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# m ent f

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# f or

−

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 en hancements and updates that were made in EPA Base Case v4.10_PTox

Mar2011 1 

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

Specifically, the capability to model HCl emissions an d 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 In jection (ACI), the emission control particularly

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

regulations and NSR and state settlements to reflec t changes that had occurr ed since the previous

base case

The current report takes the form of a supplement to the documentat ion 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/progsre gs/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 Mar2 011 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 fo r 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 SO 2 

# and NO X 

# 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 Wo rksheets 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 REPRESENTATI ON 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 EMI SSION FACTOR ASSUMPTIONS 

# ے ۑ ۑ ۑ ۑ ۑ ۑ ې



# Í New 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 (Appe ndix 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 NO

x 

# 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 NO

x 

# 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

SO 2 

# 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 NO

x 

# 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 SO 2 

# 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 NO

x 

# 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 NO

x 

# 0.125 lbs/MMBtu rate limit of NO

x 

# annually for all

coal and residual-oil fired units > 25 MW

2009

SO 2 

# 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 NO

x 

# 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 NO

x 

# 0.11 lbs/MMBtu annual rate limit and ozone season

rate limit for all Dynergy and Ameren coal steam

units > 25 MW 2012

SO 2 

# 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 NO

x 

# 0.11 lbs/MMBtu ozone season and annual rate limit

for all specified Midwest Gen coal steam units 2012

SO 2 

# 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 spec ified Midwest Gen coal

steam units 2015

Kansas NO

x 

# Emission

Reduction Rule,

K.A.R. 28-19-713a. NO

x 

# 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 SO 2 

# 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 NO

x 

# 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 NO

x 

# or

facilities within the Region of Influence that

collectively have the potential to emit 50 tons or

more per year of NO

x 

# 2005

Maine Chapter 145 NO

x 

# Control Program NO

x 

# 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 NO

x 

# 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.

2009 SO 2 

# 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 NO

x 

# 1.5 lbs/MWh annual GPS for Bayton Point, Mystic

Generating Station, Somerset Station, Mount Tom,

Canal, and Salem Harbor

2006 SO 2 

# 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 NO

x 

# 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, S t. 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 NO

x 

# 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

SO 2 

# 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 NO

x 

# 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 NO

x 

# 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 NO

x 

# 39.91 MTons non-ozone season cap for fossil fuel

units > 25 MW 2004

Part 238 SO 2 

# 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 NO

x 

# 25 MTons annual cap for Progress Energy coal

plants > 25 MW and 31 MTons annual cap for Duke

Energy coal plants > 25 MW 2007

SO 2 

# 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 CO 2 

# 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 CO 2 

# 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 CO 2 

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

plant 2004

Texas Senate Bill 7 Chapter

101 SO 2 

# 273.95 MTons cap of SO 2 

# for all grandfathered units

built before 1971 in East Texas Region

2003

NO

x 

# 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 NO

x 

# 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 NO

x 

# 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

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

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 uni ts 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 SO 2 

# rate limits in Connecticut

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

3) Addition of two Kansas Stat e Law unit-specific constraints

4) An update of the modeling of NO

x 

# rate limits in Louisiana

5) An update of the modeling of the NO

x 

# annual and summer caps and SO 2 

# annual cap in Maryland

6) An update of the modeling of the NO

x 

# rate limits in New Jersey9Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v4.10_PTox, Mar2011Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateAlabama PowerJames H.MillerAlabamaUnits 3& 4Install andoperateFGDcontinuously95%12/31/11Operateexisting SCRcontinuously0.105/01/080.0312/31/06With 45 days ofsettlemententry, APCmust retire7,538 SO2emissionallowances.APC shall notsell, trade, orotherwiseexchange anyPlant Millerexcess SO2emissionallowancesoutside of theAPC system1/1/21http://www.epa.gov/compliance/resources/cases/civil/caa/alabamapower.htmlMinnkota Power CooperativeBeginning 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 by12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500.Milton R.YoungMinnesotaUnit 1Install andcontinuouslyoperateFGD95% ifwet FGD,90% if dry12/31/11Install andcontinuouslyoperateOver-fireAIR, orequivalenttechnologywithemissionrate < .360.3612/31/090.03 ifwet FGD,.015 ifdry FGDPlant willsurrender 4,346allowances foreach year 2012–2015, 8,693allowances foryears 2016–2018, 12,170allowances foryear 2019, and14,886allowances/yearthereafter ifUnits 1–3 areoperational by12/31/2015. Ifonly Units 1 and2 areoperationalby12/31/2015,the plant shallretire 17,886units in 2020and thereafter.Minnkota shallnot sell ortrade NOxallowancesallocated toUnits 1, 2, or 3that wouldotherwise beavailable forsale or tradeas a result ofthe actionstaken by thesettlingdefendants tocomply withtherequirementshttp://www.epa.gov/compliance/resources/cases/civil/caa/minnkota.htmlUnit 2Design,upgrade,andcontinuouslyoperateFGD90%12/31/10Install andcontinuouslyoperateover-fireAIR, orequivalenttechnologywithemissionrate < .360.3612/31/070.03Before2008SIGECOFB CulleyIndianaUnit 1Repower tonaturalgas (orretire)12/31/06The provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.http://www.epa.gov/compliance/resources/cases/civil/caa/sigecofb.htmlUnit 2Improve andcontinuouslyoperateexistingFGD(shared byUnits 2 and3)95%06/30/04Unit 3Improve andcontinuously95%06/30/04OperateExisting0.109/01/03Install andcontinuously0.01506/30/0710Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateoperateexistingFGD(shared byUnits 2 and3)SCRContinuouslyoperate aBaghousePSEG FOSSILBergenNewJerseyUnit 2Repower tocombinedcycle12/31/02The provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.http://www.epa.gov/compliance/resources/cases/civil/caa/psegllc.htmlHudsonNewJerseyUnit 2Install DryFGD (orapprovedalt.technology)andcontinuallyoperate0.1512/31/06Install SCR(or approvedtech) andcontinuallyoperate0.105/01/07InstallBaghouse(or approvedtechnology)0.01512/31/06MercerNewJerseyUnits 1& 2Install DryFGD (orapprovedalt.technology)andcontinuallyoperate0.1512/31/10Install SCR(or approvedtech) andcontinuallyoperate0.1305/01/06TECOBig BendFloridaUnits 1& 2ExistingScrubber(shared byUnits 1 & 2)95%(95% or.25)09/1/00(01/01/13)Install SCR0.105/01/09The provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.http://www.epa.gov/compliance/resources/cases/civil/caa/teco.htmlUnit 3ExistingScrubber(shared byUnits 3 & 4)93% ifUnits 3 &4 areoperating2000(01/01/10)Install SCR0.105/01/09Unit 4ExistingScrubber(shared byUnits 3 & 4)93% ifUnits 3 &4 areoperating06/22/05Install SCR0.107/01/07GannonFloridaSixunitsRetireall sixcoalunitsandrepower atleast550MW ofcoalcapacity tonaturalgas12/31/04WEPCOWEPCO shall comply with the following system wide average NOxemission rates and total NOxtonnage 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 emission rate of 0.17 and 17, 400tons. For SO2emissions, 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 0.61and 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 0.32 and 33,300 tons.http://www.epa.gov/compliance/resources/cases/civil/c11Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DatePresque IsleWisconsinUnits 1–4RetireorinstallSO2andNOxcontrols12/31/12Install andcontinuouslyoperateFGD (orapprovedequiv. tech)95% or0.112/31/12Install SCR(or approvedtech) andcontinuallyoperate0.112/31/12The provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.aa/wepco.htmlUnits 5& 6Install andoperate lowNOxburners12/31/03Units 7& 8Operateexisting lowNOxburners12/31/05InstallBaghouseUnit 9Operateexisting lowNOxburners12/31/06InstallBaghousePleasantPrairieWisconsin1Install andcontinuouslyoperateFGD (orapprovedcontrol tech)95% or0.112/31/06Install andcontinuouslyoperate SCR(or approvedtech)0.112/31/062Install andcontinuouslyoperateFGD (orapprovedcontrol tech)95% or0.112/31/07Install andcontinuouslyoperate SCR(or approvedtech)0.112/31/03Oak CreekWisconsinUnits 5& 6Install andcontinuouslyoperateFGD (orapprovedcontrol tech)95% or0.112/31/12Install andcontinuouslyoperate SCR(or approvedtech)0.112/31/12Unit 7Install andcontinuouslyoperateFGD (orapprovedcontrol tech)95% or0.112/31/12Install andcontinuouslyoperate SCR(or approvedtech)0.112/31/12Unit 8Install andcontinuouslyoperateFGD (orapprovedcontrol tech)95% or0.112/31/12Install andcontinuouslyoperate SCR(or approvedtech)0.112/31/12PortWashingtonWisconsinUnits 1–4Retire12/31/04for Units 1–3. Unit 4by entry ofconsentdecreeValleyWisconsinBoilers1–4Operateexisting lowNOxburner30 daysafter entryof consentdecreeVEPCOThe 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. Beginning 1/1/2013 they will havea system wide emission rate no greater than 0.15 lb/mmBtu.12Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateMount StormWestVirginiaUnits 1–3Construct orimproveFGD95% or0.1501/01/05Install andcontinuouslyoperate SCR0.1101/01/08On or beforeMarch 31 ofevery yearbeginning in2013 andcontinuingthereafter,VEPCO shallsurrender45,000 SO2allowances.ChesterfieldVirginiaUnit 4Install andcontinuouslyoperate SCR0.101/01/13Unit 5Construct orimproveFGD95% or0.1310/12/12Install andcontinuouslyoperate SCR0.101/01/12Unit 6Construct orimproveFGD95% or0.1301/01/10Install andcontinuouslyoperate SCR0.101/01/11ChesapeakeEnergyVirginiaUnits 3& 4Install andcontinuouslyoperate SCR0.101/01/13CloverVirginiaUnits 1& 2ImproveFGD95% or0.1309/01/03PossumPointVirginiaUnits 3& 4Retireandrepower tonaturalgas05/02/03Santee CooperSantee Cooper shall comply with the following system wide averages for NOxemission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000tons, by 1/1/2007 an emission rate of 0.18 and 25,000 tons, by 1/1/2010 andemission rate of 0.15 and 20,000 tons. For SO2emission 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 rate of 0.53 and 70 tons, andby 1/1/2011 and emission rate of 0.5 and 65 tons.http://www.epa.gov/compliance/resources/cases/civil/caa/santeecooper.htmlCrossSouthCarolinaUnit 1UpgradeandcontinuouslyoperateFGD95%06/30/06Install andcontinuouslyoperate SCR0.105/31/04The provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.Unit 2UpgradeandcontinuouslyoperateFGD87%06/30/06Install andContinuouslyoperate SCR0.11/0.105/31/04and05/31/07WinyahSouthCarolinaUnit 1Install andcontinuouslyoperateFGD95%12/31/08Install andcontinuouslyoperate SCR0.11/0.111/30/04and11/30/04Unit 2Install andcontinuouslyoperateFGD95%12/31/08Install andcontinuouslyoperate SCR0.1211/30/04Unit 3UpgradeandcontinuouslyoperateexistingFGD90%12/31/08Install andcontinuouslyoperate SCR0.14/0.1211/30/2005and11/30/08Unit 4UpgradeandcontinuouslyoperateexistingFGD90%12/31/07Install andcontinuouslyoperate SCR0.13/0.1211/30/05and11/30/08GraingerSouthCarolinaUnit 1Operate lowNOxburneror more06/25/0413Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DatestringenttechnologyUnit 2Operate lowNOxburneror morestringenttechnology05/01/04JeffriesSouthCarolinaUnits3, 4Operate lowNOxburneror morestringenttechnology06/25/04Ohio EdisonOhio Edison shall achieve reductions of 2,483 tons NOxbetween 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 through April, and/or 3)emitting fewer tons than the Plant-Wide Annual Cap for NOxrequired for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2by 12/31/2010.http://www.epa.gov/compliance/resources/cases/civil/caa/ohioedison.htmlNo later than 8/11/2005, Ohio Edison shall install and operate low NOxburners 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 software to minimize NOxemissions from Sammis Units 1–5.W.H.SammisPlantOhioUnit 1InstallInductScrubber (orapprovedequiv.control tech)50%removalor 1.1lb/mmBtu12/31/08Install SNCR(or approvedalt. tech) &operatecontinuously0.2510/31/07Beginning on1/1/2006, OhioEdison mayuse, sell ortransfer anyrestricted SO2only to satisfythe OperationalNeeds at theSammis, Burgerand MansfieldPlant, or newunits within theFirstEnergySystem thatcomply with a96% removalfor SO2. Forcalendar year2006 through2017, OhioEdison mayaccumulate SO2allowances foruse at theSammis,Burger, andMansfieldplants, orFirstEnergyunits equippedwith SO2EmissionControlStandards.Beginning in2018, OhioEdison shallsurrenderunusedrestricted SO2allowances.Unit 2InstallInductScrubber (orapprovedequiv.control tech)50%removalor 1.1lb/mmBtu12/31/08OperateexistingSNCRcontinuously0.2502/15/06Unit 3InstallInductScrubber (orapprovedequiv.control tech)50%removalor 1.1lb/mmBtu12/31/08Operate lowNOxburnersand overfireair by12/1/05;install SNCR(or approvedalt. tech) &operatecontinuouslyby 12/31/070.2512/01/05and10/31/07Unit 4InstallInductScrubber (orapprovedequiv.control tech)50%removalor 1.1lb/mmBtu06/30/09Install SNCR(or approvedalt. tech) &operatecontinuously0.2510/31/07Unit 5Install FlashDryerAbsorberor ECO2(orapprovedequiv.control tech)50%removalor 1.1lb/mmBtu06/29/09Install SNCR(or approvedalt. tech) &OperateContinuously0.2903/31/0814Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective Date&operatecontinuouslyUnit 6Install FGD3(orapprovedequiv.control tech)&operatecontinuously95%removalor 0.13lb/mmBtu06/30/11Install SNCR(or approvedalt. tech) &operatecontinuously"MinimumExtentPracticable"06/30/05OperateExistingESPContinuously0.0301/01/10Unit 7Install FGD(orapprovedequiv.control tech)&operatecontinuously95%removalor 0.13lb/mmBtu06/30/11OperateexistingSNCRContinuously"MinimumExtentPracticable"08/11/05OperateExistingESPContinuously0.0301/01/10MansfieldPlantPennsylvaniaUnit 1UpgradeexistingFGD95%12/31/05Unit 2UpgradeexistingFGD95%12/31/06Unit 3UpgradeexistingFGD95%10/31/07EastlakeOhioUnit 5Install lowNOxburners,over-firedair andSNCR &operatecontinuously"MinimizeEmissionsto theExtentPracticable"12/31/06BurgerOhioUnit 4Repower withat least80%biomass fuel,up to20%lowsulfurcoal.12/31/11Unit 512/31/11MirantI1,6System-wide NOxEmission 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 NOxEmission Ozone Season Caps: 14,700 tons 2004; 13,340 tons 2005; 12,590tons 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 0.150 lb/mmBtu NOx.http://www.epa.gov/compliance/resources/cases/civil/caa/mirant.htmlPotomacRiver PlantVirginiaUnit 1Unit 2Unit 3Install lowNOxburners (ormoreeffectivetech) &05/01/0415Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateoperatecontinuouslyUnit 4Install lowNOxburners (ormoreeffectivetech) &operatecontinuously05/01/04Unit 5Install lowNOxburners (ormoreeffectivetech) &operatecontinuously05/01/04MorgantownPlantMarylandUnit 1Install SCR(or approvedalt. tech) &operatecontinuously0.105/01/07Unit 2Install SCR(or approvedalt. tech) &operatecontinuously0.105/01/08Chalk PointMarylandUnit 1Install andcontinuouslyoperateFGD (orequiv.technology)95%06/01/10For each yearafter MirantcommencesFGD operationat Chalk Point,Mirant shallsurrender thenumber of SO2Allowancesequal to theamount bywhich the SO2Allowancesallocated to theUnits at theChalk PointPlant aregreater than thetotal amount ofSO2emissionsallowed underthis SectionXVIII.Unit 2Install andcontinuouslyoperateFGD (orequiv.technology)95%06/01/10Illinois PowerSystem-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 2012; 29,000 tons 2013onward.http://www.epa.gov/compliance/resources/cases/civil/caa/illinoispower.htmlBaldwinIllinoisUnits 1& 2Install wetor dry FGD(orapprovedequiv. alt.tech) &operatecontinuously0.112/31/11OperateOFA &existing SCRcontinuously0.108/11/05Install &continuouslyoperateBaghouse0.01512/31/10By year end2008, Dynergywill surrender12,000 SO2emissionallowances, byyear end 2009 itwill surrender16Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateUnit 3Install wetor dry FGD(orapprovedequiv. alt.tech) &operatecontinuously0.112/31/11OperateOFA and/orlow NOxburners0.12 until12/30/12;0.1 from12/31/1208/11/05and12/31/12Install &continuouslyoperateBaghouse0.01512/31/1018,000, by yearend 2010 it willsurrender24,000, any byyear end 2011and each yearthereafter it willsurrender30,000allowances. Ifthe surrenderedallowancesresult ininsufficientremainingallowancesallocated to theunitscomprising theDMG system,DMG canrequest tosurrender fewerSO2allowances.HavanaIllinoisUnit 6Install wetor dry FGD(orapprovedequiv. alt.tech) &operatecontinuously1.2lb/mmBtuuntil12/30/2012; 0.1lb/mmBtufrom12/31/2012 onward08/11/05and12/31/12OperateOFA and/orlow NOxburners &operateexisting SCRcontinuously0.108/11/05Install &continuouslyoperateBaghouse,then installESP or alt.PM equipFor Baghouse:0.015lb/mmBtu; ForESP:0.03lb/mmBtuForBaghouse:12/31/12;For ESP:12/31/05HennepinIllinoisUnit 11.207/27/05OperateOFAand/or lowNOxburners"MinimumExtentPracticable"08/11/05Install ESP(or equiv. alt.tech) &continuouslyoperateESPs0.0312/31/06Unit 21.207/27/05OperateOFAand/or lowNOxburners"MinimumExtentPracticable"08/11/05Install ESP(or equiv. alt.tech) &continuouslyoperateESPs0.0312/31/06VermilionIllinoisUnits 1& 21.201/31/07OperateOFAand/or lowNOxburners"MinimumExtentPracticable"08/11/05Install ESP(or equiv. alt.tech) &continuouslyoperateESPs0.0312/31/10Wood RiverIllinoisUnits 4& 51.207/27/05OperateOFAand/or lowNOxburners"MinimumExtentPracticable"08/11/05Install ESP(or equiv. alt.tech) &continuouslyoperateESPs0.0312/31/05Kentucky Utilities CompanyEW BrownGeneratingStationKentuckyUnit 3Install FGD97% or0.10012/31/10Install andcontinuouslyoperate SCRby12/31/2012,continuouslyoperate lowNOxboilerand OFA.0.0712/31/12Continuouslyoperate ESP0.0312/31/10KU mustsurrender53,000 SO2allowances of2008 or earliervintage byMarch 1, 2009.All surplus NOxallowancesmust besurrenderedthrough 2020.SO2and NOxallowancesmay not beused forcompliance,and emissionsdecreases forpurposes ofcomplying withthe ConsentDecree do notearn credits.http://www.epa.gov/compliance/resources/cases/civil/caa/kucompany.htmlSalt River Project Agricultural Improvement and Power District (SRP)CoronadoGeneratingStationArizonaUnit 1or Unit2Immediatelybegincontinuousoperation ofexistingFGDs onboth units,install new95% or0.08New FGDinstalledby1/1/2012Install andcontinuouslyoperate lowNOxburnerand SCR0.32 priorto SCRinstallation, 0.080afterLNB by06/01/2009, SCR by06/01/2014Optimizationandcontinuousoperation ofexistingESPs.0.03Optimization beginsimmediately, rate limitbegins01/01/12(date ofnew FGDBeginning in2012, allsurplus SO2allowances forboth CoronadoandSpringervilleUnit 4 must beSO2and NOxallowancesmay not beused forcompliance,and emissionsdecreases forpurposes ofhttp://www.epa.gov/compliance/resources/cases/civil/caa/srp.html17Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateFGD.installation)surrenderedthrough 2020.The allowanceslimited by thiscondition may,however, beused forcompliance at aprospectivefuture plantusing BACTand otherwisespecified in par.54 of theconsent decree.complying withthe ConsentDecree do notearn credits.Unit 1or Unit2Install newFGD95% or0.0801/01/13Install andcontinuouslyoperate lowNOxburner0.3206/01/11Optimization beginsimmediately, rate limitbegins01/01/13(date ofnew FGDinstallation)American Electric PowerEastern System-WideAnnualCap(tons)YearAnnualCap (tons)YearNOxand SO2allowances thatwould havebeen madeavailable byemissionreductionspursuant to theConsentDecree must besurrendered.NOxand SO2allowancesmay not beused to complywith any of thelimits imposedby the ConsentDecree. TheConsentDecreeincludes aformula forcalculatingexcess NOxallowancesrelative to theCAIRAllocations,and restrictsthe use ofsome. See par.74-79 fordetails.Reducingemissionsbelow theEasternSystem-WideAnnualTonnageLimitations forNOxand SO2earnssupercompliance allowances.http://www.epa.gov/compliance/resources/cases/civil/caa/americanelectricpower1007.html450,000201096,0002009450,000201192,5002010420,000201292,5002011350,000201385,0002012340,000201485,0002013275,000201585,0002014260,000201675,0002015235,000201772,0002016 andthereafter184,0002018174,0002019 andthereafterAt least600MW fromvarious unitsWestVirginiaSporn1–4Retire,retrofit,or repower12/31/18VirginiaClinchRiver1–3IndianaTannersCreek1–318Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateWestVirginiaKammer1–3AmosWestVirginiaUnit 1Install andcontinuouslyoperateFGD12/31/09Install andcontinuouslyoperate SCR01/01/08Unit 2Install andcontinuouslyoperateFGD12/31/10Install andcontinuouslyoperate SCR01/01/09Unit 3Install andcontinuouslyoperateFGD12/31/09Install andcontinuouslyoperate SCR01/01/08Big SandyKentuckyUnit 1Burn onlycoal with nomore than1.75lb/MMBtuannualaverageDate ofentryContinuouslyoperate lowNOxburnersDate ofentryUnit 2Install andcontinuouslyoperateFGD12/31/15Install andcontinuouslyoperate SCR01/01/09CardinalOhioUnit 1Install andcontinuouslyoperateFGD12/31/08Install andcontinuouslyoperate SCR01/01/09Continuouslyoperate ESP0.0312/31/09Unit 2Install andcontinuouslyoperateFGD12/31/08Install andcontinuouslyoperate SCR01/01/09Continuouslyoperate ESP0.0312/31/09Unit 3Install andcontinuouslyoperateFGD12/31/12Install andcontinuouslyoperate SCR01/01/09Clinch RiverVirginiaUnits1–3Plantwideannualcap:21,700tons from2010 to2014,then16,300after1/1/20152010–2014,2015 andthereafterContinuouslyoperate lowNOxburnersDate ofentryConesvilleOhioUnit 1Retire,retrofit,or repowerDate ofentryUnit 2Retire,retrofit,or repowerDate ofentryUnit 3Retire,retrofit,or repower12/31/12Unit 4Install andcontinuouslyoperate12/31/10Install andcontinuouslyoperate SCR12/31/1019Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateFGDUnit 5UpgradeexistingFGD95%12/31/09Continuouslyoperate lowNOxburnersDate ofentryUnit 6UpgradeexistingFGD95%12/31/09Continuouslyoperate lowNOxburnersDate ofentryGavinOhioUnit 1Install andcontinuouslyoperateFGDDate ofentryInstall andcontinuouslyoperate SCR01/01/09Unit 2Install andcontinuouslyoperateFGDDate ofentryInstall andcontinuouslyoperate SCR01/01/09Glen LynVirginiaUnits1–3Units5, 6Burn onlycoal with nomore than1.75lb/MMBtuannualaverageDate ofentryContinuouslyoperate lowNOxburnersDate ofentryKammerWestVirginiaUnits1–3Plantwideannualcap:35,00001/01/10Continuouslyoperateover-fire airDate ofentryKanawhaRiverWestVirginiaUnits1, 2Burn onlycoal with nomore than1.75lb/MMBtuannualaverageDate ofentryContinuouslyoperate lowNOxburnersDate ofentryMitchellWestVirginiaUnit 1Install andcontinuouslyoperateFGD12/31/07Install andcontinuouslyoperate SCR01/01/09Unit 2Install andcontinuouslyoperateFGD12/31/07Install andcontinuouslyoperate SCR01/01/09MountaineerWestVirginiaUnit 1Install andcontinuouslyoperateFGD12/31/07Install andcontinuouslyoperate SCR01/01/08MuskingumRiverOhioUnits1–4Retire,retrofit,or repower12/31/15Unit 5Install andcontinuouslyoperateFGD12/31/15Install andcontinuouslyoperate SCR01/01/08Continuouslyoperate ESP0.0312/31/02PicwayOhioUnit 9Continuouslyoperate lowNOxburnersDate ofentry20Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateRockportIndianaUnit 1Install andcontinuouslyoperateFGD12/31/17Install andcontinuouslyoperate SCR12/31/17Unit 2Install andcontinuouslyoperateFGD12/31/19Install andcontinuouslyoperate SCR12/31/19SpornWestVirginiaUnit 5Retire,retrofit,or repower12/31/13TannersCreekIndianaUnits1–3Burn onlycoal with nomore than1.2lb/MMBtuannualaverageDate ofentryContinuouslyoperate lowNOxburnersDate ofentryUnit 4Burn onlycoal with nomore than1.2% sulfurcontentannualaverageDate ofentryContinuouslyoperateover-fire airDate ofentryEast Kentucky Power Cooperative Inc.By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOxcontrols at Cooper 2 by 12/31/2012 and SO2controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012.System-wideSystemwide 12-monthrollingtonnagelimits apply12-monthrollinglimit(tons)Start of12-monthcycleAll unitsmustoperate lowNOxboilers12-monthrolling limit(tons)Start of 12-monthcyclePM controldevicesmust beoperatedcontinuouslysystemwide, ESPsmust beoptimizedwithin 270days of entrydate, orEKPC maychoose tosubmit a PMPollutionControlUpgradeAnalysis.0.031 yearfrom entrydateAll surplus SO2allowancesmust besurrenderedeach year,beginning in2008.SO2and NOxallowancesmay not beused to complywith theConsentDecree. NOxallowancesthat wouldbecomeavailable as aresult ofcompliancewith theConsentDecree maynot be sold ortraded. SO2and NOxallowancesallocated toEKPC must beused within theEKPC system.Allowancesmade availabledue tosupercompliance may be soldor traded.http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.html57,00010/01/0811,50001/01/0840,00007/01/118,50001/01/1328,00001/01/138,00001/01/1521Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateSpurlockKentuckyUnit 1Install andcontinuouslyoperateFGD95% or0.16/30/2011Continuouslyoperate SCR0.12 forUnit 1 until01/01/2013, atwhichpoint theunit limitdrops to0.1. Priorto01/01/2013, thecombinedaveragewhen bothunits areoperatingmust beno morethan 0.160 daysafter entryUnit 2Install andcontinuouslyoperateFGD by10/1/200895% or0.11/1/2009Continuouslyoperate SCRand OFA0.1 forUnit 2, 0.1combinedaveragewhen bothunits areoperating60 daysafter entryDale PlantKentuckyUnit 1Install andcontinuouslyoperate lowNOxburnersby10/31/20070.4601/01/08EKPC mustsurrender 1,000NOxallowancesimmediatelyunder the ARP,and 3,107under the NOxSIP Call. EKPCmust alsosurrender15,311 SO2allowances.Date of entryhttp://www.epa.gov/compliance/resources/cases/civil/caa/eastkentuckypowerdale0907.htmlUnit 2Install andcontinuouslyoperate lowNOxburnersby10/31/20070.4601/01/08Unit 3EKPCmaychoosetoretireDale 3and 4in lieuofinstallingcontrols inCooper 212/31/2012Unit 4CooperKentuckyUnit 1Unit 2If EKPCopts toinstallcontrolsrather thanretiringDale, it must95% or0.10If EKPCelects toinstallcontrols, itmustcontinuouslyoperate SCR0.08 (or90% ifnon-SCRtechnology is used)12/31/1222Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective Dateinstall andcontinuouslyoperateFGD orequiv.technologyor installequiv.technologyNevada Power CompanyBeginning 1/1/2010, combined NOxemissions from Units 5,6,7, and 8 must be no more than 360 tons per year.ClarkGeneratingStationNevadaUnit 5UnitsmayonlyfirenaturalgasIncreasewaterinjectionimmediately,then installand operateultra-lowNOxburners(ULNBs) orequivalenttechnology.In 2009,Units 5 and8 may notemit morethan 180tonscombined5ppm 1-houraverage12/31/08(ULNBinstallation), 01/30/09(1-houraverage)Allowancesmay not beused to complywith theConsentDecree, andno allowancesmade availabledue tocompliancewith theConsentDecree may betraded or sold.http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlUnit 65ppm 1-houraverage12/31/09(ULNBinstallation), 01/30/10(1-houraverage)Unit 75ppm 1-houraverage12/31/09(ULNBinstallation), 01/30/10(1-houraverage)Unit 85ppm 1-houraverage12/31/08(ULNBinstallation), 01/30/09(1-houraverage)Dayton Power & LightNon-EPA Settlement of 10/23/2008StuartGeneratingStationOhioStation-wideCompleteinstallationof FGDs oneach unit.96% or0.1007/31/09Owners maynot purchaseany newcatalyst withSO2to SO3conversionrate greaterthan 0.5%0.17stationwide30 daysafter entry0.030 lbper unit07/31/09NOxand SO2allowancesmay not beused to complywith themonthly ratesspecified in theConsentDecree.Courtlink documentprovided by EPA in email0.17stationwide60 daysafter entrydate82%includingdata fromperiods ofmalfunctions7/31/09through7/30/11Installcontroltechnologyon one unit0.10 onany singleunit12/31/12Installrigid-typeelectrodes ineachunit'sESP12/31/1582%includingdata fromperiods ofmalfunctionsafter7/31/110.15stationwide07/01/120.10stationwide12/31/14PSEG FOSSIL, Amended Consent Decree of November 200623Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateKearnyNewJerseyUnit 7Retireunit01/01/07Allowancesallocated toKearny,Hudson, andMercer mayonly be used forthe operationalneeds of thoseunits, and allsurplusallowancesmust besurrendered.Within 90 daysof amendedConsentDecree, PSEGmust surrender1,230 NOxAllowances and8,568 SO2Allowances notalreadyallocated to orgenerated bythe units listedhere. Kearnyallowancesmust besurrenderedwith theshutdown ofthose units.http://www.epa.gov/compliance/resources/decrees/amended/psegfossilamended-cd.pdfUnit 8Retireunit01/01/07HudsonNewJerseyUnit 2Install DryFGD (orapprovedalt.technology)andcontinuallyoperate0.1512/31/10Install SCR(or approvedtech) andcontinuallyoperate0.112/31/10InstallBaghouse(or approvedtechnology)0.01512/31/10AnnualCap(tons)YearAnnualCap (tons)Year5,54720073,48620075,27020083,48620085,27020093,48620095,27020103,4862010MercerNewJerseyUnits 1&2Install DryFGD (orapprovedalt.technology)andcontinuallyoperate0.1512/31/10Install SCR(or approvedtech) andcontinuallyoperate0.101/01/07InstallBaghouse(or approvedtechnology)0.01512/31/10Westar EnergyJeffreyEnergyCenterKansasAllunitsUnits 1, 2, and 3 have a total annual limitof 6,600 tons of SO2 and an annual ratelimit of 0.07 lbs/MMBtu starting 2012Units 1, 2, and 3 must all install FGDs by2011 and operate them continuously.FGDs must maintain a 30-Day RollingAverage Unit Removal Efficiency for SO2of at least 97% or a 30-Day RollingAverage Unit Emission Rate for SO2 of nogreater than 0.070 lb/MMBtu.Units 1-3 must continuously operate LowNOx Combustion Systems by 2012 andachieve and maintain a 30-Day RollingAverage Unit Emission Rate for NOx of nogreater than 0.180 lb/MMBtu.One of the three units must install an SCRby 2015 and operate it continuously tomaintain a 30-Day Rolling Average UnitEmission Rate for NOx of no greater than0.080 lb/MMBtu.By 2013 Westar shall elect to either (a)install a second SCR on one of the otherJEC Units by 2017 or (b) meet a 0.100lb/MMBtu Plant-Wide 12-Month RollingAverage Emission Rate and 9.6 MTonsannual cap for NOx by 2015Units 1, 2, and 3 must operate each ESPand FGD system continuously by 2011 andmaintain a 0.030 lb/MMBtu PM EmissionsRate.Units 1 and 2’s ESPs must be rebuilt by2014 in order to meet a 0.030 lb/MMBtu PMEmissions RateDuke EnergyGallagherIndianaUnits 1& 3Retireorrepower asnaturalgas1/1/2012Units 2& 4Install Drysorbentinjectiontechnology80%1/1/201224Companyand PlantStateUnitSettlement ActionsReferenceRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffective DateAmerican Municipal PowerGorsuchStationOhioUnits 2& 3Elected to Retire Dec15, 2010 (must retireby Dec 31, 2012)http://amppartners.org/newsroom/amp-to-retire-gorsuch-generating-station/Units 1& 4Hoosier Energy Rural Electric CooperativeRattsIndianaUnits 1& 2Install &continuallyoperateSNCRS0.2512/31/2011Continuously operate ESPAnnually surrender any NOx and SO2 allowances thatHoosier does not need in order to meet its regulatoryobligationshttp://www.epa.gov/compliance/resources/cases/civil/caa/hoosier.htmlMeromIndianaUnit 1Continuslyrun currentFGD for90%removal andupdate FGDfor 98%removal by201298%2012ContinuouslyoperateexistingSCRs0.12Continuously operate ESP and achieve PMrate no greater than 0.007 by 6/1/12Unit 2Continuslyrun currentFGD for90%removal andupdate FGDfor 98%removal by201498%2014Continuously operate ESP and achieve PMrate no greater than 0.007 by 6/1/13Notes: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 Mercer plantunder the PSEG Fossil settlement, and an updateto the SO2emission 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 settlementactions are simplified for representation in the model. This table is not intended to be a comprehensive description of allelements of the actual settlement agreements.3) 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 as individual constraints on emission rates in EPA BaseCase, 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 EPABase Case5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected inEPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not included in EPA Base Case.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 documentation7) 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 emissionsrate 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.25Appendix 3-4 State Settlements in EPA Base Case v4.10_PTox, Mar2011Company andPlantStateUnitState Enforcement ActionsRetire/RepowerSO2controlNOxControlPM ControlMercury ControlActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateAESGreenidgeNewYorkUnit 4Install FGD90%09/01/07Install SCR0.1509/01/07Unit 3Install BACT12/31/09Install BACT12/31/09WestoverNewYorkUnit 890%12/31/10Install SCR0.1512/31/10Unit 7Install BACT12/31/09Install BACT12/31/09HicklingNewYorkUnits 1 &2Install BACT05/01/07Install BACT05/01/07JennisonNewYorkUnits 1 &2Install BACT05/01/07Install BACT05/01/07Niagara Mohawk PowerNRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2and 10,777 tons of NOx, 2006 is 34,230 of SO2and 6,772 of NOx, 2007 is 30,859 of SO2and 6,211 of NOx, 2008 is 22,733tons of SO2HuntleyNewYorkUnits63–66RetireBefore2008Public Service Co. of NMSan JuanNewMexicoUnit 1State-of-thearttechnology90%10/31/08State-of-thearttechnology0.310/31/08OperateBaghouse anddemistertechnology0.01512/31/09Designactivatedcarbon injectiontechnology (orcomparabletech)12/31/09Unit 203/31/0903/31/0912/31/0912/31/09Unit 304/30/0804/30/0804/30/0804/30/08Unit 410/31/0710/31/0710/31/0710/31/07Public Service Co of ColoradoComancheColoradoUnits 1 &2Install andoperateFGD0.1lb/mmBtucombinedaverage07/01/09Install lowNOxemissioncontrols0.15lb/mmBtucombinedaverage07/01/09Install sorbentinjectiontechnology07/01/09Unit 3Install andoperateFGD0.1lb/mmBtuInstall andoperateSCR0.08Install andoperate a fabricfilter dustcollectionsystem0.013Install sorbentinjectiontechnologyWithin 180days ofstart-upRochester Gas & ElectricRussell PlantNewYorkUnits1–4RetireallunitsMirant New YorkLovett PlantNewYorkUnit 1Retire05/07/07Unit 2Retire04/30/08Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court ofAppeals, 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 conversions 2



# 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 disc ussed 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 furnac e 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 Wilc ox’s White Paper MS-14 “Natural Gas Conversions of Exiting

Coal-Fired Boilers” 2010 ( www.babcock.co m/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 Require ments 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

equation 4



# .

• 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, Q

m 

# (million cubic feet per day)

Q

m 

# = 0.06745 * d 2.667 

# , where d is the diameter of the mainline in inches

Required Capacity of Lateral/s for Each Boiler, Q l 

# (million cubic feet per day)

Q l 

# = (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 * Q l 

# ) 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-f ired 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 allo wing 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 8Frequency(n=1294)



# Number of Laterals 

# Number of Laterals Required per 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

400Frequency(n=1294)



# Miles of Pipeline 

# Miles of Pipeline Required per 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 20Frequency(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

5000Frequency(n=1294)



# Number of Inch

‐ Miles per Boiler 

# Total Inch

‐ Miles of Laterals Required per 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

400Frequency(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

1200Frequency(n=1294)



# Cost Increment ($) 

# Cost per kW of Boiler Capacity ($)33Table 5-13 Cost of Building Pipelines to Coal PlantsUniqueID_Final Plant Name StateCoalBoilerCapacity(MW)NumberofLateralsRequiredMiles ofNewPipelineRequiredto HookUp Unit(miles)Total Cost ofNew Pipeline($)Cost of NewPipeline perKW of CoalCapacity($/kW)3_B_1 Barry AL 138 1 1 856,526 63_B_2 Barry AL 137 1 1 854,527 63_B_3 Barry AL 249 2 8 5,243,996 213_B_4 Barry AL 362 2 8 6,578,846 183_B_5 Barry AL 750 3 19 16,808,021 227_B_1 Gadsden AL 64 1 29 16,488,170 2587_B_2 Gadsden AL 66 1 29 16,913,408 2568_B_10 Gorgas AL 690 2 68 64,804,607 948_B_6 Gorgas AL 108 1 8 5,481,155 518_B_7 Gorgas AL 109 1 8 5,362,968 498_B_8 Gorgas AL 165 1 8 5,940,132 368_B_9 Gorgas AL 175 1 8 6,126,314 3510_B_1 Greene County AL 254 1 7 6,058,364 2410_B_2 Greene County AL 243 1 7 6,006,273 2526_B_1 E C Gaston AL 254 1 23 20,296,423 8026_B_2 E C Gaston AL 256 1 23 20,549,257 8026_B_3 E C Gaston AL 254 1 23 20,403,517 8026_B_4 E C Gaston AL 256 1 23 20,416,837 8026_B_5 E C Gaston AL 861 3 163 157,432,294 18347_B_1 Colbert AL 177 1 0 373,331 247_B_2 Colbert AL 177 1 0 373,331 247_B_3 Colbert AL 177 1 0 373,331 247_B_4 Colbert AL 173 1 0 370,044 23447_B_5 Colbert AL 459 2 4 3,524,413 850_B_1 Widows Creek AL 111 2 165 76,835,602 69250_B_2 Widows Creek AL 111 2 165 76,835,602 69250_B_3 Widows Creek AL 111 2 165 77,445,655 69850_B_4 Widows Creek AL 111 2 165 77,445,655 69850_B_5 Widows Creek AL 111 2 165 73,708,744 66450_B_6 Widows Creek AL 111 2 165 73,708,744 66450_B_7 Widows Creek AL 473 3 253 156,623,156 33150_B_8 Widows Creek AL 464 2 165 138,258,079 29851_B_1 Dolet Hills LA 650 4 32 24,784,949 3856_B_1 Charles R Lowman AL 86 1 17 11,062,025 12956_B_2 Charles R Lowman AL 238 2 44 30,585,021 12956_B_3 Charles R Lowman AL 238 2 44 30,950,390 13059_B_1 Platte NE 100 1 26 17,550,190 17660_B_1 Whelan Energy Center NE 77 1 8 4,771,943 6260_B_2 Whelan Energy Center NE 220 1 8 6,543,326 3087_B_1 Escalante NM 247 2 11 5,066,695 21108_B_SGU1 Holcomb KS 360 4 46 26,657,544 74113_B_1 Cholla AZ 110 1 28 18,947,152 172113_B_2 Cholla AZ 275 1 28 26,244,568 95113_B_3 Cholla AZ 271 1 28 26,736,227 99113_B_4 Cholla AZ 380 2 58 47,225,178 124126_B_4 H Wilson Sundt Generating Station AZ 156 1 4 3,325,760 21127_B_1 Oklaunion TX 690 8 560 324,667,985 471130_B_1 Cross SC 620 2 240 224,907,896 363130_B_2 Cross SC 540 2 240 216,115,742 400130_B_3 Cross SC 580 2 240 217,804,475 376130_B_4 Cross SC 600 2 240 214,338,942 357136_B_1 Seminole FL 658 3 153 123,762,396 188136_B_2 Seminole FL 658 3 153 122,186,247 18635160_B_2 Apache Station AZ 175 1 2 1,297,559 7160_B_3 Apache Station AZ 175 1 2 1,277,332 7165_B_1 GRDA OK 490 6 296 174,657,509 356165_B_2 GRDA OK 520 7 415 208,730,810 401207_B_1 St Johns River Power Park FL 626 3 212 196,013,308 313207_B_2 St Johns River Power Park FL 626 4 477 307,121,204 491298_B_LIM1 Limestone TX 831 7 325 193,623,209 233298_B_LIM2 Limestone TX 858 7 325 200,701,756 234384_B_71 Joliet 29 IL 259 2 2 1,347,435 5384_B_72 Joliet 29 IL 259 2 2 1,162,657 4384_B_81 Joliet 29 IL 259 2 2 1,248,834 5384_B_82 Joliet 29 IL 259 2 2 1,162,657 4462_B_55 W N Clark CO 18 1 40 14,508,820 824462_B_59 W N Clark CO 25 1 40 16,328,260 656465_B_3 Arapahoe CO 47 1 9 4,410,931 94465_B_4 Arapahoe CO 121 2 86 42,752,979 353469_B_1 Cherokee CO 115 2 74 33,550,262 292469_B_2 Cherokee CO 120 2 74 33,924,698 283469_B_3 Cherokee CO 165 2 74 43,357,353 263469_B_4 Cherokee CO 388 2 74 67,384,584 174470_B_1 Comanche CO 366 2 151 139,124,028 380470_B_2 Comanche CO 370 2 151 139,986,886 378470_B_3 Comanche CO 750 4 463 332,375,688 443477_B_5 Valmont CO 199 1 19 14,716,699 74492_B_5 Martin Drake CO 46 1 13 6,642,383 144492_B_6 Martin Drake CO 77 2 127 33,893,437 440492_B_7 Martin Drake CO 131 2 127 64,243,979 490525_B_H1 Hayden CO 205 2 78 48,661,086 237525_B_H2 Hayden CO 300 3 123 81,937,859 273527_B_1 Nucla CO 100 2 43 11,535,802 11536564_B_1 Stanton Energy Center FL 440 231 28,104,431 64564_B_2 Stanton Energy Center FL 446 231 27,959,515 63568_B_BHB3 Bridgeport Station CT 372 3 43 28,557,342 77593_B_3 Edge Moor DE 86 2 14 6,706,484 78593_B_4 Edge Moor DE 174 2 14 7,908,368 45594_B_3 Indian River Generating Station DE 153 1 65 48,452,569 317594_B_4 Indian River Generating Station DE 405 2 144 88,686,140 219602_B_1 Brandon Shores MD 643 2 46 42,283,145 66602_B_2 Brandon Shores MD 643 2 46 42,934,049 67628_B_1 Crystal River FL 379 2 80 64,036,264 169628_B_2 Crystal River FL 491 2 80 67,687,999 138628_B_4 Crystal River FL 722 2 80 37,187,321 52628_B_5 Crystal River FL 721 2 80 35,020,225 49641_B_4 Crist FL 78 1 6 3,592,115 46641_B_5 Crist FL 78 1 6 3,517,484 45641_B_6 Crist FL 302 2 31 24,092,073 80641_B_7 Crist FL 472 2 31 30,704,144 65642_B_1 Scholz FL 49 1 13 6,456,489 132642_B_2 Scholz FL 49 1 13 6,716,660 137643_B_1 Lansing Smith FL 162 1 22 17,226,194 106643_B_2 Lansing Smith FL 195 1 22 18,788,587 96645_B_BB01 Big Bend FL 391 2 25 18,006,544 46645_B_BB02 Big Bend FL 391 2 25 17,980,144 46645_B_BB03 Big Bend FL 364 2 25 19,260,622 53645_B_BB04 Big Bend FL 447 2 25 20,775,229 46663_B_B2 Deerhaven Generating Station FL 228 1 12 10,065,696 44667_B_1 Northside Generating Station FL 275 3 205 97,644,692 355667_B_2 Northside Generating Station FL 275 3 205 110,541,549 402676_B_3 C D McIntosh Jr FL 342 1 0 52,953 -703_B_1BLR Bowen GA 713 2 83 83,854,057 11837703_B_2BLR Bowen GA 718 2 83 85,497,920 119703_B_3BLR Bowen GA 902 3 212 165,111,996 183703_B_4BLR Bowen GA 929 3 212 168,510,330 181708_B_1 Hammond GA 112 1 42 27,538,206 246708_B_2 Hammond GA 112 1 42 27,345,875 244708_B_3 Hammond GA 112 1 42 27,384,522 245708_B_4 Hammond GA 510 2 110 102,098,030 200709_B_1 Harllee Branch GA 266 2 60 43,475,590 163709_B_2 Harllee Branch GA 325 2 60 47,552,004 146709_B_3 Harllee Branch GA 509 2 60 57,310,793 113709_B_4 Harllee Branch GA 507 2 60 57,554,933 114710_B_MB1 Jack McDonough GA 258 1 8 6,833,915 26710_B_MB2 Jack McDonough GA 259 1 8 6,833,915 26727_B_3 Mitchell GA 96 1 67 39,746,899 414728_B_Y1BR Yates GA 99 1 9 6,092,955 62728_B_Y2BR Yates GA 105 1 9 6,250,791 60728_B_Y3BR Yates GA 112 1 9 6,402,249 57728_B_Y4BR Yates GA 135 1 9 6,719,015 50728_B_Y5BR Yates GA 137 1 9 6,756,893 49728_B_Y6BR Yates GA 352 2 23 17,743,087 50728_B_Y7BR Yates GA 355 2 23 17,648,076 50733_B_1 Kraft GA 48 1 2 861,799 18733_B_2 Kraft GA 52 1 2 851,601 16733_B_3 Kraft GA 102 1 2 1,099,326 11753_B_ST Crisp Plant GA 10 1 67 20,321,021 2,032856_B_1 E D Edwards IL 112 2 61 13,738,422 123856_B_2 E D Edwards IL 273 2 61 46,425,546 170856_B_3 E D Edwards IL 364 3 125 85,921,187 236861_B_01 Coffeen IL 340 3 103 68,710,560 202861_B_02 Coffeen IL 560 3 103 82,715,063 14838863_B_05 Hutsonville IL 76 2 67 18,023,856 237863_B_06 Hutsonville IL 77 1 25 14,411,276 187864_B_05 Meredosia IL 203 1 18 15,177,107 75867_B_7 Crawford IL 213 1 19 16,157,648 76867_B_8 Crawford IL 319 2 43 31,027,338 97874_B_5 Joliet 9 IL 314 2 2 1,666,759 5876_B_1 Kincaid Generation LLC IL 584 2 11 8,272,242 14876_B_2 Kincaid Generation LLC IL 584 2 11 8,186,657 14879_B_51 Powerton IL 385 2 66 60,857,425 158879_B_52 Powerton IL 385 2 66 59,892,609 156879_B_61 Powerton IL 385 2 66 60,703,641 158879_B_62 Powerton IL 385 2 66 59,892,609 156883_B_17 Waukegan IL 100 1 15 10,038,571 100883_B_7 Waukegan IL 328 2 38 29,029,637 89883_B_8 Waukegan IL 361 2 38 30,956,775 86884_B_1 Will County IL 151 1 4 3,163,672 21884_B_2 Will County IL 148 1 4 3,225,873 22884_B_3 Will County IL 251 2 16 6,254,012 25884_B_4 Will County IL 510 3 27 19,264,080 38886_B_19 Fisk Street IL 326 2 50 37,297,455 114887_B_1 Joppa Steam IL 167 1 1 868,817 5887_B_2 Joppa Steam IL 167 1 1 868,052 5887_B_3 Joppa Steam IL 167 1 1 866,518 5887_B_4 Joppa Steam IL 167 1 1 865,749 5887_B_5 Joppa Steam IL 167 1 1 874,899 5887_B_6 Joppa Steam IL 167 1 1 867,286 5889_B_1 Baldwin Energy Complex IL 624 3 106 79,181,733 127889_B_2 Baldwin Energy Complex IL 629 3 106 81,560,802 130889_B_3 Baldwin Energy Complex IL 629 3 106 83,884,301 133891_B_9 Havana IL 487 2 74 66,810,686 13739892_B_1 Hennepin Power Station IL 81 1 14 8,519,227 105892_B_2 Hennepin Power Station IL 240 1 14 12,775,378 53897_B_1 Vermilion IL 84 1 9 5,387,282 64897_B_2 Vermilion IL 213 1 9 7,794,565 37898_B_4 Wood River IL 105 1 1 414,232 4898_B_5 Wood River IL 383 2 50 31,960,057 83963_B_31 Dallman IL 86 2 9 2,538,463 30963_B_32 Dallman IL 87 2 9 3,674,986 42963_B_33 Dallman IL 199 2 9 6,103,905 31963_B_4 Dallman IL 200 2 9 5,241,841 26976_B_123 Marion IL 120 1 2 1,159,953 10976_B_4 Marion IL 170 2 5 3,301,244 19981_B_3 State Line IN 187 1 17 13,401,529 72981_B_4 State Line IN 303 1 17 16,050,991 53983_B_1 Clifty Creek IN 217 2 73 46,944,665 216983_B_2 Clifty Creek IN 217 2 73 46,314,833 213983_B_3 Clifty Creek IN 217 2 73 46,115,920 213983_B_4 Clifty Creek IN 217 2 73 46,015,513 212983_B_5 Clifty Creek IN 217 2 73 45,451,394 209983_B_6 Clifty Creek IN 217 2 73 45,812,745 211988_B_U1 Tanners Creek IN 145 2 34 16,615,136 115988_B_U2 Tanners Creek IN 145 2 34 15,923,309 110988_B_U3 Tanners Creek IN 200 2 34 20,702,486 104988_B_U4 Tanners Creek IN 500 2 34 29,541,774 59990_B_50 Harding Street IN 109 2 19 8,909,894 82990_B_60 Harding Street IN 109 2 19 8,885,172 82990_B_70 Harding Street IN 435 2 19 15,879,585 37991_B_3 Eagle Valley IN 43 1 7 3,124,071 73991_B_4 Eagle Valley IN 56 1 7 3,485,879 62991_B_5 Eagle Valley IN 62 1 7 3,503,708 5740991_B_6 Eagle Valley IN 99 1 7 4,193,428 42994_B_1 Petersburg IN 232 3 49 21,334,190 92994_B_2 Petersburg IN 435 3 49 37,186,537 85994_B_3 Petersburg IN 540 3 49 41,499,639 77994_B_4 Petersburg IN 545 3 49 41,426,794 76995_B_7 Bailly IN 160 1 6 4,734,708 30995_B_8 Bailly IN 320 1 6 6,131,745 19996_B_11 Dean H Mitchell IN 110 1 9 6,215,826 57996_B_4 Dean H Mitchell IN 125 1 9 6,467,171 52996_B_5 Dean H Mitchell IN 125 1 9 6,298,738 50996_B_6 Dean H Mitchell IN 125 1 9 6,290,529 50997_B_12 Michigan City IN 469 2 30 23,673,656 501001_B_1 Cayuga IN 479 2 17 14,422,589 301001_B_2 Cayuga IN 473 2 17 14,501,320 311008_B_1 R Gallagher IN 140 2 68 37,331,906 2671008_B_2 R Gallagher IN 140 2 68 37,021,229 2641008_B_3 R Gallagher IN 140 2 68 37,073,612 2651008_B_4 R Gallagher IN 140 2 68 37,331,906 2671010_G_1 Wabash River IN 85 1 18 9,993,513 1181010_G_1A Wabash River IN 189 1 18 13,544,723 721010_B_2 Wabash River IN 85 1 18 10,865,630 1281010_B_3 Wabash River IN 85 1 18 10,562,318 1241010_B_4 Wabash River IN 85 1 18 10,734,687 1261010_B_5 Wabash River IN 95 1 18 10,957,573 1151010_B_6 Wabash River IN 318 2 36 27,172,030 851012_B_2 F B Culley IN 90 2 17 7,809,213 871012_B_3 F B Culley IN 270 2 17 12,236,461 451024_B_5 Crawfordsville IN 11 1 17 4,869,930 4591024_B_6 Crawfordsville IN 13 1 17 4,869,930 3871032_B_5 Logansport IN 17 1 33 12,027,095 729411032_B_6 Logansport IN 22 1 33 13,630,519 6201037_B_2 Peru IN 20 1 35 13,581,293 6791037_B_5 Peru IN 12 1 35 11,360,979 9471040_B_1 Whitewater Valley IN 35 1 15 6,598,822 1901040_B_2 Whitewater Valley IN 63 1 15 8,261,808 1321043_B_1SG1 Frank E Ratts IN 122 2 21 10,457,087 861043_B_2SG1 Frank E Ratts IN 121 2 21 10,319,734 851046_B_1 Dubuque IA 35 1 5 2,208,889 621046_B_5 Dubuque IA 30 1 5 1,972,563 651046_B_6 Dubuque IA 13 1 5 1,467,704 1111047_B_2 Lansing IA 11 1 55 17,428,351 1,5421047_B_3 Lansing IA 37 1 55 26,822,979 7331047_B_4 Lansing IA 261 1 55 51,934,638 1991048_B_2 Milton L Kapp IA 211 1 12 10,197,479 481058_B_2 Sixth Street IA 14 1 26 8,461,946 6221058_B_3 Sixth Street IA 14 1 26 8,917,212 6561058_B_4 Sixth Street IA 14 1 26 8,917,212 6561058_B_5 Sixth Street IA 14 1 26 8,917,212 6561073_B_1 Prairie Creek IA 9 1 27 7,326,935 8051073_B_2 Prairie Creek IA 10 1 27 7,746,242 7591073_B_3 Prairie Creek IA 42 1 27 12,682,328 3051073_B_4 Prairie Creek IA 125 1 27 18,508,829 1491077_B_1 Sutherland IA 31 1 13 5,431,663 1781077_B_2 Sutherland IA 31 1 13 5,478,150 1761077_B_3 Sutherland IA 82 1 13 7,308,613 891081_B_7 Riverside IA 3 1 9 1,543,342 6171081_B_8 Riverside IA 3 1 9 1,543,342 6171081_B_9 Riverside IA 130 1 9 6,507,714 501082_B_1 Walter Scott Jr. Energy Center IA 45 1 7 3,490,912 781082_B_2 Walter Scott Jr. Energy Center IA 88 1 7 4,579,541 52421082_B_3 Walter Scott Jr. Energy Center IA 690 2 20 19,594,759 281082_B_4 Walter Scott Jr. Energy Center IA 800 3 100 83,501,145 1041091_B_1 George Neal North IA 135 1 6 4,137,763 311091_B_2 George Neal North IA 300 2 94 56,762,413 1891091_B_3 George Neal North IA 515 2 94 92,812,290 1801104_B_1 Burlington IA 209 1 56 48,751,365 2331122_B_7 Ames Electric Services Power Plant IA 33 1 9 4,306,424 1301122_B_8 Ames Electric Services Power Plant IA 70 1 9 5,719,317 821131_B_6 Streeter Station IA 19 1 11 4,085,397 2161131_B_7 Streeter Station IA 36 1 11 5,297,932 1481167_B_7 Muscatine Plant #1 IA 22 1 15 6,025,405 2761167_B_8 Muscatine Plant #1 IA 35 1 15 7,448,934 2131167_B_9 Muscatine Plant #1 IA 147 1 15 11,166,673 761175_B_6 Pella IA 15 1 34 11,121,998 7411175_B_7 Pella IA 13 1 34 10,691,186 8351217_B_1 Earl F Wisdom IA 38 1 5 2,119,776 571218_B_1 Fair Station IA 23 1 13 4,940,202 2111218_B_2 Fair Station IA 41 1 13 5,861,900 1431239_B_39 Riverton KS 38 1 5 2,600,912 681239_B_40 Riverton KS 54 1 5 2,860,706 531241_B_1 La Cygne KS 724 2 38 34,344,062 471241_B_2 La Cygne KS 682 2 38 33,970,202 501250_B_3 Lawrence Energy Center KS 48 1 5 2,464,647 511250_B_4 Lawrence Energy Center KS 110 1 5 3,255,157 301250_B_5 Lawrence Energy Center KS 366 2 41 33,321,767 911252_B_10 Tecumseh Energy Center KS 129 1 20 14,251,148 1101252_B_9 Tecumseh Energy Center KS 74 1 20 12,396,350 1681295_B_1 Quindaro KS 72 1 0 291,231 41295_B_2 Quindaro KS 111 1 0 350,406 31353_B_BSU1 Big Sandy KY 260 2 13 9,325,001 36431353_B_BSU2 Big Sandy KY 800 3 28 22,413,123 281355_B_1 E W Brown KY 94 1 11 6,988,397 741355_B_2 E W Brown KY 160 1 11 8,028,683 501355_B_3 E W Brown KY 422 2 27 22,420,126 531356_B_1 Ghent KY 475 2 72 62,221,800 1311356_B_2 Ghent KY 469 2 72 60,732,185 1291356_B_3 Ghent KY 478 2 72 61,354,347 1281356_B_4 Ghent KY 478 2 72 61,336,293 1281357_B_4 Green River KY 68 1 23 13,703,486 2021357_B_5 Green River KY 95 1 23 14,284,315 1501361_B_5 Tyrone KY 71 1 29 16,305,568 2301363_B_4 Cane Run KY 155 2 69 40,785,891 2631363_B_5 Cane Run KY 168 2 69 42,701,837 2541363_B_6 Cane Run KY 240 3 118 64,697,971 2701364_B_1 Mill Creek KY 303 3 128 82,282,642 2721364_B_2 Mill Creek KY 301 3 128 82,811,245 2751364_B_3 Mill Creek KY 391 3 128 91,832,381 2351364_B_4 Mill Creek KY 477 3 128 98,648,172 2071374_B_1 Elmer Smith KY 132 1 6 4,260,976 321374_B_2 Elmer Smith KY 261 1 6 5,968,374 231378_B_1 Paradise KY 616 3 122 71,081,976 1151378_B_2 Paradise KY 602 2 73 60,900,519 1011378_B_3 Paradise KY 977 3 122 112,779,002 1151379_B_1 Shawnee KY 133 1 7 4,919,734 371379_B_10 Shawnee KY 124 1 7 5,111,900 411379_B_2 Shawnee KY 134 1 7 4,937,195 371379_B_3 Shawnee KY 134 1 7 4,937,195 371379_B_4 Shawnee KY 134 1 7 4,937,195 371379_B_5 Shawnee KY 134 1 7 4,937,195 371379_B_6 Shawnee KY 134 1 7 4,937,195 37441379_B_7 Shawnee KY 134 1 7 4,937,195 371379_B_8 Shawnee KY 134 1 7 4,937,195 371379_B_9 Shawnee KY 134 1 7 4,937,195 371381_B_C1 Kenneth C Coleman KY 150 1 13 9,632,325 641381_B_C2 Kenneth C Coleman KY 150 1 13 9,632,325 641381_B_C3 Kenneth C Coleman KY 155 1 13 9,753,637 631382_B_H1 HMP&L Station Two Henderson KY 153 2 8 4,675,164 311382_B_H2 HMP&L Station Two Henderson KY 159 2 8 4,777,427 301383_B_R1 Robert A Reid KY 65 1 2 1,099,308 171384_B_1 Cooper KY 116 1 32 20,622,529 1781384_B_2 Cooper KY 225 1 32 26,316,589 1171385_B_1 Dale KY 27 1 4 1,766,472 651385_B_2 Dale KY 27 1 4 1,773,806 661385_B_3 Dale KY 75 1 4 2,378,590 321385_B_4 Dale KY 75 1 4 2,378,590 321393_B_6 R S Nelson LA 550 3 9 8,013,893 151552_B_1 C P Crane MD 200 2 45 28,572,945 1431552_B_2 C P Crane MD 200 2 45 28,389,222 1421554_B_2 Herbert A Wagner MD 135 1 22 16,819,534 1251554_B_3 Herbert A Wagner MD 324 1 22 21,800,677 671570_B_11 R Paul Smith Power Station MD87 2 27 13,234,070 1521570_B_9 R Paul Smith Power Station MD28 1 12 4,785,577 1711571_B_1 Chalk Point LLC MD 341 1 1 1,452,650 41571_B_2 Chalk Point LLC MD 342 1 1 1,453,966 41572_B_1 Dickerson MD 182 2 9 5,429,574 301572_B_2 Dickerson MD 182 2 9 5,421,348 301572_B_3 Dickerson MD 182 2 9 5,454,113 301573_B_1 Morgantown Generating Plant MD 624 3 99 65,209,623 1051573_B_2 Morgantown Generating Plant MD 620 3 99 62,360,586 1011606_B_1 Mount Tom MA 144 1 15 10,827,679 75451619_B_1 Brayton Point MA 244 3 85 44,147,316 1811619_B_2 Brayton Point MA 244 3 85 44,233,074 1811619_B_3 Brayton Point MA 612 5 218 146,022,447 2391626_B_1 Salem Harbor MA 82 1 1 383,498 51626_B_2 Salem Harbor MA 80 1 1 379,893 51626_B_3 Salem Harbor MA 150 1 1 480,620 31695_B_4 B C Cobb MI 156 2 90 51,000,180 3271695_B_5 B C Cobb MI 156 2 90 50,689,290 3251702_B_1 Dan E Karn MI 255 1 49 42,287,400 1661702_B_2 Dan E Karn MI 260 1 49 42,567,978 1641710_B_1 J H Campbell MI 260 3 188 105,151,164 4041710_B_2 J H Campbell MI 355 3 188 123,228,381 3471710_B_3 J H Campbell MI 825 3 188 159,177,335 1931720_B_7 J C Weadock MI 151 1 48 34,952,956 2311720_B_8 J C Weadock MI 151 1 48 34,990,691 2321723_B_1 J R Whiting MI 102 1 14 8,960,245 881723_B_2 J R Whiting MI 102 1 14 8,960,245 881723_B_3 J R Whiting MI 124 1 14 9,608,933 771731_B_1 Harbor Beach MI 103 2 144 65,999,089 6411732_B_10 Marysville MI 42 1 9 4,558,011 1091732_B_11 Marysville MI 42 1 9 4,558,011 1091732_B_12 Marysville MI 42 1 9 4,558,011 1091732_B_9 Marysville MI 42 1 9 4,558,011 1091733_B_1 Monroe MI 770 3 63 51,067,983 661733_B_2 Monroe MI 785 3 63 51,099,864 651733_B_3 Monroe MI 795 3 63 51,321,409 651733_B_4 Monroe MI 775 3 63 50,810,782 661740_B_2 River Rouge MI 241 2 21 14,040,402 581740_B_3 River Rouge MI 272 3 43 18,325,670 671743_B_1 St Clair MI 151 1 1 821,585 5461743_B_2 St Clair MI 154 1 1 819,061 51743_B_3 St Clair MI 160 1 1 833,199 51743_B_4 St Clair MI 151 1 1 818,216 51743_B_6 St Clair MI 312 1 1 1,020,896 31743_B_7 St Clair MI 440 2 3 1,888,087 41745_B_16 Trenton Channel MI 53 1 7 3,518,012 671745_B_17 Trenton Channel MI 53 1 7 3,656,788 701745_B_18 Trenton Channel MI 53 1 7 3,459,862 661745_B_19 Trenton Channel MI 53 1 7 3,400,035 651745_B_9A Trenton Channel MI 536 2 28 24,802,480 461769_B_5 Presque Isle MI 88 2 310 134,703,955 1,5311769_B_6 Presque Isle MI 88 2 310 134,119,117 1,5241769_B_7 Presque Isle MI 85 2 310 142,818,725 1,6801769_B_8 Presque Isle MI 85 2 310 137,993,296 1,6231769_B_9 Presque Isle MI 85 2 310 137,993,296 1,6231771_B_1 Escanaba MI 13 1 100 33,520,946 2,5791771_B_2 Escanaba MI 13 1 100 33,520,946 2,5791825_B_3 J B Sims MI 73 1 50 28,170,957 3871830_B_3 James De Young MI 11 1 58 17,149,007 1,6331830_B_4 James De Young MI 21 1 58 21,967,043 1,0721830_B_5 James De Young MI 27 1 58 25,680,113 9511831_B_1 Eckert Station MI 40 1 24 11,844,286 2961831_B_2 Eckert Station MI 42 1 24 12,088,759 2891831_B_3 Eckert Station MI 41 1 24 12,054,339 2981831_B_4 Eckert Station MI 69 1 24 14,020,209 2031831_B_5 Eckert Station MI 69 1 24 14,438,857 2101831_B_6 Eckert Station MI 67 1 24 14,126,816 2111832_B_1 Erickson Station MI 152 1 22 16,549,274 1091843_B_2 Shiras MI 20 1 141 51,087,933 2,6201843_B_3 Shiras MI 41 1 141 67,829,244 1,654471866_B_5 Wyandotte MI 24 1 3 1,197,065 501866_B_7 Wyandotte MI 24 1 3 1,148,547 481866_B_8 Wyandotte MI 24 1 3 1,273,346 531891_B_1 Syl Laskin MN 55 1 20 10,946,407 1991891_B_2 Syl Laskin MN 55 1 20 10,946,407 1991893_B_1 Clay Boswell MN 69 1 51 28,426,438 4121893_B_2 Clay Boswell MN 69 1 51 27,994,647 4061893_B_3 Clay Boswell MN 351 3 305 209,904,664 5991893_B_4 Clay Boswell MN 525 3 305 259,254,414 4941904_B_3 Black Dog MN 94 1 15 9,442,803 1001904_B_4 Black Dog MN 165 1 15 11,307,091 691915_B_1 Allen S King MN 610 3 109 98,379,962 1611943_B_2 Hoot Lake MN 60 1 31 16,991,480 2841943_B_3 Hoot Lake MN 84 1 31 19,334,908 2301961_B_NEPP Austin Northeast MN 29 1 10 4,487,238 1531979_B_1 Hibbing MN 10 1 14 3,643,086 3571979_B_2 Hibbing MN 10 1 14 3,643,086 3571979_B_3 Hibbing MN 10 1 14 3,585,412 3522008_B_1 Silver Lake MN 9 1 43 12,680,825 1,3642008_B_2 Silver Lake MN 14 1 43 14,336,096 1,0102008_B_3 Silver Lake MN 24 1 43 16,834,510 6932008_B_4 Silver Lake MN 59 1 43 23,408,712 3952018_B_7 Virginia MN 10 1 6 1,757,260 1812018_B_9 Virginia MN 10 1 6 1,733,461 1792022_B_3 Willmar MN 20 1 12 4,429,040 2172049_B_4 Jack Watson MS 230 1 1 1,059,090 52049_B_5 Jack Watson MS 476 2 26 22,151,655 472062_B_H1 Henderson MS 11 1 2 599,246 542062_B_H3 Henderson MS 18 1 2 715,923 402076_B_1 Asbury MO 213 3 141 76,776,545 360482079_B_5A Hawthorn MO 563 2 39 40,971,852 732080_B_1 Montrose MO 170 2 59 36,622,937 2152080_B_2 Montrose MO 164 2 59 36,044,913 2202080_B_3 Montrose MO 176 2 59 36,984,154 2102094_B_1 Sibley MO 54 1 12 6,050,087 1122094_B_2 Sibley MO 54 1 12 5,930,500 1102094_B_3 Sibley MO 401 2 41 34,896,137 872098_B_5 Lake Road MO 14 1 3 1,202,124 832098_B_6 Lake Road MO 97 1 3 2,454,909 252103_B_1 Labadie MO 597 2 88 86,771,052 1452103_B_2 Labadie MO 594 2 88 84,880,112 1432103_B_3 Labadie MO 612 2 88 85,776,583 1402103_B_4 Labadie MO 612 2 88 85,099,994 1392104_B_1 Meramec MO 122 2 63 27,322,272 2242104_B_2 Meramec MO 120 2 63 25,433,774 2122104_B_3 Meramec MO 269 2 63 49,292,459 1832104_B_4 Meramec MO 347 3 143 95,551,056 2752107_B_1 Sioux MO 497 2 53 36,171,805 732107_B_2 Sioux MO 497 2 53 36,171,805 732123_B_6 Columbia MO 25 1 11 4,577,245 1872123_B_7 Columbia MO 25 1 11 4,001,683 1632132_B_1 Blue Valley MO 21 1 10 3,657,281 1742132_B_2 Blue Valley MO 21 1 10 3,657,281 1742132_B_3 Blue Valley MO 51 1 10 5,626,006 1102144_B_4 Marshall MO 5 1 16 3,494,867 7132144_B_5 Marshall MO 16 1 16 5,547,190 3472161_B_1 James River Power Station MO 21 1 46 17,279,505 8232161_B_2 James River Power Station MO 21 1 46 17,279,505 8232161_B_3 James River Power Station MO 41 1 46 22,905,772 5592161_B_4 James River Power Station MO 56 1 46 24,300,389 434492161_B_5 James River Power Station MO 97 2 120 55,733,835 5752167_B_1 New Madrid MO 580 2 41 38,953,400 672167_B_2 New Madrid MO 580 2 41 39,162,023 682168_B_MB1 Thomas Hill MO 175 1 11 9,239,564 532168_B_MB2 Thomas Hill MO 275 1 11 10,753,692 392168_B_MB3 Thomas Hill MO 670 2 44 35,713,178 532169_B_1 Chamois MO 17 1 36 12,968,063 7632169_B_2 Chamois MO 49 1 36 18,027,617 3682171_B_1 Missouri City MO 19 1 17 6,359,232 3352171_B_2 Missouri City MO 19 1 17 6,359,232 3352187_B_2 J E Corette Plant MT 158 1 150 117,905,332 7462240_B_6 Lon Wright NE 15 1 3 877,700 592240_B_7 Lon Wright NE 20 1 3 1,018,837 512240_B_8 Lon Wright NE 85 1 3 1,624,218 192277_B_1 Sheldon NE 105 1 12 8,230,098 782277_B_2 Sheldon NE 120 1 12 8,683,755 722291_B_1 North Omaha NE 79 1 15 9,059,759 1152291_B_2 North Omaha NE 111 1 15 10,288,311 932291_B_3 North Omaha NE 111 1 15 10,236,486 922291_B_4 North Omaha NE 138 2 31 14,642,191 1062291_B_5 North Omaha NE 224 2 31 20,708,445 922324_B_1 Reid Gardner NV 110 1 3 1,972,018 182324_B_2 Reid Gardner NV 110 1 3 1,993,430 182324_B_3 Reid Gardner NV 110 1 3 2,016,780 182324_B_4 Reid Gardner NV 225 1 3 2,524,264 112364_B_1 Merrimack NH 113 1 30 20,672,673 1842364_B_2 Merrimack NH 320 2 60 43,651,526 1362367_B_4 Schiller NH 48 1 3 1,393,557 292367_B_6 Schiller NH 48 1 3 1,344,635 282378_B_1 B L England NJ 129 2 94 52,365,737 406502378_B_2 B L England NJ 155 2 94 55,367,158 3572384_B_8 Deepwater NJ 80 1 9 5,464,709 682403_B_2 PSEG Hudson Generating Station NJ 608 4 43 28,685,847 472408_B_1 PSEG Mercer Generating Station NJ 324 2 20 14,828,819 462408_B_2 PSEG Mercer Generating Station NJ 324 2 20 14,394,239 442434_B_10 Howard Down NJ 23 1 22 9,263,690 4032442_B_1 Four Corners NM 170 1 4 2,915,795 172442_B_2 Four Corners NM 170 1 4 2,923,662 172442_B_3 Four Corners NM 220 1 4 3,300,614 152442_B_4 Four Corners NM 760 4 65 48,280,480 642442_B_5 Four Corners NM 760 4 65 48,390,171 642451_B_1 San Juan NM 322 2 20 11,031,400 342451_B_2 San Juan NM 320 2 20 11,210,066 352451_B_3 San Juan NM 495 3 38 25,969,488 522451_B_4 San Juan NM 506 3 38 25,016,173 492468_G_5 Raton NM 7 1 21 5,429,391 7872480_B_3 Danskammer Generating Station NY133 1 13 9,015,718 682480_B_4 Danskammer Generating Station NY236 2 33 21,202,511 902526_B_11 AES Westover NY22 1 3 1,274,492 582526_B_12 AES Westover NY22 1 3 1,289,755 592526_B_13 AES Westover NY84 1 3 2,031,559 242527_B_6 AES Greenidge LLCNY 106 1 4 2,599,972 252535_B_1 AES Cayuga NY152 1 14 10,586,859 702535_B_2 AES Cayuga NY153 1 14 10,609,438 692549_B_67 C R Huntley Generating Station NY 190 2 9 5,176,646 272549_B_68 C R Huntley Generating Station NY 190 2 9 5,176,646 272554_B_1 Dunkirk Generating Station NY 75 1 7 3,811,141 512554_B_2 Dunkirk Generating Station NY 75 1 7 3,833,477 512554_B_3 Dunkirk Generating Station NY 185 2 33 13,407,977 722554_B_4 Dunkirk Generating Station NY 185 2 33 13,487,072 73512682_B_10 S A Carlson NY 15 1 19 5,898,034 3932682_B_12 S A Carlson NY 15 1 19 5,960,664 3972682_B_9 S A Carlson NY 15 1 19 5,960,664 3972706_B_1 Asheville NC 191 1 53 42,245,167 2212706_B_2 Asheville NC 185 1 53 41,997,560 2272708_B_5 Cape Fear NC 144 1 67 48,101,001 3342708_B_6 Cape Fear NC 172 1 67 52,415,896 3052709_B_1 Lee NC 74 1 85 49,597,140 6702709_B_2 Lee NC 77 1 85 49,400,739 6422709_B_3 Lee NC 248 3 336 175,013,921 7062712_B_1 Roxboro NC 369 4 318 165,574,308 4492712_B_2 Roxboro NC 671 5 501 358,153,400 5342712_B_3A Roxboro NC 353 4 318 179,209,965 5082712_B_3B Roxboro NC 353 4 318 164,614,623 4672712_B_4A Roxboro NC 349 4 318 192,495,589 5522712_B_4B Roxboro NC 349 4 318 180,621,857 5182713_B_1 L V Sutton NC 93 2 333 159,333,256 1,7132713_B_2 L V Sutton NC 102 2 333 157,221,358 1,5412713_B_3 L V Sutton NC 403 4 767 480,939,460 1,1932716_B_1 W H Weatherspoon NC 481 119 60,915,952 1,2692716_B_2 W H Weatherspoon NC 491 119 61,084,751 1,2472716_B_3 W H Weatherspoon NC 76 1 119 69,786,937 9182718_B_1 G G Allen NC 162 1 15 11,286,661 702718_B_2 G G Allen NC 162 1 15 11,275,688 702718_B_3 G G Allen NC 260 1 15 13,258,122 512718_B_4 G G Allen NC 275 1 15 13,456,826 492718_B_5 G G Allen NC 265 1 15 13,399,377 512720_B_5 Buck NC 38 1 10 4,763,840 1272720_B_6 Buck NC 38 1 10 4,763,840 1272720_B_7 Buck NC 38 1 10 4,763,840 125522720_B_8 Buck NC 128 1 10 6,775,198 532720_B_9 Buck NC 128 1 10 6,799,947 532721_B_5 Cliffside NC 550 2 126 78,126,677 1422721_B_6 Cliffside NC 800 3 267 156,413,590 1962723_B_1 Dan River NC 67 1 1 592,542 92723_B_2 Dan River NC 67 1 1 586,647 92723_B_3 Dan River NC 142 2 2 965,276 72727_B_1 Marshall NC 378 2 85 54,785,142 1452727_B_2 Marshall NC 378 2 85 54,832,904 1452727_B_3 Marshall NC 657 2 85 58,667,715 892727_B_4 Marshall NC 657 2 85 58,648,369 892732_B_10 Riverbend NC 133 1 8 5,849,602 442732_B_7 Riverbend NC 94 1 8 5,226,437 562732_B_8 Riverbend NC 94 1 8 5,276,288 562732_B_9 Riverbend NC 133 1 8 5,828,717 442790_B_B1 R M Heskett ND 29 1 5 2,173,851 742790_B_B2 R M Heskett ND 76 1 5 3,036,810 402817_B_1 Leland Olds ND 221 1 26 23,149,954 1052817_B_2 Leland Olds ND 448 2 59 50,234,609 1122823_B_B1 Milton R Young ND 250 1 23 21,246,210 852823_B_B2 Milton R Young ND 455 2 52 44,411,133 982824_B_1 Stanton ND 130 1 26 18,738,173 1442824_B_10 Stanton ND 57 1 26 13,452,251 2342828_B_1 Cardinal OH 600 3 58 44,899,302 752828_B_2 Cardinal OH 600 3 58 46,258,050 772828_B_3 Cardinal OH 630 3 58 49,434,180 782830_B_1 Walter C Beckjord OH 94 1 7 4,025,382 432830_B_2 Walter C Beckjord OH 94 1 7 3,957,346 422830_B_3 Walter C Beckjord OH 128 1 7 4,404,241 342830_B_4 Walter C Beckjord OH 150 1 7 4,620,484 31532830_B_5 Walter C Beckjord OH 238 1 7 5,566,075 232830_B_6 Walter C Beckjord OH 414 2 39 13,252,021 322832_B_6 Miami Fort OH 163 2 31 15,320,273 942832_B_7 Miami Fort OH 500 2 31 26,978,826 542832_B_8 Miami Fort OH 500 2 31 26,795,622 542835_B_7 Ashtabula OH 244 3 147 73,712,911 3022836_B_10 Avon Lake OH 96 2 94 49,628,104 5172836_B_12 Avon Lake OH 640 4 251 192,073,460 3002837_B_1 Eastlake OH 132 2 121 68,778,521 5212837_B_2 Eastlake OH 132 2 121 68,275,329 5172837_B_3 Eastlake OH 132 2 121 67,409,064 5112837_B_4 Eastlake OH 240 3 187 98,897,850 4122837_B_5 Eastlake OH 597 3 187 146,553,511 2452838_B_18 Lake Shore OH 245 2 110 81,148,527 3312840_B_3 Conesville OH 165 2 17 5,179,593 312840_B_4 Conesville OH 780 3 36 34,479,228 442840_B_5 Conesville OH 375 2 17 13,898,446 372840_B_6 Conesville OH 375 2 17 13,806,685 372843_B_9 Picway OH 95 1 2 1,213,631 132848_B_H-1 O H Hutchings OH 58 1 3 1,541,919 272848_B_H-2 O H Hutchings OH 55 1 3 1,489,428 272848_B_H-3 O H Hutchings OH 63 1 3 1,528,214 242848_B_H-4 O H Hutchings OH 63 1 3 1,503,725 242848_B_H-5 O H Hutchings OH 63 1 3 1,575,322 252848_B_H-6 O H Hutchings OH 63 1 3 1,578,597 252850_B_1 J M Stuart OH 597 2 33 34,998,663 592850_B_2 J M Stuart OH 597 2 33 34,359,197 582850_B_3 J M Stuart OH 597 2 33 33,709,140 562850_B_4 J M Stuart OH 597 2 33 34,791,509 582861_B_1 Niles OH 108 1 16 10,610,699 98542861_B_2 Niles OH 108 1 16 10,537,680 982864_B_7 R E Burger OH 156 1 1 1,036,633 72864_B_8 R E Burger OH 156 1 1 1,058,515 72866_B_1 W H Sammis OH 180 1 12 9,298,987 522866_B_2 W H Sammis OH 180 1 12 9,339,857 522866_B_3 W H Sammis OH 180 1 12 9,257,816 512866_B_4 W H Sammis OH 180 1 12 9,232,966 512866_B_5 W H Sammis OH 300 2 30 18,766,521 632866_B_6 W H Sammis OH 600 4 69 46,052,387 772866_B_7 W H Sammis OH 600 4 69 46,307,383 772872_B_1 Muskingum River OH 190 1 4 3,481,788 182872_B_2 Muskingum River OH 190 1 4 3,456,143 182872_B_3 Muskingum River OH 205 1 4 3,526,616 172872_B_4 Muskingum River OH 205 1 4 3,427,273 172872_B_5 Muskingum River OH 585 2 18 15,822,798 272876_B_1 Kyger Creek OH 217 1 17 13,759,604 632876_B_2 Kyger Creek OH 217 1 17 13,822,283 642876_B_3 Kyger Creek OH 217 1 17 13,822,283 642876_B_4 Kyger Creek OH 217 1 17 13,874,156 642876_B_5 Kyger Creek OH 217 1 17 13,801,443 642878_B_1 Bay Shore OH 136 2 29 15,670,335 1152878_B_2 Bay Shore OH 138 2 29 16,166,545 1172878_B_3 Bay Shore OH 142 2 29 16,107,455 1132878_B_4 Bay Shore OH 215 2 29 18,700,991 872908_G_10 Lake Road OH 25 1 45 17,869,176 7152908_G_11 Lake Road OH 85 2 110 47,569,837 5602908_G_8 Lake Road OH 25 1 45 17,869,176 7152908_G_9 Lake Road OH 25 1 45 17,869,176 7152914_G_3 Dover OH 8 1 13 3,409,244 4262914_B_4 Dover OH 15 1 13 4,595,500 302552917_B_8 Hamilton OH 33 1 4 1,882,521 572917_B_9 Hamilton OH 51 1 4 2,128,420 422935_B_10 Orrville OH 13 1 20 6,488,346 5032935_B_11 Orrville OH 13 1 20 6,488,346 5032935_B_12 Orrville OH 30 1 20 7,899,993 2662935_B_13 Orrville OH 23 1 20 7,178,704 3122936_B_3 Painesville OH 11 1 58 16,231,647 1,5462936_B_4 Painesville OH 22 1 58 22,301,632 1,0372936_B_5 Painesville OH 22 1 58 20,902,148 9722937_B_4 Piqua OH 12 1 17 5,411,688 4362937_B_5 Piqua OH 12 1 17 5,296,940 4272937_B_6 Piqua OH 20 1 17 6,429,290 3212942_B_5 St Marys OH 6 1 26 6,320,195 1,0902942_B_6 St Marys OH 9 1 26 7,005,188 7782943_B_1 Shelby Municipal Light Plant OH 12 1 3 1,019,872 852943_B_2 Shelby Municipal Light Plant OH 12 1 3 1,041,965 872943_G_4 Shelby Municipal Light Plant OH 7 1 3 866,280 1242952_B_4 Muskogee OK 511 4 136 96,829,197 1902952_B_5 Muskogee OK 522 4 136 96,922,416 1862952_B_6 Muskogee OK 515 4 136 95,749,179 1862963_B_3313 Northeastern OK 450 3 57 44,740,461 992963_B_3314 Northeastern OK 450 3 57 44,806,701 1003098_B_1 Elrama PA 94 1 3 2,086,921 223098_B_2 Elrama PA 94 1 3 2,099,683 223098_B_3 Elrama PA 103 1 3 2,164,661 213098_B_4 Elrama PA 174 2 11 5,496,850 323113_B_1 Portland PA 157 1 10 7,355,187 473113_B_2 Portland PA 243 1 10 8,616,408 353115_B_1 Titus PA 81 1 11 6,152,979 763115_B_2 Titus PA 81 1 11 6,188,668 76563115_B_3 Titus PA 81 1 11 6,164,913 763118_B_1 Conemaugh PA 850 3 44 28,478,143 343118_B_2 Conemaugh PA 850 3 44 28,478,143 343122_B_1 Homer City Station PA 620 2 10 9,077,095 153122_B_2 Homer City Station PA 614 2 10 8,978,074 153122_B_3 Homer City Station PA 650 2 10 9,207,237 143130_B_1 Seward PA 261 1 2 1,629,448 63130_B_2 Seward PA 261 1 2 1,668,097 63131_B_1 Shawville PA 122 1 10 7,200,797 593131_B_2 Shawville PA 125 1 10 7,294,959 583131_B_3 Shawville PA 175 1 10 8,071,310 463131_B_4 Shawville PA 175 1 10 8,071,310 463136_B_1 Keystone PA 850 3 19 16,645,580 203136_B_2 Keystone PA 850 3 19 16,488,634 193138_B_3 New Castle PA 94 1 3 1,719,550 183138_B_4 New Castle PA 98 1 3 1,670,431 173138_B_5 New Castle PA 134 1 3 1,966,212 153140_B_1 PPL Brunner Island PA 344 2 7 4,613,100 133140_B_2 PPL Brunner Island PA 397 2 7 5,127,900 133140_B_3 PPL Brunner Island PA 754 3 34 29,273,420 393149_B_1 PPL Montour PA 750 3 99 78,561,631 1053149_B_2 PPL Montour PA 750 3 99 78,561,631 1053152_B_1A Sunbury Generation LP PA 40 1 26 12,190,368 3093152_B_1B Sunbury Generation LP PA 40 1 26 12,190,368 3093152_B_2A Sunbury Generation LP PA 40 1 26 12,190,368 3093152_B_2B Sunbury Generation LP PA 40 1 26 12,190,368 3093152_B_3 Sunbury Generation LP PA 87 1 26 16,356,969 1883152_B_4 Sunbury Generation LP PA 128 1 26 18,917,854 1483161_B_2 Eddystone Generating Station PA 3093 13 7,788,797 253178_B_1 Armstrong Power Station PA 172 1 11 8,120,940 47573178_B_2 Armstrong Power Station PA 171 1 11 8,105,917 473179_B_1 Hatfields Ferry Power Station PA 530 2 8 7,227,186 143179_B_2 Hatfields Ferry Power Station PA 530 2 8 7,194,169 143179_B_3 Hatfields Ferry Power Station PA 530 2 8 7,304,351 143181_B_33 Mitchell Power Station PA 277 3 27 11,206,077 403251_B_1 H B Robinson SC 176 1 87 66,202,863 3763264_B_1 W S Lee SC 100 1 1 878,755 93264_B_2 W S Lee SC 100 1 1 876,154 93264_B_3 W S Lee SC 170 1 1 1,039,925 63280_B_CAN1 Canadys Steam SC 105 2 210 94,419,328 8993280_B_CAN2 Canadys Steam SC 116 2 210 98,698,195 8513280_B_CAN3 Canadys Steam SC 175 2 210 125,031,058 7143287_B_MCM1 McMeekin SC 125 1 71 47,542,812 3803287_B_MCM2 McMeekin SC 125 1 71 48,485,566 3883295_B_URQ3 Urquhart SC 94 2 107 34,257,609 3643297_B_WAT1 Wateree SC 350 2 200 149,254,789 4263297_B_WAT2 Wateree SC 350 2 200 147,815,608 4223298_B_WIL1 Williams SC 615 2 259 213,418,201 3473317_B_1 Dolphus M Grainger SC 85 1 158 94,743,575 1,1153317_B_2 Dolphus M Grainger SC 85 1 158 95,251,225 1,1213319_B_3 Jefferies SC 153 1 99 74,184,083 4853319_B_4 Jefferies SC 153 1 99 73,960,402 4833325_B_1 Ben French SD 22 1 108 40,426,126 1,8723393_B_1 Allen Steam Plant TN 245 2 33 21,938,571 903393_B_2 Allen Steam Plant TN 245 2 33 21,938,571 903393_B_3 Allen Steam Plant TN 245 2 33 21,938,571 903396_B_1 Bull Run TN 881 3 204 205,971,347 2343399_B_1 Cumberland TN 1,232 3 81 80,248,498 653399_B_2 Cumberland TN 1,233 3 81 80,283,958 653403_B_1 Gallatin TN 222 1 2 1,928,621 9583403_B_2 Gallatin TN 222 1 2 1,928,621 93403_B_3 Gallatin TN 260 1 2 2,058,185 83403_B_4 Gallatin TN 260 1 2 2,058,185 83405_B_1 John Sevier TN 176 2 139 78,136,455 4443405_B_2 John Sevier TN 176 2 139 78,136,455 4443405_B_3 John Sevier TN 176 2 139 78,136,455 4443405_B_4 John Sevier TN 176 2 139 78,136,455 4443406_B_1 Johnsonville TN 106 1 19 12,724,426 1203406_B_10 Johnsonville TN 141 1 19 13,566,786 963406_B_2 Johnsonville TN 106 1 19 12,724,426 1203406_B_3 Johnsonville TN 106 1 19 12,724,426 1203406_B_4 Johnsonville TN 106 1 19 12,724,426 1203406_B_5 Johnsonville TN 106 1 19 12,342,977 1163406_B_6 Johnsonville TN 106 1 19 12,342,977 1163406_B_7 Johnsonville TN 141 1 19 13,566,786 963406_B_8 Johnsonville TN 141 1 19 13,566,786 963406_B_9 Johnsonville TN 141 1 19 13,566,786 963407_B_1 Kingston TN 134 2 97 36,622,679 2733407_B_2 Kingston TN 134 2 97 36,622,679 2733407_B_3 Kingston TN 134 2 97 36,622,679 2733407_B_4 Kingston TN 134 2 97 36,622,679 2733407_B_5 Kingston TN 175 2 97 51,649,364 2953407_B_6 Kingston TN 175 2 97 51,649,364 2953407_B_7 Kingston TN 175 2 97 51,649,364 2953407_B_8 Kingston TN 175 2 97 51,649,364 2953407_B_9 Kingston TN 175 2 97 51,649,364 2953470_B_WAP5 W A Parish TX 645 3 6 2,686,937 43470_B_WAP6 W A Parish TX 650 3 6 2,974,589 53470_B_WAP7 W A Parish TX 565 2 1 1,132,402 23470_B_WAP8 W A Parish TX 600 2 1 1,192,947 2593497_B_1 Big Brown TX 575 2 13 5,824,349 103497_B_2 Big Brown TX 575 2 13 5,447,670 93644_B_1 Carbon UT 67 1 7 3,779,914 563644_B_2 Carbon UT 105 2 67 27,882,639 2663775_B_1 Clinch River VA 235 3 164 88,926,102 3783775_B_2 Clinch River VA 235 3 164 89,731,011 3823775_B_3 Clinch River VA 235 3 164 88,097,986 3753776_B_51 Glen Lyn VA 45 1 17 8,772,437 1953776_B_52 Glen Lyn VA 45 1 17 8,772,437 1953776_B_6 Glen Lyn VA 235 2 49 32,250,863 1373788_B_1 Potomac River VA 88 1 10 6,569,511 753788_B_2 Potomac River VA 88 1 10 6,137,038 703788_B_3 Potomac River VA 102 1 10 6,137,038 603788_B_4 Potomac River VA 102 1 10 6,195,082 613788_B_5 Potomac River VA 102 1 10 6,252,233 613796_B_3 Bremo Bluff VA 71 1 13 7,856,735 1113796_B_4 Bremo Bluff VA 156 1 13 9,809,996 633797_B_3 Chesterfield VA 100 1 5 3,093,281 313797_B_4 Chesterfield VA 166 2 55 25,405,927 1533797_B_5 Chesterfield VA 310 3 142 88,732,353 2863797_B_6 Chesterfield VA 658 4 229 159,656,669 2433803_B_1 Chesapeake VA 111 2 116 56,744,698 5113803_B_2 Chesapeake VA 111 2 116 59,262,250 5343803_B_3 Chesapeake VA 156 2 116 66,253,664 4253803_B_4 Chesapeake VA 217 3 228 109,196,341 5033809_B_1 Yorktown VA 159 2 120 61,769,959 3883809_B_2 Yorktown VA 164 2 120 63,285,654 3863845_B_BW21 Transalta Centralia Generation WA 703 2 158 162,043,992 2313845_B_BW22 Transalta Centralia Generation WA 703 2 158 162,043,992 2313935_B_1 John E Amos WV 800 3 33 25,455,486 32603935_B_2 John E Amos WV 800 3 33 25,525,621 323935_B_3 John E Amos WV 1,300 4 76 54,359,572 423936_B_1 Kanawha River WV 205 2 21 10,004,729 493936_B_2 Kanawha River WV 205 2 21 9,969,552 493938_B_11 Philip Sporn WV 150 2 28 16,300,090 1093938_B_21 Philip Sporn WV 150 2 28 16,052,044 1073938_B_31 Philip Sporn WV 150 2 28 15,982,920 1073938_B_41 Philip Sporn WV 150 2 28 15,866,234 1063938_B_51 Philip Sporn WV 450 2 28 25,116,859 563942_B_1 Albright WV 73 2 20 5,946,953 813942_B_2 Albright WV 73 2 20 5,946,953 813942_B_3 Albright WV 137 2 20 10,607,955 773943_B_1 Fort Martin Power Station WV 552 2 22 20,856,287 383943_B_2 Fort Martin Power Station WV 555 2 22 20,871,288 383944_B_1 Harrison Power Station WV 652 5 89 62,842,593 963944_B_2 Harrison Power Station WV 642 5 89 62,955,955 983944_B_3 Harrison Power Station WV 651 5 89 62,590,340 963945_B_7 Rivesville WV 46 2 32 12,443,114 2713945_B_8 Rivesville WV 91 2 32 16,219,574 1783946_B_1 Willow Island WV 54 1 3 1,914,114 353946_B_2 Willow Island WV 181 2 24 16,815,933 933947_B_1 Kammer WV 210 1 1 488,386 23947_B_2 Kammer WV 210 1 1 488,025 23947_B_3 Kammer WV 210 1 1 488,025 23948_B_1 Mitchell WV 800 3 5 4,385,284 53948_B_2 Mitchell WV 800 3 5 4,375,301 53954_B_1 Mt Storm WV 524 4 152 85,613,330 1633954_B_2 Mt Storm WV 524 4 152 86,726,251 1663954_B_3 Mt Storm WV 521 3 92 74,902,071 1443992_B_7 Blount Street WI 22 1 29 11,189,692 500613992_B_8 Blount Street WI 49 1 29 13,913,394 2843992_B_9 Blount Street WI 48 1 29 13,824,500 2874041_B_5 South Oak Creek WI 2612 45 30,655,617 1174041_B_6 South Oak Creek WI 2642 45 30,967,962 1174041_B_7 South Oak Creek WI 2982 45 33,064,085 1114041_B_8 South Oak Creek WI 3122 45 33,486,899 1074042_B_1 Valley WI 70 1 5 3,047,663 444042_B_2 Valley WI 70 1 5 3,047,663 444042_B_3 Valley WI 70 1 5 3,026,671 434042_B_4 Valley WI 70 1 5 3,026,671 434050_B_3 Edgewater WI 76 1 30 17,941,613 2364050_B_4 Edgewater WI 321 2 84 55,804,908 1744050_B_5 Edgewater WI 414 3 174 100,511,909 2434054_B_1 Nelson Dewey WI 107 2 58 29,322,978 2754054_B_2 Nelson Dewey WI 111 2 58 29,643,798 2674072_B_5 Pulliam WI 49 1 10 5,081,019 1054072_B_6 Pulliam WI 72 2 118 19,051,451 2664072_B_7 Pulliam WI 88 2 118 36,909,371 4204072_B_8 Pulliam WI 133 2 118 59,324,062 4454078_B_1 Weston WI 62 1 73 42,302,848 6824078_B_2 Weston WI 86 2 204 76,891,284 8944078_B_3 Weston WI 338 4 535 305,939,828 9054078_B_4 Weston WI 519 4 535 357,497,756 6894125_B_5 Manitowoc WI 2 1 28 3,801,699 2,5344125_B_6 Manitowoc WI 18 1 28 9,652,063 5364125_B_7 Manitowoc WI 18 1 28 9,262,060 5154125_B_8 Manitowoc WI 21 1 28 9,726,975 4724125_B_9 Manitowoc WI 30 1 28 11,236,889 3754127_B_5 Menasha WI 7 1 10 2,268,040 3294127_B_B23 Menasha WI 9 1 10 2,770,899 326624127_B_B24 Menasha WI 15 1 10 3,373,140 2334140_B_B1 Alma WI 18 1 57 19,767,691 1,1234140_B_B2 Alma WI 18 1 57 19,767,691 1,1234140_B_B3 Alma WI 21 1 57 21,221,307 1,0064140_B_B4 Alma WI 51 1 57 28,803,600 5654140_B_B5 Alma WI 77 1 57 33,564,993 4364143_B_1 Genoa WI 356 2 142 98,844,475 2774150_B_5 Neil Simpson WY 15 1 22 7,681,834 5264151_B_1 Osage WY 10 1 73 22,120,867 2,1904151_B_2 Osage WY 10 1 73 22,120,867 2,1904151_B_3 Osage WY 10 1 73 22,120,867 2,1904158_B_BW41 Dave Johnston WY 106 1 8 5,447,933 514158_B_BW42 Dave Johnston WY 106 1 8 5,440,496 514158_B_BW43 Dave Johnston WY 220 1 8 7,155,406 334158_B_BW44 Dave Johnston WY 330 1 8 8,291,718 254162_B_1 Naughton WY 160 1 36 27,629,118 1734162_B_2 Naughton WY 210 1 36 30,459,162 1454162_B_3 Naughton WY 330 3 186 95,198,954 2884259_B_1 Endicott Station MI 50 1 16 8,147,501 1634271_B_B1 John P Madgett WI 398 2 138 97,551,759 2454941_B_1 Navajo AZ 750 3 348 312,653,688 4174941_B_2 Navajo AZ 750 3 348 311,741,926 4164941_B_3 Navajo AZ 750 3 348 308,739,092 4126002_B_1 James H Miller Jr AL 684 2 73 72,453,897 1066002_B_2 James H Miller Jr AL 687 2 73 72,325,000 1056002_B_3 James H Miller Jr AL 687 2 73 72,389,499 1056002_B_4 James H Miller Jr AL 688 2 73 72,163,306 1056004_B_1 Pleasants Power Station WV 639 2 31 34,629,535 546004_B_2 Pleasants Power Station WV 639 2 31 34,511,038 546009_B_1 White Bluff AR 815 3 30 29,247,265 36636009_B_2 White Bluff AR 825 3 30 29,904,002 366016_B_1 Duck Creek IL 335 2 80 65,045,755 1946017_B_1 Newton IL 557 2 32 21,256,386 386017_B_2 Newton IL 569 2 32 21,218,914 376018_B_2 East Bend KY 600 3 81 60,069,860 1006019_B_1 W H Zimmer OH 1,300 4 129 110,317,488 856021_B_C1 Craig CO 428 3 62 43,725,334 1026021_B_C2 Craig CO 428 3 62 44,007,279 1036021_B_C3 Craig CO 418 3 62 43,820,042 1056030_B_1 Coal Creek ND 554 2 85 58,252,800 1056030_B_2 Coal Creek ND 560 2 85 78,618,531 1406031_B_2 Killen Station OH 615 2 36 32,401,966 536034_B_1 Belle River MI 698 4 115 57,929,531 836034_B_2 Belle River MI 698 4 115 65,882,626 946041_B_1 H L Spurlock KY 315 2 43 34,299,690 1096041_B_2 H L Spurlock KY 509 2 43 43,854,659 866041_B_3 H L Spurlock KY 268 2 43 31,686,751 1186041_B_4 H L Spurlock KY 268 2 43 30,443,356 1146052_B_1 Wansley GA 891 3 205 125,379,945 1416052_B_2 Wansley GA 892 3 205 125,632,090 1416055_B_2B1 Big Cajun 2 LA 580 2 3 2,561,145 46055_B_2B2 Big Cajun 2 LA 575 2 3 2,555,499 46055_B_2B3 Big Cajun 2 LA 588 2 3 2,531,971 46061_B_1 R D Morrow MS 180 1 8 6,731,374 376061_B_2 R D Morrow MS 180 1 8 6,804,328 386064_B_N1 Nearman Creek KS 229 2 36 19,542,070 856065_B_1 Iatan MO 651 2 23 23,906,085 376068_B_1 Jeffrey Energy Center KS 730 2 89 85,285,064 1176068_B_2 Jeffrey Energy Center KS 730 2 89 86,254,355 1186068_B_3 Jeffrey Energy Center KS 730 2 89 88,473,899 121646071_B_1 Trimble County KY 383 3 142 97,287,993 2546071_B_2&3 Trimble County KY 760 3 142 115,264,482 1526073_B_1 Victor J Daniel Jr MS 514 2 6 5,020,082 106073_B_2 Victor J Daniel Jr MS 514 2 6 5,000,070 106076_B_1 Colstrip MT 307 2 261 184,856,344 6026076_B_2 Colstrip MT 307 2 261 184,856,344 6026076_B_3 Colstrip MT 740 2 261 288,152,024 3896076_B_4 Colstrip MT 740 2 261 288,152,024 3896077_B_1 Gerald Gentleman NE 665 2 33 32,410,571 496077_B_2 Gerald Gentleman NE 700 2 33 31,478,432 456082_B_1 AES Somerset LLCNY 681 6 278 170,834,291 2516085_B_14 R M Schahfer IN 431 2 36 31,648,586 736085_B_15 R M Schahfer IN 472 2 36 32,892,605 706085_B_17 R M Schahfer IN 361 2 36 29,462,210 826085_B_18 R M Schahfer IN 361 2 36 29,060,625 816089_B_B1 Lewis & Clark MT 52 1 19 10,381,544 1986090_B_1 Sherburne County MN 762 4 230 186,587,670 2456090_B_2 Sherburne County MN 752 4 230 181,960,628 2426090_B_3 Sherburne County MN 936 4 230 209,343,996 2246094_B_1 Bruce Mansfield PA 830 5 83 68,945,809 836094_B_2 Bruce Mansfield PA 830 5 83 68,639,498 836094_B_3 Bruce Mansfield PA 830 5 83 67,538,385 816095_B_1 Sooner OK 535 5 237 138,736,724 2596095_B_2 Sooner OK 540 5 237 148,708,188 2756096_B_1 Nebraska City NE 646 2 45 44,246,688 686096_B_2 Nebraska City NE 663 2 17 15,623,098 246098_B_1 Big Stone SD 470 2 75 63,989,316 1366101_B_BW91 Wyodak WY 335 3 207 123,430,969 3686106_B_1SG Boardman OR 585 3 292 156,464,937 2676113_B_1 Gibson IN 630 3 73 64,635,948 103656113_B_2 Gibson IN 628 3 73 64,690,650 1036113_B_3 Gibson IN 628 3 73 64,157,149 1026113_B_4 Gibson IN 622 3 73 64,544,530 1046113_B_5 Gibson IN 620 3 73 65,515,933 1066124_B_1 McIntosh GA 157 2 174 98,023,860 6266136_B_1 Gibbons Creek TX 462 2 8 6,109,161 136137_B_1 A B Brown IN 245 3 51 27,652,839 1136137_B_2 A B Brown IN 245 3 51 27,652,839 1136138_B_1 Flint Creek AR 528 6 303 183,956,789 3486139_B_1 Welsh TX 528 2 26 23,265,057 446139_B_2 Welsh TX 528 2 26 22,953,307 436139_B_3 Welsh TX 528 2 26 22,977,196 446146_B_1 Martin Lake TX 750 4 16 13,579,347 186146_B_2 Martin Lake TX 750 4 16 13,422,881 186146_B_3 Martin Lake TX 750 4 16 13,196,821 186147_B_1 Monticello TX 565 2 27 25,810,168 466147_B_2 Monticello TX 565 2 27 25,648,477 456147_B_3 Monticello TX 750 3 41 37,072,040 496155_B_1 Rush Island MO 604 4 218 158,885,720 2636155_B_2 Rush Island MO 604 4 218 153,186,703 2546165_B_1 Hunter UT 430 2 94 81,186,634 1896165_B_2 Hunter UT 430 2 94 81,003,689 1886165_B_3 Hunter UT 460 2 94 83,041,697 1816166_B_MB1 Rockport IN 1,300 4 142 138,145,250 1066166_B_MB2 Rockport IN 1,300 4 142 138,981,337 1076170_B_1 Pleasant Prairie WI 617 3 72 55,255,225 906170_B_2 Pleasant Prairie WI 617 3 72 55,822,411 906177_B_U1B Coronado AZ 395 2 132 108,847,521 2766177_B_U2B Coronado AZ 390 2 132 105,111,801 2706178_B_1 Coleto Creek TX 632 4 26 21,145,534 33666179_B_1 Fayette Power Project TX 598 5 98 65,108,619 1096179_B_2 Fayette Power Project TX 598 5 98 64,482,723 1086179_B_3 Fayette Power Project TX 445 4 64 44,478,896 1006180_B_OG1 Oak Grove TX 800 6 190 85,241,342 1076180_B_OG2 Oak Grove TX 800 6 190 85,241,342 1076181_B_1 J T Deely TX 385 2 30 27,795,726 726181_B_2 J T Deely TX 385 2 30 27,756,673 726183_B_SM-1 San Miguel TX 391 3 62 45,994,741 1186190_B_2 Rodemacher LA 523 2 27 25,318,899 486190_B_3A Rodemacher LA 330 1 5 5,011,157 156190_B_3B Rodemacher LA 330 1 5 5,011,157 156193_B_061B Harrington TX 347 4 42 22,996,183 666193_B_062B Harrington TX 347 4 42 24,424,959 706193_B_063B Harrington TX 347 4 42 24,863,255 726194_B_171B Tolk TX 535 2 24 21,681,861 416194_B_172B Tolk TX 545 2 24 21,315,741 396195_B_1 Southwest Power Station MO 178 3 224 115,261,948 6486204_B_1 Laramie River Station WY 565 4 154 86,961,102 1546204_B_2 Laramie River Station WY 570 4 154 83,331,016 1466204_B_3 Laramie River Station WY 570 4 154 92,413,957 1626213_B_1SG1 Merom IN 507 2 65 62,606,265 1236213_B_2SG1 Merom IN 493 2 65 64,220,141 1306225_B_1 Jasper 2 IN 14 1 3 866,561 626238_B_1A Pearl Station IL 22 1 6 2,112,513 966248_B_1 Pawnee CO 505 2 13 8,921,462 186249_B_1 Winyah SC 295 1 130 121,732,828 4136249_B_2 Winyah SC 295 1 130 122,722,703 4166249_B_3 Winyah SC 295 1 130 121,333,096 4116249_B_4 Winyah SC 270 1 130 120,256,266 4456250_B_1A Mayo NC 371 4 320 194,458,700 524676250_B_1B Mayo NC 371 4 320 194,458,700 5246254_B_1 Ottumwa IA 673 2 116 87,704,788 1306257_B_1 Scherer GA 837 3 233 241,767,423 2896257_B_2 Scherer GA 843 3 233 243,015,931 2886257_B_3 Scherer GA 875 3 233 247,595,035 2836257_B_4 Scherer GA 850 3 233 243,874,806 2876264_B_1 Mountaineer WV 1,300 3 50 51,914,394 406469_B_B1 Antelope Valley ND 450 2 59 50,262,299 1126469_B_B2 Antelope Valley ND 450 2 59 50,577,883 1126481_B_1SGA Intermountain Power Project UT 900 3 233 158,299,880 1766481_B_2SGA Intermountain Power Project UT 900 3 233 158,299,880 1766639_B_G1 R D Green KY 231 2 8 5,747,905 256639_B_G2 R D Green KY 233 2 8 5,770,269 256641_B_1 Independence AR 836 4 47 37,254,469 456641_B_2 Independence AR 842 4 47 37,171,856 446648_B_4 Sandow TX 545 4 107 74,584,612 1376664_B_101 Louisa IA 745 2 59 61,830,763 836705_B_1 Warrick IN 136 2 17 9,509,125 706705_B_2 Warrick IN 136 2 17 9,523,228 706705_B_3 Warrick IN 136 2 17 9,537,272 706705_B_4 Warrick IN 300 2 17 12,924,387 436761_B_101 Rawhide CO 272 2 18 12,342,549 456768_B_1 Sikeston Power Station MO 233 2 36 23,625,426 1016772_B_1 Hugo OK 440 2 67 58,910,578 1346823_B_W1 D B Wilson KY 420 2 49 36,972,967 887030_B_U1 Twin Oaks Power One TX 152 2 13 5,921,171 397030_B_U2 Twin Oaks Power One TX 153 2 13 6,858,395 457097_B_BLR1 J K Spruce TX 555 3 58 44,996,468 817097_B_BLR2 J K Spruce TX 750 3 58 48,312,157 647210_B_COP1 Cope SC 420 2 177 152,775,716 364687213_B_1 Clover VA 431 4 280 187,989,514 4367213_B_2 Clover VA 434 5 431 217,508,623 5017242_G_1CA Polk FL 123 1 1 689,955 67242_G_1CT Polk FL 132 1 1 708,828 57286_B_1 Richard Gorsuch OH 50 15 2,652,682 537286_B_2 Richard Gorsuch OH 50 15 2,652,682 537286_B_3 Richard Gorsuch OH 50 15 2,652,682 537286_B_4 Richard Gorsuch OH 50 15 2,652,682 537343_B_4 George Neal South IA 6322 94 100,888,536 1607504_B_2 Neil Simpson II WY 80 1 23 13,829,794 1737537_B_1A North Branch WV 37 1 10 4,456,718 1207537_B_1B North Branch WV 37 1 10 4,315,178 1177549_B_1 Milwaukee County WI 3 1 5 1,001,342 3037549_B_2 Milwaukee County WI 3 1 5 958,082 2907549_B_3 Milwaukee County WI 3 1 5 958,082 2907652_B_D-1 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 5337652_B_D-2 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 5337652_B_D-3 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 5337652_B_D-4 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 5337737_B_B001 Cogen South SC 90 1 82 50,925,685 5667790_B_1-1 Bonanza UT 468 5 75 40,737,592 877902_B_1 Pirkey TX 675 2 4 4,246,866 68023_B_1 Columbia WI 555 4 306 219,530,738 3968023_B_2 Columbia WI 559 4 306 214,992,053 3858042_B_1 Belews Creek NC 1,115 3 122 76,553,763 698042_B_2 Belews Creek NC 1,115 3 122 76,537,100 698066_B_BW71 Jim Bridger WY 530 2 3 2,411,220 58066_B_BW72 Jim Bridger WY 530 2 3 2,418,842 58066_B_BW73 Jim Bridger WY 530 2 3 2,404,606 58066_B_BW74 Jim Bridger WY 530 2 3 2,417,759 5698069_B_1 Huntington UT 445 2 68 63,247,668 1428069_B_2 Huntington UT 450 2 68 63,434,031 1418102_B_1 General James M Gavin OH 1,310 3 52 49,730,161 388102_B_2 General James M Gavin OH 1,300 3 52 49,430,685 388219_B_1 Ray D Nixon CO 208 2 130 91,347,020 4398222_B_B1 Coyote ND 427 2 59 50,345,130 1188223_B_1 Springerville AZ 400 2 170 137,893,456 3458223_B_2 Springerville AZ 400 2 170 137,336,825 3438223_B_3 Springerville AZ 400 2 170 142,795,380 3578223_B_4 Springerville AZ 400 2 170 131,249,797 3288224_B_1 North Valmy NV 254 3 420 246,905,695 9728224_B_2 North Valmy NV 268 3 420 262,664,147 9808226_B_1 Cheswick PA 580 3 30 23,108,254 4010002_B_CFB ACE Cogeneration Facility CA 101 1 55 36,115,023 35710003_B_BLR3 Trigen Colorado Energy CO 8 1 17 4,224,070 52110003_B_BLR4 Trigen Colorado Energy CO 8 1 17 4,224,070 52110003_B_BLR5 Trigen Colorado Energy CO 8 1 17 4,462,765 55110030_B_COGEN1 NRG Energy Center Dover DE16 1 41 13,762,699 86010043_B_B01 Logan Generating Plant NJ 219 3 7 3,257,942 1510071_B_1A Cogentrix Virginia Leasing Corporation VA 19 1 53 18,675,110 97310071_B_1B Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 93610071_B_1C Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 93610071_B_2A Cogentrix Virginia Leasing Corporation VA 19 1 53 18,675,110 97310071_B_2B Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 93610071_B_2C Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 93610075_B_1 Taconite Harbor Energy CenterMN 65 1 77 43,873,377 67510075_B_2 Taconite Harbor Energy CenterMN 67 1 77 44,056,543 65810075_B_3 Taconite Harbor Energy CenterMN 68 1 77 44,508,992 65510113_B_CFB1 John B Rich Memorial Power Station PA 40 1 22 10,166,547 25410113_B_CFB2 John B Rich Memorial Power Station PA 40 1 22 9,865,959 2477010143_B_ABB01 Colver Power Project PA 110 2 16 7,296,841 6610151_B_BLR1A Grant Town Power Plant WV 40 1 14 6,230,377 15610151_B_BLR1B Grant Town Power Plant WV 40 1 14 6,068,111 15210207_B_1 Hercules Missouri Chemical Works MO 6 1 3 668,369 11710207_B_2 Hercules Missouri Chemical Works MO 6 1 3 668,369 11710207_B_3 Hercules Missouri Chemical Works MO 6 1 3 668,369 11710333_B_1 Central Power & Lime FL 139 1 5 3,407,144 2510343_B_SG-101 Foster Wheeler Mt Carmel Cogen PA 43 1 22 10,975,235 25510367_B_CB1302 East Third Street Power PlantCA 20 1 4 1,397,893 7210368_B_CB1302 Loveridge Road Power Plant CA 19 1 3 1,250,255 6610369_B_CB1302 Wilbur West Power Plant CA 19 1 2 644,904 3410370_B_CB1302 Wilbur East Power Plant CA 19 1 3 1,043,072 5510371_B_CB1302 Nichols Road Power Plant CA 19 1 3 1,298,925 6810373_B_CB1302 Hanford CA 25 1 22 8,730,145 35210377_B_1A Cogentrix Hopewell VA 18 1 10 3,417,788 18810377_B_1B Cogentrix Hopewell VA 18 1 10 3,531,133 19410377_B_1C Cogentrix Hopewell VA 18 1 10 3,417,788 18810377_B_2A Cogentrix Hopewell VA 18 1 10 3,531,133 19410377_B_2B Cogentrix Hopewell VA 18 1 10 3,417,788 18810377_B_2C Cogentrix Hopewell VA 18 1 10 3,417,788 18810378_B_1A Primary Energy Southport NC18 1 173 59,585,090 3,34710378_B_1B Primary Energy Southport NC18 1 173 57,630,632 3,23810378_B_1C Primary Energy Southport NC 18 1 173 57,630,632 3,23810378_B_2A Primary Energy Southport NC18 1 173 59,585,090 3,34710378_B_2B Primary Energy Southport NC18 1 173 57,630,632 3,23810378_B_2C Primary Energy Southport NC 18 1 173 57,630,632 3,23810379_B_1A Primary Energy Roxboro NC 19 1 24 8,355,164 44710379_B_1B Primary Energy Roxboro NC 19 1 24 8,092,596 43310379_B_1C Primary Energy Roxboro NC 19 1 24 8,092,596 43310380_B_A BLR Elizabethtown Power LLC NC16 1 129 42,742,982 2,6717110380_B_B BLR Elizabethtown Power LLC NC16 1 129 42,742,982 2,67110382_B_UNIT1 Lumberton NC 16 1 118 39,366,830 2,46010382_B_UNIT2 Lumberton NC 16 1 118 39,366,830 2,46010384_B_1A Edgecombe GenCo NC 29 1 36 14,989,978 51910384_B_1B Edgecombe GenCo NC 29 1 36 14,534,809 50310384_B_2A Edgecombe GenCo NC 29 1 36 14,989,978 51910384_B_2B Edgecombe GenCo NC 29 1 36 14,534,809 50310464_B_E0001 Black River Generation NY 18 1 27 9,340,465 51010464_B_E0002 Black River Generation NY 18 1 27 8,971,022 49010464_B_E0003 Black River Generation NY 18 1 27 8,971,022 49010477_B_P1 Wisconsin Rapids Pulp Mill WI 11 1 80 22,287,032 1,99010477_B_P2 Wisconsin Rapids Pulp Mill WI 11 1 80 22,287,032 1,99010495_B_6 Rumford Cogeneration ME 43 1 24 11,293,272 26610495_B_7 Rumford Cogeneration ME 43 1 24 10,978,023 25810566_B_BOIL1 Chambers Cogeneration LP NJ 131 2 17 9,093,687 6910566_B_BOIL2 Chambers Cogeneration LP NJ 131 2 17 9,238,900 7110601_G_GEN1 BP Wilmington Calciner CA 29 1 3 1,039,284 3610603_B_031 Ebensburg Power PA 50 1 4 2,168,090 4410641_B_B1 Cambria Cogen PA 44 1 3 1,426,559 3210641_B_B2 Cambria Cogen PA 44 1 3 1,388,167 3210670_B_AAB001 AES DeepwaterTX 140 2 0 184,032 110671_B_1A AES Shady Point OK 80 13 1,973,180 2510671_B_1B AES Shady Point OK 80 13 1,965,567 2510671_B_2A AES Shady Point OK 80 13 1,973,180 2510671_B_2B AES Shady Point OK 80 13 1,965,567 2510672_B_CBA Cedar Bay Generating LP FL 83 1 20 11,321,540 13610672_B_CBB Cedar Bay Generating LP FL 83 1 20 11,679,195 14010672_B_CBC Cedar Bay Generating LP FL 83 1 20 11,679,195 14010675_B_A AES Thames CT 91 1 2615,600,819 17210675_B_B AES Thames CT 91 1 2615,682,088 1737210676_B_2AES Beaver Valley Partners BeaverV llPA 43 1 4 2,100,058 4910676_B_3AES Beaver Valley Partners BeaverV llPA 43 1 4 2,159,729 5010676_B_4AES Beaver Valley Partners BeaverV llPA 43 1 4 2,159,729 5010676_B_5AES Beaver Valley Partners BeaverV llPA 17 1 4 1,520,200 8910678_B_BLR1 AES Warrior Run Cogeneration FacilityMD 180 1 13 10,326,468 5710684_B_BLR25 Argus Cogen Plant CA 25 1 55 20,748,431 83010684_B_BLR26 Argus Cogen Plant CA 25 1 55 20,748,431 83010743_B_CFB1 Morgantown Energy Facility WV 25 1 12 4,578,240 18310743_B_CFB2 Morgantown Energy Facility WV 25 1 12 4,417,517 17710768_B_CFB Rio Bravo Jasmin CA 33 1 29 12,560,352 38110769_B_CFB Rio Bravo Poso CA 33 1 9 4,078,042 12410771_B_1 Hopewell VA 32 1 10 4,433,144 14110771_B_2 Hopewell VA 32 1 10 4,433,144 14110773_B_1 Altavista Power Station VA 32 1 7 3,025,687 9610773_B_2 Altavista Power Station VA 32 1 7 3,025,687 9610774_B_1 Southampton Power Station VA 63 1 21 11,523,948 18310774_B_2 Southampton Power Station VA 37 1 21 9,507,426 26010784_B_BLR1 Colstrip Energy LP MT 35 1 136 60,677,814 1,73410849_B_BLR1 Silver Bay Power MN 36 1 53 23,127,868 64210849_B_BLR2 Silver Bay Power MN 69 1 53 29,467,498 42750012_B_BLR4 Alloy Steam Station WV 38 1 16 6,888,251 18150030_B_1ANelson Industrial Steam and OperatingCLA 107 2 7 2,705,642 2550030_B_2ANelson Industrial Steam and OperatingCLA 106 2 7 2,679,457 2550039_B_1 Kline Township Cogen Facility PA 50 1 27 13,837,247 27750130_B_BLR1 G F Weaton Power Station PA 56 1 3 1,630,715 2950130_B_BLR2 G F Weaton Power Station PA 56 1 3 1,630,715 2950202_B_1 WPS Power Niagara NY 53 1 3 1,434,035 2750368_G_TG1 Cornell University Central Heat NY 1 1 3 268,863 26950368_G_TG2 Cornell University Central Heat NY 5 1 3 542,420 10250388_B_K1 Phillips 66 Carbon Plant CA 10 1 1 197,169 207350388_B_K2 Phillips 66 Carbon Plant CA 10 1 1 197,169 2050397_B_1PB035 P H Glatfelter PA 9 1 7 1,841,605 21250397_B_3PB033 P H Glatfelter PA 4 1 7 1,493,030 37350397_B_4PB034 P H Glatfelter PA 9 1 7 1,874,010 20850397_B_5PB036 P H Glatfelter PA 36 1 7 3,138,015 8750410_B_10 Chester Operations PA 36 1 0 165,409 550611_B_031 WPS Westwood Generation LLC PA 30 1 9 3,969,914 13250651_B_1 Trigen Syracuse Energy NY 11 1 8 2,211,538 19950651_B_2 Trigen Syracuse Energy NY 11 1 8 2,243,056 20250651_B_3 Trigen Syracuse Energy NY 11 1 8 2,243,056 20250651_B_4 Trigen Syracuse Energy NY 11 1 8 2,243,056 20250651_B_5 Trigen Syracuse Energy NY 11 1 8 2,243,056 20250651_G_GEN2 Trigen Syracuse Energy NY 11 1 8 2,211,538 20150776_B_BLR1 Panther Creek Energy Facility PA 42 1 22 10,108,238 24450776_B_BLR2 Panther Creek Energy Facility PA 42 1 22 10,224,344 24650806_B_PB4 Stone Container Florence Mill SC 75 1 122 69,382,961 92850835_B_1 TES Filer City Station MI 30 1 42 17,747,919 59250835_B_2 TES Filer City Station MI 30 1 42 17,141,107 57150879_B_BLR1 Wheelabrator Frackville Energy PA 45 1 21 10,414,793 23450888_B_BLR1 Northampton Generating Company PA 112 1 5 3,307,302 3050931_B_BLR1 Yellowstone Energy LP MT 28 1 149 65,987,299 2,40050931_B_BLR2 Yellowstone Energy LP MT 28 1 149 58,025,007 2,11050951_B_1 Sunnyside Cogen Associates UT51 1 15 7,903,915 15550974_B_UNIT 1 Scrubgrass Generating PA 431 8 3,993,426 9450974_B_UNIT 2 Scrubgrass Generating PA 431 8 3,881,950 9150976_B_AAB01 Indiantown Cogeneration LP FL330 2 4 3,323,473 1052007_B_BLR1 Mecklenburg Power Station VA 69 1 15 8,567,737 12452007_B_BLR2 Mecklenburg Power Station VA 69 1 15 8,567,737 12452071_B_5A Sandow 5 TX 300 2 32 23,260,335 7852071_B_5B Sandow 5 TX 300 2 32 23,260,335 787454035_B_BLR1 Westmoreland Roanoke Valley I NC 165 2 62 36,771,503 22354081_B_1A Cogentrix of Richmond VA 26 1 8 3,050,662 11654081_B_1B Cogentrix of Richmond VA 26 1 8 2,948,358 11254081_B_2A Cogentrix of Richmond VA 26 1 8 3,050,662 11654081_B_2B Cogentrix of Richmond VA 26 1 8 2,948,358 11254081_B_3A Cogentrix of Richmond VA 21 1 8 2,820,983 13254081_B_3B Cogentrix of Richmond VA 21 1 8 2,723,771 12854081_B_4A Cogentrix of Richmond VA 21 1 8 2,820,983 13254081_B_4B Cogentrix of Richmond VA 21 1 8 2,723,771 12854144_B_BRBR1 Piney Creek Project PA 33 1 16 6,808,383 20954224_B_GEN6 Franklin Heating Station MN 3 1 43 7,175,049 2,56354238_B_N64514 Port of Stockton District EnergyFac CA 22 1 3 997,963 4554238_B_N64516 Port of Stockton District EnergyFac CA 22 1 3 958,629 4454304_B_1A Birchwood Power VA 239 1 29 25,665,810 10754406_G_1 Capitol Heat and Power WI 1 1 28 2,967,700 3,29754406_G_2 Capitol Heat and Power WI 1 1 28 2,967,700 2,96854626_B_BL01 Mt Poso Cogeneration CA 52 1 18 9,385,483 18054634_B_1 St Nicholas Cogen Project PA 88 1 24 14,921,531 17054677_B_HRB CII Carbon LLC LA 23 1 1 409,816 1854677_G_TG-2 CII Carbon LLC LA 23 1 1 409,816 1854755_B_BLR2 Westmoreland Roanoke Valley II NC 44 1 9 4,516,042 10354775_B_BLR10 University of Iowa Main PowerPlant IA 4 1 12 2,476,778 59054775_B_BLR11 University of Iowa Main PowerPlant IA 4 1 12 2,476,778 59054992_G_ST Fellsway Development LLC MA 0 1 4 345,520 1,72855076_B_AA001 Red Hills Generating Facility MS 220 1 6 5,085,298 2355076_B_AA002 Red Hills Generating Facility MS 220 1 6 5,209,367 2455360_B_1 Two Elk Generating Station WY 300 2 88 32,932,652 11055479_B_3 Wygen 1 WY 70 1 22 12,384,742 17755749_B_PC1 Hardin Generator Project MT 109 1 113 76,683,994 70655856_B_PC1 Prairie State Generating Company LLC IL 800 3 102 75,746,741 957555856_B_PC2 Prairie State Generating Company LLC IL 800 3 102 75,746,741 9556037_G_1 Fox Valley Energy Center WI 7 1 12 2,829,794 43556068_B_1 Elm Road Generating Station WI 617 3 87 69,303,550 11256068_B_2 Elm Road Generating Station WI 617 3 87 69,303,550 11256163_B_1 KUCC UT 30 1 5 2,097,370 7056163_B_2 KUCC UT 30 1 5 2,097,370 7056163_B_3 KUCC UT 30 1 5 2,097,370 7056163_B_4 KUCC UT 65 1 5 2,599,586 4056224_B_001 TS Power Plant NV 200 2 279 166,191,132 83156319_B_4 Wygen WY 90 1 22 12,811,795 14256319_B_5 Wygen WY 100 1 22 13,317,187 13356456_B_STG1 Plum Point Energy AR 665 2 34 33,548,267 5056671_B_1 Longview Power WV 695 2 21 21,085,857 3082794_C_1 ERCT_TX_Coal steam TX 300 2 8 3,520,181 1282821_B_1 Great River Energy Spiritwood StationND 99 1 14 8,403,970 8582886_C_1 NWPE_WY_Coal steam WY 422 3 212 111,573,136 26482909_C_1 RFCO_IN_IGCC IN 630 3 69 56,903,399 9082916_C_1 RMPA_CO_Coal steam CO 18 1 11 3,744,305 20882932_C_1 SPPN_KS_Coal steam KS 221 10 3,755,430 17182934_C_1 SPPN_MO_Coal steamMO 1,150 3 82 79,762,328 6982998_B_CFB1 Virginia City Hybrid Energy Center VA 293 3 168 99,750,208 34182998_B_CFB2 Virginia City Hybrid Energy Center VA 293 3 168 99,750,208 341

# 76 

# ● ● ●

5.4.3 Mercury Control Capabilities

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

combinations of SO 2 

# , NO X 

# , 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 SO 2 

# and NO X 

# Retrofits

In EPA Base Case v4.10, units that install SO 2 

# , NO X 

# , 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 SO 2 

# , NO X 

# , 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, SO 2 

# 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 SO 2 

# , NO X 

# , or particulate limits or state-level mercury emission requirements.

However, in future model runs where mercury limits are present these same SO 2 

# and NO X 

# 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 SO 2 

# and NO X 

# 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 br ominated 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. Thi s 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 SO 2 

# content, the boiler and

particulate control type and, in some instances, consideration of whether an SO 2 

# scrubber

(FGD) system and SCR NO

x 

# 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.78Table 5-16. Assignment Scheme for Mercury Emissions Control Using Activated Carbon Injection (ACI) in EPA Base Case v4.10_PTox(ProposedToxics Rule).Air pollution controlsBituminous CoalSubbituminous CoalLignite CoalBurner TypeParticulate Control TypeSCRSystemFGDSystemACIRequired?ToxeconRequired?SorbentInj Rate(lb/millionacf)ACIRequired?ToxeconRequired?SorbentInj Rate(lb/millionacf)ACIRequired?ToxeconRequired?SorbentInj Rate(lb/millionacf)FBCCold Side ESP + FabricFilter without FGC----YesNo2YesNo2YesNo2FBCCold Side ESP withoutFGC----YesNo5YesNo5YesNo5FBCFabric Filter--Dry FGDNoNo0YesNo2YesNo2FBCFabric Filter----YesNo2YesNo2YesNo2FBCHot Side ESP with FGC----YesYes2YesYes2YesYes2Non-FBCCold Side ESP + FabricFilter with FGC--Dry FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter with FGC----YesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter with FGC--Wet FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter with FGCSCR--YesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter with FGCSCRDry FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter with FGCSCRWet FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter without FGC--Dry FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter without FGC----YesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter without FGC--Wet FGDYesNo2YesNo2YesNo279Non-FBCCold Side ESP + FabricFilter without FGCSCR--YesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter without FGCSCRDry FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP + FabricFilter without FGCSCRWet FGDYesNo2YesNo2YesNo2Non-FBCCold Side ESP with FGC--Dry FGDYesYes2YesYes2YesYes2Non-FBCCold Side ESP with FGC----YesYes2YesYes2YesYes2Non-FBCCold Side ESP with FGC--Wet FGDYesYes2YesYes2YesYes2Non-FBCCold Side ESP with FGCSCR--YesYes2YesYes2YesYes2Non-FBCCold Side ESP with FGCSCRDry FGDYesYes2YesYes2YesYes2Non-FBCCold Side ESP with FGCSCRWet FGDYesYes2YesYes2YesYes2Non-FBCCold Side ESP withoutFGC--Dry FGDYesNo5YesNo5YesNo5Non-FBCCold Side ESP withoutFGC----YesNo5YesNo5YesNo5Non-FBCCold Side ESP withoutFGC--Wet FGDYesNo5YesNo5YesNo5Non-FBCCold Side ESP withoutFGCSCR--YesNo5YesNo5YesNo5Non-FBCCold Side ESP withoutFGCSCRDry FGDYesNo5YesNo5YesNo5Non-FBCCold Side ESP withoutFGCSCRWet FGDYesNo5YesNo5YesNo5Non-FBCFabric Filter--Dry FGDYesNo2YesNo2YesNo2Non-FBCFabric Filter----YesNo2YesNo2YesNo280Non-FBCFabric Filter--Wet FGDYesNo2YesNo2YesNo2Non-FBCFabric FilterSCRDry FGDYesNo2YesNo2YesNo2Non-FBCFabric FilterSCR--YesNo2YesNo2YesNo2Non-FBCFabric FilterSCRWet FGDYesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter with FGC----YesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter with FGC--Wet FGDYesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter with FGC--Dry FGDNoNo0YesNo2Y(b)No2Non-FBCHot Side ESP + FabricFilter with FGCSCRWet FGDYesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter with FGCSCRDry FGDNoNo0YesNo2Y(b)No2Non-FBCHot Side ESP + FabricFilter with FGCSCR--YesNo2YesNo2Y(b)No2Non-FBCHot Side ESP + FabricFilter without FGC--Dry FGDNoNo0YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter without FGC----YesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter without FGC--Wet FGDYesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter without FGCSCRDry FGDNoNo0YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter without FGCSCR--YesNo2YesNo2YesNo2Non-FBCHot Side ESP + FabricFilter without FGCSCRWet FGDYesNo2YesNo2YesNo2Non-FBCHot Side ESP with FGC--Dry FGDYesYes2YesYes2YesYes281Non-FBCHot Side ESP with FGC----YesYes2YesYes2YesYes2Non-FBCHot Side ESP with FGC--Wet FGDYesYes2YesYes2YesYes2Non-FBCHot Side ESP with FGCSCRDry FGDYesYes2YesYes2YesYes2Non-FBCHot Side ESP with FGCSCR--YesYes2YesYes2YesYes2Non-FBCHot Side ESP with FGCSCRWet FGDYesYes2YesYes2YesYes2Non-FBCHot Side ESP without FGC--Dry FGDYesYes2YesYes2YesYes2Non-FBCHot Side ESP without FGC----YesYes2YesYes2YesYes2Non-FBCHot Side ESP without FGC--Wet FGDYesYes2YesYes2YesYes2Non-FBCHot Side ESP without FGCSCRDry FGDYesYes2YesYes2YesYes2Non-FBCHot Side ESP without FGCSCR--YesYes2YesYes2YesYes2Non-FBCHot Side ESP without FGCSCRWet FGDYesYes2YesYes2YesYes2Non-FBCNo Control--Dry FGDYesYes2YesYes2YesYes2Non-FBCNo Control----YesYes2YesYes2YesYes2Non-FBCNo Control--Wet FGDYesYes2YesYes2YesYes2Non-FBCNo ControlSCRDry FGDYesYes2YesYes2YesYes2Non-FBCNo ControlSCR--YesYes2YesYes2YesYes2Non-FBCNo ControlSCRWet FGDYesYes2YesYes2YesYes282Non-FBCPM Scrubber--Dry FGDYesYes2YesYes2YesYes2Non-FBCPM Scrubber----YesYes2YesYes2YesYes2Non-FBCPM Scrubber--Wet FGDYesYes2YesYes2YesYes2Non-FBCPM ScrubberSCRDry FGDYesYes2YesYes2YesYes2Non-FBCPM ScrubberSCR--YesYes2YesYes2YesYes2Non-FBCPM ScrubberSCRWet FGDYesYes2YesYes2YesYes2Note: 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 Rate of 2 lbs/million acfm" elsewhere inthis 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 qu alifying 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 SO 3 

# 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 ratio 5 

# . 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 ar eas (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 syst ems 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 combi ned 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 sh own 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 & Lundy 6



# .

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/

.86Table 5-18. Illustrative Activated Carbon Injection (ACI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPABase Case v4.10_PTox (Proposed Toxics Rule)Control TypeHeat Rate(Btu/kWh)CapacityPenalty(%)Heat RatePenalty (%)Variable O&M(mills/kWh)Capacity (MW)1003005007001000CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)ACI Systemwith anExisting ESPACI with aSorbentInjection Rateof 5 lbs/millionacfmAssumingBituminousCoal9,00010,00011,0000.120.130.140.120.130.142.763.073.3832.0632.5633.040.130.140.1412.6012.8012.990.050.050.058.168.298.410.030.030.046.136.236.320.030.030.034.534.604.670.020.020.02ACI Systemwith anExistingBaghouseACI with aSorbentInjection Rateof 2 lbs/millionacfmAssumingBituminousCoal9,00010,00011,0000.050.050.060.050.050.062.242.492.7427.9328.3728.800.120.120.1210.9811.1611.320.050.050.057.117.237.330.030.030.035.345.435.510.020.020.023.954.014.070.020.020.02ACI Systemwith anAdditionalBaghouseACI + FullBaghouse witha SorbentInjection Rateof 2 lbs/millionacfmAssumingBituminousCoal9,00010,00011,0000.650.650.660.650.660.660.500.540.582402592780.910.981.051821972120.690.750.801621761890.610.670.721501631760.570.620.671391511630.530.570.62

# 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

SO 2 

# 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-existi ng FGD (column 5), the HCl removal rate is 5%

higher than the reported SO 2 

# 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 SO 2 

# 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% SO 2 

# 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 adder 7



# .

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 SO 2



# removal rate

up to a

maximum of

95%

−−−

With fabric

filter: 95% Reported SO 2



# removal rate +

5% up to a

maximum of

99% If reported SO 2



# removal < 90%, unit

incurs cost to upgrade

FGD, so that SO 2



# removal is 90%. Then,

the resulting HCl

removal rate is 99%

−−−

If reported SO 2



# removal is ≥ 90% and

< 94%, then the unit

incurs a cost to

upgrade FGD and the

HCl removal rate is

99%. (The SO 2



# removal rate remains

as reported.)

−−−

If the reported SO 2



# removal rate is ≥ 94%,

the unit incurs no

upgrade cost and the

HCl removal rate is

99%.

# 89 

# 5.5.3 HCl Retrofit Em ission 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 SO 2 

# 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 5-21.90Table 5-21 Summary of Retrofit HCl (and SO2) Emission Control Performance Assumptions in v4.10_PTox (Proposed Toxics Rule).PerformanceAssumptionsLimestone Forced Oxidation(LSFO)Lime Spray Dryer (LSD) Dry Sorbent Injection (DSI)1SO2HClSO2HClSO2HClPercent Removal96%with a floor of0.06 lbs/MMBtu99%with a floor of0.0001lbs/MMBtu92%with a floor of0.065 lbs/MMBtu99%with a floor of0.0001lbs/MMBtuWith fabricfilter:70%−−−With anelectrostaticpercipitator2:50%With fabric filter:90%with a floor of0.0001 lbs/MMBtu−−−With anelectrostaticpercipitator2:60%with a floor of0.0001 lbs/MMBtuCapacity Penalty-1.65%-0.70%-0.65%Heat Rate Penalty1.68%0.71%0.65%Cost (2007$)See Table 5-3 and 5-4See Table 5-3 and 5-4 See Tables D and EApplicabilityUnits≥25MWUnits≥25MWUnits≥25MWSulfur ContentApplicabilityCoals≤2.0% Sulfur by WeightCoals≤2.0 lb/mmBtu of SO2Applicable CoalTypesBA, BB, BD, BE, BG, BH, SA, SB,SD, LD, LE, and LGBA, BB, BD, BE, SA, SB, SD, LD,LE, and LGBA, BB, BD, SA, SB, SD, and LDNotes1. The cost and performance values shown in this table apply toexisting units with pre-existing fabric filters or electrostatic precipitators.Units with neither ESP nor FF are assumed to have to install afabric filter in order to qualify for the DSI retrofit.2. The option to retrofit DSI on existing units with ESP wasnot 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 SO 2 

# 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 SO 2 

# 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 surfac e 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 C ounty, 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 SO 2 

# and post-combustion NO

x 

# controls in EPA Base

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

alternative, associated particulate control dev ices, 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 SO 2 

# or HCl

removal 8 

# is firstly a function of the flue gas SO 2 

# rate (which, in turn, is a function of the sulfur

content of the coal burned, expressed in lbs of SO 2 

# /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௘ ௚௔௦ 

# ቁ

ሺ ݁݀ݎ݅ݑݍ݁ݎ ݐܾ݁݊ݎ݋ݏ ݂݋ ݏ݈݁݋݉ ݈݅ܿܽݐ݁ݎ݋݄݁ݐ ሻ ൘

# 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 SO 2 

# 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 SO 2 

# feed rate. As

noted above the feed rate is a function of the SO 2 

# 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 & Lundy 9



# .

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 r eport is available for review and downloading at

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

.95Table5‐23.IllustrativeDrySorbentInjection(DSI)CostsforRepresentativeSizesandHeatRatesUnderAssumptionsinEPABaseCasev4.10_PTox(ProposedToxicsRule).ControlTypeHeatRate(Btu/kWh)SO2Rate(lb/MMBtu)CapacityPenalty(%)HeatRatePenalty(%)VariableO&M(mills/kWh)Capacity (MW)1003005007001000CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)DSI - FF9,0002.00.640.656.051222.25550.87380.57300.43280.36AssumingBituminousCoal10,0002.00.710.726.721252.28570.89400.58310.43310.3811,0002.00.790.797.401292.30590.90410.59340.46340.41DSI - ESP9,0002.01.081.1011.231412.41640.94470.64470.57470.52AssumingBituminousCoal10,0002.01.201.2212.471452.44660.96520.68520.61520.5611,0002.01.321.3413.721492.48680.98580.73580.65580.60

# 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 volume tric 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 der ived 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 & Lundy 10



# .

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/

.98Table5‐24.IllustrativeFabricFilter(Baghouse)CostsforRepresentativeSizesandHeatRatesUnderAssumptionsinEPABaseCasev4.10_PTox(ProposedToxicsRule).Coal TypeHeatRate(Btu/kWh)CapacityPenalty(%)HeatRatePenalty(%)VariableO&M(mills/kWh)Capacity (MW)1003005007001000CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)Bituminous9,0000.600.60 0.151880.81530.61390.61300.61220.510,0002050.91670.71510.61410.61320.611,0002210.91800.81630.71530.61430.6Notes on Implementation1. Plant specific fabric filter capitalcosts shown in this table are implemented in EPA Base Case v4.10_PTox as an FOM adder.Plants that installfabric filters incur a total FOM charge which includes the trueFOM component shown in the abovetable plus a capital cost FOMAdder derived bymultiplying the capital cost in the tableabove by a capital charge rate 11.3%, i.e.,Total FOM = True FOM + Capital Cost FOM Adderwhere the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%.Plants that install fabric filters also incurthe additional VOM costs shown in the above table.2. Since the fabric filter costs were not endogenously modeled asa retrofit option, the capacity and heat rate penalties shownin the above table werenot 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 SO 2 

# ) 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 SO 2 

# 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 SO 2 

# and mercury data

only. For Base Case v4.10_PTox it had to be performed jointly on the SO 2 

# , 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 SO 2 

# , mercury, ash, HCl, and CO 2 

# 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, SO 2 

# 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 SO 2 

# ranges associated with a given type of

coal. (The sulfur grades and associated SO 2 

# 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 SO 2 

# Content Ranges

SO 2 

# Grade SO 2 

# 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, SO 2 

# , 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

SO 2 

# , 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, SO 2 

# , 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 SO 2 

# , 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) SO 2



# Content

(lbs/MMBtu) Mercury

Content

(lbs/TBtu) A sh

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) SO 2



# Content

(lbs/MMBtu) Mercury

Content

(lbs/TBtu) A sh

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 SO 2 

# 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 SO 2 

# concentrations for each IPM

coal type was determined based on the range in average mercury , HCl, and SO 2 

# 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 SO 2 

# , HCl, and mercury values shown in Table 9-5 for that coal grade. (In the BG coal

example there are 11 such regional SO 2 

# , HCl, and mercury values.) Using the SAS cluster

procedure, each of the constituent regional values was assigned to a cluster and the cluster

average SO 2 

# , 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 SO 2 

# , HCl, and mercury

values are 3.79 lbs/MMBtu , 0.092 lbs/MMBtu, and 21.54 lbs/TBtu respectively. The Cluster #2

average SO 2 

# , 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 SO 2 

# , HCl, and mercury values are 4.84 lbs/MMBtu, 0.133 lbs/MMBtu, and 4.09 lbs/TBtu

respectively. The Cluster #5 average SO 2 

# , 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 CO 2 

# values were calculated for each of

the clusters. These values are shown in Table 9-8 and Table 9-9. (The CO 2 

# 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 SO 2 

# , mercury, ash, CO 2 

# , 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 SO 2 

# 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 Co al 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 CO 2 

# Emission Factors of Coal Used in EPA Base Case v4.10_PTox

Coal Type by Sulfur Grade CO 2 

# 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

-- -- -- -- --114Figure 9-2 ClusterMapping Example – BG Coal

# IPM Model – Revisions to Cost a nd 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 • Ch icago, 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 circ umstances. 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.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 3 

# Technology Description

Activated carbon injection (AC I) is a viable technology fo r mercury (Hg) reduction on

coal fired boilers. The ACI technology is fair ly new but is gaining acceptance. Currently

less than 10% of the U.S. coal fired boiler flue gas (based on power produ ced) is treated

for Hg by ACI. Many domestic new and re trofit 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 lik ely be required. Commercial experience has

shown that ACI can meet a 90% redu ction 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, be neficial 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 accep ted in the cement industry without prior

testing by the fly ash purchaser.



# Mercury Speciation

Mercury is contained in vary ing 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 (Hg 0 

# ),

• Ionic or Oxidized (Hg ++ 

# ), or

• Particulate.

The conversion of elemental mercury to th e other forms depends upon several factors;

cooling rate of the gas, pr esence of halogens or SO 3 

# in the flue gas, amount and

composition of fly ash, presence of unburne d 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 elem ental 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

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 4 ammonia adsorption on surface is minimal. SCR systems may have the ability to convert

some elemental mercury to ionic mercury de pending on the halide c ontent in the coal.

The catalyst used in SCR systems is desi gned to facilitate the conversion of NO

x 

# to N 2



# and H 2 

# O. The active ingredient used in SCR catalysts is vanadium pentoxide, which

oxidizes sulfur dioxide (SO 2 

# ) to sulfur trioxide (SO 3 

# ) as well as elemental mercury to

ionic mercury. Mercury oxidati on is inhibited by ammonia inj ection. Typically, most of

the mercury oxidation occurs in the last la yer of catalyst where the concentration of

ammonia is the lowest.

Another mechanism of mercury oxidation occu rs across fabric filter elements in a

baghouse. Unburned carbon in the fly ash accu mulates in the filter cake on the filter

elements. The unburned carbon oxidizes Hg 0 

# 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 th e filter cake on the fa bric filters, mercury

can be adsorbed on the carbon particles pres ent in the fly ash. The mercury is bound to

the particulates in the filter cake and the pa rticulate 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 ca rbon concentration or can improve the

capture with activat ed carbon injection.



# Mercury Capture

The speciation of the mercury plays a significant role in its capture. Elemental mercury

is insoluble in water. Therefore, Hg 0 

# is not collected in downstream FGD systems. Nor

do particulate collectors remove elemental me rcury. Elemental mercury can be removed

with ACI or it must be converted to anot her form to be captured in downstream FGD

systems.

Some flue gas constituents, especially SO 3 

# , reduce the effectivene ss of the ACI. With

flue gas SO 3 

# 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. Ba sed on commercial testing, the capacity of the

activated carbon can be cut by as much as one half with an SO 3 

# increase from just 5

ppmv to 10 ppmv. Some utilities are testi ng the injection of alka li (typically Trona)

before the ACI system to reduce the SO 3 

# 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.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 5 In contrast to elemental mercury, ionic merc ury is highly water soluble. In dry FGD

systems, the ionic mercury is captured in th e 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 th e system with the purge wa ter or the mercury can bind

with the solid phases in the FGD slurry a nd leave with the solid by-product. Recent

commercial data indicates that some of th e 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-goi ng to determine the mechanism for re-emission

and to develop additives to mitigate the probl em. 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 effici ently from the flue gas by the particulate

control device. Therefore, it is desirable to convert as much mercury as possible to

particulate mercury. High SO 3 

# levels have been shown to inhibit the binding of ionic

mercury to fly ash or carbon. Low halogen leve ls in the coal will also inhibit formation

of particulate mercury by first inhibiting fo rmation of ionic mercury. Activated carbon

and addition of halogens increase the c onversion 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 to tal mercury removal is less than 80%. To

ensure full wet FGD co-benefit capture, costs ar e included to provide slurry additives that

inhibit re-emission of the mercury. Both capit al 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 ar e required. However,

alkali injection may be required for SO 3 

# control to meet the removal requirements with

ACI. No costs were incl uded for alkali injection.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 6 PRB and lignite coals have relatively low hal ogen concentrations. For those fuels, coal

additives are required to prom ote 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 additiv es, 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 tota l mercury is required,

an ACI system would need to be installe d and no coal additives may be required.

When an ACI system is required, the design ca rbon feed rate will dictate the size of the

ACI equipment and the resulti ng capital costs. The carbon fe ed rate is a function of

required removal, particulate collection devi ce, and in some cases state regulations.

A consistent basis was establis hed to calculate th e carbon feed rate. The activated carbon

rate was based on the use of brominated car bon. Current industry experience indicates

that 5 pounds of carbon injected for ever y 1,000,000 acfm of flue gas will ensure

adequate mercury capture and is a common desi gn 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 a dditional alkali injection was included to remove

SO 3 

# or other inhibitors. In summary:

• 5 lb per 1,000,000 acfm carbon f eed 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 variab les, the capital cost was esta blished based on the actual

anticipated activated carbon feed rate, not th e 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 syst ems 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 a dditional particulate load associated

with the activated carbon injection.

• A new baghouse should be installed wh enever flue gas conditioning (SO 3 

# injection) is required for the existing ESP. Use of flue gas conditioning

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 7 indicates that the existing ESP is marginally acceptable for the current solids

load and the additional ACI load w ould result in excessive particulate

emissions.

• PRB coals tend to be low in chloride; th erefore, most of the flue gas mercury

is elemental mercury. Installation of a baghouse can result in varying degrees

of oxidation of the elemental merc ury through contact with the unburned

carbon in the fly ash. The oxidized me rcury 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 part iculate capture device that will remain in

service to capture the majority of the fl y ash. The ACI system would be installed

downstream of the existing part iculate capture device and ups tream of the new baghouse.

The design has two benefits. First, a sma ller capital investment is required for a

polishing baghouse when compared to a full si zed 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 de vice for the fly ash and activated carbon. The

lower A/C ratio will provide better bag lif e with the high inlet particulate loading

expected for the single particulat e capture device in the process.

Capital costs were developed for the baghous e addition. The option to include a 4.0 A/C

or a 6.0 A/C baghouse or not to include a baghou se is left to the user of the cost

algorithm. Cost data from the S&L current da tabase of projects, for several different

baghouse installations, was reviewed and a re lationship 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 requ ired in order to predict the total future retrofit costs:

• Type of coal,

• Unit size,

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment 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 applicab le) 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 esti mate (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 manageme nt costs at 5% of the BM cost;

• Labor adjustment for 6 x 10 hour shift pr emium, 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 subt otal (CECC) is established as the sum of

the BM and the additional engi neering and construction fees.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment 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 C onstruction (AFUDC) at 0% of the

CECC and owner’s costs as ACI projects ar e 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 tim e 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 ba sed on a multiple lump sum co ntract approach. Should a

turnkey engineering procurement constructi on (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 inst allation. 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 additiona l operation staff member.

• The fixed maintenance materials and labor is a direct function of the process

capital cost (BM).

• The administrative labor is a f unction of the FOMO and FOMM.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 10 Variable O&M (VOM)



# Variable O&M is a function of:

• Reagent use and unit costs;

• Waste production and un it 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 landf illed. 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 to tal 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 ne w 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 y ears respectively for unit operations

with 6.0 A/C.

• Bag and cage replacement every 5 a nd 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.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment 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 ba se 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 (incl uding all benefits) in $/hr.

The variables that contribut e 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 a uxiliary power requirement is re ported as a percentage of the

total gross power of the unit.

Table 1 contains an example of the comple te capital and O&M cost estimate worksheet

when using an existing ESP for the carbon a nd 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, cont ains details of an

existing SCR and wet FGD system burning P RB coal and requiring less than 80% total

mercury removal.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment 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)

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment 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)

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 14 Table 3. Example Complete Cost Estimate for an ACI System wi th an Additional Baghouse (Costs are all based on 2009 dollars)

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment Methodology – Final

Page 15 Table 4. Example Complete Cost Estimate for both Additives Systems without ACI (Costs are all based on 2009 dollars)

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March 2011



# Mercury Control Cost Develo pment 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 a nd 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 • Ch icago, 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 degr ee 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.

# Project No. 12301-007 IPM Model – Revisions to Cost and Performance for

APC Technologies August 20, 2010



# Dry Sorbent Injection Cost De velopment Methodology – Final

Page 3 

# Technology Description

Dry sorbent injection (DSI) is a viable technology for moderate SO 2 

# reduction on coal

fired boilers. Demonstrations and r ecent utility testing have shown SO 2 

# 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 particulat e capture device. NS R is defined as:

The target removal efficiency is a requiremen t from the utility and is independent of unit

size. The costs for a DSI system are primaril y dependant on sorbent fe ed rate which is a

function of NSR and SO 2 

# mass feed rate per hour. Ther efore, the cost estimation was

based on sorbent feed ra te and not on unit size.

The sorbent solids can be collected in either an ESP or a baghouse. Baghouses generally

achieve greater SO 2 

# 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 effi ciency with Trona, the NSR is reduced when a baghouse is used

for particulate capture.

The dry sorbent capture ability is also a functi on of particle surface area. To increase the

particle surface area, the sorb ent must be heated. Heati ng the solids produ ces micropores

on the particle surface which greatly improve the sulfur capture ability. For Trona, the

sorbent should be injected into flue ga s 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 μ m. Commercial testing has shown

that the reactivity of the Trona can be incr eased when the sorbent is ground to less than

30 μ m. In the cost estimati ng 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 delivere d cost of the Trona will not change, only the

reactivity and usage changes as the Trona is milled.

# Project No. 12301-007 IPM Model – Revisions to Cost and Performance for

APC Technologies August 20, 2010



# Dry Sorbent Injection Cost De velopment Methodology – Final

Page 4 Ultimately, the NSR required for a given removal is a function of Trona particle size and

particulate capture equi pment. Either as delivered Trona (around 30 μ m average size) or

in-line milled Trona (around 15 μ m average size) can be chosen for injection in the cost

program. The average Trona particle size and the type of particulat e removal both

contribute to the predic ted 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. W ith 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 sorb ent feed rate is a f unction of su lfur rate,

particulate collection device, a nd removal efficiency. To account for all of the variables,

the capital cost was established based on a sorb ent feed rate. The sorbent feed rate is

calculated from user input variables. Cost data for several DSI systems was reviewed

and a relationship was de veloped for the capital costs of the system on a sorbent feed rate

basis.



# Methodology

Inputs

Several input variables are required in order to predict fu ture retrofit costs. The sulfur

feed rate and NSR are the major variables fo r 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 fa ctor into the amount of sulfur generated.

Based on commercial testing, remo val efficiencies with DSI ar e limited by the particulate

capture device employed. Wh en the sorbent is captured in an ESP, a 40 to 50% SO 2 

# 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 sulf ur content of greater than 2 lb SO 2 

# /MMBtu.

# Project No. 12301-007 IPM Model – Revisions to Cost and Performance for

APC Technologies August 20, 2010



# Dry Sorbent Injection Cost De velopment Methodology – Final

Page 5 The equations provided in the cost methodology spreadsheet a llow the user to input the

required removal efficiency, within the limits of the t echnology. 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 increas e 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 sel ection of in-line milling equipment. The base

installed cost is then increased by:

• Engineering and c onstruction management costs at 5% of the BM cost;

• Labor adjustment for 6 x 10 hour shift pr emium, per diem, etc., at 5% of the

BM cost; and

• Contractor profit and fees at 5% of the BM cost.

# Project No. 12301-007 IPM Model – Revisions to Cost and Performance for

APC Technologies August 20, 2010



# Dry Sorbent Injection Cost De velopment Methodology – Final

Page 6 A capital, engineering, and cons truction cost subtotal (CECC) is established as the sum of

the BM and the additional engi neering and construction fees.

Additional costs and financi ng expenditures for the project are computed based on the

CECC. Financing and additi onal 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 (A FUDC) 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 procurem ent construction (EPC) contra ct 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 main tenance (O&M) cost is a function of the additional

operations staff (FOMO), main tenance labor and materials (FOMM), and administrative

labor (FOMA) associated with the DSI inst allation. The FOM is the sum of the FOMO,

FOMM, and FOMA.

The following factors and assumptions underlie calc ulations 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 numb er of additional opera tions staff required.

• The fixed maintenance materi als and labor is a direct function of the process

capital cost (BM).

• The administrative labor is a fu nction of the FOMO and FOMM.

# Project No. 12301-007 IPM Model – Revisions to Cost and Performance for

APC Technologies August 20, 2010



# Dry Sorbent Injection Cost De velopment 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 require d and unit power cost.

The following factors and assumptions underlie calc ulations 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 SO 2 

# feed rate. The gross unit size

and gross heat rate factor multiplied by the SO 2 

# rate determine the SO 2 

# feed

rate. The estimated NSR is a function of removal efficien cy required. The

basis for the total reagent ra te is a Trona purity of 98%.

• The waste generation rate is a function of the Trona fe ed rate and is adjusted

for the excess sorbent fed. The wast e generation ra te is based on reaction

products of Na 2 

# SO 4 

# and unreacted dr y sorbent as Na 2 

# CO 3



# .

• With the addition of a sodium sorb ent, 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 producti on is added to the sorbent waste to

account for a total waste st ream 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 ba se 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 be nefits) in $/hr.

# Project No. 12301-007 IPM Model – Revisions to Cost and Performance for

APC Technologies August 20, 2010



# Dry Sorbent Injection Cost De velopment 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 co ntains an example

of the complete capital and O&M cost estimate worksheet.Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Dry Sorbent Injection Cost Development Methodology – FinalPage 9Table 1. Example Complete Cost Estimate for a DSI System(Costs are all based on 2009 dollars)Project No. 12301-007IPM Model – Revisions toCost and Performance forAPC TechnologiesAugust 20, 2010Dry Sorbent Injection Cost Development Methodology – FinalPage 10

# IPM Model – Revisions to Cost a nd 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 • Ch icago, 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 circ umstances. 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.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March, 2011



# Particulate Control Cost Deve lopment Methodology – Final

Page 3 

# Technology Description

There are two main particulat e capture unit operations employe d 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 worl d. The ESP collects PM in a

three step process: charging, collecting, and cl eaning 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 a nd opacity below 10% depending on the ash

characteristics and particulate loading. Howe ver, it is difficult to collect fly ash when

burning low sulfur coal because of high fly ash resistivity requiring la rge ESP. ESPs are

not well suited for processes that are highly va riable because the collection efficiency is

sensitive to fluctuations in gas stream conditions.

Recently fabric filters (specifically pulse-je t type or PJFF) have become the preferred

choice for new and retrofit utility particul ate capture. PJFFs have been utilized

commercially for over 25 years and are consid ered 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 sorb ent injection, the SO 2 

# 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.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March, 2011



# Particulate Control Cost Deve lopment Methodology – Final

Page 4 

# Establishment of Cost Basis

The major cost driver for a baghouse is the re quired gross air-to-cloth (A/C) ratio. When

the baghouse is installed in a retrofit situation fo llowing another collection device, such

as an ESP, then an A/C of 6.0 would be appropriate if activat ed carbon injection is

applied for mercury removal.

If the baghouse will be used as the sole pa rticulate 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 basi s. 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 requ ired 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 ba ghouse 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 pr emium, per diem, etc., at 5% of the

BM cost; and

• Contractor profit and fees at 5% of the BM cost.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March, 2011



# Particulate Control Cost Deve lopment Methodology – Final

Page 5 A capital, engineering, and construction cost subt otal (CECC) is established as the sum of

the BM and the additional engi neering 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 C onstruction (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 ba sed on a multiple lump sum co ntract approach. Should a

turnkey engineering procurement constructi on (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 operat ors 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 f unction of the FOMO and FOMM.

Variable O&M (VOM)



# Variable O&M is a function of:

• Bag and cage replacement.

# Project No. 12301-009 IPM Model – Revisions to Cost and Performance for

APC Technologies March, 2011



# Particulate Control Cost Deve lopment 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 y ears respectively for unit operations

with 6.0 A/C.

• Bag and cage replacement every 5 a nd 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 ba se estimate. The variable O&M costs per

unit options are:

• Bag and cage costs in $/item.

The variables that contribut e 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 requir ement is reported as

a percentage of the total gross power of the unit.

Table 1 contains an example of the comple te capital and O&M cost estimate worksheet

for a baghouse installation.Project No. 12301-009IPM Model – Revisions toCost and Performance forAPC TechnologiesMarch, 2011Particulate Control Cost Development Methodology – FinalPage 7Table 1. Example Complete Cost Estimate for a 4.0 A/C Baghouse Installation (Costs are all based on 2009 dollars)Project No. 12301-009IPM Model – Revisions toCost and Performance forAPC TechnologiesMarch, 2011Particulate Control Cost Development Methodology – FinalPage 8Table 2. Example Complete Cost Estimate for a 6.0 A/C Baghouse Installation (Costs are all based on 2009 dollars)