3 1 CHAPTER 3. SO2 AND CARBON REDUCTION OPTIONS This chapter provides the results of analysis of hypothetical pollution control options for SO2 and carbon emissions from the electric power industry. It is organized into three sections: ( 1) SO2 reduction options, ( 2) carbon reduction options, and ( 3) SO2 and carbon reduction options.

The options presented in this report are hypothetical approaches to emission controls on the electric power industry for each pollutant and do not represent the EPA or Administration position on how any of these pollutants should be reduced in the future. EPA has made no determinations whether or how much additional SO2 control could be needed to address fine particulate problems, or whether and to what extent there should be future reductions of mercury or carbon dioxide emissions. Specifically with regard to carbon dioxide, the Administration has committed not to implement the Kyoto Protocol without the advice and consent of the Senate.

SO2 REDUCTION OPTIONS The SO2 control options examined in this report are at levels below what is required for power plants under the CAAA Title IV SO2 Allowance Trading program. These reduced levels were examined because additional SO2 reductions from electric generators, which are the dominant source of SO2 emissions, are likely to be essential to any future program designed to meet the fine particle ambient air quality standard.

The analysis of the SO2 control options assumes a continuation of the current emissions cap and trade program with the " banking" of SO2 allowances ( stockpiling of allowances for future use, or trading). For these alternatives, the SO2 emissions cap is lowered in 2007 to a level that analysis indicates will provide substantial SO2 reductions in 2010 from the Base Case. Under these options, allowances that are banked under the Title IV program before 2007 could be used by power plants to make a gradual transition to the lower SO2 levels of the 2007 emissions caps.

For this analysis, IPM was set to simulate a SO2 emissions cap for the power generation industry for 2007 and beyond. It was assumed that the cap was imposed at the beginning of 2005 and that companies could " bank" additional allowances in 2005 to 2007 for use later. Exhibit 3 1 lists the four options that were set up for this analysis and the SO2 emissions caps that would go into effect in 2007 and thereafter. The title of each alternative control option reflects the percentage reduction each option provides in SO2 emissions levels compared to the Base Case in 2010. 3 2 Exhibit 3 1 Options for SO2 Emissions Reduction Beyond CAAA Title IV for the Electric Power Industry Control Options Based on their Specified SO2 Emissions Reduction Target* 2007 SO2 Emissions Cap ( 1,000 tons)

40 Percent Reduction in SO2 in 2010 4,261 45 Percent Reduction in SO2 in 2010 3,788 50 Percent Reduction in SO2 in 2010 3,314 55 Percent Reduction in SO2 in 2010 2,841 * Reduction from the Base Case of 9,662 thousand tons of SO2 in 2010.

Air Emissions Changes For each of the pollution control options, EPA modeled the changes in SO2, NOx, carbon, and mercury emissions from the Base Case. Exhibits 3 2 through 3 6 show the national results of the analysis for each of the control options compared to the Base Case emissions. The last two exhibits in this series show mercury emissions for all sources and for coal fired units only. Exhibits 3 7 through 3 18 show the regional emissions for each air pollutant over time for these control options. The amount of regional emissions reduction occurring under each control option can be determined by comparing these results to the Base Case regional results in Chapter 2 ( see Exhibits 2 7 through 2 9).

In addition to lowering SO2 emissions, each control option decreases mercury emissions significantly from coal fired units. In the alternatives examined, mercury reductions in 2010 are 10 to 14 percent lower than the Base Case. This results from the addition of flue gas desulfurization units ( scrubbers) at coal fired units, which are assumed on average to remove a third of the mercury in the flue gas, and from the movement to greater natural gas generation from coal. ( Natural gas has only trace concentrations of mercury). There are much smaller percentage reductions in NOx and carbon emissions from these alternative SO2 control options. The results suggest that the installation of scrubbers is the dominant reason for the mercury reductions. More details on how the electric generation system responds to each of the control options are provided in the next section. 3 3 Exhibit 3 2 Annual SO2 Emissions for the Electric Power Industry for the Base Case and Four SO2 Reduction Options ( 1,000 tons)

Options 2005 2007 2010 Base Case 11,049 10,864 9,658 40 Percent Reduction in SO2 in 2010 7,103 7,021 5,661 45 Percent Reduction in SO2 in 2010 6,714 6,430 5,300 50 Percent Reduction in SO2 in 2010 6,303 5,868 4,939 55 Percent Reduction in SO2 in 2010 5,938 5,672 4,523 Exhibit 3 3 Annual and Summer NOx Emissions for the Electric Power Industry for the Base Case and Four SO2 Reduction Options ( 1,000 tons)

Options 2005 2007 2010 Annual Emissions Base Case 4,221 4,255 4,147 40 Percent Reduction in SO2 in 2010 4,212 4,252 4,085 45 Percent Reduction in SO2 in 2010 4,210 4,247 4,049 50 Percent Reduction in SO2 in 2010 4,203 4,246 4,019 55 Percent Reduction in SO2 in 2010 4,192 4,237 4,006 Summer Emissions Base Case 1,436 1,449 1,386 40 Percent Reduction in SO2 in 2010 1,436 1,449 1,375 45 Percent Reduction in SO2 in 2010 1,435 1,448 1,369 50 Percent Reduction in SO2 in 2010 1,432 1,448 1,353 55 Percent Reduction in SO2 in 2010 1,431 1,447 1,350 3 4 Exhibit 3 4 Annual Carbon Emissions for the Electric Power Industry for the Base Case and Four SO2 Reduction Options ( Million Metric Tons)

Options 2005 2007 2010 Base Case 605 615 621 40 Percent Reduction in SO2 in 2010 604 614 615 45 Percent Reduction in SO2 in 2010 603 613 612 50 Percent Reduction in SO2 in 2010 603 613 610 55 Percent Reduction in SO2 in 2010 602 612 608 Exhibit 3 5 Annual Mercury Emissions for All Sources in the Electric Power Industry for the Base Case and Four SO2 Reduction Options ( Tons)

Options 2005 2007 2010 Base Case 51.9 52.0 50.9 40 Percent Reduction in SO2 in 2010 47.5 47.6 45.9 45 Percent Reduction in SO2 in 2010 47.3 46.5 45.1 50 Percent Reduction in SO2 in 2010 46.4 46.1 44.5 55 Percent Reduction in SO2 in 2010 46.0 46.0 43.8 Exhibit 3 6 Annual Mercury Emissions for the Coal Fired Units of the Electric Power Industry for the Base Case and Four SO2 Reduction Options ( Tons)

Options 2005 2007 2010 Base Case 47.9 48.0 46.9 40 Percent Reduction in SO2 in 2010 43.4 43.6 41.9 45 Percent Reduction in SO2 in 2010 43.3 42.5 41.2 50 Percent Reduction in SO2 in 2010 42.4 42.1 40.5 55 Percent Reduction in SO2 in 2010 42.0 42.0 39.8 3 5 Exhibit 3 7 Regional Electric Generation and Air Emissions for 2005 40% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 37 86 28 93 273 1.1 16 ECAO 221 525 167 797 1,527 7.6 117 ERCT 126 261 154 323 318 4.3 45 MACE 46 101 17 58 101 1.2 9 MACW 43 101 28 120 131 2.0 17 MACS 24 55 15 64 63 0.7 9 WUMS 24 57 19 66 195 1.0 12 MANO 83 193 51 224 492 4.1 37 MAPP 73 165 154 356 442 3.6 39 UPNY 57 131 22 63 116 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 62 184 1.5 12 FRCC 90 183 121 251 198 2.1 29 VACA 126 292 69 270 826 3.4 42 TVA 66 154 43 193 420 2.2 26 SOU 103 231 87 270 807 3.6 41 SPPN 40 91 53 156 174 1.4 20 SPPS 114 227 152 303 471 2.7 41 CNV 109 249 32 76 50 1.2 22 WSCP 71 168 19 45 22 0.3 7 WSCR 109 252 178 418 294 2.7 51 TOTAL 1,610 3,633 1,436 4,212 7,103 47.5 604 3 6 Exhibit 3 8 Regional Electric Generation and Air Emissions for 2007 40% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 88 27 92 269 1.1 16 ECAO 220 527 166 800 1,474 7.4 117 ERCT 129 269 158 333 318 4.3 47 MACE 45 96 18 60 104 1.3 10 MACW 43 103 29 124 139 2.0 17 MACS 25 58 15 65 63 0.8 9 WUMS 25 58 19 63 190 1.0 12 MANO 87 203 51 223 487 4.1 37 MAPP 75 167 155 356 438 3.6 39 UPNY 59 135 22 63 113 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 63 182 1.5 12 FRCC 95 192 122 249 198 2.1 30 VACA 132 306 70 277 834 3.5 44 TVA 66 155 43 193 417 2.2 26 SOU 103 234 87 276 785 3.6 42 SPPN 41 93 54 160 177 1.4 21 SPPS 119 234 157 306 471 2.7 42 CNV 113 261 33 80 50 1.2 24 WSCP 71 168 19 45 22 0.3 7 WSCR 110 255 179 420 292 2.7 52 TOTAL 1,645 3,712 1,449 4,252 7,021 47.6 614 3 7 Exhibit 3 9 Regional Electric Generation and Air Emissions for 2010 40% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 40 92 27 92 268 1.1 17 ECAO 226 537 181 830 1,245 7.5 121 ERCT 136 285 124 247 291 4.0 44 MACE 51 104 17 57 67 1.3 11 MACW 41 98 29 126 91 2.1 18 MACS 26 63 15 67 58 0.7 9 WUMS 26 59 19 64 188 1.0 13 MANO 87 203 51 227 366 3.5 37 MAPP 76 171 151 351 430 3.5 39 UPNY 54 120 18 50 108 0.8 9 LILC 6 14 1 3 0 0.3 1 NENG 49 118 16 43 59 1.5 12 FRCC 98 200 112 233 172 2.1 30 VACA 136 320 67 279 509 3.2 45 TVA 68 158 41 186 373 2.1 25 SOU 108 241 86 273 476 3.3 42 SPPN 44 100 55 161 167 1.4 22 SPPS 122 244 139 269 429 2.6 41 CNV 121 274 31 73 50 1.2 21 WSCP 76 181 17 39 22 0.3 8 WSCR 108 249 177 416 292 2.7 51 TOTAL 1,699 3,830 1,375 4,085 5,661 45.9 615 3 8 Exhibit 3 10 Regional Electric Generation and Air Emissions for 2005 45% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 86 28 93 270 1.1 16 ECAO 220 524 168 799 1,310 7.3 117 ERCT 126 261 155 323 318 4.3 45 MACE 46 101 17 58 95 1.3 9 MACW 43 101 28 120 128 2.0 17 MACS 24 56 15 65 55 0.8 9 WUMS 24 57 19 66 195 1.0 12 MANO 84 194 52 226 488 4.1 37 MAPP 74 165 154 356 438 3.6 39 UPNY 57 131 22 64 117 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 62 180 1.5 12 FRCC 90 183 119 248 181 2.1 29 VACA 125 290 69 267 773 3.4 41 TVA 65 154 41 191 416 2.1 26 SOU 102 231 87 271 740 3.5 41 SPPN 40 91 53 157 173 1.4 20 SPPS 115 228 153 304 471 2.7 41 CNV 109 249 32 76 50 1.2 22 WSCP 71 168 19 45 22 0.3 7 WSCR 109 252 178 418 293 2.7 51 TOTAL 1,609 3,633 1,435 4,210 6,714 47.3 603 3 9 Exhibit 3 11 Regional Electric Generation and Air Emissions for 2007 45% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 39 88 27 92 264 1.0 16 ECAO 220 526 167 799 1,270 7.3 117 ERCT 129 269 158 333 318 4.3 47 MACE 45 96 18 60 102 1.3 10 MACW 43 103 29 124 118 2.0 17 MACS 24 59 15 67 58 0.7 9 WUMS 25 57 19 63 187 1.0 12 MANO 87 203 51 225 371 3.5 36 MAPP 75 167 154 355 435 3.6 39 UPNY 59 135 22 63 113 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 63 148 1.4 12 FRCC 96 192 121 246 180 2.1 30 VACA 131 304 69 272 773 3.5 43 TVA 66 156 43 193 421 2.1 26 SOU 103 235 87 280 671 3.5 42 SPPN 41 94 54 161 171 1.3 21 SPPS 119 234 157 304 466 2.6 42 CNV 113 261 33 80 50 1.2 24 WSCP 71 168 19 45 22 0.3 7 WSCR 110 255 179 420 291 2.7 52 TOTAL 1,645 3,712 1,448 4,247 6,430 46.5 613 3 10 Exhibit 3 12 Regional Electric Generation and Air Emissions for 2010 45% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 40 92 27 92 267 1.1 17 ECAO 225 534 182 826 1,172 7.4 121 ERCT 136 285 124 239 274 3.8 43 MACE 50 104 16 57 66 1.3 11 MACW 41 98 29 126 91 2.1 18 MACS 26 63 15 67 58 0.9 9 WUMS 26 58 18 62 185 1.0 12 MANO 87 202 51 225 337 3.4 36 MAPP 76 172 149 347 423 3.5 39 UPNY 54 120 18 50 102 0.7 9 LILC 6 15 1 3 0 0.3 1 NENG 50 118 16 43 50 1.4 12 FRCC 98 200 111 222 146 2.0 30 VACA 136 319 69 279 416 3.2 45 TVA 67 156 40 182 360 2.0 25 SOU 107 242 86 277 403 3.2 43 SPPN 44 101 54 160 164 1.3 22 SPPS 123 246 137 265 423 2.5 41 CNV 121 274 31 73 50 1.2 21 WSCP 76 181 17 39 22 0.3 8 WSCR 108 249 177 416 291 2.7 51 TOTAL 1,699 3,830 1,369 4,049 5,300 45.1 612 3 11 Exhibit 3 13 Regional Electric Generation and Air Emissions for 2005 50% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 86 28 93 271 1.1 16 ECAO 220 523 169 798 1,273 7.3 117 ERCT 126 261 155 323 318 4.3 45 MACE 46 101 17 58 94 1.3 9 MACW 43 101 29 119 115 2.0 17 MACS 24 56 15 65 55 0.8 9 WUMS 24 57 19 66 195 1.0 12 MANO 83 194 52 228 375 3.5 37 MAPP 74 165 154 355 437 3.6 38 UPNY 57 131 22 64 117 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 62 116 1.5 12 FRCC 90 183 119 247 180 2.1 29 VACA 125 290 68 267 707 3.3 41 TVA 65 154 41 189 416 2.1 25 SOU 102 231 87 273 644 3.4 41 SPPN 40 91 53 157 168 1.3 20 SPPS 115 228 150 296 460 2.6 41 CNV 109 249 32 76 50 1.2 22 WSCP 71 168 19 45 22 0.3 7 WSCR 109 252 178 418 293 2.7 51 TOTAL 1,609 3,633 1,432 4,203 6,303 46.4 603 3 12 Exhibit 3 14 Regional Electric Generation and Air Emissions for 2007 50% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 39 88 27 92 262 1.0 16 ECAO 221 526 168 799 1,195 7.2 117 ERCT 129 269 158 333 318 4.3 47 MACE 45 96 18 60 99 1.3 10 MACW 44 103 29 124 89 2.1 17 MACS 24 58 15 66 56 0.7 9 WUMS 25 57 19 63 187 1.0 12 MANO 86 202 50 225 361 3.4 36 MAPP 75 166 154 355 434 3.5 39 UPNY 59 135 22 63 113 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 63 116 1.5 12 FRCC 96 193 121 249 182 2.1 30 VACA 132 305 70 273 556 3.3 43 TVA 66 155 42 191 395 2.1 26 SOU 102 233 87 278 506 3.3 42 SPPN 42 95 54 160 169 1.3 21 SPPS 119 234 157 304 466 2.6 42 CNV 113 261 33 80 50 1.2 24 WSCP 71 168 19 45 22 0.3 7 WSCR 110 255 179 420 291 2.7 52 TOTAL 1,645 3,712 1,448 4,246 5,868 46.1 613 3 13 Exhibit 3 15 Regional Electric Generation and Air Emissions for 2010 50% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 41 93 27 92 249 1.0 17 ECAO 225 533 181 824 1,092 7.3 121 ERCT 136 285 121 236 268 3.7 42 MACE 50 103 16 57 66 1.3 11 MACW 41 98 29 126 91 2.1 18 MACS 26 63 15 67 56 1.0 9 WUMS 26 58 18 63 185 1.0 12 MANO 87 202 51 225 320 3.3 36 MAPP 76 172 149 346 400 3.5 38 UPNY 54 120 18 50 102 0.7 9 LILC 6 15 1 3 0 0.3 1 NENG 49 118 16 43 49 1.3 12 FRCC 97 200 100 207 115 1.9 29 VACA 136 320 69 280 400 3.1 46 TVA 68 156 40 180 355 1.9 25 SOU 108 242 87 272 340 3.0 42 SPPN 44 101 54 160 164 1.3 21 SPPS 123 247 135 263 327 2.4 41 CNV 121 274 31 73 50 1.2 21 WSCP 76 181 17 39 22 0.3 8 WSCR 108 249 177 416 290 2.7 51 TOTAL 1,699 3,830 1,353 4,019 4,939 44.5 610 3 14 Exhibit 3 16 Regional Electric Generation and Air Emissions for 2005 55% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 86 28 93 269 1.1 16 ECAO 220 523 170 798 1,217 7.3 117 ERCT 126 261 154 323 318 4.3 45 MACE 46 100 17 57 92 1.3 9 MACW 43 102 29 121 85 2.0 17 MACS 23 56 14 64 54 0.7 9 WUMS 24 57 19 66 195 1.0 12 MANO 83 193 51 227 371 3.5 37 MAPP 74 165 154 354 435 3.6 38 UPNY 57 131 22 64 117 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 62 116 1.5 12 FRCC 90 183 119 243 170 2.0 29 VACA 126 289 69 265 533 3.2 41 TVA 66 155 41 188 402 2.1 25 SOU 102 231 87 273 572 3.3 41 SPPN 40 92 53 158 169 1.3 21 SPPS 115 228 149 295 460 2.6 41 CNV 109 249 32 76 50 1.2 22 WSCP 71 168 19 45 22 0.3 7 WSCR 109 252 178 418 293 2.7 51 TOTAL 1,609 3,633 1,431 4,192 5,938 46.0 602 3 15 Exhibit 3 17 Regional Electric Generation and Air Emissions for 2007 55% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 39 88 27 92 262 1.0 16 ECAO 220 525 169 799 1,161 7.2 117 ERCT 130 270 159 334 318 4.3 47 MACE 46 97 18 62 77 1.3 10 MACW 44 103 29 123 86 2.1 17 MACS 24 58 15 66 55 0.7 9 WUMS 25 57 19 63 187 1.0 12 MANO 86 202 50 225 357 3.4 36 MAPP 75 166 154 353 433 3.5 39 UPNY 59 135 22 63 112 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 63 121 1.5 12 FRCC 96 193 121 245 172 2.1 30 VACA 132 305 70 273 544 3.3 43 TVA 67 157 42 189 385 2.1 26 SOU 101 232 86 277 423 3.3 42 SPPN 42 95 53 160 169 1.3 21 SPPS 119 233 155 303 447 2.6 41 CNV 113 261 33 80 50 1.2 24 WSCP 71 168 19 45 22 0.3 7 WSCR 110 255 179 420 291 2.7 52 TOTAL 1,645 3,712 1,447 4,237 5,672 46.0 612 3 16 Exhibit 3 18 Regional Electric Generation and Air Emissions for 2010 55% SO2 Reduction in 2010 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 40 92 26 90 148 0.9 16 ECAO 225 534 181 827 1,015 7.3 121 ERCT 136 284 121 237 247 3.6 42 MACE 50 103 16 58 54 1.3 11 MACW 41 98 29 125 90 2.1 18 MACS 26 62 15 66 50 1.0 9 WUMS 26 58 18 62 184 1.0 12 MANO 87 202 51 223 315 3.3 36 MAPP 76 172 148 345 397 3.5 38 UPNY 54 120 18 50 97 0.7 9 LILC 6 15 1 3 0 0.3 1 NENG 50 118 16 43 36 1.3 12 FRCC 97 200 99 205 114 1.9 29 VACA 138 322 71 282 301 3.0 46 TVA 67 157 40 180 353 1.9 25 SOU 108 240 86 268 282 2.9 41 SPPN 44 101 54 159 162 1.4 21 SPPS 122 247 133 257 319 2.3 40 CNV 121 275 31 73 50 1.2 21 WSCP 76 181 17 39 22 0.3 8 WSCR 108 249 177 416 287 2.7 51 TOTAL 1,699 3,829 1,350 4,006 4,523 43.8 608 3 17 Costs and Power System Changes The electric generation system will make adjustments to meet electricity demand and comply with the pollution control requirements of each of these SO2 reduction options. Exhibit 3 19 shows the annual incremental electricity production costs for power companies installing controls and making other changes to reduce SO2 emissions to the specified levels.

Exhibit 3 19 shows the incremental cost ( from the Base Case) of meeting the alternative SO2 levels. Although the analysis assumed that the SO2 emissions levels were lowered in 2007 to achieve a specific percentage reduction from the Base Case in 2010, Exhibit 3 19 shows that costs begin accruing in 2005 as many companies decide to make reductions early at a lower cost, banking those early reductions for later use. Such early banking reduces overall costs by providing sources with an option to make a more gradual transition into compliance with a lower SO2 emissions cap than a program without banking can provide.

Exhibit 3 19 Annual Costs for the Electric Power Industry for Four SO2 Reduction Options ( Million 1990$)

Control Options 2005 2007 2010 40 Percent Reduction in SO2 in 2010 $ 1,230 $ 1,282 $ 1,873 45 Percent Reduction in SO2 in 2010 $ 1,465 $ 1,639 $ 2,121 50 Percent Reduction in SO2 in 2010 $ 1,656 $ 1,977 $ 2,451 55 Percent Reduction in SO2 in 2010 $ 1,908 $ 2,116 $ 2,814 The compliance costs result from the installation of scrubbers, the addition of more natural gas combined cycle capacity, and changes in the dispatching of generation units   there is less use of coal fired generation and more use of units powered by natural gas. Exhibit 3 20 shows the increases in scrubber installation relative to the Base Case. Under the Base Case, at the beginning of 2005, about 90 GW of about 304 GW of coal fired capacity should already have scrubbers. Exhibit 3 21 shows the increases in natural gas combined cycle capacity as the SO2 emissions levels are lowered. Exhibit 3 22 provides the changes in electric generation that occurs under each of the control cases relative to the Base Case for generation units that use coal and natural gas/ oil. There is little change from the base case in the output of generation units using other fuels ( e. g. nuclear, hydroelectric) in the SO2 reduction alternatives. The next section shows the changes in coal and other fossil fuel use. 3 18 Exhibit 3 20 Cumulative Installation of New Scrubber Capacity at Coal Fired Units for the Base Case and Four SO2 Reduction Options ( GW) Options 2005 2007 2010 Base Case 4 4 6 40% SO2 Reduction in 2010 43 45 70 45% SO2 Reduction in 2010 52 59 75 50% SO2 Reduction in 2010 61 68 82 55% SO2 Reduction in 2010 67 71 93 Exhibit 3 21 Natural Gas Combined Cycle Capacity for the Base Case and Four SO2 Reduction Options ( GW) Options 2005 2007 2010 Base Case 45 50 112 40% SO2 Reduction in 2010 47 52 116 45% SO2 Reduction in 2010 47 52 117 50% SO2 Reduction in 2010 48 52 118 55% SO2 Reduction in 2010 49 53 119 Note: These estimates include both new combined cycle and repowered units to combined cycle. 3 19 Exhibit 3 22 Electric Generation Capacity and Production for Units Using Fossil Fuels for the Base Case and Four SO2 Reduction Options Fuel Type Capacity by Fuel Type ( GW) Generation by Fuel Type ( Billion kWh)

2005 2007 2010 2005 2007 2010 Base Case Coal 305 305 304 2,084 2,091 2,114 Oil/ Natural Gas 240 250 282 561 626 759 40% SO2 Reduction in 2010 Coal 304 304 302 2,066 2,073 2,067 Oil/ Natural Gas 241 251 283 578 643 805 45% SO2 Reduction in 2010 Coal 304 303 302 2,061 2,067 2,051 Oil/ Natural Gas 241 252 283 583 649 822 50% SO2 Reduction in 2010 Coal 304 303 301 2,057 2,063 2,038 Oil/ Natural Gas 242 252 285 587 653 835 55% SO2 Reduction in 2010 Coal 304 303 301 2,053 2,058 2,029 Oil/ Natural Gas 242 252 285 591 658 843 Note: Coal fired units are assumed to lose about 2 percent of their capacity when they install scrubbers. See Exhibit 3 20 to assess the impact of scrubber installation on the capacity over time.

Fossil Fuel Use Exhibits 3 23 through 3 27 show the changes in coal consumption that result from each of the alternative pollution control options relative to the Base Case. ( See Exhibit 2 11 for a geographic breakout of the coal supply regions.) Exhibit 3 28 shows the changes in natural gas and oil use by the power industry.

As expected, a lower SO2 emissions cap leads to lower coal demand and greater use of natural gas. The exhibits also show that the lower the SO2 emissions level, the lower will be the use of low sulfur western coal. This result occurs because the larger reductions in SO2 emissions can most cost effectively be reached by scrubbing lower sulfur ( generally Eastern) coal. 3 20 Exhibit 3 23 Coal Consumption by the Electric Power Industry by the Major Supply Regions for the Base Case ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 138 138 109 Central and Southern Appalachia 185 186 213 Midwest 125 120 109 West 503 511 540 Central West and Gulf 64 64 63 Total 1,015 1,019 1,034 Exhibit 3 24 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 40 % SO2 Reduction in 2010 ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 123 127 138 Central and Southern Appalachia 181 177 173 Midwest 141 144 148 West 506 506 492 Central West and Gulf 62 63 57 Total 1,014 1,017 1,008 Exhibit 3 25 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 45 % SO2 Reduction in 2010 ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 139 142 138 Central and Southern Appalachia 162 164 172 Midwest 145 152 147 West 503 491 488 Central West and Gulf 62 63 52 Total 1,012 1,011 997 3 21 Exhibit 3 26 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 50 % SO2 Reduction in 2010 ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 145 145 142 Central and Southern Appalachia 158 164 172 Midwest 153 150 140 West 489 489 486 Central West and Gulf 62 63 49 Total 1,008 1,009 989 Exhibit 3 27 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 55 % SO2 Reduction in 2010 ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 147 148 142 Central and Southern Appalachia 155 161 176 Midwest 153 147 142 West 488 488 476 Central West and Gulf 62 61 48 Total 1,005 1,006 984 3 22 Exhibit 3 28 Natural Gas and Oil Consumption Under the Base Case and Options to Lower SO2 Emissions by the Electric Power Industry Fuel Type Units 2005 2007 2010 Base Case Natural Gas Trillion cubic feet 4.6 5.2 5.3 Oil Million Barrels 21.3 21.5 0.0 40% SO2 Reduction in 2010 Natural Gas Trillion cubic feet 4.7 5.3 5.6 Oil Million Barrels 21.2 21.0 0.0 45% SO2 Reduction in 2010 Natural Gas Trillion cubic feet 4.8 5.3 5.7 Oil Million Barrels 21.0 21.0 0.0 50% SO2 Reduction in 2010 Natural Gas Trillion cubic feet 4.8 5.4 5.8 Oil Million Barrels 21.0 21.0 0.0 55% SO2 Reduction in 2010 Natural Gas Trillion cubic feet 4.8 5.4 5.8 Oil Million Barrels 21.0 21.0 0.0 CARBON REDUCTION OPTIONS In the current debate about future U. S. efforts to address climate change, various stakeholders and analysts have advanced a number of ways to lower emissions of carbon dioxide and other greenhouse gases. For this study, EPA selected two of these many options to analyze the effects that alternative carbon control levels could have on the electric power industry's costs and emissions. These options were chosen simply to represent different approaches to possible limitations on carbon emissions for electric power generators. They do not represent the full possible range of carbon control alternatives for the electric power industry. They also do not represent an EPA or Administration position on what the electric power industry should do to address climate change.

The two hypothetical options are:

Carbon Level of 567 MMT in 2008   In this hypothetical case, the following assumptions are made: 3 23 1. Beginning in 2008, electric power companies are required to have emissions allowances to cover their carbon emissions. The industry is issued a certain number of U. S. emissions allowances and is permitted to buy more allowances in an international trading market.

2. The power industry is allocated 463 MMT of carbon emissions allowances per year. This is 3 percent below the 1990 carbon emissions level of the power industry. 1 3. The power industry finds it most economical to lower its annual domestic carbon emissions down to 567 MMT and to purchase 104 MMT of allowances annually on the international market. 2 In the analysis of this option, the 567 MMT carbon emissions level is modeled as a domestic carbon cap and power plants are allowed to trade emissions allowances with each other. 3 This alternative is consistent with the economic analysis prepared by the White House Council of Economic Advisors in July 1998.4 Electricity demand in this option is the same as in the Base Case. This hypothetical option does not account for the electricity demand reductions that could result from possible increased electricity prices caused by the cost of meeting the alternative carbon levels. This option does not include additional energy efficiency measures assumed in the second option described below.

High Efficiency/ Carbon Level of 515 MMT in 2008   In this hypothetical case, assumptions 1 and 2 are the same, but the following different assumptions are made:

1. Domestic demand side programs are in place that lower electric demand by about 1.5 percent per year from 2000 through 2010 and by about 1 percent per year 1 For the U. S., the Kyoto Protocol requires a 7 percent reduction in greenhouse gases below 1990 levels between 2008 and 2012. Many analysts believe that the U. S. would really be required to lower carbon emissions to 3 percent below 1990 levels, since the Kyoto Protocol allows credit for growth in carbon sinks ( such as forest growth), which is expected to amount to 4 percent over the 2008 2012 period. The reduction target assumed for the power sector in this analysis is based on the assumption that each industry makes proportional reductions in emissions to 3 percent below its 1990 levels. The electric power industry's 1990 carbon emissions level was 477 MMT. Other assumptions could lead to higher or lower targets for the power sector. 2 This analysis assumes that international trading of carbon allowances is not restricted, consistent with the Council of Economic Advisors' study of July 1998 ( see reference 4 below). The Energy Information Administration ( EIA) estimated that electric power generators would reduce domestic carbon emissions to 567 MMT in 2010 and make international carbon allowance purchases for the rest of the needed allowances. Domestic emissions of 567 MMT would be 19 percent above 1990 levels and 15 below levels EIA has forecasted in its reference case for 2010. See EIA, Impacts of the Kyoto Protocol on U. S. Energy Markets and Economic Activity, October 1998. 3 The Kyoto Protocol actually sets up a five year budget period for 2008 2012, with a total carbon allowance budget equal to five times an annual level. This study modeled carbon as an annual limit, however, and did not attempt to model banking ( stockpiling of allowances for later use) either within the 2008 2012 period, or into a future five year period. Banking would be expected to make a program less expensive over its lifetime by providing inter temporal flexibility: Power generators would have flexibility to use a total of five times this annual limit over the five year period, in any manner that they wished, and to carry over any unused allowances from the first period to later ones. The extent of banking between periods could not be modeled without assumptions regarding carbon limits in future periods, which would go beyond the scope of this study. 4 Council of Economic Advisors, the White House, The Kyoto Protocol and the President's Policies to Address Climate Change: Administration Economic Analysis, July 1998. 3 24 from 2010 through 2020.5 By 2010, the electricity demand would be 15 percent lower than the power industry has projected it will be and forecasted carbon emissions for the power industry would be 590 MMT.

2. The power industry finds it least expensive to lower emissions to 515 MMT annually and purchase 52 MMT of allowances annually. The 515 MMT carbon emissions level is modeled as a domestic carbon emissions cap on the industry and power plants are allowed to trade emissions allowances. 6 EPA and Lawrence Berkeley National Laboratory of the Department of Energy have examined an option similar to this in a recent study. 7 Air Emissions EPA examined the changes in air emissions from 2005 to 2010 for these options. Because no early reduction banking system was assumed and because the assumed start date for meeting the carbon limits was 2008, all large changes in air emissions and operation of the electric power system relative to the Base Case occur only in the 2010 results. Therefore, only the results for 2010 are reported here. Exhibits 3 29 and 3 30 provide a national summary of air emissions for the two carbon reduction alternatives and the Base Case. Exhibits 3 31 and 3 32 show the regional emissions for the carbon reduction options ( these can be compared to the regional emissions in Chapter 2 for the Base Case.)

In 2010, the option limiting carbon emissions to 567 MMT in 2008 option lowers annual carbon emissions by 54 million metric tons ( i. e., about nine percent) below the Base Case forecast. 8 However, it lowers annual mercury emissions by about 15 percent from coal fired units. This is caused by the projected fuel use for electric generation shifting away from coal to natural gas. Natural gas has about 60 percent of the carbon emissions per BTU of fuel use, and only trace concentrations of mercury. Annual SO2 emissions are nearly unchanged because of the assumed SO2 emissions cap in place under Title IV of the Clean Air Act. This cap leads 5 North American Electric Reliability Council, Electricity Supply & Demand, 1997, electronic files released in fall 1997. 6 A carbon emissions level of 515 MMT is nine percent above 1990 levels and 21 percent below where Energy Information Administration ( EIA) has forecasted that the U. S. electric power industry will be in its reference case in 2010 ( 657 MMT), in a recent study that EIA published on options to lower carbon emissions in the energy sector. The recent EIA study is entitled Impacts of the Kyoto Protocol on U. S. Energy Markets and Economic Activity, October 1998. 7 U. S. Environmental Protection Agency and Ernest Orlando Lawrence Berkeley National Laboratory, Technology and Greenhouse Gas Emissions: An Integrated Scenario Analysis Using the LBNL NEMS Model, October 1998. 8 Earlier IPM analysis of setting carbon emissions caps in trading programs for the electric power industry shows that there is a direct relationship between the level of the carbon emissions cap and mercury emissions that will occur. As the carbon level is set at lower levels, IPM analysis of the resulting mercury emissions from the electric power industry shows that it also decreases and does so at a proportionately greater rate. This is because as the emissions cap is decreased ( i. e., made more stringent) there is less use of coal fired generation, the main source of mercury emissions, and it is displaced with natural gas generation which has much lower carbon emissions and virtually no mercury emissions. For instance, in a presentation made by EPA in November 1998 at the Center for Clean Air Policy, IPM analysis showed that having a carbon level at 477 MMT in 2010 lowers carbon emissions by 23 percent and mercury emissions by 33 percent. 3 25 sources that lower their coal use to sell allowances to other sources that will use higher sulfur coals. Summer and annual NOx emissions drop by 13 percent and 15 percent, respectively. These reductions are caused by the projected switch from coal to natural gas generation, which has lower NOx levels. The summer emissions reduction is lower, because the power companies in areas that are covered by the NOx SIP call lower NOx emissions through greater natural gas use and sell their excess allowances to other companies.

The High Efficiency   Carbon Level at 515 MMT in 2008 option lowers annual carbon emissions by 106 million metric tons below the Base Case ( more than 15 percent). However, it lowers annual mercury from coal fired units by about 23 percent. Annual SO2 emissions do not change significantly, but summer and annual NOx emissions drop by 20 percent and 23 percent, respectively. These results occur for the same reasons mentioned in the first carbon option above.

Exhibit 3 29 Annual Changes in Selected Air Emissions in 2010 for the Electric Power Industry for the Base Case and Two Carbon Reduction Options SO2 Annual NOx Summer NOx Carbon Control Options ( 1,000 tons) ( 1,000 tons) ( 1,000 tons) ( MMT)

Base Case 9,658 4,147 1,386 621 Carbon Level at 567 MMT in 2008 9,574 3,518 1,201 567 High Efficiency   Carbon Level at 515 MMT in 2008 9,389 3,203 1,109 515 Exhibit 3 30 Annual Changes in Mercury Emissions in 2010 for All Sources and Coal fired Units in the Electric Power Industry for the Base Case and Two Carbon Reduction Options ( Tons) Control Sources All Sources Coal fired Units Base Case 50.9 46.9 Carbon Level at 567 MMT in 2008 43.7 39.7 High Efficiency  Carbon Level at 515 MMT in 2008 39.9 35.9 3 26 Exhibit 3 31 Regional Electric Generation and Air Emissions for 2010 Carbon Level of 567 MMT in 2008 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 41 92 26 87 264 0.7 16 ECAO 226 533 187 832 3,021 8.4 119 ERCT 136 283 85 139 236 2.3 34 MACE 47 98 16 56 129 1.2 10 MACW 41 98 30 123 553 2.9 17 MACS 29 71 14 65 210 1.1 10 WUMS 26 61 19 63 186 0.9 13 MANO 83 185 49 182 797 3.6 31 MAPP 77 176 126 288 443 2.8 35 UPNY 56 122 19 50 183 1.1 9 LILC 7 16 2 3 0 0.3 1 NENG 48 117 15 42 126 1.5 11 FRCC 98 206 88 174 247 1.8 27 VACA 136 319 68 267 916 3.5 44 TVA 70 163 42 184 552 2.0 26 SOU 104 223 78 219 890 3.1 36 SPPN 43 94 42 97 119 0.8 16 SPPS 126 266 86 147 252 1.4 33 CNV 124 281 31 73 50 1.2 22 WSCP 79 186 17 39 124 0.4 8 WSCR 102 237 163 387 277 2.5 48 TOTAL 1,699 3,827 1,201 3,518 9,574 43.7 567 3 27 Exhibit 3 32 Regional Electric Generation and Air Emissions for 2010 High Efficiency   Carbon Level of 515 MMT in 2008 Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 85 28 87 258 0.8 15 ECAO 216 508 187 798 3,134 8.0 113 ERCT 126 265 66 106 168 1.5 29 MACE 40 86 16 56 129 1.2 9 MACW 41 97 31 124 554 2.9 17 MACS 29 69 15 62 212 1.0 10 WUMS 24 56 18 59 173 0.8 12 MANO 76 173 44 168 774 3.2 28 MAPP 70 160 109 249 415 2.5 30 UPNY 53 115 20 51 181 1.1 9 LILC 7 15 1 3 0 0.3 1 NENG 45 109 15 42 126 1.5 11 FRCC 91 194 75 147 200 1.7 25 VACA 125 290 70 261 910 3.4 40 TVA 66 154 38 154 509 1.7 22 SOU 99 206 81 207 958 2.9 33 SPPN 39 86 26 49 57 0.4 11 SPPS 122 258 75 116 207 1.1 29 CNV 118 268 30 71 50 1.2 20 WSCP 71 168 16 38 124 0.4 7 WSCR 96 222 150 355 250 2.4 44 TOTAL 1,592 3,585 1,109 3,203 9,389 39.9 515 3 28 Costs and Power System Changes In the model, electric power generators make adjustments in such things as fuel use, generator capacity utilization and new generation construction in response to changes in assumed energy demand and emissions limitations. Exhibit 3 33 shows the annual incremental costs of these adjustments for the carbon reduction options.

Note that in both cases domestic carbon emissions remain above power generators' 1990 levels. The costs and emissions reductions shown in this report are only those that result from the reductions from the Base Case level to 567 MMT and 515 MMT. The cost of purchasing international emissions allowances is not shown in this analysis. 9 The costs shown in Exhibit 3 33 are the annualized incremental costs of reducing domestic carbon emissions from levels associated with the baseline electricity demand. In the case of the 567 MMT Carbon Level option, this is a reduction of 54 MMT. This option assumes that electricity demand is the same as that used in the Base Case. For the High Efficiency option, there is a reduction of 106 MMT from Base Case levels in 2010. About 30 MMT of this reduction come from the reduction in electricity demand caused by the assumed energy efficiency measures ( see Appendix E for references describing such measures) included in this option. The investment costs and the resultant savings from electricity use are shown in Exhibit 3 34. The costs of achieving the remaining 76 MMT from changes in electricity production are shown in Exhibit 3 33.

Exhibit 3 33 Annual Costs for the Electric Power Industry in 2010 for Two Options to Lower Carbon Emissions Options Million 1990$ Carbon Level of 567 MMT in 2008 $ 1,038 High Efficiency   Carbon Level of 515 MMT in 2008 $ 2,000 Note: Costs include the additional resources that are expended to produce electric power, if the industry is lowering carbon emissions to the levels specified in each option. It does not include purchasing of carbon allowances in an international trading program. A discussion of allowance purchase costs occurs in reference 9 below.

9 The costs to the power industry of buying carbon allowances under an international cap and trade approach are difficult to estimate. The number of allowances purchased internationally depends on the number of domestic allowances that the industry is awarded and the price of international allowances. If it is assumed that the power industry is annually awarded 463 MMT of carbon allowances and that the international cost of allowances is $ 19.50 per ton in 1990 dollars ( equivalent to $ 23 per ton in 1996 dollars, the high end of the range in the CEA report referenced earlier), the costs would be estimated as follows: For the first option ( 567 MMT in 2008), the annual allowance costs would be $ 2 billion. For the second option ( High Efficiency   515 MMT in 2008), the annual allowance costs would be $ 1 billion. 3 29 Exhibit 3 34 Annual Costs for the Electric Power Industry and Power Users And Savings Resulting from Lower Electricity Use in 2010 in the High Efficiency   Carbon Level of 515 MMT in 2008 Option Cost Categories Million 1990$ Increased Production Costs* $ 2,000 Investment in Energy Reduction 4,986 Savings from Energy Reduction 7,864 Net Savings $ 878 * Costs include the additional resources that are expended to produce electric power, if the industry is lowering carbon emissions to the levels specified in each option. It does not include purchasing of carbon allowances in an international trading program. A discussion of allowance purchase costs occurs in reference 9 in this chapter.

Changes in scrubber installation, combined cycle capacity, and the mix of electric generation for units using fossil fuels are shown in Exhibits 3 35 through 3 37. Notably, neither carbon program option leads to increased use of generation units that use renewable fuels for power in 2010.

Exhibit 3 35 Installation of New Scrubber Capacity at Coal fired Units in 2010 for the Base Case and Two Carbon Reduction Options Options GW Base Case 6 Carbon Level of 567 MMT in 2008 4 High Efficiency / Carbon Level of 515 MMT in 2008 3 Exhibit 3 36 Installation of Natural Gas Combined Cycle Capacity in 2010 for the Base Case and Two Carbon Reduction Options Options GW Base Case 112 Carbon Level of 567 MMT in 2008 148 High Efficiency/ Carbon Level of 515 MMT in 2008 137 Note: These estimates include both new combined cycle and repowered units to combined cycle. 3 30 Exhibit 3 37 Electric Generation Capacity and Production for Units Using Fossil Fuels for the Base Case and Two Carbon Reduction Options Fuel Type Capacity by Fuel Type ( GW) Generation by Fuel Type ( Billion kWh)

2010 2010 Base Case Coal 304 2,114 Oil/ Natural Gas 282 759 Carbon Level of 567 MMT in 2008 Coal 300 1,843 Oil/ Natural Gas 287 1,027 High Efficiency   Carbon Level of 515 MMT in 2008 Coal 285 1,682 Oil/ Natural Gas 254 947 Note: Coal fired units are assumed to lose about 2 percent of their capacity when they install scrubbers. See Exhibit 3 35 to assess the impact of scrubber installation on the capacity over time.

Fuel Use Exhibits 3 38 through 3 41 show the forecasted fuel demand for coal and natural gas in 2010 for the two carbon reduction options. Both carbon options produce substantial changes in the demand for coal and natural gas, because fuel switching to less carbon intensive fuels is a major way of reducing carbon emissions from electricity production. No oil use is projected for 2010 under either option. 3 31 Exhibit 3 38 Coal Consumption by the Electric Power Industry by the Major Supply Regions in 2010 Under the Base Case Coal Supply Areas Million tons Northern Appalachia 109 Central and Southern Appalachia 213 Midwest 109 West 540 Central West and Gulf 63 Total 1,034 Exhibit 3 39 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 2010 Under a Carbon Level of 567 MMT in 2008 Coal Supply Areas Million tons Northern Appalachia 129 Central and Southern Appalachia 185 Midwest 117 West 400 Central West and Gulf 31 Total 861 Exhibit 3 40 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 2010 Under High Efficiency/ Carbon Level of 515 MMT in 2008 Coal Supply Areas Million tons Northern Appalachia 134 Central and Southern Appalachia 169 Midwest 114 West 335 Central West and Gulf 18 Total 771 3 32 Exhibit 3 41 Natural Gas Consumption by the Electric Power Industry in 2010 for the Base Case and Two Carbon Reduction Options Options Trillion Cubic Feet Base Case 5.3 Carbon Level of 567 MMT in 2008 6.7 High Efficiency/ Carbon Level of 515 MMT in 2008 6.2 SO2 AND CARBON REDUCTION OPTIONS This study also considered two options that lowered both carbon and SO2 emissions. In both options, carbon and SO2 emissions limitations are simulated to be achieved through capand trade programs. Early reduction banking of allowances is allowed for SO2 emissions, but not for carbon emissions. The two options are:

  SO2 Reduction of 50 Percent/ Carbon Level of 567 MMT  the CAAA Title IV SO2 emissions cap is lowered in 2007 to a level that provides a 50 percent reduction in 2010. In 2008, a carbon emissions cap is set in IPM at the level of 567 MMT. After being set, the new SO2 and carbon emissions caps remain constant through 2025. The analysis uses a conservative assumption that there will not be a reduction in electric demand resulting from the higher electricity costs that occur because of compliance with the SO2 and carbon reduction requirements.

  SO2 Reduction of 50 Percent/ High Efficiency with Carbon Level of 515 MMT the CAAA Title IV SO2 emissions cap is lowered in 2007 to a level that provides a 50 percent reduction in 2010. In 2008, a carbon emissions cap is set in IPM at a level of 515 MMT. After being set, the new SO2 and carbon emissions caps remain constant through 2025. In conjunction with these caps, the US pursues programs that lower electric demand from the Base Case by 15 percent in 2010. These energy efficiency programs begin in 2001 and gradually lower demand over time.

Air Emissions Exhibits 3 42 through 3 46 show the national air emissions changes for the two SO2/ Carbon reduction options. Regional emissions are presented in Exhibits 3 47 through 3 52. ( These regional emissions estimates can be compared to the Base Case in Chapter 2 to consider the significance of the emissions changes throughout the country.)

For SO2 emissions, the combination of a carbon reduction program with a program to lower SO2 emissions by 50 percent in 2010 leads to a shifting in the emissions pattern from 2005 to 2010. Recognizing that it will be cheaper to lower SO2 emissions in the future when a carbon program exists, the model projects that in 2005 and 2007 power companies will use more of their banked SO2 allowances and hold fewer in reserve in the future. 3 33 The combination of a carbon reduction program with a program to lower SO2 emissions by 50 percent in 2010 helps lower summer NOx emissions in 2010. In fact, if the existing installed NOx control equipment continues to operate as the model assumes that it will, summer NOx emissions in the NOx SIP call region drop below the NOx emissions cap by a small amount in 2010.

Of all the options examined in this chapter, the combined SO2/ Carbon reduction control options provide the greatest reduction in mercury emissions. By 2010, the 50% SO2 Reduction/ Carbon Level of 567 MMT option has mercury emissions from coal fired units that are 26 percent lower than the Base Case. The 50% SO2 Reduction/ High Efficiency   Carbon Level of 515 MMT option has mercury emissions from coal fired units that are 34 percent below the Base Case.

Exhibit 3 42 Annual SO2 Emissions for the Electric Power Industry for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( 1,000 tons) Options 2005 2007 2010 Base Case 11,049 10,864 9,658 50 % Reduction in SO2 in 2010 6,303 5,868 4,939 50 % Reduction in SO2/ Carbon Level of 567 MMT 6,971 6,913 4,641 50 % Reduction in SO2/ HE   Carbon Level of 515 MMT 7,260 7,099 4,549 3 34 Exhibit 3 43 Annual and Summer NOx Emissions for the Electric Power Industry for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( 1,000 tons) Options 2005 2007 2010 Annual Emissions Base Case 4,221 4,255 4,147 50 Percent Reduction in SO2 in 2010 4,203 4,246 4,019 50 % Reduction in SO2/ Carbon Level of 567 MMT 4,185 4,205 3,522 50 % Reduction in SO2/ HE   Carbon Level of 515 MMT 4,169 4,149 3,151 Summer Emissions NOx SIP Call Base Case 1,436 1,449 1,386 50 Percent Reduction in SO2 in 2010 1,432 1,448 1,353 50 % Reduction in SO2/ Carbon Level of 567 MMT 1,428 1,435 1,208 50 % Reduction in SO2/ HE   Carbon Level of 515 MMT 1,432 1,427 1,072 Exhibit 3 44 Annual Carbon Emissions for the Electric Power Industry for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( MMT) Options 2005 2007 2010 Base Case 605 615 621 50 Percent Reduction in SO2 in 2010 603 613 610 50 % Reduction in SO2/ Carbon Level of 567 MMT 602 611 567 50 % Reduction in SO2/ HE   Carbon Level of 515 MMT 593 592 515 3 35 Exhibit 3 45 Annual Mercury Emissions for All Sources in the Electric Power Industry for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( Tons) Options 2005 2007 2010 Base Case 51.9 52.0 50.9 50 Percent Reduction in SO2 in 2010 46.4 46.1 44.5 50 % Reduction in SO2/ Carbon Level of 567 MMT 47.2 47.2 38.6 50 % Reduction in SO2/ HE   Carbon Level of 515 MMT 47.1 46.7 34.8 Exhibit 3 46 Annual Mercury Emissions for the Coal Fired Units of the Electric Power Industry for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( Tons) Options 2005 2007 2010 Base Case 47.9 48.0 46.9 50 Percent Reduction in SO2 in 2010 42.4 42.1 40.5 50 % Reduction in SO2/ Carbon Level of 567 MMT 43.2 43.2 34.7 50 % Reduction in SO2/ HE   Carbon Level of 515 MMT 43.1 42.7 30.8 3 36 Exhibit 3 47 Regional Electric Generation and Air Emissions for 2005 50% Reduction in SO2/ Carbon Level of 567 MMT Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 37 85 29 93 275 1.1 16 ECAO 219 523 166 796 1,411 7.4 116 ERCT 126 261 154 322 318 4.3 45 MACE 46 101 17 58 99 1.2 9 MACW 43 101 28 120 130 2.0 17 MACS 24 55 15 64 63 0.8 9 WUMS 24 57 19 65 194 1.0 12 MANO 82 192 50 223 482 4.0 37 MAPP 77 173 150 343 449 3.5 39 UPNY 58 132 22 64 116 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 104 24 62 183 1.5 12 FRCC 89 183 120 249 201 2.1 29 VACA 126 292 69 270 803 3.4 42 TVA 67 155 43 191 411 2.2 26 SOU 104 229 88 265 824 3.6 41 SPPN 40 91 53 156 173 1.4 20 SPPS 112 226 149 302 474 2.7 41 CNV 109 249 32 76 50 1.2 22 WSCP 71 168 19 44 22 0.3 7 WSCR 109 251 178 418 293 2.7 51 TOTAL 1,610 3,633 1,428 4,185 6,971 47.2 602 3 37 Exhibit 3 48 Regional Electric Generation and Air Emissions for 2007 50% Reduction in SO2/ Carbon Level of 567 MMT Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 87 28 93 269 1.1 16 ECAO 220 525 167 798 1,367 7.3 117 ERCT 129 269 158 333 318 4.3 47 MACE 45 95 18 60 103 1.3 10 MACW 43 103 29 124 136 2.0 17 MACS 26 62 15 65 63 0.8 9 WUMS 24 58 18 64 189 1.0 12 MANO 85 200 49 216 469 3.9 36 MAPP 79 174 150 342 444 3.5 39 UPNY 59 134 22 63 113 0.8 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 24 63 183 1.5 12 FRCC 93 190 118 245 196 2.0 29 VACA 131 303 69 274 810 3.5 43 TVA 70 159 43 191 410 2.1 26 SOU 104 231 88 268 837 3.6 41 SPPN 42 96 54 156 173 1.4 21 SPPS 116 231 152 301 471 2.7 41 CNV 113 261 33 80 50 1.2 24 WSCP 71 168 19 45 22 0.3 7 WSCR 110 255 179 420 291 2.7 52 TOTAL 1,645 3,712 1,435 4,205 6,913 47.2 611 3 38 Exhibit 3 49 Regional Electric Generation and Air Emissions for 2010 50% Reduction in SO2/ Carbon Level of 567 MMT Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 40 92 27 88 253 0.7 16 ECAO 223 526 190 819 1,186 7.3 118 ERCT 135 282 94 164 180 2.5 36 MACE 48 100 16 54 81 1.2 10 MACW 42 97 31 122 82 2.1 17 MACS 29 74 14 60 37 0.7 10 WUMS 26 60 20 61 179 0.9 12 MANO 82 185 48 190 308 3.0 31 MAPP 75 171 120 275 316 2.8 33 UPNY 53 119 17 49 92 0.7 9 LILC 7 16 2 3 0 0.3 1 NENG 50 119 16 42 45 1.3 12 FRCC 101 211 92 192 115 1.8 29 VACA 136 317 65 249 426 2.8 42 TVA 73 168 37 160 289 1.6 24 SOU 102 216 80 218 344 2.5 35 SPPN 46 104 48 124 117 1.0 19 SPPS 125 268 89 158 244 1.6 34 CNV 123 281 31 73 50 1.2 22 WSCP 78 184 17 39 22 0.3 8 WSCR 104 239 168 393 276 2.5 48 TOTAL 1,698 3,828 1,220 3,534 4,641 38.6 567 3 39 Exhibit 3 50 Regional Electric Generation and Air Emissions for 2005 50% Reduction in SO2/ High Efficiency   Carbon Level of 515 MMT Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 36 83 29 93 276 1.1 16 ECAO 215 514 164 782 1,390 7.1 114 ERCT 123 256 158 335 318 4.3 45 MACE 46 100 18 59 101 1.2 9 MACW 43 101 29 120 132 2.0 17 MACS 21 49 15 62 106 0.7 8 WUMS 23 56 19 65 192 1.0 12 MANO 82 190 50 217 513 4.0 36 MAPP 75 168 151 345 478 3.5 38 UPNY 58 131 22 63 117 0.8 11 LILC 3 4 2 4 0 0.3 1 NENG 43 102 24 62 190 1.5 12 FRCC 87 178 121 248 273 2.1 28 VACA 124 288 70 269 825 3.5 41 TVA 67 153 43 189 405 2.1 25 SOU 103 228 87 262 924 3.7 40 SPPN 39 89 55 157 179 1.4 20 SPPS 107 217 148 303 475 2.7 40 CNV 107 245 32 76 50 1.2 21 WSCP 67 160 17 42 22 0.3 6 WSCR 109 251 178 417 294 2.7 51 TOTAL 1,577 3,561 1,432 4,169 7,260 47.1 593 3 40 Exhibit 3 51 Regional Electric Generation and Air Emissions for 2007 50% Reduction in SO2/ High Efficiency   Carbon Level of 515 MMT Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 36 83 28 92 273 1.1 16 ECAO 214 511 165 776 1,317 7.0 113 ERCT 125 259 160 339 318 4.3 46 MACE 43 93 18 60 105 1.2 9 MACW 43 103 30 124 139 2.0 17 MACS 23 55 15 64 102 0.7 9 WUMS 24 57 18 62 185 1.0 12 MANO 83 194 48 207 449 3.8 34 MAPP 75 166 149 340 467 3.5 38 UPNY 57 132 21 62 113 0.8 10 LILC 3 4 2 4 0 0.3 0 NENG 42 100 24 61 186 1.5 12 FRCC 88 180 119 244 269 2.1 28 VACA 125 290 70 272 839 3.5 42 TVA 66 152 42 187 398 2.1 25 SOU 104 230 88 262 923 3.7 41 SPPN 41 92 54 156 175 1.4 20 SPPS 105 213 146 299 475 2.7 40 CNV 108 246 32 76 50 1.2 21 WSCP 69 163 18 44 22 0.3 7 WSCR 109 251 178 417 293 2.7 51 TOTAL 1,584 3,573 1,427 4,149 7,099 46.7 592 3 41 Exhibit 3 52 Regional Electric Generation and Air Emissions for 2010 50% Reduction in SO2/ High Efficiency   Carbon Level of 515 MMT Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 37 84 28 88 250 0.7 15 ECAO 211 501 192 792 1,142 6.7 112 ERCT 126 265 73 121 135 1.7 30 MACE 46 95 16 53 73 1.2 9 MACW 38 89 27 110 86 1.8 15 MACS 28 71 15 60 44 0.6 10 WUMS 24 56 20 59 170 0.8 11 MANO 77 171 47 176 316 2.8 28 MAPP 70 158 103 232 294 2.3 30 UPNY 52 114 17 42 67 0.5 7 LILC 7 15 1 3 0 0.3 1 NENG 46 111 15 39 68 1.3 10 FRCC 95 200 69 137 102 1.7 26 VACA 124 290 67 243 465 2.7 39 TVA 68 157 37 147 249 1.4 22 SOU 94 198 74 183 459 2.2 30 SPPN 41 93 43 104 94 0.8 17 SPPS 122 259 77 125 197 1.2 30 CNV 113 256 31 72 50 1.2 19 WSCP 71 167 16 38 22 0.3 6 WSCR 102 236 162 385 267 2.5 47 TOTAL 1,591 3,585 1,131 3,210 4,549 34.8 515 3 42 Cost and System Changes The electric generation system will make adjustments to meet changes in electricity demand and the pollution control requirements of each of these options. Exhibit 3 53 shows the incremental annual production costs for power companies installing controls and making other changes to comply with the alternatives. Earlier, Exhibits 3 19 and 3 33 showed the annualized costs of meeting the SO2 and Carbon options separately. In looking at those exhibits in conjunction with Exhibit 3 53, it becomes clear that a joint control program will have a much lower overall cost ( between $ 450 million to $ 800 million lower in 2010 for the options analyzed) than two separate programs since some of the actions the power industry takes to comply with either program are the same. This will be discussed further below.

If either of the options ( SO2 or carbon reduction) were considered to be the baseline upon which to judge the program costs of the other options, the incremental production costs of the other additional program would be much lower that those earlier exhibits indicate. For instance, if the 50 Percent SO2 reduction option is assumed be the baseline for judging the costs of a future carbon program, then the annual incremental production cost of the Carbon Level of 567 MMT in 2008 option in 2010 is $ 590 million, rather than $ 1,038 million ( Exhibit 3 33).

Exhibit 3 53 does not show for the 50% SO2 Reduction/ High Efficiency   Carbon Level at 515 MMT option the costs of the electric demand reduction program and its savings. This information is provided in Exhibit 3 54, which shows the increased electric generation production costs, demand reduction program costs and savings, and the net costs that occur for this option.

Exhibit 3 53 Annual Costs for the Electric Power Industry Combined SO2 / Carbon Reduction Options ( million 1990$) Options 2005 2007 2010 50 % SO2 Reduction/ Carbon Level 567 MMT $ 1,320 $ 1,337 $ 3,041 50 % SO2 Reduction/ High Efficiency   Carbon Level 515 MMT $ 1,117 $ 1,173 $ 3,629 Note: Costs include the additional resources that are expended to produce electric power, if the industry is lowering carbon emissions to the levels specified in each option. It does not include purchasing of carbon allowances in an international trading program. A discussion of allowance purchase costs occurs in reference 9 in this chapter. 3 43 Exhibit 3 54 Annual Incremental Production Costs for the Electric Power Industry and Power Users and Savings Resulting from Lower Electricity Use in 2010 for the 50% SO2 Reduction/ High Efficiency   Carbon Level 515 MMT Option Cost Categories Million 1990$

Increased Production Costs $ 3,629 Investment in Energy Reduction 4,986 Savings from Energy Reduction 7,864 Net Costs $ 751 Note: These costs do not include the purchase of carbon allowances in an international trading program The electricity production system compliance costs result from companies installing scrubbers, greater installation of natural gas combined cycle units, and changes in the dispatch of generation units   there is less use of coal fired generation and more use of units powered by natural gas. Exhibit 3 55 shows the differences in scrubber installation relative to the Base Case and the 50% SO2 Reduction in 2010 option. Exhibit 3 56 shows the changes in the installation of natural gas combined cycle capacity. Exhibit 3 57 provides the changes in electric generation that occurs under each of the control cases relative to the Base Case and the 50% SO2 Reduction in 2010 option for generation units that use coal and natural gas/ oil. Notably, there is little change occurring in the use of generation units using any other fuels in these combustion options.

When the three exhibits below are examined it becomes clear that to achieve the 50 Percent SO2 Reduction in 2010 under a single control alternative, the type of changes that the power industry will make are much different than it will make if it faces a combination of programs to lower SO2 and carbon at the same time. In the combined SO2/ carbon reduction options, the analysis projects that the electric power industry will rely more heavily on combined cycle natural gas generation than scrubbers for lowering SO2 emissions. The difference in this investment strategy is substantial, because each GW of installed scrubber capacity costs about $ 150 million to install ( in 1990$).

Exhibit 3 55 Installation of New Scrubber Capacity at Coal Fired Units for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( GW) Options 2005 2007 2010 Base Case 4 4 6 50% SO2 Reduction in 2010 61 68 82 50% SO2 Reduction / Carbon Level of 567 MMT in 2008 44 46 63 50% So2 Reduction / HE   Carbon Level of 515 MMT in 2008 38 39 45 3 44 Exhibit 3 56 Installation of Natural Gas Combined Cycle Capacity for the Base Case, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options ( GW) Baselines 2005 2007 2010 Base Case 45 50 112 50% SO2 Reduction in 2010 48 52 116 50% SO2 Reduction / Carbon Level of 567 MMT in 2008 50 58 148 50% SO2 Reduction / HE   Carbon Level of 515 MMT in 2008 41 44 139 Exhibit 3 57 Electric Generation Capacity and Production for Units Using Fossil Fuels for the Base Call, 50% SO2 Reduction, and Combined SO2 / Carbon Reduction Options Fuel Type Capacity by Plant Type ( GW) Generation by Plant Type ( Billion kWh) 2005 2007 2010 2005 2007 2010 Base Case Coal 305 305 304 2,084 2,091 2,114 Oil/ Natural Gas 240 250 282 561 626 759 50% SO2 Reduction Coal 304 303 301 2,057 2,060 2,038 Oil/ Natural Gas 242 252 285 587 653 835 50% SO2 Reduction / Carbon Level of 567 MMT Coal 304 304 294 2,058 2,060 1,817 Oil/ Natural Gas 241 251 291 586 656 1,054 50% SO2 Reduction/ HE Carbon Level of 515 MMT Coal 302 302 280 2,046 2,036 1,657 Oil/ Natural Gas 228 228 260 526 540 972 Note: Coal fired units are assumed to lose about 2 percent of their capacity when they install scrubbers. See Exhibit 3 55 to assess the impact of scrubber installation on the capacity over time. 3 45 Fossil Fuel Use Exhibits 3 58 through 3 61 show the changes in coal consumption that result for each of the pollution control options relative to the Base Case and the 50% SO2 Reduction in 2010 option. Exhibit 3 62 shows the changes in natural gas and oil use by the electric power industry.

Although total coal demand drops in each SO2/ carbon reduction option from the Base Case levels, in Northern Appalachia and the Midwest, there is actually an increase in demand. This occurs for largely the same reason that it did in the SO2 reduction options in the preceding section. After the cost effective SO2 reductions from the use of western coal occurs, the next most economical increment is to install scrubbers that use higher sulfur coal which is relatively inexpensive on a delivered basis.

Exhibit 3 58 Coal Consumption by the Electric Power Industry by the Major Supply Regions Under the Base Case ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 138 138 109 Central and Southern Appalachia 185 186 213 Midwest 125 120 109 West 503 511 540 Central West and Gulf 64 64 63 Total 1,015 1,019 1,034 Exhibit 3 59 Coal Consumption by the Electric Power Industry by the Major Supply Regions for 50 % SO2 Reduction ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 145 145 142 Central and Southern Appalachia 158 163 172 Midwest 153 150 140 West 489 489 486 Central West and Gulf 62 63 49 Total 1,008 1,009 989 3 46 Exhibit 3 60 Coal Consumption by the Electric Power Industry by the Major Supply Regions for the 50 Percent Reduction/ Carbon Level of 567 MMT ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 129 132 131 Central and Southern Appalachia 174 173 146 Midwest 140 139 135 West 504 502 406 Central West and Gulf 63 63 33 Total 1,010 1,009 852 Exhibit 3 61 Coal Consumption by the Electric Power Industry by the Major Supply Regions for the 50 Percent Reduction/ High Efficiency Carbon Level of 515 MMT ( million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 124 124 122 Central and Southern Appalachia 181 181 144 Midwest 131 130 116 West 504 499 373 Central West and Gulf 63 63 21 Total 1,004 998 775 3 47 Exhibit 3 62 Natural Gas and Oil Consumption under the Base Case and Options to Lower SO2 and Carbon Emissions by the Electric Power Industry Fuel Type Units 2005 2007 2010 Base Case Natural Gas Trillion cubic feet 4.6 5.2 5.3 Oil Million Barrels 21.3 21.5 0.0 50% SO2 Reduction Natural Gas Trillion cubic feet 4.8 5.4 5.8 Oil Million Barrels 21.0 21.0 0.0 50% SO2 Reduction / Carbon Level of 567 MMT in 2008 Natural Gas Trillion cubic feet 4.8 5.3 7.0 Oil Million Barrels 21.0 21.0 0.0 50% SO2 Reduction / HE  Carbon Level of 515 MMT in 2008 Natural Gas Trillion cubic feet 4.4 4.5 6.4 Oil Million Barrels 21.6 19.9 0.0


1 Kenton County, Kentucky Kenton County is part of the Cincinnati Hamilton, OH KY IN Metropolitan Statistical Area ( MSA) and is located to the west of Campbell County, Kentucky, to the east of Boone County, Kentucky, and to the south of Cincinnati, Ohio.

EPA s June 29, 2004 proposal on appropriate designations for Kentucky included Kenton County as nonattainment based on the following criteria:

  EPA indicates that Kenton County has monitoring data very close to the PM2.5 standard, and that this indicates a potential to contribute to the PM2.5 violations in the area;

  EPA states that Kenton County has relatively high population values, VMT, and commuting patterns that are significant enough to contribute to PM2.5 violations in the MSA.

Monitoring Data and Trends The monitor located in Kenton County shows attainment with the PM2.5 standard. For the 2001 2003 timeframe the design value ( 14.9 µ g/ m 3)

demonstrates attainment with the annual standard. The annual concentrations for the area continue to show a downward trend as depicted in Figure 1, which utilized data from the year 2000 through April 2004.

Figure 1 Northern Kentucky Area PM 2.5 Trend 11 12 13 14 15 16 17 18 19 20 2000 2001 2002 2003 2004 Year A n n u a l A r i th m e t i c M e a n ( m ic r o g r a m s / c u b i c m e t e r )

Campbel, KY Kenton, KY Butler , OH Hamilton, OH 2 Figure 2 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 Hamilton, OH Butler, OH Kenton, KY Campbell, KY Decline in PM Values for NKY Area 2000 2001 2002 2003 2000 2003 shows decrease of 12% 2000 2003 shows decrease of 12% 2000 2003 shows decrease of 11% 2000 2003 shows decrease of 11%

As depicted in Figure 2 above, monitoring data for the Northern Kentucky area shows an 11 12% decrease over from the year 2000 through 2003.

The Kenton County monitor is attaining the PM2.5 standard. The continuing downward trend in PM2.5 levels throughout the region indicate that air quality is improving in the region and should continue to do so over the next several years.

Population Growth and VMT Levels EPA stated that Kenton County had relatively high population density that had the potential to impact PM2.5 violations in the area. Kenton County makes up only 8% of the population in the entire MSA, see Figure 3 below. 3 Figure 3 Northern Kentucky Area 2002 Population for USEPA Proposed PM 2.5 Nonattainment Counties Campbell, KY 5% Kenton, KY 8% Boone, KY 5% Dearborn, IN 2%

Clermont, OH 10% Butler, OH 18% Warren, OH 9% Hamilton, OH 43%

Therefore, Kentucky believes that the population density in Kenton County should not be used as a determining factor for potential contributions to PM2.5 violations in Southwestern Ohio.

Based on EPA s June 29, 2004, discussion of VMT data in the region, an attempt was made to segregate county VMT data by state rather than reviewing the data for the region as a whole. This is an unfair comparison. Data presented by EPA shows the overwhelming contribution from VMT in the area to be occurring outside of Kenton County. Figure 4 below outlines total VMT per county for the MSA.

Figure 4 Cincinnati Hamilton MSA VMT per year In thousands 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 Hamilton, OH Clermont, OH Dearborn, IN Butler, OH Boone, KY Warren, OH Kenton, KY Campbell, KY Brown, OH Grant, KY Pendleton, KY Gallatin, KY Ohio, IN VMT 4 EPA s position on traffic and commuting patterns in the June 29 th letter noted that Kenton County has potentially significant numbers of commuters impacting Hamilton County.

Although EPA stated that commuting patterns may play a role in PM2.5 levels throughout the region, they also state that 20,200 commuters traveling from Kenton County into Hamilton County is insignificant when compared to total Hamilton County commuters in 2002. Kentucky agrees with EPA that commuter data is insignificant for Kenton County and therefore should not be used as a factor in determining nonattainment.

Additionally, when reviewing VMT data, it should be noted that in 2002 Kenton County contributed only 9.2% of the total VMT s in the counties recommended by EPA as having the potential to impact the violating monitors. Due to the small contribution from Kenton County, this factor should also not be used in determining a nonattainment designation for this county.

Therefore, it is Kentucky s position that Kenton County does not have the population density levels, commuter or VMT potential to contribute to PM2.5 violations in the area.

Additional Regional/ National Controls The implementation of new federal rules to decrease the amount of sulfur in both gasoline and diesel fuel will significantly decrease the amount of SO2 in the entire area. Because of the Low Sulfur Diesel Rule, in 2007, new clean engines operating on 15 ppm sulfur diesel fuel will reduce NOx emissions by 50%, and reduce PM emissions by more than 90%. Due to the Tier 2 Vehicle and Gasoline Sulfur program, by 2006 average national gasoline sulfur levels will be 90% lower.

Upon implementation of the Clean Air Interstate Rule ( CAIR) SO2 emissions from power plants will be reduced nationwide by 3.6 million tons in 2010 ( approximately 40 percent below current levels) and by another 2 million tons per year when the rules are fully implemented ( approximately 70 percent below current levels). NOx emissions would be cut by 1.5 million tons nationwide in 2010 and 1.8 million tons annually in 2015 ( about 65 percent below today s levels).

The first phase of compliance under the CAIR rule to reduce both SO2 and NOx emissions would be required by 2010, allowing substantial emission reductions in the area, by the proposed attainment date for PM2.5 nonattainment areas. 5 Conclusions Based on the factors discussed above, Kentucky believes that Kenton County should be designated attainment for the PM2.5 standard.

  PM2.5 levels continue to decline throughout the entire region. From a review of all monitors in the region, an average 12% decline in PM2.5 levels has occurred from 2000 through 2003. The Kenton County monitor in the region is currently showing attainment of the annual PM2.5 standard using 2002 through 2004 data.

  Contributions from commuters and vehicle miles traveled in Kenton County have been shown to have no potential to impact PM2.5 levels within the region when compared to the levels from other counties and therefore should not be used to determine nonattainment status for this county.

  Additional emission reduction on a national and regional level will provide substantial additional emission reductions in the region. The anticipated sulfur reductions due to the Low Sulfur Diesel Rule, the Tier 2 Vehicle and Gasoline Low Sulfur programs, and the Clean Air Interstate Rule ( CAIR) will further lower pollutant levels within this region.

To have this county designated nonattainment would invoke additional, substantial, unnecessary requirements on local government planning agencies. Drastic emission reductions are scheduled to occur in the mobile sector throughout the next several years that will greatly impact pollutant levels in the area. Couple these changes with those anticipated by the CAIR provisions which will further reduce SOx and NOx emissions within the region, and the air monitoring data demonstrating attainment of the PM2.5 Standard, the downward trend in monitored values, and the resulting conclusion is that Kenton County, Kentucky, should be designated attainment for the PM2.5 Standard.


First, you must determine whether any discharges from your pesticide application activities in any treatment areas included under your NOI are likely to overlap directly with any NMFS Listed Resources of Concern, as identified at https://www.epa.gov/npdes/pesticide-permitting-ESA-procedures.The website provides a map where the NMFS Listed Resources of Concern are present and contact information for regional NMFS offices in those areas. If you determine that any of your discharges are to waters of the United States containing NMFS Listed Resources of Concern, you should proceed to Step Two. If you determine that no discharges from your pesticide application activities are to waters of the United States containing NMFS Listed Resources of Concern, you can certify that the activity meets Criterion A (check box A on the NOI corresponding to Criterion A). In this case, you do not have to further consider any requirements related to Criteria B-F. Note that if you are not otherwise required to submit an NOI, you do not need to submit an NOI merely to document that you meet Criterion A. However, if you are required to submit an NOI anyway, you should document on the NOI that you meet Criterion A.
Step Two: Determine if a Previous ESA-Related Action has Already been Completed for your Activities
      For each discharge to waters of the United States containing NMFS Listed Resources of Concern, Decision-makers should determine whether they are eligible under either Criterion B or C because of a previously completed ESA Section 7 consultation, or a previously issued ESA Section 10 permit, respectively as follows:
 The effects of your activities have been addressed in a consultation under ESA Section 7 on a separate Federal action and the consultation resulted in a concurrence by NMFS that the discharge was not likely to adversely affect listed species or critical habitat or NMFS concluded in a biological opinion that the discharge or discharges were not likely to jeopardize listed species or destroy or adversely modify critical habitat, either as part of your activities as planned or as modified with a reasonable and prudent alternative (check box B corresponding to Criterion B). For example, most federal agencies that apply pesticides have already consulted with NMFS, as required under 50 C.F.R. § 402.01(a), and can therefore certify under this criterion.
 The effects of your activities have been addressed through approval of a Habitat Conservation Plan under Section 10 of the ESA (check box C corresponding to Criterion C). Your pesticide discharges may be authorized by this PGP if some activity is authorized through the issuance of a permit under Section 10 of the ESA and that authorization addressed the effects of your pesticide discharges on federally-listed species and designated critical habitat. You must follow NMFS procedures when applying for an ESA Section 10 permit (see 50 CFR 222.22). Application instructions for Section 10 permits for NMFS can be obtained by accessing the NMFS website (www.nmfs.noaa.gov) or by contacting the appropriate NMFS regional office.
      If you believe an existing ESA-related action may have already been completed for your planned pesticide application activities but you are uncertain of the details, you should contact your regional NMFS office (contact information available at https://www.epa.gov/npdes/pesticide-permitting-ESA-procedures). If an existing ESA-related action has not already been completed for your activities, proceed to Step Three.
Step Three: Determine if the Pesticide Application is in Response to a Declared Pest Emergency Situation
      Determine if all the discharges to waters of the United States containing NMFS Listed Resources of Concern and that are to be included in the NOI are being performed in response to a Declared Pest Emergency Situation as defined in Appendix A of the permit (check box D corresponding to Criterion D). In such a case, an NOI must be filed no later than 15 days after beginning to discharge with that NOI identifying:
       The location of the pest management area in detail or include a map of the location;
       Pest(s) to be controlled;
       Pesticide product(s) to be discharged and method of application;
       Planned quantity and rate of discharge(s) for each method of application;
       Number of planned discharges;
       Approximate date(s) of planned discharge(s); and
       The rationale supporting the determination whether the discharge is likely to adversely affect NMFS Listed Resources of Concern, including the description of appropriate measures to be undertaken to avoid or eliminate the likelihood of adverse effects.
Information provided for items 1 through 6 above must also include any discharges that have already occurred in the days (up to 15) prior to NOI submission. The discharge or discharges to address these Declared Pest Emergency Situations are authorized under the general permit for at least 60 days after beginning to discharge. You may continue to discharge after 60 days unless EPA advises the Operator that additional conditions or an individual permit are necessary. NMFS will, within 30 days of submission of the NOI, advise EPA whether the past and planned future discharges meet the eligibility criterion of not likely to adversely affect NMFS Listed Resources of Concern; whether the eligibility criterion could be met with additional conditions; or whether the eligibility criterion is not met. EPA will advise the Decision-maker within 15 days after receiving notification from NMFS whether the discharge or discharges qualify for coverage beyond the 60-day authorization provided under the permit. If EPA identifies additional conditions to qualify discharges as eligible for coverage beyond 60 days under the permit, those conditions remain in effect for the life of the permit. EPA expects to rely on NMFS' determination in identifying eligibility for continuing authorization, either with or without additional conditions. If you do not hear from EPA within 45 days of submitting your NOI, you may assume that your authorization to discharge continues unless and until notified otherwise by EPA.
      If your pesticide application is not in response to a Declared Pest Emergency Situation, proceed to Step Four.
Step Four: Determine if the Pesticide Application is not likely to adversely affect NMFS Listed Resources of Concern.
      The PGP provides two options for Decision-makers to demonstrate that discharges from pesticide applications to waters of the United States containing NMFS Listed Resources of Concern are not likely to adversely affect those resources for the activities for which the Decision-maker is seeking permit coverage. These options include: (1) obtaining confirmation from a NMFS Regional Office prior to NOI submission that discharges are not likely to adversely affect NMFS Listed Resources of Concern, or (2) self-certifying in the NOI that based on your analysis, you have concluded that discharges are not likely to adversely affect NMFS Listed Resources of Concern. Descriptions of procedures that are to be followed for these two options are described below.
       Option 1 (Criterion E): For each treatment area that will include discharges to waters of the United States containing NMFS Listed Resources of Concern, you may contact your Regional NMFS Office and request input regarding your planned discharges. If NMFS determines that your planned discharges are found to meet eligibility criteria for use (i.e., not likely to adversely affect NMFS Listed Resources of Concern), you have satisfied your eligibility obligations under Criterion E and you may submit your NOI for coverage under the PGP (check box E corresponding to Criterion E). As part of certifying your compliance with Criterion E, you must submit information received from NMFS acknowledging the discharges that they have determined are not likely to adversely affect NMFS Listed Resources of Concern and establishing any additional requirements for your permit eligibility. To maintain eligibility under the permit for those discharges, you must abide by those additional requirements for the duration of your coverage under the PGP.
       Option 2 (Criterion F): You must self-certify in your NOI that your discharge is not likely to adversely affect NMFS Listed Resources of Concern. To do so, you will have to take appropriate measures to avoid or eliminate the likelihood of adverse effects prior to applying for PGP coverage. These measures may be relatively simple, such as applying pesticides to waters at concentrations below those found to cause adverse effects, or during seasons when species of concern are not present Provided you are able to implement appropriate measures, you may proceed with submitting your NOI for coverage under the PGP (check box F corresponding to Criterion F). As part of certifying your compliance with Criterion F, you must submit information to support your findings, including:
          The location of the pest management area in detail or include a map of the location;
          Pest(s) to be controlled;
          Pesticide product(s) to be discharged and method of application;
          Planned quantity and rate of discharge(s) for each method of application;
          Number of planned discharges;
          Approximate date(s) of planned discharge(s); and
          The rationale supporting the determination that the criterion for which the NOI is submitted is being met, including the description of appropriate measures to be undertaken to avoid or eliminate the likelihood of adverse effects.
      This information will be posted online and also will be sent to NMFS for their review.
      NMFS will, within 30 days of submission of the NOI, advise EPA whether it believes the planned discharges meet the eligibility criteria of not likely to adversely affect NMFS Listed Resources of Concern, whether the eligibility criterion could be met with additional conditions; or whether the eligibility criterion is not met. EPA will advise the Decision-maker as to whether the intended discharges qualify to proceed under the General Permit or whether an individual permit will be required. EPA expects to rely on NMFS' determination in identifying eligibility for authorization, either with or without additional conditions. If you do not hear from EPA within 30 days, you may assume that your discharge is authorized without further conditions.
      You must comply with any terms and conditions imposed under the eligibility requirements to ensure that your pesticide discharges and discharge-related activities are protective of listed species and/or critical habitat. If the eligibility requirements cannot be met and maintained, then you are not eligible for coverage under this PGP. In these instances, you may consider applying to EPA for an individual permit or revising your pesticide application activities so as to comply with these eligibility conditions and resubmitting an NOI to EPA that documents this revised eligibility.


[Federal Register: March 11, 2008 (Volume 73, Number 48)]
[Notices]
[Page 12979]
[DOCID:fr11mr08-54]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. DI08-3-000]

Providence Water Supply Board; Notice of Declaration of Intention
and Soliciting Comments, Protests, and/or Motions to Intervene

March 3, 2008.
    Take notice that the following application has been filed with the
Commission and is available for public inspection:
    a. Application Type: Declaration of Intention.
    b. Docket No: DI08-3-000.
    c. Date Filed: February 7, 2008.
    d. Applicant: Providence Water Supply Board.
    e. Name of Project: Providence Water Release Hydroelectric Project.
    f. Location: The proposed Providence Water Release Hydroelectric
Project will be located on the North Branch Pawtuxet River, in
Providence County near Scituate, Rhode Island.
    g. Filed Pursuant to: Section 23(b)(1) of the Federal Power Act, 16
U.S.C. 817(b).
    h. Applicant Contact: Paul J. Gadoury, PE, Director of Engineering,
Providence Water Supply Board, 552 Academy Avenue, Providence, RI
02908; telephone:<PHONE_NUMBER>, ext. 7236; fax:<PHONE_NUMBER>; e-
mail<EMAIL_ADDRESS>    i. FERC Contact: Any questions on this notice should be addressed
to Henry Ecton,<PHONE_NUMBER>, or E-mail address:
<EMAIL_ADDRESS>    j. Deadline for filing comments, protests, and/or motions: April 3,
2008.
     All documents (original and eight copies) should be filed with:
Secretary, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426. Comments, protests, and/or interventions may be
filed electronically via the Internet in lieu of paper. See, 18 CFR
385.2001(a)(1)(iii) and the instructions on the Commission's Web site
at http://www.ferc.gov under the ``e-Filing'' link. Please include the
docket number (DI08-3-000) on any comments, protests, and/or motions
filed.
    k. Description of Project: The proposed Providence Water Release
Hydroelectric Project will include: (1) A 20-foot-long, 12-inch-
diameter pipe, carrying overflow releases from the 60-inch-diameter
pipe which carries water to the Providence Water Treatment Plant; (2) a
proposed concrete facility containing two turbines with a total
capacity of approximately 200 kW; (3) a short tailrace channeling water
through a blow-off structure which discharges into the North Branch,
Pawtuxet River; and (4) appurtenant facilities. The project will not be
connected to the interstate grid. Power generated will be used by the
water treatment plant. The proposed project will not occupy any tribal
or federal lands.
    When a Declaration of Intention is filed with the Federal Energy
Regulatory Commission, the Federal Power Act requires the Commission to
investigate and determine if the interests of interstate or foreign
commerce would be affected by the project. The Commission also
determines whether or not the project: (1) Would be located on a
navigable waterway; (2) would occupy or affect public lands or
reservations of the United States; (3) would utilize surplus water or
water power from a government dam; or (4) if applicable, has involved
or would involve any construction subsequent to 1935 that may have
increased or would increase the project's head or generating capacity,
or have otherwise significantly modified the project's pre-1935 design
or operation.
    l. Locations of the Application: Copies of this filing are on file
with the Commission and are available for public inspection. This
filing may be viewed on the web at http://www.ferc.gov. Using the
``eLibrary'' link, select ``Docket'' and follow the
instructions. For assistance, please contact FERC Online Support at
<EMAIL_ADDRESS>or toll-free at<PHONE_NUMBER>, or TTY,
contact<PHONE_NUMBER>.
    m. Individuals desiring to be included on the Commission's mailing
list should so indicate by writing to the Secretary of the Commission.
    n. Comments, Protests, or Motions to Intervene--Anyone may submit
comments, a protest, or a motion to intervene in accordance with the
requirements of Rules of Practice and Procedure, 18 CFR 385.210, .211,
.214. In determining the appropriate action to take, the Commission
will consider all protests or other comments filed, but only those who
file a motion to intervene in accordance with the Commission's Rules
may become a party to the proceeding. Any comments, protests, or
motions to intervene must be received on or before the specified
comment date for the particular application.
    o. Filing and Service of Responsive Documents--Any filings must
bear in all capital letters the title ``COMMENTS'', ``PROTESTS'', AND/
OR ``MOTIONS TO INTERVENE'', as applicable, and the Docket Number of
the particular application to which the filing refers. A copy of any
motion to intervene must also be served upon each representative of the
Applicant specified in the particular application.
    p. Agency Comments--Federal, State, and local agencies are invited
to file comments on the described application. A copy of the
application may be obtained by agencies directly from the Applicant. If
an agency does not file comments within the time specified for filing
comments, it will be presumed to have no comments. One copy of an
agency's comments must also be sent to the Applicant's representatives.

Kimberly D. Bose,
Secretary.
 [FR Doc. E8-4733 Filed 3-10-08; 8:45 am]

BILLING CODE 6717-01-P