1 

United States 

Environmental Protection Agency 

Air and Radiation 

(6204J) 

EPA # 430-F-11-066 

December 2011 

Documentation Supplement for EPA 

Base Case v.4.10_MATS – Updates for 

Final Mercury and Air Toxics Standards 

(MATS) Rule
2 

 
3 

This report is the third of three supplements to the August 2010 documentation for EPA Base Case 

v.4.101. The previous two supplements presented the enhancements and updates that were made to the 

Base Case for the Proposed Toxics Rule (March 2011)2

 and the Cross-State Air Pollution Rule or CSAPR 

(June 2011)3. The current supplement presents the enhancements and updates that were made for the 

final Toxics Rule, now designated the Mercury and Air Toxics Standards (MATS). 

The 3 documentation supplements are cumulative in nature. Previous documented features not 

addressed here were retained in the MATS Base Case as described in the most recent previous 

documentation. Figure 1 attempts to provide a graphical representation of the cumulative structure. The 

March 2011 documentation supplement for the Proposed Toxics Rule is highlighted in Figure 1 because 

the Base Case for MATS represents an extension of the Base Case for the Proposed Toxics Rule. 

Figure 1.  Relationship of Current Report to Previous Documentation for EPA Base Case v.4.10 Variants

The current report consists of two parts: Part A briefly summarizes the changes found in the EPA Base 

 

1 The formal title of the August 2010 documentation report is Documentation for EPA Base Case v.4.10 

Using the Integrated Planning Model (EPA #430-R-10-010), August 2010. It is available for viewing and 

downloading at www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. 

2 The formal title of the March 2011 documentation supplement is Documentation Supplement for 

EPA Base Case v4.10_PTox − Updates for Proposed Toxics Rule (EPA #430-R-11-006 ), March 2011. It 

is available for viewing and downloading at www.epa.gov/airmarkets/progsregs/epaipm/docs/suppdoc.pdf 

3

 The formal title of the June 2011 documentation supplement is Documentation Supplement for EPA 

Base Case v.4.10_FTransport – Updates for Final Transport Rule (EPA #430-K-11-004). June 2011. It is 

available for viewing and downloading at www.epa.gov/airmarkets/progsregs/epaipm/CSAPR/docs/DocSuppv410_FTransport.pdf.
4 

Case v.4.10 for the MATS. To facilitate cross-references to the previous documentation reports, the topics 

in Part A are covered in the same categories and in the same order as covered in the previous 

documentation reports. At the end of Part A there a listing of corrections to errors in previous 

documentation and enhancements to previous documentation items. The items in this section of Part A 

do not represent changes in the base case itself but in the documentation describing features included in 

the base case. 

Part B of this report gives detailed information on these changes and takes the form of a supplement to 

the previous documentation, using redline and strike-out highlights to show provisions that changed and 

building upon the section numbering in the previous documentation to show where new enhancements fit 

into the modeling structure. 

 
5 

Part A 

Summary of Key Changes 

in the EPA Base Case v.4.10 

for the MATS 
6 

Power System Operations Assumptions 

(Chapter 3 in previous documentation) 

Cross-State Air Pollution Rule (CSAPR): Since issuing the Documentation Supplement for the 

Proposed Toxics Rule in March of 2011, the EPA Administrator on July 6, 2011 signed a Notice of Final 

Rulemaking for the Cross-State Air Pollution Rule (CSAPR). As a result of this regulatory action, the SO2 

and NOx provisions of CSAPR were incorporated in the EPA Base Case v.4.10_MATS. Part B CrossReference: For an indication of previous provisions removed and details of the representation of 

CASAPR provisions in the final MATS base case (including tables of key CSAPR provisions, state 

budgets, and a map of affected states), see the new redlined text in Section 3.9 in Part B. 

Colorado RPS: Part B Cross-Reference: For a summary of the Colorado RPS included see the redlined 

additions to Section 3.9.3 in Part B.) 

Colorado Clean Air – Clean Jobs Act: Due to timing, previous versions of EPA Base Case v.4.10 did 

not include this state regulation, which was enacted in April 2011. Part B Cross-Reference: For a 

summary of the modeled provisions of the Colorado Clean Air – Clean Jobs Act, see the new redlined 

additions to Section 3.9.4 in Part B.) 

Handling of State Mercury Regulations in MATS Base and Policy Cases: State mercury regulations 

(as shown in Appendix 3-2 in the Documentation Supplement for Proposed Toxics Rule) were not 

modeled in the MATS base or policy cases. Part B Cross-Reference: For an explanation of reasons why 

state mercury regulations were not included in the MATS base or policy cases, see the new text that 

appears at the end of Section 3.9.4 (“State Specific Environmental Regulations”) in Part B. 

NIPSCO and TVA NSR Settlements: Between the last previously released EPA Base Case v.4.10 (for 

CSAPR) and the base case for MATS, provisions of the NSR settlements with Northern Indiana Public 

Service Company (NIPSCO) and Tennessee Valley Authority (TVA) were announced. See 

www.epa.gov/compliance/resources/cases/civil/caa/nipsco.html and 

www.epa.gov/compliance/resources/cases/civil/caa/tvacoalfired. The NIPSCO settlement and the 

system-wide TVA SO2 limit, which were not previously included, are now represented in the Base Case 

v.4.10_MATS. Part B Cross-Reference: For a summary of the modeled provisions of the NIPSCO and 

TVA NSR settlements see the appropriate entries in the updated version of Appendix 3-3 (“New Source 

Review (NSR) Settlements in EPA Base Case v.4.10_MATS. 

Handling of Existing ACI Controls in MATS Base and Policy Cases: Certain existing ACI controls 

(shown in the NEEDS database) were not included in EPA Base Case v.4.10_MATS but were included in 

the MATS policy case. Part B Cross-Reference: For an explanation of reasons and a listing of existing 

ACI controls that were not included in the MATS Base Case but were included in the MATS policy case 

see new sub-section 3.9.7 (“Unit-Level Control Assumptions”) and 3.9.7.1 (“Existing ACI Controls in 

MATS Base and Policy Cases”) in Part B. 

 

Unit-Specific Assumptions on Emissions, Emission Controls, and Fuels: 

Unit specific assumptions were adopted for 

 Big Sandy Units 1 and 2, 

 Monroe Units 1 and 2 

 Dunkirk Units 3 and 4, 

 C R Huntley Units 7 and 8 

 Coal Units in Washington State, including the retirements at 

- Centralia 

- Boardman 

 D B Wilson plant 

 Revised coal assignments at various plants to improve consistency with EIA Form 923 

Part B Cross-Reference: For details of these changes, see new documentation sub-section 3.9.7 (“UnitLevel Control, Emission and Fuel Assumptions”) in Part B. 
7 

Generation Resources

(Chapter 4 in previous documentation) 

Revised Capital Cost Structure for New Nuclear Units: The capital cost for new nuclear capacity was 

updated to $5,000/kW from $4,621 (in 2007$). The life extension costs for existing nuclear units were 

revised to be consistent with the new nuclear plant capital costs.

Part B Cross-Reference: The changes noted here are shown in Table 4-13 in Part B. 

 
8 

Emission Control Technologies

(Chapter 5 in previous documentation) 

Filterable Particulate Matter (PM) Compliance Technologies for Existing Units: In the MATS policy 

case all coal units with a capacity greater than 25 MW must meet the filterable PM compliance 

requirement. Units that have an existing fabric filter are assumed to meet the requirement. Depending on 

the incremental filterable PM reduction needed to bring a unit into compliance, uncontrolled units and 

units with electrostatic precipitators (ESPs) for PM control that do not currently meet their compliance 

requirement are assigned either a fabric filter or one of three tiered ESP upgrades to bring them into 

compliance. The determination of the appropriate option is an off-line calculation and the assignment of 

that option is performed in setting up a run, not in the course of the run. Part B Cross-Reference: See 

new section 5.6 for details of the procedure used to determine the appropriate compliance technology. 

Updated FGD Removal Rate Assumptions for Petroleum Coke: Based on the performance 

capabilities indicated in the 2010 ICR, a 93% mercury removal rate is assumed when FGD is present on 

units that burn petroleum coke. Part B Cross-Reference: The previous sentence should be appended as 

a note under Table 5-13 (“Mercury Emission Modification Factors Used in EPA Base Case 

v.4.10_MATS”) in section 5.4.3 (“Mercury Control Capabilities”) of the August 2010 documentation for 

EPA Base Case v.4.10. (This is not reproduced in Part B.) 

Revised ACI VOM Cost for Units with Certain Particulate Control Configurations: For certain 

particulate control configurations the variable operating and maintenance (VOM) cost of activated carbon 

injection (ACI) retrofits is assumed to be 81 percent lower due the presence of pre-existing particulate 

controls. Part B Cross-Reference: See the redlined addition to section 5.4.3 (“Mercury Control 

Capabilities”) for the specific configurations affected by this VOM cost revision.

Revised HCl Emissions from Lignite and Subbituminous Coals Reflecting Impact of Ash 

Chemistry: To account for the effect of ash chemistry on HCl emissions, the HCl content of lignite and 

subbituminous coals is reduced by 75%. Part B Cross-Reference: For a fuller explanation of these 

changes see additional redlined text at end of Section 5.5.1 (“Chlorine Content of Fuels”) in Part B 

FGD Upgrade Assumptions in MATS Policy Case: In setting up the MATS policy runs, it is assumed 

that the most cost effective approach for units with pre-existing FGD that do not meet the 94% HCl 

removal requirement is to upgrade their FGD to bring the unit into compliance. Part B Cross-Reference: 

For the specifics of the FGD upgrade see the new redlined text in Section 5.5.3.1 (“Wet and Dry FGD”) in 

Part B. 

 

Dry Scrubber Removal Assumptions for Waste Coal and Petroleum Coke Units in MATS Policy 

Case: In setting up the Base Case v.4.10_MATS, waste coal and petroleum coke fired FBC units without 

an existing FGD were mistakenly not provided with a scrubber retrofit option. To make up for this 

oversight, in run year 2015 a dry scrubber and its associated capital cost (applied through and FOM 

adder) are assigned to these units when setting up the MATS policy case. Part B Cross-Reference: For 

further details on these revisions see new redlined text in Section 5.5.3.1 (“Wet and Dry FGD”). 

Revisions to DSI cost and performance assumptions in the Base Case for MATS: A number of 

additional assumptions were made regarding DSI in the Base Case v.4.10_MATS. Part B CrossReference: : See the redlined addition to section 5.5.3.2 (“Dry Sorbent Injection”) in Part 2 for a 

discussion of the specific assumptions. 

Assumed Air-to-Cloth Ratio in the Cost Equations for the DSI + Fabric Filter Retrofit Option: Based 

on public comments and engineering assessments, an air-to-cloth ratio of 4.0, rather than 6.0, was used 

in MATS to provide a conservative projection of the requirements and cost of sorbent removal. Part B 

Cross-Reference: New redlined text was added to the “Capital Cost” write-up in Section 5.5.4 (“Fabric 

Filter (Baghouse) Cost Development”) to reflect this assumption. This addition is shown in Part B. 
9 

Other Fuels and Fuel Emission Factor Assumptions 

(Chapter 11 in previous documentation) 

Correction of Error in Mercury Emission Factor (EMF) for Petroleum Coke: A previous computational 

error in the mercury emission factor for petroleum coke as presented in Table 6-3 of the EPA report titled 

Control of Mercury Emissions from Coal-fired Electric Utility Boilers: Interim Report Including Errata, 3-21-

02 was corrected (from 23.18 lbs/TBtu to 2.66 lb/TBtu) based on re-examination of the 1999 ICR data for 

petroleum coke and implementation of a procedure for flagging and excluding outlier values above the 95 

percentile value. Part B Cross-Reference: This correction is reflected in the update of Table 11-4 that 

appears in Part B. 

Mercury Removal Assumption for Waste Coal Units: Based on 2010 ICR data waste coal units in the 

Base Case for MATS were assumed to achieve 99% mercury removal. Part B Cross-Reference: This 

revision is reflected in new footnote under Table 11-4 that appears in Part B. 

 
10 

Errata and Enhancements of Previous Documentation 

Below is a listing of corrections to errors in previous documentation and enhancements to previous 

documentation items. The items below do not represent changes in the base case itself but in the 

documentation describing features included in the base case. 

SCR Cost Equations: The following editorial corrections should be made to the Sargent & Lundy paper, 

SCR Cost Development Methodology (at www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Appendix52A.pdf : 

a) on pages 5 and 6, change the formula text for "NOx Removal Factor" (L) to: K/80 

b) on page 6, add the following formula text for "Variable O&M costs for catalyst replacement & 

disposal" (VOMW): 

VOMW ($/MWh) = 0.3*(G)^2.9*(L)^0.71/8760/J*100*S 

Fabric Filter (FF) Costs Include Ash Handling: The following clarifying text should be added to the 

Sargent & Lundy paper, Particulate Control Cost Development Methodology (at 

www.epa.gov/airmarkets/progsregs/epa-ipm/docs/append5_5.pdf): 

a) on page 4, to the list of capital cost items included, add: “interconnecting piping, etc, to existing fly 

ash handling system” 

 

SNCR Removal Rates in Table 5-7: The removal rates in the last column of Table 5-7 did not correctly 

reflect the implementation in EPA Base Case v.4.10_MATS. Table 5-7 (“Summary of Retrofit NOx 

Emission Control Performance Assumptions”) is located in section 5.2 (“Nitrogen Oxides Control 

Technology”) of the previous documentation. Part B Cross-Reference: Using redline and strike-out 

highlights, the corrections to Table 5-7 are shown in Part B. 

ACI Cost Equations: The following editorial corrections should be made to the Sargent & Lundy paper, 

Mercury Control Cost Development Methodology (at www.epa.gov/airmarkets/progsregs/epaipm/docs/append5_3.pdf) : 

a) on pages 12 – 16 change the formula text for capital cost component “BMB” to: 

if(J = Not Added then 0, J = 6.0 Air-to-Cloth then 422, J = 4.0 Air-to-Cloth then 476)*B*L^0.81 

 
11 

Part B 

Detailed Information on Changes in 

EPA Base Case v.4.10_MATS 

(Using Mark-Up of Previous Documentation 

Reports) 
12 

Chapter 3: Power System Operation Assumptions 

3.9 Existing Environmental Regulations 

This section describes the existing federal, regional, and state SO2, NOx, mercury, and CO2 emissions 

regulations that are represented in the EPA Base Case v.4.10_MATS. The first three subsections 

discuss national and regional regulations. The next two subsections describe state level environmental 

regulations and a variety of legal settlements. The last subsection presents emission assumptions for 

potential units. 

Note on Clean Air Interstate Rule (CAIR): In December 2008 the U.S. Court of Appeals for the District 

of Columbia Circuit remanded CAIR to EPA to correct legal flaws in the proposed regulations as cited in 

the Court’s July 2008 ruling. Until EPA’s work was completed, CAIR, which includes a cap-and-trade 

system for SO2 and NOx emissions, was temporarily reinstated. However, although CAIR’s provisions 

were still in effect when EPA Base Case v.4.10 was released, it is not included in the base case to allow 

EPA Base Case v.4.10 to be used to analyze the regulations proposed to replace CAIR.

Note on Cross-State Air Pollution Rule (CSAPR): Since issuing the Documentation Supplement for the 

Proposed Toxics Rule in March of 2011, the EPA Administrator on July 6, 2011 signed a Notice of Final 

Rulemaking for the Cross-State Air Pollution Rule (CSAPR). As a result of this regulatory action, the SO2 

and NOx provisions of CSAPR were incorporated in the EPA Base Case v.4.10_MATS. Below are a map 

of affected states and state budget tables listing the key CSAPR provisions. 

Figure 3.1. CSAPR States 
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Table 3. 1. a) SO2  

Emissions Budget Variability Limit

In 1000 tons 2012 2014 2012 2014

Alabama 216.033 213.258 38.886 38.386

Georgia 158.527 95.231 28.535 17.142

Illinois 234.889 124.123 42.28 22.342

Indiana 285.424 161.111 51.376 29

Iowa 107.085 75.184 19.275 13.533

Kansas 41.528 41.528 7.475 7.475

Kentucky 232.662 106.284 41.879 19.131

Maryland 30.12 28.203 5.422 5.077

Michigan 229.303 143.995 41.275 25.919

Minnesota 41.981 41.981 7.557 7.557

Missouri 207.466 165.941 37.344 29.869

Nebraska 65.052 65.052 11.709 11.709

New Jersey 5.574 5.574 1.003 1.003

New York 27.325 18.585 4.919 3.345

North Carolina 136.881 57.62 24.639 10.372

Ohio 310.23 137.077 55.841 24.674

Pennsylvania 278.651 112.021 50.157 20.164

South Carolina 88.62 88.62 15.952 15.952

Tennessee 148.15 58.833 26.667 10.59

Texas 243.954 243.954 43.912 43.912

Virginia 70.82 35.057 12.748 6.31

West Virginia 146.174 75.668 26.311 13.62

Wisconsin 79.48 40.126 14.306 7.223

Table 3.1. b) Ozone Season NOx  

Emissions Budget Variability Limit

In 1000 tons 2012 2014 2012 2014

Alabama 31.746 31.499 6.667 6.615

Arkansas 15.037 15.037 3.158 3.158

Florida 27.825 27.825 5.843 5.843

Georgia 27.944 18.279 5.868 3.839

Illinois 21.208 21.208 4.454 4.454

Indiana 46.876 46.175 9.844 9.697

Iowa 16.532 16.207 3.472 3.403

Kansas 13.536 10.998 2.843 2.31

Kentucky 36.167 32.674 7.595 6.862

Louisiana 13.432 13.432 2.821 2.821

Maryland 7.179 7.179 1.508 1.508
14 

Michigan 25.752 24.727 5.408 5.193

Mississippi 10.16 10.16 2.134 2.134

Missouri 22.762 21.073 4.78 4.425

New Jersey 3.382 3.382 0.71 0.71

New York 8.331 8.331 1.75 1.75

North Carolina 22.168 18.455 4.655 3.876

Ohio 40.063 37.792 8.413 7.936

Oklahoma 21.835 21.835 4.585 4.585

Pennsylvania 52.201 51.912 10.962 10.902

South Carolina 13.909 13.909 2.921 2.921

Tennessee 14.908 8.016 3.131 1.683

Texas 63.043 63.043 13.239 13.239

Virginia 14.452 14.452 3.035 3.035

West Virginia 25.283 23.291 5.309 4.891

Wisconsin 13.704 13.216 2.878 2.775

Table 3.1. c) Annual NOx  

Emissions Budget Variability Limit

In 1000 tons 2012 2014 2012 2014

Alabama 72.691 71.962 13.084 12.953

Georgia 62.01 40.54 11.162 7.297

Illinois 47.872 47.872 8.617 8.617

Indiana 109.726 108.424 19.751 19.516

Iowa 38.335 37.498 6.9 6.75

Kansas 30.714 25.56 5.529 4.601

Kentucky 85.086 77.238 15.315 13.903

Maryland 16.633 16.574 2.994 2.983

Michigan 60.193 57.812 10.835 10.406

Minnesota 29.572 29.572 5.323 5.323

Missouri 52.374 48.717 9.427 8.769

Nebraska 26.44 26.44 4.759 4.759

New Jersey 7.266 7.266 1.308 1.308

New York 17.543 17.543 3.158 3.158

North Carolina 50.587 41.553 9.106 7.48

Ohio 92.703 87.493 16.687 15.749

Pennsylvania 119.986 119.194 21.597 21.455

South Carolina 32.498 32.498 5.85 5.85

Tennessee 35.703 19.337 6.427 3.481

Texas 133.595 133.595 24.047 24.047

Virginia 33.242 33.242 5.984 5.984

West Virginia 59.472 54.582 10.705 9.825
15 

Wisconsin 31.628 30.398 5.693 5.472

“Dispatchable” Controls Operate in CSAPR Covered States: After the Clean Air Interstate Rule (CAIR) 

was remanded to EPA by the Court for revision, existing emission controls for SO2 and NOx that had 

been installed in anticipation of CAIR were modeled as “dispatchable.” (see Documentation Supplement 

for EPA Base Case v.4.10_FTransport – Updates for Final Transport Rule (EPA #430-K-11-004). June 

2011, page 54, available at www.epa.gov/airmarkets/progsregs/epaipm/CSAPR/docs/DocSuppv410_FTransport.pdf.)

Since Base Case v.4.10_MATS includes CASPR, which EPA recently promulgated to replace CAIR, 

“dispatchable” controls in states covered by CASPR are operated in this scenario. 

Table 3.2.a) List of Units Operating "Dispatchable" FGD Retrofits in Base Case v4.10 for MATS 

Plant Name UniqueID Unit ID State Name Capacity (MW)

Cayuga 1001_B_2 2 Indiana 473

E W Brown 1355_B_1 1 Kentucky 94.0

E W Brown 1355_B_2 2 Kentucky 160

Ghent 1356_B_1 1 Kentucky 475

Ghent 1356_B_2 2 Kentucky 469

Ghent 1356_B_3 3 Kentucky 478

Ghent 1356_B_4 4 Kentucky 478

Elmer Smith 1374_B_1 1 Kentucky 132

Elmer Smith 1374_B_2 2 Kentucky 261

Paradise 1378_B_3 3 Kentucky 977

Kenneth C Coleman 1381_B_C1 C1 Kentucky 150

Kenneth C Coleman 1381_B_C2 C2 Kentucky 150

Kenneth C Coleman 1381_B_C3 C3 Kentucky 155

HMP&L Station Two

Henderson 1382_B_H1 H1 Kentucky 153

HMP&L Station Two

Henderson 1382_B_H2 H2 Kentucky 159

Dickerson 1572_B_1 1 Maryland 182

Dickerson 1572_B_2 2 Maryland 182

Dickerson 1572_B_3 3 Maryland 182

Monroe 1733_B_1 1 Michigan 770

Monroe 1733_B_2 2 Michigan 785

Monroe 1733_B_3 3 Michigan 795

Monroe 1733_B_4 4 Michigan 775

Sioux 2107_B_1 1 Missouri 497

Sioux 2107_B_2 2 Missouri 497

B L England 2378_B_1 1 New Jersey 129

B L England 2378_B_2 2 New Jersey 155

AES Cayuga 2535_B_1 1 New York 152

AES Cayuga 2535_B_2 2 New York 153

C R Huntley Generating Station 2549_B_67 67 New York 190
16 

C R Huntley Generating Station 2549_B_68 68 New York 190

Dunkirk Generating Station 2554_B_3 3 New York 185

Dunkirk Generating Station 2554_B_4 4 New York 185

E C Gaston 26_B_5 5 Alabama 861

Miami Fort 2832_B_7 7 Ohio 500

Miami Fort 2832_B_8 8 Ohio 500

Niles 2861_B_1 1 Ohio 109

Hamilton 2917_B_9 9 Ohio 51.0

Barry 3_B_5 5 Alabama 750

Homer City Station 3122_B_3 3 Pennsylvania 650

Keystone 3136_B_1 1 Pennsylvania 850

Keystone 3136_B_2 2 Pennsylvania 850

PPL Brunner Island 3140_B_1 1 Pennsylvania 335

PPL Brunner Island 3140_B_2 2 Pennsylvania 387

PPL Brunner Island 3140_B_3 3 Pennsylvania 754

PPL Montour 3149_B_1 1 Pennsylvania 761

PPL Montour 3149_B_2 2 Pennsylvania 757

Hatfields Ferry Power Station 3179_B_1 1 Pennsylvania 530

Hatfields Ferry Power Station 3179_B_2 2 Pennsylvania 530

Hatfields Ferry Power Station 3179_B_3 3 Pennsylvania 530

W S Lee 3264_B_3 3

South

Carolina 170

Wateree 3297_B_WAT1 WAT1

South

Carolina 350

Wateree 3297_B_WAT2 WAT2

South

Carolina 350

Williams 3298_B_WIL1 WIL1

South

Carolina 615

W A Parish 3470_B_WAP6 WAP6 Texas 650

Yorktown 3809_B_1 1 Virginia 159

Fort Martin Power Station 3943_B_1 1 West Virginia 552

Fort Martin Power Station 3943_B_2 2 West Virginia 555

Harrison Power Station 3944_B_1 1 West Virginia 652

Harrison Power Station 3944_B_2 2 West Virginia 642

Harrison Power Station 3944_B_3 3 West Virginia 651

Genoa 4143_B_1 1 Wisconsin 356

Charles R Lowman 56_B_1 1 Alabama 86.0

James H Miller Jr 6002_B_1 1 Alabama 684

Brandon Shores 602_B_1 1 Maryland 643

Killen Station 6031_B_2 2 Ohio 615

Gibson 6113_B_1 1 Indiana 630

Gibson 6113_B_2 2 Indiana 628
17 

Gibson 6113_B_3 3 Indiana 628

Fayette Power Project 6179_B_1 1 Texas 598

Fayette Power Project 6179_B_2 2 Texas 598

Gorgas 8_B_10 10 Alabama 690

Gorgas 8_B_8 8 Alabama 165

Gorgas 8_B_9 9 Alabama 175

Cheswick 8226_B_1 1 Pennsylvania 580

Coffeen 861_B_01 01 Illinois 340

Coffeen 861_B_02 02 Illinois 560

Havana 891_B_9 9 Illinois 487

Harding Street 990_B_70 70 Indiana 435

Petersburg 994_B_3 3 Indiana 540

Table 3.2.b) List of Units Operating "Dispatchable" SCR Retrofits in Base Case v4.10 for MATS 

Plant Name UniqueID Unit ID State Name Capacity (MW)

Lansing 1047_B_4 4 Iowa 261

AES Deepwater 10670_B_AAB001 AAB001 Texas 140

Seminole 136_B_1 1 Florida 658

Seminole 136_B_2 2 Florida 658

St Johns River Power Park 207_B_1 1 Florida 626

St Johns River Power Park 207_B_2 2 Florida 626

W A Parish 3470_B_WAP5 WAP5 Texas 645

W A Parish 3470_B_WAP6 WAP6 Texas 650

W A Parish 3470_B_WAP7 WAP7 Texas 565

W A Parish 3470_B_WAP8 WAP8 Texas 600

Edgewater 4050_B_5 5 Wisconsin 414

John P Madgett 4271_B_B1 B1 Wisconsin 398

Crystal River 628_B_4 4 Florida 722

Crystal River 628_B_5 5 Florida 721

Deerhaven Generating Station 663_B_B2 B2 Florida 228

Sandow 6648_B_4 4 Texas 545

C D McIntosh Jr 676_B_3 3 Florida 342

● ● ●

3.9.3 CO2 Regulations and Renewable Portfolio Standards 

The Regional Greenhouse Gas Initiative (RGGI) is a year-round CO2 cap and trade program affecting 

fossil fired electric power plants 25 MW or larger in Connecticut, Delaware, Maine, New Hampshire, New 

Jersey, New York, Vermont, Rhode Island, Massachusetts, and Maryland. 

EPA Base Case v.4.10_MATS incorporated the following updated targets to reflect Colorado RPS: 

- 12% of its retail electricity sales in Colorado for the years 2011-2014; 

- 20% of its retail electricity sales in Colorado for the years 2015-2019; and 
18 

- 30% of its retail electricity sales in Colorado for the years 2020 and later. 

Renewable Portfolio Standards (RPS) generally refer to various state-level policies that require the 

addition of renewable generation to meet a specified share of state-wide generation In EPA Base Case 

v.4.10 the state RPS requirements are represented at a regional level utilizing the aggregate regional 

representation of RPS requirements that is implemented in AEO 20104

 as shown in Appendix 3-6. This 

appendix shows the RPS requirements that apply to the NEMS (National Energy Modeling System) 

regions used in AEO. The RPS requirement for a particular NEMS region applies to all IPM regions that 

are predominantly contained in that NEMS region. 

3.9.4 State Specific Environmental Regulations 

EPA Base Case v.4.10 represents laws and regulations in 25 states affecting emissions from the 

electricity sector. The laws and regulations had to either be on the books or expected to come into force. 

Appendix 3-2 summarizes the provisions of state laws and regulations that are represented in EPA Base 

Case 4.10. 

EPA Base Case v.4.10_MATS incorporated the following provisions of the Colorado Clean Air-Clean 

Jobs Act (HB 1365, passed in April 2010): 

Table 3-9-4. Changes Incorporated in EPA Base Case v.4.10_MATS in Response to Provisions 

of the Colorado Clean Air-Clean Jobs Act (HB 1365, passed in April 2010) 

Plant 

Name UniqueID ORIS Plant Code 

Unit 

ID Modeled In v.4.10_FMATS 

Arapahoe 465_B_3 465 3 Unit retired, effective in 2015 run year 

Arapahoe 465_B_4 465 4 Unit forced to convert to natural gas, 

effective in 2015 run year 

Cameo 468_B_1 468 1 Retired in NEEDS 

Cameo 468_B_2 468 2 Retired in NEEDS 

Cherokee 469_B_1 469 1 Unit retired, effective in 2012 run year 

Cherokee 469_B_2 469 2 Unit retired, effective in 2012 run year 

Cherokee 469_B_3 469 3 Unit retired, effective in 2020 run year 

Cherokee 469_B_4 469 4 Unit forced to convert to natural gas, 

effective in 2020 run year 

Valmont 477_B_5 477 5 Unit retired, effective in 2020 run year 

W N Clark 462_B_55 462 55 Unit retired, effective in 2015 run year 

W N Clark 462_B_59 462 59 Unit retired, effective in 2015 run year 

State Mercury Regulations in MATS Base and Policy Cases: Consistent with the mercury risk 

deposition modeling for MATS, EPA did not model non-federally enforceable mercury-specific emissions 

reduction rules (as shown in Appendix 3-2 in the Documentation Supplement for Proposed Toxics Rule) 

in the base case or MATS policy case (see preamble section III.A) 

3.9.5 New Source Review (NSR) Settlements 

The New Source Review, (NSR) settlements refer to legal agreements with companies resulting from the 

 

4

Energy Information Administration, U.S. Department of Energy, Assumptions to Annual Energy Outlook 

2010: Renewable Fuels Module (DOE/EIA-0554(2010)), April 9, 2010, Table 13.4 “Aggregate Regional 

RPS Requirements, www.eia.doe.gov/oiaf/aeo/assumption/renewable.html and 

www.eia.doe.gov/oiaf/aeo/assumption/pdf/renewable_tbls.pdf
19 

permitting process under the CAAA which requires industry to undergo an EPA pre-construction review of 

proposed environmental controls either on new facilities or as modifications to existing facilities where 

there would result a “significant increase” in a regulated pollutant. EPA Base Case v.4.10_MATS includes 

more than 20 NSR settlements with electric power companies. EPA Base Case v.4.10_MATS includes 

provisions of the recently announced NSR settlements with Northern Indiana Public Service Company 

(NIPSCO) and Tennessee Valley Authority (TVA). See 

www.epa.gov/compliance/resources/cases/civil/caa/nipsco.html and 

www.epa.gov/compliance/resources/cases/civil/caa/tvacoalfired. An updated summary of the units 

affected and how the settlements were all the NSR settlements that are modeled in Base Case 

v.4.10_MATS can be found in Appendix 3-3. 

Seven state settlements and five citizen settlements are also represented in EPA Base Case v.4.10. 

These are summarized in Appendices 3-4 and 3-5 respectively. 

3.9.7 Unit-Level Control, Emission and Fuel Assumptions (new) 

The following unit specific assumptions were adopted in EPA Base Case v.4.10 for MATS: 

3.9.7.1 Existing ACI Controls in MATS Base and Policy Cases: As indicated above in section 3.9.4, 

EPA did not model non-federally enforceable mercury-specific emissions reduction rules. Units which 

were online before 2008 with existing ACI controls installed were therefore assumed not to operate those 

controls in EPA Base Case v.4.10_MATS, but were assumed to operate the existing ACI in the MATS 

policy case. Units that commenced operation after 2007 were assumed to operate existing ACI because 

these units are required under section 112(g) to meet HAP limitations (including Hg) for new units. 

3.9.7.2 Monroe Units 1 and 2 and Big Sandy Units 1 and 2: The flue gas desulfurization (FGD) for 

SO2 control at Monroe units 1 and 2 are assumed not to run in 2012. This restriction was not imposed 

after 2012. Big Sandy Units 1 and 2 had dispatchable controls in the Proposed MATS. This flexibility was 

not offered in Final MATS, the controls were implemented as non-dispatchable. 

3.9.7.3 Dunkirk Units 3 and 4, C R Huntley Units 7 and 8: The SO2 removal rates were adjusted to

reflect DSI technology instead of FGD that was assumed in the previous versions.   

                                                 DSI           FGD

Dunkirk Units 3 and 4                     70%                                                              95.9%

CR Huntley Units 7 and 8               70%                                                              92.3%

3.9.7.4 Coal Units in Washington State (including retirement of Centralia Units 1 and 2 and the 

Boardman Units: Due to the approval of the Washington State Senate bill (formally known as Senate 

Bill 5769), new base load coal generation in Washington is subjected to 1,100 lbs/MWh CO2 rate limit 

and Centralia Units 1 and 2 and the Boardman units are retired in 2021, 2026 and 2021 years 

respectively. 

3.9.7.5 D B Wilson plant: Based on a comment received bituminous coal in addition to petroleum coke 

was provided as a fuel option for D B Wilson (unique ID 6823_B_W1). In previous base cases its fuel 

choice had been exclusively petroleum coke. To make the additional fuel choice possible, this plant was 

assigned to coal demand region IBB3 instead of PCOK 

3.9.7.6 Revised Coal Assignments to Improve Consistency with EIA Form 923: The following table 

shows revisions in coal assignments that were made to improve the consistency between the coal 

assignments in EPA Base Case v.4.10_MATS and the coal consumption reported in EIA Form 923 for 

2008. 
20 

Table 3-9-7-5. Changes in Coal Assignments in EPA Base Case v.4.10_MATS to Improve 

Consistency with Information Reported in EIA Form 923 (2008) 

Plant Name UniqueID 

ORIS 

Plant 

Code 

Unit 

ID 

Modeled Fuels In 

v.4.10_FTransport 

Modeled Fuels In 

v.4.10_MATS Notes 

C P Crane 1552_B_1 1552 1 Subbituminous Subbituminous, 

Bituminous 

C P Crane 1552_B_2 1552 2 Subbituminous Subbituminous, 

Bituminous 

Herbert A 

Wagner 1554_B_2 1554 2 Subbituminous Subbituminous, 

Bituminous 

Herbert A 

Wagner 1554_B_3 1554 3 Subbituminous Subbituminous, 

Bituminous 

PSEG Hudson 

Generating 

Station 

2403_B_2 2403 2 Bituminous Subbituminous, 

Bituminous 

Coal demand 

region 

changed from 

NE2 to PE1 to 

provide both 

coal ranks. 

R E Burger 2864_B_5 2864 5 Bituminous Subbituminous, 

Bituminous 

R E Burger 2864_B_6 2864 6 Bituminous Subbituminous, 

Bituminous 

Willow Island 3946_B_1 3946 1 Bituminous Subbituminous 

Willow Island 3946_B_2 3946 2 Bituminous Subbituminous 
21 

Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10_MATS 

Company and 

Plant State Unit 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retiremen

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retiremen

Alabama Power 

James H. Miller Alabama Units 3 & 4 

Install and 

operate 

FGD 

continuously 

95% 12/31/11 

Operate 

existing 

SCR 

continuously 

0.1 05/01/08 0.03 12/31/06 

With 45 days of settlement entry, APC must retire 7,538 SO2emission allowances. 

Minnkota Power Cooperative Beginning 1/01/2006, Minnkota shall not emit more than 31,000 tons of SO2/year, no more than 26,000 tons beginning 2011, no more than 11,500 tons beginning 1/01/2012. If Unit 3 is not operational by 12/31/2015, theshall not exceed 8,500. 

Milton R. Young Minnesota 

Unit 1 

Install and 

continuously 

operate 

FGD 

95% if 

wet 

FGD, 

90% if 

dry 

12/31/11 

Install and 

continuously 

operate 

Over-fire 

AIR, or 

equivalent 

technology 

with 

emission 

rate < .36 

0.36 12/31/09 

0.03 if 

wet 

FGD, 

.015 if 

dry FGD 

Plant will surrender 4,346 allowances for each year 2012 –2015, 8,693 allowances for years 2016 –2018, 12,170 allowances for year 2019, and 14,886 allowances/year thereafter if Units 1 – 3 are operational by 12/31/2015If only Units 1 and 2 are operational by12/31/2015, the plant shall retire 17,886 units in 2020 and thereafter. 

Unit 2 

Design, 

upgrade, 

and 

continuously 

operate 

FGD 

90% 12/31/10 

Install and 

continuously 

operate 

over-fire 

AIR, or 

equivalent 

technology 

with 

emission 

rate < .36 

0.36 12/31/07 0.03 Before 2008 
22 

SIGECO 

FB Culley Indiana 

Unit 1 

Repower 

to 

natural 

gas (or 

retire) 

12/31/06 

The provision did not specify an amount of SO2allowances to be surrenderedIt only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. 

Unit 2 

Improve and continuously 

operate 

existing 

FGD 

(shared by 

Units 2 and 

3) 

95% 06/30/04 

Unit 3 

Improve and continuously 

operate 

existing 

FGD 

(shared by 

Units 2 and 

3) 

95% 06/30/04 

Operate 

Existing 

SCR 

Continuousl

y 

0.1 09/01/03 

Install and 

continuously 

operate a 

Baghouse 

0.015 06/30/07 

PSEG FOSSIL 

Bergen New Jersey Unit 2 

Repower 

to 

combine

d cycle 

12/31/02 

The provision did not specify an amount of SO2allowances to be surrenderedIt only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. 

Hudson New Jersey Unit 2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/06 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 05/01/07 

Install 

Baghouse 

(or approved 

technology) 

0.015 12/31/06 
23 

Mercer New Jersey Units 1 & 2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/10 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.13 05/01/06 

TECO 

Big Bend Florida 

Units 

1 & 2 

Existing 

Scrubber 

(shared by 

Units 1 & 2) 

95% 

(95% or 

.25) 

09/1/00 

(01/01/1

3) 

Install SCR 0.1 05/01/09 

The 

provision di

not specify 

an amount 

of SO2

allowances 

to be 

surrendered

It only 

provided 

that excess 

allowances 

resulting 

from 

compliance 

with NSR 

settlement 

provisions 

must be 

retired. 

Unit 3 

Existing 

Scrubber 

(shared by 

Units 3 & 4) 

93% if 

Units 3 & 

4 are 

operating 

2000 

(01/01/1

0) 

Install SCR 0.1 05/01/09 

Unit 4 

Existing 

Scrubber 

(shared by 

Units 3 & 4) 

93% if 

Units 3 & 

4 are 

operating 

06/22/05 Install SCR 0.1 07/01/07 

Gannon Florida Six units 

Retire all 

six coal 

units and 

repower 

at least 

550 MW 

of coal 

capacity 

to 

natural 

gas 

12/31/04 

WEPCO WEPCO shall comply with the following system wide average NOx emission rates and total NOx tonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and by 1/1/2013 an emission rate of 0.17 and 17, 400 tons. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an emission rate of 0.32 and 33,300 tons. 

http://www.e.html 

Presque Isle Wisconsin 

Units 

1 – 4 

Retire or 

install 

SO2 and 

NOx

controls 

12/31/12 

Install and 

continuously 

operate 

FGD (or 

approved 

equiv. tech) 

95% or 

0.1 12/31/12 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 12/31/12 

The 

provision di

not specify 

an amount 

of SO2

allowances 

to be 

surrendered

It only 

provided 

that excess 

allowances 

resulting 

from 

compliance 

with NSR 

settlement 

provisions 

must be 

retired. 

Units 

5 & 6 

Install and 

operate low 

NOx burners 

12/31/03 

Units 

7 & 8 

Operate 

existing low 

NOx burners 

12/31/05 Install Baghouse 

Unit 9 

Operate 

existing low 

NOx burners 

12/31/06 Install Baghouse 

Pleasant Prairie Wisconsin 1 

Install and 

continuously 

operate 

FGD (or 

95% or 

0.1 12/31/06 

Install and 

continuously 

operate 

SCR (or 

0.1 12/31/06 
24 

approved 

control tech) 

approved 

tech) 

2 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/07 

Install and 

continuously 

operate 

SCR (or 

approved 

tech) 

0.1 12/31/03 

Oak Creek Wisconsin 

Units 

5 & 6 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/12 

Install and 

continuously 

operate 

SCR (or 

approved 

tech) 

0.1 12/31/12 

Unit 7 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/12 

Install and 

continuously 

operate 

SCR (or 

approved 

tech) 

0.1 12/31/12 

Unit 8 

Install and 

continuously 

operate 

FGD (or 

approved 

control tech) 

95% or 

0.1 12/31/12 

Install and 

continuously 

operate 

SCR (or 

approved 

tech) 

0.1 12/31/12 

Port Washington Wisconsin Units 1 – 4 Retire 

12/31/04 

for Units 

1 – 3. 

Unit 4 by 

entry of 

consent 

decree 

Valley Wisconsin 

Boiler

s 1 –

4 

Operate 

existing low 

NOx burner 

30 days 

after 

entry of 

consent 

decree 

VEPCO The Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 – 2010, 54,000 in 2011, 50,000 in 2012, and 30,250 each year there after. Beginning 1/1/2013 they will have a system wide emission rate no greater then 0.15 lb/MMBtu. 

http://www.e.html 

Mount Storm West Virginia Units 1 – 3 Construct or improve FGD 95% or 0.15 01/01/05 Install and continuously operate SCR 0.11 01/01/08 

On or befor

March 31 o

every year 

beginning in 

2013 and 

continuing thereafter, 

VEPCO 

shall 

surrender 

45,000 SO2

allowances

Chesterfield Virginia 

Unit 4 

Install and 

continuously 

operate 

SCR 

0.1 01/01/13 

Unit 5 

Construct or 

improve 

FGD 

95% or 

0.13 10/12/12 

Install and 

continuously 

operate 

SCR 

0.1 01/01/12 

Unit 6 

Construct or 

improve 

FGD 

95% or 

0.13 01/01/10 

Install and 

continuously 

operate 

SCR 

0.1 01/01/11 
25 

Chesapeake 

Energy Virginia Units 3 & 4 

Install and 

continuously 

operate 

SCR 

0.1 01/01/13 

Clover Virginia Units 1 & 2 Improve FGD 95% or 0.13 09/01/03 

Possum Point Virginia Units 3 & 4 

Retire 

and 

repower 

to 

natural 

gas 

05/02/03 

Santee Cooper 

Santee Cooper shall comply with the following system wide averages for NOx emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 3

emission rate of 0.18 and 25,000 tons, by 1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2 emission the company shall comply with system wide averages of: by 1/1/2005 an emission 1/1/2007 and emission rate of 0.75 and 85,000 tons, by 1/1/2009 an emission rate of 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65 tons.

Cross South Carolina 

Unit 1 

Upgrade 

and 

continuously 

operate 

FGD 

95% 06/30/06 

Install and 

continuously 

operate 

SCR 

0.1 05/31/04 

The 

provision di

not specify 

an amount 

of SO2

allowances 

to be 

surrendered

It only 

provided 

that excess 

allowances 

resulting 

from 

compliance 

with NSR 

settlement 

provisions 

must be 

retired. 

Unit 2 

Upgrade 

and 

continuously 

operate 

FGD 

87% 06/30/06 

Install and 

Continuousl

y operate 

SCR 

0.11/0.1 

05/31/04 

and 

05/31/07 

Winyah South Carolina 

Unit 1 

Install and 

continuously 

operate 

FGD 

95% 12/31/08 

Install and 

continuously 

operate 

SCR 

0.11/0.1 

11/30/04 

and 

11/30/04 

Unit 2 

Install and 

continuously 

operate 

FGD 

95% 12/31/08 

Install and 

continuously 

operate 

SCR 

0.12 11/30/04 

Unit 3 

Upgrade 

and 

continuously 

operate 

existing 

FGD 

90% 12/31/08 

Install and 

continuously 

operate 

SCR 

0.14/0.12 

11/30/20

05 and 

11/30/08 

Unit 4 

Upgrade 

and 

continuously 

operate 

existing 

FGD 

90% 12/31/07 

Install and 

continuously 

operate 

SCR 

0.13/0.12 

11/30/05 

and 

11/30/08 

Grainger South Carolina 

Unit 1 

Operate low 

NOx burner 

or more 

stringent 

technology 

06/25/04 

Unit 2 

Operate low 

NOx burner 

or more 

stringent 

technology 

05/01/04 

Jeffries South Carolina Units 3, 4 

Operate low 

NOx burner 

or more 

stringent 

technology 

06/25/04 

Ohio Edison 
26 

Ohio Edison shall achieve reductions of 2,483 tons NOx between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1 – 3 during the months of October through April, and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOx required for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2 by 12/31/2010. 

http://www.edison.html 

No later than 8/11/2005, Ohio Edison shall install and operate low NOx burners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combuNOx emissions from Sammis Units 1 – 5. 

W.H. Sammis 

Plant Ohio 

Unit 1 

Install 

Induct 

Scrubber (or

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/MMBt

u 

12/31/08 

Install 

SNCR 

(or approved

alt. tech) & 

operate 

continuously 

0.25 10/31/07 

Beginning 

1/1/2006, O

Edison m

use, sell 

transfer a

restricted S

only to sat

the Operati

Needs at t

Sammis, Bu

and Mansf

Plant, or n

units within 

FirstEner

System th

comply wit

96% remo

for SO2. 

calendar y

2006 throu

2017, Oh

Edison m

accumula

SO2 allowan

for use at 

Sammis

Burger, a

Mansfiel

plants, o

FirstEner

units equip

with SO

Emissio

Control 

Standard

Beginning 

2018, Oh

Edison sh

surrende

unused 

restricted S

allowance

Unit 2 

Install 

Induct 

Scrubber (or

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/MMBt

u 

12/31/08 

Operate 

existing 

SNCR 

continuously 

0.25 02/15/06 

Unit 3 

Install 

Induct 

Scrubber (or

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/MMBt

u 

12/31/08 

Operate low 

NOx burners 

and overfire 

air by 

12/1/05; 

install SNCR(or approved

alt. tech) & 

operate 

continuously 

by 12/31/07 

0.25 

12/01/05 

and 

10/31/07 

Unit 4 

Install 

Induct 

Scrubber (or

approved 

equiv. 

control tech) 

50% 

removal 

or 1.1 

lb/MMBt

u 

06/30/09 

Install 

SNCR 

(or approved

alt. tech) & 

operate 

continuously 

0.25 10/31/07 

Unit 5 

Install Flash

Dryer 

Absorber 

or ECO2 (or

approved 

equiv. 

control tech) 

& 

operate 

continuously 

50% 

removal 

or 1.1 

lb/MMBt

u 

06/29/09 

Install 

SNCR 

(or approved

alt. tech) & 

Operate 

Continuousl

y 

0.29 03/31/08 

Unit 6 

Install FGD3

(or 

approved 

equiv. 

control tech) 

& 

operate 

continuously 

95% 

removal 

or 0.13 

lb/MMBt

u 

06/30/11 

Install 

SNCR 

(or approved

alt. tech) & 

operate 

continuously 

"Minimum

Extent 

Practicabl

e" 

06/30/05 

Operate 

Existing 

ESP 

Continuously 

0.03 01/01/10 

Unit 7 

Install FGD 

(or 

approved 

equiv. 

control tech) 

& 

operate 

continuously 

95% 

removal 

or 0.13 

lb/MMBt

u 

06/30/11 

Operate 

existing 

SNCR 

Continuousl

y 

"Minimum

Extent 

Practicabl

e" 

08/11/05 

Operate 

Existing 

ESP 

Continuously 

0.03 01/01/10 

Mansfield Plant Pennsylvan ia Unit 1 Upgrade existing FGD 95% 12/31/05 
27 

Unit 2 

Upgrade 

existing 

FGD 

95% 12/31/06 

Unit 3 

Upgrade 

existing 

FGD 

95% 10/31/07 

Eastlake Ohio Unit 5 

Install low 

NOx

burners, 

over-fired 

air and 

SNCR & 

operate 

continuously 

"Minimize 

Emission

s to the 

Extent 

Practicabl

e" 

12/31/06 

Burger Ohio 

Unit 4 Repower with at 

least 

80% 

biomass 

fuel, up 

to 20% 

low 

sulfur 

coal. 

12/31/11 

Unit 5 12/31/11 

MirantI1,6System-wide NOx Emission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NOxEmission Ozone Season Caps: 14,700 tons 2004; 13,340 tons 2005; 12,590 tons 2006; 10,190 tons 2007; 6,150 tons 2008 – 2009; 5,200 tons 2010 thereafter. Beginning on 5/1/2008, and continuing for each and every Ozone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Emission Rate of 0.150 lb/MMBtu NOx. 

http://www.e.html 

Potomac River 

Plant Virginia 

Unit 1 Unit 2 Unit 3 

Install low 

NOx

burners (or 

more 

effective 

tech) & 

operate 

continuously 

05/01/04 

Unit 4 

Install low 

NOx

burners (or 

more 

effective 

tech) & 

operate 

continuously 

05/01/04 

Unit 5 

Install low 

NOx

burners (or 

more 

effective 

tech) & 

operate 

continuously 

05/01/04 

Morgantown 

Plant Maryland Unit 1 

Install SCR 

(or approved 

alt. tech) & 

operate 

continuously 

0.1 05/01/07 
28 

Unit 2 

Install SCR 

(or approved 

alt. tech) & 

operate 

continuously 

0.1 05/01/08 

Chalk Point Maryland 

Unit 1 

Install and 

continuously 

operate 

FGD (or 

equiv. 

technology) 

95% 06/01/10 

For each y

after Mira

commenc

FGD opera

at Chalk Po

Mirant sh

surrender 

number of 

Allowance

equal to t

amount b

which the S

Allowance

allocated to 

Units at th

Chalk Po

Plant are 

greater than 

total amoun

SO2 emissi

allowed un

this Sectio

XVIII. 

Unit 2 

Install and 

continuously 

operate 

FGD (or 

equiv. 

technology) 

95% 06/01/10 

Illinois Power System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 tons 2011; 49,500 tons 2012; 29,000 tons 2013 onward. 

http://www.epower.html 

Baldwin Illinois 

Units 

1 & 2 

Install wet 

or dry FGD 

(or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

0.1 12/31/11 

Operate 

OFA & 

existing 

SCR 

continuously 

0.1 08/11/05 

Install & 

continuously 

operate 

Baghouse 

0.015 12/31/10 

By year e

2008, Dyne

will surren

12,000 SO

emission 

allowances

year end 20

will surren

18,000, by 

end 2010 it 

surrende

24,000, any 

year end 2

and each y

thereafter it 

surrende

30,000 

allowances

the surrend

allowance

result in 

insufficie

remainin

allowance

allocated to 

units 

comprising 

DMG syste

DMG ca

request t

surrender fe

SO2

allowance

Unit 3 

Install wet 

or dry FGD 

(or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

0.1 12/31/11 

Operate 

OFA and/or 

low NOx

burners 

0.12 until 

12/30/12; 

0.1 from 

12/31/12 

08/11/05 

and 

12/31/12 

Install & 

continuously 

operate 

Baghouse 

0.015 12/31/10 

Havana Illinois Unit 6 

Install wet 

or dry FGD 

(or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

1.2 

lb/MMBt

u until 

12/30/20

12; 0.1 

lb/MMBt

u from 

12/31/20

12 

onward 

08/11/05 

and 

12/31/12 

Operate 

OFA and/or 

low NOx

burners & 

operate 

existing 

SCR 

continuously 

0.1 08/11/05 

Install & 

continuously 

operate 

Baghouse, then install ESP or alt. 

PM equip 

For Baghouse: 

0.015 

lb/MMBt

u; For 

ESP: 

0.03 

lb/MMBt

u 

For 

Baghous

e: 

12/31/12;

For ESP: 

12/31/05 

Hennepin Illinois Unit 1 1.2 07/27/05 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

0.03 12/31/06 
29 

operate 

ESPs 

Unit 2 1.2 07/27/05 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/06 

Vermilion Illinois Units 1 & 2 1.2 01/31/07 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/10 

Wood River Illinois Units 4 & 5 1.2 07/27/05 

Operate 

OFA 

and/or low 

NOx burners 

"Minimum

Extent 

Practicabl

e" 

08/11/05 

Install ESP 

(or equiv. alt. 

tech) & 

continuously 

operate 

ESPs 

0.03 12/31/05 

Kentucky Utilities Company 

EW Brown 

Generating 

Station 

Kentucky Unit 3 Install FGD 97% or 0.100 12/31/10 

Install and 

continuously 

operate 

SCR by 

12/31/2012, 

continuously 

operate low 

NOx boiler 

and OFA. 

0.07 12/31/12 Continuously operate ESP 0.03 12/31/10 

KU mus

surrende

53,000 SO

allowances 

2008 or ea

vintage b

March 1, 20

All surplus 

allowance

must be 

surrender

through 20

Salt River Project Agricultural Improvement and Power District (SRP) 

Coronado 

Generating 

Station 

Arizona 

Unit 1 

or 

Unit 2 

Immediately 

begin 

continuous 

operation of 

existing 

FGDs on 

both units, 

install new 

FGD. 

95% or 

0.08 

New 

FGD 

installed 

by 

1/1/2012 

Install and 

continuously 

operate low 

NOx burner 

and SCR 

0.32 prior 

to SCR 

installatio

n, 0.080 

after 

LNB by 

06/01/20

09, SCR 

by 

06/01/20

14 Optimization and 

continuous 

operation of 

existing 

ESPs. 

0.03 

Optimiza

tion 

begins 

immediat

ely, rate 

limit 

begins 

01/01/12 

(date of 

new 

FGD 

installatio

n) 

Beginning 

2012, a

surplus S

allowances 

both Coron

and 

Springerv

Unit 4 mus

surrender

through 20

The allowan

limited by t

condition m

however, 

used fo

compliance 

prospecti

future pla

using BAC

and otherw

specified in 

54 of the 

Unit 1 

or 

Unit 2 

Install new 

FGD 

95% or 

0.08 01/01/13 

Install and 

continuously 

operate low 

NOx burner 

0.32 06/01/11 

Optimiza

tion 

begins 

immediat

ely, rate 

limit 

begins 

01/01/13 

(date of 
30 

new 

FGD 

installatio

n) 

consent dec

American Electric Power 

Eastern System-Wide 

Annual 

Cap 

(tons) 

Year 

Annual 

Cap 

(tons) 

Year 

NOx and S

allowances 

would hav

been mad

available 

emission 

reduction

pursuant to 

Consen

Decree mus

surrendere

450,000 2010 96,000 2009 450,000 2011 92,500 2010 420,000 2012 92,500 2011 350,000 2013 85,000 2012 340,000 2014 85,000 2013 275,000 2015 85,000 2014 260,000 2016 75,000 2015 235,000 2017 72,000 

2016 and 

thereafte

r 

184,000 2018 174,000 

2019 and 

thereafte

r 

At least 600MW 

from various 

units 

West 

Virginia 

Spor

n 

1 – 4 

Retire, 

retrofit, 

or repower 

12/31/18 

Virginia 

Clinc

h 

River 

1 – 3 

Indiana 

Tann

ers 

Cree

k 

1 – 3 

West 

Virginia 

Kam

mer 

1 – 3 

Amos West Virginia Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/09 

Install and 

continuously 

operate 

SCR 

01/01/08 
31 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/10 

Install and 

continuously 

operate 

SCR 

01/01/09 

Unit 3 

Install and 

continuously 

operate 

FGD 

12/31/09 

Install and 

continuously 

operate 

SCR 

01/01/08 

Big Sandy Kentucky 

Unit 1 

Burn only 

coal with no 

more than 

1.75 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/15 

Install and 

continuously 

operate 

SCR 

01/01/09 

Cardinal Ohio 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/08 

Install and 

continuously 

operate 

SCR 

01/01/09 Continuously operate ESP 0.03 12/31/09 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/08 

Install and 

continuously 

operate 

SCR 

01/01/09 Continuously operate ESP 0.03 12/31/09 

Unit 3 

Install and 

continuously 

operate 

FGD 

12/31/12 

Install and 

continuously 

operate 

SCR 

01/01/09 

Clinch River Virginia Units 1 – 3 

Plantwide 

annual 

cap: 

21,700 

tons from 

2010 to 

2014, 

then 

16,300 

after 

1/1/2015 

2010 –

2014, 

2015 and 

thereafte

r 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Conesville Ohio 

Unit 1 

Retire, 

retrofit, 

or repower 

Date of 

entry 

Unit 2 

Retire, 

retrofit, 

or repower 

Date of 

entry 
32 

Unit 3 

Retire, 

retrofit, 

or repower 

12/31/12 

Unit 4 

Install and 

continuously 

operate 

FGD 

12/31/10 

Install and 

continuously 

operate 

SCR 

12/31/10 

Unit 5 

Upgrade 

existing 

FGD 

95% 12/31/09 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Unit 6 

Upgrade 

existing 

FGD 

95% 12/31/09 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Gavin Ohio 

Unit 1 

Install and 

continuously 

operate 

FGD 

Date of 

entry 

Install and 

continuously 

operate 

SCR 

01/01/09 

Unit 2 

Install and 

continuously 

operate 

FGD 

Date of 

entry 

Install and 

continuously 

operate 

SCR 

01/01/09 

Glen Lyn Virginia 

Units 

1 – 3 

Units 

5, 6 

Burn only 

coal with no 

more than 

1.75 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Kammer West Virginia Units 1 – 3 

Plantwide 

annual 

cap: 

35,000 

01/01/10 

Continuousl

y operate 

over-fire air 

Date of 

entry 

Kanawha River West Virginia Units 1, 2 

Burn only 

coal with no 

more than 

1.75 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Mitchell West Virginia 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/07 

Install and 

continuously 

operate 

SCR 

01/01/09 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/07 

Install and 

continuously 

operate 

SCR 

01/01/09 

Mountaineer West Virginia Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/07 

Install and 

continuously 

operate 

SCR 

01/01/08 

Muskingum 

River Ohio Units 1 – 4 

Retire, 

retrofit, 

or repower 

12/31/15 
33 

Unit 5 

Install and 

continuously 

operate 

FGD 

12/31/15 

Install and 

continuously 

operate 

SCR 

01/01/08 Continuously operate ESP 0.03 12/31/02 

Picway Ohio Unit 9 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Rockport Indiana 

Unit 1 

Install and 

continuously 

operate 

FGD 

12/31/17 

Install and 

continuously 

operate 

SCR 

12/31/17 

Unit 2 

Install and 

continuously 

operate 

FGD 

12/31/19 

Install and 

continuously 

operate 

SCR 

12/31/19 

Sporn West Virginia Unit 5 

Retire, 

retrofit, 

or repower 

12/31/13 

Tanners Creek Indiana 

Units 

1 – 3 

Burn only 

coal with no 

more than 

1.2 

lb/MMBtu 

annual 

average 

Date of 

entry 

Continuousl

y operate 

low NOx

burners 

Date of 

entry 

Unit 4 

Burn only 

coal with no 

more than 

1.2% sulfur 

content 

annual 

average 

Date of 

entry 

Continuousl

y operate 

over-fire air 

Date of 

entry 

East Kentucky Power Cooperative Inc. By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOx controls at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012. 

System-wide 

Systemwide 12-

month 

rolling 

tonnage 

limits apply 

12-

month 

rolling 

limit 

(tons) 

Start of 

12-

month 

cycle All units must 

operate low 

NOx boilers 

12-month 

rolling 

limit 

(tons) 

Start of 

12-

month 

cycle 

PM control 

devices must 

be operated 

continuously 

system-wide, 

ESPs must 

be optimized 

within 270 

days of entry 

date, or 

0.03 

1 year 

from 

entry 

date 

All surplus 

allowance

must be 

surrender

each yea

beginning 

2008. 

57,000 10/01/08 11,500 01/01/08 40,000 07/01/11 8,500 01/01/13 
34 

28,000 01/01/13 8,000 01/01/15 

EKPC may 

choose to 

submit a PM 

Pollution 

Control 

Upgrade 

Analysis. 

Spurlock Kentucky Unit 1 

Install and 

continuously 

operate 

FGD 

95% or 

0.1 

6/30/201

1 

Continuousl

y operate 

SCR 

0.12 for 

Unit 1 

until 

01/01/201

3, at 

which 

point the 

unit limit 

drops to 

0.1. Prior 

to 

01/01/201

3, the 

combined 

average 

when 

both units 

are 

operating 

must be 

no more 

than 0.1 

60 days 

after 

entry 
35 

Unit 2 

Install and 

continuously 

operate 

FGD by 

10/1/2008 

95% or 

0.1 1/1/2009 

Continuousl

y operate 

SCR and 

OFA 

0.1 for 

Unit 2, 

0.1 

combined 

average 

when 

both units 

are 

operating 

60 days 

after 

entry 

Dale Plant Kentucky 

Unit 1 

Install and 

continuously 

operate low 

NOx burners 

by 

10/31/2007 

0.46 01/01/08 EKPC mu

surrender 1NOx allowan

immediate

under the A

and 3,10

under the N

SIP Call. E

must alssurrende

15,311 SO

allowance

Unit 2 

Install and 

continuously 

operate low 

NOx burners 

by 

10/31/2007 

0.46 01/01/08 

Unit 3 

EKPC 

may 

choose 

to retire 

Dale 3 

and 4 in 

lieu of 

installing 

controls 

in 

Cooper 2 

12/31/20

12 

Unit 4 

Cooper Kentucky 

Unit 1 

Unit 2 

If EKPC 

opts to 

install 

controls 

rather than 

retiring 

Dale, it must 

install and 

continuously 

operate 

FGD or 

equiv. 

technology 

95% or 

0.10 

If EKPC 

elects to 

install 

controls, it 

must 

continuously 

operate 

SCR or 

install equiv. 

technology 

0.08 (or 

90% if 

non-SCR 

technolog

y is used) 

12/31/12 

Nevada Power Company Beginning 1/1/2010, combined NOx emissions from Units 5,6,7, and 8 must be no more than 360 tons per year. 

Clark Generating 

Station Nevada Unit 5 

Units 

may only 

fire 

natural 

Increase 

water 

injection 

immediately, 

5ppm 1-

hour 

average 

12/31/08 

(ULNB 

installatio

n), 
36 

gas then install 

and operate 

ultra-low 

NOx burners 

(ULNBs) or 

equivalent 

technology. 

In 2009, 

Units 5 and 

8 may not 

emit more 

than 180 

tons 

combined 

01/30/09 

(1-hour 

average) 

Unit 6 

5ppm 1-

hour 

average 

12/31/09 

(ULNB 

installatio

n), 

01/30/10 

(1-hour 

average) 

Unit 7 

5ppm 1-

hour 

average 

12/31/09 

(ULNB 

installatio

n), 

01/30/10 

(1-hour 

average) 

Unit 8 

5ppm 1-

hour 

average 

12/31/08 

(ULNB 

installatio

n), 

01/30/09 

(1-hour 

average) 

Dayton Power & Light Non-EPA Settlement of 10/23/2008 

Stuart 

Generating 

Station 

Ohio 

Statio

nwide 

Complete 

installation 

of FGDs on 

each unit. 

96% or 

0.10 07/31/09 

Owners may 

not 

purchase 

any new 

catalyst with 

SO2 to SO3

conversion 

rate greater 

than 0.5% 

0.17 

stationwide 

30 days 

after 

entry 0.030 lb 

per unit 07/31/09 

0.17 

stationwide 

60 days 

after 

entry 

date 

82% 

including 

data 

from 

periods 

of 

malfuncti

ons 

7/31/09 

through 

7/30/11 

Install 

control 

technology 

on one unit 

0.10 on 

any 

single 

unit 

12/31/12 Install 

rigidtype 

electrodes in 

each 

unit's 

ESP 

12/31/15 82% 

including 

data 

from 

periods 

of 

malfuncti

ons 

after 

7/31/11 

0.15 

stationwide 07/01/12 

0.10 

stationwide 12/31/14 

PSEG FOSSIL, Amended Consent Decree of November 2006 

Kearny New Jersey Unit 7 Retire unit 01/01/07 

Allowance

allocated 

Kearny

Hudson, a

Mercer m

only be use

the operatio
37 

needs of th

units, and 

surplus 

allowance

must be 

surrendere

Within 90 d

of amend

Consen

Decree, PS

must surren

1,230 NO

Allowances 

8,568 SO

Allowances 

already 

allocated to 

generated 

the units lis

here. Kea

allowance

must be 

surrender

with the 

shutdown 

those uni

Unit 8 Retire unit 01/01/07 

Hudson New Jersey Unit 2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/10 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 12/31/10 

Install 

Baghouse 

(or approved 

technology) 

0.015 12/31/10 

Annual 

Cap 

(tons) 

Year 

Annual 

Cap 

(tons) 

Year 

5,547 2007 3,486 2007 5,270 2008 3,486 2008 5,270 2009 3,486 2009 5,270 2010 3,486 2010 

Mercer New Jersey Units 1 &2 

Install Dry 

FGD (or 

approved 

alt. 

technology) 

and 

continually 

operate 

0.15 12/31/10 

Install SCR 

(or approved 

tech) and 

continually 

operate 

0.1 01/01/07 

Install 

Baghouse 

(or approved 

technology) 

0.015 12/31/10 

Westar Energy 

Jeffrey Energy 

Center Kansas All units 

Units 1, 2, and 3 have a total annual limit of 6,600 tons of SO2 and an annual rate limit of 0.07 lbs/MMBtu starting 2012 Units 1, 2, and 3 must all install FGDs by 2011 and operate them continuously. FGDs must maintain a 30-Day Rolling Average Unit Removal Efficiency for SO2 of at least 97% or a 30-Day Rolling Average Unit Emission Rate for SO2 of no greater than 0.070 lb/MMBtu. 

Units 1-3 must continuously operate Low NOx Combustion Systems by 2012 and achieve and maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.180 lb/MMBtu. One of the three units must install an SCR by 2015 and operate it continuously to maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.080 lb/MMBtu. By 2013 Westar shall elect to either (a) install a second SCR on one of the other JEC Units by 2017 or (b) meet a 0.100 lb/MMBtu Plant-Wide 12-Month Rolling Average Emission Rate and 9.6 MTons annual cap for NOx by 2015 

Units 1, 2, and 3 must operate each ESP and FGD system continuously by 2011 and maintain a 0.030 lb/MMBtu PM Emissions Rate. Units 1 and 2’s ESPs must be rebuilt by 2014 in order to meet a 0.030 lb/MMBtu PM Emissions Rate 

Duke Energy 

Gallagher Indiana Units 1 & 3 

Retire or 

repower 

as 

natural 

gas 

1/1/2012 
38 

Units 

2 & 4 

Install Dry 

sorbent 

injection 

technology 

80% 1/1/2012 

American Municipal Power 

Gorsuch Station Ohio 

Units 

2 & 3 

Elected to Retire Dec 

15, 2010 (must retire 

by Dec 31, 2012) 

Units 

1 & 4 

Hoosier Energy Rural Electric Cooperative 

Ratts Indiana Units 1 & 2 

Install & 

continually 

operate 

SNCRS 

0.25 12/31/20 11 Continuously operate ESP Annually su

that Hoos

Merom Indiana 

Unit 1 

Continually 

run current 

FGD for 

90% 

removal and 

update FGD 

for 98% 

removal by 

2012 

98% 2012 

Continuously 

operate 

existing 

SCRs 

0.12 

Continuously operate ESP and achieve 

PM rate no greater than 0.007 by 

6/1/12 

Unit 2 

Continually 

run current 

FGD for 

90% 

removal and 

update FGD 

for 98% 

removal by 

2014 

98% 2014 

Continuously operate ESP and achieve 

PM rate no greater than 0.007 by 

6/1/13 

Northern Indiana Public Service Co. System-wide NOx Emission Caps in Tons: 15,537 in 2012, if NIPSCO chooses NOx Option 1: 15,247 in 2013, 14,959 in 2014, 14,365 in 2015, 11,704 in 2016 - 2018, if NIPSCO chooses NOx option A: 11,704 in 2019 & in 2019 & onwards; if NIPSCO chooses NOx Option 2: 13,752 in 2013, 13,464 in 2014, 12,870 in 2015 - 2018, if NIPSCO chooses NOx option A: 12,870 in 2019 & onwards, if NIPSCO chooses NOx option B: 11,470 in in Tons: 50,200 in 2012 - 2013,10,200 35,900 in 2014 & 2015, 25,300 in 2016-2018, if NIPSCO chooses SO2 option 1: 10,200 in 2019 & onwards, if NIPSCO chooses SO2 option 2: 11,600 in 2019 & onwards.

Bailly Indiana Units 7 & 8 Upgrade existing FGD 95% by 01/01/11 97% by 01/01/14 (95% if low sulfur coal only is burned) OFA & SCR 

0.15 lb/MMBtu by 

12/31/10 

0.13 lb/MMBtu by 

12/31/13 

0.12 lb/MMBtu by 

12/31/15 

0.3 

lb/MMBt

u (0.015 

if a 

baghous

e is 

installed

) 

12/31/20

10 

Michigan City Indiana Unit 12 FGD 0.1 lb/MMBt

u 

12/31/20

18 OFA & SCR 

0.14 lb/MMBtu by 

12/31/10 

0.12 lb/MMBtu by 

12/31/11 

0.10 lb/MMBtu by 

12/31/13 

0.3 

lb/MMBt

u (0.015 

if a 

baghous

e is 

installed

) 

12/31/20

18 
39 

Schahfer Indiana Unit 14 FGD 0.08 lb/MMBt

u 

12/31/20

13 OFA & SCR 

0.14 lb/MMBtu by 

12/31/10 

0.12 lb/MMBtu by 

12/31/12 

0.10 lb/MMBtu by 

12/31/14 

0.3 

lb/MMBt

u (0.015 

if a 

baghous

e is 

installed

) 

12/31/20

13 

Indiana Unit 15 FGD 0.08 lb/MMBt

u 

12/31/20

15 LNB/OFA 0.16 3/31/201 1 

0.3 

lb/MMBt

u (0.015 

if a 

baghous

e is 

installed

) 

12/31/20

15 

SCR 0.08 12/31/20 15 

Indiana 

Units 

17 & 

18 

Upgrade 

existing 

FGD 

97% 1/31/201 1 LNB/OFA 0.2 3/31/201 1 

0.3 

lb/MMBt

u (0.015 

if a 

baghous

e is 

installed

) 

12/31/20

10 

Dean H Mitchell Indiana 

Units 

4, 5, 

6, & 

11 

Retire 12/31/20 10 

Tennessee Valley Authority System-wide NOx Emission Caps in Tons: 100,600 in 2012, 90,791 in 2013, 86,842 in 2014, 83,042 in 2015, 70,667 in 2016, 64,951 in 2017, 52,000 in 2018 & onwards. System-wide SO2 Emission Caps in Tons: 285,00220,631 in 2015, 175,626 in 2016, 164,257 in 2017, 121,699 in 2018, 100,000 in 2019 & onwards.

Colbert Alabama Units 1- 4 FGD 6/30/201 6 SCR 6/30/201 6 

Shall surren

all calend

year NOx a

SO2 

Allowance

allocated 

TVA that a

not needed 

compliance 

its own CA

reqts. 

Allocate

allowances 

be used f

TVA’s ow

compliance 

CAA reqt

Unit 5 FGD 12/31/15 SCR Effective Date 

Widows Creek Alabama Units 1 - 6 Retire 2 units 7/31/13 Retire 2 units 7/31/14 Retire 2 units 7/31/15 

Unit 7 SCR Effective Date Unit 8 SCR Effective Date 

Paradise Kentucky Units 1 & 2 Upgrade FGD 93% 12/31/12 SCR Effective Date 

Unit 3 Wet FGD Effective Date SCR Effective Date 

Shawnee Kentucky Units 1 & 4 FGD 1.2 12/31/17 SCR 12/31/17 

Units 

5 - 10 1.2 Effective Date 

Allen Tennessee Units 1 - 3 FGD 12/31/18 0.3 12/31/18 

Bull Run Tennessee Unit 1 Wet FGD Effective Date 0.3 Effective Date 
40 

Cumberland Tennessee Units 1 & 2 Wet FGD Effective Date 

Gallatin Tennessee Units 1 - 4 FGD 12/31/17 SCR 12/31/17 0.3 12/31/17 

John Sevier Tennessee Units 1 & 2 Retire 2 Units 12/31/12 and 12/31/15 

Units 

3 & 4 FGD 12/31/15 SCR 12/31/15 

Johnsonville Tennessee Units 1 - 10 

Retire 6 Units 

12/31/15 

Retire 4 Units 

12/31/17 

Kingston Tennessee Units 1 - 9 FGD Effective Date SCR Effective Date 0.3 Effective Date 

Notes:1) Updates to the EPA Base Case 4.10 Final from EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the PSEG Fossil settlement, and an update to the SO2 emission modeling on Jeffrey Energy Center as part of the Westar settlement. 2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to bactual settlement agreements. 3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, constraints on emission rates in EPA Base Case, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire. 4) Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are alr5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those ac6) For units for which an FGD is modeled as an emissions constraint in EPA Base Case, EPA used the assumptions on removal efficiencies that are shown in the latest emission control technologies documentation 7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and a corresponding 95% removal e8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 lb/MMBtu or used 9) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case documentation materials. 10) EPA included in EPA Base Case the requirements of the settlements as they existed on January 1, 2011. 11) Some of the NSR settlements require the retirement of SO2 allowances. For Base Case, EPA estimates the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances acco
41 

Chapter 4. Generating Resources 

Table 4-13. Performance and Unit Cost Assumptions for Potential (New) Capacity from Conventional Technologies in E

Advanced 

Combined 

Cycle 

Advanced 

Combustion 

Turbine 

Nuclear 

Integrated 

Gasification 

Combined 

Cycle –

Bituminous 

Integrated 

Gasification 

Combined Cycle 

– Subbituminous 

Advanced 

Coal with 

Carbon 

CaptureBituminous1

Advanced Coal 

with Carbon 

Capture – 

Subbituminous1

Supe

Pulv

Coa

Bitu

Size (MW) 560 170 1350 600 600 500 500 

First Year 

Available 2015 2012 2017 2013 2013 2015 2015 2

Lead Time (Years) 3 2 6 4 4 4 4 

Vintage #1 

(years covered) 

2012 - 

2054 2012 - 2054 2012 - 2054 2012 - 2054 2012 - 2054 2012 - 2054 2015 - 2054 2012 

Availability 87% 92% 90% 85% 85% 85% 85% 8

Vintage #1 

Heat Rate 

(Btu/kWh) 6,810 10,720 10,400 8,424 8,062 10,149 9,713 8

Capital2

(2007$/kW) 976 698 4,621 5,000 3,265 3,310 4,720 4,785 2

Fixed O&M 

(2007$/kW/yr) 14.4 12.3 92.4 47.9 48.2 60.5 61.0 2

Variable O&M 

(2007$/MWh) 2.57 3.59 0.77 1.32 1.15 1.67 1.46 3

Notes:

1For The term “Advanced Coal with Carbon Capture” is used here and in the output files for EPA Base Case v.4.10_MATS 

of technologies that are expected to provide carbon capture capabilities. These include both supercritical steam generatorand integrated gasification combined cycle (IGCC) with carbon capture. Although IGCC with carbon capture was used to d

performance parameters that are implemented in EPA Base Case v.4.10_MATS, projections of “Advanced Coal with Carbo

Base Case v.4.10_MATS are not limited to this technology. 2Capital cost represents overnight capital cost. 
42 

Chapter 5: Emission Control Technologies 

● ● ●

5.2 Nitrogen Oxides Control Technology 

Table 5-7. Summary of Retrofit NOx Emission Control Performance Assumptions 

Control 

Performance 

Assumptions 

Selective Catalytic Reduction 

(SCR) 

Selective Non-Catalytic 

Reduction 

(SNCR) 

Unit Type Coal Oil/Gas Coal 

Percent Removal 90% down to 0.06 

lb/MMBtu 80% 

Pulverized Coal: 35%

25% with a NOx rate floor of 

0.1 lbs/MMBtu 

Fluidized Bed: 50% 

with a NOx rate floor of 

0.08lbs/MMBtu 

Size Applicability Units ≥ 25 MW Units ≥ 25 MW Units ≥ 25 MW 

Costs (2007$) See Table 5-8* Table 5-9* Table 5-8* 

* Tables in EPA Base Case v.4.10 (EPA #430-R-10-010), August 2010 at 

www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. 

● ● ●

5.4.3 Mercury Control Capabilities 

[Insert the following text at the end of section 5.4.3 as it appears in the Documentation Supplement for the 

Proposed Toxics Rule (March 2011)] 

Revisions to ACI VOM Cost in Base Case v.4.10_MATS: For coal units that have a FF embedded in LSD 

or DSI+FF retrofits, the variable operating and maintenance (VOM) cost of activated carbon injection 

(ACI) retrofits is assumed to be 81 percent lower due to the presence of pre-existing particulate controls. 

● ● ●

5.5.1 Chlorine Content of Fuels 

HCl emissions from the power sector result from the chlorine content of the coal that is combusted by 

electric generating units. Data on chlorine content of coals had been collected as part EPA’s 1999 

“Information Collection Request for Electric Utility Steam Generating Unit Mercury Emissions Information 

Collection Effort” (ICR 1999) described above in section 5.4.1 To provide the capability for EPA Base 

Case v4.10_MATS to account for HCl emissions, this data had to be incorporated into the model. The 

procedures used for this are presented in the updated text in section 9.1.3 below. 

To account for the effect of ash chemistry on HCl emissions, the HCl content of lignite and subbituminous 

coals is reduced by 75%. 

In the IPM modeling runs done in support of the proposed MATS, 100 % of the coal chlorine was 

assumed to convert to HCl and be present in the flue gas at the point of injection of the dry sorbent. This 

was the assumption for all coal ranks and types. After MATS proposal a team of EPA and DOE engineers 

and control technology specialists met regularly to further evaluate the application of DSI. One of the 

outcomes of that collaboration was recognition that western sub-bituminous coal (such as that mined in 
43 

the Powder River Basin) and lignites contain natural alkalinity in the form of non-glassy calcium oxide 

(CaO) and other alkaline and alkaline earth oxides. This fly ash (classified as ‘Class C’ fly ash) has a 

natural pH of 9 and higher and the natural alkalinity can effectively neutralize much of the HCl in the flue 

gas stream prior to the primary control device. 

Eastern bituminous coals, by contrast, tend to produce fly ash with lower natural alkalinity. Though 

bituminous fly ash (classified as ‘Class F’ fly ash) may contain calcium, it tends to be present in a glassy 

matrix and unavailable for acid-base neutralization reactions. 

In order to assess the extent of expected natural neutralization, the 2010 ICR data was examined. It was 

observed that some of the subbituminous coals contained chlorine levels in such low quantities that users 

should expect to meet the HCl emission limit with no additional controls. It was also noted that some 

other units burning subbituminous or lignite coals with higher levels of Cl were achieving 50-85 % HCl 

control with only cold-side ESP (i.e., with no flue gas desulfurization or other acid gas control technology). 

We examined the Cl content of the sub-bituminous coals that are modeled in IPM and compared those to 

the ICR results. From that analysis we believe that those coals can expect to achieve approximately 75 % 

natural HCl neutralization from the alkaline fly ash. 

 

● ● ●

5.5.3 HCl Retrofit Emission Control Options 

Table 5‐20 Summary of HCl Emission Control Technology

Assumptions in EPA Base Case v4.10_PTox  

(Proposed Toxics Rule)  

   

HCl Control Technology

Options Applicability

Limestone Forced Oxidation

(LSFO) Scrubber Base case and policy case

Lime Spray Dryer (LSD) Base case and policy case

Dry Sorbent Injection (DSI) Base case and policy case

Scrubber upgrade

adjustment

To existing coal steam units with

FGD in policy cases analyzed for

MATS Rulemaking

All the retrofit options for HCl emission control are summarized in Table 5-20. The scrubber upgrade 

adjustment was discussed above in 5.5.2. The other options are discussed in detail in the following 

sections. 

5.5.3.1 Wet and Dry FGD

In addition to providing SO2 reductions, wet scrubbers (Limestone Forced Oxidation, LSFO) and dry 

scrubbers (Lime Spray Dryer, LSD) reduce HCl as well. For both LSFO and LSD the HCl removal rate is 

assumed to be 99% with a floor of 0.0001 lbs/MMBtu. This is summarized in columns 2-5 of Table 5-21. 
44 

FGD Upgrade Assumptions in MATS Policy Case: In setting up the MATS policy case, all scrubbed unit 

that do not currently achieve an SO2 removal rate of 94% are assigned a capital cost of $100/kW (2009$) 

for an FGD upgrade that will improve their HCl removal rates to 99% and bring any unit whose SO2 

removal rate was below 90% up to 90%. 

Dry Scrubber Removal Assumptions for Waste Coal and Petroleum Coke Units in MATS Policy 

Case: In setting up the Base Case v.4.10_MATS, waste coal and petroleum coke units without an 

existing FGD were mistakenly not provided with a scrubber retrofit option. To make up for this oversight, 

in run year 2015 a dry scrubber and an associated capital cost of $748/kW (applied through and FOM 

adder) are assigned to these units when setting up the MATS policy case. (The $748/kW capital cost was 

calculated using the procedures described in section 5.1.1 and, illustrated in Appendix 5-1 for a 100 MW 

unit with an average heat rate of the waste coal units.) The removal rates obtained by the dry FGD ( 92% 

for SO2 and 99% for HCl) are incremental to existing FBC removals. In addition, petroleum coke units 

with dry FGD are assigned a mercury emission modification factor (EMF) of 0.07.] 

● ● ●

5.5.3.2 Dry Sorbent Injection 

[Insert the following text at the end of section 5.5.3.2 as it appears in the Documentation Supplement for 

the Proposed Toxics Rule (March 2011)] 

Revisions to DSI Cost and Performance Assumptions in Base Case v.4.10_MATS: The following 

additional assumptions were made with respect to DSI in the Base Case v.4.10_MATS 

(a) Since fabric filters are a pre-requisite for a DSI retrofit, the DSI retrofit VOM cost incurred by units 

with no pre-existing fabric filter is reduced by 35% to reflect the non-contamination of fly ash and 

the resulting savings in fly ash disposal costs from the forced installation of a fabric filter. 

(b) The cost of the pre-requisite fabric filter is implemented as adders to the FOM and capital cost of 

the DSI installation. 

● ● ●

5.5.4 Fabric Filter (Baghouse) Cost Development 

Fabric filters are not endogenously modeled as a separate retrofit option in EPA Base Case v4.10_PTox, 

but are accounted for as a cost adder where they are required for particulate matter (PM), mercury, or 

HCl emission control. In EPA Base Case v4.10_PTox, an existing or new fabric filter particulate control 

device is a pre-condition for installing a DSI retrofit. In the v4.10_PTox policy case any unit that was 

retrofit by the model with DSI and did not have an existing fabric filter incurred the cost of installing a 

fabric filter. This cost was added to the DSI costs discussed in section 5.5.3.2. This section describes 

the methodology used by Sargent & Lundy to derive the cost of a fabric filter. 

The engineering cost analysis is based on a pulse-jet fabric filter which collects particulate matter on a 

fabric bag and uses air pulses to dislodge the particulate from the bag surface and collect it in hoppers for 

removal via an ash handling system to a silo. This is a mature technology that has been operating 

commercially for more than 25 years. “Baghouse” and “fabric filters” are used interchangeably to refer to 

such installations. 

Capital Cost: Two governing variables are used to derive the bare module capital cost of a fabric filter. 

The first of these is the “air-to-cloth” (A/C) ratio. The major driver of fabric filter capital cost, the A/C ratio 

is defined as the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, ACFM) of flue gas 

entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth in the baghouse. 

The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater the area of the cloth required 

and the higher the cost for a given volumetric flow. 
45 

Note: Based on public comments and engineering assessments, an air-to-cloth ratio or 4.0, rather than 

6.0, was used in modeling for MATS to provide a conservative projection of the requirements and cost of 

sorbent removal. 

The other determinant of capital cost is the flue gas volumetric flow rate (in ACFM) which is a function of 

the type of coal burned and the unit’s size and heat rate. 

● ● ●

5.6 Filterable Particulate Matter (PM) Compliance 

When the MATS policy case is modeled off the v.4.10_MATS Base Case, it is assumed that all coal 

burning generating units with a capacity of 25 MW or greater will comply with the filterable PM 

requirements through the operation of either electrostatic precipitator (ESP) or fabric filter (FF) particulate 

controls. The decision of whether an upgrade of existing controls will be needed to meet the requirement 

is not modeled endogenously but supplied as an input when setting up the run. 

Units with existing fabric filters are assumed to be able to meet the filterable PM compliance requirement. 

For units with existing ESPs the following procedure is used to determine if they already meet the 

filterable PM requirement, can meet it by one of three possible ESP upgrades, or can only meet it by 

installing a FF. 

First, PM emission rate data derived either from 2005 EIA Form 767 or (where available) from EPA’s 

2010 Information Collection Request5 are compared to the applicable filterable PM compliance 

requirement. If the unit’s emission rate is equal to or less than the compliance requirement, adequate 

controls are assumed already to be in place and no additional upgrade costs are imposed. For units that 

do not meet the filterable PM compliance requirement, the incremental reduction needed (in lbs/mmBtu) 

is calculated by subtracting the filterable PM compliance standard from the reported emission rate. 

Depending on the magnitude of the incremental reduction needed, the unit is assigned one of three ESP 

upgrade costs (designated ESP1, ESP2, and ESP3) or the cost of a FF installation (designated ESP4), if 

the required incremental reduction cannot be achieved by an ESP upgrade. Table 5-25 shows the four 

levels of ESP upgrades (column 1), the key technologies included in each upgrade (column 2), trigger 

points for the upgrades (column 3), the capital cost of each upgrade (column 4), and the percent increase 

in collection efficiency provided by the upgrade, differentiated according to the rank (subbituminous, 

bituminous, or lignite) of coal burned. 

When setting up a model run, the capital costs for the ESP upgrades that are shown in Table 5-25 are 

converted into annual fixed operating and maintenance (FOM) charges which are added to the other 

FOM costs incurred by a particular generating unit. To obtain the FOM adder for the ESP upgrades, the 

values shown in Table 5-25 are multiplied by 11.3%, the capital charge rate for environmental retrofits. 

(For a discussion of all the capital charge rates in the model runs built upon the EPA base case 

v.4.10_MATS, see Chapter 8 (“Financial Assumptions”) in Documentation for EPA Base Case 

v.4.10_MATS Using the Integrated Planning Model, August 2010, EPA #430-R-10-010.) To prevent 

double counting of PM control costs, the FOM adder described here is removed if a represented 

generating unit had previously had an ESP4 fabric filter upgrade, or if, in the course of a model run, was 

retrofit with dry flue gas desulfurization (FGD), DSI, or ACI plus TOXECON --- each of which includes 

particulate controls in its capital cost. 

The percentage improvements in collection efficiency shown in column 5 in Table 5-25 are additive in the 

sense that the values shown in this column are added to the pre-upgrade collection efficiency to obtain 

the after-upgrade collection efficiency. 

 

5  2005 EIA Form 767 is the last year where the data was reported in the format of lb/MMBtu, which is compatible

with this analysis.  Since any changes to facilities since 2005 would likely have improved (reduced) emissions, the

use of this data is conservative.  More recent 2010 ICR test data is used where available.
46 

Table 5-25. Electrostatic Precipitator (ESP) Upgrades as Implemented in EPA Base Case for MATS --- Characteris

Associated Costs, and Performance Improvements Upgrade Level 

Key Technologies Employed in Upgrade 

Trigger Points for ESP Upgrade (Expressed in terms of incremental reduction needed (lbs/mmBtu) to meet the filterable PM Compliance Standard) Capital Cost 

Additive Perc

Collection Eff

the Upgrade 

rank of 

1 High Frequency transformer-rectifier (TR) sets > 0.0 to ≤ 0.005 $55/kW1 0.12 for subbitu

0.05 for bitumin0.01 for lignite 

2 

High frequency transformer-rectifier (TR) sets  + New internals (rigid electrodes, increased plate spacing, increased plate height) 

> 0.005 to ≤ 0.01 $80/kW2

0.25 for subbitu0.10 for bitumin0.02 for lignite 

3 

High frequency transformer-rectifier (TR) sets  + New internals (rigid electrodes, increased plate spacing, increased plate height)  + Additional field 

> 0.01 to ≤ 0.02 $100/kW3

0.50 for subbitu0.20 for bitumin0.05 for lignite 

4 Replacement with fabric filter (baghouse) > 0.02 Use capital cost equations for a fabric filter4 (No

1Assumes upgrading the specific collection area (SCA) to 250 square-feet/1000 afm (actual feet per minute). 2Assumes upgrading the specific collection area (SCA) to 300 square-feet/1000 afm (actual feet per minute). 3Assumes upgrading the existing specific collection area (SCA) by 100 square-feet/1000 afm (actual feet per minute), a 20

additional field. 

4The cost equations for fabric filters are described in Section 5.5.4 ("Fabric Filter (Baghouse) Cost Development") with cal

Tables 1 and 2 in Appendix 5-5 ("Example Cost Calculation Worksheets for Fabric Filters") in Documentation Supplement 

v4.10_PTox − Updates for Proposed Toxics Rule (EPA # 430-R-11-006). This documentation supplement is available on 

ww.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf. 

5The percentage improvement due to the ESP upgrade as shown in this column is added to the pre-upgrade collection eff

after-upgrade collection removal efficiency. 
47 

Appendix 5-6 contains a complete listing of coal generating units with either cold- or hot-side ESPs but no 

fabric filters. For each generating unit the table in Appendix 5-6 shows the incremental reductions 

needed to meet the PM filterable compliance requirement and the corresponding ESP upgrade (if any) 

assigned to the unit to enable it to meet that requirement. A filterable PM limit of 0.279 lb/mmBtu was 

used in this analysis. This value is roughly 10% below the limit in the final MATS rule, therefore resulting 

in a conservative estimate of the need to upgrade existing ESPs
48 

Appendix 5-6. ESP Upgrade Provided to Existing Units without Fabric Filters so that They Meet Their Filterable PM 

Plant Name Unit ID State Name UniqueID 

Capacit

y (MW) 

OnLineYe

ar Firing 

Botto

m 

Dry 

Scrubb

er 

Installe

d 

Current 

Filterable 

PM 

Emission 

(lbs/MMBt

u) 

Filterable 

PM Limit 

(lbs/MMBt

u) 

Com

ce w

th

Filter

PM L

A B Brown 2 Indiana 6137_B_2 245 1986 wall dry 0 0.0100 0.0279 YeAES Beaver Valley Partners Beaver Valley 2 

Pennsylvania 10676_B_2 43 1943 wall dry 0 0.0500 0.0279 N

AES Beaver Valley Partners Beaver Valley 3 

Pennsylvania 10676_B_3 43 1943 wall dry 0 0.0700 0.0279 N

AES Beaver Valley Partners Beaver Valley 4 

Pennsylvania 10676_B_4 43 1943 wall dry 0 0.0300 0.0279 N

AES Cayuga 1 New York 2535_B_1 150 1955 tangential dry 0 0.0200 0.0279 YeAES Cayuga 2 New York 2535_B_2 151 1958 tangential dry 0 0.0200 0.0279 YeAES Deepwater 

AAB001 Texas 

10670_B_AAB0

01 139 1986 vertical dry 0 0.0100 0.0279 Ye

AES Somerset LLC 1 New York 6082_B_1 681 1984 wall dry 0 0.0200 0.0279 YeAlbright 1 

West Virginia 3942_B_1 73 1952 wall dry 0 0.0696 0.0279 N

Albright 2 

West Virginia 3942_B_2 73 1952 wall dry 0 0.0100 0.0279 Ye

Albright 3 

West Virginia 3942_B_3 137 1954 tangential dry 0 0.0500 0.0279 N

Allen Steam Plant 1 Tennessee 3393_B_1 245 1959 cyclone wet 0 0.0100 0.0279 YeAllen Steam Plant 2 Tennessee 3393_B_2 245 1959 cyclone wet 0 0.0200 0.0279 YeAllen Steam Plant 3 Tennessee 3393_B_3 245 1959 cyclone wet 0 0.0100 0.0279 YeAlloy Steam Station BLR4 

West Virginia 50012_B_BLR4 38 1950 wall dry 0 0.0400 0.0279 N

Alma B4 Wisconsin 4140_B_B4 51 1957 wall dry 0 0.0200 0.0279 YeAlma B5 Wisconsin 4140_B_B5 77 1960 wall dry 0 0.0900 0.0279 NAmes Electric Services Power Plant 7 Iowa 1122_B_7 33 1968 tangential dry 0 0.0200 0.0279 YeAmes Electric Services Power Plant 8 Iowa 1122_B_8 70 1982 wall dry 0 0.0200 0.0279 YeApache Station 2 Arizona 160_B_2 175 1979 wall dry 0 0.0100 0.0279 YeApache Station 3 Arizona 160_B_3 175 1979 wall dry 0 0.0100 0.0279 Ye
49 

Armstrong Power Station 1 

Pennsylvania 3178_B_1 172 1958 wall dry 0 0.0400 0.0279 N

Armstrong Power Station 2 

Pennsylvania 3178_B_2 171 1959 wall dry 0 0.0100 0.0279 Ye

Asbury 1 Missouri 2076_B_1 213 1970 cyclone wet 0 0.1300 0.0279 NAsheville 1 

North Carolina 2706_B_1 191 1964 wall dry 0 0.0030 0.0279 Ye

Asheville 2 

North Carolina 2706_B_2 185 1971 wall dry 0 0.0036 0.0279 Ye

Ashtabula 7 Ohio 2835_B_7 244 1958 tangential dry 0 0.0100 0.0279 YeAustin Northeast NEPP Minnesota 1961_B_NEPP 29 1971 wall dry 0 0.0300 0.0279 NAvon Lake 10 Ohio 2836_B_10 93 1949 tangential dry 0 0.0100 0.0279 YeAvon Lake 12 Ohio 2836_B_12 616 1970 wall dry 0 0.0200 0.0279 YeB C Cobb 4 Michigan 1695_B_4 156 1956 tangential dry 0 0.1000 0.0279 NB C Cobb 5 Michigan 1695_B_5 156 1957 tangential dry 0 0.0620 0.0279 NB L England 1 New Jersey 2378_B_1 126 1962 cyclone wet 0 0.0300 0.0279 NB L England 2 New Jersey 2378_B_2 152 1964 cyclone wet 0 0.0300 0.0279 NBailly 7 Indiana 995_B_7 160 1962 cyclone wet 0 0.0300 0.0279 NBailly 8 Indiana 995_B_8 320 1968 cyclone wet 0 0.0300 0.0279 NBarry 1 Alabama 3_B_1 138 1954 tangential dry 0 0.0300 0.0279 NBarry 2 Alabama 3_B_2 137 1954 tangential dry 0 0.0400 0.0279 NBarry 3 Alabama 3_B_3 249 1959 tangential dry 0 0.0200 0.0279 YeBarry 4 Alabama 3_B_4 362 1969 tangential dry 0 0.0200 0.0279 YeBarry 5 Alabama 3_B_5 740 1971 tangential dry 0 0.0200 0.0279 YeBay Shore 2 Ohio 2878_B_2 138 1959 vertical wet 0 0.3200 0.0279 NBay Shore 3 Ohio 2878_B_3 142 1963 wall dry 0 0.3200 0.0279 NBay Shore 4 Ohio 2878_B_4 215 1968 wall dry 0 0.3200 0.0279 NBelews Creek 1 

North Carolina 8042_B_1 1115 1974 cell dry 0 0.0500 0.0279 N

Belews Creek 2 

North Carolina 8042_B_2 1115 1975 cell dry 0 0.0200 0.0279 Ye

Belle River 1 Michigan 6034_B_1 698 1984 wall dry 0 0.0300 0.0279 N
50 

Belle River 2 Michigan 6034_B_2 698 1985 wall dry 0 0.0100 0.0279 YeBig Bend BB01 Florida 645_B_BB01 391 1970 wall wet 0 0.0300 0.0279 NBig Bend BB02 Florida 645_B_BB02 391 1973 wall wet 0 0.0200 0.0279 YeBig Bend BB03 Florida 645_B_BB03 364 1976 wall wet 0 0.0200 0.0279 YeBig Bend BB04 Florida 645_B_BB04 447 1985 tangential dry 0 0.0100 0.0279 YeBig Cajun 2 2B1 Louisiana 6055_B_2B1 580 1981 wall dry 0 0.0200 0.0279 YeBig Cajun 2 2B2 Louisiana 6055_B_2B2 575 1982 wall dry 0 0.0200 0.0279 YeBig Cajun 2 2B3 Louisiana 6055_B_2B3 588 1983 wall dry 0 0.0200 0.0279 YeBig Sandy BSU1 Kentucky 1353_B_BSU1 259 1963 wall dry 0 0.0300 0.0279 NBig Sandy BSU2 Kentucky 1353_B_BSU2 789 1969 wall dry 0 0.0300 0.0279 NBlack Dog 3 Minnesota 1904_B_3 94 1955 wall dry 0 0.0400 0.0279 NBlack Dog 4 Minnesota 1904_B_4 165 1960 wall dry 0 0.0400 0.0279 NBlount Street 8 Wisconsin 3992_B_8 49 1957 wall dry 0 0.1200 0.0279 NBlount Street 9 Wisconsin 3992_B_9 48 1961 wall dry 0 0.0900 0.0279 NBlue Valley 3 Missouri 2132_B_3 51 1965 tangential dry 0 0.0300 0.0279 NBoardman 1SG Oregon 6106_B_1SG 585 1980 wall dry 0 0.0100 0.0279 YeBowen 1BLR Georgia 703_B_1BLR 713 1971 tangential dry 0 0.0800 0.0279 NBowen 2BLR Georgia 703_B_2BLR 718 1972 tangential dry 0 0.0800 0.0279 NBowen 3BLR Georgia 703_B_3BLR 902 1974 tangential dry 0 0.0500 0.0279 NBowen 4BLR Georgia 703_B_4BLR 929 1975 tangential dry 0 0.0500 0.0279 NBrayton Point 3 

Massachusetts 1619_B_3 607 1969 wall dry 0 0.0100 0.0279 Ye

Bremo Bluff 3 Virginia 3796_B_3 71 1950 wall dry 0 0.0200 0.0279 YeBremo Bluff 4 Virginia 3796_B_4 156 1958 wall dry 0 0.0200 0.0279 YeBruce Mansfield 3 

Pennsylvania 6094_B_3 830 1979 wall dry 0 0.0800 0.0279 N

Buck 5 

North Carolina 2720_B_5 38 1941 tangential dry 0 0.0400 0.0279 N

Buck 6 

North Carolina 2720_B_6 38 1941 tangential dry 0 0.0200 0.0279 Ye
51 

Buck 7 

North Carolina 2720_B_7 38 1942 tangential dry 0 0.0300 0.0279 N

Buck 8 

North Carolina 2720_B_8 128 1953 tangential dry 0 0.0200 0.0279 Ye

Buck 9 

North Carolina 2720_B_9 128 1953 tangential dry 0 0.0300 0.0279 N

Bull Run 1 Tennessee 3396_B_1 881 1967 tangential dry 0 0.0100 0.0279 YeBurlington 1 Iowa 1104_B_1 209 1968 tangential dry 0 0.1000 0.0279 NC D McIntosh Jr 3 Florida 676_B_3 340 1982 wall dry 0 0.0736 0.0279 NCanadys Steam CAN1 

South Carolina 3280_B_CAN1 105 1962 tangential dry 0 0.2600 0.0279 N

Canadys Steam CAN2 

South Carolina 3280_B_CAN2 116 1964 tangential dry 0 0.0140 0.0279 Ye

Cane Run 4 Kentucky 1363_B_4 155 1962 wall dry 0 0.0257 0.0279 YeCane Run 5 Kentucky 1363_B_5 168 1966 wall dry 0 0.0113 0.0279 YeCane Run 6 Kentucky 1363_B_6 240 1969 tangential dry 0 0.0700 0.0279 NCape Fear 5 

North Carolina 2708_B_5 144 1956 tangential dry 1 0.0700 0.0279 N

Cape Fear 6 

North Carolina 2708_B_6 172 1958 tangential dry 0 0.0600 0.0279 N

Carbon 1 Utah 3644_B_1 67 1954 tangential dry 0 0.0200 0.0279 YeCarbon 2 Utah 3644_B_2 105 1957 tangential dry 0 0.0600 0.0279 NCardinal 1 Ohio 2828_B_1 600 1967 cell dry 0 0.0114 0.0279 YeCardinal 2 Ohio 2828_B_2 600 1967 cell dry 0 0.0114 0.0279 YeCardinal 3 Ohio 2828_B_3 621 1977 wall dry 0 0.0114 0.0279 YeCayuga 1 Indiana 1001_B_1 479 1970 tangential dry 0 0.0700 0.0279 NCayuga 2 Indiana 1001_B_2 466 1972 tangential dry 0 0.0700 0.0279 NChalk Point LLC 1 Maryland 1571_B_1 341 1964 wall dry 0 0.0200 0.0279 YeChalk Point LLC 2 Maryland 1571_B_2 342 1965 wall dry 0 0.0200 0.0279 YeChamois 2 Missouri 2169_B_2 49 1960 cyclone wet 0 0.0900 0.0279 NCharles R Lowman 1 Alabama 56_B_1 85 1969 wall dry 0 0.0100 0.0279 YeCharles R Lowman 2 Alabama 56_B_2 238 1979 wall dry 0 0.0300 0.0279 NCharles R Lowman 3 Alabama 56_B_3 238 1980 wall dry 0 0.0300 0.0279 N
52 

Chesapeake 1 Virginia 3803_B_1 111 1953 tangential dry 0 0.0100 0.0279 YeChesapeake 2 Virginia 3803_B_2 111 1954 tangential dry 0 0.0100 0.0279 YeChesapeake 3 Virginia 3803_B_3 155 1959 wall dry 0 0.0300 0.0279 NChesapeake 4 Virginia 3803_B_4 216 1962 tangential dry 0 0.0100 0.0279 YeChesterfield 3 Virginia 3797_B_3 98 1952 tangential dry 0 0.0300 0.0279 NChesterfield 4 Virginia 3797_B_4 164 1960 tangential dry 0 0.0200 0.0279 YeChesterfield 5 Virginia 3797_B_5 310 1964 tangential dry 0 0.0300 0.0279 NCliffside 5 

North Carolina 2721_B_5 550 1972 tangential dry 0 0.0200 0.0279 Ye

Cliffside 6 

North Carolina 2721_B_6 800 2011 tangential dry 0 0.0300 0.0279 N

Clifty Creek 1 Indiana 983_B_1 214 1955 wall wet 0 0.0100 0.0279 YeClifty Creek 2 Indiana 983_B_2 214 1955 wall wet 0 0.0100 0.0279 YeClifty Creek 3 Indiana 983_B_3 214 1955 wall wet 0 0.0100 0.0279 YeClifty Creek 4 Indiana 983_B_4 214 1955 wall wet 0 0.0500 0.0279 NClifty Creek 5 Indiana 983_B_5 214 1955 wall wet 0 0.0500 0.0279 NClifty Creek 6 Indiana 983_B_6 214 1956 wall wet 0 0.0500 0.0279 NClinch River 1 Virginia 3775_B_1 234 1958 vertical dry 0 0.0531 0.0279 NClinch River 2 Virginia 3775_B_2 234 1958 vertical dry 0 0.0300 0.0279 NClinch River 3 Virginia 3775_B_3 234 1961 vertical dry 0 0.0300 0.0279 NCoal Creek 1 

North Dakota 6030_B_1 554 1979 tangential dry 0 0.0047 0.0279 Ye

Coal Creek 2 

North Dakota 6030_B_2 560 1981 tangential dry 0 0.0035 0.0279 Ye

Coffeen 01 Illinois 861_B_01 335 1965 cyclone wet 0 0.0600 0.0279 NCoffeen 02 Illinois 861_B_02 551 1972 cyclone wet 0 0.0600 0.0279 NColbert 1 Alabama 47_B_1 177 1955 wall dry 0 0.0100 0.0279 YeColbert 2 Alabama 47_B_2 177 1955 wall dry 0 0.0500 0.0279 NColbert 3 Alabama 47_B_3 177 1955 wall dry 0 0.0114 0.0279 YeColbert 4 Alabama 47_B_4 173 1955 wall dry 0 0.0240 0.0279 Ye
53 

Colbert 5 Alabama 47_B_5 459 1965 wall dry 0 0.0200 0.0279 YeColumbia 1 Wisconsin 8023_B_1 546 1975 tangential dry 0 0.0400 0.0279 NColumbia 2 Wisconsin 8023_B_2 551 1978 tangential dry 0 0.0300 0.0279 NConemaugh 1 

Pennsylvania 3118_B_1 850 1970 tangential dry 0 0.0100 0.0279 Ye

Conemaugh 2 

Pennsylvania 3118_B_2 850 1971 tangential dry 0 0.0200 0.0279 Ye

Conesville 3 Ohio 2840_B_3 165 1962 wall dry 0 0.0491 0.0279 NConesville 4 Ohio 2840_B_4 780 1973 tangential dry 0 0.0300 0.0279 NConesville 5 Ohio 2840_B_5 375 1976 tangential dry 0 0.0300 0.0279 NConesville 6 Ohio 2840_B_6 375 1978 tangential dry 0 0.0300 0.0279 NCooper 1 Kentucky 1384_B_1 116 1965 wall dry 0 0.1700 0.0279 NCooper 2 Kentucky 1384_B_2 221 1969 wall dry 0 0.1700 0.0279 NCoronado U1B Arizona 6177_B_U1B 395 1979 wall dry 0 0.0100 0.0279 YeCoronado U2B Arizona 6177_B_U2B 388 1980 wall dry 0 0.0100 0.0279 YeCrawford 7 Illinois 867_B_7 212 1958 tangential dry 0 0.0570 0.0279 NCrawford 8 Illinois 867_B_8 318 1961 tangential dry 0 0.0560 0.0279 NCrist 4 Florida 641_B_4 78 1959 tangential dry 0 0.0100 0.0279 YeCrist 5 Florida 641_B_5 78 1961 tangential dry 0 0.0100 0.0279 YeCrist 6 Florida 641_B_6 300 1970 wall dry 0 0.0100 0.0279 YeCrist 7 Florida 641_B_7 472 1973 wall dry 0 0.0100 0.0279 YeCross 1 

South Carolina 130_B_1 620 1995 wall dry 0 0.0140 0.0279 Ye

Cross 2 

South Carolina 130_B_2 540 1984 tangential dry 0 0.0160 0.0279 Ye

Cross 3 

South Carolina 130_B_3 580 2007 wall dry 0 0.0300 0.0279 N

Cross 4 

South Carolina 130_B_4 600 2009 wall dry 0 0.0300 0.0279 N

Crystal River 1 Florida 628_B_1 379 1966 tangential dry 0 0.1470 0.0279 NCrystal River 2 Florida 628_B_2 491 1969 tangential dry 0 0.0100 0.0279 YeCrystal River 4 Florida 628_B_4 718 1982 wall dry 0 0.1000 0.0279 N
54 

Crystal River 5 Florida 628_B_5 717 1984 wall dry 0 0.0200 0.0279 YeCumberland 1 Tennessee 3399_B_1 1232 1973 cell dry 0 0.0100 0.0279 YeCumberland 2 Tennessee 3399_B_2 1233 1973 cell dry 0 0.0100 0.0279 YeD B Wilson W1 Kentucky 6823_B_W1 420 1986 wall dry 0 0.0100 0.0279 YeDale 1 Kentucky 1385_B_1 27 1954 wall dry 0 0.0700 0.0279 NDale 2 Kentucky 1385_B_2 27 1954 wall dry 0 0.0700 0.0279 NDale 3 Kentucky 1385_B_3 75 1957 wall dry 0 0.1300 0.0279 NDale 4 Kentucky 1385_B_4 75 1960 wall dry 0 0.1300 0.0279 NDallman 31 Illinois 963_B_31 86 1968 cyclone wet 0 0.0200 0.0279 YeDallman 32 Illinois 963_B_32 87 1972 cyclone wet 0 0.0200 0.0279 YeDallman 33 Illinois 963_B_33 199 1978 tangential wet 0 0.1000 0.0279 NDan E Karn 1 Michigan 1702_B_1 255 1959 tangential dry 0 0.0100 0.0279 YeDan E Karn 2 Michigan 1702_B_2 260 1961 wall dry 0 0.0400 0.0279 NDanskammer Generating Station 3 New York 2480_B_3 133 1987 tangential dry 0 0.0200 0.0279 YeDanskammer Generating Station 4 New York 2480_B_4 236 1987 tangential dry 0 0.0200 0.0279 YeDave Johnston BW41 Wyoming 4158_B_BW41 106 1959 wall dry 0 0.0500 0.0279 NDave Johnston BW42 Wyoming 4158_B_BW42 106 1961 wall dry 0 0.0100 0.0279 YeDolet Hills 1 Louisiana 51_B_1 650 1986 wall dry 0 0.0300 0.0279 NDolphus M Grainger 1 

South Carolina 3317_B_1 85 1966 wall dry 0 0.3600 0.0279 N

Dolphus M Grainger 2 

South Carolina 3317_B_2 85 1966 wall dry 0 0.1300 0.0279 N

Dubuque 1 Iowa 1046_B_1 35 1959 wall dry 0 0.0500 0.0279 NDubuque 5 Iowa 1046_B_5 30 1952 wall dry 0 0.0500 0.0279 NDuck Creek 1 Illinois 6016_B_1 335 1976 wall dry 0 0.0033 0.0279 YeE C Gaston 1 Alabama 26_B_1 254 1960 wall dry 0 0.0100 0.0279 YeE C Gaston 4 Alabama 26_B_4 256 1962 wall dry 0 0.0200 0.0279 YeE C Gaston 5 Alabama 26_B_5 849 1974 tangential dry 0 0.0300 0.0279 N
55 

E D Edwards 1 Illinois 856_B_1 112 1960 wall dry 0 0.1300 0.0279 NE D Edwards 2 Illinois 856_B_2 273 1968 wall dry 0 0.0700 0.0279 NE D Edwards 3 Illinois 856_B_3 364 1972 wall dry 0 0.0400 0.0279 NE W Brown 1 Kentucky 1355_B_1 92 1957 wall dry 0 0.1400 0.0279 NE W Brown 2 Kentucky 1355_B_2 158 1963 tangential dry 0 0.0200 0.0279 YeE W Brown 3 Kentucky 1355_B_3 420 1971 tangential dry 0 0.0200 0.0279 YeEagle Valley 3 Indiana 991_B_3 43 1951 tangential wet 0 0.0500 0.0279 NEagle Valley 4 Indiana 991_B_4 56 1953 tangential dry 0 0.0500 0.0279 NEagle Valley 5 Indiana 991_B_5 62 1953 tangential dry 0 0.0800 0.0279 NEagle Valley 6 Indiana 991_B_6 99 1956 tangential dry 0 0.0800 0.0279 NEarl F Wisdom 1 Iowa 1217_B_1 38 1960 wall dry 0 0.0200 0.0279 YeEast Bend 2 Kentucky 6018_B_2 600 1981 wall dry 0 0.0087 0.0279 YeEastlake 1 Ohio 2837_B_1 132 1953 tangential dry 0 0.0057 0.0279 YeEastlake 2 Ohio 2837_B_2 132 1953 tangential dry 0 0.0100 0.0279 YeEastlake 3 Ohio 2837_B_3 132 1954 tangential dry 0 0.0056 0.0279 YeEastlake 4 Ohio 2837_B_4 240 1956 tangential dry 0 0.0200 0.0279 YeEastlake 5 Ohio 2837_B_5 597 1972 wall dry 0 0.0200 0.0279 YeEckert Station 1 Michigan 1831_B_1 40 1954 wall dry 0 0.1000 0.0279 NEckert Station 2 Michigan 1831_B_2 42 1958 tangential dry 0 0.0300 0.0279 NEckert Station 3 Michigan 1831_B_3 41 1961 tangential dry 0 0.1400 0.0279 NEckert Station 4 Michigan 1831_B_4 69 1964 wall dry 0 0.0400 0.0279 NEckert Station 5 Michigan 1831_B_5 69 1968 wall dry 0 0.0400 0.0279 NEckert Station 6 Michigan 1831_B_6 67 1970 wall dry 0 0.0400 0.0279 NEdge Moor 3 Delaware 593_B_3 86 1957 tangential dry 1 0.0500 0.0279 NEdge Moor 4 Delaware 593_B_4 174 1966 tangential dry 1 0.0500 0.0279 NEdgewater 3 Wisconsin 4050_B_3 76 1951 cyclone wet 0 0.0500 0.0279 NEdgewater 4 Wisconsin 4050_B_4 321 1969 cyclone wet 0 0.0400 0.0279 N
56 

Edgewater 5 Wisconsin 4050_B_5 412 1985 wall dry 0 0.0300 0.0279 NElmer Smith 1 Kentucky 1374_B_1 130 1964 cyclone wet 0 0.0147 0.0279 YeElmer Smith 2 Kentucky 1374_B_2 257 1974 tangential dry 0 0.0147 0.0279 YeElrama 1 

Pennsylvania 3098_B_1 93 1952 vertical dry 0 0.0184 0.0279 Ye

Elrama 2 

Pennsylvania 3098_B_2 93 1953 vertical dry 0 0.0184 0.0279 Ye

Elrama 3 

Pennsylvania 3098_B_3 103 1952 vertical dry 0 0.0184 0.0279 Ye

Elrama 4 

Pennsylvania 3098_B_4 171 1952 wall dry 0 0.0184 0.0279 Ye

Endicott Station 1 Michigan 4259_B_1 55 1982 wall dry 0 1.7300 0.0279 NErickson Station 1 Michigan 1832_B_1 152 1973 wall dry 0 0.0100 0.0279 YeFair Station 2 Iowa 1218_B_2 41 1967 wall dry 0 0.0300 0.0279 NFayette Power Project 1 Texas 6179_B_1 590 1979 tangential dry 0 0.0300 0.0279 NFayette Power Project 2 Texas 6179_B_2 590 1980 tangential dry 0 0.0300 0.0279 NFayette Power Project 3 Texas 6179_B_3 445 1988 tangential dry 0 0.0300 0.0279 NFisk Street 19 Illinois 886_B_19 325 1959 tangential dry 0 0.0780 0.0279 NFlint Creek 1 Arkansas 6138_B_1 528 1978 wall dry 0 0.0300 0.0279 NFort Martin Power Station 1 

West Virginia 3943_B_1 545 1967 tangential dry 0 0.0500 0.0279 N

Fort Martin Power Station 2 

West Virginia 3943_B_2 547 1968 wall dry 0 0.0500 0.0279 N

Frank E Ratts 1SG1 Indiana 1043_B_1SG1 122 1970 wall dry 0 0.3400 0.0279 NFrank E Ratts 2SG1 Indiana 1043_B_2SG1 121 1970 wall dry 0 0.3000 0.0279 NG F Weaton Power Station BLR1 

Pennsylvania 50130_B_BLR1 56 1957 tangential dry 0 0.0200 0.0279 Ye

G F Weaton Power Station BLR2 

Pennsylvania 50130_B_BLR2 56 1957 tangential dry 0 0.0100 0.0279 Ye

G G Allen 1 

North Carolina 2718_B_1 162 1957 tangential dry 0 0.0400 0.0279 N

G G Allen 2 

North Carolina 2718_B_2 162 1957 tangential dry 0 0.1400 0.0279 N

G G Allen 3 

North Carolina 2718_B_3 260 1959 tangential dry 0 0.0041 0.0279 Ye

G G Allen 4 

North Carolina 2718_B_4 275 1960 tangential dry 0 0.0041 0.0279 Ye
57 

G G Allen 5 

North Carolina 2718_B_5 265 1961 tangential dry 0 0.0400 0.0279 N

Gadsden 1 Alabama 7_B_1 64 1949 tangential dry 0 0.0300 0.0279 NGadsden 2 Alabama 7_B_2 66 1949 tangential dry 0 0.0400 0.0279 NGallatin 1 Tennessee 3403_B_1 222 1956 tangential dry 0 0.0100 0.0279 YeGallatin 2 Tennessee 3403_B_2 222 1957 tangential dry 0 0.0393 0.0279 NGallatin 3 Tennessee 3403_B_3 260 1959 tangential dry 0 0.0100 0.0279 YeGallatin 4 Tennessee 3403_B_4 260 1959 tangential dry 0 0.0100 0.0279 YeGeneral James M Gavin 1 Ohio 8102_B_1 1310 1974 cell dry 0 0.0300 0.0279 NGeneral James M Gavin 2 Ohio 8102_B_2 1300 1975 cell dry 0 0.0300 0.0279 NGeorge Neal North 1 Iowa 1091_B_1 135 1964 cyclone wet 0 0.1700 0.0279 NGeorge Neal North 2 Iowa 1091_B_2 300 1972 wall dry 0 0.2300 0.0279 NGeorge Neal North 3 Iowa 1091_B_3 515 1975 wall dry 0 0.0300 0.0279 NGeorge Neal South 4 Iowa 7343_B_4 632 1979 wall dry 0 0.0300 0.0279 NGhent 1 Kentucky 1356_B_1 468 1973 tangential dry 0 0.0600 0.0279 NGhent 2 Kentucky 1356_B_2 463 1977 tangential dry 0 0.0700 0.0279 NGhent 3 Kentucky 1356_B_3 472 1981 wall dry 0 0.0300 0.0279 NGhent 4 Kentucky 1356_B_4 472 1984 wall dry 0 0.0200 0.0279 YeGibbons Creek 1 Texas 6136_B_1 462 1983 tangential dry 0 0.3000 0.0279 NGibson 1 Indiana 6113_B_1 621 1975 wall dry 0 0.0067 0.0279 YeGibson 2 Indiana 6113_B_2 619 1975 wall dry 0 0.0038 0.0279 YeGibson 3 Indiana 6113_B_3 619 1978 wall dry 0 0.0400 0.0279 NGibson 4 Indiana 6113_B_4 622 1979 wall dry 0 0.0500 0.0279 NGibson 5 Indiana 6113_B_5 620 1982 wall dry 0 0.0900 0.0279 NGlen Lyn 51 Virginia 3776_B_51 45 1944 tangential dry 0 0.0300 0.0279 NGlen Lyn 52 Virginia 3776_B_52 45 1944 tangential dry 0 0.0300 0.0279 NGlen Lyn 6 Virginia 3776_B_6 235 1957 wall dry 0 0.0300 0.0279 NGorgas 10 Alabama 8_B_10 681 1972 tangential dry 0 0.0200 0.0279 Ye
58 

Gorgas 6 Alabama 8_B_6 108 1951 wall dry 0 0.0600 0.0279 NGorgas 7 Alabama 8_B_7 109 1952 wall dry 0 0.0300 0.0279 NGorgas 8 Alabama 8_B_8 163 1956 tangential dry 0 0.0100 0.0279 YeGorgas 9 Alabama 8_B_9 173 1958 tangential dry 0 0.0200 0.0279 YeGRDA 1 Oklahoma 165_B_1 490 1982 wall dry 0 0.0400 0.0279 NGRDA 2 Oklahoma 165_B_2 520 1986 wall dry 1 0.0200 0.0279 YeGreen River 4 Kentucky 1357_B_4 68 1954 wall dry 0 0.0900 0.0279 NGreen River 5 Kentucky 1357_B_5 95 1959 wall dry 0 0.0600 0.0279 NGreene County 1 Alabama 10_B_1 254 1965 wall dry 0 0.0140 0.0279 YeGreene County 2 Alabama 10_B_2 243 1966 wall dry 0 0.0160 0.0279 YeH B Robinson 1 

South Carolina 3251_B_1 176 1960 tangential dry 0 0.0800 0.0279 N

H L Spurlock 1 Kentucky 6041_B_1 315 1977 wall dry 0 0.0065 0.0279 YeH L Spurlock 2 Kentucky 6041_B_2 509 1981 tangential dry 0 0.0065 0.0279 YeHamilton 8 Ohio 2917_B_8 33 1964 wall dry 0 0.0400 0.0279 NHammond 1 Georgia 708_B_1 112 1954 wall dry 0 0.0430 0.0279 NHammond 2 Georgia 708_B_2 112 1954 wall dry 0 0.0430 0.0279 NHammond 3 Georgia 708_B_3 112 1955 wall dry 0 0.0430 0.0279 NHammond 4 Georgia 708_B_4 510 1970 wall dry 0 0.0190 0.0279 YeHarbor Beach 1 Michigan 1731_B_1 103 1968 wall dry 0 0.0900 0.0279 NHarding Street 50 Indiana 990_B_50 109 1958 tangential dry 0 0.0049 0.0279 YeHarding Street 60 Indiana 990_B_60 109 1961 tangential dry 0 0.0021 0.0279 YeHarding Street 70 Indiana 990_B_70 429 1973 tangential dry 0 0.0168 0.0279 YeHarllee Branch 1 Georgia 709_B_1 261 1965 cell dry 0 0.0100 0.0279 YeHarllee Branch 2 Georgia 709_B_2 319 1967 wall dry 0 0.0100 0.0279 YeHarllee Branch 3 Georgia 709_B_3 499 1968 cell dry 0 0.0500 0.0279 NHarllee Branch 4 Georgia 709_B_4 497 1969 cell dry 0 0.0500 0.0279 NHarrington 061B Texas 6193_B_061B 347 1976 tangential dry 0 0.0400 0.0279 N
59 

Harrison Power Station 1 

West Virginia 3944_B_1 643 1972 wall dry 0 0.0200 0.0279 Ye

Harrison Power Station 2 

West Virginia 3944_B_2 633 1973 wall dry 0 0.0200 0.0279 Ye

Harrison Power Station 3 

West Virginia 3944_B_3 642 1974 wall dry 0 0.0100 0.0279 Ye

Hatfields Ferry Power Station 1 

Pennsylvania 3179_B_1 523 1969 cell dry 0 0.0323 0.0279 N

Hatfields Ferry Power Station 2 

Pennsylvania 3179_B_2 523 1970 cell dry 0 0.0200 0.0279 Ye

Hatfields Ferry Power Station 3 

Pennsylvania 3179_B_3 523 1971 cell dry 0 0.0200 0.0279 Ye

Herbert A Wagner 2 Maryland 1554_B_2 135 1959 wall dry 0 0.0017 0.0279 YeHerbert A Wagner 3 Maryland 1554_B_3 324 1966 wall dry 0 0.0100 0.0279 YeHMP&L Station Two Henderson H1 Kentucky 1382_B_H1 151 1973 wall dry 0 0.0700 0.0279 NHMP&L Station Two Henderson H2 Kentucky 1382_B_H2 157 1974 wall dry 0 0.0700 0.0279 NHomer City Station 1 

Pennsylvania 3122_B_1 612 1969 wall dry 0 0.0300 0.0279 N

Homer City Station 2 

Pennsylvania 3122_B_2 606 1970 wall dry 0 0.0300 0.0279 N

Homer City Station 3 

Pennsylvania 3122_B_3 641 1977 wall dry 0 0.0600 0.0279 N

Hoot Lake 2 Minnesota 1943_B_2 60 1959 tangential dry 0 0.0812 0.0279 NHoot Lake 3 Minnesota 1943_B_3 84 1964 wall dry 0 0.0812 0.0279 NHugo 1 Oklahoma 6772_B_1 440 1982 wall dry 0 0.0100 0.0279 YeHunter 1 Utah 6165_B_1 430 1978 tangential dry 0 0.0100 0.0279 YeHunter 2 Utah 6165_B_2 430 1980 tangential dry 0 0.0300 0.0279 NHutsonville 05 Illinois 863_B_05 76 1953 tangential dry 0 0.0300 0.0279 NHutsonville 06 Illinois 863_B_06 77 1954 tangential dry 0 0.0300 0.0279 NIndependence 1 Arkansas 6641_B_1 836 1983 tangential wet 0 0.0400 0.0279 NIndependence 2 Arkansas 6641_B_2 842 1985 tangential wet 0 0.0400 0.0279 NJ B Sims 3 Michigan 1825_B_3 73 1983 wall dry 0 0.0300 0.0279 NJ C Weadock 7 Michigan 1720_B_7 151 1955 tangential dry 0 0.0500 0.0279 NJ C Weadock 8 Michigan 1720_B_8 151 1958 tangential dry 0 0.0400 0.0279 N
60 

J E Corette Plant 2 Montana 2187_B_2 158 1968 tangential dry 0 0.2700 0.0279 NJ H Campbell 1 Michigan 1710_B_1 260 1962 tangential dry 0 0.0111 0.0279 YeJ H Campbell 2 Michigan 1710_B_2 353 1967 wall dry 0 0.0111 0.0279 YeJ H Campbell 3 Michigan 1710_B_3 822 1980 wall dry 0 0.0100 0.0279 YeJ M Stuart 1 Ohio 2850_B_1 597 1971 cell dry 0 0.0500 0.0279 NJ M Stuart 2 Ohio 2850_B_2 597 1970 cell dry 0 0.0500 0.0279 NJ M Stuart 3 Ohio 2850_B_3 597 1972 cell dry 0 0.0700 0.0279 NJ M Stuart 4 Ohio 2850_B_4 597 1974 cell dry 0 0.0200 0.0279 YeJ R Whiting 1 Michigan 1723_B_1 102 1952 wall dry 0 0.1600 0.0279 NJ R Whiting 2 Michigan 1723_B_2 102 1952 wall dry 0 0.1400 0.0279 NJ R Whiting 3 Michigan 1723_B_3 124 1953 wall dry 0 0.1300 0.0279 NJack Watson 4 Mississippi 2049_B_4 230 1968 wall dry 0 0.0400 0.0279 NJack Watson 5 Mississippi 2049_B_5 476 1973 wall dry 0 0.0400 0.0279 NJames De Young 5 Michigan 1830_B_5 27 1969 wall dry 0 0.0300 0.0279 NJames H Miller Jr 1 Alabama 6002_B_1 674 1978 wall dry 0 0.0100 0.0279 YeJames H Miller Jr 2 Alabama 6002_B_2 687 1985 wall dry 0 0.0200 0.0279 YeJames H Miller Jr 3 Alabama 6002_B_3 687 1989 wall dry 0 0.0100 0.0279 YeJames H Miller Jr 4 Alabama 6002_B_4 688 1991 wall dry 0 0.0040 0.0279 YeJames River Power Station 3 Missouri 2161_B_3 41 1960 wall dry 0 0.1100 0.0279 NJames River Power Station 4 Missouri 2161_B_4 56 1964 wall dry 0 0.1000 0.0279 NJames River Power Station 5 Missouri 2161_B_5 97 1970 wall dry 0 0.0113 0.0279 YeJefferies 3 

South Carolina 3319_B_3 153 1970 wall dry 0 0.0000 0.0279 Ye

Jefferies 4 

South Carolina 3319_B_4 153 1970 wall dry 0 0.0000 0.0279 Ye

Jeffrey Energy Center 1 Kansas 6068_B_1 726 1978 tangential dry 0 0.0600 0.0279 NJeffrey Energy Center 2 Kansas 6068_B_2 727 1980 tangential dry 0 0.0300 0.0279 NJeffrey Energy Center 3 Kansas 6068_B_3 727 1983 tangential dry 0 0.0200 0.0279 Ye
61 

Jim Bridger BW71 Wyoming 8066_B_BW71 530 1974 tangential dry 0 0.0100 0.0279 YeJim Bridger BW72 Wyoming 8066_B_BW72 530 1975 tangential dry 0 0.0100 0.0279 YeJim Bridger BW73 Wyoming 8066_B_BW73 530 1976 tangential dry 0 0.0200 0.0279 YeJim Bridger BW74 Wyoming 8066_B_BW74 530 1979 tangential dry 0 0.0100 0.0279 YeJohn E Amos 1 

West Virginia 3935_B_1 800 1971 wall dry 0 0.0300 0.0279 N

John E Amos 2 

West Virginia 3935_B_2 789 1972 wall dry 0 0.0300 0.0279 N

John E Amos 3 

West Virginia 3935_B_3 1282 1973 cell dry 0 0.0300 0.0279 N

John Sevier 2 Tennessee 3405_B_2 176 1955 tangential dry 0 0.0100 0.0279 YeJohn Sevier 3 Tennessee 3405_B_3 176 1956 tangential dry 0 0.0100 0.0279 YeJohn Sevier 4 Tennessee 3405_B_4 176 1957 tangential dry 0 0.0100 0.0279 YeJohnsonville 1 Tennessee 3406_B_1 106 1951 tangential dry 0 0.0200 0.0279 YeJohnsonville 10 Tennessee 3406_B_10 141 1959 wall dry 0 0.0200 0.0279 YeJohnsonville 2 Tennessee 3406_B_2 106 1951 tangential dry 0 0.0200 0.0279 YeJohnsonville 3 Tennessee 3406_B_3 106 1952 tangential dry 0 0.0200 0.0279 YeJohnsonville 4 Tennessee 3406_B_4 106 1952 tangential dry 0 0.0200 0.0279 YeJohnsonville 5 Tennessee 3406_B_5 106 1952 tangential dry 0 0.0200 0.0279 YeJohnsonville 6 Tennessee 3406_B_6 106 1953 tangential dry 0 0.0200 0.0279 YeJohnsonville 7 Tennessee 3406_B_7 141 1958 wall dry 0 0.0200 0.0279 YeJohnsonville 8 Tennessee 3406_B_8 141 1959 wall dry 0 0.0200 0.0279 YeJohnsonville 9 Tennessee 3406_B_9 141 1959 wall dry 0 0.0200 0.0279 YeJoliet 29 71 Illinois 384_B_71 258 1965 tangential dry 0 0.0650 0.0279 NJoliet 29 72 Illinois 384_B_72 258 1965 tangential dry 0 0.0650 0.0279 NJoliet 29 81 Illinois 384_B_81 258 1965 tangential dry 0 0.0490 0.0279 NJoliet 29 82 Illinois 384_B_82 258 1965 tangential dry 0 0.0490 0.0279 NJoliet 9 5 Illinois 874_B_5 311 1959 cyclone wet 0 0.0588 0.0279 NJoppa Steam 1 Illinois 887_B_1 167 1953 tangential dry 0 0.0200 0.0279 YeJoppa Steam 2 Illinois 887_B_2 167 1953 tangential dry 0 0.0200 0.0279 Ye
62 

Joppa Steam 3 Illinois 887_B_3 167 1954 tangential dry 0 0.0400 0.0279 NJoppa Steam 4 Illinois 887_B_4 167 1954 tangential dry 0 0.0400 0.0279 NJoppa Steam 5 Illinois 887_B_5 167 1955 tangential dry 0 0.0400 0.0279 NJoppa Steam 6 Illinois 887_B_6 167 1955 tangential dry 0 0.0400 0.0279 NKammer 1 

West Virginia 3947_B_1 206 1958 cyclone wet 0 0.0300 0.0279 N

Kammer 2 

West Virginia 3947_B_2 206 1958 cyclone wet 0 0.0300 0.0279 N

Kammer 3 

West Virginia 3947_B_3 206 1959 cyclone wet 0 0.0300 0.0279 N

Kanawha River 1 

West Virginia 3936_B_1 204 1953 vertical dry 0 0.0300 0.0279 N

Kanawha River 2 

West Virginia 3936_B_2 204 1953 vertical dry 0 0.0300 0.0279 N

Kenneth C Coleman C1 Kentucky 1381_B_C1 148 1969 wall dry 0 0.1400 0.0279 NKenneth C Coleman C2 Kentucky 1381_B_C2 148 1970 wall dry 0 0.1900 0.0279 NKenneth C Coleman C3 Kentucky 1381_B_C3 153 1971 wall dry 0 0.1200 0.0279 NKeystone 1 

Pennsylvania 3136_B_1 839 1967 tangential dry 0 0.0800 0.0279 N

Keystone 2 

Pennsylvania 3136_B_2 839 1968 tangential dry 0 0.0600 0.0279 N

Killen Station 2 Ohio 6031_B_2 608 1982 wall dry 0 0.0300 0.0279 NKincaid Generation LLC 1 Illinois 876_B_1 584 1967 cyclone wet 0 0.0100 0.0279 YeKincaid Generation LLC 2 Illinois 876_B_2 584 1968 cyclone wet 0 0.0100 0.0279 YeKingston 1 Tennessee 3407_B_1 134 1954 tangential dry 0 0.0100 0.0279 YeKingston 2 Tennessee 3407_B_2 134 1954 tangential dry 0 0.0100 0.0279 YeKingston 3 Tennessee 3407_B_3 134 1954 tangential dry 0 0.0100 0.0279 YeKingston 4 Tennessee 3407_B_4 134 1954 tangential dry 0 0.0100 0.0279 YeKingston 5 Tennessee 3407_B_5 175 1955 tangential dry 0 0.0100 0.0279 YeKingston 6 Tennessee 3407_B_6 175 1955 tangential dry 0 0.0200 0.0279 YeKingston 7 Tennessee 3407_B_7 175 1955 tangential dry 0 0.0200 0.0279 YeKingston 8 Tennessee 3407_B_8 175 1955 tangential dry 0 0.0200 0.0279 YeKingston 9 Tennessee 3407_B_9 175 1955 tangential dry 0 0.0200 0.0279 Ye
63 

Kraft 1 Georgia 733_B_1 48 1958 tangential dry 0 0.0200 0.0279 YeKraft 2 Georgia 733_B_2 52 1961 tangential dry 0 0.0170 0.0279 YeKraft 3 Georgia 733_B_3 102 1965 tangential dry 0 0.0430 0.0279 NKUCC 1 Utah 56163_B_1 30 1944 wall wet 0 0.0300 0.0279 NKUCC 2 Utah 56163_B_2 30 1945 wall wet 0 0.0300 0.0279 NKUCC 3 Utah 56163_B_3 30 1945 wall wet 0 0.0300 0.0279 NKUCC 4 Utah 56163_B_4 65 1959 tangential dry 0 0.0300 0.0279 NKyger Creek 1 Ohio 2876_B_1 214 1955 wall wet 0 0.0500 0.0279 NKyger Creek 2 Ohio 2876_B_2 214 1955 wall wet 0 0.0300 0.0279 NKyger Creek 3 Ohio 2876_B_3 214 1955 wall wet 0 0.0400 0.0279 NKyger Creek 4 Ohio 2876_B_4 214 1955 wall wet 0 0.0100 0.0279 YeKyger Creek 5 Ohio 2876_B_5 214 1955 wall wet 0 0.0500 0.0279 NLa Cygne 2 Kansas 1241_B_2 682 1977 wall dry 0 0.0200 0.0279 YeLabadie 1 Missouri 2103_B_1 597 1970 tangential dry 0 0.0400 0.0279 NLabadie 2 Missouri 2103_B_2 594 1971 tangential dry 0 0.0300 0.0279 NLabadie 3 Missouri 2103_B_3 612 1972 tangential dry 0 0.0300 0.0279 NLabadie 4 Missouri 2103_B_4 612 1973 tangential dry 0 0.0200 0.0279 YeLake Road 6 Missouri 2098_B_6 97 1967 cyclone wet 0 0.0200 0.0279 YeLake Shore 18 Ohio 2838_B_18 245 1962 tangential dry 0 0.0500 0.0279 NLansing 4 Iowa 1047_B_4 260 1977 wall dry 0 0.0900 0.0279 NLansing Smith 1 Florida 643_B_1 162 1965 tangential dry 0 0.0200 0.0279 YeLansing Smith 2 Florida 643_B_2 195 1967 tangential dry 0 0.0100 0.0279 YeLaramie River Station 1 Wyoming 6204_B_1 565 1980 wall dry 0 0.0100 0.0279 YeLaramie River Station 2 Wyoming 6204_B_2 570 1981 wall dry 0 0.0100 0.0279 YeLaramie River Station 3 Wyoming 6204_B_3 570 1982 wall dry 1 0.0100 0.0279 YeLawrence Energy Center 3 Kansas 1250_B_3 48 1955 tangential dry 0 0.0300 0.0279 NLeland Olds 1 

North Dakota 2817_B_1 221 1966 wall dry 0 0.0100 0.0279 Ye
64 

Leland Olds 2 

North Dakota 2817_B_2 448 1975 cyclone wet 0 0.0100 0.0279 Ye

Limestone LIM1 Texas 298_B_LIM1 830 1985 tangential dry 0 0.0100 0.0279 YeLimestone LIM2 Texas 298_B_LIM2 857 1986 tangential dry 0 0.0100 0.0279 YeLon Wright 8 Nebraska 2240_B_8 85 1976 wall dry 0 0.1200 0.0279 NMarion 4 Illinois 976_B_4 170 1978 cyclone wet 0 0.0400 0.0279 NMarshall 1 

North Carolina 2727_B_1 378 1965 tangential dry 0 0.0200 0.0279 Ye

Marshall 2 

North Carolina 2727_B_2 378 1966 tangential dry 0 0.0200 0.0279 Ye

Marshall 3 

North Carolina 2727_B_3 657 1969 tangential dry 0 0.0600 0.0279 N

Marshall 4 

North Carolina 2727_B_4 657 1970 tangential dry 0 0.0200 0.0279 Ye

Martin Lake 1 Texas 6146_B_1 750 1977 tangential wet 0 0.0100 0.0279 YeMartin Lake 2 Texas 6146_B_2 750 1978 tangential wet 0 0.0100 0.0279 YeMartin Lake 3 Texas 6146_B_3 750 1979 tangential wet 0 0.0100 0.0279 YeMayo 1A 

North Carolina 6250_B_1A 371 1983 wall dry 0 0.0600 0.0279 N

Mayo 1B 

North Carolina 6250_B_1B 371 1983 wall dry 0 0.0600 0.0279 N

McIntosh 1 Georgia 6124_B_1 157 1979 wall dry 0 0.0200 0.0279 YeMeramec 1 Missouri 2104_B_1 122 1953 tangential dry 0 0.0300 0.0279 NMeramec 2 Missouri 2104_B_2 120 1954 tangential dry 0 0.0100 0.0279 YeMeramec 3 Missouri 2104_B_3 269 1959 wall dry 0 0.0200 0.0279 YeMeramec 4 Missouri 2104_B_4 347 1961 wall dry 0 0.0100 0.0279 YeMeredosia 05 Illinois 864_B_05 203 1960 tangential dry 0 0.0319 0.0279 NMerom 1SG1 Indiana 6213_B_1SG1 507 1983 wall dry 0 0.0200 0.0279 YeMerom 2SG1 Indiana 6213_B_2SG1 493 1982 wall dry 0 0.0200 0.0279 YeMerrimack 1 

New Hampshire 2364_B_1 111 1960 wall wet 0 0.0332 0.0279 N

Merrimack 2 

New Hampshire 2364_B_2 315 1968 cyclone wet 0 0.0332 0.0279 N

Miami Fort 6 Ohio 2832_B_6 162 1960 tangential dry 0 0.0400 0.0279 N
65 

Miami Fort 7 Ohio 2832_B_7 493 1975 wall dry 0 0.0100 0.0279 YeMiami Fort 8 Ohio 2832_B_8 493 1978 wall dry 0 0.0900 0.0279 NMichigan City 12 Indiana 997_B_12 469 1974 cyclone wet 0 0.0800 0.0279 NMill Creek 1 Kentucky 1364_B_1 303 1972 tangential dry 0 0.0500 0.0279 NMill Creek 2 Kentucky 1364_B_2 301 1974 tangential dry 0 0.0900 0.0279 NMill Creek 3 Kentucky 1364_B_3 391 1978 wall dry 0 0.0900 0.0279 NMill Creek 4 Kentucky 1364_B_4 477 1982 wall dry 0 0.0100 0.0279 YeMilton L Kapp 2 Iowa 1048_B_2 211 1967 tangential dry 0 0.1420 0.0279 NMilton R Young B1 

North Dakota 2823_B_B1 250 1970 cyclone wet 0 0.0100 0.0279 Ye

Milton R Young B2 

North Dakota 2823_B_B2 455 1977 cyclone wet 0 0.0100 0.0279 Ye

Mitchell 1 

West Virginia 3948_B_1 800 1971 wall dry 0 0.0300 0.0279 N

Mitchell 2 

West Virginia 3948_B_2 800 1971 wall dry 0 0.0300 0.0279 N

Mitchell Power Station 33 

Pennsylvania 3181_B_33 277 1963 tangential dry 0 0.1800 0.0279 N

Monroe 1 Michigan 1733_B_1 760 1972 cell dry 0 0.0300 0.0279 NMonroe 2 Michigan 1733_B_2 775 1973 cell dry 0 0.0300 0.0279 NMonroe 3 Michigan 1733_B_3 785 1973 cell dry 0 0.0200 0.0279 YeMonroe 4 Michigan 1733_B_4 765 1974 cell dry 0 0.0200 0.0279 YeMonticello 3 Texas 6147_B_3 750 1978 wall wet 0 0.0453 0.0279 NMontrose 1 Missouri 2080_B_1 170 1958 tangential dry 0 0.1300 0.0279 NMontrose 2 Missouri 2080_B_2 164 1960 tangential dry 0 0.1300 0.0279 NMontrose 3 Missouri 2080_B_3 176 1964 tangential dry 0 0.1300 0.0279 NMorgantown Generating Plant 1 Maryland 1573_B_1 624 1970 tangential dry 0 0.0700 0.0279 NMorgantown Generating Plant 2 Maryland 1573_B_2 620 1971 tangential dry 0 0.0700 0.0279 NMountaineer 1 

West Virginia 6264_B_1 1300 1980 wall dry 0 0.0300 0.0279 N

Mt Storm 1 

West Virginia 3954_B_1 524 1965 tangential dry 0 0.0100 0.0279 Ye
66 

Mt Storm 2 

West Virginia 3954_B_2 524 1966 tangential dry 0 0.0100 0.0279 Ye

Mt Storm 3 

West Virginia 3954_B_3 521 1973 tangential dry 0 0.0100 0.0279 Ye

Muscatine Plant #1 8 Iowa 1167_B_8 35 1969 cyclone wet 0 0.0200 0.0279 YeMuscatine Plant #1 9 Iowa 1167_B_9 147 1983 tangential dry 0 0.0200 0.0279 YeMuskingum River 1 Ohio 2872_B_1 190 1953 wall wet 0 0.0300 0.0279 NMuskingum River 2 Ohio 2872_B_2 190 1954 wall wet 0 0.0300 0.0279 NMuskingum River 3 Ohio 2872_B_3 205 1957 cyclone wet 0 0.0300 0.0279 NMuskingum River 4 Ohio 2872_B_4 205 1958 cyclone wet 0 0.0300 0.0279 NMuskingum River 5 Ohio 2872_B_5 578 1968 cell dry 0 0.0300 0.0279 NMuskogee 4 Oklahoma 2952_B_4 511 1977 tangential dry 0 0.0300 0.0279 NMuskogee 5 Oklahoma 2952_B_5 522 1978 tangential dry 0 0.0300 0.0279 NMuskogee 6 Oklahoma 2952_B_6 515 1984 tangential dry 0 0.0300 0.0279 NNaughton 1 Wyoming 4162_B_1 158 1963 tangential dry 0 0.0100 0.0279 YeNaughton 2 Wyoming 4162_B_2 207 1968 tangential dry 0 0.0200 0.0279 YeNaughton 3 Wyoming 4162_B_3 330 1971 tangential dry 0 0.0200 0.0279 YeNavajo 1 Arizona 4941_B_1 750 1974 tangential dry 0 0.0200 0.0279 YeNavajo 2 Arizona 4941_B_2 750 1975 tangential dry 0 0.0200 0.0279 YeNavajo 3 Arizona 4941_B_3 750 1976 tangential dry 0 0.0200 0.0279 YeNearman Creek N1 Kansas 6064_B_N1 229 1981 wall dry 0 0.0200 0.0279 YeNebraska City 1 Nebraska 6096_B_1 646 1979 wall dry 0 0.0300 0.0279 NNeil Simpson II 2 Wyoming 7504_B_2 80 1995 wall dry 1 0.0300 0.0279 NNelson Dewey 1 Wisconsin 4054_B_1 107 1959 cyclone wet 0 0.1000 0.0279 NNelson Dewey 2 Wisconsin 4054_B_2 111 1962 cyclone wet 0 0.0700 0.0279 NNew Castle 3 

Pennsylvania 3138_B_3 95 1952 wall dry 0 0.0100 0.0279 Ye

New Castle 4 

Pennsylvania 3138_B_4 96 1958 wall dry 0 0.0100 0.0279 Ye

New Castle 5 

Pennsylvania 3138_B_5 138 1964 wall dry 0 0.0500 0.0279 N
67 

New Madrid 1 Missouri 2167_B_1 580 1972 cyclone wet 0 0.0600 0.0279 NNew Madrid 2 Missouri 2167_B_2 580 1977 cyclone wet 0 0.0500 0.0279 NNewton 1 Illinois 6017_B_1 555 1977 tangential dry 0 0.0091 0.0279 YeNewton 2 Illinois 6017_B_2 567 1982 tangential dry 0 0.0091 0.0279 YeNiles 1 Ohio 2861_B_1 107 1954 cyclone wet 0 0.0100 0.0279 YeNiles 2 Ohio 2861_B_2 111 1954 cyclone wet 0 0.0100 0.0279 YeNorth Omaha 1 Nebraska 2291_B_1 79 1954 tangential dry 0 0.0300 0.0279 NNorth Omaha 2 Nebraska 2291_B_2 111 1957 tangential dry 0 0.0300 0.0279 NNorth Omaha 3 Nebraska 2291_B_3 111 1959 tangential dry 0 0.0300 0.0279 NNorth Omaha 4 Nebraska 2291_B_4 138 1963 tangential dry 0 0.0300 0.0279 NNorth Omaha 5 Nebraska 2291_B_5 224 1968 wall dry 0 0.0300 0.0279 NNortheastern 3313 Oklahoma 2963_B_3313 450 1979 tangential dry 0 0.0200 0.0279 YeNortheastern 3314 Oklahoma 2963_B_3314 450 1980 tangential dry 0 0.0200 0.0279 YeO H Hutchings H-1 Ohio 2848_B_H-1 58 1948 tangential dry 0 0.0300 0.0279 NO H Hutchings H-2 Ohio 2848_B_H-2 55 1949 tangential dry 0 0.0600 0.0279 NO H Hutchings H-3 Ohio 2848_B_H-3 63 1950 tangential dry 0 0.0300 0.0279 NO H Hutchings H-4 Ohio 2848_B_H-4 63 1951 tangential dry 0 0.0300 0.0279 NO H Hutchings H-5 Ohio 2848_B_H-5 63 1952 tangential dry 0 0.0200 0.0279 YeO H Hutchings H-6 Ohio 2848_B_H-6 63 1953 tangential dry 0 0.0200 0.0279 YeOklaunion 1 Texas 127_B_1 690 1986 wall dry 0 0.0200 0.0279 YeOttumwa 1 Iowa 6254_B_1 673 1981 tangential dry 0 0.0300 0.0279 NP H Glatfelter 

5PB036 

Pennsylvania 

50397_B_5PB0

36 36 1989 FBC dry 0 0.0300 0.0279 N

Paradise 3 Kentucky 1378_B_3 963 1970 cyclone wet 0 0.0400 0.0279 NPetersburg 1 Indiana 994_B_1 232 1967 tangential dry 0 0.0520 0.0279 NPetersburg 2 Indiana 994_B_2 435 1969 tangential dry 0 66.0000 0.0279 NPetersburg 3 Indiana 994_B_3 532 1977 tangential dry 0 0.0270 0.0279 YePetersburg 4 Indiana 994_B_4 545 1986 tangential dry 0 0.0250 0.0279 Ye
68 

Philip Sporn 11 

West Virginia 3938_B_11 150 1950 vertical dry 0 0.0300 0.0279 N

Philip Sporn 21 

West Virginia 3938_B_21 150 1950 vertical dry 0 0.0300 0.0279 N

Philip Sporn 31 

West Virginia 3938_B_31 150 1951 vertical dry 0 0.0300 0.0279 N

Philip Sporn 41 

West Virginia 3938_B_41 150 1952 vertical dry 0 0.0300 0.0279 N

Picway 9 Ohio 2843_B_9 95 1955 wall dry 0 0.0300 0.0279 NPirkey 1 Texas 7902_B_1 674 1985 wall dry 0 0.2500 0.0279 NPlatte 1 Nebraska 59_B_1 100 1982 tangential dry 0 0.0280 0.0279 NPleasant Prairie 1 Wisconsin 6170_B_1 617 1980 wall dry 0 0.0100 0.0279 YePleasant Prairie 2 Wisconsin 6170_B_2 617 1985 wall dry 0 0.0100 0.0279 YePleasants Power Station 1 

West Virginia 6004_B_1 639 1979 wall dry 0 0.0200 0.0279 Ye

Pleasants Power Station 2 

West Virginia 6004_B_2 639 1980 wall dry 0 0.0200 0.0279 Ye

Portland 1 

Pennsylvania 3113_B_1 157 1958 tangential dry 0 0.0800 0.0279 N

Portland 2 

Pennsylvania 3113_B_2 242 1962 tangential dry 0 0.0200 0.0279 Ye

Potomac River 1 Virginia 3788_B_1 88 1949 tangential dry 1 0.0200 0.0279 YePotomac River 2 Virginia 3788_B_2 88 1950 tangential dry 1 0.0300 0.0279 NPotomac River 3 Virginia 3788_B_3 102 1954 tangential dry 1 0.0500 0.0279 NPotomac River 4 Virginia 3788_B_4 102 1956 tangential dry 1 0.0100 0.0279 YePotomac River 5 Virginia 3788_B_5 102 1957 tangential dry 1 0.0200 0.0279 YePowerton 51 Illinois 879_B_51 382 1972 cyclone wet 0 0.0300 0.0279 NPowerton 52 Illinois 879_B_52 383 1972 cyclone wet 0 0.0300 0.0279 NPowerton 61 Illinois 879_B_61 382 1975 cyclone wet 0 0.0100 0.0279 YePowerton 62 Illinois 879_B_62 383 1975 cyclone wet 0 0.0100 0.0279 YePPL Brunner Island 2 

Pennsylvania 3140_B_2 382 1965 tangential dry 0 0.0256 0.0279 Ye

PPL Brunner Island 3 

Pennsylvania 3140_B_3 744 1981 tangential dry 0 0.0256 0.0279 Ye

PPL Montour 1 

Pennsylvania 3149_B_1 751 1971 tangential dry 0 0.0107 0.0279 Ye
69 

PPL Montour 2 

Pennsylvania 3149_B_2 747 1973 tangential dry 0 0.0166 0.0279 Ye

Prairie Creek 3 Iowa 1073_B_3 42 1958 wall dry 0 0.0800 0.0279 NPrairie Creek 4 Iowa 1073_B_4 125 1967 wall dry 0 0.0600 0.0279 NPulliam 5 Wisconsin 4072_B_5 49 1949 wall dry 0 0.0700 0.0279 NPulliam 6 Wisconsin 4072_B_6 72 1951 wall dry 0 0.0700 0.0279 NPulliam 7 Wisconsin 4072_B_7 88 1958 wall dry 0 0.0200 0.0279 YePulliam 8 Wisconsin 4072_B_8 133 1964 wall dry 0 0.0700 0.0279 NQuindaro 1 Kansas 1295_B_1 72 1965 cyclone wet 0 0.0284 0.0279 NQuindaro 2 Kansas 1295_B_2 111 1971 wall dry 0 0.0284 0.0279 NR D Green G1 Kentucky 6639_B_G1 231 1979 wall dry 0 0.0469 0.0279 NR D Green G2 Kentucky 6639_B_G2 233 1981 wall dry 0 0.0469 0.0279 NR D Morrow 1 Mississippi 6061_B_1 180 1978 wall dry 0 0.0300 0.0279 NR D Morrow 2 Mississippi 6061_B_2 180 1978 wall dry 0 0.0200 0.0279 YeR E Burger 5 Ohio 2864_B_5 47 1955 wall dry 0 0.0600 0.0279 NR E Burger 6 Ohio 2864_B_6 47 1955 wall dry 0 0.0400 0.0279 NR M Heskett B1 

North Dakota 2790_B_B1 29 1954 

stoker/SPR dry 0 0.0400 0.0279 N

R M Heskett B2 

North Dakota 2790_B_B2 76 1963 FBC dry 0 0.0100 0.0279 Ye

R M Schahfer 14 Indiana 6085_B_14 424 1976 cyclone wet 0 0.0152 0.0279 YeR M Schahfer 15 Indiana 6085_B_15 472 1979 wall dry 0 0.0152 0.0279 YeR M Schahfer 17 Indiana 6085_B_17 361 1983 tangential dry 0 0.0152 0.0279 YeR M Schahfer 18 Indiana 6085_B_18 361 1986 tangential dry 0 0.0152 0.0279 YeR Paul Smith Power Station 9 Maryland 1570_B_9 28 1947 wall dry 0 0.1700 0.0279 NR S Nelson 6 Louisiana 1393_B_6 550 1982 tangential wet 0 0.0113 0.0279 YeRiver Rouge 2 Michigan 1740_B_2 241 1957 tangential dry 0 0.0100 0.0279 YeRiver Rouge 3 Michigan 1740_B_3 272 1958 wall dry 0 0.0100 0.0279 YeRiverbend 10 

North Carolina 2732_B_10 133 1954 tangential dry 0 0.0284 0.0279 N
70 

Riverbend 7 

North Carolina 2732_B_7 94 1952 tangential dry 0 0.0284 0.0279 N

Riverbend 8 

North Carolina 2732_B_8 94 1952 tangential dry 0 0.1050 0.0279 N

Riverbend 9 

North Carolina 2732_B_9 133 1954 tangential dry 0 0.1050 0.0279 N

Riverside 9 Iowa 1081_B_9 130 1961 tangential dry 0 0.0500 0.0279 NRiverton 39 Kansas 1239_B_39 38 1950 wall dry 0 0.0300 0.0279 NRiverton 40 Kansas 1239_B_40 54 1954 tangential dry 0 0.0300 0.0279 NRivesville 7 

West Virginia 3945_B_7 46 1943 vertical wet 0 0.0100 0.0279 Ye

Rivesville 8 

West Virginia 3945_B_8 91 1951 vertical wet 0 0.0200 0.0279 Ye

Rockport MB1 Indiana 6166_B_MB1 1280 1984 wall dry 0 0.0300 0.0279 NRockport MB2 Indiana 6166_B_MB2 1280 1989 wall dry 0 0.0300 0.0279 NRodemacher 2 Louisiana 6190_B_2 523 1982 wall dry 0 0.0100 0.0279 YeRoxboro 1 

North Carolina 2712_B_1 369 1966 wall dry 0 0.0600 0.0279 N

Roxboro 2 

North Carolina 2712_B_2 671 1968 tangential dry 0 0.0700 0.0279 N

Roxboro 3A 

North Carolina 2712_B_3A 353 1973 wall dry 0 0.0600 0.0279 N

Roxboro 3B 

North Carolina 2712_B_3B 353 1973 wall dry 0 0.0600 0.0279 N

Roxboro 4A 

North Carolina 2712_B_4A 349 1980 wall dry 0 0.0700 0.0279 N

Roxboro 4B 

North Carolina 2712_B_4B 349 1980 wall dry 0 0.0700 0.0279 N

Rumford Cogeneration 6 Maine 10495_B_6 43 1990 FBC dry 0 0.0100 0.0279 YeRumford Cogeneration 7 Maine 10495_B_7 43 1990 FBC dry 0 0.0100 0.0279 YeRush Island 1 Missouri 6155_B_1 604 1976 tangential dry 0 0.0100 0.0279 YeRush Island 2 Missouri 6155_B_2 604 1977 tangential dry 0 0.0300 0.0279 NSalem Harbor 1 

Massachusetts 1626_B_1 82 1951 wall dry 0 0.0100 0.0279 Ye

Salem Harbor 2 

Massachusetts 1626_B_2 80 1952 wall dry 0 0.0005 0.0279 Ye

Salem Harbor 3 

Massachusetts 1626_B_3 149 1958 wall dry 0 0.0300 0.0279 N
71 

San Miguel SM-1 Texas 6183_B_SM-1 391 1982 wall dry 0 0.1000 0.0279 NSandow 4 Texas 6648_B_4 542 1981 tangential wet 0 0.0400 0.0279 NSchiller 4 

New Hampshire 2367_B_4 48 1952 wall dry 0 0.0400 0.0279 N

Scholz 1 Florida 642_B_1 49 1953 wall dry 0 0.0200 0.0279 YeScholz 2 Florida 642_B_2 49 1953 wall dry 0 0.0200 0.0279 YeSeminole 1 Florida 136_B_1 654 1984 wall dry 0 0.0210 0.0279 YeSeminole 2 Florida 136_B_2 654 1984 wall dry 0 0.0160 0.0279 YeShawville 1 

Pennsylvania 3131_B_1 122 1954 wall dry 0 0.0800 0.0279 N

Shawville 2 

Pennsylvania 3131_B_2 125 1954 wall dry 0 0.0400 0.0279 N

Shawville 3 

Pennsylvania 3131_B_3 175 1959 tangential dry 0 0.0133 0.0279 Ye

Shawville 4 

Pennsylvania 3131_B_4 175 1960 tangential dry 0 0.0133 0.0279 Ye

Sherburne County 1 Minnesota 6090_B_1 762 1976 tangential dry 0 0.0200 0.0279 YeSherburne County 2 Minnesota 6090_B_2 752 1977 tangential dry 0 0.0200 0.0279 YeSibley 1 Missouri 2094_B_1 54 1960 cyclone wet 0 0.0300 0.0279 NSibley 2 Missouri 2094_B_2 54 1962 cyclone wet 0 0.0400 0.0279 NSibley 3 Missouri 2094_B_3 401 1969 cyclone wet 0 0.0092 0.0279 YeSikeston Power Station 1 Missouri 6768_B_1 233 1981 wall dry 0 0.0200 0.0279 YeSioux 1 Missouri 2107_B_1 490 1967 cyclone wet 0 0.0034 0.0279 YeSioux 2 Missouri 2107_B_2 490 1968 cyclone wet 0 0.0034 0.0279 YeSooner 1 Oklahoma 6095_B_1 535 1979 tangential dry 0 0.0320 0.0279 NSooner 2 Oklahoma 6095_B_2 540 1980 tangential dry 0 0.0500 0.0279 NSouth Oak Creek 5 Wisconsin 4041_B_5 257 1959 wall dry 0 0.0200 0.0279 YeSouth Oak Creek 6 Wisconsin 4041_B_6 260 1961 wall dry 0 0.0100 0.0279 YeSouth Oak Creek 7 Wisconsin 4041_B_7 292 1965 tangential dry 0 0.0015 0.0279 YeSouth Oak Creek 8 Wisconsin 4041_B_8 306 1967 tangential dry 0 0.0117 0.0279 YeSouthwest Power Station 1 Missouri 6195_B_1 178 1976 wall dry 0 0.0400 0.0279 N
72 

St Clair 1 Michigan 1743_B_1 151 1953 wall dry 0 0.1000 0.0279 NSt Clair 2 Michigan 1743_B_2 154 1953 wall dry 0 0.0100 0.0279 YeSt Clair 3 Michigan 1743_B_3 160 1954 wall dry 0 0.0100 0.0279 YeSt Clair 4 Michigan 1743_B_4 151 1954 wall dry 0 0.0300 0.0279 NSt Clair 6 Michigan 1743_B_6 312 1961 tangential dry 0 0.0100 0.0279 YeSt Clair 7 Michigan 1743_B_7 440 1969 tangential dry 0 0.0200 0.0279 YeSt Johns River Power Park 1 Florida 207_B_1 623 1987 wall dry 0 0.0100 0.0279 YeSt Johns River Power Park 2 Florida 207_B_2 622 1988 wall dry 0 0.0100 0.0279 YeStanton 1 

North Dakota 2824_B_1 130 1967 wall dry 0 0.0100 0.0279 Ye

Stanton Energy Center 1 Florida 564_B_1 440 1987 wall dry 0 0.0100 0.0279 YeStanton Energy Center 2 Florida 564_B_2 446 1996 wall dry 0 0.0100 0.0279 YeStone Container Florence Mill PB4 

South Carolina 50806_B_PB4 75 1987 wall dry 0 0.0100 0.0279 Ye

Streeter Station 7 Iowa 1131_B_7 36 1973 wall dry 0 0.0300 0.0279 NSunbury Generation LP 3 

Pennsylvania 3152_B_3 94 1951 wall dry 0 0.0400 0.0279 N

Sunbury Generation LP 4 

Pennsylvania 3152_B_4 128 1953 wall dry 0 0.0600 0.0279 N

Sutherland 3 Iowa 1077_B_3 82 1961 cyclone wet 0 0.0300 0.0279 NTaconite Harbor Energy Center 1 Minnesota 10075_B_1 65 1957 tangential dry 1 0.0055 0.0279 YeTaconite Harbor Energy Center 2 Minnesota 10075_B_2 67 1957 tangential dry 1 0.0201 0.0279 YeTaconite Harbor Energy Center 3 Minnesota 10075_B_3 68 1967 tangential dry 1 0.0201 0.0279 YeTanners Creek U1 Indiana 988_B_U1 145 1951 vertical dry 0 0.0300 0.0279 NTanners Creek U2 Indiana 988_B_U2 145 1952 vertical dry 0 0.0053 0.0279 YeTanners Creek U3 Indiana 988_B_U3 200 1954 vertical dry 0 0.0053 0.0279 YeTanners Creek U4 Indiana 988_B_U4 500 1964 cyclone wet 0 0.0053 0.0279 YeTecumseh Energy Center 10 Kansas 1252_B_10 129 1962 tangential dry 0 0.0500 0.0279 NTecumseh Energy Center 9 Kansas 1252_B_9 74 1957 tangential dry 0 0.0900 0.0279 N
73 

Thomas Hill MB1 Missouri 2168_B_MB1 175 1966 cyclone wet 0 0.0300 0.0279 NThomas Hill MB2 Missouri 2168_B_MB2 275 1969 cyclone wet 0 0.0300 0.0279 NThomas Hill MB3 Missouri 2168_B_MB3 670 1982 wall dry 0 0.0300 0.0279 NTitus 1 

Pennsylvania 3115_B_1 81 1951 tangential dry 0 0.0400 0.0279 N

Titus 2 

Pennsylvania 3115_B_2 81 1951 tangential dry 0 0.0400 0.0279 N

Titus 3 

Pennsylvania 3115_B_3 81 1953 tangential dry 0 0.0300 0.0279 N

Transalta Centralia Generation BW21 Washington 3845_B_BW21 703 1972 tangential dry 0 0.0100 0.0279 YeTransalta Centralia Generation BW22 Washington 3845_B_BW22 703 1973 tangential dry 0 0.0100 0.0279 YeTrenton Channel 16 Michigan 1745_B_16 53 1949 tangential dry 0 0.0300 0.0279 NTrenton Channel 17 Michigan 1745_B_17 53 1949 tangential dry 0 0.0300 0.0279 NTrenton Channel 18 Michigan 1745_B_18 53 1949 tangential dry 0 0.0300 0.0279 NTrenton Channel 19 Michigan 1745_B_19 53 1950 tangential dry 0 0.0300 0.0279 NTrenton Channel 9A Michigan 1745_B_9A 536 1968 tangential dry 0 0.0400 0.0279 NTrimble County 1 Kentucky 6071_B_1 383 1990 tangential dry 0 0.0300 0.0279 NTyrone 5 Kentucky 1361_B_5 71 1953 wall dry 0 0.0300 0.0279 NUrquhart URQ3 

South Carolina 3295_B_URQ3 94 1955 tangential dry 0 0.0800 0.0279 N

Victor J Daniel Jr 1 Mississippi 6073_B_1 507 1977 tangential dry 0 0.0200 0.0279 YeVictor J Daniel Jr 2 Mississippi 6073_B_2 507 1981 tangential dry 0 0.0300 0.0279 NW H Sammis 5 Ohio 2866_B_5 300 1967 wall dry 0 0.0200 0.0279 YeW H Sammis 6 Ohio 2866_B_6 597 1969 wall dry 0 0.0100 0.0279 YeW H Sammis 7 Ohio 2866_B_7 600 1971 wall dry 0 0.0100 0.0279 YeW H Weatherspoon 1 

North Carolina 2716_B_1 48 1949 wall dry 0 0.0600 0.0279 N

W H Weatherspoon 2 

North Carolina 2716_B_2 49 1950 wall dry 0 0.0600 0.0279 N

W H Weatherspoon 3 

North Carolina 2716_B_3 76 1952 tangential dry 0 0.0900 0.0279 N

W H Zimmer 1 Ohio 6019_B_1 1300 1991 wall dry 0 0.0100 0.0279 Ye
74 

W S Lee 1 

South Carolina 3264_B_1 98 1951 tangential dry 0 0.1300 0.0279 N

W S Lee 2 

South Carolina 3264_B_2 98 1951 tangential dry 0 0.0700 0.0279 N

W S Lee 3 

South Carolina 3264_B_3 168 1958 tangential dry 0 0.0400 0.0279 N

Wabash River 2 Indiana 1010_B_2 43 1953 wall dry 0 0.0500 0.0279 NWabash River 4 Indiana 1010_B_4 43 1955 wall dry 0 0.1100 0.0279 NWabash River 6 Indiana 1010_B_6 318 1968 tangential dry 0 0.1100 0.0279 NWalter C Beckjord 1 Ohio 2830_B_1 94 1952 tangential dry 0 0.0700 0.0279 NWalter C Beckjord 2 Ohio 2830_B_2 94 1953 tangential dry 0 0.0500 0.0279 NWalter C Beckjord 3 Ohio 2830_B_3 128 1954 wall dry 0 0.0600 0.0279 NWalter C Beckjord 4 Ohio 2830_B_4 150 1958 tangential dry 0 0.0500 0.0279 NWalter C Beckjord 5 Ohio 2830_B_5 238 1962 tangential dry 0 0.0400 0.0279 NWalter C Beckjord 6 Ohio 2830_B_6 409 1969 tangential dry 0 0.0400 0.0279 NWalter Scott Jr. Energy Center 1 Iowa 1082_B_1 45 1954 wall dry 0 0.0700 0.0279 NWalter Scott Jr. Energy Center 2 Iowa 1082_B_2 88 1958 tangential dry 0 0.0500 0.0279 NWansley 1 Georgia 6052_B_1 891 1976 tangential dry 0 0.0620 0.0279 NWansley 2 Georgia 6052_B_2 892 1978 tangential dry 0 0.0600 0.0279 NWarrick 1 Indiana 6705_B_1 136 1960 wall dry 0 0.1000 0.0279 NWarrick 2 Indiana 6705_B_2 136 1964 wall dry 0 0.0900 0.0279 NWarrick 3 Indiana 6705_B_3 136 1965 wall dry 0 0.1500 0.0279 NWarrick 4 Indiana 6705_B_4 300 1970 cell dry 0 0.1400 0.0279 NWaukegan 17 Illinois 883_B_17 100 1952 cyclone wet 0 0.0200 0.0279 YeWaukegan 7 Illinois 883_B_7 327 1958 tangential dry 0 0.0517 0.0279 NWaukegan 8 Illinois 883_B_8 359 1962 tangential dry 0 0.0517 0.0279 NWelsh 1 Texas 6139_B_1 527 1977 wall dry 0 0.0075 0.0279 YeWelsh 2 Texas 6139_B_2 524 1980 wall dry 0 0.0075 0.0279 YeWelsh 3 Texas 6139_B_3 524 1982 wall dry 0 0.0075 0.0279 Ye
75 

Weston 1 Wisconsin 4078_B_1 62 1954 wall dry 0 0.0021 0.0279 YeWeston 2 Wisconsin 4078_B_2 86 1960 wall dry 0 0.0021 0.0279 YeWhelan Energy Center 1 Nebraska 60_B_1 76 1981 tangential dry 0 0.0042 0.0279 YeWhite Bluff 1 Arkansas 6009_B_1 815 1980 tangential dry 0 0.0100 0.0279 YeWhite Bluff 2 Arkansas 6009_B_2 825 1981 tangential dry 0 0.0070 0.0279 YeWidows Creek 7 Alabama 50_B_7 473 1961 tangential dry 0 0.0100 0.0279 YeWill County 3 Illinois 884_B_3 250 1957 tangential dry 0 0.0288 0.0279 NWill County 4 Illinois 884_B_4 503 1963 tangential dry 0 0.0288 0.0279 NWilliams WIL1 

South Carolina 3298_B_WIL1 606 1973 tangential dry 0 0.0200 0.0279 Ye

Willow Island 1 

West Virginia 3946_B_1 54 1949 vertical dry 0 0.0200 0.0279 Ye

Willow Island 2 

West Virginia 3946_B_2 181 1960 cyclone wet 0 0.0200 0.0279 Ye

Winyah 1 

South Carolina 6249_B_1 295 1975 wall dry 0 0.0800 0.0279 N

Winyah 2 

South Carolina 6249_B_2 295 1977 wall dry 0 0.0100 0.0279 Ye

Winyah 3 

South Carolina 6249_B_3 295 1980 wall dry 0 0.0400 0.0279 N

Winyah 4 

South Carolina 6249_B_4 270 1981 wall dry 0 0.0300 0.0279 N

Wood River 4 Illinois 898_B_4 105 1954 tangential dry 0 0.0400 0.0279 NWood River 5 Illinois 898_B_5 383 1964 tangential dry 0 0.0100 0.0279 YeWyandotte 7 Michigan 1866_B_7 35 1948 wall dry 0 0.0300 0.0279 NYates Y1BR Georgia 728_B_Y1BR 99 1950 tangential dry 0 0.2000 0.0279 NYates Y2BR Georgia 728_B_Y2BR 105 1950 tangential dry 0 0.2000 0.0279 NYates Y3BR Georgia 728_B_Y3BR 112 1952 tangential dry 0 0.2000 0.0279 NYates Y4BR Georgia 728_B_Y4BR 135 1957 tangential dry 0 0.0700 0.0279 NYates Y5BR Georgia 728_B_Y5BR 137 1958 tangential dry 0 0.0700 0.0279 NYates Y6BR Georgia 728_B_Y6BR 346 1974 tangential dry 0 0.0300 0.0279 NYates Y7BR Georgia 728_B_Y7BR 349 1974 tangential dry 0 0.0200 0.0279 YeYorktown 1 Virginia 3809_B_1 157 1957 tangential dry 0 0.0518 0.0279 N
76 

Yorktown 2 Virginia 3809_B_2 164 1959 tangential dry 0 0.0518 0.0279 N
77 

Gibsons Creek Power Plant: This unit is listed as only having access to subbituminious coal in NEEDS. 

However, since it the unit was originally designed to burn lignite, as evidenced by historic consumption, in 

MATS policy runs it is subjected to the Hg limit for low Btu virgin coal in the policy case. 

Treatment of DSI in Emissions Calculations: DSI is considered when calculating condensable PM for air 

quality modeling but not when assigning mercury EMFs in the power sector modeling. 

Accounting for Presence of Fabric Filters in Deriving Mercury Emission Modification Factors (EMFs) and 

Calculating Filterable Particulate Matter (PM): When fabric filters are added to generating units, the 

mercury EMFs are recalculated to account for their presence. This is applied in both the base and policy 

case v.4.10_MATS runs and in the v.4.10_MATS runs used in air quality modeling. In addition, since the 

calculation of filterable PM for air quality modeling is a function of filter efficiency, the post-processing 

procedure, used to prepare model output of air quality modeling, was also updated to account for the 

presence of FFs 

 
78 

Chapter 7: Set-Up Parameters and Rules

7.5 MATS Specific Set-Up Rules” (new) 

The following set-up features apply in the v.4.10 base and policy cases for MATS: 

7.5.1 New Builds and Retrofits in 2012: Given the short lead time, EPA’s policy analysis has disabled 

incremental new capacity and retrofit construction in the 2012 model year. The results presented for the 

2012 model year reflect the model’s enactment of investment decisions already underway (as opposed to 

any investment decisions driven by new policies). 

7.5.2 SCR Retrofits in the MATS Policy Scenario: SCR is an advanced post-combustion technology 

for NOX control. While SCR can yield mercury control cobenefits, IPM results demonstrate that MATS 

alone is insufficient to drive new SCR retrofitting by 2015; the results show that other control 

technologies, such as ACI, are generally more cost-effective compliance options in the near term for 

MATS implementation. It is possible that certain units may elect to ‘accelerate’ the installation of SCR 

that they may otherwise have considered installing in the 2020-2050 timeframe, depending on future NOX

control requirements. In light of the inherent long-run uncertainty in this type of decision, and the focus of 

this analysis on quantifying the incremental impacts of MATS in 2015, EPA conservatively constrained 

IPM to prevent the model from “re-locating” (i.e., accelerating) long-term base case SCR installations from 

2020-2050 to the 2015 model year for MATS. 
79 

Chapter 11: Other Fuels and Fuel Emission Factor Assumptions 

11.5 Fuel Emission Factors 

Table 11-4 brings together all the fuel emission factor assumptions as implemented in EPA Base Case 

v.4.10_MATS. For sulfur dioxide and mercury in coal, where emission factors vary widely based on the 

rank, grade, and supply seam source of the coal, cross references are given to tables that provide more 

detailed treatment of the topic. Nitrogen oxides (NOX) are not included in Table 11-4 because NOX levels 

are not primarily fuel based but are a factor of the combustion process. 

Table 11-4 Fuel Emission Factor Assumptions in EPA Base Case v.4.10_MATS 

Fuel Type Heat Content 

(Btu/lb)1

Carbon 

Dioxide 

(lbs/MMBtu)2

Sulfur 

Dioxide 

(lbs/MMBtu)3

Mercury 

(lbs/TBtu)3

Coal 

 Bituminous >10,260 - 13,000 205.2 - 206.6 0.67 - 6.43 1.82 - 34.71 

Subbituminous > 7,500 - 10,260 212.7 - 213.1 0.58 - 1.41 4.24 - 6.44 

 Lignite < 7,500 213.5 - 217.0 1.46 - 3.91 7.51 - 14.88 

Natural Gas -- 117.08 0 0.00014 

Fuel Oil 

 Distillate -- 161.4 0 0.48 

 Residual -- 161.4 - 173.9 0.3 - 2.65 0.48 

Biomass -- 0 0.08 0.57 

Waste Fuels 

 Waste Coal4 6,175 205.7 5.36 63.9 

 Petroleum Coke 14,150 225.1 7.27 23.182.66

 Fossil Waste -- 321.1 0.08 0 

 Non-Fossil Waste -- 0 0 0 

 Tires -- 189.5 1.65 3.58 

 Municipal Solid Waste -- 91.9 0.35 71.85 

Notes:

1

Distillate and Residual Oils, Biomass, Fossil Waste, Non-Fossil Waste, Tires, and Municipal Solid 

Waste (MSW) are priced at a $/MMBtu basis and hence heat content is not required for modeling. 2

Also see Table 9-9 in EPA Base Case v.4.10 (EPA #430-R-10-010), August 2010 at 

www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. 3

Also see Table 9-6 and Table 9-7 in EPA Base Case v.4.10 (EPA #430-R-10-010), August 2010 

at www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. 

Biomass fuel is considered to have a net zero impact on atmospheric carbon dioxide levels since 

the emissions released are equivalent in carbon content to the carbon absorbed during fuel crop 

growth. (See, for example, Hughes, E., Role of Renewables in Greenhouse Gas Reduction, 

Electric Power Research Institute (EPRI): November, 1998. Report TR-111883, p. 28.) "

Biomass Co-firing," Chapter 2 in Renewable Energy Technology Characterizations, U.S. 

Department of Energy and Electric Power Research Institute (EPRI), 1997. 

Analysis of Emissions Reduction Option for the Electric Power Industry, Office of Air and 

Radiation, U.S. Environmental Protection Agency, March 1999. 

4

In EPA Base Case v.4.10_MATS waste coal units are assumed to achieve 99% mercury removal.