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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)

April 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

Appendix 3-3 New Source Review (NSR) Settlem ents in EPA Base Case v.4.10_FTransport .... 54

# 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 version of t he model that was used in the Pro posedTransport Rule, 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 the more than 2,500 detailed comments (usually pertaining to distinct operating

characteristics of specific generating units) ar e being documented separately as part of the final

rulemaking package. EPA’s response to the universal modeling comments and the resulting updates to

the modeling platform are presented here in the form of a documentation supplement for the Final

Transport Rule.

This documentation supplement is organized by 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 coal-to-gas retrofit option, and updated

assumptions for activated carbon injection for mercury control). These capabilities were also

incorporated in the modeling for the Final Transport Rule, but are not documented here.

Documentation of the 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 – Updates for

Proposed Toxics Rule, which is available for viewing and downloading at

www.epa.gov/airmarkets/progsre gs/epa-ipm/do cs/suppdoc.pdf.



# The State Power Sector Regulations and State and Citizen Settlements shown in Appendices 3-2, 3-4

and 3-5 in the documentation supplement for the Proposed MATS also apply in EPA Base Case

v.4.10_FTransport. They reflect regulations and settlem ents that were in force as of December 2010.

Subsequent to freezing the as sumptions for EPA Base Case v.4.10_FTransport, additional NSR

settlements with Northern Indiana Public Service Company

( www.epa.gov/compliance/resources/cases/civil/caa/nipsco.html , January 13, 2011) and the Tennessee

Valley Authority ( www.epa.gov/compliance/resources/ca ses/civil/caa/tvacoal-fired.html , April 14, 2011)

were announced. For the TVA settlement EPA Base Case v.4.10_FTransport in cludes the provisions

shown in the Appendix 3-3 (“New Source Re view (NSR) Settlements in EPA Base Case

v.4.10_FTransport”) in the Addenda at t he end of this documentation supplement.

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 thei r reported technical capabilities, cogeneration units

are allowed to dispatch up to the availabilities assumed for the part icular generation technology or

up to their historic capacity factors (derived by taking the maximum historical capacity factor

reported for the unit in EIA Form 860 for years 2006-2010). In cases where the maximum reported

capacity factors is below 15%, a capacity factor of 15% is used as a limit, since historical capacity

factor values below 15% are not considered to reflect the gener ation capability of the unit.

Appendix 3-10 shows the capacity factor upper bou nds 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 w et 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 sentence. 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 

# 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

5.1 Response to the Comments Received

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 SO 2 

# emissions limits they face, and t he 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.

The indicated limitations on coal choice were consider ed technically plausible in the short term (i.e., out to

2012), provided that the unit(s) affected were exp licitly identified. Beyond 2012, however, EPA’s

assessment of industry experience suggested that ec onomic considerations would take precedent over

short-term restrictions and that the full choice of previously assigned coals should be re-instated for coal

units. This would allow the model to make fuel choices based on economic factors reflecting the tendency

of these factors to prevail beyond the short term.

Response:

(1) If a comment identified specific units that could not change from a specific coal due to short term

factors like coal contracts, the uni t’s coal assignment in 2012 would be limited to the coal stipulated in

the comment. If not explicitly stipulated in the co mment, the coal reported most recently at the plant

level in EIA Form 923 would be used. If the inform ation was not reported in EIA Form 926, the unit

would be assigned the coal grade which would result in an emission rate closest that SO 2 

# rate

reported for the unit in EPA’s Emissi on 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 all units were given thei r original v.4.10 coal assignments.

(5) Consistent with these responses, changes were ma de in the short term fuel assignments at several

coal steam plants to make short-term modeling pr ojections more consistent with near-term reported

fuel use. In addition, short-term SO 2 

# emission projections were re-calculated for greater consistency

with recently reported fuel use a nd emission rates at several plants.

5.1 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.

Add the following paragraph between new se ction 9.3.10 and before section 9.4.

# 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/epaipm/docs/v410/Chapter4.pdf)

, existing units in EPA Base Case v.4.10 incur a life extension cost if they

remain in operation past their current expected lifespan. (For existing coal units this occurs when they

pass age 40.) The assumption of a 30-year book life for retrofits is consistent with these life extension

provisions which allow existing units to stay in operation throughout the 2012-2050 modeling time

horizon, rather than forcing them retire upon reaching a pre-specified expected lifespan.

# 52 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. Mercury Emission Modification Factor (EMF) for Waste Coal Units: In EPA Base Case

v.4.10_FTransport (as in the base case for the proposed Mercury and Air Toxics Standards Rule -

EPA Base Case v.4.10_PTox), all waste coal units are assumed to have a mercury EMF of of 0.02.



# 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 disposed, the

full DSI capital, FOM, and VOM costs are incurred. In contrast, when DSI is retrofit on units with no

pre-existing fabric filter, it is assumed that the DSI will be installed after the ESP (which, in the

absence of a FF, will be present for PM control) and upstream of the FF which is installed in

conjunction with the DSI. Since 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. 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.

4. New Source Review Settlements: Appendix 3-3 below shows th e NSR settlements that are

represented in EPA Base Case v.4.10_FTransport.Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective DateJames H. Miller Alabama Units 3 & 4Install and operate FGD continuously 95% 12/31/11 Operate existing SCR continuously 0.1 05/01/08Beginning 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.Unit 1Install and continuously operate FGD 95% if wet FGD, 90% if dry 12/31/11Install and continuously operate Over-fire AIR, orequivalent technology with emission rate < .360.36 12/31/09Unit 2Design, upgrade, and continuously operate FGD 90% 12/31/10Install and continuously operate over-fire AIR, or equivalentechnology with emission rate < .360.36 12/31/07Unit 1 Repower to natural gas (or retire) 12/31/06Unit 2Improve and continuously operate existing FGD(shared by Units 2 and 3)95% 06/30/04Unit 3Improve and continuously operate existing FGD(shared by Units 2 and 3)95% 06/30/04 Operate Existing SCR Continuously 0.1 09/01/03Bergen New Jersey Unit 2 Repower to combined cycle 12/31/02Hudson New Jersey Unit 2Install Dry FGD (or approved alt. technology) andcontinually operate0.15 12/31/06 Install SCR (or approved tech) and continually operate 0.1 05/01/07Mercer New Jersey Units 1 & 2Install Dry FGD (or approved alt. technology) andcontinually operate0.15 12/31/10 Install SCR (or approved tech) and continually operate 0.13 05/01/06Units 1 & 2Existing Scrubber (shared by Units 1 & 2) 95% (95% or .25) 09/1/00 (01/01/13) Install SCR 0.1 05/01/09Unit 3Existing Scrubber (shared by Units 3 & 4) 93% if Units 3 & 4 are operating2000(01/01/10)Install SCR 0.1 05/01/09Unit 4Existing Scrubber (shared by Units 3 & 4) 93% if Units 3 & 4 are operating 06/22/05 Install SCR 0.1 07/01/07Gannon Florida Six units Retire all six coal units and repower at 12/31/04WEPCO shall comply with the following system wide average NOxemission rates and total NOxtonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and by 1/1/2013 an emission rate of 0.17 and 17, 400 tons. For SO2emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, byUnits 1–4Retire or install SO2and NOxcontrols12/31/12Install and continuously operate FGD (orapproved equiv. tech)95% or 0.1 12/31/12 Install SCR (or approved tech) and continually operate 0.1 12/31/12Units 5 & 6Install and operate low NOxburners12/31/03Units 7 & 8Operate existing low NOxburners12/31/05Unit 9Operate existing low NOxburners12/31/061Install and continuously operate FGD (orapproved control tech)95% or 0.1 12/31/06 Install and continuously operate SCR (or approved tech) 0.1 12/31/062Install and continuously operate FGD (orapproved control tech)95% or 0.1 12/31/07 Install and continuously operate SCR (or approved tech) 0.1 12/31/03Units 5 & 6Install and continuously operate FGD (orapproved control tech)95% or 0.1 12/31/12 Install and continuously operate SCR (or approved tech) 0.1 12/31/12Unit 7Install and continuously operate FGD (orapproved control tech)95% or 0.1 12/31/12 Install and continuously operate SCR (or approved tech) 0.1 12/31/12Unit 8Install and continuously operate FGD (orapproved control tech)95% or 0.1 12/31/12 Install and continuously operate SCR (or approved tech) 0.1 12/31/12Port Washington WisconsinUnits 1–4Retire 12/31/04 for Units 1Valley WisconsinBoilers 1–4Operate existing low NOxburner30 days after entry of consent decreeThe 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. Beginning 1/1/2013 they will have a system wide emission rate no greater then 0.15 lb/mmBtu.Mount Storm West VirginiaUnits 1–3Construct or improve FGD 95% or 0.15 01/01/05 Install and continuously operate SCR 0.11 01/01/08Unit 4Install and continuously operate SCR 0.1 01/01/13Unit 5Construct or improve FGD 95% or 0.13 10/12/12 Install and continuously operate SCR 0.1 01/01/12Unit 6Construct or improve FGD 95% or 0.13 01/01/10 Install and continuously operate SCR 0.1 01/01/11Chesapeake Energy Virginia Units 3 & 4Install and continuously operate SCR 0.1 01/01/13Clover Virginia Units 1 & 2Improve FGD 95% or 0.13 09/01/03Possum Point Virginia Units 3 & 4 Retire and repower to natural gas 05/02/03PSEG FOSSILTECOWEPCOVEPCOAlabama PowerMinnkota Power CooperativeSIGECOCompany and PlantRetire/Repower SO2controlNOxControlSettlemState UnitChesterfieldAppendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10_FTransportFB CulleyMilton R. YoungIndianaMinnesotaFloridaBig BendWisconsinVirginiaPresque IsleOak Creek WisconsinWisconsinPleasant Prairie54Allowance Retirement Allowance RestrictionEquipment Rate Effective Date Retirement Restriction Effective Date0.03 12/31/06With 45 days of settlement entry, APC must retire 7,538 SO2emission allowances.APC shall not sell, trade, or otherwise exchange any Plant Miller excess SO2emissionallowances outside of the APC system1/1/211) Settlement requires 95% removal efficiency for SO2, or 90% in the event that the unit combust a coal withsulfur content greater than 1% by weight. 2) The settlements requires APC to retire $4,900,000 of SO2emission allowances within 45 days of consent decree entry. 3) EPA assumed a retirement of 7, 538 SO2allowances based on a current allowance price of $650. 4) The FGD and SCR controls are modeled asemission constraints in EPA Base Case.http://www.epa.gov/compliance/resources/cases/civil/caa/alabamapower.html0.03 if wet FGD, .015if dry FGD0.03 Before 2008Settlement requires that Unit 1 must either shutdown or repower to natural gas. EPA Base Case assumes theunit will be retired.Improved operation of the FGD is hardwired into EPA Base Case.Install and continuously operate a Baghouse 0.015 06/30/07Improved operation of the FGD, continuous operation of the SCR, and installation of the baghouse arehardwired into EPA Base Case.This action is hardwired into the EPA Base CaseInstall Baghouse (or approved technology) 0.015 12/31/06The FGD, SCR, and baghouse are hardwired into EPA Base Case. The settlement requires coal with monthlyaverage sulfur content no greater than 2% at units operating FGD -- this limit is modeled as a coal choiceexception in EPA Base Case.The SCR is hardwired into EPA Base Case; the FGD is modeled as an individual constraint. The settlementrequires coal with monthly average sulfur content no greater than 2% at units operating FGD -- this limit ismodeled as a coal choice exception in EPA Base Case.Settlement requires all six coal units to shutdown by 12/31/2004. Retirement of coal units and repowering asy1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an emission rate of 0.32 and 33,300tWEPCO may elect to retire or install controls at Presque Isle Units 1 – 4. For EPA Base Case, we imposedthe SO2 and NOx limits as individual emission constraints.LNBs for Units 5 and 6 are hardwired in EPA Base Case.Install BaghouseInstall BaghouseFor EPA Base Case, we imposed the SO2 and NOx limits as individual emission constraints.WEPCO announced plans to retire Port Washington and repower with two natural gas units. Retirement of thLNBs on Units 1 – 4 are hardwired in EPA Base Case.Units 1 – 3 have installed FGD and SCR. These controls are built into EPA Base Case.SCR on this unit is hardwired in EPA Base Case. The FGD is modeled as an individual emission constraint.SCR on this unit is hardwired in EPA Base Case. The FGD is modeled as an individual emission constraint.SCR and FGD on this unit are hardwired in EPA Base Case.SCR on these units is hardwired in EPA Base Case.FGD on Clover Units 1 & 2 are hardwired into EPA Base Case.This action is hardwired into EPA Base CaseNotesPM or Mercury Controlment Actionshttp://www.epa.gov/compliance/resources/cases/civil/caa/vepco.htmlReferenceThe provision did not specify an amount of SO2allowances tobe surrendered. It only provided that excess allowancesresulting from compliance with NSR settlement provisionsmust be retired.http://www.epa.gov/compliance/resources/cases/civil/caa/sigecofb.htmlMinnkota shall not sell or trade NOxallowances allocated to Units 1, 2, or 3 that wouldotherwise be available for sale or trade as a result of the actions taken by the settlingdefendants to comply with the requirements1) Settlement requires a 95% removal efficiency for SO2 at Unit 1 if a wet FGD is installed, or 90% if a dryFGD is installed. The FGD for Units 1 and 2 and the NOx control for Unit 1 are modeled as emissionconstraints in EPA Base Case, the NOx control for Unit 2 is hardwired into EPA base Case. 2) Beginning12/31/2010, Unit 2 will achieve a phase II average NOx emission rate established through its NOx BACTdetermination. Beginning 12/31/2011, Unit 1 will achieve a phase II NOx emission rate established by itsBACT determination.http://www.epa.gov/compliance/resources/cases/civil/caa/minnkota.htmlThe provision did not specify an amount of SO2allowances tobe surrendered. It only provided that excess allowancesresulting from compliance with NSR settlement provisionsmust be retired.Plant will surrender 4,346 allowances for each year 2012–2015, 8,693 allowances for years 2016–2018, 12,170allowances for year 2019, and 14,886 allowances/yearthereafter if Units 1–3 are operational by 12/31/2015. If onlyUnits 1 and 2 are operational by12/31/2015, the plant shallretire 17,886 units in 2020 and thereafter.http://www.epa.gov/compliance/resources/cases/civil/caa/psegllc.htmlhttp://www.epa.gov/compliance/resources/cases/civil/caa/teco.htmlThe provision did not specify an amount of SO2allowances tobe surrendered. It only provided that excess allowancesresulting from compliance with NSR settlement provisionsmust be retired.FGD and SCR are installed on Units 1 – 4, and hardwired into EPA base Case.LNBS for Units 7 – 9 are hardwired in EPA Base Case. The settlement requires demonstration of full-scaleTOXECON, and these units already have ESP in place. In EPA Base Case, ESP and baghouses arehardwired on these units, and mercury emissions modification factor (EMF) for ESP & baghouse combinationis applied.On or before March 31 of every year beginning in 2013 andcontinuing thereafter, VEPCO shall surrender 45,000 SO2allowances.http://www.epa.gov/compliance/resources/cases/civil/caa/wepco.htmlThe provision did not specify an amount of SO2allowances tobe surrendered. It only provided that excess allowancesresulting from compliance with NSR settlement provisionsmust be retired.(Settlement requires compliance with the specified SO2 & NOx efficiency or limit by one-month after therequired installation date shown in this table for Pleasant Prairie Units 1 & 2.) In EPA Base Case, FGD andSCR on Units 1 & 2 are hardwired.(Settlement requires compliance with the specified SO2 & NOx efficiency or limit by one-month after therequired installation date shown in this table for Oak Creek Units 7 & 8.) In EPA Base Case, the required SO2and NOx controls on these units are modeled as individual emission constraints.55Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective DateCompany and PlantRetire/Repower SO2controlNOxControlSettlemState UnitSantee Cooper shall comply with the following system wide averages for NOxemission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000tons, by 1/1/2007 an emission rate of 0.18 and 25,000 tons, by 1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2emission the company shall comply with system wide averagesUnit 1Upgrade and continuously operate FGD 95% 06/30/06 Install and continuously operate SCR 0.1 05/31/04Unit 2Upgrade and continuously operate FGD 87% 06/30/06 Install and Continuously operate SCR 0.11/0.1 05/31/04 and 05/31/07Unit 1Install and continuously operate FGD 95% 12/31/08 Install and continuously operate SCR 0.11/0.1 11/30/04 and 11/30/04Unit 2Install and continuously operate FGD 95% 12/31/08 Install and continuously operate SCR 0.12 11/30/04Unit 3Upgrade and continuously operate existing FGD 90% 12/31/08 Install and continuously operate SCR 0.14/0.12 11/30/2005 and 11/30/08Unit 4Upgrade and continuously operate existing FGD 90% 12/31/07 Install and continuously operate SCR 0.13/0.12 11/30/05 and 11/30/08Unit 1Operate low NOxburner or more stringent technology06/25/04Unit 2Operate low NOxburner or more stringent technology 05/01/04Jeffries South Carolina Units 3, 4Operate low NOxburner or more stringent technology06/25/04Ohio Edison shall achieve reductions of 2,483 tons NOxbetween 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1–3 during the months of October through April, and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOxrequired for the Sammis Plant. Ohio Edison must reduceNo later than 8/11/2005, Ohio Edison shall install and operate low NOxburners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization with software to minimizexemissions from Sammis Units 1–5.Unit 1Install InductScrubber (orapproved equiv.control tech)50% removalor 1.1 lb/mmBtu12/31/08Install SNCR(or approvedalt. tech) &operatecontinuously0.25 10/31/07Unit 2Install InductScrubber (orapproved equiv.control tech)50% removalor 1.1 lb/mmBtu12/31/08Operateexisting SNCRcontinuously0.25 02/15/06Unit 3Install InductScrubber (orapproved equiv.control tech)50% removalor 1.1 lb/mmBtu12/31/08Operate low NOxburners and overfire air by 12/1/05;install SNCR(or approvedalt. tech)&0.2512/01/05and10/31/07Unit 4Install InductScrubber (orapproved equiv.control tech)50% removalor 1.1 lb/mmBtu06/30/09Install SNCR(or approvedalt. tech) &operate0.25 10/31/07Unit 5Install FlashDryer Absorber50% removalor 1.1 lb/mmBtu06/29/09Install SNCR(or approved0.29 03/31/08Unit 6Install FGD3(orapproved equiv.95% removal or 0.13 lb/mmBtu 06/30/11Install SNCR(or approved"MinimumExtent06/30/05Unit 7Install FGD (orapproved equiv.95% removal or 0.13 lb/mmBtu 06/30/11Operateexisting SNCR"MinimumExtent08/11/05Unit 1Upgradeexisting FGD95% 12/31/05Unit 2Upgradeexisting FGD95% 12/31/06Unit 3Upgradeexisting FGD95% 10/31/07Eastlake Ohio Unit 5Install low NOx"Minimize Emissions to 12/31/06Unit 4 12/31/11Unit 5 12/31/11System-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-wideNxEmission Ozone Season Caps: 14,700 tons 2004; 13,340 tons 2005; 12,590 tons 2006; 10,190 tons 2007; 6,150 tons 200–2009; 5,200 tons 2010 thereafter. Beginningon 5/1/2008, andcUnit 1Unit 2Unit 3Install low NOx05/01/04Unit 4Install low NOx05/01/04Unit 5Install low NOxburners (or more effective tech) &operate continuously05/01/04Unit 1Install SCR(or approvedalt. tech) &operate continuously0.1 05/01/07Unit 2Install SCR(or approvedalt. tech) &operate continuously0.1 05/01/08Unit 1Install and continuously operate FGD (or equiv.technology)95% 06/01/10Unit 2Install and continuously operate FGD (or equiv.technology)95% 06/01/10MirantI1,6Santee CooperOhio EdisonMansfield PlantRepower with at least 80% biomass fuel,up to 20% low sulfur coal.BurgerW.H. Sammis Plant OhioMarylandPotomac River PlantPennsylvaniaOhioVirginiaMarylandWinyahGraingerSouth CarolinaSouth CarolinaSouth CarolinaCrossMorgantown PlantChalk Point56Allowance Retirement Allowance RestrictionEquipment Rate Effective Date Retirement Restriction Effective DateNotesPM or Mercury Controlment ActionsReferencesof: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85,000 tons, by 1/1/2009an emission rate of 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65Effective Dates for NOx rate and SO2 efficiency are as shown in the table. SCR and FGD are hardwired intoEPA Base Case.SCR and FGD controls for Unit 2 are hardwired into EPA Base Case.SCR and FGD are hardwired into EPA Base Case.SCR and FGD are hardwired into EPA Base Case.SCR and FGD are hardwired into EPA Base Case.SCR and FGD are hardwired into EPA Base Case.LNBs on Units 3 & 4 are hardwired in EPA Base Case.e24,600 tons system-wide of SO2by 12/31/2010.If Ohio Edison cannot install Flash Dryer Absorber due to a lack of permits, this unit's requirements must bepassed off to another plant.OperateExisting0.03 01/01/10OperateExisting0.03 01/01/10Settlement requires Eastlake Plant to achieve additional reductions of 11,000 tons of NOxper yearcontinuingfor each and everyOzone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Emission Rate of 0.150 lb/mmBtux.Additional Mansfield Plant-wide SO2reductions are as follows: 4,000 tons in 2006, 8,000 tons in 2007, and12,000 tons/yr for every year after. Settlement allows relinquishment of SO2requirement upon shutdown ofunit, after which the SO2reductions must be made by another plant(s).http://www.epa.gov/compliance/resources/cases/civil/caa/ohioedison.htmlBeginning on 1/1/2006, Ohio Edison may use, sell or transferany restricted SO2only to satisfy the Operational Needs at theSammis, Burger and Mansfield Plant, or new units within theFirstEnergy System that comply with a 96% removal for SO2.For calendar year 2006 through 2017, Ohio Edison mayaccumulate SO2allowances for use at the Sammis, Burger,and Mansfield plants, or FirstEnergy units equipped with SO2Emission Control Standards. Beginning in 2018, Ohio Edisonshall surrender unused restricted SO2allowances.SNCR for each unit are hardwired into EPA Base Case. SO2controls are modeled as individual emissionconstraints in EPA Base Case Plant-wide NOxAnnual Caps: 11,371 tons 7/1/2005–12/31/2005; 21,251 tons2006; 20,596 tons 2007; 18,903 tons 2008; 17,328 tons 2009–2010; 14,845 tons 2011; 11,863 2012 onward.Sammis Plant-Wide Annual SO2Caps: 58,000 tons SO27/1/2005-12/31/2005; 116,000 tons 1/1/2006–12/31/2007; 114,000 tons 1/1/2008-12/31/2008; 101,500 tons 1/1/2009–12/31/2010; 29,900 tons 1/1/2011onward. Sammis Units 1–5 are also subject to the following SO2Monthly Caps if Ohio Edison installs theimproved SO2control technology (Unit 5's option A): 3,242 tons May, July, and August 2010; 3,137 tons Juneand September 2010. If Ohio Edison installs the required SO2technology (Unit 5's option B), the MonthlyCaps are: 2,533 tons May, July, and August 2010; 2,451 tons June and September 2010. Regardless of thetechnology used, Add'l Monthly Caps are: 2,533 tons May, July, and August 2011; 2,451 tons June andSeptember 2011 thereafter.In addition to SNCR, settlement requires installation of first SCR (or approved alt tech) on either Unit 6 or 7 by12/31/2010; second installation by 12/31/2011. Both SCRs must achieve 90% Design Removal Efficiency by180 days after installation date. Each SCR must provide a 30-Day Rolling average. NOxEmission Rate of 0.1lb/mmBtu starting180 days after installation dates aboveMirant must install and operate FGD by 6/1/2010 if they were authorized by court to reject ownership interestMorgantown Plant, or by no later than 36 months after they loose ownership interest of the Morgantown Plant.http://www.epa.gov/compliance/resources/cases/civil/caa/mirant.htmlSettlement requires installation of Separated Overfire Air tech (or more effective technology) by 5/1/2005.Plant-wide Ozone Season NOxCaps: 1,750 tons 2004; 1,625 tons 2005; 1,600 tons 2006–2009; 1,475 tons2010 thereafter. Plant-wide annual NOxCaps are 3,700 tons in 2005 and each year there after.LNBs on Units 1 & 2 are hardwired in EPA Base Case.The provision did not specify an amount of SO2allowances tobe surrendered. It only provided that excess allowancesresulting from compliance with NSR settlement provisionsmust be retired.http://www.epa.gov/compliance/resources/cases/civil/caa/santeecooper.htmlFor each year after Mirant commences FGD operation atChalk Point, Mirant shall surrender the number of SO2Allowances equal to the amount by which the SO2Allowancesallocated to the Units at the Chalk Point Plant aregreater than57Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective DateCompany and PlantRetire/Repower SO2controlNOxControlSettlemState UnitSystem-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.Units 1 & 2Install wet or dry FGD (or approved equiv. alt.tech) & operate continuously0.1 12/31/11 Operate OFA & existing SCR continuously 0.1 08/11/05Unit 3Install wet or dry FGD (or approved equiv. alt.tech) & operate continuously0.1 12/31/11Operate OFA and/or low NOxburners0.12 until 12/30/12; 0.1from 12/31/1208/11/05 and 12/31/12Havana Illinois Unit 6Install wet or dry FGD (or approved equiv. alt.tech) & operate continuously1.2 lb/mmBtu until 12/30/2012; 0.1lb/mmBtu from 12/31/2012 onward08/11/05and12/31/12Operate OFA and/or low NOxburners & operate existingSCR continuously0.1 08/11/05Unit 11.2 07/27/05 Operate OFA "Minimum 08/11/05Unit 21.2 07/27/05Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05Vermilion Illinois Units 1 & 21.2 01/31/07Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05Wood River Illinois Units 4 & 51.2 07/27/05Operate OFAand/or low NOxburners"MinimumExtentPracticable"08/11/05EW Brown Generating Station Kentucky Unit 3Install FGD 97% or 0.100 12/31/10Install and continuously operate SCR by 12/31/2012,continuously operate low NOxboiler and OFA.0.07 12/31/12Unit 1 or Unit 2Immediately begin continuous operation ofexisting FGDs on both units, install new FGD.95% or 0.08New FGD installedby 1/1/2012Install and continuously operate low NOxburner and SCR0.32 prior to SCRinstallation, 0.080 afterLNB by 06/01/2009, SCR by 06/01/2014Unit 1 or Unit 2Install new FGD 95% or 0.08 01/01/13Install and continuously operate low NOxburner0.32 06/01/11Annual Cap (tons) Year Annual Cap (tons) Year450,000 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 72,000 2016 and thereafter184,000 2018174,0002019 andthereafterWest VirginiaSporn1–4VirginiaClinch River1–3IndianaTanners Creek1–3West VirginiaKammer1–3Unit 1Install and continuously operate FGD 12/31/09 Install and continuously operate SCR 01/01/08Unit 2Install and continuously operate FGD 12/31/10 Install and continuously operate SCR 01/01/09Unit 3Install and continuously operate FGD 12/31/09 Install and continuously operate SCR 01/01/08Unit 1Burn only coal with no more than 1.75 lb/MMBtuannual averageDate of entryContinuously operate low NOxburnersDate of entryUnit 2Install and continuously operate FGD 12/31/15 Install and continuously operate SCR 01/01/09Unit 1Install and continuously operate FGD 12/31/08 Install and continuously operate SCR 01/01/09Unit 2Install and continuously operate FGD 12/31/08 Install and continuously operate SCR 01/01/09Unit 3Install and continuously operate FGD 12/31/12 Install and continuously operate SCR 01/01/09Clinch River VirginiaUnits1–3Plant-wide annual cap: 21,700 tonsfrom 2010 to 2014, then 16,300after 1/1/20152010–2014, 2015and thereafterContinuously operate low NOxburnersDate of entryUnit 1 Retire, retrofit, or re-power Date of entryUnit 2 Retire, retrofit, or re-power Date of entryUnit 3 Retire, retrofit, or re-power 12/31/12Unit 4Install and continuously operate FGD 12/31/10 Install and continuously operate SCR 12/31/10Unit 5Upgrade existing FGD 95% 12/31/09Continuously operate low NOxburnersDate of entryUnit 6Upgrade existing FGD 95% 12/31/09Continuously operate low NOxburnersDate of entryUnit 1Install and continuously operate FGD Date of entry Install and continuously operate SCR 01/01/09Unit 2Install and continuously operate FGD Date of entry Install and continuously operate SCR 01/01/09UnitsUnits 5, 6Burn only coal with no more than 1.75 lb/MMBtuannual averageDate of entryContinuously operate low NOxburnersDate of entryKammer West Virginia UnitsPlant-wide annual cap: 35,000 01/01/10 Continuously operate over-fire air Date of entryIllinois PowerKentucky Utilities CompanySalt River Project Agricultural Improvement and Power District (SRP)American Electric PowerBaldwinCoronado Generating StationAt least 600MW from various units Retire, retrofit, or re-power 12/31/18Eastern System-WideBig SandyCardinalConesvilleGavinGlen Lyn VirginiaHennepinIllinoisIllinoisAmosArizonaWest VirginiaKentuckyOhioOhioOhio58Allowance Retirement Allowance RestrictionEquipment Rate Effective Date Retirement Restriction Effective DateNotesPM or Mercury Controlment ActionsReferenceInstall & continuously operate Baghouse 0.015 12/31/10Install & continuously operate Baghouse 0.015 12/31/10Install & continuously operate Baghouse, then install ESP or alt. PMequipFor Bag-house: 0.015lb/mmBtu; For ESP:0.03 lb/mmBtuFor Baghouse: 12/31/12;For ESP: 12/31/05Install ESP (or equiv. alt. tech) & continuously operate ESPs 0.03 12/31/06Settlement requires first installation of ESP at either Unit 1 or 2 on 12/31/2006; and on the other byInstall ESP (or equiv. alt. tech) & continuously operate ESPs 0.03 12/31/06Install ESP (or equiv. alt. tech) & continuously operate ESPs 0.03 12/31/10Install ESP (or equiv. alt. tech) & continuously operate ESPs 0.03 12/31/05Settlement requires first installation of ESP at either Unit 4 or 5 on 12/31/2005; and on the other by12/31/2007.Continuously operate ESP 0.03 12/31/10KU must surrender 53,000 SO2allowances of 2008 or earliervintage by March 1, 2009. All surplus NOxallowances mustbe surrendered through 2020.SO2and NOxallowances may not be used for compliance, and emissions decreasesfor purposes of complying with the Consent Decree do not earn credits.Annual SO2cap is 31,998 tons through 2010, then 2,300 tons each year thereafter. Annual NOxcap is 4,072tons.http://www.epa.gov/compliance/resources/cases/civil/caa/kucompany.htmlOptimization begins immediately, rate limitbegins 01/01/12 (date of new FGDinstallation)Optimization begins immediately, rate limitbegins 01/01/13 (date of new FGDinstallation)Continuously operate ESP 0.03 12/31/09Continuously operate ESP 0.03 12/31/09http://www.epa.gov/compliance/resources/cases/civil/caa/srp.htmlhttp://www.epa.gov/compliance/resources/cases/civil/caa/illinoispower.html0.03Beginning in 2012, all surplus SO2allowances for bothCoronado and Springerville Unit 4 must be surrenderedthrough 2020. The allowances limited by this condition may,however, be used for compliance at a prospective future planusing BACT and otherwise specified in par. 54 of the consentdecree.SO2and NOxallowances may not be used for compliance, and emissions decreasesfor purposes of complying with the Consent Decree do not earn credits.Consent Decree does not specify which unit must install equipment by the specified dates. It refers instead to"one unit." Annual plantwide NOxcap is 7,300 tons after 6/1/2014.Optimization and continuous operation of existing ESPs.http://www.epa.gov/compliance/resources/cases/civil/caa/americanelectricpower1007.htmlNOxand SO2allowances that would have been madeavailable by emission reductions pursuant to the ConsentDecree must be surrendered.NOxand SO2allowances may not be used to comply with any of the limits imposed bythe Consent Decree. The Consent Decree includes a formula for calculating excessNOxallowances relative to the CAIR Allocations, and restricts the use of some. Seepar. 74-79 for details. Reducing emissions below the Eastern System-Wide AnnualTonnage Limitations for NOxand SO2earns supercompliance allowances.By year end 2008, Dynergy will surrender 12,000 SO2emission allowances, by year end 2009 it will surrender18,000, by year end 2010 it will surrender 24,000, any by yeaend 2011 and each year thereafter it will surrender 30,000allowances. If the surrendered allowances result ininsufficient remaining allowances allocated to the unitscomprising the DMG system, DMG can request to surrenderfewer SO2allowances.59Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective DateCompany and PlantRetire/Repower SO2controlNOxControlSettlemState UnitKanawha River West Virginia Units 1, 2Burn only coal with no more than 1.75 lb/MMBtuannual averageDate of entryContinuously operate low NOxburnersDate of entryUnit 1Install and continuously operate FGD 12/31/07 Install and continuously operate SCR 01/01/09Unit 2Install and continuously operate FGD 12/31/07 Install and continuously operate SCR 01/01/09Mountaineer West Virginia Unit 1Install and continuously operate FGD 12/31/07 Install and continuously operate SCR 01/01/08Units Retire, retrofit, or re-power 12/31/15Unit 5Install and continuously operate FGD 12/31/15 Install and continuously operate SCR 01/01/08Picway Ohio Unit 9Continuously operate low NOxburnersDate of entryUnit 1Install and continuously operate FGD 12/31/17 Install and continuously operate SCR 12/31/17Unit 2Install and continuously operate FGD 12/31/19 Install and continuously operate SCR 12/31/19Sporn West Virginia Unit 5 Retire, retrofit, or re-power 12/31/13Units1–3Burn only coal with no more than 1.2 lb/MMBtuannual averageDate of entryContinuously operate low NOxburnersDate of entryUnit 4Burn only coal with no more than 1.2% sulfurcontent annual averageDate of entry Continuously operate over-fire air Date of entryBy 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-month rolling limit (tons)Start of 12-monthcycle12-month rolling limit(tons)Start of 12-month cycle57,000 10/01/0811,500 01/01/0840,000 07/01/118,500 01/01/1328,000 01/01/138,000 01/01/15Unit 1Install and continuously operate FGD 95% or 0.1 6/30/2011 Continuously operate SCR0.12 for Unit 1 until01/01/2013, at whichpoint the unit limit dropsto 0.1. Prior to01/01/2013, thecombined averagewhen both units areoperating must be nomore than 0.160 days after entryUnit 2Install and continuously operate FGD by10/1/200895% or 0.1 1/1/2009 Continuously operate SCR and OFA0.1 for Unit 2, 0.1combined averagewhen both units areoperating60 days after entryUnit 1Install and continuously operate low NOxburners by 0.46 01/01/08Unit 2Install and continuously operate low NOxburners by10/31/20070.46 01/01/08Unit 3 EKPC may choose to retire Dale 3 and 4 12/31/2012Unit 4Unit 1Unit 2If EKPC opts to install controls rather than retiringDale, it must install and continuously operate FGDor equiv. technology95% or 0.10If EKPC elects to install controls, it must continuouslyoperate SCR or install equiv. technology0.08 (or 90% if non-SCR technology isused)12/31/12Beginning 1/1/2010, combined NOxemissions from Units 5,6,7, and 8 must be no more than 360 tons per year.Unit 55ppm 1-hour average12/31/08 (ULNB installation), 01/30/09 (1-houraverage)Unit 65ppm 1-hour average12/31/09 (ULNB installation), 01/30/10 (1-houraverage)Unit 75ppm 1-hour average12/31/09 (ULNB installation), 01/30/10 (1-houraverage)Unit 85ppm 1-hour average 12/31/08 (ULNB installation), 01/30/09 (1-hourNon-EPA Settlement of 10/23/2008Owners may not purchase any new catalyst with SO2to 0.17 station-wide 30 days after entry0.17 station-wide 60 days after entry date82% including data from periods of 7/31/09 through Install control technology on one unit 0.10 on any single unit 12/31/120.15 station-wide 07/01/120.10 station-wide 12/31/14Unit 7 Retire unit 01/01/07Unit 8 Retire unit 01/01/070.15 12/31/10 Install SCR (or approved tech) and continually operate 0.1 12/31/10Annual Cap (tons) Year Annual Cap (tons) Year5,547 20073,486 20075,270 20083,486 20085,270 20093,486 20095,270 20103,486 2010Mercer New Jersey Units 1 &2Install Dry FGD (or approved alt. technology) andcontinually operate0.15 12/31/10 Install SCR (or approved tech) and continually operate 0.1 01/01/07Nevada Power CompanyDayton Power & LightPSEG FOSSIL, Amended Consent Decree of November 2006East Kentucky Power Cooperative Inc.IndianaRockportMitchellCooper KentuckyDale Plant KentuckyKentuckyOhio Station-wideNevadaClark Generating Station Units may only fire natural gasIncrease water injection immediately, then install andoperate ultra-low NOxburners (ULNBs) or equivalenttechnology. In 2009, Units 5 and 8 may not emit morethan 180 tons combined96% or 0.10 07/31/09KearnyHudson New Jersey Unit 2System-wideInstall Dry FGD (or approved alt. technology) andcontinually operateSystem-wide 12-month rolling tonnage limits applyAll units must operate low NOxboilers82% including data from periods ofmalfunctionsTanners CreekSpurlockNew Jerseyafter 7/31/11Stuart Generating StationComplete installation of FGDs on each unit.IndianaOhioWest VirginiaMuskingum River60Allowance Retirement Allowance RestrictionEquipment Rate Effective Date Retirement Restriction Effective DateNotesPM or Mercury Controlment ActionsReferenceContinuously operate ESP 0.03 12/31/02http://www.epa.gov/compliaInstall Baghouse (or approved technology) 0.015 12/31/10Install Baghouse (or approved technology) 0.015 12/31/10Date of entryhttp://www.epa.gov/compliance/resources/cases/civil/caa/eastkentuckypowerd l 0907 h lSO2and NOxallowances may not be used to comply with the Consent Decree. NOxallowances that would become available as a result of compliance with the ConsentDecree may not be sold or traded. SO2and NOxallowances allocated to EKPC mustbe used within the EKPC system. Allowances made available due tosupercompliance may be sold or traded.http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlAll surplus SO2allowances must be surrendered each year,beginning in 2008.1 year from entry dateEKPC must surrender 1,000 NOxallowances immediatelyunder the ARP, and 3,107 under the NOxSIP Call. EKPCmust also surrender 15,311 SO2allowances.http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlAllowances may not be used to comply with the Consent Decree, and no allowancesmade available due to compliance with the Consent Decree may be traded or sold.07/31/09NOxand SO2allowances may not be used to comply with the monthly rates specifiedin the Consent Decree.Courtlink documentprovided by EPA in emailInstall rigid-type electrodes in each unit's ESP12/31/15Allowances allocated to Kearny, Hudson, and Mercer mayonly be used for the operational needs of those units, and allsurplus allowances must be surrendered. Within 90 days ofamended Consent Decree, PSEG must surrender 1,230 NOxAllowances and 8,568 SO2Allowances not already allocatedto or generated by the units listed here. Kearny allowancesmust be surrendered with the shutdown of those units.0.03PM control devices must be operated continuously system-wide,ESPs must be optimized within 270 days of entry date, or EKPCmay choose to submit a PM Pollution Control Upgrade Analysis.0.030 lb per unit61Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective DateCompany and PlantRetire/Repower SO2controlNOxControlSettlemState UnitJeffrey Energy Center Kansas All unitsUnits 1 & 3 Retire or repower as natural gas 1/1/2012Units 2 & 4Install Dry sorbent injection technology 80% 1/1/2012Units 2 & 3Units 1 & 4Ratts Indiana Units 1 & 2Install & continually operate SNCRS 0.25 12/31/2011Unit 1Continusly run current FGD for 90% removal andupdate FGD for 98% removal by 201298% 2012Unit 2Continusly run current FGD for 90% removal andupdate FGD for 98% removal by 201498% 2014Allen Steam Plant Tennessee Units 1 - 3Install FGD 12/31/2015 Operate SCR In NEEDSBull Run Tennessee Unit 1Operate Wet FGD In NEEDS Operate SCR In NEEDSUnits 1 - 4Install FGD 6/30/2016 Install SCR 6/30/2016Unit 5Install FGD 12/31/2015 Operate SCR In NEEDSCumberland Tennessee Units 1 & 2Operate Wet FGD In NEEDS Operate SCR In NEEDSGallatin Tennessee Units 1 - 4Install FGD 12/31/2017 Install SCR 12/31/2017Units 1 & 2 Retire 12/31/2012Units 3 & 4Install 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 Wet FGD In NEEDS Operate SCR In NEEDSUnits 1 & 2Upgrade FGD 93% 12/31/2012 Operate SCR In NEEDSUnit 3Operate Wet FGD In NEEDS Operate SCR In NEEDSShawnee Kentucky Units 1 & 4Install 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 Wet FGD In NEEDS Operate SCR In NEEDSNotes:1) Updates to the EPA Base Case 4.10 Final from EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the control requirements on the Mercer plantunder the PSEG Fossil settlement, and an update to the SO2emission modeling on Jeffrey Energy Center as part of the Westar settDuke EnergyTennessee Valley AuthorityWestar EnergyUnits 1, 2, and 3 have a total annual limit of 6,600 tons of SO2 and an annual rate limit of 0.07 lbs/MMBtustarting 2012Units 1, 2, and 3 must all install FGDs by 2011 and operate them continuously.FGDs must maintain a 30-DayRollingAverage Unit Removal Efficiencyfor SO2 of at least 97% or a 30Units 1-3 must continuously operate Low NOx Combustion Systems by 2012 and achieve and maintain a 30-Day Rolling Average UnitEmission Rate for NOx of no greater than 0.180 lb/MMBtu.One of the three units must install an SCR by 2015 and operate it continuously to maintain a 30-Day Rolling Average Unit Emission Ratefor NOx of no greater than 0.080 lb/MMBtu.2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlementactions are simplified for representation in the model. This table is not intended to be a comprehensive description of allelements of the actual settlement agreements.3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, future actions are generally modeled as individual constraints on emission rates in EPA Base Case, allowing the modeled economic situation to dictate whetherand wh4) 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.10) EPA included in EPA Base Case the requirements of the settlements as they existed on January 1, 2011.11) Some of the NSR settlements require the retirement of SO2 allowances. For 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.Hoosier Energy Rural Electric CooperativeGallagher Indiana0.12Merom IndianaElected to Retire Dec 15, 2010 (must retire by Dec 31, 2012)Continuously operate existing SCRsAmerican Municipal PowerGorsuch Station OhioColbert AlabamaJohn Sevier TennesseeJohnsonville TennesseeParadise KentuckyWidows Creek Alabama62Allowance Retirement Allowance RestrictionEquipment Rate Effective Date Retirement Restriction Effective DateNotesPM or Mercury Controlment ActionsReferencetlemenUnits 1, 2, and 3 must operate each ESP and FGD system continuously by 2011 and maintain a 0.030 lb/MMBtu PM Emissions Rate.Units 1 and 2’s ESPs must be rebuilt by 2014 in order to meet a 0.030 lb/MMBtu PM Emissions Rateen a unit would opt to install controls versContinuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/12http://www.epa.gov/compliance/resources/cases/civil/caa/hoosier.htmlAnnually surrender any NOx and SO2 allowances that Hoosier does not need in order to meet its regulatory obligationsContinuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/13http://amppartners.org/newsroom/amp-to-retire-gorsuchContinuously operate ESP63