United States Office of Water 

Environmental Protection Washington, DC 20460 September 2015 

Agency 

 

Incremental Costs and 

Pollutant Removals for the 

Final Effluent Limitations 

Guidelines and Standards 

for the Steam Electric Power 

Generating Point Source 

Category
Table of Contents 

i 

Table of Contents 

Page 

1. INTRODUCTION ............................................................................................................. 1-1

2. STRUCTURE OF COSTS AND POLLUTANT LOADINGS MODELS ......................................... 2-1

2.1 Cost Model ...................................................................................................... 2-1

2.1.1 Input Data to Cost Model...................................................................... 2-1

2.1.2 Industry Assumptions/Factors ............................................................... 2-2

2.1.3 Technology Cost Modules .................................................................... 2-2

2.1.4 Model Outputs ...................................................................................... 2-3

2.2 Pollutant Loadings Model ................................................................................ 2-3

2.3 References ....................................................................................................... 2-4

3. DATA SOURCES ............................................................................................................ 3-1

3.1 Steam Electric Technical Questionnaire Database ............................................ 3-1

3.1.1 Industry Factors .................................................................................... 3-2

3.1.2 Plant Characteristics ............................................................................. 3-2

3.1.3 FGD Wastewater Loadings ................................................................... 3-2

3.1.4 Ash Transport Water Loadings ............................................................. 3-2

3.1.5 Combustion Residual Leachate Loadings.............................................. 3-3

3.2 Technology Vendor Data ................................................................................. 3-3

3.3 Field Sampling Program................................................................................... 3-4

3.3.1 Detailed Study Sampling Data .............................................................. 3-4

3.3.2 EPA Field Sampling Data ..................................................................... 3-5

3.3.3 CWA 308 Monitoring Data .................................................................. 3-6

3.4 Industry- and State-Provided Data .................................................................... 3-6

3.5 Electric Power Research Institute Reports ........................................................ 3-8

3.6 NPDES Permit Data ......................................................................................... 3-9

3.7 EPA 1982 Technical Development Document .................................................. 3-9

3.8 Protection of Confidential Business Information ............................................ 3-10

3.9 References ..................................................................................................... 3-12

4. DEVELOPMENT OF MODEL INPUTS ................................................................................ 4-1

4.1 Wastestream Population and Flow Basis for Pollutant Loadings ....................... 4-1

4.1.1 FGD Wastewater .................................................................................. 4-2

4.1.2 Fly Ash and Bottom Ash Transport Water ............................................ 4-4

4.1.2.1 Plant-Level Normalized Flow ................................................ 4-5

4.1.2.2 Part C Normalized Flow ......................................................... 4-6

4.1.2.3 Unit Flow Fraction ................................................................. 4-7

4.1.2.4 Generating Unit-Level Normalized Flow ............................... 4-7

4.1.2.5 Additional Flow Adjustments ................................................. 4-7

4.1.3 Combustion Residual Leachate ............................................................. 4-8

4.1.3.1 Landfill Combustion Residual Leachate Discharge Flow ........ 4-8

4.1.3.2 Impoundment Combustion Residual Leachate Discharge 

Flow .....................................................................................4-11
Table of Contents 

Table of Contents (Continued) 

Page 

ii 

4.2 Wastestream Population and Characteristics for Costing ................................ 4-14

4.2.1 FGD Wastewater ................................................................................ 4-15

4.2.2 Fly Ash............................................................................................... 4-15

4.2.3 Bottom Ash ........................................................................................ 4-19

4.2.4 Combustion Residual Leachate ........................................................... 4-21

4.2.5 Gasification Wastewater ..................................................................... 4-21

4.3 CCR Rule Coordination Methodology............................................................ 4-22

4.3.1 Background on CCR Rule Costing Approach ..................................... 4-22

4.3.2 Methodology for Incorporating CCR Rule Output .............................. 4-24

4.3.3 CCR Rule Coordination Input Table ................................................... 4-27

4.4 Pollutant Concentrations ................................................................................ 4-28

4.5 Plant Characteristics ....................................................................................... 4-28

4.5.1 FGD Treatment-in-Place Input ........................................................... 4-28

4.5.2 High-Flow FGD Treatment Systems ................................................... 4-29

4.5.3 Cold Climate Plants ............................................................................ 4-31

4.6 Disposal of Combustion Residuals ................................................................. 4-31

4.6.1 Combustion Residual Landfills ........................................................... 4-31

4.6.2 Combustion Residual Surface Impoundments ..................................... 4-32

4.7 References ..................................................................................................... 4-32

5. GENERAL METHODOLOGY, TERMINOLOGY, AND COMMON COST ELEMENTS .................. 5-1

5.1 General Cost Methodology and Terminology ................................................... 5-1

5.2 Compliance Monitoring Cost Methodology ...................................................... 5-3

5.2.1 Monitoring Requirements ..................................................................... 5-3

5.2.2 Capital Cost Methodology .................................................................... 5-4

5.2.3 O&M Cost Methodology ...................................................................... 5-4

5.2.3.1 Sampling Labor Cost ............................................................. 5-4

5.2.3.2 Sampling Material Cost .......................................................... 5-5

5.2.3.3 Sampling Preservation Cost ................................................... 5-6

5.2.3.4 Sample Shipping Cost ............................................................ 5-7

5.2.3.5 Sample Analysis Cost ............................................................ 5-8

5.3 Transportation Cost Methodology .................................................................... 5-9

5.3.1 Technology Description........................................................................ 5-9

5.3.2 Cost Inputs ........................................................................................... 5-9

5.3.3 Cost Methodology .............................................................................. 5-10

5.3.3.1 On-Site Transportation Cost Methodology ............................5-10

5.3.3.2 Off-Site Transportation Cost Methodology ...........................5-11

5.4 Disposal Cost Methodology ........................................................................... 5-12

5.4.1 Technology Description...................................................................... 5-12

5.4.2 Cost Inputs ......................................................................................... 5-12

5.4.3 Cost Methodology .............................................................................. 5-12

5.4.3.1 On-Site Disposal Cost Methodology .....................................5-12

5.4.3.2 Off-Site Disposal Cost Methodology .....................................5-14

5.5 Surface Impoundment Operation Costs Methodology..................................... 5-15

5.5.1 Technology Description...................................................................... 5-15
Table of Contents 

Table of Contents (Continued) 

Page 

iii 

5.5.2 Input Table ......................................................................................... 5-16

5.5.3 Cost Methodology .............................................................................. 5-17

5.5.3.1 Impoundment O&M Costs ....................................................5-17

5.5.3.2 Impoundment Unitized O&M Costs ......................................5-21

5.5.3.3 Earthmoving Unitized O&M Costs .......................................5-22

5.5.3.4 Impoundment and Earthmoving Capacity Factors .................5-24

5.5.3.5 Surface Impoundment Earthmoving Recurring Costs ............5-24

5.6 References ..................................................................................................... 5-25

6. FGD WASTEWATER COST METHODOLOGY ................................................................... 6-1

6.1 Chemical Precipitation ..................................................................................... 6-1

6.1.1 Technology Description........................................................................ 6-1

6.1.2 Population Costed................................................................................. 6-3

6.1.3 Credit for Chemical Precipitation Treatment in Place............................ 6-3

6.1.4 Input Table ........................................................................................... 6-6

6.1.5 Key Variables Used in the Capital and O&M Cost 

Methodologies ...................................................................................... 6-7

6.1.6 Capital Cost Methodology .................................................................... 6-8

6.1.6.1 Purchased Equipment Costs: Mercury Analyzer ....................6-10

6.1.6.2 Purchased Equipment Costs: Pumps ......................................6-10

6.1.6.3 Purchased Equipment Costs: Tanks .......................................6-18

6.1.6.4 Purchased Equipment Costs: Chemical Feed Systems ...........6-41

6.1.6.5 Purchased Equipment Costs: Mixers .....................................6-52

6.1.6.6 Purchased Equipment Costs: Solids Contact Clarifiers ..........6-61

6.1.6.7 Purchased Equipment Costs: Filter Presses ............................6-65

6.1.6.8 Purchased Equipment Costs: Gravity Sand Filters .................6-66

6.1.6.9 Direct Capital Cost ................................................................6-71

6.1.6.10 Indirect Capital Cost .............................................................6-72

6.1.7 O&M Cost Methodology .................................................................... 6-74

6.1.7.1 Operating Labor Cost ............................................................6-74

6.1.7.2 Maintenance Labor Cost .......................................................6-74

6.1.7.3 Maintenance Materials Cost ..................................................6-75

6.1.7.4 Chemical Purchase Cost ........................................................6-76

6.1.7.5 Energy Cost ..........................................................................6-81

6.1.8 Sludge Disposal Cost .......................................................................... 6-95

6.1.9 Recurring Cost Methodology .............................................................. 6-96

6.1.10 Compliance Monitoring Cost .............................................................. 6-96

6.1.11 Impoundment Operation Cost ............................................................. 6-96

6.1.12 FGD System Outage Costs ................................................................. 6-97

6.1.13 Results and Summary of Costs ........................................................... 6-97

6.2 Biological Treatment ...................................................................................... 6-97

6.2.1 Technology Description...................................................................... 6-98

6.2.2 Population Costed............................................................................. 6-100

6.2.3 Credit for Biological Treatment in Place ........................................... 6-101

6.2.4 Input Table ....................................................................................... 6-101
Table of Contents 

Table of Contents (Continued) 

Page 

iv 

6.2.5 Capital Cost Methodology ................................................................ 6-102

6.2.5.1 Purchased Equipment Costs: Biological Treatment 

System Cost ........................................................................ 6-102

6.2.5.2 Purchased Equipment Costs: Heat Exchanger Cost.............. 6-104

6.2.5.3 Purchased Equipment Costs: Backwash Recycle Pumps 

Cost .................................................................................... 6-107

6.2.5.4 Purchased Equipment Costs: ORP Monitor ......................... 6-108

6.2.5.5 Purchased Equipment Costs: Sodium Bisulfite Addition ..... 6-108

6.2.5.6 Direct Capital Costs ............................................................ 6-111

6.2.5.7 Indirect Capital Costs .......................................................... 6-116

6.2.6 O&M Cost Methodology .................................................................. 6-118

6.2.6.1 Operating Labor Cost .......................................................... 6-119

6.2.6.2 Maintenance Labor Cost ..................................................... 6-120

6.2.6.3 Maintenance Materials Cost ................................................ 6-122

6.2.6.4 Chemical Purchase Cost ...................................................... 6-123

6.2.6.5 Energy Cost ........................................................................ 6-126

6.2.7 Sludge Disposal Cost ........................................................................ 6-130

6.2.8 Compliance Monitoring Cost ............................................................ 6-131

6.2.9 Impoundment Operation Cost ........................................................... 6-131

6.2.10 FGD System Outage Costs ............................................................... 6-131

6.2.11 Results and Summary of Costs ......................................................... 6-132

6.3 Evaporation .................................................................................................. 6-132

6.3.1 Technology Description.................................................................... 6-132

6.3.2 Population Costed............................................................................. 6-134

6.3.3 Credit for Evaporation Treatment in Place ........................................ 6-134

6.3.4 Input Table ....................................................................................... 6-134

6.3.5 Capital Cost Methodology ................................................................ 6-135

6.3.5.1 Purchased Equipment Costs: Brine Concentrator and 

Crystallizer Cost ................................................................. 6-135

6.3.5.2 Purchased Equipment Costs: Softening Equipment Cost ..... 6-136

6.3.5.3 Purchased Equipment Costs: Redundant Equipment Costs .. 6-136

6.3.5.4 Purchased Equipment Costs: Chemical Feed System 

Costs ................................................................................... 6-137

6.3.5.5 Purchased Equipment Installation Cost ............................... 6-140

6.3.5.6 Indirect Capital Costs .......................................................... 6-141

6.3.6 O&M Cost Methodology .................................................................. 6-142

6.3.6.1 Operating Labor Cost .......................................................... 6-142

6.3.6.2 Maintenance Labor and Maintenance Materials Cost ........... 6-143

6.3.6.3 Chemical Purchase Cost ...................................................... 6-144

6.3.6.4 Energy Cost ........................................................................ 6-147

6.3.7 Sludge Disposal Cost ........................................................................ 6-149

6.3.8 Compliance Monitoring Cost ............................................................ 6-149

6.3.9 Surface Impoundment Operation Cost .............................................. 6-149

6.3.10 FGD System Outage Costs ............................................................... 6-149
Table of Contents 

Table of Contents (Continued) 

Page 

v 

6.3.11 Results and Summary of Costs ......................................................... 6-150

6.4 FGD Wastewater Costs Sensitivity Analyses ................................................ 6-150

6.4.1 Biological Treatment Cost: Sodium Bisulfite O&M Cost

Analysis ........................................................................................... 6-151

6.4.2 Biological Treatment Cost: Denitrification Cost Analysis ................. 6-153

6.5 References ................................................................................................... 6-154

7. FLY ASH TRANSPORT WATER COST METHODOLOGY ..................................................... 7-1

7.1 Conversion of Wet Fly Ash Handling Systems to Dry Vacuum Fly Ash 

Handling Systems ............................................................................................ 7-1

7.1.1 Technology Description........................................................................ 7-2

7.1.2 Population Costed................................................................................. 7-4

7.1.3 Fly Ash Handling Equipment Reused in the Conversion ....................... 7-5

7.1.4 Input Table ........................................................................................... 7-5

7.1.5 Capital Cost Methodology .................................................................... 7-7

7.1.5.1 Purchased Equipment Costs: Conveyance Equipment ............ 7-8

7.1.5.2 Purchased Equipment Cost: Silo............................................7-11

7.1.5.3 Purchased Equipment Cost: Pugmill......................................7-14

7.1.5.4 Direct Capital Costs ..............................................................7-15

7.1.5.5 Indirect Capital Costs ............................................................7-17

7.1.6 O&M Cost Methodology .................................................................... 7-19

7.1.6.1 Conveyance O&M Costs: Operating Labor ...........................7-19

7.1.6.2 Conveyance O&M Costs: Maintenance Labor .......................7-21

7.1.6.3 Conveyance O&M Costs: Energy Cost..................................7-22

7.1.6.4 Conveyance O&M Costs: Maintenance Materials .................7-24

7.1.6.5 Conveyance O&M Costs: Maintenance Outage .....................7-24

7.1.6.6 Intermediate Storage O&M Costs: Operating Labor ..............7-25

7.1.6.7 Intermediate Storage O&M Costs: Maintenance Labor..........7-27

7.1.6.8 Intermediate Storage O&M Costs: Energy Cost ....................7-28

7.1.6.9 Intermediate Storage O&M Costs: Maintenance Materials ....7-29

7.1.7 Fly Ash Disposal Costs ....................................................................... 7-31

7.1.8 Impoundment Operation Costs ........................................................... 7-32

7.1.9 Recurring Costs .................................................................................. 7-32

7.1.10 Fly Ash Outage Costs ......................................................................... 7-34

7.1.11 Results and Summary of Costs ........................................................... 7-35

7.2 Vactor Truck Collection ................................................................................. 7-35

7.2.1 Technology Description...................................................................... 7-35

7.2.2 Population Costed............................................................................... 7-35

7.2.3 Input Table ......................................................................................... 7-36

7.2.4 Capital Cost Methodology .................................................................. 7-36

7.2.4.1 Total Capital Cost: Vactor Conveyance Equipment ...............7-36

7.2.4.2 Total Capital Cost: Vactor Indirect Capital Costs ..................7-37

7.2.5 O&M Cost Methodology .................................................................... 7-38

7.2.5.1 Total O&M Costs: Vactor Conveyance O&M Cost ...............7-38
Table of Contents 

Table of Contents (Continued) 

Page 

vi 

7.2.5.2 Total O&M Costs: Vactor Intermediate Storage O&M 

Cost ......................................................................................7-39

7.2.6 Fly Ash Disposal Costs ....................................................................... 7-40

7.2.7 Impoundment Operation Costs ........................................................... 7-41

7.2.8 Fly Ash Outage Costs ......................................................................... 7-41

7.2.9 Results and Summary of Costs ........................................................... 7-41

7.3 References ..................................................................................................... 7-41

8. BOTTOM ASH TRANSPORT WATER COST METHODOLOGY.............................................. 8-1

8.1 Mechanical Drag System.................................................................................. 8-1

8.1.1 Technology Description........................................................................ 8-1

8.1.2 Population Costed................................................................................. 8-2

8.1.3 Input Table ........................................................................................... 8-3

8.1.4 Capital Cost Methodology .................................................................... 8-4

8.1.4.1 MDS Purchased Equipment Cost: Conveyance 

Equipment ............................................................................. 8-5

8.1.4.2 MDS Direct Capital Costs ...................................................... 8-6

8.1.4.3 MDS Indirect Capital Costs.................................................... 8-6

8.1.5 O&M Cost Methodology ...................................................................... 8-8

8.1.5.1 MDS Conveyance O&M Costs: Operating Labor ................... 8-8

8.1.5.2 MDS Conveyance O&M Costs: Maintenance Labor .............. 8-9

8.1.5.3 MDS Conveyance O&M Costs: Energy Cost ........................8-10

8.1.5.4 MDS Conveyance O&M Costs: Maintenance Materials ........8-12

8.1.5.5 MDS Intermediate Storage O&M Cost: Operating Labor ......8-13

8.1.5.6 MDS Intermediate Storage O&M Costs: Maintenance 

Labor ....................................................................................8-14

8.1.5.7 MDS Intermediate Storage O&M Costs: Energy Cost ...........8-14

8.1.5.8 MDS Intermediate Storage O&M Costs: Maintenance 

Materials ...............................................................................8-16

8.1.5.9 Wet Sluicing O&M Costs: Operating Labor ..........................8-16

8.1.5.10 Wet Sluicing O&M Costs: Maintenance Labor......................8-17

8.1.5.11 Wet Sluicing O&M Costs: Energy Cost ................................8-18

8.1.5.12 Wet Sluicing O&M Costs: Maintenance Materials ................8-20

8.1.6 MDS Results ...................................................................................... 8-21

8.2 Remote Mechanical Drag System ................................................................... 8-21

8.2.1 Technology Description...................................................................... 8-21

8.2.2 Population Costed............................................................................... 8-22

8.2.3 Input Table ......................................................................................... 8-22

8.2.4 Capital Cost Methodology .................................................................. 8-23

8.2.4.1 Remote MDS Purchased Equipment Cost: Conveyance 

Equipment ............................................................................8-23

8.2.4.2 Remote MDS Purchase Equipment Cost: Recycle Pump .......8-24

8.2.4.3 Remote MDS Purchased Equipment Cost: Chemical Feed 

System ..................................................................................8-25

8.2.4.4 Remote MDS Building Cost ..................................................8-26
Table of Contents 

Table of Contents (Continued) 

Page 

vii 

8.2.4.5 Remote MDS Direct Capital Costs ........................................8-27

8.2.4.6 Remote MDS Indirect Capital Cost .......................................8-28

8.2.5 O&M Cost Methodology .................................................................... 8-30

8.2.5.1 Remote MDS Conveyance O&M Costs: Mechanical 

Drag System .........................................................................8-30

8.2.5.2 Remote MDS Conveyance O&M Costs: Chemical 

Purchase Cost .......................................................................8-30

8.2.5.3 Remote MDS Conveyance O&M Costs: Energy Cost ...........8-31

8.2.5.4 Remote MDS Intermediate Storage O&M Costs ...................8-34

8.2.6 Remote MDS Results ......................................................................... 8-34

8.3 Bottom Ash Disposal Costs ............................................................................ 8-34

8.4 Impoundment Operation Costs ....................................................................... 8-35

8.5 Bottom Ash Management Costs ..................................................................... 8-35

8.5.1 Population Costed............................................................................... 8-36

8.5.2 One-Time Cost Methodology ............................................................. 8-36

8.5.3 Capital Cost Methodology .................................................................. 8-37

8.5.4 O&M Cost Methodology .................................................................... 8-37

8.6 Bottom Ash Outage Costs .............................................................................. 8-37

8.7 Recurring Costs ............................................................................................. 8-38

8.8 Selection of Dry Bottom Ash Handling Technology ....................................... 8-42

8.9 Results and Summary of Costs ....................................................................... 8-43

8.10 References ..................................................................................................... 8-43

9. COMBUSTION RESIDUAL LEACHATE COST METHODOLOGY ........................................... 9-1

9.1 Technology Description ................................................................................... 9-1

9.2 Population Costed ............................................................................................ 9-2

9.3 Input Table....................................................................................................... 9-2

9.4 Capital Cost Methodology ................................................................................ 9-3

9.5 O&M Cost Methodology ................................................................................. 9-3

9.6 Sludge Disposal Cost ....................................................................................... 9-3

9.7 Compliance Monitoring Cost ........................................................................... 9-3

9.8 Surface Impoundment Operation Costs ............................................................ 9-3

9.9 Treatment System Outage Costs ....................................................................... 9-4

9.10 Results and Summary of Costs ......................................................................... 9-4

9.11 References ....................................................................................................... 9-4

10. GASIFICATION WASTEWATER COST METHODOLOGY ................................................... 10-1

10.1 Population Costed .......................................................................................... 10-1

10.2 Cost Methodology .......................................................................................... 10-1

10.3 References ..................................................................................................... 10-1

11. FGD WASTEWATER POLLUTANT LOADINGS ............................................................... 11-1

11.1 Effluent Concentration Methodology ............................................................. 11-2

11.1.1 Surface Impoundment Effluent Concentration .................................... 11-4
Table of Contents 

Table of Contents (Continued) 

Page 

viii 

11.1.1.1 Effluent Concentration using FGD Surface Impoundment 

Effluent Concentrations ........................................................11-5

11.1.1.2 Effluent Characterization Using FGD Purge Wastewater 

Concentrations ......................................................................11-5

11.1.1.3 Effluent Characterization for Conventional and 

Nonconventional Pollutants ..................................................11-8

11.1.2 Chemical Precipitation Effluent Characterization................................ 11-9

11.1.3 Biological Treatment Effluent Characterization ................................ 11-10

11.1.4 Evaporation Effluent Characterization .............................................. 11-11

11.1.5 Pollutant Concentration Basis for Loadings Calculations .................. 11-12

11.1.5.1 Pollutant Concentrations for Surface Impoundment 

Effluent ............................................................................... 11-12

11.1.5.2 Pollutant Concentrations for Chemical Precipitation 

Effluent ............................................................................... 11-12

11.1.5.3 Pollutant Concentrations for Biological Treatment 

Effluent ............................................................................... 11-15

11.1.5.4 Pollutant Concentrations for Evaporation Effluent .............. 11-19

11.2 FGD Wastewater Flow Rates ....................................................................... 11-19

11.3 Pollutant Loadings Calculations ................................................................... 11-20

11.3.1 Baseline Loadings ............................................................................ 11-20

11.3.2 Chemical Precipitation Loadings ...................................................... 11-21

11.3.3 Biological Treatment Loadings ......................................................... 11-21

11.3.4 POTW Removals .............................................................................. 11-22

11.4 Pollutant Loadings and TWPE Results ......................................................... 11-22

11.5 References ................................................................................................... 11-23

12. ASH TRANSPORT WATER POLLUTANT LOADINGS ........................................................ 12-1

12.1 Data Sources .................................................................................................. 12-2

12.1.1 EPA Detailed Study Ash Impoundment Sampling Data ...................... 12-5

12.1.2 Steam Electric Technical Questionnaire Database ............................... 12-6

12.1.3 Electrical Power Research Institute Reports ........................................ 12-6

12.1.4 Permit Application Data ..................................................................... 12-7

12.1.5 1982 Technical Development Document ............................................ 12-8

12.1.6 Data Submitted by Duke Energy ......................................................... 12-9

12.1.7 Data Submitted by Hoosier Energy Rural Electric Cooperative ......... 12-10

12.1.8 Data Submitted by UWAG ............................................................... 12-10

12.1.8.1 UWAG Public Comment Data ............................................ 12-10

12.1.8.2 November 2014 Bottom Ash Transport Water Data ............ 12-12

12.2 Loadings Calculation Methodology .............................................................. 12-12

12.2.1 Impoundment Type Pollutant Concentration Methodology ............... 12-13

12.2.2 Baseline Flow Rate Methodology ..................................................... 12-14

12.2.3 Regulatory Option Flow Rate Methodology...................................... 12-14

12.2.4 Ash Loadings Calculation ................................................................. 12-15

12.2.5 Breakout of Combined Ash Loadings ............................................... 12-16

12.3 Pollutant Loadings and TWPE Results ......................................................... 12-17
Table of Contents 

Table of Contents (Continued) 

Page 

ix 

12.4 Sensitivity Analyses ..................................................................................... 12-18

12.4.1 Sulfide Sensitivity Analysis .............................................................. 12-18

12.4.2 Settled Bottom Ash Sluice Sensitivity Analysis ................................ 12-19

12.4.3 Inclusion of Data Submitted Late ...................................................... 12-19

12.5 References ................................................................................................... 12-20

13. COMBUSTION RESIDUAL LEACHATE POLLUTANT LOADINGS ........................................ 13-1

13.1 Wastewater Characterization and Data Sources .............................................. 13-1

13.2 Wastewater Flow Rates .................................................................................. 13-3

13.3 Pollutant Loadings and Toxic-Weighted Pound Equivalent (TWPE) 

Results ........................................................................................................... 13-3

13.4 References ..................................................................................................... 13-5

14. GASIFICATION POLLUTANT LOADINGS ........................................................................ 14-1

15. SUMMARY OF COSTS AND POLLUTANT REMOVALS BY REGULATORY OPTION .............. 15-1

16. CLEAN POWER PLAN .................................................................................................. 16-1

16.1 Methodology for Incorporating the CPP ......................................................... 16-1

16.2 Summary of Costs and Pollutant Removals by Regulatory Option 

Accounting for the CPP.................................................................................. 16-2

16.3 References ..................................................................................................... 16-3

17. EVALUATION OF COST AND POLLUTANT REMOVAL ESTIMATES ................................... 17-1

17.1 Verifying Cost Data Against Acceptance Specifications ................................. 17-1

17.2 Verifying Analytical Data against acceptance Specifications .......................... 17-2

17.3 Developing and Checking the Cost and Loadings Models .............................. 17-3

17.4 Evaluating Cost Estimate Quality ................................................................... 17-4

17.5 References ..................................................................................................... 17-5

Appendix A: Plant Specific Incremental Costs and Pollutant Removal Data Accounting for 

CCR and CPP 

Appendix B: Plant Specific Incremental Costs and Pollutant Removal Data With and Without 

Accounting for CCR 
List of Tables 

x 

List of Tables 

Page

Table 1-1. Technology Cost Modules Used to Estimate Compliance Costs for 

All Regulatory Options ................................................................................................ 1-2

Table 2-1. Technology Cost Modules Used to Estimate Compliance Costs .............................. 2-7

Table 2-2. Technology Cost Modules Used to Estimate Compliance Costs by Regulatory 

Option ......................................................................................................................... 2-8

Table 3-1. Summary of Data Submitted by Industry and State Agencies.................................3-15

Table 3-2. Reports and Studies Submitted to EPA from EPRI ................................................3-16

Table 4-1. CCR Rule Compliance Approaches and Overlap with ELG Costs/Loadings ..........4-33

Table 4-2. Number of Steam Electric Plants and Generating Units Expected to Incur 

Compliance Costs by Wastestream and Regulatory Option Accounting for CCR ........4-33

Table 4-3. Number of Steam Electric Plants and Generating Units Expected to Achieve 

Pollutant Removals by Wastestream and Regulatory Option Accounting for CCR ......4-33

Table 4-4. FGD Treatment-In-Place Input Table Not Accounting for CCR .............................4-34

Table 5-1. Compliance Monitoring Labor Requirements ........................................................5-25

Table 5-2. Compliance Monitoring Sampling Materials .........................................................5-27

Table 5-3. Compliance Monitoring Sample Analysis ..............................................................5-28

Table 5-4. Capital Costs of 7-Acre Landfill Expansion from CH2MHILL ..............................5-28

Table 5-5. O&M Costs of 7-Acre Landfill Expansion from CH2MHILL ................................5-29

Table 5-6. Revised Modular Annual Revenue Requirements by Process Area for 

Direct Ponding of Nonhardening Ash without Water Reuse ........................................5-29

Table 5-7. Calculated Unitized Cost Values for Impoundment Operating Costs......................5-30

Table 5-8. Cost Factors Relative to 500-MW Plant .................................................................5-30

Table 6-1. Unit FRP Pipe Costs ............................................................................................ 6-156

Table 6-2. Expected Pretreated FGD Wastewater Characteristics for Design of the 

Biological Treatment Stage ....................................................................................... 6-156
List of Tables 

List of Tables (Continued)

Page 

xi 

Table 11-1. Data Sets Used in Developing Effluent Characterization Data for 

Surface Impoundments ............................................................................................. 11-25

Table 11-2. Average Effluent Concentrations from FGD Surface Impoundments ................. 11-26

Table 11-3. Characteristics of FGD Blowdown at EPRI Sites P, R, and S ............................. 11-27

Table 11-4. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y............................ 11-29

Table 11-5. Data Sets Used in Developing Effluent Characterization Data for 

Chemical Precipitation.............................................................................................. 11-31

Table 11-6. Average Effluent Concentration of Chemical Precipitation System .................... 11-32

Table 11-7. Data Sets Used in Developing Effluent Characterization Data for 

Biological Treatment ................................................................................................ 11-33

Table 11-8. Average Effluent Concentration of Chemical Precipitation System with 

Biological Treatment ................................................................................................ 11-34

Table 11-9. Data Sets Used in Developing Effluent Characterization Data for 

Evaporation Treatment ............................................................................................. 11-34

Table 11-10. Average Effluent Concentration of Evaporation Treatment .............................. 11-35

Table 11-11. Pollutant Concentration Basis for Surface Impoundments ................................ 11-36

Table 11-12. Pollutant Concentration Basis for Chemical Precipitation ................................ 11-37

Table 11-13. Pollutant Concentration Basis for Biological Treatment ................................... 11-38

Table 11-14. Pollutant Concentration Basis for Evaporation ................................................. 11-39

Table 11-15. Industry-Level FGD Wastewater Loadings Excluding BOD, COD, TDS, 

and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing 

Technology Basis ..................................................................................................... 11-40

Table 11-16. FGD Wastewater Pollutant Removals Excluding BOD, COD, TDS, and 

TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing 

Technology Basis ..................................................................................................... 11-40

Table 12-2. Average Effluent Concentration of Fly Ash Impoundments ............................... 12-25

Table 12-3. Average Effluent Concentration of Bottom Ash Impoundments ......................... 12-26

Table 12-4. Average Effluent Concentration of Combined Ash Impoundments .................... 12-27
List of Tables 

List of Tables (Continued)

Page 

xii 

Table 12-5. Percent Loadings for Fly Ash and Bottom Ash in Combined 

Ash Surface Impoundments ...................................................................................... 12-28

Table 12-6. Industry-Level Loadings and Pollutant Removals Excluding BOD, COD, 

TSS, and TDS and Based on Oil-Fired Units and Units 50 MW or Less Not 

Installing Technology Basis ...................................................................................... 12-29

Table 12-7. Results of Ash Loadings Baseline Calculation Excluding BOD, COD, TSS, 

and TDS ................................................................................................................... 12-30

Table 12-8. Sensitivity Analysis Results for Total Industry Loadings Based on Inclusion 

of Late Submission UWAG Data Excluding BOD, COD, TSS, and TDS .................. 12-30

Table 13-1. Average Untreated Combustion Residual Leachate Concentrations .....................13-6

Table 13-2. Average Chemical Precipitation Effluent Concentrations for Combustion 

Residual Leachate .......................................................................................................13-7

Table 13-3. Average Chemical Precipitation followed by Biological Treatment Effluent 

Concentration for Combustion Residual Leachate .......................................................13-8

Table 13-4. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, 

COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not 

Installing Technology Basis ........................................................................................13-9

Table 13-5. Combustion Residual Landfill Leachate Loadings Removals Excluding 

BOD, COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or 

Less Not Installing Technology Basis .........................................................................13-9

Table 15-1. Treatment Technologies Basis for Estimating Compliance Costs and 

Pollutant Loadings by Regulatory Option ...................................................................15-3

Table 15-2. Cost of Implementation by Regulatory Option [In millions of pre-tax 2010 

dollars] .......................................................................................................................15-4

Table 15-3. Estimated Pollutant Removals by Regulatory Option ...........................................15-4

Table 16-1. Number of Steam Electric Plants and Generating Units Expected to Incur 

Compliance Costs by Wastestream and Regulatory Option Accounting for CCR 

and CPP......................................................................................................................16-4

Table 16-2. Number of Steam Electric Plants and Generating Units Expected to Achieve 

Pollutant Removals by Wastestream and Regulatory Option Accounting for CCR 

and CPP......................................................................................................................16-4
List of Tables 

List of Tables (Continued)

Page 

xiii 

Table 16-3. Cost of Implementation by Regulatory Option Accounting for CCR and CPP 

[In millions of pre-tax 2010 dollars] ...........................................................................16-5

Table 16-4. Estimated Pollutant Removals by Regulatory Option Accounting for CCR 

and CPP......................................................................................................................16-5

Table 17-1. Pollution Control Technology Cost Data Acceptance Criteria ..............................17-7

Table 17-2. Monitoring Data Acceptance Criteria ..................................................................17-7

Table 17-3. Cost Estimate Quality Specifications ...................................................................17-8
List of Figures 

xiv 

List of Figures 

Page

Figure 2-1. Steam Electric Cost Model Flow Chart for FGD Wastewater and Combustion 

Residual Leachate ........................................................................................................ 2-5

Figure 2-2. Steam Electric Cost Model Flow Chart for Fly Ash and Bottom Ash 

Transport Water ........................................................................................................... 2-6

Figure 4-1. Map of Steam Electric Power Plants by Mean Daily Minimum Temperature ........4-35

Figure 6-1. Chemical Precipitation Treatment System .......................................................... 6-157

Figure 6-2. Solubilities of Metal Hydroxides and Sulfides as a Function of pH..................... 6-158

Figure 6-3. Two-Stage Biological Treatment System (System to follow Chemical 

Precipitation Pretreatment) ....................................................................................... 6-159

Figure 6-4. Mean Maximum Daily Temperature for July ...................................................... 6-160

Figure 6-5. Location of Plants Incurring Heat Exchanger Costs ............................................ 6-161

Figure 6-6. Chemical Precipitation and Softening Pretreatment for FGD Wastewater Prior 

to Evaporation .......................................................................................................... 6-162

Figure 6-7. Process Flow Diagram for an Evaporation System (System to Follow 

Chemical Precipitation Pretreatment) ........................................................................ 6-163

Figure 8-1. Mechanical Drag System......................................................................................8-45

Figure 8-2. Remote Mechanical Drag System .........................................................................8-45

Figure 12-1. Decision Tree for the Analytical Ash Data ....................................................... 12-31
Glossary 

xv 

Glossary

Administrator – The Administrator of the U.S. Environmental Protection Agency. 

Agency – U.S. Environmental Protection Agency. 

BAT – Best available technology economically achievable, as defined by Sections 301(b)(2)(A) 

and 304(b)(2)(B) of the CWA. 

BCT – The best conventional pollutant control technology, applicable to discharges of 

conventional pollutants from existing industrial point sources, as defined by Sections 

301(b)(2)(E) and 304(b)(4) of the CWA. 

Bioaccumulation – General term describing a process by which chemicals are taken up by an 

organism either directly from exposure to a contaminated medium or by consumption of food 

containing the chemical, resulting in a net accumulation of the chemical by an organism due to 

uptake from all routes of exposure. 

BMP – Best management practice. 

Bottom ash –The ash, including boiler slag, which settles in the furnace or is dislodged from 

furnace walls. Economizer ash is included when it is collected with bottom ash. 

BPT –The best practicable control technology currently available as defined by Sections 

301(b)(1) and 304(b)(1) of the CWA. 

CBI – Confidential Business Information. 

CCR – Coal combustion residuals. 

Clean Water Act (CWA) – The Federal Water Pollution Control Act Amendments of 1972 (33 

U.S.C. 1251 et seq.), as amended e.g., by the Clean Water Act of 1977 (Pub. L. 95–217), and the 

Water Quality Act of 1987 (Pub. L. 100–4). 

Combustion residuals – Solid wastes associated with combustion-related power plant processes, 

including fly and bottom ash from coal-, petroleum coke-, or oil-fired units; FGD solids; FGMC 

wastes; and other wastewater treatment solids associated with combustion wastewater. In 

addition to the residuals that are associated with coal combustion, this also includes residuals 

associated with the combustion of other fossil fuels. 

Combustion residual leachate – Leachate from landfills or surface impoundments containing 

combustion residuals. Leachate is composed of liquid, including any suspended or dissolved 

constituents in the liquid, that has percolated through waste or other materials emplaced in a 

landfill, or that passes through the surface impoundment’s containment structure (e.g., bottom, 

dikes, berms). Combustion residual leachate includes seepage and/or leakage from a combustion 

residual landfill or impoundment unit. Combustion residual leachate includes wastewater from 

landfills and surface impoundments located on non-adjoining property when under the 

operational control of the permitted facility. 
Glossary 

xvi 

Direct discharge – (a) Any addition of any “pollutant” or combination of pollutants to “waters of 

the United States from any “point source,” or (b) any addition of any pollutant or combination of 

pollutants to waters of the “contiguous zone” or the ocean from any point source other than a 

vessel or other floating craft which is being used as a means of transportation. This definition 

includes additions of pollutants into waters of the United States from: surface runoff which is 

collected or channeled by man; discharges through pipes, sewers, or other conveyance owned by 

a State, municipality, or other person which do not lead to a treatment works; and discharges 

through pipes, sewers, or other conveyances, leading into privately owned treatment works. This 

term does not include an addition of pollutants by any “indirect discharger.” 

Direct discharger – A facility that discharges treated or untreated wastewaters into waters of the 

United States. 

DOE – Department of Energy. 

Dry bottom ash handling system – A system that does not use water as the transport medium to 

convey bottom ash away from the boiler. It includes systems that collect and convey the ash 

without any use of water, as well as systems in which bottom ash is quenched in a water bath and 

then mechanically or pneumatically conveyed away from the boiler. Dry bottom ash handling 

systems do not include wet sluicing systems (such as remote MDS or complete recycle systems). 

Dry fly ash handling system – A system that does not use water as the transport medium to 

convey fly ash away from particulate collection equipment. 

Effluent limitation – Under Clean Water Act (CWA) section 502(11), any restriction, including 

schedules of compliance, established by a state or the Administrator on quantities, rates, and 

concentrations of chemical, physical, biological, and other constituents which are discharged 

from point sources into navigable waters, the waters of the contiguous zone, or the ocean, 

including schedules of compliance. 

EIA – Energy Information Administration. 

ELGs – Effluent limitations guidelines and standards. 

EO – Executive Order. 

EPA – U.S. Environmental Protection Agency. 

ESP – Electrostatic precipitator. 

Facility – Any NPDES “point source” or any other facility or activity (including land or 

appurtenances thereto) that is subject to regulation under the NPDES program. 

FGD – Flue gas desulfurization. 

FGD wastewater – Wastewater generated from the wet FGD scrubber system that comes into 

contact with the flue gas or the FGD solids, including but not limited to, the blowdown or purge 

from the FGD scrubber system, overflow or underflow from the solids separation process, FGD 
Glossary 

xvii 

solids wash water, and the filtrate from the solids dewatering process. Wastewater generated 

from cleaning the FGD scrubber, cleaning the FGD solids separation equipment, cleaning the 

FGD solids dewatering equipment, or that is collected in floor drains in the FGD process area is 

not considered FGD wastewater. 

FGD gypsum – Gypsum generated specifically from the wet FGD scrubber system, including 

any solids separation or solids dewatering processes. 

FGMC – Flue gas mercury control. 

FGMC system – An air pollution control system installed or operated for the purpose of 

removing mercury from flue gas. 

FGMC wastewater – Wastewater generated from an air pollution control system installed or 

operated for the purpose of removing mercury from flue gas. This includes wastewater 

associated with fly ash collection systems when the particulate control system follows the 

sorbent injection or other controls to remove mercury from flue gas. FGD wastewater generated 

at plants using oxidizing agents to remove mercury in the FGD system and not in a separate 

FGMC system is not included in this definition. 

Fly ash – The ash that is carried out of the furnace by a gas stream and collected by a capture 

device such as a mechanical precipitator, electrostatic precipitator, and/or fabric filters. 

Economizer ash is included in this definition when it is collected with fly ash. Ash is not 

included in this definition when it is collected in wet scrubber air pollution control systems 

whose primary purpose is particulate removal. 

Gasification wastewater – Wastewater generated at an integrated gasification combined cycle 

operation from the gasifier or the syngas cleaning, combustion, and cooling processes. 

Gasification wastewater includes, but is not limited to the following: sour/grey water; CO2/steam 

stripper wastewater; sulfur recovery unit blowdown, and wastewater resulting from slag handling 

or fly ash handling, particulate removal, halogen removal, or trace organic removal. Air 

separation unit blowdown, noncontact cooling water, and runoff from fuel and/or byproduct piles 

are not considered gasification wastewater. Wastewater that is collected intermittently in floor 

drains in the gasification process area from leaks, spills, and cleaning occurring during normal 

operation of the gasification operation is not considered gasification wastewater. 

Ground water – Water that is found in the saturated part of the ground underneath the land 

surface. 

IGCC – Integrated gasification combined cycle. 

Indirect discharge – Wastewater discharged or otherwise introduced to a POTW. 

IPM – Integrated Planning Model. 

Landfill – A disposal facility or part of a facility where solid waste, sludges, or other process 

residuals are placed in or on any natural or manmade formation in the earth for disposal and 

which is not a storage pile, a land treatment facility, a surface impoundment, an underground 
Glossary 

xviii 

injection well, a salt dome or salt bed formation, an underground mine, a cave, or a corrective 

action management unit. 

Low volume waste sources – Taken collectively as if from on source, wastewater from all 

sources except those for which specific limitations are otherwise established, including but not 

limited to the following: wastewaters from ion exchange water treatment systems, water 

treatment evaporator blowdown, laboratory and sampling streams, boiler blowdown, floor drains, 

cooling tower basin cleaning wastes, recirculating house service water systems, and wet scrubber 

air pollution control systems whose primary purpose is particulate removal. Sanitary wastes, air 

conditioning wastes, and wastewater from carbon capture or sequestration systems are not 

included in this definition.. 

MDS – Mechanical drag system. 

Mechanical Drag System – Bottom ash handling system that collects bottom ash from the bottom 

of the boiler in a water-filled trough. A drag chain operates in a continuous loop to drag bottom 

ash from the water trough up an incline, which dewaters the bottom ash by gravity, draining the 

water back to the trough as the bottom ash moves upward. The dewatered bottom ash is often 

conveyed to a nearby collection area, such as a small bunker outside the boiler building, from 

which it is loaded onto trucks and either sold or transported to a landfill. The MDS is considered 

a dry bottom ash handling system because the ash transport mechanism is the mechanical 

removal by the drag chain, not the water. 

Metal cleaning wastes – Any wastewater resulting from cleaning [with or without chemical 

cleaning compounds] any metal process equipment including, but not limited to, boiler tube 

cleaning, boiler fireside cleaning, and air preheater cleaning.

Mortality – Death rate or proportion of deaths in a population. 

NAICS – North American Industry Classification System. 

NPDES – National Pollutant Discharge Elimination System. 

NSPS – New Source Performance Standards. 

Oil-fired unit – A generating unit that uses oil as the primary or secondary fuel source and does 

not use a gasification process or any coal or petroleum coke as a fuel source. This definition does 

not include units that use oil only for start-up or flame-stabilization purposes. 

ORCR – Office of Resource Conservation and Recovery. 

Point source – Any discernable, confined, and discrete conveyance, including but not limited to, 

any pipe, ditch, channel, tunnel, conduit, well, discrete fissure, container, rolling stock, 

concentrationed animal feed operation, or vessel or other floating craft from which pollutants are 

or may be discharged. The term does not include agricultural stormwater discharges or return 

flows from irrigated agriculture. See CWA section 502(14), 33 U.S.C. 1362(14); 40 CFR 122.2. 
Glossary 

xix 

POTW – Publicly owned treatment works. See CWA Section 212, 33 U.S.C 1292; 40 CFR 

122.2, 403.3. 

Primary particulate collection system – The first place in the process where fly ash is collected, 

such as collection at an ESP or baghouse. For example, a coal combustion particulate collection 

system may include multiple steps including a primary particulate collection step such as ESP 

followed by other processes such as a fabric filter which would constitute a secondary particulate 

collection system. 

PSES – Pretreatment Standards for Existing Sources. 

PSNS – Pretreatment Standards for New Sources. 

Publicly Owned Treatment Works – Any device or system, owned by a state or municipality, 

used in the treatment (including recycling and reclamation) of municipal sewage or commercial 

or industrial wastes of a liquid nature that is owned by a state or municipality. This includes 

sewers, pipes, or other conveyances only if they convey wastewater to a POTW providing 

treatment. See CWA section 212, 33 U.S.C. 1292; 40 CFR 122.2. 

RCRA – The Resource Conservation and Recovery Act of 1976, 42 U.S.C. 6901 et seq. 

Remote MDS – Bottom ash handling system that collects bottom ash at the bottom of the boiler, 

then uses transport water to sluice the ash to a remote MDS that dewaters bottom ash using a 

similar configuration as the MDS. The remote MDS is considered a wet bottom ash handling 

system because the ash transport mechanism is water. 

RFA – Regulatory Flexibility Act. 

SBA – Small Business Administration. 

Sediment – Particulate material lying below water. 

Surface water – as All waters of the United States, including rivers, streams, lakes, reservoirs, 

and seas. 

Steam electric power plant wastewater - Wastewaters associated with or resulting from the 

combustion process, including ash transport water from coal-, petroleum coke-, or oil-fired units; 

air pollution control wastewater (e.g., FGD wastewater, FGMC wastewater, carbon capture 

wastewater); and leachate from landfills or surface impoundments containing combustion 

residuals. 

Toxic pollutants – As identified under the CWA, 65 pollutants and classes of pollutants, of which 

126 specific substances have been designated priority toxic pollutants. See Appendix A to 40 

CFR 423. 

Transport water –Wastewater that is used to convey fly ash, bottom ash, or economizer ash from 

the ash collection or storage equipment, or boiler, and has direct contact with the ash. Transport 

water does not include low volume, short duration discharges of wastewater from minor leaks 
Glossary 

xx 

(e.g., leaks from valve packing, pipe flanges, or piping) or minor maintenance events (e.g., 

replacement of valves or pipe sections). 

UMRA – Unfunded Mandates Reform Act. 

Wet bottom ash handling system – A system in which bottom ash is conveyed away from the 

boiler using water as the transport medium. Wet bottom ash systems typically send the ash slurry 

to dewatering bins or a surface impoundment. Wet bottom ash handling systems include systems 

that operate in conjunction with a traditional wet sluicing system to recycle all bottom ash 

transport water (remote MDS or complete recycle system). 

Wet FGD system – Wet FGD systems capture sulfur dioxide from the flue gas using a sorbent 

that has mixed with water to form a wet slurry, and that generates a water stream that exits the 

FGD scrubber absorber. 

Wet fly ash handling system – A system that conveys fly ash away from particulate removal 

equipment using water as the transport medium. Wet fly ash systems typically dispose of the ash 

slurry in a surface impoundment.
Section 1 – Introduction 

1-1 

1. INTRODUCTION 

This report describes the methodologies used to estimate plant-specific compliance costs 

(in 2010 dollars) associated with installing and operating the various technologies and practices 

that make up the regulatory options considered by EPA to revise the existing ELGs. In addition, 

this report presents the methodologies used to estimate baseline and post-compliance pollutant 

loadings and the corresponding pollutant removals associated with installing and operating these 

technologies and practices. 

In addition to this report and the Technical Development Document for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category (DCN SE05904), EPA has assembled a supplementary document titled “Supplemental 

Costs and Loadings Documentation” (DCN SE05839). This document, which can be found in 

the Steam Electric Rulemaking Record, includes the following detailed information: 

• Spreadsheets documenting development of input tables, cost factors, chemical 

dosage rates, and other cost elements. 

• Detailed cost information provided by vendors (including emails and/or telephone 

contact reports). 

• Equipment specifications provided by vendors. 

• Calculations performed using the cost information, including the generation of 

cost curves. 

Table 1-1 summarizes the regulatory options EPA analyzed for the final rule. These 

options vary in the stringency of control and affect the following wastestreams: 

• Wastewater generated from wet flue gas desulfurization (FGD) systems. 

• Fly ash transport water. 

• Bottom ash transport water.

• Leachate from landfills and surface impoundments containing combustion 

residuals. 

• Flue gas mercury control wastewater. 

• Gasification wastewater generated from integrated-gasification combined cycle 

(IGCC) steam electric power plants. 

Table 1-1 also identifies the specific technology cost elements used to estimate 

compliance costs for each regulatory option and identifies the specific section of this report 

where each cost element is discussed in more detail. 
Section 1 – Introduction 

1-2 

Table 1-1. Technology Cost Modules Used to Estimate Compliance Costs for 

All Regulatory Options 

Wastestream Technology Option 

Regulatory Option Report 

Section b A B C D E F

a

FGD Wastewater 

Chemical Precipitation X X X X X X 6,11

Biological Treatment X X X X

Evaporation X

Fly Ash Transport Water Dry Fly Ash Handling X X X X X X 7,12

Bottom Ash Transport Water Dry Bottom Ash 

Handling/Closed-Loop X c

 X X X 8,12 

Combustion Residual Leachate Chemical Precipitation X X 9,13

Gasification Wastewater Evaporation X X X X X X 10, 14

Flue Gas Mercury Control 

Wastes Dry Handling X X X X X X NA 

Other Plant-Level Costs

Solids Transportation X X X X X X 5

Solids Disposal X X X X X X 5

Impoundments X X X X X X 5

 Compliance Monitoring X X X X X X 5 

NA – Not applicable. EPA determined that, based on current practices, there would be no incremental compliance 

costs or pollutant loadings for these wastestreams; see Section 9.2 of the Technical Development Document for the 

Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(DCN SE05904). 

a – During development of the final rule, EPA decided not to base the final rule on Option F for existing sources due 

primarily to the high cost of that option, particularly in light of the costs associated with other rulemakings expected 

to impact the steam electric power generating industry (see Section VIII.C.1 of the preamble). As a result, EPA 

chose not to conduct particular analyses for Option F to the same extent that it did for some of the other options 

considered. 

b – Sections 5 through 10 of this document include more detailed descriptions of the cost methodologies for these 

technology options and Sections 11 through 14 provide more detailed descriptions of the estimated pollutant 

removals for each technology. 

c – Dry bottom ash handling or closed-loop required only for generating units with a capacity greater than or equal 

to 400 MW. Effluent requirements for bottom ash transport water from all other generating units would be set equal 

to existing BPT limitations for TSS; thus, generating units smaller than 400 MW would not install dry bottom ash 

handling to comply with the ELGs. 

In the remainder of this document, EPA presents the analytical results only for Options A 

through E for existing sources. During development of the final rule, EPA decided not to base 

the final rule on Option F for existing sources due primarily to the high cost of that option, 

particularly in light of the costs associated with other rulemakings expected to impact the steam 

electric power generating industry (see Section VIII.C.I of the preamble). As a result, EPA chose 

not to conduct particular analyses for Option F to the same extent that it did for some of the other 

options considered. 

For each of the regulatory options, EPA estimated plant-specific compliance costs for 

each of the individual treatment technologies that comprise the regulatory options using the 

methodologies described in this report. These technology-specific costs, broken down into 
Section 1 – Introduction 

1-3 

capital and operation and maintenance (O&M) (i.e., annual, 3-year, 5-year, 6-year, and 10-year) 

costs, were then summed, as appropriate, to estimate plant-specific costs for each regulatory 

option. All costs were calculated in 2010 dollars. Note that the compliance costs calculated for 

this rulemaking are incremental, meaning they represent the costs expected to be incurred by 

plants to revise existing operations to match those that form the bases of the regulatory options. 

EPA also estimated plant-specific baseline and post-compliance pollutant loadings 

associated with each of the individual treatment technologies that comprise the regulatory 

options, and then summed them, as appropriate, to calculate industry-level baseline and postcompliance pollutant loadings for each regulatory option. EPA then estimated the pollutant 

removals associated with the regulatory options by subtracting the post-compliance pollutant 

loadings from the baseline pollutant loadings. Note that these pollutant removal estimates are 

incremental, meaning they represent the pollutant removals expected to be achieved as a result of 

plants revising existing operations to match those that form the bases of the regulatory options. 

EPA estimated compliance costs and pollutant loadings several different ways to evaluate 

the effect of the final ELG on the steam electric power generating industry. EPA considered 

other rulemakings affecting the steam electric power generating industry in its analysis. Under 

one approach, EPA evaluated compliance costs and pollutant loadings taking into account 

changes that plants may make to implement the coal combustion residuals (CCR) rule (but not 

the Clean Power Plan (CPP)). The regulatory option compliance costs and pollutant loadings that 

take into account the CCR rule can be found in Section 15. Under a second approach, EPA 

evaluated compliance costs and pollutant loadings taking into account changes that plants may 

make to implement both the CCR rule and the CPP.1 The regulatory option compliance costs and 

pollutant loadings that take into account both the CCR and CPP can be found in Section 16. 

Under a third approach, EPA evaluated what the ELG costs and pollutant loadings would be if 

there were no changes to plant operations due to the CCR rule or CPP (in other words, what 

these costs and loadings would be if the CCR rule and CPP had not been promulgated). The 

plant-level estimated compliance costs and pollutant loadings for this “without CCR and CPP” 

scenario can be found in Appendix B. In general, values reported and discussed in this report 

refer to the compliance costs and pollutant loadings analysis with CCR only, unless otherwise 

noted. 

The following information is described in this report: 

• Section 2 describes the structure of the costs and loadings models. 

• Section 3 discusses the data sources used to generate the costs, loadings, and 

pollutant removal estimates. 

• Section 4 discusses the costs and loadings models inputs. 

• Section 5 describes the general cost methodology used to estimate compliance 

costs and common cost elements. 

 

1

 At the time EPA conducted these analyses, the CPP had not yet been finalized, and thus EPA used the proposed 

CPP for its analyses. 
Section 1 – Introduction 

1-4 

• Section 6 describes the cost methodology for treating FGD wastewater. 

• Section 7 describes the cost methodology for eliminating the discharge of fly ash 

transport water. 

• Section 8 describes the cost methodology for eliminating the discharge of bottom 

ash transport water. 

• Section 9 describes the cost methodology for treating combustion residual 

leachate. 

• Section 10 describes the cost methodology for treating gasification wastewater. 

• Section 11 describes the methodology used to estimate pollutant loadings and 

removals for FGD wastewater. 

• Section 12 describes the methodology used to estimate pollutant loadings and 

removals for both fly ash and bottom ash transport water. 

• Section 13 describes the methodology used to estimate pollutant loadings and 

removals for combustion residual leachate. 

• Section 14 describes the methodology used to estimate pollutant loadings and 

removals for gasification wastewater. 

• Section 15 summarizes costs and pollutant loadings and removals by regulatory 

option. 

• Section 16 described the methodology used to evaluate changes to the steam 

electric power generating industry resulting from the Clean Power Plan. 

• Section 17 describes EPA’s evaluation of the cost and pollutant removal 

estimates. 
Section 2 – Structure of Costs and Pollutant Loadings Models 

2-1 

2. STRUCTURE OF COSTS AND POLLUTANT LOADINGS 

MODELS 

EPA created two separate models associated with the regulatory options for the revisions 

to the steam electric effluent limitations guidelines and standards (ELGs). The first model 

calculates plant-specific compliance costs for each technology option associated with the 

regulatory options. The second model calculates plant-specific baseline pollutant discharge 

loadings for each wastestream evaluated, as well as post-compliance pollutant loadings and 

removals for each technology option for each wastestream. This section describes the structure of 

each of these models. All tables and figures referenced in this section are presented at the end of 

the section. 

2.1 COST MODEL

To generate industry incremental compliance cost estimates for the steam electric power 

generating industry, EPA developed a computer-based cost model made up of several individual 

technology cost modules. The cost model is executed on a personal computer and comprises a 

collection of programs written in Visual Basic® and data tables created in Microsoft Access® 

2007. Figure 2-1 and Figure 2-2, present flow diagrams of the cost model. The cost model can be 

grouped into four main components: 

• Plant-Specific Input Data. 

• Industry Assumptions/Factors. 

• Technology Cost Modules. 

• Model Outputs. 

Technology cost modules use the relevant input data and industry assumptions/factors to 

calculate plant-specific incremental compliance costs. Each technology cost module calculates 

costs for a specific cost component (e.g., transportation, disposal, ash silo cost, chemical 

precipitation system cost, etc.) for each plant. These individual cost components are then 

summed on a plant level to calculate an overall compliance cost for each plant for a specific 

technology option. Table 2-1 lists the technology cost modules and their use in calculating 

overall incremental compliance costs for each technology option. Table 2-2 shows how the 

individual technology cost modules are combined for each of the regulatory options considered 

by EPA.2

2.1.1 Input Data to Cost Model 

The cost model operates on one main input table, called the cost matrix. The cost matrix 

identifies which technology options apply to each plant. For example, if Plant X discharges fly 

ash transport water and untreated flue gas desulfurization (FGD) wastewater, but does not 

discharge bottom ash transport or combustion residual leachate, then the cost matrix would 

 

2

 The plant-level gasification costs are not calculated in the cost model, but rather, are calculated separately. Section 

10 describes the plant-level gasification costs and the results are presented in Appendix A and B to this report. 
Section 2 – Structure of Costs and Pollutant Loadings Models 

2-2 

indicate that this plant requires fly ash and FGD compliance costs, but does not require bottom 

ash or combustion residual leachate compliance costs.

Other plant-specific input data to the cost model includes the following: 

• FGD Data – plant-level indication that FGD wastewater is discharged and the 

plant-level FGD wastewater flow rate. 

• Fly Ash Data – amount of fly ash generated, amount of transport water generated, 

number of operating days, type (e.g., baseload, peaking), and capacity on a steam 

electric generating unit level. 

• Bottom Ash Data – amount of wet bottom ash generated, amount of transport 

water generated, number of operating days, type (e.g., baseload, peaking), and 

capacity on a steam electric generating unit level. 

• Landfill Data – plant-level indication that an on-site combustion residual landfill 

is present and whether combustion residual leachate is collected and discharged. 

• Surface Impoundment Data – plant-level indication that a combustion residual 

impoundment is present and whether combustion residual leachate is collected 

and/or treated. 

• Treatment-in-Place Data – plant-specific data for plants already operating relevant 

treatment systems, such as chemical precipitation, biological treatment, and 

evaporation, including the type of equipment at the plant and its capacity. 

Section 4 discusses inputs to the cost model in greater detail. 

2.1.2 Industry Assumptions/Factors 

Industry assumptions and factors are applicable to the entire industry and are not plantspecific. Each technology cost module has an individual set of assumptions/factors tables. These 

tables hold the constants and coefficients that the technology cost modules use to calculate 

capital and operation and maintenance (O&M) costs associated with each cost component. In 

addition, the following industry assumptions/factors data sets are used by multiple technology 

cost modules: 

• Cost Indices – cost index values from RS Means used to index all costs to 2010 

dollars. 

• Freight Costs – equipment-level shipping costs. 

The industry assumptions/factors used by the technology cost modules are identified 

within the capital and O&M cost equations in each technology cost module, as described in 

Section 5. 

2.1.3 Technology Cost Modules 

EPA developed the technology cost modules to calculate specific cost components, as 

listed below: 
Section 2 – Structure of Costs and Pollutant Loadings Models 

2-3 

• Biological Treatment – calculates capital and O&M costs associated with an 

anoxic/anaerobic biological treatment system. 

• Chemical Precipitation – calculates capital, O&M, and recurring costs associated 

with the chemical precipitation system. 

• Evaporation – calculates capital and O&M costs associated with the evaporation 

system. 

• Dry Fly Ash Handling – calculates capital, O&M, and recurring costs associated 

with the dry fly ash handling system. 

• Dry Bottom Ash Handling – calculates capital, O&M, one-time, and recurring 

costs associated with the dry and closed-loop recycle bottom ash handling system. 

• Transportation – calculates O&M costs associated with transporting FGD solids, 

ash, and/or combustion residual landfill leachate solids to an on-site or off-site 

landfill. 

• Disposal – calculates capital and O&M costs associated with disposing of FGD, 

ash, and/or combustion residual landfill leachate solid waste in an on- or off-site 

landfill. 

• Impoundment Operation – calculates O&M and recurring cost savings associated 

with no longer operating and maintaining an on-site impoundment. 

For each regulatory option, the cost model combines the plant-level outputs from a series 

of technology cost modules. Table 2-1 shows the various technology cost modules that are 

combined to calculate the technology option costs. The cost model uses Microsoft Access 2007 

queries to combine the cost components and calculate a total capital and O&M cost for each 

technology option. Table 2-2 lists the technology cost modules used to calculate the postcompliance cost for each regulatory option. 

2.1.4 Model Outputs 

The cost model output is a plant-level summary of the incremental technology option 

compliance costs. Each plant incurring a cost for a specified technology is presented in the model 

output. The incremental compliance costs are presented on two levels: 1) total plant-level cost; 

and 2) component-level cost. The total plant-level cost includes total capital and total O&M costs 

incurred by the plant for the technology option. The component-level costs provide more detail 

showing a breakdown of the individual cost components for each of the technology cost 

modules. The component-level costs include individual capital costs (e.g., equipment, 

installation, and engineering) and individual O&M costs (e.g., labor, materials, compliance 

monitoring, and chemicals). Plant-level cost model results are provided by technology option in 

Appendices A and B (see Sections 6, 7, 8, 9 and 10 for more details) and by regulatory option in 

Section 15. 

2.2 POLLUTANT LOADINGS MODEL

To calculate industry pollutant removals for the Steam Electric ELGs, EPA developed 

three databases in Microsoft Access 2007 to calculate baseline and post-compliance pollutant 
Section 2 – Structure of Costs and Pollutant Loadings Models 

2-4 

loadings associated with the discharge of FGD wastewater, fly and bottom ash transport water, 

and combustion residual leachate, respectively.3 Each of the three databases contains the 

following components: 

• Input table. 

• Baseline concentration data sets. 

• Technology option concentration data sets (where applicable). 

• Output baseline and post-compliance pollutant loadings. 

All three of the loadings databases were constructed in a similar fashion. The input tables 

hold plant-level data needed to calculate the baseline and post-compliance discharge loadings. 

The input tables for FGD, ash (includes both fly ash and bottom ash), and combustion residual 

leachate are discussed in more detail in Sections 4.1.1, 4.1.2, and 4.1.3, respectively. The 

baseline and technology option concentration data sets consist of analytical data used to calculate 

the average pollutant concentrations for each wastewater evaluated with and without the control 

afforded by the technology options. Because the dry fly ash handling technology option and the 

dry/closed-loop recycle bottom ash handling technology options result in zero discharge of fly 

ash and bottom ash transport water, the average technology option pollutant concentrations for 

fly and bottom ash are zero. The average baseline and technology option (i.e., post-compliance) 

pollutant concentrations, together with data from the input table, are used to calculate baseline 

and post-compliance pollutant loadings at a plant level. EPA calculates the baseline and postcompliance pollutant loadings in both pounds and toxic-weighted pound equivalents (TWPE).4

See Sections 11 through 14 for more detail on the loadings calculation methodology and results 

for each technology option. 

2.3 REFERENCES

1. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development 

Document for the Final Effluent Limtations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category. (30 September). DCN SE05904.

 

3

 EPA determined that, based on current practices, there would be no incremental pollutant removals for flue gas 

mercury control or gasification wastewater. See Section 10 of the Technical Development Document for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 

2015]. 

4

 EPA uses toxic weighting factors (TWFs) to account for differences in toxicity across pollutants. EPA calculated a 

TWPE value for each pollutant discharged to compare mass loadings of different pollutants based on their toxicity. 
Section 2 – Structure of Costs and P

2-5 

Figure 2-1. Steam Electric Cost Model Flow Chart for FGD Wastewater and Combustion Residu
Section 2 – Structure of Costs and P

2-6 

Figure 2-2. Steam Electric Cost Model Flow Chart for Fly Ash and Bottom Ash Transport W
Section 2 – Structure of Costs and P

2-7 

Table 2-1. Technology Cost Modules Used to Estimate Compliance Costs 

Technology Option 

Technology Cost Module

Chemical 

Precipitation 

Biological 

Treatment 

Evaporation 

Dry Fly Ash 

Handling 

Dry Bottom Ash 

Handling 

a

Compliance 

Monitoring 

FGD Wastewater Treatment: Chemical Precipitation   FGD Wastewater Treatment: Chemical Precipitation + Biological Treatment    FGD Wastewater Treatment: Chemical Precipitation + Evaporation    Fly Ash: Zero discharge  Bottom Ash: Zero discharge  Combustion Residual Leachate Wastewater Treatment: ChemicalPrecipitation   Gasification Wastewater b Note: EPA did not estimate costs for flue gas mercury control wastewater. a – The technology cost module is called “Dry Bottom Ash Handling” module, but it includes a technology option that is a closed-loop 

b – The plant-level gasification costs are not calculated in the cost model, but rather, are calculated separately. The plant-level gasificatiSection 10 and the results are presented in Appendices A and B to this report. 
Section 2 – Structure of Costs and P

2-8 

Table 2-2. Technology Cost Modules Used to Estimate Compliance Costs by Regulatory O

Wastestream 

Technology Cost 

Modules/Technology Option 

Regulatory Option 

A B C D 

FGD Wastewater 

Chemical Precipitation     

Biological Treatment    Evaporation 

Fly Ash Transport Water Dry Fly Ash Handling     Bottom Ash Transport Water Dry Bottom Ash Handling b  c  Combustion Residual Leachate Chemical Precipitation Gasification Wastewater Evaporation     Flue Gas Mercury Control Wastes d Zero Discharge     

Other Costs Not Specific to Wastestream 

 Solids Transportation      Solids Disposal      Impoundments      Compliance Monitoring     

a – During development of the final rule, EPA decided not to base the final rule on Option F for existing sources due primarily to thparticularly in light of the costs associated with other rulemakings expected to impact the steam electric power generating industry (

the preamble). As a result, EPA chose not to conduct particular analyses for Option F to the same extent that it did for some of the ob – The technology cost module is called the “Dry Bottom Ash Handling” module, but it includes a technology option that is a closec – Dry bottom ash handling or closed-loop system is required only for generating units with a capacity greater than or equal to 400 

requirements for bottom ash transport water from all other generating units would be set equal to existing Best Practicable Control T

Available (BPT) limitations for total suspended solids (TSS); thus generating units smaller than 400 MW would not install dry botto

comply with the ELGs. d – EPA determined that, based on current practices, there would be no incremental compliance costs for flue gas mercury control w

EPA did not create technology cost modules for this wastestream. However, this wastestream is still considered in the regulatory op

presented in the table with the appropriate technology option. 
Section 3 – Data Sources 

3-1 

3. DATA SOURCES 

EPA collected and evaluated data from a variety of sources in the course of developing 

the revisions to the effluent limitations guidelines and standards (ELGs) for the Steam Electric 

Power Generating Point Source Category (Steam Electric Category). EPA used these data to 

develop the industry profile, determine the plant population that will be affected by the rule, 

evaluate industry subcategorization, identify plant-specific operations, and determine wastewater 

characteristics, technology options, compliance costs, baseline and pollutant loadings, postcompliance pollutant removals, and non-water quality environmental impacts. This section 

discusses these data sources used to revise the Steam Electric ELGs. Each section presents a data 

source and then describes how EPA used data from that source in its compliance cost and 

pollutant loadings calculations. All tables and figures referenced in this section are presented at 

the end of the section. 

3.1 STEAM ELECTRIC TECHNICAL QUESTIONNAIRE DATABASE

A principal source of information and data used in developing the ELGs are industry 

responses to the survey distributed by EPA under the authority of Section 308 of the Clean Water 

Act (CWA), 33 U.S.C. 1318. EPA distributed the Questionnaire for the Steam Electric Power 

Generating Effluent Guidelines (Steam Electric Survey) to 733 power plants in the summer of 

2010. EPA designed the industry survey to obtain technical information related to wastewater 

generation and treatment, and economic information such as costs of wastewater treatment 

technologies and financial characteristics of potentially affected companies. The Steam Electric 

Survey obtained the following types of information from the steam electric power generating 

industry: 

• General power plant operations. 

• Flue gas desulfurization (FGD) system operations. 

• Ash handling operations. 

• Pond/impoundment system and other wastewater treatment operations. 

• Metal cleaning process operations. 

• Pond/impoundment and landfill management practices. 

• Pond/impoundment and landfill leachate sampling data. 

• Nuclear power operations. 

• Economic and financial data. 

ERG used the responses from the 733 plants to develop a database that contained all the 

responses to the Steam Electric Survey. For more information on the development of the Steam 

Electric Survey, see Section 3 of the Technical Development Document for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category [U.S. EPA, 2015b]. The remainder of this section describes the data used in the 

calculation of compliance costs and pollutant loadings and removals estimates. 
Section 3 – Data Sources 

3-2 

3.1.1 Industry Factors 

EPA developed specific industry factors to use in the cost equations detailed in Sections 

5, 6, 7, 8, 9, and 10 based on evaluation and analysis of the Steam Electric Survey data. For 

example, many of the operation and maintenance (O&M) labor rates and hours per year used in 

the cost model were derived from rates and burdens reported in responses to the Steam Electric 

Survey. EPA also developed many of the direct and indirect capital cost factors used in the cost 

model from Steam Electric Survey data (e.g., installation and engineering overhead cost factors). 

Other cost elements (e.g., equipment capacity factors, materials of construction, and chemical 

dosage rates and sludge generation rates for chemical precipitation) were derived from Steam 

Electric Survey responses. The use of Steam Electric Survey data to derive industry 

assumptions/factors is described within the costing methodology in Sections 5, 6, 7, 8, 9, and 10 

and documented in the “Supplemental Costs and Loadings Documentation” [ERG, 2015]. 

3.1.2 Plant Characteristics 

The cost methodology uses certain plant-specific Steam Electric Survey data elements as 

cost model inputs for estimating plant-level compliance costs and generating unit-level 

compliance costs. Some examples include plant-specific FGD wastewater flow rates, ash 

generation rates, generating unit nameplate capacity, type of generating unit, generating unit 

operating hours per day, and technologies currently in place. The specific plant characteristic(s) 

used to calculate compliance costs for each treatment technology are detailed in the input table 

sections of Sections 6, 7, 8, 9, and 10. 

3.1.3 FGD Wastewater Loadings 

EPA used responses to the Steam Electric Survey and industry-submitted data to identify 

the population of plants that operate wet FGD scrubbers and discharge the wastewater to surface 

water or a publicly owned treatment works (POTW). For this population of plants, EPA used 

Steam Electric Survey responses to identify the flow rate of the FGD wastewater and calculate 

the amount of treated FGD wastewater that is recycled by the plant. EPA also used Steam 

Electric Survey data to estimate FGD wastewater pollutant loadings as described further in 

Sections 4.1.1 and 11. 

3.1.4 Ash Transport Water Loadings 

EPA used responses to the Steam Electric Survey and industry-submitted data to identify 

the population of plants that operate wet fly ash and/or wet bottom ash handling systems and 

discharge the ash transport water to surface water or a POTW. For this population of plants, EPA 

used Steam Electric Survey responses and industry-submitted data to identify the discharge flow 

rate of the fly ash transport water and bottom ash transport water and determined whether the 

waters are combined for treatment. EPA also used Steam Electric Survey responses to calculate 

the amount of bottom ash transport water that is recycled by the plant. Additionally, EPA used 

data from the Steam Electric Survey, industry-submitted data, and other data as described in 

Section 3 of the TDD, to characterize fly ash transport water, bottom ash transport water, and 

combined ash transport water, and use that characterization to estimate pollutant loadings as 

described further in Sections 4.1.2 and 12. 
Section 3 – Data Sources 

3-3 

3.1.5 Combustion Residual Leachate Loadings 

EPA used responses to the Steam Electric Survey to identify the population of plants that 

collect and discharge combustion residual leachate from landfills and/or impoundments 

containing combustion residuals to surface water or a POTW. For this population of plants, EPA 

used Steam Electric Survey responses to identify the flow rate of the combustion residual 

leachate and calculate the amount of combustion residual leachate that is recycled by the plant. 

EPA also used Steam Electric Survey data to characterize the combustion residual leachate 

wastestream as well as to estimate the combustion residual leachate pollutant loadings as 

described further in Sections 4.1.3 and 13. 

3.2 TECHNOLOGY VENDOR DATA

EPA gathered data regarding the technologies used in the industry from technology 

vendors through presentations, conferences, meetings, and email and telephone contacts. The 

data collected informed the development of the detailed study, the Steam Electric Survey, 

technology costs, and loadings estimates. 

To gather information on FGD wastewater and combustion residual leachate treatment 

for the cost analyses, EPA contacted companies that manufacture, distribute, or install various 

components of chemical precipitation, biological, and/or evaporation wastewater treatment. The 

vendors provided the following types of information for EPA’s analyses: 

• Operating details. 

• Performance data. 

• Equipment used in the system. 

• Capital cost information on a component level and system level. 

• O&M costs. 

• Equipment and system energy requirements. 

To gather information on fly ash and bottom ash handling techniques, EPA also contacted 

several ash handling and ash storage vendors. The vendors provided the following types of 

information for EPA’s analyses: 

• The type of fly ash and bottom ash handling systems available for reducing or 

eliminating ash transport water. 

• Equipment, modifications, and demolition required to convert wet-sluicing fly ash 

and bottom ash handling systems to dry ash handling or closed-loop recycle 

systems.5 

• Equipment that can be reused as part of the conversion from wet to dry handling 

or in a closed-loop recycle system. 

 

5

 Throughout this report, EPA refers to bottom ash systems that eliminate the use of ash transport water as dry ash 

handling systems; however, some of these systems (e.g., mechanical drag system) still use water in a quench bath 

and, therefore, are not completely dry systems. 
Section 3 – Data Sources 

3-4 

• Outage time required to install or convert to the different types of ash handling 

systems. 

• Maintenance required for each type of system. 

• Operating data for each type of system. 

• Purchased equipment and other direct and indirect capital costs for fly ash and 

bottom ash conversions. 

• Specifications for the types of ash storage available (e.g., steel silos or concrete 

silos) for the different types of handling systems. 

• Equipment and installation capital costs associated with the storage of fly ash and 

bottom ash. 

• Additional equipment needed for redundancy. 

• O&M costs for fly ash and bottom ash handling systems. 

• System energy requirements. 

3.3 FIELD SAMPLING PROGRAM

EPA’s field sampling program consists of three distinct areas: EPA field sampling from 

the detailed study; EPA field sampling conducted as part of the rulemaking; and plant-collected 

samples analyzed by EPA. Each of these sampling programs is further described in Sections 

3.3.1, 3.3.2, and 3.3.3, respectively. 

3.3.1 Detailed Study Sampling Data 

As part of the detailed study undertaken prior to beginning the rulemaking process, EPA 

conducted a sampling program to characterize untreated wastewaters generated by coal-fired 

power plants, as well as to evaluate treatment technologies and best management practices for 

reducing pollutant discharges. Between July 2007 and October 2008, EPA collected and 

analyzed samples to characterize wastewater streams at six coal-fired power plants. EPA 

analyzed the samples for total metals (including 25 specific metals), hexavalent chromium, 

nitrogen compounds, and other classical analytes. Specifically, EPA characterized wastewater 

streams associated with wet FGD systems and ash handling operations and evaluated the 

capability of various types of treatment systems to remove metals and other pollutants prior to 

discharge. Four of the plants sampled operated some type of wet ash handling system (either wet 

bottom ash handling, wet fly ash handling, or both). The effluent samples collected from the ash 

surface impoundments at these four plants were collected as one-day grab samples and 

represented two fly ash surface impoundments, one bottom ash surface impoundment, and one 

surface impoundment that received both fly ash and bottom ash wastewater. EPA also collected 

samples from influent from the fly ash impoundment at one of the plants [U.S. EPA, 2009]. The 

surface impoundments at the four plants were categorized as follows: 

• Cardinal – Fly ash impoundment. 

• Homer City – Bottom ash impoundment. 

• Mitchell – Fly ash impoundment. 
Section 3 – Data Sources 

3-5 

• Widows Creek – Combined ash impoundment. 

As described in Section 12.1, data from the detailed study were used to identify pollutants 

of concern in ash transport water and to characterize ash impoundment effluent. 

3.3.2 EPA Field Sampling Data 

EPA conducted an international sampling program at steam electric power plants to 

collect wastewater data characterization and treatment performance data associated with FGD 

wastewater and other emerging wastestreams for which characterization data were not available 

(i.e., carbon capture and gasification wastewaters). As part of this sampling program, EPA 

conducted on-site sampling activities (i.e., samples were collected directly by EPA), as well as 

requiring some plants to collect samples for EPA (i.e., CWA 308 monitoring program). 

EPA conducted on-site sampling activities at the following selected plants:6

• Duke Energy’s Miami Fort Station, Ohio [ERG, 2012a]. 

• Duke Energy Carolina’s Belews Creek Steam Station, North Carolina [ERG, 

2012b]. 

• We Energies’ Pleasant Prairie Power Plant, Wisconsin [ERG, 2012c]. 

• Duke Energy Carolina’s Allen Steam Station, North Carolina [ERG, 2012d]. 

• Mirant Mid-Alantic, LLC’s Dickerson Generating Station, Maryland [ERG, 

2012e]. 

• NRG Energy’s Keystone Generating Station, Pennsylvania [ERG, 2012f]. 

• FirstEnergy’s Hatfield’s Ferry Power Station, Pennsylvania [ERG, 2012g]. 

• Enel’s Federico II Power Plant (Brindisi), Italy [ERG, 2012h]. 

• A2A’s Centrale di Monfalcon (Monfalcone), Italy [ERG, 2013]. 

All of the selected plants operate chemical precipitation wastewater treatment systems to 

treat their FGD wastewater. Belews Creek Steam Station, Allen Steam Station, and Dickerson 

Generating Station also operate biological treatment systems to further treat the effluent from 

chemical precipitation treatment. EPA conducted a sampling episode at Enel’s Federico II Power 

Plant (Brindisi), located in Brindisi, Italy, which operates an evaporation system. 

EPA requested the collection of one-day grab samples from a second plant in Italy, 

A2A’s Centrale di Monfalcone (Monfalcone). Monfalcone operates a chemical precipitation 

followed by evaporation system to treat FGD wastewater. Monfalcone personnel collected 

samples of the FGD influent to wastewater treatment, the distillate from the brine concentrator, 

and the condensate from the crystallizer. Site visit notes and the corresponding analytical results 

are included in the rulemaking record [ERG, 2013]. 

 

6

 Each of the seven plants at which EPA conducted on-site sampling activities also participated in the CWA 308 

monitoring program (Miami Fort Station, Hatfield’s Ferry Station, Allen Steam Station, Belews Creek Steam 

Station, Dickerson Generating Station, Kystone Generating Station, and Pleasant Prairie Power Plant). These seven 

plants collected a 24-hour composite sample one day a month for four consecutive months. 
Section 3 – Data Sources 

3-6 

3.3.3 CWA 308 Monitoring Data 

EPA required a subset of steam electric power plants to collect samples that were used to 

supplement the EPA on-site sampling program. Each of the plants selected for the on-site 

sampling program (except for Brindisi) were required to participate in the CWA 308 monitoring 

program so EPA could further evaluate the variability associated with the FGD wastewater 

treatment systems’ performance. 

For those seven plants, in addition to the samples collected by EPA during the four-day 

on-site sampling event, EPA required the plants to collect four sets of samples over a 4- or 5-

month period. The samples were collected directly by the plants and shipped to EPA-contracted 

laboratories for analysis. 

EPA required four additional plants (not sampled by EPA) to participate in its CWA 308 

monitoring program. These plants were selected to obtain data about operations or treatment 

systems because EPA did not have existing data for these processes or treatment technologies. 

EPA obtained data from the following four plants: 

1. Tampa Electric Company’s Polk Station (the first commercially operating 

integrated gasification combined cycle (IGCC) plant at the time of EPA’s 

sampling program). 7

2. Wabash Valley Power Association’s Wabash River Station (the second 

commercially operating IGCC plant at the time of EPA’s sampling program). 

3. Appalachian Power Company’s Mountaineer Plant (the only plant operating a 

carbon capture system at the time of EPA’s sampling program). 

4. Kansas City Power and Light’s Iatan Station (the only U.S. plant operating an 

evaporation system for treatment of FGD wastewater at the time of EPA’s 

sampling program). 

EPA required these four plants to collect four consecutive days of samples at two to four 

locations specifically identified for each plant. The sample locations were identified to 

characterize gasification wastewaters, carbon capture wastewaters, and the treatment of FGD 

wastewater and gasification wastewater by evaporation systems. For more information on the 

field sampling program, see Section 3 of the Technical Development Document for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category [U.S. EPA, 2015b]. For more information about the EPA CWA 308 Monitoring 

Program, see the memorandum, “Power Plant Monitoring Data Collected under Clean Water Act 

Section 308 Authority” [ERG, 2012i]. 

3.4 INDUSTRY- AND STATE-PROVIDED DATA

In addition to monitoring data submitted in the Steam Electric Survey and data collected 

during the EPA sampling program, EPA relied on industry-supplied data and publicly available 

 

7

 Duke Energy’s Edwardsport Power Station and Southern Company’s Kemper County IGCC Plant also operate an 

IGCC system; however, neither were in commercial operation at the time of EPA’s sampling program. 
Section 3 – Data Sources 

3-7 

data sources, including data received during public comment, to characterize pollutant discharge 

concentrations and evaluate treatment technologies. In some cases, EPA requested information 

from industry to fully evaluate the data provided or to support additional analyses, including the 

evaluation of FGD wastewater treatment system performance and wastewater characterization of 

ash transport water and ash impoundment effluent. EPA collected the following types of 

information from industry to characterize the evaluated wastestreams and treatment system 

performance: 

• FGD system information (e.g., identity of the organosulfide additives used in each 

chemical precipitation treatment system, conditions within each FGD scrubber 

system during sampling period). 

• Pollutant concentrations in FGD purge, FGD chemical precipitation effluent, and 

FGD biological treatment influent and effluent. 

• Ash system information. 

• Pollutant concentrations in ash impoundment influent and effluent. 

• Pollutant concentrations in source water. 

• Amount, source, sulfur content, chlorine content, and type of coal burned. 

EPA coordinated with the state of North Carolina to obtain additional FGD wastewater 

characterization data for Progress Energy Carolinas’ Roxboro Steam Plant operating an FGD 

impoundment and biological treatment system. Additionally, EPA requested additional 

monitoring data from plants operating FGD wastewater treatment systems, specifically those 

operating FGD chemical precipitation or FGD biological treatment systems. EPA’s data requests 

focused on information including coal data, FGD system operational information, FGD purge 

concentrations, and effluent concentrations for arsenic, mercury, selenium, and several other 

metals achieved by the chemical precipitation and/or the biological treatment portions of the 

FGD wastewater treatment systems over a 2-year period (i.e., January 2012-December 2013). 

EPA received public comments on the proposed revisions to the Steam Electric ELGs 

from industry, in which Duke Energy and Hoosier Energy Rural Electric Cooperative (Hoosier 

Energy) submitted data for samples of bottom ash and fly ash transport water collected at some 

of their coal-fired steam electric power plants. In some cases, these groups also provided source 

water data collected on the same day as the ash transport water samples [Duke Energy, 2013; 

Hoosier Energy, 2013]. EPA requested and received additional sample collection and quality 

information from Duke Energy and Hoosier Energy and used this additional information to 

verify the quality of the samples and ensure that the data were appropriate for use in wastestream 

characterization. EPA also requested and received additional ash transport water characterization 

data collected at these or other plants since the public comment submission [Duke Energy, 2014; 

Hoosier Energy, 2014]. As described in Section 12.1, these data were used to identify pollutants 

of concern in ash transport water and to characterize ash impoundment effluent. 

As part of its public comment submission, the Utility Water Act Group (UWAG), an 

industry trade association, provided bottom ash transport water data for 21 plants. In some cases, 

UWAG also provided source water data collected on the same sample day as the bottom ash 
Section 3 – Data Sources 

3-8 

transport water samples. UWAG also supplied a report prepared by URS Corporation with 

sampling data for sulfides (as well as some other parameters) collected in 2013 at nine plants 

[UWAG, 2013]. EPA requested and received additional information on the identity of the 

sampled plants, the sample collection location and methods used, the selection criteria used by 

UWAG when developing its data set, and additional information to verify the quality of the 

samples [UWAG, 2014a]. In November 2014, UWAG submitted additional sample 

characterization data to EPA for consideration in the final steam electric effluent limitations 

guidelines. The database included bottom ash transport water characterization data collected 

from six steam electric power plants [UWAG, 2014a]. The use of ash transport water data 

submitted by UWAG in the pollutants of concern and pollutant loadings analyses is described in 

Section 12.1. 

The information EPA received from industry in public comments on the proposed 

rulemaking, as well as from EPA’s plant-specific data requests is summarized in Table 3-1. 

3.5 ELECTRIC POWER RESEARCH INSTITUTE REPORTS

Electric Power Research Institute (EPRI) is a research-oriented trade association for the 

steam electric industry. EPRI conducts research funded by the steam electric industry and has 

extensively studied wastewater discharges from FGD systems and ash impoundments. EPA 

received technical reports from the trade association and as part of plant responses to the Steam 

Electric Survey. 

The EPRI reports provided EPA with background information regarding the 

characteristics of FGD wastewaters and the sampling techniques used during the program. These 

reports also provided EPA with information regarding the characteristics of discharges from fly 

ash and bottom ash impoundments and the respective percentage of pollutant loadings from ash 

impoundments containing both fly ash and bottom ash transport water. Additionally, the EPRI 

reports provided information on the treatment technologies available to treat FGD and ash 

wastewaters, including findings from pilot-study evaluations. Table 3-2 lists the reports provided 

to EPA by the trade association that summarize the data collected during several EPRI studies. 

The trade association provided EPA with the PISCES Water Characterization Field 

Study, Sites A-G reports that summarize the data collected during seven separate site visits to 

characterize wastewater at coal-fired power plants [EPRI, 1997-2001]. 

For the seven sites sampled, EPA reviewed the reports to determine the characteristics of 

the ash impoundments (e.g., type of wastestreams entering the impoundment, pollutant 

concentrations). The sites were identified as operating the following type of ash impoundments: 

• Site A – Combined ash impoundment. 

• Site B – Combined ash impoundment. 

• Site C – Combined ash impoundment. 

• Site D – Combined ash impoundment. 

• Site E – Combined ash impoundment. 

• Site F – Bottom ash impoundment and combined ash impoundment.

• Site G – Combined ash impoundment. 
Section 3 – Data Sources 

3-9 

As part of its response to the Steam Electric Survey, one steam electric power plant 

submitted an EPRI study on wastewater discharges from FGD systems and ash impoundments at 

the plant. Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 2006] 

presents sampling data from a fly ash impoundment at American Electric Power’s (AEP) John E. 

Amos plant. The report was submitted as part of the John E. Amos plant’s response to the Steam 

Electric Survey. As described in Section 12.1, data from these EPRI reports were used to identify 

pollutants of concern in ash transport water and to characterize ash impoundment effluent. 

3.6 NPDES PERMIT DATA

During the detailed study, EPA coordinated efforts with UWAG to create a database of 

selected National Pollutant Discharge Elimination System (NPDES) Form 2C data from 

UWAG’s member companies [UWAG, 2008]. The NPDES Form 2C (or an equivalent form 

used by a state permitting authority) is an application for a permit to discharge wastewater that 

must be completed by existing industrial plants (including manufacturing, commercial, mining, 

and silvicultural operations). This form includes plant information, data on plant outfalls, process 

flow diagrams, treatment information, and intake and effluent characteristics. 

The NPDES Form 2C database, compiled and generated by UWAG and provided to 

EPA, contains information about the outfalls from 86 coal-fired power plants that discharge 

FGD, ash handling, or coal pile runoff wastestreams. The database does not include Form 2C 

information for plants that have neither a wet FGD system nor wet fly ash handling. For 

example, if a plant has no wet FGD system and the plant’s only wet ash handling is for bottom 

ash sluicing, UWAG did not include its information in the database. 

3.7 EPA 1982 TECHNICAL DEVELOPMENT DOCUMENT

The 1982 Development Document for Effluent Limitations Guidelines and Standards and 

Pretreatment Standards for the Steam Electric Point Source Category (referred to as “the 1982 

TDD”) present the results of studies of the steam electric power generating industry that EPA 

conducted when previously revising the Steam Electric ELGs. This document contains findings, 

conclusions, and recommendations on control and treatment technologies relating to discharges 

from steam electric power plants. The 1982 TDD includes three separate tables and one appendix 

that contain ash impoundment effluent characterization data. EPA used information provided 

throughout the 1982 TDD to identify the types of influent streams entering each of the ash 

impoundments used for this loadings analysis [U.S. EPA, 1982]. 

Table V-32, Characteristics of Ash Pond Overflows with Total Suspended Solids 

Concentrations Less than 30mg/L, presents average surface impoundment overflow pollutant 

concentrations for 11 separate impoundments at 11 plants. 

Table V-33, Summary of Ash Pond Overflow Data from Discharge Monitoring Reports, 

provides an average pollutant concentration for ash surface impoundment effluent for each of the 

three different types of impoundment systems (i.e., fly ash, bottom ash, combined ash). 

Additionally, the table identified the number of impoundment systems that were used to calculate 

the average concentration. 
Section 3 – Data Sources 

3-10 

Table V-34, Summary of Quarterly TVA Trace Metal Data for Ash Pond Intake and 

Effluent Streams, summarizes average plant intake and ash surface impoundment effluent 

pollutant concentrations for 10 plants. The underlying individual data points used to calculate 

these averages are presented in Appendix A of the 1982 TDD. 

Appendix A, TVA Raw River Intake and Ash Pond Discharge Data, presents individual 

data points for the averaged data presented in Table V-34 of the 1982 TDD. 

3.8 PROTECTION OF CONFIDENTIAL BUSINESS INFORMATION

Certain data in the rulemaking record have been claimed as confidential business 

information (CBI). Due to these CBI claims, EPA has redacted certain information from the nonCBI version of this report. Additionally, EPA has withheld CBI as well as some data not claimed 

as CBI but that could indirectly reveal CBI, from the public docket in the Federal Docket 

Management System. Furthermore, EPA has aggregated certain data in the public docket, 

masked plant identities, or used other strategies to prevent the disclosure of CBI. EPA’s 

approach to CBI protection ensures that the data in the public docket explains the basis for the 

final rule, without compromising data confidentiality. This section describes the data claimed as 

CBI related to the costs and loadings analyses and how EPA determined which data needed to be 

redacted from the non-CBI version of this report. 

During the rulemaking, steam electric power plants and equipment and chemical vendors 

submitted data to EPA, some of which were claimed as CBI. These CBI data include costs 

associated with the installation and operation of the technology options evaluated as part of this 

rulemaking (or individual cost components for the system) and plant operating characteristics, 

which were used by EPA to estimate the plant-specific cost estimates and pollutant loadings. In 

general, there are three different types of CBI cost values that were redacted from the non-CBI 

version of this report: 

• Plant-Specific Operating Characteristics Used as Input Values to Estimate Costs 

and Loadings. Generally, EPA used the plant-specific operating characteristics 

from plant responses to the Steam Electric Survey. As part of the responses, 

plants were able to claim the reported data as CBI and, in many cases, the input 

values used to estimate plant-specific costs. As a result, the plant-specific costs 

and pollutant loadings calculated using these CBI values are also considered CBI 

because the input values could be back-calculated using the outputs and the 

methodologies and equations provided in this report. For this reason, the 

appendices to this report, which include the input and output data from the costs 

and loadings models at a plant level, are CBI; however, a sanitized (i.e., non-CBI) 

version of the appendices is available in the docket.8

• Vendor-Provided Cost Information. As described in Section 3.2, EPA obtained 

data regarding the technologies used in the industry through contact with 

equipment and chemical vendors. Some of this information was claimed as CBI 

 

8

 The sanitized version of the appendices includes rounded values in some cases, in order to protect CBI related to 

other output values presented in the docket. 
Section 3 – Data Sources 

3-11 

by the vendors. In all cases for which vendors provided CBI cost information, 

EPA was unable to mask the information using other vendor CBI data; therefore, 

all vendor-provided CBI was redacted from the non-CBI version of this report. 

• Industry-Specific Cost Factors Developed by EPA to Estimate Indirect Costs 

Related to Capital and O&M Costs. EPA also used the plant-specific data 

reported in response to the Steam Electric Survey to develop cost factors to 

estimate the indirect costs related to capital and O&M costs. The development of 

these cost factors is described throughout this report. In general, EPA used all the 

data available for a specific cost element, including both CBI and non-CBI data, 

to develop these cost factors. For some cost factors developed by EPA, the 

aggregated value used for the cost factor (e.g., average or median value) may 

reveal CBI data because of other available non-CBI data (i.e., the cost factor is 

CBI-deducible). EPA’s methodology for determining whether data are CBIdeducible is described in the following paragraphs. 

Where an aggregated output includes totals summed from both CBI and non-CBI data, 

there may be sufficient information available to use the non-CBI data to deduce (e.g., back 

calculate) the CBI data. Typically, CBI data can be masked (i.e., is non-deducible) if it is 

combined with at least two other CBI data points into an aggregated value (i.e., at least three CBI 

values are present, each of which must be associated with different companies). In evaluating the 

number of CBI data points aggregated, EPA reviewed the number of companies that provided 

the CBI data to determine if three or more companies provided CBI data.9

Example of CBI-Deducible Data Determination: EPA has information from the Steam 

Electric Survey from nine respondents (i.e., plants) operated by five companies. Three 

respondents claimed production data as CBI; the other six plants did not make any CBI claims on 

the data. The breakdown of respondents at the plant and company level is as shown: 

Number of Plant Respondents to 

Question Number of Company Respondents to Question 

9 Plants (Total) 5 Companies (Total) 

3 Plants (CBI) – A, B, and C 

2 Companies (CBI): 

- One Company Operates A and B 

- One Company Operates C 

Only two companies submitted CBI data. The company operating plants A and B can 

determine plant C’s CBI response, because it would have access to eight of the responses (i.e., 

the six non-CBI responses in the Steam Electric Technical Questionnaire Database, plus two 

CBI responses for plants A and B). Therefore, if the aggregated cost factor based on the nine 

responses was made publicly available, the company operating plants A and B would be able to 

determine plant C’s CBI data. For this example, EPA would redact the cost factor from the nonCBI version of this report to prevent the disclosure of CBI. 

 

9

 EPA’s evaluation of companies with CBI data is based on the majority owner identified in response to the Steam 

Electric Survey. 
Section 3 – Data Sources 

3-12 

EPA evaluated each cost factor developed for the costing methodology to determine if its 

disclosure would allow CBI to be deduced from other data in the public record. Based on its 

determination, EPA handled all cost factors determined to be CBI-deducible as CBI data and has 

redacted those values from the non-CBI version of this report. 

EPA also considered factors of company ownership and its effects on CBI 

deducibilityGiven that at least some company ownership changes have occurred since the 

proposed Steam Electric ELGs (including known and unknown changes), EPA recognized there 

would be a strong possibility that releasing all waived CBI would release potential CBIdeducible information. For example, the Agency is aware of a significant number of plants that 

changed ownership after they completed the Steam Electric Survey. With insufficient CBI values 

due to the continual change of plant ownership, data with no previous CBI deducibility concerns 

may now become CBI-deducible. See the February 17, 2015 “Memorandum Rationale for 

Handling Company Ownership Changes in CBI Deducibility Analysis to Prepare Responses for 

FOIA Request EPA-HQ-2013-008604” [U.S. EPA, 2015a]. 

3.9 REFERENCES

1. AEP. 2014. American Electirc Power. AEP Response to EPA Data Request. (3 March). 

DCN SE04375. 

2. Duke Energy. 2011a. Industry Provided Sampling Data from Duke Energy's Allen Steam 

Station. (17 August). DCN SE01809. 

3. Duke Energy. 2011b. Industry Provided Sampling Data from Duke Energy's Belews 

Creek Steam Station. (17 August). DCN SE01808. 

4. Duke Energy. 2013. Comments of Duke Energy on Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category. (7 June) EPAHQ-OW-2009-0819-4305. 

5. Duke Energy. 2014. Duke Energy Response to EPA Data Request. (4 December and 28 

March). DCN SE04331 and SE04360. 

6. ERG. 2012a. Eastern Research Group, Inc. Final Sampling Episode Report, Duke 

Energy’s Miami Fort Station. (13 April). DCN SE01304. 

7. ERG. 2012b. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy 

Caronlinas’ Belews Creek Steam Station. (13 April). DCN SE01305. 

8. ERG. 2012c. Eastern Research Group, Inc. Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 April). DCN SE01306. 

9. ERG. 2012d. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 April). DCN SE01307. 

10. ERG. 2012e. Eastern Research Group, Inc. Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 April). DCN SE01308. 
Section 3 – Data Sources 

3-13 

11. ERG. 2012f. Eastern Research Group, Inc. Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 April). DCN SE01309. 

12. ERG. 2012g. Eastern Research Group, Inc. Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 April). DCN SE01310. 

13. ERG. 2012h. Eastern Research Group, Inc. Final Site Visit Notes and Sampling Episode 

Report for Enel’s Power Plants. (8 August). DCN SE02013. 

14. ERG. 2012i. Eastern Research Group, Inc. Power Plant Monitoring Data Collected Under 

Clean Water Act Section 308 Authority. (27 March). DCN SE01326. 

15. ERG. 2013. Eastern Research Group, Inc. Final Monfalcone Site Visit Notes. (11 March). 

DCN SE03795 and SE03796. 

16. ERG. 2015. Eastern Research Group, Inc. “Supplemental Costs and Loadings 

Documentation.” (30 September). DCN SE05839. 

17. EPRI. 1997 - 2001. Electric Power Research Institute. PISCES Water Characterization 

Field Study, Sites A-G. Palo Alto, CA. DCNs SE01818-01823. 

18. EPRI. 2006. Electric Power Research Institute. Mitigation of SCR-Ammonia Related 

Aqueous Effects in a Fly Ash Impoundment: Algal Enhancement and Water Chemistry. 

Palo Alto, CA. DCN SE04742. 

19. FirstEnergy. 2014. FirstEnergy Response to EPA Data Request. (21 February). DCN 

SE04379. 

20. Hoosier Energy. 2013. Hoosier Energy Rural Electric Cooperative. Comments of Hoosier 

Energy on Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category. (20 September) EPA-HQ-OW-2009-0819-4471. 

21. Hoosier Energy. 2014. Hoosier Energy Rural Electric Cooperative. Hoosier response 

to Post Proposal Information Request. (11 and 14 April). DCN SE04701-04702.

22. NCDENR. 2011. North Carolina Department of Environment and Natural Resources. 

State Provided Sampling Data from Progress Energy’s Roxboro Plant. (26 June). DCN 

SE01812. 

23. NRG Energy. 2014. NRG Energy Response to EPA Data Request. (21 February). DCN 

SE04678. 

24. U.S. EPA. 1982. U.S. Environmental Protection Agency. Development Document for 

Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam 

Electric Point Source Category. EPA-440-1-82-029. Washington, DC. (November). 

25. U.S. EPA. 2009. U.S. Environmental Protection Agency. Steam Electric Power 

Generating Point Source Category: Final Detailed Study Report. EPA 821-R-09-008. 
Section 3 – Data Sources 

3-14 

Washington, DC. (October). Available online at: 

http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upload/2009_10_26_guide_ste

am_finalreport.pdf. 

26. U.S. EPA. 2010. U.S. Environmental Protection Agency. Questionnaire for the Steam 

Electric Power Generating Effluent Guidelines. OMB Approval Number: 2040-0281. 

Washington, DC. (2 June). DCN SE00402-SE00402A09. 

27. U.S. EPA. 2015a. U.S. Environmental Protection Agency. “Memorandum Rationale for 

Handling Company Ownership Changes in CBI Deducibility Analysis to Prepare 

Responses for FOIA Request EPA-HQ-2013-008604.” (17 February). 

28. U.S. EPA. 2015b. U.S. Environmental Protection Agency. Technical Development 

Document for the Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category. (30 September). DCN SE05904. 

29. UWAG. 2008. Utility Water Act Group. UWAG Form 2C Effluent Guidelines Database. 

(30 June). DCNs SE02918 and SE02918.A1. 

30. UWAG. 2013. Utility Water Act Group. Comments on EPA’s Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category. (7 June) EPA-HQ-OW-2009-0819-4655. 

31. UWAG. 2014a. Utility Water Act Group. UWAG Response to Post Proposal Information 

Request. (1 August). DCN SE04717. 

32. UWAG. 2014b. Utility Water Act Group. Additional Bottom ash Transport Water Data. 

(25 November). DCN SE05597. 

33. We Energies. 2013. Comments to Proposed Effluent Limitation Guidelines and Standards 

for the Steam Electric Power Genrating Point Source Category. 20 September. EPA-HWOW-0819-4475. 

34. We Energies. 2014. Response to EPA Data Request. 10 February. DCN SE04666. 

 
Section 3 – Data Sources 

3-15 

Table 3-1. Summary of Data Submitted by Industry and State Agencies

Type of Information Company Plants Reference

Coal Data 

AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Steam 

Station, Miami Fort Steam Station, 

Roxboro Steam Plant, Mayo Plant, and 

Cliffside Steam Station 

Duke Energy, 2014

First Energy Hatfield’s Ferry Power Station FirstEnergy, 2014

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2014

FGD System 

Information 

AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Steam 

Station, Miami Fort Steam Station, 

Roxboro Steam Plant, Mayo Plant, and 

Cliffside Steam Station 

Duke Energy, 2014

First Energy Hatfield’s Ferry Power Station FirstEnergy, 2014

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2014

FGD Impoundment 

Effluent 

Duke Energy 

(formerly Progress 

Energy Carolinas) 

Roxboro Steam Plant NCDENR, 2011

FGD Purge AEP Mountaineer Plant AEP, 2014

Duke Allen Steam Station, Belews Creek Steam 

Station, Miami Fort Steam Station, 

Roxboro Steam Plant, and Cliffside Steam 

Station 

Duke Energy, 2011a 

and 2011b; Duke 

Energy, 2014; 

NCDENR, 2011 

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2014

Chemical 

Precipitation Effluent 

AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Steam 

Station, Miami Fort Steam Station 

Duke Energy, 2011a 

and 2011b; Duke 

Energy, 2014 

First Energy Hatfield’s Ferry Power Station FirstEnergy, 2014

NRG Energy Keystone Generating Station NRG Energy, 2014

We Energies Pleasant Prairie Power Plant We Energies, 2013 and 

2014 

Biological Treatment 

Influent 

AEP Mountaineer Plant AEP, 2014

Biological Treatment 

Effluent 

AEP Mountaineer Plant AEP, 2014

Duke Energy Allen Steam Station, Belews Creek Station, 

Roxboro Steam Plant 

Duke Energy, 2011a 

and 2011b; Duke 

Energy, 2014; 

NCDENR, 2011 

Ash Impoundment 

Effluent

Duke Energy Marshall Steam Station, Belews Creek 

Steam Station, Cliffside Steam Station, 

Miami Fort Station, East Bend Station 

Duke Energy, 2013

and 

2014
Section 3 – Data Sources 

3-16 

Table 3-1. Summary of Data Submitted by Industry and State Agencies

Type of Information Company Plants Reference

Hoosier Energy Frank E. Ratts Generating Station Hoosier, 2013 and 

2014 

UWAG Bottom Ash Database Plants: Burlington, 

Kingston, EC Gaston, Dubuque Generating 

Station, Kammer Plant, Frank E. Ratts 

Generating Station, Monroe Power Plant, 

Gorgas, Crist, Meredosia Power Station, 

Widows Creek, Greene County, Yates, 

AmerenUE Sioux Power Plant, River 

Rouge Power Plant, Bull Run, and five 

unidentified power plants 

UWAG, 2013 and

2014 

UWAG UWAG Sulfides Data Set Plants: Kyger 

Creek Station, EC Gaston, James H. Miller 

Jr., Gorgas, and two unidentified power 

plants 

UWAG, 2013 2014a,

and 2014b 

Table 3-2. Reports and Studies Submitted to EPA from EPRI 

Title of Report/Study 

Document Control 

Number 

PISCES Wastewater Characterization Field Study, Sites A-G DCNs SE01818 – SE01823

The Fate of Mercury Absorbed in Flue Gas Desulfurization (FGD) Systems DCN SE01814

Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study DCN SE01816

EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD 

Scrubbers 

DCN SE01817

Update on Enhanced Mercury Capture by Wet FGD: Technical Update DCN SE01815

Selenium Removal by Iron Cementation from a Coal-Fired Power Plant Flue Gas

Desulfurization Wastewater in Continuous Flow System – A Pilot Study 

DCN SE0409A2

Laboratory and Pilot Evaluation of Iron and Sulfide Additives with 

Microfiltration for Mercury Water Treatment 

DCN SE0409A3

Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions 

on Selenium Speciation: 2009 Update 

DCN SE04369

Integrated Fly Ash Pond Management: A Field Study of Five Central United 

States Pond Systems. 

DCN SE04361

Current Practices for Flue Gas Desulfurization (FGD) Water Management and 

Treatment in Ponds 

DCN SE04367

Pilot-Scale and Full-Scale Evaluation of Treatment Technologies for the Removal 

of Mercury and Selenium in Flue Gas Desulphurization Water 

DCN SE04362

Impact of Wet Flue Gas Desulfurization (FGD) Design and Operating Conditions 

on Selenium Speciation: 2010 Update 

DCN SE04370

Review of Water Treatment Technologies for Selenium Removal Implemented at 

Power Plants 

DCN SE04363

Evaluation of Mercury Speciation and Its Treatment Implication in Flue Gas 

Desulfurization Waters 

DCN SE04368
Section 3 – Data Sources 

3-17 

Table 3-2. Reports and Studies Submitted to EPA from EPRI 

Title of Report/Study 

Document Control 

Number 

Thermal Flue Gas Desulfurization Wastewater Treatment Processes for Zero 

Liquid Discharge Operations 

DCN SE04365

Selenium Speciation and Management in Wet FGD Systems DCN SE04364

Corrosion in Wet Flue Gas Desulfurization (FGD) Systems: Technical Root 

Cause Analysis of Internal Corrosion on Wet FGD Alloy Absorbers 

DCN SE04366

Pilot Evaluation of the Anaerobic Membrane Bioreactor Technology for Flue Gas 

Desulfurization Wastewater Treatment 

DCN SE05615

Pilot Evaluation of the PironoxTM System for Flue Gas Desulphurization 

Wastewater Treatment 

DCN SE05616

Pilot Evaluation of a Fluidized Bed Reactor/Membrane Bioreactor Technology 

for Flue Gas Desulfurization Wastewater Treatment 

DCN SE05617

Pilot Evaluation of the ABMet Technology for Flue Gas Desulphurization 

Wastewater Treatment 

DCN SE05618

Pilot Evaluation of the ZVI BlueTM Technology for Flue Gas Desulphurization 

Wastewater Treatment 

DCN SE05619
Section 4 – Development of Model Inputs 

4-1 

4. DEVELOPMENT OF MODEL INPUTS 

This section describes the input data to the costs and loadings models that EPA used to 

estimate incremental compliance costs and post-compliance pollutant loadings and removals for 

the Steam Electric effluent limitations and standards (ELGs). These data are categorized into one 

of four groups: 

• Wastestream population and flow basis for pollutant loadings. 

• Wastestream population and characteristics for costing. 

• Pollutant concentrations. 

• Plant characteristics. 

All tables and figures referenced in this section are presented at the end of the section. 

4.1 WASTESTREAM POPULATION AND FLOW BASIS FOR POLLUTANT LOADINGS

EPA calculated baseline and post-compliance pollutant loadings for each plant 

discharging flue gas desulfurization (FGD) wastewater, fly ash transport water, bottom ash 

transport water, and/or combustion residual leachate.10 Pollutant loadings are calculated by 

multiplying the pollutant concentrations by the wastewater flow rate. 

EPA used data from the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey) and industry-submitted data to identify the population of 

plants discharging each wastestream and the wastewater flow rates. The steam electric power 

generating industry is a dynamic industry where changes are occurring frequently with a number 

of steam electric generating units retiring, converting to new type of fuel, or making changes to 

existing ash handling systems. Because these changes can have a market impact on the cost to 

comply with the ELGs, EPA accounted for planned changes in the cost and loadings analysis. 

EPA did not estimate compliance costs or pollutant removals for these generating units identified 

as retiring or converting to fuels (e.g., biomass, natural gas) that do not generate wastestreams 

covered by the ELG prior to implementing the revised ELGs. Similarly, EPA identified those 

generating units converting to dry fly ash or closed-loop/dry bottom ash handling based on 

information from company announcements and through contact with ash handling and 

wastewater treatment vendors and excluded these units from the cost and loadings analysis 

because the planned modifications would lead to compliance with the final ELGs. EPA identified 

170 plants retiring or converting fuels on at least one generating unit by 2023, an additional 18 

plants converting at least one generating unit to dry fly ash handling, and 17 plants converting at 

least one generating unit to closed-loop/dry bottom ash handling. These plants were excluded 

from the cost and loadings analysis. A list of all plants and generating units removed from the 

costs and loadings analysis as a result of retiring, converting fuels, or converting their ash 

 

10 EPA determined that, based on current practices, there would be no incremental pollutant removals for flue gas 

mercury control or gasification wastewater; see Section 10 of the Technical Development Document for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 

2015]. 
Section 4 – Development of Model Inputs 

4-2 

handling systems is included in the “Changes to Industry Profile for Steam Electric Generating 

Units for the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015a]. 

The following sections describe EPA’s methodology for determining which plants should 

be included in each wastestream population and the amount of wastewater being discharged by 

those plants based on data from the Steam Electric Survey and industry-submitted data. 

4.1.1 FGD Wastewater 

EPA used data from the Steam Electric Survey and industry-submitted data to identify 

the population of plants that currently discharge or are planning to discharge FGD wastewater to 

surface water (or a publicly owned treatment works (POTW)) and the type of treatment 

equipment at each plant. To develop this “FGD Input Table,” EPA used information from Part B 

of the Steam Electric Survey (Flue Gas Desulfurization (FGD) Systems). EPA then adjusted the 

population based on those generating units identified as retiring or converting fuels (see Section 

4.1 for additional details regarding the identification of retirements/fuel conversions). A copy of 

the “FGD Input Table” is included in the FGD Loadings Database and the FGD and Ash Steam 

Electric Cost Model [ERG, 2015d; ERG, 2015e]. EPA identified a total of 88 plants that 

currently operate wet FGD systems and discharge FGD wastewater to surface water (or a 

POTW). Of these, one plant operates only small generating units with a capacity less than or 

equal to 50 megawatts and thus would not incur costs or demonstrate pollutant removals because 

it does not need to meet any more stringent requirement than already existed under BPT 

regulations. As a result, EPA estimated that 87 plants would incur costs and demonstrate 

pollutant removals to comply with the requirements for FGD wastewater. The remainder of this 

section describes EPA’s methodology for developing FGD wastewater flow rates for each of 

these 88 plants. 

EPA used the information from Part B Section 1 (General FGD System Information) to 

identify those plants that operate a wet FGD system and have the potential to discharge FGD 

wastewater. Some plants operating wet FGD systems were excluded from this group for the 

following reasons: 

• The plant did not report a NPDES permit. 

• The plant treats the FGD wastewater using an evaporation impoundment system 

that does not discharge to a surface water or POTW. 

• The plant reuses all the FGD wastewater with no potential for later discharge to 

surface water or POTW. 

For each plant that discharges FGD wastewater, EPA determined the amount of 

wastewater that each of its FGD systems contribute to the plant’s total FGD wastewater 

discharge in gallons per day (gpd). EPA used the FGD scrubber purge rate reported in Part B 

Section 5 (FGD Wastewater Generation) as the FGD system-level wastewater flow rate used in 

the cost models. For current FGD systems that did not provide a FGD scrubber purge rate in Part 

B Section 5 (three plants), EPA developed a methodology to estimate the FGD wastewater flow 

rate based on other data provided in the Steam Electric Survey. Using information from plants 

that provided data for the FGD scrubber purge, EPA established a relationship between the FGD 
Section 4 – Development of Model Inputs 

4-3 

scrubber purge rate reported by each FGD system and the amount of coal burned at the 

generating units serviced by each of those wet FGD systems. EPA noted that this relationship 

was dependent upon the type of coal burned by these generating units; as a result, EPA 

calculated a value for the FGD wastewater flow per ton of coal for each type of coal: bituminous, 

subbituminous, lignite, and a blend of any two or more coals. EPA estimated the wastewater 

flow rate for 3 plants using Equation 4-1. 

(4-1) 

System FGD Wastewater Flow (gpd) = TonsofCoalBurned × MedianGPDperTonofCoal 

where: 

TonsofCoalBurned = The reported tons of coal burned per year by the steam 

electric generating units serviced by the FGD system. 

Data from Part A Section 8 (Fuel Usage by Steam 

Electric Generating Unit). 

MedianGPDperTonofCoal = The calculated median FGD wastewater flow rate in 

GPD per ton of coal burned per year based on the type 

of coal burned: 0.1454 for bituminous, 0.0392 for 

subbituminous, 0.2313 for lignite, and 0.1017 or any 

coal blend. 

See the “Supplemental Costs and Loadings Documentation” for the development of 

Equation 4-1 and the development of the median FGD wastewater flow per ton of coal burned 

[ERG, 2015f; see Appendix 1]. 

For each plant that, in its response to the Steam Electric Survey, reported plans to install a 

FGD system prior to January 1, 2014, EPA used the 24-hour average daily design flow rate 

reported in Part B Section 2 (Planned FGD System Information) to identify a system-level FGD 

wastewater flow rate in gallons per day, assuming the system operates 24 hours per day. 

After generating the FGD wastewater flow rates at the FGD system level, EPA then 

evaluated announced retirements/fuel conversions to determine which FGD systems would no 

longer be operating by the time the ELG is implemented and adjusted flow rates accordingly. For 

FGD systems that service generating units for which companies have announced plans to retire 

or convert to a different fuel, EPA adjusted the FGD wastewater flow rate to remove the 

contribution from those generating units. In cases where all generating units serviced by an FGD 

system are retiring/converting fuels, EPA changed the FGD wastewater flow rate to zero. In 

cases where some but not all of the generating units serviced by an FGD system are 

retiring/converting fuels, EPA adjusted the flow based on the post-retirement scrubbed capacity 

using Equation 4-2. 

 (4-2) 

System FGD Wastewater Flow (gpd) = Pre-Retirement System FGD Wastewater Flow × PostRetirement Scrubbed Capacity / Pre-Retirement Scrubbed Capacity 
Section 4 – Development of Model Inputs 

4-4 

where: 

Pre-Retirement System 

FGD Wastewater Flow 

= System-level FGD wastewater flow identified in the 

Steam Electric Survey as FGD scrubber purge flow or 

the system FGD wastewater flow estimated using 

Equation 4-1. 

Pre-Retirement Scrubbed 

Capacity 

= Total capacity, in megawatts (MW), of the generating 

units serviced by the FGD system as reported in the 

Steam Electric Survey. 

Post-Retirement Scrubbed 

Capacity 

= Total capacity, in MW, of the generating units serviced 

by the FGD system after removing all generating units 

identified as retiring or converting fuels as described in 

Section 4.5.2. 

After generating the FGD system wastewater flow rates, EPA summed each system’s 

flow rates at each plant to determine the total plant FGD wastewater flow rate used in the costs 

model. See the “Supplemental Costs and Loadings Documentation” for the detailed development 

of the “FGD Input Table” [ERG, 2015f; see Appendix 2]. 

4.1.2 Fly Ash and Bottom Ash Transport Water 

EPA used data from the Steam Electric Survey and industry-submitted data to identify 

the population of steam electric generating units that generate fly ash, bottom ash, or combined 

ash transport water, send the transport water to a surface impoundment system(s), and discharge 

the transport water to surface waters or POTWs. EPA then evaluated whether any of the 

generating units meeting that criteria were slated for retirement or fuel conversion and thus 

would no longer be generating fly ash and bottom ash by the time the ELG is implemented. 

Those generating units slated for retirement or fuel conversion were excluded from the “Ash 

Transport Water Input Table.” See Section 4.1 for additional details regarding the identification 

of retirements/fuel conversions. Additionally, EPA excluded all generating units that have 

announced plans to convert to a dry fly ash handling system from the fly ash portion of the “Ash 

Transport Water Input Table.” Finally, EPA excluded all generating units that have announced 

plans to convert to a dry bottom ash system or closed-loop wet system from the bottom ash 

portion of the “Ash Transport Water Input Table.” A copy of the input table is included in the 

Ash Loadings Database [ERG, 2015b]. EPA identified a total of 164 plants that discharge ash 

transport water. The remainder of this section describes EPA’s methodology for identifying these 

plants and determining the flow rate of ash transport water discharged. 

EPA populated the “Ash Transport Water Input Table” using the following steps: 

Step 1: Identify generating units that use wet sluicing systems, using data in Part C, 

Section 2.1 (Fly Ash Handling – Generating Unit Information) and Part C, 

Section 3.1 (Bottom Ash Handling – Generating Unit Information). 

Step 2: Identify surface impoundment systems that (1) receive ash transport wastewater 

from the generating units identified in Step 1 and (2) discharge to surface waters 
Section 4 – Development of Model Inputs 

4-5 

or POTWs based on Part D Section 3.2 (Wastewater Treatment Wastewater 

Flows). 

Step 3: Where necessary, supplement incomplete or inconclusive Part D information with 

information reported in Part A, Section 2.2 (Outfall Information), Part C, Section 

2.1 (Fly Ash Handling – Generating Unit Information), and Part C, Section 3.1 

(Bottom Ash Handling – Generating Unit Information). 

In cases where the Part D data differed from Parts A or C, EPA reviewed the process 

flow and water balance diagrams to determine whether any ash transport water enters the 

impoundments that were reported as discharging to surface water or POTWs. 

For each unit included in the “Ash Transport Water Input Table,” EPA calculated a 

normalized, generating unit-level discharge flow rate for fly ash, bottom ash, and/or combined 

ash transport water. The discharge flow rate attributed to each generating unit was calculated by 

adjusting the plant-level discharge flow rate by the proportion the unit contributed to the plantlevel transport water generation flow rate (e.g., a generating unit that produced 40 percent of all 

fly ash transport water generated at a plant was considered responsible for an equal percentage of 

the fly ash transport water discharged by the plant). It was necessary to use this approach 

because the transport water generation and discharge flow rates typically are not equal, and the 

discharge flow is the more appropriate value to use for estimating pollutant loadings and 

removals. The plant-level normalized discharge flow rate was determined using data from Part D 

of the Steam Electric Survey. Data from Part C was used to determine the generating unit-level 

normalized generation flow rate. Using the Part C normalized flow rate, EPA calculated the 

proportion of flow attributable to each operating unit and applied it to the plant-level normalized 

flow rate to calculate a generating unit-level normalized discharge flow. EPA also adjusted the 

generating unit-level normalized discharge flow to account for any necessary generating unitlevel flow adjustments (e.g., recycle). See Sections 4.1.2.1 through 4.1.2.5 for more specific 

detail on the development of the generating unit-level normalized flow. Also see the 

“Supplemental Costs and Loadings Documentation” for the detailed calculation of the generating 

unit-level normalized flows [ERG, 2015f; see Appendix 3]. 

4.1.2.1 Plant-Level Normalized Flow 

EPA reviewed data in the Steam Electric Survey and industry-submitted data to 

determine plant-level ash transport water discharge flow rates by ash type, using the following 

list of sources, to estimate the “Plant-Level Normalized Flow (GPD)” for ash transport water 

flow rates by plant: 

• Influent ash transport water flow rates to the impoundment reported in Part D 

(including process flow diagrams).11

• Percent contributions of ash sluice to plant outfall, multiplied by the total outfall 

flow rate reported in Part A, Section 2. 

 

11 EPA used ash transport water flow rates from responses to Part D of the Steam Electric Survey where available in 

an effort to account for any wastewater reuse that may occur prior to the ash transport water being sent to the

impoundment. 
Section 4 – Development of Model Inputs 

4-6 

• Process flow or water balance diagram in Part A. 

Plants do not continuously generate ash transport water and, therefore, do not necessarily 

discharge the wastewater without interruption. The discharge flow rates used to populate the 

“Ash Transport Water Input Table” were normalized to have all plants on the same basis of 

discharging over 365 days. To account for the number of days of transport water generation, 

EPA calculated a normalized daily flow rate using Equation 4-3.12

(4-3) 

Flow Rate (gpd) = Transport Flow (gpd) × Days Generated (days) / 365 days

where: 

Flow Rate = The normalized daily flow rate of the transport water 

from all generating units entering the ash impoundment 

in gpd. 

Transport Flow = The reported ash transport water flow rate from all 

generating units entering the ash impoundment in gpd, 

as reported in Part D, Part A, or the water balance 

diagram. 

Days Generated The reported number of days the ash transport water is 

generated/transferred to the ash impoundment from all 

generating units, as reported in Part D, Part A, or the 

water balance diagram. 

EPA calculated the plant-level normalized flow rate for each type of ash (i.e., fly ash, 

bottom ash, combined ash). 

4.1.2.2 Part C Normalized Flow 

EPA reviewed data submitted in Part C of the Steam Electric Survey to determine the 

flow rate at which ash transport water is generated by each generating unit. These data were used 

to estimate a normalized flow for ash transport water discharged by each generating unit. If the 

plant provided a gallons per day (GPD) and days per year (DPY) value in Part C (Table C-3 for 

fly ash and Table C-19 for bottom ash) for the generating unit, the normalized Part C flow was 

calculated by generating unit and ash type (i.e., fly ash, bottom ash, combined ash). 

However, the Part C flow data were reported inconsistently by plants and may actually 

reflect flows associated with multiple generating units. For example, some plants reported the 

exact same transport water flow rates for all generating units and EPA was unable to determine 

 

12 The approach of normalizing the flow based on the number of ash transport days may underestimate the loadings 

because the ash impoundment will continue to discharge, although at a lower flow rate, even when ash transport 

water is not transferred to the ash impoundment because other contributions to the impoundment (e.g., rainfall) will 

continue to feed the impoundment and will likely become contaminated from the ash contained in the impoundment. 
Section 4 – Development of Model Inputs 

4-7 

whether the reported flow rate represents the flow from each individual generating unit or the 

combination of all the generating units. To avoid double-counting ash transport water flow, EPA 

used only the Part C normalized flow data to calculate the unit flow fraction (described in 

Section 4.1.2.2) or in the cases where a plant-level normalized flow (described in Section 

4.1.2.1) could not be estimated. 

4.1.2.3 Unit Flow Fraction 

EPA estimated the fraction of ash transport water attributed to each generating unit using 

the Part C normalized flow. If the plant provided a gpd and dpyvalue in Part C (Table C-3 for fly 

ash and Table C-19 for bottom ash) for the generating unit, the normalized Part C flow was 

calculated by generating unit and ash type and divided by the sum of the Part C normalized flow 

of all the generating units to determine the unit flow fraction. 

If the plant did not provide either GPD or DPY in Table C-3 or C-19, EPA estimated a 

unit fraction by using the ash tonnage conveyed wet from Table C-2 or C-18, instead of the 

transport water flow rate. The generating unit flow fraction was calculated by dividing the wet 

tonnage for a generating unit by the sum of wet tonnage for all generating units. 

If the plant did not provide the GPD and DPY information in Table C-3 or C-19, and the 

ash tonnage conveyed wet was not available, EPA estimated the tonnage from the amount of coal 

burned per generating unit in Part A, Table A-11. To estimate a wet conveyed fly ash tonnage, 

EPA multiplied the tons of coal burned by the generating unit in Part A, Table A-11 by 8 percent 

(assuming 10 percent ash content for the coal and 80 percent of ash generated is fly ash). EPA 

estimated the wet conveyed bottom ash tonnage by multiplying the tons of coal burned by the 

generating unit by 2 percent (assuming 10 percent ash content for the coal and 20 percent of ash 

generated is bottom ash). EPA then divided the generating unit-level wet ash tonnage by the sum 

of the wet ash tonnage for all generating units with wet sluicing systems to determine the unit 

flow fraction. 

4.1.2.4 Generating Unit-Level Normalized Flow 

Using the plant-level normalized discharge flow rate and the unit flow fraction, EPA 

calculated generating unit-level normalized discharge flow rates by multiplying the plant-level 

normalized flow rate by the unit flow fraction. When plant-level flow data were not available, 

EPA used the Part C Normalized Flow to populate the “Ash Transport Water Input Table.” 

4.1.2.5 Additional Flow Adjustments 

In addition to the generating unit-level normalized flow, EPA also reviewed data in the 

Steam Electric Survey and industry-submitted data to identify any adjustments necessary to 

reflect wastewater recycle and potential double-counting of generating unit-level flows where 

plants may have reported a total plant flow for all generating units at the plant. 

First, EPA identified plants that reported they recycle bottom ash transport water before 

or after dewatering from Question C3-5 (recycle bottom ash sluice) and Question C3-10 (recycle 

water from solids removal) in the Steam Electric Survey, or other industry-supplied data. EPA 

reviewed the Part C, Section 3.1 flow data, water balance diagrams from Part A, Section 5, Part 

A, Section 2.2 outfall data, and Part D, Sections 3.1 and 3.2 treatment system diagrams and flows 
Section 4 – Development of Model Inputs 

4-8 

for this subset of data. EPA flagged plants operating a complete recycle system or those plants 

that did not discharge bottom ash sluice in 2009, but still had the ability to discharge (e.g., 

emergency discharge outfalls). EPA flagged these generating units as “Complete Recycle” in the 

“Discharge Flag” field in the “Ash Transport Water Input Table” and adjusted the flow to zero. 

EPA adjusted bottom ash transport water flows in the ash flow input table for plants that recycle 

any of their bottom ash transport water [ERG, 2015f; see Appendix 3]. 

EPA also reviewed specific plants in the “Ash Transport Water Input Table” that reported 

identical flow rates (GPD) and generation (DPY) in Table C-3 for fly ash (Part C, Section 2.1) 

and C-19 for bottom ash (Part C, Section 3.1) for all generating units. EPA reviewed Part D, 

Sections 3.1 and 3.2 treatment system diagrams and flows, Part A, Section 2.2 outfall data, and 

Part A, Section 5 process flow diagrams to determine if the flows provided in Part C were really 

generating unit-level or a plant-level flow rates. In addition, the unit flow fraction was analyzed 

individually for these plants to determine whether the tonnage ratios were a better source for 

determining the unit flow fraction. Where the Part C flow rates for an individual generating unit 

were less than the plant-level flow rates from Part D or Part A, EPA determined that the reported 

generating unit flow represents the flow from the individual generating units. Where the Part C 

flow rates for an individual generating unit matched the plant-level flow rates from Part D or Part 

A, EPA determined that the reported generating unit flow represents the total plant-level flow. In 

cases where the Part C flow did not represent flow on a generating unit-level, EPA adjusted the 

generating unit-level ash transport water flow rates in the “Ash Transport Water Input Table” 

accordingly. 

4.1.3 Combustion Residual Leachate 

EPA used data from the Steam Electric Survey to identify the population of landfills and 

impoundments containing combustion residuals that collect and discharge combustion residual 

leachate to surface waters or POTWs. The methodology EPA used to estimate the amount of 

combustion residual leachate discharged from landfills containing combustion residuals is 

described in Section 4.1.3.1. The methodology EPA used to estimate the amount of combustion 

residual leachate discharged from impoundments containing combustion residuals is described in 

Section 4.1.3.2. Section 9 describes the combustion residual leachate loadings methodology in 

detail. 

4.1.3.1 Landfill Combustion Residual Leachate Discharge Flow 

EPA used data from the Steam Electric Survey to identify the population of 

active/inactive landfills containing combustion residuals that collect and discharge combustion 

residual leachate to surface waters or POTWs. To develop these input data, EPA used data from 

Part F, Section 3.1 (Landfill Management Practices) for those plants that completed this 

section.13 For all other plants EPA used the information from Part A, Section 4 (Landfills) of the 

Steam Electric Survey to identify plants that collect the combustion residual leachate generated 

at landfills and then estimated the combustion residual leachate flow rates for these plants based 

 

13 Only a subset of plants were required to respond to Part F of the Steam Electric Survey. Section 3 of the Technical 

Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category provides more detail on the Steam Electric Survey [U.S. EPA, 2015]. 
Section 4 – Development of Model Inputs 

4-9 

on data from plants completing Part F. Additionally, EPA used information from Part A, Section 

2.2 (Outfall Information) and water balance diagrams to identify the plants that discharge the 

collected combustion residual leachate to surface waters or POTWs. The landfill combustion 

residual leachate flows, and the impoundment combustion residual leachate flows described in 

Section 4.1.3.2, are combined to create the “Combustion Residual Leachate Input Table.” A copy 

of the “Combustion Residual Leachate Input Table” is included in the Combustion Residual 

Leachate Loadings Database [ERG, 2015c]. EPA identified a total of 85 plants that collect and 

discharge combustion residual leachate from 109 landfills containing combustion residuals. Of 

these, two plants operate, or plan to operate, treatment system more advanced than chemical 

precipitation and one plant operates only small generating units with a capacity less than or equal 

to 50 MW and thus would not incur costs or demonstrate pollutant removals because it does not 

need to meet any more stringent requirement than already existed under BPT regulations. As a 

result, EPA estimated that 82 plants would incur costs and demonstrate pollutant removals to 

comply with the chemical precipitation requirements for landfill combustion residual leachate. 

Plants reported their collected combustion residual leachate flow rates in Part F, Section 

3.1 (Landfill Management Practices) of the Steam Electric Survey. Because only a subset of 

plants was required to complete Part F, EPA had specific landfill combustion residual leachate 

flow rates from only 18 plants. For each of these 18 plants, EPA calculated the ratio of the 

landfill acreage associated with the collected combustion residual leachate and the total 

active/inactive landfill acres at the plant reported in Part C, Section 1 (Ash Generation) of the 

Steam Electric Survey. EPA then determined the median value for the calculated ratios from the 

18 plants and applied the median value to other plants that reported collecting landfill 

combustion residual leachate but were not required to complete Part F. EPA used the median 

value, along with the reported total active/inactive landfill acres reported in Part C, to estimate 

the total landfill acres for the plant where combustion residual leachate is collected (referred to 

as leachate acreage). EPA developed separate estimates for active and inactive landfills as 

follows: 

Active Landfills: 

(4-4) 

Leachate Acreage (acre) = Median Leachate Acre Per Active Landfill Acre × Landfill Acreage 

Inactive Landfills: 

(4-5) 

Leachate Acreage (acre) = Median Leachate Acre Per Inactive Landfill Acre × Landfill Acreage 
Section 4 – Development of Model Inputs 

4-10 

where: 

Median Leachate Acre Per 

Active Landfill Acre 

= Median ratio of acreage collecting combustion residual 

leachate at a plant to total landfill acres for active 

landfills, 0.75. 

Median Leachate Acre Per 

Inactive Landfill Acre 

= Median ratio of acreage collecting combustion residuals

leachate at a plant to total landfill acres for inactive 

landfills, 0.05. 

Landfill Acreage = Total active/inactive/open landfill acreage at the plant, 

as reported in Part C, Section 1 (Ash Generation). 

See the “Supplemental Costs and Loadings Documentation” for the discussion on the 

development of Equations 4-4 and 4-5 [ERG, 2015f; see Appendix 4]. 

EPA also used the data from the 18 plants responding to Part F, Section 3.1 to generate a 

relationship between the acreage of landfills that collect combustion residual leachate and the 

amount of combustion residual leachate discharged. EPA assumed that any open landfill, active 

or inactive, at a given plant would receive similar amounts of rainfall. Of the 18 plants that 

discharge combustion residual leachate, the median leachate discharge rate was 887 gpd per acre 

of landfill. 

EPA used the following hierarchy to estimate the landfill combustion residual leachate 

flow rate for the “Landfill Combustion Residual Leachate Input Table:” 

• EPA used the volume of combustion residual leachate collected in 2009, reported 

in Part F, Section 3.1 of the Steam Electric Survey (Landfill Management 

Practices). 

• EPA used the current landfill-specific surface area from Part F, Section 3.1 of the 

Steam Electric Survey (Landfill Management Practices) and multiplied by the 

median leachate discharge rate per acre (887 gpd/acre) [ERG, 2015f; see 

Appendix 4]. 

(4-6) 

Leachate Volume (gpd) = 887 × Leachate Acreage 

• EPA used the active/inactive/open landfill acreage, reported in Part C, Section 1 

(Ash Generation) depending on whether the landfill is active or inactive, and the 

median leachate discharge flow rate per acre (887 gpd/acre).

Active Landfills: 

(4-7) 

Leachate Volume (gpd) = 887 × 0.75 × Leachate Acreage 
Section 4 – Development of Model Inputs 

4-11 

Inactive Landfills: 

(4-8) 

Leachate Volume (gpd) = 887 × 0.05 × Leachate Acreage 

where: 

Leachate Acreage = Total acreage of landfills containing combustion 

residual at the plant that collect combustion residual 

leachate, a percentage of the total landfill acres at the 

plant (see Equations 4-4 and 4-5). 

EPA used the median leachate volume from plants providing data in Part F, Section 3.1 

of the Steam Electric Survey. The average plant-level combustion residual leachate volume 

reported by the 18 plants in Part F, Section 3.1 was 46,160 gpd for active landfills and 29,651 

gpd for inactive landfills. 

During review of the landfill combustion residual leachate volumes, EPA also 

investigated the frequency of combustion residual leachate collection for the 18 plants with 

complete Part F, Section 3.1 data. The median frequency of combustion residual leachate 

collection was 365 days per year. EPA used this value to convert the combustion residual 

leachate volumes from gallons per day to gallons per year prior to populating the “Landfill 

Combustion Residual Leachate Input Table.” 

4.1.3.2 Impoundment Combustion Residual Leachate Discharge Flow 

EPA used data from the Steam Electric Survey to identify plants collecting and 

discharging combustion residual leachate from impoundments containing combustion residuals 

and to calculate a combustion residual leachate discharge flow rate. EPA identified plants that 

collect combustion residual leachate from impoundments containing combustion residuals using 

data from Part A, Section 3 (Pond/Impoundments) and Part F, Section 2 (Pond/Impoundment 

Management Practices) of the Steam Electric Survey. Using Part A, Section 2.2 (Outfall 

Information) and water balance diagrams provided as part of the Steam Electric Survey, EPA 

identified 46 impoundments (42 active and four inactive) at 25 plants discharging leachate from 

impoundments containing combustion residuals.14 The impoundment combustion residual 

leachate flows, and the landfill combustion residual leachate flows described in Section 4.1.3.1, 

are combined to create the “Combustion Residual Leachate Input Table,” a copy of which is 

included in the Combustion Residual Leachate Loadings Database [ERG, 2015c]. 

From Part F of the Steam Electric Survey, EPA identified 24 impoundments providing 

combustion residual leachate flow rate information for impoundments containing combustion 

residuals. Because only a subset of plants were required to complete Part F of the Steam Electric 

Survey, EPA used these data to develop a relationship between combustion residual leachate 

flow and impoundment size to estimate flow for the other impoundments that discharge 

 

14 Retired impoundments were excluded from this analysis. 
Section 4 – Development of Model Inputs 

4-12 

combustion residual leachate. The Steam Electric Survey data contain both a combustion 

residual leachate volume and current impoundment size information for only 21 of those 24 

impoundments, based on data from Part D, Section 4.1. Using the data for these 21 

impoundments, EPA developed an impoundment-level relationship between combustion residual 

leachate volume, in gallons per day, and impoundment square footage. EPA used Equation 4-9 to 

calculate the ratio of combustion residual leachate volume, in gallons per day,15 to impoundment 

square footage for the 21 impoundments for which data were available. 

(4-9) 

Leachate Flow Per Impoundment Area Ratio (gpd/ft2) = 

Normalized Volume of Impoundment Leachate Collected / Current Surface Area 

where: 

Normalized Volume of 

Impoundment Leachate 

Collected 

= Volume of impoundment combustion residual leachate 

collected in 2009 in normalized gallons per day (gpd 

over 365 days). 

Current Surface Area = Current impoundment surface area in ft2. 

The median ratio of leachate flow to impoundment area was found to be 0.006334 gpd 

per square foot (ft2) (or 275.91 gpd/acre). The median leachate flow for all 21 impoundments was 

34,560 gpd. 

EPA developed a plant-level relationship between the acreage of impoundments that 

collect leachate from impoundments containing combustion residuals and the total 

active/inactive/open impoundment acreage from Part C, Section 1 (Ash Generation) in order to 

estimate a combustion residual leachate flow for plants that did not provide a current 

impoundment size. EPA identified 11 plants providing an impoundment-level flow in Part F and 

total impoundment area in Part C. EPA used these data to calculate the ratio of acreage for 

impoundments collecting leachate to the total acreage of impoundments at the plant using 

Equation 4-10. 

(4-10) 

Area Collecting Leachate Per Total Impoundment Area = 

(Total Surface Area of Impoundments Collecting Leachate × 1 acre / 43560 ft2) / 

Total Impoundment Acres 

where: 

Total Surface Area of 

Impoundments Collecting 

= Sum of all current surface area for all impoundments 

containing coal combustion residuals (CCRs) that 

 

15 EPA normalized the flow rates reported in Part F, Section 3 based on the gallons per day and days per year 

reported for leachate generation. EPA recalculated the normalized flow rate based on leachate generation over 365 

days for each impoundment. 
Section 4 – Development of Model Inputs 

4-13 

Leachate collect combustion residual leachate, in ft2

, from Part 

D, Section 4.1. 

Total Impoundment Acres = Impoundment acres Active/Inactive/Open 

Impoundments from Part C, Section 1. 

EPA calculated a median ratio of acreage of impoundments collecting combustion 

residual leachate to total plant impoundments acreage of 0.8071. For those plants missing an 

impoundment-specific leachate flow and an impoundment-specific acreage, EPA used Equation 

4-11 to first estimate the acreage of impoundments collecting leachate and Equation 4-12 to 

estimate the leachate flow for the estimated acreage of impoundments collecting leachate. 

(4-11) 

Estimated Acreage of Impoundments with Leachate Collection (acre) = 

Median Area Collecting Leachate Per Total Impoundment Acres × Total Impoundment Acres 

where: 

Median Area Collecting 

Leachate Per Total 

Impoundment Area 

= Median ratio of total surface area collecting 

combustion residual leachate to total impoundment 

acreage, 0.8071 (see Equation 4-10). 

Total Impoundment Acres = Impoundment acres Active/Inactive/Open 

Impoundments from Part C, Section 1. 

(4-12) 

Leachate Flow Per Plant (gpd) = Estimated Acreage of Impoundments with 

Leachate Collection × Median Leachate Flow Per Impoundment Area Ratio 

where: 

Estimated Acreage of 

Impoundments with 

Leachate Collection 

= Acreage of impoundments collecting combustion 

leachate at the plant (see Equation 4-11). 

Median Leachate Flow Per 

Impoundment Area Ratio 

= Median ratio of amount of combustion residual 

leachate generated per impoundment area, in gpd per 

acre, 275.91 gpd/acre. 

See the “Supplemental Costs and Loadings Documentation” for the development of 

Equations 4-9 and 4-12 [ERG, 2015f; see Appendix 5]. 

EPA used the following hierarchy to determine the appropriate flow rate to populate the 

“Impoundment Combustion Residual Leachate Input Table.” 

• EPA used the normalized volume of leachate collected in 2009 (gpd over 365 

days) in Part F of the Steam Electric Survey. 
Section 4 – Development of Model Inputs 

4-14 

• For impoundments that did not provide an impoundment-specific leachate flow 

rate in Part F of the Steam Electric Survey, but did provide an impoundment 

surface area in Part D, EPA used Equation 4-13 to estimate the leachate flow. 

(4-13) 

Leachate Flow Per Impoundment (gpd) = Median Leachate Flow Per Impoundment 

Area Ratio × Current Surface Area 

where: 

Median Leachate Flow Per 

Impoundment Area Ratio 

= Median ratio of amount of combustion residual 

leachate discharged per impoundment area, in gpd per 

square foot, 0.006334 gpd/ft2.

Current Surface Area = Current impoundment surface area in ft2. 

• For impoundments that did not provide an impoundment-specific combustion 

residual leachate flow rate in Part F or impoundment surface area in Part D of the 

Steam Electric Survey, but did provide a total impoundment acreage in Part C, 

EPA used Equations 4-11 and 4-12 to calculate the combustion residual leachate 

flow. 

• For plants that did not provide impoundment-specific size data in Part D or total 

impoundment acreage in Part C of the Steam Electric Survey, EPA used the 

median impoundment combustion residual leachate flow rate for all 

impoundments responding to Part F, Section 2 (34,560 gpd) for the combustion 

residual leachate discharge flow. 

4.2 WASTESTREAM POPULATION AND CHARACTERISTICS FOR COSTING

For each plant discharging FGD wastewater, combustion residual leachate, gasification 

wastewater, or operating wet fly or bottom ash handling systems, EPA estimated a compliance 

cost to treat the wastewater or, in the case of ash transport water, eliminate the discharge 

entirely.16 For FGD wastewater and landfill combustion residual leachate, the methodology for 

estimating treatment system costs is based on the volume of wastewater. For these wastestreams, 

EPA used the same input data for both costing and pollutant loadings calculations. 

EPA also estimated compliance costs associated with eliminating the discharge of ash 

transport water, by costing plants to convert to either a dry handling or a closed-loop recycle 

system. The fly ash and bottom ash costs are based on the amount and type of ash generated by 

each generating unit. Finally, EPA estimated compliance costs associated with plants discharging 

gasification wastewater. Since all plants discharging gasification wastewater already operate the 

Best Available Technology Economically Achievable (BAT) technology that is the basis for the 

 

16 Plants can eliminate the discharge of ash transport water by either converting to a dry ash handling system or operating a 

closed-loop ash recycle system. 
Section 4 – Development of Model Inputs 

4-15 

effluent limitations in the rule, the only compliance costs for this wastestream are monitoring 

costs. 

As described in Section 4.1, EPA used Steam Electric Survey and industry-submitted 

data to identify the population of plants that is projected to incur compliance costs associated 

with the ELGs. EPA did not estimate compliance costs for all plants and generating units 

identified as retiring, converting fuels, or converting their ash handling systems prior to 

implementing the ELGs. A list of all plants and generating units removed from the costs and 

loadings analysis as a result of retiring, converting fuels, or converting their ash handling 

systems is included in the “Changes to Industry Profile for Steam Electric Generating Units for 

the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015a]. The following section 

describes what population of plants is projected to incur FGD, fly ash, bottom ash, leachate, and 

gasification compliance costs and the specific plant and generating unit-level characteristics used 

to estimate these costs. 

4.2.1 FGD Wastewater 

EPA used the same input data for both costing and loadings associated with FGD 

wastewater. For details on the “FGD Input Table,” see Section 4.1.1. 

4.2.2 Fly Ash 

EPA used data from the Steam Electric Survey and industry-submitted data to identify 

which plants would incur costs to meet a zero discharge standard for pollutants in fly ash 

transport water. EPA first identified those plants that operate wet sluicing systems and discharge 

fly ash transport water. To develop this “Fly Ash Input Table,” EPA used data from Part C (Ash 

Handling) and Part A (Steam Electric Power Plant Operation) of the Steam Electric Survey and 

plant-specific data submitted by industry through public comments to identify what costing 

elements of the fly ash system would be appropriate for each generating unit and/or plant. 

EPA assessed the costs for converting to a dry fly ash handling system on a steam electric 

generating unit level. EPA examined Steam Electric Survey and industry-submitted data for each 

generating unit that uses fly ash transport water and applied a hierarchical method to determine 

the appropriate fly ash cost elements for each generating unit that operates a wet sluicing system 

and discharges fly ash transport water. First, generating units were flagged as not incurring a cost 

if the generating unit falls into any of the following subsets: 

• Retired generating units that responded “Yes” to “Is this unit now retired?” in 

Question A6-1 in Table A-8. 

• Generating units that either have already retired or converted to dry fly ash 

handling or have announced plans to do so (eliminating the discharge of fly ash 

transport water) as identified through industry-submitted data or EPA’s retirement 

and handling conversion analysis (see Section 4.1). 
Section 4 – Development of Model Inputs 

4-16 

• Generating units that did not operate in 2009, indicated by a “No” response to 

“Operated in 2009” in Question A6-1 in Table A-8.17

• Gas-fired and nuclear-fueled generating units (these units do not produce ash). 

• Generating units that did not generate fly ash, which was determined by the plant 

either responding “No” to “Is ash generated at any fossil-fueled steam electric 

generating units at the plant?” in Question C1-1 or because it did not complete 

Part C, Section 2.1. 

• Generating units that reported fly ash generation in Table C-2 and reported dry 

handling only. These generating units reported all of their fly ash generation as 

dry conveyed, did not select wet sluicing (hydraulic) in Table C-2, and responded 

“No” to “Is wet sluicing a type of fly ash handling for this steam electric 

generating unit?” in Question C2-2. 

• Generating units that indicated both wet and dry fly ash handling by responding 

“Yes” to “Was fly ash from this steam electric generating unit conveyed both wet 

and dry in 2009?” in Question C2-10. The generating units must also have 

reported that the wet system was operated when the dry system was down due to 

maintenance in response to Question C2-11 and that no system modifications 

would be required to handle all the fly ash dry in response to Question C2-12. 

• Generating units that indicated both wet and dry fly ash handling by responding 

“Yes” to “Was fly ash from this steam electric generating unit conveyed both wet 

and dry in 2009?” in Question C2-10 and indicated in Question C2-13 that use of 

the wet fly ash handling system will end before 12/31/2023. 

• Generating units that indicated both wet and dry fly ash handling by responding 

“Yes” to “Was fly ash from this steam electric generating unit conveyed both wet 

and dry in 2009?” in Question C2-10 and responding to Question C2-11 that the 

only reason the wet fly ash handling system was operated in 2009 was because the 

dry fly ash handling system had not yet been installed. 

• Generating units at plants that did not report a National Pollutant Discharge 

Elimination System (NPDES) permit in Table A-2, indicating that they do not 

discharge to surface water, and did not report an indirect discharge of fly ash 

transport water to a POTW. 

Next, EPA identified the generating units that required a complete wet-to-dry fly ash 

conversion and therefore would incur all associated fly ash capital and O&M cost elements (i.e., 

conveyance costs, silo costs, pugmill costs, and transportation/disposal costs). These generating 

units were flagged as incurring a cost and identified using the following criteria: 

 

17 Although these generating units may still have the capability to operate, since these units were not called upon to 

operate at any time in 2009, EPA assumes that the company will retire these generating units instead of expending 

resources to convert their ash handling systems. 
Section 4 – Development of Model Inputs 

4-17 

• Generating units responding “Wet sluicing (hydraulic)” in Table C-2 and 

reporting no dry handling capabilities (Dry Vacuum system, Wet Vacuum system 

(pneumatic), Pressure system, Combined Vacuum/Pressure system, or Mechanical 

system). Generating units responding “Wet sluicing (hydraulic)” and “Other” 

were handled on an individual basis to determine whether the response in the 

“Other” field indicated a wet or dry handling system. 

• Generating units responding “Wet sluicing (hydraulic)” in Table C-2 as well as 

reporting any type of dry handling capabilities (Dry Vacuum system, Wet 

Vacuum system (pneumatic), Pressure system, Combined Vacuum/Pressure 

system, or Mechanical system), but listed all of the fly ash generation as wet 

conveyed in Table C-2.18

All generating units that were not categorized using the criteria for not incurring any cost 

or for incurring the cost for a complete wet-to-dry conversion were determined to currently have 

both wet and dry fly ash handling capabilities. EPA determined that this third group of 

generating units should only require a subset of the fly ash cost elements associated with 

converting to a completely dry fly ash handling system. For example, some generating units 

would incur capital costs for installing backup or redundant equipment. These generating units 

were flagged for costing based on the responses to Questions C2-11 and C2-12.

• Generating units were identified as needing capital and O&M conveyance costs if 

the respondent selected “Install/increase the capacity of the dry fly ash conveying 

equipment” in response to “What modifications would be required to handle all 

the fly ash with the dry fly ash handling system?” in Question C2-12. 

• Generating units were identified as needing capital and O&M silo costs if the 

respondent selected either “Increase the capacity of the silo(s)” or “Increase the 

number of the silos” in response to “What modifications would be required to 

handle all the fly ash with the dry fly ash handling system?” in Question C2-12. 

• Generating units were identified as needing capital and O&M pugmill costs 

whenever the unit was identified as needing a silo cost. Additionally, generating 

units were identified as needing pugmill costs if the respondent selected “Modify 

the loading silos to have the ability to moisture condition the ash” in response to 

“What modifications would be required to handle all the fly ash with the dry fly 

ash handling system?” in Question C2-12. 

• Generating units were identified as needing transportation/disposal costs if the 

respondent selected “Install/increase the capacity of landfills” in response to 

“What modifications would be required to handle all the fly ash with the dry fly 

ash handling system?” in Question C2-12, or if the respondent selected “Wet fly 

ash handling system operated during times in which the dry fly ash was not 

 

18 Although the plants indicated that these generating units had a dry handling system, EPA assumed that a 

completely new system would be required because the plant did not use the system at all in 2009. This assumption 

may overestimate the costs for these generating units. 
Section 4 – Development of Model Inputs 

4-18 

marketable” in response to “Indicate why fly ash from the steam electric 

generating unit was conveyed both wet and dry in 2009?” in Question C2-11. 

• Generating units were identified as needing back-up capital silo and pugmill costs 

if the respondent selected “Wet fly ash handling system operated during times in 

which the dry fly ash was not marketable” in response to “Indicate why fly ash 

from the steam electric generating unit was conveyed both wet and dry in 2009?” 

in Question C2-11 and EPA determined that the plant likely did not have the 

capabilities for moisture-conditioned unloading based on responses to Question 

C2-25 (Fly Ash Storage Information); [ERG, 2015f; see Appendix 6]. EPA 

evaluated the O&M costs associated with the dry system compared to a wet 

sluicing system and determined that operating the dry fly ash handling system is a 

cost savings compared to operating a wet sluicing system. Therefore, O&M costs 

for the backup silo and pugmill are not calculated as part of the compliance cost 

estimates; see the [ERG, 2015f; see Appendix 6]. 

• Generating units were identified as needing capital costs for conveyance system 

redundancy (e.g., additional filter-receivers, vacuum pumps, and/or pressure 

blowers based on the existing system design) if the respondent selected “Other” in 

response to “What modifications would be required to handle all the fly ash with 

the dry fly ash handling system?” in Question C2-12 and stated that some level of 

redundancy was necessary to handle all fly ash dry at the plant; [ERG, 2015f; see 

Appendix 6]. EPA evaluated the O&M costs associated with the dry system 

compared to a wet sluicing system and determined that operating the dry fly ash 

handling system is a cost savings compared to operating a wet sluicing system. 

Therefore, O&M costs for the redundant equipment are not calculated as part of 

the compliance cost estimates; [ERG, 2015f; see Appendix 6].

For all generating units included in this partial costs category that handled the fly ash 

both wet and dry in 2009, EPA evaluated the remaining responses in the “Other” fields for 

Questions C2-11 and C2-12 on an individual basis to identify any specific cost elements that 

should/should not be included for those plants/units [ERG, 2015f; see Appendix 6]. 

Based on responses to the Steam Electric Survey and publicly available information on 

planned retirements, fuel conversions and ash handling conversions, EPA identified 37 plants, 

corresponding to 95 generating units, discharging fly ash transport water that would incur either 

partial or complete wet-to-dry conversion costs if they had to eliminate the discharge of 

pollutants in fly ash transport water. Of these, eight plants operate 14 generating units that are 

oil-fired units or small units with a capacity less than or equal to 50 MW and thus would incur no 

costs to comply with the requirements for fly ash transport water. As a result, EPA estimated that 

31 plants19 operating 81 generating units would incur costs to comply with the requirements for 

fly ash transport water. For each of these 81 generating units, EPA identified the specific fly ash 

cost elements needed and collected the other necessary input data (i.e., generating unit-level wet 

fly ash production (in tons per day and days per year), generating unit-level dry fly ash 

 

19 Some plants operate steam electric generating units above and below the 50 MW threshold; therefore, the number 

of plants is not additive. 
Section 4 – Development of Model Inputs 

4-19 

production (in tons per day and days per year), operating days for the generating unit, nameplate 

capacity (in MW), generating unit type, and fly ash transport water flow rate (in gpd)).20 See 

Section 7.1.4 for more information about the specific fields for the “Fly Ash Input Table.” A 

copy of the “Fly Ash Input Table” is included in the FGD and Ash Steam Electric Cost Model 

[ERG, 2015d]. 

4.2.3 Bottom Ash 

EPA used data from the Steam Electric Survey and industry-submitted data to identify 

those plants that operate wet sluicing systems and discharge bottom ash transport water. To 

develop this “Bottom Ash Input Table,” EPA used data from Part C (Ash Handling) and Part A 

(Steam Electric Power Plant Operation) of the Steam Electric Survey and plant-specific data 

submitted by industry through public comments to identify what costing elements of the bottom 

ash system would be appropriate for each plant. 

EPA assessed costs for converting to a system that eliminates the discharge of bottom ash 

transport water on a steam electric generating unit level. EPA examined Steam Electric Survey 

and industry-submitted data for each generating unit utilizing bottom ash transport water and 

applied a hierarchical method to determine the most appropriate bottom ash cost elements for 

each unit. First, generating units were flagged as not incurring a cost if the unit falls into any of 

the following subsets: 

• Retired generating units that responded “Yes” to “Is this unit now retired?” in A8-

1 in Table A-8. 

• Generating units that either have already retired or converted to dry bottom ash 

handling or have announced plans to do so (eliminating the discharge of bottom 

ash transport water) as identified through industry-submitted data or EPA’s 

retirement and handling conversion analysis (see Section 4.1). 

• Generating units that responded “No” to “Operated in 2009” in A8-1 in Table A8.21

• Gas-fired and nuclear-fueled generating units (these units do not produce ash). 

• Generating units that do not generate bottom ash generation, which was 

determined by the plant either responding “No” to “Is bottom ash generated in 

any fossil-fueled steam electric generating units at the plant?” in Question C3-1 or 

because it did not complete Part C, Section 3.1. 

• Generating units that reported bottom ash generation in Table C-18 but not the 

use of wet sluicing. These generating units did not select “Wet sluicing” in Table 

 

20 As part of its analysis for the final rule, EPA also did this for the 12 oil-fired and small generating units that will 

not incur costs to comply with the requirements for fly ash transport water. 

21 Although these generating units may still have the capability to operate, since these units were not called upon to 

operate at any time in 2009, EPA assumes that the company will retire these generating units instead of expending 

resources to convert their ash handling systems. 
Section 4 – Development of Model Inputs 

4-20 

C-18, and selected “No” in response to “Is wet sluicing used to collect bottom ash 

for this steam electric generating unit?” in Question C3-3.

• Generating units that reported bottom ash generation in Table C-18 and reported 

both “Wet Sluicing” and at least one other type of bottom ash handling system, 

but listed all of the bottom ash generation as “Dry Conveyed.” 

• Generating units that indicated both wet and dry bottom ash handling by 

responding “Yes” to “Was the bottom ash from this steam electric generating unit 

conveyed both wet and dry in 2009?” in Question C3-16 and responding in the 

“Other” field for “What modifications would be required to handle all the bottom 

ash with a dry bottom ash handling system?” in Question C3-18 that the only 

reason the wet bottom ash handling system was operated in 2009 was because the 

dry bottom ash handling system had not yet been installed. 

• Generating units that indicated both wet and dry bottom ash handling by 

responding “Yes” to “Was the bottom ash from this steam electric generating unit 

conveyed both wet and dry in 2009?” in Question C3-16 and reporting in 

Question C3-19 that use of the wet bottom ash handling system will end before 

12/31/2023. 

• Generating units at plants that did not report a NPDES permit in Table A-2, 

indicating that they do not discharge to surface water, and did not report an 

indirect discharge of bottom ash transport water to a POTW. 

Next, EPA identified the generating units that required a complete conversion to a system 

that eliminates the discharge of bottom ash transport water. These generating units were 

identified using the following criteria: 

• Generating units that selected “Wet sluicing” in Table C-18 and did not report any 

dry handling capabilities (Mechanical drag system, Dry vacuum system, Dry 

pressure system). 

• Generating units that selected “Other” were handled on an individual basis to 

determine whether the response indicated a wet or dry handling system; [ERG, 

2015f; see Appendix 6]. 

EPA also identified those plants operating wet sluicing systems where the bottom ash 

transport water was recycled and not discharged in 2009, although plants may have the ability to 

discharge this wastewater (e.g., emergency outfalls). For generating units that responded “Yes” 

to “Is any of the wet bottom ash sluice water immediately recycled back to plant process?” in 

Question C3-5 and “Immediately recycled back to plant process” to “What is the destination(s) 

of the wastewater overflow from solids removal?” in Question C3-10, EPA evaluated the amount 

of transport water actually discharged. EPA identified plants that did not discharge any bottom 

ash transport water in 2009 as being able to develop a plan to manage the water balance to 

completely recycle the bottom ash transport water without requiring a discharge. Therefore, these 

plants were assessed a one-time bottom ash cost, described in more detail in Section 8.5. Because 

these generating units did not discharge any bottom ash transport water in 2009, EPA did not 
Section 4 – Development of Model Inputs 

4-21 

estimate bottom ash loadings for these generating units; therefore, these generating units will 

incur compliance costs but no pollutant reductions.22

Based on responses to the Steam Electric Survey and publicly available information on 

planned retirements, fuel conversions, and ash handling conversions, EPA identified 172 plants, 

corresponding to 406 generating units, having the potential to discharge bottom ash transport 

water that would incur costs if they had to eliminate the discharge of pollutants in bottom ash 

transport water. Of these, 18 plants operate 32 small generating units with a capacity less than or 

equal to 50 MW and thus would incur no costs to comply with the requirements for bottom ash 

transport water.23 As a result, EPA estimated that 164 plants24 operating 374 generating units 

would incur costs to comply with the requirements for bottom ash transport water. For each of 

these 374 generating units that discharge bottom ash transport water, EPA identified the specific 

cost elements that apply to the generating unit and collected the other necessary input data (i.e., 

generating unit-level wet bottom ash production (in tons per day and days per year), nameplate 

capacity (in MW), the operating days for the generating unit, and the bottom ash transport water 

rate (in gpd)).25 Additionally, EPA identified a subset of the plants having a potential to 

discharge bottom ash transport water (10 plants, corresponding to 17 generating units) that did 

not discharge any bottom ash transport water in 2009. For these 17 generating units, EPA 

assigned these units one-time bottom ash costs in the “Bottom Ash Input Table.” See Section 

8.1.3 for more information about the specific fields for the “Bottom Ash Input Table.” A copy of 

the “Bottom Ash Input Table” is located in the FGD and Ash Steam Electric Cost Model [ERG, 

2015d]. 

4.2.4 Combustion Residual Leachate 

EPA used the same input data for both costs and loadings associated with discharging 

combustion residual leachate from landfills. For details on the “Combustion Residual Leachate 

Input Table,” see Section 4.1.3.1. EPA did not estimate compliance costs for combustion residual 

leachate from impoundments (see Section 9.1 for more detail). 

4.2.5 Gasification Wastewater 

EPA identified three plants discharging gasification wastewater. EPA identified these 

plants through various contacts throughout the steam electric power generating industry. Since 

all plants discharging gasification wastewater already operate the BAT technology that is the 

basis for the effluent limitations in the rule, the only compliance costs for this wastestream are 

monitoring costs. 

 

22 EPA estimated bottom ash management costs for only those plants that did not discharge bottom ash transport 

water in 2009 instead of including those plants that recycle a majority (i.e., more than 90 percent) of the bottom ash 

transport water, as estimated for proposal. 

23 Additionally, 97 plants operate 226 generating units with a capacity less than or equal to 400 MW and thus would 

incur no costs to comply with requirements for bottom ash transport water under Regulatory Option C. 

24 Some plants operate steam electric generating units above and below the 50 MW threshold; therefore, the number 

of plants is not additive. 

25 As part of its analysis for the final rule, EPA also did this for the 32 small generating units that will not incur costs 

to comply with the requirements for bottom ash transport water. 
Section 4 – Development of Model Inputs 

4-22 

4.3 CCR RULE COORDINATION METHODOLOGY

Because the final CCR rule was promulgated prior to the final ELGs, EPA adjusted the 

final ELG analyses to account for the implementation of the final CCR rule. To do this, EPA 

updated its population of plants/generating units and associated treatment in place to account for 

the changes in plant operations that EPA projected under the CCR rule. Sections 4.3.1 and 4.3.2 

provide a brief background on the CCR rule and a description of how EPA used the analysis 

output from the CCR rule to adjust compliance cost and pollutant loading estimates for the 

ELGs, respectively. Section 4.3.3 presents the input table used as input for cost and loadings 

models. 

4.3.1 Background on CCR Rule Costing Approach 

The final CCR rule establishes requirements for the management of impoundments and 

landfills containing CCRs. Based on the final CCR requirements, some plants will alter the 

operation of their current CCR impoundments, including the following potential changes in 

operation: 

• Close disposal surface impoundment26 and open a new disposal surface 

impoundment in its place. 

• Convert disposal surface impoundment to a new storage impoundment.27

• Close disposal surface impoundment and convert to dry handling operations. 

• Make no changes to the operation of the disposal surface impoundment. 

The CCR rule accounts for the costs of these changes to the impoundment operations in 

its costing analyses, along with the other CCR rule requirements. Some of the inputs and 

methodologies used to develop the cost estimates for the CCR rule differ from those in the ELG 

due to differences in data sources and the analytical methodologies used. The following 

identifies some of the key differences between the costing approaches used by the CCR rule 

compared to the ELG: 

• The CCR rule uses a probabilistic modeling approach to estimate compliance 

costs. 

• The CCR rule uses a different population of impoundments based on its survey. 

• The CCR rule develops industry-level costs compared to the plant-level costs 

developed for the ELG. 

• The CCR rule uses EIA data for the annual tonnage of ash disposed in its 

impoundments to estimate costs. ELG costs for fly ash and bottom ash use Steam 

Electric Survey data for the ash tonnage generated by each unit. 

 

26 For the CCR rule, a disposal surface impoundment is generally defined as an impoundment that is not dredged 

and all CCRs are left in place in perpetuity. 

27 For the CCR rule, a storage impoundment is generally defined as an impoundment that is periodically dredged and 

has its CCR disposed of elsewhere such that it can continue operating indefinitely. 
Section 4 – Development of Model Inputs 

4-23 

• The CCR rule evaluates costs over a 100-year time frame. 

Because of these different analytical frameworks, the CCR rule analysis did not produce 

the uni-level costs that would have enabled EPA to simply subtract the CCR rule costs from the 

ELG cost output. Therefore, EPA developed an approach that uses certain analytical outputs 

from the Regulatory Impact Analysis (RIA) for the CCR rule to evaluate what changes, due to 

the CCR rule, would occur in the industry prior to the implementation of the final ELGs. This 

approach uses the yearly probabilistic model output from the CCR rule to evaluate the changes to 

specific power plants. The CCR rule output included the following information for each year in 

the analysis (at an impoundment level): 

• Unique ORCR Pond ID (which includes the Energy Information Administration 

(EIA) Plant ID). 

• Year of analysis (e.g., 2015-2114).28

• Age of the impoundment. 

• Future Management Method (Baseline Scenario), which represents the expected 

decision that the plant will make regarding the impoundment in the absence of the 

CCR rule (i.e., decision made based on compliance with state regulations). 

• Probability of surface impoundment converting to a storage impoundment and 

various disposal options (i.e., off-site landfill, existing on-site landfill, newly built 

on-site dug landfill, newly built on-site pile landfill). 

• Probability of surface impoundment closing, converting to dry handling, and 

various disposal options (i.e., off-site landfill, existing on-site landfill, newly built 

on-site dug landfill, newly built on-site pile landfill)). 

• Probability of surface impoundment closing, converting to dry handling, and 

disposal in newly built on-site pile landfill built on top of closed disposal 

impoundment; 

• Probability of surface impoundment closing and a newly built on-site disposal 

surface impoundment opens in its place. 

• Probability that surface impoundment has not yet reached a decision point. 

A copy of the CCR rule probabilistic output can be found in the “Supplemental Costs and 

Loadings Documentation” [ERG, 2015f; see Appendix 7]. 

The final CCR rule evaluated the probability of these specific options for only plants that 

were identified as operating disposal impoundments based on EIA data.29 For the CCR rule, 

 

28 Office of Resource Conservation and Recovery (ORCR) analyzes decisions related to the CCR rule over a 100-

year analysis period. Therefore, there are 100 records for each disposal impoundment corresponding to each year of 

the analysis. 

29 For the CCR rule, if a plant reported active wet CCR disposal in one or more impoundments in its EIA data, EPA 

considered the largest impoundment (in terms of capacity) at the plant as a CCR disposal impoundment. 
Section 4 – Development of Model Inputs 

4-24 

EPA did not evaluate these options for storage impoundments because EPA assumed that storage 

impoundments will operate indefinitely and if a ground water contamination event occurs, the 

plant will build a new storage impoundment (but will not convert to dry handling operations), 

thus resulting in no change to the plant’s operation or treatment based on the CCR rule.30 

4.3.2 Methodology for Incorporating CCR Rule Output 

Using the probabilistic output from the CCR rule, EPA evaluated the output to select the 

most likely compliance approach for the CCR rule for each plant/impoundment. Because the 

ELG is expected to be fully implemented by December 31, 2023,31 EPA analyzed the CCR rule 

probabilistic output in year 2023 to determine the most likely outcome that plants would have 

made by that point based on the CCR rule. This was done to identify those changes in operations 

that plants will make to comply with the CCR rule prior to implementing the new requirements 

established by the ELG. For this analysis, EPA summed the probabilities for various disposal 

options for each main CCR management method decision option listed in Section 4.3.1. For 

example, to determine the overall probability of the plant converting to dry handling, EPA 

summed the probability for each of the following: 

• Probability of surface impoundment closing, converting to dry handing, and 

disposal shifts to off-site landfill. 

• Probability of surface impoundment closing, converting to dry handing, and 

disposal shifts to existing on-site landfill. 

• Probability of surface impoundment closing, converting to dry handing, and 

disposal shifts to newly built on-site pile landfill.

• Probability of surface impoundment closing, converting to dry handing, and 

disposal shifts to newly built on-site dug landfill. 

• Probability of surface impoundment closing, converting to dry handing, and 

disposal shifts to newly built on-site pile landfill built on top of closed surface 

impoundment. 

EPA summed the various disposal options because the important aspect for this analysis 

is the determination of what changes will occur in the operation of the impoundment and the ash 

handling system, because changes in these operations may affect the ELG compliance costs. This 

was done using the CCR probabilistic model output for year 2023 and determining which CCR 

management method had the highest probability of occurring. In cases where two CCR 

management methods had the highest and equal probability in year 2023 (e.g., 45 percent for 

conversion to storage impoundments and 45 percent for conversion to dry handling), the ELG 

cost analysis assumes the plant will use the CCR management method that has the least effect on 

the ELG (i.e., assuming more costs are borne by the ELG). This approach is intended to avoid 

situations where the ELG is underestimated. 

 

30 For the CCR rule, if a plant did not report active wet CCR disposal in any impoundments in its EIA data, EPA 

considered all impoundments at the plant to be CCR storage impoundments. 

31 The final ELGs require that the revised effluent limitations shall apply no later than December 31, 2023. 
Section 4 – Development of Model Inputs 

4-25 

The CCR Rule’s model essentially assumes that each plant has just one disposal 

impoundment and all wet disposal tonnage is associated with that disposal impoundment; 

therefore, for any CCR materials (i.e., fly ash, bottom ash, FGD solids) reported in EIA as being 

disposed of in on-site impoundments at those plants, all decisions made regarding the CCR 

management method selected for the CCR rule are assumed to apply to all generating units that 

handle the CCR material wet.32 For example, if the likely CCR management method selected for 

the CCR rule is determined to be that the impoundment closes and plant converts to dry 

handling, then EPA would make the following assumptions: 

1. All generating units with wet fly ash handling at that plant are converted to dry 

handling under the CCR rule. 

2. All generating units with wet bottom ash handling at that plant are converted to 

dry handling under the CCR rule. 

3. All FGD wastewater generated at the plant is directed to an FGD chemical 

precipitation wastewater treatment system under the CCR rule.33

Table 4-1 presents a list of potential CCR management methods under the CCR rule and 

shows which methods (i.e., compliance approaches) would potentially reduce the cost to comply 

with the ELGs. 

After determining the most likely CCR management method for the CCR rule, EPA then 

evaluated how that decision affects the ELG baseline population. Since the final CCR rule was 

promulgated prior to the ELGs, all costs associated with the compliance approach selected for 

each plant are accounted for in the costs calculated for the CCR rule. Similarly, all pollutant 

removals associated with the compliance approach selected for each plant (e.g., ceasing 

discharge of ash transport water due to converting to dry ash handling systems) would be 

attributed to the CCR rule. The following describes how EPA incorporated the CCR rule into the 

ELG baseline population for each “Group Number” identified in Table 4-1: 

• Group Number 1 

For disposal surface impoundments that are expected to close and have a new 

disposal surface impoundment open in its place, there is no change in operation, 

or in the amount or characteristics of pollutants discharged. Therefore, there is no 

effect on the ELG baseline population. 

• Group Number 2 

For disposal surface impoundments that are expected to convert to a storage 

impoundment, the CCR material that was previously stored in the disposal surface 

impoundment will now be disposed by the plant in an on-site or off-site landfill. 

 

32 This plant-level approach carries through to the ELG analysis. To determine which generating units the future 

management method applies to, EPA identified generating units with wet handling based on responses to the Steam 

Electric Survey. 

33 If the plant had not reported disposal of FGD solids in the EIA data, EPA would assume that the FGD wastewater 

at the plant would continue to be transferred to the current baseline treatment system (e.g., surface impoundment). 
Section 4 – Development of Model Inputs 

4-26 

This change in operations would occur prior to the plant taking action to comply 

with new requirements established by the ELGs. With the plant now using a 

storage impoundment instead of a disposal impoundment, CCRs no longer remain 

for extended periods in the impoundment. This means that the plant is now 

regularly dredging solids from the impoundment and then transporting them to an 

on-site or off-site landfill for disposal (or, potentially, sending the solids to 

beneficial use). As a result, should the plant later convert to dry ash handling to 

comply with the ELG, there would be no transport/disposal attributable to the 

ELG because these solids are already being hauled to the disposal site by the 

plant. In fact, the plant would likely realize cost savings attributable to the ELG 

by converting to dry ash handling because it costs less to transport and dispose of 

ash from a dry handling system than disposing of ash stored in an impoundment. 

For FGD wastewater, however, under the operation of the storage impoundment, 

only the FGD solids entering the impoundment would need to be removed, 

transported, and disposed of under the CCR rule, but under the ELG, the plant 

would also need to transport and dispose of all treatment system solids resulting 

from the FGD chemical precipitation and biological treatment system. Therefore, 

EPA did not make any adjustments to the ELG baseline population for FGD 

solids disposal for these plants. 

• Group Number 3 

For disposal surface impoundments that are expected to close and convert to dry 

handling, EPA assumed that plants will convert their fly ash and bottom ash 

handling systems to dry systems and the plant will install a chemical precipitation 

system to handle the FGD wastewater. Therefore, EPA adjusted the ELG baseline 

population as follows for each wastestream:34 

Fly ash transport water: Plant operates a dry fly ash handling and all fly ash is 

disposed of. 

Bottom ash transport water: Plant operates a dry bottom ash handling and all 

bottom ash is disposed of. 

FGD wastewater: Plant operates a full BAT chemical precipitation system and all 

solids from the chemical precipitation system are disposed of. 

• Group Number 4 

For disposal surface impoundments that are not expected to reach a decision point 

by year 2023, there is no change in operation and, therefore, there is no effect on 

the ELG baseline population. 

 

34 The changes to the ELG baseline population only apply to the CCR materials that the plants reported disposing of 

in the EIA, in which case, the CCR rule is accounting for the costs for the conversion. For example, if a plant 

reported disposal tonnages for fly ash and bottom ash but not for FGD solids, then EPA would apply the ELG 

baseline population changes described in the bullets to fly ash transport water and bottom ash transport water, but

EPA would not make any changes to the ELG baseline population for FGD wastewater. 
Section 4 – Development of Model Inputs 

4-27 

For the CCR rule, EPA assumed that storage impoundments will operate indefinitely and 

if a ground water contamination event occurs, the plant will build a new storage impoundment. 

EPA reviewed the EIA data that it used for the CCR rule to identify the plants operating only 

storage impoundments under the CCR rule. For these plants, EPA evaluated whether fly ash 

and/or bottom ash were reported as “disposed” in the EIA data. Because the plants reported to 

EIA that they are disposing of those CCR materials in places other than the impoundments (e.g., 

landfill, beneficial reuse), EPA assumed that there would be no incremental change to the 

transportation and disposal costs for these plants after conversion to dry handling operations. For 

example, if a plant’s current operation consists of wet sluicing fly ash to an impoundment, 

dredging the solids on an annual basis, and disposing of the solids in an off-site landfill, EPA 

assumed that there would be no increase in the costs for that transportation/disposal compared to 

trucking the dry fly ash to the same off-site landfill after the plant converts to a dry fly ash 

handling system to comply with the final ELG. As such, EPA flagged these plants and the 

wastestreams associated with the materials meeting this criteria in Group Number 2 (Disposal 

Surface Impoundment Converts to Storage Impoundment) to indicate that all fly ash and/or 

bottom ash is already disposed of by the plant [ERG, 2015f; see Appendix 7]. 

4.3.3 CCR Rule Coordination Input Table 

Based on these analyses described in Section 4.3.2, EPA generated the “CCR Input 

Table” that was used in the costs model and loadings databases to adjust the ELG baseline 

population to account for the final CCR rule. 

After adjusting the ELG population to account for the implementation of the final CCR 

rule, EPA generated the costs, pollutant loadings, non-water quality impacts, environmental 

assessment, and benefits of the rule. As such, EPA has minimized the degree to which its 

analyses have potentially “double counted” compliance costs and benefits associated with the 

final ELG and the final CCR rule. A copy of the “CCR Input Table” is located in the FGD and 

Ash Steam Electric Cost Model as well as the models used to calculate pollutant loadings [ERG, 

2015d]. Table 4-2 presents the number of plants and stream electric generating units for which 

EPA estimated compliance costs associated with the ELG accounting for the CCR rule, and 

Table 4-3 presents the number of plants and steam electric generating units expected to achieve 

pollutant removals as a result of the ELG accounting for the CCR rule. 

As discussed earlier in Section 1, EPA conducted a sensitivity analysis to evaluate 

estimated compliance costs and pollutant loadings associated with the ELG without including 

adjustments for the CCR rule. A copy of the plant-specific data used to estimate compliance 

costs for the ELG without adjusting for CCR is located in the FGD and Ash Steam Electric Cost 

Model [ERG, 2015d]. A copy of the plant-specific data used to estimate pollutant loadings for 

the ELG without adjusting for CCR is located in the various pollutant loadings models (FGD 

Pollutant Loadings Database or Ash Loadings Database) [ERG, 2015b; ERG, 2015e]. Plant-level 

compliance cost estimates and pollutant loadings without the CCR rule are included in Appendix 

B. All compliance cost estimates and pollutant loadings and removals discussed in this report 

hereafter reflect the baseline population with updates for the final CCR rule. 
Section 4 – Development of Model Inputs 

4-28 

4.4 POLLUTANT CONCENTRATIONS

EPA calculated analyte-level pollutant loadings for each of the technology options 

considered as part of the Steam Electric ELGs. Sections 11 through 14 discuss the calculation of 

these pollutant loadings in detail. The pollutant loadings are calculated from wastestream 

characterization data collected through EPA sampling activities, Steam Electric Survey data, 

other EPA data requests, and publicly available sources. Sections 11 through 14 discuss pollutant 

loadings for each of the wastestreams considered for regulation: 

• FGD wastewater. 

• Fly ash transport water. 

• Bottom ash transport water. 

• Combustion residual leachate. 

• Flue gas mercury control wastewater. 

• Gasification wastewater. 

4.5 PLANT CHARACTERISTICS

EPA used a variety of plant-specific data from public sources and the Steam Electric 

Survey to develop input tables and cost factors used to calculate the plant-specific costs and 

loadings associated with the revisions to the Steam Electric ELGs. Section 4.5 goes into detail on 

the types of data that were used to adjust the population of plants incurring compliance costs and 

pollutant loadings. This section discusses the following topics: 

• Methodology for identifying existing FGD wastewater treatment at plants 

discharging FGD wastewater and not affected by the CCR rule (see Section 

4.5.1). 

• Approach for handling FGD wastewater treatment systems with an average 24-

hour FGD wastewater flow greater than or equal to 1,000 gallons per minute 

(gpm) (see Section 4.5.2). 

• Evaluation of climate information to assess the need for additional infrastructure 

at plants located in specific cold climates (see Section 4.5.3). 

Further description of how these specific characteristics were used to adjust an individual cost 

element is discussed in Sections 6 through 10 as they apply to each wastestream. 

4.5.1 FGD Treatment-in-Place Input 

For those plants discharging FGD wastewater and not affected by the CCR rule, EPA 

also documented the type of treatment system they operate.35 Table 4-4 includes data on each 

plant’s current level of treatment for its FGD wastewater. For plants currently treating the FGD 

wastewater using a chemical precipitation, an anoxic/anaerobic biological treatment, or an 

 

35 EPA also evaluated existing FGD wastewater treatment for those plants effected by the CCR rule in order to more 

accurately estimate compliance costs and pollutant loadings associated with the sensitivity analysis that evaluates 

costs and loadings for all generating units without the CCR rule or Clean Power Plan (CPP) rule. 
Section 4 – Development of Model Inputs 

4-29 

evaporation system, EPA assessed credit for existing treatment systems as part of the costs and 

loadings models. EPA used survey data and industry-submitted data to determine the appropriate 

level of baseline treatment. A description of how EPA used Steam Electric Survey data to assess 

the level of treatment in place is presented in Sections 6.1.3 and 11.3. A list of all plants adjusted 

for the costs and loadings analysis as a result of treatment upgrades announced since the Steam 

Electric Survey is included in the “Changes to Industry Profile for Steam Electric Generating 

Units for the Steam Electric Effluent Guidelines Final Rule” [ERG, 2015a]. Table 4-4 lists the 

plant identification numbers for those plants identified as having some amount of treatment in 

place for each type of technology. 

4.5.2 High-Flow FGD Treatment Systems 

EPA categorized five plants with an average 24-hour plant-level FGD wastewater flow 

rate greater than or equal to 1,000 gpm as “high-flow” plants. For these plants with high FGD 

wastewater flows, EPA determined it would be less expensive for a plant to implement 

additional recycle within the FGD system to allow for installing a treatment system with a lower 

overall treatment flow rate, rather than install a FGD wastewater treatment system capable of 

treating the maximum wastewater flow. However, some FGD systems already operate at or near 

the maximum chlorides operating concentration and, therefore, would not be able to increase 

their level of recycle without potentially corroding the FGD scrubber system. 

EPA used data from the Steam Electric Survey to identify the FGD systems with the 

potential capability to recycle some of the FGD wastewater and to quantify the amount of 

recycle that can be accommodated without corroding the FGD scrubber system. Wherever 

possible, based on a plant’s operating chlorides concentration and maximum design chlorides 

concentration, EPA adjusted the wastewater flow used to estimate costs associated with the FGD 

wastewater treatment system to reflect a smaller FGD wastewater flow. EPA expects that these 

plants will choose to reuse some of the FGD wastewater as absorber make-up water, reagent 

preparation water. EPA’s methodology, described in Section 6, includes capital and operation 

and maintenance costs associated with a pump and piping to transfer the recycled FGD 

wastewater from the treatment system back to the scrubber. EPA’s methodology does not expect 

plants to modify existing FGD scrubbers to include new recirculation pumps on the absorber. 

For all “high-flow” plants without some level of treatment in place, EPA compared each 

FGD system’s current operating chlorides level to the specified maximum design chlorides limit 

reported by each plant in Part B, Section 4 (Flue Gas Desulfurization Systems – Wet FGD 

System Information) of the Steam Electric Survey. Based on site visit discussions and data from 

the industry, EPA determined that plants can operate up to 80 percent of the maximum design 

chlorides level without significant corrosion concerns.36 As a result, EPA identified any system 

operating below 80 percent of the plant-specific maximum design level threshold reported in the 

Steam Electric Survey as having the potential to recycle some FGD wastewater. In cases where 

plants provided public comments indicating a specific chlorides operating limit lower than the 80 

percent of the plant-specific maximum design level threshold reported in the Steam Electric 

 

36 EPA notes that some plants reported in response to the Steam Electric Survey as operating the FGD scrubber 

system at or above the maximum design chlorides concentration. However, EPA does not believe that is a 

sustainable approach for the long-term life of the FGD system. 
Section 4 – Development of Model Inputs 

4-30 

Survey, EPA used the chlorides value from comments instead. Three of the five “high-flow” 

plants were identified as having the potential to implement some level of FGD wastewater 

recycle. For the other two “high-flow” plants, EPA determined that no amount of FGD 

wastewater recycle could be achieved and, therefore, EPA made no adjustments to the 

wastewater flow rate and costed these plants to treat the full FGD wastewater flow rate. 

For the three “high-flow” plants where EPA determined that recycle could be 

implemented, EPA then calculated a new FGD wastewater treatment flow rate and the flow of 

the FGD recycle stream. The new FGD wastewater treatment flow rate was calculated based on 

the acceptable degree of flow reduction a given system can accommodate without exceeding 80 

percent of the plant-specific maximum chlorides limit reported in the Steam Electric Survey. 

EPA used Equations 4-14 and 4-15 to calculate the new FGD wastewater treatment flow rate. 

For more discussion on how these equations were developed, see the “Supplemental Costs and 

Loadings Documentation” [ERG, 2015f; see Appendix 8]. 

(4-14) 

Acceptable Degree of Flow Reduction = (Max Design Cl Level × 0.8 – Operating Cl Level) / 

Operating Cl Level

(4-15) 

New FGD Wastewater Treatment Flow = Current FGD Wastewater Treatment Flow / 

(1+ Additional Recycle Passes) 

where: 

Max Design Cl Level = Maximum design chlorides concentration as reported 

in Part B, Section 2 of the Steam Electric Survey. 

Operating Cl Level = Typical operating chlorides concentration in the FGD 

scrubber as reported in Part B, Section 5 of the Steam 

Electric Survey. 

Current FGD Wastewater 

Treatment Flow 

= Current FGD wastewater treatment flow rate as 

reported in the Steam Electric Survey. 

Acceptable Degree of Flow 

Reduction 

= Number of additional scrubber passes that can be 

achieved based on operating chloride concentration 

(see Equation 4-14). 

The flow of the recycle stream was calculated as the differential between the current FGD 

wastewater treatment flow and the new FGD wastewater treatment flow. 

EPA developed a “High-Flow FGD Input Table” to hold plant-specific information on 

the five “high-flow” plants evaluated for FGD recycle. The “High-Flow FGD Input Table” is 

included in the FGD and Ash Steam Electric Cost Model [ERG, 2015d]. Section 6 provides 

detail on how costs for these high flow plants were estimated. 
Section 4 – Development of Model Inputs 

4-31 

4.5.3 Cold Climate Plants 

EPA’s cost methodologies for estimating compliance costs for FGD wastewater 

biological treatment and remote mechanical drag systems for bottom ash account for costs 

associated with constructing and erecting buildings to house treatment equipment for plants 

located in cold climates. For the biological treatment system, these buildings serve to protect 

microorganisms from freezing and, for the remote mechanical drag system, the buildings protect 

equipment from winter exposure and cold temperature as well as protect workers during routine 

maintenance activities. 

Using latitude and longitude data from the Steam Electric Survey, EPA compared the 

plant location to a map of mean daily minimum temperatures downloaded from the National 

Oceanic and Atmospheric Administration’s (NOAA’s) National Climate Data Center. Figure 4-1 

is the map obtained from NOAA’s website. Using the plant-specific coordinates, EPA identified 

38 plants located in areas with a mean daily minimum temperature at or below 32°F and 

determined that these plants would require buildings to protect wastewater treatment equipment. 

EPA developed a “Cold Climate Input Table” table to identify which plants would 

require additional building costs for bottom ash and/or FGD wastewater biological treatment. 

See Sections 6.2.5.6 and 8.2 for more detailed information on how the specific building costs are 

handled for FGD wastewater biological treatment and bottom ash dry handling technologies, 

respectively. A copy of the “Cold Climate Input Table” is included in the FGD and Ash Steam 

Electric Cost Model [ERG, 2015d]. 

4.6 DISPOSAL OF COMBUSTION RESIDUALS

EPA also used plant-specific data from the Steam Electric Survey to develop the input 

tables used to estimate the transport, disposal, and surface impoundment operating costs 

associated with solids resulting from the ELGs (e.g., dry ash that was previously deposited in 

impoundments or solids from the FGD wastewater treatment system). Costs associated with 

transportation and disposal of combustion residuals generated as a result of the ELG are based on 

whether plants utilize an on-site or offsite-landfill. Section 4.6.1 provides more detail on the 

input table associated with transportation and disposal costs. Costs associated with surface 

impoundment operation are cost savings based on whether plants currently operate an 

impoundment containing specific types of combustion residuals that will no longer be deposited 

in an impoundment as a result of the ELG. Section 4.6.2 provides more detail on the input table 

associated with surface impoundment operation costs. 

4.6.1 Combustion Residual Landfills 

To estimate transport and disposal costs, EPA evaluated Part A Steam Electric Survey 

data to determine the population of plants with on-site active or inactive landfills containing 

combustion residuals including FGD solids, fly ash, and/or bottom ash. This input table, called 

the “Landfill Input Table,” determines the type of transport and disposal costs (i.e., on-site or 

off-site) estimated for the plant. EPA assumed that if a plant already has an on-site landfill, the 

plant would dispose of the additional wastes generated as a result of the final ELGs in the on-site 

landfill. If a plant does not have a currently operating on-site landfill, EPA assumed that the plant 
Section 4 – Development of Model Inputs 

4-32 

would dispose of the combustion residuals at an off-site landfill. A copy of the “Landfill Input 

Table” is located in the FGD and Ash Steam Electric Cost Model [ERG, 2015d]. 

4.6.2 Combustion Residual Surface Impoundments 

EPA also evaluated Part A Steam Electric Survey data to determine the population of the 

plants operating one or more surface impoundments containing combustion residuals. The 

“Surface Impoundment Input Table” designates the specific combustion residual waste(s) (i.e., 

FGD solids, fly ash, and/or bottom ash) stored in surface impoundments located at the plant. A 

copy of the “Surface Impoundment Input Table” is located in the FGD and Ash Steam Electric 

Cost Model [ERG, 2015d]. 

4.7 REFERENCES

1. ERG. 2015a. Eastern Research Group, Inc. “Changes to Industry Profile for Steam 

Electric Generating Units for the Steam Electric Effluent Guidelines Final Rule.” (30 

September). DCN SE05069. 

2. ERG. 2015b. Eastern Research Group, Inc. Ash Loadings Model, Accounting for CCR. 

(30 September). DCN SE05584. 

3. ERG. 2015c. Eastern Research Group, Inc. Combustion Residual Leachate Loadings 

Database. (30 September). DCN SE05840. 

4. ERG. 2015d. Eastern Research Group, Inc. FGD and Ash Steam Electric Cost Model. (30 

September). DCN SE05841. 

5. ERG. 2015e. Eastern Research Group, Inc. FGD_CCR Loadings Database. (30 

September). DCN SE05866. 

6. ERG. 2015f. Eastern Research Group, Inc. “Supplemental Costs and Loadings 

Documentation.” (30 September). DCN SE05839. 

7. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development 

Document for the Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category. (30 September). DCN SE05904. 
Section 4 – Development of Model Inputs 

4-33 

Table 4-2. Number of Steam Electric Plants and Generating Units Expected to Incur 

Compliance Costs by Wastestream and Regulatory Option Accounting for CCR

Regulatory 

Option 

FGD 

Wastewater 

Fly Ash 

Transport 

Water 

Bottom Ash 

Transport 

Water 

Combustion 

Residual 

Leachate 

Gasification 

Wastewater

FGMC 

Wastewater Total a 

A 87 (215 units) 19 (45 units) 0 0 3 (3 units) 0 100 (236 units)

B 87 (215 units) 19 (45 units) 0 0 3 (3 units) 0 100 (236 units)

C 87 (215 units) 19 (45 units) 78 (147 units) 0 3 (3 units) 0 139 (306 units)

D 87 (215 units) 19 (45 units) 141 (313 units) 0 3 (3 units) 0 181 (408 units)

E 87 (215 units) 19 (45 units) 141 (313 units) 82 (196 units) 3 (3 units) 0 196 (444 units)

a – The number of plants and generating units incurring costs is not additive for each regulatory option because 

some plants and units may incur costs for multiple wastestreams. 

Table 4-3. Number of Steam Electric Plants and Generating Units Expected to Achieve 

Pollutant Removals by Wastestream and Regulatory Option Accounting for CCR

Regulatory 

Option 

FGD 

Wastewater 

Fly Ash 

Transport 

Water 

Bottom Ash 

Transport 

Water 

Combustion 

Residual 

Leachate 

Gasification 

Wastewater

FGMC 

Wastewater Total a 

A 36 (89 units) 25 (61 units) 0 0 0 0 54 (131 units)

B 71 (176 units) 25 (61 units) 0 0 0 0 86 (207 units)

C 71 (176 units) 25 (61 units) 73 (137 units) 0 0 0 122 (273 units)

D 71 (176 units) 25 (61 units) 132 (297 units) 0 0 0 162 (373 units)

E 71 (176 units) 25 (61 units) 132 (297 units) 82 (196 units) 0 0 184 (425 units)

a – The number of plants and generating units expected to achieve pollutant removals is not additive for each 

regulatory option because some plants and units may achieve removals for multiple wastestreams. 

Table 4-1. CCR Rule Compliance Approaches and Overlap with ELG Costs/Loadings 

Likely Future Management 

Method (i.e., Compliance 

Approach) Selected for the 

CCR Rule in Year 2023 

Group 

Number 

Does Not Affect 

ELG Costs & 

Loadings 

Affects ELG FGD 

and/or Ash Costs 

& Loadings 

Affects ELG 

Transport & 

Disposal Costs 

Disposal Surface Impoundment 

Closes, New Disposal Surface 

Impoundment Opens in Place 

1 

Disposal Surface Impoundment 

Converts to Storage Impoundment 

2 

Disposal Surface Impoundment 

Closes, Converts to Dry Handling 

3  

Disposal Surface Impoundment 

Does Not Reach a Decision Point 

by Year 2023 

4 
Section 4 – Development of Model Inputs 

4-34 

Table 4-4. FGD Treatment-In-Place Input Table Not Accounting for CCR

Highest Level of FGD Wastewater 

Technology 

Steam Electric Survey Plant ID Numbers Plants with Treatment in 

Place

Chemical Precipitation 00103, 00771, 01236, 01381, 01402, 02079, 02268, 02297 ,02383, 02536, 

03196, 03200, 03265, 03709, 03831, 04122, 04237, 04533, 04679, 

05015, 05318, 05477, 05570, 06283, 06377, 06616, 07256, 07785, 

08308, 08353, 08661, 09161, 09225, 09671, 09805, 09948 

Anoxic/Anaerobic Biological Treatment 02550, 04543, 08661, 09391

Evaporation 03095, 06689
Section 4 – De

4-35 

Figure 4-1. Map of Steam Electric Power Plants by Mean Daily Minimum Temperatur
[Sections 5, 6, 7, and 8 contain Confidential Business Information and have been removed 

from this document] 
Section 9 – Combustion Residual Leachate Cost Methodology 

9-1 

9. COMBUSTION RESIDUAL LEACHATE COST 

METHODOLOGY 

Combustion residuals can include flue gas desulfurization (FGD) solids, fly ash, and/or 

bottom ash. Some plants collect and discharge combustion residual leachate from landfills and 

impoundments containing these combustion residuals. EPA estimated capital and operation and 

maintenance (O&M) costs associated with installing and operating a chemical precipitation 

treatment system to treat combustion residual leachate from landfills. EPA finds that plants with 

combustion residual leachate from surface impoundments are not likely to incur costs associated 

with any leachate requirements (see Section 9.1). Where a plant generates both landfill 

combustion residual leachate and FGD wastewater, EPA evaluated the combustion residual 

leachate compliance costs separate from the FGD wastewater treatment (i.e., those plants 

discharging combustion residual leachate and FGD wastewater would install two separate 

wastewater treatment systems, one to treat the combustion residual landfill leachate and one to 

treat the FGD wastewater). 

The remainder of this section describes the capital and O&M costs associated with 

treating combustion residual landfill leachate. 

9.1 TECHNOLOGY DESCRIPTION

EPA estimated compliance costs for plants generating combustion residual leachate from 

landfills or surface impoundments to comply with the effluent limitations guidelines and 

standards (ELGs) based on treatment by the chemical precipitation technology. 

Section 6.1 details EPA’s methodology for calculating plant-specific costs for a chemical 

precipitation treatment system for the treatment of FGD wastewater. These same cost 

methodologies were used to generate plant-level costs for the treatment of combustion residual 

landfill leachate. The equations presented in Section 6.1 were applied to the flow rate of 

combustion residual leachate from a landfill containing combustion residuals, referred to as 

‘leachate flow’ throughout this section. Section 4.2.4 describes EPA’s methodology for 

estimating leachate flows for those plants identified as discharging leachate from landfills 

containing combustion residuals. 

Plants that generate surface impoundment leachate will likely use a different approach 

than installing the technology basis to comply with limitations or standards imposed on 

combustion residual leachate. EPA determined that 40 percent of plants generating combustion 

residual leachate from impoundments containing combustion residuals recycle the combustion 

residual leachate back to the impoundment from which it was collected. Additionally, some 

plants use the impoundment leachate for dust control at a landfill or to moisture-condition ash 

transported to a landfill. Based on these data, EPA determined that if the final rule included a 

limitation on the discharge of combustion residual leachate, plants would comply with the 

limitation by recycling the leachate back to the impoundment from which it was generated (or 

use the leachate for dust control/moisture conditioning) instead of installing the technology 

option to treat and discharge the wastewater because it is a less expensive alternative. There are 

negligible costs associated with recycling the leachate back to the impoundment because the 
Section 9 – Combustion Residual Leachate Cost Methodology 

9-2 

plant will either: 1) use the existing pump that transfers the leachate to a separate location to 

pump it back to the impoundment; or 2) install a pump to transfer the leachate to the 

impoundment, in which case the costs would be offset because the plant no longer needs to 

operate a separate impoundment (or other treatment system) to treat the leachate to meet the 

existing Best Practicable Control Technology Currently Available (BPT) effluent limitations 

prior to its discharge. Therefore, there are no compliance costs for combustion residual leachate 

from surface impoundments. Where this section further addresses the costing methodology for 

combustion residual leachate, it refers to the costs associated with the treatment of combustion 

residual leachate from landfills. 

9.2 POPULATION COSTED

An incremental compliance cost for combustion residual leachate is assessed to any plant 

identified as collecting and discharging leachate from a landfill containing combustion residuals. 

EPA used data from Part A (Steam Electric Power Plant Operations) and Part F (Management 

Practices for Ponds/Impoundments and Landfills) of the Questionnaire for the Steam Electric 

Power Generating Effluent Guidelines (Steam Electric Survey) to identify plants discharging 

landfill leachate. For the reasons explained in Section 9.1, EPA focused on leachate collection 

and discharge from active, inactive, or open landfills, and excluded plants that have announced 

plans to retire generating units prior to December 31, 2023, as described in Section 4.2. There are 

no compliance costs for plants that are already planned to retire all generating units contributing 

combustion residuals to the landfills prior to implementation of the ELGs. EPA identified 85 

plants as discharging combustion residual landfill leachate from an active, inactive, or open 

landfill containing combustion residuals and not retiring prior to December 31, 2023. 

9.3 INPUT TABLE

As discussed in Section 4.1.3.1, EPA used Steam Electric Survey data to identify which 

plants discharge or have the potential to discharge combustion residual landfill leachate and 

determine the estimated leachate treatment costs for these plants. The “Landfill Leachate Input 

Table” holds all the input data needed to calculate the technology option cost for combustion 

residual leachate treatment. The table contains the following fields: 

• Plant_id: Steam Electric Survey Plant ID. 

• Landfill_id: Steam Electric Survey Landfill ID (only valid for plants completing 

Part F of the Steam Electric Survey92). 

• Landfill_Type: Type of landfill designation (i.e., active or inactive). 

• Leachate_GPD: Combustion residual leachate flow in gallons per day, from 

Question F3-13 for all plants completing Part F of the Steam Electric Survey. 

 

92 Part F of the Steam Electric Survey collects data related to the management practices of impoundments and 

landfills. As described in Section 3 of the Technical Development Document for the Effluent Limitations Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category, [U.S. EPA, 2015], this portion of 

the survey was distributed to only a subset of coal- and petroleum coke-fired power plants. 
Section 9 – Combustion Residual Leachate Cost Methodology 

9-3 

93Calculated value for all plants that did not complete Part F (Management 

Practices for Ponds/Impoundments and Landfills). 

• CBI Flag: Flag indicating that the resulting costs should be handled as 

Confidential Business Information (CBI). CBI flag is marked if any data used to 

populate the input table were marked as CBI by the plant. 

Section 4.1.3.1 provides more detail on the methodology used to determine the 

combustion residual landfill leachate flow rate. A copy of the “Landfill Combustion Residual 

Leachate Input Table,” which includes only flow rates for landfill leachate from the 

“Combustion Residual Leachate Input Table,” is included in the Combustion Residual Leachate 

Steam Electric Cost Model [ERG, 2015]. 

9.4 CAPITAL COST METHODOLOGY

Capital costs associated with chemical precipitation are included in Section 6.1.6. The 

equations presented in Section 6.1.6 along with the combustion residual leachate flow rate 

discussed in Section 9.3 were used to estimate capital costs associated with a chemical 

precipitation treatment system to treat combustion residual landfill leachate.

9.5 O&M COST METHODOLOGY

O&M costs associated with chemical precipitation can be found in Section 6.1.7. The 

equations presented in Section 6.1.7 along with the combustion residual leachate flow rate 

discussed in Section 9.3 were used to estimate O&M costs associated with a chemical 

precipitation treatment system to treat combustion residual landfill leachate. 

9.6 SLUDGE DISPOSAL COST

EPA determined dewatered sludge generation rates for the chemical precipitation 

treatment technology option using the methodology described in Section 6.1.8. Sections 5.3 and 

5.4 discuss costs for the transportation and disposal of the sludge generated by each technology 

option. 

9.7 COMPLIANCE MONITORING COST

All plants costed for a combustion residual leachate wastewater treatment system 

incurred a cost for compliance monitoring. Section 5.2 discusses costs for compliance 

monitoring. 

9.8 SURFACE IMPOUNDMENT OPERATION COSTS

Section 5.5 discusses cost savings associated with ceasing operation of combustion 

residual surface impoundments. EPA assumes that plants currently operating a surface 

 

93 Part F of the Steam Electric Survey collects data related to the management practices of impoundments and 

landfills. As described in Section 3 of the Technical Development Document for the Effluent Limitations Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category, [U.S. EPA, 2015], this portion of 

the survey was distributed to only a subset of coal- and petroleum coke-fired power plants. 
Section 9 – Combustion Residual Leachate Cost Methodology 

9-4 

impoundment for leachate collection will continue to do so and, therefore, there are no cost 

savings accounted for in the combustion residual landfill leachate costing methodology. 

9.9 TREATMENT SYSTEM OUTAGE COSTS

Combustion residual leachate is defined as liquid that has percolated through or drained 

from waste or other materials placed in a landfill. The flow of combustion residual leachate is 

not critical to the operation of the steam electric power plant. Combustion residual leachate flow 

rate can be intermittent, stopping or starting at any time regardless of whether the plant is 

operating or experiencing a temporary outage for maintenance. Because the flow can be stopped 

or started at any point without effecting plant operation, EPA included no additional costs 

associated with outage time to enable plants to install and connect the leachate treatment system. 

The entire treatment system can be installed at any time, and then the combustion residual 

leachate can be rerouted to direct flow through the new treatment system. 

9.10 RESULTS AND SUMMARY OF COSTS

As described in Section 2.1.4, EPA’s combustion residual leachate cost model generated 

plant-level compliance costs for the chemical precipitation technology option. The cost output 

generated by the model includes a breakout of specific capital and O&M cost elements, 

including equipment costs, direct capital costs, indirect capital costs, operating labor, 

maintenance labor, and energy costs. The output also includes costs for the common cost 

elements described in Section 5. The plant-level costs for the treatment of combustion residual 

leachate are included in Appendix B. 

9.11 REFERENCES

1. ERG. 2015. Eastern Research Group, Inc. Combustion Residual Leachate Steam Electric 

Cost Model. (30 September). DCN SE05842. 

2. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development 

Document for the Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category. (30 September). DCN SE05904. 
Section 10 – Gasification Wastewater Cost Methodology 

10-1 

10. GASIFICATION WASTEWATER COST METHODOLOGY 

EPA evaluated one technology option (evaporation) for the treatment of gasification 

wastewater generated from integrated gasification combined cycle (IGCC) process operations. 

10.1 POPULATION COSTED

From the Questionnaire for the Steam Electric Power Generating Effluent Guidelines

(Steam Electric Survey) and publicly available data, EPA identified three plants currently 

operating, or planning to operate, IGCC generating units.94 All three of these plants already 

operate (or will operate prior to implementation of the final effluent limitations guidelines and 

standards (ELGs)) the technology option selected as the Best Available Control Technology 

Economically Achievable (BAT), evaporation. Because these three plants each already operate 

the BAT technology, there are no incremental capital or O&M costs attributable to the ELG 

associated with installing and operating the treatment technology. 

10.2 COST METHODOLOGY

While no equipment or additional operation and maintenance labor is required at these 

plants, EPA did estimate costs associated with additional compliance monitoring activities. The 

final ELGs will establish effluent limitations for: 

• Arsenic. 

• Mercury. 

• Selenium. 

• Total dissolved solids. 

EPA estimated costs for these three plants to sample and analyze their discharges to 

assess compliance with the final effluent limitations. Section 5.2 discusses costs for compliance 

monitoring. Also see the “Supplemental Costs and Loadings Documentation” for the detailed 

calculation of gasification wastewater compliance costs [ERG, 2015; see Appendix 100].The 

plant-level costs for the treatment of gasification wastewater are included in Appendix B. 

10.3 REFERENCES

1. ERG. 2015. Eastern Research Group, Inc. “Supplemental Costs and Loadings 

Documentation.” (30 September). DCN SE05839. 

 

94 EPA is also aware of the Kemper County Energy Facility that will include an IGCC unit. According to the 

operating company’s website, the plant will not discharge any gasification wastewater and, therefore, the plant will 

not incur any costs to comply with the ELGs. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-1 

11. FGD WASTEWATER POLLUTANT LOADINGS 

This section discusses annual pollutant loadings and removal estimates from existing 

steam electric power plants that discharge flue gas desulfurization (FGD) wastewater. As 

previously discussed in Section 4.1.1, EPA identified 88 plants95 that operate wet FGD systems 

and discharge the FGD wastewater to a surface water or POTW. For these plants, EPA evaluated 

two technology options as the basis of the final discharge requirements for FGD wastewater: 

chemical precipitation and chemical precipitation followed by biological treatment.96 EPA 

defined baseline loadings, post-compliance pollutant loadings, and pollutant removals for FGD 

wastewater as follows: 

• Baseline Loadings. Estimated pollutant loadings, in pounds per year, of FGD 

wastewater discharged directly to surface water or indirectly to surface water 

through publicly owned treatment works (POTWs) at the current level of 

treatment (i.e., treatment in place) and prior to implementing controls to comply 

with the final rule. 

• Post-Compliance Loadings. Estimated pollutant loadings, in pounds per year, of 

FGD wastewater after implementation of the technology option. EPA calculated 

these loadings assuming that all steam electric power plants subject to the 

requirements would install and operate wastewater treatment and pollution 

prevention technologies equivalent to the technology bases for the regulatory 

options (i.e., chemical precipitation and chemical precipitation with biological 

treatment) for FGD wastewater. 

• Pollutant Removals. The difference between the baseline loadings and postcompliance loadings for each technology option. 

Pollutant loadings calculations require a pollutant-specific concentration and plantspecific discharge flow rate. EPA determined the pollutant-specific concentrations for each plant 

by evaluating the effluent characterization data and the pollutant-specific treatment effectiveness 

of each treatment technology, which is further discussed in Section 11.1. EPA also identified 

FGD wastewater flow rates for the 88 plants, which is discussed in Section 11.2. The remainder 

of the section (Sections 11.3 and 11.4) describes pollutant loadings calculations and presents the 

summary of the results. All tables and figures referenced in this section are presented at the end 

of the section. 

 

95 One plant operates only oil-fired generating units and/or generating units with a generating capacity of 50 MW or 

less; therefore, this plant is not facing any more stringent requirements than already existed under preexisting Best 

Practicable Control Technology Currently Available (BPT) regulations. As such, EPA assumed that this plant will

not install the technology basis and, therefore, will not incur any compliance costs. Additionally, EPA assumed it 

will continue to discharge FGD wastewater at its current baseline level and will not achieve any pollutant removals 

for the technology options evaluated. 

96 As discussed in Section 6.3.11, EPA evaluated costs for evaporation but decided not to evaluate evaporation as a 

technology option for existing sources in the final rule due primarily to its high cost; see “Plant-Specific Compliance 

Cost Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed by Evaporation”for 

more details [ERG, 2015e]. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-2 

11.1 EFFLUENT CONCENTRATION METHODOLOGY

EPA collected and received FGD characterization data from sources described in Section 

3 of this report. In developing the pollutant-specific concentrations used in the pollutant loadings 

calculations, EPA reviewed characterization data that reflect four treatment systems currently in 

place at steam electric power plants for FGD wastewater: FGD surface impoundment effluent, 

chemical precipitation effluent, chemical precipitation followed by biological treatment effluent, 

and evaporation treatment effluent. For effluent concentrations used to calculate both baseline 

and post-compliance pollutant loadings, EPA considered effluent characterization data from 

plants operating only Best Available Control Technology Economically Achievable (BAT) for 

chemical precipitation and biological treatment. Two plants operate evaporation at baseline; 

therefore, EPA also used effluent characterization data from this technology to accurately reflect 

the baseline loadings for these two plants. 

EPA also reviewed other data sources outside the FGD data EPA described in Section 3 

to determine if additional data were available to support the analyses. For FGD wastewater, EPA 

determined that there were no additional data sources that met the criteria to supplement the EPA 

sampling program data, Clean Water Act (CWA) 308 monitoring data, and the industrysubmitted plant monitoring data that are the basis of the FGD pollutant loadings calculations. A 

summary of EPA’s review is presented in “Development Memorandum for the Steam Electric 

Analytical Database for the Final Rule” [ERG, 2015b]. EPA review of available data sources 

considered the following general criteria applied across all wastestreams: 

• Sample results must contain sufficient information (i.e., contain method detection 

limits or quantitation limits). 

• Sample locations must be unambiguous and clearly described such that it can be 

categorized by type (e.g., bottom ash pond effluent rather than pond effluent with 

no further definition). 

• Sample must be representative of typical full-scale plant operations (e.g., not a 

simulated sample of partially treated wastewater). 

• Sample analysis must be completed using accepted analytical methods for 

untreated wastewater. 

• Data must not be duplicative of other accepted data. Where duplicate data exists 

(e.g., submitted by a trade association representing individual plants and also 

submitted by the individual plant), EPA used only accepted data collected from 

the individual plant. 

For biphasic samples (i.e., those with solids content greater than 1 percent), 

sample analysis must provide results for both phases. 

In its review, EPA also excluded sample-specific data that were not usable in the 

development of effluent characterization data. The data exclusions are documented in detail in 

the development memorandum [ERG, 2015b]. EPA excluded data for a number of reasons, 

including: 
Section 11 – FGD Wastewater Pollutant Loadings 

11-3 

• Identical Sample Results Between Data Sources: Where the same sample results 

exist for a plant within two or more data sources, EPA included only one of the 

sample results and excluded the identical results. 

• Unavailable Quantitation Limits: EPA treated non-detect results as half the 

sample-specific quantitation limit for all analytes. Therefore, EPA excluded nondetect sample results that did not have sample-specific quantitation limits. 

• Insufficiently Sensitive Analytical Methods or Sample Quality Issues: EPA 

excluded data that were analyzed using insufficiently sensitive methods, unless 

the plants established protocol for sample analysis using these methods to account 

for quality control issues and the sample results achieved low reporting limits 

consistent with the EPA-approved methods. EPA also excluded sample results 

noted with sample quality issues, such as excessive holding times, analytical 

equipment malfunction, or other sample anomalies. EPA describes this evaluation 

in Statistical Support Document: Effluent Limitations for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for the Final Steam 

Electric Power Generating Effluent Limitations Guidelines and Standards 

[Westat, 2015]. 

• Treatment System Initial Commissioning or Plant Decommissioning Periods: 

EPA excluded data collected during the initial commissioning period for the FGD 

wastewater treatment system or the decommissioning period for a steam electric 

power plant. 

• Uncharacteristic or Atypical Operations: EPA conducted an engineering review of 

the characterization data to identify operational issues that may influence the 

outcome of the sample results. EPA also consulted plant personnel on system 

upsets and excluded data that were likely the result of uncharacteristic or atypical 

operations. 

EPA performed the following review, made substitutions, and performed the following 

analyses with the data, where appropriate, in preparing the data to use in the effluent 

characterization data sets: 

• J-Values and Non-Detects: The laboratories performing the metals analyses 

provided all the analytical results that were measured above the sample-specific 

method detection limit (MDL). Therefore, the laboratory results include values 

flagged with a “J” indicator (i.e., estimated results measured above the MDL, but 

below the quantitation limit). EPA did not use the “J-values” in the loadings 

calculations. EPA treated all results that were less than the quantitation limit (i.e., 

J-values and non-detects below the MDL) as half the sample-specific quantitation 

limit (QL) for all analytes, which is consistent with EPA’s approach for handling 

non-detects for other data sources. 

• Field Blank Analysis: EPA compared the sample results from a specific sampling 

point to the field blank results for the same sampling point, on the specific day of 
Section 11 – FGD Wastewater Pollutant Loadings 

11-4 

sample collection. For the purpose of the loadings calculations, EPA made the 

following assumptions based on the results of this field blank analysis:97

— If the sample result was less than five times the field blank result, then the 

sample result was treated as a non-detect (at a concentration equal to half the 

QL). 

— If the sample result was between five and 10 times the field blank result, then 

the sample result was flagged and handled as a qualified value. 

— If the sample result was greater than 10 times the field blank result, then the 

sample result was unchanged. 

NOTE: EPA used field blank results measured above the quantitation limit for 

this analysis; J-values associated with field blanks samples were not used. 

• Duplicate Sample Results: EPA averaged the results from each duplicate sample 

with the results of its original sample. Where a sample result was not measured 

above the quantitation limit, flagged as non-detects or J-values, EPA used a 

concentration equal to half the QL.98

Using untreated FGD wastewater data (i.e., FGD purge data), EPA conducted an analysis 

to determine pollutants of concern (POCs). In the analysis, EPA identified POCs as pollutants 

that were present in the wastewater at a sufficient concentration and frequency for EPA to 

consider treatable in the FGD wastewater treatment system [ERG, 2015h; see Appendix 101]. 

The “FGD Wastewater, Combustion Residual Leachate, and Gasification Wastewater Pollutants 

of Concern (POC) Analysis Methodology” for more detail on the methodology for determining 

POCs [ERG, 2015d]. EPA estimated pollutant loadings and removals only for pollutants that 

were identified as POCs. Therefore, for any pollutants that were not identified as a POC, EPA 

did not include the pollutant in the FGD wastewater pollutant loadings estimates. The remainder 

of Section 11 discusses EPA’s methodology for developing average pollutant concentrations and 

calculating pollutant loadings. Pollutant loadings include only pollutants identified as POCs. 

11.1.1 Surface Impoundment Effluent Concentration 

Surface impoundments use gravity to remove particulates from wastewater, reducing the 

amount of total suspended solids (TSS) and particulate forms of other specific pollutants in the 

 

97 Only the EPA sampling and CWA 308 monitoring programs collected field blank samples. 

98 Industry-submitted plant monitoring data may have also been collected on the same day as EPA’s sampling and 

CWA 308 monitoring activities (, i.e., duplicate samples may exist across multiple data sources). The data vary 

between daily, weekly, and monthly results and among the number of results between analytes. Therefore, EPA 

calculated the average effluent concentrations using these data sources as follows: 1) Treat all samples collected 

during any of the 4 EPA sampling dates as a duplicate result. Calculate daily averages for samples on these dates

and then calculate a 4-day average. For pollutant loadings calculations, the sample results for the 4 days were 

averaged into a single value. 2) Calculate the average effluent concentration as an average of the 4-day average and

the remaining sample concentrations. See “Revised Methodology to Calculate Average Effluent Concentrations for 

Chemical Precipitation and Biological Treatment Systems for FGD Wastewater” [ERG, 2015f]. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-5 

wastewater. EPA categorized all plants not operating chemical precipitation, biological treatment 

or evaporation as surface impoundment systems in the baseline loadings calculations. While 

some of these plants may operate a system that is not an impoundment, EPA determined that 

these other systems are typically only solids removal systems that do not include hydroxide or 

sulfide precipitation (e.g., clarifier with polymer addition). The operations of these types of 

systems are effective at removing solids and metals in the particulate phase but do not achieve 

removals of dissolved solids, similar to the operation of an impoundment. Table 11-1 

summarizes the data sources used to develop the impoundment effluent characterization data set 

and Table 11-2 presents the average effluent concentrations calculated for surface 

impoundments. 

EPA collected or received three different types of characterization data, which were used 

to develop the effluent characterization data for FGD surface impoundments, including: 

• Effluent concentrations from a dedicated FGD surface impoundment from one 

plant. 

• Biphasic (i.e., solid and filtrate samples) and dissolved concentrations of FGD 

purge analyzed for EPA’s Sampling Program from three plants. 

• Where biphasic concentrations were not available, total and dissolved 

concentrations and TSS concentrations of FGD purge from EPA’s sampling 

program and industry-submitted data. Four plants contributed this type of 

characterization data. 

Because the data set includes dedicated FGD surface impoundment data from only one 

plant, EPA developed an approach for calculating the average effluent concentrations from 

surface impoundments using the impoundment effluent concentrations and calculated 

impoundment effluent concentrations based on the untreated FGD purge data. EPA averaged the 

effluent concentrations calculated from each of the eight plants to generate the average effluent 

characterization data set for surface impoundments presented in Table 11-2. 

11.1.1.1 Effluent Concentration using FGD Surface Impoundment Effluent 

Concentrations 

Duke Energy Carolinas’ Roxboro Steam Electric Plant (Roxboro) operates an FGD 

surface impoundment that treats FGD purge wastewater and was the only plant that provided 

FGD surface impoundment effluent concentrations. EPA used all available FGD impoundment 

effluent monitoring data provided by Roxboro to calculate the average effluent concentrations 

from an FGD surface impoundment. 

11.1.1.2 Effluent Characterization Using FGD Purge Wastewater Concentrations 

To estimate the effluent concentrations for a surface impoundment based on FGD purge 

concentration data, EPA assumed that the surface impoundment would achieve only removals of 

the particulate phase of the sample and, therefore, would not remove pollutants present in the 

dissolved phase. Because surface impoundments are designed to remove pollutants in the 

particulate phase and not the dissolved phase, EPA used an effluent TSS concentration of 30 

milligrams/liter (mg/L) to estimate the effluent concentrations for FGD surface impoundments 
Section 11 – FGD Wastewater Pollutant Loadings 

11-6 

based on FGD purge concentration data. The TSS concentration used as the basis for these 

calculations (30 mg/L) is the current 30-day average effluent limitation for low-volume 

wastewaters set in 40 CFR 423 for BPT. 

EPA derived the basis for the assumption that pollutants in the dissolved phase of the 

FGD wastewater, primarily metals, are not significantly treated in a surface impoundment from 

data presented by the Electric Power Research Institute (EPRI) in the Flue Gas Desulfurization 

(FGD) Wastewater Characterization: Screening Study, dated March 2006 [EPRI, 2006a]. In that 

report, EPRI presents FGD blowdown data for eight coal-fired steam electric power plants. For 

six of the plants, data are presented for a filtered sample, a “settled” sample, and a total sample. 

In the report, EPRI indicates that the “settled” sample was collected by allowing the sample to 

settle for 1 hour, and then an aliquot was collected from 5 inches below the surface of the 

sample. EPRI’s report states that this “equates to a settling velocity of 0.41 ft/hr or an overflow 

rate of 3.2 million gallons per day/acre” [EPRI, 2006a]. In another EPRI report, EPRI Technical 

Manual – Guidance for Assessing Wastewater Impacts of FGD Scrubbers, dated December 

2006, EPRI references the “settled” sample data from the Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study [EPRI, 2006a] and states that they “can be 

viewed as pond effluent” [EPRI, 2006b]. 

The FGD blowdown data for the six plants from the Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study [EPRI, 2006a] are presented in Table 11-3 and 

Table 11-4. Table 11-3 presents the data for three of the six plants and Table 11-4 presents the 

data for the other three plants. After reviewing the data for these six plants, EPA determined that 

for most of the metal analytes and for most of the plants, the “settled” results were usually 

similar to the filtered (or dissolved) concentration for the analyte. Therefore, EPA concluded that 

the effluent from a surface impoundment will not achieve significant removals of pollutants 

present in the dissolved phase of the sample. 

To calculate the surface impoundment effluent concentrations, EPA assumed that the 

total surface impoundment effluent concentration was equal to the sum of the contribution from 

the solids present in the wastewater and the dissolved concentration present in the wastewater. 

EPA calculated the solid phase contribution with the following assumptions: 1) the solid phase 

concentration at the impoundment effluent is equal to the concentration in the purge, and 2) the 

TSS concentration of the impoundment effluent is 30 mg/L. EPA also assumed that the dissolved 

concentration in the impoundment effluent was equal to the dissolved concentration in the FGD 

purge because impoundments do not achieve dissolved solids removals. EPA used Equation 11-1 

to perform this calculation on an analyte-specific basis. 

(11-1) 

C (ug/L)

mg 1

1000ug 

1 10 mg 

kg 1

L

30mg 

kg

C mg 

C (ug/L) 

6 Dissolved

Dry

Settling × +

×

= × ×
Section 11 – FGD Wastewater Pollutant Loadings 

11-7 

where: 

CSettling = Calculated concentration of the analyte in the effluent 

from a surface impoundment. 

CDry = Dry weight concentration of the analyte in the solid 

phase of the wastewater sample. 

CDissolved = Dissolved concentration of the analyte in the 

wastewater sample. 

EPA obtained dissolved concentrations directly from the analytical data for the FGD 

purge wastewater. However, the solid phase contribution in Equation 11-1 involved the 

calculation of the dry weight concentration. EPA obtained both biphasic and non-biphasic (i.e., 

total and dissolved and TSS) concentration data and used two separate approaches to determine 

the dry weight concentration using each of these data sets. 

 Solid-Phase Concentration Using Biphasic Concentration Data 

As part of EPA’s sampling program, EPA required the laboratories analyzing the FGD 

scrubber purge wastewater to perform a biphasic separation of the FGD purge wastewater 

sample and analyze both the solid and aqueous phase for each analyte. EPA required the 

laboratories to perform the analysis only if the wastewater sample contained greater than 1 

percent solids, which included a total of 12 samples collected from Hatfield’s Ferry Power 

Station (Hatfield’s Ferry), Keystone Generating Station (Keystone), and Miami Fort Power Plant 

(Miami Fort). 

EPA used the biphasic concentrations from the FGD purge to estimate the analytespecific surface impoundment effluent concentrations on a dry weight basis. EPA conducted 

biphasic analyses at two laboratories. One laboratory performed the analysis of the solids based 

on the wet solids, while the other laboratory dried the solids prior to performing the analysis. 

Therefore, one of the laboratories produced a wet weight solid concentration, whereas the other 

laboratory produced a dry weight solid concentration. To put the concentrations on the same 

basis, EPA first converted the wet weight solid concentrations to dry weight solid concentrations 

using Equation 11-2. 

(11-2) 

%Solids(of solid phase)

L

C mg

 

kg 1

L 1

 - 1[ - %Solids(of solid phase)]

kg

C mg

 

kg

C mg 

wet sample

Dry 































× × 















=

where: 

CDry = Dry weight concentration of the analyte in the solid 

phase of the sample. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-8 

Csample = Concentration of the analyte in the aqueous phase of the 

sample. 

Cwet = Wet weight concentration of the analyte in the solid 

phase of the sample. 

%Solids (of solid phase) = Percent solids present in the solid phase of the sample. 

Solid-Phase Concentration using Total and Dissolved Concentrations and TSS 

EPA did not require laboratories to perform biphasic separation of the samples for plants 

where the FGD purge wastewater samples collected during EPA’s sampling program contained 

less than 1 percent solids. This included wastewater samples from Allen Steam Station (Allen), 

Belews Creek Steam Station (Belews Creek), Dickerson Generating Station (Dickerson), and 

Pleasant Prairie Power Plant (Pleasant Prairie) FGD wastewater data. 

In addition to characterization data collected during EPA’s sampling program, EPA also 

evaluated industry-submitted data and identified a subset of the Allen and Belews Creek 

monitoring data that contained sample-specific results that included total and dissolved 

concentrations and TSS concentrations for the same day. In lieu of biphasic results, these three 

components of the sample results are required to estimate the concentration of the analyte in the 

solid phase. Where these three components were not available in the characterization data, EPA 

did not use the data to estimate the effluent concentrations for surface impoundments. 

EPA used Equation 11-3 to calculate dry weight solid concentrations for a given day for 

each analyte from these plants. 

(11-3) 

1000ug 

mg 1

kg

1 10 mg 

C (mg/L)

C (ug/L) C - (ug/L)

C (mg/kg) 

6

TSS

Total Dissolved

Dry ×

×

= ×

where: 

CDry = Dry weight concentration of the analyte in the solid 

phase of the sample. 

CTotal = Total concentration of the analyte in the sample. 

CDissolved = Dissolved concentration of the analyte in the sample. 

CTSS = TSS concentration in the sample. 

11.1.1.3 Effluent Characterization for Conventional and Nonconventional Pollutants 

Conventional pollutants in EPA’s characterization data set include biochemical oxygen 

demand (BOD) and TSS. Nonconventional pollutants in EPA’s data set include total dissolved 

solids (TDS), chloride, sulfate, ammonia, chemical oxygen demand (COD), cyanide, nitratenitrite as N, total Kjeldahl nitrogen (TKN), total phosphorus, and total cyanide. To estimate the 
Section 11 – FGD Wastewater Pollutant Loadings 

11-9 

effluent concentrations of these pollutants from a surface impoundment for the seven sampled 

plants, EPA used information collected from two plants as part of the sampling program during 

the detailed study: Tennessee Valley Authority’s Widows Creek Fossil Plant (Widows Creek) 

and Buckeye Power Company’s Cardinal Power Plant (Cardinal). The data EPA collected from 

the Widows Creek plant represented a 1-day sample effluent from a surface impoundment used 

to treat FGD wastewater, and the data EPA collected from Cardinal represented a 1-day effluent 

from a surface impoundment used to treat fly ash transport water. EPA compared the effluent 

values for the classical analytes for the two plants, as well as the percent removals achieved by 

the surface impoundments (compared to the samples collected at the influent to the surface 

impoundments).99 Based on the results of the comparison, EPA made the following assumptions 

to estimate the surface impoundment effluent concentrations for the classical analytes: 

• The TSS concentration at the effluent is 30 mg/L, as previously discussed in 

Section 11.1.1.2. 

• The TDS concentration is equal to the FGD purge concentration at the influent 

(i.e., no removal). 

• The chloride concentration is equal to the FGD purge concentration at the influent 

(i.e., no removal). 

• The sulfate concentration is equal to the FGD impoundment effluent 

concentration.100 

EPA did not estimate concentrations for ammonia, BOD, COD, cyanide, nitrate-nitrite as 

N, TKN, and total phosphorus in the effluent from a surface impoundment for the plants with 

sampling data. Although EPA did not develop a methodology to estimate the effluent 

concentrations for these analytes, these analytes are present in the impoundment effluent because 

they are present in chemical precipitation effluent, as demonstrated by the data collected, but are 

not treated by this type of treatment system. Therefore, to account for these pollutants in the 

loadings analysis, EPA assumed that the concentrations of these pollutants were equal to the 

concentrations calculated for chemical precipitation effluent (see Section 11.1.5.1). 

11.1.2 Chemical Precipitation Effluent Characterization 

As part of the sampling activities described in Section 3.3, EPA identified and collected 

EPA sampling data and CWA 308 monitoring data from seven plants operating chemical 

precipitation systems, sometimes in conjunction with other technologies, such as biological 

treatment. The specific operating characteristics of the chemical precipitation treatment systems 

varied. EPA conducted an engineering review of the data and identified four systems (Hatfield’s 

Ferry, Keystone, Miami Fort, and Pleasant Prairie) operating chemical precipitation with 

hydroxide and sulfide precipitation (i.e., BAT technology basis). The remaining three plants, 

which included Allen, Belews Creek, and Dickerson, did not operate systems at the time EPA 

 

99 The influent and effluent samples collected from the surface impoundment do not represent paired samples. 

100 EPA observed sulfate removals in the detailed study data from the Widows Creek plant as well as the surface 

impoundment effluent data from the Roxboro plant. EPA used the average sulfate concentrations observed from the 

Roxboro plant to represent the impoundment effluent sulfate concentration. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-10 

sampled effluent that represented the BAT technology and, therefore, these plants were not 

included in the effluent characterization for chemical precipitation.101

The treatment systems at these four BAT plants have similar operations; however, the 

plants have varying configurations and operating characteristics, such as thickeners, filter 

presses, sand filters, and retention time. Each of these systems was designed and is operated to 

remove suspended solids and dissolved metals from the FGD wastewater to achieve a similar 

level of pollutant discharge. The systems are sized to handle a specific flow rate of FGD 

wastewater, which means that the sizes of the tanks were designed to allow for the residence 

time required for settling and/or reactions to occur in order to achieve effluent concentrations 

meeting the plant’s permit limitations. 

EPA also requested monitoring data on the chemical precipitation effluent from these 

plants, as described in Section 3.4. The monitoring data, in conjunction with the EPA sampling 

and CWA 308 monitoring data, comprise the data sets EPA used to develop the effluent 

characterization data for chemical precipitation treatment. Table 11-5 summarizes the data 

sources used to develop the effluent characterization data set and Table 11-6 presents the average 

effluent concentrations calculated for chemical precipitation. Because pollutant loadings 

calculations described in Section 11.3 are based on total concentrations, EPA included only total 

concentrations except for hexavalent chromium, which is analyzed only as a dissolved 

constituent. 

11.1.3 Biological Treatment Effluent Characterization 

Four plants operate fixed-film anoxic/anaerobic biological treatment systems.102 Two of 

these plants, Roxboro and Mountaineer, do not represent the technology basis because Roxboro 

treats its FGD wastewater with a surface impoundment followed by biological treatment (i.e., no 

chemical precipitation system) and Mountaineer treats its FGD wastewater with a dedicated 

chemical precipitation system, but then combines that effluent with untreated combustion 

residual leachate prior to sending it to the biological treatment system wastestream; therefore, the 

effluent data from these plants were not used in developing the effluent characterization for 

biological treatment of only FGD wastewater. EPA identified and collected data from two plants, 

Allen and Belews Creek, operating biological treatment systems with chemical precipitation 

pretreatment that represent the biological treatment technology option. These two plants operate 

chemical precipitation systems followed by anoxic/anaerobic biological treatment systems 

specifically designed for selenium removal. 

 

101 EPA excluded data from Dickerson because the Dickerson plant was not adding sulfide to the wastewater 

treatment system at the time of sampling. The plant also experienced frequent shutdowns and wastewater treatment 

upsets, and the treatment system is not designed and operated to remove selenium. Allen and Belews Creek also did 

not add sulfide in their chemical precipitation systems at the time of sampling. 

102 The Mayo Plant currently operates a biological treatment system but has announced plans to install an 

evaporation treatment system. For the purposes of estimating costs and pollutant loadings for the final rule, EPA 

does not consider this plant as operating a biological treatment system, but rather an evaporation treatment system. 

See “Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric Effluent Guidelines 

Final Rule” for more detail on planned treatment system upgrades [ERG, 2015a]. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-11 

EPA used the data from Allen and Belews Creek to represent the effluent characterization 

data of chemical precipitation system with biological treatment system; however, these two 

plants do not fully represent the technology option because neither plant currently uses sulfide 

precipitation in the chemical precipitation system. Therefore, the two plants likely do not 

demonstrate mercury (and other metals) effluent concentrations as low as could be achieved by a 

chemical precipitation (with sulfide precipitation) followed by a biological treatment system that 

forms the basis of the technology option. 

EPA has multiple sets of data for these two plants to develop the effluent characterization 

data for chemical precipitation followed by biological treatment, including EPA sampling data, 

CWA 308 monitoring data, and plant monitoring data. Table 11-7 summarizes the data sources 

used to develop the effluent characterization data set and Table 11-8 presents the average 

effluent concentrations calculated for chemical precipitation followed by biological treatment. 

Because pollutant loadings calculations described in Section 11.3 are based on total 

concentrations, EPA included only total concentrations except for hexavalent chromium, which 

is analyzed only as a dissolved constituent. 

11.1.4 Evaporation Effluent Characterization 

EPA developed effluent characterization data for evaporation because two plants are 

planning to install evaporation systems and are considered to operate this technology at baseline. 

The evaporation data that EPA collected as part of the CWA 308 monitoring program include 

data from one plant currently operating in the United States but not discharging wastewater, as 

well as one plant in Italy.103 EPA conducted an engineering review of the data from these two 

plants operating evaporation systems. One plant, Brindisi, operates a hydroxide-sulfide chemical 

precipitation system followed by softening, a brine concentrator, and crystallization system, 

which EPA considered as the technology basis for evaporation. The second plant, Iatan, operates 

a clarification system, with coagulant and polyelectrolyte addition, followed by a brine 

concentrator. Because the Iatan system does not include a chemical precipitation system, a 

softening system, and a crystallizer, EPA does not consider this plant to represent the 

evaporation technology basis. Table 11-9 summarizes the data sources used to develop the 

effluent characterization data set and Table 11-10 presents the average effluent concentrations 

calculated for evaporation. For this plant, EPA collected and analyzed 3 days of samples for total 

concentrations and did not have dissolved concentrations or hexavalent chromium data to use in 

the analysis. 

EPA calculated the average effluent concentrations for the evaporation treatment system, 

as follows: 

 

103 As described in Section 3.3.3, EPA also requested samples from a second plant in Italy, A2A’s Centrale de 

Monfalcone (Monfalcone). Data from Monfalcone consists of a single 1-day grab sample collected by Monfalcone 

personnel that were not trained in EPA’s sampling protocols; therefore, EPA did not include this data in any 

calculations for the final rulemaking. The pollutant concentrations seen at Monfalcone are comparable to the 

average effluent concentration for evaporation. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-12 

1. Calculate average concentration by analyte for each of the two evaporation 

wastestreams at the plant (i.e., brine concentrator distillate and crystallizer 

condensate). 

2. Calculate overall average effluent concentration by analyte by averaging the 

concentrations from the two wastestreams (i.e., brine concentrator distillate and 

crystallizer condensate).104

11.1.5 Pollutant Concentration Basis for Loadings Calculations 

Because of the concentration data available, EPA used different populations of plants to 

generate the various effluent characterization data sets presented in Table 11-2, Table 11-6, 

Table 11-8, and Table 11-10. EPA conducted an engineering review of the effluent 

concentrations across all technologies to determine if removals were observed for pollutants 

expected to be treated by the technology and likewise, if no removals were observed for 

pollutants that were not expected to be treated. Based on this review, EPA performed 

substitutions for analyte-specific concentrations where it determined that the pollutant was not 

being effectively treated in a particular treatment system. Sections 11.1.5.1 through 11.1.5.4 

describe the types of substitutions made for each technology basis. 

11.1.5.1 Pollutant Concentrations for Surface Impoundment Effluent 

For pollutants that were not included in the surface impoundment effluent 

characterization data, presented in Table 11-2, EPA assumed the concentrations of these 

pollutants were equal to the pollutant concentrations used for the chemical precipitation effluent 

(i.e., Table 11-12), which are further discussed in Section 11.1.2. This includes substitutions of 

the pollutant concentrations for ammonia, BOD, COD, chromium (VI), cyanide, nitrate-nitrite as 

N, TKN, and total phosphorus. EPA concludes that because these pollutants are present in the 

chemical precipitation effluent, they are also present in the FGD wastewater and would 

therefore, also be present in the FGD surface impoundment effluent. EPA’s assumption results in 

EPA accounting for these pollutants in the baseline loadings, but does not result in any estimated 

pollutant removals in the chemical precipitation system. Table 11-11 provides a summary of 

EPA’s substitutions of the impoundment effluent characterization data (described in Section 

11.1.1) with chemical precipitation pollutant concentrations for each of these pollutants and 

presents the pollutant concentrations for surface impoundments that EPA used in the pollutant 

loading calculations. 

11.1.5.2 Pollutant Concentrations for Chemical Precipitation Effluent 

Prior to using the effluent characterization data for chemical precipitation (in Section 

11.1.2), EPA conducted a separate analysis to ensure that the collective data set demonstrates 

positive removals across the chemical precipitation system. EPA reviewed the data set on a plant 

level to determine whether the pollutant was present at treatable levels and if so, whether the 

 

104 EPA used both the brine concentrator distillate and crystallizer condensate streams to calculate the loadings 

because both wastestreams could be discharged. The evaporation system at Brindisi is operated as a zero-discharge 

system with no wastewater being discharged to surface water or a POTW. The plant could choose to discharge the 

brine concentrator and the crystallizer condensate streams together or separately. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-13 

pollutant was effectively treated by the treatment technology. In this analysis, EPA reviewed 

pollutant concentrations at the influent to the chemical precipitation system (i.e., FGD purge 

wastewater) using data from the four plants operating this technology basis, including Hatfield’s 

Ferry, Miami Fort, Keystone, and Pleasant Prairie. On a plant level, EPA identified pollutants at 

treatable levels by comparing the average purge concentrations to the sample-specific 

quantitation limit.105 Pollutants at treatable levels were identified as those present at greater than 

or equal to 10 times the quantitation limit in at least 10 percent of the influent samples at the 

plant. If the pollutant is present at treatable levels at any of the plants, then EPA calculated plantspecific percent removals for those plants using the plant-specific average FGD purge 

concentration and the plant-specific average chemical precipitation effluent.106 If the pollutant 

(ammonia, BOD, COD, chromium (VI), TKN, silver, sulfate, and tin107) is not present at 

treatable levels at any of the plants, then EPA set the chemical precipitation effluent 

concentration for that pollutant equal to the FGD surface impoundment effluent (presented in 

Table 11-2). 

Next, EPA performed a review of the plant-specific pollutant removals to confirm that 

each pollutant is being removed across the chemical precipitation treatment system (percent 

removals greater than zero). 

1. For those pollutants where all plant-specific pollutant removals demonstrate 

positive removals across the chemical precipitation system (i.e., percent removals 

are greater than zero), EPA set the chemical precipitation effluent concentration 

equal to the average chemical precipitation effluent concentration for the FGD 

loadings analysis (presented in Table 11-6). 

2. After EPA set the chemical precipitation effluent concentrations for those 

pollutants in Step 1, it also compared the average chemical precipitation effluent 

concentrations to the average FGD surface impoundment effluent concentrations. 

EPA performed this comparison because it used different data sets to determine 

concentrations for chemical precipitation (based on four plants) and FGD surface 

impoundments (based on eight plants). For magnesium and molybdenum, the 

BAT chemical precipitation effluent concentrations were higher than the surface 

impoundment effluent concentrations. Because of this phenomenon, EPA set the 

BAT chemical precipitation effluent concentration equal to the surface 

impoundment effluent concentration for these two pollutants. 

 

105 The methodology to identify pollutants at treatable levels is similar to the methodology used in EPA’s POC 

analysis; however, this analysis is conducted at the plant level to evaluate treatment effectiveness. 

106 For the calculation of the percent removals, EPA used all available FGD purge and FGD chemical precipitation 

system effluent data. EPA did not use only paired sample results or only data from which samples were collected on 

the same day. EPA notes that this treatment effectiveness evaluation is not used to determine the exact percent

removal achieved by the chemical precipitation system, but rather, to evaluate whether the pollutant is removed 

across the system. 

107 As described in Section 11.1.5.1, no methodology exists to estimate impoundment effluent concentrations for 

ammonia, BOD, COD, chromium (VI), and TKN; therefore, EPA used the chemical precipitation effluent 

concentrations for both the surface impoundment effluent and the chemical precipitation effluent for the loadings

analysis. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-14 

3. For those pollutants that show positive removal across the chemical precipitation 

for some plants, but not all plants, EPA reviewed the data to assess whether the 

data collectively demonstrates removal across the treatment system. This affected 

the following pollutants: chloride, nitrate-nitrite as N, and sodium. 

a. Chloride: Two of the four plants had negative removals (Hatfield’s Ferry and 

Pleasant Prairie) and one plant had percent removals less than 3 percent 

(Keystone). Miami Fort achieved some removals across the chemical 

precipitation system. EPA also compared the average FGD purge 

concentration for the four plants to the average concentration for the chemical 

precipitation effluent for the four plants and found the average influent 

concentration was lower than the average effluent concentration. Additionally, 

based on a review of literature, EPA did not expect to see positive removals of 

chloride across the chemical precipitation treatment system. Based on a 

collective review of all the data and information, EPA determined that 

chemical precipitation is not any more effective at removing chlorides than 

FGD surface impoundments; therefore, EPA set the chemical precipitation 

effluent concentration equal to the FGD surface impoundment effluent 

concentration for chloride. 

b. Nitrate-Nitrite as N: One plant had negative removals (Pleasant Prairie) and 

two plants had removals less than 10 percent (Hatfield’s Ferry and Miami 

Fort). Keystone achieved some removals of nitrate-nitrite as N. Based on a 

review of literature, EPA did not expect to see positive removals of nitratenitrite as N across the chemical precipitation treatment system. Based on a 

collective review of all the data and information, EPA determined that 

chemical precipitation is not any more effective at removing nitrate-nitrite as 

N than FGD surface impoundments; therefore, EPA set the chemical 

precipitation effluent concentration equal to the FGD surface impoundment 

effluent concentration for nitrate-nitrite as N 

c. Sodium: Three of the four plants have negative removals of sodium. Miami 

Fort achieved some significant removals of sodium. Based on a review of 

literature, EPA did not expect to see positive removals of sodium across the 

chemical precipitation treatment system. Based on a collective review of all 

the data and information, EPA determined that chemical precipitation is not 

any more effective at removing sodium than FGD surface impoundments; 

therefore, EPA set the chemical precipitation effluent concentration equal to 

the FGD surface impoundment effluent concentration for sodium. 

Table 11-12 presents the pollutant concentrations EPA used to represent the effluent from 

the BAT chemical precipitation system used in the pollutant loading calculations, along with the 

basis for the concentration (i.e., FGD surface impoundment, chemical precipitation). The plantlevel results of EPA’s treatment effectiveness evaluation for chemical precipitation are included 

in the “Supplemental Costs and Loadings Documentation” [ERG, 2015h; see Appendix 102]. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-15 

11.1.5.3 Pollutant Concentrations for Biological Treatment Effluent 

Similarly to the analysis done for chemical precipitation, EPA evaluated the pollutantspecific treatment effectiveness of the biological treatment technology. For this analysis, EPA 

reviewed pollutant concentrations at the influent to the biological treatment system (i.e., 

chemical precipitation effluent) using data from the two plants operating this technology, Allen 

and Belews Creek. 

For this analysis, EPA used chemical precipitation effluent and biological treatment 

effluent data from Allen and Belews Creek. EPA first reviewed the influent data for each 

pollutant at each plant (i.e., chemical precipitation effluent) to identify those pollutants present at 

treatable levels. Pollutants at treatable levels were identified as those present at greater than or 

equal to five times the quantitation limit in at least 10 percent of the influent samples at the 

plant.108 If the pollutant is present at treatable levels, then EPA calculated plant-specific percent 

removals across the biological treatment system for those plants using the plant-specific average 

chemical precipitation effluent concentration and the plant-specific average biological treatment 

system effluent concentration.109 If the pollutant (aluminum, ammonia, antimony, arsenic, 

barium, beryllium, BOD, cadmium, chromium, chromium (VI), cobalt, copper, cyanide, iron, 

lead, manganese, molybdenum, TKN, total phosphorus, silver, thallium, tin, titanium, total 

suspended solids, vanadium, and zinc) is not present at treatable levels at any of the plants, then 

EPA set the biological treatment effluent concentration equal to the pollutant concentration that 

was determined to be most appropriate for the chemical precipitation effluent (i.e., concentration 

presented in Table 11-12). 

Next, EPA performed a review of the plant-specific pollutant removals to confirm that 

each pollutant is being removed across the biological treatment system. 

1. For those pollutants where plant-level concentration data from both plants 

demonstrates positive removals across the biological treatment system (i.e., 

percent removals greater than zero), EPA set the chemical precipitation followed 

by biological treatment system effluent concentration equal to the average 

biological treatment system effluent concentration for the FGD loadings analysis 

(i.e., concentration presented in Table 11-8). This affected the following 

pollutants: mercury, nickel, nitrate-nitrite as N, and selenium. 

 

108 For biological treatment, EPA used five times the quantitation limit instead of 10 times the quantitation limit 

because the FGD wastewater has already undergone treatment in the chemical precipitation system prior to reaching 

the influent to the biological treatment system; therefore, many of the pollutants have been reduced to lower levels 

entering the system. The biological treatment system is a portion of the overall BAT system and is not being

evaluated as its own BAT technology. EPA has selected five times the quantitation limit because it has been used in 

previous ELGs as the level required for evaluating effective treatment (e.g., metal products & machinery, 

transportation equipment cleaning). 

109 For the calculation of the percent removals, EPA used all available FGD chemical precipitation system effluent 

data and FGD biological treatment system effluent data. EPA did not use only paired sample results or only data 

from which samples were collected on the same day. EPA notes that this treatment effectiveness evaluation is not 

used to determine the exact percent removal achieved by the biological treatment system, but rather to evaluate 

generally whether the pollutant is removed across the system. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-16 

2. For those pollutants that show positive removal across the biological treatment 

system for only one plant, but not both, EPA reviewed the data to assess whether 

the data collectively demonstrated removal across the treatment system. This 

affected the following pollutants: barium, boron, calcium, chloride, COD, 

magnesium, sodium, sulfate, and TDS. 

a. Barium: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For barium, the biological 

treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Based on a review of literature, EPA 

did not expect barium to be generated across the biological system. Based 

on a collective review of all the data and information, EPA set the 

chemical precipitation followed by biological treatment system effluent 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system option (i.e., chemical 

precipitation effluent). 

b. Boron: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For boron, the biological 

treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Additionally, removal of boron 

demonstrated at the BAT plants was not consistent with the removal 

calculated based on the average chemical precipitation effluent 

concentration and the average biological treatment effluent concentration. 

Actual sampling data demonstrate less than 10 percent removal, while the 

removal between the average chemical precipitation effluent and the 

average biological effluent is 36 percent. Based on a collective review of 

all the data and information, EPA determined that biological treatment is 

not any more effective at removing boron than chemical precipitation; 

therefore, EPA set the chemical precipitation followed by biological 

treatment system effluent concentration equal to the concentration that 

was determined to be most appropriate for the chemical precipitation 

system option (i.e., chemical precipitation effluent). 

c. Calcium: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For calcium, the biological 

treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Based on a review of literature, EPA 

did not expect calcium to be generated across the biological system. Based 
Section 11 – FGD Wastewater Pollutant Loadings 

11-17 

on a collective review of all the data and information, EPA set the 

chemical precipitation followed by biological treatment system effluent 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system option (i.e., chemical 

precipitation effluent). 

d. Chloride: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For chloride, the biological 

treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Actual sampling data demonstrate 

less than 10 percent removal, while the removal between the average 

chemical precipitation effluent and the average biological effluent is 36 

percent. Based on a collective review of all the data and information, EPA 

determined that biological treatment is not any more effective at removing 

chloride than chemical precipitation; therefore, EPA set the chemical 

precipitation followed by biological treatment system effluent 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system option (i.e., surface 

impoundment effluent). 

e. COD: Based on a review of literature and because the biological treatment 

system operates in anaerobic/anoxic stages and not aerobic stages, EPA 

did not expect to see positive removal of COD across the biological 

treatment system. Based on a collective review of all the data and 

information, EPA determined that biological treatment is not any more 

effective at removing COD than chemical precipitation; therefore, EPA set 

the chemical precipitation followed by biological treatment system 

effluent concentration equal to the concentration that was determined to be 

most appropriate for the chemical precipitation system (i.e., chemical 

precipitation effluent). 

f. Magnesium: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For magnesium, the 

biological treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Actual sampling data demonstrate 

less than 5 percent removal, while the removal between the average 

chemical precipitation effluent and the average biological effluent is 82 

percent. Based on a collective review of all the data and information, EPA 

determined that biological treatment is not any more effective at removing 

magnesium than chemical precipitation; therefore, EPA set the chemical 

precipitation followed by biological treatment system effluent 
Section 11 – FGD Wastewater Pollutant Loadings 

11-18 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system option (i.e., FGD surface 

impoundment effluent). 

g. Sodium: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For sodium, the biological 

treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Actual sampling data demonstrate 

less than 5 percent removal, while the removal between the average 

chemical precipitation effluent and the average biological effluent is 91 

percent. Based on a collective review of all the data and information, EPA 

determined that biological treatment is not any more effective at removing 

sodium than chemical precipitation; therefore, EPA set the chemical 

precipitation followed by biological treatment system effluent 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system option (i.e., FGD surface 

impoundment effluent). 

h. Sulfate: EPA compared the average biological treatment system effluent 

concentration for the two plants to the average chemical precipitation 

effluent concentration for the two plants and found the average influent 

concentration was lower than the average effluent concentration. 

Additionally, the removal of sulfate demonstrated at the BAT plants was 

not consistent with the removal calculated based on the average chemical 

precipitation effluent concentration and the average biological treatment 

effluent concentration. Actual sampling data demonstrate less than 5 

percent removal while the removal between the average chemical 

precipitation effluent and theaverage biological effluent is calculated to be 

80 percent. Based on a collective review of all the data and information, 

EPA determined that biological treatment is not any more effective at 

removing sulfate than chemical precipitation; therefore, EPA set the 

chemical precipitation followed by biological treatment system effluent 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system (i.e., surface 

impoundment effluent). 

i. TDS: EPA compared the average chemical precipitation effluent 

concentration to the average biological treatment effluent concentration. 

EPA performed this comparison because it used different data sets to 

determine concentrations for chemical precipitation (based on four plants) 

and biological treatment (based on two plants). For TDS, the biological 

treatment effluent concentrations were higher than the chemical 

precipitation effluent concentrations. Actual sampling data demonstrate 

less than 5 percent removal, while the removal between the average 

chemical precipitation effluent and the average biological effluent is 46 
Section 11 – FGD Wastewater Pollutant Loadings 

11-19 

percent. Based on a collective review of all the data and information, EPA 

determined that biological treatment is not any more effective at removing 

TDS than chemical precipitation; therefore, EPA set the chemical 

precipitation followed by biological treatment system effluent 

concentration equal to the concentration that was determined to be most 

appropriate for the chemical precipitation system option (i.e., chemical 

precipitation effluent). 

Table 11-13 presents the pollutant concentrations EPA used to represent the effluent from 

the chemical precipitation and biological treatment system used in the pollutant loading 

calculations, along with the basis for the concentration (i.e., FGD surface impoundment, 

chemical precipitation, biological treatment). The plant-level results of EPA’s treatment 

effectiveness evaluation for biological treatment are included in the “Supplemental Costs and 

Loadings Documentation” [ERG, 2015h; see Appendix 102]. 

11.1.5.4 Pollutant Concentrations for Evaporation Effluent 

Similarly to its review of FGD surface impoundment effluent concentrations, described in 

Section 11.1.5.1, EPA substituted concentrations in the evaporation effluent with pollutant 

concentrations for chemical precipitation in Table 11-8 where pollutants were not characterized 

in the evaporation data set. This includes substitutions for BOD, chromium (VI), and cyanide. 

Table 11-14 provides a summary of EPA’s substitutions of the evaporation effluent 

characterization data for each pollutant and presents the pollutant concentrations for evaporation 

effluent used in the pollutant loading calculations, which incorporates EPA’s substitutions.110

11.2 FGD WASTEWATER FLOW RATES

EPA used data from the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey) to identify plants discharging FGD wastewater and 

determine the plant’s discharge flow rate. In cases where Steam Electric Survey data were 

insufficient, EPA developed a methodology for estimating flow rates. Section 4.1.1 describes 

EPA’s methodology for determining wastewater flow rates for FGD wastewater. In Section 

4.5.2, EPA evaluated FGD “high-flow” plants and determined that three plants have the potential 

to recycle some FGD wastewater back to the system and reduce the amount of FGD wastewater 

that would require treatment. 

To account for the recycle flow, EPA calculated a new FGD wastewater flow rate to use 

in the post-compliance loadings for these plants. EPA used the same FGD wastewater flow rates 

in the chemical precipitation and the biological treatment FGD wastewater technology cost 

modules (discussed in Sections 6.1.4 and 6.2.4) and the FGD wastewater pollutant loadings111 to 

 

110 Because the evaporation effluent concentrations were used only to estimate the baseline loadings for those plants

that currently operate evaporation systems and EPA did not use them to evaluate pollutant removals associated with 

installing the technology option, EPA did not conduct the treatment effectiveness analysis for this treatment 

technology. 

111 “High-flow” plants have higher baseline flow rates than post-compliance flow rates because of the plant’s 

potential to recycle some of the FGD wastewater. Due to the differences in flow rates, EPA adjusted post-
Section 11 – FGD Wastewater Pollutant Loadings 

11-20 

ensure consistency among all the FGD estimates. FGD wastewater flow rates are tabulated in the 

“FGD Input Table,” which is included in the FGD Loadings Database [ERG, 2015c]. 

EPA used the “CCR Input Table,” discussed in Section 4.3.3, to adjust the population of 

plants discharging FGD wastewater to account for the implementation of the final Coal 

Combustion Residuals (CCR) rule. A copy of the “CCR Input Table” is included in the FGD 

Loadings Database [ERG, 2015c]. 

11.3 POLLUTANT LOADINGS CALCULATIONS

EPA calculated plant-level pollutant loadings for FGD wastewater at baseline and for 

each of the treatment technologies evaluated using the plant-specific FGD wastewater flow rate 

and the average effluent pollutant concentrations for the wastestream, according to Equation 

11-4. EPA estimated loadings for the 88 plants that operate a wet FGD system and discharge the 

FGD wastewater to a surface water or POTW. 

(11-4) 

Pollutant Loading (lbs/yr) = Flow Rate × Pollutant Concentration × 

2.20462 lb/1,000,000 mg × 1,000 L / 264.17 gal × 365 days/year

where: 

Flow Rate = The FGD wastewater flow rate, in gallons per day. 

Pollutant Concentration = The average concentration of a specific pollutant 

present in the wastestream, in milligrams per liter. 

EPA applied different effluent limitations to oil-fired generating units and generating 

units with a capacity of 50 megawatts (MW) or less (one plant discharging FGD wastewater 

operates units with a capacity of 50 MW or less). In this case, the plant will not face more 

stringent requirements than already existed under preexisting regulations; therefore, postcompliance loadings are set equal to the baseline loadings. 

11.3.1 Baseline Loadings 

As described at the beginning of this section, baseline loadings are the mass of pollutants 

discharged in FGD wastewater based on the current level of treatment. For baseline loadings, 

EPA multiplied the plant-specific FGD wastewater flow rate with the average pollutant 

concentrations that represent the current level of treatment EPA assigned to each plant. As 

described earlier, EPA assigned current level of treatment for FGD wastewater using one of four 

classes of treatment: FGD surface impoundment, chemical precipitation, biological treatment, 

and evaporation. Of the 87 plants identified from the Steam Electric Survey and industry-

 

compliance loadings to equal baseline loadings for pollutants that are not effectively treated by the BAT system (i.e., 

chemical precipitation followed by biological treatment). This adjustment eliminates artificial pollutant removals 

that would have been a result of the differences in the baseline and post-compliance flow rates, including removals 

for ammonia as N, chloride, cyanide, magnesium, molybdenum, total phosphorus, and sodium. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-21 

submitted data as operating non-small (i.e., with a capacity of greater than 50 MW) and 

discharging FGD wastewater, EPA assigned the current level of treatment as follows: 

• Thirty-six plants currently operating or planning to operate surface 

impoundments. 

• Forty-five plants currently operating or planning to operate a chemical 

precipitation system. 

• Four plants currently operating or planning to operate a biological treatment 

system. 

• Two plants currently operating or planning to operate an evaporation system. 

11.3.2 Chemical Precipitation Loadings 

For post-compliance loadings associated with the chemical precipitation technology 

option, EPA assumed that plants currently treating FGD wastewater with chemical precipitation 

systems, biological treatment systems, or evaporation systems do not require additional controls 

to comply with the final rule. Therefore, these plants remain unchanged from baseline and the 

pollutant loadings for these plants were set equal to the baseline pollutant loadings. This 

assumption may underestimate the estimated pollutant removals for plants with a baseline 

chemical precipitation system that is not equivalent to the technology basis. 

EPA assumed that plants operating surface impoundments at baseline would install 

chemical precipitation treatment systems to meet the effluent requirements associated with this 

option. EPA evaluated post-compliance loadings for these plants at the effluent from the 

chemical precipitation system using the average pollutant concentration data set associated with 

a chemical precipitation system, presented in Table 11-12, and the plant-specific FGD 

wastewater flow rates. 

11.3.3 Biological Treatment Loadings 

For the post-compliance pollutant loadings associated with the chemical precipitation 

treatment system followed by biological treatment technology option, EPA assumed that the 

post-compliance loadings calculated for plants currently treating their FGD wastewater with 

biological treatment systems or evaporation systems remain unchanged from baseline and the 

pollutant loadings for these plants were set equal to the baseline pollutant loadings. This 

assumption may underestimate the pollutant removals for plants with baseline biological 

treatment systems that are not equivalent to the technology basis (i.e., chemical precipitation 

followed by biological treatment). 

EPA assumed that plants with surface impoundments would install chemical precipitation 

systems with biological treatment, and plants with chemical precipitation systems (but no 

biological treatment for selenium removal) would install biological treatment systems to meet the 

effluent requirements associated with this technology option. EPA evaluated post-compliance 

loadings for these plants at the effluent from the biological treatment system using the pollutant 

concentrations associated with a chemical precipitation system followed by biological treatment, 

presented in Table 11-13, and plant-specific FGD wastewater flow rates. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-22 

11.3.4 POTW Removals 

EPA identified two plants that reported in the Steam Electric Survey transferring FGD 

wastewater to a POTW rather than discharging directly to surface water. For these plants, EPA 

adjusted the baseline and post-compliance loadings to account for pollutant removals expected 

from POTWs for each analyte. Appendix B to this report provides the estimated pollutant 

percent removal expected to be achieved by well-operated POTWs, as reported in the “Memo to 

the 2006 Effluent Guidelines Program Plan Docket” [ERG, 2006]. For each plant identified as 

discharging to a POTW, EPA used the calculated pollutant loadings and the POTW removals 

shown in Appendix B to calculate the amount of pollutant discharged from the POTW to surface 

water, according to Equation 11-5. 

(11-5) 

Indirect Pollutant Loading (lb/yr) = Pollutant Loading × (1 - POTW Removal)

where: 

Pollutant Loading = The calculated baseline or post-compliance loadings 

from a specific pollutant, in pounds/year. 

POTW Removal = The estimated percentage of the pollutant loading that 

will be removed by a POTW. 

11.4 POLLUTANT LOADINGS AND TWPE RESULTS

In addition to expressing plant-level pollutant loadings in pounds of pollutant discharged 

per year (described in Section 11.3), EPA used toxic weighting factors (TWFs) to account for 

differences in toxicity across pollutants in FGD wastewater.112 EPA calculated a toxic-weighted 

pound equivalent (TWPE) according to Equation 11-6 for each pollutant to compare mass 

loadings between different pollutants based on their toxicity. 

(11-6) 

Pollutant-Specific TWPE = Pollutant-Specific Loading × Pollutant-Specific TWF 

EPA also calculated plant-level TWPEs by aggregating the pollutant-specific TWPEs. 

Using the plant-level mass and TWPE loadings, EPA was then able to calculate the baseline and 

post-compliance loadings at the industry level for each regulatory option. The plant-level mass 

loadings and TWPE loadings are presented in Appendix B. Table 11-15 presents the FGD 

wastewater loadings on an industry-level for baseline and each post-compliance technology 

basis. The table includes the number of plants identified as discharging FGD wastewater, the 

total industry flow rate associated with each technology option, and the total industry loading in 

pounds per year and TWPE per year. Table 11-16 presents the pollutant removals, which EPA 

 

112 A listing of pollutant-specific TWF values can be found in the “Review of Toxic Weighting Factors in Support of 

the Final Steam Electric Effluent Limitations Guidelines and Standards” [ERG, 2015g]. EPA has developed TWFs 

for more than 1,900 pollutants based on aquatic life and human health toxicity data, as well as physical/chemical 

property data. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-23 

calculated by subtracting the technology option loadings from the baseline loadings. The 

pollutant loadings and removals presented in Table 11-15 and Table 11-16 represent the 

population including adjustments for the CCR rule. The loadings exclude the pollutant 

parameters BOD, COD, TDS, and TSS because they double-count the loadings for specific 

pollutants already included. Section 15 of this report discusses the use of the FGD wastewater 

pollutant loadings and estimated pollutant loadings for other regulated wastestreams to evaluate 

the regulatory options considered by EPA. 

11.5 REFERENCES

1. ERG. 2006. Eastern Research Group, Inc. “re: Publicly Owned Treatment Works 

(POTW) Percent Removals Used for the TRI Releases2002 Database.” (12 August). 

DCN SE02932. 

2. ERG. 2015a. Eastern Research Group, Inc. “Changes to Industry Profile for Steam 

Electric Generating Units for the Steam Electric Effluent Guidelines Final Rule.” (30 

September). DCN SE05069. 

3. ERG. 2015b. Eastern Research Group, Inc. “Development Memorandum for the Steam 

Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876. 

4. ERG. 2015c. Eastern Research Group, Inc. FGD_CCR Loadings Database. (30 

September). DCN SE05866. 

5. ERG. 2015d. Eastern Research Group, Inc. “FGD Wastewater, Combustion Residual 

Leachate, and Gasification Wastewater Pollutants of Concern (POC) Analysis 

Methodology.” (30 September). DCN SE05342. 

6. ERG. 2015e. Eastern Research Group, Inc. “Plant-Specific Compliance Cost Estimates 

for the Treatment of FGD Wastewater with Chemical Precipitation Followed by 

Evaporation.” (30 September). DCN SE05730. 

7. ERG. 2015f. Eastern Research Group, Inc. “Revised Methodology to Calculate Average 

Effluent Concentrations for Chemical Precipitation and Biological Treatment Systems for 

FGD Wastewater.” (30 September). DCN SE05344. 

8. ERG. 2015g. Eastern Research Group, Inc. “Review of Toxic Weighting Factors in 

Support of the Final Steam Electric Effluent Limitations Guidelines and Standards.” (30 

September). DCN SE04479. 

9. ERG. 2015h. Eastern Research Group, Inc. “Supplemental Costs and Loadings 

Documentation.” (30 September). DCN SE05839. 

10. EPRI. 2006a. Electric Power Research Institute. Flue Gas Desulfurization (FGD) 

Wastewater Characterization: Screening Study. Palo Alto, CA. (March). Available online 

at: http://mydocs.epri.com/docs/public/000000000001010162.pdf. Date accessed: 16 

May 2008. DCN SE01816. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-24 

11. EPRI. 2006b. Electric Power Research Institute. EPRI Technical Manual: Guidance for 

Assessing Wastewater Impacts of FGD Scrubbers. Palo Alto, CA. (December). Available 

online at: http://www.epriweb.com/public/000000000001013313.pdf. Date accessed: 16 

May 2008. DCN SE01817. 

12. Westat. 2015. Statistical Support Document: Effluent Limitations for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for the Final Steam 

Electric Effluent Limitations Guidelines and Standards. (30 September). DCN SE05733. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-25 

Table 11-1. Data Sets Used in Developing Effluent Characterization Data for 

Surface Impoundments 

Plant Name Source of Data Set

Duke Energy Carolinas’ Roxboro Steam Plant (Roxboro) State-submitted plant monitoring data 

Duke Energy’s Miami Fort Station (Miami Fort) EPA on-site field sampling data

NRG Energy’s Keystone Generating Station (Keystone) EPA on-site field sampling data

First Energy’s Hatfield’s Ferry Power Station (Hatfield’s Ferry) EPA on-site field sampling data

NRG Energy’s Dickerson Generating Station (Dickerson) EPA on-site field sampling data

We Energies’ Pleasant Prairie Power Plant (Pleasant Prairie) EPA on-site field sampling data

Duke Energy Carolinas’ Allen Steam Station (Allen) EPA on-site field sampling data

Industry-submitted plant monitoring data 

Duke Energy Carolinas’ Belews Creek Steam Station (Belews Creek) EPA on-site field sampling data

Industry-submitted plant monitoring data

Source: ERG, 2015b; ERG, 2015d. 

 
Section 11 – FGD Wastewater Pollutant Loadings 

11-26 

Table 11-2. Average Effluent Concentrations from FGD Surface Impoundments 

Analyte a Unit Average Concentration 

Aluminum ug/L 2,080 

Ammonia as N ug/L No Data

Antimony ug/L 12.9

Arsenic ug/L 7.59 

Barium ug/L 303 

Beryllium ug/L 1.92 

Boron ug/L 243,000 

Cadmium ug/L 113 

Calcium ug/L 2,050,000 

Chloride ug/L 7,120,000 

Chromium ug/L 17.8 

Cobalt ug/L 183 

Copper ug/L 21.8 

Cyanide ug/L No Data 

Iron ug/L 1,510

Lead ug/L 4.66 

Magnesium ug/L 3,370,000 

Manganese ug/L 93,400 

Mercury ug/L 7.78 

Molybdenum ug/L 125 

Nickel ug/L 878 

Nitrate-Nitrite as N ug/L No Data 

Phosphorus, Total ug/L No Data 

Selenium ug/L 1,170 

Sodium ug/L 276,000 

Thallium ug/L 13.7 

Titanium ug/L 27.1 

TDS ug/L 32,500,000 

TSS ug/L 27,900 

Vanadium ug/L 16.4 

Zinc ug/L 1,390 

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 

No Data – EPA does not have data for some pollutants identified as POCs. 

a – All metals concentrations are estimated as the total recoverable metals concentrations.. The concentrations 

presented are not the expected dissolved metals concentrations. 
Section 11 – F

11-27 

Table 11-3. Characteristics of FGD Blowdown at EPRI Sites P, R, and S 

Parameter Units 

Site P Site R 

Filtered Settled Total Filtered Settled Total Filtere

Aluminum μg/L 1,000 U 1,000 U 26,000 1,000 U 1,000 U 102,000 200 Antimony μg/L 50 U 50 U 500 U 50 U 50 U 500 U 10 Arsenic μg/L 30 U 30 U 300 U 30 U 30 U 300 U 10 Barium μg/L 1,030 1,060 2,500 U 250 U 250 U 2,930 60 Beryllium μg/L 40 U 40 U 400 U 40 U 40 U 400 U 8 Boron μg/L 255,000 261,000 244,000 411,000 407,000 340,000 88,300 Cadmium μg/L 50 U 50 U 500 U 50 U 50 U 500 U 37.8 Calcium μg/L 4,240,000 4,440,000 30,500,000 748,000 751,000 34,300,000 N/A Chromium μg/L 100 U 100 U 1,030 100 U 100 U 1,000 U 20 Chromium VI μg/L Cobalt μg/L 100 U 100 U 1,000 U 100 U 100 U 1,000 U 55.8 Copper μg/L 100 U 100 U 1,000 U 321 298 4,230 U 47.4 Iron μg/L 1,000 U 1,630 60,900 1,000 U 1,000 U 185,000 200 Lead μg/L 50 U 50 U 500 U 50 U 50 U 500 U 10 Magnesium μg/L 4,510,000 4,710,000 4,290,000 1,140,000 1,150,000 1,050,000 994,000 Manganese μg/L 6,390 6,530 8,410 1,650 1,670 14,900 13,900 Mercury μg/L 0.55 2.3 73.6 7.4 6.4 91.6 0.1 Molybdenum μg/L 532 549 2,500 U 250 U 250 U 2,500 U 76.2 Nickel μg/L 447 463 2,000 U 200 U 200 U 2,000 U 258 Potassium μg/L 1,060,000 1,120,000 684,000 28,000 27,100 70,600 20,600 Selenium μg/L 1,610 1,660 2,930 1,810 1,860 2,000 U 485 Selenium IV μg/L 414 35 Selenium VI μg/L 4 1,700 Silver μg/L 100 U 100 U 1,000 U 100 U 100 U 1,000 U 20 Sodium μg/L 5,530,000 5,550,000 5,340,000 943,000 950,000 867,000 135,000 Strontium μg/L Thallium μg/L 100 U 100 U 1,000 U 100 U 100 U 1,000 U 20 Titanium μg/L 1,000 U 1,000 U 10,000 U 1,000 U 1,000 U 10,000 U 200 Vanadium μg/L 250 U 250 U 2,500 U 250 U 250 U 2,500 U 50 Zinc μg/L 200 U 200 U 2,000 U 200 U 200 U 2,000 U 1,080 Acidity mg CaCO3/L 800 780 950 400 397 470 54 Alkalinity mg CaCO3/L 155 170 3,200 625 620 5,040 202 
Section 11 – F

11-28 

Table 11-3. Characteristics of FGD Blowdown at EPRI Sites P, R, and S 

Parameter Units 

Site P Site R 

Filtered Settled Total Filtered Settled Total Filtere

Chloride a mg/L 29,200 29,200 28,800 982 963 979 1,120 Conductivity μhos/cm 79,000 80700 85,000 8,570 8,520 7,690 6,360 Fluoride a mg/L 5.8 12.9 16.3 Hardness as CaCO3 mg/L pH pH units 6.7 6.7 6.7 7.3 7.2 7.1 7.3 Sulfate a mg/L 2,180 4,750 3,240 TDS mg/L 48,400 48,100 57,700 12,600 12,800 14,200 N/A TKN mg N/L 63.9 79 97.3 33.5 31 45.9 2.9 TSS mg/L 8 91 94,900 2 U 2 U 170,000 N/A Observations High TSS and chloride Appears R dumps due to solids rather than chloride Flow (gpm avg) No information from site No information from site Source: EPRI, 2006a. U = Non-detect. N/A = Not applicable. *Results from Sites S and T for selenium speciation were from different samples (collected August 2005) than the other parameters (collected O

a – Chloride, fluoride, and sulfate were analyzed by ICP-MS so filtered in analysis. Therefore, “Total,” “Settled,” and “filtered” are all actually t

was reported. 
Section 11 – F

11-29 

Table 11-4. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y 

Parameter Units 

Site T Site U 

Filtered Settled Total Filtered Settled Total Filtere

Aluminum μg/L 1,000 U 1,810 170,000 403 739 955 25,100 Antimony μg/L 50 U 50 U 500 U 10 U 10 U 10 U 14.1 Arsenic μg/L 10 U 10 U 415 15.5 16.3 17.3 1.6 Barium μg/L 250 U 250 U 2,960 207 232 254 225 Beryllium μg/L 40 U 40 U 400 U 8 U 8 U 8 U 4 Boron μg/L 360,000 359,000 344,000 14,900 14,400 15,100 14,300 Cadmium μg/L 96.7 96.4 500 U 10 U 16.3 12.2 21 Calcium μg/L N/A N/A N/A 659,000 650,000 680,000 725,000 Chromium μg/L 100 U 100 U 1,000 U 20 U 20 U 20 U 12 Chromium VI μg/L Cobalt μg/L 100 U 100 U 1,000 U 20 U 20 U 20 U 26.7 Copper μg/L 100 U 121 1,000 U 136 157 152 145 Iron μg/L 1,000 U 2,060 292,000 200 U 657 974 100 Lead μg/L 50 U 50 U 500 U 10 U 10 U 10 U 5 Magnesium μg/L 2,550,000 2,510,000 2,680,000 851,000 838,000 873,000 199,000 Manganese μg/L 19,300 19,000 23,800 5,380 5,350 5,480 1,810 Mercury μg/L 0.44 1.4 78 3.3 7.1 7.5 9 Molybdenum μg/L 758 748 2,500 U 86.6 88.7 89.6 25 Nickel μg/L 687 694 2,000 U 173 173 181 92.1 Potassium μg/L 202,000 195,000 241,000 329,000 309,000 326,000 21,900 Selenium μg/L 1,150 1,160 2,000 U 40 U 40 U 40 U 131 Selenium IV μg/L 90 * 4.34 Selenium VI μg/L 1,350 * 6 Silver μg/L 100 U 100 U 1,000 U 20 U 20 U 20 U 10 Sodium μg/L 389,000 396,000 323,000 2,540,000 2,400,000 2,580,000 51,600 Strontium μg/L Thallium μg/L 100 U 100 U 1,000 U 20 U 20 U 20 U 10 Titanium μg/L 1,000 U 1,000 U 10,000 U 200 U 200 U 200 U 100 Vanadium μg/L 250 U 250 U 2,500 U 50 U 50 U 50 U 25 Zinc μg/L 3,480 3,440 9,040 53 54.2 58 1,290 Acidity mg CaCO3/L 268 232 274 42.2 45 44.2 128 Alkalinity mg CaCO3/L 200 136 2,100 76 74 75 5 
Section 11 – F

11-30 

Table 11-4. Characteristics of FGD Blowdown at EPRI Sites T, U, and Y 

Parameter Units 

Site T Site U 

Filtered Settled Total Filtered Settled Total Filtere

Chloride a mg/L 3,850 3,750 3,650 3,610 3,650 3,610 584 Conductivity μhos/cm 11,800 11,500 11,400 13,300 13,400 13,400 3,620 Fluoride a mg/L 48.6 8.2 51.6 Hardness as CaCO3 mg/L 5,450 5,500 5,700 2,860 pH pH units 7.2 7.2 7.2 7.3 7.2 7.3 6 Sulfate a mg/L 6,090 4,340 1,480 TDS mg/L N/A 16,400 155 14,300 14,400 14,600 4,360 TKN mg N/L 13.8 11.8 11.4 39.8 32.5 37.1 2.2 TSS mg/L N/A 231 13,700 3 U 18 32 5 Observations Oddly low TSS and chloride Low TSS is due to thickener Flow (gpm avg) No distinct chloride purge stream Based on chloride content of 9,000 ppm Source: EPRI, 2006a. U = Non-detect. N/A = Not applicable. *Results from Sites S and T for selenium speciation were from different samples (collected August 2005) than the other parameters (collected O

a – Chloride, fluoride, and sulfate were analyzed by ICP-MS so filtered in analysis. Therefore, “Total,” “Settled,” and “filtered” are all actually t

was reported. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-31 

Table 11-5. Data Sets Used in Developing Effluent Characterization Data for 

Chemical Precipitation 

Plant Name Source of Data Set 

First Energy’s Hatfield’s Ferry Power Station (Hatfield’s Ferry) 

EPA on-site field sampling data

CWA 308 monitoring data

Industry-submitted plant monitoring data

NRG Energy’s Keystone Generating Station (Keystone) 

EPA on-site field sampling data

CWA 308 monitoring data

Industry-submitted plant monitoring data

Duke Energy’s Miami Fort Station (Miami Fort) 

EPA on-site field sampling data

CWA 308 monitoring data

Industry-submitted plant monitoring data 

We Energies’ Pleasant Prairie Power Plant (Pleasant Prairie) 

EPA on-site field sampling data

CWA 308 monitoring data

Industry-submitted plant monitoring data

Source: ERG, 2015b; ERG, 2015d.

 
Section 11 – FGD Wastewater Pollutant Loadings 

11-32 

Table 11-6. Average Effluent Concentration of Chemical Precipitation System 

Analyte Unit Average Concentration

Aluminum ug/L 120

Ammonia as N ug/L 6,850

Antimony ug/L 4.25

Arsenic ug/L 5.83

Barium ug/L 140

Beryllium ug/L 1.34

Boron ug/L 225,000

Cadmium ug/L 4.21

Calcium ug/L 1,920,000

Chloride ug/L 7,820,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Cyanide ug/L 949

Iron ug/L 110

Lead ug/L 3.39

Magnesium ug/L 3,570,000

Manganese ug/L 12,500

Mercury ug/L 0.139

Molybdenum ug/L 166

Nickel ug/L 9.11

Nitrate-Nitrite as N ug/L 96,000

Phosphorus, Total ug/L 319

Selenium ug/L 928

Sodium ug/L 441,000

Thallium ug/L 9.81

Titanium ug/L 9.30

TSS ug/L 24,100,000

TDS ug/L 8,590

Vanadium ug/L 12.63

Zinc ug/L 20.0

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-33 

Table 11-7. Data Sets Used in Developing Effluent Characterization Data for 

Biological Treatment 

Plant Name Source of Data Set 

Duke Energy Carolinas’ Allen Steam Station (Allen) 

EPA on-site field sampling data

CWA 308 monitoring data

Industry-submitted plant monitoring data 

Duke Energy Carolinas’ Belews Creek Steam Station (Belews Creek) 

EPA on-site field sampling data

CWA 308 monitoring data

Industry-submitted plant monitoring data

Source: ERG, 2015b; ERG, 2015d. 

 
Section 11 – FGD Wastewater Pollutant Loadings 

11-34 

Table 11-8. Average Effluent Concentration of Chemical Precipitation System with 

Biological Treatment 

Analyte Unit Average Concentration

Aluminum ug/L 279

Ammonia as N ug/L 8,750

Antimony ug/L 3.70

Arsenic ug/L 3.52

Barium ug/L 313

Beryllium ug/L 1.20

Boron ug/L 143,000

Cadmium ug/L 2.73

Calcium ug/L 2,510,000

Chloride ug/L 4,990,000

Chromium ug/L 2.77

Cobalt ug/L 8.17

Copper ug/L 7.17

Cyanide ug/L 74.3

Iron ug/L 425

Lead ug/L 1.41

Magnesium ug/L 628,000

Manganese ug/L 1,730

Mercury ug/L 0.0507

Molybdenum ug/L 34.4

Nickel ug/L 6.30

Nitrate-Nitrite as N ug/L 647

Phosphorus, Total ug/L 115

Selenium ug/L 5.72

Sodium ug/L 41,100

Thallium ug/L 2.36

Titanium ug/L 13.0

TDS ug/L 13,800,000

TSS ug/L 8,650

Vanadium ug/L 4.44

Zinc ug/L 6.32

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 

Table 11-9. Data Sets Used in Developing Effluent Characterization Data for 

Evaporation Treatment 

Plant Name Source of Data Set 

Enel’s Federico II Power Plant (Brindisi) CWA 308 monitoring data

Source: ERG, 2015b; ERG, 2015d. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-35 

Table 11-10. Average Effluent Concentration of Evaporation Treatment 

Analyte Unit Average Concentration

Aluminum ug/L 100 

Ammonia as N ug/L 24,300 

Antimony ug/L 1.00

Arsenic ug/L 2.00

Barium ug/L 10.0

Beryllium ug/L 1.00

Boron ug/L 3,750 

Cadmium ug/L 2.00

Calcium ug/L 200 

Chloride ug/L 1,500 

Chromium ug/L 4.00

Cobalt ug/L 10.0

Copper ug/L 2.00

Cyanide ug/L No Data

Iron ug/L 100 

Lead ug/L 1.00

Magnesium ug/L 200 

Manganese ug/L 10.0

Mercury ug/L 0 .0103

Molybdenum ug/L 20.0

Nickel ug/L 2.00

Nitrate-Nitrite as N ug/L 100 

Phosphorus, Total ug/L 25.0

Selenium ug/L 2.00

Sodium ug/L 5,000 

Thallium ug/L 1.00

Titanium ug/L 10.0

TDS ug/L 10,800 

TSS ug/L 2,000 

Vanadium ug/L 5.00

Zinc ug/L 28.5

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 

No Data – EPA does not have data for some pollutants identified as POCs. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-36 

Table 11-11. Pollutant Concentration Basis for Surface Impoundments 

Analyte Concentration Basis Unit Average Concentration

Aluminum Surface Impoundment ug/L 2,080 

Ammonia as N CP Effluent ug/L 6,854

Antimony Surface Impoundment ug/L 12.9

Arsenic Surface Impoundment ug/L 7.59 

Barium Surface Impoundment ug/L 303

Beryllium Surface Impoundment ug/L 1.92 

Boron Surface Impoundment ug/L 243,000

Cadmium Surface Impoundment ug/L 113

Calcium Surface Impoundment ug/L 2,050,000

Chloride Surface Impoundment ug/L 7,120,000

Chromium Surface Impoundment ug/L 17.8 

Cobalt Surface Impoundment ug/L 183

Copper Surface Impoundment ug/L 21.8

Cyanide CP Effluent ug/L 949

Iron Surface Impoundment ug/L 1,510

Lead Surface Impoundment ug/L 4.66 

Magnesium Surface Impoundment ug/L 3,370,000

Manganese Surface Impoundment ug/L 93,400

Mercury Surface Impoundment ug/L 7.78 

Molybdenum Surface Impoundment ug/L 125

Nickel Surface Impoundment ug/L 878

Nitrate-Nitrite as N CP Effluent ug/L 96,000

Phosphorus, Total CP Effluent ug/L 319

Selenium Surface Impoundment ug/L 1,170

Sodium Surface Impoundment ug/L 276,000

Thallium Surface Impoundment ug/L 13.7 

Titanium Surface Impoundment ug/L 27.1

TDS Surface Impoundment ug/L 32,500,000

TSS Surface Impoundment ug/L 27,900

Vanadium Surface Impoundment ug/L 16.4 

Zinc Surface Impoundment ug/L 1,390

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-37 

Table 11-12. Pollutant Concentration Basis for Chemical Precipitation 

Analyte Concentration Basis Unit Average Concentration

Aluminum CP Effluent ug/L 120

Ammonia as N CP Effluent ug/L 6,854

Antimony CP Effluent ug/L 4.25 

Arsenic CP Effluent ug/L 5.83 

Barium CP Effluent ug/L 140

Beryllium CP Effluent ug/L 1.34 

Boron CP Effluent ug/L 225,000

Cadmium CP Effluent ug/L 4.21 

Calcium CP Effluent ug/L 1,920,000

Chloride Surface Impoundment ug/L 7,120,000

Chromium CP Effluent ug/L 6.45 

Cobalt CP Effluent ug/L 9.30 

Copper CP Effluent ug/L 3.78 

Cyanide CP Effluent ug/L 949

Iron CP Effluent ug/L 110

Lead CP Effluent ug/L 3.39 

Magnesium Surface Impoundment ug/L 3,370,000

Manganese CP Effluent ug/L 12,500

Mercury CP Effluent ug/L 0.139

Molybdenum Surface Impoundment ug/L 125

Nickel CP Effluent ug/L 9.11 

Nitrate-Nitrite as N CP Effluent ug/L 96,000

Phosphorus, Total CP Effluent ug/L 319

Selenium CP Effluent ug/L 928

Sodium Surface Impoundment ug/L 276,000

Thallium CP Effluent ug/L 9.81 

Titanium CP Effluent ug/L 9.30 

TDS CP Effluent ug/L 24,100,000

TSS CP Effluent ug/L 8,590

Vanadium CP Effluent ug/L 12.6 

Zinc CP Effluent ug/L 20.0

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-38 

Table 11-13. Pollutant Concentration Basis for Biological Treatment 

Analyte Concentration Basis Unit Average Concentration

Aluminum CP Effluent ug/L 120

Ammonia as N CP Effluent ug/L 6,854

Antimony CP Effluent ug/L 4.25 

Arsenic CP Effluent ug/L 5.83 

Barium CP Effluent ug/L 140

Beryllium CP Effluent ug/L 1.34 

Boron CP Effluent ug/L 225,000

Cadmium CP Effluent ug/L 4.21 

Calcium CP Effluent ug/L 1,920,000

Chloride Surface Impoundment ug/L 7,120,000

Chromium CP Effluent ug/L 6.45 

Cobalt CP Effluent ug/L 9.30 

Copper CP Effluent ug/L 3.78 

Cyanide CP Effluent ug/L 949

Iron CP Effluent ug/L 110

Lead CP Effluent ug/L 3.39 

Magnesium Surface Impoundment ug/L 3,370,000

Manganese CP Effluent ug/L 12,500

Mercury Bio Effluent ug/L 0.0507

Molybdenum Surface Impoundment ug/L 125 

Nickel Bio Effluent ug/L 6.30 

Nitrate-Nitrite as N Bio Effluent ug/L 647

Phosphorus, Total CP Effluent ug/L 319

Selenium Bio Effluent ug/L 5.72 

Sodium Surface Impoundment ug/L 276,000

Thallium CP Effluent ug/L 9.81 

Titanium CP Effluent ug/L 9.30 

TDS CP Effluent ug/L 24,100,000

TSS CP Effluent ug/L 8,590

Vanadium CP Effluent ug/L 12.6 

Zinc CP Effluent ug/L 20.0

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-39 

Table 11-14. Pollutant Concentration Basis for Evaporation 

Analyte Concentration Basis Unit Average Concentration

Aluminum Evaporation Effluent ug/L 100.0

Ammonia as N Evaporation Effluent ug/L 24,300

Antimony Evaporation Effluent ug/L 1.00

Arsenic Evaporation Effluent ug/L 2.00

Barium Evaporation Effluent ug/L 10.0

Beryllium Evaporation Effluent ug/L 1.00

Boron Evaporation Effluent ug/L 3,750

Cadmium Evaporation Effluent ug/L 2.00

Calcium Evaporation Effluent ug/L 200

Chloride Evaporation Effluent ug/L 1,500

Chromium Evaporation Effluent ug/L 4.00

Cobalt Evaporation Effluent ug/L 10.0

Copper Evaporation Effluent ug/L 2.00

Cyanide CP Effluent ug/L 949

Iron Evaporation Effluent ug/L 100

Lead Evaporation Effluent ug/L 1.00

Magnesium Evaporation Effluent ug/L 200

Manganese Evaporation Effluent ug/L 10.0

Mercury Evaporation Effluent ug/L 0.0103

Molybdenum Evaporation Effluent ug/L 20.0

Nickel Evaporation Effluent ug/L 2.00

Nitrate-Nitrite as N Evaporation Effluent ug/L 100

Phosphorus, Total Evaporation Effluent ug/L 25.0

Selenium Evaporation Effluent ug/L 2.00

Sodium Evaporation Effluent ug/L 5,000

Thallium Evaporation Effluent ug/L 1.00

Titanium Evaporation Effluent ug/L 10.0

TDS Evaporation Effluent ug/L 10,800

TSS Evaporation Effluent ug/L 2,000

Vanadium Evaporation Effluent ug/L 5.00

Zinc Evaporation Effluent ug/L 28.5

Source: ERG, 2015b; ERG, 2015d. 

Note: Concentrations are rounded to three significant figures. 
Section 11 – FGD Wastewater Pollutant Loadings 

11-40 

Table 11-15. Industry-Level FGD Wastewater Loadings Excluding BOD, COD, TDS, and 

TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology 

Basis 

Treatment Option 

Number of 

Plants 

Total Industry

Discharge Flow 

(MGD) a 

Total Industry Loadings 

Pounds/Year TWPE/Year

Baseline 88 b41.7 1,660,000,000 1,880,000

Chemical Precipitation 88 b38.4 1,620,000,000 1,070,000

Chemical Precipitation With Biological 

Treatment 

88 b38.4 1,610,000,000 925,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS and TSS. 

Note: Loadings are rounded to three significant figures.

a – The reduction in total industry discharge flow from baseline to the technology options is associated with the

plants for which EPA assumed that some recycle of the FGD wastewater would occur prior to treatment, as 

described in Section 4.5.2. 

b – One plant operates only oil-fired generating units and/or generating units with a generating capacity of 50 MW 

or less; therefore, this plant is not facing any more stringent requirements than exist under the previously established 

BPT regulations. As such, EPA assumed that this plant will not install the technology basis and, therefore, will not 

incur any compliance costs. Additionally, EPA assumed it will continue to discharge FGD wastewater at its current 

baseline level and will not achieve any pollutant removals for the technology options evaluated. 

Table 11-16. FGD Wastewater Pollutant Removals Excluding BOD, COD, TDS, and TSS 

and Based on Oil-Fired Units and Units 50 MW or Less Not Installing Technology Basis 

Treatment Option 

Total Industry Removals

Pounds/Year TWPE/Year

Removal (Baseline –>Chemical Precipitation) 36,800,000 804,000

Removal (Baseline –>Chemical Precipitation With Biological 

Treatment) 

47,200,000 952,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS and TSS. 

Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the 

technology option from the baseline using the values in Table 11-15 due to rounding.
Section 12 – Ash Transport Water Pollutant Loadings 

12-1 

12. ASH TRANSPORT WATER POLLUTANT LOADINGS 

This section discusses annual pollutant loadings from existing steam electric power plants 

that discharge ash transport water and pollutant removals estimates associated with the final rule, as 

well as several other regulatory options. EPA identified 144 plants that discharged ash transport 

water in 2009 (fly ash transport water, bottom ash transport water, and/or combined ash transport 

water) and have no plans to retire, convert fuels, or convert to dry ash handling prior to December 

31, 2023, or convert to complete dry ash handling due to the Coal Combustion Residuals (CCR) 

rule. For these plants, EPA evaluated zero discharge technology options as one of the bases for final 

requirements for fly ash and bottom ash transport water. For other technology options, EPA applied 

different effluent limitations to oil-fired generating units and generating units with a specific 

capacity (50 megawatts (MW) or less or 400 MW or less). In these cases, the plants will not face 

more stringent requirements than already existed under preexisting regulations; thus, postcompliance loadings are set equal to the baseline loadings. EPA defined baseline loadings and postcompliance pollutant loadings for ash transport water as follows: 

• Baseline Loadings. Estimated pollutant loadings, in pounds per year, of fly ash 

transport water or bottom ash transport water discharged directly to surface water or 

indirectly to surface water through publicly owned treatment works (POTWs) at the 

current level of treatment (i.e., treatment-in-place) and prior to implementing 

controls to comply with the final rule. 

• Post-Compliance Loadings. Estimated pollutant loadings, in pounds per year, of fly 

ash transport water or bottom ash transport water after implementation of the 

technology option. EPA calculated these loadings assuming that all steam electric 

power plants subject to the requirements would install and operate wastewater 

treatment and pollution prevention technologies equivalent to the technology bases 

for the regulatory options (i.e., zero discharge technologies). 

• Pollutant Removals. The difference between the baseline loadings and postcompliance loadings for each technology option. 

Loadings calculations require a pollutant-specific concentration and plant-specific discharge 

flow to determine mass discharge loadings. EPA used a variety of data sources to generate 

characterization data for fly ash transport water and bottom ash transport water. To generate the ash 

loadings, EPA developed three separate sets of characterization data to represent the effluent 

concentrations from fly ash impoundments, bottom ash impoundments, and combined fly ash and 

bottom ash impoundments. EPA then identified the ash impoundments operating in the industry and 

categorized them into the three types of impoundments. Finally, EPA calculated ash loadings using 

flow rate data for each generating unit/impoundment combination and multiplying them by the 

appropriate concentrations based on the type of impoundment. 

Section 12.1 presents the data sources used to characterize ash transport water. Section 12.2 

discusses the methodology used to calculate the plant-specific discharge flow rates, as well as the 

baseline and technology option pollutant loadings and pollutant removals. Section 12.3 presents the 

ash pollutant loadings and toxic-weighted pound equivalents (TWPE). Section 12.4 discusses 
Section 12 – Ash Transport Water Pollutant Loadings 

12-2 

sensitivity analyses of the ash loadings. All tables and figures referenced in this section are 

presented at the end of the section. 

12.1 DATA SOURCES

EPA relied on data collected during the detailed study, industry-supplied data, and publicly 

available data sources, including data received during public comment, to identify pollutants of 

concern (POCs) in fly ash transport water and bottom ash transport water, and to characterize 

pollutant discharge concentrations from ash impoundments (fly ash, bottom ash, and combined ash). 

EPA also used data collected in the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey) to characterize discharge flows. A list of data sources evaluated 

and accepted by EPA to identify POCs and characterize the discharges from ash impoundments are 

listed below: 

• EPA ash impoundment sampling data from the detailed study [U.S. EPA, 2009]. 

• The Steam Electric Technical Questionnaire Database [ERG, 2015i]. 

• Bottom Ash Wastewater Evaluation: Interstate Power and Light Co. – Dubuque 

Generating Station [Interstate, 2004] 

• Electric Power Research Institute (EPRI) Power Plant Integrated Systems - Chemical 

Emissions Study (PISCES) Reports [EPRI, 1997-2001]. 

• Mitigation of SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 

2006]. 

• Permit application data (Form 2C), as provided by member companies of the Utility 

Water Act Group (UWAG) [UWAG, 2008]. 

• Development Document for Final Effluent Limitations Guidelines, New Source 

Performance Standards, and Pretreatment Standards for the Steam Electric Point 

Source Category, EPA 440-1-82-029, November 1982 (1982 TDD) [U.S. EPA, 

1982]. 

• Public comments received from Duke Energy, including responses to EPA follow-up 

questions regarding the data submitted in comments [Duke Energy, 2013 and 2014]. 

• Public comments received from Hoosier Energy Rural Electric Cooperative, 

including responses to EPA follow-up questions regarding the data submitted in 

comments [Hoosier Energy, 2013 and 2014]. 

• Public comments and supplemental data received from UWAG, including responses 

to EPA follow-up questions and post-proposal data submissions [UWAG, 2013, 

2014a, and 2014b]. 

EPA performed a detailed review of each of these sources to identify ash transport water 

characterization data that met EPA’s data acceptance criteria for inclusion in analyses for 

identifying POCs and for characterizing discharges of ash transport water. EPA determined criteria 

for data acceptance, described in Table 12-1, and applied the criteria to each of the data sources. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-3 

During the data review, EPA extracted information from each data source to complete a data review 

matrix. Information extracted from each data source included: 

• Data source identification. 

• Plant identification. 

• Wastestream identification (i.e., the type of ash transport water, degree of treatment 

the sample(s) represent). 

• Sample identification (i.e., count of samples, whether these samples represented 

individual data points or averages). 

• Data usability (e.g., pollutants, units of measure, collection methods, analytical 

methods, and limits identified). 

• Representativeness of wastestream (i.e., appropriate sample location, sample quality, 

typical and full-scale operations). 

• Wastestream characterization (e.g., relative contribution of wastestreams making up 

the sample). 

Because EPA collected and used data from a variety of sources, the data review matrix 

allowed EPA to ensure that data were evaluated consistently across all sources. EPA’s collection, 

evaluation, and use of ash data is described in detail in the “Ash Analytical Data Review 

Memorandum” [ERG, 2015b]. In its review, EPA excluded data that did not meet the data 

acceptance criteria and therefore were not usable in the ash POC analysis and/or calculation of 

pollutant loadings. EPA’s acceptance of each ash data set evaluated during this review is provided 

in the “Ash Data Review Matrix” [ERG, 2015j]. EPA included ash impoundment effluent data of 

acceptable quality for use in the pollutant loadings calculations in the Steam Electric Analytical 

Database [ERG, 2015a]. 

The following sections describe each of the data sources EPA used in the ash analytical 

database and the creation of a data set of ash impoundment effluent concentrations by impoundment 

type and pollutant. For each set of data from each source, EPA used available information to 

characterize the impoundment/outfall as either a fly ash impoundment, bottom ash impoundment, or 

combined ash impoundment. For the purposes of this analysis, the following criteria were used to 

create those determinations: 

• Fly ash impoundment: An impoundment/outfall that receives at least 75 percent by 

volume fly ash transport water and does not receive bottom ash transport water. The 

impoundment may also receive other types of wastewater (e.g., low-volume 

wastewaters, cooling water, etc.). 

• Bottom ash impoundment: An impoundment/outfall that receives at least 75 percent 

by volume bottom ash transport water and does not receive fly ash transport water. 

The impoundment may also receive other types of wastewater (e.g., low-volume 

wastewaters, cooling water, etc.). 
Section 12 – Ash Transport Water Pollutant Loadings 

12-4 

• Combined ash impoundment: An impoundment/outfall where the combination of fly 

ash and bottom ash transport water comprises at least 75 percent by volume of the 

total flow. The impoundment may also receive other types of wastewater (e.g., lowvolume wastewaters, cooling water, etc.). 

To ensure the wastestreams are representative of ash transport water, EPA established the 

data acceptance criteria listed above, ensuring that at least 75 percent of the impoundment volume 

comprises ash transport water. Data characterizing impoundments that contained less than 75 

percent by volume of ash transport water were excluded from use in the POC analysis and pollutant 

loadings analysis because the presence of dilution volumes, such as cooling water, will result in an 

underestimate of pollutant concentrations. 

EPA conducted an analysis to identify POCs for ash transport water. EPA included data for 

fly ash and bottom ash transport water samples but did not include combined ash transport water 

samples in the POC analysis. Due to the limited data set for untreated fly transport water and 

bottom ash transport water, EPA also included samples representing partially treated fly ash and 

bottom ash transport water and fly ash and bottom ash impoundment effluent to identify POCs for 

each wastestream. For wastestreams where EPA is establishing zero discharge (i.e., fly ash transport 

water, bottom ash transport water, and flue gas mercury control (FGMC) wastewater), the POCs 

identified for each wastestream are those pollutants that are confirmed to be present at sufficient 

frequency in untreated wastewater samples of that wastestream. Because EPA did not need to 

identify pollutants at a treatable level, EPA determined partially treated ash transport water data and 

ash impoundment effluent data were also acceptable in the POC analysis. 

For some of the ash transport water data, industry also supplied paired source water data to 

demonstrate that the source water used for ash transport may contribute to the pollutants present in 

untreated ash transport water. Where paired source water and ash transport water samples were 

available, EPA reviewed data for the paired source water and ash transport water to identify 

pollutants detected at greater than or equal to two times the concentration of the source water at 10 

percent or more of all plants with paired samples. EPA used two times the source water 

concentration for the analysis because it sufficiently indicates the pollutant is present in 

concentrations above the source water concentrations. Where paired source water and ash transport 

water data were not available or did not sufficiently indicate the presence of the pollutant in ash 

transport water, EPA reviewed data for ash transport water without paired source water data and 

identified pollutants detected at greater than or equal to two times the pollutant’s baseline value at 

10 percent or more of all plants with unpaired samples. EPA used baseline values from the 

Development Document for Effluent Limitations Guidelines and Standards for the Centralized 

Waste Treatment Industry [U.S. EPA, 2000]. More details on EPA’s POC analysis for ash transport 

water, the data accepted for identifying POCs, and results of the analysis are documented in the 

memorandum, “Bottom Ash and Fly Ash Transport Water Pollutants of Concern (POC) Analysis 

Methodology” [ERG, 2015d]. 

EPA estimated pollutant loadings and removals for pollutants that were identified as POCs 

for fly ash transport water, bottom ash transport water, or that were identified as constituents of 
Section 12 – Ash Transport Water Pollutant Loadings 

12-5 

combined ash impoundments.113 Sections 12.1.1 through Section 12.1.8 focus on the data from 

each data source that was accepted for use in the ash loadings analysis to estimate average pollutant 

concentrations of ash impoundment effluents and calculate the pollutant loadings from ash 

impoundments. The remainder of Section 12 discusses EPA’s methodology for developing average 

concentrations and calculating pollutant loadings and applies only to pollutants identified as POCs. 

12.1.1 EPA Detailed Study Ash Impoundment Sampling Data 

As discussed in Section 3.3.1, EPA conducted a sampling program as part of the detailed 

study to characterize untreated wastewaters generated by coal-fired steam electric power plants, as 

well to evaluate treatment technologies and best management practices for reducing pollutant 

discharges. During the sampling program, EPA identified that four plants operated some type of wet 

ash handling system, either wet bottom ash handling, wet fly ash handling, or both. EPA collected 

samples representing two impoundments receiving fly ash transport water, one impoundment 

receiving bottom ash transport water, and one impoundment that received combined fly ash and 

bottom ash transport water [U.S. EPA, 2009]. The impoundments at the four plants were 

categorized as follows: 

• Cardinal – Fly ash impoundment. 

• Homer City – Bottom ash impoundment. 

• Mitchell – Fly ash impoundment. 

• Widows Creek – Combined ash impoundment. 

In the proposed rulemaking, EPA included the results representing effluent from these four 

impoundments in the ash analytical database and ash loadings calculations. Following proposal and 

review of the public comments, EPA revised the acceptance criteria for ash impoundment effluent 

concentration data for the final rulemaking to use ash impoundment characterization data only from 

an impoundment or outfall where ash contributions to the impoundment are at least 75 percent ash 

transport water by volume. For each of the four plants sampled, EPA reviewed available materials 

to determine if the ash impoundment effluent samples met the acceptance criteria described in Table 

12-1. Based on the review of sampling episode reports and plant-provided responses to the Steam 

Electric Survey, EPA identified one plant that had data acceptable for use in characterizing bottom 

ash impoundment effluent. Sampling data from the other three plants contain less than 75 percent 

by volume of ash transport water and were not accepted for the ash loadings analysis. 

EPA included the results from the Homer City plant sampling episode in the ash 

impoundment effluent concentrations data set. However, because EPA had additional information 

about these sampling data (e.g., quality control (QC) results) and because some of the metals were 

analyzed using two different analytical methods, EPA’s loadings methodology included a hierarchy 

to select which data should be included in the loadings calculations. The following are the steps 

EPA used to identify which concentrations to use in the Homer City bottom ash impoundment 

concentrations data set: 

 

113 EPA calculated combined ash pollutant loadings for fly ash transport water and bottom ash transport water POCs, as 

well as biochemical oxygen demand (BOD), cyanide, hexavalent chromium (chromium VI), and silver which were 

identified as constituents of combined fly ash and bottom ash impoundments. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-6 

• EPA received both routine (e.g., EPA Methods 200.7, 200.8) and low-level (i.e., 

EPA Method 1638) analytical results for 13 of the 28 metal analytes. To determine 

whether the routine or low-level measurement should be used in the loadings 

calculation, EPA developed a decision tree (see Figure 12-1). All of the sampling 

data for these 13 metal analytes were analyzed by the decision tree prior to being 

used in the loadings calculations.114

• If the analytes were not measured above the quantitation limit, then the concentration 

was assumed to be one-half the quantitation limit of the method with the lower 

reporting limit. 

12.1.2 Steam Electric Technical Questionnaire Database 

As discussed in Section 3.1, the principal source of information and data used in developing 

the ELGs are the responses provided by industry to the survey distributed by EPA under the 

authority of Section 308 of the Clean Water Act (CWA), 33 U.S.C. 1318. EPA designed the 

industry survey to obtain technical information related to wastewater generation and treatment, and 

economic information such as costs of wastewater treatment technologies and financial 

characteristics of potentially affected companies [ERG, 2015i]. The responses were used to evaluate 

pollution control options for establishing revisions to the ELGs for the Steam Electric Power 

Generating Point Source Category. EPA used certain information from the 733 plant responses to 

identify the population of plants that operate ash impoundments, as well as identify the specific 

wastestreams entering the impoundments and the associated discharge flow rates. The type of 

information used for the ash loadings is described further in Section 12.2. 

12.1.3 Electrical Power Research Institute Reports 

As described in Section 3.5, EPRI provided EPA with the PISCES Water Characterization 

Field Study, Sites A-G reports that summarize the data collected during seven separate site visits to 

characterize wastewater at coal-fired steam electric power plants [EPRI, 1997-2001]. Additionally, 

EPA received technical reports prepared by EPRI as part of plant responses to the Steam Electric 

Survey. EPA reviewed these reports submitted for ash impoundment characterization data. 

In the proposed rulemaking, EPA included the average results from each of the seven sites 

sampled in the PISCES reports in the ash impoundment effluent concentrations data set. As 

explained above, following proposal and review of the public comments, EPA revised the 

acceptance criteria for ash impoundment effluent concentration data for the final rulemaking (see 

Table 12-1). For the final rulemaking, EPA reviewed each of the seven site reports to determine if 

the samples met these acceptance criteria. Based on the review of the EPRI PISCES reports, EPA 

identified three sites that had usable ash impoundment effluent data for the ash loadings analysis for 

three impoundments. EPA included the individual sample concentrations for each pollutant for each 

of the sites in the ash impoundment effluent concentrations data set. The sites were identified as 

operating the following type of ash impoundments: 

 

114 EPA used the decision tree for all data sets for which both routine and low-level analyses were conducted for the 

same sample. This includes the EPRI PISCES data and UWAG data sets. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-7 

• Site C – Combined ash impoundment (samples collected 1996-7). 

• Site F – Bottom ash impoundment (samples collected 1998-9). 

• Site G – Combined ash impoundment (samples collected 2000). 

EPA also reviewed the industry responses to the Steam Electric Survey for reports with ash 

impoundment effluent characterization data. Based on the review of the reports, EPA identified one 

EPRI report that had data acceptable to characterize fly ash impoundment effluent. Mitigation of 

SCR-Ammonia Related Aqueous Effects in a Fly Ash Pond [EPRI, 2006] presents sampling data 

from a fly ash impoundment at American Electric Power’s (AEP) John E. Amos plant. The report 

was submitted as part of the John E. Amos plant’s response to the Steam Electric Survey. All data 

confirmed to be representative of fly ash impoundment effluent were added to the ash impoundment 

effluent analytical database. 

12.1.4 Permit Application Data 

As described in Section 3.6, UWAG created a database of selected National Pollutant 

Discharge Elimination System (NPDES) Form 2C data from UWAG’s member companies and 

provided the database to EPA [UWAG, 2008]. The NPDES Form 2C database contains information 

about the outfalls from 86 coal-fired steam electric power plants that discharge FGD, ash transport, 

or coal pile runoff wastestreams. EPA matched pollutant data from the NPDES Form 2C database 

to data in Parts A and D of the Steam Electric Survey by NPDES permit number and outfall number 

to determine which outfalls discharge fly ash transport water, bottom ash transport water, or 

combined ash transport water. For those NPDES permit IDs that did not match information from the 

Steam Electric Survey, EPA conducted a manual search to generate a crosswalk between the Form 

2C NPDES permit number and the reported NPDES permit number in the Steam Electric Survey. 

After the NPDES permit numbers were matched, EPA matched the outfalls in the Form 2C database 

to those reported in the Steam Electric Survey using the following hierarchy: 

1. Outfall numbers that matched exactly. 

2. Outfall numbers that did not match due to different formatting. 

3. Matching outfall descriptions. 

For the final rulemaking, EPA used the information from Parts A and D of the Steam 

Electric Survey to calculate the percent contribution of the ash transport water to the total outfall 

flow rate. For each outfall in the Form 2C database for which 75 percent or more of its flow is from 

ash transport water (fly, bottom, or the sum of the two), which accounts for 26 outfalls, EPA 

included the reported pollutant concentrations in the ash impoundment effluent concentrations data 

set. EPA excluded data from one permit application, NPDES outfall MO-0000353-002 (Sioux 

Power Plant), because UWAG submitted a more complete data set for this outfall as part of their 

public comments to the ELGs; these data included results for additional pollutants not captured in 

the Form 2C database. EPA included the data set provided by UWAG in place of the Form 2C data 

in the analytical database because it is more complete. For all other Form 2C data included, when 

more than one set of pollutant concentrations were presented in the database, EPA used the 

following hierarchy to select data for inclusion in the analytical database: 

1. Long-term average concentration. 

2. Thirty-day maximum concentration. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-8 

3. Daily maximum concentration. 

12.1.5 1982 Technical Development Document 

The 1982 Development Document for Effluent Limitations Guidelines and Standards and 

Pretreatment Standards for the Steam Electric Point Source Category (referred to as “the 1982 

TDD”) presents the results of studies of the steam electric power generating industry that EPA 

conducted in revising the Steam Electric Power Generating effluent guidelines [U.S. EPA, 1982]. 

This development document contains findings, conclusions, and recommendations on control and 

treatment technology relating to discharges from steam electric power plants. Ash impoundment 

characterization data are provided in three separate tables and an appendix contained within the 

1982 TDD. 

In the proposed rulemaking, EPA included the data representing effluent from Table V-32, 

Table V-33, and Table V-34 in the analytical database and ash loadings calculations. Following 

proposal and review of the public comments, EPA revised the acceptance criteria for ash 

impoundment effluent concentration data for the final rulemaking to use ash impoundment 

characterization data only from an impoundment that could be classified as a fly ash impoundment, 

bottom ash impoundment, or combined ash impoundment. Additionally, EPA only accepted data 

that are comprised of sample-specific results for a plant or plant-specific average concentrations. 

Where plant-specific average concentrations and sample-specific results were available, EPA used 

the sample-specific results. 

Based on review of the information provided in the 1982 TDD, EPA identified that 

Appendix A had data acceptable for use in characterizing ash impoundment effluent. Ash 

impoundment sample data from Table V-32, Table V-33, and Table V-34 were excluded from the 

ash loadings analysis for the reasons described below: 

Table V-32, Characteristics of Ash Pond Overflows with Total Suspended Solids 

Concentrations Less than 30mg/L presents average impoundment overflow pollutant concentrations 

for 11 separate impoundments at 11 plants. These data were not accepted by EPA for use in the ash 

loadings analysis because the data does not indicate the type of ash impoundment sampled at each 

plant; therefore, EPA could not categorize the data as representative of fly ash impoundment 

effluent, bottom ash impoundment effluent, or combined ash impoundment effluent. 

Table V-33, Summary of Ash Pond Overflow Data from Discharge Monitoring Reports

provides an average pollutant concentration for ash impoundment effluent for each of the three 

different types of impoundment systems (i.e., fly ash, bottom ash, combined ash). Additionally, the 

table identified the number of impoundment systems that were used to calculate the average 

concentration. At proposal, EPA included the same number of records of the average concentrations 

in the ash impoundment concentrations data set as the number of impoundments that were used to 

calculate the average. These data were not accepted by EPA for the final rulemaking because these 

data represent average concentrations across multiple plants rather than plant-specific average 

concentrations. 

Table V-34, Summary of Quarterly TVA Trace Metal Data for Ash Pond Intake and Effluent 

Streams summarizes average plant intake and ash impoundment effluent pollutant concentrations 

for 10 plants. Although these data were used at proposal, EPA removed the plant-specific average 
Section 12 – Ash Transport Water Pollutant Loadings 

12-9 

effluent pollutant concentration from the ash impoundment concentrations data set and replaced 

these data with individual data points available in Appendix A, TVA Raw River Intake and Ash Pond 

Discharge Data, of the 1982 TDD. 

The impoundment and discharge of ash transport water has long been a standard technique 

practiced since before 1982; therefore, EPA determined that these data were valid for 

characterization of ash impoundment effluent. Appendix A, TVA Raw River Intake and Ash Pond 

Discharge Data, presents individual data points for the averaged data presented in Table V-34. 

These data were accepted for use in the ash loadings analysis and populated in the ash 

impoundment effluent concentration data set. 

12.1.6 Data Submitted by Duke Energy 

EPA received public comments on the proposed rule from Duke Energy, in which Duke 

Energy submitted data for samples of bottom ash transport water from the Marshall Steam Station 

(Marshall), a 4-generating unit 2,200 MW coal-fired station, and the Belews Creek Steam Station 

(Belews Creek), a 2-generating unit 2,400 MW coal-fired station [Duke Energy, 2013]. Duke 

Energy also provided source water data collected on the same day as the bottom ash transport water 

samples. EPA requested additional information to clarify the sample collection procedure, sample 

quality information, and the selection criteria used by Duke Energy when sampling Belews Creek 

and Marshall, and to request bottom ash transport water data collected from any other Duke Energy 

plants. 

EPA ultimately requested and received sample collection and quality information from Duke 

Energy and used these data to interpret, validate, and evaluate the bottom ash transport water data 

collected at Belews Creek and Marshall against EPA’s acceptance criteria [Duke Energy, 2014]. As 

part of Duke Energy’s response to EPA’s information request, Duke Energy provided EPA with the 

“UWAG Bottom Ash Transport Water Sampling Protocol” which describes the sampling method 

used to collect the samples at Belews Creek and Marshall [UWAG, 2013b]. EPA reviewed the 

information in Duke Energy’s response and determined the bottom ash transport water samples 

were collected from the discharge pipe prior to mixing or comingling with any other wastestream or 

other waters. The samples were allowed to settle in an attempt to simulate treatment from a surface 

water impoundment and samples of the supernatant were collected and analyzed. Because the 

samples from Marshall and Belews Creek were collected before entering the impoundment and 

were settled for at least one hour, EPA determined that the data were not wholly representative of 

ash impoundment discharges. These data were instead used in a sensitivity analysis, as described in 

Section 12.4. 

In Duke Energy’s response to EPA’s data request, Duke Energy also confirmed they also 

collected bottom ash transport water data at their East Bend Station, Cliffside Steam Station, 

Cayuga Station, and Miami Fort Station [Duke Energy, 2014]. EPA was provided with these data 

and reviewed the data from East Bend Station and Miami Fort Station for possible inclusion in the 

ash loadings analysis. Duke Energy indicated that the bottom ash samples collected from Cliffside 

Steam Station (Cliffside) and Cayuga Station were analyzed by UWAG; however, Duke Energy 

was able to provide data for one split sample collected during the UWAG sampling episode at 

Cliffside. Because Duke Energy does not have the UWAG laboratory reports for the Cayuga Station 

samples, they were unable to provide these additional data to EPA. Data from East Bend Station 
Section 12 – Ash Transport Water Pollutant Loadings 

12-10 

and Miami Fort Station were entirely excluded from ash loadings calculations because they were 

collected before commingling in the impoundment and not allowed to settle at all. Samples from 

Cliffside were collected before entering the impoundment and were settled for at least one hour, 

EPA determined that the data were not wholly representative of ash impoundment discharges. The 

Cliffside ash transport water data were instead used in a sensitivity analysis (described in Section 

12.4). 

12.1.7 Data Submitted by Hoosier Energy Rural Electric Cooperative 

EPA received public comments on the proposed rule from Hoosier Energy Rural Electric 

Cooperative (Hoosier Energy), in which Hoosier Energy provided data on 32 samples of bottom ash 

impoundment effluent and fly ash impoundment effluent collected between September 2008 and 

December 2009 at the Frank E. Ratts Generating Station for a Reasonable Potential to Exceed 

analysis of nine parameters for a permit renewal. Additionally, Hoosier Energy provided data on 29 

samples of fly ash impoundment effluent and 28 samples of bottom ash impoundment effluent 

collected for mercury analysis [Hoosier, 2013]. 

EPA requested that Hoosier Energy provide EPA with any fly ash and/or bottom ash 

impoundment effluent data collected since December 2009. In addition, EPA requested 

identification of the specific impoundments (using Impoundment IDs reported in the Steam Electric 

Survey), impoundment dimensions, impoundment treatment operations, atypical operations that 

occurred, and identification of other wastestreams that enter the impoundment. EPA ultimately 

received and reviewed the requested sample collection and quality information and additional fly 

ash impoundment effluent and bottom ash impoundment effluent data collected between 2010 and 

2013. These data were reviewed for possible inclusion in the ash loadings analysis [Hoosier, 2014]. 

All data confirmed to be representative of fly ash impoundment effluent or bottom ash 

impoundment effluent were added to the ash impoundment effluent analytical database. 

12.1.8 Data Submitted by UWAG 

Throughout the development of the steam electric ELGs, EPA coordinated with UWAG, an 

industry trade association representing 198 individual energy companies and three trade 

associations of energy companies. As part of this coordination, UWAG provided EPA with several 

ash transport water data sets for EPA’s consideration and use in the characterization of the ash 

transport water. These UWAG ash transport water data submissions are described in Sections 

12.1.8.1 and 12.1.8.2. 

12.1.8.1 UWAG Public Comment Data 

As part of its public comment submission in September 2013, UWAG provided a table 

presenting bottom ash transport water data for samples collected from 21 plants [UWAG, 2013a]. 

The UWAG database samples were collected from 2001 to 2013, with samples from 17 plants 

collected between 2010 and 2013. In some cases, UWAG also provided source water data collected 

on the same sample day as the bottom ash transport water samples. As part of their public comment 

submission, UWAG also provided a report prepared by URS Corporation with 2013 sampling data 

for sulfides (as well as some other parameters) at nine plants. UWAG masked the identity of all 

plants included in the bottom ash transport water database and sulfides report. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-11 

EPA requested additional information and clarification from UWAG in order to properly 

interpret, validate, and evaluate the data to determine if these data met EPA’s acceptance criteria for 

inclusion in the pollutant loadings analysis. Specifically, EPA requested UWAG to provide more 

information about the identity of the sampled plants, the sample collection location and methods 

used, the selection criteria used by UWAG when developing their data set, information on how nondetect values were handled when calculating average concentrations, total suspended solids results 

associated with the samples, and other plant-specific information. EPA ultimately received and 

reviewed these data for possible inclusion in the ash loadings analysis [UWAG, 2014a].115

For ten of the data sets, UWAG did not identify the individual plants for which it submitted 

data, nor did it include these plants in Attachments 1 and 2 to its response to EPA follow-up 

questions. For such data sets, EPA could not confirm whether the samples met all the acceptance 

criteria because the Agency lacked sufficient data about the sources and volumes of wastewater 

managed by the impoundment (i.e., EPA could not verify that the ash impoundment effluent 

samples fulfilled the 75 percent or more ash transport water criteria). Additionally, the lack of plant 

identification precluded EPA from evaluating whether the UWAG data were for impoundments 

already included in EPA’s ash impoundment effluent data set.. EPA, therefore, excluded the data 

from these ten data sets from the loadings analysis. In addition, EPA excluded four data sets 

because the ash transport water contributions to the sampled impoundments represented less than 75 

percent of the flow into the impoundment, and excluded data from one plant data set where EPA 

received a more complete version of the data set as part of the public comments submitted by 

Hoosier Energy (see Section 12.1.7). A total of 15 data sets were entirely excluded from the 

loadings analysis and the sensitivity analysis. 

Also, similar to the Duke Energy data described in Section 12.1.6, nine data sets consist of 

samples collected prior to mixing or comingling with any other wastestream or other waters and 

were allowed to settle in an attempt to simulate treatment from a surface water impoundment. 

Samples from these data sets were collected prior to settling either directly from the discharge 

pipe,(eight data sets) or after the dewatering bin (one data set). Because the samples from these data 

sets were collected before commingling and settling in the impoundment, EPA determined that the 

data were not wholly representative of ash impoundment discharges.116 These data were instead 

used in a sensitivity analysis. The result of this sensitivity analysis is discussed further in Section 

12.4.2. 

Where data were confirmed to represent ash impoundment effluent samples and the ash 

contribution was at least 75 percent of the contribution by volume to the impoundment (six data 

 

115 EPA’s request for additional information was made on December 30, 2013. In that request, EPA reminded UWAG 

that the Agency is operating with a deadline for taking final action on the Steam Electric ELGs and thus requested a 

response to specific questions no later than January 24, 2014 [U.S. EPA, 2013]. UWAG’s response to EPA’s request for 

additional information was not received until August 4, 2014, more than six months after the deadline. Although data

was received well after the deadline, EPA was able to fully take these data into account for the analyses and evaluated 

the data submitted by UWAG against the acceptance criteria listed in Table 12-1. 

116 UWAG presented a comparison of settled sluice pipe samples to near-effluent discharge point samples at each of the 

six plants sampled as part of the November 2014 submission. UWAG acknowledged that “whether viewed from the 

individual facility perspective or as averaged across the six facilities, it is clear that the settled bottom ash sluice pipe 

samples substantially overestimate bottom ash effluent pollutant loadings” [UWAG, 2014b]. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-12 

sets), EPA included these data in the ash impoundment concentrations data setand further reviewed 

the data against the acceptance criteria. 

12.1.8.2 November 2014 Bottom Ash Transport Water Data 

At UWAG’s request, on September 10, 2014, EPA met with representatives from UWAG to 

discuss the use of the bottom ash transport water data submitted by UWAG in public comments. 

During this meeting, UWAG indicated that it had collected additional bottom ash transport 

characterization data. EPA stated that no further data were needed for EPA’s evaluation of bottom 

ash transport water [U.S. EPA, 2014]. 

On November 25, 2014, more than two months following the meeting with EPA on 

September 10, 2014, UWAG submitted additional bottom ash transport water data and asked EPA 

to consider it for the final Steam Electric ELGs [UWAG, 2014b].117 The late data included bottom 

ash transport water characterization data collected from six steam electric power plants. UWAG 

provided plant information sheets containing background and operational data regarding each of the 

plants sampled, analytical laboratory and quality control documentation for each sample, and the 

results of UWAG’s analysis of the results. 

By November 25, 2014, EPA had already completed analysis of available ash 

characterization data for use in the rulemaking, completed development of the Steam Electric 

Analytical Database [ERG, 2015a], and finalized the ash loadings model used to generate pollutant 

loadings estimates. Therefore, EPA did not incorporate UWAG’s November 2014 data into the 

official loadings analysis and other related analyses (e.g., the Ash Data Review Matrix, the POC 

analysis). However, EPA did conduct a sensitivity analysis of the late data that were known to meet 

EPA’s acceptance criteria, as described further in Section 12.4.3. 

12.2 LOADINGS CALCULATION METHODOLOGY

EPA estimated ash loadings for all pollutants defined as a POC for fly ash transport water or 

bottom ash transport water [ERG, 2015d], or that were identified as constituents of combined ash 

impoundments. Generally, loadings for each pollutant are calculated by multiplying a pollutant 

concentration by an associated flow rate for the wastewater, according to Equation 12-1. 

(12-1) 

Load (lb/year) = Flow Rate × Concentration × 2.205 lb / 1,000,000 mg × 

3.785 L/gal × 365 days/year

where: 

Flow Rate = The normalized flow rate of the wastewater in 

gallons/day. 

 

117 These data were received 10 months after the January 2014 deadline established by EPA’s December 30, 2013 letter. 

This was 14 months after the September 2013 close of the comment period for the proposed rule (more than 17 months 

after EPA publicly released a pre-publication version of the Federal Register notice for the proposed rule, soliciting 

additional pollutant characterization data). 
Section 12 – Ash Transport Water Pollutant Loadings 

12-13 

Concentration = The average concentration of a specific pollutant in the

wastewater in milligrams per liter (mg/L). 

Therefore, to calculate the ash loadings, EPA developed a methodology to determine the 

appropriate concentrations to use for each pollutant for each type of impoundment system and also 

developed a methodology to identify the flow rates associated with the wastewater. The following 

sections present the methodologies EPA used to calculate the ash loadings for the steam electric 

power generating industry. 

12.2.1 Impoundment Type Pollutant Concentration Methodology 

EPA used the concentration data obtained from the data sources described in Section 12.1 to 

calculate the average pollutant concentrations in fly ash impoundment effluent, bottom ash 

impoundment effluent, and combined ash impoundment effluent. EPA notes that, because the data 

associated with these impoundments may include other wastestreams (e.g., cooling water), the 

concentrations may be diluted and therefore may underestimate the baseline pollutant loadings and 

underestimate the post-compliance pollutant reductions.118 EPA first calculated the average 

pollutant concentrations for each plant and then calculated an average across all plants, using the 

following steps: 

• Construct a plant-specific data set, comprising all acceptable ash impoundment 

effluent data for that plant, regardless of the data source. 

• Identify the type of impoundment system the data represents (i.e., fly ash 

impoundment, bottom ash impoundment, combined ash impoundment). 

• For each type of ash impoundment at a plant, average the effluent concentrations by 

pollutant for each day of sampling for any pollutant detected at least once above the 

quantitation limit (QL). Values reported as non-detects were treated as equal to onehalf the QL or detection limit (DL), depending on the value reported.119

• For each type of ash impoundment at a plant, calculate the average effluent 

concentration by pollutant over all days of samples. 

After calculating a plant-specific average concentration for each type of impoundment, EPA 

calculated an industry average concentration for each pollutant for each type of impoundment. For 

example, EPA calculated an industry average pollutant concentration for a fly ash impoundment 

effluent by calculating the average concentration across all fly ash impoundments for which EPA 

had data, using the average plant-specific fly ash impoundment effluent pollutant concentrations 

 

118 Because this approach may underestimate the actual pollutant concentrations for the impoundment effluent if there

was no dilution, the baseline pollutant loadings would be underestimated and result in underestimating the pollutant 

removals that would be attained by the technology option considered for the rule. 

119 Fly ash and bottom ash transport water data include qualified results where there are insufficient data available to 

determine the respective sample-specific QL. In these instances the observation is reported as a “less than” result along 

with a value, but EPA does not know whether the reported value is the sample-specific DL or QL. For the purpose of 

estimating pollutant loadings and removals, EPA assumed the reported value is the QL and used one-half that value in 

the calculations. In cases where a QL value was not available, EPA used the DL. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-14 

calculated above. Table 12-2, Table 12-3, and Table 12-4 present a list of the POCs and the average 

effluent concentrations calculated for fly ash, bottom ash, and combined ash wastewater, 

respectively. 

12.2.2 Baseline Flow Rate Methodology 

EPA used information from the Steam Electric Survey and industry-submitted data to 

identify the population of plants that have steam electric generating units that use wet sluicing for 

fly ash or bottom ash handling and reported transferring fly ash, bottom ash, or combined ash 

transport water to impoundments that discharged to surface waters or POTWs in 2009. Section 4.1.2 

describes the methodology EPA used to develop the “Ash Transport Water Input Table,” which 

contains the generating unit-level flow rates by impoundment ash type used to estimate the fly ash 

and bottom ash pollutant loadings [ERG, 2015c]. 

EPA used the “CCR Input Table,” discussed in Section 4.3.3, to adjust the population of 

plants discharging fly ash or bottom ash transport water to account for the implementation of the 

final Coal Combustion Residuals (CCR) rule. A copy of the “CCR Input Table” is included in the 

Ash Loadings Database [ERG, 2015c]. 

For the calculation of the baseline loadings, EPA calculated loadings associated with the 

normalized ash transport water flow rates for all generating units that are not expected to 

retire/convert to dry ash handling by December 31, 2023 or convert to dry ash handling due to the 

CCR rule. 

12.2.3 Regulatory Option Flow Rate Methodology 

EPA evaluated several regulatory options for this industry that affected the generating unit 

population subject to the final rule. EPA applied different effluent limitations to oil-fired generating 

units and units with a specific steam electric power generating capacity. EPA evaluated technology 

option pollutant loadings for the following populations: 

• All oil-fired generating units and generating units less than or equal to 50 MW will 

not face more stringent requirements than already existed under preexisting 

regulations for fly ash and bottom ash transport water. 

• All oil-fired generating units and generating units less than or equal to 50 MW will 

not face more stringent requirements than already existed under preexisting 

regulations for fly ash and bottom ash transport water, and generating units less than 

or equal to 400 MW will not face more stringent requirements than already existed 

under preexisting regulations for bottom ash transport water. 

To calculate the fly ash transport water and bottom ash transport water portion of the 

regulatory option loadings, EPA calculated loadings associated with the normalized ash transport 

water flow rates for only the generating units that will not face more stringent requirements than 

already existed under preexisting regulations (i.e., those generating units that will continue wet 

sluicing ash). For example, if a plant currently has four generating units with wet fly ash handling, 

but two of the generating units are less than 50 MW, then EPA used the normalized fly ash transport 

water flow rates for the two generating units that are less than 50 MW to calculate ash loadings 
Section 12 – Ash Transport Water Pollutant Loadings 

12-15 

associated with that regulatory option. For those generating units that would need to comply with a 

zero discharge pollutant requirement, post-compliance pollutant loadings are zero. 

After identifying all the generating units that would not be subject to a specific regulatory 

option and calculating the reduced flow rate for these options, EPA developed a separate “ash flow 

input table” to reflect the revised flow rates for each regulatory option used in the ash loadings 

calculations. 

12.2.4 Ash Loadings Calculation 

Using the impoundment ash type flag, EPA multiplied the average concentrations for the 

specific impoundment type by the normalized daily flow rates included in the “Ash Transport Water 

Input Table” for the appropriate ash streams. For example, for each generating unit for which EPA 

calculates ash loadings, the normalized daily fly ash transport water flow rate for that generating 

unit was multiplied by the calculated average fly ash impoundment concentration data to calculate a 

discharge fly ash loading associated with each pollutant at the plant. EPA used Equation 12-2 to 

calculate the generating unit-level ash loadings associated with fly ash transport water to surface 

waters. 

(12-2) 

FA Unit-Level Load (lb/year) = FA Unit-Level Flow Rate (gpd) × 

FA Concentration (mg/L) × 2.205 lb / 1,000,000 mg × 3.785 L/gal × 365 Days (dpy)

where: 

FA Unit-Level Flow Rate 

(gpd) 

= The normalized generating unit-level fly ash transport 

water flow rate in gallons/day. 

FA Concentration (mg/L) = The average concentration of a specific pollutant in the 

overflow from a fly ash impoundment in mg/L, based on 

the data sources described in Sections 12.1 and 12.2.1. 

EPA used the same equation to calculate the ash loadings for bottom ash impoundments. In 

the case of combined ash impoundments, EPA first summed the fly ash and bottom ash generating 

unit-level normalized flows for all generating units contributing to the combined ash impoundment. 

This “combined ash” flow was used in the equation along with the combined ash impoundment 

effluent concentration data set to calculate combined ash loadings. For those generating units 

transferring the wastewater to a POTW, EPA adjusted the loadings to account for additional 

removals that would take place at the POTW, according to Equation 12-3. EPA identified four 

plants transferring bottom ash to a POTW and no plants transferring fly ash or combined ash to a 

POTW. A list of POTW removals is included in Appendix B. 

(12-3) 

Indirect Pollutant Loading (lb/year) = Pollutant Loading × (1 - POTW Removal)
Section 12 – Ash Transport Water Pollutant Loadings 

12-16 

where: 

Pollutant Loading = The calculated baseline or post-compliance loadings from 

a specific pollutant, in pounds/year. 

POTW Removal = The estimated percentage of the pollutant loading that 

will be removed by a POTW. 

EPA calculates the ash loadings based on the influent impoundment sluice rate, adjusted for 

any potential recycling that occurs at the plant (as described in Section 4.1.2). Additionally, the 

calculation multiplies the ash impoundment overflow concentrations, which have likely been 

diluted by other wastestreams entering the impoundment (e.g., rainfall, stormwater, cooling water, 

low-volume wastes), by only the flow rate associated with the ash transport water stream and not 

the total ash impoundment effluent flow rate, which may result in underestimating the pollutant 

loadings associated with ash impoundment discharges but ensures the loadings represent ash 

transport water. 

12.2.5 Breakout of Combined Ash Loadings 

Because the loadings associated with the combined ash represents the combined discharge 

of fly ash transport water and bottom ash transport water, EPA used data from the EPRI PISCES 

reports to estimate the breakout of the loadings among fly ash and bottom ash contributions. The 

Site A, B, C, and D EPRI PISCES reports include a table that presents the loadings to the ash 

impoundments in kilograms per day (kg/day) for each wastewater stream that is entering the 

impoundment for several metal pollutants. Based on this information, EPA used the loadings from 

the fly ash and bottom ash transport water wastestreams in the EPRI PISCES reports to break out 

the calculated combined ash loadings into fly ash loadings and bottom ash loadings. 

To perform this calculation, EPA first reviewed the information regarding the plants to 

determine whether the data were appropriate for use in the analysis. EPA made the following 

conclusions based on this review: 

• Site A was excluded from this analysis of combined ash loadings because the fly ash 

transport water is transferred to the ash impoundment only during occasional 

operation; therefore, the fly ash transport water loadings compared to the bottom ash 

transport water loadings were not representative of the operations at a typical plant 

with both wet fly and bottom ash sluicing. 

• Site B was included in the analysis as it consists of both fly and bottom ash transport 

water transferred to the ash impoundment. 

• Site C was included in the analysis as it consists of both fly and bottom ash transport 

water transferred to the ash impoundment. 

• Site D has two separate plants at the site (i.e., Plants A and B). Plant A has wet fly 

ash and bottom ash handling for all six generating units and Plant B has wet bottom 

ash for two generating units, but wet fly ash for only one of the two generating units; 

therefore, only Plant A fly ash and bottom ash loadings were included in the 

analysis. Plant B loadings were excluded. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-17 

EPA used the fly ash transport water and bottom ash transport water loadings presented in 

the EPRI PISCES reports for the sites described above to calculate a site-specific percent loading 

for fly ash and bottom ash for each pollutant. For each site and available pollutant, EPA calculated 

the percent of the pollutant loading associated with fly ash and bottom ash relative to the total ash 

loading. For this calculation, EPA included only the fly ash and bottom ash transport water 

loadings, even though EPRI included all wastewater sources entering the impoundment, because 

EPA is evaluating only the combined fly ash and bottom ash transport waters and is not considering 

other wastewater sources. EPA performed this calculation for each pollutant available for each of 

the three sites and calculated an average percent loading for fly ash and bottom ash for each of the 

twelve pollutants using the percentage calculated for each of the three sites. 

EPA then calculated an overall average percent loading for fly ash transport water and 

bottom ash transport water for each pollutant using the site-specific percentages. Because EPA did 

not have data available to calculate an average percent loading for fly ash and bottom ash transport 

water for all pollutants in the combined ash impoundment data set, EPA calculated the average 

percent loading for fly ash and bottom ash based transport water on the pollutants available, 85.9 

and 14.1 percent, respectively, and used this value for the allocate the loading for all other 

pollutants. Therefore, EPA assumed fly ash transport water and bottom ash transport water account 

for 85.9 and 14.1 percent, respectively, of all combined ash loadings for those pollutants for which 

an analyte-specific value could not be calculated using the EPRI data. These average percent 

loadings for fly ash and bottom ash are presented in Table 12-5 for each pollutant available. See the 

“Break Out of Combined Ash Loadings Methodology Memorandum” [ERG, 2015e] for more 

details on this calculation. 

12.3 POLLUTANT LOADINGS AND TWPE RESULTS

In addition to expressing plant-level pollutant loadings in pounds of pollutant discharged per 

year (described in Section 12.2), EPA used toxic weighting factors (TWFs) to account for 

differences in toxicity across pollutants in ash wastewater.120 EPA calculated a TWPE according to 

Equation 12-4 for each pollutant to compare mass loadings between different pollutants based on 

their toxicity. 

(12-4) 

Pollutant-Specific TWPE = Pollutant-Specific Loading × Pollutant-Specific TWF 

EPA also calculated plant-level TWPE by summing the pollutant-specific TWPE. Using the 

plant-level mass and TWPE loadings, EPA was then able to calculate the baseline and postcompliance loadings at the industry level for each regulatory option. The plant-level mass loadings 

and TWPE loadings are presented in Appendix B. Table 12-6 presents the results of the ash 

loadings calculation for fly ash and bottom ash transport water, for both baseline and the dry 

handling technology options. The table summarizes the industry-level loadings and pollutant 

reductions in pounds/year and TWPE/year. 

 

120 A listing of pollutant-specific TWF values can be found in the Review of Toxic Weighting Factors in Support of the 

Final Steam Electric Effluent Limitations Guidelines and Standards [ERG, 2015g]. EPA has developed TWFs for more 

than 1,900 pollutants based on aquatic life and human health toxicity data, as well as physical/chemical property data.
Section 12 – Ash Transport Water Pollutant Loadings 

12-18 

The pollutant loadings and removals in Table 12-6 include all POCs except biochemical 

oxygen demand (BOD), chemical oxygen demand (COD), total suspended solids (TSS), total 

dissolved solids (TDS), as well as sulfide. BOD, COD, TSS, and TDS are pollutant parameters that 

essentially double-count pollutant-specific loadings. 

EPA calculated the pollutant removals by subtracting the technology option loadings from 

the baseline loadings. The plant-level loadings can be found in Appendix B. 

The pollutant loadings presented in Table 12-6 are based on oil-fired generating units and 

those generating units with a generating capacity of 50 MW or less not installing the technology 

basis because they are not facing any more stringent requirements than already existed under the 

previously established regulations. Section 15 of this report discusses the use of the ash wastewater 

pollutant loadings and estimated pollutant loadings for other regulated wastestreams to evaluate the 

regulatory options considered by EPA. 

12.4 SENSITIVITY ANALYSES

 Sections 12.1 through 12.3 describe EPA’s methodology for estimating pollutant loadings 

and removals associated with the final rule. In addition to these technology options, EPA also 

conducted smaller scale sensitivity analyses related to inclusion of additional concentration data sets 

to determine how small changes to the analytical database would affect the overall industry-level 

pollutant loadings. EPA conducted the following three sensitivity analyses related to ash transport 

water pollutant loadings: 

1. Analysis to evaluate pollutant loadings associated with inclusion of sulfide in the 

loadings calculations. 

2. Analysis to evaluate pollutant loadings associated with including settled bottom ash 

transport water concentration data. 

3. Analysis to evaluate pollutant loadings associated with including bottom ash 

transport water data submitted well beyond the close of the public comment period. 

EPA conducted these sensitivity analyses on a previous version of the pollutant load 

estimates. EPA recalculated the industry loadings for fly ash transport water and bottom ash 

transport water for the final rule and determined that the difference between the final industry 

baseline loadings and the previous version of the pollutant loadings estimates is less than 1 percent 

in terms of pounds per year. Because the magnitude of this revision to the baseline loadings is very 

small and the sensitivity analyses also show little change in pollutant loadings/removals, EPA 

concluded that it was not necessary to update the sensitivity analyses with the revised baseline 

loadings because they would still show that there would be little change in the pounds of pollutants 

in the baseline loadings or removals. The following section describes the three sensitivity analysis 

conducted by EPA related to ash pollutant loadings. 

12.4.1 Sulfide Sensitivity Analysis 

During the public comment period, EPA received comments from industry asserting that 

sulfides should not be considered a POC for ash transport waters. As such, EPA also conducted 

sensitivity analyses based on the inclusion or exclusion of sulfide as a POC for fly ash transport 
Section 12 – Ash Transport Water Pollutant Loadings 

12-19 

water and bottom ash transport water. EPA’s POC analysis, described in Section 12.2, determined 

that sulfide is not a POC for fly ash or bottom ash transport water; therefore, EPA did not calculate 

loadings for sulfide from fly ash impoundment effluent or bottom ash impoundment effluent in any 

analyses. Sulfide was detected in samples representing combined ash impoundment effluent so EPA 

did calculate loadings for this constituent from combined ash impoundment effluent for this 

sensitivity analysis. The results of this sensitivity analysis are presented in Table 12-7. 

12.4.2 Settled Bottom Ash Sluice Sensitivity Analysis 

As described in Section 12.1, EPA identified certain data sets whose quality did not meet or 

could not be confirmed for use in the loadings analysis. These data were representative of ash 

transport water collected prior to commingling with other wastestreams or waters and allowed to 

settle for at least one hour before collection of the supernatant. EPA determined that these data were 

not sufficiently representative of ash impoundment effluent.121 EPA used these data sets supplied by 

Duke Energy and UWAG, in combination with the data sets accepted for use in the loadings 

calculations, in a sensitivity analysis, as shown in Table 12-7. 

The sensitivity analysis shows that the inclusion (or exclusion) of the settled ash transport 

water data sets has no impact on fly ash transport water loadings and a minor impact on the bottom 

ash transport water loadings in terms of total pounds per year. Inclusion of the settled ash transport 

water samples results in the industry baseline loadings for bottom ash transport water increasing by 

4 percent in terms of pounds per year. The average effluent concentrations for fly ash, bottom ash, 

and combined ash impoundments calculated as part of these sensitivity analyses are presented in 

Appendix B. 

12.4.3 Inclusion of Data Submitted Late 

As described in Section 12.1.8.2, UWAG provided EPA with a late submission of 

supplemental bottom ash transport water characterization data. UWAG’s late data was not sent to 

EPA until November 2014, and due to the additional time that would have been needed to fully 

evaluate the late data and revise the pollutant removal analyses and other related analyses for the 

ELGs (e.g., environmental assessments), the late data could not be fully incorporated into the 

loadings analyses. Nevertheless, EPA was able to conduct an abbreviated evaluation of the late data 

to determine the effect the late data could have on the loadings analyses. The sensitivity analysis 

performed on these data, which included bottom ash transport data from three122 of the six plants in 

UWAG’s November 2014 data set, is discussed further in the memorandum “Use of UWAG 

Bottom Ash Transport Water Data” [ERG, 2015h]. 

The results of this analysis are presented in Table 12-8. Table 12-8 illustrates the impact of 

the inclusion of these late submission data on the total industry loadings at baseline. The average 

 

121 UWAG presented a comparison of settled sluice pipe samples to near-effluent discharge point samples at each of the 

six plants sampled as part of the November 2014 submission. UWAG acknowledged that “whether viewed from the 

individual facility perspective or as averaged across the six facilities, it is clear that the settled bottom ash sluice pipe 

samples substantially overestimate bottom ash effluent pollutant loadings” [UWAG, 2014b]. 

122 EPA used data from Kammer, Kyger Creek Station, and Frank E. Ratts Generating Station. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-20 

effluent concentrations for bottom ash impoundments calculated as part of this sensitivity analysis 

are presented in Appendix B. 

The sensitivity analysis demonstrates that including UWAG’s November 2014 data would 

have little impact on both the unweighted (pounds/year) pollutant loadings/removal estimates and 

other related analyses. Including the subset of the November 2014 data decreased the estimated 

unweighted pollutant loadings for bottom ash transport water by approximately 2 percent. Because 

of the very small impact on bottom ash transport water loadings associated with this sample of late 

data, EPA concluded that the late data would not have a significant impact on the overall loadings, 

pollutant removal estimates, and related analyses for purposes of the final steam electric ELGs. 

12.5 REFERENCES

1. Duke Energy. 2013. Duke Energy. Comments of Duke Energy on Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category. 

(7 June) EPA-HQ-OW-2009-0819-4305. 

2. Duke Energy. 2014. Duke Energy. Duke Energy Response to EPA Data Request. (4 

December and 28 March). DCN SE04331 and SE04360. 

3. ERG. 2015a. Eastern Research Group, Inc. Analytical Database for Final Rule. (30 

September). DCN SE05359. 

4. ERG. 2015b. Eastern Research Group, Inc. “Ash Analytical Data Review Memorandum.” 

(30 September). DCN SE05567. 

5. ERG. 2015c. Eastern Research Group, Inc. Ash Loadings Model, Accounting for CCR. (30 

September). DCN SE05584. 

6. ERG. 2015d. Eastern Research Group, Inc. “Bottom Ash and Fly Ash Transport Water 

Pollutants of Concern (POC) Analysis Methodology” (30 September). DCN SE04745. 

7. ERG. 2015e. Eastern Research Group, Inc. “Break Out of Combined Ash Loadings 

Methodology Memorandum.” (30 September). DCN SE05586. 

8. ERG. 2015f. Eastern Research Group, Inc. “Development Memorandum for the Steam 

Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876. 

9. ERG. 2015g. Eastern Research Group, Inc. “Review of Toxic Weighting Factors in Support 

of the Final Steam Electric Effluent Limitations Guidelines and Standards.” (30 September). 

DCN SE04479. 

10. ERG. 2015h. Eastern Research Group, Inc. “Use of UWAG Bottom Ash Transport Water 

Data.” (30 September). DCN SE05581. 

11. ERG. 2015i. Eastern Research Group, Inc. Steam Electric Technical Questionnaire Database 

(“Steam Electric Survey”). (30 September). DCN SE05903. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-21 

12. ERG. 2015j. Eastern Research Group, Inc. Ash Data Review Matrix. (30 September). DCN 

SE05575. 

13. ERG. 2015k. Eastern Research Group, Inc. “Draft Ash Loadings Model, Accouting for CCR 

– Settled Ash Transport Water Sensitivity Analysis.” (30 September). DCN SE05624. 

14. ERG. 2015l. Eastern Research Group, Inc. “Draft Ash Loadings Model, Accouting for CCR 

– UWAG Late Submission Sensitivity Analysis.” (30 September). DCN SE05625. 

15. ERG. 2015m. Eastern Research Group, Inc. “Final Ash Loadings Model, Accounting for 

CCR.” (30 September). DCN SE05584. 

16. ERG. 2015n. Eastern Research Group, Inc. “Draft Ash Loadings Model, Accounting for 

CCR – Sensitivity Analysis Comparison.” (30 September). DCN SE06418. 

17. EPRI. 1997 - 2001. Electric Power Research Institute. PISCES Water Characterization 

Field Study, Sites A-G. Palo Alto, CA. DCNs SE01818-01823. 

18. EPRI. 2006. Electric Power Research Institute. Mitigation of SCR-Ammonia Related 

Aqueous Effects in a Fly Ash Impoundment: Algal Enhancement and Water Chemistry. Palo 

Alto, CA. DCN SE04742. 

19. Hoosier Energy. 2013. Hoosier Energy Rural Electric Cooperative. Comments of Hoosier 

Energy on Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category. (20 September). EPA-HQ-OW-2009-0819-4471. 

20. Hoosier Energy. 2014. Hoosier Energy Rural Electric Cooperative. Hoosier response to 

Post Proposal Information Request. (11 and 14 April). DCN SE04701-04702.

21. Interstate. 2004. Interstate Power and Light Co. Bottom Ash Wastewater Evaluation: 

Interstate Power and Light Co. – Dubuque Generating Station. Madison, WI. (June). DCN 

SE02279. 

22. U.S. EPA. 1982. U.S. Environmental Protection Agency. Development Document for 

Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam 

Electric Point Source Category. EPA-440-1-82-029. Washington, DC. (November). 

23. U.S. EPA 2000. U.S. Environmental Protection Agency. Development Document for 

Effluent Limitations Guidelines and Standards for the Centralized Waste Treatment 

Industry. EPA-821-R-00-020. Washington, DC (August). Available online at 

http://water.epa.gov/scitech/wastetech/guide/cwt/upload/CWT_DD_2000.pdf 

24. U.S. EPA. 2009. U.S. Environmental Protection Agency. Steam Electric Power Generating 

Point Source Category: Final Detailed Study Report. EPA 821-R-09-008. Washington, DC. 

(October). Available online at: 

http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upload/2009_10_26_guide_steam

_finalreport.pdf. DCN SE00003. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-22 

25. U.S. EPA. 2010. U.S. Environmental Protection Agency. Questionnaire for the Steam 

Electric Power Generating Effluent Guidelines. OMB Approval Number: 2040-0281. 

Washington, DC. (2 June). DCN SE00402-SE00402A09. 

26. U.S. EPA. 2013. U.S. Environmental Protection Agency. Post Proposal Data Request to 

UWAG – Bottom Ash Data Submitted in Public Comment. (December 30). DCN SE04711. 

27. U.S. EPA. 2014. U.S. Environmental Protection Agency. Meeting Notes for the Steam 

Electric Rulemaking Record, September 10, 2014 Meeting with Utility Water Act Group 

(UWAG) Regarding Proposed Steam Electric ELGS. (September 10). DCN SE05578. 

28. UWAG. 2008. Utility Water Act Group. UWAG Form 2C Effluent Guidelines Database. 

(30 June). DCNs SE02918 and SE02918A1. 

29. UWAG. 2013a. Utility Water Act Group. Comments on EPA’s Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category. (7 June). EPA-HQ-OW-2009-0819-4655. 

30. UWAG. 2013b. Utility Water Act Group. UWAG Bottom Ash Transport Water Sampling 

Protocol. (2013). DCN SE04360A22. 

31. UWAG. 2014a. Utility Water Act Group. UWAG Response to Post Proposal Information 

Request. (1 August). DCN SE04717. 

32. UWAG. 2014b. Utility Water Act Group. Additional Bottom ash Transport Water Data. (25 

November). DCN SE05597. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-23 

Table 12-1. Ash Data Acceptance Criteria 

POC Analysis Criteria

(Ash Transport Water Data Without 

Paired Source Water Data)

POC Analysis Criteria

(Paired Source Water & 

Ash Transport Water Data)

• Sample locations must be unambiguous and 

clearly described such that it can be categorized 

by type (e.g., bottom ash impoundment effluent 

rather than impoundment effluent with no 

further definition) and level of treatment (e.g., 

untreated, partially treated). 

• Sample must comprise at least 75% by volume 

ash transport water. 

• Sample location must not represent combined 

fly ash transport water and bottom ash transport 

water. 

• Analytical data must represent individual 

sample results or plant-level average sample 

concentrations rather than average results 

representing multiple plants. 

• For biphasic samples (i.e., those with solids 

content >1%), sample analysis must provide 

results for both phases. 

• Data must not be from an ash settling test 

conducted in a column (i.e., a simulated sample 

of partially treated wastewater). 

• Sample must be representative of full-scale, 

typical plant operations. 

• Sample analysis must be completed using 

accepted analytical methods. a

• Data must not be duplicative of other accepted 

data. b 

• Sample data must provide sufficient information 

to identify units. 

• Sample locations must be unambiguous and 

clearly described such that it can be categorized 

by type (e.g., bottom ash impoundment effluent 

rather than impoundment effluent with no 

further definition) and level of treatment (e.g., 

untreated, partially treated). 

• Sample must comprise at least 75% by volume 

ash transport water. 

• Sample location must not represent combined 

fly ash transport water and bottom ash transport 

water. 

• Analytical data must represent individual 

sample results or plant-level average sample 

concentrations rather than average results 

representing multiple plants. 

• Data must contain source water data paired with 

fly ash or bottom ash transport water. 

• Paired source water data must be collected 

within one day of fly ash or bottom ash 

transport water sample collection. 

• For biphasic samples (i.e., those with solids 

content >1%), sample analysis must provide 

results for both phases. 

• Data must not be from an ash settling test 

conducted in a column (i.e., a simulated sample 

of partially treated wastewater). 

• Sample must be representative of full-scale, 

typical plant operations. 

• Sample analysis must be completed using 

accepted analytical methods. a

• Data must not be duplicative of other accepted 

data. b 

• Sample data must provide sufficient information 

to identify units. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-24 

Table 12-1. Ash Data Acceptance Criteria 

Ash Loadings Analysis 

(Excludes Sensitivity Analysis Data)

Ash Loadings Sensitivity Analysis

(Includes Simulated Effluent Data)

• Sample locations must be unambiguous and 

clearly described such that it can be categorized 

by type (e.g., bottom ash impoundment effluent 

rather than impoundment effluent with no 

further definition) and level of treatment (e.g., 

untreated, partially treated). 

• Sample must comprise at least 75% by volume 

ash transport water. 

• Sample must be representative of actual ash 

impoundment effluent (not simulated effluent). 

• Analytical data must represent individual 

sample results or plant-level average sample 

concentrations rather than average results 

representing multiple plants. 

• For biphasic samples (i.e., those with solids 

content >1%), sample analysis must provide 

results for both phases. 

• Data must not be from an ash settling test 

conducted in a column (i.e., a simulated sample 

of partially treated wastewater). 

• Sample must be representative of full-scale, 

typical plant operations. 

• Sample analysis must be completed using 

accepted analytical methods. a 

• Data must not be duplicative of other accepted 

data. b

• Sample data must provide sufficient information 

to identify units. 

• Non-detect results were not accepted if no limit 

(e.g., DL, QL) was provided. 

• Sample results must represent total (i.e., 

dissolved results were not accepted except for 

TDS). 

• Sample locations must be unambiguous and 

clearly described such that it can be categorized 

by type (e.g., bottom ash impoundment effluent 

rather than impoundment effluent with no 

further definition) and level of treatment (e.g., 

untreated, partially treated). 

• Sample must comprise at least 75% by volume 

ash transport water.Sample must be 

representative of treated wastewater; this 

includes actual ash impoundment effluent or 

simulated effluent. 

• Analytical data must represent individual 

sample results or plant-level average sample 

concentrations rather than average results 

representing multiple plants. 

• For biphasic samples (i.e., those with solids 

content >1%), sample analysis must provide 

results for both phases. 

• Data must not be from an ash settling test 

conducted in a column (i.e., a simulated sample 

of partially treated wastewater). 

• Sample must be representative of full-scale, 

typical plant operations. 

• Sample analysis must be completed using 

accepted analytical methods. a

• Data must not be duplicative of other accepted 

data. b 

• Sample data must provide sufficient information 

to identify units. 

• Non-detect results were not accepted if no limit 

(e.g., DL, QL) was provided. 

• Sample results must represent total (i.e., 

dissolved results were not accepted except for 

TDS). 

a – See “Ash Data Review Matrix” for a list of accepted analytical methods [ERG, 2015j]. 

b – Duplicative data were submitted by associations representing individual plants (e.g., UWAG). In such cases, EPA 

only accepted data submitted by the individual plant and rejected the duplicative data provided by the association. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-25 

Table 12-2. Average Effluent Concentration of Fly Ash Impoundments 

Analyte Unit Average Concentration

Aluminum ug/L 2,230 

Arsenic ug/L 36.4

Barium ug/L 121

Beryllium ug/L 3.42 

Boron ug/L 6,630 

Cadmium ug/L 7.63

Calcium ug/L 99,300

Chloride ug/L 12,800

Chromium ug/L 27.4

Cobalt ug/L 5.67 

Copper ug/L 68.8

Fluoride ug/L 276

Iron ug/L 855

Lead ug/L 13.7

Magnesium ug/L 13,600

Manganese ug/L 144

Mercury ug/L 0.828

Molybdenum ug/L 483

Nickel ug/L 30.5

Nitrate-Nitrite as N ug/L 2,360 

Nitrogen, Total Kjeldahl ug/L 4,080

Phosphorus, Total ug/L 71.8 

Potassium ug/L 8,460

Selenium ug/L 15.4

Silica ug/L 8,570

Sodium ug/L 34,000

Strontium ug/L 429

Sulfate ug/L 409,000

Thallium ug/L 10.3 

Titanium ug/L 4.83 

TDS ug/L 469,000

TSS ug/L 10,400

Zinc ug/L 226

Source: ERG, 2015m 

Note: Concentrations are rounded to three significant figures. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-26 

Table 12-3. Average Effluent Concentration of Bottom Ash Impoundments 

Analyte Unit Average Concentration

Aluminum ug/L 1,240

Antimony ug/L 28.2 

Arsenic ug/L 17.4

Barium ug/L 110 

Boron ug/L 541

Bromide ug/L 620 

Cadmium ug/L 2.19

Calcium ug/L 68,800

COD ug/L 20,800

Chloride ug/L 28,100

Chromium ug/L 5.59

Cobalt ug/L 14.5 

Copper ug/L 13.9

Iron ug/L 1,420

Lead ug/L 12.1

Magnesium ug/L 34,500

Manganese ug/L 1,440

Mercury ug/L 0.634

Molybdenum ug/L 29.7

Nickel ug/L 16.5

Nitrate-Nitrite as N ug/L 6,070

Nitrogen, Total Kjeldahl ug/L 1,160

Phosphorus, Total ug/L 204

Potassium ug/L 2,960

Selenium ug/L 11.7

Silica ug/L 6,300 

Sodium ug/L 53,000

Strontium ug/L 258

Sulfate ug/L 347,000

Sulfite ug/L 4,750 

Thallium ug/L 89.4 

Titanium ug/L 40.9 

TDS ug/L 754,000

TSS ug/L 19,700

Zinc ug/L 31.0

Source: ERG, 2015m 

Note: Concentrations are rounded to three significant figures. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-27 

Table 12-4. Average Effluent Concentration of Combined Ash Impoundments 

Analyte Unit Average Concentration

Aluminum ug/L 1,200

Antimony ug/L 24.6

Arsenic ug/L 50.3

Barium ug/L 188

Beryllium ug/L 3.86 

BOD ug/L 4,670

Boron ug/L 1,960 

Cadmium ug/L 1.42

Calcium ug/L 74,600

COD ug/L 26,000 

Chloride ug/L 16,300

Chromium ug/L 21.6

Chromium (VI) ug/L 0.671

Cobalt ug/L 6.00 

Copper ug/L 21.9

Cyanide, Total ug/L 5.28 

Fluoride ug/L 650

Iron ug/L 601

Lead ug/L 7.52

Magnesium ug/L 15,300

Manganese ug/L 67.5

Mercury ug/L 1.18

Molybdenum ug/L 142

Nickel ug/L 19.1

Nitrate-Nitrite as N ug/L 2,550

Nitrogen, Total Kjeldahl ug/L 891 

Phosphorus, Total ug/L 196

Potassium ug/L 12,900

Selenium ug/L 28.0

Silica ug/L 5,930

Silver ug/L 4.33 

Sodium ug/L 12,400

Sulfate ug/L 209,000

Sulfite ug/L 905 

Thallium ug/L 31.0 

Titanium ug/L 22.8 

TDS ug/L 266,000

TSS ug/L 15,300

Vanadium ug/L 56.4 
Section 12 – Ash Transport Water Pollutant Loadings 

12-28 

Table 12-4. Average Effluent Concentration of Combined Ash Impoundments 

Analyte Unit Average Concentration

Zinc ug/L 72.3

Source: ERG, 2015m 

Note: Concentrations are rounded to three significant figures. 

Table 12-5. Percent Loadings for Fly Ash and Bottom Ash in Combined 

Ash Surface Impoundments 

Analyte 

Percent Loadings Fly Ash

(%) 

Percent Loadings Bottom Ash

(%) 

Aluminum 92.5 7.5

Antimony 89.3 10.7

Arsenic 96.0 4.0

Beryllium 96.0 4.0

Calcium 77.7 22.3

Copper 79.6 20.4

Iron 76.4 23.6

Mercury 71.4 28.6

Nickel 77.7 22.3

Selenium 99.0 1.0

Zinc 90.3 9.7

TSS 84.6 15.4

Average 86.9 14.1

Source: ERG, 2015e. 
Section 12 – Ash Transport 

12-29 

Table 12-6. Industry-Level Loadings and Pollutant Removals Excluding BOD, COD, TSS, and TDS and 

Units and Units 50 MW or Less Not Installing Technology Basis

Option 

Pollutant Loadings Pollutant Rem

Load (lb/year) TWPE/year Load (lb/year) 

Fly Ash

Baseline 115,000,000 225,000 - Zero Discharge for Generating Units > 50 MW 1,490,000 2,880 113,000,000 

Bottom Ash

Baseline 354,000,000 509,000 - Zero Discharge for Generating Units > 400 MW 139,000,000 198,000 216,000,000 

 Zero Discharge for Generating Units > 50 MW 1,890,000 2,390 311,000,000 

Source: ERG, 2015m Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TSS and TDS. Note: Loadings are rounded to three significant figures. 
Section 12 – Ash Transport Water Pollutant Loadings 

12-30 

Table 12-7. Results of Ash Loadings Baseline Calculation Excluding BOD, COD, TSS, 

and TDS 

Type of Ash Impoundment 

Revised Industry Loading Sensitivity Analysis Loading a

Pounds/Year Pounds/Year

Including Sulfides

Fly Ash 115,000,000 115,000,000

Bottom Ash 354,000,000 368,000,000

TOTAL 469,000,000 483,000,000

Excluding Sulfides

Fly Ash 115,000,000 115,000,000

Bottom Ash 354,000,000 368,000,000

TOTAL 469,000,000 483,000,000

Source: ERG, 2015k; ERG, 2015n 

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TSS and TDS. 

Note: Loadings are rounded to three significant figures. 

Note: EPA completed these sensitivity analyses with a previous version of the ash analytical data set. Since 

completion of the sensitivity analysis, EPA recalculated industry loadings for fly ash transport water and bottom ash 

transport water and determined that they are less than 1 percent different in terms of pounds per year for both 

wastestreams. EPA determined that the revision was not significant enough to warrant reanalysis of and the results 

of the sensitivity analysis would be comparable to the analysis presented. 

a – Sensitivity analysis loadings include Duke Energy & UWAG settled ash transport water sample data in ash 

loadings calculations. 

Table 12-8. Sensitivity Analysis Results for Total Industry Loadings Based on Inclusion 

of Late Submission UWAG Data Excluding BOD, COD, TSS, and TDS 

Sensitivity Analysis 

Total Industry Baseline Loadings

Pounds/Year Percent Difference (%)

Bottom Ash Transport Water Baseline Loadings 354,000,000 NA

Inclusion of Late Submission UWAG Bottom Ash Data a 347,000,000 (1.93%)

Source: ERG, 2015l; ERG, 2015n 

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TSS, and TDS. 

Note: Loadings are rounded to three significant figures. 

Note: EPA completed this sensitivity analyses with a previous version of the ash analytical data set. Since the 

completion of this sensitivity analysis, EPA recalculated the industry loadings for fly ash transport water and bottom ash 

transport water and determined they are less than 1 percent different in terms of pounds per year for both waste streams. 

EPA determined that this 1 percent reduction in loadings, coupled with the approximately 2 percent change from 

inclusion of the late submission UWAG bottom ash data, was not significant enough to warrant reanalysis and the 

results of the sensitivity analysis would be comparable to the analysis presented. 

a – EPA included results from three plants from the November 2014 data set where EPA had previously confirmed 

those ash contributions are at least 75 percent of the contribution, by volume, to the impoundment.
Section 12 – Ash Transport 

12-31 

Figure 12-1. Decision Tree for the Analytical Ash Data 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-1 

13. COMBUSTION RESIDUAL LEACHATE POLLUTANT 

LOADINGS 

Loadings calculations require a pollutant-specific concentration and plant-specific 

discharge flow to determine mass loadings. EPA calculated pollutant loadings for the discharge 

of combustion residual leachate from both landfills and impoundments. EPA used a variety of 

data sources to generate the characterization data to represent the untreated combustion residual 

leachate. EPA also generated a separate set of characterization data to represent the effluent from 

a chemical precipitation system for the treatment of landfill leachate. Section 13.1 presents the 

data sources and characterization data for combustion residual leachate and Section 13.2 

discusses the flow rates used to calculate pollutant loadings. All tables referenced in this section 

are presented at the end of the section. 

13.1 WASTEWATER CHARACTERIZATION AND DATA SOURCES

EPA used data collected though the Questionnaire for the Steam Electric Power 

Generating Effluent Guidelines (Steam Electric Survey) to calculate average effluent 

concentrations for untreated combustion residual leachate from landfills/impoundments. As 

described in Section 9.1, EPA determined that if stringent limitations were placed on combustion 

residual leachate from impoundments, the plants operating those impoundments would recycle 

the leachate back to the impoundment from which it was collected rather than install the 

technology basis for the discharge requirements. As a result, EPA determined that the mass 

loading discharged associated with combustion residual leachate from impoundments would not 

be reduced as a result of the discharge limitations. By recycling the leachate back to the 

impoundment, the mass loadings will eventually be discharged from the impoundment outfall. 

Therefore, EPA determined the post-compliance loadings for combustion residual leachate from 

impoundments is equal to the baseline loading for combustion residual leachate from 

impoundments. For combustion residual leachate from landfills, EPA evaluated chemical 

precipitation as a treatment technology option. EPA calculated baseline loadings and postcompliance loadings for combustion residual leachate from landfills and impoundments; 

however, the post-compliance pollutant reductions for impoundments under all regulatory 

options are zero. 

EPA’s Steam Electric Survey required certain plants to collect and analyze samples of 

leachate from landfills and impoundments and report the results of these analyses in Part G 

(Leachate Sampling Data for Ponds/Impoundments and Landfills) of the Steam Electric Survey. 

EPA requested these plants to sample any untreated leachate collected from an on-site 

impoundment or landfill containing combustion residuals. EPA used these data to calculate a 

pollutant concentration data set for use in loadings calculations to characterize combustion 

residual leachate from impoundments and landfills. EPA used all data as provided by the plants 

in the Steam Electric Survey, except for the following: 

• For values reported as less than the quantitation limit, EPA assumed the 

concentration was equal to one-half the quantitation limit provided. 

• If the plant did not provide a quantitation limit, ERG assumed the concentration 

was equal to the method detection level (MDL). 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-2 

EPA compiled all untreated combustion residual leachate sampling data reported in the 

Steam Electric Survey from 26 landfills and 15 impoundments. After reviewing the available 

data to determine the subset that could be used to determine average effluent concentrations, 

EPA conducted an analysis on the untreated combustion residual leachate data to determine 

pollutants of concern (POCs). In the analysis, EPA reviewed characterization data for the 

combustion residual leachate to identify which pollutants were present in the wastewater and 

whether those pollutants were present in the wastewater at a sufficient concentration and 

frequency to be considered treatable. The detailed results of the POC analysis is included in 

“Supplemental Costs and Loadings Documentation” [ERG, 2015d; see Appendix 101] also see 

the “FGD Wastewater, Combustion Residual Leachate, and Gasification Wastewater Pollutants 

of Concern (POC) Analysis Methodology” [ERG, 2015b] for more detail on the methodology for 

determining POCs. EPA estimated pollutant loadings and removals only for pollutants that were 

identified as POCs. Therefore, for any pollutants that were not identified as a POC, EPA did not 

include the pollutant in the combustion residual leachate pollutant loadings estimates. The 

remainder of Section 13 discusses EPA’s methodology for developing average concentrations 

and calculating pollutant loadings and applies only to pollutants identified as POCs. 

To determine the industry average concentrations for a pollutant, EPA first averaged all 

concentration data provided for each individual landfill or impoundment for which plants 

provided sampling data to calculate a landfill- or impoundment-specific average concentration. 

For example, if a plant had three landfills and two impoundments and they collected four 

samples for each of those management units (i.e., a total of 20 samples for each pollutant), EPA 

calculated an average concentration for each of the three landfills and each of the two 

impoundments (i.e., a total of five average concentrations). EPA then averaged the landfill- or 

impoundment-specific average concentrations at each plant to get a plant-level average pollutant 

leachate concentration. Using the same example above, EPA averaged the five average 

concentrations data sets together to get one plant-level average concentration. EPA then used the 

average plant-level combustion residual leachate concentration to calculate the average 

concentrations across all plants. Table 13-1 presents the average concentration for leachate from 

both landfills/impoundments. EPA used these average concentrations to calculate baseline 

loadings for all plants discharging combustion residual leachate. 

As explained in Section 9.3, based on a review of the Steam Electric Survey data 

regarding the treatment of the combustion residual landfill leachate, EPA did not identify any 

plants currently operating a chemical precipitation system to treat landfill leachate. Therefore, 

EPA transferred the limitations and standards from the flue gas desulfurization (FGD) chemical 

precipitation system. Because EPA does not have analytical data that represent treated landfill 

leachate for the technology options being considered, EPA also transferred the FGD chemical 

precipitation effluent concentrations, identified in Section 11.1.5.2, to the landfill leachate for the 

purposes of calculating post-compliance loadings. In cases where the average concentration of 

the untreated combustion residual landfill leachate is less than the FGD treated concentration for 

the technology option, EPA assumed that the treated concentration was equal to the influent (i.e., 

untreated leachate) average concentration. In this case, EPA did not calculate additional 

removals of these particular pollutants by the wastewater treatment system. Table 13-2 presents 

the chemical precipitation effluent average concentrations for leachate. Additionally, EPA 

identified one plant that currently treats its combustion residual leachate in a biological treatment 

system (combined with FGD wastewater) and one plant that is building a biological treatment 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-3 

system to treat its combustion residual leachate. To estimate the baseline combustion residual 

leachate discharges from these plants, EPA also transferred the FGD biological treatment system 

effluent concentrations, identified in Section 11.1.5.3, to the landfill leachate. In cases where the 

average concentration of the untreated combustion residual landfill leachate is less than the FGD 

treated concentration for the technology option, EPA assumed that the treated concentration was 

equal to the influent (i.e., untreated leachate) average concentration. In this case, EPA did not 

calculate additional removals of these particular pollutants by the wastewater treatment system. 

Table 13-3 presents the chemical precipitation followed by biological treatment effluent average 

concentrations for leachate. 

13.2 WASTEWATER FLOW RATES

EPA used information from the Steam Electric Survey to determine which plants 

discharge combustion residual leachate from impoundments and/or landfills and the amount of 

wastewater each plant reported discharging. EPA used plant-level leachate flow rates to calculate 

baseline and technology option loadings. EPA used the total plant-level leachate flow from the 

“Combustion Residual Leachate Input Table” to calculate compliance costs. Section 4.1.3 

describes the methodology used to estimate the leachate flow rates for both landfills and 

impoundments. A copy of the input table is included in the Combustion Residual Leachate 

Loadings Database [ERG, 2015a]. 

13.3 POLLUTANT LOADINGS AND TOXIC-WEIGHTED POUND EQUIVALENT (TWPE)

RESULTS

EPA multiplied the average pollutant concentrations for each technology presented in 

Section 13.1 with the plant-specific wastewater flow rates presented in Section 13.2 to calculate 

the mass of pollutant discharged to surface waters for each plant, as applicable. For those plants 

transferring the wastewater to a publicly owned treatment works (POTW), EPA adjusted the 

loadings to account for additional removals that would take place at the POTW. EPA identified 

five plants with non-small steam electric generating units (generating units greater than 50 

megawatts (MW)) as transferring combustion residual landfill leachate to a POTW. For these 

five plants, EPA adjusted the baseline and post-compliance loadings to account for pollutant 

removals expected from POTWs for each. Appendix B to this report provides the percent 

removal expected from well-operated POTWs, as reported in the Memorandum to the 2006 

Effluent Guidelines Program Plan Docket, entitled, “Publicly Owned Treatment Works (POTW) 

Percent Removals Used for the TRI Releases2002 Database” [ERG, 2006]. For each plant 

identified as discharging to a POTW, EPA used the calculated pollutant loadings and the POTW 

removals shown in Appendix B to calculate the mass of pollutant discharged from the POTW to 

surface water, according to Equation 13-1. 

(13-1) 

Indirect Pollutant Loading (lb/yr) = Pollutant Loading × (1 - POTW Removal)

where: 

Pollutant Loading = The calculated baseline or post-compliance loadings 

from a specific pollutant, in pounds/year. 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-4 

POTW Removal = The estimated percentage of the pollutant loading that 

will be removed by a POTW. 

After calculating these loadings for each plant and wastestream, EPA then calculated the 

TWPE associated with the pollutant discharges. These calculations were completed for the 

baseline and post-compliance pollutant loadings for each plant. Using the plant-level loadings by 

wastestream, EPA was then able to calculate the baseline and post-compliance loading at the 

industry level for each wastestream and regulatory option. 

For the chemical precipitation technology option, EPA assumed that all but the two plants 

identified as operating biological treatment systems would install a chemical precipitation 

treatment system to treat only the combustion residual landfill leachate flow. No plants currently 

treat landfill leachate with a chemical precipitation system. EPA calculated discharge loadings 

for these plants using the average concentration data set associated with chemical precipitation 

systems (presented in Table 13-2) and plant-specific leachate flow rates (discussed in Section 

4.1.3). 

The raw data output of the combustion residual leachate loadings can be found in 

Appendix B, along with a table of plant-level loadings in pounds/year and TWPE/year. Table 

13-4 presents the combustion residual leachate loadings on an industry level for baseline and 

each technology option. Table 13-4 presents loadings based on oil-fired generating units and 

those generating units with a generating capacity of 50 MW or less not installing the technology 

basis because they are not facing any more stringent requirements than already existed under the 

previously established regulations. The loadings exclude the pollutant parameters biochemical 

oxygen demand (BOD), chemical oxygen demand (COD), total dissolved solids (TDS), and total 

suspended solids (TSS) because they double count the loadings for specific pollutants already 

included. The table includes the number of plants identified as discharging combustion residual 

leachate, the total industry flow rate associated with each technology option, and the total 

industry loadings in pounds per year and TWPE per year. 

EPA evaluated applying different effluent limitations to oil-fired generating units and 

generating units with a capacity of 50 MW or less. For discharges from these generating units, 

Best Available Control Technology Economically Achievable (BAT) would be set equal to the 

current Best Practicable Control Technology Currently Available (BPT) standard for each of the 

wastestreams for which EPA is revising the effluent limitations guidelines and standards (ELGs). 

For the tables presenting the results of the loadings and the pollutant removals in this section, 

EPA presents two different versions of the tables: one version that includes the loadings and 

pollutant removals based on all generating units/plants discharging the wastestream installing the 

appropriate technology basis, and a second version based on all oil-fired generating units and 

generating units with a capacity of 50 MW or less not needing to install the technology basis 

because the current controls are sufficient to meet the BPT requirements. Section 5 of the 

Technical Development Document for the Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (TDD) provides more details regarding 

the analyses of these factors [U.S. EPA, 2015]. Section 8 of the TDD discusses the rationale 

regarding the decision. 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-5 

Table 13-5 presents the pollutant removals for combustion residual landfill leachate, in 

both pounds per year and TWPE per year, for the chemical precipitation technology options. 

Table 13-5 presents the pollutant removals based on oil-fired generating units and those 

generating units with a generating capacity of 50 MW or less not installing the technology basis 

because they are not facing any more stringent requirements than already existed under the 

previously established regulations. EPA calculated the pollutant removals by subtracting the 

technology option loadings from the baseline loadings. 

13.4 REFERENCES

1. ERG. 2015a. Eastern Research Group, Inc. Combustion Residual Leachate Loadings 

Database. (30 September). DCN SE05840. 

2. ERG. 2015b. Eastern Research Group, Inc. “FGD Wastewater, Combustion Residual 

Leachate and Gasification Pollutants of Concern (POC) Analysis Methodology.” (30 

September). DCN SE05342. 

3. ERG. 2015c. Eastern Research Group, Inc. Steam Electric Technical Questionnaire 

Database (“Steam Electric Survey”). (30 September). DCN SE05903. 

4. ERG. 2015d. Eastern Research Group, Inc. “Supplemental Costs and Loadings 

Documentation.” (30 September). DCN SE05839. 

5. U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development 

Document for the Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category. (30 September). DCN SE05904. 

 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-6 

Table 13-1. Average Untreated Combustion Residual Leachate Concentrations 

Analyte Unit 

Untreated Combustion Residual 

Leachate Concentration 

Aluminum ug/L 2,990

Antimony ug/L 3.75

Arsenic ug/L 38.4

Barium ug/L 53.2

Boron ug/L 22,400

Cadmium ug/L 10.1

Calcium ug/L 408,000

Chloride ug/L 413,000

Chromium ug/L 2,120

Cobalt ug/L 38.6

Copper ug/L 7.58

Iron ug/L 37,100

Magnesium ug/L 118,000

Manganese ug/L 2,720

Mercury ug/L 1.06

Molybdenum ug/L 1,380

Nickel ug/L 46.5

Selenium ug/L 111

Sodium ug/L 308,000

Sulfate ug/L 1,790,000

Thallium ug/L 1.16

TDS ug/L 3,500,000

TSS ug/L 35,800

Vanadium ug/L 1,910

Zinc ug/L 211

 Source: ERG, 2015a; ERG, 2015b; ERG, 2015c. 

 Note: Concentrations are rounded to three significant figures. 

 Note: Includes only those pollutants identified as POCs.

 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-7 

Table 13-2. Average Chemical Precipitation Effluent Concentrations for Combustion 

Residual Leachate 

Analyte Unit Average Concentration

Aluminum ug/L 120

Antimony ug/L 3.75

Arsenic ug/L 5.83

Barium ug/L 53.2

Boron ug/L 22,400

Cadmium ug/L 4.21

Calcium ug/L 408,000

Chloride ug/L 413,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Iron ug/L 110

Magnesium ug/L 118,000

Manganese ug/L 2,720

Mercury ug/L 0.139

Molybdenum ug/L 125

Nickel ug/L 9.11

Selenium ug/L 111

Sodium ug/L 276,000

Sulfate ug/L 1,240,000

Thallium ug/L 1.16

TDS ug/L 3,500,000

TSS ug/L 8,590

Vanadium ug/L 12.6

Zinc ug/L 20.0

Source: ERG, 2015a; ERG, 2015b; ERG, 2015c. 

Note: Concentrations are rounded to three significant figures. 

Note: Includes only those pollutants identified as POCs. 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-8 

Table 13-3. Average Chemical Precipitation followed by Biological Treatment Effluent 

Concentration for Combustion Residual Leachate 

Analyte Unit Average Concentration

Aluminum ug/L 120

Antimony ug/L 3.75

Arsenic ug/L 5.83

Barium ug/L 53.2

Boron ug/L 22,400

Cadmium ug/L 4.21

Calcium ug/L 408,000

Chloride ug/L 413,000

Chromium ug/L 6.45

Cobalt ug/L 9.30

Copper ug/L 3.78

Iron ug/L 110

Magnesium ug/L 118,000

Manganese ug/L 2,720

Mercury ug/L 0.0507

Molybdenum ug/L 125

Nickel ug/L 6.30

Selenium ug/L 5.72

Sodium ug/L 276,000

Sulfate ug/L 1,240,000

Thallium ug/L 1.16

TDS ug/L 3,500,000

TSS ug/L 8,590

Vanadium ug/L 12.6

Zinc ug/L 20.0

Source: ERG, 2015a; ERG, 2015b; ERG, 2015c. 

Note: Concentrations are rounded to three significant figures. 

Note: Includes only those pollutants identified as POCs. 

 
Section 13 – Combustion Residual Leachate Pollutant Loadings

13-9 

Table 13-4. Industry-Level Combustion Residual Leachate Loadings Excluding BOD, 

COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing 

Technology Basis 

Treatment Option 

Number of 

Plants 

Total Industry 

Flow (MGD) 

Total Industry Loadings

Pounds/Year TWPE/Year

Baseline 95 a 9.09 85,400,000 70,300

Chemical Precipitation 95 a 9.09 72,900,000 36,400

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TSS and TDS. 

Note: Loadings are rounded to three significant figures. 

a – One plant operates only oil-fired generating units and/or generating units with a generating capacity of 50 MW 

or less; therefore, this plant is not facing any more stringent requirements than exist under the previously established 

BPT regulations. As such, EPA assumed that this plant will not install the technology basis and, therefore, will not 

incur any compliance costs. Additionally, EPA assumed it will continue to discharge combustion residual leachate at 

its current baseline level and will not achieve any pollutant removals for the technology options evaluated. 

Table 13-5. Combustion Residual Landfill Leachate Loadings Removals Excluding BOD, 

COD, TDS, and TSS and Based on Oil-Fired Units and Units 50 MW or Less Not Installing 

Technology Basis

Technology Option 

Total Industry Pollutant Removals

Pounds/Year TWPE/Year

Removal (Baseline –> Chemical Precipitation) 12,500,000 33,800

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TSS and TDS. 

Note: Removals are rounded to three significant figures. The removals may not equal the subtraction of the 

technology option from the baseline using the values in Table 13-4 due to rounding. 
Section 14 - Gasification Pollutant Loadings 

14-1 

14. GASIFICATION POLLUTANT LOADINGS 

As discussed in Section 10, the three plants currently discharging gasification wastewater 

already operate the treatment technology considered by EPA to be the Best Available Control 

Technology Economically Achievable (BAT). As a result, these plants incur costs only 

associated with compliance monitoring. Additionally, because the currently operating 

gasification generating units operate evaporation (i.e., the BAT technology option), EPA 

determined that the baseline loadings are equal to the post-compliance loadings. The removals 

for gasification wastewater, baseline loadings minus technology option loadings, are equal to 

zero because all plants are currently operating the technology basis selected as BAT. Therefore, 

EPA did not estimate baseline or post-compliance loadings for gasification wastewater. 
Section 15 – Summary of Costs and Pollutant Removals by Regulatory Option

15-1 

15. SUMMARY OF COSTS AND POLLUTANT REMOVALS BY 

REGULATORY OPTION 

EPA evaluated five regulatory options comprising various combinations of the 

technology options considered for each wastestream. Table 15-1 lists each regulatory option that 

EPA evaluated along with the associated treatment technology basis for all of the affected 

wastestreams. EPA estimated the costs and pollutant loading removals associated with steam 

electric power plants to achieve compliance for each regulatory option under consideration. This 

section summarizes the total estimated compliance costs and pollutant removal estimates 

associated with each regulatory option. 

Using the methodologies described in this report, EPA combined the plant-level 

estimated compliance costs for the appropriate technology options, based on the information 

specified in Table 15-1, to generate an industry-level estimated compliance cost for each 

regulatory option. Table 15-2 presents the estimated compliance cost for each of the five 

regulatory options based on the oil-fired generating units and generating units with a capacity of 

50 megawatts (MW) or less not needing to install the technology basis because the current 

controls are sufficient to meet the Best Practicable Control Technology Currently Available 

(BPT) requirements. For each regulatory option, the capital costs, annual operation and 

maintenance costs (O&M), one-time costs, and recurring costs are presented. All cost estimates 

are expressed in terms of pre-tax 2010 dollars. 

EPA also estimated the pollutant loading removals associated with steam electric power 

plants to achieve compliance for each regulatory option under consideration. Using the 

methodology described in this report, EPA combined the plant-level pollutant loadings for the 

appropriate technology options, based on the information specified in Table 15-1, to calculate 

industry-level estimated pollutant loadings and pollutant removals for each regulatory option. 

Table 15-3 presents the total industry loadings and pollutant removals at baseline and for each of 

the five regulatory options based on the oil-fired generating units and generating units with a 

capacity of 50 MW or less not needing to install the technology basis because the current 

controls are sufficient to meet the BPT requirements. EPA excluded the pollutant parameters 

biochemical oxygen demand (BOD), chemical oxygen demand (COD), total organic carbon 

(TOC), total dissolved solids (TDS), and total suspended solids (TSS) from the total loadings and 

toxic-weighted pound equivalent (TWPE) values presented in these tables to avoid double 

counting. 

Similarly to the methodology used to calculate industry-level removals, EPA used 

pollutant-level loadings for each technology option to estimate the removals achieved by steam 

electric power plants for each of the regulatory options considered. The pollutant-level baseline 

loadings and pollutant-level removals for each regulatory option by wastestream are presented in 

the memorandum entitled “Steam Electric Pollutant-Level Loadings and Removals for Each 

Wastestream and Regulatory Option” (DCN SE05847). 

EPA also estimated the pollutant loadings removals by pollutant for each regulatory 

option. Similar to the methodology used to calculate industry-level removals, EPA used 

pollutant-level loadings for each technology option to estimate the removals achieved by steam 
Section 15 – Summary of Costs and Pollutant Removals by Regulatory Option

15-2 

electric power plants for each of the regulatory options considered. The pollutant-level baseline 

loadings and pollutant-level removals for each regulatory option by wastestream are presented in 

the memorandum entitled “Steam Electric Pollutant-Level Loadings and Removals for Each 

Wastestream and Regulatory Option” (DCN SE05847). 
Section 15 – Summary of Costs and Pollut

15-3 

Table 15-1. Treatment Technologies Basis for Estimating Compliance Costs and Pollutant Loadings 

Option

Regulatory 

Option b

TREATMENT TECHNOLOGY a 

FGD Wastewater 

Fly Ash 

Transport 

Water 

Bottom Ash 

Transport 

Water 

Combustion 

Residual 

Leachate 

Gasifica

Wastew

Chemical 

Precipitation 

Chemical 

Precipitation 

with Biological 

Treatment 

Chemical 

Precipitation with 

Evaporation 

Dry 

Vacuum 

System 

MDS/ Remote 

MDS 

Chemical 

Precipitation Evapora

A X X X 

B X X X C X X X c X 

D X X X X 

E X X X X X 

MDS – Mechanical Drag System a – Table presents only the technology options evaluated for the costs and pollutant removals. All other appropriate technology co

used to generate the compliance costs (e.g., compliance monitoring, transportation, disposal). b – Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with a capacity of 50 MW or letechnology basis for all wastestreams. Regulatory Option C assumes that oil-fired generating units and generating units with a cap

less do not install the technology basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating 

of 400 MW or less do not install the technology basis for bottom ash. c – Requires only generating units with a capacity of 400 MW or more to comply with the technology basis. 
Section 15 – Summary of Costs and Pollutant Removals by Regulatory Option

15-4 

Table 15-2. Cost of Implementation by Regulatory Option [In millions of pre-tax 2010 

dollars] 

Regulatory 

Option a

Number of 

Plants 

Capital 

Costs 

Annual 

O&M Costs 

One-Time 

Costs 

Recurring Costs

3-year 5-year 6-year 10-year b

A 100 $1,069 $78 $0 $0 $0 $7 ($25)

B 100 $1,969 $123 $0 $0 $0 $7 ($5)

C 139 $4,258 $220 $0.1 $0 $24 $7 ($54)

D 181 $5,426 $326 $0.2 $4 $49 $7 ($76)

E 196 $6,031 $360 $0.2 $44 $49 $14 ($76)

a – Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with a capacity of 

50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes that oil-fired 

generating units and generating units with a capacity of 50 MW or less do not install the technology basis for FGD 

wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity of 400 MW or 

less do not install the technology basis for bottom ash. 

b – The values in this column are negative and presented in parenthesis because they represent cost savings. 

Table 15-3. Estimated Pollutant Removals by Regulatory Option 

Regulatory Option a

Total Industry Loadings Total Industry Removal b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 2,210,000,000 2,680,000 NA NA

A 2,060,000,000 1,650,000 150,000,000 1,030,000

B 2,050,000,000 1,510,000 161,000,000 1,170,000

C 1,830,000,000 1,200,000 376,000,000 1,480,000

D 1,700,000,000 1,000,000 513,000,000 1,680,000

E 1,680,000,000 967,000 526,000,000 1,710,000

Note: Excludes loadings for pollutants not identified as POCs and loadings for BOD, COD, TDS, and TSS. 

Note: Pollutant loadings and removals are rounded to three significant figures. The removals may not equal the 

subtraction of the technology option from the baseline due to rounding. 

NA – Not applicable. 

a – Baseline and Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with 

a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes 

that oil-fired generating units and generating units with a capacity of 50 MW or less do not install the technology 

basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity 

of 400 MW or less do not install the technology basis for bottom ash. 

b – Compared to baseline. 
Section 16 – Clean Power Plan

16-1 

16. CLEAN POWER PLAN 

As discussed in Section 1, in addition to estimating compliance costs and pollutant 

loadings and removals associated with the effluent limitations guidelines and standards (ELG) 

accounting for the Coal Combustion Residual (CCR) rule, EPA also accounted for operational 

changes expected as part of the Clean Power Plan (CPP). Section 16.1 describes the 

methodology EPA used to incorporate the CPP into compliance costs and pollutant loadings and 

Section 16.2 presents the estimated compliance cost and pollutant loadings for each of the main 

regulatory options. The tables referenced in this section appear at the end of the section. 

16.1 METHODOLOGY FOR INCORPORATING THE CPP 

Because only the proposed CPP was available at the time compliance costs were 

evaluated, EPA took the approach of estimating compliance costs and pollutant loadings that 

account for expected changes from the proposed CPP as a proxy for the final CPP. EPA 

accounted for the CPP in the version of the compliance costs and pollutant loadings that also 

account for the final CCR rule. The methodologies described in elsewhere this report and the 

industry-level estimated compliance costs and industry-level estimated pollutant loadings and 

removals presented in Section 15 do not account for the CPP. As discussed in Section 1.3.3 of 

the Technical Development Document for the Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category [U.S. EPA, 2015], the CPP 

rulemaking is focused on cutting carbon pollution from steam electric power plants. 

EPA used output from the Integrated Planning Model (IPM) to account for the CPP in its 

analyses. IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. 

electric power sector that provides forecasts of least-cost capacity expansion, electricity dispatch, 

and emission control strategies for meeting energy demand and environmental, transmission, 

dispatch, and reliability constraints. During the development of the CPP, EPA used the IPM to 

predict how industry may respond to that rule. This IPM output for CPP provided insight to 

steam electric generating unit-level retirements that could potentially be triggered by 

requirements established by the CPP. For purposes of the effluent limitations guidelines and 

standards (ELG) analyses, EPA reviewed the IPM CPP policy run outputs for analyses year 

2020. Although not necessarily definitive, the IPM output can be used to develop a list of steam 

electric generating unit retirements that form the basis for a reasonable estimate of how actions 

plants (and power companies) make can affect the compliance cost and pollutant removal 

estimates for the ELG. A list of the generating units predicted to retire as a result of the CPP by 

the IPM is included in Appendix A.

To account for these estimated affects for the CPP, EPA generated a second set of 

compliance cost and pollutant loadings estimates for the ELG. For this second set of analyses, all 

generating units that are projected by IPM to close/retire due to the CPP were assumed to be 

retired prior to implementation of the final ELGs; therefore, these generating units would not 

incur any ELG compliance costs. Appendix A of this report includes a table listing plants 

estimated to incur compliance costs (and associated reductions in pollutant discharges) under the 

ELG by wastestream. This table identifies whether the IPM predicts all generating units at the 

plant to retire due to the CPP, resulting in zero compliance costs and zero pollutant removals, or 
Section 16 – Clean Power Plan

16-2 

only some generating units at the plant to retire due to the CPP, resulting in a reduction in 

compliance costs and pollutant removals, as compared to the ELG estimates that do not account 

for the CPP. As with the approach used to account for the final CCR rule, EPA determined that it 

was not necessary to revise the methodology used to estimate the compliance costs or pollutant 

loadings for these analyses. 

Table 16-1 presents the number of plants and stream electric generating units for which 

EPA estimated compliance costs associated with the ELG accounting for CCR and CPP and 

Table 16-2 presents the number of plants and steam electric generating units expected to achieve 

pollutant removals as a result of the ELG accounting for CCR and CPP. 

16.2 SUMMARY OF COSTS AND POLLUTANT REMOVALS BY REGULATORY OPTION 

ACCOUNTING FOR THE CPP 

As described in Section 15, EPA used the methodologies described in this report to 

combine the plant-level estimated compliance costs for the appropriate technology options, based 

on the information specified in Table 15-1, to generate an industry-level estimated compliance 

cost for each regulatory option. EPA then used the listing of projected generating unit 

retirements based on the CPP IPM policy run to adjust (zero out) compliance costs for those 

generating units that are expected to retire, as described in Section 16.1. Table 16-3 presents the 

estimated compliance cost for each of the five regulatory options accounting for the CPP and 

based on oil-fired generating units and generating units with a capacity of 50 MW or less not 

needing to install the technology basis because the current controls are sufficient to meet the 

BPT requirements. For each regulatory option, the capital costs, annual operation and 

maintenance costs (O&M), one-time costs, and recurring costs are presented. All cost estimates 

are expressed in terms of pre-tax 2010 dollars. 

EPA also estimated the pollutant loadings removals associated with the steam electric 

power plants to achieve compliance for each regulatory option under consideration. As described 

in Section 15, EPA used the methodologies described in this report to combine plant-level 

pollutant loadings for the appropriate technology options, based on the information specified in 

Table 15-1, to calculate industry-level estimated pollutant loadings and pollutant removals for 

each regulatory option. EPA then used the listing of projected generating unit retirements based 

on the CPP IPM policy run to adjust (zero out) the baseline and the technology option loadings 

for those generating units that are expected to retire, as described in Section 16.1. Table 16-4 

presents the total industry-level loadings and pollutant removals at baseline and for each of the 

five regulatory options accounting for the CPP. EPA excluded the pollutant parameters 

biochemical oxygen demand (BOD), chemical oxygen demand (COD), total organic carbon 

(TOC), total dissolved solids (TDS), and total suspended solids (TSS) from the total loadings and 

toxic-weighted pound equivalent (TWPE) values presented in these tables to avoid double 

counting. 

EPA also estimated the pollutant loadings removals by pollutant for each regulatory 

option [ERG, 2015]. See Appendix A for the plant-level compliance cost estimates and pollutant 

loadings for each wastestream. 
Section 16 – Clean Power Plan

16-3 

16.3 REFERENCES

1. ERG. 2015. Eastern Research Group, Inc. “Steam Electric Pollutant-Level Loadings and 

Removals for Each Wastestream and Regulatory Option.” (30 September). DCN 

SE05847. 

2. EPA. 2015. U.S. Environmental Protection Agency. Technical Development Document 

for the Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category. (30 September). DCN SE05904. 
Section 16 – Clean Power Plan

16-4 

Table 16-1. Number of Steam Electric Plants and Generating Units Expected to Incur 

Compliance Costs by Wastestream and Regulatory Option Accounting for CCR and CPP 

Regulatory 

Option 

FGD 

Wastewater 

Fly Ash 

Transport 

Water 

Bottom Ash 

Transport 

Water 

Combustion 

Residual 

Leachate 

Gasification 

Wastewater

FGMC 

Wastewater Total a 

A 69 (160 units) 16 (32 units) 0 0 2 (2 units) 0 79 (174 units)

B 69 (160 units) 16 (32 units) 0 0 2 (2 units) 0 79 (174 units)

C 69 (160 units) 16 (32 units) 61 (114 units) 0 2 (2 units) 0 108 (224 units)

D 69 (160 units) 16 (32 units) 103 (209 units) 0 2 (2 units) 0 134 (278 units)

E 69 (160 units) 16 (32 units) 103 (209 units) 60 (147 units) 2 (2 units) 0 145 (315 units)

a – The number of plants and generating units incurring costs is not additive for each regulatory option because 

some plants and units may incur costs for multiple wastestreams. 

Table 16-2. Number of Steam Electric Plants and Generating Units Expected to Achieve 

Pollutant Removals by Wastestream and Regulatory Option Accounting for CCR and CPP

Regulatory 

Option 

FGD 

Wastewater 

Fly Ash 

Transport 

Water 

Bottom Ash 

Transport 

Water 

Combustion 

Residual 

Leachate 

Gasification 

Wastewater

FGMC 

Wastewater Total a 

A 38 (86 units) 20 (38 units) 0 0 0 0 50 (108 units)

B 65 (155 units) 20 (38 units) 0 0 0 0 75 (170 units)

C 65 (155 units) 20 (38 units) 57 (106 units) 0 0 0 100 (213 units)

D 65 (155 units) 20 (38 units) 95 (195 units) 0 0 0 123 (264 units)

E 65 (155 units) 20 (38 units) 95 (195 units) 60 (147 units) 0 0 138 (307 units)

a – The number of plants and generating units expected to achieve pollutant removals is not additive for each 

regulatory option because some plants and units may achieve removals for multiple wastestreams. 
Section 16 – Clean Power Plan

16-5 

Table 16-3. Cost of Implementation by Regulatory Option Accounting for CCR and CPP [In 

millions of pre-tax 2010 dollars] 

Regulatory 

Option a

Number of 

Plants 

Capital 

Costs 

Annual 

O&M Costs 

One-Time 

Costs 

Recurring Costs

3-year 5-year 6-year 10-year b

A 79 $910 $67 $0 $0 $0 $6 ($19)

B 79 $1,640 $103 $0 $0 $0 $6 ($19)

C 108 $3,462 $180 $0.1 $0 $19 $6 ($42)

D 134 $4,161 $235 $0.2 $3 $32 $6 ($58)

E 145 $4,638 $264 $0.2 $3 $32 $11 ($58)

a – Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with a capacity of 

50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes that oil-fired 

generating units and generating units with a capacity of 50 MW or less do not install the technology basis for flue 

gas desulfurization (FGD) wastewater treatment and fly ash, while oil-fired generating units and generating units

with a capacity of 400 MW or less do not install the technology basis for bottom ash. 

b – The values in this column are negative and presented in parenthesis because they represent cost savings. 

Table 16-4. Estimated Pollutant Removals by Regulatory Option Accounting for CCR and 

CPP 

Regulatory Option a

Total Industry Loadings Total Industry Removal b

Pounds/Year TWPE/Year Pounds/Year TWPE/Year

Baseline 1,700,000,000 2,140,000 NA NA

A 1,580,000,000 1,250,000 124,000,000 891,000

B 1,570,000,000 1,130,000 132,000,000 1,010,000

C 1,390,000,000 878,000 306,000,000 1,260,000

D 1,330,000,000 785,000 371,000,000 1,350,000

E 1,320,000,000 755,000 382,000,000 1,380,000

Note: Excludes loadings for pollutants not identified as POCs and for BOD, COD, TDS, and TSS. 

Note: Pollutant loadings and removals are rounded to three significant figures. The removals may not equal the 

subtraction of the technology option from the baseline due to rounding. 

NA – Not applicable. 

a – Baseline and Regulatory Options A, B, D, and E assume that oil-fired generating units and generating units with 

a capacity of 50 MW or less do not install the technology basis for all wastestreams. Regulatory Option C assumes 

that oil-fired generating units and generating units with a capacity of 50 MW or less do not install the technology 

basis for FGD wastewater treatment and fly ash, while oil-fired generating units and generating units with a capacity 

of 400 MW or less do not install the technology basis for bottom ash. 

b – Compared to baseline.
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-1 

17. EVALUATION OF COST AND POLLUTANT REMOVAL 

ESTIMATES 

This section describes the activities EPA used to evaluate the compliance cost and 

pollutant removal estimates described in this report. Plans for these quality control activities are 

detailed in the Quality Assurance Project Plan for the Steam Electric Effluent Guidelines 

Rulemaking, Version 4, dated April 5, 2013, and approved on April 19, 2013, (hereafter referred 

to as the QAPP). The activities included: 

• Verifying that the collected cost data met the data acceptance specifications 

presented in Table 2-3 in the QAPP. 

• Checking database code, spreadsheet data entry, and calculations and 

documenting these checks for databases and spreadsheets developed to estimate 

costs and pollutant loadings. 

• Verifying that the estimated costs met the quality specifications presented in 

Table 2-4 in the QAPP. 

All tables referenced in this section are presented at the end of this section. 

17.1 VERIFYING COST DATA AGAINST ACCEPTANCE SPECIFICATIONS

EPA collected information about the costs for steam electric power plants to install and 

operate the wastewater pollution control technologies described in this report, including 

wastewater treatment systems, ash handling operations, and costs for hauling solid waste for onor off-site disposal. EPA obtained recent (i.e., 2000-2010) cost information from steam electric 

power plants in response to the Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines (Steam Electric Survey), as well as more current (i.e., 2009-2011) cost information 

from equipment vendors. 

The criteria EPA used to evaluate the quality of collected pollution control technology 

cost information are summarized in Table 17-1, along with acceptable values for each criterion. 

EPA’s verification of how well the cost data met the quality specifications is presented, by 

acceptance criterion, in this section. 

Currency. With the exception of surface impoundment installations and their operation, 

EPA collected all costs from steam electric power plants, vendors, or documented Internet 

sources and represented systems installed in 2000 or later, thus meeting the currency 

specification. 

To estimate the baseline cost for surface impoundment installations and their operation, 

EPA used two EPA studies evaluating the economics of waste disposal at coal-fired power 

plants: U.S. EPA & TVA Economics of Ash Disposal at Coal-fired Power Plants [U.S. EPA and 

TVA, 1981] and U.S. EPA Full-Scaled Field Evaluation of Waste Disposal from Coal-fired 

Electric Generating Plants [U.S. EPA, 1985]. These estimates predate the time period specified 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-2 

for the currency criterion; however, these estimates are the “best available” and suitable for the 

estimate of costs associated with baseline operations.

Technology. EPA obtained costs for equipment appropriate for and demonstrated to be 

available for steam electric power plants, including chemical precipitation, anoxic/anaerobic 

biological metals removal, and evaporation of flue gas desulfurization (FGD) wastewater and/or 

combustion residual leachate; dry vacuum fly ash handling; mechanical drag system (MDS) or 

remote MDS for bottom ash handling; and transportation and disposal of ash and FGD 

wastewater treatment solids. 

Accuracy/Reliability. As listed in Table 17-1, the specification for accuracy and 

reliability was that quotes be obtained directly from steam electric power plants or from vendors 

who do business with steam electric power plants. Quotes for anoxic/anaerobic biological metals 

removal and evaporation of FGD wastewater and/or combustion residual leachate; dry vacuum 

fly ash handling; and MDS or remote MDS for bottom ash handling were obtained from vendors 

that do business with steam electric power plants and thus met this specification. 

Although quotes for other equipment were from vendors that may or may not directly 

serve steam electric power plants, they were obtained from reputable vendors that sell the type of 

equipment (including appropriate materials of construction) used for these operations (e.g., 

chemical precipitation, transport, and disposal). For this reason, although the quotes in some 

cases are not from vendors that directly serve steam electric power plants, these quotes meet the 

criterion that the reported information is “true.” 

In addition, as described throughout this report, EPA developed industry cost factors for 

many of the direct and indirect capital cost factors (e.g., installation and engineering overhead 

cost factors) used in the cost model from Steam Electric Survey data. Other cost elements (e.g., 

equipment capacity factors, materials of construction, and chemical dosage rates and sludge 

generation rates for chemical precipitation) were also derived from Steam Electric Survey 

responses. In this way, EPA met the specification for accuracy and reliability by using industryspecific data. 

Comparability. EPA requested steam electric power plants report installation and 

operation costs for ash handling, wastewater treatment, and other waste management (dollars per 

year) in the Steam Electric Survey, if the system was installed in the year 2000 or later. EPA 

intended to use the reported capital and operating costs to evaluate comparability. Many 

respondents did not respond to this question and those who did respond either did not itemize the 

total costs, or provided only certain itemized costs. For this reason, EPA could not directly 

compare costs reported in the responses to the Steam Electric Survey to prices that EPA obtained 

for equipment, installation, and shipping. As a result, EPA could not determine the comparability 

of the collected cost data. However, EPA used reported Steam Electric Survey costs to directly 

develop industry-specific labor rates and indirect cost factors. 

17.2 VERIFYING ANALYTICAL DATA AGAINST ACCEPTANCE SPECIFICATIONS

EPA collected analytical data representing the influent and effluent pollutant 

concentrations from steam electric power plant wastewater treatment systems for use in 

estimating the baseline and post-compliance loadings for the industry. Section 3 of this report 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-3 

discusses the data used to estimate the loadings. Some of the data used in the loadings analysis 

are from EPA’s primary data collection efforts (i.e., EPA’s sampling program), while the 

remainder of the data came from secondary data (e.g., industry-provided monitoring data, Steam 

Electric Survey data, Electric Power Research Institute (EPRI) reports, 1974 and 1982 Technical 

Development Documents (TDDs)). 

EPA reviewed the data collected as part of the EPA sampling program to evaluate 

whether they were of sufficient quality for use in the loadings analysis. The data review criteria 

that EPA used in assessing the quality of the data are described in Section 5.1.1 of the QAPP. 

Based on these criteria, EPA developed data review narratives for each set of analytical data 

generated by the sampling program. These data review narratives are included in the attachments 

to the sampling episode reports for each sampling event [ERG, 2012a-2012j; U.S. EPA, 2009]. 

Based on the review of the analytical data, EPA made data point-specific determinations as to 

whether the data should be included in the loadings analysis. 

In addition to the sampling data, EPA also used other secondary data sources to estimate 

the loadings. A summary of the acceptance criteria EPA used to evaluate whether these data 

were sufficient for use in the loadings analysis can be found in the “Development Memorandum 

for the Steam Electric Analytical Database for the Final Rule” [ERG, 2015]. This memorandum 

provides a description specific to the data used to characterize each wastestream, including 

secondary data sources. 

17.3 DEVELOPING AND CHECKING THE COST AND LOADINGS MODELS

EPA developed a detailed cost model for estimating total installed capital costs and O&M 

costs for each individual steam electric power plant, as described earlier in this report. EPA also 

developed a detailed loadings model to estimate the baseline and post-compliance loadings for 

each individual steam electric power plant, as described in Section 10. The model outputs 

received several reviews: 

• A project engineer checked that the calculations reflected the methodologies 

outlined in this report. Where the calculations and assumptions documentation did 

not agree, EPA determined if the documentation or calculations required 

corrections and ensured the corrections were made. 

• An engineer involved in the models development checked the accuracy of the 

calculations in the model’s code/queries by performing hand calculations and 

comparing the results to the model outputs. Where the model and hand 

calculations resulted in a discrepancy, the model was corrected and rechecked to 

ensure the correct calculations were being executed by the model. 

• An engineer provided independent technical review of the model outputs. The 

outputs were checked to ensure the expected number of records (i.e., the number 

of known plants incurring costs/discharging). Specifically for the cost model, the 

engineer confirmed that the individual cost elements summed to the calculated 

total for each category of costs presented in the output (e.g., the sum of all 

individual capital cost elements equals the calculated total capital cost). The 

engineer also checked that the cost model output calculated the total annualized 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-4 

costs appropriately by calculating the plant-specific values in Excel and 

comparing them to annualized costs presented in the output. 

• After each model run, an engineer analyzed the specific model outputs for the 

expected changes based on industry profile changes or changes to the model 

equations and/or inputs. The engineer performed the following types of checks: 

— Confirmed that plants removed from the industry profile no longer had 

compliance costs or pollutant loadings in all outputs (e.g., FGD biological 

treatment, fly ash, bottom ash). 

— Confirmed that plants identified as incurring compliance costs/discharging 

wastewater were included in all applicable cost and loadings outputs. 

— Confirmed that plants incurring compliance costs also have a calculated 

pollutant loading, where appropriate.123

— Confirmed that changes to models and/or model inputs, such as flow rates, 

factors, or equations, resulted in the expected change in the specific cost 

elements/loadings in the model outputs. 

• The engineer noted issues or discrepancies and the model outputs were corrected. 

The engineer rechecked the new outputs for all issues identified. 

• A senior engineer reviewed the costs and loadings by comparing the estimates for 

each plant and technology and evaluating whether the trends in costs/loadings 

reflected the amount of wastewater treated or ash handled and the baseline waste 

management strategies. 

17.4 EVALUATING COST ESTIMATE QUALITY

Verification of the completed cost estimates means determining if estimated costs meet 

the data acceptance criteria specified in Table 2-4 of the QAPP. For example, the first acceptance 

criterion is that the costs meet the requirements for economic analysis. The specifications for this 

criterion were that the estimates include both one-time costs for equipment purchase, installation, 

and other direct and indirect capital costs and ongoing operation and maintenance costs. The cost 

estimates fully met these specifications. Table 17-3 reproduces the QAPP cost estimate quality 

specifications along with an assessment of whether the estimated costs met the specifications. 

To evaluate the reasonableness of the cost estimate, EPA planned to compare its 

estimated costs to costs for similar installations at steam electric power plants. EPA sought costs 

for plants through the Steam Electric Survey but obtained only limited information. In some 

cases, cost estimates provided by plants included initial research of the technologies, including 

 

123 All plants incurring a compliance cost for FGD wastewater are included in the pollutant loading calculations. For 

plants operating both wet and dry fly ash handling systems, each with the capacity to handle all ash produced at the

plant, EPA calculated a pollutant loading but included no compliance cost. For plants operating wet bottom ash 

handling systems that did not discharge bottom ash transport water in 2009, EPA assessed a compliance cost (see 

Chapter 8.5) but did not calculate a pollutant loading. 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-5 

evaluation of varying configurations and operating conditions, and therefore did not represent 

today’s expected costs to install the BAT system. For example, for anoxic/anaerobic biological 

treatment systems, a vendor for this technology indicated that the design and cost basis for the 

technology has changed significantly since those early implementations, particularly for low 

flow (<25 gallons per minute (gpm)) systems, and therefore are not reflective of capital costs that 

would be incurred today. 

In other cases, the systems installed and operated by the steam electric power plants did 

not match the Best Available Control Technology Economically Achievable (BAT) design used 

by EPA for the technology options (or there wasn’t enough documentation to determine whether 

the system matched the BAT design). For example, in some cases, EPA’s model design basis for 

ash handling exceeded the rates used in individual plant bid proposals. Therefore, EPA was 

unable to compare the reported costs to the model estimates. 

More generally, EPA compared summary statistics for cost model outputs to Steam 

Electric Survey responses for total capital, purchased equipment, installation, buildings, and site 

preparation, as well as indirect costs such as engineering and construction expenses. EPA found 

that labor costs sometimes varied because its cost model includes the use of in-house labor for 

operation and maintenance of the FGD wastewater treatment system. Contracted labor rates may 

be significantly higher, leading to higher O&M costs. For example, early implementers of the 

anoxic/anaerobic biological treatment system typically hired a contractor to operate and maintain 

their treatment system, which may have led to higher O&M costs reported in the Steam Electric 

Survey compared to model estimates. 

In certain cases, such as for evaporation treatment preceded by chemical precipitation and 

softening, there is only one plant in the United States that was operating this technology at the 

time the responses to the Steam Electric Survey were submitted. The plant operating that system 

did not provide cost information to EPA in its responses to the Steam Electric Survey. Because 

EPA was unable to collect cost data from the Steam Electric Survey, EPA relied on the cost data 

provided by the vendors. EPA notes that cost data were collected from two different vendors and 

the vendors’ estimates were similar. As described in Section 6.3.5, EPA used the cost data from 

both vendors in developing the evaporation system costs.

17.5 REFERENCES

1. ERG. 2012a. Eastern Research Group, Inc. Final Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01305. 

2. ERG. 2012b. Eastern Research Group, Inc. Sampling Episode Report, Allegheny 

Energy’s Hatfield’s Ferry Power Station. (13 March). DCN SE01310. 

3. ERG. 2012c. Eastern Research Group, Inc. Final Sampling Episode Report, Duke Energy 

Miami Fort Station. (13 March). DCN SE01304. 

4. ERG. 2012d. Eastern Research Group, Inc. Power Plant Monitoring Data Collected 

Under Clean Water Act Section 308 Authority (“CWA 308 Monitoring Data”). (30 May). 

DCN SE01326. 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-6 

5. ERG. 2012e. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy 

Carolinas’ Belews Creek Steam Station. (13 March). DCN SE01305. 

6. ERG. 2012f. Eastern Research Group, Inc. Sampling Episode Report, Duke Energy 

Carolinas’ Allen Steam Station. (13 March). DCN SE01307. 

7. ERG. 2012g. Eastern Research Group, Inc. Sampling Episode Report, Mirant MidAtlantic, LLC’s Dickerson Generating Station. (13 March). DCN SE01308. 

8. ERG. 2012h. Eastern Research Group, Inc. Sampling Episode Report, RRI Energy’s 

Keystone Generating Station. (13 March). DCN SE01309. 

9. ERG. 2012i. Eastern Research Group, Inc. Sampling Episode Report, We Energies’ 

Pleasant Prairie Power Plant. (13 March). DCN SE01306. 

10. ERG. 2012j. Eastern Research Group, Inc. Site Visit Notes and Final Sampling Episode 

Report, Enel Power Plants. (8 August). DCN SE02013. 

11. ERG. 2015. Eastern Research Group, Inc. “Development Memorandum for the Steam 

Electric Analytical Database for the Final Rule.” (30 September). DCN SE05876. 

12. U.S. EPA and TVA. 1981. U.S. Environmental Protection Agency and Tennessee Valley 

Authority. Economics of Ash Disposal at Coal-fired Power Plants. (October). DCN 

SE02970. 

13. U.S. EPA. 1985. U.S. Environmental Protection Agency. Full-Scale Field Evaluation of 

Waste Disposal from Coal-fired Electric Generating Plants. (August). DCN SE02971. 

14. U.S. EPA. 2009. U.S. Environmental Protection Agency. Steam Electric Power 

Generating Point Source Category: Final Detailed Study Report. EPA 821-R-09-008. 

Washington, DC. (October). Available online at: 

http://water.epa.gov/lawsregs/guidance/cwa/304m/archive/upload/2009_10_26_guide_ste

am_finalreport.pdf. DCN SE00003. 

 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-7 

Table 17-1. Pollution Control Technology Cost Data Acceptance Criteria 

Acceptance Criterion Description/Definition Specification

Currency (Up to Date) Does the information reflect current 

systems? 

Costs are current (e.g., 2000-2010).

Technology Does the information reported reflect 

an area relevant to the study? 

Costs reflect systems that serve as the 

technology basis for steam electric regulatory 

options. 

Accuracy/Reliability Is the information reported true? Obtained from a power plant or a vendor who 

does business with steam electric power plants.

Comparability Are the costs comparable to costs 

provided by sources that meet these 

acceptance criteria? 

Comparable to other sources, such as the Steam 

Electric Survey. 

Source: QAPP Table 2-3. 

Table 17-2. Monitoring Data Acceptance Criteria 

Type of Data 

Data Usable to Demonstrate System 

Performance/Efficiency 

Data Usable to Estimate 

Baseline Discharges 

Monitoring Data (e.g., 

National Pollutant 

Discharge Elimination 

System (NPDES) permit, 

Discharge Monitoring 

Reports (DMRs)) 

1. Represent full-scale system operated at 

applicable steam electric power plant. 

2. Influent and effluent data or percent 

removal identified. 

3. Analytes identified and units included. 

Identified as discharge, analytes 

identified and units provided, 

approved analytical method used, 

represent current treatment 

operations. 

 
Section 17- Evaluation of Cost and Pollutant Removal Estimates

17-8 

Table 17-3. Cost Estimate Quality Specifications 

Acceptance 

Criterion: 

Cost Estimates Specification 

Comparison of 

Cost Estimate to the 

Specification 

Meet Requirements 

for Economic 

Analysis 

• Include one-time costs for equipment purchase and 

installation. 

• Include one-time costs for treatability and optimization 

studies, as appropriate. 

• Include ongoing O&M costs (annual costs). 

• Include periodic O&M costs, as appropriate. 

• True

• True 

• True 

• True 

Appropriate for 

Actual Plant 

Locations 

• Equipment costs, including transportation and 

installation, reflect the costs for supplies and labor at 

steam electric power plant locations. 

• Operating costs (electricity, diesel fuel, labor, chemicals, 

etc.) reflect the costs at steam electric power plant 

locations. 

• True

• True 

Unit Costs are on 

Specified, Standard 

Year Basis 

• Input costs escalated to 2010, using R.S. Means 

Construction Index or other standard cost index. 

• True

Complete • Include costs for all elements necessary to implement the 

waste management option. 

• Reflects EPA’s current 

understanding. 

Accurate (Model

Input) 

• Model inputs reflect design assumptions agreed on with 

project team. 

• Model inputs reflect baseline conditions at each plant. 

• True

• Reflects EPA’s current 

understanding based on 

Steam Electric Survey 

responses. 

Accurate 

(Calculations) 

• Model calculations are correct.

• Unit conversions are correct. 

• True

• True 

Reasonable • Order of magnitude of costs is comparable to costs for 

similar installations at similar plants. 

• Cost trends follow the design basis trends (i.e., costs for 

large plants are greater than the costs for small plants). 

• See discussion above.

• True