United States Air and Radiation EPA 430-K-11-004 Environmental Protection Agency (6204J) June 2011 Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule ------- Documentation Supplement for EPA Base Case v.4.10_FTransport Updates for Final Transport Rule U.S. Environmental Protection Agency Clean Air Markets Division 1200 Pennsylvania Avenue, NW (6204J) Washington, D.C. 20460 (www.epa.gov/airmarkets) June 2011 ------- Table of Contents Introduction 1 Universal Comments Resulting in Model Revisions 1 Cogeneration Units 2 2 NOX Rates 35 3 SO2 Removal Rates for Flue Gas Desulfurization (FGD) 41 4 Coal Switching - Bituminous to Subbituminous 44 5 Restrictions on coal choice in 2012 46 6 Waste Coal Cost Correction 48 7 Comments Considered but that did not Result in Changes 51 • Oil consumption at dual fired (oil/gas) units • Capital cost of Flue Gas Desulfurization (FGD) on units whose capacity is less than 100 MW • Selective Catalytic Reduction (SCR) retrofit costs • 30 year book life for emission control retrofits • Must run, black start, and spinning reserve units • Availability assumptions for existing coal units Addenda: Notes on various modeling assumptions 53 • Dry Sorbent Injection (DSI) and Fabric Filter Cost Development • Variable Operating and Maintenance (VOM) Cost of Dry Sorbent Injection (DSI) Retrofits • Updated Appendices 3-2 through 3-4 • 2012 Emission Control Retrofits • Emission Controls in IPM Parsed Files • Mercury Emission Modification Factor (EMF) for Waste Coal Units • Carbon dioxide (CO2) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization (FGD) System for Sulfur Dioxide (SO2) Control Addendum A — Dry Sorbent Injection (DSI) and Fabric Filter Cost Development in EPA Base Case v.4.10_FTransport 55 Addendum B — Representation of State Electric Power Emission Regulations (Appendix 3-2), New Source Review (NSR) Settlements (Appendix 3-3), and State Settlements (Appendix 3-4) in EPA Base Case v.4.10_FTransport 67 ------- Introduction This documentation supplement describes the changes implemented for the Final Transport Rule analysis in EPA's application of the Integrated Planning Model (IPM), the modeling platform used by EPA for U.S. electric power sector analysis. The changes described here resulted from comments received on the Proposed Transport Rule and on the Notice of Data Availability (NODA) for the Proposed Transport Rule, which were announced on September 1, 2010. The NODA included detailed documentation of the version of the model that EPA proposed using in the final rulemaking, a database of generating unit level input data used in the model, model run results, and user guides to input assumptions and model outputs. Comments received on the modeling platform fell into two basic categories: detailed comments on specific generating units and universal comments affecting broad categories of generating units. Changes resulting from detailed unit level comments (usually pertaining to distinct operating characteristics of specific generating units) are being documented separately as part of the "Transport Rule IPM Assumptions Response To Comments" document. EPA's response to the universal modeling comments and the resulting updates to the modeling platform are presented here in the form of a documentation supplement for the Final Transport Rule. This documentation supplement is organized by comment topic. The presentation of each comment is divided into two sections. The first section summarizes the comment and EPA's responses. The second section contains a mark-up of the relevant sections of the Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model (www.epa.gov/airmarkets/progsregs/epa- ipm/BaseCasev410.html), indicating the exact modeling changes that resulted from the universal comments. To make it easier to recognize these mark-ups, they appear on a gray background, visually signaling that they are revisions of the previous documentation. In the discussion below the following terminology is used: "EPA Base Case v.4.10_NODA version"1 refers to base case released as part of the September 1, 2010 NODA. Its assumptions and results were the subject of the public comments received by EPA. "EPA Base Case v.4.10_FTransport" incorporated the changes described below and was used in the modeling for the Final Transport Rule. It should also be noted that on March 16, 2011, EPA signed a Notice of Proposed Rulemaking for the Mercury and Air Toxics Standards (MATS). For that rulemaking EPA enhanced its power sector modeling platform with capabilities specifically needed for the Proposed MATS (for example the capability to model HCI emissions and controls, a coal-to-gas retrofit option, and updated assumptions for activated carbon injection for mercury control). These capabilities were also incorporated in the modeling for the Final Transport Rule. However, only those features relevant to the Final Transport Rule are documented here. These include provision of dry sorbent injection (DSI), accompanied by a fabric filter, as a retrofit option for SO2 (and HCI) emission control (documented in Addendum A at the end of this report) and updates of the State Power Sector Regulations and New Source Review (NSR) and State Settlements shown in Appendices 3-2 through 3-4 of the documentation supplement for the Proposed MATS (also found in Addendum B in this report). Appendices 3-2 through 3-4 reflect regulations and settlements that were in force through December 2010. Subsequent to freezing the assumptions for EPA Base Case v.4.10_FTransport, additional NSR settlements with Northern Indiana Public Service Company (www.epa.gov/compliance/resources/cases/civil/caa/nipsco.html, January 13, 2011) and the Tennessee Valley Authority (www.epa.gov/compliance/resources/cases/civil/caa/tvacoal- fired, htm I, April 14, 2011) were announced. Forthe TVA settlement EPA Base Case v.4.10_FTransport includes the provisions shown in the Appendix 3-3. Documentation of the full modeling capabilities for the Proposed MATS can be found in a separately issued report entitled Documentation Supplement for EPA Base Case v.4.10_Rox- Updates for Proposed Toxics Rule, which is available for viewing and downloading atwww.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf. 1 In Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model the term "draft EPA Base Case v.4.10" was used when referring to what is now called "EPA Base Case v.4.10 NODA version" 1 ------- 1 Cogeneration Units 1.1 Response to the Comments Received Comment Theme: Comments indicated that the extent of the operation and emissions from units that produce both steam and electricity (i.e., cogeneration units) in EPA Base Case v.4.10_NODA was considerably lower than actual operating experience. Discussion: In the draft base case which provoked these comments, cogeneration units were assigned the gross heat rates applicable to both the steam and electric portion of their operation. However, dispatch decisions in IPM are only based on the heat rate efficiency of the electric portion of a cogeneration unit. The lower a unit's heat rate, the more efficient is its use of fuel for electricity generation, and the more likely it is to be dispatched. For electrical dispatch purposes, the net heat rate should have been used for cogeneration units. Since the net heat rate can be considerably lower than the gross heat rate, this revision should increase the extent that cogeneration units are operated. At the same time, since emissions from both the electric and steam portions of cogeneration units are covered by the Transport Rule, an emission multiplier should be used to ensure that total emissions are taken into account. The increased operation together with the emissions multiplier should correct the observation of low cogeneration operations and emissions and should address the points raised in the comments. Response: Based on these comments, a review was made of the representation of cogeneration units in draft EPA Base Case v.4.10. As a result this review, modifications were made so that the representation of cogeneration units would better reflect the extent of their operation and emissions. In particular, the following revisions were made. (1) In the draft base case, gross heat rates had been assigned to cogeneration units. That is, the heat rates (efficiency) of cogeneration units were calculated by summing the energy content of the fuel consumed for both steam and power generation and then dividing this sum by the electricity generated. Factoring in both the fuel consumed in producing steam and electricity when calculating the gross heat rate made the cogeneration units less efficient for electricity generation than their operating experience indicated. In the base case for the final Transport Rule net heat rates (heat content of fuel consumed for power generation divided by their generation) are assigned to cogeneration units. This will more accurately reflect their electric generation efficiency and make cogeneration units more economic to dispatch. (2) In conjunction with the use of net heat rates for cogeneration units in the base case for the final Transport Rule, cogeneration units are allowed to dispatch up to the availabilities assumed for the particular generation technology or up to their historic capacity factors (derived by taking the maximum historical capacity factor reported for the unit in EIA Form 860 for years 2006-2010). These limits are intended to prevent dispatch patterns that exceed the reported technical capabilities of these units. In cases where the maximum reported capacity factors is below 15%, a capacity factor of 15% is used as a limit, since historical capacity factor values below 15% are not considered to reflect the generation capability of the unit. (3) Even though the dispatch of cogeneration units in the Final Transport Rule will be based on their electric power (net) heat rate characteristics, the emissions from both power and steam production will be taken into account, since for cogeneration units the Transport Rule covers the emissions attributable to both electric and steam generation. To capture these total emissions a multiplier (derived by dividing the total fuel consumed for both steam and power by the fuel consumed for power) is applied to the power only emissions. 1.2 Resulting Updates The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case v4.10_FTransport. ------- 3.5.2 Capacity Factor Add the following paragraph at the end of this section: To prevent dispatch patterns that exceed their reported technical capabilities, cogeneration units are allowed to dispatch up to the availabilities assumed for the particular generation technology or up to their historic capacity factors (derived by taking the maximum historical capacity factor reported for the unit in EIA Form 860 for years 2006-2010). In cases where the maximum reported capacity factors is below 15%, a capacity factor of 15% is used as a limit, since historical capacity factor values below 15% are not considered to reflect the generation capability of the unit. Appendix 3-10 shows the capacity factor upper bounds for all the existing cogeneration units that are represented in EPA Base Case v.4.10. 3.8 Heat Rate Add the following paragraph at the end of this section: For cogeneration units only, the heating value of the fuel combusted for electricity generation is used to derive the heat rate, since dispatch decisions in IPM are only based on the heat rate efficiency of the electric portion of a cogeneration unit. Known as a cogeneration unit's net heat rate, it is calculated by dividing heat content of fuel consumed for power generation by electric generated from this fuel. To capture the total emissions from the cogeneration unit, a multiplier (derived by dividing the total fuel consumed for both steam and power by the fuel consumed for power) is applied to the power only emissions. Appendix 3-10 shows the heat rate and emission multipliers of all the existing cogeneration units that are represented in EPA Base Case v.4.10. For purposes of comparison Appendix 3-10 includes the net heat rate values currently used in modeling and the gross heat rate used prior to correcting the representation as a result of comments received in the September 2010 Notice of Data Availability (NODA). The net heat rates appear in the column labeled '"Post-NODA Heat Rate (Btu/kWh)." The gross heat rates appear in the column labeled "NODA Heat Rate (Btu/kWh)." Since the net heat rate cannot exceed the gross heat rate, instances where the value of the "'Post-NODA Heat Rate (Btu/kWh)" exceeds the value of the "NODA Heat Rate (Btu/kWh)" were caused by a change in the source of the data between the NODA and post- NODA period. Such instances are highlighted and explained in Appendix 3-10. Add the following appendix at the end of Chapter 3: ------- Appendix 3-10. Cogeneration Units - Heat Rates (Before and After NODA Comments), Capacity Factor Upper Bounds, and Emission Multipliers = Higher Post-NODA Heat Rate Due to Higher Reported Value in AEO 2010 than in AEO 2008 = Higher Post-NODA Heat Rate Based on NODA Comment = Higher Post-NODA Heat Rate Based on Net Heat Rate Reported in EIA Form 923 2012 Capacity NODA Post-NODA Factor Upper Region Capacity Heat Rate Heat Rate Emissions Bound Plant Name UniquelD_Final PlantType Name (MW) (Btu/kWh) (Btu/kWh) Multiplier Implemented ACE Cogeneration Facility 10002_B_ Trigen Colorado Energy 10003_B_ Trigen Colorado Energy 10003_B_ Trigen Colorado Energy 10003_B_ Trigen Colorado Energy 10003_B_ Trigen Colorado Energy 10003_B_ Baptist Medical Center 10008_G_ Baptist Medical Center 10008_G_ Baptist Medical Center 10008_G_ Baptist Medical Center 10008_G_ Baptist Medical Center 10008_G_ NRG Energy Center Dover 10030_B_ Greater Detroit Resource Recovery 10033_B_ Greater Detroit Resource Recovery 10033_B_ Greater Detroit Resource Recovery 10033_B_ Gilroy Power Plant 10034_G_ Gilroy Power Plant 10034_G_ Logan Generating Plant 10043_B_ Central Utilities Plant LAX 10048_G_ Central Utilities Plant LAX 10048_G_ Cogentrix Virginia Leasing Corporation 10071_B_ Cogentrix Virginia Leasing Corporation 10071_B_ Cogentrix Virginia Leasing Corporation 10071_B_ CFB Coal Steam CA-S 101 BLR1 0/G Steam RMPA 8.1 BLR2 0/G Steam RMPA 8.1 BLR3 Coal Steam RMPA 8.1 BLR4 Coal Steam RMPA 8.1 BLR5 Coal Steam RMPA 8.1 CG-3 1C Engine FRCC 0.50 TG-1 Combustion Turbine FRCC 2.3 TG-2 Combustion Turbine FRCC 2.2 TG-3 Combustion Turbine FRCC 2.7 TG-4 Combustion Turbine FRCC 3.2 COGEN1 Coal Steam MACE 16.0 11 Municipal Solid Waste MECS 21.2 12 Municipal Solid Waste MECS 21.2 13 Municipal Solid Waste MECS 21.2 GEN1 Combined Cycle CA-N 90.0 GEN2 Combined Cycle CA-N 40.0 B01 Coal Steam MACE 219 GEN1 Combustion Turbine CA-S 4.0 GEN2 Combustion Turbine CA-S 4.0 1A Coal Steam VAPW 19.2 IB Coal Steam VAPW 19.2 1C Coal Steam VAPW 19.2 10921 11972 11964 10331 10331 11768 13298 15981 15981 15981 12503 11782 19338 19338 19338 8330 8330 9890 15981 15981 11354 10331 10331 10526 8300 8300 8300 8300 8300 13199 15845 8700 8700 8700 11782 8300 8300 ^^^^ 8300 8373 8373 9890 8700 8700 10888 10320 10320 1.04 1.44 1.44 1.24 1.24 1.42 1.00 1.00 1.82 1.82 1.43 1.00 1.96 1.96 1.96 1.00 1.00 1.00 1.82 1.82 1.04 1.00 1.00 89.70 89.51 89.51 86.40 86.40 86.40 89.24 89.24 89.24 89.24 89.24 75.40 52.47 52.47 52.47 84.63 84.63 83.80 89.24 89.24 74.60 74.60 74.60 ------- Cogentrix Virginia Leasing Corporation Cogentrix Virginia Leasing Corporation Cogentrix Virginia Leasing Corporation Pedricktown Cogen Plant Pedricktown Cogen Plant Frito-Lay Cogen Plant John B Rich Memorial Power Station John B Rich Memorial Power Station Harrisburg Facility Harrisburg Facility Harrisburg Facility Indiana University of Pennsylvania Indiana University of Pennsylvania Indiana University of Pennsylvania Indiana University of Pennsylvania Sierra Pacific Lincoln Facility Fresno Cogen Partners Fresno Cogen Partners Fresno Cogen Partners Cardinal Cogen Cardinal Cogen Carson Cogeneration Carson Cogeneration Metro Wastewater Reclamation District Metro Wastewater Reclamation District Metro Wastewater Reclamation District Metro Wastewater Reclamation District Metro Wastewater Reclamation District Metro Wastewater Reclamation District Central Utility Plant Central Utility Plant Central Utility Plant IMC Phosphates Company Uncle Sam IMC Phosphates Company Uncle Sam Hercules Missouri Chemical Works Hercules Missouri Chemical Works Hercules Missouri Chemical Works Snowbird Power Plant Snowbird Power Plant Snowbird Power Plant Alabama River Pulp 10071_B_2A Coal Steam 10071_B_2B Coal Steam 10071_B_2C Coal Steam 10099_G_GEN1 Combined Cycle 10099_G_GEN2 Combined Cycle 10110_G_GEN1 Combustion Turbine 10113_B_CFB1 Coal Steam 10113_B_CFB2 Coal Steam 10118_B_1 Municipal Solid Waste 10118_B_2 Municipal Solid Waste 10118_B_3 Municipal Solid Waste 10129_G_GEN1 1C Engine 10129_G_GEN2 1C Engine 10129_G_GEN3 1C Engine 10129_G_GEN4 1C Engine 10144_G_GEN4 Biomass 10156_G_GEN2 Combined Cycle 10156_G_GEN3 Combined Cycle 10156_G_GEN4 Combined Cycle 10168_G_GTG1 Combined Cycle 10168_G_STG1 Combined Cycle 10169_G_GEN1 Combined Cycle 10169_G_GEN2 Combined Cycle 10180_G_1 Non-Fossil Waste 10180_G_2 Non-Fossil Waste 10180_G_3 Non-Fossil Waste 10180_G_4 Non-Fossil Waste 10180_G_5 Non-Fossil Waste 10180_G_6 Non-Fossil Waste 10184_G_EG1 1C Engine 10184_G_EG2 1C Engine 10184_G_TG1 0/G Steam 10198_G_GEN1 Non-Fossil Waste 10198_G_GEN2 Non-Fossil Waste 10207_B_1 Coal Steam 10207_B_2 Coal Steam 10207_B_3 Coal Steam 10215_G_1367 1C Engine 10215_G_1391 1C Engine 10215_G_1392 1C Engine 10216 B PB1 Biomass VAPW 19.2 VAPW 19.2 VAPW 19.2 MACE 79.2 MACE 36.5 CA-N 5.1 MACW 40.0 MACW 40.0 MACW 6.9 MACW 6.9 MACW 6.9 MACW 6.0 MACW 6.0 MACW 6.0 MACW 6.0 CA-N 17.2 CA-N 6.0 CA-N 21.9 CA-N 45.0 CA-N 32.5 CA-N 9.4 CA-S 41.3 CA-S 8.0 RMPA 1.2 RMPA 1.2 RMPA 1.2 RMPA 1.2 RMPA 2.5 RMPA 2.5 ERCT 4.3 ERCT 3.2 ERCT 0.23 ENTG 10.2 ENTG 10.2 GWAY 5.7 GWAY 5.7 GWAY 5.7 NWPE 0.59 NWPE 0.59 NWPE 0.59 SOU 22.3 11353 10331 10331 8350 8350 15981 11190 10331 19338 19338 19338 13298 13298 13298 13298 15517 7651 7651 7651 9939 9939 8994 8994 14283 14283 14283 14283 10000 10000 13298 13298 11425 13102 13102 12508 12508 12508 13298 13298 13298 15517 10888 10320 10320 7916 7916 15845 8300 8300 8300 8300 8300 9480 9480 9480 9480 8300 8594 8594 8594 9738 9738 8557 8557 8700 8700 8700 8700 8700 8700 13199 13199 10036 9854 9854 8300 8300 8300 8700 8700 8700 8300 1.04 1.00 1.00 1.00 1.00 1.00 1.35 1.24 2.33 2.33 2.33 1.39 1.39 1.39 1.39 1.89 1.09 1.09 1.09 1.00 1.00 1.01 1.01 1.64 1.64 1.64 1.64 1.15 1.15 1.00 1.00 1.11 1.30 1.30 1.49 1.49 1.49 1.52 1.52 1.52 1.89 74.60 74.60 74.60 84.63 84.63 89.24 95.00 95.00 88.41 88.41 88.41 89.24 89.24 89.24 89.24 83.00 15.00 15.00 15.00 84.63 84.63 84.63 84.63 77.35 77.35 77.35 77.35 77.35 77.35 89.24 89.24 89.51 75.66 75.66 85.26 85.26 85.26 89.24 89.24 89.24 83.00 ------- Alabama River Pulp Leaf River Cellulose LLC Leaf River Cellulose LLC King City Power Plant King City Power Plant Bayou Cogen Plant Bayou Cogen Plant Bayou Cogen Plant Bayou Cogen Plant Bellingham Cogeneration Facility Bellingham Cogeneration Facility Bellingham Cogeneration Facility Sayreville Cogeneration Facility Sayreville Cogeneration Facility Sayreville Cogeneration Facility Central Power & Lime Foster Wheeler Martinez Foster Wheeler Martinez Foster Wheeler Martinez Foster Wheeler Mt Carmel Cogen Charleston Resource Recovery Facility Charleston Resource Recovery Facility Greenleaf 2 Power Plant Greenleaf 1 Power Plant Greenleaf 1 Power Plant Cogentrix Hopewell Cogentrix Hopewell Cogentrix Hopewell Cogentrix Hopewell Cogentrix Hopewell Cogentrix Hopewell Primary Energy Southport Primary Energy Southport Primary Energy Southport Primary Energy Southport Primary Energy Southport Primary Energy Southport Primary Energy Roxboro Primary Energy Roxboro Primary Energy Roxboro Elizabethtown Power LLC 10216_B_RB1 10233_B_PB 10233_B_RB 10294_G_GTG 10294_G_STG 10298_G_GEN1 10298_G_GEN2 10298_G_GEN3 10298_G_GEN4 10307_G_CT1 10307_G_CT2 10307_G_ST1 10308_G_CT1 10308_G_CT2 10308_G_ST1 10333_B_1 10342_G_TG1 10342_G_TG2 10342_G_TG3 10343_B_SG-101 10344_B_B1 10344_B_B2 10349_G_GEN1 10350_G_GEN1 10350_G_GEN2 10377_B_1A 10377_B_1B 10377_B_1C 10377_B_2A 10377_B_2B 10377_B_2C 10378_B_1A 10378_B_1B 10378_B_1C 10378_B_2A 10378_B_2B 10378_B_2C 10379_B_1A 10379_B_1B 10379_B_1C 10380_B_A BLR Non-Fossil Waste Biomass Non-Fossil Waste Combined Cycle Combined Cycle Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam Combined Cycle Combined Cycle Combined Cycle Coal Steam Municipal Solid Waste Municipal Solid Waste Combustion Turbine Combined Cycle Combined Cycle Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam SOU 22.3 SOU 37.5 SOU 12.5 CA-N 73.0 CA-N 38.0 ERCT 65.0 ERCT 65.0 ERCT 65.0 ERCT 65.0 NENG 102 NENG 102 NENG 60.0 MACE 98.0 MACE 98.0 MACE 75.0 FRCC 139 CA-N 35.0 CA-N 35.0 CA-N 33.5 MACW 43.0 VACA 4.8 VACA 4.8 CA-N 49.5 CA-N 42.0 CA-N 8.0 VAPW 18.2 VAPW 18.2 VAPW 18.2 VAPW 18.2 VAPW 18.2 VAPW 18.2 VACA 17.8 VACA 17.8 VACA 17.8 VACA 17.8 VACA 17.8 VACA 17.8 VACA 18.7 VACA 18.7 VACA 18.7 16.0 13102 15517 13102 7990 7990 15981 15981 15981 15981 8300 8300 8300 8650 8650 8650 10896 8600 8600 8600 12500 19338 19338 10578 8290 8290 10331 11360 10331 11359 10331 10331 11362 10331 10331 11361 10331 10331 11362 10331 10331 NotindB 8300 8300 8300 7990 7990 8700 8700 8700 8700 7953 7953 7953 8200 8200 8200 10327 8266 8266 8266 11845 9587 9587 8700 6181 6181 9194 9194 9194 9194 9194 9194 11362 10320 10320 11361 10320 10320 11362 10320 10320 11113 1.54 1.89 1.54 1.00 1.00 1.82 1.82 1.82 1.82 1.04 1.04 1.04 1.00 1.00 1.00 1.06 1.13 1.13 1.13 1.06 1.70 1.70 1.22 1.49 1.49 1.12 1.24 1.12 1.24 1.12 1.12 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.05 55.17 83.00 55.17 84.63 84.63 90.81 90.81 90.81 90.81 22.19 22.19 22.19 84.63 84.63 84.63 60.53 84.63 84.63 84.63 90.10 89.39 89.39 90.81 66.10 66.10 83.40 83.40 83.40 83.40 83.40 83.40 41.34 41.34 41.34 41.34 41.34 41.34 83.00 83.00 83.00 41.34 ------- Elizabethtown Power LLC Green Power Kenansville Green Power Kenansville Lumberton Lumberton Edgecombe GenCo Edgecombe GenCo Edgecombe GenCo Edgecombe GenCo Little Company of Mary Hospital Laidlaw Energy & Environmental Laidlaw Energy & Environmental Laidlaw Energy & Environmental Laidlaw Energy & Environmental KingsburgCogen KingsburgCogen Inland Ontario Mill Wisconsin Rapids Pulp Mill Wisconsin Rapids Pulp Mill Wisconsin Rapids Pulp Mill Wisconsin Rapids Pulp Mill Wisconsin Rapids Pulp Mill Wisconsin Rapids Pulp Mill Pitchess Cogen Station Pitchess Cogen Station Rumford Cogeneration Rumford Cogeneration Kern River Cogeneration Kern River Cogeneration Kern River Cogeneration Kern River Cogeneration Mid-Set Cogeneration San Jose Cogeneration Chambers Cogeneration LP Chambers Cogeneration LP Algonquin Windsor Locks Algonquin Windsor Locks Sixth Street Sixth Street Sixth Street Sixth Street 10380_B_B BLR 10381_B_1A 10381_B_1B 10382_B_UNIT1 10382_B_UNIT2 10384_B_1A 10384_B_1B 10384_B_2A 10384_B_2B 10400_G_GEN1 10403_G_ALLI 10403_G_CAT3 10403_G_CAT4 10403_G_WEST 10405_G_GEN1 10405_G_GEN2 10427_G_GEN1 10477_B_P1 10477_B_P2 10477_B_P3 10477_B_R1 10477_B_R2 10477_B_R3 10478_G_GEN1 10478_G_GEN2 10495_B_6 10495_B_7 10496_G_GTAG 10496_G_GTBG 10496_G_GTCG 10496_G_GTDG 10501_G_K100 10548_G_GEN1 10566_B_BOIL1 10566_B_BOIL2 10567_G_GTG 10567_G_STG 1058_B_2 1058_B_3 1058_B_4 1058 B 5 Coal Steam Biomass Biomass Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Combustion Turbine Combined Cycle 1C Engine 1C Engine Combined Cycle Combined Cycle Combined Cycle Combustion Turbine Coal Steam Coal Steam 0/G Steam Non-Fossil Waste Non-Fossil Waste Non-Fossil Waste Combined Cycle Combined Cycle Coal Steam Coal Steam Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Coal Steam Coal Steam Combined Cycle Combined Cycle Coal Steam Coal Steam Coal Steam Coal Steam 16.0 VACA 16.2 VACA 16.2 16.0 16.0 VAPW 28.9 VAPW 28.9 VAPW 28.9 VAPW 28.9 COMD 3.2 UPNY 2.6 UPNY 0.40 UPNY 0.40 UPNY 0.70 CA-N 22.0 CA-N 11.8 CA-S 34.0 WUMS 11.2 WUMS 11.2 WUMS 11.2 WUMS 11.2 WUMS 11.2 WUMS 11.2 CA-S 21.5 CA-S 5.7 NENG 42.5 NENG 42.5 CA-N 72.0 CA-N 72.0 CA-N 72.0 CA-N 72.0 CA-N 36.0 CA-N 5.6 MACE 131 MACE 131 NENG 26.0 NENG 12.0 13.6 13.6 13.6 13.6 NotindB 11564 15517 NotindB NotindB 11325 10331 11325 10331 15981 11860 11100 11100 11860 9832 9832 15981 10331 10331 11332 13102 13102 13102 10211 10211 11058 10331 16509 16509 16509 16509 15506 15981 10000 10331 10186 10186 Not in dB Not in dB Not in dB Not in dB 11113 11498 11498 11247 11247 11062 10320 11062 10320 8700 11860 11100 11100 11860 8492 8492 15845 8300 8300 8300 8300 8300 8300 6716 6716 8300 8300 8700 8700 8700 8700 8700 11640 10000 10079 7106 7106 12551 14500 14500 14500 1.05 1.37 1.37 1.04 1.04 1.02 1.00 1.02 1.00 1.82 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.24 1.24 1.39 1.54 1.54 1.54 1.68 1.68 1.33 1.24 1.90 1.90 1.90 1.90 1.78 1.36 1.00 1.02 1.30 1.30 1.00 1.00 1.00 1.00 41.34 83.00 83.00 15.00 15.00 90.00 90.00 90.00 90.00 89.24 84.63 89.24 89.24 84.63 84.63 84.63 89.87 85.26 85.26 92.41 75.66 75.66 75.66 84.63 84.63 94.10 94.10 90.81 90.81 90.81 90.81 89.87 89.24 74.80 74.80 84.63 84.63 35.53 35.53 35.53 35.53 ------- BP Wilmington Calciner Ebensburg Power Domtar - Woodland Mill Domtar - Woodland Mill CH Resources Beaver Falls CH Resources Beaver Falls Civic Center Civic Center Wheelabrator Baltimore Refuse Wheelabrator Baltimore Refuse Wheelabrator Baltimore Refuse Hopewell Cogeneration Hopewell Cogeneration Hopewell Cogeneration Hopewell Cogeneration Corona Cogen Cambria Cogen Cambria Cogen Bear Mountain Cogen Badger Creek Cogen Burney Forest Products Burney Forest Products Sierra Pacific Sonora AES Deepwater AES Shady Point AES Shady Point AES Shady Point AES Shady Point Cedar Bay Generating LP Cedar Bay Generating LP Cedar Bay Generating LP AES Thames AES Thames AES Beaver Valley Partners Beaver Valley AES Beaver Valley Partners Beaver Valley AES Beaver Valley Partners Beaver Valley AES Beaver Valley Partners Beaver Valley AES Placerita AES Placerita AES Placerita AES Warrior Run Cogeneration Facility 10601_G_GEN1 Coal Steam 10603_B_031 Coal Steam 10613_B_3RB 0/G Steam 10613_B_9PB Biomass 10617_G_GEN1 Combined Cycle 10617_G_GEN2 Combined Cycle 10623_G_GEN1 Combined Cycle 10623_G_GEN2 Combined Cycle 10629_B_BLR1 Municipal Solid Waste 10629_B_BLR2 Municipal Solid Waste 10629_B_BLR3 Municipal Solid Waste 10633_G_GT1 Combined Cycle 10633_G_GT2 Combined Cycle 10633_G_GT3 Combined Cycle 10633_G_ST1 Combined Cycle 10635_G_GEN1 Combustion Turbine 10641_B_B1 Coal Steam 10641_B_B2 Coal Steam 10649_G_GEN1 Combustion Turbine 10650_G_GEN1 Combustion Turbine 10652_B_BLR1 Biomass 10652_B_BLR2 Biomass 54517_G_GEN2 Biomass 10670_B_AAB001 Coal Steam 10671_B_1A Coal Steam 10671_B_1B Coal Steam 10671_B_2A Coal Steam 10671_B_2B Coal Steam 10672_B_CBA Coal Steam 10672_B_CBB Coal Steam 10672_B_CBC Coal Steam 10675_B_A Coal Steam 10675_B_B Coal Steam 10676_B_2 Coal Steam 10676_B_3 Coal Steam 10676_B_4 Coal Steam 10676_B_5 Coal Steam 10677_G_UNT1 Combined Cycle 10677_G_UNT2 Combined Cycle 10677_G_UNT3 Combined Cycle 10678 B BLR1 Coal Steam CA-S 29.0 MACW 49.5 NENG 23.0 NENG 23.0 UPNY 52.5 UPNY 34.0 CA-S 18.5 CA-S 1.2 MACS 20.4 MACS 20.4 MACS 20.4 84.1 84.1 84.1 96.0 CA-S 40.0 MACW 44.0 MACW 44.0 CA-N 46.0 CA-N 46.0 CA-N 15.5 CA-N 15.5 CA-N 5.5 ERCT 140 SPPS 80.0 SPPS 80.0 SPPS 80.0 SPPS 80.0 FRCC 83.3 FRCC 83.3 FRCC 83.3 NENG 90.5 NENG 90.5 RFCP 43.0 RFCP 43.0 RFCP 43.0 RFCP 17.0 CA-S 46.0 CA-S 46.0 CA-S 23.0 RFCP 180 10331 12500 11844 15517 8700 8700 9939 9939 19338 19338 19338 NotindB NotindB NotindB NotindB 15727 11076 10331 13225 13225 15517 15517 15517 14500 10471 10331 10469 10331 9504 10331 10331 10173 10331 11621 12508 12508 12508 9900 9900 9900 11177 9854 12500 8300 8300 8700 8700 8577 8577 16297 16297 16297 8292 8292 8292 8292 8700 12200 12200 8700 8700 15716 15716 8300 11801 10471 10320 10469 10320 9375 9375 9375 9491 9491 10910 10910 10910 10910 9894 9894 9894 10577 1.05 1.00 1.39 1.89 1.00 1.00 1.14 1.14 1.00 1.00 1.00 1.09 1.09 1.09 1.09 1.81 1.00 1.00 1.52 1.52 1.00 1.00 1.89 1.23 1.00 1.00 1.00 1.00 1.01 1.10 1.10 1.07 1.09 1.07 1.14 1.14 1.14 1.00 1.00 1.00 1.06 85.26 95.00 86.60 83.00 84.63 84.63 84.63 84.63 90.00 90.00 90.00 27.40 27.40 27.40 27.40 89.87 95.00 95.00 89.87 89.87 83.00 83.00 83.00 85.26 80.90 80.90 80.90 80.90 82.80 82.80 82.80 94.10 94.10 72.07 72.07 72.07 72.07 84.63 84.63 84.63 92.30 8 ------- Colorado Power Partners Colorado Power Partners Colorado Power Partners BCP BCP Argus Cogen Plant Argus Cogen Plant Westend Facility Rapids Energy Center Rapids Energy Center Rapids Energy Center Rapids Energy Center Jackson County Resource Recovery Selkirk Cogen Selkirk Cogen Selkirk Cogen Selkirk Cogen Selkirk Cogen Masspower Masspower Prairie Creek Prairie Creek Prairie Creek Prairie Creek Clear Lake Cogeneration Ltd Clear Lake Cogeneration Ltd Clear Lake Cogeneration Ltd Clear Lake Cogeneration Ltd Clear Lake Cogeneration Ltd Morgantown Energy Facility Morgantown Energy Facility Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture 10682_G_GT1 10682_G_GT2 10682_G_ST1 10683_G_GT3 10683_G_ST2 10684_B_BLR25 10684_B_BLR26 10685_G_PINA 10686_B_5 10686_B_6 10686_B_7 10686_B_8 10722_G_1 10725_G_GEN1 10725_G_GEN2 10725_G_GEN3 10725_G_GEN4 10725_G_GEN5 10726_G_GEN1 10726_G_GEN2 1073_B_1 1073_B_2 1073_B_3 1073_B_4 10741_G_G102 10741_G_G103 10741_G_G104 10741_G_S101 10741_G_S102 10743_B_CFB1 10743_B_CFB2 10745_G_1G12 10745_G_BP15 10745_G_GT10 10745_G_GT11 10745_G_GT12 10745_G_GT13 10745_G_GT14 10745_G_GT3 10745_G_GT4 10745 G GTS Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam Coal Steam Combustion Turbine Biomass Biomass 0/G Steam 0/G Steam Municipal Solid Waste Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam Coal Steam Coal Steam Coal Steam Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam Coal Steam 1C Engine Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle RMPA 25.0 RMPA 25.0 RMPA 30.0 RMPA 32.0 RMPA 40.0 CA-S 25.0 CA-S 25.0 CA-S 15.0 MRO 11.2 MRO 11.2 MRO 3.5 MRO 3.5 MECS 3.0 DSNY 72.6 DSNY 9.2 DSNY 79.7 DSNY 79.7 DSNY 124 NENG 82.2 NENG 82.2 MRO 9.1 MRO 10.2 MRO 41.6 MRO 125 ERCT 100 ERCT 100 ERCT 100 ERCT 52.0 ERCT 14.0 RFCP 25.0 RFCP 25.0 MECS 5.2 MECS 13.4 MECS 84.0 MECS 84.0 MECS 84.0 MECS 84.0 MECS 84.0 MECS 84.0 MECS 88.0 MECS 88.0 11860 11860 11860 11860 11860 10331 10331 15981 15517 20328 14500 11332 19338 8861 8861 8861 8861 8861 8224 8224 11595 12230 11090 10198 10540 10540 10540 10540 10540 11298 10331 11585 8974 8974 8974 8974 8974 8974 8974 8974 8974 8841 8841 8841 9885 9885 8300 8300 8700 13179 13179 11511 11511 8300 8109 8109 8109 8109 8109 8507 8507 11595 12230 11090 10198 5500 5500 5500 5500 5500 8693 8693 11585 7289 7289 7289 7289 7289 7289 7289 7289 7289 1.34 1.34 1.34 1.00 1.00 1.24 1.24 1.82 1.19 1.54 1.00 1.00 2.33 1.16 1.16 1.16 1.16 1.16 1.01 1.01 1.00 1.00 1.00 1.00 1.82 1.82 1.82 1.82 1.82 1.52 1.52 1.00 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 25.35 25.35 25.35 84.63 84.63 85.26 85.26 89.24 83.00 83.00 92.41 92.41 52.47 63.58 63.58 63.58 63.58 63.58 26.13 26.13 52.20 52.20 52.20 52.20 25.04 25.04 25.04 25.04 25.04 85.26 85.26 89.24 37.26 37.26 37.26 37.26 37.26 37.26 37.26 37.26 37.26 ------- Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Midland Cogeneration Venture Rifle Generating Station Rifle Generating Station Rifle Generating Station Rifle Generating Station Las Vegas Cogen LP Las Vegas Cogen LP Rio Bravo Jasmin Rio Bravo Poso Southampton Power Station Southampton Power Station E F Oxnard Energy Facility Seaford Delaware Plant Seaford Delaware Plant Seaford Delaware Plant Lowell Cogen Plant Lowell Cogen Plant Ogdensburg Power Ogdensburg Power Ogdensburg Power Ogdensburg Power Kenilworth Energy Facility Kenilworth Energy Facility Riverside Riverside Riverside NTC/MCRD Energy Facility NTC/MCRD Energy Facility Naval Station Energy Facility Naval Station Energy Facility Naval Station Energy Facility North Island Energy Facility North Island Energy Facility Ada Cogeneration LP Ada Cogeneration LP Walter Scott Jr. Energy Center 10745_G_GT6 10745_G_GT7 10745_G_GT8 10745_G_GT9 10745_G_ST1 10745_G_ST2 10755_G_GT2 10755_G_GT3 10755_G_GT4 10755_G_ST1 10761_G_GEN1 10761_G_GEN2 10768_B_CFB 10769_B_CFB 10774_B_1 10774_B_2 10776_G_GTG 10793_B_BLR1 10793_B_BLR3 10793_B_BLR5 10802_G_GEN1 10802_G_GEN2 10803_B_1 10803_G_GEN1 10803_G_GEN2 10803_G_GEN3 10805_G_GEN1 10805_G_GEN2 1081_B_7 1081_B_8 1081_B_9 10810_G_GEN1 10810_G_GEN2 10811_G_GEN1 10811_G_GEN2 10811_G_GEN3 10812_G_GEN1 10812_G_GEN2 10819_G_GEN1 10819_G_GEN2 1082 B 3 Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam Coal Steam Coal Steam Coal Steam Combustion Turbine 0/G Steam 0/G Steam 0/G Steam Combined Cycle Combined Cycle Biomass Biomass Biomass Biomass Combined Cycle Combined Cycle Coal Steam Coal Steam Coal Steam Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam MECS 88.0 MECS 88.0 MECS 84.0 MECS 84.0 MECS 410 MECS 380 RMPA 13.0 RMPA 13.0 RMPA 21.2 RMPA 21.2 SNV 41.0 SNV 9.0 CA-S 33.0 CA-N 33.0 36.5 36.5 CA-S 48.5 MACE 9.0 MACE 9.0 MACE 9.0 NENG 18.7 NENG 6.3 26.0 UPNY 8.3 UPNY 8.3 UPNY 8.3 MACE 22.5 MACE 4.5 MRO 2.5 MRO 2.5 MRO 130 CA-S 21.6 CA-S 2.2 CA-S 36.7 CA-S 9.8 CA-S 4.8 CA-S 33.5 CA-S 3.5 MECS 23.0 MECS 6.4 MRO 690 8974 8974 8974 8974 8974 8974 11860 11860 11860 11860 8289 8289 11568 11568 NotindB NotindB 15349 14517 14517 12534 9800 9800 Not in dB 8911 8911 8911 10700 10700 12508 12508 10720 10013 10013 11520 11520 11520 9194 9194 8950 8950 10927 7289 7289 7289 7289 7289 7289 10422 10422 10422 10422 7701 7701 11445 11568 11277 11277 8700 8300 8300 8300 9800 9800 8573 Retired Retired 8573 9867 9867 12406 12406 10720 7705 7705 8143 8143 8143 6803 6803 5866 5866 10927 1.22 1.22 1.22 1.22 1.22 1.22 1.00 1.00 1.00 1.00 1.00 1.00 1.01 1.00 1.00 1.00 1.76 1.72 1.72 1.35 1.00 1.00 1.04 1.04 1.08 1.08 1.00 1.00 1.00 1.23 1.23 1.20 1.20 1.20 1.26 1.26 1.55 1.55 1.00 37.26 37.26 37.26 37.26 37.26 37.26 84.63 84.63 84.63 84.63 84.63 84.63 92.00 95.00 59.87 90.00 89.87 86.60 86.60 92.41 84.63 84.63 15.00 0.00 0.00 83.00 76.45 76.45 64.00 64.00 64.00 84.63 84.63 82.26 82.26 82.26 84.17 84.17 84.63 84.63 73.40 10 ------- Coca Cola Bottling of New York Coca Cola Bottling of New York Coca Cola Bottling of New York Silver Bay Power Silver Bay Power Mojave Cogen Mojave Cogen Biomass One LP Biomass One LP Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Medical Area Total Energy Plant Ames Electric Services Power Plant Ames Electric Services Power Plant Muscatine Plant #1 Louisiana 1 Louisiana 1 Louisiana 1 Louisiana 1 Louisiana 1 RS Nelson RS Nelson RS Nelson RS Nelson Kendall Square Station Kendall Square Station Kendall Square Station Kendall Square Station Apache Station 10829_G_ENG1 1C Engine DSNY 0.60 10829_G_ENG2 1C Engine DSNY 0.60 10829_G_ENG3 1C Engine DSNY 0.60 10849_B_BLR1 Coal Steam 36.0 10849_B_BLR2 Coal Steam 69.0 10850_G_GEN1 Combined Cycle CA-S 40.0 10850_G_GEN2 Combined Cycle CA-S 15.3 10869_B_NORTH Biomass PNW 8.5 10869_B_SOUTH Biomass PNW 14.0 10883_B_GTHSG1 0/G Steam NENG 3.1 10883_B_GTHSG2 0/G Steam NENG 3.1 10883_B_HSG1 0/G Steam NENG 3.1 10883_B_HSG2 0/G Steam NENG 3.1 10883_B_PSG1 0/G Steam NENG 3.1 10883_B_PSG2 0/G Steam NENG 3.1 10883_B_PSG3 0/G Steam NENG 3.1 10883_G_CT1 Combustion Turbine NENG 12.5 10883_G_CT2 Combustion Turbine NENG 12.5 10883_G_DEG1 1C Engine NENG 6.0 10883_G_DEG2 1C Engine NENG 6.0 10883_G_DEG3 1C Engine NENG 6.0 10883_G_DEG4 1C Engine NENG 6.0 10883_G_DEG5 1C Engine NENG 6.0 10883_G_DEG6 1C Engine NENG 6.0 1122_B_7 Coal Steam MRO 33.0 1122_B_8 Coal Steam MRO 70.0 1167_B_8 Coal Steam MRO 35.0 1391_G_1A Combined Cycle ENTG 18.0 1391_G_2A Combined Cycle ENTG 55.0 1391_G_3A Combined Cycle ENTG 55.0 1391_G_4A Combined Cycle ENTG 100 1391_G_5A Combined Cycle ENTG 154 1393_B_1A Coal Steam ENTG 107 1393_B_2A Coal Steam ENTG 106 1393_B_3 0/G Steam ENTG 153 1393_B_4 0/G Steam ENTG 500 1595_G_1 Combined Cycle NENG 15.0 1595_G_2 Combined Cycle NENG 20.0 1595_G_3 Combined Cycle NENG 21.7 1595_G_GEN4 Combined Cycle NENG 180 160_G_GT1 Combined Cycle AZNM 10.0 12942 12942 13080 NotindB NotindB 11600 11600 15517 15517 11332 11332 11332 11332 11332 11332 11332 12503 12503 13988 13988 13988 13988 13988 13988 12926 12926 15279 10472 10472 10472 10472 10472 11041 11041 10476 10419 8658 8658 8658 8658 11855 Retired Retired Retired 9693 9693 7870 7870 12056 12056 8300 8300 8300 8300 8300 8300 8300 8700 8700 8700 8700 8700 8700 8700 8700 12926 12926 15279 5500 5500 5500 5500 5500 11041 11041 10476 10419 8945 8945 8945 8945 11071 1.06 1.06 1.25 1.25 1.30 1.30 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.43 1.43 1.60 1.60 1.60 1.60 1.60 1.60 1.00 1.00 1.00 1.90 1.90 1.90 1.90 1.90 1.00 1.00 1.00 1.00 1.16 1.16 1.16 1.16 1.00 0.00 0.00 0.00 85.26 85.26 82.77 82.77 83.00 83.00 92.41 92.41 92.41 92.41 92.41 92.41 92.41 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 59.00 59.00 71.93 63.33 63.33 63.33 63.33 63.33 85.26 85.26 84.42 84.42 71.62 71.62 71.62 71.62 84.63 11 ------- Apache Station Mistersky Mistersky Mistersky MLHibbard MLHibbard Nibbing Nibbing Nibbing Nibbing New Ulm New Ulm New Ulm Virginia Virginia Virginia Virginia Willmar Willmar Chevron Oil Chevron Oil Chevron Oil Chevron Oil Chevron Oil Raton East River East River Ravenswood AES Westover AES Westover AES Westover Hamilton Johnsonville Johnsonville Johnsonville Johnsonville Johnsonville Johnsonville Johnsonville Johnsonville Johnsonville 160_G_ST1 Combined Cycle AZNM 72.0 1822_B_5 0/G Steam 163 1822_B_6 0/G Steam 163 1822_B_7 0/G Steam 163 1897_B_3 Biomass MRO 33.3 1897_B_4 Biomass MRO 15.3 1979_B_1 Coal Steam MRO 10.2 1979_B_2 Coal Steam MRO 10.2 1979_B_3 Coal Steam MRO 10.2 1979_B_wood Biomass MRO 20.0 2001_B_1 0/G Steam MRO 3.1 2001_B_2 0/G Steam MRO 3.1 2001_B_4 0/G Steam MRO 16.3 2018_B_10 0/G Steam MRO 9.7 2018_B_7 Coal Steam MRO 9.7 2018_B_9 Coal Steam MRO 9.7 2018_B_wood Biomass MRO 15.0 2022_B_2 0/G Steam MRO 3.0 2022_B_3 Coal Steam MRO 20.4 2047_G_1 Combustion Turbine SOU 15.0 2047_G_2 Combustion Turbine SOU 15.0 2047_G_3 Combustion Turbine SOU 16.0 2047_G_4 Combustion Turbine SOU 16.0 2047_G_5 Combustion Turbine SOU 65.0 2468_G_5 Coal Steam AZNM 6.9 2493_B_60 0/G Steam NYC 134 2493_B_70 0/G Steam NYC 182 2500_G_4 Combined Cycle NYC 231 2526_B_11 Coal Steam UPNY 21.9 2526_B_12 Coal Steam UPNY 21.9 2526_B_13 Coal Steam UPNY 84.0 2917_G_GT2 Combined Cycle RFCO 12.0 3406_B_1 Coal Steam TVA 106 3406_B_10 Coal Steam TVA 141 3406_B_2 Coal Steam TVA 106 3406_B_3 Coal Steam TVA 106 3406_B_4 Coal Steam TVA 106 3406_B_5 Coal Steam TVA 106 3406_B_6 Coal Steam TVA 106 3406_B_7 Coal Steam TVA 141 3406_B_8 Coal Steam TVA 141 11855 Not in dB Not in dB Not in dB 14500 14500 10331 10331 9906 14500 14500 14500 14500 11804 12245 11947 14500 14500 12260 15154 15154 15188 15188 13160 14200 12215 12215 7933 12184 12508 11000 36790 11957 10649 11957 11957 11957 11031 11031 10649 10649 11071 14500 14500 14500 14500 14500 10320 10320 9906 15716 14500 14500 14500 11804 12245 11947 15716 14500 12260 15154 15154 15188 15188 13160 14200 12830 11980 15000 11030 11030 11000 15000 11957 10649 11957 11957 11957 11031 11031 10649 10649 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.10 1.12 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 84.63 89.51 92.41 89.51 83.00 83.00 40.46 40.46 40.46 83.00 92.41 92.41 92.41 92.41 38.33 38.33 83.00 92.41 38.07 89.24 89.24 89.24 89.24 90.81 95.00 83.29 83.29 84.63 74.27 74.27 74.27 84.63 72.87 72.87 72.87 72.87 72.87 72.87 72.87 72.87 72.87 12 ------- Johnsonville Valley Valley Valley Valley Manitowoc Manitowoc Manitowoc Manitowoc Manitowoc Menasha Menasha Menasha Pittsfield Generating LP Pittsfield Generating LP Pittsfield Generating LP Pittsfield Generating LP Chalk Cliff Cogen Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Linden Cogen Plant Nelson Industrial Steam and Operating Company Nelson Industrial Steam and Operating Company Kline Township Cogen Facility Pacific Lumber Pacific Lumber Pacific Lumber Borger Plant Borger Plant Sierra Power Marcus Hook Refinery Cogen EQ Waste Energy Services EQ Waste Energy Services EQ Waste Energy Services EQ Waste Energy Services 3406_B_9 Coal Steam TVA 141 4042_B_1 Coal Steam WUMS 70.0 4042_B_2 Coal Steam WUMS 70.0 4042_B_3 Coal Steam WUMS 70.0 4042_B_4 Coal Steam WUMS 70.0 4125_B_5 Coal Steam WUMS 1.5 4125_B_6 Coal Steam WUMS 18.0 4125_B_7 Coal Steam WUMS 18.0 4125_B_8 Coal Steam WUMS 20.6 4125_B_9 Coal Steam WUMS 30.0 4127_B_5 Coal Steam WUMS 6.9 4127_B_B23 Coal Steam 8.50 4127_B_B24 Coal Steam 14.5 50002_G_GEN1 Combined Cycle NENG 33.8 50002_G_GEN2 Combined Cycle NENG 33.8 50002_G_GEN3 Combined Cycle NENG 33.8 50002_G_GEN4 Combined Cycle NENG 39.6 50003_G_GEN1 Combustion Turbine CA-N 46.0 50006_G_GTG1 Combined Cycle MACE 90.0 50006_G_GTG2 Combined Cycle MACE 90.0 50006_G_GTG3 Combined Cycle MACE 90.0 50006_G_GTG4 Combined Cycle MACE 90.0 50006_G_GTG5 Combined Cycle MACE 90.0 50006_G_GTG6 Combined Cycle MACE 182 50006_G_STG1 Combined Cycle MACE 89.0 50006_G_STG2 Combined Cycle MACE 89.0 50006_G_STG3 Combined Cycle MACE 89.0 50030_B_1A Coal Steam 107 50030_B_2A Coal Steam 106 50039_B_1 Coal Steam MACW 50.0 50049_B_BLRA Biomass CA-N 16.2 50049_B_BLRB Biomass CA-N 8.7 50049_B_BLRC Biomass CA-N 8.7 50067_B_1 Fossil Waste SPPS 16.0 50067_B_2 Fossil Waste SPPS 16.0 50068_G_WEST Biomass CA-S 7.0 50074_G_GEN1 Combustion Turbine MACE 50.0 50077_G_CAT1 Landfill Gas MECS 0.50 50077_G_CAT2 Landfill Gas MECS 0.30 50077_G_CAT3 Landfill Gas MECS 0.30 50077_G_CAT4 Landfill Gas MECS 0.30 10649 13428 13428 13199 13199 11365 11470 10331 10331 10331 10331 Not in dB Not in dB 10808 10808 10808 10808 13225 9174 9174 9174 9174 9174 9174 9174 9174 9174 NotindB NotindB 12138 15517 15517 15517 9107 9107 15517 10973 13388 13388 13388 13388 10649 13428 13428 13199 13199 11365 11470 10320 10320 10320 8844 11844 11844 9095 9095 9095 9095 8700 6778 6778 6778 6778 6778 6778 6778 6778 6778 11041 11041 12138 15716 15716 15716 8300 8300 14500 8700 13698 13698 13698 13698 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.22 1.22 1.04 1.04 1.04 1.04 1.52 1.18 1.18 1.18 1.18 1.18 1.18 1.19 1.22 1.46 1.00 1.00 1.00 1.00 1.00 1.00 1.10 1.10 1.08 1.26 1.00 1.00 1.00 1.00 72.87 61.87 61.87 61.87 61.87 93.20 93.20 93.20 93.20 93.20 31.67 24.01 24.01 15.00 15.00 15.00 15.00 89.87 65.22 65.22 65.22 65.22 65.22 65.22 65.22 65.22 65.22 85.26 85.26 92.20 83.00 83.00 83.00 70.88 70.88 83.00 90.81 90.00 90.00 90.00 90.00 13 ------- Trigen Trenton Energy Trigen Trenton Energy Tillotson Rubber Tillotson Rubber Sierra Pacific Anderson Facility United Cogen United Cogen Collins Pine Project Sierra Pacific Burney Facility Sierra Pacific Quincy Facility Susanville Susanville US Borax ConocoPhillips Rodeo Refinery ConocoPhillips Rodeo Refinery ConocoPhillips Rodeo Refinery Coalinga Cogeneration Sycamore Cogeneration Sycamore Cogeneration Sycamore Cogeneration Sycamore Cogeneration Snider Industries Union Carbide Seadrift Cogen Union Carbide Seadrift Cogen Union Carbide Seadrift Cogen Union Carbide Seadrift Cogen Union Carbide Seadrift Cogen Union Carbide Seadrift Cogen Union Carbide Seadrift Cogen Dow St Charles Operations Dow St Charles Operations Dow St Charles Operations Dow St Charles Operations Dow St Charles Operations Berry Cogen Rowan University Watson Cogeneration Watson Cogeneration Watson Cogeneration Watson Cogeneration Watson Cogeneration 50094_G_7213 1C Engine 50094_G_7214 1C Engine 50095_B_EU1 Biomass 50095_B_EU2 0/G Steam 55049_G_GEN1 Biomass 50104_G_G-1 Combined Cycle 50104_G_G-2 Combined Cycle 10661_B_4 Biomass 50110_B_BLR1 Biomass 50112_B_BLR1 Biomass 50113_G_GEN1 Biomass 50113_G_GEN2 Biomass 50115_G_GEN1 Combustion Turbine 50119_G_GENA Non-Fossil Waste 50119_G_GENB Non-Fossil Waste 50119_G_GENC Non-Fossil Waste 50131_G_K100 Combustion Turbine 50134_G_GTAG Combustion Turbine 50134_G_GTBG Combustion Turbine 50134_G_GTCG Combustion Turbine 50134_G_GTDG Combustion Turbine 50141_G_WGN1 Biomass 50150_G_GE10 Combined Cycle 50150_G_GE11 Combined Cycle 50150_G_GEN5 Combined Cycle 50150_G_GEN6 Combined Cycle 50150_G_GEN7 Combined Cycle 50150_G_GEN8 Combined Cycle 50150_G_GEN9 Combined Cycle 50152_G_CGN1 Combined Cycle 50152_G_CGN2 Combined Cycle 50152_G_CSTG Combined Cycle 50152_G_CTG Combined Cycle 50152_G_STG Combined Cycle 50170_G_GEN1 Combustion Turbine 50173_G_GEN1 Combustion Turbine 50216_G_GN91 Combined Cycle 50216_G_GN92 Combined Cycle 50216_G_GN93 Combined Cycle 50216_G_GN94 Combined Cycle 50216_G_GN95 Combined Cycle MACE 3.0 MACE 3.0 NENG 0.70 NENG 0.60 CA-N 5.0 CA-N 22.0 CA-N 7.0 CA-N 12.0 CA-N 16.3 CA-N 14.4 11.0 2.00 CA-N 39.0 CA-N 13.5 CA-N 13.5 CA-N 13.5 CA-N 36.0 CA-S 76.0 CA-S 76.0 CA-S 76.0 CA-S 76.0 SPPS 5.0 ERCT 15.0 ERCT 35.0 ERCT 15.0 ERCT 35.0 ERCT 6.0 ERCT 35.0 ERCT 15.0 ENTG 100 ENTG 100 ENTG 50.0 ENTG 10.0 ENTG 22.0 CA-N 35.0 MACE 1.2 CA-S 82.0 CA-S 82.0 CA-S 82.0 CA-S 82.0 CA-S 35.0 11625 11625 14594 12364 15517 9939 9939 15517 15517 15517 Not in dB Not in dB 15981 13102 13102 13102 15015 16038 16038 16038 16038 15517 9489 9489 9489 9489 9489 9489 9489 8004 8004 8004 8004 8004 15981 12503 9939 9939 9939 9939 9939 8700 8700 8300 9210 8300 9738 9738 8300 8300 8300 15716 15716 8700 8700 8700 8700 8700 8700 8700 8700 8700 8300 9335 9335 9335 9335 9335 9335 9335 8006 8006 8006 8006 8006 8700 12477 5500 5500 5500 5500 5500 1.34 1.34 1.89 1.25 1.89 1.00 1.00 1.89 1.89 1.89 1.00 1.00 1.82 1.47 1.47 1.47 1.73 1.84 1.84 1.84 1.84 1.89 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.82 1.00 1.77 1.77 1.77 1.77 1.77 89.24 89.24 83.00 86.60 83.00 84.63 84.63 83.00 83.00 83.00 83.00 83.00 89.87 79.92 79.92 79.92 89.87 90.81 90.81 90.81 90.81 83.00 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 89.87 89.24 70.07 70.07 70.07 70.07 70.07 14 ------- Watson Cogeneration Texas Petrochemicals Bucksport Mill Bucksport Mill Bucksport Mill Bucksport Mill Bucksport Mill Archibald Power Station Ripon Mill San Gabriel Facility Cornell University Central Heat Cornell University Central Heat Paxton Creek Cogeneration Paxton Creek Cogeneration Newark Bay Cogeneration Project Newark Bay Cogeneration Project Newark Bay Cogeneration Project Phillips 66 Carbon Plant Phillips 66 Carbon Plant P H Glatfelter P H Glatfelter P H Glatfelter P H Glatfelter P H Glatfelter BP Chemicals Green Lake Plant BP Chemicals Green Lake Plant Mobile Energy Services LLC Mobile Energy Services LLC Mobile Energy Services LLC Chester Operations Olmsted Waste Energy Olmsted Waste Energy Bronx Zoo Bronx Zoo Bronx Zoo Bronx Zoo University of Michigan University of Michigan University of Michigan University of Michigan University of Michigan 50216_G_GN96 50229_B_TPCBLR 50243_B_5 50243_B_6 50243_B_7 50243_B_8 50243_G_GEN4 50279_B_MAIN 50299_G_GEN1 50300_G_GEN1 50368_G_TG1 50368_G_TG2 50373_G_GEN1 50373_G_GEN2 50385_G_GEN1 50385_G_GEN2 50385_G_GEN3 50388_B_K1 50388_B_K2 50397_B_1PB035 50397_B_3PB033 50397_B_4PB034 50397_B_5PB036 50397_B_REC037 50404_G_TG2 50404_G_TG3 50407_B_7PB 50407_B_8PB 50407_B_8RB 50410_B_10 50413_G_TG2 50413_G_TGI 50427_G_GEN1 50427_G_GEN2 50427_G_GEN3 50427_G_GEN4 50431_G_TG1 50431_G_TG10 50431_G_TG7 50431_G_TG8 50431_G_TG9 Combined Cycle 0/G Steam 0/G Steam 0/G Steam 0/G Steam Biomass Combustion Turbine Landfill Gas Combustion Turbine Combustion Turbine Coal Steam Coal Steam 1C Engine 1C Engine Combined Cycle Combined Cycle Combined Cycle Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Non-Fossil Waste Non-Fossil Waste Non-Fossil Waste Biomass 0/G Steam 0/G Steam Coal Steam Municipal Solid Waste Municipal Solid Waste 1C Engine 1C Engine 1C Engine 1C Engine Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle CA-S ERCT NENG NENG NENG NENG NENG MACW CA-N CA-S UPNY UPNY MACW MACW MACE MACE MACE CA-N CA-N MACW MACW MACW MACW MACW ERCT ERCT SOU SOU SOU MACE MRO MRO NYC NYC NYC NYC MECS MECS MECS MECS MECS CA-S 35.0 ERCT 35.0 NENG 23.3 NENG 23.3 NENG 23.3 NENG 23.3 NENG 176 MACW 20.0 CA-N 46.5 CA-S 39.0 UPNY 1 UPNY 5.3 MACW 6.0 MACW 6.0 MACE 42.0 MACE 42.0 MACE 34.0 CA-N 10.0 CA-N 10.0 MACW 8.7 MACW 4.0 MACW 9.0 MACW 36.1 MACW 31.2 ERCT 15.0 ERCT 23.8 SOU 14.4 SOU 12.5 SOU 13.2 MACE 36.0 MRO 1.3 MRO 1.4 NYC 0.50 NYC 0.50 NYC 1.1 NYC 1.5 MECS 11.5 MECS 3.0 MECS 11.5 MECS 11.5 MECS 3.0 9939 11332 11844 11332 11332 15517 12435 13682 15778 16200 10331 10331 14993 14993 8700 8700 8700 10331 10331 10331 12508 10331 10331 13102 13102 13102 15517 11425 11425 10331 19338 19338 11600 11600 11600 11600 6920 6920 6920 6920 6920 5500 8300 8300 8300 8300 8300 9963 13698 8700 8700 9628 9628 8851 8851 8181 8181 8181 10320 10320 8300 8300 8300 8300 8300 9854 9854 10510 10538 10538 8300 11773 11773 8700 8700 8700 8700 5500 5500 5500 5500 5500 1.77 1.39 1.39 1.39 1.39 1.89 1.24 1.00 1.81 1.86 1.07 1.07 1.69 1.69 1.06 1.06 1.06 1.00 1.00 1.24 1.49 1.24 1.24 1.54 1.30 1.30 1.50 1.09 1.06 1.24 1.38 1.38 1.29 1.29 1.29 1.29 1.26 1.26 1.26 1.26 1.26 70.07 92.41 89.51 89.51 89.51 83.00 90.81 90.00 89.87 89.87 85.26 85.26 89.24 89.24 15.23 15.23 15.23 85.26 85.26 85.26 85.26 85.26 85.26 88.41 89.10 89.10 83.00 92.41 92.41 85.26 63.34 63.34 89.24 89.24 89.24 89.24 34.14 34.14 34.14 34.14 34.14 15 ------- S D Warren Westbrook S D Warren Westbrook S D Warren Westbrook S D Warren Westbrook Indeck Silver Springs Energy Center Indeck Silver Springs Energy Center Indeck Oswego Energy Center Indeck Oswego Energy Center Indeck Yerkes Energy Center Indeck Yerkes Energy Center Indeck Corinth Energy Center Indeck Corinth Energy Center Oxnard Oxnard American Ref-Fuel of Niagara American Ref-Fuel of Niagara American Ref-Fuel of Niagara American Ref-Fuel of Niagara Corpus Christi Bryant Sugar House Bryant Sugar House Bryant Sugar House Bryant Sugar House Bryant Sugar House Bryant Sugar House PPG Powerhouse C PPG Powerhouse C PPG Powerhouse C PPG Powerhouse C PPG Powerhouse C Gas Utilization Facility Gas Utilization Facility Double C Double C Kern Front Kern Front High Sierra High Sierra Bayonne Cogen Plant Bayonne Cogen Plant Bayonne Cogen Plant 50447_B_17 0/G Steam 50447_B_18 0/G Steam 50447_B_20 Biomass 50447_B_21 Biomass 50449_G_GEN1 Combined Cycle 50449_G_GEN2 Combined Cycle 50450_G_GEN1 Combined Cycle 50450_G_GEN2 Combined Cycle 50451_G_GEN1 Combined Cycle 50451_G_GEN2 Combined Cycle 50458_G_GEN1 Combined Cycle 50458_G_GEN2 Combined Cycle 50464_G_GEN1 Combustion Turbine 50464_G_GEN2 Combustion Turbine 50472_B_BLR1 0/G Steam 50472_B_BLR2 Biomass 50472_B_BLR3 Municipal Solid Waste 50472_B_BLR4 Municipal Solid Waste 50475_G_GEN1 Combustion Turbine 50483_B_B1 Biomass 50483_B_B2 Biomass 50483_B_B3 Biomass 50483_B_B4 Biomass 50483_B_B7 Biomass 50483_B_B8 Biomass 50489_G_C1 Combined Cycle 50489_G_C2 Combined Cycle 50489_G_C3 Combined Cycle 50489_G_C4 Combined Cycle 50489_G_C5 Combined Cycle 50492_G_1 Non-Fossil Waste 50492_G_2 Non-Fossil Waste 50493_G_DC1 Combustion Turbine 50493_G_DC2 Combustion Turbine 50494_G_KF1 Combustion Turbine 50494_G_KF2 Combustion Turbine 50495_G_HS1 Combustion Turbine 50495_G_HS2 Combustion Turbine 50497_G_GTG1 Combined Cycle 50497_G_GTG2 Combined Cycle 50497_G_GTG3 Combined Cycle NENG 11.9 NENG 11.9 NENG 11.9 NENG 26.9 UPNY 33.7 UPNY 17.2 UPNY 30.1 UPNY 16.2 UPNY 29.0 UPNY 19.4 DSNY 76.5 DSNY 55.0 CA-S 21.5 CA-S 45.0 UPNY 9.0 UPNY 9.0 UPNY 9.0 UPNY 9.0 ERCT 33.0 FRCC 4.4 FRCC 4.4 FRCC 4.4 FRCC 4.4 FRCC 4.4 FRCC 4.4 ENTG 55.0 ENTG 55.0 ENTG 52.0 ENTG 70.6 ENTG 70.6 CA-S 2.3 CA-S 2.3 CA-N 23.0 CA-N 23.0 CA-N 23.0 CA-N 23.0 CA-N 23.0 CA-N 23.0 MACE 36.0 MACE 36.0 MACE 36.0 11844 11844 15517 15517 8890 8890 9250 9250 9870 9870 8030 8030 15981 15981 11332 15517 19338 19338 15981 15517 15517 15517 15517 15517 15517 9939 9939 9939 9939 9939 13102 13102 14379 14379 15423 15423 15410 15410 9300 9300 9300 9021 9021 8300 8300 8270 8270 8370 8370 9325 9325 7996 7996 8700 8700 8300 8456 8300 8300 8700 8300 8300 8300 8300 8300 8300 9738 9738 9738 9738 9738 8700 8700 8700 8700 8700 8700 8700 8700 5634 5634 5634 1.28 1.28 1.87 1.89 1.00 1.00 1.03 1.03 1.01 1.01 1.00 1.00 1.82 1.82 1.39 1.86 1.96 1.96 1.82 1.89 1.89 1.89 1.89 1.89 1.89 1.00 1.00 1.00 1.00 1.00 1.47 1.47 1.65 1.65 1.77 1.77 1.77 1.77 1.64 1.64 1.64 86.60 86.60 64.60 83.00 84.63 84.63 15.00 15.00 15.00 15.00 84.63 84.63 89.87 89.87 92.41 83.00 80.91 80.91 89.87 83.00 83.00 83.00 83.00 83.00 83.00 84.63 84.63 84.63 84.63 84.63 82.98 82.98 89.87 89.87 89.87 89.87 89.87 89.87 15.00 15.00 15.00 16 ------- Bayonne Cogen Plant Capital District Energy Center Capital District Energy Center Mosaic Co Mulberry Facility SRI International Cogen Project Black Hills Ontario Facility Black Hills Ontario Facility Rosemary Power Station Rosemary Power Station Rosemary Power Station PowerSmith Cogeneration Project PowerSmith Cogeneration Project Eagle Point Cogeneration Eagle Point Cogeneration Eagle Point Cogeneration McKittrick Cogen TXU Sweetwater Generating Plant TXU Sweetwater Generating Plant TXU Sweetwater Generating Plant TXU Sweetwater Generating Plant Berry Cogen Tanne Hills 18 Berry Cogen Tanne Hills 18 Gaviota Oil Plant Gaviota Oil Plant Gaviota Oil Plant Gaviota Oil Plant ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery ExxonMobil Beaumont Refinery Covanta Marion Inc Covanta Marion Inc Mosaic Co Martlow Facility Mosaic Co Martlow Facility Potlatch Idaho Pulp Paper Potlatch Idaho Pulp Paper 50497_G_STG1 Combined Cycle 50498_G_GTG Combined Cycle 50498_G_STG Combined Cycle 50510_G_CGN1 Non-Fossil Waste 50537_G_GEN1 Combustion Turbine 50538_G_GEN1 Combustion Turbine 50538_G_GEN2 Combustion Turbine 50555_G_GEN1 Combined Cycle 50555_G_GEN2 Combined Cycle 50555_G_GEN3 Combined Cycle 50558_G_GT01 Combined Cycle 50558_G_ST01 Combined Cycle 50561_G_GTG1 Combined Cycle 50561_G_GTG2 Combined Cycle 50561_G_STG1 Combined Cycle 50612_G_GEN1 Combustion Turbine 50615_G_GT01 Combined Cycle 50615_G_GT02 Combined Cycle 50615_G_GT03 Combined Cycle 50615_G_STG1 Combined Cycle 50622_G_GEN1 Combustion Turbine 50622_G_GEN2 Combustion Turbine 50623_G_GENA Combustion Turbine 50623_G_GENB Combustion Turbine 50623_G_GENC Combustion Turbine 50623_G_GEND Combustion Turbine 50625_B_22 Fossil Waste 50625_B_24 0/G Steam 50625_B_33 Fossil Waste 50625_B_34 Fossil Waste 50625_G_TG23 Combined Cycle 50625_G_TG24 Combined Cycle 50625_G_TG41 Combustion Turbine 50625_G_TG42 Combustion Turbine 50625_G_TG43 Combustion Turbine 50630_B_BLR1 Municipal Solid Waste 50630_B_BLR2 Municipal Solid Waste 50633_G_GEN1 Non-Fossil Waste 50633_G_GEN2 Non-Fossil Waste 50637_B_1PWR 0/G Steam 50637_B_2PWR 0/G Steam MACE 62.0 NENG 34.3 NENG 21.0 FRCC 19.5 CA-N 5.6 CA-S 4.5 CA-S 4.5 VAPW 75.0 VAPW 36.0 VAPW 54.0 SPPS 67.3 SPPS 44.1 MACE 75.0 MACE 75.0 MACE 45.0 CA-N 46.0 ERCT 32.0 ERCT 72.0 ERCT 72.0 ERCT 64.0 CA-N 7.0 CA-N 7.0 CA-S 3.0 CA-S 3.0 CA-S 3.0 CA-S 3.0 ENTG 16.7 ENTG 8.3 ENTG 37.5 ENTG 37.5 ENTG 38.6 ENTG 32.0 ENTG 152 ENTG 152 ENTG 152 PNW 5.8 PNW 5.8 FRCC 36.0 FRCC 44.0 PNW 1.4 PNW 1.4 9300 9200 9200 13102 15981 15981 15981 8900 8900 8900 7272 7272 7933 7933 7933 15073 13157 13157 13157 13157 15899 15899 15981 15981 15981 15981 9107 11425 9107 9107 7933 7933 12435 12435 12435 19338 19338 13102 13102 14789 14789 5634 9545 9545 Retired 8700 Retired Retired 9911 9911 9911 8009 8009 7942 7942 7942 8700 13157 13157 13157 13157 8700 8700 8700 8700 8700 8700 8300 11177 8300 8300 6377 6377 8700 8700 8700 16297 16297 9854 9854 12156 12156 1.64 1.00 1.00 1.82 1.00 1.00 1.00 1.08 1.08 1.00 1.00 1.00 1.73 1.00 1.00 1.00 1.00 1.83 1.83 1.82 1.82 1.82 1.82 1.10 1.00 1.10 1.10 1.25 1.25 1.42 1.42 1.42 1.00 1.00 1.30 1.30 1.17 1.17 15.00 84.63 84.63 0.00 89.24 0.00 0.00 84.63 84.63 84.63 47.06 47.06 84.63 84.63 84.63 89.87 84.63 84.63 84.63 84.63 89.24 89.24 89.24 89.24 89.24 89.24 23.76 92.41 23.76 23.76 84.63 84.63 90.81 90.81 90.81 90.00 90.00 74.23 74.23 89.51 89.51 17 ------- Potlatch Idaho Pulp Paper Potlatch Idaho Pulp Paper Potlatch Idaho Pulp Paper Sierra Pacific Quincy Facility Covanta Indianapolis Energy Trigen Syracuse Energy Trigen Syracuse Energy Trigen Syracuse Energy Trigen Syracuse Energy Trigen Syracuse Energy Trigen Syracuse Energy Thermo Power & Electric Thermo Power & Electric Thermo Power & Electric KMS Crossroads TCP 272 TCP 272 TCP 272 TCP 272 TCP 272 TCP 272 TCP 272 Thermo Greeley BP Naperville Cogeneration Facility Sterling Power Plant Sterling Power Plant Agnews Power Plant Agnews Power Plant Coalinga Cogeneration Facility Coalinga Cogeneration Facility Southeast Kern River Cogen Southeast Kern River Cogen Southeast Kern River Cogen Viking Energy of Northumberland EFS Parlin EFS Parlin EFS Parlin EFS Parlin Stone Container Florence Mill Stone Container Florence Mill Stone Container Florence Mill 50637_B_4PWR Biomass 50637_B_4REC 0/G Steam 50637_B_5REC Non-Fossil Waste 50112_B_BLR2 Biomass 50647_G_GEN1 Municipal Solid Waste 50651_B_1 Coal Steam 50651_B_2 Coal Steam 50651_B_3 Coal Steam 50651_B_4 Coal Steam 50651_B_5 Coal Steam 50651_G_GEN2 Coal Steam 50676_G_GEN1 Combined Cycle 50676_G_GEN2 Combined Cycle 50676_G_GEN3 Combined Cycle 50693_G_DG-1 1C Engine 50707_G_LMA Combined Cycle 50707_G_LMB Combined Cycle 50707_G_LMC Combined Cycle 50707_G_LMD Combined Cycle 50707_G_LME Combined Cycle 50707_G_STA Combined Cycle 50707_G_STB Combined Cycle 50709_G_GEN1 Combustion Turbine 50722_G_GEN1 Combustion Turbine 50744_G_GEN1 Combined Cycle 50744_G_GEN2 Combined Cycle 50748_G_GEN1 Combined Cycle 50748_G_GEN2 Combined Cycle 50750_G_GEN1 Combustion Turbine 50750_G_GEN2 Combustion Turbine 50751_G_GTG1 Combustion Turbine 50751_G_GTG2 Combustion Turbine 50751_G_GTG3 Combustion Turbine 50771_B_B1 Biomass 50799_G_GT1 Combined Cycle 50799_G_GT2 Combined Cycle 50799_G_STG1 Combined Cycle 50799_G_STG2 Combined Cycle 50806_B_PB1 0/G Steam 50806_B_PB3 Biomass 50806 B PB4 Coal Steam PNW 27.2 PNW 1.6 PNW 32.2 CA-N 14.4 RFCO 5.0 UPNY 11.1 UPNY 11.1 UPNY 11.1 UPNY 11.1 UPNY 11.1 UPNY 11.0 RMPA 30.0 RMPA 30.0 RMPA 8.0 MACE 7.0 RMPA 31.8 RMPA 31.8 RMPA 31.8 RMPA 31.8 RMPA 31.8 RMPA 52.0 RMPA 52.0 RMPA 37.0 COMD 7.0 UPNY 38.8 UPNY 16.0 CA-N 23.0 CA-N 7.3 CA-N 3.2 CA-N 3.2 CA-N 20.5 CA-N 3.0 CA-N 3.0 MACW 16.0 MACE 38.0 MACE 38.0 MACE 25.0 MACE 25.0 VACA 5.6 VACA 7.6 VACA 74.8 15517 11332 13102 15517 19338 10000 10331 10331 10331 10331 10000 8650 8650 8650 10100 9400 9400 9400 9400 9400 9400 9400 14104 12503 8968 8968 8944 8944 15981 15981 15981 15981 15981 15517 10500 10500 10500 10500 11844 15517 10331 12152 11511 12147 8300 8300 8300 8300 8300 8300 8300 8300 6245 6245 6245 10100 9503 9503 9503 9503 9503 9503 9503 8700 12477 8247 8247 7884 7884 8700 8700 8700 8700 8700 14500 7942 7942 7942 7942 8300 8300 8300 1.29 1.00 1.05 1.89 1.96 1.20 1.24 1.24 1.24 1.24 1.20 1.68 1.68 1.68 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.62 1.00 1.03 1.03 1.08 1.08 1.82 1.82 1.82 1.82 1.82 1.08 1.00 1.00 1.00 1.00 1.39 1.89 1.24 83.00 89.51 57.86 83.00 88.41 41.00 41.00 41.00 41.00 41.00 41.00 20.09 20.09 20.09 89.24 84.63 84.63 84.63 84.63 84.63 84.63 84.63 89.87 89.24 15.00 15.00 83.51 83.51 89.24 89.24 89.73 89.73 89.73 83.00 84.63 84.63 84.63 84.63 89.51 83.00 85.26 18 ------- Stone Container Florence Mill Stone Container Hopewell Mill Stone Container Hopewell Mill CoGen Lyondell CoGen Lyondell CoGen Lyondell CoGen Lyondell CoGen Lyondell CoGen Lyondell CoGen Lyondell TES Filer City Station TES Filer City Station Southeast Resource Recovery Southeast Resource Recovery Southeast Resource Recovery WeirCogen Plant PE Berkeley PE Berkeley OLS Energy Chino OLS Energy Chino OLS Energy Camarillo OLS Energy Camarillo RPL Holdings RPL Holdings Onondaga Cogeneration Onondaga Cogeneration Onondaga Cogeneration Kent County Waste to Energy Facility Kent County Waste to Energy Facility Sargent Canyon Cogeneration Salinas River Cogeneration Wheelabrator Sherman Energy Facility Wheelabrator Norwalk Energy Wheelabrator Norwalk Energy Wheelabrator Frackville Energy Wheelabrator Gloucester LP Wheelabrator Gloucester LP Northampton Generating Company Oswego County Energy Recovery Oswego County Energy Recovery Potlatch Southern Wood Products 50806_B_RBF 0/G Steam 50813_B_CB1 Biomass 50813_B_RB1 Non-Fossil Waste 50815_G_GEN1 Combined Cycle 50815_G_GEN2 Combined Cycle 50815_G_GEN3 Combined Cycle 50815_G_GEN4 Combined Cycle 50815_G_GEN5 Combined Cycle 50815_G_GEN6 Combined Cycle 50815_G_GEN7 Combined Cycle 50835_B_1 Coal Steam 50835_B_2 Coal Steam 50837_B_UNIT1 Municipal Solid Waste 50837_B_UNIT2 Municipal Solid Waste 50837_B_UNIT3 Municipal Solid Waste 50848_G_GT1 Combustion Turbine 50849_G_GEN1 Combined Cycle 50849_G_GEN2 Combined Cycle 50850_G_GEN1 Combined Cycle 50850_G_GEN2 Combined Cycle 50851_G_GEN1 Combined Cycle 50851_G_GEN2 Combined Cycle 50852_G_GEN1 Combined Cycle 50852_G_GEN2 Combined Cycle 50855_G_GEN1 Combined Cycle 50855_G_GEN2 Combined Cycle 50855_G_GEN3 Combined Cycle 50860_B_BLR1 Municipal Solid Waste 50860_B_BLR2 Municipal Solid Waste 50864_G_K100 Combustion Turbine 50865_G_K100 Combustion Turbine 50874_B_19425 Biomass 50876_G_GEN1 Combined Cycle 50876_G_GEN2 Combined Cycle 50879_B_BLR1 Coal Steam 50885_B_BLR1 Municipal Solid Waste 50885_B_BLR2 Municipal Solid Waste 50888_B_BLR1 Coal Steam 50907_G_UNT1 Municipal Solid Waste 50907_G_UNT2 Municipal Solid Waste 50640 B BLR1 Biomass VACA 15.3 VAPW 20.4 VAPW 20.4 ERCT 64.0 ERCT 64.0 ERCT 64.0 ERCT 64.0 ERCT 64.0 ERCT 64.0 ERCT 64.0 MECS 30.0 MECS 30.0 CA-S 9.3 CA-S 9.3 CA-S 9.3 CA-N 3.2 CA-N 21.0 CA-N 2.0 CA-S 22.5 CA-S 6.5 CA-S 21.5 CA-S 6.8 MACE 51.0 MACE 13.9 UPNY 45.0 UPNY 25.0 UPNY 23.0 MECS 7.9 MECS 7.9 CA-N 30.0 CA-N 33.0 21.0 CA-S 19.8 CA-S 6.6 MACW 44.5 6.00 6.00 MACW 112 UPNY 1.7 UPNY 1.7 ENTG 10.0 11844 15517 13102 9500 9500 9500 9500 9500 9500 9500 11308 10331 19338 19338 19338 15981 9939 9939 8650 8650 8580 8580 10000 10000 9188 9188 9188 19338 19338 14996 15001 Not in dB 9280 9280 11503 Not in dB Not in dB 12174 19338 19338 15517 8300 8300 8300 9486 9486 9486 9486 9486 9486 9486 11308 10320 16297 16297 16297 15845 5500 5500 7132 7132 7828 7828 11652 11652 Retired Retired Retired 16297 16297 8700 8700 15716 7870 7870 9282 16297 16297 11336 8300 8300 8300 1.39 1.89 1.54 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.00 1.00 1.00 1.00 1.00 1.00 1.77 1.77 1.18 1.18 1.03 1.03 1.00 1.00 1.00 1.00 1.72 1.72 1.00 1.20 1.20 1.24 1.00 1.00 1.07 1.96 1.96 1.89 89.51 83.00 67.40 76.54 76.54 76.54 76.54 76.54 76.54 76.54 93.30 93.30 90.00 90.00 90.00 89.24 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 0.00 0.00 0.00 90.00 90.00 89.87 89.87 83.00 39.95 39.95 95.00 90.00 90.00 89.30 80.91 80.91 83.00 19 ------- Yellowstone Energy LP Yellowstone Energy LP Watsonville Power Plant Watsonville Power Plant Indiantown Cogeneration LP Pryor Power Plant Pryor Power Plant Pryor Power Plant STEC-S LLC North Shore Towers North Shore Towers North Shore Towers North Shore Towers North Shore Towers North Shore Towers Trigen Nassau Energy Trigen Nassau Energy Rhodia Dominguez Plant Rhodia Houston Plant Rhodia Houston Plant McKittrick Cogen McKittrick Cogen McKittrick Cogen North Midway Cogen North Midway Cogen North Midway Cogen Concord Cogen Concord Cogen Cymric 31X Cogen Cymric 31X Cogen Cymric 6Z Cogen Cymric 6Z Cogen Coalinga 6C Cogen Coalinga 6C Cogen Taft 26C Cogen Taft 26C Cogen Taft 26C Cogen Taft 26C Cogen Coalinga 25D Cogen Coalinga 25D Cogen Coalinga 25D Cogen 50931_B_BLR1 Coal Steam 50931_B_BLR2 Coal Steam 50968_G_GEN1 Combined Cycle 50968_G_GEN2 Combined Cycle 50976_B_AAB01 Coal Steam 50991_G_GEN1 Combustion Turbine 50991_G_GEN2 Combustion Turbine 50991_G_GN10 0/G Steam 56079_B_North Biomass 52052_G_GEN1 1C Engine 52052_G_GEN2 1C Engine 52052_G_GEN3 1C Engine 52052_G_GEN4 1C Engine 52052_G_GEN5 1C Engine 52052_G_GEN6 1C Engine 52056_G_GT1 Combined Cycle 52056_G_ST1 Combined Cycle 52064_G_GEN1 0/G Steam 52065_G_GEN1 Non-Fossil Waste 52065_G_GEN2 Non-Fossil Waste 52076_G_GEN1 Combustion Turbine 52076_G_GEN2 Combustion Turbine 52076_G_GEN3 Combustion Turbine 52078_G_GEN7 Combustion Turbine 52078_G_GEN8 Combustion Turbine 52078_G_GEN9 Combustion Turbine 52080_G_1605 1C Engine 52080_G_1606 1C Engine 52081_G_TG1 Combustion Turbine 52081_G_TG2 Combustion Turbine 52082_G_TG1 Combustion Turbine 52082_G_TG2 Combustion Turbine 52083_G_TG1 Combustion Turbine 52083_G_TG2 Combustion Turbine 52085_G_TG1 Combustion Turbine 52085_G_TG2 Combustion Turbine 52085_G_TG3 Combustion Turbine 52085_G_TG4 Combustion Turbine 52086_G_TG1 Combustion Turbine 52086_G_TG2 Combustion Turbine 52086 G TG3 Combustion Turbine NWPE 27.5 NWPE 27.5 CA-N 22.0 CA-N 6.9 FRCC 330 SPPS 17.5 SPPS 17.5 SPPS 13.0 ENTG 2.0 NYC 1.1 NYC 1.1 NYC 1.1 NYC 1.1 NYC 1.1 NYC 1.1 LILC 43.0 LILC 12.0 CA-S 3.0 ERCT 6.0 ERCT 1.5 CA-N 2.9 CA-N 2.9 CA-N 2.9 CA-N 2.9 CA-N 2.9 CA-N 2.9 CA-N 1.5 CA-N 1.5 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 14500 10331 11693 11693 9200 12503 12503 14789 15517 13298 13298 13298 13298 13298 13298 7492 7492 11332 13102 13102 15981 15981 15981 15981 15981 15981 13298 13298 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 11122 10320 7636 7636 9200 Retired Retired Retired 14500 8700 8700 8700 8700 8700 8700 6231 6231 8300 8300 8300 8700 8700 8700 8700 8700 8700 10526 10526 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 1.30 1.00 1.12 1.12 1.00 1.08 1.52 1.52 1.52 1.52 1.52 1.52 1.55 1.55 1.39 1.54 1.54 1.82 1.82 1.82 1.82 1.82 1.82 1.25 1.25 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 85.26 85.26 64.66 64.66 74.13 0.00 0.00 0.00 83.00 89.24 89.24 89.24 89.24 89.24 89.24 84.63 84.63 92.45 89.10 89.10 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 20 ------- Coalinga 25D Cogen Texas City Power Plant Texas City Power Plant Texas City Power Plant Texas City Power Plant New York Methodist Hospital New York Methodist Hospital Oxford Cogeneration Facility Oxford Cogeneration Facility Kern River Fee A Cogen Kern River Fee A Cogen Kern River Fee C Cogen Kern River Fee C Cogen Berry Placerita Cogen Berry Placerita Cogen Cymric 36W Cogen Cymric 36W Cogen Cymric 36W Cogen Cymric 36W Cogen Kern River Eastridge Cogen Kern River Eastridge Cogen C PKelcoSan Diego Plant C PKelcoSan Diego Plant C PKelcoSan Diego Plant Midway Sunset Cogen Midway Sunset Cogen Midway Sunset Cogen C R Wing Cogen Plant C R Wing Cogen Plant C R Wing Cogen Plant Yuba City Cogen Partners Delaware City Plant Delaware City Plant Delaware City Plant Delaware City Plant JRW Associates LP JRW Associates LP JRW Associates LP JRW Associates LP JRW Associates LP JRW Associates LP 52086_G_TG4 Combustion Turbine 52088_G_GEN1 Combined Cycle 52088_G_GEN2 Combined Cycle 52088_G_GEN3 Combined Cycle 52088_G_GEN4 Combined Cycle 52091_G_3A 1C Engine 52091_G_4C 1C Engine 52093_G_GEN1 Combustion Turbine 52093_G_GEN2 Combustion Turbine 52094_G_GEN1 Combustion Turbine 52094_G_GEN2 Combustion Turbine 52095_G_GEN1 Combustion Turbine 52095_G_GEN2 Combustion Turbine 52096_G_GEN1 Combustion Turbine 52096_G_GEN2 Combustion Turbine 52104_G_GEN1 Combustion Turbine 52104_G_GEN2 Combustion Turbine 52104_G_GEN3 Combustion Turbine 52104_G_GEN4 Combustion Turbine 52107_G_101A Combustion Turbine 52107_G_101B Combustion Turbine 52147_G_GEN1 Combustion Turbine 52147_G_GEN2 Combustion Turbine 52147_G_GEN3 Combustion Turbine 52169_G_A Combustion Turbine 52169_G_B Combustion Turbine 52169_G_C Combustion Turbine 52176_G_GEN1 Combined Cycle 52176_G_GEN2 Combined Cycle 52176_G_GEN3 Combined Cycle 52186_G_GEN1 Combustion Turbine 52193_G_CT1 Fossil Waste 52193_G_CT2 Fossil Waste 52193_G_G1 Fossil Waste 52193_G_G2 Fossil Waste 52198_G_GEN1 0/G Steam 52198_G_GEN2 0/G Steam 52198_G_GEN3 1C Engine 52198_G_GEN4 1C Engine 52198_G_GEN5 1C Engine 52198_G_GEN6 1C Engine CA-N 2.7 ERCT 139 ERCT 104 ERCT 104 ERCT 104 NYC 0.70 NYC 0.70 CA-N 2.4 CA-N 2.4 CA-S 3.2 CA-S 3.2 CA-S 3.6 CA-S 3.2 CA-S 19.6 CA-S 19.6 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 2.7 CA-N 21.0 CA-N 21.0 CA-S 8.0 CA-S 9.3 CA-S 9.3 CA-N 73.0 CA-N 73.0 CA-N 73.0 ERCT 76.0 ERCT 76.0 ERCT 75.0 CA-N 48.7 MACE 101 MACE 92.0 MACE 29.5 MACE 29.5 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 15981 10299 10299 10299 10299 12870 12870 15981 15981 15981 15981 15981 15981 12503 12503 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 15981 8982 8982 8982 15256 9107 9107 9107 9107 11425 11425 11600 11600 11600 11600 8700 6319 6319 6319 6319 8700 8700 15845 15845 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 8700 7718 7718 7718 8700 9107 9107 9107 9107 11177 11177 8700 8700 8700 8700 1.82 1.49 1.49 1.49 1.49 1.48 1.48 1.00 1.00 1.82 1.82 1.82 1.82 1.43 1.43 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.82 1.11 1.11 1.11 1.75 1.00 1.00 1.00 1.00 1.00 1.00 1.29 1.29 1.29 1.29 89.24 42.30 42.30 42.30 42.30 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.87 89.87 89.24 89.24 89.24 89.24 89.87 89.87 89.24 89.24 89.24 90.81 90.81 90.81 31.59 31.59 31.59 89.87 90.00 90.00 90.00 90.00 92.45 92.45 89.24 89.24 89.24 89.24 21 ------- JRW Associates LP JRW Associates LP Ridgewood/Byron Power Partners Ridgewood/Byron Power Partners Ridgewood/Byron Power Partners Ridgewood/Byron Power Partners Ridgewood/Byron Power Partners Sunnyside Cogen Partners Sunnyside Cogen Partners Sunnyside Cogen Partners Sunnyside Cogen Partners Sunnyside Cogen Partners Pittsburg Power Plant Pittsburg Power Plant Pittsburg Power Plant Westmoreland Roanoke Valley I Lockport Energy Associates LP Lockport Energy Associates LP Lockport Energy Associates LP Lockport Energy Associates LP Wythe Park Power Petersburg Plant Wythe Park Power 3 Richmond Plant Pawtucket Power Associates Pawtucket Power Associates IndeckOlean Energy Center IndeckOlean Energy Center Cogentrix of Richmond Cogentrix of Richmond Cogentrix of Richmond Cogentrix of Richmond Cogentrix of Richmond Cogentrix of Richmond Cogentrix of Richmond Cogentrix of Richmond Kennedy International Airport Cogen Kennedy International Airport Cogen Kennedy International Airport Cogen Fortistar North Tonawanda Fortistar North Tonawanda Fulton Cogeneration Associates Stony Brook Cogen Plant 52198_G_GEN7 1C Engine 52198_G_GEN8 1C Engine 52199_G_GEN1 1C Engine 52199_G_GEN2 1C Engine 52199_G_GEN3 1C Engine 52199_G_GEN4 1C Engine 52199_G_GEN5 1C Engine 52201_G_GEN1 1C Engine 52201_G_GEN2 1C Engine 52201_G_GEN3 1C Engine 52201_G_GEN4 1C Engine 52201_G_GEN5 1C Engine 54001_G_GEN1 Combustion Turbine 54001_G_GEN2 Combustion Turbine 54001_G_GEN3 Combustion Turbine 54035_B_BLR1 Coal Steam 54041_G_GEN1 Combined Cycle 54041_G_GEN2 Combined Cycle 54041_G_GEN3 Combined Cycle 54041_G_GEN4 Combined Cycle 54045_G_1 Fossil Waste 54047_G_EXIS 1C Engine 54056_G_GEN1 Combined Cycle 54056_G_GEN2 Combined Cycle 54076_G_GEN1 Combined Cycle 54076_G_GEN2 Combined Cycle 54081_B_1A Coal Steam 54081_B_1B Coal Steam 54081_B_2A Coal Steam 54081_B_2B Coal Steam 54081_B_3A Coal Steam 54081_B_3B Coal Steam 54081_B_4A Coal Steam 54081_B_4B Coal Steam 54114_G_GEN1 Combined Cycle 54114_G_GEN2 Combined Cycle 54114_G_GEN3 Combined Cycle 54131_G_GEN1 Combined Cycle 54131_G_GEN2 Combined Cycle 54138_G_GTG Combustion Turbine 54149 G GEN1 Combustion Turbine CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 16.5 CA-N 22.0 CA-N 22.0 VAPW 165 UPNY 45.0 UPNY 45.0 UPNY 45.0 UPNY 75.2 VAPW 3.0 VAPW 3.0 NENG 36.0 NENG 27.0 UPNY 31.9 UPNY 44.6 VAPW 26.3 VAPW 26.3 VAPW 26.3 VAPW 26.3 VAPW 21.3 VAPW 21.3 VAPW 21.3 VAPW 21.3 NYC 49.0 NYC 50.3 NYC 27.0 UPNY 40.4 UPNY 16.3 UPNY 42.0 LILC 44.5 11600 11600 13776 13776 13776 13776 13776 11303 11303 11303 11303 11303 9939 9939 9939 10370 9091 9091 9091 9091 12320 12283 8950 8950 8740 8740 11303 10331 11303 10331 11300 10331 11300 10331 10315 10315 10315 7800 7800 12503 12082 8700 8700 12672 12672 12672 12672 12672 11303 11303 11303 11303 11303 8700 8700 8700 9109 7428 7428 7428 7428 9316 9000 8908 8908 8626 8626 9258 9258 9258 9258 9258 9258 9258 9258 8033 8033 8033 7815 7815 12477 8700 1.29 1.29 1.09 1.09 1.09 1.09 1.09 1.00 1.00 1.00 1.00 1.00 1.14 1.14 1.14 1.14 1.16 1.16 1.16 1.16 1.32 1.36 1.00 1.00 1.00 1.00 1.22 1.11 1.22 1.11 1.22 1.11 1.22 1.11 1.28 1.28 1.28 1.15 1.15 1.00 1.39 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.24 27.74 27.74 27.74 90.70 47.49 47.49 47.49 47.49 6.17 89.24 84.63 84.63 84.63 84.63 71.07 71.07 71.07 71.07 71.07 71.07 71.07 71.07 49.51 49.51 49.51 15.00 15.00 89.87 89.87 22 ------- Franklin Heating Station Franklin Heating Station Franklin Heating Station Franklin Heating Station Franklin Heating Station Franklin Heating Station Franklin Heating Station Franklin Heating Station Port of Stockton District Energy Fac Port of Stockton District Energy Fac March Point Cogeneration March Point Cogeneration March Point Cogeneration March Point Cogeneration Saguaro Power Saguaro Power Saguaro Power Birchwood Power Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Goodyear Beaumont Chemical Plant Bucknell University Bucknell University Nevada Cogen Associates 2 Black Mountain Nevada Cogen Associates 2 Black Mountain Nevada Cogen Associates 2 Black Mountain Nevada Cogen Associates 2 Black Mountain Nevada Cogen Assocttl GarnetVly Nevada Cogen Assocttl GarnetVly Nevada Cogen Assocttl GarnetVly Nevada Cogen Assocttl GarnetVly Orange Cogeneration Facility 54224_B_GEN6 54224_B_SG1 54224_B_SG2 54224_B_SG3 54224_B_SG4 54224_G_EG1 54224_G_EG2 54224_G_EG3 54238_B_N64514 54238_B_N64516 54268_G_GTG1 54268_G_GTG2 54268_G_GTG3 54268_G_STG1 54271_G_CTG1 54271_G_CTG2 54271_G_STG 54304_B_1A 54321_B_3B101 54321_B_3B102 54321_B_3B103 54321_B_3B104 54321_B_3B105 54321_B_3B106 54321_B_3B107 54321_B_3B108 54321_G_2N80 54321_G_N802 54321_G_N803 54321_G_N804 54333_G_G001 54333_G_G502 54349_G_GTA 54349_G_GTB 54349_G_GTC 54349_G_STM 54350_G_GTA 54350_G_GTB 54350_G_GTC 54350_G_STM 54365_G_APC1 Coal Steam 0/G Steam 0/G Steam 0/G Steam 0/G Steam 1C Engine 1C Engine 1C Engine Coal Steam Coal Steam Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam 0/G Steam 0/G Steam 0/G Steam 0/G Steam 0/G Steam 0/G Steam 0/G Steam 0/G Steam Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle MRO 2.8 MRO 1 MRO 1 MRO 4.1 MRO 4.1 MRO 2.0 MRO 2.0 MRO 2.0 CA-N 22.0 CA-N 22.0 PNW 39.6 PNW 40.0 PNW 40.6 PNW 26.0 SNV 35.0 SNV 35.0 SNV 22.0 VAPW 239 ENTG 1.6 ENTG 1.6 ENTG 1.6 ENTG 1.6 ENTG 1.6 ENTG 1.6 ENTG 1.6 ENTG 1.6 ENTG 4.0 ENTG 4.0 ENTG 4.0 ENTG 4.0 MACW 4.3 MACW 0.50 SNV 21.7 SNV 21.7 SNV 21.7 SNV 19.9 SNV 21.7 SNV 21.7 SNV 21.7 SNV 19.9 FRCC 46.4 10331 14789 14789 14789 14789 12334 12334 12334 11465 10331 11500 11500 11500 11500 9200 9200 9200 10067 11425 11425 11425 11425 11425 11425 11425 11425 12503 12503 12503 12503 7933 7933 7132 7132 7132 7132 10182 10182 10182 10182 8999 10320 8300 8300 8300 8300 12062 12062 12062 11465 10320 6096 6096 6096 6096 9200 9200 9200 9669 8300 8300 8300 8300 8300 8300 8300 8300 8700 8700 8700 8700 7942 7942 6600 6600 6600 6600 7316 7316 7316 7316 7380 1.00 1.72 1.72 1.72 1.72 1.00 1.00 1.00 1.00 1.00 1.82 1.82 1.82 1.82 1.00 1.00 1.00 1.04 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.43 1.43 1.43 1.43 1.00 1.00 1.36 1.36 1.36 1.36 1.22 1.22 1.22 1.22 1.16 85.26 89.51 89.51 89.51 89.51 89.24 89.24 89.24 69.73 69.73 58.62 58.62 58.62 58.62 84.63 84.63 84.63 65.54 92.41 92.41 92.41 92.41 92.41 92.41 92.41 92.41 89.24 89.24 89.24 89.24 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 84.63 40.15 23 ------- Orange Cogeneration Facility Orange Cogeneration Facility Oildale Cogen University of Colorado University of Colorado University of Colorado Southbridge Energy Center LLC Southbridge Energy Center LLC Southbridge Energy Center LLC Southbridge Energy Center LLC Southbridge Energy Center LLC Capitol Heat and Power Capitol Heat and Power DAI Oildale DAI Oildale Lake Cogen Ltd Lake Cogen Ltd Lake Cogen Ltd Pasco Cogen Ltd Pasco Cogen Ltd Pasco Cogen Ltd Project Orange Associates LP Project Orange Associates LP Mulberry Cogeneration Facility Mulberry Cogeneration Facility Alabama Pine Pulp Alabama Pine Pulp Rincon Facility Welport Lease Project Dome Project Dome Project Orlando Cogen LP Sumas Power Plant Sumas Power Plant Oroville Cogeneration LP Oroville Cogeneration LP Oroville Cogeneration LP Oroville Cogeneration LP Oroville Cogeneration LP Oroville Cogeneration LP Oroville Cogeneration LP 54365_G_APC2 Combined Cycle 54365_G_APC3 Combined Cycle 54371_G_ODC1 Combustion Turbine 54372_G_GT1 Combined Cycle 54372_G_GT2 Combined Cycle 54372_G_ST1 Combined Cycle 54373_G_ENG1 1C Engine 54373_G_ENG2 1C Engine 54373_G_ENG3 1C Engine 54373_G_ENG4 1C Engine 54373_G_ENG5 1C Engine 54406_G_1 Coal Steam 54406_G_2 Coal Steam 54410_G_CTG Combined Cycle 54410_G_STG Combined Cycle 54423_G_GT1 Combined Cycle 54423_G_GT2 Combined Cycle 54423_G_ST1 Combined Cycle 54424_G_GT1 Combined Cycle 54424_G_GT2 Combined Cycle 54424_G_ST1 Combined Cycle 54425_G_GT1 Combustion Turbine 54425_G_GT2 Combustion Turbine 54426_G_GT1 Combined Cycle 54426_G_ST1 Combined Cycle 54429_B_PB2 Biomass 54429_B_RB2 Non-Fossil Waste 54445_G_GEN1 Combustion Turbine 54447_G_TI Combustion Turbine 54449_G_T1 Combustion Turbine 54449_G_T2 Combustion Turbine 54466_G_GEN1 Combined Cycle 54476_G_GEN1 Combined Cycle 54476_G_GEN2 Combined Cycle 54477_G_GEN1 1C Engine 54477_G_GEN2 1C Engine 54477_G_GEN3 1C Engine 54477_G_GEN4 1C Engine 54477_G_GEN5 1C Engine 54477_G_GEN6 1C Engine 54477_G_GEN7 1C Engine FRCC 46.4 FRCC 24.6 CA-N 39.0 RMPA 15.0 RMPA 15.0 RMPA 1 NENG 1.3 NENG 1.3 NENG 1.3 NENG 1.3 NENG 1.3 WUMS 0.90 WUMS 1 CA-N 22.6 CA-N 7.3 FRCC 41.5 FRCC 41.5 FRCC 27.0 FRCC 48.8 FRCC 48.8 FRCC 31.2 UPNY 48.0 UPNY 48.0 FRCC 76.0 FRCC 37.0 SOU 32.1 SOU 32.1 CA-S 1.7 CA-N 4.5 CA-N 3.3 CA-N 3.2 FRCC 120 PNW 87.8 PNW 37.7 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 CA-N 1.1 8999 8999 16463 7933 7933 7933 11600 11600 11600 11600 11600 10331 10331 7933 7933 7550 7550 7550 7701 7701 7701 12503 12503 8520 8520 15517 13102 12503 12503 15981 15981 9960 8120 8120 11600 11600 11600 11600 11600 11600 11600 7380 7380 8700 7164 7164 7164 9106 9106 9106 9106 9106 8300 8300 7942 7942 7447 7447 7447 7784 7784 7784 8700 8700 8104 8104 8300 8300 Retired 8882 8700 8700 7882 7262 7262 11185 11185 11185 11185 11185 11185 11185 1.16 1.16 1.89 1.11 1.11 1.11 1.23 1.23 1.23 1.23 1.23 1.24 1.24 1.00 1.00 1.14 1.14 1.14 1.06 1.06 1.06 1.43 1.43 1.02 1.02 1.89 1.54 1.40 1.82 1.82 1.26 1.14 1.14 1.00 1.00 1.00 1.00 1.00 1.00 1.00 40.15 40.15 89.87 15.00 15.00 15.00 89.24 89.24 89.24 89.24 89.24 85.26 85.26 84.63 84.63 49.56 49.56 49.56 43.15 43.15 43.15 89.87 89.87 41.67 41.67 83.00 55.17 0.00 89.24 89.24 89.24 84.63 20.82 20.82 89.24 89.24 89.24 89.24 89.24 89.24 89.24 24 ------- STEC-S LLC Formosa Plastics Formosa Plastics Formosa Plastics Formosa Plastics Formosa Plastics Lyonsdale Biomass LLC Tenaska Ferndale Cogeneration Station Tenaska Ferndale Cogeneration Station Tenaska Ferndale Cogeneration Station Entenmanns Energy Center Entenmanns Energy Center Entenmanns Energy Center Entenmanns Energy Center Sithe Independence Station Sithe Independence Station Sithe Independence Station Sithe Independence Station Sithe Independence Station Sithe Independence Station ExxonMobil Mobile Bay Onshore ExxonMobil Mobile Bay Onshore ExxonMobil Mobile Bay Onshore ExxonMobil Mobile Bay Onshore Jefferson Smurfit Santa Clara Mill Jefferson Smurfit Santa Clara Mill North East Cogeneration Plant North East Cogeneration Plant North East Cogeneration Plant Saranac Facility Saranac Facility Saranac Facility Glenns Ferry Cogen Facility Rupert Cogen Project Batavia Power Plant Batavia Power Plant Mt Poso Cogeneration Okeelanta Cogeneration Okeelanta Cogeneration Okeelanta Cogeneration Okeelanta Cogeneration 56079_B_South Biomass ENTG 2.0 54518_G_GT1 Combined Cycle ENTG 33.0 54518_G_GT2 Combined Cycle ENTG 33.0 54518_G_GT3 Combined Cycle ENTG 33.0 54518_G_ST1 Combined Cycle ENTG 8.0 54518_G_ST2 Combined Cycle ENTG 8.0 54526_B_00001 Biomass UPNY 19.0 54537_G_CT1A Combined Cycle PNW 88.0 54537_G_CT1B Combined Cycle PNW 88.0 54537_G_ST1 Combined Cycle PNW 95.0 54541_G_1 1C Engine LILC 1.3 54541_G_2 1C Engine LILC 1.3 54541_G_3 1C Engine LILC 1.3 54541_G_4 1C Engine LILC 1.3 54547_G_1 Combined Cycle UPNY 144 54547_G_2 Combined Cycle UPNY 144 54547_G_3 Combined Cycle UPNY 144 54547_G_4 Combined Cycle UPNY 144 54547_G_5 Combined Cycle UPNY 204 54547_G_6 Combined Cycle UPNY 204 54550_G_901 Combined Cycle SOU 0.90 54550_G_901A Combined Cycle SOU 3.4 54550_G_901B Combined Cycle SOU 3.4 54550_G_901C Combined Cycle SOU 3.4 54561_G_GT-G Combined Cycle CA-N 23.0 54561_G_ST-G Combined Cycle CA-N 3.0 54571_G_GEN1 Combined Cycle MACW 36.5 54571_G_GEN2 Combined Cycle MACW 36.5 54571_G_GEN3 Combined Cycle MACW 8.0 54574_G_GEN1 Combined Cycle UPNY 78.0 54574_G_GEN2 Combined Cycle UPNY 77.0 54574_G_GEN3 Combined Cycle UPNY 85.0 54578_G_1001 Combined Cycle PNW 10.4 54579_G_1002 Combined Cycle NWPE 10.4 54593_G_GEN1 Combined Cycle UPNY 38.2 54593_G_GEN2 Combined Cycle UPNY 17.5 54626_B_BL01 Coal Steam CA-N 52.0 54627_B_A Biomass FRCC 25.0 54627_B_B Biomass FRCC 25.0 54627_B_C Biomass FRCC 25.0 54627_G_GEN2 Biomass FRCC 74.9 15517 8648 8648 8648 8648 8648 15517 11260 11260 11260 12703 12703 12703 12784 7418 7418 7418 7418 7418 7418 7933 7933 7933 7933 9780 9780 9163 9163 9163 8616 8616 8616 9800 9800 8771 8771 11384 15517 15517 15517 15517 14500 Retired 8582 8582 8582 8582 13201 7576 7576 7576 8700 8700 8700 8700 6984 6984 6984 6984 6984 6984 7942 7942 7942 7942 5764 5764 6747 6747 6747 7399 7399 7399 8470 6324 7440 7440 11299 8904 8904 8904 8904 1.08 1.00 1.00 1.00 1.00 1.19 1.10 1.10 1.10 1.46 1.46 1.46 1.47 1.12 1.12 1.12 1.12 1.12 1.12 1.00 1.00 1.00 1.00 1.72 1.72 1.36 1.36 1.36 1.19 1.19 1.19 1.00 1.27 1.12 1.12 1.19 1.77 1.77 1.77 1.53 83.00 0.00 84.63 84.63 84.63 84.63 83.00 36.93 36.93 36.93 89.24 89.24 89.24 89.24 33.74 33.74 33.74 33.74 33.74 33.74 84.63 84.63 84.63 84.63 84.63 84.63 15.00 15.00 15.00 84.63 84.63 84.63 84.68 71.01 15.00 15.00 83.00 83.00 83.00 83.00 83.00 25 ------- St Nicholas Cogen Project JCO Oxides Olefins Plant JCO Oxides Olefins Plant Lakewood Cogen LP Lakewood Cogen LP Lakewood Cogen LP Auburndale Power Partners Auburndale Power Partners Oyster Creek Unit VIII Oyster Creek Unit VIII Oyster Creek Unit VIII Oyster Creek Unit VIII CM Carbon LLC CM Carbon LLC York Cogen Facility York Cogen Facility York Cogen Facility York Cogen Facility York Cogen Facility York Cogen Facility Yuma Cogeneration Associates Yuma Cogeneration Associates Hunterdon Cogen Facility Montclair Cogen Facility Port Neches Plant Goal Line LP Goal Line LP Westmoreland Roanoke Valley II Hermiston Generating Plant Hermiston Generating Plant Hermiston Generating Plant Hermiston Generating Plant Boydton Plank Road Cogen Plant Live Oak Cogen University of Iowa Main Power Plant University of Iowa Main Power Plant University of Iowa Main Power Plant University of Iowa Main Power Plant University of Iowa Main Power Plant Grays Ferry Cogeneration Grays Ferry Cogeneration 54634_B_1 54637_G_GCG1 54637_G_GCG2 54640_G_GEN1 54640_G_GEN2 54640_G_NA 54658_G_CT 54658_G_ST 54676_G_G81 54676_G_G82 54676_G_G83 54676_G_G84 54677_B_HRB 54677_G_TG-2 54693_G_GT#1 54693_G_GT#2 54693_G_GT#5 54693_G_GT#6 54693_G_ST#1 54693_G_ST#2 54694_G_GEN1 54694_G_GEN2 54707_G_1 54708_G_1 54748_G_G1 54749_G_CTG 54749_G_STG 54755_B_BLR2 54761_G_GEN1 54761_G_GEN2 54761_G_GEN3 54761_G_GEN4 54766_G_GEN1 54768_G_GEN1 54775_B_BLR10 54775_B_BLR11 54775_B_BLR7 54775_B_BLR8 54775_B_BLR9 54785_G_GEN1 54785_G_GEN2 Coal Steam Combustion Turbine Combustion Turbine Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Coal Steam Coal Steam Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combustion Turbine Combustion Turbine Combustion Turbine Combined Cycle Combined Cycle Coal Steam Combined Cycle Combined Cycle Combined Cycle Combined Cycle Fossil Waste Combustion Turbine Coal Steam Coal Steam 0/G Steam 0/G Steam 0/G Steam Combined Cycle Combined Cycle MACW 87.9 ENTG 30.5 ENTG 30.5 MACE 78.0 MACE 78.0 MACE 83.0 FRCC 105 FRCC 49.6 ERCT 73.0 ERCT 73.0 ERCT 73.0 ERCT 160 ENTG 23.0 ENTG 23.0 MACW 6.9 MACW 6.6 MACW 6.9 MACW 6.1 MACW 7.2 MACW 6.9 AZNM 35.1 AZNM 17.1 MACE 4.1 MACE 3.7 ENTG 32.0 CA-S 40.0 CA-S 9.4 VAPW 44.0 PNW 80.0 PNW 152 PNW 80.0 PNW 152 VAPW 3.0 CA-N 46.0 MRO 4.2 MRO 4.2 MRO 4.2 MRO 4.2 MRO 4.2 MACE 50.0 MACE 100 10931 12503 12503 8129 8129 8129 8900 8900 10000 10000 10000 10000 10331 10331 9830 9830 9830 9830 9830 9830 8971 8971 12503 12503 12503 9182 9182 11346 11182 11182 11182 11182 11036 15065 12508 12508 14789 14789 14789 9033 9033 10931 8700 8700 8129 8129 8129 8302 8302 9662 9662 9662 9662 10320 10320 9830 9830 9830 9830 9830 9830 7604 7604 8700 8700 8700 7724 7724 9515 7322 7322 7322 7322 11036 8700 8300 8300 8300 8300 8300 5522 5522 1.00 1.43 1.43 1.00 1.00 1.00 1.06 1.06 1.02 1.02 1.02 1.02 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.14 1.14 1.43 1.43 1.43 1.02 1.02 1.19 1.00 1.00 1.00 1.00 1.00 1.73 1.49 1.49 1.72 1.72 1.72 1.64 1.64 95.00 89.87 89.87 84.63 84.63 84.63 48.82 48.82 69.15 69.15 69.15 69.15 85.26 85.26 84.63 84.63 84.63 84.63 84.63 84.63 80.86 80.86 89.24 89.24 89.87 74.62 74.62 91.60 84.68 84.68 84.68 84.68 90.00 89.87 85.26 85.26 92.41 92.41 92.41 36.96 36.96 26 ------- Plymouth State College Cogeneration Milagro Cogeneration Plant Milagro Cogeneration Plant Milagro Cogeneration Plant Milagro Cogeneration Plant Johnson County Johnson County Panda Brandywine LP Panda Brandywine LP Panda Brandywine LP Outagamie County Co-Generation Facility Gordonsville Energy LP Gordonsville Energy LP Gordonsville Energy LP Gordonsville Energy LP Cox Waste to Energy Cox Waste to Energy Brooklyn Navy Yard Cogeneration Brooklyn Navy Yard Cogeneration Brooklyn Navy Yard Cogeneration Brooklyn Navy Yard Cogeneration Michigan Power LP Michigan Power LP Sauder Power Plant Sauder Power Plant Fellsway Development LLC Fellsway Development LLC Fellsway Development LLC Fellsway Development LLC SPSA Waste To Energy Power Plant SPSA Waste To Energy Power Plant SPSA Waste To Energy Power Plant SPSA Waste To Energy Power Plant LSP-Cottage Grove LP LSP-Cottage Grove LP LSP-WhitewaterLP LSP-WhitewaterLP Sweeny Cogen Facility Sweeny Cogen Facility Sweeny Cogen Facility Sweeny Cogen Facility 54803_G_A 1C Engine 54814_G_GENA Combustion Turbine 54814_G_GENB Combustion Turbine 54814_G_G01A Combustion Turbine 54814_G_G01B Combustion Turbine 54817_G_GT-1 Combined Cycle 54817_G_ST-1 Fossil Waste 54832_G_1 Combined Cycle 54832_G_2 Combined Cycle 54832_G_3 Combined Cycle 54842_G_GEN1 Landfill Gas 54844_G_GOR1 Combined Cycle 54844_G_GOR2 Combined Cycle 54844_G_GOR3 Combined Cycle 54844_G_GOR4 Combined Cycle 54850_G_01 Biomass 54850_G_02 Biomass 54914_G_01 Combined Cycle 54914_G_02 Combined Cycle 54914_G_03 Combined Cycle 54914_G_04 Combined Cycle 54915_G_G001 Combined Cycle 54915_G_G101 Combined Cycle 54974_G_UNT1 Biomass 54974_G_UNT2 Biomass 54992_G_CAT1 1C Engine 54992_G_CAT2 1C Engine 54992_G_GT Combustion Turbine 54992_G_ST Coal Steam 54998_B_12300 Municipal Solid Waste 54998_B_12400 Municipal Solid Waste 54998_B_12500 Municipal Solid Waste 54998_B_12600 Municipal Solid Waste 55010_G_CTG1 Combined Cycle 55010_G_STG1 Combined Cycle 55011_G_CTG1 Combined Cycle 55011_G_STG1 Combined Cycle 55015_G_1 Combustion Turbine 55015_G_2 Combustion Turbine 55015_G_3 Combustion Turbine 55015 G 4 Combustion Turbine NENG 1.2 AZNM 30.4 AZNM 30.4 AZNM 30.4 AZNM 30.4 ERCT 163 ERCT 104 MACS 78.6 MACS 78.6 MACS 72.8 WUMS 0.80 VAPW 71.4 VAPW 71.4 VAPW 40.6 VAPW 40.6 TVAK 3.0 TVAK 0.30 NYC 85.0 NYC 85.0 NYC 30.0 NYC 30.0 MECS 58.0 MECS 70.0 RFCO 3.6 RFCO 3.6 NENG 0.70 NENG 0.80 NENG 0.60 NENG 0.20 VAPW 11.6 VAPW 11.6 VAPW 11.6 VAPW 11.6 MRO 154 MRO 97.0 WUMS 156 WUMS 97.0 ERCT 115 ERCT 115 ERCT 115 ERCT 115 12334 16541 16541 16521 16541 7060 7859 8330 8330 8330 13682 8593 8593 8593 8593 15517 15517 7477 7477 7477 7477 10880 10880 18060 18060 13123 13123 15981 13754 19338 19338 19338 19338 7745 7745 7739 7739 11707 11707 11707 11707 9448 8700 8700 8700 8700 7859 7859 7612 7612 7612 9273 8706 8706 8706 8706 8300 8300 6759 6759 6759 6759 9334 9334 18060 18060 9704 9704 9704 10320 12524 12524 12524 12524 7278 7278 6654 6654 11707 11707 11707 11707 1.28 1.90 1.90 1.90 1.90 1.00 1.00 1.37 1.37 1.37 1.48 1.00 1.00 1.00 1.00 1.89 1.89 1.34 1.34 1.34 1.34 1.01 1.01 1.00 1.00 1.34 1.34 1.63 1.00 1.30 1.30 1.30 1.30 1.08 1.08 1.20 1.20 1.00 1.00 1.00 1.00 89.24 89.87 89.87 89.87 89.87 84.63 90.00 32.08 32.08 32.08 67.72 84.63 84.63 84.63 84.63 83.00 83.00 84.63 84.63 84.63 84.63 72.92 72.92 83.00 83.00 89.24 89.24 89.24 85.26 67.40 67.40 67.40 67.40 38.81 38.81 47.91 47.91 90.81 90.81 90.81 90.81 27 ------- J & L Electric J & L Electric Mid-Georgia Cogeneration Facility Mid-Georgia Cogeneration Facility Mid-Georgia Cogeneration Facility Cherokee County Cogen Cherokee County Cogen Pasadena Cogeneration Pasadena Cogeneration Pasadena Cogeneration Pasadena Cogeneration Pasadena Cogeneration Tamarack Energy Partnership Georgia Gulf Plaquemine Georgia Gulf Plaquemine Georgia Gulf Plaquemine Black Hawk Station Black Hawk Station Pine Bluff Energy Center Pine Bluff Energy Center Crockett Cogen Project Gregory Power Facility Gregory Power Facility Gregory Power Facility Dearborn Industrial Generation Dearborn Industrial Generation Dearborn Industrial Generation Dearborn Industrial Generation Taft Cogeneration Facility Taft Cogeneration Facility Taft Cogeneration Facility Taft Cogeneration Facility Plummer Forest Products Miramar Landfill Metro Biosolids Center Miramar Landfill Metro Biosolids Center Miramar Landfill Metro Biosolids Center Miramar Landfill Metro Biosolids Center Portside Energy Portside Energy Klamath Cogeneration Plant Klamath Cogeneration Plant 55034_G_0001 Biomass 55034_G_0002 Biomass 55040_G_CT1 Combined Cycle 55040_G_CT2 Combined Cycle 55040_G_ST1 Combined Cycle 55043_G_GT1 Combined Cycle 55043_G_ST1 Combined Cycle 55047_G_CTG1 Combined Cycle 55047_G_CTG2 Combined Cycle 55047_G_CTG3 Combined Cycle 55047_G_STG1 Combined Cycle 55047_G_STG2 Combined Cycle 50099_G_GEN1 Biomass 55051_G_X773 Combustion Turbine 55051_G_X774 Combustion Turbine 55051_G_X775 Combustion Turbine 55064_G_UNT1 Combustion Turbine 55064_G_UNT2 Combustion Turbine 55075_G_CT01 Combined Cycle 55075_G_ST01 Combined Cycle 55084_G_GE1 Combined Cycle 55086_G_GT1A Combined Cycle 55086_G_GT1B Combined Cycle 55086_G_STG Combined Cycle 55088_G_GT 1 Combined Cycle 55088_G_GT2 Combined Cycle 55088_G_GTP1 Combined Cycle 55088_G_ST1 Combined Cycle 55089_G_CT1 Combined Cycle 55089_G_CT2 Combined Cycle 55089_G_CT3 Combined Cycle 55089_G_ST1 Combined Cycle 55090_G_GEN1 Biomass 55094_G_UNT1 Landfill Gas 55094_G_UNT2 Landfill Gas 55094_G_UNT3 Landfill Gas 55094_G_UNT4 Landfill Gas 55096_G_GT Combined Cycle 55096_G_ST Combined Cycle 55103_G_CT1 Combined Cycle 55103_G_CT2 Combined Cycle NENG 0.35 NENG 0.50 SOU 107 SOU 107 SOU 103 VACA 80.0 VACA 35.0 ERCT 155 ERCT 165 ERCT 165 ERCT 50.0 ERCT 165 PNW 5.8 ENTG 80.0 ENTG 80.0 ENTG 80.0 SPPS 111 SPPS 111 ENTG 150 ENTG 48.0 CA-N 247 ERCT 156 ERCT 156 ERCT 100 MECS 150 MECS 150 MECS 150 MECS 250 ENTG 155 ENTG 155 ENTG 155 ENTG 325 PNW 5.8 CA-S 1.6 CA-S 1.6 CA-S 1.6 CA-S 1.6 RFCO 34.0 RFCO 10.0 PNW 150 PNW 150 15517 15517 7950 7950 7950 8000 8000 7200 7200 7200 7200 7200 15943 12435 12435 12435 13188 13200 7274 7274 7500 7274 7274 7274 7274 7274 7274 7274 7933 7933 7933 7933 16912 11855 11855 11855 11855 6920 6920 6920 6920 15716 15716 6813 6813 6813 8663 8663 6723 6723 6723 6723 6723 14500 8700 8700 8700 8800 8800 5500 5500 5919 5500 5500 5500 5500 5500 5500 5500 7316 7316 7316 7316 10049 12899 12899 12899 12899 6920 6920 6794 6794 1.00 1.00 1.14 1.14 1.14 1.01 1.01 1.14 1.14 1.14 1.14 1.14 1.10 1.42 1.42 1.42 1.50 1.50 1.50 1.50 1.80 1.72 1.72 1.72 1.46 1.46 1.46 1.46 1.04 1.04 1.04 1.04 1.68 1.06 1.06 1.06 1.06 1.00 1.00 1.10 1.10 83.00 83.00 15.00 15.00 15.00 22.38 22.38 59.17 59.17 59.17 59.17 59.17 83.00 90.81 90.81 90.81 90.81 90.81 77.47 77.47 41.22 80.75 80.75 80.75 24.62 24.62 24.62 24.62 58.54 58.54 58.54 58.54 83.00 75.52 75.52 75.52 75.52 84.63 84.63 73.73 73.73 28 ------- Klamath Cogeneration Plant Sabine Cogen Sabine Cogen Sabine Cogen RS Cogen RS Cogen RS Cogen SRW Cogen LP SRW Cogen LP SRW Cogen LP NAFTA Region Olefins Complex Cogen Fac NAFTA Region Olefins Complex Cogen Fac Eastman Cogeneration Facility Eastman Cogeneration Facility Eastman Cogeneration Facility Channelview Channelview Channelview Channelview Channelview Corpus Christi Energy Center Corpus Christi Energy Center Corpus Christi Energy Center Aera South Belridge Cogen Facility Aera South Belridge Cogen Facility Aera South Belridge Cogen Facility Aera South Belridge Cogen Facility Los Medanos Energy Center Los Medanos Energy Center Los Medanos Energy Center Ina Road Water Pollution Control Fac Ina Road Water Pollution Control Fac Ina Road Water Pollution Control Fac Ina Road Water Pollution Control Fac Ina Road Water Pollution Control Fac Ina Road Water Pollution Control Fac Ina Road Water Pollution Control Fac Whiting Clean Energy Whiting Clean Energy Whiting Clean Energy Decatur Energy Center 55103_G_ST1 Combined Cycle 55104_G_SAB1 Combined Cycle 55104_G_SAB2 Combined Cycle 55104_G_STG Combined Cycle 55117_G_RS-4 Combined Cycle 55117_G_RS-5 Combined Cycle 55117_G_RS-6 Combined Cycle 55120_G_GT1A Combined Cycle 55120_G_GT1B Combined Cycle 55120_G_ST1A Combined Cycle 55122_G_UN1 Combustion Turbine 55122_G_UN2 Combustion Turbine 55176_G_GEN1 Combined Cycle 55176_G_GEN2 Combined Cycle 55176_G_GEN3 Combined Cycle 55187_G_CHV1 Combined Cycle 55187_G_CHV2 Combined Cycle 55187_G_CHV3 Combined Cycle 55187_G_CHV4 Combined Cycle 55187_G_ST1 Combined Cycle 55206_G_CT1 Combined Cycle 55206_G_CT2 Combined Cycle 55206_G_ST1 Combined Cycle 55216_G_STG1 Combined Cycle 55216_G_UNT1 Combined Cycle 55216_G_UNT2 Combined Cycle 55216_G_UNT3 Combined Cycle 55217_G_CTG1 Combined Cycle 55217_G_CTG2 Combined Cycle 55217_G_STG3 Combined Cycle 55257_G_1 1C Engine 55257_G_2 1C Engine 55257_G_3 1C Engine 55257_G_4 1C Engine 55257_G_5 1C Engine 55257_G_6 1C Engine 55257_G_7 1C Engine 55259_G_CT1 Combined Cycle 55259_G_CT2 Combined Cycle 55259_G_ST1 Combined Cycle 55292_G_CTG1 Combined Cycle PNW 170 ENTG 37.0 ENTG 37.0 ENTG 27.0 ENTG 60.2 ENTG 168 ENTG 168 ENTG 160 ENTG 160 ENTG 100 ENTG 35.0 ENTG 35.0 SPPS 146 SPPS 146 SPPS 110 ERCT 161 ERCT 161 ERCT 161 ERCT 161 ERCT 135 162 162 159 COMD 62.0 COMD 38.0 COMD 38.0 COMD 38.0 CA-N 165 CA-N 165 CA-N 237 AZNM 0.59 AZNM 0.59 AZNM 0.59 AZNM 0.59 AZNM 0.59 AZNM 0.59 AZNM 0.59 RFCO 167 RFCO 167 RFCO 213 TVA 155 6920 7274 7274 7274 7933 7933 7933 7274 7274 7274 12503 12503 7274 7274 7274 10457 10457 10457 10457 10457 NotindB NotindB NotindB 10244 10244 10244 10244 6920 6920 6920 13298 13298 13298 13298 13298 13298 13298 7113 7113 7113 7274 6794 9201 9201 9201 7942 7942 7942 7751 7751 7751 9934 9934 6289 6289 6289 9909 9909 9909 9909 9909 7535 7535 7535 5896 5896 5896 5896 6656 6656 6656 8700 8700 8700 8700 8700 8700 8700 9051 9051 9051 9999 1.10 1.00 1.00 1.92 1.00 1.00 1.00 1.04 1.04 1.04 1.26 1.26 1.48 1.48 1.48 1.00 1.00 1.00 1.00 1.97 1.00 1.00 1.00 1.41 1.41 1.41 1.41 1.15 1.15 1.15 1.52 1.52 1.52 1.52 1.52 1.52 1.52 1.06 1.06 1.06 1.00 73.73 84.63 84.63 68.22 84.63 84.63 84.63 76.43 76.43 76.43 89.87 89.87 62.33 62.33 62.33 84.63 84.63 84.63 84.63 76.78 84.63 84.63 84.63 33.26 33.26 33.26 33.26 70.00 70.00 70.00 89.24 89.24 89.24 89.24 89.24 89.24 89.24 26.24 26.24 26.24 84.68 29 ------- Decatur Energy Center Decatur Energy Center Decatur Energy Center Morgan Energy Center Morgan Energy Center Morgan Energy Center Morgan Energy Center Channel Energy Center Channel Energy Center Channel Energy Center Calvert City Air Products Port Arthur Air Products Port Arthur Ingleside Cogeneration Ingleside Cogeneration Ingleside Cogeneration Chuck Lenzie Generating Station Chuck Lenzie Generating Station Chuck Lenzie Generating Station Baytown Energy Center Baytown Energy Center Baytown Energy Center Baytown Energy Center Columbia Energy Center Columbia Energy Center Columbia Energy Center Carville Energy LLC Carville Energy LLC Carville Energy LLC Plaquemine Cogeneration Plant Plaquemine Cogeneration Plant Plaquemine Cogeneration Plant Plaquemine Cogeneration Plant Plaquemine Cogeneration Plant Deer Park Energy Center Deer Park Energy Center Deer Park Energy Center Deer Park Energy Center Deer Park Energy Center Green Power 2 Green Power 2 55292_G_CTG2 Combined Cycle 55292_G_CTG3 Combined Cycle 55292_G_STG1 Combined Cycle 55293_G_CTG1 Combined Cycle 55293_G_CTG2 Combined Cycle 55293_G_CTG3 Combined Cycle 55293_G_STG1 Combined Cycle 55299_G_CTG1 Combined Cycle 55299_G_CTG2 Combined Cycle 55299_G_ST-1 Combined Cycle 55308_G_GEN1 Combustion Turbine 55309_G_GEN1 Combined Cycle 55309_G_GEN2 Combined Cycle 55313_G_CTG1 Combined Cycle 55313_G_CTG2 Combined Cycle 55313_G_STG Combined Cycle 55322_G_CTG1 Combined Cycle 55322_G_CTG2 Combined Cycle 55322_G_ST1 Combined Cycle 55327_G_CTG1 Combined Cycle 55327_G_CTG2 Combined Cycle 55327_G_CTG3 Combined Cycle 55327_G_STG1 Combined Cycle 55386_G_CT1 Combined Cycle 55386_G_CT2 Combined Cycle 55386_G_ST1 Combined Cycle 55404_G_CTG1 Combined Cycle 55404_G_CTG2 Combined Cycle 55404_G_STG Combined Cycle 55419_G_G500 Combined Cycle 55419_G_G600 Combined Cycle 55419_G_G700 Combined Cycle 55419_G_G800 Combined Cycle 55419_G_ST5 Combined Cycle 55464_G_CTG1 Combined Cycle 55464_G_CTG2 Combined Cycle 55464_G_CTG3 Combined Cycle 55464_G_CTG4 Combined Cycle 55464_G_STG1 Combined Cycle 55470_G_ST1 Combined Cycle 55470_G_TR1 Combined Cycle TVA 155 TVA 155 TVA 159 TVA 161 TVA 161 TVA 161 TVA 266 ERCT 185 ERCT 185 ERCT 215 TVA 23.0 ENTG 33.2 ENTG 3.0 ERCT 155 ERCT 155 ERCT 150 SNV 134 SNV 168 SNV 184 ERCT 170 ERCT 170 ERCT 170 ERCT 275 157 157 151 ENTG 180 ENTG 180 ENTG 140 ENTG 169 ENTG 169 ENTG 169 ENTG 169 ENTG 168 ERCT 155 ERCT 155 ERCT 155 ERCT 155 ERCT 258 ERCT 110 ERCT 158 7274 7274 7274 7355 7355 7355 7355 7200 7200 7200 12503 7274 7274 7933 7933 7933 7031 7031 7031 7274 7274 7274 7274 NotindB NotindB NotindB 7274 7274 7274 7274 7274 7274 7274 7274 7274 7274 7274 7274 7274 7933 7933 9999 9999 9999 7421 7421 7421 7421 6016 6016 6016 8700 10719 10719 8479 8479 8479 7735 7735 7735 7484 7484 7484 7484 6407 6407 6407 5966 5966 5966 6394 6394 6394 6394 6394 5712 5712 5712 5712 5712 5500 5500 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.34 1.34 1.34 1.43 1.00 1.00 1.07 1.07 1.07 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.73 1.73 1.73 1.36 1.36 1.36 1.11 1.11 1.11 1.11 1.11 1.75 1.75 1.75 1.75 1.75 1.44 1.44 84.68 84.68 84.68 84.68 84.68 84.68 84.68 40.92 40.92 40.92 89.88 84.63 84.63 57.25 57.25 57.25 84.63 84.63 84.63 84.63 84.63 84.63 84.63 15.00 15.00 15.00 56.35 56.35 56.35 51.42 51.42 51.42 51.42 51.42 76.57 76.57 76.57 76.57 76.57 73.01 73.01 30 ------- Green Power 2 Green Power 2 Blackburn Landfill Co-Generation Blackburn Landfill Co-Generation Blackburn Landfill Co-Generation Wilmington Hydrogen Plant Combined Locks Energy Center Combined Locks Energy Center Binghamton Cogen Mingo Junction Energy Center Mingo Junction Energy Center Mingo Junction Energy Center Mingo Junction Energy Center FPL Energy Marcus Hook LP FPL Energy Marcus Hook LP FPL Energy Marcus Hook LP FPL Energy Marcus Hook LP Desert Power LP Co-Gen LLC Ashtabula Ashtabula Ashtabula Ashtabula Ashtabula Ashtabula Ashtabula Trigen Revere Trigen Revere WWTP Power Generation Station WWTP Power Generation Station WWTP Power Generation Station Fox Valley Energy Center UMCPCHP Plant UMCPCHP Plant UMCPCHP Plant Millennium Hawkins Point Millennium Hawkins Point Millennium Hawkins Point Millennium Hawkins Point Millennium Hawkins Point Millennium Hawkins Point 55470_G_TR2 Combined Cycle 55470_G_TR3 Combined Cycle 55488_G_BB1 Landfill Gas 55488_G_BB2 Landfill Gas 55488_G_BB3 Landfill Gas 55557_G_T101 0/G Steam 55558_G_GEN1 Combined Cycle 55558_G_GEN2 Combined Cycle 55600_G_1 Combustion Turbine 55611_B_BOIL1 0/G Steam 55611_B_BOIL2 0/G Steam 55611_B_BOIL3 0/G Steam 55611_B_BOIL4 0/G Steam 55801_G_CT13 Combined Cycle 55801_G_CT1A Combined Cycle 55801_G_CTIB Combined Cycle 55801_G_STG Combined Cycle 55858_G_GEN7 Coal Steam 50921_G_GEN1 Biomass 55990_G_1 Combined Cycle 55990_G_2 Combined Cycle 55990_G_3 Combined Cycle 55990_G_4 Combined Cycle 55990_G_5 Combined Cycle 55990_G_6 Combined Cycle 55990_G_7 Combined Cycle 55999_G_GEN1 1C Engine 55999_G_GEN2 1C Engine 56036_G_GEN1 Non-Fossil Waste 56036_G_GEN2 Non-Fossil Waste 56036_G_GEN3 Non-Fossil Waste 56037_G_1 Coal Steam 56038_G_1 Combined Cycle 56038_G_2 Combined Cycle 56038_G_3 Combined Cycle 56045_G_1A Combined Cycle 56045_G_1B Combined Cycle 56045_G_2A Combined Cycle 56045_G_2B Combined Cycle 56045_G_3A Combined Cycle 56045_G_3B Combined Cycle ERCT 158 ERCT 158 VACA 1 VACA 1 VACA 0.90 CA-S 23.0 WUMS 40.8 WUMS 4.3 UPNY 42.0 RFCO 7.5 RFCO 7.5 RFCO 7.5 RFCO 7.5 MACE 162 MACE 162 MACE 160 MACE 234 NWPE 40.0 PNW 7.0 RFCO 4.4 RFCO 4.4 RFCO 4.4 RFCO 4.4 RFCO 4.4 RFCO 0.69 RFCO 0.69 NENG 2.8 NENG 2.8 CA-N 2.0 CA-N 2.0 CA-N 2.0 WUMS 6.5 MACS 9.4 MACS 9.4 MACS 2.0 MACS 1.1 MACS 1.1 MACS 1.1 MACS 1.1 MACS 1.1 MACS 1.1 7933 7933 12328 12328 12328 11425 7933 7933 10894 11425 11425 11425 11425 7274 7274 7274 7274 9650 17974 7274 7274 7274 7274 7274 7274 7274 10850 10850 14653 14653 14653 10331 7933 7933 7933 7933 7933 7933 7933 7933 7933 5500 5500 8700 8700 8700 9854 6221 6221 9358 8300 8300 8300 8300 7274 7274 7274 7274 Retired 8566 7083 7083 7083 7083 7083 7083 7083 9732 9732 14653 14653 14653 8300 6534 6534 6534 13490 13490 13490 13490 13490 13490 1.44 1.44 1.57 1.57 1.57 1.13 1.28 1.28 1.16 1.35 1.35 1.35 1.35 1.00 1.00 1.00 1.00 2.10 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.11 1.11 1.00 1.00 1.00 1.24 1.80 1.80 1.80 1.09 1.09 1.09 1.09 1.09 1.09 73.01 73.01 67.05 67.05 67.05 92.45 18.89 18.89 89.87 92.41 92.41 92.41 92.41 84.63 84.63 84.63 84.63 0.00 83.00 73.53 73.53 73.53 73.53 73.53 73.53 73.53 89.24 89.24 90.00 90.00 90.00 85.26 84.63 84.63 84.63 37.14 37.14 37.14 37.14 37.14 37.14 31 ------- Millennium Hawkins Point Co-Gen II LLC Sierra Pacific Aberdeen Middlesex Generating Facility Middlesex Generating Facility Middlesex Generating Facility SP Newsprint- Newberg Cogen SP Newsprint- Newberg Cogen SP Newsprint- Newberg Cogen Macon Energy Center Groveton Paper Board Groveton Paper Board Freeport Energy Center Freeport Energy Center Freehold Asbury Park Press Freehold Asbury Park Press Cogeneration 1 Perham Incinerator Shell Chemical Shell Chemical Trigen St.Louis Trigen St.Louis Trigen St.Louis Trigen St.Louis Trigen St.Louis Clearwater Power Plant Clearwater Power Plant Domain Plant Robert Mueller Energy Center Sierra Pacific Burlington Facility Tesoro SLC Cogeneration Plant Tesoro SLC Cogeneration Plant Edge Moor Edge Moor Sherburne County Sherburne County Big Stone Warrick Warrick Warrick Warrick 56045_G_ST1 50993_G_GEN1 55882_B_BLR1 56119_G_100 56119_G_200 56119_G_300 56124_B_10BLR 56124_G_GT1 56124_G_GT2 56127_G_1 56140_G_TUR1 56140_G_TUR2 56152_G_CTG1 56152_G_STG1 56169_G_UNT1 56169_G_UNT2 56229_G_CT1 56243_G_1 56248_G_101G 56248_G_201G 56309_G_CT-1 56309_G_CT-2 56309_G_ST-3 56309_G_ST-4 56309_G_ST-5 56356_G_CT1 56356_G_ST1 56373_G_DOMG1 56374_G_CT1 56406_G_GEN1 56509_G_1 56509_G_2 593_B_3 593_B_4 6090_B_1 6090_B_2 6098_B_1 6705_B_1 6705_B_2 6705_B_3 6705 B 4 Combined Cycle Biomass Biomass Non-Fossil Waste Non-Fossil Waste Non-Fossil Waste 0/G Steam Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine Combined Cycle Combined Cycle 1C Engine 1C Engine Combined Cycle Municipal Solid Waste Combustion Turbine Combustion Turbine Combined Cycle Combined Cycle 0/G Steam Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combustion Turbine Combustion Turbine Biomass Combustion Turbine Combustion Turbine Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam Coal Steam MACS 0.50 PNW 7.0 PNW 16.5 4.10 4.10 10.6 PNW 22.3 PNW 41.6 PNW 41.6 GWAY 9.1 NENG 4.0 NENG 4.0 180 80.0 MACE 1.1 MACE 1.1 AZNM 8.3 MRO 1.2 ENTG 32.0 ENTG 32.0 GWAY 4.0 GWAY 4.2 GWAY 18.0 GWAY 0.77 GWAY 0.81 CA-S 21.0 CA-S 7.0 ERCT 5.0 ERCT 3.7 PNW 25.0 NWPE 11.0 NWPE 11.0 MACE 86.0 MACE 174 MRO 762 MRO 752 MRO 470 RFCO 136 RFCO 136 RFCO 136 RFCO 300 7933 17139 15517 NotindB NotindB NotindB 11332 12503 12503 13301 12678 12678 NotindB NotindB 11797 11797 7933 19338 12503 12503 11985 11985 11425 11985 11985 9100 9100 11862 12503 15517 12503 12503 13668 9569 10611 10452 11609 10986 11017 11056 10418 13490 10285 8300 7274 7274 7274 11511 Retired Retired 13301 12477 12477 7942 7942 10000 10000 7942 16297 10994 10994 5583 5583 11177 5583 5583 9368 9368 11862 9960 12695 8700 8700 12721 9569 10611 10452 11609 10986 11002 11002 10418 1.09 1.67 1.89 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.18 1.18 1.00 1.00 1.13 1.13 2.15 2.15 1.00 2.15 2.15 1.00 1.00 1.00 1.00 1.24 1.44 1.44 1.07 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 37.14 83.00 83.00 90.00 90.00 90.00 92.41 0.00 0.00 89.24 89.24 89.24 84.63 84.63 89.24 89.24 84.63 90.00 89.87 89.87 52.35 52.35 92.45 52.35 52.35 84.63 84.63 89.24 89.24 83.00 89.24 89.24 41.53 41.53 68.27 68.27 79.70 73.94 73.94 73.94 73.93 32 ------- Gadsden Gadsden Whitehead Whitehead Whitehead Whitehead Whitehead Whitehead Whitehead Brandon Station Richard Gorsuch Richard Gorsuch Richard Gorsuch Richard Gorsuch George Neal South University of Florida Coyote Springs Coyote Springs Indian Trails Cogen 1 Indian Trails Cogen 1 Indian Trails Cogen 1 Carson Ice-Gen Project Carson Ice-Gen Project Milwaukee County Milwaukee County Milwaukee County SCA Cogen 2 SCA Cogen 2 SCA Cogen 2 SCA Cogen 2 SPA Cogen 3 SPA Cogen 3 Everett Cogen US DOE Savannah River Site (D Area) US DOE Savannah River Site (D Area) US DOE Savannah River Site (D Area) US DOE Savannah River Site (D Area) Washington County Cogeneration Facility Washington County Cogeneration Facility General Electric Plastic General Electric Plastic 7_B_1 Coal Steam SOU 64.0 1 12376 7_B_2 Coal Steam SOU 66.0 12846 7028_G_K1 1C Engine NWPE 5.9 14151 7028_G_K2 1C Engine NWPE 6.0 7028_G_K3 1C Engine NWPE 5.9 7028_G_K4 1C Engine NWPE 4.0 7028_G_K5 1C Engine NWPE 2.0 7028_G_K6 1C Engine NWPE 2.1 7028_G_K7 1C Engine NWPE 2.1 7131_G_1 Combustion Turbine SPPS 20.0 7286_B_1 Coal Steam RFCO 50.0 7286_B_2 Coal Steam RFCO 50.0 7286_B_3 Coal Steam RFCO 50.0 7286_B_4 Coal Steam RFCO 50.0 7343_B_4 Coal Steam MRO 632 7345_G_P1 Combustion Turbine FRCC 45.0 7350_G_1 Combined Cycle PNW 142 7350_G_2 Combined Cycle PNW 71.3 7384_B_1 0/G Steam GWAY 3.3 7384_B_2 0/G Steam GWAY 3.3 7384_B_3 0/G Steam GWAY 3.3 7527_G_1 Combined Cycle CA-N 41.2 7527_G_2 Combined Cycle CA-N 16.6 7549_B_1 Coal Steam WUMS 3.3 7549_B_2 Coal Steam WUMS 3.3 7549_B_3 Coal Steam WUMS 3.3 7551_G_CCST Combined Cycle CA-N 37.6 7551_G_CT1A Combined Cycle CA-N 39.6 7551_G_CT1B Combined Cycle CA-N 39.6 7551_G_CT1C Combined Cycle 45.7 7552_G_CCCT Combined Cycle CA-N 111 7552_G_CCST Combined Cycle CA-N 53.0 7627_B_14 Biomass PNW 36.0 7652_B_D-1 Coal Steam 19.6 7652_B_D-2 Coal Steam 19.6 7652_B_D-3 Coal Steam 19.6 10069 10069 10069 10746 10746 10746 12503 11084 11084 11071 11071 10470 9249 7337 7337 11425 11425 11425 11860 11860 11704 10331 10331 11094 11094 11094 Not in dB 8394 8394 15517 NotindB NotindB NotindB 7652_B_D-4 Coal Steam 19.6 iNotindB 7697_G_1 Combined Cycle SOU 80.0 7274 7697_G_2 Combined Cycle SOU 22.0 7274 7698_G_1 Combined Cycle SOU 85.0 7698 G 2 Combined Cycle SOU 12.0 7274 7274 12376 12846 14151 10069 10069 10069 10746 10746 10746 12503 11084 11084 11071 11071 10470 9249 7598 7598 11177 11177 11177 8327 8327 11704 10320 10320 8469 8469 8469 8469 8137 8137 11844 10320 10320 10320 10320 9026 9026 11972 11972 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.33 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 50.27 50.27 89.24 89.24 89.24 89.24 89.24 89.24 89.24 89.87 60.67 60.67 60.67 60.67 80.10 89.87 84.68 84.68 92.41 92.41 92.41 84.63 84.63 71.80 71.80 71.80 84.63 84.63 84.63 84.63 84.63 84.63 83.00 31.67 31.67 31.67 31.67 84.63 84.63 84.63 84.63 33 ------- Fairless Hills 7701_B_4 Landfill Gas MACE 30.0 Fairless Hills 7701_B_5 Landfill Gas MACE 30.0 Pea Ridge 7715_G_1 Combustion Turbine SOU 4.0 Pea Ridge 7715_G_2 Combustion Turbine SOU 4.0 Pea Ridge 7715_G_3 Combustion Turbine SOU 4.0 Theodore Cogen Facility 7721_G_1 Combined Cycle SOU 152 Theodore Cogen Facility 7721_G_2 Combined Cycle SOU 36.0 Cogen South 7737_B_B001 Coal Steam VACA 90.0 Encogen 7870_G_CTG1 Combined Cycle PNW 39.4 Encogen 7870_G_CTG2 Combined Cycle PNW 39.4 Encogen 7870_G_CTG3 Combined Cycle PNW 39.4 Encogen 7870_G_STG Combined Cycle PNW 51.8 West Campus Cogeneration Facility 7991_G_1 Combined Cycle WUMS 38.0 West Campus Cogeneration Facility 7991_G_CT2 Combined Cycle WUMS 37.2 West Campus Cogeneration Facility 7991_G_STG1 Combined Cycle WUMS 55.0 Ware Cogeneration 81542_G_1 Biomass NENG 4.1 Kimberly Clark 82800_G_CC1 Combined Cycle NENG 17.5 Kimberly Clark 82800_G_GT1 Combustion Turbine NENG 17.5 Great River Energy Spiritwood Station 82821_B_1 Coal Steam MRO 99.0 SPPN_KS_Coal steam 82932_C_1 Coal Steam SPPN 22.0 Cabot Holyoke 9864_B_5 0/G Steam 5.80 Cabot Holyoke 9864_B_6 0/G Steam 5.80 Cabot Holyoke 9864_B_7 0/G Steam 5.80 Cabot Holyoke 9864_B_8 0/G Steam 5.80 13682 13682 14111 11210 11210 7274 7274 10966 11200 11200 11200 11200 11985 11985 11985 15517 7031 10664 8763 10820 Not in dB Not in dB Not in dB Not in dB 12789 12789 14111 11210 11210 7065 7065 10966 9118 9118 9118 9118 8367 8367 8367 15716 7942 12477 8937 8937 14500 14500 10817 14500 1.07 1.07 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 47.11 47.11 89.24 89.24 89.24 84.63 84.63 70.87 84.68 84.68 84.68 84.68 84.63 84.63 84.63 83.00 84.63 89.24 85.26 85.26 89.51 89.51 89.51 89.51 34 ------- 2 NOX Rates 2.1 Response to the Comments Received Comment Theme: There were a substantial number of comments indicating that the NOX rates shown in NEEDS2 were too low and not achievable. Discussion: Based on these comments, the decision rules used to derive the NEEDS NOX rates were reviewed and an out-of-date assumption was found to be causing instances of low NOX rates. Specifically, the out-of-date decision rule (which was developed at a time when units were subject, at most, to summer season, not annual, NOX rate limits) designated the winter NOX rate as the uncontrolled NOX rate. Applying percent reductions attributable to NOX post-combustion controls to the winter NOX rates resulted in unrealistically low controlled NOX rates for units that in reality operated NOX controls in the winter. Response: The previous decision rules were replaced by a more robust procedure for identifying uncontrolled NOX rates. In addition, a thorough review was made of all the decision rules affecting NOX rates and, where appropriate, revisions were made. The revised decision rules are shown in the documentation supplement which follows. In addition, as announced in the Federal Register Notice of Data Availability for the Proposed Transport Rule (FR, vol. 75, no.169, September 1, 2010, 53614-53615) the NOX rates for fossil-fuel fired units in the final rule are based on 2009 data rather than 2007 NOX data used in the modeling for the proposed Transport Rule. Reported to EPA by generating units covered under Title IV of the Clean Air Act Amendments of 1990 (Acid Rain Program) and NOX Budget Program, the updated NOX rates more accurately reflect the unit level control installations that have occurred at power plants during the past several years. 2.1 Resulting Updates The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case v4.10_FTransport. In the documentation for EPA Base Case v.4.10_NODA, \he following replaces the response to question Q4 that had previously appeared in Appendix 3-1 in the NOD A documentation. 2 The National Electrical Energy Data System (NEEDS) is a database which provides EPA's model of the electric power sector with information on all currently operating and planned-committed electric generating units. An updated version of NEEDS (v.4.10) was part of the September 1, 2010 Notice of Data Availability for the Proposed Transport Rule. 35 ------- NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport Q4: How are the values of the Mode 1-4 NOx rates derived? A4: The revised draft of the methodology to develop NOX rates for coal steam boilers in EPA Base Case v.4.10_FTransport is summarized below. The procedure employs the following hierarchy of NOX rate data sources: 1. 2009 ETS 2. EPA 410 NODA Comments 3. 2007 ETS 4. 2005 EIA Form 767 5. Defaults The existing coal steam boilers in US are categorized into three groups depending on the configuration of NOX combustion and post-combustion controls Group 1 - Coal boilers without post combustion NCX controls Mode 1 = 2009 ETS Annual Average NOX Rate Mode 2 = Mode 1 Mode 3 For coal boilers located in a SIP call NOX, CAIR ozone/annual NOX or any NOX regulated state, Mode 3 = Mode 1 For coal boilers that are not located in a SIP call NOX, CAIR ozone/annual NOX or any NOX regulated state, follow Steps 1-7 Step 1: Pre-screen units that already have state of art (SOA) combustion controls from units that have non- SOA combustion controls from units that have no combustion controls Step 2: For units listed as not having combustion controls Make sure their NOX rates do not indicate that they really do have SOA control If Mode 1 > Cut-off (in Table 3-1.2), then Mode 1 = Base NOX rate. Go to Step 6 If Mode 1 < Cut-off (in Table 3-1.2), then the unit has SOA control and Mode 3 = Mode 1 Step 3: For units listed as having SOA combustion controls. Mode 3 = Mode 1. Step 4: For units listed as not having SOA combustion controls Make sure their NOX rates do not indicate that they really do have SOA control If Mode 1 < Cut-off (in Table 3-1.2), then the unit has SOA control and Mode 3 = Mode 1 If Mode 1 > Cut-off (in Table 3-1.2), then go to Step 5 Step 5: Determine the unit's Base NOX rate, i.e., the unit's uncontrolled emission rate without combustion controls, using the appropriate equation (not in boldface italics) in Table 3-1.3 to back calculate their Base NOX rate. Use the default Base NOX rate values if back calculations can't be performed. Once the Base NOX rate is obtained, go to Step 6. Step 6: Use the appropriate equations (in boldface italics) in Table 3-1.3 to calculate the NOX rate with SOA combustion controls. Step 7: Compare the value calculated in Step 6 to the applicable NOX floor rate in Table 3-1.2. If the value from Step 6 is > floor, use the Step 6 value as Mode 3. Otherwise, use the floor as the Mode 3 NOX rate. Mode 4 Mode 4 = Mode 3 36 ------- NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont'd) Group 2 - Coal boilers with Dispatchable/Non-Dispatchable SCR Pre-screen coal boilers with 2009 ETS NOX rates into the following four operating regimes. A coal boiler is assumed to be operating its SCR when the seasonal NOX rate is less than 0.2 Ibs/MMBtu Group 2a. Coal boilers with Non-Dispatchable SCR Group 2a.1 SCR is not operating in both summer and winter seasons Follow the NOX rate rules summarized for Group 1 boilers. No state of the art combustion controls are implemented. Mode 1 = 2009 ETS Annual Average NOX Rate Mode 2 = maximum {(1-0.9) * Mode 1, 0.07} Mode 3 = Mode 1 Mode 4 = Mode 2 Group 2a.2 SCR is operating in summer only Mode 1 = 2009 ETS Winter NOX Rate Mode 2 = 2009 ETS Summer NOX Rate Mode 3 = Mode 1 Mode 4 = Mode 2 Group 2a.3 SCR is operating in winter only Mode 1 = 2009 ETS Summer NOX Rate Mode 2 = 2009 ETS Winter NOX Rate Mode 3 = Mode 1 Mode 4 = Mode 2 Group 2a.4 SCR is operating year-round Mode 1 = if (2007 ETS Winter NOX Rate > 0.2, 2007 ETS Winter NOX Rate, 2009 ETS Annual Average NOX Rate) Mode 2 = 2009 ETS Annual Average NOX Rate Mode 3 = Mode 1 Mode 4 = Mode 2 Group 2b. Coal boilers with Dispatchable SCR Group 2b.1 SCR is not operating in both summer and winter seasons Follow the NOX rate rules summarized for Group2a.1 boilers. Group 2b.2 SCR is operating in summer only Mode 1 = 2009 ETS Winter NOX Rate Mode 2 = Mode 1 Mode 3 = Mode 1 Mode 4 = Mode 2 Group 2b.3 SCR is operating in winter only Mode 1 = 2009 ETS Summer NOX Rate Mode 2 = Mode 1 Mode 3 = Mode 1 Mode 4 = Mode 2 Group 2b.4 SCR is operating year-round Mode 1 = if (2007 ETS Winter NOX Rate > 0.2, 2007 ETS Winter NOX Rate, 2009 ETS Annual Average NOX Rate) Mode 2 = Mode 1 Mode 3 = Mode 1 Mode 4 = Mode 2 37 ------- NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont'd) Group 3 - Coal boilers with SNCR Step 1: Pre-screen coal boilers with 2009 ETS NOX rates to verify if they have not operated their SNCR in both summer and winter seasons. A coal boiler is assumed to be not operating its SNCR when the NOX rate is greater than 0.3 Ibs/MMBtu in both summer and winter seasons. Group 3.1 SNCR is not operating in both summer and winter seasons Follow the NOX rate rules summarized for Group 1 boilers Step 2: Pre-screen coal boilers with 2009 ETS NOX rates into the following three operating regimes. First estimate the implied removal for a coal boiler using the following equation: Implied Removal (%) = ((Winter NOX Rate - Summer NOX Rate)/ Winter NOX Rate) * 100 Second, assign the coal boiler to a specific operating regime based on the following logic. If Implied Removal > 20% then SNCR is operating in summer season only, Else if Implied Removal < -20% then SNCR is operating in winter season only, Else SNCR is operating year-round Group 3.2 SNCR is operating in summer only Mode 1 = 2009 ETS Winter NOX Rate Mode 2= 2009 ETS Summer NOX Rate Mode 3 = same as Group 1 Mode 3 Mode 4 = maximum {(1-0.25) * Mode 3, 0.1} for non FBC units Mode 4 = maximum {(1-0.50) * Mode 3, 0.08} for FBC units Note: The (1-.25) and (1-0.5) terms in the equations above represents the NOX removal efficiencies of SNCR for non FBC and FBC boilers. Group 3.3 SNCR is operating in winter only Mode 1 = 2009 ETS Summer NOX Rate Mode 2 = 2009 ETS Winter NOX Rate Mode 3 = same as Group 3.2 Mode 3 Mode 4 = same as Group 3.2 Mode 4 Group 3.4 SNCR is operating year-round Mode 1 = if (2007 ETS Winter NOX Rate > 0.3, 2007 ETS Winter NOX Rate, 2009 ETS Annual Average NOX Rate) Mode 2 = 2009 ETS Annual Average NOX Rate Mode 3 = same as Group 3.2 Mode 3 Mode 4 = Mode 3 38 ------- Table 3-1.1 Examples of Base and Policy NOX Rates Occurring in EPA Base Case v.4.10_FTransport Plant Name Unique ID Post- Corn busti on Control edNOx Racp Ratp Control! edNOx Base Rate Uncontroll edNOx Policy Rate Control! edNOx Policy Rate Explanation Situation 1: For generating units that do not have post-combustion controls, the controlled and uncontrolled rates will be the same. Four Corners 2442_B_1 None 0.786 0.786 0.509 0.509 Situation 4 also applies, i.e., unit had LNB and now added OFA so see drop in policy rates. Situation 2: For generating units that do have post-combustion controls, the controlled and uncontrolled rates will differ. Big Sandy 1353 B BS U2 SCR 0.629 0.146 0.629 0.146 (1) Has SCR so see difference between uncontrolled and controlled rates (2) Situation 3b also applies. Situation 3a: Base and Policy NOX rates will be same if the unit has state-of-the-art NOX combustion controls or... Greene County Chalk Point LLC 10_B_2 1571_B_1 None SCR 0.363 0.485 0.363 0.156 0.363 0.485 0.363 0.156 Situation 1 also applies. Situation 2 also applies. Situation 3b:... is in the NOX Regulated Region where current combustion controls are assumed to be retained. Thomas Hill Waukegan 2168 B MB 3 883_B_17 SCR None 0.221 0.336 0.102 0.336 0.221 0.336 0.102 0.336 Situation 2 also applies. (1) Has NOX combustion control and is in SIP so doesn't get added combustion control. (2) Situation 1 also applies. Situation 4: Base and policy rates will differ if a unit does not currently have state-of-the-art combustion controls and would install such controls in response to a NOX policy. Crist 641_B_4 SNCR 0.404 0.404 0.240 0.180 (1) Drop in uncontrolled policy NOX rate compared to uncontrolled base rate is due to addition of combustion controls. (Note 0.24 is floor.) NOX regulated region includes: Alabama, Arkansas, Connecticut, Delaware, District Of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Hampshire, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin. 39 ------- Table 3-1.2 Cutoff and Floor NOX Rates (Ib/MMBtu) in EPA Base Case v.4.10_FTransport Boiler Type Wall-Fired Dry-Bottom Tangentially -Fired Cell- Burners Cyclones Vertically- Fired Cutoff Bituminous 0.43 0.34 0.43 0.62 0.57 Rate (Ibs/MMBtu) Subbitumino Lignit us e 0.33 0.29 0.24 0.22 0.43 0.43 0.67 0.67 0.44 0.44 Floor Bituminous 0.32 0.24 0.32 0.47 0.49 Rate (Ibs/MMBtu) Subbitumino us 0.18 0.12 0.32 0.49 0.25 Lignit e 0.18 0.17 0.32 0.49 0.25 Table 3-1.3 NOX Removal Efficiencies for Different Combustion Control Configurations in EPA Base Case v.4.10_FTransport (State of the art configurations are shown in bold italic.) Boiler Type Dry Bottom Wall-Fired Dry Bottom Wall-Fired Tangentially- Fired Tangentially- Fired Coal Type Bituminous Subbituminous /Lignite Bituminous Subbituminous /Lignite Combustion Control Technology LNB LNB + OFA LNB LNB + OFA LNC1 LNC2 LNC3 LNC1 LNC2 LNC3 Fraction of Removal 0.163 + 0.272* Base NOX 0.373 + 0.272* Base NOX 0.135 + 0.541* Base NOX 0.285 + 0.547* Base NOX 0.162 + 0.336* Base NOX 0.212 + 0.336* Base NOX 0.362 + 0.336* Base NOX 0.20 + 0.717* Base NOX 0.25 + 0.717* Base NOX 0.35 + 0.777* Base NOX Default Removal 0.568 0.778 0.574 0.724 0.42 0.47 0.62 0.563 0.613 0.773 Notes: LNB = Low NOX Burner OFA = Overfire Air LNC = Low NOX Control 40 ------- 3 SO2 Removal Rates for Flue Gas Desulfurization (FGD) Comment Theme: In EPA Base Case v.4.10 the assumed SO2 removal efficiency for wet and dry FGD on new units and retrofits was 98% and 95% respectively. Comments indicated that the assumption of a 98% SO2 removal rate for wet FGD on new units and retrofits might be suitable as a short-term performance guarantee but exceeded the long term removal rate that could be achieved under real operating conditions where load following is required. EPA was requested to use the same default wet and dry FGD removal rates as assumed in the previous base case v.3.0.2 EISA , i.e., 95% for wet FGD and 92% for dry FGD. Discussion: In response to this comment, it was decided to base removal rates for new and retrofit FGD on historical performance data reported in EIA 860 (2008) rather than on the engineering design capabilities of the controls, as was previously used in EPA Base Case v.4.10. This will put the removal rate assumptions for be new and retrofit FGD on the same basis as existing controls. Response: Default SO2 removal rates for wet and dry FGD were revised to be based on data reported in EIA 860 (2008). This ensures that they reflect operating removal rates rather than the engineering design removal rates which some commenters asserted could not be maintained under load following conditions. In particular, for new units and FGD retrofits installed by the model, the assumed SO2 removal rates will be 96% for wet FGD and 92% for dry FGD. These are the average of the SO2 removal efficiencies reported in EIA 860 (2008) for dry and wet FGD installed in 2008 or later. Existing units reporting FGD removal rates in form EIA 860 (2008) will be assigned those rates. However, to reduce the incidence of implausibly high, outlier removal rates, units whose reported EIA Form 860 (2008) SO2 removal rates are higher than the average of the upper quartile SO2 removal rates will be assigned the upper quartile average unless the reported EIA 860 rate is confirmed in a submitted comment. One upper quartile removal rate is calculated across all installation years and replaces any reported removal rate that exceeds it no matter what installation year. Existing units not reporting FGD removal rates in form EIA 860 (2008) will be assigned the average of the applicable SO2 removal rate for a dry or wet FGD as reported in EIA 860 (2008) for the same FGD installation year. 3.2 Resulting Updates The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case v4.10_FTransport. In Chapter 3 - Power System Operation Assumptions Change the entries in Table 3-11 as shown in red on the following page. 41 ------- Table 3-11 Emission and Removal Rate Assumptions for Potential (New) Units in EPA Base Case v.4.10 FTransport Gas S02 NOX Hg C02 HC1 Removal, and Emissions Rates Removal / Emissions Rate Emission Rate Emissions Rate Emissions Rate Removal / Emissions Rate Supercritical Pulverized Coal - Wet Scrubber 98%-96%with a floor of 0.06 Ibs/MMBtu 0.07 Ibs/MMBtu 90% 205.2-217.3 Ibs/MMBtu 99% 0.0001 Ibs/mmBtu Supercritical Pulverized Coal - Dry Scrubber 93% 92% with 0.065 0.08 Ibs/MMBtu 0.05 Ibs/MMBtu 90% 205.2-217.3 Ibs/MMBtu 99% 0.0001 Ibs/mmBtu Integrated Gasification Combined Cycle 99% 0.013 Ibs/MMBtu 90% 205.2-217.3 Ibs/MMBtu 99% 0.0001 Ibs/mmBtu Advanced Coal with Carbon Capture 99% 0.013 Ibs/MMBtu 90% 90% 99% 0.0001 Ibs/mmBtu Advanced Combined Cycle None 0.011 Ibs/MMBtu Natural Gas: 0.000138 Ibs/MMBtu Oil: 0.483 Ibs/MMBtu Natural Gas: 117.08 Ibs/MMBtu Oil: 161.39 Ibs/MMBtu - Advanced Combustion Turbine None 0.011 Ibs/MMBtu Natural Gas: .000138 Ibs/MMBtu Oil: 0.483 Ibs/MMBtu Natural Gas: 117.08 Ibs/MMBtu Oil: 161.39 Ibs/MMBtu - Biomass Conventional Direct-Fired Boiler 0.08 Ibs/MMBtu 0.36 Ibs/MMBtu 0.57 Ibs/MMBtu None - Biomass Gasification Combined Cycle 0 08 Ibs/MMBtu 0.102 Ibs/MMBtu 0.57 Ibs/MMBtu None - Geothermal None None 3.70 None - Landfill Gas None 0.09 Ibs/MMBtu None None - 42 ------- In Chapter 5 - Emission Control Technologies Incorporate the changes shown in red below. 5.1 Sulfur Dioxide Control Technologies Two commercially available Flue Gas Desulfurization (FGD) technology options for removing the SO2 produced by coal-fired power plants are offered in EPA Base Case v.4.10: Limestone Forced Oxidation (LSFO) — a wet FGD technology — and Lime Spray Dryer (LSD) — a semi-dry FGD technology which employs a spray dryer absorber (SDA). In wet FGD systems, the polluted gas stream is brought into contact with a liquid alkaline sorbent (typically limestone) by forcing it through a pool of the liquid slurry or by spraying it with the liquid. In dry FGD systems the polluted gas stream is brought into contact with the alkaline sorbent in a semi-dry state through use of a spray dryer. The removal efficiency for SDA drops steadily for coals whose SO2 content exceeds 3 Ibs SO2/MMBtu, so this technology is provided only to plants which have the option to burn coals with sulfur content no greater than 3 Ibs SO2/MMBtu. In EPA Base Case v.4.10 when a unit retrofits with an LSD SO2 scrubber, it loses the option of burning BG, BH, and LG coals due to their high sulfur content. In EPA Base Case v.4.10 the LSFO and LSD SO2 emission control technologies are available to existing "unscrubbed" units. They are also available to existing "scrubbed" units with reported removal efficiencies of less than fifty percent. Such units are considered to have an injection technology and classified as "unscrubbed" for modeling purposes in the NEEDS database of existing units which is used in setting up the EPA base case. The scrubber retrofit costs for these units are the same as regular unscrubbed units retrofitting with a scrubber. Scrubber efficiencies for existing units were derived from data reported in EIA Form 767-860 (2008). In transferring this data for use in EPA Base Case v.4.10 the following changes were made. The maximum removal efficiency was set at 98% for wet scrubbers and 93% for dry scrubber units. Existing units reporting efficiencies above these levels in Form 767 were assigned the maximum removal efficiency in NEEDS v.4.10 indicated in the previous sentence. Units whose reported EIA Form 860 (2008) SO2 removal rates were higher than the average of the upper quartile SO2 removal rates were assigned the upper quartile average unless the EIA 860 rate was confirmed in a comment submitted during the Transport Rulemaking . One upper quartile removal rate is calculated across all installation years and replaces any reported removal rate that exceeds it no matter what installation year. Existing units not reporting FGD removal rates in form EIA 860 (2008) were assigned the average of the applicable SO2 removal rate for a dry or wet FGD as reported in EIA 860 (2008) for the same FGD installation year. As shown in Table 5-2, existing units that are selected to be retrofitted by the model with scrubbers are given the maximum removal efficiencies of 98%-96% for LSFO and 93%-92% for LSD. The procedures used to derive the cost of each scrubber type are discussed in detail in the following sections. Table 5-2 Summary of Retrofit SO2 Emission Control Performance Assumptions Performance Assumptions Percent Removal Capacity Penalty Heat Rate Penalty Cost (2007$) Applicability Sulfur Content Applicability Applicable Coal Types Limestone Forced Oxidation (LSFO) 94^96% with a floor of 0.06 Ibs/MMBtu Calculated based on characteristics of the unit: See Table 5-4 for examples Units > 25 MW BA, BB, BD, BE, BG, BH, SA, SB, SD, LD, LE, and LG Lime Spray Dryer (LSD) 939^92% with a floor of 0.065 0.08 Ibs/MMBtu Calculated based on characteristics of the unit: See Table 5-4 for examples Units > 25 MW Coals < 3 Ibs SO2/MMBtu BA, BB, BD, BE, SA, SB, SD, LD, and LE Potential (new) coal-fired units built by the model are also assumed to be constructed with a scrubber achieving a removal efficiency of 9&%-96% for LSFO and 93%-92% for LSD. In EPA Base Case v.4.10 the costs of potential new coal units include the cost of scrubbers. 43 ------- 4 Coal Switching - Bituminous to Subbituminous 4.1 Response to the Comments Received Comment Theme: In draft EPA Base Case v.410 it was assumed that generating units that had the option to burn both bituminous and subbituminous coal could use any proportion needed of each type of coal. Comments pointed out that there were limitations that prevented unrestricted switching at some existing generating units. Discussion: Based on these comments, a procedure was developed to capture limitations that prevent unrestricted switching from bituminous to subbituminous coal without incurring additional investment costs. The procedure consisted of the following steps: (1) Determining a level of subbituminous coal consumption indicative of an existing capability to burn 100% subbituminous coal. (2) Developing cost adders, heat rate penalties, and decision rules that would apply to units that don't meet this threshold. In EPA Base Case v.4.10_FTransport, existing units with a historical record of burning a high percentage of subbituminous (specifically, 90% or more) are assumed to have made investments required for high percentage subbituminous firing. Existing units not meeting the 90% criteria incur a fuel cost adder and heat rate penalty for combusting more than a pre-specified percent of subbituminous. The cost adder is designed to reflect material handling and boiler modification costs. The heat rate penalty reflects the impact of the higher moisture content subbituminous coal on the unit's heat rate. The procedure, which is summarized below, applies only to units that are currently designated to burn both bituminous and subbituminous coal in EPA Base Case v.4.10_FTransport. Historical fuel usage data is used to infer whether units have already made investments allowing them to burn unrestricted amounts of subbituminous coal. Staff engineering analyses indicated that (a) all boilers that are designated to burn both bituminous and subbituminous coal should be able to burn a limited percentage of subbituminous (i.e., below 20%) without incurring the cost of boiler modifications and fuel handling improvements and (b) while boiler improvements can remove the limitations on the amount of subbituminous coal burned at a unit, they come at a cost ($250/kW) and an associated heat rate penalty (5%). Consideration was given to allowing units that historically had burned more than 20%, but less than 90% subbituminous coal, to burn up to their historic maximum at no additional cost and only incur the additional cost and heat rate penalty when consuming above their historical maximum percent subbituminous use. However, comments (e.g., the 10/11/10 Dairyland Power Cooperative comment EPA-HQ-OAR-2009-0491-2733.1 on Genoa Unit 1) indicated that during the economic recession of 2007, 2008, and 2009 when electricity demand was lower than normal, units burned higher proportions of subbituminous coal without making the investments that would otherwise have been necessary if their generation had been high enough to trigger a capacity derating. During the recession, units were not generating at high enough levels for capacity deratings to become an issue. Taking this into consideration, EPA took the more conservative approach of assuming that unless the unit historically had burned more than 90% subbituminous coal, it had not previously made the investments needed to burn more than 20% subbituminous coal. Response: The specifics of the procedure are as follows: (b) For coal plants that have the option to burn both bituminous and subbituminous coal in EPA Base Case v.4.10_FTransport, those that have burned 90% or more subbituminous coal in 2008, 2009, or first half of 2010 are assumed to have already made the fuel handling and boiler investments needed to burn up to 100% subbituminous coal and would therefore not face any additional costs. In addition, their reported heat rates are assumed to reflect the impact of burning the corresponding proportion of subbituminous coal. EIA Form 423 is used to determine the percent of subbituminous coal burned in 2008, 2009, and first half of 2010. (c) All other units with the option to burn both bituminous and subbituminous coal in EPA Base Case v.4.10, would have the option to burn (i) Less than 20% subbituminous coal without incurring any additional cost or heat rate penalty. 44 ------- (j) Twenty percent (20%) or more subbituminous coal at a cost of $250/kW and a heat rate penalty of 5% to reflect additional fuel handling and boiler modification costs associated with burning higher proportions of subbituminous coal. The $250/kW cost adder is designed to cover boiler modifications or alternative power purchases in lieu of capacity deratings that would otherwise be associated with burning subbituminous coal with its lower heating value relative to bituminous coal. 4.2 Resulting Updates The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case v4.10_FTransport. Add the following paragraph between sections 9.3.9 and 9.4. 9.3.10 Coal Switching Recognizing that boiler modifications and fuel handling enhancements may be required for unrestricted switching from bituminous to subbituminous coal, the following conditions apply in EPA Base Case v.4.10_FTransport to coal plants that have the option to burn both bituminous and subbituminous coal. Those that have burned 90% or more subbituminous coal in 2008, 2009, and first half of 2010 are assumed to have already made the fuel handling and boiler investments needed to burn up to 100% subbituminous coal and would therefore not face any additional costs. In addition, their reported heat rates are assumed to reflect the impact of burning the corresponding proportion of subbituminous coal. EIA Form 423 is used to determine the percent of subbituminous coal burned in 2008, 2009, and first half of 2010. All other units with the option to burn both bituminous and subbituminous coal in EPA Base Case v.4.10_FTransport, are subject to the following conditions: (1) If the unit consumes less than 20% subbituminous coal, no additional cost or heat rate penalty is incurred. (2) If the unit consumes twenty percent (20%) or more subbituminous coal, it incurs a cost of $250/kWand a heat rate penalty of 5% to reflect additional fuel handling and boiler modification costs associated with burning higher proportions of subbituminous coal. The $250/kWcost adder is designed to cover boiler modifications or alternative power purchases in lieu of capacity deratings that would otherwise be associated with burning subbituminous coal with its lower heating value relative to bituminous coal. The heat rate penalty reflects the impact of the higher moisture content subbituminous coal on the unit's heat rate 45 ------- 5 Restrictions on coal choice in 2012 Comment Theme: Some comments indicated that various factors (including coal contracts and boiler engineering considerations) limited the ability of coal units to change coal grades in the short to medium term and requested that the model reflect these limitations. Discussion: In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit's engineering characteristics, the SO2 emissions limits they face, and the historical record of coals burned at the unit. Once the coal assignments are made, no further restrictions are typically placed on the fuels available to the unit. Factors limiting changes is near term coal use were considered technically plausible in the first model run year of 2012. Consequently, EPA incorporated such limitations in 2012 in cases where the affected units were explicitly identified, where sufficient documentation and an adequate explanation of the governing factors were provided, where EPA was not aware of data contradicting the claim, and where the inclusion of the limitation might affect modeling results. Beyond 2012, however, EPA's assessment of industry experience suggested that economic considerations would take precedent over short-term restrictions and that the full choice of previously assigned coals should be re-instated for coal units. This would allow the model to make fuel choices based on economic factors reflecting the tendency of these factors to prevail beyond the short term. Response: (1) If a comment identified specific units that could not change from a specific coal due to short term constraints and generally met the conditions outlined above, the unit's coal assignment in 2012 would be limited to the coal stipulated in the comment. If not explicitly stipulated in the comment, the coal reported most recently at the plant level in EIA Form 926 would be used. If the information was not reported in EIA Form 926, the unit would be assigned the coal grade which would result in an emission rate closest to the SO2 rate reported for the unit in EPA's Emission Tracking System (ETS) 2009. (2) If a comment identified by name a group of units (e.g., by company or by plant name) whose coal choices could not change over the short run, the same procedure as described in item #1 was followed, except that it was applied to all units in the group of units. (3) If a comment did not identify specific units or a specific set of units where coal choices were limited, no change was made. (4) After 2012, such restrictions no longer apply.. Changes to be Incorporated in Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model Add the following paragraph between new section 9.3.10 and before section 9.4. 9.3.11 Short-term restrictions on coal choice In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit's engineering characteristics, the SO2 emissions limits they face, and the historical record of coals burned at the unit. Once the coal assignments are made, no further restrictions are typically placed on the fuels available to the unit. However, coal choice was further restricted in the first model run year (2012) in the modeling horizon in situations where information was provided to EPA indicating that short-term factors (like coal contracts and boiler engineering considerations) limited a unit's choice to a particular assigned coal. Beyond the first model run year the full set of assigned coals was restored in keeping with the underlying modeling assumption that economic considerations prevail over short-term restrictions in the longer term. 46 ------- 9.3.11 Short-term restrictions on coal choice and related issues In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit's engineering characteristics, the SO2 emissions limits they face, and the historical record of coals burned at the unit. Once the coal assignments are made, no further restrictions are typically placed on the fuels available to the unit. However, coal choice was further restricted in the first model run year (2012) in the modeling horizon in situations where information was provided to EPA indicating that short-term factors (like coal contracts and boiler engineering considerations) limited a unit's choice to a particular assigned coal. Beyond the first model run year the full set of assigned coals was restored in keeping with the underlying modeling assumption that economic considerations prevail over short-term restrictions in the longer term. In conjunction with these changes, limits were imposed in fuel assignments at four Texas coal steam plants to increase consistency with reported fuel use at the plants. The percentage of lignite used in the first model run year (2012) was calibrated so that it would not exceed the historical level reported in 2009, the latest year for available fuel data as reported in EIA Form 923. This limit was increased linearly in model run year 2015 so that by model run year 2020 there would no longer be a limit on lignite use. In other words by model run year 2020, the unit could choose to use up to 100% lignite if the model found that this was economically optimal. The four power plants that were affected by this procedure and the specific applicable limits are shown in the following table: Plant Name Big Brown Limestone Martin Lake Monticello Plant ORIS ID 3497 298 6146 6147 Maximum Percent of Heat Input (MMBtu) from Lignite For IPM Run Years Shown 2012 < 50% < 54% < 69% <19% 2015 < 69% <71% < 80% < 50% 2020 <100% <100% <100% <100% In addition, post-modeling quality assurance checks flagged the 100% subbituminous coal consumption projected at the Martin Lake for 2012 as a discrepancy with the high share of lignite use (74% by weight, 69% on an MMBtu heat content basis) that was reported for 2009 at this lignite mine- mouth plant. To increase short-term modeling consistency with the plant's recent operating history, its 2012 SO2 emissions were re-calculated using its 2009 reported SO2 emission rate and its 2012 projected heat input. Post-modeling quality assurance found a similar discrepancy between the short-term projection and operating history at Gibbons Creek (ORIS 6136) Unit 1 where reported SO2 emissions at the unit were indicative either of a unit not operating a scrubber or of a scrubber with a very low SO2 removal efficiency, i.e., producing emission roughly equivalent to the sulfur content of purchased coal as reported in the EIA-923, Since the unit's scrubber had not been designated as "dispatchable" the model was forced to operate it, producing emissions in 2012 and 2014 that were not consistent with the recent operating experience of the unit. To increase short-term modeling consistency with the plant's operating history, its 2012 and 2014 SO2 emissions were re-calculated to factor out the projected reductions from scrubbing. 47 ------- 6 Waste Coal Cost Correction 6.1 Response to the Comments Received Comment Theme: Comments were received indicating that the cost of waste coal in draft EPA Base Case v.4.10 was much higher than actually encountered by buyers. Discussion: Upon investigation it was found that a data entry error had resulted in incorrect waste coal prices. The labeling of the prices in a file obtained by EPA from an outside source had indicated units of 1987 dollars per short ton, which should have been labeled 2008 dollars per short ton. Response: The dollar year labeling error was corrected and costs were then properly converted to 2007 dollars per short ton. The resulting corrected prices were consistent with those noted in the comment. 6.2 Resulting Updates The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case v4.10_FTransport. For waste coal entries only (Coal Supply Region: NA; Coal Grade: WC) replace the previous values shown under the "Cost of Production" with the corrected values (highlighted in yellow in the table below) Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10 1 Waste Coal Entries Only Year 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 Coal Supply Region NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA Coal Grade WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC WC Step Name S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 Heat Content (MMBtu/Ton) 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 Cost of Production (2007$/Ton) Previous 21.9 22.8 23.9 24.3 24.5 24.6 24.6 24.8 25.4 28.8 41.8 22.0 23.2 24.6 25.2 25.4 25.6 25.7 26.0 27.1 32.9 58.7 Corrected 12.7 13.3 13.9 14.2 14.3 14.3 14.3 14.4 14.8 16.7 24.3 12.8 13.5 14.3 14.6 14.8 14.9 15.0 15.1 15.8 19.2 34.2 Coal Production (Million Tons/Year) 6.6 3.9 2.6 0.9 0.3 0.1 0.1 0.3 0.9 2.6 3.9 7.2 4.2 2.8 0.9 0.3 0.2 0.2 0.3 0.9 2.8 4.2 48 ------- Appendix 9-4 Coal Supply Curves in EPA Base Case V, (cont'd) Waste Coal Entries Only 4.10 Year 2020 2020 2020 2020 2020 2020 2020 2020 2020 2020 2020 2030 2030 2030 2030 2030 2030 2030 2030 2030 2030 2030 2040 2040 2040 2040 2040 2040 2040 2040 2040 2040 2040 Coal Supply Region NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA Coal Grade we we we we we we we we we we we we we we we we we we we we we we we we we we we we we we we we we Step Name S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 Heat Content (MMBtu/Ton) 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 Cost of Production (2007$/Ton) Previous 22.1 23.1 24.3 24.8 25.0 25.1 25.2 25.4 26.1 30.1 46.1 22.1 23.0 24.2 24.6 24.8 24.9 24.9 25.1 25.7 29.1 42.3 22.2 23.2 24.4 24.9 25.1 25.1 25.2 25.4 26.2 30.1 45.8 Corrected 12.9 13.5 14.2 14.4 14.5 14.6 14.7 14.8 15.2 17.5 26.9 12.9 13.4 14.1 14.3 14.4 14.5 14.5 14.6 15.0 16.9 24.6 12.9 13.5 14.2 14.5 14.6 14.6 14.7 14.8 15.2 17.5 26.7 Coal Production (Million Tons/Year) 6.8 4.0 2.7 0.9 0.3 0.1 0.1 0.3 0.9 2.7 4.0 6.6 3.9 2.6 0.9 0.3 0.1 0.1 0.3 0.9 2.6 3.9 6.8 4.0 2.6 0.9 0.3 0.1 0.1 0.3 0.9 2.6 4.0 ------- Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10 (cont'd) Waste Coal Entries Only Year 2050 2050 2050 2050 2050 2050 2050 2050 2050 2050 2050 Coal Supply Region NA NA NA NA NA NA NA NA NA NA NA Coal Grade we we we we we we we we we we we Step Name S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 Heat Content (MMBtu/Ton) 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 12.35 Cost of Production (2007$/Ton) Previous 22.2 23.2 24.4 24.9 25.1 25.1 25.2 25.4 26.2 30.1 45.8 Corrected 12.9 13.5 14.2 14.5 14.6 14.6 14.7 14.8 15.2 17.5 26.7 Coal Production (Million Tons/Year) 6.8 4.0 2.6 0.9 0.3 0.1 0.1 0.3 0.9 2.6 4.0 50 ------- 7 Comments Considered but that did not Result in Changes Oil consumption at dual fired (oil/gas) units Comment Theme: When compared with recent operating experience, the extent of oil burned by dual fuel generating units in draft EPA Base Case v.4.10 was considerably lower than some commenters thought it should be. Response: Consideration was given to a number of options for modifying the modeling of oil use at duel fuel units, but it was ultimately decided not to change the previous representation for the following reasons: (1) The underlying factors that could be causing greater oil consumption were very site specific and the information that would allow modeling such occurrences was not available. (2) In the absence of site specific information, imposing generic requirements for pre-specified levels of oil consumption was considered to have more drawbacks than the current representation. (3) Due to their small population, dual fired units are not likely figure significantly in modeling the Transport Rule. Enhanced modeling capability in this regard could be revisited if and when future policies are modeled where oil use by duel fuel units has significant policy implications. Capital cost of Flue Gas Desulfurization (FGD) on units whose capacity is less than 100 MW Comment Theme: Some commenters considered the capital cost assumptions in draft EPA Base Case v.4.10 for retrofitting generating units under 100 MWwith FGD to be too low. For example, one commenter indicated that the v.4.10 FGD retrofit costs for these units should be multiplied by 4. Response: The original cost assumptions were retained. Specifically, the FGD capital cost for units below 100 MW is assumed to be the same as those for 100 MW units. While it is recognized that economies of scale would not be realized by units smaller than 100 MWthat installed a standard FGD dedicated solely to that unit, prior engineering practice indicates a number of ways that costs will be held at the 100 MW level. Such practices include combining the emissions from multiple smaller units into a larger FGD and thereby achieving economy of scale. Another cost controlling approach for achieving economies of scale that has recently been seen in the marketplace is the development of innovative combinations of controls (e.g., dry sorbent injection, alkali injection, and circulating scrubbers) whose overall cost is lower than the sum of each of the constituent controls taken individually. These options provide a sound technical and economic basis for retaining the current approach of determining the capital cost of FGD for the universe of units less than 100 MWin EPA Base Case v.4.10 Selective Catalytic Reduction (SCR) retrofit costs Comment Theme: Assumed SCR retrofit costs are too low in EPA Base Case v.4.10 Response: The SCR and FGD cost assumptions in EPA Base Case v.4.10 were updated in the summer of 2010 based on substantial engineering analyses and market assessments by an independent engineering firm. (This is documented on EPA web site at www.epa.gov/airmarkets/progsregs/epa- ipm/docs/v410/Chapter5.pdf and www.epa.gov/airmarkets/progsregs/epa- ipm/docs/v410/Appendix52A.pdf.) In response to the comments received on SCR costs, EPA reviewed the cost assumptions and concluded not to modify them at this time. Although site specific conditions (which may the basis for the comments) can result in higher costs, the assumptions developed for EPA Base Case v.4.10 were deemed to be current, to have a strong economic and engineering basis, and to be applicable across the fleet of U.S. generating units. 30 year book life for emission control retrofits Comment Theme: The 30 year book life assumed for retrofits in v.4.10 is too long. Many retrofits are on smaller and older units where an additional 20-30 year of life is not likely. Response: For several reasons, the 30 year book life assumption for emission control retrofits was retained. First, as described in section 4.2.8 and Table 4-10 of Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model (www.epa.gov/airmarkets/progsregs/epa- 51 ------- ipm/docs/v410/Chapter4.pdf), existing units in EPA Base Case v.4.10 incur a life extension cost if they remain in operation past their current expected lifespan. (For existing coal units this occurs when they pass age 40.) The assumption of a 30-year book life for retrofits is consistent with these life extension provisions which allow existing units to stay in operation throughout the 2012-2050 modeling time horizon, rather than forcing them retire upon reaching a pre-specified expected lifespan. The 30-year book life is in line with the 30-year design life typically specified in purchase agreements to ensure the quality of materials and cyclic fatigue life of power boilers, turbines and associated emission control systems. It is also well within the service life of such equipment which extends far beyond 30 years when generally accepted maintenance practices are followed. Must run, black start, and spinning reserve units Comment Theme: The model retires units that some commenters identified as being prevented from retiring for reliability purposes Response: There are several reasons for retaining the current approach that does not attempt to account for "must run" units and does not prevent such units from retiring. First, for competitive business reasons, a comprehensive listing of must-run units is not available from either public or private sources. Limiting the "must run" designation only to those units identified in comments would introduce inconsistency across the universe of units. Second, there is no technically sound approach for defining the extent of operation of a "must run" unit. Finally, there is no technical basis for defining the period over which the "must run" designation would last. This is a particularly important issue in view of the long modeling time horizon (2012 to 2050) in EPA Base Case v.4.10. Availability assumptions for existing coal units Comment Theme: The availability assumption for coal units in EPA Base Case v.4.10 should not be based on historical capacity factor data from the Energy Information Administration's Annual Energy Outlook 2010 (AEO 2010 but on availabilities in NERC GADS as was done in previous EPA base cases (including v.3.0.2 EISA) Response: Rather than using NERC GADS availabilities, EPA Base Case v.4.10 adopts an approach similar to AEO 2010 of using historical capacity factors to define the availabilities of existing coal units. The change was a result of analysis that showed that for a large portion of the coal fleet, actual capacity factors for existing coal units fell below the availabilities in NERC GADS. It is also based on an assessment that indicated that the system-level availabilities that are found in NERC GADS were not entirely comparable to the plant level availabilities required for IPM. Comparing previous base case projections to historical data showed tendencies to over-project coal consumption and under-project gas consumption as a result of the use of the GADS availabilities. Consequently, v.4.10 adopts the approach used in AEO 2010 and other modeling efforts which tie availability assumptions for existing coal units to historical capacity factors (plus a growth assumption for capacity factors below 75% and an upper cut off of 95% to reflect an assumed 5% force outage rate). The historical capacity factors used to derive the availability assumptions in EPA Base Case v.4.10 were obtained from AEO 2010. 52 ------- Addenda - Notes on various modeling assumptions Though not necessarily responses to comments received on the Transport Rule or NODA, the following features of EPA Base Case v.4.10_FTransport are annotated below for purposes of documentation. 1. Dry Sorbent Injection (DSI) and Fabric Filter Cost Development Section 5.5.3.2 and Appendix 5- 4 on dry sorbent injection and section 5.5.4 and Appendix 5-5 on fabric filter cost development are incorporated below from the Documentation Supplement for EPA Base Case v.4.10_Rox- Updates for Proposed Toxics Rule. Minor changes have been made to the text to highlight aspects particularly relevant to the Final Transport Rule, i.e., the use of DSI in combination a fabric filter as a retrofit option for SO2 control. 2. Variable Operating and Maintenance (VOM) Cost of Dry Sorbent Injection (DSI) Retrofits: In modeling the Final Transport Rule (i.e., in EPA Base Case v.4.10_FTransport), DSI is provided as a retrofit for units burning coals with an SO2 content of less than 2 Ibs/mmBtu and is assumed to be retrofit in conjunction with a fabric filter. When retrofit on units with a pre-existing fabric filter, it is assumed that no ESP is present and that the DSI is installed upstream of the FF. Consequently, the fly ash that is caught in the fabric filter will be contaminated by the sorbent and not marketable. Since the entire combined fly ash, reaction products, and unreacted sorbent mass will have to be disposed, the full DSI capital, FOM, and VOM costs are incurred. In contrast, when DSI is retrofit on units with no pre-existing fabric filter, it is assumed that the DSI will be installed after the ESP (which, in the absence of a FF, will be present for PM control) and upstream of the FF which is installed in conjunction with the DSI. Since the upstream ESP will capture the fly ash before it arrives at the DSI, it will not be contaminated by the sorbent and can be sold rather than disposed. (Note: No credit for fly ash sales is taken into account in IPM.) Only the reaction products and unreacted sorbent which is caught in the FF will need to be landfilled. Since the waste disposal cost only applies to the sorbent, there is a 35% reduction in VOM. In this situation the reduced VOM and standard capital and FOM costs are incurred for the DSI retrofit plus the capital, FOM, and VOM costs for the associated FF. 3. Updated Appendices 3-2 through 3-4: These appendices, which are included below, show the state power sector air emissions regulations (Appendix 3-2), NSR settlements (Appendix 3-3) and state settlements (Appendix 3-4) that are represented in EPA Base Case v.4.10_FTransport. 4. 2012 Emission Control Retrofits: In EPA's modeling for the Final Transport Rule, emission controls in response to the Transport Rule are not allowed to be occur in 2012, the first model run year, because of insufficient lead time to install flue gas desulfurization (FGD) for SO2 and selective catalytic reduction (SCR) for NOX control by 2012. However, in order not to overstate the emission levels without the Transport Rule, emission controls are allowed to occur in 2012 in response to non- Transport Rule legal requirements that were in place in 2010 or earlier. While the specific controls that the model builds and operates (or partially operates) may not correspond to those actually installed as part of a source's compliance strategy, they should capture valid levels of emission reductions that can be expected to be achieved in complying with binding non-Transport Rule agreements or regulations. This dual approach to 2012 retrofits is implemented by allowing the model to install emission control retrofits in 2012 in the base case (which does not include Transport Rule but does include binding non-Transport Rule legal requirements). Any 2012 retrofits occurring in the base case are then carried over into the "Remedy" policy case (which includes the Final Transport Rule emission requirements), but the model is not allowed to install any additional 2012 emission controls (which would come in response to the Transport Rule requirements). 5. Emission Controls in IPM Parsed Files: Users are sometimes unclear about the origins of the advanced post-combustion emission controls (e.g., FGD or SCR) that appear in the "parsed files" for 53 ------- an IPM model run. These controls originate in one of four possible sources. (1) Most existing controls are the same as those found in the National Electric Energy Data System (NEEDS), the database of existing and planned/committed units which serves as the starting point for setting up EPA's base and policy cases using IPM. For the Final Transport Rule existing controls are those present in 2011 or earlier. (2) A small number of existing emission controls appear in parsed files, but are not found in NEEDS. They are controls that became known after the NEEDS database was "frozen" for purposes of setting up a family of model runs. Rather than appearing in NEEDS, they are represented directly in IPM as emission control retrofit options available from the start of the modeling time horizon. They can either be forced to operate through the imposition of modeling constraints (in which case they are termed "non-dispatchable" controls) or be left for the model to determine endogenously whether emission policies require them to operate (in which case they are termed "dispatchable" controls). (3) Some generating units have either (a) an existing legal requirement, such as a consent decree or state rule requiring the installation of a control by a particular date post 2011, or (b) have publically announced or submitted comment noting the installation and/or beginning of construction of a control for post 2011 start-up. In instances where the control is expected in the future, but not present by 2011 or earlier, the control is represented directly in IPM as a retrofit option which is either forced by a modeling constraint to be installed and operate (non-dispatchable controls) or left for the model to determine whether they need to operate (dispatchable controls). These controls appear in the model run year corresponding to the year they are expected to operate (typically 2012 or 2015) both in IPM outputs and parsed files. They do not appear in NEEDS (since they were not present prior to 2012). (4) The remaining emission controls found in parsed files are those that the model builds as part of the optimal (most cost effective) solution in response to all the requirements faced by the electric power system represented in the model. 6. Mercury Emission Modification Factor (EMF) for Waste Coal Units: In EPA Base Case v.4.10_FTransport (as in the base case for the proposed Mercury and Air Toxics Standards Rule - EPA Base Case v.4.10_PTox), all waste coal units are assumed to have a mercury EMF of 0.02. 7. Carbon dioxide (CO2) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization (FGD) System for Sulfur Dioxide (SO2) Control: In EPA applications of IPM the chemical reactions in a limestone forced oxidation (LSFO) system (also known as a wet FGD or wet scrubber) are assumed to cause CO2 increases according to the following equation: CO2 increase in % of total CO2 from fuel = 0.35 X SO2 emission rate of the fuel (in Ib/MMBtu) - 0.02 For example, for coal with an SO2 emission factor of 4.3 Ib/MMBtu, the increase in CO2 is 1.485%. In contrast to LSFO, there is no representation of direct emissions of CO2 or other greenhouse gases from the other control technologies in IPM. These include limestone spray dryers (LSD) for SO2 control, dry sorbent injection (DSI) forSO2 and hydrogen chloride (HCI) control, selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) for NOX control, and activated carbon injection (ACI) for mercury control. 54 ------- Addendum A — Dry Sorbent Injection (DSI) and Fabric Filter Cost Development in EPA Base Case v.4.10_FTransport Note: The numbering of the sections and tables in this addendum is the same as found in the Documentation Supplement for EPA Base Case v.4.10_Ptox - Updates for Proposed Toxics Rule, where this material originally appeared. 55 ------- Table 5-21 Summary of Retrofit SO2 (and HCI) Emission Control Performance Assumptions in v4.10_FTransport Performance Assumptions Percent Removal Capacity Penalty Heat Rate Penalty Cost (2007$) Applicability Sulfur Content Applicability Applicable Coal Types Limestone Forced Oxidation (LSFO) SO2 96% with a floor of 0.06 Ibs/MMBtu HCI 99% with a floor of 0.0001 Ibs/MMBtu -1 .65% 1 .68% See Table 5-3 and 5-4 Units > 25 MW BA, BB, BD, BE, BG, BH, SA, SB, SD, LD, LE, and LG Lime Spray Dryer (LSD) SO2 92% with a floor of 0.065 Ibs/MMBtu HCI 99% with a floor of 0.0001 Ibs/MMBtu -0.70% 0.71% See Table 5-3 and 5-4 Units > 25 MW Coals < 2.0% Sulfur by Weight BA, BB, BD, BE, SA, SB, SD, LD, LE, and LG Dry Sorbent Injection (DSI)1 SO2 With fabric filter: 70% With an electrostatic percipitator2: 50% HCI With fabric filter: 90% with a floor of 0.0001 Ibs/MMBtu With an electrostatic percipitator2: 60% with a floor of 0.0001 Ibs/MMBtu -0.65% 0.65% See Tables D and E Units > 25 MW Coals < 2.0 Ib/mmBtu of SO2 BA, BB, BD, SA, SB, SD, and LD Notes 1. The cost and performance values shown in this table apply to existing units with pre-existing fabric filters or electrostatic precipitators. Units with neither ESP nor FF are assumed to have to install a fabric filter in order to qualify for the DSI retrofit. 2. The option to retrofit DSI on existing units with ESP was not offered in the runs performed for the current rulemaking. 56 ------- 5.5.3.2 Dry Sorbent Injection EPA Base Case v4.10_FTransport includes dry sorbent injection (DSI) as a retrofit option for achieving (in combination with a particulate control device) SO2 (and HCI) removal. With DSI a dry sorbent is injected into the flue gas duct where it reacts with the SO2 and HCI in the flue gas to form a compound, which is then captured in a downstream fabric filter or electrostatic precipitator (ESP) and disposed of as waste. (A sorbent is a material that takes up another substance by either adsorption on its surface or absorption internally or in solution. A sorbent may also chemically react with another substance.) The sorbent assumed in the cost and performance characterization discussed in this section is trona, a sodium-rich material with major underground deposits found in Sweetwater County, Wyoming. Trona is typically delivered with an average particle size of 30 urn diameter, but can be reduced to about 15 urn through onsite in-line milling to increase its surface area and capture capability. Removal rate assumptions: The removal rate assumptions for DSI are summarized in Table 5-21. The assumptions shown in the last two columns of Table 5-21 were derived from assessments by EPA engineering staff in consultation with Sargent & Lundy. As indicated in this table, the assumed SO2 removal rate for DSI + ESP is 50% and for DSI + fabric filter is 70%. The assumed HCI removal rate is 60% for DSI + ESP and 90% for DSI + fabric filter. (This is noted in the next-to-the-last column in Table 5-21.) Although the option to retrofit DSI on existing units with ESP is shown in Table 5-21 it was not offered in the runs performed for the current rulemaking. Methodology for Obtaining DSI Control Costs: The engineering firm of Sargent & Lundy, whose analyses were used to update the cost of SO2 and post-combustion NOX controls in EPA Base Case , v4.10, performed similar engineering assessments of the cost of DSI retrofits with two alternative, associated particulate control devices, i.e., ESP and fabric filter (also called a "baghouse"). Their analysis of DSI noted that the cost drivers of DSI are quite different from those of wet or dry FGD. Whereas plant size and coal sulfur rates are key underlying determinants of FGD cost, sorbent feed rate and fly ash waste handling are the main drivers of the capital cost of DSI with plant size and coal sulfur rates playing a secondary role. Sorbent feed rate determines the amount of sorbent required and the size and extensiveness of the DSI installation. The sorbent feed rate needed to achieve a specified percent SO2 or HCI removal4 is firstly a function of the flue gas SO2 rate (which, in turn, is a function of the sulfur content of the coal burned, expressed in Ibs of SO2/mmBtu ), the unit's size and heat rate, and the sorbent particle size (which determines whether in-line milling is needed). The sorbent feed rate is also a function of the residence time of the sorbent in the flue gas stream and the extent of mixing and penetration of the sorbent in the flue gas. Residence time, penetration, and mixing are largely dependent on the type of particulate control device use (electrostatic precipitator or fabric filter). In EPA Base Case v4.10_FTransport the DSI sorbent feed rate and variable O&M costs are based on assumptions that a fabric filter and in-line trona milling are used, and that the SO2 removal rate is 60%. The corresponding HCI removal effect is assumed to be 90%, based on information from Solvay Chemicals (H. Davidson, Dry Sorbent Injection for Multi-pollutant Control Case Study, CIBO IECT VIM, August 2010). The cost of fly ash waste handling, the other key contributorto DSI cost, is a function of the type of particulate capture device and the flue gas SO2 rate (which, as noted above, is itself a function of the 4 For purposes of engineering calculations the percent removal is often translated into a corresponding "Normalized Stoichiometric Ratio" (NSR) associated with a particular percent removal, where the NSR is defined as / moles of sobent inject \molesofS02influegas 1 (theoretical moles of sorbent required) 57 ------- sulfur content of the coal and the unit's size and heat rate). Fly ash waste handling costs are also a function of the ash content and the higher heating value (HHV) of the coal. The governing variables of the key capital cost components of DSI are presented in Table 5-22. Table 5-22. Capital Cost Components and Their Governing Variables for HCI Removal with DSI. Module Sorbent Feed Handling Fly Ash Waste Handling Retrofit Difficulty (1 = average) X X Particulate Capture Type (ESP or Baghouse) X Sorbent Particle Size Require- ment (milled or unmilled) X Heat Rate (Btu/ kWh) X X S02 Rate of coal (Ib/ MMBtu) X Ash Content of Coal (percent) X Higher Heating Value (HHV) of Coal (Btu/lb) X Unit Size (MW) X X Once the key variables for the two DSI modules are identified, they are used to derive costs for each base module component. These costs are then summed to obtain total bare module costs. The base installed cost for DSI includes • All equipment • Installation • Buildings • Foundations • Electrical • Average retrofit difficulty • In-line milling equipment is assumed to be included This total is increased by 15% to account for additional engineering and construction management costs, labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account for owner's home office costs, i.e., owner's engineering, management, and procurement costs. Since DSI installations are expected to be completed in less than a year, no Allowance for Funds used During Construction (AFUDC) is provided for DSI. The cost resulting from these calculations is the capital cost factor (expressed in $/kW) that is used in EPA Base Case v4.10_FTransport. Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an emission control device. They are proportional to the electrical energy produced and are expressed in units of $ per MWh. For DSI, Sargent & Lundy identified three components of VOM: (a) costs for sorbent usage, (b) costs associated with waste production and disposal, (c) cost of additional power required to run the DSI control (often called the "parasitic load"). For DSI, sorbent usage is a function of the "Normalized Stoichiometric Ratio" and SO2 feed rate. As noted above the feed rate is a function of the SO2 rate of the coal and the unit's size and heat rate. Total waste production involves the production of both reacted and unreacted sorbent and fly ash. 58 ------- Sorbent waste is a function of the sorbent feed rate with an adjustment for excess sorbent feed. Use of DSI makes the fly ash unsalable, which means that any fly ash produced must be landfilled along with the reacted and unreacted sorbent waste. Typical ash contents for each fuel are used to calculate a total fly ash production rate. The fly ash production is added to the sorbent waste to account for the total waste stream for the VOM analysis. For purposes of modeling, the total VOM includes the first two component costs noted in the previous paragraph, i.e., the costs for sorbent usage and the costs associated with waste production and disposal,. The last component- cost of additional power- is factored into IPM, not in the VOM value, but through a capacity and heat rate penalty as described in the next paragraph. Capacity and Heat Rate Penalty: The amount of electrical power required to operate the DSI is represented through a reduction in the amount of electricity that is available for sale to the grid. For example, if 0.65% of the unit's electrical generation is needed to operate DSI, the generating unit's capacity is reduced by 0.65%. This is the "capacity penalty." At the same time, to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for operating the DSI device), the unit's heat rate is scaled up such that a comparable reduction (0.65% in the previous example) in the new higher heat rate yields the original heat rate. The factor used to scale up the original heat rate is called "heat rate penalty." It is a modeling procedure only and does not represent an increase in the unit's actual heat rate (i.e., a decrease in the unit's generation efficiency). As was the case for FGD in EPA Base Case v4.10, specific DSI heat rate and capacity penalties are calculated for each installation. For DSI the installation specific calculations take into account the additional power required by air blowers for the injection system, drying equipment for the transport air, and in-line milling equipment, if required. Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining an emission control. They represent expenses incurred regardless of the extent to which the emission control system is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent & Lundy took into account labor and materials costs associated with operations, maintenance, and administrative functions. The following assumptions were made: • FOM for operations is based on the number of operators needed which is a function of the size (i.e., MW capacity) of the generating unit. In general for DSI two (2) additional operators are assumed to be needed. • FOM for maintenance is a direct function of the DSI capital cost. • FOM for administration is a function of the FOM for operations and maintenance. Table 5-23 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalties of a DSI retrofit for an illustrative and representative set of generating units with the capacities and heat rates indicated. Illustration worksheets of the detailed calculations performed to obtain the capital, VOM, and FOM costs for an example DSI appear in Appendix 5-4. The worksheets were developed by Sargent & Lundy5. 5These worksheets were extracted from Sargent & Lundy LLC, IPM Model - Revisions to Cost and Performance forAPC Technologies: Complete Dry Sorbent Injection Cost Development Methodology (Project 12301-007), May 2010. The complete report is available for review and downloading at www.epa.qov/airmarkets/proqsreqs/epa-ipm/. 59 ------- Table 5-23. Illustrative Dry Sorbent Injection (DSI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_FTransport Control Type DSI - FF Assuming Bituminous Coal DSI - ESP Assuming Bituminous Coal Heat Rate (Btu/ kWh) 9,000 10,000 11,000 9,000 10,000 11,000 S02 Rate (Ib/ MMBtu) 2.0 2.0 2.0 2.0 2.0 2.0 Capacity Penalty 0.64 0.71 0.79 1.08 1.20 1.32 Heat Rate Penalty 0.65 0.72 0.79 1.10 1.22 1.34 Variable O&M (mills/ kWh) 6.05 6.72 7.40 11.23 12.47 13.72 Capacity (MW) 100 yr) 122 2.25 125 2.28 129 2.30 141 2.41 145 2.44 149 2.48 300 yr) 55 0.87 57 0.89 59 0.90 64 0.94 66 0.96 68 0.98 500 yr) 38 0.57 40 0.58 41 0.59 47 0.64 52 0.68 58 0.73 700 yr) 30 0.43 31 0.43 34 0.46 47 0.57 52 0.61 58 0.65 1000 ($/kw> (*™~ 28 0.36 31 0.38 34 0.41 47 0.52 52 0.56 58 0.60 60 ------- 5.5.4 Fabric Filter (Baghouse) Cost Development Fabric filters are not endogenously modeled as a separate retrofit option in EPA Base Case v4.10_FTransport, but are accounted for as a cost adder when installed in conjunction with DSI. In EPA Base Case v4.10_FTransport, an existing or new fabric filter particulate control device is a pre-condition for installing a DSI retrofit. Any unit that is retrofit by the model with DSI and does not have an existing fabric filter incurs the cost of installing a fabric filter. This cost is added to the DSI costs discussed in section 5.5.3.2. This section describes the methodology used by Sargent & Lundy to derive the cost of a fabric filter. The engineering cost analysis is based on a pulse-jet fabric filter which collects particulate matter on a fabric bag and uses air pulses to dislodge the particulate from the bag surface and collect it in hoppers for removal via an ash handling system to a silo. This is a mature technology that has been operating commercially for more than 25 years. "Baghouse" and "fabric filters" are used interchangeably to refer to such installations. Capital Cost: Two governing variables are used to derive the bare module capital cost of a fabric filter. The first of these is the "air-to-cloth" (A/C) ratio. The major driver of fabric filter capital cost, the A/C ratio is defined as the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, ACFM) of flue gas entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater the area of the cloth required and the higher the cost for a given volumetric flow. The other determinant of capital cost is the flue gas volumetric flow rate (in ACFM) which is a function of the type of coal burned and the unit's size and heat rate. The capital cost for fabric filters include: • Duct work modifications, • Foundations, • Structural steel, • Induced draft (ID) fan modifications or new booster fans, and • Electrical modifications. After the bare installed total capital cost is calculated, it is increased by 20% to account for additional engineering and construction management costs, labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account for owner's home office costs, i.e., owner's engineering, management, and procurement costs, and by another 6% to account for Allowance for Funds used During Construction (AFUDC) which is premised on a 2-year project duration. The cost resulting from these calculations is the capital cost factor (expressed in $/kW). Fabric filter capital costs are implemented in EPA Base Case v4.10_FTransport as an FOM adder. Plants that install fabric filters incur a total FOM charge which includes the true FOM associated with the fabric filter plus a capital cost FOM Adder derived by multiplying the capital cost by a capital charge rate of 11.3%, i.e., Total FOM = True FOM + Capital Cost FOM Adder where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3% In EPA Base Case v4.10_FTransport the capital cost of a fabric filter is based on the use of a "polishing" fabric filter designed with A/C=6.0. This basis results in a capital cost that is at least 10% less than the cost of a design with A/C=4.0, and assumes that the existing ESP remains in place and active. 61 ------- Variable Operating and Maintenance Costs (VOM): For fabric filters the VOM is strictly a function of the costs of the fabric filter bag and cage translated in a $/MWhr cost based on the filter and bag replacement cycle for a specified A/C ratio. For units whose A/C ratio = 6.0, the replacement cycle for the bag is 3 years and the cage is 9 years, whereas for units whose A/C ratio = 4.0, the bag and cage replacement cycles are 5 and 10 years respectively. Capacity and Heat Rate Penalty: Conceptually, the capacity and heat rate penalties for fabric filters represent the amount of electrical power required to operate the baghouse and are calculated by the same procedure used when calculating the capacity and heat rate penalty for DSI as described in section 5.5.3.2. The resulting capacity and heat rate penalties are both 0.6%. However, since fabric filters were not endogenously modeled as a retrofit option, but simply added to the DSI costs for generating units that do not have an existing baghouse, the capacity and heat rate penalties described here were not factored into the representation of fabric filters in EPA Base Case v4.10_FTransport. Fixed Operating and Maintenance Costs (FOM): Sargent & Lundy's engineering analysis indicated that no additional operations staff would be required for a baghouse. Consequently the FOM strictly includes two components: • FOM for maintenance is a direct function of the DSI capital cost. • FOM for administration is a function of the FOM for operations (which is zero) and maintenance. Table 5-24 presents the capital, VOM, and FOM costs for fabric filters as represented in EPA Base Case v4.10_FTransport for an illustrative set of generating units with a representative range of capacities and heat rates. Worksheets illustrating the detailed calculations performed to obtain the capital, VOM, and FOM costs for two example fabric filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) appear in Appendix 5-5. The worksheets were developed by Sargent & Lundy6. 6 These worksheets were extracted from Sargent & Lundy LLC, IPM Model - Revisions to Cost and Performance forAPC Technologies: Particulate Control Cost Development Methodology (Project 12301- 009), October 2010. The complete report is available for review and downloading at www.epa.qov/airmarkets/proqsreqs/epa-ipm/. 62 ------- Table 5-24. Illustrative Fabric Filter (Baghouse) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_FTransport Coal Type Bituminous Heat Rate (Btu/ kWh) 9,000 10,000 11,000 Capacity Penalty 0.60 Heat Rate Penalty 0.60 Variable O&M (mills/ kWh) 0.15 Capacity (MW) 100 yr) 188 0.8 205 0.9 221 0.9 300 ($/°kw) <$;™- 153 0.6 167 0.7 180 0.8 500 ($/°kw) <$;™- 139 0.6 151 0.6 163 0.7 700 ($/°kw) <$;™- 130 0.6 141 0.6 153 0.6 1000 ($/°kw) <$;™- 122 0.5 132 0.6 143 0.6 Notes on Implementation 1. Plant specific fabric filter capital costs shown in this table are implemented in EPA Base Case v4.10_FTransport as an FOM adder. Plants that install fabric filters incur a total FOM charge which includes the true FOM component shown in the above table plus a capital cost FOM Adder derived by multiplying the capital cost in the table above by a capital charge rate 11.3%, i.e., Total FOM = True FOM + Capital Cost FOM Adder where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%. Plants that install fabric filters also incur the additional VOM costs shown in the above table. 2. Since the fabric filter costs were not endogenously modeled as a retrofit option, the capacity and heat rate penalties shown in the above table were not represented in the model. 63 ------- Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCI (and SO2) Emissions Control in EPA Base Case v4.10_FTransport ^il P 11^^- Complete Dry Sorbent Injection Cost Development Methodology - Final Table 1. Example Complete Cost Estimate for a DSI System * mutate 3*jiijn»3)E4i T- ' SB „, rai " itSMJjl ' I^Tp^-f i ,i ..« »-* 'P.IV } V"*1 'a T J -feV n, ^ ..„ "TTT^^^T™™™™™™™"^^ » — : — , lUlt P Bfftil f O TfM • ". ^ t-»i * ?y IT -! rt i . - .t- r ».n. mtj E'u.* s *.»• .-.H , V_- : 3>- ^•*3 9iT£f J >, * » •RUE * -i li!j^_. •-• 1* »« '^^ «1 i im. ff '** • *:_.' — jwtj *- _i i-" jii'ajB -ef^! has « W="" * » : *J>^ ^1 t*** i- -1 F* ^ _! 9^>- ,,, ,.-'( t ^r-iJ" — if w «-.« T «.t ( j' £; * * t « * ( "f •»*! }- t- - t~t •? * ! "K !,!',: -.v,r i1 M.1:1.^ . f,"-: v;i*^ 1';:. , ' jj «a ! " ^ i ,i t" i,. » '-",""1 fe. , i^ik,^. . ;-»^ r.rar, «*.- ,..,.-, -, ^.^P^, .„ ::.„ .-.-. •«".)•'•.... i i . w .1 I « 5l»iM ta U»M) In rr«»l IriM i,. .-1..1, • -h^-" Costs art all basfii on 2910 dollars .,_„, :. HI * - S «' t*i • • t! * .. i * "" ""*" """ " -• • "I 1 - • -' -' " '- " I* S-i dCE.CC TPC ! TPC | rK iZwra fsi ««; nsi 1 ',* 64 ------- Complete Dry Sorbeot Injection Cost Development Methodology -Final ?.'gnia? atraft *as a ^i:tg ' 3 S-v -r' 1J ^- Tr -R3 . 1 - A. Sfc^ttld t>eii**rt H -4JI ,?'..'«• j -at. ail bas»d on 201C dolln eoit FCHO SJ:Wj,r> 11 ; 02! Fs f,Ji Td¥ Fwri OgM -iOM S*f fc *u< Ftevec ^ 65 ------- Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) in EPA Base Case v4.10_FTransport Table 1. Example Complete C ost Estimate for a 4.0 A'C Bughouse Instillation (Costs are aD based on 2009 dollars) E^ L- al Cd. tirtihuii *.S.JB. b.^t a- SU ;I. - ikb lia- «!«e«8l inpul. ? ir- I i +> ^ * i *ft |^j <•• cere ' En + Hi •*- c i * ca fCf.1O'«C JSTOMM : ' rniMM * FDH.ft Mr i I •*»! ' r " -:• A»i.i£r-Cii4h m^f :>CM,l - A Q ^'-fa-^ telfi Table 2. Example Complete Cost Estimate for a 6,0 A/C Biishonselnstalladon (Cost^ are all based on 2009 dollars) I'ifi^-A r 1 iff , rtn •, , i, _*. 1 s^^. " _"fl v .01 I^Jft" ** «r V " f 'fflTJ? 1^3" ^ " -L^ f>5 flW* &UK f*0»Bt '" ""' -•%-!• -f •r*i * -5 i a* Hi'* " C! E F N J )> M i"f ' ^. ^....^ 3' it (jrfrrn 1^1 , ,\f,3 -•5,^ icn ftr*if) t •*• v « ' L" i * ?>"£ ""*;' t"frU L :K »M5 w fV! -i-S* l-p,' 1.*- 1 |^» — '.jMTpj' '^r i-0 f 3n ', ,-,•" P«P ".- >! - A ~'n 4rr *i7* . If 'SB -31 J" A _ IS; J. ^j-s.^u^SfisMilbHs-s^Sa-mcxlWir^jl jrf - raU a; , lr^ nbw^ll^ TPC {|> a CECC * B^ + U + TPC ^>KWl • ! . L U [.* sJ B i j A 1 -*, ! t-« (. *1 ati » 1 )| (-l.fi i-*(- « * » ^-vfi) rt**1" it* VCf.B 5WsV>-,j - rt~S - 6 5 Ait %-Dy^. !^^ 3 DC-£ E - -i VOW (ifrlWh) = VOMB 66 0 -S3 012 ------- Addendum B — Representation of State Electric Power Emission Regulations (Appendix 3-2), New Source Review (NSR) Settlements (Appendix 3-3), and State Settlements (Appendix 3-4) in EPA Base Case v.4.10_FTransport Note: The numbering of the appendices in this addendum is the same as found in the Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, where an earlier version of these appendices previously appeared. 67 ------- Appendices 3-2 (State Regulations), 3-3 (NSR Settlements), and 3-4 (State Settlements) The tables of State Power Sector Regulations (Appendix 3-2), New Source Review Settlements (Appendix 3-3), and State Settlements (Appendix 3-4) were updated to reflect changes that had occurred since the provisions had been incorporated in EPA Base Case v4.10. The updated tables are included below. Appendix 3-2 State Power Sector Regulations included in EPA Base Case v4.10_FTransport State/Region Alabama Arizona California Colorado Connecticut Delaware Bill Alabama Administrative Code Chapter 335-3-8 Title 18, Chapter 2, Article 7 CA Reclaim Market 40C.F.R. Part 60 Executive Order 19 and Regulations of Connecticut State Agencies (RCSA) 22a-1 74-22 Executive Order 19, RCSA22a-198& Connecticut General Statues (CGS) 22a- 198 Public Act No. 03-72 &RCSA22a-198 Regulation 1148: Control of Stationary Combustion Turbine ECU Emissions Regulation No. 1146: Electric Generating Unit (ECU) Multi- Pollutant Regulation Emission Type NOX Hg NOX S02 Hg NOX SO2 Hg NOX NOX S02 Emission Specifications 0.02 Ibs/MMBtu annual PPMDV for combined cycle EGUs which commenced operation after April 1 , 2003 90% removal of Hg content of fuel or 0.0087 Ib/GWH-hr annual reduction for all non-cogen coal units > 25 MW 9.68 MTons annual cap for list of entities in Appendix A of "Annual RECLAIM Audit Market Report for the Compliance Year 2005" (304 entities) 4.292 MTons annual cap for list of entities in Appendix A of "Annual RECLAIM Audit Market Report for the Compliance Year 2005" (304 entities) 201 2 & 201 3: 80% reduction of Hg content of fuel or 0.01 74 Ib/GW-hr annual reduction for Pawnee Station 1 and Rawhide Station 101 201 4 through 201 6: 80% reduction of Hg content of fuel or 0.01 74 Ib/GW-hr annual reduction for all coal units > 25 MW 2017 onwards: 90% reduction of Hg content of fuel or 0.0087 Ib/GW-hr annual reduction for all coal units > 25 MW 0.1 5 Ibs/MMBtu rate limit in the winter season for all fossil units > 15 MW 0.33 Ibs/MMBtu annual rate limit for all Title IV sources > 15 MW 0.55 Ibs/MMBtu annual rate limit for all non-Title IV sources > 15 MW 90% removal of Hg content of fuel or 0.0087 Ib/GW- hr annual reduction for all coal-fired units 0.19 Ibs/MMBtu ozone season PPMDV for stationary, liquid fuel fired CT EGUs >1 MW 0.39 Ibs/MMBtu ozone season PPMDV for stationary, gas fuel fired CT EGUs >1 MW 0.125 Ibs/MMBtu rate limit of NOxannually for all coal and residual-oil fired units > 25 MW 0.26 Ibs/MMBtu annual rate limit for coal and residual-oil fired units > 25 MW Implementation Status 2003 2017 1994 2012 2003 2008 2009 2009 68 ------- State/Region Georgia Illinois Kansas Louisiana Maine Bill Multipollutant Control for Electric Utility Steam Generating Units Title 35, Section 217.706 Title 35, Part 225, Subpart B: Control of Hg Emissions from Coal Fired Electric Generation Units Title 35 Part 225; Subpart F: Combined Pollutant Standards NOX Emission Reduction Rule, K.A.R. 28-1 9-71 3a. Title 33 Part III - Chapter 22, Control of Emissions of Nitrogen Oxides Title 33 Part III - Chapter 15, Emission Standards for Sulfur Dioxide Chapter 145 NOX Control Program Statue 585-B Title 38, Chapter 4: Protection and Improvement of Air Emission Type Hg SCR, FGD, and Sorbent Injection Baghouse controls to be installed NOX NOX SO2 Hg NOX SO2 Hg NOX SO2 NOX NOX Hg Emission Specifications 201 2: 80% removal of Hg content of fuel or 0.01 74 Ib/GW-hr annual reduction for all coal units > 25 MW 2013 onwards: 90% removal of Hg content of fuel or 0.0087 Ib/GW-hr annual reduction for all coal units > 25 MW The following plants must install controls: Bowen, Branch, Hammond, McDonough, Scherer, Wansley, and Yates 0.25 Ibs/MMBtu summer season rate limit for all fossil units > 25 MW 0.1 1 Ibs/MMBtu annual rate limit and ozone season rate limit for all Dynergy and Ameren coal steam units > 25 MW 201 3 & 201 4: 0.33 Ibs/MMBtu annual rate limit for all Dynergy and Ameren coal steam units > 25 MW 2015 onwards: 0.25 Ibs/MMBtu annual rate limit for all Dynergy and Ameren coal steam units > 25 MW 90% removal of Hg content of fuel or 0.08 Ibs/GW-hr annual reduction for all Ameren and Dynergy coal units > 25 MW 0.1 1 Ibs/MMBtu ozone season and annual rate limit for all specified Midwest Gen coal steam units 0.44 Ibs/MMBtu annual rate limit in 2013, decreasing annually to 0.11 Ibs/MMBtu in 2019 for all specified Midwest Gen coal steam units 90% removal of Hg content of fuel or 0.08 Ibs/GWh annual reduction for all specified Midwest Gen coal steam units 0.20 Ibs/MMBtu annual rate limit for Quindaro Unit 2 and 0.26 Ibs/MMBtu annual rate limit for Nearman Unit 1. 1 .2 Ibs/MMBtu ozone season PPMDV for all single point sources that emit or have the potential to emit 5 tons or more of SO2 into the atmosphere Various annual rate limits depending on plant and fuel type for facilities within the Baton Rouge Nonatiainment Area that collectively have the potential to emit 25 tons or more per year of NOX or facilities within the Region of Influence that collectively have the potential to emit 50 tons or more per year of NOX 0.22 Ibs/MMBtu annual rate limit for all fossil fuel units > 25 MW built before 1995 with a heat input capacity < 750 MMBtu/hr 0.15 Ibs/MMBtu annual rate limit for all fossil fuel units > 25 MW built before 1995 with a heat input capacity > 750 MMBtu/hr 0.20 Ibs/MMBtu annual rate limit for all fossil fuel fired indirect heat exchangers, primary boilers, and resource recovery units with heat input capacity > 250 MMBtu/hr 25 Ibs annual cap for any facility including EGUs Implementation Status Implementation from 2008 through 2015, depending on plant and control type 2004 2012 2013 2015 2012 2013 2015 2012 2005 2005 2005 2010 69 ------- State/Region Maryland Massachusett s Michigan Minnesota Missouri Montana New Hampshire Bill Maryland Healthy Air Act 310CMR7.29 Part 15. Emission Limitations and Prohibitions - Mercury Minnesota Hg Emission Reduction Act 10CSR 10-6.350 Montana Mercury Rule Adopted 10/16/06 RSA 125-0: 11-18 Emission Type NOX S02 Hg NOX S02 Hg Hg Hg NOX Hg Hg Emission Specifications 3.6 MTons summer cap and 8.3 MTons annual cap for Mirant coal units 0.5 MTons summer cap and 1 .4 MTons annual cap for Allegheny coal units 3.6 MTons summer cap and 8.03 MTons annual cap for Constellation coal units. 2009 through 2012: 23.4 MTons annual cap for Constellation coal units, 24.2 MTons annual cap for Mirant Coal units, and 4.6 MTons annual cap for Allegheny coal units. 201 3 onwards: 1 7.9 MTons annual cap for Constellation coal units, 18.5 MTons annual cap for Mirant Coal units, and 4.6 MTons annual cap for Allegheny coal units. 2010 through 2012: 80% removal of Hg content of fuel for Mirant, Allegheny, and Constellation coal steam units 2013 onwards: 90% removal of Hg content of fuel for Mirant, Allegheny, and Constellation coal steam units 1 .5 Ibs/MWh annual GPS for Bayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor 3.0 Ibs/MWh annual GPS for Bayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor 2012: 85% removal of Hg content of fuel or 0.00000625 Ibs/MWh annual GPS for Brayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor 2013 onwards: 95% removal of Hg content of fuel or 0.00000250 Ibs/MWh annual GPS for Brayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor 90% removal of Hg content of fuel annually for all coal units > 25 MW 90% removal of Hg content of fuel annually for all coal units > 250 MW 0.25 Ibs/MMBtu annual rate limit for all fossil fuel units > 25 MW in the following counties: Bellinger, Butler, Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Gasconade, Iron, Lewis, Lincoln, Madison, Marion, Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Phelps, Pike, Rails, Reynolds, Ripley, St. Charles, St. Francois, Ste. Genevieve, Scott, Shannon, Stoddard, Warren, Washington and Wayne 0.18 Ibs/MMBtu annual rate limit for all fossil fuel units > 25 MWthe following counties: City of St. Louis, Franklin, Jefferson, and St. Louis 0.35 Ibs/MMBtu annual rate limit for all fossil fuel units > 25 MW in the following counties: Buchanan, Jackson, Jasper, Randolph, and any other county not listed 0.90 Ibs/TBtu annual rate limit for all non-lignite coal units 1 .50 Ibs/TBtu annual rate limit for all lignite coal units 80% reduction of aggregated Hg content of the coal burned at the facilities for Merrimack Units 1 & 2 and Schiller Units 4, 5, &6 Implementation Status 2009 2006 2015 2008 2004 2010 2012 70 ------- State/Region New Jersey New York North Carolina Oregon Bill ENV-A2900 Multiple pollutant annual budget trading and N.J.A.C. 7:27-27.5, 27.6, 27.7, and 27.8 N.J. A. C. Title 7, Chapter 27, Subchapter 19, Table 1 N.J. A. C. Title 7, Chapter 27, Subchapter 19, Table 4 Part 237 Part 238 Mercury Reduction Program for Coal- Fired Electric Utility Steam Generating Units MP Plasm Smokestacks Act: Statute 143-21 5. 107D Oregon Administrative Rules, Chapter 345, Division 24 Emission Type NOX S02 Hg NOX NOX NOX SO2 Hg NOX SO2 CO2 Emission Specifications 2.90 MTons summer cap for all fossil steam units > 250 MMBtu/hr operated at any time in 1 990 and all new units > 15 MW 3.64 MTons annual cap for Merrimack 1 & 2, Newington 1 , and Schiller 4 through 6 7.29 MTons annual cap for Merrimack 1 & 2, Newington 1 , and Schiller 4 through 6 90% removal of Hg content of fuel annually for all coal-fired units 95% removal of Hg content of fuel annually for all MSW incinerator units 2009 - 201 2 annual rate limits in Ibs/MMBtu for the following technologies: Coal Boilers (Wet Bottom) - 1 .0 for tangential and wall-fired, 0.60 for cyclone-fired Coal Boilers (Dry Bottom) - 0.38 for tangential, 0.45 for wall-fired, 0.55 for cyclone-fired Oil and/or Gas or Gas only: 0.20 for tangential, 0.28 for wall-fired, 0.43 for cyclone-fired 201 3 & 201 4 annual rate limits in Ibs/MWh for the following technologies: All Coal Boilers: 1.50 for all Oil and/or Gas: 2.0 for tangential, 2.80 for wall-fired, 4.30 for cyclone-fired Gas only: 2.0 for tangential and wall-fired, 4.30 for cyclone-fired 2015 onward annual rate limits in Ibs/MWh for the following technologies: All Coal Boilers: 1.50 for all Oil and/or Gas: 2.0 for fuel heavier than No. 2 fuel oil, 1 .0 for No. 2 and lighter fuel oil Gas only: 1.0 for all 2.2 Ibs/MWh annual GPS for gas-burning simple cycle combustion turbine units 3.0 Ibs/MWh annual GPS for oil-burning simple cycle combustion turbine units 1 .3 Ibs/MWh annual GPS for gas-burning combined cycle CT or regenerative cycle CT units 2.0 Ibs/MWh annual GPS for oil-burning combined cycle CT or regenerative cycle CT units 39.91 MTons non-ozone season cap for fossil fuel units > 25 MW 1 31 .36 MTons annual cap for fossil fuel units > 25 MW 786 Ibs annual cap through 201 4 for all coal fired boiler or CT units >25 MW after Nov. 1 5, 1 990. 0.60 Ibs/TBtu annual rate limit for all coal units > 25 MW developed after Nov. 15 1990 25 MTons annual cap for Progress Energy coal plants > 25 MW and 31 MTons annual cap for Duke Energy coal plants > 25 MW 2012: 100 MTons annual cap for Progress Energy coal plants > 25 MW and 1 50 MTons annual cap for Duke Energy coal plants > 25 MW 2013 onwards: 50 MTons annual cap for Progress Energy coal plants > 25 MWand 80 MTons annual cap for Duke Energy coal plants > 25 MW 675 Ibs/MWh annual rate limit for new combustion turbines burning natural gas with a CF >75% and all new non-base load plants (with a CE <= 75%) emitting CO2 Implementation Status 2007 2007 2009 2007 2004 2005 2010 2007 2009 1997 71 ------- State/Region Pacific Northwest Texas Utah Wisconsin Bill Oregon Utility Mercury Rule - Existing Units Oregon Utility Mercury Rule - Potential Units Washington State House Bill 31 41 Senate Bill 7 Chapter 101 Chapter 117 R307-424 Permits: Mercury Requirements for Electric Generating Units NR 428 Wisconsin Administration Code Emission Type Hg Hg CO2 SO2 NOX NOX Hg NOX Emission Specifications 90% removal of Hg content of fuel reduction or 0.6 Ibs/TBtu limitation for all existing coal units >25 MW 25 Ibs rate limit for all potential coal units > 25 MW $1 .45/Mton cost (2004$) for all new fossil-fuel power plant 273.95 MTons cap of SO2 for all grandfathered units built before 1971 in East Texas Region Annual cap for all grandfathered units built before 1971 in MTons: 84.48 in East Texas, 18.10 in West Texas, 1 .06 in El Paso Region East and Central Texas annual rate limits in Ibs/MMBtu for units that came online before 1 996: Gas fired units: 0.14 Coal fired units: 0.165 Stationary gas turbines: 0.14 Dallas/Fort Worth Area annual rate limit for utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in an electric power generating system except for CT and CC units online after 1992: 0.033 Ibs/MMBtu or 0.50 Ibs/MWh output or 0.0033 Ibs/MMBtu on system wide heat input weighted average for large utility systems 0.06 Ibs/MMBtu for small utility systems Houston/Galveston region annual Cap and Trade (MECT) for all fossil units: 17.57 MTons Beaumont-Port Arthur region annual rate limits for utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in an electric power generating system: 0.10 Ibs/MMBtu 90% removal of Hg content of fuel annually for all coal units > 25 MW Annual rate limits in Ibs/MMBtu for coal fired boilers > 1,OOOMMBtu/hr: Wall fired, tangential fired, cyclone fired, and fluidized bed: 2009: 0.15, 2013 onwards: 0.10 Arch fired: 2009 onwards: 0.18 Annual rate limits in Ibs/MMBtu for coal fired boilers between 500 and 1 ,000 MMBtu/hr: Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 2013 Tangential fired: 2009 onwards: 0.15 Cyclone fired: 2009: 0.20; 2013 onwards: 0.15 Fluidized bed: 2009: 0.15; 2013 onwards: 0.10 Arch fired: 2009 onwards: 0.18 Implementation Status 2012 2009 2004 2003 2007 2013 2009 72 ------- State/Region Bill Chapter NR 446. Control of Mercury Emissions Emission Type Hg Emission Specifications Annual rate limits for CTs in Ibs/MMBtu: Natural gas CTs > 50 MW: 0.1 1 Distillate oil CTs > 50 MW: 0.28 Biologically derived fuel CTs > 50 MW: 0.15 Natural gas CTs between 25 and 49 MW: 0.19 Distillate oil CTs between 25 and 49 MW: 0.41 Biologically derived fuel CTs between 25 and 49 MW:0.15 Annual rate limits for CCs in Ibs/MMBtu: Natural gas CCs > 25 MW: 0.04 Distillate oil CCs > 25 MW: 0.18 Biologically derived fuel CCs > 25 MWs: 0.15 Natural gas CCs between 1 0 and 24 MW: 0.1 9 2012 through 2014: 40% reduction in total Hg emissions for all coal-fired units in electric utilities with annual Hg emissions > 100 Ibs 2015 onwards: 90% removal of Hg content of fuel or 0.0080 Ibs/GW-hr reduction in coal fired EGUs > 150MW 80% removal of Hg content of fuel or 0.0080 Ibs/GW-hr reduction in coal fired EGUs > 25 MW Implementation Status 2010 Notes: Updates to the EPA Base Case v4.10_FTransport from EPA Base Case 4.10 include the following: 1) An update of the modeling of SO2 rate limits in Connecticut 2) An update of the modeling of the effective dates of various controls on units in Georgia 3) Addition of two Kansas State Law unit-specific constraints 4) An update of the modeling of NOX rate limits in Louisiana 5) An update of the modeling of the NOX annual and summer caps and SO2 annual cap in Maryland 6) An update of the modeling of the NOX rate limits in New Jersey 73 ------- Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10_FTransport (05-16-11) Company and Settlement Actions Ret ire/Re power Action Alabama Power James H. Miller Alabama Units 3&4 Effective Date SO2 control Equipment p.. Removal or Rate Effective Date NOX Contro Equipment Rate Effective Date PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement Allowance Restriction Restriction Effective Date Install and operate FGD continuously 95% 12/31/11 Operate existing SCR continuously 0.1 05/01/08 0.03 12/31/06 Within 45 days of settlement entry, ARC must retire 7,538 SO2 emission allowances. ARC shall not sell, trade, or otherwise exchange any Plant Miller excess SO2 emission allowances outside of the A PC system 1/1/21 http://www.epa.gov/complia n ce/reso u rces/cases/civ i l/c aa/ala bamapower.html Minnkota Power Cooperative Beginning 1/01/2006, Minnkota shall not emit more than 31, 000 tons of SQ/year, no more than 26, 000 tons beginning 2011, no more than 11, 500 tons beginning 1/01/2012. If Units is not operational by 12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500 Milton R. Young Minnesota Unitl Unit 2 Install and continuously operate FGD Design, upgrade, and continuously operate FGD 95% if wet FGD, 90% if dry 90% 12/31/11 12/31/10 Install and continuously operate Over- fire AIR, or equivalent technology with emission rate < .36 Install and continuously operate over- fire AIR, or equivalent technology rate < 36 0.36 0.36 12/31/09 12/31/07 0.03 if wet FGD, .015 f dry FGD 0.03 Before 2008 Plant will surrender 4, 346 allowances for each year 2012 -2015,8,693 allowances for years 2016- 2018, 12,170 allowances for year 2019, and 14,886 allowances/year thereafter if Units 1 -3 are operational by 12/31/2015. If only Units 1 and 2 are operational by12/31/2015, the plant shall retire 17,886 units in 2020 and thereafter. Minnkota shall not sell or trade NOX allowances allocated to Units 1, 2, or 3 that would otherwise be available for sale or trade as a result of the actions taken by the settling defendants to comply with the requirements http://www.epa.gov/complia nce/resources/cases/civil/c SIGECO FB Culley PSEG FOSSIL Bergen Indiana New Jersey Unitl Unit 2 Units Unit 2 Re power to natural gas 12/31/06 Re power to combined cycle 12/31/02 Improve and continuously operate existing FGD (shared by Units 2 and 3) Improve and continuously operate existing FGD (shared by Units 2 and 3) 95% 95% 06/30/04 06/30/04 Operate Existing SCR Continuously 0.1 09/01/03 Install and continuously operate a Baghouse 0.015 06/30/07 The provision did not specify SO2 allowances surrendered. It only provided that excess resulting from compliance with NSR settlement provisions must ' The provision http://www.epa.gov/complia nce/resources/cases/civil/c aa/sigecofb.html ------- Company and Plant Hudson Mercer TECO Big Bend Gannon State New Jersey New Jersey Florida Florida Unit Unit 2 Units 1 & 2 Units 1 & 2 Units Unit 4 Six units Settlement Actions Ret ire /Re power Action Effective Date Retire all six coal units and re power at least 550 MW of coal capacity to natural gas 12/31/04 SO2 control Equipment Install Dry FGD (or approved alt. technology) and continually operate Install Dry FGD (or approved alt. technology) and continually operate Existing Scrubber (shared by Units 1 &2) Existing Scrubber (shared by Units 3 & 4) Existing Scrubber (shared by Units 3 & 4) Percent Removal or Rate 0.15 0.15 95% (95% or .25) 93% if Units 3 &4are operating 93% if Units 3 &4are operating Effective Date 12/31/06 12/31/10 09/1/00 (01/01/13) 2000 (01/01/10) 06/22/05 NOX Contro Equipment Install SCR (or approved tech) and continually operate Install SCR (or approved tech) and continually operate Install SCR Install SCR Install SCR Rate 0.1 0.13 0.1 0.1 0.1 Effective Date 05/01/07 05/01/06 05/01/09 05/01/09 07/01/07 PM or Mercury Control Equipment Install Baghouse (or approved technology) Rate 0.015 Effective Date 12/31/06 Allowance Retirement Retirement did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. Allowance Restriction Restriction Effective Date WEPCO WEPCO shall comply with the following system wide average NQ emission rates and total NCl< tonnage permissible: by 1/1/2005 an emisson rate of 0.27 and 31, 500 tons, by 1/1/2007 an emission rate of 0.19 and 23, 400 tons, and by 1/1/2013 an emission rate of 0.17 and 17, 400 tons. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86, 900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an emission rate of 0.32 and 33,300 tons. Presque Isle Pleasant Prairie Wisconsin Wisconsin Units 1 -4 Units 5 & 6 Units 7 & 8 Unit 9 1 2 Retire or install SO2 and NOX controls 12/31/12 Install and continuously operate FGD (or approved equiv. tech) Install and continuously operate FGD (or approved control tech) Install and continuously operate FGD (or approved control tech) 95% or 0.1 95% or 0.1 95% or 0.1 12/31/12 12/31/06 12/31/07 Install SCR (or approved tech) and continually operate Install and operate low NO,, burners Operate existing low NOX burners Operate existing low NOx burners Install and continuously operate SCR (or approved tech) Install and continuously operate SCR (or approved tech) 0.1 0.1 0.1 12/31/12 12/31/03 12/31/05 12/31/06 12/31/06 12/31/03 Install Baghouse Install Baghouse The provision did not specify an amount of SO2 allowances to be surrendered. It only provided Reference http://www.epa.gov/complia nce/resources/cases/civil/c aa/psegllc.html http://www.epa.gov/complia nce/resources/cases/civil/c aa/teco.html http://www.epa.gov/complia nce/resources/cases/civil/c aa/wepco.html ------- Company and Plant Oak Creek Port Washington Valley State Wisconsin Wisconsin Wisconsin Unit Units 5 & 6 Unit 7 Units Units 1-4 Boilers 1-4 Settlement Actions Ret ire /Re power Action Retire Effective Date 12/3 1/04 for Units 1-3. Unit 4 by entry of consent decree SO2 control Equipment Install and continuously operate FGD (or approved control tech) Install and continuously operate FGD (or approved control tech) Install and continuously operate FGD (or approved control tech) Percent Removal or Rate 95% or 0.1 95% or 0.1 95% or 0. 1 Effective Date 12/31/12 12/31/12 12/31/12 NOX Contro Equipment Install and continuously operate SCR (or approved tech) Install and continuously operate SCR (or approved tech) Install and continuously operate SCR (or approved tech) Operate existing low NOX burner Rate 0.1 0.1 0.1 Effective Date 12/31/12 12/31/12 12/31/12 30 days after entry of consent decree PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement that excess allowances resulting from compliance with NSR settlement provisions must be retired. Allowance Restriction Restriction Effective Date Reference VEPCO The Total Permiss ble NOx Emiss ons (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 - 2010, 54,000 in 201 1, 50,000 in 2012, and 30,250 each year there after. Beginning 1/1/2013 they will have a system wde emission rate no greater then 0.15 Ib/mmBtu. Mount Storm Chesterfield Chesapeake Energy Clover Possum Point West Virginia Virginia Virginia Virginia Virginia Units 1 -3 Unit 4 Unit5 Unite Units 3&4 Units 1 &2 Units3&4 Retire and re power to natural qas 05/02/03 Constructor improve FGD Construct or improve FGD Construct or improve FGD Improve FGD 95% or 0.1 5 95% or 0.1 3 95% or 0.1 3 95%or0.13 01/01/05 10/12/12 01/01/10 09/01/03 Install and continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR 0.11 0.1 0.1 0.1 0.1 01/01/08 01/01/13 01/01/12 01/01/11 01/01/13 On or before March 31 of every year beginning in 2013 and continuing thereafter, VEPCO shall surrender 45,000 SO2 allowances. http://www.epa.gov/complia nce/resources/cases/civil/c aa/vepco.html Santee Cooper Santee Cooper shall comply with the following system wide averages for NQ emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30, 000 tons, by 1/1/2007 an emission rate of 0.18 and 25,000 tons, by 1/1/2010 and emission rate of 0.15 and 20, 000 tons. For SO? emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85, 000 tons, by 1/1/2009 an emission rate of 0.53 and 70 tons, and by 1/1/201 1 and emission rate of 0.5 and 65 tons. Cross Winyah South Carolina South Carolina Unitl Unit 2 Unitl Unit 2 Units Upgrade and continuously operate FGD Upgrade and continuously operate FGD Install and continuously operate FGD Install and continuously operate FGD Upgrade and continuously operate existing FGD 95% 87% 95% 95% 90% 06/30/06 06/30/06 12/31/08 12/31/08 12/31/08 Install and continuously operate SCR Install and Continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR 0.1 0.11/0.1 0.11/0.1 0.12 0.14/0.12 05/31/04 05/31/04 and 05/31/07 11/30/04 and 11/30/04 11/30/04 11/30/2005 and 11/30/08 The provision did not specify an amount of SO2 allowances to be surrendered. It http://www.epa.gov/complia nce/reso u rces/cases/civ i l/c aa/santeecooper.html ------- Company and Plant Grainger Jeffries State South Carolina South Carolina Unit Unit 4 Unit 1 Unit 2 Units 3, 4 Settlement Actions Ret ire /Re power Action Effective Date SO2 control Equipment Upgrade and continuously operate existing FGD Percent Removal or Rate 90% Effective Date 12/31/07 NOX Contro Equipment Install and continuously operate SCR Operate low NO,, burner or more stringent technology Operate low NOX burner or more stringent technology Operate low NOX burner or more stringent technology Rate 0.13/0.12 Effective Date 11/30/05 and 1 1/30/08 06/25/04 05/01/04 06/25/04 PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement that excess allowances resulting from compliance with NSR settlement provisions must be retired. Allowance Restriction Restriction Effective Date Reference Ohio Edison Ohio Edison shall achieve reductions of 2, 483 tons NOX between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1-3 during the months of October through April, and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NQ required for the Sammis Plant. Ohio Edison must reduce 24, 600 tons system-wide of SQ by 12/31/2010. No later than 8/1 1 minimize NC^em W.H. Sammis Plant /2005, Ohio Edison shall install and operate low NQ burners on Sammis Units 1 - 7 and overtired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization with software tc ssions from Sammis Units 1 - 5. Ohio Unitl Unit 2 Units Unit 4 Units Install Induct Scrubber (or approved equiv. control tech) Install Induct Scrubber (or approved equiv. control tech) Install Induct Scrubber (or approved equiv. control tech) Install Induct Scrubber (or approved equiv. control tech) Install Flash Dryer Absorber or ECO2 (or approved equiv. control tech) & operate continuously 50% removal or 1.1 Ib/mmBtu 50% removal or 1.1 Ib/mmBtu 50% removal or 1.1 Ib/mmBtu 50% removal or 1.1 Ib/mmBtu 50% removal or 1.1 Ib/mmBtu 12/31/08 12/31/08 12/31/08 06/30/09 06/29/09 Install SNCR (or approved alt. tech) & operate continuously Operate existing SNCR continuously Operate low NO,, burners and overfire air by 12/1/05; install SNCR (or approved alt. tech) & operate continuously by 12/31/07 Install SNCR (or approved alt. tech) & operate continuously Install SNCR (or approved alt. tech) & Operate Continuously 0.25 0.25 0.25 0.25 0.29 10/31/07 02/15/06 12/01/05 and 10/31/07 10/31/07 03/31/08 Beginning on 1/1/2006, Ohio Edison may use, sell or transfer any restricted SO2 only to satisfy the Operational Needs at the Sammis, Burger and Mansfield Plant, or new units within the FirstEnergy System that comply with a 96% removal for SO2. For calendar year onnfithmiinh http://www.epa.gov/complia nce/resources/cases/civil/c aa/ohioedison.html ------- Company and Plant Mansfield Plant Eastlake Burger State Pennsylvania Ohio Ohio Unit Unite Unit 7 Unitl Unit 2 Units Units Unit 4 Units Settlement Actions Retire /Repower Action Repower with at least 80% biomassfuel, up to 20% low sulfur coal. Effective Date 12/31/11 12/31/11 SO2 control Equipment Install FGD3 (or approved equiv. control tech) & operate continuously nstall FGD (or approved equiv. control tech) & operate continuously Upgrade existing FGD Upgrade existing FGD Upgrade existing FGD Percent Removal or Rate 95% removal orO.13 Ib/mmBtu 95% removal orO.13 Ib/mmBtu 95% 95% 95% Effective Date 06/30/1 1 06/30/1 1 12/31/05 12/31/06 10/31/07 NOX Contro Equipment Install SNCR (or approved alt. tech) & operate continuously Operate existing SNCR Continuously Install low NO, burners, over- fired air and SNCR & operate continuously Rate "Minimum Extent Practicable" "Minimum Extent Practicable" "Minimize Emissions to the Extent Practicable" Effective Date 06/30/05 08/11/05 12/31/06 PM or Mercury Control Equipment Operate Existing ESP Continuously Operate Existing ESP Continuously Rate 0.03 0.03 Effective Date 01/01/10 01/01/10 Allowance Retirement Retirement 2017, Ohio Edison may accumulate SO2 allowances for use at the Sammis, Burger, and Mansfield plants, or FirstEnergy units equipped with SO2 Emission Control Standards. Beginning in 2018, Ohio Edison shall surrender unused restricted SO2 allowances. Allowance Restriction Restriction Effective Date Mirantl1'6 System-wide NO, Emission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NQ Emission Ozone Season Caps: 14,700 tons 2004; 13,340 tons 2005; 12,590 tons 2006; 10, 190 tons 2007; 6,150 tons 2008- 2009; 5, 200 tons 2010 thereafter. Beginning on 5/1/2008, and continuing for each and every Ozone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Emission Rate of 0.150 Ib/mmBtu NO,. Potomac River Plant Virginia Unitl Unit 2 Units Unit 4 Units Install low NO, burners (or more effective tech) & operate continuously Install low NO, burners (or more effective tech) & operate continuously nstall low NO, burners (or more effective tech) & operate continuously 05/01/04 05/01/04 05/01/04 Reference http://www.epa.gov/complia nce/resources/cases/civil/c aa/miranthtml ------- Company and Plant Morgantown Plant Chalk Point Maryland Maryland Unit Unit 1 Unit 2 Unit 1 Unit 2 Settlement Actions Ret ire /Re power Action Effective Date SO2 control Equipment Install and continuously operate FGD (or equiv. technology) Install and continuously operate FGD (or equiv. technology) Percent Removal or Rate 95% 95% Effective Date 06/01/10 06/01/10 NOX Contro Equipment Install SCR (or approved alt. tech) & operate continuously Install SCR (or approved alt. tech) & operate continuously Rate 0.1 0.1 Effective Date 05/01/07 05/01/08 PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement For each year after Mirant commences FGD operation at Chalk Point, Mirant shall surrender the number of SO2 Allowances equal to the amount by which the SO2 Allowances allocated to the Units at the Chalk Point Plant are greater than the total amount of SO2 emissions allowed under this Section XVIII. Allowance Restriction Restriction Effective Date Illinois Power System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 - 2006; 65,000 tons 2007; 62,000 tons 2008 - 2010; 57,000 tons 201 1; 49,500 tons 2012; 29, 000 tons 2013 onward. Baldwin Havana Illinois Illinois Units 1 S.2 Units Unite Install wet or dry FGD (or approved equiv. alt. tech) & operate continuously Install wet or dry FGD (or approved equiv. alt. tech) & operate continuously Install wet or dry FGD (or approved equiv. alt. tech) & operate continuously 0.1 0.1 1.2 Ib/mmBtu until 12/30/2012; 0.1 Ib/mmBtu from 12/31/2012 onward 12/31/11 12/31/11 08/11/05 and 12/31/12 Operate OFA & existing SCR continuously Operate OFA and/or low NOx burners Operate OFA and/or low NOx urners existing SCR continuously 0.1 0.1 2 until 12/30/12; 0.1 from 12/31/12 0.1 08/11/05 08/1 1/05 and 12/31/12 08/11/05 continuously Baghouse Installs. continuously operate Baghouse Installs. continuously operate Baghouse, then install ESP or alt. PM equip 0.015 0.015 For Bag- house: 0.015 Ib/mmBtu; For ESP: 0.03 Ib/mmBtu 12/31/10 12/31/10 For Baghouse: 12/31/12; For ESP: 12/31/05 Note: Havana Unite in the Illinois Power NSR settlement refers to the affected electric generator. The provsions shown here as applying to Havana Unite are represented in IPM as applying to Havana Unit 9, which is the boiler that powers generator unit #6. By year end 2008, Dynergy will surrender 1 2,000 SO2 emission allowances, by year end 2009 it will surrender 18,000, by year end 2010 it will surrender 24,000, any by year end 2011 and each year thereafter it will surrender 30,000 allowances. If http://www.epa.gov/complia nce/resources/cases/civil/c aa/illinoispower.html ------- Company and Vermilion Wood River Kentucky Utilitie EW Brown Generating Station Salt River Projec Corona do Generating Station Illinois Illinois s Company Kentucky t Agricultural Irr Arizona Unit 1 Unit 2 Units 1 &2 Units 4&5 Units provement a Unit 1 or Unit 2 Unit 1 or Unit 2 Settlement Actions Ret ire /Re power Action nd Power Dist Effective Date rict (SRP) American Electric Power SO2 control Equipment Install FGD Immediately begin continuous operation of existing FGDs on both units, install new FGD. Install new FGD Removal or Rate 1.2 1.2 1.2 1.2 97% or 0.1 00 95% or 0.08 95% or 0.08 Annual Cap (tons) Effective Date 07/27/05 07/27/05 01/31/07 07/27/05 12/31/10 New FGD installed by 1/1/2012 01/01/13 Year NOX Contro Equipment Operate OFA and/or low NOX burners Operate OFA and/or low NO* burners Operate OFA and/or low NOX Operate OFA and/or low NOX Install and continuously operate SCR by 12/31/2012, continuously operate low NOX boiler and OFA. Install and continuously operate low NOX burner and SCR Install and continuously operate low NO* burner Rate "Minimum Extent Practicable" "Minimum Extent Practicable" "Minimum Extent Practicable" "Minimum Extent Practicable" 0.07 0.32 prior to SCR installation, 0.080 after 0.32 Annual Cap (tons) Effective Date 08/11/05 08/11/05 08/11/05 08/11/05 12/31/12 LNBby 06/01/2009, SCR by 06/01/2014 06/01/11 PM or Mercury Control Equipment Install ESP (or & continuously operate ESPs Install ESP (or equiv. alt. tech) & continuously operate ESPs Install ESP (or equiv. alt. tech) & continuously operate ESPs Install ESP (or equiv. alt. tech) & continuously operate ESPs Continuously operate ESP Optimization and continuous operation of existing ESPs. Rate 0.03 0.03 0.03 0.03 0.03 0.03 Effective Date 12/31/06 12/31/06 12/31/10 12/31/05 12/31/10 Optimization immediately, rate limit begins 01/01/12 (date of new FGD Optimization immediately, begins (date of new installation) Allowance Retirement Retirement the surrendered allowances result in insufficient allowances allocated to the units comprising the DMG can request to surrender fewer SO2 allowances. 53 000 SO2 2008 or earlier vintage by March 1,2009. All surplus NO* allowances must be surrendered through 2020. Beginning in 2012, all surplus SO2 allowances for both Coronado and Springerville Unit 4 must be surrendered through 2020. The allowances limited by this condition may, however, be used for compliance at a prospective future plant using BACTand otherwise specified in par. 54 of the consent decree. Allowance Restriction Restriction SO2 and NOX allowances may not be used for compliance, and emissions decreases for purposes of complying with the Consent earn credits. SO2 and NOX allowances may not be used for compliance, and emissions decreases for purposes of complying with the Consent Decree do not earn credits. Effective Date http://www.epa.gov/complia nce/resources/cases/civil/c aa/kucompany.html http://www.epa.gov/complia nce/resources/cases/civil/c aa/srp.html NOX and SO2 ------- Company and Plant State Unit Eastern System-Wide At least 600MW from various units Amos Big Sandy West Virginia Virginia Indiana West Virginia West Virginia Kentucky Sporn 1 -4 Clinch River 1 -3 Tanners Creek 1 -3 Kammer 1 -3 Unit 1 Unit 2 Units Unitl Unit 2 Settlement Actions Ret ire /Re power Action Retire, retrofit, or re- power Effective Date 12/31/18 SO2 control Equipment Install and continuously operate FGD Install and continuously operate FGD Install and continuously operate FGD Burn only coal with no more than 1.75 Ib/MMBtu annual average Install and continuously operate FGD Percent Removal or Rate 450,000 450,000 420,000 350,000 340,000 275,000 260,000 235,000 184,000 174,000 Effective Date 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 and thereafter 12/31/09 12/31/10 12/31/09 Date of entry 12/31/15 NOX Contro Equipment Install and continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR Continuously operate low NO,, burners Install and continuously operate SCR Rate 96,000 92,500 92,500 85,000 85,000 85,000 75,000 72,000 Effective Date 2009 2010 2011 2012 2013 2014 2015 2016 and thereafter 01/01/08 01/01/09 01/01/08 Date of entry 01/01/09 PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement NOX and SO2 allowances that would have been made available by emission reductions pursuant to the Consent Decree must be surrendered. Allowance Restriction Restriction allowances may not be used to comply with any of the limits imposed by the Consent Decree. The Consent Decree includes a formula for calculating excess NOX allowances relative to the CAIR Allocations, and restricts the use of some. See par. 74-79 for details. Reducing emissions below the Eastern System- Wide Annual Tonnage Limitations for NOX and SO2 earns supercomplian ce allowances. Effective Date Reference http://www.epa.gov/complia n ce/reso u rces/cases/civ i l/c aa/americanelectricpower1 0 07.html ------- Company and Plant Cardinal Clinch River Conesville Gavin Glen Lyn Kammer Kanawha River Mitchell State Ohio Virginia Ohio Ohio Virginia West Virginia West Virginia West Virginia Unit Unit 1 Unit 2 Units Units 1 -3 Unitl Unit 2 Units Unit 4 Units Unit 6 Unitl Unit 2 Units 1 -3 Units 5, 6 Units 1-3 Units 1, 2 Unitl Unit 2 Settlement Actions Ret ire /Re power Action Retire, retrofit, or re- power Retire, retrofit, or re- power Retire, retrofit, or re- power Effective Date Date of entry Date of entry 12/31/12 SO2 control Equipment Install and continuously operate FGD Install and continuously operate FGD Install and continuously operate FGD Install and continuously operate FGD Upgrade existing FGD Upgrade existing FGD Install and continuously operate FGD Install and continuously operate FGD Burn only coal with no more than 1.75 Ib/MMBtu annual average Burn only coal with no more than 1.75 Ib/MMBtu annual average Install and continuously operate FGD Install and continuously operate FGD Percent Removal or Rate Plant-wide annual cap: 2 1,700 tons from 20 10 to 2014, then 16, 300 after 1/1/2015 95% 95% Plant-wide annual cap: 35,000 Effective Date 12/31/08 12/31/08 12/31/12 2010-2014, 2015 and thereafter 12/31/10 12/31/09 12/31/09 Date of entry Date of entry Date of entry 01/01/10 Date of entry 12/31/07 12/31/07 NOX Contro Equipment Install and continuously operate SCR Install and continuously operate SCR Install and continuously operate SCR Continuously operate low NOX burners Install and continuously operate SCR Continuously operate low NOX burners Continuously operate low NOX burners Install and continuously operate SCR Install and continuously operate SCR Continuously operate low NO,, burners Continuously operate over- fire air Continuously operate low NOX burners Install and continuously operate SCR Install and continuously operate SCR Rate Effective Date 01/01/09 01/01/09 01/01/09 Date of entry 12/31/10 Date of entry Date of entry 01/01/09 01/01/09 Date of entry Date of entry Date of entry 01/01/09 01/01/09 PM or Mercury Control Equipment Continuously operate ESP Continuously operate ESP Rate 0.03 0.03 Effective Date 12/31/09 12/31/09 Allowance Retirement Retirement Allowance Restriction Restriction Effective Date Reference ------- Company and Plant Mountaineer Muskingum River Picway Rockport Sporn Tanners Creek State West Virginia Ohio Ohio Indiana West Virginia Indiana Unit Unit 1 Units 1 -4 Units Unit 9 Unit 1 Unit 2 Units Units 1 -3 Unit 4 Settlement Actions Ret ire /Re power Action Retire, retrofit, or re- power Retire, retrofit, or re- power Effective Date 12/31/15 12/31/13 SO2 control Equipment Install and continuously operate FGD Install and continuously operate FGD Install and continuously operate FGD Install and continuously operate FGD Burn only coal with no more than 1.2 Ib/MMBtu annual average Burn only coal with no more than 1.2% sulfur content annual average Percent Removal or Rate Effective Date 12/31/07 12/31/15 12/31/17 12/31/19 Date of entry Date of entry NOX Contro Equipment Install and continuously operate SCR Install and continuously operate SCR Continuously operate low NOX burners Install and continuously operate SCR Install and continuously operate SCR Continuously operate low NOX burners Continuously operate over- fire air Rate Effective Date 01/01/08 01/01/08 Date of entry 12/31/17 12/31/19 Date of entry Date of entry PM or Mercury Control Equipment Continuously operate ESP Rate 0.03 Effective Date 12/31/02 Allowance Retirement Retirement Allowance Restriction Restriction Effective Date Reference East Kentucky Power Cooperative Inc. By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NQ contro s at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012. System-wide System-wide 12- mo nth rolling tonnage limits apply 12-month rolling limit (tons) 57,000 40,000 Start of 12- month cycle 10/01/08 07/01/11 All units must operate low NOX boilers 12-month rolling limit (tons) 11,500 8,500 Start of 12- month cycle 01/01/08 01/01/13 PM control devices must be operated continuously system-wide, ESPs must be optimized within 270 days of entry date, or EKPC may choose to submit a PM Pollution Control Upgrade Analysis. 0.03 1 year from entry date AllsurplusSO2 allowances must be surrendered each year, beginning in 2008. SO2 and NOX allowances may not be used to comply with the Consent Decree. NOX allowances that would become available as a result of compliance with the Consent Decree may not be sold or traded. SO2 and NO,, allowances allocated to EKPC must be used within the http://www.epa.gov/complia nce/reso u rces/cases/civ i l/c aa/nevadapower.html ------- Company and Plant Spurlock Dale Plant State Kentucky Kentucky Unit Unit 1 Unit 2 Unitl Unit 2 Units Unit 4 Unitl Settlement Actions Ret ire /Re power Action EKPC may choose to retire Dale 3 and 4 in lieu of installing controls in Cooper 2 Effective Date 12/31/2012 SO2 control Equipment Install and continuously operate FGD Install and continuously operate FGD by 10/1/2008 Percent Removal or Rate 28,000 95% or 0.1 95% or 0. 1 Effective Date 01/01/13 6/30/2011 1/1/2009 NOX Contro Equipment Continuously operate SCR Continuously operate SCR and OFA Install and continuously operate low NOX burners by 10/31/2007 Install and continuously operate low NOX burners by 10/31/2007 Rate 8,000 0.1 2 for Unit 1 until 01/01/2013, at which point the unit limit drops to 0.1. Prior to 01/01/2013, the combined average when both units are operating must be no more than 0.1 0.1 for Unit 2, 0.1 combined average when both units are operating 0.46 0.46 Effective Date 01/01/15 60 days after entry 60 days after entry 01/01/08 01/01/08 PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement EKPC must surrender 1,000 NOX allowances immediately under the ARP, and 3,107 under theNOxSIP Call. EKPC must also surrender 15,311 SO2 allowances. Allowance Restriction Restriction Allowances made available due to supercomplian ce may be sold or traded. Effective Date Date of entry Reference http://www.epa.gov/complia nce/resources/cases/civil/c aa/eastkentuckypower- dale0907.html ------- Company and Plant Cooper State Kentucky Unit Unit 2 Settlement Actions Ret ire /Re power Action Effective Date SO2 control Equipment If EKPC opts to install controls rather than retiring Dale, it must install and continuously operate FGD orequiv. technology Percent Removal or Rate 95% or 0.10 Effective Date NOX Contro Equipment If EKPC elects to install controls, it must continuously operate SCR or install equiv. technology Rate 0.08 (or 90% if non- SCR technology is used) Effective Date 12/31/12 PM or Mercury Control Equipment Rate Effective Date Allowance Retirement Retirement Allowance Restriction Restriction Effective Date Nevada Power Company Beginning 1/1/2010, combined NQ< emissions from Units 5,6,7, and 8 must be no more than 360 tons per year. Clark Generating Station Nevada Units Unite Unit? Units Units may only fire natural gas ncrease water injection immediately, then install and operate ultra- low NOx burners (ULNBs) or equivalent technology. In 2009, Units 5 and 8 may not emit more than 180 tons combined 5ppm 1- hour average 5ppm 1- hour average 5ppm 1- hour average 5ppm 1- hour average 12/31/08 (ULNB installation), 01/30/09 (1- hour average) 12/31/09 (ULNB installation), 01/30/10(1- hour average) 12/31/09 (ULNB installation), 01/30/10(1- hour average) 12/31/08 (ULNB installation), 01/30/09 (1- hour average) Allowances may not be used to comply with the Consent Decree, and no allowances made available due to compliance with the Consent Decree may be traded or sold. Reference http://www.epa.gov/complia nce/resources/cases/civil/c aa/nevadapower.html Dayton Power & Light Non-EPA Settlement of 10/23/2008 Stuart Generating Station PSEG FOSSIL, ft Kearny Ohio mended Conse New Jersey Station-wide it Decree of Unit? Units November 200C Retire unit Retire unit 01/01/07 01/01/07 Complete installation of FGDs on each unit. 96% or 0.10 82% including data from periods of malfunctions 82% including data from periods of malfunctions 07/31/09 7/31/09 through 7/30/1 1 after 7/31/11 Owners may not purchase any new catalyst with SO2 to SO3 conversion rate greater than 0.5% Install control technology on one unit 0.17 station- wide 0.17 station- wide 0.10 on any single unit 0.15 station- wide 0.10 station- wide 30 days after entry 60 days after entry date 12/31/12 07/01/12 12/31/14 0.030 Ib per unit Install rigid-type electro- des in each units ESP 07/31/09 12/31/15 Allowances allocated to Kearny, Hudson, and NOX and SO2 allowances may not be used to comply with the monthly rates specified in the Consent Decree. Courtlink document provided by EPA in email http://www.epa.gov/complia nce/resources/decrees/ame nded/psegfossil-amended- cd.pdf ------- Company and Plant Hudson Mercer Westar Energy Jeffrey Energy Center Duke Energy Gallagher American Munic Gorsuch Station State New Jersey New Jersey Kansas Indiana pal Power Ohio Unit Unit 2 Units 1 &2 All units Units 1 & 3 Units 2&4 Units 2&3 Units 1 &4 Settlement Actions Ret ire /Re power Action Effective Date Retire or re power as natural gas 1/1/2012 Elected to Retire Dec 15, 2010 (must retire by Dec 31, 2012) SO2 control Equipment Install Dry FGD (or approved alt. technology) and continually operate Install Dry FGD (or approved alt. technology) and continually operate Percent Removal or Rate 0.15 Annual Cap (tons) 5,547 5,270 5,270 5,270 0.15 Effective Date 12/31/10 Year 2007 2008 2009 2010 12/31/10 Units 1, 2, and 3 have a total annual limit of 6,600 tons of SO2 and an annual rate limit of 0.07 Ibs/MMBtu starting 2012 Units 1, 2, and 3 must all install FGDs by 201 1 and operate them continuously. FGDs must ma ntain a 30-Day Rolling Average Unit Removal Efficiency for SO2 of at least 97% or a 30-Day Rolling Average Unit Emission Rate for SO2 of no greater than 0.070 Ib/MMBtu. Install Dry sorbent injection technology 80% 1/1/2012 NOX Contro Equipment Install SCR (or approved tech) and continually operate Install SCR (or approved tech) and continually operate Rate 0.1 Annual Cap (tons) 3,486 3,486 3,486 3,486 0.1 Effective Date 12/31/10 Year 2007 2008 2009 2010 01/01/07 Units 1-3 must continuously operate Low NOx Combustion Systems by 2012 and achieve and ma ntain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.1 80 Ib/MMBtu. One of the three units must install an SCR by 2015 and operate it continuously to maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.080 Ib/MMBtu. By 2013 Westar shall elect to either (a) install a second SCR on one of the other JEC Units by 201 7 or (b) meet a 0.100 Ib/MMBtu Plant- Wide 12-Month Rolling Average Emission Rate and 9.6 MTons annual cap for NOx by 2015 PM or Mercury Control Equipment Install Baghouse (or approved technology) Install Baghouse (or approved technology) Rate 0.015 0.015 Effective Date 12/31/10 12/31/10 Units 1, 2, and 3 must operate each ESP and FGD system continuously by 201 1 and maintain a 0.030 Ib/MMBtu PM Emissions Rate. Units 1 and 2's ESPs must be rebuilt by 2014 in order to meet a 0.030 Ib/MMBtu PM Emissions Rate Allowance Retirement Retirement Mercer may only be used for the operational needs of those units, and all surplus allowances must be surrendered. Within 90 days of amended Consent Decree, PSEG must surrender 1,230 NO, Allowances and 8,568 SO2 Allowances not already allocated to or generated by the units listed here. Kearny allowances must be surrendered with the shutdown of those units. Allowance Restriction Restriction Effective Date Reference http://ampparr.ners. ora/news roo m/amp-to- retire-go rs uch- gene rating-station/ ------- Company and Plant Hoosier Energy Ratts Merom Tennessee Valle Allen Steam Plan Bull Run Colbert Cumberland Gallatin John Sevier Johnsonville Kingston Paradise Shawnee Widows Creek State Rural Electric C Indiana Indiana y Authority Tennessee Tennessee Alabama Tennessee Tennessee Tennessee Tennessee Kentucky Kentucky Kentucky Alabama Unit ^operative Units 1 &2 Unitl Unit 2 Units 1 - 3 Unitl Units 1 - 4 Units Units 1 &2 Units 1 - 4 Units 1 & 2 Units 3 & 4 Units 1 - 4 Units 5- 8 Units 9 & 10 Units 1 - 9 Units 1 & 2 Units Units 1 &4 Units 1 & 2 Units 3 & 4 Units 5 & 6 Units 7 & 8 Settlement Actions Retire /Repower . .. Effective Action Date Retire 12/31/2012 Retire 12/31/2017 Retire 12/31/2018 Retire 12/31/2019 Retire 7/31/2013 Retire 7/31/2014 Retire 7/31/2015 SO2 control Equipment Percent Removal or Rate Effective Date Continusly run current FGD for 90% removal and update FGD for 98% removal by 2012 Continusly run current FGD for 90% removal and update FGD for 98% removal by 2014 Install FGD Operate Wet FGD Install FGD Install FGD Operate Wet FGD Install FGD 98% 98% 2012 2014 12/31/2015 In NEEDS 6/30/2016 12/31/2015 In NEEDS 12/31/2017 Install FGD 12/31/2015 Operate Wet FGD Upgrade FGD Operate Wet FGD Install FGD 93% In NEEDS 12/31/2012 In NEEDS 12/31/2017 Operate Wet FGD In NEEDS NOX Contro Equipment Installs, continually operate SNCRS Continuously operate existing SCRs Operate SCR Operate SCR Install SCR Operate SCR Operate SCR Install SCR Rate 0.25 0.12 Effective Date 12/31/2011 In NEEDS In NEEDS 6/30/2016 In NEEDS In NEEDS 12/31/2017 Install SCR 12/31/2015 Operate SCR Operate SCR Operate SCR Install SCR In NEEDS In NEEDS In NEEDS 12/31/2017 Operate SCR In NEEDS PM or Mercury Control _ . . _ . Effective Equipment Rate Continuously operate ESP Continuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/12 Continuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/13 Allowance Retirement Retirement Allowance Restriction Restriction Effective Date Annually surrender any NOx and SO2 allowances that Hoosier does not need in order to meet its regulatory obligations Reference http://www.epa.dov/complia nce/resources/cases/civil/c aa/hoosier.html Notes: 1) Updates to the EPA Base Case 4.10_FTransportfrom EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the control requirements on the Mercer plant under the PSEG Fossil settlement, and an update to the SO2 emission modeling on Jeffrey Energy Center as part of the Westar settlement. 2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description of all elements of the actual settlement agreements. 3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, future actions are generally modeled as individual constraints on emission rates in EPA Base Case, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire. 4) Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place are built into EPA Base Case 5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not included in EPA Base Case. 6) For units for which an FGD is modeled as an emissions constraint in EPA Base Case, EPA used the assumptions on removal efficiencies that are shown in the latest emission control technologies documentation 7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and a corresponding 95% removal efficiency for wet and 90% for dry. 8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 Ib/MMBtu or used the emission limit if provided. 9) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case documentation materials. 10) EPA included in EPA Base Case the requirements of the settlements as they existed on January 1, 2011. 11) Some of the NSR settlements require the retirement of SO2 allowances. For the Base Case, EPA estimate the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly. ------- Appendix 3-4 State Settlements in EPA Base Case v4.10_FTransport Company and Plant State Unit State Enforcement Actions Retire/Repower Actio n AES Greenidge Westover Hickling Jennison New York New York New York New York Unit 4 Units Units Unit 7 Units 1 & 2 Units 1 & 2 Effective Date SO2 control Equipment Percent Removal or Rate Effective Date NOX Control Equipment Rate Effective Date PM Control Equipment Rate Efj^jjJ[Ve Mercury Control Equipment Rate Effective Date Install FGD Install BACT Install BACT Install BACT Install BACT 90% 90% 09/01/07 12/31/09 12/31/10 12/31/09 05/01/07 05/01/07 Install SCR Install BACT Install SCR Install BACT Install BACT Install BACT 0.15 0.15 09/01/07 12/31/09 12/31/10 12/31/09 05/01/07 05/01/07 Niagara Mohawk Power NRG shall comply with the below annual tonnage limitat ons for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2 and 1 0,777 tons of NOX, 2006 is 34,230 of SO2 and 6,772 of NOX, 2007 is 30,859 of SO2 and 6,21 1 of NOX, 2008 is 22,733 tons of SO2 Huntley New York Units 63-66 Retire Public Service Co. of NM San Juan New Mexico Unitl Unit 2 Units Unit 4 B20W State-of-the- art technology 90% 10/31/08 03/31/09 04/30/08 10/31/07 State-of-the- art technology 0.3 10/31/08 03/31/09 04/30/08 10/31/07 12/31/09 Operate 12/31/og Baqhouse and - -,r demister 04/30/08 technoloav 10/31/07 Design activated carbon injection technology (or comparable tech) 12/31/09 12/31/09 04/30/08 10/31/07 Public Service Co of Colorado Comanche Colora do Units 1 & 2 Units Install and operate FGD Install and operate FGD 0.1 Ib/mmBtu combined average 0.1 Ib/mmBtu 07/01/09 Install low- NOX emission controls Install and operate SCR 0.15 Ib/mmBtu combined average 0.08 07/01/09 Install and operate a fabric filter dust 0.013 collection system Install sorbent injection technology Install sorbent injection technology 07/01/09 Within 180 days of start-up Rochester Gas & Electric Russell Plant New York Units 1 -4 Retire all units Mirant New York Lovett Plant New York Unitl Unit 2 Retire Retire 05/07/07 04/30/08 Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court of Appeals, Fourth Circuit Court reversing the settlement. ------- |