31/15 82% 

including 

data from 

periods of 

malfuncti

ons 

after 

7/31/11 

0.15 

stationwide 07/01/12 

0.10 

stationwide 12/31/14 

PSEG FOSSIL, Amended Consent Decree of November 2006 
23

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

Kearny New Jersey 

Unit 7 Retire unit 01/01/07 

Allowances 

allocated to 

Kearny, 

Hudson, and 

Mercer may 

only be used for 

the operational 

needs of those 

units, and all 

surplus 

allowances 

must be 

surrendered. 

Within 90 days 

of amended 

Consent 

Decree, PSEG 

must surrender 

1,230 NOx

Allowances and 

8,568 SO2

Allowances not 

already 

allocated to or 

generated by 

the units listed 

here. Kearny 

allowances 

must be 

surrendered 

with the 

shutdown of 

those units. 

Unit 8 Retire unit 01/01/07 

Hudson New Jersey Unit 2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/10 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 12/31/10 

Install 

Baghouse 

(or approved 

technology) 

0.015 12/31/10 

Annual 

Cap 

(tons) 

Year Annual Cap (tons) Year 

5,547 2007 3,486 2007 5,270 2008 3,486 2008 5,270 2009 3,486 2009 5,270 2010 3,486 2010 

Mercer New Jersey Units 1 &2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/10 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 01/01/07 

Install 

Baghouse 

(or approved 

technology) 

0.015 12/31/10 

Westar Energy 

Jeffrey 

Energy 

Center 

Kansas All units 

Units 1, 2, and 3 have a total annual limit of 6,600 tons of SO2 and an annual rate limit of 0.07 lbs/MMBtu starting 2012 Units 1, 2, and 3 must all install FGDs by 2011 and operate them continuously. FGDs must maintain a 30-Day Rolling Average Unit Removal Efficiency for SO2 of at least 97% or a 30-Day Rolling Average Unit Emission Rate for SO2 of no greater than 0.070 lb/MMBtu. 

Units 1-3 must continuously operate Low NOx Combustion Systems by 2012 and achieve and maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.180 lb/MMBtu. One of the three units must install an SCR by 2015 and operate it continuously to maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.080 lb/MMBtu. By 2013 Westar shall elect to either (a) install a second SCR on one of the other JEC Units by 2017 or (b) meet a 0.100 lb/MMBtu Plant-Wide 12-Month Rolling Average Emission Rate and 9.6 MTons annual cap for NOx by 2015 

Units 1, 2, and 3 must operate each ESP and FGD system continuously by 2011 and maintain a 0.030 lb/MMBtu PM Emissions Rate. Units 1 and 2’s ESPs must be rebuilt by 2014 in order to meet a 0.030 lb/MMBtu PM Emissions Rate 

Duke Energy 

Gallagher Indiana 

Units 1 

& 3 

Retire 

or 

repow

er as 

natural 

gas 

1/1/2012 

Units 2 

& 4 

Install Dry 

sorbent 

injection 

technology 

80% 1/1/2012 
24

Company 

and Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allowance Restriction 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restriction 

American Municipal Power 

Gorsuch 

Station Ohio 

Units 2 

& 3 Elected to Retire Dec 

15, 2010 (must retire 

by Dec 31, 2012) 

Units 1 

& 4 

Hoosier Energy Rural Electric Cooperative 

Ratts Indiana Units 1 & 2 

Install & 

continually 

operate 

SNCRS 

0.25 12/31/2011 Continuously operate ESP 

Annually surrender any NOx a

Hoosier does not need in orde

obligation

Merom Indiana 

Unit 1 

Continusly 

run current 

FGD for 

90% 

removal and 

update FGD 

for 98% 

removal by 

2012 

98% 2012 

Continuously 

operate existing 

SCRs 

0.12 

Continuously operate ESP and achieve PM 

rate no greater than 0.007 by 6/1/12 

Unit 2 

Continusly 

run current 

FGD for 

90% 

removal and 

update FGD 

for 98% 

removal by 

2014 

98% 2014 Continuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/13 

Notes:1) Updates to the EPA Base Case v4.10_PTox from EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the control requirements on the Mercto the SO2 emission modeling on Jeffrey Energy Center as part of the Westar settlement. 2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description of a3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, future actions are generally modeled Case, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire. 4) Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place are built into EPA Bas5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not included in EPA Base 6) For units for which an FGD is modeled as an emissions constraint in EPA Base Case, EPA used the assumptions on removal efficiencies that are shown in the latest emission control technologies documentation 7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and corresponding 95% removal efficiency for wet and 90% for dry. 8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 lb/MMBtu or used the emission limit if provided. 9) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case documentation materials. 10) EPA included in EPA Base Case the requirements of the settlements as they existed on January 1, 2011. 11) Some of the NSR settlements require the retirement of SO2 allowances. EPA estimated the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly. 
25

Appendix 3-4 State Settlements in EPA Base Case v4.10_PTox, Mar2011 

Company and 

Plant State Unit 

State Enforcement Actions 

Retire/Repower SO2 control NOx Control PM Control 

Actio

n 

Effective 

Date Equipment 

Percent 

Removal or 

Rate 

Effective 

Date Equipment Rate Effective Date Equipment Rate Effec

Da

AES 

Greenidge New York Unit 4 Install FGD 90% 09/01/07 Install SCR 0.15 09/01/07 Unit 3 Install BACT 12/31/09 Install BACT 12/31/09 

Westover New York Unit 8 90% 12/31/10 Install SCR 0.15 12/31/10 Unit 7 Install BACT 12/31/09 Install BACT 12/31/09 

Hickling New York Units 1 & 2 Install BACT 05/01/07 Install BACT 05/01/07 

Jennison New York Units 1 & 2 Install BACT 05/01/07 Install BACT 05/01/07 

Niagara Mohawk Power NRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2 and 10,777 tons of NOx, 2006 is 34,230 of SO2 and 6,772 of NOx, 2007 is 30tons of SO2

Huntley New York Units 63 – 66 Retire Before 2008 

Public Service Co. of NM 

San Juan New Mexico 

Unit 1 

State-of-theart 

technology 

90% 

10/31/08 

State-of-theart 

technology 

0.3 

10/31/08 

Operate 

Baghouse and 

demister 

technology 

0.015 

12/3

Unit 2 03/31/09 03/31/09 12/3Unit 3 04/30/08 04/30/08 04/30Unit 4 10/31/07 10/31/07 10/3

Public Service Co of Colorado 

Comanche Colora do 

Units 1 & 

2 

Install and 

operate 

FGD 

0.1 

lb/mmBtu 

combined 

average 

07/01/09 

Install lowNOx

emission 

controls 

0.15 

lb/mmBtu 

combined 

average 

07/01/09 

Unit 3 

Install and 

operate 

FGD 

0.1 

lb/mmBtu 

Install and 

operate 

SCR 

0.08 

Install and 

operate a fabric 

filter dust 

collection 

system 

0.013 

Rochester Gas & Electric 

Russell Plant New York Units 1 – 4 Retire all units 

Mirant New York 

Lovett Plant New York Unit 1 Retire 05/07/07 Unit 2 Retire 04/30/08 

Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court of Appeals, Fourth Circuit Court reversing the settlement.
26

Documentation Supplement to Chapter 5 (“Emission Control Technologies”) 

Chapter 5 covers a number of new capabilities incorporated in EPA Base Case v4.10_PTox. 

Section 5.3 presents features added to give existing coal units the option to burn natural gas by 

investing in a coal-to-gas retrofit. Section 5.4.3 describes the comprehensive update of the cost 

and performance assumptions for activated carbon injection (ACI) for mercury control. Section 

5.5 describes the assumptions in v4.10_PTox related to hydrogen chloride (HCl) emission rate 

and control assumptions. This includes defining the removal rates for existing and new 

generating units and for wet and dry FGD (section 5.5.3.1). It also involves adding dry sorbent 

injection (DSI) and fabric filters (sections 5.5.3.2 and 5.5.4 respectively) as retrofit control 

technologies for HCl removal and developing associated cost and performance assumptions. 

These changes and additions are presented in full below: 

************************************************************************************************************* 

5. Emission Control Technologies 

● ● ●

5.3 Coal-to-Gas conversions2

In EPA Base Case v4.10_PTox existing coal plants are given the option to burn natural gas in 

addition to coal by investing in a coal-to-gas retrofit. There are two components of cost in this 

option: Boiler modification costs and the cost of extending natural gas lateral pipeline spurs 

from the boiler to a natural gas main transmission line. These two components of cost and their 

associated performance implications are discussed in the following sections. 

5.3.1 Boiler Modifications For Coal-To-Gas Conversions 

Enabling natural gas firing in a coal boiler typically involves installation of new gas burners and 

modifications to the ducting, windbox (i.e., the chamber surrounding a burner through which 

pressurized air is supplied for fuel combustion), and possibly to the heating surfaces used to 

transfer energy from the exiting hot flue gas to steam (referred to as the “convection pass”). It 

may also involve modification of environmental equipment. Engineering studies are performed 

to assess operating characteristics like furnace heat absorption and exit gas temperature; 

material changes affecting piping and components like superheaters, air (re)heaters, 

economizers, and recirculating fans; and operational changes to sootblowers, spray flows, air 

heaters, and emission controls. 

The following table summarizes the cost and performance assumptions for such boiler 

modifications as incorporated in Base Case v4.10_PTox. The values in the table were 

developed by EPA’s engineering staff based on technical papers3 and discussions with industry 

engineers familiar with such projects. They were designed to be applicable across the existing 

coal fleet. 

 

2 As discussed here coal-to-gas conversion refers to the modification of an existing boiler to allow it to fire 

natural gas. It does not refer to the addition of a gas turbine to an existing boiler cycle, the replacement 

of a coal boiler with a new natural gas combined cycle plant, or to the gasification of coal for use in a 

natural gas combustion turbine. 

3 For an example see Babcock and Wilcox’s White Paper MS-14 “Natural Gas Conversions of Exiting 

Coal-Fired Boilers” 2010 (www.babcock.com/library/tech-utility.html#14). 
27 

Table 5-11 Cost and Performance Assumptions for Coal-to-Gas Retrofits 

Factor Description Notes 

Applicability: Existing pulverized coal (PC) 

fired and cyclone boiler units 

of a size greater than 25 MW: 

Not applicable for fluidized bed 

combustion (FBC) and stoker 

boilers. 

Capacity Penalty: None The furnace of a boiler designed to 

burn coal is oversized for natural 

gas, and coal boilers include 

equipment, such as coal mills, that 

are not needed for gas. As a result, 

burning gas should have no impact 

on net power output. 

Heat Rate 

Penalty: 

+ 5% When gas is combusted instead of 

coal, the stack temperature is lower 

and the moisture loss to stack is 

higher. This reduces efficiency, 

which is reflected in an increase in 

the heat rate. 

Incremental 

Capital Cost: 

PC units: $/kW = 

250*(75/MW)^0.35 

Cyclone units: $/kW = 

350*(75/MW)^0.35 

The cost function covers new gas 

burners and piping, windbox 

modifications, air heater upgrades, 

gas recirculating fans, and control 

system modifications. 

Example for 50 MW PC unit: 

$/kW = 250*(75/50)^0.35 = 288 

Incremental 

Fixed O&M: 

 -(0.33)*31.1*(75/MW)^0.1 Due to reduced needs for operators, 

maintenance materials, and 

maintenance staff when natural gas 

combusted, FOM costs decrease by 

33%. 

Incremental 

Variable O&M: 

= (0.25)*1.74*(75/MW)^0.2 Due to reduced waste disposal and 

miscellaneous other costs, VOM 

costs decrease by 25%. 

Fuel Cost: Natural gas To obtain natural gas the unit incurs 

the cost of extending lateral pipeline 

spurs from the boiler to the local 

transmission mainline. See section 

5.3.2. 

NOx emission 

rate: 

50% of existing coal unit NOx 

emission rate, with a floor of 

0.05 lbs/MMBtu 

The 0.05 lbs/MMBtu floor is the 

same as the NOx rate floor for new 

retrofit SCR on units burning 

subbituminous coal 

SO2 emissions: Zero 

5.3.2 Natural Gas Pipeline Requirements For Coal-To-Gas Conversions 

For every individual coal boiler in the U.S., EPA tasked the gas team at ICF International to 
28 

determine the miles and associated cost of extending pipeline laterals from each boiler to the 

interstate natural gas pipeline system. 

To develop these costs the following principles were applied: 

• For each boiler, gas volume was estimated based on size and heat rate. 

• Direct distance to the closest pipeline was calculated. (The analysis only considered 

mainlines with diameters that were 16 inches or greater. The lateral distance 

represented the shortest distance – “as the crow flies” – between the boiler and the 

mainline.) 

• Gas volume (per day) of the initial lateral was not allowed to exceed more than 10 

percent of the estimated capacity of the mainline. 

• The mainline capacities were estimated from the pipe’s diameter using the Weymouth 

equation4

. 

• If the gas requirement exceeded 10 percent of the estimated capacity of the mainline, 

the cost of a second lateral to connect to the next closest mainline was calculated. 

• This procedure was repeated until the entire capacity required for the boiler was 

reached. 

• Diameters of each lateral were then calculated using the Weymouth equation based on 

their required capacities. 

• The cost of all the laterals was calculated based on the pipeline diameter and mileage 

required. Thus, the final pipeline cost for each boiler was based on the total miles of 

laterals required. 

Figure 5-1 shows the calculations performed. 

Figure 5-1 Calculations Performed in Costing Lateral Pipeline Requirement 

Mainline Flow Capacity, Qm (million cubic feet per day)

Qm = 0.06745 * d 2.667, where d is the diameter of the mainline in inches 

Required Capacity of Lateral/s for Each Boiler, Ql (million cubic feet per day)

Ql = (Boiler Capacity * Heat Rate *24) / 1,030,000, where Boiler Capacity is in MW and the Heat 

Rate is in Btu/kWh 

Diameter of Each Lateral, D (inches)

D = (14.83 * Ql)

 0.37495, where each lateral’s capacity may not exceed 10% of the mainline 

capacity to which the lateral connects 

Cost per Lateral, C ($)

C = 60,000 *D * Number of Miles 

Note: The above calculations assume a pipeline cost of $60,000 per inch-mile based on 

recently completed projects. 

 

4

The Weymouth equation in classical fluid dynamics is used in calculating compressible gas flow as a function of

pipeline diameter and friction factors.   It is used for pipe sizing.
29 

There are several points to note about the approach. First, for relatively large boilers or in 

cases where the closest mainline has a relatively small diameter, multiple laterals are required 

to connect the boiler to the interstate gas transmission grid. This assures that each individual 

boiler will not become a relatively large portion of a pipelines’ transmission capacity. It also 

reflects real-world practices where larger gas-fired power plants typically have multiple laterals 

connecting them to different mainlines. This increases the reliability of their gas supply and 

provides multiple options for gas purchase allowing them to capture favorable prices from 

multiple sources of gas supply at different points in time. 

Second, expansion of mainlines was not included in the boiler specific pipeline cost, because 

the integrated gas model within IPM already includes corridor expansion capabilities. However, 

if in future IPM runs, multiple converted boilers are concentrated on a single pipeline along a 

corridor that includes multiple pipelines, a further assessment may be required to make sure 

that the mainline expansion is not being understated due to modeled efficiencies that may not 

actually be available in the field. 

Figures 5-2 through 5-7 summarize the results of the pipeline costing procedure described 

above. They provide histograms of the number of laterals required per boiler (Figure 5-2), miles 

of pipeline required per boiler (Figure 5-3), diameters of the laterals in inches (Figure 5-4), total 

inch-miles of laterals required per boiler (Figure 5-5), total cost to each boiler in million$ (Figure 

5-6), and cost (in $) per kW of boiler capacity (Figure 5-7). Table 5-12 gives a consolidated 

overview of the information in these figures by showing the minimum, maximum, average, and 

median values that appear in the figures. Table 5-13 (“Cost of Building Pipelines to Coal 

Plants”) shows the pipeline costing results for each qualifying existing coal fired unit represented 

in EPA Base Case v4.10_PTox. 

Figure 5‐2

0

100

200

300

400

500

600

700

800

1 2 3 4 5 6 7 8

Frequency (n=1294)

Number of Laterals

Number of Laterals Requiredper Boiler
30 

Figure 5‐3

Figure 5‐4

0

50

100

150

200

250

300

0 to 1 1 to 5 5 to 10 10 to 25 25 to 50 50 to 100 100 to

200

200 to

300

300 to

400

More than

400

Frequency (n=1294)

Miles of Pipeline

Miles of Pipeline Requiredper Boiler

0

100

200

300

400

500

600

700

800

1 to 2 2 to 4 4 to 6 6 to 8 8 to 10 10 to 12 12 to 14 14 to 16 16 to 18 18 to 20 More

than 20

Frequency (n=2248)

Diameter of Laterals, in Inches

Diameter of Laterals, in Inches
31 

Figure 5‐5

Figure 5‐6

0

50

100

150

200

250

300

1 to

50

50 to

100

100 to

200

200 to

400

400 to

600

600 to

800

800 to

1000

1000

to

1200

1200

to

1400

1400

to

1600

1600

to

1800

1800

to

2000

2000

to

3000

3000

to

4000

4000

to

5000

More

than

5000

Frequency (n=1294)

Number of Inch‐Miles per Boiler

Total Inch‐Miles of Laterals Requiredper Boiler

0

50

100

150

200

250

300

0 to 1 1 to 5 5 to 10 10 to 25 25 to 50 50 to 100 100 to

200

200 to

300

300 to

400

More than

400

Frequency (n=1294)

Cost Increment (Million$)

Total Cost to Each Boiler (Million$)
32 

Figure 5‐7

 

0

50

100

150

200

250

300

0 to 1 1 to

5

5 to

10

10 to

25

25 to

50

50 to

100

100

to

200

200

to

300

300

to

400

400

to

500

500

to

600

600

to

700

700

to

800

800

to

900

900

to

1000

1000

to

1100

1100

to

1200

More

than

1200

Frequency (n=1294)

Cost Increment ($)

Cost per kW of Boiler Capacity ($)
33

Table 5-13 Cost of Building Pipelines to Coal Plants 

UniqueID_Final Plant Name State 

Coal 

Boiler 

Capacity 

(MW) 

Number 

of 

Laterals 

Required 

Miles of 

New 

Pipeline 

Required 

to Hook 

Up Unit 

(miles) 

Total Cos

New Pipe

($) 

3_B_1 Barry AL 138 1 1 8563_B_2 Barry AL 137 1 1 8543_B_3 Barry AL 249 2 8 5,2433_B_4 Barry AL 362 2 8 6,5783_B_5 Barry AL 750 3 19 16,8087_B_1 Gadsden AL 64 1 29 16,4887_B_2 Gadsden AL 66 1 29 16,913

8_B_10 Gorgas AL 690 2 68 64,804

8_B_6 Gorgas AL 108 1 8 5,4818_B_7 Gorgas AL 109 1 8 5,3628_B_8 Gorgas AL 165 1 8 5,9408_B_9 Gorgas AL 175 1 8 6,126

10_B_1 Greene County AL 254 1 7 6,05810_B_2 Greene County AL 243 1 7 6,00626_B_1 E C Gaston AL 254 1 23 20,29626_B_2 E C Gaston AL 256 1 23 20,54926_B_3 E C Gaston AL 254 1 23 20,40326_B_4 E C Gaston AL 256 1 23 20,41626_B_5 E C Gaston AL 861 3 163 157,43247_B_1 Colbert AL 177 1 0 37347_B_2 Colbert AL 177 1 0 37347_B_3 Colbert AL 177 1 0 37347_B_4 Colbert AL 173 1 0 370
34

47_B_5 Colbert AL 459 2 4 3,52450_B_1 Widows Creek AL 111 2 165 76,83550_B_2 Widows Creek AL 111 2 165 76,83550_B_3 Widows Creek AL 111 2 165 77,44550_B_4 Widows Creek AL 111 2 165 77,44550_B_5 Widows Creek AL 111 2 165 73,70850_B_6 Widows Creek AL 111 2 165 73,70850_B_7 Widows Creek AL 473 3 253 156,62350_B_8 Widows Creek AL 464 2 165 138,25851_B_1 Dolet Hills LA 650 4 32 24,78456_B_1 Charles R Lowman AL 86 1 17 11,06256_B_2 Charles R Lowman AL 238 2 44 30,58556_B_3 Charles R Lowman AL 238 2 44 30,95059_B_1 Platte NE 100 1 26 17,55060_B_1 Whelan Energy Center NE 77 1 8 4,77160_B_2 Whelan Energy Center NE 220 1 8 6,54387_B_1 Escalante NM 247 2 11 5,066

108_B_SGU1 Holcomb KS 360 4 46 26,657

113_B_1 Cholla AZ 110 1 28 18,947113_B_2 Cholla AZ 275 1 28 26,244113_B_3 Cholla AZ 271 1 28 26,736113_B_4 Cholla AZ 380 2 58 47,225126_B_4 H Wilson Sundt Generating Station AZ 156 1 4 3,325127_B_1 Oklaunion TX 690 8 560 324,667130_B_1 Cross SC 620 2 240 224,907130_B_2 Cross SC 540 2 240 216,115130_B_3 Cross SC 580 2 240 217,804130_B_4 Cross SC 600 2 240 214,338136_B_1 Seminole FL 658 3 153 123,762136_B_2 Seminole FL 658 3 153 122,186
35

160_B_2 Apache Station AZ 175 1 2 1,297160_B_3 Apache Station AZ 175 1 2 1,277165_B_1 GRDA OK 490 6 296 174,657165_B_2 GRDA OK 520 7 415 208,730207_B_1 St Johns River Power Park FL 626 3 212 196,013207_B_2 St Johns River Power Park FL 626 4 477 307,121

298_B_LIM1 Limestone TX 831 7 325 193,623298_B_LIM2 Limestone TX 858 7 325 200,701

384_B_71 Joliet 29 IL 259 2 2 1,347384_B_72 Joliet 29 IL 259 2 2 1,162384_B_81 Joliet 29 IL 259 2 2 1,248384_B_82 Joliet 29 IL 259 2 2 1,162462_B_55 W N Clark CO 18 1 40 14,508462_B_59 W N Clark CO 25 1 40 16,328

465_B_3 Arapahoe CO 47 1 9 4,410465_B_4 Arapahoe CO 121 2 86 42,752469_B_1 Cherokee CO 115 2 74 33,550469_B_2 Cherokee CO 120 2 74 33,924469_B_3 Cherokee CO 165 2 74 43,357469_B_4 Cherokee CO 388 2 74 67,384470_B_1 Comanche CO 366 2 151 139,124470_B_2 Comanche CO 370 2 151 139,986470_B_3 Comanche CO 750 4 463 332,375477_B_5 Valmont CO 199 1 19 14,716492_B_5 Martin Drake CO 46 1 13 6,642492_B_6 Martin Drake CO 77 2 127 33,893492_B_7 Martin Drake CO 131 2 127 64,243

525_B_H1 Hayden CO 205 2 78 48,661525_B_H2 Hayden CO 300 3 123 81,937

527_B_1 Nucla CO 100 2 43 11,535
36

564_B_1 Stanton Energy Center FL 440 2 31 28,104564_B_2 Stanton Energy Center FL 446 2 31 27,959

568_B_BHB3 Bridgeport Station CT 372 3 43 28,557

593_B_3 Edge Moor DE 86 2 14 6,706593_B_4 Edge Moor DE 174 2 14 7,908594_B_3 Indian River Generating Station DE 153 1 65 48,452594_B_4 Indian River Generating Station DE 405 2 144 88,686602_B_1 Brandon Shores MD 643 2 46 42,283602_B_2 Brandon Shores MD 643 2 46 42,934628_B_1 Crystal River FL 379 2 80 64,036628_B_2 Crystal River FL 491 2 80 67,687628_B_4 Crystal River FL 722 2 80 37,187628_B_5 Crystal River FL 721 2 80 35,020641_B_4 Crist FL 78 1 6 3,592641_B_5 Crist FL 78 1 6 3,517641_B_6 Crist FL 302 2 31 24,092641_B_7 Crist FL 472 2 31 30,704642_B_1 Scholz FL 49 1 13 6,456642_B_2 Scholz FL 49 1 13 6,716643_B_1 Lansing Smith FL 162 1 22 17,226643_B_2 Lansing Smith FL 195 1 22 18,788

645_B_BB01 Big Bend FL 391 2 25 18,006645_B_BB02 Big Bend FL 391 2 25 17,980645_B_BB03 Big Bend FL 364 2 25 19,260645_B_BB04 Big Bend FL 447 2 25 20,775

663_B_B2 Deerhaven Generating Station FL 228 1 12 10,065

667_B_1 Northside Generating Station FL 275 3 205 97,644667_B_2 Northside Generating Station FL 275 3 205 110,541676_B_3 C D McIntosh Jr FL 342 1 0 52

703_B_1BLR Bowen GA 713 2 83 83,854
37

703_B_2BLR Bowen GA 718 2 83 85,497703_B_3BLR Bowen GA 902 3 212 165,111703_B_4BLR Bowen GA 929 3 212 168,510

708_B_1 Hammond GA 112 1 42 27,538708_B_2 Hammond GA 112 1 42 27,345708_B_3 Hammond GA 112 1 42 27,384708_B_4 Hammond GA 510 2 110 102,098709_B_1 Harllee Branch GA 266 2 60 43,475709_B_2 Harllee Branch GA 325 2 60 47,552709_B_3 Harllee Branch GA 509 2 60 57,310709_B_4 Harllee Branch GA 507 2 60 57,554

710_B_MB1 Jack McDonough GA 258 1 8 6,833710_B_MB2 Jack McDonough GA 259 1 8 6,833

727_B_3 Mitchell GA 96 1 67 39,746

728_B_Y1BR Yates GA 99 1 9 6,092728_B_Y2BR Yates GA 105 1 9 6,250728_B_Y3BR Yates GA 112 1 9 6,402728_B_Y4BR Yates GA 135 1 9 6,719728_B_Y5BR Yates GA 137 1 9 6,756728_B_Y6BR Yates GA 352 2 23 17,743728_B_Y7BR Yates GA 355 2 23 17,648

733_B_1 Kraft GA 48 1 2 861733_B_2 Kraft GA 52 1 2 851733_B_3 Kraft GA 102 1 2 1,099

753_B_ST Crisp Plant GA 10 1 67 20,321

856_B_1 E D Edwards IL 112 2 61 13,738856_B_2 E D Edwards IL 273 2 61 46,425856_B_3 E D Edwards IL 364 3 125 85,921

861_B_01 Coffeen IL 340 3 103 68,710861_B_02 Coffeen IL 560 3 103 82,715
38

863_B_05 Hutsonville IL 76 2 67 18,023863_B_06 Hutsonville IL 77 1 25 14,411864_B_05 Meredosia IL 203 1 18 15,177

867_B_7 Crawford IL 213 1 19 16,157867_B_8 Crawford IL 319 2 43 31,027874_B_5 Joliet 9 IL 314 2 2 1,666876_B_1 Kincaid Generation LLC IL 584 2 11 8,272876_B_2 Kincaid Generation LLC IL 584 2 11 8,186

879_B_51 Powerton IL 385 2 66 60,857879_B_52 Powerton IL 385 2 66 59,892879_B_61 Powerton IL 385 2 66 60,703879_B_62 Powerton IL 385 2 66 59,892883_B_17 Waukegan IL 100 1 15 10,038

883_B_7 Waukegan IL 328 2 38 29,029883_B_8 Waukegan IL 361 2 38 30,956884_B_1 Will County IL 151 1 4 3,163884_B_2 Will County IL 148 1 4 3,225884_B_3 Will County IL 251 2 16 6,254884_B_4 Will County IL 510 3 27 19,264

886_B_19 Fisk Street IL 326 2 50 37,297

887_B_1 Joppa Steam IL 167 1 1 868887_B_2 Joppa Steam IL 167 1 1 868887_B_3 Joppa Steam IL 167 1 1 866887_B_4 Joppa Steam IL 167 1 1 865887_B_5 Joppa Steam IL 167 1 1 874887_B_6 Joppa Steam IL 167 1 1 867889_B_1 Baldwin Energy Complex IL 624 3 106 79,181889_B_2 Baldwin Energy Complex IL 629 3 106 81,560889_B_3 Baldwin Energy Complex IL 629 3 106 83,884891_B_9 Havana IL 487 2 74 66,810
39

892_B_1 Hennepin Power Station IL 81 1 14 8,519892_B_2 Hennepin Power Station IL 240 1 14 12,775897_B_1 Vermilion IL 84 1 9 5,387897_B_2 Vermilion IL 213 1 9 7,794898_B_4 Wood River IL 105 1 1 414898_B_5 Wood River IL 383 2 50 31,960

963_B_31 Dallman IL 86 2 9 2,538963_B_32 Dallman IL 87 2 9 3,674963_B_33 Dallman IL 199 2 9 6,103

963_B_4 Dallman IL 200 2 9 5,241

976_B_123 Marion IL 120 1 2 1,159

976_B_4 Marion IL 170 2 5 3,301981_B_3 State Line IN 187 1 17 13,401981_B_4 State Line IN 303 1 17 16,050983_B_1 Clifty Creek IN 217 2 73 46,944983_B_2 Clifty Creek IN 217 2 73 46,314983_B_3 Clifty Creek IN 217 2 73 46,115983_B_4 Clifty Creek IN 217 2 73 46,015983_B_5 Clifty Creek IN 217 2 73 45,451983_B_6 Clifty Creek IN 217 2 73 45,812

988_B_U1 Tanners Creek IN 145 2 34 16,615988_B_U2 Tanners Creek IN 145 2 34 15,923988_B_U3 Tanners Creek IN 200 2 34 20,702988_B_U4 Tanners Creek IN 500 2 34 29,541

990_B_50 Harding Street IN 109 2 19 8,909990_B_60 Harding Street IN 109 2 19 8,885990_B_70 Harding Street IN 435 2 19 15,879

991_B_3 Eagle Valley IN 43 1 7 3,124991_B_4 Eagle Valley IN 56 1 7 3,485991_B_5 Eagle Valley IN 62 1 7 3,503
40

991_B_6 Eagle Valley IN 99 1 7 4,193994_B_1 Petersburg IN 232 3 49 21,334994_B_2 Petersburg IN 435 3 49 37,186994_B_3 Petersburg IN 540 3 49 41,499994_B_4 Petersburg IN 545 3 49 41,426995_B_7 Bailly IN 160 1 6 4,734995_B_8 Bailly IN 320 1 6 6,131

996_B_11 Dean H Mitchell IN 110 1 9 6,215

996_B_4 Dean H Mitchell IN 125 1 9 6,467996_B_5 Dean H Mitchell IN 125 1 9 6,298996_B_6 Dean H Mitchell IN 125 1 9 6,290

997_B_12 Michigan City IN 469 2 30 23,6731001_B_1 Cayuga IN 479 2 17 14,4221001_B_2 Cayuga IN 473 2 17 14,5011008_B_1 R Gallagher IN 140 2 68 37,3311008_B_2 R Gallagher IN 140 2 68 37,0211008_B_3 R Gallagher IN 140 2 68 37,0731008_B_4 R Gallagher IN 140 2 68 37,331

1010_G_1 Wabash River IN 85 1 18 9,993

1010_G_1A Wabash River IN 189 1 18 13,544

1010_B_2 Wabash River IN 85 1 18 10,8651010_B_3 Wabash River IN 85 1 18 10,5621010_B_4 Wabash River IN 85 1 18 10,7341010_B_5 Wabash River IN 95 1 18 10,9571010_B_6 Wabash River IN 318 2 36 27,1721012_B_2 F B Culley IN 90 2 17 7,8091012_B_3 F B Culley IN 270 2 17 12,2361024_B_5 Crawfordsville IN 11 1 17 4,8691024_B_6 Crawfordsville IN 13 1 17 4,8691032_B_5 Logansport IN 17 1 33 12,027
41

1032_B_6 Logansport IN 22 1 33 13,6301037_B_2 Peru IN 20 1 35 13,5811037_B_5 Peru IN 12 1 35 11,3601040_B_1 Whitewater Valley IN 35 1 15 6,5981040_B_2 Whitewater Valley IN 63 1 15 8,261

1043_B_1SG1 Frank E Ratts IN 122 2 21 10,4571043_B_2SG1 Frank E Ratts IN 121 2 21 10,319

1046_B_1 Dubuque IA 35 1 5 2,2081046_B_5 Dubuque IA 30 1 5 1,9721046_B_6 Dubuque IA 13 1 5 1,4671047_B_2 Lansing IA 11 1 55 17,4281047_B_3 Lansing IA 37 1 55 26,8221047_B_4 Lansing IA 261 1 55 51,9341048_B_2 Milton L Kapp IA 211 1 12 10,1971058_B_2 Sixth Street IA 14 1 26 8,4611058_B_3 Sixth Street IA 14 1 26 8,9171058_B_4 Sixth Street IA 14 1 26 8,9171058_B_5 Sixth Street IA 14 1 26 8,9171073_B_1 Prairie Creek IA 9 1 27 7,3261073_B_2 Prairie Creek IA 10 1 27 7,7461073_B_3 Prairie Creek IA 42 1 27 12,6821073_B_4 Prairie Creek IA 125 1 27 18,5081077_B_1 Sutherland IA 31 1 13 5,4311077_B_2 Sutherland IA 31 1 13 5,4781077_B_3 Sutherland IA 82 1 13 7,3081081_B_7 Riverside IA 3 1 9 1,5431081_B_8 Riverside IA 3 1 9 1,5431081_B_9 Riverside IA 130 1 9 6,5071082_B_1 Walter Scott Jr. Energy Center IA 45 1 7 3,4901082_B_2 Walter Scott Jr. Energy Center IA 88 1 7 4,579
42

1082_B_3 Walter Scott Jr. Energy Center IA 690 2 20 19,5941082_B_4 Walter Scott Jr. Energy Center IA 800 3 100 83,5011091_B_1 George Neal North IA 135 1 6 4,1371091_B_2 George Neal North IA 300 2 94 56,7621091_B_3 George Neal North IA 515 2 94 92,8121104_B_1 Burlington IA 209 1 56 48,7511122_B_7 Ames Electric Services Power Plant IA 33 1 9 4,3061122_B_8 Ames Electric Services Power Plant IA 70 1 9 5,7191131_B_6 Streeter Station IA 19 1 11 4,0851131_B_7 Streeter Station IA 36 1 11 5,2971167_B_7 Muscatine Plant #1 IA 22 1 15 6,0251167_B_8 Muscatine Plant #1 IA 35 1 15 7,4481167_B_9 Muscatine Plant #1 IA 147 1 15 11,1661175_B_6 Pella IA 15 1 34 11,1211175_B_7 Pella IA 13 1 34 10,6911217_B_1 Earl F Wisdom IA 38 1 5 2,1191218_B_1 Fair Station IA 23 1 13 4,9401218_B_2 Fair Station IA 41 1 13 5,861

1239_B_39 Riverton KS 38 1 5 2,6001239_B_40 Riverton KS 54 1 5 2,860

1241_B_1 La Cygne KS 724 2 38 34,3441241_B_2 La Cygne KS 682 2 38 33,9701250_B_3 Lawrence Energy Center KS 48 1 5 2,4641250_B_4 Lawrence Energy Center KS 110 1 5 3,2551250_B_5 Lawrence Energy Center KS 366 2 41 33,321

1252_B_10 Tecumseh Energy Center KS 129 1 20 14,251

1252_B_9 Tecumseh Energy Center KS 74 1 20 12,3961295_B_1 Quindaro KS 72 1 0 2911295_B_2 Quindaro KS 111 1 0 350

1353_B_BSU1 Big Sandy KY 260 2 13 9,325
43

1353_B_BSU2 Big Sandy KY 800 3 28 22,413

1355_B_1 E W Brown KY 94 1 11 6,9881355_B_2 E W Brown KY 160 1 11 8,0281355_B_3 E W Brown KY 422 2 27 22,4201356_B_1 Ghent KY 475 2 72 62,2211356_B_2 Ghent KY 469 2 72 60,7321356_B_3 Ghent KY 478 2 72 61,3541356_B_4 Ghent KY 478 2 72 61,3361357_B_4 Green River KY 68 1 23 13,7031357_B_5 Green River KY 95 1 23 14,2841361_B_5 Tyrone KY 71 1 29 16,3051363_B_4 Cane Run KY 155 2 69 40,7851363_B_5 Cane Run KY 168 2 69 42,7011363_B_6 Cane Run KY 240 3 118 64,6971364_B_1 Mill Creek KY 303 3 128 82,2821364_B_2 Mill Creek KY 301 3 128 82,8111364_B_3 Mill Creek KY 391 3 128 91,8321364_B_4 Mill Creek KY 477 3 128 98,6481374_B_1 Elmer Smith KY 132 1 6 4,2601374_B_2 Elmer Smith KY 261 1 6 5,9681378_B_1 Paradise KY 616 3 122 71,0811378_B_2 Paradise KY 602 2 73 60,9001378_B_3 Paradise KY 977 3 122 112,7791379_B_1 Shawnee KY 133 1 7 4,919

1379_B_10 Shawnee KY 124 1 7 5,111

1379_B_2 Shawnee KY 134 1 7 4,9371379_B_3 Shawnee KY 134 1 7 4,9371379_B_4 Shawnee KY 134 1 7 4,9371379_B_5 Shawnee KY 134 1 7 4,9371379_B_6 Shawnee KY 134 1 7 4,937
44

1379_B_7 Shawnee KY 134 1 7 4,9371379_B_8 Shawnee KY 134 1 7 4,9371379_B_9 Shawnee KY 134 1 7 4,937

1381_B_C1 Kenneth C Coleman KY 150 1 13 9,6321381_B_C2 Kenneth C Coleman KY 150 1 13 9,6321381_B_C3 Kenneth C Coleman KY 155 1 13 9,7531382_B_H1 HMP&L Station Two Henderson KY 153 2 8 4,6751382_B_H2 HMP&L Station Two Henderson KY 159 2 8 4,7771383_B_R1 Robert A Reid KY 65 1 2 1,099

1384_B_1 Cooper KY 116 1 32 20,6221384_B_2 Cooper KY 225 1 32 26,3161385_B_1 Dale KY 27 1 4 1,7661385_B_2 Dale KY 27 1 4 1,7731385_B_3 Dale KY 75 1 4 2,3781385_B_4 Dale KY 75 1 4 2,3781393_B_6 R S Nelson LA 550 3 9 8,0131552_B_1 C P Crane MD 200 2 45 28,5721552_B_2 C P Crane MD 200 2 45 28,3891554_B_2 Herbert A Wagner MD 135 1 22 16,8191554_B_3 Herbert A Wagner MD 324 1 22 21,800

1570_B_11 R Paul Smith Power Station MD 87 2 27 13,234

1570_B_9 R Paul Smith Power Station MD 28 1 12 4,7851571_B_1 Chalk Point LLC MD 341 1 1 1,4521571_B_2 Chalk Point LLC MD 342 1 1 1,4531572_B_1 Dickerson MD 182 2 9 5,4291572_B_2 Dickerson MD 182 2 9 5,4211572_B_3 Dickerson MD 182 2 9 5,4541573_B_1 Morgantown Generating Plant MD 624 3 99 65,2091573_B_2 Morgantown Generating Plant MD 620 3 99 62,3601606_B_1 Mount Tom MA 144 1 15 10,827
45

1619_B_1 Brayton Point MA 244 3 85 44,1471619_B_2 Brayton Point MA 244 3 85 44,2331619_B_3 Brayton Point MA 612 5 218 146,0221626_B_1 Salem Harbor MA 82 1 1 3831626_B_2 Salem Harbor MA 80 1 1 3791626_B_3 Salem Harbor MA 150 1 1 4801695_B_4 B C Cobb MI 156 2 90 51,0001695_B_5 B C Cobb MI 156 2 90 50,6891702_B_1 Dan E Karn MI 255 1 49 42,2871702_B_2 Dan E Karn MI 260 1 49 42,5671710_B_1 J H Campbell MI 260 3 188 105,1511710_B_2 J H Campbell MI 355 3 188 123,2281710_B_3 J H Campbell MI 825 3 188 159,1771720_B_7 J C Weadock MI 151 1 48 34,9521720_B_8 J C Weadock MI 151 1 48 34,9901723_B_1 J R Whiting MI 102 1 14 8,9601723_B_2 J R Whiting MI 102 1 14 8,9601723_B_3 J R Whiting MI 124 1 14 9,6081731_B_1 Harbor Beach MI 103 2 144 65,999

1732_B_10 Marysville MI 42 1 9 4,5581732_B_11 Marysville MI 42 1 9 4,5581732_B_12 Marysville MI 42 1 9 4,558

1732_B_9 Marysville MI 42 1 9 4,5581733_B_1 Monroe MI 770 3 63 51,0671733_B_2 Monroe MI 785 3 63 51,0991733_B_3 Monroe MI 795 3 63 51,3211733_B_4 Monroe MI 775 3 63 50,8101740_B_2 River Rouge MI 241 2 21 14,0401740_B_3 River Rouge MI 272 3 43 18,3251743_B_1 St Clair MI 151 1 1 821
46

1743_B_2 St Clair MI 154 1 1 8191743_B_3 St Clair MI 160 1 1 8331743_B_4 St Clair MI 151 1 1 8181743_B_6 St Clair MI 312 1 1 1,0201743_B_7 St Clair MI 440 2 3 1,888

1745_B_16 Trenton Channel MI 53 1 7 3,5181745_B_17 Trenton Channel MI 53 1 7 3,6561745_B_18 Trenton Channel MI 53 1 7 3,4591745_B_19 Trenton Channel MI 53 1 7 3,400

1745_B_9A Trenton Channel MI 536 2 28 24,802

1769_B_5 Presque Isle MI 88 2 310 134,7031769_B_6 Presque Isle MI 88 2 310 134,1191769_B_7 Presque Isle MI 85 2 310 142,8181769_B_8 Presque Isle MI 85 2 310 137,9931769_B_9 Presque Isle MI 85 2 310 137,9931771_B_1 Escanaba MI 13 1 100 33,5201771_B_2 Escanaba MI 13 1 100 33,5201825_B_3 J B Sims MI 73 1 50 28,1701830_B_3 James De Young MI 11 1 58 17,1491830_B_4 James De Young MI 21 1 58 21,9671830_B_5 James De Young MI 27 1 58 25,6801831_B_1 Eckert Station MI 40 1 24 11,8441831_B_2 Eckert Station MI 42 1 24 12,0881831_B_3 Eckert Station MI 41 1 24 12,0541831_B_4 Eckert Station MI 69 1 24 14,0201831_B_5 Eckert Station MI 69 1 24 14,4381831_B_6 Eckert Station MI 67 1 24 14,1261832_B_1 Erickson Station MI 152 1 22 16,5491843_B_2 Shiras MI 20 1 141 51,0871843_B_3 Shiras MI 41 1 141 67,829
47

1866_B_5 Wyandotte MI 24 1 3 1,1971866_B_7 Wyandotte MI 24 1 3 1,1481866_B_8 Wyandotte MI 24 1 3 1,2731891_B_1 Syl Laskin MN 55 1 20 10,9461891_B_2 Syl Laskin MN 55 1 20 10,9461893_B_1 Clay Boswell MN 69 1 51 28,4261893_B_2 Clay Boswell MN 69 1 51 27,9941893_B_3 Clay Boswell MN 351 3 305 209,9041893_B_4 Clay Boswell MN 525 3 305 259,2541904_B_3 Black Dog MN 94 1 15 9,4421904_B_4 Black Dog MN 165 1 15 11,3071915_B_1 Allen S King MN 610 3 109 98,3791943_B_2 Hoot Lake MN 60 1 31 16,9911943_B_3 Hoot Lake MN 84 1 31 19,334

1961_B_NEPP Austin Northeast MN 29 1 10 4,487

1979_B_1 Hibbing MN 10 1 14 3,6431979_B_2 Hibbing MN 10 1 14 3,6431979_B_3 Hibbing MN 10 1 14 3,5852008_B_1 Silver Lake MN 9 1 43 12,6802008_B_2 Silver Lake MN 14 1 43 14,3362008_B_3 Silver Lake MN 24 1 43 16,8342008_B_4 Silver Lake MN 59 1 43 23,4082018_B_7 Virginia MN 10 1 6 1,7572018_B_9 Virginia MN 10 1 6 1,7332022_B_3 Willmar MN 20 1 12 4,4292049_B_4 Jack Watson MS 230 1 1 1,0592049_B_5 Jack Watson MS 476 2 26 22,151

2062_B_H1 Henderson MS 11 1 2 5992062_B_H3 Henderson MS 18 1 2 715

2076_B_1 Asbury MO 213 3 141 76,776
48

2079_B_5A Hawthorn MO 563 2 39 40,971

2080_B_1 Montrose MO 170 2 59 36,6222080_B_2 Montrose MO 164 2 59 36,0442080_B_3 Montrose MO 176 2 59 36,9842094_B_1 Sibley MO 54 1 12 6,0502094_B_2 Sibley MO 54 1 12 5,9302094_B_3 Sibley MO 401 2 41 34,8962098_B_5 Lake Road MO 14 1 3 1,2022098_B_6 Lake Road MO 97 1 3 2,4542103_B_1 Labadie MO 597 2 88 86,7712103_B_2 Labadie MO 594 2 88 84,8802103_B_3 Labadie MO 612 2 88 85,7762103_B_4 Labadie MO 612 2 88 85,0992104_B_1 Meramec MO 122 2 63 27,3222104_B_2 Meramec MO 120 2 63 25,4332104_B_3 Meramec MO 269 2 63 49,2922104_B_4 Meramec MO 347 3 143 95,5512107_B_1 Sioux MO 497 2 53 36,1712107_B_2 Sioux MO 497 2 53 36,1712123_B_6 Columbia MO 25 1 11 4,5772123_B_7 Columbia MO 25 1 11 4,0012132_B_1 Blue Valley MO 21 1 10 3,6572132_B_2 Blue Valley MO 21 1 10 3,6572132_B_3 Blue Valley MO 51 1 10 5,6262144_B_4 Marshall MO 5 1 16 3,4942144_B_5 Marshall MO 16 1 16 5,5472161_B_1 James River Power Station MO 21 1 46 17,2792161_B_2 James River Power Station MO 21 1 46 17,2792161_B_3 James River Power Station MO 41 1 46 22,9052161_B_4 James River Power Station MO 56 1 46 24,300
49

2161_B_5 James River Power Station MO 97 2 120 55,7332167_B_1 New Madrid MO 580 2 41 38,9532167_B_2 New Madrid MO 580 2 41 39,162

2168_B_MB1 Thomas Hill MO 175 1 11 9,2392168_B_MB2 Thomas Hill MO 275 1 11 10,7532168_B_MB3 Thomas Hill MO 670 2 44 35,713

2169_B_1 Chamois MO 17 1 36 12,9682169_B_2 Chamois MO 49 1 36 18,0272171_B_1 Missouri City MO 19 1 17 6,3592171_B_2 Missouri City MO 19 1 17 6,3592187_B_2 J E Corette Plant MT 158 1 150 117,9052240_B_6 Lon Wright NE 15 1 3 8772240_B_7 Lon Wright NE 20 1 3 1,0182240_B_8 Lon Wright NE 85 1 3 1,6242277_B_1 Sheldon NE 105 1 12 8,2302277_B_2 Sheldon NE 120 1 12 8,6832291_B_1 North Omaha NE 79 1 15 9,0592291_B_2 North Omaha NE 111 1 15 10,2882291_B_3 North Omaha NE 111 1 15 10,2362291_B_4 North Omaha NE 138 2 31 14,6422291_B_5 North Omaha NE 224 2 31 20,7082324_B_1 Reid Gardner NV 110 1 3 1,9722324_B_2 Reid Gardner NV 110 1 3 1,9932324_B_3 Reid Gardner NV 110 1 3 2,0162324_B_4 Reid Gardner NV 225 1 3 2,5242364_B_1 Merrimack NH 113 1 30 20,6722364_B_2 Merrimack NH 320 2 60 43,6512367_B_4 Schiller NH 48 1 3 1,3932367_B_6 Schiller NH 48 1 3 1,3442378_B_1 B L England NJ 129 2 94 52,365
50

2378_B_2 B L England NJ 155 2 94 55,3672384_B_8 Deepwater NJ 80 1 9 5,4642403_B_2 PSEG Hudson Generating Station NJ 608 4 43 28,6852408_B_1 PSEG Mercer Generating Station NJ 324 2 20 14,8282408_B_2 PSEG Mercer Generating Station NJ 324 2 20 14,394

2434_B_10 Howard Down NJ 23 1 22 9,263

2442_B_1 Four Corners NM 170 1 4 2,9152442_B_2 Four Corners NM 170 1 4 2,9232442_B_3 Four Corners NM 220 1 4 3,3002442_B_4 Four Corners NM 760 4 65 48,2802442_B_5 Four Corners NM 760 4 65 48,3902451_B_1 San Juan NM 322 2 20 11,0312451_B_2 San Juan NM 320 2 20 11,2102451_B_3 San Juan NM 495 3 38 25,9692451_B_4 San Juan NM 506 3 38 25,016

2468_G_5 Raton NM 7 1 21 5,429

2480_B_3 Danskammer Generating Station NY 133 1 13 9,0152480_B_4 Danskammer Generating Station NY 236 2 33 21,202

2526_B_11 AES Westover NY 22 1 3 1,2742526_B_12 AES Westover NY 22 1 3 1,2892526_B_13 AES Westover NY 84 1 3 2,031

2527_B_6 AES Greenidge LLC NY 106 1 4 2,5992535_B_1 AES Cayuga NY 152 1 14 10,5862535_B_2 AES Cayuga NY 153 1 14 10,609

2549_B_67 C R Huntley Generating Station NY 190 2 9 5,1762549_B_68 C R Huntley Generating Station NY 190 2 9 5,176

2554_B_1 Dunkirk Generating Station NY 75 1 7 3,8112554_B_2 Dunkirk Generating Station NY 75 1 7 3,8332554_B_3 Dunkirk Generating Station NY 185 2 33 13,4072554_B_4 Dunkirk Generating Station NY 185 2 33 13,487
51

2682_B_10 S A Carlson NY 15 1 19 5,8982682_B_12 S A Carlson NY 15 1 19 5,960

2682_B_9 S A Carlson NY 15 1 19 5,9602706_B_1 Asheville NC 191 1 53 42,2452706_B_2 Asheville NC 185 1 53 41,9972708_B_5 Cape Fear NC 144 1 67 48,1012708_B_6 Cape Fear NC 172 1 67 52,4152709_B_1 Lee NC 74 1 85 49,5972709_B_2 Lee NC 77 1 85 49,4002709_B_3 Lee NC 248 3 336 175,0132712_B_1 Roxboro NC 369 4 318 165,5742712_B_2 Roxboro NC 671 5 501 358,153

2712_B_3A Roxboro NC 353 4 318 179,2092712_B_3B Roxboro NC 353 4 318 164,6142712_B_4A Roxboro NC 349 4 318 192,4952712_B_4B Roxboro NC 349 4 318 180,621

2713_B_1 L V Sutton NC 93 2 333 159,3332713_B_2 L V Sutton NC 102 2 333 157,2212713_B_3 L V Sutton NC 403 4 767 480,9392716_B_1 W H Weatherspoon NC 48 1 119 60,9152716_B_2 W H Weatherspoon NC 49 1 119 61,0842716_B_3 W H Weatherspoon NC 76 1 119 69,7862718_B_1 G G Allen NC 162 1 15 11,2862718_B_2 G G Allen NC 162 1 15 11,2752718_B_3 G G Allen NC 260 1 15 13,2582718_B_4 G G Allen NC 275 1 15 13,4562718_B_5 G G Allen NC 265 1 15 13,3992720_B_5 Buck NC 38 1 10 4,7632720_B_6 Buck NC 38 1 10 4,7632720_B_7 Buck NC 38 1 10 4,763
52

2720_B_8 Buck NC 128 1 10 6,7752720_B_9 Buck NC 128 1 10 6,7992721_B_5 Cliffside NC 550 2 126 78,1262721_B_6 Cliffside NC 800 3 267 156,4132723_B_1 Dan River NC 67 1 1 5922723_B_2 Dan River NC 67 1 1 5862723_B_3 Dan River NC 142 2 2 9652727_B_1 Marshall NC 378 2 85 54,7852727_B_2 Marshall NC 378 2 85 54,8322727_B_3 Marshall NC 657 2 85 58,6672727_B_4 Marshall NC 657 2 85 58,648

2732_B_10 Riverbend NC 133 1 8 5,849

2732_B_7 Riverbend NC 94 1 8 5,2262732_B_8 Riverbend NC 94 1 8 5,2762732_B_9 Riverbend NC 133 1 8 5,828

2790_B_B1 R M Heskett ND 29 1 5 2,1732790_B_B2 R M Heskett ND 76 1 5 3,036

2817_B_1 Leland Olds ND 221 1 26 23,1492817_B_2 Leland Olds ND 448 2 59 50,234

2823_B_B1 Milton R Young ND 250 1 23 21,2462823_B_B2 Milton R Young ND 455 2 52 44,411

2824_B_1 Stanton ND 130 1 26 18,738

2824_B_10 Stanton ND 57 1 26 13,452

2828_B_1 Cardinal OH 600 3 58 44,8992828_B_2 Cardinal OH 600 3 58 46,2582828_B_3 Cardinal OH 630 3 58 49,4342830_B_1 Walter C Beckjord OH 94 1 7 4,0252830_B_2 Walter C Beckjord OH 94 1 7 3,9572830_B_3 Walter C Beckjord OH 128 1 7 4,4042830_B_4 Walter C Beckjord OH 150 1 7 4,620
53

2830_B_5 Walter C Beckjord OH 238 1 7 5,5662830_B_6 Walter C Beckjord OH 414 2 39 13,2522832_B_6 Miami Fort OH 163 2 31 15,3202832_B_7 Miami Fort OH 500 2 31 26,9782832_B_8 Miami Fort OH 500 2 31 26,7952835_B_7 Ashtabula OH 244 3 147 73,712

2836_B_10 Avon Lake OH 96 2 94 49,6282836_B_12 Avon Lake OH 640 4 251 192,073

2837_B_1 Eastlake OH 132 2 121 68,7782837_B_2 Eastlake OH 132 2 121 68,2752837_B_3 Eastlake OH 132 2 121 67,4092837_B_4 Eastlake OH 240 3 187 98,8972837_B_5 Eastlake OH 597 3 187 146,553

2838_B_18 Lake Shore OH 245 2 110 81,148

2840_B_3 Conesville OH 165 2 17 5,1792840_B_4 Conesville OH 780 3 36 34,4792840_B_5 Conesville OH 375 2 17 13,8982840_B_6 Conesville OH 375 2 17 13,8062843_B_9 Picway OH 95 1 2 1,213

2848_B_H-1 O H Hutchings OH 58 1 3 1,5412848_B_H-2 O H Hutchings OH 55 1 3 1,4892848_B_H-3 O H Hutchings OH 63 1 3 1,5282848_B_H-4 O H Hutchings OH 63 1 3 1,5032848_B_H-5 O H Hutchings OH 63 1 3 1,5752848_B_H-6 O H Hutchings OH 63 1 3 1,578

2850_B_1 J M Stuart OH 597 2 33 34,9982850_B_2 J M Stuart OH 597 2 33 34,3592850_B_3 J M Stuart OH 597 2 33 33,7092850_B_4 J M Stuart OH 597 2 33 34,7912861_B_1 Niles OH 108 1 16 10,610
54

2861_B_2 Niles OH 108 1 16 10,5372864_B_7 R E Burger OH 156 1 1 1,0362864_B_8 R E Burger OH 156 1 1 1,0582866_B_1 W H Sammis OH 180 1 12 9,2982866_B_2 W H Sammis OH 180 1 12 9,3392866_B_3 W H Sammis OH 180 1 12 9,2572866_B_4 W H Sammis OH 180 1 12 9,2322866_B_5 W H Sammis OH 300 2 30 18,7662866_B_6 W H Sammis OH 600 4 69 46,0522866_B_7 W H Sammis OH 600 4 69 46,3072872_B_1 Muskingum River OH 190 1 4 3,4812872_B_2 Muskingum River OH 190 1 4 3,4562872_B_3 Muskingum River OH 205 1 4 3,5262872_B_4 Muskingum River OH 205 1 4 3,4272872_B_5 Muskingum River OH 585 2 18 15,8222876_B_1 Kyger Creek OH 217 1 17 13,7592876_B_2 Kyger Creek OH 217 1 17 13,8222876_B_3 Kyger Creek OH 217 1 17 13,8222876_B_4 Kyger Creek OH 217 1 17 13,8742876_B_5 Kyger Creek OH 217 1 17 13,8012878_B_1 Bay Shore OH 136 2 29 15,6702878_B_2 Bay Shore OH 138 2 29 16,1662878_B_3 Bay Shore OH 142 2 29 16,1072878_B_4 Bay Shore OH 215 2 29 18,700

2908_G_10 Lake Road OH 25 1 45 17,8692908_G_11 Lake Road OH 85 2 110 47,569

2908_G_8 Lake Road OH 25 1 45 17,8692908_G_9 Lake Road OH 25 1 45 17,8692914_G_3 Dover OH 8 1 13 3,409

2914_B_4 Dover OH 15 1 13 4,595
55

2917_B_8 Hamilton OH 33 1 4 1,8822917_B_9 Hamilton OH 51 1 4 2,128

2935_B_10 Orrville OH 13 1 20 6,4882935_B_11 Orrville OH 13 1 20 6,4882935_B_12 Orrville OH 30 1 20 7,8992935_B_13 Orrville OH 23 1 20 7,178

2936_B_3 Painesville OH 11 1 58 16,2312936_B_4 Painesville OH 22 1 58 22,3012936_B_5 Painesville OH 22 1 58 20,9022937_B_4 Piqua OH 12 1 17 5,4112937_B_5 Piqua OH 12 1 17 5,2962937_B_6 Piqua OH 20 1 17 6,4292942_B_5 St Marys OH 6 1 26 6,3202942_B_6 St Marys OH 9 1 26 7,0052943_B_1 Shelby Municipal Light Plant OH 12 1 3 1,0192943_B_2 Shelby Municipal Light Plant OH 12 1 3 1,041

2943_G_4 Shelby Municipal Light Plant OH 7 1 3 866

2952_B_4 Muskogee OK 511 4 136 96,8292952_B_5 Muskogee OK 522 4 136 96,9222952_B_6 Muskogee OK 515 4 136 95,749

2963_B_3313 Northeastern OK 450 3 57 44,7402963_B_3314 Northeastern OK 450 3 57 44,806

3098_B_1 Elrama PA 94 1 3 2,0863098_B_2 Elrama PA 94 1 3 2,0993098_B_3 Elrama PA 103 1 3 2,1643098_B_4 Elrama PA 174 2 11 5,4963113_B_1 Portland PA 157 1 10 7,3553113_B_2 Portland PA 243 1 10 8,6163115_B_1 Titus PA 81 1 11 6,1523115_B_2 Titus PA 81 1 11 6,188
56

3115_B_3 Titus PA 81 1 11 6,1643118_B_1 Conemaugh PA 850 3 44 28,4783118_B_2 Conemaugh PA 850 3 44 28,4783122_B_1 Homer City Station PA 620 2 10 9,0773122_B_2 Homer City Station PA 614 2 10 8,9783122_B_3 Homer City Station PA 650 2 10 9,2073130_B_1 Seward PA 261 1 2 1,6293130_B_2 Seward PA 261 1 2 1,6683131_B_1 Shawville PA 122 1 10 7,2003131_B_2 Shawville PA 125 1 10 7,2943131_B_3 Shawville PA 175 1 10 8,0713131_B_4 Shawville PA 175 1 10 8,0713136_B_1 Keystone PA 850 3 19 16,6453136_B_2 Keystone PA 850 3 19 16,4883138_B_3 New Castle PA 94 1 3 1,7193138_B_4 New Castle PA 98 1 3 1,6703138_B_5 New Castle PA 134 1 3 1,9663140_B_1 PPL Brunner Island PA 344 2 7 4,6133140_B_2 PPL Brunner Island PA 397 2 7 5,1273140_B_3 PPL Brunner Island PA 754 3 34 29,2733149_B_1 PPL Montour PA 750 3 99 78,5613149_B_2 PPL Montour PA 750 3 99 78,561

3152_B_1A Sunbury Generation LP PA 40 1 26 12,1903152_B_1B Sunbury Generation LP PA 40 1 26 12,1903152_B_2A Sunbury Generation LP PA 40 1 26 12,1903152_B_2B Sunbury Generation LP PA 40 1 26 12,190

3152_B_3 Sunbury Generation LP PA 87 1 26 16,3563152_B_4 Sunbury Generation LP PA 128 1 26 18,9173161_B_2 Eddystone Generating Station PA 309 3 13 7,7883178_B_1 Armstrong Power Station PA 172 1 11 8,120
57

3178_B_2 Armstrong Power Station PA 171 1 11 8,1053179_B_1 Hatfields Ferry Power Station PA 530 2 8 7,2273179_B_2 Hatfields Ferry Power Station PA 530 2 8 7,1943179_B_3 Hatfields Ferry Power Station PA 530 2 8 7,304

3181_B_33 Mitchell Power Station PA 277 3 27 11,206

3251_B_1 H B Robinson SC 176 1 87 66,2023264_B_1 W S Lee SC 100 1 1 8783264_B_2 W S Lee SC 100 1 1 8763264_B_3 W S Lee SC 170 1 1 1,039

3280_B_CAN1 Canadys Steam SC 105 2 210 94,4193280_B_CAN2 Canadys Steam SC 116 2 210 98,6983280_B_CAN3 Canadys Steam SC 175 2 210 125,031

3287_B_MCM1 McMeekin SC 125 1 71 47,5423287_B_MCM2 McMeekin SC 125 1 71 48,485

3295_B_URQ3 Urquhart SC 94 2 107 34,2573297_B_WAT1 Wateree SC 350 2 200 149,2543297_B_WAT2 Wateree SC 350 2 200 147,815

3298_B_WIL1 Williams SC 615 2 259 213,418

3317_B_1 Dolphus M Grainger SC 85 1 158 94,7433317_B_2 Dolphus M Grainger SC 85 1 158 95,2513319_B_3 Jefferies SC 153 1 99 74,1843319_B_4 Jefferies SC 153 1 99 73,9603325_B_1 Ben French SD 22 1 108 40,4263393_B_1 Allen Steam Plant TN 245 2 33 21,9383393_B_2 Allen Steam Plant TN 245 2 33 21,9383393_B_3 Allen Steam Plant TN 245 2 33 21,9383396_B_1 Bull Run TN 881 3 204 205,9713399_B_1 Cumberland TN 1,232 3 81 80,2483399_B_2 Cumberland TN 1,233 3 81 80,2833403_B_1 Gallatin TN 222 1 2 1,928
58

3403_B_2 Gallatin TN 222 1 2 1,9283403_B_3 Gallatin TN 260 1 2 2,0583403_B_4 Gallatin TN 260 1 2 2,0583405_B_1 John Sevier TN 176 2 139 78,1363405_B_2 John Sevier TN 176 2 139 78,1363405_B_3 John Sevier TN 176 2 139 78,1363405_B_4 John Sevier TN 176 2 139 78,1363406_B_1 Johnsonville TN 106 1 19 12,724

3406_B_10 Johnsonville TN 141 1 19 13,566

3406_B_2 Johnsonville TN 106 1 19 12,7243406_B_3 Johnsonville TN 106 1 19 12,7243406_B_4 Johnsonville TN 106 1 19 12,7243406_B_5 Johnsonville TN 106 1 19 12,3423406_B_6 Johnsonville TN 106 1 19 12,3423406_B_7 Johnsonville TN 141 1 19 13,5663406_B_8 Johnsonville TN 141 1 19 13,5663406_B_9 Johnsonville TN 141 1 19 13,5663407_B_1 Kingston TN 134 2 97 36,6223407_B_2 Kingston TN 134 2 97 36,6223407_B_3 Kingston TN 134 2 97 36,6223407_B_4 Kingston TN 134 2 97 36,6223407_B_5 Kingston TN 175 2 97 51,6493407_B_6 Kingston TN 175 2 97 51,6493407_B_7 Kingston TN 175 2 97 51,6493407_B_8 Kingston TN 175 2 97 51,6493407_B_9 Kingston TN 175 2 97 51,649

3470_B_WAP5 W A Parish TX 645 3 6 2,6863470_B_WAP6 W A Parish TX 650 3 6 2,9743470_B_WAP7 W A Parish TX 565 2 1 1,1323470_B_WAP8 W A Parish TX 600 2 1 1,192
59

3497_B_1 Big Brown TX 575 2 13 5,8243497_B_2 Big Brown TX 575 2 13 5,4473644_B_1 Carbon UT 67 1 7 3,7793644_B_2 Carbon UT 105 2 67 27,8823775_B_1 Clinch River VA 235 3 164 88,9263775_B_2 Clinch River VA 235 3 164 89,7313775_B_3 Clinch River VA 235 3 164 88,097

3776_B_51 Glen Lyn VA 45 1 17 8,7723776_B_52 Glen Lyn VA 45 1 17 8,772

3776_B_6 Glen Lyn VA 235 2 49 32,2503788_B_1 Potomac River VA 88 1 10 6,5693788_B_2 Potomac River VA 88 1 10 6,1373788_B_3 Potomac River VA 102 1 10 6,1373788_B_4 Potomac River VA 102 1 10 6,1953788_B_5 Potomac River VA 102 1 10 6,2523796_B_3 Bremo Bluff VA 71 1 13 7,8563796_B_4 Bremo Bluff VA 156 1 13 9,8093797_B_3 Chesterfield VA 100 1 5 3,0933797_B_4 Chesterfield VA 166 2 55 25,4053797_B_5 Chesterfield VA 310 3 142 88,7323797_B_6 Chesterfield VA 658 4 229 159,6563803_B_1 Chesapeake VA 111 2 116 56,7443803_B_2 Chesapeake VA 111 2 116 59,2623803_B_3 Chesapeake VA 156 2 116 66,2533803_B_4 Chesapeake VA 217 3 228 109,1963809_B_1 Yorktown VA 159 2 120 61,7693809_B_2 Yorktown VA 164 2 120 63,285

3845_B_BW21 Transalta Centralia Generation WA 703 2 158 162,0433845_B_BW22 Transalta Centralia Generation WA 703 2 158 162,043

3935_B_1 John E Amos WV 800 3 33 25,455
60

3935_B_2 John E Amos WV 800 3 33 25,5253935_B_3 John E Amos WV 1,300 4 76 54,3593936_B_1 Kanawha River WV 205 2 21 10,0043936_B_2 Kanawha River WV 205 2 21 9,969

3938_B_11 Philip Sporn WV 150 2 28 16,3003938_B_21 Philip Sporn WV 150 2 28 16,0523938_B_31 Philip Sporn WV 150 2 28 15,9823938_B_41 Philip Sporn WV 150 2 28 15,8663938_B_51 Philip Sporn WV 450 2 28 25,116

3942_B_1 Albright WV 73 2 20 5,9463942_B_2 Albright WV 73 2 20 5,9463942_B_3 Albright WV 137 2 20 10,6073943_B_1 Fort Martin Power Station WV 552 2 22 20,8563943_B_2 Fort Martin Power Station WV 555 2 22 20,8713944_B_1 Harrison Power Station WV 652 5 89 62,8423944_B_2 Harrison Power Station WV 642 5 89 62,9553944_B_3 Harrison Power Station WV 651 5 89 62,5903945_B_7 Rivesville WV 46 2 32 12,4433945_B_8 Rivesville WV 91 2 32 16,2193946_B_1 Willow Island WV 54 1 3 1,9143946_B_2 Willow Island WV 181 2 24 16,8153947_B_1 Kammer WV 210 1 1 4883947_B_2 Kammer WV 210 1 1 4883947_B_3 Kammer WV 210 1 1 4883948_B_1 Mitchell WV 800 3 5 4,3853948_B_2 Mitchell WV 800 3 5 4,3753954_B_1 Mt Storm WV 524 4 152 85,6133954_B_2 Mt Storm WV 524 4 152 86,7263954_B_3 Mt Storm WV 521 3 92 74,9023992_B_7 Blount Street WI 22 1 29 11,189
61

3992_B_8 Blount Street WI 49 1 29 13,9133992_B_9 Blount Street WI 48 1 29 13,8244041_B_5 South Oak Creek WI 261 2 45 30,6554041_B_6 South Oak Creek WI 264 2 45 30,9674041_B_7 South Oak Creek WI 298 2 45 33,0644041_B_8 South Oak Creek WI 312 2 45 33,4864042_B_1 Valley WI 70 1 5 3,0474042_B_2 Valley WI 70 1 5 3,0474042_B_3 Valley WI 70 1 5 3,0264042_B_4 Valley WI 70 1 5 3,0264050_B_3 Edgewater WI 76 1 30 17,9414050_B_4 Edgewater WI 321 2 84 55,8044050_B_5 Edgewater WI 414 3 174 100,5114054_B_1 Nelson Dewey WI 107 2 58 29,3224054_B_2 Nelson Dewey WI 111 2 58 29,6434072_B_5 Pulliam WI 49 1 10 5,0814072_B_6 Pulliam WI 72 2 118 19,0514072_B_7 Pulliam WI 88 2 118 36,9094072_B_8 Pulliam WI 133 2 118 59,3244078_B_1 Weston WI 62 1 73 42,3024078_B_2 Weston WI 86 2 204 76,8914078_B_3 Weston WI 338 4 535 305,9394078_B_4 Weston WI 519 4 535 357,4974125_B_5 Manitowoc WI 2 1 28 3,8014125_B_6 Manitowoc WI 18 1 28 9,6524125_B_7 Manitowoc WI 18 1 28 9,2624125_B_8 Manitowoc WI 21 1 28 9,7264125_B_9 Manitowoc WI 30 1 28 11,2364127_B_5 Menasha WI 7 1 10 2,268

4127_B_B23 Menasha WI 9 1 10 2,770
62

4127_B_B24 Menasha WI 15 1 10 3,373

4140_B_B1 Alma WI 18 1 57 19,7674140_B_B2 Alma WI 18 1 57 19,7674140_B_B3 Alma WI 21 1 57 21,2214140_B_B4 Alma WI 51 1 57 28,8034140_B_B5 Alma WI 77 1 57 33,564

4143_B_1 Genoa WI 356 2 142 98,8444150_B_5 Neil Simpson WY 15 1 22 7,6814151_B_1 Osage WY 10 1 73 22,1204151_B_2 Osage WY 10 1 73 22,1204151_B_3 Osage WY 10 1 73 22,120

4158_B_BW41 Dave Johnston WY 106 1 8 5,4474158_B_BW42 Dave Johnston WY 106 1 8 5,4404158_B_BW43 Dave Johnston WY 220 1 8 7,1554158_B_BW44 Dave Johnston WY 330 1 8 8,291

4162_B_1 Naughton WY 160 1 36 27,6294162_B_2 Naughton WY 210 1 36 30,4594162_B_3 Naughton WY 330 3 186 95,1984259_B_1 Endicott Station MI 50 1 16 8,147

4271_B_B1 John P Madgett WI 398 2 138 97,551

4941_B_1 Navajo AZ 750 3 348 312,6534941_B_2 Navajo AZ 750 3 348 311,7414941_B_3 Navajo AZ 750 3 348 308,7396002_B_1 James H Miller Jr AL 684 2 73 72,4536002_B_2 James H Miller Jr AL 687 2 73 72,3256002_B_3 James H Miller Jr AL 687 2 73 72,3896002_B_4 James H Miller Jr AL 688 2 73 72,1636004_B_1 Pleasants Power Station WV 639 2 31 34,6296004_B_2 Pleasants Power Station WV 639 2 31 34,5116009_B_1 White Bluff AR 815 3 30 29,247
63

6009_B_2 White Bluff AR 825 3 30 29,9046016_B_1 Duck Creek IL 335 2 80 65,0456017_B_1 Newton IL 557 2 32 21,2566017_B_2 Newton IL 569 2 32 21,2186018_B_2 East Bend KY 600 3 81 60,0696019_B_1 W H Zimmer OH 1,300 4 129 110,317

6021_B_C1 Craig CO 428 3 62 43,7256021_B_C2 Craig CO 428 3 62 44,0076021_B_C3 Craig CO 418 3 62 43,820

6030_B_1 Coal Creek ND 554 2 85 58,2526030_B_2 Coal Creek ND 560 2 85 78,6186031_B_2 Killen Station OH 615 2 36 32,4016034_B_1 Belle River MI 698 4 115 57,9296034_B_2 Belle River MI 698 4 115 65,8826041_B_1 H L Spurlock KY 315 2 43 34,2996041_B_2 H L Spurlock KY 509 2 43 43,8546041_B_3 H L Spurlock KY 268 2 43 31,6866041_B_4 H L Spurlock KY 268 2 43 30,4436052_B_1 Wansley GA 891 3 205 125,3796052_B_2 Wansley GA 892 3 205 125,632

6055_B_2B1 Big Cajun 2 LA 580 2 3 2,5616055_B_2B2 Big Cajun 2 LA 575 2 3 2,5556055_B_2B3 Big Cajun 2 LA 588 2 3 2,531

6061_B_1 R D Morrow MS 180 1 8 6,7316061_B_2 R D Morrow MS 180 1 8 6,804

6064_B_N1 Nearman Creek KS 229 2 36 19,542

6065_B_1 Iatan MO 651 2 23 23,9066068_B_1 Jeffrey Energy Center KS 730 2 89 85,2856068_B_2 Jeffrey Energy Center KS 730 2 89 86,2546068_B_3 Jeffrey Energy Center KS 730 2 89 88,473
64

6071_B_1 Trimble County KY 383 3 142 97,287

6071_B_2&3 Trimble County KY 760 3 142 115,264

6073_B_1 Victor J Daniel Jr MS 514 2 6 5,0206073_B_2 Victor J Daniel Jr MS 514 2 6 5,0006076_B_1 Colstrip MT 307 2 261 184,8566076_B_2 Colstrip MT 307 2 261 184,8566076_B_3 Colstrip MT 740 2 261 288,1526076_B_4 Colstrip MT 740 2 261 288,1526077_B_1 Gerald Gentleman NE 665 2 33 32,4106077_B_2 Gerald Gentleman NE 700 2 33 31,4786082_B_1 AES Somerset LLC NY 681 6 278 170,834

6085_B_14 R M Schahfer IN 431 2 36 31,6486085_B_15 R M Schahfer IN 472 2 36 32,8926085_B_17 R M Schahfer IN 361 2 36 29,4626085_B_18 R M Schahfer IN 361 2 36 29,060

6089_B_B1 Lewis & Clark MT 52 1 19 10,381

6090_B_1 Sherburne County MN 762 4 230 186,5876090_B_2 Sherburne County MN 752 4 230 181,9606090_B_3 Sherburne County MN 936 4 230 209,3436094_B_1 Bruce Mansfield PA 830 5 83 68,9456094_B_2 Bruce Mansfield PA 830 5 83 68,6396094_B_3 Bruce Mansfield PA 830 5 83 67,5386095_B_1 Sooner OK 535 5 237 138,7366095_B_2 Sooner OK 540 5 237 148,7086096_B_1 Nebraska City NE 646 2 45 44,2466096_B_2 Nebraska City NE 663 2 17 15,6236098_B_1 Big Stone SD 470 2 75 63,989

6101_B_BW91 Wyodak WY 335 3 207 123,430

6106_B_1SG Boardman OR 585 3 292 156,464

6113_B_1 Gibson IN 630 3 73 64,635
65

6113_B_2 Gibson IN 628 3 73 64,6906113_B_3 Gibson IN 628 3 73 64,1576113_B_4 Gibson IN 622 3 73 64,5446113_B_5 Gibson IN 620 3 73 65,5156124_B_1 McIntosh GA 157 2 174 98,0236136_B_1 Gibbons Creek TX 462 2 8 6,1096137_B_1 A B Brown IN 245 3 51 27,6526137_B_2 A B Brown IN 245 3 51 27,6526138_B_1 Flint Creek AR 528 6 303 183,9566139_B_1 Welsh TX 528 2 26 23,2656139_B_2 Welsh TX 528 2 26 22,9536139_B_3 Welsh TX 528 2 26 22,9776146_B_1 Martin Lake TX 750 4 16 13,5796146_B_2 Martin Lake TX 750 4 16 13,4226146_B_3 Martin Lake TX 750 4 16 13,1966147_B_1 Monticello TX 565 2 27 25,8106147_B_2 Monticello TX 565 2 27 25,6486147_B_3 Monticello TX 750 3 41 37,0726155_B_1 Rush Island MO 604 4 218 158,8856155_B_2 Rush Island MO 604 4 218 153,1866165_B_1 Hunter UT 430 2 94 81,1866165_B_2 Hunter UT 430 2 94 81,0036165_B_3 Hunter UT 460 2 94 83,041

6166_B_MB1 Rockport IN 1,300 4 142 138,1456166_B_MB2 Rockport IN 1,300 4 142 138,981

6170_B_1 Pleasant Prairie WI 617 3 72 55,2556170_B_2 Pleasant Prairie WI 617 3 72 55,822

6177_B_U1B Coronado AZ 395 2 132 108,8476177_B_U2B Coronado AZ 390 2 132 105,111

6178_B_1 Coleto Creek TX 632 4 26 21,145
66

6179_B_1 Fayette Power Project TX 598 5 98 65,1086179_B_2 Fayette Power Project TX 598 5 98 64,4826179_B_3 Fayette Power Project TX 445 4 64 44,478

6180_B_OG1 Oak Grove TX 800 6 190 85,2416180_B_OG2 Oak Grove TX 800 6 190 85,241

6181_B_1 J T Deely TX 385 2 30 27,7956181_B_2 J T Deely TX 385 2 30 27,756

6183_B_SM-1 San Miguel TX 391 3 62 45,994

6190_B_2 Rodemacher LA 523 2 27 25,318

6190_B_3A Rodemacher LA 330 1 5 5,0116190_B_3B Rodemacher LA 330 1 5 5,011

6193_B_061B Harrington TX 347 4 42 22,9966193_B_062B Harrington TX 347 4 42 24,4246193_B_063B Harrington TX 347 4 42 24,8636194_B_171B Tolk TX 535 2 24 21,6816194_B_172B Tolk TX 545 2 24 21,315

6195_B_1 Southwest Power Station MO 178 3 224 115,2616204_B_1 Laramie River Station WY 565 4 154 86,9616204_B_2 Laramie River Station WY 570 4 154 83,3316204_B_3 Laramie River Station WY 570 4 154 92,413

6213_B_1SG1 Merom IN 507 2 65 62,6066213_B_2SG1 Merom IN 493 2 65 64,220

6225_B_1 Jasper 2 IN 14 1 3 866

6238_B_1A Pearl Station IL 22 1 6 2,112

6248_B_1 Pawnee CO 505 2 13 8,9216249_B_1 Winyah SC 295 1 130 121,7326249_B_2 Winyah SC 295 1 130 122,7226249_B_3 Winyah SC 295 1 130 121,3336249_B_4 Winyah SC 270 1 130 120,256

6250_B_1A Mayo NC 371 4 320 194,458
67

6250_B_1B Mayo NC 371 4 320 194,458

6254_B_1 Ottumwa IA 673 2 116 87,7046257_B_1 Scherer GA 837 3 233 241,7676257_B_2 Scherer GA 843 3 233 243,0156257_B_3 Scherer GA 875 3 233 247,5956257_B_4 Scherer GA 850 3 233 243,8746264_B_1 Mountaineer WV 1,300 3 50 51,914

6469_B_B1 Antelope Valley ND 450 2 59 50,2626469_B_B2 Antelope Valley ND 450 2 59 50,577

6481_B_1SGA Intermountain Power Project UT 900 3 233 158,2996481_B_2SGA Intermountain Power Project UT 900 3 233 158,299

6639_B_G1 R D Green KY 231 2 8 5,7476639_B_G2 R D Green KY 233 2 8 5,770

6641_B_1 Independence AR 836 4 47 37,2546641_B_2 Independence AR 842 4 47 37,1716648_B_4 Sandow TX 545 4 107 74,584

6664_B_101 Louisa IA 745 2 59 61,830

6705_B_1 Warrick IN 136 2 17 9,5096705_B_2 Warrick IN 136 2 17 9,5236705_B_3 Warrick IN 136 2 17 9,5376705_B_4 Warrick IN 300 2 17 12,924

6761_B_101 Rawhide CO 272 2 18 12,342

6768_B_1 Sikeston Power Station MO 233 2 36 23,6256772_B_1 Hugo OK 440 2 67 58,910

6823_B_W1 D B Wilson KY 420 2 49 36,972

7030_B_U1 Twin Oaks Power One TX 152 2 13 5,9217030_B_U2 Twin Oaks Power One TX 153 2 13 6,858

7097_B_BLR1 J K Spruce TX 555 3 58 44,9967097_B_BLR2 J K Spruce TX 750 3 58 48,312

7210_B_COP1 Cope SC 420 2 177 152,775
68

7213_B_1 Clover VA 431 4 280 187,9897213_B_2 Clover VA 434 5 431 217,508

7242_G_1CA Polk FL 123 1 1 689

7242_G_1CT Polk FL 132 1 1 708

7286_B_1 Richard Gorsuch OH 50 1 5 2,6527286_B_2 Richard Gorsuch OH 50 1 5 2,6527286_B_3 Richard Gorsuch OH 50 1 5 2,6527286_B_4 Richard Gorsuch OH 50 1 5 2,6527343_B_4 George Neal South IA 632 2 94 100,8887504_B_2 Neil Simpson II WY 80 1 23 13,829

7537_B_1A North Branch WV 37 1 10 4,4567537_B_1B North Branch WV 37 1 10 4,315

7549_B_1 Milwaukee County WI 3 1 5 1,0017549_B_2 Milwaukee County WI 3 1 5 9587549_B_3 Milwaukee County WI 3 1 5 958

7652_B_D-1 US DOE Savannah River Site (D Area) SC 20 1 30 10,4557652_B_D-2 US DOE Savannah River Site (D Area) SC 20 1 30 10,4557652_B_D-3 US DOE Savannah River Site (D Area) SC 20 1 30 10,4557652_B_D-4 US DOE Savannah River Site (D Area) SC 20 1 30 10,455

7737_B_B001 Cogen South SC 90 1 82 50,925

7790_B_1-1 Bonanza UT 468 5 75 40,737

7902_B_1 Pirkey TX 675 2 4 4,2468023_B_1 Columbia WI 555 4 306 219,5308023_B_2 Columbia WI 559 4 306 214,9928042_B_1 Belews Creek NC 1,115 3 122 76,5538042_B_2 Belews Creek NC 1,115 3 122 76,537

8066_B_BW71 Jim Bridger WY 530 2 3 2,4118066_B_BW72 Jim Bridger WY 530 2 3 2,4188066_B_BW73 Jim Bridger WY 530 2 3 2,4048066_B_BW74 Jim Bridger WY 530 2 3 2,417
69

8069_B_1 Huntington UT 445 2 68 63,2478069_B_2 Huntington UT 450 2 68 63,4348102_B_1 General James M Gavin OH 1,310 3 52 49,7308102_B_2 General James M Gavin OH 1,300 3 52 49,4308219_B_1 Ray D Nixon CO 208 2 130 91,347

8222_B_B1 Coyote ND 427 2 59 50,345

8223_B_1 Springerville AZ 400 2 170 137,8938223_B_2 Springerville AZ 400 2 170 137,3368223_B_3 Springerville AZ 400 2 170 142,7958223_B_4 Springerville AZ 400 2 170 131,2498224_B_1 North Valmy NV 254 3 420 246,9058224_B_2 North Valmy NV 268 3 420 262,6648226_B_1 Cheswick PA 580 3 30 23,108

10002_B_CFB ACE Cogeneration Facility CA 101 1 55 36,115

10003_B_BLR3 Trigen Colorado Energy CO 8 1 17 4,22410003_B_BLR4 Trigen Colorado Energy CO 8 1 17 4,22410003_B_BLR5 Trigen Colorado Energy CO 8 1 17 4,462

10030_B_COGEN1 NRG Energy Center Dover DE 16 1 41 13,762

10043_B_B01 Logan Generating Plant NJ 219 3 7 3,257

10071_B_1A Cogentrix Virginia Leasing Corporation VA 19 1 53 18,67510071_B_1B Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966

10071_B_1C Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966

10071_B_2A Cogentrix Virginia Leasing Corporation VA 19 1 53 18,67510071_B_2B Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966

10071_B_2C Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966

10075_B_1 Taconite Harbor Energy Center MN 65 1 77 43,87310075_B_2 Taconite Harbor Energy Center MN 67 1 77 44,05610075_B_3 Taconite Harbor Energy Center MN 68 1 77 44,508

10113_B_CFB1 John B Rich Memorial Power Station PA 40 1 22 10,16610113_B_CFB2 John B Rich Memorial Power Station PA 40 1 22 9,865
70

10143_B_ABB01 Colver Power Project PA 110 2 16 7,296

10151_B_BLR1A Grant Town Power Plant WV 40 1 14 6,23010151_B_BLR1B Grant Town Power Plant WV 40 1 14 6,068

10207_B_1 Hercules Missouri Chemical Works MO 6 1 3 66810207_B_2 Hercules Missouri Chemical Works MO 6 1 3 66810207_B_3 Hercules Missouri Chemical Works MO 6 1 3 66810333_B_1 Central Power & Lime FL 139 1 5 3,407

10343_B_SG-101 Foster Wheeler Mt Carmel Cogen PA 43 1 22 10,975

10367_B_CB1302 East Third Street Power Plant CA 20 1 4 1,39710368_B_CB1302 Loveridge Road Power Plant CA 19 1 3 1,25010369_B_CB1302 Wilbur West Power Plant CA 19 1 2 64410370_B_CB1302 Wilbur East Power Plant CA 19 1 3 1,04310371_B_CB1302 Nichols Road Power Plant CA 19 1 3 1,29810373_B_CB1302 Hanford CA 25 1 22 8,730

10377_B_1A Cogentrix Hopewell VA 18 1 10 3,41710377_B_1B Cogentrix Hopewell VA 18 1 10 3,531

10377_B_1C Cogentrix Hopewell VA 18 1 10 3,417

10377_B_2A Cogentrix Hopewell VA 18 1 10 3,53110377_B_2B Cogentrix Hopewell VA 18 1 10 3,417

10377_B_2C Cogentrix Hopewell VA 18 1 10 3,417

10378_B_1A Primary Energy Southport NC 18 1 173 59,58510378_B_1B Primary Energy Southport NC 18 1 173 57,630

10378_B_1C Primary Energy Southport NC 18 1 173 57,630

10378_B_2A Primary Energy Southport NC 18 1 173 59,58510378_B_2B Primary Energy Southport NC 18 1 173 57,630

10378_B_2C Primary Energy Southport NC 18 1 173 57,630

10379_B_1A Primary Energy Roxboro NC 19 1 24 8,35510379_B_1B Primary Energy Roxboro NC 19 1 24 8,092

10379_B_1C Primary Energy Roxboro NC 19 1 24 8,092

10380_B_A BLR Elizabethtown Power LLC NC 16 1 129 42,742
71

10380_B_B BLR Elizabethtown Power LLC NC 16 1 129 42,742

10382_B_UNIT1 Lumberton NC 16 1 118 39,36610382_B_UNIT2 Lumberton NC 16 1 118 39,366

10384_B_1A Edgecombe GenCo NC 29 1 36 14,98910384_B_1B Edgecombe GenCo NC 29 1 36 14,53410384_B_2A Edgecombe GenCo NC 29 1 36 14,98910384_B_2B Edgecombe GenCo NC 29 1 36 14,534

10464_B_E0001 Black River Generation NY 18 1 27 9,34010464_B_E0002 Black River Generation NY 18 1 27 8,97110464_B_E0003 Black River Generation NY 18 1 27 8,971

10477_B_P1 Wisconsin Rapids Pulp Mill WI 11 1 80 22,28710477_B_P2 Wisconsin Rapids Pulp Mill WI 11 1 80 22,287

10495_B_6 Rumford Cogeneration ME 43 1 24 11,29310495_B_7 Rumford Cogeneration ME 43 1 24 10,978

10566_B_BOIL1 Chambers Cogeneration LP NJ 131 2 17 9,09310566_B_BOIL2 Chambers Cogeneration LP NJ 131 2 17 9,23810601_G_GEN1 BP Wilmington Calciner CA 29 1 3 1,039

10603_B_031 Ebensburg Power PA 50 1 4 2,168

10641_B_B1 Cambria Cogen PA 44 1 3 1,42610641_B_B2 Cambria Cogen PA 44 1 3 1,388

10670_B_AAB001 AES Deepwater TX 140 2 0 184

10671_B_1A AES Shady Point OK 80 1 3 1,97310671_B_1B AES Shady Point OK 80 1 3 1,96510671_B_2A AES Shady Point OK 80 1 3 1,97310671_B_2B AES Shady Point OK 80 1 3 1,965

10672_B_CBA Cedar Bay Generating LP FL 83 1 20 11,32110672_B_CBB Cedar Bay Generating LP FL 83 1 20 11,679

10672_B_CBC Cedar Bay Generating LP FL 83 1 20 11,679

10675_B_A AES Thames CT 91 1 26 15,60010675_B_B AES Thames CT 91 1 26 15,682
72

10676_B_2 AES Beaver Valley Partners Beaver V ll PA 43 1 4 2,10010676_B_3 AES Beaver Valley Partners Beaver V ll PA 43 1 4 2,15910676_B_4 AES Beaver Valley Partners Beaver V ll PA 43 1 4 2,15910676_B_5 AES Beaver Valley Partners Beaver V ll PA 17 1 4 1,520

10678_B_BLR1 AES Warrior Run Cogeneration Facility MD 180 1 13 10,326

10684_B_BLR25 Argus Cogen Plant CA 25 1 55 20,74810684_B_BLR26 Argus Cogen Plant CA 25 1 55 20,748

10743_B_CFB1 Morgantown Energy Facility WV 25 1 12 4,57810743_B_CFB2 Morgantown Energy Facility WV 25 1 12 4,417

10768_B_CFB Rio Bravo Jasmin CA 33 1 29 12,56010769_B_CFB Rio Bravo Poso CA 33 1 9 4,078

10771_B_1 Hopewell VA 32 1 10 4,43310771_B_2 Hopewell VA 32 1 10 4,43310773_B_1 Altavista Power Station VA 32 1 7 3,02510773_B_2 Altavista Power Station VA 32 1 7 3,02510774_B_1 Southampton Power Station VA 63 1 21 11,52310774_B_2 Southampton Power Station VA 37 1 21 9,507

10784_B_BLR1 Colstrip Energy LP MT 35 1 136 60,67710849_B_BLR1 Silver Bay Power MN 36 1 53 23,12710849_B_BLR2 Silver Bay Power MN 69 1 53 29,46750012_B_BLR4 Alloy Steam Station WV 38 1 16 6,888

50030_B_1A Nelson Industrial Steam and Operating C LA 107 2 7 2,70550030_B_2A Nelson Industrial Steam and Operating C LA 106 2 7 2,679

50039_B_1 Kline Township Cogen Facility PA 50 1 27 13,837

50130_B_BLR1 G F Weaton Power Station PA 56 1 3 1,63050130_B_BLR2 G F Weaton Power Station PA 56 1 3 1,630

50202_B_1 WPS Power Niagara NY 53 1 3 1,434

50368_G_TG1 Cornell University Central Heat NY 1 1 3 26850368_G_TG2 Cornell University Central Heat NY 5 1 3 542

50388_B_K1 Phillips 66 Carbon Plant CA 10 1 1 197
73

50388_B_K2 Phillips 66 Carbon Plant CA 10 1 1 197

50397_B_1PB035 P H Glatfelter PA 9 1 7 1,84150397_B_3PB033 P H Glatfelter PA 4 1 7 1,49350397_B_4PB034 P H Glatfelter PA 9 1 7 1,87450397_B_5PB036 P H Glatfelter PA 36 1 7 3,138

50410_B_10 Chester Operations PA 36 1 0 165

50611_B_031 WPS Westwood Generation LLC PA 30 1 9 3,969

50651_B_1 Trigen Syracuse Energy NY 11 1 8 2,21150651_B_2 Trigen Syracuse Energy NY 11 1 8 2,24350651_B_3 Trigen Syracuse Energy NY 11 1 8 2,24350651_B_4 Trigen Syracuse Energy NY 11 1 8 2,24350651_B_5 Trigen Syracuse Energy NY 11 1 8 2,243

50651_G_GEN2 Trigen Syracuse Energy NY 11 1 8 2,211

50776_B_BLR1 Panther Creek Energy Facility PA 42 1 22 10,10850776_B_BLR2 Panther Creek Energy Facility PA 42 1 22 10,224

50806_B_PB4 Stone Container Florence Mill SC 75 1 122 69,382

50835_B_1 TES Filer City Station MI 30 1 42 17,74750835_B_2 TES Filer City Station MI 30 1 42 17,141

50879_B_BLR1 Wheelabrator Frackville Energy PA 45 1 21 10,41450888_B_BLR1 Northampton Generating Company PA 112 1 5 3,30750931_B_BLR1 Yellowstone Energy LP MT 28 1 149 65,98750931_B_BLR2 Yellowstone Energy LP MT 28 1 149 58,025

50951_B_1 Sunnyside Cogen Associates UT 51 1 15 7,903

50974_B_UNIT 1 Scrubgrass Generating PA 43 1 8 3,99350974_B_UNIT 2 Scrubgrass Generating PA 43 1 8 3,881

50976_B_AAB01 Indiantown Cogeneration LP FL 330 2 4 3,323

52007_B_BLR1 Mecklenburg Power Station VA 69 1 15 8,56752007_B_BLR2 Mecklenburg Power Station VA 69 1 15 8,567

52071_B_5A Sandow 5 TX 300 2 32 23,26052071_B_5B Sandow 5 TX 300 2 32 23,260
74

54035_B_BLR1 Westmoreland Roanoke Valley I NC 165 2 62 36,771

54081_B_1A Cogentrix of Richmond VA 26 1 8 3,05054081_B_1B Cogentrix of Richmond VA 26 1 8 2,94854081_B_2A Cogentrix of Richmond VA 26 1 8 3,05054081_B_2B Cogentrix of Richmond VA 26 1 8 2,94854081_B_3A Cogentrix of Richmond VA 21 1 8 2,82054081_B_3B Cogentrix of Richmond VA 21 1 8 2,72354081_B_4A Cogentrix of Richmond VA 21 1 8 2,82054081_B_4B Cogentrix of Richmond VA 21 1 8 2,723

54144_B_BRBR1 Piney Creek Project PA 33 1 16 6,808

54224_B_GEN6 Franklin Heating Station MN 3 1 43 7,175

54238_B_N64514 Port of Stockton District Energy Fac CA 22 1 3 99754238_B_N64516 Port of Stockton District Energy Fac CA 22 1 3 958

54304_B_1A Birchwood Power VA 239 1 29 25,665

54406_G_1 Capitol Heat and Power WI 1 1 28 2,96754406_G_2 Capitol Heat and Power WI 1 1 28 2,967

54626_B_BL01 Mt Poso Cogeneration CA 52 1 18 9,385

54634_B_1 St Nicholas Cogen Project PA 88 1 24 14,921

54677_B_HRB CII Carbon LLC LA 23 1 1 409

54677_G_TG-2 CII Carbon LLC LA 23 1 1 409

54755_B_BLR2 Westmoreland Roanoke Valley II NC 44 1 9 4,516

54775_B_BLR10 University of Iowa Main Power Plant IA 4 1 12 2,47654775_B_BLR11 University of Iowa Main Power Plant IA 4 1 12 2,476

54992_G_ST Fellsway Development LLC MA 0 1 4 345

55076_B_AA001 Red Hills Generating Facility MS 220 1 6 5,08555076_B_AA002 Red Hills Generating Facility MS 220 1 6 5,209

55360_B_1 Two Elk Generating Station WY 300 2 88 32,93255479_B_3 Wygen 1 WY 70 1 22 12,384

55749_B_PC1 Hardin Generator Project MT 109 1 113 76,68355856_B_PC1 Prairie State Generating Company LLC IL 800 3 102 75,746
75

55856_B_PC2 Prairie State Generating Company LLC IL 800 3 102 75,746

56037_G_1 Fox Valley Energy Center WI 7 1 12 2,829

56068_B_1 Elm Road Generating Station WI 617 3 87 69,30356068_B_2 Elm Road Generating Station WI 617 3 87 69,30356163_B_1 KUCC UT 30 1 5 2,09756163_B_2 KUCC UT 30 1 5 2,09756163_B_3 KUCC UT 30 1 5 2,09756163_B_4 KUCC UT 65 1 5 2,599

56224_B_001 TS Power Plant NV 200 2 279 166,191

56319_B_4 Wygen WY 90 1 22 12,81156319_B_5 Wygen WY 100 1 22 13,317

56456_B_STG1 Plum Point Energy AR 665 2 34 33,548

56671_B_1 Longview Power WV 695 2 21 21,085

82794_C_1 ERCT_TX_Coal steam TX 300 2 8 3,520

82821_B_1 Great River Energy Spiritwood Station ND 99 1 14 8,403

82886_C_1 NWPE_WY_Coal steam WY 422 3 212 111,57382909_C_1 RFCO_IN_IGCC IN 630 3 69 56,90382916_C_1 RMPA_CO_Coal steam CO 18 1 11 3,74482932_C_1 SPPN_KS_Coal steam KS 22 1 10 3,75582934_C_1 SPPN_MO_Coal steam MO 1,150 3 82 79,762

82998_B_CFB1 Virginia City Hybrid Energy Center VA 293 3 168 99,75082998_B_CFB2 Virginia City Hybrid Energy Center VA 293 3 168 99,750
76

● ● ●

5.4.3 Mercury Control Capabilities 

EPA Base Case v4.10_PTox offers two options for meeting mercury reduction requirements: (1) 

combinations of SO2, NOX, and particulate controls which deliver mercury reductions as a cobenefit and (2) Activated Carbon Injection (ACI), a retrofit option specifically designed for 

mercury control. These two options are discussed below. 

Mercury Control through SO2 and NOX Retrofits 

In EPA Base Case v4.10, units that install SO2, NOX, and particulate controls, reduce mercury 

emissions as a byproduct of these retrofits. Section 5.4.2 described how EMFs are used in the 

base case to capture the unregulated mercury emissions depending on the rank of coal burned, 

the generating unit’s combustion characteristics, and the specific configuration of SO2, NOX, and 

particulate controls (i.e., hot and cold-side electrostatic precipitators (ESPs), fabric filters (also 

called “baghouses”) and particulate matter (PM) scrubbers). These same EMFs would be 

available in mercury policy runs to characterize the mercury reductions that can be achieved by 

retrofitting a unit with SCR, SO2 scrubbers and particulate controls. The absence of a federal 

mercury emission reduction policy means that these controls appear in the base case in 

response to SO2, NOX, or particulate limits or state-level mercury emission requirements. 

However, in future model runs where mercury limits are present these same SO2 and NOX

controls could be deliberately installed for mercury control if they provide the least cost option 

for meeting mercury policy limits. 

Activated Carbon Injection (ACI) 

The technology specifically designated for mercury control is Activated Carbon Injection (ACI) 

downstream of the combustion process in coal fired units. In preparation for performing 

modeling of air toxics, a comprehensive update of ACI cost and performance assumptions was 

undertaken by Sargent & Lundy, the same engineering firm that developed the SO2 and NOX

control assumptions used in EPA Base Case v4.10. The ACI update, whose elements are 

described below, incorporates the latest field experience through 2010. 

Assuming a target of 90% removal from the level of mercury in the coal, three alternative ACI 

options were identified as providing the required rate of removal for all possible configurations of 

boiler, emission controls, and coal types used in the U.S. electric power sector. The three ACI 

options differed based on the type of particulate control device − electrostatic precipitator (ESP) 

or pre-existing or new fabric filter (also called a “baghouse”), i.e., 

• ACI with Existing ESP 

• ACI with Existing Baghouse 

• ACI with an Additional Full Baghouse (also referred to as Toxecon) 

All three configurations assume the use of brominated ACI, where a small amount of bromine is 

chemically bonded to the powdered carbon which is injected into the flue gas stream. The use 

of brominated ACI exploits the discovery that by converting elemental mercury to oxidized 

mercury, halogens (like chlorine, iodine, and bromine) can make activated carbon more 

effective in capturing the mercury at the high temperatures found in industrial processes like 

power generation. The ionic mercury adheres to the activated carbon (and to fly ash and 

unburned carbon in the fuel gas) which can be removed efficiently from the flue gas by the 
77

particulate control device (ESP or fabric filter). In the third option listed above the additional 

baghouse is installed downstream of the pre-existing particulate matter device and the activated 

carbon is injected after the existing controls. This configuration allows the fly ash to be removed 

before the mercury controls to preserve its marketability. 

The applicable ACI option depends on the coal type burned, its SO2 content, the boiler and 

particulate control type and, in some instances, consideration of whether an SO2 scrubber 

(FGD) system and SCR NOx post-combustion control are present. Table 5-16 shows the ACI 

assignment scheme used in EPA Base Case v4.10_PTox to achieve 90% mercury removal. 
78

Table 5-16. Assignment Scheme for Mercury Emissions Control Using Activated Carbon Injection (ACI) in EPA Base CasToxics Rule). 

Air pollution controls Bituminous Coal Subbituminous Coal 

Burner Type Particulate Control Type SCR System FGD System ACI Required? Toxecon Required? 

Sorbent 

Inj Rate 

(lb/million 

acf) 

ACI 

Required? 

Toxecon 

Required? 

Sorbent 

Inj Rate 

(lb/million 

acf) 

FBC Cold Side ESP + Fabric Filter without FGC -- -- Yes No 2 Yes No 2 FBC Cold Side ESP without FGC -- -- Yes No 5 Yes No 5 FBC Fabric Filter -- Dry FGD No No 0 Yes No 2 FBC Fabric Filter -- -- Yes No 2 Yes No 2 FBC Hot Side ESP with FGC -- -- Yes Yes 2 Yes Yes 2 

Non-FBC Cold Side ESP + Fabric Filter with FGC -- Dry FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter with FGC -- -- Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter with FGC -- Wet FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter with FGC SCR -- Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter with FGC SCR Dry FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter with FGC SCR Wet FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter without FGC -- Dry FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter without FGC -- -- Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter without FGC -- Wet FGD Yes No 2 Yes No 2 
79

Non-FBC Cold Side ESP + Fabric Filter without FGC SCR -- Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter without FGC SCR Dry FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP + Fabric Filter without FGC SCR Wet FGD Yes No 2 Yes No 2 Non-FBC Cold Side ESP with FGC -- Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC Cold Side ESP with FGC -- -- Yes Yes 2 Yes Yes 2 Non-FBC Cold Side ESP with FGC -- Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC Cold Side ESP with FGC SCR -- Yes Yes 2 Yes Yes 2 Non-FBC Cold Side ESP with FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC Cold Side ESP with FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC Cold Side ESP without FGC -- Dry FGD Yes No 5 Yes No 5 Non-FBC Cold Side ESP without FGC -- -- Yes No 5 Yes No 5 Non-FBC Cold Side ESP without FGC -- Wet FGD Yes No 5 Yes No 5 Non-FBC Cold Side ESP without FGC SCR -- Yes No 5 Yes No 5 Non-FBC Cold Side ESP without FGC SCR Dry FGD Yes No 5 Yes No 5 Non-FBC Cold Side ESP without FGC SCR Wet FGD Yes No 5 Yes No 5 Non-FBC Fabric Filter -- Dry FGD Yes No 2 Yes No 2 Non-FBC Fabric Filter -- -- Yes No 2 Yes No 2 
80

Non-FBC Fabric Filter -- Wet FGD Yes No 2 Yes No 2 Non-FBC Fabric Filter SCR Dry FGD Yes No 2 Yes No 2 Non-FBC Fabric Filter SCR -- Yes No 2 Yes No 2 Non-FBC Fabric Filter SCR Wet FGD Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter with FGC -- -- Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter with FGC -- Wet FGD Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter with FGC -- Dry FGD No No 0 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter with FGC SCR Wet FGD Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter with FGC SCR Dry FGD No No 0 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter with FGC SCR -- Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter without FGC -- Dry FGD No No 0 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter without FGC -- -- Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter without FGC -- Wet FGD Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter without FGC SCR Dry FGD No No 0 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter without FGC SCR -- Yes No 2 Yes No 2 Non-FBC Hot Side ESP + Fabric Filter without FGC SCR Wet FGD Yes No 2 Yes No 2 Non-FBC Hot Side ESP with FGC -- Dry FGD Yes Yes 2 Yes Yes 2 
81

Non-FBC Hot Side ESP with FGC -- -- Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP with FGC -- Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP with FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP with FGC SCR -- Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP with FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP without FGC -- Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP without FGC -- -- Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP without FGC -- Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP without FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP without FGC SCR -- Yes Yes 2 Yes Yes 2 Non-FBC Hot Side ESP without FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC No Control -- Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC No Control -- -- Yes Yes 2 Yes Yes 2 Non-FBC No Control -- Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC No Control SCR Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC No Control SCR -- Yes Yes 2 Yes Yes 2 Non-FBC No Control SCR Wet FGD Yes Yes 2 Yes Yes 2 
82

Non-FBC PM Scrubber -- Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC PM Scrubber -- -- Yes Yes 2 Yes Yes 2 Non-FBC PM Scrubber -- Wet FGD Yes Yes 2 Yes Yes 2 Non-FBC PM Scrubber SCR Dry FGD Yes Yes 2 Yes Yes 2 Non-FBC PM Scrubber SCR -- Yes Yes 2 Yes Yes 2 Non-FBC PM Scrubber SCR Wet FGD Yes Yes 2 Yes Yes 2 

Note: In the table above "Toxecon" refers to the option described as "ACI System with an Additional Baghouse" and "ACI + Full Baghouse with a Sorbent Injection this chapter. 
83

Methodology for Obtaining ACI Control Costs: For ACI systems the carbon feed rate dictates 

the size of the equipment and resulting costs. The feed rate in turn is a function of the required 

removal (in this case 90%) and the type of particulate control device. Engineering experience 

had established that a carbon feed rate of 5 pounds of carbon injected for every 1,000,000 

actual cubic feet per minute (acfm) of flue gas would provide the stipulated 90% mercury 

removal rate for units shown in Table 5-16 as qualifying for ACI systems with existing ESP. For 

generating units with fabric filters a 2 pound per million acfm is required. Alternative sets of 

costs were developed for each of the three ACI options: ACI systems for units with existing 

ESPs, ACI for units with existing fabric filters (baghouses), and the combined cost of ACI plus 

an additional baghouse for units that either have no existing particulate control or that require 

ACI plus a baghouse in addition to their existing particulate control. There are various reasons 

that a combined ACI plus additional baghouse would be required. These include situations 

where the existing ESP cannot handle the additional particulate load associate with the ACI or 

where SO3 injection is currently in use to condition the flue gas for the ESP. Another cause for 

combined ACI and baghouse is use of PRB coal whose combustion produces mostly elemental 

mercury, not ionic mercury, due to this coal’s low chlorine content. 

Capital Cost: Included in the installed capital cost of ACI are 

• All equipment 

• Installation 

• Buildings 

• Foundations 

• Electrical 

If an additional baghouse is required in combination with the ACI, specific installed capital costs 

include 

• Duct work 

• Foundations 

• Structural steel 

• Induced draft (ID) fan modifications or new booster fans 

• Electrical modifications 

For the combined ACI and fabric filter option a full size baghouse with an air-to-cloth (A/C) ratio 

of 4.0 is assumed, not a polishing baghouse with a 6.0 A/C ratio5

. Table 5-17 shows the capital 

cost modules and the governing variables for ACI systems. 

 

5

The “air-to-cloth” (A/C) ratio is the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, 

ACFM) of flue gas entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth 

in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater area of the 

cloth required and the higher the cost for a given volumetric flow.
84

Table 5‐17.  Capital Cost Components and Their Governing Variables for ACI Systems  

Module

Hg

Removal

Rate

Retrofit

Difficulty

(1 =

average)

Particulate

Capture

Type

(ESP or

Baghouse)

Heat Rate

(Btu/kWh)

Unit

Size

(MW)

Coal

Type

ACI

Injection ‐

Carbon

Feed Rate

X X X X X    

Additional

Fabric

Filter (if

needed)

   X     X X X

A bare installed total cost is calculated from the carbon feed rate based on the required removal 

rate, the particulate control, and the flue gas flow rate. The resulting bare installed total cost is 

increased by 15% to account for additional engineering and construction management costs, 

labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, 

and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC 

subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, 

management, and procurement costs. Since ACI systems are expected to be completed in less 

than a year, no Allowance for Funds used During Construction (AFUDC) is provided for ACI 

systems by themselves. However, if combined with an additional baghouse, 6% is added to 

account for Allowance for Funds used During Construction (AFUDC) which is premised on a 2-

year project duration for the baghouse. 

The cost resulting from these calculations is the capital cost factor (expressed in $/kW) that is 

used in EPA Base Case v4.10_PTox. 

Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an 

emission control device. They are proportional to the electrical energy produced and are 

expressed in units of $ per MWh. For ACI, Sargent & Lundy identified three components of 

VOM: (a) reagent use and unit costs, (b) waste production and disposal cost, (c) cost of 

additional power required to run the DSI control (often called the “parasitic load”). For the ACI in 

combination with fabric filter option, the VOM includes a fourth component: (d) the cost of filter 

bag and cage replacement. (With an assumption that the A/C ratio = 6.0, the bag and cage 

replacement cycles are 3 and 9 years respectively.) 

 

For ACI carbon usage is a function of unit size and heat rate. The carbon waste production is 

equal to the carbon feed rate. To provide a conservative estimate, the costing analysis 

assumed that the carbon is captured in the same particulate collector as the fly ash, making it 
85

necessary for both the total fly ash and the carbon to be landfilled. Typical ash contents for 

each fuel were used to calculate a total fly ash production rate. 

For purposes of modeling, the total VOM includes cost components (a), (b), and, where 

applicable, (d) as noted above. Component (c) – cost of additional power for the ACI system – is 

factored into IPM, not in the VOM value, but through capacity and heat rate penalties as 

described in the next paragraph. 

Capacity and Heat Rate Penalty: The amount of electrical power required to operate the ACI 

system is represented through a reduction in the amount of electricity that is available for sale to 

the grid. For example in the option of a combined ACI system with an additional baghouse, if 

0.65% of the unit’s electrical generation is needed to operate the combined system, the 

generating unit’s capacity is reduced by 0.65%. This is the “capacity penalty.” At the same time, 

to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for 

operating the ACI device), the unit’s heat rate is scaled up such that a comparable reduction 

(0.65% in the previous example) in the new higher heat rate yields the original heat rate. The 

factor used to scale up the original heat rate is called “heat rate penalty.” It is a modeling 

procedure only and does not represent an increase in the unit’s actual heat rate (i.e., a 

decrease in the unit’s generation efficiency). As was the case for FGD in EPA Base Case 

v4.10, specific ACI heat rate and capacity penalties are calculated for each installation. For 

ACI, the site specific calculations take into account the additional power required for blowers for 

the injection system and, where an additional fabric filter is present, the power for the baghouse 

compressors. 

Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining a 

unit. They represent expenses incurred regardless of the extent to which the emission control 

system is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent & 

Lundy took into account labor and materials costs associated with operations, maintenance, and 

administrative functions. The following assumptions were made: 

• FOM for operations is based on the number of addition operators needed. For ACI one 

(1) additional operator is assumed to be needed. 

• FOM for maintenance is a direct function of the ACI capital cost. 

• FOM for administration is a function of the FOM for operations and maintenance. 

Table 5-18 presents the capital, VOM, and FOM costs as well as the capacity and heat rate 

penalties for the three ACI options represented in EPA Base Case v4.10_PTox (Proposed 

Toxics Rule). For each ACI option values are shown for an illustrative set of generating units 

with a representative range of capacities and heat rates. 

Tables 1-3 in Appendix 5-3 contains illustration worksheets of the detailed calculations 

performed to obtain the capital, VOM, and FOM costs for examples of the three ACI options 

described in this section. The worksheets were developed by Sargent & Lundy6

.

 

6 These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and Performance for 

APC Technologies: Mercury Control Cost Development Methodology (Project 12301-009), October 2010. The 

complete report is available for review and downloading at www.epa.gov/airmarkets/progsregs/epa-ipm/. 
86 

Table 5-18. Illustrative Activated Carbon Injection (ACI) Costs for Representative Sizes and Heat Rates Under AssBase Case v4.10_PTox (Proposed Toxics Rule) 

Control Type Heat Rate (Btu/kWh) Capacity Penalty (%) Heat Rate Penalty (%) Variable O&M (mills/kWh) 

Capacity (MW) 

100 300 500 7

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

ACI System 

with an 

Existing ESP

ACI with a 

Sorbent 

Injection Rate 

of 5 lbs/million 

acfm 

Assuming 

Bituminous 

Coal

9,000 

10,000 11,000 

0.12 0.13 0.14 

0.12 0.13 0.14 

2.76 3.07 3.38 

32.06 32.56 33.04 

0.13 0.14 0.14 

12.60 12.80 12.99 

0.05 0.05 0.05 

8.16 8.29 8.41 

0.03 0.03 0.04 

6.13 6.23 6.32 

ACI System with an Existing BaghouseACI with a Sorbent Injection Rate of 2 lbs/million acfm Assuming Bituminous Coal

9,000 

10,000 11,000 

0.05 0.05 0.06 

0.05 0.05 0.06 

2.24 2.49 2.74 

27.93 28.37 28.80 

0.12 0.12 0.12 

10.98 11.16 11.32 

0.05 0.05 0.05 

7.11 7.23 7.33 

0.03 0.03 0.03 

5.34 5.43 5.51 

ACI System with an Additional BaghouseACI + Full Baghouse with a Sorbent Injection Rate of 2 lbs/million acfm Assuming Bituminous Coal

9,000 

10,000 11,000 

0.65 0.65 0.66 

0.65 0.66 0.66 

0.50 0.54 0.58 

240 259 278 

0.91 0.98 1.05 

182 197 212 

0.69 0.75 0.80 

162 176 189 

0.61 0.67 0.72 

150 163 176 
87 

5.5 Hydrogen Chloride (HCl) Control Technologies 

Consistent with other analysis performed for the Toxics Rule, hydrogen chloride (HCl) is used in 

EPA Base Case v4.10_PTox (Proposed Toxics Rule) as a surrogate for the acid gas hazardous 

air pollutants (HAPs). (See Toxics Rule preamble for a discussion of this topic.) The following 

sections describe how HCl emissions from coal are represented in IPM, the emission control 

technologies available for HCl removal, and the cost and performance characteristics of these 

technologies. 

 5.5.1 Chlorine Content of Fuels 

HCl emissions from the power sector result from the chlorine content of the coal that is 

combusted by electric generating units. Data on chlorine content of coals had been collected as 

part EPA’s 1999 “Information Collection Request for Electric Utility Steam Generating Unit 

Mercury Emissions Information Collection Effort” (ICR 1999) described above in section 5.4.1 

To provide the capability for EPA Base Case v4.10 to account for HCl emissions, this data had 

to be incorporated into the model. The procedures used for this are presented in the updated 

text in section 9.1.3 below. 

5.5.2 HCl Removal Rate Assumptions for Existing and Potential Units 

SO2 emission controls on existing and new (potential) units provide the HCl reductions indicated 

in Table 5-19. New supercritical pulverized coal units (column 3) that the model builds include 

FGD (wet or dry) which is assumed to provide a 99% removal rates for HCl. For existing 

conventional pulverized coal units with pre-existing FGD (column 5), the HCl removal rate is 5% 

higher than the reported SO2 removal rate up to a maximum of 99% removal. In addition, for 

fluidized bed combustion units (column 4) with no FGD and no fabric filter, the HCl removal rate 

is the same as the SO2 removal rate up to a maximum of 95%. FBCs with fabric filters have an 

HCl removal rate of 95%. 

 

When policies for controlling toxics emissions are modeled, it is assumed prior to performing a 

model run that the most cost effective default option for existing coal steam units with FGD 

would be to upgrade their FGDs to obtain at least 90% SO2 removal and 99% HCl removal and 

then let the model determine if any further reductions are needed. The cost of the FGD 

Upgrade Adjustment, as it is called, is assumed to be $100/kW (in 2009$). It is applied in the 

model as an FOM cost adder7

. 

 

 

7 The FGD Upgrade Adjustment is applied in the model as a FOM cost adder, where 

FOM Adder = FGD Upgrade Adjustment X Capital Charge Rate 

= $100/kW ($2009) X 11.3% 

= $11.30/kW-yr ($2009) 
88 

Table 5‐19. HCl Removal Rate Assumptions for Potential (New) and Existing Units in EPA Base Case

v4.10_PTox (Proposed Toxics Rule)  

   Potential

(New)

Existing Units with FGD

      Base Case Policy Case

Gas

Controls ==>

Supercritical

Pulverized

Coal with Wet

or Dry FGD

Fluidized

Bed

Combustion

(FBC)

Conventional

Pulverized Coal

(CPC) with Wet

or Dry FGD

Existing Coal Steam

Units with FGD

Upgrade Adjustment

HCl Removal

Rate 99%

Without

fabric filter:  

Same as

reported SO2

removal rate

up to a

maximum of

95%

−−− 

With fabric

filter:  95%

Reported SO2

removal rate +

5% up to a

maximum of

99%

If reported SO2

removal < 90%, unit

incurs cost to upgrade

FGD, so that SO2

removal is 90%.  Then,

the resulting HCl

removal rate is 99%

−−− 

If reported SO2

removal is ≥ 90% and

< 94%,  then the unit

incurs a cost to

upgrade FGD and the

HCl removal rate is

99%. (The SO2

removal rate remains

as reported.)

−−− 

If the reported SO2

removal rate is ≥ 94%,

the unit incurs no

upgrade cost and the

HCl removal rate is

99%.
89 

5.5.3 HCl Retrofit Emission Control Options 

Table 5‐20 Summary of HCl Emission Control Technology

Assumptions in EPA Base Case v4.10_PTox  

(Proposed Toxics Rule)  

   

HCl Control Technology

Options Applicability

Limestone Forced

Oxidation (LSFO)

Scrubber

Base case and policy case

Lime Spray Dryer (LSD) Base case and policy case

Dry Sorbent Injection

(DSI) Base case and policy case

Scrubber upgrade

adjustment

To existing coal steam units

with FGD in policy cases

analyzed for Toxics

Rulemaking

All the retrofit options for HCl emission control are summarized in Table 5-20. The scrubber 

upgrade adjustment was discussed above in 5.5.2. The other options are discussed in detail in 

the following sections. 

5.5.3.1 Wet and Dry FGD

In addition to providing SO2 reductions, wet scrubbers (Limestone Forced Oxidation, LSFO) and 

dry scrubbers (Lime Spray Dryer, LSD) reduce HCl as well. For both LSFO and LSD the HCl 

removal rate is assumed to be 99% with a floor of 0.0001 lbs/MMBtu. This is summarized in 

columns 2-5 of Table 5-21.
90 

Table 5-21 Summary of Retrofit HCl (and SO2) Emission Control Performance Assumptions in v4.10_PTox (Propo

. 

Performance 

Assumptions 

Limestone Forced Oxidation 

(LSFO) Lime Spray Dryer (LSD) Dry Sorbent In

SO2 HCl SO2 HCl SO2 

Percent Removal 

96% 

with a floor of 

0.06 lbs/MMBtu 

99% 

with a floor of 

0.0001 

lbs/MMBtu 

92% 

with a floor of 

0.065 lbs/MMBtu 

99% 

with a floor of 

0.0001 

lbs/MMBtu 

With fabric 

filter: 70% 

−−−

With an 

electrostatic 

percipitator2:

50% 

Capacity Penalty -1.65% -0.70% -0.6Heat Rate Penalty 1.68% 0.71% 0.6Cost (2007$) See Table 5-3 and 5-4 See Table 5-3 and 5-4 See TableApplicability Units ≥ 25 MW Units ≥ 25 MW Units ≥ Sulfur Content Applicability Coals ≤ 2.0% Sulfur by Weight Coals ≤ 2.0 lb/Applicable Coal Types 

BA, BB, BD, BE, BG, BH, SA, SB, 

SD, LD, LE, and LG 

BA, BB, BD, BE, SA, SB, SD, LD, 

LE, and LG BA, BB, BD, SA, 

Notes1. The cost and performance values shown in this table apply to existing units with pre-existing fabric filters or electrostatUnits with neither ESP nor FF are assumed to have to install a fabric filter in order to qualify for the DSI retrofit. 2. The option to retrofit DSI on existing units with ESP was not offered in the runs performed for the current rulemaking. 
91 

5.5.3.2 Dry Sorbent Injection 

Besides HCl reductions obtained from FGD, EPA Base Case v4.10_PTox includes dry sorbent 

injection (DSI), not previously included in the base case, as a retrofit option for achieving (in 

combination with a particulate control device) both SO2 and HCl removal. In DSI for HCl 

reduction, a dry sorbent is injected into the flue gas duct where it reacts with the HCl and SO2 in 

the flue gas to form a compound, which is then captured in a downstream fabric filter or 

electrostatic precipitator (ESP) and disposed of as waste. (A sorbent is a material that takes up 

another substance by either adsorption on its surface or absorption internally or in solution. A 

sorbent may also chemically react with another substance.) The sorbent assumed in the cost 

and performance characterization discussed in this section is trona, a sodium-rich material with 

major underground deposits found in Sweetwater County, Wyoming. Trona is typically 

delivered with an average particle size of 30 μm diameter, but can be reduced to about 15 μm 

through onsite in-line milling to increase its surface area and capture capability. 

 

Removal rate assumptions: The removal rate assumptions for DSI are summarized in Table 5-

21. The assumptions shown in the last two columns of Table 5-21 were derived from 

assessments by EPA engineering staff in consultation with Sargent & Lundy. As indicated in 

this table, the assumed SO2 removal rate for DSI + ESP is 50% and for DSI + fabric filter is 

70%. The assumed HCl removal rate is 60% for DSI + ESP and 90% for DSI + fabric filter. 

(This is noted in the next-to-the-last column in Table 5-21.) Although the option to retrofit DSI on 

existing units with ESP is shown in Table 5-21 it was not offered in the runs performed for the 

current rulemaking. 

Methodology for Obtaining DSI Control Costs: The engineering firm of Sargent & Lundy, whose 

analyses were used to update the cost of SO2 and post-combustion NOx controls in EPA Base 

Case , v4.10, performed similar engineering assessments of the cost of DSI retrofits with two 

alternative, associated particulate control devices, i.e., ESP and fabric filter (also called a 

“baghouse”). Their analysis of DSI noted that the cost drivers of DSI are quite different from 

those of wet or dry FGD. Whereas plant size and coal sulfur rates are key underlying 

determinants of FGD cost, sorbent feed rate and fly ash waste handling are the main drivers of 

the capital cost of DSI with plant size and coal sulfur rates playing a secondary role. 

 

Sorbent feed rate determines the amount of sorbent required and the size and extensiveness of 

the DSI installation. The sorbent feed rate needed to achieve a specified percent SO2 or HCl 

removal8

 is firstly a function of the flue gas SO2 rate (which, in turn, is a function of the sulfur 

content of the coal burned, expressed in lbs of SO2/mmBtu ), the unit’s size and heat rate, and 

the sorbent particle size (which determines whether in-line milling is needed). The sorbent feed 

rate is also a function of the residence time of the sorbent in the flue gas stream and the extent 

of mixing and penetration of the sorbent in the flue gas. Residence time, penetration, and 

mixing are largely dependent on the type of particulate control device use (electrostatic 

precipitator or fabric filter). 

 

8

For purposes of engineering calculations the percent removal is often translated into a corresponding

“Normalized Stoichiometric Ratio” (NSR) associated with a particular percent removal, where the NSR is defined as

ܴܰܵ ൌ ቀ ௠௢௟௘௦ ௢௙ ௦௢௕௘௡௧ ௜௡௝௘௖௧

௠௢௟௘௦ ௢௙ ௌைଶ ௜௡ ௙௟௨௘ ௚௔௦ቁ

൘ ሻ݁݀ݎ݅ݑݍ݁ݎ ݐܾ݁݊ݎ݋ݏ ݂݋ ݏ݈݁݋݉ ݈݅ܿܽݐ݁ݎ݋݄݁ݐሺ
92 

In EPA Base Case v4.10_PTox the DSI sorbent feed rate and variable O&M costs are based on 

assumptions that a fabric filter and in-line trona milling are used, and that the SO2 removal rate 

is 60%. The corresponding HCl removal effect is assumed to be 90%, based on information 

from Solvay Chemicals (H. Davidson, Dry Sorbent Injection for Multi-pollutant Control Case 

Study, CIBO IECT VIII, August, 2010). 

The cost of fly ash waste handling, the other key contributor to DSI cost, is a function of the type 

of particulate capture device and the flue gas SO2 rate (which, as noted above, is itself a 

function of the sulfur content of the coal and the unit’s size and heat rate). Fly ash waste 

handling costs are also a function of the ash content and the higher heating value (HHV) of the 

coal. The governing variables of the key capital cost components of DSI are presented in Table 

5-22. 

Table 5‐22.  Capital Cost Components and Their Governing Variables for HCl Removal with DSI.

Module

Retrofit

Difficulty

(1 =

average)

Particulate

Capture

Type

(ESP or

Baghouse)

Sorbent  

Particle

Size

Require‐

ment

(milled or

unmilled)

Heat

Rate

(Btu/

kWh)

SO2

Rate

of coal

(lb/

MMBtu)

Ash

Content

of Coal

(percent)

Higher

Heating

Value

(HHV)

of Coal

(Btu/lb)

Unit

Size

(MW)

Sorbent

Feed

Handling

X     X X X        X

Fly Ash

Waste

Handling

X X     X     X X X

Once the key variables for the two DSI modules are identified, they are used to derive costs for 

each base module component. These costs are then summed to obtain total bare module 

costs. The base installed cost for DSI includes 

• All equipment 

• Installation 

• Buildings 

• Foundations 

• Electrical 

• Average retrofit difficulty 

• In-line milling equipment is assumed to be included 

This total is increased by 15% to account for additional engineering and construction 

management costs, labor premiums, and contractor profits and fees. The resulting value is the 

capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost 

(TPC), the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., 

owner’s engineering, management, and procurement costs. Since DSI installations are 
93 

expected to be completed in less than a year, no Allowance for Funds used During Construction 

(AFUDC) is provided for DSI. The cost resulting from these calculations is the capital cost factor 

(expressed in $/kW) that is used in EPA Base Case v4.10_PTox. 

Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an 

emission control device. They are proportional to the electrical energy produced and are 

expressed in units of $ per MWh. For DSI, Sargent & Lundy identified three components of 

VOM: (a) costs for sorbent usage, (b) costs associated with waste production and disposal, (c) 

cost of additional power required to run the DSI control (often called the “parasitic load”). For 

DSI, sorbent usage is a function of the “Normalized Stoichiometric Ratio” and SO2 feed rate. As 

noted above the feed rate is a function of the SO2 rate of the coal and the unit’s size and heat 

rate. 

Total waste production involves the production of both reacted and unreacted sorbent and fly 

ash. Sorbent waste is a function of the sorbent feed rate with an adjustment for excess sorbent 

feed. Use of DSI makes the fly ash unsalable, which means that any fly ash produced must be 

landfilled along with the reacted and unreacted sorbent waste. Typical ash contents for each 

fuel are used to calculate a total fly ash production rate. The fly ash production is added to the 

sorbent waste to account for the total waste stream for the VOM analysis. 

For purposes of modeling, the total VOM includes the first two component costs noted in the 

previous paragraph, i.e., the costs for sorbent usage and the costs associated with waste 

production and disposal,. The last component – cost of additional power – is factored into IPM, 

not in the VOM value, but through a capacity and heat rate penalty as described in the next 

paragraph. 

Capacity and Heat Rate Penalty: The amount of electrical power required to operate the DSI is 

represented through a reduction in the amount of electricity that is available for sale to the grid. 

For example, if 0.65% of the unit’s electrical generation is needed to operate DSI, the 

generating unit’s capacity is reduced by 0.65%. This is the “capacity penalty.” At the same time, 

to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for 

operating the DSI device), the unit’s heat rate is scaled up such that a comparable reduction 

(0.65% in the previous example) in the new higher heat rate yields the original heat rate. The 

factor used to scale up the original heat rate is called “heat rate penalty.” It is a modeling 

procedure only and does not represent an increase in the unit’s actual heat rate (i.e., a 

decrease in the unit’s generation efficiency). As was the case for FGD in EPA Base Case 

v4.10, specific DSI heat rate and capacity penalties are calculated for each installation. For DSI 

the installation specific calculations take into account the additional power required by air 

blowers for the injection system, drying equipment for the transport air, and in-line milling 

equipment, if required. 

Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining an 

emission control. They represent expenses incurred regardless of the extent to which the 

emission control system is run. They are expressed in units of $ per kW per year. In calculating 

FOM Sargent & Lundy took into account labor and materials costs associated with operations, 

maintenance, and administrative functions. The following assumptions were made: 

• FOM for operations is based on the number of operators needed which is a function of 
94 

the size (i.e., MW capacity) of the generating unit. In general for DSI two (2) additional 

operators are assumed to be needed. 

• FOM for maintenance is a direct function of the DSI capital cost. 

• FOM for administration is a function of the FOM for operations and maintenance. 

Table 5-23 presents the capital, VOM, and FOM costs as well as the capacity and heat rate 

penalties of a DSI retrofit for an illustrative and representative set of generating units with the 

capacities and heat rates indicated. 

Illustration worksheets of the detailed calculations performed to obtain the capital, VOM, and 

FOM costs for an example DSI appear in Appendix 5-4. The worksheets were developed by 

Sargent & Lundy9

.

 

9

These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and 

Performance for APC Technologies: Complete Dry Sorbent Injection Cost Development Methodology 

(Project 12301-007), May 2010. The complete report is available for review and downloading at 

www.epa.gov/airmarkets/progsregs/epa-ipm/. 
95 

Table 5‐23. Illustrative Dry Sorbent Injection (DSI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA B

(Proposed Toxics Rule) .

Control 

Type 

Heat Rate 

(Btu/ 

kWh) 

SO2 

Rate 

(lb/ 

MMBtu) 

Capacity 

Penalty 

(%) 

Heat Rate 

Penalty 

(%) 

Variable 

O&M 

(mills/ 

kWh) 

Capacity (MW) 

100 300 500 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Cap

Co

($/k

DSI - FF 9,000 2.0 0.64 0.65 6.05 122 2.25 55 0.87 38 0.57 30 Assuming Bituminous Coal 

10,000 2.0 0.71 0.72 6.72 125 2.28 57 0.89 40 0.58 31 11,000 2.0 0.79 0.79 7.40 129 2.30 59 0.90 41 0.59 34 

DSI - ESP 9,000 2.0 1.08 1.10 11.23 141 2.41 64 0.94 47 0.64 47 Assuming Bituminous Coal 

10,000 2.0 1.20 1.22 12.47 145 2.44 66 0.96 52 0.68 52 11,000 2.0 1.32 1.34 13.72 149 2.48 68 0.98 58 0.73 58 
96 

 

5.5.4 Fabric Filter (Baghouse) Cost Development 

Fabric filters are not endogenously modeled as a separate retrofit option in EPA Base Case 

v4.10_PTox, but are accounted for as a cost adder where they are required for particulate 

matter (PM), mercury, or HCl emission control. In EPA Base Case v4.10_PTox, an existing or 

new fabric filter particulate control device is a pre-condition for installing a DSI retrofit. In the 

v4.10_PTox policy case any unit that was retrofit by the model with DSI and did not have an 

existing fabric filter incurred the cost of installing a fabric filter. This cost was added to the DSI 

costs discussed in section 5.5.3.2. This section describes the methodology used by Sargent & 

Lundy to derive the cost of a fabric filter. 

The engineering cost analysis is based on a pulse-jet fabric filter which collects particulate 

matter on a fabric bag and uses air pulses to dislodge the particulate from the bag surface and 

collect it in hoppers for removal via an ash handling system to a silo. This is a mature 

technology that has been operating commercially for more than 25 years. “Baghouse” and 

“fabric filters” are used interchangeably to refer to such installations. 

Capital Cost: Two governing variables are used to derive the bare module capital cost of a 

fabric filter. The first of these is the “air-to-cloth” (A/C) ratio. The major driver of fabric filter 

capital cost, the A/C ratio is defined as the volumetric flow, (typically expressed in Actual Cubic 

Feet per Minute, ACFM) of flue gas entering the baghouse divided by the areas (typically in 

square feet) of fabric filter cloth in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0 

compared to A/C = 6.0, the greater the area of the cloth required and the higher the cost for a 

given volumetric flow. 

The other determinant of capital cost is the flue gas volumetric flow rate (in ACFM) which is a 

function of the type of coal burned and the unit’s size and heat rate. 

The capital cost for fabric filters include: 

• Duct work modifications, 

• Foundations, 

• Structural steel, 

• Induced draft (ID) fan modifications or new booster fans, and 

• Electrical modifications. 

After the bare installed total capital cost is calculated, it is increased by 20% to account for 

additional engineering and construction management costs, labor premiums, and contractor 

profits and fees. The resulting value is the capital, engineering, and construction cost (CECC) 

subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to 

account for owner’s home office costs, i.e., owner’s engineering, management, and 

procurement costs, and by another 6% to account for Allowance for Funds used During 

Construction (AFUDC) which is premised on a 2-year project duration. 

The cost resulting from these calculations is the capital cost factor (expressed in $/kW). Fabric 

filter capital costs are implemented in EPA Base Case v4.10_PTox as an FOM adder. Plants 

that install fabric filters incur a total FOM charge which includes the true FOM associated with 

the fabric filter plus a capital cost FOM Adder derived by multiplying the capital cost by a capital 
97 

charge rate of 11.3%, i.e., 

Total FOM = True FOM + Capital Cost FOM Adder 

where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3% 

In EPA Base Case v4.10_PTox the capital cost of a fabric filter is based on the use of a 

“polishing” fabric filter designed with A/C=6.0. This basis results in a capital cost that is at least 

10% less than the cost of a design with A/C=4.0, and assumes that the existing ESP remains in 

place and active. 

Variable Operating and Maintenance Costs (VOM): For fabric filters the VOM is strictly a 

function of the costs of the fabric filter bag and cage translated in a $/MWhr cost based on the 

filter and bag replacement cycle for a specified A/C ratio. For units whose A/C ratio = 6.0, the 

replacement cycle for the bag is 3 years and the cage is 9 years, whereas for units whose A/C 

ratio = 4.0, the bag and cage replacement cycles are 5 and 10 years respectively. 

Capacity and Heat Rate Penalty: Conceptually, the capacity and heat rate penalties for fabric 

filters represent the amount of electrical power required to operate the baghouse and are 

calculated by the same procedure used when calculating the capacity and heat rate penalty for 

DSI as described in section 5.5.3.2. The resulting capacity and heat rate penalties are both 

0.6%. 

However, since fabric filters were not endogenously modeled as a retrofit option, but simply 

added to the DSI costs for generating units that do not have an existing baghouse, the capacity 

and heat rate penalties described here were not factored into the representation of fabric filters 

in EPA Base Case v4.10_PTox. 

Fixed Operating and Maintenance Costs (FOM): Sargent & Lundy’s engineering analysis 

indicated that no additional operations staff would be required for a baghouse. Consequently 

the FOM strictly includes two components: 

• FOM for maintenance is a direct function of the DSI capital cost. 

• FOM for administration is a function of the FOM for operations (which is zero) and 

maintenance. 

Table 5-24 presents the capital, VOM, and FOM costs for fabric filters as represented in EPA 

Base Case v4.10_PTox for an illustrative set of generating units with a representative range of 

capacities and heat rates. 

Worksheets illustrating the detailed calculations performed to obtain the capital, VOM, and FOM 

costs for two example fabric filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) appear in Appendix 5-

5. The worksheets were developed by Sargent & Lundy10. 

 

10 These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and 

Performance for APC Technologies: Particulate Control Cost Development Methodology (Project 12301-

009), October 2010. The complete report is available for review and downloading at 

www.epa.gov/airmarkets/progsregs/epa-ipm/. 
98 

Table 5‐24. Illustrative Fabric Filter (Baghouse) Costs for Representative Sizes and Heat Rates Under Assumptions in E

(Proposed Toxics Rule) .

Coal Type 

Heat Rate 

(Btu/ 

kWh) 

Capacity 

Penalty 

(%) 

Heat Rate 

Penalty 

(%) 

Variable 

O&M 

(mills/ 

kWh) 

Capacity (MW) 

100 300 500 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capit

Cost 

($/kW

Bituminous 

9,000 

0.60 0.60 0.15 

188 0.8 153 0.6 139 0.6 130 

10,000 205 0.9 167 0.7 151 0.6 141 11,000 221 0.9 180 0.8 163 0.7 153 

Notes on Implementation 1. Plant specific fabric filter capital costs shown in this table are implemented in EPA Base Case v4.10_PTox as an FOM fabric filters incur a total FOM charge which includes the true FOM component shown in the above table plus a capital cosmultiplying the capital cost in the table above by a capital charge rate 11.3%, i.e.,  Total FOM = True FOM + Capital Cost FOM Adder where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%.Plants that install fabric filters also incur the additional VOM costs shown in the above table. 2. Since the fabric filter costs were not endogenously modeled as a retrofit option, the capacity and heat rate penalties shonot represented in the model. 
99 

Appendix 5-3 Example Cost Calculation Worksheets for Three Activated Carbon Injection 

(ACI) Options for Mercury Emission Control in EPA Base Case v4.10_PTox (Proposed 

Toxics Rule) 
100 
101 
102 

Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCl 

(and SO2) Emissions Control in EPA Base Case v4.10_PTox (Proposed Toxics Rule) 
103 
104 

Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filters (A/C Ratio = 4.0 

and A/C Ratio = 6.0) in EPA Base Case v4.10_PTox (Proposed Toxics Rule) 
105 
106 

Documentation Supplement to Chapter 9 (“Coal”)

To allow HCl emissions to be modeled, the chlorine content of the coal offered to electric 

generating units in EPA Base Case v4.10_PTox had to be represented in the model. This 

involved adding data on coal chlorine content and then re-running the clustering set-up 

procedure, which makes the coal quality data usable in the model. The following discussion will 

refer to the HCl emission rate (in lbs/MMBtu) of the coal and the chlorine content of the coal 

interchangeably. The HCl emission rate is obtained by multiplying the chlorine content of the 

coal by a factor of 1.03. This is an alternate way of expressing chlorine content and is 

consistent with using an SO2 emission rate (in lbs/MMBtu) to express the sulfur content of the 

coal. 

For EPA Base Case v4.10 the clustering procedure was performed on SO2 and mercury data 

only. For Base Case v4.10_PTox it had to be performed jointly on the SO2, mercury, and HCl 

data. The addition of HCl data and the consequent re-clustering are reflected in complete 

updates of Tables 9-5 through 9-9 and the addition of a new table for HCl equivalent to Tables 

9-6 through 9-9. These tables show the SO2, mercury, ash, HCl, and CO2 emission factors that 

result after the clustering procedure is performed. 

The enhancements made to accommodate the HCl data in the model are documented below in 

the form of a mark-up of sections 9.1.3 (“Coal Quality Characteristics”) and 9.1.4 (“Emission 

Factors”) of the v4.10 documentation report “Documentation for EPA Base Case v4.10 Using 

the Integrated Planning Model” (August 2010). Substantive changes to the original text are 

shown in red, boldface italics. Revised Tables 9-5 through 9-9 and the new HCl emission factor 

Table 9-10 are shown without special highlighting. 

Note: For EPA Base Case v4.10_PTox the only coal assumptions and procedures which 

changed are those presented in sections 9.1.3 and 9.1.4 below. The other unchanged sections 

of Chapter 9 can be found at www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter9.pdf. 

************************************************************************************************************* 

9 Coal

● ● ●

9.1.3 Coal Quality Characteristics 

Coal varies by heat content, SO2 content, HCl content, and mercury content among other 

characteristics. To capture differences in the sulfur and heat content of coal, a two letter “coal 

grade” nomenclature is used. The first letter indicates the “coal rank” (bituminous, subbituminous, or lignite) with their associated heat content ranges (as shown in Table 9-3). The 

second letter indicates their “sulfur grade,” i.e., the SO2 ranges associated with a given type of 

coal. (The sulfur grades and associated SO2 ranges are shown in Table 9-4.) 

Table 9-3 Coal Rank Heat Content Ranges

Coal Type Heat Content 

(Btu/lb) Classification 

Bituminous >10,260 – 13,000 B

Sub-bituminous > 7,500 – 10,260 S
107 

Lignite less than 7,500 L

Table 9-4 Coal Grade SO2 Content Ranges

SO2 Grade SO2 Content Range (lbs/MMBtu) 

A 0.00 – 0.80 

B 0.81 – 1.20 

D 1.21 – 1.66 

E 1.67 – 3.34 

G 3.35 – 5.00 

H > 5.00 

The assumptions in EPA Base Case v4.10_PTox regarding the heat, HCl, mercury, SO2, and 

ash content of coal are derived from EPA’s “Information Collection Request for Electric Utility 

Steam Generating Unit Mercury Emissions Information Collection Effort” (ICR)11. A two-year 

effort initiated in 1998 and completed in 2000, the ICR had three main components: 

(1) identifying all coal-fired units owned and operated by publicly-owned utility companies, 

Federal power agencies, rural electric cooperatives, and investor-owned utility generating 

companies, (2) obtaining “accurate information on the amount of mercury contained in the asfired coal used by each electric utility steam generating unit... with a capacity greater than 25 

megawatts electric, as well as accurate information on the total amount of coal burned by each 

such unit,”, and (3) obtaining data by coal sampling and stack testing at selected units to 

characterize mercury reductions from representative unit configurations. Data regarding the 

SO2, chlorine, and ash content of the coal used were obtained along with mercury content. 

The 1998-2000 ICR resulted in more than 40,000 data points indicating the coal type, sulfur 

content, mercury content, ash content, chlorine content, and other characteristics of coal 

burned at coal-fired utility units greater than 25 MW. 

9.1.4 Emission Factors 

To make this data usable in EPA Base Case v4.10_PTox, the ICR data points were first 

grouped by IPM coal grades and IPM coal supply regions. Using the grouped ICR data, the 

average heat, SO2, mercury, HCl, and ash content were calculated for each coal grade/supply 

region combination. In instances where no data were available for a particular coal grade in a 

specific supply region, the national average SO2, HCl, and mercury values for the coal grade 

were used as the region’s values. The resulting values are shown in Table 9-5. 

 

11 Data from the ICR can be found at www.epa.gov/ttn/atw/combust/utiltox/mercury.html. 
108 

Table 9-5 Coal Quality Characteristics by Supply Region and Coal Grade in EPA Base Case v4.10_PTox

Coal 

Supply 

Region 

Coal 

Grade 

Heat Content 

(MMBtu/Ton) 

SO2

Content 

(lbs/MMBtu) 

Mercury 

Content 

(lbs/TBtu) 

Ash 

Content 

(lbs/MMBtu) 

HCl Content

(lbs/MMBtu) 

Cluster 

Number 

AL 

BB 24.82 1.1 4.2 9.8 0.012 1 

BD 24.00 1.4 7.3 10.8 0.029 6 

BE 23.82 2.7 12.6 10.7 0.028 1 

AZ BB 24.64 1.1 5.3 7.9 0.067 2 

CG BA 21.49 0.7 3.1 7.3 0.040 3 

BB 22.01 0.9 4.1 8.4 0.021 1 

CR 

BA 25.50 0.7 3.5 7.0 0.027 5 

BD 22.20 1.4 7.0 8.3 0.096 6 

CU 

BA 23.80 0.7 2.6 6.3 0.007 1 

BB 23.22 0.9 4.0 7.8 0.009 1 

BD 23.21 1.3 3.1 8.1 0.008 1 

IL 

BE 23.00 2.2 6.5 6.6 0.214 3 

BG 23.01 4.6 6.5 8.1 0.113 2 

BH 22.19 5.6 5.4 9.1 0.103 1 

IN 

BD 22.62 1.4 3.8 7.4 0.030 5 

BE 23.43 2.3 5.2 8.0 0.037 3 

BG 23.37 4.3 7.2 8.2 0.028 2 

BH 23.41 6.1 7.1 8.6 0.019 2 

KE 

BA 25.32 0.7 3.0 6.1 0.114 4 

BB 25.79 1.0 4.8 6.4 0.112 5 

BD 25.33 1.4 6.0 7.4 0.087 4 

BE 25.14 2.1 7.9 7.7 0.076 4 

BG 24.09 3.8 12.0 10.2 0.041 3 

KS BG 25.32 4.8 4.1 8.5 0.133 4 

KW 

BD 24.23 1.6 5.6 6.2 0.281 4 

BE 24.45 2.8 7.1 7.4 0.199 3 

BG 23.93 4.5 6.9 8.0 0.097 2 

BH 22.84 5.7 8.2 10.2 0.054 3 

LA LE 14.09 2.5 7.3 17.1 0.014 2 

MD 

BB 24.64 1.1 5.3 7.9 0.067 2 

BD 26.32 1.6 7.8 9.5 0.029 6 

BE 24.85 2.8 15.6 11.7 0.072 6 

BG 23.26 3.6 16.6 16.6 0.018 5 

ME LD 13.36 1.4 8.6 11.3 0.019 1 

MP 

SA 18.90 0.6 4.2 4.0 0.007 1 

SD 17.23 1.5 4.5 10.1 0.006 1 

MS LE 13.19 2.8 12.4 21.5 0.018 1 

MT BB 21.00 1.1 5.3 7.9 0.067 2 

ND LD 13.70 1.5 6.4 10.7 0.012 1 

LE 13.46 2.3 8.3 12.8 0.014 2 

NS 

BB 26.40 1.1 5.3 7.9 0.067 2 

BD 18.10 1.6 5.5 19.6 0.005 4 

BE 18.10 1.8 8.2 18.8 0.006 4 

OH 

BB 24.68 1.1 5.7 9.8 0.083 6 

BD 25.55 1.4 6.4 10.3 0.065 4 

BE 25.24 3.1 18.7 7.1 0.075 5 

BG 24.34 4.0 18.5 8.0 0.072 5 

BH 23.92 6.4 13.9 9.1 0.058 4 
109 

Table 9-5 (cont’d): Coal Quality Characteristics by Supply Region and Coal Grade in EPA Base Case 

v4.10_PTox 

Coal 

Supply 

Region 

Coal Grade 

Heat 

Content 

(MMBtu/Ton) 

SO2

Content 

(lbs/MMBtu) 

Mercury 

Content 

(lbs/TBtu) 

Ash 

Content 

(lbs/MMBtu) 

HCl Content

(lbs/MMBtu) 

Cluster 

Number 

OK BE 22.15 2.7 25.8 11.3 0.033 2 

PC 

BD 25.06 1.4 21.7 49.3 0.066 2 

BE 25.66 2.6 18.0 9.2 0.096 5 

BG 25.33 3.8 21.5 9.6 0.092 1 

BH 23.39 6.3 34.7 13.9 0.149 5 

PW 

BD 24.26 1.6 11.2 10.0 0.086 3 

BE 26.22 2.5 8.4 5.4 0.091 4 

BG 25.86 3.7 8.6 6.5 0.059 2 

TN 

BB 24.18 1.1 3.8 10.4 0.084 3 

BD 23.91 1.3 6.3 10.4 0.083 4 

BE 26.75 2.1 8.4 6.5 0.043 4 

TX 

LD 13.06 1.6 12.0 22.3 0.028 2 

LE 13.22 3.0 14.7 25.6 0.020 1 

LG 12.27 3.9 14.9 25.5 0.036 1 

UT 

BA 23.68 0.7 4.4 7.4 0.015 2 

BB 23.23 0.9 3.9 8.6 0.016 1 

BD 23.05 1.4 4.4 10.5 0.026 5 

BE 25.06 2.3 9.2 7.4 0.095 4 

VA 

BA 22.70 0.7 3.5 7.0 0.027 5 

BB 25.97 1.0 4.6 7.0 0.054 5 

BD 25.76 1.4 5.7 8.0 0.028 4 

BE 26.03 2.1 8.4 8.1 0.028 4 

WG BB 21.67 1.1 1.8 5.6 0.005 4 

SD 18.50 1.3 4.3 10.0 0.008 2 

WH 

SA 17.43 0.6 5.6 5.5 0.012 2 

SB 17.43 0.9 6.4 6.5 0.012 1 

WL SB 17.15 0.9 6.4 6.5 0.012 1 

WN 

BD 25.01 1.5 10.3 9.2 0.100 3 

BE 25.67 2.5 10.3 7.9 0.092 4 

BG 26.03 4.0 9.3 6.9 0.075 2 

BH 25.15 6.1 8.8 9.6 0.045 3 

WS 

BA 26.20 0.7 3.5 7.0 0.027 5 

BB 24.73 1.1 5.7 9.2 0.091 6 

BD 24.64 1.3 8.1 9.3 0.098 6 

BE 24.38 1.9 8.8 9.9 0.102 4 

BG 25.64 4.7 7.1 6.4 0.051 2 
110 

Next, a clustering algorithm was used to further aggregate the data in EPA Base Case 

v4.10_PTox, for model size management purposes. The clustering analysis was performed on 

the mercury, HCl, and SO2 data shown in Table 9-5 using the SAS statistical software package. 

Clustering analysis places objects into groups or clusters, such that data in a given cluster tend 

to be similar to each other and dissimilar to data in other clusters. The clustering analysis 

involved two steps. (In the following write-up BG coal is used to illustrate how the procedure 

worked.) First, the number of clusters of mercury, HCl, and SO2 concentrations for each IPM 

coal type was determined based on the range in average mercury, HCl, and SO2

concentrations across all coal supply regions for a specific coal type. In EPA Base Case v4.10

each coal type used either one or two clusters. After adding the HCl data in EPA Base Case 

v4.10_PTox, three coal grades (BB, BD, and BE) were assigned 6 clusters, another three 

coal grades (BA, BG, and BH) were assigned 5 clusters, four coal grades (SA, SD, LD, LE) 

were assigned 2 clusters, and two grades (SB, and LG) were assigned one cluster each. 

The total number of clusters for each coal grade was limited to keep the model size and run 

time within feasible limits. (Whereas three clusters were used for BG coal in v4.10, with the 

addition of HCl as a clustering parameter, five clusters were needed for BG coal in 

v4.10_PTox.) Second, for each coal grade the clustering procedure was applied to all the 

regional SO2, HCl, and mercury values shown in Table 9-5 for that coal grade. (In the BG coal 

example there are 11 such regional SO2, HCl, and mercury values.) Using the SAS cluster 

procedure, each of the constituent regional values was assigned to a cluster and the cluster 

average SO2, HCl, and mercury values were recorded. The resulting values are shown in 

Tables 9-6, 9-7, and Table 9-10. (For BG coal the Cluster #1 average SO2, HCl, and mercury 

values are 3.79 lbs/MMBtu, 0.092 lbs/MMBtu, and 21.54 lbs/TBtu respectively. The Cluster #2 

average SO2, HCl, and mercury values are 4.28 lbs/MMBtu, 0.070 lbs/MMBtu, and 7.60

lbs/TBtu respectively. The Cluster #3 average SO2, HCl, and mercury values are 3.79

lbs/MMBtu, 0.041 lbs/MMBtu, and 11.99 lbs/TBtu respectively. The Cluster #4 average SO2, 

HCl, and mercury values are 4.84 lbs/MMBtu, 0.133 lbs/MMBtu, and 4.09 lbs/TBtu 

respectively. The Cluster #5 average SO2, HCl, and mercury values are 3.78 lbs/MMBtu, 

0.045 lbs/MMBtu, and 17.59 lbs/TBtu respectively.) 

Although not used in determining the clusters, ash and CO2 values were calculated for each of 

the clusters. These values are shown in Table 9-8 and Table 9-9. (The CO2 values were derived 

from data in the Energy Information Administration’s Annual Energy Outlook 2009 (AEO 2009), 

not from data collected in the ICR.) 

IPM input files retain the mapping between different coal grade/supply region combinations and 

the clusters. The mapping can be seen in the last column of Table 9-5 which shows the cluster 

number associated with the coal grade/supply region combination indicated in the first and 

second columns of this table. (For BG coal, the SAS cluster procedure mapped supply region 

PC into Cluster #1, IL, IN, KW, PW,WN and WS into Cluster #2, KE into Cluster #3, KS into 

Cluster #4, and MD and OH into Cluster #5.. See Figure 9-2 for an illustration of this 

mapping.) Table 9-6 to Table 9-10 show the SO2, mercury, ash, CO2, and HCl values that are 

assigned to coal grades and regions based on this cluster mapping. The values shown in Table 

9-6 to Table 9-10 are used in EPA Base Case v4.10 for calculating emissions. 

 
111 

Table 9-6 SO2 Emission Factors of Coal Used in EPA Base Case v4.10_PTox 

Coal Type by Sulfur Grade 

Sulfur Emission Factors (lbs/MMBtu) 

Cluster 

#1 

Cluster 

#2 

Cluster # 

3 

Cluster 

#4 

Cluster # 

5 

Cluster # 

6 

Low Sulfur Eastern Bituminous (BA) 0.70 0.67 0.72 0.74 0.68 -- 

Low Sulfur Western Bituminous (BB) 0.95 1.05 1.14 1.13 1.04 1.08 

Low Medium Sulfur Bituminous (BD) 1.31 1.42 1.51 1.46 1.41 1.41 

Medium Sulfur Bituminous (BE) 2.68 2.68 2.46 2.19 2.82 2.78 

High Sulfur Bituminous (BG) 3.79 4.28 3.79 4.84 3.78 -- 

High Sulfur Bituminous (BH) 5.58 6.15 5.91 6.43 6.29 -- 

Low Sulfur Subbituminous (SA) 0.62 0.58 -- -- -- -- 

Low Sulfur Subbituminous (SB) 0.94 -- -- -- -- -- 

Low Medium Sulfur Subbituminous 

(SD) 1.49 1.33 -- -- -- -- 

Low Medium Sulfur Lignite (LD) 1.46 1.61 -- -- -- -- 

Medium Sulfur Lignite (LE) 2.88 2.38 -- -- -- -- 

High Sulfur Lignite (LG) 3.91 -- -- -- -- -- 

Table 9-7 Mercury Emission Factors of Coal Used in EPA Base Case v4.10_PTox 

Coal Type by Sulfur Grade 

Mercury Emission Factors (lbs/Tbtu) 

Cluster 

#1 

Cluster 

#2 

Cluster 

#3 

Cluster 

#4 

Cluster # 

5 

Cluster # 

6 

Low Sulfur Eastern Bituminous (BA) 2.55 4.37 3.07 3.01 3.50 -- 

Low Sulfur Western Bituminous (BB) 4.05 5.27 3.78 1.82 4.70 5.84 

Low Medium Sulfur Bituminous (BD) 3.13 21.67 10.76 5.91 4.08 7.54 

Medium Sulfur Bituminous (BE) 12.58 25.83 6.28 8.70 18.33 15.62 

High Sulfur Bituminous (BG) 21.54 7.60 11.99 4.09 17.59 -- 

High Sulfur Bituminous (BH) 5.43 7.11 8.49 13.93 34.71 -- 

Low Sulfur Subbituminous (SA) 4.24 5.61 -- -- -- -- 

Low Sulfur Subbituminous (SB) 6.44 -- -- -- -- -- 

Low Medium Sulfur Subbituminous 

(SD) 4.53 4.33 -- -- -- -- 

Low Medium Sulfur Lignite (LD) 7.51 12.00 -- -- -- -- 

Medium Sulfur Lignite (LE) 13.55 7.81 -- -- -- -- 

High Sulfur Lignite (LG) 14.88 -- -- -- -- -- 

 
112 

Table 9-8 Ash Emission Factors of Coal Used in EPA Base Case v4.10_PTox 

Coal Type by Sulfur Grade 

Ash Emission Factors (lbs/MMBtu) 

Cluster 

#1 

Cluster 

#2 

Cluster 

#3 

Cluster 

#4 

Cluster # 

5 

Cluster # 

6 

Low Sulfur Eastern Bituminous (BA) 6.31 7.39 7.26 6.09 6.99 -- 

Low Sulfur Western Bituminous (BB) 8.65 7.86 10.35 5.59 6.69 7.87 

Low Medium Sulfur Bituminous (BD) 8.12 49.31 9.61 10.33 8.97 9.49 

Medium Sulfur Bituminous (BE) 10.70 11.35 7.34 8.95 8.16 11.71 

High Sulfur Bituminous (BG) 9.59 7.35 10.21 8.47 12.30 -- 

High Sulfur Bituminous (BH) 9.06 8.63 9.91 9.13 13.89 -- 

Low Sulfur Subbituminous (SA) 3.98 6.50 -- -- -- -- 

Low Sulfur Subbituminous (SB) 6.50 -- -- -- -- -- 

Low Medium Sulfur Subbituminous 

(SD) 10.13 10.02 -- -- -- -- 

Low Medium Sulfur Lignite (LD) 11.01 22.33 -- -- -- -- 

Medium Sulfur Lignite (LE) 23.58 15.00 -- -- -- -- 

High Sulfur Lignite (LG) 25.51 -- -- -- -- -- 

Table 9-9 CO2 Emission Factors of Coal Used in EPA Base Case v4.10_PTox 

Coal Type by Sulfur Grade 

CO2 Emission Factors (lbs/MMBtu) 

Cluster 

#1 

Cluster 

#2 

Cluster 

#3 

Cluster 

#4 

Cluster # 

5 

Cluster # 

6 

Low Sulfur Eastern Bituminous (BA) 205.4 205.4 205.4 205.4 205.4 -- 

Low Sulfur Western Bituminous (BB) 205.8 205.8 205.8 205.8 205.8 205.8 

Low Medium Sulfur Bituminous (BD) 206.6 206.6 206.6 206.6 206.6 206.6 

Medium Sulfur Bituminous (BE) 206.3 206.3 206.3 206.3 206.3 206.3 

High Sulfur Bituminous (BG) 205.2 205.2 205.2 205.2 205.2 -- 

High Sulfur Bituminous (BH) 205.2 205.2 205.2 205.2 205.2 -- 

Low Sulfur Subbituminous (SA) 213.1 213.1 -- -- -- -- 

Low Sulfur Subbituminous (SB) 212.7 -- -- -- -- -- 

Low Medium Sulfur Subbituminous 

(SD) 213.1 213.1 -- -- -- -- 

Low Medium Sulfur Lignite (LD) 217.0 217.0 -- -- -- -- 

Medium Sulfur Lignite (LE) 214.8 214.8 -- -- -- -- 

High Sulfur Lignite (LG) 213.5 -- -- -- -- -- 

 
113 

Table 9-10 HCl Emission Factors of Coal Used in EPA Base Case v4.10_PTox 

Coal Type by Sulfur Grade 

HCl Emission Factors (lbs/MMBtu) 

Cluster 

#1 

Cluster 

#2 

Cluster 

#3 

Cluster 

#4 

Cluster # 

5 

Cluster # 

6 

Low Sulfur Eastern Bituminous (BA) 0.007 0.015 0.040 0.114 0.027 -- 

Low Sulfur Western Bituminous (BB) 0.015 0.067 0.083 0.005 0.083 0.065 

Low Medium Sulfur Bituminous (BD) 0.008 0.066 0.092 0.091 0.028 0.063 

Medium Sulfur Bituminous (BE) 0.028 0.033 0.150 0.067 0.085 0.072 

High Sulfur Bituminous (BG) 0.092 0.070 0.041 0.133 0.045 -- 

High Sulfur Bituminous (BH) 0.103 0.019 0.049 0.058 0.148 -- 

Low Sulfur Subbituminous (SA) 0.007 0.010 -- -- -- -- 

Low Sulfur Subbituminous (SB) 0.012 -- -- -- -- -- 

Low Medium Sulfur Subbituminous 

(SD) 0.006 0.008 -- -- -- -- 

Low Medium Sulfur Lignite (LD) 0.016 0.028 -- -- -- -- 

Medium Sulfur Lignite (LE) 0.019 0.014 -- -- -- -- 

High Sulfur Lignite (LG) 0.036 -- -- -- -- -- 
114 

 Figure 9-2 Cluster Mapping Example – BG Coal 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

Mercury Control Cost Development Methodology

Final

March 2011 

Project 12301-009 

Systems Research and Applications Corporation 

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000 
 

LEGAL NOTICE 

This analysis (“Deliverable”) was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole 

use of Systems Research and Applications Corporation ("Client") in accordance with the agreement 

between S&L and Client. This Deliverable was prepared using the degree of skill and care ordinarily 

exercised by engineers practicing under similar circumstances. Client acknowledges: (1) S&L prepared 

this Deliverable subject to the particular scope limitations, budgetary and time constraints, and business 

objectives of the Client; (2) information and data provided by others may not have been independently 

verified by S&L; and (3) the information and data contained in this Deliverable are time sensitive and 

changes in the data, applicable codes, standards, and acceptable engineering practices may invalidate the 

findings of this Deliverable. Any use or reliance upon this Deliverable by third parties shall be at their sole 

risk. 

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of 

William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by 

Dr. Jim Staudt, President of Andover Technology Partners. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 3 

Technology Description 

Activated carbon injection (ACI) is a viable technology for mercury (Hg) reduction on 

coal fired boilers. The ACI technology is fairly new but is gaining acceptance. Currently 

less than 10% of the U.S. coal fired boiler flue gas (based on power produced) is treated 

for Hg by ACI. Many domestic new and retrofit units require Hg control to meet 

operating permits in accordance with the limits set forward in state regulations and/or 

consent decrees. Due to the limits set forth by these regulations, and future legislation, 

mercury removal of greater than 90% will likely be required. Commercial experience has 

shown that ACI can meet a 90% reduction in total Hg in some cases. 

It should be noted that with the addition of an ACI system, and capture of the carbon in 

the same particulate collector as the fly ash, beneficial use of the fly ash may be limited. 

The carbon may prevent sale of the fly ash to the cement markets. Even the “concrete 

friendly” activated carbons are not well accepted in the cement industry without prior 

testing by the fly ash purchaser. 

Mercury Speciation 

Mercury is contained in varying concentrations in different coal supplies. During 

combustion, mercury is released in the form of elemental mercury. As the combustion 

gases cool, a portion of the mercury transforms to ionic mercury. Ultimately, there are 

three possible forms of mercury: 

• Elemental (Hg0

), 

• Ionic or Oxidized (Hg++), or 

• Particulate. 

The conversion of elemental mercury to the other forms depends upon several factors; 

cooling rate of the gas, presence of halogens or SO3 in the flue gas, amount and 

composition of fly ash, presence of unburned carbon, and the installed air pollution 

control equipment. 

Considering the interaction of the various parameters, ionic mercury can vary between 

10% and 90% of the total mercury in the flue gas. Particulate mercury generally ranges 

from about 5-15% of the total mercury. The remainder is elemental mercury that 

typically makes up 10-90% of the total mercury. 

Air Pollution Control Equipment Co-Benefits 

SCR catalysts promote the oxidation of elemental mercury. However, the extent of 

oxidation through the SCR catalyst beds can be limited by other factors, such as low flue 

gas halogen concentrations and amount of catalyst available for Hg oxidation after the 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 4 

ammonia adsorption on surface is minimal. SCR systems may have the ability to convert 

some elemental mercury to ionic mercury depending on the halide content in the coal. 

The catalyst used in SCR systems is designed to facilitate the conversion of NOx to N2

and H2O. The active ingredient used in SCR catalysts is vanadium pentoxide, which 

oxidizes sulfur dioxide (SO2) to sulfur trioxide (SO3) as well as elemental mercury to 

ionic mercury. Mercury oxidation is inhibited by ammonia injection. Typically, most of 

the mercury oxidation occurs in the last layer of catalyst where the concentration of 

ammonia is the lowest. 

Another mechanism of mercury oxidation occurs across fabric filter elements in a 

baghouse. Unburned carbon in the fly ash accumulates in the filter cake on the filter 

elements. The unburned carbon oxidizes Hg0 to Hg++ in the presence of chlorides in the 

flue gas. The degree of oxidation depends on the quantity of unburned carbon present in 

the filter cake. The ionic mercury converted in a baghouse could be captured by an FGD 

system downstream of the baghouse. 

Through intimate contact of the flue gas with the filter cake on the fabric filters, mercury 

can be adsorbed on the carbon particles present in the fly ash. The mercury is bound to 

the particulates in the filter cake and the particulate mercury is removed at the same 

efficiency as the solids. For this reason, fabric filters can result in extremely high 

mercury capture depending on the unburned carbon concentration or can improve the 

capture with activated carbon injection. 

Mercury Capture 

The speciation of the mercury plays a significant role in its capture. Elemental mercury 

is insoluble in water. Therefore, Hg0

 is not collected in downstream FGD systems. Nor 

do particulate collectors remove elemental mercury. Elemental mercury can be removed 

with ACI or it must be converted to another form to be captured in downstream FGD 

systems. 

Some flue gas constituents, especially SO3, reduce the effectiveness of the ACI. With 

flue gas SO3 concentrations greater than 5 - 7 ppmv, the carbon feed rate must be 

increased significantly to meet a high Hg removal and 90% mercury removal may not be 

feasible in some cases even with ACI. Based on commercial testing, the capacity of the 

activated carbon can be cut by as much as one half with an SO3 increase from just 5 

ppmv to 10 ppmv. Some utilities are testing the injection of alkali (typically Trona) 

before the ACI system to reduce the SO3 concentration. For the purposes of this 

evaluation, no alkali injection was included. Any benefits from alkali injection would 

reduce the carbon feed rate and subsequently reduce the costs estimated in this study. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 5 

In contrast to elemental mercury, ionic mercury is highly water soluble. In dry FGD 

systems, the ionic mercury is captured in the injected lime slurry. Dry FGD systems 

evaporate the liquid phase, allowing the ionic mercury to be removed with the solid byproduct in the baghouse. In wet FGD systems, ionic mercury is soluble in the liquid. 

The captured mercury leaves the system with the purge water or the mercury can bind 

with the solid phases in the FGD slurry and leave with the solid by-product. Recent 

commercial data indicates that some of the ionic mercury captured by the wet FGD can 

be reduced to the elemental form and be re-emitted to the stack under certain 

circumstances. Extensive testing is on-going to determine the mechanism for re-emission 

and to develop additives to mitigate the problem. For the purposes of the cost estimation, 

a wet FGD additive that eliminates re-emission is modeled as an additional variable 

operating cost. 

Particulate mercury is removed very efficiently from the flue gas by the particulate 

control device. Therefore, it is desirable to convert as much mercury as possible to 

particulate mercury. High SO3 levels have been shown to inhibit the binding of ionic 

mercury to fly ash or carbon. Low halogen levels in the coal will also inhibit formation 

of particulate mercury by first inhibiting formation of ionic mercury. Activated carbon 

and addition of halogens increase the conversion of elemental and ionic mercury to 

particulate mercury. 

Establishment of Cost Basis 

Commercial experience indicates that wet or dry FGD systems can capture up to 90% of 

the ionic mercury. SCR catalysts can convert much of the elemental mercury to ionic 

mercury in the presence of halogens. When an SCR exists and there are relatively high 

halogen concentrations in the flue gas, about 90% of the mercury will be ionic mercury. 

Therefore, the maximum capture by an FGD following an SCR would be around 80% of 

the total mercury if there is no re-emission. 

Bituminous coals will have relatively high halogen concentrations in the flue gas. So flue 

gas mercury from bituminous coals that is treated by an SCR could be approximately 

90% ionic mercury. ACI is not required when an FGD system exists downstream of an 

SCR for bituminous fuels and the required total mercury removal is less than 80%. To 

ensure full wet FGD co-benefit capture, costs are included to provide slurry additives that 

inhibit re-emission of the mercury. Both capital and variable O&M costs were included 

for the slurry additive injection system. If a total mercury removal of greater than 80% is 

required, an ACI system must be installed and no slurry additives are required. However, 

alkali injection may be required for SO3 control to meet the removal requirements with 

ACI. No costs were included for alkali injection. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 6 

PRB and lignite coals have relatively low halogen concentrations. For those fuels, coal 

additives are required to promote ionic mercury speciation. With an SCR followed by an 

FGD and coal additives included, a maximum of 80% total mercury removal could be 

achieved without an ACI system. Coal additives, for PRB and lignite fuels, are included 

in the cost estimate when an SCR and an FGD system exist and the total mercury 

removal is less than 80%. In that case, an ACI system should not be required. The coal 

additive costs include capital, variable O&M and a one time royalty fee associated with 

the injection process. If a removal of greater than 80% of the total mercury is required, 

an ACI system would need to be installed and no coal additives may be required. 

When an ACI system is required, the design carbon feed rate will dictate the size of the 

ACI equipment and the resulting capital costs. The carbon feed rate is a function of 

required removal, particulate collection device, and in some cases state regulations. 

A consistent basis was established to calculate the carbon feed rate. The activated carbon 

rate was based on the use of brominated carbon. Current industry experience indicates 

that 5 pounds of carbon injected for every 1,000,000 acfm of flue gas will ensure 

adequate mercury capture and is a common design target for systems with an ESP. When 

a baghouse is used to capture the carbon, a reduced feed rate of 2 pounds of carbon 

injected for every 1,000,000 acfm is generally acceptable. No co-benefit removal was 

considered in the carbon feed rate. No additional alkali injection was included to remove 

SO3 or other inhibitors. In summary: 

• 5 lb per 1,000,000 acfm carbon feed rate with an ESP 

• 2 lb per 1,000,000 acfm carbon feed rate with a baghouse 

• Flue gas rate established after the air preheater 

• No co-benefit or other unit operations considered 

• No alkali injection considered 

To account for all of the variables, the capital cost was established based on the actual 

anticipated activated carbon feed rate, not the plant power rating. Cost data for several 

ACI systems was reviewed and a relationship was developed for the capital costs of the 

system on a carbon feed rate basis. 

Another capital cost impact from ACI systems is often the addition of a baghouse to 

capture the carbon. A baghouse can be required for several reasons: 

• The existing ESP cannot remove the additional particulate load associated 

with the activated carbon injection. 

• A new baghouse should be installed whenever flue gas conditioning (SO3

injection) is required for the existing ESP. Use of flue gas conditioning 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 7 

indicates that the existing ESP is marginally acceptable for the current solids 

load and the additional ACI load would result in excessive particulate 

emissions. 

• PRB coals tend to be low in chloride; therefore, most of the flue gas mercury 

is elemental mercury. Installation of a baghouse can result in varying degrees 

of oxidation of the elemental mercury through contact with the unburned 

carbon in the fly ash. The oxidized mercury may be captured in downstream 

FGD systems. Mercury oxidation does not proceed at the same rate through 

an ESP. 

A polishing baghouse with an air-to-cloth (A/C) ratio of 6.0 should be considered when 

the baghouse is installed after an existing particulate capture device that will remain in 

service to capture the majority of the fly ash. The ACI system would be installed 

downstream of the existing particulate capture device and upstream of the new baghouse. 

The design has two benefits. First, a smaller capital investment is required for a 

polishing baghouse when compared to a full sized baghouse. Second, any beneficial use 

of the fly ash can be maintained. 

A full sized baghouse, with an A/C ratio of 4.0, should be specified when the baghouse 

will be the primary particulate collection device for the fly ash and activated carbon. The 

lower A/C ratio will provide better bag life with the high inlet particulate loading 

expected for the single particulate capture device in the process. 

Capital costs were developed for the baghouse addition. The option to include a 4.0 A/C 

or a 6.0 A/C baghouse or not to include a baghouse is left to the user of the cost 

algorithm. Cost data from the S&L current database of projects, for several different 

baghouse installations, was reviewed and a relationship was developed for the capital 

costs of the system on a flue gas rate basis. The capital costs include: 

• Duct work modifications, 

• Foundations, 

• Structural steel, 

• ID fan modifications or new booster fans, and 

• Electrical modifications. 

Methodology 

Inputs 

Several input variables are required in order to predict the total future retrofit costs: 

• Type of coal, 

• Unit size, 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 8 

• Unit heat rate, and 

• Baghouse addition option and required size. 

A retrofit factor that equates to difficulty in construction of the system must be defined. 

Outputs 

Total Project Costs (TPC) 

First the base installed cost for the complete ACI system is calculated (BMC). Then a 

base installed cost for the baghouse (as applicable) is calculated (BMB). However, if an 

ACI system is not needed because of the existing equipment co-benefit capture, some 

form of additive addition may be required. If a wet FGD is used to remove 90% of the 

ionic mercury, slurry additives may be required. A base module price for the slurry 

additives would be included in the capital estimate (BMF). If PRB or lignite is fired, and 

the total mercury removal is less than 80%, then additional halogens must be added to the 

coal. The installed capital cost for the coal additive system is included as applicable 

(BMA). The base installed costs include: 

• All equipment; 

• Installation; 

• Buildings; 

• Foundations; 

• Electrical; and 

• Average retrofit difficulty. 

The base installed costs are then increased by: 

• Engineering and construction management costs at 5% of the BM cost; 

• Labor adjustment for 6 x 10 hour shift premium, per diem, etc., at 5% of the 

BM cost; and 

• Contractor profit and fees at 5% of the BM cost. 

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of 

the BM and the additional engineering and construction fees. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 9 

Additional costs and financing expenditures for the project are computed based on the 

CECC. Financing and additional project costs include: 

• Owner’s home office costs (owner’s engineering, management, and 

procurement) at 5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 0% of the 

CECC and owner’s costs as ACI projects are expected to be completed in less 

than a year. 

• With the addition of a baghouse, 6% of the CECC is added to account for 

AFUDC based on a complete project duration of 2 years. 

• If coal additives are required, based on the type of fuel, existing equipment, 

and total mercury removal; then a one time royalty fee must be added to the 

total project cost (C2). The royalty fee is added to the bottom line project cost 

with no burden allowances. 

The total project cost is based on a multiple lump sum contract approach. Should a 

turnkey engineering procurement construction (EPC) contract be executed, the total 

project cost would be 10 to 15% higher than what is currently estimated. 

Escalation is not included in the estimate. The total project cost (TPC) is the sum of the 

CECC and the additional costs and financing expenditures. 

Fixed O&M (FOM) 

The fixed operating and maintenance (O&M) cost is a function of the additional 

operations staff (FOMO), maintenance labor and materials (FOMM), and administrative 

labor (FOMA) associated with the ACI installation. The FOM is the sum of the FOMO, 

FOMM, and FOMA. 

The following factors and assumptions underlie calculations of the FOM: 

• All of the FOM costs were tabulated on a per kilowatt-year (kW-yr) basis. 

• In general, 1 additional operator is required for an ACI system. The FOMO 

was based on one additional operation staff member. 

• The fixed maintenance materials and labor is a direct function of the process 

capital cost (BM). 

• The administrative labor is a function of the FOMO and FOMM. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 10 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Reagent use and unit costs; 

• Waste production and unit disposal costs; 

• Additional power required and unit power cost; and 

• Bag and cage replacement as applicable. 

The following factors and assumptions underlie calculations of the VOM: 

• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis. 

• The carbon usage is calculated from the unit size and heat rate. 

• The carbon waste generation rate is equal to the carbon feed rate. 

• When the carbon is captured in the same particulate collector as the fly ash, 

any fly ash produced may have to be landfilled. As a worst case cost estimate, 

the entire fly ash amount is included in the waste rate. Typical ash contents 

for each fuel are used to calculate a total fly ash production rate. The fly ash 

production is only added to the carbon waste when a new baghouse is not 

included. With the addition of a new baghouse, the existing particulate 

collector should remain in operation to capture the fly ash and maintain any 

beneficial uses. 

• Bag and cage replacement every 3 and 9 years respectively for unit operations 

with 6.0 A/C. 

• Bag and cage replacement every 5 and 10 years respectively for unit 

operations with 4.0 A/C. 

• The additional power required includes air blowers for the injection system 

and power for the baghouse compressors as applicable. 

• An allowance for wet FGD additives, to reduce re-emission of the mercury, is 

included for wet FGD systems with SCRs only. 

• An additional allowance is included for PRB or lignite coals. The allowance 

is based on halogen coal additives to enhance ionic mercury formation with 

units that have both an FGD and an SCR. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 11 

Input options are provided for the user to adjust the variable O&M costs per unit. 

Average default values are included in the base estimate. The variable O&M costs per 

unit options are: 

• Carbon cost in $/ton; 

• Waste disposal costs in $/ton; 

• Auxiliary power cost in $/kWh; 

• Bag and cage costs in $/item; and 

• Operating labor rate (including all benefits) in $/hr. 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for carbon 

VOMW = Variable O&M costs for waste disposal 

VOMB = Variable O&M costs for bags and cage replacement 

VOMF = 

Variable O&M costs for a wet FGD additive, only applies when 

there is an SCR, wet FGD system, and less than 80% total mercury 

capture. In that case, no ACI system is required. 

VOMA = 

Variable O&M costs for a coal additive, only applies when there is 

an SCR, FGD system, and less than 80% total mercury capture and 

either PRB or lignite fuel. In that case, no ACI system is required. 

The total VOM is the sum of VOMR, VOMW, VOMB, and VOMF and/or VOMA as 

applicable. The additional auxiliary power requirement is reported as a percentage of the 

total gross power of the unit. 

Table 1 contains an example of the complete capital and O&M cost estimate worksheet 

when using an existing ESP for the carbon and fly ash capture. Table 2 contains an 

example of the complete capital and O&M cost estimate worksheet when using an 

existing baghouse for the carbon and fly ash capture. Table 3 shows the same complete 

cost methodology except with the addition of a baghouse. Table 4, contains details of an 

existing SCR and wet FGD system burning PRB coal and requiring less than 80% total 

mercury removal.
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 12 

Table 1. Example Complete Cost Estimate for an ACI System with an Existing ESP (Costs are all based on 2009 dollars)
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 13 

Table 2. Example Complete Cost Estimate for an ACI System with an Existing Baghouse (Costs are all based on 2009 dollars) 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 14 

Table 3. Example Complete Cost Estimate for an ACI System with an Additional Baghouse (Costs are all based on 2009 dollars) 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 15 

Table 4. Example Complete Cost Estimate for both Additives Systems without ACI (Costs are all based on 2009 dollars)
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March 2011

Mercury Control Cost Development Methodology – Final 

Page 16 

Table 5. Example Complete Cost Estimate for Coal Additives without ACI (Costs are all based on 2009 dollars) 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

Dry Sorbent Injection Cost Development Methodology

FINAL

August 2010 

Project 12301-007 

Perrin Quarles Associates, Inc. 

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000 
 

LEGAL NOTICE 

This analysis (“Deliverable”) was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole 

use of Perrin Quarles Associates, Inc. ("Client") in accordance with the agreement between S&L and 

Client. This Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers 

practicing under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to 

the particular scope limitations, budgetary and time constraints, and business objectives of the Client; (2) 

information and data provided by others may not have been independently verified by S&L; and (3) the 

information and data contained in this Deliverable are time sensitive and changes in the data, applicable 

codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any 

use or reliance upon this Deliverable by third parties shall be at their sole risk. 

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of 

William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by 

Dr. Jim Staudt, President of Andover Technology Partners. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 3 

Technology Description 

Dry sorbent injection (DSI) is a viable technology for moderate SO2 reduction on coal 

fired boilers. Demonstrations and recent utility testing have shown SO2 removals greater 

than 80% for systems using sodium based sorbents. The most common sodium based 

sorbent is Trona. 

The level of removal for Trona can vary from 0 to 90% depending on the Normalized 

Stoichiometric Ratio (NSR) and particulate capture device. NSR is defined as: 

The target removal efficiency is a requirement from the utility and is independent of unit 

size. The costs for a DSI system are primarily dependant on sorbent feed rate which is a 

function of NSR and SO2 mass feed rate per hour. Therefore, the cost estimation was 

based on sorbent feed rate and not on unit size. 

The sorbent solids can be collected in either an ESP or a baghouse. Baghouses generally 

achieve greater SO2 removal efficiencies than ESPs by virtue of the filter cake on the 

bags, which allows for longer reaction time between the sorbent solids and the flue gas. 

For a given removal efficiency with Trona, the NSR is reduced when a baghouse is used 

for particulate capture. 

The dry sorbent capture ability is also a function of particle surface area. To increase the 

particle surface area, the sorbent must be heated. Heating the solids produces micropores 

on the particle surface which greatly improve the sulfur capture ability. For Trona, the 

sorbent should be injected into flue gas above 275°F to maximize the micropore 

structure. However, if the flue gas is too hot (greater than 800°F), the solids may sinter 

and surface area is reduced. 

Another way to increase surface area is to mechanically reduce the particle size by 

grinding the sorbent. Typical Trona is delivered unmilled. The ore is ground such that 

the unmilled product has an average size around 30 μm. Commercial testing has shown 

that the reactivity of the Trona can be increased when the sorbent is ground to less than 

30 μm. In the cost estimating methodology, the Trona is always delivered in the 

unmilled state. To mill the Trona, in-line mills are continuously used during the Trona 

injection process. Therefore, the delivered cost of the Trona will not change, only the 

reactivity and usage changes as the Trona is milled. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 4 

Ultimately, the NSR required for a given removal is a function of Trona particle size and 

particulate capture equipment. Either as delivered Trona (around 30 μm average size) or 

in-line milled Trona (around 15 μm average size) can be chosen for injection in the cost 

program. The average Trona particle size and the type of particulate removal both 

contribute to the predicted Trona feed rate. 

Establishment of Cost Basis 

For the wet or SDA FGD systems, the sulfur removal is generally specified at the 

maximum achievable level. With those systems, costs are primarily a function of plant 

size and sulfur rate. However, the DSI systems are quite different. The major cost for 

the DSI system is the sorbent itself. The sorbent feed rate is a function of sulfur rate, 

particulate collection device, and removal efficiency. To account for all of the variables, 

the capital cost was established based on a sorbent feed rate. The sorbent feed rate is 

calculated from user input variables. Cost data for several DSI systems was reviewed 

and a relationship was developed for the capital costs of the system on a sorbent feed rate 

basis. 

Methodology 

Inputs 

Several input variables are required in order to predict future retrofit costs. The sulfur 

feed rate and NSR are the major variables for the cost estimate. The NSR is a function 

of: 

• Removal efficiency; 

• Trona particle size; and 

• Particulate capture device. 

A retrofit factor that equates to difficulty in construction of the system must be defined. 

The gross unit size and gross heat rate will factor into the amount of sulfur generated. 

Based on commercial testing, removal efficiencies with DSI are limited by the particulate 

capture device employed. When the sorbent is captured in an ESP, a 40 to 50% SO2

removal is typically achieved without an increase in particulate emissions. A higher 

efficiency (70 – 75%) is generally achieved with a baghouse. The DSI technology should 

not be applied to fuels with a sulfur content of greater than 2 lb SO2/MMBtu. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 5 

The equations provided in the cost methodology spreadsheet allow the user to input the 

required removal efficiency, within the limits of the technology. To simplify the 

correlation, the removal with an ESP should be set at 50% and 70% with a baghouse. 

The simplified sorbent NSR would then be: 

For an ESP at the target 50% removal: 

Unmilled Trona NSR = 2.85 

Milled Trona NSR = 1.40 

For a baghouse at the target 70% removal: 

Unmilled Trona NSR = 2.00 

Milled Trona NSR = 1.55 

The correlation could be further simplified by assuming that only milled Trona is used. 

The current trend in the industry is to use in-line milling of the Trona to improve the 

utilization. For a minor increase in capital, the milling can greatly reduce the variable 

operating expenses. It is recommended that only milled Trona be considered in the 

simplified model. 

Outputs 

Total Project Costs (TPC) 

First the base installed cost for the complete DSI system is calculated (BM). The base 

installed cost includes: 

• All equipment; 

• Installation; 

• Buildings; 

• Foundations; 

• Electrical; and 

• Average retrofit difficulty. 

The base module cost is adjusted by the selection of in-line milling equipment. The base 

installed cost is then increased by: 

• Engineering and construction management costs at 5% of the BM cost; 

• Labor adjustment for 6 x 10 hour shift premium, per diem, etc., at 5% of the 

BM cost; and 

• Contractor profit and fees at 5% of the BM cost. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 6 

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of 

the BM and the additional engineering and construction fees. 

Additional costs and financing expenditures for the project are computed based on the 

CECC. Financing and additional project costs include: 

• Owner’s home office costs (owner’s engineering, management, and 

procurement) at 5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 0% of the 

CECC and owner’s costs as these projects are expected to be completed in 

less than a year. 

The total project cost is based on a multiple lump sum contract approach. Should a 

turnkey engineering procurement construction (EPC) contract be executed, the total 

project cost could be 10 to 15% higher than what is currently estimated. 

Escalation is not included in the estimate. The total project cost (TPC) is the sum of the 

CECC and the additional costs and financing expenditures. 

Fixed O&M (FOM) 

The fixed operating and maintenance (O&M) cost is a function of the additional 

operations staff (FOMO), maintenance labor and materials (FOMM), and administrative 

labor (FOMA) associated with the DSI installation. The FOM is the sum of the FOMO, 

FOMM, and FOMA. 

The following factors and assumptions underlie calculations of the FOM: 

• All of the FOM costs were tabulated on a per kilowatt-year (kW-yr) basis. 

• In general, 2 additional operators are required for a DSI system. The FOMO 

was based on the number of additional operations staff required. 

• The fixed maintenance materials and labor is a direct function of the process 

capital cost (BM). 

• The administrative labor is a function of the FOMO and FOMM. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 7 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Reagent use and unit costs; 

• Waste production and unit disposal costs; and 

• Additional power required and unit power cost. 

The following factors and assumptions underlie calculations of the VOM: 

• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis. 

• The reagent usage is a function of NSR and SO2 feed rate. The gross unit size 

and gross heat rate factor multiplied by the SO2 rate determine the SO2 feed 

rate. The estimated NSR is a function of removal efficiency required. The 

basis for the total reagent rate is a Trona purity of 98%. 

• The waste generation rate is a function of the Trona feed rate and is adjusted 

for the excess sorbent fed. The waste generation rate is based on reaction 

products of Na2SO4 and unreacted dry sorbent as Na2CO3. 

• With the addition of a sodium sorbent, any fly ash produced must be 

landfilled. Typical ash contents for each fuel are used to calculate a total fly 

ash production rate. The fly ash production is added to the sorbent waste to 

account for a total waste stream in the O&M analysis. 

• The additional power required includes air blowers for the injection system, 

drying equipment for the transport air, and in-line Trona milling equipment as 

needed. 

Input options are provided for the user to adjust the variable O&M costs per unit. 

Average default values are included in the base estimate. The variable O&M costs per 

unit options are: 

• Trona cost in $/ton; 

• Waste disposal costs in $/ton; 

• Auxiliary power cost in $/kWh; 

• Operating labor rate (including all benefits) in $/hr. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 8 

The variables that contribute to the overall VOM are: 

VOMR = Variable O&M costs for trona reagent 

VOMW = Variable O&M costs for waste disposal 

VOMP = Variable O&M costs for additional auxiliary power 

The total VOM is the sum of VOMR, VOMW, and VOMP. Table 1 contains an example 

of the complete capital and O&M cost estimate worksheet.
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 9 

Table 1. Example Complete Cost Estimate for a DSI System (Costs are all based on 2009 dol
IPM Model – Revisions to Cost and Performance for Project No. 12301-007

APC Technologies August 20, 2010

Dry Sorbent Injection Cost Development Methodology – Final 

Page 10 
 

IPM Model – Revisions to Cost and Performance for APC Technologies

Particulate Control Cost Development Methodology

FINAL

March 2011 

Project 12301-009 

Systems Research and Applications Corporation 

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000 
 

LEGAL NOTICE 

This analysis (“Deliverable”) was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole 

use of Systems Research and Applications Corporation ("Client") in accordance with the agreement 

between S&L and Client. This Deliverable was prepared using the degree of skill and care ordinarily 

exercised by engineers practicing under similar circumstances. Client acknowledges: (1) S&L prepared 

this Deliverable subject to the particular scope limitations, budgetary and time constraints, and business 

objectives of the Client; (2) information and data provided by others may not have been independently 

verified by S&L; and (3) the information and data contained in this Deliverable are time sensitive and 

changes in the data, applicable codes, standards, and acceptable engineering practices may invalidate the 

findings of this Deliverable. Any use or reliance upon this Deliverable by third parties shall be at their sole 

risk. 

This work was funded and reviewed by the U.S. Environmental Protection Agency under the supervision of 

William A. Stevens, Senior Advisor – Power Technologies. Additional input and review was provided by 

Dr. Jim Staudt, President of Andover Technology Partners. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March, 2011

Particulate Control Cost Development Methodology – Final 

Page 3 

Technology Description 

There are two main particulate capture unit operations employed in the utility industry: 

• Electrostatic Precipitator (ESP) 

• Fabric Filter (FF) 

ESPs have been implemented in the utility industry since the 1960’s; there have been a 

great number of installations in the U.S. and around the world. The ESP collects PM in a 

three step process: charging, collecting, and cleaning the collected ash off the electrodes. 

The ESP relies on fly as resistivity to charge and collect the particles. ESPs can reduce 

PM emissions to below 0.015 lb/MMBtu and opacity below 10% depending on the ash 

characteristics and particulate loading. However, it is difficult to collect fly ash when 

burning low sulfur coal because of high fly ash resistivity requiring large ESP. ESPs are 

not well suited for processes that are highly variable because the collection efficiency is 

sensitive to fluctuations in gas stream conditions. 

Recently fabric filters (specifically pulse-jet type or PJFF) have become the preferred 

choice for new and retrofit utility particulate capture. PJFFs have been utilized 

commercially for over 25 years and are considered a mature technology. Modern PJFFs 

are reliable, versatile and cost effective. In a PJFF, particulate matter is collected on a 

fabric bag; then the particles are cleaned off the bag surfaces with a pulse of air. During 

cleaning, the collected particulate falls into hoppers and is removed via an ash handling 

system to a silo. PJFF suppliers provide guarantees as low as 0.010 lb/MMBtu 

depending on the application. 

Co-Benefits 

Due to the filter cake inherent in PJFFs, PJFF units have additional benefits that are not 

available in ESPs: 

• Mercury removal is enhanced by a PJFF by contacting the flue gas with the 

unburned carbon in the fly ash; 

• Collection of injected activated carbon with a PJFF can dramatically increase 

the mercury removal from the flue gas versus an ESP particulate collector; 

• With in-duct dry sorbent injection, the SO2 removal can be greatly increased 

when an PJFF is used versus an ESP for the sorbent capture; and 

• Acid gases are removed when the flue gas is passed through the filter cake in 

a PJFF. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March, 2011

Particulate Control Cost Development Methodology – Final 

Page 4 

Establishment of Cost Basis 

The major cost driver for a baghouse is the required gross air-to-cloth (A/C) ratio. When 

the baghouse is installed in a retrofit situation following another collection device, such 

as an ESP, then an A/C of 6.0 would be appropriate if activated carbon injection is 

applied for mercury removal. 

If the baghouse will be used as the sole particulate capture unit operation, an A/C of 4.0 

should be specified. The lower A/C ratio will provide better bag life with the high inlet 

particulate loading expected for the single particulate capture device in the process. 

Cost data from the S&L current database of projects, for several different baghouse 

installations, was reviewed and a relationship was developed for the capital costs of the 

system on a flue gas rate basis. The capital costs include: 

• Duct work modifications, 

• Foundations, 

• Structural steel, 

• ID fan modifications or new booster fans, and 

• Electrical modifications. 

Methodology 

Inputs 

Several input variables are required in order to predict the total future retrofit costs: 

• Type of coal, 

• Unit size, 

• Unit heat rate, and 

• Baghouse required size. 

A retrofit factor that equates to difficulty in construction of the system must be defined. 

Outputs 

Total Project Costs (TPC) 

A base installed cost for the baghouse is calculated (BM). The base installed cost is then 

increased by: 

• Engineering and construction management costs at 10% of the BM cost; 

• Labor adjustment for 6 x 10 hour shift premium, per diem, etc., at 5% of the 

BM cost; and 

• Contractor profit and fees at 5% of the BM cost. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March, 2011

Particulate Control Cost Development Methodology – Final 

Page 5 

A capital, engineering, and construction cost subtotal (CECC) is established as the sum of 

the BM and the additional engineering and construction fees. 

Additional costs and financing expenditures for the project are computed based on the 

CECC. Financing and additional project costs include: 

• Owner’s home office costs (owner’s engineering, management, and 

procurement) at 5% of the CECC; and 

• Allowance for Funds Used During Construction (AFUDC) at 6% of the 

CECC is added to account for AFUDC based on a complete project duration 

of 2 years. 

The total project cost is based on a multiple lump sum contract approach. Should a 

turnkey engineering procurement construction (EPC) contract be executed, the total 

project cost would be 10 to 15% higher than what is currently estimated. 

Escalation is not included in the estimate. The total project cost (TPC) is the sum of the 

CECC and the additional costs and financing expenditures. 

Fixed O&M (FOM) 

The fixed operating and maintenance (O&M) cost is a function of the additional 

operations staff (FOMO), maintenance labor and materials (FOMM), and administrative 

labor (FOMA) associated with the baghouse installation. The FOM is the sum of the 

FOMO, FOMM, and FOMA. 

The following factors and assumptions underlie calculations of the FOM: 

• All of the FOM costs were tabulated on a per kilowatt-year (kW-yr) basis. 

• In general, 0 additional operators are required for a baghouse. 

• The fixed maintenance materials and labor is a direct function of the process 

capital cost (BM). 

• The administrative labor is a function of the FOMO and FOMM. 

Variable O&M (VOM) 

Variable O&M is a function of: 

• Bag and cage replacement. 
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March, 2011

Particulate Control Cost Development Methodology – Final 

Page 6 

The following factors and assumptions underlie calculations of the VOM: 

• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis. 

• Bag and cage replacement every 3 and 9 years respectively for unit operations 

with 6.0 A/C. 

• Bag and cage replacement every 5 and 10 years respectively for unit 

operations with 4.0 A/C. 

Input options are provided for the user to adjust the variable O&M costs per unit. 

Average default values are included in the base estimate. The variable O&M costs per 

unit options are: 

• Bag and cage costs in $/item. 

The variables that contribute to the overall VOM are: 

VOMB = Variable O&M costs for bags and cage replacement 

The total VOM is the VOMB. The additional auxiliary power requirement is reported as 

a percentage of the total gross power of the unit. 

Table 1 contains an example of the complete capital and O&M cost estimate worksheet 

for a baghouse installation.
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March, 2011

Particulate Control Cost Development Methodology – Final 

Page 7 

Table 1. Example Complete Cost Estimate for a 4.0 A/C Baghouse Installation (Costs are all based on 20
IPM Model – Revisions to Cost and Performance for Project No. 12301-009

APC Technologies March, 2011

Particulate Control Cost Development Methodology – Final 

Page 8 

Table 2. Example Complete Cost Estimate for a 6.0 A/C Baghouse Installation (Costs are all based on 20