Given that historic variability at well-balanced DRs is stable within a reasonable envelope appoximating the state-level variability limits, and given the observable

opportunities for future DR consolidation to reduce DR-level variability, EPA believes that a one-time realignment of DRs within a state could provide adequate flexibility for year-to-year operations for many years to come under the Transport Rule programs. In other words, DR-level variability can respect the assurance envelope without requiring utilities to re-balance their DR choices in each future year, even though they will indeed have that flexibility if desired. High DR-level variability in the existing structure correlates very strongly with each DR's share of units that have very low utilization (and thus low annual emissions); correspondingly, the most controlled DR-level variability is correlated with the DR's share of high-utilization (e.g., baseloaded) units. For example, in Maryland, a single DR represents 9 units at 4 facilities, but those units' capacity factors in 2010 were only 1% to 3%. For units with extremely low heat input in a given control period, year-to-year variability will look dramatic in percentage terms but will reflect small swings in actual tonnage. The same company (Constellation) has a separate DR in Maryland representing 6 units at 2 other facilities, most of which have higher capacity factors and yield a much more controlled variability level. Meanwhile, another DR in Maryland represents a single unit with an 86% capacity factor that yields single-digit variability for that DR. Clearly there are opportunities for consolidating DRs across different types of generators to achieve more balanced outcomes if they are desired. 

### Highlights of Case Studies

EPA integrated parameters from four databases to illustrate the current DR-level landscape for a cross-section of states reflecting both cost-of-service (IA, SC) and competitive (MD) power markets as well as Group 1 (IA, MD) and Group 2 (SC) states under the Transport Rule programs. The table on the "Data and Methods" tab explains how the spreadsheet was constructed and how you can review its results.

All units subject to the Transport Rule are included in these case studies, including infrequently-operating combustion turbines (CTs) and oil/gas steam boilers. CTs in particular, if represented uniquely at the DR level, appear to drive significant year-to-year variability but are deviating from an extremely small base heat input (and thus have very small emissions).

Some companies currently have multiple DRs in a state while others have broader fleet coverage with a single DR. In South Carolina, for example, Duke has separate DRs for its Mill Creek and W.S. Lee facilities, which experience substantially different levels of year-to-year variability due to the types of generation represented at those facilities. Meanwhile, Santee Cooper shows a single DR across its entire fleet, and its DR-level variability is much more balanced by having grouped 5 facilitiestogether. Another interesting example is in Iowa, where Alliant has no fewer than 15 different facilities all grouped under a single DR and achieves single-digit yearto-year variability, while Berkshire Hathaway groups 4 facilities into one DR but has unique DRs at 4 other facilities, leading to unnecessarily high variability at the DRlevel that could be tempered with further grouping of facilities by common DR.Given that historic variability at well-balanced DRs is stable within a reasonable envelope appoximating the state-level variability limits, and given the observable opportunities for future DR consolidation to reduce DR-level variability, EPA believes that a one-time realignment of DRs within a state could provide adequate flexibility for year-to-year operations for many years to come under the Transport Rule programs. In other words, DR-level variability can respect the assurance envelope without requiring utilities to re-balance their DR choices in each future year, even though they will indeed have that flexibility if desired. High DR-level variability in the existing structure correlates very strongly with each DR's share of units that have very low utilization (and thus low annual emissions); correspondingly, the most controlled DR-level variability is correlated with the DR's share of high-utilization (e.g., baseloaded) units. For example, in Maryland, a single DR represents 9 units at 4 facilities, but those units' capacity factors in 2010 were only 1% to 3%. For units with extremely low heat input in a given control period, year-to-year variability will look dramatic in percentage terms but will reflect small swings in actual tonnage. The same company (Constellation) has a separate DR in Maryland representing 6 units at 2 other facilities, most of which have higher capacity factors and yield a much more controlled variability level. Meanwhile, another DR in Maryland represents a single unit with an 86% capacity factor that yields single-digit variability for that DR. Clearly there are opportunities for consolidating DRs across different types of generators to achieve more balanced outcomes if they are desired. EPA integrated parameters from four databases to illustrate the current DR-level landscape for a cross-section of states reflecting both cost-of-service (IA, SC) and competitive (MD) power markets as well as Group 1 (IA, MD) and Group 2 (SC) states under the Transport Rule programs. The table on the "Data and Methods" tab

All units subject to the Transport Rule are included in these case studies, including infrequently-operating combustion turbines (CTs) and oil/gas steam boilers. CTs in particular, if represented uniquely at the DR level, appear to drive significant year-to-year variability but are deviating from an extremely small base heat input (and

Some companies currently have multiple DRs in a state while others have broader fleet coverage with a single DR. In South Carolina, for example, Duke has separate DRs for its Mill Creek and W.S. Lee facilities, which experience substantially different levels of year-to-year variability due to the types of generation represented at those facilities. Meanwhile, Santee Cooper shows a single DR across its entire fleet, and its DR-level variability is much more balanced by having grouped 5 facilitiestogether. Another interesting example is in Iowa, where Alliant has no fewer than 15 different facilities all grouped under a single DR and achieves single-digit yearto-year variability, while Berkshire Hathaway groups 4 facilities into one DR but has unique DRs at 4 other facilities, leading to unnecessarily high variability at the DR-

### Source/Methodology Reported to EPA as of June 2011

SO2 Percent deviation from the 2002-2008 mean annual

heat input at coal-fired units, capturing 95% of potential annual values (95% confidence level)

Annual NOX Percent deviation from the 2002-2008 mean annual

heat input at fossil-fired units, capturing 95% of potential annual values (95% confidence level)

Ozone-Season NOXPercent deviation from the 2002-2008 mean ozoneseason heat input at fossil-fired units, capturing 95% of potential ozone-season values (95% confidence level) Recorded by Ventyx as of October 2010

EPA's Clean Air Markets Data EPA's Clean Air Markets Data EPA's Clean Air Markets Data EPA's NEEDS Database EPA's Clean Air Markets Data EPA's Clean Air Markets Data EPA's Clean Air Markets Data Calculated by dividing 2010 heat input reported to EPA by the unit's maximum hourly heat inputreported to EPA converted into an annual upperbound heat input.

EPA's NEEDS Database

EPA's NEEDS Database DR-Level Historic Heat Input Variability



### Data Field Designated Representative (DR)

Parent Company

Plant Name

SCR by 2010? 2010 Ozone-Season NOXEmissions

2010 Capacity Factor

Scrubber by 2010? Plant Type Unit ID Capacity (MW) 2010 SO2Emissions 2010 Annual NOXEmissions

### Notes

This field is N/A for current DRs that lack coal-fired units. EPA analyzed historic heat input at coal-fired units only to determine SO2variability at the state level; this methodology is consistent but applied to the DR level.

Consistent with EPA's state-level analysis of historic heat input variability.

Consistent with EPA's state-level analysis of historic heat input variability.

Ownership data aggregated to the parent company is not directly reported to EPA

Generator capacity is not directly reported to EPA If the unit did not operate in 2010, this value is empty. If the unit did not operate in 2010, this value is empty. If the unit did not operate in 2010, this value is empty.

This field notes whether a physical scrubber has been installed at a given unit by 2010; however, 2010 emissions (rates and tons) may not reflect full or optimal operation of such equipment given regulatory uncertainty in advance of the Transport Rule. This field notes whether a physical SCR has been installed at a given unit by 2010; however, 2010 emissions (rates and tons) may not reflect full or optimal operation of such equipment given regulatory uncertainty in advance of the Transport Rule.Designated

RepresentativeSO2 Annual NOxOzone-Season NOxParent Company Muscatine Power & Water Muscatine Power & Water IA - B 77% 77% 64% Cedar Falls Utilities Pella Municipal Light & Power Pella Municipal Light & Power Pella Municipal Light & Power Missouri River Energy Services Missouri River Energy Services Missouri River Energy Services Corn Belt Power Coop Corn Belt Power Coop Central Iowa Power Coop Central Iowa Power Coop Central Iowa Power Coop Ames Municipal Electric System Ames Municipal Electric System Ames Municipal Electric System Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc IA - I 16% 16% 9% Berkshire Hathaway Inc Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Historic Heat Input Variability (2002 - 2008) at the Designated Representative Level

IA - A 6% 6% 8%

IA - C 37% 36% 34%

IA - D N/A 118% 128%

IA - E 96% 90% 64%

IA - F 26% 25% 15%

IA - G 15% 15% 29%

IA - H 5% 5% 6%

IA - J 6% 7% 11%Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Alliant Energy Corp Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc IA - L 20% 20% 13% Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc Berkshire Hathaway Inc IA - M N/A 38% 84% IA - K 38% 38% 42%Plant Name Plant Type Unit IDCapacity (MW) SO2Rate Muscatine Coal Steam 8 35 0.588 Muscatine Coal Steam 9 147 0.016 Streeter Station Coal Steam 7 36 0.828 Pella Coal Steam 6 15 0.566 Pella Coal Steam 7 13 0.552 Pella O/G Steam 8 15 0.000 Exira Station Combustion Turbine U-1 46 0.001 Exira Station Combustion Turbine U-2 47 0.001 Exira Station Combustion Turbine U-3 0.001 Earl F Wisdom Coal Steam 1 38 1.994 Earl F Wisdom Combustion Turbine2 76 0.002 Fair Station Coal Steam 2 41 3.764 Summit Lake Combined Cycle 1G 31 0.001 Summit Lake Combined Cycle 2G 32 0.001 Ames Coal Steam 7 33 0.447 Ames Coal Steam 8 70 0.386 Day ton Avenue Substation Combustion Turbine GT2 18 0.051 George Neal North Coal Steam 1 135 0.579 George Neal North Coal Steam 2 300 0.642 George Neal North Coal Steam 3 515 0.623 George Neal South Coal Steam 4 632 0.657 Riverside (1081) Coal Steam 9 130 0.688 Burlington (IA) Coal Steam 1 209 0.604 Centerville Combustion Turbine 1 2 0.081 Centerville Combustion Turbine2 2 0.081 Dubuque Coal Steam 1 35 0.676 Dubuque Coal Steam 5 30 0.679 Dubuque Coal Steam 6 13 0.451 Emery Station Combined Cycle 11 160 0.001 Emery Station Combined Cycle 12 160 0.001 Grinnell Combustion Turbine 1 25 0.060 Grinnell Combustion Turbine2 22 0.060 Lansing Coal Steam 1 Lansing Coal Steam 2 11 Lansing Coal Steam 3 37 Lansing Coal Steam 4 261 0.674 Lime Creek Combustion Turbine**1 35 0.020 Lime Creek Combustion Turbine**2 34 0.021 Marshalltown CTs Combustion Turbine 1A 54 0.070 Marshalltown CTs Combustion Turbine 1B 0.070 Marshalltown CTs Combustion Turbine2A 55 0.070 Marshalltown CTs Combustion Turbine2B 0.070Marshalltown CTs Combustion Turbine3A 56 0.070

Marshalltown CTs Combustion Turbine3B 0.070 Milton L Kapp Coal Steam 2 211 0.722 Ottumwa Coal Steam 1 673 0.573 Prairie Creek Coal Steam 3 42 0.648 Prairie Creek Coal Steam 4 125 0.652 Sixth Street Coal Steam 2 14 Sixth Street Coal Steam 3 14 Sixth Street Coal Steam 4 14 Sixth Street Coal Steam 5 14 Sutherland Coal Steam 1 30 0.725 Sutherland Coal Steam 2 31 Sutherland Coal Steam 3 82 1.690 Walter Scott Jr. Energy Center Coal Steam 1 45 0.642 Walter Scott Jr. Energy Center Coal Steam 2 88 0.713 Walter Scott Jr. Energy Center Coal Steam 3 690 0.307 Walter Scott Jr. Energy Center Coal Steam 4 800 0.079 Louisa Coal Steam 101 745 0.277 Electrifarm Combustion Turbine1 60 0.001 Electrifarm Combustion Turbine2 68 0.001 Electrifarm Combustion Turbine3 72 0.001 Greater Des Moines Energy Center Combined Cycle 1 180 0.001 Greater Des Moines Energy Center Combined Cycle 2 180 0.001 Pleasant Hill Energy Center Combustion Turbine1 39 0.001 Pleasant Hill Energy Center Combustion Turbine2 39 0.001 Pleasant Hill Energy Center Combustion Turbine3 86 0.001 Sycamore Combustion Turbine Combustion Turbine1 75 0.007 Sycamore Combustion Turbine Combustion Turbine2 75 0.007SO2TonsAnnual NOX Rate Annual NOX

Tons Ozone-season

NOXRate Ozone-season

NOXTons 2010

Capacity FactorScrubber

by 2010? 1,842 0.760 2,384 0.754 885 66% 91 0.130 735 0.127 299 64%Yes 308 0.680 253 0.658 81 17% 64 0.416 47 0.416 34 14% 199 0.422 152 0.415 52 38% 0 0.138 0 0.138 0 0% 0 0.115 1 0.109 1 0% 0 0.095 0 0.090 0 0% 0 0.152 1 0.158 1 0% 329 0.802 132 0.804 87 8% 0 0.037 0 0.039 0 0% 3,918 0.454 472 0.498 260 50% 0 0.331 36 0.361 12 5% 0 0.355 44 0.389 18 6% 310 0.375 260 0.374 113 30% 634 0.423 696 0.414 333 38% 0 0.320 1 0.294 0 0% 3,062 0.491 2,594 0.480 1,243 57% 6,689 0.237 2,470 0.246 1,065 74% 11,911 0.232 4,434 0.230 1,896 72% 16,575 0.228 5,754 0.222 2,422 78% 3,014 0.205 900 0.205 390 83% 2,890 0.150 718 0.156 282 40% 2 0.712 13 0.712 11 1% 0 0.752 4 0.752 3 0% 504 0.656 489 0.640 182 25% 268 0.776 306 0.790 158 21% 11 0.950 24 0.170 1 1% 1 0.019 21 0.015 10 9% 1 0.017 15 0.015 10 8% 1 0.364 4 0.364 4 1% 1 0.386 5 0.386 4 1%

4,729 0.230 1,611 0.161 398 52% 0 0.251 0 0.280 0 0% 0 0.269 0 0.288 0 0% 2 0.574 17 0.582 4 2% 2 0.565 18 0.572 4 2% 1 0.648 9 0.668 3 1% 1 0.626 8 0.637 3 1%

2010 Emissions Data2 0.483 10 0.482 5 1%

2 0.511 11 0.510 5 1% 3,462 0.113 540 0.112 273 48% 13,461 0.144 3,382 0.145 1,500 60% 1,132 0.362 631 0.304 215 66% 2,424 0.404 1,503 0.401 667 62%

890 0.340 417 0.328 149 40%

4,285 0.326 826 0.318 345 44% 1,346 0.290 607 0.297 267 56% 2,374 0.143 475 0.149 195 69% 8,723 0.191 5,411 0.189 2,203 76%Yes 2,129 0.052 1,405 0.053 604 80%Yes 7,075 0.186 4,745 0.184 2,082 68%Yes 0 0.320 67 0.320 42 6% 0 0.186 42 0.186 19 6% 0 0.202 62 0.202 33 8% 1 0.007 6 0.006 5 9% 0 0.006 5 0.006 5 9% 0 0.157 8 0.157 7 2% 0 0.157 8 0.157 8 2% 0 0.105 17 0.098 10 3% 2 0.477 111 0.473 67 6% 2 0.477 125 0.474 80 6%SCR by

2010?

Yes Yes

YesYes

Yes YesDesignated

RepresentativeSO2 Annual NOxOzone-Season NOxParent Company Northland Power Income Fund Northland Power Income Fund Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Mirant Corp Allco Finance Group Limited Allco Finance Group Limited Allco Finance Group Limited Allco Finance Group Limited Allegheny Energy Inc Allegheny Energy Inc EDF Group EDF Group MD - F 7% 7% 12% AES Corp (The) MD - G N/A 99% 156% NRG Energy Inc Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Historic Heat Input Variability (2002 - 2008) at the Designated Representative Level

MD - A N/A 15% 21%

MD - B 5% 6% 16%

MD - C N/A 64% 45%

MD - D 37% 37% 42%

MD - E 11% 11% 20%

MD - H 9% 10% 11%Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group Constellation Energy Group MD - I N/A 109% 112%Plant Name Plant Type Unit IDCapacity (MW) SO2Rate Panda Brandy

wine Combined Cycle 1 79 0.001 Panda Brandy

wine Combined Cycle 2 79 0.001 Chalk Point Combustion Turbine**GT3 86 0.036 Chalk Point Combustion Turbine**GT4 86 0.015 Chalk Point Combustion Turbine**GT5 109 0.035 Chalk Point Combustion Turbine**GT6 109 0.018 Chalk Point Coal Steam 1 341 0.113 Chalk Point Coal Steam 2 342 0.122 Chalk Point O/G Steam 3 612 0.025 Chalk Point O/G Steam 4 612 0.014 Chalk Point Combustion Turbine GT2 30 0.137 Chalk Point Combustion TurbineSMECO 84 0.024 Dickerson Coal Steam 1 182 0.189 Dickerson Coal Steam 2 182 0.163 Dickerson Coal Steam 3 182 0.184 Dickerson Combustion Turbine GT2 147 0.014 Dickerson Combustion Turbine GT3 147 0.025 Morgantown Coal Steam 1 624 0.141 Morgantown Coal Steam 2 620 0.129 Morgantown Combustion Turbine GT3 54 0.124 Morgantown Combustion Turbine GT4 54 0.124 Morgantown Combustion Turbine GT5 54 0.124 Morgantown Combustion Turbine GT6 54 0.124 Rock Springs Generating Facility Combustion Turbine 1 190 0.001 Rock Springs Generating Facility Combustion Turbine2 190 0.001 Rock Springs Generating Facility Combustion Turbine3 190 0.001 Rock Springs Generating Facility Combustion Turbine4 190 0.001 R. Paul Smith Power Station Coal Steam 11 87 1.349 R. Paul Smith Power Station Coal Steam 9 28 1.370 C P Crane Coal Steam 1 200 0.719 C P Crane Coal Steam 2 200 1.332 AES Warrior Run Coal Steam 001 180 0.164 Vienna O/G Steam 8 153 1.370 Brandon Shores Coal Steam 1 643 0.033 Brandon Shores Coal Steam 2 643 0.050 Herbert A Wagner O/G Steam 1 131 0.049 Herbert A Wagner Coal Steam 2 135 1.176 Herbert A Wagner Coal Steam 3 324 0.995 Herbert A Wagner O/G Steam 4 397 0.629 Gould Street O/G Steam 3 100 0.001 Perryman Combustion Turbine**51 152 0.052 Perryman Combustion TurbineCT1 52 0.051Perryman Combustion TurbineCT2 52 0.050

Perryman Combustion TurbineCT3 52 0.051 Perryman Combustion TurbineCT4 52 0.050 Riverside O/G Steam 4 78 0.001 Riverside Combustion TurbineCT6 127 0.040 Westport Combustion TurbineCT5 121 0.001SO2TonsAnnual NOX Rate Annual NOX

Tons Ozone-season

NOXRate Ozone-season

NOXTons 2010

Capacity FactorScrubber

by 2010? 1 0.029 39 0.026 21 27% 1 0.028 31 0.023 17 22% 3 0.093 8 0.085 5 2% 2 0.076 8 0.069 5 2% 6 0.089 16 0.072 8 3% 3 0.064 12 0.056 7 3% 1,219 0.139 1,497 0.164 767 79% 1,254 0.198 2,038 0.195 1,012 75% 70 0.130 365 0.129 327 9% 56 0.133 528 0.132 445 14% 1 0.988 9 0.968 6 1% 0 0.724 2 0.724 2 0% 875 0.263 1,215 0.247 559 64% 823 0.265 1,337 0.247 568 70% 877 0.263 1,255 0.248 556 66% 3 0.109 19 0.102 14 2% 7 0.114 32 0.098 20 3% 3,029 0.049 1,059 0.042 353 92%Yes 2,229 0.041 710 0.033 265 74%Yes 5 0.679 29 0.665 15 1% 5 0.680 30 0.671 17 2% 3 0.665 18 0.656 13 1% 5 0.605 24 0.549 12 1% 0 0.027 13 0.027 13 6% 0 0.031 16 0.031 15 6% 0 0.031 22 0.031 20 8% 0 0.031 24 0.031 23 9% 1,641 0.326 397 0.306 228 30% 425 0.425 132 0.416 76 18% 1,315 0.539 986 0.620 727 17% 4,274 0.456 1,463 0.465 653 29% 1,247 0.080 611 0.081 260 85% 101 0.272 20 0.278 15 1% 540 0.113 1,853 0.087 579 47% 720 0.132 1,913 0.099 760 41% 8 0.134 23 0.153 19 3% 3,176 0.386 1,043 0.428 585 34% 5,852 0.060 355 0.057 189 49% 146 0.258 60 0.257 56 1% 0 0.113 17 0.113 17 3% 13 0.169 42 0.157 28 3% 2 0.612 26 0.596 22 1%

2010 Emissions Data2 0.498 23 0.483 17 1%

2 0.595 28 0.581 21 1% 2 1.200 47 1.200 40 1% 0 0.515 26 0.515 26 1% 2 0.225 11 0.216 10 1% 0 0.216 14 0.216 13 1%SCR by

2010?

Yes

Yes Yes

Yes Yes

YesDesignated

RepresentativeSO2 Annual NOxOzone-Season NOxParent Company Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Santee Cooper Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp Duke Energy Corp SCANA Corp SCANA Corp Historic Heat Input Variability (2002 - 2008) at the Designated Representative Level

SC - A 8% 5% 17%

SC - B N/A 143% 153%

SC - C 30% 30% 36%SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp SCANA Corp Calpine Corp Calpine Corp Calpine Corp Calpine Corp Calpine Corp Calpine Corp Calpine Corp Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc Progress Energy Inc SC - G N/A 63% 65% NextEra Energy Inc SC - F 19% 16% 28% SC - D 12% 12% 18%

SC - E N/A 60% 60%Plant Name Plant Type Unit IDCapacity (MW) SO2Rate Cross Coal Steam 1 620 0.089 Cross Coal Steam 2 540 0.239 Cross Coal Steam 3 580 0.065 Cross Coal Steam 4 600 0.060 Dolphus M Grainger Coal Steam 1 85 2.439 Dolphus M Grainger Coal Steam 2 85 2.453 Hilton Head Gas Turbine Site Combustion TurbineCT1 20 0.500 Hilton Head Gas Turbine Site Combustion TurbineCT2 20 0.501 Hilton Head Gas Turbine Site Combustion TurbineCT3 57 0.500 Jefferies O/G Steam 1 46 1.177 Jefferies O/G Steam 2 46 0.978 Jefferies Coal Steam 3 153 2.660 Jefferies Coal Steam 4 153 2.688 John S. Rainey

Generating Station Combined Cycle CT1A 146 0.001 John S. Rainey

Generating Station Combined Cycle CT1B 146 0.001 John S. Rainey

Generating Station Combustion TurbineCT2A 146 0.001 John S. Rainey

Generating Station Combustion TurbineCT2B 146 0.001 John S. Rainey

Generating Station Combustion TurbineCT3 74 0.001 John S. Rainey

Generating Station Combustion TurbineCT4 74 0.001 John S. Rainey

Generating Station Combustion TurbineCT5 74 0.001 Myrtle Beach Gas Turbine Site Combustion TurbineCT3 20 0.500 Myrtle Beach Gas Turbine Site Combustion TurbineCT4 20 0.500 Myrtle Beach Gas Turbine Site Combustion TurbineCT5 30 0.500 Winyah Coal Steam 1 295 0.034 Winyah Coal Steam 2 295 0.072 Winyah Coal Steam 3 295 0.283 Winyah Coal Steam 4 270 0.196 Mill Creek Combustion Turbine Sta Combustion Turbine 1 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine2 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine3 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine4 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine5 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine6 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine7 74 0.001 Mill Creek Combustion Turbine Sta Combustion Turbine8 74 0.001 WS Lee Coal Steam 1 100 1.431 WS Lee Coal Steam 2 100 1.430 WS Lee Coal Steam 3 170 1.430 WS Lee Combustion Turbine7C 35 0.005 WS Lee Combustion Turbine8C 35 0.002 Canadys Steam Coal Steam CAN1 105 1.773 Canadys Steam Coal Steam CAN2 116 1.907Canadys Steam Coal Steam CAN3 175 1.953

Cope Station Coal Steam COP1 420 0.141 Hagood Combustion Turbine HAG4 86 0.003 Jasper County

Generating Facility Combined Cycle CT01 149 0.001 Jasper County

Generating Facility Combined Cycle CT02 149 0.001 Jasper County

Generating Facility Combined Cycle CT03 149 0.002 McMeekin Coal Steam MCM1 125 1.482 McMeekin Coal Steam MCM2 125 1.575 Urquhart Coal Steam URQ3 94 2.170 Urquhart Combustion TurbineURQ4 47 0.062 Urquhart Combined Cycle URQ5 66 0.001 Urquhart Combined Cycle URQ6 68 0.001 Wateree Coal Steam WAT1 350 0.889 Wateree Coal Steam WAT2 350 0.879 Williams Coal Steam WIL1 615 0.058 Williams Combustion TurbineWIL4 20 0.033 Williams Combustion TurbineWIL5 20 0.011 Broad River Energy Center Combustion TurbineCT-1 168 0.001 Broad River Energy Center Combustion TurbineCT-2 168 0.001 Broad River Energy Center Combustion TurbineCT-3 169 0.001 Broad River Energy Center Combustion TurbineCT-4 168 0.001 Broad River Energy Center Combustion TurbineCT-5 168 0.001 Columbia Energy Center (SC) Combined Cycle CT-1 157 0.001 Columbia Energy Center (SC) Combined Cycle CT-2 157 0.001 Darlington County Combustion Turbine1 51 0.007 Darlington County Combustion Turbine10 51 0.500 Darlington County Combustion Turbine11 50 Darlington County Combustion Turbine12 121 0.003 Darlington County Combustion Turbine13 114 0.002 Darlington County Combustion Turbine2 49 0.500 Darlington County Combustion Turbine3 46 0.012 Darlington County Combustion Turbine4 53 0.500 Darlington County Combustion Turbine5 53 0.003 Darlington County Combustion Turbine6 50 0.500 Darlington County Combustion Turbine7 54 0.002 Darlington County Combustion Turbine8 49 0.500 Darlington County Combustion Turbine9 53 0.500 H B Robinson Coal Steam 1 176 1.520 Cherokee County Cogen Combined Cycle CCCP1 80 0.001SO2TonsAnnual NOX Rate Annual NOX

Tons Ozone-season

NOXRate Ozone-season

NOXTons 2010

Capacity FactorScrubber

by 2010? 1,579 0.091 1,625 0.090 773 60%Yes 5,388 0.088 1,988 0.088 868 78%Yes 917 0.068 963 0.070 519 47%Yes 1,416 0.069 1,620 0.070 690 75%Yes 2,569 0.463 488 0.466 291 23% 3,027 0.435 537 0.441 343 26% 1 1.200 1 1.201 0 0% 0 1.200 1 1.203 0 0% 2 0.343 1 0.344 0 0% 50 0.273 12 0.136 1 2% 65 0.272 18 0.242 7 2% 5,990 0.497 1,120 0.492 550 27% 4,062 0.472 713 0.467 369 17% 3 0.014 67 0.007 15 59% 3 0.013 62 0.007 14 57% 0 0.033 27 0.032 14 10% 0 0.032 25 0.029 12 9% 0 0.031 4 0.031 3 4% 0 0.031 4 0.031 2 3% 0 0.032 5 0.032 3 4% 4 1.200 10 1.200 7 1% 4 1.200 9 1.200 6 1% 6 1.200 14 1.200 8 1% 262 0.085 650 0.081 279 54%Yes 575 0.106 849 0.105 407 47%Yes 2,342 0.103 852 0.101 452 49%Yes 1,819 0.112 1,035 0.111 442 59%Yes 0 0.034 3 0.034 3 1% 0 0.032 2 0.032 2 1% 0 0.036 3 0.036 3 1% 0 0.032 2 0.032 2 1% 0 0.029 2 0.029 2 1% 0 0.034 2 0.034 2 1% 0 0.028 2 0.028 2 1% 0 0.027 2 0.027 2 1% 2,041 0.239 341 0.232 225 27% 2,013 0.243 343 0.242 229 23% 4,232 0.233 688 0.233 403 27% 0 0.115 3 0.121 1 1% 0 0.107 5 0.101 3 2% 2,927 0.356 588 0.338 282 24% 3,723 0.358 699 0.348 318 31%

2010 Emissions Data6,031 0.302 933 0.294 676 35%

1,759 0.078 983 0.077 393 61%Yes 1 0.154 30 0.146 23 3% 3 0.008 41 0.008 23 45% 3 0.008 43 0.008 21 49% 8 0.009 45 0.008 22 49% 5,080 0.299 1,024 0.298 470 58% 4,600 0.288 842 0.299 435 47% 5,146 0.295 699 0.287 376 45% 9 0.112 16 0.099 8 7% 3 0.033 114 0.027 58 44% 2 0.032 104 0.025 54 41% 9,362 0.098 1,037 0.099 485 56% 8,877 0.094 947 0.103 420 52% 947 0.123 2,023 0.115 804 53% 0 0.733 3 0.700 2 0% 0 0.710 6 0.700 4 1% 1 0.038 43 0.038 33 12% 1 0.039 41 0.039 32 11% 1 0.037 39 0.037 28 11% 1 0.038 37 0.039 28 10% 0 0.040 32 0.040 25 9% 0 0.018 8 0.018 8 4% 0 0.024 8 0.024 8 3% 0 0.478 18 0.472 17 1% 5 0.703 7 0.703 4 0%

1 0.084 36 0.080 23 5% 1 0.088 36 0.085 26 5% 5 0.703 7 0.703 5 0% 0 0.483 20 0.472 16 1% 5 0.703 7 0.703 4 0% 0 0.474 29 0.472 26 1% 3 0.703 4 0.703 4 0% 0 0.473 29 0.472 25 1% 4 0.703 6 0.703 5 0% 3 0.703 4 0.703 3 0% 7,772 0.437 2,233 0.473 978 49% 1 0.026 50 0.026 27 53%SCR by

2010? Yes Yes Yes Yes

Yes Yes

Yes Yes Yes YesYes

Yes Yes Yes Yes

Yes Yes

Yes