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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

# Table of Contents

Introduction .................................................................................................................. ..................... 1

Universal Comments Result ing in Model Revisions

1 Cogenerat ion Un its ......................................................................................................... .............. 2

2 NO

x 

# Rates ........................................................................................................................ ........... 35

3 SO 2 

# Removal Rates for Flue Gas Desulfurization (FGD)

........................................................... 41

4 Coal Switching

− Bituminous to S ubbituminous ......................................................................... 44

5 Restrictions on coal choice in 2012 ........................................................................................ .... 46

6 Waste Coal Co st 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 model ing assumpti ons...................................................................... 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 Filt er Cost Development in EPA Base Case

v.4.10_FTransport ............................................................................................................. ............. 55

Addendum B

─ Representation of State Electric Powe r 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_ FTrans port ........................................................................................................ ......... 67

# 1 

# Introduction

This documentation supplement describes the chan ges implemented for the Final Transport Rule

analysis in EPA’s application of the Integrated Pla nning Model (IPM), the modeling platform used by

EPA for U.S. electric power sector analysis. The changes described her e 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 versi on 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 af fecting broad categories of generating units.

Changes resulting from detailed unit level comm ents (usually pertaining to distinct operating

characteristics of specific generating units) ar e being documented separately as part of the "Transport Rule

IPM Assumptions Response To Comment s" document . EPA’s response to the universal modeling

comments and the resulting updates to the modeling pl atform are presented here in the form of a

documentation supplement for the Final Transport Rule.

This documentation supplement is organized by comm ent topic. The presentation of each comment is

divided into two sections. The first section su mmarizes 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/epaipm/BaseCasev410.html), indicating the exact model ing changes that resulted from the universal

comments. To make it easier to recognize these mark-ups, they appear on a gr ay background, visually

signaling that they are revisions of the previous documentation.

In the discussion below the following terminology is used: “EPA Base Ca se v.4.10_NODA version” 1



# refers to base case released as part of the S eptember 1, 201O 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 si gned a Notice of Propose d 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 HCl emissions and controls, a co al-to-gas retrofit opti on, and updated assumptions

for activated carbon injection for mercury control). These capabilities were also incorporated in the

modeling for the Final Transport Rule. However, onl y 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 SO 2 

# (and HCl) 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 thro ugh 3-4 of the documentation supplement for the

Proposed MATS (also found in Addendum B in th is 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, addi tional NSR settlements with Northern Indiana

Public Service Company ( www.epa.gov/compliance/resource s/cases/civil/caa/nipsco.html , January 13,

2011) and the Tennessee Valley Authority ( www.epa.gov/compliance/resources/cases/civil/caa/tvacoalfired.html , April 14, 2011) were announced. For the 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_Ptox – Up dates for Proposed Toxics Rule, which is available for viewing and

downloading at www.epa.gov/airmarkets/p rogsregs/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 wh at is now called “EPA Ba se Case v.4.10 NODA

version”

# 2 

# 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 electricit y (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 t he steam and electric portion of their operation.

However, dispatch decisions in IPM are only based on t he 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 t he net heat rate can be considerably lower than

the gross heat rate, this revision should increase t he extent that cogeneration units are operated. At the

same time, since emissions from both the electric a nd 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 wi th the emissions multiplier should correct the

observation of low cogeneration operations and emissi ons 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 reflec t the extent of their operation and emissions. In

particular, the following revisions were made.

(1) In the draft base case, gross heat rates had be en assigned to cogeneration units. That is, the heat

rates (efficiency) of cogeneration units were calcul ated 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 le ss 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 fo r cogeneration units in the base case for the final

Transport Rule, cogenerati on units are allowed to dispatch up to the availabilities assumed for the

particular generation technology or up to their hi storic 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 ma ximum reported capacity factors is below 15%, a

capacity factor of 15% is used as a limit, since hi storical capacity factor values below 15% are not

considered to reflect the generat ion capability of the unit.

(3) Even though the dispatch of coge neration 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 Trans port Rule analysis in EPA Base

Case v4.10_FTransport.

# 3 Add the following appendix at the end of Chapter 3: 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 assu med for the particular generation technology or up to

their historic capacity factors (der ived by taking the maximum historic al 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 us ed 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 de cisions in IPM are only based on the heat rate

efficiency of the electric portion of a cogenerati on 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 t he 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).” T he gross heat rates appear in the column labeled

“NODA Heat Rate (Btu/kWh).” Si nce the net heat rate cannot exc eed 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 betwe en the NODA and postNODA period. Such instances are highl ighted and explained in Appendix 3-10.4Appendix3‐10.CogenerationUnits‐HeatRates(BeforeandAfterNODAComments),CapacityFactorUpperBounds,andEmissionMultipliers=HigherPost‐NODAHeatRateDuetoHigherReportedValueinAEO2010thaninAEO2008=HigherPost‐NODAHeatRateBasedonNODAComment=HigherPost‐NODAHeatRateBasedonNetHeatRateReportedinEIAForm923PlantNameUniqueID_FinalPlantTypeRegionNameCapacity(MW)NODAHeatRate(Btu/kWh)Post‐NODAHeatRate(Btu/kWh)EmissionsMultiplier2012CapacityFactorUpperBoundImplementedACECogenerationFacility10002_B_CFBCoalSteamCA‐S10110921105261.0489.70TrigenColoradoEnergy10003_B_BLR1O/GSteamRMPA8.11197283001.4489.51TrigenColoradoEnergy10003_B_BLR2O/GSteamRMPA8.11196483001.4489.51TrigenColoradoEnergy10003_B_BLR3CoalSteamRMPA8.11033183001.2486.40TrigenColoradoEnergy10003_B_BLR4CoalSteamRMPA8.11033183001.2486.40TrigenColoradoEnergy10003_B_BLR5CoalSteamRMPA8.11176883001.4286.40BaptistMedicalCenter10008_G_CG‐3ICEngineFRCC0.5013298131991.0089.24BaptistMedicalCenter10008_G_TG‐1CombustionTurbineFRCC2.315981158451.0089.24BaptistMedicalCenter10008_G_TG‐2CombustionTurbineFRCC2.21598187001.8289.24BaptistMedicalCenter10008_G_TG‐3CombustionTurbineFRCC2.71598187001.8289.24BaptistMedicalCenter10008_G_TG‐4CombustionTurbineFRCC3.21250387001.4389.24NRGEnergyCenterDover10030_B_COGEN1CoalSteamMACE16.011782117821.0075.40GreaterDetroitResourceRecovery10033_B_11MunicipalSolidWasteMECS21.21933883001.9652.47GreaterDetroitResourceRecovery10033_B_12MunicipalSolidWasteMECS21.21933883001.9652.47GreaterDetroitResourceRecovery10033_B_13MunicipalSolidWasteMECS21.21933883001.9652.47GilroyPowerPlant10034_G_GEN1CombinedCycleCA‐N90.0833083731.0084.63GilroyPowerPlant10034_G_GEN2CombinedCycleCA‐N40.0833083731.0084.63LoganGeneratingPlant10043_B_B01CoalSteamMACE219989098901.0083.80CentralUtilitiesPlantLAX10048_G_GEN1CombustionTurbineCA‐S4.01598187001.8289.24CentralUtilitiesPlantLAX10048_G_GEN2CombustionTurbineCA‐S4.01598187001.8289.24CogentrixVirginiaLeasingCorporation10071_B_1ACoalSteamVAPW19.211354108881.0474.60CogentrixVirginiaLeasingCorporation10071_B_1BCoalSteamVAPW19.210331103201.0074.60CogentrixVirginiaLeasingCorporation10071_B_1CCoalSteamVAPW19.210331103201.0074.605CogentrixVirginiaLeasingCorporation10071_B_2ACoalSteamVAPW19.211353108881.0474.60CogentrixVirginiaLeasingCorporation10071_B_2BCoalSteamVAPW19.210331103201.0074.60CogentrixVirginiaLeasingCorporation10071_B_2CCoalSteamVAPW19.210331103201.0074.60PedricktownCogenPlant10099_G_GEN1CombinedCycleMACE79.2835079161.0084.63PedricktownCogenPlant10099_G_GEN2CombinedCycleMACE36.5835079161.0084.63Frito‐LayCogenPlant10110_G_GEN1CombustionTurbineCA‐N5.115981158451.0089.24JohnBRichMemorialPowerStation10113_B_CFB1CoalSteamMACW40.01119083001.3595.00JohnBRichMemorialPowerStation10113_B_CFB2CoalSteamMACW40.01033183001.2495.00HarrisburgFacility10118_B_1MunicipalSolidWasteMACW6.91933883002.3388.41HarrisburgFacility10118_B_2MunicipalSolidWasteMACW6.91933883002.3388.41HarrisburgFacility10118_B_3MunicipalSolidWasteMACW6.91933883002.3388.41IndianaUniversityofPennsylvania10129_G_GEN1ICEngineMACW6.01329894801.3989.24IndianaUniversityofPennsylvania10129_G_GEN2ICEngineMACW6.01329894801.3989.24IndianaUniversityofPennsylvania10129_G_GEN3ICEngineMACW6.01329894801.3989.24IndianaUniversityofPennsylvania10129_G_GEN4ICEngineMACW6.01329894801.3989.24SierraPacificLincolnFacility10144_G_GEN4BiomassCA‐N17.21551783001.8983.00FresnoCogenPartners10156_G_GEN2CombinedCycleCA‐N6.0765185941.0915.00FresnoCogenPartners10156_G_GEN3CombinedCycleCA‐N21.9765185941.0915.00FresnoCogenPartners10156_G_GEN4CombinedCycleCA‐N45.0765185941.0915.00CardinalCogen10168_G_GTG1CombinedCycleCA‐N32.5993997381.0084.63CardinalCogen10168_G_STG1CombinedCycleCA‐N9.4993997381.0084.63CarsonCogeneration10169_G_GEN1CombinedCycleCA‐S41.3899485571.0184.63CarsonCogeneration10169_G_GEN2CombinedCycleCA‐S8.0899485571.0184.63MetroWastewaterReclamationDistrict10180_G_1Non‐FossilWasteRMPA1.21428387001.6477.35MetroWastewaterReclamationDistrict10180_G_2Non‐FossilWasteRMPA1.21428387001.6477.35MetroWastewaterReclamationDistrict10180_G_3Non‐FossilWasteRMPA1.21428387001.6477.35MetroWastewaterReclamationDistrict10180_G_4Non‐FossilWasteRMPA1.21428387001.6477.35MetroWastewaterReclamationDistrict10180_G_5Non‐FossilWasteRMPA2.51000087001.1577.35MetroWastewaterReclamationDistrict10180_G_6Non‐FossilWasteRMPA2.51000087001.1577.35CentralUtilityPlant10184_G_EG1ICEngineERCT4.313298131991.0089.24CentralUtilityPlant10184_G_EG2ICEngineERCT3.213298131991.0089.24CentralUtilityPlant10184_G_TG1O/GSteamERCT0.2311425100361.1189.51IMCPhosphatesCompanyUncleSam10198_G_GEN1Non‐FossilWasteENTG10.21310298541.3075.66IMCPhosphatesCompanyUncleSam10198_G_GEN2Non‐FossilWasteENTG10.21310298541.3075.66HerculesMissouriChemicalWorks10207_B_1CoalSteamGWAY5.71250883001.4985.26HerculesMissouriChemicalWorks10207_B_2CoalSteamGWAY5.71250883001.4985.26HerculesMissouriChemicalWorks10207_B_3CoalSteamGWAY5.71250883001.4985.26SnowbirdPowerPlant10215_G_1367ICEngineNWPE0.591329887001.5289.24SnowbirdPowerPlant10215_G_1391ICEngineNWPE0.591329887001.5289.24SnowbirdPowerPlant10215_G_1392ICEngineNWPE0.591329887001.5289.24AlabamaRiverPulp10216_B_PB1BiomassSOU22.31551783001.8983.006AlabamaRiverPulp10216_B_RB1Non‐FossilWasteSOU22.31310283001.5455.17LeafRiverCelluloseLLC10233_B_PBBiomassSOU37.51551783001.8983.00LeafRiverCelluloseLLC10233_B_RBNon‐FossilWasteSOU12.51310283001.5455.17KingCityPowerPlant10294_G_GTGCombinedCycleCA‐N73.0799079901.0084.63KingCityPowerPlant10294_G_STGCombinedCycleCA‐N38.0799079901.0084.63BayouCogenPlant10298_G_GEN1CombustionTurbineERCT65.01598187001.8290.81BayouCogenPlant10298_G_GEN2CombustionTurbineERCT65.01598187001.8290.81BayouCogenPlant10298_G_GEN3CombustionTurbineERCT65.01598187001.8290.81BayouCogenPlant10298_G_GEN4CombustionTurbineERCT65.01598187001.8290.81BellinghamCogenerationFacility10307_G_CT1CombinedCycleNENG102830079531.0422.19BellinghamCogenerationFacility10307_G_CT2CombinedCycleNENG102830079531.0422.19BellinghamCogenerationFacility10307_G_ST1CombinedCycleNENG60.0830079531.0422.19SayrevilleCogenerationFacility10308_G_CT1CombinedCycleMACE98.0865082001.0084.63SayrevilleCogenerationFacility10308_G_CT2CombinedCycleMACE98.0865082001.0084.63SayrevilleCogenerationFacility10308_G_ST1CombinedCycleMACE75.0865082001.0084.63CentralPower&Lime10333_B_1CoalSteamFRCC13910896103271.0660.53FosterWheelerMartinez10342_G_TG1CombinedCycleCA‐N35.0860082661.1384.63FosterWheelerMartinez10342_G_TG2CombinedCycleCA‐N35.0860082661.1384.63FosterWheelerMartinez10342_G_TG3CombinedCycleCA‐N33.5860082661.1384.63FosterWheelerMtCarmelCogen10343_B_SG‐101CoalSteamMACW43.012500118451.0690.10CharlestonResourceRecoveryFacility10344_B_B1MunicipalSolidWasteVACA4.81933895871.7089.39CharlestonResourceRecoveryFacility10344_B_B2MunicipalSolidWasteVACA4.81933895871.7089.39Greenleaf2PowerPlant10349_G_GEN1CombustionTurbineCA‐N49.51057887001.2290.81Greenleaf1PowerPlant10350_G_GEN1CombinedCycleCA‐N42.0829061811.4966.10Greenleaf1PowerPlant10350_G_GEN2CombinedCycleCA‐N8.0829061811.4966.10CogentrixHopewell10377_B_1ACoalSteamVAPW18.21033191941.1283.40CogentrixHopewell10377_B_1BCoalSteamVAPW18.21136091941.2483.40CogentrixHopewell10377_B_1CCoalSteamVAPW18.21033191941.1283.40CogentrixHopewell10377_B_2ACoalSteamVAPW18.21135991941.2483.40CogentrixHopewell10377_B_2BCoalSteamVAPW18.21033191941.1283.40CogentrixHopewell10377_B_2CCoalSteamVAPW18.21033191941.1283.40PrimaryEnergySouthport10378_B_1ACoalSteamVACA17.811362113621.0041.34PrimaryEnergySouthport10378_B_1BCoalSteamVACA17.810331103201.0041.34PrimaryEnergySouthport10378_B_1CCoalSteamVACA17.810331103201.0041.34PrimaryEnergySouthport10378_B_2ACoalSteamVACA17.811361113611.0041.34PrimaryEnergySouthport10378_B_2BCoalSteamVACA17.810331103201.0041.34PrimaryEnergySouthport10378_B_2CCoalSteamVACA17.810331103201.0041.34PrimaryEnergyRoxboro10379_B_1ACoalSteamVACA18.711362113621.0083.00PrimaryEnergyRoxboro10379_B_1BCoalSteamVACA18.710331103201.0083.00PrimaryEnergyRoxboro10379_B_1CCoalSteamVACA18.710331103201.0083.00ElizabethtownPowerLLC10380_B_ABLRCoalSteam16.0NotindB111131.0541.347ElizabethtownPowerLLC10380_B_BBLRCoalSteam16.0NotindB111131.0541.34GreenPowerKenansville10381_B_1ABiomassVACA16.211564114981.3783.00GreenPowerKenansville10381_B_1BBiomassVACA16.215517114981.3783.00Lumberton10382_B_UNIT1CoalSteam16.0NotindB112471.0415.00Lumberton10382_B_UNIT2CoalSteam16.0NotindB112471.0415.00EdgecombeGenCo10384_B_1ACoalSteamVAPW28.911325110621.0290.00EdgecombeGenCo10384_B_1BCoalSteamVAPW28.910331103201.0090.00EdgecombeGenCo10384_B_2ACoalSteamVAPW28.911325110621.0290.00EdgecombeGenCo10384_B_2BCoalSteamVAPW28.910331103201.0090.00LittleCompanyofMaryHospital10400_G_GEN1CombustionTurbineCOMD3.21598187001.8289.24LaidlawEnergy&Environmental10403_G_ALLICombinedCycleUPNY2.611860118601.0084.63LaidlawEnergy&Environmental10403_G_CAT3ICEngineUPNY0.4011100111001.0089.24LaidlawEnergy&Environmental10403_G_CAT4ICEngineUPNY0.4011100111001.0089.24LaidlawEnergy&Environmental10403_G_WESTCombinedCycleUPNY0.7011860118601.0084.63KingsburgCogen10405_G_GEN1CombinedCycleCA‐N22.0983284921.0084.63KingsburgCogen10405_G_GEN2CombinedCycleCA‐N11.8983284921.0084.63InlandOntarioMill10427_G_GEN1CombustionTurbineCA‐S34.015981158451.0089.87WisconsinRapidsPulpMill10477_B_P1CoalSteamWUMS11.21033183001.2485.26WisconsinRapidsPulpMill10477_B_P2CoalSteamWUMS11.21033183001.2485.26WisconsinRapidsPulpMill10477_B_P3O/GSteamWUMS11.21133283001.3992.41WisconsinRapidsPulpMill10477_B_R1Non‐FossilWasteWUMS11.21310283001.5475.66WisconsinRapidsPulpMill10477_B_R2Non‐FossilWasteWUMS11.21310283001.5475.66WisconsinRapidsPulpMill10477_B_R3Non‐FossilWasteWUMS11.21310283001.5475.66PitchessCogenStation10478_G_GEN1CombinedCycleCA‐S21.51021167161.6884.63PitchessCogenStation10478_G_GEN2CombinedCycleCA‐S5.71021167161.6884.63RumfordCogeneration10495_B_6CoalSteamNENG42.51105883001.3394.10RumfordCogeneration10495_B_7CoalSteamNENG42.51033183001.2494.10KernRiverCogeneration10496_G_GTAGCombustionTurbineCA‐N72.01650987001.9090.81KernRiverCogeneration10496_G_GTBGCombustionTurbineCA‐N72.01650987001.9090.81KernRiverCogeneration10496_G_GTCGCombustionTurbineCA‐N72.01650987001.9090.81KernRiverCogeneration10496_G_GTDGCombustionTurbineCA‐N72.01650987001.9090.81Mid‐SetCogeneration10501_G_K100CombustionTurbineCA‐N36.01550687001.7889.87SanJoseCogeneration10548_G_GEN1CombustionTurbineCA‐N5.615981116401.3689.24ChambersCogenerationLP10566_B_BOIL1CoalSteamMACE13110000100001.0074.80ChambersCogenerationLP10566_B_BOIL2CoalSteamMACE13110331100791.0274.80AlgonquinWindsorLocks10567_G_GTGCombinedCycleNENG26.01018671061.3084.63AlgonquinWindsorLocks10567_G_STGCombinedCycleNENG12.01018671061.3084.63SixthStreet1058_B_2CoalSteam13.6NotindB125511.0035.53SixthStreet1058_B_3CoalSteam13.6NotindB145001.0035.53SixthStreet1058_B_4CoalSteam13.6NotindB145001.0035.53SixthStreet1058_B_5CoalSteam13.6NotindB145001.0035.538BPWilmingtonCalciner10601_G_GEN1CoalSteamCA‐S29.01033198541.0585.26EbensburgPower10603_B_031CoalSteamMACW49.512500125001.0095.00Domtar‐WoodlandMill10613_B_3RBO/GSteamNENG23.01184483001.3986.60Domtar‐WoodlandMill10613_B_9PBBiomassNENG23.01551783001.8983.00CHResourcesBeaverFalls10617_G_GEN1CombinedCycleUPNY52.5870087001.0084.63CHResourcesBeaverFalls10617_G_GEN2CombinedCycleUPNY34.0870087001.0084.63CivicCenter10623_G_GEN1CombinedCycleCA‐S18.5993985771.1484.63CivicCenter10623_G_GEN2CombinedCycleCA‐S1.2993985771.1484.63WheelabratorBaltimoreRefuse10629_B_BLR1MunicipalSolidWasteMACS20.419338162971.0090.00WheelabratorBaltimoreRefuse10629_B_BLR2MunicipalSolidWasteMACS20.419338162971.0090.00WheelabratorBaltimoreRefuse10629_B_BLR3MunicipalSolidWasteMACS20.419338162971.0090.00HopewellCogeneration10633_G_GT1CombinedCycle84.1NotindB82921.0927.40HopewellCogeneration10633_G_GT2CombinedCycle84.1NotindB82921.0927.40HopewellCogeneration10633_G_GT3CombinedCycle84.1NotindB82921.0927.40HopewellCogeneration10633_G_ST1CombinedCycle96.0NotindB82921.0927.40CoronaCogen10635_G_GEN1CombustionTurbineCA‐S40.01572787001.8189.87CambriaCogen10641_B_B1CoalSteamMACW44.011076122001.0095.00CambriaCogen10641_B_B2CoalSteamMACW44.010331122001.0095.00BearMountainCogen10649_G_GEN1CombustionTurbineCA‐N46.01322587001.5289.87BadgerCreekCogen10650_G_GEN1CombustionTurbineCA‐N46.01322587001.5289.87BurneyForestProducts10652_B_BLR1BiomassCA‐N15.515517157161.0083.00BurneyForestProducts10652_B_BLR2BiomassCA‐N15.515517157161.0083.00SierraPacificSonora54517_G_GEN2BiomassCA‐N5.51551783001.8983.00AESDeepwater10670_B_AAB001CoalSteamERCT14014500118011.2385.26AESShadyPoint10671_B_1ACoalSteamSPPS80.010471104711.0080.90AESShadyPoint10671_B_1BCoalSteamSPPS80.010331103201.0080.90AESShadyPoint10671_B_2ACoalSteamSPPS80.010469104691.0080.90AESShadyPoint10671_B_2BCoalSteamSPPS80.010331103201.0080.90CedarBayGeneratingLP10672_B_CBACoalSteamFRCC83.3950493751.0182.80CedarBayGeneratingLP10672_B_CBBCoalSteamFRCC83.31033193751.1082.80CedarBayGeneratingLP10672_B_CBCCoalSteamFRCC83.31033193751.1082.80AESThames10675_B_ACoalSteamNENG90.51017394911.0794.10AESThames10675_B_BCoalSteamNENG90.51033194911.0994.10AESBeaverValleyPartnersBeaverValley10676_B_2CoalSteamRFCP43.011621109101.0772.07AESBeaverValleyPartnersBeaverValley10676_B_3CoalSteamRFCP43.012508109101.1472.07AESBeaverValleyPartnersBeaverValley10676_B_4CoalSteamRFCP43.012508109101.1472.07AESBeaverValleyPartnersBeaverValley10676_B_5CoalSteamRFCP17.012508109101.1472.07AESPlacerita10677_G_UNT1CombinedCycleCA‐S46.0990098941.0084.63AESPlacerita10677_G_UNT2CombinedCycleCA‐S46.0990098941.0084.63AESPlacerita10677_G_UNT3CombinedCycleCA‐S23.0990098941.0084.63AESWarriorRunCogenerationFacility10678_B_BLR1CoalSteamRFCP18011177105771.0692.309ColoradoPowerPartners10682_G_GT1CombinedCycleRMPA25.01186088411.3425.35ColoradoPowerPartners10682_G_GT2CombinedCycleRMPA25.01186088411.3425.35ColoradoPowerPartners10682_G_ST1CombinedCycleRMPA30.01186088411.3425.35BCP10683_G_GT3CombinedCycleRMPA32.01186098851.0084.63BCP10683_G_ST2CombinedCycleRMPA40.01186098851.0084.63ArgusCogenPlant10684_B_BLR25CoalSteamCA‐S25.01033183001.2485.26ArgusCogenPlant10684_B_BLR26CoalSteamCA‐S25.01033183001.2485.26WestendFacility10685_G_PINACombustionTurbineCA‐S15.01598187001.8289.24RapidsEnergyCenter10686_B_5BiomassMRO11.215517131791.1983.00RapidsEnergyCenter10686_B_6BiomassMRO11.220328131791.5483.00RapidsEnergyCenter10686_B_7O/GSteamMRO3.514500115111.0092.41RapidsEnergyCenter10686_B_8O/GSteamMRO3.511332115111.0092.41JacksonCountyResourceRecovery10722_G_1MunicipalSolidWasteMECS3.01933883002.3352.47SelkirkCogen10725_G_GEN1CombinedCycleDSNY72.6886181091.1663.58SelkirkCogen10725_G_GEN2CombinedCycleDSNY9.2886181091.1663.58SelkirkCogen10725_G_GEN3CombinedCycleDSNY79.7886181091.1663.58SelkirkCogen10725_G_GEN4CombinedCycleDSNY79.7886181091.1663.58SelkirkCogen10725_G_GEN5CombinedCycleDSNY124886181091.1663.58Masspower10726_G_GEN1CombinedCycleNENG82.2822485071.0126.13Masspower10726_G_GEN2CombinedCycleNENG82.2822485071.0126.13PrairieCreek1073_B_1CoalSteamMRO9.111595115951.0052.20PrairieCreek1073_B_2CoalSteamMRO10.212230122301.0052.20PrairieCreek1073_B_3CoalSteamMRO41.611090110901.0052.20PrairieCreek1073_B_4CoalSteamMRO12510198101981.0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EN3CombustionTurbineCA‐N22.0993987001.1427.74WestmorelandRoanokeValleyI54035_B_BLR1CoalSteamVAPW1651037091091.1490.70LockportEnergyAssociatesLP54041_G_GEN1CombinedCycleUPNY45.0909174281.1647.49LockportEnergyAssociatesLP54041_G_GEN2CombinedCycleUPNY45.0909174281.1647.49LockportEnergyAssociatesLP54041_G_GEN3CombinedCycleUPNY45.0909174281.1647.49LockportEnergyAssociatesLP54041_G_GEN4CombinedCycleUPNY75.2909174281.1647.49WytheParkPowerPetersburgPlant54045_G_1FossilWasteVAPW3.01232093161.326.17WytheParkPower3RichmondPlant54047_G_EXISICEngineVAPW3.01228390001.3689.24PawtucketPowerAssociates54056_G_GEN1CombinedCycleNENG36.0895089081.0084.63PawtucketPowerAssociates54056_G_GEN2CombinedCycleNENG27.0895089081.0084.63IndeckOleanEnergyCenter54076_G_GEN1CombinedCycleUPNY31.9874086261.0084.63IndeckOleanEnergyCenter54076_G_GEN2CombinedCycleUPNY44.6874086261.0084.63CogentrixofRichmond54081_B_1ACoalSteamVAPW26.31130392581.2271.07CogentrixofRichmond54081_B_1BCoalSteamVAPW26.31033192581.1171.07CogentrixofRichmond54081_B_2ACoalSteamVAPW26.31130392581.2271.07CogentrixofRichmond54081_B_2BCoalSteamVAPW26.31033192581.1171.07CogentrixofRichmond54081_B_3ACoalSteamVAPW21.31130092581.2271.07CogentrixofRichmond54081_B_3BCoalSteamVAPW21.31033192581.1171.07CogentrixofRichmond54081_B_4ACoalSteamVAPW21.31130092581.2271.07CogentrixofRichmond54081_B_4BCoalSteamVAPW21.31033192581.1171.07KennedyInternationalAirportCogen54114_G_GEN1CombinedCycleNYC49.01031580331.2849.51KennedyInternationalAirportCogen54114_G_GEN2CombinedCycleNYC50.31031580331.2849.51KennedyInternationalAirportCogen54114_G_GEN3CombinedCycleNYC27.01031580331.2849.51FortistarNorthTonawanda54131_G_GEN1CombinedCycleUPNY40.4780078151.1515.00FortistarNorthTonawanda54131_G_GEN2CombinedCycleUPNY16.3780078151.1515.00FultonCogenerationAssociates54138_G_GTGCombustionTurbineUPNY42.012503124771.0089.87StonyBrookCogenPlant54149_G_GEN1CombustionTurbineLILC44.51208287001.3989.8723FranklinHeatingStation54224_B_GEN6CoalSteamMRO2.810331103201.0085.26FranklinHeatingStation54224_B_SG1O/GSteamMRO11478983001.7289.51FranklinHeatingStation54224_B_SG2O/GSteamMRO11478983001.7289.51FranklinHeatingStation54224_B_SG3O/GSteamMRO4.11478983001.7289.51FranklinHeatingStation54224_B_SG4O/GSteamMRO4.11478983001.7289.51FranklinHeatingStation54224_G_EG1ICEngineMRO2.012334120621.0089.24FranklinHeatingStation54224_G_EG2ICEngineMRO2.012334120621.0089.24FranklinHeatingStation54224_G_EG3ICEngineMRO2.012334120621.0089.24PortofStocktonDistrictEnergyFac54238_B_N64514CoalSteamCA‐N22.011465114651.0069.73PortofStocktonDistrictEnergyFac54238_B_N64516CoalSteamCA‐N22.010331103201.0069.73MarchPointCogeneration54268_G_GTG1CombinedCyclePNW39.61150060961.8258.62MarchPointCogeneration54268_G_GTG2CombinedCyclePNW40.01150060961.8258.62MarchPointCogeneration54268_G_GTG3CombinedCyclePNW40.61150060961.8258.62MarchPointCogeneration54268_G_STG1CombinedCyclePNW26.01150060961.8258.62SaguaroPower54271_G_CTG1CombinedCycleSNV35.0920092001.0084.63SaguaroPower54271_G_CTG2CombinedCycleSNV35.0920092001.0084.63SaguaroPower54271_G_STGCombinedCycleSNV22.0920092001.0084.63BirchwoodPower54304_B_1ACoalSteamVAPW2391006796691.0465.54GoodyearBeaumontChemicalPlant54321_B_3B101O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B102O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B103O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B104O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B105O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B106O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B107O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_B_3B108O/GSteamENTG1.61142583001.3592.41GoodyearBeaumontChemicalPlant54321_G_2N80CombustionTurbineENTG4.01250387001.4389.24GoodyearBeaumontChemicalPlant54321_G_N802CombustionTurbineENTG4.01250387001.4389.24GoodyearBeaumontChemicalPlant54321_G_N803CombustionTurbineENTG4.01250387001.4389.24GoodyearBeaumontChemicalPlant54321_G_N804CombustionTurbineENTG4.01250387001.4389.24BucknellUniversity54333_G_G001CombinedCycleMACW4.3793379421.0084.63BucknellUniversity54333_G_G502CombinedCycleMACW0.50793379421.0084.63NevadaCogenAssociates2BlackMountain54349_G_GTACombinedCycleSNV21.7713266001.3684.63NevadaCogenAssociates2BlackMountain54349_G_GTBCombinedCycleSNV21.7713266001.3684.63NevadaCogenAssociates2BlackMountain54349_G_GTCCombinedCycleSNV21.7713266001.3684.63NevadaCogenAssociates2BlackMountain54349_G_STMCombinedCycleSNV19.9713266001.3684.63NevadaCogenAssoc#1GarnetVly54350_G_GTACombinedCycleSNV21.71018273161.2284.63NevadaCogenAssoc#1GarnetVly54350_G_GTBCombinedCycleSNV21.71018273161.2284.63NevadaCogenAssoc#1GarnetVly54350_G_GTCCombinedCycleSNV21.71018273161.2284.63NevadaCogenAssoc#1GarnetVly54350_G_STMCombinedCycleSNV19.91018273161.2284.63OrangeCogenerationFacility54365_G_APC1CombinedCycleFRCC46.4899973801.1640.1524OrangeCogenerationFacility54365_G_APC2CombinedCycleFRCC46.4899973801.1640.15OrangeCogenerationFacility54365_G_APC3CombinedCycleFRCC24.6899973801.1640.15OildaleCogen54371_G_ODC1CombustionTurbineCA‐N39.01646387001.8989.87UniversityofColorado54372_G_GT1CombinedCycleRMPA15.0793371641.1115.00UniversityofColorado54372_G_GT2CombinedCycleRMPA15.0793371641.1115.00UniversityofColorado54372_G_ST1CombinedCycleRMPA1793371641.1115.00SouthbridgeEnergyCenterLLC54373_G_ENG1ICEngineNENG1.31160091061.2389.24SouthbridgeEnergyCenterLLC54373_G_ENG2ICEngineNENG1.31160091061.2389.24SouthbridgeEnergyCenterLLC54373_G_ENG3ICEngineNENG1.31160091061.2389.24SouthbridgeEnergyCenterLLC54373_G_ENG4ICEngineNENG1.31160091061.2389.24SouthbridgeEnergyCenterLLC54373_G_ENG5ICEngineNENG1.31160091061.2389.24CapitolHeatandPower54406_G_1CoalSteamWUMS0.901033183001.2485.26CapitolHeatandPower54406_G_2CoalSteamWUMS11033183001.2485.26DAIOildale54410_G_CTGCombinedCycleCA‐N22.6793379421.0084.63DAIOildale54410_G_STGCombinedCycleCA‐N7.3793379421.0084.63LakeCogenLtd54423_G_GT1CombinedCycleFRCC41.5755074471.1449.56LakeCogenLtd54423_G_GT2CombinedCycleFRCC41.5755074471.1449.56LakeCogenLtd54423_G_ST1CombinedCycleFRCC27.0755074471.1449.56PascoCogenLtd54424_G_GT1CombinedCycleFRCC48.8770177841.0643.15PascoCogenLtd54424_G_GT2CombinedCycleFRCC48.8770177841.0643.15PascoCogenLtd54424_G_ST1CombinedCycleFRCC31.2770177841.0643.15ProjectOrangeAssociatesLP54425_G_GT1CombustionTurbineUPNY48.01250387001.4389.87ProjectOrangeAssociatesLP54425_G_GT2CombustionTurbineUPNY48.01250387001.4389.87MulberryCogenerationFacility54426_G_GT1CombinedCycleFRCC76.0852081041.0241.67MulberryCogenerationFacility54426_G_ST1CombinedCycleFRCC37.0852081041.0241.67AlabamaPinePulp54429_B_PB2BiomassSOU32.11551783001.8983.00AlabamaPinePulp54429_B_RB2Non‐FossilWasteSOU32.11310283001.5455.17RinconFacility54445_G_GEN1CombustionTurbineCA‐S1.712503Retired0.00WelportLeaseProject54447_G_TICombustionTurbineCA‐N4.51250388821.4089.24DomeProject54449_G_T1CombustionTurbineCA‐N3.31598187001.8289.24DomeProject54449_G_T2CombustionTurbineCA‐N3.21598187001.8289.24OrlandoCogenLP54466_G_GEN1CombinedCycleFRCC120996078821.2684.63SumasPowerPlant54476_G_GEN1CombinedCyclePNW87.8812072621.1420.82SumasPowerPlant54476_G_GEN2CombinedCyclePNW37.7812072621.1420.82OrovilleCogenerationLP54477_G_GEN1ICEngineCA‐N1.111600111851.0089.24OrovilleCogenerationLP54477_G_GEN2ICEngineCA‐N1.111600111851.0089.24OrovilleCogenerationLP54477_G_GEN3ICEngineCA‐N1.111600111851.0089.24OrovilleCogenerationLP54477_G_GEN4ICEngineCA‐N1.111600111851.0089.24OrovilleCogenerationLP54477_G_GEN5ICEngineCA‐N1.111600111851.0089.24OrovilleCogenerationLP54477_G_GEN6ICEngineCA‐N1.111600111851.0089.24OrovilleCogenerationLP54477_G_GEN7ICEngineCA‐N1.111600111851.0089.2425STEC‐SLLC56079_B_SouthBiomassENTG2.015517145001.0883.00FormosaPlastics54518_G_GT1CombinedCycleENTG33.08648Retired0.00FormosaPlastics54518_G_GT2CombinedCycleENTG33.0864885821.0084.63FormosaPlastics54518_G_GT3CombinedCycleENTG33.0864885821.0084.63FormosaPlastics54518_G_ST1CombinedCycleENTG8.0864885821.0084.63FormosaPlastics54518_G_ST2CombinedCycleENTG8.0864885821.0084.63LyonsdaleBiomassLLC54526_B_00001BiomassUPNY19.015517132011.1983.00TenaskaFerndaleCogenerationStation54537_G_CT1ACombinedCyclePNW88.01126075761.1036.93TenaskaFerndaleCogenerationStation54537_G_CT1BCombinedCyclePNW88.01126075761.1036.93TenaskaFerndaleCogenerationStation54537_G_ST1CombinedCyclePNW95.01126075761.1036.93EntenmannsEnergyCenter54541_G_1ICEngineLILC1.31270387001.4689.24EntenmannsEnergyCenter54541_G_2ICEngineLILC1.31270387001.4689.24EntenmannsEnergyCenter54541_G_3ICEngineLILC1.31270387001.4689.24EntenmannsEnergyCenter54541_G_4ICEngineLILC1.31278487001.4789.24SitheIndependenceStation54547_G_1CombinedCycleUPNY144741869841.1233.74SitheIndependenceStation54547_G_2CombinedCycleUPNY144741869841.1233.74SitheIndependenceStation54547_G_3CombinedCycleUPNY144741869841.1233.74SitheIndependenceStation54547_G_4CombinedCycleUPNY144741869841.1233.74SitheIndependenceStation54547_G_5CombinedCycleUPNY204741869841.1233.74SitheIndependenceStation54547_G_6CombinedCycleUPNY204741869841.1233.74ExxonMobilMobileBayOnshore54550_G_901CombinedCycleSOU0.90793379421.0084.63ExxonMobilMobileBayOnshore54550_G_901ACombinedCycleSOU3.4793379421.0084.63ExxonMobilMobileBayOnshore54550_G_901BCombinedCycleSOU3.4793379421.0084.63ExxonMobilMobileBayOnshore54550_G_901CCombinedCycleSOU3.4793379421.0084.63JeffersonSmurfitSantaClaraMill54561_G_GT‐GCombinedCycleCA‐N23.0978057641.7284.63JeffersonSmurfitSantaClaraMill54561_G_ST‐GCombinedCycleCA‐N3.0978057641.7284.63NorthEastCogenerationPlant54571_G_GEN1CombinedCycleMACW36.5916367471.3615.00NorthEastCogenerationPlant54571_G_GEN2CombinedCycleMACW36.5916367471.3615.00NorthEastCogenerationPlant54571_G_GEN3CombinedCycleMACW8.0916367471.3615.00SaranacFacility54574_G_GEN1CombinedCycleUPNY78.0861673991.1984.63SaranacFacility54574_G_GEN2CombinedCycleUPNY77.0861673991.1984.63SaranacFacility54574_G_GEN3CombinedCycleUPNY85.0861673991.1984.63GlennsFerryCogenFacility54578_G_1001CombinedCyclePNW10.4980084701.0084.68RupertCogenProject54579_G_1002CombinedCycleNWPE10.4980063241.2771.01BataviaPowerPlant54593_G_GEN1CombinedCycleUPNY38.2877174401.1215.00BataviaPowerPlant54593_G_GEN2CombinedCycleUPNY17.5877174401.1215.00MtPosoCogeneration54626_B_BL01CoalSteamCA‐N52.011384112991.1983.00OkeelantaCogeneration54627_B_ABiomassFRCC25.01551789041.7783.00OkeelantaCogeneration54627_B_BBiomassFRCC25.01551789041.7783.00OkeelantaCogeneration54627_B_CBiomassFRCC25.01551789041.7783.00OkeelantaCogeneration54627_G_GEN2BiomassFRCC74.91551789041.5383.0026StNicholasCogenProject54634_B_1CoalSteamMACW87.910931109311.0095.00JCOOxidesOlefinsPlant54637_G_GCG1CombustionTurbineENTG30.51250387001.4389.87JCOOxidesOlefinsPlant54637_G_GCG2CombustionTurbineENTG30.51250387001.4389.87LakewoodCogenLP54640_G_GEN1CombinedCycleMACE78.0812981291.0084.63LakewoodCogenLP54640_G_GEN2CombinedCycleMACE78.0812981291.0084.63LakewoodCogenLP54640_G_NACombinedCycleMACE83.0812981291.0084.63AuburndalePowerPartners54658_G_CTCombinedCycleFRCC105890083021.0648.82AuburndalePowerPartners54658_G_STCombinedCycleFRCC49.6890083021.0648.82OysterCreekUnitVIII54676_G_G81CombinedCycleERCT73.01000096621.0269.15OysterCreekUnitVIII54676_G_G82CombinedCycleERCT73.01000096621.0269.15OysterCreekUnitVIII54676_G_G83CombinedCycleERCT73.01000096621.0269.15OysterCreekUnitVIII54676_G_G84CombinedCycleERCT1601000096621.0269.15CIICarbonLLC54677_B_HRBCoalSteamENTG23.010331103201.0085.26CIICarbonLLC54677_G_TG‐2CoalSteamENTG23.010331103201.0085.26YorkCogenFacility54693_G_GT#1CombinedCycleMACW6.9983098301.0084.63YorkCogenFacility54693_G_GT#2CombinedCycleMACW6.6983098301.0084.63YorkCogenFacility54693_G_GT#5CombinedCycleMACW6.9983098301.0084.63YorkCogenFacility54693_G_GT#6CombinedCycleMACW6.1983098301.0084.63YorkCogenFacility54693_G_ST#1CombinedCycleMACW7.2983098301.0084.63YorkCogenFacility54693_G_ST#2CombinedCycleMACW6.9983098301.0084.63YumaCogenerationAssociates54694_G_GEN1CombinedCycleAZNM35.1897176041.1480.86YumaCogenerationAssociates54694_G_GEN2CombinedCycleAZNM17.1897176041.1480.86HunterdonCogenFacility54707_G_1CombustionTurbineMACE4.11250387001.4389.24MontclairCogenFacility54708_G_1CombustionTurbineMACE3.71250387001.4389.24PortNechesPlant54748_G_G1CombustionTurbineENTG32.01250387001.4389.87GoalLineLP54749_G_CTGCombinedCycleCA‐S40.0918277241.0274.62GoalLineLP54749_G_STGCombinedCycleCA‐S9.4918277241.0274.62WestmorelandRoanokeValleyII54755_B_BLR2CoalSteamVAPW44.01134695151.1991.60HermistonGeneratingPlant54761_G_GEN1CombinedCyclePNW80.01118273221.0084.68HermistonGeneratingPlant54761_G_GEN2CombinedCyclePNW1521118273221.0084.68HermistonGeneratingPlant54761_G_GEN3CombinedCyclePNW80.01118273221.0084.68HermistonGeneratingPlant54761_G_GEN4CombinedCyclePNW1521118273221.0084.68BoydtonPlankRoadCogenPlant54766_G_GEN1FossilWasteVAPW3.011036110361.0090.00LiveOakCogen54768_G_GEN1CombustionTurbineCA‐N46.01506587001.7389.87UniversityofIowaMainPowerPlant54775_B_BLR10CoalSteamMRO4.21250883001.4985.26UniversityofIowaMainPowerPlant54775_B_BLR11CoalSteamMRO4.21250883001.4985.26UniversityofIowaMainPowerPlant54775_B_BLR7O/GSteamMRO4.21478983001.7292.41UniversityofIowaMainPowerPlant54775_B_BLR8O/GSteamMRO4.21478983001.7292.41UniversityofIowaMainPowerPlant54775_B_BLR9O/GSteamMRO4.21478983001.7292.41GraysFerryCogeneration54785_G_GEN1CombinedCycleMACE50.0903355221.6436.96GraysFerryCogeneration54785_G_GEN2CombinedCycleMACE100903355221.6436.9627PlymouthStateCollegeCogeneration54803_G_AICEngineNENG1.21233494481.2889.24MilagroCogenerationPlant54814_G_GENACombustionTurbineAZNM30.41654187001.9089.87MilagroCogenerationPlant54814_G_GENBCombustionTurbineAZNM30.41654187001.9089.87MilagroCogenerationPlant54814_G_GO1ACombustionTurbineAZNM30.41652187001.9089.87MilagroCogenerationPlant54814_G_GO1BCombustionTurbineAZNM30.41654187001.9089.87JohnsonCounty54817_G_GT‐1CombinedCycleERCT163706078591.0084.63JohnsonCounty54817_G_ST‐1FossilWasteERCT104785978591.0090.00PandaBrandywineLP54832_G_1CombinedCycleMACS78.6833076121.3732.08PandaBrandywineLP54832_G_2CombinedCycleMACS78.6833076121.3732.08PandaBrandywineLP54832_G_3CombinedCycleMACS72.8833076121.3732.08OutagamieCountyCo‐GenerationFacility54842_G_GEN1LandfillGasWUMS0.801368292731.4867.72GordonsvilleEnergyLP54844_G_GOR1CombinedCycleVAPW71.4859387061.0084.63GordonsvilleEnergyLP54844_G_GOR2CombinedCycleVAPW71.4859387061.0084.63GordonsvilleEnergyLP54844_G_GOR3CombinedCycleVAPW40.6859387061.0084.63GordonsvilleEnergyLP54844_G_GOR4CombinedCycleVAPW40.6859387061.0084.63CoxWastetoEnergy54850_G_01BiomassTVAK3.01551783001.8983.00CoxWastetoEnergy54850_G_02BiomassTVAK0.301551783001.8983.00BrooklynNavyYardCogeneration54914_G_01CombinedCycleNYC85.0747767591.3484.63BrooklynNavyYardCogeneration54914_G_02CombinedCycleNYC85.0747767591.3484.63BrooklynNavyYardCogeneration54914_G_03CombinedCycleNYC30.0747767591.3484.63BrooklynNavyYardCogeneration54914_G_04CombinedCycleNYC30.0747767591.3484.63MichiganPowerLP54915_G_G001CombinedCycleMECS58.01088093341.0172.92MichiganPowerLP54915_G_G101CombinedCycleMECS70.01088093341.0172.92SauderPowerPlan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tmanCogenerationFacility55176_G_GEN1CombinedCycleSPPS146727462891.4862.33EastmanCogenerationFacility55176_G_GEN2CombinedCycleSPPS146727462891.4862.33EastmanCogenerationFacility55176_G_GEN3CombinedCycleSPPS110727462891.4862.33Channelview55187_G_CHV1CombinedCycleERCT1611045799091.0084.63Channelview55187_G_CHV2CombinedCycleERCT1611045799091.0084.63Channelview55187_G_CHV3CombinedCycleERCT1611045799091.0084.63Channelview55187_G_CHV4CombinedCycleERCT1611045799091.0084.63Channelview55187_G_ST1CombinedCycleERCT1351045799091.9776.78CorpusChristiEnergyCenter55206_G_CT1CombinedCycle162NotindB75351.0084.63CorpusChristiEnergyCenter55206_G_CT2CombinedCycle162NotindB75351.0084.63CorpusChristiEnergyCenter55206_G_ST1CombinedCycle159NotindB75351.0084.63AeraSouthBelridgeCogenFacility55216_G_STG1CombinedCycleCOMD62.01024458961.4133.26AeraSouthBelridgeCogenFacility55216_G_UNT1CombinedCycleCOMD38.01024458961.4133.26AeraSouthBelridgeCogenFacility55216_G_UNT2CombinedCycleCOMD38.01024458961.4133.26AeraSouthBelridgeCogenFacility55216_G_UNT3CombinedCycleCOMD38.01024458961.4133.26LosMedanosEnergyCenter55217_G_CTG1CombinedCycleCA‐N165692066561.1570.00LosMedanosEnergyCenter55217_G_CTG2CombinedCycleCA‐N165692066561.1570.00LosMedanosEnergyCenter55217_G_STG3CombinedCycleCA‐N237692066561.1570.00InaRoadWaterPollutionControlFac55257_G_1ICEngineAZNM0.591329887001.5289.24InaRoadWaterPollutionControlFac55257_G_2ICEngineAZNM0.591329887001.5289.24InaRoadWaterPollutionControlFac55257_G_3ICEngineAZNM0.591329887001.5289.24InaRoadWaterPollutionControlFac55257_G_4ICEngineAZNM0.591329887001.5289.24InaRoadWaterPollutionControlFac55257_G_5ICEngineAZNM0.591329887001.5289.24InaRoadWaterPollutionControlFac55257_G_6ICEngineAZNM0.591329887001.5289.24InaRoadWaterPollutionControlFac55257_G_7ICEngineAZNM0.591329887001.5289.24WhitingCleanEnergy55259_G_CT1CombinedCycleRFCO167711390511.0626.24WhitingCleanEnergy55259_G_CT2CombinedCycleRFCO167711390511.0626.24WhitingCleanEnergy55259_G_ST1CombinedCycleRFCO213711390511.0626.24DecaturEnergyCenter55292_G_CTG1CombinedCycleTVA155727499991.0084.6830DecaturEnergyCenter55292_G_CTG2CombinedCycleTVA155727499991.0084.68DecaturEnergyCenter55292_G_CTG3CombinedCycleTVA155727499991.0084.68DecaturEnergyCenter55292_G_STG1CombinedCycleTVA159727499991.0084.68MorganEnergyCenter55293_G_CTG1CombinedCycleTVA161735574211.0084.68MorganEnergyCenter55293_G_CTG2CombinedCycleTVA161735574211.0084.68MorganEnergyCenter55293_G_CTG3CombinedCycleTVA161735574211.0084.68MorganEnergyCenter55293_G_STG1CombinedCycleTVA266735574211.0084.68ChannelEnergyCenter55299_G_CTG1CombinedCycleERCT185720060161.3440.92ChannelEnergyCenter55299_G_CTG2CombinedCycleERCT185720060161.3440.92ChannelEnergyCenter55299_G_ST‐1CombinedCycleERCT215720060161.3440.92CalvertCity55308_G_GEN1CombustionTurbineTVA23.01250387001.4389.88AirProductsPortArthur55309_G_GEN1CombinedCycleENTG33.27274107191.0084.63AirProductsPortArthur55309_G_GEN2CombinedCycleENTG3.07274107191.0084.63InglesideCogeneration55313_G_CTG1CombinedCycleERCT155793384791.0757.25InglesideCogeneration55313_G_CTG2CombinedCycleERCT155793384791.0757.25InglesideCogeneration55313_G_STGCombinedCycleERCT150793384791.0757.25ChuckLenzieGeneratingStation55322_G_CTG1CombinedCycleSNV134703177351.0084.63ChuckLenzieGeneratingStation55322_G_CTG2CombinedCycleSNV168703177351.0084.63ChuckLenzieGeneratingStation55322_G_ST1CombinedCycleSNV184703177351.0084.63BaytownEnergyCenter55327_G_CTG1CombinedCycleERCT170727474841.0084.63BaytownEnergyCenter55327_G_CTG2CombinedCycleERCT170727474841.0084.63BaytownEnergyCenter55327_G_CTG3CombinedCycleERCT170727474841.0084.63BaytownEnergyCenter55327_G_STG1CombinedCycleERCT275727474841.0084.63ColumbiaEnergyCenter55386_G_CT1CombinedCycle157NotindB64071.7315.00ColumbiaEnergyCenter55386_G_CT2CombinedCycle157NotindB64071.7315.00ColumbiaEnergyCenter55386_G_ST1CombinedCycle151NotindB64071.7315.00CarvilleEnergyLLC55404_G_CTG1CombinedCycleENTG180727459661.3656.35CarvilleEnergyLLC55404_G_CTG2CombinedCycleENTG180727459661.3656.35CarvilleEnergyLLC55404_G_STGCombinedCycleENTG140727459661.3656.35PlaquemineCogenerationPlant55419_G_G500CombinedCycleENTG169727463941.1151.42PlaquemineCogenerationPlant55419_G_G600CombinedCycleENTG169727463941.1151.42PlaquemineCogenerationPlant55419_G_G700CombinedCycleENTG169727463941.1151.42PlaquemineCogenerationPlant55419_G_G800CombinedCycleENTG169727463941.1151.42PlaquemineCogenerationPlant55419_G_ST5CombinedCycleENTG168727463941.1151.42DeerParkEnergyCenter55464_G_CTG1CombinedCycleERCT155727457121.7576.57DeerParkEnergyCenter55464_G_CTG2CombinedCycleERCT155727457121.7576.57DeerParkEnergyCenter55464_G_CTG3CombinedCycleERCT155727457121.7576.57DeerParkEnergyCenter55464_G_CTG4CombinedCycleERCT155727457121.7576.57DeerParkEnergyCenter55464_G_STG1CombinedCycleERCT258727457121.7576.57GreenPower255470_G_ST1CombinedCycleERCT110793355001.4473.01GreenPower255470_G_TR1CombinedCycleERCT158793355001.4473.0131GreenPower255470_G_TR2CombinedCycleERCT158793355001.4473.01GreenPower255470_G_TR3CombinedCycleERCT158793355001.4473.01BlackburnLandfillCo‐Generation55488_G_BB1LandfillGasVACA11232887001.5767.05BlackburnLandfillCo‐Generation55488_G_BB2LandfillGasVACA11232887001.5767.05BlackburnLandfillCo‐Generation55488_G_BB3LandfillGasVACA0.901232887001.5767.05WilmingtonHydrogenPlant55557_G_T101O/GSteamCA‐S23.01142598541.1392.45CombinedLocksEnergyCenter55558_G_GEN1CombinedCycleWUMS40.8793362211.2818.89CombinedLocksEnergyCenter55558_G_GEN2CombinedCycleWUMS4.3793362211.2818.89BinghamtonCogen55600_G_1CombustionTurbineUPNY42.01089493581.1689.87MingoJunctionEnergyCenter55611_B_BOIL1O/GSteamRFCO7.51142583001.3592.41MingoJunctionEnergyCenter55611_B_BOIL2O/GSteamRFCO7.51142583001.3592.41MingoJunctionEnergyCenter55611_B_BOIL3O/GSteamRFCO7.51142583001.3592.41MingoJunctionEnergyCenter55611_B_BOIL4O/GSteamRFCO7.51142583001.3592.41FPLEnergyMarcusHookLP55801_G_CT13CombinedCycleMACE162727472741.0084.63FPLEnergyMarcusHookLP55801_G_CT1ACombinedCycleMACE162727472741.0084.63FPLEnergyMarcusHookLP55801_G_CTIBCombinedCycleMACE160727472741.0084.63FPLEnergyMarcusHookLP55801_G_STGCombinedCycleMACE234727472741.0084.63DesertPowerLP55858_G_GEN7CoalSteamNWPE40.09650Retired0.00Co‐GenLLC50921_G_GEN1BiomassPNW7.01797485662.1083.00Ashtabula55990_G_1CombinedCycleRFCO4.4727470831.0373.53Ashtabula55990_G_2CombinedCycleRFCO4.4727470831.0373.53Ashtabula55990_G_3CombinedCycleRFCO4.4727470831.0373.53Ashtabula55990_G_4CombinedCycleRFCO4.4727470831.0373.53Ashtabula55990_G_5CombinedCycleRFCO4.4727470831.0373.53Ashtabula55990_G_6CombinedCycleRFCO0.69727470831.0373.53Ashtabula55990_G_7CombinedCycleRFCO0.69727470831.0373.53TrigenRevere55999_G_GEN1ICEngineNENG2.81085097321.1189.24TrigenRevere55999_G_GEN2ICEngineNENG2.81085097321.1189.24WWTPPowerGenerationStation56036_G_GEN1Non‐FossilWasteCA‐N2.014653146531.0090.00WWTPPowerGenerationStation56036_G_GEN2Non‐FossilWasteCA‐N2.014653146531.0090.00WWTPPowerGenerationStation56036_G_GEN3Non‐FossilWasteCA‐N2.014653146531.0090.00FoxValleyEnergyCenter56037_G_1CoalSteamWUMS6.51033183001.2485.26UMCPCHPPlant56038_G_1CombinedCycleMACS9.4793365341.8084.63UMCPCHPPlant56038_G_2CombinedCycleMACS9.4793365341.8084.63UMCPCHPPlant56038_G_3CombinedCycleMACS2.0793365341.8084.63MillenniumHawkinsPoint56045_G_1ACombinedCycleMACS1.17933134901.0937.14MillenniumHawkinsPoint56045_G_1BCombinedCycleMACS1.17933134901.0937.14MillenniumHawkinsPoint56045_G_2ACombinedCycleMACS1.17933134901.0937.14MillenniumHawkinsPoint56045_G_2BCombinedCycleMACS1.17933134901.0937.14MillenniumHawkinsPoint56045_G_3ACombinedCycleMACS1.17933134901.0937.14MillenniumHawkinsPoint56045_G_3BCombinedCycleMACS1.17933134901.0937.1432MillenniumHawkinsPoint56045_G_ST1CombinedCycleMACS0.507933134901.0937.14Co‐GenIILLC50993_G_GEN1BiomassPNW7.017139102851.6783.00SierraPacificAberdeen55882_B_BLR1BiomassPNW16.51551783001.8983.00MiddlesexGeneratingFacility56119_G_100Non‐FossilWaste4.10NotindB72741.0090.00MiddlesexGeneratingFacility56119_G_200Non‐FossilWaste4.10NotindB72741.0090.00MiddlesexGeneratingFacility56119_G_300Non‐FossilWaste10.6NotindB72741.0090.00SPNewsprint‐NewbergCogen56124_B_10BLRO/GSteamPNW22.311332115111.0092.41SPNewsprint‐NewbergCogen56124_G_GT1CombustionTurbinePNW41.612503Retired0.00SPNewsprint‐NewbergCogen56124_G_GT2CombustionTurbinePNW41.612503Retired0.00MaconEnergyCenter56127_G_1CombustionTurbineGWAY9.113301133011.0089.24GrovetonPaperBoard56140_G_TUR1CombustionTurbineNENG4.012678124771.0089.24GrovetonPaperBoard56140_G_TUR2CombustionTurbineNENG4.012678124771.0089.24FreeportEnergyCenter56152_G_CTG1CombinedCycle180NotindB79421.0084.63FreeportEnergyCenter56152_G_STG1CombinedCycle80.0NotindB79421.0084.63FreeholdAsburyParkPress56169_G_UNT1ICEngineMACE1.111797100001.1889.24FreeholdAsburyParkPress56169_G_UNT2ICEngineMACE1.111797100001.1889.24Cogeneration156229_G_CT1CombinedCycleAZNM8.3793379421.0084.63PerhamIncinerator56243_G_1MunicipalSolidWasteMRO1.219338162971.0090.00ShellChemical56248_G_101GCombustionTurbineENTG32.012503109941.1389.87ShellChemical56248_G_201GCombustionTurbineENTG32.012503109941.1389.87TrigenSt.Louis56309_G_CT‐1CombinedCycleGWAY4.01198555832.1552.35TrigenSt.Louis56309_G_CT‐2CombinedCycleGWAY4.21198555832.1552.35TrigenSt.Louis56309_G_ST‐3O/GSteamGWAY18.011425111771.0092.45TrigenSt.Louis56309_G_ST‐4CombinedCycleGWAY0.771198555832.1552.35TrigenSt.Louis56309_G_ST‐5CombinedCycleGWAY0.811198555832.1552.35ClearwaterPowerPlant56356_G_CT1CombinedCycleCA‐S21.0910093681.0084.63ClearwaterPowerPlant56356_G_ST1CombinedCycleCA‐S7.0910093681.0084.63DomainPlant56373_G_DOMG1CombustionTurbineERCT5.011862118621.0089.24RobertMuellerEnergyCenter56374_G_CT1CombustionTurbineERCT3.71250399601.0089.24SierraPacificBurlingtonFacility56406_G_GEN1BiomassPNW25.015517126951.2483.00TesoroSLCCogenerationPlant56509_G_1CombustionTurbineNWPE11.01250387001.4489.24TesoroSLCCogenerationPlant56509_G_2CombustionTurbineNWPE11.01250387001.4489.24EdgeMoor593_B_3CoalSteamMACE86.013668127211.0741.53EdgeMoor593_B_4CoalSteamMACE174956995691.0041.53SherburneCounty6090_B_1CoalSteamMRO76210611106111.0068.27SherburneCounty6090_B_2CoalSteamMRO75210452104521.0068.27BigStone6098_B_1CoalSteamMRO47011609116091.0079.70Warrick6705_B_1CoalSteamRFCO13610986109861.0073.94Warrick6705_B_2CoalSteamRFCO13611017110021.0073.94Warrick6705_B_3CoalSteamRFCO13611056110021.0073.94Warrick6705_B_4CoalSteamRFCO30010418104181.0073.9333Gadsden7_B_1CoalSteamSOU64.012376123761.0050.27Gadsden7_B_2CoalSteamSOU66.012846128461.0050.27Whitehead7028_G_K1ICEngineNWPE5.914151141511.0089.24Whitehead7028_G_K2ICEngineNWPE6.010069100691.0089.24Whitehead7028_G_K3ICEngineNWPE5.910069100691.0089.24Whitehead7028_G_K4ICEngineNWPE4.010069100691.0089.24Whitehead7028_G_K5ICEngineNWPE2.010746107461.0089.24Whitehead7028_G_K6ICEngineNWPE2.110746107461.0089.24Whitehead7028_G_K7ICEngineNWPE2.110746107461.0089.24BrandonStation7131_G_1CombustionTurbineSPPS20.012503125031.0089.87RichardGorsuch7286_B_1CoalSteamRFCO50.011084110841.0060.67RichardGorsuch7286_B_2CoalSteamRFCO50.011084110841.0060.67RichardGorsuch7286_B_3CoalSteamRFCO50.011071110711.0060.67RichardGorsuch7286_B_4CoalSteamRFCO50.011071110711.0060.67GeorgeNealSouth7343_B_4CoalSteamMRO63210470104701.0080.10UniversityofFlorida7345_G_P1CombustionTurbineFRCC45.0924992491.0089.87CoyoteSprings7350_G_1CombinedCyclePNW142733775981.0084.68CoyoteSprings7350_G_2CombinedCyclePNW71.3733775981.0084.68IndianTrailsCogen17384_B_1O/GSteamGWAY3.311425111771.0092.41IndianTrailsCogen17384_B_2O/GSteamGWAY3.311425111771.0092.41IndianTrailsCogen17384_B_3O/GSteamGWAY3.311425111771.0092.41CarsonIce‐GenProject7527_G_1CombinedCycleCA‐N41.21186083271.0084.63CarsonIce‐GenProject7527_G_2CombinedCycleCA‐N16.61186083271.0084.63MilwaukeeCounty7549_B_1CoalSteamWUMS3.311704117041.0071.80MilwaukeeCounty7549_B_2CoalSteamWUMS3.310331103201.0071.80MilwaukeeCounty7549_B_3CoalSteamWUMS3.310331103201.0071.80SCACogen27551_G_CCSTCombinedCycleCA‐N37.61109484691.0084.63SCACogen27551_G_CT1ACombinedCycleCA‐N39.61109484691.0084.63SCACogen27551_G_CT1BCombinedCycleCA‐N39.61109484691.0084.63SCACogen27551_G_CT1CCombinedCycle45.7NotindB84691.0084.63SPACogen37552_G_CCCTCombinedCycleCA‐N111839481371.0084.63SPACogen37552_G_CCSTCombinedCycleCA‐N53.0839481371.0084.63EverettCogen7627_B_14BiomassPNW36.015517118441.3383.00USDOESavannahRiverSite(DArea)7652_B_D‐1CoalSteam19.6NotindB103201.0031.67USDOESavannahRiverSite(DArea)7652_B_D‐2CoalSteam19.6NotindB103201.0031.67USDOESavannahRiverSite(DArea)7652_B_D‐3CoalSteam19.6NotindB103201.0031.67USDOESavannahRiverSite(DArea)7652_B_D‐4CoalSteam19.6NotindB103201.0031.67WashingtonCountyCogenerationFacility7697_G_1CombinedCycleSOU80.0727490261.0084.63WashingtonCountyCogenerationFacility7697_G_2CombinedCycleSOU22.0727490261.0084.63GeneralElectricPlastic7698_G_1CombinedCycleSOU85.07274119721.0084.63GeneralElectricPlastic7698_G_2CombinedCycleSOU12.07274119721.0084.6334FairlessHills7701_B_4LandfillGasMACE30.013682127891.0747.11FairlessHills7701_B_5LandfillGasMACE30.013682127891.0747.11PeaRidge7715_G_1CombustionTurbineSOU4.014111141111.0089.24PeaRidge7715_G_2CombustionTurbineSOU4.011210112101.0089.24PeaRidge7715_G_3CombustionTurbineSOU4.011210112101.0089.24TheodoreCogenFacility7721_G_1CombinedCycleSOU152727470651.0084.63TheodoreCogenFacility7721_G_2CombinedCycleSOU36.0727470651.0084.63CogenSouth7737_B_B001CoalSteamVACA90.010966109661.0070.87Encogen7870_G_CTG1CombinedCyclePNW39.41120091181.0084.68Encogen7870_G_CTG2CombinedCyclePNW39.41120091181.0084.68Encogen7870_G_CTG3CombinedCyclePNW39.41120091181.0084.68Encogen7870_G_STGCombinedCyclePNW51.81120091181.0084.68WestCampusCogenerationFacility7991_G_1CombinedCycleWUMS38.01198583671.0084.63WestCampusCogenerationFacility7991_G_CT2CombinedCycleWUMS37.21198583671.0084.63WestCampusCogenerationFacility7991_G_STG1CombinedCycleWUMS55.01198583671.0084.63WareCogeneration81542_G_1BiomassNENG4.115517157161.0083.00KimberlyClark82800_G_CC1CombinedCycleNENG17.5703179421.0084.63KimberlyClark82800_G_GT1CombustionTurbineNENG17.510664124771.0089.24GreatRiverEnergySpiritwoodStation82821_B_1CoalSteamMRO99.0876389371.0085.26SPPN_KS_Coalsteam82932_C_1CoalSteamSPPN22.01082089371.0085.26CabotHolyoke9864_B_5O/GSteam5.80NotindB145001.0089.51CabotHolyoke9864_B_6O/GSteam5.80NotindB145001.0089.51CabotHolyoke9864_B_7O/GSteam5.80NotindB108171.0089.51CabotHolyoke9864_B_8O/GSteam5.80NotindB145001.0089.51

# 35 

# 2 NO

x 

# Rates

2.1 Response to the Comments Received

Comment Theme: There were a substantial number of comments indicating that the NO

x 

# rates shown in

NEEDS 2 

# were too low and not achievable.

Discussion: Based on these comments, the decision rules used to derive the NEEDS NO

x 

# rates were

reviewed and an out-of-date assumption was fo und to be causing instances of low NO

x 

# 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, NO

x 

# rate limits) designated the winter NO

x 

# rate as the uncontrolled NO

x 

# rate.

Applying percent reductions attributable to NO

x 

# post-combustion controls to the winter NO

x 

# rates resulted

in unrealistically low controlled NO

x 

# rates for units that in reality operated NO

x 

# controls in the winter.

Response: The previous decision rules were replaced by a more robust procedure for identifying

uncontrolled NO

x 

# rates. In addition, a thorough review was made of all the decision rules affecting NO

x 

# 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, Sept ember 1, 2010, 53614-53615) the NO

x 

# rates for fossil-fuel fired units in the

final rule are based on 2009 data rather than 2007 NO

x 

# data used in the modeling for the proposed

Transport Rule. Reported to EPA by generating unit s covered under Title IV of the Clean Air Act

Amendments of 1990 (Acid Rain Program) and NO

x 

# Budget Program, the updated NO

x 

# rates more

accurately reflect the unit level control installation s 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, t he following replaces the response to question

Q4 that had previously appeared in Appendix 3-1 in the NODA documentation.

2 

# The National Electrical Energy Data System (NEE DS) is a database which pr ovides 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.

# 36 Q4: How are the values of the Mode 1-4 NOx rates derived?

A4: The revised draft of the methodology to develop NO

x 

# rates for coal steam boilers in EPA Base Case

v.4.10_FTransport is summarized below.

The procedure employs the following hierarchy of NO

x 

# 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 categorize d into three groups depending on the configuration of

NO

x 

# combustion and post-combustion controls

Group 1 - Coal boilers without post combustion NO

x 

# controls

Mode 1 = 2009 ETS Annual Average NO

x 

# Rate

Mode 2 = Mode 1

Mode 3

For coal boilers located in a SIP call NO

x 

# , CAIR ozone/annual NO

x 

# or any NO

x 

# regulated state,

Mode 3 = Mode 1

For coal boilers that are not located in a SIP call NO

x 

# , CAIR ozone/annual NO

x 

# or any NO

x 

# regulated state,

follow Steps 1-7

Step 1: Pre-screen units that already have state of art (SOA) combustion controls from units that have nonSOA combustion controls from units that have no combustion controls

Step 2: For units listed as not having combustion controls

Make sure their NO

x 

# 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 NO

x 

# 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 NO

x 

# 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 NO

x 

# rate, i.e., the unit’s uncontrolled emission rate without combustion

controls, using the appropriate equation (not in boldfac e italics) in Table 3-1. 3 to back calculate their

Base NO

x 

# rate. Use the default Base NO

x 

# rate values if back calculations can’t be performed. Once

the Base NO

x 

# rate is obtained, go to Step 6.

Step 6: Use the appropriate equations (in boldface italics) in Table 3-1.3 to calculate the NO

x 

# rate with SOA

combustion controls.

Step 7: Compare the value calculated in Step 6 to the applicable NO

x 

# 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 NO

x 

# rate.

Mode 4

Mode 4 = Mode 3 NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport

# 37 Group 2 - Coal boilers with Dispatchable/Non-Dispatchable SCR

Pre-screen coal boilers with 2009 ETS NO

x 

# rates into the following four operating regimes. A

coal boiler is assumed to be operat ing its SCR when the seasonal NO

x 

# rate is less than 0.2

lbs/MMBtu

Group 2a. Coal boilers with Non-Dispatchable SCR

Group 2a.1 SCR is not operating in both summer and winter seasons

Follow the NO

x 

# rate rules summarized for Group 1 boilers. No state of the art

combustion controls are implemented.

Mode 1 = 2009 ETS Annual Average NO

x 

# 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 NO

x 

# Rate

Mode 2 = 2009 ETS Summer NO

x 

# Rate

Mode 3 = Mode 1

Mode 4 = Mode 2

Group 2a.3 SCR is operating in winter only

Mode 1 = 2009 ETS Summer NO

x 

# Rate

Mode 2 = 2009 ETS Winter NO

x 

# Rate

Mode 3 = Mode 1

Mode 4 = Mode 2

Group 2a.4 SCR is operating year-round

Mode 1 = if (2007 ETS Winter NO

x 

# Rate > 0.2, 2007 ETS Winter NO

x 

# Rate, 2009 ETS

Annual Average NO

x 

# Rate)

Mode 2 = 2009 ETS Annual Average NO

x 

# 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 NO

x 

# rate rules summarized for Group2a.1 boilers.

Group 2b.2 SCR is operating in summer only

Mode 1 = 2009 ETS Winter NO

x 

# 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 NO

x 

# 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 NO

x 

# Rate > 0.2, 2007 ETS Winter NO

x 

# Rate, 2009 ETS

Annual Average NO

x 

# Rate)

Mode 2 = Mode 1

Mode 3 = Mode 1

Mode 4 = Mode 2 NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont’d)

# 38 Group 3 - Coal boilers with SNCR

Step 1: Pre-screen coal boilers with 2009 ETS NO

x 

# 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 NO

x 

# rate is greater than 0.3 lbs/MMBtu in both summer and winter seasons.

Group 3.1 SNCR is not operating in both summer and winter seasons

Follow the NO

x 

# rate rules summarized for Group 1 boilers

Step 2: Pre-screen coal boilers with 2009 ETS NO

x 

# rates into the following three operating regimes.

First estimate the implied removal for a coal boiler using the following equation:

Implied Removal (%) = ((Winter NO

x 

# Rate – Summer NO

x 

# Rate)/ Winter NO

x 

# 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 NO

x 

# Rate

Mode 2= 2009 ETS Summer NO

x 

# 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 NO

x 

# removal

efficiencies of SNCR for non FBC and FBC boilers.

Group 3.3 SNCR is operating in winter only

Mode 1 = 2009 ETS Summer NO

x 

# Rate

Mode 2 = 2009 ETS Winter NO

x 

# 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 NO

x 

# Rate > 0.3, 2007 ETS Winter NO

x 

# Rate, 2009 ETS Annual

Average NO

x 

# Rate)

Mode 2 = 2009 ETS Annual Average NO

x 

# Rate

Mode 3 = same as Group 3.2 Mode 3

Mode 4 = Mode 3 NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont’d)39Table 3-1.1 Examples of Base and Policy NOxRates Occurring in EPA Base Case v.4.10_FTransportPlant NameUnique IDPostCombustionControlUncontrolled NOxBase RateControlled NOxBaseRateUncontrolled NOxPolicyRateControlled NOxPolicyRateExplanationSituation 1: For generating units that do not have post-combustion controls, the controlled and uncontrolled rates will be thesame.FourCorners2442_B_1None0.7860.7860.5090.509Situation 4 also applies, i.e., unit had LNB andnow 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 Sandy1353_B_BSU2SCR0.6290.1460.6290.146(1) Has SCR so see difference betweenuncontrolled and controlled rates(2) Situation 3b also applies.Situation 3a: Base and Policy NOxrates will be same if theunit has state-of-the-art NOxcombustion controls or . . .GreeneCounty10_B_2None0.3630.3630.3630.363Situation 1 also applies.Chalk PointLLC1571_B_1SCR0.4850.1560.4850.156Situation 2 also applies.Situation 3b: . . . is in the NOxRegulated Region3where current combustion controls are assumed to be retained.Thomas Hill2168_B_MB3SCR0.2210.1020.2210.102Situation 2 also applies.Waukegan883_B_17None0.3360.3360.3360.336(1) Has NOxcombustion control and is in SIP sodoesn't get added combustion control.(2) Situation 1 also applies.Situation 4: Base and policy rates willdiffer if a unit does not currently have state-of-the-art combustion controls and would installsuch controls in response to a NOxpolicy.Crist641_B_4SNCR0.4040.4040.2400.180(1) Drop in uncontrolled policy NOxratecompared to uncontrolled base rate is due toaddition of combustion controls. (Note 0.24 isfloor.)3NOxregulated 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.

# 40 Table 3-1.2 Cutoff and Floor NO

x 

# Rates (lb/MMBtu) in EPA Base Case v.4.10_FTransport

Boiler Type Cutoff Rate (lbs/MMBtu) Floor Rate (lbs/MMBtu)

Bituminous Subbitumino

us Lignit

e Bituminous Subbitumino

us Lignit

e

Wall-Fired

Dry-Bottom 0.43 0.33 0.29 0.32 0.18 0.18

Tangentially

-Fired 0.34 0.24 0.22 0.24 0.12 0.17

CellBurners 0.43 0.43 0.43 0.32 0.32 0.32

Cyclones 0.62 0.67 0.67 0.47 0.49 0.49

VerticallyFired 0.57 0.44 0.44 0.49 0.25 0.25

Table 3-1.3 NO

x 

# 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 Coal Type Combustion Control

Technology Fraction of

Removal Default

Removal

Dry Bottom

Wall-Fired Bituminous LNB 0.163 + 0.272*

Base NO

x 

# 0.568

LNB + OFA 0.313 + 0.272*

Base NO

x 

# 0.718

Dry Bottom

Wall-Fired Subbituminous

/Lignite LNB 0.135 + 0.541*

Base NO

x 

# 0.574

LNB + OFA 0.285 + 0.541*

Base NO

x 

# 0.724

TangentiallyFired Bituminous LNC1 0.162 + 0.336*

Base NO

x 

# 0.42

LNC2 0.212 + 0.336*

Base NO

x 

# 0.47

LNC3 0.362 + 0.336*

Base NO

x 

# 0.62

TangentiallyFired Subbituminous

/Lignite LNC1 0.20 + 0.717*

Base NO

x 

# 0.563

LNC2 0.25 + 0.717*

Base NO

x 

# 0.613

LNC3 0.35 + 0.717*

Base NO

x 

# 0.713

Notes:

LNB = Low NO

x 

# Burner

OFA = Overfire Air

LNC = Low NO

x 

# Control

# 41 

# 3 SO 2 

# Removal Rates for Flue Gas Desulfurization (FGD)

Comment Theme: In EPA Base Case v.4.10 the assumed SO 2 

# removal efficiency for wet and dry FGD

on new units and retrofits was 98% and 95% respective ly. Comments indicated that the assumption of a

98% SO 2 

# removal rate for wet FGD on new units and retrofits might be suitable as a short-term

performance guarantee but exceeded the long term re moval rate that could be achieved under real

operating conditions where load following is requir ed. 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 EI A 860 (2008) rather than on the engineering design

capabilities of the controls, as wa s 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 SO 2 

# 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 coul d not be maintained under load following conditions.

In particular, for new units and FGD retrof its installed by the model, the assumed SO 2 

# removal rates will

be 96% for wet FGD and 92% for dry FGD. These are the average of the SO 2 

# 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 EI A 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) SO 2 

# removal rates are higher than the average of the upper quartile SO 2 

# removal rates will be

assigned the upper quartile average unless the report ed 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 SO 2 

# 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.42Table 3-11 Emission and Removal Rate Assumptions for Potential (New) Units in EPA Base Case v.4.10_FTransportGasControls,Removal,andEmissionsRatesSupercriticalPulverizedCoal - WetScrubberSupercriticalPulverizedCoal - DryScrubberIntegratedGasificationCombinedCycleAdvancedCoal withCarbonCaptureAdvancedCombinedCycleAdvancedCombustionTurbineBiomassConventionalDirect-FiredBoilerBiomassGasificationCombinedCycleGeothermalLandfill GasSO2Removal /EmissionsRate98%96%witha floor of 0.06lbs/MMBtu93%92%witha floor of0.0650.08lbs/MMBtu99%99%NoneNone0.08 lbs/MMBtu0.08lbs/MMBtuNoneNoneNOxEmissionRate0.07lbs/MMBtu0.05lbs/MMBtu0.013lbs/MMBtu0.013lbs/MMBtu0.011lbs/MMBtu0.011lbs/MMBtu0.36 lbs/MMBtu0.102lbs/MMBtuNone0.09lbs/MMBtuHgRemoval /EmissionsRate90%90%90%90%Natural Gas:0.000138lbs/MMBtuOil:0.483lbs/MMBtuNatural Gas:.000138lbs/MMBtuOil:0.483lbs/MMBtu0.57 lbs/MMBtu0.57lbs/MMBtu3.70NoneCO2Removal /EmissionsRate205.2 - 217.3lbs/MMBtu205.2 - 217.3lbs/MMBtu205.2 - 217.3lbs/MMBtu90%Natural Gas:117.08lbs/MMBtuOil:161.39lbs/MMBtuNatural Gas:117.08lbs/MMBtuOil:161.39lbs/MMBtuNoneNoneNoneNoneHClRemoval /EmissionsRate99%0.0001lbs/mmBtu99%0.0001lbs/mmBtu99%0.0001lbs/mmBtu99%0.0001lbs/mmBtu−−−−−−

# 43 In Chapter 5

− Emission Control Technologies

Incorporate the changes shown in red below.



# 5.1 Sulfur Dioxide Control Technologies

Two commercially available Flue Gas Desulfurizatio n (FGD) technology options for removing the SO 2 

# produced by coal-fired power plants are offered in E PA 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 syste ms, the polluted gas stream is brought into contact

with a liquid alkaline sorbent (typically limestone) by forc ing 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 SO 2 

# content exceeds 3 lbs SO 2 

# /MMBtu, so this technology is prov ided only to plants which have the

option to burn coals with sulfur content no greater than 3 lbs SO 2 

# /MMBtu. In EPA Base Case v.4.10 when a

unit retrofits with an LSD SO 2 

# scrubber, it loses the option of burni ng BG, BH, and LG coals due to their high

sulfur content.

In EPA Base Case v.4.10 the LSFO and LSD SO 2 

# 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 databa se of existing units which is used in setting up the

EPA base case. The scrubber retrofit costs for thes e units are the same as regular unsc rubbed 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 Ba se 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 leve ls in Form 767 were assigned the maximum removal

efficiency in NEEDS v.4.10 indicated in the previous sentenc e. Units whose reported EIA Form 860 (2008)

SO 2 

# removal rates were higher than the average of the upper quartile SO 2 

# removal rates were assigned the

upper quartile average unless the EIA 860 rate was conf irmed in a comment submitted during the Transport

Rulemaking . One upper quartile removal rate is calc ulated 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 SO 2 

# 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 scrubbe r type are discussed in detail in the following sections.

Table 5-2 Summary of Retrofit SO 2 

# Emission Control Performance Assumptions

Performance

Assumptions Limestone Forced

Oxidation (LSFO) Lime Spray Dryer (LSD)

Percent Removal 98% 96%

with a floor of 0.06 lbs/MMBtu 93% 92%

with a floor of 0.065 0.08

lbs/MMBtu

Capacity Penalty Calculated based on

characteristics of the unit:

See Table 5-4 for examples Calculated based on

characteristics of the unit:

See Table 5-4 for examples Heat Rate Penalty

Cost (2007$)

Applicability Units ≥ 25 MW Units ≥ 25 MW

Sulfur Content

Applicability Coals ≤ 3 lbs SO 2 

# /MMBtu

Applicable Coal Types BA, BB, BD, BE, BG, BH, SA,

SB, SD, LD, LE, and LG 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 98 % 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.

# 44 

# 4 Coal Switching

− Bituminous to Subbituminous

4.1 Response to the Comments Received

Comment Theme: In draft EPA Base Case v.410 it was as sumed 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 limitatio ns that prevented unrestric ted switching at some

existing generating units.

Discussion: Based on these comments, a procedure was dev eloped to capture limit ations that prevent

unrestricted switching from bituminous to subbitum inous 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-spec ified 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_FTranspor t. Historical fuel usage data is used to infer

whether units have already made investments a llowing 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 amo unt 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 hist orically 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 consum ing 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) i ndicated that during the ec onomic 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 der ating. 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 co nservative 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 th erefore 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 42 3 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 incu rring any additional cost or heat rate penalty.

# 45 (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 boi ler 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 li eu 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 bet ween 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 bitumi nous to subbituminous coal, the following conditions apply in EPA

Base Case v.4.10_FTransport to coal plants t hat have the option to burn both bituminous and

subbituminous coal.

Those that have burned 90% or more subbitumino us 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 per cent of subbituminous coal burned in 2008, 2009,

and first half of 2010.

All other units with the option to burn both bi tuminous and subbitu minous 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/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. The heat rate penalty reflects the impact of the higher

moisture content subbituminous coal on the unit’s heat rate

# 46 

# 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 restrictio ns are typically placed on

the fuels available to the unit.

Factors limiting changes is near term coal use were co nsidered technically plausible in the first model run

year of 2012. Consequently, EPA incorporated such li mitations in 2012 in cases where the affected units

were explicitly identified, where sufficient docum entation and an adequate explanation of the governing

factors were provided, where EPA wa s 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 w ould take precedent over short-term restrictions

and that the full choice of previously assigned coals s hould be re-instated for coal units. This would allow

the model to make fuel choices based on economic fa ctors reflecting the tendenc y 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 assi gned the coal grade which would result in an

emission rate closest to the SO2 rate reported fo r 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, t he 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 sp ecific 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 se ction 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 t hey face, and the historical record of coals burned

at the unit. Once the coal assignments are made, no further restrictions are ty pically 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 informatio n was provided to EPA indicating that shor t-term factors (like coal contracts

and boiler engineering considerations) limited a unit’s c hoice 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.

# 47 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 restrictio ns are typically placed

on the fuels available to the unit.

However, coal choice was further restricted in t he 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 considerat ions prevail over short-term restrictions in

the longer term.

In conjunction with these changes, limits were impose d 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 t hat 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 lim its are shown in the following table:

Plant Name Plant

ORIS

ID Maximum Percent of Heat

Input (MMBtu) from Lignite

For IPM Run Years Shown

2012 2015 2020

Big Brown 3497 ≤ 50% ≤ 69% ≤ 100%

Limestone 298 ≤ 54% ≤ 71% ≤ 100%

Martin Lake 6146 ≤ 69% ≤ 80% ≤ 100%

Monticello 6147 ≤ 19% ≤ 50% ≤ 100%

In addition, post-modeling quality assurance ch ecks 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 minemouth plant. To increase short-term modeling consis tency with the plant’s recent operating history, its

2012 SO 2 

# emissions were re-calculated using its 2009 reported SO 2 

# emission rate and its 2012

projected heat input.

Post-modeling quality assurance found a similar di screpancy between the short-term projection and

operating history at Gibbons Creek (O RIS 6136) Unit 1 where reported SO 2 

# emissions at the unit were

indicative either of a unit not operating a scrubber or of a scrubber with a very low SO 2 

# 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 scrubb er 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 in crease short-term modeling consistency with the

plant’s operating history, its 2012 and 2014 SO 2 

# emissions were re-calculated to factor out the

projected reductions from scrubbing.

# 48 

# 6 Waste Coal Cost Correction

6.1 Response to the Comments Received

Comment Theme: Comments were received indi cating 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 ent ry error had resulted in incorrect waste coal

prices. The labeling of the prices in a file obtaine d 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 Cur ves in EPA Base Case V.4.10

Waste Coal Entries Only

Year Coal

Supply

Region Coal

Grade Step

Name Heat Content

(MMBtu/Ton) Cost of Production

(2007$/Ton) Coal

Production

(Million

Tons/Year) Previous Corrected

2012 NA WC S1 12.35 21.9 12.7 6.6

2012 NA WC S2 12.35 22.8 13.3 3.9

2012 NA WC S3 12.35 23.9 13.9 2.6

2012 NA WC S4 12.35 24.3 14.2 0.9

2012 NA WC S5 12.35 24.5 14.3 0.3

2012 NA WC S6 12.35 24.6 14.3 0.1

2012 NA WC S7 12.35 24.6 14.3 0.1

2012 NA WC S8 12.35 24.8 14.4 0.3

2012 NA WC S9 12.35 25.4 14.8 0.9

2012 NA WC S10 12.35 28.8 16.7 2.6

2012 NA WC S11 12.35 41.8 24.3 3.9

2015 NA WC S1 12.35 22.0 12.8 7.2

2015 NA WC S2 12.35 23.2 13.5 4.2

2015 NA WC S3 12.35 24.6 14.3 2.8

2015 NA WC S4 12.35 25.2 14.6 0.9

2015 NA WC S5 12.35 25.4 14.8 0.3

2015 NA WC S6 12.35 25.6 14.9 0.2

2015 NA WC S7 12.35 25.7 15.0 0.2

2015 NA WC S8 12.35 26.0 15.1 0.3

2015 NA WC S9 12.35 27.1 15.8 0.9

2015 NA WC S10 12.35 32.9 19.2 2.8

2015 NA WC S11 12.35 58.7 34.2 4.2

# 49 

# Appendix 9-4 Coal Supply Cur ves in EPA Base Case V.4.10

(cont’d)

Waste Coal Entries Only

Year Coal

Supply

Region Coal

Grade Step

Name Heat

Content

(MMBtu/Ton) Cost of Production

(2007$/Ton) Coal

Production

(Million

Tons/Year) Previous Corrected

2020 NA WC S1 12.35 22.1 12.9 6.8

2020 NA WC S2 12.35 23.1 13.5 4.0

2020 NA WC S3 12.35 24.3 14.2 2.7

2020 NA WC S4 12.35 24.8 14.4 0.9

2020 NA WC S5 12.35 25.0 14.5 0.3

2020 NA WC S6 12.35 25.1 14.6 0.1

2020 NA WC S7 12.35 25.2 14.7 0.1

2020 NA WC S8 12.35 25.4 14.8 0.3

2020 NA WC S9 12.35 26.1 15.2 0.9

2020 NA WC S10 12.35 30.1 17.5 2.7

2020 NA WC S11 12.35 46.1 26.9 4.0

2030 NA WC S1 12.35 22.1 12.9 6.6

2030 NA WC S2 12.35 23.0 13.4 3.9

2030 NA WC S3 12.35 24.2 14.1 2.6

2030 NA WC S4 12.35 24.6 14.3 0.9

2030 NA WC S5 12.35 24.8 14.4 0.3

2030 NA WC S6 12.35 24.9 14.5 0.1

2030 NA WC S7 12.35 24.9 14.5 0.1

2030 NA WC S8 12.35 25.1 14.6 0.3

2030 NA WC S9 12.35 25.7 15.0 0.9

2030 NA WC S10 12.35 29.1 16.9 2.6

2030 NA WC S11 12.35 42.3 24.6 3.9

2040 NA WC S1 12.35 22.2 12.9 6.8

2040 NA WC S2 12.35 23.2 13.5 4.0

2040 NA WC S3 12.35 24.4 14.2 2.6

2040 NA WC S4 12.35 24.9 14.5 0.9

2040 NA WC S5 12.35 25.1 14.6 0.3

2040 NA WC S6 12.35 25.1 14.6 0.1

2040 NA WC S7 12.35 25.2 14.7 0.1

2040 NA WC S8 12.35 25.4 14.8 0.3

2040 NA WC S9 12.35 26.2 15.2 0.9

2040 NA WC S10 12.35 30.1 17.5 2.6

2040 NA WC S11 12.35 45.8 26.7 4.0

# 50 

# Appendix 9-4 Coal Supply Cur ves in EPA Base Case V.4.10

(cont’d)

Waste Coal Entries Only

Year Coal

Supply

Region Coal

Grade Step

Name Heat

Content

(MMBtu/Ton) Cost of Production

(2007$/Ton) Coal

Production

(Million

Tons/Year) Previous Corrected

2050 NA WC S1 12.35 22.2 12.9 6.8

2050 NA WC S2 12.35 23.2 13.5 4.0

2050 NA WC S3 12.35 24.4 14.2 2.6

2050 NA WC S4 12.35 24.9 14.5 0.9

2050 NA WC S5 12.35 25.1 14.6 0.3

2050 NA WC S6 12.35 25.1 14.6 0.1

2050 NA WC S7 12.35 25.2 14.7 0.1

2050 NA WC S8 12.35 25.4 14.8 0.3

2050 NA WC S9 12.35 26.2 15.2 0.9

2050 NA WC S10 12.35 30.1 17.5 2.6

2050 NA WC S11 12.35 45.8 26.7 4.0

# 51 

# 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 exper ience, 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 c hange 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, im posing 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 MW with FGD to be too low. For example, one

commenter indicated that the v.4. 10 FGD retrofit costs for these un its 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 MW that 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 injecti on, 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 un its less than 100 MW in 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 Ba se 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/epaipm/docs/v410/Chapter5.pdf and www.epa.gov/airmarkets/progsregs/epaipm/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 hav e 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-

# 52 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 reachi ng a pre-specified expected lifespan. The 30-year

book life is in line with the 30-year design life typica lly 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 co mmenters identified as being prevented from

retiring for reliability purposes

Response: There are several reasons for retaining the curr ent approach that does not attempt to account

for “must run” units and does not prevent such units fr om retiring. First, for competitive business reasons,

a comprehensive listing of must-run units is not availabl e from either public or private sources. Limiting

the “must run” designation only to those units iden tified in comments would introduce inconsistency

across the universe of units. Second, there is no technically sound approach fo r 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 particula rly 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 uni ts 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 availabili ties, EPA Base Case v.4.10 adopts an approach

similar to AEO 2010 of using historical capacity factor s to define the availabilities of existing coal units.

The change was a result of analysis that showed that fo r a large portion of the coal fleet, actual capacity

factors for existing coal units fell below the ava ilabilities in NERC GADS. It is also based on an

assessment that indicated that t he system-level availabilities that are found in NERC GADS were not

entirely comparable to the plant leve l 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 assumpti on 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 Ca se v.4.10 were obtained from AEO 2010.

# 53 

# Addenda

− Notes on various modeling assumptions

Though not necessarily responses to comments rece ived on the Transport Rule or NODA, the following

features of EPA Base Case v.4.10_FTransport are a nnotated 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 App endix 5-5 on fabric filter cost development are

incorporated below from the Documentation Supplement for EPA Ba se Case v.4.10_Ptox – 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 fabr ic filter as a retrofit

option for SO 2 

# 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 SO 2 

# content of less than 2 lbs/mmBtu and is assumed to be

retrofit in conjunction with a fabric filter. When re trofit on units with a pre-ex isting fabric filter, it is

assumed that no ESP is present and that the DSI is installed upstream of t he 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 inst alled 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 t he 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 t he waste disposal cost only applies to the sorbent,

there is a 35% reduction in VOM. In this si tuation 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 Tr ansport 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 fl ue gas desulfurization (FGD) for SO2 and selective

catalytic reduction (SCR) for NO

x 

# 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 nonTransport 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 strate gy, 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 respon se 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

# 54 an IPM model run. These controls originate in one of f our possible sources. (1) Most existing controls

are the same as those found in the National Electr ic 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 Ru le existing controls are those present in 2011 or

earlier. (2) A small number of existing emission c ontrols 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 ca se 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 installati on and/or beginning of construction of a control

for post 2011 start-up. In instances where the cont rol 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 expe cted to operate (typically 2012 or 2015) both in IPM

outputs and parsed files. They do not appear in NEED S (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 res ponse 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 unit s are assumed to have a mercury EMF of 0.02.



# 7. Carbon dioxide (CO 2 

# ) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization

(FGD) System for Sulfur Dioxide (SO 2 

# ) Control: In EPA applications of IP M the chemical reactions

in a limestone forced oxidation (LSFO) system (also known as a wet FGD or wet scrubber) are

assumed to cause CO 2 

# increases according to the following equation:

CO 2 

# increase in % of total CO 2 

# from fuel =

0.35 X SO 2 

# emission rate of the fuel (in lb/MMBtu) – 0.02

For example, for coal with an SO 2 

# emission factor of 4.3 lb/MMBtu, the increase in CO 2 

# is 1.485%. In

contrast to LSFO, there is no repres entation of direct emissions of CO 2 

# or other greenhouse gases

from the other control technologies in IPM. T hese include limestone spray dryers (LSD) for SO 2 

# control, dry sorbent injection (DSI) for SO 2 

# and hydrogen chloride (HCl) co ntrol, selective catalytic

reduction (SCR) and selective non-ca talytic reduction (SNCR) for NO

x 

# control, and activated carbon

injection (ACI) for mercury control.

# 55 

# 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.56Table 5-21 Summary of Retrofit SO2(and HCl) Emission Control Performance Assumptions in v4.10_FTransportPerformanceAssumptionsLimestone Forced Oxidation(LSFO)Lime Spray Dryer (LSD) Dry Sorbent Injection (DSI)1SO2HClSO2HClSO2HClPercent Removal96%with a floor of0.06 lbs/MMBtu99%with a floor of0.0001lbs/MMBtu92%with a floor of0.065 lbs/MMBtu99%with a floor of0.0001lbs/MMBtuWith fabricfilter:70%−−−With anelectrostaticpercipitator2:50%With fabric filter:90%with a floor of0.0001 lbs/MMBtu−−−With anelectrostaticpercipitator2:60%with a floor of0.0001 lbs/MMBtuCapacity Penalty-1.65%-0.70%-0.65%Heat Rate Penalty1.68%0.71%0.65%Cost (2007$)See Table 5-3 and 5-4See Table 5-3 and 5-4 See Tables D and EApplicabilityUnits≥25MWUnits≥25MWUnits≥25MWSulfur ContentApplicabilityCoals≤2.0% Sulfur by WeightCoals≤2.0 lb/mmBtu of SO2Applicable CoalTypesBA, BB, BD, BE, BG, BH, SA, SB,SD, LD, LE, and LGBA, BB, BD, BE, SA, SB, SD, LD,LE, and LGBA, BB, BD, SA, SB, SD, and LDNotes1. The cost and performance values shown in this table apply toexisting units with pre-existing fabric filters or electrostatic precipitators.Units with neither ESP nor FF are assumed to have to install afabric filter in order to qualify for the DSI retrofit.2. The option to retrofit DSI on existing units with ESP wasnot offered in the runs performed for the current rulemaking.

# 57 5.5.3.2 Dry Sorbent Injection

EPA Base Case v4.10_FTransport includes dry sorbent inje ction (DSI) as a retrofit option for achieving (in

combination with a particulate control device) SO 2 

# (and HCl) removal. With DSI a dry sorbent is injected

into the flue gas duct where it reacts with the SO 2 

# and HCl in the flue gas to form a compound, which is

then captured in a downstream fabric f ilter or electrostatic precipitator (ESP) and disposed of as waste.

(A sorbent is a material that takes up another substa nce by either adsorption on its surface or absorption

internally or in solution. A sorbent may also chem ically react with another substance.) The sorbent

assumed in the cost and performance characterization discussed in this section is trona, a sodium-rich

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

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

onsite in-line milling to increase its surface area and c apture capability.

Removal rate assumptions : The removal rate assumptions for DSI are summarized in Table 5-21. The

assumptions shown in the last two columns of Table 5-21 were derived from assessments by EPA

engineering staff in consultation with Sargent & Lundy. As indicated in this table, the assumed SO2

removal rate for DSI + ESP is 50% and for DSI + fabric filter is 70%. The assumed HCl removal rate is

60% for DSI + ESP and 90% for DSI + fabric filter. (Thi s is noted in the next-to-t he-last column in Table

5-21.) Although the option to retrof it DSI on existing units with ESP is shown in Table 5-21 it was not

offered in the runs performed for the current rulemaking.

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

were used to update the cost of SO 2 

# and post-combustion NO

x 

# controls in EPA Base Case , v4.10,

performed similar engineering assessments of the cost of DSI retrofits with tw o 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 ar e quite different from those of wet or dry FGD. Whereas plant size

and coal sulfur rates are key underlying determinants of FGD cost, sorbent feed rate and fly ash waste

handling are the main drivers of the capital cost of DSI with plant size and coal sulfur rates playing a

secondary role.

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

installation. The sorbent feed rate needed to achieve a specified percent SO 2 

# or HCl removal 4 

# is firstly a

function of the flue gas SO 2 

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

expressed in lbs of SO 2 

# /mmBtu ), the unit’s size and heat rate , and the sorbent particle size (which

determines whether in-line milling is needed). The sor bent feed rate is also a function of the residence

time of the sorbent in the flue gas stream and the ex tent 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 prec ipitator or fabric filter).

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

assumptions that a fabric filter and in-line trona millin g are used, and that the SO2 removal rate is 60%.

The corresponding HCl removal effect is assum ed to be 90%, based on information from Solvay

Chemicals (H. Davidson, Dry Sorbent Injection for Multi-pollutant Control Case Study , CIBO IECT VIII,

August 2010).

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

particulate capture device and the flue gas SO 2 

# rate (which, as noted above, is itself a function of the

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

ܴܰܵ ൌ ቀ ௠௢௟௘௦ ௢௙ ௦௢௕௘௡௧ ௜௡௝௘௖௧

௠௢௟௘௦ ௢௙ ௌைଶ ௜௡ ௙௟௨௘ ௚௔௦ 

# ቁ

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

# 58 sulfur content of the coal and the unit’s size and h eat rate). Fly ash waste handling costs are also a

function of the ash content and the higher heating val ue (HHV) of the coal. The governing variables of

the key capital cost components of DSI are presented in Table 5-22.

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

DSI.

Module Retrofit

Difficulty

(1 =

average) Particulate

Capture

Type

(ESP or

Baghouse) Sorbent

Particle

Size

Requirement

(milled or

unmilled) Heat

Rate

(Btu/

kWh) SO2

Rate

of coal

(lb/

MMBtu) Ash

Content

of Coal

(percent) Higher

Heating

Value

(HHV)

of Coal

(Btu/lb) Unit

Size

(MW)

Sorbent

Feed

Handling X X X X X

Fly Ash

Waste

Handling X X X X X X

Once the key variables for the two DSI modules are i dentified, 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. Th e 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 (AFU DC) is provided for DSI. The cost resulting from

these calculations is the capital cost factor (exp ressed 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 comp onents 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 func tion of the “Normalized

Stoichiometric Ratio” and SO 2 

# feed rate. As noted above the feed rate is a function of the SO 2 

# rate of the

coal and the unit’s size and heat rate.

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

# 59 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 cont ents 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 sorb ent usage and the costs associated wi th waste production and disposal,.

The last component – cost of additional power – is fact ored 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 electr icity that is available for sale to the grid. For

example, if 0.65% of the unit’s electrical gener ation 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 fact or 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 e fficiency). 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 requir ed by air blowers for the

injection system, drying equipment for the transpo rt 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 in curred regardless of the extent to which the emission control system

is run. They are expressed in units of $ per kW pe r year. In calculating FOM Sargent & Lundy took into

account labor and materials costs associated with oper ations, 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 re presentative set of generating units wi th the capacities and heat rates

indicated.

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

for an example DSI appear in Appendix 5-4. The worksheets were developed by Sargent & Lundy 5



# .

5 

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

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

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

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

.60Table 5-23. Illustrative Dry Sorbent Injection (DSI) Costs forRepresentative Sizes and Heat Rates Under Assumptions in EPA Base Casev4.10_FTransportControlTypeHeatRate(Btu/kWh)SO2Rate(lb/MMBtu)CapacityPenalty(%)HeatRatePenalty(%)VariableO&M(mills/kWh)Capacity (MW)1003005007001000CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)DSI - FF9,0002.00.640.656.051222.25550.87380.57300.43280.36AssumingBituminousCoal10,0002.00.710.726.721252.28570.89400.58310.43310.3811,0002.00.790.797.401292.30590.90410.59340.46340.41DSI - ESP9,0002.01.081.1011.231412.41640.94470.64470.57470.52AssumingBituminousCoal10,0002.01.201.2212.471452.44660.96520.68520.61520.5611,0002.01.321.3413.721492.48680.98580.73580.65580.60

# 61 5.5.4 Fabric Filter (Baghouse) Cost Development

Fabric filters are not endogeno usly modeled as a separate retr ofit option in EPA Base Case

v4.10_FTransport, but are accounted fo r as a cost adder when installed in conjunction with DSl. 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 retrof it by the model with DSI and does not have an existing

fabric filter incurs the cost of installing a fabric f ilter. This cost is added to the DSI costs discussed in

section 5.5.3.2. This section de scribes the methodology used by Sarg ent & 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 particu late 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 f abric filter capital cost, the A/C ratio

is defined as the volumetric flow, (typically expressed in Actual Cubi c Feet per Minute, ACFM) of flue gas

entering the baghouse divided by the areas (typically in square feet) of f abric 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 vo lumetric 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 calculat ed, it is increased by 20% to account for additional

engineering and construction management costs, labo r premiums, and contractor profits and fees. The

resulting value is the capital, engineering, and cons truction 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 cost s, 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 capi tal 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 mu ltiplying the capital cost by a c apital 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.

# 62 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 m odeled as a retrofit option, but simply added to the

DSI costs for generating units that do not have an ex isting baghouse, the capacity and heat rate penalties

described here were not factored into the repr esentation 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 uni ts with a representative range of capacities and

heat rates.

Worksheets illustrating the detailed calculations pe rformed to obtain the capital, VOM, and FOM costs for

two example fabric filters (A/C Ratio = 4.0 and A/C Ra tio = 6.0) appear in Appendix 5-5. The worksheets

were developed by Sargent & Lundy 6



# .

6 

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

Performance for APC Technologies: Particulate Control Cost Development Methodology (Project 12301-

009), October 2010. The complete report is available for review and downloading at

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

.63Table 5-24. Illustrative Fabric Filter (Baghouse) Costs for Representative Sizes and Heat RatesUnder Assumptions in EPA BaseCasev4.10_FTransportCoal TypeHeatRate(Btu/kWh)CapacityPenalty(%)HeatRatePenalty(%)VariableO&M(mills/kWh)Capacity (MW)1003005007001000CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)Bituminous9,0000.600.60 0.15188 0.8 153 0.6 139 0.6 130 0.6 122 0.510,000205 0.9 167 0.7 151 0.6 141 0.6 132 0.611,000221 0.9 180 0.8 163 0.7 153 0.6 143 0.6Notes on Implementation1. Plant specific fabric filtercapital costs shown in this table are implemented in EPA Base Case v4.10_FTransport as an FOM adder. Plants thatinstall fabric filters incur a total FOM charge which includes the true FOM component shown in the above table plus a capital cost FOM Adder derivedby multiplying the capital cost in the table above by a capital charge rate 11.3%, i.e.,Total FOM = True FOM + Capital Cost FOM Adderwhere the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%.Plants that install fabric filters also incurthe additional VOM costs shown in the above table.2. Since the fabric filter costs were not endogenously modeled asa retrofit option, the capacity and heat rate penalties shownin the above table werenot represented in the model.

# 64 

# Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCl

(and SO 2 

# ) Emissions Control in EPA Base Case v4.10_FTransport

# 65

# 66 

# 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

# 67 

# 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.

# 6 8 

# Appendices 3-2 (State Regulations), 3-3 (NSR Settlements), and 3-4 (State Settlements)

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

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

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



# *************************************************************************************************************

Appendix 3-2 State Power Sector Regulations included in EPA Base Case v4.10_ **F** T **ransp** o **rt**

State/Region Bill Emission

Type Emission Specifications Implementation

Status

Alabama Alabama

Administrative Code

Chapter 335-3-8 NO

x 

# 0.02 lbs/MMBtu annual PPMDV for combined cycle

EGUs which commenced operation after April 1,

2003 2003

Arizona Title 18, Chapter 2,

Article 7 Hg 90% removal of Hg content of fuel or 0.0087

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

units > 25 MW 2017

California CA Reclaim Market NO

x 

# 9.68 MTons annual cap for list of entities in

Appendix A of "Annual RECLAIM Audit Market

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

SO 2 

# 4.292 MTons annual cap for list of entities in

Appendix A of "Annual RECLAIM Audit Market

Report for the Compliance Year 2005" (304 entities)

Colorado 40 C.F.R. Part 60 Hg 2012 & 2013: 80% reduction of Hg content of fuel or

0.0174 lb/GW-hr annual reduction for Pawnee

Station 1 and Rawhide Station 101

2014 through 2016: 80% reduction of Hg content of

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

units > 25 MW

2017 onwards: 90% reduction of Hg content of fuel

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

units > 25 MW 2012

Connecticut Executive Order 19

and Regulations of

Connecticut State

Agencies (RCSA)

22a-174-22 NO

x 

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

fossil units > 15 MW

2003

Executive Order 19,

RCSA 22a-198 &

Connecticut General

Statues (CGS) 22a198 SO 2 

# 0.33 lbs/MMBtu annual rate limit for all Title IV

sources > 15 MW

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

sources > 15 MW

Public Act No. 03-72

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

Delaware Regulation 1148:

Control of Stationary

Combustion Turbine

EGU Emissions NO

x 

# 0.19 lbs/MMBtu ozone season PPMDV for

stationary, liquid fuel fired CT EGUs >1 MW

0.39 lbs/MMBtu ozone season PPMDV for

stationary, gas fuel fired CT EGUs >1 MW 2009

Regulation No. 1146:

Electric Generating

Unit (EGU) MultiPollutant Regulation NO

x 

# 0.125 lbs/MMBtu rate limit of NO

x 

# annually for all

coal and residual-oil fired units > 25 MW

2009

SO 2 

# 0.26 lbs/MMBtu annual rate limit for coal and

residual-oil fired units > 25 MW

# 69 State/Region Bill Emission

Type Emission Specifications Implementation

Status

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

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

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

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

25 MW

Georgia Multipollutant Control

for Electric Utility

Steam Generating

Units SCR, FGD,

and

Sorbent

Injection

Baghouse

controls to

be installed The following plants must install controls: Bowen,

Branch, Hammond, McDonough, Scherer, Wansley,

and Yates Implementation

from 2008

through 2015,

depending on

plant and control

type

Illinois Title 35, Section

217.706 NO

x 

# 0.25 lbs/MMBtu summer season rate limit for all

fossil units > 25 MW 2004

Title 35, Part 225,

Subpart B: Control of

Hg Emissions from

Coal Fired Electric

Generation Units NO

x 

# 0.11 lbs/MMBtu annual rate limit and ozone season

rate limit for all Dynergy and Ameren coal steam

units > 25 MW 2012

SO 2 

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

Dynergy and Ameren coal steam units > 25 MW

2015 onwards: 0.25 lbs/MMBtu annual rate limit for

all Dynergy and Ameren coal steam units > 25 MW 2013

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

annual reduction for all Ameren and Dynergy coal

units > 25 MW 2015

Title 35 Part 225;

Subpart F: Combined

Pollutant Standards NO

x 

# 0.11 lbs/MMBtu ozone season and annual rate limit

for all specified Midwest Gen coal steam units 2012

SO 2 

# 0.44 lbs/MMBtu annual rate limit in 2013, decreasing

annually to 0.11 lbs/MMBtu in 2019 for all specified

Midwest Gen coal steam units 2013

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

annual reduction for all spec ified Midwest Gen coal

steam units 2015

Kansas NO

x 

# Emission

Reduction Rule,

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

x 

# 0.20 lbs/MMBtu annual rate limit for Quindaro Unit 2

and 0.26 lbs/MMBtu annual rate limit for Nearman

Unit 1. 2012

Louisiana Title 33 Part III -

Chapter 22, Control of

Emissions of Nitrogen

Oxides SO 2 

# 1.2 lbs/MMBtu ozone season PPMDV for all single

point sources that emit or have the potential to emit

5 tons or more of SO2 into the atmosphere 2005

Title 33 Part III -

Chapter 15, Emission

Standards for Sulfur

Dioxide NO

x 

# Various annual rate limits depending on plant and

fuel type for facilities within the Baton Rouge

Nonattainment Area that collectively have the

potential to emit 25 tons or more per year of NO

x 

# or

facilities within the Region of Influence that

collectively have the potential to emit 50 tons or

more per year of NO

x 

# 2005

Maine Chapter 145 NO

x 

# Control Program NO

x 

# 0.22 lbs/MMBtu annual rate limit for all fossil fuel

units > 25 MW built before 1995 with a heat input

capacity < 750 MMBtu/hr

0.15 lbs/MMBtu annual rate limit for all fossil fuel

units > 25 MW built before 1995 with a heat input

capacity > 750 MMBtu/hr

0.20 lbs/MMBtu annual rate limit for all fossil fuel

fired indirect heat exchangers, primary boilers, and

resource recovery units with heat input capacity >

250 MMBtu/hr 2005

Statue 585-B Title 38,

Chapter 4: Protection

and Improvement of

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

# 70 State/Region Bill Emission

Type Emission Specifications Implementation

Status

Maryland Maryland Healthy Air

Act NO

x 

# 3.6 MTons summer cap and 8.3 MTons annual cap

for Mirant coal units

0.5 MTons summer cap and 1.4 MTons annual cap

for Allegheny coal units

3.6 MTons summer cap and 8.03 MTons annual cap

for Constellation coal units.

2009 SO 2 

# 2009 through 2012: 23.4 MTons annual cap for

Constellation coal units, 24.2 MTons annual cap for

Mirant Coal units, and 4.6 MTons annual cap for

Allegheny coal units.

2013 onwards: 17.9 MTons annual cap for

Constellation coal units, 18.5 MTons annual cap for

Mirant Coal units, and 4.6 MTons annual cap for

Allegheny coal units.

Hg 2010 through 2012: 80% removal of Hg content of

fuel for Mirant, Allegheny, and Constellation coal

steam units

2013 onwards: 90% removal of Hg content of fuel

for Mirant, Allegheny, and Constellation coal steam

units

Massachusett

s 310 CMR 7.29 NO

x 

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

Generating Station, Somerset Station, Mount Tom,

Canal, and Salem Harbor

2006 SO 2 

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

Generating Station, Somerset Station, Mount Tom,

Canal, and Salem Harbor

Hg 2012: 85% removal of Hg content of fuel or

0.00000625 lbs/MWh annual GPS for Brayton Point,

Mystic Generating Station, Somerset Station, Mount

Tom, Canal, and Salem Harbor

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

0.00000250 lbs/MWh annual GPS for Brayton Point,

Mystic Generating Station, Somerset Station, Mount

Tom, Canal, and Salem Harbor

Michigan Part 15. Emission

Limitations and

Prohibitions - Mercury Hg 90% removal of Hg content of fuel annually for all

coal units > 25 MW 2015

Minnesota Minnesota Hg

Emission Reduction

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

coal units > 250 MW 2008

Missouri 10 CSR 10-6.350 NO

x 

# 0.25 lbs/MMBtu annual rate limit for all fossil fuel

units > 25 MW in the following counties: Bollinger,

Butler, Cape Girardeau, Carter, Clark, Crawford,

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

Madison, Marion, Mississippi, Montgomery, New

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

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

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

Washington and Wayne

0.18 lbs/MMBtu annual rate limit for all fossil fuel

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

Louis, Franklin, Jefferson, and St. Louis

0.35 lbs/MMBtu annual rate limit for all fossil fuel

units > 25 MW in the following counties: Buchanan,

Jackson, Jasper, Randolph, and any other county

not listed 2004

Montana Montana Mercury

Rule Adopted

10/16/06 Hg 0.90 lbs/TBtu annual rate limit for all non-lignite coal

units

1.50 lbs/TBtu annual rate limit for all lignite coal

units 2010

New

Hampshire RSA 125-O: 11-18 Hg 80% reduction of aggregated Hg content of the coal

burned at the facilities for Merrimack Units 1 & 2 and

Schiller Units 4, 5, & 6 2012

# 71 State/Region Bill Emission

Type Emission Specifications Implementation

Status

ENV-A2900 Multiple

pollutant annual

budget trading and

banking program NO

x 

# 2.90 MTons summer cap for all fossil steam units >

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

new units > 15 MW

3.64 MTons annual cap for Merrimack 1 & 2,

Newington 1, and Schiller 4 through 6 2007

SO 2 

# 7.29 MTons annual cap for Merrimack 1 & 2,

Newington 1, and Schiller 4 through 6

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

27.6, 27.7, and 27.8 Hg 90% removal of Hg content of fuel annually for all

coal-fired units

95% removal of Hg content of fuel annually for all

MSW incinerator units 2007

N.J. A. C. Title 7,

Chapter 27,

Subchapter 19, Table

1 NO

x 

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

following technologies:

Coal Boilers (Wet Bottom) - 1.0 for tangential and

wall-fired, 0.60 for cyclone-fired

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

for wall-fired, 0.55 for cyclone-fired

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

for wall-fired, 0.43 for cyclone-fired

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

following technologies:

All Coal Boilers: 1.50 for all

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

4.30 for cyclone-fired

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

cyclone-fired

2015 onward annual rate limits in lbs/MWh for the

following technologies:

All Coal Boilers: 1.50 for all

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

oil, 1.0 for No. 2 and lighter fuel oil

Gas only: 1.0 for all 2009

N.J. A. C. Title 7,

Chapter 27,

Subchapter 19, Table

4 NO

x 

# 2.2 lbs/MWh annual GPS for gas-burning simple

cycle combustion turbine units

3.0 lbs/MWh annual GPS for oil-burning simple

cycle combustion turbine units

1.3 lbs/MWh annual GPS for gas-burning combined

cycle CT or regenerative cycle CT units

2.0 lbs/MWh annual GPS for oil-burning combined

cycle CT or regenerative cycle CT units 2007

New York Part 237 NO

x 

# 39.91 MTons non-ozone season cap for fossil fuel

units > 25 MW 2004

Part 238 SO 2 

# 131.36 MTons annual cap for fossil fuel units > 25

MW 2005

Mercury Reduction

Program for CoalFired Electric Utility

Steam Generating

Units Hg 786 lbs annual cap through 2014 for all coal fired

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

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

MW developed after Nov.15 1990 2010

North Carolina NC Clean

Smokestacks Act:

Statute 143-215.107D NO

x 

# 25 MTons annual cap for Progress Energy coal

plants > 25 MW and 31 MTons annual cap for Duke

Energy coal plants > 25 MW 2007

SO 2 

# 2012: 100 MTons annual cap for Progress Energy

coal plants > 25 MW and 150 MTons annual cap for

Duke Energy coal plants > 25 MW

2013 onwards: 50 MTons annual cap for Progress

Energy coal plants > 25 MW and 80 MTons annual

cap for Duke Energy coal plants > 25 MW 2009

Oregon Oregon Administrative

Rules, Chapter 345,

Division 24 CO 2 

# 675 lbs/MWh annual rate limit for new combustion

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

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

emitting CO 2 

# 1997

# 7 2 State/Region Bill Emission

Type Emission Specifications Implementation

Status

Oregon Utility

Mercury Rule -

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

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

Oregon Utility

Mercury Rule -

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

Pacific

Northwest Washington State

House Bill 3141 CO 2 

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

plant 2004

Texas Senate Bill 7 Chapter

101 SO 2 

# 273.95 MTons cap of SO 2 

# for all grandfathered units

built before 1971 in East Texas Region

2003

NO

x 

# Annual cap for all grandfathered units built before

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

Texas, 1.06 in El Paso Region

Chapter 117 NO

x 

# East and Central Texas annual rate limits in

lbs/MMBtu for units that came online before 1996:

Gas fired units: 0.14

Coal fired units: 0.165

Stationary gas turbines: 0.14

2007 Dallas/Fort Worth Area annual rate limit for utility

boilers, auxiliary steam boilers, stationary gas

turbines, and duct burners used in an electric power

generating system except for CT and CC units

online after 1992:

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

lbs/MMBtu on system wide heat input weighted

average for large utility systems

0.06 lbs/MMBtu for small utility systems

Houston/Galveston region annual Cap and Trade

(MECT) for all fossil units:

17.57 MTons

Beaumont-Port Arthur region annual rate limits for

utility boilers, auxiliary steam boilers, stationary gas

turbines, and duct burners used in an electric power

generating system: 0.10 lbs/MMBtu

Utah R307-424 Permits:

Mercury

Requirements for

Electric Generating

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

coal units > 25 MW 2013

Wisconsin NR 428 Wisconsin

Administration Code NO

x 

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

> 1,000 MMBtu/hr :

Wall fired, tangential fired, cyclone fired, and

fluidized bed: 2009: 0.15, 2013 onwards: 0.10

Arch fired: 2009 onwards: 0.18

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

between 500 and 1,000 MMBtu/hr:

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

Tangential fired: 2009 onwards: 0.15

Cyclone fired: 2009: 0.20; 2013 onwards: 0.15

Fluidized bed: 2009: 0.15; 2013 onwards: 0.10

Arch fired: 2009 onwards: 0.18

# 73 State/Region Bill Emission

Type Emission Specifications Implementation

Status

Annual rate limits for CTs in lbs/MMBtu:

Natural gas CTs > 50 MW: 0.11

Distillate oil CTs > 50 MW: 0.28

Biologically derived fuel CTs > 50 MW: 0.15

Natural gas CTs between 25 and 49 MW: 0.19

Distillate oil CTs between 25 and 49 MW: 0.41

Biologically derived fuel CTs between 25 and 49

MW: 0.15

Annual rate limits for CCs in lbs/MMBtu:

Natural gas CCs > 25 MW: 0.04

Distillate oil CCs > 25 MW: 0.18

Biologically derived fuel CCs > 25 MWs: 0.15

Natural gas CCs between 10 and 24 MW: 0.19

Chapter NR 446.

Control of Mercury

Emissions Hg 2012 through 2014: 40% reduction in total Hg

emissions for all coal-fired uni ts in electric utilities

with annual Hg emissions > 100 lbs

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

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

150 MW

80% removal of Hg content of fuel or 0.0080

lbs/GW-hr reduction in coal fired EGUs > 25 MW 2010

Notes:

Updates to the EPA Base Case v4.10_ F T ransport from EPA Base Case 4.10 include the following:

1) An update of the modeling of SO 2 

# rate limits in Connecticut

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

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

4) An update of the modeling of NO

x 

# rate limits in Louisiana

5) An update of the modeling of the NO

x 

# annual and summer caps and SO 2 

# annual cap in Maryland

6) An update of the modeling of the NO

x 

# rate limits in New JerseyAllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateAlabama PowerJames H. Miller Alabama Units 3 & 4Install andoperate FGDcontinuously95% 12/31/11Operateexisting SCRcontinuously0.1 05/01/08 0.03 12/31/06Within 45 daysof settlemententry, APC mustretire 7,538 SO2emissionallowances.APC shall notsell, trade, orotherwiseexchange anyPlant Millerexcess SO2emissionallowancesoutside of theAPC system1/1/21http://www.epa.gov/compliance/resources/cases/civil/caa/alabamapower.htmlMinnkota Power CooperativeUnit 1Install andcontinuouslyoperate FGD95% if wetFGD, 90% ifdry12/31/11Install andcontinuouslyoperate Overfire AIR, orequivalenttechnologywith emissionrate < .360.36 12/31/090.03 if wetFGD, .015if dry FGDUnit 2Design,upgrade, andcontinuouslyoperate FGD90% 12/31/10Install andcontinuouslyoperate overfire AIR, orequivalenttechnologywith emissionrate < .360.36 12/31/07 0.03 Before 2008SIGECOUnit 1Repower tonatural gas(or retire)12/31/06Unit 2Improve andcontinuouslyoperateexisting FGD(shared byUnits 2 and 3)95% 06/30/04Unit 3Improve andcontinuouslyoperateexisting FGD(shared byUnits 2 and 3)95% 06/30/04OperateExisting SCRContinuously0.1 09/01/03Install andcontinuouslyoperate aBaghouse0.015 06/30/07PSEG FOSSILBergen New Jersey Unit 2Repower tocombinedcycle12/31/02Plant willsurrender 4,346allowances foreach year 2012–2015, 8,693allowances foryears 2016–2018, 12,170allowances foryear 2019, and14,886allowances/yearthereafter ifUnits 1–3 areoperational by12/31/2015. Ifonly Units 1 and2 areoperationalby12/31/2015,the plant shallretire 17,886units in 2020and thereafter.The provisionAppendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10_FTransport (05-16-11)ReferenceThe provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.http://www.epa.gov/compliance/resources/cases/civil/caa/sigecofb.htmlMinnkota shallnot sell ortrade NOxallowancesallocated toUnits 1, 2, or 3that wouldotherwise beavailable forsale or tradeas a result ofthe actionstaken by thesettlingdefendants tocomply withtherequirementshttp://www.epa.gov/compliance/resources/cases/civil/caa/minnkota.htmlUnitIndianaCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateMilton R. YoungFB CulleyMinnesotaBeginning 1/01/2006, Minnkota shall not emit more than 31,000 tons of SO2/year, no more than 26,000 tons beginning 2011, no more than 11,500 tons beginning 1/01/2012. If Unit 3 is not operational by12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500.74AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateHudson New Jersey Unit 2Install DryFGD (orapproved alt.technology)andcontinuallyoperate0.15 12/31/06Install SCR (orapproved tech)and continuallyoperate0.1 05/01/07InstallBaghouse (orapprovedtechnology)0.015 12/31/06Mercer New Jersey Units 1 & 2Install DryFGD (orapproved alt.technology)andcontinuallyoperate0.15 12/31/10Install SCR (orapproved tech)and continuallyoperate0.13 05/01/06TECOUnits 1 & 2ExistingScrubber(shared byUnits 1 & 2)95% (95% or.25)09/1/00(01/01/13)Install SCR 0.1 05/01/09Unit 3ExistingScrubber(shared byUnits 3 & 4)93% if Units 3& 4 areoperating2000(01/01/10)Install SCR 0.1 05/01/09Unit 4ExistingScrubber(shared byUnits 3 & 4)93% if Units 3& 4 areoperating06/22/05 Install SCR 0.1 07/01/07Gannon Florida Six unitsRetire all sixcoal units andrepower atleast 550 MWof coalcapacity tonatural gas12/31/04WEPCOUnits 1–4Retire orinstall SO2and NOxcontrols12/31/12Install andcontinuouslyoperate FGD(or approvedequiv. tech)95% or 0.1 12/31/12Install SCR (orapproved tech)and continuallyoperate0.1 12/31/12Units 5 & 6Install andoperate lowNOxburners12/31/03Units 7 & 8Operateexisting lowNOxburners12/31/05InstallBaghouseUnit 9Operateexisting lowNOxburners12/31/06InstallBaghouse1Install andcontinuouslyoperate FGD(or approvedcontrol tech)95% or 0.1 12/31/06Install andcontinuouslyoperate SCR(or approvedtech)0.1 12/31/062Install andcontinuouslyoperate FGD(or approvedcontrol tech)95% or 0.1 12/31/07Install andcontinuouslyoperate SCR(or approvedtech)0.1 12/31/03http://www.epa.gov/compliance/resources/cases/civil/caa/wepco.htmlPresque IsleThe provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedhWisconsinPleasant PrairieWEPCO shall comply with the following system wide average NOxemission rates and total NOxtonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and by 1/1/2013 an emission rateof 0.17 and 17, 400 tons. For SO2emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, by 1/1/2007 an emission rate of 0.61and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 anemission rate of 0.32 and 33,300 tons.Big BendThe provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.WisconsinFloridahttp://www.epa.gov/compliance/resources/cases/civil/caa/teco.htmlhttp://www.epa.gov/compliance/resources/cases/civil/caa/psegllc.htmldid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.75AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnits 5 & 6Install andcontinuouslyoperate FGD(or approvedcontrol tech)95% or 0.1 12/31/12Install andcontinuouslyoperate SCR(or approvedtech)0.1 12/31/12Unit 7Install andcontinuouslyoperate FGD(or approvedcontrol tech)95% or 0.1 12/31/12Install andcontinuouslyoperate SCR(or approvedtech)0.1 12/31/12Unit 8Install andcontinuouslyoperate FGD(or approvedcontrol tech)95% or 0.1 12/31/12Install andcontinuouslyoperate SCR(or approvedtech)0.1 12/31/12Port Washington WisconsinUnits 1–4Retire12/31/04 forUnits 1–3.Unit 4 byentry ofconsentdecreeValley WisconsinBoilers 1–4Operateexisting lowNOxburner30 days afterentry of consentdecreeVEPCOMount Storm West VirginiaUnits 1–3Construct orimprove FGD95% or 0.15 01/01/05Install andcontinuouslyoperate SCR0.11 01/01/08Unit 4Install andcontinuouslyoperate SCR0.1 01/01/13Unit 5Construct orimprove FGD95% or 0.13 10/12/12Install andcontinuouslyoperate SCR0.1 01/01/12Unit 6Construct orimprove FGD95% or 0.13 01/01/10Install andcontinuouslyoperate SCR0.1 01/01/11ChesapeakeEnergyVirginia Units 3 & 4Install andcontinuouslyoperate SCR0.1 01/01/13Clover Virginia Units 1 & 2 Improve FGD 95% or 0.13 09/01/03Possum Point Virginia Units 3 & 4Retire andrepower tonatural gas05/02/03Santee CooperUnit 1Upgrade andcontinuouslyoperate FGD95% 06/30/06Install andcontinuouslyoperate SCR0.1 05/31/04Unit 2Upgrade andcontinuouslyoperate FGD87% 06/30/06Install andContinuouslyoperate SCR0.11/0.105/31/04 and05/31/07Unit 1Install andcontinuouslyoperate FGD95% 12/31/08Install andcontinuouslyoperate SCR0.11/0.111/30/04 and11/30/04Unit 2Install andcontinuouslyoperate FGD95% 12/31/08Install andcontinuouslyoperate SCR0.12 11/30/04Unit 3Upgrade andcontinuouslyoperateexisting FGD90% 12/31/08Install andcontinuouslyoperate SCR0.14/0.1211/30/2005 and11/30/08that excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.Oak Creek WisconsinThe provisiondid not specifyan amount ofSO2allowancesto besurrendered. Itonly providedhttp://www.epa.gov/compliance/resources/cases/civil/caa/santeecooper.htmlCrossOn or beforeMarch 31 ofevery yearbeginning in2013 andcontinuingthereafter,VEPCO shallsurrender45,000 SO2allowances.WinyahSouth CarolinaSouth CarolinaVirginiahttp://www.epa.gov/compliance/resources/cases/civil/caa/vepco.htmlChesterfieldThe Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 – 2010, 54,000 in 2011, 50,000 in 2012, and 30,250 each year there after. Beginning1/1/2013 they will have a system wide emission rate no greater then 0.15 lb/mmBtu.Santee Cooper shall comply with the following system wide averages for NOxemission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000tons, by 1/1/2007 an emission rate of 0.18 and 25,000tons, by 1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85,000 tons, by1/1/2009 an emission rate of 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65 tons.76AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnit 4Upgrade andcontinuouslyoperateexisting FGD90% 12/31/07Install andcontinuouslyoperate SCR0.13/0.1211/30/05 and11/30/08Unit 1Operate lowNOxburner ormore stringenttechnology06/25/04Unit 2Operate lowNOxburner ormore stringenttechnology05/01/04Jeffries South Carolina Units 3, 4Operate lowNOxburner ormore stringenttechnology06/25/04Ohio EdisonUnit 1Install InductScrubber (orapprovedequiv.control tech)50% removalor 1.1lb/mmBtu12/31/08Install SNCR(or approvedalt. tech) &operatecontinuously0.25 10/31/07Unit 2Install InductScrubber (orapprovedequiv.control tech)50% removalor 1.1lb/mmBtu12/31/08Operateexisting SNCRcontinuously0.25 02/15/06Unit 3Install InductScrubber (orapprovedequiv.control tech)50% removalor 1.1lb/mmBtu12/31/08Operate lowNOxburnersand overfire airby 12/1/05;install SNCR(or approvedalt. tech) &operatecontinuouslyby 12/31/070.2512/01/05and10/31/07Unit 4Install InductScrubber (orapprovedequiv.control tech)50% removalor 1.1lb/mmBtu06/30/09Install SNCR(or approvedalt. tech) &operatecontinuously0.25 10/31/07Unit 5Install FlashDryerAbsorberor ECO2(orapprovedequiv.control tech) &operatecontinuously50% removalor 1.1lb/mmBtu06/29/09Install SNCR(or approvedalt. tech) &OperateContinuously0.29 03/31/08onlyprovidedthat excessallowancesresulting fromcompliance withNSR settlementprovisions mustbe retired.Grainger South CarolinaW.H. SammisPlantOhiohttp://www.epa.gov/compliance/resources/cases/civil/caa/ohioedison.htmlBeginning on1/1/2006, OhioEdison may use,sell or transferany restrictedSO2only tosatisfy theOperationalNeeds at theSammis, Burgerand MansfieldPlant, or newunits within theFirstEnergySystem thatcomply with a96% removal forSO2. Forcalendar year2006 throughOhio Edison shall achieve reductions of 2,483 tons NOxbetween 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1–3 during the months of October throughApril, and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOxrequired for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2by 12/31/2010.No later than 8/11/2005, Ohio Edison shall install and operate low NOxburners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization with software tominimize NOxemissions from Sammis Units 1–5.77AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnit 6Install FGD3(orapprovedequiv.control tech) &operatecontinuously95% removalor 0.13lb/mmBtu06/30/11Install SNCR(or approvedalt. tech) &operatecontinuously"MinimumExtentPracticable"06/30/05OperateExistingESPContinuously0.03 01/01/10Unit 7Install FGD (orapprovedequiv.control tech) &operatecontinuously95% removalor 0.13lb/mmBtu06/30/11Operateexisting SNCRContinuously"MinimumExtentPracticable"08/11/05OperateExistingESPContinuously0.03 01/01/10Unit 1Upgradeexisting FGD95% 12/31/05Unit 2Upgradeexisting FGD95% 12/31/06Unit 3Upgradeexisting FGD95% 10/31/07Eastlake Ohio Unit 5Install low NOxburners, overfiredair and SNCR& operatecontinuously"MinimizeEmissionsto theExtentPracticable"12/31/06Unit 4 12/31/11Unit 5 12/31/11MirantI1,6Unit 1Unit 2Unit 3Install low NOxburners (ormore effectivetech) &operatecontinuously05/01/04Unit 4Install low NOxburners (ormore effectivetech) &operatecontinuously05/01/04Unit 5Install low NOxburners (ormore effectivetech) &operatecontinuously05/01/04PennsylvaniaOhioVirginiahttp://www.epa.gov/compliance/resources/cases/civil/caa/mirant.htmlPotomac RiverPlant2006through2017, OhioEdison mayaccumulate SO2allowances foruse at theSammis,Burger, andMansfieldplants, orFirstEnergyunits equippedwith SO2EmissionControlStandards.Beginning in2018, OhioEdison shallsurrenderunusedrestricted SO2allowances.Mansfield PlantRepower withat least 80%biomass fuel,up to 20% lowsulfur coal.BurgerSystem-wide NOxEmission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NOxEmission Ozone Season Caps: 14,700 tons 2004; 13,340tons 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 SeasonEmission Rate of 0.150 lb/mmBtu NOx.78AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnit 1Install SCR(or approvedalt. tech) &operatecontinuously0.1 05/01/07Unit 2Install SCR(or approvedalt. tech) &operatecontinuously0.1 05/01/08Unit 1Install andcontinuouslyoperate FGD(or equiv.technology)95% 06/01/10Unit 2Install andcontinuouslyoperate FGD(or equiv.technology)95% 06/01/10Illinois PowerUnits 1 & 2Install wet ordry FGD (orapprovedequiv. alt.tech) &operatecontinuously0.1 12/31/11Operate OFA& existing SCRcontinuously0.1 08/11/05Install &continuouslyoperateBaghouse0.015 12/31/10Unit 3Install wet ordry FGD (orapprovedequiv. alt.tech) &operatecontinuously0.1 12/31/11Operate OFAand/or low NOxburners0.12 until12/30/12;0.1 from12/31/1208/11/05 and12/31/12Install &continuouslyoperateBaghouse0.015 12/31/10Havana Illinois Unit 6Install wet ordry FGD (orapprovedequiv. alt.tech) &operatecontinuously1.2 lb/mmBtuuntil12/30/2012;0.1 lb/mmBtufrom12/31/2012onward08/11/05and12/31/12Operate OFAand/or low NOxburners &operateexisting SCRcontinuously0.1 08/11/05Install &continuouslyoperateBaghouse,then installESP or alt. PMequipFor Baghouse:0.015lb/mmBtu;For ESP:0.03lb/mmBtuForBaghouse:12/31/12;For ESP:12/31/05By year end2008, Dynergywill surrender12,000 SO2emissionallowances, byyear end 2009 itwill surrender18,000, by yearend 2010 it willsurrender24,000, any byyear end 2011and each yearthereafter it willsurrender30,000allowances. IfIllinoisMorgantownPlantChalk PointFor each yearafter MirantcommencesFGD operationat Chalk Point,Mirant shallsurrender thenumber of SO2Allowancesequal to theamount bywhich the SO2Allowancesallocated to theUnits at theChalk PointPlant aregreater than thetotal amount ofSO2emissionsallowed underthis SectionXVIII.MarylandMarylandhttp://www.epa.gov/compliance/resources/cases/civil/caa/illinoispower.htmlBaldwinNote: Havana Unit 6 in the Illinois Power NSR settlement refers to the affected electric generator. The provisions shown here as applying to Havana Unit 6 are represented in IPM as applying to Havana Unit 9,which is the boiler that powers generator unit #6.System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 tons 2011; 49,500 tons 2012;29,000 tons 2013 onward.79AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnit 1 1.2 07/27/05Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05Install ESP (orequiv. alt. tech)& continuouslyoperate ESPs0.03 12/31/06Unit 2 1.2 07/27/05Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05Install ESP (orequiv. alt. tech)& continuouslyoperate ESPs0.03 12/31/06Vermilion Illinois Units 1 & 2 1.2 01/31/07Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05Install ESP (orequiv. alt. tech)& continuouslyoperate ESPs0.03 12/31/10Wood River Illinois Units 4 & 5 1.2 07/27/05Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05Install ESP (orequiv. alt. tech)& continuouslyoperate ESPs0.03 12/31/05Kentucky Utilities CompanyEW BrownGeneratingStationKentucky Unit 3 Install FGD 97% or 0.100 12/31/10Install andcontinuouslyoperate SCRby 12/31/2012,continuouslyoperate lowNOxboiler andOFA.0.07 12/31/12Continuouslyoperate ESP0.03 12/31/10KU mustsurrender53,000 SO2allowances of2008 or earliervintage byMarch 1, 2009.All surplus NOxallowances mustbe surrenderedthrough 2020.SO2and NOxallowancesmay not beused forcompliance,and emissionsdecreases forpurposes ofcomplying withthe ConsentDecree do notearn credits.http://www.epa.gov/compliance/resources/cases/civil/caa/kucompany.htmlSalt River Project Agricultural Improvement and Power District (SRP)Unit 1 orUnit 2Immediatelybegincontinuousoperation ofexisting FGDson both units,install newFGD.95% or 0.08New FGDinstalled by1/1/2012Install andcontinuouslyoperate lowNOxburnerand SCR0.32 prior toSCRinstallation,0.080 afterLNB by06/01/2009,SCR by06/01/2014Optimizationbeginsimmediately,rate limitbegins01/01/12(date of newFGDinstallation)Unit 1 orUnit 2Install newFGD95% or 0.08 01/01/13Install andcontinuouslyoperate lowNOxburner0.32 06/01/11Optimizationbeginsimmediately,rate limitbegins01/01/13(date of newFGDinstallation)American Electric PowerAnnual Cap(tons)YearAnnual Cap(tons)YearArizonathe surrenderedallowancesresult ininsufficientremainingallowancesallocated to theunits comprisingthe DMGsystem, DMGcan request tosurrender fewerSO2allowances.Hennepin IllinoisNOxand SO2CoronadoGeneratingStationOptimizationand continuousoperation ofexisting ESPs.0.03Beginning in2012, all surplusSO2allowancesfor bothCoronado andSpringervilleUnit 4 must besurrenderedthrough 2020.The allowanceslimited by thiscondition may,however, beused forcompliance at aprospectivefuture plantusing BACT andotherwisespecified in par.54 of theconsent decree.SO2and NOxallowancesmay not beused forcompliance,and emissionsdecreases forpurposes ofcomplying withthe ConsentDecree do notearn credits.http://www.epa.gov/compliance/resources/cases/civil/caa/srp.html80AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsState450,000 2010 96,000 2009450,000 2011 92,500 2010420,000 2012 92,500 2011350,000 2013 85,000 2012340,000 2014 85,000 2013275,000 2015 85,000 2014260,000 2016 75,000 2015235,000 2017 72,0002016 andthereafter184,000 2018174,0002019 andthereafterWest VirginiaSporn1–4VirginiaClinch River1–3IndianaTannersCreek1–3West VirginiaKammer1–3Unit 1Install andcontinuouslyoperate FGD12/31/09Install andcontinuouslyoperate SCR01/01/08Unit 2Install andcontinuouslyoperate FGD12/31/10Install andcontinuouslyoperate SCR01/01/09Unit 3Install andcontinuouslyoperate FGD12/31/09Install andcontinuouslyoperate SCR01/01/08Unit 1Burn only coalwith no morethan 1.75lb/MMBtuannualaverageDate of entryContinuouslyoperate lowNOxburnersDate of entryUnit 2Install andcontinuouslyoperate FGD12/31/15Install andcontinuouslyoperate SCR01/01/09Amos West VirginiaKentuckyBig Sandyhttp://www.epa.gov/compliance/resources/cases/civil/caa/americanelectricpower1007.htmlAt least 600MWfrom variousunitsRetire, retrofit,or re-power12/31/18Eastern System-WideNOxand SO2allowances thatwould havebeen madeavailable byemissionreductionspursuant to theConsent Decreemust besurrendered.allowancesmay not beused to complywith any of thelimits imposedby the ConsentDecree. TheConsentDecreeincludes aformula forcalculatingexcess NOxallowancesrelative to theCAIRAllocations,and restrictsthe use ofsome. Seepar. 74-79 fordetails.Reducingemissionsbelow theEasternSystem-WideAnnualTonnageLimitations forNOxand SO2earnssupercompliance allowances.81AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnit 1Install andcontinuouslyoperate FGD12/31/08Install andcontinuouslyoperate SCR01/01/09Continuouslyoperate ESP0.03 12/31/09Unit 2Install andcontinuouslyoperate FGD12/31/08Install andcontinuouslyoperate SCR01/01/09Continuouslyoperate ESP0.03 12/31/09Unit 3Install andcontinuouslyoperate FGD12/31/12Install andcontinuouslyoperate SCR01/01/09Clinch River VirginiaUnits1–3Plant-wideannual cap:21,700 tonsfrom 2010 to2014, then16,300 after1/1/20152010–2014,2015 andthereafterContinuouslyoperate lowNOxburnersDate of entryUnit 1Retire, retrofit,or re-powerDate of entryUnit 2Retire, retrofit,or re-powerDate of entryUnit 3Retire, retrofit,or re-power12/31/12Unit 4Install andcontinuouslyoperate FGD12/31/10Install andcontinuouslyoperate SCR12/31/10Unit 5Upgradeexisting FGD95% 12/31/09Continuouslyoperate lowNOxburnersDate of entryUnit 6Upgradeexisting FGD95% 12/31/09Continuouslyoperate lowNOxburnersDate of entryUnit 1Install andcontinuouslyoperate FGDDate of entryInstall andcontinuouslyoperate SCR01/01/09Unit 2Install andcontinuouslyoperate FGDDate of entryInstall andcontinuouslyoperate SCR01/01/09Units1–3Units 5, 6Burn only coalwith no morethan 1.75lb/MMBtuannualaverageDate of entryContinuouslyoperate lowNOxburnersDate of entryKammer West VirginiaUnits1–3Plant-wideannual cap:35,00001/01/10Continuouslyoperate over-fire airDate of entryKanawha River West Virginia Units 1, 2Burn only coalwith no morethan 1.75lb/MMBtuannualaverageDate of entryContinuouslyoperate lowNOxburnersDate of entryUnit 1Install andcontinuouslyoperate FGD12/31/07Install andcontinuouslyoperate SCR01/01/09Unit 2Install andcontinuouslyoperate FGD12/31/07Install andcontinuouslyoperate SCR01/01/09OhioWest VirginiaOhioOhioVirginiaCardinalConesvilleGavinGlen LynMitchell82AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateMountaineer West Virginia Unit 1Install andcontinuouslyoperate FGD12/31/07Install andcontinuouslyoperate SCR01/01/08Units1–4Retire, retrofit,or re-power12/31/15Unit 5Install andcontinuouslyoperate FGD12/31/15Install andcontinuouslyoperate SCR01/01/08Continuouslyoperate ESP0.03 12/31/02Picway Ohio Unit 9Continuouslyoperate lowNOxburnersDate of entryUnit 1Install andcontinuouslyoperate FGD12/31/17Install andcontinuouslyoperate SCR12/31/17Unit 2Install andcontinuouslyoperate FGD12/31/19Install andcontinuouslyoperate SCR12/31/19Sporn West Virginia Unit 5Retire, retrofit,or re-power12/31/13Units1–3Burn only coalwith no morethan 1.2lb/MMBtuannualaverageDate of entryContinuouslyoperate lowNOxburnersDate of entryUnit 4Burn only coalwith no morethan 1.2%sulfur contentannualaverageDate of entryContinuouslyoperate overfire airDate of entryEast Kentucky Power Cooperative Inc.By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOxcontrols at Cooper 2 by 12/31/2012 and SO2controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012.12-monthrolling limit(tons)Start of 12-month cycle12-monthrolling limit(tons)Start of 12-month cycle57,000 10/01/08 11,500 01/01/0840,000 07/01/11 8,500 01/01/13OhioMuskingumRiverIndianaTanners Creek0.03System-wide12-monthrolling tonnagelimits applyAll units mustoperate lowNOxboilersPM controldevices mustbe operatedcontinuouslysystem-wide,ESPs must beoptimizedwithin 270 daysof entry date,or EKPC maychoose tosubmit a PMPollutionControlUpgradeAnalysis.System-wideAll surplus SO2allowances mustbe surrenderedeach year,beginning in2008.1 year fromentry dateSO2and NOxallowancesmay not beused to complywith theConsentDecree. NOxallowancesthat wouldbecomeavailable as aresult ofcompliancewith theConsentDecree maynot be sold ortraded. SO2and NOxallowancesallocated toEKPC must beused within theEKPC systemhttp://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlIndianaRockport83AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsState28,000 01/01/13 8,000 01/01/15Unit 1Install andcontinuouslyoperate FGD95% or 0.1 6/30/2011Continuouslyoperate SCR0.12 forUnit 1 until01/01/2013,at whichpoint theunit limitdrops to0.1. Priorto01/01/2013,thecombinedaveragewhen bothunits areoperatingmust be nomore than0.160 days afterentryUnit 2Install andcontinuouslyoperate FGDby 10/1/200895% or 0.1 1/1/2009Continuouslyoperate SCRand OFA0.1 for Unit2, 0.1combinedaveragewhen bothunits areoperating60 days afterentryUnit 1Install andcontinuouslyoperate lowNOxburners by10/31/20070.46 01/01/08Unit 2Install andcontinuouslyoperate lowNOxburners by10/31/20070.46 01/01/08Unit 3EKPC maychoose toretire Dale 3and 4 in lieuof installingcontrols inCooper 212/31/2012Unit 4Unit 1SpurlockEKPC mustsurrender 1,000NOxallowancesimmediatelyunder the ARP,and 3,107 underthe NOxSIPCall. EKPCmust alsosurrender15,311 SO2allowances.Dale Plant KentuckyKentuckyDate of entryhttp://www.epa.gov/compliance/resources/cases/civil/caa/eastkentuckypowerdale0907.htmlEKPCsystem.Allowancesmade availabledue tosupercompliance may be soldor traded.84AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateUnit 2If EKPC optsto installcontrols ratherthan retiringDale, it mustinstall andcontinuouslyoperate FGDor equiv.technology95% or 0.10If EKPC electsto installcontrols, itmustcontinuouslyoperate SCRor install equiv.technology0.08 (or90% if nonSCRtechnologyis used)12/31/12Nevada Power CompanyBeginning 1/1/2010, combined NOxemissions from Units 5,6,7, and 8 must be no more than 360 tons per year.Unit 55ppm 1-houraverage12/31/08 (ULNBinstallation),01/30/09 (1-hour average)Unit 65ppm 1-houraverage12/31/09 (ULNBinstallation),01/30/10 (1-hour average)Unit 75ppm 1-houraverage12/31/09 (ULNBinstallation),01/30/10 (1-hour average)Unit 85ppm 1-houraverage12/31/08 (ULNBinstallation),01/30/09 (1-hour average)Dayton Power & LightNon-EPA Settlement of 10/23/2008Owners maynot purchaseany newcatalyst withSO2to SO3conversionrate greaterthan 0.5%0.17 stationwide30 days afterentry0.17 stationwide60 days afterentry date82% includingdata fromperiods ofmalfunctions7/31/09through7/30/11Install controltechnology onone unit0.10 on anysingle unit12/31/120.15 stationwide07/01/120.10 stationwide12/31/14PSEG FOSSIL, Amended Consent Decree of November 2006Unit 7 Retire unit 01/01/07http://www.epa.gov/compliance/resources/decrees/amended/psegfossil-amendedcd.pdfUnit 8 Retire unit 01/01/070.030 lbper unitOhioNew Jerseyafter 7/31/11StuartGeneratingStation82% includingdata fromperiods ofmalfunctionsKearnyAllowancesallocated toKearny,Hudson,and07/31/09NOxand SO2allowancesmay not beused to complywith themonthly ratesspecified in theConsentDecree.Courtlink documentprovided by EPA in emailInstallrigid-typeelectrodes ineachunit's ESP12/31/1596% or 0.10 07/31/09Station-widehttp://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlNevadaClark GeneratingStationUnits mayonly firenatural gasIncrease waterinjectionimmediately,then install andoperate ultralow NOxburners(ULNBs) orequivalenttechnology. In2009, Units 5and 8 may notemit more than180 tonscombinedAllowancesmay not beused to complywith theConsentDecree, andno allowancesmade availabledue tocompliancewith theConsentDecree maybe traded orsold.Completeinstallation ofFGDs on eachunit.Cooper Kentucky85AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsState0.15 12/31/10Install SCR (orapproved tech)and continuallyoperate0.1 12/31/10InstallBaghouse (orapprovedtechnology)0.015 12/31/10Annual Cap(tons)YearAnnual Cap(tons)Year5,547 2007 3,486 20075,270 2008 3,486 20085,270 2009 3,486 20095,270 2010 3,486 2010Mercer New Jersey Units 1 &2Install DryFGD (orapproved alt.technology)andcontinuallyoperate0.15 12/31/10Install SCR (orapproved tech)and continuallyoperate0.1 01/01/07InstallBaghouse (orapprovedtechnology)0.015 12/31/10Jeffrey EnergyCenterKansas All unitsDuke EnergyUnits 1 & 3Retire orrepower asnatural gas1/1/2012Units 2 & 4Install Drysorbentinjectiontechnology80% 1/1/2012Units 2 & 3Units 1 & 4American Municipal PowerGorsuch Station Ohiohttp://amppartners.org/newsroom/amp-to-retire-gorsuchgenerating-station/Elected to Retire Dec 15,2010 (must retire by Dec 31,2012)IndianaInstall DryFGD (orapproved alt.technology)andcontinuallyoperateGallagherWestar EnergyUnits 1, 2, and 3 have a total annual limit of6,600 tons of SO2 and an annual rate limit of0.07 lbs/MMBtu starting 2012Units 1, 2, and 3 must all install FGDs by2011 and operate them continuously.FGDs must maintain a 30-Day RollingAverage Unit Removal Efficiency for SO2 ofat least 97% or a 30-Day Rolling AverageUnit Emission Rate for SO2 of no greaterthan 0.070 lb/MMBtu.Units 1-3 must continuously operate LowNOx Combustion Systems by 2012 andachieve and maintain a 30-Day RollingAverage Unit Emission Rate for NOx of nogreater than 0.180 lb/MMBtu.One of the three units must install an SCR by2015 and operate it continuously to maintaina 30-Day Rolling Average Unit Emission Ratefor NOx of no greater than 0.080 lb/MMBtu.By 2013 Westar shall elect to either (a) installa second SCR on one of the other JEC Unitsby 2017 or (b) meet a 0.100 lb/MMBtu PlantWide 12-Month Rolling Average EmissionRate and 9.6 MTons annual cap for NOx by2015Units 1, 2, and 3 must operate each ESPand FGD system continuously by 2011and maintain a 0.030 lb/MMBtu PMEmissions Rate.Units 1 and 2’s ESPs must be rebuilt by2014 in order to meet a 0.030 lb/MMBtuPM Emissions Rate,Mercer may onlybe used for theoperationalneeds of thoseunits, and allsurplusallowances mustbe surrendered.Within 90 daysof amendedConsentDecree, PSEGmust surrender1,230 NOxAllowances and8,568 SO2Allowances notalreadyallocated to orgenerated bythe units listedhere. Kearnyallowances mustbe surrenderedwith theshutdown ofthose units.Hudson New Jersey Unit 286AllowanceRetirementAllowanceRestrictionActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipment Rate Effective Date Equipment RateEffectiveDateRetirement RestrictionEffectiveDateReferenceUnitCompany andPlantRetire/RepowerSO2controlPM or Mercury ControlNOxControlSettlement ActionsStateRatts Indiana Units 1 & 2Install &continuallyoperateSNCRS0.25 12/31/2011Unit 1Continusly runcurrent FGDfor 90%removal andupdate FGDfor 98%removal by201298% 2012Unit 2Continusly runcurrent FGDfor 90%removal andupdate FGDfor 98%removal by201498% 2014Allen Steam PlantTennessee Units 1 - 3 Install FGD 12/31/2015 Operate SCR In NEEDSBull Run Tennessee Unit 1Operate WetFGDIn NEEDS Operate SCR In NEEDSUnits 1 - 4 Install FGD 6/30/2016 Install SCR 6/30/2016Unit 5 Install FGD 12/31/2015 Operate SCR In NEEDSCumberland Tennessee Units 1 & 2Operate WetFGDIn NEEDS Operate SCR In NEEDSGallatin Tennessee Units 1 - 4 Install FGD 12/31/2017 Install SCR 12/31/2017Units 1 & 2 Retire 12/31/2012Units 3 & 4 Install FGD 12/31/2015 Install SCR 12/31/2015Units 1 - 4 Retire 12/31/2017Units 5 - 8 Retire 12/31/2018Units 9 & 10 Retire 12/31/2019Kingston Kentucky Units 1 - 9Operate WetFGDIn NEEDS Operate SCR In NEEDSUnits 1 & 2 Upgrade FGD 93% 12/31/2012 Operate SCR In NEEDSUnit 3Operate WetFGDIn NEEDS Operate SCR In NEEDSShawnee Kentucky Units 1 & 4 Install FGD 12/31/2017 Install SCR 12/31/2017Units 1 & 2 Retire 7/31/2013Units 3 & 4 Retire 7/31/2014Units 5 & 6 Retire 7/31/2015Units 7 & 8Operate WetFGDIn NEEDS Operate SCR In NEEDSNotes:Widows Creek AlabamaParadise KentuckyTennesseeJohn Sevier TennesseeJohnsonvilleColbert AlabamaMerom IndianaContinuouslyoperateexisting SCRsContinuously operate ESP0.12Continuously operate ESP and achievePM rate no greater than 0.007 by 6/1/12http://www.epa.gov/compliance/resources/cases/civil/caa/hoosier.htmlAnnually surrender any NOx and SO2allowances that Hoosier does not need inorder to meet its regulatory obligationsContinuously operate ESP and achievePM rate no greater than 0.007 by 6/1/1310) 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.6) For units for which an FGD is modeled as an emissions constraint in EPA Base Case, EPA used the assumptions on removal efficiencies that are shown in the latest emission control technologies documentation7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and 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 emissionsrate equal to 10% of the unit's uncontrolled rate, with a floor of .06 lb/MMBtu or used the emission limit if provided.9) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case documentation materials.2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlementactions are simplified for representation in the model. This table is not intended to be a comprehensive description of allelements of the actual settlementagreements.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 onemission 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 EPABase Case5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected inEPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not included in EPA Base Case.Hoosier Energy Rural Electric Cooperative1) Updates to the EPA Base Case 4.10_FTransport from EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the control requirements on the Mercer plant under the PSEG Fossilsettlement, and an update to the SO2emission modeling on Jeffrey Energy Center as part of the Westar settlement.Tennessee Valley Authority8788Appendix 3-4 State Settlements in EPA Base Case v4.10_FTransportCompany andPlantStateUnitState Enforcement ActionsRetire/RepowerSO2controlNOxControlPM ControlMercury ControlActionEffectiveDateEquipmentPercentRemoval orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateAESGreenidgeNewYorkUnit 4Install FGD90%09/01/07Install SCR0.1509/01/07Unit 3Install BACT12/31/09Install BACT12/31/09WestoverNewYorkUnit 890%12/31/10Install SCR0.1512/31/10Unit 7Install BACT12/31/09Install BACT12/31/09HicklingNewYorkUnits 1 &2Install BACT05/01/07Install BACT05/01/07JennisonNewYorkUnits 1 &2Install BACT05/01/07Install BACT05/01/07Niagara Mohawk PowerNRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2and 10,777 tons of NOx, 2006 is 34,230 of SO2and 6,772 of NOx, 2007 is 30,859 of SO2and 6,211 of NOx, 2008 is 22,733tons of SO2HuntleyNewYorkUnits63–66RetireBefore2008Public Service Co. of NMSan JuanNewMexicoUnit 1State-of-thearttechnology90%10/31/08State-of-thearttechnology0.310/31/08OperateBaghouse anddemistertechnology0.01512/31/09Designactivatedcarbon injectiontechnology (orcomparabletech)12/31/09Unit 203/31/0903/31/0912/31/0912/31/09Unit 304/30/0804/30/0804/30/0804/30/08Unit 410/31/0710/31/0710/31/0710/31/07Public Service Co of ColoradoComancheColoradoUnits 1 &2Install andoperateFGD0.1lb/mmBtucombinedaverage07/01/09Install lowNOxemissioncontrols0.15lb/mmBtucombinedaverage07/01/09Install sorbentinjectiontechnology07/01/09Unit 3Install andoperateFGD0.1lb/mmBtuInstall andoperateSCR0.08Install andoperate a fabricfilter dustcollectionsystem0.013Install sorbentinjectiontechnologyWithin 180days ofstart-upRochester Gas & ElectricRussell PlantNewYorkUnits1–4RetireallunitsMirant New YorkLovett PlantNewYorkUnit 1Retire05/07/07Unit 2Retire04/30/08Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court ofAppeals, Fourth Circuit Court reversing the settlement.