United States Air and Radiation EPA 430-K-11-004
Environmental Protection Agency (6204J) June 2011
Documentation Supplement for EPA
Base Case v.4.10_FTransport -
Updates for Final Transport Rule
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Documentation Supplement for
EPA Base Case v.4.10_FTransport
Updates for Final Transport Rule
U.S. Environmental Protection Agency
Clean Air Markets Division
1200 Pennsylvania Avenue, NW (6204J)
Washington, D.C. 20460
(www.epa.gov/airmarkets)
June 2011
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Table of Contents
Introduction 1
Universal Comments Resulting in Model Revisions
1 Cogeneration Units 2
2 NOX Rates 35
3 SO2 Removal Rates for Flue Gas Desulfurization (FGD) 41
4 Coal Switching - Bituminous to Subbituminous 44
5 Restrictions on coal choice in 2012 46
6 Waste Coal Cost Correction 48
7 Comments Considered but that did not Result in Changes 51
• Oil consumption at dual fired (oil/gas) units
• Capital cost of Flue Gas Desulfurization (FGD) on units whose capacity is less than 100 MW
• Selective Catalytic Reduction (SCR) retrofit costs
• 30 year book life for emission control retrofits
• Must run, black start, and spinning reserve units
• Availability assumptions for existing coal units
Addenda: Notes on various modeling assumptions 53
• Dry Sorbent Injection (DSI) and Fabric Filter Cost Development
• Variable Operating and Maintenance (VOM) Cost of Dry Sorbent Injection (DSI) Retrofits
• Updated Appendices 3-2 through 3-4
• 2012 Emission Control Retrofits
• Emission Controls in IPM Parsed Files
• Mercury Emission Modification Factor (EMF) for Waste Coal Units
• Carbon dioxide (CO2) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization
(FGD) System for Sulfur Dioxide (SO2) Control
Addendum A — Dry Sorbent Injection (DSI) and Fabric Filter Cost Development in EPA Base Case
v.4.10_FTransport 55
Addendum B — Representation of State Electric Power Emission Regulations (Appendix 3-2), New
Source Review (NSR) Settlements (Appendix 3-3), and State Settlements (Appendix 3-4) in EPA Base
Case v.4.10_FTransport 67
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Introduction
This documentation supplement describes the changes implemented for the Final Transport Rule
analysis in EPA's application of the Integrated Planning Model (IPM), the modeling platform used by
EPA for U.S. electric power sector analysis. The changes described here resulted from comments
received on the Proposed Transport Rule and on the Notice of Data Availability (NODA) for the
Proposed Transport Rule, which were announced on September 1, 2010. The NODA included detailed
documentation of the version of the model that EPA proposed using in the final rulemaking, a database
of generating unit level input data used in the model, model run results, and user guides to input
assumptions and model outputs.
Comments received on the modeling platform fell into two basic categories: detailed comments on
specific generating units and universal comments affecting broad categories of generating units.
Changes resulting from detailed unit level comments (usually pertaining to distinct operating
characteristics of specific generating units) are being documented separately as part of the "Transport Rule
IPM Assumptions Response To Comments" document. EPA's response to the universal modeling
comments and the resulting updates to the modeling platform are presented here in the form of a
documentation supplement for the Final Transport Rule.
This documentation supplement is organized by comment topic. The presentation of each comment is
divided into two sections. The first section summarizes the comment and EPA's responses. The
second section contains a mark-up of the relevant sections of the Documentation for EPA Base Case
v.4.10 Using the Integrated Planning Model (www.epa.gov/airmarkets/progsregs/epa-
ipm/BaseCasev410.html), indicating the exact modeling changes that resulted from the universal
comments. To make it easier to recognize these mark-ups, they appear on a gray background, visually
signaling that they are revisions of the previous documentation.
In the discussion below the following terminology is used: "EPA Base Case v.4.10_NODA version"1
refers to base case released as part of the September 1, 2010 NODA. Its assumptions and results
were the subject of the public comments received by EPA. "EPA Base Case v.4.10_FTransport"
incorporated the changes described below and was used in the modeling for the Final Transport Rule.
It should also be noted that on March 16, 2011, EPA signed a Notice of Proposed Rulemaking for the
Mercury and Air Toxics Standards (MATS). For that rulemaking EPA enhanced its power sector
modeling platform with capabilities specifically needed for the Proposed MATS (for example the
capability to model HCI emissions and controls, a coal-to-gas retrofit option, and updated assumptions
for activated carbon injection for mercury control). These capabilities were also incorporated in the
modeling for the Final Transport Rule. However, only those features relevant to the Final Transport
Rule are documented here. These include provision of dry sorbent injection (DSI), accompanied by a
fabric filter, as a retrofit option for SO2 (and HCI) emission control (documented in Addendum A at the
end of this report) and updates of the State Power Sector Regulations and New Source Review (NSR)
and State Settlements shown in Appendices 3-2 through 3-4 of the documentation supplement for the
Proposed MATS (also found in Addendum B in this report). Appendices 3-2 through 3-4 reflect
regulations and settlements that were in force through December 2010. Subsequent to freezing the
assumptions for EPA Base Case v.4.10_FTransport, additional NSR settlements with Northern Indiana
Public Service Company (www.epa.gov/compliance/resources/cases/civil/caa/nipsco.html, January 13,
2011) and the Tennessee Valley Authority (www.epa.gov/compliance/resources/cases/civil/caa/tvacoal-
fired, htm I, April 14, 2011) were announced. Forthe TVA settlement EPA Base Case v.4.10_FTransport
includes the provisions shown in the Appendix 3-3. Documentation of the full modeling capabilities for
the Proposed MATS can be found in a separately issued report entitled Documentation Supplement for
EPA Base Case v.4.10_Rox- Updates for Proposed Toxics Rule, which is available for viewing and
downloading atwww.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf.
1 In Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model the term "draft EPA
Base Case v.4.10" was used when referring to what is now called "EPA Base Case v.4.10 NODA
version"
1
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1 Cogeneration Units
1.1 Response to the Comments Received
Comment Theme: Comments indicated that the extent of the operation and emissions from units that
produce both steam and electricity (i.e., cogeneration units) in EPA Base Case v.4.10_NODA was
considerably lower than actual operating experience.
Discussion: In the draft base case which provoked these comments, cogeneration units were
assigned the gross heat rates applicable to both the steam and electric portion of their operation.
However, dispatch decisions in IPM are only based on the heat rate efficiency of the electric portion of a
cogeneration unit. The lower a unit's heat rate, the more efficient is its use of fuel for electricity
generation, and the more likely it is to be dispatched. For electrical dispatch purposes, the net heat rate
should have been used for cogeneration units. Since the net heat rate can be considerably lower than
the gross heat rate, this revision should increase the extent that cogeneration units are operated. At the
same time, since emissions from both the electric and steam portions of cogeneration units are covered
by the Transport Rule, an emission multiplier should be used to ensure that total emissions are taken
into account. The increased operation together with the emissions multiplier should correct the
observation of low cogeneration operations and emissions and should address the points raised in the
comments.
Response: Based on these comments, a review was made of the representation of cogeneration units
in draft EPA Base Case v.4.10. As a result this review, modifications were made so that the
representation of cogeneration units would better reflect the extent of their operation and emissions. In
particular, the following revisions were made.
(1) In the draft base case, gross heat rates had been assigned to cogeneration units. That is, the heat
rates (efficiency) of cogeneration units were calculated by summing the energy content of the fuel
consumed for both steam and power generation and then dividing this sum by the electricity
generated. Factoring in both the fuel consumed in producing steam and electricity when calculating
the gross heat rate made the cogeneration units less efficient for electricity generation than their
operating experience indicated. In the base case for the final Transport Rule net heat rates (heat
content of fuel consumed for power generation divided by their generation) are assigned to
cogeneration units. This will more accurately reflect their electric generation efficiency and make
cogeneration units more economic to dispatch.
(2) In conjunction with the use of net heat rates for cogeneration units in the base case for the final
Transport Rule, cogeneration units are allowed to dispatch up to the availabilities assumed for the
particular generation technology or up to their historic capacity factors (derived by taking the
maximum historical capacity factor reported for the unit in EIA Form 860 for years 2006-2010).
These limits are intended to prevent dispatch patterns that exceed the reported technical
capabilities of these units. In cases where the maximum reported capacity factors is below 15%, a
capacity factor of 15% is used as a limit, since historical capacity factor values below 15% are not
considered to reflect the generation capability of the unit.
(3) Even though the dispatch of cogeneration units in the Final Transport Rule will be based on their
electric power (net) heat rate characteristics, the emissions from both power and steam production
will be taken into account, since for cogeneration units the Transport Rule covers the emissions
attributable to both electric and steam generation. To capture these total emissions a multiplier
(derived by dividing the total fuel consumed for both steam and power by the fuel consumed for
power) is applied to the power only emissions.
1.2 Resulting Updates
The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning
Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base
Case v4.10_FTransport.
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3.5.2 Capacity Factor
Add the following paragraph at the end of this section:
To prevent dispatch patterns that exceed their reported technical capabilities, cogeneration units are
allowed to dispatch up to the availabilities assumed for the particular generation technology or up to
their historic capacity factors (derived by taking the maximum historical capacity factor reported for
the unit in EIA Form 860 for years 2006-2010). In cases where the maximum reported capacity
factors is below 15%, a capacity factor of 15% is used as a limit, since historical capacity factor
values below 15% are not considered to reflect the generation capability of the unit. Appendix 3-10
shows the capacity factor upper bounds for all the existing cogeneration units that are represented
in EPA Base Case v.4.10.
3.8 Heat Rate
Add the following paragraph at the end of this section:
For cogeneration units only, the heating value of the fuel combusted for electricity generation is
used to derive the heat rate, since dispatch decisions in IPM are only based on the heat rate
efficiency of the electric portion of a cogeneration unit. Known as a cogeneration unit's net heat
rate, it is calculated by dividing heat content of fuel consumed for power generation by electric
generated from this fuel. To capture the total emissions from the cogeneration unit, a multiplier
(derived by dividing the total fuel consumed for both steam and power by the fuel consumed for
power) is applied to the power only emissions. Appendix 3-10 shows the heat rate and emission
multipliers of all the existing cogeneration units that are represented in EPA Base Case v.4.10. For
purposes of comparison Appendix 3-10 includes the net heat rate values currently used in modeling
and the gross heat rate used prior to correcting the representation as a result of comments received
in the September 2010 Notice of Data Availability (NODA). The net heat rates appear in the column
labeled '"Post-NODA Heat Rate (Btu/kWh)." The gross heat rates appear in the column labeled
"NODA Heat Rate (Btu/kWh)." Since the net heat rate cannot exceed the gross heat rate, instances
where the value of the "'Post-NODA Heat Rate (Btu/kWh)" exceeds the value of the "NODA Heat
Rate (Btu/kWh)" were caused by a change in the source of the data between the NODA and post-
NODA period. Such instances are highlighted and explained in Appendix 3-10.
Add the following appendix at the end of Chapter 3:
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Appendix 3-10. Cogeneration Units - Heat Rates (Before and After NODA Comments), Capacity Factor Upper Bounds, and Emission Multipliers
= Higher Post-NODA Heat Rate Due to Higher Reported Value in AEO 2010 than in AEO 2008
= Higher Post-NODA Heat Rate Based on NODA Comment
= Higher Post-NODA Heat Rate Based on Net Heat Rate Reported in EIA Form 923
2012
Capacity
NODA Post-NODA Factor Upper
Region Capacity Heat Rate Heat Rate Emissions Bound
Plant Name UniquelD_Final PlantType Name (MW) (Btu/kWh) (Btu/kWh) Multiplier Implemented
ACE Cogeneration Facility 10002_B_
Trigen Colorado Energy 10003_B_
Trigen Colorado Energy 10003_B_
Trigen Colorado Energy 10003_B_
Trigen Colorado Energy 10003_B_
Trigen Colorado Energy 10003_B_
Baptist Medical Center 10008_G_
Baptist Medical Center 10008_G_
Baptist Medical Center 10008_G_
Baptist Medical Center 10008_G_
Baptist Medical Center 10008_G_
NRG Energy Center Dover 10030_B_
Greater Detroit Resource Recovery 10033_B_
Greater Detroit Resource Recovery 10033_B_
Greater Detroit Resource Recovery 10033_B_
Gilroy Power Plant 10034_G_
Gilroy Power Plant 10034_G_
Logan Generating Plant 10043_B_
Central Utilities Plant LAX 10048_G_
Central Utilities Plant LAX 10048_G_
Cogentrix Virginia Leasing Corporation 10071_B_
Cogentrix Virginia Leasing Corporation 10071_B_
Cogentrix Virginia Leasing Corporation 10071_B_
CFB Coal Steam CA-S 101
BLR1 0/G Steam RMPA 8.1
BLR2 0/G Steam RMPA 8.1
BLR3 Coal Steam RMPA 8.1
BLR4 Coal Steam RMPA 8.1
BLR5 Coal Steam RMPA 8.1
CG-3 1C Engine FRCC 0.50
TG-1 Combustion Turbine FRCC 2.3
TG-2 Combustion Turbine FRCC 2.2
TG-3 Combustion Turbine FRCC 2.7
TG-4 Combustion Turbine FRCC 3.2
COGEN1 Coal Steam MACE 16.0
11 Municipal Solid Waste MECS 21.2
12 Municipal Solid Waste MECS 21.2
13 Municipal Solid Waste MECS 21.2
GEN1 Combined Cycle CA-N 90.0
GEN2 Combined Cycle CA-N 40.0
B01 Coal Steam MACE 219
GEN1 Combustion Turbine CA-S 4.0
GEN2 Combustion Turbine CA-S 4.0
1A Coal Steam VAPW 19.2
IB Coal Steam VAPW 19.2
1C Coal Steam VAPW 19.2
10921
11972
11964
10331
10331
11768
13298
15981
15981
15981
12503
11782
19338
19338
19338
8330
8330
9890
15981
15981
11354
10331
10331
10526
8300
8300
8300
8300
8300
13199
15845
8700
8700
8700
11782
8300
8300
^^^^ 8300
8373
8373
9890
8700
8700
10888
10320
10320
1.04
1.44
1.44
1.24
1.24
1.42
1.00
1.00
1.82
1.82
1.43
1.00
1.96
1.96
1.96
1.00
1.00
1.00
1.82
1.82
1.04
1.00
1.00
89.70
89.51
89.51
86.40
86.40
86.40
89.24
89.24
89.24
89.24
89.24
75.40
52.47
52.47
52.47
84.63
84.63
83.80
89.24
89.24
74.60
74.60
74.60
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Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Cogentrix Virginia Leasing Corporation
Pedricktown Cogen Plant
Pedricktown Cogen Plant
Frito-Lay Cogen Plant
John B Rich Memorial Power Station
John B Rich Memorial Power Station
Harrisburg Facility
Harrisburg Facility
Harrisburg Facility
Indiana University of Pennsylvania
Indiana University of Pennsylvania
Indiana University of Pennsylvania
Indiana University of Pennsylvania
Sierra Pacific Lincoln Facility
Fresno Cogen Partners
Fresno Cogen Partners
Fresno Cogen Partners
Cardinal Cogen
Cardinal Cogen
Carson Cogeneration
Carson Cogeneration
Metro Wastewater Reclamation District
Metro Wastewater Reclamation District
Metro Wastewater Reclamation District
Metro Wastewater Reclamation District
Metro Wastewater Reclamation District
Metro Wastewater Reclamation District
Central Utility Plant
Central Utility Plant
Central Utility Plant
IMC Phosphates Company Uncle Sam
IMC Phosphates Company Uncle Sam
Hercules Missouri Chemical Works
Hercules Missouri Chemical Works
Hercules Missouri Chemical Works
Snowbird Power Plant
Snowbird Power Plant
Snowbird Power Plant
Alabama River Pulp
10071_B_2A Coal Steam
10071_B_2B Coal Steam
10071_B_2C Coal Steam
10099_G_GEN1 Combined Cycle
10099_G_GEN2 Combined Cycle
10110_G_GEN1 Combustion Turbine
10113_B_CFB1 Coal Steam
10113_B_CFB2 Coal Steam
10118_B_1 Municipal Solid Waste
10118_B_2 Municipal Solid Waste
10118_B_3 Municipal Solid Waste
10129_G_GEN1 1C Engine
10129_G_GEN2 1C Engine
10129_G_GEN3 1C Engine
10129_G_GEN4 1C Engine
10144_G_GEN4 Biomass
10156_G_GEN2 Combined Cycle
10156_G_GEN3 Combined Cycle
10156_G_GEN4 Combined Cycle
10168_G_GTG1 Combined Cycle
10168_G_STG1 Combined Cycle
10169_G_GEN1 Combined Cycle
10169_G_GEN2 Combined Cycle
10180_G_1 Non-Fossil Waste
10180_G_2 Non-Fossil Waste
10180_G_3 Non-Fossil Waste
10180_G_4 Non-Fossil Waste
10180_G_5 Non-Fossil Waste
10180_G_6 Non-Fossil Waste
10184_G_EG1 1C Engine
10184_G_EG2 1C Engine
10184_G_TG1 0/G Steam
10198_G_GEN1 Non-Fossil Waste
10198_G_GEN2 Non-Fossil Waste
10207_B_1 Coal Steam
10207_B_2 Coal Steam
10207_B_3 Coal Steam
10215_G_1367 1C Engine
10215_G_1391 1C Engine
10215_G_1392 1C Engine
10216 B PB1 Biomass
VAPW 19.2
VAPW 19.2
VAPW 19.2
MACE 79.2
MACE 36.5
CA-N 5.1
MACW 40.0
MACW 40.0
MACW 6.9
MACW 6.9
MACW 6.9
MACW 6.0
MACW 6.0
MACW 6.0
MACW 6.0
CA-N 17.2
CA-N 6.0
CA-N 21.9
CA-N 45.0
CA-N 32.5
CA-N 9.4
CA-S 41.3
CA-S 8.0
RMPA 1.2
RMPA 1.2
RMPA 1.2
RMPA 1.2
RMPA 2.5
RMPA 2.5
ERCT 4.3
ERCT 3.2
ERCT 0.23
ENTG 10.2
ENTG 10.2
GWAY 5.7
GWAY 5.7
GWAY 5.7
NWPE 0.59
NWPE 0.59
NWPE 0.59
SOU 22.3
11353
10331
10331
8350
8350
15981
11190
10331
19338
19338
19338
13298
13298
13298
13298
15517
7651
7651
7651
9939
9939
8994
8994
14283
14283
14283
14283
10000
10000
13298
13298
11425
13102
13102
12508
12508
12508
13298
13298
13298
15517
10888
10320
10320
7916
7916
15845
8300
8300
8300
8300
8300
9480
9480
9480
9480
8300
8594
8594
8594
9738
9738
8557
8557
8700
8700
8700
8700
8700
8700
13199
13199
10036
9854
9854
8300
8300
8300
8700
8700
8700
8300
1.04
1.00
1.00
1.00
1.00
1.00
1.35
1.24
2.33
2.33
2.33
1.39
1.39
1.39
1.39
1.89
1.09
1.09
1.09
1.00
1.00
1.01
1.01
1.64
1.64
1.64
1.64
1.15
1.15
1.00
1.00
1.11
1.30
1.30
1.49
1.49
1.49
1.52
1.52
1.52
1.89
74.60
74.60
74.60
84.63
84.63
89.24
95.00
95.00
88.41
88.41
88.41
89.24
89.24
89.24
89.24
83.00
15.00
15.00
15.00
84.63
84.63
84.63
84.63
77.35
77.35
77.35
77.35
77.35
77.35
89.24
89.24
89.51
75.66
75.66
85.26
85.26
85.26
89.24
89.24
89.24
83.00
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Alabama River Pulp
Leaf River Cellulose LLC
Leaf River Cellulose LLC
King City Power Plant
King City Power Plant
Bayou Cogen Plant
Bayou Cogen Plant
Bayou Cogen Plant
Bayou Cogen Plant
Bellingham Cogeneration Facility
Bellingham Cogeneration Facility
Bellingham Cogeneration Facility
Sayreville Cogeneration Facility
Sayreville Cogeneration Facility
Sayreville Cogeneration Facility
Central Power & Lime
Foster Wheeler Martinez
Foster Wheeler Martinez
Foster Wheeler Martinez
Foster Wheeler Mt Carmel Cogen
Charleston Resource Recovery Facility
Charleston Resource Recovery Facility
Greenleaf 2 Power Plant
Greenleaf 1 Power Plant
Greenleaf 1 Power Plant
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
10216_B_RB1
10233_B_PB
10233_B_RB
10294_G_GTG
10294_G_STG
10298_G_GEN1
10298_G_GEN2
10298_G_GEN3
10298_G_GEN4
10307_G_CT1
10307_G_CT2
10307_G_ST1
10308_G_CT1
10308_G_CT2
10308_G_ST1
10333_B_1
10342_G_TG1
10342_G_TG2
10342_G_TG3
10343_B_SG-101
10344_B_B1
10344_B_B2
10349_G_GEN1
10350_G_GEN1
10350_G_GEN2
10377_B_1A
10377_B_1B
10377_B_1C
10377_B_2A
10377_B_2B
10377_B_2C
10378_B_1A
10378_B_1B
10378_B_1C
10378_B_2A
10378_B_2B
10378_B_2C
10379_B_1A
10379_B_1B
10379_B_1C
10380_B_A BLR
Non-Fossil Waste
Biomass
Non-Fossil Waste
Combined Cycle
Combined Cycle
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Municipal Solid Waste
Municipal Solid Waste
Combustion Turbine
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
SOU 22.3
SOU 37.5
SOU 12.5
CA-N 73.0
CA-N 38.0
ERCT 65.0
ERCT 65.0
ERCT 65.0
ERCT 65.0
NENG 102
NENG 102
NENG 60.0
MACE 98.0
MACE 98.0
MACE 75.0
FRCC 139
CA-N 35.0
CA-N 35.0
CA-N 33.5
MACW 43.0
VACA 4.8
VACA 4.8
CA-N 49.5
CA-N 42.0
CA-N 8.0
VAPW 18.2
VAPW 18.2
VAPW 18.2
VAPW 18.2
VAPW 18.2
VAPW 18.2
VACA 17.8
VACA 17.8
VACA 17.8
VACA 17.8
VACA 17.8
VACA 17.8
VACA 18.7
VACA 18.7
VACA 18.7
16.0
13102
15517
13102
7990
7990
15981
15981
15981
15981
8300
8300
8300
8650
8650
8650
10896
8600
8600
8600
12500
19338
19338
10578
8290
8290
10331
11360
10331
11359
10331
10331
11362
10331
10331
11361
10331
10331
11362
10331
10331
NotindB
8300
8300
8300
7990
7990
8700
8700
8700
8700
7953
7953
7953
8200
8200
8200
10327
8266
8266
8266
11845
9587
9587
8700
6181
6181
9194
9194
9194
9194
9194
9194
11362
10320
10320
11361
10320
10320
11362
10320
10320
11113
1.54
1.89
1.54
1.00
1.00
1.82
1.82
1.82
1.82
1.04
1.04
1.04
1.00
1.00
1.00
1.06
1.13
1.13
1.13
1.06
1.70
1.70
1.22
1.49
1.49
1.12
1.24
1.12
1.24
1.12
1.12
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.05
55.17
83.00
55.17
84.63
84.63
90.81
90.81
90.81
90.81
22.19
22.19
22.19
84.63
84.63
84.63
60.53
84.63
84.63
84.63
90.10
89.39
89.39
90.81
66.10
66.10
83.40
83.40
83.40
83.40
83.40
83.40
41.34
41.34
41.34
41.34
41.34
41.34
83.00
83.00
83.00
41.34
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Elizabethtown Power LLC
Green Power Kenansville
Green Power Kenansville
Lumberton
Lumberton
Edgecombe GenCo
Edgecombe GenCo
Edgecombe GenCo
Edgecombe GenCo
Little Company of Mary Hospital
Laidlaw Energy & Environmental
Laidlaw Energy & Environmental
Laidlaw Energy & Environmental
Laidlaw Energy & Environmental
KingsburgCogen
KingsburgCogen
Inland Ontario Mill
Wisconsin Rapids Pulp Mill
Wisconsin Rapids Pulp Mill
Wisconsin Rapids Pulp Mill
Wisconsin Rapids Pulp Mill
Wisconsin Rapids Pulp Mill
Wisconsin Rapids Pulp Mill
Pitchess Cogen Station
Pitchess Cogen Station
Rumford Cogeneration
Rumford Cogeneration
Kern River Cogeneration
Kern River Cogeneration
Kern River Cogeneration
Kern River Cogeneration
Mid-Set Cogeneration
San Jose Cogeneration
Chambers Cogeneration LP
Chambers Cogeneration LP
Algonquin Windsor Locks
Algonquin Windsor Locks
Sixth Street
Sixth Street
Sixth Street
Sixth Street
10380_B_B BLR
10381_B_1A
10381_B_1B
10382_B_UNIT1
10382_B_UNIT2
10384_B_1A
10384_B_1B
10384_B_2A
10384_B_2B
10400_G_GEN1
10403_G_ALLI
10403_G_CAT3
10403_G_CAT4
10403_G_WEST
10405_G_GEN1
10405_G_GEN2
10427_G_GEN1
10477_B_P1
10477_B_P2
10477_B_P3
10477_B_R1
10477_B_R2
10477_B_R3
10478_G_GEN1
10478_G_GEN2
10495_B_6
10495_B_7
10496_G_GTAG
10496_G_GTBG
10496_G_GTCG
10496_G_GTDG
10501_G_K100
10548_G_GEN1
10566_B_BOIL1
10566_B_BOIL2
10567_G_GTG
10567_G_STG
1058_B_2
1058_B_3
1058_B_4
1058 B 5
Coal Steam
Biomass
Biomass
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Combustion Turbine
Combined Cycle
1C Engine
1C Engine
Combined Cycle
Combined Cycle
Combined Cycle
Combustion Turbine
Coal Steam
Coal Steam
0/G Steam
Non-Fossil Waste
Non-Fossil Waste
Non-Fossil Waste
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Coal Steam
Coal Steam
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Coal Steam
Coal Steam
16.0
VACA 16.2
VACA 16.2
16.0
16.0
VAPW 28.9
VAPW 28.9
VAPW 28.9
VAPW 28.9
COMD 3.2
UPNY 2.6
UPNY 0.40
UPNY 0.40
UPNY 0.70
CA-N 22.0
CA-N 11.8
CA-S 34.0
WUMS 11.2
WUMS 11.2
WUMS 11.2
WUMS 11.2
WUMS 11.2
WUMS 11.2
CA-S 21.5
CA-S 5.7
NENG 42.5
NENG 42.5
CA-N 72.0
CA-N 72.0
CA-N 72.0
CA-N 72.0
CA-N 36.0
CA-N 5.6
MACE 131
MACE 131
NENG 26.0
NENG 12.0
13.6
13.6
13.6
13.6
NotindB
11564
15517
NotindB
NotindB
11325
10331
11325
10331
15981
11860
11100
11100
11860
9832
9832
15981
10331
10331
11332
13102
13102
13102
10211
10211
11058
10331
16509
16509
16509
16509
15506
15981
10000
10331
10186
10186
Not in dB
Not in dB
Not in dB
Not in dB
11113
11498
11498
11247
11247
11062
10320
11062
10320
8700
11860
11100
11100
11860
8492
8492
15845
8300
8300
8300
8300
8300
8300
6716
6716
8300
8300
8700
8700
8700
8700
8700
11640
10000
10079
7106
7106
12551
14500
14500
14500
1.05
1.37
1.37
1.04
1.04
1.02
1.00
1.02
1.00
1.82
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.24
1.24
1.39
1.54
1.54
1.54
1.68
1.68
1.33
1.24
1.90
1.90
1.90
1.90
1.78
1.36
1.00
1.02
1.30
1.30
1.00
1.00
1.00
1.00
41.34
83.00
83.00
15.00
15.00
90.00
90.00
90.00
90.00
89.24
84.63
89.24
89.24
84.63
84.63
84.63
89.87
85.26
85.26
92.41
75.66
75.66
75.66
84.63
84.63
94.10
94.10
90.81
90.81
90.81
90.81
89.87
89.24
74.80
74.80
84.63
84.63
35.53
35.53
35.53
35.53
-------
BP Wilmington Calciner
Ebensburg Power
Domtar - Woodland Mill
Domtar - Woodland Mill
CH Resources Beaver Falls
CH Resources Beaver Falls
Civic Center
Civic Center
Wheelabrator Baltimore Refuse
Wheelabrator Baltimore Refuse
Wheelabrator Baltimore Refuse
Hopewell Cogeneration
Hopewell Cogeneration
Hopewell Cogeneration
Hopewell Cogeneration
Corona Cogen
Cambria Cogen
Cambria Cogen
Bear Mountain Cogen
Badger Creek Cogen
Burney Forest Products
Burney Forest Products
Sierra Pacific Sonora
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
AES Beaver Valley Partners Beaver Valley
AES Beaver Valley Partners Beaver Valley
AES Beaver Valley Partners Beaver Valley
AES Beaver Valley Partners Beaver Valley
AES Placerita
AES Placerita
AES Placerita
AES Warrior Run Cogeneration Facility
10601_G_GEN1 Coal Steam
10603_B_031 Coal Steam
10613_B_3RB 0/G Steam
10613_B_9PB Biomass
10617_G_GEN1 Combined Cycle
10617_G_GEN2 Combined Cycle
10623_G_GEN1 Combined Cycle
10623_G_GEN2 Combined Cycle
10629_B_BLR1 Municipal Solid Waste
10629_B_BLR2 Municipal Solid Waste
10629_B_BLR3 Municipal Solid Waste
10633_G_GT1 Combined Cycle
10633_G_GT2 Combined Cycle
10633_G_GT3 Combined Cycle
10633_G_ST1 Combined Cycle
10635_G_GEN1 Combustion Turbine
10641_B_B1 Coal Steam
10641_B_B2 Coal Steam
10649_G_GEN1 Combustion Turbine
10650_G_GEN1 Combustion Turbine
10652_B_BLR1 Biomass
10652_B_BLR2 Biomass
54517_G_GEN2 Biomass
10670_B_AAB001 Coal Steam
10671_B_1A Coal Steam
10671_B_1B Coal Steam
10671_B_2A Coal Steam
10671_B_2B Coal Steam
10672_B_CBA Coal Steam
10672_B_CBB Coal Steam
10672_B_CBC Coal Steam
10675_B_A Coal Steam
10675_B_B Coal Steam
10676_B_2 Coal Steam
10676_B_3 Coal Steam
10676_B_4 Coal Steam
10676_B_5 Coal Steam
10677_G_UNT1 Combined Cycle
10677_G_UNT2 Combined Cycle
10677_G_UNT3 Combined Cycle
10678 B BLR1 Coal Steam
CA-S 29.0
MACW 49.5
NENG 23.0
NENG 23.0
UPNY 52.5
UPNY 34.0
CA-S 18.5
CA-S 1.2
MACS 20.4
MACS 20.4
MACS 20.4
84.1
84.1
84.1
96.0
CA-S 40.0
MACW 44.0
MACW 44.0
CA-N 46.0
CA-N 46.0
CA-N 15.5
CA-N 15.5
CA-N 5.5
ERCT 140
SPPS 80.0
SPPS 80.0
SPPS 80.0
SPPS 80.0
FRCC 83.3
FRCC 83.3
FRCC 83.3
NENG 90.5
NENG 90.5
RFCP 43.0
RFCP 43.0
RFCP 43.0
RFCP 17.0
CA-S 46.0
CA-S 46.0
CA-S 23.0
RFCP 180
10331
12500
11844
15517
8700
8700
9939
9939
19338
19338
19338
NotindB
NotindB
NotindB
NotindB
15727
11076
10331
13225
13225
15517
15517
15517
14500
10471
10331
10469
10331
9504
10331
10331
10173
10331
11621
12508
12508
12508
9900
9900
9900
11177
9854
12500
8300
8300
8700
8700
8577
8577
16297
16297
16297
8292
8292
8292
8292
8700
12200
12200
8700
8700
15716
15716
8300
11801
10471
10320
10469
10320
9375
9375
9375
9491
9491
10910
10910
10910
10910
9894
9894
9894
10577
1.05
1.00
1.39
1.89
1.00
1.00
1.14
1.14
1.00
1.00
1.00
1.09
1.09
1.09
1.09
1.81
1.00
1.00
1.52
1.52
1.00
1.00
1.89
1.23
1.00
1.00
1.00
1.00
1.01
1.10
1.10
1.07
1.09
1.07
1.14
1.14
1.14
1.00
1.00
1.00
1.06
85.26
95.00
86.60
83.00
84.63
84.63
84.63
84.63
90.00
90.00
90.00
27.40
27.40
27.40
27.40
89.87
95.00
95.00
89.87
89.87
83.00
83.00
83.00
85.26
80.90
80.90
80.90
80.90
82.80
82.80
82.80
94.10
94.10
72.07
72.07
72.07
72.07
84.63
84.63
84.63
92.30
8
-------
Colorado Power Partners
Colorado Power Partners
Colorado Power Partners
BCP
BCP
Argus Cogen Plant
Argus Cogen Plant
Westend Facility
Rapids Energy Center
Rapids Energy Center
Rapids Energy Center
Rapids Energy Center
Jackson County Resource Recovery
Selkirk Cogen
Selkirk Cogen
Selkirk Cogen
Selkirk Cogen
Selkirk Cogen
Masspower
Masspower
Prairie Creek
Prairie Creek
Prairie Creek
Prairie Creek
Clear Lake Cogeneration Ltd
Clear Lake Cogeneration Ltd
Clear Lake Cogeneration Ltd
Clear Lake Cogeneration Ltd
Clear Lake Cogeneration Ltd
Morgantown Energy Facility
Morgantown Energy Facility
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
10682_G_GT1
10682_G_GT2
10682_G_ST1
10683_G_GT3
10683_G_ST2
10684_B_BLR25
10684_B_BLR26
10685_G_PINA
10686_B_5
10686_B_6
10686_B_7
10686_B_8
10722_G_1
10725_G_GEN1
10725_G_GEN2
10725_G_GEN3
10725_G_GEN4
10725_G_GEN5
10726_G_GEN1
10726_G_GEN2
1073_B_1
1073_B_2
1073_B_3
1073_B_4
10741_G_G102
10741_G_G103
10741_G_G104
10741_G_S101
10741_G_S102
10743_B_CFB1
10743_B_CFB2
10745_G_1G12
10745_G_BP15
10745_G_GT10
10745_G_GT11
10745_G_GT12
10745_G_GT13
10745_G_GT14
10745_G_GT3
10745_G_GT4
10745 G GTS
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Combustion Turbine
Biomass
Biomass
0/G Steam
0/G Steam
Municipal Solid Waste
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
1C Engine
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
RMPA 25.0
RMPA 25.0
RMPA 30.0
RMPA 32.0
RMPA 40.0
CA-S 25.0
CA-S 25.0
CA-S 15.0
MRO 11.2
MRO 11.2
MRO 3.5
MRO 3.5
MECS 3.0
DSNY 72.6
DSNY 9.2
DSNY 79.7
DSNY 79.7
DSNY 124
NENG 82.2
NENG 82.2
MRO 9.1
MRO 10.2
MRO 41.6
MRO 125
ERCT 100
ERCT 100
ERCT 100
ERCT 52.0
ERCT 14.0
RFCP 25.0
RFCP 25.0
MECS 5.2
MECS 13.4
MECS 84.0
MECS 84.0
MECS 84.0
MECS 84.0
MECS 84.0
MECS 84.0
MECS 88.0
MECS 88.0
11860
11860
11860
11860
11860
10331
10331
15981
15517
20328
14500
11332
19338
8861
8861
8861
8861
8861
8224
8224
11595
12230
11090
10198
10540
10540
10540
10540
10540
11298
10331
11585
8974
8974
8974
8974
8974
8974
8974
8974
8974
8841
8841
8841
9885
9885
8300
8300
8700
13179
13179
11511
11511
8300
8109
8109
8109
8109
8109
8507
8507
11595
12230
11090
10198
5500
5500
5500
5500
5500
8693
8693
11585
7289
7289
7289
7289
7289
7289
7289
7289
7289
1.34
1.34
1.34
1.00
1.00
1.24
1.24
1.82
1.19
1.54
1.00
1.00
2.33
1.16
1.16
1.16
1.16
1.16
1.01
1.01
1.00
1.00
1.00
1.00
1.82
1.82
1.82
1.82
1.82
1.52
1.52
1.00
1.22
1.22
1.22
1.22
1.22
1.22
1.22
1.22
1.22
25.35
25.35
25.35
84.63
84.63
85.26
85.26
89.24
83.00
83.00
92.41
92.41
52.47
63.58
63.58
63.58
63.58
63.58
26.13
26.13
52.20
52.20
52.20
52.20
25.04
25.04
25.04
25.04
25.04
85.26
85.26
89.24
37.26
37.26
37.26
37.26
37.26
37.26
37.26
37.26
37.26
-------
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Midland Cogeneration Venture
Rifle Generating Station
Rifle Generating Station
Rifle Generating Station
Rifle Generating Station
Las Vegas Cogen LP
Las Vegas Cogen LP
Rio Bravo Jasmin
Rio Bravo Poso
Southampton Power Station
Southampton Power Station
E F Oxnard Energy Facility
Seaford Delaware Plant
Seaford Delaware Plant
Seaford Delaware Plant
Lowell Cogen Plant
Lowell Cogen Plant
Ogdensburg Power
Ogdensburg Power
Ogdensburg Power
Ogdensburg Power
Kenilworth Energy Facility
Kenilworth Energy Facility
Riverside
Riverside
Riverside
NTC/MCRD Energy Facility
NTC/MCRD Energy Facility
Naval Station Energy Facility
Naval Station Energy Facility
Naval Station Energy Facility
North Island Energy Facility
North Island Energy Facility
Ada Cogeneration LP
Ada Cogeneration LP
Walter Scott Jr. Energy Center
10745_G_GT6
10745_G_GT7
10745_G_GT8
10745_G_GT9
10745_G_ST1
10745_G_ST2
10755_G_GT2
10755_G_GT3
10755_G_GT4
10755_G_ST1
10761_G_GEN1
10761_G_GEN2
10768_B_CFB
10769_B_CFB
10774_B_1
10774_B_2
10776_G_GTG
10793_B_BLR1
10793_B_BLR3
10793_B_BLR5
10802_G_GEN1
10802_G_GEN2
10803_B_1
10803_G_GEN1
10803_G_GEN2
10803_G_GEN3
10805_G_GEN1
10805_G_GEN2
1081_B_7
1081_B_8
1081_B_9
10810_G_GEN1
10810_G_GEN2
10811_G_GEN1
10811_G_GEN2
10811_G_GEN3
10812_G_GEN1
10812_G_GEN2
10819_G_GEN1
10819_G_GEN2
1082 B 3
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Combustion Turbine
0/G Steam
0/G Steam
0/G Steam
Combined Cycle
Combined Cycle
Biomass
Biomass
Biomass
Biomass
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Coal Steam
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
MECS 88.0
MECS 88.0
MECS 84.0
MECS 84.0
MECS 410
MECS 380
RMPA 13.0
RMPA 13.0
RMPA 21.2
RMPA 21.2
SNV 41.0
SNV 9.0
CA-S 33.0
CA-N 33.0
36.5
36.5
CA-S 48.5
MACE 9.0
MACE 9.0
MACE 9.0
NENG 18.7
NENG 6.3
26.0
UPNY 8.3
UPNY 8.3
UPNY 8.3
MACE 22.5
MACE 4.5
MRO 2.5
MRO 2.5
MRO 130
CA-S 21.6
CA-S 2.2
CA-S 36.7
CA-S 9.8
CA-S 4.8
CA-S 33.5
CA-S 3.5
MECS 23.0
MECS 6.4
MRO 690
8974
8974
8974
8974
8974
8974
11860
11860
11860
11860
8289
8289
11568
11568
NotindB
NotindB
15349
14517
14517
12534
9800
9800
Not in dB
8911
8911
8911
10700
10700
12508
12508
10720
10013
10013
11520
11520
11520
9194
9194
8950
8950
10927
7289
7289
7289
7289
7289
7289
10422
10422
10422
10422
7701
7701
11445
11568
11277
11277
8700
8300
8300
8300
9800
9800
8573
Retired
Retired
8573
9867
9867
12406
12406
10720
7705
7705
8143
8143
8143
6803
6803
5866
5866
10927
1.22
1.22
1.22
1.22
1.22
1.22
1.00
1.00
1.00
1.00
1.00
1.00
1.01
1.00
1.00
1.00
1.76
1.72
1.72
1.35
1.00
1.00
1.04
1.04
1.08
1.08
1.00
1.00
1.00
1.23
1.23
1.20
1.20
1.20
1.26
1.26
1.55
1.55
1.00
37.26
37.26
37.26
37.26
37.26
37.26
84.63
84.63
84.63
84.63
84.63
84.63
92.00
95.00
59.87
90.00
89.87
86.60
86.60
92.41
84.63
84.63
15.00
0.00
0.00
83.00
76.45
76.45
64.00
64.00
64.00
84.63
84.63
82.26
82.26
82.26
84.17
84.17
84.63
84.63
73.40
10
-------
Coca Cola Bottling of New York
Coca Cola Bottling of New York
Coca Cola Bottling of New York
Silver Bay Power
Silver Bay Power
Mojave Cogen
Mojave Cogen
Biomass One LP
Biomass One LP
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Medical Area Total Energy Plant
Ames Electric Services Power Plant
Ames Electric Services Power Plant
Muscatine Plant #1
Louisiana 1
Louisiana 1
Louisiana 1
Louisiana 1
Louisiana 1
RS Nelson
RS Nelson
RS Nelson
RS Nelson
Kendall Square Station
Kendall Square Station
Kendall Square Station
Kendall Square Station
Apache Station
10829_G_ENG1 1C Engine DSNY 0.60
10829_G_ENG2 1C Engine DSNY 0.60
10829_G_ENG3 1C Engine DSNY 0.60
10849_B_BLR1 Coal Steam 36.0
10849_B_BLR2 Coal Steam 69.0
10850_G_GEN1 Combined Cycle CA-S 40.0
10850_G_GEN2 Combined Cycle CA-S 15.3
10869_B_NORTH Biomass PNW 8.5
10869_B_SOUTH Biomass PNW 14.0
10883_B_GTHSG1 0/G Steam NENG 3.1
10883_B_GTHSG2 0/G Steam NENG 3.1
10883_B_HSG1 0/G Steam NENG 3.1
10883_B_HSG2 0/G Steam NENG 3.1
10883_B_PSG1 0/G Steam NENG 3.1
10883_B_PSG2 0/G Steam NENG 3.1
10883_B_PSG3 0/G Steam NENG 3.1
10883_G_CT1 Combustion Turbine NENG 12.5
10883_G_CT2 Combustion Turbine NENG 12.5
10883_G_DEG1 1C Engine NENG 6.0
10883_G_DEG2 1C Engine NENG 6.0
10883_G_DEG3 1C Engine NENG 6.0
10883_G_DEG4 1C Engine NENG 6.0
10883_G_DEG5 1C Engine NENG 6.0
10883_G_DEG6 1C Engine NENG 6.0
1122_B_7 Coal Steam MRO 33.0
1122_B_8 Coal Steam MRO 70.0
1167_B_8 Coal Steam MRO 35.0
1391_G_1A Combined Cycle ENTG 18.0
1391_G_2A Combined Cycle ENTG 55.0
1391_G_3A Combined Cycle ENTG 55.0
1391_G_4A Combined Cycle ENTG 100
1391_G_5A Combined Cycle ENTG 154
1393_B_1A Coal Steam ENTG 107
1393_B_2A Coal Steam ENTG 106
1393_B_3 0/G Steam ENTG 153
1393_B_4 0/G Steam ENTG 500
1595_G_1 Combined Cycle NENG 15.0
1595_G_2 Combined Cycle NENG 20.0
1595_G_3 Combined Cycle NENG 21.7
1595_G_GEN4 Combined Cycle NENG 180
160_G_GT1 Combined Cycle AZNM 10.0
12942
12942
13080
NotindB
NotindB
11600
11600
15517
15517
11332
11332
11332
11332
11332
11332
11332
12503
12503
13988
13988
13988
13988
13988
13988
12926
12926
15279
10472
10472
10472
10472
10472
11041
11041
10476
10419
8658
8658
8658
8658
11855
Retired
Retired
Retired
9693
9693
7870
7870
12056
12056
8300
8300
8300
8300
8300
8300
8300
8700
8700
8700
8700
8700
8700
8700
8700
12926
12926
15279
5500
5500
5500
5500
5500
11041
11041
10476
10419
8945
8945
8945
8945
11071
1.06
1.06
1.25
1.25
1.30
1.30
1.39
1.39
1.39
1.39
1.39
1.39
1.39
1.43
1.43
1.60
1.60
1.60
1.60
1.60
1.60
1.00
1.00
1.00
1.90
1.90
1.90
1.90
1.90
1.00
1.00
1.00
1.00
1.16
1.16
1.16
1.16
1.00
0.00
0.00
0.00
85.26
85.26
82.77
82.77
83.00
83.00
92.41
92.41
92.41
92.41
92.41
92.41
92.41
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
59.00
59.00
71.93
63.33
63.33
63.33
63.33
63.33
85.26
85.26
84.42
84.42
71.62
71.62
71.62
71.62
84.63
11
-------
Apache Station
Mistersky
Mistersky
Mistersky
MLHibbard
MLHibbard
Nibbing
Nibbing
Nibbing
Nibbing
New Ulm
New Ulm
New Ulm
Virginia
Virginia
Virginia
Virginia
Willmar
Willmar
Chevron Oil
Chevron Oil
Chevron Oil
Chevron Oil
Chevron Oil
Raton
East River
East River
Ravenswood
AES Westover
AES Westover
AES Westover
Hamilton
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
Johnsonville
160_G_ST1 Combined Cycle AZNM 72.0
1822_B_5 0/G Steam 163
1822_B_6 0/G Steam 163
1822_B_7 0/G Steam 163
1897_B_3 Biomass MRO 33.3
1897_B_4 Biomass MRO 15.3
1979_B_1 Coal Steam MRO 10.2
1979_B_2 Coal Steam MRO 10.2
1979_B_3 Coal Steam MRO 10.2
1979_B_wood Biomass MRO 20.0
2001_B_1 0/G Steam MRO 3.1
2001_B_2 0/G Steam MRO 3.1
2001_B_4 0/G Steam MRO 16.3
2018_B_10 0/G Steam MRO 9.7
2018_B_7 Coal Steam MRO 9.7
2018_B_9 Coal Steam MRO 9.7
2018_B_wood Biomass MRO 15.0
2022_B_2 0/G Steam MRO 3.0
2022_B_3 Coal Steam MRO 20.4
2047_G_1 Combustion Turbine SOU 15.0
2047_G_2 Combustion Turbine SOU 15.0
2047_G_3 Combustion Turbine SOU 16.0
2047_G_4 Combustion Turbine SOU 16.0
2047_G_5 Combustion Turbine SOU 65.0
2468_G_5 Coal Steam AZNM 6.9
2493_B_60 0/G Steam NYC 134
2493_B_70 0/G Steam NYC 182
2500_G_4 Combined Cycle NYC 231
2526_B_11 Coal Steam UPNY 21.9
2526_B_12 Coal Steam UPNY 21.9
2526_B_13 Coal Steam UPNY 84.0
2917_G_GT2 Combined Cycle RFCO 12.0
3406_B_1 Coal Steam TVA 106
3406_B_10 Coal Steam TVA 141
3406_B_2 Coal Steam TVA 106
3406_B_3 Coal Steam TVA 106
3406_B_4 Coal Steam TVA 106
3406_B_5 Coal Steam TVA 106
3406_B_6 Coal Steam TVA 106
3406_B_7 Coal Steam TVA 141
3406_B_8 Coal Steam TVA 141
11855
Not in dB
Not in dB
Not in dB
14500
14500
10331
10331
9906
14500
14500
14500
14500
11804
12245
11947
14500
14500
12260
15154
15154
15188
15188
13160
14200
12215
12215
7933
12184
12508
11000
36790
11957
10649
11957
11957
11957
11031
11031
10649
10649
11071
14500
14500
14500
14500
14500
10320
10320
9906
15716
14500
14500
14500
11804
12245
11947
15716
14500
12260
15154
15154
15188
15188
13160
14200
12830
11980
15000
11030
11030
11000
15000
11957
10649
11957
11957
11957
11031
11031
10649
10649
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.10
1.12
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
84.63
89.51
92.41
89.51
83.00
83.00
40.46
40.46
40.46
83.00
92.41
92.41
92.41
92.41
38.33
38.33
83.00
92.41
38.07
89.24
89.24
89.24
89.24
90.81
95.00
83.29
83.29
84.63
74.27
74.27
74.27
84.63
72.87
72.87
72.87
72.87
72.87
72.87
72.87
72.87
72.87
12
-------
Johnsonville
Valley
Valley
Valley
Valley
Manitowoc
Manitowoc
Manitowoc
Manitowoc
Manitowoc
Menasha
Menasha
Menasha
Pittsfield Generating LP
Pittsfield Generating LP
Pittsfield Generating LP
Pittsfield Generating LP
Chalk Cliff Cogen
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Linden Cogen Plant
Nelson Industrial Steam and Operating Company
Nelson Industrial Steam and Operating Company
Kline Township Cogen Facility
Pacific Lumber
Pacific Lumber
Pacific Lumber
Borger Plant
Borger Plant
Sierra Power
Marcus Hook Refinery Cogen
EQ Waste Energy Services
EQ Waste Energy Services
EQ Waste Energy Services
EQ Waste Energy Services
3406_B_9 Coal Steam TVA 141
4042_B_1 Coal Steam WUMS 70.0
4042_B_2 Coal Steam WUMS 70.0
4042_B_3 Coal Steam WUMS 70.0
4042_B_4 Coal Steam WUMS 70.0
4125_B_5 Coal Steam WUMS 1.5
4125_B_6 Coal Steam WUMS 18.0
4125_B_7 Coal Steam WUMS 18.0
4125_B_8 Coal Steam WUMS 20.6
4125_B_9 Coal Steam WUMS 30.0
4127_B_5 Coal Steam WUMS 6.9
4127_B_B23 Coal Steam 8.50
4127_B_B24 Coal Steam 14.5
50002_G_GEN1 Combined Cycle NENG 33.8
50002_G_GEN2 Combined Cycle NENG 33.8
50002_G_GEN3 Combined Cycle NENG 33.8
50002_G_GEN4 Combined Cycle NENG 39.6
50003_G_GEN1 Combustion Turbine CA-N 46.0
50006_G_GTG1 Combined Cycle MACE 90.0
50006_G_GTG2 Combined Cycle MACE 90.0
50006_G_GTG3 Combined Cycle MACE 90.0
50006_G_GTG4 Combined Cycle MACE 90.0
50006_G_GTG5 Combined Cycle MACE 90.0
50006_G_GTG6 Combined Cycle MACE 182
50006_G_STG1 Combined Cycle MACE 89.0
50006_G_STG2 Combined Cycle MACE 89.0
50006_G_STG3 Combined Cycle MACE 89.0
50030_B_1A Coal Steam 107
50030_B_2A Coal Steam 106
50039_B_1 Coal Steam MACW 50.0
50049_B_BLRA Biomass CA-N 16.2
50049_B_BLRB Biomass CA-N 8.7
50049_B_BLRC Biomass CA-N 8.7
50067_B_1 Fossil Waste SPPS 16.0
50067_B_2 Fossil Waste SPPS 16.0
50068_G_WEST Biomass CA-S 7.0
50074_G_GEN1 Combustion Turbine MACE 50.0
50077_G_CAT1 Landfill Gas MECS 0.50
50077_G_CAT2 Landfill Gas MECS 0.30
50077_G_CAT3 Landfill Gas MECS 0.30
50077_G_CAT4 Landfill Gas MECS 0.30
10649
13428
13428
13199
13199
11365
11470
10331
10331
10331
10331
Not in dB
Not in dB
10808
10808
10808
10808
13225
9174
9174
9174
9174
9174
9174
9174
9174
9174
NotindB
NotindB
12138
15517
15517
15517
9107
9107
15517
10973
13388
13388
13388
13388
10649
13428
13428
13199
13199
11365
11470
10320
10320
10320
8844
11844
11844
9095
9095
9095
9095
8700
6778
6778
6778
6778
6778
6778
6778
6778
6778
11041
11041
12138
15716
15716
15716
8300
8300
14500
8700
13698
13698
13698
13698
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.22
1.22
1.04
1.04
1.04
1.04
1.52
1.18
1.18
1.18
1.18
1.18
1.18
1.19
1.22
1.46
1.00
1.00
1.00
1.00
1.00
1.00
1.10
1.10
1.08
1.26
1.00
1.00
1.00
1.00
72.87
61.87
61.87
61.87
61.87
93.20
93.20
93.20
93.20
93.20
31.67
24.01
24.01
15.00
15.00
15.00
15.00
89.87
65.22
65.22
65.22
65.22
65.22
65.22
65.22
65.22
65.22
85.26
85.26
92.20
83.00
83.00
83.00
70.88
70.88
83.00
90.81
90.00
90.00
90.00
90.00
13
-------
Trigen Trenton Energy
Trigen Trenton Energy
Tillotson Rubber
Tillotson Rubber
Sierra Pacific Anderson Facility
United Cogen
United Cogen
Collins Pine Project
Sierra Pacific Burney Facility
Sierra Pacific Quincy Facility
Susanville
Susanville
US Borax
ConocoPhillips Rodeo Refinery
ConocoPhillips Rodeo Refinery
ConocoPhillips Rodeo Refinery
Coalinga Cogeneration
Sycamore Cogeneration
Sycamore Cogeneration
Sycamore Cogeneration
Sycamore Cogeneration
Snider Industries
Union Carbide Seadrift Cogen
Union Carbide Seadrift Cogen
Union Carbide Seadrift Cogen
Union Carbide Seadrift Cogen
Union Carbide Seadrift Cogen
Union Carbide Seadrift Cogen
Union Carbide Seadrift Cogen
Dow St Charles Operations
Dow St Charles Operations
Dow St Charles Operations
Dow St Charles Operations
Dow St Charles Operations
Berry Cogen
Rowan University
Watson Cogeneration
Watson Cogeneration
Watson Cogeneration
Watson Cogeneration
Watson Cogeneration
50094_G_7213 1C Engine
50094_G_7214 1C Engine
50095_B_EU1 Biomass
50095_B_EU2 0/G Steam
55049_G_GEN1 Biomass
50104_G_G-1 Combined Cycle
50104_G_G-2 Combined Cycle
10661_B_4 Biomass
50110_B_BLR1 Biomass
50112_B_BLR1 Biomass
50113_G_GEN1 Biomass
50113_G_GEN2 Biomass
50115_G_GEN1 Combustion Turbine
50119_G_GENA Non-Fossil Waste
50119_G_GENB Non-Fossil Waste
50119_G_GENC Non-Fossil Waste
50131_G_K100 Combustion Turbine
50134_G_GTAG Combustion Turbine
50134_G_GTBG Combustion Turbine
50134_G_GTCG Combustion Turbine
50134_G_GTDG Combustion Turbine
50141_G_WGN1 Biomass
50150_G_GE10 Combined Cycle
50150_G_GE11 Combined Cycle
50150_G_GEN5 Combined Cycle
50150_G_GEN6 Combined Cycle
50150_G_GEN7 Combined Cycle
50150_G_GEN8 Combined Cycle
50150_G_GEN9 Combined Cycle
50152_G_CGN1 Combined Cycle
50152_G_CGN2 Combined Cycle
50152_G_CSTG Combined Cycle
50152_G_CTG Combined Cycle
50152_G_STG Combined Cycle
50170_G_GEN1 Combustion Turbine
50173_G_GEN1 Combustion Turbine
50216_G_GN91 Combined Cycle
50216_G_GN92 Combined Cycle
50216_G_GN93 Combined Cycle
50216_G_GN94 Combined Cycle
50216_G_GN95 Combined Cycle
MACE 3.0
MACE 3.0
NENG 0.70
NENG 0.60
CA-N 5.0
CA-N 22.0
CA-N 7.0
CA-N 12.0
CA-N 16.3
CA-N 14.4
11.0
2.00
CA-N 39.0
CA-N 13.5
CA-N 13.5
CA-N 13.5
CA-N 36.0
CA-S 76.0
CA-S 76.0
CA-S 76.0
CA-S 76.0
SPPS 5.0
ERCT 15.0
ERCT 35.0
ERCT 15.0
ERCT 35.0
ERCT 6.0
ERCT 35.0
ERCT 15.0
ENTG 100
ENTG 100
ENTG 50.0
ENTG 10.0
ENTG 22.0
CA-N 35.0
MACE 1.2
CA-S 82.0
CA-S 82.0
CA-S 82.0
CA-S 82.0
CA-S 35.0
11625
11625
14594
12364
15517
9939
9939
15517
15517
15517
Not in dB
Not in dB
15981
13102
13102
13102
15015
16038
16038
16038
16038
15517
9489
9489
9489
9489
9489
9489
9489
8004
8004
8004
8004
8004
15981
12503
9939
9939
9939
9939
9939
8700
8700
8300
9210
8300
9738
9738
8300
8300
8300
15716
15716
8700
8700
8700
8700
8700
8700
8700
8700
8700
8300
9335
9335
9335
9335
9335
9335
9335
8006
8006
8006
8006
8006
8700
12477
5500
5500
5500
5500
5500
1.34
1.34
1.89
1.25
1.89
1.00
1.00
1.89
1.89
1.89
1.00
1.00
1.82
1.47
1.47
1.47
1.73
1.84
1.84
1.84
1.84
1.89
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.82
1.00
1.77
1.77
1.77
1.77
1.77
89.24
89.24
83.00
86.60
83.00
84.63
84.63
83.00
83.00
83.00
83.00
83.00
89.87
79.92
79.92
79.92
89.87
90.81
90.81
90.81
90.81
83.00
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
89.87
89.24
70.07
70.07
70.07
70.07
70.07
14
-------
Watson Cogeneration
Texas Petrochemicals
Bucksport Mill
Bucksport Mill
Bucksport Mill
Bucksport Mill
Bucksport Mill
Archibald Power Station
Ripon Mill
San Gabriel Facility
Cornell University Central Heat
Cornell University Central Heat
Paxton Creek Cogeneration
Paxton Creek Cogeneration
Newark Bay Cogeneration Project
Newark Bay Cogeneration Project
Newark Bay Cogeneration Project
Phillips 66 Carbon Plant
Phillips 66 Carbon Plant
P H Glatfelter
P H Glatfelter
P H Glatfelter
P H Glatfelter
P H Glatfelter
BP Chemicals Green Lake Plant
BP Chemicals Green Lake Plant
Mobile Energy Services LLC
Mobile Energy Services LLC
Mobile Energy Services LLC
Chester Operations
Olmsted Waste Energy
Olmsted Waste Energy
Bronx Zoo
Bronx Zoo
Bronx Zoo
Bronx Zoo
University of Michigan
University of Michigan
University of Michigan
University of Michigan
University of Michigan
50216_G_GN96
50229_B_TPCBLR
50243_B_5
50243_B_6
50243_B_7
50243_B_8
50243_G_GEN4
50279_B_MAIN
50299_G_GEN1
50300_G_GEN1
50368_G_TG1
50368_G_TG2
50373_G_GEN1
50373_G_GEN2
50385_G_GEN1
50385_G_GEN2
50385_G_GEN3
50388_B_K1
50388_B_K2
50397_B_1PB035
50397_B_3PB033
50397_B_4PB034
50397_B_5PB036
50397_B_REC037
50404_G_TG2
50404_G_TG3
50407_B_7PB
50407_B_8PB
50407_B_8RB
50410_B_10
50413_G_TG2
50413_G_TGI
50427_G_GEN1
50427_G_GEN2
50427_G_GEN3
50427_G_GEN4
50431_G_TG1
50431_G_TG10
50431_G_TG7
50431_G_TG8
50431_G_TG9
Combined Cycle
0/G Steam
0/G Steam
0/G Steam
0/G Steam
Biomass
Combustion Turbine
Landfill Gas
Combustion Turbine
Combustion Turbine
Coal Steam
Coal Steam
1C Engine
1C Engine
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Non-Fossil Waste
Non-Fossil Waste
Non-Fossil Waste
Biomass
0/G Steam
0/G Steam
Coal Steam
Municipal Solid Waste
Municipal Solid Waste
1C Engine
1C Engine
1C Engine
1C Engine
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
CA-S
ERCT
NENG
NENG
NENG
NENG
NENG
MACW
CA-N
CA-S
UPNY
UPNY
MACW
MACW
MACE
MACE
MACE
CA-N
CA-N
MACW
MACW
MACW
MACW
MACW
ERCT
ERCT
SOU
SOU
SOU
MACE
MRO
MRO
NYC
NYC
NYC
NYC
MECS
MECS
MECS
MECS
MECS
CA-S 35.0
ERCT 35.0
NENG 23.3
NENG 23.3
NENG 23.3
NENG 23.3
NENG 176
MACW 20.0
CA-N 46.5
CA-S 39.0
UPNY 1
UPNY 5.3
MACW 6.0
MACW 6.0
MACE 42.0
MACE 42.0
MACE 34.0
CA-N 10.0
CA-N 10.0
MACW 8.7
MACW 4.0
MACW 9.0
MACW 36.1
MACW 31.2
ERCT 15.0
ERCT 23.8
SOU 14.4
SOU 12.5
SOU 13.2
MACE 36.0
MRO 1.3
MRO 1.4
NYC 0.50
NYC 0.50
NYC 1.1
NYC 1.5
MECS 11.5
MECS 3.0
MECS 11.5
MECS 11.5
MECS 3.0
9939
11332
11844
11332
11332
15517
12435
13682
15778
16200
10331
10331
14993
14993
8700
8700
8700
10331
10331
10331
12508
10331
10331
13102
13102
13102
15517
11425
11425
10331
19338
19338
11600
11600
11600
11600
6920
6920
6920
6920
6920
5500
8300
8300
8300
8300
8300
9963
13698
8700
8700
9628
9628
8851
8851
8181
8181
8181
10320
10320
8300
8300
8300
8300
8300
9854
9854
10510
10538
10538
8300
11773
11773
8700
8700
8700
8700
5500
5500
5500
5500
5500
1.77
1.39
1.39
1.39
1.39
1.89
1.24
1.00
1.81
1.86
1.07
1.07
1.69
1.69
1.06
1.06
1.06
1.00
1.00
1.24
1.49
1.24
1.24
1.54
1.30
1.30
1.50
1.09
1.06
1.24
1.38
1.38
1.29
1.29
1.29
1.29
1.26
1.26
1.26
1.26
1.26
70.07
92.41
89.51
89.51
89.51
83.00
90.81
90.00
89.87
89.87
85.26
85.26
89.24
89.24
15.23
15.23
15.23
85.26
85.26
85.26
85.26
85.26
85.26
88.41
89.10
89.10
83.00
92.41
92.41
85.26
63.34
63.34
89.24
89.24
89.24
89.24
34.14
34.14
34.14
34.14
34.14
15
-------
S D Warren Westbrook
S D Warren Westbrook
S D Warren Westbrook
S D Warren Westbrook
Indeck Silver Springs Energy Center
Indeck Silver Springs Energy Center
Indeck Oswego Energy Center
Indeck Oswego Energy Center
Indeck Yerkes Energy Center
Indeck Yerkes Energy Center
Indeck Corinth Energy Center
Indeck Corinth Energy Center
Oxnard
Oxnard
American Ref-Fuel of Niagara
American Ref-Fuel of Niagara
American Ref-Fuel of Niagara
American Ref-Fuel of Niagara
Corpus Christi
Bryant Sugar House
Bryant Sugar House
Bryant Sugar House
Bryant Sugar House
Bryant Sugar House
Bryant Sugar House
PPG Powerhouse C
PPG Powerhouse C
PPG Powerhouse C
PPG Powerhouse C
PPG Powerhouse C
Gas Utilization Facility
Gas Utilization Facility
Double C
Double C
Kern Front
Kern Front
High Sierra
High Sierra
Bayonne Cogen Plant
Bayonne Cogen Plant
Bayonne Cogen Plant
50447_B_17 0/G Steam
50447_B_18 0/G Steam
50447_B_20 Biomass
50447_B_21 Biomass
50449_G_GEN1 Combined Cycle
50449_G_GEN2 Combined Cycle
50450_G_GEN1 Combined Cycle
50450_G_GEN2 Combined Cycle
50451_G_GEN1 Combined Cycle
50451_G_GEN2 Combined Cycle
50458_G_GEN1 Combined Cycle
50458_G_GEN2 Combined Cycle
50464_G_GEN1 Combustion Turbine
50464_G_GEN2 Combustion Turbine
50472_B_BLR1 0/G Steam
50472_B_BLR2 Biomass
50472_B_BLR3 Municipal Solid Waste
50472_B_BLR4 Municipal Solid Waste
50475_G_GEN1 Combustion Turbine
50483_B_B1 Biomass
50483_B_B2 Biomass
50483_B_B3 Biomass
50483_B_B4 Biomass
50483_B_B7 Biomass
50483_B_B8 Biomass
50489_G_C1 Combined Cycle
50489_G_C2 Combined Cycle
50489_G_C3 Combined Cycle
50489_G_C4 Combined Cycle
50489_G_C5 Combined Cycle
50492_G_1 Non-Fossil Waste
50492_G_2 Non-Fossil Waste
50493_G_DC1 Combustion Turbine
50493_G_DC2 Combustion Turbine
50494_G_KF1 Combustion Turbine
50494_G_KF2 Combustion Turbine
50495_G_HS1 Combustion Turbine
50495_G_HS2 Combustion Turbine
50497_G_GTG1 Combined Cycle
50497_G_GTG2 Combined Cycle
50497_G_GTG3 Combined Cycle
NENG 11.9
NENG 11.9
NENG 11.9
NENG 26.9
UPNY 33.7
UPNY 17.2
UPNY 30.1
UPNY 16.2
UPNY 29.0
UPNY 19.4
DSNY 76.5
DSNY 55.0
CA-S 21.5
CA-S 45.0
UPNY 9.0
UPNY 9.0
UPNY 9.0
UPNY 9.0
ERCT 33.0
FRCC 4.4
FRCC 4.4
FRCC 4.4
FRCC 4.4
FRCC 4.4
FRCC 4.4
ENTG 55.0
ENTG 55.0
ENTG 52.0
ENTG 70.6
ENTG 70.6
CA-S 2.3
CA-S 2.3
CA-N 23.0
CA-N 23.0
CA-N 23.0
CA-N 23.0
CA-N 23.0
CA-N 23.0
MACE 36.0
MACE 36.0
MACE 36.0
11844
11844
15517
15517
8890
8890
9250
9250
9870
9870
8030
8030
15981
15981
11332
15517
19338
19338
15981
15517
15517
15517
15517
15517
15517
9939
9939
9939
9939
9939
13102
13102
14379
14379
15423
15423
15410
15410
9300
9300
9300
9021
9021
8300
8300
8270
8270
8370
8370
9325
9325
7996
7996
8700
8700
8300
8456
8300
8300
8700
8300
8300
8300
8300
8300
8300
9738
9738
9738
9738
9738
8700
8700
8700
8700
8700
8700
8700
8700
5634
5634
5634
1.28
1.28
1.87
1.89
1.00
1.00
1.03
1.03
1.01
1.01
1.00
1.00
1.82
1.82
1.39
1.86
1.96
1.96
1.82
1.89
1.89
1.89
1.89
1.89
1.89
1.00
1.00
1.00
1.00
1.00
1.47
1.47
1.65
1.65
1.77
1.77
1.77
1.77
1.64
1.64
1.64
86.60
86.60
64.60
83.00
84.63
84.63
15.00
15.00
15.00
15.00
84.63
84.63
89.87
89.87
92.41
83.00
80.91
80.91
89.87
83.00
83.00
83.00
83.00
83.00
83.00
84.63
84.63
84.63
84.63
84.63
82.98
82.98
89.87
89.87
89.87
89.87
89.87
89.87
15.00
15.00
15.00
16
-------
Bayonne Cogen Plant
Capital District Energy Center
Capital District Energy Center
Mosaic Co Mulberry Facility
SRI International Cogen Project
Black Hills Ontario Facility
Black Hills Ontario Facility
Rosemary Power Station
Rosemary Power Station
Rosemary Power Station
PowerSmith Cogeneration Project
PowerSmith Cogeneration Project
Eagle Point Cogeneration
Eagle Point Cogeneration
Eagle Point Cogeneration
McKittrick Cogen
TXU Sweetwater Generating Plant
TXU Sweetwater Generating Plant
TXU Sweetwater Generating Plant
TXU Sweetwater Generating Plant
Berry Cogen Tanne Hills 18
Berry Cogen Tanne Hills 18
Gaviota Oil Plant
Gaviota Oil Plant
Gaviota Oil Plant
Gaviota Oil Plant
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
ExxonMobil Beaumont Refinery
Covanta Marion Inc
Covanta Marion Inc
Mosaic Co Martlow Facility
Mosaic Co Martlow Facility
Potlatch Idaho Pulp Paper
Potlatch Idaho Pulp Paper
50497_G_STG1 Combined Cycle
50498_G_GTG Combined Cycle
50498_G_STG Combined Cycle
50510_G_CGN1 Non-Fossil Waste
50537_G_GEN1 Combustion Turbine
50538_G_GEN1 Combustion Turbine
50538_G_GEN2 Combustion Turbine
50555_G_GEN1 Combined Cycle
50555_G_GEN2 Combined Cycle
50555_G_GEN3 Combined Cycle
50558_G_GT01 Combined Cycle
50558_G_ST01 Combined Cycle
50561_G_GTG1 Combined Cycle
50561_G_GTG2 Combined Cycle
50561_G_STG1 Combined Cycle
50612_G_GEN1 Combustion Turbine
50615_G_GT01 Combined Cycle
50615_G_GT02 Combined Cycle
50615_G_GT03 Combined Cycle
50615_G_STG1 Combined Cycle
50622_G_GEN1 Combustion Turbine
50622_G_GEN2 Combustion Turbine
50623_G_GENA Combustion Turbine
50623_G_GENB Combustion Turbine
50623_G_GENC Combustion Turbine
50623_G_GEND Combustion Turbine
50625_B_22 Fossil Waste
50625_B_24 0/G Steam
50625_B_33 Fossil Waste
50625_B_34 Fossil Waste
50625_G_TG23 Combined Cycle
50625_G_TG24 Combined Cycle
50625_G_TG41 Combustion Turbine
50625_G_TG42 Combustion Turbine
50625_G_TG43 Combustion Turbine
50630_B_BLR1 Municipal Solid Waste
50630_B_BLR2 Municipal Solid Waste
50633_G_GEN1 Non-Fossil Waste
50633_G_GEN2 Non-Fossil Waste
50637_B_1PWR 0/G Steam
50637_B_2PWR 0/G Steam
MACE 62.0
NENG 34.3
NENG 21.0
FRCC 19.5
CA-N 5.6
CA-S 4.5
CA-S 4.5
VAPW 75.0
VAPW 36.0
VAPW 54.0
SPPS 67.3
SPPS 44.1
MACE 75.0
MACE 75.0
MACE 45.0
CA-N 46.0
ERCT 32.0
ERCT 72.0
ERCT 72.0
ERCT 64.0
CA-N 7.0
CA-N 7.0
CA-S 3.0
CA-S 3.0
CA-S 3.0
CA-S 3.0
ENTG 16.7
ENTG 8.3
ENTG 37.5
ENTG 37.5
ENTG 38.6
ENTG 32.0
ENTG 152
ENTG 152
ENTG 152
PNW 5.8
PNW 5.8
FRCC 36.0
FRCC 44.0
PNW 1.4
PNW 1.4
9300
9200
9200
13102
15981
15981
15981
8900
8900
8900
7272
7272
7933
7933
7933
15073
13157
13157
13157
13157
15899
15899
15981
15981
15981
15981
9107
11425
9107
9107
7933
7933
12435
12435
12435
19338
19338
13102
13102
14789
14789
5634
9545
9545
Retired
8700
Retired
Retired
9911
9911
9911
8009
8009
7942
7942
7942
8700
13157
13157
13157
13157
8700
8700
8700
8700
8700
8700
8300
11177
8300
8300
6377
6377
8700
8700
8700
16297
16297
9854
9854
12156
12156
1.64
1.00
1.00
1.82
1.00
1.00
1.00
1.08
1.08
1.00
1.00
1.00
1.73
1.00
1.00
1.00
1.00
1.83
1.83
1.82
1.82
1.82
1.82
1.10
1.00
1.10
1.10
1.25
1.25
1.42
1.42
1.42
1.00
1.00
1.30
1.30
1.17
1.17
15.00
84.63
84.63
0.00
89.24
0.00
0.00
84.63
84.63
84.63
47.06
47.06
84.63
84.63
84.63
89.87
84.63
84.63
84.63
84.63
89.24
89.24
89.24
89.24
89.24
89.24
23.76
92.41
23.76
23.76
84.63
84.63
90.81
90.81
90.81
90.00
90.00
74.23
74.23
89.51
89.51
17
-------
Potlatch Idaho Pulp Paper
Potlatch Idaho Pulp Paper
Potlatch Idaho Pulp Paper
Sierra Pacific Quincy Facility
Covanta Indianapolis Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Trigen Syracuse Energy
Thermo Power & Electric
Thermo Power & Electric
Thermo Power & Electric
KMS Crossroads
TCP 272
TCP 272
TCP 272
TCP 272
TCP 272
TCP 272
TCP 272
Thermo Greeley
BP Naperville Cogeneration Facility
Sterling Power Plant
Sterling Power Plant
Agnews Power Plant
Agnews Power Plant
Coalinga Cogeneration Facility
Coalinga Cogeneration Facility
Southeast Kern River Cogen
Southeast Kern River Cogen
Southeast Kern River Cogen
Viking Energy of Northumberland
EFS Parlin
EFS Parlin
EFS Parlin
EFS Parlin
Stone Container Florence Mill
Stone Container Florence Mill
Stone Container Florence Mill
50637_B_4PWR Biomass
50637_B_4REC 0/G Steam
50637_B_5REC Non-Fossil Waste
50112_B_BLR2 Biomass
50647_G_GEN1 Municipal Solid Waste
50651_B_1 Coal Steam
50651_B_2 Coal Steam
50651_B_3 Coal Steam
50651_B_4 Coal Steam
50651_B_5 Coal Steam
50651_G_GEN2 Coal Steam
50676_G_GEN1 Combined Cycle
50676_G_GEN2 Combined Cycle
50676_G_GEN3 Combined Cycle
50693_G_DG-1 1C Engine
50707_G_LMA Combined Cycle
50707_G_LMB Combined Cycle
50707_G_LMC Combined Cycle
50707_G_LMD Combined Cycle
50707_G_LME Combined Cycle
50707_G_STA Combined Cycle
50707_G_STB Combined Cycle
50709_G_GEN1 Combustion Turbine
50722_G_GEN1 Combustion Turbine
50744_G_GEN1 Combined Cycle
50744_G_GEN2 Combined Cycle
50748_G_GEN1 Combined Cycle
50748_G_GEN2 Combined Cycle
50750_G_GEN1 Combustion Turbine
50750_G_GEN2 Combustion Turbine
50751_G_GTG1 Combustion Turbine
50751_G_GTG2 Combustion Turbine
50751_G_GTG3 Combustion Turbine
50771_B_B1 Biomass
50799_G_GT1 Combined Cycle
50799_G_GT2 Combined Cycle
50799_G_STG1 Combined Cycle
50799_G_STG2 Combined Cycle
50806_B_PB1 0/G Steam
50806_B_PB3 Biomass
50806 B PB4 Coal Steam
PNW 27.2
PNW 1.6
PNW 32.2
CA-N 14.4
RFCO 5.0
UPNY 11.1
UPNY 11.1
UPNY 11.1
UPNY 11.1
UPNY 11.1
UPNY 11.0
RMPA 30.0
RMPA 30.0
RMPA 8.0
MACE 7.0
RMPA 31.8
RMPA 31.8
RMPA 31.8
RMPA 31.8
RMPA 31.8
RMPA 52.0
RMPA 52.0
RMPA 37.0
COMD 7.0
UPNY 38.8
UPNY 16.0
CA-N 23.0
CA-N 7.3
CA-N 3.2
CA-N 3.2
CA-N 20.5
CA-N 3.0
CA-N 3.0
MACW 16.0
MACE 38.0
MACE 38.0
MACE 25.0
MACE 25.0
VACA 5.6
VACA 7.6
VACA 74.8
15517
11332
13102
15517
19338
10000
10331
10331
10331
10331
10000
8650
8650
8650
10100
9400
9400
9400
9400
9400
9400
9400
14104
12503
8968
8968
8944
8944
15981
15981
15981
15981
15981
15517
10500
10500
10500
10500
11844
15517
10331
12152
11511
12147
8300
8300
8300
8300
8300
8300
8300
8300
6245
6245
6245
10100
9503
9503
9503
9503
9503
9503
9503
8700
12477
8247
8247
7884
7884
8700
8700
8700
8700
8700
14500
7942
7942
7942
7942
8300
8300
8300
1.29
1.00
1.05
1.89
1.96
1.20
1.24
1.24
1.24
1.24
1.20
1.68
1.68
1.68
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.62
1.00
1.03
1.03
1.08
1.08
1.82
1.82
1.82
1.82
1.82
1.08
1.00
1.00
1.00
1.00
1.39
1.89
1.24
83.00
89.51
57.86
83.00
88.41
41.00
41.00
41.00
41.00
41.00
41.00
20.09
20.09
20.09
89.24
84.63
84.63
84.63
84.63
84.63
84.63
84.63
89.87
89.24
15.00
15.00
83.51
83.51
89.24
89.24
89.73
89.73
89.73
83.00
84.63
84.63
84.63
84.63
89.51
83.00
85.26
18
-------
Stone Container Florence Mill
Stone Container Hopewell Mill
Stone Container Hopewell Mill
CoGen Lyondell
CoGen Lyondell
CoGen Lyondell
CoGen Lyondell
CoGen Lyondell
CoGen Lyondell
CoGen Lyondell
TES Filer City Station
TES Filer City Station
Southeast Resource Recovery
Southeast Resource Recovery
Southeast Resource Recovery
WeirCogen Plant
PE Berkeley
PE Berkeley
OLS Energy Chino
OLS Energy Chino
OLS Energy Camarillo
OLS Energy Camarillo
RPL Holdings
RPL Holdings
Onondaga Cogeneration
Onondaga Cogeneration
Onondaga Cogeneration
Kent County Waste to Energy Facility
Kent County Waste to Energy Facility
Sargent Canyon Cogeneration
Salinas River Cogeneration
Wheelabrator Sherman Energy Facility
Wheelabrator Norwalk Energy
Wheelabrator Norwalk Energy
Wheelabrator Frackville Energy
Wheelabrator Gloucester LP
Wheelabrator Gloucester LP
Northampton Generating Company
Oswego County Energy Recovery
Oswego County Energy Recovery
Potlatch Southern Wood Products
50806_B_RBF 0/G Steam
50813_B_CB1 Biomass
50813_B_RB1 Non-Fossil Waste
50815_G_GEN1 Combined Cycle
50815_G_GEN2 Combined Cycle
50815_G_GEN3 Combined Cycle
50815_G_GEN4 Combined Cycle
50815_G_GEN5 Combined Cycle
50815_G_GEN6 Combined Cycle
50815_G_GEN7 Combined Cycle
50835_B_1 Coal Steam
50835_B_2 Coal Steam
50837_B_UNIT1 Municipal Solid Waste
50837_B_UNIT2 Municipal Solid Waste
50837_B_UNIT3 Municipal Solid Waste
50848_G_GT1 Combustion Turbine
50849_G_GEN1 Combined Cycle
50849_G_GEN2 Combined Cycle
50850_G_GEN1 Combined Cycle
50850_G_GEN2 Combined Cycle
50851_G_GEN1 Combined Cycle
50851_G_GEN2 Combined Cycle
50852_G_GEN1 Combined Cycle
50852_G_GEN2 Combined Cycle
50855_G_GEN1 Combined Cycle
50855_G_GEN2 Combined Cycle
50855_G_GEN3 Combined Cycle
50860_B_BLR1 Municipal Solid Waste
50860_B_BLR2 Municipal Solid Waste
50864_G_K100 Combustion Turbine
50865_G_K100 Combustion Turbine
50874_B_19425 Biomass
50876_G_GEN1 Combined Cycle
50876_G_GEN2 Combined Cycle
50879_B_BLR1 Coal Steam
50885_B_BLR1 Municipal Solid Waste
50885_B_BLR2 Municipal Solid Waste
50888_B_BLR1 Coal Steam
50907_G_UNT1 Municipal Solid Waste
50907_G_UNT2 Municipal Solid Waste
50640 B BLR1 Biomass
VACA 15.3
VAPW 20.4
VAPW 20.4
ERCT 64.0
ERCT 64.0
ERCT 64.0
ERCT 64.0
ERCT 64.0
ERCT 64.0
ERCT 64.0
MECS 30.0
MECS 30.0
CA-S 9.3
CA-S 9.3
CA-S 9.3
CA-N 3.2
CA-N 21.0
CA-N 2.0
CA-S 22.5
CA-S 6.5
CA-S 21.5
CA-S 6.8
MACE 51.0
MACE 13.9
UPNY 45.0
UPNY 25.0
UPNY 23.0
MECS 7.9
MECS 7.9
CA-N 30.0
CA-N 33.0
21.0
CA-S 19.8
CA-S 6.6
MACW 44.5
6.00
6.00
MACW 112
UPNY 1.7
UPNY 1.7
ENTG 10.0
11844
15517
13102
9500
9500
9500
9500
9500
9500
9500
11308
10331
19338
19338
19338
15981
9939
9939
8650
8650
8580
8580
10000
10000
9188
9188
9188
19338
19338
14996
15001
Not in dB
9280
9280
11503
Not in dB
Not in dB
12174
19338
19338
15517
8300
8300
8300
9486
9486
9486
9486
9486
9486
9486
11308
10320
16297
16297
16297
15845
5500
5500
7132
7132
7828
7828
11652
11652
Retired
Retired
Retired
16297
16297
8700
8700
15716
7870
7870
9282
16297
16297
11336
8300
8300
8300
1.39
1.89
1.54
1.27
1.27
1.27
1.27
1.27
1.27
1.27
1.00
1.00
1.00
1.00
1.00
1.00
1.77
1.77
1.18
1.18
1.03
1.03
1.00
1.00
1.00
1.00
1.72
1.72
1.00
1.20
1.20
1.24
1.00
1.00
1.07
1.96
1.96
1.89
89.51
83.00
67.40
76.54
76.54
76.54
76.54
76.54
76.54
76.54
93.30
93.30
90.00
90.00
90.00
89.24
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
0.00
0.00
0.00
90.00
90.00
89.87
89.87
83.00
39.95
39.95
95.00
90.00
90.00
89.30
80.91
80.91
83.00
19
-------
Yellowstone Energy LP
Yellowstone Energy LP
Watsonville Power Plant
Watsonville Power Plant
Indiantown Cogeneration LP
Pryor Power Plant
Pryor Power Plant
Pryor Power Plant
STEC-S LLC
North Shore Towers
North Shore Towers
North Shore Towers
North Shore Towers
North Shore Towers
North Shore Towers
Trigen Nassau Energy
Trigen Nassau Energy
Rhodia Dominguez Plant
Rhodia Houston Plant
Rhodia Houston Plant
McKittrick Cogen
McKittrick Cogen
McKittrick Cogen
North Midway Cogen
North Midway Cogen
North Midway Cogen
Concord Cogen
Concord Cogen
Cymric 31X Cogen
Cymric 31X Cogen
Cymric 6Z Cogen
Cymric 6Z Cogen
Coalinga 6C Cogen
Coalinga 6C Cogen
Taft 26C Cogen
Taft 26C Cogen
Taft 26C Cogen
Taft 26C Cogen
Coalinga 25D Cogen
Coalinga 25D Cogen
Coalinga 25D Cogen
50931_B_BLR1 Coal Steam
50931_B_BLR2 Coal Steam
50968_G_GEN1 Combined Cycle
50968_G_GEN2 Combined Cycle
50976_B_AAB01 Coal Steam
50991_G_GEN1 Combustion Turbine
50991_G_GEN2 Combustion Turbine
50991_G_GN10 0/G Steam
56079_B_North Biomass
52052_G_GEN1 1C Engine
52052_G_GEN2 1C Engine
52052_G_GEN3 1C Engine
52052_G_GEN4 1C Engine
52052_G_GEN5 1C Engine
52052_G_GEN6 1C Engine
52056_G_GT1 Combined Cycle
52056_G_ST1 Combined Cycle
52064_G_GEN1 0/G Steam
52065_G_GEN1 Non-Fossil Waste
52065_G_GEN2 Non-Fossil Waste
52076_G_GEN1 Combustion Turbine
52076_G_GEN2 Combustion Turbine
52076_G_GEN3 Combustion Turbine
52078_G_GEN7 Combustion Turbine
52078_G_GEN8 Combustion Turbine
52078_G_GEN9 Combustion Turbine
52080_G_1605 1C Engine
52080_G_1606 1C Engine
52081_G_TG1 Combustion Turbine
52081_G_TG2 Combustion Turbine
52082_G_TG1 Combustion Turbine
52082_G_TG2 Combustion Turbine
52083_G_TG1 Combustion Turbine
52083_G_TG2 Combustion Turbine
52085_G_TG1 Combustion Turbine
52085_G_TG2 Combustion Turbine
52085_G_TG3 Combustion Turbine
52085_G_TG4 Combustion Turbine
52086_G_TG1 Combustion Turbine
52086_G_TG2 Combustion Turbine
52086 G TG3 Combustion Turbine
NWPE 27.5
NWPE 27.5
CA-N 22.0
CA-N 6.9
FRCC 330
SPPS 17.5
SPPS 17.5
SPPS 13.0
ENTG 2.0
NYC 1.1
NYC 1.1
NYC 1.1
NYC 1.1
NYC 1.1
NYC 1.1
LILC 43.0
LILC 12.0
CA-S 3.0
ERCT 6.0
ERCT 1.5
CA-N 2.9
CA-N 2.9
CA-N 2.9
CA-N 2.9
CA-N 2.9
CA-N 2.9
CA-N 1.5
CA-N 1.5
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
14500
10331
11693
11693
9200
12503
12503
14789
15517
13298
13298
13298
13298
13298
13298
7492
7492
11332
13102
13102
15981
15981
15981
15981
15981
15981
13298
13298
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
11122
10320
7636
7636
9200
Retired
Retired
Retired
14500
8700
8700
8700
8700
8700
8700
6231
6231
8300
8300
8300
8700
8700
8700
8700
8700
8700
10526
10526
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
1.30
1.00
1.12
1.12
1.00
1.08
1.52
1.52
1.52
1.52
1.52
1.52
1.55
1.55
1.39
1.54
1.54
1.82
1.82
1.82
1.82
1.82
1.82
1.25
1.25
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
85.26
85.26
64.66
64.66
74.13
0.00
0.00
0.00
83.00
89.24
89.24
89.24
89.24
89.24
89.24
84.63
84.63
92.45
89.10
89.10
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
20
-------
Coalinga 25D Cogen
Texas City Power Plant
Texas City Power Plant
Texas City Power Plant
Texas City Power Plant
New York Methodist Hospital
New York Methodist Hospital
Oxford Cogeneration Facility
Oxford Cogeneration Facility
Kern River Fee A Cogen
Kern River Fee A Cogen
Kern River Fee C Cogen
Kern River Fee C Cogen
Berry Placerita Cogen
Berry Placerita Cogen
Cymric 36W Cogen
Cymric 36W Cogen
Cymric 36W Cogen
Cymric 36W Cogen
Kern River Eastridge Cogen
Kern River Eastridge Cogen
C PKelcoSan Diego Plant
C PKelcoSan Diego Plant
C PKelcoSan Diego Plant
Midway Sunset Cogen
Midway Sunset Cogen
Midway Sunset Cogen
C R Wing Cogen Plant
C R Wing Cogen Plant
C R Wing Cogen Plant
Yuba City Cogen Partners
Delaware City Plant
Delaware City Plant
Delaware City Plant
Delaware City Plant
JRW Associates LP
JRW Associates LP
JRW Associates LP
JRW Associates LP
JRW Associates LP
JRW Associates LP
52086_G_TG4 Combustion Turbine
52088_G_GEN1 Combined Cycle
52088_G_GEN2 Combined Cycle
52088_G_GEN3 Combined Cycle
52088_G_GEN4 Combined Cycle
52091_G_3A 1C Engine
52091_G_4C 1C Engine
52093_G_GEN1 Combustion Turbine
52093_G_GEN2 Combustion Turbine
52094_G_GEN1 Combustion Turbine
52094_G_GEN2 Combustion Turbine
52095_G_GEN1 Combustion Turbine
52095_G_GEN2 Combustion Turbine
52096_G_GEN1 Combustion Turbine
52096_G_GEN2 Combustion Turbine
52104_G_GEN1 Combustion Turbine
52104_G_GEN2 Combustion Turbine
52104_G_GEN3 Combustion Turbine
52104_G_GEN4 Combustion Turbine
52107_G_101A Combustion Turbine
52107_G_101B Combustion Turbine
52147_G_GEN1 Combustion Turbine
52147_G_GEN2 Combustion Turbine
52147_G_GEN3 Combustion Turbine
52169_G_A Combustion Turbine
52169_G_B Combustion Turbine
52169_G_C Combustion Turbine
52176_G_GEN1 Combined Cycle
52176_G_GEN2 Combined Cycle
52176_G_GEN3 Combined Cycle
52186_G_GEN1 Combustion Turbine
52193_G_CT1 Fossil Waste
52193_G_CT2 Fossil Waste
52193_G_G1 Fossil Waste
52193_G_G2 Fossil Waste
52198_G_GEN1 0/G Steam
52198_G_GEN2 0/G Steam
52198_G_GEN3 1C Engine
52198_G_GEN4 1C Engine
52198_G_GEN5 1C Engine
52198_G_GEN6 1C Engine
CA-N 2.7
ERCT 139
ERCT 104
ERCT 104
ERCT 104
NYC 0.70
NYC 0.70
CA-N 2.4
CA-N 2.4
CA-S 3.2
CA-S 3.2
CA-S 3.6
CA-S 3.2
CA-S 19.6
CA-S 19.6
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 2.7
CA-N 21.0
CA-N 21.0
CA-S 8.0
CA-S 9.3
CA-S 9.3
CA-N 73.0
CA-N 73.0
CA-N 73.0
ERCT 76.0
ERCT 76.0
ERCT 75.0
CA-N 48.7
MACE 101
MACE 92.0
MACE 29.5
MACE 29.5
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
15981
10299
10299
10299
10299
12870
12870
15981
15981
15981
15981
15981
15981
12503
12503
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
15981
8982
8982
8982
15256
9107
9107
9107
9107
11425
11425
11600
11600
11600
11600
8700
6319
6319
6319
6319
8700
8700
15845
15845
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
8700
7718
7718
7718
8700
9107
9107
9107
9107
11177
11177
8700
8700
8700
8700
1.82
1.49
1.49
1.49
1.49
1.48
1.48
1.00
1.00
1.82
1.82
1.82
1.82
1.43
1.43
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.82
1.11
1.11
1.11
1.75
1.00
1.00
1.00
1.00
1.00
1.00
1.29
1.29
1.29
1.29
89.24
42.30
42.30
42.30
42.30
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.87
89.87
89.24
89.24
89.24
89.24
89.87
89.87
89.24
89.24
89.24
90.81
90.81
90.81
31.59
31.59
31.59
89.87
90.00
90.00
90.00
90.00
92.45
92.45
89.24
89.24
89.24
89.24
21
-------
JRW Associates LP
JRW Associates LP
Ridgewood/Byron Power Partners
Ridgewood/Byron Power Partners
Ridgewood/Byron Power Partners
Ridgewood/Byron Power Partners
Ridgewood/Byron Power Partners
Sunnyside Cogen Partners
Sunnyside Cogen Partners
Sunnyside Cogen Partners
Sunnyside Cogen Partners
Sunnyside Cogen Partners
Pittsburg Power Plant
Pittsburg Power Plant
Pittsburg Power Plant
Westmoreland Roanoke Valley I
Lockport Energy Associates LP
Lockport Energy Associates LP
Lockport Energy Associates LP
Lockport Energy Associates LP
Wythe Park Power Petersburg Plant
Wythe Park Power 3 Richmond Plant
Pawtucket Power Associates
Pawtucket Power Associates
IndeckOlean Energy Center
IndeckOlean Energy Center
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Cogentrix of Richmond
Kennedy International Airport Cogen
Kennedy International Airport Cogen
Kennedy International Airport Cogen
Fortistar North Tonawanda
Fortistar North Tonawanda
Fulton Cogeneration Associates
Stony Brook Cogen Plant
52198_G_GEN7 1C Engine
52198_G_GEN8 1C Engine
52199_G_GEN1 1C Engine
52199_G_GEN2 1C Engine
52199_G_GEN3 1C Engine
52199_G_GEN4 1C Engine
52199_G_GEN5 1C Engine
52201_G_GEN1 1C Engine
52201_G_GEN2 1C Engine
52201_G_GEN3 1C Engine
52201_G_GEN4 1C Engine
52201_G_GEN5 1C Engine
54001_G_GEN1 Combustion Turbine
54001_G_GEN2 Combustion Turbine
54001_G_GEN3 Combustion Turbine
54035_B_BLR1 Coal Steam
54041_G_GEN1 Combined Cycle
54041_G_GEN2 Combined Cycle
54041_G_GEN3 Combined Cycle
54041_G_GEN4 Combined Cycle
54045_G_1 Fossil Waste
54047_G_EXIS 1C Engine
54056_G_GEN1 Combined Cycle
54056_G_GEN2 Combined Cycle
54076_G_GEN1 Combined Cycle
54076_G_GEN2 Combined Cycle
54081_B_1A Coal Steam
54081_B_1B Coal Steam
54081_B_2A Coal Steam
54081_B_2B Coal Steam
54081_B_3A Coal Steam
54081_B_3B Coal Steam
54081_B_4A Coal Steam
54081_B_4B Coal Steam
54114_G_GEN1 Combined Cycle
54114_G_GEN2 Combined Cycle
54114_G_GEN3 Combined Cycle
54131_G_GEN1 Combined Cycle
54131_G_GEN2 Combined Cycle
54138_G_GTG Combustion Turbine
54149 G GEN1 Combustion Turbine
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 16.5
CA-N 22.0
CA-N 22.0
VAPW 165
UPNY 45.0
UPNY 45.0
UPNY 45.0
UPNY 75.2
VAPW 3.0
VAPW 3.0
NENG 36.0
NENG 27.0
UPNY 31.9
UPNY 44.6
VAPW 26.3
VAPW 26.3
VAPW 26.3
VAPW 26.3
VAPW 21.3
VAPW 21.3
VAPW 21.3
VAPW 21.3
NYC 49.0
NYC 50.3
NYC 27.0
UPNY 40.4
UPNY 16.3
UPNY 42.0
LILC 44.5
11600
11600
13776
13776
13776
13776
13776
11303
11303
11303
11303
11303
9939
9939
9939
10370
9091
9091
9091
9091
12320
12283
8950
8950
8740
8740
11303
10331
11303
10331
11300
10331
11300
10331
10315
10315
10315
7800
7800
12503
12082
8700
8700
12672
12672
12672
12672
12672
11303
11303
11303
11303
11303
8700
8700
8700
9109
7428
7428
7428
7428
9316
9000
8908
8908
8626
8626
9258
9258
9258
9258
9258
9258
9258
9258
8033
8033
8033
7815
7815
12477
8700
1.29
1.29
1.09
1.09
1.09
1.09
1.09
1.00
1.00
1.00
1.00
1.00
1.14
1.14
1.14
1.14
1.16
1.16
1.16
1.16
1.32
1.36
1.00
1.00
1.00
1.00
1.22
1.11
1.22
1.11
1.22
1.11
1.22
1.11
1.28
1.28
1.28
1.15
1.15
1.00
1.39
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.24
27.74
27.74
27.74
90.70
47.49
47.49
47.49
47.49
6.17
89.24
84.63
84.63
84.63
84.63
71.07
71.07
71.07
71.07
71.07
71.07
71.07
71.07
49.51
49.51
49.51
15.00
15.00
89.87
89.87
22
-------
Franklin Heating Station
Franklin Heating Station
Franklin Heating Station
Franklin Heating Station
Franklin Heating Station
Franklin Heating Station
Franklin Heating Station
Franklin Heating Station
Port of Stockton District Energy Fac
Port of Stockton District Energy Fac
March Point Cogeneration
March Point Cogeneration
March Point Cogeneration
March Point Cogeneration
Saguaro Power
Saguaro Power
Saguaro Power
Birchwood Power
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Goodyear Beaumont Chemical Plant
Bucknell University
Bucknell University
Nevada Cogen Associates 2 Black Mountain
Nevada Cogen Associates 2 Black Mountain
Nevada Cogen Associates 2 Black Mountain
Nevada Cogen Associates 2 Black Mountain
Nevada Cogen Assocttl GarnetVly
Nevada Cogen Assocttl GarnetVly
Nevada Cogen Assocttl GarnetVly
Nevada Cogen Assocttl GarnetVly
Orange Cogeneration Facility
54224_B_GEN6
54224_B_SG1
54224_B_SG2
54224_B_SG3
54224_B_SG4
54224_G_EG1
54224_G_EG2
54224_G_EG3
54238_B_N64514
54238_B_N64516
54268_G_GTG1
54268_G_GTG2
54268_G_GTG3
54268_G_STG1
54271_G_CTG1
54271_G_CTG2
54271_G_STG
54304_B_1A
54321_B_3B101
54321_B_3B102
54321_B_3B103
54321_B_3B104
54321_B_3B105
54321_B_3B106
54321_B_3B107
54321_B_3B108
54321_G_2N80
54321_G_N802
54321_G_N803
54321_G_N804
54333_G_G001
54333_G_G502
54349_G_GTA
54349_G_GTB
54349_G_GTC
54349_G_STM
54350_G_GTA
54350_G_GTB
54350_G_GTC
54350_G_STM
54365_G_APC1
Coal Steam
0/G Steam
0/G Steam
0/G Steam
0/G Steam
1C Engine
1C Engine
1C Engine
Coal Steam
Coal Steam
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
0/G Steam
0/G Steam
0/G Steam
0/G Steam
0/G Steam
0/G Steam
0/G Steam
0/G Steam
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
MRO 2.8
MRO 1
MRO 1
MRO 4.1
MRO 4.1
MRO 2.0
MRO 2.0
MRO 2.0
CA-N 22.0
CA-N 22.0
PNW 39.6
PNW 40.0
PNW 40.6
PNW 26.0
SNV 35.0
SNV 35.0
SNV 22.0
VAPW 239
ENTG 1.6
ENTG 1.6
ENTG 1.6
ENTG 1.6
ENTG 1.6
ENTG 1.6
ENTG 1.6
ENTG 1.6
ENTG 4.0
ENTG 4.0
ENTG 4.0
ENTG 4.0
MACW 4.3
MACW 0.50
SNV 21.7
SNV 21.7
SNV 21.7
SNV 19.9
SNV 21.7
SNV 21.7
SNV 21.7
SNV 19.9
FRCC 46.4
10331
14789
14789
14789
14789
12334
12334
12334
11465
10331
11500
11500
11500
11500
9200
9200
9200
10067
11425
11425
11425
11425
11425
11425
11425
11425
12503
12503
12503
12503
7933
7933
7132
7132
7132
7132
10182
10182
10182
10182
8999
10320
8300
8300
8300
8300
12062
12062
12062
11465
10320
6096
6096
6096
6096
9200
9200
9200
9669
8300
8300
8300
8300
8300
8300
8300
8300
8700
8700
8700
8700
7942
7942
6600
6600
6600
6600
7316
7316
7316
7316
7380
1.00
1.72
1.72
1.72
1.72
1.00
1.00
1.00
1.00
1.00
1.82
1.82
1.82
1.82
1.00
1.00
1.00
1.04
1.35
1.35
1.35
1.35
1.35
1.35
1.35
1.35
1.43
1.43
1.43
1.43
1.00
1.00
1.36
1.36
1.36
1.36
1.22
1.22
1.22
1.22
1.16
85.26
89.51
89.51
89.51
89.51
89.24
89.24
89.24
69.73
69.73
58.62
58.62
58.62
58.62
84.63
84.63
84.63
65.54
92.41
92.41
92.41
92.41
92.41
92.41
92.41
92.41
89.24
89.24
89.24
89.24
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
84.63
40.15
23
-------
Orange Cogeneration Facility
Orange Cogeneration Facility
Oildale Cogen
University of Colorado
University of Colorado
University of Colorado
Southbridge Energy Center LLC
Southbridge Energy Center LLC
Southbridge Energy Center LLC
Southbridge Energy Center LLC
Southbridge Energy Center LLC
Capitol Heat and Power
Capitol Heat and Power
DAI Oildale
DAI Oildale
Lake Cogen Ltd
Lake Cogen Ltd
Lake Cogen Ltd
Pasco Cogen Ltd
Pasco Cogen Ltd
Pasco Cogen Ltd
Project Orange Associates LP
Project Orange Associates LP
Mulberry Cogeneration Facility
Mulberry Cogeneration Facility
Alabama Pine Pulp
Alabama Pine Pulp
Rincon Facility
Welport Lease Project
Dome Project
Dome Project
Orlando Cogen LP
Sumas Power Plant
Sumas Power Plant
Oroville Cogeneration LP
Oroville Cogeneration LP
Oroville Cogeneration LP
Oroville Cogeneration LP
Oroville Cogeneration LP
Oroville Cogeneration LP
Oroville Cogeneration LP
54365_G_APC2 Combined Cycle
54365_G_APC3 Combined Cycle
54371_G_ODC1 Combustion Turbine
54372_G_GT1 Combined Cycle
54372_G_GT2 Combined Cycle
54372_G_ST1 Combined Cycle
54373_G_ENG1 1C Engine
54373_G_ENG2 1C Engine
54373_G_ENG3 1C Engine
54373_G_ENG4 1C Engine
54373_G_ENG5 1C Engine
54406_G_1 Coal Steam
54406_G_2 Coal Steam
54410_G_CTG Combined Cycle
54410_G_STG Combined Cycle
54423_G_GT1 Combined Cycle
54423_G_GT2 Combined Cycle
54423_G_ST1 Combined Cycle
54424_G_GT1 Combined Cycle
54424_G_GT2 Combined Cycle
54424_G_ST1 Combined Cycle
54425_G_GT1 Combustion Turbine
54425_G_GT2 Combustion Turbine
54426_G_GT1 Combined Cycle
54426_G_ST1 Combined Cycle
54429_B_PB2 Biomass
54429_B_RB2 Non-Fossil Waste
54445_G_GEN1 Combustion Turbine
54447_G_TI Combustion Turbine
54449_G_T1 Combustion Turbine
54449_G_T2 Combustion Turbine
54466_G_GEN1 Combined Cycle
54476_G_GEN1 Combined Cycle
54476_G_GEN2 Combined Cycle
54477_G_GEN1 1C Engine
54477_G_GEN2 1C Engine
54477_G_GEN3 1C Engine
54477_G_GEN4 1C Engine
54477_G_GEN5 1C Engine
54477_G_GEN6 1C Engine
54477_G_GEN7 1C Engine
FRCC 46.4
FRCC 24.6
CA-N 39.0
RMPA 15.0
RMPA 15.0
RMPA 1
NENG 1.3
NENG 1.3
NENG 1.3
NENG 1.3
NENG 1.3
WUMS 0.90
WUMS 1
CA-N 22.6
CA-N 7.3
FRCC 41.5
FRCC 41.5
FRCC 27.0
FRCC 48.8
FRCC 48.8
FRCC 31.2
UPNY 48.0
UPNY 48.0
FRCC 76.0
FRCC 37.0
SOU 32.1
SOU 32.1
CA-S 1.7
CA-N 4.5
CA-N 3.3
CA-N 3.2
FRCC 120
PNW 87.8
PNW 37.7
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
CA-N 1.1
8999
8999
16463
7933
7933
7933
11600
11600
11600
11600
11600
10331
10331
7933
7933
7550
7550
7550
7701
7701
7701
12503
12503
8520
8520
15517
13102
12503
12503
15981
15981
9960
8120
8120
11600
11600
11600
11600
11600
11600
11600
7380
7380
8700
7164
7164
7164
9106
9106
9106
9106
9106
8300
8300
7942
7942
7447
7447
7447
7784
7784
7784
8700
8700
8104
8104
8300
8300
Retired
8882
8700
8700
7882
7262
7262
11185
11185
11185
11185
11185
11185
11185
1.16
1.16
1.89
1.11
1.11
1.11
1.23
1.23
1.23
1.23
1.23
1.24
1.24
1.00
1.00
1.14
1.14
1.14
1.06
1.06
1.06
1.43
1.43
1.02
1.02
1.89
1.54
1.40
1.82
1.82
1.26
1.14
1.14
1.00
1.00
1.00
1.00
1.00
1.00
1.00
40.15
40.15
89.87
15.00
15.00
15.00
89.24
89.24
89.24
89.24
89.24
85.26
85.26
84.63
84.63
49.56
49.56
49.56
43.15
43.15
43.15
89.87
89.87
41.67
41.67
83.00
55.17
0.00
89.24
89.24
89.24
84.63
20.82
20.82
89.24
89.24
89.24
89.24
89.24
89.24
89.24
24
-------
STEC-S LLC
Formosa Plastics
Formosa Plastics
Formosa Plastics
Formosa Plastics
Formosa Plastics
Lyonsdale Biomass LLC
Tenaska Ferndale Cogeneration Station
Tenaska Ferndale Cogeneration Station
Tenaska Ferndale Cogeneration Station
Entenmanns Energy Center
Entenmanns Energy Center
Entenmanns Energy Center
Entenmanns Energy Center
Sithe Independence Station
Sithe Independence Station
Sithe Independence Station
Sithe Independence Station
Sithe Independence Station
Sithe Independence Station
ExxonMobil Mobile Bay Onshore
ExxonMobil Mobile Bay Onshore
ExxonMobil Mobile Bay Onshore
ExxonMobil Mobile Bay Onshore
Jefferson Smurfit Santa Clara Mill
Jefferson Smurfit Santa Clara Mill
North East Cogeneration Plant
North East Cogeneration Plant
North East Cogeneration Plant
Saranac Facility
Saranac Facility
Saranac Facility
Glenns Ferry Cogen Facility
Rupert Cogen Project
Batavia Power Plant
Batavia Power Plant
Mt Poso Cogeneration
Okeelanta Cogeneration
Okeelanta Cogeneration
Okeelanta Cogeneration
Okeelanta Cogeneration
56079_B_South Biomass ENTG 2.0
54518_G_GT1 Combined Cycle ENTG 33.0
54518_G_GT2 Combined Cycle ENTG 33.0
54518_G_GT3 Combined Cycle ENTG 33.0
54518_G_ST1 Combined Cycle ENTG 8.0
54518_G_ST2 Combined Cycle ENTG 8.0
54526_B_00001 Biomass UPNY 19.0
54537_G_CT1A Combined Cycle PNW 88.0
54537_G_CT1B Combined Cycle PNW 88.0
54537_G_ST1 Combined Cycle PNW 95.0
54541_G_1 1C Engine LILC 1.3
54541_G_2 1C Engine LILC 1.3
54541_G_3 1C Engine LILC 1.3
54541_G_4 1C Engine LILC 1.3
54547_G_1 Combined Cycle UPNY 144
54547_G_2 Combined Cycle UPNY 144
54547_G_3 Combined Cycle UPNY 144
54547_G_4 Combined Cycle UPNY 144
54547_G_5 Combined Cycle UPNY 204
54547_G_6 Combined Cycle UPNY 204
54550_G_901 Combined Cycle SOU 0.90
54550_G_901A Combined Cycle SOU 3.4
54550_G_901B Combined Cycle SOU 3.4
54550_G_901C Combined Cycle SOU 3.4
54561_G_GT-G Combined Cycle CA-N 23.0
54561_G_ST-G Combined Cycle CA-N 3.0
54571_G_GEN1 Combined Cycle MACW 36.5
54571_G_GEN2 Combined Cycle MACW 36.5
54571_G_GEN3 Combined Cycle MACW 8.0
54574_G_GEN1 Combined Cycle UPNY 78.0
54574_G_GEN2 Combined Cycle UPNY 77.0
54574_G_GEN3 Combined Cycle UPNY 85.0
54578_G_1001 Combined Cycle PNW 10.4
54579_G_1002 Combined Cycle NWPE 10.4
54593_G_GEN1 Combined Cycle UPNY 38.2
54593_G_GEN2 Combined Cycle UPNY 17.5
54626_B_BL01 Coal Steam CA-N 52.0
54627_B_A Biomass FRCC 25.0
54627_B_B Biomass FRCC 25.0
54627_B_C Biomass FRCC 25.0
54627_G_GEN2 Biomass FRCC 74.9
15517
8648
8648
8648
8648
8648
15517
11260
11260
11260
12703
12703
12703
12784
7418
7418
7418
7418
7418
7418
7933
7933
7933
7933
9780
9780
9163
9163
9163
8616
8616
8616
9800
9800
8771
8771
11384
15517
15517
15517
15517
14500
Retired
8582
8582
8582
8582
13201
7576
7576
7576
8700
8700
8700
8700
6984
6984
6984
6984
6984
6984
7942
7942
7942
7942
5764
5764
6747
6747
6747
7399
7399
7399
8470
6324
7440
7440
11299
8904
8904
8904
8904
1.08
1.00
1.00
1.00
1.00
1.19
1.10
1.10
1.10
1.46
1.46
1.46
1.47
1.12
1.12
1.12
1.12
1.12
1.12
1.00
1.00
1.00
1.00
1.72
1.72
1.36
1.36
1.36
1.19
1.19
1.19
1.00
1.27
1.12
1.12
1.19
1.77
1.77
1.77
1.53
83.00
0.00
84.63
84.63
84.63
84.63
83.00
36.93
36.93
36.93
89.24
89.24
89.24
89.24
33.74
33.74
33.74
33.74
33.74
33.74
84.63
84.63
84.63
84.63
84.63
84.63
15.00
15.00
15.00
84.63
84.63
84.63
84.68
71.01
15.00
15.00
83.00
83.00
83.00
83.00
83.00
25
-------
St Nicholas Cogen Project
JCO Oxides Olefins Plant
JCO Oxides Olefins Plant
Lakewood Cogen LP
Lakewood Cogen LP
Lakewood Cogen LP
Auburndale Power Partners
Auburndale Power Partners
Oyster Creek Unit VIII
Oyster Creek Unit VIII
Oyster Creek Unit VIII
Oyster Creek Unit VIII
CM Carbon LLC
CM Carbon LLC
York Cogen Facility
York Cogen Facility
York Cogen Facility
York Cogen Facility
York Cogen Facility
York Cogen Facility
Yuma Cogeneration Associates
Yuma Cogeneration Associates
Hunterdon Cogen Facility
Montclair Cogen Facility
Port Neches Plant
Goal Line LP
Goal Line LP
Westmoreland Roanoke Valley II
Hermiston Generating Plant
Hermiston Generating Plant
Hermiston Generating Plant
Hermiston Generating Plant
Boydton Plank Road Cogen Plant
Live Oak Cogen
University of Iowa Main Power Plant
University of Iowa Main Power Plant
University of Iowa Main Power Plant
University of Iowa Main Power Plant
University of Iowa Main Power Plant
Grays Ferry Cogeneration
Grays Ferry Cogeneration
54634_B_1
54637_G_GCG1
54637_G_GCG2
54640_G_GEN1
54640_G_GEN2
54640_G_NA
54658_G_CT
54658_G_ST
54676_G_G81
54676_G_G82
54676_G_G83
54676_G_G84
54677_B_HRB
54677_G_TG-2
54693_G_GT#1
54693_G_GT#2
54693_G_GT#5
54693_G_GT#6
54693_G_ST#1
54693_G_ST#2
54694_G_GEN1
54694_G_GEN2
54707_G_1
54708_G_1
54748_G_G1
54749_G_CTG
54749_G_STG
54755_B_BLR2
54761_G_GEN1
54761_G_GEN2
54761_G_GEN3
54761_G_GEN4
54766_G_GEN1
54768_G_GEN1
54775_B_BLR10
54775_B_BLR11
54775_B_BLR7
54775_B_BLR8
54775_B_BLR9
54785_G_GEN1
54785_G_GEN2
Coal Steam
Combustion Turbine
Combustion Turbine
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Coal Steam
Coal Steam
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combined Cycle
Combined Cycle
Coal Steam
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Fossil Waste
Combustion Turbine
Coal Steam
Coal Steam
0/G Steam
0/G Steam
0/G Steam
Combined Cycle
Combined Cycle
MACW 87.9
ENTG 30.5
ENTG 30.5
MACE 78.0
MACE 78.0
MACE 83.0
FRCC 105
FRCC 49.6
ERCT 73.0
ERCT 73.0
ERCT 73.0
ERCT 160
ENTG 23.0
ENTG 23.0
MACW 6.9
MACW 6.6
MACW 6.9
MACW 6.1
MACW 7.2
MACW 6.9
AZNM 35.1
AZNM 17.1
MACE 4.1
MACE 3.7
ENTG 32.0
CA-S 40.0
CA-S 9.4
VAPW 44.0
PNW 80.0
PNW 152
PNW 80.0
PNW 152
VAPW 3.0
CA-N 46.0
MRO 4.2
MRO 4.2
MRO 4.2
MRO 4.2
MRO 4.2
MACE 50.0
MACE 100
10931
12503
12503
8129
8129
8129
8900
8900
10000
10000
10000
10000
10331
10331
9830
9830
9830
9830
9830
9830
8971
8971
12503
12503
12503
9182
9182
11346
11182
11182
11182
11182
11036
15065
12508
12508
14789
14789
14789
9033
9033
10931
8700
8700
8129
8129
8129
8302
8302
9662
9662
9662
9662
10320
10320
9830
9830
9830
9830
9830
9830
7604
7604
8700
8700
8700
7724
7724
9515
7322
7322
7322
7322
11036
8700
8300
8300
8300
8300
8300
5522
5522
1.00
1.43
1.43
1.00
1.00
1.00
1.06
1.06
1.02
1.02
1.02
1.02
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.14
1.14
1.43
1.43
1.43
1.02
1.02
1.19
1.00
1.00
1.00
1.00
1.00
1.73
1.49
1.49
1.72
1.72
1.72
1.64
1.64
95.00
89.87
89.87
84.63
84.63
84.63
48.82
48.82
69.15
69.15
69.15
69.15
85.26
85.26
84.63
84.63
84.63
84.63
84.63
84.63
80.86
80.86
89.24
89.24
89.87
74.62
74.62
91.60
84.68
84.68
84.68
84.68
90.00
89.87
85.26
85.26
92.41
92.41
92.41
36.96
36.96
26
-------
Plymouth State College Cogeneration
Milagro Cogeneration Plant
Milagro Cogeneration Plant
Milagro Cogeneration Plant
Milagro Cogeneration Plant
Johnson County
Johnson County
Panda Brandywine LP
Panda Brandywine LP
Panda Brandywine LP
Outagamie County Co-Generation Facility
Gordonsville Energy LP
Gordonsville Energy LP
Gordonsville Energy LP
Gordonsville Energy LP
Cox Waste to Energy
Cox Waste to Energy
Brooklyn Navy Yard Cogeneration
Brooklyn Navy Yard Cogeneration
Brooklyn Navy Yard Cogeneration
Brooklyn Navy Yard Cogeneration
Michigan Power LP
Michigan Power LP
Sauder Power Plant
Sauder Power Plant
Fellsway Development LLC
Fellsway Development LLC
Fellsway Development LLC
Fellsway Development LLC
SPSA Waste To Energy Power Plant
SPSA Waste To Energy Power Plant
SPSA Waste To Energy Power Plant
SPSA Waste To Energy Power Plant
LSP-Cottage Grove LP
LSP-Cottage Grove LP
LSP-WhitewaterLP
LSP-WhitewaterLP
Sweeny Cogen Facility
Sweeny Cogen Facility
Sweeny Cogen Facility
Sweeny Cogen Facility
54803_G_A 1C Engine
54814_G_GENA Combustion Turbine
54814_G_GENB Combustion Turbine
54814_G_G01A Combustion Turbine
54814_G_G01B Combustion Turbine
54817_G_GT-1 Combined Cycle
54817_G_ST-1 Fossil Waste
54832_G_1 Combined Cycle
54832_G_2 Combined Cycle
54832_G_3 Combined Cycle
54842_G_GEN1 Landfill Gas
54844_G_GOR1 Combined Cycle
54844_G_GOR2 Combined Cycle
54844_G_GOR3 Combined Cycle
54844_G_GOR4 Combined Cycle
54850_G_01 Biomass
54850_G_02 Biomass
54914_G_01 Combined Cycle
54914_G_02 Combined Cycle
54914_G_03 Combined Cycle
54914_G_04 Combined Cycle
54915_G_G001 Combined Cycle
54915_G_G101 Combined Cycle
54974_G_UNT1 Biomass
54974_G_UNT2 Biomass
54992_G_CAT1 1C Engine
54992_G_CAT2 1C Engine
54992_G_GT Combustion Turbine
54992_G_ST Coal Steam
54998_B_12300 Municipal Solid Waste
54998_B_12400 Municipal Solid Waste
54998_B_12500 Municipal Solid Waste
54998_B_12600 Municipal Solid Waste
55010_G_CTG1 Combined Cycle
55010_G_STG1 Combined Cycle
55011_G_CTG1 Combined Cycle
55011_G_STG1 Combined Cycle
55015_G_1 Combustion Turbine
55015_G_2 Combustion Turbine
55015_G_3 Combustion Turbine
55015 G 4 Combustion Turbine
NENG 1.2
AZNM 30.4
AZNM 30.4
AZNM 30.4
AZNM 30.4
ERCT 163
ERCT 104
MACS 78.6
MACS 78.6
MACS 72.8
WUMS 0.80
VAPW 71.4
VAPW 71.4
VAPW 40.6
VAPW 40.6
TVAK 3.0
TVAK 0.30
NYC 85.0
NYC 85.0
NYC 30.0
NYC 30.0
MECS 58.0
MECS 70.0
RFCO 3.6
RFCO 3.6
NENG 0.70
NENG 0.80
NENG 0.60
NENG 0.20
VAPW 11.6
VAPW 11.6
VAPW 11.6
VAPW 11.6
MRO 154
MRO 97.0
WUMS 156
WUMS 97.0
ERCT 115
ERCT 115
ERCT 115
ERCT 115
12334
16541
16541
16521
16541
7060
7859
8330
8330
8330
13682
8593
8593
8593
8593
15517
15517
7477
7477
7477
7477
10880
10880
18060
18060
13123
13123
15981
13754
19338
19338
19338
19338
7745
7745
7739
7739
11707
11707
11707
11707
9448
8700
8700
8700
8700
7859
7859
7612
7612
7612
9273
8706
8706
8706
8706
8300
8300
6759
6759
6759
6759
9334
9334
18060
18060
9704
9704
9704
10320
12524
12524
12524
12524
7278
7278
6654
6654
11707
11707
11707
11707
1.28
1.90
1.90
1.90
1.90
1.00
1.00
1.37
1.37
1.37
1.48
1.00
1.00
1.00
1.00
1.89
1.89
1.34
1.34
1.34
1.34
1.01
1.01
1.00
1.00
1.34
1.34
1.63
1.00
1.30
1.30
1.30
1.30
1.08
1.08
1.20
1.20
1.00
1.00
1.00
1.00
89.24
89.87
89.87
89.87
89.87
84.63
90.00
32.08
32.08
32.08
67.72
84.63
84.63
84.63
84.63
83.00
83.00
84.63
84.63
84.63
84.63
72.92
72.92
83.00
83.00
89.24
89.24
89.24
85.26
67.40
67.40
67.40
67.40
38.81
38.81
47.91
47.91
90.81
90.81
90.81
90.81
27
-------
J & L Electric
J & L Electric
Mid-Georgia Cogeneration Facility
Mid-Georgia Cogeneration Facility
Mid-Georgia Cogeneration Facility
Cherokee County Cogen
Cherokee County Cogen
Pasadena Cogeneration
Pasadena Cogeneration
Pasadena Cogeneration
Pasadena Cogeneration
Pasadena Cogeneration
Tamarack Energy Partnership
Georgia Gulf Plaquemine
Georgia Gulf Plaquemine
Georgia Gulf Plaquemine
Black Hawk Station
Black Hawk Station
Pine Bluff Energy Center
Pine Bluff Energy Center
Crockett Cogen Project
Gregory Power Facility
Gregory Power Facility
Gregory Power Facility
Dearborn Industrial Generation
Dearborn Industrial Generation
Dearborn Industrial Generation
Dearborn Industrial Generation
Taft Cogeneration Facility
Taft Cogeneration Facility
Taft Cogeneration Facility
Taft Cogeneration Facility
Plummer Forest Products
Miramar Landfill Metro Biosolids Center
Miramar Landfill Metro Biosolids Center
Miramar Landfill Metro Biosolids Center
Miramar Landfill Metro Biosolids Center
Portside Energy
Portside Energy
Klamath Cogeneration Plant
Klamath Cogeneration Plant
55034_G_0001 Biomass
55034_G_0002 Biomass
55040_G_CT1 Combined Cycle
55040_G_CT2 Combined Cycle
55040_G_ST1 Combined Cycle
55043_G_GT1 Combined Cycle
55043_G_ST1 Combined Cycle
55047_G_CTG1 Combined Cycle
55047_G_CTG2 Combined Cycle
55047_G_CTG3 Combined Cycle
55047_G_STG1 Combined Cycle
55047_G_STG2 Combined Cycle
50099_G_GEN1 Biomass
55051_G_X773 Combustion Turbine
55051_G_X774 Combustion Turbine
55051_G_X775 Combustion Turbine
55064_G_UNT1 Combustion Turbine
55064_G_UNT2 Combustion Turbine
55075_G_CT01 Combined Cycle
55075_G_ST01 Combined Cycle
55084_G_GE1 Combined Cycle
55086_G_GT1A Combined Cycle
55086_G_GT1B Combined Cycle
55086_G_STG Combined Cycle
55088_G_GT 1 Combined Cycle
55088_G_GT2 Combined Cycle
55088_G_GTP1 Combined Cycle
55088_G_ST1 Combined Cycle
55089_G_CT1 Combined Cycle
55089_G_CT2 Combined Cycle
55089_G_CT3 Combined Cycle
55089_G_ST1 Combined Cycle
55090_G_GEN1 Biomass
55094_G_UNT1 Landfill Gas
55094_G_UNT2 Landfill Gas
55094_G_UNT3 Landfill Gas
55094_G_UNT4 Landfill Gas
55096_G_GT Combined Cycle
55096_G_ST Combined Cycle
55103_G_CT1 Combined Cycle
55103_G_CT2 Combined Cycle
NENG 0.35
NENG 0.50
SOU 107
SOU 107
SOU 103
VACA 80.0
VACA 35.0
ERCT 155
ERCT 165
ERCT 165
ERCT 50.0
ERCT 165
PNW 5.8
ENTG 80.0
ENTG 80.0
ENTG 80.0
SPPS 111
SPPS 111
ENTG 150
ENTG 48.0
CA-N 247
ERCT 156
ERCT 156
ERCT 100
MECS 150
MECS 150
MECS 150
MECS 250
ENTG 155
ENTG 155
ENTG 155
ENTG 325
PNW 5.8
CA-S 1.6
CA-S 1.6
CA-S 1.6
CA-S 1.6
RFCO 34.0
RFCO 10.0
PNW 150
PNW 150
15517
15517
7950
7950
7950
8000
8000
7200
7200
7200
7200
7200
15943
12435
12435
12435
13188
13200
7274
7274
7500
7274
7274
7274
7274
7274
7274
7274
7933
7933
7933
7933
16912
11855
11855
11855
11855
6920
6920
6920
6920
15716
15716
6813
6813
6813
8663
8663
6723
6723
6723
6723
6723
14500
8700
8700
8700
8800
8800
5500
5500
5919
5500
5500
5500
5500
5500
5500
5500
7316
7316
7316
7316
10049
12899
12899
12899
12899
6920
6920
6794
6794
1.00
1.00
1.14
1.14
1.14
1.01
1.01
1.14
1.14
1.14
1.14
1.14
1.10
1.42
1.42
1.42
1.50
1.50
1.50
1.50
1.80
1.72
1.72
1.72
1.46
1.46
1.46
1.46
1.04
1.04
1.04
1.04
1.68
1.06
1.06
1.06
1.06
1.00
1.00
1.10
1.10
83.00
83.00
15.00
15.00
15.00
22.38
22.38
59.17
59.17
59.17
59.17
59.17
83.00
90.81
90.81
90.81
90.81
90.81
77.47
77.47
41.22
80.75
80.75
80.75
24.62
24.62
24.62
24.62
58.54
58.54
58.54
58.54
83.00
75.52
75.52
75.52
75.52
84.63
84.63
73.73
73.73
28
-------
Klamath Cogeneration Plant
Sabine Cogen
Sabine Cogen
Sabine Cogen
RS Cogen
RS Cogen
RS Cogen
SRW Cogen LP
SRW Cogen LP
SRW Cogen LP
NAFTA Region Olefins Complex Cogen Fac
NAFTA Region Olefins Complex Cogen Fac
Eastman Cogeneration Facility
Eastman Cogeneration Facility
Eastman Cogeneration Facility
Channelview
Channelview
Channelview
Channelview
Channelview
Corpus Christi Energy Center
Corpus Christi Energy Center
Corpus Christi Energy Center
Aera South Belridge Cogen Facility
Aera South Belridge Cogen Facility
Aera South Belridge Cogen Facility
Aera South Belridge Cogen Facility
Los Medanos Energy Center
Los Medanos Energy Center
Los Medanos Energy Center
Ina Road Water Pollution Control Fac
Ina Road Water Pollution Control Fac
Ina Road Water Pollution Control Fac
Ina Road Water Pollution Control Fac
Ina Road Water Pollution Control Fac
Ina Road Water Pollution Control Fac
Ina Road Water Pollution Control Fac
Whiting Clean Energy
Whiting Clean Energy
Whiting Clean Energy
Decatur Energy Center
55103_G_ST1 Combined Cycle
55104_G_SAB1 Combined Cycle
55104_G_SAB2 Combined Cycle
55104_G_STG Combined Cycle
55117_G_RS-4 Combined Cycle
55117_G_RS-5 Combined Cycle
55117_G_RS-6 Combined Cycle
55120_G_GT1A Combined Cycle
55120_G_GT1B Combined Cycle
55120_G_ST1A Combined Cycle
55122_G_UN1 Combustion Turbine
55122_G_UN2 Combustion Turbine
55176_G_GEN1 Combined Cycle
55176_G_GEN2 Combined Cycle
55176_G_GEN3 Combined Cycle
55187_G_CHV1 Combined Cycle
55187_G_CHV2 Combined Cycle
55187_G_CHV3 Combined Cycle
55187_G_CHV4 Combined Cycle
55187_G_ST1 Combined Cycle
55206_G_CT1 Combined Cycle
55206_G_CT2 Combined Cycle
55206_G_ST1 Combined Cycle
55216_G_STG1 Combined Cycle
55216_G_UNT1 Combined Cycle
55216_G_UNT2 Combined Cycle
55216_G_UNT3 Combined Cycle
55217_G_CTG1 Combined Cycle
55217_G_CTG2 Combined Cycle
55217_G_STG3 Combined Cycle
55257_G_1 1C Engine
55257_G_2 1C Engine
55257_G_3 1C Engine
55257_G_4 1C Engine
55257_G_5 1C Engine
55257_G_6 1C Engine
55257_G_7 1C Engine
55259_G_CT1 Combined Cycle
55259_G_CT2 Combined Cycle
55259_G_ST1 Combined Cycle
55292_G_CTG1 Combined Cycle
PNW 170
ENTG 37.0
ENTG 37.0
ENTG 27.0
ENTG 60.2
ENTG 168
ENTG 168
ENTG 160
ENTG 160
ENTG 100
ENTG 35.0
ENTG 35.0
SPPS 146
SPPS 146
SPPS 110
ERCT 161
ERCT 161
ERCT 161
ERCT 161
ERCT 135
162
162
159
COMD 62.0
COMD 38.0
COMD 38.0
COMD 38.0
CA-N 165
CA-N 165
CA-N 237
AZNM 0.59
AZNM 0.59
AZNM 0.59
AZNM 0.59
AZNM 0.59
AZNM 0.59
AZNM 0.59
RFCO 167
RFCO 167
RFCO 213
TVA 155
6920
7274
7274
7274
7933
7933
7933
7274
7274
7274
12503
12503
7274
7274
7274
10457
10457
10457
10457
10457
NotindB
NotindB
NotindB
10244
10244
10244
10244
6920
6920
6920
13298
13298
13298
13298
13298
13298
13298
7113
7113
7113
7274
6794
9201
9201
9201
7942
7942
7942
7751
7751
7751
9934
9934
6289
6289
6289
9909
9909
9909
9909
9909
7535
7535
7535
5896
5896
5896
5896
6656
6656
6656
8700
8700
8700
8700
8700
8700
8700
9051
9051
9051
9999
1.10
1.00
1.00
1.92
1.00
1.00
1.00
1.04
1.04
1.04
1.26
1.26
1.48
1.48
1.48
1.00
1.00
1.00
1.00
1.97
1.00
1.00
1.00
1.41
1.41
1.41
1.41
1.15
1.15
1.15
1.52
1.52
1.52
1.52
1.52
1.52
1.52
1.06
1.06
1.06
1.00
73.73
84.63
84.63
68.22
84.63
84.63
84.63
76.43
76.43
76.43
89.87
89.87
62.33
62.33
62.33
84.63
84.63
84.63
84.63
76.78
84.63
84.63
84.63
33.26
33.26
33.26
33.26
70.00
70.00
70.00
89.24
89.24
89.24
89.24
89.24
89.24
89.24
26.24
26.24
26.24
84.68
29
-------
Decatur Energy Center
Decatur Energy Center
Decatur Energy Center
Morgan Energy Center
Morgan Energy Center
Morgan Energy Center
Morgan Energy Center
Channel Energy Center
Channel Energy Center
Channel Energy Center
Calvert City
Air Products Port Arthur
Air Products Port Arthur
Ingleside Cogeneration
Ingleside Cogeneration
Ingleside Cogeneration
Chuck Lenzie Generating Station
Chuck Lenzie Generating Station
Chuck Lenzie Generating Station
Baytown Energy Center
Baytown Energy Center
Baytown Energy Center
Baytown Energy Center
Columbia Energy Center
Columbia Energy Center
Columbia Energy Center
Carville Energy LLC
Carville Energy LLC
Carville Energy LLC
Plaquemine Cogeneration Plant
Plaquemine Cogeneration Plant
Plaquemine Cogeneration Plant
Plaquemine Cogeneration Plant
Plaquemine Cogeneration Plant
Deer Park Energy Center
Deer Park Energy Center
Deer Park Energy Center
Deer Park Energy Center
Deer Park Energy Center
Green Power 2
Green Power 2
55292_G_CTG2 Combined Cycle
55292_G_CTG3 Combined Cycle
55292_G_STG1 Combined Cycle
55293_G_CTG1 Combined Cycle
55293_G_CTG2 Combined Cycle
55293_G_CTG3 Combined Cycle
55293_G_STG1 Combined Cycle
55299_G_CTG1 Combined Cycle
55299_G_CTG2 Combined Cycle
55299_G_ST-1 Combined Cycle
55308_G_GEN1 Combustion Turbine
55309_G_GEN1 Combined Cycle
55309_G_GEN2 Combined Cycle
55313_G_CTG1 Combined Cycle
55313_G_CTG2 Combined Cycle
55313_G_STG Combined Cycle
55322_G_CTG1 Combined Cycle
55322_G_CTG2 Combined Cycle
55322_G_ST1 Combined Cycle
55327_G_CTG1 Combined Cycle
55327_G_CTG2 Combined Cycle
55327_G_CTG3 Combined Cycle
55327_G_STG1 Combined Cycle
55386_G_CT1 Combined Cycle
55386_G_CT2 Combined Cycle
55386_G_ST1 Combined Cycle
55404_G_CTG1 Combined Cycle
55404_G_CTG2 Combined Cycle
55404_G_STG Combined Cycle
55419_G_G500 Combined Cycle
55419_G_G600 Combined Cycle
55419_G_G700 Combined Cycle
55419_G_G800 Combined Cycle
55419_G_ST5 Combined Cycle
55464_G_CTG1 Combined Cycle
55464_G_CTG2 Combined Cycle
55464_G_CTG3 Combined Cycle
55464_G_CTG4 Combined Cycle
55464_G_STG1 Combined Cycle
55470_G_ST1 Combined Cycle
55470_G_TR1 Combined Cycle
TVA 155
TVA 155
TVA 159
TVA 161
TVA 161
TVA 161
TVA 266
ERCT 185
ERCT 185
ERCT 215
TVA 23.0
ENTG 33.2
ENTG 3.0
ERCT 155
ERCT 155
ERCT 150
SNV 134
SNV 168
SNV 184
ERCT 170
ERCT 170
ERCT 170
ERCT 275
157
157
151
ENTG 180
ENTG 180
ENTG 140
ENTG 169
ENTG 169
ENTG 169
ENTG 169
ENTG 168
ERCT 155
ERCT 155
ERCT 155
ERCT 155
ERCT 258
ERCT 110
ERCT 158
7274
7274
7274
7355
7355
7355
7355
7200
7200
7200
12503
7274
7274
7933
7933
7933
7031
7031
7031
7274
7274
7274
7274
NotindB
NotindB
NotindB
7274
7274
7274
7274
7274
7274
7274
7274
7274
7274
7274
7274
7274
7933
7933
9999
9999
9999
7421
7421
7421
7421
6016
6016
6016
8700
10719
10719
8479
8479
8479
7735
7735
7735
7484
7484
7484
7484
6407
6407
6407
5966
5966
5966
6394
6394
6394
6394
6394
5712
5712
5712
5712
5712
5500
5500
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.34
1.34
1.34
1.43
1.00
1.00
1.07
1.07
1.07
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.73
1.73
1.73
1.36
1.36
1.36
1.11
1.11
1.11
1.11
1.11
1.75
1.75
1.75
1.75
1.75
1.44
1.44
84.68
84.68
84.68
84.68
84.68
84.68
84.68
40.92
40.92
40.92
89.88
84.63
84.63
57.25
57.25
57.25
84.63
84.63
84.63
84.63
84.63
84.63
84.63
15.00
15.00
15.00
56.35
56.35
56.35
51.42
51.42
51.42
51.42
51.42
76.57
76.57
76.57
76.57
76.57
73.01
73.01
30
-------
Green Power 2
Green Power 2
Blackburn Landfill Co-Generation
Blackburn Landfill Co-Generation
Blackburn Landfill Co-Generation
Wilmington Hydrogen Plant
Combined Locks Energy Center
Combined Locks Energy Center
Binghamton Cogen
Mingo Junction Energy Center
Mingo Junction Energy Center
Mingo Junction Energy Center
Mingo Junction Energy Center
FPL Energy Marcus Hook LP
FPL Energy Marcus Hook LP
FPL Energy Marcus Hook LP
FPL Energy Marcus Hook LP
Desert Power LP
Co-Gen LLC
Ashtabula
Ashtabula
Ashtabula
Ashtabula
Ashtabula
Ashtabula
Ashtabula
Trigen Revere
Trigen Revere
WWTP Power Generation Station
WWTP Power Generation Station
WWTP Power Generation Station
Fox Valley Energy Center
UMCPCHP Plant
UMCPCHP Plant
UMCPCHP Plant
Millennium Hawkins Point
Millennium Hawkins Point
Millennium Hawkins Point
Millennium Hawkins Point
Millennium Hawkins Point
Millennium Hawkins Point
55470_G_TR2 Combined Cycle
55470_G_TR3 Combined Cycle
55488_G_BB1 Landfill Gas
55488_G_BB2 Landfill Gas
55488_G_BB3 Landfill Gas
55557_G_T101 0/G Steam
55558_G_GEN1 Combined Cycle
55558_G_GEN2 Combined Cycle
55600_G_1 Combustion Turbine
55611_B_BOIL1 0/G Steam
55611_B_BOIL2 0/G Steam
55611_B_BOIL3 0/G Steam
55611_B_BOIL4 0/G Steam
55801_G_CT13 Combined Cycle
55801_G_CT1A Combined Cycle
55801_G_CTIB Combined Cycle
55801_G_STG Combined Cycle
55858_G_GEN7 Coal Steam
50921_G_GEN1 Biomass
55990_G_1 Combined Cycle
55990_G_2 Combined Cycle
55990_G_3 Combined Cycle
55990_G_4 Combined Cycle
55990_G_5 Combined Cycle
55990_G_6 Combined Cycle
55990_G_7 Combined Cycle
55999_G_GEN1 1C Engine
55999_G_GEN2 1C Engine
56036_G_GEN1 Non-Fossil Waste
56036_G_GEN2 Non-Fossil Waste
56036_G_GEN3 Non-Fossil Waste
56037_G_1 Coal Steam
56038_G_1 Combined Cycle
56038_G_2 Combined Cycle
56038_G_3 Combined Cycle
56045_G_1A Combined Cycle
56045_G_1B Combined Cycle
56045_G_2A Combined Cycle
56045_G_2B Combined Cycle
56045_G_3A Combined Cycle
56045_G_3B Combined Cycle
ERCT 158
ERCT 158
VACA 1
VACA 1
VACA 0.90
CA-S 23.0
WUMS 40.8
WUMS 4.3
UPNY 42.0
RFCO 7.5
RFCO 7.5
RFCO 7.5
RFCO 7.5
MACE 162
MACE 162
MACE 160
MACE 234
NWPE 40.0
PNW 7.0
RFCO 4.4
RFCO 4.4
RFCO 4.4
RFCO 4.4
RFCO 4.4
RFCO 0.69
RFCO 0.69
NENG 2.8
NENG 2.8
CA-N 2.0
CA-N 2.0
CA-N 2.0
WUMS 6.5
MACS 9.4
MACS 9.4
MACS 2.0
MACS 1.1
MACS 1.1
MACS 1.1
MACS 1.1
MACS 1.1
MACS 1.1
7933
7933
12328
12328
12328
11425
7933
7933
10894
11425
11425
11425
11425
7274
7274
7274
7274
9650
17974
7274
7274
7274
7274
7274
7274
7274
10850
10850
14653
14653
14653
10331
7933
7933
7933
7933
7933
7933
7933
7933
7933
5500
5500
8700
8700
8700
9854
6221
6221
9358
8300
8300
8300
8300
7274
7274
7274
7274
Retired
8566
7083
7083
7083
7083
7083
7083
7083
9732
9732
14653
14653
14653
8300
6534
6534
6534
13490
13490
13490
13490
13490
13490
1.44
1.44
1.57
1.57
1.57
1.13
1.28
1.28
1.16
1.35
1.35
1.35
1.35
1.00
1.00
1.00
1.00
2.10
1.03
1.03
1.03
1.03
1.03
1.03
1.03
1.11
1.11
1.00
1.00
1.00
1.24
1.80
1.80
1.80
1.09
1.09
1.09
1.09
1.09
1.09
73.01
73.01
67.05
67.05
67.05
92.45
18.89
18.89
89.87
92.41
92.41
92.41
92.41
84.63
84.63
84.63
84.63
0.00
83.00
73.53
73.53
73.53
73.53
73.53
73.53
73.53
89.24
89.24
90.00
90.00
90.00
85.26
84.63
84.63
84.63
37.14
37.14
37.14
37.14
37.14
37.14
31
-------
Millennium Hawkins Point
Co-Gen II LLC
Sierra Pacific Aberdeen
Middlesex Generating Facility
Middlesex Generating Facility
Middlesex Generating Facility
SP Newsprint- Newberg Cogen
SP Newsprint- Newberg Cogen
SP Newsprint- Newberg Cogen
Macon Energy Center
Groveton Paper Board
Groveton Paper Board
Freeport Energy Center
Freeport Energy Center
Freehold Asbury Park Press
Freehold Asbury Park Press
Cogeneration 1
Perham Incinerator
Shell Chemical
Shell Chemical
Trigen St.Louis
Trigen St.Louis
Trigen St.Louis
Trigen St.Louis
Trigen St.Louis
Clearwater Power Plant
Clearwater Power Plant
Domain Plant
Robert Mueller Energy Center
Sierra Pacific Burlington Facility
Tesoro SLC Cogeneration Plant
Tesoro SLC Cogeneration Plant
Edge Moor
Edge Moor
Sherburne County
Sherburne County
Big Stone
Warrick
Warrick
Warrick
Warrick
56045_G_ST1
50993_G_GEN1
55882_B_BLR1
56119_G_100
56119_G_200
56119_G_300
56124_B_10BLR
56124_G_GT1
56124_G_GT2
56127_G_1
56140_G_TUR1
56140_G_TUR2
56152_G_CTG1
56152_G_STG1
56169_G_UNT1
56169_G_UNT2
56229_G_CT1
56243_G_1
56248_G_101G
56248_G_201G
56309_G_CT-1
56309_G_CT-2
56309_G_ST-3
56309_G_ST-4
56309_G_ST-5
56356_G_CT1
56356_G_ST1
56373_G_DOMG1
56374_G_CT1
56406_G_GEN1
56509_G_1
56509_G_2
593_B_3
593_B_4
6090_B_1
6090_B_2
6098_B_1
6705_B_1
6705_B_2
6705_B_3
6705 B 4
Combined Cycle
Biomass
Biomass
Non-Fossil Waste
Non-Fossil Waste
Non-Fossil Waste
0/G Steam
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combined Cycle
Combined Cycle
1C Engine
1C Engine
Combined Cycle
Municipal Solid Waste
Combustion Turbine
Combustion Turbine
Combined Cycle
Combined Cycle
0/G Steam
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combustion Turbine
Combustion Turbine
Biomass
Combustion Turbine
Combustion Turbine
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
Coal Steam
MACS 0.50
PNW 7.0
PNW 16.5
4.10
4.10
10.6
PNW 22.3
PNW 41.6
PNW 41.6
GWAY 9.1
NENG 4.0
NENG 4.0
180
80.0
MACE 1.1
MACE 1.1
AZNM 8.3
MRO 1.2
ENTG 32.0
ENTG 32.0
GWAY 4.0
GWAY 4.2
GWAY 18.0
GWAY 0.77
GWAY 0.81
CA-S 21.0
CA-S 7.0
ERCT 5.0
ERCT 3.7
PNW 25.0
NWPE 11.0
NWPE 11.0
MACE 86.0
MACE 174
MRO 762
MRO 752
MRO 470
RFCO 136
RFCO 136
RFCO 136
RFCO 300
7933
17139
15517
NotindB
NotindB
NotindB
11332
12503
12503
13301
12678
12678
NotindB
NotindB
11797
11797
7933
19338
12503
12503
11985
11985
11425
11985
11985
9100
9100
11862
12503
15517
12503
12503
13668
9569
10611
10452
11609
10986
11017
11056
10418
13490
10285
8300
7274
7274
7274
11511
Retired
Retired
13301
12477
12477
7942
7942
10000
10000
7942
16297
10994
10994
5583
5583
11177
5583
5583
9368
9368
11862
9960
12695
8700
8700
12721
9569
10611
10452
11609
10986
11002
11002
10418
1.09
1.67
1.89
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.18
1.18
1.00
1.00
1.13
1.13
2.15
2.15
1.00
2.15
2.15
1.00
1.00
1.00
1.00
1.24
1.44
1.44
1.07
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
37.14
83.00
83.00
90.00
90.00
90.00
92.41
0.00
0.00
89.24
89.24
89.24
84.63
84.63
89.24
89.24
84.63
90.00
89.87
89.87
52.35
52.35
92.45
52.35
52.35
84.63
84.63
89.24
89.24
83.00
89.24
89.24
41.53
41.53
68.27
68.27
79.70
73.94
73.94
73.94
73.93
32
-------
Gadsden
Gadsden
Whitehead
Whitehead
Whitehead
Whitehead
Whitehead
Whitehead
Whitehead
Brandon Station
Richard Gorsuch
Richard Gorsuch
Richard Gorsuch
Richard Gorsuch
George Neal South
University of Florida
Coyote Springs
Coyote Springs
Indian Trails Cogen 1
Indian Trails Cogen 1
Indian Trails Cogen 1
Carson Ice-Gen Project
Carson Ice-Gen Project
Milwaukee County
Milwaukee County
Milwaukee County
SCA Cogen 2
SCA Cogen 2
SCA Cogen 2
SCA Cogen 2
SPA Cogen 3
SPA Cogen 3
Everett Cogen
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)
Washington County Cogeneration Facility
Washington County Cogeneration Facility
General Electric Plastic
General Electric Plastic
7_B_1 Coal Steam SOU 64.0 1 12376
7_B_2 Coal Steam SOU 66.0 12846
7028_G_K1 1C Engine NWPE 5.9 14151
7028_G_K2 1C Engine NWPE 6.0
7028_G_K3 1C Engine NWPE 5.9
7028_G_K4 1C Engine NWPE 4.0
7028_G_K5 1C Engine NWPE 2.0
7028_G_K6 1C Engine NWPE 2.1
7028_G_K7 1C Engine NWPE 2.1
7131_G_1 Combustion Turbine SPPS 20.0
7286_B_1 Coal Steam RFCO 50.0
7286_B_2 Coal Steam RFCO 50.0
7286_B_3 Coal Steam RFCO 50.0
7286_B_4 Coal Steam RFCO 50.0
7343_B_4 Coal Steam MRO 632
7345_G_P1 Combustion Turbine FRCC 45.0
7350_G_1 Combined Cycle PNW 142
7350_G_2 Combined Cycle PNW 71.3
7384_B_1 0/G Steam GWAY 3.3
7384_B_2 0/G Steam GWAY 3.3
7384_B_3 0/G Steam GWAY 3.3
7527_G_1 Combined Cycle CA-N 41.2
7527_G_2 Combined Cycle CA-N 16.6
7549_B_1 Coal Steam WUMS 3.3
7549_B_2 Coal Steam WUMS 3.3
7549_B_3 Coal Steam WUMS 3.3
7551_G_CCST Combined Cycle CA-N 37.6
7551_G_CT1A Combined Cycle CA-N 39.6
7551_G_CT1B Combined Cycle CA-N 39.6
7551_G_CT1C Combined Cycle 45.7
7552_G_CCCT Combined Cycle CA-N 111
7552_G_CCST Combined Cycle CA-N 53.0
7627_B_14 Biomass PNW 36.0
7652_B_D-1 Coal Steam 19.6
7652_B_D-2 Coal Steam 19.6
7652_B_D-3 Coal Steam 19.6
10069
10069
10069
10746
10746
10746
12503
11084
11084
11071
11071
10470
9249
7337
7337
11425
11425
11425
11860
11860
11704
10331
10331
11094
11094
11094
Not in dB
8394
8394
15517
NotindB
NotindB
NotindB
7652_B_D-4 Coal Steam 19.6 iNotindB
7697_G_1 Combined Cycle SOU 80.0 7274
7697_G_2 Combined Cycle SOU 22.0 7274
7698_G_1 Combined Cycle SOU 85.0
7698 G 2 Combined Cycle SOU 12.0
7274
7274
12376
12846
14151
10069
10069
10069
10746
10746
10746
12503
11084
11084
11071
11071
10470
9249
7598
7598
11177
11177
11177
8327
8327
11704
10320
10320
8469
8469
8469
8469
8137
8137
11844
10320
10320
10320
10320
9026
9026
11972
11972
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.33
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
50.27
50.27
89.24
89.24
89.24
89.24
89.24
89.24
89.24
89.87
60.67
60.67
60.67
60.67
80.10
89.87
84.68
84.68
92.41
92.41
92.41
84.63
84.63
71.80
71.80
71.80
84.63
84.63
84.63
84.63
84.63
84.63
83.00
31.67
31.67
31.67
31.67
84.63
84.63
84.63
84.63
33
-------
Fairless Hills 7701_B_4 Landfill Gas MACE 30.0
Fairless Hills 7701_B_5 Landfill Gas MACE 30.0
Pea Ridge 7715_G_1 Combustion Turbine SOU 4.0
Pea Ridge 7715_G_2 Combustion Turbine SOU 4.0
Pea Ridge 7715_G_3 Combustion Turbine SOU 4.0
Theodore Cogen Facility 7721_G_1 Combined Cycle SOU 152
Theodore Cogen Facility 7721_G_2 Combined Cycle SOU 36.0
Cogen South 7737_B_B001 Coal Steam VACA 90.0
Encogen 7870_G_CTG1 Combined Cycle PNW 39.4
Encogen 7870_G_CTG2 Combined Cycle PNW 39.4
Encogen 7870_G_CTG3 Combined Cycle PNW 39.4
Encogen 7870_G_STG Combined Cycle PNW 51.8
West Campus Cogeneration Facility 7991_G_1 Combined Cycle WUMS 38.0
West Campus Cogeneration Facility 7991_G_CT2 Combined Cycle WUMS 37.2
West Campus Cogeneration Facility 7991_G_STG1 Combined Cycle WUMS 55.0
Ware Cogeneration 81542_G_1 Biomass NENG 4.1
Kimberly Clark 82800_G_CC1 Combined Cycle NENG 17.5
Kimberly Clark 82800_G_GT1 Combustion Turbine NENG 17.5
Great River Energy Spiritwood Station 82821_B_1 Coal Steam MRO 99.0
SPPN_KS_Coal steam 82932_C_1 Coal Steam SPPN 22.0
Cabot Holyoke 9864_B_5 0/G Steam 5.80
Cabot Holyoke 9864_B_6 0/G Steam 5.80
Cabot Holyoke 9864_B_7 0/G Steam 5.80
Cabot Holyoke 9864_B_8 0/G Steam 5.80
13682
13682
14111
11210
11210
7274
7274
10966
11200
11200
11200
11200
11985
11985
11985
15517
7031
10664
8763
10820
Not in dB
Not in dB
Not in dB
Not in dB
12789
12789
14111
11210
11210
7065
7065
10966
9118
9118
9118
9118
8367
8367
8367
15716
7942
12477
8937
8937
14500
14500
10817
14500
1.07
1.07
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
47.11
47.11
89.24
89.24
89.24
84.63
84.63
70.87
84.68
84.68
84.68
84.68
84.63
84.63
84.63
83.00
84.63
89.24
85.26
85.26
89.51
89.51
89.51
89.51
34
-------
2 NOX Rates
2.1 Response to the Comments Received
Comment Theme: There were a substantial number of comments indicating that the NOX rates shown in
NEEDS2 were too low and not achievable.
Discussion: Based on these comments, the decision rules used to derive the NEEDS NOX rates were
reviewed and an out-of-date assumption was found to be causing instances of low NOX rates. Specifically,
the out-of-date decision rule (which was developed at a time when units were subject, at most, to summer
season, not annual, NOX rate limits) designated the winter NOX rate as the uncontrolled NOX rate.
Applying percent reductions attributable to NOX post-combustion controls to the winter NOX rates resulted
in unrealistically low controlled NOX rates for units that in reality operated NOX controls in the winter.
Response: The previous decision rules were replaced by a more robust procedure for identifying
uncontrolled NOX rates. In addition, a thorough review was made of all the decision rules affecting NOX
rates and, where appropriate, revisions were made. The revised decision rules are shown in the
documentation supplement which follows.
In addition, as announced in the Federal Register Notice of Data Availability for the Proposed Transport
Rule (FR, vol. 75, no.169, September 1, 2010, 53614-53615) the NOX rates for fossil-fuel fired units in the
final rule are based on 2009 data rather than 2007 NOX data used in the modeling for the proposed
Transport Rule. Reported to EPA by generating units covered under Title IV of the Clean Air Act
Amendments of 1990 (Acid Rain Program) and NOX Budget Program, the updated NOX rates more
accurately reflect the unit level control installations that have occurred at power plants during the past
several years.
2.1 Resulting Updates
The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model
show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case
v4.10_FTransport.
In the documentation for EPA Base Case v.4.10_NODA, \he following replaces the response to question
Q4 that had previously appeared in Appendix 3-1 in the NOD A documentation.
2 The National Electrical Energy Data System (NEEDS) is a database which provides EPA's model of the
electric power sector with information on all currently operating and planned-committed electric
generating units. An updated version of NEEDS (v.4.10) was part of the September 1, 2010 Notice of
Data Availability for the Proposed Transport Rule.
35
-------
NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport
Q4: How are the values of the Mode 1-4 NOx rates derived?
A4: The revised draft of the methodology to develop NOX rates for coal steam boilers in EPA Base Case
v.4.10_FTransport is summarized below.
The procedure employs the following hierarchy of NOX rate data sources:
1. 2009 ETS
2. EPA 410 NODA Comments
3. 2007 ETS
4. 2005 EIA Form 767
5. Defaults
The existing coal steam boilers in US are categorized into three groups depending on the configuration of
NOX combustion and post-combustion controls
Group 1 - Coal boilers without post combustion NCX controls
Mode 1 = 2009 ETS Annual Average NOX Rate
Mode 2 = Mode 1
Mode 3
For coal boilers located in a SIP call NOX, CAIR ozone/annual NOX or any NOX regulated state,
Mode 3 = Mode 1
For coal boilers that are not located in a SIP call NOX, CAIR ozone/annual NOX or any NOX regulated state,
follow Steps 1-7
Step 1: Pre-screen units that already have state of art (SOA) combustion controls from units that have non-
SOA combustion controls from units that have no combustion controls
Step 2: For units listed as not having combustion controls
Make sure their NOX rates do not indicate that they really do have SOA control
If Mode 1 > Cut-off (in Table 3-1.2), then Mode 1 = Base NOX rate. Go to Step 6
If Mode 1 < Cut-off (in Table 3-1.2), then the unit has SOA control and
Mode 3 = Mode 1
Step 3: For units listed as having SOA combustion controls.
Mode 3 = Mode 1.
Step 4: For units listed as not having SOA combustion controls
Make sure their NOX rates do not indicate that they really do have SOA control
If Mode 1 < Cut-off (in Table 3-1.2), then the unit has SOA control and
Mode 3 = Mode 1
If Mode 1 > Cut-off (in Table 3-1.2), then go to Step 5
Step 5: Determine the unit's Base NOX rate, i.e., the unit's uncontrolled emission rate without combustion
controls, using the appropriate equation (not in boldface italics) in Table 3-1.3 to back calculate their
Base NOX rate. Use the default Base NOX rate values if back calculations can't be performed. Once
the Base NOX rate is obtained, go to Step 6.
Step 6: Use the appropriate equations (in boldface italics) in Table 3-1.3 to calculate the NOX rate with SOA
combustion controls.
Step 7: Compare the value calculated in Step 6 to the applicable NOX floor rate in Table 3-1.2.
If the value from Step 6 is > floor, use the Step 6 value as Mode 3. Otherwise, use the floor as the
Mode 3 NOX rate.
Mode 4
Mode 4 = Mode 3
36
-------
NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont'd)
Group 2 - Coal boilers with Dispatchable/Non-Dispatchable SCR
Pre-screen coal boilers with 2009 ETS NOX rates into the following four operating regimes. A
coal boiler is assumed to be operating its SCR when the seasonal NOX rate is less than 0.2
Ibs/MMBtu
Group 2a. Coal boilers with Non-Dispatchable SCR
Group 2a.1 SCR is not operating in both summer and winter seasons
Follow the NOX rate rules summarized for Group 1 boilers. No state of the art
combustion controls are implemented.
Mode 1 = 2009 ETS Annual Average NOX Rate
Mode 2 = maximum {(1-0.9) * Mode 1, 0.07}
Mode 3 = Mode 1
Mode 4 = Mode 2
Group 2a.2 SCR is operating in summer only
Mode 1 = 2009 ETS Winter NOX Rate
Mode 2 = 2009 ETS Summer NOX Rate
Mode 3 = Mode 1
Mode 4 = Mode 2
Group 2a.3 SCR is operating in winter only
Mode 1 = 2009 ETS Summer NOX Rate
Mode 2 = 2009 ETS Winter NOX Rate
Mode 3 = Mode 1
Mode 4 = Mode 2
Group 2a.4 SCR is operating year-round
Mode 1 = if (2007 ETS Winter NOX Rate > 0.2, 2007 ETS Winter NOX Rate, 2009 ETS
Annual Average NOX Rate)
Mode 2 = 2009 ETS Annual Average NOX Rate
Mode 3 = Mode 1
Mode 4 = Mode 2
Group 2b. Coal boilers with Dispatchable SCR
Group 2b.1 SCR is not operating in both summer and winter seasons
Follow the NOX rate rules summarized for Group2a.1 boilers.
Group 2b.2 SCR is operating in summer only
Mode 1 = 2009 ETS Winter NOX Rate
Mode 2 = Mode 1
Mode 3 = Mode 1
Mode 4 = Mode 2
Group 2b.3 SCR is operating in winter only
Mode 1 = 2009 ETS Summer NOX Rate
Mode 2 = Mode 1
Mode 3 = Mode 1
Mode 4 = Mode 2
Group 2b.4 SCR is operating year-round
Mode 1 = if (2007 ETS Winter NOX Rate > 0.2, 2007 ETS Winter NOX Rate, 2009 ETS
Annual Average NOX Rate)
Mode 2 = Mode 1
Mode 3 = Mode 1
Mode 4 = Mode 2
37
-------
NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont'd)
Group 3 - Coal boilers with SNCR
Step 1: Pre-screen coal boilers with 2009 ETS NOX rates to verify if they have not operated their
SNCR in both summer and winter seasons. A coal boiler is assumed to be not operating its SNCR
when the NOX rate is greater than 0.3 Ibs/MMBtu in both summer and winter seasons.
Group 3.1 SNCR is not operating in both summer and winter seasons
Follow the NOX rate rules summarized for Group 1 boilers
Step 2: Pre-screen coal boilers with 2009 ETS NOX rates into the following three operating regimes.
First estimate the implied removal for a coal boiler using the following equation:
Implied Removal (%) = ((Winter NOX Rate - Summer NOX Rate)/ Winter NOX Rate) * 100
Second, assign the coal boiler to a specific operating regime based on the following logic.
If Implied Removal > 20% then SNCR is operating in summer season only,
Else if Implied Removal < -20% then SNCR is operating in winter season only,
Else SNCR is operating year-round
Group 3.2 SNCR is operating in summer only
Mode 1 = 2009 ETS Winter NOX Rate
Mode 2= 2009 ETS Summer NOX Rate
Mode 3 = same as Group 1 Mode 3
Mode 4 = maximum {(1-0.25) * Mode 3, 0.1} for non FBC units
Mode 4 = maximum {(1-0.50) * Mode 3, 0.08} for FBC units
Note: The (1-.25) and (1-0.5) terms in the equations above represents the NOX removal
efficiencies of SNCR for non FBC and FBC boilers.
Group 3.3 SNCR is operating in winter only
Mode 1 = 2009 ETS Summer NOX Rate
Mode 2 = 2009 ETS Winter NOX Rate
Mode 3 = same as Group 3.2 Mode 3
Mode 4 = same as Group 3.2 Mode 4
Group 3.4 SNCR is operating year-round
Mode 1 = if (2007 ETS Winter NOX Rate > 0.3, 2007 ETS Winter NOX Rate, 2009 ETS Annual
Average NOX Rate)
Mode 2 = 2009 ETS Annual Average NOX Rate
Mode 3 = same as Group 3.2 Mode 3
Mode 4 = Mode 3
38
-------
Table 3-1.1 Examples of Base and Policy NOX Rates Occurring in EPA Base Case v.4.10_FTransport
Plant Name
Unique ID
Post-
Corn busti
on
Control
edNOx
Racp Ratp
Control!
edNOx
Base
Rate
Uncontroll
edNOx
Policy
Rate
Control!
edNOx
Policy
Rate
Explanation
Situation 1: For generating units that do not have post-combustion controls, the controlled and uncontrolled rates will be the same.
Four
Corners
2442_B_1
None
0.786
0.786
0.509
0.509
Situation 4 also applies, i.e., unit had LNB and
now added OFA so see drop in policy rates.
Situation 2: For generating units that do have post-combustion controls, the controlled and uncontrolled rates will differ.
Big Sandy
1353 B BS
U2
SCR
0.629
0.146
0.629
0.146
(1) Has SCR so see difference between
uncontrolled and controlled rates
(2) Situation 3b also applies.
Situation 3a: Base and Policy NOX rates will be same if the unit has state-of-the-art NOX combustion controls or...
Greene
County
Chalk Point
LLC
10_B_2
1571_B_1
None
SCR
0.363
0.485
0.363
0.156
0.363
0.485
0.363
0.156
Situation 1 also applies.
Situation 2 also applies.
Situation 3b:... is in the NOX Regulated Region where current combustion controls are assumed to be retained.
Thomas Hill
Waukegan
2168 B MB
3
883_B_17
SCR
None
0.221
0.336
0.102
0.336
0.221
0.336
0.102
0.336
Situation 2 also applies.
(1) Has NOX combustion control and is in SIP so
doesn't get added combustion control.
(2) Situation 1 also applies.
Situation 4: Base and policy rates will differ if a unit does not currently have state-of-the-art combustion controls and would install
such controls in response to a NOX policy.
Crist
641_B_4
SNCR
0.404
0.404
0.240
0.180
(1) Drop in uncontrolled policy NOX rate
compared to uncontrolled base rate is due to
addition of combustion controls. (Note 0.24 is
floor.)
NOX regulated region includes: Alabama, Arkansas, Connecticut, Delaware, District Of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana,
Maine, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Hampshire, New Jersey, New York, North Carolina, Ohio, Pennsylvania,
Rhode Island, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.
39
-------
Table 3-1.2 Cutoff and Floor NOX Rates (Ib/MMBtu) in EPA Base Case v.4.10_FTransport
Boiler Type
Wall-Fired
Dry-Bottom
Tangentially
-Fired
Cell-
Burners
Cyclones
Vertically-
Fired
Cutoff
Bituminous
0.43
0.34
0.43
0.62
0.57
Rate (Ibs/MMBtu)
Subbitumino Lignit
us e
0.33 0.29
0.24 0.22
0.43 0.43
0.67 0.67
0.44 0.44
Floor
Bituminous
0.32
0.24
0.32
0.47
0.49
Rate (Ibs/MMBtu)
Subbitumino
us
0.18
0.12
0.32
0.49
0.25
Lignit
e
0.18
0.17
0.32
0.49
0.25
Table 3-1.3 NOX Removal Efficiencies for Different Combustion Control Configurations in EPA
Base Case v.4.10_FTransport
(State of the art configurations are shown in bold italic.)
Boiler Type
Dry Bottom
Wall-Fired
Dry Bottom
Wall-Fired
Tangentially-
Fired
Tangentially-
Fired
Coal Type
Bituminous
Subbituminous
/Lignite
Bituminous
Subbituminous
/Lignite
Combustion Control
Technology
LNB
LNB + OFA
LNB
LNB + OFA
LNC1
LNC2
LNC3
LNC1
LNC2
LNC3
Fraction of
Removal
0.163 + 0.272*
Base NOX
0.373 + 0.272*
Base NOX
0.135 + 0.541*
Base NOX
0.285 + 0.547*
Base NOX
0.162 + 0.336*
Base NOX
0.212 + 0.336*
Base NOX
0.362 + 0.336*
Base NOX
0.20 + 0.717*
Base NOX
0.25 + 0.717*
Base NOX
0.35 + 0.777*
Base NOX
Default
Removal
0.568
0.778
0.574
0.724
0.42
0.47
0.62
0.563
0.613
0.773
Notes:
LNB = Low NOX Burner
OFA = Overfire Air
LNC = Low NOX Control
40
-------
3 SO2 Removal Rates for Flue Gas Desulfurization (FGD)
Comment Theme: In EPA Base Case v.4.10 the assumed SO2 removal efficiency for wet and dry FGD
on new units and retrofits was 98% and 95% respectively. Comments indicated that the assumption of a
98% SO2 removal rate for wet FGD on new units and retrofits might be suitable as a short-term
performance guarantee but exceeded the long term removal rate that could be achieved under real
operating conditions where load following is required. EPA was requested to use the same default wet
and dry FGD removal rates as assumed in the previous base case v.3.0.2 EISA , i.e., 95% for wet FGD
and 92% for dry FGD.
Discussion: In response to this comment, it was decided to base removal rates for new and retrofit FGD
on historical performance data reported in EIA 860 (2008) rather than on the engineering design
capabilities of the controls, as was previously used in EPA Base Case v.4.10. This will put the removal
rate assumptions for be new and retrofit FGD on the same basis as existing controls.
Response: Default SO2 removal rates for wet and dry FGD were revised to be based on data reported in
EIA 860 (2008). This ensures that they reflect operating removal rates rather than the engineering design
removal rates which some commenters asserted could not be maintained under load following conditions.
In particular, for new units and FGD retrofits installed by the model, the assumed SO2 removal rates will
be 96% for wet FGD and 92% for dry FGD. These are the average of the SO2 removal efficiencies
reported in EIA 860 (2008) for dry and wet FGD installed in 2008 or later.
Existing units reporting FGD removal rates in form EIA 860 (2008) will be assigned those rates. However,
to reduce the incidence of implausibly high, outlier removal rates, units whose reported EIA Form 860
(2008) SO2 removal rates are higher than the average of the upper quartile SO2 removal rates will be
assigned the upper quartile average unless the reported EIA 860 rate is confirmed in a submitted
comment. One upper quartile removal rate is calculated across all installation years and replaces any
reported removal rate that exceeds it no matter what installation year. Existing units not reporting FGD
removal rates in form EIA 860 (2008) will be assigned the average of the applicable SO2 removal rate for
a dry or wet FGD as reported in EIA 860 (2008) for the same FGD installation year.
3.2 Resulting Updates
The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model
show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case
v4.10_FTransport.
In Chapter 3 - Power System Operation Assumptions
Change the entries in Table 3-11 as shown in red on the following page.
41
-------
Table 3-11 Emission and Removal Rate Assumptions for Potential (New) Units in EPA Base Case v.4.10 FTransport
Gas
S02
NOX
Hg
C02
HC1
Removal,
and
Emissions
Rates
Removal /
Emissions
Rate
Emission
Rate
Emissions
Rate
Emissions
Rate
Removal /
Emissions
Rate
Supercritical
Pulverized
Coal - Wet
Scrubber
98%-96%with
a floor of 0.06
Ibs/MMBtu
0.07
Ibs/MMBtu
90%
205.2-217.3
Ibs/MMBtu
99%
0.0001
Ibs/mmBtu
Supercritical
Pulverized
Coal - Dry
Scrubber
93% 92% with
0.065 0.08
Ibs/MMBtu
0.05
Ibs/MMBtu
90%
205.2-217.3
Ibs/MMBtu
99%
0.0001
Ibs/mmBtu
Integrated
Gasification
Combined
Cycle
99%
0.013
Ibs/MMBtu
90%
205.2-217.3
Ibs/MMBtu
99%
0.0001
Ibs/mmBtu
Advanced
Coal with
Carbon
Capture
99%
0.013
Ibs/MMBtu
90%
90%
99%
0.0001
Ibs/mmBtu
Advanced
Combined
Cycle
None
0.011
Ibs/MMBtu
Natural Gas:
0.000138
Ibs/MMBtu
Oil:
0.483
Ibs/MMBtu
Natural Gas:
117.08
Ibs/MMBtu
Oil:
161.39
Ibs/MMBtu
-
Advanced
Combustion
Turbine
None
0.011
Ibs/MMBtu
Natural Gas:
.000138
Ibs/MMBtu
Oil:
0.483
Ibs/MMBtu
Natural Gas:
117.08
Ibs/MMBtu
Oil:
161.39
Ibs/MMBtu
-
Biomass
Conventional
Direct-Fired
Boiler
0.08 Ibs/MMBtu
0.36 Ibs/MMBtu
0.57 Ibs/MMBtu
None
-
Biomass
Gasification
Combined
Cycle
0 08
Ibs/MMBtu
0.102
Ibs/MMBtu
0.57
Ibs/MMBtu
None
-
Geothermal
None
None
3.70
None
-
Landfill Gas
None
0.09
Ibs/MMBtu
None
None
-
42
-------
In Chapter 5 - Emission Control Technologies
Incorporate the changes shown in red below.
5.1 Sulfur Dioxide Control Technologies
Two commercially available Flue Gas Desulfurization (FGD) technology options for removing the SO2
produced by coal-fired power plants are offered in EPA Base Case v.4.10: Limestone Forced Oxidation
(LSFO) — a wet FGD technology — and Lime Spray Dryer (LSD) — a semi-dry FGD technology which
employs a spray dryer absorber (SDA). In wet FGD systems, the polluted gas stream is brought into contact
with a liquid alkaline sorbent (typically limestone) by forcing it through a pool of the liquid slurry or by spraying
it with the liquid. In dry FGD systems the polluted gas stream is brought into contact with the alkaline sorbent
in a semi-dry state through use of a spray dryer. The removal efficiency for SDA drops steadily for coals
whose SO2 content exceeds 3 Ibs SO2/MMBtu, so this technology is provided only to plants which have the
option to burn coals with sulfur content no greater than 3 Ibs SO2/MMBtu. In EPA Base Case v.4.10 when a
unit retrofits with an LSD SO2 scrubber, it loses the option of burning BG, BH, and LG coals due to their high
sulfur content.
In EPA Base Case v.4.10 the LSFO and LSD SO2 emission control technologies are available to existing
"unscrubbed" units. They are also available to existing "scrubbed" units with reported removal efficiencies of
less than fifty percent. Such units are considered to have an injection technology and classified as
"unscrubbed" for modeling purposes in the NEEDS database of existing units which is used in setting up the
EPA base case. The scrubber retrofit costs for these units are the same as regular unscrubbed units
retrofitting with a scrubber. Scrubber efficiencies for existing units were derived from data reported in EIA
Form 767-860 (2008). In transferring this data for use in EPA Base Case v.4.10 the following changes were
made. The maximum removal efficiency was set at 98% for wet scrubbers and 93% for dry scrubber units.
Existing units reporting efficiencies above these levels in Form 767 were assigned the maximum removal
efficiency in NEEDS v.4.10 indicated in the previous sentence. Units whose reported EIA Form 860 (2008)
SO2 removal rates were higher than the average of the upper quartile SO2 removal rates were assigned the
upper quartile average unless the EIA 860 rate was confirmed in a comment submitted during the Transport
Rulemaking . One upper quartile removal rate is calculated across all installation years and replaces any
reported removal rate that exceeds it no matter what installation year. Existing units not reporting FGD
removal rates in form EIA 860 (2008) were assigned the average of the applicable SO2 removal rate for a dry
or wet FGD as reported in EIA 860 (2008) for the same FGD installation year.
As shown in Table 5-2, existing units that are selected to be retrofitted by the model with scrubbers are given
the maximum removal efficiencies of 98%-96% for LSFO and 93%-92% for LSD. The procedures used to
derive the cost of each scrubber type are discussed in detail in the following sections.
Table 5-2 Summary of Retrofit SO2 Emission Control Performance Assumptions
Performance
Assumptions
Percent Removal
Capacity Penalty
Heat Rate Penalty
Cost (2007$)
Applicability
Sulfur Content
Applicability
Applicable Coal Types
Limestone Forced
Oxidation (LSFO)
94^96%
with a floor of 0.06 Ibs/MMBtu
Calculated based on
characteristics of the unit:
See Table 5-4 for examples
Units > 25 MW
BA, BB, BD, BE, BG, BH, SA,
SB, SD, LD, LE, and LG
Lime Spray Dryer (LSD)
939^92%
with a floor of 0.065 0.08
Ibs/MMBtu
Calculated based on
characteristics of the unit:
See Table 5-4 for examples
Units > 25 MW
Coals < 3 Ibs SO2/MMBtu
BA, BB, BD, BE, SA, SB, SD,
LD, and LE
Potential (new) coal-fired units built by the model are also assumed to be constructed with a scrubber
achieving a removal efficiency of 9&%-96% for LSFO and 93%-92% for LSD. In EPA Base Case v.4.10 the
costs of potential new coal units include the cost of scrubbers.
43
-------
4 Coal Switching - Bituminous to Subbituminous
4.1 Response to the Comments Received
Comment Theme: In draft EPA Base Case v.410 it was assumed that generating units that had the
option to burn both bituminous and subbituminous coal could use any proportion needed of each type of
coal. Comments pointed out that there were limitations that prevented unrestricted switching at some
existing generating units.
Discussion: Based on these comments, a procedure was developed to capture limitations that prevent
unrestricted switching from bituminous to subbituminous coal without incurring additional investment
costs. The procedure consisted of the following steps: (1) Determining a level of subbituminous coal
consumption indicative of an existing capability to burn 100% subbituminous coal. (2) Developing cost
adders, heat rate penalties, and decision rules that would apply to units that don't meet this threshold.
In EPA Base Case v.4.10_FTransport, existing units with a historical record of burning a high percentage
of subbituminous (specifically, 90% or more) are assumed to have made investments required for high
percentage subbituminous firing. Existing units not meeting the 90% criteria incur a fuel cost adder and
heat rate penalty for combusting more than a pre-specified percent of subbituminous. The cost adder is
designed to reflect material handling and boiler modification costs. The heat rate penalty reflects the
impact of the higher moisture content subbituminous coal on the unit's heat rate. The procedure, which is
summarized below, applies only to units that are currently designated to burn both bituminous and
subbituminous coal in EPA Base Case v.4.10_FTransport. Historical fuel usage data is used to infer
whether units have already made investments allowing them to burn unrestricted amounts of
subbituminous coal.
Staff engineering analyses indicated that (a) all boilers that are designated to burn both bituminous and
subbituminous coal should be able to burn a limited percentage of subbituminous (i.e., below 20%)
without incurring the cost of boiler modifications and fuel handling improvements and (b) while boiler
improvements can remove the limitations on the amount of subbituminous coal burned at a unit, they
come at a cost ($250/kW) and an associated heat rate penalty (5%).
Consideration was given to allowing units that historically had burned more than 20%, but less than 90%
subbituminous coal, to burn up to their historic maximum at no additional cost and only incur the
additional cost and heat rate penalty when consuming above their historical maximum percent
subbituminous use. However, comments (e.g., the 10/11/10 Dairyland Power Cooperative comment
EPA-HQ-OAR-2009-0491-2733.1 on Genoa Unit 1) indicated that during the economic recession of 2007,
2008, and 2009 when electricity demand was lower than normal, units burned higher proportions of
subbituminous coal without making the investments that would otherwise have been necessary if their
generation had been high enough to trigger a capacity derating. During the recession, units were not
generating at high enough levels for capacity deratings to become an issue. Taking this into
consideration, EPA took the more conservative approach of assuming that unless the unit historically had
burned more than 90% subbituminous coal, it had not previously made the investments needed to burn
more than 20% subbituminous coal.
Response: The specifics of the procedure are as follows:
(b) For coal plants that have the option to burn both bituminous and subbituminous coal in EPA Base
Case v.4.10_FTransport, those that have burned 90% or more subbituminous coal in 2008, 2009, or
first half of 2010 are assumed to have already made the fuel handling and boiler investments needed
to burn up to 100% subbituminous coal and would therefore not face any additional costs. In
addition, their reported heat rates are assumed to reflect the impact of burning the corresponding
proportion of subbituminous coal. EIA Form 423 is used to determine the percent of subbituminous
coal burned in 2008, 2009, and first half of 2010.
(c) All other units with the option to burn both bituminous and subbituminous coal in EPA Base Case
v.4.10, would have the option to burn
(i) Less than 20% subbituminous coal without incurring any additional cost or heat rate penalty.
44
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(j) Twenty percent (20%) or more subbituminous coal at a cost of $250/kW and a heat rate penalty
of 5% to reflect additional fuel handling and boiler modification costs associated with burning
higher proportions of subbituminous coal. The $250/kW cost adder is designed to cover boiler
modifications or alternative power purchases in lieu of capacity deratings that would otherwise be
associated with burning subbituminous coal with its lower heating value relative to bituminous
coal.
4.2 Resulting Updates
The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model
show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case
v4.10_FTransport.
Add the following paragraph between sections 9.3.9 and 9.4.
9.3.10 Coal Switching
Recognizing that boiler modifications and fuel handling enhancements may be required for
unrestricted switching from bituminous to subbituminous coal, the following conditions apply in EPA
Base Case v.4.10_FTransport to coal plants that have the option to burn both bituminous and
subbituminous coal.
Those that have burned 90% or more subbituminous coal in 2008, 2009, and first half of 2010 are
assumed to have already made the fuel handling and boiler investments needed to burn up to 100%
subbituminous coal and would therefore not face any additional costs. In addition, their reported heat
rates are assumed to reflect the impact of burning the corresponding proportion of subbituminous
coal. EIA Form 423 is used to determine the percent of subbituminous coal burned in 2008, 2009,
and first half of 2010.
All other units with the option to burn both bituminous and subbituminous coal in EPA Base Case
v.4.10_FTransport, are subject to the following conditions:
(1) If the unit consumes less than 20% subbituminous coal, no additional cost or heat rate penalty is
incurred.
(2) If the unit consumes twenty percent (20%) or more subbituminous coal, it incurs a cost of
$250/kWand a heat rate penalty of 5% to reflect additional fuel handling and boiler modification
costs associated with burning higher proportions of subbituminous coal. The $250/kWcost adder
is designed to cover boiler modifications or alternative power purchases in lieu of capacity
deratings that would otherwise be associated with burning subbituminous coal with its lower
heating value relative to bituminous coal. The heat rate penalty reflects the impact of the higher
moisture content subbituminous coal on the unit's heat rate
45
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5 Restrictions on coal choice in 2012
Comment Theme: Some comments indicated that various factors (including coal contracts and boiler
engineering considerations) limited the ability of coal units to change coal grades in the short to medium
term and requested that the model reflect these limitations.
Discussion: In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the
unit's engineering characteristics, the SO2 emissions limits they face, and the historical record of coals
burned at the unit. Once the coal assignments are made, no further restrictions are typically placed on
the fuels available to the unit.
Factors limiting changes is near term coal use were considered technically plausible in the first model run
year of 2012. Consequently, EPA incorporated such limitations in 2012 in cases where the affected units
were explicitly identified, where sufficient documentation and an adequate explanation of the governing
factors were provided, where EPA was not aware of data contradicting the claim, and where the inclusion
of the limitation might affect modeling results. Beyond 2012, however, EPA's assessment of industry
experience suggested that economic considerations would take precedent over short-term restrictions
and that the full choice of previously assigned coals should be re-instated for coal units. This would allow
the model to make fuel choices based on economic factors reflecting the tendency of these factors to
prevail beyond the short term.
Response:
(1) If a comment identified specific units that could not change from a specific coal due to short term
constraints and generally met the conditions outlined above, the unit's coal assignment in 2012 would
be limited to the coal stipulated in the comment. If not explicitly stipulated in the comment, the coal
reported most recently at the plant level in EIA Form 926 would be used. If the information was not
reported in EIA Form 926, the unit would be assigned the coal grade which would result in an
emission rate closest to the SO2 rate reported for the unit in EPA's Emission Tracking System (ETS)
2009.
(2) If a comment identified by name a group of units (e.g., by company or by plant name) whose coal
choices could not change over the short run, the same procedure as described in item #1 was
followed, except that it was applied to all units in the group of units.
(3) If a comment did not identify specific units or a specific set of units where coal choices were limited,
no change was made.
(4) After 2012, such restrictions no longer apply..
Changes to be Incorporated in Documentation for EPA Base Case v.4.10 Using the Integrated
Planning Model
Add the following paragraph between new section 9.3.10 and before section 9.4.
9.3.11 Short-term restrictions on coal choice
In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit's
engineering characteristics, the SO2 emissions limits they face, and the historical record of coals burned
at the unit. Once the coal assignments are made, no further restrictions are typically placed on the fuels
available to the unit.
However, coal choice was further restricted in the first model run year (2012) in the modeling horizon in
situations where information was provided to EPA indicating that short-term factors (like coal contracts
and boiler engineering considerations) limited a unit's choice to a particular assigned coal. Beyond the
first model run year the full set of assigned coals was restored in keeping with the underlying modeling
assumption that economic considerations prevail over short-term restrictions in the longer term.
46
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9.3.11 Short-term restrictions on coal choice and related issues
In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit's
engineering characteristics, the SO2 emissions limits they face, and the historical record of coals
burned at the unit. Once the coal assignments are made, no further restrictions are typically placed
on the fuels available to the unit.
However, coal choice was further restricted in the first model run year (2012) in the modeling horizon
in situations where information was provided to EPA indicating that short-term factors (like coal
contracts and boiler engineering considerations) limited a unit's choice to a particular assigned coal.
Beyond the first model run year the full set of assigned coals was restored in keeping with the
underlying modeling assumption that economic considerations prevail over short-term restrictions in
the longer term.
In conjunction with these changes, limits were imposed in fuel assignments at four Texas coal steam
plants to increase consistency with reported fuel use at the plants. The percentage of lignite used in
the first model run year (2012) was calibrated so that it would not exceed the historical level reported
in 2009, the latest year for available fuel data as reported in EIA Form 923. This limit was increased
linearly in model run year 2015 so that by model run year 2020 there would no longer be a limit on
lignite use. In other words by model run year 2020, the unit could choose to use up to 100% lignite if
the model found that this was economically optimal. The four power plants that were affected by this
procedure and the specific applicable limits are shown in the following table:
Plant Name
Big Brown
Limestone
Martin Lake
Monticello
Plant
ORIS
ID
3497
298
6146
6147
Maximum Percent of Heat
Input (MMBtu) from Lignite
For IPM Run Years Shown
2012
< 50%
< 54%
< 69%
<19%
2015
< 69%
<71%
< 80%
< 50%
2020
<100%
<100%
<100%
<100%
In addition, post-modeling quality assurance checks flagged the 100% subbituminous coal
consumption projected at the Martin Lake for 2012 as a discrepancy with the high share of lignite use
(74% by weight, 69% on an MMBtu heat content basis) that was reported for 2009 at this lignite mine-
mouth plant. To increase short-term modeling consistency with the plant's recent operating history, its
2012 SO2 emissions were re-calculated using its 2009 reported SO2 emission rate and its 2012
projected heat input.
Post-modeling quality assurance found a similar discrepancy between the short-term projection and
operating history at Gibbons Creek (ORIS 6136) Unit 1 where reported SO2 emissions at the unit were
indicative either of a unit not operating a scrubber or of a scrubber with a very low SO2 removal
efficiency, i.e., producing emission roughly equivalent to the sulfur content of purchased coal as
reported in the EIA-923, Since the unit's scrubber had not been designated as "dispatchable" the
model was forced to operate it, producing emissions in 2012 and 2014 that were not consistent with
the recent operating experience of the unit. To increase short-term modeling consistency with the
plant's operating history, its 2012 and 2014 SO2 emissions were re-calculated to factor out the
projected reductions from scrubbing.
47
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6 Waste Coal Cost Correction
6.1 Response to the Comments Received
Comment Theme: Comments were received indicating that the cost of waste coal in draft EPA Base
Case v.4.10 was much higher than actually encountered by buyers.
Discussion: Upon investigation it was found that a data entry error had resulted in incorrect waste coal
prices. The labeling of the prices in a file obtained by EPA from an outside source had indicated units of
1987 dollars per short ton, which should have been labeled 2008 dollars per short ton.
Response: The dollar year labeling error was corrected and costs were then properly converted to 2007
dollars per short ton. The resulting corrected prices were consistent with those noted in the comment.
6.2 Resulting Updates
The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model
show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case
v4.10_FTransport.
For waste coal entries only (Coal Supply Region: NA; Coal Grade: WC) replace the previous values
shown under the "Cost of Production" with the corrected values (highlighted in yellow in the table below)
Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10
1 Waste Coal Entries Only
Year
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
Coal
Supply
Region
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Coal
Grade
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
WC
Step
Name
S1
S2
S3
S4
S5
S6
S7
S8
S9
S10
S11
S1
S2
S3
S4
S5
S6
S7
S8
S9
S10
S11
Heat Content
(MMBtu/Ton)
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
Cost of Production
(2007$/Ton)
Previous
21.9
22.8
23.9
24.3
24.5
24.6
24.6
24.8
25.4
28.8
41.8
22.0
23.2
24.6
25.2
25.4
25.6
25.7
26.0
27.1
32.9
58.7
Corrected
12.7
13.3
13.9
14.2
14.3
14.3
14.3
14.4
14.8
16.7
24.3
12.8
13.5
14.3
14.6
14.8
14.9
15.0
15.1
15.8
19.2
34.2
Coal
Production
(Million
Tons/Year)
6.6
3.9
2.6
0.9
0.3
0.1
0.1
0.3
0.9
2.6
3.9
7.2
4.2
2.8
0.9
0.3
0.2
0.2
0.3
0.9
2.8
4.2
48
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Appendix 9-4 Coal Supply Curves in EPA Base Case V,
(cont'd)
Waste Coal Entries Only
4.10
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2030
2030
2030
2030
2030
2030
2030
2030
2030
2030
2030
2040
2040
2040
2040
2040
2040
2040
2040
2040
2040
2040
Coal
Supply
Region
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Coal
Grade
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
we
Step
Name
S1
S2
S3
S4
S5
S6
S7
S8
S9
S10
S11
S1
S2
S3
S4
S5
S6
S7
S8
S9
S10
S11
S1
S2
S3
S4
S5
S6
S7
S8
S9
S10
S11
Heat
Content
(MMBtu/Ton)
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
Cost of Production
(2007$/Ton)
Previous
22.1
23.1
24.3
24.8
25.0
25.1
25.2
25.4
26.1
30.1
46.1
22.1
23.0
24.2
24.6
24.8
24.9
24.9
25.1
25.7
29.1
42.3
22.2
23.2
24.4
24.9
25.1
25.1
25.2
25.4
26.2
30.1
45.8
Corrected
12.9
13.5
14.2
14.4
14.5
14.6
14.7
14.8
15.2
17.5
26.9
12.9
13.4
14.1
14.3
14.4
14.5
14.5
14.6
15.0
16.9
24.6
12.9
13.5
14.2
14.5
14.6
14.6
14.7
14.8
15.2
17.5
26.7
Coal
Production
(Million
Tons/Year)
6.8
4.0
2.7
0.9
0.3
0.1
0.1
0.3
0.9
2.7
4.0
6.6
3.9
2.6
0.9
0.3
0.1
0.1
0.3
0.9
2.6
3.9
6.8
4.0
2.6
0.9
0.3
0.1
0.1
0.3
0.9
2.6
4.0
-------
Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10
(cont'd)
Waste Coal Entries Only
Year
2050
2050
2050
2050
2050
2050
2050
2050
2050
2050
2050
Coal
Supply
Region
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Coal
Grade
we
we
we
we
we
we
we
we
we
we
we
Step
Name
S1
S2
S3
S4
S5
S6
S7
S8
S9
S10
S11
Heat
Content
(MMBtu/Ton)
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
12.35
Cost of Production
(2007$/Ton)
Previous
22.2
23.2
24.4
24.9
25.1
25.1
25.2
25.4
26.2
30.1
45.8
Corrected
12.9
13.5
14.2
14.5
14.6
14.6
14.7
14.8
15.2
17.5
26.7
Coal
Production
(Million
Tons/Year)
6.8
4.0
2.6
0.9
0.3
0.1
0.1
0.3
0.9
2.6
4.0
50
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7 Comments Considered but that did not Result in Changes
Oil consumption at dual fired (oil/gas) units
Comment Theme: When compared with recent operating experience, the extent of oil burned by dual
fuel generating units in draft EPA Base Case v.4.10 was considerably lower than some commenters
thought it should be.
Response: Consideration was given to a number of options for modifying the modeling of oil use at duel
fuel units, but it was ultimately decided not to change the previous representation for the following
reasons:
(1) The underlying factors that could be causing greater oil consumption were very site specific and the
information that would allow modeling such occurrences was not available.
(2) In the absence of site specific information, imposing generic requirements for pre-specified levels of
oil consumption was considered to have more drawbacks than the current representation.
(3) Due to their small population, dual fired units are not likely figure significantly in modeling the
Transport Rule. Enhanced modeling capability in this regard could be revisited if and when future
policies are modeled where oil use by duel fuel units has significant policy implications.
Capital cost of Flue Gas Desulfurization (FGD) on units whose capacity is less than 100 MW
Comment Theme: Some commenters considered the capital cost assumptions in draft EPA Base Case
v.4.10 for retrofitting generating units under 100 MWwith FGD to be too low. For example, one
commenter indicated that the v.4.10 FGD retrofit costs for these units should be multiplied by 4.
Response: The original cost assumptions were retained. Specifically, the FGD capital cost for units
below 100 MW is assumed to be the same as those for 100 MW units. While it is recognized that
economies of scale would not be realized by units smaller than 100 MWthat installed a standard FGD
dedicated solely to that unit, prior engineering practice indicates a number of ways that costs will be held
at the 100 MW level. Such practices include combining the emissions from multiple smaller units into a
larger FGD and thereby achieving economy of scale. Another cost controlling approach for achieving
economies of scale that has recently been seen in the marketplace is the development of innovative
combinations of controls (e.g., dry sorbent injection, alkali injection, and circulating scrubbers) whose
overall cost is lower than the sum of each of the constituent controls taken individually. These options
provide a sound technical and economic basis for retaining the current approach of determining the
capital cost of FGD for the universe of units less than 100 MWin EPA Base Case v.4.10
Selective Catalytic Reduction (SCR) retrofit costs
Comment Theme: Assumed SCR retrofit costs are too low in EPA Base Case v.4.10
Response: The SCR and FGD cost assumptions in EPA Base Case v.4.10 were updated in the summer
of 2010 based on substantial engineering analyses and market assessments by an independent
engineering firm. (This is documented on EPA web site at www.epa.gov/airmarkets/progsregs/epa-
ipm/docs/v410/Chapter5.pdf and www.epa.gov/airmarkets/progsregs/epa-
ipm/docs/v410/Appendix52A.pdf.) In response to the comments received on SCR costs, EPA reviewed
the cost assumptions and concluded not to modify them at this time. Although site specific conditions
(which may the basis for the comments) can result in higher costs, the assumptions developed for EPA
Base Case v.4.10 were deemed to be current, to have a strong economic and engineering basis, and to
be applicable across the fleet of U.S. generating units.
30 year book life for emission control retrofits
Comment Theme: The 30 year book life assumed for retrofits in v.4.10 is too long. Many retrofits are on
smaller and older units where an additional 20-30 year of life is not likely.
Response: For several reasons, the 30 year book life assumption for emission control retrofits was
retained. First, as described in section 4.2.8 and Table 4-10 of Documentation for EPA Base Case v.4.10
Using the Integrated Planning Model (www.epa.gov/airmarkets/progsregs/epa-
51
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ipm/docs/v410/Chapter4.pdf), existing units in EPA Base Case v.4.10 incur a life extension cost if they
remain in operation past their current expected lifespan. (For existing coal units this occurs when they
pass age 40.) The assumption of a 30-year book life for retrofits is consistent with these life extension
provisions which allow existing units to stay in operation throughout the 2012-2050 modeling time
horizon, rather than forcing them retire upon reaching a pre-specified expected lifespan. The 30-year
book life is in line with the 30-year design life typically specified in purchase agreements to ensure the
quality of materials and cyclic fatigue life of power boilers, turbines and associated emission control
systems. It is also well within the service life of such equipment which extends far beyond 30 years when
generally accepted maintenance practices are followed.
Must run, black start, and spinning reserve units
Comment Theme: The model retires units that some commenters identified as being prevented from
retiring for reliability purposes
Response: There are several reasons for retaining the current approach that does not attempt to account
for "must run" units and does not prevent such units from retiring. First, for competitive business reasons,
a comprehensive listing of must-run units is not available from either public or private sources. Limiting
the "must run" designation only to those units identified in comments would introduce inconsistency
across the universe of units. Second, there is no technically sound approach for defining the extent of
operation of a "must run" unit. Finally, there is no technical basis for defining the period over which the
"must run" designation would last. This is a particularly important issue in view of the long modeling time
horizon (2012 to 2050) in EPA Base Case v.4.10.
Availability assumptions for existing coal units
Comment Theme: The availability assumption for coal units in EPA Base Case v.4.10 should not be
based on historical capacity factor data from the Energy Information Administration's Annual Energy
Outlook 2010 (AEO 2010 but on availabilities in NERC GADS as was done in previous EPA base cases
(including v.3.0.2 EISA)
Response: Rather than using NERC GADS availabilities, EPA Base Case v.4.10 adopts an approach
similar to AEO 2010 of using historical capacity factors to define the availabilities of existing coal units.
The change was a result of analysis that showed that for a large portion of the coal fleet, actual capacity
factors for existing coal units fell below the availabilities in NERC GADS. It is also based on an
assessment that indicated that the system-level availabilities that are found in NERC GADS were not
entirely comparable to the plant level availabilities required for IPM. Comparing previous base case
projections to historical data showed tendencies to over-project coal consumption and under-project gas
consumption as a result of the use of the GADS availabilities. Consequently, v.4.10 adopts the approach
used in AEO 2010 and other modeling efforts which tie availability assumptions for existing coal units to
historical capacity factors (plus a growth assumption for capacity factors below 75% and an upper cut off
of 95% to reflect an assumed 5% force outage rate). The historical capacity factors used to derive the
availability assumptions in EPA Base Case v.4.10 were obtained from AEO 2010.
52
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Addenda - Notes on various modeling assumptions
Though not necessarily responses to comments received on the Transport Rule or NODA, the following
features of EPA Base Case v.4.10_FTransport are annotated below for purposes of documentation.
1. Dry Sorbent Injection (DSI) and Fabric Filter Cost Development Section 5.5.3.2 and Appendix 5-
4 on dry sorbent injection and section 5.5.4 and Appendix 5-5 on fabric filter cost development are
incorporated below from the Documentation Supplement for EPA Base Case v.4.10_Rox- Updates
for Proposed Toxics Rule. Minor changes have been made to the text to highlight aspects particularly
relevant to the Final Transport Rule, i.e., the use of DSI in combination a fabric filter as a retrofit
option for SO2 control.
2. Variable Operating and Maintenance (VOM) Cost of Dry Sorbent Injection (DSI) Retrofits: In
modeling the Final Transport Rule (i.e., in EPA Base Case v.4.10_FTransport), DSI is provided as a
retrofit for units burning coals with an SO2 content of less than 2 Ibs/mmBtu and is assumed to be
retrofit in conjunction with a fabric filter. When retrofit on units with a pre-existing fabric filter, it is
assumed that no ESP is present and that the DSI is installed upstream of the FF. Consequently, the
fly ash that is caught in the fabric filter will be contaminated by the sorbent and not marketable. Since
the entire combined fly ash, reaction products, and unreacted sorbent mass will have to be disposed,
the full DSI capital, FOM, and VOM costs are incurred. In contrast, when DSI is retrofit on units with
no pre-existing fabric filter, it is assumed that the DSI will be installed after the ESP (which, in the
absence of a FF, will be present for PM control) and upstream of the FF which is installed in
conjunction with the DSI. Since the upstream ESP will capture the fly ash before it arrives at the DSI,
it will not be contaminated by the sorbent and can be sold rather than disposed. (Note: No credit for
fly ash sales is taken into account in IPM.) Only the reaction products and unreacted sorbent which is
caught in the FF will need to be landfilled. Since the waste disposal cost only applies to the sorbent,
there is a 35% reduction in VOM. In this situation the reduced VOM and standard capital and FOM
costs are incurred for the DSI retrofit plus the capital, FOM, and VOM costs for the associated FF.
3. Updated Appendices 3-2 through 3-4: These appendices, which are included below, show the
state power sector air emissions regulations (Appendix 3-2), NSR settlements (Appendix 3-3) and
state settlements (Appendix 3-4) that are represented in EPA Base Case v.4.10_FTransport.
4. 2012 Emission Control Retrofits: In EPA's modeling for the Final Transport Rule, emission controls
in response to the Transport Rule are not allowed to be occur in 2012, the first model run year,
because of insufficient lead time to install flue gas desulfurization (FGD) for SO2 and selective
catalytic reduction (SCR) for NOX control by 2012. However, in order not to overstate the emission
levels without the Transport Rule, emission controls are allowed to occur in 2012 in response to non-
Transport Rule legal requirements that were in place in 2010 or earlier. While the specific controls
that the model builds and operates (or partially operates) may not correspond to those actually
installed as part of a source's compliance strategy, they should capture valid levels of emission
reductions that can be expected to be achieved in complying with binding non-Transport Rule
agreements or regulations. This dual approach to 2012 retrofits is implemented by allowing the
model to install emission control retrofits in 2012 in the base case (which does not include Transport
Rule but does include binding non-Transport Rule legal requirements). Any 2012 retrofits occurring in
the base case are then carried over into the "Remedy" policy case (which includes the Final Transport
Rule emission requirements), but the model is not allowed to install any additional 2012 emission
controls (which would come in response to the Transport Rule requirements).
5. Emission Controls in IPM Parsed Files: Users are sometimes unclear about the origins of the
advanced post-combustion emission controls (e.g., FGD or SCR) that appear in the "parsed files" for
53
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an IPM model run. These controls originate in one of four possible sources. (1) Most existing controls
are the same as those found in the National Electric Energy Data System (NEEDS), the database of
existing and planned/committed units which serves as the starting point for setting up EPA's base and
policy cases using IPM. For the Final Transport Rule existing controls are those present in 2011 or
earlier. (2) A small number of existing emission controls appear in parsed files, but are not found in
NEEDS. They are controls that became known after the NEEDS database was "frozen" for purposes
of setting up a family of model runs. Rather than appearing in NEEDS, they are represented directly
in IPM as emission control retrofit options available from the start of the modeling time horizon. They
can either be forced to operate through the imposition of modeling constraints (in which case they are
termed "non-dispatchable" controls) or be left for the model to determine endogenously whether
emission policies require them to operate (in which case they are termed "dispatchable" controls). (3)
Some generating units have either (a) an existing legal requirement, such as a consent decree or
state rule requiring the installation of a control by a particular date post 2011, or (b) have publically
announced or submitted comment noting the installation and/or beginning of construction of a control
for post 2011 start-up. In instances where the control is expected in the future, but not present by
2011 or earlier, the control is represented directly in IPM as a retrofit option which is either forced by a
modeling constraint to be installed and operate (non-dispatchable controls) or left for the model to
determine whether they need to operate (dispatchable controls). These controls appear in the model
run year corresponding to the year they are expected to operate (typically 2012 or 2015) both in IPM
outputs and parsed files. They do not appear in NEEDS (since they were not present prior to 2012).
(4) The remaining emission controls found in parsed files are those that the model builds as part of
the optimal (most cost effective) solution in response to all the requirements faced by the electric
power system represented in the model.
6. Mercury Emission Modification Factor (EMF) for Waste Coal Units: In EPA Base Case
v.4.10_FTransport (as in the base case for the proposed Mercury and Air Toxics Standards Rule -
EPA Base Case v.4.10_PTox), all waste coal units are assumed to have a mercury EMF of 0.02.
7. Carbon dioxide (CO2) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization
(FGD) System for Sulfur Dioxide (SO2) Control: In EPA applications of IPM the chemical reactions
in a limestone forced oxidation (LSFO) system (also known as a wet FGD or wet scrubber) are
assumed to cause CO2 increases according to the following equation:
CO2 increase in % of total CO2 from fuel =
0.35 X SO2 emission rate of the fuel (in Ib/MMBtu) - 0.02
For example, for coal with an SO2 emission factor of 4.3 Ib/MMBtu, the increase in CO2 is 1.485%. In
contrast to LSFO, there is no representation of direct emissions of CO2 or other greenhouse gases
from the other control technologies in IPM. These include limestone spray dryers (LSD) for SO2
control, dry sorbent injection (DSI) forSO2 and hydrogen chloride (HCI) control, selective catalytic
reduction (SCR) and selective non-catalytic reduction (SNCR) for NOX control, and activated carbon
injection (ACI) for mercury control.
54
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Addendum A — Dry Sorbent Injection (DSI) and Fabric Filter
Cost Development in EPA Base Case v.4.10_FTransport
Note: The numbering of the sections and tables in this addendum is the same as found in the
Documentation Supplement for EPA Base Case v.4.10_Ptox - Updates for Proposed Toxics Rule, where
this material originally appeared.
55
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Table 5-21 Summary of Retrofit SO2 (and HCI) Emission Control Performance Assumptions in v4.10_FTransport
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.
56
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5.5.3.2 Dry Sorbent Injection
EPA Base Case v4.10_FTransport includes dry sorbent injection (DSI) as a retrofit option for achieving (in
combination with a particulate control device) SO2 (and HCI) removal. With DSI a dry sorbent is injected
into the flue gas duct where it reacts with the SO2 and HCI 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 removal4 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).
In EPA Base Case v4.10_FTransport 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 VIM,
August 2010).
The cost of fly ash waste handling, the other key contributorto 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
4 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)
57
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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
S02
Rate
of coal
(Ib/
MMBtu)
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 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_FTransport.
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.
58
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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 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 & Lundy5.
5These 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.qov/airmarkets/proqsreqs/epa-ipm/.
59
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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_FTransport
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> (*™~
28 0.36
31 0.38
34 0.41
47 0.52
52 0.56
58 0.60
60
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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_FTransport, but are accounted for as a cost adder when installed in conjunction with DSI. In EPA
Base Case v4.10_FTransport, an existing or new fabric filter particulate control device is a pre-condition
for installing a DSI retrofit. Any unit that is retrofit by the model with DSI and does not have an existing
fabric filter incurs the cost of installing a fabric filter. This cost is 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_FTransport 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 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_FTransport 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.
61
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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_FTransport.
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_FTransport 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 & Lundy6.
6 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.qov/airmarkets/proqsreqs/epa-ipm/.
62
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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_FTransport
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_FTransport 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.
63
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Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCI
(and SO2) Emissions Control in EPA Base Case v4.10_FTransport
^il P 11^^-
Complete Dry Sorbent Injection Cost Development Methodology - Final
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Costs art all basfii on 2910 dollars
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64
-------
Complete Dry Sorbeot Injection Cost Development Methodology -Final
?.'gnia? atraft *as a ^i:tg '
3 S-v -r' 1J ^- Tr -R3
. 1 - A. Sfc^ttld t>eii**rt
H -4JI
,?'..'«• j -at.
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eoit
FCHO SJ:Wj,r> 11 ;
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S*f fc *u< Ftevec ^
65
-------
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_FTransport
Table 1. Example Complete C ost Estimate for a 4.0 A'C Bughouse Instillation (Costs are aD based on 2009 dollars)
E^ L- al Cd. tirtihuii
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Table 2. Example Complete Cost Estimate for a 6,0 A/C Biishonselnstalladon (Cost^ are all based on 2009 dollars)
I'ifi^-A
r 1 iff , rtn
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66
0 -S3
012
-------
Addendum B — Representation of
State Electric Power Emission Regulations (Appendix 3-2),
New Source Review (NSR) Settlements (Appendix 3-3), and
State Settlements (Appendix 3-4)
in EPA Base Case v.4.10_FTransport
Note: The numbering of the appendices in this addendum is the same as found in the Documentation for
EPA Base Case v.4.10 Using the Integrated Planning Model, where an earlier version of these
appendices previously appeared.
67
-------
Appendices 3-2 (State Regulations), 3-3 (NSR Settlements), and 3-4 (State Settlements)
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_FTransport
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
68
-------
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
69
-------
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
70
-------
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
71
-------
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
72
-------
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_FTransport 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
73
-------
Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10_FTransport (05-16-11)
Company and
Settlement Actions
Ret ire/Re power
Action
Alabama Power
James H. Miller
Alabama
Units 3&4
Effective
Date
SO2 control
Equipment
p..
Removal or
Rate
Effective
Date
NOX Contro
Equipment
Rate
Effective Date
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective
Date
Install and
operate FGD
continuously
95%
12/31/11
Operate
existing SCR
continuously
0.1
05/01/08
0.03
12/31/06
Within 45 days
of settlement
entry, ARC must
retire 7,538 SO2
emission
allowances.
ARC shall not
sell, trade, or
otherwise
exchange any
Plant Miller
excess SO2
emission
allowances
outside of the
A PC system
1/1/21
http://www.epa.gov/complia
n ce/reso u rces/cases/civ i l/c
aa/ala bamapower.html
Minnkota Power Cooperative
Beginning 1/01/2006, Minnkota shall not emit more than 31, 000 tons of SQ/year, no more than 26, 000 tons beginning 2011, no more than 11, 500 tons beginning 1/01/2012. If Units is not operational by 12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500
Milton R. Young
Minnesota
Unitl
Unit 2
Install and
continuously
operate FGD
Design,
upgrade, and
continuously
operate FGD
95% if 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
rate < 36
0.36
0.36
12/31/09
12/31/07
0.03 if wet
FGD, .015
f dry FGD
0.03
Before 2008
Plant will
surrender 4, 346
allowances for
each year 2012
-2015,8,693
allowances for
years 2016-
2018, 12,170
allowances for
year 2019, and
14,886
allowances/year
thereafter if
Units 1 -3 are
operational by
12/31/2015. If
only Units 1 and
2 are
operational
by12/31/2015,
the plant shall
retire 17,886
units in 2020
and thereafter.
Minnkota shall
not sell or
trade NOX
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
SIGECO
FB Culley
PSEG FOSSIL
Bergen
Indiana
New Jersey
Unitl
Unit 2
Units
Unit 2
Re power to
natural gas
12/31/06
Re power to
combined
cycle
12/31/02
Improve and
continuously
operate
existing FGD
(shared by
Units 2 and 3)
Improve and
continuously
operate
existing FGD
(shared by
Units 2 and 3)
95%
95%
06/30/04
06/30/04
Operate
Existing SCR
Continuously
0.1
09/01/03
Install and
continuously
operate a
Baghouse
0.015
06/30/07
The provision
did not specify
SO2 allowances
surrendered. It
only provided
that excess
resulting from
compliance with
NSR settlement
provisions must
'
The provision
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/sigecofb.html
-------
Company and
Plant
Hudson
Mercer
TECO
Big Bend
Gannon
State
New Jersey
New Jersey
Florida
Florida
Unit
Unit 2
Units 1 & 2
Units 1 & 2
Units
Unit 4
Six units
Settlement Actions
Ret ire /Re power
Action
Effective
Date
Retire all six
coal units and
re power at
least 550 MW
of coal
capacity to
natural gas
12/31/04
SO2 control
Equipment
Install Dry
FGD (or
approved alt.
technology)
and
continually
operate
Install Dry
FGD (or
approved alt.
technology)
and
continually
operate
Existing
Scrubber
(shared by
Units 1 &2)
Existing
Scrubber
(shared by
Units 3 & 4)
Existing
Scrubber
(shared by
Units 3 & 4)
Percent
Removal or
Rate
0.15
0.15
95% (95% or
.25)
93% if Units 3
&4are
operating
93% if Units 3
&4are
operating
Effective
Date
12/31/06
12/31/10
09/1/00
(01/01/13)
2000
(01/01/10)
06/22/05
NOX Contro
Equipment
Install SCR (or
approved tech)
and continually
operate
Install SCR (or
approved tech)
and continually
operate
Install SCR
Install SCR
Install SCR
Rate
0.1
0.13
0.1
0.1
0.1
Effective Date
05/01/07
05/01/06
05/01/09
05/01/09
07/01/07
PM or Mercury Control
Equipment
Install
Baghouse (or
approved
technology)
Rate
0.015
Effective
Date
12/31/06
Allowance
Retirement
Retirement
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.
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
WEPCO
WEPCO shall comply with the following system wide average NQ emission rates and total NCl< tonnage permissible: by 1/1/2005 an emisson 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. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86, 900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an
emission rate of 0.32 and 33,300 tons.
Presque Isle
Pleasant Prairie
Wisconsin
Wisconsin
Units 1 -4
Units 5 & 6
Units 7 & 8
Unit 9
1
2
Retire or
install SO2
and NOX
controls
12/31/12
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)
95% or 0.1
95% or 0.1
95% or 0.1
12/31/12
12/31/06
12/31/07
Install SCR (or
approved tech)
and continually
operate
Install and
operate low
NO,, 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)
0.1
0.1
0.1
12/31/12
12/31/03
12/31/05
12/31/06
12/31/06
12/31/03
Install
Baghouse
Install
Baghouse
The provision
did not specify
an amount of
SO2 allowances
to be
surrendered. It
only provided
Reference
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/psegllc.html
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/teco.html
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/wepco.html
-------
Company and
Plant
Oak Creek
Port Washington
Valley
State
Wisconsin
Wisconsin
Wisconsin
Unit
Units 5 & 6
Unit 7
Units
Units 1-4
Boilers 1-4
Settlement Actions
Ret ire /Re power
Action
Retire
Effective
Date
12/3 1/04 for
Units 1-3.
Unit 4 by
entry of
consent
decree
SO2 control
Equipment
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
Effective
Date
12/31/12
12/31/12
12/31/12
NOX Contro
Equipment
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
NOX burner
Rate
0.1
0.1
0.1
Effective Date
12/31/12
12/31/12
12/31/12
30 days after
entry of consent
decree
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
that excess
allowances
resulting from
compliance with
NSR settlement
provisions must
be retired.
Allowance
Restriction
Restriction
Effective
Date
Reference
VEPCO
The Total Permiss ble NOx Emiss ons (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 there after. Beginning
1/1/2013 they will have a system wde emission rate no greater then 0.15 Ib/mmBtu.
Mount Storm
Chesterfield
Chesapeake
Energy
Clover
Possum Point
West Virginia
Virginia
Virginia
Virginia
Virginia
Units 1 -3
Unit 4
Unit5
Unite
Units 3&4
Units 1 &2
Units3&4
Retire and
re power to
natural qas
05/02/03
Constructor
improve FGD
Construct or
improve FGD
Construct or
improve FGD
Improve FGD
95% or 0.1 5
95% or 0.1 3
95% or 0.1 3
95%or0.13
01/01/05
10/12/12
01/01/10
09/01/03
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
0.11
0.1
0.1
0.1
0.1
01/01/08
01/01/13
01/01/12
01/01/11
01/01/13
On or before
March 31 of
every year
beginning in
2013 and
continuing
thereafter,
VEPCO shall
surrender
45,000 SO2
allowances.
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/vepco.html
Santee Cooper
Santee Cooper shall comply with the following system wide averages for NQ 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 SO? 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
Winyah
South Carolina
South Carolina
Unitl
Unit 2
Unitl
Unit 2
Units
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
95%
87%
95%
95%
90%
06/30/06
06/30/06
12/31/08
12/31/08
12/31/08
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
0.1
0.11/0.1
0.11/0.1
0.12
0.14/0.12
05/31/04
05/31/04 and
05/31/07
11/30/04 and
11/30/04
11/30/04
11/30/2005 and
11/30/08
The provision
did not specify
an amount of
SO2 allowances
to be
surrendered. It
http://www.epa.gov/complia
nce/reso u rces/cases/civ i l/c
aa/santeecooper.html
-------
Company and
Plant
Grainger
Jeffries
State
South Carolina
South Carolina
Unit
Unit 4
Unit 1
Unit 2
Units 3, 4
Settlement Actions
Ret ire /Re power
Action
Effective
Date
SO2 control
Equipment
Upgrade and
continuously
operate
existing FGD
Percent
Removal or
Rate
90%
Effective
Date
12/31/07
NOX Contro
Equipment
Install and
continuously
operate SCR
Operate low
NO,, burner or
more stringent
technology
Operate low
NOX burner or
more stringent
technology
Operate low
NOX burner or
more stringent
technology
Rate
0.13/0.12
Effective Date
11/30/05 and
1 1/30/08
06/25/04
05/01/04
06/25/04
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
that excess
allowances
resulting from
compliance with
NSR settlement
provisions must
be retired.
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 NQ required for the Sammis Plant. Ohio Edison must reduce 24, 600 tons system-wide of SQ by 12/31/2010.
No later than 8/1 1
minimize NC^em
W.H. Sammis
Plant
/2005, Ohio Edison shall install and operate low NQ burners on Sammis Units 1 - 7 and overtired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization with software tc
ssions from Sammis Units 1 - 5.
Ohio
Unitl
Unit 2
Units
Unit 4
Units
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) &
operate
continuously
50% removal
or 1.1
Ib/mmBtu
50% removal
or 1.1
Ib/mmBtu
50% removal
or 1.1
Ib/mmBtu
50% removal
or 1.1
Ib/mmBtu
50% removal
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
onnfithmiinh
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/ohioedison.html
-------
Company and
Plant
Mansfield Plant
Eastlake
Burger
State
Pennsylvania
Ohio
Ohio
Unit
Unite
Unit 7
Unitl
Unit 2
Units
Units
Unit 4
Units
Settlement Actions
Retire /Repower
Action
Repower with
at least 80%
biomassfuel,
up to 20% low
sulfur coal.
Effective
Date
12/31/11
12/31/11
SO2 control
Equipment
Install FGD3
(or
approved
equiv.
control tech) &
operate
continuously
nstall FGD (or
approved
equiv.
control tech) &
operate
continuously
Upgrade
existing FGD
Upgrade
existing FGD
Upgrade
existing FGD
Percent
Removal or
Rate
95% removal
orO.13
Ib/mmBtu
95% removal
orO.13
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 Contro
Equipment
Install SNCR
(or approved
alt. tech) &
operate
continuously
Operate
existing SNCR
Continuously
Install low NO,
burners, over-
fired
air and SNCR
& operate
continuously
Rate
"Minimum
Extent
Practicable"
"Minimum
Extent
Practicable"
"Minimize
Emissions
to the
Extent
Practicable"
Effective Date
06/30/05
08/11/05
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
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.
Allowance
Restriction
Restriction
Effective
Date
Mirantl1'6
System-wide NO, 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 NQ 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 NO,.
Potomac River
Plant
Virginia
Unitl
Unit 2
Units
Unit 4
Units
Install low NO,
burners (or
more effective
tech) &
operate
continuously
Install low NO,
burners (or
more effective
tech) &
operate
continuously
nstall low NO,
burners (or
more effective
tech) &
operate
continuously
05/01/04
05/01/04
05/01/04
Reference
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/miranthtml
-------
Company and
Plant
Morgantown
Plant
Chalk Point
Maryland
Maryland
Unit
Unit 1
Unit 2
Unit 1
Unit 2
Settlement Actions
Ret ire /Re power
Action
Effective
Date
SO2 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 Contro
Equipment
Install SCR
(or approved
alt. tech) &
operate
continuously
Install SCR
(or approved
alt. tech) &
operate
continuously
Rate
0.1
0.1
Effective Date
05/01/07
05/01/08
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
For each year
after Mirant
commences
FGD operation
at Chalk Point,
Mirant shall
surrender the
number of SO2
Allowances
equal to the
amount by
which the SO2
Allowances
allocated to the
Units at the
Chalk Point
Plant are
greater than the
total amount of
SO2 emissions
allowed under
this Section
XVIII.
Allowance
Restriction
Restriction
Effective
Date
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
Havana
Illinois
Illinois
Units 1 S.2
Units
Unite
Install wet or
dry FGD (or
approved
equiv. alt.
tech) &
operate
continuously
Install wet or
dry FGD (or
approved
equiv. alt.
tech) &
operate
continuously
Install wet or
dry FGD (or
approved
equiv. alt.
tech) &
operate
continuously
0.1
0.1
1.2 Ib/mmBtu
until
12/30/2012;
0.1 Ib/mmBtu
from
12/31/2012
onward
12/31/11
12/31/11
08/11/05
and
12/31/12
Operate OFA
& existing SCR
continuously
Operate OFA
and/or low NOx
burners
Operate OFA
and/or low NOx
urners
existing SCR
continuously
0.1
0.1 2 until
12/30/12;
0.1 from
12/31/12
0.1
08/11/05
08/1 1/05 and
12/31/12
08/11/05
continuously
Baghouse
Installs.
continuously
operate
Baghouse
Installs.
continuously
operate
Baghouse,
then install
ESP or alt. PM
equip
0.015
0.015
For Bag-
house:
0.015
Ib/mmBtu;
For ESP:
0.03
Ib/mmBtu
12/31/10
12/31/10
For
Baghouse:
12/31/12;
For ESP:
12/31/05
Note: Havana Unite in the Illinois Power NSR settlement refers to the affected electric generator. The provsions shown here as applying to Havana Unite are represented in IPM as applying to Havana Unit 9,
which is the boiler that powers generator unit #6.
By year end
2008, Dynergy
will surrender
1 2,000 SO2
emission
allowances, by
year end 2009 it
will surrender
18,000, by year
end 2010 it will
surrender
24,000, any by
year end 2011
and each year
thereafter it will
surrender
30,000
allowances. If
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/illinoispower.html
-------
Company and
Vermilion
Wood River
Kentucky Utilitie
EW Brown
Generating
Station
Salt River Projec
Corona do
Generating
Station
Illinois
Illinois
s Company
Kentucky
t Agricultural Irr
Arizona
Unit 1
Unit 2
Units 1 &2
Units 4&5
Units
provement a
Unit 1 or
Unit 2
Unit 1 or
Unit 2
Settlement Actions
Ret ire /Re power
Action
nd Power Dist
Effective
Date
rict (SRP)
American Electric Power
SO2 control
Equipment
Install FGD
Immediately
begin
continuous
operation of
existing FGDs
on both units,
install new
FGD.
Install new
FGD
Removal or
Rate
1.2
1.2
1.2
1.2
97% or 0.1 00
95% or 0.08
95% or 0.08
Annual Cap
(tons)
Effective
Date
07/27/05
07/27/05
01/31/07
07/27/05
12/31/10
New FGD
installed by
1/1/2012
01/01/13
Year
NOX Contro
Equipment
Operate OFA
and/or low NOX
burners
Operate OFA
and/or low NO*
burners
Operate OFA
and/or low NOX
Operate OFA
and/or low NOX
Install and
continuously
operate SCR
by 12/31/2012,
continuously
operate low
NOX boiler and
OFA.
Install and
continuously
operate low
NOX burner
and SCR
Install and
continuously
operate low
NO* burner
Rate
"Minimum
Extent
Practicable"
"Minimum
Extent
Practicable"
"Minimum
Extent
Practicable"
"Minimum
Extent
Practicable"
0.07
0.32 prior to
SCR
installation,
0.080 after
0.32
Annual Cap
(tons)
Effective Date
08/11/05
08/11/05
08/11/05
08/11/05
12/31/12
LNBby
06/01/2009,
SCR by
06/01/2014
06/01/11
PM or Mercury Control
Equipment
Install ESP (or
& 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
Continuously
operate ESP
Optimization
and continuous
operation of
existing ESPs.
Rate
0.03
0.03
0.03
0.03
0.03
0.03
Effective
Date
12/31/06
12/31/06
12/31/10
12/31/05
12/31/10
Optimization
immediately,
rate limit
begins
01/01/12
(date of new
FGD
Optimization
immediately,
begins
(date of new
installation)
Allowance
Retirement
Retirement
the surrendered
allowances
result in
insufficient
allowances
allocated to the
units comprising
the DMG
can request to
surrender fewer
SO2 allowances.
53 000 SO2
2008 or earlier
vintage by
March 1,2009.
All surplus NO*
allowances must
be surrendered
through 2020.
Beginning in
2012, all surplus
SO2 allowances
for both
Coronado and
Springerville
Unit 4 must be
surrendered
through 2020.
The allowances
limited by this
condition may,
however, be
used for
compliance at a
prospective
future plant
using BACTand
otherwise
specified in par.
54 of the
consent decree.
Allowance
Restriction
Restriction
SO2 and NOX
allowances
may not be
used for
compliance,
and emissions
decreases for
purposes of
complying with
the Consent
earn credits.
SO2 and NOX
allowances
may not be
used for
compliance,
and emissions
decreases for
purposes of
complying with
the Consent
Decree do not
earn credits.
Effective
Date
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/kucompany.html
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/srp.html
NOX and SO2
-------
Company and
Plant
State
Unit
Eastern System-Wide
At least 600MW
from various
units
Amos
Big Sandy
West Virginia
Virginia
Indiana
West Virginia
West Virginia
Kentucky
Sporn
1 -4
Clinch River
1 -3
Tanners
Creek
1 -3
Kammer
1 -3
Unit 1
Unit 2
Units
Unitl
Unit 2
Settlement Actions
Ret ire /Re power
Action
Retire, retrofit,
or re- power
Effective
Date
12/31/18
SO2 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
Percent
Removal or
Rate
450,000
450,000
420,000
350,000
340,000
275,000
260,000
235,000
184,000
174,000
Effective
Date
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019 and
thereafter
12/31/09
12/31/10
12/31/09
Date of entry
12/31/15
NOX Contro
Equipment
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Continuously
operate low
NO,, burners
Install and
continuously
operate SCR
Rate
96,000
92,500
92,500
85,000
85,000
85,000
75,000
72,000
Effective Date
2009
2010
2011
2012
2013
2014
2015
2016 and
thereafter
01/01/08
01/01/09
01/01/08
Date of entry
01/01/09
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
NOX and SO2
allowances that
would have
been made
available by
emission
reductions
pursuant to the
Consent Decree
must be
surrendered.
Allowance
Restriction
Restriction
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 NOX
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
NOX and SO2
earns
supercomplian
ce allowances.
Effective
Date
Reference
http://www.epa.gov/complia
n ce/reso u rces/cases/civ i l/c
aa/americanelectricpower1 0
07.html
-------
Company and
Plant
Cardinal
Clinch River
Conesville
Gavin
Glen Lyn
Kammer
Kanawha River
Mitchell
State
Ohio
Virginia
Ohio
Ohio
Virginia
West Virginia
West Virginia
West Virginia
Unit
Unit 1
Unit 2
Units
Units
1 -3
Unitl
Unit 2
Units
Unit 4
Units
Unit 6
Unitl
Unit 2
Units
1 -3
Units 5, 6
Units
1-3
Units 1, 2
Unitl
Unit 2
Settlement Actions
Ret ire /Re power
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
SO2 control
Equipment
Install and
continuously
operate FGD
Install and
continuously
operate FGD
Install and
continuously
operate FGD
Install and
continuously
operate 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
Percent
Removal or
Rate
Plant-wide
annual cap:
2 1,700 tons
from 20 10 to
2014, then
16, 300 after
1/1/2015
95%
95%
Plant-wide
annual cap:
35,000
Effective
Date
12/31/08
12/31/08
12/31/12
2010-2014,
2015 and
thereafter
12/31/10
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
NOX Contro
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
Continuously
operate low
NOX burners
Continuously
operate low
NOX burners
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Continuously
operate low
NO,, burners
Continuously
operate over-
fire air
Continuously
operate low
NOX burners
Install and
continuously
operate SCR
Install and
continuously
operate SCR
Rate
Effective Date
01/01/09
01/01/09
01/01/09
Date of entry
12/31/10
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
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
-------
Company and
Plant
Mountaineer
Muskingum
River
Picway
Rockport
Sporn
Tanners Creek
State
West Virginia
Ohio
Ohio
Indiana
West Virginia
Indiana
Unit
Unit 1
Units
1 -4
Units
Unit 9
Unit 1
Unit 2
Units
Units
1 -3
Unit 4
Settlement Actions
Ret ire /Re power
Action
Retire, retrofit,
or re- power
Retire, retrofit,
or re- power
Effective
Date
12/31/15
12/31/13
SO2 control
Equipment
Install and
continuously
operate FGD
Install and
continuously
operate FGD
Install and
continuously
operate FGD
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
Percent
Removal or
Rate
Effective
Date
12/31/07
12/31/15
12/31/17
12/31/19
Date of entry
Date of entry
NOX Contro
Equipment
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
Continuously
operate low
NOX burners
Continuously
operate over-
fire air
Rate
Effective Date
01/01/08
01/01/08
Date of entry
12/31/17
12/31/19
Date of entry
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
East Kentucky Power Cooperative Inc.
By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NQ contro s at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012.
System-wide
System-wide
12- mo nth
rolling tonnage
limits apply
12-month
rolling limit
(tons)
57,000
40,000
Start of 12-
month cycle
10/01/08
07/01/11
All units must
operate low
NOX boilers
12-month
rolling limit
(tons)
11,500
8,500
Start of 12-
month cycle
01/01/08
01/01/13
PM control
devices must
be operated
continuously
system-wide,
ESPs must be
optimized
within 270 days
of entry date,
or EKPC may
choose to
submit a PM
Pollution
Control
Upgrade
Analysis.
0.03
1 year from
entry date
AllsurplusSO2
allowances must
be surrendered
each year,
beginning in
2008.
SO2 and NOX
allowances
may not be
used to comply
with the
Consent
Decree. NOX
allowances
that would
become
available as a
result of
compliance
with the
Consent
Decree may
not be sold or
traded. SO2
and NO,,
allowances
allocated to
EKPC must be
used within the
http://www.epa.gov/complia
nce/reso u rces/cases/civ i l/c
aa/nevadapower.html
-------
Company and
Plant
Spurlock
Dale Plant
State
Kentucky
Kentucky
Unit
Unit 1
Unit 2
Unitl
Unit 2
Units
Unit 4
Unitl
Settlement Actions
Ret ire /Re power
Action
EKPC may
choose to
retire Dale 3
and 4 in lieu
of installing
controls in
Cooper 2
Effective
Date
12/31/2012
SO2 control
Equipment
Install and
continuously
operate FGD
Install and
continuously
operate FGD
by 10/1/2008
Percent
Removal or
Rate
28,000
95% or 0.1
95% or 0. 1
Effective
Date
01/01/13
6/30/2011
1/1/2009
NOX Contro
Equipment
Continuously
operate SCR
Continuously
operate SCR
and OFA
Install and
continuously
operate low
NOX burners by
10/31/2007
Install and
continuously
operate low
NOX burners by
10/31/2007
Rate
8,000
0.1 2 for
Unit 1 until
01/01/2013,
at which
point the
unit limit
drops to
0.1. Prior
to
01/01/2013,
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
Effective Date
01/01/15
60 days after
entry
60 days after
entry
01/01/08
01/01/08
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
theNOxSIP
Call. EKPC
must also
surrender
15,311 SO2
allowances.
Allowance
Restriction
Restriction
Allowances
made available
due to
supercomplian
ce may be sold
or traded.
Effective
Date
Date of entry
Reference
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/eastkentuckypower-
dale0907.html
-------
Company and
Plant
Cooper
State
Kentucky
Unit
Unit 2
Settlement Actions
Ret ire /Re power
Action
Effective
Date
SO2 control
Equipment
If EKPC opts
to install
controls rather
than retiring
Dale, it must
install and
continuously
operate FGD
orequiv.
technology
Percent
Removal or
Rate
95% or 0.10
Effective
Date
NOX Contro
Equipment
If EKPC elects
to install
controls, it
must
continuously
operate SCR
or install equiv.
technology
Rate
0.08 (or
90% if non-
SCR
technology
is used)
Effective Date
12/31/12
PM or Mercury Control
Equipment
Rate
Effective
Date
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective
Date
Nevada Power Company
Beginning 1/1/2010, combined NQ< emissions from Units 5,6,7, and 8 must be no more than 360 tons per year.
Clark Generating
Station
Nevada
Units
Unite
Unit?
Units
Units may
only fire
natural gas
ncrease 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.
Reference
http://www.epa.gov/complia
nce/resources/cases/civil/c
aa/nevadapower.html
Dayton Power & Light
Non-EPA Settlement of 10/23/2008
Stuart
Generating
Station
PSEG FOSSIL, ft
Kearny
Ohio
mended Conse
New Jersey
Station-wide
it Decree of
Unit?
Units
November 200C
Retire unit
Retire unit
01/01/07
01/01/07
Complete
installation of
FGDs on each
unit.
96% or 0.10
82% including
data from
periods of
malfunctions
82% including
data from
periods of
malfunctions
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
units ESP
07/31/09
12/31/15
Allowances
allocated to
Kearny,
Hudson, and
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
http://www.epa.gov/complia
nce/resources/decrees/ame
nded/psegfossil-amended-
cd.pdf
-------
Company and
Plant
Hudson
Mercer
Westar Energy
Jeffrey Energy
Center
Duke Energy
Gallagher
American Munic
Gorsuch Station
State
New Jersey
New Jersey
Kansas
Indiana
pal Power
Ohio
Unit
Unit 2
Units 1 &2
All units
Units 1 & 3
Units 2&4
Units 2&3
Units 1 &4
Settlement Actions
Ret ire /Re power
Action
Effective
Date
Retire or
re power as
natural gas
1/1/2012
Elected to Retire Dec 15,
2010 (must retire by Dec 31,
2012)
SO2 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
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 install FGDs by
201 1 and operate them continuously.
FGDs must ma ntain a 30-Day Rolling
Average Unit Removal Efficiency for SO2 of
at least 97% or a 30-Day Rolling Average
Unit Emission Rate for SO2 of no greater
than 0.070 Ib/MMBtu.
Install Dry
sorbent
injection
technology
80%
1/1/2012
NOX Contro
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
Units 1-3 must continuously operate Low
NOx Combustion Systems by 2012 and
achieve and ma ntain a 30-Day Rolling
Average Unit Emission Rate for NOx of no
greater than 0.1 80 Ib/MMBtu.
One of the three units must install an SCR by
2015 and operate it continuously to maintain
a 30-Day Rolling Average Unit Emission Rate
for NOx of no greater than 0.080 Ib/MMBtu.
By 2013 Westar shall elect to either (a) install
a second SCR on one of the other JEC Units
by 201 7 or (b) meet a 0.100 Ib/MMBtu Plant-
Wide 12-Month Rolling Average Emission
Rate and 9.6 MTons annual cap for NOx by
2015
PM or Mercury Control
Equipment
Install
Baghouse (or
approved
technology)
Install
Baghouse (or
approved
technology)
Rate
0.015
0.015
Effective
Date
12/31/10
12/31/10
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
Allowance
Retirement
Retirement
Mercer may only
be used for the
operational
needs of those
units, and all
surplus
allowances must
be surrendered.
Within 90 days
of amended
Consent
Decree, PSEG
must surrender
1,230 NO,
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://ampparr.ners. ora/news
roo m/amp-to- retire-go rs uch-
gene rating-station/
-------
Company and
Plant
Hoosier Energy
Ratts
Merom
Tennessee Valle
Allen Steam Plan
Bull Run
Colbert
Cumberland
Gallatin
John Sevier
Johnsonville
Kingston
Paradise
Shawnee
Widows Creek
State
Rural Electric C
Indiana
Indiana
y Authority
Tennessee
Tennessee
Alabama
Tennessee
Tennessee
Tennessee
Tennessee
Kentucky
Kentucky
Kentucky
Alabama
Unit
^operative
Units 1 &2
Unitl
Unit 2
Units 1 - 3
Unitl
Units 1 - 4
Units
Units 1 &2
Units 1 - 4
Units 1 & 2
Units 3 & 4
Units 1 - 4
Units 5- 8
Units 9 & 10
Units 1 - 9
Units 1 & 2
Units
Units 1 &4
Units 1 & 2
Units 3 & 4
Units 5 & 6
Units 7 & 8
Settlement Actions
Retire /Repower
. .. Effective
Action
Date
Retire 12/31/2012
Retire 12/31/2017
Retire 12/31/2018
Retire 12/31/2019
Retire 7/31/2013
Retire 7/31/2014
Retire 7/31/2015
SO2 control
Equipment
Percent
Removal or
Rate
Effective
Date
Continusly run
current FGD
for 90%
removal and
update FGD
for 98%
removal by
2012
Continusly run
current FGD
for 90%
removal and
update FGD
for 98%
removal by
2014
Install FGD
Operate Wet
FGD
Install FGD
Install FGD
Operate Wet
FGD
Install FGD
98%
98%
2012
2014
12/31/2015
In NEEDS
6/30/2016
12/31/2015
In NEEDS
12/31/2017
Install FGD
12/31/2015
Operate Wet
FGD
Upgrade FGD
Operate Wet
FGD
Install FGD
93%
In NEEDS
12/31/2012
In NEEDS
12/31/2017
Operate Wet
FGD
In NEEDS
NOX Contro
Equipment
Installs,
continually
operate
SNCRS
Continuously
operate
existing SCRs
Operate SCR
Operate SCR
Install SCR
Operate SCR
Operate SCR
Install SCR
Rate
0.25
0.12
Effective Date
12/31/2011
In NEEDS
In NEEDS
6/30/2016
In NEEDS
In NEEDS
12/31/2017
Install SCR
12/31/2015
Operate SCR
Operate SCR
Operate SCR
Install SCR
In NEEDS
In NEEDS
In NEEDS
12/31/2017
Operate SCR
In NEEDS
PM or Mercury Control
_ . . _ . Effective
Equipment Rate
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
Allowance
Retirement
Retirement
Allowance
Restriction
Restriction
Effective
Date
Annually surrender any NOx and SO2
allowances that Hoosier does not need in
order to meet its regulatory obligations
Reference
http://www.epa.dov/complia
nce/resources/cases/civil/c
aa/hoosier.html
Notes:
1) Updates to the EPA Base Case 4.10_FTransportfrom EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the control requirements on the Mercer plant under the PSEG Fossil
settlement, and an update to the SO2 emission modeling on Jeffrey Energy Center as part of the Westar settlement.
2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description of all elements of the actual settlement
agreements.
3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, future actions are generally modeled as individual constraints on
emission rates in EPA 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 required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place are built into EPA Base Case
5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not included in EPA Base 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 a corresponding 95% removal efficiency for wet and 90% for dry.
8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 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 requirements of the settlements as they existed on January 1, 2011.
11) Some of the NSR settlements require the retirement of SO2 allowances. For the Base Case, EPA estimate the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly.
-------
Appendix 3-4 State Settlements in EPA Base Case v4.10_FTransport
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 Efj^jjJ[Ve
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.
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