Given that historic variability at well-balanced DRs is stable within a reasonable envelope appoximating the state-level variab

opportunities for future DR consolidation to reduce DR-level variability, EPA believes that a one-time realignment of DRs with

flexibility for year-to-year operations for many years to come under the Transport Rule programs. In other words, DR-level v

envelope without requiring utilities to re-balance their DR choices in each future year, even though they will indeed have tha

High DR-level variability in the existing structure correlates very strongly with each DR's share of units that have very low util

correspondingly, the most controlled DR-level variability is correlated with the DR's share of high-utilization (e.g., baseloaded

single DR represents 9 units at 4 facilities, but those units' capacity factors in 2010 were only 1% to 3%. For units with extrem

period, year-to-year variability will look dramatic in percentage terms but will reflect small swings in actual tonnage. The sam

separate DR in Maryland representing 6 units at 2 other facilities, most of which have higher capacity factors and yield a muc

Meanwhile, another DR in Maryland represents a single unit with an 86% capacity factor that yields single-digit variability for 

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 reflec

competitive (MD) power markets as well as Group 1 (IA, MD) and Group 2 (SC) states under the Transport Rule programs. Th

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 turbin

particular, if represented uniquely at the DR level, appear to drive significant year-to-year variability but are deviating from a

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 C

DRs for its Mill Creek and W.S. Lee facilities, which experience substantially different levels of year-to-year variability due to t

those facilities. Meanwhile, Santee Cooper shows a single DR across its entire fleet, and its DR-level variability is much more 

together. Another interesting example is in Iowa, where Alliant has no fewer than 15 different facilities all grouped under a s

to-year variability, while Berkshire Hathaway groups 4 facilities into one DR but has unique DRs at 4 other facilities, leading to 

level that could be tempered with further grouping of facilities by common DR.
envelope appoximating the state-level variability limits, and given the observable 

eves that a one-time realignment of DRs within a state could provide adequate 

t Rule programs. In other words, DR-level variability can respect the assurance 

year, even though they will indeed have that flexibility if desired.

ch DR's share of units that have very low utilization (and thus low annual emissions); 

R's share of high-utilization (e.g., baseloaded) units. For example, in Maryland, a 

0 were only 1% to 3%. For units with extremely low heat input in a given control 

flect small swings in actual tonnage. The same company (Constellation) has a 

have higher capacity factors and yield a much more controlled variability level. 

y factor that yields single-digit variability for that DR. Clearly there are opportunities 

ced outcomes if they are desired.

 landscape for a cross-section of states reflecting both cost-of-service (IA, SC) and 

ates under the Transport Rule programs. The table on the "Data and Methods" tab 

g infrequently-operating combustion turbines (CTs) and oil/gas steam boilers. CTs in 

r-to-year variability but are deviating from an extremely small base heat input (and 

r fleet coverage with a single DR. In South Carolina, for example, Duke has separate 

rent levels of year-to-year variability due to the types of generation represented at 

et, and its DR-level variability is much more balanced by having grouped 5 facilities 

n 15 different facilities all grouped under a single DR and achieves single-digit year

as 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 NOX

Percent 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 input 

reported 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 NOX Emissions

2010 Capacity Factor

Scrubber by 2010?

Plant Type

Unit ID

Capacity (MW)

2010 SO2 Emissions

2010 Annual NOX Emissions
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 SO2 variability 

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 

Representative SO2 Annual NOx Ozone-Season NOx Parent 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 ID

Capacity 

(MW) SO2

 Rate

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 Turbine 2 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

Dayton 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 Turbine 2 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 Turbine 2 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 Turbine 2A 55 0.070

Marshalltown CTs Combustion Turbine 2B 0.070
Marshalltown CTs Combustion Turbine 3A 56 0.070

Marshalltown CTs Combustion Turbine 3B 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 Turbine 1 60 0.001

Electrifarm Combustion Turbine 2 68 0.001

Electrifarm Combustion Turbine 3 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 Turbine 1 39 0.001

Pleasant Hill Energy Center Combustion Turbine 2 39 0.001

Pleasant Hill Energy Center Combustion Turbine 3 86 0.001

Sycamore Combustion Turbine Combustion Turbine 1 75 0.007

Sycamore Combustion Turbine Combustion Turbine 2 75 0.007
SO2

 Tons

Annual NOX 

Rate

Annual NOX 

Tons

Ozone-season 

NOX Rate

Ozone-season 

NOX Tons

2010 

Capacity 

Factor

Scrubber 

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 Data
2 0.483 10 0.482

5 1%

2 0.511 11 0.5105 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

Yes
Yes

Yes

Yes
Designated 

Representative SO2 Annual NOx Ozone-Season NOx Parent 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 ID

Capacity 

(MW) SO2

 Rate

Panda Brandywine Combined Cycle 1 79 0.001

Panda Brandywine 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 Turbine SMECO 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 Turbine 2 190 0.001

Rock Springs Generating Facility Combustion Turbine 3 190 0.001

Rock Springs Generating Facility Combustion Turbine 4 190 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 Turbine CT1 52 0.051
Perryma

n Combustion Turbine CT2 52 0.050

Perryman Combustion Turbine CT3 52 0.051

Perryman Combustion Turbine CT4 52 0.050

Riverside O/G Steam4 78 0.001

Riverside Combustion Turbine CT6 127 0.040

Westport Combustion Turbine CT5 121 0.001
SO2

 Tons

Annual NOX 

Rate

Annual NOX 

Tons

Ozone-season 

NOX Rate

Ozone-season 

NOX Tons

2010 

Capacity 

Factor

Scrubber 

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 Data
2 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

Yes

Designated 

Representative SO2 Annual NOx Ozone-Season NOx Parent 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 ID

Capacity 

(MW) SO2

 Rate

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 Turbine CT1 20 0.500

Hilton Head Gas Turbine Site Combustion Turbine CT2 20 0.501

Hilton Head Gas Turbine Site Combustion Turbine CT3 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 Turbine CT2A 146 0.001

John S. Rainey Generating Station Combustion Turbine CT2B 146 0.001

John S. Rainey Generating Station Combustion Turbine CT3 74 0.001

John S. Rainey Generating Station Combustion Turbine CT4 74 0.001

John S. Rainey Generating Station Combustion Turbine CT5 74 0.001

Myrtle Beach Gas Turbine Site Combustion Turbine CT3 20 0.500

Myrtle Beach Gas Turbine Site Combustion Turbine CT4 20 0.500

Myrtle Beach Gas Turbine Site Combustion Turbine CT5 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 Turbine 2 74 0.001

Mill Creek Combustion Turbine Sta Combustion Turbine 3 74 0.001

Mill Creek Combustion Turbine Sta Combustion Turbine 4 74 0.001

Mill Creek Combustion Turbine Sta Combustion Turbine 5 74 0.001

Mill Creek Combustion Turbine Sta Combustion Turbine 6 74 0.001

Mill Creek Combustion Turbine Sta Combustion Turbine 7 74 0.001

Mill Creek Combustion Turbine Sta Combustion Turbine 8 74 0.001

W S Lee Coal Steam 1 100 1.431

W S Lee Coal Steam 2 100 1.430

W S Lee Coal Steam 3 170 1.430

W S Lee Combustion Turbine 7C 35 0.005

W S Lee Combustion Turbine 8C 35 0.002

Canadys Steam Coal Steam CAN1 105 1.773

Canadys Steam Coal Steam CAN2 116 1.907
Canadys 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 Turbine URQ4 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 Turbine WIL4 20 0.033

Williams Combustion Turbine WIL5 20 0.011

Broad River Energy Center Combustion Turbine CT-1 168 0.001

Broad River Energy Center Combustion Turbine CT-2 168 0.001

Broad River Energy Center Combustion Turbine CT-3 169 0.001

Broad River Energy Center Combustion Turbine CT-4 168 0.001

Broad River Energy Center Combustion Turbine CT-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 Turbine 1 51 0.007

Darlington County Combustion Turbine 10 51 0.500

Darlington County Combustion Turbine 11 50

Darlington County Combustion Turbine 12 121 0.003

Darlington County Combustion Turbine 13 114 0.002

Darlington County Combustion Turbine 2 49 0.500

Darlington County Combustion Turbine 3 46 0.012

Darlington County Combustion Turbine 4 53 0.500

Darlington County Combustion Turbine 5 53 0.003

Darlington County Combustion Turbine 6 50 0.500

Darlington County Combustion Turbine 7 54 0.002

Darlington County Combustion Turbine 8 49 0.500

Darlington County Combustion Turbine 9 53 0.500

H B Robinson Coal Steam 1 176 1.520

Cherokee County Cogen Combined Cycle CCCP1 80 0.001
SO2

 Tons

Annual NOX 

Rate

Annual NOX 

Tons

Ozone-season 

NOX Rate

Ozone-season 

NOX Tons

2010 

Capacity 

Factor

Scrubber 

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 Data
6,031 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

Yes
Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes