United States Air and Radiation March 2011
Environmental Protection Agency (6204J)
Documentation Supplement for
EPA Base Case v4.10_PTox -
Updates for Proposed Toxics Rule
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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
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This report documents enhancements and updates that were made in EPA Base Case v4.10_PTox
Mar20111to provide capabilities required to perform modeling for the Proposed Toxics Rule.
Specifically, the capability to model HCI emissions and controls was added. Existing coal units were
given the option to burn natural gas by investing in a coal-to-gas retrofit. The cost and performance
assumptions were updated for Activated Carbon Injection (ACI), the emission control particularly
designated for mercury emission reductions. In addition, updates were made to the tables of state
regulations and NSR and state settlements to reflect changes that had occurred since the previous
base case
The current report takes the form of a supplement to the documentation report "Documentation for EPA
Base Case v4.10 Using the Integrated Planning Model" (August 2010) that can be found on the web at
www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html. Exhibit 1 contains an abbreviated
version of the table of contents of the v4.10 Documentation. Additions and changes found in this
Documentation Supplement are shown in red.
1 EPA Base Case v4.10_PTox Mar2011 refers to EPA's application of the Integrated Planning Model
(IPM) of the U.S. power sector that was developed and used in analysis of the Proposed Toxics Rule.
For brevity it is often referred to as v4.10_PTox in subsequent pages of this documentation supplement.
IPM® is a registered trademark of ICF International.
1
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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 4- Updated
Appendix 3-4 State Settlements
4 GENERATING RESOURCES
5 EMISSION CONTROL TECHNOLOGIES
5.3 COAL-TO-GAS CONVERSIONS
5.3.1 Boiler Modifications for Coal-to-Gas Conversions
5.3.2 Natural Gas Pipeline Requirements for Coal-to-Gas Conversions
• • •
5.4 MERCURY CONTROL TECHNOLOGIES
New fuel retrofit option
5.4.3 Mercury Control Capabilities
Mercury Control through SO2 and NOX Retrofits
Activated Carbon Injection (ACI) <- Replaced based on current engineering assessment
5.5 Hydrogen Chloride (HCI) Control Technologies
5.5.1 Chlorine Content of Fuels
5.5.2 HCI Removal Rate Assumptions for Existing and Potential Units
5.5.3 HCI Retrofit Emission Control Options
5.5.3.1 Dry and Wet FGD
5.5.3.2 Dry Sorbent Injection
5.5.4 Fabric Filter (Baghouse) Cost Development
Appendix 5-3 Example Cost Calculation Worksheets for 3 ACI Options
Appendix 5-4 Example Cost Calculation Worksheets for DSI
Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filter (Baghouse)
6 CO2 CAPTURE, TRANSPORT, AND STORAGE
7 SET-UP PARAMETERS AND RULES
8 FINANCIAL ASSUMPTIONS
9 COAL
9.1 COAL MARKET REPRESENTATION IN EPA BASE CASE V4.10
HCI modeling
9.1.3 Coal Quality Characteristics
9.1.4 Emission Factors
Enhanced to include HCI content of coals
10 NATURAL GAS
11 OTHER FUELS AND FUEL EMISSION FACTOR ASSUMPTIONS
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Documentation Supplement to Chapter 3 ("Power System Operation Assumptions")
The tables of State Power Sector Regulations (Appendix 3-2), New Source Review Settlements (Appendix
3-3), and State Settlements (Appendix 3-4) were updated to reflect changes that had occurred since the
provisions had been incorporated in EPA Base Case v4.10. The updated tables are included below.
Appendix 3-2 State Power Sector Regulations included in EPA Base Case v4.10_PTox, Mar2011
State/Region
Alabama
Arizona
California
Colorado
Connecticut
Delaware
Bill
Alabama
Administrative Code
Chapter 335-3-8
Title 18, Chapter 2,
Article 7
CA Reclaim Market
40C.F.R. Part 60
Executive Order 19
and Regulations of
Connecticut State
Agencies (RCSA)
22a-1 74-22
Executive Order 19,
RCSA22a-198&
Connecticut General
Statues (CGS) 22a-
198
Public Act No. 03-72
&RCSA22a-198
Regulation 1148:
Control of Stationary
Combustion Turbine
ECU Emissions
Regulation No. 1146:
Electric Generating
Unit (ECU) Multi-
Pollutant Regulation
Emission
Type
NOX
Hg
NOX
S02
Hg
NOX
SO2
Hg
NOX
NOX
S02
Emission Specifications
0.02 Ibs/MMBtu annual PPMDV for combined cycle
EGUs which commenced operation after April 1 ,
2003
90% removal of Hg content of fuel or 0.0087
Ib/GWH-hr annual reduction for all non-cogen coal
units > 25 MW
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)
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)
201 2 & 201 3: 80% reduction of Hg content of fuel or
0.01 74 Ib/GW-hr annual reduction for Pawnee
Station 1 and Rawhide Station 101
201 4 through 201 6: 80% reduction of Hg content of
fuel or 0.01 74 Ib/GW-hr annual reduction for all coal
units > 25 MW
2017 onwards: 90% reduction of Hg content of fuel
or 0.0087 Ib/GW-hr annual reduction for all coal
units > 25 MW
0.1 5 Ibs/MMBtu rate limit in the winter season for all
fossil units > 15 MW
0.33 Ibs/MMBtu annual rate limit for all Title IV
sources > 15 MW
0.55 Ibs/MMBtu annual rate limit for all non-Title IV
sources > 15 MW
90% removal of Hg content of fuel or 0.0087 Ib/GW-
hr annual reduction for all coal-fired units
0.19 Ibs/MMBtu ozone season PPMDV for
stationary, liquid fuel fired CT EGUs >1 MW
0.39 Ibs/MMBtu ozone season PPMDV for
stationary, gas fuel fired CT EGUs >1 MW
0.125 Ibs/MMBtu rate limit of NOxannually for all
coal and residual-oil fired units > 25 MW
0.26 Ibs/MMBtu annual rate limit for coal and
residual-oil fired units > 25 MW
Implementation
Status
2003
2017
1994
2012
2003
2008
2009
2009
-------
State/Region
Georgia
Illinois
Kansas
Louisiana
Maine
Bill
Multipollutant Control
for Electric Utility
Steam Generating
Units
Title 35, Section
217.706
Title 35, Part 225,
Subpart B: Control of
Hg Emissions from
Coal Fired Electric
Generation Units
Title 35 Part 225;
Subpart F: Combined
Pollutant Standards
NOX Emission
Reduction Rule,
K.A.R. 28-1 9-71 3a.
Title 33 Part III -
Chapter 22, Control of
Emissions of Nitrogen
Oxides
Title 33 Part III -
Chapter 15, Emission
Standards for Sulfur
Dioxide
Chapter 145 NOX
Control Program
Statue 585-B Title 38,
Chapter 4: Protection
and Improvement of
Air
Emission
Type
Hg
SCR, FGD,
and
Sorbent
Injection
Baghouse
controls to
be installed
NOX
NOX
SO2
Hg
NOX
SO2
Hg
NOX
SO2
NOX
NOX
Hg
Emission Specifications
201 2: 80% removal of Hg content of fuel or 0.01 74
Ib/GW-hr annual reduction for all coal units > 25 MW
2013 onwards: 90% removal of Hg content of fuel or
0.0087 Ib/GW-hr annual reduction for all coal units >
25 MW
The following plants must install controls: Bowen,
Branch, Hammond, McDonough, Scherer, Wansley,
and Yates
0.25 Ibs/MMBtu summer season rate limit for all
fossil units > 25 MW
0.1 1 Ibs/MMBtu annual rate limit and ozone season
rate limit for all Dynergy and Ameren coal steam
units > 25 MW
201 3 & 201 4: 0.33 Ibs/MMBtu annual rate limit for all
Dynergy and Ameren coal steam units > 25 MW
2015 onwards: 0.25 Ibs/MMBtu annual rate limit for
all Dynergy and Ameren coal steam units > 25 MW
90% removal of Hg content of fuel or 0.08 Ibs/GW-hr
annual reduction for all Ameren and Dynergy coal
units > 25 MW
0.1 1 Ibs/MMBtu ozone season and annual rate limit
for all specified Midwest Gen coal steam units
0.44 Ibs/MMBtu annual rate limit in 2013, decreasing
annually to 0.11 Ibs/MMBtu in 2019 for all specified
Midwest Gen coal steam units
90% removal of Hg content of fuel or 0.08 Ibs/GWh
annual reduction for all specified Midwest Gen coal
steam units
0.20 Ibs/MMBtu annual rate limit for Quindaro Unit 2
and 0.26 Ibs/MMBtu annual rate limit for Nearman
Unit 1.
1 .2 Ibs/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
Various annual rate limits depending on plant and
fuel type for facilities within the Baton Rouge
Nonatiainment Area that collectively have the
potential to emit 25 tons or more per year of NOX or
facilities within the Region of Influence that
collectively have the potential to emit 50 tons or
more per year of NOX
0.22 Ibs/MMBtu annual rate limit for all fossil fuel
units > 25 MW built before 1995 with a heat input
capacity < 750 MMBtu/hr
0.15 Ibs/MMBtu annual rate limit for all fossil fuel
units > 25 MW built before 1995 with a heat input
capacity > 750 MMBtu/hr
0.20 Ibs/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
25 Ibs annual cap for any facility including EGUs
Implementation
Status
Implementation
from 2008
through 2015,
depending on
plant and control
type
2004
2012
2013
2015
2012
2013
2015
2012
2005
2005
2005
2010
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State/Region
Maryland
Massachusett
s
Michigan
Minnesota
Missouri
Montana
New
Hampshire
Bill
Maryland Healthy Air
Act
310CMR7.29
Part 15. Emission
Limitations and
Prohibitions - Mercury
Minnesota Hg
Emission Reduction
Act
10CSR 10-6.350
Montana Mercury
Rule Adopted
10/16/06
RSA 125-0: 11-18
Emission
Type
NOX
S02
Hg
NOX
S02
Hg
Hg
Hg
NOX
Hg
Hg
Emission Specifications
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 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.
201 3 onwards: 1 7.9 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.
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
1 .5 Ibs/MWh annual GPS for Bayton Point, Mystic
Generating Station, Somerset Station, Mount Tom,
Canal, and Salem Harbor
3.0 Ibs/MWh annual GPS for Bayton Point, Mystic
Generating Station, Somerset Station, Mount Tom,
Canal, and Salem Harbor
2012: 85% removal of Hg content of fuel or
0.00000625 Ibs/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 Ibs/MWh annual GPS for Brayton Point,
Mystic Generating Station, Somerset Station, Mount
Tom, Canal, and Salem Harbor
90% removal of Hg content of fuel annually for all
coal units > 25 MW
90% removal of Hg content of fuel annually for all
coal units > 250 MW
0.25 Ibs/MMBtu annual rate limit for all fossil fuel
units > 25 MW in the following counties: Bellinger,
Butler, Cape Girardeau, Carter, Clark, Crawford,
Dent, Dunklin, Gasconade, Iron, Lewis, Lincoln,
Madison, Marion, Mississippi, Montgomery, New
Madrid, Oregon, Pemiscot, Perry, Phelps, Pike,
Rails, Reynolds, Ripley, St. Charles, St. Francois,
Ste. Genevieve, Scott, Shannon, Stoddard, Warren,
Washington and Wayne
0.18 Ibs/MMBtu annual rate limit for all fossil fuel
units > 25 MWthe following counties: City of St.
Louis, Franklin, Jefferson, and St. Louis
0.35 Ibs/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
0.90 Ibs/TBtu annual rate limit for all non-lignite coal
units
1 .50 Ibs/TBtu annual rate limit for all lignite coal
units
80% reduction of aggregated Hg content of the coal
burned at the facilities for Merrimack Units 1 & 2 and
Schiller Units 4, 5, &6
Implementation
Status
2009
2006
2015
2008
2004
2010
2012
-------
State/Region
New Jersey
New York
North Carolina
Oregon
Bill
ENV-A2900 Multiple
pollutant annual
budget trading and
N.J.A.C. 7:27-27.5,
27.6, 27.7, and 27.8
N.J. A. C. Title 7,
Chapter 27,
Subchapter 19, Table
1
N.J. A. C. Title 7,
Chapter 27,
Subchapter 19, Table
4
Part 237
Part 238
Mercury Reduction
Program for Coal-
Fired Electric Utility
Steam Generating
Units
MP Plasm
Smokestacks Act:
Statute 143-21 5. 107D
Oregon Administrative
Rules, Chapter 345,
Division 24
Emission
Type
NOX
S02
Hg
NOX
NOX
NOX
SO2
Hg
NOX
SO2
CO2
Emission Specifications
2.90 MTons summer cap for all fossil steam units >
250 MMBtu/hr operated at any time in 1 990 and all
new units > 15 MW
3.64 MTons annual cap for Merrimack 1 & 2,
Newington 1 , and Schiller 4 through 6
7.29 MTons annual cap for Merrimack 1 & 2,
Newington 1 , and Schiller 4 through 6
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
2009 - 201 2 annual rate limits in Ibs/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
201 3 & 201 4 annual rate limits in Ibs/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 Ibs/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
2.2 Ibs/MWh annual GPS for gas-burning simple
cycle combustion turbine units
3.0 Ibs/MWh annual GPS for oil-burning simple
cycle combustion turbine units
1 .3 Ibs/MWh annual GPS for gas-burning combined
cycle CT or regenerative cycle CT units
2.0 Ibs/MWh annual GPS for oil-burning combined
cycle CT or regenerative cycle CT units
39.91 MTons non-ozone season cap for fossil fuel
units > 25 MW
1 31 .36 MTons annual cap for fossil fuel units > 25
MW
786 Ibs annual cap through 201 4 for all coal fired
boiler or CT units >25 MW after Nov. 1 5, 1 990.
0.60 Ibs/TBtu annual rate limit for all coal units > 25
MW developed after Nov. 15 1990
25 MTons annual cap for Progress Energy coal
plants > 25 MW and 31 MTons annual cap for Duke
Energy coal plants > 25 MW
2012: 100 MTons annual cap for Progress Energy
coal plants > 25 MW and 1 50 MTons annual cap for
Duke Energy coal plants > 25 MW
2013 onwards: 50 MTons annual cap for Progress
Energy coal plants > 25 MWand 80 MTons annual
cap for Duke Energy coal plants > 25 MW
675 Ibs/MWh annual rate limit for new combustion
turbines burning natural gas with a CF >75% and all
new non-base load plants (with a CE <= 75%)
emitting CO2
Implementation
Status
2007
2007
2009
2007
2004
2005
2010
2007
2009
1997
-------
State/Region
Pacific
Northwest
Texas
Utah
Wisconsin
Bill
Oregon Utility
Mercury Rule -
Existing Units
Oregon Utility
Mercury Rule -
Potential Units
Washington State
House Bill 31 41
Senate Bill 7 Chapter
101
Chapter 117
R307-424 Permits:
Mercury
Requirements for
Electric Generating
Units
NR 428 Wisconsin
Administration Code
Emission
Type
Hg
Hg
CO2
SO2
NOX
NOX
Hg
NOX
Emission Specifications
90% removal of Hg content of fuel reduction or 0.6
Ibs/TBtu limitation for all existing coal units >25 MW
25 Ibs rate limit for all potential coal units > 25 MW
$1 .45/Mton cost (2004$) for all new fossil-fuel power
plant
273.95 MTons cap of SO2 for all grandfathered units
built before 1971 in East Texas Region
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
East and Central Texas annual rate limits in
Ibs/MMBtu for units that came online before 1 996:
Gas fired units: 0.14
Coal fired units: 0.165
Stationary gas turbines: 0.14
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 Ibs/MMBtu or 0.50 Ibs/MWh output or 0.0033
Ibs/MMBtu on system wide heat input weighted
average for large utility systems
0.06 Ibs/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 Ibs/MMBtu
90% removal of Hg content of fuel annually for all
coal units > 25 MW
Annual rate limits in Ibs/MMBtu for coal fired boilers
> 1,OOOMMBtu/hr:
Wall fired, tangential fired, cyclone fired, and
fluidized bed: 2009: 0.15, 2013 onwards: 0.10
Arch fired: 2009 onwards: 0.18
Annual rate limits in Ibs/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
Implementation
Status
2012
2009
2004
2003
2007
2013
2009
-------
State/Region
Bill
Chapter NR 446.
Control of Mercury
Emissions
Emission
Type
Hg
Emission Specifications
Annual rate limits for CTs in Ibs/MMBtu:
Natural gas CTs > 50 MW: 0.1 1
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 Ibs/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 1 0 and 24 MW: 0.1 9
2012 through 2014: 40% reduction in total Hg
emissions for all coal-fired units in electric utilities
with annual Hg emissions > 100 Ibs
2015 onwards: 90% removal of Hg content of fuel or
0.0080 Ibs/GW-hr reduction in coal fired EGUs >
150MW
80% removal of Hg content of fuel or 0.0080
Ibs/GW-hr reduction in coal fired EGUs > 25 MW
Implementation
Status
2010
Notes:
Updates to the EPA Base Case v4.10_PTox from EPA Base Case 4.10 include the following:
1) An update of the modeling of SO2 rate limits in Connecticut
2) An update of the modeling of the effective dates of various controls on units in Georgia
3) Addition of two Kansas State Law unit-specific constraints
4) An update of the modeling of NOX rate limits in Louisiana
5) An update of the modeling of the NOX annual and summer caps and SO2 annual cap in Maryland
6) An update of the modeling of the NOX rate limits in New Jersey
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Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v4.10_PTox, Mar2011
Company
and Plant
State
Unit
Settlement Actions
Retire/Repower
Action
Alabama Power
JamesH.
Miller
Alabama
Units 3
&4
Effective
Date
SOz control
Equipment
Percent
Removal
or Rate
Effective
Date
NOX Control
Equipment
Rate
Effective
Date
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
Install and
operate
FGD
continuously
95%
12/31/11
Operate
existing SCR
continuously
0.1
05/01/08
0.03
12/31/06
With 45 days of
entry, ARC
must retire
7,538 SO2
emission
allowances.
ARC shall not
exchange any
Plant Miller
excess SO2
emission
outside of the
ARC system
1/1/21
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/alab am apower.htm I
Minnkota Power Cooperative
Beginning 1/01/2006, Minnkota shall not emit more than 31, 000 tons of SC>2/year, no more than 26,000 tons beginning 2011, no more than 11, 500 tons beginning 1/01/2012. If Unit 3 is not operational by 12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500.
Milton R.
Young
Minnesot
a
Unit 1
Unit 2
Install and
continuously
operate
FGD
Design,
upgrade,
and
continuously
operate
FGD
wet FGD,
90% if dry
90%
12/31/11
12/31/10
Install and
continuously
operate
Over-fire
AIR, or
equivalent
technology
with
emission
rate < .36
Install and
continuously
operate
over-fire
AIR, or
equivalent
technology
with
emission
rate < .36
0.36
0.36
12/31/09
12/31/07
0.03 if
wet FGD,
.015 if
dry FGD
0.03
Before
2008
Plant will
surrender 4,346
allowances for
each year 2012
-2015,8,693
allowances for
years 201 6 -
2018,12,170
allowances for
year 2019, and
14,886
allowances/ year
thereafter if
Units 1-3 are
operational by
12/31/2015. If
only Units 1 and
2 are
operational
by1 2/31/201 5,
the plant shall
retire 17,886
units in 2020
and thereafter.
Minnkota shall
not sell or
trade NO,
allowances
allocated to
Units 1,2, or 3
that would
otherwise be
available for
sale or trade
as a result of
the actions
taken by the
settling
defendants to
comply with
the
requirements
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/minnkota.html
SIGECO
Unit 1
Unit 2
Unit 3
Repow
erto
natural
gas (or
retire)
12/31/06
continuously
operate
existing
FGD
Units 2 and
3)
Improve and
continuously
95%
95%
06/30/04
06/30/04
Operate
Existing
0.1
09/01/03
Install and
continuously
0.015
06/30/07
The provision
did not specify
an amount of
SO2 allowances
surrendered. It
only provided
allowances
resulting from
compliance with
NSR settlement
be retired.
http://www.epa.gov/complia
aa/si gecofb.htm I
-------
Company
and Plant
State
Unit
Settlement Actions
Retire/Repower
Action
Effective
Date
SOz control
Equipment
operate
existing
FGD
(shared by
Units 2 and
3)
Percent
Removal
or Rate
Effective
Date
NOX Control
Equipment
SCR
Continuously
Rate
Effective
Date
PM or Mercury Control
Equipment Rate EffJ«^
operate a
Baghouse
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
PSEG FOSSIL
Bergen
Hudson
Mercer
New
Jersey
New
Jersey
New
Jersey
Unit 2
Unit 2
Units 1
&2
Repow
erto
combin
ed
cycle
12/31/02
Install Dry
FGD (or
approved
alt.
technology)
and
continually
operate
Install Dry
FGD (or
approved
alt.
technology)
and
continually
operate
0.15
0.15
12/31/06
12/31/10
Install SCR
(or approved
tech) and
continually
operate
Install SCR
(or approved
tech) and
continually
operate
0.1
0.13
05/01/07
05/01/06
(ofafproved °-°15 12/31™
technology)
The provision
did not specify
an amount of
SC>2 allowances
to be
surrendered. It
only provided
that excess
allowances
resulting from
compliance with
NSR settlement
provisions must
be retired.
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/p segllc.html
TECO
Big Bend
Gannon
Florida
Florida
Units 1
&2
Units
Unit 4
Six
units
Retire
all six
coal
units
and
repow
erat
least
550
MWof
coal
capacit
y to
natural
gas
12/31/04
Existing
Scrubber
(shared by
Units 1 & 2)
Existing
Scrubber
(shared by
Units 3 & 4)
Existing
Scrubber
(shared by
Units 3 & 4)
95%
(95% or
.25)
93% if
Units 3 &
4 are
operating
93% if
Units 3 &
4 are
operating
09/1/00
(01/01/13)
2000
(01/01/10)
06/22/05
Install SCR
Install SCR
Install SCR
0.1
0.1
0.1
05/01/09
05/01/09
07/01/07
The provision
did not specify
an amount of
SC>2 allowances
to be
surrendered. It
only provided
that excess
allowances
resulting from
compliance with
NSR settlement
provisions must
be retired.
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/teco.html
WEPCO
WEPCO shall comply with the following system wide average NOK em sson rates and total NOX tonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31, 500 tons, by 1/1/2007 an emission rate of 0.19 and 23, 400 tons, and by 1/1/2013 an emission rate of 0.17 and 17, 400
tons. ForSO2 emissions, WEPCO will comply with: by 1/1/2005 an em ssion rate of 0.76 and 86, 900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55, 400 tons, and by 1/1/201 3 an emission rate of 0.32 and 33,300 tons.
http://www.epa.gov/complia
nce/resources/cases/civil/c
10
-------
Company
and Plant
Presque Isle
Pleasant
Prairie
Oak Creek
Port
Washington
Valley
State
Wisconsi
n
Wisconsi
n
Wisconsi
n
Wisconsi
n
Wisconsi
n
Unit
Units 1
-4
Units 5
&6
Units 7
&8
Unit 9
1
2
Units 5
&6
Unit 7
Units
Units 1
-4
Boilers
1 -4
Settlement Actions
Retire/Repower
Action
Retire
or
install
S02
and
NO,
control
s
Retire
Effective
Date
12/31/12
12/31/04
for Units 1
-3. Unit 4
by entry of
consent
decree
SOz control
Equipment
Install and
continuously
operate
FGD (or
approved
equiv. tech)
Install and
continuously
operate
FGD (or
approved
control tech)
Install and
continuously
operate
FGD (or
approved
control tech)
Install and
continuously
operate
FGD (or
approved
control tech)
Install and
continuously
operate
FGD (or
approved
control tech)
Install and
continuously
operate
FGD (or
approved
control tech)
Percent
Removal
or Rate
95% or
0.1
95% or
0.1
95% or
0.1
95% or
0.1
95% or
0.1
95% or
0.1
Effective
Date
12/31/12
12/31/06
12/31/07
12/31/12
12/31/12
12/31/12
NOX Control
Equipment
Install SCR
(or approved
tech) and
continually
operate
Install and
operate low
NOX burners
Operate
existing low
NOX burners
Operate
existing low
NOX burners
Install and
continuously
operate SCR
(or approved
tech)
Install and
continuously
operate SCR
(or approved
tech)
Install and
continuously
operate SCR
(or approved
tech)
Install and
continuously
operate SCR
(or approved
tech)
Install and
continuously
operate SCR
(or approved
tech)
Operate
existing low
NOK burner
Rate
0.1
0.1
0.1
0.1
0.1
0.1
Effective
Date
12/31/12
12/31/03
12/31/05
12/31/06
12/31/06
12/31/03
12/31/12
12/31/12
12/31/12
30 days
after entry
of consent
decree
PM or Mercury Control
Equipment
Install
Baghouse
Install
Baghouse
Rate
Effective
Date
Allowance
Retirement
Retirement
The provision
did not specify
an amount of
SO2 allowances
to be
surrendered. It
only provided
that excess
allowances
resulting from
compliance with
NSR settlement
provisions must
be retired.
Allowance
Restriction
Restriction
Effective Date
Reference
aa/wepco.html
VEPCO
The Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81 ,000 in 2007, 63,000 in 2008 - 2010, 54,000 in 201 1, 50,000 in 2012, and 30,250 each year thereafter. Beginning 1/1/2013 they will have
a system wide emission rate no greater than 0.15 Ib/mmBtu.
11
-------
Company
and Plant
Mount Storm
Chesterfield
Chesapeake
Energy
Clover
Possum
Point
State
West
Virginia
Virginia
Virginia
Virginia
Virginia
Unit
Units 1
-3
Unit 4
Units
Unite
Units 3
&4
Units 1
&2
Units 3
&4
Settlement Actions
Retire/Repower
Action
Retire
and
repow
erto
natural
gas
Effective
Date
05/02/03
SOz control
Equipment
Construct or
improve
FGD
Construct or
improve
FGD
Construct or
improve
FGD
Improve
FGD
Percent
Removal
or Rate
95% or
0.15
95% or
0.13
95% or
0.13
95% or
0.13
Effective
Date
01/01/05
10/12/12
01/01/10
09/01/03
NOX Control
Equipment
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Rate
0.11
0.1
0.1
0.1
0.1
Effective
Date
01/01/08
01/01/13
01/01/12
01/01/11
01/01/13
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
On or before
March 31 of
every year
beginning in
2013 and
continuing
thereafter,
VEPCO shall
surrender
45,000 SO2
allowances.
Allowance
Restriction
Restriction
Effective Date
Reference
Santee Cooper
Santee Cooper shall comply wth the follow ng system wide averages for NOK emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000 tons, by 1/1/2007 an emission rate of 0.18 and 25, 000 tons, by 1/1/2010 and
emission rate of 0.15 and 20, 000 tons. For SC>2 emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85,000 tons, by 1/1/2009 an emission rate of 0.53 and 70 tons, and
by 1/1/201 1 and emission rate of 0.5 and 65 tons.
Cross
Win yah
Grainger
South
Carolina
South
Carolina
South
Carolina
Unit 1
Unit 2
Unit 1
Unit 2
Unit 3
Unit 4
Unit 1
Upgrade
and
continuously
operate
FGD
Upgrade
and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Upgrade
and
continuously
operate
existing
FGD
Upgrade
and
continuously
operate
existing
FGD
95%
87%
95%
95%
90%
90%
06/30/06
06/30/06
12/31/08
12/31/08
12/31/08
12/31/07
Install and
continuously
operate SCR
Install and
Continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Operate low
NOK burner
or m ore
0.1
0.11/0.1
0.11/0.1
0.12
0.14/0.12
0.13/0.12
05/31/04
05/31/04
and
05/31/07
11/30/04
and
11/30/04
11/30/04
1 1/30/2005
and
11/30/08
11/30/05
and
11/30/08
06/25/04
The provision
did not specify
an amount of
SO2 allowances
to be
surrendered. It
only provided
that excess
allowances
resulting from
compliance with
NSR settlement
provisions must
be retired.
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/santeecooper.html
12
-------
Company
and Plant
Jeffries
State
South
Carolina
Unit
Unit 2
Units
3,4
Settlement Actions
Retire/Repower
Action
Effective
Date
SOz control
Equipment
Percent
Removal
or Rate
Effective
Date
NOX Control
Equipment
stringent
technology
Operate low
NOK burner
or m ore
stringent
technology
Operate low
NOK burner
or m ore
stringent
technology
Rate
Effective
Date
05/01/04
06/25/04
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
Ohio Edison
Ohio Edison shall achieve reductions of 2,483 tons NOX between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1 - 3 during the months of October through April, and/or 3)
emitting fewer tons than the Plant-Wide Annual Cap for NO* required for the Sam mis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2 by 12/31/2010.
No later than 8/11/2005, Ohio Edison shall nstall and operate low NO, burners on Samm s Units 1-7 and overtired air on Sam mis 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 NOX
emissions from Sammis Units 1-5.
W.H.
Sammis
Plant
Ohio
Unit 1
Unit 2
Unit 3
Unit 4
Unit 5
Install
Induct
Scrubber (or
approved
equiv.
control tech)
Install
Induct
Scrubber (or
approved
equiv.
control tech)
Install
Induct
Scrubber (or
approved
equiv.
control tech)
Install
Induct
Scrubber (or
approved
equiv.
control tech)
Install Flash
Dryer
Absorber
or ECO2 (or
approved
equiv.
control tech)
50%
rem oval
or 1.1
Ib/mmBtu
50%
rem oval
or 1.1
Ib/mmBtu
50%
rem oval
or 1.1
Ib/mmBtu
50%
rem oval
or 1.1
Ib/mmBtu
50%
rem oval
or 1.1
Ib/mmBtu
12/31/08
12/31/08
12/31/08
06/30/09
06/29/09
Install SNCR
(or approved
alt. tech) &
operate
continuously
Operate
existing
SNCR
continuously
Operate low
NO* burners
and overfire
air by
12/1/05;
install SNCR
(or approved
alt. tech) &
operate
continuously
by 12/31/07
Install SNCR
(or approved
alt. tech) &
operate
continuously
Install SNCR
(or approved
alt. tech) &
Operate
Continuously
0.25
0.25
0.25
0.25
0.29
10/31/07
02/15/06
12/01/05
and
10/31/07
10/31/07
03/31/08
Beginning on
1/1/2006, Ohio
Edison may
use, sell or
transfer any
restricted SO2
only to satisfy
the Operational
Needs at the
Sammis, Burger
and Mansfield
Plant, or new
units within the
FirstEnergy
System that
comply with a
96% removal
for SO2. For
calendar year
2006 through
2017, Ohio
Edison may
accumulate SO2
allowances for
use at the
Sammis,
Burger, and
Mansfield
plants, or
FirstEnergy
units equipped
with SO2
Emission
Control
Standards.
Beginning in
2018, Ohio
Edison shall
surrender
unused
restricted SO2
allowances.
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/ohioedison.html
13
-------
Company
and Plant
Mansfield
Plant
Eastlake
Burger
State
Pennsylv
ania
Ohio
Ohio
Unit
Unite
Unit 7
Unit 1
Unit 2
Units
Units
Unit 4
Unit 5
Settlement Actions
Retire/Repower
Action
Repow
er with
at least
80%
biomas
sfuel,
up to
20%
low
sulfur
coal.
Effective
Date
12/31/11
12/31/11
SOz control
Equipment
&
operate
continuously
Install FGDJ
(or
approved
equiv.
control tech)
&
operate
continuously
Install FGD
(or
approved
equiv.
control tech)
&
operate
continuously
Upgrade
existing
FGD
Upgrade
existing
FGD
Upgrade
existing
FGD
Percent
Removal
or Rate
95%
rem oval
or 0.1 3
Ib/mmBtu
95%
rem oval
or 0.1 3
Ib/mmBtu
95%
95%
95%
Effective
Date
06/30/1 1
06/30/1 1
12/31/05
12/31/06
10/31/07
NOX Control
Equipment
Install SNCR
(or approved
alt. tech) &
operate
continuously
Operate
existing
SNCR
Continuously
Install low
NOx
burners,
over-fired
air and
SNCR&
operate
continuously
Rate
"Minimum
Extent
Practicabl
e"
"Minimum
Extent
Practicabl
e"
"Minimize
Emissions
to the
Extent
Practicabl
e"
Effective
Date
06/30/05
08/1 1/05
12/31/06
PM or Mercury Control
Equipment
Operate
Existing
ESP
Continuously
Operate
Existing
ESP
Continuously
Rate
0.03
0.03
Effective
Date
01/01/10
01/01/10
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
Mirantl1'6
System-wide NOK Emission Annual Caps: 36,500 tons 2004; 33, 840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22, 000 tons 2008; 19,650 tons 2009; 16, 000 tons 2010 onward. System-wide NOK Emission Ozone Season Caps: 14, 700 tons 2004; 13,340 tons 2005; 12,590
tons 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 Ib/mmBtu NOX.
Potomac
River Plant
Virginia
Unit 1
Unit 2
Units
Install low
NOx
burners (or
more
effective
tech) &
05/01/04
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/mirant.html
14
-------
Company
and Plant
Morgantown
Plant
Chalk Point
State
Maryland
Maryland
Unit
Unit 4
Unit 5
Unit 1
Unit 2
Unit 1
Unit 2
Settlement Actions
Retire/Repower
Action
Effective
Date
SOz control
Equipment
Install and
continuously
operate
FGD (or
equiv.
technology)
Install and
continuously
operate
FGD (or
equiv.
technology)
Percent
Removal
or Rate
95%
95%
Effective
Date
06/01/10
06/01/10
NOX Control
Equipment
operate
continuously
Install low
NOX
burners (or
more
effective
tech) &
operate
continuously
Install low
burners (or
more
effective
tech) &
operate
continuously
Install SCR
(or approved
alt. tech) &
operate
continuously
Install SCR
(or approved
alt. tech) &
operate
continuously
Rate
0.1
0.1
Effective
Date
05/01/04
05/01/04
05/01/07
05/01/08
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
For each year
after Mi rant
commences
FGD operation
at Chalk Point,
Mi rant shall
surrender the
number of SO2
Allowances
equal to the
amount by
which the SO2
Allowances
allocated to the
Units at the
Chalk Point
Plant are
greater than the
total amount of
SO2 emissions
allowed under
this Section
XVIII.
Allowance
Restriction
Restriction
Effective Date
Reference
Illinois Power
System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 - 2006; 65,000 tons 2007; 62,000 tons 2008 - 2010; 57,000 tons 201 1 ; 49,500 tons 2012; 29,000 tons 2013
onward .
Baldwin
Illinois
Units 1
&2
Install wet
or dry FGD
(or
approved
equiv. alt.
tech) &
operate
continuously
0.1
12/31/11
Operate
OFA&
existing SCR
continuously
0.1
08/1 1/05
Install &
continuously
operate
Baghouse
0.015
12/31/10
By year end
2008, Dynergy
will surrender
12,OOOSO2
emission
allowances, by
year end 2009 it
will surrender
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/illinoi spower.htm I
15
-------
Company
and Plant
Havana
Hennepm
Vermilion
Wood River
State
Illinois
Illinois
Illinois
Illinois
Unit
Units
Unit 6
Unit 1
Unit 2
Units 1
&2
Units 4
&5
Settlement Actions
Retire/Repower
Action
Effective
Date
SOz control
Equipment
Install wet
or dry FGD
(or
approved
equiv. alt.
tech) &
operate
continuously
Install wet
or dry FGD
(or
approved
equiv. alt.
tech) &
operate
continuously
Percent
Removal
or Rate
0.1
1.2
Ib/mmBtu
until
12/30/201
2; 0.1
Ib/mmBtu
from
12/31/201
2 onward
1.2
1.2
1.2
1.2
Effective
Date
12/31/11
08/1 1/05
and
12/31/12
07/27/05
07/27/05
01/31/07
07/27/05
NOx Control
Equipment
Operate
OFA and/or
lowNOx
burners
Operate
OFA and/or
lowNOx
burners &
operate
existing SCR
continuously
Operate
OFA
and/or low
NO* burners
Operate
OFA
and/or low
NOX burners
Operate
OFA
and/or low
NO* burners
Operate
OFA
and/or low
NOX burners
Rate
0.12 until
12/30/12;
0.1 from
12/31/12
0.1
"Minimum
Extent
Practicabl
e"
"Minimum
Extent
Practicabl
e"
"Minimum
Extent
Practicabl
e"
"Minimum
Extent
Practicabl
e"
Effective
Date
and
08/1 1/05
08/1 1/05
08/1 1/05
08/1 1/05
08/1 1/05
PM or Mercury Control
Equipment
Install &
continuously
operate
Baghouse
Install &
continuously
operate
Baghouse,
then install
ESP or alt.
PM equip
Install ESP
(or equiv. alt.
tech) &
continuously
operate
ESPs
Install ESP
(or equiv. alt.
tech) &
continuously
operate
ESPs
Install ESP
(or equiv. alt.
tech) &
continuously
operate
ESPs
Install ESP
(or equiv. alt.
tech) &
continuously
operate
ESPs
Rate
0.015
For Bag-
house:
0.015
Ib/mmBtu
;For
ESP:
0.03
Ib/mmBtu
0.03
0.03
0.03
0.03
Effective
Date
12/31/10
For
Baghouse:
12/31/12;
For ESP:
12/31/05
12/31/06
12/31/06
12/31/10
12/31/05
Allowance
Retirement
Retirement
18,000, by year
end 201 Oil will
surrender
24,000, any by
year end 2011
and each year
thereafter it will
surrender
30,000
allowances. If
the surrendered
allowances
result in
insufficient
remaining
allowances
allocated to the
units
comprising the
DMG system,
DMG can
request to
surrender fewer
allowances.
Allowance
Restriction
Restriction
Effective Date
Reference
Kentucky Utilities Company
EW Brown
Generating
Station
Kentucky
Units
Install FGD
97% or
0.100
12/31/10
continuously
by
12/31/2012,
continuously
operate low
and OFA.
0.07
12/31/12
Continuously
operate ESP
0.03
12/31/10
KU must
surrender
53,000 SO2
2008 or earlier
vintage by
March 1,2009.
All surplus NOx
allowances
must be
surrendered
through 2020.
SO2 and NO,
allowances
may not be
compliance,
and emissions
decreases for
purposes of
complying with
the Consent
Decree do not
earn credits.
httD://www.eDa.aov/comolia
nce/resources/cases/civil/c
aa/ku com p an v. htm I
Salt River Project Agricultural Improvement and Power District (SRP)
Coronado
Generating
Station
Arizona
Unit 1
or Unit
2
Immediately
begin
continuous
operation of
existing
FGDs on
both units,
install new
95% or
0.08
New FGD
installed
by
1/1/2012
Install and
continuously
operate low
NOK burner
0.32 prior
to SCR
installation
, 0.080
LNB by
06/01/2009
, SCR by
06/01/2014
Optimization
and
continuous
operation of
existing
ESPs.
0.03
Optimizatio
n begins
im medial el
y, rate limit
begins
01/01/12
(date of
new FGD
Beginning in
2012, all
surplus SO2
allowances for
both Coronado
and
Springerville
Unit 4 must be
SO2 and NOK
allowances
may not be
used for
compliance,
and emissions
decreases for
purposes of
httD://www.eDa.aov/comolia
nce/resources/cases/civil/c
aa/srp.html
16
-------
Company
and Plant
State
Unit
Unit 1
or Unit
2
Settlement Actions
Retire/Repower
Action
Effective
Date
SOz control
Equipment
FGD.
Install new
FGD
Percent
Removal
or Rate
95% or
0.08
Effective
Date
01/01/13
NOX Control
Equipment
Install and
continuously
operate low
NOK burner
Rate
0.32
Effective
Date
06/01/1 1
PM or Mercury Control
Equipment
Rate
Effective
Date
installation
)
Optimizatio
n begins
im medial el
y, rate limit
begins
01/01/13
(date of
new FGD
installation
)
Allowance
Retirement
Retirement
surrendered
through 2020.
The allowances
limited by this
condition may,
however, be
used for
compliance at a
prospective
future plant
using BACT
and otherwise
specified in par.
54 of the
consent decree.
Allowance
Restriction
Restriction
complying with
the Consent
Decree do not
earn credits.
Effective Date
Reference
American Electric Power
Eastern System -Wide
At least
eOOMWfrom
various units
West
Virginia
Virginia
Indiana
Sporn
1 -4
Clinch
River
1-3
Tanner
s
Creek
1-3
Retire,
retrofit,
or re-
power
12/31/18
Annual
Cap
(tons)
450,000
450,000
420,000
350,000
340,000
275,000
260,000
235,000
184,000
174,000
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019 and
thereafter
Annual
Cap (tons)
96,000
92,500
92,500
85,000
85,000
85,000
75,000
72,000
Year
2009
2010
2011
2012
2013
2014
2015
2016 and
thereafter
NO, and SO2
allowances that
would have
been made
available by
emission
reductions
pursuant to the
Consent
Decree must be
surrendered.
NO x and SO2
allowances
may not be
used to comply
with any of the
limits imposed
by the Consent
Decree. The
Consent
Decree
includes a
formula for
calculating
excess NO,,
allowances
relative to the
CAIR
Allocations,
and restricts
the use of
some. See par.
74-79 for
details.
Reducing
emissions
below the
Eastern
System -Wide
Annual
Tonnage
Limitations for
NO x and SO2
earns
supercomplian
ce allowances.
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/americanelectricpower1
007.html
17
-------
Company
and Plant
Amos
Big Sandy
Cardinal
Clinch River
Conesville
State
West
Virginia
West
Virginia
Kentucky
Ohio
Virginia
Ohio
Unit
Kamm
er
1-3
Unit 1
Unit 2
Unit 3
Unit 1
Unit 2
Unit 1
Unit 2
Unit 3
Units
1-3
Unit 1
Unit 2
Units
Unit 4
Settlement Actions
Retire/Repower
Action
Retire,
retrofit,
or re-
power
Retire,
retrofit,
or re-
power
Retire,
retrofit,
or re-
power
Effective
Date
Date of
entry
Date of
entry
12/31/12
SOz control
Equipment
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Burn only
coal with no
more than
1.75
Ib/MMBtu
annual
average
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
Percent
Removal
or Rate
Plant-
wide
annual
cap:
21,700
tons from
2010 to
2014,
then
16,300
after
1/1/2015
Effective
Date
12/31/09
12/31/10
12/31/09
Date of
entry
12/31/15
12/31/08
12/31/08
12/31/12
2010-
2014,
2015 and
thereafter
12/31/10
NOX Control
Equipment
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Continuously
operate low
NOX burners
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Continuously
operate low
NOX burners
Install and
continuously
operate SCR
Rate
Effective
Date
01/01/08
01/01/09
01/01/08
Date of
entry
01/01/09
01/01/09
01/01/09
01/01/09
Date of
entry
12/31/10
PM or Mercury Control
Equipment
Continuously
operate ESP
Continuously
operate ESP
Rate
0.03
0.03
Effective
Date
12/31/09
12/31/09
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
-
-
-
-
-
-
-
-
-
18
-------
Company
and Plant
Gavin
Glen Lyn
Kammer
Kan awn a
River
Mitchell
Mountaineer
Muskingum
River
Picway
State
Ohio
Virginia
West
Virginia
West
Virginia
West
Virginia
West
Virginia
Ohio
Ohio
Unit
Units
Unit 6
Unit 1
Unit 2
Units
1-3
Units
Units
1-3
Units
1,2
Unit 1
Unit 2
Unit 1
Units
1 -4
Unit 5
Unit 9
Settlement Actions
Retire/Repower
Action
Retire,
retrofit,
or re-
power
Effective
Date
12/31/15
SOz control
Equipment
FGD
Upgrade
existing
FGD
Upgrade
existing
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Burn only
coal with no
more than
1.75
Ib/MMBtu
annual
average
Burn only
coal with no
more than
1.75
Ib/MMBtu
annual
average
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD
Percent
Removal
or Rate
95%
95%
Plant-
wide
annual
cap:
35,000
Effective
Date
12/31/09
12/31/09
Date of
entry
Date of
entry
Date of
entry
01/01/10
Date of
entry
12/31/07
12/31/07
12/31/07
12/31/15
NOX Control
Equipment
Continuously
operate low
NOX burners
Continuously
operate low
NO* burners
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Continuously
operate low
NOX burners
Continuously
operate
over-fire air
Continuously
operate low
NOx burners
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Continuously
operate low
NOX burners
Rate
Effective
Date
Date of
entry
Date of
entry
01/01/09
01/01/09
Date of
entry
Date of
entry
Date of
entry
01/01/09
01/01/09
01/01/08
01/01/08
Date of
entry
PM or Mercury Control
Equipment
Continuously
operate ESP
Rate
0.03
Effective
Date
12/31/02
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
-
-
-
-
-
-
-
-
-
-
19
-------
Company
and Plant
Sporn
Tanners
Creek
State
West
Unit
Unit 1
Unit 2
Units
Units
1-3
Unit 4
Settlement Actions
Retire/Repower
Action
Retire,
retrofit,
power
Effective
Date
12/31/13
SOz control
Equipment
Install and
continuously
operate
Install and
continuously
operate
FGD
Burn only
coal with no
more than
1.2
Ib/MMBtu
annual
average
Burn only
coal with no
more than
1.2% sulfur
content
annual
average
Removal
Effective
Date
12/31/17
12/31/19
Date of
entry
Date of
entry
NOX Control
Equipment
continuously
operate SCR
continuously
operate SCR
Continuously
operate low
NOX burners
Continuously
operate
over-fire air
Rate
Effective
Date
12/31/17
12/31/19
Date of
entry
Date of
entry
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
-
East Kentucky Power Cooperative Inc.
By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NO, controls at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/201 2 or 2) retire Dale 3 and Dale 4 by 12/31/2012.
System -wide
System-
wide 12-
month
rolling
tonnage
limits apply
1 2-m onth
rolling
limit
(tons)
57,000
40,000
28,000
Start of
1 2-m onth
cycle
10/01/08
07/01/1 1
01/01/13
All units
must
operate low
NOK boilers
1 2-m onth
rolling limit
(tons)
11,500
8,500
8,000
Start of 12-
month
cycle
01/01/08
01/01/13
01/01/15
PM control
must be
operated
continuously
system-
wide, ESPs
must be
optimized
within 270
days of entry
date, or
EKPC may
submit a PM
pollution
Control
Analysis.
0.03
1 year
from entry
date
All surplus SO2
allowances
must be
surrendered
each year,
beginning in
2008.
SO2 and NO*
allowances
may not be
used to comply
wi e
Decree. NO*
that would
.. . .
It f
compliance
with the
Consent
Decree may
not be sold or
traded. SO2
allowances
allocated to
EKPC must be
EKPC system.
Allowances
made available
due to
supercomplian
ce may be sold
or traded.
http://www.epa.gov/complia
n ce/resou rces/cases/ci vi l/c
aa/n evadapower.htm I
20
-------
Company
and Plant
Spurlock
Dale Plant
Cooper
State
Kentucky
Kentucky
Kentucky
Unit
Unit 1
Unit 2
Unit 1
Unit 2
Units
Unit 4
Unit 1
Unit 2
Settlement Actions
Retire/Repower
Action
EKPC
may
choose
to
retire
DaleS
and 4
in lieu
of
install!
ng
control
s in
Coope
r2
Effective
Date
12/31/2012
SOz control
Equipment
Install and
continuously
operate
FGD
Install and
continuously
operate
FGD by
10/1/2008
If EKPC
opts to
install
controls
rather than
retiring
Dale, it must
Percent
Removal
or Rate
95% or
0.1
95% or
0.1
95% or
0.10
Effective
Date
6/30/2011
1/1/2009
NOX Control
Equipment
Continuously
operate SCR
Continuously
operate SCR
and OFA
Install and
continuously
operate low
NO* burners
by
10/31/2007
Install and
continuously
operate low
NOX burners
by
10/31/2007
If EKPC
elects to
install
controls, it
must
continuously
operate SCR
Rate
0.1 2 for
Unit 1 until
01/01/201
3, at
which
point the
unit limit
drops to
0.1. Prior
to
01/01/201
3, the
combined
average
when both
units are
operating
must be
no more
than 0.1
0.1 for
Unit 2, 0.1
combined
average
when both
units are
operating
0.46
0.46
0.08 (or
90% if
non-SCR
technolog
y is used)
Effective
Date
60 days
after entry
60 days
after entry
01/01/08
01/01/08
12/31/12
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
EKPC must
surrender 1,000
NOX allowances
immediately
under the ARP,
and 3,107
under the NOx
SIP Call. EKPC
must also
surrender
15,311 SO2
allowances.
Allowance
Restriction
Restriction
Effective Date
Date of entry
Reference
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/eastkentuckypower-
dale0907.html
21
-------
Company
and Plant
State
Unit
Settlement Actions
Retire/Repower
Action
Effective
Date
SOz control
Equipment
install and
continuously
operate
FGDor
equiv.
technology
Percent
Removal
or Rate
Effective
Date
NOx Control
Equipment
or install
equiv.
technology
Rate
Effective
Date
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective Date
Reference
Nevada Power Company
Beginning 1/1/2010, combined NOX emissions from Un
Clark
Generating
Station
Nevada
Units
Unite
Unit 7
Units
Units
may
only
fire
natural
gas
:s 5,6,7, and 8 must be no more than 360 tons per year.
Increase
water
injection
immediately,
then install
and operate
ultra-low
NOx burners
(ULNBs)or
equivalent
technology.
In 2009,
Units 5 and
8 may not
emit more
than 180
tons
combined
5ppm 1-
hour
average
5ppm 1-
hour
average
5ppm 1-
hour
average
5ppm 1-
hour
average
12/31/08
(ULNB
installation
), 01/30/09
(1-hour
average)
12/31/09
(ULNB
installation
), 01/30/10
(1-hour
average)
12/31/09
(ULNB
installation
), 01/30/10
(1-hour
average)
12/31/08
(ULNB
installation
), 01/30/09
(1-hour
average)
Allowances
may not be
used to comply
with the
Consent
Decree, and
no allowances
made available
due to
compliance
with the
Consent
Decree may be
traded or sold.
http://www.epa.qov/complia
nce/resources/cases/civil/c
aa/n evadapower.htm I
Dayton Power & Light
Non-EPA Settlement of 10/23/2008
Stuart
Generating
Station
Ohio
Station
-wide
Complete
installation
of FGDs on
each unit.
96% or
0.10
82%
including
data from
periods of
malfuncti
ons
82%
including
data from
periods of
malfuncti
ons
07/31/09
7/31/09
through
7/30/1 1
after
7/31/11
Owners may
not purchase
any new
catalyst with
SO2 to SO3
conversion
rate greater
than 0.5%
Install
control
technology
on one unit
0.17
station-
wide
0.17
station-
wide
0.10 on
any single
unit
0.15
station-
wide
0.10
station-
wide
30 days
after entry
60 days
after entry
date
12/31/12
07/01/12
12/31/14
0.030 Ib
per unit
Install
rigid-type
electro-
des in
each
unit's
ESP
07/31/09
12/31/15
NOx and SO2
allowances
may not be
used to comply
with the
monthly rates
specified in the
Consent
Decree.
Courtlink document
provided by EPA in email
PSEG FOSSIL, Amended Consent Decree of November 2006
22
-------
Company
and Plant
Kearny
Hudson
Mercer
State
New
Jersey
New
Jersey
New
Jersey
Unit
Unit/
Units
Unit 2
Units 1
&2
Settlement Actions
Retire/Repower
Ac,ion **%•
Rue«[e 01/01/07
Rue«[e 01/01/07
SOz control
Equipment
Install Dry
FGD (or
approved
alt.
technology)
and
continually
operate
Install Dry
FGD (or
approved
alt.
technology)
and
continually
operate
Percent
Removal
or Rate
0.15
Annual
Cap
(tons)
5,547
5,270
5,270
5,270
0.15
Effective
Date
12/31/10
Year
2007
2008
2009
2010
12/31/10
NOX Control
Equipment
Install SCR
(or approved
tech) and
continually
operate
Install SCR
(or approved
tech) and
continually
operate
Rate
0.1
Annual
Cap (tons)
3,486
3,486
3,486
3,486
0.1
Effective
Date
12/31/10
Year
2007
2008
2009
2010
01/01/07
PM or Mercury Control
Equipment
Install
Bag house
(or approved
technology)
Install
Bag house
(or approved
technology)
Rate
0.015
0.015
Effective
Date
12/31/10
12/31/10
Allowance
Retirement
Retirement
Allowances
allocated to
Kearny,
Hudson, and
Mercer may
only be used for
the operational
needs of those
units, and all
surplus
allowances
must be
surrendered.
Within 90 days
of amended
Consent
Decree, PS EG
must surrender
1,230 NOx
Allowances and
8,568 SO2
Allowances not
already
allocated to or
generated by
the units listed
here. Kearny
allowances
must be
surrendered
with the
shutdown of
those units.
Allowance
Restriction
Restriction
Effective Date
Reference
http://www.epa.gov/complia
nce/resou rces/d ecrees/am
ended/psegfossil-
amended-cd.pdf
Westar Energy
Jeffrey
Energy
Center
Kansas
All
units
Units 1 , 2, and 3 have a total annual limit
of 6,600 tons of SO2 and an annual rate
limit of 0.07 Ibs/MMBtu starting 2012
Units 1 , 2, and 3 must all insta I FGDs by
2011 and operate them continuously.
FGDs must maintain a 30-Day Rolling
Average Unit Removal Efficiency for SO2
of at least 97% or a 30-Day Ro ling
Average Unit Emission Rate for SO2 of no
greater than 0.070 Ib/MMBtu.
Units 1-3 must continuously operate Low
NOx Combustion Systems by 2012 and
achieve and maintain a 30-Day Rolling
Average Unit Emission Rate for NOx of no
greater than 0.180 Ib/MMBtu.
One of the three units must install an SCR
by 201 5 and operate it continuously to
maintain a 30-Day Rolling Average Unit
Emission Rate for NOx of no greater than
0.080 Ib/MMBtu.
By 201 3 Westar shall elect to either (a)
install a second SCR on one of the other
JEC Units by 2017 or (b) meet a 0.100
Ib/MMBtu Plant-Wide 12-Month Rolling
Average Emiss on Rate and 9.6 MTons
annual cap for NOx by 2015
Units 1, 2, and 3 must operate each ESP
and FGD system continuously by 201 1 and
maintain a 0.030 Ib/MMBtu PM Emissions
Rate.
Units 1 and 2's ESPs must be rebuilt by
2014 in order to meet a 0.030 Ib/MMBtu PM
Emissions Rate
Duke Energy
Gallagher
Indiana
Units 1
&3
Units 2
&4
Retire
rl?°™ 1/1/2012
natural
gas
Install Dry
sorbent
injection
technology
80%
1/1/2012
23
-------
Company
and Plant
State
Unit
Settlement Actions
Retire/Repower
Ac,ion *£«
SOz control
Equipment
Removal
Effective
Date
NOx Control
Equipment
Rate
Effective
Date
PM or Mercury Control
Equipment Rate EffJ«^
Allowance Allowance
Retirement Restriction
Retirement Restriction
American Municipal Power
Station
Units 2
&3
Units 1
&4
Hoosier Energy Rural Electric Cooperat
Ratts
Merom
Indiana
Indiana
Units 1
&2
Unit 1
Unit 2
Elected to Retire Dec
by Dec 31, 201 2)
Effective Date
Reference
http://amppartners.org/new
gorsuch-generating-station/
ve
Continusly
run current
FGDfor
removal and
update FGD
removal by
2012
Continusly
run current
FGDfor
removal and
update FGD
for 98%
removal by
2014
98%
98%
2012
2014
Install &
continually
operate
SNCRS
Continuously
operate
existing
SCRs
0.25
0.12
12/31/2011
Continuously operate ESP
Continuously operate ESP and achieve PM
rate no greater than 0.007 by 6/1/12
Continuously operate ESP and achieve PM
rate no greater than 0.007 by 6/1/13
Annually surrender any NOx and SO2 allowances that
Hoosier does not need in order to meet its regulatory
obligations
httD://www.eDa.aov/comolia
n ce/resou rces/cases/ci vi l/c
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 reguirements on the Mercer plant under the PSEG Fossil settlement, and an update
to the SC>2 emission modeling on Jeffrey Energy Center as part of the Westar settlement.
2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description of all elements of the actual settlement agreements.
3) Settlement actions for which the reguired 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 Base
Case, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire.
4) Some control installations that are reguired by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place are built into EPA Base Case
5) If a settlement agreement reguires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement reguires 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 documentation
7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and corresponding 95% removal efficiency for wet and 90% for dry.
8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate egual to 10% of the unit's uncontrolled rate, with a floor of .06 Ib/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 reguirements of the settlements as they existed on January 1, 2011.
11) Some of the NSR settlements reguirethe retirement of SO2 allowances. EPA estimated the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly.
24
-------
Appendix 3-4 State Settlements in EPA Base Case v4.10_PTox, Mar2011
Company and
Plant
State
Unit
State Enforcement Actions
Retire/Repower
Actio
n
AES
Greenidge
Westover
Hickling
Jennison
New
York
New
York
New
York
New
York
Unit 4
Units
Units
Unit 7
Units 1 &
2
Units 1 &
2
Effective
Date
SO2 control
Equipment
Percent
Removal or
Rate
Effective
Date
NOX Control
Equipment
Rate
Effective
Date
PM Control
Equipment Rate ^a,'™
Mercury Control
Equipment
Rate
Effective
Date
Install FGD
Install BACT
Install BACT
Install BACT
Install BACT
90%
90%
09/01/07
12/31/09
12/31/10
12/31/09
05/01/07
05/01/07
Install SCR
Install BACT
Install SCR
Install BACT
Install BACT
Install BACT
0.15
0.15
09/01/07
12/31/09
12/31/10
12/31/09
05/01/07
05/01/07
Niagara Mohawk Power
NRG shall comply with the below annual tonnage limitat ons for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2 and 1 0,777 tons of NOX, 2006 is 34,230 of SO2 and 6,772 of NOX, 2007 is 30,859 of SO2 and 6,21 1 of NOX, 2008 is 22,733
tons of SO2
Huntley
New
York
Units
63-66
Retire
Public Service Co. of NM
San Juan
New
Mexico
Unitl
Unit 2
Units
Unit 4
B20W
State-of-the-
art
technology
90%
10/31/08
03/31/09
04/30/08
10/31/07
State-of-the-
art
technology
0.3
10/31/08
03/31/09
04/30/08
10/31/07
12/31/09
Operate 12/31/og
Baqhouse and - -,r
demister 04/30/08
technoloav
10/31/07
Design
activated
carbon injection
technology (or
comparable
tech)
12/31/09
12/31/09
04/30/08
10/31/07
Public Service Co of Colorado
Comanche
Colora
do
Units 1 &
2
Units
Install and
operate
FGD
Install and
operate
FGD
0.1
Ib/mmBtu
combined
average
0.1
Ib/mmBtu
07/01/09
Install low-
NOX
emission
controls
Install and
operate
SCR
0.15
Ib/mmBtu
combined
average
0.08
07/01/09
Install and
operate a fabric
filter dust 0.013
collection
system
Install sorbent
injection
technology
Install sorbent
injection
technology
07/01/09
Within 180
days of
start-up
Rochester Gas & Electric
Russell Plant
New
York
Units
1 -4
Retire
all
units
Mirant New York
Lovett Plant
New
York
Unitl
Unit 2
Retire
Retire
05/07/07
04/30/08
Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court of Appeals, Fourth Circuit Court reversing the settlement.
25
-------
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 (HCI) 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 HCI removal and developing associated cost and performance assumptions.
These changes and additions are presented in full below:
5. Emission Control Technologies
• • •
5.3 Coal-to-Gas conversions2
In EPA Base Case v4.10_PTox existing coal plants are given the option to burn natural gas in
addition to coal by investing in a coal-to-gas retrofit. There are two components of cost in this
option: Boiler modification costs and the cost of extending natural gas lateral pipeline spurs
from the boiler to a natural gas main transmission line. These two components of cost and their
associated performance implications are discussed in the following sections.
5.3.1 Boiler Modifications For Coal-To-Gas Conversions
Enabling natural gas firing in a coal boiler typically involves installation of new gas burners and
modifications to the ducting, windbox (i.e., the chamber surrounding a burner through which
pressurized air is supplied for fuel combustion), and possibly to the heating surfaces used to
transfer energy from the exiting hot flue gas to steam (referred to as the "convection pass"). It
may also involve modification of environmental equipment. Engineering studies are performed
to assess operating characteristics like furnace heat absorption and exit gas temperature;
material changes affecting piping and components like superheaters, air (re)heaters,
economizers, and recirculating fans; and operational changes to sootblowers, spray flows, air
heaters, and emission controls.
The following table summarizes the cost and performance assumptions for such boiler
modifications as incorporated in Base Case v4.10_PTox. The values in the table were
developed by EPA's engineering staff based on technical papersS and discussions with industry
engineers familiar with such projects. They were designed to be applicable across the existing
coal fleet.
2 As discussed here coal-to-gas conversion refers to the modification of an existing boiler to allow it to fire
natural gas. It does not refer to the addition of a gas turbine to an existing boiler cycle, the replacement
of a coal boiler with a new natural gas combined cycle plant, or to the gasification of coal for use in a
natural gas combustion turbine.
3 For an example see Babcock and Wilcox's White Paper MS-14 "Natural Gas Conversions of Exiting
Coal-Fired Boilers" 2010 (www.babcock.com/librarv/tech-utility.htmltf14).
26
-------
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)A0.35
Cyclone units: $/kW =
350*(75/MW)A0.35
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)A0.35 = 288
Incremental
Fixed O&M:
-(0.33)*31.1*(75/MW)A0.1
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)A0.2
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 Ibs/MMBtu
The 0.05 Ibs/MMBtu floor is the
same as the NOx rate floor for new
retrofit SCR on units burning
subbituminous coal
SO2 emissions:
Zero
5.3.2 Natural Gas Pipeline Requirements For Coal-To-Gas Conversions
For every individual coal boiler in the U.S., EPA tasked the gas team at ICF International to
27
-------
determine the miles and associated cost of extending pipeline laterals from each boiler to the
interstate natural gas pipeline system.
To develop these costs the following principles were applied:
• For each boiler, gas volume was estimated based on size and heat rate.
• Direct distance to the closest pipeline was calculated. (The analysis only considered
mainlines with diameters that were 16 inches or greater. The lateral distance
represented the shortest distance - "as the crow flies" - between the boiler and the
mainline.)
• Gas volume (per day) of the initial lateral was not allowed to exceed more than 10
percent of the estimated capacity of the mainline.
• The mainline capacities were estimated from the pipe's diameter using the Weymouth
equation4.
• If the gas requirement exceeded 10 percent of the estimated capacity of the mainline,
the cost of a second lateral to connect to the next closest mainline was calculated.
• This procedure was repeated until the entire capacity required for the boiler was
reached.
• Diameters of each lateral were then calculated using the Weymouth equation based on
their required capacities.
• The cost of all the laterals was calculated based on the pipeline diameter and mileage
required. Thus, the final pipeline cost for each boiler was based on the total miles of
laterals required.
Figure 5-1 shows the calculations performed.
Figure 5-1 Calculations Performed in Costing Lateral Pipeline Requirement
Mainline Flow Capacity, Qm (million cubic feet per day)
Qm = 0.06745 * d 2 667, where d is the diameter of the mainline in inches
Required Capacity of Lateral/s for Each Boiler, Qi (million cubic feet per day)
Qi = (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 * Qi) °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.
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.
28
-------
There are several points to note about the approach. First, for relatively large boilers or in
cases where the closest mainline has a relatively small diameter, multiple laterals are required
to connect the boiler to the interstate gas transmission grid. This assures that each individual
boiler will not become a relatively large portion of a pipelines' transmission capacity. It also
reflects real-world practices where larger gas-fired power plants typically have multiple laterals
connecting them to different mainlines. This increases the reliability of their gas supply and
provides multiple options for gas purchase allowing them to capture favorable prices from
multiple sources of gas supply at different points in time.
Second, expansion of mainlines was not included in the boiler specific pipeline cost, because
the integrated gas model within IPM already includes corridor expansion capabilities. However,
if in future IPM runs, multiple converted boilers are concentrated on a single pipeline along a
corridor that includes multiple pipelines, a further assessment may be required to make sure
that the mainline expansion is not being understated due to modeled efficiencies that may not
actually be available in the field.
Figures 5-2 through 5-7 summarize the results of the pipeline costing procedure described
above. They provide histograms of the number of laterals required per boiler (Figure 5-2), miles
of pipeline required per boiler (Figure 5-3), diameters of the laterals in inches (Figure 5-4), total
inch-miles of laterals required per boiler (Figure 5-5), total cost to each boiler in millions (Figure
5-6), and cost (in $) per kW of boiler capacity (Figure 5-7). Table 5-12 gives a consolidated
overview of the information in these figures by showing the minimum, maximum, average, and
median values that appear in the figures. Table 5-13 ("Cost of Building Pipelines to Coal
Plants") shows the pipeline costing results for each qualifying existing coal fired unit represented
in EPA Base Case v4.10 PTox.
Figure 5-2
Number of Laterals Required per Boiler
Number of Laterals
Minimum 1
Maximum S
Average 1.7
Median
456
Number of Laterals
29
-------
Figure 5-3
300
Miles of Pipeline Required per Boiler
Miles per Boiler
Minimum 0.1
Maximum 767.4
Average 57.4
Median 26.2
Otol
Ito5
5 to 10 10 to 25 25 to 50 50 to 100
100 to 200 to 300 to More than
200 300 400 400
Miles of Pipeline
Figure 5-4
Diameter of Laterals, in Inches
Diameter of Laterals
Minimum 1.2
Ma si mum 20.5
Average 9.6
Median 9.2
1 to 2 2 to 4 4 to 6
6 to 8 8 to 10 10 to 12 12 to 14 14 to 16 16 to 18 18 to 20 More
than 20
Diameter of Laterals, in Inches
30
-------
Figure 5-5
Total Inch-Miles of Laterals Required per Boiler
300
-* 25°
(N
Inch-Miles per Boiler
Minimum 1
Maximum 6.B71
Avera ge bii
Median 2DS
Ito
50
50 to 100 to 200 to 400 to 600 to 800 to 1000 1200 1400 1600 1800 2000 3000 4000 More
100 200 400 600 800 1000 to to to to to to to to than
1200 1400 1600 1800 2000 3000 4000 5000 5000
Number of Inch-Miles per Boiler
Figure 5-6
Total Cost to Each Boiler (Million$)
300
Otol
Ito 5
5 to 10 10 to 25 25 to 50 50 to 100
100 to
200
200 to
300
300 to
400
More than
400
Cost Increment (MillionS)
31
-------
Figure 5-7
Cost per kW of Boiler Capacity ($)
$
(N
II
C
u
C
-------
Table 5-13 Cost of Building Pipelines to Coal Plants
UniquelD_Final
3_B_1
3_B_2
3_B_3
3_B_4
3_B_5
7_B_1
7_B_2
8_B_10
8_B_6
8_B_7
8_B_8
8_B_9
10_B_1
10_B_2
26_B_1
26_B_2
26_B_3
26_B_4
26_B_5
47_B_1
47_B_2
47_B_3
47_B_4
Plant Name
Barry
Barry
Barry
Barry
Barry
Gadsden
Gadsden
Gorgas
Gorgas
Gorgas
Gorgas
Gorgas
Greene County
Greene County
E C Gaston
E C Gaston
E C Gaston
E C Gaston
E C Gaston
Colbert
Colbert
Colbert
Colbert
State
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
AL
Coal
Boiler
Capacity
(MW)
138
137
249
362
750
64
66
690
108
109
165
175
254
243
254
256
254
256
861
177
177
177
173
Number
of
Laterals
Required
1
1
2
2
3
1
1
2
1
1
1
1
1
1
1
1
1
1
3
1
1
1
1
Miles of
New
Pipeline
Required
to Hook
Up Unit
(miles)
1
1
8
8
19
29
29
68
8
8
8
8
7
7
23
23
23
23
163
0
0
0
0
Total Cost of
New Pipeline
($)
856,526
854,527
5,243,996
6,578,846
16,808,021
16,488,170
16,913,408
64,804,607
5,481,155
5,362,968
5,940,132
6,126,314
6,058,364
6,006,273
20,296,423
20,549,257
20,403,517
20,416,837
157,432,294
373,331
373,331
373,331
370,044
Cost of New
Pipeline per
KW of Coal
Capacity
($/kW)
6
6
21
18
22
258
256
94
51
49
36
35
24
25
80
80
80
80
183
2
2
2
2
33
-------
47_B_5 Colbert
50_B_1 Widows Creek
50_B_2 Widows Creek
50_B_3 Widows Creek
50_B_4 Widows Creek
50_B_5 Widows Creek
50_B_6 Widows Creek
50_B_7 Widows Creek
50_B_8 Widows Creek
51_B_1 Dolet Hills
56_B_1 Charles R Lowman
56_B_2 Charles R Lowman
56_B_3 Charles R Lowman
59_B_1 Platte
60_B_1 Whelan Energy Center
60_B_2 Whelan Energy Center
87_B_1 Escalante
108_B_SGU1 Holcomb
113_B_1 Cholla
113_B_2 Cholla
113_B_3 Cholla
113_B_4 Cholla
126_B_4 H Wilson Sundt Generating Station
127_B_1 Oklaunion
130_B_1 Cross
130_B_2 Cross
130_B_3 Cross
130_B_4 Cross
136_B_1 Seminole
136 B 2 Seminole
AL
AL
AL
AL
AL
AL
AL
AL
AL
LA
AL
AL
AL
NE
NE
NE
NM
KS
AZ
AZ
AZ
AZ
AZ
TX
SC
SC
SC
SC
FL
FL
459
111
111
111
111
111
111
473
464
650
86
238
238
100
77
220
247
360
110
275
271
380
156
690
620
540
580
600
658
658
2
2
2
2
2
2
2
3
2
4
1
2
2
1
1
1
2
4
1
1
1
2
1
8
2
2
2
2
3
3
4
165
165
165
165
165
165
253
165
32
17
44
44
26
8
8
11
46
28
28
28
58
4
560
240
240
240
240
153
153
3,524,413
76,835,602
76,835,602
77,445,655
77,445,655
73,708,744
73,708,744
156,623,156
138,258,079
24,784,949
11,062,025
30,585,021
30,950,390
17,550,190
4,771,943
6,543,326
5,066,695
26,657,544
18,947,152
26,244,568
26,736,227
47,225,178
3,325,760
324,667,985
224,907,896
216,115,742
217,804,475
214,338,942
123,762,396
122,186,247
8
692
692
698
698
664
664
331
298
38
129
129
130
176
62
30
21
74
172
95
99
124
21
471
363
400
376
357
188
186
34
-------
160_B_2
160_B_3
165_B_1
165_B_2
207_B_1
207_B_2
298_B_LIM1
298_B_LIM2
384_B_71
384_B_72
384_B_81
384_B_82
462_B_55
462_B_59
465_B_3
465_B_4
469_B_1
469_B_2
469_B_3
469_B_4
470_B_1
470_B_2
470_B_3
477_B_5
492_B_5
492_B_6
492_B_7
525_B_H1
525_B_H2
527 B 1
Apache Station
Apache Station
GRDA
GRDA
St Johns River Power Park
St Johns River Power Park
Limestone
Limestone
Joliet29
Joliet29
Joliet29
Joliet29
W N Clark
W N Clark
Arapahoe
Arapahoe
Cherokee
Cherokee
Cherokee
Cherokee
Comanche
Comanche
Comanche
Valmont
Martin Drake
Martin Drake
Martin Drake
Hayden
Hayden
Nucla
AZ
AZ
OK
OK
FL
FL
TX
TX
IL
IL
IL
IL
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
CO
175
175
490
520
626
626
831
858
259
259
259
259
18
25
47
121
115
120
165
388
366
370
750
199
46
77
131
205
300
100
1
1
6
7
3
4
7
7
2
2
2
2
1
1
1
2
2
2
2
2
2
2
4
1
1
2
2
2
3
2
2
2
296
415
212
477
325
325
2
2
2
2
40
40
9
86
74
74
74
74
151
151
463
19
13
127
127
78
123
43
1,297,559
1,277,332
174,657,509
208,730,810
196,013,308
307,121,204
193,623,209
200,701,756
1,347,435
1,162,657
1,248,834
1,162,657
14,508,820
16,328,260
4,410,931
42,752,979
33,550,262
33,924,698
43,357,353
67,384,584
139,124,028
139,986,886
332,375,688
14,716,699
6,642,383
33,893,437
64,243,979
48,661,086
81,937,859
11,535,802
7
7
356
401
313
491
233
234
5
4
5
4
824
656
94
353
292
283
263
174
380
378
443
74
144
440
490
237
273
115
35
-------
564_B_1
564_B_2
568_B_BHB3
593_B_3
593_B_4
594_B_3
594_B_4
602_B_1
602_B_2
628_B_1
628_B_2
628_B_4
628_B_5
641_B_4
641_B_5
641_B_6
641_B_7
642_B_1
642_B_2
643_B_1
643_B_2
645_B_BB01
645_B_BB02
645_B_BB03
645_B_BB04
663_B_B2
667_B_1
667_B_2
676_B_3
703 B 1BLR
Stanton Energy Center
Stanton Energy Center
Bridgeport Station
Edge Moor
Edge Moor
Indian River Generating Station
Indian River Generating Station
Brandon Shores
Brandon Shores
Crystal River
Crystal River
Crystal River
Crystal River
Crist
Crist
Crist
Crist
Scholz
Scholz
Lansing Smith
Lansing Smith
Big Bend
Big Bend
Big Bend
Big Bend
Deerhaven Generating Station
Northside Generating Station
Northside Generating Station
C D Mclntosh Jr
Bowen
FL
FL
CT
DE
DE
DE
DE
MD
MD
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
FL
GA
440
446
372
86
174
153
405
643
643
379
491
722
721
78
78
302
472
49
49
162
195
391
391
364
447
228
275
275
342
713
2
2
3
2
2
1
2
2
2
2
2
2
2
1
1
2
2
1
1
1
1
2
2
2
2
1
3
3
1
2
31
31
43
14
14
65
144
46
46
80
80
80
80
6
6
31
31
13
13
22
22
25
25
25
25
12
205
205
0
83
28,104,431
27,959,515
28,557,342
6,706,484
7,908,368
48,452,569
88,686,140
42,283,145
42,934,049
64,036,264
67,687,999
37,187,321
35,020,225
3,592,115
3,517,484
24,092,073
30,704,144
6,456,489
6,716,660
17,226,194
18,788,587
18,006,544
17,980,144
19,260,622
20,775,229
10,065,696
97,644,692
110,541,549
52,953
83,854,057
64
63
77
78
45
317
219
66
67
169
138
52
49
46
45
80
65
132
137
106
96
46
46
53
46
44
355
402
-
118
36
-------
703_B_2BLR
703_B_3BLR
703_B_4BLR
708_B_1
708_B_2
708_B_3
708_B_4
709_B_1
709_B_2
709_B_3
709_B_4
710_B_MB1
710_B_MB2
727_B_3
728_B_Y1 BR
728_B_Y2BR
728_B_Y3BR
728_B_Y4BR
728_B_Y5BR
728_B_Y6BR
728_B_Y7BR
733_B_1
733_B_2
733_B_3
753_B_ST
856_B_1
856_B_2
856_B_3
861_B_01
861 B 02
Bowen
Bowen
Bowen
Hammond
Hammond
Hammond
Hammond
Harllee Branch
Harllee Branch
Harllee Branch
Harllee Branch
Jack McDonough
Jack McDonough
Mitchell
Yates
Yates
Yates
Yates
Yates
Yates
Yates
Kraft
Kraft
Kraft
Crisp Plant
E D Edwards
E D Edwards
E D Edwards
Coffeen
Coffeen
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
GA
IL
IL
IL
IL
IL
718
902
929
112
112
112
510
266
325
509
507
258
259
96
99
105
112
135
137
352
355
48
52
102
10
112
273
364
340
560
2
3
3
1
1
1
2
2
2
2
2
1
1
1
1
1
1
1
1
2
2
1
1
1
1
2
2
3
3
3
83
212
212
42
42
42
110
60
60
60
60
8
8
67
9
9
9
9
9
23
23
2
2
2
67
61
61
125
103
103
85,497,920
165,111,996
168,510,330
27,538,206
27,345,875
27,384,522
102,098,030
43,475,590
47,552,004
57,310,793
57,554,933
6,833,915
6,833,915
39,746,899
6,092,955
6,250,791
6,402,249
6,719,015
6,756,893
17,743,087
17,648,076
861,799
851,601
1,099,326
20,321,021
13,738,422
46,425,546
85,921,187
68,710,560
82,715,063
119
183
181
246
244
245
200
163
146
113
114
26
26
414
62
60
57
50
49
50
50
18
16
11
2,032
123
170
236
202
148
37
-------
863_B_05 Hutsonville
863_B_06 Hutsonville
864_B_05 Meredosia
867_B_7 Crawford
867_B_8 Crawford
874_B_5 Joliet 9
876_B_1 Kincaid Generation LLC
876_B_2 Kincaid Generation LLC
879_B_51 Powerton
879_B_52 Powerton
879_B_61 Powerton
879_B_62 Powerton
883_B_17 Waukegan
883_B_7 Waukegan
883_B_8 Waukegan
884_B_1 Will County
884_B_2 Will County
884_B_3 Will County
884_B_4 Will County
886_B_19 Fisk Street
887_B_1 Joppa Steam
887_B_2 Joppa Steam
887_B_3 Joppa Steam
887_B_4 Joppa Steam
887_B_5 Joppa Steam
887_B_6 Joppa Steam
889_B_1 Baldwin Energy Complex
889_B_2 Baldwin Energy Complex
889_B_3 Baldwin Energy Complex
891 B 9 Havana
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
76
77
203
213
319
314
584
584
385
385
385
385
100
328
361
151
148
251
510
326
167
167
167
167
167
167
624
629
629
487
2
1
1
1
2
2
2
2
2
2
2
2
1
2
2
1
1
2
3
2
1
1
1
1
1
1
3
3
3
2
67
25
18
19
43
2
11
11
66
66
66
66
15
38
38
4
4
16
27
50
1
1
1
1
1
1
106
106
106
74
18,023,856
14,411,276
15,177,107
16,157,648
31,027,338
1,666,759
8,272,242
8,186,657
60,857,425
59,892,609
60,703,641
59,892,609
10,038,571
29,029,637
30,956,775
3,163,672
3,225,873
6,254,012
19,264,080
37,297,455
868,817
868,052
866,518
865,749
874,899
867,286
79,181,733
81,560,802
83,884,301
66,810,686
237
187
75
76
97
5
14
14
158
156
158
156
100
89
86
21
22
25
38
114
5
5
5
5
5
5
127
130
133
137
38
-------
892_B_1
892_B_2
897_B_1
897_B_2
898_B_4
898_B_5
963_B_31
963_B_32
963_B_33
963_B_4
976_B_123
976_B_4
981_B_3
981_B_4
983_B_1
983_B_2
983_B_3
983_B_4
983_B_5
983_B_6
988_B_U1
988_B_U2
988_B_U3
988_B_U4
990_B_50
990_B_60
990_B_70
991_B_3
991_B_4
991 B 5
Hennepin Power Station
Hennepin Power Station
Vermilion
Vermilion
Wood River
Wood River
Dallman
Dallman
Dallman
Dallman
Marion
Marion
State Line
State Line
Clifty Creek
Clifty Creek
Clifty Creek
Clifty Creek
Clifty Creek
Clifty Creek
Tanners Creek
Tanners Creek
Tanners Creek
Tanners Creek
Harding Street
Harding Street
Harding Street
Eagle Valley
Eagle Valley
Eagle Valley
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IL
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
81
240
84
213
105
383
86
87
199
200
120
170
187
303
217
217
217
217
217
217
145
145
200
500
109
109
435
43
56
62
1
1
1
1
1
2
2
2
2
2
1
2
1
1
2
2
2
2
2
2
2
2
2
2
2
2
2
1
1
1
14
14
9
9
1
50
9
9
9
9
2
5
17
17
73
73
73
73
73
73
34
34
34
34
19
19
19
7
7
7
8,519,227
12,775,378
5,387,282
7,794,565
414,232
31,960,057
2,538,463
3,674,986
6,103,905
5,241,841
1,159,953
3,301,244
13,401,529
16,050,991
46,944,665
46,314,833
46,115,920
46,015,513
45,451,394
45,812,745
16,615,136
15,923,309
20,702,486
29,541,774
8,909,894
8,885,172
15,879,585
3,124,071
3,485,879
3,503,708
105
53
64
37
4
83
30
42
31
26
10
19
72
53
216
213
213
212
209
211
115
110
104
59
82
82
37
73
62
57
39
-------
991_B_6
994_B_1
994_B_2
994_B_3
994_B_4
995_B_7
995_B_8
996_B_11
996_B_4
996_B_5
996_B_6
997_B_12
1001_B_1
1001_B_2
1008_B_1
1008_B_2
1008_B_3
1008_B_4
1010_G_1
1010_G_1A
1010_B_2
1010_B_3
1010_B_4
1010_B_5
1010_B_6
1012_B_2
1012_B_3
1024_B_5
1024_B_6
1032 B 5
Eagle Valley
Petersburg
Petersburg
Petersburg
Petersburg
Bailly
Bailly
Dean H Mitchell
Dean H Mitchell
Dean H Mitchell
Dean H Mitchell
Michigan City
Cayuga
Cayuga
R Gallagher
R Gallagher
R Gallagher
R Gallagher
Wabash River
Wabash River
Wabash River
Wabash River
Wabash River
Wabash River
Wabash River
F B Culley
F B Culley
Crawfordsville
Crawfordsville
Logansport
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
IN
99
232
435
540
545
160
320
110
125
125
125
469
479
473
140
140
140
140
85
189
85
85
85
95
318
90
270
11
13
17
1
3
3
3
3
1
1
1
1
1
1
2
2
2
2
2
2
2
1
1
1
1
1
1
2
2
2
1
1
1
7
49
49
49
49
6
6
9
9
9
9
30
17
17
68
68
68
68
18
18
18
18
18
18
36
17
17
17
17
33
4,193,428
21,334,190
37,186,537
41,499,639
41,426,794
4,734,708
6,131,745
6,215,826
6,467,171
6,298,738
6,290,529
23,673,656
14,422,589
14,501,320
37,331,906
37,021,229
37,073,612
37,331,906
9,993,513
13,544,723
10,865,630
10,562,318
10,734,687
10,957,573
27,172,030
7,809,213
12,236,461
4,869,930
4,869,930
12,027,095
42
92
85
77
76
30
19
57
52
50
50
50
30
31
267
264
265
267
118
72
128
124
126
115
85
87
45
459
387
729
40
-------
1032_B_6
1037_B_2
1037_B_5
1040_B_1
1040_B_2
1043_B_1SG1
1043_B_2SG1
1046_B_1
1046_B_5
1046_B_6
1047_B_2
1047_B_3
1047_B_4
1048_B_2
1058_B_2
1058_B_3
1058_B_4
1058_B_5
1073_B_1
1073_B_2
1073_B_3
1073_B_4
1077_B_1
1077_B_2
1077_B_3
1081_B_7
1081_B_8
1081_B_9
1082_B_1
1082 B 2
Logansport
Peru
Peru
Whitewater Valley
Whitewater Valley
Frank E Ratts
Frank E Ratts
Dubuque
Dubuque
Dubuque
Lansing
Lansing
Lansing
Milton L Kapp
Sixth Street
Sixth Street
Sixth Street
Sixth Street
Prairie Creek
Prairie Creek
Prairie Creek
Prairie Creek
Sutherland
Sutherland
Sutherland
Riverside
Riverside
Riverside
Walter Scott Jr. Energy Center
Walter Scott Jr. Energy Center
IN
IN
IN
IN
IN
IN
IN
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
22
20
12
35
63
122
121
35
30
13
11
37
261
211
14
14
14
14
9
10
42
125
31
31
82
3
3
130
45
88
1
1
1
1
1
2
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
33
35
35
15
15
21
21
5
5
5
55
55
55
12
26
26
26
26
27
27
27
27
13
13
13
9
9
9
7
7
13,630,519
13,581,293
11,360,979
6,598,822
8,261,808
10,457,087
10,319,734
2,208,889
1,972,563
1,467,704
17,428,351
26,822,979
51,934,638
10,197,479
8,461,946
8,917,212
8,917,212
8,917,212
7,326,935
7,746,242
12,682,328
18,508,829
5,431,663
5,478,150
7,308,613
1,543,342
1,543,342
6,507,714
3,490,912
4,579,541
620
679
947
190
132
86
85
62
65
111
1,542
733
199
48
622
656
656
656
805
759
305
149
178
176
89
617
617
50
78
52
41
-------
1082.
1082.
1091.
1091.
1091.
1104.
1122.
1122.
1131.
1131.
1167.
1167.
1167.
1175.
1175.
1217.
1218.
1218.
1239_
1239_
1241.
1241.
1250.
1250.
1250.
1252_
1252.
1295.
1295.
1353 B
B_3
B_4
B_1
B_2
B_3
B_1
B_7
B_8
B_6
B_7
B_7
B_8
B_9
B_6
B_7
_B_2
B_39
B_40
_B_1
_B_2
_B_3
_B_4
_B_5
B_10
_B_9
_B_1
_B_2
BSU1
Walter Scott Jr. Energy Center
Walter Scott Jr. Energy Center
George Neal North
George Neal North
George Neal North
Burlington
Ames Electric Services Power Plant
Ames Electric Services Power Plant
Streeter Station
Streeter Station
Muscatine Plant #1
Muscatine Plant #1
Muscatine Plant #1
Pella
Pella
Earl F Wisdom
Fair Station
Fair Station
Riverton
Riverton
La Cygne
La Cygne
Lawrence Energy Center
Lawrence Energy Center
Lawrence Energy Center
Tecumseh Energy Center
Tecumseh Energy Center
Quindaro
Quindaro
Big Sandy
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
IA
KS
KS
KS
KS
KS
KS
KS
KS
KS
KS
KS
KY
690
800
135
300
515
209
33
70
19
36
22
35
147
15
13
38
23
41
38
54
724
682
48
110
366
129
74
72
111
260
2
3
1
2
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
2
1
1
1
1
2
20
100
6
94
94
56
9
9
11
11
15
15
15
34
34
5
13
13
5
5
38
38
5
5
41
20
20
0
0
13
19,594,759
83,501,145
4,137,763
56,762,413
92,812,290
48,751,365
4,306,424
5,719,317
4,085,397
5,297,932
6,025,405
7,448,934
11,166,673
11,121,998
10,691,186
2,119,776
4,940,202
5,861,900
2,600,912
2,860,706
34,344,062
33,970,202
2,464,647
3,255,157
33,321,767
14,251,148
12,396,350
291,231
350,406
9,325,001
28
104
31
189
180
233
130
82
216
148
276
213
76
741
835
57
211
143
68
53
47
50
51
30
91
110
168
4
3
36
42
-------
1353_B_BSU2
1355_B_1
1355_B_2
1355_B_3
1356_B_1
1356_B_2
1356_B_3
1356_B_4
1357_B_4
1357_B_5
1361_B_5
1363_B_4
1363_B_5
1363_B_6
1364_B_1
1364_B_2
1364_B_3
1364_B_4
1374_B_1
1374_B_2
1378_B_1
1378_B_2
1378_B_3
1379_B_1
1379_B_10
1379_B_2
1379_B_3
1379_B_4
1379_B_5
1379_B_6
Big Sandy
E W Brown
E W Brown
E W Brown
Ghent
Ghent
Ghent
Ghent
Green River
Green River
Tyrone
Cane Run
Cane Run
Cane Run
Mill Creek
Mill Creek
Mill Creek
Mill Creek
Elmer Smith
Elmer Smith
Paradise
Paradise
Paradise
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
800
94
160
422
475
469
478
478
68
95
71
155
168
240
303
301
391
477
132
261
616
602
977
133
124
134
134
134
134
134
3
1
1
2
2
2
2
2
1
1
1
2
2
3
3
3
3
3
1
1
3
2
3
1
1
1
1
1
1
1
28
11
11
27
72
72
72
72
23
23
29
69
69
118
128
128
128
128
6
6
122
73
122
7
7
7
7
7
7
7
22,413,123
6,988,397
8,028,683
22,420,126
62,221,800
60,732,185
61,354,347
61,336,293
13,703,486
14,284,315
16,305,568
40,785,891
42,701,837
64,697,971
82,282,642
82,811,245
91,832,381
98,648,172
4,260,976
5,968,374
71,081,976
60,900,519
112,779,002
4,919,734
5,111,900
4,937,195
4,937,195
4,937,195
4,937,195
4,937,195
28
74
50
53
131
129
128
128
202
150
230
263
254
270
272
275
235
207
32
23
115
101
115
37
41
37
37
37
37
37
43
-------
1379_B_7
1379_B_8
1379_B_9
1381_B_C1
1381_B_C2
1381_B_C3
1382_B_H1
1382_B_H2
1383_B_R1
1384_B_1
1384_B_2
1385_B_1
1385_B_2
1385_B_3
1385_B_4
1393_B_6
1552_B_1
1552_B_2
1554_B_2
1554_B_3
1570_B_11
1570_B_9
1571_B_1
1571_B_2
1572_B_1
1572_B_2
1572_B_3
1573_B_1
1573_B_2
1606 B 1
Shawnee
Shawnee
Shawnee
Kenneth C Coleman
Kenneth C Coleman
Kenneth C Coleman
HMP&L Station Two Henderson
HMP&L Station Two Henderson
Robert A Reid
Cooper
Cooper
Dale
Dale
Dale
Dale
R S Nelson
C P Crane
C P Crane
Herbert A Wagner
Herbert A Wagner
R Paul Smith Power Station
R Paul Smith Power Station
Chalk Point LLC
Chalk Point LLC
Dickerson
Dickerson
Dickerson
Morgantown Generating Plant
Morgantown Generating Plant
Mount Tom
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
KY
LA
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MD
MA
134
134
134
150
150
155
153
159
65
116
225
27
27
75
75
550
200
200
135
324
87
28
341
342
182
182
182
624
620
144
1
1
1
1
1
1
2
2
1
1
1
1
1
1
1
3
2
2
1
1
2
1
1
1
2
2
2
3
3
1
7
7
7
13
13
13
8
8
2
32
32
4
4
4
4
9
45
45
22
22
27
12
1
1
9
9
9
99
99
15
4,937,195
4,937,195
4,937,195
9,632,325
9,632,325
9,753,637
4,675,164
4,777,427
1,099,308
20,622,529
26,316,589
1,766,472
1,773,806
2,378,590
2,378,590
8,013,893
28,572,945
28,389,222
16,819,534
21,800,677
13,234,070
4,785,577
1,452,650
1,453,966
5,429,574
5,421,348
5,454,113
65,209,623
62,360,586
10,827,679
37
37
37
64
64
63
31
30
17
178
117
65
66
32
32
15
143
142
125
67
152
171
4
4
30
30
30
105
101
75
44
-------
1619_B_1
1619_B_2
1619_B_3
1626_B_1
1626_B_2
1626_B_3
1695_B_4
1695_B_5
1702_B_1
1702_B_2
1710_B_1
1710_B_2
1710_B_3
1720_B_7
1720_B_8
1723_B_1
1723_B_2
1723_B_3
1731_B_1
1732_B_10
1732_B_11
1732_B_12
1732_B_9
1733_B_1
1733_B_2
1733_B_3
1733_B_4
1740_B_2
1740_B_3
1743 B 1
Brayton Point
Brayton Point
Brayton Point
Salem Harbor
Salem Harbor
Salem Harbor
B C Cobb
B C Cobb
Dan E Karn
Dan E Karn
J H Campbell
J H Campbell
J H Campbell
J C Weadock
J C Weadock
J R Whiting
J R Whiting
J R Whiting
Harbor Beach
Marysville
Marysville
Marysville
Marysville
Monroe
Monroe
Monroe
Monroe
River Rouge
River Rouge
St Clair
MA
MA
MA
MA
MA
MA
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
244
244
612
82
80
150
156
156
255
260
260
355
825
151
151
102
102
124
103
42
42
42
42
770
785
795
775
241
272
151
3
3
5
1
1
1
2
2
1
1
3
3
3
1
1
1
1
1
2
1
1
1
1
3
3
3
3
2
3
1
85
85
218
1
1
1
90
90
49
49
188
188
188
48
48
14
14
14
144
9
9
9
9
63
63
63
63
21
43
1
44,147,316
44,233,074
146,022,447
383,498
379,893
480,620
51,000,180
50,689,290
42,287,400
42,567,978
105,151,164
123,228,381
159,177,335
34,952,956
34,990,691
8,960,245
8,960,245
9,608,933
65,999,089
4,558,011
4,558,011
4,558,011
4,558,011
51,067,983
51,099,864
51,321,409
50,810,782
14,040,402
18,325,670
821,585
181
181
239
5
5
3
327
325
166
164
404
347
193
231
232
88
88
77
641
109
109
109
109
66
65
65
66
58
67
5
45
-------
1743_B_2
1743_B_3
1743_B_4
1743_B_6
1743_B_7
1745_B_16
1745_B_17
1745_B_18
1745_B_19
1745_B_9A
1769_B_5
1769_B_6
1769_B_7
1769_B_8
1769_B_9
1771_B_1
1771_B_2
1825_B_3
1830_B_3
1830_B_4
1830_B_5
1831_B_1
1831_B_2
1831_B_3
1831_B_4
1831_B_5
1831_B_6
1832_B_1
1843_B_2
1843 B 3
St Clair
St Clair
St Clair
St Clair
St Clair
Trenton Channel
Trenton Channel
Trenton Channel
Trenton Channel
Trenton Channel
Presque Isle
Presque Isle
Presque Isle
Presque Isle
Presque Isle
Escanaba
Escanaba
J B Sims
James De Young
James De Young
James De Young
Eckert Station
Eckert Station
Eckert Station
Eckert Station
Eckert Station
Eckert Station
Erickson Station
Shiras
Shiras
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
Ml
154
160
151
312
440
53
53
53
53
536
88
88
85
85
85
13
13
73
11
21
27
40
42
41
69
69
67
152
20
41
1
1
1
1
2
1
1
1
1
2
2
2
2
2
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
3
7
7
7
7
28
310
310
310
310
310
100
100
50
58
58
58
24
24
24
24
24
24
22
141
141
819,061
833,199
818,216
1,020,896
1,888,087
3,518,012
3,656,788
3,459,862
3,400,035
24,802,480
134,703,955
134,119,117
142,818,725
137,993,296
137,993,296
33,520,946
33,520,946
28,170,957
17,149,007
21,967,043
25,680,113
11,844,286
12,088,759
12,054,339
14,020,209
14,438,857
14,126,816
16,549,274
51,087,933
67,829,244
5
5
5
3
4
67
70
66
65
46
1,531
1,524
1,680
1,623
1,623
2,579
2,579
387
1,633
1,072
951
296
289
298
203
210
211
109
2,620
1,654
46
-------
1866_B_5
1866_B_7
1866_B_8
1891_B_1
1891_B_2
1893_B_1
1893_B_2
1893_B_3
1893_B_4
1904_B_3
1904_B_4
1915_B_1
1943_B_2
1943_B_3
1961_B_NEPP
1979_B_1
1979_B_2
1979_B_3
2008_B_1
2008_B_2
2008_B_3
2008_B_4
2018_B_7
2018_B_9
2022_B_3
2049_B_4
2049_B_5
2062_B_H1
2062_B_H3
2076 B 1
Wyandotte
Wyandotte
Wyandotte
Syl Laskin
Syl Laskin
Clay Boswell
Clay Boswell
Clay Boswell
Clay Boswell
Black Dog
Black Dog
Allen S King
Hoot Lake
Hoot Lake
Austin Northeast
Hibbing
Hibbing
Hibbing
Silver Lake
Silver Lake
Silver Lake
Silver Lake
Virginia
Virginia
Willmar
Jack Watson
Jack Watson
Henderson
Henderson
Asbury
Ml
Ml
Ml
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MN
MS
MS
MS
MS
MO
24
24
24
55
55
69
69
351
525
94
165
610
60
84
29
10
10
10
9
14
24
59
10
10
20
230
476
11
18
213
1
1
1
1
1
1
1
3
3
1
1
3
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
1
1
3
3
3
3
20
20
51
51
305
305
15
15
109
31
31
10
14
14
14
43
43
43
43
6
6
12
1
26
2
2
141
1,197,065
1,148,547
1,273,346
10,946,407
10,946,407
28,426,438
27,994,647
209,904,664
259,254,414
9,442,803
11,307,091
98,379,962
16,991,480
19,334,908
4,487,238
3,643,086
3,643,086
3,585,412
12,680,825
14,336,096
16,834,510
23,408,712
1,757,260
1,733,461
4,429,040
1,059,090
22,151,655
599,246
715,923
76,776,545
50
48
53
199
199
412
406
599
494
100
69
161
284
230
153
357
357
352
1,364
1,010
693
395
181
179
217
5
47
54
40
360
47
-------
2079_B_5A
2080_B_1
2080_B_2
2080_B_3
2094_B_1
2094_B_2
2094_B_3
2098_B_5
2098_B_6
2103_B_1
2103_B_2
2103_B_3
2103_B_4
2104_B_1
2104_B_2
2104_B_3
2104_B_4
2107_B_1
2107_B_2
2123_B_6
2123_B_7
2132_B_1
2132_B_2
2132_B_3
2144_B_4
2144_B_5
2161_B_1
2161_B_2
2161_B_3
2161 B 4
Hawthorn
Montrose
Montrose
Montrose
Sibley
Sibley
Sibley
Lake Road
Lake Road
Labadie
Labadie
Labadie
Labadie
Meramec
Meramec
Meramec
Meramec
Sioux
Sioux
Columbia
Columbia
Blue Valley
Blue Valley
Blue Valley
Marshall
Marshall
James River Power Station
James River Power Station
James River Power Station
James River Power Station
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
563
170
164
176
54
54
401
14
97
597
594
612
612
122
120
269
347
497
497
25
25
21
21
51
5
16
21
21
41
56
2
2
2
2
1
1
2
1
1
2
2
2
2
2
2
2
3
2
2
1
1
1
1
1
1
1
1
1
1
1
39
59
59
59
12
12
41
3
3
88
88
88
88
63
63
63
143
53
53
11
11
10
10
10
16
16
46
46
46
46
40,971,852
36,622,937
36,044,913
36,984,154
6,050,087
5,930,500
34,896,137
1,202,124
2,454,909
86,771,052
84,880,112
85,776,583
85,099,994
27,322,272
25,433,774
49,292,459
95,551,056
36,171,805
36,171,805
4,577,245
4,001,683
3,657,281
3,657,281
5,626,006
3,494,867
5,547,190
17,279,505
17,279,505
22,905,772
24,300,389
73
215
220
210
112
110
87
83
25
145
143
140
139
224
212
183
275
73
73
187
163
174
174
110
713
347
823
823
559
434
48
-------
2161_B_5
2167_B_1
2167_B_2
2168_B_MB1
2168_B_MB2
2168_B_MB3
2169_B_1
2169_B_2
2171_B_1
2171_B_2
2187_B_2
2240_B_6
2240_B_7
2240_B_8
2277_B_1
2277_B_2
2291_B_1
2291_B_2
2291_B_3
2291_B_4
2291_B_5
2324_B_1
2324_B_2
2324_B_3
2324_B_4
2364_B_1
2364_B_2
2367_B_4
2367_B_6
2378 B 1
James River Power Station
New Madrid
New Madrid
Thomas Hill
Thomas Hill
Thomas Hill
Chamois
Chamois
Missouri City
Missouri City
J E Corette Plant
Lon Wright
Lon Wright
Lon Wright
Sheldon
Sheldon
North Omaha
North Omaha
North Omaha
North Omaha
North Omaha
Reid Gardner
Reid Gardner
Reid Gardner
Reid Gardner
Merrimack
Merrimack
Schiller
Schiller
B L England
MO
MO
MO
MO
MO
MO
MO
MO
MO
MO
MT
NE
NE
NE
NE
NE
NE
NE
NE
NE
NE
NV
NV
NV
NV
NH
NH
NH
NH
NJ
97
580
580
175
275
670
17
49
19
19
158
15
20
85
105
120
79
111
111
138
224
110
110
110
225
113
320
48
48
129
2
2
2
1
1
2
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
1
1
1
2
1
1
2
120
41
41
11
11
44
36
36
17
17
150
3
3
3
12
12
15
15
15
31
31
3
3
3
3
30
60
3
3
94
55,733,835
38,953,400
39,162,023
9,239,564
10,753,692
35,713,178
12,968,063
18,027,617
6,359,232
6,359,232
117,905,332
877,700
1,018,837
1,624,218
8,230,098
8,683,755
9,059,759
10,288,311
10,236,486
14,642,191
20,708,445
1,972,018
1,993,430
2,016,780
2,524,264
20,672,673
43,651,526
1,393,557
1,344,635
52,365,737
575
67
68
53
39
53
763
368
335
335
746
59
51
19
78
72
115
93
92
106
92
18
18
18
11
184
136
29
28
406
49
-------
2378_B_2
2384_B_8
2403_B_2
2408_B_1
2408_B_2
2434_B_10
2442_B_1
2442_B_2
2442_B_3
2442_B_4
2442_B_5
2451_B_1
2451_B_2
2451_B_3
2451_B_4
2468_G_5
2480_B_3
2480_B_4
2526_B_11
2526_B_12
2526_B_13
2527_B_6
2535_B_1
2535_B_2
2549_B_67
2549_B_68
2554_B_1
2554_B_2
2554_B_3
2554 B 4
B L England
Deepwater
PSEG Hudson Generating Station
PSEG Mercer Generating Station
PSEG Mercer Generating Station
Howard Down
Four Corners
Four Corners
Four Corners
Four Corners
Four Corners
San Juan
San Juan
San Juan
San Juan
Raton
Danskammer Generating Station
Danskammer Generating Station
AES Westover
AES Westover
AES Westover
AES Greenidge LLC
AES Cayuga
AES Cayuga
C R Huntley Generating Station
C R Huntley Generating Station
Dunkirk Generating Station
Dunkirk Generating Station
Dunkirk Generating Station
Dunkirk Generating Station
NJ
NJ
NJ
NJ
NJ
NJ
NM
NM
NM
NM
NM
NM
NM
NM
NM
NM
NY
NY
NY
NY
NY
NY
NY
NY
NY
NY
NY
NY
NY
NY
155
80
608
324
324
23
170
170
220
760
760
322
320
495
506
7
133
236
22
22
84
106
152
153
190
190
75
75
185
185
2
1
4
2
2
1
1
1
1
4
4
2
2
3
3
1
1
2
1
1
1
1
1
1
2
2
1
1
2
2
94
9
43
20
20
22
4
4
4
65
65
20
20
38
38
21
13
33
3
3
3
4
14
14
9
9
7
7
33
33
55,367,158
5,464,709
28,685,847
14,828,819
14,394,239
9,263,690
2,915,795
2,923,662
3,300,614
48,280,480
48,390,171
11,031,400
11,210,066
25,969,488
25,016,173
5,429,391
9,015,718
21,202,511
1,274,492
1,289,755
2,031,559
2,599,972
10,586,859
10,609,438
5,176,646
5,176,646
3,811,141
3,833,477
13,407,977
13,487,072
357
68
47
46
44
403
17
17
15
64
64
34
35
52
49
787
68
90
58
59
24
25
70
69
27
27
51
51
72
73
50
-------
2682_B_10
2682_B_12
2682_B_9
2706_B_1
2706_B_2
2708_B_5
2708_B_6
2709_B_1
2709_B_2
2709_B_3
2712_B_1
2712_B_2
2712_B_3A
2712_B_3B
2712_B_4A
2712_B_4B
2713_B_1
2713_B_2
2713_B_3
2716_B_1
2716_B_2
2716_B_3
2718_B_1
2718_B_2
2718_B_3
2718_B_4
2718_B_5
2720_B_5
2720_B_6
2720_B_7
S A Carlson
S A Carlson
S A Carlson
Asheville
Asheville
Cape Fear
Cape Fear
Lee
Lee
Lee
Roxboro
Roxboro
Roxboro
Roxboro
Roxboro
Roxboro
L V Sutton
L V Sutton
L V Sutton
W H Weatherspoon
W H Weatherspoon
W H Weatherspoon
GG Allen
GG Allen
GG Allen
GG Allen
GG Allen
Buck
Buck
Buck
NY
NY
NY
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
15
15
15
191
185
144
172
74
77
248
369
671
353
353
349
349
93
102
403
48
49
76
162
162
260
275
265
38
38
38
1
1
1
1
1
1
1
1
1
3
4
5
4
4
4
4
2
2
4
1
1
1
1
1
1
1
1
1
1
1
19
19
19
53
53
67
67
85
85
336
318
501
318
318
318
318
333
333
767
119
119
119
15
15
15
15
15
10
10
10
5,898,034
5,960,664
5,960,664
42,245,167
41,997,560
48,101,001
52,415,896
49,597,140
49,400,739
175,013,921
165,574,308
358,153,400
179,209,965
164,614,623
192,495,589
180,621,857
159,333,256
157,221,358
480,939,460
60,915,952
61,084,751
69,786,937
11,286,661
11,275,688
13,258,122
13,456,826
13,399,377
4,763,840
4,763,840
4,763,840
393
397
397
221
227
334
305
670
642
706
449
534
508
467
552
518
1,713
1,541
1,193
1,269
1,247
918
70
70
51
49
51
127
127
125
51
-------
2720_B_8
2720_B_9
2721_B_5
2721_B_6
2723_B_1
2723_B_2
2723_B_3
2727_B_1
2727_B_2
2727_B_3
2727_B_4
2732_B_10
2732_B_7
2732_B_8
2732_B_9
2790_B_B1
2790_B_B2
2817_B_1
2817_B_2
2823_B_B1
2823_B_B2
2824_B_1
2824_B_10
2828_B_1
2828_B_2
2828_B_3
2830_B_1
2830_B_2
2830_B_3
2830 B 4
Buck
Buck
Cliffside
Cliffside
Dan River
Dan River
Dan River
Marshall
Marshall
Marshall
Marshall
Riverbend
Riverbend
Riverbend
Riverbend
R M Heskett
R M Heskett
Leland Olds
Leland Olds
Milton R Young
Milton R Young
Stanton
Stanton
Cardinal
Cardinal
Cardinal
Walter C Beckjord
Walter C Beckjord
Walter C Beckjord
Walter C Beckjord
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
ND
ND
ND
ND
ND
ND
ND
ND
OH
OH
OH
OH
OH
OH
OH
128
128
550
800
67
67
142
378
378
657
657
133
94
94
133
29
76
221
448
250
455
130
57
600
600
630
94
94
128
150
1
1
2
3
1
1
2
2
2
2
2
1
1
1
1
1
1
1
2
1
2
1
1
3
3
3
1
1
1
1
10
10
126
267
1
1
2
85
85
85
85
8
8
8
8
5
5
26
59
23
52
26
26
58
58
58
7
7
7
7
6,775,198
6,799,947
78,126,677
156,413,590
592,542
586,647
965,276
54,785,142
54,832,904
58,667,715
58,648,369
5,849,602
5,226,437
5,276,288
5,828,717
2,173,851
3,036,810
23,149,954
50,234,609
21,246,210
44,411,133
18,738,173
13,452,251
44,899,302
46,258,050
49,434,180
4,025,382
3,957,346
4,404,241
4,620,484
53
53
142
196
9
9
7
145
145
89
89
44
56
56
44
74
40
105
112
85
98
144
234
75
77
78
43
42
34
31
52
-------
2830_B_5
2830_B_6
2832_B_6
2832_B_7
2832_B_8
2835_B_7
2836_B_10
2836_B_12
2837_B_1
2837_B_2
2837_B_3
2837_B_4
2837_B_5
2838_B_18
2840_B_3
2840_B_4
2840_B_5
2840_B_6
2843_B_9
2848_B_H-1
2848_B_H-2
2848_B_H-3
2848_B_H-4
2848_B_H-5
2848_B_H-6
2850_B_1
2850_B_2
2850_B_3
2850_B_4
2861 B 1
Walter C Beckjord
Walter C Beckjord
Miami Fort
Miami Fort
Miami Fort
Ashtabula
Avon Lake
Avon Lake
Eastlake
Eastlake
Eastlake
Eastlake
Eastlake
Lake Shore
Conesville
Conesville
Conesville
Conesville
Picway
O H Hutchings
O H Hutchings
O H Hutchings
O H Hutchings
O H Hutchings
O H Hutchings
J M Stuart
J M Stuart
J M Stuart
J M Stuart
Miles
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
238
414
163
500
500
244
96
640
132
132
132
240
597
245
165
780
375
375
95
58
55
63
63
63
63
597
597
597
597
108
1
2
2
2
2
3
2
4
2
2
2
3
3
2
2
3
2
2
1
1
1
1
1
1
1
2
2
2
2
1
7
39
31
31
31
147
94
251
121
121
121
187
187
110
17
36
17
17
2
3
3
3
3
3
3
33
33
33
33
16
5,566,075
13,252,021
15,320,273
26,978,826
26,795,622
73,712,911
49,628,104
192,073,460
68,778,521
68,275,329
67,409,064
98,897,850
146,553,511
81,148,527
5,179,593
34,479,228
13,898,446
13,806,685
1,213,631
1,541,919
1,489,428
1,528,214
1,503,725
1,575,322
1,578,597
34,998,663
34,359,197
33,709,140
34,791,509
10,610,699
23
32
94
54
54
302
517
300
521
517
511
412
245
331
31
44
37
37
13
27
27
24
24
25
25
59
58
56
58
98
53
-------
2861_B_2
2864_B_7
2864_B_8
2866_B_1
2866_B_2
2866_B_3
2866_B_4
2866_B_5
2866_B_6
2866_B_7
2872_B_1
2872_B_2
2872_B_3
2872_B_4
2872_B_5
2876_B_1
2876_B_2
2876_B_3
2876_B_4
2876_B_5
2878_B_1
2878_B_2
2878_B_3
2878_B_4
2908_G_10
2908_G_11
2908_G_8
2908_G_9
2914_G_3
2914 B 4
Miles
R E Burger
R E Burger
WH Sammis
WH Sammis
WH Sammis
WH Sammis
WH Sammis
WH Sammis
WH Sammis
Muskingum River
Muskingum River
Muskingum River
Muskingum River
Muskingum River
Kyger Creek
Kyger Creek
Kyger Creek
Kyger Creek
Kyger Creek
Bay Shore
Bay Shore
Bay Shore
Bay Shore
Lake Road
Lake Road
Lake Road
Lake Road
Dover
Dover
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
108
156
156
180
180
180
180
300
600
600
190
190
205
205
585
217
217
217
217
217
136
138
142
215
25
85
25
25
8
15
1
1
1
1
1
1
1
2
4
4
1
1
1
1
2
1
1
1
1
1
2
2
2
2
1
2
1
1
1
1
16
1
1
12
12
12
12
30
69
69
4
4
4
4
18
17
17
17
17
17
29
29
29
29
45
110
45
45
13
13
10,537,680
1,036,633
1,058,515
9,298,987
9,339,857
9,257,816
9,232,966
18,766,521
46,052,387
46,307,383
3,481,788
3,456,143
3,526,616
3,427,273
15,822,798
13,759,604
13,822,283
13,822,283
13,874,156
13,801,443
15,670,335
16,166,545
16,107,455
18,700,991
17,869,176
47,569,837
17,869,176
17,869,176
3,409,244
4,595,500
98
7
7
52
52
51
51
63
77
77
18
18
17
17
27
63
64
64
64
64
115
117
113
87
715
560
715
715
426
302
54
-------
2917_B_8
2917_B_9
2935_B_10
2935_B_1 1
2935_B_12
2935_B_13
2936_B_3
2936_B_4
2936_B_5
2937_B_4
2937_B_5
2937_B_6
2942_B_5
2942_B_6
2943_B_1
2943_B_2
2943_G_4
2952_B_4
2952_B_5
2952_B_6
2963_B_3313
2963_B_3314
3098_B_1
3098_B_2
3098_B_3
3098_B_4
3113_B_1
3113_B_2
3115_B_1
3115_B_2
Hamilton
Hamilton
Orrville
Orrville
Orrville
Orrville
Painesville
Painesville
Painesville
Piqua
Piqua
Piqua
St Marys
St Marys
Shelby Municipal Light Plant
Shelby Municipal Light Plant
Shelby Municipal Light Plant
Muskogee
Muskogee
Muskogee
Northeastern
Northeastern
Elrama
Elrama
Elrama
Elrama
Portland
Portland
Titus
Titus
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OH
OK
OK
OK
OK
OK
PA
PA
PA
PA
PA
PA
PA
PA
33
51
13
13
30
23
11
22
22
12
12
20
6
9
12
12
7
511
522
515
450
450
94
94
103
174
157
243
81
81
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
4
4
4
3
3
1
1
1
2
1
1
1
1
4
4
20
20
20
20
58
58
58
17
17
17
26
26
3
3
3
136
136
136
57
57
3
3
3
11
10
10
11
11
1,882,521
2,128,420
6,488,346
6,488,346
7,899,993
7,178,704
16,231,647
22,301,632
20,902,148
5,411,688
5,296,940
6,429,290
6,320,195
7,005,188
1,019,872
1,041,965
866,280
96,829,197
96,922,416
95,749,179
44,740,461
44,806,701
2,086,921
2,099,683
2,164,661
5,496,850
7,355,187
8,616,408
6,152,979
6,188,668
57
42
503
503
266
312
1,546
1,037
972
436
427
321
1,090
778
85
87
124
190
186
186
99
100
22
22
21
32
47
35
76
76
55
-------
3115_B_3
3118_B_1
3118_B_2
3122_B_1
3122_B_2
3122_B_3
3130_B_1
3130_B_2
3131_B_1
3131_B_2
3131_B_3
3131_B_4
3136_B_1
3136_B_2
3138_B_3
3138_B_4
3138_B_5
3140_B_1
3140_B_2
3140_B_3
3149_B_1
3149_B_2
3152_B_1A
3152_B_1B
3152_B_2A
3152_B_2B
3152_B_3
3152_B_4
3161_B_2
3178 B 1
Titus
Conemaugh
Conemaugh
Homer City Station
Homer City Station
Homer City Station
Seward
Seward
Shawville
Shawville
Shawville
Shawville
Keystone
Keystone
New Castle
New Castle
New Castle
PPL Brunner Island
PPL Brunner Island
PPL Brunner Island
PPL Montour
PPL Montour
Sunbury Generation LP
Sunbury Generation LP
Sunbury Generation LP
Sunbury Generation LP
Sunbury Generation LP
Sunbury Generation LP
Eddystone Generating Station
Armstrong Power Station
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
PA
81
850
850
620
614
650
261
261
122
125
175
175
850
850
94
98
134
344
397
754
750
750
40
40
40
40
87
128
309
172
1
3
3
2
2
2
1
1
1
1
1
1
3
3
1
1
1
2
2
3
3
3
1
1
1
1
1
1
3
1
11
44
44
10
10
10
2
2
10
10
10
10
19
19
3
3
3
7
7
34
99
99
26
26
26
26
26
26
13
11
6,164,913
28,478,143
28,478,143
9,077,095
8,978,074
9,207,237
1,629,448
1,668,097
7,200,797
7,294,959
8,071,310
8,071,310
16,645,580
16,488,634
1,719,550
1,670,431
1,966,212
4,613,100
5,127,900
29,273,420
78,561,631
78,561,631
12,190,368
12,190,368
12,190,368
12,190,368
16,356,969
18,917,854
7,788,797
8,120,940
76
34
34
15
15
14
6
6
59
58
46
46
20
19
18
17
15
13
13
39
105
105
309
309
309
309
188
148
25
47
56
-------
3178_B_2
3179_B_1
3179_B_2
3179_B_3
3181_B_33
3251_B_1
3264_B_1
3264_B_2
3264_B_3
3280_B_CAN1
3280_B_CAN2
3280_B_CAN3
3287_B_MCM1
3287_B_MCM2
3295_B_URQ3
3297_B_WAT1
3297_B_WAT2
3298_B_WIL1
3317_B_1
3317_B_2
3319_B_3
3319_B_4
3325_B_1
3393_B_1
3393_B_2
3393_B_3
3396_B_1
3399_B_1
3399_B_2
3403 B 1
Armstrong Power Station
Hatfields Ferry Power Station
Hatfields Ferry Power Station
Hatfields Ferry Power Station
Mitchell Power Station
H B Robinson
WSLee
WSLee
WSLee
Canadys Steam
Canadys Steam
Canadys Steam
McMeekin
McMeekin
Urquhart
Wateree
Wateree
Williams
Dolphus M Grainger
Dolphus M Grainger
Jefferies
Jefferies
Ben French
Allen Steam Plant
Allen Steam Plant
Allen Steam Plant
Bull Run
Cumberland
Cumberland
Gallatin
PA
PA
PA
PA
PA
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SC
SD
TN
TN
TN
TN
TN
TN
TN
171
530
530
530
277
176
100
100
170
105
116
175
125
125
94
350
350
615
85
85
153
153
22
245
245
245
881
1,232
1,233
222
1
2
2
2
3
1
1
1
1
2
2
2
1
1
2
2
2
2
1
1
1
1
1
2
2
2
3
3
3
1
11
8
8
8
27
87
1
1
1
210
210
210
71
71
107
200
200
259
158
158
99
99
108
33
33
33
204
81
81
2
8,105,917
7,227,186
7,194,169
7,304,351
11,206,077
66,202,863
878,755
876,154
1,039,925
94,419,328
98,698,195
125,031,058
47,542,812
48,485,566
34,257,609
149,254,789
147,815,608
213,418,201
94,743,575
95,251,225
74,184,083
73,960,402
40,426,126
21,938,571
21,938,571
21,938,571
205,971,347
80,248,498
80,283,958
1,928,621
47
14
14
14
40
376
9
9
6
899
851
714
380
388
364
426
422
347
1,115
1,121
485
483
1,872
90
90
90
234
65
65
9
57
-------
3403_B_2
3403_B_3
3403_B_4
3405_B_1
3405_B_2
3405_B_3
3405_B_4
3406_B_1
3406_B_10
3406_B_2
3406_B_3
3406_B_4
3406_B_5
3406_B_6
3406_B_7
3406_B_8
3406_B_9
3407_B_1
3407_B_2
3407_B_3
3407_B_4
3407_B_5
3407_B_6
3407_B_7
3407_B_8
3407_B_9
3470_B_WAP5
3470_B_WAP6
3470_B_WAP7
3470_B_WAP8
Gallatin
Gallatin
Gallatin
John Sevier
John Sevier
John Sevier
John Sevier
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
WA Parish
WA Parish
WA Parish
WA Parish
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TN
TX
TX
TX
TX
222
260
260
176
176
176
176
106
141
106
106
106
106
106
141
141
141
134
134
134
134
175
175
175
175
175
645
650
565
600
1
1
1
2
2
2
2
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
2
2
2
2
2
139
139
139
139
19
19
19
19
19
19
19
19
19
19
97
97
97
97
97
97
97
97
97
6
6
1
1
1,928,621
2,058,185
2,058,185
78,136,455
78,136,455
78,136,455
78,136,455
12,724,426
13,566,786
12,724,426
12,724,426
12,724,426
12,342,977
12,342,977
13,566,786
13,566,786
13,566,786
36,622,679
36,622,679
36,622,679
36,622,679
51,649,364
51,649,364
51,649,364
51,649,364
51,649,364
2,686,937
2,974,589
1,132,402
1,192,947
9
8
8
444
444
444
444
120
96
120
120
120
116
116
96
96
96
273
273
273
273
295
295
295
295
295
4
5
2
2
58
-------
3497.
3497.
3644.
3644.
3775.
3775.
3775.
3776_
3776_
3776.
3788.
3788.
3788.
3788.
3788.
3796.
3796.
3797.
3797.
3797.
3797.
3803.
3803.
3803.
3803.
3809.
3809.
3845_B.
3845_B.
3935
_B_2
_B_1
_B_2
_B_1
_B_2
_B_3
B_51
B_52
_B_6
_B_1
_B_2
_B_3
_B_4
_B_5
_B_3
_B_4
_B_3
_B_4
_B_5
_B_6
_B_1
_B_2
_B_3
_B_4
_B_1
_B_2
_BW21
_BW22
B 1
Big Brown
Big Brown
Carbon
Carbon
Clinch River
Clinch River
Clinch River
Glen Lyn
Glen Lyn
Glen Lyn
Potomac River
Potomac River
Potomac River
Potomac River
Potomac River
Bremo Bluff
Bremo Bluff
Chesterfield
Chesterfield
Chesterfield
Chesterfield
Chesapeake
Chesapeake
Chesapeake
Chesapeake
Yorktown
Yorktown
Transalta Centralia Generation
Transalta Centralia Generation
John E Amos
TX
TX
UT
UT
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
VA
WA
WA
WV
575
575
67
105
235
235
235
45
45
235
88
88
102
102
102
71
156
100
166
310
658
111
111
156
217
159
164
703
703
800
2
2
1
2
3
3
3
1
1
2
1
1
1
1
1
1
1
1
2
3
4
2
2
2
3
2
2
2
2
3
13
13
7
67
164
164
164
17
17
49
10
10
10
10
10
13
13
5
55
142
229
116
116
116
228
120
120
158
158
33
5,824,349
5,447,670
3,779,914
27,882,639
88,926,102
89,731,011
88,097,986
8,772,437
8,772,437
32,250,863
6,569,511
6,137,038
6,137,038
6,195,082
6,252,233
7,856,735
9,809,996
3,093,281
25,405,927
88,732,353
159,656,669
56,744,698
59,262,250
66,253,664
109,196,341
61,769,959
63,285,654
162,043,992
162,043,992
25,455,486
10
9
56
266
378
382
375
195
195
137
75
70
60
61
61
111
63
31
153
286
243
511
534
425
503
388
386
231
231
32
59
-------
3935_B_2
3935_B_3
3936_B_1
3936_B_2
3938_B_11
3938_B_21
3938_B_31
3938_B_41
3938_B_51
3942_B_1
3942_B_2
3942_B_3
3943_B_1
3943_B_2
3944_B_1
3944_B_2
3944_B_3
3945_B_7
3945_B_8
3946_B_1
3946_B_2
3947_B_1
3947_B_2
3947_B_3
3948_B_1
3948_B_2
3954_B_1
3954_B_2
3954_B_3
3992 B 7
John E Amos
John E Amos
Kanawha River
Kanawha River
Philip Sporn
Philip Sporn
Philip Sporn
Philip Sporn
Philip Sporn
Albright
Albright
Albright
Fort Martin Power Station
Fort Martin Power Station
Harrison Power Station
Harrison Power Station
Harrison Power Station
Rivesville
Rivesville
Willow Island
Willow Island
Kammer
Kammer
Kammer
Mitchell
Mitchell
Mt Storm
Mt Storm
Mt Storm
Blount Street
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
wv
Wl
800
1,300
205
205
150
150
150
150
450
73
73
137
552
555
652
642
651
46
91
54
181
210
210
210
800
800
524
524
521
22
3
4
2
2
2
2
2
2
2
2
2
2
2
2
5
5
5
2
2
1
2
1
1
1
3
3
4
4
3
1
33
76
21
21
28
28
28
28
28
20
20
20
22
22
89
89
89
32
32
3
24
1
1
1
5
5
152
152
92
29
25,525,621
54,359,572
10,004,729
9,969,552
16,300,090
16,052,044
15,982,920
15,866,234
25,116,859
5,946,953
5,946,953
10,607,955
20,856,287
20,871,288
62,842,593
62,955,955
62,590,340
12,443,114
16,219,574
1,914,114
16,815,933
488,386
488,025
488,025
4,385,284
4,375,301
85,613,330
86,726,251
74,902,071
11,189,692
32
42
49
49
109
107
107
106
56
81
81
77
38
38
96
98
96
271
178
35
93
2
2
2
5
5
163
166
144
500
60
-------
3992_B_8
3992_B_9
4041_B_5
4041_B_6
4041_B_7
4041_B_8
4042_B_1
4042_B_2
4042_B_3
4042_B_4
4050_B_3
4050_B_4
4050_B_5
4054_B_1
4054_B_2
4072_B_5
4072_B_6
4072_B_7
4072_B_8
4078_B_1
4078_B_2
4078_B_3
4078_B_4
4125_B_5
4125_B_6
4125_B_7
4125_B_8
4125_B_9
4127_B_5
4127 B B23
Blount Street
Blount Street
South Oak Creek
South Oak Creek
South Oak Creek
South Oak Creek
Valley
Valley
Valley
Valley
Edgewater
Edgewater
Edgewater
Nelson Dewey
Nelson Dewey
Pulliam
Pulliam
Pulliam
Pulliam
Weston
Weston
Weston
Weston
Manitowoc
Manitowoc
Manitowoc
Manitowoc
Manitowoc
Menasha
Menasha
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
Wl
49
48
261
264
298
312
70
70
70
70
76
321
414
107
111
49
72
88
133
62
86
338
519
2
18
18
21
30
7
9
1
1
2
2
2
2
1
1
1
1
1
2
3
2
2
1
2
2
2
1
2
4
4
1
1
1
1
1
1
1
29
29
45
45
45
45
5
5
5
5
30
84
174
58
58
10
118
118
118
73
204
535
535
28
28
28
28
28
10
10
13,913,394
13,824,500
30,655,617
30,967,962
33,064,085
33,486,899
3,047,663
3,047,663
3,026,671
3,026,671
17,941,613
55,804,908
100,511,909
29,322,978
29,643,798
5,081,019
19,051,451
36,909,371
59,324,062
42,302,848
76,891,284
305,939,828
357,497,756
3,801,699
9,652,063
9,262,060
9,726,975
11,236,889
2,268,040
2,770,899
284
287
117
117
111
107
44
44
43
43
236
174
243
275
267
105
266
420
445
682
894
905
689
2,534
536
515
472
375
329
326
61
-------
4127_B_B24
4140_B_B1
4140_B_B2
4140_B_B3
4140_B_B4
4140_B_B5
4143_B_1
4150_B_5
4151_B_1
4151_B_2
4151_B_3
4158_B_BW41
4158_B_BW42
4158_B_BW43
4158_B_BW44
4162_B_1
4162_B_2
4162_B_3
4259_B_1
4271_B_B1
4941_B_1
4941_B_2
4941_B_3
6002_B_1
6002_B_2
6002_B_3
6002_B_4
6004_B_1
6004_B_2
6009 B 1
Menasha
Alma
Alma
Alma
Alma
Alma
Genoa
Neil Simpson
Osage
Osage
Osage
Dave Johnston
Dave Johnston
Dave Johnston
Dave Johnston
Naughton
Naughton
Naughton
Endicott Station
John P Madgett
Navajo
Navajo
Navajo
James H Miller Jr
James H Miller Jr
James H Miller Jr
James H Miller Jr
Pleasants Power Station
Pleasants Power Station
White Bluff
Wl
Wl
Wl
Wl
Wl
Wl
Wl
WY
WY
WY
WY
WY
WY
WY
WY
WY
WY
WY
Ml
Wl
AZ
AZ
AZ
AL
AL
AL
AL
WV
WV
AR
15
18
18
21
51
77
356
15
10
10
10
106
106
220
330
160
210
330
50
398
750
750
750
684
687
687
688
639
639
815
1
1
1
1
1
1
2
1
1
1
1
1
1
1
1
1
1
3
1
2
3
3
3
2
2
2
2
2
2
3
10
57
57
57
57
57
142
22
73
73
73
8
8
8
8
36
36
186
16
138
348
348
348
73
73
73
73
31
31
30
3,373,140
19,767,691
19,767,691
21,221,307
28,803,600
33,564,993
98,844,475
7,681,834
22,120,867
22,120,867
22,120,867
5,447,933
5,440,496
7,155,406
8,291,718
27,629,118
30,459,162
95,198,954
8,147,501
97,551,759
312,653,688
311,741,926
308,739,092
72,453,897
72,325,000
72,389,499
72,163,306
34,629,535
34,511,038
29,247,265
233
1,123
1,123
1,006
565
436
277
526
2,190
2,190
2,190
51
51
33
25
173
145
288
163
245
417
416
412
106
105
105
105
54
54
36
62
-------
6009_B_2
6016_B_1
6017_B_1
6017_B_2
6018_B_2
6019_B_1
6021_B_C1
6021_B_C2
6021_B_C3
6030_B_1
6030_B_2
6031_B_2
6034_B_1
6034_B_2
6041_B_1
6041_B_2
6041_B_3
6041_B_4
6052_B_1
6052_B_2
6055_B_2B1
6055_B_2B2
6055_B_2B3
6061_B_1
6061_B_2
6064_B_N1
6065_B_1
6068_B_1
6068_B_2
6068 B 3
White Bluff
Duck Creek
Newton
Newton
East Bend
WH Zimmer
Craig
Craig
Craig
Coal Creek
Coal Creek
Killen Station
Belle River
Belle River
H L Spurlock
H L Spurlock
H L Spurlock
H L Spurlock
Wansley
Wansley
Big Cajun 2
Big Cajun 2
Big Cajun 2
R D Morrow
R D Morrow
Nearman Creek
latan
Jeffrey Energy Center
Jeffrey Energy Center
Jeffrey Energy Center
AR
IL
IL
IL
KY
OH
CO
CO
CO
ND
ND
OH
Ml
Ml
KY
KY
KY
KY
GA
GA
LA
LA
LA
MS
MS
KS
MO
KS
KS
KS
825
335
557
569
600
1,300
428
428
418
554
560
615
698
698
315
509
268
268
891
892
580
575
588
180
180
229
651
730
730
730
3
2
2
2
3
4
3
3
3
2
2
2
4
4
2
2
2
2
3
3
2
2
2
1
1
2
2
2
2
2
30
80
32
32
81
129
62
62
62
85
85
36
115
115
43
43
43
43
205
205
3
3
3
8
8
36
23
89
89
89
29,904,002
65,045,755
21,256,386
21,218,914
60,069,860
110,317,488
43,725,334
44,007,279
43,820,042
58,252,800
78,618,531
32,401,966
57,929,531
65,882,626
34,299,690
43,854,659
31,686,751
30,443,356
125,379,945
125,632,090
2,561,145
2,555,499
2,531,971
6,731,374
6,804,328
19,542,070
23,906,085
85,285,064
86,254,355
88,473,899
36
194
38
37
100
85
102
103
105
105
140
53
83
94
109
86
118
114
141
141
4
4
4
37
38
85
37
117
118
121
63
-------
6071_B_1
6071_B_2&3
6073_B_1
6073_B_2
6076_B_1
6076_B_2
6076_B_3
6076_B_4
6077_B_1
6077_B_2
6082_B_1
6085_B_14
6085_B_15
6085_B_17
6085_B_18
6089_B_B1
6090_B_1
6090_B_2
6090_B_3
6094_B_1
6094_B_2
6094_B_3
6095_B_1
6095_B_2
6096_B_1
6096_B_2
6098_B_1
6101_B_BW91
6106_B_1SG
6113 B 1
Trimble County
Trimble County
Victor J Daniel Jr
Victor J Daniel Jr
Colstrip
Colstrip
Colstrip
Colstrip
Gerald Gentleman
Gerald Gentleman
AES Somerset LLC
R M Schahfer
R M Schahfer
R M Schahfer
R M Schahfer
Lewis & Clark
Sherburne County
Sherburne County
Sherburne County
Bruce Mansfield
Bruce Mansfield
Bruce Mansfield
Sooner
Sooner
Nebraska City
Nebraska City
Big Stone
Wyodak
Board man
Gibson
KY
KY
MS
MS
MT
MT
MT
MT
NE
NE
NY
IN
IN
IN
IN
MT
MN
MN
MN
PA
PA
PA
OK
OK
NE
NE
SD
WY
OR
IN
383
760
514
514
307
307
740
740
665
700
681
431
472
361
361
52
762
752
936
830
830
830
535
540
646
663
470
335
585
630
3
3
2
2
2
2
2
2
2
2
6
2
2
2
2
1
4
4
4
5
5
5
5
5
2
2
2
3
3
3
142
142
6
6
261
261
261
261
33
33
278
36
36
36
36
19
230
230
230
83
83
83
237
237
45
17
75
207
292
73
97,287,993
115,264,482
5,020,082
5,000,070
184,856,344
184,856,344
288,152,024
288,152,024
32,410,571
31,478,432
170,834,291
31,648,586
32,892,605
29,462,210
29,060,625
10,381,544
186,587,670
181,960,628
209,343,996
68,945,809
68,639,498
67,538,385
138,736,724
148,708,188
44,246,688
15,623,098
63,989,316
123,430,969
156,464,937
64,635,948
254
152
10
10
602
602
389
389
49
45
251
73
70
82
81
198
245
242
224
83
83
81
259
275
68
24
136
368
267
103
64
-------
6113_B_2
6113_B_3
6113_B_4
6113_B_5
6124_B_1
6136_B_1
6137_B_1
6137_B_2
6138_B_1
6139_B_1
6139_B_2
6139_B_3
6146_B_1
6146_B_2
6146_B_3
6147_B_1
6147_B_2
6147_B_3
6155_B_1
6155_B_2
6165_B_1
6165_B_2
6165_B_3
6166_B_MB1
6166_B_MB2
6170_B_1
6170_B_2
6177_B_U1B
6177_B_U2B
6178 B 1
Gibson
Gibson
Gibson
Gibson
Mclntosh
Gibbons Creek
A B Brown
A B Brown
Flint Creek
Welsh
Welsh
Welsh
Martin Lake
Martin Lake
Martin Lake
Monticello
Monticello
Monticello
Rush Island
Rush Island
Hunter
Hunter
Hunter
Rockport
Rockport
Pleasant Prairie
Pleasant Prairie
Coronado
Coronado
Coleto Creek
IN
IN
IN
IN
GA
TX
IN
IN
AR
TX
TX
TX
TX
TX
TX
TX
TX
TX
MO
MO
UT
UT
UT
IN
IN
Wl
Wl
AZ
AZ
TX
628
628
622
620
157
462
245
245
528
528
528
528
750
750
750
565
565
750
604
604
430
430
460
1,300
1,300
617
617
395
390
632
3
3
3
3
2
2
3
3
6
2
2
2
4
4
4
2
2
3
4
4
2
2
2
4
4
3
3
2
2
4
73
73
73
73
174
8
51
51
303
26
26
26
16
16
16
27
27
41
218
218
94
94
94
142
142
72
72
132
132
26
64,690,650
64,157,149
64,544,530
65,515,933
98,023,860
6,109,161
27,652,839
27,652,839
183,956,789
23,265,057
22,953,307
22,977,196
13,579,347
13,422,881
13,196,821
25,810,168
25,648,477
37,072,040
158,885,720
153,186,703
81,186,634
81,003,689
83,041,697
138,145,250
138,981,337
55,255,225
55,822,411
108,847,521
105,111,801
21,145,534
103
102
104
106
626
13
113
113
348
44
43
44
18
18
18
46
45
49
263
254
189
188
181
106
107
90
90
276
270
33
65
-------
6179_B_1
6179_B_2
6179_B_3
6180_B_OG1
6180_B_OG2
6181_B_1
6181_B_2
6183_B_SM-1
6190_B_2
6190_B_3A
6190_B_3B
6193_B_061B
6193_B_062B
6193_B_063B
6194_B_171B
6194_B_172B
6195_B_1
6204_B_1
6204_B_2
6204_B_3
6213_B_1SG1
6213_B_2SG1
6225_B_1
6238_B_1A
6248_B_1
6249_B_1
6249_B_2
6249_B_3
6249_B_4
6250 B 1A
Fayette Power Project
Fayette Power Project
Fayette Power Project
Oak Grove
Oak Grove
J T Deely
J T Deely
San Miguel
Rodemacher
Rodemacher
Rodemacher
Harrington
Harrington
Harrington
Tolk
Tolk
Southwest Power Station
Laramie River Station
Laramie River Station
Laramie River Station
Merom
Merom
Jasper 2
Pearl Station
Pawnee
Winyah
Winyah
Winyah
Winyah
Mayo
TX
TX
TX
TX
TX
TX
TX
TX
LA
LA
LA
TX
TX
TX
TX
TX
MO
WY
WY
WY
IN
IN
IN
IL
CO
SC
SC
SC
SC
NC
598
598
445
800
800
385
385
391
523
330
330
347
347
347
535
545
178
565
570
570
507
493
14
22
505
295
295
295
270
371
5
5
4
6
6
2
2
3
2
1
1
4
4
4
2
2
3
4
4
4
2
2
1
1
2
1
1
1
1
4
98
98
64
190
190
30
30
62
27
5
5
42
42
42
24
24
224
154
154
154
65
65
3
6
13
130
130
130
130
320
65,108,619
64,482,723
44,478,896
85,241,342
85,241,342
27,795,726
27,756,673
45,994,741
25,318,899
5,011,157
5,011,157
22,996,183
24,424,959
24,863,255
21,681,861
21,315,741
115,261,948
86,961,102
83,331,016
92,413,957
62,606,265
64,220,141
866,561
2,112,513
8,921,462
121,732,828
122,722,703
121,333,096
120,256,266
194,458,700
109
108
100
107
107
72
72
118
48
15
15
66
70
72
41
39
648
154
146
162
123
130
62
96
18
413
416
411
445
524
66
-------
6250_B_1B
6254_B_1
6257_B_1
6257_B_2
6257_B_3
6257_B_4
6264_B_1
6469_B_B1
6469_B_B2
6481_B_1SGA
6481_B_2SGA
6639_B_G1
6639_B_G2
6641_B_1
6641_B_2
6648_B_4
6664_B_101
6705_B_1
6705_B_2
6705_B_3
6705_B_4
6761_B_101
6768_B_1
6772_B_1
6823_B_W1
7030_B_U1
7030_B_U2
7097_B_BLR1
7097_B_BLR2
7210 B COP1
Mayo
Ottumwa
Scherer
Scherer
Scherer
Scherer
Mountaineer
Antelope Valley
Antelope Valley
Intermountain Power Project
Intermountain Power Project
R D Green
R D Green
Independence
Independence
Sandow
Louisa
Warrick
Warrick
Warrick
Warrick
Rawhide
Sikeston Power Station
Hugo
D B Wilson
Twin Oaks Power One
Twin Oaks Power One
J K Spruce
J K Spruce
Cope
NC
IA
GA
GA
GA
GA
WV
ND
ND
UT
UT
KY
KY
AR
AR
TX
IA
IN
IN
IN
IN
CO
MO
OK
KY
TX
TX
TX
TX
SC
371
673
837
843
875
850
1,300
450
450
900
900
231
233
836
842
545
745
136
136
136
300
272
233
440
420
152
153
555
750
420
4
2
3
3
3
3
3
2
2
3
3
2
2
4
4
4
2
2
2
2
2
2
2
2
2
2
2
3
3
2
320
116
233
233
233
233
50
59
59
233
233
8
8
47
47
107
59
17
17
17
17
18
36
67
49
13
13
58
58
177
194,458,700
87,704,788
241,767,423
243,015,931
247,595,035
243,874,806
51,914,394
50,262,299
50,577,883
158,299,880
158,299,880
5,747,905
5,770,269
37,254,469
37,171,856
74,584,612
61,830,763
9,509,125
9,523,228
9,537,272
12,924,387
12,342,549
23,625,426
58,910,578
36,972,967
5,921,171
6,858,395
44,996,468
48,312,157
152,775,716
524
130
289
288
283
287
40
112
112
176
176
25
25
45
44
137
83
70
70
70
43
45
101
134
88
39
45
81
64
364
67
-------
7213_B_1
7213_B_2
7242_G_1CA
7242_G_1CT
7286_B_1
7286_B_2
7286_B_3
7286_B_4
7343_B_4
7504_B_2
7537_B_1A
7537_B_1B
7549_B_1
7549_B_2
7549_B_3
7652_B_D-1
7652_B_D-2
7652_B_D-3
7652_B_D-4
7737_B_B001
7790_B_1-1
7902_B_1
8023_B_1
8023_B_2
8042_B_1
8042_B_2
8066_B_BW71
8066_B_BW72
8066_B_BW73
8066 B BW74
Clover
Clover
Polk
Polk
Richard Gorsuch
Richard Gorsuch
Richard Gorsuch
Richard Gorsuch
George Neal South
Neil Simpson II
North Branch
North Branch
Milwaukee County
Milwaukee County
Milwaukee County
US DOE Savannah River Site (D Area)
US DOE Savannah River Site (D Area)
US DOE Savannah River Site (D Area)
US DOE Savannah River Site (D Area)
Cogen South
Bonanza
Pirkey
Columbia
Columbia
Belews Creek
Belews Creek
Jim Bridger
Jim Bridger
Jim Bridger
Jim Bridger
VA
VA
FL
FL
OH
OH
OH
OH
IA
WY
WV
WV
Wl
Wl
Wl
SC
SC
SC
SC
SC
UT
TX
Wl
Wl
NC
NC
WY
WY
WY
WY
431
434
123
132
50
50
50
50
632
80
37
37
3
3
3
20
20
20
20
90
468
675
555
559
1,115
1,115
530
530
530
530
4
5
1
1
1
1
1
1
2
1
1
1
1
1
1
1
1
1
1
1
5
2
4
4
3
3
2
2
2
2
280
431
1
1
5
5
5
5
94
23
10
10
5
5
5
30
30
30
30
82
75
4
306
306
122
122
3
3
3
3
187,989,514
217,508,623
689,955
708,828
2,652,682
2,652,682
2,652,682
2,652,682
100,888,536
13,829,794
4,456,718
4,315,178
1,001,342
958,082
958,082
10,455,104
10,455,104
10,455,104
10,455,104
50,925,685
40,737,592
4,246,866
219,530,738
214,992,053
76,553,763
76,537,100
2,411,220
2,418,842
2,404,606
2,417,759
436
501
6
5
53
53
53
53
160
173
120
117
303
290
290
533
533
533
533
566
87
6
396
385
69
69
5
5
5
5
68
-------
8069_B_1
8069_B_2
8102_B_1
8102_B_2
8219_B_1
8222_B_B1
8223_B_1
8223_B_2
8223_B_3
8223_B_4
8224_B_1
8224_B_2
8226_B_1
10002_B_CFB
10003_B_BLR3
10003_B_BLR4
10003_B_BLR5
10030_B_COGEN1
10043_B_B01
10071_B_1A
10071_B_1B
10071_B_1C
10071_B_2A
10071_B_2B
10071_B_2C
10075_B_1
10075_B_2
10075_B_3
10113_B_CFB1
10113 B CFB2
Huntington
Huntington
General James M Gavin
General James M Gavin
Ray D Nixon
Coyote
Springerville
Springerville
Springerville
Springerville
North Valmy
North Valmy
Cheswick
ACE Cogeneration Facility
Trigen Colorado Energy
Trigen Colorado Energy
Trigen Colorado Energy
NRG Energy Center Dover
Logan Generating Plant
Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Taconite Harbor Energy Center
Taconite Harbor Energy Center
Taconite Harbor Energy Center
John B Rich Memorial Power Station
John B Rich Memorial Power Station
UT
UT
OH
OH
CO
ND
AZ
AZ
AZ
AZ
NV
NV
PA
CA
CO
CO
CO
DE
NJ
VA
VA
VA
VA
VA
VA
MN
MN
MN
PA
PA
445
450
1,310
1,300
208
427
400
400
400
400
254
268
580
101
8
8
8
16
219
19
19
19
19
19
19
65
67
68
40
40
2
2
3
3
2
2
2
2
2
2
3
3
3
1
1
1
1
1
3
1
1
1
1
1
1
1
1
1
1
1
68
68
52
52
130
59
170
170
170
170
420
420
30
55
17
17
17
41
7
53
53
53
53
53
53
77
77
77
22
22
63,247,668
63,434,031
49,730,161
49,430,685
91,347,020
50,345,130
137,893,456
137,336,825
142,795,380
131,249,797
246,905,695
262,664,147
23,108,254
36,115,023
4,224,070
4,224,070
4,462,765
13,762,699
3,257,942
18,675,110
17,966,383
17,966,383
18,675,110
17,966,383
17,966,383
43,873,377
44,056,543
44,508,992
10,166,547
9,865,959
142
141
38
38
439
118
345
343
357
328
972
980
40
357
521
521
551
860
15
973
936
936
973
936
936
675
658
655
254
247
69
-------
10143_B.
10151_B.
10151_B.
10207.
10207.
10207.
10333.
10343_B_
10367_B_
10368_B_
10369_B_
10370_B_
10371_B_
10373_B_
10377_
10377_
10377_
10377_
10377_
10377_
10378_
10378_
10378_
10378_
10378_
10378_
10379_
10379_
10379_
10380 B
_ABB01
.BLR1A
.BLR1B
_B_1
_B_2
_B_3
_B_1
.SG-101
CB1302
CB1302
CB1302
CB1302
CB1302
CB1302
B_1A
B_1B
B_1C
B_2A
B_2B
B_2C
B_1A
B_1B
B_1C
B_2A
B_2B
B_2C
B_1A
B_1B
B_1C
A BLR
Colver Power Project
Grant Town Power Plant
Grant Town Power Plant
Hercules Missouri Chemical Works
Hercules Missouri Chemical Works
Hercules Missouri Chemical Works
Central Power & Lime
Foster Wheeler Mt Carmel Cogen
East Third Street Power Plant
Loveridge Road Power Plant
Wilbur West Power Plant
Wilbur East Power Plant
Nichols Road Power Plant
Hanford
Cogentrix Hopewell
Cogentrix Hopewell
Cogentrix Hopewell
Cogentrix Hopewell
Cogentrix Hopewell
Cogentrix Hopewell
Primary Energy Southport
Primary Energy Southport
Primary Energy Southport
Primary Energy Southport
Primary Energy Southport
Primary Energy Southport
Primary Energy Roxboro
Primary Energy Roxboro
Primary Energy Roxboro
Elizabethtown Power LLC
PA
WV
WV
MO
MO
MO
FL
PA
CA
CA
CA
CA
CA
CA
VA
VA
VA
VA
VA
VA
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
110
40
40
6
6
6
139
43
20
19
19
19
19
25
18
18
18
18
18
18
18
18
18
18
18
18
19
19
19
16
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
16
14
14
3
3
3
5
22
4
3
2
3
3
22
10
10
10
10
10
10
173
173
173
173
173
173
24
24
24
129
7,296,841
6,230,377
6,068,111
668,369
668,369
668,369
3,407,144
10,975,235
1,397,893
1,250,255
644,904
1,043,072
1,298,925
8,730,145
3,417,788
3,531,133
3,417,788
3,531,133
3,417,788
3,417,788
59,585,090
57,630,632
57,630,632
59,585,090
57,630,632
57,630,632
8,355,164
8,092,596
8,092,596
42,742,982
66
156
152
117
117
117
25
255
72
66
34
55
68
352
188
194
188
194
188
188
3,347
3,238
3,238
3,347
3,238
3,238
447
433
433
2,671
70
-------
10380_B_BBLR
10382_B_UNIT1
10382_B_UNIT2
10384_B_1A
10384_B_1B
10384_B_2A
10384_B_2B
10464_B_E0001
10464_B_E0002
10464_B_E0003
10477_B_P1
10477_B_P2
10495_B_6
10495_B_7
10566_B_BOIL1
10566_B_BOIL2
10601_G_GEN1
10603_B_031
10641_B_B1
10641_B_B2
10670_B_AAB001
10671_B_1A
10671_B_1B
10671_B_2A
10671_B_2B
10672_B_CBA
10672_B_CBB
10672_B_CBC
10675_B_A
10675 B B
Elizabethtown Power LLC
Lumberton
Lumberton
Edgecombe GenCo
Edgecombe GenCo
Edgecombe GenCo
Edgecombe GenCo
Black River Generation
Black River Generation
Black River Generation
Wisconsin Rapids Pulp Mill
Wisconsin Rapids Pulp Mill
Rumford Cogeneration
Rumford Cogeneration
Chambers Cogeneration LP
Chambers Cogeneration LP
BP Wilmington Calciner
Ebensburg Power
Cambria Cogen
Cambria Cogen
AES Deepwater
AES Shady Point
AES Shady Point
AES Shady Point
AES Shady Point
Cedar Bay Generating LP
Cedar Bay Generating LP
Cedar Bay Generating LP
AES Thames
AES Thames
NC
NC
NC
NC
NC
NC
NC
NY
NY
NY
Wl
Wl
ME
ME
NJ
NJ
CA
PA
PA
PA
TX
OK
OK
OK
OK
FL
FL
FL
CT
CT
16
16
16
29
29
29
29
18
18
18
11
11
43
43
131
131
29
50
44
44
140
80
80
80
80
83
83
83
91
91
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
1
1
2
1
1
1
1
1
1
1
1
1
129
118
118
36
36
36
36
27
27
27
80
80
24
24
17
17
3
4
3
3
0
3
3
3
3
20
20
20
26
26
42,742,982
39,366,830
39,366,830
14,989,978
14,534,809
14,989,978
14,534,809
9,340,465
8,971,022
8,971,022
22,287,032
22,287,032
11,293,272
10,978,023
9,093,687
9,238,900
1,039,284
2,168,090
1,426,559
1,388,167
184,032
1,973,180
1,965,567
1,973,180
1,965,567
11,321,540
11,679,195
11,679,195
15,600,819
15,682,088
2,671
2,460
2,460
519
503
519
503
510
490
490
1,990
1,990
266
258
69
71
36
44
32
32
1
25
25
25
25
136
140
140
172
173
71
-------
10676_B_2
10676_B_3
10676_B_4
10676_B_5
10678_B_BLR1
10684_B_BLR25
10684_B_BLR26
10743_B_CFB1
10743_B_CFB2
10768_B_CFB
10769_B_CFB
10771_B_1
10771_B_2
10773_B_1
10773_B_2
10774_B_1
10774_B_2
10784_B_BLR1
10849_B_BLR1
10849_B_BLR2
50012_B_BLR4
50030_B_1A
50030_B_2A
50039_B_1
50130_B_BLR1
50130_B_BLR2
50202_B_1
50368_G_TG1
50368_G_TG2
50388 B K1
AES Beaver Valley Partners Beaver
AES Beaver Valley Partners Beaver
AES Beaver Valley Partners Beaver
AES Beaver Valley Partners Beaver
AES Warrior Run Cogeneration Facility
Argus Cogen Plant
Argus Cogen Plant
Morgantown Energy Facility
Morgantown Energy Facility
Rio Bravo Jasmin
Rio Bravo Poso
Hopewell
Hopewell
Altavista Power Station
Altavista Power Station
Southampton Power Station
Southampton Power Station
Colstrip Energy LP
Silver Bay Power
Silver Bay Power
Alloy Steam Station
Nelson Industrial Steam and Operating
Nelson Industrial Steam and Operating
Kline Township Cogen Facility
G F Weaton Power Station
G F Weaton Power Station
WPS Power Niagara
Cornell University Central Heat
Cornell University Central Heat
Phillips 66 Carbon Plant
PA
PA
PA
PA
MD
CA
CA
WV
WV
CA
CA
VA
VA
VA
VA
VA
VA
MT
MN
MN
WV
LA
LA
PA
PA
PA
NY
NY
NY
CA
43
43
43
17
180
25
25
25
25
33
33
32
32
32
32
63
37
35
36
69
38
107
106
50
56
56
53
1
5
10
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
1
1
1
1
1
4
4
4
4
13
55
55
12
12
29
9
10
10
7
7
21
21
136
53
53
16
7
7
27
3
3
3
3
3
1
2,100,058
2,159,729
2,159,729
1,520,200
10,326,468
20,748,431
20,748,431
4,578,240
4,417,517
12,560,352
4,078,042
4,433,144
4,433,144
3,025,687
3,025,687
11,523,948
9,507,426
60,677,814
23,127,868
29,467,498
6,888,251
2,705,642
2,679,457
13,837,247
1,630,715
1,630,715
1,434,035
268,863
542,420
197,169
49
50
50
89
57
830
830
183
177
381
124
141
141
96
96
183
260
1,734
642
427
181
25
25
277
29
29
27
269
102
20
72
-------
50388_B_K2
50397_B_1 PB035
50397_B_3PB033
50397_B_4PB034
50397_B_5PB036
50410_B_10
50611_B_031
50651_B_1
50651_B_2
50651_B_3
50651_B_4
50651_B_5
50651_G_GEN2
50776_B_BLR1
50776_B_BLR2
50806_B_PB4
50835_B_1
50835_B_2
50879_B_BLR1
50888_B_BLR1
50931_B_BLR1
50931_B_BLR2
50951_B_1
50974_B_UNIT 1
50974_B_UNIT2
50976_B_AAB01
52007_B_BLR1
52007_B_BLR2
52071_B_5A
52071 B 5B
Phillips 66 Carbon Plant
P H Glatfelter
P H Glatfelter
P H Glatfelter
P H Glatfelter
Chester Operations
WPS Westwood Generation LLC
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Panther Creek Energy Facility
Panther Creek Energy Facility
Stone Container Florence Mill
TES Filer City Station
TES Filer City Station
Wheelabrator Frackville Energy
Northampton Generating Company
Yellowstone Energy LP
Yellowstone Energy LP
Sunnyside Cogen Associates
Scrubgrass Generating
Scrubgrass Generating
Indiantown Cogeneration LP
Mecklenburg Power Station
Mecklenburg Power Station
Sandow 5
Sandow 5
CA
PA
PA
PA
PA
PA
PA
NY
NY
NY
NY
NY
NY
PA
PA
SC
Ml
Ml
PA
PA
MT
MT
UT
PA
PA
FL
VA
VA
TX
TX
10
9
4
9
36
36
30
11
11
11
11
11
11
42
42
75
30
30
45
112
28
28
51
43
43
330
69
69
300
300
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
1
1
2
2
1
7
7
7
7
0
9
8
8
8
8
8
8
22
22
122
42
42
21
5
149
149
15
8
8
4
15
15
32
32
197,169
1,841,605
1,493,030
1,874,010
3,138,015
165,409
3,969,914
2,211,538
2,243,056
2,243,056
2,243,056
2,243,056
2,211,538
10,108,238
10,224,344
69,382,961
17,747,919
17,141,107
10,414,793
3,307,302
65,987,299
58,025,007
7,903,915
3,993,426
3,881,950
3,323,473
8,567,737
8,567,737
23,260,335
23,260,335
20
212
373
208
87
5
132
199
202
202
202
202
201
244
246
928
592
571
234
30
2,400
2,110
155
94
91
10
124
124
78
78
73
-------
54035_B_BLR1
54081_B_1A
54081_B_1B
54081_B_2A
54081_B_2B
54081_B_3A
54081_B_3B
54081_B_4A
54081_B_4B
54144_B_BRBR1
54224_B_GEN6
54238_B_N64514
54238_B_N64516
54304_B_1A
54406_G_1
54406_G_2
54626_B_BL01
54634_B_1
54677_B_HRB
54677_G_TG-2
54755_B_BLR2
54775_B_BLR10
54775_B_BLR11
54992_G_ST
55076_B_AA001
55076_B_AA002
55360_B_1
55479_B_3
55749_B_PC1
55856 B PC1
Westmoreland Roanoke Valley I
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Piney Creek Project
Franklin Heating Station
Port of Stockton District Energy Fac
Port of Stockton District Energy Fac
Birchwood Power
Capitol Heat and Power
Capitol Heat and Power
Mt Poso Cogeneration
St Nicholas Cogen Project
CM Carbon LLC
CM Carbon LLC
Westmoreland Roanoke Valley II
University of Iowa Main Power Plant
University of Iowa Main Power Plant
Fellsway Development LLC
Red Hills Generating Facility
Red Hills Generating Facility
Two Elk Generating Station
Wygen 1
Hardin Generator Project
Prairie State Generating Company LLC
NC
VA
VA
VA
VA
VA
VA
VA
VA
PA
MN
CA
CA
VA
Wl
Wl
CA
PA
LA
LA
NC
IA
IA
MA
MS
MS
WY
WY
MT
IL
165
26
26
26
26
21
21
21
21
33
3
22
22
239
1
1
52
88
23
23
44
4
4
0
220
220
300
70
109
800
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
1
1
3
62
8
8
8
8
8
8
8
8
16
43
3
3
29
28
28
18
24
1
1
9
12
12
4
6
6
88
22
113
102
36,771,503
3,050,662
2,948,358
3,050,662
2,948,358
2,820,983
2,723,771
2,820,983
2,723,771
6,808,383
7,175,049
997,963
958,629
25,665,810
2,967,700
2,967,700
9,385,483
14,921,531
409,816
409,816
4,516,042
2,476,778
2,476,778
345,520
5,085,298
5,209,367
32,932,652
12,384,742
76,683,994
75,746,741
223
116
112
116
112
132
128
132
128
209
2,563
45
44
107
3,297
2,968
180
170
18
18
103
590
590
1,728
23
24
110
177
706
95
74
-------
55856_B_PC2
56037_G_1
56068_B_1
56068_B_2
56163_B_1
56163_B_2
56163_B_3
56163_B_4
56224_B_001
56319_B_4
56319_B_5
56456_B_STG1
56671_B_1
82794_C_1
82821_B_1
82886_C_1
82909_C_1
82916_C_1
82932_C_1
82934_C_1
82998_B_CFB1
82998 B CFB2
Prairie State Generating Company LLC
Fox Valley Energy Center
Elm Road Generating Station
Elm Road Generating Station
KUCC
KUCC
KUCC
KUCC
TS Power Plant
Wygen
Wygen
Plum Point Energy
Longview Power
ERCT_TX_Coal steam
Great River Energy Spiritwood Station
NWPE_WY_Coal steam
RFCOJNJGCC
RMPA_CO_Coal steam
SPPN_KS_Coal steam
SPPN_MO_Coal steam
Virginia City Hybrid Energy Center
Virginia City Hybrid Energy Center
IL
Wl
Wl
Wl
UT
UT
UT
UT
NV
WY
WY
AR
WV
TX
ND
WY
IN
CO
KS
MO
VA
VA
800
7
617
617
30
30
30
65
200
90
100
665
695
300
99
422
630
18
22
1,150
293
293
3
1
3
3
1
1
1
1
2
1
1
2
2
2
1
3
3
1
1
3
3
3
102
12
87
87
5
5
5
5
279
22
22
34
21
8
14
212
69
11
10
82
168
168
75,746,741
2,829,794
69,303,550
69,303,550
2,097,370
2,097,370
2,097,370
2,599,586
166,191,132
12,811,795
13,317,187
33,548,267
21,085,857
3,520,181
8,403,970
111,573,136
56,903,399
3,744,305
3,755,430
79,762,328
99,750,208
99,750,208
95
435
112
112
70
70
70
40
831
142
133
50
30
12
85
264
90
208
171
69
341
341
75
-------
5.4.3 Mercury Control Capabilities
EPA Base Case v4.10_PTox offers two options for meeting mercury reduction requirements: (1)
combinations of SO2, NOX, and particulate controls which deliver mercury reductions as a co-
benefit and (2) Activated Carbon Injection (ACI), a retrofit option specifically designed for
mercury control. These two options are discussed below.
Mercury Control through SO2 and NOX Retrofits
In EPA Base Case v4.10, units that install SO2, NOX, and particulate controls, reduce mercury
emissions as a byproduct of these retrofits. Section 5.4.2 described how EMFs are used in the
base case to capture the unregulated mercury emissions depending on the rank of coal burned,
the generating unit's combustion characteristics, and the specific configuration of SO2, NOX, and
particulate controls (i.e., hot and cold-side electrostatic precipitators (ESPs), fabric filters (also
called "baghouses") and particulate matter (PM) scrubbers). These same EMFs would be
available in mercury policy runs to characterize the mercury reductions that can be achieved by
retrofitting a unit with SCR, SO2 scrubbers and particulate controls. The absence of a federal
mercury emission reduction policy means that these controls appear in the base case in
response to SO2, NOX, or particulate limits or state-level mercury emission requirements.
However, in future model runs where mercury limits are present these same SO2 and NOX
controls could be deliberately installed for mercury control if they provide the least cost option
for meeting mercury policy limits.
Activated Carbon Injection (ACI)
The technology specifically designated for mercury control is Activated Carbon Injection (ACI)
downstream of the combustion process in coal fired units. In preparation for performing
modeling of air toxics, a comprehensive update of ACI cost and performance assumptions was
undertaken by Sargent & Lundy, the same engineering firm that developed the SO2 and NOX
control assumptions used in EPA Base Case v4.10. The ACI update, whose elements are
described below, incorporates the latest field experience through 2010.
Assuming a target of 90% removal from the level of mercury in the coal, three alternative ACI
options were identified as providing the required rate of removal for all possible configurations of
boiler, emission controls, and coal types used in the U.S. electric power sector. The three ACI
options differed based on the type of particulate control device - electrostatic precipitator (ESP)
or pre-existing or new fabric filter (also called a "baghouse"), i.e.,
• ACI with Existing ESP
• ACI with Existing Baghouse
• ACI with an Additional Full Baghouse (also referred to as Toxecon)
All three configurations assume the use of brominated ACI, where a small amount of bromine is
chemically bonded to the powdered carbon which is injected into the flue gas stream. The use
of brominated ACI exploits the discovery that by converting elemental mercury to oxidized
mercury, halogens (like chlorine, iodine, and bromine) can make activated carbon more
effective in capturing the mercury at the high temperatures found in industrial processes like
power generation. The ionic mercury adheres to the activated carbon (and to fly ash and
unburned carbon in the fuel gas) which can be removed efficiently from the flue gas by the
76
-------
participate control device (ESP or fabric filter). In the third option listed above the additional
baghouse is installed downstream of the pre-existing participate matter device and the activated
carbon is injected after the existing controls. This configuration allows the fly ash to be removed
before the mercury controls to preserve its marketability.
The applicable ACI option depends on the coal type burned, its SO2 content, the boiler and
particulate control type and, in some instances, consideration of whether an SO2 scrubber
(FGD) system and SCR NOX post-combustion control are present. Table 5-16 shows the ACI
assignment scheme used in EPA Base Case v4.10_PTox to achieve 90% mercury removal.
77
-------
Table 5-16. Assignment Scheme for Mercury Emissions Control Using Activated Carbon Injection (ACI) in EPA Base Case v4.10_PTox (Proposed
Toxics Rule).
Air pollution controls
Burner Type Particulate Control Type _ . _ .
FRr Cold Side ESP + Fabric
Filter without FGC
„„ Cold Side ESP without
FBC FGC
FBC Fabric Filter - Dry FGD
FBC Fabric Filter
FBC Hot Side ESP with FGC
Non-FBC SerwShF'GC^3^ " DrV FGD
Non-FBC SerwShF'GC^3^
Non-FBC . . -- Wet FGD
Filter with FGC
cor* Cold Side ESP + Fabric o/^o
Non-FBC p.?. ?f ppp + l~aDrlc SCR Dry FGD
Non-FBC p.?. ?f ppp + l~aDrlc SCR Wet FGD
Non-FBC ~ Drv FGD
Filter without FGC
,_ p.. .^ Cold Side ESP ~t~ Fabric
Non-FBC
Non-FBC . . ~ Wet FGD
Bituminous Coal
Sorbent
ACI Toxecon Inj Rate
Required? Required? (Ib/million
acf)
Yes No 2
Yes No 5
No No 0
Yes No 2
Yes Yes 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Subbituminous Coal
Sorbent
ACI Toxecon Inj Rate
Required? Required? (Ib/million
acf)
Yes No 2
Yes No 5
Yes No 2
Yes No 2
Yes Yes 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Lignite Coal
Sorbent
ACI Toxecon Inj Rate
Required? Required? (Ib/million
acf)
Yes No 2
Yes No 5
Yes No 2
Yes No 2
Yes Yes 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
Yes No 2
78
-------
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Cold Side ESP + Fabric
Filter without FGC
Cold Side ESP + Fabric Qrp _ Frn
Filter without FGC SCR Dry FGD
Cold Side ESP + Fabric Qrp .... Frn
Filter without FGC SCR Wet FGD
Cold Side ESP with FGC - Dry FGD
Cold Side ESP with FGC
Cold Side ESP with FGC - Wet FGD
Cold Side ESP with FGC SCR
Cold Side ESP with FGC SCR Dry FGD
Cold Side ESP with FGC SCR Wet FGD
Cold Side ESP without _ _„_
FGC " Dry FGD
Cold Side ESP without
FGC
Cold Side ESP without __ We( pGD
FGC
Cold Side ESP without
FGC SCR
Cold Side ESP without SQR Qry pGD
roL/
Cold Side ESP without Qrp .... cnn
p^rt o^>r\ vvcl roU
Fabric Filter - Dry FGD
Fabric Filter
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
79
2
2
2
2
2
2
2
2
2
5
5
5
5
5
5
2
2
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
2
2
2
2
2
2
2
2
2
5
5
5
5
5
5
2
2
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
2
2
2
2
2
2
2
2
2
5
5
5
5
5
5
2
2
-------
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Non-FBC
Fabric Filter - Wet FGD
Fabric Filter SCR Dry FGD
Fabric Filter SCR
Fabric Filter SCR Wet FGD
Hot Side ESP + Fabric
Filter with FGC
Hot Side ESP + Fabric .... ,-_n
Filter with FGC " Wet FGD
Hot Side ESP + Fabric _ cnn
Filter with FGC " ury i-^u
r-?,' S'd-?1,E[f^+ FabnC SCR Wet FGD
Filter with FGC
Hot Side ESP + Fabric
Filter with FGC SCR Dry FGD
Hot Side ESP + Fabric qrR
Filter with FGC
Hot Side ESP + Fabric _ Fpn
Filter without FGC "" y
Hot Side ESP + Fabric
Filter without FGC
Hot Side ESP + Fabric ... . ___
Filter without FGC " Wet FGD
Hot Side ESP + Fabric
Filter without FGC SCR Dry FGD
Hot Side ESP + Fabric qrR
Filter without FGC bohc
° ' e., . ,-* a rlC SCR Wet FGD
Filter without FGC
Hot Side ESP with FGC - Dry FGD
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes
No
Yes
No
Yes
Yes
No
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
80
2
2
2
2
2
2
0
2
0
2
0
2
2
0
2
2
2
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Yes
Yes
Yes
Yes
Yes
Yes
Y(b)
Yes
Y(b)
Y(b)
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
-------
Non-FBC Hot Side ESP with FGC
Non-FBC Hot Side ESP with FGC
Non-FBC Hot Side ESP with FGC
Non-FBC Hot Side ESP with FGC
Non-FBC Hot Side ESP with FGC
Non-FBC Hot Side ESP without FGC
Non-FBC Hot Side ESP without FGC
Non-FBC Hot Side ESP without FGC
Non-FBC Hot Side ESP without FGC
Non-FBC Hot Side ESP without FGC SCR
Non-FBC Hot Side ESP without FGC
Non-FBC No Control
Non-FBC No Control
Non-FBC No Control
Non-FBC No Control
Non-FBC No Control
Non-FBC No Control
-
Wet FGD
SCR Dry FGD
SCR
SCR Wet FGD
Dry FGD
-
Wet FGD
SCR Dry FGD
SCR
SCR Wet FGD
Dry FGD
-
Wet FGD
SCR Dry FGD
SCR
SCR Wet FGD
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
81
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
-------
Non-FBC PM Scrubber - Dry FGD
Non-FBC PM Scrubber
Non-FBC PM Scrubber - Wet FGD
Non-FBC PM Scrubber SCR Dry FGD
Non-FBC PM Scrubber SCR
Non-FBC PM Scrubber SCR Wet FGD
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Yes Yes 2
Note: In the table above "Toxecon" refers to the option described as "ACI System with an Additional Baghouse" and "ACI + Full Baghouse with a Sorbent Injection Rate of 2 Ibs/million acfm" elsewhere in
this chapter.
82
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Methodology for Obtaining ACI Control Costs: For ACI systems the carbon feed rate dictates
the size of the equipment and resulting costs. The feed rate in turn is a function of the required
removal (in this case 90%) and the type of particulate control device. Engineering experience
had established that a carbon feed rate of 5 pounds of carbon injected for every 1,000,000
actual cubic feet per minute (acfm) of flue gas would provide the stipulated 90% mercury
removal rate for units shown in Table 5-16 as qualifying for ACI systems with existing ESP. For
generating units with fabric filters a 2 pound per million acfm is required. Alternative sets of
costs were developed for each of the three ACI options: ACI systems for units with existing
ESPs, ACI for units with existing fabric filters (baghouses), and the combined cost of ACI plus
an additional baghouse for units that either have no existing particulate control or that require
ACI plus a baghouse in addition to their existing particulate control. There are various reasons
that a combined ACI plus additional baghouse would be required. These include situations
where the existing ESP cannot handle the additional particulate load associate with the ACI or
where SO3 injection is currently in use to condition the flue gas for the ESP. Another cause for
combined ACI and baghouse is use of PRB coal whose combustion produces mostly elemental
mercury, not ionic mercury, due to this coal's low chlorine content.
Capital Cost: Included in the installed capital cost of ACI are
• All equipment
• Installation
• Buildings
• Foundations
• Electrical
If an additional baghouse is required in combination with the ACI, specific installed capital costs
include
• Duct work
• Foundations
• Structural steel
• Induced draft (ID) fan modifications or new booster fans
• Electrical modifications
For the combined ACI and fabric filter option a full size baghouse with an air-to-cloth (A/C) ratio
of 4.0 is assumed, not a polishing baghouse with a 6.0 A/C ratio5. Table 5-17 shows the capital
cost modules and the governing variables for ACI systems.
5 The "air-to-cloth" (A/C) ratio is the volumetric flow, (typically expressed in Actual Cubic Feet per Minute,
ACFM) of flue gas entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth
in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater area of the
cloth required and the higher the cost for a given volumetric flow.
83
-------
Table 5-17. Capital Cost Components and Their Governing Variables for ACI Systems
Module
ACI
Injection -
Carbon
Feed Rate
Additional
Fabric
Filter (if
needed)
Hg
Removal
Rate
X
Retrofit
Difficulty
(1 =
average)
X
X
Particulate
Capture
Type
(ESP or
Baghouse)
X
Heat Rate
(Btu/kWh)
X
X
Unit
Size
(MW)
X
X
Coal
Type
X
A bare installed total cost is calculated from the carbon feed rate based on the required removal
rate, the particulate control, and the flue gas flow rate. The resulting bare installed total cost is
increased by 15% to account for additional engineering and construction management costs,
labor premiums, and contractor profits and fees. The resulting value is the capital, engineering,
and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC
subtotal is increased by 5% to account for owner's home office costs, i.e., owner's engineering,
management, and procurement costs. Since ACI systems are expected to be completed in less
than a year, no Allowance for Funds used During Construction (AFUDC) is provided for ACI
systems by themselves. However, if combined with an additional baghouse, 6% is added to
account for Allowance for Funds used During Construction (AFUDC) which is premised on a 2-
year project duration for the baghouse.
The cost resulting from these calculations is the capital cost factor (expressed in $/kW) that is
used in EPA Base Case v4.10_PTox.
Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an
emission control device. They are proportional to the electrical energy produced and are
expressed in units of $ per MWh. For ACI, Sargent & Lundy identified three components of
VOM: (a) reagent use and unit costs, (b) waste production and disposal cost, (c) cost of
additional power required to run the DSI control (often called the "parasitic load"). For the ACI in
combination with fabric filter option, the VOM includes a fourth component: (d) the cost of filter
bag and cage replacement. (With an assumption that the A/C ratio = 6.0, the bag and cage
replacement cycles are 3 and 9 years respectively.)
For ACI carbon usage is a function of unit size and heat rate. The carbon waste production is
equal to the carbon feed rate. To provide a conservative estimate, the costing analysis
assumed that the carbon is captured in the same particulate collector as the fly ash, making it
84
-------
necessary for both the total fly ash and the carbon to be landfilled. Typical ash contents for
each fuel were used to calculate a total fly ash production rate.
For purposes of modeling, the total VOM includes cost components (a), (b), and, where
applicable, (d) as noted above. Component (c) - cost of additional power for the ACI system - is
factored into IPM, not in the VOM value, but through capacity and heat rate penalties as
described in the next paragraph.
Capacity and Heat Rate Penalty: The amount of electrical power required to operate the ACI
system is represented through a reduction in the amount of electricity that is available for sale to
the grid. For example in the option of a combined ACI system with an additional baghouse, if
0.65% of the unit's electrical generation is needed to operate the combined system, the
generating unit's capacity is reduced by 0.65%. This is the "capacity penalty." At the same time,
to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for
operating the ACI device), the unit's heat rate is scaled up such that a comparable reduction
(0.65% in the previous example) in the new higher heat rate yields the original heat rate. The
factor used to scale up the original heat rate is called "heat rate penalty." It is a modeling
procedure only and does not represent an increase in the unit's actual heat rate (i.e., a
decrease in the unit's generation efficiency). As was the case for FGD in EPA Base Case
v4.10, specific ACI heat rate and capacity penalties are calculated for each installation. For
ACI, the site specific calculations take into account the additional power required for blowers for
the injection system and, where an additional fabric filter is present, the power for the baghouse
compressors.
Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining a
unit. They represent expenses incurred regardless of the extent to which the emission control
system is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent &
Lundy took into account labor and materials costs associated with operations, maintenance, and
administrative functions. The following assumptions were made:
• FOM for operations is based on the number of addition operators needed. For ACI one
(1) additional operator is assumed to be needed.
• FOM for maintenance is a direct function of the ACI capital cost.
• FOM for administration is a function of the FOM for operations and maintenance.
Table 5-18 presents the capital, VOM, and FOM costs as well as the capacity and heat rate
penalties for the three ACI options represented in EPA Base Case v4.10_PTox (Proposed
Toxics Rule). For each ACI option values are shown for an illustrative set of generating units
with a representative range of capacities and heat rates.
Tables 1-3 in Appendix 5-3 contains illustration worksheets of the detailed calculations
performed to obtain the capital, VOM, and FOM costs for examples of the three ACI options
described in this section. The worksheets were developed by Sargent & Lundy6.
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 atwww.epa.gov/airmarkets/proqsreqs/epa-ipm/.
85
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Table 5-18. Illustrative Activated Carbon Injection (ACI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA
Base Case v4.10_PTox (
Control Type
ACI System
with an
Existing ESP
ACI with a
Sorbent
Injection Rate
of 5 Ibs/million
acfm
Assuming
Bituminous
Coal
ACI System
with an
Existing
Baqhouse
ACI with a
Sorbent
Injection Rate
of 2 Ibs/million
acfm
Assuming
Bituminous
Coal
ACI System
with an
Additional
Baqhouse
ACI + Full
Baghouse with
a Sorbent
Injection Rate
of 2 Ibs/million
acfm
Assuming
Bituminous
Coal
Heat Rate
(Btu/kWh)
9,000
10,000
1 1 ,000
9,000
10,000
1 1 ,000
9,000
10,000
1 1 ,000
Proposed Toxics Rule)
Capacity
Penalty
(/o)
0.12
0.13
0.14
0.05
0.05
0.06
0.65
0.65
0.66
Heat Rate
Penalty (%)
0.12
0.13
0.14
0.05
0.05
0.06
0.65
0.66
0.66
Variable O&M
(mills/kWh)
2.76
3.07
3.38
2.24
2.49
2.74
0.50
0.54
0.58
Capacity (MW)
100
Fixed
Capital — 0 ..
-, , O&M
($/kW) ($J^-
32.06 0.13
32.56 0.14
33.04 0.14
27.93 0.12
28.37 0.12
28.80 0.12
240 0.91
259 0.98
278 1 .05
300
Capital Fixed
— , O&M
($/kw> Mff-
12.60 0.05
12.80 0.05
12.99 0.05
10.98 0.05
11.16 0.05
11.32 0.05
182 0.69
197 0.75
212 0.80
500
Capital Fixed
Cost O&M
yr)
8.16 0.03
8.29 0.03
8.41 0.04
7.11 0.03
7.23 0.03
7.33 0.03
162 0.61
176 0.67
189 0.72
700
Capital Fixed
— , O&M
($/kW) PJJJ*-
6.13 0.03
6.23 0.03
6.32 0.03
5.34 0.02
5.43 0.02
5.51 0.02
150 0.57
163 0.62
176 0.67
1000
Fixed
Capital — 0 ..
-, , O&M
($/kW) <$/yk™-
4.53 0.02
4.60 0.02
4.67 0.02
3.95 0.02
4.01 0.02
4.07 0.02
139 0.53
151 0.57
163 0.62
86
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5.5 Hydrogen Chloride (HCI) Control Technologies
Consistent with other analysis performed for the Toxics Rule, hydrogen chloride (HCI) 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 HCI emissions from coal are represented in IPM, the emission control
technologies available for HCI removal, and the cost and performance characteristics of these
technologies.
5.5.1 Chlorine Content of Fuels
HCI 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 HCI 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 HCI Removal Rate Assumptions for Existing and Potential Units
SO2 emission controls on existing and new (potential) units provide the HCI 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 HCI. For existing
conventional pulverized coal units with pre-existing FGD (column 5), the HCI removal rate is 5%
higher than the reported SO2 removal rate up to a maximum of 99% removal. In addition, for
fluidized bed combustion units (column 4) with no FGD and no fabric filter, the HCI removal rate
is the same as the SO2 removal rate up to a maximum of 95%. FBCs with fabric filters have an
HCI removal rate of 95%.
When policies for controlling toxics emissions are modeled, it is assumed prior to performing a
model run that the most cost effective default option for existing coal steam units with FGD
would be to upgrade their FGDs to obtain at least 90% SO2 removal and 99% HCI removal and
then let the model determine if any further reductions are needed. The cost of the FGD
Upgrade Adjustment, as it is called, is assumed to be $100/kW (in 2009$). It is applied in the
model as an FOM cost adder7.
7 The FGD Upgrade Adjustment is applied in the model as a FOM cost adder, where
FOM Adder = FGD Upgrade Adjustment X Capital Charge Rate
= $100/kW ($2009) X 11.3%
= $11.30/kW-yr ($2009)
87
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Table 5-19. HCI Removal Rate Assumptions for Potential (New) and Existing Units in EPA Base Case
v4.10_PTox (Proposed Toxics Rule)
Gas
HCI
Controls ==>
Removal
Rate
Potential
(New)
Supercritical
Pulverized
Coal with Wet
or Dry FGD
99%
Existing Units with FGD
Base Case
Fluidized
Bed
Combustion
(FBC)
Without
fabric filter:
Same as
reported SO2
removal rate
up to a
maximum of
95%
With fabric
filter: 95%
Conventional
Pulverized Coal
(CPC) with Wet
or Dry FGD
Reported SO2
removal rate +
5% up to a
maximum of
99%
Policy Case
Existing Coal Steam
Units with FGD
Upgrade Adjustment
If reported SO2
removal < 90%, unit
incurs cost to upgrade
FGD, so that SO2
removal is 90%. Then,
the resulting HCI
removal rate is 99%
If reported SO2
removal is > 90% and
< 94%, then the unit
incurs a cost to
upgrade FGD and the
HCI removal rate is
99%. (The SO2
removal rate remains
as reported.)
If the reported SO2
removal rate is > 94%,
the unit incurs no
upgrade cost and the
HCI removal rate is
99%.
88
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5.5.3 HCI Retrofit Emission Control Options
Table 5-20 Summary of HCI Emission Control Technology
Assumptions in EPA Base Case v4.10_PTox
(Proposed Toxics Rule)
HCI Control Technology
Options
Limestone Forced
Oxidation (LSFO)
Scrubber
Lime Spray Dryer (LSD)
Dry Sorbent Injection
(DSI)
Scrubber upgrade
adjustment
Applicability
Base case and policy case
Base case and policy case
Base case and policy case
To existing coal steam units
with FGD in policy cases
analyzed for Toxics
Rulemaking
All the retrofit options for HCI emission control are summarized in Table 5-20. The scrubber
upgrade adjustment was discussed above in 5.5.2. The other options are discussed in detail in
the following sections.
5.5.3.1 Wet and Dry FGD
In addition to providing SO2 reductions, wet scrubbers (Limestone Forced Oxidation, LSFO) and
dry scrubbers (Lime Spray Dryer, LSD) reduce HCI as well. For both LSFO and LSD the HCI
removal rate is assumed to be 99% with a floor of 0.0001 Ibs/MMBtu. This is summarized in
columns 2-5 of Table 5-21.
89
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Table 5-21 Summary of Retrofit HCI (and SO2) Emission Control Performance Assumptions in v4.10_PTox (Proposed Toxics Rule)
Performance
Assumptions
Percent Removal
Capacity Penalty
Heat Rate Penalty
Cost (2007$)
Applicability
Sulfur Content
Applicability
Applicable Coal
Types
Limestone Forced Oxidation
(LSFO)
SO2
96%
with a floor of
0.06 Ibs/MMBtu
HCI
99%
with a floor of
0.0001
Ibs/MMBtu
-1 .65%
1 .68%
See Table 5-3 and 5-4
Units > 25 MW
BA, BB, BD, BE, BG, BH, SA, SB,
SD, LD, LE, and LG
Lime Spray Dryer (LSD)
SO2
92%
with a floor of
0.065 Ibs/MMBtu
HCI
99%
with a floor of
0.0001
Ibs/MMBtu
-0.70%
0.71%
See Table 5-3 and 5-4
Units > 25 MW
Coals < 2.0% Sulfur by Weight
BA, BB, BD, BE, SA, SB, SD, LD,
LE, and LG
Dry Sorbent Injection (DSI)1
SO2
With fabric
filter: 70%
With an
electrostatic
percipitator2:
50%
HCI
With fabric filter:
90%
with a floor of
0.0001 Ibs/MMBtu
With an
electrostatic
percipitator2:
60%
with a floor of
0.0001 Ibs/MMBtu
-0.65%
0.65%
See Tables D and E
Units > 25 MW
Coals < 2.0 Ib/mmBtu of SO2
BA, BB, BD, SA, SB, SD, and LD
Notes
1. The cost and performance values shown in this table apply to existing units with pre-existing fabric filters or electrostatic precipitators.
Units with neither ESP nor FF are assumed to have to install a fabric filter in order to qualify for the DSI retrofit.
2. The option to retrofit DSI on existing units with ESP was not offered in the runs performed for the current rulemaking.
90
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5.5.3.2 Dry Sorbent Injection
Besides HCI reductions obtained from FGD, EPA Base Case v4.10_PTox includes dry sorbent
injection (DSI), not previously included in the base case, as a retrofit option for achieving (in
combination with a particulate control device) both SO2 and HCI removal. In DSI for HCI
reduction, a dry sorbent is injected into the flue gas duct where it reacts with the HCI and SO2 in
the flue gas to form a compound, which is then captured in a downstream fabric filter or
electrostatic precipitator (ESP) and disposed of as waste. (A sorbent is a material that takes up
another substance by either adsorption on its surface or absorption internally or in solution. A
sorbent may also chemically react with another substance.) The sorbent assumed in the cost
and performance characterization discussed in this section is trona, a sodium-rich material with
major underground deposits found in Sweetwater County, Wyoming. Trona is typically
delivered with an average particle size of 30 urn diameter, but can be reduced to about 15 urn
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 HCI removal rate is 60% for DSI + ESP and 90% for DSI + fabric filter.
(This is noted in the next-to-the-last column in Table 5-21.) Although the option to retrofit DSI on
existing units with ESP is shown in Table 5-21 it was not offered in the runs performed for the
current rulemaking.
Methodology for Obtaining DSI Control Costs: The engineering firm of Sargent & Lundy, whose
analyses were used to update the cost of SO2 and post-combustion NOX controls in EPA Base
Case , v4.10, performed similar engineering assessments of the cost of DSI retrofits with two
alternative, associated particulate control devices, i.e., ESP and fabric filter (also called a
"baghouse"). Their analysis of DSI noted that the cost drivers of DSI are quite different from
those of wet or dry FGD. Whereas plant size and coal sulfur rates are key underlying
determinants of FGD cost, sorbent feed rate and fly ash waste handling are the main drivers of
the capital cost of DSI with plant size and coal sulfur rates playing a secondary role.
Sorbent feed rate determines the amount of sorbent required and the size and extensiveness of
the DSI installation. The sorbent feed rate needed to achieve a specified percent SO2 or HCI
removal8 is firstly a function of the flue gas SO2 rate (which, in turn, is a function of the sulfur
content of the coal burned, expressed in Ibs of SO2/mmBtu ), the unit's size and heat rate, and
the sorbent particle size (which determines whether in-line milling is needed). The sorbent feed
rate is also a function of the residence time of the sorbent in the flue gas stream and the extent
of mixing and penetration of the sorbent in the flue gas. Residence time, penetration, and
mixing are largely dependent on the type of particulate control device use (electrostatic
precipitator or fabric filter).
8 For purposes of engineering calculations the percent removal is often translated into a corresponding
"Normalized Stoichiometric Ratio" (NSR) associated with a particular percent removal/ where the NSR is defined as
/ moles of sobent inject
\molesofS02influegas
1 (theoretical moles of sorbent required)
91
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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 HCI removal effect is assumed to be 90%, based on information
from Solvay Chemicals (H. Davidson, Dry Sorbent Injection for Multi-pollutant Control Case
Study, CIBO IECT VIII, August, 2010).
The cost of fly ash waste handling, the other key contributor to DSI cost, is a function of the type
of particulate capture device and the flue gas SO2 rate (which, as noted above, is itself a
function of the sulfur content of the coal and the unit's size and heat rate). Fly ash waste
handling costs are also a function of the ash content and the higher heating value (HHV) of the
coal. The governing variables of the key capital cost components of DSI are presented in Table
5-22.
Table 5-22. Capital Cost Components and Their Governing Variables for HCI Removal with DSI.
Module
Sorbent
Feed
Handling
Fly Ash
Waste
Handling
Retrofit
Difficulty
(1 =
average)
X
X
Particulate
Capture
Type
(ESP or
Baghouse)
X
Sorbent
Particle
Size
Require-
ment
(milled or
unmilled)
X
Heat
Rate
(Btu/
kWh)
X
X
SO2
Rate
of coal
(Ib/
MM Btu)
X
Ash
Content
of Coal
(percent)
X
Higher
Heating
Value
(HHV)
of Coal
(Btu/lb)
X
Unit
Size
(MW)
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
92
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expected to be completed in less than a year, no Allowance for Funds used During Construction
(AFUDC) is provided for DSI. The cost resulting from these calculations is the capital cost factor
(expressed in $/kW) that is used in EPA Base Case v4.10_PTox.
Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an
emission control device. They are proportional to the electrical energy produced and are
expressed in units of $ per MWh. For DSI, Sargent & Lundy identified three components of
VOM: (a) costs for sorbent usage, (b) costs associated with waste production and disposal, (c)
cost of additional power required to run the DSI control (often called the "parasitic load"). For
DSI, sorbent usage is a function of the "Normalized Stoichiometric Ratio" and SO2 feed rate. As
noted above the feed rate is a function of the SO2 rate of the coal and the unit's size and heat
rate.
Total waste production involves the production of both reacted and unreacted sorbent and fly
ash. Sorbent waste is a function of the sorbent feed rate with an adjustment for excess sorbent
feed. Use of DSI makes the fly ash unsalable, which means that any fly ash produced must be
landfilled along with the reacted and unreacted sorbent waste. Typical ash contents for each
fuel are used to calculate a total fly ash production rate. The fly ash production is added to the
sorbent waste to account for the total waste stream for the VOM analysis.
For purposes of modeling, the total VOM includes the first two component costs noted in the
previous paragraph, i.e., the costs for sorbent usage and the costs associated with waste
production and disposal,. The last component - cost of additional power - is factored into IPM,
not in the VOM value, but through a capacity and heat rate penalty as described in the next
paragraph.
Capacity and Heat Rate Penalty: The amount of electrical power required to operate the DSI is
represented through a reduction in the amount of electricity that is available for sale to the grid.
For example, if 0.65% of the unit's electrical generation is needed to operate DSI, the
generating unit's capacity is reduced by 0.65%. This is the "capacity penalty." At the same time,
to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for
operating the DSI device), the unit's heat rate is scaled up such that a comparable reduction
(0.65% in the previous example) in the new higher heat rate yields the original heat rate. The
factor used to scale up the original heat rate is called "heat rate penalty." It is a modeling
procedure only and does not represent an increase in the unit's actual heat rate (i.e., a
decrease in the unit's generation efficiency). As was the case for FGD in EPA Base Case
v4.10, specific DSI heat rate and capacity penalties are calculated for each installation. For DSI
the installation specific calculations take into account the additional power required by air
blowers for the injection system, drying equipment for the transport air, and in-line milling
equipment, if required.
Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining an
emission control. They represent expenses incurred regardless of the extent to which the
emission control system is run. They are expressed in units of $ per kW per year. In calculating
FOM Sargent & Lundy took into account labor and materials costs associated with operations,
maintenance, and administrative functions. The following assumptions were made:
• FOM for operations is based on the number of operators needed which is a function of
93
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the size (i.e., MW capacity) of the generating unit. In general for DSI two (2) additional
operators are assumed to be needed.
• FOM for maintenance is a direct function of the DSI capital cost.
• FOM for administration is a function of the FOM for operations and maintenance.
Table 5-23 presents the capital, VOM, and FOM costs as well as the capacity and heat rate
penalties of a DSI retrofit for an illustrative and representative set of generating units with the
capacities and heat rates indicated.
Illustration worksheets of the detailed calculations performed to obtain the capital, VOM, and
FOM costs for an example DSI appear in Appendix 5-4. The worksheets were developed by
Sargent & Lundy9.
9These worksheets were extracted from Sargent & Lundy LLC, IPM Model- Revisions to Cost and
Performance forAPC Technologies: Complete Dry Sorbent Injection Cost Development Methodology
(Project 12301-007), May 2010. The complete report is available for review and downloading at
www.epa.gov/airmarkets/progsregs/epa-ipm/.
94
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Table 5-23. Illustrative Dry Sorbent Injection (DSI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_PTox
(Proposed Toxics Rule).
Control
Type
DSI - FF
Assuming
Bituminous
Coal
DSI - ESP
Assuming
Bituminous
Coal
Heat
Rate
(Btu/
kWh)
9,000
10,000
11,000
9,000
10,000
11,000
S02
Rate
(Ib/
MMBtu)
2.0
2.0
2.0
2.0
2.0
2.0
Capacity
Penalty
0.64
0.71
0.79
1.08
1.20
1.32
Heat
Rate
Penalty
0.65
0.72
0.79
1.10
1.22
1.34
Variable
O&M
(mills/
kWh)
6.05
6.72
7.40
11.23
12.47
13.72
Capacity (MW)
100
yr)
122 2.25
125 2.28
129 2.30
141 2.41
145 2.44
149 2.48
300
yr)
55 0.87
57 0.89
59 0.90
64 0.94
66 0.96
68 0.98
500
yr)
38 0.57
40 0.58
41 0.59
47 0.64
52 0.68
58 0.73
700
yr)
30 0.43
31 0.43
34 0.46
47 0.57
52 0.61
58 0.65
1000
($/kW) ($ykW-
28 0.36
31 0.38
34 0.41
47 0.52
52 0.56
58 0.60
95
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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 HCI emission control. In EPA Base Case v4.10_PTox, an existing or
new fabric filter particulate control device is a pre-condition for installing a DSI retrofit. In the
v4.10_PTox policy case any unit that was retrofit by the model with DSI and did not have an
existing fabric filter incurred the cost of installing a fabric filter. This cost was added to the DSI
costs discussed in section 5.5.3.2. This section describes the methodology used by Sargent &
Lundy to derive the cost of a fabric filter.
The engineering cost analysis is based on a pulse-jet fabric filter which collects particulate
matter on a fabric bag and uses air pulses to dislodge the particulate from the bag surface and
collect it in hoppers for removal via an ash handling system to a silo. This is a mature
technology that has been operating commercially for more than 25 years. "Baghouse" and
"fabric filters" are used interchangeably to refer to such installations.
Capital Cost: Two governing variables are used to derive the bare module capital cost of a
fabric filter. The first of these is the "air-to-cloth" (A/C) ratio. The major driver of fabric filter
capital cost, the A/C ratio is defined as the volumetric flow, (typically expressed in Actual Cubic
Feet per Minute, ACFM) of flue gas entering the baghouse divided by the areas (typically in
square feet) of fabric filter cloth in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0
compared to A/C = 6.0, the greater the area of the cloth required and the higher the cost for a
given volumetric flow.
The other determinant of capital cost is the flue gas volumetric flow rate (in ACFM) which is a
function of the type of coal burned and the unit's size and heat rate.
The capital cost for fabric filters include:
• Duct work modifications,
• Foundations,
• Structural steel,
• Induced draft (ID) fan modifications or new booster fans, and
• Electrical modifications.
After the bare installed total capital cost is calculated, it is increased by 20% to account for
additional engineering and construction management costs, labor premiums, and contractor
profits and fees. The resulting value is the capital, engineering, and construction cost (CECC)
subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to
account for owner's home office costs, i.e., owner's engineering, management, and
procurement costs, and by another 6% to account for Allowance for Funds used During
Construction (AFUDC) which is premised on a 2-year project duration.
The cost resulting from these calculations is the capital cost factor (expressed in $/kW). Fabric
filter capital costs are implemented in EPA Base Case v4.10_PTox as an FOM adder. Plants
that install fabric filters incur a total FOM charge which includes the true FOM associated with
the fabric filter plus a capital cost FOM Adder derived by multiplying the capital cost by a capital
96
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charge rate of 11.3%, i.e.,
Total FOM = True FOM + Capital Cost FOM Adder
where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%
In EPA Base Case v4.10_PTox the capital cost of a fabric filter is based on the use of a
"polishing" fabric filter designed with A/C=6.0. This basis results in a capital cost that is at least
10% less than the cost of a design with A/C=4.0, and assumes that the existing ESP remains in
place and active.
Variable Operating and Maintenance Costs (VOM): For fabric filters the VOM is strictly a
function of the costs of the fabric filter bag and cage translated in a $/MWhr cost based on the
filter and bag replacement cycle for a specified A/C ratio. For units whose A/C ratio = 6.0, the
replacement cycle for the bag is 3 years and the cage is 9 years, whereas for units whose A/C
ratio = 4.0, the bag and cage replacement cycles are 5 and 10 years respectively.
Capacity and Heat Rate Penalty: Conceptually, the capacity and heat rate penalties for fabric
filters represent the amount of electrical power required to operate the baghouse and are
calculated by the same procedure used when calculating the capacity and heat rate penalty for
DSI as described in section 5.5.3.2. The resulting capacity and heat rate penalties are both
0.6%.
However, since fabric filters were not endogenously modeled as a retrofit option, but simply
added to the DSI costs for generating units that do not have an existing baghouse, the capacity
and heat rate penalties described here were not factored into the representation of fabric filters
in EPA Base Case v4.10_PTox.
Fixed Operating and Maintenance Costs (FOM): Sargent & Lundy's engineering analysis
indicated that no additional operations staff would be required for a baghouse. Consequently
the FOM strictly includes two components:
• FOM for maintenance is a direct function of the DSI capital cost.
• FOM for administration is a function of the FOM for operations (which is zero) and
maintenance.
Table 5-24 presents the capital, VOM, and FOM costs for fabric filters as represented in EPA
Base Case v4.10_PTox for an illustrative set of generating units with a representative range of
capacities and heat rates.
Worksheets illustrating the detailed calculations performed to obtain the capital, VOM, and FOM
costs for two example fabric filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) appear in Appendix 5-
5. The worksheets were developed by Sargent & Lundy10.
10 These worksheets were extracted from Sargent & Lundy LLC, IPM Model - Revisions to Cost and
Performance forAPC 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/.
97
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Table 5-24. Illustrative Fabric Filter (Baghouse) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_PTox
(Proposed Toxics Rule).
Coal Type
Bituminous
Heat
Rate
(Btu/
kWh)
9,000
10,000
11,000
Capacity
Penalty
0.60
Heat
Rate
Penalty
0.60
Variable
O&M
(mills/
kWh)
0.15
Capacity (MW)
100
yr)
188 0.8
205 0.9
221 0.9
300
($/°kw) <$;™-
153 0.6
167 0.7
180 0.8
500
($/°kw) <$;™-
139 0.6
151 0.6
163 0.7
700
($/°kw) <$;™-
130 0.6
141 0.6
153 0.6
1000
($/°kw) <$;™-
122 0.5
132 0.6
143 0.6
Notes on Implementation
1. Plant specific fabric filter capital costs shown in this table are implemented in EPA Base Case v4.10_PTox as an FOM adder. Plants that install
fabric filters incur a total FOM charge which includes the true FOM component shown in the above table plus a capital cost FOM Adder derived by
multiplying the capital cost in the table above by a capital charge rate 11.3%, i.e.,
Total FOM = True FOM + Capital Cost FOM Adder
where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%.
Plants that install fabric filters also incur the additional VOM costs shown in the above table.
2. Since the fabric filter costs were not endogenously modeled as a retrofit option, the capacity and heat rate penalties shown in the above table were
not represented in the model.
98
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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)
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iftrmry Control Cost Development Metbodolof y - R*v J
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101
-------
Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCI
(and SO2) Emissions Control in EPA Base Case v4.10_PTox (Proposed Toxics Rule)
Complete Diy Sorbent Injection Cost Development Methodology - Final
Table 1. Example Complete Cost Estimate for a DSI System
w.'IHr-.t
r.T,y. h>.H FW
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102
-------
Complete Dry Sorbeut Injection Cost Development Methodology -Final
Er^ipwlinr
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-------
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)
Table 1. Example Complete Cost Estimate for a 4.0 _VC Bughouse Installation (Costs nre a]] based on -009 dollars)
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104
-------
Toble 2. Esample Complete Co-it Estimate for a 6.0 .VC Bughouse Installation (Co?t5 are all ba;ed on 2009 dollar-*)
u
CECC IllkW) •
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105
-------
Documentation Supplement to Chapter 9 ("Coal")
To allow HCI 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 HCI emission rate (in Ibs/MMBtu) of the coal and the chlorine content of the coal
interchangeably. The HCI emission rate is obtained by multiplying the chlorine content of the
coal by a factor of 1.03. This is an alternate way of expressing chlorine content and is
consistent with using an SO2 emission rate (in Ibs/MMBtu) to express the sulfur content of the
coal.
For EPA Base Case v4.10 the clustering procedure was performed on SO2 and mercury data
only. For Base Case v4.10_PTox it had to be performed jointly on the SO2, mercury, and HCI
data. The addition of HCI 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 HCI equivalent to Tables
9-6 through 9-9. These tables show the SO2, mercury, ash, HCI, and CO2 emission factors that
result after the clustering procedure is performed.
The enhancements made to accommodate the HCI 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 HCI 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/proqsreqs/epa-
ipm/docs/v410/Chapter9.pdf.
9 Coal
• • •
9.1.3 Coal Quality Characteristics
Coal varies by heat content, SO2 content, HCI 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, sub-
bituminous, or lignite) with their associated heat content ranges (as shown in Table 9-3). The
second letter indicates their "sulfur grade," i.e., the SO2 ranges associated with a given type of
coal. (The sulfur grades and associated SO2 ranges are shown in Table 9-4.)
Table 9-3 Coal Rank Heat Content Ranges
Coal Type
Bituminous
Sub-bituminous
Heat Content
(Btu/lb)
>1 0,260 -13,000
> 7,500 -10,260
Classification
B
S
106
-------
Lignite
less than 7,500
L
Table 9-4 Coal Grade SO2 Content Ranges
SO2 Grade
A
B
D
E
G
H
SO2 Content
0.
0.
1.
1.
3.
Range (Ibs/MMBtu)
00-0.80
81 -1.20
21 -1.66
67-3.34
35-5.00
>5.00
The assumptions in EPA Base Case v4.10_PTox regarding the heat, HCI, mercury, SO2, and
ash content of coal are derived from EPA's "Information Collection Request for Electric Utility
Steam Generating Unit Mercury Emissions Information Collection Effort" (ICR)11. A two-year
effort initiated in 1998 and completed in 2000, the ICR had three main components:
(1) identifying all coal-fired units owned and operated by publicly-owned utility companies,
Federal power agencies, rural electric cooperatives, and investor-owned utility generating
companies, (2) obtaining "accurate information on the amount of mercury contained in the as-
fired coal used by each electric utility steam generating unit... with a capacity greater than 25
megawatts electric, as well as accurate information on the total amount of coal burned by each
such unit,", and (3) obtaining data by coal sampling and stack testing at selected units to
characterize mercury reductions from representative unit configurations. Data regarding the
SO2, chlorine, and ash content of the coal used were obtained along with mercury content.
The 1998-2000 ICR resulted in more than 40,000 data points indicating the coal type, sulfur
content, mercury content, ash content, chlorine content, and other characteristics of coal
burned at coal-fired utility units greater than 25 MW.
9.1.4 Emission Factors
To make this data usable in EPA Base Case v4.10_P7ox, the ICR data points were first
grouped by IPM coal grades and IPM coal supply regions. Using the grouped ICR data, the
average heat, SO2, mercury, HCI, and ash content were calculated for each coal grade/supply
region combination. In instances where no data were available for a particular coal grade in a
specific supply region, the national average SO2, HCI, and mercury values for the coal grade
were used as the region's values. The resulting values are shown in Table 9-5.
Data from the ICR can be found at www.epa.gov/ttn/atw/combust/utiltox/mercury.html.
107
-------
Table 9-5 Coal Quality Characteristics by Supply Region and Coal Grade in EPA Base Case v4.10_PTox
Coal
Supply
Region
AL
AZ
CG
CR
CU
IL
IN
KE
KS
KW
LA
MD
ME
MP
MS
MT
ND
NS
OH
Coal
Grade
BB
BD
BE
BB
BA
BB
BA
BD
BA
BB
BD
BE
BG
BH
BD
BE
BG
BH
BA
BB
BD
BE
BG
BG
BD
BE
BG
BH
LE
BB
BD
BE
BG
LD
SA
SD
LE
BB
LD
LE
BB
BD
BE
BB
BD
BE
BG
BH
Heat Content
(MMBtu/Ton)
24.82
24.00
23.82
24.64
21.49
22.01
25.50
22.20
23.80
23.22
23.21
23.00
23.01
22.19
22.62
23.43
23.37
23.41
25.32
25.79
25.33
25.14
24.09
25.32
24.23
24.45
23.93
22.84
14.09
24.64
26.32
24.85
23.26
13.36
18.90
17.23
13.19
21.00
13.70
13.46
26.40
18.10
18.10
24.68
25.55
25.24
24.34
23.92
SO2
Content
(Ibs/MMBtu)
1.1
1.4
2.7
1.1
0.7
0.9
0.7
1.4
0.7
0.9
1.3
2.2
4.6
5.6
1.4
2.3
4.3
6.1
0.7
1.0
1.4
2.1
3.8
4.8
1.6
2.8
4.5
5.7
2.5
1.1
1.6
2.8
3.6
1.4
0.6
1.5
2.8
1.1
1.5
2.3
1.1
1.6
1.8
1.1
1.4
3.1
4.0
6.4
Mercury
Content
(Ibs/TBtu)
4.2
7.3
12.6
5.3
3.1
4.1
3.5
7.0
2.6
4.0
3.1
6.5
6.5
5.4
3.8
5.2
7.2
7.1
3.0
4.8
6.0
7.9
12.0
4.1
5.6
7.1
6.9
8.2
7.3
5.3
7.8
15.6
16.6
8.6
4.2
4.5
12.4
5.3
6.4
8.3
5.3
5.5
8.2
5.7
6.4
18.7
18.5
13.9
Ash
Content
(Ibs/MMBtu)
9.8
10.8
10.7
7.9
7.3
8.4
7.0
8.3
6.3
7.8
8.1
6.6
8.1
9.1
7.4
8.0
8.2
8.6
6.1
6.4
7.4
7.7
10.2
8.5
6.2
7.4
8.0
10.2
17.1
7.9
9.5
11.7
16.6
11.3
4.0
10.1
21.5
7.9
10.7
12.8
7.9
19.6
18.8
9.8
10.3
7.1
8.0
9.1
HCI Content
(Ibs/MMBtu)
0.012
0.029
0.028
0.067
0.040
0.021
0.027
0.096
0.007
0.009
0.008
0.214
0.113
0.103
0.030
0.037
0.028
0.019
0.114
0.112
0.087
0.076
0.041
0.133
0.281
0.199
0.097
0.054
0.014
0.067
0.029
0.072
0.018
0.019
0.007
0.006
0.018
0.067
0.012
0.014
0.067
0.005
0.006
0.083
0.065
0.075
0.072
0.058
Cluster
Number
1
6
1
2
3
1
5
6
1
1
1
3
2
1
5
3
2
2
4
5
4
4
3
4
4
3
2
3
2
2
6
6
5
1
1
1
1
2
1
2
2
4
4
6
4
5
5
4
108
-------
Table 9-5 (cont'd): Coal Quality Characteristics by Supply Region and Coal Grade in EPA Base Case
v4.10 PTox
Coal
Supply
Region
OK
PC
PW
TN
TX
UT
VA
WG
WH
WL
WN
WS
Coal Grade
BE
BD
BE
BG
BH
BD
BE
BG
BB
BD
BE
LD
LE
LG
BA
BB
BD
BE
BA
BB
BD
BE
BB
SD
SA
SB
SB
BD
BE
BG
BH
BA
BB
BD
BE
BG
Heat
Content
(MMBtu/Ton)
22.15
25.06
25.66
25.33
23.39
24.26
26.22
25.86
24.18
23.91
26.75
13.06
13.22
12.27
23.68
23.23
23.05
25.06
22.70
25.97
25.76
26.03
21.67
18.50
17.43
17.43
17.15
25.01
25.67
26.03
25.15
26.20
24.73
24.64
24.38
25.64
SO2
Content
(Ibs/MMBtu)
2.7
1.4
2.6
3.8
6.3
1.6
2.5
3.7
1.1
1.3
2.1
1.6
3.0
3.9
0.7
0.9
1.4
2.3
0.7
1.0
1.4
2.1
1.1
1.3
0.6
0.9
0.9
1.5
2.5
4.0
6.1
0.7
1.1
1.3
1.9
4.7
Mercury
Content
(Ibs/TBtu)
25.8
21.7
18.0
21.5
34.7
11.2
8.4
8.6
3.8
6.3
8.4
12.0
14.7
14.9
4.4
3.9
4.4
9.2
3.5
4.6
5.7
8.4
1.8
4.3
5.6
6.4
6.4
10.3
10.3
9.3
8.8
3.5
5.7
8.1
8.8
7.1
Ash
Content
(Ibs/MMBtu)
11.3
49.3
9.2
9.6
13.9
10.0
5.4
6.5
10.4
10.4
6.5
22.3
25.6
25.5
7.4
8.6
10.5
7.4
7.0
7.0
8.0
8.1
5.6
10.0
5.5
6.5
6.5
9.2
7.9
6.9
9.6
7.0
9.2
9.3
9.9
6.4
HCI Content
(Ibs/MMBtu)
0.033
0.066
0.096
0.092
0.149
0.086
0.091
0.059
0.084
0.083
0.043
0.028
0.020
0.036
0.015
0.016
0.026
0.095
0.027
0.054
0.028
0.028
0.005
0.008
0.012
0.012
0.012
0.100
0.092
0.075
0.045
0.027
0.091
0.098
0.102
0.051
Cluster
Number
2
2
5
1
5
3
4
2
3
4
4
2
1
1
2
1
5
4
5
5
4
4
4
2
2
1
1
3
4
2
3
5
6
6
4
2
109
-------
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, HCI, and SO2 data shown in Table 9-5 using the SAS statistical software package.
Clustering analysis places objects into groups or clusters, such that data in a given cluster tend
to be similar to each other and dissimilar to data in other clusters. The clustering analysis
involved two steps. (In the following write-up BG coal is used to illustrate how the procedure
worked.) First, the number of clusters of mercury, HCI, and SO2 concentrations for each IPM
coal type was determined based on the range in average mercury, HCI, and SO2
concentrations across all coal supply regions for a specific coal type. In EPA Base Case v4.10
each coal type used either one or two clusters. After adding the HCI 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 HCI as a clustering parameter, five clusters were needed for BG coal in
v4.10_PTox.) Second, for each coal grade the clustering procedure was applied to all the
regional SO2, HCI, and mercury values shown in Table 9-5 for that coal grade. (In the BG coal
example there are 11 such regional SO2, HCI, and mercury values.) Using the SAS cluster
procedure, each of the constituent regional values was assigned to a cluster and the cluster
average SO2, HCI, and mercury values were recorded. The resulting values are shown in
Tables 9-6, 9-7, and Table 9-10. (For BG coal the Cluster #1 average SO2, HCI, and mercury
values are 3.79 Ibs/MMBtu, 0.092 Ibs/MMBtu, and 21.54 Ibs/TBtu respectively. The Cluster #2
average SO2, HCI, and mercury values are 4.28 Ibs/MMBtu, 0.070 Ibs/MMBtu, and 7.60
Ibs/TBtu respectively. The Cluster #3 average SO2, HCI, and mercury values are 3.79
Ibs/MMBtu, 0.041 Ibs/MMBtu, and 11.99 Ibs/TBtu respectively. The Cluster #4 average SO2,
HCI, and mercury values are 4.84 Ibs/MMBtu, 0.133 Ibs/MMBtu, and 4.09 Ibs/TBtu
respectively. The Cluster #5 average SO2, HCI, and mercury values are 3.78 Ibs/MMBtu,
0.045 Ibs/MMBtu, and 17.59 Ibs/TBtu respectively.)
Although not used in determining the clusters, ash and CO2 values were calculated for each of
the clusters. These values are shown in Table 9-8 and Table 9-9. (The CO2 values were derived
from data in the Energy Information Administration's Annual Energy Outlook 2009 (AEO 2009),
not from data collected in the ICR.)
IPM input files retain the mapping between different coal grade/supply region combinations and
the clusters. The mapping can be seen in the last column of Table 9-5 which shows the cluster
number associated with the coal grade/supply region combination indicated in the first and
second columns of this table. (For BG coal, the SAS cluster procedure mapped supply region
PC into Cluster #1, IL, IN, KW, PW,WN and WS into Cluster #2, KE into Cluster #3, KS into
Cluster #4, and MD and OH into Cluster #5.. See Figure 9-2 for an illustration of this
mapping.) Table 9-6 to Table 9-10 show the SO2, mercury, ash, CO2, and HCI 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.
110
-------
Table 9-6 SO2 Emission Factors of Coal Used in EPA Base Case v4.10_PTox
Coal Type by Sulfur Grade
Low Sulfur Eastern Bituminous (BA)
Low Sulfur Western Bituminous (BB)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
High Sulfur Bituminous (BG)
High Sulfur Bituminous (BH)
Low Sulfur Subbituminous (SA)
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous
(SD)
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
High Sulfur Lignite (LG)
Cluster
#1
0.70
0.95
1.31
2.68
3.79
5.58
0.62
0.94
1.49
1.46
2.88
3.91
Sulfur
Cluster
#2
0.67
1.05
1.42
2.68
4.28
6.15
0.58
-
1.33
1.61
2.38
-
Emission
Factors (Ibs/MMBtu)
Cluster # Cluster
3 #4
0.72
1.14
1.51
2.46
3.79
5.91
-
-
—
-
-
-
0.74
1.13
1.46
2.19
4.84
6.43
-
-
—
-
-
-
Cluster #
5
0.68
1.04
1.41
2.82
3.78
6.29
-
-
—
-
-
-
Cluster #
6
-
1.08
1.41
2.78
-
-
-
-
—
-
-
-
Table 9-7 Mercury Emission Factors of Coal Used in EPA Base Case v4.10_PTox
Coal Type by Sulfur Grade
Low Sulfur Eastern Bituminous (BA)
Low Sulfur Western Bituminous (BB)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
High Sulfur Bituminous (BG)
High Sulfur Bituminous (BH)
Low Sulfur Subbituminous (SA)
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous
(SD)
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
High Sulfur Lignite (LG)
Cluster
#1
2.55
4.05
3.13
12.58
21.54
5.43
4.24
6.44
4.53
7.51
13.55
14.88
Mercury
Cluster
#2
4.37
5.27
21.67
25.83
7.60
7.11
5.61
-
4.33
12.00
7.81
-
Emission
Cluster
#3
3.07
3.78
10.76
6.28
11.99
8.49
-
-
-
-
-
-
Factors
(Ibs/Tbtu)
Cluster Cluster #
#4 5
3.01
1.82
5.91
8.70
4.09
13.93
-
-
-
-
-
-
3.50
4.70
4.08
18.33
17.59
34.71
-
-
-
-
-
-
Cluster #
6
~
5.84
7.54
15.62
-
-
-
-
-
-
-
-
111
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Table 9-8 Ash Emission Factors of Coal Used in EPA Base Case v4.10 PTox
Coal Type by Sulfur Grade
Low Sulfur Eastern Bituminous (BA)
Low Sulfur Western Bituminous (BB)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
High Sulfur Bituminous (BG)
High Sulfur Bituminous (BH)
Low Sulfur Subbituminous (SA)
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous
(SD)
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
High Sulfur Lignite (LG)
Cluster
#1
6.31
8.65
8.12
10.70
9.59
9.06
3.98
6.50
10.13
11.01
23.58
25.51
Ash
Cluster
#2
7.39
7.86
49.31
11.35
7.35
8.63
6.50
-
10.02
22.33
15.00
-
Emission Factors (Ibs/MMBtu)
Cluster
#3
7.26
10.35
9.61
7.34
10.21
9.91
-
-
"
-
-
-
Cluster
#4
6.09
5.59
10.33
8.95
8.47
9.13
-
-
"
-
-
-
Cluster #
5
6.99
6.69
8.97
8.16
12.30
13.89
-
-
"
-
-
-
Cluster #
6
-
7.87
9.49
11.71
-
-
-
-
"
-
-
-
Table 9-9 CO2 Emission Factors of Coal Used in EPA Base Case v4.10_PTox
Coal Type by Sulfur Grade
Low Sulfur Eastern Bituminous (BA)
Low Sulfur Western Bituminous (BB)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
High Sulfur Bituminous (BG)
High Sulfur Bituminous (BH)
Low Sulfur Subbituminous (SA)
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous
(SD)
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
High Sulfur Lignite (LG)
Cluster
#1
205.4
205.8
206.6
206.3
205.2
205.2
213.1
212.7
213.1
217.0
214.8
213.5
C02
Cluster
#2
205.4
205.8
206.6
206.3
205.2
205.2
213.1
-
213.1
217.0
214.8
-
Emission Factors (Ibs/MMBtu)
Cluster
#3
205.4
205.8
206.6
206.3
205.2
205.2
-
-
—
-
-
-
Cluster
#4
205.4
205.8
206.6
206.3
205.2
205.2
-
-
—
-
-
-
Cluster #
5
205.4
205.8
206.6
206.3
205.2
205.2
-
-
—
-
-
-
Cluster #
6
-
205.8
206.6
206.3
-
-
-
-
—
-
-
-
112
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Table 9-10 HCI Emission Factors of Coal Used in EPA Base Case v4.10 PTox
Coal Type by Sulfur Grade
Low Sulfur Eastern Bituminous (BA)
Low Sulfur Western Bituminous (BB)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
High Sulfur Bituminous (BG)
High Sulfur Bituminous (BH)
Low Sulfur Subbituminous (SA)
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous
(SD)
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
High Sulfur Lignite (LG)
Cluster
#1
0.007
0.015
0.008
0.028
0.092
0.103
0.007
0.012
0.006
0.016
0.019
0.036
HCI
Cluster
#2
0.015
0.067
0.066
0.033
0.070
0.019
0.010
-
0.008
0.028
0.014
-
Emission Factors (Ibs/MMBtu)
Cluster
#3
0.040
0.083
0.092
0.150
0.041
0.049
-
-
"
-
-
-
Cluster
#4
0.114
0.005
0.091
0.067
0.133
0.058
-
-
"
-
-
-
Cluster #
5
0.027
0.083
0.028
0.085
0.045
0.148
-
-
"
-
-
-
Cluster #
6
~
0.065
0.063
0.072
-
-
-
-
"
-
-
-
113
-------
Figure 9-2 Cluster Mapping Example - BG Coal
BG - Cluster #1
S02. 3.8 Ibs/MMBtu
Hg: 21.5 Ibs/TBtu
HCI 0.09 Ibs/MMBtu
IN-BG
4.3 Ibs/M
Hg: 7.2 Ibs/TBtu
HCI: 0.03 Ibs/MMBtu
PC-BG
3.8 Ibs/M!
Hg: 21.5 Ibs/TBtu
HCI: 0.09 Ibs/MMBtu
KE - BG
S02: 3.8 Ibs/MMBtu
Hg: 12.0 Ibs/TBtu *
HCI: 0.04 Ibs/MMBtu
IL-BG
S02: 4.6 Ibs/MMBtu
Hg: 6.5 Ibs/TBtu
HCI: 0.11 Ibs/MMBtu
BG - Cluster #3
S02: 3.8 Ibs/MMBtu
Hg: 12.0lbsfTBtu
HCI: 0.04 Ibs/MMBtu
KS-BG
4.8 Ibs/MI
Hg: 4.1 Ibs/TBtu
HCI: 0.13 Ibs/MMBtu
PW-BG --^.
S02: 3.7 Ibs/MMBtu
Hg: 8.6 Ibs/TBtu
HCI: 0.06 Ibs/MMBtu
BG - Cluster #2
S02: A.3 Ibs/MMBtu
Hg: 7.6 Ibs/TBtu
HCI: 0.07 Ibs/MMBtu
KW - BG
S02: 4.5 Ibs/MMBtu
'Hg: 6.9 Ibs/TBtu
HCI: 0.10 Ibs/MMBtu
BG - Cluster #4
S02: 4.8 Ibs/MMBtu
Hg: 4.1 Ibs/TBtu
HCI: 0.13 Ibs/MMBtu
WN - BG
4.0 Ibs/M!-
Hg: 9.3 Ibs/TBtu
HCI: 0.08 Ibs/MMBtu
WS-BG
S02: 4.7 Ibs/MMBtu
Hg: 7.1 Ibs/TBtu
HCI: 0.05 Ibs/MMBtu
MD - BG
S02: 3.6 Ibs/MMBtu
Hg: 16.6 Ibs/TBtu
HCI: 0.02 Ibs/MMBtu
OH -BG
S02: 4.0 Ibs/MMBtu
Hg: 18.5 Ibs/TBtu
HCI: 0.07 Ibs/MMBtu
BG - Cluster #5
S02: 3.8 Ibs/MMBtu
Hg: 17.6 Ibs/TBtu
HCI: 0.05 Ibs/MMBtu
114
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